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DATE: |
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TO: |
Office of Commission Clerk (Cole) |
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FROM: |
Office of Auditing and Performance Analysis (Hallenstein, Harvey, Mailhot, Vinson) Office of the General Counsel (Fleming, Klancke, Sayler, Young) Division of Service, Safety & Consumer Assistance (C. Lewis, Moses, Vickery) Division of Regulatory Analysis (Crawford, Ellis, Graves, Webb ) |
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RE: |
Docket No. 090079-EI – Petition for increase in rates by Progress Energy Florida, Inc.
Docket No. 090144-EI – Petition for limited proceeding to include Bartow repowering project in base rates, by Progress Energy Florida, Inc.
Docket No. 090145-EI – Petition for expedited approval of the deferral of pension expenses, authorization to charge storm hardening expenses to the storm damage reserve, and variance from or waiver of Rule 25-6.0143(1)(c), (d), and (f), F.A.C., by Progress Energy Florida, Inc. |
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AGENDA: |
01/11/10 – 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\090079.RCM.DOC |
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Issue Description Page
6 Quality and Reliability of Electric Service (Vickery, C. Lewis, Moses)
8 Capital Recovery Schedules (P. Lee)
9 Calculation of the Average Remaining Life (P. Lee)
11 Life Spans for Combined Cycle Plants (P. Lee)
12 Depreciation Parameters for Production Units (P. Lee)
13 Depreciation Parameters for Transmission, Distribution and General Plant Account (Ollila)
14 Calculated Theoretical Reserves (P. Lee)
15 Corrective Reserve Measures (P. Lee, Maurey)
FOSSIL DISMANTLEMENT COST STUDY
17 Annual Dismantlement Provision (Higgins)
18 Corrective Reserve Measures (Higgins)
19 Annual Provision for Dismantlement (Springer, Higgins)
20 Fossil Dismantlement Study (Higgins, Dowds)
NUCLEAR DECOMMISSIONING COST STUDY
24 Non-utility Activities (Wright)
27 Level of Plant in Service (Slemkewicz)
28 Accumulated Depreciation (Marsh, P. Lee)
29 Accumulated Depreciation and Amortization (Marsh, P. Lee)
31 Plant Held for Future Use (Wright)
32 Level of Nuclear Fuel (Matlock)
33 Storm Damage Reserve (Wright)
35 Unamortized Rate Case Expense (Wright)
36 SFAS 143 (Asset Retirement Obligations) (Wright)
37 Working Capital Allowance (Slemkewicz)
38 Level of Rate Base (Slemkewicz)
39 Accumulated Deferred Taxes (Davis)
40 Unamortized Investment Tax Credits (Davis)
41 Pro Forma Adjustment (Maurey)
43 Reconciliation of Rate Base and Capital Structure (D. Buys)
44 Capital Structure (D. Buys)
45 Cost Rate for Short-term Debt (D. Buys)
46 Cost Rate for Long-term Debt (D. Buys)
48 Weighted Average Cost of Capital (Davis)
49 Total Operating Revenues (Slemkewicz)
50 Bartow Repowering Project (Wright)
57 Advertising Expenses (Marsh)
59 Directors and Officers Liability Insurance (Marsh)
60 Injuries and Damages Expense (Marsh)
61 A&G Office Supplies and Expenses (Marsh)
62 Productivity Improvements (Marsh)
63 Average Salary Increases (Marsh)
64 Rate Case Expense and Amortization Period (Marsh)
66 Incentive Compensation (Marsh)
67 Employee Benefit Expense (Marsh)
68 Accrual for Property Damage (Marsh)
69 Generation O&M Expense (Marsh)
70 Transmission O&M Expense (Marsh)
71 Distribution O&M Expense (Marsh)
73 Amortization Period for Rate Case Expense (Marsh)
75 Test Year Depreciation Expense (Marsh, P. Lee)
76 Depreciation and Fossil Dismantlement Expense (Marsh, P. Lee, Springer)
80 Taxes Other than Income (Slemkewicz)
81 Parent Debt Adjustment (D. Buys)
82 Income Tax Expense (Davis, Slemkewicz)
83 Operating Expenses (Slemkewicz)
84 Net Operating Income (Slemkewicz)
85 Affiliated Transactions (Marsh)
87 Annual Operating Revenue Increase (Slemkewicz)
COST OF SERVICE AND RATE DESIGN
88 Revenues at Current Rates (A. Roberts)
89 Separation of Costs and Revenues (Laux)
90 Cost of Service Methodology (Webb)
91 Cost Allocation Methodology (Draper)
92 Change in Revenue Requirements (Draper)
95 Elimination of Certain Rate Schedules (Piper)
96 Grandfather Certain Terms and Conditions of Rate Schedules (Piper)
98 Customer Charges (Thompson)
100 Temporary Service (Thompson)
101 Premium Distribution Service Charge (Thompson)
107 Time of Use Rates (Kummer)
108 Firm, Interruptible, and Curtailable Standby Service Rate Schedules (Draper)
109 Interruptible Credit (Ellis, Graves, Draper)
110 Interruptible Credit (Draper)
113 Lighting Charges (A. Roberts)
114 Leave Service Action (LSA) Provision (Draper)
115 Revised Rates and Charges (Draper)
115A Chapter 366, Florida Statutes (Fleming, Sayler)
115B Mandate under Section 366.01, Florida Statutes (Fleming, Sayler)
116 Interim Rate Increase (Slemkewicz)
119 Creation of a Regulatory Asset and Deferral of Pension Expenses (Maurey, Fleming)
120 Retroactive Ratemaking (Maurey, Fleming)
121 Double Recovery of Expenses (Maurey, Fleming)
122 Close the Docket (Fleming)
This proceeding commenced on March 20, 2009, with the filing of a petition for a permanent rate increase by Progress Energy Florida, Inc. (PEF 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 jurisdiction of the Commission. PEF’s service area comprises approximately 20,000 square miles in 35 of Florida’s counties. PEF serves more than 1.6 million retail customers.
PEF requested an increase in its retail rates and charges to generate $499,997,000 in additional gross annual revenues. This increase would allow the Company to earn an overall rate of return of 9.21 percent or a 12.54 percent return on equity (range 11.54 percent to 13.54 percent). The Company based its request on a projected test year ending December 31, 2010. PEF stated that this test year is the appropriate period to be utilized because it represents the conditions to be faced by the Company, and is representative of the customer base, investment requirements, and overall cost of service to be realized for the period when the new rates will be in effect.
PEF also requested an interim rate increase in its retail rates and charges to generate $13,078,000 in additional gross annual revenues. This increase would allow the Company to earn an overall rate of return of 7.84 percent or a 10.00 percent return on equity. The Company based its interim request on a historical test year ended December 31, 2008. Order No. PSC-09-0413-PCO-EI, issued June 10, 2009, in this docket, suspended the proposed final rates and granted a $13,078,000 interim rate increase.
In PEF’s most recent base rate proceeding in Docket No. 050078-EI,[1] the Commission approved a stipulation and settlement agreement (Stipulation). The Stipulation provides that retail base rates will not increase during the term of the Stipulation except for the recovery of the revenue requirements associated with certain power plants that go into service during the term of the agreement. Essentially, the Stipulation terminates on December 31, 2009.
The Office of the Public Counsel (OPC), the Office of the Attorney General (AG), the Florida Industrial Power Users Group (FIPUG), the Florida Retail Federation (FRF), the Florida Association for Fairness in Rate Making (AFFIRM), the Navy (NAVY), and White Springs Agricultural Chemicals, Inc. d/b/a PCS Phosphate – White Springs (PCS) intervened in this proceeding.
On April 3, 2009, OPC, FIPUG, AG, FRF, and PCS (collectively, Intervenors) filed a joint consolidated response, opposing PEF’s request for interim rate relief, petition related to accounting treatment for pension and storm hardening expenses, and petition for limited proceeding to include the Bartow Repowering Project in base rates. On April 8, 2009, the parties and staff met to discuss the Intervenors’ joint consolidated response. At the meeting, staff noted that while a response to a response is not normally contemplated by the Commission’s rules, it might be helpful for PEF to file some additional clarifying comments regarding the Intervenors’ response. The Intervenors did not object to staff’s request at that time, nor did they file an objection to PEF’s response. PEF filed a response to the joint intervenors consolidated response on April 15, 2009. Order No. PSC-09-0415-PAA -EI,[2] issued June 12, 2009, consolidated Docket No. 090144-EI with Docket No. 090079-EI. In addition, Order No. PSC-09-0586-PCO-EI,[3] issued August 31, 2009, consolidated Docket No. 090145-EI with Docket No. 090079-EI.
10 customer service hearings were held at the following locations and dates: Lake Wales, July 7, 2009; New Port Richey, July 8, 2009; Live Oak, July 9, 2009; Lake Mary, July 15, 2009; St. Petersburg, July 16, 2009; Clearwater, July 16, 2009; Ocala, July 17, 2009; Citrus County, July 17, 2009; Apalachicola, July 30, 2009; and Tallahassee, September 21, 2009. The Technical Hearing was held in Tallahassee on September 21-25, 28-30, 2009 and October 1, 2009.
On October 2, 2009, Governor Charlie Crist sent a letter requesting that the Commission postpone its decision on the rate increase until the two newly appointed Commissioners take office. All parties were invited to brief the Commission on the topics of whether the Commission could postpone the decision on the rate case, and whether PEF could implement rates, subject to refund. Staff’s recommendation regarding the Governor’s request was considered at the October 27, 2009, Agenda Conference. Order No. PSC-09-0753-PCO-EI, issued November 16, 2009, in this docket, recognized that PEF could increase its rates on January 1, 2010, subject to refund. However, the Commission requested and directed PEF to do everything that it could to minimize any potential impact on ratepayers in the short-term.
In response to the Commission’s request, PEF filed a Motion for Expedited Approval of a Regulatory Asset or Liability as an Alternative to Implementing Rates Subject to Refund Pursuant to Section 366.06(3), F.S., (Motion) on November 2, 2009. OPC filed a response to PEF’s Motion on November 9, 2009. The Commission is scheduled to consider staff’s recommendation at the December 1, 2009, Agenda Conference.
This recommendation addresses the requested permanent rate increase. The Commission has jurisdiction pursuant to Sections 366.06 and 366.071, F.S.
Approved Stipulations
The Commission has previously approved several stipulated issues. The stipulated issues are reflected later in the recommendation as “Stipulated” in sequential order of the approved numbering of the issues, pursuant to the Prehearing Order No. PSC-09-0638-PHO-EI, issued September 18, 2009, and subsequent decisions by the Commission at the Technical Hearing held on September 21-25 and September 28-October 2, 2009. Also, a consolidated list of all stipulations is attached as Appendix 1.
DROPPED.
Is PEF's projected test period of the twelve months ending December 31, 2010 appropriate? (Category 1 Stipulation)
Approved Stipulation:
Yes. The twelve months ended December 31, 2010 is the appropriate test year. (AFFIRM, FIPUG, NAVY, and PCS do not affirmatively stipulate this issue, and took no position.)
What are the appropriate inflation, customer growth, and other trend factors for use in forecasting? (Category 2 Stipulation)
Approved Stipulation:
The appropriate inflation, customer growth and other trend factors for use in forecasting are those included in the MFRs, as filed.
Are PEF's forecasts of customer growth, KWH by revenue class, and system KW for the projected test year appropriate? (Category 2 Stipulation)
Approved Stipulation:
Yes.
Are PEF's forecasts of billing determinants by rate class for the projected test year appropriate? (Category 2 Stipulation)
Approved Stipulation:
Yes.
Is the quality and reliability of electric service provided by PEF adequate?
Recommendation:
Yes. Based upon the analysis of customer complaints, the objective measurements of the System Average Interruption Duration Index (SAIDI), the System Average Interruption Frequency Index (SAIFI), the Customer Average Interruption Duration Index (CAIDI) relating to PEF’s distribution system, and the four indices for the transmission system that include Circuit-SAIDI, Transmission-SAIFI, Momentary interruptions or SAIFI-M, and the System Average Restoration Index (SARI), the quality and reliability of the electric service provided by PEF is adequate. (Vickery, C. Lewis, Moses)
Position of the Parties
Yes. PEF has gone beyond the provision of adequate service, steadily improving performance in several key areas. Today, the Company provides high quality, reliable electric service that is in the top quartile in the industry in many indices.
OPC:
No position.
AFFIRM:
No position.
AG:
No. Many customers testified about concerns with the service quality of Progress. Although Progress indicated that it had resolved most concerns since the hearing, it also agreed that customers should not have needed to attend a service hearing to have their concerns addressed. Progress emphasized the many means available to address customer complaints, but many customers attending the hearings testified that they had not yet had their concerns addressed. More significantly, although Progress refers to J.D. Power’s ratings of its customer satisfaction, the recent J.D. Power report, EXH 265, indicates that residential customers rank their satisfaction with Progress below average for its segment of South Region—Large Utilities. Of some concern is the fact that Progress, with a score of 619, ranks substantially below its sister company, Progress Energy Carolinas, which scored 657. Mr. Dolan testified that this low ranking may be attributable to customer dissatisfaction with Progress’s rates, rather than quality of service, TR 261, but this does not change the fact of the low ranking. Neither does it put to rest the poor manner in which Progress addressed the many customer complaints regarding such issues as vegetation overgrowth and the manner in which the company undertook repairs. Progress’s head of customer service testified that it would make repairs only if the customer had purchased two levels of surge protectors provided by the company at a substantial expense. This testimony conflicts with the testimony of Mr. Dolan, who stated that the company would make repairs for damage Progress had caused even if the customer had not purchased the company’s surge protectors. This conflict should be of concern to the Commission since it clearly reflects the potential for inconsistent handling of identical complaints, which could result in customers not receiving consistent and acceptable service. The testimony of the Progress customer service representative is consistent with the testimony of customers who complained about the lack of response and company’s refusal to cover damages suffered. The testimony of the customers is sufficient for this Commission to require Progress to implement programs to address its persistent vegetation overgrowth problems prior to it impacting service.
FIPUG:
No position.
FRF:
Based on the available evidence, while PEF’s customers raised serious concerns about PEF’s service quality, objective measures indicate that the quality and reliability of service provided by PEF is adequate.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
Only PEF, AG and FRF, took positions on this issue.
PEF witness Dolan stated the reliability of PEF continues to improve by reducing a reliability index known as the System Average Interruption Duration Index (SAIDI) by 40 percent since 1997. (TR 121) As shown in EXH 49, the 1997 SAIDI indicates an average interruption on the system lasted for 127 minutes whereas in 2008 an average interruption lasted for 76 minutes. This represents a reduction (51 minutes) in the length of time the system was out of service. (TR 121) SAIDI is a system-wide indicator concerning the distribution of electricity and it reflects the average length of time for an outage on the distribution system. The length of time an outage occurs on the distribution system is a key indicator of overall performance.
PEF witness Joyner testified that the distribution system delivers power to approximately 1.6 million customers across a service area that is over 20,000 square miles. The system includes 18,000 circuit miles of overhead primary voltage distribution conductors, approximately 13,000 miles of underground primary voltage distribution cable, distribution substations and related poles, transformers, cables, wires, and other material and equipment ranging from bucket trucks to pickup trucks. (TR 655) He sets the stage for PEF’s service reliability by explaining the “Commitment to Excellence (CTE)” program that was developed in 2002-2004 and expanded in 2005 to seven reliability initiatives in order to build upon the CTE program’s success. The seven reliability initiatives are listed below:
· A maintenance program on its underground network
· Replacement of annealed conductors
· An infrared scanning program to replace high current connection points
· An underground cable replacement program
· A capacitor maintenance program to account for growth
· An infrastructure capacity planning program for customer growth
· An increase in vegetation management
(TR 656-657)
Witness Joyner also stated that PEF uses the electric utility industry standards to measure reliability of the distribution system. The industry standards include (1) the System Average Interruption Duration Index (SAIDI) as discussed by witness Dolan; (2) the System Average Interruption Frequency Index (SAIFI) which measures the number of interruptions a customer experiences; and (3) Customer Average Interruption Duration Index (CAIDI), which represents the average length of time an interruption lasts for a customer. (TR 658)
Additionally, PEF has the Customer Reliability Excellence Monitor (CREM) program. The CREM program tracks the outages for those customers that experience more than four outages within a year. This measure is known as the Customers Experiencing Multiple Interruptions greater than four (CEMI4). The Momentary Average Interruption Frequency Index (MAIFIe) and Customers Experiencing Long Interruption Durations greater than three hours (CELID3) are also recorded. Witness Joyner testified that the CREM program seeks to balance reliability improvements and to focus on the reliability metrics that matter the most to PEF’s customers. (TR 658)
Witness Joyner also stated setting a goal of 80 minutes for SAIDI is a key component of the reliability program being measured by CREM and maintained by CTE. Specifically, the SAIDI was reduced by 23 percent in 2004 and PEF continues to hold the SAIDI below 80 minutes in the years 2005, 2006, 2007, and 2008. PEF’s reliability metrics were provided in EXH. 65 for the years 2000 through 2008. (TR 659) Witness Joyner stated that PEF maintains a reliable system at a reasonable cost and that the Commission’s storm hardening initiatives require aggressive wooden pole inspections and vegetation management that is beyond the established electric utility practices. Witness Joyner testified that vegetation management and specifically PEF’s Commission approved Integrated Vegetation Management (IVM) program has trimmed over 11,000 miles of overhead lines or 62 percent of the total requirement. (TR 667-669)
Witness Oliver stated that PEF’s transmission system is an interconnected interstate and intrastate electric power network that allows utilities to exchange power. The interstate and intrastate connections require the transmission system to be subject to regulation by the Federal Energy Regulatory Commission (FERC) and the Florida Public Service Commission. The system is composed of about 5,000 circuit miles of transmission lines operating in the 500, 230, 115, and 69 kilovolt (KV) ranges. The Florida transmission system is spread across 20,000 square miles and provides service to the other Investor Owned Utilities (IOU), twenty-two municipal electric utilities, and nine rural electric cooperatives. PEF’s transmission system delivers generated power to be distributed to its customers’ homes and businesses around-the-clock, each day. (TR 555)
In order to gauge PEF’s effectiveness in providing reliable transmission, PEF utilizes electric industry reliability measures or indices. The indices include (1) the Circuit System Average Interruption Duration Index or Circuit-SAIDI. The Circuit-SAIDI index tracks the average duration of a transmission system outage; (2) the System Average Interruption Frequency Index or SAIFI, which tracks the average frequency (number) of transmission caused outages; (3) the System Average Interruption Frequency Index for Momentary interruptions or SAIFI-M, which tracks the average frequency of transmission caused outages of less than a minute; and (4) the System Average Restoration Index or SARI, which tracks the time required to re-energize the circuits following an outage. (TR 557)
In reference to the indices above, PEF witness Oliver testified that for the last completed five-year window that ended in 2007, the results indicated across the board reliability improvements for the transmission system. Circuit SAIDI decreased by 23.4 percent, SAIFI decreased by 7.9 percent, SAIFI-M decreased by 10.1 percent, and SARI decreased by 20.6 percent. Witness Oliver states that these indices demonstrate that PEF is providing its customers with reliable transmission service. (TR 558)
The AG argued that when PEF points to its ratings for customer satisfaction, in the recent J.D. Power Report, EXH 265, that in reality the ranking is below average for its segment of South Region—Large Utilities. The AG also argued that a PEF score of 619 ranks substantially below the score of Progress Energy Carolinas which scored 657. In explaining the difference, PEF witness Dolan testified that this low ranking may be attributable to customer dissatisfaction with Progress’s rates, rather than quality of service. (TR 261)
The AG argued that PEF did a poor job of addressing the customer complaints raised at the service hearings. Regarding the Lake Mary Service Hearing and PEF’s power surge protection program, the AG expressed concern over the fact that two levels of power surge protection were required before PEF would pay any claims for damages. Also, the AG argued there were differences in the processing of customer claims. The differences were identified during PEF witness Dolan’s explanation on how a claim would be handled versus the customer service representative and the requirements of the power surge program. (AG BR 4)
FRF argued in its brief that PEF has a low customer satisfaction rating. FRF utilized the J.D. Power Report, EXH 265, and the number of customers that expressed concerns about the reliability of their electric service during the service hearings. FRF also noted that PEF’s segment of the South Region – Large Utilities and PEF’s score of 619 was identified as being significantly lower than Progress Energy Carolinas score of 657. However, FRF concluded that the objective measurements of service reliability indicate that PEF’s service quality is adequate. (FRF BR 51)
ANALYSIS
The quality and reliability of the electric service provided by a utility is objectively measured through the use of electric industry reliability indices and the number and types of customer complaints. The Commission has established specific requirements and reliability indices for both the transmission and distribution system of a utility (found within Rule 25-6.0455, F.A.C.). The reliability indices track the duration and frequency of power interruptions and are typically examined at a system level. SAIDI, SAIFI, and CAIDI are the most common indices and are, in reality, measures of unreliability such that as the indices increase, reliability becomes increasingly worse. All of the indices provide information about average system performance over a specific time period and that it is best to examine the current results of a single utility and to make a determination as to whether the trend of the current and past results are improving or worsening. However, using averages as the sole basis for decision making can mask the interruption for a specific customer. In determining the reliability and adequacy of PEF’s electric service, staff notes that PEF’s service territory covers approximately 20,000 square miles and that the utility serves over 1.6 million customers. Therefore, an individual customer’s outage experience is averaged within the system indices.
Service Hearings and Complaints
The AG approached the determination of PEF’s service quality and reliability from the single dimension of customer satisfaction/complaints whereas FRF included objective measurements of system service reliability and customer satisfaction. Both parties argued that the J.D. Power and Associates Report for customer satisfaction indicated that PEF had a rating of 619 whereas Progress Energy Carolinas had a rating of 657 and that the relative position of PEF below Progress Energy Carolinas is significant. (AG BR 4; FRF BR 51) Staff finds it extremely difficult to compare utilities in two different states and believe that the numbers serve to merely rank the companies among other utilities regarding customer satisfaction and that no determination was made as to whether the service reliability was adequate. Witness Dolan testified that PEF was in the first or second quartile of residential customer satisfaction for the past six years according to the J.D. Power and Associates Report. (TR 122) FRF does conclude that the objective measurements of service reliability indicate that PEF is providing adequate service reliability. (FRF BR 51)
The AG argued that customers should not have to come to a public service hearing to have their complaints heard. (TR 703) Approximately 300 customers expressed their displeasure with either PEF’s requested rate increase or problems with PEF’s electric service. The electric service related problems involved 18 customers. (TR 704) Staff agrees with the AG to the extent that customers should not have to appear at a public service hearing to have their complaints heard. The typical customer complaint is either handled directly by PEF and its customer service agents or as staff witness Hicks testified by the Commission’s Bureau of Consumer Assistance. The function of the Bureau of Consumer Assistance is to resolve disputes between regulated companies and its customers. In her testimony, witness Hicks identified several programs for complaint resolution other than PEF’s service hearings. These included the Commission’s Transfer-Connect (Warm Transfer) System and the Consumer Activity Tracking System that logs and tracks the customer’s complaint until it is resolved. The Transfer Connect system allows the Commission to put the customer in immediate contact with the Utility’s customer service personnel. (TR 2329) In response to the service hearings, PEF filed a Customer Service Hearing Report to document the corrective actions taken. (EXH 270)
PEF witness Joyner explained several customer service complaints from the PEF’s service hearings and in reference to the Clearwater Service Hearing, he stated that PEF met with the individual experiencing surge related issues and offered to change out his service drop. (TR 704-705; EXH 270) Witness Joyner also stated that in the Lake Mary Service Hearing a customer alleged that a computer was damaged by PEF because of momentary interruptions. (TR 706) The investigation revealed that the customer was participating in PEF’s Meter Base Protection (MBP) program and that the customer had a large scale suppression device on the meter base, but that the small appliance (computer) did not have an individual surge suppressor. The meter base protection mitigates power surges of a large scale; however, individual suppressors are still recommended for those high voltage spikes that on occasion make it through the meter base protector. (TR 707) Staff notes that there is a difference between power surges which may occur due to lightning strikes and momentary interruptions. The momentary interruptions are typically caused by tree branches striking the line, an animal contacting a live circuit, equipment failure, or an automobile hitting a pole. Power surges cause an increase in voltage whereas a momentary interruption causes a loss of power. In this complaint and for every complaint, witness Joyner testified there are direct standards in which PEF will be held accountable for a claim. He also stated the investigation is the actual determinate of the claim and not whether the customer had two levels of surge suppression. (TR 708-709) The AG argued that two of PEF’s witnesses testified to different procedures for processing a claim. Staff agrees that there are different procedures, one for processing claims made to PEF for customers that are participants in the MBP program and customers that are filing a claim. However, as witnesses Dolan and Joyner testified, the claim investigation is the ultimate determinate as to whether PEF will pay a claim. (Dolan TR 161; Joyner TR 708)
Additional service issues included outages purported to be caused by the lack of tree trimming. (TR 710) Witness Joyner stated that there were cases where PEF had scheduled tree trimming based upon its cyclic schedule for vegetation management and that in several cases the tree trimming was scheduled for the first half of 2010. (TR 710) PEF indicated that all of the service related problems identified at the customer service hearings were corrected by PEF. (EXH 270)
Staff witness Hicks provided Exhibits 206 and 207 concerning customer complaints reported to the Commission for a two year period from July 1, 2007 to June 30, 2009. She stated that 4,386 of the 5,611 complaints were warm-transferred directly to PEF for resolution via the Commission’s Transfer Connect Program. Approximately 37 percent or 2,052 of the total complaints were service quality issues. (TR 2328) An analysis of the PEF’s service reliability complaints in Appendix B of the Commission’s annual report “Review of Florida’s Investor-Owned Electric Utilities’ Service Reliability in 2007” indicates that the service reliability complaints since 2004 are trending downward. The service reliability complaints were categorized and included service interruptions, quality of service, repair, safety, and trees. (EXH 20, BSP 71–75)
Staff does not discount the importance of each customer comment and problem expressed at the service hearings or recorded in the docket file; however, the overall number of service reliability related complaints has decreased since 2004. Staff believes the customer complaints are reflected in the reliability indices known as SAIDI, SAIFI and CAIDI recorded in PEF’s distribution system. The electric utility indices described below are required by Rule 25-6.0455, F.A.C., and include a trend analysis for a five year period from 2004 through 2008.
Reliability Indices
The electrical system reliability indices are identified by acronyms and each is the result of a mathematical computation. PEF presented indices for both the transmission system and the distribution system. The transmission system was evaluated using several indices. First, the Circuit System Average Interruption Duration Index or Circuit-SAIDI tracks the average duration of a transmission system outage. Second, the System Average Interruption Frequency Index or SAIFI tracks the average frequency (number) of transmission caused outages. Third, the System Average Interruption Frequency Index for Momentary interruptions or SAIFI-M tracks the average frequency of transmission caused outages of less than a minute. Finally, the System Average Restoration Index or SARI, tracks the time required to re-energize the circuits following an outage. (TR 557) No party disputed witness Oliver’s testimony that PEF’s transmission system reliability indices had across the board improvements for the five year period beginning in 2003 and concluding in 2007. (TR 557-558)
Witness Joyner provided the indices that were used to evaluate the distribution system: SAIDI, the System Average Interruption Duration Index is calculated by dividing the customer minutes of interruption (CMI) by the number of customers (C) served by the system (SAIDI = CMI ÷ C). SAIFI, the System Average Interruption Frequency Index is calculated by dividing the number of service interruptions (CI) by the number of customers (C) served (SAIFI = CI ÷ C). CAIDI is the last index and it is known as the Customer Average Interruption Duration Index. CAIDI is calculated by dividing the total system customer minutes of interruption (CMI) by the number of interrupted customers (CI), (CAIDI = CMI ÷ CI). (EXH 65)
PEF witness Joyner identified two additional programs, Customer Reliability Excellence Monitor (CREM) and Commitment to Excellence (CTE) that are utilized by the utility in determining electric reliability. The CREM program appears to be more customer oriented than the Commission’s reporting requirements in that CREM tracks service interruptions for customers that experience more than four momentary interruptions on a yearly basis; whereas, the Commission requires that the IOUs report customer interruptions that are greater than five momentary interruptions. For those customers experiencing multiple momentary interruptions, triggering reporting on four interruptions versus five allows the Company to assess the impact of momentary interruptions sooner in order to maintain the overall system reliability.
PEF also utilizes goal setting for one of its distribution reliability indices. PEF set the SAIDI goal for the distribution system to 80 minutes in order to ensure that PEF is providing reliable distribution service. (TR 658-659) Staff believes this is a noteworthy approach and that goal setting appears to benefit PEF’s customers by maintaining the SAIDI below 80 minutes for the past five years as seen in Figure 1 below.
Figure 1 SAIDI
Figure 1 illustrates the average length of time, in minutes, for an outage or interruption on PEF’s distribution system. For example, in 2004, when an outage on the system occurred, the outage would last an average of 77 minutes. The years 2005 through 2008 are also between 74 and 78 minutes. Plotting a linear trend line from the data indicates the SAIDI trend is relatively flat across the 76 minute axis. (EXH 65) Staff concludes that when an outage occurs on PEF’s distribution system, the length of time for the outage has remained fairly stable over the last five years. This is indicated by the trend line along the 76 minute axis.
The average number of interruptions on the distribution system is graphically illustrated in Figure 2. The SAIFI index is relatively flat and is trending downward for the last five years. The numbers of interruptions a customer experiences, on average, has steadily decreased from 1.19 interruptions in 2004 to 1.05 in 2008. (EXH 65; EXH 20, BSP 71-75)
Figure 2 SAIFI
A graphical analysis of CAIDI, shown in Figure 3, indicates that the duration of a customer’s average interruption has increased from a low of 65 minutes in 2004 to a high of 72 minutes in 2008. The CAIDI index is slightly increasing for the last five years; however, in 2006 and 2007 it remained unchanged. Staff also examined the data found in the “Review of Florida’s Investor-Owned Electric Utilities’ Service Reliability in 2007.” (EXH 20, BSP 71-74) Plotting a CAIDI trend line for the period of 1997 through 2008 indicates that CAIDI is trending downward. The 1997 CAIDI was reported as 75, in 2008 the CAIDI was reported as 72 and the highest CAIDI reported between 1997 and 2008 was recorded in the year 2000 which was 75.4 minutes. Staff believes that examining a broad range of years (5 to 10) is appropriate when trying to assess an electric utility’s system reliability. The determination of the adequacy of PEF’s service quality and reliability involves more than a single dimension or index. All of the indices for the distribution system and the transmission system coupled with PEF’s customer service complaints indicate the adequacy of PEF’s service quality and reliability.
Figure 3 CAIDI
CONCLUSION
Based upon the analysis of customer complaints, the objective measurements of the System Average Interruption Duration Index (SAIDI), the System Average Interruption Frequency Index (SAIFI), the Customer Average Interruption Duration Index (CAIDI) relating to PEF’s distribution system, and the four indices for the transmission system that include Circuit-SAIDI, Transmission-SAIFI, Momentary interruptions or SAIFI-M, and the System Average Restoration Index (SARI), staff recommends that the quality and reliability of the electric service provided by PEF is adequate.
Should the current-approved depreciation rates, capital recovery schedules, and amortization schedules be revised? (Category 1 Stipulation)
Approved Stipulation:
Yes. The parties’ positions on how they should be revised are set forth in subsequent issues. (AFFIRM did not affirmatively stipulate to this issue, and took no position.)
What are the appropriate capital recovery schedules?
Recommendation:
Staff recommends capital recovery schedules to address the net unrecovered investments associated with the retirement of the Avon Park and Bartow steam plants, the upgrade at Crystal River Units 4 and 5, and the Crystal River Unit 3 steam generator replacement. Staff also recommends recovery schedules to address the negative reserve amounts existing in Meters, Account 370, and Power Operated Equipment, Account 396. Staff recommends that existing reserve surpluses in the production plant and the distribution plant functions, as discussed in Issue 15, can be used for the immediate recovery of the Avon Park, Bartow, Crystal River Units 4 and 5, Crystal River Unit 3, meters, and power operated equipment unrecovered net investments, respectively. (P. Lee)
Position of the Parties
PEF:
None, as PEF has not proposed any capital recovery schedules.
OPC:
The appropriate recovery schedules should be revised consistent with recommendations of OPC witness Jacob Pous. This issue should be a “fallout issue” that takes into account the Commission’s consideration of, and explicit rulings on the specific depreciation-related issues.
AFFIRM:
No position.
AG:
The appropriate capital recovery schedules are those recommended by Jacob Pous.
FIPUG:
The capital recovery schedules should be revised consistent with the recommendations of witnesses Pous and Pollock outlined in the following issues. Further, this should be a “fallout issue” that takes into account the Commission’s consideration of, and explicit rulings on, the specific depreciation-related issues that OPC and other parties have raised and addressed through testimony and participation in this proceeding.
FRF:
The appropriate capital recovery schedules are those recommended by witness Jacob Pous on behalf of the Citizens of the State of Florida.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
Rule 25-6.0436(10)(a-c), F.A.C, provides that capital recovery schedules may be used to recover the unrecovered amounts associated with the near-term retirement of major installations. This issue addresses the appropriate recovery schedules to be approved for PEF. PEF and OPC are the only parties that provided testimony addressing the appropriate capital recovery schedules.
PARTIES’ ARGUMENTS
PEF witness Robinson asserted that he does not believe capital recovery schedules are appropriate and, furthermore, PEF has not proposed any. For these reasons, witness Robinson believed no capital recovery schedules should be approved. Additionally, witness Robinson disagreed with the Commission’s long-standing practice of using capital recovery schedules. Witness Robinson averred that remaining life depreciation rates will provide recovery; nothing more is needed. (TR 3532; EXH 36, BSP 1039)
OPC asserted that this issue is a fall-out of the specific depreciation issues and should be consistent with the recommendations of witness Pous. The witness testified that the remaining life recovers the remaining unrecovered balance over the remaining life of the property. (TR 2033)
The AG, FRF, and PCS did not sponsor testimony relating to capital recovery schedules, but adopted the position of OPC in their briefs. (AG BR 5; FRF BR 31-32; PCS BR 4) Affirm and Navy did not take a position.
ANALYSIS
Under the capital recovery schedule mechanism, the investment and associated reserve of installations facing near-term retirement are separated out as sub-accounts, and the unrecovered net amounts are amortized over the period of their remaining service to the public. The mechanism has been in the Commission’s depreciation rules, and has been the standard practice of the Commission, for over 20 years. (TR 2175) PEF witness Robinson asserted that capital recovery schedules are not needed; remaining life will provide full recovery. (EXH 20, BSP 71-75; EXH 36, BSP 1039) Staff agrees that remaining life will provide recovery over the remaining life of the given account or the given group of assets. However, to the extent a company’s planning changes, so should the remaining period of recovery.
The purpose of depreciation is to match expenses to the period the assets associated with those expenses are providing service to the public. Under group depreciation, it is recognized that some assets within the group will experience a life shorter than the average while others will experience a life longer than the average. (EXH 36, BSP 1132) However, if there is a group of assets planned for near-term retirement that now have a significantly shorter life than the overall group life, the associated investments should be withdrawn from the group and recovered over their expected life as provided by the Commission’s rules.
The record in this proceeding shows that the remaining life mechanism is designed to recover the net investment over the remaining life of the group or account. (Robinson TR 3532; Pous TR 2042) Staff believes that recovery over the remaining period of service is in fact the remaining life methodology. This is the principle of matching expenses to consumption. If assets retire earlier than the average life of the group without recovery afforded, a negative reserve component is created. The negative reserve component translates into a positive rate base element. From the Company’s standpoint, it will continue to earn a return on this non-existent plant over the life of the group. From the ratepayers’ standpoint, they will continue paying for plant no longer providing service until the situation is corrected. Negative reserve amounts are non-life related net investments that the Commission has historically corrected as fast as practicable to remedy the existing intergenerational inequity.[4]
Utilities are required by Rule 25-6.0436, F.A.C., to file a depreciation study at least once every four years from the date of the last filed study. Because of rate case settlements in 2002 and 2005, the last depreciation study for PEF (then Florida Power Corporation, FPC) that underwent Commission review was in 1997. In that case, the Company itself proposed capital recovery schedules, clearly recognizing the advantage of the Commission’s provided mechanism. In FPC’s 1997 depreciation study,[5] revised depreciation rates and recovery/amortization schedules were approved for FPC, with an effective date of January 1, 1998. The Company’s proposed recovery schedule concerning the net unrecovered assets of the Suwannee River Steam Production units was approved. In this instance, a four-year amortization, representing the time period between depreciation studies, was approved, even though Company planning indicated continued operation through 1999. Two additional recovery schedules were approved and related to the recovery of assets that were not viable for reuse with the repowering of the Higgins and Turner plants. The approved recovery period for these schedules represented the “remaining service period of the related assets.[6]”
In the instant case, PEF has not proposed any capital recovery schedules. In response to staff discovery, PEF asserted that the Bartow Steam Units 1-3 are now planned for retirement in 2009 rather than 2016. (EXH 36, BSP 1048) PEF stated that it “is proposing updated Steam Production depreciation rates which when adopted will effectively recover the remaining unrecovered net investment associated with these retired assets over the useful life of the plants in the Steam Production depreciation group.” (EXH 36, BSP 1039) Thus, PEF proposed that the recovery of the net investments no longer providing service be over the remaining life of the all steam production plant, including the new replacement plant. When staff inquired through discovery about PEF’s planning for near-term retirements in connection with major upgrades or overhauls, the response was basically non-responsive. (EXH 43, BSP 1783) PEF objected to the request and identified only upgrades taking place in 2010. Staff is puzzled by PEF’s attitude concerning a mechanism that is intended to work in conjunction with remaining life and ensure full recovery.
Staff notes that Table 5F-Future (Pro Forma) of PEF’s depreciation study shows several accounts with estimated negative reserves as of December 31, 2009. (EXH 84, Section 2, pp. 2-67 - 2-73) According to PEF witness Robinson, the negative reserve for Avon Park, Account 311, was an error and should be negative $5,410,811. The negative reserve amounts for Bartow, Accounts 311, 312, 314, and 316, are due to the unrecovered amounts at its 2009 retirement. Witness Robinson admits that these negative reserve amounts are not associated with plant that is serving the public. These negative amounts are associated with investments retired earlier than provided in the remaining life rate design. (EXH 36, BSP 1048, 1129, 1136; TR 1216-1219) These unrecovered amounts create positive rate base components, upon which the Company continues to earn a return. (EXH 36, BSP 1129; TR 1219-1221) Witness Robinson commented that the Bartow Steam unrecovered amounts are being distributed to the other properties within the plant account and recovered over the remaining life of the applicable group. (TR 1220-1221) This action was not specifically proposed or discussed in the depreciation study (EXH 84, Section 4, pp. 4-1 – 4-10, 4-21 – 4-32). Witness Robinson’s proposal will ultimately recover the negative reserve amounts, but that recovery will be over the remaining life of all accounts. Staff believes that these unrecovered costs associated with the repowering of Bartow do not relate to the peaking or new combined-cycle plants. In this case, these assets will be recovered after they have been retired and are no longer serving the public. Staff believes that deferring recovery to the future is not good depreciation practice and is tantamount to mortgaging the future. Staff believes these net investments should be recovered as fast as practicable. As discussed in further detail in Issue 15, staff believes a portion of the reserve surplus existing in PEF’s production plants can be used to fully recover these unrecovered costs associated with the retirement of the Avon Park and Bartow steam plants.
Crystal River Units 4 and 5 are in the process of a major upgrade that will be completed in 2010. The upgrade includes adding a flue gas desulfurization system and scrubber at the units. As a result of the upgrade, PEF has identified investments of $21.2 million that will retire in 2009. The reserve associated with these investments is $15.3 million, resulting in a net unrecovered amount of $5.9 million as of December 31, 2009. (EXH 36, BSP 1033-1036) Staff recommends that the reserve surplus existing in the production accounts discussed in Issue 15 be used to recover the associated unrecovered costs relating to plant no longer providing service.
In response to staff discovery, PEF identified $15.2 million retiring associated with the steam generator replacements at Crystal River Unit 3 (CR3) in 2009.[7] The projected estimated reserve at retirement is $12.6 million, not including removal costs. (EXH 22, BSP 98, 99, 103; EXH 36, BSP 1131) Staff believes the $2.6 million unrecovered cost should be recovered ideally over the remaining period in service. In this case, however, new depreciation rates are being prescribed effective January 1, 2010, after the generator’s retirement. For this reason, this net unrecovered investment relates to plant no longer in service. Staff believes these unrecovered net investments should be recovered as fast as practicable as they represent plant no longer in service and, like the Bartow retirements, result in a negative rate base component. Staff recommends that the reserve surplus existing in the nuclear production function discussed in Issue 15 be used to recover the associated retiring steam generator net investments.
PEF’s depreciation study also identified a negative reserve for Account 370, Meters, in the amount of $11,443,192, and Account 396, Power Operated Equipment, in the amount of $3,221,612. (EXH 84, Section 2, Table 4F-Future Pro Forma, pp. 2-67 – 2-73) The negative reserve for Meters is the result of the Automatic Meter Reading (AMR) upgrades that occurred in 2006. (EXH 36, BSP 1040, 1044-1045) For Account 396, Power Operated Equipment, the specific cause for the account’s negative reserve is not known and is not addressed in PEF’s depreciation study. Nevertheless, both negative reserve amounts represent plant no longer providing service to the public, and thus recovery through a capital recovery schedule is recommended. Staff believes that recovery of net investments such as these should be recovered as fast as practicable. As discussed in further detail in Issue 15, staff believes the reserve surplus existing in other distribution accounts can be used to fully recover this negative reserve.
The net unrecovered investments discussed above are associated with plant no longer providing service. Under PEF’s proposal, these costs would be recovered over the remaining life of the replacement plant, perhaps as long as 30 years. Staff believes that ratepayers should not continue to bear the recovery of these costs of plant no longer in service while not receiving any benefits. Staff believes these costs should be recovered as fast as practicable.
CONCLUSION
Staff recommends capital recovery schedules to address the net unrecovered investments associated with the retirement of the Avon Park and Bartow steam plants, the upgrade at Crystal River Units 4 and 5, and the Crystal River Unit 3 steam generator replacement. Staff also recommends recovery schedules to address the negative reserve amounts existing in Meters, Account 370, and Power Operated Equipment, Account 396. Staff recommends that existing reserve surpluses in the production plant and the distribution plant functions, as discussed in Issue 15, can be used for the immediate recovery of the Avon Park, Bartow, Crystal River Units 4 and 5, Crystal River Unit 3, meter, and power operated equipment unrecovered net investments, respectively.
Is PEF's calculation of the average remaining life appropriate?
Recommendation:
Yes, Staff recommends that PEF’s calculation of the average remaining life is appropriate. (P. Lee)
Position of the Parties
PEF:
Yes, PEF calculated the average remaining life consistent with Commission rules and precedent.
OPC:
Yes. However, the OPC does not agree with the assumptions and inputs used; the methodology and the math appear to be correct.
AFFIRM:
No position.
AG:
Support OPC’s position.
FIPUG:
No. PEF has understated the life spans for its coal and combined cycle plants and overstated its depreciation requirements.
FRF:
Yes, but only to the extent that the methodology and arithmetic appear to be correct. The FRF does not agree with the assumptions and inputs used in the calculation.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
PEF asserted that its depreciation study was prepared in accordance with the Rule 25-6.0436, F.A.C. The Company argued that the Commission has followed the remaining life method for depreciation rate setting purposes for over 20 years. (PEF BR 23)
OPC and FRF argued that PEF’s mathematical calculation of remaining life appears correct. However, PEF’s assumptions and inputs used in determining the remaining life are not appropriate. (OPC BR 11; FRF BR 31-32) FIPUG argued in its brief that PEF’s calculation of the average remaining life is not appropriate because the Company understated the life spans of its coal and combined cycle units. (FIPUG BR 6) The AG and PCS adopted the position of OPC in their briefs. (AG BR 5; PCS BR 4) No other party briefed this issue.
ANALYSIS
This issue addresses whether PEF’s mathematical calculation of the average remaining life is appropriate. Testimony proffered by PEF and OPC discussed the determination of the remaining life. (EXH 84, Section 6, pp. 6-1 – 6-175, Section 9, pp. 9-1 – 9-169; Robinson TR 1100-1114; Pous TR 2034) No other party presented testimony particularly on point with regards to this issue.
While the parties disagreed with the assumptions and inputs to be used in the calculation of the remaining life, their positions indicate that they agree that the calculation itself is correct. (TR 2036-2037) PEF’s assumptions, including life spans, and inputs used in determining its proposed average remaining lives are discussed in Issues 11-13. No party refuted PEF’s mathematical calculation of remaining life. Staff reviewed PEF’s remaining life calculation in its depreciation study and believes the calculation is appropriate. (EXH 84, Section 6, pp. 6-1 – 6-175, Section 9, pp. 9-1 – 9-169)
CONCLUSION
Staff recommends that PEF’s calculation of the average remaining life is appropriate.
What life spans should be used for PEF's coal plant?
Recommendation:
Staff recommends that a 54-year life span should be used for Crystal River Units 1 and 2 and a 60-year life span should be used for Crystal River Units 4 and 5 for determining appropriate life parameters in this proceeding. (P. Lee)
Position of the Parties
PEF:
The appropriate depreciation parameters, amortizations and resulting rates for each production unit are those set forth in the 2009 Depreciation Study filed as Exhibit No. EMR-2 to the testimony of Mr. Robinson.
OPC:
PEF’s proposed life spans of 53.5 and 50.5 years, respectively, for the Crystal River 4 and 5 coal-fired generating units are artificially short. Based on empirical evidence and the treatment afforded such units in other jurisdictions, as well as indications of PEF’s expectations, a 60-year life span is appropriate for coal-fired units.
AFFIRM:
No position.
AG:
Agree with OPC that the appropriate depreciation life span for PEF's coal units is 60 years.
FIPUG:
Based on industry experience and specific examples, the Commission should use a life span of at least 55 years for its coal plants.
FRF:
Agree with OPC that the appropriate depreciation life span for PEF's coal units is 60 years.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
This issue addresses the life spans to use in developing the average remaining lives for PEF’s four coal plants, Crystal River Units 1 and 2 (CR 1 & 2) and Crystal River Units 4 and 5 (CR 4 & 5). These units were placed into service during 1966 (CR 1 & 2), 1982, and 1984, respectively. (EXH 217; EXH 36, BSP 1361)
The life spans are used in the development of the appropriate average remaining lives addressed in Issue 12. Life spans are dependent on the average in-service date and an estimated date of retirement for each unit. The difference between the two is the life span. (Robinson TR 1108-1109; Crisp TR 3524; Pous TR 2024; Pollock TR 3198-3199)
PEF, OPC, and FIPUG offered testimony on life spans. The AG, FRF, and PCS did not proffer testimony but adopted OPC’s position in their briefs. (AG BR 5; FRF BR 31; PCS BR 4) No other party addressed the issue of life spans.
PEF proposed a life span for CR 1 & 2 of 54 years based on a retirement date of 2020. For CR 4 & 5, PEF proposed life spans of 53.5 years for CR 4 and 50.5 years for CR 5, based on a retirement date of 2035. (EXH 84; EXH 36, BSP 1361) OPC proposed a life span of 60 years for PEF’s CR 4 & 5 and has no disagreement with PEF’s life span of 54 years for CR 1 & 2. (Pous TR 2057-2058, 2168) FIPUG proposed a minimum life span of 55 years for both CR 4 & 5 and CR 1 & 2. (Pollock TR 3201) The AG and PCS support OPC’s position.
PARTIES’ ARGUMENTS
PEF witness Robinson testified that he prepared PEF’s depreciation study. (TR 1097, 1133) His tasks included “an investigation and analysis of PEF’s historical plant data, together with an interpretation of PEF’s past experience and future expectations, to determine the remaining lives of PEF’s property.” (TR 1097) The witness stated that his study used historical data, discussions with PEF’s staff and management to identify prior and prospective factors affecting plant, and generally accepted industry standard depreciation methods, procedures, and techniques. (TR 1097)
Witness Robinson testified that the estimated retirement dates of PEF’s generating facilities were determined by PEF operating and planning management. (TR 1110) In the currently filed depreciation study, PEF assumed a retirement date for CR 1 & 2 of mid-2020 and a retirement date for CR 4 & 5 of mid-2035. (EXH 216; EXH 36, BSP 1361; TR 3408) CR 4&5 are in the process of a major upgrade. (EXH 84, Section 4, p. 4-1)
OPC witness Pous and FIPUG witness Pollock asserted that PEF’s life spans for its coal plants are understated. FIPUG and OPC testified that PEF provided no justification for its life spans other than generalized comments about the “uniqueness” of the units. (Pous TR 2024, 2052-2053; Pollock TR 3198-3199) OPC witness Pous affirmed that PEF has operated oil and gas-fired generating facilities for more than 55 years and expects to operate such facilities for more than 60 years. (TR 2053; EXH 216) The witness reasoned that if smaller less efficient units can operate or be expected to operate in this fashion, then newer, larger and costly generating facilities should not be limited to life spans in the low 50-year range. (TR 2053)
FIPUG witness Pollock testified that the life span is the most important assumption in determining appropriate depreciation rates, an assumption not addressed in PEF witness Robinson’s depreciation study. (TR 3161, 3196, 3235-3236) Both OPC witness Pous and FIPUG witness Pollock stated that retirement dates for PEF’s coal units were not indicated in PEF’s 2009 Ten-Year Site Plan, except for the Suwannee plant. (Pous TR 2052; Pollock TR 3199)
OPC witness Pous and FIPUG witness Pollock asserted that PEF’s proposed life spans are contrary to standard economic theory that dictates that large capital-intensive investments should be operated as long as possible to obtain the greatest level of economic benefit. (Pous TR 2053; Pollock TR 3200-3201) OPC witness Pous testified that PEF presented no analysis demonstrating that its large coal, gas or oil-fired units cannot economically operate for a period longer than what was proposed. (TR 2056-2057)
OPC witness Pous testified that empirical data indicate life spans for coal units in the 50-year to 60-year range. (TR 2055-2056) Witness Pous referred to information maintained by the Energy Information Administration of the Department of Energy that demonstrates longer life spans for coal-fired generating units than what PEF has proposed. (TR 2055-2056) Both OPC witness Pous and FIPUG witness Pollock indicated that life spans used by other utilities and other regulatory commissions have ranged from 55 years to 68 years. (Pous TR 2054-2055; Pollock TR 3198-3200; EXH 308) Witness Pollock also noted that the two largest operators of coal plants in the nation, American Electric Power Company and the Southern Company, have determined that life spans of 60 years are appropriate. Finally, witness Pollock asserted that Gulf Power Company is using a 65-year life span for its coal units.[8] (TR 3200) FIPUG believed this evidence indicates that PEF’s proposed life spans are understated, resulting in higher than appropriate depreciation rates. (TR 3199-3200)
OPC witness Pous testified that carbon emission concerns do not appear to have impacted life spans of other coal units across the country and, based on what is known today, coal units should be expected to operate longer than PEF’s estimates. (TR 2056-2057) FIPUG witness Pollock asserted that PEF provided no analysis in its depreciation study as to the impact of trends regarding decreased reliance on fossil fuel and increased regulation of carbon emissions on operation of the coal units. (TR 3230)
PEF witnesses Robinson and Crisp responded to the recommendations of OPC witness Pous and FIPUG witness Pollock. PEF witness Crisp criticized the OPC and FIPUG proposals, although he had no direct role in the preparation of PEF’s depreciation study. (TR 3415, 3492) Witness Crisp asserted that given the small differences between PEF’s proposed life spans and those recommended by the intervenors, PEF’s life spans should be considered reasonable. (TR 3415) The witness testified that he provided witness Robinson the facility service lives of the power plants that were used in the depreciation study, along with projected retirement dates. (TR 3418-3419, 3422, 3427; EXH 216) Witness Crisp asserted that PEF’s estimated lives for its coal units are based on PEF’s expertise and experience with the condition, operation, and maintenance of these units to meet PEF’s load demands under the operational, environmental, and regulatory conditions facing PEF. (TR 3399, 3415) Witness Crisp explained that the addition of flue gas desulfurization (FGD) systems at CR 4 & 5 has resulted in PEF’s expecting a longer operating life (life span) for these units. (TR 3409) The witness also testified that the CR 1&2 retirement date was predicated on a current agreement with the Florida Department of Environmental Protection (DEP) to retire these units upon the commercial operation of Levy Unit 2, a PEF planned nuclear unit. (TR 3409)
Witness Robinson testified that he discussed the service lives for PEF’s generating facilities with the Company’s resource planning group and reviewed materials they provided to him. (TR 3557) Witness Robinson stated that he visited representative PEF generating plants “to observe field operations and obtain local operating input.” (TR 3557, 3618) The witness avowed that OPC witness Pous and FIPUG witness Pollock did not visit PEF’s generating facilities and have not considered the operational, environmental, and regulatory conditions in which the Company operates. (TR 3557) Witness Robinson contended that PEF’s determination of the retirement dates and service lives for its generating facilities was based on its experience and judgment and was the product of an on-going, internal management resource planning process. Witness Robinson emphasized there was no reason for him to substitute his judgment for PEF management in the estimated retirement dates. Witness Robinson asserted that the Commission should not substitute PEF’s judgment with anecdotal information provided and generalizations made by the intervenor witnesses. (TR 3357-3559)
Witness Crisp criticized the intervenor witnesses for using only information from other areas around the country that do not correlate to Progress Energy Florida’s units and do not correlate to the climate, do not correlate to the operating conditions, do not correlate to the load requirements and do not correlate to the regulatory structure of Florida. (TR 3399, 3423) The PEF witness explained that PEF developed the projected retirement dates for its generating units in the course of its regular planning process. This planning process included 1) the specific current condition of each unit; 2) updates, changes, and reconfigurations made at each plant that affect operating characteristics; 3) complexity of operations and maintenance and longer term validity of the units; 4) subtropical operating environment; and 5) bulk system operating requirements and demands placed on the generating plants. These decisions, asserted the witness, reflect PEF’s accumulated past and current experience with operating its units under PEF’s operating, environmental, and regulatory conditions to meet its load demands. (TR 3403-3406) The witness contended that neither OPC witness Pous nor FIPUG witness Pollock have experience with the operations and system planning considerations for PEF and have not visited any of PEF’s generating plants. (TR 3407) In contrast, stated witness Crisp, witness Robinson discussed the resource planning process and PEF’s “estimated service lives” with PEF resource planning staff. (TR 3406-3407) For the foregoing reasons, witness Crisp asserted that there is no reason for the intervenors’ judgment to be substituted for PEF’s judgment. (TR 3399)
ANALYSIS
Staff notes that the retirement date for CR 1&2 is tied to the commercial operation of Levy Unit 2, a PEF planned nuclear unit. For this reason, staff believes that PEF’s retirement date for these units is reasonable to use in determination of the life and salvage parameters for revised depreciation rates. (EXH 36, BSP 976)
However, staff believes that PEF has not supported the life spans for CR 4&5 used in the depreciation study. PEF witness Robinson was hired by the Company to perform its depreciation study. While the witness was the sole sponsor of the study, he received additional information from PEF operations personnel relative to plant operations, including the estimated retirement date for each generating unit. (TR 1133-1134) Even so, staff believes that PEF’s depreciation study and its results rest with witness Robinson, PEF’s depreciation witness.
Witness Robinson agreed that life spans are important in developing depreciation rates. (TR 1192) The witness also acknowledged that PEF’s depreciation study did not include substantive information on PEF’s generating unit life spans because they were provided by PEF. (TR 1194) While the witness could broadly explain how retirement dates are determined, he admitted that these were developed by PEF. Witness Robinson stated that he did not review the life spans provided to him because he was only tasked with performing the depreciation study using the information provided to him. (TR 1109, 1194; EXH 36, BSP 1138) Therefore, staff concludes that PEF’s depreciation study does not contain persuasive supporting information with regards to its proposed life spans.
PEF witness Crisp provided the only support for PEF’s estimated retirement dates and life spans. (EXH 216; TR 3403-3404) Staff observes that the claimed support consists of one page indicating the average in-service date for each generating unit, along with the retirement date assumed in the 2005 depreciation study, the current projected retirement date for use in the instant study, and some broad comments regarding PEF’s plant sites. For example, the retirement dates for CR 4&5 were extended 14 years, from 2021 until 2035. The extent of PEF’s comments for the estimated retirement dates for the Crystal River coal units is “clean air legislation.” (EXH 216; EXH 36, BSP 1360-1361)
As acknowledged by witness Crisp, the specific information supporting PEF’s proposed life spans was not specifically identifiable in Exhibit 216; it was embedded in the exhibit but not disclosed discretely and separately. (TR 3433, 3440-3446) Witness Crisp explained that there are many factors that go into the determination of life spans, including the cost-effectiveness of a given unit and where it fits within certain external drivers, such as climate change, but acknowledged that none of this specific information was discussed in his testimony or his offered support. (TR 3452) Absent this substantive information, staff is unable to conclude whether or not PEF’s life spans are appropriate.
Additionally, while witness Crisp stated that PEF’s service lives reflect the optimum time based on its analyses, it’s Ten-Year Site Plan, and modeling studies, the witness acknowledged that longer life spans as proposed by the intervenors were not considered in PEF’s analysis. (TR 3543-3454) Staff observes that it is therefore unknown whether the intervenors’ proposed life spans would be optimal for PEF’s ratepayers.
Staff believes that the criticisms PEF waged against the intervenors’ proposed life spans can equally apply to PEF. Both OPC witness Pous and FIPUG witness Pollock asserted that based on their review of PEF’s depreciation study, they found that the study did not contain specific information with regards to 1) the condition of PEF’s generating facilities with respect to their life spans, 2) PEF’s expertise in operating or maintaining its generating units, 3) substantiation that PEF has unique load demands or how load demands impact the life spans, 4) updates, changes and reconfigurations made at each plant and how each affects the operating characteristics of the generating units with respect to life spans, 5) how renewable energy requirements may impact the life spans, and 6) the environmental risks PEF faces and how these risks may impact the life spans of the generating facilities. (Pous TR 2179-2181; Pollock TR 3230-3232) Staff believes these omissions are compelling, especially given that PEF witness Robinson acknowledged that the depreciation study did not address or analyze such information. (EXH 312) Staff notes that PEF’s depreciation witness admitted that he had no specific knowledge with regard to any of the items about which the intervenors are criticized. (EXH 312) Staff believes that if PEF had specific information supporting its life spans, it should have provided it in the depreciation study. Rule 25-6.0436, F.A.C., requires that a depreciation study include a justification for a company’s proposed depreciation parameters for each study category. This justification includes such things as growth, Company planning, technology, physical conditions, and trends.
Based on the foregoing, staff believes that PEF’s depreciation study is void of any supporting information regarding the life spans for CR 4 & 5 used in the depreciation study. Moreover, staff agrees that the supporting information provided in response to staff discovery consisted of conclusory responses without any specific data or analysis to support the life spans. Further, recognizing that PEF itself acknowledged that the actual service life or life span of a generating unit is not actually known until it is retired, staff agrees with OPC and FIPUG that consideration of life spans used by other electric companies is in order. (TR 2033, 3527) Staff finds it compelling that PEF did not refute that other utilities use life spans for coal plants in the range of 55 to 65 years. In light of the lack of persuasive PEF-specific information supporting its proposed life spans, staff believes that OPC’s proposed life span of 60 years for CR 4 & 5 is reasonable to use in this proceeding for determining appropriate life parameters for PEF’s coal plants.
CONCLUSION
Staff recommends that a 54-year life span should be used for Crystal River 1 and 2 and a 60-year life span should be used for Crystal River Unit 4 and 5 for determining appropriate life parameters in this proceeding.
What life spans should be used for PEF's combined cycle plants?
Recommendation:
Staff recommends that a 35-year life span be used in this proceeding to determine the appropriate depreciation parameters for the Hines Energy Complex Units 1-4 and the new Bartow unit. For Tiger Bay, staff recommends using PEF’s proposed 41-year life span. Also, staff recommends that PEF provide with its next depreciation study a detailed analysis demonstrating the expected life span of its combined cycle generating facilities, including why they should not be expected to operate for 35 years or longer. (P. Lee)
Position of the Parties
PEF:
The appropriate life span for PEF’s combined cycle plants is 30 years.
OPC:
The 30-year life span that PEF uses for combined cycle units is unrealistically short. The Commission should direct PEF to evaluate available information and develop a more appropriate life span in its next depreciation study. If the Commission decides to revise the life span for combined cycle units in this proceeding, it should set the minimum value at 35 years per the testimony of Witness Marz.
AFFIRM:
No position.
AG:
Support OPC’s position as set forth in the testimony of Jacob Pous.
FIPUG:
Based on industry experience and specific examples, the Commission should use a life span of at least 35 years for its combined cycle plants.
FRF:
The appropriate depreciation life span for PEF's combined cycle units is 40 years. The other appropriate depreciation parameters are those recommended by witness Jacob Pous on behalf of the Citizens of the State of Florida.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PEF witness Sorrick testified that the Company has five combined cycle units: Hines Energy Complex Units 1-4 and Tiger Bay. A new combined cycle unit at Bartow is planned to become operational in 2009. (TR 373-374) PEF witness Crisp explained that a combined cycle plant consists of a simple cycle combustion turbine (CT) and steam generators. (TR 3509-3511)
PEF, OPC, and FIPUG offered testimony regarding the life spans for these units. PEF proposed an average life span of 30 years.[9] (Crisp TR 3400; EXH 84, Section 9, p. 9-71; EXH 36, BSP 1361) OPC proposed PEF be directed to evaluate and develop a more appropriate life span in its next depreciation study or use a 35-year life span in the instant proceeding. (Pous TR 2058) FIPUG proposed a life span of at least 35 years. (Pollock TR 3203) FRF advocated a life span of 40 years but did not proffer any testimony. (FRF BR 32) The AG and PCS support the position of OPC but did not proffer testimony. (AG BR 5; PCS BR 4) The remaining parties took no position.
Life spans are used in the development of appropriate average remaining lives which are addressed in Issue 12. Life spans are dependent on the average in-service date and an estimated date of retirement for each unit. The difference between the average in-service date and the estimated date of retirement is the life span. (Robinson TR 1108-1109; Crisp TR 3524; Pous TR 2024; Pollock TR 3198-3199)
PARTIES’ ARGUMENTS
PEF witness Robinson testified that the estimated retirement dates and life spans for PEF’s generating units were determined by the Company’s operating and planning management. (TR 1110) In the current depreciation study, PEF proposed a 29-year life span for Hines Unit 1, and a 30-year life span for each of the other three combined cycle units at the Hines Energy Center and the new Bartow unit planned for operation in 2009. For Tiger Bay, PEF proposed an estimated retirement date of 2038 and 43-year life span, based in part on the CT rotor replacement that occurred in 2008. (EXH 36, BSP 1361; EXH 84, Section 9, p. 9-71)
OPC witness Pous and FIPUG witness Pollock testified that PEF’s 30-year life span for its combined cycle units is understated. (Pous TR 2024, 2058; Pollock TR 3202) Both witnesses contended that a life span of at least 35 years is more appropriate. (Pous TR 2058; Pollock TR 3203) Additionally, OPC witness Pous proposed that PEF should be directed to perform a detailed analysis in its next depreciation study demonstrating why its combined cycle generating facilities cannot be expected to operate for 35 years or longer. (TR 2058)
FIPUG witness Pollock testified that the life span is the most important assumption in determining appropriate depreciation rates, an assumption not addressed in PEF witness Robinson’s depreciation study. (TR 3196, 3235-3236) Witness Pollock asserted that PEF has not justified its proposed life spans. The witness also stated that PEF has not explained why its combined cycle units cannot operate longer than 30 years, especially given that these units represent the most efficient units on PEF’s system. (TR 3202)
FIPUG witness Pollock supported his proposed life span by reference to combined cycle life spans used by other utilities that ranged from 35 years to 60 years. (Pollock TR 3202-3203) Witness Pollock also noted that the Commission approved depreciation rates for Gulf Power Company that were based on a 34-year life span for Gulf Power’s combined cycle units.[10] (TR 3203) Both OPC witness Pous and FIPUG witness Pollock asserted that considering life spans approved in other states, as well as the Florida example, demonstrated the unreasonableness of PEF’s proposed life spans. (Pous TR 2058; Pollock TR 3203)
PEF witnesses Robinson and Crisp responded to the recommendations of OPC witness Pous and FIPUG witness Pollock. PEF witness Crisp criticized the OPC and FIPUG proposals, although he had no direct role in preparing PEF’s depreciation study. (TR 3415-3416, 3492) The witness contended that given the small differences between PEF’s proposed life spans and those recommended by the intervenors, PEF’s life spans should be considered reasonable. (TR 3415) Witness Crisp testified that he provided witness Robinson with the “facility service lives of the power plants that were used in the depreciation study.” (TR 3418-3419, 3422, 3427; EXH 216) Finally, the witness asserted that PEF’s estimated lives for its combined cycle units are “based on PEF’s expertise and experience with the condition, operation, and maintenance of these units to meet PEF’s load demands under the operational, environmental, and regulatory conditions facing PEF.” (TR 3399, 3415)
PEF witness Robinson testified that he discussed the service lives for PEF’s generating facilities with the Company’s resource planning group and reviewed the materials they provided. (TR 3557) Witness Robinson stated that he visited representative generation plants “to observe field operations and obtain local operating input.” (TR 3557, 3618) The witness contended that OPC witness Pous and FIPUG witness Pollock did not visit PEF’s generation facilities and did not consider the operational, environmental, and regulatory conditions in which the Company operates. (TR 3557) Witness Robinson claimed that PEF’s determination of the retirement dates and service lives for its generating facilities was based on its experience and judgment and was the product of an ongoing, internal management resource planning process. Witness Robinson maintained that there was no reason for him to substitute his judgment for PEF management as to the estimated retirement dates. Witness Robinson also contended that the Commission should not substitute PEF’s judgment with those made by the intervenor witnesses based on anecdotal information and generalizations. (TR 3557-3559)
Witness Crisp criticized the intervenor witnesses for using “only information from other areas around the country that do not correlate to Progress Energy Florida’s units and do not correlate to the climate, do not correlate to the operating conditions, do not correlate to the load requirements and do not correlate to the regulatory structure of Florida.” (TR 3399, 3423) The witness explained that PEF developed the projected retirement dates for its generating units in the course of its regular planning process that included 1) the specific current condition of each unit; 2) updates, changes, and reconfigurations made at each plant that affect operating characteristics; 3) complexity of operations and maintenance and longer term validity of the units; 4) subtropical operating environment; and 5) bulk system operating requirements and demands place on the generating plants. These decisions, asserted the witness, reflect PEF’s accumulated past and current experience with operating its units under PEF’s operating, environmental, and regulatory conditions to meet its load demands. (TR 3403-3406) The witness contended that neither OPC witness Pous nor FIPUG witness Pollock has experience with the operations and system planning considerations for PEF and has not visited any of PEF’s generating plants. (TR 3407) In contrast, the witness asserted, witness Robinson discussed the resource planning process and PEF’s “estimated service lives” with PEF resource planning staff. (TR 3407) Thus, witness Crisp concluded that there is no reason for the intervenors’ judgment to be substituted for PEF’s judgment. (TR 3399)
In its brief, FRF advocated a 40-year life span for PEF’s combined cycle units based on the following reasoning:
· Several of PEF’s steam units and combustion turbines on its system have been in service for more than 40 years, and all are projected to be in service longer than 40 years.
· PEF’s Ten-Year Site Plan indicated that its non-coal steam units have ages between 35 and 66 years, with the oldest units at the Suwannee station estimated to retire in 2015.
· PEF’s simple cycle CT units are between nine years and 41 years of age, with the oldest units being considered for retirement or cold standby status in 2016, at ages approaching 50 years. (EXH 286; FRF BR 33)
FRF argued that if these older technology units have operated for more than 40 years, it then follows that combined cycle units should experience life spans over 40 years. Additionally, FRF pointed out that Gulf Power Company, in its 2009 Ten-Year Site Plan, indicated plans to construct and operate a new combined cycle unit with an estimated 40-year life span. (EXH 314; FRF BR 33)
FRF asserted in its brief that PEF’s argument that cycling a combined cycle unit shortens its life span is meritless, as PEF witness Crisp testified that many of PEF’s generating units have been used for cycling duty over their life spans. (TR 3511-3512) With respect to PEF’s argument that environmental conditions may result in shorter life spans, FRF argued that this is contradicted by the fact that PEF’s steam units at Bartow were over 50 years old when they were retired, and simple cycle CTs that are 37 years old remain at Bartow. FRF argued that this evidence supports a 40-year life span for PEF’s combined cycle plants. (FRF BR 34)
ANALYSIS
As with PEF’s coal units addressed in Issue 10, staff believes that PEF has not supported the life spans used in the depreciation study for its combined cycle units. PEF witness Robinson was hired by the Company to perform its depreciation study. While the witness was the sole sponsor of the study, he received additional information from PEF operations personnel relative to plant operations, including the estimated retirement date for each generating unit. (TR 1133-1134, 1144, 3557) Even so, staff believes that PEF’s depreciation study and its results rest with witness Robinson, PEF’s depreciation witness.
Witness Robinson agreed that life spans are important in developing depreciation rates. (TR 1192) The witness also acknowledged that PEF’s depreciation study did not include substantive information on PEF’s generating unit life spans because they were provided by PEF. (TR 1194) While the witness could broadly explain how retirement dates are determined, he admitted that these were developed by PEF. Witness Robinson stated that he did not review the life spans provided to him because he was only tasked with performing the depreciation study using the information provided to him. (TR 1109, 1194; EXH 36, BSP 1138) Therefore, staff concludes that PEF’s depreciation study does not contain supporting information with regards to its proposed life spans.
PEF witness Crisp provided the only support for PEF’s estimated retirement dates and life spans. (EXH 216; TR 3422) Staff observes that the claimed support consists of one page indicating the average in-service date for each generating unit, along with the retirement date assumed in the 2005 depreciation study, and the current projected retirement date for use in the instant study. (EXH 216; EXH 36, BSP 1360-1361) However, as acknowledged by witness Crisp, the specific information supporting PEF’s proposed life spans was not specifically identifiable in Exhibit 216; it was embedded in the exhibit but not disclosed discretely and separately. (TR 3433, 3440-3446) Witness Crisp explained that there are many factors that go into the determination of life spans, including the cost-effectiveness of a given unit and where it fits within certain external drivers, such as climate change, but acknowledged that none of this specific information was in his testimony or the support he offered. (TR 3452) Without substantive information supporting PEF’s life span determinations, staff is unable to conclude whether or not they are appropriate to use in the instant depreciation study.
Staff believes that the criticisms PEF waged against the intervenors’ proposed life spans can equally apply to PEF. Both OPC witness Pous and FIPUG witness Pollock stated that based on their review of PEF’s depreciation study, they found that the study did not contain specific information with regards to 1) the condition of PEF’s generating facilities with respect to their life spans, 2) PEF’s expertise in operating or maintaining its generating units, 3) substantiation that PEF has unique load demands or how load demands impact the life spans, 4) updates, changes and reconfigurations made at each plant and how each affects the operating characteristics of the generating units with respect to life spans, 5) how renewable energy requirements may impact the life spans, and 6) the environmental risks PEF faces and how these risks may impact the life spans of the generating facilities. (Pous TR 2179-218; Pollock TR 3230-3232) Staff believes these omissions are compelling, especially given that PEF witness Robinson acknowledged that the depreciation study did not address or analyze such information. (EXH 312) Staff notes that PEF’s depreciation witness admitted that he had no specific knowledge with regard to any of the items about which the intervenors criticized. (EXH 312) Staff believes that if PEF had specific information supporting its life spans, it should have provided it in the depreciation study. Rule 25-6.0436, F.A.C., requires that a depreciation study include a justification for a company’s proposed depreciation parameters for each study category. This justification includes such things as growth, Company planning, technology, physical conditions, and trends.
Based on the foregoing, staff agrees with OPC and FIPUG that PEF’s depreciation study is void of any supporting information regarding the life spans used in the depreciation study. Moreover, staff believes that the supporting information provided in response to staff discovery consisted of conclusory responses without any specific data or analysis to support the life spans. Further, recognizing that PEF itself acknowledged that the actual service life or life span of a generating unit is not actually known until it is retired, staff agrees with FIPUG that consideration of life spans used by other electric companies is in order. (Pollock TR 3202-3203) Staff finds it compelling that Gulf Power lengthened the estimated life span for its combined cycle units in Florida to 34 years in 2007[11], and that Gulf Power’s 2009 Ten-Year Site Plan indicated an estimated 40-year life span for a new combined cycle unit. (EXH 314; TR 3518-3519; FRF BR 33)
On balance, staff believes a minimum life span of 35 years should be used in this proceeding for PEF’s combined cycle units. For the Hines Energy Complex and the new Bartow units for which PEF proposed life spans shorter than 35 years, staff recommends that 35 years be used for determining depreciation parameters. PEF’s proposed life span of 41 years for Tiger Bay appears reasonable for this proceeding. Staff recognizes that FRF pointed out that based on the composition of combined cycle units, they should likely experience life spans of 40 years or more based on the ages of PEF’s existing steam and combustion turbine units. For this reason, staff believes that PEF should provide in its next depreciation study a detailed analysis demonstrating the expected life span of its combined cycle generating facilities including why they should not be expected to operate for 35 years or longer.
CONCLUSION
Staff recommends that a 35-year life span be used in this proceeding to determine the appropriate depreciation parameters for the Hines Energy Complex Units 1-4 and the new Bartow unit. For Tiger Bay, staff recommends using PEF’s proposed 41-year life span. Also, Staff recommends that PEF provide with its next depreciation study a detailed analysis demonstrating the expected life span of its combined cycle generating facilities, including why they should not be expected to operate for 35 years or longer.
What are the appropriate depreciation parameters (remaining life, net salvage percent, and reserve percent), amortizations, and resulting rates for each production unit, including but not limited to coal, steam, combined cycle, etc.?
Recommendation:
Staff’s recommended depreciation parameters and resulting depreciation rates for production plant are shown on Table 12-1. The reserve positions shown incorporate the effects of the staff recommended reserve allocations addressed in Issue 15. The resultant test year depreciation expenses based on the staff recommendation in this issue and in Issue 13 are addressed in Issue 75. (P. Lee)
Position of the Parties
PEF:
The appropriate life span for PEF’s combined cycle plants is 30 years.
OPC:
The appropriate depreciation parameters should be determined using the life spans, remaining life calculations, the level of interim retirements, net salvage and resulting depreciation rates as shown in Exhibit No. 133 (JP-1), Exhibit No. 136 (JP-4) and Exhibit No. 137 (JP-5) as addressed as proposed by OPC witness Pous in the sub-categories below:
Production Units Life Span
Coal-fired production units: 60 years
Large steam oil or gas-fired generating facilities (Anclote 1 & 2): 50 years
Combined cycle generating facilities: 35 years
AFFIRM:
No position.
AG:
The appropriate depreciation parameters for PEF’s generating plants are those recommended by Jacob Pous.
FIPUG:
See Issues 9, 10, 11, 13.
FRF:
The appropriate depreciation parameters for PEF’s generating plants are those recommended by witness Jacob Pous, except that the proper life span for combined cycle units is 40 years.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
This issue addresses the appropriate life and salvage parameters for PEF’s production plants. PEF witness Robinson and OPC witness Pous filed testimony specifically addressing the appropriate lives and salvage values for production plant. PEF witness Crisp filed rebuttal testimony addressing production plant life spans. FIPUG’s testimony only addressed life spans and depreciation rates for PEF’s coal and combined cycle plants. These arguments were previously addressed in Issues 10 and 11 and are not repeated here. The AG, FRF, and PCS did not file testimony but adopted the recommendations of OPC. (AG BR 5; FRF BR 32-34; PCS BR 5) No other party addressed this issue.
PEF utilized the life span method for determining the life characteristics of its production plants. In using this study method, an estimated retirement date is determined for each production unit. The span of time between the in-service date and the date at which the facility is estimated to retire is termed the life span. Once the overall life span for each facility is determined, an interim retirement rate is applied to determine the average service life and average remaining life. (Robinson TR 1108-1109, 2034; EXH 84, Section 3, p. 3-1; Pous TR 2034, 2049) Interim retirements[12] represent the investment not expected to live the full life span of the generating plant. (Pous TR 2025, 2049, 2059; Robinson TR 3559-3560; EXH 84, Section 3) Because final removal costs associated with the retirement of PEF’s fossil fuel plants are addressed separately through a dismantlement reserve, the net salvage for production plant as addressed in this issue relates to interim retirements. (Robinson TR 1108; Pous TR 2063)
The parties’ arguments and analysis below first address overall positions and then address the main components comprising the proposed life and salvage parameters: life spans, interim retirement rates, service lives, and interim net salvage.
PARTIES’ ARGUMENTS
PEF witness Robinson sponsored the Company’s depreciation study in this proceeding. (TR 1133) PEF witness Robinson testified that the depreciation study is based on data through December 31, 2007, with pro forma adjustments for forecasted changes in investments through 2009. (TR 3534, 3726) The witness stated that the scope of PEF’s depreciation study included statistical analysis of Company historical data, discussions with Company management to identify prior and prospective factors that could impact service lives, and information from plant inspection tours. (EXH 84, Section 3, p. 3-1) Sections 1 and 3 of the study identified and explained the method, procedure, and technique, as well as the process used in the historical statistical analysis and estimation of life and salvage estimates. Section 2 consisted of summary schedules for each account. Section 4 of the depreciation study contained statistics and discussions relative to each account. The other sections included detailed information and/or documentation supporting the schedules in Sections 2 and 4. (Robinson TR 1112, 1130-1131; EXH 36, BSP 999-1001; EXH 84)
PEF witness Robinson explained that PEF provided him the in-service dates and the estimated retirement dates for each of the production plants. The witness explained that estimated retirement dates were determined after considering such factors as management plans, industry standards, the original construction date, subsequent additions, resultant average age, and the current and overall expected service life of the property being studied. Historical interim retirements were studied to determine an appropriate interim retirement rate. Witness Robinson then selected interim service life parameters (Iowa curve and life) to depict the level of investments that are not expected to live the entire life span of the property. The interim service life parameters were used with the investments and dates of retirement to determine the average remaining lives. (EXH 84, Section 3, p. 3-13)
PEF witness Robinson explained that historical life analyses were used as a tool to make “informed assessments” in determining the appropriate life and salvage parameters.[13] (TR 1110) Consideration was also given to anticipated impacts that “current events, PEF’s ongoing operations, PEF management’s future plans, and general industry events” may have on the lives of the facilities. (TR 1110-1111, 1113) Finally, witness Robinson stated that professional judgment was incorporated into his life and salvage determinations. (TR 1111) Witness Robinson’s resulting proposed depreciation rates reflect the plant investment, the book reserve, the future net salvage, and the “composite” remaining life for each account for each production plant. (TR 1120)
PEF witness Robinson testified that the most notable changes in the production plant depreciation rates occurred in Account 312, Boiler Plant Equipment; Account 322, Nuclear Reactor Plant Equipment; and Account 343, Other Production Prime Movers. The witness explained that the basic factors influencing the proposed depreciation parameters for Account 312, Boiler Plant Equipment, and Account 322, Nuclear Reactor Plant Equipment, were changes in the interim retirement rate, the date of retirement, the estimated interim net salvage factors, and the current book reserve levels. The estimated date of retirement for Account 322 was based on the anticipated license expiration date of 2036 for Crystal River Unit 3. (TR 1115-1117) For Account 343, Other Production Prime Movers, witness Robinson testified that changes in the estimated depreciation parameters were due to the new Bartow combined cycle plant becoming operational during 2009. (TR 1117)
OPC witness Pous testified that setting depreciation rates necessarily involves the use of estimates and projections. (TR 2018) Witness Pous considered PEF’s proposed depreciation lives and salvage values for production plant too short. (TR 2043) The witness asserted that PEF’s depreciation study did not contain the basis for its proposals. The OPC witness also asserted that the bases for PEF’s life and salvage proposals were not contained in witness Robinson’s workpapers or responses to discovery. Witness Pous stated that PEF witness Robinson simply provided statements that the process was not arithmetic but interpretive. (TR 2193-2194) OPC witness Pous asserted that given the subjectivity involved in the estimation process, judgment employed in the determination of life and salvage values played an important role. However, that “does not mean that an analyst can simply refer to ‘judgment’ as the basis for a proposal without providing meaningful factual support for that ‘judgment,’ nor can ‘judgment’ serve as the basis for ignoring relevant facts.” (TR 2035-2036)
I. Life Spans
As noted previously, estimating a future expected retirement date is necessary in the life span method to determine appropriate lives. (TR 2049) The length of time from the date of installation until the time the plant will retire is the life span. Because the property will be retired at the same time, the date of retirement is a critical element. (EXH 311) Life spans for coal-fired and combined cycle units are discussed in Issues 10 and 11. This discussion will address the life spans for PEF’s large oil and gas-fired plants and combustion turbine facilities (CTs).
PEF provided the estimated dates of retirement for each of its generating facilities to witness Robinson. (TR 1194; EXH 84, Section 2, pp. 2-125 – 2-128, Section 4, pp. 4-1 - 4-32) The life spans were developed by PEF management “after considering all factors affecting the current and prospective operation of the facilities as well as production requirements.” (TR 3563)
A. Steam Production
These plants consist of coal-fired as well as oil or oil/gas generating units. The life spans of PEF’s coal units are addressed in Issue 10. For the remaining units, PEF proposed a retirement date of 2022 for its Suwannee units and 2013 for its Anclote units. (EXH 216)
OPC witness Pous asserted that PEF’s proposed retirement dates for its newer large oil and gas-fired (Anclote) generating units were too short. (TR 2052) Witness Pous proposed a minimum 50-year life span for Anclote. (TR 2024) Witness Pous asserted that actual operation of PEF’s units showed that oil/gas-fired facilities can operate longer than 60 years. (EXH 36, BSP 1361) Witness Pous reasoned that if smaller less efficient generating facilities could operate for 60 years or more, then economic theory dictated that newer, larger, and more efficient facilities should be expected to experience a similar life span. (TR 2053) Additionally, witness Pous asserted that 60-year life spans have been adopted for steam generating units in recent cases in other states. (TR 2053-2055) Further, the witness testified that a review of the generating facilities data maintained by the Energy Information Administration of the Department of Energy demonstrates that longer life spans are supported for steam generating units. (TR 2055-2056)
OPC witness Pous testified that PEF has not presented any economic analysis that supports that its generating units cannot economically operate longer than its proposed life spans. With respect to carbon emission concerns of fossil-fueled plants, the witness noted that other utilities and regulators have recognized longer life spans, even given consideration of those concerns. (TR 2057)
Rebutting OPC’s position, PEF witness Robinson relied on PEF witness Crisp to support the Company’s proposed life spans. (TR 3557) Witness Robinson testified that, in his professional opinion, PEF had completed a full and thorough investigation of the current and estimated future operations capability of its generating facilities to estimate those life spans. (TR 3557-3558) Regarding the life span for Anclote, PEF witness Crisp stated that “PEF’s judgment is that 46 years is appropriate.” Witness Crisp asserted that PEF’s proposal is reasonable, especially in light of witness Pous’ recommended 50-year life span. Witness Crisp asserted that the life span for Anclote “is based on PEF’s specific knowledge about and experience with the condition, operation, and maintenance of this unit and its planning judgment with respect to the service life for this unit on PEF’s system.” (TR 3405, 3415; EXH 216)
B. Nuclear Production
The life span of Crystal River Unit 3 is tied to its specific license termination date. PEF assumed the pending 20-year license extension will be granted by reflecting a license termination date of December 2, 2036. PEF proposed a remaining life that assumes Crystal River Unit 3 will retire mid-year 2036. (EXH 84, Section 2, pp. 2-125 – 2-128) OPC witness Pous proposed a remaining life that recognizes the specific license termination date of December 2036 rather than assuming a mid-year retirement date. (TR 2058)
C. Other Production Plant
Other production consists of combustion turbines and combined cycle plants. The life span for combined cycle units is discussed in Issue 11. The parties did not appear to disagree with PEF’s life spans for its combustion turbines. (EXH 6, BSP 64; EXH 20, BSP 64; EXH 36, BSP 1361; EXH 199)
II. Interim Retirement Rate
Table 6 in Section 2 of PEF’s depreciation study showed the interim retirement rate witness Robinson used in developing the proposed average service life and average remaining life for each account. (EXH 84, Section 2, p. 2-158 – 2-163) The depreciation study narrative stated that the interim retirement rate was based on an actuarial analysis[14] of historical interim retirements to define the level of investments at each of the various plants that will retire prior to the retirement date of the given property. Interim service life parameters (Iowa curve and life) were then selected to estimate the level interim retirements. (EXH 84, Section 3, p. 3-19)
OPC witness Pous asserted that PEF’s interim retirement rates overstate the level of expected interim retirements, especially when compared to interim retirement levels historically experienced. (TR 2025) The OPC witness viewed PEF’s use of an Iowa curve shape to identify interim retirements as inappropriate and cumbersome. (TR 2060) The witness posited that the different types of investments within each production plant account do not reasonably lend themselves to actuarial analysis, because the actuarial approach treats all items in the same account as the same for life estimation purposes. (TR 2061) The OPC witness also asserted that the actuarial approach can overreact to unusual activity or the timing of unusual activity, resulting in higher than appropriate interim retirement projections. (TR 2025, 2061-2066)
OPC witness Pous proposed an alternative approach for determining an interim retirement rate that replaces the actuarial component of the analysis. He used a constant interim retirement rate approach that is sponsored by the California Public Utilities Commission and also recognized in the National Association of Regulatory Utility Commissioners Public Utility Depreciation Practices manual as being appropriate.[15] (EXH 286; TR 2066) The witness explained that his proposed interim retirement ratios were based on PEF’s historical retirement activity for each account. (EXH 137)
PEF witness Robinson countered that OPC witness Pous incorrectly calculated his constant interim retirement rate, thereby understating interim retirements. He asserted that witness Pous’ interim retirement rate was the result of simply dividing the aggregate amount of historical interim retirements by the number of years of data. This produced a single interim retirement rate for all production accounts. Witness Robinson stated that the calculation should have been based on the ratio of each year’s retirements and the then-existing plant balance subject to retirement, to yield a weighted average of each year’s retirement ratios. (TR 3561) Even if the calculation were corrected, witness Robinson asserted that OPC witness Pous’ constant interim rate was inferior to his approach because it was based only on history, and did not consider the increasing level of interim retirements that will occur as the property ages or expected future interim retirement events. Moreover, witness Robinson alleged that OPC witness Pous’ cited authority to support his interim retirement calculation, indicated that PEF’s approach using actuarial analysis to estimate interim retirements was more accurate. (TR 3563-3565)
III. Lives
PEF witness Robinson averred that PEF’s plant is subject to several forces of retirement: physical, functional, and contingent casualties. (EXH 84, Section 3, p. 3-14) Witness Robinson explained that the life analysis he performed considered both historical experience and future expectations to determine the appropriate average remaining life of the property. These considerations ensured the selection of an average service life that best represented the expected life of the property investment. (EXH 84, Section 3, p. 3-15) In contrast, OPC witness Pous applied his proposed interim retirement rate to the unadjusted remaining life of each account to develop a remaining life adjusted for interim retirements. (TR 2066; EXH 137)
IV. Interim Net Salvage
Location-type properties such as generating facilities experience both interim and final net salvage.[16] Both PEF witness Robinson and OPC witness Pous explained that interim net salvage corresponds to the projected interim retirements. (EXH 84, Section 3, p.3-14; Pous TR 2067) Final net salvage is associated with the final retirement of a plant site and is addressed through a fossil dismantlement accrual addressed in Issue 19. (EXH 84, Section 3, p.3-14)
PEF witness Robinson testified that his interim net salvage proposals were based on an analysis of historical experience, “consideration of the net salvage forecast, plus current and prospective factors.” (TR 1116) The result was then applied to the level of interim retirements anticipated to occur over the life span of the applicable property. (TR 1109)
In contrast, OPC witness Pous asserted that since PEF’s estimated interim retirements were overstated, then so were PEF’s net salvage results. (TR 2025-2026, 2063) The witness contended that PEF witness Robinson failed to identify, either through testimony or responses to discovery, how the initial net salvage result before adjusting for interim retirements was determined. (TR 2070, 2073-2077) For this reason, witness Pous proposed that the actual overall historical net salvage values be used for interim retirement purposes. Where the historical data yielded a positive net salvage, witness Pous proposed that the interim net salvage parameter be zero. Additionally, the witness proposed that PEF be directed to perform a detailed, thorough, and documented depreciation study for its next regularly scheduled filing, clearly identifying what information was relied on for each account and how the information results in the recommended proposal. (TR 2073)
With respect to PEF’s interim net salvage analysis, witness Pous testified that PEF’s historical net salvage values were based on data as of December 31, 2007. The witness contended that while PEF updated its plant data through December 31, 2009 for remaining life purposes, it chose not to do so for salvage analysis purposes. (TR 2073-2074) By ignoring the significant additions and retirements forecasted for 2008 and 2009, witness Pous submitted that the level of retirements used in witness Robinson’s calculation was overstated, thereby overstating the resulting negative net salvage applicable to interim retirements. (TR 2074-2076)
PEF witness Robinson asserted that OPC witness Pous was incorrect with his claim that PEF’s interim net salvage estimates needed to be updated for 2008 and 2009 activity. The witness testified that his net salvage parameters were estimated as of the depreciation analysis date. The witness noted that while OPC faulted PEF for not updating its data, OPC witness Pous’ proposals do not reflect updated data. (TR 3572)
ANALYSIS
PEF’s depreciation rates were last fully reviewed in 1997 and the results of this review were memorialized in Order No. PSC-98-1723-FOF-EI, issued December 18, 1998, in Docket No. 971570-EI, In re: 1997 Depreciation Study by Florida Power Corporation (1997 FPC Depreciation Order). As part of its 2002 earnings settlement,[17] PEF’s depreciation rates approved in 1997 continued unchanged. In the 2005 rate case settlement,[18] the depreciation rates contained in PEF’s depreciation study filed in that proceeding were accepted with some modifications agreed to by the parties. The instant study therefore represents the first opportunity in 12 years for a complete and thorough review of PEF’s recovery position by the Commission.
