DATE:	November 7, 2012
TO:	Office of Commission Clerk (Cole)
FROM:	Division of Accounting and Finance (Bulecza-Banks) Division of Economics (Garl) Division of Engineering (Graves) Office of the General Counsel (Lawson, Bennett, Young) Office of Industry Development and Market Analysis (Breman, Laux, Lewis)
RE:	Docket No. 120009-EI – Nuclear cost recovery clause.
AGENDA:	11/26/12 – Special Agenda – Post-Hearing – Participation is Limited to Commissioners and Staff.
COMMISSIONERS ASSIGNED:			All Commissioners
PREHEARING OFFICER:			Balbis
CRITICAL DATES:			None
SPECIAL INSTRUCTIONS:			None
FILE NAME AND LOCATION:			S:\PSC\AFD\WP\120009.RCM.DOC

 

Table of Contents

Issue       Description                                                                                                                     Page

               List of Acronyms and Abbreviations. 3

               Case Background. 4

1             Commission's Authority to Disallow Recovery of Carrying Costs (Lawson) 8

1A          Scope of "certain costs" Upon a Finding of Imprudence (Lawson) 11

3             Authority to Defer Prudence Determination Concerning CR3 (Lawson) 14

4             Whether Levy Project Activities Qualify as NCRC Activities (Graves, Laux) 16

5             Long-term Feasibility of Completing the Levy Project (Garl, Graves) 23

6             The Levy Project Estimated Total Cost (Garl, Graves) 39

7             The Levy Project Estimated Commercial Operation Dates (Garl) 41

8             Prudence of 2011 Levy Project Management (Laux) 43

9             Prudence of 2011 Levy Project Incurred Costs (Laux) 48

10           Reasonableness of Estimated 2012 Levy Project Costs (Laux) 51

11           Reasonableness of Projected 2013 Levy Project Costs (Laux) 55

13           Prudence of 2011 CR3 Uprate Project Management (Laux, Lawson) 59

14           2011 Prudence in the Absence of a Final CR3 Repair (Laux, Lawson) 67

15           Prudence of 2011 CR3 Uprate Project Incurred Costs (Laux, Lawson) 73

17           Reasonableness of Estimated 2012 CR3 Uprate Project Costs. 78

18           Reasonableness of Projected 2013 CR3 Uprate Project (Laux) 81

19           PEF's Net 2013 Recovery Amount (Laux) 84

20           Do FPL's Turkey Point 6 & 7 Activities Qualify Under Section 366.93, F.S. (Garl, Breman) 91

21           Long-term Feasibility of Completing the Turkey Point 6 & 7 Project (Garl) 98

22           Estimated Total Turkey Point 6 & 7 Project Costs (Garl) 111

23           Turkey Point 6 & 7 Estimated Commercial Operation Dates (Garl) 113

24           Prudence of 2011 Turkey Point 6 & 7 Project Management (Breman) 115

25           Prudence of 2011 Turkey Point 6 & 7 Incurred Costs (Breman) 120

26           Reasonableness of Estimated 2012 Turkey Point 6 & 7 Project Costs (Lewis) 124

27           Reasonableness of Projected 2013 Turkey Point 6 & 7 Project Costs (Lewis) 128

28           Long-term Feasibilit of Completing the FPL Uprate Project (Graves) 132

29           Prudence of 2011 FPL Uprate Project Management (Breman) 139

29A        Prudence of the Turkey Point Portion of the FPL Uprate Project (Breman) 145

30           Prudence of 2011 FPL Uprate Project Incurred Costs (Breman) 154

31           Reasonableness of Estimated 2012 FPL Uprate Project Costs (Lewis) 158

32           Reasonableness of Projected 2013 FPL Uprate Project Costs (Lewis) 162

33           FPL's Net 2013 Recovery Amount (Breman) 165

               Attachment A (Stipulation on Issues 2, 12 and 16) 167

               Attachment B (Partial Issue 29 Stipulation) 168

              

 

 

 Case Background

On March 1, 2012, Progress Energy Florida, Inc. (PEF) and Florida Power & Light Company (FPL) filed petitions seeking prudence review and final true-up of the 2011 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.).  PEF, on April 30, 2012, and FPL, on April 27, 2012, filed additional petitions seeking approval to recover estimated 2012 costs and projected 2013 costs.  Both companies requested to recover these costs in 2013 through the Capacity Cost Recovery Clause.

Each PEF petition addressed two nuclear projects.  The first PEF project is a multi-phased uprate of its existing nuclear generating plant, Crystal River Unit 3 (CR3 Uprate).  PEF obtained an affirmative need determination for the CR3 Uprate project in 2007 by Order No. PSC-07-0119-FOF-EI.[1]  The second PEF project is the construction of two new nuclear generating units, Levy Units 1 & 2 (Levy).  PEF obtained an affirmative need determination for the Levy project in 2008 by Order No. PSC-08-0518-FOF-EI.[2]

Each FPL petition also addressed two nuclear projects.  The first FPL project is composed of extended power uprate activities at its four existing nuclear generating plants, Turkey Point Units 3 & 4 and St. Lucie Units 1 & 2 (FPL Uprate).  FPL obtained an affirmative need determination for its extended power uprate project in 2008 by Order No. PSC-08-0021-FOF-EI.[3]  The second FPL project is the construction of two new nuclear generating units, Turkey Point Units 6 & 7.  FPL obtained an affirmative need determination for the two new nuclear generating plants in 2008 by Order No. PSC-08-0237-FOF-EI.[4]

Traditionally, all eligible prudently incurred power plant construction project costs are afforded the same regulatory accounting and ratemaking treatment.  That is, once the need for a project has been determined, the utility records 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 the amount in the account and the resulting dollar amount is then added to the account balance.  This process continues until completion of the project.

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

Under the traditional regulatory scheme, if the power plant project is terminated, rather than being placed in commercial service, the utility may petition for its prudently incurred CWIP account balance to become a regulatory asset that is amortized over a period of years.

In 2006, the Florida Legislature enacted Section 366.93, F.S. (creating an alternative cost recovery mechanism), to encourage utility investment in nuclear electric generation in Florida.  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 adoption of rules that provide for, among other things, annual reviews and cost recovery for nuclear plant construction through the existing capacity cost recovery clause.  Rule 25-6.0423, F.A.C., was adopted to implement Section 366.93, F.S.

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 utility may petition for cost recovery using the alternative mechanism.  Three types of prudently incurred costs are described in the rule.

•           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, issued October 12, 2008, the Commission approved stipulations among the parties to Docket No. 080009-EI, recommending that site selection costs be treated in the same manner as pre-construction costs.

            Pursuant to Section 366.93(2), F.S., and Rule 25-6.0423(5), F.A.C., all prudently incurred preconstruction costs, as well as the carrying charges on prudently incurred construction costs, are to be recovered directly through the Capacity Cost Recovery Clause.  The costs are recovered over the entire time the new power plant project is being developed.

            Pursuant to Section 366.93(4), F.S., and Rule 25-6.0423(7), F.A.C., a utility is allowed an increase in its base rate charges when a power plant is placed in commercial service.  The Statute describes the method for calculating the increase and the Rule provides further details on the calculations and the process.

In the event a utility elects not to complete or is precluded from completing the power plant project subject to the alternative cost recovery mechanism, Section 366.93(6), F.S., and Rule 25-6.0423(6), F.A.C., allow a utility to recover its prudently incurred costs, by amortizing them over at least 5 years, through the Capacity Cost Recovery Clause.

Rule 25-6.0423(5), F.A.C., sets forth the process by which the Commission conducts an annual hearing to determine the recoverable amount that will be included in the Capacity Cost Recovery Clause pursuant to Section 366.93, F.S.  This is the fifth year of the Nuclear Cost Recovery Clause (NCRC) roll-over docket.

Intervention in the 2012 Nuclear Cost Recovery Clause proceeding was granted to the following parties: the Office of Public Counsel (OPC), Southern Alliance for Clean Energy (SACE), Florida Industrial Power Users Group (FIPUG), White Springs Agricultural Chemicals Inc. d/b/a PCS Phosphate – White Springs (PCS Phosphate), the Federal Executive Agencies (FEA), and the Florida Retail Federation (FRF).  Testimony and associated exhibits were filed by PEF, FPL, OPC and Commission staff.

In 2012, PEF filed a Petition for Limited Proceeding to Approve a Stipulation and Settlement Agreement (Settlement Agreement) that was signed by OPC, FRF, FIPUG, FEA, and PCS Phosphate.  The Commission approved this Settlement Agreement by Order No. PSC-12-0104-FOF-EI.[5]  The Settlement Agreement was a comprehensive agreement addressing issues from multiple dockets including the Nuclear Cost Recovery Docket.  Requirements from this agreement that affect this docket include:

·        A requirement that PEF’s 2013-2017 NCRC annual recovery amounts, for the Levy project portion, reflected the use of a prescribed fixed $/kWh factor set by rate class.

·        For the Levy portion of PEF 2013-2017 NCRC recovery, a requirement that PEF is limited in its recovery of only those costs associated with certain Levy project activities, as identified in the agreement, and PEF may not file for any additional Levy project activity cost recovery unless otherwise agreed to by the parties.

·        A true up of Levy project cost recovery revenues to authorized actual project costs is required to take place in the final year of the Agreement.

·        During the Settlement period, PEF will not petition for in-service cost recovery related to any Uprate of CR3 prior to nine months following the commencement of commercial operation of CR3.

·        The parties to the agreement concurred that for the CR3 Uprate project, PEF is allowed to recover carrying costs and other NCRC recoverable costs through the NCRC consistent with section 366.93, Florida Statutes.

On August 14, 2012, PEF filed a motion requesting that the Commission defer its review of the long-term feasibility of completing the CR3 Uprate (Issue 12) and its determination of the reasonableness of PEF’s 2012 and 2013 CR3 Uprate expenditures and associated carrying costs (Issues 17 and 18, respectively) until the 2013 Nuclear Cost Recovery Clause proceedings.  PEF provided revised testimony and positions reflecting the exclusion of any CR3 Uprate project costs that may be incurred during 2012 and 2013.  PEF’s motion was unopposed and approved by the Commission as a preliminary matter on September 5, 2012.[6] 

The evidentiary hearing for the PEF portion of the 2012 Nuclear Cost Recovery Clause was held on September 10, 2012.  During the hearing, PEF, OPC, SACE, FIPUG, PCS Phosphate, FEA and FRF offered a stipulation that rendered moot other disputed matters (Issues 2, 12, and 16) associated with review of PEF’s 2012 and 2013 CR3 Uprate project in this proceeding because of the Commission’s approval of PEF's motion on September 5, 2012.[7]  The Commission approved the stipulation and a copy of it is shown in Attachment A of this recommendation.[8]

The FPL portion of the evidentiary hearing was held on September 5 and 11, 2012.  On September 11, 2012, during the FPL portion of the hearing, staff offered an unopposed partial stipulation with FPL of matters disputed in Issue 29 as shown in Attachment B.[9]  The Commission approved the partial stipulation.[10]

            All parties filed post-hearing briefs on October 1, 2012, addressing the remaining unresolved issues.  The Commission has jurisdiction over these matters pursuant to Section 366.93, F.S., as well as Sections 366.04, 366.041, 366.05, 366.06, and 366.07, F.S.

Discussion of Issues

Issue 1: 

 Does Section 366.93, Florida Statutes, authorize the Commission to disallow recovery of all, or a portion of, the carrying costs prescribed by Section 366.93(2)(b), Florida Statutes?

Recommendation: 

 The Commission may disallow the recovery of all costs that are imprudently incurred. (Lawson) 

Position of the Parties

PEF: 

  No, Section 366.93, Florida Statutes, does not authorize the Commission to disallow recovery of all, or a portion of, the carrying costs prescribed by Section 366.93(2)(b), Florida Statutes, on prudently incurred costs. If the Commission finds, based on a preponderance of the evidence adduced at a hearing before the Commission under Section 120.57, Florida Statutes, that certain nuclear power plant costs were imprudently incurred, then the Commission can disallow the carrying costs on those imprudent nuclear power plant costs. Absent that factual determination by the Commission, disallowance of the statutorily prescribed carrying costs is legally impermissible.

FPL: 

  Only to the extent the underlying costs to which the carrying costs apply are determined to be imprudent. If the underlying costs are determined to be prudent, Section 366.93, F.S., dictates the carrying costs that shall be recoverable by the utility. The statute does not provide the Commission discretion or authority to change the carrying costs by excluding an equity component, or in any other way, for any reason. In fact, doing so would be contrary to "encouraging investment and providing certainty" which is the stated intent of the relevant statutory provision.

 

OPC: 

  Yes.  Section 366.93, F.S., allows the Commission to disallow the recovery of any costs, including resulting carrying costs, which the Commission after hearing determines to be unreasonable or imprudently incurred.  Section 366.93(2)(b), F.S., does not authorize carrying charges, but merely specifies or prescribes how carrying charges on prudently incurred costs will be calculated once a utility satisfies the requirements of Section 366.93, F.S.  As a backstop to Section 366.93, F.S., under Chapter 366, F.S., the Commission has the inherent authority, power, and jurisdiction to disallow for recovery of any costs, including carrying costs, which the Commission determines to be unreasonable or imprudently incurred following a hearing.

SACE: 

  Agree with OPC.

FEA: 

  Agree with OPC.

FRF: 

  Yes. Although Section 366.93, Florida Statutes, neither authorizes nor prohibits the disallowance of carrying charges per se, the Commission must have the inherent authority to disallow carrying charges associated with unreasonable or imprudently incurred costs.

 

Staff Analysis:  Every party that has taken a position on this issue generally agrees that the Commission can disallow the recovery of any costs that are imprudently incurred as a result of a finding of imprudence, based on a preponderance of the evidence adduced at a hearing before the Commission pursuant to Section 120.57, F.S. (FPL BR 10; PEF BR 4-5; OPC BR 4-5; FRF BR 3; SACE BR 4; FRF BR 3)  Both of the utilities claim that this provision must be strictly interpreted in that it can only disallow costs after a factual determination of imprudence.  From their point of view, an incurred cost is either completely prudent or completely imprudent, and the Commission cannot selectively disallow portions of any costs such as changing “carrying costs by excluding a portion of the equity component.” (FPL BR 10-12; PEF BR 4)  Both utilities acknowledge that if the Commission finds that the carrying costs are imprudently incurred, then all of those carrying costs should be disallowed.  OPC argues that the Commission has an inherent authority to disallow any costs it deems unreasonable or imprudently incurred, but that the Commission can only do so after a factual finding of imprudence at a hearing before the Commission pursuant to Section 120.57, F.S. (OPC BR 5) OPC maintains that if the Commission determines that some expenditures were imprudently incurred, then the Commission may disallow the portion of the costs (and carrying costs) associated with the imprudent expenditures and allow the prudent expenditures.

 

            Turning to the text of the statute, Section 366.93(2), F.S., reads as follows:

 

Within 6 months after the enactment of this act, the commission shall 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, including new, expanded, or relocated electrical transmission lines and facilities that are necessary thereto, or of an integrated gasification combined cycle power plant. Such mechanisms shall be designed to promote utility investment in nuclear or integrated gasification combined cycle power plants and allow for the recovery in rates of all prudently incurred costs and shall include, but not be limited to:

 

 (b)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. . .

 

(emphasis added)

 

            The guide for statutory construction is legislative intent, which should be determined from the language of the statute.[11] Generally when a statute is clear and unambiguous, courts will not look behind the statute’s plain language for legislative intent, or resort to rules of statutory construction to ascertain intent insofar as this would constitute an abrogation of legislative power.[12] It is also acknowledged as a general rule that beyond any discussion of legislative intent, the courts should give the statute its plain and obvious meaning.[13] Therefore, courts should avoid interpretations that would render part of a statute meaningless. Another basic rule of statutory construction is that a literal interpretation of the language of the statute need not be given when to do so would lead to unreasonable conclusions or defeat legislative intent.[14] Furthermore, according to Black’s Law Dictionary defines the word “shall” as “has a duty to; more broadly is required to.”  The definition found in that dictionary also states that, “this (definition) is the mandatory sense that drafters typically intend and that the courts typically uphold.”[15]

 

            Based on these rules of construction staff believes that the legislature’s use of the word “shall” as a predicate to the phrase “allow for the recovery in rates of all prudently incurred costs and shall include . . .” indicates the legislature created a mandatory obligation for the Commission to allow the recovery of all prudently incurred costs.  The use of the word “all” suggests the legislature intended the complete inclusion of any prudent costs including carrying costs.  This is bolstered by Section 403.519(4)(e), F.S., which states “costs incurred prior to commercial operation . . . shall not be subject to challenge unless and only to the extent the Commission finds, based on a preponderance of the evidence adduced at a hearing before the commission under s. 120.57, that certain costs were imprudently incurred.”  If costs are only prudent or imprudent, and if the legislative intent provides for the recovery of all prudent costs, then the statute does not appear to provide for the partial disallowance of only a portion of any prudent cost.

 

            Staff believes the legislative mandate as presented in the statute is clear and unambiguous and should be given its plain meaning. Therefore, staff recommends that the Commission may disallow the recovery of all costs that are imprudently incurred.  This includes the carrying costs prescribed by Section 366.93(2)(b), F.S., should the Commission find those costs were imprudently incurred.

 

 

 

 

Issue 1A: 

 Does the term "certain costs" in Section 403.519(4)(e), Florida Statutes, include costs caused by an imprudent decision or action that are incurred in years subsequent to the year of the imprudent decision or action?

Recommendation: 

 “Certain costs” can include costs caused by an imprudent decision or action that are incurred in years subsequent to the year of the imprudent decision or action.  (Lawson)

Position of the Parties

PEF: 

 Yes.  Pursuant to Section 403.519(4)(e), Florida Statutes, “certain costs” are those costs that “shall not be subject to challenge unless and only to the extent the commission finds, based on a preponderance of the evidence adduced at a hearing before the commission under s. 120.57, that certain costs were imprudently incurred.”  Thus, if the Commission finds that a certain decision or action was imprudent, “certain costs” can include costs that are actually and proximately casually-related to that imprudent decision or action.

FPL: 

 Pursuant to Section 403.519(4)(e), F.S., based on a preponderance of the evidence, the Commission must first find that the Company imprudently incurred certain costs (i.e., that a particular act or decision was imprudent and that act or decision caused the company to incur certain costs).  If the Commission finds that an act or decision was imprudent, and further finds that the imprudence caused costs to be incurred, then costs incurred in a year subsequent to the imprudent act or decision – if in fact caused by the imprudent act or decision – would be “certain costs” within the meaning of Section 403.519(4)(e), F.S.

OPC: 

 Yes.  While in Sections 366.93 and 403.519(4)(e), F.S., the Legislature intended to encourage the development of nuclear power, the Legislature also intended to empower the Commission to protect ratepayers from bearing imprudently incurred costs of any such development.  While the evidentiary and procedural standards of Section 403.519(4)(e) must be met, to give effect to the Legislature’s intent the term “certain costs” must pertain to those excessive costs that are incurred as a result of the imprudence, regardless of the period in which they are incurred.

Staff Analysis: 

 Section 403.519(4)(e), F.S., reads as follows:

 

After a petition for determination of need for a nuclear or integrated gasification combined cycle power plant has been granted, the right of a utility to recover any costs incurred prior to commercial operation, including, but not limited to, costs associated with the siting, design, licensing, or construction of the plant and new, expanded, or relocated electrical transmission lines or facilities of any size that are necessary to serve the nuclear power plant, shall not be subject to challenge unless and only to the extent the commission finds, based on a preponderance of the evidence adduced at a hearing before the commission under s. 120.57, that certain costs were imprudently incurred. Proceeding with the construction of the nuclear or integrated gasification combined cycle power plant following an order by the commission approving the need for the nuclear or integrated gasification combined cycle power plant under this act shall not constitute or be evidence of imprudence.  Imprudence shall not include any cost increases due to events beyond the utility’s control. Further, a utility’s right to recover costs associated with a nuclear or integrated gasification combined cycle power plant may not be raised in any other forum or in the review of proceedings in such other forum.  Costs incurred prior to commercial operation shall be recovered pursuant to chapter 366.

 

            The guide for statutory construction is legislative intent, which must be determined primarily from the language of the statute.[16] Generally when a statute is clear and unambiguous, courts will not look behind the statute’s plain language for legislative intent, or resort to rules of statutory construction to ascertain intent insofar as this would constitute an abrogation of legislative power.[17] It is also acknowledged as a general rule that beyond any discussion of legislative intent the courts should give the statute its plain and obvious meaning.[18] Therefore, courts should avoid interpretations that would render part of a statute meaningless.  Another basic rule of statutory construction is that a literal interpretation of the language of the statute need not be given when to do so would lead to unreasonable conclusions or defeat legislative intent.[19]  

 

            Based on these rules of construction, the meaning of certain costs may be derived from a plain reading of Section 403.519(4)(e) that states “. . . the rights of a utility to recover any costs incurred prior to commercial operation,…shall not be subject to challenge unless and only to the extent the Commission finds, based on a preponderance of the evidence adduced at a hearing before the Commission under s.120.57, that certain costs were imprudently incurred.” (emphasis added) In short, “certain costs” under this statutory provision can include costs that were imprudently incurred.

 

            This basic understanding of “certain costs” is generally agreed upon by OPC as well as both PEF and FPL (FPL BR 13; PEF BR 8; OPC BR 5), although there is some variance as to how the definition of “certain costs” would apply to “costs caused by an imprudent decision or action that are incurred in years subsequent to the year of the imprudent decision or action.”  Both FPL and PEF agree that since the Commission may find, based on a preponderance of evidence at a hearing, that if a given action or decision is found imprudent, it follows that costs incurred subsequent to the imprudent act or decision would also be imprudent, provided the subsequent act was caused by the earlier imprudent act or decision.  (FPL BR 13; PEF BR 8)  FPL also makes the distinction that future year costs not yet reviewed for prudence cannot be found imprudently incurred in advance of the year they are subject to prudence review. (FPL BR 13)

 

            OPC takes a similar position in that it also agrees that “certain costs must pertain to those excessive costs that are incurred as a result of the imprudence, regardless of the period in which they are incurred.” (OPC BR 5)  OPC’s basis for its argument is that the when the legislature drafted legislation to encourage development of nuclear power in Florida, it also created a countervailing power to protect ratepayers from bearing imprudently incurred costs which may arise from such development. (OPC BR 5)  In its discussion of this issue, OPC applies this line of reasoning to the Turkey Point EPU; however, that discussion is covered more thoroughly in the analysis of Issue 29A.

 

            Turning to the basic legal issue, Section 403.519(4)(e), F.S., indicates that “certain costs” can include costs caused by an imprudent decision or action.  Once an action or decision is found imprudent, it logically follows that those costs incurred by continuing in an imprudent manner or continuing to follow an imprudent decision would also be imprudent costs.  Since findings of prudence are not revisited and stand in perpetuity once they are final,[20] there is no reason for a utility to expect it can recover costs incurred in subsequent years by continuing in an act or decision previously found to be imprudent.  Therefore, staff believes the phrase “certain costs” should include costs caused by an imprudent decision or action that are incurred in years subsequent to the year of the imprudent decision or action.  Staff would note the caveat, as stated by the utilities and OPC, is that the subsequent act must be caused by or directly flow from the prior act in order to find an act or decision imprudent simply by virtue of its association with an earlier imprudent act or decision. (FPL BR 13; PEF BR 8; OPC BR 5)  

 

            Therefore, “certain costs” as described in Section 403.519(4)(e), F.S., can include costs caused by an imprudent decision or action that are incurred in years subsequent to the year of the imprudent decision or action.

 

 

 

 

Issue 3: 

 Does the Commission have the authority to defer the determination of prudence for the Crystal River Unit 3 Uprate project in 2012 and 2013 due to lack of a final decision to repair or retire Crystal River Unit 3?  If yes, what amount should the Commission disallow, if any?

Recommendation: 

 Staff recommends that Issues 13, 14 and 15 involving the prudence of PEF’s 2011 CR3 costs are ripe for a decision by the Commission. Staff is recommending that there is sufficient evidence in the record to make a prudence determination for the Crystal River Unit 3 Uprate project for 2011.  If the Commission approves staff’s recommendation in Issues 13, 14 and 15, this Issue will be moot.  (Lawson)

Position of the Parties

PEF: 

 No.  The Commission does not have the legal authority to unilaterally defer a determination of prudence for the CR3 Uprate project 2011 costs pursuant to Section 366.93 and Rule 25-6.0423.  The annual prudence determination is mandatory and the Commission is not authorized to defer this determination absent a request or stipulation by a utility subject to Rule 25-6.0423.  Moreover, there is no reason to defer the prudence determination.  The record regarding PEF’s 2011 CR3 Uprate project decisions and costs is complete.  There is no additional information bearing on historical 2011 decisions and costs that the Commission needs to determine the prudence of PEF’s 2011 costs.  The assertion that future, unrelated information is necessary to evaluate historical 2011 decisions and costs is incorrect.

FPL: 

 Not unilaterally.  Pursuant to Rule 25-6.0423, Fla. Admin. Code, a utility is entitled to a prudence determination on actual, prior year costs and a reasonableness determination on current year and projected year costs.  This process is a key component of the nuclear cost recovery framework that is intended to encourage nuclear investment.  Absent agreement or waiver by the utility, the Commission does not have the authority to defer its requisite annual prudence and reasonableness findings.

OPC: 

 Yes. Section 366.93, F.S., is silent on whether the Commission has authority to defer determinations of prudence and reasonableness for the CR3 uprate project until a final decision to repair or retire has been implemented.  Such a factual situation was not contemplated by the Legislature when the NCRC statute was enacted.  Thus, the Commission can and should rely upon its inherent power and ratemaking jurisdiction under Chapter 366, F.S., to defer determinations of prudence and reasonableness of 2011 expenditures.  Moreover, the 2011 and 2012 deferrals of reasonableness and prudence requested by PEF and granted by the Commission are further evidence of the Commission’s general authority to defer such determinations.

SACE: 

 Agree with OPC.

FIPUG: 

 Yes, the Commission has authority to defer issues related to the CR3 uprate.  Given the unique circumstances of this, it should do so.

FEA: 

 Agree with FIPUG.

FRF: 

 Yes.  The Commission has the authority to defer its determinations of prudence and reasonableness regarding the CR3 EPU project, and the Commission should defer its determinations until after the repair vs. retire decision is made, in order to give PEF proper incentives to scrutinize EPU costs.

Staff Analysis: 

 In Issues 13, 14 and 15, staff recommends that the Commission find that the costs incurred by PEF in 2011 with respect to the CR3 Uprate project were prudent based on the analysis of those issues.  When making a prudence finding, the Commission determines what a reasonable utility manager would have done in light of the conditions or circumstances which were known or should have been known at the time the decision was made.[21]  It is staff’s recommendation in those issues that the Commission has sufficient evidence in the record to understand what information PEF knew or should have known in 2011, when it made decisions or undertook actions to incur costs.  Accordingly, staff is recommending in Issues 13, 14 and 15 that the Commission has sufficient information to make a prudence determination.  If the Commission votes to approve staff’s recommendations in these issues, then this issue is moot.

 

 

Issue 4: 

 Do PEF's activities since January 2011 related to Levy Units 1 & 2 qualify as "siting, design, licensing, and construction" of a nuclear power plant as contemplated by Section 366.93, F.S.?

Recommendation: 

 Yes.  Staff recommends the Commission find PEF’s activities since January 2011 related to Levy project qualify as siting, design, licensing, and construction of a nuclear power plant as contemplated by Section 366.93, F.S.  (Graves, Laux)

Position of the Parties

PEF: 

 Yes.  This same issue was included in prior NCRC Dockets.  In both prior NCRC Dockets the Commission found that PEF’s activities qualified under the statute.  See Order No. PSC-11-0547-FOF-EI and Order No. PSC-11-0095-FOF-EI.  The undisputed evidence shows that PEF’s LNP activities since January 2011 are similar to the Company’s prior LNP activities and they likewise qualify as the “siting, design, licensing, and construction” of a nuclear power plant under Section 366.93, Florida Statutes.

OPC: 

 Issues 4 through 11 are governed by the settlement approved by Order No. PSC-12-0104-FOF-EI, issued March 8, 2012, in Docket No. 120022-EI.  The settlement does not relieve PEF from prudently managing the Levy Nuclear Project (LNP) or for complying with any requirements of Section 366.93, Florida Statutes (F.S.), or Rule 25-6.0423, Florida Administrative Code (F.A.C.).  Any amounts to be approved for recovery for the LNP are specified in the settlement. 

SACE: 

 No.  PEF’s activities since January 2011 fail to demonstrate the requisite intent to build the LNP.  PEF has further pushed out projected operation dates for the LNP and remains focused solely on obtaining a COL from the NRC to create the option to build the LNP should it become feasible in the future.  Section 366.93, Fla. Stat. and Commission precedent do not contemplate such an approach.  As a result, PEF is not engaged in the “siting, design, licensing, and construction” of the LNP, and is not eligible for recovery of costs related to the LNP.

FIPUG: 

 So long as PEF’s filing is consistent with the parties’ settlement, FIPUG supports the company’s position.

PCS Phosphate: 

 Consistent with the terms of the settlement agreement, PCS Phosphate does not challenge Progress Energy Florida’s (“Progress”) proposed Levy component of nuclear cost recovery for 2013.

FEA: 

 Agree with FIPUG.

FRF: 

 The Settlement Agreement executed by PEF and several Consumer Parties provides that the Consumer Parties do not oppose PEF obtaining the Combined Operating License for the LNP and PEF’s recovery of the costs of doing so.

Staff Analysis: 

 This issue addresses whether PEF’s activities, since January 2011, related to the Levy project qualify as siting, design, licensing and construction of a nuclear power plant as contemplated by Section 366.93, F.S.

PARTIES’ ARGUMENTS

In its post-hearing brief, PEF noted that similar issues were included for Commission consideration in prior nuclear cost recovery clause dockets, namely Docket Nos. 100009-EI and 110009-EI.  In both of these dockets the Commission found that PEF’s Levy project activities qualified for recovery under the statute in question.  PEF argued that its Levy activities, since January 2011, were similar to the types of activities reviewed in these prior dockets and therefore should equally qualify under the statute. (PEF BR 14-15)

OPC adopted its prehearing position that the settlement agreement approved by the Commission by Order No. PSC-12-0104-FOF-EI in Docket No. 120022-EI does not relieve PEF from demonstrating to the Commission that PEF’s activities since January 2011 related to the Levy Project qualify as siting, design, licensing, and construction of a nuclear power plant as contemplated by Section 366.93, F.S. (OPC BR 2)  PCS Phosphate and FRF joined OPC in this position. (PCS Phosphate BR 1; FRF BR 4)

FIPUG and FEA supported PEF’s position as long as PEF’s request was consistent with the parties’ approved settlement agreement. (FIPUG BR 1; FEA BR 3)

SACE stated that PEF’s activities since January 2011 demonstrate that PEF intends to do nothing more than obtain a Combined Operating License (COL) for the Levy project. (SACE BR 2, 5)  SACE argued that PEF’s activities plainly demonstrate that, due to increasing risk and uncertainty surrounding the development of new nuclear generation, PEF continues to employ an “option creation” approach where the only intent on the part of the utility is to create the option to construct by attempting to obtain the necessary licenses and approvals to operate the proposed new nuclear project, should it become feasible at some point in the future.  This option creation approach does not satisfy the intent to build requirement, as the statute and the Commission’s interpretation of the same, doesn’t contemplate such an approach.  (SACE BR 2-3)  As a result, SACE argued that PEF is not engaged in the “siting, design, licensing, and construction” of Levy Units 1 & 2, nor has it demonstrated the requisite intent to construct the proposed new nuclear projects.  Therefore, SACE asserted, the Commission should protect PEF ratepayers and find that PEF is not eligible for recovery of costs related to the Levy project under Section 366.93, F.S. (SACE BR 2-7)

ANALYSIS

Staff notes that with the exception of SACE, none of the intervenors offered testimony at hearing or addressed the Levy project activities in their briefs.  SACE’s discussion of Levy project activities is directed at the question of demonstration of intent to build and not the prudence of any actual Levy project activities.

Section 366.93, F.S., provides for cost recovery for utilities engaged in the siting, design, licensing, and construction of new nuclear power plants.  Within Order No. PSC-11-0095-FOF-EI, staff notes that the Commission interpreted and defined this statutory provision to include the building of new nuclear power plants and the modification of existing nuclear power plants.[22]  As discussed in this order, the main question to review when analyzing this issue is whether a utility must engage in the siting, design, licensing, and construction of nuclear power plant activities simultaneously in order to meet the statutory requirements of Section 366.93, F.S.

Under Section 366.93(1)(a), F.S., “cost” include, but is not limited to, all expenses related to or resulting from the activities of siting, licensing, design, construction, or operation of the nuclear power plant.  Furthermore, Section 366.93(1)(f), F.S., defines “preconstruction” as that period of time after a site has been selected through and including the date the utility completes site clearing work.  Rule 25-6.0423(2)(h), F.A.C., which implements Section 366.93(1)(f), F.S., provides:

Site selection costs and pre-construction costs include, but are not limited to: any and all costs associated with preparing, reviewing and defending a Combined Operating License (COL) application for a nuclear power plant; costs associated with site and technology selection; costs of engineering, designing, and permitting the nuclear or integrated gasification combined cycle power plant; costs of clearing, grading, and excavation; and costs of on-site construction facilities (i.e., construction offices, warehouses, etc.).

In reviewing this issue, staff took guidance from Order No. PSC-11-0095-FOF-EI.  At page 9 of this order, staff notes that the Commission found that a utility need not engage in the siting, design, licensing, and construction activities of a nuclear power plant simultaneously in order to meet the statutory requirements under Section 366.93, F.S.  As noted on page 11 of this order, the utility, however, must demonstrate through its actions an intent to build the nuclear power plant for which it seeks advance recovery of costs to be in compliance with Section 366.93, F.S.

In support of its position, PEF witnesses Garrett and O’Cain (TR 231-234, 247-260) described Levy project activities PEF engaged in during 2011.  PEF witness Elnitsky described the Levy project activities PEF is currently engaged in and those that are planned for 2013. (TR 408-409, 417)

Witness Garrett stated that in 2011, PEF was engaged in project activities concerning licensing application and support, engineering and design, power block engineering, real estate acquisition, and project management support. (TR 231-234).

Witness O’Cain stated that PEF’s:

2011 LNP costs were incurred in connection with licensing application activities to support the Levy Combined Operating License Application (“COLA”) to the Nuclear Regulatory Commission (“NRC”), engineering activities in support of the COLA, and activities under PEF’s LNP Engineering, Procurement and Construction (“EPC”) contract with Westinghouse and Shaw, Stone and Webster (the “Consortium”).  In addition, costs were incurred for Levy Transmission strategic land acquisitions.  PEF took appropriate steps to ensure that the 2011 costs were reasonable and prudent and that all of these costs were necessary to the LNP.

(TR 247)

As to 2012 and 2013 activities, witness Elnitsky testified:

The company will continue work necessary to obtain the LNP COL from the NRC in 2012 and 2013. This work includes licensing and engineering work to address the NRC Fukushima Near Term Task Force recommendations.  It also includes the licensing and engineering work to support the Company during the contested and mandatory hearing process.

Licensing and engineering work is also necessary in 2012 and 2013 to continue to support environmental permitting and implementation of conditions of certification (CoC).  The environmental permitting work includes work on the USACE Section 404 permit for the LNP.  Environmental work scope will include preconstruction environmental monitoring, wetland mitigation plan implementation, aquifer performance testing, and other site CoC.

The Company further continues its participation in industry groups to advance the AP1000 design and operation.  This includes the AP1000 owners group, the NEI New Plant Working Group, NEI Nuclear Plant Oversight Committee and INPO New Plant Deployment Executive Working Group.

PEF will continue to provide project management for all of these tasks and activities for the LNP in 2012 and 2013.

(TR 408-410)

All of this work is reasonable and necessary in 2012 and 2013 to move the LNP forward on a schedule with the expected in-service dates for Levy Units 1 and 2 in 2024 and 2025, respectively.  PEF currently intends to build the LNP and to build the LNP with the current 2024 and 2025 estimated in-service dates for Levy Units 1 and 2.  All of this work in 2012 and 2013 is reasonable and necessary to meet that schedule.

(TR 417)

Concerning the question of PEF’s actual intent to build, witness Lyash, PEF’s Executive Vice-President of Energy Supply, responded during cross-examination:

Q  . . . Wouldn’t it be a more honest assessment of the company’s intent to say that the company, Duke Progress, intends to get a COL for the LNP and then reassess the increased risk and uncertainty that we talked about with Mr. Elnitsky that you discussed in your testimony and make a decision at that point in time of whether or not to build the LNP?

A  No, I wouldn’t agree with that characterization.

Q  How so?

A  Well, we’ve made a decision to build Levy and that decision was made at the outset when we filed the Certificate of Need.  You know, that was the passing of our judgment on the item under consideration at the time, and the Commission weighed in on that, as well.  So what has transpired as we’ve moved through the project is a prudent management approach that evaluates the project, itself, the landscape, emergent items that either were not or could not have been anticipated to reaffirm that that decision should stand either unaltered or should be adjusted in some way, given the circumstance.  So I don’t consider Levy an option, at all.  I consider Levy a decision that’s been made.

(TR 531)

Reviewing the record, staff believes that PEF’s actions since 2011 support the requirement of demonstrating its intent to build.  From this review, staff has established that the Levy project has and continues to be approved and funded by PEF’s Senior Management Committee and Board of Directors as required by PEF’s internal policy and governing procedures. (TR 372, 401-402, 436)  The project is active, supported by a required integrated project plan, covered by a construction contract, and currently under NRC licensing application review. (TR 389-391, 404, 418-419, 425, 429) 

Staff agrees with the statement PEF offered in its brief that “. . . intervenors presented or elicited any evidence that PEF was not incurring costs for these activities [siting, design, licensing, or construction] for the Levy project.” (PEF BR 16)

SACE argued that by entering into the Settlement Agreement (approved by Order No. PSC-12-0104-FOF-EI in Docket No. 120022-EI) PEF demonstrated that it does not have the requisite intent to build the Levy project.  SACE argued that since, under the agreement, PEF would be allowed to recover the costs of canceling the project, entering into the agreement reflects PEF’s intent concerning the Levy project. (SACE BR 6)

Staff does not agree with either the premise or the conclusion reached by SACE concerning PEF’s involvement with the settlement agreement.  Staff notes that even if PEF’s “intent” was to terminate the project, as argued by SACE, Section 366.93(6), F.S., allows for recovery of all prudent preconstruction and construction costs in the event the utility elects not to complete or is precluded from completing the construction of the nuclear power plant.  Therefore, PEF did not need to enter into a settlement agreement to recover these costs.  Further, SACE’s argument that one can imply intent to build from PEF’s action of entering into a settlement agreement was tested and addressed by PEF during SACE’s cross-examination of witness Elnitsky:

Q  This settlement agreement kind of strikes me as kind of an exit strategy.  Do you agree with that?

A  No, I do not.

Q  Why - - how so?

A  I think it provides flexibility, as I previously described, to go a couple of paths, either to go faster, stay on the current track, or to cancel if that’s what ultimately in the best interest of the customers.  It provides a structure to allow us to do that here over the interim period.

Q  So cancellation of the project is certainly a possibility?

A  We continue to evaluate each year as part of our feasibility analysis and part of our review of the project whether we, it is in the best interest of the customers and the shareholders to move forward with the project, yes.

(TR 444)

In addition, SACE had the following exchange with witness Elnitsky:

Q  Mr. Elnitsky, I asked you before if you considered this an exit strategy.  You said no.  Maybe it’s more accurately characterized as kind of a hedging strategy; would you agree with that?

A  No.

Q  Why not?

A  I think I, as I previously described, I think it provides for a couple of different paths for the project, and I think it is consistent with the risks that the company faces as well as the customers face in moving forward with the project.  I think it struck an even balance, as I described in my testimony.

Q  And, regardless of which one of those paths the company chooses, it’s assured of recovery of the costs through this agreement; correct?

A  Provided that our actions are reasonable and prudent.

(TR 447-448)

Staff believes that this exchange illustrates that a unique understanding concerning PEF’s intent to build cannot be derived from PEF’s action of entering into the settlement agreement. 

As to OPC, PCS Phosphate, FRF, FIPUG and FEA position, staff notes that none of these parties took issue with or argued in their post-hearing brief that the Levy project activities for which PEF is requesting cost recovery are inconsistent with the parties’ approved settlement agreement. (OPC BR 2; PCS Phosphate BR 1; FRF BR 1, 4; FIPUG BR 1, 3; FEA BR 3)

From our review, staff believes the Levy project activities since January 2011 are similar and consistent with those the Commission has reviewed in prior proceedings and found to be appropriate for nuclear cost recovery.[23]  Staff also notes that PEF's 2011, 2012 and projected 2013 activities for the Levy project qualify as preconstruction activities as defined in Section 366.93(1)(f), F.S., and as interpreted by Rule 25-6.0423(2)(h), F.A.C., since PEF has not entered into the actual construction phase of the project or announced termination of the project.  Staff believes that, taken as a whole, all of the noted activities are more consistent with a demonstration of intent to build as opposed to termination of the Levy project.

Given the guidance afforded by the Commission in Order No. PSC-11-0095-FOF-EI, and the preponderance of the evidence in the record, staff believes that PEF has satisfied the requirement to demonstrate intent to build the Levy project for which it seeks recovery of costs in this docket.

CONCLUSION

Staff recommends the Commission find PEF’s activities since January 2011 related to Levy project qualify as siting, design, licensing, and construction of a nuclear power plant as contemplated by Section 366.93, F.S.

