DATE:	October 7, 2009
TO:	Office of Commission Clerk (Cole)
FROM:	Division of Economic Regulation (Breman, Hinton, Laux, Slemkewicz) Office of the General Counsel (Young, Bennett, Williams) Office of Strategic Analysis and Governmental Affairs (Graves)
RE:	Docket No. 090009-EI – Nuclear cost recovery clause.
AGENDA:	10/16/09 – Special Agenda – Post hearing Decision – Participation is Limited to Commissioners and Staff
COMMISSIONERS ASSIGNED:			All Commissioners
PREHEARING OFFICER:			New Commissioner
CRITICAL DATES:			None
SPECIAL INSTRUCTIONS:			None
FILE NAME AND LOCATION:			S:\PSC\ECR\WP\090009.RCM.DOC

 

Case Background

On March 2, 2009, Florida Power & Light Company (FPL) and Progress Energy Florida, Inc. (PEF) filed petitions seeking prudence review and recovery through the Capacity Cost Recovery Clause (CCRC) of the final true-up costs for certain nuclear power plant projects pursuant to Rule 25-6.0423, Florida Administrative Code, (F.A.C.) and Section 366.93, Florida Statutes (F.S.).  On May 1, 2009, FPL and PEF filed petitions seeking approval to recover estimated 2009 costs and projected 2010 costs for both projects through the CCRC.  PEF’s May 1, 2009 petition also requested implementation of a rate management plan.

FPL’s petition addressed two nuclear projects.  The first FPL project is composed of uprate activities at its existing nuclear generating plants, Turkey Point Units 3 & 4 and St. Lucie Units 1 & 2.  Collectively, these uprate activities are known as the extended power uprate project (EPU Project).  FPL obtained an affirmative need determination for the EPU Project by Order No. PSC-08-0021-FOF-EI.[1]  The second FPL project is the Turkey Point Units 6 & 7 project (TP67 project).  FPL obtained an affirmative need determination for the TP67 project by Order No. PSC-08-0237-FOF-EI.[2]

PEF’s petition also addressed two nuclear projects.  The first PEF project is an extended uprate at the existing nuclear generating plant Crystal River Unit 3 (CR3 Uprate).  PEF obtained an affirmative need determination for the CR3 Uprate by Order No. PSC-07-0119-FOF-EI.[3]  The second PEF project is the Levy Units 1 & 2 project (LNP).  PEF obtained an affirmative need determination for the LNP by Order No. PSC-08-0518-FOF-EI.[4]

Traditionally, all eligible power plant construction projects have been afforded the same regulatory accounting and ratemaking treatment.  That is, once a need for a project has been determined by the Commission, the utility books all expenditures associated with the project into account 107 Construction Work in Progress (CWIP) for that particular project.  A monthly allowance-for-funds-used-during-construction (AFUDC) rate is applied to the average balance of this account and the resulting dollar amount is then credited to the account balance.  This process continues until the completion of the project.

Once the plant is placed in commercial service, the CWIP account balance is transferred to the appropriate plant-in-service account and becomes part of the utility’s rate base.  The impacts of including the total project costs in a utility’s rate base, as well as the impacts of additional plant operational expenses, are addressed during a subsequent proceeding wherein the Commission determines whether customer base rate charges should be changed in order to provide the opportunity to recover these costs.

In 2006 the Florida Legislature enacted Section 366.93, F.S., in order to encourage utility investment in nuclear electric generation by creating an alternative cost recovery mechanism.  Section 366.93, F.S., authorized the Commission to allow investor-owned electric utilities to recover certain construction costs in a manner that reduces the overall financial risk associated with building a nuclear power plant.  In 2007, Section 366.93, F.S., was amended to include integrated gasification combined cycle plants, and in 2008, the statute was amended to include new, expanded, or relocated transmission lines and facilities necessary for the new power plant.  The statute required the Commission to adopt rules that provide for, among other things, annual reviews and cost recovery for nuclear plant construction through the existing capacity cost recovery clause.  By Order No. PSC-07-0240-FOF-EI, the Commission adopted Rule 25-6.0423, F.A.C., to implement Section 366.93, F.S.[5]

Pursuant to Rule 25-6.0423(4) and (5), F.A.C., once a utility obtains an affirmative need determination for a power plant covered by Section 366.93, F.S., the affected utility may petition for cost recovery using the alternative mechanism.  Three types of prudently incurred costs are described in the rule for such consideration.

•           Site selection costs are costs incurred prior to the selection of a site.  A site is deemed selected upon the filing for a determination of need.  (Rule 25-6.0423(2)(e) and (f), F.A.C.)

•           Preconstruction costs are those costs incurred after a site is selected through the date site clearing work is completed.  (Rule 25-6.0423(2)(g), F.A.C.)

•           Construction costs are costs that are expended to construct the power plant including, but not limited to, the costs of constructing power plant buildings and all associated permanent structures, equipment and systems.  (Rule 25-6.0423(2)(i), F.A.C.)

In Order No. PSC-08-0749-FOF-EI, the Commission approved stipulations among the parties to Docket No. 080009-EI recommending site selection costs be included in and recovered through the Nuclear Cost Recovery Clause (NCRC) in the same manner as pre-construction costs.  Pursuant to Rule 25-6.0423(5)(a), F.A.C., all prudently incurred preconstruction costs will be recovered directly through the CCRC.  Additionally, Rule 25-6.0423(5)(b), F.A.C., provides for annual recovery of carrying charges on prudently incurred construction costs through the CCRC.

Commission decisions implementing Rule 25-6.0423, F.A.C., began in 2008.  On May 5, 2008, the Commission issued Order No. PSC-08-0295-DS-EI, granting FPL’s request for a declaratory statement that “advance payments made prior to the completion of site clearing work are properly characterized as preconstruction costs to be recovered pursuant to the mechanism provided in Rule 25-6.0423, F.A.C.”[6]  On November 12, 2008, by Order No. PSC-08-0749-FOF-EI, the Commission addressed FPL’s and PEF’s first petitions for nuclear cost recovery amounts.[7]  On November 26, 2008, by Order No. PSC-08-0779-TRF-EI, the Commission approved a base rate increase addressing the completed phase of the CR3 Uprate known as the measurement uncertainty recapture (MUR).[8]  On April 6, 2009, by Order No. PSC-09-0208-PAA-EI, [9] the Commission authorized PEF to defer recovery of $198,000,000 in site selection and preconstruction costs for the LNP.  Recovery of these deferred costs is addressed in this proceeding.

Rule 25-6.0423(5), F.A.C., sets forth the process by which the Commission is to conduct an annual hearing to determine the recoverable amount that will be included in the CCRC pursuant to Section 366.93, F.S.  This is the second year of this newly established NCRC roll-over docket.

The Commission granted intervention to the following parties: the Office of Public Counsel (OPC), Florida Industrial Power Users Group (FIPUG), White Springs Agricultural Chemicals Inc. d/b/a PCS Phosphate – White Springs (PCS Phosphate), Southern Alliance for Clean Energy (SACE), and the Federal Executive Agencies (FEA).  Testimony and associated exhibits where filed by FPL, PEF, OPC, PCS Phosphate, SACE, and Commission staff.  On August 10, 2009, FPL, PEF, OPC, FIPUG, PCS Phosphate, SACE, and Commission staff filed prehearing statements.

The Commission held its evidentiary hearing for the NCRC docket on September 8-10, 2009.  The intervenors took “No position” on various prudence issues and on issues addressing final 2008 true-up amounts which allowed for staff, FPL, and PEF to present partial stipulations and resolve the issues.  The Commission approved the partial stipulations as a preliminary matter during the September 2009 hearing.  These partial stipulations are included in Attachment A.

The remaining unresolved issues in this proceeding pertain to implementation policies, certain 2008 project management decisions, long-term feasibility analysis for the TP67 project and the LNP, the reasonableness of estimated 2009 and projected 2010 costs, and PEF’s proposed rate management plan.

All parties, excluding FEA, filed post-hearing briefs on September 18, 2009.  The Commission has jurisdiction over these matters pursuant to Section 366.93, F.S., and other provisions of Chapter 366, F.S.

 

Table of Contents

 

List of acronyms and abbreviations................................................................................................. 7

 

 

NCRC Implementation Policy Issues

 

2          Carrying charge rate on deferred balances.......................................................................... 8

3          Recognition of different AFUDC rates.............................................................................. 11

 

 

FPL Issues

 

FPL Project Management

7          Project management, contracting, and oversight controls................................................... 17

7A       Consideration of alternative contracting structures for the TP67 project............................. 19

 

FPL’s Annual TP67 Project Feasibility Analysis

8          Approval of FPL’s submitted analysis.............................................................................. 22

8A       Actions if FPL’s submittal is denied.................................................................................. 26

 

FPL’s EPU Project

11        Requirement for separate and apart cost analysis.............................................................. 28

12        Reasonableness of 2009 costs and estimated true-up........................................................ 31

13        Reasonableness of 2010 projected costs.......................................................................... 34

 

FPL’s TP67 Project

16        Reasonableness of 2009 costs and estimated true-up........................................................ 36

17        Reasonableness of 2010 projected costs.......................................................................... 38

 

18        FPL’s Total Recoverable Amount for the 2010 CCRC.................................................... 40

 

PEF Issues

 

PEF Project Management

21        Project management, contracting, and oversight controls................................................... 42

21A     The December 2008 LNP engineering, procurement and construction contract................. 46

 

PEF’s Annual LNP Feasibility Analysis

23        Approval of PEF’s submitted Analysis............................................................................. 52

23A     Actions if PEF’s submittal is denied.................................................................................. 57

23B      Further Commission actions............................................................................................. 60

 

PEF’s CR3 Uprate Project

26        Reasonableness of 2009 costs and estimated true-up........................................................ 62

PEF’s LNP

30        Reasonableness of 2009 costs and estimated true-up........................................................ 64

31        Reasonableness of 2010 projected costs.......................................................................... 66

 

PEF’s Total Recoverable Amount for the 2010 CCRC

32        PEF’s rate management plan............................................................................................ 69

32A     2010 CCRC amount implementing the rate management plan ........................................... 71

32B      2010 CCRC amount without the rate management plan.................................................... 74

 

 

Appendix A

            Partially stipulated issues.................................................................................................. 76

 

 

 

Discussion of Issues

Issue 2: 

 When a utility elects to defer recovery of some or all of the costs that the Commission approves for recovery through the Capacity Cost Recovery Clause, what carrying charge should accrue on the deferred balance?

Recommendation: 

 Staff recommends that the applicable carrying charge rate on an NCRC regulatory asset that has been deferred from recovery is the pretax AFUDC rate in effect June 12, 2007, as set forth in Rule 25-6.0423, F.A.C.  For qualifying projects for which need petitions are submitted after December 31, 2010, the utility’s existing pretax AFUDC rate should be used.  (Slemkewicz, Young)

Position of the Parties

FPL: 

 If a utility elects to defer recovery, the deferred balance should remain in the NCRC as a regulatory asset and accrue carrying charges as the June 2007 pre-tax AFUDC rate.  Deferred amounts do not contribute to over/under recoveries subject to interest at the commercial paper rate applied to the CCRC.

PEF: 

  Pursuant to Section 366.93(1)(f) and Rule 25-6.0423(5)(a), a carrying charge equal to the utility’s allowance for funds used during construction rate should accrue until costs are recovered in rates.  If a utility is permitted to defer collection of costs, they are not recovered and should accrue the above carrying charge.

OPC: 

 No position.

PCS Phosphate: 

 No position.

FIPUG: 

 (Prehearing) FIPUG has not had adequate opportunity to formulate a legal opinion on this issue and will brief it.

SACE: 

 (Prehearing) SACE has not had adequate opportunity to formulate a legal opinion on this issue and will brief it.

Staff Analysis: 

 Resolution of this issue will establish the carrying charge applicable to an amount that a utility has been authorized to recover through the Capacity Cost Recovery Clause (CCRC), but for which recovery is deferred.  The resolution of this policy matter is timely because PEF requested approval of a rate management plan that is intended to recover an approved amount over a five-year period rather than over one year. (TR 930)  While PEF presented a position in its post-hearing brief, it did not explain why PEF supports the position. OPC’s and PCS Phosphate’s post-hearing briefs stated “No position” on this issue.  FIPUG and SACE did not address this issue in their post-hearing briefs.  Therefore, pursuant to the prehearing order, FIPUG and SACE have waived their positions on this issue.

FPL witness Powers asserted that if a utility requests deferral of approved costs and the Commission approves such deferral, then the Commission has effectively created a regulatory asset for future recovery. (TR 767)  The regulatory asset remains in the NCRC and continues to accrue carrying charges at the pre-tax allowance for funds used during construction (AFUDC) rate. (TR 767)  The regulatory asset does not contribute to over or under recoveries in the CCRC that are subject to the commercial paper rate. (TR 767-768)  Witness Powers explained that by Order No. PSC-03-0393-FOF-EI the Commission previously allowed a return on a regulatory liability for gains associated with emission allowances. (TR 767-768)  She also explained that, by Order No. 10306, the Commission created a regulatory asset and authorized FPL to charge AFUDC to the deferred amounts. (TR 767)  FPL asserted no party presented evidence supporting a different approach or questioned the reasonableness of the approach described by witness Powers. (FPL BR 8)

Staff believes FPL presented the appropriate analysis and accurately represented past Commission decisions.  On pages 4 and 5 of Order PSC-03-0393-FOF-EI,[10] the Commission stated:

First, we hold that Florida Power and Light Company should record the cost of emission allowances in Account 158.1, Allowances Inventory.  Any gains or losses associated with the disposition of allowances should be recorded in Account 254, Other Regulatory Liabilities, or Account 182.3, Other Regulatory Assets, respectively.  The above items are properly included in working capital until the applicable allowances are expensed.

In Order No. 10306,[11] at page 12, the Commission stated:

. . . we authorize FP&L to charge AFUDC to that amount until such time as the matter is considered in ratemaking proceeding following the resolution of litigation.

In both instances, the company booked amounts which accrued carrying charges and there was no contribution to clause over and under recovery calculations.  Consistent with past practices, deferral of recoverable NCRC amounts creates a regulatory asset that should accrue a carrying charge.  The applicable NCRC carrying charge is established by Section 366.93(2)(b), F.S., which states in part:

for nuclear or integrated gasification combined cycle power plant need petitions submitted on or before December 31, 2010, associated carrying costs shall be equal to the pretax AFUDC in effect upon this act becoming law.  For nuclear or integrated gasification combined cycle power plants for which need petitions are submitted after December 31, 2010, the utility's existing pretax AFUDC rate is presumed to be appropriate unless determined otherwise by the commission in the determination of need for the nuclear or integrated gasification combined cycle power plant.

Section 366.93, F.S., became law June 19, 2006.  Pursuant to the requirements of 366.93, F.S., the Commission adopted Rule 25-6.0423(5)(b), F.A.C., which states:

1. For power plant need petitions submitted on or before December 31, 2010, the associated carrying costs shall be computed based on the pretax AFUDC rate in effect on June 12, 2007;

2. For power plant need petitions submitted after December 31, 2010, the utility’s pretax AFUDC rate in effect at the time the petition for determination of need is filed is presumed to be appropriate unless the Commission determines otherwise in its need determination order; . . .

Staff believes that the applicable NCRC carrying charge rate is the same whether a company elects recovery or deferral of recovery.  Consequently, for costs associated with qualifying projects currently included in the NCRC, staff recommends that the applicable carrying charge rate is the pretax AFUDC rate in effect June 12, 2007.  For qualifying projects for which need petitions are submitted after December 31, 2010, the utility’s existing pretax AFUDC rate should be used. 

Staff believes that if a utility requests deferral of approved NCRC costs, and the Commission approves such deferral, then the Commission should authorize a NCRC regulatory asset for future recovery.  The regulatory asset remains in the NCRC and continues to accrue the applicable NCRC carrying charges.  The NCRC regulatory asset does not contribute to over or under recoveries in the CCRC that are subject to the commercial paper rate.

Conclusion

Staff recommends that the applicable carrying charge rate on an NCRC regulatory asset that has been deferred from recovery is the pretax AFUDC rate in effect June 12, 2007, as set forth in Rule 25-6.0423, F.A.C.  For qualifying projects for which need petitions are submitted after December 31, 2010, the utility’s existing pretax AFUDC rate should be used.

Issue 3:  Should FPL and PEF be permitted to record in rate base the incremental difference between Allowance for Funds Used During Construction (AFUDC) permitted by Section 366.93, F.S. and their respective most currently approved AFUDC, for recovery when the nuclear plant enters commercial operation?

 

Recommendation:  No.  Staff recommends that utilities not be permitted to record in rate base the incremental difference between carrying costs established in Section 366.93, F.S., and their respective most currently approved AFUDC rate applicable to all other projects, for recovery when the nuclear plant enters commercial operation.  Staff recommends the Commission find that Section 366.93, F.S., establishes a fixed project carrying cost to be applied to all nuclear construction projects with need petitions filed prior to December 31, 2010.  (Young, Hinton, Slemkewicz)

 

Position of the Parties

FPL: 

  Yes.  As defined by applicable Rule and Law, “costs” includes, but is not limited to, all capital investments including rate of return.  Recording the incremental or decremental difference would enable recovery of the Commission-approved carrying cost through the NCRC, while ensuring the customers only pay for actual financing costs.

PEF: 

  No, utilities should not be permitted to record in rate base the incremental difference between AFUDC permitted by statute and their most currently approved AFUDC for recovery when the nuclear plant enters commercial operation.  Section 366.93 fixes the carrying charge at the last approved AFUDC when the need was approved.

OPC: 

  No position.

PCS Phosphate: 

  No position.

FIPUG: 

  (Prehearing) FIPUG has not had adequate opportunity to formulate a legal opinion on this issue and will brief it.

SACE: 

  (Prehearing) SACE has not had adequate opportunity to formulate a legal opinion on this issue and will brief it.

Staff Analysis: 

 This issue addresses whether FPL and PEF should account for the difference between the carrying cost set forth in Section 366.93, F.S., and their respective Commission- approved AFUDC rates.  In question is whether the Statute establishes a particular project carrying cost to be applied regardless of changes to the currently approved AFUDC for a utility, or whether the Statute merely sets forth the amount (rate) that is permitted for recovery through the annual CCRC, with the difference between that amount and the utilities’ approved AFUDC rates being recorded and then recovered later.

In its statement of position, PEF asserted that the Statute fixes the carrying charge at the last approved AFUDC rate when the need was approved. (PEF BR 2)  PEF witness Foster explained that the Company’s position was based on a plain reading of the Section 366.93(2)(b), F.S. (TR 948)  PEF did not provide further support of its position in its post-hearing brief.