The scope of PEF’s depreciation study included statistical analyses of Company historical data, discussions with Company management to identify prior and prospective factors that could impact service lives, and information from plant inspection tours. (EXH 84, Section 3, p. 3-1) The FIPUG and OPC witnesses asserted that PEF did not provide the requisite specific substantiating information necessary to support and justify its proposals. (Pous TR 2179-2181, 2193; Pollock TR 3230-3232) PEF witness Robinson stated that while he had knowledge and general understanding of the production facilities, he could not identify specific factors affecting PEF’s generating plants. (TR 1196-1198)
Rule 25-6.0436, F.A.C. (the Commission’s depreciation study rule), sets forth depreciation study requirements. Subsection 6(f) of the rule requires that each study contain:
An explanation and justification for each study category of depreciable plant defining the specific factors that justify the life and salvage components being proposed. Each explanation and justification shall include substantiating factors utilized by the utility in the design of depreciation rates for the specific category, e.g., company planning, growth, technology, physical conditions, and trends. The explanation and justification shall discuss any proposed transfers of reserve between categories or accounts intended to correct deficient or surplus reserve balances. It should also state any statistical or mathematical methods of analysis of calculation used in the design of the category rate.
The depreciation study rule also requires that depreciation studies be filed at least once every four years from the date of the previously filed study, unless otherwise required by the Commission. If a company wishes to have revised depreciation rates considered in a base rate revenue requirements proceeding, the rule requires that the study be submitted by the time of the filing of the Minimum Filing Requirements (MFRs). (Rule 25-6.0436(8), F.A.C.).
While PEF witness Robinson testified that the depreciation study was prepared in accordance with Rule 25-6.0436, F.A.C., staff notes that witness Robinson admitted that not all the documentation required by the depreciation study rule was included in the depreciation study. (TR 1139-1143) Although additional information was provided in response to discovery requests, witness Robinson acknowledged that it was not sufficient to comply with the depreciation study rule requirements. (TR 1138-1148) When PEF was asked to specifically identify what information was relied upon in the course of performing the depreciation study, what life analysis procedure was utilized, and any other information specifically relied upon in developing the resulting life parameters, PEF witness Robinson responded that “the process of service life and future net salvage estimation is interpretative as opposed to an arithmetic approach.” (EXH 36, BSP 1225) Staff believes that the information PEF provided to support the average service lives for PEF’s generating units simply shows its proposed service lives with some conclusory statements, but no substantiating information. (EXH 216) For the production accounts, PEF’s depreciation study only provided the proposed parameters with generalized discussions. (EXH 84, Section 4, pp. 4-1 – 4-32) There is no discussion or explanation of the pressures facing PEF, how those pressures are impacting life and salvage parameters, or how PEF plans to address those pressures.
Staff believes that PEF’s depreciation study did not discuss how or why witness Robinson selected the specific experience bands[19] that he used in his statistical actuarial analyses. While witness Robinson quoted from the National Association of Regulatory Utility Commissioners Public Utility Depreciation Practices (NARUC depreciation manual) that “depreciation analysts should avoid becoming ensnared in the mechanics of the historical life study and relying solely on mathematical solutions,” if he relied on anything besides the past, staff believes that information was not specifically identified in the depreciation study.
Section 4 of the PEF depreciation study provided the study analysis and results. For example, Account 311 contained plant statistics as of December 31, 2007, such as the investment, average age of the surviving investment, original gross additions, the oldest surviving vintage, historical retirements, and the average age of retirements. These statistics were not estimated out to PEF’s proposed implementation date of January 1, 2010. Section 4 of the study also provided a narrative of plant considerations and future expectations. This included a general description of the generating plants, including when they were placed into service. The remaining discussion consisted of:
The Crystal River Units 4 & 5 are in the process of undergoing major upgrading and the Bartow Units are scheduled for retirement during 2009. The increasing focus on air quality standards inclusive of carbon regulation will continue to place increasing burdens on the Company to maintain and/or continue to operate generating plants within i[t]s fossil fleet.
(EXH 84, Section 4, p. 4-1)
Staff notes that this exact same narrative was provided for each of the steam production accounts. (EXH 84, pp. 4-2 – 4-10) Similar non-specific narratives were provided for PEF’s nuclear and other production accounts. (EXH 84, pp. 4-11 – 4-32) Other than the results of the historical statistical analysis, this language was the only support offered for PEF’s proposed life and salvage factors for the steam production plants and accounts. Staff believes that these narratives did not constitute an adequate explanation and justification for any of the steam production accounts, and did not define or describe the specific factors that justified the life and salvage components being proposed. Staff cannot locate anything in PEF’s study that meaningfully discussed the key factors presumably considered by PEF in its design of depreciation rates for a given category, such as company planning, anticipated growth, technology, physical conditions, and trends. The only thing the study contained was the results of the statistical analyses performed and the calculations yielding the category’s rate. There was no indication how the interim retirement rate was selected or why. There was no information regarding how potential changes in air quality standards may impact the lives of the steam plants.
In a depreciation study review, staff believes that depreciation rates should only be revised where warranted. With the passage of time, all other things remaining equal, the average remaining life will necessarily change due to the increased age of the plant. OPC witness Pous asserted that the sole support and basis for PEF’s life and salvage proposals for production plant are only the numerical analyses presented and a statement that life and salvage determinations are not an arithmetic process but an interpretative process. (TR 2193) Staff requested that PEF identify the factors it evaluated that indicate a need to revise the estimated life and salvage values from the 2005 study, other than the results of the depreciation computer program analysis. PEF responded, “Mr. Robinson’s depreciation study analysis approach is to view each study as a fresh start project.” The response goes on to state that the study analysis is the reason for the proposed changes. (EXH 36, BSP 1019, 1151, 1226) Staff believes PEF provided no other basis, narrative, or explanations supporting its assumptions or determinations. Staff thus concludes that PEF failed to carry its burden of proof regarding its proposed depreciation rates for production plant. Staff agrees with OPC witness Pous that PEF has provided only generalized statements with little support or documentation. (TR 2194) Staff believes there should be an objective reason for changing life and salvage values other than that the computer program dictates the change. Staff believes company planning is an important element in developing appropriate life parameters for production plant, a discussion that was lacking in PEF’s depreciation study and discovery responses, even though it was requested.
OPC witness Pous stated that the remaining life technique recognizes that depreciation is a forecast or estimation process. (TR 2033, 2036) Both PEF witness Robinson and OPC witness Pous testified that depreciation involves subjectivity and judgment plays an important role. (TR 2035) However, OPC witness Pous asserted that simply referring to judgment as the basis for a proposal without providing factual support, or as the basis for ignoring relevant facts, is inappropriate. (TR 2035-2036) Staff believes OPC’s arguments are persuasive.
I. Life Spans
Production plant was studied using the life span method. The depreciation study narrative stated that a probable retirement date was determined after considering “management plans, industry standards, the original construction date, subsequent additions, resultant average age and the current – as well as the overall – expected service life of the property being studied.” (EXH 84, Section 3, p. 3-18) When asked to identify the industry standards considered in determining the probable retirement dates, PEF responded, “company management completed a specific detailed review of its generating plants with the task of estimating terminal dates at which time the various operating plants would be retired and/or anticipated to be significantly upgraded/rebuild to enable the facilities to continue to provide future service.” (EXH 36, BSP 1138) None of the referenced “detailed review” was documented or provided in the depreciation study or in PEF’s discovery responses. (TR 2179-2181)
PEF’s proposed retirement date for the Suwannee steam units is 2013. With an in-service date of 1953, this translates into a life span of 60 years. PEF’s 2009 Ten-Year Site Plan encompassed planning for the retirement of this plant. Recognizing that OPC or any intervenor did not appear to object to the projections for the Suwannee plant, staff believes a 60-year life span is appropriate to use in this proceeding.
For Anclote, staff believes that the criticisms PEF waged against OPC’s proposed life span can equally apply to PEF. OPC witness Pous stated that based on his review of PEF’s depreciation study, he found that the study did not contain specific information with regards to 1) the condition of PEF’s generating facilities with respect to their life spans, 2) PEF’s expertise in operating or maintaining its generating units, 3) substantiation that PEF has unique load demands or how load demands impact the life spans, 4) updates, changes and reconfigurations made at each plant and how each affects the operating characteristics of the generating units with respect to life spans, 5) how renewable energy requirements may impact the life spans, and 6) the environmental risks PEF faces and how these risks may impact the life spans of the generating facilities. (TR 2179-2181) Staff believes these omissions are compelling, especially since PEF witness Robinson acknowledged that the depreciation study did not address or analyze such information. (EXH 312) Staff notes that PEF’s depreciation witness admitted that he had no specific knowledge with regard to any of the aforementioned items for which the intervenors are criticized. (EXH 312) Staff believes that if PEF had specific information supporting its life spans, it should have provided it in the depreciation study.
Staff notes that PEF admitted that its proposed life spans did not reflect firm decisions. (EXH 36, BSP 1071) Further, although PEF witness Crisp provided the only support for PEF’s life spans, staff notes that this was not filed as support for PEF’s depreciation study. (TR 3422) Even so, staff believes the information presented by witness Crisp is not adequate in that it gave only conclusory comments.
Staff agrees with OPC that PEF’s depreciation study is void of any supporting information regarding the life spans used in the depreciation study. While staff generally believes that the lives of production plant should be based on company-specific planning and information, in the instant case, that information is lacking. Further, recognizing that PEF itself acknowledged that the actual service life or life span of a generating unit is not actually known until it is retired, staff agrees with OPC that consideration of life spans used for other electric companies is reasonable. (TR 2033)
In sum, staff believes PEF has not provided competent substantial evidence supporting its proposed life spans. Staff reiterates its belief that company-specific planning is a very important element in a depreciation study. In this respect, staff believes PEF’s depreciation study falls short. For these reasons, staff believes that relying on the life span estimates of other companies, as OPC did, has merit. Staff recommends that a 50-year life span for the large steam or oil-fired plants be used to determine the appropriate life factors in this proceeding.
B. Nuclear Production
The narrative discussion in Section 4 of the depreciation study regarding plant considerations and future expectations for PEF’s nuclear plant, Crystal River Unit 3, described the investment and the method used for life analysis. Given that PEF is seeking a license extension for Crystal River Unit 3, staff is puzzled why issues relating to license extension were not considered sufficiently important to discuss in the depreciation study.
PEF developed its proposed life span assuming a 20-year license extension is approved by the Nuclear Regulatory Commission. PEF’s life span was based on a retirement date of mid-2036. OPC witness Pous’ proposed life span was based on an actual license termination date of December 2036. All things considered, staff believes OPC witness Pous’ life span is more reasonable, because it matches the end of the unit’s extended operating licensed life.
C. Other Production
Other production includes combustion turbines and combined cycle plants. Given that no evidence was presented that challenged PEF’s proposed life spans for its combustion turbines, staff recommends that those be used in determining the depreciation life parameters in this proceeding. For the reasons set forth in Issue 11, as well as those discussed above regarding steam production life spans, staff recommends the use of a minimum life span of 35 years in determining the appropriate life parameters for PEF’s combined cycle plants.
II. Interim Retirement Rate
Under the life span study method, an interim retirement rate was developed to recognize investments expected to retire prior to the retirement date of the applicable property. (EXH 84, Section 3, pp. 3-18 – 3-19) PEF witness Robinson used an actuarial survivor curve analysis to develop his interim retirement rates. The witness’ approach was based on an Iowa curve truncated at the retirement date. Witness Robinson stated that the specific Iowa curve he selected to represent future interim retirements was representative of historical retirements. (EXH 312; EXH 36, BSP 1139-1140) If this is true, then staff infers that witness Robinson concluded that PEF’s generating plants will experience the same level of interim retirements in the future as they did in the past.
On the other hand, OPC witness Pous used a constant interim retirement rate based on PEF’s historical retirement data for each account. While PEF witness Robinson alleged that OPC witness Pous’ calculation produced one single interim retirement rate for all production accounts, this is not correct. Staff notes that contrary to PEF’s contention, the OPC witness developed a constant interim retirement rate for each production account, not one rate for all accounts. (EXH 137)
Regarding the use of actuarial analyses in determining interim retirement rates, OPC witness Pous asserted that actuarial analyses are not suitable for production plant investments and they overstate projected interim retirements. (TR 2025-2066) As an example, witness Pous referenced Account 312, Boiler Plant Equipment. Using PEF’s proposed interim retirement approach, $394 million of investments would be expected to retire over the 20-year remaining life, or about $20 million annually. However, a review of the historical retirement activity for this account indicated total retirements of about $60 million over the past 32 years. Witness Pous concluded that, on an annual basis, PEF’s approach results in projected interim retirement levels that would result in more than 10 times the average annual historical retirement levels. The OPC witness contended that no evidence demonstrated that Boiler Plant Equipment could reasonably be expected to incur future interim retirements of this magnitude. (TR 2064-2065) Staff agrees and notes that PEF did not refute OPC’s allegation that actuarial analyses can overstate interim retirements.
Both PEF witness Robinson and OPC witness Pous cited to the California Public Utilities Commission PUC-U-4 publication to support their selected approach to calculate the interim retirement rates used in determining the average remaining lives for each account within each plant. (EXH 286) The witnesses also acknowledged that both approaches are recognized approaches in the NARUC depreciation manual for determining an interim retirement rate. (EXH 312; Pous TR 2066)
Staff believes that an actuarial analysis studies how property has lived historically. Knowing what happened yesterday may help one better understand what is happening today and what may happen tomorrow. However, PEF provided no substantive information regarding anticipated future retirement characteristics. Moreover, if PEF witness Robinson’s analysis is representative of historical retirements, then presumably so is that of OPC witness Pous, since his method is also based on historical retirements.
PEF was requested to identify and provide documents supporting its selected life and Iowa curve combinations for each of the production plant accounts. In some responses, PEF stated that the estimation of life parameters is “interpretative” which includes a consideration of historical data as well as anticipated future changes. In another response, PEF stated that “[a]ll Iowa curves that indicate a good fit with the observed data are the product of our proprietary software model and would have to be rerun to provide all other curve fits besides the selected curves provided in this study.” (EXH 36, BSP 1059, 1150-1159, 11691185, 1317-1318) In another response, PEF stated that the computer software was proprietary and provided statistical output. (EXH 36, BSP 1329-1330) Staff believes that these responses do not support the reasonableness of PEF’s interim retirement rate. Absent sufficient evidence as gleaned from these responses, staff is unable to verify that witness Robinson’s interim retirement rates are appropriate.
For the above reasons, staff believes that PEF has not provided substantial competent evidence supporting the reasonableness of its interim retirement rates. Thus, staff is unable to advocate the use of them in this proceeding. However, staff recognizes that PEF acknowledged that OPC’s interim retirement approach was an acceptable method, although not what it recommended. Because an interim retirement rate is needed to determine the average remaining life for each production account within each production account, staff believes that the interim retirement rates proposed by OPC witness Pous are appropriate to use in this proceeding. (EXH 137)
III. Lives
The interim retirement rate is applied to the life span to determine the resulting average service life for each account within each plant. No party objected to this methodology. Staff observes that both PEF and OPC recognize that depreciation involves estimates. (Robinson TR 1203; Pous TR 2018) For this reason, staff believes there is little reason to be as precise as a hundredth of a year. Staff’s recommended lives reflect the rounding of lives over 20 years to the nearest whole year and lives less than 20 years to the tenth of the year.
Staff’s recommended remaining lives reflect applying the applicable interim retirement rates truncated at the retirement date as determined by the life spans discussed above. Staff agrees with PEF that using the life span study method, no investment can be considered surviving past the retirement date of the production unit.
IV. Interim Net Salvage
PEF’s depreciation study stated that the level of interim net salvage was based on an account level analysis of historical data. (EXH 84, Section 4, pp. 4-1 – 4-31) The result was then applied to the level of interim retirements anticipated to occur over the life span of the applicable plant. (TR 1109) However, like OPC, staff was unable to duplicate PEF’s historical results.
Considering PEF’s reliance on historical data, discovery responses stating that PEF’s approach was interpretive rather than mathematical is puzzling. (EXH 36, BSP 1230-1231, 1239, 1261, 1278, 1280, 1288, 1290, 1292) While PEF witness Robinson stated that management input regarding current and potential changes were considered, staff is perplexed that PEF did not provide information regarding its net salvage analysis, even when requested. For this reason, staff agrees with OPC that PEF did not adequately explain how the initial net salvage result before adjusting for interim retirements was determined.
Under a reserve-sensitive depreciation methodology like remaining life, staff believes it is requisite that the data match the implementation date of revised depreciation rates. Estimates are permitted under the depreciation study rule, and PEF used its forecasted 2008 and 2009 data in its remaining life calculations. However, as noted by OPC, PEF’s salvage data was provided through December 31, 2007. (EXH 84, Section 8) PEF contended that because its life analyses did not include 2008 and 2009 forecasted addition and retirement data, then its salvage analyses did not necessitate updated data. (TR 3572) As noted by OPC, to the extent there were significant additions and retirements forecasted and these were not considered in the analyses, PEF’s proposed net salvage results could be overstated. (TR 2074-2076) Staff agrees with OPC and also believes that the same can be said with regard to PEF’s life analyses. Whether estimating life or salvage characteristics, the data being studied, estimated if necessary, should match the implementation date of proposed depreciation rates. Staff believes this is another reason to question PEF’s proposals.
Staff’s net salvage proposals for each account reflect PEF’s historical salvage analysis adjusted for interim retirements using the applicable constant retirement rates discussed previously. As with the determination of lives, staff truncated the constant interim retirement curve at the date of retirement. As the OPC witness proposed, where the historical data yielded a positive net salvage, staff conservatively recommends a zero interim net salvage. With respect to OPC’s additional proposal that PEF be directed to perform a detailed, thorough, and documented depreciation study for its next regularly scheduled filing, staff believes the substance of this proposal is set forth in the depreciation study rule and no other direction is necessary.
CONCLUSION
Staff’s recommended depreciation parameters and resulting depreciation rates for production plant are shown on Table 12-1. The reserve positions shown incorporate the effects of the staff recommended reserve allocations addressed in Issue 15. The resultant test year depreciation expenses based on the staff recommendation in this issue and in Issue 13 are addressed in Issue 75.
What are the appropriate depreciation parameters (remaining life, net salvage percent, and reserve percent), amortizations, and resulting rates for each transmission, distribution, and general plant account?
Recommendation:
Staff’s recommendations for these accounts are found in Table 13-2. (Ollila)
Position of the Parties
PEF:
The appropriate depreciation parameters, amortizations and resulting rates for each transmission, distribution and general plant account are those set forth in the 2009 Depreciation Study filed as Exhibit No. EMR-2 to the testimony of Mr. Robinson.
OPC:
The Commission should adopt the depreciation rates as recommended by OPC witness Pous as outlined specifically in his testimony as contained in Exhibit 133 (JP-1). The net salvage results proposed by the company are unrealistic and undocumented. The Commission should accept witness Pous’ recommendations regarding net salvage as shown on Exhibit 142 (JP-10).
AFFIRM:
No position.
AG:
The appropriate depreciation parameters are those recommended by Jacob Pous.
FIPUG:
Agree with OPC.
FRF:
The appropriate depreciation parameters are those recommended by witness Jacob Pous on behalf of the Citizens of the State of Florida.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ Arguments
PEF
PEF argued that its “Depreciation Study was prepared in accordance with the Commission’s applicable depreciation rules and generally accepted utility industry depreciation methods.” (PEF BR 23) PEF’s proposed pro forma depreciation rates were developed using 2007 data updated with budget activity for 2008 and 2009. (PEF BR 24) PEF argued that no intervenors disputed PEF’s depreciation study methodology; rather, they disputed some of the results of the study. (PEF BR 24-25)
PEF depreciation witness Robinson averred that the “process of service life and future net salvage estimation is interpretative as opposed to an arithmetic approach.” (EXH 36, BSP 1216; PEF BR 57) He asserted that while analysis of historical information is used to determine what has occurred in the past, “there is no assurance that the future will mirror past circumstances.” (EXH 36, BSP 1188) He asserted that a depreciation professional uses personal knowledge and experience of property classes, but also considers other factors. (EXH 36, BSP 1216) These factors include the account’s content, “detailed” discussions with PEF, whether the composition of the account has changed over time, changes in the growth of the account, the ages of the property under analysis, and what impact future retirements are expected to have on plant lives. (EXH 36, BSP 1216; TR 3618)
Witness Robinson included retirements, cost of removal, and salvage data that occurred as result of the 2004-2005 hurricanes in his historical life analysis. Witness Robinson did not consider hurricane-impacted retirements to be abnormal or atypical data. (EXH 36, BSP 1115) Witness Robinson included hurricanes because they “occur with sufficient frequency [such] that it is highly probable that they will regularly impact property over its typical useful life.” (EXH 36, BSP 1115) When asked in his deposition for an example of an atypical event that he would exclude from analysis, witness Robinson responded that a 9/11-type attack would be excluded. (EXH 312, p. 10)
Witness Robinson excluded gross salvage related to “return to stores” (inventory) because these transactions “are not true gross salvage” because “they are simply an accounting entry related to limited retirements of the Company’s total plant in service and are applicable to reuse of material within the Company’s operating system.” (EXH 36, BSP 1223) Witness Robinson averred that the inclusion of these items in future net salvage estimates is inappropriate because “[T]he overwhelming majority of retired property in service will not experience such treatment . . . .” (EXH 36, BSP 1223)
PEF witness Robinson based the average service lives for certain transmission and distribution accounts on the “judgment and consideration of industry data” because of “limited or no available” PEF data. (EXH 36, BSP 1118) The industry data used by witness Robinson was from an AGA/EEI (American Gas Association/Edison Electric Institute) depreciation survey. (EXH 36, BSP 1118) Although witness Robinson’s use of industry data will be discussed in the account-specific portion of this recommendation, staff notes that for each account, witness Robinson’s proposed average service life is longer than industry average life contained in the survey. (EXH 36, BSP 1118)
Witness Robinson characterized his approach to a depreciation study as a “fresh start;” that is, he does not view the results of the prior study until after the current study is completed. (EXH 36, BSP 1188) Witness Robinson asserted that “[U]nless there is some compelling reason to maintain the existing depreciation parameters (which is not typically the circumstance) the newly estimated parameters become the basis of the proposed depreciation rates . . . .” (EXH 36, BSP 1188)
OPC
OPC witness Pous provided testimony as well as specific proposals for some of the transmission, distribution, and general plant accounts. OPC argued that PEF’s depreciation study is in violation of Rule 25-6.0436, F.A.C., because “PEF did not provide the mandatory, required specific substantiating” information. (OPC BR 7) OPC witness Pous asserted that the basis for PEF’s study is not in the study, workpapers, and responses to data requests where witness Pous requested the basis for PEF’s proposals. (TR 2193) OPC argued that PEF witness Robinson “acknowledged that the company [sic] did not file the documentation required by the rule.” (OPC BR 9) In its brief OPC contended that because of “this failure alone, the Commission should accept the recommendations of OPC witness POUS [sic] relating to all depreciation issues.” (OPC BR 8) Witness Pous noted that PEF described the depreciation study process as one that is “interpretative,” not “arithmetic;” however, witness Pous asserted, what was presented by PEF was “numerical” and without “any other basis, narrative, explanations.” (TR 2193) Witness Pous further contended that in the 2005 PEF depreciation study, witness Robinson provided a narrative, unlike the 2009 depreciation study. (TR 2193)
Witness Pous disagreed with PEF witness Robinson’s view that hurricane data should not be removed from the study. He asserted that, “[T]o base a negative net salvage proposal on unusual activity which reflects higher costs of removal than would be anticipated during more normal operation should not be relied upon for establishing long term net salvage expectations.” (TR 2127)
PEF Rebuttal
PEF argued that, “[B]ased on the evidence, sound regulatory policy, and well recognized depreciation principles, their [intervenor witnesses] recommendations must be rejected.” (PEF BR 25) PEF witness Robinson asserted that “it is my testimony that a depreciation expert can turn to the study, look at the range of data and rather quickly visualize and interpret what we estimated in the way of net salvage and to either agree or disagree with that estimate.” (TR 1181) PEF characterized OPC’s study as “results-driven;” for example, OPC’s recommendations to increase average service lives for “two of the largest” accounts “have a much larger impact on the Company’s level of depreciation expense.” (PEF BR 56)
In his response to a question about the information available in the study for a particular account, witness Robinson testified that
It’s there, black and white. It’s in data. One can see it. I would anticipate that anyone that is investigating this study would be knowledgeable in depreciation analysis, and if they look and see that I’ve estimated zero percent, to me – maybe I’m reading things into it, but to me it’s rather obvious that, well, you’ve experienced positive salvage, it’s now turned negative, so certainly zero would be a reasonable, gradual approach in the middle of that estimate. (TR 1182-1183)
Witness Robinson further testified that those knowledgeable about depreciation might not “concur” with his answer, but that they could either accept or reject his estimate based upon the range of data that is there. (TR 1183-1184)
Witness Robinson compared his proposed net salvage factors for selected plant accounts with those for Florida investor-owned utilities. (TR 3615) His comparison included proposed net salvage percentages for FPL and Gulf, with Commission-approved net salvage for TECO. (TR 3615-3616) Witness Robinson asserted this comparison shows that his proposals “are reasonably comparable, if not lower, than [the] other operating entities. . . .” (TR 3616) While witness Robinson asserted that net salvage factors should be based on the merits of the information within each operating company, the comparison demonstrates that his recommendations are not excessively negative and in fact are conservative. (TR 3616)
PEF argued that the comparison of net salvage factors “demonstrates that OPC’s proposed net salvage factors for PEF and FPL are driven by a results oriented approach.” (TR 3616; PEF BR 58) According to witness Robinson, OPC witness Pous “recommended a considerably lower level of negative net salvage for PEF’s property than he recommended for FPL’s property.” (TR 3616)
ANALYSIS
Staff’s recommended depreciation parameters include the remaining life, net salvage percent, and reserve percent, all of which are used to calculate the remaining life depreciation rate. Parties also provided a proposal for a curve and average service life (often referred to as ASL), both of which are used in the calculation of the remaining life. Curves are generally denoted by a letter that describes when retirements are more likely to occur. An L curve implies that retirements tend to occur early in the average life, while an R curve implies that retirements tend to occur after the average life of plant. (TR 1106) The average service life denotes the average number of years that the plant within a particular account is expected to live. While the ASL may be based, at least in part, on historical data, it is prospective in its outlook and implementation. The remaining life is the average number of years left for plant in the account.[20] The net salvage, also based on historical data and prospective in outlook, is the sum of the gross salvage and cost of removal. The reserve percent is calculated by dividing the book reserve by the original cost of plant.
Staff notes that the reserve is discussed in Issue 15. Account 370.00, Meters, has a negative reserve balance because of significant retirements due to a change-out in meters. The book reserve for Account 367.00 (Underground Conductors and Devices) is less than the calculated theoretical reserve, the minimum level it should be. In order to bring the reserves for Accounts 370.00 and 367.00 back in balance, staff recommends reserve transfers from Account 362.00 (Station Equipment) and 366.00 (Underground Conduit) to Accounts 370.00 and 367.00. Because the reserve is used in the calculation of the remaining life rate for these accounts, the reserve transfers will affect any comparison between PEF’s and OPC’s proposed remaining life rates and staff’s remaining life rates and resulting depreciation accruals.
Account 396.00, Power Operated Equipment has a negative reserve for which staff also recommends a reserve transfer, from Account 365.00, Overhead Conductors and Devices. The reserve for Account 396.00 does not have an impact on its depreciation rate because the rate is a specific rate, originally approved in Order No. PSC-05-0945-S-EI in Docket No. 050078-EI, issued September 28, 2005, page 164.
OPC witness Pous provided testimony as well as proposals for some of the transmission, distribution, and general plant accounts. PEF’s and OPC’s arguments can be divided into those that apply to all accounts and those that are account-specific. Staff will discuss the parties’ arguments that apply to all accounts first and then follow with an account-by-account analysis which includes arguments specific to each account.
Not unexpectedly, there are many points of disagreement between PEF and OPC. Two of the most significant include the required and appropriate level of supporting documentation, and whether the impacts of hurricanes should be included in, or excluded from, the data analyzed.
A key element missing from PEF’s proposals is a narrative that explains the reasons for proposed changes. PEF’s view is that any person knowledgeable in depreciation can review the study data and understand why PEF is proposing what it is. As a corollary to that, PEF believes that a “fresh start” is appropriate and that it is not necessary to explain large differences between current and proposed parameters because the data tells the story.
Narratives are the simplest way to describe the underlying reason why, for example, a change in curve from L2 to R3 is being proposed. Staff believes that the level of explanation or narrative preferred may differ depending on the difference between the current and proposed parameters. However, staff believes that the burden is on the Company to provide a depreciation study that adequately explains the basis for its proposals. While a review of the data analyzed provides a depreciation analyst with a great deal of information, data analysis alone does not tell the whole story. For example, most depreciation analysts familiar with recent hurricane activity in Florida will suspect that unusually high retirements and cost of removal in or adjoining major hurricane years (such as 2004 and 2005) are the results of the hurricanes. But there may be other factors at play and unless the Company explains what those factors are, staff is unable to develop a complete understanding of what is occurring in each account.
Staff is puzzled by PEF’s “fresh start” approach. Staff agrees that the data should be studied independently; however, a key part of any study is understanding what the differences are between what is currently in use and what is proposed. The reason may be as simple as four more years of data yields better results but, it may be more complex than that. Whatever the reason, the Company is in the best position to know. Staff believes that the Company should explain significant differences between its current and proposed parameters in its study.
With regard to hurricane data, PEF clearly includes it as normal data. Staff is not advocating that PEF exclude the data for years with significant hurricane impacts, but staff agrees with OPC that including hurricane data can skew the results. (TR 2130-2131) Hurricanes are a fact of life in Florida; however, predicting their frequency and severity is something not even the experts can do. Staff believes that PEF’s approach can lead to overestimating the impact of hurricanes, thus unnecessarily increasing depreciation expense. For the purpose of this proceeding and given recent hurricane activity, staff believes that it is reasonable and appropriate to discount or eliminate hurricane activity to the extent the record permits.
While PEF’s comparison of some net salvage percentages with other Florida utilities is interesting, staff notes that it is not possible to accurately compare PEF’s selected proposals with the other Florida utilities because there is no information in this record, for example, on whether FPL, Gulf, and TECO include the impacts of hurricanes in their net salvage analysis, as PEF does. Staff agrees with PEF that net salvage should be based on “the merits of the information within each operating company.” (TR 3616)
PEF argued that OPC’s proposals are “results driven.” Staff is not privy to how OPC determined the accounts for which it made proposals. Staff believes that the appropriate analysis is done on an account-by-account basis, analyzing the basis of the proposals from both PEF and OPC rather than the results.
Staff and OPC conducted extensive discovery on PEF’s depreciation study. PEF also provided additional information in its rebuttal of OPC’s proposals for certain accounts. Staff believes that the record contains sufficient information to analyze and critique PEF’s depreciation study.
Account-Specific Analysis: Transmission Plant
Account 350.10 – Land Rights
PEF proposed no change in its curve (R3), its average service life (75), or its net salvage (0 percent). PEF witness Robinson considered and based his proposal on industry data for this account. (EXH 36, BSP 1118) Industry data, obtained from the AGA/EEI depreciation survey, show an industry average life of 66 years for this account. (EXH 36, BSP 1118) None of the intervenors offered a proposal for this account different from PEF’s proposal.
Account 352.00 – Structures and Improvements
PEF proposed no change in its curve of R2.5, or its net salvage of (15) percent. PEF proposed an increase in the average service life from 60 to 75 years. None of the intervenors offered a proposal for this account that differs from PEF’s proposal.
When asked in discovery for the “specific factors” that resulted in the change of ASL, witness Robinson did not provide any information specific to this account; instead, he provided a general explanation. (EXH 36, BSP 1187)
Account 353.10 – Station Equipment
PEF proposed a modest change in the curve from R1 to R0.5, an increase in the average service life from 52 to 53 years, and no change in the net salvage of 0 percent. OPC proposed an increase in net salvage from 0 to 5 percent.
OPC argued in support of its net salvage proposal that PEF is unable to identify the “mix” of investment and retirements in this account which means that it has not investigated the investment mix and retirement mix to see if the historical data represents current expectations. (TR 2115; TR 2118) OPC also argued that transformers have increased in scrap value recently. (TR 2117) Witness Pous also asserted that, “Mr. Robinson has over reacted to recent negative net salvage occurrences that correspond to hurricane time frames.” (TR 2118)
PEF witness Robinson responded that a portion of the large net salvage in 2007 was related to over 50 transformers that had been long out of service. (TR 3598) According to witness Robinson, excluding the effect of these old transformers would have resulted in (22.2) net salvage. (TR 3598) Witness Robinson opined that any increase in scrap value is “far from certain.” (TR 3599) PEF witness Robinson’s rebuttal is persuasive to staff; therefore, staff believes keeping the net salvage of 0 percent is appropriate.
Account 353.20 – Station Equipment – Station Control
PEF proposed a significant change in its curve, from L2 to R3, but no change in its average service life of 17 years, and its 0 percent net salvage. None of the intervenors offered a proposal for this account different from PEF’s proposal.
As described earlier, an L curve implies that retirements tend to occur early in the average life, while an R curve implies that retirements tend to occur after the average life of plant. When asked in discovery for the specific factors that resulted in the need to change the curve, other than the results of the depreciation program’s computer analysis, PEF witness Robinson responded with a general response that described his “fresh start” approach. (EXH 36, BSP 1189) He stated that the results of the previous study are not compared to the current study until the current study has been completed. He asserted that, “[U]nless there is some compelling reason to maintain the existing depreciation parameters (which is not typically the circumstance) the newly estimated parameters become the basis of the proposed depreciation rates being set forth in the current depreciation study.” (EXH 36, BSP 1189) Witness Robinson did not provide specific reasons that could account for the change from an L curve to an R curve. Staff believes that a curve change from L2 to R3 is too great a change to occur without any information about why the average plant appears to be retiring at a later age. Staff believes that witness Robinson’s support for his change in curve was inadequate. Therefore, staff believes that a more reasonable approach is to retain the L2 curve.
Account 354.00 – Towers & Fixtures
PEF proposed a modest change in its curve, from R4 to R3, an increase in average service life from 58 to 65 years, and a decrease in net salvage, from (25) percent to (30) percent. PEF witness Robinson considered and based his proposal on the AGA/EEI industry data for this account, which show an industry average life of 50 years. (EXH 36, BSP 1118) None of the intervenors offered a proposal for this account different from PEF’s proposal.
PEF’s proposed original cost balance for this account is $66.5 million dollars as of December 31, 2009. Since 1999, there have been retirements in only three years: 2002 ($165,088), 2005 ($2.6 million), and 2007 ($5,484). (EXH 84, pp. 8-78 through 8-81) Staff believes that these limited retirements over the past ten years lend credence to PEF’s proposed lengthening of life to 65 years. Although the cost of removal has been negative since 2003, staff believes that the limited amount of data is inadequate to support a decrease in net salvage from (25) percent to (30) percent.
Account 355.00 – Poles and Fixtures
PEF proposed a modest change in the curve from R1.5 to R2, a decrease in the average service life from 40 to 38 years, and a decrease in net salvage from (25) to (50) percent. OPC proposed that the net salvage remain at (25) percent.
OPC argued that its net salvage recommendation “does not react to the unexplained 5 to 10 fold increase in cost of removal” seen by PEF during the last several years, coincident with hurricane impacts. (TR 2120) OPC witness Pous asserted that gross salvage has occurred in “only” one of the last four years, which “contrasts significantly” with PEF’s historical gross salvage of 36 percent. (TR 2120)
PEF witness Robinson does not address the impact of hurricanes; however, he did point to “some modest level of third party damages.” (TR 3600) Witness Robinson also speculated that a “sizeable portion of the recorded gross salvage is likely property returned to stores,” and thus “not real salvage at all.” (TR 3600) Staff believes OPC’s argument in favor of retaining the current net salvage is persuasive and provides for a moderate result.
Account 356.00 – Overhead Conductors and Devices
PEF proposed a modest change in curve from R2 to R1.5, an increase in average service life from 48 to 55 years, and no change in the (30) percent net salvage. OPC proposed an increase in salvage from (30) percent to (10) percent.
OPC argued that its proposed net salvage of (10) percent “recognizes that prior to the impact of the recent hurricanes the Company had almost exclusively experienced positive net salvage for this account.” (TR 2121-2122) OPC also argued that PEF “appears to be overreacting to the excessive level of negative net salvage incurred in association with various projects that are heavily weighted to hurricane activity.” (TR 2122)
PEF did not respond to OPC’s argument concerning hurricane impacts. PEF witness Robinson did not provide an explanation of “considerable levels of negative net salvage;” rather, he discussed his belief that “historical gross salvage will simply not occur at the end of the property’s life.” (TR 3601) Witness Robinson noted that there will be “some level” of scrap value but it will be limited due to primarily aluminum conductors. (TR 3601)
Staff believes that OPC’s observation that hurricane impacts likely account for net salvage appearing too negative is persuasive; however, staff is concerned that OPC’s recommended change from (30) to (10) percent net salvage might be drastic. Staff believes the record supports a compromise between the two positions; staff recommends (20) percent.
Account 357.00 – Underground Conduit
PEF proposed a modest change in its curve from R2.5 to R3, no change in its average service life of 55 years, and no change in its net salvage of 0 percent. This is one of the accounts for which PEF witness Robinson used industry data. The industry average life for this account is 51 years, less than PEF’s proposed 55 years. (EXH 36, BSP 1118) None of the intervenors offered a proposal for this account different from PEF’s proposal.
Account 358.00 – Underground Conductors and Devices
PEF proposed a modest curve change from R2.5 to R3, a decrease in the average service life from 55 to 50 years, and no change in the net salvage of (3) percent. OPC proposed an increase in net salvage from (3) percent to 0 percent.
OPC witness Pous asserted that, absent any narrative explanation in PEF’s 2009 depreciation study, he looked to PEF’s 2005 depreciation study for insight. According to witness Pous, the 2005 depreciation study estimated the net salvage at (3) percent because of the “limited size of the amount of the property.” (TR 2124-2125) According to witness Pous, there have been four retirements in 31 years and the overall net salvage is (0.27) percent. (TR 2125) Witness Pous contended that a net salvage of zero is the “only appropriate” net salvage based on the information available. (TR 2125)
PEF witness Robinson responded that “a modest level of future negative net salvage will be required to disconnect the facilities. . . .” (TR 3602) This is one of the accounts for which PEF used industry data for the average service life, which shows an average age of 39 years. (EXH 36, BSP 1118)
Staff is not persuaded by PEF’s arguments. Staff agrees with OPC witness Pous a net salvage of 0 percent is appropriate in light of the extremely limited historical data and the long life of this account.
Account 359.00 – Roads and Trails
PEF proposed a modest change in the curve, from R2.5 to R3, a decrease in average service life from 90 to 75 years, and no change in net salvage (0 percent). None of the intervenors offered a proposal for this account different from PEF’s proposal.
PEF explained the decrease in life in general terms; however, it did not offer any specific reasons for the proposed decrease in life. This account is one of the accounts for which witness Robinson relied on his industry survey data. The industry average life for this account is 58 years. (EXH 36, BSP 1118) Staff believes the evidence to change the ASL is inadequate and the magnitude of PEF’s proposed change is too large; therefore, staff recommends that the ASL remain at 90 years.
Account-Specific Analysis: Distribution Plant
Account 360.10 – Land Rights
PEF proposed no change in its curve (R3), its average service life (75), or its net salvage (0 percent). PEF relies on industry data for use with this account. (EXH 36, BSP 1118) The average life for PEF’s industry data is 57 years. None of the intervenors offered a proposal for this account different from PEF’s proposal.
Account 361.00 – Structures and Improvements
PEF proposed a modest change in its curve, from R2.5 to R2, an increase in the average service life from 55 to 75 years, and a decrease in the net salvage, from (5) percent to (10) percent. None of the intervenors offered a proposal for this account different from PEF’s proposal.
Witness Robinson provided no specific explanation for the change in net salvage. However, in a discovery response, he stated that, “ . . . the current estimate of future net salvage is based upon a conservative approach in that current estimates are routinely focused on more recent experience with a gradualism towards the longer term future net salvage forecast.” (EXH 36, BSP 1217) Staff believes that PEF’s proposal appears to be reasonable.
Account 362.00 – Station Equipment
PEF proposed a modest change in curve from R1 to R0.5, an increase in the average service life from 45 to 60 years, and no change in the net salvage of (15) percent. OPC proposed an increase in the net salvage from (15) to 0 percent.
OPC’s primary arguments for increasing net salvage included removing the impact of recent hurricanes and an expected increase in scrap metal prices. (TR 2127) PEF witness Robinson asserted that OPC witness Pous “ignored” the historical data provided to witness Pous at his request. (TR 3602-3603) PEF also argued that increases in scrap prices are “far from certain.” (TR 3603)
While staff believes OPC’s hurricane impact argument to be persuasive, staff is concerned that a change in the net salvage from (15) to 0 percent is too great an increase. Staff believes that net salvage should be increased; however, the increase should be smaller. Staff believes a change from (15) to (10) percent is a moderate change that also recognizes OPC’s hurricane impact argument.
Account 364.00 – Poles, Towers, and Fixtures
PEF proposed a significant change in curve from L4 to R4, an increase in average service life from 28 to 29 years, and a decrease in net salvage from (35) percent to (50) percent. OPC proposed an increase in average service life from 28 to 35 years, an R3 curve, and no increase to the (35) percent net salvage.
This is one of two accounts where OPC proposed a change in average service life (the other is Account 368.00, Line Transformers). OPC witness Pous asserted that PEF’s proposed average service life is “significantly shorter than any ASL Mr. Robinson has presented for investment in this account during the past 10 years.” (TR 2094) This fact alone, OPC argued, “should have caused Mr. Robinson to further investigate or explain in detail why” his proposed life is appropriate. (TR 2094) OPC also pointed to significantly higher retirements for a three-year period. (TR 2095) OPC witness Pous averred that this period of higher retirements, unexplained by PEF, can have an impact on the shape of the survivor curve, “indicating a longer ASL.” (TR 2097) OPC argued that its 35-year ASL proposal is a “conservative estimate” for this account. (TR 2100)
PEF witness Robinson asserted that OPC witness Pous reached his proposal by eliminating retirements that did not assist his objective and by using unsupported statements and conclusions. (TR 3577) Yet, the retirements are substantial enough that staff believes they should have been explained by PEF witness Robinson. Witness Robinson, however, did not offer any reasons for the retirements referred to by OPC.
PEF witness Robinson averred that he believes it “inappropriate” to depend on studies for other companies when PEF-specific data is available. (TR 3578) Witness Robinson summed up his rebuttal by stating that “Mr. Pous’ estimate is simply a results oriented estimate from other operating company’s service life information.” (TR 3579)
Staff believes that both PEF and OPC made good arguments; however, staff is uncomfortable with the lack of explanation for the retirements in the three-year period. At the same time, staff is uncomfortable with basing a recommendation on what PEF witness Robinson has presented in other cases. Staff believes the most reasonable approach is a compromise. Therefore, staff recommends an average service life of 32 years.
PEF proposed a change in curve from L4 to R4, while OPC proposes an R3 curve. Staff notes that when the average service life is changed to 32 years, the difference in remaining lives between the L4 and R4 is one tenth of a year. With a modest difference between the R3 and R4 curves, staff believes it is reasonable to recommend an R4 curve.
PEF and OPC disagreed as to the appropriate net salvage. PEF proposed a decrease in net salvage from (35) to (50) percent while OPC proposed that net salvage remain at (35) percent. According to OPC witness Pous, PEF’s proposal relies on “data that the Company admits occurred ‘under catastrophic circumstances.’” (TR 2129) OPC argued that its proposal of (35) percent “is very conservative while providing additional time to determine how net salvage levels settle once the impacts of catastrophic circumstances associated with hurricane activity subside.” (TR 2130)
PEF argued in response that OPC’s “proposal is based heavily on historical data as opposed to consideration of future expectancies.” (TR 3604) PEF witness Robinson asserted that the cost of removal is “likely” to return to higher levels, fueled in part by labor costs and “the fact that retirements and related cost of removal routinely occurs randomly” in PEF’s service territory, thus necessitating “extensive travel time.” (TR 3605) Witness Robinson considered his proposal of (50) percent to be “conservative.” (TR 3605-3606)
Since PEF witness Robinson effectively built the effects of the 2004 and 2005 hurricanes into his analysis, staff is concerned that his proposal understates net salvage. Staff believes the appropriate approach is to retain the current net salvage of (35) percent.
Account 365.00 – Overhead Conductors and Devices
PEF proposed a modest change in curve from R2 to R0.5, an increase in the average service life from 33 to 36 years, and a decrease in net salvage from (15) percent to (45) percent. OPC proposed a decrease in net salvage from (15) to (20) percent.
OPC witness Pous asserted his proposal places less weight on more recent data for two reasons. (TR 2130) The first reason is that PEF admitted it did not report gross salvage for 2003 – 2006. The second reason is that PEF stated that retirements in 2004 and 2005 include equipment removed due to hurricane damage. (TR 2130) Hurricane damage accounted for approximately 67 percent of retirements in 2004 and 64 percent in 2005. (EXH 36, BSP 1093) The 2004 and 2005 hurricanes have also caused the cost of removal to fluctuate because of timing differences. (EXH 36, BSP 1093)
PEF explained that the reason for no gross salvage was because of a “true-up of the salvage for return to stores inventory that was processed in 2007.” (EXH 36, BSP 1093) According to PEF, this account’s property units are “normally scrapped.” (EXH 36, BSP 1093)
OPC witness Pous averred that PEF’s net salvage proposal “appears to be in reaction to hurricane related activity.” (TR 2131) Staff agrees and believes that net salvage of (20) is more reasonable.
Account 366.00 – Underground Conduit
PEF proposed a modest change in curve from R3 to R2.5, an increase in average service life from 55 to 67 years, and a decrease in net salvage from 0 to (10) percent. OPC proposed that the net salvage remain at 0 percent.
OPC argued that if the plant is abandoned there should be minimal negative net salvage and that if the plant is removed, there should be some gross salvage. (TR 2132) OPC also noted the “excessive level of cost of removal the Company experienced during the recent hurricanes.” (TR 2132) According to OPC witness Pous, PEF proposed 0 percent net salvage in its last (2005) depreciation study. (TR 2132)
PEF argued that OPC’s proposal “is entirely based upon the statement that the property will be abandoned in place irrespective of the fact that the Company has experienced negative net salvage.” (TR 3607) Witness Robinson asserted that the “very modest” (10) percent net salvage is reflective of the fact that “much of the property may be abandoned in place.” (TR 3607)
Staff believes that both parties make good points in their arguments. In an effort to at least partially remove the hurricane impact and to account for cost of removal for abandoned plant, and finally, in an effort to change the net salvage in a more gradual manner, staff recommends a compromise, a net salvage of (5) percent.
Account 367.00 – Underground Conductors and Devices
PEF proposed a modest change in curve from R3 to R2, an increase in average service life from 34 to 35 years, and a decrease in net salvage from (5) percent to (10) percent. OPC proposed no change in net salvage, leaving it at (5) percent.
When asked in discovery why PEF is proposing to change the net salvage from (5) to (10) percent, witness Robinson provided the same answer that he provided for other accounts, which is the “fresh start.” (EXH 36, BSP 1110) PEF’s response stated that the “newly estimated parameters” are used unless there is “compelling evidence” not to use them. (EXH 36, BSP 1771)
OPC argued that if the excessive levels of negative net salvage associated with calendar years 2004 and 2005 were excluded, PEF’s net salvage would be positive. (TR 2134) OPC witness Pous also stated that PEF “admits” to retiring investment in place. (TR 2134) Witness Pous asserted that when PEF actually retires and removes conductors, there should be gross salvage associated with the retirements. (TR 2134) According to witness Pous, a net salvage of (5) percent “may also be excessively negative.” (TR 2134)
PEF witness Robinson did not address hurricane impacts. While he agreed that gross salvage is possible with “third party damage,” he asserted that “it is extremely unlikely that levels [of gross salvage] anywhere near the levels recorded in the past will be applicable. . . .” (TR 3608) He also asserted that cost of removal “actually forecasts to in excess of” 130 percent. (TR 3608-3609) Staff believes OPC’s proposal to retain (5) percent net salvage is a reasonable approach in the face of significant hurricane impacts in recent data.
Account 368.00 – Line Transformers
PEF proposed a modest change in curve from R2.5 to R2, an increase in average service life from 26 to 27 years, and a decrease in net salvage from (5) to (15) percent. OPC proposed an increase in the ASL from 26 to 33 years, an S0.5 curve, and no change in the net salvage of (5) percent.
OPC’s arguments for an increased life for this account are similar to the arguments for an increased life in Account 364.00, Poles, Towers, and Fixtures. PEF witness Robinson’s rebuttal is also similar to his rebuttal for Account 364.00. However, for this account, OPC proposed a different mode curve, an S0.5. Staff believes a compromise is the most reasonable approach for the ASL; however, for the curve, staff believes that PEF’s proposal is reasonable. Staff believes an R2 curve with a 31 year ASL is a reasonable compromise.
For net salvage, PEF proposed a change from (5) to (15) percent while OPC proposed that the net salvage remain at (10) percent. The OPC witness asserted that hurricane-related retirements need to be taken into account. (TR 2135) Witness Pous asserted that during 2005 and 2006 PEF retired a “significantly higher percentage” of equipment which is “opposite” the actual investment mix. (TR 2135-2136) OPC witness Pous characterized his proposal as “conservative.” (TR 2136) PEF witness Robinson countered that there is a “recent decline” in gross salvage, while cost of removal levels have been increasing in the “last several years.” (TR 3609) Staff believes both parties have made good arguments; therefore, staff believes a compromise of (10) percent is appropriate.
Account 369.10 – Services – Overhead
PEF proposed no change in the R3 curve, a decrease in average service life from 36 to 34 years, and no change in the net salvage of (50) percent. OPC proposed to increase the net salvage from (50) to (40) percent.
OPC argued that PEF did not recognize that the most recent data, including the effects of hurricanes, result in a positive net salvage. (TR 2137) Since 2001, there have been retirements only in 2004, resulting in a net salvage of 2.67 percent. (EXH 84, pp. 8-131) According to OPC witness Pous, reliance on recent data would serve to reduce the negative net salvage; however, he based his recommendation on the “concept of gradualism . . . only recommending a change to a negative 40% net salvage for this account.” (TR 2137)
PEF witness Robinson asserted that OPC witness Pous’ assertion that recent data yields a positive level of net salvage is “incorrect and unsupported.” (TR 3610) PEF witness Robinson further averred that OPC witness Pous was “wrong” when he asserted that this account “routinely generate[s] positive salvage” because of the labor intensive removal and limited scrap value. (TR 3610) Witness Robinson asserted that although there may be gross salvage in the future, “nothing near the overall recorded levels of gross salvage will be experienced. . . .” (TR 3610-3611) Staff believes OPC’s argument is persuasive; it is a moderate change, based on available data.
Account 369.20 – Services – Underground
PEF proposed a relatively modest change in curve from R2.5 to R0.5, an increase in average service life from 38 to 43 years, and a decrease in net salvage from 0 to (15) percent. OPC proposed that the net salvage remain at 0 percent.
OPC argued that the net salvage should be increased because PEF’s proposal “appears to react to a major cost of removal reported during 2005 corresponding to hurricane related activity.” (TR 2138) Witness Pous asserted that “Mr. Robinson’s failure to compensate in any manner for the unusual storm related activity during the last several years is incorrect and unacceptable.” (TR 2139) According to witness Pous, if PEF had eliminated the retirements and the corresponding negative net salvage from 2005, overall net salvage for the last 10 years would have been between zero and (4) percent. (TR 2139)
PEF witness Robinson disagreed that hurricane damage is a “contributing factor to negative net salvage” because with underground facilities, “little, if any hurricane damage would occur.” (TR 3611) Witness Robinson asserted that PEF’s historic net salvage of (6) percent is “influenced by the significant levels of positive salvage during the 1970’s and early 1980’s.” (TR 3611) Witness Robinson averred that even if “much if not most” of this account will be abandoned in place, there will still be cost of removal because PEF will need to disconnect the plant. (TR 3612)
Staff believes that PEF’s argument is somewhat persuasive, even with hurricane-related retirements included. Staff also agrees with OPC that the net salvage should not be changed from 0 to (15) percent. Staff believes that a net salvage of (5) percent is an appropriate compromise.
Account 370.00 – Meters
PEF proposed a relatively modest change in the curve from R2.5 to R0.5, a decrease in the average service life from 26 to 18 years, and a decrease in net salvage from (8) to (10) percent. OPC offered a proposal to increase the net salvage from (8) to (6) percent.
PEF witness Robinson testified that PEF’s proposed 18-year average service life was based on his analysis of meter investment through December 31, 2007. (EXH 36, BSP 1301) Witness Robinson further testified that because of changing technology, the historical experience is considered “conservative,” and that 18 years is likely the maximum life in the future. (EXH 36, BSP 1301) OPC witness Pous provided no testimony pertaining to the average service life. Staff believes that PEF’s average service life proposal is reasonable based on the record evidence.
This account saw significant retirements in 2006, approximately $82 million. (EXH 84, p. 8-139) Of this amount, about $81 million of the retirements were related to replacing current meters with advanced meters, known as AMR (automatic meter reading) meters. (EXH 36, BSP 1040) According to PEF, historical net salvage for this account averaged (7) percent, “dramatically influenced by the change out of a significant quantity of meters during the last couple of years.” (TR 3612-3613) Salvage amounts reflected in 2005 and 2006 were part of a formal salvage agreement PEF had with the vendor of the new meters. (EXH 36, BSP 1099) PEF witness Robinson asserted that with the meter project complete in 2007, he expects a return to a “more typical” cost for net salvage of (10) to (15) percent or higher. (EXH 36, BSP 1761; TR 3613)
OPC witness Pous proposed a change in net salvage to (6) percent because this is reflective of the net salvage percent achieved after 2005 retirements. (TR 2141) Witness Pous also pointed to the experience of a utility in Texas that achieved a cost of removal per meter of $5.63. According to witness Pous, relying on a cost of removal per meter of $5.63 in PEF’s territory would result in net salvage close to (6) percent. Therefore, he recommends (6) percent cost of removal. (TR 2141)
Staff believes that it is premature to decrease the net salvage, as PEF proposes. There has been a large change in the account with the addition of the new AMR meters. Staff does not believe that using the information provided by witness Pous on the Texas utility’s cost of removal per meter is sufficient to be used as support for an increase in net salvage. Additionally, the negative net salvage achieved by PEF for the $82 million of retirements was in part based on a salvage agreement with the vendor. Staff believes that the appropriate approach at this time is to retain the current net salvage of (8) percent.
Account 371.00 – Installation on Customers Premises
PEF proposed no changes in its curve (R2) or its net salvage of 0 percent. PEF proposes to lengthen the average service life from 24 to 25 years. PEF witness Robinson considered an industry life of 19 years for this account. (EXH 36, BSP 1118) None of the intervenors offered a proposal for this account different from PEF’s proposal.
Account 373.00 – Street Lighting and Signal Systems
PEF proposed a modest change in the curve from L2 to L1.5, an increase in the average service life from 17 to 20 years, and a decrease in net salvage from 0 percent to (20) percent. OPC proposed a decrease in net salvage from 0 percent to (5) percent.
OPC witness Pous averred that his proposed net salvage of (5) percent is “both reasonable and appropriate, but [that] it does not give adequate weight to the potential of selling future street lighting systems.” (TR 2142) Witness Pous asserted that because of the future sale potential, his recommendation is “conservative in favor of the Company.” (TR 2142)
PEF witness Robinson asserted that “much of the gross salvage is likely attributable to return to stores,” which “is not true gross salvage.” (TR 3614) According to witness Robinson, there are no anticipated street lighting acquisitions. (TR 3614) Staff believes that OPC’s arguments are more persuasive.
Account-Specific Analysis: General Plant
Account 390.00 – Structures and Equipment
PEF proposed a modest curve change from L0 to L0.5, a decrease in the average service life of four years from 28 to 24, and a decrease in net salvage, from 0 to (5) percent. OPC proposed a net salvage of 15 percent.
OPC argued that “[b]uildings can be anticipated to appreciate rather than depreciate in value . . . .” (TR 2143) OPC witness Pous asserted that given the type of investment and PEF’s proposed 24-year average service life, it is “unreasonable and unrealistic” to expect that relatively new buildings would require demolition and removal instead of a sale or reuse. (TR 2144) Witness Pous opined that “[S]ome form of net salvage is appropriate” therefore, he recommended a 15 percent net salvage. (TR 2144) PEF argued that OPC “ignores the realities of the operations of special use utility properties . . . .” (TR 3614) Witness Robinson pointed to a $12 million retirement in 2007 which resulted in net salvage of more than (5) percent. Staff believes that both parties make reasonable arguments; however, staff believes OPC’s argument is generally more persuasive. Therefore, staff is recommending a compromise net salvage of 10 percent.
Other General Plant Accounts
Pursuant to Rule 25-6.04361(5)(f), F.A.C., certain General Plant Accounts may use an amortization schedule. PEF proposed to amortize these accounts in accordance with the rule, continuing to use a seven-year amortization schedule for:
· Account 391.00 – Office Furniture and Equipment,
· Account 393.00 – Stores Equipment,
· Account 394.00 – Tools, Shop, and Garage Equipment,
· Account 395.00 – Laboratory Equipment,
· Account 397.00 – Communication Equipment; and
· Account 398.00 – Miscellaneous Equipment.
Under PEF’s proposal there will be no change to the depreciation accrual. None of the intervenors offered a proposal for this account different from PEF’s proposal.
For each of the following general accounts, PEF currently is using a depreciation rate approved in Order No. PSC-05-0945-S-EI, issued on September 28, 2005, in Docket No. 050078-EI, page 164. The accounts and their current depreciation rates are shown in Table 13-1.
Table 13-1: General Accounts with Specific Depreciation Rates
|
Account No. |
Account Name |
Depreciation Rate (percent) |
|
392.10 |
Passenger Cars |
8.7 |
|
392.20 |
Light Trucks |
8.7 |
|
392.30 |
Heavy Trucks |
4.8 |
|
392.40 |
Special Trucks |
5.0 |
|
392.50 |
Trailers |
1.7 |
|
396.00 |
Power Operated Equipment |
5.8 |
PEF proposed to continue using the previously approved depreciation rates. There will be no change to the depreciation accrual under PEF’s proposal. None of the intervenors offered any proposal for these accounts.
CONCLUSION
Staff’s recommendations for remaining life, net salvage percent, allocated reserve percent, amortizations, and resulting rates for each transmission, distribution, and general plant account are contained in Table 13-2.
Table 13-2: Current Approved and Staff
Recommended Parameters and Rates
Based on the application of the depreciation parameters that the Commission has deemed appropriate to PEF's data, and a comparison of the calculated theoretical reserves to the book reserves, what are the resulting differences?
Recommendation:
Using the life and salvage parameters staff recommends in Issues 12 and 13, a reserve surplus of $727.1 million results. (P. Lee)
Position of the Parties
PEF:
When compared with the hypothetical reserve calculated in PEF’s Depreciation Study, the book reserve shows a positive net variance as set forth in the 2009 Depreciation Study filed as Exhibit No. EMR-2, Table 5f-Future (Pro Forma).
OPC:
PEF currently has a depreciation reserve excess of $858 million. This amount is based on acceptance of OPC witness Jacob Pous’ adjustments to PEF’s depreciation study. It does not take into account OPC’s and Mr. Pous’ position that the life spans that PEF assigns to combined cycle units are too short; modifying those values to more realistic life spans in this proceeding would increase the size of PEF’s depreciation reserve excess.
AFFIRM:
No position.
AG:
Jacob Pous's testimony and exhibits indicate that Progress has a depreciation reserve excess of $858 million.
FIPUG:
PEF has a surplus depreciation reserve in excess of $646 million.
FRF:
Based on Witness Jacob Pous's testimony and exhibits, PEF has a depreciation reserve excess of $858 million.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
A reserve imbalance exists when the prospective calculated theoretical reserve is either more or less than the actual reserve. (TR 2037) Applying its proposed depreciation parameters, PEF calculated a reserve surplus of $646 million. (EXH 84, Section 2, Table 4F-Future Pro Forma, pp. 2-67 - 2-73; Robinson TR 3550; PEF BR 2, 25) OPC calculated a reserve surplus of $858 million based on its proposed parameters. (TR 2020; OPC BR 15) FIPUG witness Pollock did not calculate a theoretical reserve imbalance using his proposed depreciation parameters but accepted PEF’s calculation as a minimum amount. (TR 3197-3198; FIPUG BR 13) FRF and PCS did not submit testimony but adopted OPC’s position. (FRF BR 24; PCS BR 5) No other party took a position with respect to quantifying the difference between PEF’s book reserve and the calculated theoretical reserve.
ANALYSIS
The theoretical reserve is the calculated balance that would be in the reserve if the life and salvage estimates now considered appropriate had always been applied. (Robinson TR 3535; Garrett TR 3729-3730; Pous TR 2037; Pollock TR 3197-3198, 3225) The book reserve is the amount actually recovered to date. (TR 2037) The formula for the prospective theoretical reserve is provided in Rule 25-6.0436(4)(k), F.A.C. Using this formula and the life and salvage components staff recommends in Issues 12 and 13, staff calculates a reserve imbalance of $727.1 million, as shown in Table 14-1 below:
|
Table 14-1: Reserve Imbalance |
|
|
|
(000) |
|
Steam Production |
$173.5 |
|
Nuclear Production |
102.5 |
|
Other Production |
55.8 |
|
Transmission |
99.5 |
|
Distribution & General |
295.8 |
|
Total Reserve Imbalance |
$727.1 |
CONCLUSION
Using the life and salvage parameters staff recommends in Issues 12 and 13, a reserve surplus of $727.1 million results.
What, if any, corrective reserve measures should be taken with respect to the differences identified in the Issue 14?
Recommendation:
Staff recommends the reserve allocations shown in Table 15-1. This action will bring each affected account’s reserve more in line with its theoretically correct level. In light of concerns with reduced cash flow and the impact that a short amortization period could have on the financial integrity of PEF, including a higher cost of capital and cost of debt, resulting in higher customer rates in the long term, staff recommends that the residual remaining reserve surplus be recovered through the remaining life rate design. (P. Lee, Maurey)
Position of the Parties
PEF:
The Commission should take no corrective reserve measures with respect to these differences. The variance should be treated consistent with the Depreciation Study filed by PEF in this docket and with well established Commission precedent and be amortized over the composite average remaining life of the depreciable plant assets. PEF’s Depreciation Study filed in this docket, including the depreciation rates contained therein, should be approved by the Commission.
OPC:
PEF’s enormous depreciation reserve excess means it has over-collected depreciation expense from current customers in a way that constitutes a massive intergenerational inequity. PEF should be required to amortize $646 million of its reserve excess back to customers over a period of four years.
AFFIRM:
No position.
AG:
Support OPC’s position so that as much of this excess as possible should be returned to the consumers who paid for this excess depreciation.
FIPUG:
To compensate for the huge reserve surplus that PEF has, the Commission should order PEF to implement a $100 million annual depreciation expense adjustment. PEF should credit depreciation expense and debit to the bottom line depreciation reserve by at least $100 million per year.
FRF:
PEF's huge depreciation reserve indicates that current and recent-period customers have overpaid drastically relative to the true depreciation costs incurred by PEF, resulting in a gross inequity being imposed on those customers. The Commission should remedy this gross inequity by amortizing 75% of the surplus, or $646 million, over 4 years; limiting the amount of the surplus to be amortized will maintain PEF's financial integrity, taking account of all of the Citizens' witnesses' testimony, after reducing Progress's retail rates by $35 million per year.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
This issue addresses what actions, if any, should be taken to remedy the reserve imbalance quantified in Issue 14. All witnesses agreed that the remaining life depreciation rate methodology will resolve any reserve imbalance over the remaining life by adjusting the prospective depreciation rate. (Robinson TR 3532; Garrett TR 3883; Pous TR 2042; Pollock TR 3205) The issue in contention is whether the reserve imbalance should be corrected over a period of time shorter than the average remaining life.
PEF, OPC, and FIPUG submitted testimony specifically addressing this issue. FRF did not file testimony but addressed its position and argument in its brief. AG and PCS adopted the position of OPC. (AG BR 6; PCS BR 5) The Navy and Affirm took no position.
PEF witnesses Robinson, Garrett, and Vilbert proposed that the average remaining life depreciation approach be used to address the variance between the Company’s book reserve and the calculated theoretical reserve. (Robinson TR 3544; Garrett TR 3723; Vilbert TR 3949) OPC witness Pous proposed to amortize $646 million of his $858 million calculated reserve imbalance over four years. (TR 2021) FIPUG witness Pollock proposed to amortize $100 million of PEF’s calculated reserve imbalance each year for three years.[21] (TR 3226-3227) FRF argued in its brief that $646 million of the reserve surplus identified by OPC witness Pous should be amortized over four years. (FRF BR 28)
PARTIES’ ARGUMENTS
The issue of the reserve surplus and correction thereof was raised by the intervenors in their direct testimony. Therefore, the parties’ arguments will first discuss the intervenors’ positions, followed by a discussion of PEF’s response.
Intervenors
Both OPC witness Pous and FIPUG witness Pollock testified that PEF’s reserve imbalance is of such a magnitude that an approach other than the normal average remaining life rate design is warranted. (Pous TR 2021, 2042-2043; Pollock TR 3198, 3204) The OPC and FIPUG witnesses asserted that the existence of a reserve imbalance identifies intergenerational inequities in that current and past customers have paid more than they should have, thereby subsidizing future customers. (Pous TR 2151; Lawton TR 2218; Pollock TR 3198) In its brief, FRF concurred with the OPC and FIPUG witnesses. (FRF BR 24-25, 28)
OPC calculated a reserve imbalance in excess of $858 million. (TR 2020) FIPUG accepted PEF’s calculated reserve imbalance of $646 million as a minimum amount. (TR 3197) OPC witness Pous recommended that PEF’s calculated reserve surplus be amortized over a four-year period;[22] FIPUG witness Pollock recommended that $300 million of PEF’s reserve surplus be amortized over a three-year period.[23] (Pous TR 2046; Pollock TR 3204) By not amortizing the full amount of the reserve imbalance posited by the witnesses, they believe their proposals will leave PEF a cushion in the reserve in the event of major changes. (Pous TR 2024; Pollock TR 3204) OPC witness Pous testified that relying solely on the remaining life approach, as PEF did, the reserve imbalance would not be corrected for 21 years. (TR 2021) OPC witness Pous and FIPUG witness Pollock contended that amortizing the reserve surplus over a period shorter than the remaining life would be consistent with prior Commission decisions regarding correcting reserve imbalances. (Pous TR 2024; Pollock TR 3204-3205) FRF concurred with OPC and FIPUG. (FRF BR 24-26)
OPC witness Pous explained that the remaining life rate formula recognizes that depreciation is a forecast or estimation process that requires true-ups over time in order to achieve full recovery of the invested capital. (TR 2033) In other words, the remaining life formula will adjust the depreciation rate when a reserve imbalance is present. When the imbalance is a reserve surplus, the remaining life rate will decrease over the remaining life. (TR 2050) When a material imbalance between the theoretical and book reserve exists, witness Pous asserted that there are two general options for correcting the imbalance: 1) to amortize the imbalance over a short period of time, or 2) to implement new remaining life depreciation rates that will recover the imbalance over the average remaining life of the related assets. (TR 2038-2039) FRF argued that the National Association of Regulatory Commissioners Public Utility Depreciation Practices explicitly recognizes that amortization of a reserve imbalance is an acceptable practice. (FRF BR 26; EXH 311)
OPC witnesses Pous and Lawton and FRF asserted that the proposed four-year amortization approach is in line with the Commission’s long-established policy of correcting material reserve imbalances by the use of (1) reserve transfers between accounts, (2) one-time reserve adjustments based on changes to revenue requirements in areas other than depreciation, and (3) amortizations over a period of time shorter than the average remaining life of the investment. (Pous TR 2038-2039, 2176; Lawton TR 2228; FRF BR 25) Additionally, witness Pous referred to Order No. PSC-05-0902-S-EI, issued September 14, 2005, in Docket Nos. 050045, In re: Petition for rate increase by Florida Power & Light Company, and 050188-EI, In re: 2005 comprehensive depreciation study by Florida Power & Light Company (FPL 2005 Rate Case Settlement Order) where FPL was allowed to record a depreciation expense credit of up to $125 million per year, thereby reducing revenue requirements. (TR 2038) Witness Pous testified that the Commission’s policy regarding reserve imbalances has been to provide corrective action as fast as possible unless such action prevents the company from earning a fair rate of return.[24] (TR 2039) As support for their respective positions, OPC witness Pous, FIPUG witness Pollock, and FRF referenced a number of Commission orders that they contended reflect the amortization of reserve imbalances over periods shorter than the remaining life. (Pous TR 2040; Pollock TR 3204-3205; EXH 286, BSP 92; FRF BR 27-28)
Whether the reserve imbalance is a surplus or a deficit, witness Pous asserted that the treatment should be the same. (TR 2042) Because depreciation involves estimates of the future that change over time, reserve imbalances occur. However, they are normally treated through the remaining life rate determination process. Nevertheless, asserted witness Pous, the greater the disparity between the reserve and the theoretical reserve, the greater the level of intergenerational inequity that exists, and the more compelling the need to address the imbalance over a shorter period. (TR 2042-2043)
Witness Pous explained that the basis for his four-year proposed amortization approach was that four years is within the range of periods prescribed by the Commission in other cases where a depreciation reserve imbalance was addressed, and it “corrects the intergenerational equity situation in an effective but manageable manner.” (TR 2047) Witness Pous asserted that current ratepayers should not be penalized for the benefit of future customers, therefore warranting a shorter amortization period. (TR 2048) Moreover, contended the witness, four years is the time period between depreciation studies as required by Commission rule. (TR 2047)
OPC witness Lawton addressed the ratemaking policy and financial implications of witness Pous’ proposed amortization of PEF’s reserve surplus. Witness Lawton asserted that an amortization approach addressing PEF’s reserve imbalance is consistent with sound regulatory policy and ratemaking guidelines and will not have a detrimental effect on PEF’s financial integrity or financial metrics. (TR 2218, 2233-2235; EXH 177) Moreover, asserted the witness, amortization over a short period would ensure that the customers that paid the surplus would likely be the same customers receiving the benefits. (TR 2218)
Witness Lawton asserted that amortization of PEF’s reserve imbalance is consistent with Generally Accepted Accounting Principles (GAAP). (TR 2228) Witness Lawton testified that the correction of the reserve surplus will correct the allocation of costs over the expected useful life and will not diminish or impair the asset value. Witness Lawton contended that the issue is how much should be recovered annually over the expected remaining life of the related assets. (TR 2228) The witness stated that PEF will be afforded full recovery; correction of the reserve imbalance will assure that the recovery of capital investment will be equitably allocated over the useful life of the related assets. (TR 2228)
Witness Lawton testified that OPC’s four-year amortization approach to correct the calculated reserve surplus will reduce annual depreciation expense and thus revenue requirements each year by about $161 million. Because depreciation is a non-cash expense, witness Lawton asserted that PEF will not forego cash recovery as a result of the amortization. (TR 2229) However, at the end of the four-year period, PEF’s rate base will be $646 million higher under witness Pous’ recommendation. (TR 2230) Witness Lawton quantified the annual net impact of the proposed amortization to PEF’s pre-tax cash flow as a net reduction to PEF of about $149.3 million. (EXH 175)
In its brief, FRF argued that PEF’s suggestion that a reserve imbalance is not real money and is inconsistent with GAAP is a smokescreen. (FRF BR 26) FRF argued that PEF could not point to any specific accounting principle that an amortization approach would violate. (FRF BR 26)
With regard to financial integrity, OPC witness Lawton provided an analysis of the impacts of amortizing the reserve imbalance. He asserted that these analyses showed that PEF’s financial integrity metrics, on both a before-tax and after-tax basis, will remain within acceptable ranges for a BBB-rated utility, and even for an A-rated utility. (EXH 177) Even with the cash flow reduction resulting from the reserve imbalance amortization, witness Lawton concluded that PEF will “maintain solid financial metrics.” (TR 2233-2234) Witness Lawton asserted that the cash flow reduction will not disallow expenditures, but rather will correct the rate of asset recovery. (TR 2234-2235)
FIPUG witness Pollock did not address how his proposed amortization of the reserve imbalance will affect PEF’s financial condition. The witness testified that he had not analyzed the impact of his adjustment on PEF’s financial ratios. (TR 3227-3228)
In its brief, FRF argued that when PEF amortized $62.5 million of its surplus annually in accordance with its Order No. PSC-02-0655-AS-EI (FPC 2002 Rate Case Settlement Order),[25] the Company still earned significant annual equity returns of 13.90 percent, 13.43 percent, 13.48 percent, and 8.8 percent. While earning a return in 2007 (9.70 percent) and 2008 (9.71 percent) less than what OPC witness Woolridge recommended in this proceeding, FRF argued that PEF still provided adequate service and was able to raise capital. FRF concluded that PEF’s financial integrity should therefore be acceptable even with both the reserve surplus amortization and the return on equity of 9.75 percent recommended by OPC witness Woolridge. Moreover, FRF argued that since no rating agency criteria were entered as evidence in this docket, the Commission should not conclude that PEF needs a return on equity of more than 9.71 percent in order to protect its bond rating in the future. (FRF BR 31)
FRF asserted in its brief that PEF should be required (1) to rebalance its book reserve for each account to the theoretically correct level based on the depreciation rates ordered in this proceeding; (2) to book the identified reserve surplus to a separated, unallocated, depreciation account; (3) amortize $646 million of the unallocated reserve surplus to customers of record over four years to restore intergenerational equity as soon as is reasonably practicable based on the percentage of each class’s base rate revenues to total base rate revenues; and (4) to provide, as part of its annual report for the next four years, a theoretical reserve to book reserve comparison based on the authorized depreciation rates, and reallocate the book reserves to theoretical levels, while booking any reserve surplus to the unallocated excess reserve account. (FRF BR 28-29) FRF argued that such action will restore intergenerational equity while preserving PEF’s financial integrity. (FRF BR 28)
PEF
Contrary to the intervenors’ positions, PEF witnesses Robinson and Garrett contended that the existence of a reserve imbalance did not mean that current and prior customers paid more than they should have. (Robinson TR 3548; Garrett TR 3728) The witnesses asserted that a theoretical reserve was as the name implied: it was theoretical. (Robinson TR 3335; Garrett TR 3730-3731) Witnesses Robinson and Garrett testified that a theoretical reserve was a calculation made at a single point in time and included in depreciation studies. (Robinson TR 3538; Garrett 3729) The witnesses stated that the theoretical reserve calculation assumed that current depreciation parameters had always been in effect. Historical depreciation rates, not the proposed depreciation rates, were those paid by customers. (Robinson TR 3551; Garrett TR 3731-3732; EXH 36, BSP 1305)
PEF witness Robinson characterized the intervenors’ proposed amortization of the reserve imbalance as a “radical departure” from the remaining life depreciation standard. (TR 3555) The witness testified that the application of remaining life matches the recovery of the investment to the remaining time that property provides service to customers. (TR 3548) In its brief, PEF argued that all intervenors recognized this matching principle as a fundamental depreciation principle. (PEF BR 27)
Witness Robinson challenged the intervenors’ contention that the calculated reserve imbalance was material or significant. The witness asserted that neither OPC nor FIPUG provided an industry standard definition of a material imbalance. Witness Robinson also claimed that OPC witness Pous and FIPUG witness Pollock provided no rational or meaningful basis for their proposed short amortization periods. The PEF witness considered the intervenor proposals as nothing more than retroactive ratemaking. Witness Robinson asserted that the intervenors’ proposals did not reflect the impact of their proposed reserve imbalance in the calculation of their proposed depreciation rates. Finally, the witness contended that depreciation rates in the future would be higher to recover the short-term reductions proposed by the intervenors. (TR 3550-3554)
PEF witnesses Vilbert and Garrett asserted that OPC and FIPUG’s amortization proposals represent unsustainable rate reductions that have far-reaching financial and customer impacts. Both witnesses testified that the intervenors’ proposals 1) were contrary to the industry standard of remaining life in which depreciation rates self-adjust to correct a reserve imbalance over the remaining service life, 2) ignored the benefits that customers received from previously approved depreciation estimates, 3) were contrary to the Federal Energy Regulatory Commission (FERC) Uniform System of Accounts and GAAP, and 4) were contrary to regulatory ratemaking principles and prior Commission policy. For these reasons, the witnesses contended that the intervenor proposals should be rejected. (Garrett TR 3723-3724, 3728, 3740-3741; Vilbert TR 3913-3914, 3918-3919, 3942-3943)
Witnesses Vilbert and Garrett asserted that the intervenors’ proposals would adversely impact PEF’s cost of capital and increase its need to raise capital to replace the reduced cash flow. (Garrett TR 3741; Vilbert TR 3928-3932) Further, the reduced cash flow would weaken PEF’s credit ratios and the cost of debt may increase. The witnesses posited that the cost of equity would increase because of the uncertainty and risk introduced to investors that prior Commission decisions could be reversed in the future. (Garrett TR 3741; Vilbert TR 3928) All these factors may likely lead to another rate case in each of the next four years. (Vilbert TR 3966-3968) Witness Vilbert asserted that if the intervenors’ approach was adopted, customers would receive a lower rate temporarily, but a higher long term rate and more variability in rates. (TR 3943)
PEF witness Vilbert viewed the intervenors’ proposals as a reversal of depreciation already recovered. (TR 3917) Witness Vilbert asserted that the intervenor proposals would create winners and losers among the Company’s customers. (TR 3932) While customers would receive lower revenue requirements over the four-year amortization period, witness Vilbert claimed that this would be at the expense of past and future customers. (TR 3932) The witness stated that such action would not resolve any alleged intergenerational inequity among customers, but would rather create intergenerational inequity among customers. (TR 3917)
PEF witness Garrett testified that customers have paid what was established in the cost of service for depreciation, and that has been reflected in the Company’s book reserve position that served to reduce the recovery of investments on a prospective basis. Because of this, asserted witness Garrett, customers have not paid more than they should have. (TR 3905-3906)
PEF witness Robinson testified that the reserve variance was due to changes in life and salvage estimates, in particular, the longer lives now estimated for PEF’s production plants. (TR 3733-3734) These longer lives reflect the longer life spans now expected for the Crystal River Units 4 and 5, Crystal River Units 1 and 2, Anclote, and several combustion turbine peaking units. (TR 3736, 3539-3540; EXH 216) PEF witness Vilbert asserted that a change in depreciation life and salvage estimates did not mean that customers overpaid in the past. (Vilbert TR 3918) It simply meant that estimates of the future changed. PEF witnesses Garrett, Vilbert, and Robinson stated that the reserve imbalance was not the result of a mistake by the Commission in setting depreciation rates in the past, and not the result of some error by the Company. Rather, the reserve imbalance was due to changed circumstances. The PEF witnesses contended that the argument that customers have allegedly overpaid in the past, presupposes the “retroactive” application of what is known today to the past. (Garrett TR 3735-3736; Vilbert TR 3918; Robinson TR 3535-3936, 3541-3542)
PEF witnesses Vilbert and Garrett contended that anything other than the remaining life rate methodology would violate GAAP, specifically Financial Accounting Standard (FAS) 154. FAS 154 states “[a] change in estimate shall not be accounted for by restating or retrospectively adjusting amounts reported in financial statements of prior periods or reporting pro-forma amounts for prior periods.” Thus, contended the witnesses, correcting reserve imbalances would violate fundamental accounting principles that the disposition of imbalances should be handled as a change in estimate that is reflected prospectively, as the remaining life methodology provided. (EXH 35, BSP 1306; Vilbert TR 3922-3923; Garrett TR 3752-3753)
PEF witness Garrett testified that amortization of the reserve variance was inconsistent with FERC depreciation policy and practice. (TR 3748-3749) Witness Garrett asserted that the FERC’s policy was clear that reserve variances or imbalances were addressed prospectively with an adjustment to the depreciation rate. (EXH 228) The witness stated that the FERC policy had been in effect since the 1970s. (TR 3748)
PEF witness Garrett testified that amortization of the reserve variance is also inconsistent with prior Commission policy and practice. Both PEF witnesses Robinson and Garrett contended that the average remaining life is the Commission’s rule rather than the exception when addressing reserve imbalances. (Robinson TR 3554-3556; Garrett TR 3742-3752) The witnesses averred that many of the orders cited as support to the intervenors’ position, relate to reserve deficiencies, imbalances due to changes in depreciation methodology, negative reserve balances, reserve transfers that have no relevance to the current proceeding, and accounting adjustments to facilitate a level playing field to recognize possible deregulation. (Robinson TR 3555-3556; Garrett TR 3743-3752) The witnesses contended that none of the cited orders related to an amortization of a reserve surplus such as proposed in this proceeding.
In its brief, PEF pointed out that the Commission expressed its concern in the past with adjusting depreciation expense in response to economic conditions. In Order No. PSC-98-1723-FOF-EI, issued December 18, 1998, in Docket No. 971570-EI, In re: 1997 Depreciation Study by Florida Power Corporation, the Commission explained that setting depreciation rates in this context “makes the next step easier and can lead to the design of depreciation rates that will no longer reflect the matching principle but rather the level of the companies’ earnings.” (PEF BR 34-35)
ANALYSIS
As noted previously, all witnesses agreed that the remaining life depreciation methodology recovers the net remaining investment over the average remaining life of the associated assets. (Robinson TR 3544-3455; Garrett TR 3739; Pous 2160-2161, 2042; Pollock TR 3196) Staff observes that the parties agreed that:
· Depreciation rates should be based on the best information available today. (Robinson TR 3536, 3548; Pous TR 2035-2036; Pollock TR 3195-3196)
· A reserve surplus of at least $646 million exists based on the theoretical reserve calculation. (EXH 84, Section 2, pp. 2-74 – 2-79; Pous TR 2020; Pollock TR 3197)
· The reserve surplus serves to reduce PEF’s future depreciation expenses. (Robinson TR 3544; Pous TR 2046; Pollock TR 3204)
Staff believes the crux of this issue is whether the reserve imbalance should be corrected over the remaining life or a shorter period of time. (Pous TR 2042; Lawton TR 2236-2237; Garrett TR 3773) To this end, PEF witnesses Robinson and Garrett contended that the remaining life depreciation approach to resolve reserve imbalances is the norm and there is no reason to deviate. (TR 3723) OPC witness Pous and FIPUG witness Pollock asserted that the magnitude of the reserve variance warrants a corrective approach other than the normal remaining life depreciation approach. (Pous TR 2147; Pollock TR 3204) Staff notes that PEF witness Vilbert agreed that it would be best if there were no reserve imbalance. (TR 3998)
Staff observes that the National Association of Regulatory Utility Commissioners Public Utility Depreciation Practices manual (NARUC depreciation manual) sets forth two accepted methods for calculating a theoretical depreciation reserve: the prospective method and the retrospective method. (EXH 311) The prospective method is required in the Commission’s depreciation study rule, Rule 25-6.0436(6)(d), F.A.C. PEF witness Robinson and OPC witness Pous acknowledged the NARUC manual as setting forth standard depreciation practices. (EXH 312; Pous TR 2176-2177)
The NARUC depreciation manual states that if a reserve imbalance is material, common methods for correcting the imbalance are either through an amortization over an abbreviated period of time or remaining life depreciation rates. (TR 2176-2177; EXH 311) Staff notes that the NARUC depreciation manual does not quantify what constitutes a “material” imbalance. In its brief, PEF argued that amortization of reserve deficiencies caused by plant retiring earlier than the average service life is what NARUC meant when it referenced amortization as a common method to address reserve imbalances, because amortization in this instance more closely follows the matching principle. (PEF BR 42) Staff disagrees with PEF’s assertion. The NARUC depreciation manual is clear that amortization is an acceptable method for correcting material reserve imbalances. Staff believes that if there were exceptions to the use of amortization, as PEF implied, the NARUC depreciation manual would have so stated. Moreover, staff agrees with FRF that it makes little sense that the NARUC depreciation manual would support a policy that violated GAAP or represented retroactive ratemaking as alleged by PEF. While PEF apparently agreed with the recovery of investments retiring earlier than their average service life, it did not address the negative reserves that currently exist with the retirement of Bartow, Avon Park, meters, or power operated equipment.
FIPUG argued in its brief that PEF’s claim that amortization of a reserve imbalance is retroactive ratemaking is without merit. FIPUG asserted that retroactive ratemaking involves going back in the past and changing an approved rate. FIPUG cited in its brief to City of Miami v. FPSC, 208 So.2d 249, 259-260 (Fla. 1968), for the proposition that retroactive ratemaking involves the application of new rates to past consumption. (FIPUG BR 14)
FIPUG asserted that in the instant case, the issue is the setting of PEF’s prospective depreciation rates. FIPUG contended that revised depreciation rates will be applied going forward and an amortization of a reserve imbalance going forward is not retroactive ratemaking. (FIPUG BR 14) Staff agrees. Depreciation rates are designed and applied prospectively and so is the correction of any reserve transfers or correction of a reserve imbalance via an amortization. The calculation of the theoretical reserve is prospective, as defined in Rule 25-6.0436, F.A.C.