 

Issue 5: 

 Should the Commission approve what PEF has submitted as its 2012 annual detailed analysis of the long-term feasibility of completing the Levy Units 1 & 2 project, as provided for in Rule 25-6.0423, F.A.C.?  If not, what action, if any, should the Commission take?

Recommendation: 

 Yes.  PEF presented evidence that examined the economic, regulatory, and technical factors impacting the long-term feasibility of the Levy Project that demonstrated the project remains feasible.  In addition, PEF provided updated fuel, environmental, and project costs forecasts as requested by the Commission.    (Garl)

Position of the Parties

PEF: 

 Yes, the Commission should approve PEF’s annual analysis of the long-term feasibility of completing the Levy Project.  With the testimony and exhibits of Mr. Elnitsky, PEF submitted a detailed analysis setting forth the long-term feasibility of completing the Levy Project, consistent with Rule      25-6.0423 and the analysis this Commission approved in Docket Nos. 090009-EI, 100009-EI, and 110009-EI.  If the Commission does not approve PEF’s submission based on perceived technical deficiencies, it should identify the deficiencies and permit PEF to re-file with additional information.  If the Commission finds the Levy Project is not feasible on substantive grounds, this would preclude PEF from completing the Levy Project and the Commission should award PEF its prudent 2011, reasonable 2012, and reasonable project exit costs pursuant to Section 366.93(6).

OPC: 

 Issues 4 through 11 are governed by the settlement approved by Order No. PSC-12-0104-FOF-EI, issued March 8, 2012, in Docket No. 120022-EI.  The settlement does not relieve PEF from prudently managing the Levy Nuclear Project (Levy Project) or for complying with any requirements of Section 366.93, Florida Statutes (F.S.), or Rule 25-6.0423, Florida Administrative Code (F.A.C.).  Any amounts to be approved for recovery for the Levy Project are specified in the settlement.

SACE: 

 No.  PEF has failed to complete and properly analyze a realistic feasibility analysis which properly takes into account all of the factors that have resulted in the great uncertainty and risk adversely impacting new nuclear generation generally, and the Levy Project in particular, including, but not limited to:  historically low natural gas prices, lack of a cost of carbon; continued depressed economic conditions; and the true impact of efficiency and renewables.  The Commission should deny cost recovery for PEF’s 2012 and 2013 costs related to the Levy Project.

FIPUG: 

 So long as PEF’s filings is consistent with the parties’ settlement, FIPUG supports the company’s position.

PCS Phosphate: 

 Consistent with the terms of the settlement agreement, PCS Phosphate does not challenge Progress Energy Florida’s (“Progress”) proposed Levy component of nuclear cost recovery for 2013.

FEA: 

 Agree with FIPUG.

FRF: 

 The Settlement Agreement executed by PEF and several Consumer Parties provides that the Consumer Parties do not oppose PEF obtaining the Combined Operating License for the Levy Project and PEF’s recovery of the costs of doing so.  PEF must still demonstrate the long-term feasibility of the Levy Project.

Staff Analysis:  This issue addresses PEF's detailed long-term feasibility analysis of completing the Levy project as required by Rule 25-6.0423, F.A.C., and Order No. PSC-08-0518-FOF-EI[24] from the Levy project Need Determination proceeding.

PARTIES’ ARGUMENTS

PEF

PEF introduced in evidence its detailed analysis setting forth the updated long-term feasibility of completing the Levy project, consistent with Commission Rule 25-6.0423, F.A.C., orders, and prior PEF Levy project feasibility analyses approved by the Commission. (TR 373-408; EXH 11)  PEF argued that no intervenor introduced or elicited any evidence challenging PEF’s current Levy project feasibility analysis.  PEF asserted its analysis conclusively demonstrates that the Levy project is feasible.

In sum, PEF stated that its analysis demonstrated that the Levy project is qualitatively and quantitatively feasible.  The Levy project is feasible from a regulatory perspective. (TR 373-400)  The NRC approved the AP1000 design, issued Combined Operating Licenses (COL) for the Vogtle and Summer AP1000 plants, and issued the Levy project final environmental impact statement.  Further, the NRC will soon issue the Levy project final safety evaluation report and is preceding with the Levy project Combined Operating License Application (COLA) review. (TR 390-391, 396-400, 525-526)  The expected Levy Project COL has been delayed by recent Court of Appeals and NRC decisions with respect to the NRC Waste Confidence Rule; however, the COL is expected in 2014. (TR 362, 427-428, 437-438, 493, 512)  All licenses and permits necessary to operate the Levy project can be obtained. (TR 389-399)  PEF asserted the Levy project is also technically feasible.  Similar construction of AP1000 nuclear reactors is proceeding in China and at the Vogtle and Summer sites. (TR 396-400, 485, 525-526)  There is no reason to believe the AP1000 nuclear reactors cannot be built at the Levy site.  The near term enterprise risks have increased, leading to PEF’s decision to extend the current partial suspension and place the Levy units in service in 2024 and 2025, but there is no reason to expect these increased enterprise risks to continue for the length of time to develop the Levy project and operate the Levy nuclear units. (TR 400-403, 501-502, 509-510) 

PEF asserted that the Levy project continues to be economically feasible.  The updated cumulative present value revenue requirements (CPVRR) economic analysis includes updated, lower natural gas fuel forecasts, PEF’s updated total Levy project cost estimate based on the 2024 and 2025 Levy unit in-service dates, and demonstrates that the Levy Project is economically feasible. (TR 404-408; EXH 11)  This CPVRR economic analysis demonstrates that the Levy project is more cost-effective than the all natural gas generation resource plan. (TR 405-406, EXH 11)  As a result, PEF has demonstrated that the Levy project is economically beneficial to PEF’s customers over the 60-year life of the Levy nuclear units. (TR 380-384, 405-407)

PEF asserted that the Levy project fulfills the Florida legislative objectives embodied in Section 403.519(4), F.S., and the Commission’s need determination for the Levy project.  The Levy project provides fuel portfolio diversity to the State and PEF, reduces reliance on fossil fuels for energy production, provides carbon free energy generation, and provides base load capacity with a low cost fuel source. (TR 478-479, 499, 515)  These long-term benefits further justify completion of the Levy project. (TR 478-479, 497-499, 520-521) 

PEF observed that no intervenor introduced any evidence and no witness testified that the Levy project is not feasible.  PEF asserted that SACE will argue, however, that current, historically low natural gas prices, the present lack of carbon costs on all fossil fuel energy generation as a result of greenhouse gas regulation, and low demand render new nuclear generation economically infeasible. (TR 450-454)  SACE will further assert that other utilities have recognized that nuclear generation is not cost-effective and cancelled or abandoned new nuclear generation. (TR 455-459; EXH 117, 126)  SACE’s arguments mischaracterize PEF’s testimony and are unsupported by any evidence that the Levy project is not cost-effective over the 60-year operational life of the Levy nuclear units, which is the appropriate measure of economic feasibility under the analyses previously approved by this Commission.[25] 

PEF’s witnesses Elnitsky and Lyash agreed that, at the present time, natural gas prices are at historical lows at levels indicative of the low fuel forecast prices in PEF’s Levy project CPVRR analysis. (TR 454-455, 451, 520-521)  That does not mean, however, that the low fuel forecast is the appropriate forecast to use in the CPVRR analysis over the 60-year life of the Levy nuclear units.  Rather, as witnesses Elnitsky and Lyash made clear, current, historically low natural gas prices result from an imbalance between supply and demand that logically, and as a matter of fundamental economic principles, cannot be expected to continue over the long-term, expected operational life of the Levy nuclear units. (TR 451, 454)  To illustrate this point, witness Elnitsky testified that if you try to guarantee current, low natural gas prices for the next 20 years in the market “they’ll laugh at you,” and guarantee a 20-year gas supply only at a price roughly five times the current market price. (TR 459, 464)  The evidence demonstrates that PEF appropriately accounted for this temporary imbalance in the natural gas market in its evaluation of natural gas prices in its CPVRR analysis. (TR 478-479)  No evidence was presented and no one testified that PEF’s evaluation of natural gas prices in its fuel forecasts in the Levy project CPVRR analysis was erroneous. (TR 462) 

Likewise, PEF contended that current greenhouse gas legislative and regulatory circumstances are not indicative of future greenhouse gas legislation or regulation.  The lack of greenhouse gas legislation or regulation imposing a carbon cost on all fossil fuel generation at the present time does not mean that there will never be any carbon cost on fossil fuel generation over the 60-year life of the Levy Units. (TR 380-384, 520-521)  PEF presented evidence that the environmental regulation of fossil fuels is continuing, not lessening, and that greenhouse gas legislation or regulation imposing some cost on carbon is inevitable.  The only uncertainty is what form that regulation will take and when it will occur. (TR 380-384, 536-537)  This evidence was undisputed.

Finally, PEF witness Elnitsky agreed that the Levy project was not needed today to meet demand, but testified that the Levy project was needed to meet customer long-term demand for reliable base load capacity. (TR 448)  Again, by focusing on present circumstances, PEF believed SACE ignored the fundamental nature of the Levy project and the determination of the cost-effectiveness of the Levy units.  The Levy project cannot be built and is not being built to serve the customers’ immediate needs for electrical power.  Rather, the Levy project is being built to serve the long-term needs of customers for reliable, base load power over the expected 60-year operational life of the Levy nuclear units. (TR 380-384)  This is the relevant time period to determine if the Levy project is cost-effective or not, and the undisputed evidence in this proceeding demonstrates that the Levy project is cost-effective over this time period. (TR 404-408; EXH 11)

In sum, PEF argued that its qualitative and quantitative feasibility analyses, in addition to the undisputed evidence of record, demonstrated that completion of the Levy project remained feasible. 

OPC, FIPUG, PCS Phosphate, FEA, and FRF

OPC’s position, as joined by FIPUG, PCS Phosphate, FEA, and FRF, referenced the settlement approved by Order No. PSC-12-0104-FOF-EI, issued March 8, 2012, in Docket No. 120022-EI.  The parties noted that the settlement did not relieve PEF from submitting its 2012 annual detailed analysis of the long-term feasibility of completing the Levy Units 1 & 2 project, as provided for in Rule 25-6.0423, F.A.C., nor the Commission’s determination of long-term feasibility. 

FRF, in addition, believed that the critical long-term feasibility issue relative to the Levy project will come in future proceedings, if and when, PEF proposes to increase actual spending on the construction of the Levy project, as opposed to simply obtaining the COL.

FRF did not dispute PEF’s assertion that the current total estimated all inclusive cost for the Levy project, including AFUDC and sunk costs, as of 2012 is approximately $24.1 billion.  However, given the track record of ever-escalating Levy project cost estimates, FRF doubts the accuracy of this estimate.

SACE

SACE noted that as part of its annual consideration of a utility’s petition for cost recovery, the Commission is required to evaluate the long-term feasibility of completion of a proposed nuclear project.  Rule 25-6.0423(5)(c)5, F.A.C., provides:

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.

SACE argued that this review forces utilities to regularly review whether their investment decisions, which will be borne by the ratepayers, continue to be justified in light of changing economic, technological, and regulatory conditions.  This review is part of the quid pro quo for the extraordinary financial incentive provided to the utility through the cost recovery clause, because the utilities are spending their ratepayers’ money, with no real risk to their own bottom lines.  SACE argued that PEF’s 2012 feasibility analysis (both the qualitative and the quantitative analyses) fails to demonstrate that completion of the Levy project is feasible in the long-term.  Therefore, the Commission should deny PEF’s estimated 2012 and projected 2013 costs related to the Levy project.

SACE claimed that PEF undertook a qualitative feasibility analysis in order to assess the feasibility of completing the Levy project, which consists mainly of an evaluation of enterprise risks facing the Levy project.  SACE pointed out that, in 2012, PEF concluded that there were increased enterprise risks facing the Levy project, i.e., increased risk and uncertainty, and this conclusion resulted in the decision to further push out the projected in-service dates for the Levy project. (TR 375)  PEF witness Elnitsky testified that the cost of natural gas and the lack of a cost of carbon are two key drivers in a feasibility analysis, and low natural gas prices and the lack of a cost of carbon adversely affect the cost-effectiveness of new nuclear generation. (TR 450-451)  Thus, PEF, due to (1) historically low natural gas prices and (2) the lack of a cost of carbon, concluded that:

Issuance of the [Full Notice to Proceed] next year to commence full scale Levy project construction is not supported by near term, lower natural gas prices and delayed carbon cost impacts . . . .

(TR 375)  

SACE also contended that PEF witness Elnitsky testified at the hearing that the company has no assurances that pushing out the Levy project by three years will be enough time for this risk and uncertainty to resolve favorably for new nuclear generation. (TR 435)  SACE asserted that PEF witness Elnitsky admitted that nuclear power is “really hard to justify” in the near term. (TR 456)  Moreover, witness Elnitsky did not dispute that other utilities disagree with PEF’s long term forecasts in terms of the price of natural gas and the cost of carbon, and as a result have cancelled proposed new nuclear projects because completion is not feasible. (TR 461; EXH 117, 126)

SACE argued that with the two most influential drivers in PEF’s feasibility analysis showing that completion of the Levy project is not feasible, Mr. Elnitsky testified that PEF’s conclusion that the Levy project was still feasible was, and had to be, based on long term projections that differ greatly from current reality. (TR 454)  They also differ from the long term projections of other major utilities. (TR 461)  As a result, PEF, once again, resorted to delaying in service dates because completion of the Levy project is not currently feasible.  SACE opined that this delay had the effect of increasing the estimated cost of the Levy project to over $24 billion, further calling into question the feasibility of the project.  The Commission, SACE asserted, should not continue to allow PEF to continue to simply delay the Levy project in hopes that completion of the project will become feasible.  Ultimately, PEF’s qualitative feasibility analysis fails to demonstrate that completion of the Levy project is feasible in the long term as required by Rule 25-6.0423(5)(c)5, F.A.C.

SACE observed that PEF submitted an updated CPVRR analysis which PEF claimed demonstrated that the Levy project is economically feasible.  However, the CPVRR demonstrated that, in the low fuel reference case (reflecting current conditions) the Levy Project was the preferred resource plan only if a high cost of carbon was assumed. (TR 461; EXH 11)  Similarly, the CPVRR demonstrated that if no cost of carbon was assumed (reflecting current conditions) then fuel prices would have to be high for the Levy project to be the preferred resource plan. (TR 461; EXH 11)  Thus, while PEF contends that the CPVRR demonstrates that the Levy project is the preferred resource plan in a majority of cases, these cases are based on long term projections that differ from current reality and moreover differ from what other major utilities are forecasting. (EXH 17, 26)  Furthermore, SACE argued that PEF does not assess the relative likelihood of any of the fuel and gas scenarios it models in its CPVRR. (TR 461-462)  SACE further argued that it goes without saying that such an assessment would greatly improve the relevance, and reliability, of the CPVRR and, moreover, would greatly enhance the Commission’s ability to weigh the CPVRR analysis and make a more accurate determination on long term feasibility.

Ultimately, SACE concluded, from both a qualitative and quantitative standpoint, PEF has failed to demonstrate that completion of the Levy project is feasible.  This Commission should not, as the cost of the Levy project continues to increase to astronomical levels, and projected in-service dates continue to be pushed out, continue to accept PEF’s feasibility analyses, which are based on long term projections that not only differ greatly from current reality, but also differ from the projections of other major utilities across the country. Put simply, it is difficult to imagine PEF ever admitting to the Commission that completion of the Levy project is not feasible in the long term.

ANALYSIS

Staff’s analysis began with a review of the requirements for PEF’s long-term feasibility analysis, and PEF’s compliance with those requirements.  Staff then analyzed the feasibility of the Levy project from an economic, regulatory, technical, and financial perspective, as well as considering the status of joint ownership, and finally presenting staff’s conclusion about the feasibility of completing the Levy project.

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 adopted Rule 25-6.0423, F.A.C., 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,[26] from the Levy project Need Determination proceeding, at page 21, the Order contains the following language lending insight to the Commission's intent regarding the long-term feasibility of PEF's Levy project:

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.

Additionally, 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.

Required elements

Staff believes PEF satisfied the submission requirements as outlined in Rule 25-6.0423, F.A.C., and Order No. PSC-08-0518-FOF-EI with the information provided in Exhibit 11.

Staff believes that the forecasts, cost estimates, and analyses are necessary filing requirements to assess PEF's 2012 Levy project feasibility analysis. In addition, staff reviewed regulatory and technical aspects of the project.  These elements provide a holistic perspective for staff's recommendation regarding the approval or denial of PEF's detailed long-term feasibility analysis.

Economic Feasibility

Updated Fuel Forecasts

PEF’s updated fuel price forecast was developed from the same industry-accepted sources PEF has used since the need determination proceeding.  Figure 5-1 depicts the medium range price forecasts of natural gas used from the 2010 and 2011 Nuclear Cost Recovery Clause proceeding and this year’s filing for low, mid-reference, and high ranges used to support PEF’s feasibility analysis.  Staff notes that the mid-reference natural gas price forecast has declined since the forecast presented last year. 

Figure 5-1:  PEF Delivered Gas Price Forecasts

($/MMBtu, $Nominal)

EXH 11, pp. 12-14; Order No. PSC-11-0547-FOF-EI, p. 75; Order No. PSC-11-0095-FOF-EI, p. 26

In support of SACE’s assertion that full scale construction next year was not supported by near term natural gas prices, SACE selected testimony from PEF witness Elnitsky’s discussion of how PEF was mitigating risks.  The quotation SACE used was part of witness Elnitsky’s response to a question about PEF’s conclusions after evaluating the Levy project enterprise risks where witness Elnitsky began by observing:

The Company concluded from its qualitative analysis of the LNP enterprise risks this year that the LNP [Levy Nuclear Project] is still feasible, both qualitatively and quantitatively, over the long-term life of the Levy nuclear units, however, near term there is greater uncertainty and, thus, increased near term enterprise risks.

 

(TR 375)

 

SACE additionally questioned PEF’s fuel price forecast by eliciting witness Elnitsky’s lack of assurance about the future price of natural gas.  Furthermore, SACE mischaracterized words from a magazine article, attributing them to witness Elnitsky by the misuse of quotation marks:  “In fact, PEF witness Elnitsky admitted that nuclear power is ‘really hard to justify’ in the near term.” (SACE BR 9)  The actual cross examination of Mr. Elnitsky was as follows:

Q  Mr. Elnitsky, would you agree with General Electric's CEO, Mr. Immelt, and I'm not sure if I'm pronouncing that right, you probably know better than I do, with the first sentence here that nuclear power is so expensive compared with other forms of energy that it has become, quote, unquote, really hard to justify?

A  I would say I only agree in the near term.

(TR 456)

Finally, SACE attempted to assert witness Elnitsky concluded that other utilities cancelled nuclear projects deemed unfeasible because those other utilities relied on natural gas price forecasts that differed from PEF’s long term natural gas price forecast.  The actual exchange, beginning with witness Elnitsky being asked to read a letter from Exelon to the Nuclear Regulatory Commission, was as follows:

Q  Okay. If you would, would you read the, the first sentence of the second paragraph, Exelon has reassessed?

A  Exelon has reassessed the economic viability of new nuclear plant construction in the merchant generation market, and based on several factors contributing to an unfavorable economic outlook, Exelon has made the decision to cancel the VCS ESP project.

Q  Are you aware of the Exelon cancellation of its ESP for the Victoria County site?

A  Yes, I was.

Q  Okay. And are you aware that permanent cheap natural gas was one of the economic factors cited in this letter?

A  No, I was not in terms of permanent, but I understand.

Q  Okay. Do you have any reason to dispute that?

A  It's a different market, different situation.  I can't comment on how Exelon drew their conclusions.

Q  Okay. I guess what I'm trying to get at is, is what, what do y'all know that GE and Exelon don't know?

A  I know that if you go out today and you try to ask the gas markets to guarantee $2 gas for the next 20 years, they'll laugh at you, and they say they'll be happy to sell it to you for $10 for the next 20 years.

(TR 458-459)

While witness Elnitsky’s testimony continually emphasized uncertainty of natural gas prices in the near term, SACE contended that uncertainty, including low gas prices, will extend for the 60-year life of the project, thereby making the project infeasible.   

Staff notes that no evidence was offered to suggest the long-term natural gas prices PEF provided were unreasonable or not credible.  Evidence SACE did offer was a letter from Exelon Generation to the Nuclear Regulatory Commission that addressed cancellation of a nuclear plant in the merchant generation market “based on several factors contributing to an unfavorable economic outlook.” (EXH 117)  There was no reference to “permanent cheap natural gas” in the letter as a reason for the cancellation.  In regard to the merchant generation market, witness Elnitsky testified, “It's a different market, different situation.  I can't comment on how Exelon drew their conclusions.” (TR 459) 

SACE’s also offered the magazine article mentioned above.  The Chief Executive Officer of General Electric was quoted as saying natural gas was becoming “permanently cheap.” (EXH 126)  Staff suggests that the article with one individual’s uncorroborated, hearsay characterization of gas prices, with no further explanation, should be weighted accordingly.

Staff notes that PEF, as in past years, continued to use multiple fuel price forecasts in its analysis.  The range of forecast prices provides an expectation that actual prices will be included within the range, thereby lending credibility to PEF’s cost-effectiveness analysis.  Staff believes it is reasonable to accept PEF’s updated fuel cost data in this proceeding. 

Environmental Forecasts

As with the fuel price forecasts, the updated environmental cost forecasts PEF submitted were developed from the same industry-accepted sources PEF has used since the need determination proceeding.  Figure 5-2 depicts the price forecasts of carbon dioxide (CO₂) emission costs from four of the five scenarios presented in PEF’s cost-effectiveness analysis.  The fifth scenario used a CO₂ emission cost of $0.00 (zero).

Figure 5-2:  2012 PEF CO₂ Emission Cost Forecasts

($/Ton, $Nominal)

EXH 11, p. 10

As with the fuel cost forecast, staff rejects SACE’s argument that:

This Commission should not, as the cost of the Levy project continues to increase to astronomical levels, and projected in-service dates continue to be pushed out, continue to accept PEF’s feasibility analyses, which are based on long term projections that not only differ greatly from current reality, but also differ from the projections of other major utilities across the country.

(SACE BR 10)

The same analysis applies here as in the discussion of the projected natural gas prices.  SACE contends that PEF’s feasibility analysis should be based on the cost of CO₂ emissions continuing at today’s price, $0.00 (zero), for the 60-year life of the Levy project.  In contrast to PEF’s cost projections from industry-accepted sources, SACE presented no evidence that such a scenario would occur.  Likewise, SACE presented no evidence of what any other utility’s long-term projections of emission costs were. 

None of the other parties contested the reasonableness or credibility of the emissions cost forecasts PEF submitted.  Staff also observes that PEF, as in past years, continued to use multiple price forecasts for CO₂ emissions in its analysis.  The range of forecast prices provides an expectation that actual prices will be included within the range, thereby lending credibility to PEF’s cost-effectiveness analysis.  Staff believes it is reasonable to accept PEF’s updated environmental cost data in this proceeding.

Project Cost Estimate

Figure 5-3, below, depicts PEF’s cost estimates for the Levy project each year since the 2007 need determination proceeding.

Figure 5-3:  PEF’s Levy Project Cost Estimate

at Then-Year Dollars, including AFUDC and Sunk Cost

EXH 6, p. 4; Order No. PSC-11-0095-FOF-EI, p. 22; Order PSC-11-0547-FOF-EI, p. 76

Intervenor Florida Retail Federation (FRF) expressed doubt about the accuracy of PEF’s cost estimate, and offered the observation that estimated project costs continue to increase.  Staff notes that FRF offered no evidence to support its opinion concerning PEF’s forecasting accuracy. (FRF BR 5)  Other intervenors did not contest PEF’s cost estimate, and no evidence was presented to refute or change PEF’s estimate. 

PEF estimated that the cost of the Levy project is $24.1 billion, which includes about $7 billion in carrying costs and about $783 million in sunk costs thus far. (EXH 6, p. 4)  The revised total cost estimate for 2012 represents a 6.7 percent increase of the cost estimates PEF provided in the 2010 and 2011 Nuclear Cost Recovery Clause proceedings.[27]  This year, PEF witness Lyash observed:

. . . [T]he price of the Levy project really has only changed from its original 14.2 billion, I think, with the Certificate of Need, to the current 18.8 billion.  The driver for that, as was questioned earlier, is the escalation as you move the project out with the passage of time.

(TR 525)

PEF used this current project cost estimate in its 2012 cost-effectiveness analysis.  Results of the analysis demonstrated that the cost-effectiveness of the project has declined since last year in comparison to the competing plan without nuclear generation, but still remains cost-effective.  Staff believes PEF’s cost estimate is reasonable.

Project Cost-Effectiveness

The CPVRR economic analysis PEF submitted indicated that the Levy project is economically viable and has the potential to provide PEF and its customers with billions of dollars of savings over the life of the project. (TR 407)  PEF witness Elnitsky, however, testified that the Project Management Team’s qualitative feasibility analysis led to the conclusion that slower than expected economic recovery in Florida, uncertainty about the price of natural gas, as well as lack of clarity in Federal and state energy and environmental policies, among other factors, constituted an increase in the near term enterprise risk since last year.  PEF’s Senior Management Committee agreed and approved a revised Integrated Project Plan (IPP) in April 2012.  The revised plan now places the in-service date of Levy Unit 1 in 2024 and the second unit 18 months later in 2025.  PEF senior management believes the delay will help mitigate the near term enterprise risks by providing more clarity and certainty to the qualitative factors evaluated while preserving the long term benefits of new nuclear generation.  (TR 376-389; 400-403).  Table 5-1, below, shows the results of the updated CPVRR analysis based on the revised fuel and environmental cost forecasts, cost estimate, and in-service dates.

Table 5-1:  PEF Summary CPVRR Review for 2012 NCRC Filing ($2012)

Note:  A positive number indicates the Levy Project would be more cost-effective than the non-nuclear alternative.

           Conversely, a negative number indicates the Levy Project would be less cost-effective than the non-nuclear alternative.

EXH 11, p. 7

As shown in Table 5-1, the analysis results are that 10 of 15 fuel sensitivity scenarios, at 100 percent ownership, show savings over the non-nuclear alternative.  At 80 percent ownership, the results are similar, and at 50 percent ownership, 9 of 15 scenarios show savings.  The capital cost scenarios show similar results with each of the 3 ownership cases showing savings in 56 to 70 percent of the scenarios. 

Staff notes that the CPVRR analysis PEF submitted this year shows the Levy project is less cost-effective than last year’s analysis; however, the analysis still shows the Levy project is cost-effective.  The cost-effectiveness has decreased due to lower gas costs, but it is still positive.   

As discussed above, SACE suggested the Commission should reject PEF’s feasibility analysis because of the downward trend in the price forecast for natural gas and the lack of legislation placing a cost on carbon dioxide emissions.  SACE asserted that the CPVRR analysis is based on “long term projections that differ from current reality and moreover differ from what other major utilities are forecasting.” (SACE BR 10) 

Staff believes that, by definition, a projection of future prices should be expected to differ from today’s prices, i.e. “current reality.”  The Commission’s position, as established in 2010, was: “We find that the low fuel reference scenario should be discounted because it assumes natural gas prices to remain less than $5.00/MMBtu over the next 30 years.”[28]  The low fuel scenario in PEF’s 2012 analysis has prices projected below $3.00/MMBtu for 28 of the next 30 years. (EXH 11, p. 12)  PEF demonstrated that the only scenario not cost-effective for the medium fuel is the zero cost for CO₂ for the life of the project.  The project remains cost-effective in the other 4 medium fuel scenarios at 100 percent ownership.  While no one can precisely predict the future cost of natural gas or CO₂ emissions, it is clear that nuclear power will reduce both of these costs from what they would otherwise have been.

Furthermore, while contending that PEF’s natural gas and environmental price forecasts differ from those of other utilities, SACE did not provide any evidence to support such a claim.  In its Post-Hearing Brief, SACE included two citations from the hearing record for this claim, Exhibits 17 and 26. (SACE BR 10)  Exhibit 17 is a letter from the Nuclear Regulatory Commission to PEF announcing acceptance of PEF’s license amendment request for the extended power update of Crystal River Unit 3.  Exhibit 26 is a PSC Audit report.  Neither document contains any mention of price forecasts from other utilities.

Despite contention by SACE that PEF’s cost-effectiveness analysis is deficient, staff believes otherwise.  Staff believes the CPVRR analysis methodology PEF has consistently used, and which the Commission has consistently accepted as a demonstration of cost-effectiveness, is reasonable.  Staff, therefore, recommends that the Levy project is economically feasible.

Regulatory Feasibility

PEF acknowledged continued uncertainties in the regulation of federal and state emissions and energy policy, NRC approval of the COL, impacts of the nuclear disaster in Japan, and, most recently, the Waste Confidence Rule, to name a few. (TR 376-389)  PEF witness Elnitsky discussed these uncertainties in depth, which he summarized as follows:

Extending the time for the commencement of the Levy project construction provides more time for the Florida economy to recover, for economic conditions for Florida customers to improve, for federal and state energy and environmental policy to develop, and therefore, for more certainty to develop with respect to the project’s enterprise risks.

 

(TR 375)

PEF witness Lyash testified about his confidence in regulatory aspects of the Levy project:

What's gotten more clear over time is the licensing and permitting risk, and I think that has generally subsided, with the waste competence issue being a recent exception to that.  And so that's part of the basis for my confidence. The AP1000 design was certified, the Vogtle license was issued, the SCANA license was issued; they're under construction. The Chinese are well along. The Part 52 licensing process is being exercised very effectively.

The Levy project has really no substantial deviations from that.  It should follow in its footsteps.  I see no reason why it shouldn't.  So I'm confident of our ability to license it.

(TR 525-526)

Intervenors mentioned no concerns about the regulatory uncertainties, and none provided evidence suggesting the Levy project was not feasible from a regulatory standpoint.

Staff believes that PEF has an effective process in place to provide its management with an ongoing, detailed analysis of the uncertainties and risks that could impact its licensing, approval, and certifications necessary for project success, and that the project is feasible from a regulatory standpoint.

Technical Feasibility

PEF witness Elnitsky observed that the NRC approved all aspects of the Westinghouse AP1000 technology that PEF plans to use in the Levy project, and issued COLs for plants in Georgia and South Carolina that are currently under construction.  Construction of these two plants using the AP1000 technology are well underway in China.  In addition, the NRC is continuing its review of the Levy project Combined Operating License Application.  Witness Elnitsky summarized the technical feasibility of the Levy project testifying, “[T]here is no reason to believe that the AP1000 nuclear reactor design cannot be successfully installed at the Levy site.” (TR 400)

Intervenors did not present any testimony or exhibits specifically addressing the technical feasibility of the Levy project.

Staff believes the evidence supports the Levy project being viewed as technically feasible.

Funding Feasibility

PEF’s access to funding for the Levy project was not mentioned in any testimony, exhibits, or post-hearing briefs.  However, staff notes that the nuclear power plants currently under construction in Georgia and South Carolina suggest that necessary funding was available and obtained for these projects.  Staff also notes that PEF witness Elnitsky’s testimony last year indicated that financial rating agencies responded positively to announcement of the merger between PEF and Duke Energy.[29]  These observations suggest that PEF also will have access to necessary funding for the Levy project.

Staff continues to view PEF's current access to capital markets as confirmation of continued funding feasibility.

Joint Ownership

In the 2011 NCRC proceeding, PEF witness Elnitsky testified that PEF could go forward with the Levy Project without joint ownership.[30]  This year, PEF witness Lyash responded to a cross-examination request for an update on partners in the Levy project:

The situation with respect to partners in the project, I don't think, has really materially changed recently.  We have from the beginning had a number of potential partners who expressed significant interest in the project.  They continue to express significant interest in the project.  We keep them apprised of its progress, but we have not reached the point with any of those potential partners where they have committed to close on an ownership share plan. 

(TR 524)

Staff, therefore, believes a preponderance of the evidence suggests joint ownership is not a project feasibility concern at this time.  

CONCLUSION

PEF presented evidence that examined the economic, regulatory, and technical factors impacting the long-term feasibility of the Levy project that demonstrated the project remains feasible.  In addition, PEF provided updated fuel, environmental, and project costs forecasts as requested by the Commission.  Staff recommends that the Commission accept and approve PEF’s long-term feasibility analysis of the Levy project.

 

Issue 6:  What is the current total estimated all-inclusive cost (including AFUDC and sunk costs) of the proposed Levy Units 1 & 2 nuclear project?

Recommendation:  The Commission should accept PEF's estimated cost of approximately $24.1 billion for the Levy Project.   (Garl)

Position of the Parties

PEF:  The current total estimated all inclusive cost for the Levy Units 1 & 2 nuclear project, including AFUDC and sunk costs, as of 2012 is approximately $24.1 billion.

OPC:  Issues 4 through 11 are governed by the settlement approved by Order No. PSC-12-0104-FOF-EI, issued March 8, 2012, in Docket No. 120022-EI.  The settlement does not relieve PEF from prudently managing the Levy Nuclear Project (LNP) or for complying with any requirements of Section 366.93, Florida Statutes (F.S.), or Rule 25-6.0423, Florida Administrative Code (F.A.C.).  Any amounts to be approved for recovery for the LNP are specified in the settlement.

SACE:  No position.

FIPUG:  Given the scope and size of this undertaking, this information is critical to provide transparency to those who are paying for this enormous project.  Further, the Commission must consider whether the costs make sense in view of the magnitude of the expenditures.  This information is in the possession of PEF and should be provided to the Commission and ratepayers.

PCS Phosphate:  Consistent with the terms of the settlement agreement, PCS Phosphate does not challenge Progress Energy Florida’s (“Progress”) proposed Levy component of nuclear cost recovery for 2013.

FEA:  Agree with FIPUG.

FRF:  The FRF does not, presently, dispute PEF’s assertion that the current total estimated all inclusive cost for the LNP, including AFUDC and sunk costs, as of 2012 is approximately $24.1 billion.  However, given the track record of ever-escalating LNP cost estimates, the FRF doubts the accuracy of this estimate.

Staff Analysis:  This issue addresses the current total estimated all-inclusive cost (including AFUDC and sunk costs) of the proposed Levy project.

PARTIES’ AGRUMENTS

PEF

PEF stated that it demonstrated that the total estimated cost for the Levy project including AFUDC and sunk costs is approximately $24.1 billion. (TR 433, 464)  No one presented any contrary evidence or disputed this estimate.  Therefore, as a factual matter, the total estimated all-inclusive cost for the proposed Levy Units 1 & 2 nuclear project has been established.

OPC, PCS Phosphate, FRF

OPC adopted its prehearing position that the settlement agreement approved by the Commission by Order No. PSC-12-0104-FOF-EI in Docket No. 120022-EI does not relieve PEF from prudently managing the Levy Project or for complying with any requirements of Section 366.93, F.S., or Rule 25-6.0423, F.A.C. (OPC BR 2)  PCS Phosphate and FRF joined OPC in this position. (PCS Phosphate BR 1; FRF BR 4)

FIPUG, FEA

FIPUG and FEA supported PEF’s position as long as PEF’s request was consistent with the parties’ approved settlement agreement. (FIPUG BR 1; FEA BR 3)

SACE

SACE offered no position on this issue.

ANALYSIS

 

PEF estimated that the cost of the Levy project is $24.1 billion, which includes about $7 billion in carrying costs and about $783 million in sunk costs. (EXH 6, p. 4)  The revised total cost estimate for 2012 represents a 6.7 percent increase of the cost estimates PEF provided in the 2010 and 2011 NCRC proceeding.[31]  This year, PEF witness Lyash observed:

. . . [T]he price of the Levy Project really has only changed from its original 14.2 billion, I think, with the Certificate of Need, to the current 18.8 billion.  The driver for that, as was questioned earlier, is the escalation as you move the project out with the passage of time.

(TR 525)

 

FRF expressed doubt about the accuracy of PEF’s cost estimate and offered the observation that the estimated cost of the project continued to increase. (FRF BR 5)  Staff notes that FRF did not offer evidence or argument to support its doubt concerning estimated project cost escalation. (FRF BR 5)  Other intervenors did not contest PEF’s cost estimate, and no evidence was presented to refute or change PEF’s estimate.  PEF used its current project cost estimate in conducting its cost-effectiveness analysis.  Results of the analysis demonstrate that the cost-effectiveness of the project has declined in comparison to the competing plan without nuclear generation, but it still remains cost-effective under a variety of scenarios. 

CONCLUSION

Staff believes PEF’s cost estimate is reasonable.  The Commission should accept PEF's estimated cost of approximately $24.1 billion for the Levy project.
Issue 7: 

 What is the current estimated planned commercial operation date of the planned Levy Units 1 & 2 nuclear facility?

Recommendation: 

 The Commission should accept PEF's estimated commercial operation dates for Levy Units 1 and 2 of 2024 and 2025, respectively.   (Garl)

Position of the Parties

PEF: 

 The Levy Units 1 & 2 nuclear plants are currently estimated for commercial operation in 2024 for Unit 1 and eighteen months later in 2025 for Unit 2.

OPC: 

 Issues 4 through 11 are governed by the settlement approved by Order No. PSC-12-0104-FOF-EI, issued March 8, 2012, in Docket No. 120022-EI.  The settlement does not relieve PEF from prudently managing the Levy Nuclear Project (LNP) or for complying with any requirements of Section 366.93, Florida Statutes (F.S.), or Rule 25-6.0423, Florida Administrative Code (F.A.C.).  Any amounts to be approved for recovery for the LNP are specified in the settlement.

SACE: 

 No position.

FIPUG: 

 Given the scope and size of this undertaking, this information is critical to provide transparency to those who are paying for this enormous project.  Further, the Commission must consider whether the estimated planned commercial operation date make sense in view of the magnitude of the expenditures.  This information is in the possession of PEF and should be provided to the Commission and ratepayers.

PCS Phosphate: 

 Consistent with the terms of the settlement agreement, PCS Phosphate does not challenge Progress Energy Florida’s (“Progress”) proposed Levy component of nuclear cost recovery for 2013.

FEA: 

 Agree with FIPUG.

FRF: 

 In view of the pattern of further and further postponements of the LNP’s projected operation date, the FRF doubts that the LNP units will come into service in 2024 and 2025 as asserted by PEF.  This issue will become critical if and when PEF seeks recovery of actual LNP construction costs.

Staff Analysis: 

 This issue addresses the current estimated planned commercial operation date of the planned Levy Units 1 & 2 nuclear facility.

PARTIES’ ARGUMENTS

PEF

PEF argued that the undisputed evidence demonstrates that the estimated commercial operation dates for the LNP are 2024 and 2025. (TR 369, 401, 421, 497-498, 510, 511, 530; EXH 10)  According to PEF, no one presented any contrary evidence or disputed these estimated in-service dates.  PEF concludes that, as a factual matter, the estimated LNP commercial operation dates have been established. 

OPC, PCS Phosphate, FRF

OPC maintained its prehearing position that the settlement agreement approved by the Commission by Order No. PSC-12-0104-FOF-EI in Docket No. 120022-EI does not relieve PEF from demonstrating to the Commission that PEF’s is prudently managing the Levy Nuclear Project or for complying with any requirements of Section 366.93, F.S., or Rule 25-6.0423, F.A.C. (OPC BR 2)  PCS Phosphate and FRF joined OPC in this position. (PCS Phosphate BR 1; FRF BR 4)

FIPUG, FEA

FIPUG and FEA supported PEF’s position as long as PEF’s request was consistent with the parties’ approved settlement agreement. (FIPUG BR 1; FEA BR 3)

SACE

SACE offered no position on this issue.

ANALYSIS

PEF witness Elnitsky testified that the current estimated in-service dates for the Levy units were revised to 2024 and 2025. (TR 424-430)  In addition, both PEF’s April 2012 Levy Nuclear Project Integrated Project Plan and project schedules for Levy show that PEF plans for the units to enter service in 2024 and 2025. (EXH 10; EXH 11, pp. 11, 17)  Witness Elnitsky further testified about PEF’s project evaluation process and rationale for revising the dates, based on uncertainty about Florida’s economic recovery, the projected price of natural gas, and lack of clarity in Federal and state energy and environmental policy. (TR 370-373) 

As noted in the parties’ position statements above, FRF has doubts about the 2024 and 2025 in-service dates.  However, there is no evidence in the record suggesting the revised dates are not achievable, nor are they contested by any party.

CONCLUSION

Staff recommends it is reasonable to accept PEF’s estimated commercial operations date for Levy Units 1 & 2 as 2024 and 2025, respectively.

 

 

 

Issue 8: 

 Should the Commission find that, for 2011, PEF's project management, contracting, accounting and cost oversight controls were reasonable and prudent for the Levy Units 1 & 2 project?  If not, what action, if any, should the Commission take?

Recommendation: 

 Yes.  Staff recommends the Commission find that project management, contracting, accounting and cost oversight controls employed by PEF for the Levy project during 2011 were reasonable and prudent.  (Laux)

Position of the Parties

PEF: 

 Yes, for the year 2011, PEF’s project management, contracting, accounting and cost oversight controls were reasonable and prudent for the LNP.  These procedures are designed to ensure timely and cost-effective completion of the project.  These project management and cost oversight controls include regular risk assessment, evaluation, and management.  These policies, procedures, and controls are continually reviewed, and where necessary, revised and enhanced, all in line with industry best practices.  The Company has appropriate, reasonable project accounting controls, project monitoring procedures, disbursement services controls, and regulatory accounting controls.  The Company’s 2011 LNP management and cost oversight controls, policies, and procedures are substantially the same as the policies and procedures reviewed and previously determined to be prudent by the Commission.