FPL asserted that utilities should be allowed to track, and eventually recover, the incremental/decremental difference between the carrying charge rate required by the Statute and the most current Commission-approved AFUDC rate for that utility. (FPL BR 9)  In its brief, FPL argued that Section 366.93, F.S., requires that Commission rules allow recovery of all prudently incurred costs, and that “costs” as defined by the Statute expressly includes “all capital investments, including rate of return.” (FPL BR 11)  FPL asserted that this means utilities are entitled to recover all carrying costs ultimately through the clause or in rates, and that it is not lawful to exclude any prudently incurred carrying costs. (FPL BR 11)  FPL witness Powers argued that utilities should be allowed to recover the approved carrying costs by tracking the incremental/decremental difference between the carrying charge rate required by the Statute and the most current Commission-approved AFUDC rate. (TR 768)

FPL witness Powers explained that the nuclear cost recovery rule allows recovery through the CCRC of a carrying charge at a fixed rate based upon the AFUDC rate in effect on June 12, 2007.  She further explained that FPL’s AFUDC rate is established by Rule 25-6.0141, F.A.C., and is applied to all eligible construction work in progress (CWIP) charges.  As FPL is only allowed to recover a carrying charge through the CCRC at the fixed rate specified in the Rule, any resulting incremental/decremental AFUDC amounts will remain in CWIP until the nuclear project is placed into service, at which time any increment or decrement will be transferred to plant in service. (TR 326-327)

Witness Powers suggested that the incremental/decremental difference should be accumulated and recorded to CWIP and then either recovered or returned through base rates once the plant is placed in commercial service. (TR 768; BR 9)  She explained that this method allows for recovery of FPL’s Commission-approved carrying cost through the NCRC, while ensuring the customer ultimately only pays for the actual financing costs incurred. (TR 768-770, 773; FPL BR 9)  Witness Powers asserted that this approach is fair to both customers and the utility. (TR 772; FPL BR 9) 

FPL argued that its position prevents the “very real likelihood of windfall gains or losses to FPL or customers which would arise over time under other parties’ interpretations, as a utility’s actual AFUDC financing costs vary, either higher or lower, than the carrying cost amount provided by statue and rule for NCRC collections.” (FPL BR 10-11)  FPL argued that the other party’s position would foster either a permanent over or under-recovery, depending on the difference between a utility’s AFUDC rate from time to time and the carrying cost provided for in the Rule. (FPL BR 11)  FPL suggested that this unfair result can be easily avoided by the simple approach advocated by FPL. (FPL BR 11)  FPL witness Powers stated that the ultimate result of FPL’s methodology would be that the company recovers its actual rate of return and the customer pays only the actual rate of return on the nuclear projects, no more and no less.  (Composite EXH 2, No. 8, p.51; FPL BR 10)  Intervenors in this proceeding took no position on this issue. 

Section 366.93(2)(b), F.S., states:

Recovery through an incremental increase in the utility's capacity cost recovery clause rates of the carrying costs on the utility's projected construction cost balance associated with the nuclear or integrated gasification combined cycle power plant. To encourage investment and provide certainty, for nuclear or integrated gasification combined cycle power plant need petitions submitted on or before December 31, 2010, associated carrying costs shall be equal to the pretax AFUDC in effect upon this act becoming law.  For nuclear or integrated gasification combined cycle power plants for which need petitions are submitted after December 31, 2010, the utility's existing pretax AFUDC rate is presumed to be appropriate unless determined otherwise by the commission in the determination of need for the nuclear or integrated gasification combined cycle power plant.

Rule 25-6.0423(5)(b), F.A.C., is the Commission’s interpretation of Section 366.93, F.S.  Rule 25-6.0423(5)(b), F.A.C., titled “Carrying Costs on Construction Cost Balance,” provides:

A utility is entitled to recover, through the utility’s Capacity Cost Recovery Clause, the carrying costs on the utility’s annual projected construction cost balance associated with the power plant.  The actual carrying costs recovered through the Capacity Cost Recovery Clause shall reduce the allowance for funds used during construction (AFUDC) that would otherwise have been recorded as a cost of construction eligible for future recovery as plant in service.

1. For power plant need petitions submitted on or before December 31, 2010, the associated carrying costs shall be computed based on the pretax AFUDC rate in effect on June 12, 2007;

2. For power plant need petitions submitted after December 31, 2010, the utility’s pretax AFUDC rate in effect at the time the petition for determination of need is filed is presumed to be appropriate unless the Commission determines otherwise in its need determination order;

3. The Commission shall include carrying costs on the balance of construction costs determined to be reasonable or prudent in setting the factor in the annual Capacity Cost Recovery Clause proceedings, as specified in paragraph (5)(c) of this rule.

As mentioned above, the Commission must determine whether the Statute and Rule establish a particular carrying cost to be applied to nuclear projects regardless of changes to the AFUDC rate applied to other construction projects, or whether the utilities are entitled to track and record the difference between the carrying cost specified for NCRC recovery and the currently-approved AFUDC rate.  As stated, FPL suggests that in “deciding this issue and the appropriate interpretation of the controlling Statute and Rule, the Commission must view the Statute and the Rule in their entirety and harmonize the various provisions to give meaning to the laws as a whole.” (FPL BR 12)  Staff agrees that this is the appropriate approach.  However, staff does not believe the Statute or Rule should be used in such a way as to assume a meaning or intent that is not clearly portrayed in the language.

Although FPL’s methodology of tracking and recording the incremental/decremental CWIP balance difference resulting from using two rates is not necessarily an unreasonable approach, staff is not persuaded that this methodology was contemplated or intended by Section 366.93, F.S., and Rule 25-6.0423, F.A.C.  In its brief, FPL asserted that Rule 25-6.0423(5)(b)(1) “expressly contemplates and allows” for FPL’s approach to tracking the incremental/decremental difference between its actual AFUDC rate and the rate used for computation of clause recovery. (FPL BR 11) This section of the Rule states:

The actual carrying costs recovered through the Capacity Cost Recovery Clause shall reduce the allowance for funds used during construction (AFUDC) that would otherwise have been recorded as a cost of construction eligible for future recovery as plant in service.

FPL stated that the only way to give meaning to the requirement of the Statute and Rule is to recover the rule-specified carrying cost amount through the NCRC, while recording the increment/decrement “as a cost of construction eligible for future recovery as plant in service” as required by this section of the Rule. (FPL BR 12)  Staff disagrees.  Staff believes this language was included to guard against double recovery of carrying costs by ensuring that carrying costs are deducted from the utility’s total CWIP allowance for all projects as the carrying costs are recovered through the CCRC each year.  Staff does not believe the Rule “expressly contemplated” that a portion of the currently approved AFUDC would remain in CWIP, or that a negative would be recorded in CWIP if a carrying cost higher than the currently approved AFUDC rate is recovered through the CCRC. 

When a utility’s currently-approved AFUDC rate is higher than the carrying cost rate permitted by the Statute and the Rule, it is understandable that one might seek to recover the difference as FPL suggests.  However, in the converse, staff believes FPL’s approach could lead to the absurd result of purposefully allowing annual recovery of a carrying cost that is higher, with the intent of truing-up the carrying cost when the plant goes into commercial operation.  In either scenario, this mechanism of true-up to the Commission-prescribed AFUDC under Rule 25-6.0141, F.A.C., is not presented in either Section 366.93, F.S., or Rule 25-6.0423, F.A.C.

If FPL’s approach was intended by the Statute or Rule, it could have easily been stated as such.  Section 366.93(2)(b), F.S., specifically states in part:

To encourage investment and provide certainty, for nuclear or integrated gasification combined cycle power plant need petitions submitted on or before December 31, 2010, associated carrying costs shall be equal to the pretax AFUDC in effect upon this act becoming law.  For nuclear or integrated gasification combined cycle power plants for which need petitions are submitted after December 31, 2010, the utility's existing pretax AFUDC rate is presumed to be appropriate unless determined otherwise by the commission in the determination of need for the nuclear or integrated gasification combined cycle power plant.

(emphasis added)

If the intent was to allow recovery through the CCRC of only a portion, or perhaps in excess, of the utility’s currently approved AFUDC rate, the language could have stated that intent.  Rather, staff agrees with PEF that this section of the Statute and the corresponding Rule language established a fixed carrying cost to be applied to nuclear projects filed prior to December 31, 2010.  For projects filed after that date, the utility’s existing AFUDC rate would apply. Here, FPL filed its need petition for Turkey Point 6 & 7 project (TP67 project) before December 31, 2010.  Similarly, FPL filed its need petition for Turkey Point Units 3 & 4 and St. Lucie Units 1 & 2 uprate (EPU Project) before December 31, 2010.  Thus, the associated carrying cost applicable to these project costs is FPL’s AFUDC rate in effect when Section 366.93, F.S., became law, which is 7.42 percent.

FPL argued that its position is consistent with the statutory purpose of encouraging development of additional generation to benefit FPL’s customers, and that ensuring recovery of only the financing cost actually incurred reduces risk for FPL, investors, and customers. (FPL BR 10)  Staff agrees that the statutory purpose of Section 366.93, F.S., is to promote utility investment in nuclear power plants.  To do so, the legislature created an alternative cost recovery mechanism.  That mechanism includes a fixed carrying cost rate to be applied to project costs for which FPL and PEF seek recovery under the alternative mechanism.  Section 366.93(2)(b), F.S., states that in order to “encourage investment and provide certainty,” carrying costs shall be equal to the pretax AFUDC rate in effect on June 12, 2007.  Staff believes the legislature provided certainty by establishing a  carrying cost rate to be applied to the nuclear projects, and this carrying cost shall be recovered pursuant to Rule 25-6.0423(2), F.A.C., no more and no less.

Moreover, since the enactment of Section 366.93, F.S., the Commission has consistently distinguished the carrying cost associated with the nuclear projects (i.e., TP67 project) from the carrying cost associated with all other utility projects.  Order No. PSC-08-0265-PAA-EI, issued April 28, 2008, in Docket No. 080088-EI, In re: Request for approval of change in rate used to capitalize allowance for funds used during construction (AFUDC) from 7.42% to 7.65%, effective January 1, 2008, by Florida Power & Light Company, the Commission specifically held that the revised AFUDC rate shall be effective as of January 1, 2008, for all purposes except for Rule 25-6.0423, F.A.C.  Similarly, in Order No. 09-0377-PAA-EI, issued May 28, 2009, in Docket No. 090108-EI, In re: Request for approval of change in rate used to capitalize allowance for funds used during construction (AFUDC) from 7.65% to 7.41%, effective January 1, 2009, by Florida Power & Light Company, the Commission held that the revised AFUDC rate shall be effective as of January 1, 2009, for all purposes except for Rule 25-6.0423, F.A.C.  This emphasizes the point that Section 366.93(2)(b), F.S., establishes a fixed project carrying cost to be applied to all nuclear construction projects with need petitions filed prior to December 31, 2010.  Staff believes any other interpretation of Section 366.93(2)(b), F.S., is incorrect. 

FIPUG’s and SACE’s prehearing positions state they have “not had adequate opportunity to formulate a legal opinion on this issue and will brief it.”  However, FIPUG and SACE did not address this issue in their post-hearing briefs.  Therefore, pursuant to the prehearing order, FIPUG and SACE have waived their positions on this issue.

Conclusion

Staff recommends that utilities not be permitted to record in rate base the incremental difference between carrying costs established in Section 366.93, F.S., and their respective most currently approved AFUDC rate applicable to all other projects, for recovery when the nuclear plant enters commercial operation.  Staff recommends the Commission find that Section 366.93, F.S., establishes a fixed project carrying cost to be applied to all nuclear construction projects with need petitions filed prior to December 31, 2010.

Issue 7: 

 Should the Commission find that for the year 2008, FPL’s project management, contracting, and oversight controls were reasonable and prudent for the Turkey Point Units 6 & 7 project and the Extended Power Uprate project?

Recommendation: 

 Staff recommends the Commission find FPL’s 2008 project management, contracting, and oversight controls were reasonable and prudent for the EPU project and for the TP67 project.  FPL’s approach to TP67 project EPC contract management is addressed separately in Issue 7A.  The feasibility of continuing FPL’s TP67 project and FPL’s supporting feasibility analysis are addressed in Issue 8.  (Breman)

Position of the Parties

FPL: 

  Yes. FPL’s practices include a series of well-documented, highly developed, overlapping processes that ensure the Company’s system of internal controls is being implemented within the projects and ensure the appropriate levels of senior management oversight.

OPC: 

  For Turkey Point Units 6 & 7, see Issue 7A. With respect to the EPU project, no position at this time.

FIPUG: 

  Concurs with OPC’s position.

SACE: 

  No position.

Staff Analysis: 

 This issue addresses the reasonableness and prudence of 2008 project management, contracting, and oversight controls incorporated by FPL as part of its EPU project and the TP67 project.  However, matters related to FPL’s assessment of an alternative to a TP67 project engineering, procurement and construction contract (EPC contract) are addressed separately in Issue 7A (page 19).  Also, FPL’s TP67 project feasibility and submitted analysis are addressed in Issue 8 (page 22).

Staff reviewed the record, post-hearing positions of the parties, and the briefs.  Aside from the issues mentioned above, no party raised questions concerning FPL’s 2008 project management, contracting, and oversight controls for the TP67 project and the EPU project.

OPC’s prehearing and post-hearing positions are the same, and state “For Turkey Point Units 6 & 7, see Issue 7A.  With respect to the EPU project, no position at this time.”  FIPUG’s position concurs with OPC’s position.  FIPUG did not address this issue in its post-hearing brief; therefore, pursuant to the prehearing order, FIPUG has waived its position on this issue.  SACE took no position prior to hearing and did not address this issue in its post-hearing brief; thus, SACE has waived its position on this issue.

FPL contracted with Concentric Energy Advisors, Inc. (Concentric), an economic advisory and management consulting firm, to review the appropriate prudence standard, review the processes and procedures FPL used to manage the EPU and TP67 projects, FPL’s internal controls, and FPL’s compliance with its internal procedures and controls. (TR 358, 415)  Witness Reed, the Chairman and Chief Executive Officer of Concentric, filed testimony asserting that FPL’s policies and procedures were robust and have been adhered to.  (TR 431, 432)  Witness Reed affirmed that it would be appropriate for the Commission to consider the prudence of a utility's decision based upon the information it knew or should have known at the time the decision was made. (TR 822)   Witness Reed presented Concentric’s conclusion that FPL had reasonable polices and procedures, FPL adhered to them, and that the project costs were prudently incurred. (TR 409, 410, 431, 432)

Staff witnesses Fisher and Rich sponsored testimony and an audit report examining the internal control procedures by which FPL manages and tracks the costs and the schedules of FPL’s two projects. (TR 604; EX 70)  Staff witnesses Fisher and Rich stated:

The primary objective of this review was to document project key developments, along with the organization, management, internal controls, and oversight that FPL has in place or plans to employ for these projects. The internal controls examined were related to the following areas of project activity: planning, management and organization, cost and schedule controls, contractor selection and management, and auditing and quality assurance.

(TR 605)

The audit report addressed the period April 2008 through June 2009. (TR 604)  Staff reviewed the management audit report, Exhibit 70, to determine whether it contained support for a finding of imprudence, and did not find any.  The applied standard for determining prudence is consideration of what a reasonable utility manager would have done in light of conditions and circumstances which were known or reasonably should have been known at the time decisions were made.[12]  Staff notes that this is the same standard applied by witness Reed. (TR 362-367)

Conclusion

Based on record of evidence, staff believes that FPL’s decisions and actions were in keeping with reasonable business practices, and were prudent.  Staff recommends the Commission find FPL’s 2008 project management, contracting, and oversight controls were reasonable and prudent for the EPU project and for the TP67 project.  FPL’s approach to TP67 project EPC contract management is addressed separately in Issue 7A.  The feasibility of continuing FPL’s TP67 project and FPL’s supporting feasibility analysis are addressed in Issue 8.

 

Issue 7A: 

 Is FPL's decision in 2008 to pursue an alternative to an Engineering Procurement Construction (EPC) contract for the Turkey Point 6 & 7 project prudent and reasonable?

Recommendation: 

 Staff recommends that FPL’s 2008 decision to create the potential for additional competitive opportunity through an EP/C contractual approach to the TP67 project was reasonable and prudent.   (Breman)

Position of the Parties

FPL: 

  Yes.  FPL chose to create the option to pursue separate EP and C contracts while preserving the option of pursuing an EPC contract for Turkey Point 6 & 7.  FPL’s approach creates greater flexibility and optionally for itself and its customers, as well as the potential for significant cost savings for FPL’s customers.

OPC: 

  No.  Given the proprietary nature of the AP1000 technology, separating the construction function from engineering and procurement in a project as large and complex as the Turkey Point 6 & 7 project would expose FPL and its customers to the risk of unreasonably high costs.

FIPUG: 

  No.  Separating the construction portion from the engineering and procurement portions of an engineering, procurement and construction contract, (“EPC”) imposes greater risks on the ratepayers for scheduling delays and uncertainty related to scope of services.

SACE: 

  (Prehearing) No position.

Staff Analysis: 

 This issue addresses the reasonableness and prudence of FPL’s 2008 project management decision to assess an alternative contracting strategy for the TP67 project.  One contractual approach is a comprehensive EPC contract.  The alternative approach FPL considered separates the engineering and procurement contract from the construction contract (EP/C contracts).  (TR 63, 64, 76, 152, 153, 156; EX 70 p 5)  FPL has not entered into EP/C contracts and has not abandoned the option of an EPC contract. (TR 20, 64, 616, 640, 816)  Neither has FPL quantified the potential savings of an EP/C approach over an EPC approach. (TR 190)  In his March 2, 2009 testimony FPL witness Scroggs described what FPL considered and determined with regard to the contracting strategy.

The vendor-proposed business model for new nuclear project deployment of the AP-1000 design involves an EPC contract with Westinghouse/Shaw with defined scope and schedule responsibility. FPL challenged this business model based on several key observations. First, the EPC offered by Westinghouse/Shaw is limited in its ability to provide cost and schedule certainty as to key project elements (such as construction labor) that are not included in the EPC contract scope and pricing. Additionally, the proposed EPC approach does not provide opportunities for other engineering and construction firms to compete directly for components of the work.

(TR 63, emphasis added)

The proprietary portion of the TP67 project is approximately $3 billion of the approximate total $18 billion project cost. (TR 652)  FPL will necessarily be required to sole source the engineering and procurement portion of the project to Shaw/Westinghouse due to the proprietary nature of the AP-1000 design. (TR 622)  However, discussion with Shaw/Westinghouse offered limited ability to provide construction cost and schedule certainty. (TR 63, 655D)  FPL witness Reed noted that splitting out the construction piece from the engineering and procurement could potentially lead to greater disputes about scope of services and responsibilities compared to combining all three elements together. (TR 465)  He also expressed a view that there are potentially very substantial customer benefits related to separating the EP work from the construction work. (TR 465)

Consequently, FPL sought to create the potential for more competitive options for the construction phase of the project. (TR 63)  FPL selected a consortium of Black & Veatch and Zachry Construction (BVZ), an engineering firm independent of Shaw/Westinghouse, to perform certain preconstruction planning and design work. (TR 63, 614, EX 71)  The scope of work BVZ was selected to perform is not the EP or C portion of an EP/C contract. (TR 613)  As previously noted, FPL has not entered into EP/C contracts nor has it abandoned the EPC option.

In its position statement, FIPUG argued that FPL was not prudent.  FIPUG asserted that no nuclear power plant previously developed in the United States by an investor-owned utility has utilized a contracting strategy which separates the construction from the engineering and procurement. (FIPUG BR 3, TR 465)  FIPUG alleged that continued pursuit of FPL’s strategy, without a direct contractual linkage to the construction portion of the project, will likely result in questions and disputes and undoubtedly increase costs of the project. (FIPUG BR 3)  FIPUG argued that FPL’s decision is questionable, especially when the purported benefits have not been quantified in a meaningful way. (FIPIG BR 4)

OPC witness Jacobs expressed a view that “an EPC type contract utilizing a turn-key approach with a single entity clearly reduces the risk for FPL.” (TR 479)   He asserted FPL's plan for a separate construction contractor may ultimately result in higher costs for this project. (TR 478-479, 482)  His expectation is that FPL’s choice may result in unreasonably high costs. (TR 498)  He raised this issue now so that it is clear that the potential for increased costs was identified “without the benefit of hindsight in future prudence determinations.” (TR 478) 

SACE did not address this issue in its post-hearing brief.  Therefore, pursuant to the prehearing order, FIPUG and SACE have waived their positions on this issue.