Intergenerational Inequity
The intervenors claimed that the existence of PEF’s reserve imbalance indicates that past and current customers have paid more than their fair share of depreciation expenses and that future customers will therefore pay less than their fair share. (Pous TR 2045, 2146, 2149; Pollock TR 3199; FRF BR 25) In contrast, PEF contended that the existing imbalance would inure to the benefit of current and future customers because the depreciation rates will be lower than they otherwise would be. (Garrett TR 3740)
Staff believes that the very presence of a reserve imbalance indicates the existence of an intergenerational inequity. Based on what is known today, the estimates of yesterday are now viewed as being too short. PEF has lengthened the life span estimates for its production plants. Net salvage estimates have changed. Does that mean that past life and salvage estimates were wrong? Staff believes it does not. Disregarding that settlements were reached in 2002[26] and 2005[27] that addressed depreciation and many other matters, the last time the Commission actually conducted a thorough review and analysis of PEF’s depreciation parameters was in 1997. Conditions, Company plans, and regulatory requirements change. PEF witness Pous acknowledged that depreciation parameters change over time simply because depreciation is a projection of anticipated events in the future. (TR 2036, 2099) FRF recognized in its brief that in a depreciation study review, a goal has been to align the actual and theoretical reserve positions for all accounts. (FRF BR 28)
Staff agrees with PEF witness Robinson and OPC witness Pous that it is unlikely there would ever be a time when there is no reserve imbalance, simply because as time passes, more information is known and hopefully better estimates of life and salvage can be determined. (Pous TR 2018; Robinson TR 3548, 3552) That said, staff believes that is no reason for not taking some action to correct reserve imbalances, where possible, either through reserve transfers or an amortization. Staff also believes it is the magnitude of the reserve imbalance that should dictate what action is taken.
Staff agrees with PEF that current and future customers will receive the benefit of the existing reserve surplus through lower depreciation rates. If the reserve surplus is reduced, the depreciation reserve will increase, thereby, all things remaining equal, causing depreciation rates and future revenue requirements to naturally increase. At the present time, staff believes it can be argued that the current reserve surplus results in prospective depreciation rates that are artificially low. This is the beauty or the beast of the remaining life rate methodology. A surplus means that more than enough under present expectations has been recovered and so there is a smaller amount left to be recovered over the average remaining life. Conversely, the presence of a reserve deficit means that not enough has been recovered to date, so the depreciation rate must increase to make up the difference in the future. (TR 2146)
Previous Commission Orders Regarding Reserve Imbalances
Staff observes that the intervenors contended that past Commission orders support a position that reserve imbalances have historically been recovered over a period of time that is shorter than the average remaining life. (EXH 286) PEF, on the other hand, contended that the orders referenced by the intervenors refer to reserve deficiencies, not to reserve surpluses as exist in this case, and so these orders are not pertinent. (Robinson TR 3554-3556; Garrett TR 3744-3752) Staff believes this is a distinction without a difference.
The existence of a negative reserve caused by plant retiring earlier than the related average service life creates a positive component in rate base on which the Company is allowed to earn a return until it is corrected. Staff believes that negative reserves reflect an overstatement of rate base. Staff presumes that PEF undoubtedly concurs or it would not have made the statement that amortization in these circumstances is warranted. (Robinson TR 3555)
Staff agrees with OPC witness Pous that whether the imbalance is a deficiency or a surplus, the rate base is misstated and should be corrected. (TR 2047) By design, the remaining life rate self-adjusts and corrects any reserve imbalance over the remaining life of the associated plant. Historically, the Commission has addressed reserve imbalances through the use of reserve transfers or allocations. (Pous TR 2176; Lawton TR 2228) For electric companies, in light of possible cross-subsidies between functions, the Commission has limited transfers between accounts within the same function. In other words, transfers are only made between accounts within the production function, transfers between accounts within the transmission function, and so on. (TR 2228)
PEF recognized the Commission’s practice of using reserve transfers between accounts to correct reserve imbalances. (PEF BR 43) PEF witness Vilbert also acknowledged that this practice was not a restatement of depreciation reserve, but rather a reallocation among accounts. (TR 3963) However, PEF asserted that reserve transfers were not needed or were inappropriate to use in its depreciation study. (EXH 36, BSP 1038) PEF witness Garrett contended that such reserve correction would effectively represent reserve transfers that may not be GAAP compliant, although this is contradicted by PEF witness Vilbert. (Garrett TR 3802; Vilbert TR 3963) Staff also notes that, according to PEF’s outside auditors’ guidance, transfers of depreciation expense from transmission or distribution accounts to generating accounts are generally acceptable under FAS 71 as long as the transfers do not result in negative depreciation for any account. (EXH 36, BSP 1306) Thus, staff believes that the practice of reserve transfers between accounts does not violate GAAP.
In its brief, PEF recognized that the Commission has previously approved accelerated depreciation when faced with potential changes in the regulatory environment as a result of possible deregulation. In this instance, the Commission stated that the accounting adjustments “will facilitate the establishment off a level ‘accounting’ playing field between [the utility] and possible non-regulated competitors.”[28] (TR 3750; PEF BR 43-44) Staff notes that the expected competition did not come to fruition. Staff believes that this does not mean that an error was made. Just as the Commission reacted to events it thought were likely to take place, staff believes it can react to existing circumstances by amortizing PEF’s reserve imbalance over a shorter period of time than the remaining life. Staff believes that there is nothing in this prior Order or any other Order that prohibits the Commission from addressing the reserve imbalance identified in this proceeding in a manner different from the remaining life rate design approach.
In Order No. PSC-02-0655-AS-EI, issued May 14, 2002, in Docket Nos. 000824-EI, In re: Review of Florida Power Corporation’s earnings, including effects of proposed acquisition of Florida Power Corporation by Carolina Power & Light and 020001-EI, In re: Fuel and purchased power cost recovery clause with generating performance incentive factor (PEF 2002 Rate Case Settlement Order), the Company agreed to a credit to depreciation expense, which staff believes is tantamount to an annual amortization. PEF opposed the intervenors’ current proposals, which are similar approaches. Staff recognizes, as pointed out by PEF in its brief, that settlements involve give and takes. Staff also agrees with PEF that a settlement is not binding precedent on the Commission. That said, staff is puzzled why PEF would have agreed to a credit to depreciation expense if it indeed believed that doing so was in violation of GAAP and FERC guidelines.
FIPUG argued in its brief that the current proposed amortization of the reserve imbalance is conceptually the same as prior Commission actions for Florida Power & Light Company (FPL). By Order No. PSC-96-0461-FOF-EI,[29] FPL was authorized to record additional depreciation expense of $126 million in 1995, an additional $30 million beginning in 1996, and additional expenses in 1996 and 1997 based on differences between actual and forecasted revenues to correct a $175.3 million reserve deficiency existing in FPL’s nuclear production facilities, with any residual expense to be applied to the other production facilities. In its 1997 depreciation study,[30] Florida Power Corporation (FPC) was ordered to amortize the gain realized from the sale of a combustion turbine, to be used to offset a reserve deficiency at the Suwannee Peaking Plant. In the FPL 2005 Rate Case Settlement Order, FPL was authorized to amortize up to $125 million annually as a credit to depreciation expense and a debit to the bottom line depreciation reserve over the term of the Settlement. FIPUG asserted that the material reserve surplus in the instant case warrants similar adjustments to restore generational equity and to help mitigate the impact of the proposed base rate increases. (Pollock TR 3204-3205; FIPUG BR 15-16) Staff believes that FIPUG’s arguments do not recognize that in the cited FPL cases, the recording of additional depreciation expense to correct perceived reserve deficiencies was made in the context of ensuring the Company would earn within its authorized rate of return. For the FPC case cited, staff notes that rather than amortizing the proceeds from the sale of the CT unit over five years, the Commission held that the proceeds should have been recognized as gross salvage and recorded as a credit to the depreciation reserve. Because the sale proceeds exceeded the net unrecovered costs associated with the retired CT, the surplus was transferred to help offset a reserve deficiency for the Suwannee Peaking Plant.
FRF argued in its brief that the Commission’s declared policy with respect to reserve imbalances is to correct them as soon as possible without adversely impacting a company’s ability to earn a fair and reasonable return.[31] (FRF BR 25) FRF noted that the Commission also targeted overearnings in the past to book additional depreciation expense, thereby lowering reported earnings and bringing them in line with the allowed rate of return. (FRF BR 25) In the instant proceeding, the Commission is setting a new rate of return for PEF. Staff believes that in deciding whether to amortize the reserve imbalance as the intervenors proposed, the Commission should also consider any negative impacts such an amortization will have on PEF’s financial integrity and the ratepayers.
GAAP
PEF witnesses Garrett and Vilbert asserted that amortization of a reserve imbalance violates GAAP, specifically FAS 154. (Garrett TR 3752-3753; Vilbert TR 3944-3945) The witnesses contended that retroactive depreciation adjustments and reversal of prior period depreciation expenses are not GAAP-compliant. While this may be, staff does not believe the intervenors’ proposals constitute retroactive adjustments or the reversal of depreciation expenses. The intervenors have not claimed that PEF’s prior depreciation rates were incorrect. The existing reserve imbalance is due to changes in prospective life and salvage estimates. Depreciation rates are prospective in nature and so is any correction to the reserve imbalance.
PEF witness Garrett testified that FAS 154 does not necessarily limit how regulated companies establish their cost of service, and this Commission has considerable latitude in its ratemaking endeavors. (TR 3807) Staff believes that while FAS 154 governs financial accounting, it does not govern regulatory accounting. (EXH 43, BSP 1920-1924) In response to discovery, PEF stated that as long as an action did not result in negative depreciation for any account, the action would be generally acceptable under FAS 71. (EXH 36, BSP 1306) PEF witness Garrett testified to the same point. (TR 3807)
When asked at the hearing whether remaining life rates restated depreciation expense, PEF witness Garrett responded in the negative. (TR 3814) Staff disagrees. If the remaining life rate is lower prospectively than the currently approved depreciation rate, the reserve is being restated over the newly-established remaining life. The very nature of remaining life depreciation rates is that they self-adjust to recover net unrecovered investments over the applicable remaining life. (Garrett TR 3882-3883) Under PEF’s logic then, remaining life depreciation rates would be considered retroactive, since the methodology, by design, restates the reserve.
Financial Integrity
OPC asserted in its brief that amortization of the reserve imbalance would serve to reduce expense and increase earnings. Accordingly, OPC argued that PEF’s reported achieved return on equity would increase from the current level of about nine percent to over 12 percent, all other things remaining equal. (OPC BR 19) OPC acknowledged that rate base would naturally increase at the end of the amortization period. However, OPC witness Lawton acknowledged that the annual net impact of OPC’s proposed amortization on PEF’s pre-tax cash flow is a reduction of approximately $149.3 million per year for four years. (EXH 175)
PEF witness Vilbert testified that the rate base increase under OPC’s proposal was essentially no different than if depreciation rates in the past had been established using today’s estimates. (TR 3966) However, the intervenors did not address the impact of their proposals on prospective depreciation rates. (Pous TR 2167; Pollock TR 3227-3228) Staff believes this is an important consideration. If an amortization is considered, then depreciation rates should be recalculated using the corrected reserve position. Because the depreciation reserve will be lowered, depreciation rates will increase.[32]
Regarding the intervenors’ amortization proposals, PEF asserted that depreciation expense will be reduced during each year of the amortization period and rate base will accordingly increase, thereby increasing the return to which the Company is entitled. (TR 3924) The resulting reduction in cash flow will require PEF to raise additional capital to meet its construction budget. This will likely lead to higher transaction costs associated with acquiring new capital for capital investments. (TR 3943) However, staff notes that since PEF’s forecast of capital expenditures is an excess of its cash flows, it already plans to go to the market to raise more debt and equity. (TR 3945)
PEF also cautioned that the intervenors’ proposed amortization would increase its cost of capital due to increased investor uncertainty. Moreover, such an amortization would likely weaken PEF’s credit metrics and result in an increase in its cost of debt and cost of equity on a going forward basis. A higher cost of capital applied to a larger rate base yields higher customer rates. (TR 3943, 3967) As illustrated by PEF witness Vilbert, the intervenors’ proposals would decrease revenue requirements in the short term, but would increase revenue requirements about $200 million between year 4 and year 5. (TR 3927) Staff notes that witness Vilbert did not provide a sensitivity analysis that quantified the minimum level of reduced depreciation cash flow that would not have an adverse affect on the Company’s financial integrity.
The financial metrics affected by the intervenors’ proposal are the cash from operations to interest ratio (CFO/Interest) and the cash from operations to debt ratio (CFO/Debt). (Sullivan TR 4140-4145; EXH 238) The ratings criteria published by Moody’s Investor Service (Moody’s) and Standard and Poor’s Rating Service (S&P) for PEF’s current credit rating of A3 and BBB+, respectively, include the following cash flow metric standards.
|
|
Moody’s A rating |
S&P BBB rating |
|
CFO/Interest |
4.5x – 6.0x |
3.0x - 4.5x |
|
CFO/Debt |
22% - 30% |
25% - 45% |
(EXH 95; EXH 234, p. 13)
The intervenors’ proposed adjustment for the theoretical reserve surplus will lower PEF’s cash flow metrics. (Lawton TR 2232; EXH 177) Witness Lawton demonstrated that PEF’s CFO/Interest will decrease from 4.9x to 4.0x and its CFO/Debt will decrease from 35 percent to 29 percent based on PEF receiving the full amount of its requested rate increase except for the amortization. (EXH 177) However, the proposed adjustment does not take into account any other adjustments that will impact cash flow. (Lawton TR 2233) By itself, the intervenors’ proposed adjustment would not lower PEF’s financial metrics below the standards required for its current credit rating. (Lawton TR 2232) Then again, the proposed adjustment in combination with other adjustments that reduce cash flow could result in PEF’s credit metrics falling below those required for an investment grade rating. (Vilbert TR 3931) For example, OPC’s proposed $35 million revenue reduction will result in a CFO/Interest of 3.8x and a CFO/Debt of 18 percent. (Sullivan TR 4143-4144; EXH 238) The resulting financial metrics would not meet the standards for Moody’s financial metrics for PEF’s current credit rating of A3. (Sullivan TR 4143-4144; EXH 237, p. 4) While there is no one key financial metric that determines a particular bond rating level, these financial ratios are helpful in evaluating a company’s financial integrity and liquidity for assessing its credit quality. (Lawton TR 2232)
Recommendation
In the review of any depreciation study, staff believes the reserve position of the company should be reviewed. Indeed, the depreciation study rule, Rule 25-6.0436, F.A.C., requires a calculation of the prospective theoretical reserve for each account. As noted in previous issues, this is the first thorough review of PEF’s recovery position since 1997. Reserve imbalances are to be expected in over 10 years’ time. As shown in Issue 14, staff’s calculation indicates a total reserve imbalance of $727.1 million. Staff used the prospective theoretical reserve formula as set forth in the depreciation study rule, and the life and salvage parameters recommended in Issues 12 and 13, to arrive at this amount.
As discussed in Issue 8, PEF reports net unrecovered investments associated with the retirement of the Bartow Plant and Avon Park steam plants, the Crystal River Units 4 and 5 upgrade, and the Crystal River Unit 3 steam generator. There are also negative reserves associated with the retirement of meters and power operated equipment that retired earlier than the associated expected life. Staff recommends that the initial appropriate corrective action is to allocate some of the reserve surplus existing in the production and distribution plant functions to correct these net unrecovered costs.
Staff reviewed the reserve position of PEF’s accounts. Based on staff’s calculations, the reserve surplus existing for Anclote, Crystal River Units 1 and 2, and Crystal River Units 4 and 5 can be transferred to correct the reserve deficiencies existing at Suwannee, to correct the negative reserves at the retired Bartow and Avon Park sites, and to offset the unrecovered net investments at Crystal River Units 4 and 5 associated with the retirements planned in connection with the upgrade. For Crystal River Unit 3, staff recommends an allocation of reserve from Account 325, Miscellaneous Power Plant Equipment, to offset the calculated reserve deficiency in Account 312, Reactor Plant Equipment, and to recover the net investments associated with the steam generator retirement. Additionally, staff recommends that reserve allocations be made among the accounts of the other production sites at Avon Park, Bartow, Debary, Debary P7-1, Higgins, Hines Energy Complex (Units 1-4), Intercession City (#11, P1-P6, and P12-P14), Turner, Rio Pinar, and Suwannee to bring their respective book reserve positions more in line with the theoretically correct levels.
Staff recommends that the reserve surpluses existing in the Distribution Plant function, specifically in Account 362, Station Equipment; Account 365, Overhead Conductors and Devices; and Account 366, Underground Conduit, be transferred to correct the calculated reserve deficiencies in Account 367, Underground Conductors and Devices, and the negative reserves in Account 370, Meters, and Account 396, Power Operated Equipment. These transfers will bring the reserve for both underground conductors and devices and meters to their theoretically correct levels and correct the negative reserve in power operated equipment.
Once the above corrected reserve allocations are made, the question remains what additional action should be taken with respect to the remaining calculated reserve surplus of $720 million. Normally, staff would recommend amortization of a reserve imbalance as fast as economically practicable, whether the imbalance is a deficiency or a surplus. In this case, the reduction to cash flow and indicated adverse impact to PEF’s financial integrity give staff pause. The intervenors’ proposed amortization, taken in isolation, might not adversely impact PEF’s current credit rating. However, in combination with other adjustments that reduce cash flow, an amortization could result in PEF’s credit metrics falling below those required for an investment grade rating. Additionally, the reduced revenue requirements resulting from an amortization would be short-lived. PEF witness Vilbert demonstrated that at the end of the amortization, revenue requirements would increase about $200 million, resulting in higher customer rates, all things remaining equal. Finally, it was not disputed that over 70 percent of the reserve surplus is the direct result of PEF’s projected longer life spans of its production plants. For all the above reasons, staff recommends that the remaining $720 million reserve surplus should be recovered through the remaining life rate design. If the Commission decides an amortization is appropriate, the depreciation rates recommended in Issue 12 will need to be recalculated to recognize a lower reserve position.
CONCLUSION
Staff recommends the reserve allocations shown in Table 15-1. This action will bring each affected account’s reserve more in line with its theoretically correct level. In light of concerns with reduced cash flow and the impact that a short amortization period could have on the financial integrity of PEF, including a higher cost of capital and cost of debt, resulting in higher customer rates in the long term, staff recommends that the residual reserve surplus be recovered through the remaining life rate design.
What should be the implementation date for revised depreciation rates, capital recovery schedules, and amortization schedules? (Category 1 Stipulation)
Approved Stipulation:
The implementation date should be January 1, 2010. (AFFIRM did not affirmatively stipulate this issue, and took no position.)
FOSSIL DISMANTLEMENT COST STUDY
Should the current-approved annual dismantlement provision be revised?
Recommendation:
Yes. Staff recommends that PEF’s currently approved annual dismantlement provision should be revised. (Higgins)
Position of the Parties
PEF:
Yes, the annual dismantlement provision should be revised in accordance with PEF’s 2008 Fossil Dismantlement Study.
OPC:
The Commission should direct PEF to propose a more realistic approach and cost level to terminal net salvage in its next depreciation study.
AFFIRM:
No position.
AG:
Support OPC’s position.
FIPUG:
Yes. Agree with OPC.
FRF:
No.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
PEF believes its 2008 dismantlement cost study (EXH 126), sponsored by witness Toomey, indicates there is a need to update its annual dismantlement accrual. (PEF BR 8) PEF’s cost study methodology is consistent with Commission Order No. 24741, issued July 1, 1991, in Docket No. 890186-EI, In Re: Investigation of the Ratemaking and Accounting Treatment for the Dismantlement of Fossil-Fueled Generating Stations (Order No. 24741), and Rule 25-6.04346, F.A.C.
Staff notes that OPC witness Pous refers to fossil dismantlement as terminal net salvage. While witness Pous believes that the Commission should direct PEF to propose a different approach to fossil plant dismantlement, witness Pous does not directly address the issue of whether PEF’s annual dismantlement accrual should be changed. Further discussion of OPC witness Pous’s recommendations is contained in Issue 20.
Staff notes that AFFIRM and NAVY took no position on this issue. Parties supporting OPC’s position include AG, FIPUG and PCS. FRF took the position that PEF’s annual dismantlement provision should not be revised. PEF and OPC are the only parties to file testimony on this issue.
ANALYSIS
Fossil dismantlement for PEF was last addressed in Order No. PSC-05-0945-S-EI, issued September 28, 2005, in Docket No. 050078-EI, In Re: Petition for rate increase by Progress Energy Florida. The parties to that proceeding reached a stipulation of all issues. The Commission later approved the stipulation and settlement agreement. As part of the approved stipulation, PEF continued zero annual accruals to its reserve for fossil dismantlement. The Stipulation is effective through the last billing cycle in December 2009. In accordance with the above referenced order, PEF filed its fossil dismantlement study on July 31, 2009. Staff has completed its review and presents its recommendation herein.
PEF’s 2008 fossil dismantlement study (EXH 126) filed in this proceeding indicates a need to adjust PEF’s current annual fossil dismantlement accrual, which is currently set at zero. This 2008 dismantlement study represents an update of PEF’s base dismantlement costs, contingency, and inflation forecasts. PEF contends an annual accrual of $3,845,221 is required to meet its fossil dismantlement needs. Staff’s analysis and critique of PEF’s 2008 fossil dismantlement study, and our recommended annual accrual, are contained in Issue 19. Nevertheless, staff believes PEF has made a prima facie case for some increase from zero to its annual fossil dismantlement accrual. Staff recommends a January 1, 2010 implementation date for any revised annual fossil dismantlement accrual to take effect.
A comparison of cost estimates for fossil dismantlement from the prior 2004 study (projected 2006 test year) and the 2008 study (projected 2010 test year) is shown below.
|
Table 17-1 |
|||
|
FOSSIL FUEL DISMANTLEMENT COST ESTIMATES |
|||
|
|
DISMANTLEMENT 2004 COST STUDY (2006 DOLLARS)[33] |
DISMANTLEMENT 2008 COST STUDY (2010 DOLLARS) |
VARIANCE BETWEEN STUDIES |
|
|
($) |
($) |
($) |
|
Anclote |
15,032,810 |
10,135,582 |
(4,897,228) |
|
Avon Park Gas Turbine |
626,166 |
171,048 |
(455,118) |
|
Bartow - Steam |
25,501,460 |
28,097,998 |
2,596,538 |
|
Bartow - CT |
9,063,700 |
10,707,360 |
1,643,660 |
|
Bartow-Anclote Pipeline |
976,106 |
346,322 |
(629,784) |
|
Bartow - CC |
0 |
449,770 |
449,770 |
|
Bayboro |
1,791,891 |
978,450 |
(813,441) |
|
Crystal River South Units 1 & 2 |
37,966,224 |
32,097,229 |
(5,868,995) |
|
Crystal River North Units 4 & 5 |
28,133,314 |
26,630,663 |
(1,502,651) |
|
Crystal River Common |
8,589,643 |
12,514,898 |
3,925,255 |
|
Crystal River Helper |
3,316,175 |
4,153,459 |
837,284 |
|
Crystal River Mariculture |
1,153,299 |
1,571,058 |
417,759 |
|
Debary Gas Turbine units 1 - 6 |
2,854,274 |
595,998 |
(2,258,276) |
|
Debary Gas Turbine units 7 - 10 |
5,007,768 |
7,248,325 |
2,240,557 |
|
Higgins - Steam |
5,948,848 |
0 |
(5,948,848) |
|
Higgins - Peaker |
553,259 |
343,512 |
(209,747) |
|
Hines PB1 |
1,681,716 |
560,201 |
(1,121,515) |
|
Hines PB2 |
6,203,936 |
560,201 |
(5,643,735) |
|
Hines PB3 |
0 |
560,201 |
560,201 |
|
Hines PB4 |
0 |
661,543 |
661,543 |
|
Intercession City Units 1 - 6 |
1,625,509 |
457,098 |
(1,168,411) |
|
Intercession City Units 7 -10 |
3,133,121 |
1,720,105 |
(1,413,016) |
|
Intercession City Units 11 |
576,567 |
198,446 |
(378,121) |
|
Intercession City Units 12 -14 |
2,408,368 |
4,760,719 |
2,352,351 |
|
Port St. Joe |
265,285 |
0 |
(265,285) |
|
Rio Pinar |
664,211 |
322,364 |
(341,847) |
|
Suwannee - Steam units 1 - 3 |
13,282,882 |
14,060,964 |
778,082 |
|
Suwannee - CT 1 - 3 |
480,297 |
279,534 |
(200,763) |
|
Tiger Bay Combined Cycle |
1,850,390 |
389,942 |
(1,460,448) |
|
Turner Gas Turbine Units 1 - 2 |
8,210,467 |
0 |
(8,210,467) |
|
Turner Gas Turbine Units 3 - 4 |
282,905 |
24,044 |
(258,861) |
|
Turner - Steam |
728,937 |
432,155 |
(296,782) |
|
University of Florida Gas Turbine |
1,324,447 |
301,464 |
(1,022,983) |
|
Totals |
189,233,975 |
161,330,653 |
(27,903,322) |
(EXH 44)
CONCLUSION
Staff recommends that PEF’s currently approved annual dismantlement provision should be revised.
What, if any, corrective reserve measures should be approved for fossil dismantlement?
Recommendation:
Staff recommends the Commission approve the reserve allocations presented in Table 18-1 of this recommendation. (Higgins)
Position of the Parties
PEF:
This dismantlement reserve balances should be adjusted as reflected on page 47 of Exhibit PT-10 (Hearing Exhibit 126).
OPC:
No position.
AFFIRM:
No position.
AG:
No position.
FIPUG:
No position.
FRF:
No position.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
PEF is requesting that the Commission approve certain adjustments to its fossil dismantlement reserves. PEF proposes transfers be made from plants with reserve surpluses, to plants with reserve deficiencies, starting with the plants that have the shortest remaining lives. These adjustments are contained in witness Toomey’s Exhibit PT-10, p. 47. (EXH 126) Staff notes that no other party to this proceeding filed testimony or took a position on this issue.
ANALYSIS
PEF’s 2008 fossil dismantlement study contains proposed adjustments to correct reserve imbalances as a result of updating its fossil dismantlement cost estimates. It has proposed that reserve surpluses for Avon Park Gas Turbine, Higgins, Inglis Steam, Port St. Joe Gas Turbine, and Turner Steam plants, be transferred to Bartow Steam, Suwannee Steam Units, Bartow-Anclote Pipeline, and Crystal River Units 1 & 2 plants. (EXH 126) This Commission has consistently approved reserve transfers in fossil dismantlement studies. PEF’s last reserve transfer was approved by Order No. PSC-01-2386-PAA-EI, issued December 10, 2001, in Docket No. 010031-EI, In Re: 2000 Fossil Dismantlement Cost Study by Florida Power Corporation. Staff has reviewed PEF’s proposed reserve transfers and, consistent with Commission precedent, believes they are reasonable.
|
PROGRESS ENERGY FLORIDA THEORETICAL RESERVE REALLOCATIONS AS OF JANUARY 1, 2010 |
|||||
|
Table 18-1 |
|
||||
|
Plant |
Accumulated Reserve as of December 31, 2009 |
Theoretical Future Dollars to Dismantle |
Reserve Transfers |
Restated Reserve as of January 1, 2010 |
|
|
|
($) |
($) |
($) |
($) |
|
|
Avon Park Gas Turbine |
$5,410,811 |
- |
($5,410,811) |
$0 |
|
|
Higgins |
$10,158,455 |
- |
($10,158,455) |
$0 |
|
|
Inglis Steam |
$88,472 |
- |
($88,472) |
$0 |
|
|
Port St. Joe Gas Turbine |
$599,283 |
- |
($599,283) |
$0 |
|
|
Turner Steam |
$6,693,907 |
- |
($6,693,907) |
$0 |
|
|
Bartow Steam |
$21,137,835 |
$30,260,118 |
$9,122,283 |
$30,260,118 |
|
|
Suwannee - Steam Units |
$10,512,957 |
$17,327,448 |
$6,814,491 |
$16,461,076 |
|
|
Bartow-Anclote Pipeline |
$3,397,041 |
$15,424,962 |
$599,283 |
$6,865,925 |
|
|
Crystal River Units 1 & 2 |
$25,916,397 |
$43,332,297 |
$6,414,872 |
$34,665,555 |
|
|
Total* |
$83,915,158 |
$106,344,825 |
$0 |
$83,915,158 |
|
|
* May not add to total due to rounding |
|
|
|
|
|
CONCLUSION
Staff recommends the Commission approve the reserve allocations presented in Table 18-1 of this recommendation. These reserve allocations are to correct plant-specific dismantlement reserve imbalances based on current dismantlement cost estimates.
What is the appropriate annual provision for dismantlement?
Recommendation:
The appropriate system annual provision for dismantlement is $3,845,221, and the retail annual accrual amount is $3,113,889. These accruals reflect current estimates of dismantlement costs on a site-specific basis using an August 2008 inflation forecast and a 20 percent contingency factor. (Springer, Higgins)
Position of the Parties
PEF:
PEF’s 2008 Fossil Plant Dismantlement Study shows PEF will need to accrue $3.8 million (system) annually beginning in 2010 in order to ensure that sufficient funds will be available to cover the costs of dismantlement of the Company’s fossil plant generating sites.
OPC:
If the Commission decides to address fossil dismantlement in this proceeding, the Company’s costs should be reduced by 60%.
AFFIRM:
No position.
AG:
Agree with OPC’s position.
FIPUG:
If the Commission decides to address fossil dismantlement in this proceeding, the Company’s costs should be reduced by 60%.
FRF:
Agree with OPC that if fossil dismantlement is addressed in this proceeding, PEF's costs should be reduced by 60%.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
Based on its updated fossil dismantlement study, the Company alleged that the total base cost to dismantle its fossil plants increased to $294 million. After applying salvage credits for scrap steel and copper, the Company estimated the net cost to dismantle its fossil plants to be approximately $161 million. PEF proposed a levelized annual accrual for 2010-2014 of $3,845,221 (system). (EXH 126)
OPC witness Pous did not recommend any specific adjustments to PEF’s fossil dismantlement study. (TR 2086) However, witness Pous asserted that if the Commission does decide to address fossil dismantlement in this proceeding, then the Commission should reduce PEF’s dismantlement costs by 60 percent. (TR 2086-2087)
OPC witness Pous discussed a number of factors that he believes result in excessive demolition cost estimates. First, witness Pous objected to the Company’s use of a 20 percent cost contingency factor. Second, witness Pous asserted that the Company dismantlement assumptions are based on “reverse construction,” and this demolition approach is a “high side” estimate. Witness Pous further asserted that if a reverse construction demolition approach is employed, a negative contingency factor may be warranted. (TR 2084)
Witness Pous argued that PEF has erroneously calculated its expected labor costs. (TR 2085) In its responses to OPC discovery, PEF claimed it utilized an average of the local union labor rate and the RS Means Heavy Construction Cost Data 22nd Annual Edition. (EXH 37) Witness Pous’s analysis shows that only the local union labor rate was utilized. (TR 2086)
In response to the labor rate issue addressed by OPC witness Pous, PEF witness Kopp asserts that while there was no error in the calculation of the labor rate, there was an error in its discovery responses to OPC. Witness Kopp confirms that the labor rates included in its 2008 fossil dismantlement study are the local union labor rates only. (TR 3691)
PEF witness Kopp believes PEF’s requested contingency factor is appropriate irrespective of how OPC witness Pous characterizes such an estimate. (TR 3689) Witness Kopp stated that applying a contingency factor to dismantlement cost estimates is a standard industry approach, accounting for issues such as weather delays, which would not be accounted for in a base cost estimate. Witness Kopp believes the Company’s approach is consistent with Rule 25-6.04346, Subsection (2)(a), F.A.C., which permits contingency costs to be included in fossil dismantlement cost estimates for “unforeseeable elements of cost within the defined project scope.” (TR 3689)
Staff notes that AFFIRM and Navy took no position on this issue. FIPUG and PCS support OPC’s position. FRF and AG assert that PEF’s fossil dismantlement assumptions are not reasonable, but sponsored no testimony on this issue or cited record evidence to support their position. PEF and OPC are the only parties to file testimony on this issue.
ANALYSIS
PEF's previous 2004 fossil dismantlement cost study was filed in 2005, but was not placed into effect due to the Stipulation in Order No. PSC-05-0945-S-EI.[34] As stated in the Stipulation approved in paragraph 11 of Order No. PSC-05-0945-S-EI, “PEF will continue to suspend accruals to its reserve for nuclear decommissioning and fossil dismantlement, and shall apply the depreciation rates consistent with those in PEF’s Depreciation Study, as modified by Exhibit 2, attached to the Stipulation.”
The major factors contributing to the 15 percent decrease in the cost estimate between the current study and the previous study are: (1) the completed dismantlement of two plants; (2) changes in inflation rates; and (3) the change in salvage values. (EXH 126, p. 3 of 54)
While the 2008 fossil dismantlement study was conducted by Burns and McDonnell, PEF’s previous dismantlement studies were conducted by a different engineering firm. As such, there are differences between the current study and prior studies as to the approach employed and certain inputs used. Staff notes two changes between the studies, below.
First, dismantlement studies typically include a contingency factor. A contingency factor is designed to account for unknown expenses at the time the estimate is prepared, but expected to be expended on the project. (EXH 44, BSP 1947) While the 2008 fossil dismantlement study incorporated a 20 percent contingency factor, the 2004 fossil dismantlement study applied a 15 percent contingency factor. (EXH 44, BSP 1938-39)
Second, in the 2008 fossil dismantlement study, Burns and McDonnell applied to the outputs of its analysis an additional 5 percent “project indirects” factor. (EXH 126) According to PEF, this factor is designed to recover what are typically contracted demolition costs not included in other cost estimates. (EXH 44, BSP 1947) In contrast, while it appears that prior PEF dismantlement studies also reflected costs for project indirects, their treatment in these studies differed from the approach in the current study. Accordingly, due to methodological differences between the two studies, staff is unable to determine if the relative costs included for project indirects in the two studies are comparable.
The recommended dismantlement accruals shown in Table 19-1 are based on PEF’s current cost estimates, escalated to future costs through the time of actual dismantlement. The future costs, less dismantlement reserves recovered to date and subject to reallocation, have been discounted over the remaining life of each plant site/unit. The calculation of the annual accrual for each site is based on the methodology for dismantlement established by Rule 25-6.04364, F.A.C. (EXH 126, p. 4 of 54)
Moody’s Economy.com[35] publishes inflation factors that are updated on a monthly basis. (EXH 126, p. 3 of 54) PEF used Moody’s Economy.com to obtain the inflation forecast as well as factors for use in both studies. (EXH 126, p. 3 of 54) In the 2008 fossil dismantlement study, the inflation factors PEF used in its original filing were based on the August 2008 issue of Moody’s Economy.com. (EXH 126, p. 3 of 54, EXH 44) Staff requested that PEF update its study using the latest available Moody’s Economy.com inflation factors, which were from the July 2009 forecast. (EXH 44) It was not readily apparent to staff from PEF’s updated results that the sizeable increase in the annual accruals were solely attributed to the July 2009 inflation forecast. (EXH 44) In addition, the models that were provided contained a rigid design that prevented staff from performing the usual sensitivity analyses to test various inflation inputs and contingency factors. (EXH 44)
In documentation provided by the Company in response to staff’s discovery to update the original filing, the major increases in the updated PEF fossil dismantlement study were attributed to revised scrap metal prices, the revised inflation forecast, and the updated jurisdictional separation factors. (EXH 25, BSP 448)
The effects of the updated assumptions increased the fossil dismantlement retail annual accrual from $3.1M to $8.6M, an increase of approximately $5.5M (system annual accrual increased from $3.8M to $10.0M, an increase of $6.2M). (EXH 25, BSP 448) However, PEF does not seek to establish its annual accrual based on these revised results. (PEF BR 16)
CONCLUSION
Staff recommends that the appropriate system annual provision for dismantlement is $3,845,221, and the retail annual accrual amount is $3,113,889. These accruals reflect current estimates of dismantlement costs on a site-specific basis using an August 2008 inflation forecast and a 20 percent contingency factor. The staff recommended dismantlement accruals are shown in Table 19-1.
PROGRESS ENERGY FLORIDA
FOSSIL DISMANTLEMENT ACCRUAL
Table 19-1
|
PLANT |
CURRENT ACCRUAL[36]
|
COMPANY PROPOSED ACCRUAL
|
COMPANY PROPOSED CHANGE IN ACCRUAL |
STAFF RECOMMENDED ACCRUAL
|
STAFF RECOMMENDED CHANGE IN ACCRUAL |
|
|
$ |
$ |
$ |
$ |
$ |
|
Anclote |
- |
232,936 |
232,936 |
232,936 |
232,936 |
|
Avon Park Gas Turbine |
- |
3,485 |
3,485 |
3,485 |
3,485 |
|
Bartow - Steam |
- |
0 |
0 |
0 |
0 |
|
Bartow - CT |
- |
7,222 |
7,222 |
7,222 |
7,222 |
|
Bartow-Anclote Pipeline |
- |
574,928 |
574,928 |
574,928 |
574,928 |
|
Bartow - CC |
- |
(7,753) |
(7,753) |
(7,753) |
(7,753) |
|
Bayboro |
- |
21,329 |
21,329 |
21,329 |
21,329 |
|
Crystal River South Units 1 & 2 |
- |
691,265 |
691,265 |
691,265 |
691,265 |
|
Crystal River North Units 4 & 5 |
- |
627,398 |
627,398 |
627,398 |
627,398 |
|
Crystal River Common |
- |
411,978 |
411,978 |
411,978 |
411,978 |
|
Crystal River Helper |
- |
176,932 |
176,932 |
176,932 |
176,932 |
|
Crystal River Mariculture |
- |
62,717 |
62,717 |
62,717 |
62,717 |
|
Debary Gas Turbine units 1 - 6 |
- |
13,601 |
13,601 |
13,601 |
13,601 |
|
Debary Gas Turbine units 7 - 10 |
- |
396,844 |
396,844 |
396,844 |
396,844 |
|
Higgins |
- |
7,077 |
7,077 |
7,077 |
7,077 |
|
Hines PB1 |
- |
21,228 |
21,228 |
21,228 |
21,228 |
|
Hines PB2 |
- |
17,650 |
17,650 |
17,650 |
17,650 |
|
Hines PB3 |
- |
16,643 |
16,643 |
16,643 |
16,643 |
|
Hines PB4 |
- |
19,989 |
19,989 |
19,989 |
19,989 |
|
Intercession City Units 1 - 6 |
- |
10,363 |
10,363 |
10,363 |
10,363 |
|
Intercession City Units 7 -10 |
- |
59,188 |
59,188 |
59,188 |
59,188 |
|
Intercession City Units 11 |
- |
12,516 |
12,516 |
12,516 |
12,516 |
|
Intercession City Units 12 -14 |
- |
207,479 |
207,479 |
207,479 |
207,479 |
|
Port St. Joe |
- |
0 |
0 |
0 |
0 |
|
Rio Pinar |
- |
6,930 |
6,930 |
6,930 |
6,930 |
|
Suwannee - Steam units 1 - 3 |
- |
216,593 |
216,593 |
216,593 |
216,593 |
|
Suwannee - CT 1 - 3 |
- |
6,992 |
6,992 |
6,992 |
6,992 |
|
Tiger Bay Combined Cycle |
- |
10,912 |
10,912 |
10,912 |
10,912 |
|
Turner Gas Turbine Units 1 - 2 |
- |
711 |
711 |
711 |
711 |
|
Turner Gas Turbine Units 3 - 4 |
- |
9,040 |
9,040 |
9,040 |
9,040 |
|
Turner - Steam |
- |
0 |
0 |
0 |
0 |
|
University of Florida Gas Turbine |
- |
9,028 |
9,028 |
9,028 |
9,028 |
|
|
|
|
|
|
|
|
Total Dismantlement Accrual |
- |
3,845,221 |
3,845,221 |
3,845,221 |
3,845,221 |
Source(s): EXH 44; EXH 125, p. 6 of 54
Are PEF's assumptions in the fossil dismantlement study with regard to site restoration reasonable?
Recommendation:
Yes. Staff recommends that the assumptions made by PEF in its 2008 dismantlement study with regards to site restoration are reasonable. (Higgins, Dowds)
Position of the Parties
PEF:
Yes, PEF’s assumptions are consistent with industry standards and with Commission Rule 25-6.04364. Burns & McDonnell specifically reviewed each of PEF’s generating units and sites and reasonably estimated the costs to dismantle each unit.
OPC:
No.
AFFIRM:
No position.
AG:
No.
FIPUG:
No. FIPUG agrees with OPC.
FRF:
No.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
PEF states that the methodology employed for developing costs is essentially the same as that used in the company’s last dismantlement study. PEF states that it made no significant changes to the study’s dismantlement assumptions. Changes in the quantity of materials were only made for plants to which physical changes had occurred since PEF’s 2004 study. (EXH 126, Section 7, p. 1-1) PEF’s 2008 study indicates that site remediation includes returning the site to a condition compatible with the surrounding land. (EXH 126, Section 4.0, p. 4-1)
In his testimony, OPC witness Pous objects to two aspects of PEF’s fossil dismantlement approach. First, he contends that PEF’s dismantlement assumptions “assumed a 100 percent worst case scenario, that being full demolition and site restoration.” (TR 2079) Witness Pous asserts that PEF is not legally required to restore its plant sites to a “greenfield” condition. (TR 2080) Although the OPC witness does not define “greenfield condition” in his testimony, staff believes this term typically means that site restoration remediates the land/site suitable for any future use, without restriction, from economic development to recreation. PEF witness Kopp defines restoring to “greenfield” condition as removing all installations above and below ground. (TR 3682) However, PEF witness Kopp asserts that PEF’s dismantlement study assumes that all underground piping and foundations two feet below grade will remain in place. (TR 3682)
Second, witness Pous argues that assuming a “reverse construction” approach is unreasonable. Witness Pous describes “reverse construction” as assuming the Company will dismantle a generating facility piece by piece, including removing foundations and underground piping. (TR 2081) Witness Pous recommends the Commission order PEF to perform detailed analyses of different options and approaches to fossil dismantlement and submit this information with its next fossil dismantlement study. (TR 2087) With respect to “reverse construction,” PEF witness Kopp argues that a combination of demolition techniques would likely be utilized in order to dismantle a plant, as opposed to completely dismantling a plant “piece by piece.” (TR 3683)
Staff notes that while OPC witness Pous does not recommend any adjustments to PEF’s study, he offers that if the Commission wishes to modify PEF’s request, it should reduce overall dismantlement costs by 60 percent. (TR 2087)
Staff further notes that AFFIRM and NAVY took no position on this issue. FIPUG and PCS support OPC’s position. (OPC BR 28; FIPUG BR 20; PCS BR 5-6) FRF and AG assert that PEF’s fossil dismantlement assumptions are not reasonable, but sponsored no testimony on this issue or cited record evidence to support their position. PEF and OPC are the only parties to file testimony on this issue.
ANALYSIS
PEF retained the engineering firm Burns and McDonnell to prepare its 2008 fossil dismantlement study. PEF’s 2004 fossil dismantlement study was filed in Docket No. 050078-EI, and was conducted by Sargent & Lundy, LLC. Pursuant to the Stipulation approved by this Commission and in accordance with the terms of the stipulation approved in Order No. PSC-05-0945-S-EI, issued September 28, 2005, in Docket No. 050078-EI, In Re: Petition for rate increase by Progress Energy Florida, the 2004 fossil dismantlement study was withdrawn by the Company.
Rule 25-6.04346, F.A.C., is this Commission’s dismantlement rule. Of particular interest to this issue are subparts 2 (b) and (c):
(2)(b) “Dismantlement.” The process of safely managing, removing, demolishing, disposing, or converting for reuse the materials and equipment that remain at the fossil fuel generating unit following its retirement from service and restoring the site to a marketable or useable condition.
(2)(c) “Dismantlement Costs.” The costs for the ultimate physical removal and disposal of plant and site restoration, minus any attendant gross salvage amount, upon final retirement of the site or unit from service.
Staff believes that PEF’s site restoration assumptions in its 2008 fossil dismantlement study comport to the Commission’s rule. Accordingly, since they comport to the Commission rule, staff believes PEF’s site restoration assumptions by definition are reasonable.
Staff believes that OPC witness Pous may be suggesting that the Commission should revisit the site restoration provisions of the PSC’s dismantlement rule. If this is the case, staff notes that OPC at its option can file a petition for the Commission to revisit Rule 25-6.04346, F.A.C.
CONCLUSION
Staff recommends that the assumptions made by PEF in its 2008 fossil dismantlement study with regards to site restoration are reasonable.
DROPPED.
NUCLEAR DECOMMISSIONING COST STUDY
Should the currently approved annual nuclear decommissioning accruals be revised? (Category 1 Stipulation)
Approved Stipulation:
No. The issues associated with PEF’s nuclear decommissioning study should be deferred from the rate case and addressed next year when FPL files its nuclear decommissioning study in December 2010. This will afford the Commission the opportunity to address the appropriateness of each companies’ cost of nuclear decommissioning at the same time. PEF will not be required to prepare a new site-specific nuclear decommissioning study. However, PEF will be required to update the current study with the most currently available escalation rates. (AFFIRM, AG, and NAVY did not affirmatively stipulate this issue, and took no position.)
What is the appropriate annual decommissioning accrual in equal dollar amounts necessary to recover future decommissioning costs over the remaining life Crystal River Unit 3 (CR3)? (Category 1 Stipulation)
Approved Stipulation:
The issues associated with PEF’s nuclear decommissioning study should be deferred from the rate case and addressed next year when FPL files its nuclear decommissioning study in December 2010. This will afford the Commission the opportunity to address the appropriateness of each companies’ cost of nuclear decommissioning at the same time. PEF will not be required to prepare a new site-specific nuclear decommissioning study. However, PEF will be required to update the current study with the most currently available escalation rates. (AFFIRM, AF, and NAVY did not affirmatively stipulate this issue, and took no position.)
Has the company removed all non-utility activities from rate base?
Recommendation:
No. Plant-in-service should be reduced by $874,089 and accumulated depreciation should be reduced by $18,405, for a total reduction to rate base of $892,494. Depreciation expense should be reduced by $26,039 and property tax should be reduced by $8,300. (Wright)
Position of the Parties
PEF:
Yes, all non-utility activities have been appropriately removed from rate base.
OPC:
No. Rate base and associated accumulated depreciation should be reduced to account for the erroneous wholesale direct allocation to the City of Tallahassee’s ownership in CR3.
AFFIRM:
No position.
AG:
No.
FIPUG:
No. Rate base and associated accumulated depreciation should be reduced to account for the erroneous wholesale direct allocation to the City of Tallahassee’s ownership in CR3.
FRF:
No.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
OPC witness Dismukes stated that the Company did not assign any general plant and administrative and general expenses to the City of Tallahassee’s interest in Crystal River Unit 3 (CR3) plant. (TR 2264) Witness Dismukes explained that general plant and administrative and general expenses are common costs which essentially support the Company’s entire operations. Witness Dismukes continued by stating that these general plant and general expenses are not dedicated to specific groups of customers and that these costs should be distributed to all customers, including those for which the Company uses a direct assignment methodology. (TR 2265) Witness Dismukes recommended that the Commission allocate general plant to the Company’s Directly Assigned Wholesale operations using its percentage of directly assigned production, transmission and distribution plant to the total company production, transmission, and distribution plant. Witness Dismukes recommended reducing net plant by $1.8 million based on this methodology. She also recommended reducing retail test year administrative and general expenses by $6.3 million based on the directly assigned percentage of production, transmission, and distribution expenses to the total company production, transmission and distribution expenses. (TR 2265) Finally, witness Dismukes recommended reducing depreciation expense by $68,887 and property tax by $21,433. (EXH 152)
PEF witness Slusser did not agree with OPC witness Dismukes’ adjustment. He stated that the City of Tallahassee’s costs include a share of general plant and administrative and general expenses (A&G) based on the application of a labor ratio to total general plant and A&G. (TR 4053) Witness Slusser explained that the City of Tallahassee’s responsibility is included through the development and application of a labor ratio. He stated that a labor ratio is a common and recognized basis for allocating general plant and A&G expenses in a cost allocation study. Witness Slusser continued, explaining that the Company’s total labor component of O&M assignment for the City of Tallahassee is $701,000 for the test period. He stated that the Company’s total labor component of O&M expenses, excluding A&G, is $245,846,000 and that this computes to a percentage ratio of 0.285 percent ($701,000 divided by $245,846,000). (TR 4053) He continued, stating that this amount was included with other wholesale business’s responsibility that results in a wholesale labor responsibility of 12.309 percent. (TR 4054)
PEF witness Slusser testified that the labor allocator is identified as “K627” and is derived on Schedule 12, pages 1 and 2 of the Jurisdictional Separation Study. (EXH 47) He stated that the “K627” allocator can be seen as being applied to General Plant on Schedule 2, page 1, line 27, and is applied to A&G expense on Schedule 6, page 2, line 11 of the Jurisdictional Separation Study. (TR 4053-4054)
PEF’s brief states that according to Exhibit 152, total system A&G expenses are $269,669,716 and by dividing the $269,669,716 by total system energy of 48,574,364 MWH yields a system average A&G cost of $5.55 per MWH. (PEF BR 115) PEF contended that OPC witness Dismukes would assign $6,278,578 of A&G costs to the sale of 102,119 MWH to the City of Tallahassee, or an average cost of $61.48 per MWH. Finally, in its brief, PEF stated that the assignment to the City of Tallahassee, on a MWH basis of more than eleven times the system average A&G expense is absurd on its face. (PEF BR 115)
Affirm and the Navy did not address this issue in their briefs. AG’s and FRF’s position is that PEF has not removed all non-utility activity from rate base. (AG BR 7; FRF BR 55) FIPUG’s position is that rate base and associated accumulated depreciation should be reduced to account for the erroneous wholesale direct allocation to the City of Tallahassee’s ownership in CR3. (FIPUG BR 16) PCS Phosphate agreed with and adopted the position of OPC. (PCS BR 6)
ANALYSIS
After reviewing the Jurisdictional Separation Study (EXH 47), staff agrees with PEF witness Slusser that the City of Tallahassee’s costs include a share of general plant and A&G costs through the application of a labor ratio developed in PEF’s Jurisdictional Separation Study. Staff believes that, for plant and accumulated depreciation, a better allocator is the one recommended by OPC witness Dismukes with a staff modification, rather than the labor ratio developed by PEF’s Jurisdictional Cost Study. As described above, witness Dismukes allocated general plant to the wholesale operations using the percentage of directly assigned production, transmission, and distribution plant to the total company production, transmission, and distribution plant or .46 percent. (EXH 152) Using this methodology for plant results in a staff recommended reduction to plant of $874,089. As testified by PEF witness Slusser, the Company did make an adjustment to plant of .285 percent which results in a plant allocation to wholesale operations of $1,438,298 on a jurisdictional basis. OPC’s recommended adjustment was to reduce plant by $2,312,387 or $874,089 more than the Company allocated to wholesale. Staff recommends reducing plant by $874,089 based on OPC’s direct assignment methodology and after recognizing the amount already allocated by the Company.
OPC recommended increasing accumulated depreciation by $562,236 based on the same .46 percent used to allocate general plant. (EXH 152) Staff would modify the percentage calculation based on the Company’s percentage of directly assigned accumulated depreciation for production, transmission, and distribution to total accumulated depreciation for production, transmission, and distribution as shown on MFR Schedule B-6. OPC is in agreement with the modified calculation which results in a percentage of .27 percent rather than the .46 percent used by OPC witness Dismukes. (EXH 287) Applying the .27 percent to PEF’s Accumulated Depreciation amount results in an adjustment to increase Accumulated Depreciation by $331,304 on a jurisdictional basis. The Company included an adjustment of $349,709 to Accumulated Depreciation in its cost study. Staff recommends that the Company’s allocation be reduced by $18,405 ($349,709-$331,304). Staff’s total recommendation to rate base is a reduction of $892,494 ($874,089+$18,405). As a result of the recommended rate base adjustment, depreciation expense should be reduced by $26,039 and property tax should be reduced by $8,300.
Staff does not agree with OPC’s adjustment to reduce A&G expense by $6,278,578 as it appears that the adjustment is too high. While the plant allocation calculated by OPC resulted in a .46 percent of plant being allocated to wholesale operations, OPC’s A&G allocation percentage was calculated to be 3.5 percent. (EXH 152) Staff would agree with the Company that, based on an average cost per MWH, OPC’s adjustment appears to be unreasonable. Staff believes that the Company’s labor ratio of .285 percent is appropriate when allocating A&G expense to the Wholesale operations. Based on the Company’s Jurisdictional Separations Study, the Company has $266,959,000 labor related A&G expense. (EXH 47) The Company allocated $760,833 ($266,959,000 times .285 percent) of A&G expense on a system basis or $667,783 on a jurisdictional basis related to Tallahassee’s interest in CR3. This equates to $6.54 per MWH ($667,783 divided by 102,119 MWH) The $6.54 per MWH that the Company has allocated is more in line with the system average of $5.55 per MWH described above.
CONCLUSION
Staff recommends that plant-in-service be reduced by $874,089 and accumulated depreciation be reduced by $18,405, a total reduction to rate base of $892,494, based on a direct assignment allocation of general plant with modifications, rather than the labor ratio used by the Company for its wholesale operations allocation. Staff recommends that no additional adjustment is necessary for the allocation of A&G expense, as the amount of A&G expense the Company allocates to the wholesale operations is reasonable. Depreciation expense should be reduced by $26,039 and property tax should be reduced by $8,300 related to the general plant adjustment.
Should any adjustments be made to rate base related to the Bartow Repowering Project? (Category 1 Stipulation)
Approved Stipulation:
No. This stipulation does not prejudice the rights of any intervenor to contest the legality of including the Bartow project in rates during 2009. The new rates resulting from Docket No. 090079-EI, which will reflect the rate base and revenue requirement impact of the Bartow project, will supercede the rate change resulting from Order No. PSC-09-0415-PAA -EI as of the effective date of the new rates. (AFFIRM, and NAVY did not affirmatively stipulate this issue, and took no position.)
Should an adjustment be made to reflect any test year or post test year revenue requirement impacts of "The American Recovery and Reinvestment Act" signed into law by the President on February 17, 2009? (Category 2 Stipulation)
Approved Stipulation: No.
Is PEF's requested level of Plant in Service for the projected 2010 test year appropriate?
Recommendation:
No. The appropriate level of Plant in Service for the 2010 projected test year is $10,383,946,687. (Slemkewicz)
Position of the Parties
PEF:
Yes. PEF’s requested level of Electric Plant in Service for 2010 of $10,381,341,000 is appropriate.
OPC:
No. Plant in service should be adjusted ($2,312,287) to properly allocate general plant to wholesale operations. See Issue 24.
AFFIRM:
No position.
AG:
No.
FIPUG:
No. Plant in service should be adjusted ($2,312,287) to properly allocate general plant to wholesale operations.
FRF:
No.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
This is a fallout issue. Based on staff’s recommendations, the appropriate 13-month average of plant in service for the 2010 projected test year is $10,383,946,687. (See Schedule 1)
What adjustments, if any, should be made to accumulated depreciation to reflect revised depreciation rates, capital recovery schedules, and amortization schedules resulting from PEF's depreciation study?
Recommendation:
Staff recommends that accumulated depreciation be reduced by $52,413,604 jurisdictional ($56,741,252 system) for the 2010 projected test year to reflect the revised depreciation rates, capital recovery schedules, and amortization schedules resulting from PEF's depreciation study. (Marsh, P. Lee)
Position of the Parties
PEF:
No adjustments should be made.
OPC:
Accumulated depreciation should be reduced ($112,883,411) to account for the net impact of the amortization of the depreciation reserve surplus reserve recommended by OPC witness Jacob Pous and the impact of the wholesale allocation adjustment proposed by OPC witness Kimberly Dismukes.
AFFIRM:
No position.
AG:
Agree with OPC that accumulated depreciation should be reduced.
FIPUG:
See Issues 9 -13.
FRF:
Agree with OPC that accumulated depreciation should be reduced by $112,883,411.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
The parties addressed this issue under previous issues.
ANALYSIS
Staff calculated composite depreciation rates for each of the six functional areas of plant. Those rates are based staff’s recommendations in Issues 8 through 13. The composite rates are:
Steam Production 2.3 percent
Nuclear Production 2.3 percent
Other Production 3.1 percent
Transmission 2.2 percent
Distribution 2.6 percent
General 5.1 percent
Using these factors and the monthly plant balances shown on MFR Schedule B-8, staff calculated the depreciation expense using the composite rates. Substituting this expense for the Company’s accruals shown on MFR Schedule B-9, staff recalculated the 13-month average reserve balances.
CONCLUSION
Based on this calculation, staff recommends that accumulated depreciation be reduced by $52,413,604 jurisdictional ($56,741,252 system) for the 2010 projected test year to reflect the revised depreciation rates, capital recovery schedules, and amortization schedules resulting from PEF's depreciation study.
Is PEF's requested level of Accumulated Depreciation and Amortization in the amount of $4,437,117 for the 2010 projected test year appropriate?
Recommendation:
No. The appropriate Accumulated Depreciation and Amortization for the 2010 projected test year is $4,384,741,507. This is a fallout issue. (Marsh, P. Lee)
Position of the Parties
PEF:
Yes. PEF’s requested level of Accumulated Depreciation for 2010 of $4,437,117,000 is appropriate.
OPC:
No.
AFFIRM:
No position.
AG:
No.
FIPUG:
No. The adjustments Intervenors recommend should be made.
FRF:
No.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
This is a fallout issue. Based on staff’s recommendations in Issues 24, 28, and 69, the appropriate 13-month average amount of Accumulated Depreciation of Electric Plant in Service for the projected test year is $4,384,741,507. (See Schedule 1)
Is PEF's requested level of CWIP-No AFUDC in the amount of $151,145,000 for the projected 2010 test year appropriate?
Recommendation:
Yes. PEF’s requested level of CWIP-No AFUDC in the amount of $151,145,000 for the projected 2010 test year is appropriate. (Wright)
Position of the Parties
PEF:
Yes. PEF’s requested level of CWIP-No AFUDC for 2010 of $151,145,000 is appropriate.
OPC:
No position.
AFFIRM:
No position.
AG:
No position.
FIPUG:
No position.
FRF:
Agree with OPC.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
No party filed specific testimony on this issue or addressed it in their briefs. Staff recommends that PEF’s requested level of CWIP-No AFUDC in the amount of $151,145,000 for the projected 2010 test year is appropriate.
Is PEF's requested level of Plant Held for Future Use in the amount of $25,723,000 for the projected 2010 test year appropriate?
Recommendation:
Yes. PEF’s requested level of Plant Held for Future Use in the amount of $25,723,000 for the projected 2010 test year is appropriate. (Wright)
Position of the Parties
PEF:
Yes. PEF’s requested level of Plant Held for Future Use for 2010 of $25,723,000 is appropriate.
OPC:
No.
AFFIRM:
No position.
AG:
No.
FIPUG:
No.
FRF:
No.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
No party filed specific testimony for this issue or supported any adjustment to the Company’s amount. Staff recommends that PEF’s requested level of Plant Held for Future Use in the amount of $25,723,000 for the projected 2010 test year is appropriate. Affirm and the Navy did not address this issue in their briefs. While OPC, AG, FIPUG, and FRF took the position of “no”, none of these intervenors addressed the issue in their briefs. (OPC BR 30; AG BR 8; FIPUG BR 17; FRF BR 56)
Is PEF's requested level of Nuclear Fuel - No AFUDC (net) in the amount of $126,566,000 for the projected 2010 test year appropriate?
Recommendation:
Staff recommends that the Commission approve PEF’s requested amount of $126,556,000. (Matlock)
Position of the Parties
PEF:
Yes. PEF’s requested level of Nuclear Fuel-No AFUDC for 2010 of $126,556,000 is appropriate.
OPC:
No. PEF’s proposed nuclear fuel balance should be reduced ($26,752,411) as a result of the company’s failure to provide any justification for the large increase in test year nuclear fuel.
AFFIRM:
No position.
AG:
No position.
FIPUG:
No. PEF’s proposed nuclear fuel balance should be reduced ($26,752,411) as a result of the company’s failure to provide any justification for the large increase in test year nuclear fuel.
FRF:
No. PEF has failed to justify its nuclear fuel balance for the test year, and accordingly, its nuclear fuel balance should be reduced by $26,752,411.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
Nuclear fuel is included in working capital, which is a part of rate base. The parties did not brief this issue. PEF’s requested amount is $155,017,000. (MFR B-16, p. 1) The jurisdictional amount, with a separation factor of 0.81646, is $126,556,000. (PEF BR 10; TR 1915) Witness Weintraub’s direct testimony did not specifically state the amount in the B schedules.
PARTIES’ ARGUMENTS
OPC Witness Schultz recommended an adjustment of $32,766,000 to the nuclear fuel inventory. (TR 1915) Witness Schultz pointed out that the 2009 amount was $68,723,000 greater than the 2008 amount and that PEF should have to justify the increase. (TR 1915- 1916)
Witness Schultz calculated his recommended adjustment by starting with the December 2008 balance and adjusting it by PEF’s estimated purchases and amortization amounts for 2009 and 2010. (TR 1915 - 1916) The calculations appear in EXH 170, Schedule B-3. (EXH 170)
PEF witness Donahue addressed the requested amount in his rebuttal testimony. Witness Donahue testified that PEF’s original Schedule F-8 included only natural uranium inventory procurement for 2009, and that PEF inadvertently omitted $38 million in reload batch-specific services for the 2009 refueling. (TR 3625) MFR Schedule B-16 reflects the additional 2009 charges. Witness Donahue’s Exhibit 219 corrects the calculations in witness Schultz’s Exhibit 170. (EXH 219) Witness Donahue’s calculations differ slightly from those of witness Schultz. Witness Donahue explained that PEF included a June 2010 amortization expense, whereas witness Schultz had not. Witness Donahue explained further that witness Schultz’s calculations had employed averaged values for amortization and expenditures rather than PEF’s original inputs. (TR 3632 - 3633)
Witness Donahue explained the $68,723,000 increase from 2009 to 2010 in terms of PEF’s strategic inventory policy. (TR 3628 - 3629) PEF’s target inventory amount is 400,000 kilograms, a minimum of two years forward operation. (TR 3628) PEF’s nuclear unit has a 24 month refueling cycle, and the proposed policy would protect against supply interruptions and price uncertainty. (TR 3662 - 3663; 3628) PEF does not want to have to purchase uranium in the spot market. (TR 3629 - 3630) Further, witness Donahue explained that PEF does not want to have to operate the nuclear unit at reduced capacity. (TR 3652) Witness Donahue noted that several utilities have had to make spot market purchases of uranium because of supply interruptions. (TR 3655) Witness Donahue made further note of three other factors that influenced PEF’s inventory policy: the uranium price increases in 2006 to 2008, the increased number of nuclear power plants worldwide, and potential supply interruptions due to mines closing temporarily or not being ready for production when planned. (TR 3630; 3651) These observations of recent market conditions are the reasons for PEF’s strategic inventory policy and the increase in the nuclear fuel inventory. By having uranium in inventory, PEF may evaluate the most cost-effective purchase at the time the purchase is made. (TR 3629) Witness Donahue was questioned as to whether he considered the inventory strategy to be an intrinsic hedge against price fluctuation, and he agreed that it was. (TR 3672)
ANALYSIS
Staff agrees that due to the changes in the nuclear fuel market in recent years, both in the number of nuclear power plants worldwide, and in the potential unavailability of nuclear fuel at the time it is needed, PEF’s strategic inventory is sound. Witness Donahue testified that the nuclear unit burns the lowest cost fuel. (TR 3671) Staff notes that by guarding against supply interruptions, PEF’s strategy is not only a hedge against possible fluctuations in nuclear fuel prices, but a hedge against having to incur the higher costs of other fuels.
CONCLUSION
Due to the dollar amount corrections noted in witness Donahue’s rebuttal testimony and the rationale provided by witness Donahue for maintaining its target inventory level, staff recommends that no adjustment to PEF’s request nuclear fuel inventory amount.
Should an adjustment be made to PEF's requested storm damage reserve, annual accrual of $14.9 million, and target level of $150 million?
Recommendation:
Yes. PEF’s requested increases in storm damage reserve, annual accrual, and the storm damage target reserve level should be rejected. The annual accrual should remain at its current level of $5,566,000 ($6 million system) which results in an average storm damage reserve of $144,559,128 for 2010. PEF should discontinue accruing interest on the storm reserve balance and instead include the reserve as a reduction to rate base. Working capital should be increased by $14,546,872 for the test period. Operation and Maintenance expense should be reduced by $9,356,000 ($10 million system) for the test year. (Wright)
Position of the Parties
PEF:
No, PEF’s requested storm damage annual accrual of $14.9 million (jurisdictional) and its target reserve level of $152.5 million are appropriate given the likelihood of storms impacting PEF’s service territory and the increase in T&D infrastructure across PEF’s territory.
OPC:
Yes, PEF has not justified any increase in its storm damage accrual. PEF’s storm damage reserve is at a level that is more than adequate to cover its expected level of non-catastrophic storms based on recent experience. The Commission should order PEF to cease its storm damage accrual entirely.
AFFIRM:
No position.
AG:
Yes. Support OPC’s position.
FIPUG:
Yes. PEF’s requested storm reserve accrual of $14.9 million (jurisdictional), $16 million (system) should be suspended concurrent with the effective date of the new rates in this case. No further accruals should be made to the storm reserve as the current reserve balance is sufficient to provide for coverage of the expected annual loss (EAL) and also provides coverage for all category 1 storms.
FRF:
Yes. The Commission should order PEF to reduce its storm accrual to zero, because the current reserve balance is sufficient to cover the costs of non-catastrophic storms and because the company has available other means of addressing cost recovery in the event of catastrophic storms.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
On September 18, 2006, the Commission authorized PEF to continue a $6.0 million annual accrual to the storm reserve.[37] PEF was ordered to calculate interest on the after-tax balance of the storm reserve using a 30-day Dealer Commercial Paper rate equivalent to PEF’s actual rating as published by the Federal Reserve.
PEF witness Harris presented a Storm Loss Analysis to estimate PEF’s expected annual damage from hurricanes affecting its transmission and distribution (T&D) facilities. He explained that the analysis estimates all possible hurricane events and estimates the damage done to the assets at risk. (TR 1007) Witness Harris stated that, to make a reliable estimate of the expected annual loss (EAL), he included the most complete and full damage distribution that could be determined using both actual experience and possible damage from simulated hurricanes. (TR 1007) He testified that the EAL was based on data from the long term 100-year hurricane hazard record. PEF provided T&D asset portfolio data on a county-by-county basis. The study estimated that PEF’s expected annual hurricane damage is $20.2 million, but that $16.4 million of the $20.2 million EAL is assumed to be an annual obligation of the reserve. (TR 1009)
PEF witness Harris performed a Hurricane Landfall Analysis for Saffir-Simpson Hurricane Scale (SSI or Category) ranges that examined the potential impact on PEF of single hurricanes. (TR 1012) He stated that storms are grouped using Category intensities ranging from a least intensive storm rating of SSI-1 up to SSI-4. For SSI-1 landfalls, the study predicted the highest T&D damage to PEF’s territory would be less than $50 million and for SSI-2 storms the highest T&D damage would be approximately $140 million. Witness Harris stated that if a similar Category 3 hurricane to the one that hit Pinellas county in 1921 were to make landfall today, there would be estimated damages of $250 million. (TR 1013)
PEF witness Harris tested the Company’s current annual accrual level of $6 million, as well as three higher accruals of $16 million, $25 million, and $35 million. He testified that, for each funding case, the initial $133 million reserve balance was considered and he assumed that interest would be credited on positive reserve balances at a rate of 3.45 percent. (TR 1010) Witness Harris testified that PEF’s choice of an accrual of $16 million represents a balance between costs to PEF’s customers and protection from future surcharges due to storm damage that exceeds the reserve level. (TR 1006)
PEF witness Harris stated that he was familiar with PEF’s use of a storm restoration surcharge to restore its fund and to recover reasonable and prudent storm restoration costs after the 2004 and 2005 storms. (TR 1077) He responded that he understood that the reserve fund did go negative for a period after the 2004 storms and that PEF’s customers paid what the Commission approved as the reasonable and prudent restoration costs associated with the 2004 and 2005 storms. (TR 1077)
PEF witness Toomey stated that, based on the results of an updated Storm Loss and Reserve Solvency Study (Study), PEF included an increase in the annual accrual to its Storm Damage Reserve to $16 million on a system basis, or $10 million more that the $6 million accrual approved by the Commission in Order No. PSC-94-0852-FOF-EI, issued on July 13, 1994, Docket No. 940621-EI. (TR 1664) Mr. Toomey states that the $16 million accrual is equivalent to the expected, average recoverable annual storm loss based on the study. He continued, stating that this accrual level produces an expected reserve balance in five years of $152.5 million with a ten percent probability of a negative balance during that period. (TR 1664)
PEF witness Toomey also proposed to include the storm damage reserve in rate base and to discontinue the practice of accruing interest on the reserve balance, which would result in a reduction to rate base. He stated that the terms of the Stipulation approved in Order No. PSC-06-0772-PAA -EI, issued September 18, 2006, provided that this interest treatment was only in effect until such time as new permanent base rates are set and the parties to that agreement are free to advocate any position regarding interest on the storm reserve in any future proceeding. (TR 1664)
OPC Witness Schultz pointed out that the Company’s reserve has increased significantly over the past three plus years due to the collection of a surcharge from customers and also due to the low level of charges against the reserve. (TR 1917) Witness Schultz excluded 2004 and 2005 from his average calculation because he stated the year 2004 was an extraordinary year for hurricane costs and those costs were not charged against the reserve. He explained that, in Docket No. 041272-EI, PEF contended that the costs of severe storms like the 2004 hurricanes are too volatile, irregular in their occurrence, and unpredictable to be addressed in base rates; yet, the Company has made its recommendations based on a study that did factor in the impact from those storms. (TR1919)
OPC witness Schultz stated that PEF witness Toomey focused on the historical storms, with an emphasis made on a 1921 storm that hit Pinellas County, and that while Pinellas County is the Company’s most densely populated service territory, there are significantly larger geographical areas served by the Company with a statistically higher probability of landfall. (TR 1918) Witness Schultz testified that a major factor missing in Mr. Harris’s study is an explanation as to why a $150 million reserve would be better than a $125 million or a $100 million reserve. The Company explained that the $150 million presents a lower probability that the reserve will be exhausted over a five year period, decreasing the likelihood of having to petition the Commission for an additional storm surcharge. Witness Schultz believed that this is not justification for a $16 million accrual or a reserve of $150 million and that ratepayers should not be required to continue to fund a reserve that is excessive, especially in today’s economic climate. (TR 1922-1923)
OPC witness Schultz recommended that the Company’s accrual should be reduced to zero because the reserve is sufficient at this time to cover storm costs that are likely to occur based on recent history. He explained that charging the most recent three year average of $6.590 million against the reserve, without any additional accrual, results in a December 31, 2010 reserve balance of $128,651,299 and that, based on the Study, the probability that storm costs in a single year would eclipse the reserve is approximately 3.4 percent. (TR 1923) Witness Schultz stated that his recommendation reduced O&M expense $14.922 million and increased working capital and rate base $27.160 million. (TR 1923)
FIPUG witness Marz testified that PEF has not supported a $10 million increase. He continued, stating that since the current $133 million storm reserve is sufficient to cover all but the most severe storms, all contributions to the storm reserve should cease. (TR 2319 – 2320) Witness Marz stated that over the last three years PEF has charged less than $13 million (in total) to the reserve and that this equates to a three-year average of $4.3 million. (TR 2321) He testified that, according to PEF’s Study, there is a 3.3 percent probability that there will be damage in any one year that exceeds the current reserve level of $133 million. In other words, a storm inflicting damage in an amount of approximately $130 million is likely to occur once every 33 years. (TR 2322) He explains that the storm reserve and associated accrual are only part of the framework for recovering storm restoration costs.
FIPUG witness Marz stated that, according to the recent order in the TECO rate case, Order No. PSC-09-0283-FOF-EI, issued April 30, 2009, the Commission used the following framework to address the storm restoration cost issue:
We have established a regulatory framework consisting of three major components: (1) an annual storm accrual, adjusted over time as circumstances change; (2) a storm reserve adequate to accommodate most, but not all storm years; and, (3) a provision for utilities to seek recovery of costs that go beyond the storm reserve. (TR 2318)
FIPUG witness Marz explained that the Commission has demonstrated its ability and willingness to promptly consider and act upon a utility request to cover storm costs. As such, the storm reserve need not cover all storms and, to do so, would impose an unnecessary added burden on ratepayers. (TR 2322) Witness Marz explained that if accruals are stopped, over time, the level of the reserve will decline, however, absent a direct strike in the most populated portion of PEF’s service territory, or the once in every 35 year storm occurrence causing over $130 million in damage, the current reserve balance is sufficient to cover the EAL for the next eight years. (TR 2324)
In response to OPC witness Schultz excluding the 2004 storms, PEF witness Harris stated that, excluding any possible damage events, whether large and infrequent or small and frequent, is neither meaningful nor appropriate. (TR 1019) In rebuttal to witness Schultz and witness Marz’s recommendations to cease accruals, witness Harris testified that the concept of self-insurance using a reserve with accruals is to allow the accumulation of funds during periods of favorable storm experience that will be available for infrequent future hurricane losses. (TR 1024) He continued, stating PEF estimates that the value of its T&D assets has increased by more than a factor of three since 1993, when the accrual was approved by the Commission. Further, a higher accrual is appropriate to reflect the current increased value of its T&D assets. (TR 1024)
FRF stated, in its brief, that the Commission should order PEF to reduce its storm accrual to zero, because the current reserve balance is sufficient to cover the costs of non-catastrophic storms and the Company has available other means of addressing cost recovery in the event of catastrophic storms. (FRF BR 56) FRF stated that Progress’ storm costs, chargeable to its storm reserve, since the 2004 and 2005 seasons, have averaged approximately $6.6 million per year. FRF’s brief continued, stating that replicating the above analyses using the lesser annual damage/cost value, based on recent experience, indicates that the reserve balance at the end of 2014, heading into 2015, would be between $142 million and $147 million. (FRF BR 43) FRF further stated that since PEF’s customers in 2006 and 2007 paid in the majority – more than $121 million – of the balance in the storm reserve, it is far more fair to those customers who paid it, to relieve them of the obligation to pay in even more now. (FRF BR 45)
Affirm and Navy did not address this issue in their briefs. AG agreed with and supported OPC’s position. (AG BR 8) PCS Phosphate also agreed with and adopted the position of OPC. (PCS BR 7)
ANALYSIS
PEF witness Harris, when asked if the storm experience for 2005, 2006, 2007, 2008, and to date for 2009 was factored into his study, would the study produce any different results, responded that the study did in fact include 2006 and 2007 which had no storms. He continued, stating that 2008 and 2009 have not been included in the study and the 2008 data of no storms would in fact reduce to some very small extent the hazard. (TR 1058) Witness Harris also stated that storm hardening impacts were not taken into consideration in the study and that it’s generally understood that the activities for storm hardening will, in fact, reduce damage and restoration times. (TR 1059)
OPC witness Schultz and FIPUG witness Marz both recommended that the requested $10 million increase in the storm accrual be denied and that the current accrual cease. (TR 1923; TR 2319-2320) Witness Marz stated that the Commission has demonstrated its ability and willingness to promptly consider and act upon a utility’s request to recover storm costs. As such, the storm reserve need not cover all storms and to do so would impose an unnecessary added burden on ratepayers. (TR 2322)
Staff believes that if 2008 and 2009 data were included in the study, there would be some reduction in the hazard estimates. In addition, if the Company had included the storm hardening effects in the study, there would have been some hazard estimate reduction.
Based on PEF’s supplemental Schedule B-21, filed March 27, 2009, the Storm Damage reserve is projected to be $151,646,000 at December 31, 2009. (EXH 117) This amount does not include charges for Tropical Storm Fay (2008) of $9,869,872 (EXH 284), which would reduce the reserve to $141,776,128 at the end of 2009. It appears likely, at this point in time, that there will be no substantial charges to the storm reserve for 2009. According to witness Harris’s study, there is a 3 percent chance of having storm damages greater than $140 million in any given year and a 2.7 percent chance of having storm damages greater than $150 in any given year. (EXH 85)
Table 33-1 below demonstrates some storm reserve accrual options and the effect on PEF’s storm reserve. If the Commission chooses to have the Company continue to accrue interest on the storm damage reserve, as shown in column two, then the average storm reserve balance would not be deducted from rate base, as the Company is currently doing.
|
Table 33-1
2010 Projected Storm Reserve Balances
|
||||
|
|
(1) |
(2) |
(3) |
(4) |
|
|
Estimated Storm Reserve with no Additional Annual Accrual for 2010 |
Estimated Storm Reserve with interest only added. |
Estimated Storm Reserve with Current $6 million Annual Accrual for 2010 |
Estimated Storm Reserve with $16 million Annual accrual for 2010 |
|
Estimated Reserve Balance at December 31, 2009 |
$141,776,128 |
$141,776,128 |
$141,776,128 |
$141,776,128 |
|
Accrual |
$0 |
|
$5,566,000 |
$14,922,000 |
|
Estimated interest only accrued at 3.45% |
|
$4,891,000 |
|
|
|
Estimated Year-End Reserve Balance at December 31, 2010 |
$141,776,128 |
$146,667,128 |
$147,342,128 |
$156,698,128 |
|
Estimated Avg. Reserve Balance at December 31, 2010 |
$141,776,128 |
$144,221,628 |
$144,559,128 |
$149,237,128 |
PEF’s Study shows that the expected value of the reserve in 5 years will be $99 million with a 14 percent probability of the reserve being less than $0 based on the Study’s expected annual loss of $16.4 million and an annual accrual of $6 million. (EXH 85) Increasing the annual accrual to $16 million from $6 million reduces the probability of the reserve going negative by only 4 percent (from 14 percent to 10 percent). Staff believes that continuing the current $6 million storm accrual will continue to strike a balance between the ratepayers and the Company as it relates to the hazard risk of future storms affecting the reserve. While a category 4 storm could result in damage of over $500 million, the study shows that the probability of that occurring in any year is less than 1 percent. (EXH 85)
Based on OPC and FIPUG witnesses’ testimony, the average annual charges to the reserve in the last three years have ranged from $4.3 million to $6.5 million. (Marz TR 2321; Shultz TR 1923) If that pattern continues, for which of course there is no guarantee, then maintaining the reserve accrual at the $5.566 million dollar level should allow the Company to keep its storm reserve balance around the $140 million level, which would cover damages from a Category Two storm, based on PEF’s study. (EXH 85) If a storm occurs which is greater than a Category Two storm, then the Company has the option of petitioning the Commission for a surcharge to recover the storm damage costs not recovered through the storm damage reserve. As demonstrated in the past, the Commission has allowed companies to recover extraordinary hurricane losses, such as the ones experienced by PEF in 2004, through a separate surcharge.
If staff’s recommendation to maintain the accruals to the storm reserve at the current level of $5.566 million a year ($6 million system) is approved, then the average balance to working capital would include a storm reserve balance of $144,559,128, as shown in Table 33-1 above, at the bottom of the third column. The Company included $159,106,000 as a deduction to working capital and therefore rate base in its filing, based on its proposed annual accrual of $14,922,000 ($16 million system) for 2010. [Including the staff recommended $144,559,128 storm damage reserve as a deduction to rate base requires rate base to be increased by $14,546,872 ($159,106,000-$144,559,128).] Staff further recommends that the Company discontinue the practice of accruing interest on the storm reserve balance and instead include the reserve amount as a deduction to rate base. The Company included $14,922,000 ($16 million system) in operating expense due the storm damage accrual, therefore expenses should be reduced by $9,356,000 ($14,922,000-$5,566,000).
CONCLUSION
Staff recommends that PEF’s requested increases to its storm damage annual accrual and storm damage target reserve level be rejected because the current annual accrual of $5,566,000 million ($6 million system) is adequate. This results in an estimated average storm damage reserve of $144,559,128 for 2010. Working capital should be increased by $14,546,872 for the test period. The Company’s jurisdictional O&M expense should be reduced by $9,356,000 ($10 million system).
Should any adjustments be made to PEF's fuel inventories? (Category 2 Stipulation)
Approved Stipulation:
No adjustment should be made to PEF’s requested level of non-nuclear fuel inventories in the amount of $347,235,000 (system). The appropriate jurisdictional amount is a fall-out based on the jurisdictional separation factor approved in Issue 89.
Should unamortized rate case expense be included in Working Capital?
Recommendation:
No. Unamortized rate case expense in the amount of $2,787,000 should be removed from working capital. (Wright)
Position of the Parties
PEF:
Yes. $1,688,000 of unamortized rate case expense should be included in working capital. This 13-month average balance is based on total rate case expense of $2,251,077 amortized over 24 months.
OPC:
No.
AFFIRM:
No position.
AG:
No, as demonstrated by testimony of Mr. Schultz.
FIPUG:
No.
FRF:
No.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
PEF included $2,787,000 of unamortized rate case expense in working capital for 2010. (MFR Schedule B-1, p. 1) PEF revised, in its brief, the amount of unamortized rate case expense to be included in working capital to $1,688,000. (PEF BR 11)
OPC witness Schultz stated that the Company requested the full amount of unamortized rate case expense be included in rate base without factoring in amortization in the rate year and ignoring the fact that rate base is an average not a beginning of the year amount. (TR 1944) He stated that allowing the Company’s proposed treatment would result in a double charge to ratepayers and ignore the fact that amortization in the rate year occurred. (TR 1944) Witness Schultz recommended an adjustment to reduce the Company’s requested amount by $969,531 which resulted an unamortized rate case expense amount to be included in rate base of $1,817,469. (EXH 170, Schedule C-5, p. 1) On cross examination, witness Schultz agreed that it would also be appropriate to exclude rate case expense from working capital altogether. (TR 2000)
Affirm and the Navy did not address this issue in their briefs. AG’s position is “No”, as demonstrated by the testimony of Mr. Schultz. (AG BR 8) FIPUG’s and FRF’s positions are that unamortized rate case expense should be removed from working capital. (FIPUG BR 21; FGR BR 56) PCS Phosphate agreed with and adopted the position of OPC. (PCS BR 7)
ANALYSIS
The Commission has a long-standing policy in electric and gas rate cases of excluding unamortized rate case expense from working capital, as demonstrated in a number of prior cases.[38] 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 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. (Section 367.0816, F.S.) While unamortized rate case expense is not allowed to earn a return in working capital for electric and gas companies, it is offset by the fact that rates are not reduced after the amortization period ends.
Staff agrees with the long-standing policy that the cost of the rate case should be shared, and therefore recommends that the unamortized rate case expense amount of $2,787,000 be removed from working capital.
CONCLUSION
Staff recommends that the unamortized rate case expense of $2,787,000 be removed from working capital as this is the Commission’s long-standing policy.
Has PEF appropriately reflected the impact of SFAS 143 (Asset Retirement Obligations) in its proposed working capital calculation?
Recommendation:
Yes, PEF has appropriately reflected the impact of SFAS 143 (Asset Retirements Obligations) in its proposed working capital calculation. (Wright)
Position of the Parties
PEF:
Yes, PEF has appropriately removed the impact of SFAS 143 (Asset Retirement Obligations) in its proposed working capital.
OPC:
PEF has not demonstrated that it has reflected the impact of SFAS 143 in a revenue neutral manner as required by Commission Rule 25-14.014. The Commission should require PEF to record a system adjustment of $398,038,000 (reduction) to rate base to offset the increase in working capital caused by the ARO adjustment.
AFFIRM:
No position.
AG:
No.
FIPUG:
No. PEF has not demonstrated that it has reflected the impact of SFAS 143 in a revenue neutral manner as required by Rule 25-14.014, F.A.C. Absent any demonstration that PEF has complied with the rule, the Commission should require PEF to record an appropriate reduction to rate base to offset the increase in working capital caused by the ARO adjustment.
FRF:
No.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
OPC witness Schultz stated that the Company increased the working capital requirement by $446,569,000 and reduced plant in service $48,532,000 for a total net increase to rate base of $398,038,000 related to the Company’s Asset Retirement Obligations (ARO). (TR 1924) He explained that Commission Rule 25-14.014, F.A.C., Accounting for Asset Retirement Obligations Under SFAS 143, states that the implementation of the accounting treatment shall be revenue neutral in the rate making process. Witness Shultz expressed concern that he could not find any detailed explanation in testimony or in the filing that would explain this adjustment. He testified that the entry made by the Company in this docket removes the liability from working capital and does not have an equivalent entry made to plant, accumulated depreciation and/or the deferred assets included in working capital. (TR 1925) Witness Schultz did not recommend an adjustment in his direct testimony, but proposed to defer any determination to allow the Company to provide justification for the adjustment. (TR 1926) In its brief, OPC recommends that the Commission require PEF to record a system adjustment of $398,038,000 (reduction) to rate base to offset the increase in working capital caused by the ARO adjustment. (OPC BR 39)
PEF, in its brief, stated that the adjustments that OPC witness Schultz references, were made simply to remove from rate base the cumulative effect of the entries for SFAS 143, as required by rule. PEF’s brief states that what witness Schultz fails to recognize is that this adjustment has been made to remove the effects of FAS 143 per the requirements of Rule 25-14.014, F.A.C., because the account balances related to FAS 143 are included as a net reduction to the system per books numbers on MFR B-1. (PEF BR 113) The brief continued, explaining that the net ARO liability that is adjusted out of rate base is a funded liability and that the offsetting assets for this liability are the accounts for the nuclear decommissioning trust fund located in the Other Special Funds adjustment in MFR Schedule B-1, as explained in PEF’s response to Staff’s Interrogatory number 323. (EXH 42)
Affirm and the Navy did not address this issue in their briefs. AG’s and PEF’s position are that PEF has not appropriately reflected the impact of SFAS 143 in a revenue neutral manner. (AG BR 8; FRF BR 56) FIPUG stated that PEF has not demonstrated that it has reflected the impact of SFAS 143 in a revenue neutral manner, as required by Rule 25-14.014, F.A.C. Absent any demonstration that PEF has complied with the rule, the Commission should require PEF to record an appropriate reduction to rate base to offset the increase in working capital caused by the ARO adjustment. (FIPUG BR 21) PCS Phosphate agreed with and adopted the position of OPC. (PCS BR 8)
ANALYSIS
Staff has reviewed the ARO adjustments made to working capital as shown in MFR Schedules B-1 and B-17 and would agree with the Company that the ARO adjustments are in compliance with Rule 25-14.014, F.A.C. Rule 25-14.014, F.A.C., states that SFAS applies to legal obligations associated with the retirement of tangible, long-lived assets that result from the acquisition, construction, development or normal operation of a long-lived asset. For utilities required to implement SFAS 143, it shall be implemented in a manner such that the assets, liabilities and expenses created by SFAS 143 and the application of SFAS 143 shall be revenue neutral in the rate making process. According to PEF’s Working Capital MFR B-17, Account 230, Asset Retirement Obligations, in the amount of $376,877,000, was included in the system per books amount shown on B-1; additional amounts across various accounts totaling $69,692,000 related to SFAS 143 were also shown on B-17. (EXH 117) The total of these two amounts is $446,569,000 which is shown on MFR Schedule B-1, line 3, column H. There is also a net plant adjustment of a negative $48,532,000, shown on line 3 of MFR Schedule B-1, related to the ARO adjustment. Combining these two amounts results in the total rate base adjustment of $398,038,000 ($446,569,000- $48,532,000) shown on MFR Schedule B-1, page 1, column J. (EXH 117)
According to a Company response to staff’s discovery, MFR Schedule B-1, page 1 of 3, line 13, an adjustment to Other Special Funds, in the amount of a negative $446,428,000, contains the offsetting working capital liability accounts that correspond with the asset working capital accounts. (EXH 42) As evidenced by the Company’s MFR adjustments, staff agrees that the impact of SFAS 143 has been removed in a revenue neutral manner.