OPC: 

 Issues 4 through 11 are governed by the settlement approved by Order No. PSC-12-0104-FOF-EI, issued March 8, 2012, in Docket No. 120022-EI.  The settlement does not relieve PEF from prudently managing the Levy Nuclear Project (LNP) or for complying with any requirements of Section 366.93, Florida Statutes (F.S.), or Rule 25-6.0423, Florida Administrative Code (F.A.C.).  Any amounts to be approved for recovery for the LNP are specified in the settlement.

SACE: 

 No.  PEF has pushed out the projected in-service dates for the LNP even further, and the estimated cost of the LNP has again dramatically increased.  Reasonable and prudent project management, contracting, accounting, and cost oversight would have prevented such an outcome.  The Commission should deny cost recovery for PEF’s 2011, 2012 and 2013 costs related to the LNP.

FIPUG: 

 So long as PEF’s filing is consistent with the parties’ settlement, FIPUG supports the company’s position.

PCS Phosphate: 

 Consistent with the terms of the settlement agreement, PCS Phosphate does not challenge Progress Energy Florida’s (“Progress”) proposed Levy component of nuclear cost recovery for 2013.

FEA: 

 Agree with FIPUG.

FRF: 

 The FRF does not oppose recovery of costs within the parameters of the Settlement Agreement executed by PEF and Consumer Parties in January 2012.

Staff Analysis: 

 This issue addresses project management, contracting, accounting and cost oversight controls employed by PEF during 2011 for the Levy project.  Examples of project management oversight controls include having stated corporate policies for developing project schedules, developing annual budgets, tracking variances, training on these policies, and verifying that the team members adhere to corporate policies.  With the exception of SACE, no specific concerns or deficiencies were identified by the intervenors or staff witnesses.

Staff notes that if, in Issue 4, the Commission determines that PEF’s 2011 Levy project activities do not qualify as Section 366.93, F.S., activities, then this issue becomes moot for purposes of implementing Section 366.93, F.S., and Rule 25-6.0423, F.A.C.  However, staff believes PEF’s project activities do qualify and thus a determination of PEF’s prudence is required by Section 366.93, F.S., and Rule 25-6.0423, F.A.C.

PARTIES’ ARGUMENTS

PEF stated that they have appropriate and reasonable project controls that are continually reviewed and, where necessary, revised or enhanced all in line with industry best practices.  PEF asserted that the undisputed evidence demonstrates that PEF’s 2011 project management, contracting, accounting and cost oversight controls for the Levy project are reasonable and prudent and that no one credibly challenged PEF’s testimony. Further, PEF argued that the Company’s 2011 Levy project management and cost controls, policies, and procedures are substantially the same as the policies and procedures reviewed and previously determined to be prudent by the Commission. (PEF BR 23-24)

OPC stated that the settlement agreement approved by the Commission by Order No. PSC-12-0104-FOF-EI in Docket No. 120022-EI does not relieve PEF from proving that its 2011 project management, contracting, accounting and costs oversight controls were reasonable and prudent for the Levy project. (OPC BR 2)  PCS Phosphate and FRF joined OPC in this position. (PCS Phosphate BR 1; FRF BR 5)  FIPUG and FEA stated their support of PEF’s position as long as PEF’s filing was consistent with the parties’ approved settlement agreement. (FIPUG BR 1; FEA BR 4)

SACE stated that PEF has pushed out the projected in-service dates for the Levy project and that the estimated cost of the project has again dramatically increased.  SACE asserted that reasonable and prudent project management, contracting accounting and cost oversight would have prevented such an outcome. (SACE BR 10-11)  However, in its post-hearing brief, SACE did not discuss or present any argument supporting its position specific to this issue, and instead relied on its discussion under Issue 4, that was focused on PEF’s failure to demonstrate its intent to build. (SACE BR 10-11)

ANALYSIS

PEF witnesses Garrett, O’Cain, and Elnitsky provided reviews of PEF’s major project management and accounting control systems in place for the Levy project during 2011 and identified key activities and changes that took place in these systems during that time. (TR 238-242; TR 260-270; TR 420-421)  Witness Garrett opined that the project accounting and cost oversight controls that PEF utilizes to ensure the proper accounting treatment for the LNP and the CR3 uprate project have not substantively changed since 2009.  He further stated that these controls were found to be reasonable and prudent in Docket Nos. 090009-EI, 100009-EI, and 110009-EI. (TR 237-238)  Similarly, witnesses O’Cain and Elnitsky stated that the Company’s current LNP project management and cost oversight controls policies and procedures are substantially the same as the policies and procedures reviewed and previously determined to be reasonable and prudent by the Commission. (TR 269; TR 421)

In addition to providing a review of the systems, controls, policies and procedures PEF had in place during 2011, witness O’Cain outlined certain enhancements PEF implemented in this area during 2011:

During 2011 there were limited field activities for both LNP generation and transmission and as a result, the Company’s general oversight and management plan did not change in 2011.  PEF did however implement several enhancements to continuously improve the oversight and management of contractors for the LNP.  Corporate and nuclear contact procedures were further reviewed and revised in 2011.  Overall sixty-one (61) corporate, nuclear, and EPC procedures were revised and eight (8) new procedures were created in 2011.  Of these eight new procedures, two (2) were new PMCoE (Project Management Center of Excellence organization) procedures issued in 2011.  Most of these updates were minor revisions or updates to existing policies and procedures.  One substantive procedure issued during 2011 was the “Development, Planning, and Execution of Large Construction Projects.”  This procedure updated the project flow and approval gate process, provided additional guidance for formal project review requirements, and formally aligned NGPP (New Generation Programs and Projects) project management processes with PMCoE procedures.

In addition, in 2011, NGPP implemented an enhancement to the LNP Contract Administration function.  Bi-weekly “Levy EPC Change Order, Letters and Invoice Review Meetings” were conducted to discuss upcoming EPC contract invoice milestone, any invoice issues identified, and any open/upcoming change orders and letters that required action.

(TR 263)

Concerning PEF’s major project management and accounting control systems witness Elnitsky opined:

We believe that our LNP project management and cost oversight policies and procedures are consistent with best practices for capital project management in the industry.  We believe the project management, contracting, and cost control policies and procedures that we have implemented for the LNP are reasonable and prudent and consistent with industry best practices.

(TR 421)

Commission staff audit witnesses Coston and Hallenstein reviewed PEF’s project management, accounting, and related controls in their 2012 audit report on the Crystal River Unit 3 uprate and the Levy Nuclear projects.  Witnesses Coston and Hallenstein stated in their pre-filed testimony that:

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

(TR 549-550)

Commission staff accounting audit witness Small provided testimony and sponsored the staff’s 2012 accounting audit report of 2011 Levy project costs.  As noted in this testimony, the staff’s audit activities included reconciliation and verification of 2011 project costs to the general ledger, monthly accrual balances and the Company’s filing in the 2012 Nuclear Cost Recovery Clause Docket. (TR 720-724; EXH 26)

Staff’s review of witnesses Coston’s, Hallenstein’s and Small’s audit reports (EXH 25; EXH 26) revealed no recommendations or issues identified by the audit staff concerning project management or project controls.  Witnesses Coston and Hallenstein confirmed this by stating during the summary of their testimony at hearing that they: “. . .had no specific recommendations concerning the company’s project management internal controls employed by both projects for the current period.” (TR 533)  Witness Small responded to the question of were there any audit findings concerning the Levy project by answering “no.” (TR 723-724)

OPC, PCS Phosphate, FRF, FIPUG and FEA in their post-hearing briefs address whether PEF’s Levy project management, contracting, accounting and cost oversight controls employed during 2011 were inconsistent with the parties’ approved settlement agreement. (OPC BR 2; PCS Phosphate BR 1; FRF BR 1, 5; FIPUG BR 1, 4; FEA BR 4)  However, as noted in the parties’ argument section, only SACE asserted that had PEF employed reasonable and prudent project management, contracting accounting and cost oversight systems during 2011, push back of the projected in-service dates and the associated increase in the estimated cost of the Levy project would have been prevented. (SACE BR 10-11) 

From our review of the record staff found that witness Elnitsky provided information concerning the change to the Levy project schedule, and how the change in schedule impacted the estimated total project cost and 2012 feasibility study. (TR 370-373, 401-408)  Witnesses Elnitsky and Lyash presented information concerning the fundamental reasons why the project team suggested to the Senior Management Committee (SMC) that the recommended changes to the project schedule should be adopted and reflected in the project’s controlling integrated project plan (IPP) document.  Witness Lyash also discussed the revised IPP as approved by the SMC. (TR 418, 422, 497-501, 508-510)  In its post-hearing brief, SACE did not discuss or present additional support for its position on project controls and oversight, and instead relied upon its discussion under Issue 4 (intent to build). (SACE BR 5-7, 10-11)

Staff notes that pursuant to longstanding Commission practice, “. . . the standard for determining prudence is consideration of what a reasonable utility manager would have done, in light of the conditions and circumstances which were known, or should been known, at the time the decision was made.”[32]  Applying this prudence standard and based on the foregoing review of the record, staff believes that PEF’s Levy project management and accounting and related controls were subjected to a reasonable level of review sufficient to determine prudence.  Staff believes there is no record evidence that identified any PEF Levy project management or accounting decisions that were unneeded or were unreasonable.  Therefore, staff believes no evidence of imprudent 2011 project management and related controls and oversight has been reasonably demonstrated by the parties.

CONCLUSION

Staff recommends the Commission find that project management, contracting, accounting and cost oversight controls employed by PEF for the Levy project during 2011 were reasonable and prudent.

 

 

Issue 9: 

 What system and jurisdictional amounts should the Commission approve as PEF's final 2011 prudently incurred costs and final true-up amounts for the Levy Units 1 & 2 project?

Recommendation: 

 Staff recommends the Commission approve the following amounts as prudently incurred 2011 Levy project costs: capital costs of confidential number[33] (hereinafter referred to as Confidential Number A) ($67,092,100 jurisdictional), O&M expenses of $1,258,687 ($1,154,469 jurisdictional), and carrying costs of $48,658,064.  The resulting final 2011 true-up amount of $12,649,655 over recovery should be used in determining the 2013 approved Nuclear Cost Recovery Clause recovery amount. (Laux)

Position of the Parties

PEF: 

 Capital costs (System) confidential number A; (Jurisdictional) $67,092,100.  O&M costs (System) $1,258,687; (Jurisdictional) $1,154,469.  Carrying costs $48,658,064.

The over-recovery of $12,649,655 should be included in setting the allowed 2013 NCRC recovery.

The 2011 variance is the sum of over-projection preconstruction costs of $12,675,090, plus an over-projection of O&M expenses of $260,104 plus an under-projection of carrying costs of $285,540.

OPC: 

 Issues 4 through 11 are governed by the settlement approved by Order No. PSC-12-0104-FOF-EI, issued March 8, 2012, in Docket No. 120022-EI.  The settlement does not relieve PEF from prudently managing the Levy Nuclear Project (LNP) or for complying with any requirements of Section 366.93, Florida Statutes (F.S.), or Rule 25-6.0423, Florida Administrative Code (F.A.C.).  Any amounts to be approved for recovery for the LNP are specified in the settlement.

SACE: 

 None.  PEF failed to demonstrate the requisite intent to build in docket 110009-EI, and thus was not engaged in the “siting, design, licensing, and construction” of the LNP, and thus is not eligible for recovery of these 2011 costs related to the LNP.

FIPUG: 

 So long as PEF’s filing is consistent with the parties’ settlement, FIPUG supports the company’s position.

PCS Phosphate: 

 Consistent with the terms of the settlement agreement, PCS Phosphate does not challenge Progress Energy Florida’s (“Progress”) proposed Levy component of nuclear cost recovery for 2013.

FEA: 

 Agree with FIPUG.

FRF: 

 The amounts to be recovered for the LNP through the Nuclear Cost Recovery Clause in 2013 are specified in the Settlement Agreement executed by PEF and Consumer Parties in January 2012.

Staff Analysis: 

 This issue addresses PEF’s request concerning the final 2011 prudent costs and true-up amounts for the Levy project.  Staff notes that if, in Issue 4, the Commission determines that PEF’s 2011 Levy project activities do not qualify as Section 366.93, F.S., activities, then this issue becomes moot for purposes of implementing Section 366.93, F.S., and Rule 25-6.0423, F.A.C.  Staff further notes that the Commission’s decision in Issue 8 could affect its decision in this issue.  In addition, staff notes that the determination of prudence is a review of what a reasonable utility manager would have done in light of the facts that were known or were reasonably knowable at the time the decision(s) were made.  Accordingly, Commission staff is limiting its discussion and analysis to the facts in the record related to 2011.

PARTIES’ ARGUMENTS

OPC, FIPUG, PCS Phosphate, FEA, and FRF did not take issue with PEF’s position as long as the amounts requested are derived from and consistent with the agreed upon project activities as stated in the Settlement Agreement approved by Commission Order No. PSC-12-0104-FOF-EI. (OPC BR 2; PCS Phosphate BR 1; FRF BR 1, 5; FIPUG BR 1, 4; FEA BR 4)

SACE argued that PEF failed to demonstrate the requisite intent to build the LNP and as such is not eligible for recovery of costs related to the LNP in 2011.  (SACE BR 11)

ANALYSIS

As previously discussed in Issue 8, the standard for determining prudence is consideration of what a reasonable utility manager would have done, in light of the conditions and circumstances which were known, or should have been known, at the time the decision was made.  Staff notes that beyond the SACE argument discussed below, no other concerns were identified regarding the reasonableness or prudence of PEF’s 2011 Levy project incurred costs.

PEF witness Garrett provided support for the activities and the method used to determine the requested recovery amounts. (TR 229-235; EXH 2; EXH 6)  PEF witness O’Cain provided descriptions of the activities and project cost variances associated with the final 2011 costs and true-up amounts for the Levy project. (TR 247-260; EXH 2; EXH 6)

Witness Garrett stated that the data used to support these requests were taken from PEF’s books and records that are kept in accordance with generally accepted accounting principles and practices, provisions of the Uniform System of Accounts, and other accounting rules and orders as established by the Commission. (TR 229)

In Exhibit 2, witness Garrett identified the 2011 Levy project costs PEF believes were prudently incurred.  These amounts include: capital costs of confidential number A ($67,092,100 jurisdictional), O&M expenses of $1,258,687 ($1,154,469 jurisdictional), and carrying costs of $48,658,064.

Witness O’Cain stated:

2011 LNP costs were incurred in connection with licensing application activities to support the Levy Combined Operating License Application (“COLA”) to the Nuclear Regulatory Commission (“NRC”), engineering activities in support of the COLA, and activities under PEF’s LNP Engineering, Procurement and Construction (“EPC”) contract with Westinghouse and Shaw, Stone and Webster (the “Consortium”).  In addition, costs were incurred for Levy Transmission strategic land acquisitions.  PEF took appropriate steps to ensure that the 2011 costs were reasonable and prudent and that all of these costs were necessary to the LNP.

(TR 247)

The final 2011 Levy project costs were compared to prior Commission-approved recovery amounts to determine a net final true-up amount for 2011 as a $12,649,655 over recovery. (EXH 2)  Witness Garrett states that this amount should be approved as reasonable and prudent since it was calculated in accordance with Rule 25-6.0423, F.A.C. (TR 229-230)

The requested final 2011 Levy project true-up amount is the summation of the following components: $12,675,090 over projection of preconstruction capital costs, $260,104 over projection of O&M costs, and $285,540 under projection of carrying costs. (EXH 2; EXH 6)

In reviewing the post-hearing positions of the parties, staff notes that no specific items were identified concerning PEF’s requested final 2011 incurred costs and final true-up amount. (OPC BR 2; PCS Phosphate BR 1; FRF BR 1, 5; FIPUG BR 1, 4; FEA BR 3)  SACE’s stated concern is a carryover of their positions discussed in Issue 4 (project cost eligibility under 366.93, F.S.) and Issue 8 (imprudent project management).  Review of staff’s accounting audit and management review audit identified no recommendations concerning PEF’s 2011 Levy project costs. (EXH 25; EXH 26)

Consistent with staff’s recommendations in Issues 4 and 8, verification of PEF’s calculations and true-up amounts, and a preponderance of the evidence in the record, staff believes that PEF’s information was subjected to a reasonable level of review sufficient to determine the prudence of its 2011 Levy project costs and true-up amount.  Staff believes that PEF has demonstrated the requested 2011 Levy project costs, activities and final true-up requests are reasonable and prudent.

CONCLUSION

Staff recommends the Commission approve the following amounts as prudently incurred 2011 Levy project costs: capital costs of confidential number A ($67,092,100 jurisdictional), O&M expenses of $1,258,687 ($1,154,469 jurisdictional), and carrying costs of $48,658,064.  The resulting final 2011 true-up amount of $12,649,655 over recovery should be used in determining the 2013 approved Nuclear Cost Recovery Clause recovery amount.

 

Issue 10: 

 What system and jurisdictional amounts should the Commission approve as reasonably estimated 2012 costs and estimated true-up amounts for PEF's Levy Units 1 & 2 project?

Recommendation: 

 Staff recommends the Commission approve as reasonable the following Levy project actual/estimated 2012 costs: capital costs of confidential number[34] (hereinafter referred to as Confidential Number B) ($21,391,932 jurisdictional), O&M costs of $1,010,929 ($927,458 jurisdictional) and carrying costs of $48,548,055.  The resulting estimated 2012 true-up of $13,013,480 over recovery should be used in determining the 2013 Nuclear Cost Recovery Clause recovery amount.  (Laux)

Position of the Parties

PEF: 

 Capital Costs (System) confidential number B; (Jurisdictional) $21,391,932.  O&M Costs (System) $1,010,929; (Jurisdictional) $927,458.  Carrying Costs $48,548,055.

The Commission should also approve an estimated 2012 LNP project true-up over-recovery amount of $13,013,480 to be included in setting the allowed 2013 NCRC recovery.

The 2012 variance is the sum of an over-projection of Preconstruction costs of $12,617,788, plus an over-projection of O&M expenses of $477,616 plus an under-projection of carrying charges of $81,924.

OPC: 

 Issues 4 through 11 are governed by the settlement approved by Order No. PSC-12-0104-FOF-EI, issued March 8, 2012, in Docket No. 120022-EI.  The settlement does not relieve PEF from prudently managing the Levy Nuclear Project (LNP) or for complying with any requirements of Section 366.93, Florida Statutes (F.S.), or Rule 25-6.0423, Florida Administrative Code (F.A.C.).  Any amounts to be approved for recovery for the LNP are specified in the settlement.

SACE: 

 None.  PEF’s activities since January 2011 fail to demonstrate the requisite intent to build the LNP.  As such, PEF is not engaged in the “siting, design, licensing, and construction” of the LNP, and thus is not eligible for recovery of costs related to the LNP.  Furthermore, PEF has failed to demonstrate that completion of the LNP is feasible in the long term.

FIPUG: 

 So long as PEF’s filing is consistent with the parties’ settlement, FIPUG supports the company’s position.

PCS Phosphate: 

 Consistent with the terms of the settlement agreement, PCS Phosphate does not challenge Progress Energy Florida’s (“Progress”) proposed Levy component of nuclear cost recovery for 2013.

FEA: 

 Agree with FIPUG.

FRF: 

 The amounts to be recovered for the LNP through the Nuclear Cost Recovery Clause in 2013 are specified in the Settlement Agreement executed by PEF and Consumer Parties in January 2012.

Staff Analysis: 

 This issue addresses PEF’s request concerning the reasonableness of 2012 actual/estimated and estimated true-up amounts for the Levy project.  Staff notes that if, in Issue 4, the Commission determines that PEF’s 2011 Levy project activities do not qualify as Section 366.93, F.S., activities, then this issue becomes moot for purposes of implementing Section 366.93, F.S., and Rule 25-6.0423, F.A.C.  Staff further notes the Commission’s decision on this issue may be affected by the Commission’s decision in Issue 8.

PARTIES’ ARGUMENTS

OPC, FIPUG, PCS Phosphate, FEA, and FRF did not take issue with PEF’s requested recovery amounts as long as the amounts requested are derived from and consistent with the agreed upon project activities as stated in the Settlement Agreement approved by Commission Order No. PSC-12-0104-FOF-EI. (OPC BR 2; PCS Phosphate BR 1; FRF BR 1, 6; FIPUG BR 1, 3; FEA BR 3)

SACE argued that PEF failed to demonstrate the requisite intent to build the Levy project and as such PEF is not eligible to recover costs related to the project in 2012.  In addition, SACE argued that PEF failed to demonstrate that completion of the Levy project is feasible in the long term and therefore the Commission should deny recovery of any 2012 Levy project costs. (SACE BR 11)

ANALYSIS

PEF witness Foster provided support for the activities and method of calculation used to determine the requested recovery amounts. (TR 302, 309-313; EXH 4)  PEF witness Elnitsky provided descriptions of the Levy project 2012 activities. (TR 408-410)

Witness Foster stated that the schedules provided with his testimony were true and accurate and filed in accordance with requirements of the Nuclear Cost Recovery Clause and other rules and orders as approved by the Commission. (TR 304-310)

In Exhibit 4, witness Foster identified the 2012 actual/estimated Levy project costs PEF believes are and will be reasonably incurred.  These costs include: capital costs of confidential number B ($21,391,932 jurisdictional), O&M expenses of $1,010,929 ($927,458 jurisdictional), and carrying costs of $48,548,055.

As to activities PEF is currently and will undertake on the Levy project, witness Elnitsky stated:

The company will continue work necessary to obtain the LNP COL from the NRC in 2012 and 2013. This work includes licensing and engineering work to address the NRC Fukushima Near Term Task Force recommendations.  It also includes the licensing and engineering work to support the Company during the contested and mandatory hearing process . . . .

Licensing and engineering work is also necessary in 2012 and 2013 to continue to support environmental permitting and implementation of conditions of certification (CoC).  The environmental permitting work includes work on the USACE Section 404 permit for the LNP . . . Environmental work scope will include preconstruction environmental monitoring, wetland mitigation plan implementation, aquifer performance testing, and other site CoC.

The Company further continues its participation in industry groups to advance the AP1000 design and operation.  This includes the AP1000 owners group . . ., the NEI New Plant Working Group, NEI Nuclear Plant Oversight Committee and INPO New Plant Deployment Executive Working Group …

PEF will continue to provide project management for all these tasks and activities for the LNP in 2012 and 2013.

(TR 408-410)

All of this work is reasonable and necessary in 2012 and 2013 to move the LNP forward on a schedule with the expected in-service dates for Levy Units 1 and 2 in 2024 and 2025, respectively.  PEF currently intends to build the LNP and to build the LNP with the current 2024 and 2025 estimated in-service dates for Levy Units 1 and 2.  All of this work in 2012 and 2013 is reasonable and necessary to meet that schedule.

(TR 417)

As shown within Exhibit 4, estimated 2012 project costs were compared to prior Commission-approved recovery amounts to determine the estimated true-up amount for 2012.  Witness Foster identified this amount as a $13,013,480 over recovery and opined that it should be approved as reasonable since it was calculated in accordance with Rule 25-6.0423, F.A.C. (TR 310, 313)

The requested estimated 2012 Levy project true-up amount is the summation of the following components: a $12,617,788 over projection of preconstruction capital costs, $477,616 over projection of O&M costs, and an $81,924 under projection of carrying costs. (EXH 4)

In reviewing the post-hearing positions of the parties, staff notes that no specific items were identified concerning PEF’s requested 2012 actual/estimated and estimated true-up amounts, or whether the project activities were inconsistent with the requirements of the Settlement Agreement. (OPC BR 2; PCS Phosphate BR 1; FRF BR 1, 6; FIPUG BR 1, 4; FEA BR 3)  SACE’s stated concerns are carryovers of their positions in Issues 4 (project cost eligibility under 366.93, F.S.), 5 (project feasibility), and 8 (imprudent project management), each of which are addressed in their respective issues.  Review of staff’s management review identified no recommendations which would affect PEF’s 2012 Levy project costs. (EXH 25)

Consistent with staff’s recommendations in Issues 4, 5 and 8, verification of PEF’s calculations and true-up amounts, and a preponderance of the evidence in the record, staff believes that PEF has demonstrated the reasonableness of its requested 2012 actual/estimated and estimated true-up Levy project amounts.

CONCLUSION

Staff recommends the Commission approve as reasonable the following Levy project actual/estimated 2012 costs: capital costs of confidential number B ($21,391,932 jurisdictional), O&M costs of $1,010,929 ($927,458 jurisdictional) and carrying costs of $48,548,055.  The resulting estimated 2012 true-up of $13,013,480 over recovery should be used in determining the 2013 Nuclear Cost Recovery Clause recovery amount.

 

Issue 11: 

 What system and jurisdictional amounts should the Commission approve as reasonably projected 2013 costs for PEF's Levy Units 1 & 2 project?

Recommendation: 

 Staff recommends the Commission approve as reasonable the following Levy project 2013 projected costs: capital costs of confidential number[35] (hereinafter referred to as Confidential Number C) ($95,888,097 jurisdictional), O&M expenses of $1,106,148 ($1,025,100 jurisdictional), and carrying costs of $22,089,049.  Further, staff recommends the Commission approve $40,312,451 as Levy’s 2013 recoverable project costs for use in determining the total 2013 Nuclear Cost Recovery Clause recovery amount.  (Laux)

Position of the Parties

PEF: 

 Capital costs (System) confidential number C; (Jurisdictional) $95,888,097.  O&M costs (System) $1,106,148; (Jurisdictional) $1,025,100.  Carrying charges $22,089,049.

For the LNP, an amount necessary to achieve the rates included in Exhibit 5 ($3.45/1,000kWh on the residential bill) of the Settlement Agreement approved in Order No. PSC-12-104-FOF-EI page 147 should be included in establishing PEF’s 2013 CCRC.

OPC: 

 Issues 4 through 11 are governed by the settlement approved by Order No. PSC-12-0104-FOF-EI, issued March 8, 2012, in Docket No. 120022-EI.  The settlement does not relieve PEF from prudently managing the Levy Nuclear Project (LNP) or for complying with any requirements of Section 366.93, Florida Statutes (F.S.), or Rule 25-6.0423, Florida Administrative Code (F.A.C.).  Any amounts to be approved for recovery for the LNP are specified in the settlement.

SACE: 

 None.  PEF’s activities since January 2011 fail to demonstrate the requisite intent to build the LNP.  As such, PEF is not engaged in the “siting, design, licensing, and construction” of the LNP, and thus is not eligible for recovery of costs related to the LNP.  Furthermore, PEF has failed to demonstrate that completion of the LNP is feasible in the long term.

FIPUG: 

 This is a fall out issue.

PCS Phosphate: 

 Consistent with the terms of the settlement agreement, PCS Phosphate does not challenge Progress Energy Florida’s (“Progress”) proposed Levy component of nuclear cost recovery for 2013.

FEA: 

 Agree with OPC.

FRF: 

 The amount to be recovered for the LNP through the Nuclear Cost Recovery Clause in 2013 are specified in the Settlement Agreement executed by PEF and Consumer Parties in January 2012.

Staff Analysis: 

 This issue addresses PEF’s request concerning the reasonableness of 2013 projected amounts for the Levy project.  Staff notes that if, in Issue 4, the Commission determines that PEF’s 2011 Levy project activities do not qualify as Section 366.93, F.S., activities, then this issue becomes moot for purposes of implementing Section 366.93, F.S., and Rule 25-6.0423, F.A.C.  Staff further notes the Commission’s decision on this issue may be affected by the Commission’s decisions in Issues 5 and 8.

PARTIES’ ARGUMENTS

OPC, FIPUG, PCS Phosphate, FEA, and FRF did not take issue with PEF’s requested recovery amounts as long as the amounts requested are derived from and consistent with the agreed upon project activities as stated in the Settlement Agreement approved by Commission Order No. PSC-12-0104-FOF-EI. (OPC BR 2; PCS Phosphate BR 1; FRF BR 1, 6; FIPUG BR 1, 4; FEA BR 4)

SACE argued that PEF failed to demonstrate the requisite intent to build the Levy project and, as such, PEF is not eligible to recover costs related to the project in 2013.  In addition, SACE argued that PEF failed to demonstrate that completion of the Levy project is feasible in the long term and therefore the Commission should deny recovery of any 2013 Levy project costs. (SACE BR 11)

ANALYSIS

In reviewing the post-hearing positions of the parties, staff notes that no specific items were identified concerning PEF’s requested 2013 Levy project projected costs or whether the activities were inconsistent with the Settlement Agreement. (OPC BR 2; PCS Phosphate BR 1; FRF BR 1, 6; FIPUG BR 1, 4; FEA BR 4)  SACE’s stated concerns are carryovers of their positions in Issues 4 (project cost eligibility under 366.93, F.S.), 5 (project feasibility) and 8 (imprudent project management), and are addressed in each of the respective issues. 

PEF witness Foster provided support for the activities and the method of calculations used to determine the requested recovery amounts. (TR 302, 313-318; EXH 5)  PEF witness Elnitsky provided descriptions of the Levy project 2013 activities. (TR 408-410)

Witness Foster stated that the schedules provided with his testimony were true and accurate and filed in accordance with requirements of the Nuclear Cost Recovery Clause and other rules and orders approved by the Commission, including the Settlement Agreement as approved in Docket No. 120022-EI. (TR 304, 314)

On Exhibit 5, witness Foster identified the 2013 projected Levy project costs PEF believes are reasonably forecasted.  These costs include: capital costs of confidential number C ($95,888,097 jurisdictional), O&M expenses of $1,106,148 ($1,025,100 jurisdictional), and carrying costs of $22,089,049.

As found within Exhibit 5, witness Foster presented PEF’s projected 2013 Levy project costs for which they are requesting recovery.  As shown, PEF is requesting that the Commission find as reasonable, projected 2013 Levy project costs in the amount of $40,312,451. (TR 313)  This amount includes $17,198,302 in preconstruction costs, $1,025,100 in O&M expenses, and carrying costs of $22,089,049. (TR 313-314)

Witness Foster noted that the amounts shown within Exhibit 5 reflect the reclassification of Levy land, at year-end 2012, to Plant Held for Future Use.  In addition, the transfer from the Nuclear Cost Recovery Clause (effective with the first billing cycle in January 2013) to base rate collection of the annual retail revenue requirement associated with the carrying costs on deferred tax assets was also incorporated.  These adjustments were required by the terms and conditions of the Settlement Agreement as approved in Docket No. 120022-EI. (TR 314-315)

In support of PEF’s request, PEF witness Elnitsky identified the activities associated with the projected amounts that PEF plans to undertake during 2013 on the Levy project.  In support, witness Elnitsky stated:

The company will continue work necessary to obtain the LNP COL from the NRC in 2012 and 2013. This work includes licensing and engineering work to address the NRC Fukushima Near Term Task Force recommendations.  It also includes the licensing and engineering work to support the Company during the contested and mandatory hearing process.

Licensing and engineering work is also necessary in 2012 and 2013 to continue to support environmental permitting and implementation of conditions of certification (CoC).  The environmental permitting work includes work on the USACE Section 404 permit for the LNP.  Environmental work scope will include preconstruction environmental monitoring, wetland mitigation plan implementation, aquifer performance testing, and other site CoC.

The Company further continues its participation in industry groups to advance the AP1000 design and operation.  This includes the AP1000 owners group . . ., the NEI New Plant Working Group . . ., NEI Nuclear Plant Oversight Committee and INPO New Plant Deployment Executive Working Group. 

PEF will continue to provide project management for all these tasks and activities for the LNP in 2012 and 2013.

(TR 408-410)

All of this work is reasonable and necessary in 2012 and 2013 to move the LNP forward on a schedule with the expected in-service dates for Levy Units 1 and 2 in 2024 and 2025, respectively.  PEF currently intends to build the LNP and to build the LNP with the current 2024 and 2025 estimated in-service dates for Levy Units 1 and 2.  All of this work in 2012 and 2013 is reasonable and necessary to meet that schedule.

(TR 417)

Consistent with staff’s recommendations in Issues 4, 5 and 8, verification of PEF’s calculations and projections, and a preponderance of the evidence in the record, staff believes that PEF has demonstrated the reasonableness of its projected 2013 Levy project amounts.

CONCLUSION

Staff recommends the Commission approve as reasonable the following Levy project 2013 projected costs: capital costs of confidential number C ($95,888,097 jurisdictional), O&M expenses of $1,106,148 ($1,025,100 jurisdictional), and carrying costs of $22,089,049.  Further, staff recommends the Commission approve $40,312,451 as Levy’s 2013 recoverable project costs for use in determining the total 2013 Nuclear Cost Recovery Clause recovery amount.

 

Issue 13: 

 Should the Commission find that, for 2011, PEF's project management, contracting, accounting, and cost oversight controls were reasonable and prudent for the Crystal River Unit 3 Uprate project?  If not, what action, if any, should the Commission take?

Recommendation: 

 Yes, staff recommends that the Commission determine that PEF's project management, contracting, accounting, and cost oversight controls were reasonable and prudent for the CR3 Uprate project in 2011. (Laux, Lawson)

Position of the Parties

PEF: 

 Yes, for the year 2011, PEF’s project management, contracting, accounting and cost oversight controls were reasonable and prudent for the CR3 Uprate.  These procedures are designed to ensure timely and cost-effective completion of the project.  These project management and cost oversight controls include regular risk assessment, evaluation, and management.  These policies, procedures, and controls are continually reviewed, and where necessary, revised and enhanced, all in line with industry best practices.  The Company has appropriate, reasonable project accounting controls, project monitoring procedures, disbursement services controls, and regulatory accounting controls.  The Company’s 2011 CR3 Uprate management and cost oversight controls, policies, and procedures are substantially the same as the policies and procedures reviewed and previously determined to be prudent by the Commission.

OPC: 

 No.  Until a final decision to repair or retire has been implemented, the Commission should defer determining that PEF’s project management, contracting, accounting and cost oversight controls were reasonable and prudent for the Crystal River Unit 3 Uprate project.

SACE: 

 Agree with OPC.

FIPUG: 

 No.  Given the great uncertainty, especially after the Duke/PEF merger, as to whether Crystal River 3 will be repaired or retired, the Commission should defer all prudence and reasonableness determinations and all cost recovery until it knows whether Crystal River 3 will be repaired or retired.

PCS Phosphate: 

 Agree with OPC

FEA: 

 Agree with FIPUG.

FRF: 

 No.  Until a final decision to repair or retire has been implemented, the Commission should defer any decisions regarding whether PEF’s project management, contracting, accounting and cost oversight controls for the CR3 EPU project were reasonable and prudent.

Staff Analysis: 

 This issue addresses project management, contracting, accounting and cost oversight controls employed by PEF during 2011 for the CR3 Uprate project.  Examples of project management oversight controls include having stated corporate policies for developing project schedules, developing annual budgets, tracking variances, training on these policies, and verifying that the team members adhere to corporate policies.  In addition, staff notes, the determination of prudence is a review of what a reasonable utility manager would have done in light of the facts that were known or were reasonably knowable at the time the decision(s) were made.  Accordingly, Commission staff is limiting its discussion and analysis to the facts in the record related to 2011.

PARTIES’ ARGUMENTS

PEF stated that the Company has appropriate and reasonable project controls that are continually reviewed and, where necessary, revised or enhanced, all in line with industry best practices.  PEF stated that the Company’s CR3 Uprate project management and cost controls, policies, and procedures are substantially the same as the policies and procedures reviewed and previously determined to be prudent by the Commission.  PEF argued that no one challenged the evidence PEF presented that demonstrates PEF’s 2011 project management, contracting, accounting and cost oversight controls for the CR3 Uprate project are reasonable and prudent.  PEF further noted that this evidence was supported by the Commission staff’s testimony and audit report concerning PEF’s 2011 CR3 Uprate project management, contracting, accounting and cost oversight controls.  Therefore, the Commission should find that PEF’s 2011 project management, contracting, accounting and cost oversight controls for the CR3 Uprate project are reasonable and prudent. (PEF BR 26-27)

OPC asserted that the Nuclear Cost Recovery Clause statute and its implementing rule never contemplated a situation where cost recovery would be blindly allowed for an extended power uprate on a damaged containment building that potentially may never go into commercial operation. (OPC BR 11-12)  OPC stated that it is “absurd” for PEF to argue that the Commission cannot take notice of this real factual situation and defer the determination of prudence until the factual situation changes and Section 366.93 specifically applies.  OPC stated that acceding to PEF’s request to approve as prudent the 2011 expenditures requires the Commission to “wear blinders to this undisputed factual reality.” (OPC BR 11-12)  OPC stated that the reason they are requesting that the Commission defer the determination of prudence for 2011 expenditures is simple – it protects the ratepayers and prevents the utility from throwing good money after bad.  OPC stated that according to Section 366.93(6), “If the utility elects not to complete or is precluded from completing construction of the nuclear power plant, . . . the utility shall be allowed to recover all prudent preconstruction and construction cost . . .”.  Therefore, OPC argued, if the Commission exercises its authority to defer and does not determine that the utility’s expenditures were prudent, the utility cannot recover those expenditures from ratepayers even if the utility is later precluded from completing the project unless there is a later finding of prudence. (OPC BR 13) 

OPC also argued that by exercising its authority and deferring a determination of prudence on the 2011 actual expenditures and collection of carrying costs, the Commission would meaningfully lower customer bills in 2013.  In addition, OPC argued that this exercise of authority potentially will assure customers might not pay the nearly $43.6 million of 2011 EPU costs if Duke decides to retire CR3, and the decision to continue to incur additional post-March 14 costs is deemed to have been imprudent based on all the facts and circumstances known at the time. (OPC BR 14)  SACE and PCS Phosphate joined OPC in these arguments. (SACE BR 12; PCS Phosphate BR 1)

FIPUG argued that PEF should not be allowed to fully recover all monies it spends on the CR3 Uprate project, given the uncertainty as to whether the Crystal River nuclear power plant will ever operate again.  FIPUG asserted that the Uprate project has no value if the Crystal River Unit 3 is not repaired and operating. FIPUG argued that PEF failed to show that continuing to make expenditures after the second delamination event, or after the third delamination event were prudent.  FIPUG argued that if the Commission allows PEF to recover 2011 expenditures after the second and third delamination events, it will send the wrong message . . ., especially if Duke Energy Corporation eventually decides to retire the CR3 plant. (FIPUG BR 1-2, 4-5)  FEA joined FIPUG in these arguments. (FEA BR 4)

FRF argued that until a final decision to repair or retire has been implemented, the Commission should defer any decisions regarding whether PEF’s project management, contracting, accounting and cost oversight controls for the CR3 Uprate project were reasonable and prudent. (FRF BR 2)

ANALYSIS

PEF witnesses Garrett and Franke provided reviews of PEF’s major project management and accounting control systems in place during 2011 for the CR3 Uprate project and identified key activities and changes that took place in these systems. (TR 237-242; TR 623-624)  Witness Garrett opined that the project accounting and cost oversight controls that PEF utilizes to ensure the proper accounting treatment for the Levy project and CR3 Uprate projects have not substantively changed since 2009.  He stated that these controls were found to be reasonable and prudent in Docket Nos. 090009-EI, 100009-EI, and 110009-EI. (TR 237-238)  Witness Garrett testified that during 2011, the review and testing of controls were conducted by the Audit Services Department, and conclusions/results of the Departments activities were reviewed and approved by both the Steering Committee and the Compliance Team chairpersons.  Based on these internal audits, PEF’s management has determined that PEF maintained effective internal control over financial reporting and identified no material weaknesses within the required Sarbanes-Oxley controls during 2011. (TR 242)  Witness Garrett further stated that with respect to external audits, Deloitte and Touche, PEF’s external auditors, determined that the Company maintained internal control over financial reporting during 2011. (TR 242)

Similarly, witness Franke stated that the Company’s current CR3 project management and cost oversight control policies and procedures also are substantially the same as the policies and procedures reviewed and previously determined to be reasonable and prudent by the Commission. (TR 623-624)

Commission staff accounting audit witness Small provided testimony and sponsored the staff’s 2012 accounting audit report on 2011 CR3 Uprate project costs.  As noted in this testimony, the staff’s audit activities included reconciliation and verification of 2011 project costs to the general ledger, monthly accrual balances and the Company’s filing in the 2012 Nuclear Cost Recovery Clause docket. (TR 720-724; EXH 27)  From his testimony, witness Small responded to a question of whether there were any audit findings concerning the CR3 project:

Yes, Audit Finding No. 1 provides information on legal costs included as recoverable O&M expenditures on Schedule T-4 of the filing that the Company states will be removed by posting a journal adjustment in April 2012 that will reduce next years Schedule T-4 filing by $12,683 ($11,716 jurisdictional).

(TR 724)

Staff notes witness Small identified no other findings in his audit report concerning CR3 Uprate project costs in 2011.

Commission staff audit witnesses Coston and Hallenstein reviewed PEF’s project management, accounting, and related controls in their 2012 audit report on the Crystal River Unit 3 Uprate and the Levy Nuclear projects.  Witnesses Coston and Hallenstein stated in their pre-filed testimony:

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

(TR 549-550; EXH 26)

Staff’s review of witnesses Coston and Hallenstein’s report revealed no recommendations or identified issues concerning project management or project controls.  Witnesses Coston and Hallenstein confirmed this by stating during the summary of their testimony at hearing that they: “. . . had no specific recommendations concerning the company’s project management internal controls employed by both projects for the current period.” (TR 533)

In his rebuttal testimony, PEF witness Franke stated:

[n]o witness has filed testimony in this proceeding disputing the prudence of any specific cost incurred by PEF on the CR3 Uprate project in 2011. Finally, no witness has filed testimony in this proceeding disputing the prudence of PEF’s CR3 Uprate project management, contracting, accounting and cost oversight controls.