Staff reviewed the record evidence for any analysis by witness Jacobs addressing FPL’s contract discussions with Shaw-Stone & Webster and Westinghouse (Shaw/Westinghouse) and found none.  This is significant because OPC relied on the testimony of witness Jacobs as support for its position that FPL was not prudent. (OPC BR 25)  Additionally, witness Jacobs was the sole witness challenging FPL’s contractual actions.  As stated, the standard for determining prudence requires a review of the information FPL’s management relied on or should have been aware of at the time the decision was made.  Staff found no analysis of FPL’s contract discussions apart from FPL’s testimony.  Therefore, staff believes that OPC witness Jacobs offered a generic statement that does not consider specific matters a reasonable utility manager should have considered at the time of making a decision.

However, staff believes a decision regarding the prudence of FPL’s possible contract(s) and subsequent contract management are premature.  At this time, the terms and conditions of any EPC contract or EP/C contracts are unknown.  When and if FPL requests recovery of prudently incurred costs resulting from such contracts, then the terms and conditions that give rise to those costs can be reviewed.  At that time FPL will have the opportunity to demonstrate why it believes the contract terms and conditions are prudent and reasonable.  FPL’s actions are, and will continue to be, reviewed pursuant to Section 366.93, F.S., and Rule 25-6.0423, F.A.C.

Conclusion

Based on the forgoing analysis, staff recommends that FPL’s 2008 decision to create the potential for additional competitive opportunity through an EP/C contractual approach to the TP67 project was reasonable and prudent.

 

 

Issue 8: 

 Should the Commission approve what FPL has submitted as its annual detailed analyses of the long-term feasibility of completing the Turkey Point 6 & 7 project, as provided for in Rule 25-6.0423, F.A.C.?

Recommendation: 

 Yes.  Staff believes that the information and analysis submitted by FPL are sufficient and satisfactory for compliance with Rule 25-6.0423, F.A.C., and Order No. PSC-08-0237-FOF-EI regarding the annual detailed analysis of the long-term feasibility of Turkey Point 6 & 7 project.  FPL should be required to file updated capital cost estimates in its next annual NCRC filing.  (Graves)

Position of the Parties

FPL: 

  Yes.  FPL’s analyses consider different fuel cost and environmental compliance cost forecasts to examine the economics of the project in a variety of future scenarios.  These assumptions, as well as forecasted load and other inputs, are updated annually.  FPL’s non-binding cost estimate used in these analyses continues to be valid.

OPC: 

  No.  FPL updated its assumptions in other respects, but did not update its estimate of the cost of Turkey Point 6&7.  Without the updated construction costs, FPL’s “updated feasibility study” is worthless.

FIPUG: 

  No.  Detailed and updated construction costs should have been provided.  Without such information, the Commission cannot undertake properly its responsibility to determine whether the project is feasible.

SACE: 

  No.  FPL has not submitted the detailed analysis required by Rule 25-6.0423(5)(c)5.  FPL’s economic analysis was based on a low, outdated total project cost estimate range and was centered on an unrealistic set of assumptions.  The analysis also failed to consider regulatory and technological feasibility.

Staff Analysis: 

 This issue addresses review and approval of FPL’s detailed long-term feasibility of continuing construction and completing the TP67 project as provided for in Rule 25-6.0423, F.A.C.

FPL asserted that its 2009 feasibility analysis satisfied the requirements of the rule.  FPL further claimed that the analytical approach that was used in the 2009 feasibility analysis for TP67 is the same as the approach used in the 2007 Determination of Need filing and the 2008 feasibility analysis.  FPL further contended that the calculation of overnight “breakeven” costs continues to be the appropriate approach to use at this time. (FPL BR 29-32)

OPC argued that because FPL did not update capital costs of the proposed nuclear plant, its analysis has only been half performed.  OPC further contended that the chief component of feasibility is the projected capital investment that will be necessary to place the unit into service.  OPC asserted that FPL’s omission of an updated capital cost estimate creates the impression that it is withholding bad news that would place into question the prudence or wisdom of moving forward with the project. (OPC BR  9-11)

FIPUG asserted that without legislation, FPL’s nuclear project costs would be recovered in base rates by means of a rate case.  Furthermore, FIPUG argued that in a rate case, FPL would have to prove the details and prudence of the costs it seeks to recover.   FIPUG contended that FPL's failure to provide detailed updated construction costs for the proposed nuclear power plants cannot be overlooked and FPL failed to meet its burden of proof. (FIPUG BR 4-5)

SACE contended that FPL’s decision to proceed with TP67 was based on important assumptions that have changed since FPL was granted an affirmative determination of need for TP67.  SACE argued that FPL used a low estimate of the cost of nuclear reactors, downplayed the contribution that efficiency and renewables can make in meeting the need for electricity, assumed much higher prices for natural gas than are now projected, and assumed a much higher price for carbon dioxide emissions for fossil plants than recent legislation in Congress would impose. (SACE BR 13-16)

In an effort to mitigate the economic risks associated with the long lead time and high capital costs associated with nuclear power plants, the Florida Legislature enacted Sections 366.93 and 403.519(4), F.S., during the 2006 legislative session.  Section 366.93(2), F.S., requires the Commission to establish, by rule, alternative cost recovery mechanisms for the recovery of costs incurred in the siting, design, licensing, and construction of a nuclear power plant.  The Commission established Rule 25-6.0423, F.A.C, in order to satisfy the requirements of Section 366.93(2), F.S.  Rule 25-6.0423(5)(c)5, F.A.C, states:

By May 1 of each year, along with the filings required by this paragraph, a utility shall submit for Commission review and approval a detailed analysis of the long-term feasibility of completing the power plant.

On page 29 of Order No. PSC-08-0237-FOF-EI , the Commission provided specific guidance to FPL regarding the requirements necessary to satisfy Rule 25-6.0423(5)(c)5, F.A.C.[13]  The Order reads as follows:

FPL shall provide a long-term feasibility analysis as part of its annual cost recovery process which, in this case, shall also include updated fuel forecasts, environmental forecasts, break-even costs, and capital cost estimates.  In addition, FPL should account for sunk costs.  Providing this information on an annual basis will allow us to monitor the feasibility regarding the continued construction of Turkey Point 6 and 7.

Staff believes that the discussed forecasts, information, estimates, and analyses are necessary filing requirements to assess FPL’s 2009 TP67 project feasibility analysis and will provide the basis for staff’s recommendation regarding the approval or denial of FPL’s detailed analysis.

Updated Fuel Forecasts

FPL used high, medium, and low fuel forecast scenarios in its feasibility analysis.  FPL’s fuel forecasts provided in this docket are the same as those relied on in the Company’s 2009 Ten-Year Site Plan. (EX 2, p. 54)  A comparison of forecasted natural gas costs utilized in FPL’s 2009 feasibility analysis with those used in FPL’s 2008 analysis shows a general trend of: (i) lower natural gas costs in 2010, (ii) higher natural gas costs in the near-term years of 2015 through 2025, then (iii) lower natural gas costs in the later years of 2030 through 2040. (TR 279)

OPC asserted that FPL appropriately identified changes in key parameters such as gas prices. (TR 486)  SACE argued that FPL’s natural gas price forecasts were too high. (TR 561) FPL contended that SACE’s analysis of long-term natural gas prices was inconsistent and inappropriate. (TR 808-810)  Staff believes that there is inherent uncertainty surrounding fuel forecasting.  Staff believes that FPL’s use of third party forecasts is consistent with Commission accepted practice. (EX 2, Tab 10; EX 129)  Additionally, staff believes that reviewing the TP67 project feasibility using a range of long-term fuel forecasts reasonably accounts for the volatility in the natural gas market.  As discussed below, the updated fuel forecasts did not significantly affect the break-even analysis.

Updated Environmental Forecasts

FPL’s environmental compliance cost forecasts were based on ICF International’s U.S. Emission & Fuel Markets Outlook Winter 2007/2008.  From this, FPL produced four sets of projected compliance costs.  The set of compliance costs provided a range of potential costs.  (EX 2, p. 55)

OPC asserted that FPL appropriately identified changes in key parameters such as carbon tax. (TR 486)  SACE contended that FPL’s carbon estimates were too high and that the company’s exclusion of an analysis assuming a renewable portfolio standard renders the filing deficient. (TR 562-563, 571)  SACE argued that H.R. 2545, the American Clean Energy and Security Act, should have been considered by FPL.  FPL argued that it had to freeze assumptions months ahead of time before the testimony filing date of May 1, 2009. (TR 746-748)  FPL further asserted that it could not project all of the effects of a bill that changed significantly a number of times before passage and still meet the NCRC filing date. (TR 736-747)  Staff believes that there is uncertainty regarding the future legislation of carbon dioxide (CO2), as well as potential issues regarding the timing of filing requirements and on-going legislation.  Staff believes that providing a range of CO2 forecasts is reasonable until legislation is enacted.

Break-Even Costs

OPC asserted that FPL appropriately calculated the break-even capital costs for comparison with an alternative project. (TR 486)  SACE contended that FPL’s break-even analysis was not a common approach to making the comparison between alternatives. (TR 581)  Staff recognizes that the analysis is unique; however, the Commission previously accepted this approach in the TP67 project need determination.  Staff believes such an approach is reasonable today.  It is notable that according to FPL’s analysis, the TP67 project is the most cost-effective generation alternative at this time. (TR 287)  The results of FPL’s non-binding estimated range of capital costs in 2007 dollars of $3,108/kw to $4,540/kw, shows that the projected breakeven capital costs for the TP67 project are above the upper bound of $4,540/kw in 8 of the 9 fuel cost and environmental compliance cost scenarios. (TR 286-287)  In the 9th scenario, which consists of low fuel costs and low environmental compliance costs, the projected breakeven capital costs are at the upper end ($4,414/kw) of this range. (TR 286-287)  Staff believes that an annual economic analysis can and should be used to track trends and determine the effects of those trends. 

Capital Cost Estimates

FPL’s capital cost range remained as presented in the TP67 project need determination. (TR 623)  OPC contended that FPL’s capital cost estimates rely on stale information.  FPL witness Sim argued that the capital cost range presented in the TP67 project need determination were still applicable for this analysis. (TR 623)  Staff recognizes that several uncertainties regarding the cost of TP67 project remain at this time.  Staff believes that FPL’s presentation of the capital cost estimate as a range is reasonable at this time.  As discussed in Issue 7A (page 19), FPL has not completed negotiations regarding its EP/C or EPC contracts.  FPL should be required to file updated capital cost estimates in its next annual NCRC filing.

Conclusion

Based upon the summation of the discussion above, staff believes the information and analysis provided by FPL are sufficient and satisfactory for compliance with Rule 25-6.0423, F.A.C., and Order No. PSC-08-0237-FOF-EI regarding the annual detailed analysis of the long-term feasibility of the TP67 project.  Staff believes that the information and analysis provided allows the necessary review to track potential trends that are paramount in determining the on-going feasibility of the TP67 project.  Staff also believes that the analysis supports a conclusion that completing the TP67 project is feasible at this time.

 

Issue 8A: 

 If the Commission does not approve FPL’s long term feasibility analyses of Turkey Point 6 & 7, what further action, if any, should the Commission take?

Recommendation: 

 If the Commission does not approve FPL’s May 1, 2009 long-term feasibility analysis of Turkey Point 6 & 7, staff recommends that FPL address the Commission’s concerns with the current filing in their May 1, 2010 testimony. (Graves, Breman, Laux)

Position of the Parties

FPL: 

  No Commission action is necessary.  FPL’s annual detailed analysis of the long-term feasibility of completing the Turkey Point 6 & 7 project complies with Rule 25-6.0423, F.A.C., as should be approved.

OPC: 

  The Commission should order FPL to conduct the proper updated feasibility study by a time certain.  Once the Commission receives it, the Commission should evaluate whether the project remains feasible on a long term basis.

FIPUG: 

  The Commission should require FPL to prepare and file, in a timely fashion, an updated feasibility study.  The Commission should suggest that FPL explore a strategic partnership with other Florida investor-owned utilities and provide additional information on risk and cost reduction to consumers.  FPL should use its best efforts to forge a meaningful strategic partnership with other Florida investor-owned utilities.

SACE: 

  The Commission should deny cost recovery for FPL’s estimated 2009 and projected 2010 costs.

Staff Analysis: 

  This issue is moot if the Commission approves staff’s recommendation in Issue 8 (page 22).

This issue addresses what further action, if any, the Commission should take if it does not approve FPL’s 2009 detailed long-term feasibility analysis of the TP67 project.  In Issue 8, FPL argued that its long-term feasibility analysis fully comply with Rule 25-6.0423, F.A.C. (FPL BR 33)   The intervenors, while asserting FPL failed to comply with the rule, did not necessarily agree on the reasons.  OPC asserted FPL’s study is incomplete and not detailed because FPL did not update its capital cost estimate.  (OPC BR 9-11)  Similarly, FIPUG argued that FPL failed to meet its burden of proof by not providing detailed updated construction costs. (FIPUG BR 5)  SACE contended that FPL’s economic analysis was insufficient. (SACE BR 16)

The intervenors similarly disagreed on what further actions the Commission should take in addressing asserted non-compliance.  OPC suggested FPL be ordered to conduct the proper updated feasibility study by a time certain. (OPC BR 9)  FIPUG also urged the Commission to require that FPL prepare and file, in a timely fashion, an updated study. (FIPUG BR 5) Additionally, FIPUG stated that the Commission should suggest FPL explore a strategic partnership with other Florida investor-owned utilities and provide additional information of risk and cost reductions.  (FIPUG BR 5)  SACE contended that the Commission deny recovery of 2009 and 2010 TP67 project costs until a sufficient feasibility analysis is filed.[14] (SACE BR 1, 3)

Staff believes resolution of this issue hinges on the Commission’s basis for denial of FPL’s 2009 TP67 feasibility analysis in Issue 8.  As described above, there may be various reasons for Commission denial.  Depending on the rationale for denial, the Commission may choose to take different corrective actions.  Given this, staff believes that the following potential actions may exist.

·        Deferred Decision:  The Commission can elect not to make a decision regarding project feasibility analysis until it has reviewed the next annual filing, due May 1, 2010, in order to establish a pattern or trend.  FPL’s subsequent filing would include use of appropriate updated assumptions, costs, and be expanded, as necessary, to address any concerns with additional scope.  This action is supported if the Commission finds a lack of credible capital cost evidence supporting the feasibility analysis at this time.  It is also consistent with the ongoing nature of the clause.  This action does not result in adjustments to the recoverable amounts in any of FPL’s issues.

·        Require an Updated 2009 Long-term Feasibility Analysis:  The Commission can direct FPL to file an updated long-term TP67 project feasibility analysis by January 1, 2010.  This action is supportable if the Commission finds FPL failed to appropriately include available assumptions and cost data in its 2009 filing.  This action does not result in adjustments to the recoverable amounts in any of FPL’s issues.

·        Deny Future Cost Recovery: The Commission can elect to deny cost recovery if the Commission finds credible evidence that FPL’s plan to continue the TP67 project is imprudent.  The cost recovery adjustments resulting from this action are included in staff’s analysis of Issues 16, 17, and 18 (pages 36, 38, 40).

Conclusion

If FPL’s 2009 long-term feasibility analysis of the TP67 project, filed May 1, are not approved, staff recommends FPL be directed to address the Commission’s concerns in its May 1, 2010 annual filings and testimony. 

 

Issue 11: 

 Are FPL’s 2008 actual, 2009 actual/estimated and 2010 projected EPU project costs separate and apart from the nuclear costs that would have been necessary to provide safe and reliable service had there been no EPU project?

Recommendation: 

 Staff recommends that the Commission find FPL’s 2008 actual, 2009 actual/estimated and 2010 projected EPU project costs are separate and apart from the nuclear costs that would have been necessary to provide safe and reliable service had there been no EPU project.  (Breman)

Position of the Parties

FPL: 

  Yes. FPL employs a rigorous, engineering-based process to ensure that only costs that are “separate and apart” from those that would have been incurred otherwise have been included in its NCRC request.  FPL is in full compliance with the stipulation on this issue, entered into in Docket 080009-EI.

OPC: 

  FPL has not met its burden of proving that these costs are separate and apart from the nuclear costs that would have been necessary to provide safe and reliable service had there been no EPU project.

FIPUG: 

  Insufficient evidence was provided at hearing to meet FPL’s burden of proof that such costs are separate and apart from nuclear costs that would have been necessary to provide safe and reliable service had there been on EPU project.

SACE: 

  (Prehearing) No position.

Staff Analysis: 

 This issue addresses whether FPL’s EPU project costs are separate and apart from the costs that would have otherwise been necessary had there been no EPU project.  In Order PSC-08-0749-FOF-EI, at page 29, the Commission approved the following stipulation:

OPC and FPL stipulate that as it applies to nuclear uprate projects, the NCRC should be limited to those costs that are separate and apart from nuclear costs that would have been necessary to provide safe and reliable service had there been no uprate project.  OPC and FPL will work with PSC staff to develop an NFR form for use in the 2009 hearing cycle that specifies the information that a utility will provide in support of its request, that the uprate costs in its NCRC filing are separate and apart from the costs that would have been necessary to provide safe and reliable service without the uprate.  For purposes of the 2008 NCRC hearings, OPC will not challenge the prudence of FPL’s 2007 uprate costs on the “separate and apart” issue.  OPC’s position for the 2007 uprate costs, however, does not prevent OPC from raising the “separate and apart” issue for any FPL uprate costs incurred subsequent to 2007.

Witness Kundalkar explained that FPL‘s “separate and apart” analysis focuses on:

(i) determining the scope of modifications required for the uprate conditions through detailed engineering analyses; (ii) reviewing historical nuclear division plans for plant expenditures to validate that none of the modifications necessary for the EPU project were included in prior plans; (iii) reviewing Nuclear Regulatory Commission (NRC) license renewal commitments to validate that none of the modifications necessary for the uprate conditions were included in FPL’s existing license renewal commitments; (iv) establishing a cross-functional review team including engineering, accounting, business operations, and others to review uprate activities and confirm these activities are separate and apart from nuclear costs that would have been necessary to provide safe and reliable service had there been no uprate project; and (v) the careful process of recording costs and compiling its Nuclear Filing Requirements, and the many processes and procedures attendant thereto.

(TR 664)  

FPL witness Reed performed a review of FPL’s process for determining how costs are separate and apart and how FPL segregates them. Witness Reed noted that the separate and apart concept is not concerned with whether or not the costs were prudently incurred, but whether they are necessary to the uprate project as opposed to ongoing nuclear capital or maintenance activities. (TR 375)  The question solely relates to whether the costs should be included in this proceeding or one of the FPL's base rate proceedings. (TR 376)

FIPUG took the position that FPL did not meet its burden of proving that its EPU project costs are separate and apart. (FIPUG BR 5)  However, FIPUG’s post-hearing brief did not provide further support of its position.  OPC also maintained that FPL did not meet its burden proof. (OPC BR 11)  OPC argued Jacobs stated “it was my understanding [FPL] agreed to provide a 20-year capital analysis of projects that might be needed in order for the plant to run for 20 years, and they have not provided that information.”  (TR 487)  Witness Jacobs offered no other evidence in support of his understanding.  OPC argued in its belief that the study is needed to differentiate between those costs needed to continue operating the unit over the long term, which are included in base rates, from the additional costs that would not be incurred “but for” the decision to uprate. (OPC BR 11-12)  OPC urged the Commission to adopt the application of its proposed standard. (OPC BR 11)

Witness Kundalkar noted that OPC witness Jacobs did not identify any flaw in FPL’s analysis. (TR 667)  He described the analysis supported by witness Jacobs as requiring a component-by-component predictive study. (TR 668)  Witness Kundalkar asserted the study would be meaningless for decision-making purposes. (TR 668)  Due to the speculative nature of such a study, witness Kundalkar opined that it was not useful for the NCRC. (TR 671)

OPC’s arguments hinge on a position that the applicable standard is a 20-year component-by-component study.  Since FPL did not provide such a study, OPC opined that FPL failed to meet its burden of proof.  Rule 25-6.0423, F.A.C., and Order PSC-08-0749-FOF-EI do not require FPL to perform a 20-year component-by-component separate and apart study.  However, FPL is required to implement a process that appropriately identifies NCRC costs as separate and apart.