CONCLUSION
The Company has properly accounted for the impact of SFAS 143 in its working capital calculation and therefore no adjustment to rate base for this item is required.
Is PEF's requested level of Working Capital Allowance in the amount of ($9,041,000) for the projected test year appropriate?
Recommendation:
No. The appropriate 13-month average for working capital for the 2010 projected test year is $2,719,872. (Slemkewicz)
Position of the Parties
PEF:
Yes. PEF’s requested level of Working Capital Allowance for 2010 of ($9,041,000) was appropriate at the time of PEF’s original filing. However, an adjustment is necessary to correct the balance of unamortized rate case expense, based on the updated rate case expense estimate of $2,251,077 provided in response to Staff Interrogatory 267, which decreases Working Capital Allowance by ($1,099,000), resulting in an appropriate adjusted level of Working Capital Allowance for the 2010 projected test year of ($10,140,000).
OPC:
Working capital allowance should be increased $24,372,752 after adjusting for removing all unamortized rate case expense and excess storm damage reserve amounts.
AFFIRM:
No position.
AG:
No.
FIPUG:
No. Working capital allowance should be increased $26,190,221 after adjusting for removing unamortized rate case expense and excess storm damage reserve amounts.
FRF:
No.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
This is a fallout issue. Based on staff’s recommendations, the appropriate 13-month average for working capital for the 2010 projected test year is $2,719,872. (See Schedule 1)
Is PEF's requested level of Rate Base in the amount of $6,238,617,000 for the 2010 projected test year appropriate?
Recommendation:
No. The appropriate 13-month average rate base for the 2010 projected test year is $6,305,357,338. (Slemkewicz)
Position of the Parties
PEF:
Yes. PEF’s requested level of Rate Base for 2010 of $6,238,617,000 was appropriate at the time of PEF’s original filing. However, with the adjustment described in Issue 37 of ($1,099,000), the appropriate adjusted level of Rate Base for the 2010 projected year is $6,237,518,000.
OPC:
No. Rate base should be $6,348,626,000 after adjustments recommended by OPC witnesses Pous, Dismukes and Schultz.
AFFIRM:
No position.
AG:
No. Support OPC’s position.
FIPUG:
No. The adjustments suggested by Intervenors should be made.
FRF:
No. Consistent with the recommendations of the Citizens' witnesses, PEF's rate base should be $6,348,626,000.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
This is a fallout issue. Based on staff’s recommendations, the appropriate 13-month average rate base for the 2010 projected test year is $6,305,357,338. (See Schedule 1)
What is the appropriate amount of accumulated deferred taxes to include in the capital structure for the projected test year?
Recommendation:
The appropriate amount of accumulated deferred taxes to include in the capital structure is $420,330,116. (Davis)
Position of the Parties
PEF:
At the time of PEF’s original filing, the appropriate amount of accumulated deferred taxes to include in the capital structure was $389,297,000. However, as a result of changes identified in PEF’s position on Issue 38, the appropriate adjusted level of rate base for the 2010 projected year is $6,237,518,000. When synchronizing rate base to capital structure, the appropriate amount of accumulated deferred income taxes to include in capital structure for the 2010 projected test year is $389,229,000.
OPC:
$373,161,000.
AFFIRM:
No position.
AG:
Support OPC’s position.
FIPUG:
The appropriate amount of accumulated deferred taxes to include in the capital structure for the projected test year is $373,161,000.
FRF:
$329,399,000.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
According to PEF’s brief, the Company recorded a balance of jurisdictional ADITs to include in its capital structure of $389,229,000. (PEF BR 11) This is a reduction of $68,000 from PEF’s original filing of $389,297,000. (EXH 47, MFR Schedule D-1a) Deferred income taxes are a component of the capital structure that are a result of timing differences between depreciation used for calculating federal income tax liabilities and actual book depreciation for utility property or plant. (TR 1880)
OPC and FIPUG asserted that the correct amount of accumulated deferred income taxes is $373,161,000. They did not sponsor any specific testimony or propose any specific adjustment. (OPC BR 42) FRF asserted that the correct amount of ADITs is $329,399,000. FRF did not sponsor any specific testimony or propose any specific adjustment to the ADITs.
Affirm and the Navy took no position on this issue. AG and PCS Phosphate adopted OPC’s position on this issue.
ANALYSIS
The correct amount of accumulated deferred income taxes is a result of various adjustments. Adjustments to net operating income, depreciation, rate base, etc. all affect the amount of ADITs. Based on adjustments to various capital structure and rate base items discussed in other issues, the net effect is an increase in the balance of ADITs.
CONCLUSION
Staff recommends that the appropriate amount of accumulated deferred taxes to include in PEF’s capital structure is $420,330,116.
What is the appropriate amount and cost rate of the unamortized investment tax credits to include in the capital structure for the projected test year?
Recommendation:
The appropriate amount of unamortized investment tax credit to include in PEF’s capital structure is $3,898,262 at a cost rate of 8.74 percent. (Davis)
Position of the Parties
PEF:
At the time of PEF’s original filing, thee appropriate amount of unamortized investment tax credits to include in the capital structure was $3,610,000. However, as a result of changes identified in PEF’s position on Issue 38, the appropriate adjusted level of rate base for the 2010 projected year is $6,237,518,000. When synchronizing rate base to capital structure, the appropriate amount of unamortized investment tax credits to include in capital structure for the 2010 projected test year is $3,609,000 and the appropriate cost rate is 9.74 percent.
OPC:
$4,991,000. The appropriate cost rate is 7.84%.
AFFIRM:
No position.
AG:
Support OPC’s position.
FIPUG:
The appropriate amount of the unamortized investment tax credit is $4,991,000. The appropriate cost rate is 7.84%.
FRF:
$4,991,000; appropriate cost rate of 7.84%.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
The Company included $3,609,000 of unamortized ITCs in its capital structure at a cost rate of 9.74 percent. (PEF BR 12) The Company recognized that the balance of ITCs has changed from its original filing as a result of changes made to the jurisdictional rate base. (EXH 47, MFR Schedule D-1a)
OPC and FIPUG proposed an ITC balance of $4,991,000, with a cost rate of 7.84 percent. (OPC BR 42; FIPUG BR 22) OPC acknowledged that “this issue is dependent upon the final determination of the cost of Common Equity and the capital structure proportions recommended by the Commission.” (OPC BR 42) OPC’s position is based on the capital structure and ROE recommended by witness Woolridge. There was no specific testimony regarding the ITCs.
AG and PCS Phosphate adopted the position of OPC. (AG BR 9; PCS BR 8) Affirm, FRF, and Navy did not specifically address this issue.
ANALYSIS
Staff believes that PEF’s methodology for calculating the balance of ITCs is appropriate and is in accordance with IRS requirements. (EXH 47, MFR Schedule B-23) However, due to adjustments to various capital structure and rate base items discussed in other issues, the net effect is an increase in the balance of ITCs.
In addition, staff does not agree with the Company’s proposed cost rate of 9.74 percent. (EXH 47, MFR Schedule D-1a) This rate is based on a number of adjustments and the cost rates of investor sources of capital that staff has recommended be changed in other issues. Staff recalculated the ITC cost rate based on other staff adjustments and staff’s recommended return on equity, resulting in an 8.74 percent weighted average cost rate for ITCs.
CONCLUSION
Staff recommends that the appropriate amount and cost rate of unamortized ITCs to include in PEF’s capital structure are $3,898,262 and 8.74 percent, respectively, as shown on Schedule 2.
Should PEF's requested pro forma adjustment to equity to offset off-balance sheet purchased power obligations be approved?
Recommendation:
No. The pro forma adjustment in question in the amount of $711,330,000 (system) should be removed from the capital structure through a specific adjustment to common equity on a system basis. (Maurey)
Position of the Parties
PEF:
Yes.
OPC:
No. Phantom equity should not be allowed. Due to the lack of guidance given by S&P on the risk factor they use, the Commission’s support for the collection of payments for PPAs, the fact that the PPAs are not GAAP adjustments and are not liabilities on the company books and the fact that, from a regulatory perspective, PPA payments are unlike debt, no phantom equity related to PPA adjustment to the Company’s capital structure is appropriate.
AFFIRM:
No position.
AG:
No. Support OPC’s position as explained by Dr. Woolridge.
FIPUG:
No. PEF should not be permitted to impute debt for purchased power agreements. Recovery for such contracts is under the purview of this Commission and once such contracts are approved, PEF is entitled to full and direct recovery of all such costs and has no risk of disallowance. Thus, they should not be treated as imputed debt.
FRF:
No.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
PEF witness Sullivan testified that all three rating agencies consider off-balance sheet obligations such as purchased power agreements (PPAs) when assessing a company’s credit quality. (TR 1245; PEF BR 65) While he acknowledged that each of the rating agencies employs different methodologies for the treatment of PPAs, witness Sullivan stressed that each rating agency considers PPAs when assessing PEF’s credit quality. (TR 4152) For this reason, he testified that the weighted average cost of capital approved for purposes of this proceeding must recognize on a pro forma basis the amount of equity necessary to offset the effect of the imputed debt associated with long-term PPAs. (TR 1249; PEF BR 68)
Based upon the methodology employed by Standard & Poors’ (S&P), witness Sullivan testified that PEF would need approximately $711 million of additional equity in its capital structure to maintain a 50 percent equity ratio after the recognition of imputed debt associated with its long-term PPAs. (TR 1249; PEF BR 65) He noted that the 2005 Stipulation approved by the Commission in Order No. PSC-05-0945-S-EI included a pro forma adjustment to PEF’s capital structure for ratemaking purposes to account for S&P’s methodology related to the treatment of PPAs.[39] (TR 1251) Witness Sullivan further testified that “an unfavorable outcome in PEF’s current base rate proceeding, including a reversal of the favorable treatment of long-term PPAs in the Company’s capital structure under its existing rate case stipulation and settlement agreement approved by this Commission in Order No. PSC-05-0945-S-EI, would have a negative impact on PEF’s credit profile and could result in a downgrade.” (TR 1250–1251)
OPC witness Woolridge testified that, given the Commission’s specific clause recovery mechanism for PPA payments, the financial condition of an electric company is not impaired by entering into these contracts. (TR 3000; OPC BR 43; FRF BR 22) He based his opinion on the following passage from a March 2005 Moody’s Investors Service (Moody’s) report:
If a utility enters into a PPA for the purpose of providing an assured supply and there is reasonable assurance that regulators will allow the costs to be recovered in regulated rates, Moody’s may view the PPA as being most akin to an operating cost. In this circumstance, there most likely will be no imputed adjustment to the obligations of the utility.
(TR 3001)
In addition, witness Woolridge testified that even if S&P did impute debt associated with PPAs, such an adjustment is not consistent with GAAP accounting and will not show up in the balance sheet the Company files with the Securities and Exchange Commission (SEC). (TR 3002; OPC BR 46; FRF BR 23) For these reasons, witness Woolridge argued that “providing incremental revenues through a higher equity ratio and a higher overall rate of return is unnecessary and would result in an unwarranted revenue benefit to the utility.” (TR 3000–3001; OPC BR 47; FRF BR 22–23)
FIPUG witness Pollock also testified that it is unnecessary to impute equity for PPA obligations. (TR 3207) He noted that, once approved, PEF is allowed full and direct recovery of firm energy and purchased power capacity costs under the fuel and capacity cost recovery clauses. Moreover, because such contracts are reviewed in annual cost recovery proceedings, witness Pollock testified there is minimal recovery risk associated with PPAs. (TR 3207; FIPUG BR 25)
Witness Pollock testified that, due to the cost recovery mechanisms available to PEF for the recovery of costs associated with PPAs, he believes it is unlikely Moody’s would make an imputed debt adjustment applicable to these contracts. (TR 3211; FIPUG BR 25; FRF BR 22) He also referenced language from a May 2007 S&P report that explained how its methodology for the treatment of PPAs is for the rating agency’s own analytical purposes. Specifically, S&P stated:
We adjust utilities’ financial metrics, incorporating PPA fixed obligations, so that we can compare companies that finance and build generation capacity and those that purchase capacity to satisfy customer needs. The analytical goal of our financial adjustments for PPAs is to reflect the fixed obligations in a way that depicts the credit exposure that is added by PPAs. That said, PPAs also benefit utilities that enter into contracts with suppliers because PPAs will typically shift various risks to the suppliers, such as construction risk and most of the operating risk. PPAs can also provide utilities with asset diversity that might not have been achievable through self-build. The principal risk borne by a utility that relies on PPAs is the recovery of the financial obligation in rates.
(TR 3212 -3213; EXH 94)
Finally, witness Pollock noted that the Commission recently rejected a similar proposal by Tampa Electric Company (TECO) to recognize imputed equity in its capital structure in Order No. PSC-09-0283-FOF-EI.[40] (TR 3212; FIPUG BR 23; FRF BR 23) For these reasons, he recommended the Commission exclude PEF’s imputed equity adjustment from its capital structure for purposes of setting rates in this proceeding. (TR 3207; FIPUG BR 26; FRF BR 22–23)
ANALYSIS
PEF included a $711 million pro forma adjustment to equity in its projected 2010 capital structure for purposes of setting rates in this proceeding. (TR 1247, 3000, 3207) This adjustment has the effect of increasing PEF’s equity ratio as a percentage of investor capital from 50.3 percent to 53.9 percent. (TR 3206, 4148) The annual revenue requirement impact of this adjustment is $24.7 million. (TR 1283; EXH 42, BSP 1621)
The pro forma adjustment to equity proposed by PEF is not an actual equity investment in the utility. (EXH 39, BSP 1488–1489) It is a ratemaking adjustment. (TR 1260) If this adjustment is approved for purposes of setting rates in this proceeding, the Company would essentially be allowed to earn a risk-adjusted equity return on an incremental equity investment that was never made. (TR 1259–1260)
PEF witness Sullivan acknowledged that, given the cost recovery mechanism in Florida and the fact that PEF has never been denied recovery of PPA costs, there is a very low risk of non-recovery of PPA costs. (TR 1263) He also agreed that Moody’s does not make an explicit adjustment for PPAs like S&P does and that there is no guarantee PEF’s bond rating would be upgraded by any rating agency if this pro forma adjustment were approved for rate setting purposes. (TR 1267, 4151) Witness Sullivan acknowledged that the proposed pro forma adjustment is not consistent with GAAP accounting. (TR 4151) He also agreed that the Commission recently denied a request by TECO for a similar adjustment in its rate case. (TR 1267) Finally, witness Sullivan agreed that, while the 2005 Stipulation included a pro forma adjustment to PEF’s capital structure for ratemaking purposes to account for S&P’s methodology related to the treatment of PPAs, said approval did not constitute binding Commission precedent in any future proceeding. (TR 4169–4170; EXH 129)
CONCLUSION
Based on the record evidence and for the reasons discussed above, staff recommends PEF’s requested pro forma adjustment to equity be denied for purposes of setting rates in this proceeding. Thus, staff recommends the $711 million (system) adjustment be removed from the capital structure through a specific adjustment to common equity on a system basis.
What is the appropriate equity ratio that should be used for PEF for purposes of setting rates in this proceeding?
Recommendation:
The appropriate equity ratio that should be used for PEF for purposes of setting rates in this proceeding is 46.7 percent as a percentage of total capital which equates to an equity ratio of 50.3 percent as a percentage of investor capital. (Maurey)
Position of the Parties
PEF:
The appropriate equity ratio is 50.52% equity as reflected in MFR D-1a.
OPC:
As demonstrated by Dr. Woolridge, a 50% equity ratio is fair to the Company and is conservative compared to electric utilities generally and is consistent with the way investors view PEF’s capital structure.
AFFIRM:
No position.
AG:
Support OPC’s position as explained by Dr. Woolridge.
FIPUG:
The appropriate equity ratio for PEF is 50.3%. This is comparable to other A-rated electric utilities. This capital structure reduces PEF’s revenue request by $33 million.
FRF:
50%.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
PEF witness Sullivan testified that PEF needs a solid investment grade rating in order to provide the Company with access to low-cost debt under all capital market conditions. (TR 1233, 1252; PEF BR 62) PEF is currently rated triple B plus by S&P, single A3 by Moody’s, and single A flat by Fitch Ratings (Fitch). (TR 1232) Witness Sullivan testified that the Company is targeting a mid-single A rating from each of the three rating agencies. (TR 1233; PEF BR 62)
Witness Sullivan testified that utilities with stronger bond ratings, such as the mid-single A rating targeted by PEF, can expect to pay a lower premium on its debt and equity than utilities with weaker bond ratings. (TR 1240; PEF BR 64) He stated that achievement and maintenance of a mid-single A rating requires a capital structure and other credit metrics that are supportive of this rating. (TR 1252) Witness Sullivan also cautioned that both S&P and Moody’s have indicated in recent reports that a lack of improvement in PEF’s credit metrics could result in ratings being lowered. (TR 1242; PEF BR 64)
Witness Sullivan testified that the importance of financial strength is even more pronounced for utilities pursuing new nuclear generation. (TR 1236) He stated that rating agencies as well as equity investors expect utilities with plans for nuclear development or other large generation projects to maintain strong ratings to offset the perceived risks associated with such projects. (TR 1236) Given PEF’s significant capital expenditure program, he stated that PEF needs to strengthen its financial profile in the near term so the Company has sufficient access to both the short-term and long-term capital markets at a reasonable cost. (TR 1242–1243; PEF BR 64)
Witness Sullivan challenged the reasonableness of the intervenors’ recommendations regarding the appropriate equity ratio for PEF. (TR 4146–4149; PEF BR 64–65) He testified that OPC witness Woolridge’s and FIPUG witness Pollock’s recommended adjustments would negatively impact PEF’s ability to maintain and improve its financial strength. (TR 4132) Moreover, witness Sullivan argued that if the intervenors’ recommended adjustments to cash flow, return on equity, and capital structure were adopted, “the change in the tone of the Florida regulatory environment and the resulting implications on the Company’s cash flow and credit metrics would likely result in a credit rating downgrade.” (TR 4157–4158) PEF witness Dolan further added that “denying some or all of PEF’s rate request will affect the Company’s financial strength and potentially have an adverse impact on the timing and ultimate construction of the Levy Nuclear Project.” (TR 2495; PEF BR 68)
OPC witness Woolridge testified that PEF’s proposed equity ratio of 53.9 percent as a percentage of investor capital is not appropriate for purposes of this proceeding because it is not based on Company book figures due to a number of adjustments, most notably imputed equity; it does not reflect the actual capitalization of PEF or Progress Energy, Inc. (Progress Energy); and it does not reflect the capitalization of other electric utilities. (TR 2964; OPC BR 48; FRF BR 21)
Witness Woolridge recommended an equity ratio of 50.0 percent as a percentage of investor capital. (TR 2962; OPC BR 49; FRF BR 21) He arrived at his recommended level of equity capitalization by averaging the Company’s projected 2009 and 2010 equity capitalizations. (TR 2963; EXH 158) He stated that his recommended equity ratio is higher than the average equity ratio for the companies in his electric utility proxy group and therefore represents a lower financial risk than his group of comparable companies. (TR 2963) By eliminating the proposed pro forma adjustment to equity, witness Woolridge testified that his recommended equity ratio is a more realistic view of the expected equity capitalization of the Company as viewed by investors. (TR 2959–2960; OPC BR 49)
FIPUG witness Pollock testified that PEF’s equity ratio of 50.3 percent (excluding the imputed equity adjustment for PPAs) should be used for purposes of determining the cost of capital in this proceeding. (TR 3215; FIPUG BR 28; FRF BR 21–22) He noted that a 50 percent equity ratio is higher than the industry average. (TR 3207) For the period 2006 through the first quarter of 2009, the average equity ratio for all electric utilities followed by SNL Financial ranged from 46.1 percent to 47.6 percent. (TR 3213–3214; EXH 200) He concluded that an “adjusted 2010 test year common equity ratio of 50.3 percent would be well above the average” equity ratio of other electric utilities. (TR 3214; FIPUG BR 27; FRF BR 21–22)
Witness Pollock also addressed the issue of whether a 50 percent equity ratio would be sufficient to maintain PEF’s current bond ratings. He testified that the average equity ratio for A-rated electric utilities over the period 2006 through the first quarter of 2009 varied from a low of 49.5 percent to a high of 51.0 percent and averaged 50.2 percent over the entire period. (TR 3215; EXH 200; FIPUG BR 27; FRF BR 22) Based on this analysis, he stated that PEF’s equity ratio of 50.3 percent (without including an adjustment for PPAs) is consistent with comparable A-rated electric utilities. (TR 3215) For these reasons, witness Pollock recommended the Commission recognize an equity ratio of 50.3 percent as a percentage of investor capital and 46.9 percent as a percentage of total capital for purposes of this proceeding. (TR 3215; FIPUG BR 28; FRF BR 22)
ANALYSIS
The projected 2010 capital structure PEF has proposed for purposes of setting rates in this proceeding reflects an equity ratio as a percentage of investor capital of 53.9 percent. (EXH 47, MFR Schedule D-1a) Excluding the $711 million pro forma adjustment to equity, the capital structure reflects an equity ratio of 50.3 percent. (TR 4148) Staff’s recommendation regarding whether PEF’s proposed pro forma adjustment related to imputed equity should be approved is discussed in Issue 41. The equity ratio at year-end 2008 was 42.2 percent. (EXH 47, MFR Schedule D-2)
Witness Sullivan testified that the Company’s proposed equity ratio is necessary to generate credit metrics commensurate with a bond rating in the mid-single A range. (TR 1252) However, there are a number of factors used to determine a company’s bond rating, not just its capital structure. (TR 4148) Even if the Commission were to approve PEF’s petition and grant the full amount of its requested rate increase, there is no guarantee that S&P would upgrade PEF’s credit rating from triple B to single A. (TR 1272–1273)
Witness Sullivan acknowledged that Company management makes the decisions that affect the relative balance of debt and equity maintained in PEF’s capital structure. (TR 1271) He also agreed that management’s decisions regarding the relative capitalization of PEF impact the Company’s bond rating. (TR 1271) S&P employs a consolidated rating methodology whereby it generally assigns a rating to each entity in an organization based upon the credit profile of the consolidated entity. (TR 1271–1272) Witness Sullivan agreed that the reason S&P assigns a lower rating to PEF than the ratings assigned by Moody’s and Fitch is due to the consolidated rating methodology that considers the credit profile of Progress Energy, not just the credit profile of PEF on a stand-alone basis. (TR 1272) Moreover, witness Sullivan agreed that S&P would not upgrade PEF’s rating until the credit metrics of both PEF and Progress Energy improved to the level necessary to support the stronger rating. (TR 1272)
Prior to the acquisition of Florida Progress Corporation by Carolina Power and Light Company (CPL), PEF was referred to as Florida Power Corporation (FPC). (TR 1277) At that time, FPC was rated double A minus by S&P and double A3 by Moody’s. (EXH 39, BSP 1464, 1466) After the acquisition was announced, Moody’s placed FPC’s ratings on review for possible downgrade. (TR 1276; EXH 39, BSP 1466) In its August 23, 1999 report, Moody’s stated:
Concern for ratings pressure from acquisition financing drives the review for downgrade of FPC securities and the negative outlook for CPL’s ratings. While the two entities are roughly equal in size, Moody’s is concerned FPC, the higher-rated and therefore more liquid entity, may come under relatively greater pressure to service acquisition leverage.
(TR 1276; EXH 39, BSP 1466)
On November 20, 2000, S&P downgraded FPC’s rating from double A minus to triple B plus. (TR 1275; EXH 39, BSP 1464) In the report that announced the downgrade, S&P stated:
The rating actions are in anticipation of the imminent completion of the previously announced agreement by Carolina Power & Light to purchase Florida Progress and its affiliates in a stock-and-cash transaction, valued at $5.3 billion. The transaction will require a substantial amount of debt financing (approximately $3.5 billion) initially funded through commercial paper at the CP&L energy level.
(EXH 39, BSP 1464) While its rating was further downgraded to triple B flat in August 2003 and later upgraded back to triple B plus in March 2007, PEF’s rating from S&P never recovered to its preacquisition rating, or even a single A rating, principally due to the pressure to service significant debt leverage at the parent level. (EXH 39, BSP1386–1388, 1455)
From 1999 through 2003, FPC/PEF generated net income of $1.4 billion. (EXH 39, BSP 1395–1396) Approximately 23 percent of this amount was invested in the utility and the remaining 77 percent was retained by the parent company. (EXH 39, BSP 1395–1396) Equity infusions from the parent to the utility totaled $71 million over this period. From 1999 through 2003, FPC/PEF’s equity ratio varied from a low of 47.7 percent to a high of 54.7 percent and averaged 51.8 percent over the period. (EXH 39, BSP 1391; EXH 47, MFR Schedule D-2)
From 2004 through 2008, PEF generated net income of $1.6 billion. (EXH 39, BSP 1395–1396) Approximately 76 percent of this amount was invested in the utility and the remaining 24 percent was retained by the parent company. (EXH 39, BSP 1395–1396) There were no equity infusions from the parent to the utility over this period. From 2004 through 2008, PEF’s equity ratio varied from a low of 42.2 percent to a high of 50.5 percent and averaged 47.5 percent over the period. (EXH 39, BSP 1391; EXH 47, MFR Schedule D-2)
For the 10-year period 1999 – 2008, PEF’s equity ratio averaged 49.7 percent. (EXH 39, BSP 1391; EXH 47, MFR Schedule D-2) However, by year-end 2008 PEF’s equity ratio was 42.2 percent. (EXH 47, MFR Schedule D-2) To achieve an equity ratio of 53.9 percent for purposes of the 2010 projected capital structure, PEF assumed it would pay no dividend to Progress Energy in 2009, would receive an equity infusion from Progress Energy totaling $640 million in 2009, and would have $711 million of imputed equity recognized in its 2010 capital structure. (TR 1259; EXH 39, BSP 1396)
Staff does not agree with the arguments advanced by Company witnesses that the Commission must set rates in this proceeding to generate revenue sufficient to achieve financial metrics in a particular rating range. The Commission has a long history of constructive regulatory decisions that provide for the timely recovery of prudently incurred expenses and capital investments to support the financial integrity of companies under its jurisdiction. If a company believes a particular debt rating is optimal, it is the parent company’s responsibility to manage the flow of funds between itself and its operating companies. This includes making equity infusions in the utility sufficient to achieve financial metrics in that rating range consistently over time, not just during the test year.
In addition to the fact that there is no guarantee that PEF’s rating from S&P would be upgraded to single A even if it received the full rate increase it requested in this proceeding, it is unrealistic to expect S&P to upgrade PEF until the financial metrics at the consolidated level also improve. The level of equity recognized for purposes of setting rates should be in line with the risk associated with the provision of regulated operations. (TR 1451) There is no mandate from S&P or any of the other rating agencies that this Commission or any other regulatory commission allow an inflated equity ratio at the utility level to compensate for the parent company’s use of higher debt leverage. (EXH 39, BSP 1442–1443) The Commission’s statutory responsibility is to set a rate of return for this Company commensurate with returns on investments in other companies of comparable risk, sufficient to maintain the financial integrity of the company, and sufficient to attract capital under reasonable terms. (TR 1320–1321, 3040–3041) This responsibility does not extend to setting a rate of return to generate cash flow sufficient to improve the debt rating of the parent company.
As for the testimony that rating agencies and equity investors expect utilities with plans for new nuclear projects to have stronger credit ratings to offset the perceived risks associated with such projects, staff is in agreement. (TR 1236) Florida has a progressive recovery mechanism in place for the timely recovery of prudently incurred costs associated with new nuclear development. (TR 1288–1289; EXH 276) The nuclear cost recovery statute passed by the Florida Legislature in 2006 effectively shifted risk from a company’s shareholders to its customers to help mitigate the perceived risk associated with new nuclear construction. (EXH 39, BSP 1408–1409) However, Moody’s has commented on the various means available to companies pursuing new nuclear generation to defend existing ratings or to limit negative rating actions. (TR 4247; EXH 240) It was the Company’s decision to pursue a nuclear project that is significantly greater than the value of its existing rate base. (TR 1284–1286, 1332) Now having made this election, it is the responsibility of management and the Board of Directors of PEF to actively pursue financial policies that will permit the utility to strengthen it financial metrics as well as improve the financial metrics at the consolidated level necessary to support a higher rating. (TR 4247–4248) In a June 19, 2009, report regarding PEF, Moody’s stated that:
An upgrade is unlikely while the utility has a major rate case pending and is undertaking a major new nuclear construction project. An upgrade could be considered, however, if there are significant mitigants to offset the risks inherent in such a large and complex nuclear construction project, including preapproval of recovery for nuclear capital expenditures, the sharing of risk with contractors or other parties, and the inclusion of co-owners or other partners. An upgrade could also be considered if there is a recovery of cash flow coverage metrics from currently low levels, including a ratio of CFO before working capital plus interest to interest above 5.0x and CFO before working capital to debt above 25 percent. The rating is somewhat constrained by the high level of debt at the parent company level.
(EXH 39, BSP 1410–1414)
The Commission will provide for the timely recovery of prudently incurred expenses and capital expenditures. However, as noted earlier, the Commission cannot set rates sufficient to overcome constraints on the utility’s bond rating due to a high debt level at the parent company.
Finally, PEF witness Vander Weide identified a group of companies that he testified face comparable business risk and represent a reasonable proxy for the risk of investing in PEF. (TR 1361; 2357–2358) The companies in witness Vander Weide’s proxy group had an average equity ratio of 47.4 percent in 2007 and 45.7 percent in 2008. (TR 1458–1460; EXH 278) While the companies are projected to have equity ratios in 2010 that range from a low of 38.5 percent to a high of 55.5 percent, the average projected equity ratio for the group is 46.6 percent. (EXH 278)
CONCLUSION
Staff recommends the capital structure shown on Schedule 2. This capital structure reflects the Company’s proposed capital structure for 2010 with a specific adjustment to remove the $711 million of imputed equity as discussed in Issue 41. This capital structure reflects an equity ratio of 50.3 percent as a percentage of investor capital. This equity ratio reflects the projected $640 million equity infusion from Progress Energy. (EXH 39, BSP 1396) As of June 2009, nearly half or $310 million of this amount has actually been invested in the utility. (EXH 39, BSP 1439) While this relative level of equity is within the range of projected equity ratios of the companies in witness Vander Weide’s proxy group, it is above the average equity ratio for the group. In addition, although this level of equity is below the equity ratio requested by PEF, it is higher than the actual equity ratio the Company has maintained on average over the past decade. The recommended equity ratio is supported by competent and substantial evidence in the record.
While the equity ratio and authorized ROE are discussed in two separate issues, staff believes equity ratio and ROE are inextricably related. Staff’s recommended ROE of 11.25 percent discussed in Issue 47 is implicitly linked to the equity ratio recommended herein. If a decision is made to adopt a higher or lower equity ratio, staff’s recommendation regarding ROE may decrease or increase accordingly to recognize the decrease or increase in financial risk.
Have rate base and capital structure been reconciled appropriately?
Recommendation:
Yes. For the sole purpose of setting rates in this case only, and with the exception of certain adjustments to capital structure discussed in Issues 41, 42, and 44, rate base and capital structure have been reconciled appropriately. (D. Buys)
Position of the Parties:
PEF:
Yes specific adjustments have been made where appropriate and the pro rata adjustment has been appropriately been made across all sources of capital.
OPC:
No position.
AFFIRM:
No position.
AG:
No position.
FIPUG:
No position.
FRF:
No position.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
In its post-hearing brief, PEF stated, “[t]he only evidence in the record concerning the appropriate method of reconciling rate base to capital structure is found in the testimony of Mr. Toomey and in Exhibit 42.” (PEF BR 73) PEF argued that a significant portion of PEF’s non-specific (pro rata) adjustments reflect the removal of clause-related plant and AFUDC-eligible CWIP from PEF’s retail rate base. (PEF BR 73; EXH 42, BSP 1630) PEF asserted that when these items are removed from rate base, it is appropriate to make the necessary reconciling adjustment to capital structure on a pro rata basis over all sources of capital in order to avoid double-counting the benefit of zero cost deferred taxes and low cost customer deposits. (PEF BR 73; EXH 42, BSP 1630-1631) PEF argued that making the adjustment in this manner is the easiest way to avoid a potential violation of the IRS tax normalization rules and avoid the risk of losing the IRS tax benefit of accelerated depreciation. (PEF BR 73) PEF explained that reconciling rate base over all sources of capital also matches the way PEF funds its rate base and manages its sources of capital. (PEF BR 74) PEF argued, “[g]iven this uncontroverted evidence on the appropriate way to reconcile rate base to capital structure, PEF’s reconciliation methodology should be approved.” (PEF BR 74)
None of the intervenors took a position on this issue nor did any intervenor proffer any testimony or file a post-hearing brief regarding the appropriate method to reconcile rate base to capital structure.
ANALYSIS
The purpose of this issue is to determine if specific and pro rata adjustments made by PEF to rate base have been appropriately reconciled to the capital structure. The appropriateness of those adjustments centers on whether certain specific and pro rata adjustments should be reconciled over all sources of capital or over investor sources of capital only. PEF stated that the Company reconciled rate base to capital structure by first making specific adjustments where appropriate. (PEF BR 73) MFR Schedule D-1b lists the specific and pro rata adjustments that PEF made to the Company’s proposed capital structure for the 2010 test year. (EXH 47) PEF made specific adjustments to common equity, short-term debt, and deferred income taxes. For common equity, PEF removed $4,825,000 of non-utility investment consistent with Commission practice. (Toomey TR 1669; EXH 47) PEF added $711,330,000 to common equity to compensate for off-balance sheet obligations related to PPAs. Staff’s recommendation regarding whether PEF’s proposed pro forma adjustment related to imputed equity should be approved was addressed in Issue 41. PEF removed $7,833,000 from short-term debt to convert a variable rate to a daily weighted average balance. (PEF BR 73, Toomey TR 1668; EXH 47) For accumulated deferred income taxes (ADITs), PEF added $32,524,000 to reflect ADITs related to nuclear decommissioning and added $127,565,000 to recognize the impact that the recovery of the costs through the Nuclear Cost Recovery Clause has on ADITs. (PEF BR 73; MFR Schedule D-1b; Toomey TR 1669) After PEF made these adjustments to specific components in the capital structure, all other adjustments were made pro rata over all sources of capital.
In its response to Staff’s 27th Set of Interrogatories, Number 321 (EXH 42), PEF explained how the amount of CWIP removed from the rate base should be removed from the capital structure for the 2010 test year. In its response, PEF stated:
With the exception of the portion of CWIP generated by the Levy Nuclear project and collected through the clause, PEF believes that the CWIP rate base adjustments should be adjusted from the capital structure on a pro rata basis over all sources of capital. This approach is preferred as the simplest way to assure that ADIT adjustments do not violate tax normalization rules. Under the tax normalization rules, any ratemaking adjustment with respect to a utility’s deferred tax reserves must be consistently applied with respect to rate base, depreciation expense and income tax expense. The consequence of a normalization violation would be the risk of loss of accelerated tax methods for depreciation. This would represent a loss of substantial benefits to our customers. In addition this approach makes sense in that it matches the way PEF funds rate base and manages it sources of capital.
(EXH 42, BSP 1630)
PEF explained that a significant portion of its pro rata adjustments reflect the removal of clause-related plant and AFUDC eligible CWIP from PEF’s retail rate base. (EXH 42, BSP 1630) PEF removed the clause-related items because they earn their own return outside of base rates through a cost recovery clause. (EXH 42, BSP 1630) The clause-related plant and AFUDC-eligible CWIP removed from rate base earn a Commission approved rate of return calculated over all sources of capital including accumulated deferred income taxes, customer deposits, and investment tax credits. (EXH 42, BSP 1630) PEF maintained that one approach to assure the Company does not violate IRS tax normalization rules is to have the calculation of the rate of return for the reconciled jurisdictional rate base match the calculation of the rate of return for clause-related items. (EXH 42, BSP 1630) PEF stated that this avoids the potential of double counting the benefit of ADITs and customer deposits. (EXH 42, BSP 1630) PEF explained:
If PEF were to adjust rate base over only investor sources of capital, when clause assets are removed from jurisdictional rate base, the proportion of deferred taxes and customer deposits that remain in the reconciled, jurisdictional adjusted capital structure used to calculate the base rate required rate of return is increased. The same zero cost deferred taxes and customer deposits that reduced the clause rate of return are used again to lower the base rate required rate of return. This is the double counting effect.
(EXH 42, BSP 1630)
PEF asserted that the same scenario occurs when an adjustment is made to exclude AFUDC-eligible CWIP from rate base. (EXH 42, BSP 1630) PEF explained that the AFUDC rate that provides a capitalized return on the CWIP balances removed from rate base is calculated over all sources of capital. (EXH 42, BSP 1630) It is PEF’s position that the methodology used to calculate the base rate required rate of return should match the methodology to calculate the rate of return earned on CWIP. (EXH 42, BSP 1630) PEF explained that if the AFUDC-eligible CWIP balance remaining in the jurisdictional rate base is reconciled over investor sources of capital only, no deferred taxes and customer deposits are removed from the capital structure, thus, a double counting of ADITs and customer deposits would occur again. (EXH 42, BSP 1630)
In response to Staff’ 20th Request For Production Of Documents, Number 107, PEF provided copies of the Internal Revenue Code and IRS income tax regulations regarding the IRS tax normalization rules. (EXH 39) During cross examination, PEF witness Toomey was presented with a copy of PEF’s response and testified that he was generally familiar with the IRS tax normalization rules. (TR 1886) Witness Toomey agreed that the IRS tax normalization rules relate to the treatment of deferred taxes and income tax expense for the purpose of calculating federal income tax liability. (TR 1886) Witness Toomey testified that he believed the IRS normalization rules specify things that have to be done in the reporting of the deferred taxes in order to ensure that PEF does not violate normalization. (TR 1887) Witness Toomey was asked if the IRS tax normalization rules specify that a regulated utility shall make adjustments to its rate base over all sources of capital as opposed to only investor sources of capital in its capital structure. In reply, witness Toomey stated, “[i] don’t know if it does specifically or not.” (TR 1888) Witness Toomey could not identify anything in the Internal Revenue Code and IRS income tax regulations that would specifically tell PEF exactly how to make the adjustments in its MFRs or reconcile its rate base. (TR 1888)
PEF argued that a second reason to reconcile rate base over all sources of capital is that it matches the way PEF funds its rate base and manages its sources of capital. (EXH 42, BSP 1631; PEF BR 74) PEF explained that all sources of capital, including customer deposits, deferred taxes, and investment tax credits are pooled together to fund PEF’s rate base in the normal course of its operations. (EXH 42, BSP 1631) PEF stated that its sources of capital cannot be traced solely to investor-supplied sources of capital and that it does not segregate its sources of capital. (EXH 42, BSP 1631; PEF BR 74) PEF explained that such adjustments would be appropriate only in PEF were financing the clause-related plant and CWIP that is excluded from rate base differently than it is financing the plant and CWIP included in the recoverable base rate. (EXH 42, BSP 1631)
CONCLUSION
PEF believes that to avoid a potential violation of IRS tax normalization rules the rate of return for clause-related plant and AFUDC-eligible CWIP removed from the rate base should be calculated using the same methodology as the rate of return for the jurisdictional rate base so that adjustments to ADITs are applied consistently. PEF has reconciled rate base to capital structure over all sources of capital. Staff believes that the appropriate method to reconcile rate base to capital structure is to make adjustments to the class of capital in the capital structure that correspond to adjustments made to related accounts in rate base. For example, adjustments made to rate base from accounts that do not generate deferred taxes or investment tax credits should not be reconciled over deferred taxes or investment tax credits in the capital structure. However, staff recognizes that the record does not contain testimony and evidence supporting this methodology. The record shows that PEF does not segregate its sources of capital and track its funding usage. Accordingly, for the sole purpose of setting rates in this rate case only, staff recommends that rate base and capital structure have been reconciled appropriately.
What is the appropriate capital structure for the projected test year?
Recommendation:
The appropriate capital structure for the purpose of setting rates in this proceeding is based on PEF’s projected 2010 capital structure with certain adjustments to reflect the level of equity investment in the utility on a going-forward basis. The capital structure reflects a projected equity ratio of approximately 50.3 percent as a percentage of investor capital. The appropriate capital structure for the projected 2010 test year is shown on Schedule 2. (D. Buys)
Position of the Parties:
PEF:
The appropriate capital structure is shown in MFR D-1a.
OPC:
The capital structure recommended by Dr. Woolridge as reflected in Ex. 170, Schedule D, appended to the testimony of Helmuth W. Schultz, is the appropriate capital structure.
AFFIRM:
No position.
AG:
Support OPC’s position as recommended by Dr. Woolridge.
FIPUG:
See Issue 41 regarding disallowance of an adjustment for purchased power agreements and Issue 42 as to the appropriate equity ratio. FIPUG agrees with OPC as to the other components of capital structure.
FRF:
The appropriate capital structure for PEF in this case is that recommended by Dr. J. Randall Woolridge, witness for the Citizens of the State of Florida.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
PEF has targeted a mid-single A long-term credit rating from each of the three rating agencies that perform credit analysis on PEF. (PEF BR 62). PEF witness Sullivan asserted that PEF’s projected 2010 capital structure reflects a 50 percent common equity ratio, before taking long-term power purchase agreements into account. (TR 1249) He argued that PEF will need approximately $711 million of additional common equity in its capital structure to maintain a 50 percent equity ratio after recognizing imputed debt associated with the PPA contracts as off-balance sheet adjustments made by S&P. (TR 1249) Witness Sullivan also argued that PEF must improve its financial risk profile based on the financial metrics applied by the ratings agencies. (TR 1248) PEF argued that improving its financial risk profile means improving its cash flow and achieving a projected 2010 book capital structure ratio with 50 percent common equity while also taking the off-balance sheet impact of long-term purchase power contracts into account. (PEF BR 64; TR 1243) Witness Sullivan concluded that a mid-single A long-term credit rating is important because it provides PEF access to low-cost debt under all capital market conditions. (PEF BR 62; TR 1233)
OPC argued that the capital structure for ratemaking purposes rests essentially on the contested items of PEF’s equity ratio and PEF’s proposed pro forma adjustment for the off-balance sheet purchased power obligations in Issues 41 and 42. (OPC BR 49) In its brief, OPC explained that the difference between PEF’s requested equity ratio of 53.9 percent and OPC’s proposed equity ratio of 50 percent is PEF’s addition of $711 million to common equity. (BR 48) OPC argued that its proposed capital structure much more accurately reflects the Company’s capital structure as viewed by investors. (OPC BR 48; Woolridge TR 2999). OPC witness Schultz provided OPC’s proposed capital structure in an attachment to his direct testimony. (TR 1969; EXH 170) OPC asserted that the appropriate capital structure for PEF contains an equity ratio of 46.94 percent as a percentage of total capital for rate making purposes. (EXH 170, p. 1 of 2)
FIPUG witness Pollock argued that the Commission should eliminate the PPA adjustment in determining PEF’s capital structure which would reduce PEF’s common equity ratio to 50.3 percent. (TR 3213) He also argued that a common equity ratio of 50.3 percent should be the basis for determining the cost of capital in this proceeding. (TR 3215) Witness Pollock testified that the common equity ratio of 50.3 percent translates into a 46.93 percent regulatory common equity. (TR 3215) Witness Pollock asserted that on a comparable basis, the adjusted 2010 test year common equity ratio of 50.3 percent is 345 basis points higher than the average equity ratio of other electric utilities over the period 2006 to 2009. (TR 3213-3214; EXH 200) FIPUG argued that such a high equity range would be detrimental to ratepayers. (FIPUG BR 27) Witness Pollock testified that:
Common equity is more expensive than debt. In this instance, PEF is asking for a common equity return that is over 600 basis points higher than its embedded cost of long-term debt. A utility having too much equity in its capital structure has a higher cost of capital than a utility with a more balanced common equity ratio. All else being equal, the higher the overall common equity ratio, the higher the rates all PEF ratepayers will bear.
(TR 3214)
In its post-hearing brief, FIPUG asserted that throughout this case, the Commission heard utility witnesses opine that they must have a higher bond rating to access capital markets. (BR 27) FIPUG disagreed with PEF’s view and argued that a capital structure containing a 50 percent common equity ratio is sufficient to maintain PEF’s current bond rating. (FIPUG BR 27) Witness Pollock argued that PEF’s 50 percent common equity ratio (without the imputed equity) is consistent with comparable A-rated electric utilities. (TR 3215)
FRF argued that the appropriate capital structure is that recommended by OPC witness Woolridge. (FRF BR 57)
ANALYSIS
This issue addresses the appropriate capital structure for ratemaking purposes for the projected 2010 test year. This issue is in essence a fall out issue from Issues 41 and 42. Issue 41 addresses whether PEF’s requested pro forma adjustment to common equity to offset off-balance sheet purchased power obligations should be included in the capital structure. Issue 42 addresses the appropriate equity ratio for PEF for the purposes of setting rates. The Commission’s decisions on Issues 41 and 42 will affect the amount of equity in PEF’s projected 2010 capital structure discussed herein. PEF proposes a capital structure for the projected 2010 test year that reflects an equity ratio as a percentage of investor capital of 53.9 percent. (MFR Schedule D-1a) Excluding the $711 million of imputed equity, the capital structure reflects an equity ratio of 49.2 percent. (Sullivan TR 4148)
As discussed in Issue 41, staff recommends that the Commission disallow the pro forma adjustment to add $711 million to common equity to offset the imputed debt associated with PEF’s PPA contracts. The adjustment removes $711 million from common equity in PEF’s projected capital structure for the 2010 test year. This results in an equity ratio of 50.3 percent as a percentage of investor capital and 46.7 percent as a percentage of total capital.
PEF has targeted a long-term debt credit rating in the mid-single A range from each of the three rating agencies: Standard and Poor’s Rating Service (S&P), Moody’s Investor Service (Moody’s), and Fitch Ratings (Fitch). (Sullivan TR 1233) Currently, PEF’s credit ratings are BBB+ from S&P, A3 from Moody’s, and A from Fitch. (Sullivan TR 1232) Witness Sullivan testified that recognizing the imputed debt associated with long-term PPAs in this base rate proceeding would be a positive development for PEF’s credit profile. (TR 1249) Witness Sullivan argued that in order to obtain an “A” rating from S&P, PEF’s leverage ratio (percentage of debt in its capital structure) should be no more than 50 percent. (TR 1248) Witness Sullivan maintained that the effect of the off-balance sheet obligations changes PEF’s projected 2010 leverage ratio from 50 percent to 53.1 percent. (TR 1248) Witness Sullivan asserted that without the imputed equity adjustment, the equity ratio in PEF’s projected capital structure for year-end 2010 would be 46.56 percent. (TR 1247) He argued that PEF’s weighted average cost of capital should be adjusted to properly reflect the additional equity necessary to offset the additional imputed debt. (Sullivan TR 1249)
PEF has proposed a capital structure designed to increase operating cash flow by $300 million. (Sullivan TR 1243) Witness Sullivan testified that this positive cash flow increase improves PEF’s credit metrics which enhances PEF’s credit risk profile and increases the chances of consistent ratings across all three rating agencies and a top tier short-term credit rating. (TR 1243) Witness Sullivan testified that, “[a] strong credit rating will reduce the risk to a manageable level that PEF may not have continuous access to the capital markets to fund its capital obligations or to fund them at a reasonable cost to our customers.” (TR 1235)
Staff does not agree with PEF that the Commission should authorize a capital structure in this proceeding that will generate revenue sufficient to achieve a particular credit rating. Witness Sullivan agreed that if the Commission were to approve PEF’s petition and grant the full amount of its requested rate increase, there is no guarantee the S&P will upgrade PEF’s credit rating to single A. (Sullivan TR 1272-1273) If a company believes a particular debt rating is optimal, it is the parent company’s responsibility to make equity infusions in the utility consistently over time sufficient to achieve financial metrics in that rating range, not just during the test year.
PEF’s management and Board of Directors make the decisions regarding the level of debt and equity in PEF’s capital structure. (Sullivan TR 1271) Those decisions have an impact on PEF’s credit ratings. (Sullivan TR 1271) S&P assigns a lower credit rating to PEF than the ratings assigned by Moody’s and Fitch due to S&P’s consolidated rating methodology. (Sullivan TR 1272) S&P considers the credit profile of Progress Energy and all its subsidiaries, not just the credit profile of PEF on a stand-alone basis. (Sullivan TR 1271) Witness Sullivan agreed that, at least with respect to S&P, PEF’s credit rating will not improve until the credit metrics of both PEF and Progress Energy improve to a level necessary to support a stronger credit rating. (TR 1272)
OPC witness Woolridge proposed a capital structure for ratemaking purposes that includes an equity ratio of 50 percent based on investor provided capital. (TR 2962) Witness Woolridge testified that PEF’s proposed capital structure contains too high an equity ratio and the Commission should either employ a more reasonable capital structure and reflect this capital structure in revenue requirements or recognize the downward impact that a high equity ratio will have on the financial risk of a utility and authorize a lower common equity cost rate. (TR 2962)
PEF applied a jurisdictional factor of 75.95 percent to customer deposits included in its proposed capital structure for the 2010 test year. The application of a jurisdictional factor of 75.95 percent to customer deposits is inconsistent with prior Commission practice. A jurisdictional factor of 100 percent for customer deposits was used in Florida Power & Light Company’s 1983 rate case.[41] Staff believes it is appropriate to use 100 percent of the customer deposits in the capital structure for the purposes of setting rates in this case.
CONCLUSION
Staff is recommending a capital structure that reflects PEF’s proposed capital structure for the projected 2010 test year on MFR Schedule D-1a, page 1 of 3, with specific adjustments to remove the $711 million of imputed equity from common equity as discussed in Issue 41, and increase the jurisdictional factor applied to customer deposits from 75.95 percent to 100 percent. Staff believes the equity ratio and ROE are inextricably related. Staff’s recommended ROE of 11.25 percent discussed in Issue 47 is implicitly linked to staff’s recommended equity ratio of 50.3 percent discussed in Issue 42. If the Commission decides to adopt a higher or lower ROE, staff’s recommendation regarding the equity ratio may decrease or increase accordingly to recognize the decrease or increase in financial risk. Staff’s recommended capital structure is supported by competent and substantial evidence in the record. Accordingly, staff recommends that the appropriate capital structure for the purpose of setting rates in this proceeding is based on PEF’s projected 2010 capital structure with certain adjustments to reflect the level of equity investment in the utility on a going-forward basis. The capital structure reflects a projected equity ratio of approximately 50.3 percent as a percentage of investor capital. The appropriate capital structure for the projected 2010 test year is shown on Schedule 2.
What is the appropriate cost rate for short-term debt for the projected test year?
Recommendation:
The appropriate cost rate for short-term debt for the projected 2010 test year is 3.72 percent. (D. Buys)
Position of the Parties:
PEF:
The appropriate cost rate for short-term debt is 5.25% as presented in MFR D-3.
OPC:
3.06%.
AFFIRM:
No position.
AG:
Support OPC’s position.
FIPUG:
The appropriate cost rate for short-term debt for the projected test year is 3.06%.
FRF:
3.06%.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
PEF proposed a cost rate of 5.25 percent for short-term debt for the projected test year. (PEF BR 61; EXH 47, MFR Schedule D-3, p. 1 of 3) PEF’s 2010 short-term debt rate is based on a Commercial Paper (CP) borrowing rate of 4.50 percent. (PEF BR 61) In its post-hearing brief, OPC asserted that, “The Company’s short-term debt rate is reasonable and should be approved because it is the only rate that appropriately takes into account the projected short-term debt costs in 2010.” (BR 61)
OPC witness Woolridge testified that a short-term debt cost rate of 3.06 percent is appropriate instead of the Company’s proposed 5.25 percent. (OPC BR 50; TR 2964) Witness Woolridge asserted that PEF’s CP rate is derived from the projected three-month London Interbank Offered Rate (LIBOR) implied from the Bloomberg LIBOR forward curve plus a CP yield differential. (TR 2964) Witness Woolridge affirmed that PEF’s average three-month LIBOR rate implied from the Bloomberg LIBOR forward curve is 2.66 percent for 2009. (OPC BR 50; TR 2964) Witness Woolridge argued that 2.66 percent is significantly above the three-month LIBOR rates that have existed in 2009. (TR 2964) Witness Woolridge asserted that the three-month LIBOR rates peaked in the fall of 2008, fell to 1.00 percent in May, and have continued to decline. (TR 2964) Witness Woolridge computed a short-term debt cost rate of 3.06 percent and argued this is a very fair cost rate given that the current three-month LIBOR rate is 0.47 percent compared to the 2009 average of 1.00 percent. (OPC BR 50; TR 2965)
In his rebuttal testimony, witness Sullivan argued that witness Woolridge based his short-term debt cost rate on spreads above the average three-month LIBOR rate for 2009 of 1.00 percent. (TR 4153) Witness Sullivan argued that although this average is more than double the current three-month LIBOR rate, it does not properly capture future expectations for increases in the three-month LIBOR. (TR 4153) He claimed that the three-month LIBOR is expected to be approximately 1.25 percent by the middle of 2010 and over 2.00 percent in December 2010. (Sullivan TR 4153) Witness Sullivan explained that witness Woolridge’s recommended short-term debt cost rate of 3.06 percent includes 0.21 percent for fees associated with PEF’s credit facility. (TR 4153) He argued that the 0.21 percent fee used by witness Woolridge is incorrectly based on 2009 amounts. (Sullivan TR 4163, MFR Schedule D-2, p. 2) Witness Sullivan maintained the correct fee is 0.75 percent, as reflected on MFR Schedule D-2, page 1. (TR 4153; EXH 47) He asserted that witness Woolridge’s recommended short-term debt cost rate is understated by 0.54 percent for credit facility fees and the market expectations for increases in the three-month LIBOR in 2010. (Sullivan TR 4153-4154)
ANALYSIS
PEF’s 5.25 percent cost rate for short-term debt for the projected 2010 test year is comprised of an assumed commercial paper borrowing rate of 4.50 percent, plus fees associated with its credit facility of 0.75 percent. (EXH 39, BSP 1471-1472) PEF based its 4.50 percent CP interest rate assumption on an estimated yield spread over the projected three-month LIBOR rate. (EXH 39, BSP 1449-1450)
PEF’s projected three-month LIBOR rates for 2009 and 2010 are based on an implied three-month LIBOR forward curve from Bloomberg dated November 24, 2008. (EXH 39, BSP 1449-1450) The three-month LIBOR rates PEF used for 2010 from the Bloomberg forward curve are as follows:
Q1 2010 = 1.65%
Q2 2010 = 1.35%
Q3 2010 = 1.10%
Q4 2010 = 2.90%
The average of the four three-month LIBOR rates for 2010 is 1.75 percent. The three-month LIBOR rates PEF used for 2009 from the Bloomberg forward curve are as follows:
Q1 2009 = 2.98%
Q2 2009 = 2.75%
Q3 2009 = 2.95%
Q4 2009 = 1.94%
The average of the four, three-month LIBOR rates for 2009 is 2.66 percent. Staff agrees with witness Woolridge that 2.66 percent is significantly above the three-month LIBOR rates that have existed in 2009. Staff concurs that the average three-month LIBOR rate for 2009 is approximately 1.00 percent. (TR 3036) The three-month LIBOR rate was at 0.30 percent at the time of witness Woolridge’s cross examination on September 29, 2009. (TR 3036) Staff believes the record indicates the data PEF provided for the implied three-month LIBOR forward curves from Bloomberg for 2009 and 2010 is stale and has been shown to be overstated.
Staff believes that the record supports a range of 1.00 percent to 1.25 percent for an estimated three-month LIBOR rate for 2010. (Woolridge TR 2965; Sullivan TR 4153) For ratemaking purposes, staff believes a fair estimate is the median of that range or 1.12 percent.
To achieve its forecasted CP borrowing rate, PEF added an estimated yield spread over the three-month LIBOR rate for 2010. PEF indicated that spreads would range from 160 basis points to 340 basis points. (EXH 39, BSP 1449-1450) PEF provided no documents to support its assumed yield spread. (EXH 39, BSP 1471-1472) Staff agrees with witness Woolridge’s methodology explained in his direct testimony to interpolate an assumed yield spread. (TR 2965; EXH 158, p. 4 of 5) Using the data for 2009, witness Woolridge subtracted the average three-month LIBOR rate implied from the Bloomberg LIBOR forward curve of 2.66 percent from PEF’s assumed CP borrowing rate of 4.50 percent which resulted in an assumed CP yield spread of 1.845 percent. (TR 2965) Staff believes this estimate is supported by PEF’s CP yield spreads for the last four months of 2008. In its response to OPC Interrogatory 168, PEF stated, “[o]ur commercial paper rates in the last 4 months of 2008 had spreads to three-month LIBOR ranging from -7 basis points to +333 basis points . . .” (EXH 39, BSP 1449-1450) The central tendency of the range of negative 7 to 333 basis points is a median of 163 basis points. Therefore, staff believes an assumed CP yield spread of 184.5 basis points for 2010 is reasonable.
The third component of the cost rate for short-term debt is the fees associated with PEF’s credit facility. Staff agrees with witness Sullivan that the appropriate adjustment for credit facility fees is 0.75 percent. (TR 4153) The record shows that the PEF is obligated to pay annually 0.07 percent of the $450 million credit facility committed to PEF by the lenders. (EXH 39, BSP 1471-1472, and 1449-1450) PEF is also obligated to pay an annual administrative agency fee of $25,000 for the credit facility. (EXH 39, BSP 1471-1472, and 1449-1450) PEF also amortizes the expenses associated with fees incurred to originate the credit facility in March 2005. (EXH 39, BSP 1471-1472, and 1449-1450) PEF estimated that the amortization is expected to be approximately $145,000 in 2010. (EXH 39, BSP 1471-1472, and 1449-1450) The total amount of the fees is $485,000. (EXH 39, BSP 1471-1472, and 1449-1450) PEF divided the amount of the fixed fees by the projected amount of the 13-month average outstanding balance for short-term debt during the projected 2010 test year to arrive at a cost rate of 0.75 percent for the credit facility fees ($485,000 ¸ $65,051,000 = 0.75). (EXH 39, BSP 1449-1450; MFR Schedule D-3, p. 1)
In his testimony, witness Woolridge used 0.21 percent to account for the credit facility fees in his computation for the short-term debt cost rate. (TR 2965) He did not provide any testimony that explains how he arrived at 21 basis points for the credit facility fees. (TR 2965) PEF estimated that the total credit facility fees in 2009 to be $485,000. (EXH 39, BSP 1471-1472, and 1449-1450) Dividing the amount of the fixed fees by the amount of the 13-month average outstanding balance of short-term debt during 2009 results in a cost rate of 0.20 percent for the credit facility fees ($485,000 ¸ $238,364,000 = 0.20). (EXH 47, MFR Schedule D-2, p. 2) Staff agrees with witness Sullivan that the 0.21 percent fee used by witness Woolridge is incorrectly based on 2009 amounts. (TR 4163, EXH 47, MFR Schedule D-2, p. 2)
CONCLUSION
Staff believes the record supports a cost rate for short-term debt of 3.72 percent for the projected 2010 test year. To arrive at its recommended cost rate, staff utilized the same methodology as PEF and OPC but used different inputs in its computation. Staff used an estimated three-month LIBOR rate of 1.12 percent and added an assumed CP yield spread of 1.85 percent to arrive at the projected CP borrowing rate of 2.97 percent. Staff added 75 basis points for the cost of credit facility fees to the CP borrowing rate of 2.97 percent for a total cost rate for short-term debt of 3.72 percent. Accordingly, staff recommends that the appropriate cost rate for short-term debt for the projected 2010 test year is 3.72 percent.
What is the appropriate cost rate for long-term debt for the projected test year?
Recommendation:
The appropriate cost rate for long-term debt for the projected 2010 test year is 6.18 percent. (D. Buys)
Position of the Parties:
PEF:
The appropriate cost rate for long-term debt is 6.42% as presented in MFR D-4a.
OPC:
6.05%.
AFFIRM:
No position.
AG:
Support OPC’s position.
FIPUG:
The appropriate cost rate for long-term debt for the projected test year is 6.05%.
FRF:
6.05%.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
PEF asserted that its projected cost rate for long-term debt of 6.42 percent reflects expected future interest rates for a mix of ten-year and thirty-year bonds. (PEF BR 62) PEF argued that its projected cost rate is reasonable because interest rates are expected to increase in the future and PEF has historically issued a mix of ten-year and thirty-year bonds. (PEF BR 62)
OPC proposed a cost rate for long-term debt of 6.05 percent. (OPC BR 50) OPC witness Woolridge asserted that PEF’s cost rate for long-term debt includes a projected ten-year bond issue on March 1, 2010 at a coupon rate of 6.98 percent. (OPC BR 50; TR 2965; MFR Schedule D-4a) OPC Witness Woolridge testified that the current yields on ten-year, A and BBB+ rated utility bonds are 5.19 percent and 5.60 percent, respectively. (TR 2965) He argued that PEF’s projected bond yield of 6.98 percent is not reflective of current market interest rates. (OPC BR 50; TR 2965) In his testimony, witness Woolridge stated that he used PEF’s 2009 projected long-term debt cost rate of 6.05 percent in his cost of capital for PEF. (TR 2965)
PEF Witness Sullivan disagreed with witness Woolridge’s recommended cost rate for long-term debt of 6.05 percent. (TR 5154) Witness Sullivan argued that witness Woolridge chose to use the overall embedded long-term debt cost rate for 2009 as the long-term debt cost rate for 2010. (PEF BR 61; TR 5154) Witness Sullivan asserted that PEF currently has a $300 million first mortgage bond with an interest rate of 4.50 percent that matures on June 1, 2010. (TR 5154) Witness Sullivan argued that in order for the 2010 long-term debt cost rate to remain at the 2009 embedded cost rate of 6.05 percent, the new $750 million bond required in 2010 would have to be issued at a rate of 4.30 percent. (PEF BR 62; TR 5154) He maintained that PEF’s projected yield is based on expected future market interest rates, not current interest rates. (Sullivan TR 5154) Witness Sullivan argued that the yields on ten-year and thirty-year U.S. Treasury notes/bonds are expected to increase to well over 4.00 percent and 5.00 percent, respectively, in 2010. (TR 5154-5155) Witness Sullivan argued that using only current ten-year bond rates as a proxy for rates in the future leads to unrealistically low new debt issuance cost assumptions for 2010. (TR 4155)
ANALYSIS
The disagreement between the parties centers on the difference between the parties’ estimated coupon rate on PEF’s projected issuance of a new $750 million ten-year bond on March 1, 2010. (Woolridge TR 3036; EXH 47, MFR Schedule D-4a) PEF based its estimate on forecasted ten-year and thirty-year U.S. Treasury yields and the estimated spreads above those yields. (EXH 39, BSP 1445) PEF used the ten-year bond in its financial forecast and based its estimated interest rate on the average coupon rate on ten-year and thirty-year bonds. (EXH 39, BSP 1445) PEF used the average of the coupon rates for a ten-year issuance of 6.63 percent and a thirty-year issuance of 7.33 percent. (EXH 39, BSP 1445) PEF based its estimate of the ten-year coupon rate on an estimated spread of 197 basis points above a forecasted U.S. Treasury yield of 4.66 percent. (EXH 39, BSP 1445) PEF based its estimate of the thirty-year coupon rate on an estimated spread of 207 basis points above a forecasted thirty-year U.S. Treasury yield of 5.26 percent. (EXH 39, BSP 1445) PEF’s 6.98 percent interest rate was originally calculated in June 2008. (EXH 39, BSP 1445) PEF believes a blended coupon rate of 6.98 percent in 2010 is still a reasonable estimate given the continued uncertainty in the market and volatility in U.S. Treasury yields and credit spreads. (EXH 39, BSP 1445)
Staff believes that PEF’s methodology to average the ten-year and thirty-year estimated bond yields to arrive at its estimate for the coupon rate of 6.98 percent is unreasonable. PEF’s projected bond issuance on March 1, 2010 has a life of ten years. (EXH 47, MFR Schedule D4a) Staff believes it is more appropriate to use an estimated coupon rate that matches the life of the bond. Staff agrees with OPC that PEF’s projected yield of 6.98 percent is not reflective of current market interest rates. (Woolridge TR 2695) However, OPC did not provide testimony demonstrating what PEF’s embedded cost of long-term debt would be using its proposed coupon rate of about 5.50 percent. (Woolridge TR 3036) Conversely, staff agrees with PEF that using only current ten-year bond rates as a proxy for rates in 2010 leads to unrealistically low yield estimates. (Sullivan TR 4155)
Staff believes the record reflects that 5.64 percent is the most reasonable estimate for the coupon rate of PEF’s projected issuance of a new $750 million bond on March 1, 2010. The ten-year U.S. Treasury forward curve from Bloomberg forecasts that the yield on ten-year U.S. Treasury bonds will be 3.67 percent on February 22, 2010. (EXH 39, BSP 1472-1473) Adding PEF’s estimated spread of 197 basis points for a ten-year bond to the forecasted ten-year U.S. Treasury bond yield of 3.67 percent results in an estimated coupon rate of 5.64 percent. The estimated interest rate of 5.64 percent is also in line with OPC’s estimated interest rate. In his testimony, witness Woolridge provided a chart showing the yields on ten-year, A and BBB+ rated utility bonds. (EXH 158) The current yield is 5.6 percent for BBB+ rated utility bonds. (Woolridge TR 2965; EXH 158) PEF’s current S&P credit rating for its senior unsecured long-term debt is BBB+. (Sullivan TR 1232)
To calculate the appropriate embedded cost of long-term debt, staff made an adjustment to MFR Schedule D-4a. Staff substituted PEF’s estimated coupon rate of 6.98 percent with staff’s recommended coupon rate of 5.64 percent on line 15 in MFR Schedule D-4a. The result reduced the interest expense for the new issuance to $32,538,000 for the projected test year. The lower interest expense reduced the embedded cost of long-term debt from 6.42 percent to 6.18 percent.
CONCLUSION
Staff believes the record reflects that the most reasonable estimate of the coupon rate for PEF’s projected issuance of a new $750 million bond on March 1, 2010, is 5.64 percent. Hence, the appropriate embedded cost rate for long-term debt for the projected test year is 6.18 percent.
What is the appropriate return on equity (ROE) for the projected test year?
Recommendation:
The appropriate return on equity for the 2010 projected test year is 11.25 percent with a range of plus or minus 100 basis points. (Maurey)
Position of the Parties
PEF:
The appropriate return on equity for the projected test year is 12.54%.
OPC:
9.75%.
AFFIRM:
No position.
AG:
9.75%, as explained by Dr. Woolridge.
FIPUG:
The appropriate ROE should be no higher than 9.75%.
FRF:
9.75%.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
INTRODUCTION
Two witnesses testified in this proceeding regarding the appropriate return on equity (ROE) for PEF. PEF witness Vander Weide recommended an ROE of 12.54 percent. (TR 1362; PEF BR 82; OPC BR 54; FIPUG BR 29; FRF BR 14) OPC witness Woolridge recommended an ROE of 9.75 percent. (TR 2998; PEF BR 80; OPC BR 51; FIPUG BR 28; FRF BR 20) As expressly stated in the 2005 Stipulation, PEF does not currently have an authorized ROE.[42] However, for purposes other than reporting or assessing earnings (such as cost recovery clauses or AFUDC), the 2005 Stipulation provided for PEF to use an ROE of 11.75 percent. (FRF BR 17)
The statutory principles for determining the appropriate rate of return for a regulated utility are set forth by the U.S. Supreme Court in its Hope and Bluefield decisions.[43] (PEF BR 74; FRF BR 17–18) These decisions define the fair and reasonable standards for determining rate of return for regulated enterprises. Namely, these decisions hold that the authorized return for a public utility should be commensurate with returns on investments in other companies of comparable risk, sufficient to maintain the financial integrity of the company, and sufficient to maintain its ability to attract capital under reasonable terms. (TR 1320–1321; 3040–3041; PEF BR 74; FRF BR 17–18)
While the logic of the legal and economic concepts of a fair rate of return are fairly straight forward, the actual implementation of these concepts is controversial. Unlike the cost rate on debt that is fixed and known due to its contractual terms, the cost of equity is a forward-looking concept and must be estimated. (TR 1322, 2971–2972; PEF BR 75) Financial models have been developed to estimate the investor-required ROE for a company. (TR 1318, 2966) Market-based approaches such as the Discounted Cash Flow (DCF) model, Capital Asset Pricing Model (CAPM), and ex ante Risk Premium (RP) model are generally recognized as being consistent with the market-based standards of a fair return enunciated in the Hope and Bluefield decisions. (TR 1333–1334, 2972–2973; PEF BR 75; FRF BR 15)
DISCOUNTED CASH FLOW MODEL
Both witnesses used the DCF model to estimate the investor-required ROE for PEF. Because PEF is a wholly-owned subsidiary of Progress Energy, its common stock is not publicly traded. (TR 1311) To apply the model, each witness had to select a group of companies with publicly traded stock to serve as a proxy for PEF. (TR 1311–1312, 2956)
PEF witness Vander Weide
To select his group of comparable companies, PEF witness Vander Weide started with all electric utilities followed by Value Line Investment Survey (Value Line). (TR 1344) From this initial sample, he removed all companies that were actively involved in a merger, had reduced or eliminated its dividend in the last two years, or had not paid a dividend in every quarter of the last two years. He further narrowed his proxy group by including only the companies with an investment grade bond rating; a Value Line Safety Rank of 1, 2, or 3; and had at least three analyst projections included in the I/B/E/S earnings growth forecast. (TR 1334–1335) Based on this selection criteria, witness Vander Weide identified a group of 24 companies in his direct testimony and a group of 32 companies in his rebuttal testimony that he testified represented “a reasonable proxy for the risk of investing in PEF.” (TR 2358; EXH 98; EXH 248)
Witness Vander Weide used the quarterly DCF model. (TR 1337) In his direct testimony, he relied on stock prices for the three month period ended November 2008 and in his rebuttal testimony he relied on stock prices for the three month period ended July 2009. (EXH 98; EXH 248) All stock prices were as reported by Thomson Reuters. (TR 1342) He derived the estimated quarterly dividends based on past dividends as reported by Value Line. (EXH 98) In his direct testimony, he relied on five year forecasts of earnings per share (EPS) growth rates from I/B/E/S as of November 2008 and in his rebuttal testimony he relied on EPS growth rates as of July 2009. (TR 1339; EXH 98; EXH 248) His DCF model included a five percent adjustment for flotation costs. (TR 1342)
The result of witness Vander Weide’s DCF model based on data as of November 2008 indicated a market-weighted average cost of equity of 12.3 percent. (EXH 98) The result of his DCF model based on data as of July 2009 indicated a market-weighted average cost of equity of 11.5 percent. (EXH 248)
OPC witness Woolridge
To select his group of comparable companies, OPC witness Woolridge started with all electric utilities followed by Value Line and AUS Utility Reports. (TR 2956) From this initial sample, he removed all companies that did not have an investment grade bond rating from Moody’s and/or S&P, and a three year history of paying dividends. (TR 2956) He further narrowed his proxy group by focusing on companies with operating revenues less than $15 billion and that generate at least 75 percent of their operating revenues from regulated electric operations. (TR 2956) Based on this selection criteria, witness Woolridge identified a group of 15 comparable companies for use in his analysis. (TR 2956)
Witness Woolridge used the annual DCF model. (EXH 163) He relied on dividend yields for the six month period ended July 2009 and for the month of July 2009 as reported by AUS Utility Reports. (TR 2977) He relied on Value Line’s historical and projected growth rate estimates for EPS, dividends per share (DPS), and book value per share (BVPS). In addition, he used the average EPS growth rate forecasts from Yahoo First Call, Zacks, and Reuters and the expected growth rate as measured by the earnings retention method. (TR 2978–2979) Witness Woolridge’s DCF analysis did not include an adjustment for flotation costs. In addition to applying the DCF model to his own proxy group, witness Woolridge also applied his model to the proxy group identified in witness Vander Weide’s direct testimony. (TR 2982) The indicated return from witness Woolridge’s DCF analysis is 10.3 percent when applied to his proxy group and 10.5 percent when applied to witness Vander Weide’s proxy group. (TR 2983)
Rebuttal
Each witness filed testimony challenging the reasonableness of certain aspects of the other witness’ DCF analysis. (TR 2361–2381; 3003–3013) Both witnesses used generally accepted versions of the DCF model, similar estimates of the dividend yields, and relatively comparable proxy groups from a risk perspective. (TR 1386, 2957) The primary reason for the difference in indicated returns between the two witnesses’ DCF analyses is their respective estimates of the growth rate to include in the DCF model. (TR 1339–1341; 2978–2979)
PEF witness Vander Weide used five year forecasts of analyst estimates of future EPS growth as reported by I/B/E/S in his DCF analysis. (TR 1339) The average growth rate included in witness Vander Weide’s DCF model was 7.3 percent. (TR 3006) He testified that he relied exclusively on analyst forecasts of EPS growth to estimate the investor-expected growth rate in the DCF model because there is empirical evidence that investors rely on analysts’ forecasts to estimate future earnings growth. (TR 1340)
OPC witness Woolridge used historical and projected growth rate estimates for EPS, DPS, and BVPS from Value Line; analyst EPS growth rates from Yahoo First Call, Zacks, and Reuters; and an estimate of the sustainable growth rate to develop the growth rate estimate used in his DCF analysis. (TR 2978–2979) The average growth rate included in witness Woolridge’s DCF model was 4.75 percent. (TR 2983) He testified that he did not rely exclusively on EPS forecasts because the appropriate growth rate in the DCF model is the dividend growth rate, not the EPS growth rate, and because evidence indicates Wall Street security analyst EPS forecasts are overly optimistic and upwardly biased. (TR 2980) Witness Woolridge acknowledged that over the long-run, dividend and earnings will grow at a similar growth rate. (TR 2980) He also testified that investors presumably will use some combination of historical and/or projected growth rates for earnings and dividends in their analyses. (TR 2978) For these reasons, witness Woolridge relied on a number of measures for growth in his DCF analysis, not just EPS growth rates. (TR 2978)
Relative to the impact the growth rate used in a DCF analysis has on the indicated return, the other differences between the two witnesses’ application of the DCF model are rather modest in comparison. The incremental difference in indicated returns between a quarterly DCF model and an annual DCF model is approximately 17 basis points. (EXH 40, BSP 1502) The incremental difference in indicated returns between a DCF analysis with an adjustment for flotation costs and a DCF model without this adjustment is approximately 25 basis points. (TR 1355) Any difference related to which witness’ electric utility proxy group is more comparable to PEF was not considered to be meaningful in this case. (TR 3035) As a result, the decision regarding which DCF result is more indicative of investors’ required return for an investment in PEF comes down to which witness’ estimate of growth is believed to be more appropriate.
CAPITAL ASSET PRICING MODEL
Both witnesses relied on the CAPM approach to estimate the investor-required ROE for PEF. For the reason discussed earlier, the witnesses used their respective proxy groups for certain inputs to their CAPM analyses.
PEF witness Vander Weide
PEF witness Vander Weide performed both an ex ante and an ex post CAPM analysis. (TR 1357) For his estimate of the risk-free rate, he used the forecasted yield on 10-year and 30-year U.S. Treasury bonds as published by Blue Chip Financial Forecast (Blue Chip) to derive the forecasted yield on 20-year U.S. Treasury bonds of 4.87 percent used in his analysis. (TR 1355–1356) For the estimate of the company-specific risk, or beta, he used the average Value Line beta for his group of proxy companies of .79. (TR 1356) He derived a risk premium of 8.83 percent for use in his ex ante, or DCF-based, CAPM analysis and a risk premium of 7.10 percent for use in his ex post, or historical, CAPM analysis. (EXH 103, EXH 104) Witness Vander Weide’s analysis indicated a return of 11.8 percent based on his ex ante CAPM approach and a return of 10.7 percent based on his ex post CAPM approach. (TR 1357)
OPC witness Woolridge
OPC witness Woolridge performed an ex ante CAPM analysis. (TR 2990) For the risk-free rate, he used an estimate of the forward-looking yield on 30-year U.S. Treasury bonds of 4.50 percent. (TR 2985–2986; EXH 164) For beta, he used the average Value Line beta for his group of proxy companies of .70. (TR 2986) He determined an expected risk premium of 4.37 percent based on the results of various studies of historical risk premium, ex ante risk premium studies, and equity risk premium surveys. (TR 2987–2997) Witness Woolridge’s CAPM analysis indicated an ROE of 7.6 percent. (TR 2997)
Rebuttal
Each witness filed testimony challenging the reasonableness of certain aspects of the other witness’ CAPM analysis. (TR 2381–2386, 3027–3030) Both witnesses used relatively similar betas (.79 and .70). (TR 1356, 2986) While their respective estimates of the risk-free rate are not that similar (4.87 percent and 4.50 percent, respectively), the primary reason for the difference in their indicated CAPM results is the significant difference between their respective risk premium estimates. (TR 2997; EXH 103, EXH 104)
Witness Vander Weide testified that the average yield on Moody’s Baa-rated utility bonds over the last year was 7.72 percent. (TR 2382) Since an investment in a company’s equity is more risky than an investment in its bonds, a company’s cost of equity should be higher than its cost of debt. (TR 2382) Because witness Woolridge’s CAPM estimate of 7.6 percent is less than the average yield on Baa-rated utility bonds, witness Vander Weide testified that witness Woolridge’s CAPM result is below a reasonable range of estimates of PEF’s cost of equity. (TR 2381)
Witness Woolridge testified that witness Vander Weide’s CAPM results are unreasonable because the risk-free rate and risk premiums witness Vander Weide used in his analysis are overstated. (TR 3037) As noted above, witness Vander Weide used a risk-free rate of 4.87 percent. Witness Woolridge testified that the current risk-free rate is approximately 4.00 percent. (TR 3037) In addition, witness Woolridge testified that witness Vander Weide’s risk premiums of 7.10 and 8.83 percent are inflated and excessive. (TR 3003, 3030) For these reasons, witness Woolridge testified that witness Vander Weide’s CAPM results are above a reasonable range of estimates of PEF’s cost of equity. (TR 2947–2948)
While each witness disagreed with the other witnesses’ approach to performing the CAPM analysis, they both agreed that under current market conditions the CAPM produced less reliable cost of equity results for electric utilities at this time. (TR 2383) Witness Vander Weide testified that due to the efforts of the U.S. Treasury to keep interest rates low, the spread between the risk-free rate and the interest rate on public utility debt has increased. (TR 2383) Because the CAPM relates the cost of equity to the yield on government securities, and yields on government securities are abnormally low due to the U.S. Treasury’s efforts to stimulate the economy, he believes the CAPM approach understates the utility cost of equity. (TR 2383–2384) In his own analysis, witness Woolridge gave primary weight to his DCF analysis in determining his recommended ROE for PEF. (TR 2383, 2998)
RISK PREMIUM MODEL
In addition to the DCF and CAPM analyses, PEF witness Vander Weide also performed two versions of the RP analysis. (TR 1347) In his ex ante RP method, he applied his DCF model to the Moody’s Index of electric companies. (TR 1348; EXH 99, EXH 109) He compared the results of this DCF analysis to the concurrent interest rate on Moody’s A-rated bonds. (TR 1348; EXH 99, EXH 109) This comparison indicated an estimated risk premium of 4.9 percent. (TR 1349) He derived a forecasted yield to maturity on A-rated utility bonds of 6.3 percent based on information from the December 2008 Blue Chip. Based on this approach, witness Vander Weide’s ex ante RP model indicated an ROE of 11.2 percent. (TR 1349)
In his ex post RP method, witness Vander Weide relied on historical, earned returns for the S&P 500 stock portfolio and the S&P Utilities stock portfolio for the period 1937 – 2008. (TR 1349) The average annual return on an investment in the S&P 500 stock portfolio is 11.4 percent and the average annual return on an investment in the S&P Utilities stock portfolio is 11.0 percent. (TR 1350) The average annual return on an investment in the Moody’s A-rated utility bond portfolio was 6.4 percent. (TR 1350) Thus, he concluded that the risk premium on the S&P 500 index is 5.0 percent and on the S&P Utility index is 4.6 percent. (TR 1350) He used the average of these two risk premiums, or 4.8 percent, as his estimate of the risk premium in this approach. (TR 1351) Adding the 4.8 percent risk premium to the forecasted interest rate on Moody’s A-rated bonds of 6.3 percent discussed earlier, he obtained an indicated ROE of 11.1 percent. (TR 1355) Adding 25 basis points for flotation costs, witness Vander Weide obtained an estimate of 11.4 percent as the cost of equity for PEF using the ex post risk premium method. (TR 1355)
OPC witness Woolridge testified that there are a number of errors in PEF witness Vander Weide’s RP analyses. (TR 3017) Witness Woolridge testified that witness Vander Weide’s ex ante RP result is overstated due to an inflated base interest rate and an excessive risk premium. (TR 3017) He testified that the current yield on long-term, A-rated utility bonds is less than 6.0 percent, well below the 6.3 percent assumed in witness Vander Weide’s analysis. (TR 3017) In addition, witness Woolridge testified that witness Vander Weide’s ex ante, or DCF-based, RP method suffers from the same deficiencies discussed earlier in the section on the stand-alone DCF model. Because witness Vander Weide’s DCF component to this approach relied exclusively on EPS growth and thus overstated investor-required returns, witness Woolridge testified that this approach produced upwardly biased results. (TR 3018)
Witness Woolridge testified that witness Vander Weide ex post RP method suffered from similar flaws. (TR 3017) The issue related to the base interest rate was discussed above. In addition, witness Woolridge testified that witness Vander Weide’s ex post risk premium is excessive because he relied on historical, earned returns to estimate the forward-looking market risk premium. (TR 3019) Witness Woolridge noted the numerous academic studies and other empirical evidence which demonstrate that using the historical relationship between stocks and bond returns to measure an ex ante risk premium is erroneous. (TR 3018–3028)
ADJUSTMENTS
In arriving at his recommended return of 12.54 percent for PEF, witness Vander Weide made two specific adjustments in his analysis. To allow for the recovery of flotation costs associated with the issuance of common equity, he made an adjustment to his DCF model and DCF-based CAPM and RP approaches that equates to 25 basis points. (TR 1343) For his non-DCF-based CAPM and RP approaches, he added 25 basis points to the indicated returns. (TR 1355) Witness Vander Weide testified that all firms that have sold securities in the capital markets have incurred some level of flotation costs, including underwriters’ commissions, legal fees, printing costs, etc. (TR 1342) He stated that these costs range between three and five percent of the proceeds of an equity issuance. (TR 1343) In addition to these costs, for large equity issuances, there can be a decline in the price of the shares. On average, he said that the decline due to market pressure has been from two to three percent of the proceeds. (TR 1343) Thus, total flotation costs, including both issuance expense and market pressure, could range from five to eight percent of the proceeds of an equity issuance. (TR 1343) For this reason, witness Vander Weide believed a five percent allowance for flotation costs was a conservative estimate that should be recognized in the determination of the ROE. (TR 1343)
OPC witness Woolridge testified that it is not necessary to make an upward adjustment to the cost of equity for the recovery of flotation costs. (TR 3014) He stated that PEF has not identified any actual flotation costs for the Company. (TR 3014) In addition, because electric utilities have market-to-book ratios in excess of 1.0x, he testified that there should be a flotation cost reduction (and not increase) to the equity cost rate. (TR 3014) Finally, he argued that investors also incur transaction costs when they purchase shares. If these transaction costs are taken into account, the price of shares would be higher. If witness Vander Weide had included these transaction costs in his DCF analysis, the higher effective stock prices paid for stocks would have led to lower dividend yields. This would have resulted in a downward adjustment to his DCF equity cost rate. (TR 3016) For these reasons, witness Woolridge testified that it is unnecessary to recognize a flotation cost adjustment in the determination of the investor-required ROE. (TR 3014–3016)
Based on his application of the various cost of equity models, witness Vander Weide concluded that the cost of equity for his proxy group was 11.5 percent. (TR 1359) However, because the average market value equity ratio of the companies in his proxy group exceeded the book value equity ratio of PEF that would be recognized for purposes of setting rates, he argued it was necessary to make a leverage adjustment to equate PEF’s weighted average cost of capital on a book value basis to the weighted average cost of capital for his proxy group on a market value basis. (TR 1361–1362, 2416; EXH 105) This adjustment equated to 104 basis points, and when added to his indicated return for the proxy group of 11.5 percent, produced the 12.54 percent ROE witness Vander Weide recommends is a fair rate of return on equity for PEF. (TR 1361, EXH 105)
OPC witness Woolridge testified that this leverage adjustment is unwarranted. (TR 3030) He testified that witness Vander Weide’s proposed adjustment inappropriately mixes book value and market value equity capitalization ratios. (TR 3031) He noted that financial publications, investment firms, and this Commission report and work with capitalization ratios on a book value basis, not a market value basis. (TR 3031) Moreover, to the extent that a company’s market value exceeds its book value, witness Wooldridge testified that this shows that the company is earning a return on equity in excess of its cost of equity. (TR 3031) Finally, witness Woolridge noted that witness Vander Weide could not identify any proceeding in which the regulatory commission had adopted his leverage adjustment. (TR 3031)
ANALYSIS
Based on a literal reading of the testimony in this proceeding, the record could support an authorized ROE within the range of 7.6 percent to 12.54 percent. (TR 1359, 2998) As noted earlier, the witnesses’ recommended returns suggest a range of 9.75 percent to 12.54 percent. (TR 1362, 2998) Based on a review of the testimony as well as the additional evidence presented in this proceeding, staff believes the record more strongly supports an ROE for PEF in the range of 10.3 percent to 11.5 percent. (TR 1359, 2368, 2683, 3003)
Both witnesses recognized that the generally accepted models used for estimating ROE are based on a number of restrictive assumptions. (TR 1322, 2972) Under normal economic circumstances, the relaxation of these assumptions for the practical application of these models is generally understood. (TR 1370–1371, 2966–2967) And while the state of the economy has improved since the market disruption in the fall of 2008, the economic recovery is still somewhat tenuous. (TR 1423–1427, 2953) This realization does not mean the models no longer have value, rather, it is particularly important at this point in time to exercise informed judgment in the application of the models. (TR 1322, 2351–2352, 3055)
Each witness argued that the other witness made certain assumptions in the application of their respective DCF analysis that either understated or overstated the investor-required ROE for PEF. (TR 2361–2381, 3003–3013) As discussed earlier, the majority of the differences between the two witnesses’ respective DCF approaches have only a marginal impact on the difference in the indicated returns. The primary reason for the difference in the witnesses’ DCF results relates to their respective estimates of the growth rate to include in the DCF model. (TR 1339–1341; 2978–2979) The results of the witnesses’ DCF analyses based on financial data as of July 2009 produced a range of 10.3 percent to 11.5 percent. (TR 2983; EXH 248) Recognizing that the top end of this range represents a DCF result based exclusively on EPS growth forecasts, staff believes this is a conservatively high estimate of the investor-required return.
Each witness argued that the other witness made certain assumptions in the application of their respective CAPM approaches that either understated or overstated the investor-required ROE for PEF. (TR 2381–2386, 3027–3030) However, recognizing the impact the Federal Government’s unprecedented intervention in the capital markets has had on the yields on long-term Treasury bonds, staff believes models that relate the investor-required return on equity to the yield on government securities, such as the CAPM approach, produce less reliable estimates of the ROE at this time.