(TR 627)

After reviewing the record, staff agrees with PEF’s witness Franke and believes no evidence was presented by any other party that suggested or demonstrated the project management and related controls PEF employed during 2011 on the CR3 Uprate project were unreasonably or imprudently implemented.

Staff believes, however, that the intervenors’ stated concerns in this issue have more to do with the prudence of any project management decisions PEF made in 2011 than with actual project management systems, controls and oversight employed by PEF during 2011.

In its most basic form, intervenors argued that PEF’s management decision to continue making expenditures on the CR3 Uprate project in 2011 was imprudent, given the uncertainty surrounding the ongoing repairs of the CR3 Unit’s containment building.  They asserted that PEF failed to show that continued expenditures after the second delamination event in March of 2011, or after the third delamination event that occurred in July 2011, were prudent. (FIPUG BR 4-5)  As such, intervenors argued the Commission should find PEF imprudent or, in the alternative, defer making any decision on the prudence and reasonableness of costs or deny recovery of them until after a decision concerning the repair to the CR3 containment building has been made. (OPC BR 8-15; FIPUG BR 1-2, 4-5; FRF BR 2)

To address the concern of imprudent management decisions resulting in the continuation of expenditures on the CR3 Uprate project in 2011, staff reviewed the record on PEF’s management and project actions concerning the CR3 Uprate project during 2011.  Staff determined witness Franke was the only witness at hearing who directly addressed the intervenors’ concern. 

Staff notes that witness Franke presented the following CR3 Uprate project information:

In 2011, prior to the March 14, 2011 delamination, PEF was proceeding with a project plan and CR3 Uprate project schedule to complete the EPU work in a then planned 2013 CR3 re-fueling outage.  PEF obviously, then, had incurred and committed to incur EPU costs in the first quarter of 2011, prior to and immediately after the mid-March 2011 delamination, that were not amenable to revision as a result of this event.  Subsequent to this delamination event, however, PEF evaluated the EPU phase work and determined that the reasonable course of action was to take steps to preserve the option of completing the CR3 Uprate work in the current CR3 outage without unnecessarily incurring costs for the CR3 Uprate project. 

To develop the current CR3 Uprate project schedule, PEF evaluated the EPU phase work to identify what work was critical to proceed with to maintain a schedule to complete the EPU during the current CR3 outage and what work was not on this critical path.  Based on this evaluation, PEF slowed down and postponed work on the EPU phase in 2011 and 2012 to minimize the CR3 Uprate project costs while preserving the Company’s ability to complete the EPU work during the current CR3 outage and implement the power uprate when CR3 returns to service.

(TR 637)

 

 

Witness Franke went on to state:

For example, no EPU phase work has been or is being accelerated, all overtime work has been postponed, and only regular work hours are permitted on EPU work that PEF has determined needs to be done to maintain the current CR3 Uprate project schedule.  PEF also delayed the selection of a construction contractor for the EPU phase.  PEF individually evaluated each contract and change order for the EPU phase work before execution.  For contracts or change orders below $100,000, the EPU phase project manager performed this evaluation; for contracts or change orders at or above $100,000, the project manager conducted this evaluation and made recommendations with respect to execution of the contract or change order that were reviewed by the manager of nuclear projects and senior management.  No contract or change order at or above $100,000 for the EPU phase work was executed without senior management approval.  That approval was not granted unless there was a demonstration that the work under the contract or change order was reasonable and necessary to preserve the Company’s ability to complete the EPU work on the current CR3 Uprate project schedule.  This type of evaluation was conducted for each item of work for the EPU phase of the CR3 Uprate project.

(TR 637-638)

Witness Franke also stated:

PEF was able to reallocate project management resources and reduce project management expenditures for the CR3 Uprate project by 4.7 million in 2011.  PEF’s 2011 Power Block Engineering, procurement, and related construction costs were reduced by $34.2 million.

(TR 639)

In addition to his testimony, witness Franke was cross-examined in detail by the intervenors concerning PEF’s management decisions, actions and contracts that were in play during 2011 for the CR3 Uprate project. (TR 659-716) 

Staff notes that the only other witness, besides PEF witnesses, that offer testimony concerning the prudence of CR3 Uprate project management decisions in this docket was OPC witness Jacobs.  Witness Jacobs indicated in his testimony that he was asked to assist the OPC to conduct a review and evaluation of requests by PEF for authority to collect historical and projected costs associated with the “EPU” project being pursued at CR3 through the capacity cost recovery clause. (TR 718B)  In addition, the witness described that he assisted the OPC in the issuance of interrogatories and requests for production of documents, evaluated issues related to project schedule and cost, reviewed internal documents, status reports and correspondence with regulatory authorities and reviewed responses to discovery requests. (TR 718C-718L)

Staff observed from its review of witness Jacobs’ testimony that it focused on 2012 and 2013 issues, and did not focus on or address any of the 2011 prudence issues concerning management decisions, actions, or costs for the CR3 project. (TR 718C-718L)

OPC argued that if the Commission decides not to defer, until 2013, its determination of prudence, on EPU expenditures that could have been deferred or delayed or avoided, but were not, they should be considered imprudently incurred. (OPC BR 16)  OPC stated:

OPC witness Dr. Williams Jacobs provided testimony in support of this position.  Because of all the inherent uncertainty surrounding the decision to repair or retire CR3 following the March 14, 2011 delamination, OPC witness Jacobs recommended:

[t]he Commission to ensure that PEF minimize all expenditures related to the CR3 EPU project.  I recommend that the avoidable or deferrable remaining EPU construction work not be contracted for or performed until late in the containment repair process when the success of the repair and NRC acceptance of that repair is assured.  In addition, the Commission should require that PEF provides timely updates on the status of the containment repair decision and update its EPU project plan, even if it requires supplemental testimony.

(OPC BR 16)

While staff does not disagree with the general direction of witness Jacobs’s actual recommendation, the assertion by OPC that witness Jacobs’s testimony and recommendation supports OPC’s argument in this issue should not be used as a basis for any Commission determination of prudence concerning managerial decisions made in 2011. Staff notes the statement of witness Jacobs which OPC refers to in its brief was offered by the witness in response to the following question: “What do you recommend regarding future expenditures for the CR3 EPU Project?” (TR 718J)  Since this evidence was offered in response to questions about future expenditures, the Commission [given the Commission’s prudence review standard] should not rely on this witness’s statement in making any decisions concerning the prudence of historical actions or incurred costs.

Based on a review of the record and information contained in briefs offered by intervenors in this docket, staff identified no evidence that directly challenged the prudence of any specific managerial action or decision PEF made in 2011.  Staff believes that PEF demonstrated that its decisions and actions concerning the CR3 Uprate project were reasonable in light of the uncertainties affecting the project which were known to management in 2011.

As discussed in Issue 3 and this issue, the intervenors argued that the Commission cannot make an informed decision of prudence concerning the CR3 Uprate project 2011 costs or activities until a final decision to repair or retire the CR3 Unit has been made by PEF.  Therefore, the Commission should defer its decision on prudence until after that decision is known. (OPC BR 7-9, 12, 21; FIPUG BR 1-2, 5; PCS Phosphate BR 3, 8; FRF BR 2)  As stated in Issue 8, staff notes that pursuant to long standing Commission practice, “. . . the standard for determining prudence is consideration of what a reasonable utility manager would have done, in light of the conditions and circumstances which were known, or should have been known, at the time the decision was made.”  Applying this standard, staff believes that any knowledge which may be gleaned from the future resolution of a question which was identified during the period under review is unnecessary in the making of a prudence determination of actions that actually occurred during the period under review.  Staff does believe, however, that it is necessary to review and understand what actions were taken in light of any known unresolved uncertainty.  Future resolution of the uncertainty will not change the facts and circumstances faced by managers when they made their actual decisions.  Staff agrees with the following statement which was offered by PEF’s in its brief:

The historical CR3 Uprate project decisions in 2011 have been made and the 2011 costs incurred and nothing that occurs after 2011 changes those decisions.

(PEF BR 29)

Based on its review, staff believes there is sufficient evidence in the record to allow a thorough review of the decisions PEF’s managers made during 2011, thereby allowing the Commission to make a determination concerning the prudence of 2011 CR3 Uprate project activities and costs.  Staff recommends that the Commission can and should make such a determination in this docket.

Based on the foregoing review of the evidence in the record, staff believes that PEF’s 2011 CR3 Uprate project management and accounting and related controls were subjected to a reasonable level of review sufficient to determine prudence.  Staff believes there is no record evidence identifying any PEF CR3 Uprate project 2011 management decisions or accounting system oversight activities that were shown to be unneeded or implemented in an unreasonable manner.  Therefore, the Commission should determine that PEF's project management, contracting, accounting, and cost oversight controls were reasonable and prudent for the CR3 Uprate project in 2011.

CONCLUSION

Staff recommends that the Commission determine that PEF's project management, contracting, accounting, and cost oversight controls were reasonable and prudent for the CR3 Uprate project in 2011.

 

Issue 14: 

 Were all of the actual Crystal River Unit 3 Uprate project expenditures prudently incurred or expended in 2011 in the absence of a final decision to repair or retire Crystal River Unit 3 in 2011?

Recommendation: 

 Staff recommends that the Commission find actual CR3 Uprate project expenditures were prudently incurred and expended in 2011 even in the absence of a final decision to repair or retire Crystal River Unit 3. (Laux, Lawson)

Position of the Parties

PEF: 

 Yes, all of the CR3 Uprate 2011 actual costs were prudently incurred.  As explained by Mr. Franke, prior to the March 14, 2011 determination, PEF was proceeding to complete the CR3 Uprate project in a 2013 re-fueling outage.  At that point, PEF had incurred and committed to incur costs for the Uprate project in 2011 that were not amenable to revision as a result of this event.  PEF therefore prudently minimized CR3 Uprate costs in 2011 to ensure that those only costs necessary to continue with the CR3 Uprate project if CR3 was repaired were incurred until a final decision to repair CR3 is made.

OPC: 

 No.  Until a final decision to repair or retire has been implemented, the Commission should defer determining the prudence of 2011 expenditures.  However, should the Commission decide not defer the determination of prudence on 2011 expenditures, only EPU expenditures that could not have been deferred or delayed or avoided should be determined prudent and all others imprudent.

SACE: 

 Agree with OPC.

FIPUG: 

 No.  Until a final decision has been made to repair Crystal River 3 (if that is the final decision), it is imprudent to spend money on an uprate that may never occur.  The Commission should defer all prudence and reasonableness determinations and all cost recovery until it knows whether Crystal River 3 will be repaired or retired.

PCS Phosphate: 

 No.  Progress has failed to demonstrate that the Crystal River Unit 3 Uprate project remains feasible and thus the Commission lacks sufficient evidence to find that all of the actual Crystal River Unit 3 Uprate project expenditures were prudently incurred.

FEA: 

 Agree with FIPUG.

FRF: 

 No.  Until a final decision to repair or retire has been implemented, the Commission should defer any determination of the prudence of 2011 expenditures.

Staff Analysis: 

 This issue addresses whether actual CR3 Uprate project expenditures were prudently incurred or expended in 2011 in the absence of a final decision to repair or retire Crystal River Unit 3 in 2011.  As also noted in Issue 13, the determination of prudence is a review of what a reasonable utility manager would have done in light of the facts that were known or were reasonably knowable at the time the decision(s) were made.  Accordingly, Commission staff is limiting its discussion and analysis to the facts in the record related to 2011.

PARTIES’ ARGUMENTS

As argued in the prior issue, OPC asserted that PEF has not made a final decision to repair or retire the plant; therefore, the Commission should defer any prudence determination concerning the project.  OPC argued that the Commission should defer collection of all CR3 Uprate project cost recovery until at least the 2013 Nuclear Cost Recovery Clause hearing cycle so as to protect customers from any further losses should Duke decide to retire the CR3 unit.  However, should the Commission decide not to defer the determination of prudence on 2011 expenditures, only EPU expenditures that could not have been deferred, delayed, or avoided should be determined prudent, and all others imprudent. (OPC BR 1-2, 16-21) 

Likewise, SACE, FIPUG, FEA, and FRF generally restated their positions which were discussed in Issue 13. (SACE BR 12; FIPUG BR 2, 5; FEA BR 5; FRF BR 2, 7-8)

PCS Phosphate asserted that PEF cannot establish that the CR3 Uprate project is feasible until a repair decision is made.  Lacking this showing of feasibility, PCS Phosphate argued that the Commission lacks sufficient evidence to find that any CR3 Uprate project expenditures were prudently incurred; therefore, recovery of any CR3 Uprate costs should be denied in 2013. (PCS Phosphate BR 8-9)

ANALYSIS

Staff notes that this issue is similar to that argued in Issue 13, but has as its focus the prudence of incurring cost for the CR3 Uprate project in 2011 as compared to the prudence of management decisions that were made for the Uprate project during 2011.

PEF witness Garrett provided testimony concerning PEF’s final actual costs and expenditures made for the CR3 Uprate project in 2011. (TR 228-230; EXH 3)  Witness Garrett stated that the data used supporting the information presented in Exhibit 3 were taken from PEF’s books and records that are kept in accordance with generally accepted accounting principles and practices, provisions of the Uniform System of Accounts, and other accounting rules and orders as established by the Commission. (TR 229)

PEF witness Franke provided testimony concerning PEF’s actual costs incurred during 2011 for the CR3 Uprate project. (TR 568-569, 570-579)  Witness Franke stated that PEF reasonably and prudently incurred the 2011 CR3 Uprate project costs which were necessary for the continuation of work for the EPU phase, and that PEF’s 2011 CR3 Uprate project costs were reasonably and prudently incurred. (TR 578)

Commission staff accounting audit witness Small provided testimony and sponsored the staff’s 2012 accounting audit report of 2011 CR3 Uprate project costs.  As noted in this testimony, the staff’s audit activities included reconciliation and verification of 2011 project costs to the general ledger, monthly accrual balances and the Company’s filing in the 2012 Nuclear Cost Recovery Clause Docket. (TR 720-724; EXH 27)  From his testimony, witness Small responded to a question of whether there were any audit findings concerning the CR3 Uprate project:

Yes, Audit Finding No. 1 provides information on legal costs included as recoverable O&M expenditures on Schedule T-4 of the filing that the Company states will be removed by posting a journal adjustment in April 2012 that will reduce next years Schedule T-4 filing by $12,683 ($11,716 jurisdictional).

(TR 724)

Staff notes that witness Small identified no other findings in his audit report concerning CR3 Uprate project costs in 2011.

As in Issue 13, witness Franke presented testimony concerning PEF’s management and project based actions concerning the CR3 Uprate project during 2011.  These actions are the basis for costs that where incurred during 2011. (TR 637-639)  In addition to his pre-filed testimony, witness Franke was also cross-examined in detail by the intervenors concerning PEF’s management decisions, actions, and whether any costs associated with contracts for the CR3 Uprate project during 2011 could have been avoided or deferred. (TR 659-716) 

PEF argued in its brief:

As explained by Mr. Franke, subsequent to the March 2011 delamination, PEF evaluated the CR3 Uprate project work and determined that the reasonable course of action was to take steps to preserve the Company’s ability to complete the CR3 Uprate in the current CR3 outage, without unnecessarily incurring costs for the project in 2011, while assessments regarding the potential repair off the CR3 containment building continued.  PEF prudently minimized CR3 Uprate costs in 2011 to ensure that only those costs necessary to continue with the CR3 Uprate project if CR3 was repaired were incurred until a final decision to repair CR3 is made.

(PEF BR 28)

Witness Franke addressed the efforts that PEF took to minimize CR3 Uprate costs incurred in 2011, which resulted in the avoidance or deferral of costs to a later period of time.  Witness Franke testified:

PEF was able to reallocate project management resources and reduce project management expenditures for the CR3 Uprate project by $4.7 million in 2011.  PEF’s 2011 Power Block Engineering, Procurement, and related construction costs were further reduced by $34.2 million.

(TR 639)

PEF further asserted that “Dr. Jacobs (the only intervenor witness to address CR3 issues) did not testify that any historical 2011 CR3 Uprate costs was unnecessary for the project or otherwise imprudently incurred.  The evidence, then, is undisputed that PEF’s 2011 CR3 Uprate project costs were prudently incurred.” (PEF BR 29)

OPC stated within its brief:

OPC applauds PEF’s efforts to evaluate and scale back EPU expenditures in 2011 immediately following the delamination, but those efforts to slow spending may not be enough if Duke ultimately decides to retire CR3 in 2012 or 2013.  It was a good first step.  However, OPC maintains that PEF should continue this evaluation process and postpone all deferrable or avoidable EPU expenditures until PEF decides to implement the repair to CR3 in earnest.  At the very least, PEF should halt or minimize incurring additional expenditures and refocus its effort on implementing the EPU in the R-17 refueling outage and defer those deferrable expenditures with the outage as the goal for completion of the EPU.

(OPC BR 21)

FIPUG, OPC and FRF encouraged the Commission to defer its decision concerning the prudence of 2011 CR3 Uprate project costs until after PEF has made a decision on whether to repair or retire the CR3 unit.  Alternatively, these intervenors argue that only CR3 Uprate expenditures that could not have been deferred, delayed, or avoided should be determined prudent and all others found imprudent because PEF has not yet determined whether to repair or retire CR3. (OPC BR 1-2, 16-21; FIPUG BR 2, 5; FRF BR 2, 7-8)

In addition to the intervenors’ positions concerning prudence of incurred costs, PCS Phosphate argued that PEF cannot satisfy its burden of proof concerning prudence due to the absence of a reviewed 2011 feasibility analysis of completing the CR3 Uprate project as required by Rule 25-6.0423(5)(c)5, F.A.C. 

PEF argued that the long-term feasibility of completing the power plant uprate has nothing to do with the historical decisions that led to incurring actual costs on the project. (PEF BR 13)  PEF further argued that nowhere in the rule is determination of prudence of previous year actual costs dependent on the determination of the feasibility of completing the power plant, nor could it logically be. (PEF BR 13)  PEF asserted that the “long-term feasibility of completing a power plant project includes cost projections, and other forecasts in the analysis.  By definition, estimates, projections, and forecasts do not involve actual, historical costs.  As a result, the feasibility of the CR3 Uprate project on a going forward basis has nothing to do with consideration of the prudence of past project cost.” (PEF BR 14)

According to PCS Phosphate, the only way for PEF to satisfy its burden of proof is for the Commission to make a feasibility finding.  PCS Phosphate argues that absent the feasibility finding, PEF cannot satisfy its burden of proof, and the Commission has no basis to conclude that PEF’s 2011 expenditures were prudent. (PCS Phosphate BR 8)

PCS Phosphate referred to Order No. PSC-11-0095-FOF-EI, issued in Docket No. 110009-EI, in which the Commission notes that the burden is on “the utility [to] prove that its costs in new nuclear power plant capacity were prudently incurred.”  PCS Phosphate asserted that pursuant to Rule 25-6.0423(5)(c)2, F.A.C., the Commission must conduct a hearing each year and determine the prudence of actual construction expenditures by the utility.  According to PCS Phosphate, the utility must submit a detailed analysis of the long-term feasibility of completing the power plant as part of the annual review. (Rule 25-6.0423(5)(c)5, F.A.C.)  PCS Phosphate cited to the Commission’s order in PEF’s need determination of the Levy nuclear plants as the purpose for the Commission’s review of the project’s feasibility which is to provide “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.” (Order No. PSC-08-0518-FOF-EI) (PCS Phosphate BR 6-7)

PCS Phosphate asserted that witness Franke testified that for PEF’s ratepayers to receive any value from the CR3 Uprate project, PEF must return the CR3 Unit back to service.  PCS Phosphate argued that at this time, PEF is unable to establish that CR3 will ever produce energy again and that this uncertainty persisted throughout most of 2011, following the March 2011 delamination event. (PCS Phosphate BR 7)

PCS Phosphate contended that PEF cannot demonstrate that the power uprate investment is feasible.  PCS Phosphate argued that by seeking recovery for 2011 costs, PEF asked the Commission to find that PEF was prudent to presume the containment repairs would be made by the end of 2014 (the identified CR3 repair plan began in 2011).  PCS Phosphate stated that there was, and remains, no tangible support for that presumption that containment repairs would be made by the end of 2014.  In support of its statement, PCS Phosphate noted the August 15, 2012 Wall Street Journal article they offered as an exhibit at hearing.  PCS Phosphate asserted that as of October 1, 2012, PEF/Duke Energy management still has not made the decision to repair or retire the CR3 Unit. (PCS Phosphate BR 7-8)

In conclusion, PCS Phosphate asserted that the 2011 delamination events changed the scope required of a feasibility analysis.  PCS Phosphate stated PEF filed a deferral motion concerning the Commission’s review of the feasibility analyses for both 2011 and 2012.  Because of the 2011 motion, PCS Phosphate asserted, the feasibility analysis of the CR3 Uprate project is not before the Commission and cannot serve as a basis for the Commission to find the 2011 expenditures were prudently incurred. (PCS Phosphate BR 8)

Staff believes that PCS Phosphate, and other intervenors, do not properly apply the prudence standard employed by the Commission to the facts that PEF knew or should have known in 2011, when decisions to continue expenditures on the project were made.  PCS Phosphate’s brief is replete with information that the Commission and PEF know now, in 2012, but could not have known during 2011.  For instance both the 2012 Wall Street Journal article and the fact that PEF/Duke would not make a decision to repair or retire sometime during 2011, is not a fact that was known or reasonably knowable in 2011.  PCS Phosphate refers to facts within their arguments as they are known now, not as they were known in 2011.  Staff noted that PCS Phosphate did accurately reflect that during March 2011, after the second “delamination event,” uncertainty concerning the future of the Uprate project changed.

Based on a review of the record and argument derived from the briefs offered by intervenors in this docket, no evidence was identified that directly challenged the prudence of any specific costs that PEF incurred in 2011 on the CR3 Uprate project.  The only record evidence staff could identify supports a conclusion that PEF appropriately downscaled project activities and resulting costs in 2011 while PEF re-evaluated the containment building repair activities for the CR3 Unit (see discussion of witness Franke’s testimony above or as presented in Issue 13).  Moreover, staff notes that OPC witness Jacobs, and OPC in its brief, confirm and applaud PEF’s actions in scaling back its 2011 historical expenditures.  In addition, staff did not identify any evidence presented by the intervenors which showed that any specific costs or activities PEF undertook in 2011 was unneeded, avoidable, or should have been reasonably deferred until another period. 

Staff believes that PEF has demonstrated that its decisions and actions concerning the CR3 Uprate project where reasonable in light of the uncertainties known to management in 2011 that were affecting the project.  Therefore, staff believes the costs incurred due to PEF’s decisions and actions during 2011 should be considered prudent.

CONCLUSION

Staff recommends that the Commission find actual CR3 Uprate project expenditures were prudently incurred and expended in 2011 even in the absence of a final decision to repair or retire Crystal River Unit 3.

 

 

Issue 15: 

 What system and jurisdictional amounts should the Commission approve as PEF's 2011 prudently incurred costs and final true-up amounts for the Crystal River Unit 3 Uprate Project?

Recommendation: 

 Staff recommends the Commission approve the following amounts as prudently incurred 2011 CR3 Uprate project costs: capital costs $49,049,270 ($43,648,799 jurisdictional, net of joint owners), O&M costs $498,775 ($461,200 jurisdictional, net of joint owners), carrying costs $16,127,875 and a base revenue requirement credit of $3,346,641.  The resulting final 2011 true-up amount of $3,498,125 should be used in determining the 2013 Nuclear Cost Recovery Clause recovery amount. (Laux, Lawson)

Position of the Parties

PEF: 

 Capital Costs (System) $49,049,270; (Jurisdictional, net of joint owners) $43,648,799.  O&M Costs (System) $498,775; (Jurisdictional, net of joint owners) $461,200.  Carrying Costs $16,127,875 and a base revenue requirement credit of $3,346,641.

The under-recovery of $3,498,125 should be included in setting the allowed 2013 NCRC recovery.  The 2011 variance is the sum of an O&M under-projection of $461,276, under-projection of carrying charges of $3,207,094 and an over-projection of other adjustments of $170,245.

OPC: 

 None.  Until a final decision to repair or retire has been implemented, the Commission should defer consideration of approval of PEF’s 2011 requested costs and final true-up amounts for the Crystal River Unit 3 Uprate project.  However, should the Commission decide not defer the determination of prudence on 2011 expenditures, then the portion, if any, of EPU expenditures that could have been deferred or delayed or avoided, but were not, should be reduced from the system and jurisdictional amount being requested.

SACE: 

 Agree with OPC.

FIPUG: 

 No.  Until a final decision has been made to repair Crystal River 3 (if that is the final decision), it is imprudent to spend money on an uprate that may never occur.  The Commission should defer all prudence and reasonableness determinations and all cost recovery until it knows whether Crystal River 3 will be repaired or retired.

PCS Phosphate: 

 $0.  Due to Progress’ inability to demonstrate the continued feasibility of the CR3 Uprate, the Commission lacks sufficient evidence to find that all of the actual Crystal River Unit 3 Uprate project expenditures were prudently incurred.

FEA: 

 Agree with FIPUG.

FRF: 

 No.  Until a final decision to repair or retire has been implemented, the Commission should defer approval of PEF’s requested 2011 costs and true-up amounts.

Staff Analysis: 

 This issue addresses PEF’s request concerning the final 2011 prudent costs and true-up amounts for the CR3 Uprate project.  Staff notes that resolution of Issues 13 and 14 may impact the Commission’s decision on this issue.  As also noted in Issue 13, the determination of prudence is a review of what a reasonable utility manager would have done in light of the facts that were known or were reasonably knowable at the time the decision(s) were made.  Accordingly, Commission staff is limiting its discussion and analysis to the facts in the record related to 2011.

PARTIES’ ARGUMENTS

As argued in the prior two issues, OPC asserted that absent PEF implementing a final decision to proceed with a repair of the CR3 containment building, the Commission should defer allowing recovery of any CR3 EPU costs until after the 2012 hearing cycle.  OPC further argued that should the Commission decide not to defer the determination of prudence on 2011 expenditures, then the portion, if any, of EPU expenditures that could have been deferred or delayed or avoided, but were not, should be reduced from the system and jurisdictional amounts being requested. (OPC BR 23)  SACE joined OPC in this position. (SACE BR 12)

As discussed in Issue 13, FIPUG argued that PEF should not be allowed to fully recover all monies it spends on the Crystal River Unit 3 Uprate project, given the uncertainty as to whether the Crystal River nuclear power plant will ever operate again.  FIPUG asserted that the Uprate project has no value if the Crystal River 3 Unit is not repaired and operating.  FIPUG argued that PEF has failed to show that continuing to make expenditures after the second delamination event, or after the third delamination event, were prudent. (FIPUG BR 1-2, 5)  FEA joined FIPUG in this position.  (FEA BR 5)

As discussed in Issue 14, PCS Phosphate asserted that PEF cannot establish that the CR3 Uprate project is feasible until a repair decision is made.  Lacking this showing of feasibility, PCS Phosphate argued that the Commission lacks sufficient evidence to find that any CR3 Uprate project expenditures were prudently incurred; therefore, recovery of any CR3 Uprate costs should be denied in 2013. (PCS Phosphate BR 8-9)

FRF agreed with the Citizens and generally restated its position which was discussed in Issue 13. (FRF BR 2, 7-8)

ANALYSIS

Staff notes that this issue is similar to that argued in Issue 13, but has as its focus the prudence of costs incurred for the CR3 Uprate project in 2011, as compared to the prudence of management decisions made by PEF for the Uprate project during 2011.  

PEF witness Garrett provided testimony concerning PEF’s final actual costs and expenditures made for the CR3 Uprate project in 2011. (TR 228-230; EXH 3)  Witness Garrett stated that the data supporting the information presented in Exhibit 3 were taken from PEF’s books and records that are kept in accordance with generally accepted accounting principles and practices, provisions of the Uniform System of Accounts, and other accounting rules and orders as established by the Commission. (TR 229)

From Exhibit 3, witness Garrett identified the 2011 CR3 Uprate project costs PEF believes were prudently incurred.  These amounts include: capital costs $49,049,270 ($43,648,799 jurisdictional, net of joint owners), O&M costs $498,775 ($461,200 jurisdictional, net of joint owners), carrying costs $16,127,875, and a base revenue requirement credit of $3,346,641. (TR 225-230, 235-237)

PEF witness Franke also provided testimony concerning PEF’s actual costs incurred during 2011 for the CR3 Uprate project. (TR 566-579)  Witness Franke stated that PEF reasonably and prudently incurred the 2011 CR3 Uprate project costs which were necessary for the continuation of work for the EPU phase, and that PEF’s 2011 CR3 Uprate project costs were reasonably and prudently incurred. (TR 578)

The final 2011 CR3 Uprate project costs were compared to prior Commission-approved recovery amounts to determine the net final true-up amount for 2011 as a $3,498,125 under recovery. (EXH 3)  Witness Garrett stated that this amount should be approved as reasonable and prudent since it was calculated in accordance with Rule 25-6.0423, F.A.C.

The requested final CR3 Uprate project 2011 true-up is the summation of the following components: $461,276 under projection of O&M costs, a $3,207,094 under projection of carrying costs, and a $170,245 over projection of other adjustments. (EXH 3, TR 225-230)

Commission staff accounting audit witness Small provided testimony and sponsored the staff’s 2012 accounting audit report of 2011 CR3 Uprate project costs.  As noted in this testimony, the staff’s audit activities included reconciliation and verification of 2011 project costs to the general ledger, monthly accurual balances and the Company’s filing in the 2012 NCRC Docket. (TR 720-724; EXH 27)  As noted from his testimony, witness Small responded to a question of whether there were any audit findings concerning the CR3 Uprate project:

Yes, Audit Finding No. 1 provides information on legal costs included as recoverable O&M expenditures on Schedule T-4 of the filing that the Company states will be removed by posting a journal adjustment in April 2012 that will reduce next years Schedule T-4 filing by $12,683 ($11,716 jurisdictional).

(TR 724)

Staff notes that witness Small identified no other findings in his audit report concerning CR3 Uprate project costs in 2011.

Commission staff audit witnesses Coston and Hallenstein reviewed PEF’s project management, accounting, and related controls in their 2012 audit report on the Crystal River Unit 3 Uprate and the Levy Nuclear projects.  Witnesses Coston and Hallenstein stated in their pre-filed testimony:

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

(TR 549)

Staff’s review of witnesses Coston’s and Hallenstein’s report (EXH 25) revealed no recommendations or identified issues concerning CR3 Uprate project management or project controls.  Witnesses Coston and Hallenstein confirmed this by stating during the summary of their testimony that they: “. . . had no specific recommendations concerning the company’s project management internal controls employed by both projects for the current period.” (TR 533)

As in Issue 13, witness Franke presented testimony concerning PEF’s management and project based actions concerning the CR3 Uprate project during 2011.  These actions are the basis for costs that were incurred during 2011. (TR 637-639)  In addition to his testimony, witness Franke was also cross-examined in detail by the intervenors concerning PEF’s management decisions, actions, and whether any costs associated with contracts for the CR3 Uprate project during 2011 could have been avoided or deferred. (TR 659-716) 

PEF argued in its brief:

As explained by Mr. Franke, subsequent to the March 2011 delamination, PEF evaluated the CR3 Uprate project work and determined that the reasonable course of action was to take steps to preserve the Company’s ability to complete the CR3 Uprate in the current CR3 outage, without unnecessarily incurring costs for the project in 2011, while assessments regarding the potential repair off the CR3 containment building continued.  PEF prudently minimized CR3 Uprate costs in 2011 to ensure that only those costs necessary to continue with the CR3 Uprate project if CR3 was repaired were incurred until a final decision to repair CR3 is made.

(PEF BR 28)

PEF further asserted that “Dr. Jacobs [the only intervenor witness to address CR3 issues] did not testify that any historical, 2011 CR3 Uprate costs were unnecessary for the project or otherwise imprudently incurred.  The evidence, then, is undisputed that PEF’s 2011 CR3 Uprate project costs were prudently incurred.” (PEF BR 29)

The position of the intervenors that the Commission should defer all prudence and reasonableness determinations and cost recovery until it knows whether Crystal River Unit 3 will be repaired or retired was addressed in Issue 13.  In that issue, staff recommended that there is sufficient evidence in the record to allow a thorough review of the decisions PEF’s managers made during 2011, thereby allowing the Commission to make a determination concerning the prudence of 2011 CR3 Uprate project activities and costs.

Alternatively, the intervenors also argued in Issues 13 and 14, that if the Commission decides not to defer the determination of prudence on 2011 expenditures, then the portion, if any, of EPU expenditures that could have been deferred, delayed, or avoided, but were not, should be reduced from the system and jurisdictional amount being requested.  In those issues, staff stated that PEF demonstrated its decisions and actions concerning the CR3 Uprate project were reasonable in light of the uncertainties affecting the project that were known to management in 2011 and, no evidence was identified by the intervenors that any specific CR3 Uprate project cost or activity incurred or undertaken in 2011 by PEF was shown to be unneeded, avoidable, or could have been reasonably deferred.

The concern presented by intervenors that PEF cannot establish that the CR3 Uprate project is feasible until a repair decision is made; therefore, the Commission lacks sufficient evidence to find that any CR3 Uprate project expenditures were prudently incurred, was addressed in Issue 14.  In that issue, staff concluded the intervenors’ arguments concerning prudence was an improper application of the standard that is employed by the Commission.

Staff notes that no other concerns were identified by the parties on this issue.

Consistent with staff’s recommendations in Issues 13 and 14, verification of PEF’s calculations and true-up amounts, and a preponderance of the evidence in the record, staff believes that PEF’s information was subjected to a reasonable level of review sufficient to determine the prudence of its 2011 CR3 Uprate project costs and true-up amounts.  Staff believes that PEF has demonstrated that the 2011 CR3 Uprate project costs, activities and final true-up as requested are reasonable and prudent.

CONCLUSION

Staff recommends the Commission approve the following amounts as prudently incurred 2011 CR3 Uprate project costs: capital costs $49,049,270 ($43,648,799 jurisdictional, net of joint owners), O&M costs $498,775 ($461,200 jurisdictional, net of joint owners), carrying costs $16,127,875 and a base revenue requirement credit of $3,346,641.  The resulting final 2011 true-up amount of $3,498,125 should be used in determining the 2013 Nuclear Cost Recovery Clause recovery amount.

 

 

Issue 17: 

 What system and jurisdictional amounts should the Commission approve as reasonably estimated 2012 costs and estimated true-up amounts for PEF's Crystal River Unit 3 Uprate project?

Recommendation: 

 Staff recommends the Commission find, as reasonable, the revised 2012 true-up of CR3 Uprate project recoverable costs in the amount of $6,186,144.  This amount should be used in determining the 2013 NCRC recovery amount.  (Laux)

Position of the Parties

PEF: 

 Pursuant to PEF’s Motion for Deferral approved by the Commission on September 5, 2012:

Capital costs (System) $0; (Jurisdictional, net of joint owners) $0.  O&M costs (System) $0; (Jurisdictional, net of joint owners) $130.  Carrying costs $19,041,421 and a base revenue requirement credit of $3,242,310.

The Commission should also approve an estimated 2012 EPU project true-up under-recovery of $6,186,144 to be included in setting the allowed 2013 NCRC recovery.  The 2012 variance is the sum of an O&M under-projection of $840, plus an under-projection of carrying charges of $6,165,675 plus an over-projection of other adjustments of $19,629.

OPC: 

 None.  Absent PEF implementing a final decision to proceed with a repair, the Commission should defer consideration of recovery of any CR3 EPU costs until after the 2012 hearing cycle. If the Commission nevertheless proceeds, OPC asserts cost recovery should not exceed the amounts minimally needed to fulfill contractual or other obligations required to keep the uprate project viable for a repaired CR3.

SACE: 

 Agree with OPC.

FIPUG: 

 This is a fall out issue.

PCS Phosphate: 

 Progress has failed to demonstrate that the Crystal River Unit 3 Uprate project remains feasible and thus the Commission lacks sufficient evidence to find that all of the actual Crystal River Unit 3 Uprate project expenditures were prudently incurred.

FEA: 

 Agree with OPC.

FRF: 

 None.  The Commission should defer consideration of allowing recovery of any CR3 Extended Power Uprate costs until the 2013 NCRC hearings, and defer any possible recovery of CR3 EPU costs until at least 2014.

Staff Analysis: 

 This issue addresses PEF’s revised request concerning the reasonableness of the 2012 estimated true-up amount for the CR3 Uprate project.  Staff notes the Commission’s decision on this issue may be affected by decisions in Issues 13, 14 and 15.

 

PARTIES’ ARGUMENTS

PEF stated that its requested recovery of revised projected CR3 Uprate costs is consistent with the requirements of the Motion to Defer which was approved by the Commission on September 5, 2012. (PEF BR 31)  PEF asserts that the Commission cannot legally deny the recovery of carrying costs if the Commission finds the underlying construction costs were prudently incurred. PEF argued that the evidence conclusively demonstrates PEF prudently incurred its actual 2011 CR3 Uprate project costs.  Therefore, PEF argued the Commission cannot disallow the recovery of carrying costs on prudently incurred capital expenditures. (PEF BR 3)

As it argued in prior CR3 issues, OPC asserted that absent PEF implementing a final decision to proceed with a repair of the CR3 containment building, the Commission should defer allowing recovery of any CR3 EPU costs until after the 2012 hearing cycle.  OPC also argued that if the Commission nevertheless allows cost recovery, recovery should not exceed the minimal amount needed to fulfill contractual or other obligations required to keep the uprate project viable for a repaired CR3. (OPC BR 23)  SACE and FEA joined OPC in this position. (SACE BR 12; FEA BR 5)

From their stated position in prior CR3 issues, PCS Phosphate asserted that PEF failed to demonstrate the CR3 Uprate project remains feasible; thus, the Commission lacks sufficient evidence to find that any or all of the CR3 Uprate project expenditures were prudently incurred. (PCS Phosphate BR 4-9)

FIPUG stated that this is a fall-out issue. (FIPUG BR 6)

As argued in proceeding issues, FRF asserted that until the repair/retire decision has been made, the Commission should withhold any determination of reasonableness of costs or prudence of expenditures for the CR3 EPU project, and correspondingly defer its consideration of any CR3 EPU expenditures for cost recovery. (FRF BR 2, 8)

ANALYSIS

Staff notes that the information presented in this issue is based on data contained in the revised filing offered by PEF on September 7, 2012.  This revision was offered to reflect adjustments to PEF’s original request and filing pursuant to the Commission’s approval, on September 5, of the Motion to Defer.  From this motion, PEF requested that the Commission defer, until the 2013 Nuclear Cost Recovery Clause docket, its review of estimated 2012 and projected 2013 new capital expenditures and associated cost for the CR3 Uprate project.

PEF witness Foster provided support for the activities and method of calculations used to determine the requested 2012 revised recovery amounts. (TR 302-309, EXH 7)  As noted above, witness Foster offered revised testimony, covering the same subject matter as his original testimony but incorporating the requirements of the approved Motion to Defer. (TR 319-322)  Witness Foster stated that the schedules provided with his revised testimony were true and accurate and filed in accordance with requirements of the Nuclear Cost Recovery Clause and other rules and orders approved by the Commission, including any requirements from the Settlement Agreement that was approved by the Commission in Docket No. 120022-EI. (TR 304, 319-322)

PEF witness Franke identified estimated project costs and provided descriptions of CR3 Uprate 2012 activities. (TR 593-615)  Since PEF is not requesting recovery, at this time, of any new (2012 or 2013) capital expenditures that are estimated to be incured on the CR3 Uprate project in 2012, a detailed description and understanding of these activities is not necessary to make a determination of the reasonableness of the remaining project cost amounts that are being requested for recovery.

On Exhibit 7, witness Foster identified the revised 2012 estimated CR3 Uprate project costs PEF believes were reasonably incurred or estimated. Witness Foster stated the amounts shown are consistent with the requirements of the Motion to Defer. (TR 319)  These costs include: capital costs of $0 ($0 jurisdictional, net of joint owners), O&M expenses of $0 ($130 jurisdictional, net of joint owners), carrying costs of $19,041,421, and a base revenue requirement credit of $3,242,310.  As shown on Exhibit 7, the requested carrying cost amount was calculated by applying the statutory carrying charge to the average balance of unrecovered capital expenditures that were incurred prior to 2012.

On Exhibit 7, witness Foster presents PEF’s revised 2012 true-up amount for the CR3 Uprate project for which PEF is requesting recovery.  As shown within this exhibit, PEF is requesting that the Commission find as reasonable, an estimated 2012 true-up amount for the CR3 Uprate project in the amount of $6,186,144 under recovery. (TR 322)  This amount is comprised of: O&M under projection of $840, an under projection of carrying charges of $6,165,675, plus an over projection of other adjustments of $19,629. (TR 322, EXH 7)

In reviewing the positions of the parties in this issue, staff notes that no specific 2012 costs that PEF is requesting recovery of were identified as unreasonable.  The parties’ positions on this issue are restatements or carryover positions as argued in Issues 13, 14, and 15 and focused on the collectability of recovery in 2013 as compared to the reasonableness of any amount that is being requested to be recovered for 2012.

Consistent with staff’s recommendations in prior issues, staff’s verification of PEF’s calculations and estimations, and the preponderance of evidence in the record, staff believes that PEF has demonstrated the reasonableness of it revised estimated 2012 CR3 Uprate project true-up recovery amounts.

CONCLUSION

Staff recommends the Commission find, as reasonable, the revised 2012 true-up of CR3 Uprate project recoverable costs in the amount of $6,186,144.  This amount should be used in determining the 2013 Nuclear Cost Recovery Clause recovery amount.