As previously noted, FPL presented its separate and apart methodology.  Staff’s review of FPL’s petitions and filings in the NCRC has not identified a policy concern with FPL’s separate and apart methodology.  OPC witness Jacobs did not identify any specific flaws in FPL’s methodology. (TR 667)  Instead, OPC witness Jacobs maintains that the appropriate analysis is a 20-year component-by-component capital expenditure study. (TR 477)  Staff is not persuaded.  The EPU project is estimated to be completed in 2013. (EX 32)  Thus, a 20-year analysis period extends well beyond the EPU project commercial operation date.  Staff believes that costs incurred after 2013 are by definition beyond the scope of the EPU project.  Consequently, staff questions the appropriateness of a 20-year study to assess separate and apart costs.

Conclusion

Based on the forgoing, staff recommends FPL’s separate and apart methodology is reasonable and appropriate for identifying NCRC costs.  Staff recommends that the Commission find FPL’s 2008 actual, 2009 actual/estimated and 2010 projected EPU project costs are separate and apart from the nuclear costs that would have been necessary to provide safe and reliable service had there been no EPU project.

 

 

Issue 12: 

 What system and jurisdictional amounts should the Commission approve as FPL’s reasonable actual/estimated 2009 costs for the Extended Power Uprate project?

Recommendation: 

 Staff recommends the Commission approve, as reasonable, actual/estimated 2009 EPU project construction costs in the amount of $258,926,772 ($252,317,529 jurisdictional), O&M expenses of $568,000 ($544,467 jurisdictional), carrying charges of $20,297,390, and a base rate revenue requirement of $83,460.  The Commission should also approve an estimated 2009 EPU project true-up amount of $4,372,298.  These amounts include a $191 adjustment to FPL’s requested base rate revenue requirement.  (Breman)

Position of the Parties

FPL: 

  The Commission should approve $258,926,772 ($252,317,529 jurisdictional, net of participants) plus related carrying charges of $20,297,390 as reasonable 2009 EPU construction costs.  Additionally, recoverable O&M expenses in the amount of $568,000 ($544,467 jurisdictional, net of participants) and base rate revenue requirements of $83,651 are reasonable and should be approved.

OPC: 

  (Prehearing) No position.

FIPUG: 

  (Prehearing) No position.

SACE: 

  (Prehearing) No position.

Staff Analysis: 

 This issue addresses FPL’s request concerning the reasonableness of actual/estimated 2009 EPU project costs and the true-up amount to be included in Issue 18.  OPC, FIPUG and SACE did not propose adjustments to FPL’s estimated 2009 costs or the true-up amount.  OPC, FIPUG and SACE took no position on this issue and did not address this issue in their post-hearing briefs.  Therefore, pursuant to the prehearing order, OPC, FIPUG, and SACE have waived their positions on this issue.

FPL estimates the St. Lucie Unit 2 gantry crane will enter commercial service October 2009. (TR TR 331, 340; EX 39)  In Order No. PSC-08-0749-FOF-EI, at page 6, the Commission found that “PEF and FPL shall be allowed to recover through the NCRC associated revenue requirements for a phase or portion of a system placed into commercial service during a projected recovery period.” Therefore, staff believes that FPL’s inclusion of a base rate requirement for the St. Lucie 2 gantry crane in the estimate costs for 2009 is consistent with Commission policy.  However, staff recommends an adjustment to FPL’s estimated 2009 base rate revenue requirements based, in part, upon the resolution of Issue 3.

In 2007 FPL determined how it would address any differences in AFUDC rates resulting from Rule 25-6.0423, F.A.C., and Rule 25-6.0141, F.A.C. (EX 2, Tab 8)  FPL decided to track any resulting incremental or decrementa1 AFUDC amounts remaining on the Company’s books and records until the projects are placed into service, at which time the cumulative increment or decrement would be transferred to plant in service. (TR 327)  On February 8, 2008, FPL requested a change to its AFUDC rate from 7.42% to 7.65%.[15]  However, FPL’s petition did not request implementation of FPL’s internal 2007 decision.  On March 6, 2009, FPL requested another change to its AFUDC rate from 7.65% to 7.41%.[16]  Again, FPL’s petition did not request implementation of FPL’s internal 2007 decision.  In this proceeding, FPL witness Powers acknowledged that the Commission has not issued an order approving FPL’s 2007 internal AFUDC approach. (TR 353, 354; EX 2, Tab 8)  Thus, staff believes that FPL has had at least two opportunities to present the matter to the Commission but chose not to do so.  Staff believes FPL’s election to wait two years to present this matter and then request that the policy be applied to construction costs incurred in prior periods is not appropriate ratemaking policy.  Policies should generally be applied on a prospective basis.

FPL’s AFUDC approach results in an estimated St. Lucie Unit 2 gantry crane base rate revenue requirement of $83,651. (TR 331, 338, 340, 348; EX 39)  The base rate revenue requirement without FPL’s AFUDC approach is $83,460. (EX 2, Tab 8)  This is a $191 reduction.  Staff reflects this adjustment in the remainder of this analysis.  If the Commission approves staff’s recommendation in Issue 3, and does not approve FPL’s AFUDC approach, then staff’s recommendation in this issue already makes the appropriate adjustment.  No other matters are disputed with respect to FPL’s estimated 2009 EPU project costs and true-up amount.  

FPL witness Kundalkar described actual and estimated 2009 EPU activities and costs. (TR 250-258; EX 22, 23, 29)  FPL witness Powers addressed FPL’s accounting, including calculation of revenue requirements and true-up amounts. (TR 329-332, 337, 338, 340, 348; EX 2, Tab 8; EX 38, 39)  FPL’s actual and estimated 2009 EPU project cost include construction costs of $258,926,772 ($252,317,529 jurisdictional), operation and maintenance (O&M) expenses of $568,000 ($544,467 jurisdictional), and carrying charges of $20,297,390.  Based on the prior discussion, there is also a base rate revenue requirement of $83,460. All jurisdictional costs are net of joint owner and other adjustments.

Staff compared these actual and estimated 2009 costs to the approved 2009 projected NCRC amounts to determine the estimated true-up amount.  Order No. PSC-08-0749-FOF-EI, at page 32, identified a projected carrying cost amount $16,553,019, but no O&M expenses or base rate revenue requirements.  Thus, the 2009 true-up is $4,372,298.  This amount is the sum of an under estimate of $3,744,371 in carrying charges ($20,297,390 - 16,553,019 = $3,744,371), plus an under estimate of $544,467 in O&M expenses, plus and underestimate of $83,460 in base rate revenue requirements.  These amounts and similar calculations, excluding staff’s recommended adjustment, appear in revised Exhibit 38.

Conclusion

Based on the forgoing, staff recommends the Commission approve, as reasonable, actual/estimated 2009 EPU project construction costs in the amount of $258,926,772 ($252,317,529 jurisdictional), O&M expenses of 568,000 ($544,467 jurisdictional), carrying charges of $20,297,390, and a base rate revenue requirement of $83,460.  The Commission should also approve an estimated 2009 EPU project true-up amount of $4,372,298.  These amounts include a $191 adjustment to FPL’s requested base rate revenue requirement.

 

Issue 13: 

 What system and jurisdictional amounts should the Commission approve as FPL’s reasonably projected 2010 costs for the Extended Power Uprate project?

Recommendation: 

 Staff recommends the Commission approve, as reasonable, projected 2010 EPU project construction costs in the amount of $391,614,248 ($376,703,895 jurisdictional), O&M expenses of $2,209,376 ($2,147,983 jurisdictional), carrying charges of $41,594,586, and a base rate revenue requirement of $15,887,677.  The recommended 2010 recovery amount is $59,620,246. These amounts include a $113,427 adjustment to FPL’s requested base rate revenue requirement.  (Breman)

Position of the Parties

FPL: 

 The Commission should approve $391,614,248 (376,703,895 jurisdictional, net of participants) plus related carrying charges of $41,594,586, as reasonable 2010 EPU construction costs.  Additionally, recoverable O&M expenses in the amount of $2,209,376 ($2,147,983 jurisdictional, net of participants) and base rate revenue requirements of $15,991,104 are reasonable and should be approved.

OPC: 

 (Prehearing) No position.

FIPUG: 

 (Prehearing) No position.

SACE: 

 (Prehearing) No position.

Staff Analysis: 

 This issue addresses FPL’s request concerning the reasonableness of projected 2010 EPU project costs and the corresponding recovery amount to be included in Issue 18.  OPC, FIPUG and SACE did not propose adjustments to FPL’s projected 2010 costs or recovery amount.  OPC, FIPUG and SACE took no position on this issue and did not address this issue in their post-hearing briefs.  Therefore, pursuant to the prehearing order, OPC, FIPUG and SACE have waived their positions on this issue.

Similar to Issue 12, the policy addressed in Issue 3 will either increase of decrease certain projected 2010 base rate revenue requirements.  During 2010, FPL projects that nine different components of its EPU project will enter commercial service at various dates.  (EX 39)  In Order No. PSC-08-0749-FOF-EI, at page 6, the Commission found that “PEF and FPL shall be allowed to recover through the NCRC associated revenue requirements for a phase or portion of a system placed into commercial service during a projected recovery period.”  Therefore, staff believes that FPL’s inclusion of projected base rate requirements for these nine components is consistent with the regulatory policy expressed in Order No. PSC-08-0749-FOF-EI.  Consistent with staff’s recommendation in the Issue 12, staff recommends an adjustment to FPL’s proposed base rate revenue requirements for 2010.

In Issue 3, staff recommends that FPL’s AFUDC approach not be approved.  However, if the Commission approves FPL’s approach, staff believes FPL’s approach should not be implemented on a historical basis.  As explained in Issue 12, FPL had ample opportunity to request Commission approval but chose not to do so.  Staff believes new policy should be implemented on a prospective basis.  Consequently, staff recommends excluding FPL’s AFUDC approach for purposes of this proceeding.

FPL’s AFUDC approach results in 2010 base rate revenue requirement of $15,991,104. (TR 331, 339, 341; EX 39)  Excluding FPL’s AFUDC approach results in lower base rate revenue requirements of $15,887,677.  (EX 2, Tab 8)  This is a $113,427 reduction.  Staff reflects this adjustment in the remainder of this analysis.  No other matters are disputed with respect to FPL’s projected 2010 EPU project costs.

FPL witness Kundalkar described 2010 EPU activities and costs. (TR 260-265; EX 22, 23, 29)  FPL witness Powers addressed FPL’s accounting, including calculation of revenue requirements and true-up amounts. (TR 329, 331, 339, 341; EX 2, Tab 8; EX 38, 39) FPL’s projected 2010 EPU project costs include construction costs of $391,614,248 ($376,703,895 jurisdictional), O&M expenses of $2,209,376 ($2,147,983 jurisdictional), and carrying charges of $41,594,586.  Based on the prior discussion, there is also a $15,887,677 base rate revenue requirement.  All jurisdictional costs are net of joint owner and other adjustments.  The 2010 EPU project NCRC recovery amount is the sum of $2,147,983 in O&M expenses plus $41,594,586 in carrying charges plus $15,887,677 in base rate revenue requirements, for a total of $59,620,246.  These amounts and similar calculations, excluding staff’s recommended adjustment, appear in revised Exhibit 38.  As previously noted, a $113,427 downward adjustment has been made to FPL’s requested base rate revenue requirement because FPL’s request seeks to apply a new policy on costs incurred in prior periods.

Conclusion

Based on the foregoing, staff recommends the Commission approve, as reasonable, projected 2010 EPU project construction costs in the amount of $391,614,248 ($376,703,895 jurisdictional), O&M expenses of $2,209,376 ($2,147,983 jurisdictional), carrying charges of $41,594,586, and a base rate revenue requirement of $15,887,677.  The recommended 2010 recovery amount is $59,620,246.  These amounts include a $113,427 adjustment to FPL’s requested base rate revenue requirement.

Issue 16:  What system and jurisdictional amounts should the Commission approve as reasonably estimated 2009 costs for FPL’s Turkey Point Units 6 & 7 project?

Recommendation: 

 Staff recommends the Commission approve, as reasonable, estimated 2009 TP67 project preconstruction costs of $45,640,661 ($45,444,468 jurisdictional), associated carrying charges of $3,560,771, and carrying charges on unrecovered site selection costs of $472,938.  The Commission should also approve an estimated 2009 TP67 project true-up amount of negative $67,916,601.  (Breman)

Position of the Parties

FPL: 

  The Commission should approve $45,640,661 ($45,444,468 jurisdictional) in preconstruction costs, $3,560,771 in related carrying charges and $472,938 as carrying charges on prior years’ unrecovered site selection costs.  FPL’s 2009 actual/estimated expenditures are supported by comprehensive procedures, processes and controls which help ensure that these costs are reasonable.

OPC: 

 (Prehearing) No position.

FIPUG: 

  (Prehearing) No position.

SACE: 

 None.  FPL has not demonstrated long-term feasibility as required by Rule 25-6.0423(5)(c)5, F.A.C., therefore no such cost could be reasonably and prudently estimated and/or incurred.

Staff Analysis: 

 This issue addresses FPL’s request concerning the reasonableness of estimated 2009 TP67 project costs and the true-up amount to be included in setting the 2010 recoverable amount in Issue 18.  OPC and FIPUG took no position on this issue and did not address this issue in their post-hearing briefs.  Therefore, pursuant to the prehearing order, OPC and FIPUG have waived their positions on this issue.

SACE argued FPL failed to comply with the detailed analysis of long-term feasibility requirements of Rule 25-6.0423(5)(c)5, F.A.C. (SACE BR 1, 4, 10, 26, 30)  Thus, SACE asserted no costs can be reasonably estimated or incurred. (TR 550, 552, 587)  SACE maintained that there should be consequences in the cost recovery framework for failing to demonstrate long-term feasibility of completing a project. (SACE BR 1) Consequently, SACE urges the Commission to deny recovery of estimated 2009 costs. (SACE BR 1, 3, 10, 26, 30).  SACE witness Cooper supported a view that spending more on nuclear reactors and allowing the utilities to recover those costs from ratepayers would be imprudent. (TR 550, 552, 587)  However, SACE witness Gundersen said  “. . . the problems are eventually surmountable.  There are no show-stoppers.” (TR 542)   Staff addresses FPL’s long-term feasibility analysis in Issue 8 (page 22).  Consistent with staff’s recommendation in Issue 8, and review of the record evidence, staff believes that denial of recovery is an extreme measure that is not warranted because FPL’s recovery of 2009 expenditures will be subject to a future prudence review.

Should the Commission agree with SACE and find FPL imprudent to continue with the TP67 project, then the Commission should deny FPL recovery of 2009 TP67 project costs included in this proceeding as well as the projected 2009 costs FPL already collected.  Pursuant to Order No. PSC-08-0749-FOF-EI, FPL was authorized to collect $117,394,778 in projected expenses during 2009 (see page 36).  Thus, upon a finding of imprudence consistent with the position maintained by SACE, the Commission should require FPL to refund the 2009 projected amount of $117,394,778 already collected.

No other matters are disputed with respect to FPL’s estimated 2009 TP67 project costs.  (FPL BR 43)  FPL witness Scroggs described 2009 TP67 activities and costs. (TR 90-91, 99, 108-111, 113-126; EX 13, 14, 16)  FPL witness Powers addressed FPL’s accounting, including calculation of revenue requirements and true-up amounts. (TR 329, 332-335, 341-343, 346; EX 38, 39) FPL’s actual and estimated 2009 TP67 project cost are preconstruction costs of $45,640,661 ($45,444,468 jurisdictional), preconstruction carrying charges of $3,560,771 and site selection carrying charges of $472,938.  Staff notes that while site selection activities have ended, these carrying charges result from site selection costs that FPL has not yet recovered through the true-up process.

Staff compared these estimated 2009 costs to the approved 2009 projected NCRC amounts to determine the estimated true-up amount.  Order No. PSC-08-0749-FOF-EI, at page 36, identified projected preconstruction costs of $109,540,915, associated carrying charges totaling $7,344,813, and projected site selection carrying charges of $509,050.

Staff believes that the 2009 estimated true-up amount is negative $67,916,601.  The 2009 variance is the sum of an over-projection of $64,096,447 ($109,540,915 - $45,444,468 = $64,096,447), over-projected associated carrying charges of $3,784,042 ($7,344,813 - $3,560,771 = $3,784,042), and over-projected site selection carrying charges of $36,112 ($509,050 - $472,938 = $36,112).  These amounts and similar calculations also appear in revised Exhibit 38.

Conclusion

Therefore, staff recommends that the Commission approve, as reasonable, estimated 2009 TP67 project preconstruction costs of $45,640,661 ($45,444,468 jurisdictional), preconstruction carrying charges of $3,560,771, and site selection carrying charges of $472,938.  The Commission should also approve an estimated 2009 TP67 project true-up amount of negative $67,916,601.

Issue 17:  What system and jurisdictional amounts should the Commission approve as reasonably projected 2010 costs for FPL’s Turkey Point Units 6 & 7 project?

Recommendation: 

 Staff recommends that the Commission approve, as reasonable, projected 2010 TP67 project preconstruction costs of $91,730,615 ($90,654,124 jurisdictional), preconstruction carrying charges of $973,735, and carrying charges on unrecovered site selection costs of $233,136.  The recommended 2010 recovery amount is $91,860,995.  (Breman)

Position of the Parties

FPL: 

  The Commission should approve $91,730,615 ($90,654,124 jurisdictional) preconstruction costs, $973,735 in related carrying charges and $233,136 as carrying charges on prior years’ unrecovered site selection costs.  FPL’s 2010 projected expenditures are supported by comprehensive procedures, processes and controls which help ensure that these projected costs are reasonable.

OPC: 

  (Prehearing) No position.

FIPUG: 

  (Prehearing) No position.

SACE: 

  None.  FPL has not demonstrated long-term feasibility as required by Rule 25-6.0423(5)(c)5, F.A.C., therefore no such cost could be reasonably and prudently projected and/or incurred.

Staff Analysis: 

 This issue addresses FPL’s request concerning the reasonableness of projected 2010 TP67 project costs.  OPC and FIPUG took no position on this issue and did not address this issue in their post-hearing briefs.  Therefore, pursuant to the prehearing order, OPC and FIPUG have waived their positions on this issue.

SACE argued FPL failed to comply with the detailed analysis of long-term feasibility requirements of Rule 25-6.0423(5)(c)5, F.A.C. (SACE BR 1, 4, 10, 26, 30)  Staff addresses FPL’s long-term feasibility analysis in Issue 8 (page 22).  Consistent with staff’s recommendation in Issue 8, and a review of the record evidence, staff believes that denial of recovery is an extreme measure that is not warranted.  FPL’s recovery of 2010 expenditures will be subject to a future prudence review.  However, if the Commission agrees with SACE’s arguments, then the Commission should approve a zero amount for recoverable 2010 TP67 project costs.

No other matters are disputed with respect to FPL’s projected 2010 TP67 project costs.  (FPL BR 44)  FPL witness Scroggs described 2010 TP67 activities and costs. (TR 90-91, 99, 108, 110-126; EX 13, 14, 16)  FPL witness Powers addressed FPL’s accounting, including calculation of revenue requirements and true-up amounts. (TR 329, 332, 336-337, 343-346; EX 38, 39)  FPL’s projected amount is $91,860,995, which includes preconstruction costs of $91,730,615 ($90,654,124 jurisdictional), preconstruction carrying charges of $973,735 and site selection carrying charges of $233,136.  Staff notes that while there are no 2010 site selection activities, these carrying charges result from site selection costs that FPL has not yet recovered through the true-up process.  Thus, variances identified in 2009 are carried forward into 2010.