Due to the academic studies and other empirical research documenting that RP models based on historical earned returns are poor predictors of current market expectations, staff has reservations regarding the reliability of the results of witness Vander Weide’s ex post RP model. (TR 2947, 3018–3028) While witness Woolridge also expressed concerns regarding the results of witness Vander Weide’s ex ante RP model as well, staff notes that witness Vander Weide’s ex ante risk premium of 4.9 percent is not significantly greater than witness Woolridge’s ex ante risk premium of 4.4 percent. (TR 1349, 2997)
Both witnesses made persuasive arguments for including and not including an allowance for the recovery of flotation costs in the determination of the ROE. While it has been the Commission’s practice to recognize an adjustment for flotation costs in certain applications, the determination of an authorized ROE by a regulatory commission in an evidentiary proceeding very seldom involves the level of specificity that would permit the itemization of a specific allowance for flotation costs. 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 blended growth rate or an earnings-only growth rate in the DCF analysis. Staff’s recommended ROE does not specifically recognize or exclude an allowance for flotation costs but rather represents a blend of the results of the witnesses’ analyses, some that include and others that do not include an adjustment for flotation costs.
Staff does not believe witness Vander Weide’s proposed 104 basis point leverage adjustment to his estimated equity cost rate is appropriate. (TR 1361; EXH 105) While the logic of the leverage adjustment proposed by witness Vander Weide is sound, the inappropriate mixing of market value and book value capitalization ratios in the formula is a fatal flaw. (TR 3031) Witness Vander Weide testified that PEF’s ratemaking capital structure contained an appropriate mix of debt and equity and was an appropriate capital structure for ratemaking purposes. (TR 1360) In addition, he was afforded multiple opportunities to make a comparison of PEF’s ratemaking capital structure to the equivalent capital structures of the investor-owned utilities (IOUs) of the companies in his proxy group but declined to do so. (TR 1396–1399; 1456–1457; EXH 40, BSP 1492) Finally, even though he testified that he has been including this leverage adjustment in ROE testimony since the early 1990’s, witness Vander Weide was unable to identify any Commission decision involving an electric utility that had recognized this adjustment. (TR 1368, 3031)
Due to the reliance on historical earned returns to estimate the current risk premium in the ex post CAPM and RP models, concerns over the exclusive reliance on EPS growth rates in the DCF analyses, and the decision to recognize an inappropriately quantified leverage adjustment, staff believes the Company’s requested ROE of 12.54 percent overstates the current investor-required ROE for PEF. (TR 2978–2979, 3003, 3017–3019, 3030) Conversely, recognizing that the marginal cost of long-term, single A-rated utility bonds is near 6.0 percent, staff believes returns in the single digits as recommended by the Intervenors may understate the investor-required ROE in the current market. (TR 1350, 2997, 3017)
Finally, Exhibit 264 reports the authorized ROEs set during 2009 for the electric utilities followed by Regulatory Research Associates (RRA). (EXH 264) The ROEs set during 2009 ranged from a low of 8.75 percent to a high of 11.5 percent and averaged 10.51 percent for the group. (EXH 264) While staff does not believe the authorized ROE for PEF should be based upon the average return set by Commissions during 2009, staff does not believe recommended returns significantly above or below this level are indicative of the investor-required return for PEF, either.
CONCLUSION
Staff recommends an authorized ROE of 11.25 percent with a range of plus or minus 100 basis points. In arriving at this return, staff has weighed the identified strengths and weaknesses associated with the respective witness’ analyses. Staff has also taken into account PEF’s proposed construction program and its need to access the capital markets under reasonable terms. In addition, staff considered the equity ratio recommended in Issue 42. Staff believes, at an equity ratio of approximately 50 percent, an authorized ROE of 11.25% 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 projected capital structure?
Recommendation:
The appropriate weighted average cost of capital for the projected 2010 test year is 8.23 percent, as shown on Schedule 2. (Davis)
Position of the Parties
PEF:
The appropriate weighted average cost of capital is 9.210% as calculated in MFR D-1a.
OPC:
7.48%. See Exhibit 170 page 1.
AFFIRM:
No position.
AG:
Concur with OPC’s position as explained by Dr. Woolridge.
FIPUG:
The appropriate weighted average cost of capital including the proper components, amounts and costs rates associated with the projected capital structure is 7.48%.
FRF:
7.33%.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES ARGUMENTS
Since this issue is the culmination of many expert witnesses’ input and the staff analysis referred to in other issues, please refer to the parties arguments in Issues 39-47.
ANALYSIS
The weighted average cost of capital is dependent upon many other issues, including but not limited to, Issue 39 regarding the accumulated deferred income taxes, Issue 40 – unamortized investment tax credit, Issue 41 – imputed equity adjustment for purchased power obligations, Issue 42 – equity ratio, Issue 43 – reconciliation of rate base to capital structure, Issue 44 – jurisdictional capital structure, Issue 45 – cost rate for short-term debt, Issue 46 – cost rate for long-term debt, and Issue 47 the appropriate return on equity. If the Commission agrees with the staff recommendations on these issues, the weighted average cost of capital would be 8.23 percent.
The net effect of these adjustments is a decrease in the overall cost of capital from the 9.21 percent return requested by PEF to a return of 8.23 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, staff recommends that the appropriate weighted average cost of capital for PEF for purposes of setting rates in this proceeding is 8.23 percent.
Is PEF's projected level of total operating revenues in the amount of $1,517,918,000 for the 2010 projected test year appropriate?
Recommendation:
No. The appropriate projected level of total operating revenues for the 2010 projected test year is $1,650,019,000. (Slemkewicz, A. Roberts)
Position of the Parties
PEF:
Yes. PEF’s requested level of operating revenues for 2010 of $1,517,918,000 is appropriate.
OPC:
Projected operating revenues should be adjusted by $8,646,274 as recommended by OPC witness Dismukes to correct for inadequate attribution of costs to the non regulated operations. Projected test year revenues should be at least $1,526,564,000.
AFFIRM:
No position.
AG:
Agree with OPC’s position.
FIPUG:
Projected operating revenues should be adjusted by $8,646,274.
FRF:
No.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
This is a fallout issue based on the resolution of other issues. Per Stipulated Issues 3, 4 and 5, there are no adjustments to PEF’s forecasts of customers, kWh, kw, inflation factors or billing determinants for the 2010 projected test year. However as discussed in Issue 88, revenues at current rates for the projected test year should be increased by $132,101,000 to account for the Bartow Repowering Project (BRP) base rate increase approved by the Commission in Order No. PSC-09-0415-PAA-EI.[44] Therefore, staff recommends that $1,650,019,000 is the appropriate projected level of total operating revenues for the 2010 projected test year. (See Schedule 3)
What are the appropriate adjustments to reflect the base rate increase for the Bartow Repowering Project authorized in Order No. PSC-09-0415-PAA -EI?
Recommendation:
Revenues at current rates for the projected test year should be adjusted as addressed in Issue 88. No adjustment is needed for proposed revenues since the revenue requirement amounts for the Bartow Repowering Project are included in the 2010 projected amounts. (Wright)
Position of the Parties
PEF:
The appropriate adjustment to reflect the base rate increase for the Bartow Repowering project would be to adjust present revenues to include the authorized increase. No adjustment should be made to the proposed revenues as they reflect the Company’s total cost of service including the revenue requirements for the Bartow repowering project in the 2010 test period.
OPC:
No position.
AFFIRM:
No position.
AG:
Agree with OPC’s position.
FIPUG:
No position.
FRF:
Agree with OPC.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
Issue 88 addresses the adjustment to reflect revenues at current rates for the projected 2010 test period related to the Bartow Repowering Project. The revenue requirements related to the Bartow Repowering Project are included in the 2010 projected amounts, therefore no adjustments to the proposed revenues are necessary.
No parties other than PEF took a position on this issue.
Has PEF made the appropriate test year adjustments to remove conservation revenues and expenses recoverable through the Conservation Cost Recovery Clause? (Category 2 Stipulation)
Approved Stipulation:
Yes.
Has PEF made the appropriate test year adjustments to remove fuel and purchased power revenues and expenses recoverable through the Fuel and Purchased Power Cost Recovery Clause? (Category 2 Stipulation)
Approved Stipulation:
Yes.
Has PEF made the appropriate test year adjustments to remove capacity revenues and expenses recoverable through the Capacity Cost Recovery Clause? (Category 2 Stipulation)
Approved Stipulation:
Yes.
Has PEF made the appropriate test year adjustments to remove environmental revenues and expenses recoverable through the Environmental Cost Recovery Clause? (Category 2 Stipulation)
Approved Stipulation:
Yes.
DROPPED.
Has PEF made the appropriate adjustments to remove Aviation cost for the test year?
Recommendation:
Yes. PEF has made the appropriate adjustments to remove aviation cost for the test year. (Marsh)
Position of the Parties
PEF:
Yes, PEF has appropriately removed aviation costs of $3,126,000 as reflected in MFR C-2.
OPC:
No position.
AFFIRM:
No position.
AG:
No position.
FIPUG:
No position.
FRF:
No position.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
PEF stated in its brief that it has appropriately removed aviation costs of $3,126,000 as reflected in MFR Schedule C-2. (PEF BR 13)
OPC, Affirm, AG, FRF, and the Navy did not address this issue in their briefs. FIPUG took no position on this issue. (FIPUG BR 30) PCS Phosphate agreed with and adopted the position of the OPC. (PCS BR 10)
ANALYSIS
PEF removed corporate aircraft costs in the amount of $3,126,000. (EXH 47, MFR Schedule C-2, p. 1 of 8) The jurisdictional amount, net of tax, is $1,921,000. (EXH 47, MFR Schedule C-3, p. 1 of 6) The explanation given by PEF is to exclude cost of corporate aircraft in order to comply with Commission guidelines. (EXH 47, MFR Schedule C-3, p. 2 of 6) PEF does not own any airplanes or helicopters. (EXH 45, BSP 2062)
No party addressed this issue. Since PEF does not own aircraft, and an adjustment has been made to remove all corporate aviation expense allocations, staff believes that all aviation costs have been removed.
CONCLUSION
Based on the above, staff recommends that PEF has made the appropriate adjustments to remove aviation cost for the test year.
Should an adjustment be made to advertising expenses?
Recommendation:
No. PEF has made the appropriate adjustments to remove advertising expenses for the test year. (Marsh)
Position of the Parties
PEF:
An adjustment has been appropriately made to remove image-building advertising expense in the amount of $3,388,000 as reflected in MFR C-2.
OPC:
No position.
AFFIRM:
No position.
AG:
No position.
FIPUG:
No position.
FRF:
No position.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
PEF stated in its brief that an adjustment has been properly made to remove image-building advertising expense in the amount of $3,388,000 as shown in MFR Schedule C-2. (PEF BR 14)
OPC, Affirm, AG, FRF, and the Navy did not address this issue in its brief. FIPUG took no position on this issue. (FIPUG BR 30) PCS Phosphate agreed with and adopted the position of the OPC. (PCS BR 10)
ANALYSIS
PEF removed promotional advertising costs in the amount of $3,388,000. (EXH 47, MFR Schedule C-2, p. 1 of 8, column 10, line 10) The jurisdictional amount, net of tax, is $2,081,000. (EXH 47, MFR Schedule C-3, p. 1 of 6, column 10, line 8) The explanation given by PEF is to exclude the cost of promotional advertising in order to comply with Commission guidelines. (EXH 47, MFR Schedule C-3, p. 2 of 6, line 11)
Staff notes an excerpt from the procedures followed by the staff auditors for the 2008 base year:
We reviewed additional samples of utility advertising expenses, industry dues, economic development expenses, outside services, sales expenses, customer service expenses and administrative and general service expenses to ensure that amounts supporting non-utility operations were removed. (EXH 208, p. 5)
The Company’s advertising expense is one of the areas specifically examined by the staff auditors. There were no findings with respect to this issue.
No party other than PEF addressed this issue. Staff believes that the adjustments made by PEF are appropriate.
CONCLUSION
Therefore, staff recommends that PEF has made the appropriate adjustments to remove advertising expenses for the test year.
DROPPED.
Is PEF's proposed allowance of $2,412,100 for directors and officers liability insurance appropriate?
Recommendation:
Yes. Directors and Officers (D&O) liability insurance is a necessary cost of doing business for a public-owned company and should be allowed. Staff recommends that no adjustment should be made. (Marsh)
Position of the Parties
PEF:
No. PEF provided the system amount of directors and officers (D&O) liability insurance in response to OPC Interrogatory No. 310 of $2,200,000.
OPC:
No. Directors and Officers Liability insurance expense should be disallowed it its entirety as those costs are incurred only for the protection and benefit of the shareholders who are ultimately responsible for hiring directors and officers.
AFFIRM:
No position.
AG:
No.
FIPUG:
No, this amount should be disallowed. Ratepayers should not be required to fund this expense which directly benefits only PEF’s shareholders.
FRF:
No.
NAVY:
No position.
PCS:
No position.
Staff Analysis:
PARTIES’ ARGUMENTS
PEF did not file testimony on this issue. However, PEF argued in its brief that OPC witness Shultz is incorrect in his assertion that D&O liability insurance does not benefit ratepayers, and thus should be disallowed. (PEF BR 113) PEF cited to the most recent TECO case in which this Commission decided that D&O liability insurance is a necessary and reasonable business expense and is appropriately included in customers’ rates.[45] (PEF BR 113) PEF stated that “the Commission has already rejected the argument that Mr. Shultz raises in other cases and there is no valid reason for the Commission to depart from its previous findings in this case.” (PEF BR 113)
OPC witness Shultz questioned whether the cost of D&O liability insurance is a necessary and appropriate expense to pass on to ratepayers. (TR 1953) He stated that the 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. (TR 1953) He noted that the Company included $2.2 million in Account 925 for D&O liability insurance, but he believes the correct amount to be $2,750,650 for $300,000,000 in coverage. (TR 1953) He disagreed with a recent Commission Peoples Gas case in which the expense was allowed as a legitimate business expense.[46] (TR 1953) The witness testified that the pertinent issue is whether the cost is beneficial to ratepayers, not whether it is a legitimate business expense. (TR 1954) He stated that the FPSC has disallowed the cost in the past. (TR 1954)
OPC witness Shultz testified that other jurisdictions have disallowed the expense. (TR 1955) He stated, for example, that a Connecticut decision limited recovery by Connecticut Light and Power to thirty percent, because “ratepayers should not be required to protect shareholders from the decisions they make in electing the Board of Directors.” (TR 1955) He added that Consolidated Edison was not allowed to recover the full amount in a New York case. He explained that the disallowance was due to excessive coverage in part, and that a portion of the amount found to be reasonable was also disallowed. He stated the reason for the additional disallowance was that D&O Liability insurance provides protection to shareholders from matters in which the customers have no influence. (TR 1955)
OPC witness Shultz recommended disallowance of the total cost of D&O liability insurance of $2,750,650 ($2,412,100 jurisdictional) because the purpose of the insurance is to protect shareholders, not ratepayers. (TR 1956) He stated that he does not take the position that the Company should not have the insurance, but that it should be paid for by those who benefit from the insurance; that is, the shareholders. (TR 1956-1957)
OPC argued that PEF did not offer any testimony in rebuttal to OPC witness Schultz that the D&O liability insurance should be disallowed. (OPC BR 56) OPC stated that, in each of the cases cited by witness Shultz in his testimony, the Company argued that D&O liability insurance is a necessary and prudent cost required to attract and retain competent directors and officers, yet a disallowance was made. (OPC BR 58) OPC challenged the cost for $300,000,000 of coverage as being excessive, and questioned whether the cost for that level of coverage is appropriate to pass on to ratepayers. (OPC BR 56)
OPC noted in particular a Consolidated Edison Company Case 08-E-0539. (OPC BR 57-58) OPC stated that, in the final decision the New York Commission (NYC) ruled that $300,000,000 of coverage was excessive based on the comparisons to similar companies and disallowed the premium associated with $100,000,000 excess and then disallowed 50 percent of the premium associated with the $200,000,000 that was determined to be reasonable. (OPC BR 58) OPC stated that, in the discussion, the NYC noted that D&O insurance provides substantial protection to shareholders who elect directors and have influence over whether competent directors and officers are in place, while customers have no influence. (OPC BR 58) OPC noted that the NYC further stated at page 91 of its order that:
We find no particularly good way to distinguish and quantify the benefits of D&O insurance to ratepayers from the benefits to shareholders, especially taking into account the advantage that shareholders have in control over directors and officers. We believe the fairest and most reasonable way to apportion the cost of D&O insurance therefore is to share it equally between ratepayers and shareholders.
(TR 1953-1955; EXH 298, p. 91; OPC BR 58)
Affirm and the Navy did not address this issue in their briefs. AG stated “no,” but did not address the issue further. (AG BR 11) FIPUG stated that the amount should be disallowed, because the expense directly benefits only PEF’s shareholders, but did not address the issue further. (FIPUG BR 30) FRF stated “no,” but did not address the issue further. (FRF BR 59) PCS Phosphate agreed with and adopted the position of OPC. (PCS BR 11)
ANALYSIS
Staff agrees with OPC witness Shultz that the Commission has disallowed D&O insurance in water and wastewater cases in the past.[47] Nevertheless, staff maintains that such insurance expense is a legitimate cost of doing business, consistent with electric and gas cases at this Commission.
Staff does not agree with OPC that the ratepayers do not benefit from D&O liability insurance. Staff believes that D&O liability insurance has become a necessary part of conducting business for any company or organization and it would be difficult for companies to attract and retain competent directors and officers with out it. Staff also believes that ratepayers receive benefits from being part of a large public company, such as easier access to capital which may result in lower rates. As stated in the TECO order:
We find that [D&O liability] insurance is a part of doing business for a publicly-owned Company. It is necessary to attract and retain competent directors and officers. Corporate surveys indicate that virtually all public entities maintain [D&O liability] insurance, including investor-owned electric utilities. . . . We do not agree with OPC that the ratepayers do not benefit from [D&O liability] insurance. It is not realistic to expect a large public company to operate effectively without [D&O liability] insurance.[48]
Staff agrees with PEF’s position in its brief that the amount of the D&O liability insurance provided in discovery responses is $2.2 million, not $2.75 million as adjusted by OPC witness Shultz. (EXH 45, BSP 2123-2124) Staff also notes that the amount of the premium for the test year is projected to be higher than the premium for 2008-2009, but lower than the previous three years, even though the amount of coverage was increased from $280 million to $300 million. (EXH 45, BSP 2123-2124)
In summary, staff believes that D&O liability insurance has become a necessary part of conducting business for any publicly owned company and it would be difficult for companies to attract and retain competent directors and officers without it. Staff also believes that ratepayers receive benefits from being part of a large public company including, among other things, easier access to capital.
CONCLUSION
Staff recommends that D&O liability insurance is a necessary cost of doing business for a public-owned company and should be allowed. Staff therefore recommends that no adjustment should be made.
Is PEF's proposed allowance of $3,669,000 for 2010 injuries and damages expense appropriate?
Recommendation:
No. Staff recommends a decrease of $4,778,603 jurisdictional ($5,020,063 system) for 2010 injuries and damages expense. (Marsh)
Position of the Parties
PEF:
No. PEF’s original filing includes injuries and damages (FERC Acct 925) of $9,821,000 on a system basis. In addition to injuries and damages, this account includes corporate insurance in the amount of $5,637,097. When removing the corporate insurance, the remaining injuries and damages budget in 2010 is $4,184,000 on a system basis and $3,699,000 on a jurisdictional basis (as noted in this issue). In response to OPC Interrogatory No. 386, PEF explained that $450,000 had been classified as “salaries and wages” that should have been classified as “injuries and damages”. When including this amount, total system injuries and damages is appropriately $4,634,000, and the jurisdictional amount is $4,064,000.
OPC:
No. Since it appears that the injuries and damages reserve expense is not supported by the record or the company’s efforts to justify it and the amount of $4,778,604 -- which includes dollars identified as related to both Injuries & Damages Expense and A&G Office Supplies & Expense -- should be disallowed.
AFFIRM:
No position.
AG:
No.
FIPUG:
No. This amount should be disallowed because it is not supported in PEF’s filing.
FRF:
No.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
PEF witness Toomey did not provide testimony on this point. However, he did explain in a discovery response that MFR Schedule B-21 is incorrect where it shows no injuries and damages expense for the test year. (EXH 45, BSP 2140)
PEF stated that FERC Account 925 on MFR Schedule C-4, p. 44 of 48, reflects an expense of $8,882,000 for injuries and expenses. (PEF BR 114) PEF stated that the numbers were audited by the Commission auditors who reconciled the amounts on the MFRs for 2008 expenses to the Company’s actual book and records. (PEF BR 114; EXH 208) PEF stated that it based its 2010 budget for injuries and damages expense on the Company’s actual historical 2008 expenses. (PEF BR 114) PEF argued that it is, therefore, entitled to recover this expense. (PEF BR 114)
PEF argued in its brief that injuries and damages expense has been recognized as a legitimate business expense in the Company’s rates in the past. (PEF BR 114) PEF noted that the Commission has previously recognized it as a legitimate business expense.[49] (PEF BR 114) PEF argued that “[t]here is no justification for the elimination of this expense in its entirety from the Company’s revenue requirements and Mr. Schultz provides none.” (PEF BR 114)
OPC witness Shultz testified that the Company’s request for injuries and damages expense is not supported by the record. (TR 1957) He stated that MFR Schedule B-21, p. 1 of 4, did not show an expense for injuries and damages. (TR 1957) He recommended an adjustment of $5,449,303 system or $4,778,603 jurisdictional. (TR 1957)
OPC witness Shultz stated that information provided by PEF showed that $2,694,313 was included in various budget centers, and another $1,700,000 was included in the legal department’s budget for injuries and damages. (TR 1957) He testified that this information is incorrect in that there are additional amounts. (TR 1957) He explained that the Company advised in response to discovery that an amount of $450,000 in salaries and wages in the nuclear budget should have been included in A&G Injuries and Damages. (TR 1958) He concluded that all of these amounts and errors together totaled $4,844,313 ($2,694,313 + $1,700,000 + $450,000) of injuries and damages in the projected test year. (TR 1958)
OPC witness Shultz testified that his analysis of the budget showed the costs included by the Company actually totaled $5,020,063, not $4,844,313. (TR 1958) He stated that he found $1,825,000 in the legal budget, plus another $50,750 for injuries and damages, as compared to the $1,700,000 pointed out by the Company, as discussed above. (TR 1958; EXH 34, BSP 967) The witness stated that the $1,825,000 was verified in the response to OPC POD No. 274. (TR 1958; EXH 34, BSP 965-968)
OPC witness Shultz testified that PEF failed to provide any justification for its 2010 injuries and damages costs. (TR 1958) He stated that the Company provided actual and budgeted costs for 2008 that showed a negative expense in 2008. (TR 1958) He stated that it “would not be appropriate for the Company to be allowed an expense in the projected test year when there was no expense in the base year 2008.” (TR 1958-1959) He noted that there was no testimony or justification for any amount in 2010. (TR 1959)
OPC stated in its brief that PEF did not offer any testimony either supporting the amount or rebutting Mr. Schultz’s testimony on this point. (OPC BR 59) OPC noted that the PEF witness for MFR Schedule B-21, witness Toomey, does not discuss injuries and damages in his testimony in this case. (OPC BR 59) OPC argued that the adjustment of $5,449,303 or $4,778,603 jurisdictional is warranted. (OPC BR 59; EXH 170, Schedule C-9)
Affirm and the Navy did not address this issue in their briefs. AG stated “no” but did not address the issue further. (AG BR 11) FIPUG stated that the amount should be disallowed because it is not supported in PEF’s filing, but did not address the issue further. (FIPUG BR 30) FRF stated “no” but did not address the issue further. (FRF BR 59) PCS Phosphate agreed with and adopted the position of OPC. (PCS BR 11)
ANALYSIS
Staff agrees with PEF that injuries and damages expense is a legitimate business expense. The issue here is whether the costs have been properly supported in the record and whether the Company will actually incur the amount of expense it has requested.
PEF stated that the numbers for this account were audited by the Commission auditors who reconciled the amounts on the MFRs for 2008 expenses to the Company’s actual book and records. (PEF BR 114; EXH 208) Staff has not found any specific information from the staff audit report that supports the numbers for this account. Staff notes the following excerpt from the procedures followed by the staff auditors for the 2008 base year:
We verified, based on a sample of utility transactions for select O&M expense accounts, that utility O&M expense balances are adequately supported by source documentation, prudent, utility in nature and do not include non-utility items.
We reviewed additional samples of utility advertising expenses, industry dues, economic development expenses, outside services, sales expenses, customer service expenses and administrative and general service expenses to ensure that amounts supporting non-utility operations were removed.
(EXH 208, p. 5)
Although certain specific accounts were sampled, as noted above, there is no indication that the injuries and damages account was separated out for specific examination. The audit is based on samples. There is no information in the record from the staff audit that supports the Company’s 2008 number on which its 2010 request is based.
PEF showed an amount for Injuries and Damages expense in Account 925 in its MFRs of $9,821,000 system, $8,612,000 jurisdictional for the 2010 test year. (EXH 47, MFR Schedule C-4, p. 12 of 48) However, the amount is not properly reflected in MFR Schedule B-21, where it should be shown as an expensed amount in the right hand column, as noted by OPC witness Shultz. That column shows a zero amount. (EXH 47, MFR Schedule B-21, p. 1 of 4) Staff believes the Company’s response is correct that this is an error. (EXH 45, BSP 2140) Staff does not believe the error is a reason to disallow the expense.
In addition to the 2010 amount above, the Company showed a system amount of $8,882,000 ($8,142,000 jurisdictional) for 2008 in Account 925, and $9,942,000 system ($9,114,000 jurisdictional) for 2009. (EXH 47, MFR Schedule C-4, pp. 44, and 28 of 48) Compared to 2008 and 2009, staff believes the 2010 amount appears reasonable. However, the numbers for all three years are unsupported. OPC witness Shultz disagreed that this is the actual amount of expense for 2008, due to a credit of $836,977 from the Energy Delivery Department. (EXH 170, Schedule C-9) Further, when the insurance cost for 2008 was removed from the account, witness Shultz determined that the amount of injuries and damages expense for 2008 was a negative $429,420. (EXH 170, Schedule C-9) Without the Energy Delivery credit, the expense less insurance would have been only $489,697 for 2008, as calculated by staff using witness Shultz’s schedules. There is no record evidence to support the large increase for 2010 over the 2008 amounts.
Staff agrees with OPC witness Shultz that the amount of injuries and damages expense included in PEF’s filing is actually $10,657,160 when the errors are corrected. (EXH 170, Schedule C-9) Of that amount $5,637,097 is for insurance, as compared to insurance costs of $5,878,629 for 2008. (EXH 170, Schedule C-9) The total expense less insurance is $5,020,063. ($10,657,160 – $5,637,097 = $5,020,063) The numbers are unrebutted.
PEF noted that $450,000 was classified as salaries and wages that should have been classified as injuries and damages expense, as discussed in Issue 63. Staff notes that this amount was included as part of OPC witness Shultz's adjustment and does not need to be addressed separately.
PEF has not justified its request for injuries and damages expense. Although such expense is a legitimate business expense, the large increase over 2008 was not explained. The amount requested for 2010 less insurance is $5,020,063, as compared to actual expense for 2008 of ($429,240). As previously noted, even if the credits were removed for 2008, the actual expense excluding insurance would have been $489,697. The adjustment recommended by OPC witness Shultz allows the Company the full amount PEF requested for insurance, but removes all additional amounts. The adjustment is greater than the amount initially requested by PEF, due to the correction of several errors as previously discussed. Staff believes OPC’s adjustment is appropriate given the lack of support for PEF’s request and the large unexplained increase.
CONCLUSION
Staff recommends a decrease of $4,778,603 jurisdictional ($5,020,063 system) or for 2010 injuries and damages expense.
Is PEF's proposed allowance of $23,228,000 for 2010 A&G office supplies and expenses appropriate?
Recommendation:
No. The 2010 A&G Office Supplies and Expenses should be reduced by $1,298,435 jurisdictional ($1,480,677 system). (Marsh)
Position of the Parties
PEF:
No. As explained in response to OPC Interrogatory No. 386, PEF budgeted $1,208,000 to Salaries and Wages that should have been budgeted to A&G Office Supplies and Expense by $1,319,000. MFR C-4, page 12 shows system A&G office supplies and expense as $26,783,000. With these adjustments, the appropriate amount of A&G Office Supplies and Expense on a system basis is $26,672,000 and the jurisdictional amount is $23,130,000.
OPC:
No. $2,331,755 of A&G Office Supplies and Expense should be disallowed as a result of the failure to explain or justify those expenses in the 2001 budget.
AFFIRM:
No position.
AG:
No.
FIPUG:
No. $2,331,755 of A&G Office Supplies and Expense should be disallowed as a result of the failure to explain or justify those expenses in the 2001 budget.
FRF:
No.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
PEF did not file testimony on this issue. The Company stated in its brief that it budgeted $1,208,000 to Salaries and Wages that should have been budgeted to A&G Office Supplies and Expense. (PEF BR 14; EXH 45, BSP 2152-2153) PEF did not address the issue further.
OPC witness Shultz recommended an adjustment of $2,331,755 jurisdictional ($2,688,677 system) comprised of several items included in A&G Office Supplies and Expense that he stated are not appropriate costs to be included in rates. (TR 1962; Exhibit 170, Schedule C-10) He stated that the first adjustment of $1,488,677 included $1,268,677 for events such as the Tampa Bay Lightning for $59,900, the Tampa Bay Buccaneers for $139,527, the Orlando Magic for $20,000 and others. (TR 1963) He stated that the two listings of events and costs are included in his exhibit HWS-3. (TR 1963; EXH 172) He testified that the remaining $220,000 was for service awards. (TR 1963)
OPC witness Schultz recommended removal of an additional $1,200,000 for what was shown by PEF as “Corporate Managed Account.” (TR 1963) He testified that the account appeared to be a large petty cash account for the president’s budget center. (TR 1963) He stated that PEF did not provide any supporting documentation for this expense, so the expense should be excluded from rates for lack of justification. (TR 1963)
OPC witness Schultz stated that there is no evidence that the costs were removed from the test year. (TR 1963) He testified that the costs were budgeted in Account 921, A&G Office Supplies and Expense. (TR 1963) He explained that, in response to discovery, (EXH 45, BSP 2156-2157) the Company supplied a reconciliation linking the budgeted costs to MFR Schedules C-1 and C-2. (TR 1963) The witness noted that the only adjustments to O&M expense that removed budgeted costs were for aircraft and advertising; the A&G items did not fall into either category. (TR 1963-1964)
OPC argued in its brief that the Company did not offer supporting documentation or rebuttal testimony in rebuttal to this issue. (OPC BR 62)
Affirm and the Navy did not address this issue in their briefs. AG stated “no” but did not address the issue further. (AG BR 11) FIPUG stated that $2,331,755 should be disallowed because the amount was not explained or justified in PEF’s budget, but did not address the issue further. (FIPUG BR 31) FRF stated “no” but did not address the issue further. (FRF BR 59) PCS Phosphate agreed with and adopted the position of OPC. (PCS BR 11)
ANALYSIS
The testimony and proposed adjustment offered by OPC witness Shultz are unrebutted. Through examination of exhibits, staff was able to determine that there is partial agreement on the part of PEF with the OPC adjustment. In response to the FPSC staff audit, PEF agreed with Audit Finding No. 4 that a number of items included in A&G for 2008 were not utility related. (EXH 290) The finding showed that the Company included items such as provision of hospitality beverages for the Arnold Palmer Invitational, food for the Honda Grand Prix, and a VIP suite. Some of the items from the audit finding are also included in the list of items supporting OPC witness Shultz’s adjustment. (EXH 172) The Company responded that it agreed with the audit finding and proposed an adjustment for 2010 in the amount of $482,479 jurisdictional ($544,000 system).
Staff agrees with OPC witness Shultz’s recommended adjustment of $2,688,677 system ($2,331,755 jurisdictional). (TR 1962; Exhibit 170, Schedule C-10) In addition to those items noted in the staff audit, he determined that other non-utility items were included in the expense, such as Tampa Bay Lightning and the Tampa Bay Buccaneers events. (TR 1963) Witness Shultz also discussed a $1.2 million account in the president’s budget center that was not supported by PEF. (TR 1963) As noted by OPC in its brief, there was no PEF testimony on these amounts. Staff believes all of the items included by witness Shultz in his adjustment are inappropriate to include in customer rates.
Staff notes that PEF stated that it budgeted $1,208,000 to Salaries and Wages that should have been budgeted to A&G Office Supplies and Expense, as discussed in Issue 63. (EXH 45, BSP 2152-2153) Staff agrees with this adjustment. This results in an increase to A&G Office Supplies and Expense of $1,208,000 system or $1,097,000 jurisdictional. Accordingly, the adjustment proposed by OPC witness Shultz should be netted with this amount. The effect is a reduction of $1,480,677 system, $1,298,435 jurisdictional. ($1,480,677 x .87692 = $1,298,435)
CONCLUSION
Staff recommends 2010 A&G Office Supplies and Expenses be reduced by $1,298,435 jurisdictional ($1,480,677 system).
Should an adjustment be made to PEF's proposed 2010 allowance for O&M expense to reflect productivity improvements, if any?
Recommendation:
No. Staff recommends that adjustments have been made to address the variances in O&M expenses in other issues. No further adjustments are necessary. (Marsh)
Position of the Parties
PEF:
No, such an adjustment is inappropriate. The Company has supported all of its 2010 O&M expenses through the testimony of its witnesses, and its budgets already reflect the productivity improvements the Company has implemented.
OPC:
Yes. The Commission should recognize the company’s incentive to implement post rate case award efficiencies beyond those reflected in its filing. PEF’s strategic plan sets as a goal achievement of annual productivity gains of 3-5%. The Commission should utilize the more conservative target of 3% and reduce projected O&M expense by $13.034 million.
AFFIRM:
No position.
AG:
Yes.
FIPUG:
Yes. The Commission should recognize PEF’s incentive to implement post rate case award efficiencies beyond those reflected in its filing. PEF’s strategic plan sets as a goal achievement of annual productivity gains of 3-5%. The Commission should utilize the more conservative target of 3% and reduce projected O&M expense by $13.034 million.
FRF:
Yes.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
PEF witness Joyner testified that the $7.7 million variance addressed by OPC witness Shultz is a product of Mr. Shultz’s lack of understanding of supporting MFRs and documentation rather than a true variance. (TR 3083) Witness Joyner stated that PEF’s actual O&M expenditures total $114.4 million for 2008, which represents the sum of the FERC 580 and 590 accounts. (TR 3084) He stated that the base year O&M expenses of $114.4 million, multiplied by the 1.1415 compound multiplier yields, the 2010 Test Year Benchmark of $130.6 million. (TR 3084; EXH 47, MFR Schedule C-37; EXH 47, MFR Schedule C-40) He stated that the variance between the benchmark and the 2010 Adjusted Test year O&M of $144.9 million is $14.3 million. (TR 3084) He added that MFR Schedule C-41 provides the explanations for the variances associated with vegetation management, environmental, operational cost efficiencies and re-organization, and FERC account reclassifications. (TR 3085) He disagreed with OPC witness Shultz’s assertion that there is a $7.7 million unexplained variance. (TR 3085)
OPC witness Schultz testified that PEF identified a number of improvements without any explanation as to where the cost savings are reflected. (TR 1964) He stated that there is an unsupported FERC 890 cost of $6.9 million and an unidentified distribution increase of $7.7 million. (TR 1964) He stated that PEF witness Sorrick indicated a cost savings from the Hines Power Block 4 Combustion Optimization Package in the future, along with a reduction in maintenance costs resulting from the Anclote Cooling Tower project. (TR 1964) Witness Shultz stated that there must be some benefit to ratepayers from the significant increase in spending to offset the cost. (TR 1964-1965) He asserted that if that cost savings is not reflected then it may flow through to shareholders instead of the ratepayers. (TR 1965) He stated that if rates are set based on the significant spending without recognition of the benefits that are forthcoming, when the cost savings occur there is no way for ratepayers to receive that benefit.” (TR 1965)
OPC witness Schultz testified that the 2009 Progress Energy Florida Strategic Plan shows the Company’s strategy commitment in the statement “‘[t]he overall mission of Progress Energy is to reward its investors by providing above-average total shareholder returns over a continuous timeframe.’” (TR 1965) He stated that the financial objectives include annual EPS growth of 4 to 5 percent, continued dividend growth, and an annual total shareholder return of 8 to 10 percent. (TR 1965) He stated that the document indicates that the “base rate filing in 2009 will add significantly to the 2010 price.” (TR 1965) The witness testified that the Company has a strategy of annual productivity gains of at least 3 to 5 percent. (TR 1965) OPC argued in its brief that this strategy is exactly the one that was communicated to Wall Street at the same time the case was being filed, but the Company did not include the benefits of these measures in the filing. (OPC BR 66; Dolan TR 2558-2560; EXH 293, p. 24)
OPC witness Schultz testified that the Company looks at difficult economic times from the shareholder perspective. (TR 1966-1967) He stated that “[t]here is no goal to minimize the rate request and that is substantiated with the business as usual pay increases, increased incentive compensation and the other significant cost increases that are recorded above the line.” (TR 1966) In contrast, witness Shultz testified that the Company stated that the declining economic condition was the reason that donations and civic expenses were less in the 2010 budget than in 2008. (TR 1967) He noted that there was a budget reduction of approximately 20 percent for below the line costs for civic functions and donations that would impact shareholder returns. (TR 1967)
OPC witness Schultz recommended a reduction to O&M expense of $13.034 million, by taking PEF’s requested 2010 O&M expense net of labor and assuming a 3 percent productivity factor. (TR 1969; EXH 70, Schedule C-11) He stated that 3 percent is the low end of the Company strategy. (TR 1968)
Witness Schultz discussed a similar adjustment for Consolidated Edison Company in Case 08-E-0539. (TR 1968; EXH 298) He testified that the New York Commission determined that because of the increased investment in plant there would be an increase in productivity and ruled that the productivity adjustment should be 2 percent instead of 1 percent. (TR 1968) He stated that the New York Commission made an additional adjustment reducing O&M cost by $60 million, which factored in the downturn in the economy and the impact the company’s request would have on ratepayers. (TR 1968) He stated that Consolidated Edison was ordered to implement austerity programs to constrain costs and tighten belts to limit discretionary spending. (TR 1968)
OPC argued in its brief that the Company has made no effort to make sure that the MFRs are representative of going-forward expense levels. (OPC BR 63; TR 1722-1724) OPC notes that, at the same time, the Company states that it is targeting budget reductions and undertaking significant belt tightening efforts. (OPC BR 63; EXH 293, p. 24) OPC points out that the Company told the Commission that for 2009 there was only a $3.5 million budget cut possibility (with no carry forward to 2010) and “minimal belt tightening with no quantification – mainly in the de minimis area of meals and entertainment, conferences and travel.” (OPC BR 63; TR 458) OPC argues that none of the cost containment efforts are reflected in the test year presentation for the Commission’s consideration. (OPC BR 63; TR 459-460) OPC stated that the Company told Wall Street that the Florida operation contributed significant earnings growth in 2008, in line with what should be expected from a utility with major capital expenditures. (OPC BR 64; EXH 293, p. 45) OPC argues that PEF “is willing to take the measures necessary to meet its EPS guidance, even if it means seeking extraordinary relief and cost deferrals and raids on the storm reserve.” (OPC BR 64; TR 2553-2554; EXH 293, p. 24)
Affirm and the Navy did not address this issue in their briefs. AG stated “yes” but did not address the issue further. (AG BR 11) FIPUG stated that PEF’s projected O&M expense should be reduced by $13.034 million to reflect 3 percent annual productivity gains; however, FIPUG did not address the issue further. (FIPUG BR 31) FRF stated “yes” but did not address the issue further. (FRF BR 59) PCS Phosphate agreed with and adopted the position of OPC. (PCS BR 11)
ANALYSIS
OPC witness Shultz notes a number of areas with which he is concerned. Witness Shultz’s adjustment seems to be based primarily on the fact that there are variances in O&M expenses above the benchmark. He stated that the additional costs must be offset by a savings to the ratepayer. The variances of concern to witness Shultz are addressed in other issues, with recommendations as appropriate contained in those issues, as discussed below.
Issue 69 dealt with the variance over the benchmark in generation O&M. Staff is recommending a $9,004,955 jurisdictional reduction for specific items that comprise a portion of the variance. Of the $53,100,000 above the benchmark, $30,300,000 was addressed specifically, and the remainder was also considered. Staff recommended in that issue that no further adjustments were necessary. Staff believes the variance of concern to OPC has been addressed.
Of the total $10,300,000 variance addressed in Issue 70, $6,900,00 is due to FERC 890 requirements. (TR 2880) Staff did not recommend an adjustment to this amount. However, staff did recommend a reduction of $1,717,042 for excess vegetation management expense that results from deferred maintenance. An additional $1,000,000 for bonding and grounding was also discussed, with no adjustment recommended. Thus, all but $682,958 of the total variance was specifically addressed.
Similarly, the increase in distribution O&M expense is addressed under Issue 71. In that issue, staff recommended an adjustment of $8,924,197, again for excess vegetation management expense that results from deferred management. When this adjustment is taken into consideration, the $7,700,000 variance discussed by OPC witness Shultz is eliminated.
Staff does not believe the fact that there is a variance above the benchmark is sufficient reason to make an adjustment. Moreover, staff does not agree that an increase in cost must also have a demonstrable cost savings. It was noted by PEF witnesses, such as witness Sorrick, that improved performance from the maintenance would result in fuel cost savings. (TR 2778) Such savings would not be reflected in the MFRs. Staff believes that PEF has demonstrated that the requested maintenance cost is necessary, except as adjusted in Issues 69 through 71.
CONCLUSION
Staff recommends that adjustments have been made to address the variances in O&M expenses in other issues. Therefore, no further adjustments are necessary.
Should an adjustment be made to PEF's requested level of salaries and employee benefits for the 2010 projected test year?
Recommendation:
Yes. Staff recommends that the salaries and wages account should be reduced by $1,454,000 jurisdictional ($1,658,000 system). (Marsh)
Position of the Parties
PEF:
Yes, as explained in response to OPC Interrogatory No. 386, PEF budgeted $1,208,000 to Salaries and Wages that should have been budgeted to A&G Office Supplies and Expense. In addition, PEF budgeted $450,000 to Salaries and Wages that should have been budgeted to A&G Injuries and Damages. Therefore, Salaries and Wages should be reduced by $1,658,000 (system) and $1,454,000 (jurisdictional).
OPC:
As demonstrated by OPC Witness Schultz, a reduction of $53,831,980 ($47,540,636 on a jurisdictional basis) be made to compensation expense.
AFFIRM:
No position.
AG:
Yes. Such salaries and benefits should be reduced to the extent that customers testified their salaries and benefits have been reduced.
FIPUG:
Yes. See Issues 64-66.
FRF:
Yes.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
PEF stated that it budgeted $1,208,000 to Salaries and Wages that should have been budgeted to A&G Office Supplies and Expense and $450,000 to Salaries and Wages that should have been budgeted to A&G Injuries and Damages. PEF advised that Salaries and Wages should be reduced by $1,454,000 jurisdictional ($1,658,000 system). (PEF BR 15; EXH 45, BSP 2152-2153)
OPC argued that, as demonstrated by OPC witness Schultz, a reduction of $53,831,980 ($47,540,636 on a jurisdictional basis) should be made to compensation expense. (OPC BR 67) OPC advised that the components of the adjustments are discussed in detail in Issues 64-67. (OPC BR 68)
Affirm and the Navy did not address this issue in their briefs. AG stated that salaries and benefits should be reduced to the extent that customers testified their salaries and benefits have been reduced; however, AG did not address the issue further. (AG BR 12) FIPUG addressed this issue in later issues. (FIPUG BR 31) FRF stated “yes” but did not address the issue further. (FRF BR 59) PCS Phosphate agreed with and adopted the position of OPC. (PCS BR 11)
ANALYSIS
PEF noted an error of $1,208,000 in Salaries and Wages that should have been budgeted to A&G Office Supplies and Expense and $450,000 to Salaries and Wages that should have been budgeted to A&G Injuries and Damages. Staff agrees with PEF’s adjustment of $1,658,000 (system) and $1,454,000 (jurisdictional). The $450,000 is addressed in issue 60 as part of OPC witness Shultz’s adjustment. The $1,208,000 is addressed in Issue 61 where it is netted against the OPC adjustment.
The Company and the intervenors addressed salaries and wages in Issues 64 through 67.
CONCLUSION
Based on the above, staff recommends that the salaries and wages account should be reduced by $1,454,000 jurisdictional ($1,658,000 system).
Are PEF's proposed increases to average salaries for 2010 appropriate?
Recommendation:
No. Salaries expense should be reduced by $10,146,776 jurisdictional ($12,209,439 system) for the 2010 projected test year. (Marsh)
Position of the Parties
PEF:
Yes, PEF’s proposed increases in average salaries are based on market studies and are designed to maintain total compensation packages that are competitive so that the Company can attract and retain qualified employees.
OPC:
No. PEF’s proposed 4.7% overall increase in base salaries is excessive in light of the labor market specifically and the economy in general. The overall increase should be held to 2.35%, resulting in a reduction to payroll expense of $12,209,439.
AFFIRM:
No position.
AG:
No. Agree with OPC that Progress’s proposed increase of 4.7% in base salaries is excessive. In light of customer testimony regarding pay cuts, lost jobs, frozen benefits and Social Security payments, it is appropriate that Progress’s employees not receive salary increases paid for by consumers during such difficult economic times.
FIPUG:
No; in these difficult economic times, PEF should be required to tighten its belt just as many citizens, county governments and school boards must do. Employee increases are inappropriate.
FRF:
No. Agree with OPC that PEF's proposed increase of 4.7% in base salaries is excessive in light of current labor market conditions and in light of the current bleak state of the economy.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
PEF witness DesChamps discussed one of the studies, which was also included in his rebuttal Exhibit MSD-12. (TR 3368; EXH 213) He explained that the study is used by the Company to assess compensation on an ongoing basis. (TR 3368) He described it as CORE, or compensation ongoing review and evaluation. (TR 3369) He stated that that the Company uses this study to look at 20 to 25 percent of PEF’s positions on an ongoing, rolling basis. (TR 3369) He testified that the CORE is used to evaluate salaries for non-officer positions, positions below vice-president. (TR 3370)
Witness DesChamps explained that a job value (JV), or market value is based on PEF’s surveys of market data, and represents a value of a position that PEF uses to benchmark the position to the general market. (TR 3371) He advised that a job value equaled about 7 percent. (TR 3371; EXH 213, p. 4) Witness DesChamps testified that of the 68 PEF job titles with below-market salaries, as shown in the CORE study, 13 were two JVs below market and 55 were one JV below in 2008. (TR 3369, 3371-3372, EXH 213, p. 4) He stated that of the 2,100 employees who were the subject of the study, 332 were below market, but none were above market. (TR 3373) When asked whether the breakdown of job titles below market was contained in the report, he stated that it was not. (TR 3372)
Witness DesChamps stated that the dollar impact of the CORE information that was reflected in PEF’s 2010 test year salaries is $39,500. (TR 3374) He agreed that there were no other salary increases in the 2010 test year that were supported by the findings of the CORE study. (TR 3375)
PEF filed testimony on other areas of compensation and discussed its salary policies generally, as pointed out in its brief and as discussed in other issues. However, the Company did not rebut OPC witness Shultz on this specific issue.
PEF stated that while it “is cognizant and empathetic of the economic conditions facing both PEF and its customers, it must also plan for the long-term future of the Company.” (PEF BR 98) PEF noted that it has been providing electric service for over one hundred years, and stated that it plans to continue to do so for many more years. (Dolan TR 2525-2527; PEF BR 98) PEF argued that part of the key to its success has been steady and moderate growth. (Dolan TR 2525-27; Dolan 220-221; PEF BR 98) PEF stated that it cannot afford to “take a short-sighted view of the economy and eliminate incentive compensation pay or freeze salaries, because it must compete in the national market for the skilled employees it needs to provide electric service.” (DesChamps TR 3249; PEF BR 98-99)
PEF argued that it takes a long-term, strategic approach to attracting and retaining its employees. (PEF BR 99) The Company stated that it continuously benchmarks its total compensation plans, including base pay and incentive compensation, to ensure it remains within the 50th percentile of its peer utilities. (DesChamps TR 3242-3243, 3249; PEF BR 99) PEF noted that it uses various survey and market benchmarking tools to make comparisons with other companies. (DesChamps TR 3250-3253; PEF BR 99) PEF argued that recent survey data shows companies have not eliminated incentive compensation and have started to reverse previous salary freezing decisions made as a result of the economy. (DesChamps TR 3249-50; PEF BR 99) PEF states that it “cannot and should not take any short-sighted measures to reduce total compensation, because it risks losing its skilled employees.” (PEF BR 99)
OPC witness Shultz testified that PEF’s compensation request is excessive and inappropriate. (TR 1926) He recommended a reduction of $47,540,636 jurisdictional ($53,831,980 system) to compensation expense. (TR 1926) He stated that:
[t]he Company’s request totally ignores the state of the economy and the impact that the request will have on the citizens of Florida who are served by the Company. The request includes business as usual pay increases, an increase in payroll for employees that have not been hired yet and an increase in incentive compensation, when the current amount of incentive compensation is not justified. (TR 1926)
OPC witness Shultz testified that a study dated June 17, 2009 indicated that 69 percent of companies surveyed had 2009 budgeted aggregate base pay equal to or below the 2008 budget. (TR 1928) He stated that PEF’s requested increase was business as usual; PEF ignored the current economic climate as well as measures it could have taken to curb costs. (TR 1927-1928) He advised that other utilities limited salary increases: Green Mountain Power in Vermont limited increases in compensation to the contractual rate for bargaining employees, and froze wages for the non-bargaining employees; Potomac Electric Power Company did not request a wage increase for non-bargaining employees, and only asked for a portion of the increase for the bargaining employees; Peoples Gas System eliminated the executive increase and reduced the employees’ compensation increases. (TR 1928)
OPC witness Shultz testified that the Company budgeted pay increases for non-bargaining positions at 3.75 percent and for bargaining positions at 3 percent in 2009 and 2010. (TR 1927; EXH 45, BSP 2068-2069) He stated that the actual increase implemented for non-bargaining positions in 2009 was 2 percent for management and 3 percent for non-management positions. (TR 1929-1930; EXH 45, BSP 2068-2069) He calculated the actual average base pay increase per employee as shown in the MFRs to be 9.4 percent from 2008 to 2010, or 4.7 percent per year. (TR 1927; EXH 170, Schedule C-3)
OPC witness Shultz testified that the Company was asked whether it had considered the state of the economy with regard to its salary increases. (TR 1928) He noted the Company responded that the 3.75 percent budgeted salary increase reflects historical trends and current economic conditions by holding the increase flat at 3.75 percent. (TR 1928-1929) Witness Shultz stated that PEF budgeted an increase of 3.5 percent in 2006 and 2007 when the economy was doing well, but increased it to 3.75 percent in 2008. (TR 1929) He stated that this behavior is counter to claims by the Company that it is trying to minimize costs. (TR 1929)
OPC witness Shultz recommended that the average annual increase in base pay be limited to 2.35 percent, or one-half the 4.7 percent increase as calculated by the witness. (TR 1929) He stated that this calculation reduces the average base salary from $75,170 to $71,979 and reduces test year payroll expense by $12,209.439. (TR 1929; EXH 170, Schedule C-3)
OPC witness Shultz noted that PEF did not identify the amount of overtime included in its request. (TR 1927) He stated that MFR Schedule C-35 does not include any overtime. (TR 1927) He testified that the Company has elected to bury the overtime costs in various other MFR schedules. (TR 1927) He stated that the overtime was identified in response to discovery. (TR 1927; EXH 45, BSP 2071-2072) Witness Shultz explained that the portion expensed was estimated based on the expense ratio for the payroll costs as shown on MFR Schedule C-35 and the response to OPC Interrogatory No. 128 that identified the portion of payroll from MFR Schedule C-35 expensed in the projected test year. (TR 1927; EXH 45, BSP 2072)
OPC noted in its brief that the total payroll requested is $489,779,401 and the amount included in expense is approximately $354,600,286. (OPC BR 67) OPC stated that the Company’s request for compensation is excessive and inappropriate. (OPC BR 67) OPC pointed out, as shown on Exhibit 170, Schedule C-3, p. 1 of 2, that witness Schultz recommended a reduction of $53,831,980 ($47,540,636 on a jurisdictional basis) be made to compensation expense. (OPC BR 67-68)
Affirm and the Navy did not address this issue in their briefs. AG stated that it agreed with OPC that Progress’s proposed increase of 4.7 percent in base salaries is excessive. AG continued that, in light of customer testimony regarding pay cuts, lost jobs, frozen benefits and Social Security payments, it is appropriate that Progress’s employees not receive salary increases paid for by consumers during such difficult economic times. However, AG did not address the issue further. (AG BR 12) FIPUG stated that employee increases are inappropriate and PEF should be required to tighten its belt in these difficult times as others must do; however, FIPUG did not address the issue further. (FIPUG BR 31) FRF agreed with OPC that PEF's proposed increase of 4.7 percent in base salaries is excessive in light of current labor market conditions and in light of the current bleak state of the economy; however, FRF did not address the issue further. (FRF BR 60) PCS Phosphate agreed with and adopted the position of OPC. (PCS BR 11)
ANALYSIS
PEF uses various survey and market benchmarking tools to make salary comparisons with other companies. (DesChamps TR 3250-3253) The Company provided several compensation studies in response to staff discovery. (EXH 32, BSP 776-902) When questioned about the studies, PEF witness DesChamps replied on cross examination that the documents provided in response to staff discovery were the actual salaries studies, not simply summaries. (TR 3365-3368) He responded that the documents provided are the only support PEF has for its 2010 compensation increases. (TR 3368)
Staff notes that the CORE study provided by PEF is a summary of a larger study. (EXH 213; TR 3252) PEF witness DesChamps described the document as such, but on cross-examination stated that the Company provided actual compensation studies in response to staff discovery. (TR 3365-3368) Staff believes that the information provided by PEF in response to staff discovery is not all of the documents PEF has that support its salaries. Staff cross-examined PEF witness DesChamps about the CORE study in particular. Information was provided by witness DesChamps that was not available in the documents, such as a breakdown of job titles below market. (TR 3372) Upon examination of the study, staff notes that there were no specifics as to the names of the employees whose salaries were below market. Only $39,500 of salary increases in the test year were based on the CORE document. (DesChamps TR 3374) PEF provided no other documents to support the salary increases in the test year. (DesChamps TR 3368) It is clear to staff, from an examination of the documents provided by PEF, that there must be some other documents that were not provided, in spite of PEF’s insistence that all were provided. Staff believes that PEF’s salary request is not supported by the record.
As noted by OPC witness Shultz, the actual increase implemented for non-bargaining positions in 2009 was 2 percent for management and 3 percent for non-management positions. (Shultz TR 1929-1930; EXH 45, BSP 2068-2069) OPC witness Shultz recommended that the average annual increase in base pay be limited to 2.35 percent, or one-half the 4.7 percent increase as calculated by the witness. (TR 1929) Staff notes that the 2.35 percent increase falls between the actual 2009 salary increases of 2 percent for management and 3 percent for non-management positions. OPC witness Shultz’s adjustment reduces the average base salary from $75,170 to $71,979 and reduces test year payroll expense by $12,209,439. (Shultz TR 1929; EXH 170, Schedule C-3)
Staff believes that a 2.35 percent increase to base pay is reasonable given the actual 2009 figures of 2 percent for management employees and 3 percent for non-management. As previously noted, staff does not believe the Company provided the studies requested by staff to support the increases. The summary of a study that was provided was the basis for an increase of $39,500 overall for selected employees. Upon review of the evidence, staff believes a reduction to payroll expense of $12,209,439 as calculated by OPC witness Shultz is appropriate.
OPC witness Shultz expressed concern that PEF buried the overtime costs in various other MFR schedules rather than show it on MFR Schedule C-35. (TR 1927; EXH 47, Schedule C-35) However, he did not propose an adjustment.
Staff agrees that the overtime is not shown on Schedule C-35. The record is silent as to the reason it is not shown. Staff examined information provided by the Company that indicates overtime and premium pay were stable, with $35,222,231 for 2006; $43,077,488 for 2007; $43,088,714 for 2008; and $43,455,819 for 2009. (EXH 45, BSP 2071) The 2010 projected test year amount is $40,860,669, which is lower than the 2007, 2008, and 2009 amounts. Staff engaged in discussion with PEF witness DesChamps about a limited number of employees that earned large amounts of overtime. (TR 923-927) The witness stated that the Company has 47 employees in the highly skilled positions that were the subject of the discussion. (TR 924-925) Although the amount of overtime for certain of the employees is high, the skill level of the position may warrant the overtime that is paid. Further, given the stability of the overtime over recent years, staff does not believe an adjustment to overtime is warranted.
No party addressed bonuses. Staff notes that PEF witness DesChamps stated that PEF did not include bonuses in the 2010 test year. (TR 930)
CONCLUSION
Staff recommends that salaries expense should be reduced by $10,146,776 jurisdictional ($12,209,439 system) for the 2010 projected test year.
Are PEF's proposed increases in employee positions for 2010 appropriate?
Recommendation:
No. Staff recommends that PEF's proposed increases in employee positions for 2010 be reduced by 80 positions for a dollar reduction of $4,156,891 (system) or $3,454,626 (jurisdictional). (Marsh)
Position of the Parties
PEF:
Yes, PEF’s proposed increase of thirty-six new positions is appropriate.
OPC:
No. The Company’s proposed allowance for filling 80 positions should be rejected to account for the overall level of vacant positions that will likely exist in the test year. This reduces payroll expense $4,156,891.
AFFIRM:
No position.
AG:
No.
FIPUG:
No; PEF should be required to freeze employee hiring in order to hold down costs, just as many citizens, county governments and school boards must do.
FRF:
No.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
PEF argued in its brief that OPC witness Shultz’s recommendation that 80 positions be removed from PEF’s employee count for 2010 is unsupported by record evidence. (PEF BR 94) PEF stated that the 80 positions represent 26 of 36 proposed new positions not filled as of June 22, 2009; 25 vacant positions; and an allocation of 29 Service Company Full Time Equivalents (FTEs). (PEF BR 94-95; EXH 45, BSP 2114-2115) PEF stated that the need for the positions was explained by PEF’s operational witnesses for generation, transmission, and distribution. (PEF BR 94)
PEF argued that OPC witness Schultz did not refute PEF’s need for any of the 36 new positions, but recommends taking away 26 positions that were unfilled as of June 22, 2009, simply because they have not been filled yet. (TR 1931-32; PEF BR 95) PEF stated that this recommendation is not based on any analysis. (PEF BR 95) The Company argued that the proposed reduction improperly assumes that the Company does not plan to fill these positions. (PEF BR 95) PEF stated that witness Schultz has no evidence that PEF is not going to fill these positions other than the fact that they are currently vacant. (PEF BR 95) PEF noted that some of the new positions are not scheduled to be filled until 2010, so they would not be filled in the first half of 2009. (PEF BR 95) The Company argued that it needs these employees and will fill these positions during the remainder of 2009 and 2010. (PEF BR 95)
PEF stated that OPC witness Schultz does not challenge the Company’s need for the 25 vacant positions which had not been filled as of June 22, 2009. (PEF BR 95) PEF argued that Witness Schultz “does not and cannot provide any evidence that the Company will not fill these positions, other than the fact that the particular positions were vacant as of a particular date.” (PEF BR 95) PEF stated that, of the 25 positions, 15 are in the Transmission Operations and Planning area. (PEF BR 95) The Company stated that it plans to fill these positions to address the increased scope of transmission work required by NERC standards as witness Oliver discusses in his testimony. (TR 563-65; PEF BR 95)
PEF stated that the 29 Service Company allocated full time employees were supported in PEF’s response to OPC’s Interrogatory 299. (EXH 45, BSP 2114-2115) PEF explained that the additional FTEs is due to an increase in the allocation ratio to PEF driven by an increase in PEF base payroll costs compared to PEC as a result of the many projects which were explained by PEF’s operational witnesses for generation, transmission, and distribution. (PEF BR 95-96) Staff notes that the Company points to no specific testimony by its witnesses that support the change in allocation.
OPC witness Shultz testified that PEF’s human resource department does not maintain budgeted employee level detail. (TR 1930) He stated that comparisons to budget cannot be made to evaluate the Company’s projections. (TR 1930-1931) The witness stated that “[t]he decrease of 18 employees is evidence that the fact of vacancies cannot be ignored and raises concerns whether the increase projected is reasonable.” (TR 1931)
OPC witness Shultz asserted that the Company had 4,929 employees as of December 31, 2008, but only 4,911 as of March 31, 2009. He opined that the decrease in employees is evidence that vacancies cannot be ignored, and questioned whether the Company’s projected increase in employees is reasonable. (TR 1931)
OPC witness Shultz testified that 497 positions are proposed for addition, while 127 are to be eliminated, for a net of 370 additional employees. (TR 1931; EXH 45, BSP 2114-2116) He noted the Company’s explanation was that 387 positions are clause-related, and 29 positions are allocated headcounts. (TR 1931) He stated that the Company appears to believe these positions do not require justification. (TR 1931) The witness testified that PEF indicated that only 81 of the 370 positions impacted base rates, consisting of 36 new positions and 45 vacancies. (TR 1931) He noted that only 10 of the new positions and 20 of the vacancies had been filled, but as of March 31, 2009, there were additional vacancies. (TR 1931) He stated that only 33 of the 36 new positions were referenced in testimony, which means that the other 48 of the 81 positions had no justification. (TR 1931-1932) Witness Shultz recommended that 51 unfilled positions be removed, along with the 29 allocated headcount service company positions. (TR 1932; EXH 45, BSP 2112) He stated that the resulting reduction using his average base salary of $71,979 per employee would be $4,156,891. (TR 1932)
OPC witness Shultz testified that he interpolated the projected increase in employees by assuming a level increase month to month. (TR 1932) He calculated a vacancy rate of 1.94 percent, which would yield 103 vacant positions of the 5,299 projected positions for 2010. (TR 1932) He stated that, based on his assumptions, his recommendation to reduce positions by 80 is conservative. (TR 1932)
OPC stated that the Company provided no rebuttal to OPC witness Schultz’s recommendation. OPC argued that PEF’s proposed increase also ignores the impact that will be reflected on customer bills in an economy that is already difficult. (OPC BR 71)
Affirm and the Navy did not address this issue in their briefs. AG stated “no,” but did not address the issue further. (AG BR 12) FIPUG stated that PEF should hold down costs as many others must do, and freeze hiring; however, FIPUG did not address the issue further. (FIPUG BR 31) FRF stated “no,” but did not address the issue further. (FRF BR 60) PCS Phosphate agreed with and adopted the position of the OPC. (PCS BR 11)
ANALYSIS
According to OPC witness Shultz, PEF indicated that only 81 of the 370 positions it has requested impacted base rates, consisting of 36 new positions and 45 vacancies. (TR 1931) Witness Shultz pointed out that only 10 of the new positions and 20 of the vacancies had been filled, but as of March 31, 2009, there were additional vacancies. (TR 1931) He testified that only 33 of the 36 new positions were referenced in testimony, which means that the other 48 of the 81 positions had no justification. (TR 1931-1932)
Witness Shultz also considered the Company’s vacancy rate in formulating his adjustment. He based the adjustment on a level increase in employees from month to month. (Shultz TR 1932) A vacancy rate of 1.94 percent yields 103 vacant positions of the 5,299 projected positions for 2010. (TR 1932) Thus, the recommended adjustment of 80 employees is lower than the calculated number. (TR 1932) A reduction of 80 employees using OPC’s average base salary of $71,979 per employee yields an adjustment of $4,156,891 system. (TR 1932; EXH 170, Schedule C-3) Using a jurisdictional separations factor of 0.83106, the jurisdictional amount is $3,454,626. (EXH 47, Schedule C-4, p. 13 of 48)
While PEF stated that OPC’s adjustment is not based on any analysis, staff believes the calculations used by OPC witness Shultz, which are based on record evidence, show that he did perform an analysis of the historical data, including the vacancies and decline in employees. (TR 1932; EXH 45, BSP 2114)
Staff notes that PEF employees declined from 5,005 in December 2007 to 4,929 in December 2008, to 4911 in March 2009. This is a decrease of 94 employees over a 15-month period. According to OPC witness Shultz, the decrease in employees is evidence that vacancies cannot be ignored. (TR 1931) Staff also notes that the testimony of OPC witness Shultz is unrebutted.
The Company projects an increase in employees to 5,245 in December 2009 and to 5,299 in December 2010. (EXH 45, BSP 2112) There was an increase in employees from 4,785 in 2006 to 5,005 in 2007, a change of 220, but when offset by the subsequent decline of 94 positions, the net increase over a two-year period was 126. Given the Company’s actual numbers, staff is not convinced that the Company will add 370 employees from 2008 through the end of 2010. This is almost 3 times the net increase from December 2007 to March 2009.
PEF stated in its brief that its operational witnesses explained the need for additional employees. (PEF BR 94) PEF stated that employees would be hired to address the increased scope of transmission work required by NERC standards as PEF witness Oliver discusses in his testimony. (TR 563-565: PEF BR 95) Staff notes that witness Oliver does discuss the NERC standards, but does not mention employees or positions. Staff has not found any testimony by PEF witnesses to support its request for additional employees.
When asked by staff whether the Company was planning any workforce reductions, PEF witness Dolan testified that the Company’s business units are always striving for efficiency which may result in a workforce reduction, but those would be a normal course of business type of reduction. (TR 301) He stated that there is not a broader plan for workforce reductions. (TR 301) Staff notes that it is not clear from his discussion that the Company will add the additional employees. It appears to staff that a reduction in employees is as possible as an increase.
Staff believes any company can expect a certain number of unfilled positions at any given time. Staff believes that the calculation provided by OPC witness Shultz is based on sound reasoning.
CONCLUSION
Based on the above, staff recommends that PEF's proposed increases in employee positions for 2010 be reduced by 80 positions for a dollar reduction of $4,156,891 (system) or $3,454,626 (jurisdictional).
Should the proposed 2010 allowance for incentive compensation be adjusted?
Recommendation:
Yes. The proposed 2010 allowance for incentive compensation be reduced by $22,181,891 jurisdictional ($25,295,228 system). (Marsh)
Position of the Parties
PEF:
No adjustment for incentive compensation is warranted.
OPC:
Yes. PEF’s expense in the amount of $25,371,639 for incentive compensation and $12,094,011 for long term incentive compensation should be disallowed as providing no benefit to ratepayers and constituting nothing more than added compensation that is inappropriate at any times, but especially in today’s economic climate.
AFFIRM:
No position.
AG:
Yes. Agree with OPC that Progress's proposed incentive compensation amount of $25,371,639 and proposed $12,094,011 for long-term incentive compensation should be disallowed because such amounts do not provide a significant benefit for Progress customers.
FIPUG:
Yes. At a minimum, the Commission should disallow $18.25 million of incentive compensation. Such additional awards should not be permitted in light of the difficult economic climate.
FRF:
Yes. Agree with OPC that PEF's proposed incentive compensation amount of $25,371,639 and PEF's proposed $12,094,011 for long-term incentive compensation should be disallowed.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
PEF witness DesChamps explained the Company’s four incentive compensation plans. (TR 802)
· The Employee Cash Incentive Plan (EICP) – an annual short-term cash incentive award for achievement of strategic company and business goals. “[D]esigned to ensure a close link between pay and performance and to share the company’s financial success with the employees who make it happen.” Based on Earnings Per Share (EPS) and ten strategic goals by business unit, such as safety, budget adherence, electric service reliability, plant production and efficiency, and other similar goals on a yearly basis. The plan has a CEO discretion component. (TR 802; TR 3243) The EPS component and the ten operational goals have equal weighting. (TR 3243)
· The Management Incentive Compensation Plan (MICP) – provides annual incentive opportunities to executives, managers, and supervisors to promote achievement of annual performance objectives, based on desired corporate financial and operational objectives. (TR 3244)
· The Executive Incentive Plan (EIP) – an umbrella plan for senior executive officers designed to preserve tax deductibility of incentive awards. (TR 3244)
· The Long-Term Incentive plan – provides equity awards to managers and executives, based on sustained achievement of financial and operational goals. (TR 3244)
PEF witness DesChamps stated that the plans aid in attracting, retaining, and rewarding managers and executives. (TR 3246) He testified that PEF’s compensation program is market- based at the 50th percentile within national, regional, and local comparative markets. (TR 3242) He stated that incentive compensation is an integral part of the total compensation package. (TR 3242) He explained that when the Company benchmarks jobs with similar peer utilities, it does so with the value of the total compensation package. (TR 3242)
PEF witness DesChamps testified that maintaining a financially strong company benefits customers as well as shareholders. (TR 3245) He stated that a financially strong company can access capital more easily at a lower cost, which benefits customers by lowering rates. (TR 3245) He contended that the fact that the Company’s shareholders also benefit from these incentive compensation goals is irrelevant to whether the costs of the incentive compensation plans should be included in base rates. (TR 3245)
PEF witness DesChamps contended that elimination of incentive compensation would cause PEF to increase its base pay to compete with other utilities and industries on total compensation basis for the workforce it needs. (TR 3246-3247) He testified that the Company would lose the flexibility to adjust compensation based on performance. (TR 3247)
PEF witness DesChamps noted that Florida has recognized the value of incentive compensation plans in the past, and has approved their inclusion in rates. (TR 3247) He provided the Commission order from Florida Power Corporation’s 1992 rate case.[50] (EXH 209) He noted that the Commission specifically included the utility’s request for incentive compensation, finding that such plans are tied to the achievement of corporate goals and provide an incentive to control costs. (EXH 73, p. 117; TR 3247) The witness also discussed Gulf Power’s 2002 rate case, in which OPC witness Schultz testified that Gulf’s incentive compensation expenses should be disallowed.[51] (TR 3247) PEF witness DesChamps stated that the Commission rejected those arguments and in doing so recognized that customers would receive quality service and low rates as a result of the inclusion of incentive compensation. (EXH 210, p. 71; TR 3247-3248)
PEF witness DesChamps noted that in the recent TECO proceeding, the PSC excluded only the portion of TECO’s incentive compensation tied to the financial goals of its parent, TECO Energy.[52] (TR 3248) He testified that while TECO is a utility industry peer, Progress Energy, Inc. (PEI) can be distinguished from TECO Energy. (TR 3248) He stated that TECO Energy has many more non-regulated subsidiaries upon which its financial performance is based, while PEI receives revenue primarily from its two electric utility subsidiaries, PEF and Progress Energy Carolinas (PEC). (TR 3248) He explained that many of the incentive compensation goals are tied specifically to PEF performance, with only the EPS goal tied to PEI. (TR 3248)
PEF argued in its brief that PEI has divested itself of the great majority of its non-regulated businesses as stated by OPC witness Dismukes, (TR 2249-2250; PEF BR 98) The Company stated that PEF witness Sullivan, PEF’s Treasurer, testified that the Company has returned to a back to basics focus on core electric utility operations. (TR 4257-4258; PEF BR 98) PEF contrasted PEI’s non-regulated business with TECO Energy, stating that TECO Energy has a higher percentage of non-regulated subsidiaries than PEI. (TR 3248; PEF BR 98) PEF noted that the Commission, in the TECO decision, explained that incentive compensation should be directly tied to the results of TECO and not to the diversified interest of its parent company.[53] (PEF BR 98) PEF argued that PEI is not diversified and is focused on the electric utility business and, therefore, any financial goals related to PEI are more directly related to the financial performance of PEF. (PEF BR 98) PEF stated that this distinguishes the TECO order from the instant case. (PEF BR 98)
PEF witness DesChamps also addressed orders from other jurisdictions that were discussed by OPC witness Schultz and FIPUG witness Marz. He stated that there are important distinctions between PEF and the utilities in those proceedings. (TR 3248) He testified that the economic factors that impact compensation levels can vary depending on the geographic location of the utility, the size, the generation mix, and the complexity of operations of a utility. (TR 3248)
PEF witness DesChamps testified that PEF’s incentive compensation costs are reasonable and necessary to continue to retain and recruit quality employees for the 2010 test year and beyond. (TR 3249) He stated that he was not aware of other utilities eliminating incentive compensation from their total compensation packages. (TR 3249)
PEF witness DesChamps provided a survey conducted by the Company in July, 2009, which shows that the twenty-one responding utilities are continuing to provide incentive compensation to their employees even with the state of the economy. (TR 3249; EXH 211) He noted that the number of employers planning to reverse salary cuts and freezes has increased in the past two months, based on surveys by consulting firm Watson Wyatt. (TR 3249-3250) He testified that 33 percent of employers that froze salaries plan to unfreeze them within the next six months, up from 17 percent two months ago, as shown by the survey. (TR 3250) He added that the number of companies indicating that they would roll back salary cuts in the next six months went from 30 percent to 44 percent over a two month period. (TR 3250)
PEF witness DesChamps testified that OPC witness Schultz did not perform a specific analysis as to PEF’s particular studies, nor did witness Shultz analyze whether a particular peer utility in a study skewed the results of the study. (TR 3250) He further noted that witness Shultz did not analyze whether the utilities in PEF’s studies are allowed to include incentive compensation in the rates charged to customers. (TR 3250-3251) He stated that PEF evaluates and monitors its peer group to ensure that it remains appropriate for such comparisons, provides representative data, and avoids the possibility that one or two organizations will skew the results. (TR 3251)
PEF witness DesChamps testified that witness Schultz’s assertion that the utility companies included in the studies do not have all their incentive compensation included in rates is irrelevant. (TR 3251) He stated that the important point is not whether a utility charges its incentive compensation to customers, shareholders, or otherwise; rather, the purpose of market studies is to compare the total compensation paid to employees, not to compare how different jurisdictions treat the recovery of portions of that compensation paid to employees. (TR 3251)
PEF witness DesChamps testified that the Company uses job value studies to ensure that each particular position is appropriately valued within the market. (TR 3252) He explained that such studies are conducted on all jobs below Vice President for about one-quarter of the job classifications annually. (TR 3252) He stated that the market review entails collecting and validating job content for each classification and benchmarking that content to external survey databases within the appropriate peer group. (TR 3252)
PEF witness DesChamps testified that witness Schultz relies on the results of a Towers Perrin survey that shows the ranking of drivers like competitive base pay, competitive health care benefits, and competitive retirement benefits, but not incentive compensation as top drivers for employees to choose an employer. (TR 3253) He stated that witness Schultz challenges the importance of incentive pay in the choice of an employer, but does not acknowledge that incentive compensation is an integral part of the total compensation package. (TR 3253)
PEF witness DesChamps noted that OPC witness Schultz considered the goals to be too low because incentive awards were made to 99.7 percent of employees. (TR 3253) Witness DesChamps testified that 99.7 percent of employees received some amount of incentive payment, but not necessarily the target amount for which they were eligible under their incentive compensation plans. (TR 3254)
PEF witness Oliver disagreed with OPC witness Schultz’s assessment of PEF’s SAIDI goals. (TR 2877) He testified that the SAIDI data of which witness Schultz expressed concern was grid SAIDI or customer SAIDI, while the SAIDI data witness Oliver referred to in his direct testimony was circuit SAIDI. (TR 2878) He stated that witness Shultz is making apples-to-oranges comparisons with data not provided or sponsored by witness Oliver. (TR 2878)
PEF witness Oliver testified that the 2006 SAIDI goal quoted by witness Schultz was based on calculations made using the events and customer bases of both electric utilities owned by Progress Energy – PEF and Progress Energy Carolinas (PEC). (TR 2878) He explained that, for 2007, the SAIDI goals for PEF and PEC were separated to better identify individual system differences and address them. (TR 2878) He testified that OPC witness Schultz compared PEF’s individual grid SAIDI goal for 2007 (9.48) to the 2006 grid SAIDI goal for the two companies combined (9.3). (TR 2878)
PEF witness Oliver testified that OPC witness Schultz’s assertion that the SAIDI goal was listed twice at different levels demonstrates witness Shultz’s lack of understanding of the data he is using. (TR 2878) Witness Oliver stated specifically that in 2006 and 2007 there were two distinct SAIDI goals. (TR 2878) He explained that the first was calculated in similar fashion to SAIDI goals of past years, while the second was considered a “stretch” goal, which would require significantly greater effort to achieve. (TR 2878) He testified that the SAIDI stretch goal was eliminated in 2008 in order to make the goals more concise and straightforward. (TR 2878-2879)
PEF witness Oliver testified that OPC witness Schultz does not understand the methodology behind setting the PEF grid SAIDI goal for a given year. (TR 2879) He explained that PEF considers several factors as part of this process, such as historical performance of the transmission system (i.e., SAIDI actuals from recent years); possible aberrations in weather trending; increased size of the transmission system (which directly affects the number of outages); and number of customers. (TR 2879) He stated that all incentive goals are audited annually by PEF's internal auditing department to ensure that PEF’s goals are set at challenging levels. (TR 2879)
PEF witness Oliver testified that PEF's circuit SAIDI actual performance for 2003-2007 decreased by 23.4 percent. (TR 2879) He explained that circuit SAIDI includes all load-related outages and all nonload-related outages which make it a comprehensive view of the transmission system performance. (TR 2879) He testified that this downward trend demonstrates that PEF has been setting challenging SAIDI goals with positive results. (TR 2879)
PEF witness Sorrick testified that PEF’s goals are realistic and performance-based. (TR 2766) He stated that the goals provide employees incentives to perform well while meeting the expectations of PEF’s customers and shareholders. (TR 2766) He stated that each specific goal requires an action, end result, measurement, and time frame. (TR 2766)
PEF witness Sorrick testified that the basic assertion of OPC witness Schultz challenges two goals: safety and environmental compliance. (TR 2766) He opined that witness Shultz expected PEF’s safety goal should be no accidents ever and its environmental goal should be one of absolute perfection. (TR 2766) He testified that safety is the highest priority at PEF and a great deal of effort goes into maintaining a safe work environment and mitigating safety issues when they occur. (TR 2767) He continued that PEF also takes its environmental responsibilities very seriously by closely measuring performance standards for its environmental standards. (TR 2767) He contended that to set either of these goals at levels that are beyond achievable is unrealistic. (TR 2677)
PEF witness Sorrick testified that PEF’s ECIP/MICP safety goals are set at levels to drive the actual safety performance of the work crews to top decile performance when compared to peer utilities. (TR 2767) He stated that, while the ultimate safety goal is zero injuries, performance goals are developed to provide employees with realistic and attainable goals. (TR 2767) Witness Sorrick testified that PEF’s safety goal is based on the Occupational Safety and Health Administration Injury and Illness (OSHA I&I) rate. (TR 2768) He explained that the I&I rate is an index that measures the number of employee injuries for every 200,000 work-hours of labor and is a standard key performance indicator used in the industry to measure safety performance. (TR 2768)
PEF witness Sorrick testified that OPC witness Schultz seems to want to punish PEF for excellent environmental performance. (TR 2769) He advised that the Environmental Index (EI) is the Company’s proxy measurement for environmental performance. (TR 2769) He noted that compliance in environmental performance is the minimum acceptable standard for all employees in the generation unit. (TR 2769) He explained that achievement of a 4.0 on the Environmental Index (on a scale of 0-5) marks a level of performance that is much better than nominal compliance, drives continual improvement, and addresses the major environmental aspects, impacts, and risks of power plant operations. (TR 2769) He contended that a sustained goal of 4.0 on the EI index is indicative of top-tier performance that should be rewarded with incentives. (TR 2769)
PEF witness Sorrick listed the key plant operations performance metrics in the areas of air emissions (S02, NOx, opacity and monitoring), surface water quality (pollutant discharges), spills or chemical releases, hazardous waste generation, and ground water usage. (TR 2770) He stated that the components of PEF’s EI are reviewed annually. (TR 2770) He stated that each plant has its own site-specific EI. (TR 2770)
OPC witness Shultz testified that incentive compensation is in addition to base pay that can only be justified if the performance of employees results in improved customer service, customer reliability, and improved financial results. (TR 1933) He asserted that the improvements benefit both ratepayers and shareholders, and the cost for incentives should follow the benefit. (TR 1933) He explained that improvements to profits, without improvements to service and reliability, should be borne by the shareholders. (TR 1933) He stated that it should not be assumed that incentive compensation is a required part of a compensation package that should automatically be passed through to the ratepayers. (TR 1933) He noted that the Company expressed unwillingness to remove the cost of incentive compensation from its request. (TR 1934)
OPC witness Shultz advised that a number of jurisdictions either limit or disallow incentive compensation in rates. (TR 1934) He identified several jurisdictions that have disallowed some portion of incentive compensation. (TR 1940) He stated that in New York, Consolidated Edison Company’s cash incentive compensation and stock- based plan costs were disallowed. (TR 1940) He testified that incentive compensation was removed in accordance with previous decisions in a Washington, D.C. Potomac Electric Power Company. (TR 1940) He advised that incentive compensation was totally disallowed in a Vermont Green Mountain Power case. (TR 1940) He stated that in Arizona, stock based incentive compensation is generally excluded and cash-based incentives are shared between ratepayers and shareholders. (TR 1940)
Witness Shultz testified that the Company’s use of the 50th percentile argument to justify use of incentive compensation is a misnomer. (TR 1934-1935) He stated that companies participating in compensation surveys do not all have incentive compensation included in base rates. (TR 1934) He stated that the use of surveys to justify the inclusion of incentive compensation in base rates puts ratepayers at a disadvantage as compared to ratepayers in other jurisdictions. (TR 1935)
OPC witness Shultz questioned whether incentive compensation is a significant factor in attracting and retaining competent employees. (TR 1935) He stated that the top five drivers used by an employee to choose an employer were competitive base pay, competitive health care benefits, vacation/paid time off, competitive retirement benefits, and career advancement opportunities. (TR 1935; EXH 32, BSP 757) He noted that incentive compensation was not included in the top five, nor was it even in the top ten attraction drivers. (TR 1935-1936; EXH 32, BSP 907)
OPC witness Shultz stated that no salary study he has reviewed over the past 30 years indicated that salary levels within a study had been adjusted to reflect disallowed incentive compensation. (TR 1936) He added that the Company confirmed that no such adjustments had been made. (TR 1936; EXH 32, BSP 756)
OPC witness Shultz expressed concern with the incentive compensation plans themselves. (TR 1937) He noted that the stated purpose of the Management Incentive Compensation Plan (MICP) was to promote the financial interests of the Company. (TR 1937) He stated that the emphasis is on financial performance, which benefits shareholders. (TR 1937) Witness Shultz noted that there was no reference to ratepayers in the incentive compensation plans. (TR 1939)
OPC witness Shultz stated that the incentive compensation plan is based on goals that do not require above average performance. (TR 1937) He asserted that some of the operational goals may not be real goals. (TR 1937) He noted that goals may be relaxed when they are missed, such as a goal of less than 1.25 recordable injuries that was not achieved in 2006. (TR 1937) He added that the goal was relaxed in 2007 to less than 1.37 recordable injuries. (TR 1937) He testified that the transmission goal for System Average Interruption Index (SAIDI) of less than or equal to 9.3 was not achieved in 2006. (TR 1938) He added that even though the reduced goal of 9.48 was met in 2007, it was reset in 2008 to 10.2, thus lowering the performance requirement. (TR 1938) He stated that the Sarbannes-Oxley goal of no material weakness in internal controls is an expected duty that should fall under base pay. (TR 1938) He asserted that even though PEF witness David Sorrick stated that it is the Company’s goal to have zero accidents, the incentive compensation goals allow for accidents. (TR 1938) Finally, he stated that while the environmental goal of greater than or equal to 4 was achieved in 2005, 2006, 2007, and 2008, the goal has not been raised. (TR 1938) Witness Shultz opined that the term “incentive” means to stimulate; there is no stimulation if goals are not increased. (TR 1938)
OPC witness Shultz testified that 99.6 percent of all eligible employees received incentive compensation in 2006, while in both 2007 and 2008, 99.7 percent of eligible employees received the awards. (TR 1939; EXH 32, p. 726) He stated that with approximately 5,000 employees, he found it very hard to believe that performance was so high among the employees that almost everyone earned a payment. (TR 1939) He opined that this is evidence that the incentive compensation is just added compensation, not a true incentive compensation. (TR 1939)
OPC witness Shultz recommended that $25,371,639 of incentive compensation and $12,094,011 of long-term incentive compensation expense be disallowed in its entirety. (TR 1940) He based the recommendation on the failure of the Company to establish a plan that is designed to provide a tangible and/or quantifiable benefit to ratepayers. (TR 1940-1941) He opined that it is insensitive to ratepayers to allow in rates added compensation with dubious demonstrable benefits. (TR 1941)
OPC argued as follows:
true incentive compensation is compensation in addition to base pay that can only be justified if the performance of employees results in improved customer service, customer reliability and improved financial results. With those improvements there is a benefit to both ratepayers and shareholders. The cost for incentives should follow the benefit. Therefore, if the improvement in operations can be shown in service, reliability and earnings then it would be appropriate for shareholders and ratepayers to share the cost of that improved performance.
(BR 74; TR 1933)
FIPUG witness Marz testified that payment of incentive compensation is a reward for achievement of goals and objectives that are discretionary. (TR 2309) He stated that incentive compensation that is based on the achievement of financial goals benefits shareholders, not ratepayers, and should be disallowed on that basis. (TR 2309-2310) He recommended a reduction of $2.6 million of incentive compensation budgeted for executives and senior management, and a $15.6 million reduction representing 50 percent of all other incentive compensation. (TR 2310; EXH 184) He stated that all executive/senior management incentive compensation is based on earnings per share (EPS), and that 50 percent of other incentive compensation is based on achieving a certain level of EPS. (TR 2310)
FIPUG witness Marz explained how each of the incentive compensation plans tied to the financial performance of the parent company. (TR 2311) He testified that the Executive Incentive Plan (EIP) payment is made from an award pool of up to 1 percent of the operating income of PEF’s parent at the discretion of the Organization and Operations Committee of the Board of Directors of Progress (Committee). (TR 2311) He stated that, under the Senior Management Performance Sub-Share Plan, senior managers may receive stock awards that are tied to a combination of the total shareholder return and the rate of growth in EPS. (TR 2311) He continued that under the MCIP payout is based in part on EPS and upon Earnings before Interest, Taxes, Depreciation and Amortization (EBITDA). (TR 2311) He stated that under the EICP the award is based on EPS and on business unit goals. (TR 2311-2312) He explained the EICP portion that is tied to EPS is not paid if only the minimum targeted EPS is met, and if the minimum EPS is not achieved, may also be reduced by up to 15 percent. (TR 2312)
FIPUG witness Marz advised that total incentive compensation included in the MFRs was $33.9 million, with $2.6 million for executive compensation and $31.3 million for incentive compensation for management and non-executive employees. (TR 2312; EXH 184) He testified that PEF has assumed that the total payout for 2010 will be its full budgeted amount of $33.9 million across all employee classes and has sought to include that full amount in the setting of rates. (TR 2312) He stated that all of PEF’s incentive compensation programs are discretionary and contingent upon earnings targets being met, except for the ECIP. (TR 2313) He noted that under the ECIP at least half of the potential award is based on the EPS minimum target being exceeded, and the remaining amount is based on business unit goals. (TR 2313)
FIPUG witness Marz testified that the contingent nature of the payments means that the incentive compensation payments are not guaranteed; as a result, the inclusion of the entire budgeted amount of incentive compensation provides a fund that management may choose to use to boost earnings. (TR 2313) He stated that the payment is not known and measurable because of the contingency. (TR 2313) He asserted that if an expense is not known and measurable it should not be allowed. (TR 2313)
FIPUG witness Marz recommended that all of the compensation paid to executives under the EIP and the Performance Sub-Share Plan should be excluded from the rate request in the amount of $2.6 million. (TR 2314) He explained that such compensation is based on earnings of the parent company, not on the results of PEF, so it should not be borne by ratepayers. (TR 2314) He further recommended that 50 percent of the total incentive compensation for management and non-management employees totaling $15.6 million be disallowed. (TR 2314) He stated that MICP is based on EPS and EBITDA and thus benefits shareholders. (TR 2314) Further, he noted that ECIP is based in part upon EPS. (TR 2314) He asserted that:
To the extent that the reward is for enhancing shareholder returns, the payment is much more in the nature of a profit sharing between shareholders and management. To the extent that employees are being paid for enhancing value to shareholders, it is shareholders that should bear the overall responsibility of such costs.