 

Issue 18: 

 What system and jurisdictional amounts should the Commission approve as reasonably projected 2013 costs for PEF's Crystal River Unit 3 Uprate project?

Recommendation: 

 Staff recommends the Commission find, as reasonable, the revised projected 2013 CR3 Uprate project recoverable costs in the amount of $30,349,407.  This amount should be used in determining the 2013 Nuclear Cost Recovery Clause recovery amount.  (Laux)

Position of the Parties

PEF: 

 Pursuant to PEF’s Motion for Deferral approved by the Commission on September 5, 2012:

Capital Costs (System) $0; (Jurisdictional, net of joint owners) $0.  O&M Costs (System) $0; (Jurisdictional, net of joint owners) $173.  Carrying Costs $30,352,822 and a base revenue requirement credit of $3,587.

OPC: 

 None.  Absent PEF implementing of a final decision to proceed with a repair, the Commission should defer allowing recovery of any CR3 EPU costs until after the 2012 hearing cycle. If the Commission nevertheless proceeds, OPC asserts cost recovery should not exceed the amounts minimally needed to fulfill contractual or other obligations required to keep the uprate project viable for a repaired CR3.

SACE: 

 Agree with OPC.

FIPUG: 

 This is a fall out issue.

PCS Phosphate: 

 Progress has failed to demonstrate that the Crystal River Unit 3 Uprate project remains feasible and thus the Commission lacks sufficient evidence to find that all of the actual Crystal River Unit 3 Uprate project expenditures were prudently incurred.

FEA: 

 Agree with OPC.

FRF: 

 None.  The Commission should defer consideration of allowing recovery of any CR3 Extended Power Uprate costs until the 2013 NCRC hearings, and defer any possible recovery of CR3 EPU costs until at least 2014.

Staff Analysis: 

 This issue addresses PEF’s revised request concerning the reasonableness of 2013 projected amounts for the CR3 Uprate project.  Staff notes the Commission’s decision on this issue may be affected by decisions in Issues 13, 14 and 15.

PARTIES’ ARGUMENTS

PEF stated that its requested recovery of revised projected CR3 Uprate costs is consistent with the requirements of the Motion to Defer which was approved by the Commission on September 5, 2012. (PEF BR 31)  PEF asserted that the Commission cannot legally deny the recovery of carrying costs if the Commission finds the underlying construction costs were prudently incurred. PEF argued that the evidence conclusively demonstrates PEF prudently incurred its actual 2011 CR3 Uprate project costs.  Therefore, PEF argued the Commission cannot disallow the recovery of carrying cost on prudently incurred capital expenditures. (PEF BR 3)

As it argued in preceding issues, OPC asserted that absent PEF implementing a final decision to proceed with a repair of the CR3 containment building, the Commission should defer allowing recovery of any CR3 EPU costs until after the 2012 hearing cycle.  OPC also argued that if the Commission nevertheless does allow cost recovery, recovery should not exceed the minimal amount needed to fulfill contractual or other obligations required to keep the uprate project viable for a repaired CR3. (OPC BR 23)  SACE and FEA joined OPC in this position. (SACE BR 12; FEA BR 5)

PCS Phosphate also restated its position from prior CR3 issues by asserting that Progress failed to demonstrate the CR3 Uprate project remains feasible, thus, the Commission lacks sufficient evidence to find that any of the CR3 Uprate project expenditures were prudently incurred. (PCS Phosphate BR 4-9)

FIPUG stated that this is a fall-out issue. (FIPUG BR 6)

As argued in preceding issues, FRF asserted that until the repair/retire decision has been made, the Commission should withhold any determination of reasonableness of costs or prudence of expenditures for the CR3 EPU project, and correspondingly defer its consideration of any CR3 EPU expenditures for cost recovery. (FRF BR 2, 8)

ANALYSIS

Staff notes that the information presented in this issue is based on data contained in the revised filing offered by PEF on September 7, 2012.  This revision was offered to reflect adjustments to PEF’s original request and filing pursuant to the Commission’s approval, on September 5, of the Motion to Defer.  From this motion, PEF requested that the Commission defer, until the 2013 Nuclear Cost Recovery docket, its review of estimated 2012 and projected 2013 new capital expenditures and associated cost for the CR3 Uprate project.

PEF witness Foster provided support for the activities and method of calculations used to determine the requested 2013 revised recovery amounts. (TR 322-325)  As noted above, witness Foster offered revised testimony, covering the same subject matter as his original testimony but incorporating the requirements of the approved Motion to Defer. (TR 319-325)  Witness Foster stated that the schedules provided with his revised testimony were true and accurate and filed in accordance with requirements of the Nuclear Cost Recovery Clause and other rules and orders approved by the Commission, including any requirements from the Settlement Agreement that was approved by the Commission in Docket No. 120022-EI. (TR 304, 319-325)

PEF witness Franke identified projected project costs and provided descriptions of planned 2013 activities for the CR3 Uprate. (TR 593-615)  Since PEF is not requesting recovery, at this time, of any new (2012 or 2013) capital expenditures that it projects to incur in 2013, a detailed description and understanding of these activities is not necessary to make a determination of the reasonableness of the remaining CR3 Uprate project cost amounts that are being requested for recovery.

On Exhibit 8 witness Foster identified the revised 2013 projected CR3 Uprate project costs PEF believes were reasonably forecasted and consistent with the requirements of the Motion to Defer.  These costs include: capital costs of $0 ($0 jurisdictional, net of joint owners), $0 O&M expense ($173 jurisdictional, net of joint owners), carrying costs of $30,352,822, and a base revenue requirement credit of $3,587.  As shown on Exhibit 8, the requested carrying costs amount was calculated by applying the statutory carrying charge to the average balance of unrecovered capital expenditures incurred prior to 2012, in addition to carrying charges on the regulatory asset (Rate Management Plan). (TR 323)

On Exhibit 8, witness Foster presented PEF’s revised projected 2013 CR3 Uprate project costs for which they are requesting recovery.  As shown within this exhibit, PEF is requesting that the Commission find as reasonable, projected 2013 CR3 Uprate costs in the amount of $30,349,407. (TR 323)

In reviewing the positions of the parties in this issue, staff notes that no specific 2012 costs PEF is requesting recovery of were identified as unreasonable.  The parties’ positions on this issue are restatements or carryover positions as argued in Issues 13, 14, and 15 and focused on the collectability of recovery in 2013 as compared to the reasonableness of any amount that is being requested to be recovered for 2013. 

Consistent with staff’s recommendations in those issues, staff’s verification of PEF’s calculations and projections, and the preponderance of evidence in the record, staff believes that PEF has demonstrated the reasonableness of its revised 2013 CR3 Uprate project recovery amounts.

CONCLUSION

Staff recommends the Commission find, as reasonable, the revised projected 2013 CR3 Uprate project recoverable costs in the amount of $30,349,407.  This amount should be used in determining the 2013 Nuclear Cost Recovery Clause recovery amount.

 

 

 

Issue 19: 

 What is the total jurisdictional amount to be included in establishing PEF's 2013 Capacity Cost Recovery Clause factor?

Recommendation: 

 Staff recommends that for the CR3 Uprate project, the Commission approve a total jurisdictional amount of $40,033,676 to be included in the Capacity Cost Recovery Clause factor for collection in 2013.  For the Levy project, the amount to be collected in the 2013 Capacity Cost Recovery Clause factor is the amount necessary to achieve the rates required pursuant to the Settlement Agreement as approved by Order No. PSC-12-0104-FOF-EI.  For future true-up purposes, the Commission should recognize $102,696,903 as the estimated 2013 Levy project Nuclear Cost Recovery Clause recovery amount. (Laux)

Position of the Parties

PEF: 

 Pursuant to PEF’s Motion for Deferral approved by the Commission on September 5, 2012:

For the CR3 Uprate project, $40,033,676 (before revenue tax multiplier) should be included in establishing PEF’s 2013 CCRC Factor.  Please see chart below for a further breakout of these costs.  For the LNP, an amount necessary to achieve the rates included in Exhibit 5 ($3.45/1,000kWh on the residential bill) of the Settlement Agreement in Order No. PSC-12-104-FOF-EI page 147 should be included in establishing PEF’s 2013 CCRC.

OPC: 

 The total jurisdictional amount will be a fall-out from other decisions.  Recovery should be confined to the LNP project subject to the settlement.  Recovery of CR3 EPU carrying costs should be deferred from consideration until 2013.

SACE: 

 The total jurisdictional amount will be a fall out from other decisions.  There should be no recovery of LNP related costs, as PEF has failed to demonstrate the requisite intent to build and as such is not engaged in the “siting, design, licensing, and construction” of the LNP.

FIPUG: 

 This is a fall out issue.

PCS Phosphate: 

 Agree with OPC.

FEA: 

 Agree with FRF.

FRF: 

 The total jurisdictional amount to be included in PEF’s 2013 Capacity Cost Recovery factor is the amount of LNP costs specified in the January 2012 Settlement Agreement between PEF and Consumer Parties approved by the Commission.

Staff Analysis: 

 This issue addresses the amount the Commission should establish for PEF’s 2013 Nuclear Cost Recovery Clause and the amount to be approved for collection through the 2013 Capacity Cost Recovery Clause factor.  Staff notes that in prior years, establishing the amount for the overall Nuclear Cost Recovery Clause was a fall-out process reflecting the summation of the Commission’s decisions on all issues presented in that year’s filing.  While this process is intact for establishing the 2013 recovery amount for the CR3 Uprate project, establishing the level for the Levy project has been affected by certain requirements contained within the Settlement Agreement approved in Docket No. 120022-EI.  Staff will address process impacts in this issue.

PARTIES’ ARGUMENTS

PEF asserted that its requested recovery levels are consistent with the requirements of the Settlement Agreement (as approved by Order No. PSC-12-0104-FOF-EI), and the Motion to Defer [as approved by the Commission on September 5, 2012].  PEF stated the Commission should (for the Levy project) establish an amount necessary to achieve the rates included on Exhibit 5 of the Settlement Agreement.  PEF further asserted the Commission should approve for collection, through the CCRC in 2013, an amount of $40,033,676 for the CR3 Uprate project.  PEF argued the Commission should approve these requested amounts since the requirements of Section 366.93, F.S., and Rule 25-6.0423, F.A.C., have been fulfilled and the request is consistent with the conditions in the approved Settlement Agreement and the accepted Motion to Defer.  In addition, PEF stated that the record in this case conclusively demonstrated that no credible dispute exists concerning the respective prudence issues or the reasonableness of any requested costs. (PEF BR 1)

Levy 2013 cost recovery arguments

From the post-hearing briefs of OPC, FIPUG, PCS Phosphate, FEA and FRF, staff notes these parties offered no arguments concerning PEF’s 2013 Levy project requested recovery amounts. (OPC BR 24; FIPUG BR 1; PCS Phosphate BR 1; FEA BR 5; FRF BR 2, 5)

As argued in preceding issues, SACE simply stated that PEF is not entitled to any Levy project cost recovery in 2013 since they failed to demonstrate the requisite intent to build or demonstrate that completion of the Levy project is feasible in the long term. (SACE BR 2-4)

CR3 Uprate cost recovery arguments

Concerning the CR3 Uprate project 2013 Nuclear Cost Recovery Clause request, as argued in prior issues, OPC asserted that PEF has not made a final decision to repair or retire the plant; therefore, the Commission should defer any prudence determination concerning this project.  OPC also argued that the Commission should defer collection of all CR3 Uprate project costs recovery until at least the 2013 Nuclear Cost Recovery Clause hearing cycle so as to protect customers from any further losses should Duke decide to retire the CR3 unit. (OPC BR 1-2)  Like OPC, SACE, FIPUG, FEA, and FRF restated their positions which were argued in prior issues. (SACE BR 12; FIPUG BR 2; FEA BR 5; FRF BR 2)

PCS Phosphate also restated its position from prior CR3 issues, stating that PEF cannot establish the CR3 Uprate project is feasible until a repair decision is made.  Given no showing of feasibility, PCS Phosphate argued that the Commission lacks sufficient evidence to find that any CR3 Uprate project expenditures were prudently incurred; therefore, recovery of any CR3 costs should be denied in 2013. (PCS Phosphate BR 8-9)

 

ANALYSIS

This issue is essentially a wrap up or fall-out issue as the differing concerns expressed by the parties are primarily addressed in Issues 4, 5, 8, 12, 13, 14, 15, 16 and 17.

Staff notes that for 2013, the approved Motion to Defer and Settlement Agreement affects and governs to some extent the scope, type, and amount of costs PEF’s can be authorized to recover through the capacity cost recovery clause in 2013. [See case background, pp 5-6]

As noted in the Case Background section, the Motion to Defer limits what costs PEF can include in it’s requested 2013 cost recovery amount for the CR3 Uprate project.  The Settlement Agreement also contains two main conditions which affect 2013 Levy project cost recovery.  Those conditions are: a method of calculation and limitation concerning the level of revenue that can be collected each year for the Levy project, and a requirement to true-up actual collected revenues from the capacity cost recovery clause to prudently incurred project costs at the conclusion of the agreement period.

Given the requirements/conditions of the Settlement Agreement and the Motion to Defer, staff notes that the Commission will need to address the following two questions:

·        What is the appropriate level of CR3 Uprate project cost recovery that should be included in the 2013 Capacity Cost Recovery Clause factor? (This part of the process is not different that what the Commission has done each year.)

·        What estimated level of Levy project cost recovery should be established for 2013 for the limited use of next year’s project cost true-up? (This part of the process is different that what the Commission has done in the past because there is no need for the Commission to approve an amount to be included in the 2013 Capacity Cost Recovery Clause factor for the Levy project, since that part of the factor has already been established through the approval of the Settlement Agreement; however, an estimated amount needs to be established for ongoing project costs true-up purposes.)

CR3 Uprate Project Cost 2013 Recovery Level

Pursuant to the approved Motion to Defer, PEF modified its 2013 requested cost recovery for the CR3 Uprate project to include only new expenditures and costs incurred in 2011, and recovery of costs associated with capital expenditures that were found to have been prudently incurred in prior dockets.  PEF’s modified request establishes a 2013 recovery amount of $40,033,676 for the CR3 Uprate project, which has been requested to be included for collection in the 2013 Capacity Cost Recovery Clause factor. (PEF BR 31-32; EXH 8) 

The net $40,033,676 amount represents current balances of statutory carrying charges that have accrued on CR3 Uprate costs prudently incurred prior to 2012 and reflects $0 for new capital expenditures in 2012 and 2013. (TR 321)  As stated by witness Foster, the requested recovery amount includes the Motion to Defer’s required treatment of new 2012 and 2013 CR3 Uprate capital expenditures and is made up of the following amounts: a 2011 final true-up of $3,498,125, a 2012 estimated true-up of $6,186,144, and a 2013 projected amount of $30,349,407. (TR 230, 319-325)

Levy Project 2013 Estimated Recovery Level

As staff noted, the Commission need not make a decision on the dollar amount to be included in the 2013 Capacity Cost Recovery Clause factor for the Levy project, since one of the requirements contained in the approved Settlement Agreement established the factors to be applied to actual sales each year by class of service.  For example and informational purposes, applying the fixed factor shown for the residential class of service on Exhibit 5, of the Settlement Agreement, will produce $3.45 of revenues per 1000 kWh sold.

However, since the application of the Settlement Agreement causes a temporary disconnect between the level of revenues which are authorized to be collected through the capacity cost recovery clause  for the Levy project and those project costs that are incurred each year (which would normally become the amount of revenues available for recovery through the capacity cost recovery clause), the Commission will still need to establish an “estimated” annual recovery amount to be used only within the NCRC project cost true-up process during each year the Settlement Agreement is in effect.  Staff notes that the annual NCRC true-up process is still needed to establish actual project account balances from year to year.  The true-up process that is required under the terms of the Settlement Agreement is a different process which requires a true-up of actual revenues collected during the term of the Settlement Agreement to actual project costs incurred during this same period.  This true-up process will take place at the end of the Settlement Agreement period.

Staff notes that the first step in the modified process to establish an annual “estimated” recovery level for the Levy project is summing the approved project cost recovery amounts from Levy project cost Issues 9, 10 and 11 of this recommendation.  This step is consistent with past NCRC process activities and results in an amount of $14,649,316, if staff’s recommendations are approved from prior issues.  The amount includes: a 2011 final true-up of $12,649,655 over recovery (Issue 9), a 2012 estimated true-up of $13,013,480 over recovery (Issue 10), and a 2013 projection of $40,312,451 (Issue 11). (TR 229-230, 309-314)

The next step in this modified process is to compare the potential Commission-approved direct project recovery amount (taken from prior issues) and comparing that amount to an estimate of the revenues which may be collected when applying the fixed factors to actual sales that will occur in 2013.  To estimate this revenue amount, witness Foster offered the following in his direct testimony:

PEF calculated the estimated revenue requirement by applying the rates in Exhibit 5 of the Settlement to the sales forecast shown on Exhibit TGF-2 to generate the projected revenues for 2013.  As can be seen in Schedule P-8 in column 2, this amount is $102.8 million [$102,696,903 before expansion for taxes].

(TR 316)

Comparing the pre-tax estimated revenue to project costs available for recovery in 2013, results in a difference or potential over recovery of $88,047,587 [$102,696,903 the estimated potential revenues in 2013 minus $14,649,316 of Levy project 2013 cost recovery].

In an effort to minimize differences like the one noted above or minimize any other cost impacts on the required annual true-up process, witness Foster offered the following revenue assignment routine (offered to address the difference between actual project costs and revenues estimated to be collected) for Commission consideration:

In order to effectively track different cost categories and for ease of administration, PEF will apply the agreed upon collection amount to the various costs in the following manner:

·        First to recovery of carrying costs on any regulatory assets, unamortized preconstruction costs, or construction costs balances,

·        Second to any prior period over/under recovery,

·        Third to O&M costs,

·        Fourth to current period preconstruction investment,

·        Fifth to prior period unrecovered preconstruction costs and

·        Sixth to construction cost investment.

(TR 317)

Witness Foster further stated:

To the extent there are differences, the difference will be applied to the last bucket of costs we are assigning revenue to which in this case would be the preconstruction balance from prior to 2013 (unrecovered regulatory asset balance).

(TR 317)

Staff notes the unrecovered regulatory asset (identified by witness Foster) is what has been previously referred to within the Nuclear Cost Recovery Clause as the “Rate Management Plan.”  This regulatory asset is made up of costs the Commission approved eligible for cost recovery but, to date, has not been included in any annual recovery amount for actual collection.

In reviewing this request, staff agrees with PEF that it is appropriate, this year, to credit the regulatory asset for the $88,047,587, which is the estimated difference between direct project cost recovery items and the estimated revenues that may be collected in 2013.  Staff believes this action is appropriate since the estimated unrecovered balance of the regulatory asset, at year-end 2012, will be approximately $117 million. (EXH 4)  Reducing the uncollected balance of this regulatory asset will have the effect of lowering associated carrying costs in future years.

While staff does not take issue with witness Foster’s proffered revenue assignment process for purposes of estimating the 2013 capacity cost recovery amount, staff does not recommend that the Commission adopt this process going forward.  Staff notes there are bound to be differences between the revenues collected due to the Settlement Agreement and actual project costs that are incurred in any given year.  Since these differences can be either positive or negative, the use of the step-wise process offered by witness Foster may or may not be the most efficient or appropriate means to address all future situations.  Staff suggests that a case-by-case review of any future assignments or allocations of revenues PEF may need to make will not impose an undue burden on the parties or the process.  As such, staff believes the adoption of the revenue assignment routine offered by witness Foster is unnecessary.

Estimated Total 2013 Recovery Amount

Consistent with staff’s recommendation on all prior issues, staff believes that PEF has met the requirements of Rule 25-6.0423, F.A.C., and supported its requested cost recovery amounts for 2013.  Staff recommends that the Commission approve for the CR3 Uprate project a jurisdictional amount of $40,033,676 to be included in the Capacity Cost Recovery Clause factor for collection in 2013.  For the Levy project, the amount to be collected in the 2013 Capacity Cost Recovery Clause factor is the amount necessary to achieve the rates required pursuant to the Settlement Agreement approved by Order No. PSC-12-0104-FOF-EI.  Consequently, for future true-up purposes, the Commission should recognize $102,696,903 as the estimated 2013 Levy project recovery amount.  The amounts supported by each of the parties on prior issues are shown below.

Table 19-1:  PEF’s Net 2013 Nuclear Cost Recovery Clause Amount

 

CONCLUSION

Staff recommends that for the CR3 Uprate project, the Commission approve a total jurisdictional amount of $40,033,676 to be included in the Capacity Cost Recovery Clause factor for collection in 2013.  For the Levy project, the amount to be collected in the 2013 Capacity Cost Recovery Clause factor is the amount necessary to achieve the rates required pursuant to the Settlement Agreement as approved by Order No. PSC-12-0104-FOF-EI.  For future true-up purposes, the Commission should recognize $102,696,903 as the estimated 2013 Levy project Nuclear Cost Recovery Clause recovery amount.

 

 

Issue 20: 

 Do FPL's activities since January 2011 related to Turkey Point Units 6 & 7 qualify as "siting, design, licensing, and construction" of a nuclear power plant as contemplated by Section 366.93, F.S.?

Recommendation: 

 Yes.  Staff recommends the Commission find that FPL’s activities since January 2011 related to Turkey Point Units 6 & 7 qualify as “siting, design, licensing, and construction” of a nuclear power plant as contemplated by Section 366.93, F.S.  (Garl, Breman)

Position of the Parties

FPL: 

 Yes.  FPL is conducting activities and incurring expenses necessary to obtain the license, permits, and approvals to develop Turkey Point 6 & 7 consistent with the intent of Section 366.93, F.S., to promote investment in nuclear power plants.  Because FPL has received a determination of need for Turkey Point 6 & 7 pursuant to Section 403.519(4), F.S., FPL is entitled to recover all prudently incurred costs including, but not limited to, those associated with siting, design, licensing, and construction.  FPL’s “intent to build” Turkey Point 6 & 7, as that phrase was used by the Commission in 2010 (it is not a statutory requirement), is evident in the actions it is taking to develop Turkey Point 6 & 7.

OPC: 

 No position.

SACE: 

 No.  FPL’s activities since January 2011 fail to demonstrate the requisite intent to build TP 6 & 7.  FPL remains focused solely on obtaining a COL from the NRC to create the option to build TP 6 & 7 should it become feasible in the future.  Section 366.93, Fla. Stat. and Commission precedent do not contemplate such an approach.  As a result, FPL is not engaged in the “siting, design, licensing, and construction” of TP 6 & 7, and is not eligible for recovery of costs related to TP 6 & 7.

FIPUG: 

 No position at this time.

FEA: 

 No position.

FRF: 

 No position on this issue as stated.  The FRF does not oppose FPL’s recovery of limited licensing costs for Turkey Point 6 & 7 at this time.

Staff Analysis:  The dispute in this issue is whether FPL’s Turkey Point Units 6 & 7 project activities preclude FPL from the alternative regulatory treatment under Section 366.93, F.S.

 

PARTIES’ ARGUMENTS

FPL

In its brief, FPL argued that the Commission has twice addressed similar issues.  FPL asserted that in 2010, the Commission specifically evaluated what types of activities qualify as siting, design, licensing, and construction when it determined that the licensing costs PEF was incurring for its new nuclear project were recoverable.[36]  FPL noted that intervenors in that case had questioned whether PEF would build the new nuclear facility.  FPL contended that the Commission found that a utility need not be engaged in actual construction in order for its costs to be recoverable.[37] (FPL BR 14)  FPL also asserted that in 2011, the Commission determined that FPL’s Turkey Point Units 6 & 7 project activities and resultant costs qualified as recoverable preconstruction costs as defined in Section 366.93(1)(f), F.S., and demonstrated FPL’s intent to build.[38]  (FPL BR 15)

FPL asserted it is still actively pursuing the license, permits and approvals necessary to create the opportunity to complete the Turkey Point Units 6 & 7 Project. (TR 766-770, 789-792, 805-806, 809, 828-829, 870-871, 876).  FPL stated it also entered into a forging reservation agreement with Westinghouse Electric Company to secure manufacturing capacity for ultra-heavy forgings to support the project's original schedule. (TR 829)  FPL contended that that agreement, through ongoing negotiations, continued to be in place with modifications that reflect revised in-service dates. (TR 760, 794, 878, 885-886)  FPL asserted its project activities included installation of an underground injection control exploratory well at the project site.  (TR 789, 793-794, 800, 836, 839)  Additionally, FPL has been engaged in land exchange negotiations with multiple state and federal agencies concerning transmission facilities associated with the project. (TR 773-774, 794-795, 822, 841)  FPL also examined the reasonableness of its commercial in-service dates due to recent NRC review schedule revisions and concluded the dates remained achievable. (TR 827)

FPL witness Scroggs acknowledged it has not yet decided to initiate site preparation activities but was pursuing the necessary license, permits, and approvals. (FPL BR 15; TR 809)  Witness Scroggs also noted that FPL’s “approach provides the best opportunity to deliver the benefits of the project on the earliest practicable schedule.” (TR 809)  FPL argued in its brief that to maintain the current project schedule, substantial expenditures for construction are unnecessary at this time.  Instead, FPL asserted in its brief that it is taking the steps necessary to enable it to construct a nuclear power plant. (FPL BR 16-17)

SACE

SACE argued in its brief that “FPL’s activities since January of 2011 plainly demonstrate that FPL intends to do nothing more than obtain a Turkey Point Units 6 & 7 COL.”  (SACE BR 13)  SACE argued that FPL’s activities simply are not indicative of a utility who intends to build two new nuclear reactors. (SACE BR 14) 

SACE argued that FPL witness Scroggs characterized FPL’s activities as “creating the opportunity.” (TR 871)  SACE also opined that if FPL intended to build these units, and place them in service in 2022 and 2023, FPL would have expended far more funds to effectuate this intent.  (SACE BR 14) 

SACE argued in its brief that FPL’s activities plainly demonstrate that FPL continued to employ an “option creation” approach, where FPL’s only intent is to preserve the option to construct by obtaining the necessary licenses and approvals to operate new nuclear projects. (SACE BR 2, 14)  SACE concluded “[t]his options creation approach does not satisfy the intent to build requirement, as the statute, and the Commission’s interpretation of the same doesn’t contemplate such an approach.” (SACE BR 3) 

SACE asserted that because FPL failed to demonstrate the requisite intent to construct these proposed new nuclear projects, SACE concluded that FPL failed to demonstrate that the costs for which it requested recovery were reasonable and prudently incurred. (SACE BR 4, 20-21)

OPC and FRF

OPC, joined by FRF, did not contest FPL’s approach to, or expenses related to, the Turkey Point 6 & 7 Project at this time.  OPC opined that FPL is pursuing an approach that limits expenses to minimal licensing activities to the extent possible. (OPC BR 1; FRF BR 2)

FIPUG and FEA

Prior to hearing, FIPUG and FEA took “no position.”  Their respective post-hearing briefs did not discuss this issue and did not present a different position. (FIPUG BR 6; FEA BR 5)  Therefore, pursuant to the Prehearing Order, FIPUG and FEA have waived their positions on this issue.

ANALYSIS

Staff notes that none of the intervenors offered witness testimony addressing FPL’s Turkey Point Units 6 & 7 project activities.  From its brief, SACE’s discussion of FPL’s project activities is directed at the question of FPL’s intent to complete the project, not the prudence of any of FPL’s project activities.

As discussed in Issue 4, Section 366.93, F.S., provides for cost recovery for utilities engaged in the siting, design, licensing, and construction of nuclear power plants.  Within Order No. PSC-11-0095-FOF-EI, staff notes that the Commission interpreted and defined this statutory provision to include the building of new nuclear power plants and the modification of existing nuclear power plants.[39]  As discussed in this order, the main question to review when analyzing this issue is whether a utility must engage in the siting, design, licensing, and construction of nuclear power plant activities simultaneously in order to meet the statutory requirements of Section 366.93, F.S.

Section 366.93(1)(a), F.S., explains that “cost” includes, but is not limited to, all expenses related to or resulting from the activities of siting, licensing, design, construction, or operation of the nuclear power plant.  Furthermore, Section 366.93(1)(f), F.S., defines “preconstruction” as that period of time after a site has been selected through and including the date the utility completes site clearing work.  Rule 25-6.0423(2)(h), F.A.C., which implements Section 366.93(1)(f), F.S., provides:

Site selection costs and pre-construction costs include, but are not limited to: any and all costs associated with preparing, reviewing and defending a Combined Operating License (COL) application for a nuclear power plant; costs associated with site and technology selection; costs of engineering, designing, and permitting the nuclear or integrated gasification combined cycle power plant; costs of clearing, grading, and excavation; and costs of on-site construction facilities (i.e., construction offices, warehouses, etc.).

In reviewing this issue, staff took guidance from Order No. PSC-11-0095-FOF-EI.  At page 9 of this order, staff notes that the Commission found that a utility need not engage in the siting, design, licensing, and construction activities of a nuclear power plant simultaneously in order to meet the statutory requirements under Section 366.93, F.S.  As noted on page 11 of this order, the utility, however, must demonstrate through its actions an intent to build the nuclear power plant for which it seeks advance recovery of costs to be in compliance with Section 366.93 F.S.

In support of its position, FPL witness Scroggs described the Turkey Point Units 6 & 7 project activities as primarily focused on permitting and licensing efforts as well as planning for the next phase of the project. (TR 760, 765-766, 795, 814, 870-871, 805-808)

During 2011, the Turkey Point 6 & 7 project continued to make progress with licensing and permitting activities, and maintained costs well within the annual budget. FPL continued its disciplined pursuit of the approvals and authorizations necessary to create the opportunity to add the benefits of new nuclear generation for its customers. The project achieved key milestones in the SCA process by achieving completeness and moving on to the agency review stage. In the Nuclear Regulatory Commission (NRC) licensing process, significant progress was made responding to Requests for Additional Information (RAI) and updating the Combined Operating License Application (COLA) with Revision 3. This should allow the federal review to move forward in 2012.

(TR 765)

The project made measurable progress in all regulatory processes towards obtaining all necessary licenses, permits, and approvals. The three key processes include the Combined Operating License (COL) process administered by the NRC, wetland permits under the jurisdiction of the US Army Corps of Engineers (USACOE), and the SCA process, coordinated by the Florida Department of Environmental Protection (FDEP). In general, 2011 was another year of information exchange with agencies to ensure all relevant and required information necessary for agency evaluations has been provided.

(TR 766)

As a part of its overall project management, FPL once again considered the appropriateness and timing associated with initiating the next phase of project activities; namely those related to engineering design, procurement of long lead equipment, and initiation of preliminary construction activities.

(TR 795)

In 2012 and 2013 the project is scheduled to continue its progress in much the same manner as it has in past years, responding to regulatory requirements as various steps in the application processes are completed. Expenses requested are primarily related to obtaining the licenses and permits, with a portion covering planning and design studies needed to support the project schedule. Delays in the regulatory review process have been accommodated allowing the projected commercial operation dates (CODs) of 2022 for Unit 6 and 2023 for Unit 7 to be maintained, however delays are possible. Recognizing that the experience to date is a likely indicator of the remainder of the licensing phase, FPL’s stepwise approach continues to provide FPL customers with the best opportunity to make steady progress on the project.

(TR 805-806)

FPL continues to develop Turkey Point 6 & 7 through a deliberate and careful process navigating through the four phases of project development: Exploratory, Licensing, Preparation, and Construction. The project has completed the Exploratory phase, and is currently focused on the Licensing phase prior to initiating Preparation phase activities. The approach allows FPL to make progress on obtaining licenses and approvals without taking on the risks of committing to a specific construction schedule and the associated expenditures. For example, through 2013, FPL projects it will have spent (and recovered through this Nuclear Cost Recovery process) a total of $206 million on the Turkey Point 6 & 7 project - approximately 1% of the total estimated project cost.

(TR 807-808)

Procurement activities in 2012 and 2013 continue to focus on the licensing and permitting process. Professional services are required from technical and environmental consultants, legal service firms, and subject matter experts to respond to the inquiries of intervenors and the reviewing agencies during the application review process or subsequent hearings. Additionally, some planning studies and early site preparation design activities are scheduled for 2013.

(TR 814)

SACE, in its brief, asserted that FPL only demonstrated its intent to obtain the Combined Operating License. (SACE BR 13) Concerning the question of FPL’s intent to complete the project, witness Scroggs responded during cross-examination:

Q  Thank you. So in your prefiled testimony this year and today in front of this Commission under oath you've tested that, you've testified that FPL intends to pursue completion; correct?

A  That's correct.

Q  And whereas last year Mr. Olivera stated that the intention was to go through the licensing process and then to reassess, reassess economics, things like that. Would that be an accurate characterization?

A  Yes, it would.

Q  Okay. So do you dispute Mr. Olivera's statement from last year?

A  No. I think there's a difference in, in how you're interpreting it and how I'm interpreting it.  If I'd be allowed to explain.

Q  Sure. Sure.

A  I think what Mr. Olivera is actually just being very frank with the Commission about the same things that I've said. We're committed to go forward with the project. We wouldn't have initiated the need order, we wouldn't be here every year in nuclear cost recovery and pursuing the licenses if we didn't intend to go through with the project. That said, it doesn't mean that we would blindly make a commitment at a very far time from when all the information is in, that we would go through a project with, without regard to the results of what an economic analysis may show one year from now, two years from now. So I would do the annual feasibility analysis every year.  So I don't see any inconsistency in how I as a project manager am looking at stepwise decision-making through each phase and how Mr. Olivera explained it last year.

(TR 876-877)

Q  You also just stated in your attempt to explain your answer that y'all are committed to go forward, but we've already established y'all have not committed to construction; correct?

A  Yes. And, again, I think that's a difference of looking at the project as a whole. We would not have initiated the project if we weren't ready to move forward with it. That said, these projects are highly complex, they span years. The fundamental inputs change over those years, which is why we review them annually and make the decision that is merited at the time of the information.

(TR 877-878)

            Reviewing the record, staff believes that FPL’s actions since 2011 support the requirement of demonstrating its intent to build.  Staff notes that even if FPL’s “intent” was to terminate the project, Section 366.93(6), F.S., allows for recovery of all prudent preconstruction and construction costs in the event the utility elects not to complete or is precluded from completing the construction of the nuclear power plant.

            Staff notes SACE’s assertion that if FPL intended to complete the project, FPL would have already spent more on this project. (SACE BR 14)  Staff reviewed the record for evidence supporting SACE’s argument but found none.  SACE’s brief did not identify any transcript reference or exhibit in support of its assertion.  FPL argued that the alternative management approach advocated by SACE would entail committing substantial sums of money to lock down construction plans now, despite the fact that such expenditures are unnecessary at this time to maintain the current project schedule. (FPL BR 17)  FPL witness Scroggs asserted FPL will continue to develop the Turkey Point Units 6 & 7 project through four phases: exploratory, licensing, preparation, and construction.  (TR 807)  The exploration process is complete and FPL is currently focused on the licensing phase.  (TR 807; FPL BR 15)  By deciding not to initiate preparation phase activities until they are absolutely necessary, FPL has minimized cost to customers. (TR 809)  FPL asserted that no witness or record evidence challenged this conclusion. (FPL BR 15)  Staff agrees.

From our review, staff believes the FPL’s Turkey Point Unit 6 & 7 project activities since January 2011 are similar and consistent with those the Commission has reviewed in prior proceedings and found to be appropriate for nuclear cost recovery.[40]  Staff also notes that FPL's testimony identified actions that qualify as preconstruction activities as defined in Section 366.93(1)(f), F.S., and as interpreted by Rule 25-6.0423(2)(h), F.A.C., since FPL has not entered into the actual construction phase of the project or announced termination of the project.  Staff believes that, taken as a whole, all of the noted activities are more consistent with a demonstration of intent to build as opposed to termination of the Turkey Point Units 6 & 7 project.  FPL’s recovery of its prudently incurred preconstruction costs is addressed in Issue 25.

CONCLUSION

Staff believes that FPL's activities for the Turkey Point Units 6 & 7 project qualify as "siting, design, licensing, and construction" of a nuclear power plant as contemplated by Section 366.93, F.S.

 

Issue 21: 

 Should the Commission approve what FPL has submitted as its 2012 annual detailed analysis of the long-term feasibility of completing the Turkey Point Units 6 & 7 project, as provided for in Rule 25-6.0423, F.A.C.?  If not, what action, if any, should the Commission take?

Recommendation: 

 Yes. A preponderance of the evidence demonstrates that FPL fully considered the economic, regulatory, technical, funding, and joint ownership considerations impacting the feasibility of the project. While continuing uncertainty exists in virtually all these areas, the Turkey Point 6 & 7 project continues to appear feasible at this time.  (Garl)

Position of the Parties

FPL: 

 Yes.  FPL’s analysis considers a range of fuel and environmental compliance costs to serve as possible future scenarios in which to view the economics of Turkey Point 6 & 7.  FPL annually updates these fuel and environmental compliance cost projections and updates a number of other assumptions, such as the project cost and system load forecast, for its economic analysis.  Based on this analysis, completion of Turkey Point 6 & 7 is projected to be solidly cost-effective for FPL’s customers in five out of seven scenarios and within the break even range in the remaining two scenarios.  The results of the analysis fully support the feasibility of continuing the Turkey Point 6 & 7 project.

OPC: 

 No position.

SACE: 

 No.  FPL has failed to complete and properly analyze a realistic feasibility analysis which properly takes into account all of the factors that have resulted in the great uncertainty and risk adversely impacting new nuclear generation generally and TP 6 & 7 in particular, including, but not limited to:  depressed natural gas prices, absence of a cost of carbon; continued depressed economic conditions; and the true impact of efficiency and renewable.  The Commission should deny cost recovery for FPL’s 2012 and 2013 costs related to TP 6 & 7.

FIPUG: 

 No position at this time.

FEA: 

 No position.

FRF: 

 No position.

Staff Analysis:  This issue addresses review and approval of FPL's detailed long-term feasibility analysis of continuing construction and completing the Turkey Point 6 & 7 Project  as required by Rule 25-6.0423, F.A.C., and Order No. PSC-08-0237-FOF-EI.

PARTIES’ ARGUMENTS

FPL

FPL stated that its 2012 Turkey Point feasibility analysis was presented to satisfy the requirement of subsection 5(c)5 of the NCR Rule (25-6.0423), which 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.” (TR 1195)

FPL noted that the analytical approach used in the 2012 feasibility analysis for the Turkey Point 6 & 7 Project is the same approach used in the 2007 Need Determination filing and the 2008, 2009, 2010, and 2011 NCRC feasibility analyses. (TR 1205-1206)  Using this approach, FPL calculated the “breakeven” overnight capital costs for the new nuclear units in a variety of fuel cost and environmental compliance cost scenarios.[41] (TR 1206)  FPL updated key assumptions used in this analysis, including forecasted peak and annual loads, forecasted fuel costs, forecasted environmental compliance costs, and project-specific assumptions. (TR 1209-1210, 1213-1215, 1217-1218)  Additionally, FPL incorporated updates for certain resource planning and EPU project assumption changes. (TR 1210, 1215-1218)

FPL argued that the results of its 2012 analysis continue to support the feasibility of continuing the Turkey Point 6 & 7 project.  FPL contends that, in five of seven scenarios, the breakeven capital cost was above FPL’s non-binding cost estimate range for the Turkey Point 6 & 7 Project, and in the remaining two scenarios, the breakeven capital cost was within FPL’s non-binding cost estimate range. (TR 1236; EXH 91)  Importantly, according to FPL, the results have remained favorable despite declining natural gas prices.  FPL says in nominal terms, a resource plan that includes the Turkey Point 6 & 7 Project is currently projected to save customers $58 billion in fuel cost savings over the life of the new plant. (TR 1233: EXH 81)  FPL adds that the Turkey Point 6 & 7 Project will reduce reliance on natural gas by about 13 percent and reduce carbon dioxide emissions by about 255 million tons. (TR 1233-1234; EXH 81)  It is, therefore, clear that even with currently low natural gas price forecasts, the project remains highly beneficial for FPL’s customers.[42]

FPL contended that SACE claims, in its prehearing position, to have “brought to the Commission’s attention” the uncertainty and risk surrounding Turkey Point 6 & 7 and claims that this uncertainty and risk renders the project infeasible.[43]  But it is FPL that has consistently testified that there is uncertainty and the potential for issues to arise that impact the project and its economics. (TR 820-821, 831)  In fact, this is the very basis for FPL’s deliberate, step-wise approach (with which, ironically, SACE takes issue).  SACE jumps to the conclusion that this uncertainty somehow makes the project infeasible and states in its prehearing position – without any evidentiary support whatsoever – that low natural gas prices and the lack of greenhouse gas legislation “make new nuclear generation cost prohibitive.”[44]  FPL asserts its analysis, which fully accounts for lower natural gas prices and lower/later environmental regulations imposing costs on carbon dioxide emissions, demonstrates otherwise. 

No intervenor presented evidence contradicting FPL’s feasibility analysis approach or results.  FPL argued, therefore, that its feasibility analysis should be approved.

 SACE

SACE noted that, as part of its annual consideration of a utility’s Petition for cost recovery, the Commission is required to evaluate the long-term feasibility of completion of a proposed project.  Rule 25-6.0423(5)(c)5, F.A.C., provides:

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.

SACE asserted that this review forces utilities to regularly review whether their investment decisions, which will be borne by the ratepayers continue to be justified in light of changing economic, technological, and regulatory conditions.  SACE asserts that this review is part of the quid pro quo for the extraordinary financial incentive provided to the utility through the cost recovery clause, because the utilities are spending their ratepayers’ money, with no real risk to their own bottom lines. SACE claimed that FPL’s 2012 feasibility analysis fails to demonstrate that completion of these reactors is feasible in the long-term.  SACE concludes that the Commission should deny FPL’s estimated 2012 and projected 2013 costs related to the Levy Project.