Conclusion

Staff recommends that the Commission approve, as reasonable, projected 2010 TP67 project preconstruction costs of $91,730,615 ($90,654,124 jurisdictional), preconstruction carrying charges of $973,735, and carrying charges on unrecovered site selection costs of $233,136.  The recommended 2010 recovery amount is $91,860,995.

Issue 18:  What is the total jurisdictional amount to be included in establishing FPL’s 2010 Capacity Cost Recovery Clause factor?

Recommendation: 

 Consistent with staff’s recommendation on all prior issues, the Commission should approve $62,676,366 to be included in establishing FPL’s 2010 CCRC factor.  (Breman)

Position of the Parties

FPL: 

  The total amount to be included in $62,789,984.  This includes site selection costs, pre-construction costs and carrying charges for Turkey Point 6 & 7; and carrying charges on construction costs, O&M costs and base rate revenue requirements for EPU – all as provided for in Section 366.93 and the Rule.

OPC: 

  (Prehearing) No position.

FIPUG: 

  (Prehearing) No position.

SACE: 

  (Prehearing) No position.

Staff Analysis: 

 This issue is a fall-out issue reflecting decisions on all prior issues that impact FPL’s level of recovery in 2010.  Both contested and stipulated issues impacting the total amount are identified in the following table.  As shown in the table, only staff and SACE supported adjustments to FPL’s 2010 recovery level.  A negative total 2010 recovery amount indicates a refund.

 

Staff notes a $3 rounding difference between FPL’s requested recovery amount and the sum of individual amounts by issue.  In calculating the total 2010 recovery amount pursuant to staff’s and SACE’s recommendations, staff used the total amount FPL requested.  OPC, FIPUG, and SACE took no position on this issue and did not address this issue in their post-hearing briefs.  Therefore, pursuant to the prehearing order, OPC, FIPUG and SACE have waived their positions on this issue.

Conclusion

Consistent with staff’s recommendation on all prior issues, the Commission should approve $62,676,366 to be included in establishing FPL’s 2010 CCRC factor.

 

Issue 21: 

 Should the Commission find that for the year 2008, PEF’s project management, contracting, and oversight controls were reasonable and prudent for the Levy Units 1 & 2 project and the Crystal River Unit 3 Uprate project?

Recommendation: 

 Staff recommends the Commission find that during 2008, PEF’s project management, contracting, and oversight controls were reasonable and prudent for the Levy Units 1 & 2 and Crystal River Unit 3 Uprate projects.  (Laux)

Position of the Parties

PEF: 

  Yes, PEF’s 2008 project management, contracting, and oversight controls were reasonable and prudent for the CR3 Uprate project and the LNP.  These procedures, designed to ensure timely and cost-effective completion, include regular status meetings, regular risk management, evaluation and management, as well as adequate, reasonable polices regarding contracting procedures.

OPC: 

  No. The Commission should note the status of the NRC’s review and approval process notify PEF that costs expended for projects yet to be licensed – although recoverable at this time – may be subject to prudence review if not licensed.

PCS Phosphate: 

  PCS Phosphate agrees with and adopts the position of the OPC.

FIPUG: 

  (Prehearing) Concurs with OPC.

SACE: 

  No.  In regard to the Levy Units 1 & 2 project, PEF unreasonably and imprudently relied upon the assumption that the NRC would grant PEF a LWA as requested in its COLA, and made fundamental contracting, scheduling, and cost assumptions based on this assumption.

Staff Analysis: 

 This issue addresses the reasonableness and prudence of PEF’s project management, contracting, and oversight controls in place during 2008 for the Levy Units 1 & 2 (LNP) and Crystal River Unit 3 Uprate (CR3 Uprate) projects.  Matters related to the LNP engineering, procurement, and construction (EPC) contract are addressed in Issue 21A (page 46).  Matters related to project feasibility analysis are addressed in Issue 23 (page 52).

As discussed in Issue 7, the applied standard for determining prudence is consideration of what a reasonable utility manager would have done in light of conditions and circumstances which were known or reasonably should have been known at the time decisions were made.  Staff notes, that this is the same standard applied by witness Doughty. (TR 2002)

In reviewing the record, staff notes that none of the parties challenged the prudence of the overall project management, contracting, and oversight controls in placed during 2008 for the LNP and CR3 Uprate projects. (TR 1485, 1543, 1627)  OPC, PCS Phosphate, and SACE, however, raised questions concerning certain management decisions made during 2008 by PEF associated with the LNP and CR3 Uprate projects.  OPC witness Jacobs questioned the reasonableness of PEF’s decision to incur construction costs for the CR3 Uprate project without an approved NRC License Amendment. (TR 1467-1471)  In its statement of position on this issue, SACE addressed matters pertaining to PEF’s LNP. SACE argued that “PEF unreasonably and imprudently relied upon the assumption that the NRC would grant PEF an LWA as requested in its COLA, and made fundamental contracting, scheduling, and cost assumptions based on this assumption.” (SACE BR 4)

Crystal River Unit 3 Uprate

As noted above, none of the parties challenged the prudence of the overall project management, contracting, and oversight controls in placed during 2008 for the CR3 Uprate project.  However, OPC witness Jacobs questioned the reasonableness of PEF’s decision to incur construction cost for the balance of plant construction activities at the CR3 Uprate project without prior NRC approval of the license amendment request (LAR).  PCS Phosphate agreed with and adopted OPC’s position on this issue. (PCS Phosphate BR 12)

The focus of the intervenor’s concerns is presented by witness Jacobs in the following question and answer:

Q.        Are you questioning the engineering approach PEF is utilizing in its NRC application?

A.        No.  My point is that PEF cannot say for certain that the NRC will approve its request to the extent or in the manner requested.

 

(TR 1468)

Witness Jacobs further stated,

I think from an engineering and operation perspective, the sequence of events is probably reasonable that they undertook, but from a risk management perspective, it results in PEF spending a significant fraction of the money for this project before knowing that the desired outcome will be achievable.

(TR 1496)

He further clarified this risk by stating that the basis of his concern is on possible denial of the LAR because “[t]his is the first Babcock & Wilcox reactor that has been attempted to be uprated to this magnitude.” (TR 1498)  However, witness Jacobs admitted, under cross-examination, that he was aware that the NRC had not denied any of the 104 uprate requests submitted since 2001. (TR 1498)

PEF’s witness Franke opined that the company has reasonable assurance the NRC will approve the LAR before the uprate construction activities are completed. (TR 1701)  He testified that project design, construction, and regulatory risks have been reasonably mitigated given PEF’s project management activities. (TR 1672, 1674, 1675, 1680)  He asserted that the majority of the engineering analysis and solutions proposed for the CR3 Uprate are similar to those in use and approved by the NRC for the Davis-Besse Unit, a Babcock & Wilcox reactor similar to Crystal River Unit. (TR 1709)  Additionally, other plant modifications, proposed in the LAR, will allow for the removal of certain current NRC operational limits. (TR1713)  He also contended that witness Jacobs has not actually reviewed the proposed technical and engineering analysis and solutions that have been developed over the last year and a half that are part of the LAR proposal. (TR 1675)

Staff witnesses Coston and Vinson sponsored Exhibit 108, an audit report that “reviewed the internal controls and management oversight of the nuclear projects underway at Progress Energy Florida.” (TR 1645; Exhibit 108)  Witnesses Coston and Vinson stated “[t]he primary objective of this review was to document project key development, along with the organization, management, internal controls and oversight that PEF has in place or plans to employ for these projects.” (TR 1646)  The only questions asked of these witnesses concerned the control of project schedule once the LNP combined operating license application (COLA) was filed with the NRC and overall project costs.  No party questioned the witnesses on project management, contracting, and oversight controls used for the CR3 Uprate project.  Staff reviewed the management audit report to determine whether it contained support for a finding of imprudence and did not find any.

Staff believes that the concerns identified by OPC witness Jacobs do not support a finding that PEF’s project management, contracting, and oversight controls at the CR3 Uprate project during 2008 were unreasonable or imprudent.  The concern identified by witness Jacobs, regarding a future NRC decision on the LAR, does not show that project risks were inappropriately addressed by PEF. (PEF BR 11)  Staff notes that witness Jacobs’ suggested approach to managing the Uprate project would delay all construction and extend the project schedule.  However, witness Jacobs provided no additional analysis addressing possible cost risks, schedule risks, and customer benefit risks of PEF’s approach compared to his alternative.

Based on the record evidence, staff believes that PEF implemented a management approach that supports a reasonable balance between the level of project risk and the timing of project benefits.  Therefore, staff recommends that the Commission find that during 2008, PEF’s project management, contracting, and oversight controls were reasonable and prudent for the CR3 Uprate project.

Levy Units 1 & 2 Project

As stated above, none of the parties challenged the prudence of the overall project management, contracting, and oversight controls PEF had in place during 2008 for the LNP.  SACE took issue with the reasonableness and prudence of PEF’s decision to incorporate a limited work authorization (LWA) in the schedule developed for the LNP project and included in the COLA.[17]  However, SACE’s brief did not explain the position taken apart from project feasibility.  This topic is discussed in detail in Issue 23 (page 52).

Staff notes only PEF witness Thompson provided testimony directly addressing the reasonableness of including an LWA in PEF’s LNP COLA. (TR 1931-1936)  Witness Thompson opined that the NRC intended for licensees to use the LWA process. (TR 1933)  In discussing his opinion, he pointed to NRC activities in 2007 concerning the revision of the LWA rule and regulations.  Witness Thompson stated, “. . . the NRC clearly indicated to the public and the nuclear industry that it was worth spending NRC resources on the LWA process and that the NRC expected the nuclear industry to be in a position to use LWAs, if needed, to meet projected construction schedule needs.” (TR 1934)  Witness Thompson also noted that “by the time PEF had decided to request an LWA, the NRC had not only established a new regulation for reviewing and issuing LWAs, but it had also established an Office that was responsible for conducting those reviews in a timely schedule, provided that an acceptable application had been submitted.” (TR 1935)  No party challenged these statements.

Staff notes that the NRC docketed the LWA and COLA on October 6, 2008.  Docketing an application indicates that the application was technically sufficient for NRC review. (TR 1930)  PEF believed its requested NRC review schedule for the LWA and COLA was necessary to achieve the 2016 and 2017 in-service dates. (TR 1753, 1858)  No party challenged PEF’s need to secure its proposed LWA to meet 2016 and 2017 in-service dates.  No party asserted PEF was non-responsive to the NRC staff.  Instead, intervenors raise matters related to the prudence of signing an EPC contract and project feasibility which are addressed separately in Issues 21A and 23.

Regarding PEF’s oversight of the Levy project, staff believes PEF management acted appropriately in developing a Levy project construction schedule that included an LWA, because the LWA is a viable construction schedule management tool offered by the NRC.  Staff believes that PEF implemented a management approach that supports a reasonable balance between the level of project risk and the timing of project benefits.  Therefore, staff recommends that the Commission find that during 2008, PEF’s project management, contracting, and oversight controls were reasonable and prudent for the LNP project.

Conclusion

Based on the foregoing, staff recommends the Commission find that during 2008, PEF’s project management, contracting, and oversight controls were reasonable and prudent for the Levy Units 1 & 2 and Crystal River Unit 3 Uprate projects.

 

Issue 21A: 

 Was it reasonable and prudent for PEF to execute its EPC contract at the end of 2008?  If the Commission finds that this action was not reasonable and prudent, what actions, if any, should the Commission take?

Recommendation: 

 Staff recommends the Commission find that the timing of PEF’s decision to execute an EPC contract at the end of 2008 was reasonable.  Staff also recommends the Commission not make a finding on PEF’s prudence concerning the actual terms and conditions contained within its EPC contract.  (Laux)

Position of the Parties

PEF: 

  Yes, PEF acted reasonably and prudently in executing the EPC contract.  Execution of the EPC contract in December 2008 preserved benefits obtained after roughly two years of hard-fought negotiations.

OPC: 

  No. Based on the circumstances the PEF knew or should have reasonably known, it was not reasonable or prudent for PEF to sign the EPC contract with the Consortium.

PCS Phosphate: 

  No. PCS Phosphate supports OPC.  Moreover, the Commission should conduct a detailed examination of the EPC contract’s execution in view of the known and reasonably expected ramifications of an unfavorable NRC determination concerning the Limited Work Authorization request.

FIPUG: 

  No.  PEF did not act reasonably in executing the engineering, procurement, and construction (EPC) contract on December 31, 2008 given the uncertainty surrounding the status of its request for a limited work authorization (LWA).

SACE: 

  No.  PEF unreasonably relied upon the assumption that the NRC would grant PEF a LWA, and made fundamental contracting, scheduling, and cost decisions based on this assumption.  The Commission should deny cost recovery for PEF’s 2009 and 2010 costs that would be incurred as a result of executing the EPC.

Staff Analysis: 

 Staff notes that while this issue addresses the prudence of PEF to execute its EPC contract, the only disputed matter was the timing of PEF’s decision without full knowledge of the NRC’s decisions concerning PEF’s requested COLA and LWA reviews.  The referenced EPC contract has not been submitted for Commission review.  Consequently, this recommendation only addresses disputed matters regarding the timing of PEF’s decision to enter into an EPC contract.

The dispute addressed is the intervenors’ (OPC, PCS Phosphate and FIPUG) contention that PEF prematurely entered into the EPC agreement without full knowledge of the NRC’s decisions concerning the COLA review, in particular, the requested LWA review schedule.  According to the intervenors, PEF’s decision regarding the timing of contract execution was unreasonable given what was or should have been known by PEF in late December 2008. (FIPUG BR 7, PCS Phosphate BR 5, TR 1456, 1460)  SACE’s position on this issue was focused on LNP schedule slippage, and the effect this slippage may have on long-term project feasibility.  Long-term project feasibility matters are addressed in Issue 23 (page 52).

As discussed in Issue 7, the applied standard for determining prudence is consideration of what a reasonable utility manager would have done in light of conditions and circumstances which were known or reasonably should have been known at the time decisions were made.  Staff notes, that this is the same standard applied by witness Doughty. (TR 2002)

As stated by PEF witnesses Miller and Lyash, PEF entered into an EPC contract for the LNP project with Shaw/Westinghouse on December 31, 2008. (TR 1174, 2039)  Witness Lyash asserted that PEF’s management approved execution of the EPC agreement in December due to the following reasons:

·            After two years of negotiations all outstanding contract issues, that needed to be resolved, were resolved and the EPC agreement was ready for execution. (TR 2042)

·            PEF had obtained a number of key contractual benefits from Shaw/Westinghouse that were offered to PEF on a time limited basis. (TR 2041, 2043(confidential))

·            Execution of the EPC agreement provided an orderly framework to accommodate potential adjustments to the project schedule. (TR 2037)

·            Execution of the EPC agreement at this time was necessary to move the project forward to meet the 2016, 2017 LNP in-service dates. (TR 2042)

Addressing the question of what PEF knew or should have known about the NRC’s potential decision on the LWA request prior to signing the EPC, witness Lyash stated, “in December 2008, the company did not know and should not have known that the NRC would not approve the LWA before issuing the combined license.  PEF reasonably and prudently acted on this information that was available at the time, and by so doing was able to preserve the contractual benefits that had been secured through two years of intense negotiations.” (TR 2076-2077)  Witness Lyash further asserted that “[i]n fact had PEF known about the NRC’s position with respect to the LWA in December 2008 … PEF would have still executed the EPC agreement and proceeded to amend the EPC agreement under the EPC’s contract suspension and amendment provision just like PEF is doing now.” (TR 2052)

OPC witness Jacobs opined that PEF’s decision to execute the EPC agreement in December 2008 was not reasonable. (TR 1456)  Witness Jacobs supported his opinion by stating,

Receipt of the LWA within the requested timeframe was a requirement for implementation of the contract on the schedule contained in the EPC contract.  Not only did PEF not have any assurance that the LWA would be issued, the NRC specifically told them in the October 6, 2008 letter that it was unlikely that the requested timeline would be met.  Under the totality of circumstances, PEF should have assumed that an LWA review schedule different than the overall COLA review schedule would not have been adopted by the NRC.  To assume otherwise and sign the EPC contract with this cloud hanging over this critical date was not reasonable.

(TR 1456)

The following statement from the NRC’s October 6, 2008 letter to PEF, according to witness Jacobs, is what clearly informed PEF that it was unlikely that the requested [NRC review] timeline could be met:

Because of the complexity of the site characteristics and the need for additional information, it is unlikely that the LNP COLA review can be completed in accordance with this timeline.

(TR 1453; EX 2 Tab 12, 101)

Witness Jacobs further asserted:

It is not reasonable to assume that given the fact that the NRC made an effort to specifically mention the complexity of the site that it was only suggesting a brief delay in the schedule.  This is true when contrasted with the extensive effort PEF made to impress upon senior NRC staff of the need to meet its ‘aggressive’ schedule.

(TR 1453-1454)

PCS Phosphate expressed similar views on the reasonableness of PEF’s decision to execute the EPC before the NRC established a review schedule for the LWA request. (PCS Phosphate BR 11)  In its brief, PCS Phosphate opined that given what was known or should have been known at the time, PEF unreasonably assumed risks in executing the EPC under the circumstances. (PCS Phosphate BR 11)

Staff agrees with the parties that to make a finding concerning the timing of PEF’s decision, the review should be made in light of what was known, or should have been known, at the time that the decision was made.  In response to staff discovery, PEF provided a listing of key informational points leading up to the NRC’s January 23rd announcement on PEF’s COLA/LWA review schedule request.  No party took issue at hearing with this listing or identified any other key informational points that should have been considered.  The key informational points contained within the exhibit are:

·                  1/08, PEF advised the NRC at a public meeting that the COLA for the Levy project would include an LWA request.

·                  1/10/08, PEF met with NRC technical staff to review Levy geotechnical issues.

·                  2/2008, The NRC stated that applicants should give advance notice of their intent to request an LWA.

·                  3/5/08, PEF formally notified the NRC that it intended to request an LWA with its Levy COLA filing.

·                  6/30/08, PEF met with NRC managers to discuss the need for Levy and overall plans for the project.

·                  7/28/08, PEF met with NRC technical staff on the Levy geotechnical issues.

·                  7/30/08, PEF filed its COLA/LWA application with the NRC.

·                  9/5/08, The NRC requested that PEF revise the scope of the LWA to include dewatering and permeation grouting.

·                  9/9/08, PEF management held a “drop-in” meeting with NRC management to review the overall plan for LNP and the project schedule.

·                  9/12/08, PEF supplemented its filings to revise the proposed scope of the LWA as the NRC requested.

·                  10/6/08, Brian Anderson (NRC project manager) issued a docketing letter for Levy, which indicates that the application is sufficient for review.  Requests for additional information (RAI) relating to geotechnical issues are sent to PEF.

·                  11/20/08, PEF submitted its responses to the NRC’s RAIs.

·                  12/20/08, PEF is advised that it would receive a review schedule before the end of January 2009.

·                  12/31/08, PEF entered into the EPC agreement with Shaw/Westinghouse.

·                  1/23/09, NRC staff informed PEF that review of the LWA request would take as long as the review of the COLA.

(EX 2 Tab 12)

PEF witness Miller asserted, “[t]here was no indication that an LWA would not be issued for the scope requested.” (TR 1178)  Similarly, witness Lyash asserted,

The NRC never told the Company nor intimated that the NRC would not issue the LWA until it issued the COL.  In our experience with the NRC, when the NRC wants to tell us something they do so, they do not leave room for doubt.  When the NRC determined in January 2009 that it was going to review the LWA on the same timeline as the COL and not sequentially as PEF had requested that is what the NRC expressly said it was going to do.