(TR 2314-2315)
FIPUG witness Marz testified that other jurisdictions exclude a portion of incentive compensation when setting rates. (TR 2315) He stated that the Public Utility Commission of Texas (PUCT) has disallowed incentive compensation that is tied to corporate financial objectives. (TR 2315) He described the AEP Central Case in which the PUCT found that incentive compensation tied to operational factors should be included, because such incentives are necessary to the provision of utility services, and are of a more immediate benefit to ratepayers, but excluded incentive compensation that was tied to financial interests because it was of more immediate benefit to shareholders. (TR 2315) Witness Marz also described a Wyoming Public Service Commission case in which 50 percent of incentive compensation was disallowed because business unit and corporate incentives were primarily for the benefit of shareholders. (TR 2315)
FIPUG witness Marz also discussed the recent Commission TECO rate case in which a portion of incentive compensation was disallowed. (TR 2316) He explained that the Commission found that incentive compensation that was tied to the earnings of the parent company’s diversified interests did not benefit ratepayers. (TR 2316)
FIPUG stated that PEF witness DesChamps was unable to explain how an increase in earnings per share for a stockholder might benefit the ratepayers. (TR 842; FIPUG BR 35) FIPUG pointed out that witness DesChamps admitted that an increase in share price does not convey a customer satisfaction benefit. (TR 842; FIPUG BR 35) FIPUG noted that when asked how a bigger dividend or a higher price for the sale of stock benefitted the ratepayers, witness DesChamps stated that he did not know. (TR 843; FIPUG BR 35) FIPUG argued that the connection has not been established nor could it be as ratepayers do not benefit from compensation awards based on parent company earnings. (FIPUG BR 35)
FIPUG argued that all of the compensation paid to executives under the EIP and the Performance Sub-Share Plan should be excluded from the calculation of operating expenses and rates. (FIPUG BR 35) FIPUG explained that such compensation is based on the earnings of the parent company, not tied to the results of PEF. (TR 2314; FIPUG BR 35-36)
Affirm, FRF, and the Navy did not address this issue in their briefs. AG stated that it agreed with OPC that Progress' proposed incentive compensation amount of $25,371,639 and proposed $12,094,011 for long-term incentive compensation should be disallowed because such amounts do not provide a significant benefit for Progress customers,” but did not address the issue further. (AG BR 12) FRF stated that PEF's proposed incentive compensation amount of $25,371,639 and PEF's proposed $12,094,011 for long-term incentive compensation should be disallowed, but did not address the issue further. (FRF BR 60) PCS Phosphate agreed with and adopted the position of the OPC. (PCS BR 11)
ANALYSIS
OPC witness Shultz and FIPUG witness Marz each addressed this issue in different ways. Witness Shultz based his recommendation on total incentive compensation. Witness Schultz recommended that incentive compensation of $25,371,639 and $12,094,011 of long-term incentive compensation be excluded from base rates, based on the expense ratio he calculated. (TR 3246)
On the other hand, FIPUG witness Marz based his recommended adjustment on the Incentive Compensation Plan on PEF’s MFR Schedule C-35, but did not address the Long-Term Incentive Compensation Plan on the next line. (EXH 184; EXH 47, MFR Schedule C-35) Witness Marz recommended that all of the Company’s incentive compensation budgeted for executives and senior management, as well as 50 percent of the incentive compensation for management and non-management employees, be excluded from the Company’s rate request. (TR 3246) Staff notes that while the reduction to incentive compensation was intensely argued by the Company, witness Marz’s use of 50 percent to represent the non-EPS portion of incentive compensation is unrebutted.
FIPUG argued in its brief that all of the compensation paid to executives under the EIP and the Performance Sub-Share Plan should be excluded from the calculation of operating expenses and rates. Staff believes the Performance Sub-Share Plan referred to by FIPUG is a Long-Term Incentive Plan. As noted previously by staff, FIPUG witness Marz did not address the Long-Term portion.
The Company’s proxy statement shows certain categories of incentive compensation have a primary purpose to "align interests of shareholders and management, and aid in attracting and retaining executives.” (DesChamps TR 3354-3355; EXH 310) In particular, the Long-term Incentives – Performance Shares and the Long-term Incentives – Restricted Stock/Restricted Stock Units both share that primary purpose. Staff notes that the long-term incentives are equity-based compensation plans. (TR 803)
PEF witness DesChamps compared PEF to the recent TECO case in which the Commission excluded that portion of TECO’s incentive compensation tied to the financial goals of its parent, TECO Energy.[54] (TR 3248) According to witness DesChamps PEI can be distinguished from TECO Energy, even though it is an industry peer. (TR 3248) He explained that TECO has a number of non-regulated subsidiaries upon which its financial performance is based, while PEI receives revenue primarily from its two electric utility subsidiaries, not from non-regulated subsidiaries. (TR 3248)
As explained by PEF witness DesChamps, a portion of the incentive compensation goals are tied specifically to PEF performance, while only the goals based on EPS are tied to PEI. (TR 3248) He discussed a table in the Company’s proxy statement with a column showing compensation based on company Earnings per Share. (TR 3363; EXH 310) The witness explained that there is a target opportunity for executives to receive a level of compensation based on company Earnings per Share. He explained that for William Johnson, 100 percent of the target opportunity for Mr. Johnson's annual incentive compensation is based on the company earnings per share measure. He stated that the measure applied to each of the officers listed in the proxy statement table. (TR 3364) The Company’s proxy statement shows that executive incentive compensation is based on company Earnings per Share. (TR 3363-3364; EXH 310)
Staff believes that incentive compensation should be directly tied to the results of PEF and not to the interests of its parent company, PEI, in the form of EPS. While PEF distinguishes itself from TECO, no dollar comparisons were provided by PEF. Staff notes that those revenues that are received by PEF from non-regulated sources are at very high rates of return, as noted by OPC witness Dismukes. (TR 2661) She testified that the non-regulated segment of PEF earned a return of at least 109 percent in 2007, 131 percent in 2008, 176 percent projected for 2009 and 92 percent projected for 2010. (TR 2261; EXH 151) She contended these returns may be seriously understated. (TR 2261) The subject of affiliate transactions is discussed further in Issue 85.
Moreover, staff is concerned that the Company has placed an emphasis on EPS that has negative consequences, in particular, the deferral of certain items of maintenance as discussed in Issues 70 and 71. For example, PEF witness Oliver testified that PEF’s focus for transmission vegetation management in 2007, 2008, and 2009 was on lines greater than 200kV to avoid significant penalties. (TR 2883) PEF witness Oliver explained that funding was shifted from lines not subject to the penalties to those that were. (TR 2883) Lower voltage lines were cleared on an “as needed” basis, but were not cleared to the full extent that would normally be performed during cycle clearing. (TR 2883) He stated that additional funds are needed now for clearing of the lower voltage lines that are not subject to the $1 million per day penalties. (TR 2883)
According to PEF witness Joyner, distribution vegetation management has been prioritized based upon expected impact to system performance, and to yield the maximum benefit for the money spent. (TR 3089) He indicated that the Commission’s storm hardening rule required an increased scope of work, but it did not provide the additional maintenance dollars above the amount received in the Company’s 2005 rate case settlement that are necessary to perform the work. (TR 3088) Staff believes that the Company limited the amount of money it spent on vegetation management to avoid spending the requisite dollars.
Staff believes both of these instances demonstrate a concern for EPS above that of conducting appropriate maintenance where it might impact Company earnings. Staff does not believe employees should be rewarded for that. Accordingly, staff believes that incentive compensation tied to EPS should not be passed on to ratepayers.
OPC witness Shultz questions whether incentive compensation is a significant factor in attracting and retaining competent employees. (TR 1935) He stated that the top five drivers used by an employee to choose an employer were competitive base pay, competitive health care benefits, vacation/paid time off, competitive retirement benefits, and career advancement opportunities. (TR 1935; EXH 32, BSP 757) He noted that incentive compensation was not included in the top five, nor was it even in the top ten attraction drivers. (TR 1935-1936; EXH 32, BSP 907)
PEF witness DesChamps stated that OPC witness Shultz did not analyze whether the utilities in PEF’s studies are allowed to include incentive compensation in the rates charged to customers. (TR 3250-3251) Staff notes that witness DesChamps stated it was not possible to ascertain whether adjustments had been made, because individuality of the data was confidential. (TR 1936; EXH 32, BSP 756) OPC witness Shultz stated that no salary study he has reviewed over the past 30 years indicated that salary levels within a study had been adjusted to reflect disallowed incentive compensation. (TR 1936)
PEF witness DesChamps testified that OPC witness Schultz did not perform a specific analysis as to PEF’s particular studies, nor did witness Shultz analyze whether a particular peer utility in a study skewed the results of the study. (TR 3250)
Staff notes that PEF witness DesChamps stated that PEF provided all studies it had that supported its compensation levels. On cross-examination, information was provided by the witness that was not available in the salary documents provided by PEF. (TR 3372) Further, there were no specifics as to the job titles that were impacted or the names of the employees in the Company’s CORE document, which shows that there must be some other document that was not provided in response to staff’s request. (TR 3368) Staff questions whether the actual studies were made available for an analysis to be performed.
Witness DesChamps noted that Florida has recognized the value of incentive compensation plans in the past, and has approved their inclusion in rates. (TR 3247; EXH 209; EXH 210) Staff notes that the decisions discussed by the witness were based on the record in those cases. While prior decisions are important, the decision in this case must be based on this record, which may be different from that considered previously. There is extensive testimony from several PEF witnesses as well as intervenors in this case. Staff also notes that cases in other jurisdictions may be instructive, but those decisions are not the driving factor for a decision in Florida. The utility has the burden of proof to show that recovery for these plans is appropriate in this case.
OPC witness Shultz testified that PEF’s incentive compensation goals do not require above average performance and may be relaxed when they are missed. (TR 1937) He expressed doubt that the operational goals are real goals. (TR 1937)
PEF witness Oliver stated that witness Shultz is making apples-to-oranges comparisons with the goals. (TR 2878) He explained that some of the changes in goals noted by witness Shultz were based on PEF and PEC together at one point, then later separated. (TR 2878) He also stated that witness Shultz compared different types of SAIDI as if they were the same. (TR 2878)
PEF witness Sorrick addressed two specific types of goals based on safety and environmental compliance. (TR 2766) He stated that PEF’s ECIP/MICP safety goals are set at levels to drive the actual safety performance of the work crews to top decile performance when compared to peer utilities. (TR 2767) He explained that compliance in environmental performance is the minimum acceptable standard for all employees in the generation unit. (TR 2769) He stated that a sustained goal of 4.0 (on a scale of 0-5) on the EI index is indicative of top-tier performance that should be rewarded with incentives. (TR 2769)
Staff believes that the operational goals discussed by the PEF witnesses are appropriate incentive goals. The evidence does not show that goals are arbitrarily changed if they are missed, to allow employees an easier target. Rather, it appears to staff that the goals are set to reward a high level of achievement on a consistent basis.
In summary, staff believes that PEF has demonstrated that its operational goals are realistic and appropriate incentive goals. Staff disagrees with OPC witness Shultz that all incentive compensation should be removed, although some adjustment is warranted. Staff believes FIPUG witness Marz’s use of a 50 percent factor applied to the incentive compensation is appropriate. However, as previously noted, witness Marz did not address the Long-term incentive compensation. Staff believes OPC is correct that it should be adjusted, because it is based on EPS, and thus is tied to the earnings of the parent company, not the operational goals of PEF. Staff believes FIPUG witness Marz’s 50 percent factor, applied to all incentive compensation, including long term compensation, is appropriate. This approach reflects allowance of the portion that is based on operational goals, while removing the portion that is based on EPS. The total incentive compensation is $50,590,455 ($33,886,020 + 16,704,435). (EXH 47, Schedule C-35) a reduction of 50 percent is $25,295,228 system. The jurisdictional amount is $22,181,891 ($25,295,228 x .87692).
CONCLUSION
Based on the above, staff recommends that the proposed 2010 allowance for incentive compensation be reduced by $22,181,891 jurisdictional ($25,295,228 system).
Should the Company's proposed 2010 allowance for employee benefit expense be adjusted?
Recommendation:
Yes. The proposed 2010 allowance for employee benefit expense should be reduced by $1,706,667 jurisdictional ($1,946,206 system) to reflect a reduction in employee positions. (Marsh)
Position of the Parties
PEF:
No adjustment for employee benefit expense is warranted.
OPC:
Yes. Employee benefits expense should be reduced by $9,376,809 to account for an unexplained discrepancy between the MFRs and the revised MFRs. Additionally, an adjustment needs to be made to be consistent with the adjustment in the level of employee due to vacant positions (See, Issue 65).
AFFIRM:
No position.
AG:
Yes. Agree with OPC that Progress's employee benefit expense should be reduced by $9,376,809.
FIPUG:
Yes. Employee benefits expense should be reduced by $9,376, 809 to account for an unexplained discrepancy between the MFRs and the revised MFRs. Additionally, an adjustment needs to be made to be consistent with the adjustment in the level of employee due to vacant positions.
FRF:
Yes. Agree with OPC that PEF's employee benefit expense should be reduced by $9,376,809.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
PEF witness DesChamps testified that OPC witness Schultz recommended an adjustment to the Company’s requested average benefit per employee expense by reducing the number of employee positions. (TR 3254) He stated that witness Schultz also made an adjustment based on changes to the Company’s MFR Schedule C-35. (TR 3254; EXH 47, MFR Schedule C-35) He noted that witness Schultz made some observations about the PEF’s health care costs and retirement plans, but did not make any specific adjustments. (TR 3254)
PEF witness DesChamps stated that OPC witness Shultz did not do any specific analysis of the Company’s health care costs. (TR 3254-3255) Pointing to a statement by witness Schultz that PEF’s employee contributions increased by 3 percent, while healthcare costs have been increasing 10 to 12 percent annually, witness DesChamps contended that witness Schultz has taken data from PEF’s interrogatory response out of context. (TR 3255) He explained that the 3 percent figure is for bargaining unit plans only and only reflects the increase from 2008 to 2009. (TR 3255) He testified that witness Schultz did not acknowledge the Company’s benefit strategy, which includes the introduction of consumer-driven health plans, and action taken to limit its health care cost increases per employee to well below the national average over the past several years. (TR 3255) Witness DesChamps asserted that although cost increases have fluctuated from year to year, the costs still remain below the national average, as reflected in his exhibit MSD-14. (TR 3255; EXH 215) He contended that witness Schultz does not analyze what employee contributions should be, nor does he assess whether increasing employee contributions would limit the Company’s healthcare cost increases. (TR 3255)
PEF witness DesChamps stated that witness Schultz’s reference to the 10 to 12 percent annual increase in health care costs is based on the Company’s budget projections, which are based in part on national trends. (TR 3255) He explained that employee contributions are set based upon review of prior year’s experience as compared to projections for the next year. (TR 3255) He stated that, to the extent the prior year’s actual claims experience is less than the budget projection, employee contributions will not relate directly to the corresponding budget projection. (TR 3255) He opined that the Company must consider its need to remain competitive with other utilities and other large employers when setting employee rates. (TR 3255)
PEF witness DesChamps noted that OPC witness Schultz did not do any specific analysis as to the costs for the Company’s retirement plans. (TR 3256) He stated that witness Schultz made statements that the Company has a generous benefit package, while many of PEF’s customers do not enjoy similar benefits. (TR 3256) He testified that the Company’s benefits packages are part of a carefully designed and benchmarked total compensation package. (TR 3256) He stated that PEF is competing against other utilities, as well as non-regulated companies, for highly skilled employees. (TR 3256) He explained that an employee may choose better health or pension benefits over a higher salary. (TR 3256) He advised that, if a significant piece of the overall compensation package, such as pension or incentive compensation, is eliminated, other portions of the total rewards package may require increases. (TR 3256) He testified that this Commission recognized the value of a total compensation approach in Gulf’s 2002 rate case proceeding.[55] (TR 3256; EXH 210) PEF witness DesChamps asserted that the Company’s total compensation package, and all the expenses included in this rate case for the package, should be approved as reasonable. (TR 3256)
OPC witness Shultz testified that an adjustment should be made based on his recommended adjustment to the number of employees. (TR 1941) He explained that the adjustment was made using the average benefit expense per employee multiplied by his recommended adjustment of 80 positions, which resulted in an adjustment of $1,946,206. (TR 1942) OPC stated in its brief that this adjustment was not rebutted by the Company. (OPC BR 81)
OPC witness Shultz advised that an additional adjustment of $9,376,809 is needed to reflect changes made to MFR Schedule C-35 in a revised filing by the Company. (TR 1941; EXH 47, MFR Schedule C-35) He explained that the amount was determined by multiplying the expense ratio of fringe benefits by the total fringe benefit cost on revised MFR Schedule C-35. (TR 1941-1942; EXH 45, BSP 2072)
In addition, OPC witness Shultz testified that pension cost increases of $67,472,819 and medical cost increases of $7,071,527 have driven an increase in fringe benefit costs. (TR 1942) He noted that the Company projected an increase of $79,676,684 in fringe benefit costs from $95,825,556 in the 2008 base year to $175,502,240 in the 2010 projected test year. (TR 1942) He testified that the pension cost increase is due to a significant downturn in the economy. (TR 1942) He argued that the healthcare costs appeared excessive due to the fact that employee sharing has not kept pace with the cost increases the Company has projected. (TR 1942) He noted that the employee contributions increased by 3 percent, while health care costs were rising at a rate of 10 to 12 percent annually. (TR 1942; EXH 32, BSP 772; EXH 32, BSP 748)
OPC witness Shultz noted that PEF has a wide array of benefits that include two pension plans. (TR 1942) He stated having two retirement plans is a luxury that most ratepayers do not have. (TR 1942) He noted that the Company also has generous health care plans that include general health, pre-tax health savings, dental and vision care, miscellaneous benefits and retiree benefits that are paid for by the ratepayers. (TR 1942-1943) He stated that ratepayers may be uninsured and may not have a retirement plan. (TR 1943) He testified that the Commission should factor this into its decision given today’s economic climate. (TR 1943)
OPC stated in its brief that it does not support any cuts in benefits actually provided. (OPC BR 80)
Affirm and the Navy did not address this issue in their briefs. AG stated that it agreed with OPC that Progress's employee benefit expense should be reduced by $9,376,809, but did not address the issue further. (AG BR 12) FIPUG stated that employee benefits expense should be reduced by $9,376,809 to account for an unexplained discrepancy between the MFRs and the revised MFRs, and that an adjustment needs to be made to be consistent with the adjustment in the level of employee due to vacant positions; however, FIPUG did not address the issue further. (FIPUG BR 37) FRF stated that it agrees with OPC that PEF's employee benefit expense should be reduced by $9,376,809 but did not address the issue further. (FRF BR 60) PCS Phosphate agreed with and adopted the position of the OPC. (PCS BR 11)
ANALYSIS
Staff agrees with OPC witness Shultz that fringe benefit expense should be reduced consistent with the reduction in numbers of employee positions addressed in Issue 65. In that issue, staff recommended a reduction of 80 positions in agreement with OPC. Thus, staff also agrees that an adjustment of $1,946,206 should be made to reflect the reduction in positions.
The basis for OPC witness Shultz’s second adjustment regarding the discrepancy in the revised MFR Schedule C-35 is based on the fact that the revised schedule shows a lower amount of fringe benefit expense than the original filing. Staff notes that the total expense numbers for all O&M expenses are the same as the original filing. The discrepancy pointed to by witness Shultz is a recategorization of certain expenses. However, there is no impact on the Company’s overall rate request. Therefore, staff does not believe a reduction should be made.
Finally, OPC discusses the Company’s medical and pension benefits, but does not recommend a specific adjustment. There is no evidence in the record that the fringe benefits are unreasonable as compared to other companies. PEF witness DesChamps testified that health care cost increases per employee have been well below the national average over the past several years. (TR 3255; EXH 215) Staff does not believe a reduction other than that previously discussed should be made.
CONCLUSION
Based on the above, staff recommends that the proposed 2010 allowance for employee benefit expense be reduced by $1,706,667 jurisdictional ($1,946,206 system) to reflect a reduction in employee positions.
Should an adjustment be made to the accrual for property damage for the 2010 projected test year?
Recommendation:
No. The annual accrual for property damage should remain at its current level of $5,566,000 ($6 million system), as addressed in Issue 33. (Marsh)
Position of the Parties
PEF:
No.
OPC:
Yes. The accrual for storm damage should be eliminated. (See, Issue 33).
AFFIRM:
No position.
AG:
Yes. Support OPC’s position.
FIPUG:
Yes. The accrual for storm damage should be eliminated. See discussion in Issue 33.
FRF:
Yes. PEF's annual accrual for storm damage reserve should be eliminated because the current reserve balance is effectively at the Company’s proposed target level, because the current balance is sufficient to cover the costs of non-catastrophic storms for at least the next 5 years, and because the company has adequate other means of addressing cost recovery in the event of catastrophic storms.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
The accrual for property damage is discussed in Issue 33. The annual accrual should remain at its current level of $5,566,000 ($6 million system). After reducing the annual accrual by $9,356,000 ($10 million system) as recommended in Issue 33, no further adjustment is necessary.
Should an adjustment be made to PEF's 2010 generation O&M expense?
Recommendation:
Yes. Staff recommends that Plant in Service should be increased by $3,479,776 jurisdictional, Accumulated Depreciation should be increased by $19,706 jurisdictional, O&M expense should be decreased by $9,004,955 jurisdictional, and depreciation expense should be increased by $41,680 jurisdictional. (Marsh)
Position of the Parties
PEF:
No.
OPC:
Yes. Power Operations Expense should be reduced $17,741,309 due to the lack of justification and documentation for the company’s proposed increases in expense levels or due to the recurring nature of costs.
AFFIRM:
No position.
AG:
Yes. Support OPC’s position.
FIPUG:
Yes. PEF’s steam and other generation O&M expense is overstated. PEF projects a 36% increase in expenses compared to its budgeted 2009 numbers. It projects a 57% increase in comparison to its four-year average (2006-2009) expenses. This dramatic increase is a result of PEF moving a CR3 outage from a period beyond the 2010 test year, additional planned outages, and a “contingency” expense. A $15 million reduction should be made to generation O&M to address these excessive amounts.
FRF:
Yes. PEF's Power Operations Expense should be reduced by $17,741,309.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
PEF witness Sorrick testified that OPC witness Schultz’s assertion that PEF’s power operations O&M expense request appears excessive demonstrates his fundamental lack of understanding of PEF’s O&M cost requirements. (TR 2771) Witness Sorrick stated that the maintenance requirements included in the 2010 budget are driven by actual unit operations over the past few years and the projected operations for 2009 and 2010. (TR 2771) He disagreed with witness Schultz’s assertion that the rate request set forth for 2010 is based upon a high year, stating that it is an uninformed assertion. (TR 2771) Witness Sorrick stated that the major maintenance costs do fluctuate from year to year, and that the Company tries to levelize the maintenance requirements within reason. (TR 2771) Witness Sorrick testified that it is not always possible to levelize the maintenance requirements due to the number of units within the fleet, the operational characteristics of each unit, and each unit’s position in its given maintenance cycle. (TR 2772)
PEF witness Sorrick explained that the maintenance expenses are necessary to optimize the fleet’s performance going forward. (TR 2772) He testified that, as the units operate, they accumulate major maintenance requirements which are the primary driver of the expenditures. (TR 2772) He stated that the material condition of the equipment will degrade until it breaks and is forced out of service. (TR 2772) He asserted that preventive action in the form of major maintenance outages is necessary to assure that the equipment does not break down. (TR 2772) Witness Sorrick advised that generating equipment operates at high temperatures in severe environments, so that the loss of features like cooling or protective coatings can rapidly lead to total failure of a part. (TR 2773) He added that parts are expensive to manufacture because some of the materials are too hard and strong to be machined using conventional methods. (TR 2773) Witness Sorrick stated that criteria have been established by the original equipment manufacturers for determining when maintenance and repair is required. (TR 2774)
PEF witness Sorrick testified that FIPUG witness Marz is incorrect that PEF’s planned outages are included in the test year for the purpose of driving up the costs. (TR 2774-2775) He stated that the increase in costs is driven by maintenance requirements on the fleet as they exist now. (TR 2775) He added that PEF has added several combined cycle units to PEF’s fleet over the past several years, which is a key driver of PEF’s major maintenance requirements. (TR 2775) He stated that witness Marz does not understand how PEF’s generation fleet actually operates. (TR 2775)
PEF witness Sorrick testified that OPC witness Schultz is incorrect that the cost of the maintenance at Crystal River Unit 4 (CR4) is typically performed every nine years and is not typical maintenance. (TR 2775) He stated that this major maintenance must be done on an interval basis for the fossil steam fleet, the combined cycle fleet, and the simple cycle combustion turbine fleet. (TR 2775)
PEF witness Sorrick stated that FIPUG witness Marz’s approach to allow only 11.1 percent of the CR4 outage costs does not account for the major maintenance requirements for the entire fleet. (TR 2777) He testified that to arbitrarily remove one of the higher cost outages from the stack of requirements in 2010 for different treatment will not account for the overall and on-going maintenance cost requirements for the fleet. (TR 2777) He explained that PEF combined the CR4 major boiler and turbine maintenance project with the clean air project construction outages to tie the clean air equipment into the existing plant equipment. (TR 2777) He stated that boiler and turbine maintenance is also combined due to the significant outage time of the unit, so that an outage will not occur again the following year. (TR 2777) The witness testified that PEF customers will benefit from the combined outage in fuel savings by having CR4 available more of the time and by the improved performance expected out of CR4 after this major maintenance is performed. (TR 2778) Witness Sorrick stated that it is important to minimize outages on base loaded units in order to minimize fuel costs to the customer. (TR 2778) Witness Sorrick explained that:
[i]f less expensive (e.g. - base loaded) units are off-line, then [sic] more expensive units are required to operate in their place. In other words, the ability to optimize outage times (scheduled and forced) will also optimize the customers’ fuel costs.
(TR 2778)
PEF witness Sorrick testified that the proposal of OPC witness Shultz to reduce power operations expense by $7.35 million to smooth out the costs being charged to the ratepayers would require the deferral or cancellation of required maintenance into future years. (TR 2779) He stated that the result will be lower fleet reliability and a building backlog of major maintenance. (TR 2779) He testified that to suggest a reduction of this nature and to ignore the physical requirements of the equipment does not make good engineering sense, nor does it adhere to sound maintenance practices of performing the work needed on critical equipment prior to failure. (TR 2779)
PEF witness Sorrick addressed witness Marz’s concern with the $5.3 million in emerging equipment costs and other items. (TR 2780-2781) He explained that some of the items included in that expense are repair of equipment damaged during forced outages, engineering studies, site infrastructure repairs, minor equipment repairs, execution of opportunity projects, parts repairs from previous outages, and major maintenance activities. (TR 2781) He stated that the $5.3 million is not a contingency expense as indicated by witness Marz. (TR 2781) Witness Sorrick explained that the purpose of this funding is to address both emergent issues that most certainly will occur as well as opportunity projects with the goal of allowing budgeted funding to be used where it was originally intended. (TR 2782) He testified that it is unfair to refer to it as a contingency expense because PEF’s experience with fleet operation indicates that this funding has been used most efficiently on the smaller projects and emergent projects. (TR 2782)
PEF witness Sorrick testified that the clean air equipment at CR4 includes $5.3 million for a precipitator that has changed somewhat based upon the latest condition assessment information. (TR 2782) He stated that only $1.1 million of the $5.3 million total work to be performed on the precipitator will be expensed, with the balance to be capitalized. (TR 2782)
PEF witness Sorrick discussed the changes to the Equivalent Forced Outage Rate (EFOR) at the Crystal River units. (TR 2783) He explained that investments in the generating equipment, such as major maintenance, improve performance of those assets, thus benefitting the customer. (TR 2783) He testified in response to OPC witness Shultz that in 2008 CR1, CR4 and CR5 EFOR did increase, but major maintenance activities were performed at CR1 during the last half of 2008 that improved the EFOR. (TR 2783) He advised that CR5 has improved after the spring outage on that unit, and CR4 is scheduled for major maintenance in 2010. (TR 2783) He contended that the improvements in unit performance that will result from maintenance investments in the equipment benefit the ratepayer. (TR 2783)
PEF witness Sorrick also addressed OPC witness Schultz’s assertion that unit availability declined for a majority of the units in 2008. (TR 2783) He explained that it is true on an aggregate basis, but the decline for the fossil fleet was less than 1 percent and the combined cycle fleet was less than 1.5 percent. (TR 2783) He testified that witness Schultz did not take into consideration that outages in order to address an equipment issue might make the unit more dependable in the longer term and ultimately reduce the overall costs to the customer. (TR 2783-2784) He stated that the nature of the Equipment Availability calculation does not account for such situations. (TR 2784)
PEF witness Sorrick disagreed with OPC witness Shultz that PEF’s power operation maintenance costs are not supported by the Company’s MFRs, testimony, or discovery responses. (TR 2784) He stated that PEF has described the nature of the planned expenditures and has shown that the need for these expenditures is driven by actual unit operations, which are in turn driven by demand for the Company’s product. (TR 2784) He added that unit operations over several years accumulate to trigger major maintenance requirements. (TR 2784) He testified that PEF has supported its maintenance costs by demonstrating this process. (TR 2784)
PEF witness Sorrick testified that the $4.6 million cost estimate for the Bartow Long Term Service Agreement (LTSA) is based upon a contract with Siemens Power Corporation. (TR 2784) He stated that PEF’s responses to OPC’s discovery have provided the information requested. (TR 2785) He noted that the specific information on the LTSA was provided in several places. (EXH 26, BSP 517-520; EXH 47, MFR Schedule C-41, p. 3 of 18; TR 2785) He testified that to disallow the costs of required maintenance because witness Schultz states the costs are not supported is both unfair and irresponsible. (TR 2785)
PEF witness Sorrick testified that OPC witness Schultz’s assertion that the work performed under the LTSA is infrequently performed is not true. (TR 2785) He noted that witness Schultz estimates that it would take 6 years of running around the clock to trigger this maintenance on a 12,500 hour maintenance interval. (TR 2785) Witness Sorrick calculated that if the unit ran around the clock, the maintenance interval would trigger every 1.4 years (12,500 hr interval/8,760 hr/yr = 1.4 years). (TR 2785) He stated that the units are actually expected to run an average of 5,900 hours over the next 3 years, which equates to a maintenance frequency of every 2.1 years, not every 6 years as witness Schultz stated in his testimony. (TR 2785)
PEF witness Sorrick testified that he has provided documentation for the $14.7 million increase for existing fleet maintenance in a number of documents. (TR 2786; EXH 26, BSP 500-501; EXH 26, BSP 517-526; EXH 26, BSP 534; EXH 46, BSP 1358 and CD; EXH 47, MFR Schedule C-41, p. 3 of 18) He stated that he:
. . . explained the concept repeatedly that the budget request is directly tied to the amount of maintenance required within the fleet. In many cases, PEF’s cost estimates are based on years of experience in maintaining our fleet of generation equipment. We have learned over the years that we are able to self perform much of the required maintenance at a lower cost than third parties so we do not always have an invoice or a quotation. However, we utilize our experience with the equipment and engineering judgment to develop cost estimates. These are the estimates included in my original testimony and in PEF’s MFRs.
(TR 2786-2787)
PEF stated that witness Sorrick provided preliminary budget information for 2011 and 2012 that shows the Company expects to spend about $177 million and $180 million, respectively, for power generation O&M. (TR 448-449; PEF BR 85) PEF argued that, contrary to intervenors’ assertions, the O&M request for the 2010 test year of $175 million is not inappropriately high or overstated. (PEF BR 85)
PEF argued that OPC witness Schultz’s suggestion that projected costs should be supported by the same level of detail and documentation that is available for actual, incurred costs is without merit. (PEF BR 85) PEF stated that detailed invoices and charge slips, available to support actual costs, will not be available for a projected cost. (PEF BR 85) PEF stated that it did present support for its projected costs. (PEF BR 85) PEF argued that for the LTSA for the Bartow plant, PEF explained the costs in MFR Schedule C-41, and in witness Sorrick’s direct testimony, while relevant portions of the LTSA were provided, which is a confidential contract. (TR 394; TR 2785; TR 2827-28; PEF BR 85).
OPC witness Shultz stated that the Company’s request appears excessive. (TR 1949) He testified that there was a limited amount of specifics regarding what the figures included. (TR 1949) He explained that the Power Operations O&M expense is $175 million after payroll taxes, employee benefits, and injuries and damages. (TR 1949) He stated that the real budget total is $201 million. (TR 1949) He contended that PEF witness Sorrick’s generic explanation of the benchmark variance of $53.1 million is not adequate justification for the $175 million identified by witness Sorrick. (TR 1949)
PEF witness Shultz testified that the $175 million request is a significant increase over the 2008 costs of $138 million and the 2007 costs of $127 million. (TR 1949; EXH 47, MFR Schedule C-6) He stated that the Company has not provided an adequate explanation nor has it justified the cost increase requested. (TR 1950) He noted the improvement in the EFOR for CR2. (TR 1950) He stated that PEF witness Sorrick discusses an improvement in the rate, but witness Shultz determined from discovery responses that in 2008, the rate increased for CR1, CR4, and CR5. (TR 1950) He stated that there are other increases as well. (TR 1950) He noted that unit availability declined for a majority of units in 2008. (TR 1950) He added that there are discussions about costs savings and efficiencies but no indication that they are reflected in the MFRs. (TR 1950) Witness Shultz recommended that Power Operations Maintenance Expense be reduced by $17,741,309 jurisdictional, as shown in his exhibit HWS-1, Schedule C-8. (TR 1950; EXH 170)
PEF witness Shultz explained that maintenance expense can fluctuate from year to year, making it inappropriate to base the rate request on one higher year. (TR 1951) He stated that the maintenance expense is projected to increase $19 million or 35 percent from $54 million in 2008 to $73 million in 2010, excluding company labor. (TR 1950) He testified that an adjustment is required to smooth out the cost to the ratepayers. (TR 1951)
PEF witness Shultz stated that one of the drivers of the increase is the adding of Clean Air Equipment at Crystal River Unit 4. (TR 1951) He expressed concern with a $15.1 million added cost for work that is typically done every nine years. (TR 1951) He stated that spreading the $15.1 million cost over 5 years reduces the 2010 cost by $12 million. (TR 1951) He also expressed concern with a $5.3 million precipitator, which he stated is a capital cost, not an expense. (TR 1951)
The next specific area discussed by witness Shultz is the $4.6 million cost estimate for 2010 maintenance under the Long Term Service Agreement (LTSA) discussed by PEF witness Sorrick. (TR 1951) Witness Shultz stated that OPC requested all supporting documentation for this cost. (TR 1951) He testified that the only response provided by PEF was a reference to MFR Schedule C-41. (TR 1951) He stated that the schedule provides only a generic explanation for the increase over the benchmark which was that the $4.6 million was the Company’s estimate for the work covered by the LTSA which included completion of two combustion inspections and two Balance of Plant Outages. (TR 1951) Witness Shultz testified that OPC again asked for additional information. (TR 1951-1952) He stated that the response explained that the inspection of the two units occurs every 12,500 hours. (TR 1952) He stated the $4.6 million in cost should be disallowed because it is only an estimate and is not supported. (TR 1952) He added that, because it is an infrequent cost, he is recommending that half be allowed in rates, resulting in a reduction of $2.3 million. (TR 1952)
The final item OPC witness Shultz addressed is the $14.7 million increase for existing fleet maintenance. (TR 1952) He stated that this item also was unsupported, except for the statement in MFR Schedule C-41, and a summary listing of the cost estimate. (TR 1952) He testified that the summary of the cost shows that the 2010 projections contain an overloading of maintenance expense. (TR 1952) He recommended that the $14.7 million be reduced by $7.25 million, or by one half, to smooth out the effect on the ratepayers. (TR 1952)
OPC argued that a fallacy in the Company’s case is that the selection of a number of projects that add up exactly to the amount of the overage does not constitute justification or even true explanation of the reason for the overage. (OPC BR 82) OPC argued that PEF’s testimony does not provide an adequate explanation and it does not justify the cost increase requested. (OPC BR 82) OPC noted that witness Sorrick admitted on the stand that overhaul expense for planned and unplanned outages, projected to be $53 million in 2010, was more than double the amount of any of the previous 4 years. (TR 434; OPC BR 82) OPC argued that there was no testimony whether the expense would stay at that level beyond the test year. (OPC BR 82)
OPC stated that PEF witness Sorrick admitted that the activities that were listed in MFR C-41, totaling $53.1 million in excess of the benchmark, were not intended to be comparisons to the same activities in the 2006 base year. (TR 442-443; OPC BR 83) OPC argued that the explanations in the MFR Schedule do not constitute justification of the numbers. (OPC BR 83)
FIPUG witness Marz stated that the 2010 test year steam and other production maintenance costs are $111.1 million, total Company. (TR 2304) He testified that the generation maintenance costs are overstated, with a 36 percent increase for the 2010 test year over the 2009 budget. (TR 2305) He stated that the corresponding four-year average for 2006 through 2009 is $40.6 million or 57 percent. (TR 2305; EXH 182)
FIPUG witness Marz stated that PEF witness Sorrick identified an accelerated outage at Crystal River 4 (CR4), for major boiler and turbine maintenance that will cost $9.3 million. (TR 2305) He testified that this one item accounts for 28 percent of the projected increase in steam generation maintenance costs. (TR 2305) He stated that the outage was not originally scheduled for the test year, but was moved up from a date beyond the test year. (TR 2306) Witness Marz noted that this type of outage occurs every nine years, as acknowledged by PEF. (TR 2306) As a result, he stated that the full cost should not be included in rates. (TR 2306) He testified that inclusion of the full amount treats it as if it occurs every year instead of every nine years. (TR 2306) He stated that only 11.1 percent or one-ninth should be recognized for ratemaking purposes. (TR 2306)
FIPUG witness Marz noted a $5.3 million increase for emerging equipment issues and other repairs. (TR 2307) He testified that his conclusion was that this amount was a contingency put in to preserve options. (TR 2307) He stated that in response to OPC Interrogatory 260, PEF stated that the money would be used for forced outage repairs or to enhance the fleet. (TR 2307; EXH 26, BSP 517-519)
FIPUG witness Marz recommended a $15 million reduction to Steam and other Generation maintenance expense. He testified that this is a 50 percent reduction in PEF’s projected increase from 2010 over 2009. (TR 2307) He stated that even with the reduction, the increase would still be 17 percent above the 2009 budget. (TR 2307-2308) His adjustments were included in Exhibit MJM-3. (TR 2308; EXH 183)
Affirm and the Navy did not address this issue in their briefs. AG stated that it supported OPC’s position but did not address the issue further. (AG BR 13) FRF stated that PEF's Power Operations Expense should be reduced by $17,741,309, but did not address the issue further. (FRF BR 60) PCS Phosphate agreed with and adopted the position of OPC. (PCS BR 11)
ANALYSIS
OPC recommended a total reduction of $21,650,000 system, $17,741,309 jurisdictional to PEF's 2010 generation O&M expense. (EXH 170, Schedule C-8) The reduction is comprised of three adjustments: $12 million for Clean Air Equipment at CR4, $2.3 million for one-half of the LTSA contract, and $7.35 to smooth out the cost of generation maintenance to the ratepayers.
First, OPC witness Shultz spreads a $15.1 million cost associated with the adaptation of Clean Air Equipment at Crystal River Unit 4 (CR4) over five years. (TR 1951) Although his recommended adjustment was based on 5 years, he stated that he believes such work is typically done every nine years. (TR 1951) The recommended treatment reduces the 2010 cost by $12 million. (TR 1951)
FIPUG witness Marz also testified that the maintenance occurs only once every nine years. He recommended that one-ninth of the amount be allowed in the test year.
According to PEF, major maintenance must be done on an interval basis for the fossil steam fleet, the combined cycle fleet, and the simple cycle combustion turbine fleet. (TR 2775) Considering the C4 outage in isolation does not account for the major maintenance requirements for the entire fleet. (TR 2777) It is important to minimize outages on base loaded units in order to minimize fuel costs to the customer. (TR 2778)
Staff believes that customers will benefit from the combined outage. Further, as described by PEF witness Sorrick, this type of maintenance is performed on an ongoing basis for the entire fleet, even though it might only occur at intervals for a specific unit. There is record evidence that customers benefit through reduced fuel costs. (TR 2778) Accordingly, staff does not recommend an adjustment for this item.
The second specific area discussed by OPC witness Shultz is the $4.6 million cost estimate for 2010 under the LTSA. (TR 1951) The basis for witness Shultz’s adjustment is that the cost is only an estimate and is not supported. (TR 1952) Additionally, because it is an infrequent cost, he is recommending that half be allowed in rates, resulting in a reduction of $2.3 million. (TR 1952)
The $4.6 million cost estimate for the Bartow LTSA is based upon a contract with Siemens Power Corporation. (TR 2784) Staff believes that sufficient information has been provided by PEF to support this cost. (EXH 26, BSP 517-520; EXH 47, MFR Schedule C-41, p. 3 of 18; TR 2785) Moreover, according to PEF witness Sorrick’s calculations, the units are actually expected to run an average of 5,900 hours over the next 3 years, which equates to a maintenance frequency of every 2.1 years, not every 6 years as witness Schultz stated in his testimony. (TR 2785)
Staff believes the cost for the LTSA is reasonable. The Bartow facility has four combustion turbines. (TR 374) Staff believes that OPC witness Shultz’s calculation showing the maintenance to be performed every 6 years is in error. Maintenance will occur every 2.1 years. (TR 2785) Thus, two units will be inspected each year. The cost includes inspection of two of the combustion units. (EXH 26, BSP 520) Therefore, staff believes the LTSA cost is appropriate.
The third item witness Shultz addressed is a $14.7 million increase for existing fleet maintenance. (TR 1952) He stated that this item also was unsupported, except by the statement in MFR Schedule C-41, and a summary listing of the cost estimate. (TR 1952) He testified that the summary of the cost shows that the 2010 projections contain an overloading of maintenance expense. (TR 1952) His recommended adjustment was to reduce the $14.7 million by one half, or by $7.35 million, to smooth out the effect on the ratepayers. (TR 1952)
PEF provided documentation for the $14.7 million increase for existing fleet maintenance in a number of documents. (TR 2786; EXH 26, BSP 500-501; EXH 26, BSP 517-526; EXH 26, BSP 534; EXH 46, BSP 1358 and CD; EXH 47, MFR Schedule C-41, p. 3 of 18) PEF witness Sorrick testified that the proposal of OPC witness Shultz to reduce power operations maintenance by $7.35 million to smooth out the costs being charged to the ratepayers would require the deferral or cancellation of required maintenance into future years. (TR 2779) He testified that to suggest a reduction of this nature and to ignore the physical requirements of the equipment does not make good engineering sense, nor does it adhere to sound maintenance practices of performing the work needed on critical equipment prior to failure. (TR 2779)
Preliminary budget information for 2011 and 2012 shows that the Company expects to spend about $177 million and $180 million, respectively, for power generation O&M. (TR 448-449; PEF BR 85) PEF argued that, contrary to intervenors’ assertions, the O&M request for the 2010 test year of $175 million is not inappropriately high or overstated. (PEF BR 85)
Staff notes that the basis for the OPC adjustment is that the costs are not supported. Staff agrees with PEF that the maintenance costs are supported by the record. The costs are ongoing in nature. Staff believes costs to the ratepayers should be minimized wherever possible, but not at the cost of deferring necessary maintenance.
Staff notes that the specific items identified and addressed in this issue, including those discussed below, account for $30.3 million of the variance above the benchmark. Staff believes that the benchmark is not a hard ceiling that cannot be exceeded. OPC witness Shultz recommends his adjustment essentially because the amount exceeds the benchmark, but witness Shultz does not take into consideration the necessity for the maintenance or the benefits to the ratepayers, such as reduced fuel costs. Although staff agrees it is important to smooth costs to ratepayers for non-recurring items, staff believes the costs are supported by record evidence. Accordingly, staff does not recommend further adjustments.
OPC witness Shultz also expressed concern with a $5.3 million precipitator, which he stated is a capital cost, not an expense. (TR 1951) However, he did not recommend an adjustment for this item.
PEF witness Sorrick testified that the clean air equipment at CR4 includes $5.3 million for a precipitator that has changed somewhat based upon the latest condition assessment information. (TR 2782) He stated that only $1.1 million of the $5.3 million total work to be performed on the precipitator will be expensed, with the balance to be capitalized. (TR 2782) Given PEF’s statement that there has been a change in this item, staff believes it is appropriate to make an adjustment. As a result, O&M expense should be reduced by $4,200,000 system, $3,981,138 jurisdictional. Plant in Service should be increased by $4,200,000 million system, $3,479,776 jurisdictional. Depreciation expense should be increased by $48,300 system, $41,680 jurisdictional, using a 2.3 percent composite depreciation rate for steam production as calculated by staff, and a half-year convention. The thirteen month average accumulated depreciation should be increased by $24,150 system, $19,706 jurisdictional.
FIPUG witness Marz noted a $5.3 million increase for emerging equipment issues and other repairs. (TR 2782) He testified that his conclusion was that this amount was a contingency put in to preserve options. (TR 2782) He stated that in response to OPC Interrogatory 260, PEF stated that the money would be used for forced outage repairs or to enhance the fleet. (TR 2782; EXH 26, BSP 517-519)
PEF witness Sorrick addressed witness Marz’s concern with the $5.3 million in emerging equipment costs and other items. (TR 2780-2781) He explained that “the purpose of this funding is to address both emergent issues that most certainly will occur as well as opportunity projects with the goal of allowing budgeted funding to be used where it was originally intended.” (TR 2782) He testified that it is unfair to refer to it as a contingency expense because PEF’s experience with fleet operation indicates that this funding has been used most efficiently on the smaller projects and emergent projects. (TR 2782)
Staff agrees with FIPUG witness Marz that this is a contingency expense. The Company has no specific maintenance or plant increases associated with this money. Its purpose is to spend it on whatever comes up, as the Company sees fit. There is no evidence that anything will arise in the test year. Staff believes, given the large increase in generation maintenance expense in the test year, ratepayers should not be asked to also pay for something that may or may not arise in the future. While there may be some cost in the future, it may well be offset by a decrease in the cost of other items.
Staff recommends that the $5.3 million in emerging equipment costs be removed. This results in an O&M reduction of $5,300,000 system, $5,023,817 jurisdictional.
Although FIPUG witness Marz addressed two specific areas of concern, the CR4 maintenance and the emerging equipment costs, his adjustment does not appear to reflect his recommended adjustments for CR4 maintenance or emerging equipment. (EXH 182, 183) Witness Marz recommended a $15 million reduction to Steam and other Generation maintenance expense. This is based on approximately 50 percent of the budget increase for 2010 over 2009 for Steam and Other Generation, which excluded nuclear. (TR 2307)
As discussed above, the specific items identified and addressed in this issue account for $30.3 million of the variance above the benchmark. FIPUG witness Marz based his adjustment, not on the items he addresses in testimony, but solely on the fact that the maintenance expense increased in 2010 over 2009. Staff does not recommend further adjustments for generation O&M expense.
The total adjustments recommended by staff are as follows:
|
Jurisdictional Increase/(Decrease) |
Plant in Service |
Accumulated Depreciation |
O&M Expense |
Depreciation Expense |
|
Emerging Equipment |
|
|
($5,023,817) |
|
|
Precipitator |
$3,479,776 |
$21,420 |
($3,981,128) |
$41,680 |
|
TOTAL |
$3,479,776 |
$21,420 |
($9,004,955) |
$41,680 |
CONCLUSION
Staff recommends that Plant in Service should be increased by $3,479,776 jurisdictional, Accumulated Depreciation should be increased by $19,420 jurisdictional, O&M expense should be decreased by $9,004,955 jurisdictional, and depreciation expense should be increased by $41,680 jurisdictional.
Should an adjustment be made to PEF's 2010 transmission O&M expense?
Recommendation:
Yes. Staff recommends a reduction to transmission O&M expense of $1,717,042 jurisdictional for vegetation management expense. Staff recommends no adjustment for expenses related to FERC 890, or for line bonding and grounding. (Marsh)
Position of the Parties
PEF:
No.
OPC:
Yes. Transmission vegetative management expenses should be reduced $1,717,043 due to the lack of justification for the increase over historical levels. Further, transmission bonding and grounding expense should be reduced $338,145 due to account for the fact that the proposed 2010 expense does not reflect that the cost is not incurred on an annual basis.
AFFIRM:
No position.
AG:
Yes. Support OPC’s position.
FIPUG:
Yes. PEF’s transmission expense should be reduced by $3.75 million. PEF has overstated the amount of this expense by including storm hardening activities, like vegetation management and tree trimming, which have been required by the Commission since 2006.
FRF:
Yes. PEF's Transmission expenses should be reduced by $2,055,188.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
PEF witness Oliver testified that approximately $6.9 million of the $10.3 million increase in transmission O&M expenses for 2010 relates to the FERC Order 890’s requirement to provide credits to transmission customers under the Open Access Transmission Tariff (OATT) for customer-owned integrated transmission facilities. (TR 2880) He stated that PEF must incur new costs to comply with FERC Order 890, and that the costs are recurring, incremental costs beyond PEF’s control. (TR 2880) He stated that expenses for customer credits associated with this compliance requirement are being budgeted for the first time in 2010. (TR 2880; EXH 28, BSP 567) Witness Oliver explained that customers expected to be eligible for credits have contracts for service, but will not actually be taking service under PEF’s OATT until late 2009. (TR 2880)
PEF witness Oliver stated that the remainder of the increase relates to O&M expenses for FERC Account No. 571 - Transmission Overhead Lines Maintenance, specifically $1 million for Line Bonding and Grounding and $2.75 million for Vegetation Management, offset by an approximately $0.35 million net decrease to other transmission FERC accounts. (TR 2880-2881) Witness Oliver asserted that the cost increases are reasonable on their face, because the transmission O&M expenses are $30,000, or less than 1 percent, above the Commission O&M benchmark cost. (TR 2881) He noted that the $30,000 increase excluded the $6.9 million PEF has requested to comply with FERC Order 890. (TR 2881)
PEF witness Oliver testified that, due to the high volume of lightning strikes in PEF's service territory, increased bonding and grounding on transmission lines is the most effective way to mitigate transmission outages and improve transmission reliability during storm season, which is generally the time of the year when electricity use is at its highest levels for PEF. (TR 2881) He explained that increased bonding and grounding spending resulted in improvements to transmission line performance. (TR 2881) Witness Oliver stated that in 2003 and 2004, there was a 28 percent and 40 percent improvement, respectively, in the performance of targeted lines. (TR 2881) He testified that bonding and grounding has been continued as part of PEF’s routine line maintenance program along with pole inspections and repairs. (TR 2881) He stated that increased funding is necessary to improve line performance on targeted lines. (TR 2881) He testified that bonding and grounding of a line is labor intensive as it requires working on one pole at a time for the length of the line, usually over the energized conductors. (TR 2882) Witness Oliver stated that bonding and grounding efforts take years to complete, so the level of funding in PEF’s rate request is needed now and for future years. (TR 2282)
PEF witness Oliver testified that vegetation management expenses are also part of FERC Account No. 571 - Transmission Overhead Lines Maintenance. (TR 2882) He explained that PEF’s transmission vegetation management program includes tree trimming, hand cutting, mowing, danger tree removal, proactive herbicide program and aerial patrols to assess system conditions. (TR 2882) He stated that an increase in vegetation management is the result of the 2005 Energy Policy Act that was passed in response to the 2003 blackout in the northeastern United States. (TR 2882) He testified that the blackout was in part attributed to trees growing into transmission lines. (TR 2882) He stated that in June of 2007, Standard FAC-003-1 was approved by NERC, which stipulates penalties of up to $1 million per day for violations of the standard on transmission lines greater than 200kV. (TR 2882-2883)
PEF witness Oliver testified that the focus of transmission vegetation management in 2007, 2008 and 2009 was on lines greater than 200kV to ensure compliance with the standard and to avoid significant penalties. (TR 2883) He stated that funding shifted to NERC line clearing from non-NERC line clearing. (TR 2883) He testified that the lower voltage lines were primarily cleared on an “as needed” basis to maintain safe, reliable operation, but were not cleared to the full extent that would normally be performed during cycle clearing. (TR 2883) He explained that the increase in vegetation management funding is needed for cycle clearing on lines less than 200kV. (TR 2883) He asserted that additional cost also arises from the significant capital investments that have been made to Florida’s transmission system over the last decade, resulting in added transmission lines and substations requiring vegetation management. (TR 2883)
OPC witness Shultz testified that he had a general concern with the significant increase in the budgeted dollars. (TR 1944) He stated that, based on the Company’s MFR Schedule C-4, the costs for transmission O&M increased from $31.3 million in 2005 to $35.2 million in 2008. (TR 1945) He stated that the 2009 budgeted cost is $35.1 million, but in 2010, the cost increased by $10.3 million to a total of $45.3 million. (TR 1945) He expressed concern with three areas: an increase of $6.9 million for added costs of FERC Order 890, an increase of $1 million for a line bonding and grounding program, and an increase of $2.7 million for vegetation management (TR 1945)
OPC witness Shultz testified that the FERC Order 890 is an estimate that is not based on historical costs. (TR 1945) He stated that there is no explanation for the bonding and grounding program in the Company’s filing, but that it appears that it is not an annual cost. (TR 1945) He testified that the vegetative management increase appears to coincide with the fact that the Company is in for a rate increase and ignores an potential cost savings resulting from this activity. (TR 1945)
OPC witness Shultz stated that the cost for vegetative management was $6.3 million in 2006, $6.9 million in 2007, $5.9 million in 2008 and budgeted at $6.6 million for 2009. (TR 1945; EXH 28, BSP 565) He noted that the cost in the projected test year is $9.3 million. (TR 1945) Witness Shultz testified that the amount in the test year is excessive when compared to prior years and the 2009 budget. (TR 1945) He stated that the increase in the tree trimming budget would have occurred in 2009 if it had been a requirement by the Commission. (TR 1945) He concluded that the 2010 increase is not justified. (TR 1946)
OPC witness Shultz made an adjustment of $1,717,043 jurisdictional for vegetative management (TR 1946; EXH 170, Schedule C-6) He stated that the adjustment assumes that the trimming will continue at the same level that the Company performed from 2006 through 2009. (TR 1946) He testified that the Company’s explanation that the additional trimming is required to comply with FERC and Commission standard does not support the requested increase. (TR 1946) He stated that there is no indication that the historical spending level was insufficient. (TR 1946)
OPC witness Shultz also made an adjustment of $338,145 jurisdictional ($500,000 x .67629) to normalize the line bonding and grounding expense. (TR 1946) He stated that the adjustment reflects an expense that occurs every other year. (TR 1946) Witness Shultz did not recommend an adjustment for FERC 890 expense as part of this issue. (TR 1947)
FIPUG witness Marz testified that FERC Account 571 is used for recording of expenses for maintenance of overhead transmission lines, including tree trimming and vegetation removal. (TR 2301) He stated that the test year included $11.8 million for this account. (TR 2301) Witness Marz testified that Account 571 costs increased by $3.8 million or 47 percent from 2009 to 2010 and are $44.5 million or 62 percent higher than the 2006-2009 average expenses. (TR 2303; EXH 181) He recommended a reduction of $3.75 million, resulting in adjusted expenses of $8.05 million. (TR 2301)
FIPUG witness Marz testified that tree trimming and vegetation management are not new undertakings, but date back to 2006 when a vegetation management program was established.[56] (TR 2302) He stated that PEF had already implemented an integrated vegetation management (IVM) program by 2006 that was approved later that year. (TR 2302) He added that the Commission approved the Company’s storm hardening plan in 2007.[57] (TR 2302) Witness Marz stated that the IVM program and storm hardening began well before 2010. (TR 2302) He stated that any increase in costs necessitated by the IVM program should have been reflected in costs as far back as 2006. (TR 2302) He testified that MFR Schedule C-6 reflects a substantial increase in maintenance of overhead lines beginning in 2007. (TR 2304)
FIPUG witness Marz questioned whether the Company actually implemented its IVM in 2006 and its storm hardening in 2007. (TR 2304) He stated that there should not be a spike in costs in 2010, as the costs should have already been reflected in PEF’s actual 2008 and budgeted 2009 costs. (TR 2304) He recommended that 2009 levels of expense be used for the test year as well. (TR 2304) He stated that this would reduce Account 571 by $3.75 million for 2010. (TR 2304)
FIPUG stated that PEF has overstated the amount of this IVM expense by including storm hardening activities, like vegetation management and tree trimming, which have been required by the Commission since 2006. (FIPUG BR 37)
Affirm and the Navy did not address this issue in their briefs. AG stated that it supports OPC’s position, but did not address the issue further. (AG BR 13) FRF stated that PEF's Transmission expenses should be reduced by $2,055,188, but did not address the issue further. (FRF BR 60) PCS Phosphate agreed with and adopted the position of OPC. (PCS BR 11)
ANALYSIS
There is a total increase of $10.3 million in transmission O&M expenses for 2010. (Oliver TR 2880) The increase is comprised of three different areas, net of a $0.35 million decrease to other transmission items. (Oliver TR 2880-2881) Those areas are vegetation management, the added costs of FERC Order 890, and PEF’s line bonding and grounding program.
As noted by PEF witness Oliver, a company can incur up to $1 million per day in penalties for violations of the 2005 Energy Policy Act on transmission lines greater than 200kV. (TR 2882-2883) As a result, PEF’s focus for transmission vegetation management in 2007, 2008, and 2009 was on lines greater than 200kV to avoid significant penalties. (Oliver TR 2883) Funding was shifted from lines not subject to the penalties to those that were, while lower voltage lines were not cleared to the full extent that would normally be performed during cycle clearing. (Oliver TR 2883) PEF now requests additional funds for clearing of the lower voltage lines. (TR 2883)
Vegetation management is not a new requirement. (Shultz TR 2910, 2911; Marz TR 2304) Vegetation management program was implemented in 2006, and storm hardening was implemented in 2007, both well before 2010. (Marz TR 2304) Witness Marz recommended a reduction of $3.75 million for 2010 to the transmission O&M expense. (TR 2304)
Staff agrees with the intervenor witnesses that increases in vegetation management costs are not due to new requirements. The testimony of PEF’s witness Oliver leads staff to the conclusion that certain line clearing was deferred in favor of clearing those lines that would potentially cause the Company to incur a substantial penalty. Staff notes, as pointed out by OPC witness Shultz, that vegetation management costs were less in 2008 than 2006. Staff believes PEF should have spent more in prior years on the tree trimming. PEF is now requesting additional funds to catch up.
The intervenor witnesses have differing amounts for the adjustment. Witness Shultz’s adjustment is based on allowing an increase to the 2009 budget amount of $6,554,550 to $6,750,000 for 2010. This results in a decrease of $2,550,000 system, or $1,717,042 jurisdictional. (TR 2911; EXH 170, Schedule C-6) On the other hand, FIPUG witness Marz reduced the 571 account by the entire amount of increase from 2009 to 2010. FIPUG’s adjustment of $3.75 million is greater than the amount of the vegetation management increase of $2.75 million noted by PEF witness Oliver. Staff notes that witness Marz based his reduction on the entire increase of Account 571 from 2009 to 2010, recommending that the entire increase be removed, not just the amount associated with vegetation management.
Staff believes that OPC witness Shultz’s adjustment is based on record evidence as to the budget associated with vegetation management. (EXH 28, BSP 565) Also, staff believes that the Company deferred maintenance on the lower voltage lines, as discussed by PEF witness Oliver. The ratepayers should not have to pay to catch up on that maintenance. Accordingly, staff recommends a reduction to transmission O&M expense of $1,717,042 jurisdictional for vegetation management expense.
PEF included an additional $6.9 million for FERC Order 890 costs, a new item that has not been budgeted for in the past. (Oliver TR 2880) As noted by PEF witness Oliver, the additional cost arises from a requirement that the Company provide customer credits under its OATT, something that PEF has not previously had to provide. (TR 2880)
OPC witness Shultz testified that the FERC 890 expense is not based on historical costs. (TR 1945) However, he did not recommend an adjustment as part of this issue. (TR 1947)
Staff does not believe an adjustment is warranted, and none has been recommended in this issue. PEF’s witness explained that the cost is new, so OPC witness Shultz is correct that it is not based on historical costs. Staff believes that is not a reason to deny a requested expense. Accordingly, staff recommends no adjustment for expenses related to FERC 890.
The final area is the line bonding and grounding program. PEF requested a $1 million increase for this program. (TR 2880) The record evidence shows that the program is necessary due in part to the to high volume of lightning strikes in PEF’s area, and is an effective way to mitigate storm-related outages. (Oliver TR 2881) It is a continuing part of PEF’s routine line maintenance. (Oliver TR 2881) The increased funding is necessary to improve line performance on targeted lines. (Oliver TR 2881) Bonding and grounding is labor intensive as it requires working on one pole at a time, and takes years to complete. (Oliver TR 2882)
OPC witness Shultz stated that bonding and grounding expense does not appear to be an annual cost. (TR 1945) He recommended an adjustment of $338,145 jurisdictional ($500,000 x .67629) to normalize the expense, by spreading over a two-year period. (TR 1946)
Staff notes that the OPC witness does not disagree with the necessity for line bonding and grounding. His adjustment is based on his belief that it is not an annual expense. Staff notes that PEF’s witness explained the need for the program and the fact that it will be ongoing for a number of years. (TR 2882) Staff believes this is a cost that benefits ratepayers through increased system reliability as explained by witness Oliver. (TR 2881) Accordingly, staff recommends no adjustment to the line bonding and grounding portion of the increase in transmission O&M expense.
CONCLUSION
Based on the above, staff recommends a reduction to transmission O&M expense of $1,717,042 jurisdictional for vegetation management expense. Staff recommends no adjustment for expenses related to FERC 890, or for line bonding and grounding.
Should an adjustment be made to PEF's 2010 distribution O&M expense?
Recommendation:
Yes. Staff recommends that distribution vegetation management O&M expense be reduced by $8,924,197 jurisdictional for the 2010 test year. (Marsh)
Position of the Parties
PEF:
No.
OPC:
Yes. Distribution vegetative management expense should be reduced $8,924,197 to account for PEF’s deferral of 2009 expenses into the test year. The Company’s proposed cost level is not representative of annual requirements to perform tree trimming and the adjustment accounts for that.
AFFIRM:
No position.
AG:
Yes. Support OPC’s position.
FIPUG:
Yes. PEF’s distribution expense should reduced by $13.9 million. PEF has overstated the amount of this expense by including storm hardening activities, like vegetation management and tree trimming, which have been required by the Commission since 2006.
FRF:
Yes.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
PEF witness Joyner testified that PEF has spent increased amounts of money on vegetation management since its last rate case in 2005, due to storm hardening requirements. (TR 3086) He stated that prior to 2005, PEF spent about $14 million per year on vegetation management, which was increased to about $19 million per year from 2006 to 2009. (TR 3086) He stated that the increase totaled about $21 million more over the four year period than was provided for under the 2005 rate case settlement. (TR 3086-3087)
PEF witness Joyner stated that the vegetation management plan for 2010 includes miles necessary to keep pace with a 3-year backbone cycle and complete the fifth year of a 5-year lateral cycle. (TR 3087) He testified that PEF was able to meet its 3-year backbone cycle in 2008 through increased spending in 2006 through 2009. (TR 3087) He stated that the number of miles needed to meet the 5-year lateral cycle is less than it would have been for 2010 due to the increased spending. (TR 3087) He testified that there was an acceleration of expenditures in 2010, the test year. (TR 722)
PEF witness Joyner testified that feeder backbones are 3-phase trunk lines that serve large numbers of customers and have the greatest impact on system reliability. He stated that backbones are relatively accessible because they are typically located along major roads. (TR 3088) He explained that feeder laterals branch from backbones and serve fewer customers (TR 3088) He stated that the laterals are not as accessible as backbones, such as lines that are located in back-lot areas where climbing and manual pruning is required. (TR 3088) He stated that feeder backbones and accessible laterals generally yield a higher reliability benefit per dollar spent than inaccessible lateral lines. (TR 3088)
PEF witness Joyner testified that the Commission’s storm hardening rule required an increased scope of work, but it did not provide the additional maintenance dollars above the amount received in the Company’s 2005 rate case settlement that are necessary to perform the work. (TR 3088) He stated, as a result, that tree pruning in all years has been prioritized based upon expected impact to system performance. (TR 3090) He asserted that PEF prioritized work to yield the maximum benefit for the money spent. (TR 3090) He testified that the requested $34.5 million for 2010 is necessary to meet regulatory requirements. (TR 3090) He stated that while costs could go down after 2010, the costs could also go up. (TR 3090)
PEF witness Joyner stated that OPC witness Shultz’s proposed $8.9 million reduction is arbitrary and does not address the manner in which distribution systems are maintained and operated. (TR 3089-3090) He testified that “unfounded reductions” to the needed funding would prevent PEF from meeting its regulatory requirements and impact PEF’s ability to provide safe and reliable service. (TR 3090)
PEF witness Joyner testified that the variance in costs discussed by FIPUG witness Marz is needed by PEF to meet the Commission’s 3/5 year requirement. (TR 3090) He stated that the removal of the $13.9 variance in FERC Account 593 for 2010 makes the amount equal to the 2009 budget. (TR 3090) The witness stated that the increased costs for 2010 as compared to 2006, are driven by such factors as increases to fuel and labor rates. (TR 3091) Witness Joyner asserted that PEF has taken measures to offset these rising costs. (TR 3091) He described measures such as the increased the level of system data, which reduces cost by allowing the Company to choose the most effective way to prune a particular area (for example, by machine or by hand). (TR 3092)
PEF argued that if the Commission disallows these expenses, PEF’s ability to provide safe and reliable electric service may be hampered. (PEF BR 94)
OPC witness Shultz stated that PEF provided no specifics for its $145 million distribution O&M expense except for $3.2 million for pole inspections and $34.4 million for vegetation management. (TR 1947) Witness Shultz testified that the benchmark comparison on MFR Schedule C-41 does not provide much in the way of explanation. (TR 1947) He stated that the 2008 distribution O&M was $120.6 million, compared to the $145 million in the 2010 test year. (TR 1947) He stated that the vegetation management accounts for $15.9 million of the increase and an additional $.8 million is attributable to pole inspection costs, leaving $8.5 million of the $24.4 million increase in distribution O&M unexplained. (TR 1947)
OPC witness Shultz testified that the Company’s historical trimming consisted of 3,419 miles in 2006, 4,303 miles in 2007 and 3,297 miles in 2008. (TR 1948) He stated that the 2009 budget is comparable to the 2007 expenditures. (TR 1948; EXH 31, BSP 585) He stated that the 2010 projected expense is based on trimming 5,080 miles. (TR 1948; EXH 31, BSP 587) He testified that the increase suggests that the Company did not perform the necessary trimming in the prior years and is trying to make up for it in the test year. (TR 1948) Witness Shultz asserted that the amount allowed in rates should be based on the annual trimming requirement, not on deferred costs. (TR 1948)
OPC witness Shultz recommended an adjustment of $8,924,197 jurisdictional for distribution vegetation management. (TR 1948; EXH 170, Schedule C-7) He explained that the adjustment was based on trimming of the 18,341 primary conductor miles over a five year period using the Company’s $5,538 cost per mile. He stated that he added an estimated $5 million for trimming of the remaining 7,297 miles of secondary conductors. (TR 1948) Witness Shultz did not recommend other adjustments for the additional increases in distribution O&M expenses. (TR 1949)
FIPUG witness Marz testified that FERC Account 593 is for recording of expenses for maintenance of overhead distribution lines, including tree trimming and vegetation removal. (TR 2301) He stated that the test year included $45.8 million for this account. (TR 2301) He recommended a reduction of $13.9 million, resulting in adjusted expenses of $31.9 million. (TR 2301) He stated the PEF witness Joyner attributed the increased costs to the additional cost of vegetation management to meet Commission directives for hurricane preparation and storm hardening. (TR 2301-2302)
FIPUG witness Marz testified that vegetation management is not a new undertaking, but dates back to 2006 when the vegetation management program was established.[58] (TR 2302) He stated that PEF had already implemented an integrated vegetation management (IVM) program by 2006 that was approved later that year. (TR 2302) He added that the Commission approved the Company’s storm hardening plan in 2007.[59] (TR 2302) Witness Marz stated that the IVM program and storm hardening began well before 2010. (TR 2302)
FIPUG witness Marz stated that any increase in costs necessitated by the IVM program should have been reflected in costs as far back as 2006. (TR 2302) He testified that MFR Schedule C-6 reflects a substantial increase in maintenance of overhead lines beginning in 2007. (TR 2304)
FIPUG witness Marz testified that Account 593 costs remained relatively constant from 2006 through the 2009 budgeted expenses, but a substantial increase was reflected for 2010. (TR 2303; EXH 181) He noted that the amounts PEF has recorded in these accounts have increased substantially for the test year. He stated that Account 593 costs remained relatively constant from 2006 through 2008, up to and including the budgeted 2009 expense, but in the test year, expenses rise from about $32 million in 2009 to over $45 million. (TR 2303). He advised that Account 593 expenses increased by $3.8 million (47 percent) from 2009 to 2010, and are $4.5 million (62 percent) higher than the 2006-2009 average expenses. (TR 2303)
FIPUG witness Marz questioned whether the Company actually implemented its IVM in 2006 and its storm hardening in 2007. (TR 2304) He stated that there should not be a spike in costs in 2010, because these costs should have already been reflected in PEF’s actual 2008 and budgeted 2009 costs. (TR 2304) He recommended that 2009 levels of expense be used for the test year as well. (TR 2304) He stated that this would reduce Account 593 by $13.9 million for 2010. (TR 2304)
FIPUG argued in its brief that its adjustment was made in order to make the test year more representative of the costs. (FIPUG BR 38)
Affirm and the Navy did not address this issue in their briefs. AG stated that it supported OPC’s position, but did not address the issue further. (AG BR 13) FRF stated “yes,” but did not address the issue further. (FRF BR 61) PCS Phosphate agreed with and adopted the position of OPC. (PCS BR 12)
ANALYSIS
According to PEF witness Joyner, vegetation management has been prioritized based upon the expected impact to system performance, and to yield the maximum benefit for the money spent. (TR 3089) He indicated that the Commission’s storm hardening rule required an increased scope of work, but it did not provide the additional maintenance dollars above the amount received in the Company’s 2005 rate case settlement. (TR 3088) Staff believes that the Company has limited the amount of money it has spent on vegetation management since it did not receive the requisite dollars.
FIPUG witness Marz testified that storm hardening is not a new undertaking, but dates back to 2006 when a vegetation management program was established. (TR 2302) According to witness Marz, PEF’s vegetation management program was approved in 2006, and its storm hardening plan was approved in 2007. (TR 2302) Staff agrees with FIPUG witness Marz that vegetation management is not a new requirement. As a result, staff believes increases in tree trimming should have occurred well before 2010 and to a greater extent than that indicated by PEF witness Joyner.
Witness Marz’s $13.9 reduction in distribution O&M expense is based on reducing the requested amount of expenses for the 2010 test year to the 2009 budgeted level. (EXH 181) While his testimony addresses the vegetation management, his adjustment encompasses the entire Account 593. He does not address the specifics for reducing any other items in the account beyond vegetation management.
On the other hand, OPC witness Shultz calculated his adjustment based on the number of miles to be trimmed. Staff believes this approach is more reasonable, because it targets the item the witnesses discuss, that is, the vegetation management.
OPC witness Shultz testified that the increase in tree trimming expense suggests that the Company did not perform the necessary trimming in the prior years and is trying to make up for it in the test year. (TR 1948) Witness Shultz asserted that the amount allowed in rates should be based on the annual trimming requirement, not on deferred costs. (TR 1948) Staff agrees. Staff believes the large increase in the number of miles to be trimmed is indicative of deferred maintenance.
OPC witness Shultz recommended an adjustment of $8,924,197 jurisdictional for distribution vegetation management. (TR 1948; EXH 170, Schedule C-7) His calculation is based on the trimming of the 18,341 primary conductor miles over a five-year period using the Company’s $5,538 cost per mile. He added $5 million for trimming of the remaining 7,297 miles that consist of secondary conductors. (TR 1948) Staff notes that 3,668 primary conductor miles would be trimmed each year over the five years, along with 1,459 miles of secondary conductors.
Staff does not believe ratepayers should pay for deferred maintenance. The adjustment recommended by OPC witness Shultz is based on a reasonable estimate of the vegetation management cost. Further, it allows for an increase over the 2009 budged amount for Account 593, even after the adjustment is made.
CONCLUSION
Staff recommends that distribution vegetation management O&M expense be reduced by $8,924,197 jurisdictional for the 2010 test year.
DROPPED.
What is the appropriate amount and amortization period for PEF's rate case expense for the 2010 projected test year?
Recommendation:
Staff recommends that rate case expense be set at $2,153,855 with a 4-year amortization period. The annual amortization amount should be $538,464 ($2,153,855/4). The Company's total requested rate case expense amount should be reduced by $633,145 ($2,787,000 - $2,153,855), and the annual amortization should be reduced by $855,036 ($1,393,500 - $538,464). (Marsh)
Position of the Parties
PEF:
The appropriate amount for rate case expense is $2,251,000 amortized over a two year period beginning January, 2010.
OPC:
Rate case expense should be reduced by $989,618 and the amount included in rate base should be reduced at least $2,787,000.
AFFIRM:
No position.
AG:
Support OPC’s position.
FIPUG:
Rate case expense should be amortized over 4 years. Rate case expense should be reduced by $989,618 and the amount included in rate base should be reduced at least $969,531.
FRF:
Rate case expense should be reduced by $989,618.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
PEF witness Toomey testified that the Company proposed to amortize rate case expenses over a two year period based on long-standing Commission practice. (TR 1663) He explained that MFR Schedule C-10 itemizes and details these expenses. (TR 1663; EXH 47, MFR Schedule C-10)
PEF witness Toomey stated in response to discovery that Commission practice is to amortize rate case expenses over a number of years that may vary. (EXH 45, BSP 2147) He cited a TECO case in which rate case expense was amortized over a two-year period. (EXH 45, BSP 2147) He stated that recent Commission practice has been to use specific amortization periods based on the circumstances of the specific case. (EXH 45, BSP 2147)
PEF argued that the amortization period for rate case expense should reflect the time period between one rate case and the next that is filed by a company. (PEF BR 116) PEF stated that the two-year period is appropriate for PEF given the period of rapid capital investment and expansion that the Company expects to enter. (PEF BR 116) PEF argued that the expected rapid capital expansion is similar to the early 1990s, when it was common for the Commission to approve two-year amortization periods.[60]
PEF stated that the intervenors argued for a four-year amortization period based on a recent Commission TECO order as support. (PEF BR 116; TR 1943-44; TR 1799-1800) PEF argued that it is different from TECO in terms of length of time between rate cases. (PEF BR 117) PEF stated that TECO had not been in a rate case proceeding for more than a decade, while only four years has passed since PEF’s last rate case, which was governed by a settlement. (PEF BR 117) PEF argued that it is entering a period of rapid capital investment that increases the likelihood of more frequent rate cases. (PEF BR 117)
PEF stated that OPC witness Schultz based his adjustment of the rate case expense on information that had not been updated. (EXH 45 BSP 2013; CONFIDENTIAL EXH 285; PEF BR 117) PEF argued that its discovery response demonstrates that PEF’s rate case expense was supported, justified, and estimated, where necessary, based on reasonable estimating tools. (EXH 45 BSP 2013; CONFIDENTIAL EXH 285; PEF BR 117)
OPC witness Shultz testified that PEF’s rate case expense is excessive. (TR 1943) He stated that the expense portion of the request should be reduced by $989,618. (TR 1943) He stated that the amount requested does not reflect the contractual terms of the consultants and lawyers. (TR 1943) He stated that the costs were overstated by $70,090 for consultants and by $697,500 for attorneys. (TR 1943) The total amount of rate case expense witness Shultz recommended was $2,019,410. (EXH 170, Schedule C-5)
OPC witness Shultz testified that the two-year amortization period is not consistent with ratemaking principles. (TR 1943) He noted that PEF cited a 1982 case as the basis for the amortization period, but ignored rulings in more recent years, as well as the length of time that typically extends between a company’s rate cases. (TR 1944) Witness Shultz recommended a five year amortization period to reflect the timing of rate case filings in recent years and to help reduce the immediate impact on ratepayers. (TR 1944)
OPC stated in its brief that rate case expense should be reduced by $989,618 and the amount included in rate base should be reduced by at least $2,787,000. (OPC BR 39)
FIPUG disagreed with PEF’s assertion that its proposal to amortize rate case expense over a period of two years is based on long standing Commission practice. (TR 1796; TR 1663; FIPUG BR 42) FIPUG stated that PEF relied on a Tampa Electric order from 1982. (FIPUG BR 42) FIPUG argued that the two-year amortization period is in direct contrast to long-standing Commission practice regarding rate case amortization. (FIPUG BR 42)
FIPUG noted in a recent Tampa Electric rate case order the Commission increased the amortization period from three to four years, consistent with several of the Commission’s recent rate cases. (FIPUG BR 42) FIPUG stated that PEF witness Toomey admitted that the four-year amortization was the more recent Commission practice. (TR 1800; FIPUG BR 42)
Affirm and the Navy did not address this issue in their briefs. AG stated that it supported OPC’s position, but did not address the issue further. (AG BR 13) FRF stated that rate case expense should be reduced by $989,618, but did not address the issue further. (FRF BR 61) PCS Phosphate agreed with and adopted the position of OPC. (PCS BR 12)
ANALYSIS
This issue addresses two areas of rate case expense: the dollar amount of the expense, and the amortization period. Rate case expense is shown on MFR Schedule C-10. PEF requested total rate case expense of $2,787,000 with a two-year amortization period, which yields a test-year amortization expense of $1,393,500. (EXH 47, MFR Schedule C-10) The rate base portion is addressed under issue 35, dealing with working capital.
PEF submitted updated support for its rate case expense showing projected costs through the end of the hearing. (CONFIDENTIAL EXH 285; EXH 45) Staff notes that Exhibit 285 is confidential, but all numbers referenced in this discussion are from the non-confidential portion of EXH 45.
Three areas of cost shown in the exhibit are higher than originally projected, while one is lower. The lower expense estimate is for legal costs. The Company initially projected legal costs of $2,000,000. The revised expense of $1,376,258 results in a reduction of $623,742 from the original filing, which is close to OPC’s recommended reduction of $697,000. (CONFIDENTIAL EXH 285; EXH45) Staff’s recommends the legal expense of $1,376,258 as projected by PEF be allowed.
The higher areas of expense include outside consultants, travel, and printing and administrative costs. The Company submitted a revised estimate for consultants that was $15,707 higher than originally shown in the MFRs. (CONFIDENTIAL EXH 285, Staff’s 22nd Interrogatories No. 267 – non-confidential portion) Staff reviewed the invoices and contracts supporting the costs. There was no support provided for the additional amount for the consultants. The accompanying production of documents did not include any invoices, estimates, or additional support for the increased amount for consultants. (CONFIDENTIAL EXH 285; EXH 45) OPC witness Shultz testified that consultant costs were overstated by $70,090. His position was unrebutted. Staff notes that this adjustment is a reduction to the original filing amount of $600,000, which would result in a consultant expense of $529,910. Staff believes the amount proposed by OPC is reasonable and should be allowed.
The explanation PEF provided for travel costs for the hearing is based on hotel costs of $130 per day, food of $50 per day, and 9 cars at $50 per day, for 14 days for 36 people. (EXH 285, Staff’s 22nd Interrogatories No. 267) Staff notes that the hearing was completed one day early. Further, staff does not believe all witnesses were present at the hearing the full time. However, costs were based on all 36 persons remaining at the hearing for a full 14 days. By dividing the travel expense associated with the hearing of $107,820 (EXH 285; EXH 45) by 14 days, one day less of hearing would result in a reduction of $7,701. Further, staff believes hotel expenses of $130 per day and $50 per day for meals are excessive for Tallahassee. The Company did not submit any reservation confirmations, hotel names, or other documentation in support of its request. Staff does not believe the Company has justified the additional travel expense. The amount originally requested of $110,000 should be allowed.
The only explanation given for the printing costs is that it was for printing of rate inserts and cost of service. (EXH 285; EXH 45) No other explanation has been provided for the additional cost. Staff reviewed the invoices and other supporting documentation provided by the Company. (EXH 45, BSP 2170-2249; EXH 285) Staff believes there is sufficient support for the cost of printing that the Company requested. Therefore, the entire printing cost of $137,687 should be allowed.
Table 73-1
Rate Case Expense
|
|
Original Filing MFR C-10 |
OPC Recommended Adjustment |
Company Updated Filing |
Difference from original filing |
Staff recommended amount |
||||
|
Legal Services |
$2,000,000 |
($697,500) |
$1,376,258 |
($623,742) |
$1,376,258 |
||||
|
Outside Consultants |
$600,000 |
($70,090) |
$615,707 |
$15,707 |
$529,910 |
||||
|
Travel |
$110,000 |
0 |
$121,426 |
$11,426 |
$110,000 |
||||
|
Printing & Administrative |
$77,000 |
0 |
$137,687 |
$60,687 |
$137,687 |
||||
|
Total expense |
$2,787,000 |
($767,590) |
$2,251,077 |
$535,922 |
$2,153,855 |
||||
Source: EXH 47 MFR Schedule C-10; Shultz testimony TR 1943; EXH 170, Schedule C-5; CONFIDENTIAL EXH 285, Staff’s 22nd Interrogatories No. 267 – non-confidential portion.
PEF witness Toomey and OPC witness Shultz disagreed over the proper amortization period for rate case expense. PEF asked for two years, while OPC recommended a five-year amortization. PEF argued that it is entering a period of rapid capital investment that increases the likelihood of more frequent rate cases. Witness Shultz raised a concern about the impact on ratepayers, thus recommending a five-year amortization period. The only support offered for the two-year amortization is a case that occurred in 1982, as pointed out by PEF and FIPUG.
Staff notes that in recent years, the four-year amortization has been reflected in a number of cases, including the TECO and Peoples Gas cases.[61] In both cases, OPC argued for a five-year amortization period, while the companies argued for lesser amortization periods. Staff does not believe either party gave sufficient support to vary from the four-year amortization period that has been used recently by this Commission. Further, the four-year amortization is supported by FIPUG. Staff does not believe PEF has provided sufficient evidence to vary from established practice. Given the differences among the parties, the four-year period falls between the high and low amortization periods and is consistent with recent Commission practice. Staff believes a four-year amortization is appropriate.
CONCLUSION
Based on the above, staff recommends that rate case expense be set at $2,153,855 with a 4-year amortization period. The annual amortization amount should be $538,464 ($2,153,855/4). The Company's total requested rate case expense amount should be reduced by $633,145 ($2,787,000 - $2,153,855), and the annual amortization should be reduced by $855,036 ($1,393,500 - $538,464).
Should an adjustment be made to bad debt expense for the 2010 projected test year? (Category 2 Stipulation)
Approved Stipulation:
No.
What adjustments, if any, should be made to the 2010 projected test year depreciation expense to reflect revised depreciation rates, capital recovery schedules, and amortization schedules resulting from PEF's depreciation study?
Recommendation:
Staff recommends that the 2010 projected test year depreciation expense be reduced by $124,115,709 jurisdictional ($138,786,891 system), to reflect revised depreciation rates, capital recovery schedules, and amortization schedules resulting from PEF's depreciation study. (Marsh, P. Lee)
Position of the Parties
PEF:
No adjustment should be made to PEF’s depreciation expense as reflected in its 2009 Depreciation Study.
OPC:
Depreciation expense requested by PEF should be reduced by $113,112,961.
AFFIRM:
No position.
AG:
Progress's allowed depreciation expense should be reduced by $113,112,961 as explained by Jacob Pous.
FIPUG:
The adjustments recommended by Intervenors should be made. See discussion contained in Issues 8 - 13.
FRF:
PEF's allowed depreciation expense should be reduced by $113,112,961.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
OPC included its discussion on this issue in Issues 8 through 16. (OPC BR 90) Affirm and the Navy did not address this issue in their briefs. FIPUG stated that the adjustments recommended by the intervenors should be made, based on its discussion in Issues 8 through 13. (FIPUG BR 42) FRF stated that PEF's allowed depreciation expense should be reduced by $113,112,961, but did not address the issue further. (FRF BR 61) PCS Phosphate agreed with and adopted the position of OPC. (PCS BR 12)
ANALYSIS
Staff calculated composite depreciation rates for each of the six functional areas of plant. Those rates are based staff’s recommendations in Issues 8 through 13. The composite rates are:
Steam Production 2.3 percent
Nuclear Production 2.3 percent
Other Production 3.1 percent
Transmission 2.2 percent
Distribution 2.6 percent
General 5.1 percent
Using these factors and the monthly plant balances shown on MFR schedule B-8, staff calculated the depreciation expense for the 2010 projected test year using the composite rates.
CONCLUSION
Staff recommends that the 2010 projected test year depreciation expense be reduced by $124,115,709 jurisdictional ($138,786,891 system) to reflect revised depreciation rates, capital recovery schedules, and amortization schedules resulting from PEF's depreciation study.
What is the appropriate amount of depreciation and fossil dismantlement expense for the 2010 projected test year?
Recommendation:
The appropriate retail amount of depreciation expense is $233,768,932. The appropriate system annual provision for dismantlement is $3,845,221, and the retail annual accrual amount is $3,113,889. (Marsh, P. Lee, Springer)
Position of the Parties
PEF:
PEF’s requested level of depreciation and dismantlement expenses for the 2010 projected test year of $354,755,000 and $3,114,000, respectively, are appropriate. PEF updated its dismantlement costs in response to Staff’s Interrogatory No. 319. The updated cost is higher than in PEF’s original filing, however PEF does not seek to recover this increase. PEF believes its fossil dismantlement accrual is appropriate and reasonable given the inherent uncertainty and volatility with regard to inflation and scrap value assumptions as well as the time frame between dismantlement filings.
OPC:
The appropriate depreciation expense for PEF for 2010 is $322,500,632. OPC’s position on the level of fossil dismantlement expense is reflected in Issue 19.
AFFIRM:
No position.
AG:
Support OPC’s position.
FIPUG:
The adjustments recommended by Intervenors should be made. See discussion contained in Issues 8 - 13, 17, 19 - 20.
FRF:
The appropriate depreciation expense for PEF for 2010 is $322,500,632. The FRF's position on fossil dismantlement is stated at Issue 19.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
OPC stated that the appropriate depreciation expense for PEF for 2010 is $322,500,632. OPC’s position on the level of fossil dismantlement expense is reflected in Issue 19. OPC addressed the issue under earlier issues. (OPC BR 91)
Affirm and the Navy did not address this issue in their briefs. FIPUG stated that the adjustments recommended by the intervenors should be made, based on its discussion in Issues 8 – 13, 17, 19 - 20. (FIPUG BR 42) FRF stated that the appropriate depreciation expense for PEF for 2010 is $322,500,632. FRF's position on fossil dismantlement is included at Issue 19. (FRF BR 61) PCS Phosphate agreed with and adopted the position of OPC. (PCS BR 12)
ANALYSIS
The depreciation expense is a fallout number. Based on staff’s recommended adjustments in Issues 24, 69, and 75, the projected retail 2010 Depreciation and Amortization Expense is $233,772,556. (See Schedule 3)
The System Annual Accrual amount for fossil dismantlement is $3,845,221 ($3,113,889 jurisdictional) as contained in Issue 19.