SACE argued that FPL’s 2012 qualitative feasibility analysis consists of nothing more than one page of cursory discussion of non-economic factors affecting the feasibility of the Turkey Point 6 & 7 Project. (TR 834)  Mr. Scroggs did not conduct any type of analysis of these factors, and certainly not a “detailed analysis” as required by Rule 25-6.0423(5)(c)5, F.A.C.  Furthermore, at the hearing, it was brought out that the Nuclear Regulatory Commission (NRC) chastised FPL in a May 2012 letter and informed the company that “substantial modifications” to its Combined Operating License Application will be required, and, after the NRC analyzes these modifications, a new review schedule will be issued. (TR 864-866; Ex. 116)  This failure to provide the NRC with accurate information adversely affects the feasibility of completing the Turkey Point 6 & 7 Project, and this should have been analyzed by Mr. Scroggs and presented to the Commission.  SACE asserted that, ultimately, the lack of any qualitative analysis, and the omission of analysis of the impacts of the May 2012 letter, especially given the great uncertainty and risk adversely affecting the development of new nuclear generation, warrants Commission disapproval of FPL’s feasibility analysis.

SACE claimed that FPL witness Sim sponsored an updated CPVRR for the quantitative portion of FPL’s feasibility analysis; however, this CPVRR, like PEF’s, fails to present the Commission with a realistic picture of the feasibility of completing the Turkey Point 6 & 7 Project, and further fails to demonstrate that completion is feasible in the long term.  FPL witnesses Scroggs and Sim confirmed that the projected fuel savings for FPL’s customers over the life of the Turkey Point 6 & 7 Project was $58 billion – down from a projected $90 billion in 2010. (Scroggs TR 871-872; Sim TR 1252)  This represents a decrease of over $30 billion in projected fuel savings compared to what was projected by FPL in 2010. (TR 872)  FPL witness Sim testified that the cost of natural gas and the cost of carbon were two of the primary drivers of any economic feasibility analysis (TR 1251), and further conceded that gas prices were at a historical low, and that long term projections showed gas prices trending lower. (TR 1248-1249; Ex. 82)  Similarly, FPL witness Sim testified that long term trends for cost of carbon were trending negatively for new nuclear generation.  Specifically, witness Sim testified that carbon dioxide costs were starting significantly later, and that the costs were lower on a year by year basis as compared to what FPL has previously projected. (TR 1251)  Based on all of the above factors, witness Sim conceded that the economic feasibility of the Turkey Point 6 & 7 Project was declining. (TR 1252-1253) 

SACE stated that, despite the declining economic feasibility of the Turkey Point 6 & 7 Project, FPL’s updated CPVRR analysis purported to show that the Turkey Point 6 & 7 Project remained the preferred resource plan, as opposed to an all gas plan, in 5 of 7 scenarios. (EXH 91; TR 1251)  However, as was the case with PEF, FPL did not perform any assessment or analysis of the relative likelihoods of any of these fuel and environmental compliance scenarios, which certainly skews the analysis. Moreover, it is difficult to comprehend how, given that the two key drivers in the feasibility analysis, natural gas prices and cost of carbon, are both trending negatively for new nuclear generation in the long term, FPL can maintain that the Turkey Point 6 & 7 Project is still preferable in a majority of scenarios as compared to an all gas generation plan. In fact, SACE asserted, based on the “results” of FPL’s CPVRR analysis, it is readily apparent that nothing could happen that would result in the CPVRR coming out in favor of the all gas generation plan.

            FIPUG, FEA, and FRF, took no position on this issue.

ANALYSIS

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 adopted Rule 25-6.0423, F.A.C., 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-08-0237-FOF-EI, at page 29, the Commission provided specific guidance regarding the requirements necessary for FPL to satisfy Rule 25-6.0423(5)(c)5, F.A.C. 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, breakeven 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.[45]

Required Elements

Staff believes that FPL satisfied the requirements of Order No. PSC-08-0237-FOF-EI and Rule 25-6.0423, F.A.C., through various means. (TR 1191-1237; EXH 82-83, 86, 90-91)

FPL’s 2012 feasibility analysis for completion of the Turkey Point 6 & 7 Project remained consistent with the methodology it used in the need determination and each subsequent NCRC proceeding.  Stated most simply, FPL compared competing resource plans, one with the nuclear resource option and one with a non-nuclear resource option.  The competing, non-nuclear resource option is a new highly fuel-efficient combined cycle generating unit of the type FPL is constructing at its Port Everglades Modernization project.  In evaluating these options, FPL considered numerous quantitative and qualitative factors.  Among the quantitative factors that FPL examined were fuel and environmental price forecasts, project costs, and cost-effectiveness using multiple sensitivities for fuel and environmental costs.  Qualitative factors considered included regulatory feasibility, technical feasibility, funding feasibility, and joint ownership.  Staff examined each of these factors to determine the acceptability of FPL’s long-term feasibility analysis.

Staff believes that the forecasts, cost estimates, and cost-effectiveness analyses are necessary filing requirements to assess FPL's 2012 Turkey Point 6 & 7 Project feasibility analysis.  In addition, staff reviewed regulatory and technical aspects of the project.  These elements provide a holistic perspective for staff's recommendation regarding the acceptability of FPL's detailed long-term feasibility analysis.

Economic Feasibility

Updated Fuel Forecast

The updated fuel price forecasts submitted by FPL were developed from the same industry-accepted sources FPL has used since the need determination proceeding.  Therefore, staff believes it is reasonable to accept FPL’s updated fuel cost data in this proceeding.  Figure 21-1 depicts the price forecasts for the medium range of natural gas used from the 2009 NCRC proceeding through this year’s filing to support FPL’s feasibility analysis.  Staff notes that the increase in natural gas price forecasts are trending slightly downward each year. 

Figure 21-1:  Forecasted Delivered Natural Gas Prices – Medium Fuel Forecast ($/MMBTU, $Nominal)

Order PSC-11-0547-FOF-EI, p. 12; EXH 82

 

While none of the parties contested the reasonableness or credibility of FPL’s fuel forecast, SACE asserted that FPL failed to take into account the declining natural gas costs, among other factors, in performing its feasibility analysis. (SACE BR 14-15)  SACE then discussed how FPL actually did take declining natural gas costs into account in performing its feasibility analysis.  SACE noted that FPL reported a reduction in life-cycle fuel savings, acknowledged natural gas prices were at an all-time low and trending lower in the long term, and noted that the overall economic feasibility has declined. (SACE BR 16)  Absent in SACE’s argument, however, is any evidence to suggest declining fuel prices make the Turkey Point 6 & 7 Project not cost-effective.  SACE, as it did last year,[46] attempted to suggest the project should be abandoned and cost recovery denied, not because the project was not cost-effective, but because the project was not as cost-effective as when fuel costs were higher. 

Staff again rejects SACE’s contention that FPL failed to consider the decline in forecasted gas prices.  FPL’s analysis shows that both the total cost difference between the competing plans and breakeven costs have declined due, in part, to lower forecasted gas prices.  In addition, SACE’s acknowledgement that FPL has shown a decline in savings over the life of the project demonstrated that FPL has not failed to take into account the declining natural gas costs.  Staff believes it is reasonable to accept FPL’s updated fuel cost data in this proceeding.

Updated Environmental Forecast

The updated environmental cost forecasts FPL submitted were developed from the same industry-accepted sources FPL has used since the need determination proceeding.  Table 21-1 below depicts the price forecasts for the medium range of environmental costs (ENV II) used from the 2009 NCRC proceeding through this year’s filing to support FPL’s feasibility analysis. 

Table 21-1:  Forecasted Environmental Compliance Costs ($/ton, $Nominal)

Order No. PSC-11-547-FOF-EI, p. 14; EXH 83

Staff notes that the price forecast for sulfur dioxide (SO₂) and nitrous oxides (NOx) dropped dramatically between 2010 and 2011 but remained close to the 2011 price projection in 2012.  FPL witness Sim testified in the 2011 proceeding that the 2010-2011 reductions were due to utilities, in response to Environmental Protection Agency rules, adding control devices for these emissions.  This, in turn, produces more emission allowances on the market in future years, thereby reducing the value of the allowances.[47]  This year, witness Sim responded to a cross examination question about the trend of carbon dioxide emission costs:

Yes, I think there are two trends for CO₂ that were certainly much different this year than what we saw in 2011.  Number one, the CO₂ costs are assumed to start significantly later than what we have seen before, and that the costs, on a year-by-year basis, are lower than what they were in 2011.

(TR 1251)

None of the intervenors contested the credibility or accuracy of FPL’s updated environmental cost forecast.  SACE, however, suggested that FPL failed to take into account that projected costs of carbon dioxide emissions “were trending negatively for new nuclear generation.” (SACE BR 16) 

As with gas prices, staff rejects SACE’s contention that FPL failed to consider the decline in environmental costs. FPL’s feasibility (cost-effectiveness) analysis demonstrates changes in the forecasted cost of emissions were considered.  Staff believes it is reasonable to accept FPL’s updated environmental cost data in this proceeding. 

Updated Project Cost Estimate

FRF expressed doubt about the accuracy of FPL’s non-binding cost estimate; however, FRF neither contested the estimate nor presented any evidence supporting the expressed doubt. (FRF BR 9)  Other intervenors did not contest FPL’s estimated cost. 

FPL’s total in-service cost estimate for the Turkey Point 6 & 7 Project is in the range of $12.8 billion to $18.7 billion.  This estimated range includes carrying costs of $3.6 billion to $5.3 billion (EXH 40, p. 60) and sunk costs of $0.2 billion (EXH 86).  Considering FPL’s 2012 non-binding overnight capital cost estimate range of $3,570/kW to $5,190/kW, there is a 14.3 percent increase from FPL’s estimated maximum cost in the 2007 need determination proceeding and a 14.9 percent increase in the minimum cost.  The history of cost range estimates is shown in the chart below.

Figure 21-2:  Range of Non-Binding Overnight Capital Cost Estimates ($/kW)

Order No. PSC-11-0547-FOF-EI, p.14; EXH 86

FPL used its updated project cost estimate in conducting its cost-effectiveness analysis below.  Staff believes FPL’s cost estimate is reasonable.  Results of the analysis demonstrate that the cost-effectiveness of the project has declined in comparison with the competing plan without nuclear generation; however, the project remains cost-effective. 

Project Cost-Effectiveness

FPL’s analysis of the cost-effectiveness of the TP 6 & 7 project once again relied on the same breakeven analysis it used since the need determination.  FPL compared a present value revenue stream assuming zero capital costs for the nuclear units to a traditional present value revenue stream which includes capital and system fuel costs for a combined cycle unit as a replacement for the nuclear units.  The results of this analysis show the highest capital costs at which nuclear generation would still be cost-effective compared to the combined cycle alternative.

FPL performed its analysis under a wide range of scenarios which combined varying fuel forecasts (low, medium, and high) and environmental compliance cost projections (ENV I-III).  ENV I represented a low compliance cost scenario, while ENV III represented a high compliance cost scenario.  Seven different fuel/environmenta1 cost scenarios were analyzed for each alterative to the Turkey Point 6 & 7 Project.  The projected present value savings over the study period for each scenario was then used to calculate a breakeven capital cost estimate of what the nuclear units could cost and still produce net savings over the study period when compared to the combined cycle units.  Each breakeven value was then compared to the overnight capital cost range of $3,570/kW-$5,190/kW to determine the likelihood of the nuclear project producing a net savings over the study period. (EXH 86)  If the breakeven values are higher than the current capital cost-estimates, then the nuclear plants would provide net savings over the life of the units compared to alterative baseload units.  Staff believes that FPL’s approach in performing this analysis remains reasonable. 

The results of the breakeven analysis, shown in Table 21-2 below, demonstrate that the Turkey Point 6 & 7 Project remains cost-effective compared to the alternative combined cycle unit.  The results in six of the seven scenarios show breakeven nuclear capital costs are above FPL’s estimated range of costs, which demonstrates a high likelihood of cost-effectiveness.  Staff notes that the low fuel/low environmental cost scenario breakeven nuclear capital cost, $4,202/kW, is within FPL’s estimated range of costs, $3,570/kW to $5,190/kW.  This indicates a possibility that the nuclear project may not be cost-effective if the capital costs approach the upper limit of the range and long-term fuel and environmental costs remain relatively low for the duration of the analysis (52 years).

Table 21-2:  2012 Feasibility Analyses Results for the Turkey Point 6 & 7 Project

 

EXH 91

Staff notes that FPL’s breakeven analyses for 2012 compared to 2011, in Table 21-3 below, demonstrates that the magnitude and range of the breakeven nuclear capital costs have declined.  However, the 2012 analysis showed the project was cost-effective in the same 6 of the 7 scenarios as the 2011 analysis. 

                         Table 21-3:  2011 Feasibility Analyses Results for the Turkey Point 6 & 7 Project

 

Order No. PSC-11-0547-FOF-EI, p. 15

Figure 21-3 below portrays the migration of the breakeven costs and the estimated project costs.  If the estimated capital cost range increases into the range of the breakeven costs, the project becomes less cost-effective.  In 2011, the upper limit of breakeven cost was 71 percent greater and the lower limit was 3 percent below the highest estimated capital costs.  In 2012, the upper limit of breakeven costs was 22 percent greater and the lower limit was 19 percent below the highest estimated capital costs.  This indicates that the range and magnitude of breakeven costs have decreased since 2011.  The lowest 2012 breakeven cost now being within the range of the estimated costs, as mentioned above, suggests that the project may not be cost-effective if long-term fuel and environmental costs remain low.  Staff notes, however, that 2012 is not the first year the lowest breakeven cost has been within the range of estimated costs.  As the figure shows, the same situation was reported in the 2008 need determination, and the 2009 and 2011 NCRC orders. 

Figure 21-3:  2008 – 2012 Breakeven and Estimated Capital Cost Range Comparison

 

Order No. PSC-08-0237-FOF-EI, p. 23; Order No. PSC-09-0783-FOF-EI, pp. 15-16; Order No. PSC-11-0547-FOF-EI, EXH 86, and EXH 91.

As discussed above, SACE asserted that FPL failed to consider the declining cost of natural gas and carbon dioxide emissions in FPL’s economic analysis.  SACE argued that this shortcoming should prompt the Commission to reject FPL’s long-term feasibility analysis and deny cost recovery. (SACE BR 14-17)  Other parties to the proceeding do not contest FPL’s cost-effectiveness analysis methodology or results.

Staff believes that SACE’s argument is unpersuasive.  FPL clearly considered projected costs of natural gas and emissions in its feasibility analysis, as evidenced by the reduced life-cycle savings, and decline in cost-effectiveness.  Nonetheless, the Turkey Point 6 & 7 Project remains cost-effective at this time.  The Commission should accept FPL’s cost-effectiveness analysis.

Regulatory Feasibility

SACE asserted that FPL’s feasibility analysis should be rejected and cost recovery be denied because FPL failed to conduct a detailed analysis of the feasibility of completing the Turkey Point 6 & 7 Project.  SACE pointed to what it describes as “one page of cursory discussion of non-economic factors affecting the feasibility of TP 6 & 7.”  SACE rebuked FPL witness Scroggs for not conducting a detailed analysis of these non-economic factors, as required by rule.  In addition, SACE argued that the NRC “chastised” FPL in a May 2012 letter requiring “substantial modifications” to FPL’s Combined Operating License Application.  SACE argued that this “failure to provide the NRC accurate information adversely affects the feasibility of completing TP 6 & 7 . . .” (SACE BR 15)

In contrast, the record clearly shows FPL witness Scoggs testified about FPL’s continuing review of numerous regulatory issues, such as the NRC combined license schedule, the Florida Site Certification process, and negotiations for land, roadway improvements, and water supply.  Witness Scroggs presented numerous pages in his prefiled testimony discussing the many activities at local, state, national, and international levels that FPL follows closely, and the intensive review process used to identify potential impacts and manage risk on the Turkey Point 6 & 7 Project. (TR 766-768; 770-784; 789-797; 807-822) 

Further, witness Scroggs clarified the NRC’s request for additional information in response to a question from the bench:

So in your opinion, you know, for example, the geologic and seismology questions that were brought up, they weren't from a lack of performance from FPL's subcontractor or a lack of information provided that's normally expected. It's additional information that really wasn't expected at the time?

THE WITNESS:  I think it runs the range. You know, you have -- it's a very highly technical and complex subject area, and you have very well-versed academics who have studied the area and they have certain opinions.

So when our experts answered original questions and they didn't put a lot of weight on a certain survey or a certain piece of information, but the NRC wanted to see more information on that, maybe they would put more weight on it, that's what they're asking to provide more information.

So when you see questions that, you know, not supported by the references provided in the, in the first paragraph, I think they're saying that, you know, you need to provide more information, more support for the conclusions that your experts have come to.

(TR 888-889)

Staff is not persuaded by SACE’s contention that FPL offered a cursory discussion of non-economic issues, nor of SACE’s characterization of the NRC letter adversely impacting feasibility of the Turkey Point 6 & 7 Project.

Staff believes that FPL has an effective process in place to provide its management with an ongoing, detailed analysis of the uncertainties and risks that could impact its licensing, approval, and certifications necessary for project success.

Technical Feasibility

Closely related to regulatory issues are some technical issues with the Westinghouse AP1000 nuclear power units planned for the Turkey Point 6 & 7 Project.  First is the NRC certification of the latest design change to the AP1000.  This process was successfully completed with the NRC completing rulemaking for the AP1000 Design Certification in 2011. (TR 897)

FPL witness Scroggs testified that two nuclear construction projects using the AP1000 design in China are on schedule to begin operation in 2013 and 2015.  Recently approved projects in Georgia and South Carolina are also continuing on schedule. (TR 772-773)

None of the intervenors contested any technical aspects of the project.  Staff believes the evidence supports viewing the Turkey Point 6 & 7 Project as technically feasible.

Funding Feasibility

In addition to elements of economic feasibility, staff believes availability of funding for the project should also be considered.  FPL witness Scoggs testified, “Activity on other U.S. projects shows a strong interest in the investment community to participate in new nuclear financing.”  As an example, he discussed a successful $2.7 billion bond solicitation by Municipal Electric Authority of Georgia for its portion of the Vogtle Units 3 and 4. (TR 834)  None of the intervenors contested FPL’s ability to obtain funding for the project.

Staff views FPL's current access to capital markets as confirmation of continued funding feasibility.

Joint Ownership

The 2012 proceeding included no mention of joint ownership associated with the Turkey Point 6 & 7 Project by any intervenor.  In the 2011 proceeding, FPL witness Scoggs discussed the periodic meetings he had with other utilities from Florida about the status of the project and, most recently, about the events at Fukushima.  Witness Scoggs explained that, because of where FPL currently is in the project, it would not be an appropriate time to enter into a joint ownership agreement.[48] 

Staff agrees with Witness Scoggs.  The project is still in its early stages with uncertainties, associated risks, and pending NRC licensing.  Given the current status of the project, staff believes that the lack of joint ownership should not be deemed a fatal flaw to project feasibility at this time.

CONCLUSION

A preponderance of the evidence shows FPL fully considered the economic, regulatory, technical, funding, and joint ownership considerations impacting the feasibility of the project. While continuing uncertainty exists in virtually all these areas, staff recommends that completion of the Turkey Point 6 & 7 Project continues to appear feasible at this time.

 

 

Issue 22: 

 What is the current total estimated all-inclusive cost (including AFUDC and sunk costs) of the proposed Turkey Point Units 6 & 7 nuclear project?

Recommendation: 

 The Commission should accept FPL's estimated range of $3,570/kW ($12.8 billion) to $5,190/kW ($18.7 billion) as the cost of the Turkey Point 6 & 7 Project.   (Garl)

Position of the Parties

FPL: 

 FPL’s current non-binding cost estimate range for the Turkey Point 6 & 7 Project is $3,570/kW to $5,190/kW in overnight costs, or $12.8 billion to $18.7 billion including AFUDC, as stated in the April 27, 2012 direct testimony of Steven Scroggs.

OPC: 

 No position.

SACE: 

 No position.

FIPUG: 

 Given the scope and size of this undertaking, this information is critical to provide transparency to those who are paying for this enormous project.  Further, the Commission must consider whether the costs make sense in view of the magnitude of the expenditures.  This information is in the possession of FPL and should be provided to the Commission and ratepayers.

FEA: 

 Agree with FIPUG.

FRF: 

 The FRF does not, presently, dispute FPL’s estimate of $18.7 billion as the all-inclusive cost of the Turkey Point 6 & 7 project.  However, the FRF doubts the accuracy of this estimate.

Staff Analysis:  This issue addresses the current total estimated all-inclusive cost (including AFUDC and sunk costs) of the proposed Turkey Point 6 & 7 Project.

PARTIES’ ARGUMENTS

FPL stated that its current non-binding cost estimate range for the Turkey Point 6 & 7 Project is $3,570/kW to $5,190/kW in overnight costs, or $12.8 billion to $18.7 billion including carrying costs. (TR 829-830)  FPL’s non-binding cost estimate range reflects the results of a review that was conducted on the previous non-binding cost estimate range to capture any potential changes and estimate the potential cost impact. (TR 831-832)  No party presented any evidence demonstrating that different all-inclusive cost estimate is appropriate.

OPC and SACE, having taken no position, do not argue this issue.

FIPUG, FEA, and FRF do not argue this issue beyond their position statement.

ANALYSIS

FRF expressed doubt about the accuracy of FPL’s non-binding cost estimate; however, FRF neither contested the estimate nor presented any evidence supporting the expressed doubt. (FRF BR 9)  Other intervenors did not contest FPL’s estimated cost. 

FPL’s total in-service cost estimate for the Turkey Point 6 & 7 Project is in the range of $12.8 billion to $18.7 billion.  This estimated range includes carrying costs of $3.6 billion to $5.3 billion (EXH 40, p. 60) and sunk costs of $0.2 billion (EXH 86).  Considering FPL’s 2012 non-binding overnight capital cost estimate range of $3,570/kW to $5,190/kW, this represents a 14.3 percent increase from FPL’s estimated maximum cost in the 2007 need determination proceeding and a 14.9 percent increase in the minimum cost.  The history of cost range estimates is shown in the chart below.

Figure 21-2:  Range of Non-Binding Overnight Capital Cost Estimates ($/kW)

Order No. PSC-11-0547-FOF-EI, p.14; EXH 86

FPL used its updated project cost estimate in conducting its cost-effectiveness analysis discussed in Issue 21.  Staff believes FPL’s cost estimate is reasonable.  Results of the analysis demonstrate that the cost-effectiveness of the project has declined in comparison with the competing plan without nuclear generation; however, the project remains cost-effective. 

CONCLUSION

Staff recommends that the Commission should accept FPL's estimated range of $3,570/kW ($12.8 billion) to $5,190/kW ($18.7 billion) as the cost of the Turkey Point 6 & 7 Project.

 

 

Issue 23: 

 What is the current estimated planned commercial operation date of the planned Turkey Point Units 6 & 7 nuclear facility?

Recommendation: 

 The Commission should accept FPL's estimated commercial operations dates of 2022 and 2023 for Turkey Point Units 6 & 7, respectively.   (Garl)

Position of the Parties

FPL: 

 For planning purposes, FPL’s current estimated commercial operations dates for Turkey Point Units 6 & 7 are 2022 and 2023, respectively, as stated in the April 27, 2012 direct testimony of Steven Scoggs.

OPC: 

 No position.

SACE: 

 No position.

FIPUG: 

 Given the scope and size of this undertaking, this information is critical to provide transparency to those who are paying for this enormous project.  Further, the Commission must consider whether the commercial operation date makes sense in view of the magnitude of the expenditures.  This information is in the possession of FPL and should be provided to the Commission and ratepayers.

FEA: 

 Agree with FIPUG.

FRF: 

 No position as to what the estimated planned commercial operation date for the Turkey Point Units 6 & 7 nuclear facility may be.  However, the FRF has concerns regarding he accuracy of any projected in-service date for this project.

Staff Analysis:  This issue addresses the current estimated planned commercial operation date of the planned Turkey Point 6 & 7 Project.

PARTIES’ ARGUMENTS

FPL stated that, for planning purposes, its current estimated commercial operation dates for Turkey Point Units 6 & 7 are 2022 and 2023, respectively. (TR 827, 829)  No party presented eveidence demonstrating that different commercial operation dates would be appropriate.

OPC and SACE, having taken no position, do not argue this issue.

FIPUG, FEA, and FRF do not argue this issue beyond their position statement.

ANALYSIS

FRF had “concerns” about the accuracy of FPL’s projected in-service dates; however, FRF neither contested the estimate nor presented any evidence supporting its concern. (FRF BR 10)  Other intervenors did not comment on or contest FPL’s estimated in-service dates.

FPL witness Scroggs testified that an October 2011 revised schedule for review of the Turkey Point 6 & 7 Project Combined Operating License Application from the Nuclear Regulatory Commission prompted FPL to perform a complete review of the project schedule.  “The review concluded that the current 2022/2023 commercial operation dates could be achieved,” witness Scoggs said. (TR 825, 827)

CONCLUSION

Staff notes that FPL used the 2022/2023 dates in its annual feasibility analyses for 2012. Staff, therefore, recommends that the Commission accept FPL's estimated commercial operations dates of 2022 and 2023 for Turkey Point Units 6 & 7, respectively.

 

 

Issue 24: 

 Should the Commission find that FPL's 2011 project management, contracting, accounting and cost oversight controls were reasonable and prudent for the Turkey Point Units 6 & 7 project?

Recommendation: 

 Yes.  Staff recommends the Commission find that project management, contracting, accounting and cost oversight controls employed by FPL during 2011 for the Turkey Point Units 6 & 7 project were reasonable and prudent.  (Breman)

Position of the Parties

FPL: 

 Yes.  FPL’s project management, contracting, accounting, and cost oversight controls are comprehensive and overlapping.  They include FPL’s Accounting Policies and Procedures; financial systems and related controls; annual budgeting and planning process and reporting and monitoring of costs incurred; and Business Unit specific controls and processes.  The project controls are comprised of financial systems, department procedures, work/desktop instructions and best practices, providing governance and oversight of project cost and schedule processes.  The project management, cost estimation, and risk management attributes of FPL are highly developed, well documented, and adhered to by the project teams.  FPL’s management decisions with respect to Turkey Point 6 & 7 are the product of properly qualified, well-informed FPL management following appropriate procedures and internal controls.

OPC: 

 No position.

SACE: 

 No.  As evidenced by the NRC’s May 4, 2012 letter, FPL has failed to provide accurate information to the NRC relating to its COLA in the areas of safety and environmental review.  Reasonable and prudent project management, contracting, accounting, and cost oversight would have prevented such an outcome.  The Commission should deny cost recovery for FPL’s 2011, 2012 and 2013 costs related to TP 6 & 7.

FIPUG: 

 No position at this time.

FEA: 

 No position.

FRF: 

 No position.

Staff Analysis: 

 This issue addresses project management, contracting, accounting, and oversight controls employed by FPL during 2011 for the Turkey Point Units 6 & 7 project.  Examples of project management oversight controls are having stated corporate policies for developing project schedules, developing annual budgets, tracking variances, training on these policies, and verifying that the team members adhere to corporate policies. (EXH 100, p. 8, 18, 23-29)

 

Decisions in Issue 20 could impact the need to address FPL’s 2011 project management.  The only questions raised in this issue centered on a May 4, 2012, letter from the NRC.

 

 

PARTIES’ ARGUMENTS

FPL

FPL asserted that the evidence demonstrated that its project management, contracting, account and cost oversight controls for the Turkey Point Units 6 & 7 project were reasonable and prudent. (FPL BR 22) 

Regarding accounting and cost oversight, FPL witness Powers explained that FPL relied on its corporate and overlapping business unit controls for recording and reporting transactions.  These controls are regularly assessed and audited.  (TR 934)  FPL witness Scroggs addressed FPL’s contracting controls and preference for competitive bidding and explained that case-by-case justification was otherwise necessary for alternatives to competitive bidding. (TR 785-787)  He also discussed FPL’s reliance on routine project meetings, communications, and reports. (TR 776-780)

FPL asserted its internal controls were audited by Commission audit staff and Concentric Energy Advisors (Concentric). (FPL BR 21-22)  Commission audit staff concluded that “FPL employs internal controls, risk evaluation, management oversight, and regular reporting requirements that adequately address project schedule, budget, costs, vendor performance, and risk.”  (EXH 100, p. 6)  FPL witness Reed, who presented the Concentric review, concluded, “In addition, Concentric's review indicates that FPL’s management of the PTN [Turkey Point] 6 & 7 Project over the course of 2011 has resulted in prudently incurred costs.” (TR 67)

FPL maintained that no party had presented evidence disputing the adequacy of FPL’s internal controls for its Turkey Point Units 6 & 7 project. (FPL BR 22)

SACE

SACE argued that FPL should be found imprudent based on a NRC’s May 4, 2012 letter (Exhibit 116), that noted FPL failed to provide accurate information to the NRC related to its COL in the areas of safety and environmental review.  SACE concluded that “[r]easonable and prudent, project management, contracting, accounting, and cost oversight would have prevented such an outcome.  The Commission should deny FPL’s request for recovery of 2011, 2012, and 2013 Turkey Point Units 6 & 7 project costs.” (SACE BR 17)  There is no discussion or additional argument in SACE’s brief supporting its position; instead, SACE relied on its discussion under Issues 20 and 21.  (SACE BR 17)

OPC, FIPUG, FEA and FRF

            Prior to hearing, OPC and FRF took “no position,” on this issue.  In their respective post-hearing briefs, there is no discussion of this issue.  Therefore, pursuant to the Prehearing Order, OPC and FRF have waived their positions on this issue.  FIPUG and FEA took no position on this issue.

 

ANALYSIS

This issue addresses FPL’s 2011 project management, contracting, accounting, and oversight controls for the Turkey Point Units 6 & 7 project.  Staff notes that if, in Issue 20, the Commission determines that FPL’s 2011 Turkey Point Units 6 & 7 project activities do not qualify as Section 366.93, F.S., activities, then this issue becomes moot for purposes of implementing Section 366.93, F.S., and Rule 25-6.0423, F.A.C.  However, staff believes FPL’s project activities do qualify as preconstruction activities and consequently, pursuant to FPL’s petition, a determination of FPL’s 2011 prudence is required by Section 366.93, F.S., and Rule 25-6.0423, F.A.C.

The only asserted concern was argued by SACE.  SACE asserted that had FPL been reasonable and prudent, FPL would not have received a May 4, 2012, letter from the NRC. (SACE BR 17)  The letter was entered into the record as Exhibit 116.  A portion of Exhibit 116 stated the following:

The NRC staff issued requests for additional information (RAIs) in the areas of geology, seismology, and geotechnical engineering in September and October 2011 as part of its review of Sections 2.5.1 - 2.5.5 of your combined license application (COLA) for Turkey Point Units 6 and 7. Many of the RAI responses are either unclear, incomplete, or based on conclusions that are not supported by the references provided. Further, in some cases, FPL's responses reflect a re-interpretation of the data and results of peer reviewed publications, which has resulted in dismissal of certain geologically recent deformations. Dismissal of such information could result in minimizing the potential seismic hazard in the region without providing sufficient justification. Based on the technical information provided to date, significant technical issues remain.

Before the NRC staff will restart its review in the geology, seismology, and geotechnical areas, FPL needs to revise the RAI responses and make substantial modifications to Final Safety Analysis Report (FSAR) Sections 2.5.1-2.5.5. Specific examples (but not an all inclusive list) of deficiencies are provided in Enclosure 1. The staff also requests that FPL: 1) conduct an internal audit of its quality assurance processes and management oversight processes that were in place when FPL performed the work submitted as part of its COLA application in these areas; 2) conduct an "extent of condition" quality assurance audit of FPL's contractor that performed this work and any other work that FPL's contractor has performed on the Turkey Point Units 6 and 7 COLA; and 3) inform NRC of its findings and any corrective actions taken in the development of its revised application materials for FSAR Sections 2.5.1-2.5.5 to mitigate the deficiencies.

(EXH 116)

FPL witness Scroggs explained that the COL application occurred in 2009 and the events of Fukushima happened in March of 2011. (TR 888)  Following the events of Fukushima, there was heightened interest in seismic hazards. (TR 863, 888)  FPL met with the NRC in May of 2011, and later in 2011 FPL received a set of requests for additional information. (TR 888)  When witness Scrogg`s was questioned at the hearing as to whether the NRC’s geologic and seismologic questions were due to lack of performance or a request for additional information, witness Scroggs responded:

I think it runs the range.  You know, you have --it's a very highly technical and complex subject area, and you have very well-versed academics who have studied the area and they have certain opinions.  So when our experts answered original questions and they didn't put a lot of weight on a certain survey or a certain piece of information, but the NRC wanted to see more information on that, maybe they would put more weight on it, that's what they're asking to provide more information.  So when you see questions that, you know, not supported by the references provided in the, in the first paragraph, I think they're saying that, you know, you need to provide more information, more support for the conclusions that your experts have come to.

(TR 889)

Regarding the audits requested by the NRC in Exhibit 116, witness Scroggs confirmed that the audits for both FPL and its contractor were complete and the NRC had been informed of the results. (TR 863)  FPL retained witness Diaz with ND2 Group, a consulting firm, to review the reasonableness of FPL’s continued pursuit of a COL for the Turkey Point 6 & 7 project. (TR 895-896)  Witness Diaz opined that audits are instituted and normally established as part of the NRC’s quality assurance programs. (TR 904)  FPL witness Reed, with Concentric Energy Advisors, Inc., presented an independent review of FPL’s 2011 internal project controls, processes, and procedures. (TR 23-24, 26-27)  FPL witness Reed commented that nothing in the NRC letter changed his views regarding FPL’s 2011 project management. (TR 164)  He continued to believe all of FPL’s 2011 decisions and costs were prudent. (TR 164)  Witness Reed commented that the matter will likely be addressed in the review of FPL’s 2012 activities because the letter was dated May 4, 2012. (TR 159-160)

Audit staff witnesses Fisher and Rich reviewed FPL’s 2011 project management controls. (TR 1305-1306; EXH 100)  The review was entered into the record as Exhibit 100.  The review included, among other things, a summary depiction of historical, current, and future relevant key issues, such as cost estimates, permitting, construction contract, long lead time forging, and Fukushima impacts. (EXH 100, p. 12)  Audit staff’s review also noted the NRC’s May 4, 2012, letter, and that the project schedule and costs impacts due to Fukushima were unknown at this time. (EXH 100, p. 11)  Audit staff’s review did not present any findings of imprudence.

FPL’s Turkey Point Units 6 & 7 accounting and related controls were generally described by FPL witness Powers. (TR 933-939)  Witness Powers noted that the 2011 costs and controls are subject to audits. (TR 947-948)

Commission staff accounting audit witness Ngo provided testimony and sponsored the staff’s 2012 accounting audit report of FPL’s 2011 costs associated with the Turkey Point Units 6 & 7 project.  (TR 1314-1316; EXH 103)  As noted in this testimony, the staff’s audit activities included reconciliation and verification of 2011 costs to the general ledger and monthly accrual balances.  The staff audit report verified FPL’s 2011 Nuclear Cost Recovery Clause filings are consistent with and in compliance with Section 366.93, F.S. and Rule 25-6.0423, F.A.C.  Witness Ngo did not report any findings.

Prudence Standard

As previously discussed in Issues 8, 9, and 15, the standard for determining prudence is consideration of what a reasonable utility manager would have done, in light of the conditions and circumstances which were known, or should been known, at the time the decision was made.

Based on the foregoing, staff believes that FPL’s 2011 Turkey Point Units 6 & 7 project management and accounting and related controls were subjected to a reasonable level of review sufficient to determine prudence.  Staff believes there is no record evidence identifying any FPL 2011 Turkey Point Units 6 & 7 project management decisions or accounting as unneeded or unreasonable.  Staff also believes that, at this time, no party has identified specific 2011 FPL Turkey Point Units 6 & 7 project management actions as unreasonable or imprudent.

Staff believes that review of emergent matters, such as those discussed in Exhibit 116, are, as characterized by FPL witness Reed, a normal and expected effort in a future Nuclear Cost Recovery Clause proceedings.  Until a review of FPL's final actions regarding the Exhibit 116 emergent matters is completed, staff believes it is premature to assess FPL’s prudence at this time.  Accordingly staff believes there is no evidence of imprudent 2011 project management and related controls has been reasonably demonstrated.

CONCLUSION

Staff recommends the Commission find that project management, contracting, accounting and cost oversight controls employed by FPL during 2011 for the Turkey Point Units 6 & 7 project were reasonable and prudent.

 

 

 

Issue 25: 

 What system and jurisdictional amounts should the Commission approve as FPL's final 2011 prudently incurred costs and final true-up amounts for the Turkey Point Units 6 & 7 project?

Recommendation: 

 Staff recommends the Commission approve as prudently incurred 2011 Turkey Point Units 6 & 7 project preconstruction costs of $23,150,978 ($22,877,378 jurisdictional).  The recommended final 2011 true-up amount, net of prior recoveries, is an over recovery of $15,372,530 and should be used in determining the net total 2013 Nuclear Cost Recovery Clause amount.  (Breman)

Position of the Parties

FPL: 

 The Commission should approve FPL’s final 2011 prudently incurred Turkey Point 6 & 7 Preconstruction expenditures of $23,150,979 (system), $22,877,378 (jurisdictional), and the final 2011 true-up amount of ($14,629,595).  The Commission should also approve Turkey Point 6 & 7 Preconstruction carrying charges of ($1,555,615) and Site Selection carrying charges of $171,052, as well as the final 2011 carrying charge true-up amount of ($742,934).  FPL’s 2011 expenditures were supported by comprehensive procedures, processes and controls that help ensure those expenditures were prudent.  The net amount of ($15,372,530) should be included in FPL’s 2013 NCR amount.

OPC: 

 No position.

SACE: 

 None.  FPL failed to demonstrate the requisite intent to build in Docket 110009-EI, and thus was not engaged in the “siting, design, licensing, and construction” of TP 6 & 7, and thus is not eligible for recovery of these 2011 costs related to TP 6 & 7.

FIPUG: 

 This is a fall out issue.

FEA: 

 Agree with FIPUG.

FRF: 

 No position.

Staff Analysis: 

  This issue addresses FPL’s request concerning the prudence of its 2011 Turkey Point Units 6 & 7 incurred costs and the final 2011 project true-up of amounts FPL will be required to refund during 2013.  Decisions in Issues 20 and 24 could impact the amounts the Commission should approve in this issue.  No new matters were disputed that were not already addressed in prior issues.

PARTIES’ ARGUMENTS

FPL

FPL’s 2011 Turkey Point Units 6 & 7 project costs were presented in detail through the testimony of FPL witnesses Scroggs and Powers and their respective exhibits.  FPL asserted this evidence supports Commission approval of 2011 prudently incurred Turkey Point Units 6 & 7 preconstruction expenditures of $23,150,979 (system), $22,877,378 (jurisdictional), and the final 2011 true-up over recovery amount of $14,629,595.  FPL also asserted that the testimony also supports Commission approval of Turkey Point Units 6 & 7 preconstruction carrying charges of ($1,555,615) and site selection carrying charges of $171,052, as well as the 2011 carrying charge true-up amounts of ($742,934).  FPL maintained that the net amount of ($15,372,530) should therefore be included in FPL’s 2013 Nuclear Cost Recovery Clause amount.  (FPL BR 23; TR 798-801, 925-927; EXHs 33, 49)

SACE

SACE, consistent with its position in Issue 20, maintained that FPL’s activities since January 2011 failed to demonstrate the requisite intent to build Turkey Point Units 6 & 7.   Thus, SACE asserted that FPL is not eligible for recovery of its project costs.    (SACE BR 18)

OPC and FRF

Prior to hearing OPC and FRF took “no position.”  Their respective post-hearing briefs did not present a different position.  Therefore, pursuant to the Prehearing Order, OPC and FRF have waived their positions on this issue.

FIPUG and FEA

FIPUG, joined by FRF, asserted this is a fall out issue and therefore did not discuss this issue in their respective post-hearing briefs.

ANALYSIS

This issue addresses the level of FPL’s 2011 prudently incurred project costs and the final 2011 true-up amount FPL will be required either to refund or collect during 2013 based on the resolution of Issues 20 and 24.  No additional matters impacting the 2011 period were disputed.

Staff notes that if, in Issue 20, the Commission determines that FPL’s 2011 Turkey Point Units 6 & 7 project activities do not qualify as Section 366.93, F.S., activities, then the Commission does not need to make a prudence determination and should require FPL to refund all amounts FPL collected that were held subject to this prudence review.  However, staff believes FPL’s project activities do qualify as preconstruction activities and consequently, pursuant to FPL’s petition, a determination of FPL’s 2011 prudently incurred costs and final true-up amount is required by Section 366.93, F.S., and Rule 25-6.0423, F.A.C.

Issue 24 addresses the prudence of FPL’s 2011 management of the Turkey Point Units 6 & 7 project.  Any finding of imprudence in Issue 24 should be reflected in the Commission’s determinations in this issue.  However, as discussed in Issue 24, staff believes FPL prudently managed the project during 2011.