(TR 2048)

OPC witness Jacobs opined that PEF was premature in signing the EPC agreement since PEF did not have a firm schedule for review and approval of the LWA by the NRC at the time that the EPC was signed. (TR 1475)  Witness Jacobs asserted:

Prior to signing the EPC contract, the NRC had indicated that it was unlikely that the requested schedule could be met due to the complexity of the site characteristics and the need for additional information.  I believe that PEF should not have signed the EPC contract without assurance that the LWA would be approved on the schedule that was needed for the project.

(TR 1476)

Witness Jacobs further asserted, “[a] more reasonable, cautions[sic] approach given the uncertainty in the LWA schedule and the list of concerns identified above would have been to continue to support development of the COLA while delaying signing of the EPC contract until the issuance of the LWA was known and the above concerns are resolved.” (TR 1459)  Witness Jacobs stated:

This decision (signing of the contract) may result in significant extra cost to the project that could have been avoided with a more cautious approach given the known risks and uncertainties at the time of signing.  At the very least, the Commission does not have sufficient information to determine whether 2009 and 2010 EPC contract costs are reasonable.

(TR 1462)

PCS Phosphate witness Bradford stated, “[i]n the present proceeding, the Commission needs only determine the prudence of the actual construction cost incurred in 2008.  As a result, the Commission does not need to determine costs associated with Progress’ decision to enter into the EPC agreement prior to the receipt of the LWA, as the contract was not executed until the end of 2008.” (TR 1529)  Witness Bradford further stated, “Progress has relied heavily on the NRC’s meeting of its announced schedules despite the facts a) that the revised licensing process is untested and b) that the industry has presented the NRC with a consistently changing profile rather than a firm commitment to certified designs on which those schedules have been based.” (TR 1533)  Finally, witness Bradford opined that there is a substantial likelihood that PEF should have waited until it had the LWA for Levy before signing the EPC. (TR 1548)

Staff’s review of the record found that the intervenors primarily focused their attention on what PEF should have known concerning the likelihood of obtaining NRC approval of the requested LWA review schedule.  Staff agrees that gaining approval of the LWA was an important component of the construction schedule to meet the proposed commercial in service dates for the units.  However, it is not the only important component of this schedule.  As addressed by witness Lyash, the LWA was a critical milestone. (TR 2141)  But it is no more or less critical than, for example; the final environmental impact statement, the final safety evaluation report, the license issuance, or the site certification. (TR 2141)  Staff agrees with witness Lyash that PEF must satisfy all critical regulatory milestones to meet the proposed commercial in service dates for the LNP.  Staff believes that all of these milestones could have an influence on the project construction schedule in the same manner as the LWA.

In addition to meeting the project construction schedule, PEF asserted other reasons for signing the EPC were considered at the time of their decision. (TR 2041)  These reasons appear earlier in this recommendation.  Staff notes that the parties generally did not address these reasons.

Based on staff’s review of what PEF knew or should have known regarding the LWA in late 2008, staff believes that the intervenors failed to make a persuasive showing that PEF was unreasonable concerning the timing of its decision to enter into the EPC agreement.  Consistent with 10 CFR Part 50.3, staff believes that the only NRC action that clearly indicates the NRC’s intention concerning the review schedule for the LWA was its January 23, 2009 announcement.[18]  Based on the foregoing, staff believes the NRC undertook actions necessary to establish a review schedule for PEF’s LNP applications.  Staff believes any other interpretation of the NRC’s actions is speculative.

Staff notes, absent concerns with PEF’s LWA efforts, no dispositive evidence was presented that PEF should not have otherwise signed an EPC contract at the end of 2008.  As previously noted, PEF’s EPC contract has not been submitted for Commission review.  Consequently, staff’s recommendation cannot address PEF’s prudence concerning the actual terms and conditions contained within the agreement.  However, staff is persuaded that PEF’s actions and planning regarding an LWA leading up to the signing of an EPC contract were reasonable and consistent with good business practices.

Conclusion

Based on the foregoing analysis, staff recommends the Commission find that the timing of PEF’s decision to execute an EPC contract at the end of 2008 was reasonable.  Staff also recommends the Commission not make a finding on PEF’s prudence concerning the actual terms and conditions contained within its EPC contract.

Issue 23: 

 Should the Commission approve what PEF has submitted as its annual detailed analysis of the long-term feasibility of continuing construction and completing the Levy Units 1 & 2 project, as provided for in Rule 25-6.0423, F.A.C., and Order No. PSC-08-0518-FOF-EI (Determination of Need Order)?

Recommendation: 

 Staff recommends the Commission deny approval of PEF’s May 1, 2009 annual detailed analysis of the long-term feasibility of continuing construction and completing the Levy Units 1 & 2 project.  However, PEF’s responses to staff interrogatories provided the economic analysis necessary to comply with Rule 25-6.0423, F.A.C., and Order No. PSC-08-0518-FOF-EI.  PEF should be required to file updated capital cost estimates in its next annual NCRC filing.  (Graves)

Position of the Parties

PEF: 

  Yes, PEF’s submitted annual detailed analysis of long-term feasibility of completing the LNP should be approved.

OPC: 

  No.  The Commission should order PEF to file a feasibility analysis per the rule after renegotiation [of] the EPC and then the Commission should evaluate whether the project remains feasible on a long term basis.

PCS Phosphate: 

  No.  The information submitted by Progress does not satisfy the requirements of a detailed analysis on the feasibility of completing the project based on current and reasonable assumptions.

FIPUG: 

  (Prehearing) Concurs with OPC.

SACE: 

  No.  Asking the Commission to judge the long-term feasibility of the Levy Nuclear project without knowing “all end” project costs is unreasonable, unwarranted, and inconsistent with the nuclear cost recovery rule, 25-6.0423, F.A.C.

Staff Analysis: 

 This issue addresses review and approval of PEF’s detailed long-term feasibility analysis of continuing construction and completing the LNP project as provided for in Rule 25-6.0423, F.A.C., and Order No. PSC-08-0518-FOF-EI.

PEF argued that it has complied with this directive by providing the Commission with the information upon which the Company’s management relies in making its determination of a project’s feasibility.  PEF asserted that the feasibility of completing the LNP project means the project is capable of being completed, i.e., the project is technically and legally feasible.  PEF claims that the appropriate analysis is a qualitative analysis not a rote quantitative cost-effective analysis based on year to year fluctuations in spot prices, forecasts and projections.  (PEF BR 19-22)

PCS Phosphate argued that PEF’s direct filing in May 2009 disregarded statutory and Commission ordered requirements by not providing an economic analysis of the LNP project.  PCS Phosphate further asserted that PEF’s fuel price forecasts and emission cost assumptions were outdated.  Lastly PCS Phosphate argued that PEF did not possess updated LNP project cost and schedule information required to perform the required economic assessments. (PCS Phosphate BR 15-20)  OPC supports the analysis provided by PCS Phosphate in its post-hearing statement.  (OPC BR 25)  OPC’s position is that the Commission should order PEF to file a feasibility analysis per the rule after renegotiation of the EPC. (OPC BR 16)

FIPUG argued that PEF focused on the technological and regulatory feasibility of completing the project, but largely ignored the economic feasibility of completing the project.  FIPUG further asserted that long-term feasibility cannot be determined if PEF cannot satisfactorily provide the cost of the project. (FIPUG BR 8-9)

SACE argued that PEF’s feasibility analysis was deficient and did not demonstrate that completion of the LNP is feasible in the long-term.  SACE further asserted that PEF’s May 1 testimony only contained technical and regulatory feasibility but contained no economic analysis or discussion of project cost as it relates to the feasibility of the LNP.  SACE argued that PEF’s cumulative present value revenue requirement (CPVRR) analysis, submitted as part of its rebuttal testimony, was based upon assumptions that were outdated and unreasonable. (SACE BR 15, 19-21)

As previously stated, in an effort to mitigate the economic risks associated with the long lead time and high capital costs associated with nuclear power plants, the Florida Legislature enacted Sections 366.93 and 403.519(4), F.S., during the 2006 legislative session.  Section 366.93(2), F.S., requires the Commission to establish, by rule, alternative cost recovery mechanisms for the recovery of costs incurred in the siting, design, licensing, and construction of a nuclear power plant.  The Commission established Rule 25-6.0423, F.A.C, in order to satisfy the requirements of Section 366.93(2), F.S.  Rule 25-6.0423, 5(c)5, F.A.C, states:

By May 1 of each year, along with the filings required by this paragraph, a utility shall submit for Commission review and approval a detailed analysis of the long-term feasibility of completing the power plant.

In Order No. PSC-08-0518-FOF-EI., at page 24, the Commission provided specific guidance regarding the requirements necessary for PEF to satisfy Rule 25-6.0423, 5(c)5, F.A.C.  The Order reads as follows:

ORDERED that Progress Energy Florida, Inc. shall provide a long-term feasibility analysis as part of its annual cost recovery process which, in this case, shall also include updated fuel forecasts, environmental forecasts, non-binding capital cost estimates, and information regarding discussions pertaining to joint ownership.

Additionally, at pages 15 and 21, the Order contains the following language lending insight to the Commission’s intent regarding the long-term feasibility of PEF’s LNP project:

We also find that the CO2 price projections used in the cost-effective analysis represent a reasonable range of forecasts based upon CO2 compliance cost studies available to PEF at the time that the cost-effective analysis was undertaken.  Since the price forecasts are based upon on-going federal CO2 legislation, we find it appropriate that PEF provide updated cost information as part of its annual feasibility report.

We will review the continued feasibility of Levy Units 1 and 2 during its annual nuclear cost recovery proceedings; thus, providing the appropriate checks and balances to ensure that the construction of the nuclear units continues to be in the best interest of PEF’s ratepayers.

Staff believes that the discussed forecasts, information, estimates, and analysis are necessary filing requirements to assess PEF’s 2009 LNP project feasibility analysis and will provide the basis for staff’s recommendation regarding the approval or denial of PEF’s detailed analysis.

Updated Fuel Forecasts

PEF used high, mid, and low fuel forecast scenarios in its feasibility analysis.  PEF’s fuel forecasts provided in this docket were the same as those relied on in PEF’s 2009 Ten-Year Site Plan.  (EX 2, p. 421)

SACE argued that PEF’s recent analysis reflect a bubble in natural gas prices which has burst and is not likely to return. (TR 1595)  As pointed out by PCS Phosphate, approximately a year ago PEF assured the Commission that “the likelihood of the low fuel price forecast occurring at all in the future is improbable.” (TR 1531)  Staff believes that the statement above precisely focuses on the inherent uncertainty surrounding fuel forecasting.  Staff believes that PEF’s use of third party forecasts is consistent with Commission-accepted practice.[19]  Additionally, staff believes that reviewing the LNP using a range of fuel forecasts accounts for the volatility in the natural gas market.[20]  PEF has described the current forecasts as generally higher than the forecast presented in the LNP need determination.

Updated Environmental Forecasts

PEF provided four CO2 compliance cost scenarios in its feasibility analysis.  PEF’s environmental forecasts with regard to CO2 costs are numerically the same as in the need determination. (TR 1869)  PEF’s cost-effectiveness analysis, provided in response to a staff interrogatory, additionally included a scenario with no CO2 costs.

SACE argued that PEF’s forecast of CO2 costs were too high and did not reflect current pending legislation. (TR 1567-1568)  The same witness, however, asserted that the nature and scope of carbon mitigation and compliance cost had yet to be defined. (TR 1594)  PCS Phosphate argued that the Waxman Markey Bill should have been considered by PEF because the bill was pending in May 2009, and PEF’s rebuttal testimony was filed after the bill passed the House. (PCS Phosphate BR 19)  Staff believes that there is uncertainty regarding the future legislation of CO2 as well as potential issues regarding the timing of filing requirements and on-going legislation.  Staff believes that providing a range of CO2 forecasts is reasonable until legislation is enacted.

Project Cost Estimate

Although PEF’s total project cost estimate remained the same, PEF indicated that it has been updated and refined. (TR 1405-1406)  PEF further indicated that the total cost estimate may change depending on the outcome of the current change order negotiations with the Shaw/Westinghouse, but until those negotiations are concluded, the total capital cost estimate remains the current amount of $17.2 billion. (TR 1412-1413)  OPC ’s position is that the Commission should order PEF to file a feasibility analysis per the rule after renegotiation of the EPC.  Staff believes that PEF’s anticipated action will satisfy OPC’s desire.  As this is an annual review, staff would expect that any updates be included in PEF’s next filings and testimony.

Discussion Pertaining to Joint Ownership

In its May 1 filing, PEF indicated that it is continuing negotiations with municipal, electric cooperative, and investor-owned utilities regarding potential joint ownership in the LNP.  No party disputed PEF’s filing with regards to joint-ownership discussions. (TR 1196-1197)

Economic Analysis

PEF contended that a feasibility analysis should not be a type of annual cost-effective analysis that compares the cumulative present value revenue requirements for the LNP to other generation alternatives based on load, fuel, and emission cost forecast changes each year. (TR 2063)  PEF witness Franke, when giving his definition of feasibility with regard to the CR3 uprates, describes feasibility as “the ability of the project to provide an extended power uprate for Crystal River 3 and achieve an economic benefit for my customers.” (TR 1018)  Such a definition clearly emphasizes the importance of an economic analysis when addressing the feasibility of a project.  Staff believes that the PEF’s lack of an economic analysis for the LNP project contradicts its own definition of feasibility.  As stated by PCS Phosphate “a detailed economic analysis using current and reasonable assumptions should always be required.” (PCS Phosphate BR 18)  Staff agrees.

Through discovery and rebuttal testimony PEF provided an economic analysis.  It is notable that according to PEF’s analysis, the LNP project is the most cost-effective generation alternative at this time.  (EXH 2. pp 431-433)  The results of the economic analysis provided in response to discovery are comparable to what was presented in the need determination proceedings for the Levy projects.  PEF anticipates presenting the results of its EPC contract change order in the following NCRC proceeding, or perhaps before. (TR 2147)

PCS Phosphate indicated that Rule 25-6.0423, F.A.C., neither limits the types of analysis that may be required, nor specifies a particular set of analysis that must be submitted.  (EXH 2, pp.878-879)  Staff agrees that Rule 25-6.0423, F.A.C., does not provide a prescriptive list of requirements.  PCS Phosphate also asserted that the Commission is the only governing authority that has regulatory authority over the economic impact of the LNP.  (EXH 2, p.878) Given the Commission’s responsibilities, staff believes that an economic analysis is a requirement.

PEF contended that it cannot determine the feasibility of completing the LNP based on a year-to-year change in load and fuel forecasts.  (TR 2073)  PEF further contended that these projections can and will change from year to year, especially when the economy is in a recession like this year.  (TR 2064) Lastly, PEF asserted that if it applied changes in such forecasts to decide whether to stop or restart the project each year, PEF could never build a nuclear power plant.  (TR 2064) Staff recognizes the unique economic times that are influencing short-term trends, and furthermore believes that forecasts such as natural gas price forecasts are inherently uncertain.  Thus it is staff’s position that the feasibility of a long-term project such as the LNP project cannot be made on instant circumstances.  Staff believes that an annual economic analysis can and should be used to track trends and determine the effects of those trends.

Staff, through discovery, obtained the additional necessary information to evaluate the long-term feasibility of the LNP.  Staff believes that the additional analysis provided through discovery and rebuttal testimony support a conclusion that completing the LNP project is feasible at this time.  Staff believes that OPC’s desire for an updated analysis following the company’s negotiation change orders to the EPC contract will be satisfied through the annual filings in the NCRC.  PEF should be required to file updated capital cost estimates in its next annual NCRC filing.

Conclusion

Based upon the summation of the discussion above, staff believes that the Commission should not approve what PEF submitted as its May 1 annual detailed analysis of the long-term feasibility of completing the LNP project, pursuant to Rule 25-6.0423, F.A.C., and Order No. PSC-08-0518-FOF-E.  However, through discovery and rebuttal testimony, the necessary analysis to evaluate the economics of the long-term feasibility of the LNP project was obtained.  Staff believes that there is sufficient evidence in the record to support a conclusion that completing the LNP project is feasible at this time.

 

Issue 23A: 

 If the Commission does not approve PEF’s long term feasibility analysis of Levy Units 1 & 2, what further action, if any, should the Commission take?

Recommendation: 

 If PEF’s 2009 detailed long-term feasibility analysis of the LNP project is not approved, staff recommends PEF be directed to file a 2010 detailed annual long-term feasibility analysis in its May 1, 2010 annual filings and testimony.  The 2010 detailed long-term feasibility analysis should include updated assumptions and information, an economic analysis, and address the Commission’s rational for denial. (Graves, Laux, Breman)

Position of the Parties

PEF: 

  The Commission should specifically identify the perceived deficiencies and permit resubmission with the additional information and should not disallow any of PEF’s requested cost recovery amounts.

OPC: 

  (Prehearing) The Commission should order PEF to file a feasibility analysis pursuant to the rule and need order as soon as the costs associated with the revised schedule are known and measurable.  The Commission should consider identifying and withholding approval of costs that would not have been incurred but for the signing of the EPC contract (or a reasonable estimate or surrogate for those costs) until and unless PEF files an adequate long term feasibility analysis.

PCS Phosphate: 

  Levy cost recoveries in 2010 should be suspended until PEF completes its assessment of project schedule options, negotiates its EPC agreement changes, files a detailed updated economic feasibility assessment utilizing current cost estimates and realistic natural gas price forecasts, and receives Commission findings of on-going feasibility and reasonableness.

FIPUG: 

  The Commission should require PEF to prepare and file, in a timely fashion, an updated feasibility study which includes detailed cost information flowing from PEF’s revised project schedule.

SACE: 

  The Commission should deny cost recovery for PEF’s estimated 2009 and projected 2010 costs.

Staff Analysis: 

 This issue is moot if the Commission approves staff’s recommendation in Issue 23 (page 52).

This issue addresses what further action, if any, the Commission should take if it does not approve PEF’s 2009 detail long-term feasibility analysis of the LNP project.  In Issue 23, PEF argued that it complied with Rule 25-6.0423, F.A.C., and demonstrated LNP project feasibility. (PEF BR 19)

As discussed in Issue 23, the intervenors disagree with PEF’s assertion that its filing complied with the applicable requirements.  PCS Phosphate contended that PEF’s direct filing in May 2009 disregarded statutory and Commission-ordered requirements by not providing an economic analysis of the LNP project.  PCS Phosphate further asserted that PEF’s fuel price forecasts and emission cost assumptions were outdated.  Lastly, PCS argued that PEF did not possess updated LNP project cost and schedule information required to perform the required economic assessments. (PCS Phosphate BR 15-20)  OPC supports the post-hearing analysis provided by PCS Phosphate. (OPC BR 25)  FIPUG contended that PEF focused on the technological and regulatory feasibility of completing the project, and largely ignored the economic feasibility of completing the project. (FIPUG BR 8-9)  Similarly, SACE asserted that PEF’s May 1 testimony only contained technical and regulatory feasibility but contained no economic analysis or discussion of project cost as it relates to the feasibility of the LNP.  SACE also argued that PEF’s cumulative present value revenue requirement (CPVRR) analysis, submitted as part of its rebuttal testimony, was based upon assumptions that were outdated and unreasonable. (SACE BR 15, 19-21)

In this issue, the intervenors suggested various actions.  FIPUG argued that the Commission should defer its decision on the long-term feasibility of the project and order PEF to provide updated cost information, including any costs associated with the re-negotiated EPC schedule when such information is available. (FIPUG BR 8-9)  PCS Phosphate argued that the Commission should require that PEF prepare and submit an updated project feasibility analysis once the utility has re-established expected cost and in-service dates for the Levy units.  PCS further asserted that the analysis should be subject to discovery and challenge in a separate proceeding.  Lastly, PCS Phosphate contended that cost recovery for the LNP project should follow rather than precede Commission approval of this analysis.  (PCS Phosphate BR 20-21)  OPC supports the analysis provided by PCS Phosphate in its post-hearing statement. (OPC BR 25)  SACE contended that the Commission should deny cost recovery for PEF’s estimated 2009 and projected 2010 costs.[21]   (SACE BR 27)

Staff believes resolution of this issue hinges on the Commission’s basis for denial of PEF’s 2009 LNP feasibility analysis in Issue 23.  As described above, there may be various reasons for Commission denial.  Depending on the rational for denial, the Commission may choose to take different corrective actions.  Staff identified the following three potential actions.