CONCLUSION
Staff recommends that the appropriate retail Accumulated Depreciation and Amortization for the December 2010 projected test year is $233,768,932. The appropriate system annual provision for dismantlement is $3,845,221, and the retail annual accrual amount is $3,113,889.
What is the appropriate amount of nuclear decommissioning expense for the 2010 projected test year? (Category 1 Stipulation)
Approved Stipulation:
The appropriate amount if $0. (AFFIRM did not affirmatively stipulate this issue, and took no position.)
What adjustments, if any, should be made to the amortization of End of Life Material and Supplies inventories? (Category 2 Stipulation)
Approved Stipulation:
No adjustments should be made.
What adjustments, if any, should be made to the amortization of the costs associated with the last core of nuclear fuel? (Category 2 Stipulation)
Approved Stipulation:
No adjustments should be made.
Should an adjustment be made to taxes other than income taxes for the 2010 projected test year?
Recommendation:
Yes. Taxes other than income taxes for the 2010 projected test year should be increased by $86,813 for an adjusted total of $129,673,813. (Slemkewicz)
Position of the Parties
PEF:
No adjustment to taxes other than income taxes for 2010 is necessary based on PEF’s original filing of $129,587,000.
OPC:
No position.
AFFIRM:
No position.
AG:
No position.
FIPUG:
No position.
FRF:
Agree with OPC.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
This is a fallout issue. Based on staff’s recommendations in Issues 24 and 88, taxes other than income taxes for the 2010 projected test year should be increased by $86,813 for an adjusted total of $129,673,813. (See Schedule 3)
Is it appropriate to make a parent debt adjustment as per Rule 25-14.004, Florida Administrative Code?
Recommendation:
Yes. Jurisdictional income tax expense should be decreased by $14,487,526 ($23,833,265 system) to reflect the parent debt adjustment required by Rule 25-14.004, F.A.C. (D. Buys)
Position of the Parties:
PEF:
No. It is not appropriate to make a parent-debt adjustment. The equity contributions made to PEF by the parent were from equity issuances at the parent, not debt. Equity issued in 2008, 2009 and 2010 at the parent will be greater than contributions made to PEF in 2009 and 2010.
OPC:
No position.
AFFIRM:
No position.
AG:
Yes. Adopt OPC’s position.
FIPUG:
Yes.
FRF:
Yes.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
In its post-hearing brief, PEF asserted that no intervenor witness filed any testimony and no intervening party presented any evidence on this issue. (PEF BR 69) PEF argued that the evidence demonstrates that no parent debt was used to make equity contributions to PEF. (PEF BR 69) PEF maintained that a parent-debt adjustment does not apply in this case because the parent company invests only equity in its subsidiaries. (PEF BR 69) PEF argued that no equity contributions were made to PEF until 2009, and all contributions expected to be made in 2009 and 2010 will be made from funds generated from common equity issuances at Progress Energy. (PEF BR 69; EXH 39, BSP 1403-1404) PEF argued that Rule 25-14.004, F.A.C., applies when an actual parent-subsidiary relationship exists and a consolidated income tax return is filed. (PEF BR 69) PEF argued that the presumption that a parent’s investment in a subsidiary was made in the same ratios that exist in the parent’s capital structure is rebuttable. (PEF BR 69)
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.
Staff believes that 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. Since 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. As of June 30, 2009, Progress Energy had $3.35 billion of long-term debt outstanding. (EXH 39, BSP 1442) The equity ratio for Progress Energy was 42.4 percent as of December 31, 2008. (EXH 39, BSP 1434)
Staff believes that PEF has not demonstrated that the interest on the debt on its books can be attributed to any source other than the general funds of the parent which is used to fund PEF’s operations. (TR 2249) Staff believes the record shows that no equity contributions were made to PEF until 2009. (EXH 39, BSP 1396) The projected equity infusion from Progress Energy to PEF in 2009 is $640 million. (EXH 39, BSP 1396) However, staff believes that PEF has not met its burden of proof to demonstrate its claim that “. . . all contributions made and expected to be made by Progress Energy to PEF in 2009 and 2010 will be from funds generated from common equity issuances at Progress Energy.” (PEF BR 69; EXH 39, BSP 1403-1404)
In a prior rate case involving Indiantown Company, Inc., the Commission ordered that a parent debt adjustment was required.
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.[62]
In Docket No. 080317-EI, the Commission also applied the parent debt adjustment in the TECO rate case and concluded that TECO did not effectively rebut the presumption that a parent debt adjustment should be applied pursuant to Rule 25-14.004, F.A.C.[63]
Staff acknowledges that none of the intervening parties proffered testimony regarding the parent-debt adjustment. However, staff believes that the lack of testimony by the intervening parties does not constitute support for PEF’s argument to not make a parent-debt adjustment pursuant to Commission rules. Evidence in the record that Progress Energy maintains a significant amount of debt at the parent level was not rebutted. (EXH 39, BSP 1410-1414, 1442-1444) The fact that Progress Energy files a consolidated tax return was also uncontroverted. (EXH 47, MFR Schedules C-26, C-27, and D-2) Staff believes that PEF has not met its burden to show that the debt of the parent is not invested in the equity of its subsidiary and that PEF has not effectively rebutted the presumption that a parent debt adjustment should be applied pursuant to Rule 25-14.004, F.A.C.
Staff believes that the parent debt adjustment should be applied in this case, and the elements of the computation should be based on the projected test year capital structures of Progress Energy and PEF. In PEF’s response to Staff’s Nineteenth Set of Interrogatories, Number 212 (EXH 39, BSP 1403-1404), PEF provided the following financial information necessary to make a parent debt adjustment for the 2010 test year in accordance with Rule 25-14.004, F.A.C.
Capital Structure of the Parent
Long-Term Debt $3,717,224,000 39.64%
Short-Term Debt $315,994,000 3.37%
Common Equity $5,345,190,000 56.99%
Total Capitalization $9,378,408,000 100.00%
Cost of Debt of the Parent
Weighted average cost of long-term debt for Progress Energy 7.515%
Cost of short-term debt for Progress Energy 4.50%
Weighted average cost of long-term and short-term debt 7.288%
Applicable Consolidated Tax Rate 38.575%
Equity Dollars of the Subsidiary
Equity dollars of PEF, excluding retained earnings: $1,971,076,000
Staff’s calculation of the system income tax reduction is as follows:
Debt Ratio of parent .4301
Debt Cost Rate of parent x .07288
= .0313456
Consolidated Tax Rate x .385750
= .0120915
Subsidiary Equity x $1,971,076,000
Parent Debt Adjustment = $23,833,265
In MFR Schedule C-4, page 16, PEF calculated a jurisdictional separation factor for income taxes of 0.60787. Applying this factor to the parent debt adjustment calculated above results in a jurisdictional adjustment of $14,487,526 ($23,833,265 x 0.60787).
CONCLUSION
PEF has not effectively rebutted the presumption that a parent debt adjustment should be applied pursuant to Rule 25-14.004, F.A.C. Further, the appropriate subsidiary equity amount to be used in the calculation is the projected test year equity of $1,971,076,000. Accordingly, the appropriate jurisdictional adjustment is a reduction of income tax expense in the amount of $14,487,526 ($23,833,265 system).
Should an adjustment be made to Income Tax expense for the test year?
Recommendation:
Yes. Total Income Tax expense should be increased by $110,041,251 resulting in a total income tax expense of $152,984,251 for the 2010 projected test year. (Davis, Slemkewicz)
Position of the Parties
PEF:
Yes. Based on the adjustments to reduce rate case expense by $269,000 and A&G office supplies and expense by $1,157,000 (jurisdictional) as explained in the Rebuttal Testimony of Peter Toomey Exhibit PT-17, an adjustment should be made to increase income tax expense by $550,000 based on the statutory income tax rate of 38.575%. Therefore, with this adjustment, income tax expense is $45,040,000.
OPC:
No position.
AFFIRM:
No position.
AG:
Agree with OPC’s position.
FIPUG:
Any adjustment is a fall out of other adjustments.
FRF:
Agree with OPC that this would be a fallout of decisions on other issues.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
This is a fallout issue. PEF proposed an initial Income Tax expense of $44,490,000 (MFR Schedule C-2 p5), but agrees that reductions to expenses made by the commission will increase the Income Tax expense based on the statutory income tax rate of 38.575 percent. (PEF BR 17)
The intervenors either take no position on this issue or agree that it is a fall out issue based on the outcome of other adjustments made in this case.
ANALYSIS
The Income Tax expense is a result of other adjustments made by the Commission. Based on staff’s recommendations, the requested total income tax expense of $42,943,000 should be increased by $110,041,251 resulting in an adjusted total Income Tax expense of $152,984,251.
Amount Requested $42,943,000
Staff Adjustments: 110,041,251
Total Income Tax Expense $152,984,251
CONCLUSION
The Income Tax expense for the test year should be $152,984,251.
Is PEF's requested level of Operating Expenses in the amount of $1,249,372,000 for the 2010 projected test year appropriate?
Recommendation:
No. The appropriate level of Operating Expenses for the 2010 projected test year is $1,160,521,768. (Slemkewicz)
Position of the Parties
PEF:
No. PEF’s requested level of Operating Expense of $1,249,372,000 must be adjusted to reduce A&G Office Supplies and Expense and Rate Case Expense. With these adjustments, the level of Operating Expense is $1,248,488,000.
OPC:
No.
AFFIRM:
No position.
AG:
No. Adopt OPC’s position.
FIPUG:
No. The adjustments recommended by Intervenors should be made.
FRF:
No.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
This is a fallout issue. Based on staff’s recommendations, the appropriate level of Operating Expenses for the 2010 projected test year is $1,160,521,768. (See Schedule 3)
Is PEF's projected net operating income in the amount of $268,546,000 for the 2010 projected test year appropriate?
Recommendation:
No. The appropriate Net Operating Income for the 2010 projected test year is $489,497,232. (Slemkewicz)
Position of the Parties
PEF:
No. PEF’s net operating income must be adjusted to reflect the decrease in operating expense of $876,000 as explained in Issue No. 83. With this adjustment, the projected net operating income is $269,422,000.
OPC:
No.
AFFIRM:
No position.
AG:
No. Adopt OPC’s position.
FIPUG:
No. The adjustments recommended by Intervenors should be made.
FRF:
No.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
This is a fallout issue. Based on staff’s recommendations, the appropriate net operating income for the 2010 projected test year is $489,497,232. (See Schedule 3)
Has PEF appropriately accounted for affiliated transactions? If not, what adjustment, if any, should be made?
Recommendation:
Yes. PEF has appropriately accounted for affiliated transactions. Staff recommends that no adjustment should be made. (Marsh)
Position of the Parties
PEF:
Yes, PEF has appropriately accounted for affiliate transactions. There are no adjustments necessary.
OPC:
No. The commission should make two general adjustments to account for PEF's failure to protect retail ratepayers from non jurisdictional transactions.
Excessive profitability (return on investment) of affiliated non-regulated operations indicates that PEF is not fairly allocating costs to these operations. All related costs and revenues of the operations should be treated above the line for ratemaking. This would increase net operating income by $8.6 million. In order to properly allocate administrative and general and general plant to the City of Tallahassee's interest in the Crystal River nuclear plant, the Commission should reduce plant and associated accumulated depreciation and property taxes for a net plant reduction of at least $1.8 million. Retail test year A&G expense should be reduced by $6.3 million.
AFFIRM:
No position.
AG:
No. Adopt OPC’s position.
FIPUG:
No. PEF has failed to appropriately recognize the value of the use of its name by its non regulated operations.
FRF:
No.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
PEF did not file testimony that directly addresses this issue.
PEF argued that PEI, PEF’s parent company, has divested the great majority of its non-regulated utility businesses since 2005, as noted by OPC witness Dismukes. (TR 2249; PEF BR 110) The Company stated that in 2008, approximately 0.1 percent of PEI’s revenues came from non-regulated businesses. (TR 2249; PEF BR 110) PEF noted that witness Dismukes did not make any recommendations with respect to PEF’s affiliate transactions. (TR 2245-50; PEF BR 110) PEF stated that while witness Dismukes discusses affiliate transactions, she did not find any improper affiliate allocations with respect to PEF. (TR 2245-2248; PEF BR 111)
PEF argued that OPC witness Dismukes spent a significant portion of her testimony discussing non-regulated operations although those expenses are not part of PEF’s base rate request. (PEF BR 111) PEF stated that non-regulated activities and their associated expense are recorded “below-the-line” and as a result do not impact the Company’s revenue requirement request. (PEF BR 111) The Company noted that Rule 25-6.1351(2)(g), F.A.C., 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.” (PEF BR 111)
PEF addressed OPC witness Dismukes’ recommendation that the Commission move all the revenues, expenses, and investment associated with these non-regulated operations above the line for ratemaking purposes. (TR 2262; PEF BR 111) PEF argued that the Commission must reject this recommendation, because it does not have legal authority to regulate non-regulated operations. (PEF BR 111) PEF stated that a search of Commission orders revealed no authority for witness Dismukes’ recommendation. (PEF BR 111) PEF argued governance costs for non-regulated operations are properly assigned to the non-regulated operations as explained by PEF witness Toomey and in PEF’s responses to OPC Interrogatory No. 402 and OPC Request for Production No. 250. (TR 1805-1806; EXH 282; PEF BR 111-112)
OPC witness Dismukes testified that cost allocations to affiliates should be frequently reviewed to determine that the Company’s regulated operations are not subsidizing the non-regulated operations. She stated that the arms-length bargaining of a normal competitive environment is not present in transactions with affiliates. (TR 2245) She asserted that there is an incentive to misallocate or shift costs to regulated companies so that the non-regulated companies can reap the benefits. (TR 2246) The witness stated that the Commission’s rules set forth the criteria to be followed by electric utilities for affiliate transactions.[64] (TR 2246) She testified that it is the utility's burden to prove that its costs are reasonable. (TR 2248)
OPC witness Dismukes stated that the Company offers numerous products and services that are not regulated or tariffed by the Commission. (TR 2250) She explained that the revenues and costs for these products and services are recorded below-the-line for ratemaking purposes. (TR 2250) She advised that there is an incentive to shift costs to the regulated operations, thus yielding higher profits for PEF and its parent company PEI. (TR 2250) She stated that the Commission should ensure that the regulated operations of PEF do not subsidize the non-regulated operations. (TR 2250-2251)
OPC witness Dismukes testified that the Commission does not have rules governing the costs charged between regulated and non-regulated operations of electric utilities. (TR 2251) She stated that the Commission can utilize the same principles embodied in its affiliate transactions rules as guidelines for examining the relationship between the Company’s regulated and non-regulated operations. (TR 2251)
OPC witness Dismukes noted that PEF offers over 20 different products and services that are not regulated by the Commission. (TR 2251; EXH 151) She described several services available to residential customers. (TR 2254) She explained that the HomeWire service covers the repair costs on selected residential electrical wiring components. (TR 2254) She noted that for $3.95 per month, the service includes $500 worth of covered repairs, such as outlets, switches, dimmers, fuses, breakers, inside wiring or building-mounted electric meter housing. (TR 2254) Witness Dismukes stated that within the total non-regulated operations, the HomeWire service generated the most revenue at $8.1 million followed by Power Quality Services (surge protection) at $7.0 million. (TR 2256) She also noted among others the Company’s surge protection and a water heater repair service. (TR 2254)
OPC witness Dismukes testified that in 2007 non-regulated operations produced $22.5 million in revenue, in 2008 $18.5 million in revenue, in 2009 revenues are projected at $20.9 million, and in 2010 revenues are projected at $16.7 million. (TR 2255; EXH 151) The witness stated that the projected revenue amounts appear to be understated as the Company had revenue in several categories for the first two months of 2009, but did not show any revenue in these categories for 2009 and 2010. She calculated that projected revenue for 2009 and 2010 be on the order of $21.5 million, and $22.5 million, respectively (TR 2255)
OPC witness Dismukes testified that PEI, the parent company of PEF, has approximately 68 subsidiaries and affiliates. (TR 2248) She stated that PEI’s non-regulated businesses have declined significantly. (TR 2249) Witness Dismukes noted that non-regulated revenues represented 21.4 percent of PEI’s consolidated revenue in 2005, 8.8 percent in 2006, to 0.2 percent in 2007, and 0.1 percent in 2008. (TR 2249) She stated that this is indicative of PEI’s strategy to divest most of its noncore assets. (TR 2249)
OPC witness Dismukes advised that there are approximately 47 persons that attribute time to the non-regulated operations of PEF as well as PEC. (TR 2257) She stated that of these 47 employees, 15 are sales representatives, 8 provide back office support, 7 are field coordinators, 6 provide technical support, and the remainder provide programming, IT, and accounting support. (TR 2257) She noted that the revenues and expenses associated with PEF’s non-regulated operations are recorded below-the-line, and any capital required for the non-regulated operations is booked to Nonutility Property. (TR 2257)
OPC witness Dismukes testified that the Company provided the amount of expenses (by account) allocated, assigned, or otherwise charged to its non-regulated operations for only two accounts, 417001 [sic] and 4210701. (TR 2257; EXH 151) She explained that these accounts include revenues and expenses applicable to operations which are nonutility in character but nevertheless constitute a distinct operating activity of the enterprise as a whole. (TR 2257-2258) She stated that no detail was provided regarding the types of expense charged to the non-regulated operations, making it difficult to examine or evaluate the reasonableness of the expenses recorded below-the-line. (TR 2258)
OPC witness Dismukes expressed concern regarding the type of costs that have been assigned to the non-regulated operations. (TR 2258) She stated that only the direct costs and allocated customer service employee payroll costs are charged to these non-regulated operations and thus removed from PEF’s expenses recorded above-the-line. (TR 2258) She stated that charges to non-regulated businesses by PEF are accomplished one of two ways, direct charges that are expensed as incurred on the books of the non-regulated business, or allocated, which is used only for customer service employee payroll costs by PEF. (TR 2259)
OPC witness Dismukes expressed her belief that there are common overhead costs that have not been assigned to the non-regulated operations. (TR 2259) She stated that the Company did indicate that some governance costs from Progress Energy Service Company were allocated to the non-regulated operations. (TR 2259; EXH 45, BSP 2110-2111) She testified that the overhead costs include: Administrative and General Salaries, Office Supplies and Expense, Outside Services, Property Insurance, Injuries and Damages, Employee Pensions and Benefits, Franchise Requirements, Regulatory Commission Expenses, General Advertising Expenses, Miscellaneous General Expenses, and Rents. (TR 2259)
OPC witness Dismukes examined the return on net investment earned by the Company’s non-regulated operations as a gauge of whether or not the costs have been properly assigned or allocated. (TR 2260) She testified that the Commission should be concerned about the attribution of costs between the Company’s regulated and non-regulated operations to the extent the return on investments appears abnormal. (TR 2260)
OPC witness Dismukes stated, based upon the data supplied by the Company for revenues, expenses, and net investment of the non-regulated operations, the non-regulated segment of PEF earned a return of 109 percent in 2007, 131 percent in 2008, 176 percent projected for 2009, and 92 percent projected for 2010. (TR 2261; EXH 151) She testified that she calculated imputed revenues for 2009 and 2010 based on amounts she believes are understated; the imputed revenues produce a return on net investment of 188 percent in 2009 and 212 percent in 2010. (TR 2261) She stated that such high returns on investment are abnormal and that those returns strongly suggest that the costs attributed to the non-regulated operations are seriously understated. (TR 2261)
OPC witness Dismukes testified that there are substantial benefits to PEF’s non-regulated operations being associated with the regulated company. (TR 2260) She stated that these benefits include the use of Progress Energy’s name, logo, reputation, goodwill, and corporate image; association with a large, financially strong, well-entrenched electric company; use of Progress Energy’s personnel; and, use of Progress Energy’s facilities. (TR 2260) She testified that all of these benefits were developed as a result of the regulated operations. (TR 2260) She stated that the non-regulated operations obtain these significant intangible benefits by being associated with the regulated utility operations at no cost. (TR 2260)
OPC witness Dismukes recommended that the Commission treat non-regulated revenues, expenses and investment above-the-line for rate setting purposes. (TR 2262) She stated that the Company has failed to demonstrate that costs have been properly allocated to these non-regulated operations. (TR 2262) She developed an adjustment to net operating income by using the return on rate base recommended by OPC witness Woolridge of 7.5 percent. (TR 2262) She testified that the difference between the allowed net operating income and the achieved net operating income, grossed up for income taxes, is the amount of revenue that should be moved above-the-line for rate setting purposes. (TR 2262) She recommended an adjustment to net operating income of $8.6 million. (TR 2262; EXH 151)
Affirm and the Navy did not address this issue in their briefs. AG stated that it adopts OPC’s position, but did not address the issue further. (AG BR 14) FRF stated “no” but did not address the issue further. (FRF BR 62) PCS Phosphate agreed with and adopted the position of OPC. (PCS BR 13)
FIPUG argued in its brief that PEF has failed to appropriately recognize the value of the use of its name by its non-regulated operations. (FIPUG BR 43) FIPUG stated that PEF’s unregulated operations receive substantial benefits due to their association with PEF. (FIPUG BR 43) FIPUG noted that PEF witness Toomey testified that the unregulated entities have an advantage over competitors in marketing their services. (TR 1808; FIPUG BR 43) FIPUG stated that the benefits include “the use of Progress Energy’s name, logo, reputation, goodwill, and corporate image; association with a large, financially strong, well-entrenched electric company; use of Progress Energy’s personnel; and use of Progress Energy’s facilities.” (FIPUG BR 43) FIPUG argued that all of the benefits were developed as a result of the regulated operations., but the non-regulated operations obtain these intangible benefits of being associated with the regulated utility operations at no cost. (TR 2260; FIPUG BR 43)
FIPUG supported the recommendation of OPC that PEF be required to treat the revenues, expenses, and investment from non-regulated operations above the line for rate setting purposes. (FIPUG BR 43) FIPUG stated that another alternative would be to assess a royalty fee for the intangible benefits of the non-regulated operations. (FIPUG BR 43-44)
ANALYSIS
As noted by both PEF and OPC witness Dismukes, PEI has divested the great majority of its non-regulated utility businesses since 2005. (TR 2249; PEF BR 110) Approximately 0.1 percent of PEI’s revenues came from non-regulated businesses in 2008. (TR 2249; PEF BR 110)
PEF did address OPC witness Dismukes’ recommendation that the Commission move all the revenues, expenses, and investment associated with these non-regulated operations above the line for ratemaking purposes. (TR 2262; PEF BR 111) PEF argued that the Commission must reject this recommendation, because it does not have legal authority to regulate non-regulated operations. (PEF BR 111)
Staff agrees with PEF that non-regulated activities and their associated expense are recorded “below-the-line” and, as a result, do not impact the Company’s revenue requirement request. (PEF BR 111) As noted by the Company, Rule 25-6.1351(2)(g), F.A.C., 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.” (PEF BR 111)
Staff notes that the basis for OPC witness Dismukes’ belief that costs are not properly allocated is that the profit percentages have been large for non-regulated services. (TR 2261) However, no evidence was provided that supports the allegation that specific costs were misallocated. No examples of a specific cost that was misallocated was provided. OPC witness Dismukes acknowledged that some governance costs for non-regulated operations are assigned to the non-regulated operations. (TR 1805-1806; TR 2259; EXH 45 and 282; PEF BR 111-112)
Staff also notes that the non-regulated transactions are audited by Commission staff auditors. One of the stated objectives on the PEF audit was to review intercompany charges to and from affiliated companies and non-regulated operations to determine if an appropriate amount of costs were allocated pursuant to Rule 25-6.1351, F.A.C. (EXH 208, p. 2) Based on the evidence, staff believes that the Company is following the correct methodology for allocation of its non-regulated costs.
FIPUG supports OPC’s recommended adjustment. Thus, staff has not addressed FIPUG’s arguments separately.
OPC included the allocation of administrative and general costs to the City of Tallahassee’s interest in the Crystal River nuclear plant in its position. This is addressed in Issue 24.
CONCLUSION
PEF has appropriately accounted for affiliated transactions. Therefore, staff recommends that no adjustment should be made.
What is the appropriate projected test year revenue expansion factor and the appropriate net operating income multiplier, including the appropriate elements and rates for PEF? (Category 2 Stipulation)
Approved Stipulation:
The appropriate projected test year revenue expansion factor is 61.207% and the appropriate net operating income multiplier is 1.63381.
Is PEF's requested annual operating revenue increase of $499,997,000 for the 2010 projected test year appropriate?
Recommendation:
No. The appropriate annual operating revenue increase for the 2010 projected test year is $48,089,265. (Slemkewicz)
Position of the Parties
PEF:
Yes. The requested increase of $499,997,000 is appropriate, subject to the adjustments to net operating income and rate base described herein.
OPC:
No. Required annual operating revenues for the 2010 projected test year are ($35,038,000). PEF’s retail rates should be reduced to reflect this.
AFFIRM:
No position.
AG:
No. This requested increase is excessive, especially under the current economic conditions. Progress does not need additional increases in order to maintain its profitability and meet the future electric needs of its customers. Under these circumstances, such a request is not in the public interest.
FIPUG:
No. Required annual operating revenues for the 2010 projected test year are ($35,038,000). PEF’s retail rates should be reduced to reflect this.
FRF:
No. This increase is excessive and unnecessary to enable PEF to provide adequate and reliable service and also unnecessary to enable PEF to attract needed capital. Granting PEF's requested increase would result in rates that are unfair, unjust, unreasonable, and contrary to the public interest.
NAVY:
No position.
PCS:
No. PCS Phosphate agrees with and adopts the position of the OPC that required retail revenues for the 2010 projected test year should be a reduction of $35,038,000 and that rates should be reduced accordingly.
Staff Analysis:
This is a fallout issue. Based on staff’s recommendations, the appropriate annual operating revenue increase for the 2010 projected test year is $48,089,265. The following schedule shows the calculation of the operating revenue increase.
|
Calculation of Annual Operating Revenue Increase December 31, 2010 Test Year |
||
|
|
||
|
|
PEF |
STAFF |
|
Rate Base (Issue 38) Rate of Return (Issue 48) |
$6,238,617,000 x 9.21% |
$6,305,359,052 x 8.23% |
|
Required NOI Adjusted Achieved NOI (Issue 84) |
$574,577,000 (268,546,000) |
$518,931,050 (489,497,232) |
|
NOI Deficiency Revenue Expansion Factor (Issue 86) |
$306,031,000 x 1.63380 |
$29,433,818 x 1.63381 |
|
Total Operating Revenue Increase |
$499,997,000 |
$48,089,265 |
COST OF SERVICE AND RATE DESIGN
Has PEF correctly calculated revenues at current rates for the projected test year?
Recommendation:
No. Revenues at current rates for the projected test year should be increased from $1,448,466,000 to $1,580,567,000, or by $132,101,000 as shown in PEF’s response to Staff Interrogatory No. 136 (EXH 41, BSP 1574-1575), to account for the Bartow Repowering Project (BRP) base rate increase approved by the Commission in Order No. PSC-09-0415-PAA -EI. (A. Roberts)
Position of the Parties
PEF:
Yes. PEF appropriately calculated revenues using test period billing determinants as developed from the sales forecast filed with its March 2009 filing.
OPC:
No position.
AFFIRM:
No position.
AG:
No position with respect to the revenue calculation for 2010 in PEF's original case filed in March 2009. However, the Attorney General objects to consideration of the revised sales forecast filed on August 31, 2009, to the consideration of the jurisdictional cost study based thereon, and to any other consideration of the revised forecast with respect to this issue and to any other issue impacted by Progress's revised sales forecast.
FIPUG:
No position.
FRF:
Consistent with its Statement of Basic Position above, the FRF has "No position" with respect to the revenue calculation for 2010 in PEF's original case filed in March 2009. However, the FRF objects – with respect to this issue and to any other issue impacted by PEF's revised sales forecast filed on August 31, 2009 – to consideration of the revised sales forecast.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the FIPUG.
Staff Analysis:
PARTIES’ ARGUMENTS
PEF basic position is that the revenues submitted in their original March 2009 filing were appropriately calculated for the 2010 projected test year.
OPC, FIPUG, Navy and PCS have taken no position on this issue. The AG and FRF do not take a position with respect to the revenues filed in PEF’s original filing, but objects to using the revised sales forecasts filed by the company on August 31, 2009.
ANALYSIS
Staff believes PEF did not correctly calculate revenues at current rates for the projected test year. The initial revenue calculations submitted in the MFR Schedule E-13c excluded revenues received from the BRP, which went into base rates on July 1, 2009. In response to Staff’s Interrogatory No. 136 (EXH 41, BSP 1574-1575), the company provided revised calculations to include revenues received from the Bartow Repowering Project. The revision of revenue calculations increased PEF projected revenues from $1,448,466,000 to $1,580,567,000, a difference of $132,101,000. In witness Slusser’s deposition, he agreed that the BRP revenues should be included in the revenue calculations at current rates for the projected test year. (EXH 318)
While the AG and FRF do not object to the revenue calculations, they state in their post-hearing briefs that they object to the use of the revised sales forecast filed by PEF on August 31, 2009 (AG BR 15; FRF BR 63). However, since PEF has stricken all reference to the revised sales forecast from the record, it is no longer an issue in this case. (TR 4031-4032)
CONCLUSION
Revenues at current rates for the projected test year should be increased from $1,448,466,000 to $1,580,567,000, or by $132,101,000 as shown in PEF’s response to Staff Interrogatory No. 136 (EXH 41, BSP 1574-1575), to account for the Bartow Repowering Project base rate increase approved by the Commission in Order No. PSC-09-0415-PAA-EI.
Is PEF's proposed separation of costs and revenues between the wholesale and retail jurisdictions appropriate?
Recommendation:
Yes, PEF’s proposed separation of costs and revenues between the wholesale and retail jurisdictions is appropriate. (Laux)
Position of the Parties
PEF:
Yes. PEF’s proposed separation of costs and revenues between wholesale and retail jurisdictions is appropriate for the jurisdictional cost of service study.
OPC:
No position.
AFFIRM:
No position.
AG:
No position with respect to the jurisdictional separation cost study for 2010 in Progress's original case filed in March 2009. However, the Attorney General objects to consideration of the revised sales forecast filed on August 31, 2009, to the consideration of the jurisdictional cost study based thereon, and to any other consideration of the revised forecast with respect to this issue and to any other issue impacted by Progress's revised sales forecast.
FIPUG:
No position.
FRF:
Consistent with its Statement of Basic Position above, the FRF has "No position" with respect to the jurisdictional separation cost study for 2010 in PEF's original case filed in March 2009. However, the FRF objects – with respect to this issue and to any other issue impacted by PEF's revised sales forecast filed on August 31, 2009 – to consideration of the revised sales forecast, to the consideration of the jurisdictional cost study based thereon, and to any other consideration of the revised forecast.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the FIPUG.
Staff Analysis:
PARTIES ARGUMENTS
Upon the withdrawal of PEF’s revised sales forecast, none of the parties challenged PEF’s 2010 jurisdictional separation cost study methodology.
ANALYSIS
This issue addresses PEF’s proposed separation of costs and revenues between the wholesale and retail jurisdictions. Staff reviewed the jurisdictional separation methodology incorporated in the jurisdictional cost study that was filed in Section E of PEF’s MFRs. Staff believes that the methodology is appropriate and that the methodology was consistently applied to forecasted 2010 costs and revenues.
CONCLUSION
Staff recommends that the Commission find that PEF’s proposed separation of costs and revenues between the wholesale and retail jurisdictions is appropriate.
What is the appropriate Cost of Service Methodology to be used to allocate base rate and cost recovery costs to the rate classes?
Recommendation:
The appropriate methodology is 12 Coincident Peak (CP) and 25 percent Average Demand (AD) for production plant costs, which reflects a change from PEF’s current 12 CP and 1/13 AD methodology. Transmission plant costs should continue to be allocated according to the 12 CP methodology. (Webb)
Position of the Parties
PEF:
The appropriate cost of service methodology is “12 CP and 50 percent AD” method for allocating production capacity costs and the 12 CP method for allocating transmission costs.
OPC:
No position.
AFFIRM:
12 CP and 1/13th Average Demand.
AG:
No position.
FIPUG:
The Commission should continue to use the 12CP and 1/13th AD cost of service methodology. It should not adopt the cost of service methodology PEF proposes, 12CP and 50 percent AD, because this methodology fails to follow cost causation principles. If the Commission does decide to replace the 12CP and 1/13th AD method, it should adopt the Average and Excess (A&E) method described in witness Pollock’s testimony. The summer/winter coincident peak method described by witness Pollock should be used to allocate transmission plant costs.
FRF:
No position.
NAVY:
Summer/winter coincidence peaks should be used to allocate fixed production costs. If the Commission elects not to utilize a summer/winter peak coincident peak allocation the results of the cost of service study that utilizes a 12 coincident peak study with a 1/13 weighted to energy should be used.
PCS:
PCS Phosphate agrees with and adopts the position of FIPUG. The Commission should require PEF to continue to use the 12CP and 1/13th AD (“average demand” or “energy”) cost allocation method.
Staff Analysis:
Background:
The purpose of a cost of service study is to form a cost basis for establishing revenue requirements for each rate class. To accomplish this, a cost of service study performs three activities. First, it functionalizes costs into production, transmission, distribution, customer and administrative/general categories. Second, these functionalized costs are separated into classifications based on the utility service being provided. There are three principal classifications of costs: (1) demand costs, which are costs that vary with the kilowatt (kW) demand imposed by the customer; (2) energy costs, which are costs that vary with the energy or kilowatt-hours (kwh) used; and (3) customer costs, which are costs that are directly related to the number of customers served. Finally, the costs are allocated among the rate classes, with the goal that the share of cost responsibility borne by each class approximates the costs to provide service to that class.
Typically, the only point of contention on the cost of service methodology deals with the treatment of production demand costs in the cost of service study. PEF submitted three cost of service studies in this proceeding. The Commission requires an investor-owned utility to file, at a minimum, a cost of service study consistent with the methodology approved in the utility’s last rate case. As required by the MFRs, PEF filed a cost of service study allocating production demand cost on a 12 Coincident Peak (CP) and 1/13th Average Demand (AD), or energy, method. Under the 12 CP and 1/13th AD method, approximately 92 percent, or 12/13, of the production demand classified costs are allocated on a 12 CP basis, and approximately eight percent, or 1/13th, is allocated on an average demand, or energy basis. CP is the maximum peak demand of the class which occurs at the time of the system peak.
The term “12 CP” refers to the average of each rate class’s 12 monthly CP demands in the projected test year. Average demand or energy is simply the relative kWh usage by class. This has been the method most often relied upon by the Commission for Florida’s investor-owned electric utilities. In addition, PEF filed two variations of its approved methodology. Both allocate more of the production costs on average demand or energy. The 12 CP and 25 percent methodology allocates 75 percent of demand costs on peak demand and 25 percent on energy. The 12 CP and 50 percent methodology, which PEF is supporting in this docket, allocates production costs evenly between peak demand and energy. While the Commission approved a 25 percent average demand allocation for Tampa Electric, moving to a 50 percent energy allocation would represent a change in Commission policy. In addition to the three cost allocation methodologies proposed by PEF, the Navy proposed a fourth methodology, a Summer/Winter peak methodology which would allocate production costs on the highest summer and winter peak months.
PARTIES’ ARGUMENTS
PEF
PEF argued that the appropriate methodology is the 12 CP and 50 percent AD. (PEF BR 122) PEF believed that it provides an appropriate classification and allocation of production plant to the rate classes in a manner reflecting the planning and operation of power plants in an era of higher fuel costs, stricter emissions requirements, and emphasis on providing clean, efficient generation. The use of 50 percent AD allocation rather than the 1/13th (or approximately 8 percent) better apportions production capacity costs in the manner by which customers realize benefits, which is on an energy basis. (PEF BR 123)
PEF’s proposed cost of service study does not affect the total dollars collected by PEF when compared to the 12 CP and 1/13th study, but simply changes allocation, or the way those dollars are collected from the various rate classes. A greater energy allocation shifts costs away from low load factor customers, such as residential and small commercial customers, to larger commercial and non-firm customers, who have a greater energy responsibility relative to their peak load responsibility.
Witness Slusser testified that an increase in the allocation on average demand is warranted because of the greater extent that energy considerations bear in the incurrence of production capacity costs. (TR 1495) In addition, witness Slusser stated that PEF’s increased investment in generation with higher up-front costs and lower fuel costs results in a benefit for customers that grows with each additional energy unit. (TR 1497-1498) As the benefits to customers grow, so should the cost allocation. (TR 1498) In Exhibit WCS-3, witness Slusser provided a cost listing of generation resources required to meet peak demand only. (EXH 113) He relied on this exhibit to illustrate his contention that PEF has not installed the cheapest technology solely for the purpose of meeting peak demand, but has instead, installed cleaner, more efficient, and more expensive units for the purpose of lowering overall operating costs. (TR 1498-1499)
Witness Slusser testified that allocating 50 percent of PEF’s production capacity costs on class energy responsibility better matches the costs with benefits for customers. (TR 1498) He estimated that approximately 50 percent of PEF’s embedded investment in generating facilities as of 12/31/2008 was made for reasons other than serving peak demand. This resulted in half of the embedded generating capacity costs going toward achieving lower fuel costs. (EXH 113) Although PEF is proposing the adoption of the 12 CP and 50 percent AD methodology, in Slusser’s direct testimony, he states that the 12 CP and 25 percent AD methodology has merit for inclusion in PEF’s filings because it has been recommended by both PEF and TECO in recent years, and because it is a compromise between the Commission prescribed 12 CP and 1/13th energy weighting and that of the “Equivalent Peaker” resultant energy weightings of 50 percent for PEF and 70 percent for TECO. (TR 1499, 1500) The Commission recently approved the 12 CP and 25 percent AD cost of service methodology for TECO in Docket No. 080317-EI.[65]
PEF previously filed for a 12 CP and 25 percent AD cost of service methodology in Docket Nos. 000824-EI and 050078-EI, both of which were settled by a stipulation which included retention of the 12 CP and 1/13th methodology. PEF states that the greatest change in circumstances since those filings in 2000 and 2005 has been what the utility terms a dramatic increase in fuel prices: a 2.024 cents per kWh fuel charge to customers on January 1, 2000, as compared to a 3.918 cents per kWh on January 1, 2005, and a 5.933 cents per kWh currently. (EXH 41, BSP 1582) As fuel prices increase, the utility adjusts its generation mix to include more high capital cost, low fuel cost generation, providing customers increasing benefits over time. Examples of current generation projects supporting this assertion include: (1) build out of combined cycle technology generation at Hines Energy Complex, (2) repowering and application of combined cycle technology at the Bartow Power Station, (3) upgrading and replacement of the steam generator at the Crystal River nuclear plant, and (4) pre-construction for new nuclear generation in Levy County. (EXH 41, BSP 1583)
In response to intervenor testimony supporting the Average and Excess Cost Allocation Methodology as an alternative to the 12 CP an 1/13th AD, witness Slusser elaborated on the shortfalls of this approach. The A&E methodology allocates a portion of the production and transmission costs on the system’s average load factor. The remaining costs are allocated on the difference between a class’s maximum demand and its average demand (Excess demand). (TR 4042-4043) Witness Slusser argued that employing a class’s non-coincident demand as an allocator for production costs does not reflect the utility’s actual power supply capacity requirement, which is based on a class’s load that is coincident with monthly peaks. Witness Slusser argued that employing a class’s non-coincident demand as an allocator for production costs does not reflect the utility’s actual power supply capacity requirement, which is based on a class’s load that is coincident with monthly peaks. In his rebuttal testimony, witness Slusser provided two examples of why the A&E methodology was inappropriate. (TR 4043-4044)
AFFIRM
AFFIRM witness Klepper testified that the Commission should continue to use the 12 CP and 1/13th AD cost of service methodology that it has used for many years. (AFFIRM BR 2) He asserts that the Commission must choose the methodology that best accomplishes the objective of matching costs and benefits to customer rate classes. (TR 2287) The underlying objective for generation investment planning is reliably serving load, making it inappropriate to weight energy usage disproportionately when allocating fixed production capacity costs. (AFFIRM BR 3; TR 2288)
Witness Klepper noted that a significant portion of the generation related capacity costs that are being allocated today arose from the generation related investment strategies of thirty years ago, and thus should continue to be allocated on the same basis as the decisions to make those investments, namely, the 12 CP and 1/13th AD method. AFFIRM asserts that the foundation of generation planning does include consideration of fuel costs and environmental considerations, as asserted by PEF, but this planning primarily consists of reliably serving the expected loads of the utility. (TR 2288) Further, witness Klepper stated that the proposed methodology is not supported by economic principles and does not result in prices that reflect related costs. He states that when customers receive a price signal that reflects more than full cost, they have an incentive to forego energy use that would be economically productive. Price signals for the consumption of electric energy would not be accurately reported to customers under PEF’s proposed methodology. (TR 2289)
FIPUG
FIPUG supported retaining the 12 CP and 1/13th AD cost of service allocation methodology because it appropriately allocates production investment, and properly recognizes that load duration drives a utility’s investment decision. (FIPUG BR 46-48, TR 3172) Although witness Pollock believed that a summer/winter peak methodology would better reflect cost-causation, FIPUG recommended retaining the current 12 CP and 1/13th AD cost methodology. (TR 3160, 3221) Witness Pollock raised four primary objections to PEF proposal to increase the average demand allocation: (1) PEF’s strong summer and winter peaks drive the need for capacity; (2) PEF’s proposal is not a cost causation model but a “costs follow benefits” approach; (3) average demand does not drive the higher cost for capacity; (4) capacity is undervalued in PEF’s analysis; and (5) Coincident peak is double counted. (TR 3160)
Summer/Winter Peaks. In critiquing PEF’s proposed 12 CP and 50 percent AD, witness Pollock pointed out that cost causation is primarily a function of peak demand. (TR 3164) He demonstrates that PEF has strong summer and winter peaks and experiences its tightest margins during the summer/winter peak months, and therefore the other months are irrelevant for determining capacity requirements. (TR 3165-3166, EXH 189) He asserted that planned outages which normally occur during the spring and fall do not make these months important in determining capacity needs because PEF’s reserve margins, adjusted for scheduled outages range from 27 percent to 47 percent for non-peak months. (TR 3166)
Cost causation. FIPUG also took issue with PEF’s argument that PEF’s proposal follows a cost causation approach to cost allocation. (TR 3167) Rather than a cost causation approach to cost allocations, witness Pollock argues that PEF uses a “costs follow the benefits” approach. He argued that according to PEF, the 12 CP and 50 percent AD method is designed to match production plant costs relative to the benefits received, but that PEF fails to apply this standard in recognizing that some variable costs provide reliability benefits. (TR 3160) Witness Pollock discusses the inconsistency in terms of the provision of ancillary services which are necessary to support load and provide for reliable operation of the system, but do not produce energy sold to consumers. (TR 3169-70) He noted that contingency reserves require a utility to either maintain additional generation capacity on-line at all hours, or to commit additional capacity not actually needed to provide service to end-use customers. This requirement for contingency reserves results in higher fuel costs. Yet, PEF did not consider these higher fuel costs as capacity related, resulting in an inconsistent application of the costs follow benefits philosophy. (TR 3170-3171)
Average demand. Witness Pollock also disagreed with the 12 CP and 50 percent AD methodology because allocating base and intermediate plant (which have lower fuel costs) on an energy basis is at odds with the utility planning process. He asserted that the determining factor in deciding what kind of plant gets built is the expected load factor, or the number of hours the plant is expected to run. (TR 3172) Annual usage does not cause plant investment. (TR 3172) FIPUG maintains that the 12 CP and 1/13th method appropriately allocates production investment and properly recognizes that load duration drives a utility’s investment decision because the higher costs of base load and intermediate capacity are not caused by average demand. (TR 3160, 3167-3169, 3172)
Capacity undervalued. Pollock stated that the proposed methodology also under values capacity and double-counts coincident demand. (TR 3174-3175) In Exhibit JP-4, witness Pollock showed that the PEF is spending less than 20 percent of capital for reasons other than maintaining system reliability, and that allocating 50 percent of the costs on average demand is therefore inappropriate. (EXH 191) He also alleged that the 12 CP and 50 percent methodology is flawed because it allocates production plant costs partially on average demand and partially on coincident peak demand. Double-counting occurs because average demand is also a component of the coincident peak demand. (TR 3174-3175)
While FIPUG supported the retention of the 12 CP and 1/13th AD cost methodology, should the Commission choose to move to a more energy weighted approach, witness Pollock suggests the Commission adopt the Average and Excess (A&E) method in lieu of the method proposed by PEF. The A&E methodology allocates a portion of the production and transmission costs on the system’s average load factor. The remaining costs are allocated on the difference between a class’s maximum demand and its average demand (Excess demand). (TR 3177) This method is further described in witness Pollock’s exhibit JP-5. (EXH 192) This method, witness Pollock asserts, is superior to the 12 CP and 50 percent AD method because it recognizes the dual functionality of generating plants (i.e., that such plants serve both base and cycling loads) without double-counting peak demand. (TR 3178, 3220) Additionally, witness Pollock advocated that the Commission apply the Summer Winter Coincident Peak method for allocating transmission plant costs. Although he does not elaborate on this point, witness Pollock appears to rely on his arguments that PEF has significant summer and winter peaks and that transmission must be designed to meet those peaks, even if it is not completely utilized in other months. (TR 3179)
Navy
According to the Navy, the retail class cost of service study methodology proposed by PEF is inappropriate because it allocates 50 percent of the production fixed cost on an energy basis. The fact that different technologies have different capital costs and different fuel costs does not provide justification for a higher energy weighting. (TR 1625) Witness Selecky stated that utility planners do not construct more capital intensive capacity for the sole purpose of reducing fuel costs. Rather, the goal is to install a mix of generation that yields the lowest total cost. (TR 1626)
Witness Selecky stated that proposal fails to provide a symmetrical allocation of fixed production costs and fuel costs. (TR 1623) Allocating 50 percent of the fixed production cost on an energy basis has the effect of skewing allocation of generation capacity costs toward high-load factor customers without providing a proper share of the lower cost of fuel from the base load resources. High load factor customers receiving an above average allocation of base load production costs should receive the benefit of lower fuel costs produced by that generation resource. (TR 1623, 1629-1630)
PCS Phosphate
PCS agreed with FIPUG that the Commission should approve the traditional 12 CP and 1/13th AD method. (PCS BR 14-15) PEF’s peak loads are determined largely by the residential class, which drives the utility’s capacity planning. (PCS BR 15) The proposed methodology of 12 CP and 50 percent AD is inappropriate and inconsistent with cost causation principles as well as policies to manage peak load growth. (PCS BR 3)
ANALYSIS
Although there were several accepted cost allocation methodologies discussed, there is no one ‘correct’ cost allocation methodology. It is a matter of judgment. PEF’s proposal to use a 12 CP and 50 percent average demand methodology is a departure from Commission practice. The 12 CP and 1/13th AD has been the dominant cost methodology approved by the Commission for the last 30 years. It was based in part on the fact that while peak load drives capacity, the type of plant built is determined on how long the plant will run. (TR 1496-1497)
Parties raised several objections to the higher energy weighting for production costs. FIPUG and the Navy raised the issue of break even costs. (TR 1627, 3172) However, staff was convinced by PEF’s arguments that units being constructed today are more expensive because they provide benefits other than just additional capacity. Such benefits may be mandated by federal or state environmental requirements, and may result in fuel savings or environmental benefits which accrue to all customers, not just those causing the peak demand. (TR 1497-1498)
In 1990, the Commission found that a higher level of energy allocation, such as that proposed by PEF in this case, allocates plant costs to hours past the break-even point, and thus results in misleading conclusions for generation planning.[66] However, as discussed during the hearing in Docket No. 080317-EI for TECO, both the first and the last kWh benefit equally from the lower operating costs of the base and intermediate plant according to average cost pricing, which has traditionally been used to set utility rates.[67] Staff found the intervenors’ argument against consideration of benefits accrued beyond the break-even point to be unpersuasive in both the TECO docket and the current PEF proceeding. PEF must consider not only the pure capital substitution argument offered by FIPUG, but also the societal emphasis on environmental quality and efficiency. (TR 1498-1499) While fuel costs and investment costs can be easily quantifiable, the environmental and efficiency benefits are, to some extent, societal benefits that benefit all of PEF’s customers equally, and staff believes a greater sharing of investment costs associated with these benefits is merited.
Two parties allege double-counting of coincident demand within the proposed 12 CP and 50 percent AD methodology. The Commission has previously ruled on the double-counting argument in this same context.[68] As described by the Commission, a double-counting problem does not exist because the costs that the utility incurred because of energy loads to be served are allocated on the basis of the classes’ proportions of energy use. A separate pot of dollars, the amount that would have been spent to serve peak loads, is allocated using an appropriate summer-winter peak demand allocation factor. Staff supports the Commission’s prior ruling on this matter.
FIPUG and the Navy contended that PEF should implement a Summer/Winter Coincident Peak methodology (as either a first or second preference) for cost allocation due to the existence of the utility’s peak periods falling within those months. However, the utility argued that it has less load management capability during the spring and fall months, and takes advantage of lower load for planned outages for maintenance. This necessary decrease in generating capacity makes each month of the year significant from a cost allocation standpoint. (TR 4045-6) Staff agrees with this position that consideration of the total annual generation profile is significant.
Staff also disagreed with FIPUG’s argument that PEF is being inconsistent with its treatment of fuel expense used for system reliability. Witness Slusser stated that fuel expenditures relating to load regulation and maintaining operating reserves occur around the clock, and that it is, therefore, inequitable to assess those costs only on peak usage. (TR 4037)
FIPUG is the only party to this case disputing the proposed 12 CP allocation specifically related to transmission costs, suggesting instead a Summer/Winter Coincident Peak allocation. However, a utility does not incur additional costs in its transmission facilities in order to provide transmission capacity during peak or non-peak months. Transmission capacity remains stable throughout the year, and is subject to maintenance planning just as with production plant. (EXH 318) For these reasons, staff believes a change in transmission cost allocation is not appropriate.
Although it endorsed the continued use of the 12 CP and 1/13th cost allocation methodology, FIPUG also offered as an alternative if the Commission chooses to go to a more energy oriented allocation, the Average and Excess Demand cost allocation methodology. Staff supports witness Slusser’s argument that using a class’s non-coincident demand as an allocator for production costs does not reflect the utility’s actual power supply capacity requirement, which is based on a class’s load that is coincident with monthly peaks. Witness Slusser provided two examples to illustrate his point of understated cost responsibility.
The first, Rate Schedule GS-2, or the 100 percent Load Factor rate class represents a continuous load of approximately 10 MW on PEF’s system during all hours in the year. (TR 4043) Under the Average and Excess methodology, the class’s excess demand would be calculated as the non-coincident peak of 10 MW, minus the class’s average demand of 10 MW, which would result in a net demand of zero for the peak capacity component of cost responsibility. (TR 4043-4044) This rate class would therefore bear no responsibility for the portion of capacity costs that are intended to recognize peak capacity responsibility, even though they operated during peak periods. (TR 4044) The second example provided by witness Slusser against the use of the Average and Excess methodology is that of PEF’s Rate Schedule LS-1, or the Lighting Service rate class. (TR 4044) This class imposes approximately 88 MW of load predominantly during off-peak periods, therefore, contributing little to the component of costs associated with peak capacity requirements. Under Average and Excess methodology, this rate class is calculated to have a load amount equal to about half of its non-coincident class demand, a level disproportionate to the class’s burden on the utility’s system. Staff agrees with the rebuttal testimony of witness Slusser that the use of the Average and Excess methodology is inappropriate for PEF.
CONCLUSION
Staff is persuaded by PEF’s arguments that units being constructed today are more expensive because they provide benefits other than just additional capacity. Such benefits may be mandated by federal or state environmental requirements, and may include fuel cost reductions as well as environmental benefits which accrue to all customers, not just those causing the peak demand. (TR 1497) However, while PEF has supported the argument that a greater allocation should be made to class energy responsibility, it had not sufficiently justified that a 50 percent allocation would better match costs with benefits than would a 25 percent allocation. Staff agrees with the testimony of the opposing parties that allocation of production plant costs equally on peak demand and energy places an undue burden on high load factor customers and inappropriately undervalues the costs to lower load factor customers who would be more likely to conserve energy in response to the proper pricing signals.
Based on the record, staff believes a 12 CP and 25 percent Average Demand allocation is reasonable, balances the interests of the parties, is based on Commission precedent, and should be approved.
If the Commission approves a cost allocation methodology other than the 12 CP and 1/13th Average Demand, should all cost recovery factors be adjusted to reflect the new cost of service methodology.
Recommendation:
Yes. If the Commission approves a cost allocation methodology other than the 12 CP and 1/13th Average Demand in Issue 90, all cost recovery factors should be adjusted to reflect the new cost of service methodology. The revised cost recovery factors should become effective coincident with the base rate changes approved in this docket. (Draper)
Position of the Parties
PEF:
Yes. The Commission’s practice has been to use the same cost allocation method approved in a utility’ last base rate proceeding to allocate costs in the utility’s cost recovery clauses for each functional cost.
OPC:
No position.
AFFIRM:
No position.
AG:
No position.
FIPUG:
Yes, provided that the interruptible credit is adjusted to reflect its full value.
FRF:
No position.
NAVY:
Yes. The cost allocation methodology approved by the Commission should primarily be utilized to allocate any increase in this proceeding.
PCS:
Yes, provided that the interruptible credit is adjusted to reflect its full value (PCS Phosphate agrees with FIPUG).
Staff Analysis:
PARTIES’ ARGUMENTS
PEF takes the position that the same cost allocation method approved by the Commission should also apply to the cost recovery clauses. (PEF BR 18) FIPUG and PCS agree, provided that the interruptible credit is adjusted to reflect its full value. (FIPUG BR 50; PCS BR 20) The NAVY agrees that cost recovery factors should be adjusted to reflect the new cost of service methodology. (NAVY BR 2)
ANALYSIS
As discussed in Issue 90, PEF proposed a 12 CP and 50 percent Average Demand methodology to allocate production capacity costs. Witness Slusser explained in his direct testimony that production capacity related costs make up about 40 percent of the company’s base recoverable costs, and over 80 percent of the costs recovered through the capacity cost recovery, energy conservation cost recovery, and environmental cost recovery clauses. (TR 1485) Thus, witness Slusser stated, that if the Commission adopts PEF’s proposal for the 12 CP and 50 percent Average Demand method, the same methodology should apply to all production costs in total and be utilized for the cost recovery clauses. (TR 4070) It appears that FIPUG, NAVY, and PCS agree with PEF. FIPUG and NAVY add to their posthearing brief that the interruptible credit is adjusted to its full value. The level of the interruptible credit is addressed in Issue 109.
CONCLUSION
Staff recommends that if the Commission approves a cost allocation methodology other than the 12 CP and 1/13th Average Demand in Issue 90, all cost recovery factors should be adjusted to reflect the new cost of service methodology. PEF’s currently approved cost recovery factors are based on the 12 CP and 1/13th Average Demand method. The revised cost recovery factors should become effective coincident with the base rate changes approved in this docket. That is consistent with the Commission’s decision in the TECO rate case, where certain changes to the allocation and rate design to TECO’s cost recovery factors became effective May 7, 2009, coincident with TECO’s revised base rates.[69]
How should any change in revenue requirements approved by the Commission be allocated among the customer classes?
Recommendation:
The appropriate allocation of any change in revenue requirements, after recognizing any additional revenues from service charges, should track each rate class’s revenue deficiency as determined from the approved cost of service study. The appropriate rate classes are shown in Exhibit 115. No rate class should receive an increase greater than 1.5 times the system average percentage increase in total, including cost recovery clauses, and no class should receive a decrease. When calculating the percent class revenue increase, PEF should account for any changes in the cost recovery clauses which may result from any approved changes in the cost of service methodology. (Draper)
Position of the Parties
PEF:
The appropriate allocation of any change in revenue requirements, after recognizing any additional revenues from service charges, should track, to the extent practical, each class’s revenue deficiency as determined from the approved cost of service study. No class should receive an increase greater than 1.5 times the system average percentage increase in total, and no class should receive a decrease. The appropriate allocation should recognize the combination of the Curtailable and Interruptible rate classes for the purpose of establishing base rate and filling adjustment charges. It should also recognize any customer migration that may occur between the GS and GSD rate schedules as a result of the final rate design.
OPC:
No position.
AFFIRM:
No position.
AG:
No position.
FIPUG:
If an increase is granted, no rate schedule should receive an increase greater than 150% of the system average base rate increase. This has been the Commission’s long-standing practice and policy. To do otherwise would result in excessive increases to certain classes, some of which are over 50%.
FRF:
Any decrease (or increase) in PEF's authorized revenue requirements should be allocated to the customer classes on the basis of an equal percentage decrease (or increase) to all base rates.
NAVY:
The Commission should utilize the result of a retail class cost of service study as a primary factor to allocate any changes in the revenue requirement among the customer classes.
PCS:
PCS Phosphate agrees with and adopts the position of FIPUG. No rate schedule should receive an increase greater than 150% of the system average increase.
Staff Analysis:
PARTIES’ ARGUMENTS
This issue addresses allocation of any revenue increase granted in Issue 87 to the various rate classes. PEF witness Slusser testified in his direct testimony that the basis in determining the portion of PEF’s base rate revenue increase to be assigned to each rate class is the cost of service study. (TR 1503) Witness Slusser added that ideally, the rates developed will produce revenues from each of the rate classes that equal the costs allocated to that class by the cost of service study. (TR 1503) Witness Slusser stated that the first step in determining how much each rate class should share in PEF’s total revenue increase, is to determine for each rate class the shortfall between costs allocated to that class and the revenues produced by applying current rates to the class’s test year billing determinants. (TR 1503) Witness Slusser further stated that the next step is to determine how much of each class’s revenue shortfall will be offset by additional revenues from any increase in service charges. (TR 1503) Once the net revenue deficiency for each rate class has been determined, the final step is identify whether any ratemaking policy considerations should limit the amount of any rate class’s revenue increase. (TR 1503-1504) Witness Slusser testified that where an increase limit is imposed on a rate class, the other classes must make up the deficiency. (TR 1504)
PEF proposed to limit certain rate class revenue increases to recognize the Commission’s prior practice of limiting any individual class’s increase to 150 percent of the overall percentage increase in PEF’s total revenues. (TR 1504) The calculation of PEF’s proposed revenue increase by rate class is shown in an exhibit attached to witness Slusser’s direct testimony. (EXH 115) The exhibit shows PEF proposed a system increase of 34.24 percent. Thus, PEF limited the increase in base revenues to any particular rate class to 51.36 percent (34.24 x 1.5). Increases for two classes, the CS/IS rate class and the Lighting Energy sub-group rate class, are significantly limited by this practice. (TR 1504) The third rate class, GSD, is being limited a very minor amount. (TR 1504)
OPC, Affirm, and the AG took no position on this issue.
FIPUG stated in its brief that base revenues should reflect the actual cost of providing service to each rate schedule as closely as practicable and that the Commission has consistently limited the immediate movement to cost based on principles of gradualism of rate administration. (FIPUG BR 50) Witness Pollock testified that the proposed base rate increases to certain classes would exceed one and a half times a system average increase when taking the changes in the cost recovery clauses into account. (TR 3216) Witness Pollock further testified that while FIPUG is a strong advocate of cost-based rates, the Commission must also bear in mind the tremendous shock that will result if certain classes are moved immediately toward cost. (TR 3217) Therefore, witness Pollock took the position that if an increase is granted, all rates should move as closely as possible to costs, but the increase should be limited to one and a half times the system average, taking into account any changes that may occur in the cost recovery clauses. (TR 3217)
FRF took the position in its brief that any decrease (or increase) in PEF's authorized revenue requirements should be allocated to the customer classes on the basis of an equal percentage decrease (or increase) to all base rates. (FRF BR 63) The Navy stated that the Commission should utilize the result of a retail class cost of service study as a primary factor to allocate any changes in the revenue requirement among the customer classes. In its brief, the Navy supported PEF’s proposal that no customer class’ revenue increase should exceed 150 percent of the total percentage increase. (NAVY BR 10)
PCS agreed with FIPUG. PCS stated in its brief that the essential purpose of the Commission’s long standing policy limiting rate increases to 150 percent of the system average increase is to prevent rate shock to any group of customers. (PCS BR 21) PCS added that this policy is particularly important where the utility is proposing a very large base rate increase and all consumers are bearing the brunt of difficult economic circumstances. (PCS BR 21) PCS stated that based on PEF’s rate filing, the proposed rate increases for rates GSD-1, IS-1/IS-2, and SS-3 all would exceed 150 percent of the system average increase. (PCS BR 21)
ANALYSIS
The final allocation to each rate class is largely dependent on the Commission-approved cost of service and revenue increase amount. PEF, FIPUG, and PCS agree on the overarching principle that limiting a class’s increase to no more than 1.5 times, or 150 percent the system average, is a mitigation effort. (TR 4078-4079) Staff notes that this practice has been approved in prior rate cases, such as for Gulf Power Company (Gulf)[70] and for TECO.[71]
While the parties who took a position on this issue all appear to agree that rate impacts should be mitigated, FIPUG and PCS disagree with PEF on two issues regarding the calculation of a class’s revenue increase. The two points of disagreement are addressed separately below.
The first disagreement between FIPUG and PEF centers on whether the 150 percent limitation is to be applied by rate class or rate schedule (emphasis added). Witness Slusser applied the 150 percent limitation to rate class, while witness Pollock applied the limitation to rate schedule. A rate class as presented in PEF’s exhibit 115 may include more than one rate schedule.
Staff reviewed witness Slusser’s proposed revenue increase as shown in Exhibit 115, and witness Pollock’s proposed revenue increase as shown in Exhibit 195. Witness Slusser’s exhibit showed proposed revenue increases for five rate classes: (1) RS and GS-1, (2) GS-2, (3) GSD and SS-1, (4) CS and IS, and (5) Lighting Energy. Those five rate classes mirror the rate classes presented in the cost of service study MFRs. (EXH 47) As can be seen, some rate classes include more than one rate schedule. In his direct testimony, witness Slusser stated that for the GSD and SS-1, CS and IS, and Lighting Energy rate classes the increases are limited to 1.5 times the system percentage increase. (TR 1504)
Witness Slusser testified that where an increase limit is imposed on a rate class, the other rate classes must make up the deficiency. (TR 1504-1505) In response to staff discovery, PEF stated that by limiting the increase to the CS/IS classes to 150 percent the system percentage increase, the residential and general service non-demand classes require an additional $5,061,000 in revenues. (EXH 41, BSP 1568) Similarly, by limiting the increase to the lighting energy rate class, the residential and general service non-demand classes require an additional $1,117,000 in revenues. (EXH 41, BSP 1568)
Witness Pollock calculated proposed class revenue allocations for twelve rate schedules: (1) RS, (2) GS-1, (3) GS-2, (4) GSD-1, (5) GSD transferred to GS, (6) CS-1, CS-2, (7) IS-1, IS-2), (8) SS-1, (9) SS-2, (10) SS-3, (11) LS-1, and (12) Lighting Facilities. (EXH 195) Staff is unclear why witness Pollock showed GSD customers who transferred to GS as a rate schedule.
FIPUG stated in its brief that PEF tries to mask this policy, i.e., limiting a class’s increase, by showing its proposed revenue allocation would result in no cost of-service class receiving a relative increase higher than 150 percent of the retail average increase. (FIPUG BR 51) To illustrate, witness Slusser limited the increase to the GSD/SS-1 rate class to 51.3 percent. Witness Pollock, however, presented the increase for the GSD and the SS-1 rate schedules separately in Exhibit 195. By performing a separate calculation, witness Pollock showed that for the GSD-1 rate schedule, the increase would exceed the 150 percent of the system average increase which is the standard the Commission applies, while for the SS-1 rate schedule the increase is lower. (EXH 195) FIPUG stated that the rate impact is further exacerbated because the proposed cost of service methodology will also apply to recovery clauses. (TR 3216)
To support its position, FIPUG asserted that in the Gulf Power Company (Gulf) rate case order the Commission used the terms rate class and rate schedule interchangeably.[72] (FIPUG BR 51) Specifically, FIPUG relied on the following paragraph from the Gulf rate case order to illustrate its point: No increases are allocated for the other Outdoor (OS-III), Standby (SBS), Real Time Pricing (RTP), and Large High Load Factor (PX/PXT) rate schedules because they are all significantly above parity.[73] (FIPUG BR 51) Upon cross examination by FIPUG, witness Slusser testified the Gulf rate case order does not give him enough information what rate classes were established by Gulf. (TR 4082-4083) Witness Slusser was provided an excerpt of the Gulf order. (TR 4081)
Staff reviewed the Gulf rate case order, and believes that FIPUG is incorrect in believing that the Commission has used the terms rate class and rate schedule interchangeably in that order. The Gulf order states on page 75 that no class shall receive an increase greater than 1.5 times the system average percentage. Page 108 of the Gulf order shows the actual calculation of the Commission approved revenue increase by rate class. That calculation shows that the SBS, ISS, RTP, PX, and PXT rate schedules were considered as one rate class, with the same percentage increase applying to that rate class. Therefore, staff believes, that the paragraph FIPUG relied on during cross examination of witness Slusser simply lists the rate schedules included in a particular rate class.
Upon cross examination by FIPUG, witness Slusser testified that some of the rate schedules in a class are really a fall-out of system costs. (TR 4080) Witness Slusser stated that for example, the IS class that is slightly above the 1.5 times system average, has a standby optional rate associated with IS, and the costs that are included in the standby rate are a fall-out of system costs. (TR 4080) Witness Slusser stated that if the standby rate, which is SS-2, comes out from system costs only being 24.24 percent increase as shown by witness Pollock in Exhibit 195, then something else in that class has to make up the difference. (TR 4080) Witness Slusser concluded that is why the IS class is a little above the 1.5 system increase. (TR 4080)
Staff agrees with witness Slusser that some of the rate schedules are a fall-out of system costs, and therefore do not fall under the 1.5 times system average limit. Those rate schedules are the SS-1, SS-2, and SS-3 rate schedules, which are standby service. Stand-by service is available for commercial customers who have on-site generating equipment. Rates for standby service are set pursuant to a methodology prescribed in Commission Order No. 17159[74] and are based on distribution, transmission, and production unit cost of the underlying firm rate schedules. Those unit costs are essentially a fall-out of the final Commission-approved cost of service study. The standby rates are addressed in Issue 108, and based on FIPUG’s position in that issue, it appears FIPUG agrees that the standby rates are a fall out issue of the cost of service study.
Staff agrees with PEF that the revenue increase approved by the Commission in Issue 87 should be allocated to the rate classes as identified in the cost of service study. (EXH 111) The use of rate classes, rather than rate schedules, to calculate a revenue increase, is consistent with the Commission’s decision in the Gulf and TECO rate cases.[75] The cost of service study forms the basis in determining the portion of PEF’s base rate revenue increase to be assigned to each rate class. (TR 1503) PEF’s cost of service study identifies the following rate classes: RS, GS-1, GS-2, GSD/SS-1, CS/SS-3/IS/SS-2, and Lighting. Lighting has two subparts: Energy and Facilities. (EXH 47, MFR Section E, pp. 1 and 2) While RS and GS-1 are shown separately in the cost of service, they have been combined in Exhibit 115, due to the application of the same rate charges to each rate class. The GS-1 rate is a rate for small commercial customers. Witness Slusser testified that is has been a practice since 1982 that the energy charges of the GS-1 rate schedule is set equal to that of the residential rate to circumvent any potential administrative problem of residential customers claiming entitlement to the GS-1 rate based on commercial activities in the residence. (TR 1507) Therefore, staff believes it is appropriate to determine the same percentage increase for the RS and GS rate schedules.
The second point of disagreement between PEF and FIPUG arises from the fact that PEF’s proposed change in cost of service methodology, if approved, will also affect the calculation of the cost recovery factors (see Issue 91). Witness Slusser stated that the Company only applied the mitigation factor of one and a half times to the base revenues. (TR 4075) To the extent the Commission approves a departure from PEF’s current cost of service study in Issue 90, the cost recovery clauses may also be impacted.
FIPUG entered Exhibit 317 into evidence to illustrate that the impact of the requested base rate increase as well as the clause increase using PEF’s proposed 12 CP and 50 percent Average Demand method. (TR 4072) During cross examination on Exhibit 317, witness Slusser agreed that when including the clauses, the CS/IS rate class appears to receive a percentage increase that is greater than 1.5 times the system average. (TR 4075) Staff agrees with FIPUG that any change in the cost of service methodology impacting the cost recovery clauses should be taken into account when considering revenue increases by rate class. That is consistent with the Gulf order, which states that the allocation of the increase does not impose an increase on any rate class that exceeds 1.5 times the system average increase, including adjustment clause revenues.[76]
Staff also rejects FRF’s proposal to apply a flat percentage increase or decrease to all classes. This approach ignores any changes in relative costs to serve among classes. Over time, as customers shift usage patterns and new rate classes are developed, costs shift as well. It is necessary to adjust the relative revenues per class to recognize the costs shifts. A general base rate proceeding is the only mechanism for addressing these cost shifts. FRF’s approach would perpetuate any existing rate structure issues and is therefore inappropriate.
CONCLUSION
Staff recommends that the appropriate allocation of any change in revenue requirements, after recognizing any additional revenues from service charges, should track each rate class’s revenue deficiency as determined from the approved cost of service study. Staff agrees with PEF’s use of rate classes as shown in Exhibit 115. No rate class should receive an increase greater than 1.5 times the system average percentage increase in total, including cost recovery clauses, and no class should receive a decrease. Staff agrees with FIPUG that when calculating the percent class revenue increase, PEF should account for any changes in the cost recovery clauses as a result of a change, if approved, in the cost of service methodology.
Is PEF's proposed methodology for treatment of unbilled revenue due to any recommended rate change appropriate? (Category 2 Stipulation)
Approved Stipulation:
Yes.
Is PEF's proposed charge for Investigation of Unauthorized Used appropriate? (Category 2 Stipulation)
Approved Stipulation:
Yes.
Should the Commission approve PEF's proposal to eliminate its IS-1, IST-1, CS-1, and CST-1 rate schedules and transfer the current customers to otherwise applicable rate schedules?
Recommendation:
Yes, the IS-1, IST-1, CS-1, and CST-1 rate schedules should be eliminated and the current customers should be transferred to otherwise applicable IS-2, IST-2, CS-2, and CST-2 rate schedules. The 36-month notice provision to move to a firm rate schedule should be reduced to 12 months for the transferred IS-1, IST-1, CS-1, and CST-1 customers. (Piper, Draper)
Position of the Parties
PEF:
Yes. These rate schedules, which are proposed to be eliminated, have been closed to new customers since April 1996. At that time, existing customers were grandfathered under these schedules to avoid the possibility of hardship from immediate transfer to comparable, cost effective rate schedules. It is now appropriate to bring this interim grandfathering to a close.
OPC:
No position.
AFFIRM:
No position.
AG:
Adopt OPC’s position.
FIPUG:
No. The Commission should retain the IS-1, IST-1, CS-1 and CST-1 rate schedules. These are separate and distinct schedules which should be maintained. PEF has not demonstrated that these schedules are not cost-effective. In fact, a study performed by PEF shows that PEF projects a need for additional non firm load.
FRF:
No.
NAVY:
No position.
PCS:
No. The Commission should direct PEF to retain the IS-1, IST-1, CS-1 and CST-1 rate schedules. Further, no existing customers should be transferred to any optional rate schedule. Customers should be allowed to elect among available rate options.
Staff Analysis:
PARTIES’ ARGUMENTS
PEF proposed to eliminate the IS-1 rate schedules, and transfer the customers served under these rate schedules to the applicable CS-2, CST-2, IS-2, or IST-2 (IS-2) rate schedules. (TR 1509-1510) In support of its position, PEF stated the IS-1 rate schedules have been closed to new customers since April 1996. (TR 1509, 1519) The IS-1 rate schedules were closed in 1996 because they were no longer cost-effective. (TR 1510) The transferred customers will continue to have the same quality of service, and be subject to the same base rates and recovery clauses, as they would have otherwise under the current IS-1 rates. The primary difference is that the transferred customers will be subject to the cost-effective curtailable and interruptible demand credits that apply under the open IS-2 schedules to which they are transferred. (TR 1510) In its brief, PEF stated that it is time to complete the transition and eliminate the non-cost-effective IS-1 rate schedules. (PEF BR 129)
FIPUG objected to the elimination of the IS-1 rate schedules. FIPUG stated that PEF has made no demonstration that interruptible load served under the IS-1 rate schedules is not cost-effective. (TR 3219) FIPUG stated that PEF has provided a study saying that paying the interruptible customers the capacity equivalent of $10.49 of kW is cost-effective. This would translate into an average interruptible demand credit of $7.13 per billing kW. (TR 3219)
Witness Pollock testified that interruptible power is a lower quality of service than firm power. (TR 3189) Witness Pollock further stated that when capacity is needed to serve firm load customers, interruptible customers will have their electricity discontinued (with or without notice and without limitation as to the frequency and duration of curtailment) so that service will be maintained for the firm customer base. (TR 3190) Such interruption often causes production processes of interruptible customers to be shut down resulting in economic losses for the interruptible customer. (FIPUG BR 53; TR 3190)
OPC, AFFIRM, the AG, and the Navy took no position on this issue.
FRF took the position that the IS-1 rate schedules should not be eliminated.
PCS stated that the Commission should direct PEF to retain the IS-1, IST-1, CS-1 and CST-1 rate schedules and increase the demand credits under those rate schedules to the levels that have been shown to be cost-effective. (PCS BR 23) Further, PCS stated that in its brief that if the IS-1 rate schedules are eliminated, PEF should not be permitted to simply transfer customers to the IS-2 rate schedules. (PCS BR 25) Customers should be permitted to elect among available rate schedules following an appropriate transition period. (PCS BR 25)
ANALYSIS
This issue deals with commercial/industrial customers who take service under PEF’s optional Interruptible General Service (IS-1), Interruptible General Service Time of Use (IST-1), Curtailable Service (CS-1), and Curtailable Service Time of Use (CST-1), collectively referred to as IS-1 rate schedules. An interruptible customer can have its power interrupted at any time if the company needs the capacity to serve its firm customers or to serve load in another utility’s territory in the event of a capacity shortage by that utility. (TR 1538-1539, 3189) In exchange for that lower quality of service, interruptible customers receive a credit on their monthly bill. (TR 1539, 3189) Curtailable customers also receive a credit, but have a choice whether they want to be interrupted. If they do not curtail, they will pay a penalty. (TR 1539)
The staff analysis addresses two issues: (1) the elimination of the IS-1 rate schedules, and (2) the appropriate notice provision for the transferred IS-1 customers. Staff recommends that the IS-1 rate schedules be eliminated and the IS-1 customers be transferred to the applicable IS-2 rate schedules. The 36-month notice provision contained in the IS-2 rate schedules should be reduced to 12-months for the transferred IS-1 customers.
Elimination of IS-1 rate schedules. Currently, 133 customers take service under the closed IS-1 rate schedules. (EXH 41, BSP 1550) While IS-1 and IS-2 customers pay the same base rate and cost recovery charges, there are three differences between the two rate schedules: (1) the IS-1 credit is higher than the IS-2 credit, (2) the IS-1 credit is applied to billing demand while the IS-2 credit is applied to load factor adjusted demand, and (3) some of the terms and conditions differ.
In the 1994 demand side management (DSM) docket, PEF’s predecessor, Florida Power Corporation (FPC), demonstrated that the existing IS-1 interruptible and curtailable rate schedules were no longer cost-effective.[77] In Docket No. 950645-EI, the Commission approved a stipulation between the parties to that docket to close the IS-1 rates schedules to new customers. The stipulation also provided that existing customers were allowed to continue to receive service under the existing IS-1 rates.[78]
In addition to the closure of the IS-1 rates to new customers, the Commission also approved in Docket No. 950645-EI the new cost-effective IS-2 rate schedules. The IS-2 rate schedules provide for lower credits than the IS-1 rate schedules. Witness Slusser testified that PEF proposed to eliminate the closed IS-1 rate schedules in its last two rate cases in 2002 and 2005, but both cases ended in stipulations under which the grandfathered customers were allowed to continue to take service under the closed rate schedules. (PEF BR 127-128; TR 1587-1588)
FIPUG’s witness Pollock did not directly address the elimination of the IS-1 rate schedules in his direct testimony. Witness Pollock’s testimony focuses on the level of both the IS-1 and IS-2 credits and the application of the credit. (TR 3161) Witness Pollock testified that the Company’s proposal to move the IS-1 customers to the IS-2 rate schedules would result in a 44 percent reduction in the interruptible credit currently paid to IS-1 customers. (TR 3192) This is a result primarily of the application of the load factor adjustment to the credit, addressed in Issue 110. In addition, witness Pollock testified that the current IS-2 credit is too low. (TR 3192) However, as discussed in Issue 109, staff recommends that PEF should file an updated cost-effectiveness analysis when it submits demand-side management programs for approval following the DSM goal setting proceeding.
During cross examination by FIPUG, witness Slusser stated that FIPUG’s members are typically large industrial customers, and that for many of them electricity is the highest variable cost. (TR 4076-4077) Witness Slusser agreed that IS-1 customers that are being transferred to the IS-2 rates would see the economic effect of lesser credits. (TR 1556) However, witness Slusser also testified that the IS-1 customers were grandfathered to a generous credit and have had a long transition period of deciding whether they are going to continue as an interruptible customer or chose other options. (TR 1558-1559) Staff does not dispute witness Pollock’s assertion that the IS-1 customers may experience an increase in their bills as a result of eliminating the IS-1 rate, however, they have benefited from a non-cost effective rate since 1996. (TR 1558) The credits for the interruptible classes are paid by all of PEF’s rate payers through the Energy Conservation Cost Recovery factor. (TR 1495, 1599) Credits are non cost-effective if they exceed the capacity costs avoided by interruption. (TR 1513) If the costs exceed the benefits, all of PEF’s ratepayers are paying more than they are receiving in benefits from the IS-1 customers. As the AG pointed out, numerous witnesses at the service hearings noted that they would have great difficulty meeting any increase in their electric bills. (AG BR 2) Witness Slusser added that these are difficult times for all customers, and that he was not familiar how FIPUG members manage their business when faced with large increases. (TR 4077)
Notice provision of transferred IS-1 customers. PCS supported FIPUG’s position and stated in its brief that the Commission should require PEF to retain the existing IS-1 rate schedules and increase the demand credits. (PCS BR 23) PCS further stated that in the event that the Commission allowed PEF to eliminate those rate schedules, PEF should not be permitted to simply transfer existing IS-1 customers to the IS-2 rate schedules and that customers should be permitted to elect among available rate schedules following an appropriate transition period. (PCS BR 24-25) Under the IS-1 rate schedules the notice provision is 60 months, while under the IS-2 rate schedules the notice provision is 36 months. (TR 1591)
PCS during the hearing asked witness Slusser a series of questions on whether he knew if any of the existing 71 IST-1 customers would want to take service under the IST-2 rate. (TR 1554-1556) Witness Slusser testified that if none of the IST-1 customers are interested in the IST-2 tariff, they will have to give 36 months notice to get out of the IST-1 rate. (TR 1559)
PEF in its post-hearing brief stated that no intervenor presented evidence that any transferred customers would elect to move off the IS-2 rate schedules, either now or 36 months in the future and that an attorney’s questions are not evidence. (PEF BR 129) Staff agrees with PEF that there is no customer testimony in the record to indicate that an IS(T)-1 customer would prefer to receive firm service than service under the IS(T)-2 rate. Witness Slusser testified that the purpose of the notice provision is to provide lead time to adjust its generation facilities plan. (TR 1592) PEF does not include interruptible load in determining the need for additional capacity. (TR 3189) The 36-month notice represents PEF’s planning horizon to build capacity to serve interruptible load should they transfer to firm service. (TR 1554)
However, upon cross examination by PCS, witness Crisp stated that PEF has adequate reserves to absorb 300 megawatts of interruptible load without impacting the system. (TR 989) When asked whether it would make more sense, since PEF is proposing to eliminate the grandfathered IS-1 rate, that the IS-1 customers be given an upfront choice as to which tariff they want to take service under, witness Slusser replied that he thinks the Company would give that some consideration. (TR 1556)
Staff believes PCS made a compelling argument that if the Commission eliminates the IS-1 rate schedules, the IS-1 customers should be given a choice whether they want to be transferred to the IS-2 rate schedules, or to an applicable firm rate. Witness Slusser testified that for the IS-1 customers, other than the IS-2 rates, the firm GSD and GSDT rate schedules would be available, which would result in higher bills when compared to the IS-2 rates. (TR 1593) While staff does not believe that any IS-1 customers would choose to transfer to a firm rate, since a firm rate will likely result in higher bills when compared to the IS-2 rate, staff also believes that since witness Crisp testified that PEF has the capacity to absorb 300 megawatts of interruptible load, that the general body of ratepayers is protected in case any IS-1 customers choose to transfer to firm service.
PCS stated in its brief that if the Commission eliminates the IS-1 rate schedules, the IS-1 customers should be permitted to elect among available rate schedules following an appropriate transition period. (PCS BR 25) PCS did not specify how long that transition period should be. However, during the cross examination, PCS asked witness Slusser whether he would be opposed to shortening the notice to terminate to a year. (TR 1554) While PCS did not propose a specific transition period, based on PCS’s question to witness Slusser whether he would be opposed to shortening the notice to terminate to a year, staff believes that PCS considered a 12- month transition period to be appropriate.
CONCLUSION
Staff recommends that the IS-1, IST-1, CS-1, and CST-1 rate schedules be eliminated and the current customers should be transferred to otherwise applicable IS-2, IST-2, CS-2, and CST-2 rate schedules. The 36-month notice provision to move to a firm rate schedule should be reduced to 12 months for the transferred IS-1, IST-1, CS-1, and CST-1 customers. The base rates are currently the same for both the IS-1 and IS-2 rate schedules, and will increase or decrease by the same amount approved in this case. FIPUG and PCS have presented no persuasive testimony as to why the IS-1 rate schedules should not be eliminated in this proceeding. FIPUG’s and PCS’s objections focus on the level of credit, which they believe is too low under both the IS-1 and IS-2 rate schedules. The level of credit is addressed in Issue 109. IS-1 and IS-2 customers provide the same type of benefits. There is no basis to support the continuation of two separate interruptible rate schedules, with different credits. If the Commission approves a revised credit in another proceeding, the cost effective credit should be the same for all interruptible and curtailable customers.
Is PEF's proposal to grandfather certain terms and conditions for existing IS-1, IST-1, CS-1, and CST-1 customers transferred to the IS-2, IST-2, CS-2, and CST-2 rate schedules appropriate?
Recommendation:
Yes, PEF's proposal to grandfather certain terms and conditions for existing IS-1, IST-1, CS-1, and CST-1 customers transferred to the IS-2, IST-2, CS-2, and CST-2 rate schedules is appropriate if Issue 95 is approved. If Issue 95 is not approved, this issue is moot. (Piper)
Position of the Parties
PEF:
Yes. Grandfathering certain terms and conditions is appropriate to avoid placing an undue burden on the transferred customers.
OPC:
No position.
AFFIRM:
No position.
AG:
Adopt OPC’s position.
FIPUG:
Yes. If the existing IS-1, IST-1, CS-1, and CST-1 customers are transferred, all terms and conditions for service to those classes should be grandfathered. including the 60 month transfer requirement.
FRF:
No position.
NAVY:
No position.
PCS:
Subject to PCS Phosphate’s objections to the elimination of those rate schedules and the unauthorized transfer of existing customers to optional rate schedules discussed in response to Issue 95, PCS agrees with and adopts the position of the FIPUG.
Staff Analysis:
PARTIES’ ARGUMENTS
PEF, FIPUG, and PCS agree that certain terms and conditions should be grandfathered in for existing IS-1, IST-1, CS-1, and CST-1 customers who are transferred to the IS-2, IST-2, CS-2, and CST-2 rate schedules. (PEF BR 19; FIPUG BR 53; PCS BR 25)
ANALYSIS
PEF proposed to eliminate the closed rate schedules IS-1, IST-1, CS-1, and CST-1 and transfer the customers served under these rate schedules to the applicable open IS-2, IST-2, CS-2, and CST-2 rate schedules. In addition to the level of the credit addressed in Issue 109 and the application of the credit addressed in Issue 110, there are some differences in the terms between the open and the closed schedules, so certain modifications need to be made to accommodate the transferred customers. (TR 1510)
The first difference deals with the time period of a required notice provision by a customer who may desire to transfer to a firm rate schedule. The new notice for the customer is 36 months instead of 60 months, which is less restrictive for the customer. PEF proposed to permit the transferred customers to use the less restrictive provision that is in the open rate schedules. (TR 1510)
The second difference relates to the requirement of a minimum billing demand of 500 kW for IS-2 customers. The IS-1 rate schedules do not include a minimum demand provision. PEF found that loads of less than 500 kW posed administrative problems and often required customized interruptible equipment and metering installations which were costly and impractical. PEF proposed that any transferred customer should be exempt from this minimum billing demand. Witness Slusser stated that this is appropriate because the interruptible equipment and meters are already installed. (TR 1510-1511)
The third difference affects customer accounts that were established after June 3, 2003 on the IS-2 rate schedules. Customers who established service after this date are limited to premises where an interruption or curtailment will not significantly affect members of the general public, nor interfere with functions performed for the protection of public health or safety. PEF realizes that some transferred customers may not satisfy this limitation, and proposed that the limitation not apply to them. (TR 1511)
The fourth difference is that the open IS-2 rate schedules are not available if the customer’s load is designated for use as a public shelter during periods of emergency or natural disaster. Transferred customers that are designated public shelters will be allowed to take service under the IS-2 rate schedules. PEF will not interrupt service to these customers if PEF receives notice of the facilities’ use as a public shelter sufficiently in advance to permit the deactivation of automatic interruption devices. (TR 1511; EXH 47, Section E of MFR’s, proposed tariff sheet No. 6.257)
CONCLUSION
PEF's proposal to grandfather certain terms and conditions for existing IS-1, IST-1, CS-1, and CST-1 customers transferred to the IS-2, IST-2, CS-2, and CST-2 rate schedules is appropriate if Issue 95 is approved. If Issue 95 is not approved, this issue is moot.
Should PEF's proposal to close the RST-1 rate to new customers be approved? (Category 2 Stipulation)
Approved Stipulation:
Yes.
Are PEF's proposed customer charges appropriate?
Recommendation:
Staff recommends that the Commission approve the methodology used by PEF in calculating the customer charges with one exception. Staff recommends the removal of the transformer costs from PEF’s proposed residential class customer charge. Based on PEF’s requested revenue requirement this would lower the customer charge by $4.24. Transformer costs should continue to be recovered through the non-fuel energy charge. PEF should recalculate the customer charges based on the revenue requirement approved by the Commission in Issue 87. The decision on the final customer charges should be made at the Rates Agenda. (Thompson)
Position of the Parties
PEF:
Yes.
OPC:
No position.
AFFIRM:
No position.
AG:
No.
FIPUG:
No position.
FRF:
No. PEF's proposed customer charges should be reduced to reflect the reduction in revenue requirements identified by the Citizens' witnesses.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
For the purposes of developing its customer charges, PEF either set rates at cost or derived them using on and off peak class usage factors. It also levelized some of its classes to maintain the appropriate relationship across related rate classes. (EXH 47, Schedule E-14 Supplement)
FRF takes the position that the customer charges should not be increased and that the proposed charge should be reduced to reflect the reduction in revenue requirements identified by the Citizens’ witnesses. (FRF BR 64)
OPC, AFFIRM, AG, FIPUG, PCS, and the Navy take no position.