FPL’s 2011 Turkey Point Units 6 & 7 Project Costs

FPL provided a series of schedules detailing its 2011 project costs including its calculation of its requested 2011 recovery amount; this information is contained in Exhibit Exhibit 33.  In Exhibit 33, FPL witnesses Powers and Scroggs indicated that the 2011 incurred preconstruction costs for Turkey Point Units 6 & 7 project include capital costs of $23,150,978 ($22,877,378 jurisdictional).  Exhibit 33 also indicated that the carrying charges on these capital costs totaled an over recovery of $1,555,615. (TR 926-927)  Exhibit 38 provided a listing of FPL’s 2011 preconstruction activities and associated costs. (TR 926-927)  FPL provided a summary schedule comparing its actual 2011 costs to its approved estimated true-up as well as initial projection of 2011 recovery amounts. (EXH 45)  FPL requested the Commission review and approve FPL’s 2011 amounts as prudent and recoverable. (TR 919-921)  In support of its request, FPL witness Scroggs stated:

The major activities centered around supporting the additional information requested by regulatory agencies related to the federal and state applications and activities supporting installation of the Underground Injection Control (UIC) exploratory well at the project site.

(TR 789)

FPL’s year-ending 2011 incurred costs were $14,804,558 less than its May 2011 estimate of $37,955,536. (TR 798)  FPL spent $9,450,642 less in licensing costs primarily because of lower than planned NRC and NuStart fees. (TR 799; EXH 33, p. 23)  Project permitting costs were $1,737,480 lower than previously estimated due to reduced staffing requirements and communications support. (TR 800; EXH 33, p. 23)  Engineering and design costs were $3,616,435 lower than planned because of FPL’s decision to further delay the start of the UIC exploratory well while various regulatory agencies were consulted. (TR 800-801; EXH 33, p. 23)  None of the parties identified any specific activity or cost as imprudently incurred or a result of an imprudent action.

FPL’s 2011 Turkey Point Units 6 & 7 Project Final True-up Amount

FPL witness Powers explained that the actual 2011 project jurisdictional costs were compared to the prior estimate of 2011 jurisdictional costs to determine the final net over recovery true-up amount for 2011 of $15,372,530. (TR 927; EXH 45, 49)  The requested 2011 final net true-up amount includes the following items: over-estimated capital costs of $14,629,596 and over-estimated carrying costs of $742,934. (TR 927; EXH 45, 49)  FPL requested that these amounts be used in determining the 2013 total NCRC recovery amount. (TR 920-921; EXH 49)  As discussed in Issue 24, audit staff witness Ngo audited FPL’s accounting and related controls. (TR 1315)  Audit staff witness Ngo reported no findings. (TR 1316)

Prudence Standard

As noted in Issues 8, 9, 15, and 24, the standard for determining prudence is consideration of what a reasonable utility manager would have done, in light of the conditions and circumstances which were known, or should been known, at the time the decision was made.  Staff notes that beyond the SACE arguments discussed in Issues 20 and 24, no other concerns were identified regarding the reasonableness or prudence of FPL’s 2011 incurred costs that would support any adjustment to adjust FPL’s requested amounts for the 2011 period.

Consistent with staff’s recommendations in Issues 20 and 24, staff’s verification of FPL’s calculations and true-up amount, and a preponderance of the evidence in the record, staff believes FPL has demonstrated the prudence of its requested 2011 incurred costs and final true-up amount for the Turkey Point Units 6 & 7 project.

CONCLUSION

Staff recommends the Commission approve as prudently incurred 2011 Turkey Point Units 6 & 7 project preconstruction costs of $23,150,979 ($22,877,378 jurisdictional).  The recommended final 2011 true-up amount, net of prior recoveries, is an over recovery of $15,372,530 and should be used in determining the net total 2013 Nuclear Cost Recovery Clause amount.

 

 

 

Issue 26: 

 What system and jurisdictional amounts should the Commission approve as reasonably estimated 2012 costs and estimated true-up amounts for FPL's Turkey Point Units 6 & 7 project?

Recommendation: 

 Staff recommends the Commission approve as reasonably estimated 2012 Turkey Point Units 6 & 7 project preconstruction costs of $34,907,426 ($34,279,877 jurisdictional).  The estimated 2012 true-up amount of $734,498, net of prior recoveries, should be used in determining the total net 2013 Nuclear Cost Recovery Clause amount.  (Lewis)

Position of the Parties

FPL: 

 The Commission should approve as reasonable FPL’s 2012 actual/estimated Preconstruction expenditures of $34,907,426 (system), $34,279,877 (jurisdictional), and the 2012 estimated true-up amount of $3,257,796.  The Commission should also approve as reasonable FPL’s 2012 actual/estimated Preconstruction carrying charges of $3,097,000 and Site Selection carrying charges of $180,883, as well as the 2012 carrying charge estimated true-up amount of ($2,523,298).  FPL’s 2012 actual/estimated expenditures are supported by comprehensive procedures, processes and controls which help ensure that these costs are reasonable.  The net amount of $734,498 should be included in FPL’s 2013 NCR amount.

OPC: 

 No position.

SACE: 

 None.  FPL’s activities since January 2011 fail to demonstrate the requisite intent to build the LNP [sic].  As such, FPL is not engaged in the “siting, design, licensing, and construction” of TP 6 & 7, and thus is not eligible for recovery of costs related to TP 6 & 7.  Furthermore, FPL has failed to demonstrate that completion of TP 6 & 7 is feasible in the long term.

FIPUG: 

 This is a fall out issue.

FEA: 

 Agree with FIPUG.

FRF: 

 No position.

Staff Analysis: 

 This issue addresses FPL’s request concerning the reasonableness of its 2012 Turkey Point Units 6 & 7 project estimated costs and the estimated true-up amount for 2012.  Decisions in Issues 20, 21 and 24 could impact the amounts the Commission should approve in this issue.    No new matters were disputed that were not already addressed in prior issues.

PARTIES’ ARGUMENTS

FPL

In 2012, FPL estimated it would continue to focus on obtaining the necessary Turkey Point Units 6 & 7 project licenses and permits that will enable construction and operation of the facility.  FPL opined that the estimated pace of the project was maintained without incurring unnecessary cost or schedule risks.  (FPL BR 23-24; TR 805-808)

As supported by FPL witnesses Scroggs and Powers, FPL argued that the Commission should approve, as reasonable, FPL’s 2012 Turkey Point Units 6 & 7 estimated preconstruction expenditures of $34,907,426 ($34,279,877 jurisdictional), and the estimated 2012 true-up amount of $3,257,796.  FPL also asserted that the Commission should approve as reasonable FPL’s 2012 project preconstruction carrying charges of $3,097,000 and site selection carrying charges of $180,883, as well as the 2012 carrying charge estimated true-up amount of ($2,523,298).  FPL requested the net amount of $734,498 should be included in its 2013 Nuclear Cost Recovery Clause Amount.  (FPL BR 24; TR 960; EXH 40; EXH 49)

SACE

SACE’s post-hearing brief did not raise any additional argument supporting its position and instead relied on its discussion under Issues 20 and 21.  (SACE BR 18)

OPC and FRF

Prior to hearing OPC and FRF took “no position.”  Their respective post-hearing briefs did not discuss this issue and did not present a different position.  Therefore, pursuant to the Prehearing Order, OPC and FRF have waived their positions on this issue.

FIPUG and FEA

FIPUG, joined by FEA, asserted this is a fall out issue and therefore did not discuss this issue in their respective post-hearing briefs.

ANALYSIS

This issue addresses FPL’s request concerning the reasonableness of its 2012 Turkey Point Units 6 & 7 project estimated costs and the estimated true-up amount for 2012.  Decisions in Issues 20, 21 and 24 could impact the amounts the Commission should approve in this issue.    No new matters were disputed that were not already addressed in prior issues.

Staff notes that if, in Issue 20, the Commission determines that FPL’s Turkey Point Units 6 & 7 project activities do not qualify as Section 366.93, F.S., activities, then it follows that ongoing similar activities during the 2012 period would also not qualify.  Since FPL’s 2011-2012 period activities are substantially similar in nature, a disqualification finding in Issue 20 would make this issue moot. However, staff believes FPL’s project activities do qualify as preconstruction activities and consequently, pursuant to FPL’s petition, a determination of FPL’s 2012 costs is required by Section 366.93, F.S., and Rule 25-6.0423, F.A.C.

Issue 21 addresses the feasibility of completing the Turkey Point Units 6 & 7 project.  FPL’s estimates for 2012 are consistent with completing the project.  A finding that completing the project is not feasible would require a finding that FPL’s estimates for the 2012 period are not reasonable estimates of project termination activities.

Issue 24 addresses the prudence of FPL’s 2011 management of the Turkey Point Units 6 & 7 project.  Any finding of imprudence in Issue 24 that affects future costs should be reflected in the Commission’s determinations in this issue.  However, as discussed in Issue 24, staff believes FPL prudently managed the project during 2011 and therefore there are no resultant adjustments to FPL’s estimates for the 2012 period, at this time.

FPL’s 2012 Turkey Point Units 6 & 7 Project Costs

FPL witness Powers provided support for the 2012 Turkey Point Units 6 & 7 project costs and methods used to determine the requested estimated true-up recovery amount. (TR 917-927, 933-939, 946-949; 960-962; EXH 40)  Witnesses Powers and Scroggs co-sponsored Exhibit 40 which includes a series of schedules detailing FPL’s 2012 project costs and its calculation of its requested 2012 recovery amount. (TR 803-804, 952)

In Exhibit 40 FPL witnesses Powers and Scroggs identified 2012 Turkey Point Units 6 & 7 preconstruction costs of $34,907,426 ($34,279,877 jurisdictional).  Exhibit 40 also indicated that the estimated 2012 preconstruction carrying costs were over projected by $2,423,506.  There are no 2012 site selection costs for the Turkey Point Units 6 & 7 project as these costs have been fully recovered.  (EXH 46) 

FPL witness Scroggs provided descriptions of the 2012 Turkey Point Units 6 & 7 project activities, costs, and variances. (TR 803-841; EXH 40; EXH 41)  In support of FPL’s request, FPL witness Scroggs stated:

FPL continues to develop Turkey Point 6 & 7 through a deliberate and careful process navigating through the four phases of project development:  Exploratory, Licensing, Preparation, and Construction.  The project has completed the exploratory phase, and is currently focused on the Licensing phase prior to initiating Preparation phase activities.  The approach allows FPL to make progress on obtaining licenses and approvals without taking on the risks of committing to a specific construction schedule and the associated expenditures.

(TR 807-808)

            FPL witnesses Scroggs and Powers provided the current deployment schedule for various phases of the Turkey Point Units 6 & 7 project from 2007 through 2023. (EXH 40)  During 2012, FPL has been engaged primarily in activities associated with licensing and permitting requirements. (TR 814, 820-825)  Witness Scroggs testified that FPL expects to receive a COL from the NRC for the Turkey Point Units 6 & 7 project in June 2014. (TR 825)  Preliminary activities such as initiating contracts for construction would likely take place in early 2015, “with actual activities on site moving dirt as early as I think July or August 2014.” (TR 880)

 

            FPL’s estimate of year-ending 2012 incurred costs was $34,907,426. (EXH 40)  The 2012 cost estimate included amounts for licensing of $27,805,569, permitting of $1,463,969, and engineering and design of $5,637,888.  The estimated 2012 costs for the categories of long lead procurement advance payments, power block engineering and procurement, and transmission engineering activities were zero. (TR 836-837)

 

            The estimated 2012 costs are $3,514,338 greater than FPL’s May 2011 projection of its 2012 costs. (EXH 40)  Licensing costs increased by $442,677, permitting costs decreased by $956,177, and engineering and design costs increased by $4,027,838.  FPL attributed the increase to the engineering and design activities performed in 2012 to support the permitting effort for the underground injection control well system that was delayed from 2011 and pushed into 2012. (TR 840)

 

FPL’s 2012 Turkey Point Units 6 & 7 Project Estimated True-up Amount

            Witness Powers explained that the estimated 2012 project costs were compared to the prior projection of 2012 costs to determine the estimated true-up amount for 2012 of $734,498.  (TR 960 - 962; EXH 49)  The projected amounts were identified in Exhibits 38, 40 and 49.  The requested 2012 true-up amount includes the following items: under-projected preconstruction costs of $3,257,796 and a $2,523,298 over-projection of preconstruction carrying costs. (TR 960; EXH 49)  No additional site selection costs will be incurred in the future and there is no related true-up of 2012 site selection costs to be included in the net total Nuclear Cost Recovery Clause amount.  (TR 960; EXH 49)  These 2012 estimated true-up amounts were included in FPL’s net total Nuclear Cost Recovery Clause request of $151,491,402.  (TR 953, 959, 972; EXH 49)

 

            Consistent with staff’s recommendations in prior issues, staff’s verification of FPL’s calculations and true-up amounts, and a preponderance of the evidence in the record, staff believes FPL has demonstrated the reasonableness of its requested estimate of 2012 incurred costs and true-up amounts for the Turkey Point Units 6 & 7 project.

 

CONCLUSION

            Staff recommends that the Commission approve as reasonably estimated 2012 Turkey Point Units 6 & 7 project capital costs of $34,907,426 ($34,279,877 jurisdictional).  The estimated 2012 true-up amount of $734,498, net of prior recoveries, should be used in determining the total net 2013 Nuclear Cost Recovery Clause amount.

 

Issue 27: 

 What system and jurisdictional amounts should the Commission approve as reasonable projected 2013 costs for FPL's Turkey Point Units 6 & 7 project?

Recommendation: 

 Staff recommends that the Commission approve as reasonably projected 2013 Turkey Point 6 & 7 project preconstruction costs of $29,211,385 ($28,686,236 jurisdictional).  The projected 2013 amount of $34,994,155 should be used in determining the net Nuclear Cost Recovery Clause amount.  (Lewis)

Position of the Parties

FPL: 

 The Commission should approve as reasonable FPL’s 2013 projected Preconstruction expenditures of $29,211,385 (system), $28,686,236 (jurisdictional).  The Commission should also approve as reasonable FPL’s 2013 projected Preconstruction carrying charges of $6,127,036 and Site Selection carrying charges of $180,883.  FPL’s 2013 projected expenditures are supported by comprehensive procedures, processes and controls which help ensure that these costs are reasonable.  The net amount of $34,994,155 should be included in FPL’s 2013 NCR amount.

OPC: 

 No position.

SACE: 

 None.  FPL’s activities since January of 2011 fail to demonstrate the requisite intent to build TP 6 & 7.  As such, FPL is not engaged in the “siting, design, licensing, and construction” of TP 6 & 7, and thus is not eligible for recovery of costs related to TP 6 & 7.  Furthermore, FPL has failed to demonstrate that completion of TP 6 & 7 is feasible in the long term.

FIPUG: 

 This is a fall out issue.

FEA: 

 Agree with FIPUG.

FRF: 

 No position.

Staff Analysis: 

 This issue addresses FPL’s request concerning the reasonableness of its projected 2013 Turkey Point Units 6 & 7 project costs and recovery amount.  Decisions in Issues 20, 21 and 24 could impact the amounts the Commission should approve in this issue.    No new matters were disputed that were not already addressed in prior issues.

PARTIES’ ARGUMENTS

FPL

FPL projects to incur costs in 2013 to support the continued review of the Turkey Point Units 6 & 7 project licenses, applications, approvals, and planning studies.  FPL asserted its projected 2013 Turkey Point Units 6 & 7 preconstruction expenditures were $29,211,385 ($28,686,236 jurisdictional).  FPL also asserted the Commission should approve as reasonable preconstruction carrying charges of $6,127,036 and site selection carrying charges of $180,883.  FPL opined that the net amount of $34,994,155 should be included in its 2013 Nuclear Cost Recovery Clause amount.  (FPL BR 25; TR 804-806, 828, 835-836, 961; EXH 40; EXH 49)

SACE

SACE’s post-hearing brief did not raise any additional argument supporting its position and instead relied on its discussion under Issues 20 and 21.  (SACE BR 18)

OPC and FRF

Prior to hearing, OPC and FRF took “no position.”  Their respective post-hearing briefs did not discuss this issue and did not present a different position.  Therefore, pursuant to the Prehearing Order, OPC and FRF have waived their positions on this issue.

FIPUG and FEA

FIPUG, joined by FEA, asserted this is a fall out issue and therefore did not discuss this issue in their respective post-hearing briefs.

ANALYSIS

This issue addresses FPL’s request concerning the reasonableness of its projected 2013 Turkey Point Units 6 & 7 project costs and recovery amount.  Decisions in Issues 20, 21 and 24 could impact the amounts the Commission should approve in this issue.    No new matters were disputed that were not already addressed in prior issues.

Staff notes that if, in Issue 20, the Commission determines that FPL’s Turkey Point Units 6 & 7 project activities do not qualify as Section 366.93, F.S., activities, then it follows that ongoing similar activities during the 2013 period would also not qualify.  Since FPL’s 2011-2013 period activities are substantially similar in nature, a disqualification finding in Issue 20 would make this issue moot. However, staff believes FPL’s project activities do qualify as preconstruction activities and consequently, pursuant to FPL’s petition, a determination of the reasonableness of FPL’s 2013 costs is required by Section 366.93, F.S., and Rule 25-6.0423, F.A.C.

Issue 21 addresses the feasibility of completing the Turkey Point Units 6 & 7 project.  FPL’s projections for the 2013 period are consistent with completing the project.  A finding that completing the project is not feasible would require a finding that FPL’s estimates for the 2013 period are not reasonable estimates of project termination activities.

Issue 24 addresses the prudence of FPL’s 2011 management of the Turkey Point Units 6 & 7 project.  Any finding of imprudence in Issue 24 that results in forward costs should be reflected in the Commission’s determinations in this issue.  However, as discussed in Issue 24, staff believes FPL prudently managed the project during 2011 and therefore there are no resultant adjustments for the 2013 period, at this time.

FPL’s 2013 Turkey Point Units 6 & 7 Project Costs

            FPL witness Powers provided support for the 2013 Turkey Point Units 6 & 7 project costs and methods used to determine the requested recovery amount. (TR 961-962; EXH 49)  FPL witness Scroggs provided descriptions of the 2013 Turkey Point Units 6 & 7 project activities and costs. (TR 951-952, 957-958)  Witnesses Powers and Scroggs co-sponsored Exhibit 40 which includes a series of schedules detailing FPL’s 2013 project costs and its calculation of its requested 2013 recovery.

 

            In Exhibit 49, witness Powers identified the 2013 Turkey Point Units 6 & 7 preconstruction capital costs of $29,211,385 ($28,686,236 jurisdictional).  Exhibit 49 also indicated that the projected 2013 preconstruction carrying costs were $6,127,036.  (TR 960-961)  On Exhibit 49, witness Powers identified additional carrying costs on site selection costs of $180,833 due to tax effects on FPL’s previously recovered site selection costs. (TR 957; EXH 40)  In support of FPL’s request, FPL witness Scroggs stated:

 

Procurement activities in 2012 and 2013 continue to focus on the licensing and permitting process.  Professional services are required from technical and environmental consultants, legal service firms, and subject matter experts to respond to the inquiries of intervenors and the reviewing agencies during the application review process or subsequent hearings.  Additionally, some planning studies and early site preparation design activities are scheduled for 2013.

 

(TR 814)

 

            Witness Scroggs described FPL’s focus as remaining on obtaining the license, permits, and approvals necessary to construct and operate the Turkey Point Units 6 & 7 project. (TR 822)  Additionally, witness Scroggs explained that the land use and site certification hearings have been consolidated into a single hearing by the Department of Environmental Protection and the administrative law judge which is scheduled to take place in July 2013.  (TR 759-760, 823-824)

 

            FPL’s projected 2013 costs total $29,211,385. (TR 961)  The 2013 costs projection included amounts for licensing of $26,743,630, permitting of $1,231,506, and engineering and design of $1,236,250.  The following cost categories had 2013 cost projections of zero:  long-lead procurement; power block engineering and procurement; and transmission engineering.  (TR 836-837, 839-840; EXH 40)  No party identified any amount of FPL’s 2013 Turkey Point Units 6 & 7 project cost estimates as unreasonable or unnecessary to complete the project.

 

FPL’s 2013 Turkey Point Units 6 & 7 Project Recovery Amount

            FPL’s requested Nuclear Cost Recovery Clause amount for 2013 project costs was $34,994,155.  (TR 961; EXH 49)  This amount includes the following items that have been previously discussed in this issue:  pre-construction capital costs in the amount of $28,686,236, associated carrying charges of $6,127,036, and $180,833 in carrying charges on prior years’ unrecovered site selection costs. (TR 960; EXH 40; EXH 49)  FPL included these 2013 amounts in its total net NCRC recovery request of $151,491,402. (TR 953; EXH 49)

 

            Consistent with staff’s recommendations in prior issues, staff’s verification of FPL’s calculations, and a preponderance of the evidence in the record, staff believes FPL has demonstrated the reasonableness of its requested projection of 2013 incurred costs and recovery amounts for the Turkey Point Units 6 & 7 project.

CONCLUSION

            Staff recommends that the Commission approve as reasonably projected 2013 Turkey Point Units 6 & 7 preconstruction costs of $29,211,385 ($28,686,236 jurisdictional).  The projected 2013 amount of $34,994,155 should be used in determining the net Nuclear Cost Recovery Clause amount.

 

Issue 28: 

 Should the Commission approve what FPL has submitted as its 2012 annual detailed analysis of the long-term feasibility of completing FPL’s Extended Power Uprate project, as provided for in Rule 25-6.0423, F.A.C.?  If not, what action, if any, should the Commission take?

Recommendation: 

 Yes.  The analytical approach that was used by FPL in performing its 2012 feasibility analysis for the Uprate project is similar to the Company’s approach used in prior feasibility analyses.  The results of FPL’s analysis demonstrate that completion of the Uprate project remains in the best interest of FPL’s customers.  (Graves, Garl)

Position of the Parties

FPL: 

 Yes.  FPL’s analysis considers a range of fuel and environmental compliance costs to serve as possible future scenarios in which to view the economics of the EPU project.  FPL annually updates these fuel and environmental compliance cost projections and updates a number of other assumptions for its economic analysis.  Based on this analysis, completion of the EPU project is projected to be solidly cost-effective for FPL’s customers.  There is no reason to break apart the project and examine its underlying components on a stand-alone basis, nor would it be feasible to do so.  The entire project, as approved by the Commission, continues to be cost effective.  The results of the analysis fully support the feasibility of completing the EPU project.

OPC: 

 No.  FPL’s estimate of TP EPU costs has increased by more than $500 million in a year.  FPL’s consolidated feasibility study masks the impact of the soaring, runaway costs of FPL’s Turkey Point uprate project on customers.  Plant-specific views are needed.  OPC witness Smith’s analysis separates the uprate project costs by plant, then assigns 50% of total savings to each plant site.  The simplifying assumption of the 50/50 assignment of savings is enormously favorable to the economics of the Turkey Point uprate project.  In spite of this, Mr. Smith’s exhibit shows that the Turkey Point uprate project would result in net costs, rather than net benefits, based on FPL’s current estimate of total costs.

SACE: 

 Agree with OPC.

FIPUG: 

 The Commission should not approve the detailed analyses of the long-term feasibility of completing FPL’s Extended Power Uprate project because FPL did not sufficiently separate the Turkey Point Uprate project from the St. Lucie Uprate project.  The distinct projects should be evaluated for long-term feasibility separately, and the Commission should so direct FPL.

FEA: 

 No.  The Commission should not approve FPL’s long-term feasibility study of completing FPL’s Extended Power Uprate (EPU) Project.  The $555 million year over year increase of the Turkey Point portion of the uprate project dwafs the St. Lucie portion to such a degree that warrants the Commission to require a separate study of the Turkey Point project.

FRF: 

 No.  FPL’s analyses fail to separate the feasibility of the Turkey Point and St. Lucie EPU projects and accordingly are distorted, and the Commission should reject them.

Staff Analysis: 

 As discussed in Issue 21, the Commission’s review of FPL’s annual detailed analysis of the long-term feasibility of FPL’s nuclear projects provides the Commission an opportunity to consider trends impacting the projects and to evaluate whether the projects remain in the best interest of ratepayers.  FPL’s Uprate project consists of modifications that increase the capabilities of four existing generating at two generating sites.  Two of the units are located at the St. Lucie plant site and two are located at the Turkey Point plant site.  Consistent with past feasibility analyses, FPL’s 2012 feasibility analysis examined the Uprate project as a comprehensive project encompassing both sites.     

PARTIES’ ARGUMENTS

            FPL stated that its 2012 Uprate feasibility analysis demonstrates that the completion of the EPU project is solidly cost-effective for customers and should be approved. (FPL BR 26)  FPL further explained that the analytical approach that was used in the 2012 feasibility analysis for the EPU project is the same approach used in the 2007 Determination of Need filing and the 2008, 2009, 2010, and 2011 NCR feasibility analyses. (FPL BR 27)  FPL additionally asserted that no intervenor disputed the results of FPL’s Uprate feasibility analysis. (FPL BR 26)   

           

            In response to arguments that the Uprate project should be split (i.e. evaluated as two separate site-specific projects), FPL provided several arguments.  FPL first contended that the Uprate project was approved by the Commission as a single project and should be evaluated as such. (FPL BR 26)  FPL additionally asserted that such an evaluation would (1) ignore the cost savings and efficiencies that have been gained by proceeding with one comprehensive project, and (2) ignore the impossibility of accurately separating costs by site as if only one or the other plant was uprated. (FPL BR 26)

 

            OPC does not believe the Commission should approve FPL’s 2012 annual detailed analysis of the long-term feasibility of completing FPL’s Uprate project.  OPC argued that the “runaway” costs of the Turkey Point uprate constitute a dramatic change in circumstances that compels an evaluation of the status and feasibility of the Turkey Point uprate on a separate stand alone basis. (OPC BR 2)  OPC additionally claimed that the extremely conservative analysis of its witness, witness Smith, suggests that the Turkey Point uprate is not cost-effective. (OPC BR 3) 

 

            SACE did not provide discussion relating to Issue 28; however, SACE’s position statement is “Agree with OPC.”     

 

            Citing the different locations, as well as other aspects of the uprate projects, FIPUG contended that the two projects are materially different and concluded that the Commission should require that FPL consider, report, and prove the long-term feasibility of each uprate project separately. (FIPUG BR 8)

 

            FEA and FRF contended that the cost overruns experienced by FPL for its Turkey Point uprate support the need to evaluate long-term feasibility of each uprate project separately.  Both parties further argued that the Commission should accept the feasibility analysis performed by OPC witness Smith. (FEA BR 6-7 and FRF BR 11) 

 

 

ANALYSIS

           

            Staff’s analysis is based on FPL’s 2012 feasibility analysis of the FPL Uprate project filed on April 27, 2012.  Staff believes FPL’s feasibility analysis sufficiently shows that completion of the FPL Uprate project is in the best interest of ratepayers.  As discussed in greater detail below, the EPU project is projected to produce a net savings, ranging from $760 million to $243 million, in six of seven future scenarios evaluated by FPL.  Since FPL’s initial filing, the projected capacity of the FPL Uprate project has been increased. (TR 1189-1190)  As discussed in staff’s analysis, inclusion of this assumption would likely result in the FPL Uprate project producing more fuel and environmental savings than currently projected. (TR 1404) 

 

FPL’s 2012 Feasibility Analysis

As previously mentioned, FPL’s Uprate project consists of two uprates at the Company’s St. Lucie site and two uprates at the Company’s Turkey Point site. (TR 117)  Table 28-1 below, provides a summary of the Uprate project.  At the time of the hearing (September 11, 2012), uprates at St. Lucie Unit 1 and Turkey Point Unit 3 were complete. (TR 1077)

Table 28-1:  Summary of Uprate Project

           Source: (EXH 100 p. 26)

FPL’s basic analytical approach for evaluating the feasibility of its Uprate project has remain unchanged since the 2007 Determination of Need filing. (TR 1206)  This approach compares the cumulative present value of revenue requirements (CPVRR) of a resource plan that includes the Uprate project versus a resource plan that excludes the Uprate project and adds instead additional natural gas fired capacity.[49] (TR 1206 and 1239)  No parties disputed FPL’s methodology for evaluating the FPL UPRATE project. 

As with prior feasibility analyses, FPL examined multiple potential future scenarios that result from combining various fossil fuel price forecasts (High, Medium, and Low) and environmental compliance cost forecasts. (TR 1196)  In regard to the environmental compliance cost forecasts, FPL used three forecasts in its 2012 resource planning work:  Env I (representing low CO₂ compliance costs), Env II (representing medium CO₂ compliance costs), and Env III (representing high CO₂ compliance costs). (TR 1214)  Commission Order No. PSC-08-0237-FOF-EI, states “if environmental compliance costs are higher, gas prices will go up.”  Consistent with prior feasibility analyses, FPL excluded a low fuel scenario which included medium or high CO₂ compliance costs.  FPL’s 2012 feasibility analysis of the Uprate project included the same updated forecasts for fuel costs and environmental compliance costs as those used in FPL’s evaluation of its Turkey Point 6 & 7 project. (TR 1243)   

The results of FPL’s analyses, summarized in Table 28-2 below, indicated that a resource plan with the Uprate project is projected to be cost-effective in six of seven potential future scenarios.  No party contested the results of FPL’s analyses.

Table 28- 2:  CPVRR Analysis Results - Estimated NPV of Total Savings from Uprate Project (millions)

        Source: (EXH 88)

As illustrated in Table 28-2 above, the cost-effectiveness of the Uprate project has declined since 2011.  FPL witness Sim testified that the projected cost of natural gas and the projected cost of carbon are two key drivers in the feasibility analyses of FPL’s Uprate project. (TR 1251)   Witness Sim testified that the FPL Uprate project will reduce natural gas consumption by 41 million MMBtu in its first full year (2014) of operation, thus reducing FPL’s reliance on natural gas by approximately 3 percent in that same year. (TR 1223, 1239)  Witness Sim further testified that the FPL Uprate project is projected to reduce carbon dioxide emissions by approximately 32 million tons over the life of the project. (TR 1239-1240)  Therefore, scenarios which include higher fuel costs or higher environmental costs result in greater savings for the FPL Uprate project.  The updated fuel and environmental costs used in FPL’s 2012 feasibility analyses are significantly lower than previous forecasts, thus reducing the projected benefits associated with the FPL Uprate project. (TR 1238-1239, TR 1218-1219)  As discussed in Issue 21, staff has reviewed the aforementioned forecasts and believes they are reasonable for this docket.

            FPL provided updated assumptions that primarily impact the feasibility of the FPL Uprate project including the total capacity of the project.  The projected total incremental capacity increase from the FPL Uprate project has increased from the 450 MW used in the 2011 feasibility analyses to 490 MW. (TR 1215)  FPL witness Powers testified that calculations performed in 2011 support FPL’s current estimate of about 490 MW. (TR 981-982)  The increased MW capacity results in additional fuel savings from the project, thus increasing the cost-effectiveness of the project. (TR 1219) 

For its 2012 feasibility analysis, FPL used a non-binding cost estimate of $3.05 billion. (TR 1216)  When compared to FPL’s 2011 estimate, FPL’s 2012 non-binding capital cost estimate of the FPL Uprate project has increased approximately $0.57 billion.  Witness Jones testified that detailed construction planning disclosed the need for much more extensive construction efforts than had been previously estimated. (TR 1041)  Witness Jones explained that the additional implementation efforts require additional man-hours for engineering, construction, and project support, causing the cost estimate to increase. (TR 1041-1042) 

FPL’s 2012 feasibility analysis excluded approximately $1.46 billion of sunk costs (costs that have been spent through December 31, 2011) resulting in a “going forward” capital cost projection for completing the FPL Uprate project of approximately $1.59 billion ($3.05 billion - $1.46 billion = $1.59 billion). (TR 1216)  FPL’s approach to sunk costs follows the guidance provided by the Commission. (TR 1205)  Commission Order No. PSC-11-0547-FOF-EI, states “the long-term feasibility is primarily meant to analyze the “going forward” costs of the EPU project.”  No parties argued with FPL’s updated FPL Uprate project capital costs.

            FPL’s updated assumptions that primarily impact the feasibility of the Uprate project are summarized in Table 28-3 below.  Staff believes the described assumptions are reasonable for the purposes of evaluating the feasibility of the FPL Uprate project.  Furthermore, no party disputed the discussed assumptions.  For comparison purposes, Table 28-3 also summarizes the same information from FPL’s 2011 feasibility analysis.

Table 28-3:  Summary of Uprate Project Assumptions

             Source: (EXH 86)

Subsequent to FPL’s filing of its feasibility analysis, FPL witness Jones testified that the FPL Uprate project is likely to add approximately 522-532 MW. (TR 1075)  The more than 30 MW projected increase is based on the performance of the St. Lucie uprate which was completed on July 25, 2012. (TR 1074-1075)  The described uprate work increased the capacity of St. Lucie Unit 1 to approximately 144 MW which is approximately 12 percent more megawatts than FPL’s early 2012 estimate of approximately 129 MW. (TR 1074)  If the discussed increased capacity (144 MW) had been included in FPL’s feasibility analyses, it is reasonable to assume greater savings over the life of the project. (TR 1404)

Based on the summation of staff’s review of FPL’s feasibility analyses of the FPL UPRATE project, staff believes that completion of the project is in the best interest of the rate payers.  As demonstrated by the economic analyses of the FPL Uprate project, there is a high likelihood of FPL’s ratepayers realizing net benefits from completion of the FPL Uprate project.  No party argued that FPL should not complete the FPL Uprate project.  

The Need for Separate Economic Analysis by Site  

In the 2011 NCRC proceedings, the Commission addressed the issue of whether there was a need for a separate economic analysis by plant, when examining the Uprate project.  In that proceeding, OPC argued that “the project should be broken up into two separate analyses due to the higher estimated capital costs of the Turkey Point plant portion of the Uprate project . . . .[50]

 

In that same proceeding, several FPL witnesses suggested that requiring separate feasibility analyses by plant site would be difficult.  FPL witness Sim noted that “. . . while separate contracts were acquired for the plant sites, contracts were negotiated based on an uprate of all four nuclear units, and therefore they could not be used to determine costs for a single site without somehow excluding this benefit.”[51]  Commission Order No. PSC-11-0547-FOF-EI, states the following:

 

We [the Commission] agree with FPL that a separate economic analysis for each of the EPU project plant[s] is unnecessary, and would be difficult to calculate.  While a mathematical average of the benefits derived from lessons learned and equipment bulk orders can be developed, it is not known if these would have materialized if only one plant was upgraded.  Therefore, completing separate analyses would incorrectly attribute to the individual plants the benefits gained from performing uprates at both plants simultaneously.[52]

 

In the instant docket, OPC witness Jacobs testified that the increase in the capital cost of the FPL Uprate project is being driven by increasing costs at the Turkey Point plant site. (TR 1298)  Witness Jacobs argued that the increase in the estimated construction cost of the Turkey Point Uprate represents a change in circumstances that compels a separate analysis of the Turkey Point Uprate project. (TR 1299-1300) 

           

Witness Jacobs contended that, in addition to the increase costs, information that came to light in the cycle of this proceeding should lead the Commission to revisit the above stated decision. (TR 1292)  Witness Jacobs cited to a cost estimate from Bechtel, FPL’s Uprate contractor that identified a need for more pipe, cable, and valves at the Turkey Point site when compared to the St. Lucie site. (TR 1293)  OPC witness Smith testified that he used information included in FPL’s testimony to demonstrate that in six of the seven scenarios Turkey Point EPU activities show a net cost to customers. (TR 1271)

 

FPL witness Jones provided rebuttal testimony akin to that offered by FPL in the 2011 NCRC which supports a single feasibility analysis.  FPL witness Jones testified that performing the uprate work on all four units at the two plants would allow the project team to share resources, and that FPL could realize cost savings and leverage purchasing power by purchasing multiple pieces of the same equipment.  Witness Jones continued that those benefits remain true regardless of the resources required at a single plant site. (TR 1329)  Witness Jones additionally provided the following:

. . . benefits of performing the St. Lucie and Turkey Point Extended Power Uprates simultaneously include achieving economies of scale and cost avoidance for personnel, rental and purchase of tools, materials and equipment, volume discounts on major equipment purchases and synergies through design engineering, work package planning, the sharing of lessons learned, best practices and key resources.

(TR 1329)

As stated in the Commission’s prior Order, “completing separate analyses would incorrectly attribute to the individual plants the benefits gained from performing uprates at both plants simultaneously.”  No testimony in the record identifies what costs would have been incurred if an uprate at only one plant site had been pursued.  Additionally no evidence in the record demonstrates that FPL’s current Uprate project estimate reasonably reflects costs that would have been incurred if an uprate at only one plant site had been pursued.  This point is important because FPL’s estimates served as the basis for OPC witness Smith’s analysis and assumptions. (TR 1265)  Therefore, staff believes the testimony and analysis put forth by OPC is not sufficient to compel a deviation from the Commission’s prior decision.

 

Finally, staff notes that OPC’s position statement for Issue 29A states, “At this advanced stage of the project, OPC believes FPL should complete the project.” (OPC BR 6)  Consequently, the additional analysis does not have any bearing on whether the FPL Uprate project should be completed.

CONCLUSION

The analytical approach that was used by FPL in performing its 2012 feasibility analysis for the FPL Uprate project is similar to the Company’s approach used in prior feasibility analyses.  The results of FPL’s analysis demonstrate that completion of the FPL Uprate project remains in the best interest of FPL’s customers.  Therefore, staff believes the Commission should approve FPL’s 2012 annual detailed analysis of the long-term feasibility of completing the FPL Uprate project. 

 

 

 

Issue 29: 

 Should the Commission find that FPL's 2011 project management, contracting, accounting and cost oversight controls were reasonable and prudent for FPL's Extended Power Uprate project?

Recommendation: 

 Yes.  Staff recommends the Commission find that FPL’s 2011 Uprate project management, contracting, accounting and cost oversight controls were reasonable and prudent.  (Breman)

Position of the Parties

FPL: 

 Yes.  FPL’s project management, contracting, accounting, and cost oversight controls are comprehensive and overlapping.  They include FPL’s Accounting Policies and Procedures; financial systems and related controls; annual budgeting and planning process and reporting and monitoring of costs incurred; and Business Unit specific controls and processes.  The project controls are comprised of financial systems, department procedures, work/desktop instructions and best practices, providing governance and oversight of project cost and schedule processes.  The project management, cost estimation, and risk management attributes of FPL are highly developed, well documented, and adhered to by the project teams.  FPL’s management decisions with respect to Turkey Point 6 & 7 are the product of properly qualified, well-informed FPL management following appropriate procedures and internal controls.

OPC: 

 As its position statement for Issue 29, OPC adopts and incorporates by reference its position on Issue 29A, below.

SACE: 

 Agree with OPC.

FIPUG: 

 No.  See FIPUG briefing below.

FEA: 

 See FEA’s position for 29A.

FRF: 

 No.  FPL’s cost overruns of $550 million, in one year, are, in practical terms, prima facie evidence of imprudence.  Moreover, evidence shows that FPL ignored predictions by its consultants that, had it been heeded, could have reduced the magnitude of these cost overruns.

Staff Analysis: 

 This issue addresses project management, contracting, accounting, and oversight controls employed by FPL during 2011 for its Extended Power Uprate project, inclusive of all activities and costs for the St. Lucie site and Turkey Point site.  Consequently, the resolution of this issue subsumes the determinations made in Issue 29A, which focuses on the Turkey Point portion of FPL’s Uprate project.

PARTIES’ ARGUMENTS

FPL

FPL asserted that it had robust project planning, management, and execution processes in place, which include the use of project guidelines and project instructions. (TR 993; EXH 53; FPL BR 35)  FPL states that the project team held regularly scheduled meetings and generated reports communicating the status of the project, scope changes, schedule and cost variances, risks, and risk mitigation. (TR 997-998; EXH 54; FPL BR 35)  According to FPL, the risk management process was governed to ensure appropriate actions were taken to mitigate or eliminate identified risks. (TR 999: FPL BR 35)

FPL relied on comprehensive corporate and overlapping business unit controls for recording and reporting transactions. (TR 934, 936-939; FPL BR 34, 36)  FPL asserted that these controls are regularly assessed and audited. (TR 934; FPL BR 34)  FPL stated that its Nuclear Business Operations group provides additional accounting oversight that was independent of the project team. (TR 994-995; FPL BR 35)

FPL engaged Concentric Energy Advisors to perform an independent review of FPL’s 2011 project controls. (TR 24; FPL BR 35)  FPL witness Reed presented the review performed by Concentric Energy Advisors and concluded FPL was prudent regarding the development of its project controls and implementation of those controls. (TR 24, 27; FPL BR 36)  FPL also engaged Burns and Roe Enterprises, Inc., to review FPL’s 2011 project management. (TR 1136-1137; FPL BR 35)  FPL witness Ferrer, representing Burns and Roe Enterprises, Inc., presented the review and concluded FPL prudently managed the project. (TR 1136-1137; FPL BR 36)

FPL noted that Commission staff also audited FPL. (FPL BR 35; TR 1305-1306; EXH 100)  According to FPL audit staff had one recommended disallowance that FPL resolved through additional vendor negotiations and which was the subject of a stipulation that was approved by the Commission on September 11, 2012.  (TR 726-728; FPL BR 35; EXH 128)

FPL asserts in its brief that the record demonstrated that FPL’s project management, contracting, accounting and cost oversight controls were reasonable and prudent. (FPL BR 36)

OPC, SACE, FIPUG, FEA, and FRF

The intervenors focused on the costs for activities at the Turkey Point site that are addressed in Issue 29A.  Consequently, the prudence of 2011 Uprate project management matters raised by the intervenors regarding the Turkey Point site are presented in Issue 29A.

ANALYSIS

This issue addresses FPL’s 2011 project management, contracting, accounting, and oversight controls for the FPL Uprate project.  Staff notes that if the Commission determines in Issue 29A that FPL was imprudent, then that finding should be reflected in the resolution of this issue.  However, staff believes FPL was prudent in the Turkey Point site matters addressed in Issue 29A.  Staff notes that the only additional matter was raised by audit staff witnesses concerning FPL’s contractor oversight and accounting.