·        Deferred Decision:  The Commission can elect not to make a decision regarding project feasibility analysis until it has reviewed the next annual filing, due May 1, 2010, in order to establish a pattern or trend.  PEF’s subsequent filing would include use of appropriate updated assumptions, costs, and be expanded, as necessary, to address concerns with economic analysis and the Commission’s rational for denial.  This action is supported by the ongoing nature of the clause, and if the Commission does not approve PEF’s feasibility analysis.  This action does not result in adjustments to the recoverable amounts in any of PEF’s issues.

·        Suspend 2010 Cost Recovery:  The Commission can elect to defer a decision regarding PEF’s collection of 2010 costs until the Commission has reviewed the next annual filing, due May 1, 2010.  PEF’s subsequent filing would include use of appropriate updated assumptions, costs, and be expanded, as necessary, to address any concerns with additional scope.  This action is supported if the Commission believes the amount to be suspended from recovery is closely related to PEF’s EPC change order negotiations, and that approval of the feasibility analysis is a prerequisite for cost recovery.  The cost recovery adjustments resulting from this action are included in staff’s analysis of Issues 31, 32A and 32B (pages 66, 71, 74).

·        Deny Future Cost Recovery: The Commission can elect to deny cost recovery if the Commission finds credible evidence that PEF’s plan to continue the LNP project is   imprudent.  The cost recovery adjustments resulting from this action are included in staff’s analysis of Issues 30, 31, 32A and 32B (pages 64, 66, 71, 74).

Conclusion

If PEF’s 2009 detailed long-term feasibility analysis of the LNP project is not approved, staff recommends PEF be directed to file a 2010 detailed annual long-term feasibility analysis in its May 1, 2010 annual filings and testimony.  The 2010 detailed long-term feasibility analysis should include updated assumptions and information, an economic analysis, and address the Commission’s rational for denial.

 

 

Issue 23B: 

 What further steps, if any, should the Commission require PEF to take regarding the Levy Units 1 & 2?

Recommendation: 

 Staff recommends further Commission actions, in addition to those taken in Issues 23 and 23A, are not necessary regarding PEF’s 2009 detailed long-term feasibility analysis of completing the LNP project.  (Graves, Laux, Breman)

Position of the Parties

PEF: 

  The Commission has all the information necessary to make a prudence determination on the Company’s costs and actions for 2006-2008, and a reasonableness determination on the costs for 2009 and 2010.  Therefore, the Commission should require nothing else with respect to Levy Units 1& 2 in this proceeding.

OPC: 

  (Prehearing) See Issue 23A position. In addition, the commission should consider spinning off into a separate docket the issues of feasibility and prudence and cost impacts associated with the LNP project relative to the schedule delay issue. The Commission should require PEF to file additional information relating to the circumstances related to the signing of the EPC and the costs of a renegotiated EPC contract.

PCS Phosphate: 

  The Commission should indicate that PEF’s failure to fulfill the standards expected of an entity undertaking construction of projects of this magnitude may result in appointment of a special master empowered to take all necessary measures to assure PEF customers of the prudence and reasonableness of PEF decision-making.

FIPUG: 

  The Commission should require PEF to provide additional capital cost information on Levy Units 1 and 2 so that the Commission has the necessary information to determine whether the project meets the requirement for long-term feasibility.  Included with this information should be cost information related to the renegotiated EPC schedule.

SACE: 

  At a minimum, PEF should have to demonstrate that Levy Units 1 & 2 are the least-cost alternative of supplying a properly projected demand for power when the project is reasonably expected to come online.

Staff Analysis: 

 This issue addresses what additional action the Commission should take regarding PEF’s 2009 detailed long-term feasibility analysis of completing the LNP project.

PEF asserted that if the Commission determines that PEF’s submissions are for some reason deficient, due process requires the Commission afford PEF an opportunity to correct any perceived deficiency. (PEF BR 19)  The intervenors’ post-hearing briefs do not explain their respective positions on this issue.

Staff notes that the positions of OPC, FIPUG and SACE relate to Commission actions in approval of PEF’s feasibility analysis in Issue 23 (page 52), or denial in Issue 23A (page 57).  PCS Phosphate maintained that the Commission should indicate that it may appoint a special master empowered to take all necessary measures to assure PEF customers of the prudence and reasonableness of PEF decision-making.  As noted, PCS Phosphate’s post-hearing brief did not explain how the action would be implemented under Section 366.93, F.S.

OPC witness Jacobs expressed a view that spin-off dockets to address LNP project feasibility and PEF’s prudence related to LNP project schedule changes are needed.  (TR 1473)  While asserted, witness Jacobs did not explain problems that would necessitate departure from the current ongoing review docket pursuant to Rule 25-6.0423, F.A.C.

Staff believes that all disputed matters concerning PEF’s LNP project feasibility analysis and prudence are addressed in staff’s recommendations and analyses found in prior issues.  Additionally, PEF’s actions concerning LNP project schedule changes identified during 2009 will be subject to ongoing review in the NCRC.  Thus, staff believes additional actions are not necessary at this time.

Conclusion

Based upon the foregoing, staff believes Commission actions, in addition to those taken in Issues 23 and 23A, are not necessary regarding PEF’s 2009 detailed long-term feasibility analysis of completing the LNP project.

 

Issue 26: 

 What system and jurisdictional amounts should the Commission approve as PEF’s reasonably estimated 2009 costs for the Crystal River Unit 3 Uprate project?

Recommendation: 

 Staff recommends the Commission approve, as reasonable, estimated 2009 Crystal River Unit 3 Uprate project construction costs in the amount of $117,537,552 ($84,322,605 jurisdictional), O&M expenses of $117,638 ($772,528 jurisdictional), carrying charges of $14,229,591, and a base rate revenue requirement of $752,789.  The Commission should also approve an estimated 2009 LNP project true-up amount of $530,215.  (Laux)

Position of the Parties

PEF: 

  Capital Costs (System) $126,126,306; (Jurisdictional) $91,712,976.  O&M Costs (System) $8,108,218; (Jurisdictional) $7,596,559.

OPC: 

  (Prehearing) No position.

PCS Phosphate: 

  No position.

FIPUG: 

  (Prehearing) No position.

SACE: 

  (Prehearing) No position.

Staff Analysis: 

 This issue addresses PEF’s request concerning the reasonableness of estimated 2009 project costs and the estimated 2009 true up amount for the CR3 Uprate project.  PEF witness Foster provided support regarding the amounts and method used to determine the requested recovery amounts. (EX 86)  PEF witness Franke provided descriptions of the planning and construction activities that are associated with the 2009 period costs. (TR 958-971, 983-992)  No party challenged the reasonableness of PEF’s requested 2009 CR3 Uprate Project costs. (TR 1484, 1543, 1627)

OPC, FIPUG and SACE took no position on this issue and did not address this issue in their post-hearing briefs.  Therefore, pursuant to the prehearing order, OPC, FIPUG, and SACE have waived their positions on this issue.

Staff notes that PEF’s post-hearing position does not reflect the changes presented at hearing with respect to O&M expenses.  PEF witness Foster’s initial estimated construction costs were $126,126,306 ($91,712,976 jurisdictional), O&M costs were $8,108,218 ($7,596,559 jurisdictional), carry charges were $14,920,565, and the base rate revenue requirement was $1,242,555. (EX 86)  Witness Foster sponsored the following adjustments to his initially estimated amounts: a decrease in capital costs of $8,588,854 ($7,390,371 jurisdictional), a decrease in O&M expenses of $7,930,580 ($6,824,031 jurisdictional), an increase in carrying charges of $983,108, and a decrease in base rate revenue requirements of $489,766. (EX 140)  Thus, PEF’s revised estimated amounts are construction costs of $117,537,552 ($84,322,605 jurisdictional), O&M costs of $117,638 ($772,528 jurisdictional), carry charges of $14,229,591 and a base rate revenue requirement of $752,789.  The impact of estimated obsolete inventory is reflected in PEF’s revised O&M amounts.  If approved, all amounts are subject to a future prudence review and final true-up.

Staff compared these estimated 2009 costs to the approved 2009 projected NCRC amounts to determine the estimated true-up amount.  PSC-08-0749-FOF-EI, at page 15, identified projected carrying charges totaling $14,920,565 and projected O&M expenses of $304,128.  Staff believes that the 2009 estimated true-up amount is $530,215.  The 2009 variance is the sum of over-projected carrying charges of $690,974 ($14,920,565 – 14,229,591 = $690,974), and under-projected O&M expenses of $468,400 ($304,128 – $772,528 = $468,400), and an over-projected base rate revenue requirement of $752,789 ($0 – $752,789 = $752,789).

Conclusion

Staff reviewed PEF’s calculations and supporting information and recommends the Commission approve, as reasonable, estimated 2009 CR3 Uprate project construction costs in the amount of $117,537,552 ($84,322,605 jurisdictional), O&M expenses of $117,638 ($772,528 jurisdictional), carry charges of $14,229,591, and a base rate revenue requirement of $752,789.  Staff recommends that the Commission also approve an estimated 2009 CR3 project true-up amount of $530,215

 

Issue 30: 

 What system and jurisdictional amounts should the Commission approve as reasonably estimated 2009 costs for PEF’s Levy Units 1 & 2 project?

Recommendation: 

 Staff recommends the Commission approve, as reasonable, estimated 2009 Levy Units 1 & 2 project construction costs of $24,596,242 ($17,235,584 jurisdictional), preconstruction costs of $291,904,861 ($262,362,852 jurisdictional), O&M expenses of $5,513,853 ($4,931,288 jurisdictional), and carry charges of $22,278,969.  The Commission should also approve, as reasonable, an estimated 2009 LNP project true-up amount of $141,665,654.  (Laux)

Position of the Parties

PEF: 

  Capital Costs (System) $316,501,103; (Jurisdictional) $279,598,436. O&M costs (System) $5,513,853; (Jurisdictional) $4,931,288.

OPC: 

  (Prehearing) No position.

PCS Phosphate: 

  PCS Phosphate agrees and adopts the position of the OPC.

FIPUG: 

  (Prehearing) No position.

SACE: 

  None.  PEF has not demonstrated long-term feasibility as required by Rule 25-6.0423(5)(c)5, F.A.C.  Therefore no such cost could be reasonably projected and/or incurred.

Staff Analysis: 

 This issue addresses PEF’s request concerning the reasonableness of estimated 2009 LNP project costs and the estimated 2009 true up amount for the LNP.  PEF witness Foster provided support regarding the amounts and method used to determine the requested recovery amounts. (TR 916-918, 923-926; EX 83)  Witnesses Furman and Miller provided descriptions of the planning and construction activities that are associated with the 2009 period costs for which PEF requested recovery. (TR 1135-1144, 1172, 1186-1191)

OPC and FIPUG took no position on this issue and did not address this issue in their post-hearing briefs.  Therefore, pursuant to the prehearing order, OPC and FIPUG have waived their positions on this issue.

SACE argued PEF failed to comply with the detailed analysis of long-term feasibility requirements of Rule 25-6.0423(5)(c)5, F.A.C. (SACE BR 1, 4, 10, 27, 30)  Staff addresses PEF’s long-term feasibility analysis in Issue 23 (page 52).  Consistent with staff’s recommendation in Issue 23, and a preponderance of the record, staff believes that denial of recovery is an extreme measure that is not warranted.  PEF’s recovery of 2009 expenditures will be subject to a future prudence review.  However, should the Commission agree with SACE and deny PEF recovery of 2009 LNP project costs, then PEF should be required to refund the 2009 projected amount of $147,907,456 that PEF was authorized to collect pursuant to Order No. PSC-08-0749-FOF-EI , at page 21.

No other party supported adjustments to PEF’s requested amounts.  Staff reviewed PEF’s calculations and supporting information.  PEF’s position presented estimated capital costs of $316,501,103 (279,598,436 jurisdictional), O&M expenses of $5,513,853 ($4,931,288) jurisdictional), and carry charges of $22,278,969. (EX 83)  Staff notes that capital cost amounts in PEF’s position statement include both construction and preconstruction costs.  The construction costs are $24,596,242 ($17,235,584 jurisdictional) and the preconstruction costs are $291,904,861 ($262,362,852 jurisdictional).  (EX 83)  If approved, all amounts are subject to a future prudence review and final true-up.

Staff compared these estimated 2009 costs to the approved 2009 projected NCRC amounts to determine the estimated true-up amount.  Order No. PSC-08-0749-FOF-EI, at pages 20 and 21, identified projected preconstruction costs of $97,084,049, carrying charges totaling $49,580,292 and projected O&M expenses of $1,243,114.  Staff believes that the 2009 estimated true-up amount is $141,665,654 based on PEF’s revised estimate of 2009 costs. (EX 139)  The 2009 true-up variance is the sum of over-projected carrying charges of $27,301,323 ($49,580,291 – $22,278,969 = $27,301,323), and under-projected O&M expenses of $3,688,174 ($1,243,114 – $4,931,288 = $3,688,174), and under-projected preconstruction costs of $165,278,803 ($97,084,049 – $262,362,852 = $165,278,803).

Conclusion

Staff reviewed PEF’s calculations and supporting information and recommends the Commission approve, as reasonable, estimated 2009 LNP project construction costs of $24,596,242 ($17,235,584 jurisdictional), preconstruction costs of $291,904,861 ($262,362,852 jurisdictional), O&M expenses of $5,513,853 ($4,931,288) jurisdictional) and carry charges of $22,278,969.  The Commission should approve an estimated 2009 LNP project true-up amount of $141,665,654.

 

 

Issue 31: 

 What system and jurisdictional amounts should the Commission approve as reasonably projected 2010 costs for PEF’s Levy Units 1 & 2 project?

Recommendation: 

 Consistent with staff’s recommendation in Issue 32 to approve PEF’s proposed rate management plan, staff recommends the Commission approve, as reasonable, projected 2010 LNP project construction costs of $64,796,549 ($43,397,584 jurisdictional), preconstruction costs of $123,752,490 ($106,122,607 jurisdictional), O&M expenses of $5,201,011 ($4,433,053 jurisdictional), and carrying costs of $53,620,827.  The Commission should also approve the projected 2010 LNP recovery amount of $164,176,487 for use in fall-out Issue 32A.  (Laux)

Position of the Parties

PEF: 

  Capital costs (System) $188,549,039; (Jurisdictional) $149,520,191.  O&M Costs (System) $5,201,011; (Jurisdictional) $4,433,053.

OPC: 

  (Prehearing) No position.

PCS Phosphate: 

  PCS Phosphate agrees and adopts the position of the OPC.

FIPUG: 

  (Prehearing) No position.

SACE: 

  None.  PEF has not demonstrated long-term feasibility as required by Rule 25-6.0423(5)(c)5, F.A.C.  Therefore no such cost could be reasonably projected and/or incurred.

Staff Analysis: 

 This issue addresses PEF’s request concerning the reasonableness of projected  2010 project costs for the LNP.  PEF witness Foster provided support for the amounts and method used to determine the requested recovery amounts. (TR 927-930; EX 2 Tab 15; EX 84, 85, 139)  Witnesses Furman and Miller provided descriptions of the planning and construction activities that are associated with the 2010 period costs for which PEF is requesting recovery. (TR 1135-1144, 1172, 1186-1191)

OPC and FIPUG took no position on this issue and did not address this issue in their post-hearing briefs.  Therefore, pursuant to the prehearing order, OPC and FIPUG have waived their positions on this issue.

SACE argued PEF failed to comply with the detailed analysis of long-term feasibility requirements of Rule 25-6.0423(5)(c)5, F.A.C. (SACE BR 1, 4, 10, 27, 30)  Consequently, SACE urged the Commission to deny recovery of projected 2010 costs. (SACE BR 1, 5, 10, 27, 30)  PCS Phosphate urged the Commission to suspend cost recovery until PEF completes its assessments of project schedule, contracts, total project costs, and feasibility. (PCS Phosphate BR 22)  No other party supported adjustments to PEF’s requested recovery amounts.

The concerns of SACE and PCS Phosphate related to PEF’s long-term feasibility analysis which is addressed Issue 23 (page 52).  Consistent with staff’s recommendation in Issue 23, and a preponderance of the record, staff believes that denial of recovery, as suggested by SACE, is an extreme measure that is not warranted.  However, if the Commission agrees with SACE’s arguments, then the Commission should approve a zero amount for recoverable 2010 LNP costs. 

Uncertainties will exist until PEF has completed its EPC contract change order negotiations with Shaw/Westinghouse due to LWA matters. (TR 1415)  PEF witness Miller asserted the change order results may be well within the CPVRR analysis presented in rebuttal by witness Lyash. (TR 1415)  Staff believes that until PEF completes its EPC contract change order negotiations, PEF will not have substantive updates to cost and schedule information. (TR 1415)  PEF anticipates presenting the results of its EPC contract change order in the following NCRC proceeding, perhaps before. (TR 2147)  Additionally, staff notes that the NCRC prudence review and true-up process provides customer protection if it is ultimately determined that PEF imprudently incurred 2010 costs.  Consequently, staff is not persuaded that suspension of PEF’s 2010 recovery, as suggested by PCS Phosphate, is the appropriate response to uncertainties rising from PEF’s EPC contract change order negotiations and possible impacts to the LNP project feasibility.  Staff believes the appropriate response is to follow the NCRC prudence review and final true-up process.

PEF witness Foster presented two projections of 2010 LNP costs. (EX 84, 85)  One projection excludes a rate management plan and the other is based on implementing a rate management plan.  However, these exhibits do not reflect PEF’s stipulation in Issue 1 to exclude CCRC sales forecast variances from the NCRC. (EX 2 Tab 15)  Witness Foster sponsored Exhibit 139 which provided updated total 2010 projected amounts consistent with stipulated Issue 1 and PEF’s position on Issue 32A.  Staff notes that PEF’s positions in Issues 32A and 32B are consistent with stipulated Issue 1.

PEF’s position regarding projected 2010 costs presented capital costs of $188,549,039 ($149,520,191 jurisdictional), O&M expenses of $5,201,011 ($4,433,053 jurisdictional), and carry charges of $53,620,827. (EX 85, 139)  Staff notes that the capital cost amount in PEF’s position statement includes both construction and preconstruction costs. (EX 85)  The construction costs are $64,796,549 ($43,397,584 jurisdictional) and the preconstruction costs are $123,752,490 ($106,122,607 jurisdictional).  (EX 85)  These amounts are calculated consistent with a proposed rate management plan, discussed in Issue 32 and implemented in fall-out Issue 32A. 

For purposes of implementing PEF’s rate management plan in fall-out Issue 32A, the projected 2010 LNP recovery amount is $164,176,487.  ($53,620,827 + $4,433,053 + $106,122,607 = $164,176,487)  Not implementing PEF’s rate management plan reduces the carrying charges that accrue during 2010 from $53,620,827 to $26,094,107.  For purposes of fall-out Issue 32B, the 2010 LNP recovery amount is $136,649,767.  ($26,094,107 + $4,433,053 + $106,122,607 = $136,649,767)  Staff notes that all projected amounts are subject to a future prudence review and final true-up.