ANALYSIS
Customer charges are flat fees assessed each month, regardless of the amount of energy (kilowatt hours) used. Utilities typically design and levy customer charges to recover specific accounts associated with meter reading, metering equipment, customer service, and bill processing. Customer charges differ by rate class, depending on the class of customer and the types of equipment used to provide service.
Staff has reviewed PEF’s methodology used to determine the proposed customer charges for the all rate classes. Staff agrees that PEF has properly included the appropriate customer costs, as historically defined, in its proposed customer charges, except for the residential class. Staff is concerned with PEF’s proposal to include the cost of transformers in the customer charge for the residential class.
Staff conducted discovery on how PEF’s residential service customer charges were determined. Cost support for these charges is contained in PEF’s Cost of Service Study, filed as part of its MFRs. (EXH 47) PEF witness Slusser stated that the proposed customer charge for residential service is designed to include the customer’s transformer cost, in addition to other normally included costs. (TR 1505) Witness Slusser stated that the customer charge is intended to recover those fixed costs that are independent of the level of a customer’s usage. (TR 1506)
PEF maintains that the transformer, like the residential customer’s meter and service wire tap, are considered necessary facilities to be installed to make a customer electrically active and should more appropriately be recovered in a customer charge than in a usage charge. (TR 1506) Currently, PEF recovers the cost of the transformer through the per kilowatt hour charge, which for residential customers, recovers both demand and energy costs. (TR 1585) Witness Slusser testified that if the Commission does not approve PEF’s proposal to include the cost of the transformer in the customer charge, PEF will still be able to recover that transformer through the energy charge. (TR 1585)
PEF’s proposed customer charge for the residential class is $13.21, including the transformer costs. (MFR E-13c p.1, MFR E-14 Sup B, TR 1586) By excluding the cost of the transformers, the charge would be reduced by approximately $4.24 for the standard residential rate class. (TR 1586, EXH 41, BSP 1557) A higher customer charge has a larger impact on the total bill for a low usage customer than a higher usage customer. (TR 1586) Therefore, it is important to keep the fixed charges as low as possible, consistent with cost causation and rate stability. Using PEF’s proposed customer charges, witness Slusser calculated a break-even point of 1,118 kilowatt hours, meaning that usage less than 1,118 kilowatt hours would incur a higher bill, and usage above 1,118 would incur a lower bill if the transformer cost was included in the customer charge. (TR 1586)
Staff further recognizes FRF’s concern that customer charges may be affected if the Commission approves a smaller increase, or a decrease, in overall revenue requirements. Due to the wide range of revenue requirements discussed in this case, the costs associated with the customer charge could change significantly. However, no party, other than staff, took issue with the methodology used by PEF in calculating its proposed customer charges.
CONCLUSION
In general, PEF’s proposed charges follow the process used in prior rate cases to design customer charges, keeping in mind rate stability and rate shock. Staff recommends the removal of the transformer costs from PEF’s proposed residential class charge which results in a reduction of $4.24 at PEF’s proposed revenue requirements. Transformer costs should continue to be recovered through the non-fuel energy charge. The Commission has previously ruled that the appropriate customer charge should be based upon the cost of the meter, service drop, meter reading, and basic customer service costs.[79] In two later cases, the Commission also ordered that the distribution costs which should be included in the customer charges consist of those related to the distribution from the pole to the customer’s structure.[80]
PEF should recalculate the costs used to determine the customer charges, based on the approved revenue requirement. A decision on the final customer charges should be deferred to the Rates Agenda Conference, along with other final rates.
Are PEF's proposed service charges appropriate?
Recommendation:
The appropriate service charges are $75 for Initial Connection, $30 for Existing Customer Reconnect, $11 for Leave Service Active, $50 for Non-payment Reconnect, and $65 for Non-normal Reconnect. If the Commission in Issue 87 approves no increase, or a decrease in operating revenues as proposed by OPC, FIPUG, and PCS, the service charges should remain at their current levels. (Thompson)
Position of the Parties
PEF:
Yes. The proposed service charges will more appropriately assign costs to the customers imposing such costs.
OPC:
No position.
AFFIRM:
No position.
AG:
No.
FIPUG:
No position.
FRF:
No.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARUGUMENTS
PEF’s proposed service charges were calculated based on cost of service and reasonableness. The AG and FRF state that PEF’s proposed service charges are not appropriate. (AG BR 16, FRF BR 64) Neither party supplied any additional information to support their position. OPC, AFFIRM, FIPUG, PCS, and the Navy take no position.
ANALYSIS
In witness Slusser’s direct testimony, he stated that revenues from service charges serve as a credit to offset a corresponding revenue requirement that would otherwise increase the Company’s base rate charges. (TR 1515) In order to appropriately analyze these service charges, staff prepared the following table:
|
comparison of service charges |
|||
|
|
Current Charge |
Proposed Charge |
Cost of Connection |
|
Initial Connect |
$61.00 |
$75.00 |
$179.23 |
|
Existing Customer Reconnect |
$28.00 |
$30.00 |
$30.18 |
|
Leave Service Active |
$10.00 |
$11.00 |
*See explanation below |
|
Non-payment Reconnect |
$40.00 |
$50.00 |
$60.00 |
|
Non-normal Reconnect |
$50.00 |
$65.00 |
$127.91 |
Initial Service Connection
The initial establishment of service charge is collected to cover the cost to connect a customer to service where service did not previously exist. (TR 1578) PEF’s current rate for the initial establishment of service is $61 and the proposed rate is $75. (TR 1579, Schedule E-14, Proposed Tariff Sheet 6.110) Witness Slusser completed a cost calculation for the cost the Company incurs for this service. The cost established was $179.23. (Schedule E-7, p. 1) Witness Slusser explains that “the company was trying to be reasonable in increasing this charge, and believes that $75 is a fair appropriate charge to charge an initial customer that is beginning service with the company. We [PEF] just felt that going to full cost of service is just an unreasonable assessment in getting a customer started at a new location.” (TR 1579) The difference in the cost of this service and the proposed charge will be recovered through base rates for all ratepayers. (TR 1580) The cost of this difference for each residential customer was roughly calculated at the hearing at 13 cents per thousand kilowatt hours. (TR 1602-1603)
Existing Customer Reconnect
PEF’s current rate for the existing customer reconnect is $28 and the proposed rate is $30. (Schedule E-14 Supplement Schedule A, p. 1, Schedule E-14 Proposed Tariff Sheet 6.110) A cost study was completed to evaluate the cost the company incurs for this service. The cost established was $30.18. (Schedule E-7, p. 2) The proposed rate was set at cost of service.
Leave Service Active
The Leave Service Active charge is applied to a customer who establishes service at a location covered by a Leave Service Active Agreement (LSA). A Leave Service Active Agreement is an arrangement entered into by landlords with multi-family rental housing facilities to maintain service between tenants and reduce the cost for new tenants to establish service in their own name. PEF has proposed changes to the terms and conditions of the LSA Agreement which is discussed in greater detail in Issue 114. The current issue addresses the charge assessed to new tenants under a LSA arrangement.
PEF’s current rate for re-establishment of service with Leave Service Active Agreement is $10 and the proposed rate is $11. (Schedule E-14 Supplement Schedule A, p. 1, Schedule E-14 Proposed Tariff Sheet 6.110) In response to staff’s discovery, witness Slusser explained the basis of the $11 charge. He stated “the charge reflects the avoidance of approximately $19 of loaded, field labor cost included in the cost support for deriving the re-establishment of service charge presented in MFR E-7 page 2 of 7. Thus, the charge of $30 for the re-establishment of service is reduced by $19 to derive the charge of $11 for the re-establishment of service where there is a LSA agreement.” (EXH 41)
Non-payment Reconnect
The Non-payment Reconnect charge is collected for the reconnection of service after disconnection for nonpayment or violation of company or Commission rules, where such reconnection is performed during normal working hours. (Schedule E-14 Proposed Tariff Sheet No. 6.110) PEF’s current rate for Non-payment Reconnect is $40 and the proposed rate is $50. (Schedule E-14 Supplement Schedule A, p. 1, Schedule E-14 Proposed Tariff Sheet 6.110) A cost study was completed to evaluate the cost the Company incurs for this service. The cost established was $60. (Schedule E-7, p. 4) PEF explained that the proposed amount is a reasonable amount. (Schedule E-14 Supplement Schedule A, p. 1) The difference in the cost of this service and the proposed charge will be collected through the base rates for all rate payers.
Non-normal Reconnect
The Non-normal Reconnect charge is collected for the reconnection of service for nonpayment of violation of company or Commission Rules where such reconnection is performed outside of normal working hours. (Schedule E-14 Proposed Tariff Sheet No. 6.110) PEF’s current rate for Non-normal Reconnect is $50 and the proposed rate is $65. (Schedule E-14 Supplement Schedule A, p. 1, Schedule E-14 Proposed Tariff Sheet 6.110) A cost study was completed to evaluate the cost the Company incurs for this service. The cost established was $127.91. (Schedule E-7, p. 5) The difference in the cost of this service and the proposed charge will be collected through the base rates for all rate payers.
CONCLUSION
Staff recommends the appropriate service charges are $75 for Initial Connection, $30 for Existing Customer Reconnect, $11 for Leave Service Active, $50 for Non-payment Reconnect, and $65 for Non-normal Reconnect. Although some charges are set at less than the cost determined by the cost of service study, staff agrees that the impact on the customer must also be considered in setting such one-time charges. While any difference between cost and revenue under the proposed charges will be collected through monthly rates, the amount shifted is relatively small and does not have a material impact on the monthly charges. If the Commission in Issue 87 approves no increase, or a decrease in operating revenues as proposed by OPC, FIPUG, and PCS, the service charges should remain at their current levels.
Is PEF's proposed charge to Temporary Service appropriate?
Recommendation:
The appropriate Temporary Service Charge is $250. (Thompson)
Position of the Parties
PEF:
Yes.
OPC:
No position.
AFFIRM:
No position.
AG:
Adopt OPC’s position.
FIPUG:
No position.
FRF:
No. PEF's proposed charges should be reduced to reflect the reduction in revenue requirements identified by the Citizens' witnesses.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES ARGUMENTS
PEF proposes an increase in the Temporary Service Charge from $227 to $250. (EXH 47, MFR Schedule E-13b, p.1) For Temporary Service, the labor costs total $161.10, the transportation costs are $22.36, the materials cost $79.21, and general overhead loading is calculated at $39.40. The total costs are $302.07. (EXH 47, MRF Schedule E-7, p. 6 of 7)
FRF takes the position that the costs should not be increased and that the proposed charge should be reduced to reflect the reduction in revenue requirements identified by the Citizens’ witnesses. (FRF BR 64)
OPC, AFFIRM, AG, FIPUG, PCS, and the Navy take no position.
ANALYSIS
This issue addresses PEF’s proposal for temporary service which is applicable to customers who require temporary service such as construction, fairs, displays, exhibits, and similar temporary purposes. (MFR E-14 proposed legislative tariff sheet No. 6.330)
Temporary Service is installed where there are no permanent customers or need for service, such as construction sites or temporary public events. Witness Slusser testified that the cost of providing that service is $302.07. (TR 1581) However, PEF is proposing a Temporary Service Charge of $250. (TR 1581) The $50 difference between PEF’s actual costs and the cost it is proposing to charge will be included in base rates. (TR 1580 - 1581) Witness Slusser explained that PEF does not have too many temporary services at this time with the economy and the impact of charging a temporary service fee that is below cost would affect the base rates minimally at only one cent per 1,000 kilowatt hours. (TR 1603)
CONCLUSION
Staff has reviewed PEF’s documentation provided on Temporary Service. Staff believes PEF’s proposal to charge $250, which is $50 less than the cost of providing the Temporary Service, appears reasonable.
Is PEF's proposed Premium Distribution Service charge appropriate?
Recommendation:
Staff recommends that the Premium Distribution Service charges proposed by PEF are appropriate, however, to the extent that the distribution unit cost would change as a result of other decisions in this docket, PEF should recalculate the distribution service charges. (Thompson)
Position of the Parties
PEF:
Yes.
OPC:
No position.
AFFIRM:
No position.
AG:
Adopt OPC’s position.
FIPUG:
No position.
FRF:
No. PEF's proposed charges should be reduced to reflect the reduction in revenue requirements identified by the Citizens' witnesses.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES ARGUMENTS
PEF states that the proposed Premium Distribution charges should be approved. (PEF BR 19)
The FRF takes the position that the costs should not be increased and that the proposed charge should be reduced to reflect the reduction in revenue requirements identified by the Citizens’ witnesses. (FRF BR 64)
OPC, AFFIRM, AG, FIPUG, PCS, and the Navy take no position.
ANALYSIS
Premium distribution service is an optional service for customers who wish to install facilities capable of providing automatic delivery transfer to an alternate distribution circuit in the event of an outage of the principal distribution circuit. The Premium Distribution Charge is a monthly charge that recovers the cost of reserving capacity in an alternate distribution primary circuit. (Schedule E-14 Proposed Tariff Sheet No. 6.150). The proposed charges are as follows:
|
PEF's Premium Distribution Charge ($ per KW Month) |
||
|
Class |
Current Rate |
Proposed Rate |
|
GST-1 |
*0.542 |
*0.968 |
|
GS-2 |
*0.109 |
*0.168 |
|
GSDT-1 |
0.80 |
1.23 |
|
CST-3 |
0.80 |
1.23 |
|
IST-2 |
0.80 |
1.23 |
|
SS-1 |
0.74 |
1.13 |
|
SS-2 |
0.74 |
1.13 |
|
SS-3 |
0.74 |
1.13 |
|
* cents per KWH |
||
PEF’s proposed new rates are based on distribution primary unit cost as shown in Schedule E-14 Supplement Schedule H. To the extent that the distribution unit cost would change as a result of a other decisions in this docket, PEF should recalculate the distribution service charges. That is consistent with FRF’s position that the charges should be reduced if the Commission adopts the reduction in revenue requirements identified by the Citizens’ witnesses.
CONCLUSION
Staff recommends that the Premium Distribution Service charges proposed by PEF are appropriate, however, to the extent that the distribution unit cost would change as a result of a other decisions is this docket, PEF should recalculate the distribution service charges.
DROPPED.
Are PEF's proposed monthly fixed charge carrying rates to be applied to the installed cost of customer-requested distribution equipment, lighting service fixtures, and lighting service poles, for which there are no tariffed charges, appropriate? (Category 1 Stipulation)
Approved Stipulation:
The methodology used by PEF to calculate the monthly fixed charge carrying rates is appropriate. To the extent any of the inputs used by PEF in the calculation are modified at the revenue requirements Agenda, PEF should recalculate the monthly fixed charge carrying rates using the approved inputs. (OPC, AFFIRM, AG, FIPUG, NAVY, and PCS did not affirmatively stipulate this issue, and took no position.)
Are PEF's proposed delivery voltage credits appropriate? (Category 2 Stipulation)
Approved Stipulation:
Yes.
Are PEF's power factor charges and credits appropriate? (Category 2 Stipulation)
Approved Stipulation:
Yes. PEF’s proposed power factor charge and credit of $0.25 kilovolt-ampere reactive (kVAR) is appropriate.
Is PEF's proposed lump sum payment for time-of-use metering costs appropriate? (Category 2 Stipulation)
Approved Stipulation:
Yes. PEF’s proposed $90 lump sum payment contained in the RST-1 rate for time-of-use metering costs is appropriate.
What is the appropriate method of designing time-of-use rates for PEF?
Recommendation:
PEF’s proposed time-of-use rate design is appropriate in this docket. Staff further recommends that PEF provide to staff by July 1, 2010, a proposed tariff for a multi-period commercial time-of-use rate, if available, or at a minimum, a report on their progress in defining such a new tariff. (Kummer)
Position of the Parties
PEF:
The appropriate methodology is that used by PEF, which designed those schedules in the same manner as has been prescribed by the Commission since their inception.
OPC:
No position.
AFFIRM:
The appropriate method of designing time-of-use rates is one that produces rates that (1) vary during different time periods and (2) reflect the variance, if any, in the utility’s cost of generation and purchasing electricity at the wholesale level. Moreover, the design and implantation of the rate should enable the electric consumer to manage energy use and cost through advanced metering and communications technology.
AG:
No position.
FIPUG:
No position.
FRF:
No position.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the AFFIRM.
Staff Analysis:
PARTIES’ ARGUMENTS
AFFIRM and PCS
AFFIRM represents a coalition of quick serve restaurants that have substantially similar usage patterns, such as Waffle House, Wendy’s, Arby’s and YUM! Brands. (TR 2274) PCS is a large industrial customer. In its brief, AFFIRM states that it has two main reasons for intervening in this case. The primary objective is to seek a more appropriately structured time-of-use rate for the AFFIRM Members that are served under the General Service Demand family of rates. (AFFIRM BR 1) Witness Klepper states that usage patterns of AFFIRM members are materially different from the majority of commercial customers because their monthly peaks typically occur during what most utilities deem to be either off-peak or shoulder hours. (TR 2275, 2277) Witness Klepper further notes that the only other rate schedule available to AFFIRM’s customer base is the General Service Demand Time-of-use (GSD-T) rate schedule. However, witness Klepper believes the current GSD-T rate is highly ineffective because of the higher customer cost, and because the ratio of on-peak to off-peak usage for AFFIRM’s clients is greater than the system average, resulting in more usage billed at on-peak rates. He states that commercial customers who wish to become more efficient are denied the opportunity to make efficiency improvement, due to the limited on- and off-peak pricing periods in current rates. It is AFFIRM’s position that a new commercial time-of-use rate should be developed which recognizes the variability in GSD customer usage patterns to better match costs and revenues in each time period. (TR 2278-2281) AFFIRM’s primary objection to the current GSD-T rate appears to be that it contains two broad pricing periods which results in shoulder peak usage being billed at on-peak rates when the cost of providing the energy may be less than a more narrowly defined peak period. AFFIRM asks the Commission to required PEF to design a multi-period time-of-use rate.
PEF
PEF’s current time-of-use methodology was established in its 1991 rate case.[81] PEF has not proposed any change in the method used to calculate time-of-use rates in this proceeding. (TR 4113) The Cost of Service And Rate Design Stipulation in that 1991 case set forth the methodology to be used.
The rate design for all Time-Of-Use (TOU) rates will set the off-peak energy rate at the average system energy component from the cost of service study (approximately 0.580 cents per KWH). The on-peak charge will then be the result of a break even calculation with the standard rate, based on the rate class’s or combined rate classes’ on-peak and off-peak energy consumption. (The combined classes will be the RS-1 and GS-1 and GSD-1 and GSLD-1 classes; the CS-1 class and the IS-1 class will be individual classes.) For Demand TOU rates, a demand charge equivalent to 1/2 (sic) of the unit cost for Distribution Plant will be applicable to the customer’s maximum measured demand. The on-peak demand charge shall include [in addition to production costs] the on-peak unit cost for Transmission Plant and 1/2 of the on-peak unit cost for Distribution Plant.[82]
Witness Slusser discussed PEF’s TOU methodology in his deposition. He notes that if the customer can shift usage so that his maximum usage occurs outside of peak hours, the applicable demand charge is less than the otherwise applicable demand charge for flat rate customers and the customer benefits from the time-of-use rate. If his maximum demand occurs during peak periods, he will pay the same as if he were on a flat rate. (EXH 318)
The energy charge likewise reflects on and off-peak costs. Non-fuel base rate energy charges are designed assuming using the on- and off-peak usage ratios for the whole class. If a customer uses less energy on-peak than the class average, he will see a reduction in his bill because the off-peak energy charge is lower than the flat rate energy charge. (EXH 318) Witness Slusser also points out the fuel cost differentiation for on- and off-peak usage. Like the non-fuel energy charge, the fuel charges are set, using the system’s on- and off-peak energy ratios. If a customer’s usage shows a higher percentage off-peak than the system average, he will realize a lower fuel cost compared to a flat rate. (EXH 318)
Witness Slusser takes issue with several points raised by AFFIRM. First, he points out that PEF was able to identify 151 AFFIRM customer accounts and of those a predominance of these customers take service under the GSD-T rate schedule. (TR 4050) His rebuttal testimony exhibit WCS-10 indicates that, as a whole, GSD commercial customers who take service on the GSD-T rate realize an eleven percent lower cents/kWh cost for electricity that those who take service on the GSD rate. (EXH 253) Witness Slusser also notes that this same exhibit shows that the identified AFFIRM customers have a slightly higher on-peak load factor as the total GSD class. (TR 4051) As discussed above, the GSD-T base rate is designed using the class on- and off-peak ratios. Also, the on- and off-peak fuel rates are design using the system on-peak percentage which witness Slusser stated is thirty-two percent, not forty-five percent as alleged by the AFFIRM witness. If the average AFFIRM customer has an on-peak usage factor of twenty-nine percent, he will benefit from the time-of-use rate. (TR 4051)
Witness Slusser noted that PEF does not have time recording meters on any AFFIRM customers to record hourly data. However, PEF does have a similar fast food customer included in the Cost of Service Load Research study.[83] The study results for this customer appears to show long periods of on-peak usage under the currently approved definition of peak and off-peak periods. Even so, the on-peak percentage of this customer is only twenty-eight percent which indicates that he would benefit from the GSD-T rate. (TR 4051-4052) However, witness Slusser also stated that PEF is already studying ways to better recognize the incentives to move consumption from peak periods to off-peak periods and to establish what are critical pricing periods are. (TR 4113)
ANALYSIS
AFFIRM and PCS took issue with PEF’s time-of-use rate design and only for the GSD class. AFFIRM recommended specific actions and PCS adopted AFFIRM’s position without further elaboration in its brief. PEF has not proposed any changes to its time-of-use rate design for any rate class.
PEF’s current GSD-T rate schedule was approved by the Commission in 1992. This is the first proceeding in which AFFIRM has raised their allegations of unfairness. They were not a party to either the 1991, 2001, or the 2005 rate cases. AFFIRM asks the Commission to direct PEF to develop a new commercial time-of-use rate that would be more effective by providing periodic price signals. (TR 2281) While witness Slusser appears to recognize that a new rate may be appropriate at some point, AFFIRM presented no specific rate design to be considered in this proceeding defining alternative rating periods, and provided no specific usage data to support any alternative rate design. In addition, witness Slusser demonstrated that, contrary to witness Klepper’s testimony, AFFIRM customers currently take service on the GSD-T rate and realize a lower cents/kWh, diluting the argument that something needs to be done immediately.
The current on- and off-peak rating periods were established by the Commission when it adopted the Public Utility Regulatory Policy Act (PURPA) recommendations on time-of-use rates. The periods have remained essentially unchanged since the early 1980s. The rating periods were set at that time, based on utility load data.[84] Staff disagrees with AFFIRM’s contention in its brief that the current TOU rate design does not comply with federal requirements. The current rate design does recognize that usage which occurs outside the designated peak periods can be served at a lower cost. AFFIRM seems to simply argue that a more finely delineated rate would do a better job of that.
Witness Slusser indicated that PEF is already considering alternatives to the current pricing incentives to encourage customers to shift usage to off peak periods. (TR 4113) A utility may propose a new optional rate structure at any time, and in fact, Gulf Power Company (Gulf) and Tampa Electric Company (TECO) have received approval for multi-period time-of-use pricing for residential customers.[85] TECO has also received approval for a pilot program offering multi-period time-of-use pricing for General Service customers (non-demand metered commercial customers).[86] However, in the TECO and Gulf cases, the utilities came forward with the proposal, and justified the programs based on load research information. Hourly usage data is necessary to determine if different or multiple rating periods were appropriate, and if so, what those rating periods should be, based on system cost information. (TR 4114, 4120)
As a practical matter, witness Slusser stated that current GSD metering does not have the capability to record hourly usage for AFFIRM’s customer base. (TR 4110) The installation of meters capable of recording and transmitting hourly data to the utility could approach $30,000 per location. (TR 4112) The costs for installing such advanced metering has not been considered in this case. Relevant load information is not available in this docket. (TR 4120) It is inappropriate to require PEF to propose a new rate without knowing if any such program is cost effective to the general body of ratepayers.
CONCLUSION
Staff recommends that the time-of-use rate design proposed by PEF in this docket is appropriate and should be approved. AFFIRM had identified what it perceives as problems, but did not propose any specific changes which could be considered in this proceeding. Staff believes there is insufficient evidence in this record to recommend any changes to the method proposed by PEF at this time. PEF has provided evidence that AFFRIM members currently benefit from the proposed rate design, although perhaps not to the degree those customers would like. PEF has stated that it is already investigating potential options to modify to its time-of-use rates. There are clearly costs associated with measuring usage in more discrete intervals necessary to properly design a new rate, and those costs have not been identified or considered in this case. Neither has the impact on other customers, other than AFFIRM’s members, or any impact on revenues, been discussed or determined in this case. Any new rate design must consider the overall impact, not just the impact on those customers who stand to benefit directly from any change. Staff further recommends that PEF continue to work on an option which offers more narrowly defined rating periods and provide staff by July 1, 2010 a proposed tariff for a multi-period commercial time-of-use rate, if available, or at a minimum, a report on their progress in defining such a new tariff. Staff believes that is a reasonable time frame to conduct the necessary load and cost analysis to at least identify some possible cost effective options. When PEF files a proposed tariff, AFFIRM will have adequate opportunities to participate in any future changes to time-of-use rate design.
What are the appropriate charges under the Firm, Interruptible, and Curtailable Standby Service rate schedules?
Recommendation:
This is a fall-out issue and will be decided at the January 28, 2010, Agenda Conference. The Standby Service charges should be designed in accordance with the Commission’s prescribed methodology in Order No. 17159. (Draper)
Position of the Parties
PEF:
PEF’s proposed Standby Service charges were appropriately developed in accordance with Commission prescribed methodology.
OPC:
No position.
AFFIRM:
No position.
AG:
No position.
FIPUG:
This is a fall out issue of the cost of service study.
FRF:
The appropriate charges are those that reflect the reduction in revenue requirements identified by the Citizens' witnesses.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the FIPUG.
Staff Analysis:
This is a fall-out issue and will be decided at the January 28, 2010, Agenda Conference. The Standby Service charges should be designed in accordance with the Commission’s prescribed methodology in Order No. 17159, issued February 6, 1987, in Docket No. 850673-EU, In re: Generic Investigation of Standby Rates for Electric Utilities.
What is the appropriate level of the interruptible credit?
Recommendation:
Staff recommends that the interruptible credit should be $3.62/kW for IS-1 customers and $3.31/kW for IS-2 customers. However, in the event the Commission determines to eliminate the IS-1, IST-1 rate schedules, staff recommends that the appropriate credit for the IS-2, IST-2 rate schedules should be $5.65. The recommended credits should remain in effect until the Commission reviews and approves PEF's conservation program modifications following the resetting of conservation goals. This recommendation is consistent with a stipulation rendered by PEF, FIPUG, and PCS in Docket No. 090002-EG. (Ellis, Graves, Draper)
Position of the Parties
PEF:
There should be no change in the current level of the interruptible credit in this docket. Any change in the credit should be addressed in the DSM goals docket or the conservation clause docket.
OPC:
No position.
AFFIRM:
No position.
AG:
No position.
FIPUG:
The credit for interruptible customers should be $10.49 per kW-Month to reflect the current value of the credit. PEF provided an updated cost-effectiveness test that shows that this is the appropriate value for the credit.
FRF:
No position.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the FIPUG. The interruptible credit should be $10.49/kW-mo. and should not be load factor adjusted. This credit level is justified based on PEF’s most current cost-effectiveness study.
Staff Analysis:
PARTIES’ ARGUMENTS
PEF argues the level of the interruptible and curtailable credits and the associated payment structure are not base rate issues and are not appropriate for resolution in this docket. PEF further asserts that the value of the Company’s ability to interrupt or curtail the demand is reflected in a billing credit, not in base rates. PEF also states that the Commission treats such credits as a demand side management program. This means that the level of the credit must be cost-justified in the same manner as the cost of any other demand-side management (DSM) program. It also means that the credit payments are accounted for as DSM costs, and are recovered from all customers through the conservation cost recovery clause. The DSM goals docket or the conservation clause docket is thus the proper forum to address the cost-effective level of the credit and its payment structure. (PEF BR 129)
FIPUG asserts that PEF has proposed to reduce the interruptible credit that IS-1 customers receive by 44 percent by transferring IS-1 customers to IS-2. FIPUG argues that the value of the interruptible credit (calculated by PEF to be $3.31 per kW, which is then load factor adjusted) is greatly understated. FIPUG claims that PEF’s updated cost-effectiveness test shows that the resulting credit for interruptible customers should be based on a capacity value of $10.49 per kW-Month. FIPUG believes that the capacity value of $10.49 per kW-Month is the appropriate value for interruptible credits. (FIPUG BR 54-55)
PEF’s current IS-1 and IS-2 credit levels were set by Commission Order No. PSC-07-0900-PAA -EI.[87] In that order the credit levels for IS-1 and IS-2 customers were set at a rate of $3.62/kW and $3.31/kW, respectively. As discussed in greater detail in Issue 95, PEF is proposing to eliminate the IS-1 rate schedule and transfer the current customers to IS-2 rate schedules. In this docket, PEF is proposing that the IS-2 rate remain at $3.31/kW.
FIPUG contends that a value of $10.49 per kW-Month is the appropriate value for interruptible credits. (TR 3191) FIPUG’s $10.49 per kW-Month value is derived from a document provided by PEF to FIPUG in response to a production of documents request. (TR 1546-1547; EXH 279) FIPUG did not provide an independent calculation or analysis supporting its recommended value.
PEF witness Slusser testified that the cost-effectiveness study relied upon to develop the $10.49 per kW-Month value was prepared as long as two years ago and further claimed that things would change if the study was redone. (TR 1546-1547) Witness Slusser additionally disagreed with certain terminology regarding the document which contained the $10.49 per kW-Month value. (TR 1547) No PEF witness was identified that could speak specifically to any calculations or assumptions used in the development of the $10.49 per kW-Month value. Although PEF questioned the $10.49 per kW-Month value, it did not offer an updated cost-effectiveness analysis regarding a more appropriate level of the interruptible credit.
On October 30, 2009, PEF, FIPUG, and PCS entered into a stipulation in Docket No. 090002-EG, (The Energy Conservation Cost Recovery Clause), as follows:
The non-fuel energy, demand, and customer charges are appropriately reviewed as part of a utility's base rate proceeding. The credits applied to an interruptible customer's bills are appropriately reviewed as part of the Commission's review of any utility filed demand-side management (DSM) program modifications. The Commission is currently scheduled to review utility DSM program modifications subsequent to establishing new DSM goals in Docket Nos. 080407-EG through 080413-EG. The current credits to interruptible customers will remain in effect until the Commission reviews and approves a utility's DSM program modifications. In the event the Commission determines to eliminate the IS-1, IST-1 rate schedules in Docket 090079-EI, the parties agree that the appropriate credit for the IS-2, IST-2 credit shall be $5.65 (subject to load factor adjustments) until such time as a final decision is rendered in Docket 080408-EI.
On November 2, 2009, the Commission approved the proposed stipulation.[88]
CONCLUSION
The interruptible credit level proposed by FIPUG appears to be derived from an analysis prepared as long as two years ago. Because, at least some of the data in the analysis may be outdated, staff does not recommend relying on the credit suggested by FIPUG. Staff would note that the Commission does have cyclical review of PEF’s interruptible programs, and associated credits, in the DSM goals docket. The Commission will be adopting new DSM goals at the December 1, 2009, agenda conference and an order establishing the adopted goals will be issued before January 1, 2010. Per Commission Rule 25-17.0021, F.A.C., PEF will be required to file a DSM plan, which includes a cost-effectiveness analysis of each program, within 90 days of the final order establishing the utility’s goals.
Staff recommends that the interruptible credit should be $3.62/kW for IS-1 customers and $3.31/kW for IS-2 customers. However, in the event the Commission determines to eliminate the IS-1, IST-1 rate schedules, staff recommends that the appropriate credit for the IS-2, IST-2 rate schedules should be $5.65. The recommended credits should remain in effect until the Commission reviews and approves PEF's DSM program modifications following the resetting of conservation goals. This recommendation is consistent with the stipulation rendered by PEF, FIPUG, and PCS in Docket No. 090002-EG.
Should the interruptible credit be load factor adjusted?
Recommendation:
There is no basis in this docket to change the application of the interruptible IS-2 credit. However, staff believes that witness Pollock’s two recommended alternatives to determine the amount of interruptible demand subject to the credit merit review by PEF. Staff recommends that PEF review witness Pollock’s alternatives, and provide an analysis to the Commission for review when PEF modifies its interruptible programs as part of the Company’s DSM goal implementation. (Draper)
Position of the Parties
PEF:
There should be no change in the application of the credit in this docket. Any change in the application of the credit should be addressed in the DSM goals docket or the conservation clause docket.
OPC:
No position.
AFFIRM:
No position.
AG:
No position.
FIPUG:
No. PEF’s proposal uses a customer’s billing load factor as a proxy for the customer’s coincidence factor. This approach incorrectly assumes that load factor and coincidence factor are the same. The interruptible class has a 61% billing load factor. However, the average coincidence factor (with PEF’s monthly system peaks) is 68%. Further, curtailments can occur at any time, not just during the system peaks. Thus, the Interruptible Demand Credit should apply to the amount of load that PEF is not obligated to serve during an interruption event.
FRF:
No position.
NAVY:
No position.
PCS:
No. PCS Phosphate agrees with and adopts the position of the FIPUG.
Staff Analysis:
PARTIES’ ARGUMENTS
PEF in its brief stated that the application of the interruptible credit is not a base rate issue and is not appropriate for resolution in this docket. (PEF BR 129) In his rebuttal testimony, witness Slusser testified that the payment method for this credit should not be considered in this proceeding. (TR 4049)
OPC, Affirm, AG, FRF, and the Navy take no position on this issue.
FIPUG objects to a load factor adjusted credit. (FIPUG BR 55) PCS agrees with FIPUG and its brief supports the position of FIPUG witness Pollock. (PCS BR 27)
ANALYSIS
The current interruptible demand credit (credit) contained in the IS-1 rate is 3.62 per kilowatt (kW) of billing demand. The current credit contained in the IS-2 rate is $3.31 per kW of load factor adjusted demand. The load factor adjusted demand is the product of the monthly billing demand and the monthly billing load factor. Thus, the $3.31 per kW credit would be reduced in proportion to the customer’s billing load factor. Under this method, customers with higher load factors receive a larger total credit than customers with lower load factors. Only a customer with a 100 percent load factor would receive the full credit amount under the IS-2 rate. (TR 1557) To be a 100 percent load factor, a customer would have to use his maximum billing demand for all 8,760 hours a year. (TR 1557) Witness Slusser explained that only load like traffic signals or amplifier stations operate as continuous loads. (TR 1557)
The Commission approved the load factor adjusted credit for the IS-2 rate in 1996, when it approved the closure of the IS-1 rates to new customers and the new IS-2 rates.[89] Thus, the load factor adjusted credit has been in effect for IS-2 customers since 1996. The load factor adjusted credit was also an issue in the TECO rate case. TECO’s General Service Load Management Rider (GSLM) tariff provides for a load factor adjusted credit, similar to PEF’s IS-2 rate.
Witness Pollock objected to a load factor adjustment of the credit, testifying that load factor is not a reasonable proxy for the amount of capacity that a customer curtails, and because curtailments can occur at any time, not just during the hour that PEF’s monthly coincident peak occurs. (TR 3161) Witness Pollock further testified that since PEF proposed to move the IS-1 customer to the IS-2 rate, the combined IS-1/IS-2 class is projected to have an average billing load factor of about 61 percent. This would result in an average load-factor adjusted credit of $2.02. [90] (TR 3192) Thus, witness Pollock testified that the company’s proposal to transfer the IS-1 customers to the IS-2 rate, would result in a 44 percent reduction in the interruptible credit currently paid to IS-1 customers. (TR 3192)
During the hearing upon cross examination by FIPUG, witness Slusser testified that when the IS-2 rate was developed, much study went into the method of applying the credit and the belief was that by applying it to the load factor adjusted demand was a better measurement of the amount of curtailable or interruptible load that was available. (TR 1544)
Order No. PSC-96-0842-FOF-EI, which approved the IS-2 rates, states:
This adjustment of the amount of the credit is justified because load research data indicates that there is a positive relationship between the customer's billing load factor and his coincidence factor. Coincidence factor is a measure of the relationship between a customer's maximum billing demand and his demand at the time of the system peak. Customers with high coincidence factors are more likely to be on the system at the time of peak demand and thus are more likely to provide significant load reductions to the system when interruptions are required.
While the coincidence factor cannot be measured directly, billing load factor, which measures the relationship between the customer's maximum monthly billing demand and his kilowatt hour consumption, has been shown to track coincidence factor. Billing load factor is readily available from billing records and is a suitable proxy for coincidence in adjusting the credits.
Witness Slusser testified that customers are getting the $3.13 per kW credit for what PEF is estimating as the customer’s coincident demand, i.e., demand during or coincident with the system peak. (TR 1544) And the coincident demand is being estimated by applying the load factor to billing demand. (TR 1544) Witness Slusser further testified that the IS-1 customers were grandfathered to a generous credit and have had a long transition period. (TR 1558) While FIPUG is correct that interruptions may occur at any time, system capacity shortages are most likely to occur during peak usage periods. Witness Pollock provided no data to support his contention that the number of non-peak interruptions were significant enough to change the methodology.
While objecting to the method used by PEF, witness Pollock in his direct testimony recommended two alternatives as to how to determine the amount of interruptible demand subject to the credit. (TR 3193) This implies that he believes some type of load factor adjustment is appropriate. First, witness Pollock stated that the interruptible demand subject to the credit should be based on customer’s normal operating demand for a defined base line period using actual data from a prior critical period. (TR 3193) In the alternative, witness Pollock recommended directly measuring the amount of interruptible demand in real-time for each customer. (TR 3194) Witness Pollock stated that this process is similar to determining the generation and transmission capacity charges in the standby rate and should not be burdensome to require the same process in determining the interruptible credit. (TR 3194)
Staff believes that there is not enough evidence in the record to determine whether witness Pollock’s recommended alternatives to determining the amount of interruptible demand are reasonable. To determine the appropriate credit amount, the utility would need to know what the customer’s demand was coincident with the system peak during an interruption event. PEF’s current load factor adjusted credit provides an estimate of what the customer’s load would have been during the monthly system peak.
CONCLUSION
Staff agrees with PEF that there is no basis in this docket to change the application of the IS-2 credit. However, staff believes that witness Pollock’s two recommended alternatives to determine the amount of interruptible demand subject to the credit merit review by PEF. Staff recommends that PEF review witness Pollock’s alternatives, and provide an analysis to the Commission for review when PEF submits demand-side management programs for approval following the DSM goal setting proceeding.
What are the appropriate energy charges?
Recommendation:
This is a fall-out issue and will be addressed at the January 28, 2010, rates Agenda Conference. (Draper)
Position of the Parties
PEF:
Energy charges should be set in combination with demand charges to produce the target revenue requirements and to the extent practical provide for uniform percentage increases throughout the class.
OPC:
No position.
AFFIRM:
No position.
AG:
Adopt position of OPC.
FIPUG:
PEF’s current non-fuel energy charges should remain the same. The non-fuel energy charges PEF proposes are much higher than PEF’s actual energy costs. The current non-fuel energy charges for Schedules GSD, CS, and IS already exceed non-fuel energy unit costs at PEF’s proposed rates. Thus, any increase allocated to these rates should be applied only to the demand charges. Similarly, any rate decrease should be used to reduce the current non-fuel energy charges.
FRF:
The appropriate energy charges are those that reflect the reduction in revenue requirements identified by the Citizens' witnesses.
NAVY:
The energy charges should be designed to collect only those costs that fluctuate with kWh usage.
PCS:
PCS Phosphate agrees with and adopts the position of the FIPUG.
Staff Analysis:
This is a fall-out issue and will be addressed at the January 28, 2010, rates Agenda Conference. For a discussion on the methodology to determine the demand and energy charges, see Issue 112. Since the demand and energy charges are set in combination to produce the class revenue requirement, staff believes it is more appropriate to discuss the development of both charges under Issue 112.
What are the appropriate demand charges?
Recommendation:
If the Commission approves an increase, or decrease, to PEF’s operating revenues in Issue 87, the demand charges in combination with the energy charges should be revised on a proportionate basis to provide for a uniform percentage change for most customers in a rate class. The final demand charges will be determined at the January 28, 2010, rates Agenda Conference. (Draper)
Position of the Parties
PEF:
Demand charges should be set at a level to at least recover distribution costs and be set in combination with energy charges to produce the target revenue requirements and to the extent practical provide for uniform percentage increases throughout the class.
OPC:
No position.
AFFIRM:
No position.
AG:
Adopt position of OPC.
FIPUG:
Any approved revenue increase that is not recovered in the customer charge should be recovered in the demand charges.
FRF:
The appropriate demand charges are those that reflect the reduction in revenue requirements identified by the Citizens' witnesses.
NAVY:
Demand related or fixed costs should be recovered through the demand charges.
PCS:
PCS Phosphate agrees with and adopts the position of the FIPUG.
Staff Analysis:
PARTIES’ POSITIONS
PEF stated that demand charges should be set at a level to at least recover distribution costs and be set in combination with energy charges to produce the target revenue requirements and to the extent practical provide for uniform percentage increases throughout the class. (PEF BR 21)
FIPUG took the position that PEF has underpriced the demand charges and overpriced the energy charges for the GSD, CS, and IS rate classes. (FIPUG BR 57) FIPUG witness Pollock testified that PEF’s rate design is problematic, since energy charges are higher than actual costs. (TR 3217) Witness Pollock therefore recommended that PEF’s current energy charges should remain the same, and any increase should be applied to the demand charges. (TR 3218) Similarly, any rate decrease should be used to reduce the current energy charges. (TR 3188) PCS Phosphate agrees with and adopts the position of the FIPUG.
FRF took the position that the appropriate demand charges are those that reflect the reduction in revenue requirements identified by the Citizens’ witnesses. (FRF BR 65) The Navy stated that the energy charges should be designed to collect only those costs that fluctuate with kWh usage. (NAVY BR 2)
ANALYSIS
This issue in conjunction with Issue 111 only addresses the methodology PEF should use to design the demand charges if the Commission grants PEF a change in operating revenues in Issue 87. The actual demand and energy charges will be determined at the January 28, 2010, rates Agenda Conference, and will be based on the Commission vote in all issues addressed in this recommendation.
Staff believes it may be helpful to first discuss the overall rate design process to show how the charges interact. After determining each class’s revenue responsibility, the next step in rate design is to divide each rate class’s total revenue responsibility among the various rate elements: the customer, demand, and energy charges. The customer charges are addressed in Issue 98, and are typically determined first based on the cost of service for meter and billing-related cost. The revenue generated by the customer charges times the number of bills is subtracted from the class revenue requirement. The reminder of the class revenue requirement is recovered through the energy charge for the RS and GS classes. The RS and GS classes have only two rate elements, customer and energy charge.
In addition to the customer and energy charges, the GSD, CS, and IS rate classes include a demand charge. Thus, after determining the customer charge revenues, the remaining class revenue requirement must be recovered from the demand and energy charge. The energy charge is billed on kilowatt-hours (kWh) consumed, while the demand charge is applied to the customer’s billing demand. Billing demand is the maximum 30-minute kilowatt (kW) demand established during a billing period.
Witness Slusser testified that rates must be designed to recover each class’s share of the revenue requirements from the members of that class in a fair and equitable manner. (TR 1518) Witness Slusser further stated that to accomplish this, PEF is generally proposing to maintain its current rate structure. (TR 1518) Within the non-residential classes that pay both demand and energy charges, PEF proposed to adjust its demand and energy charges proportionally to provide uniform percentage increases for most customers. (TR 4048)
Witness Pollock disagreed with PEF’s proposed development of the demand and energy charges. (TR 3187) Specifically, witness Pollock testified that PEF underpriced the demand charges for rate schedules GSD, CS, and IS. (TR 3187) Witness Pollock stated that the demand charges should closely reflect the corresponding demand related costs as derived in the cost-of-service study. (TR 3187) Witness Pollock concluded that since the current energy charges in schedules GSD, CS, and IS already exceed the energy unit costs, any increase allocated to those classes should be applied only to the demand charges. (TR 3188) The energy charge should not change, and any rate decrease should be used to reduce the current energy charge. (TR 3188)
In his rebuttal testimony, witness Slusser testified that witness Pollock’s proposed rate design is likely to unfairly burden low load factor customers, and provide an unfair advantage to high load factor customers. (TR 4047) Witness Pollock testified that high load factor customers have steady demand, are the most efficient and the least costly customer to serve. (TR 3218) While staff agrees that high load factor customers have steady demand, staff does not believe it would be appropriate to shield the high load factor customers from an increase at the expense of low load factor customers.
Witness Slusser in rebuttal testimony also addressed witness Pollock’s testimony that the demand charges do not reflect demand-related costs. Witness Slusser stated that PEF’s demand charges for the GSD, CS and IS rate classes recover distribution costs, while a portion of production and transmission costs are recovered on an energy bases. Witness Slusser stated that for billing purposes, the customer’s maximum demand whenever it occurs is being measured. (TR 4047) In his deposition, witness Slusser explained that the responsibility for production and transmission costs is not a responsibility related to the customer’s maximum demand, but a responsibility related to the customer’s coincident demand. (EXH 318) Coincident demand is demand that occurs during the system peak. Maximum, or billing demand, may, or may not be coincident with PEF’s system peak demand. (TR 4047) Witness Slusser further stated that there is a stronger correlation of contribution to monthly system peak with energy usage than with billing demand. (TR 4048) Thus, PEF finds it appropriate to recover a portion of production and transmission costs on an energy charge basis. (TR 4048)
CONCLUSION
Staff finds PEF’s argument to increase both the demand and the energy charge on a proportionate bases to provide for uniform percentage increases for all customers in a rate class persuasive. Staff does not believe it would be equitable to allocate any increase for the GSD and CS/IS rate classes to the demand charge only, which benefits high load factor customers at the expense of low load factor customers.
What are the appropriate lighting charges?
Recommendation:
This is a fall-out issue and will be decided at the January 28, 2010, Agenda Conference. (A. Roberts)
Position of the Parties
PEF:
The appropriate lighting charges are those presented in the tariff sheets contained in MFR E-14.
OPC:
No position.
AFFIRM:
No position.
AG:
Adopt position of OPC.
FIPUG:
No position.
FRF:
The appropriate lighting charges are those that reflect the reduction in revenue requirements identified by the Citizens' witnesses.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis: This is a fall-out issue and will be decided at the January 28, 2010, Agenda Conference.
Should PEF's proposal to revise its Leave Service Active (LSA) provision (tariff sheet No. 6.110) be approved?
Recommendation:
No. The proposed tariff language should be modified to eliminate the ten unit minimum to qualify for an LSA agreement. The requirement of the units to be contiguous and that the property have an on-site manager should be retained as proposed. (Kummer)
Position of the Parties
PEF:
Yes.
OPC:
No position.
AFFIRM:
No position.
AG:
Adopt position of OPC.
FIPUG:
No position.
FRF:
No position.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
PEF was the only party to address this issue in witness Slusser’s direct testimony. The Leave Service Active Agreement (LSA) is an option offered to landlords to maintain service to rental units between tenants, to avoid reconnection charges. If a landlord signs an LSA, he agrees to be responsible for electric usage at the designated rental units between termination of service by one tenant and initiation of service by another. This allows the landlord to continue electric service to clean and maintain the premises between tenants without the need to pay to establish service in his name, then discontinue service and require a new tenant to pay to establish service in their name. It is a more efficient process for both the utility and the landlord to simply transfer the name on the service. This provision has been in PEF’s tariffs since the early 1980’s. Although the language does not appear in its tariffs, PEF currently limits the availability of the LSA option to landlords with ten or more units. It has proposed to add language specifying the ten unit minimum to Tariff Sheet 6.110, along with language which requires rental properties to be multi-family and on contiguous property. (MFR Schedule E-14) PEF believes this is appropriate because fewer units or units which are not contiguous may lack adequate supervision to ensure that tenants do not simply discontinue service with the utility and remain in the rental unit. (TR 1595)
ANALYSIS
Witness Slusser stated that PEF is adding the language limiting the LSA to landlords with ten or more units for two reasons. First, this is consistent with how the company is applying the agreement today. (TR 1594) Second, he believes that landlords with less than 10 units would not be able to provide close supervision of their properties and may not be aware of when tenants leave. (TR 1595) The concept of LSA was initially developed to address an issue raised by an apartment owners association who managed large rental projects. They were able to monitor tenants closely and know when the tenant left and power was transferred to the landlord’s name. (TR 1595-1596) Witness Slusser believes that today there are more investors buying two and three homes or apartment who aren’t in the full time business of managing those rental units. He stated that the Company was uncomfortable dealing with these types of customers when it came to transferring the responsibility of usage at those locations. (TR 1596)
PEF provided no specific justification for requiring the presence of an on-site manager, or that the units be contiguous, but staff believes these are prudent requirements, to ensure that the LSA agreement is properly administered and enforced. Individual rental units are more difficult to monitor and a landlord may not be aware of the departure of a tenant in a timely manner. This can lead to disputes over when usage was transferred to the landlord. Similarly, staff believes the presence of an on-site manager is also an appropriate condition. An absent landlord may not be able to adequately monitor electric usage during vacancies as efficiently as if there was a manager presence at the rental location on a daily basis.
However, staff does not believe that PEF has adequately explained why the number of units should be limited to ten. (TR 1597-1598) Witness Slusser agreed that any landlord entering into an LSA agreement would be responsible of all usage for all units covered by that agreement that occurred between tenants. (TR 1596) Under the terms of the LSA, once a tenant contacts the utility to discontinue service, the service automatically reverts to the landlord’s account. Therefore, the utility is not at risk of non-payment, no matter the number of the rental units subject to the LSA. The utility does not appear to be at any greater risk for bill default for smaller rental groupings than for a unit containing a minimum of ten units. PEF’s statement that the customer service personnel did not want to deal with smaller landlords was not supported by any evidence or explanation. (TR 1597-8) Retaining the requirement that the units be contiguous and have an on-site manager appears to be sufficient safeguards without limitation on the number of units eligible for the LSA.
CONCLUSION
Staff recommends that the proposed tariff language be modified to eliminate the ten unit minimum to qualify for an LSA agreement, and that the requirement of the units to contiguous and that the property have an on-site manager be retained as proposed.
What is the appropriate effective date for PEF's revised rates and charges?
Recommendation:
The revised rates and charges should apply to meter readings taken on or after 30 days following the date of the Commission vote approving the rates and charges. (Draper)
Position of the Parties
PEF:
The appropriate effective date for the revised rates is the first billing cycle for the month of January, 2010. The appropriate effective date for revised service charges is January 1, 2010.
OPC:
The appropriate effective date for any change in rates as a result of this docket is January 1, 2010. No customers should experience a rate change for any usage prior to January 1, 2010.
AFFIRM:
No position.
AG:
The appropriate effective date for any changes in PEF's rates and charges as a result of this docket is for usage (consumption) on and after January 1, 2010 and for services rendered on and after January 1, 2010.
FIPUG:
The rates the Commission sets in this proceeding may only apply to customer consumption after January 1, 2010, pursuant to the terms of the Rate Case Stipulation.
FRF:
The appropriate effective date for any changes in PEF's rates and charges as a result of this docket is for usage (consumption) on and after January 1, 2010, and for services rendered on and after January 1, 2010.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
The parties’ positions reflect the original schedule of this case. However, since at the October 27, 2009, Agenda Conference, the Commission postponed its final decision on rates to January 28, 2010, the parties’ positions are no longer accurate. The revised rates and charges should apply to meter readings taken on or after 30 days following the date of the Commission vote approving the rates and charges which, under the current schedule, would mean for meter readings taken on or after February 27, 2010.
Are the rates proposed by Progress Energy Florida fair, just, and reasonable, and compensatory as those terms are used in Chapter 366, Florida Statutes, including specifically Section 366.03, 366.041(1), 366.05(1), and 366.06(1), Florida Statutes?
Recommendation:
This issue will be decided at the January 28, 2010, Agenda Conference along with the final rates. (Fleming, Sayler)
Position of the Parties
PEF:
Yes, for all the reasons set forth in PEF’s petition, testimony, exhibits, and MFRs.
OPC:
No position.
AFFIRM:
No position.
AG:
No. Progress’s requested rates and return on equity are unreasonably high during these difficult economic times and the witnesses presented by OPC demonstrate that these rates are unnecessary for Progress to maintain its profitability and meet its customers’ future electric needs. This is further emphasized by the recent increases which Progress has been granted, including the interim rates, the Bartow repowering, and the nuclear expenses granted on Friday. Although Progress argues that it needs greater revenues, the evidence demonstrates it has been profitable every year and has clearly not made all the available expense reductions in light of the proposed increases in salary and benefits which are consistent with previous years. This is contrasted with the testimony of the customers who must make significant sacrifices and choices as to whether to purchase food and medication or use their electricity. Some customers testified about taking medication every other day to save money and not turning on their electricity until it was dangerously hot. Others spoke of themselves or family members with medical problems that required 24-hour electricity and necessitated other sacrifices with food and medication. Many customers talked about living on retirement incomes that no longer covered their necessities and the fact that Social Security payments will be frozen for two years.
It is not in the public interest to allow the requested rate increase for Progress when the customers who paid their bills and made the company so profitable are struggling through difficult economic times. Many customers also noted that the benefits promised by Progress are years in the future and these paying customers are of such an age that they may well not experience any of these benefits. In light of these circumstances, it cannot be said that the requested rates are fair, reasonable or in the public interest.
FIPUG:
No. Based on the other issues discussed above, the Commission should reduce PEF’s rates.
FRF:
No. Progress’s proposed rates are based on unreasonably high costs and cost factors, such as ROE and equity ratio, and other assumptions, such as shorter than justified depreciation lives, all of which combine to make Progress’s proposed rates unfair, unjust, unreasonable, and far greater than necessary to enable Progress to provide safe, adequate, reliable service at a reasonable cost and to earn a reasonable return and attract sufficient capital.
NAVY:
No position.
PCS:
No. Based on the other issues discussed above, the Commission should reduce PEF’s rates.
Staff Analysis:
This issue will be decided at the January 28, 2010, Agenda Conference along with the final rates.
In fulfilling it mandate under Section 366.01, Florida Statutes, to regulated public utilities in the public interest and for the protection of the public welfare, and its mandate under Section 366.041(1) to fix fair, just, reasonable, and compensatory rates that consider among other things the value of such service to the public and that do not deny the utility a reasonable return upon its rate base, should the Commission grant any part of PEF's proposal to increase its base rate in this docket?
Recommendation:
This issue will be decided at the January 28, 2010, Agenda Conference along with the final rates. (Fleming, Sayler)
Position of the Parties
PEF:
Yes, the Commission should grant all of PEF’s proposal to increase its base rates, for all the reasons set forth in PEF’s petition, testimony, exhibits, and MFRs.
OPC:
No position.
AFFIRM:
No position.
AG:
No. Progress has already been granted increases this year, including interim rate increases, the Bartow repowering costs, and the nuclear costs on Friday. Progress cannot argue that its needs have not been met and the witnesses presented by OPC and the other interveners demonstrated that Progress does not need any further rate increase this year in order to make a reasonable return on its rate base and provide for the future electric needs of its customers. Progress is a profitable, regulated monopoly and even Progress’s experts admitted that these conditions provide for a safe investment. Considering the circumstances which Progress customers are experiencing and the increases already granted Progress this year, no further increases are warranted to provide Progress a fair return on equity and future access to credit. The return on equity requested by Progress is also excessive and would be the highest ROE in the country. As OPC witnesses and customers who had experience in this area testified, regulated monopolies do not require high ROE to acquire credit. Progress admitted that it had never been denied credit (except possibly during a brief period last year when everyone was denied credit) and has been profitable each year. Accordingly, Progress’s additional requested rate increase and requested return on equity should be denied.
FIPUG:
No. Based on the other issues discussed above, the Commission should reduce PEF’s rates.
FRF:
No. The Commission should deny PEF’s proposed base rate increase in its entirety. Progress’s proposed rates are based on unreasonably high costs and cost factors, such as ROE and equity ratio, and other assumptions, such as shorter than justified depreciation lives, all of which combine to make Progress’s proposed rates unfair, unjust, unreasonable, and far greater than necessary to enable Progress to provide safe, adequate, reliable service at a reasonable cost and to earn a reasonable return and attract sufficient capital.
NAVY:
No position.
PCS:
No. Based on the other issues discussed above, the Commission should reduce PEF’s rates.
Staff Analysis:
This issue will be decided at the January 28, 2010, Agenda Conference along with the final rates.
Should any of the $13,078,000 interim rate increase granted by Order No. PSC-09-0413-PCO-EI be refunded to the ratepayers?
Recommendation:
No refund of any of the interim rate increase is required. Further, upon issuance of the Final Order in this docket, the corporate undertaking should be released. (Slemkewicz)
Position of the Parties
PEF:
No.
OPC:
Yes. The increase was not lawfully granted and should be refunded with interest as determined by commission rule.
AFFIRM:
No position.
AG:
Yes. The increase was not lawfully granted and should be refunded to customers, with interest.
FIPUG:
Yes. The entire amount should be refunded, as collection of this amount violates the Stipulation Agreement entered into to settle PEF’s last rate case.
FRF:
Yes. The increase was not lawfully granted and should be refunded to customers with interest.
NAVY:
No position.
PCS:
Yes. PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
By Order No. PSC-09-0413-PCO-EI, issued June 10, 2009 (Interim Rates Order), the Commission authorized the collection of interim rates, subject to refund, pursuant to Section 366.071, F.S. The approved interim revenue requirement was $652,883,238, which represents an increase of $13,078,000 or 0.91 percent. The interim collection period is June 2009 through February 2010.
parties’ arguments
PEF disagrees with the intervenors’ arguments that the interim rates were not lawfully granted and/or barred by the 2005 Stipulation and Settlement of PEF’s previous rate case (Stipulation). The legal arguments concerning the Stipulation’s impact, if any, on an interim increase were decided by the Commission’s order granting interim rates. Thus, the intervenors’ positions on this issue reflect untimely and improper re-argument pursuant to Rule 25-22.0376, F.A.C. The calculation of any potential refund should be determined by application of Section 366.071(4), F.S. Based upon the evidence in this proceeding, PEF concludes there should be no refund. (PEF BR 115-116)
OPC argues that the granting of the interim rates by Order No. PSC-09-0413-PCO-EI was based upon an erroneous understanding that the terms of the Stipulation created a 10 percent threshold for purposes of determining interim relief. OPC cites to paragraphs 7 and 14 of the Stipulation in support of its position that PEF did not have an authorized ROE and that the 10 percent threshold referenced in the Stipulation was simply a trigger for seeking a change in base rates when its earnings fell below that threshold. Since the Stipulation did not specifically allow entitlement to interim rates or provide an authorized ROE, PEF was not entitled to interim rates. (OPC BR 97-102)
Alternatively, OPC argues that PEF made a pro forma adjustment to equity associated with purchase power agreements (PPA), which is the subject of Issue 41. If the Commission disallows this adjustment, then OPC argues that an adjustment must be made to the interim rates revenue requirement calculation in Order No. PSC-09-0413-PCO -EI. OPC’s recalculation of the interim revenue requirement, without the pro forma adjustment to equity, shows there was no revenue deficiency for 2009 and, thus, the interim rate increase should be refunded in its entirety. (OPC BR 102-104)
FIPUG argues that the granting of the Interim Rates Order violated the terms of the Stipulation. FIPUG cites to paragraphs 7 and 14 of the Stipulation in support of its position. FIPUG asserts that PEF did not have an ROE and the 10 percent threshold referenced in the Stipulation was simply a trigger for seeking a change in base rates and not interim rates. (FIPUG BR 59-60)
AG, FRF, and PCS’s briefs did not contain any arguments on this issue. Affirm and the Navy took no position on this issue.
analysis
OPC, AG, FIPUG, FRF, and PCS (adopting OPC’s position) each argue that the order granting the interim rate increase was unlawful. In addition, OPC raises an alternative argument concerning PEF’s imputed equity adjustment associated with PPAs.
In this case, the arguments raised by the intervenors are substantially the same as the arguments they raised at the May 19, 2009, Agenda Conference, where the Commission voted on whether to approve PEF’s interim rate request. The Commission’s Interim Rates Order, issued June 19, 2009, addressed the intervenors’ arguments when it approved an interim rate increase for PEF. However, the intervenors have failed to provide any new analysis or insight into the Stipulation which would persuade staff to believe that interim rate increase was granted unlawfully. Moreover, the intervenors did not seek reconsideration of the Interim Rates Order.
With regards to OPC’s alternative argument, staff is similarly not persuaded. Pursuant to paragraph 17 of the Stipulation, PEF was permitted to impute equity for all purposes allowed by the Stipulation for the term of the Stipulation. Since the Commission determined that the Stipulation permitted PEF to request an interim rate increase, then PEF properly calculated its interim revenue deficiency using imputed equity from the PPA agreements. Therefore, staff believes that the interim rate request was lawfully granted.
CONCLUSION
According to Section 366.071, F.S., any refund should be calculated to reduce the rate of return of the utility during the pendency of the proceeding to the same level within the range of the newly authorized rate of return. Adjustments made in the rate case test period that do not relate to the period interim rates are in effect should be removed. Rate case expense is an example of an adjustment which is recovered only after final rates are established.
In this proceeding, the test period for establishment of interim rates is the 12-month period ending December 31, 2008. PEF’s approved interim rates did not include any provisions for pro forma or projected operating expenses or plant. The interim increase was designed to allow recovery of actual interest costs, and the lower limit of the last authorized range for return on equity.
To establish the proper refund amount, staff has calculated a revised interim revenue requirement utilizing calendar year 2009 as a proxy for the interim collection period. Items such as rate case expense and the storm damage accrual were excluded because these items are prospective in nature and did not occur during the interim collection period. Using the principles discussed above, because the $1,522,328,000 revenue requirement granted in Order No. PSC-09-0413-PCO-EI for the December 2008 interim test year is less than the revenue requirement for the interim collection period of $1,714,416,092, staff recommends that no refund is required. Further, upon issuance of the Final Order in this docket, the corporate undertaking should be released.
Should PEF be required to file, within 90 days after the date of the final order in this docket, a description of all entries or adjustments to its annual report, earnings surveillance reports, and books and records which will be required as a result of the Commission's findings in this proceeding? (Category 1 Stipulation)
Approved Stipulation:
Yes. (AFFIRM did not affirmatively stipulate this issue, and took no position.)
DROPPED.
Does the creation of a regulatory asset and the deferral of pension expenses from a period covered by the Stipulation approved by Order No. PSC-05-0945-S-EI to a future period violate the terms of the Stipulation and order?
Recommendation:
No. Staff recommends that the Commission find that the deferral of pension expenses does not violate the terms of the 2005 Stipulation and Order, does not constitute retroactive ratemaking, and will not lead to double recovery. Accordingly, staff recommends that only the retail portion of PEF’s actual 2009 pension expense, estimated to be $31.5 million, should be deferred as a regulatory asset (2009 Pension Regulatory Asset). On an annual basis, PEF should use any pension expense levels below the allowance provided for in rates in the 2010 base rate proceeding in Docket No. 090079-EI to write-down the 2009 Pension Regulatory Asset. In the event that such write-downs are insufficient to fully amortize the 2009 Pension Regulatory Asset, PEF should not be allowed recovery of this item through a base rate case prior to 2015. Finally, staff recommends that PEF not earn a carrying charge on this regulatory asset. (Maurey, Fleming)
Position of the Parties
PEF:
No, nothing in the Stipulation precludes the creation of a regulatory asset and the deferral of pension expenses.
OPC:
Yes.
AFFIRM:
No position.
AG:
Yes, adopt position of the OPC.
FIPUG:
Yes. The Stipulation’s revenue sharing mechanism is the sole means through which to address PEF earnings through 2009. Allowing PEF to carry costs into 2010 violates the Stipulation.
FRF:
Yes.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
This is a legal issue related to the protest filed by certain intervenors to Order No. PSC-09-0484-PAA-EI.[91]
PARTIES’ ARGUMENTS
PEF asserted that Issues 119, 120, and 121 are legal issues related to the Commission’s PAA Order issued in Docket No. 090145-EI, which granted, in part, the Company’s request for the creation of a regulatory asset for the deferral of 2009 pension expense. PEF noted that although certain intervenors filed a timely protest to the Commission’s Order, none of the intervenors submitted any evidence or raised any factual issues in this proceeding with respect to the issues raised in the PAA Order. As a result, PEF asserted that the Commission’s legal ruling on these issues in Order No. PSC-09-0484-PAA -EI is uncontroverted and binding. PEF concluded that “any attempt by the intervenors to reargue the Commission’s legal ruling would amount to an improper motion for reconsideration and thus should be rejected.” (PEF BR 116)
OPC submitted that the Commission’s approval of PEF’s request in Docket No. 090145-EI to create a regulatory asset for the deferral of 2009 pension expense was “unjust and contrary to the plain language and intent of the stipulation.”[92] (OPC BR 108) OPC asserted that PEF’s request to defer any level of pension expense that would otherwise be recorded in a year covered by the 2005 Stipulation violates the principle of retroactive ratemaking. OPC noted that the Florida Supreme Court has consistently ruled that such actions are unlawful inasmuch as they attempt to recover past costs in future rates. (OPC BR 106) In addition, OPC argued that if the Commission allows PEF to violate the 2005 Stipulation by allowing these costs to be moved out of the stipulated period into a future period, then the sanctity of any future stipulation would be brought into doubt. For these reasons, OPC recommended the Commission deny PEF’s request to defer the 2009 pension expense and on its own motion adjust pension expense for purposes of setting rates in 2010 to a more appropriate level based on current market conditions. (OPC BR 105–108)
FIPUG submitted that PEF’s attempt to defer pension expense from the period covered by the 2005 Stipulation into a period beyond the 2005 Stipulation is an inappropriate shifting of costs into a future period. FIPUG asserted that the 10 percent ROE threshold from paragraph 7 of the 2005 Stipulation upon which PEF relied as the basis for its request for approval to defer the 2009 pension expenses is not applicable in this instance. Thus, FIPUG concluded that “the Commission erred when it permitted PEF to defer these expenses beyond the period of the Stipulation and this decision should be reversed.” (FIPUG BR 61)
AG, FRF, and PCS did not brief this issue. AFFIRM and NAVY took no position on this issue.
ANALYSIS
PEF’s Petition
On March 20, 2009, PEF filed a petition seeking the expedited approval of the deferral of $52.9 million in pension expense (Docket No. 090145-EI). The Company stated that this amount was the difference between actual pension plan income of $21.4 million for the year ended December 31, 2008, and projected pension plan expense of $31.5 million for the year ending December 31, 2009. PEF asserted that the deferral would not involve a change in retail rates or charges. Further, the Company stated that the benefit of the net pension income for 2008 had been recognized and passed on to customers in the interim rate increase calculation in the Company’s request for interim relief.[93]
The basis for PEF’s request was that unexpected economic conditions had resulted in a significant decline in the fair market value of the pension plan’s investments. The Company noted the Commission’s authorization for the establishment of a regulatory asset as a result of PEF’s adoption of SFAS 158[94] in 2007 was required in order to be in compliance with GAAP. PEF asserted that the decrease in the value of plan investments was the result of the severe economic downturn. Because the downturn in the economy was an event beyond its control, the Company contended the deferral requested should be granted. In support of its position, PEF cited to an Order of the Public Service Commission of South Carolina that approved an accounting order for regulatory accounting purposes authorizing South Carolina Electric and Gas Company (SCE&G) to defer certain pension costs as a regulatory asset for recovery in a future period.[95]
Intervenors’ Consolidated Response
On April 3, 2009, OPC, FIPUG, AG, FRF, and PCS (collectively, Intervenors) filed a joint response opposing PEF’s petition related to the requested accounting treatment for pension expense. In their consolidated response, the Intervenors objected to approval of PEF’s request to defer pension expense to a future period. The Intervenors’ objection was based on a number of arguments. The Intervenors stated that pension income for 2008 and the projected pension expense for 2009 fell within the period covered by the 2005 Stipulation. In their opinion, the requested deferral was an attempt to circumvent the express terms of the 2005 Stipulation by shifting results of operations from the stipulation period to a future period. In addition, the Intervenors believed that the requested treatment was a violation of the prohibition against retroactive ratemaking in that it would be an attempt to recover past expenses in future rates. The Intervenors also stated that the requested deferral would violate the recognition of pension expense specified in SFAS 87,[96] in that pension expense would not be recognized over the approximate service period of the employees covered by the plan. Finally, the Intervenors noted that the economic downturn impacted pension plans across a broad spectrum, including plans of both regulated and nonregulated companies, and as such did not represent an exogenous event unique to PEF.
PEF’s Response to Intervenors’ Consolidated Response
On April 15, 2009, PEF filed its response to the Intervenors’ consolidated response.[97] PEF disagreed with the assertion that the requested deferral would constitute retroactive ratemaking because the Company maintains that it has the right to seek limited proceeding rate relief under the provisions of the 2005 Stipulation. PEF stated that it was not requesting to defer 2009 pension expense to the 2010 base rate proceeding, but to some undefined future base rate proceeding. The Company also disagreed with the Intervenors’ assertion that the requested deferral would not conform with the requirements of SFAS 87. PEF cited to paragraph 210 of SFAS 87 which “contemplates that regulators may alter the timing of the recognition of pension expense but not the determination of the cost of the pension benefit.”
On July 6, 2009, the Commission issued PAA Order No. PSC-09-0484-PAA-EI, which granted, in part, PEF’s request to create a regulatory asset to defer 2009 pension expense (2009 Pension Regulatory Asset). In its Order, the Commission stated: “Based on our reading of the accounting statements, our understanding of the terms of the Stipulation, and the facts alleged in this case, we find that PEF’s request to create a regulatory asset to defer 2009 pension expense is hereby approved subject to the conditions outlined above.” The conditions specified that the appropriate amount to defer is the retail portion of the actual 2009 pension expense, then estimated to be $31.5 million. In addition, PEF was ordered to use any pension expense levels below the allowance provided for in rates in the 2010 base rate proceeding in Docket No. 090079-EI to write-down the 2009 Pension Regulatory Asset. In the event such write-downs were insufficient to fully amortize the 2009 Pension Regulatory Asset, the Order stated that PEF could not seek recovery of this item through a base rate case prior to 2015. Until that time, the unamortized balance of the 2009 Pension Regulatory Asset would be included in rate base for purposes of Earnings Surveillance Reporting. Finally, the Commission ordered that PEF would not earn a carrying charge on this regulatory asset.
On July 27, 2009, the Intervenors filed a joint petition protesting Order No. PSC-09-0484-PAA-EI. In particular, the Intervenors identified and protested three issues: a) whether PEF violated the terms of the 2005 Stipulation approved in Order No. PSC-05-0945-S-EI by seeking to create a regulatory asset and to defer pension expenses from a period covered by the 2005 Stipulation to a future period; b) whether the creation of a regulatory asset and deferral of pension expenses from a period covered by the 2005 Stipulation constitutes retroactive ratemaking; and c) whether PEF will double recover its deferred pension expenses deferred from a period covered by the 2005 Stipulation since revenue sharing is the exclusive mechanism for determining earnings for the 2005 Stipulation’s duration. The Intervenors further requested that the Commission set Order No. PSC-09-0484-PAA -EI for hearing on PEF’s proposal to create a regulatory asset and defer pension expense.
On August 20, 2009, Commission staff as well as the parties to Docket No. 090079-EI conducted an issue identification meeting for purposes of determining the issues to be addressed at hearing in the rate case. During the pendency of the issue identification meeting, the parties agreed to consolidate the Intervenors’ issues raised in the protest of the PAA Order issued in Docket No. 090145-EI into the hearing scheduled in Docket No. 090079-EI. Accordingly, at the request of the parties the Prehearing Officer consolidated Docket Nos. 090145-EI and 090079-EI for the purpose of an evidentiary hearing.[98] Neither PEF nor the parties offered any evidence on the above identified issues (Issues 119, 120, and 121, respectively) at the hearing but the Company and several parties did address the issues in their respective briefs.
Analysis
In Order No. PSC-09-0484-PAA-EI, the Commission acknowledged the concern raised by the Intervenors over what appears to be cost shifting from the stipulation period to some future, undefined period. On its face, it appears that the Company’s request is an attempt to track the pension expense in 2009 in isolation. According to PEF’s 2008 10K filing with the Securities and Exchange Commission (SEC), the Company reported a total pension benefit of approximately $47 million (system) for the years 2006 through 2008.[99] In viewing the four-year stipulation period in its entirety, even with consideration of the projected pension expense of $34 million (system) in 2009, PEF will still enjoy a net pension benefit over the term of the 2005 Stipulation.
As noted in PEF’s petition, the Commission previously approved deferral accounting and creation of a regulatory asset when PEF adopted SFAS 158.[100] In its 2006 Order, the Commission stated that:
FAS 71 allows regulated companies to defer costs and create regulatory assets, provided that it is probable that future revenue in an amount at least equal to the capitalized cost will result from inclusion of that cost in allowable costs for rate-making purposes. To create a regulatory asset or liability, a regulated company must have the approval of its regulator. This concept of deferral accounting allows companies to defer costs due to events beyond their control and seek recovery through rates at a later time. The alternative would be for the company to seek a rate case each time it experiences an exogenous event.
The Commission agreed with PEF that SFAS 158 imposed a specific accounting treatment related to the funded status of pension plans. The Commission also agreed with the Company that SFAS 71 permits the deferral of costs through the creation of a regulatory asset under certain circumstances.
That said, certain aspects of PEF’s proposal are distinguishable from the South Carolina Electric & Gas (SCE&G) decision for several reasons. First, the South Carolina order expressly stated that approval of SCE&G’s request for deferral was predicated in part on the South Carolina Commission’s ability to avoid consideration of a rate case to increase base rates. Since PEF is currently before the Florida Commission with a request for an increase in base rates in Docket No. 090079-EI, PEF’s request for deferral of the 2009 pension expense is not directly comparable with the situation in South Carolina. Second, the difference between the two cases arises from the disparate treatment of the pension expense for ratemaking purposes by the respective Commissions. In the South Carolina matter, the revenue requirement approved in 2007 for SCE&G in its most recent rate case expressly recognized an annual pension benefit of approximately $4 million. This treatment has had the effect of reducing SCE&G’s operating and maintenance (O&M) expense, thereby reducing customer rates.[101] In contrast, the order approving the 1993 step increase in base rates for PEF included an annual pension expense of approximately $3.8 million.[102] This treatment has had the effect of increasing PEF’s O&M expense and thereby increasing customer rates. While the South Carolina decision recognized the sum of the annual amount of pension benefit expressly reflected in base rates with the projected pension expense in that same year (2009), PEF’s request asked that the pension benefit from the prior year (2008) be added to the projected pension expense in 2009. These two requests are not the same. The 2005 Stipulation was silent with respect to pension expense.
While staff believes the Commission has the discretion to create a regulatory asset to defer pension expense, staff questions the calculation of the proposed deferral amount. For the reasons discussed above, it would be inappropriate to use the sum of the 2008 pension benefit and the 2009 pension expense to determine the deferral amount. Contrary to the position advanced by PEF, staff does not believe the $21.4 million pension benefit from 2008 is embedded in the Company’s 2009 revenue requirement. The pension benefit from 2008 has already been booked to income by the Company and is not relevant to the amount of pension expense PEF will incur in 2009. Staff believes the appropriate amount to defer is the retail portion of the actual 2009 expense which at the time of PEF’s petition was estimated to be $31.5 million.
Staff also acknowledges the Company’s claim that it is not seeking a change in rates associated with the 2009 pension expense. While the MFRs filed in Docket No. 090079-EI in support of its rate case reflected an annual pension expense of $27.1 million for the 2010 projected test year, PEF did not include any recognition of the 2009 pension expense in its filing. (EXH 47, MFR Schedules C–4, C–17) Moreover, it is recommended PEF use any pension expense levels below the allowance provided for in rates in the 2010 base rate proceeding in Docket No. 090079-EI to write-down the 2009 Pension Regulatory Asset. In the event such write-downs are insufficient to fully amortize the 2009 Pension Regulatory Asset, it is recommended PEF not be allowed to seek recovery of this item through a base rate case prior to 2015. Until that time, the unamortized balance of the 2009 Pension Regulatory Asset will be included in rate base for purposes of Earnings Surveillance Reporting. Staff also recommends that PEF not earn a carrying charge on this regulatory asset.
PEF asserted that none of the Intervenors submitted any evidence or raised any factual issues in this proceeding with respect to Issues 119, 120, and 121. PEF argued that the Commission’s ruling on these issues is binding and that any attempt to reargue the Commission’s legal ruling would amount to an improper motion for reconsideration and thus should be rejected. (PEF BR 116) A reconsideration standard is not appropriate here. Instead the Commission is voting on the issues concerning the deferral of a regulatory asset associated with the pension expense with a fresh look as if a decision never took place. By Order No. PSC-09-0484-PAA-EI, issued July 6, 2009, in Docket No. 090145-EI, the Commission memorialized its decision regarding the deferral of pension expenses. On July 27, 2009, the Intervenors filed a joint petition protesting the Order and identified and protested three issues. On August 3, 2009, PEF filed a Motion requesting that the matter be set for an informal hearing or in the alternative consolidated with the rate case docket. In its Motion, PEF argued that the three issues identified by the Intervenors were issues of law relating to the legal interpretation of the 2005 Stipulation. As such, PEF argued that the legal issues raised should be resolved on the basis of briefs and oral arguments. By Order No. PSC-09-0586-PCO-EI, issued on August 31, Docket Nos. 090145-EI and 090079-EI were consolidated for purposes of an evidentiary hearing.
Stipulation
OPC asserted that the creation of a regulatory asset for the deferral of pension expense is contrary to the plain language of the 2005 Stipulation. (OPC BR 105) On September 28, 2005, in Order No. PSC-05-0945-S-EI, issued in Docket No. 050078-EI, the Commission approved the 2005 Stipulation between the parties to PEF’s last petition for a rate increase. Section 4 of the 2005 Stipulation provides that PEF may not petition for an increase in base rates that would take effect prior to the first billing cycle for January 2010, except as provided in Sections 7 and 10 of the 2005 Stipulation. Section 7 allows PEF to petition for a limited proceeding if its retail base rate earnings fall below a 10 percent ROE as reported on its monthly earnings surveillance report. Section 10 pertains to Storm Cost Recovery. The relevant portion of Section 4 of the 2005 Stipulation provides:
4. No Party to this Agreement will request, support, or seek to impose a change in the application of any provision hereof . . . [and] neither seek nor support any reduction in PEF’s base rates and charges, including interim rate decreases, that would take effect prior to the first billing cycle for January 2010 . . . unless such reduction is requested by PEF. PEF may not petition for an increase in base rates and charges that would take effect prior to the first billing cycle for January 2010 . . . except as otherwise provided for in Sections 7 [Earning falling below 10 percent] and 10 [Storm Cost Recovery] of this Agreement. . . .
(emphasis added).
PEF’s request to create a regulatory asset to defer pension expense is not a request to change rates and charges during the stipulation period; thus, Section 4 of the 2005 Stipulation is not applicable to the treatment of pension expenses. Furthermore, the 2005 Stipulation is silent as to the treatment of pension expenses. Accordingly, staff believes that the creation of a regulatory asset to defer pension expenses falls outside the scope of the 2005 Stipulation and does not violate the terms of the 2005 Stipulation.
Retroactive Ratemaking
OPC asserted that PEF’s request to defer any level of pension expense that would otherwise be recorded in a year covered by the 2005 Stipulation violates the principle of retroactive ratemaking. Relying on Order No. PSC-98-1243-FOF-WS,[103] OPC argued that this violates the ratemaking principle of attempting to recover past expenses or revenues in future rates. (OPC BR 105-106) Staff believes United Water is distinguishable from the facts in this case. In United Water, the utility was seeking a deferral of costs that had already been incurred, which violates SFAS 71. In this case, PEF is requesting a deferral of pension expense before the costs are incurred. The Florida Supreme Court has recognized that retroactive ratemaking occurs where a new rate is requested and applied retroactively.[104] The Florida Supreme Court has also stated that the general principle of retroactive ratemaking is that new rates are not to be applied to past consumption.[105] In this case, PEF is not requesting that new rates be applied to past consumption, rather, PEF is requesting a deferral of costs before the costs are incurred. Thus, staff believes that the deferral of any level of pension expense will not constitute retroactive ratemaking.
Double Recovery
OPC also asserted that PEF’s proposal amounts to a form of double recovery since the expenses incurred during the operational timeframe of the revenue sharing mechanism are presumed to be recovered under that plan. OPC argued that allowing the pension expenses to be deferred and recovered in rates set for 2010 forward will allow PEF to effectively recover them again. (OPC BR 106-107)
FIPUG submitted that PEF’s attempt to defer pension expense from the period covered by the Stipulation into a period beyond the Stipulation is an inappropriate shifting of costs into a future period. FIPUG asserted that allowing pension expenses to be deferred and recovered in rates set for 2010 forward would allow PEF to effectively recover such expenses twice – once under the mechanism in place under the 2005 Stipulation and once in the future beyond the 2005 Stipulation. FIPUG concluded that this treatment constitutes an impermissible modification of the 2005 Stipulation and results in double recovery. (FIPUG BR 62)
Staff does not agree with the Intervenors that PEF’s proposed treatment of 2009 pension expense falls under the revenue sharing mechanism or that the creation of a regulatory asset for the deferral of this expense constitutes double recovery. Expenses are not relevant to the revenue sharing mechanism. The revenue sharing mechanism in the 2005 Stipulation is based on revenues, not earnings. Refunds are only made if revenues exceed a certain threshold and therefore the sharing mechanism is not affected by how much the Company may earn in any given period. In addition, by deferring the 2009 pension expense it is as if the expense never occurred. With the deferral, PEF will not recover the costs in 2009 and thus there can be no double recovery.
Finally, in its brief OPC requested the Commission, on its own motion, adjust pension expense for purposes of setting rates in 2010 to a more appropriate level based on current market conditions. While certain parties questioned the reasonableness of PEF’s projected 2010 pension expense, there is no evidence in the record regarding a more appropriate expense level. Moreover, no party raised an issue to make an adjustment to the Company’s proposed jurisdictional pension expense for 2010 of $27.1 million. As a result, there is no basis for the action OPC has requested in its brief related to the 2010 pension expense.
CONCLUSION
For the reasons discussed above, staff recommends that the Commission find that the deferral of pension expenses does not violate the terms of the 2005 Stipulation and Order, does not constitute retroactive ratemaking, and will not lead to double recovery. Accordingly, staff recommends that only the retail portion of PEF’s actual 2009 pension expense, estimated to be $31.5 million, should be deferred as a regulatory asset (2009 Pension Regulatory Asset). On an annual basis, PEF should use any pension expense levels below the allowance provided for in rates in the 2010 base rate proceeding in Docket No. 090079-EI to write-down the 2009 Pension Regulatory Asset. In the event such write-downs are insufficient to fully amortize the 2009 Pension Regulatory Asset, PEF should not be allowed recovery of this item through a base rate case prior to 2015. Finally, staff recommends that PEF not earn a carrying charge on this regulatory asset. However, if the Commission believes that the deferral of pension expense violates the terms of the 2005 Stipulation and Order, constitutes retroactive ratemaking, or will lead to double recovery, the Commission should not approve the creation of a regulatory asset to defer 2009 pension expense.
Does the creation of a regulatory asset and the deferral of pension expenses from a period covered by the Stipulation and order to a future period constitute retroactive ratemaking?
Recommendation:
No. As discussed in Issue 119, staff recommends that the Commission find that the deferral of pension expenses does not violate the terms of the 2005 Stipulation and Order, does not constitute retroactive ratemaking, and will not lead to double recovery. Accordingly, staff recommends that only the retail portion of PEF’s actual 2009 pension expense, currently estimated to be $31.5 million, should be deferred as a regulatory asset (2009 Pension Regulatory Asset). On an annual basis, PEF should use any pension expense levels below the allowance provided for in rates in the 2010 base rate proceeding in Docket No. 090079-EI to write-down the 2009 Pension Regulatory Asset. In the event that such write-downs are insufficient to fully amortize the 2009 Pension Regulatory Asset, PEF should not be allowed recovery of this item through a base rate case prior to 2015. Finally, staff recommends that PEF not earn a carrying charge on this regulatory asset. (Maurey, Fleming)
Position of the Parties
PEF:
No, the deferral of these expenses to a future period does not constitute retroactive ratemaking.
OPC:
Yes.
AFFIRM:
No position.
AG:
Yes, adopt position of the OPC.
FIPUG:
Yes. The creation of a regulatory asset violates the prohibition against retroactive ratemaking because it would allow PEF to recover past expenses in future rates.
FRF:
Yes.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
This is a legal issue related to the protest filed by certain intervenors to Order No. PSC-09-0484-PAA-EI.[106] Staff’s analysis of whether the creation of a regulatory asset and the deferral of pension expenses from a period covered by the 2005 Stipulation and Order to a future period constitute retroactive ratemaking is discussed in Issue 119.
Does the creation of a regulatory asset and the deferral of pension expenses from a period covered by the revenue sharing provisions of the Stipulation and order to a future period result in double recovery of those expenses?
Recommendation:
No. As discussed in Issue 119, staff recommends that the Commission find that the deferral of pension expenses does not violate the terms of the 2005 Stipulation and Order, does not constitute retroactive ratemaking, and will not lead to double recovery. Accordingly, staff recommends that only the retail portion of PEF’s actual 2009 pension expense, currently estimated to be $31.5 million, should be deferred as a regulatory asset (2009 Pension Regulatory Asset). On an annual basis, PEF should use any pension expense levels below the allowance provided for in rates in the 2010 base rate proceeding in Docket No. 090079-EI to write-down the 2009 Pension Regulatory Asset. In the event that such write-downs are insufficient to fully amortize the 2009 Pension Regulatory Asset, PEF should not be allowed recovery of this item through a base rate case prior to 2015. Finally, staff recommends that PEF not earn a carrying charge on this regulatory asset. (Maurey, Fleming)
Position of the Parties
PEF:
No, the deferral of these expenses to a future period does not result in any double recovery.
OPC:
Yes.
AFFIRM:
No position.
AG:
Yes, adopt position of the OPC.
FIPUG:
Yes. PEF’s recovery of such expenses incurred during the period of the Stipulation is covered by the revenue sharing mechanism in the Stipulation. This is the sole basis for treating expenses during the Stipulation period.
FRF:
Yes.
NAVY:
No position.
PCS:
PCS Phosphate agrees with and adopts the position of the OPC.
Staff Analysis:
This is a legal issue related to the protest filed by certain intervenors to Order No. PSC-09-0484-PAA-EI.[107] Staff’s analysis of whether the creation of a regulatory asset and the deferral of pension expenses from a period covered by the revenue sharing provisions of the 2005 Stipulation and Order to a future period result in double recovery of those expenses is discussed in Issue 119.
Should this docket be closed?
Recommendation:
The docket should be closed after the time for filing an appeal has run. (Fleming)
Position of the Parties
PEF:
Yes.
OPC:
No position.
AFFIRM:
No position.
AG:
Yes. After the Commission issues its order and that order has become final as a matter of law, this docket should be closed.
FIPUG:
Yes. This docket should be closed once PEF’s rates are reduced and a final order is issued.
FRF:
Yes. After the Commission issues its order reducing Progress's rates as recommended by the Citizens' witnesses, and after that order has become final as a matter of law, this docket should be closed.
NAVY:
No position.
PCS:
Yes, once a final order has been issued in this matter.
Staff Analysis:
The docket should be closed 32 days after issuance of the order, to allow the time for filing an appeal to run.