Conclusion

Consistent with staff’s recommendation in Issue 32 to approve PEF’s proposed rate management plan, staff recommends the Commission approve, as reasonable, projected 2010 LNP project construction costs of $64,796,549 ($43,397,584 jurisdictional), preconstruction costs of $123,752,490 ($106,122,607 jurisdictional), O&M expenses of $5,201,011 ($4,433,053 jurisdictional), and carrying costs of $53,620,827.  The Commission should also approve the projected 2010 LNP recovery amount of $164,176,487 for use in fall-out Issue 32A.

 

Issue 32: 

 Should the Commission approve PEF’s alternative cost recovery proposal, as set forth in PEF’s Petition and supporting Testimony, as to recovery of NCRC costs?

Recommendation: 

 Yes.  Staff recommends the Commission approve a rate management plan whereby PEF will be permitted to defer recovery of certain approved site selection and preconstruction costs and then collect those costs during subsequent years.  The deferred costs should be treated as a regulatory asset with carrying charges applied pursuant to Section 366.92(1)(f), F.S., and Rule 25-6.0423(5)(a), F.A.C.  Staff recommends the Commission approve $273,889,606 as the January 1, 2010, beginning balance of the regulatory asset with $36,618,113 of that balance being approved for inclusion in rates in 2010.  (Hinton, Young)

Position of the Parties

PEF: 

  Yes, the Commission should approve PEF alternative cost recovery proposal due to both the current economic climate and to provide the ratepayers some immediate relief as stated in PEF’s petition filed May 1, 2009 in Docket # 090009 and presented in the Issue position statement in the prehearing order.

OPC: 

  (Prehearing)  The Citizens do not object to PEF’s requested cost recovery being lower.  At this time we do not have a position on the determination of carrying costs associated with voluntary deferral of costs already approved.

PCS Phosphate: 

  Yes, to the extent Progress’ actual/estimated 2009 costs are deemed reasonable.

FIPUG: 

  (Prehearing) Concurs with OPC.

SACE: 

  (Prehearing) No position.

Staff Analysis: 

 In its petition and supporting testimony PEF has proposed a rate management plan designed to decrease the rate impact that would otherwise occur if the entire approved nuclear cost recovery amount were to be included in 2010 rates.  In its brief, PEF asserted that the Commission should approve PEF’s alternative cost recovery schedule due to both the current economic climate and to provide the ratepayer some immediate relief. (PEF BR 6)  PEF has proposed to defer certain site selection and preconstruction costs approved for recovery through the NCRC, and collect those costs over the next five years.  (TR 930)  Under PEF’s proposal, a carrying charge would be applied to the deferred balance pursuant to the Statute and Rule. (TR 930)  PCS Phosphate supported approval of a rate management plan, provided the 2009 preconstruction costs to be deferred are deemed reasonable. (PCS Phosphate BR 22)  No other party took a position on this issue in their post-hearing briefs.

Staff agrees that PEF’s proposed rate management plan could provide relief to ratepayers by decreasing rate impact during 2010.  Staff believes PEF should be permitted to defer recovery of costs that have been approved for recovery through the NCRC.  However, while PEF’s proposal suggests recovery of the deferred balance over a five year period, staff believes greater flexibility to manage rates should be retained and that PEF should be permitted to annually reconsider changes to the deferred amount and recovery schedule.  Approval of PEF’s rate management plan would require PEF to file rate management plan testimony and schedules with its annual NCRC final true-up, estimated true-up and projection testimony.

Staff would note that the Commission’s decision on Issue 2 will have a direct impact on the treatment of the deferred balance under the rate management plan.  Consistent with staff’s recommendation in Issue 2, staff believes the deferred balance should be treated as a regulatory asset with a carrying charge applied pursuant to Section 366.92(1)(f), F.S., and Rule 25-6.0423(5)(a), F.A.C.

PEF’s updated position in Issue 32A includes a proposed deferral amount of $273,889,606.  (EX 139)  This amount would be the 2010 beginning balance of a regulatory asset.  As revised, PEF’s plan includes recovery of $36,618,113 of that regulatory asset during 2010. (EX 139)  PEF proposes to recover the entire regulatory asset by 2014.

Conclusion

Staff recommends the Commission approve a rate management plan whereby PEF will be permitted to defer recovery of certain approved site selection and preconstruction costs and then collect those costs during subsequent years.  The deferred costs should be treated as a regulatory asset with carrying charges applied pursuant to Section 366.92(1)(f), F.S., and Rule 25-6.0423(5)(a), F.A.C.  Staff recommends the Commission approve $273,889,606 as the January 1, 2010, beginning balance of the regulatory asset with $36,618,113 of that balance being approved for inclusion in rates in 2010.

Issue 32A: 

 If the answer to Issue 32 is yes, what is the total jurisdictional amount to be included in establishing PEF’s 2010 Capacity Cost Recovery Clause factor?

Recommendation: 

 Consistent with staff’s recommendation on all prior issues, including the rate management plan, staff recommends the Commission approve $206,907,726 to be included in establishing PEF’s 2010 CCRC factor.  (Laux)

Position of the Parties

PEF: 

  The total jurisdictional amount to be included in establishing PEF’s 2010 Capacity Cost Recovery Clause factor should be $236,251,017 inclusive of sales variances from prior periods or $213,238,415 with sales variances removed (before revenue tax multiplier).

CR3 Uprate 2010 Revenue Requirement Summary
		2006-2008 True Up	2009 A/E True Up	2010 Projected		Total
O&M		(95,044)	7,292,431	214,203		7,411,590
Carrying Costs		64,444	(1,674,082)	5,325,702		3,716,064
Plant In-service		73,606	1,242,555			1,316,161
CCRC Variance (due to sales variance)				(1,774,957)		(1,774,957)
Total Uprate 366.93 Revenue Requirements		43,006	6,860,904	3,764,948		10,668,858

 

Levy 2010 PEF Alternative NCRC Recovery Revenue Requirement Summary
		2006-2008 True Up	2009 A/E True Up	2010 Projected		Total
Site Selection & Preconstruction Additions	(65,763,507)		165,278,803	106,122,607		205,637,903
O&M		2,305,178	3,688,174	4,433,053		10,426,405
Carrying Costs		(2,317,719)	(27,301,323)	53,620,827		24,001,785
Order No. 09-0208 Deferral				198,000,000		198,000,000
CCRC Variance (due to sales variance)				24,787,559		24,787,559
Total Levy 366.93 Revenue Requirements	(65,776,048)		141,665,654	386,964,046		462,853,652
Less: Proposed Deferral						(273,889,606)
Plus: 2010 Amortization of Proposed Deferral						36,618,113
Proposed Levy Revenue Requirements for 2010 CCRC						225,582,159

 

OPC: 

  (Prehearing) No position.

PCS Phosphate: 

  PCS Phosphate agrees and adopts the position of the OPC.

FIPUG: 

  (Prehearing) No position.

SACE: 

  (Prehearing) No position.

Staff Analysis: 

 This issue is a fall-out issue that reflects decisions on all prior issues, including approval of PEF’s rate management plan.  Both contested and partially stipulated issues impacting the total amount are identified in the following table.  As shown in the table, only SACE, PCS Phosphate, and staff supported adjustments to PEF’s 2010 recovery level in prior issues.

 

OPC, FIPUG and SACE took no position on this issue and did not address this issue in their post-hearing briefs.  Therefore, pursuant to the prehearing order, OPC, FIPUG and SACE have waived their positions on this issue.  PCS Phosphate provided a post-hearing position that adopts OPC’s position, which is no position.  However, PCS Phosphate supports PEF’s cost recovery proposal to the extent PEF’s estimated costs are deemed reasonable.  (PCS Phosphate BR 5, 22)

Conclusion

Consistent with staff’s recommendation on all prior issues, staff recommends the Commission approve $206,907,726 to be included in establishing PEF’s 2010 CCRC factor.

 

Issue 32B: 

 If the answer to Issue 32 is no, what is the total jurisdictional amount to be included in establishing PEF’s 2010 Capacity Cost Recovery Clause factor?

Recommendation: 

 If a rate management plan is not approved, staff recommends the Commission approve $416,652,499 to be included in establishing PEF’s 2010 CCRC factor.  (Laux)

Position of the Parties

PEF: 

  The total jurisdictional amount to be included in establishing PEF’s 2010 Capacity Cost Recovery Clause factor should be $445,995,790 inclusive of sales variances from prior periods or $422,983,188 with sales variances removed (before revenue tax multiplier).

CR3 Uprate 2010 Revenue Requirement Summary
		2006-2008 True Up	2009 A/E True Up	2010 Projected		Total
O&M		(95,044)	7,292,431	214,203		7,411,590
Carrying Costs		64,444	(1,674,082)	5,325,702		3,716,064
Plant In-service		73,606	1,242,555			1,316,161
CCRC Variance (due to sales variance)				(1,774,957)		(1,774,957)
Total Uprate 366.93 Revenue Requirements		43,006	6,860,904	3,764,948		10,668,858

 

Levy 2010 Traditional NCRC Recovery Revenue Requirement Summary
		2006-2008 True Up	2009 A/E True Up	2010 Projected		Total
Site Selection & Preconstruction Additions		(65,763,507)	165,278,803	106,122,607		205,637,903
O&M		2,305,178	3,688,174	4,433,053		10,426,405
Carrying Costs		(2,317,719)	(27,301,323)	26,094,107		(3,524,935)
Order No. 09-0208 Deferral				198,000,000		198,000,000
CCRC Variance (due to sales variance)				24,787,559		24,787,559
Total Levy 366.93 Revenue Requirements		(65,776,048)	141,665,654	359,437,326		435,326,932

 

OPC: 

  (Prehearing) No position.

PCS Phosphate: 

  No position.

FIPUG: 

  (Prehearing) No position.

SACE: 

  (Prehearing) No position.

Staff Analysis: 

 This issue is an alternative fall-out issue in the event a rate management plan is not approved in Issue 32.  Both contested and partially stipulated issues impacting PEF’s total 2010 recovery amount are identified in the following table.  As shown in the table, only SACE, PCS Phosphate, and staff supported adjustments to PEF’s 2010 recovery level in prior issues.

 

OPC, FIPUG and SACE took no position on this issue and did not address this issue in their post-hearing briefs.  Therefore, pursuant to the prehearing order, OPC, FIPUG and SACE have waived their positions on this issue.  PCS Phosphate’s post-hearing position is no position.  However, in the above table, staff includes PCS Phosphates position concerning PEF’s recovery of 2010 LNP costs.

All the amounts in the above table reflect denial of PEF’s rate management plan and are consistent with staff’s analyses in all other prior issues.  If a rate management plan is not approved, staff recommends the Commission approve $416,652,499 to be included in establishing PEF’s 2010 CCRC factor.

Policy and Legal - Proposed Category II Stipulated Issue among FPL, PEF, and Staff

 

ISSUE 1:         Should over or under collections in the Capacity Cost Recovery Clause be included in the calculation of recoverable costs in the NCRC?

 

POSITION:    No.  Rule 25-6.0423 defines the appropriate costs to be recovered in the NCRC.  That definition does not included CCRC over or under collections.  Over and under collections in the CCRC should remain in the CCRC, because they are the result of over/under collections of actual sales revenues that are greater than or less than costs to be recovered in the CCRC, and will incur interest at the commercial paper rate.  Prospectively, if the Commission approves deferral of collection of certain NCRC costs and thereby removes them from rates, they should not be reflected in the Capacity Cost Recovery Clause over or under recovery.  Differences between the NCRC actual costs incurred and the actual/estimated or projected costs will be included in the calculation of recoverable costs in the NCRC, and will accrue a carrying charge at the fixed rate provided for pursuant to Section 366.93, F.S., until recovered in a future period.

 

Florida Power & Light Company - Proposed Category II Stipulated Issues between FPL and Staff

 

ISSUE 4:         Should the Commission find that for the years 2006 and 2007, FPL’s accounting and costs oversight controls were reasonable and prudent for the Turkey Point Units 6 & 7 project?

 

POSITION:    For the years 2006 and 2007, FPL’s accounting and costs oversight controls were reasonable and prudent for the Turkey Point Units 6 & 7 project.

 

ISSUE 5:         Should the Commission find that for the years 2006 and 2007, FPL’s project management, contracting, and oversight controls were reasonable and prudent for the Turkey Point Units 6 & 7 project?

 

POSITION:    Yes.  For the years 2006 and 2007, FPL’s project management, contracting, and oversight controls were reasonable and prudent for the Turkey Point Units 6 & 7 project.

 

ISSUE 6:         Should the Commission find that for the year 2008, FPL’s accounting and costs oversight controls were reasonable and prudent for the Turkey Point Units 6 & 7 project and the Extended Power Uprate project?

 

POSITION:    Yes. For the year 2008, FPL’s accounting and costs oversight controls were reasonable and prudent for Turkey Point Units 6 & 7 project and the Extended Power Uprate project.

 

ISSUE 9:         Should the Commission approve what FPL has submitted as its annual detailed analyses of the long-term feasibility of completing the EPU project, as provided for in Rule 25-6.0423, F.A.C.?

 

POSITION:    Yes.  The analyses support a conclusion that completing the EPU project is feasible.

 

ISSUE 10:       What system and jurisdictional amounts should the Commission approve as FPL’s final 2008 prudently incurred costs for the Extended Power Uprate project?

 

POSITION:    The 2008 prudently incurred system EPU costs are $99,754,304 in expenses and $269,184 in O&M expenses.  The resultant jurisdictional costs, net of joint owner and other adjustments, are $95,097,049 for capital expenses, $2,357,995 in carrying charges, and $256,091 in O&M expenses.

 

For purposes of the CCRC, the final 2008 NCRC true up amount, is an over estimate of $1,375,009 in carrying costs plus an under estimate of $256,091 in O&M expenses.  The net amount of -$1,118,918 should be included in setting the allowed 2010 NCRC recovery.

 

ISSUE 14:       What system and jurisdictional amounts should the Commission approve as FPL’s final 2006 and 2007 prudently incurred costs for the Turkey Point Units 6 & 7 project?

POSITION:    The 2006 and 2007 prudently incurred system Turkey Point Units 6 & 7 costs are $8,651,370 ($8,615,263 jurisdictional) in expenses and $0 in O&M expenses.  The resultant jurisdictional carrying costs are $155,189.

 

                        For purposes of the CCRC, the final 2007 NCRC trueup amount, is an over estimate of $304,739 in expenses and $7,216 in carrying costs.  The net amount of -$311,955 should be included in setting the allowed 2010 NCRC recovery.

 

ISSUE 15:       What system and jurisdictional amounts should the Commission approve as FPL’s final 2008 prudently incurred costs for the Turkey Point Units 6 & 7 project?

 

POSITION:    The 2008 prudently incurred system Turkey Point Units 6 & 7 costs are $47,215,633 ($47,049,854 jurisdictional) in expenses and $0 in O&M expenses.  The associated 2008 jurisdictional carrying costs are $2,886,482.

 

                        For purposes of the CCRC, the final 2008 NCRC true up amount, is an over estimate of $22,658,001 in expenses and $1,171,701 in carrying costs.  The net amount of -$23,829,702 should be included in setting the allowed 2010 NCRC recovery.

 

Progress Energy Florida, Inc.  -  Proposed  Category  II  Stipulated Issues between PEF and Staff

 

ISSUE 19:       Should the Commission find that for the years 2006 and 2007, PEF’s accounting and costs oversight controls were reasonable and prudent for the Levy Units 1 & 2 project?

 

POSITION:    Yes.  For the years 2006 and 2007, PEF’s accounting and costs oversight controls were reasonable and prudent for the Levy Units 1 & 2 project.

 

ISSUE 20:       Should the Commission find that for the years 2006 and 2007, PEF’s project management, contracting, and oversight controls were reasonable and prudent for the Levy Units 1 & 2 project?

 

POSITION:    Yes.  For the years 2006 and 2007, PEF’s project management, contracting, and oversight controls were reasonable and prudent for the Levy Units 1 & 2 project.

 

ISSUE 22:       Should the Commission find that for the year 2008, PEF’s accounting and costs oversight controls were reasonable and prudent for the Levy Units 1 & 2 project and the Crystal River Unit 3 Uprate project?

 

POSITION:    Yes.  For the year 2008, PEF’s accounting and costs oversight controls were reasonable and prudent for Levy Units 1 & 2 project and the Crystal River Unit 3 Uprate project.

 

ISSUE 24:       Should the Commission approve what PEF has submitted as its annual detailed analysis of the long-term feasibility of completing the Crystal River Unit 3 Uprate project, as provided for in Rule 25-6.0423, F.A.C.?

 

POSITION:    Yes.  The analyses support a conclusion that completing the Crystal River Unit 3 Uprate project is feasible.

 

ISSUE 25:       What system and jurisdictional amounts should the Commission approve as PEF’s final 2008 prudently incurred costs for the Crystal River Unit 3 Uprate project?

 

POSITION:    The 2008 prudently incurred total system costs are $65,137,303 for capitalized expenses and $180,076 in O&M expenses.  The resultant jurisdictional costs are $43,898,888 for capital expenses, $6,133,922 in carrying charges, and $166,588 in O&M expenses.

 

For purposes of the CCRC, the final 2008 NCRC trueup amount, is an under estimate of $64,444 in carrying costs plus an over estimate of $95,044 in O&M expenses plus an under estimate of $73,606 for base rates associated with a completed phase of the project.  The net amount of $43,006 should be included in setting the allowed 2010 NCRC recovery.

 

ISSUE 27:       What system and jurisdictional amounts should the Commission approve as PEF’s reasonably projected 2010 costs for the Crystal River Unit 3 Uprate project?

 

POSITION:    A reasonable projection of 2010 system Crystal River Unit 3 Uprate costs are $49,872,156 for capitalized expenses and $244,268 in O&M expenses.  The resultant jurisdictional costs, net of joint owner and other adjustments, are $58,380,739 for capital expenses, $5,325,702 in carrying charges, and $214,203 in O&M expenses.  The net amount of $5,539,905 should be included in setting the allowed 2010 NCRC recovery.

 

ISSUE 28:       What system and jurisdictional amounts should the Commission approve as PEF’s final 2006 and 2007 prudently incurred costs for the Levy Units 1 & 2 project as filed in Docket No. 080009-EI?

POSITION:    The 2006 and 2007 prudently incurred system Levy Units 1 & 2 project costs are $87,406,779 ($71,828,329 jurisdictional) in expenses and $707,867 ($547,473 jurisdictional) in O&M expenses.  The resultant jurisdictional carrying costs are $2,965,965.

 

Mr. Small has testified that there are three methodologies to allocate costs for the Lybass parcel, and that PEF has used one of those methodologies to make that allocation.  Mr. Small does not testify that one methodology is preferable to any other methodology.

 

The final true up of $19,780,695 was included in setting PEF’s 2009 NCRC recovery amount.  Consequently, the net true up amount of $0 should be used in setting the allowed 2010 NCRC recovery amount.

 

ISSUE 29:       What system and jurisdictional amounts should the Commission approve as PEF’s final 2008 prudently incurred costs for the Levy Units 1 & 2 project?

 

POSITION:    The prudently incurred 2008 system Levy Units 1 & 2 project costs are $155,306,978 ($138,609,648 jurisdictional) in expenses and $4,167,550 ($3,784,810 jurisdictional) in O&M expenses.  The associated 2008 jurisdictional carrying costs are $20,717,072.

 

                        For purposes of the CCRC, the final 2008 NCRC true up amount is an over estimate of $65,763,507 in expenses plus an under estimate of $2,305,178 in O&M expenses plus an over estimate of $2,317,719 in carrying costs.  The net amount of -$65,776,048 should be included in setting the allowed 2010 NCRC recovery.