Summary of FPL’s Uprate Project Management Activities

FPL witness Jones, FPL’s Vice President of Nuclear Power Uprates, explained that the FPL Uprate project continued to be implemented in four overlapping phases in order to complete the project as soon as practical. (TR 987 - 989)

·        The engineering analysis phase develops and supports the NRC license applications and reviews which necessarily identifies and confirms the major modifications and project scope.  (TR 987-988)  All necessary NRC applications were filed in or before 2011. (TR 988, 1005-1007)

·        The long lead equipment procurement phase establishes the purchase specifications, issues proposals, reviews vendor quotes, and awards contracts.  The majority of this activity was completed in 2011. (TR 988, 1007-1008)

·        The engineering design modification phase develops detailed modification packages that include calculations, construction drawings, additional equipment and materials procurement, installation and testing guidelines.  The engineering design modification packages for the three outages in 2011 were completed and progress was made on the packages required for the three outages scheduled for 2012. (TR 988)

·        The implementation phase is a two step process: planning and scheduling.  The implementation planning process focuses on the development of the detailed work orders for the actual facility modifications.  The implementation scheduling process integrates the logistics and detailed work orders and includes the performance of the work, testing, return to normal operations, and project closeout.  The implementation phase continued throughout 2011. (TR 988) 

FPL witness Jones opined that the NRC’s licensing review required additional FPL engineering and review time. (TR 1023)  He believed the 2011 earthquake and tsunami in Japan and the 2011 earthquake in Virginia adversely impacted the NRC’s staff resources and delayed review and approval of FPL’s applications. (TR 1017)  These events contributed to FPL’s decision to delay a St. Lucie Unit 1 outage and to review the timing of a planned 2012 outage of Turkey Point Unit 3. (TR 1017)  Witness Jones asserted that these were the primary drivers of FPL’s unanticipated delays, increased design and engineering work, and implementation modifications, and contributed to increased costs. (TR 1017, 1023)  Staff also addresses FPL’s Uprate project 2011 cost increases in Issues 29A and 30.

Witness Jones explained that as a result of the above factors, particularly design evolution and complexity of construction, Bechtel’s[53] efforts in the engineering and work package preparation took longer than anticipated. (TR 1023)  FPL directed Bechtel to subcontract some of the work, reprioritized others, and developed and began implementing a plan to streamline Bechtel’s work packages. (TR 1010)  As of December 31, 2011, 222 packages had been identified, of which 171 were at least 90 percent complete and 143 were final and approved. (TR 1011; EXH 61)  FPL also engaged Bechtel in senior-level meetings to address observed trends and metrics. (TR 1011)  FPL also awarded scopes of the St. Lucie work to other vendors as cost control efforts. (TR 1011)  FPL witness Jones provided a summary listing of 2011 FPL Uprate activities indicating the power plant, respective contract, and scoping documents supporting the described activity. (EXH 59)

FPL witness Jones discussed examples of resultant project planning impacts.  FPL rescheduled a few St. Lucie Unit 2 modifications from Spring 2011 to Summer 2012, and a few Turkey Point Unit 4 modifications from the Spring 2011 outage into the Fall of 2012.  Limited transmission and substation work was also moved into 2012.  These revisions also impacted FPL’s estimate of assets that had been estimated to be placed in service during 2011. (TR 1014-1015)  A summary listing of the assets at the St. Lucie and Turkey Point sites that were placed in service during 2011 was provided. (EXH 60)

A December 31, 2011, revised summary timeline of the entire FPL Uprate project was also provided in witness Jones’ March 1, 2012 testimony. (EXH 62)  The project schedule shows NRC licensing activities were expected to continue into 2012, all long lead materials had been acquired, engineering design activities for St. Lucie Unit 1 and Turkey Point Unit 3 sites were completed late in 2011, but work continued into 2012 for the other sites.   The completed implementation activities include the first outage cycle at each of the four units and the beginning of the second St. Lucie Unit 2 outage.  Project close out was expected to begin in 2012 and end mid-2013. (EXH 62)

FPL witness Jones explained FPL’s 2011 cost variances by major cost category. Staff notes that two variances exceeded $10 million: licensing costs addressing NRC requirements increased approximately $20 million; and power block engineering and procurement expenses increased approximately $41.8 million, due primarily to increased work scope, longer installation times, increased planning, and scheduling changes. (TR 1018-1023)  No party identified any specific activity or cost variance as unreasonable or unnecessary to complete the Uprate project.

The only prudence concern with FPL’s 2011 Uprate project management actions was raised by audit staff witnesses Fisher and Rich, and involved FPL’s oversight of Siemens during a St. Lucie outage and led to a $3.5 million adjustment. (EXH 100)  Audit staff’s review was filed June 19, 2012. (TR 1303)  On August 1, 2012, FPL witness Jones filed supplemental testimony that explained subsequent to audit staff’s review a new commercial resolution between FPL and Siemens had been established that resolved the prudence concern. (TR 1073-1074; EXH 112)  Staff agreed and during the hearing, on September 10, 2012, the Commission approved a stipulation, Exhibit 128, which explained the resolution. (EXH 128; TR 726-728)

FPL’s Uprate Project Management Procedures and Related Controls

FPL’s controls were documented, assessed, audited, and tested on a going forward basis by both FPL’s internal and external auditors, as well as Commission audit staff. (TR 1002-1003)

FPL witness Reed, with Concentric Energy Advisors, Inc., presented an independent review of FPL’s 2011 internal project controls, processes, and procedures. (TR 23-24, 26-27)  Based on his review, he concluded that FPL’s project management practices and procedures were reasonable and met or exceeded industry norms. (TR 105)  He opined that FPL had appropriately and prudently managed the FPL Uprate project. (TR 27, 86, 179)

FPL witness Ferrer, with Burns and Roe Enterprises, Inc., presented an independent review of FPL’s 2011 Uprate project activities to determine whether FPL performed reasonably and prudently. (TR 1134, 1136-1137)  Witness Ferrer opined that FPL’s implementation of the Uprate project was reasonable and prudent but not perfect. (TR 1166-1167)

As previously noted, audit staff reviewed FPL’s 2011 project management controls. (TR 1305-1306; EXH 100)  The primary objective of each annual audit is to document key project developments, along with the organization, management, internal controls, and oversight that FPL has in place or plans to employ for these projects. (TR 1306)  The internal controls examined annually are related to the following areas of project activity: planning, management and organization, cost and schedule controls, contractor selection and management, auditing, and quality assurance. (TR 1306)  The review included a summary of historical, current, and future relevant key issues, such as cost estimates, NRC license review status, outages, work stoppages, and NRC’s developing requirements since the 2011 tsunami in Japan. (EXH 100)

Audit staff’s review discussed concerns with FPL’s oversight of Bechtel but made no specific finding of imprudence. (TR 179-185; EXH 100)  FPL witness Reed characterized audit staff as providing a “heads-up.” (TR 182)  Witnesses Fisher and Rich believed that, with the exception of the previously discussed Siemens oversight matter, FPL had and employed an adequate system of project controls, risk evaluation, and management oversight. (EXH 100)

Staff notes that FPL witness Jones’ August 1, 2012, supplemental testimony indicated that three ongoing audits had been completed. (TR 1075)  FPL witness Jones affirmed that if the resolution of these investigations results in ineligible costs, then those costs will be reversed in the FPL’s 2013 filings. (TR 1075)

FPL’s Uprate Accounting and Related Controls

FPL’s Uprate project accounting and related controls were generally described by FPL witness Powers. (TR 933-936, 940-946)  Witness Powers stated that the 2011 costs and controls will have been audited prior to the start of the hearing. (TR 947-948, 973)  Witness Powers asserted these audits will continue to provide assurance that the internal controls surrounding transactions and processes are well-established, maintained and communicated to employees, and provide additional assurance that the financial and operating information generated within FPL is accurate and reliable. (TR 948)

Commission staff accounting audit witness Maitre provided testimony and sponsored the staff’s 2012 accounting audit report of FPL’s Uprate project.  (TR 1307-1313; EXH 101; EXH 102)  As noted in this testimony, the staff’s audit activities included reconciliation and verification of 2011 costs to the general ledger and monthly accrual balances.  The staff audit report verified that, absent three miscalculations, FPL’s March 2012 filings for the 2011 period were consistent with and in compliance with Section 366.93, F.S., and Rule 25-6.0423, F.A.C.  FPL witness Powers filed supplemental testimony on September 7, 2012, that explained FPL’s June 11, 2012, errata filings had implemented corrections for the miscalculations. (TR 973)

Prudence Standard

As discussed in Issues 8, 9, and 15, the standard for determining prudence is consideration of what a reasonable utility manager would have done, in light of the conditions and circumstances which were known, or should been known, at the time the decision was made.  Staff notes that the only unresolved 2011 Uprate project management subject matter is addressed in Issue 29A.

Based on the foregoing, staff believes that FPL’s 2011 Uprate project management, accounting and related controls were subjected to a reasonable level of review sufficient to determine prudence.  Staff believes there is no record evidence identifying any of FPL’s 2011 Uprate project management or accounting decisions and actions as unneeded or unreasonable.  Staff also believes that no party identified specific 2011 Extended Power Uprate project management actions as unreasonable or imprudent.

CONCLUSION

Staff believes the Commission should find FPL’s 2011 Uprate project management, contracting, accounting and cost oversight controls reasonable and prudent.

 

 

 

Issue 29A: 

 Should the Commission find that in the previous year (2011) and the current year to date (2012), FPL managed the Extended Power Uprate activities in a reasonable and prudent manner?  If not, what action should the Commission take?

Recommendation: 

 Yes.  Staff recommends the Commission find that in the previous year (2011) and the current year to date (2012), FPL managed the Extended Power Uprate activities in a reasonable and prudent manner.  (Breman)

Position of the Parties

FPL: 

 Yes.  During 2011 and 2012, FPL managed the work of thousands of employees and contractors, completed the EPU work on two nuclear units (one at St. Lucie and one at Turkey Point), completed the design engineering for the remaining outages, and obtained the last of its LAR approvals.  FPL also revised its non-binding cost estimate range in 2011 and in 2012, each time properly reflecting the best information known to FPL at the time, including information from vendors that reflected FPL’s use of information from High Bridge in its negotiations.  Both the EPU project work and the process of revising FPL’s non-binding cost estimate were managed in a reasonable and prudent manner.

OPC: 

 No. FPL’s consulting estimator foresaw soaring Turkey Point EPU costs in 2010.  Had FPL acted on this advice timely and prudently to maximize value to customers, in 2011 it would have assessed the economics of the Turkey Point uprate project separately and curtailed the project early in its life.  At this advanced stage of the project, OPC believes FPL should complete the project.  However, the Commission should recognize that FPL failed to manage the activities associated with the Turkey Point uprate that have led to a $555 million increase within the last year in a reasonable and prudent manner.  The Commission should hold FPL to the current estimate of the costs of completing the Turkey Point uprate project.

SACE: 

 Agree with OPC.

FIPUG: 

 No.  See FIPUG briefing below.

FEA: 

 No.  FP&L unreasonably disregarded an independent engineering study which concluded that the Turkey Point EPU costs would reach the high levels FPL is now projecting for the project ($555 million year-over-year cost increase).  Additionally, the evidence revealed a fatal flaw in the underlying approach FPL used to conduct a $300,000 independent consulting study which assessed FPL’s management of EPU activities.  As a result, the Commission should hold FPL to the current estimate of the costs to complete the Turkey Point EPU.

FRF: 

 No.  See position on Issue 29.

Staff Analysis: 

  OPC questioned whether FPL was prudent in its use of 2010 information in its management of the Turkey Point portion of its Extended Power Uprate (EPU or Uprate) and thus believes whether FPL’s recovery of its actual costs to complete the EPU activities at the Turkey Point site should be limited.  All other matters pertaining to the prudence of FPL’s 2011 management of the EPU project are addressed in Issue 29 and the cost effects, if any, are reflected in Issue 30.  The reasonableness of FPL’s 2012 actions and costs that are unrelated to the dispute in this issue are addressed in Issue 31.

PARTIES’ ARGUMENTS

OPC, SACE, FEA, and FRF

OPC expressed concern with FPL’s approximate $671 million increase in its non-binding cost estimate to complete the Extended Power Uprate project compared to FPL’s 2011 estimate.  Approximately $555 million of the increase pertained to work at the Turkey Point site. (OPC BR 2, 8)  FRF, under Issue 29, argued FPL’s cost overruns of $550 million in one year are prima facie evidence of imprudence. (FRF BR 12)

OPC, through witness Jacobs, argued that FPL was imprudent in 2010 when it ignored predictions by High Bridge Associates that the final costs of the Turkey Point Units 3 & 4 EPU activities would be about $1.4 billion. (TR 1293; OPC BR 3, 5, 10-11, 19)  According to OPC, the 2010 High Bridge Associates estimate was developed at a time when FPL had specified only 44 modifications and was evaluating 10 more potential modifications. (TR 1356; OPC BR 10-11)  OPC asserted that it was not until February 2012 that FPL acknowledged that the Turkey Point project costs would be as much as the amount that High Bridge Associates had previously reported. (TR 1294)  OPC opined in its brief that if FPL genuinely regarded the High Bridge Associates estimate as too conceptual, FPL could have, and should have, slowed or stopped work until it had completed the number of engineering specifications that it deemed sufficient to confirm the cost estimate. (OPC BR 11)  OPC argued that instead, FPL made the poor management decision to disregard the implications of the High Bridge Associates’ estimate and press ahead. (TR 1285; OPC BR 3, 5, 11)

OPC argued in its brief that prudence demanded that FPL address “the red flag of its own expert consultant’s 2010 estimate of the Turkey Point uprate costs.” (OPC BR 5)  OPC’s position on FPL’s imprudence was based on FPL’s failure to respond to the High Bridge Associates’ estimate. (OPC BR 5)  FPL chose to “blind itself to the High Bridge Associates estimate and dilute the poor economics of the Turkey Point EPU in an overall, consolidated feasibility study.” (OPC BR 11)  OPC argued in its brief, that since the prudent alternative was not pursued, the costs of FPL’s imprudence cannot be measured directly, thus requiring use of a proxy. (OPC BR 4)  OPC noted in its brief that FPL acknowledged in its prehearing position on Issue 1A that “certain costs” can be incurred in periods subsequent to the time frame in which the imprudence occurred. (OPC BR 4)

 If the Commission agrees with OPC, the resulting disallowance by definition would be based on FPL’s imprudence. (OPC BR 19)  OPC recommended that the Commission employ FPL’s current estimate of the Turkey Point Extended Power Uprate construction costs as the basis against which to measure costs associated with FPL’s imprudence, and to hold FPL to that current estimate. (OPC BR 4, 6, 20)  The estimate OPC supported was FPL’s 2012 estimate that included a $555 million increase in Turkey Point site costs relative to last year’s estimate. (OPC BR 4)  SACE, FEA, and FRF agreed with OPC’s recommended action.  (SACE BR 19; FEA BR 7-8; FRF BR 3, 29)

FIPUG

Similar to OPC’s arguments, FIPUG asserted in its brief that given the delays and projected cost overruns associated with the Turkey Point Extended Power Uprate activities, the Commission should cap the amount of money that FPL can recover for the Turkey Point related activities.  (FIPUG BR 2) 

FIPUG asserted that the Commission should reject FPL’s contention that cost increases and delays can be traced exclusively to seismic events in Japan and Virginia, and NRC staffing issues.  (FIPUG BR 2, 9)  In its brief, FIPUG contended that some portion of the delays resulted from certain engineering work being performed more slowly than anticipated and management challenges FPL encountered, but the delays were not caused by acts of God.  (FIPUG BR 2, 9; TR 1014, 1093)  Thus, FIPUG argued not all of the delays were caused by seismic events and a shift in workload at the NRC. (FIPUG BR 9)  It proposed that the Commission review the record and determine the number of delay days attributable to FPL. (FIPUG BR 9)  According to FIPUG, FPL witness Ferrer estimated that the daily amount of money spent by FPL on its uprate projects was in excess of $1 million per day. (TR 1169-70)  FIPUG thus concluded that for each day of delay attributable, directly or indirectly to FPL, the Commission should reduce by $1 million the amount that FPL is able to recover from its ratepayers for these activities. (FIPUG BR 2-3, 9) 

FPL

FPL asserted that in 2011, and in 2012, it revised its non-binding cost estimate range to reflect the best information known at the time. (FPL BR 39)  FPL stated that in 2011, FPL’s non-binding cost estimate range reflected the fact that approximately 36 percent of the total engineering had been completed, and only 81 out of 209 modification packages were 90 percent completed. (TR 1041; FPL BR 39)  FPL contended its current non-binding cost estimate range reflects the fact that approximately 90 percent of the total engineering is complete, and 206 of the 220 modification packages are at the 90 percent complete stage. (TR 1041; FPL BR 39)  FPL asserted that the primary cost drivers of the non-binding cost estimate increase include NRC regulatory requirements and delays, design evolution, and construction implementation and logistics. (TR 1046-1047; FPL BR 40) 

FPL argued in its brief that OPC’s position relies on a draft, highly conceptual Turkey Point cost estimate prepared by High Bridge Associates in 2010.  FPL argues that OPC mischaracterized the document, its purpose, and FPL’s use of it.  FPL also asserted OPC conducted hindsight analysis. (FPL BR 37)

FPL contended that in 2009, FPL hired High Bridge Associates to develop a cost estimate specific to planned modifications at Turkey Point Unit 3 for the purpose of challenging Bechtel’s (FPL’s primary contractor) cost estimates the Turkey Point Unit 3 work.  FPL asserted that, however, in performing this work, High Bridge Associates initially included a highly conceptual estimate for Turkey Point Unit 4. (FPL BR 40; TR 1330)  FPL stated that this conceptual estimate did not have sufficient detail to be used to challenge Bechtel. (TR 133)  According to FPL, the estimate was revised to include only the Turkey Point Unit 3 scope directly estimated. (TR 1330, 1084)  In a footnote in its brief, FPL asserted:

The use of the 2010 High Bridge data consistently has been explained by Witness Jones in prior NCR proceedings.  TR 1084 (Jones), see also, Order No. PSC-11-0547-FOF-EI, p. 52 (stating that “FPL also initiated a third-party assessment and independent budget estimate for uprate activities at Turkey Point Unit 3 to validate necessary scope work, modifications, implementation strategy, and range of costs.”.

(emphasis added by FPL; FPL BR 40)

FPL further asserted that the final High Bridge Associates’ estimate was successfully used to challenge Bechtel, and Bechtel re-evaluated and lowered its modification cost estimates. (TR 1085, 1330-1331; FPL BR 40)  FPL claimed that both the draft and final High Bridge Associates estimates were provided to OPC in 2010.  FPL observed that it is only now, with the new 2012 non-binding cost estimate in hand, that OPC claims FPL should have done something different with the 2010 data. (TR 1330; FPL BR 41)

FPL opined in its brief that neither of OPC’s witnesses identified any imprudent FPL activities that caused the cost of the Turkey Point EPU work to increase, and FPL witness Jones’ testimony on this subject is unrebutted in the record. (FPL BR 42)  Accordingly, FPL concluded that the request to cap FPL’s recovery would disallow recovery of prudently incurred costs contrary to Section 366.93, F.S., Section 403.519(4)(e), F.S., Rule 25-6.0423, F.A.C., and prior Commission orders, and therefore should be rejected. (FPL BR 42)

FPL asserted that Section 366.93(2), F.S., requires that the Commission “promote utility investment in nuclear . . . power plants and allow for recovery in rates of all prudently incurred costs. . . .”  FPL further asserted that OPC’s request for a disallowance of all Turkey Point costs in excess of a hard cap is without regard to whether the costs were prudently incurred.  Additionally, FPL argued that OPC’s request violates Section 403.519(4)(e), F.S., that states a disallowance is only permissible if “the commission find, based on a preponderance of the evidence adduced at hearing . . . that certain costs were imprudently incurred.” (FPL BR 42)

FPL concluded that OPC’s request: “(i) fails to meet the statute’s requirement of alleging that “certain costs were imprudently incurred”; (ii) seeks disallowances of amounts not yet spent or subject to prudence review; and (iii) fails to separate out amounts already found prudent in past NCR cases.”  (FPL BR 42)

ANALYSIS

Staff’s analysis discusses each of the following matters: FPL’s engagement of High Bridge Associates; the effect of using the High Bridge Associates’ estimate to perform a feasibility analysis; the historical pattern of increasing cost estimates; and FIPUG’s alternative offered in its brief, to OPC’s proposed cost recovery limitation.

FPL’s Engagement of High Bridge Associates

OPC witness Jacobs makes the following observations regarding FPL’s requested High Bridge Associates work product.

. . . Lastly, the consultant that FPL engaged specifically to advise it on projections of ultimate costs informed FPL in 2010 that the Turkey Point project costs would reach the order of magnitude that FPL is now, belatedly acknowledging.

(TR 1283)

Further, FPL’s decision to pursue the Turkey Point uprate activities without first fully confronting the extremely high estimate of final costs which it engaged its consultant to prepare was a poor management decision, and the impact of that action should be absorbed by FPL, not its customers.

(TR 1285)

In 2010, FPL hired High Bridge Associates to independently review the Turkey Point EPU project costs.  High Bridge issued a report on Turkey Point 3&4 EPU cost that estimated the final cost to be $1,428,541,326.  Significantly, this estimate did not encompass all the modifications involved in the full Turkey Point EPU activity.  In other words, because High Bridge did not “price out” all necessary modifications associated with the Turkey Point uprate project, the High Bridge estimate necessarily was lower than the indicated cost of the full project.

(TR 1293-1294)

It [the Commission] should not ignore either the $555 million increase in Turkey Point EPU costs, or the fact that the consultant that FPL hired to educate it on total project costs alerted FPL to the extreme cost of the project in 2010, only to have its work product effectively ignored by the client who had paid for the estimate, or the clear indication that the project is fast becoming uneconomic.

(TR 1296)

            Staff observes OPC witness Jacobs asserted or implied that FPL engaged High Bridge Associates for the purpose of estimating the final costs for the Turkey Point activities.  However, witness Jacobs appears to have acknowledged that the scope of the work product may have been intended to be more limited:

Even though its purpose in engaging High Bridge Associates was to provide an independent check on the information that FPL was receiving from Bechtel, FPL did not accept High Bridge’s estimate until much later.

(TR 1294)

            FPL witness Jones rebutted witness Jacobs’ contentions, asserting that FPL hired High Bridge Associates to develop a cost estimate specific to the Turkey Point Unit 3 EPU modifications, to be used to challenge Bechtel’s cost estimates for specific Unit 3 EPU project scope.  (TR 1330-1331)  FPL asserted that the final High Bridge Associates estimate was successfully used in challenging Bechtel and Bechtel ultimately lowered its cost estimates. (TR 1330-1331)

            Staff reviewed Exhibit 98, which is an excerpt from the 2010 High Bridge Associates report.  Staff found no information on the two-page exhibit that would serve to indicate that the cost estimate was not inclusive of both Turkey Point Units 3 & 4 EPU modifications.  Staff notes that FPL did not dispute that the cost estimate represented costs for both Turkey Point Units 3 & 4 EPU modifications; FPL only disputed OPC witness Jacobs’ representations that FPL’s scope of engagement with High Bridge Associates had been for a total estimate involving both Turkey Point Units 3 & 4.  Therefore, staff believes witness Jacobs’ characterizations of the 2010 work product as inclusive of costs for activities at both Turkey Point Units 3 & 4, as reflected in Exhibit 98, was accurate.  However, OPC witness Jacobs’ characterization of FPL’s purpose in engaging High Bridge Associates may be inconsistent with the limited scope FPL requested because FPL did not engage High Bridge Associates to provide a total project estimate that included both Turkey Point Units 3 & 4.  Consequently, staff believes it would be inappropriate to make a finding of imprudence if that finding hangs solely on witness Jacobs’ representation of the purpose of FPL’s engagement of High Bridge Associates.

Staff notes that High Bridge Associates was also used in a subsequent cost estimating effort.  FPL witness Jones testified that during 2011, FPL asked Bechtel to provide a “proposed target price to complete the Turkey Point EPU work.” (TR 1012, 1088)  High Bridge Associates was retained by Bechtel, at FPL’s request, to assist in estimating the labor portion of the implementation services. (TR 1012, 1043)  In November 2011, FPL received Bechtel’s cost estimate, which reflected (i) design evolution, (ii) increased implementation complexity, (iii) constructability issues, and (iv) increased direct and indirect labor. (TR 1012)  Witness Jones described FPL’s actions upon receipt of Bechtel’s estimated cost to complete Turkey Point EPU work:

In December 2011 through April 2012, FPL performed extensive due diligence on Bechtel’s Turkey Point EAC as well as revised estimates for St. Lucie. This included enormous amounts of engineering, corporate staff and executive work to analyze the EAC. In order to better understand and analyze the basis for the EAC, FPL’s due diligence included several trips to Bechtel in Frederick, Maryland by FPL senior management and several trips to FPL’s headquarters by Bechtel senior management.

FPL worked with Bechtel and High Bridge to perform a detailed review of all inputs and assumptions used in estimating the remaining work at each plant. The detailed review work included three days of lengthy sessions with senior management from FPL and Bechtel. Those sessions built upon the close analyses that FPL had already performed to scrutinize in detail key elements of the cost estimate, including: (i) units of productivity; (ii) quantifications of commodities; (iii) “implied complexity factors” which are an industry standard measure of how complicated work is to perform; (iv) labor rates; and (v) professional rates, among other cost estimate inputs. The focus of these detailed reviews was to validate that the inputs being used in the cost estimating process were not overly conservative.

(TR 1043-1044)

            FPL and Bechtel ultimately negotiated price reductions totaling $135 million. (TR 1046)  Staff notes no party presented evidence challenging the prudence of FPL’s various engagements of High Bridge Associates nor FPL’s use of the cost estimates High Bridge Associates provided.

The Significance of a $1.4 Billion Estimate in a 2011 Feasibility Analysis

OPC witness Jacobs opined that the 2012 increase in the total EPU project cost estimate “is being driven by soaring costs at the Turkey Point plant site, which is on a runaway course of its own.” (TR 1298)  He then asserted:

. . . Had FPL incorporated an estimate for Turkey Point that was consistent with the High Bridge's 2010 estimate during the 2011 proceeding, the magnitude of the increase would have led to a materially different feasibility calculation.

(TR 1294, 1299)

It appears OPC witness Jacobs represented that if FPL had used a higher total cost estimate in the 2011 feasibility analysis, that would have, in turn, influenced FPL’s decisions to reduce future expenditures to avoid the “soaring project costs.”  However, witness Jacobs did not identify any activity(s) or cost adjustment(s) that would have resulted from using the $1.4 billion estimate in the 2011 feasibility analysis in lieu of the amount FPL did use in its 2011 feasibility study.  Nevertheless, OPC witness Jacobs contended that FPL was imprudent for not using the $1.4 billion estimate in 2011, and he asserted that soaring project costs resulted.  He opined that the remedy necessary to protect customers from these asserted soaring project costs was a cap on FPL’s allowed recovery amount at FPL’s current projection to complete the Turkey Point EPU activities. (TR 1285, 1297, 1300; OPC BR 4)  Staff notes that witness Jacobs’ recommended solution relied on FPL’s current cost estimate which he also used to suggest the existence of soaring project costs.

Regardless, staff finds both FPL and OPC support the use of the same 2012 estimated amount.  FPL’s current total project cost estimate is $1.673 billion for the Turkey Point site.  FPL opined in its brief that OPC’s witness did not identify any imprudent FPL activities that caused the cost of the Turkey Point EPU work to increase. (FPL BR 42)  Staff agrees.  Staff concludes that the record did not demonstrate that use of a $1.4 billion estimate in FPL’s 2011 feasibility analysis would have resulted in a lower cost estimate than FPL’s current cost estimate.

Historical Pattern of Annual Increases

            FPL’s cost estimates have increased each year. (TR 1283, 1288, 1290)  An illustration of these changes was presented by OPC witness Jacobs.  (TR 1290; EXH 99)   Although FPL witness Jones rebutted the OPC witness’ cost levels in certain years, the fact of annual increases was not denied. (TR 1332-1333)  OPC witness Jacobs opined that “. . . the Commission should take action to protect customers in the event FPL fails to manage the balance of the Turkey Point uprate activities within its current estimate.”  (TR 1283)  Staff agrees that the consequence of any FPL imprudence should not be placed on its customers, even if FPL completes the project below its current cost estimate.

            Staff agrees that, all things being equal, increasing costs, even if prudently incurred, could make a project appear to be economically infeasible.  However, as addressed in Issue 28, the analysis of feasibility considers factors that are not solely economic.  Consistent with staff’s recommendation in Issue 28, staff does not believe the year-to-year increases in cost estimates demonstrate that FPL was imprudent.

FIPUG’s Alternative

FIPUG argued that an alternative to limiting FPL’s recovery level was to reject FPL’s contention that cost increases and delays can be traced exclusively to seismic events in Japan and Virginia, and NRC staffing issues.  (FIPUG BR 2, 9)  In its brief, FIPUG asserted FPL witness Ferrer estimated that the daily amount of money spent by FPL on its uprate projects was in excess of $1 million per day. (FIPUG BR 9)  FIPUG argued that, for each day of delay attributable, directly or indirectly, to FPL, the Commission should reduce by $1 million the amount that FPL is able to recover from its ratepayers for these activities. (FIPUG BR 2-3, 9) 

Staff notes that use of $1 million per day figure relies on the following exchange:

Q  Do you have an idea as we sit here today what the -- I'll call it a daily burn rate, but what I'm referring to is what the expenditures are on a daily basis for the combined projects.

 

A  Certainly it would be very high but I did not calculate a number. Again, it was not a necessary issue. I was more interested in the decisions and actions that FP&L personnel were taking on a daily, weekly, monthly basis for the year 2011.

 

Q  So you don't have any idea on the –

 

A  I know it's a very large number, in the order of millions.

 

Q  I'm sorry?

 

A  In the order of millions, but I don't know the number.

 

Q  On a daily basis?

 

A  I would say so, close to it. I would say at least a million dollars a day easy.

 

(TR 1169-1170)

            Staff questions the sufficiency of the above testimony to impose a $1 million per day penalty as suggested by FIPUG, in an effort to address FPL’s management of the Turkey Point Uprate activities.  The above testimony clearly indicates the $1 million estimate was provided in response to a question regarding the total Uprate project daily expenses inclusive of the costs for activities at St. Lucie and Turkey Point.  Consequently, the $1 million amount may be excessive in addressing matters specific and unique to FPL’s oversight of the Turkey Point Uprate activities and costs.  Additionally, the record evidence did not identify any 2011 project delays at the Turkey Point site that were attributable to FPL.  However, as discussed in Issue 29, project delays at the St. Lucie site were identified and addressed. (EXH 128)

Prudence Standard

As previously discussed in Issues 8, 9, 15, 24, 25, and 29, the standard for determining prudence is consideration of what a reasonable utility manager would have done, in light of the conditions and circumstances which were known, or should been known, at the time the decision was made.

Based on the foregoing, staff believes that FPL’s actions concerning the 2010 High Bridge Associates work products were reviewed sufficient to determine prudence.  Staff is not persuaded that FPL was imprudent in this matter.  Staff also believes that no party identified activities or costs specific to completing the Turkey Point Extended Power Uprate project that are unreasonable or imprudent, and would necessitate adjustments or exclusions.

CONCLUSION

Staff recommends the Commission find that in the previous year (2011) and the current year to date (2012), FPL managed the Extended Power Uprate activities in a reasonable and prudent manner.

 

 

 

Issue 30: 

 What system and jurisdictional amounts should the Commission approve as FPL's final 2011 prudently incurred costs and final true-up amounts for FPL's Extended Power Uprate project?

Recommendation: 

 Staff recommends the Commission approve as prudently incurred 2011 Extended Power Uprate project capital costs of $667,493,187 ($640,855,812 jurisdictional net of joint owners and other adjustments) and O&M costs of $12,172,529 ($11,584,442 jurisdictional net of joint owners) including interest.  The recommended final 2011 true-up amount, net of prior recoveries, is $270,057 and should be used in determining the total net 2013 Nuclear Cost Recovery Clause amount.  (Breman)

Position of the Parties

FPL: 

 The Commission should approve FPL’s final 2011 EPU expenditures of $667,493,187 (system), $640,855,812 (jurisdictional, net of participants); O&M costs, including interest, of $12,172,529 (system), $11,584,442 (jurisdictional, net of participants); and carrying charges of $78,251,442.  The final true-up of O&M costs including interest is ($679,375); and final true-up of carrying charges is $7,964,134.  In addition, the Commission should approve FPL’s final 2011 EPU base rate revenue requirements, including carrying charges, of $9,138,883; and the final true-up revenue requirements, including carrying charges, of ($7,014,702).  FPL’s EPU expenditures are supported by comprehensive procedures, processes and controls that help ensure they were the result of prudent decision making.  The net amount of $270,057 should be included in FPL’s 2013 NCR amount.

OPC: 

 OPC adopts and incorporates its position on Issue 29A and the Argument section that follows below.

SACE: 

 Agree with OPC.

FIPUG: 

 Considerably less than sought by FPL.  See FIPUG briefing below.

FEA: 

 Agree with FIPUG.

FRF: 

 The Commission should allow recovery of the reasonable and prudent costs for the EPU projects, but the Commission should mandate that FPL will not be allowed to recover any costs for the Turkey Point EPU project greater than its current, 2012, estimate.

Staff Analysis: 

 This issue addresses FPL’s request concerning the prudently incurred 2011 Uprate project costs and the final true-up of its 2011 recovery amount.  Decisions in Issues 29 and 29A could impact whether conditions are placed on the amounts the Commission approves in this issue.  No new matters were disputed that were not already addressed in prior issues.

PARTIES’ ARGUMENTS

FPL

In its brief, FPL argued that it did not misuse draft High Bridge Associates’ information and no intervenor identified any 2011 imprudent act or decision that caused FPL to incur its reported costs. (FPL BR 45)  FPL asserted in its brief that in Issue 29, its project management decisions were supported by a robust system of internal processes, procedures and controls.  FPL also argued that in Issue 29A, its management of the Uprate project was prudent and OPC’s arguments regarding the draft High Bridge Associates information should be rejected. (FPL BR 44-46)

OPC and SACE

OPC’s position on this issue relied on arguments it presented in Issue 29A.  OPC asserted that FPL was imprudent in 2010 when it ignored predictions by its consulting engineers that the costs of the Turkey Point Units 3 & 4 Uprate activities would reach levels near FPL’s current projections.  Consequently, the Commission should hold FPL to its current estimate of the cost of completing the Turkey Point Units 3 & 4 Uprate activities. (OPC BR 6) SACE agreed with OPC’s position but did not provide additional discussion or argument in its post-hearing brief. (SACE BR 19)

FIPUG and FEA

FIPUG’s position on this issue relied on arguments presented in Issue 29A.  FIPUG argued that not all of the 2011-2012 delays were NRC-related, and FPL’s request should be reduced by $1 million per day for the delays attributable to FPL.  Alternatively, FIPUG supports OPC’s suggestion.  (FIPUG BR 2-3, 7-9)  FEA agreed with FIPUG’s position but did not provide additional discussion or argument in its post-hearing brief. (FEA BR 2, 9-10)

FRF

FRF opined that it shared the concerns raised by OPC regarding the approximate $500 million increase in the Uprate project activities at the Turkey Point site and supported holding FPL to its current cost estimate for the Turkey Point activities.  (FRF BR 2-3, 12)

ANALYSIS

This issue addresses the level of FPL’s 2011 prudently incurred project costs and the final 2011 true-up amount FPL will be required to refund or collect during 2013 based on the resolution of Issues 29A and 29.  No additional matters affecting the 2011 period costs were disputed in this issue.

Issue 29A addresses FPL’s use or, lack of use, of a 2010 cost estimate provided by High Bridge Associates.  If the Commission determines that FPL was imprudent, consistent with the position of OPC in Issue 29A, then the Commission should find in this issue that FPL’s amounts are reasonable because FPL’s 2011 year-end balance does not exceed FPL’s current estimated amount to complete the project.  However, staff believes FPL was prudent with respect to the Turkey Point Uprate matters addressed in Issue 29A.  In Issue 29, addressing FPL’s overall project management and oversight, staff determined there were no additional matters that would result in any adjustments to FPL’s requested amounts.

FPL’s Final 2011 Uprate Project Costs

            FPL provided a series of schedules detailing its 2011 Uprate costs and its calculation of its requested 2011 recovery amount; this information is contained in Exhibit 51.  In Exhibit 51, FPL witnesses Powers and Jones indicated that the 2011 incurred construction costs for the Uprate project totaled $667,493,187 ($640,855,812 jurisdictional, net of participants).  As of year-end 2011, FPL’s Uprate project construction costs totaled $1,314,908,119 ($1,218,121,252 jurisdictional, net of participants). (EXH 51)   Exhibit 51 also indicated that the carrying costs on FPL’s Uprate project capital costs totaled $78,251,442.  FPL’s 2011 O&M costs, and interest calculation of $12,172,529 ($11,584,442 jurisdictional, net of participants) were also included in Exhibit 51.  In Exhibit 63 FPL witness Jones provided a summary of FPL’s actual system 2011 construction costs by major activity.

As discussed in Issue 29, no party identified any specific activity or cost as unreasonable, imprudent, or unnecessary to complete the Uprate project.  FPL requested the Commission review and approve its 2011 amounts as prudent and recoverable. (FPL BR 44-46)

FPL’s Final True-up of the 2011 Uprate Project Recovery Amount

FPL witness Powers provided a summary schedule, based on data in Exhibit 51, of FPL’s 2011 Nuclear Cost Recovery Clause amounts comparing its actual 2011 amounts to amounts approved in prior proceedings. (EXH 45)  Witness Powers explained that FPL’s resulting final 2011 Nuclear Cost Recovery Clause amount should be $270,057, because final 2011 costs were, on a net basis, higher than the prior estimate. (TR 917, 928; EXH 45; EXH 51)  In addition to Exhibit 51, FPL witness Powers provided support for the variance in estimated base rate revenue requirements for portions of the Uprate project that were planned to enter service during 2011. (TR 917 931-932; EXH 46; EXH 47)

  The requested 2011 final net true-up amount includes the following items: under-estimated carrying costs of $7,964,134, over-estimated O&M costs of $679,375, and over-estimated base rate revenue requirements for 2011 of $7,014,702, including associated carrying charges. (TR 917, 928; EXH 45; EXH 51)  FPL requested that these amounts be used in determining the 2013 total NCRC recovery amount. (TR 928)

Prudence standard

The prudence of FPL’s 2011 Uprate project management and oversight was addressed in Issues 29 and 29A, and no additional matters were raised pertaining to the 2011 period.  Consistent with staff’s recommendations in Issues 29 and 29A, staff’s verification of FPL’s calculations and true-up amount, and a preponderance of the evidence in the record, staff believes FPL has demonstrated the prudence of its requested 2011 incurred costs and final true-up amounts for its Uprate project.

CONCLUSION

Staff recommends that the Commission approve as prudently incurred 2011 Extended Power Uprate project capital costs of $667,493,187 ($640,855,812 jurisdictional net of joint owners and other adjustments) and O&M costs of $12,172,529 ($11,584,442 jurisdictional net of joint owners) including interest.  The recommended final 2011 true-up amount, net of prior recoveries, is $270,057 and should be used in determining the total net 2013 Nuclear Cost Recovery Clause amount.

 

 

 

Issue 31: 

 What system and jurisdictional amounts should the Commission approve as reasonably estimated 2012 costs and estimated true-up amounts for FPL's Extended Power Uprate project?

Recommendation: 

 Staff recommends the Commission approve as reasonably estimated 2012 Extended Power Uprate project capital costs of $1,058,854,365 ($1,017,306,408 jurisdictional net of participants) and O&M costs of $15,000,523 ($14,546,749 jurisdictional net of participants).  The recommended estimated 2012 true-up amount, net of prior recoveries, is $45,615,272 and should be used in determining the total net 2013 Nuclear Cost Recovery Clause amount.  (Lewis)

Position of the Parties

FPL: 

 The Commission should approve FPL’s final 2012 actual/estimated EPU expenditures of $1,058,854,365 (system), $1,017,306,408 (jurisdictional, net of participants); FPL’s 2012 actual/estimated O&M costs, including interest, of $15,000,523 (system), $14,546,749 (jurisdictional, net of participants); and carrying charges of $104,909,726.  The estimated true-up of O&M costs including interest is $9,085,552 and the estimated true-up of carrying charges is $37,645,274.  Additionally, the Commission should approve FPL’s 2012 actual/estimated EPU base rate revenue requirements, including carrying charges, of $79,075,219; and the 2012 estimated true-up of revenue requirements, including carrying charges, of ($1,115,554).  FPL’s 2012 actual/estimated EPU costs are supported by comprehensive procedures, processes and controls that help ensure they are reasonable.  The net amount of $45,615,272 should be included in FPL’s 2013 NCR amount.

OPC: 

 OPC adopts and incorporates by reference its position on Issue 29A and the argument that follows below.

SACE: 

 Agree with OPC.

FIPUG: 

 Considerably less than sought by FPL.  See FIPUG briefing below.

FEA: 

 Agree with FIPUG.

FRF: 

 See position on Issue 30.

Staff Analysis: 

 This issue addresses FPL’s request concerning the reasonableness of its 2012 Uprate project costs and the estimated true-up of its 2012 recovery amount.  Decisions in Issues 28 and 29A could impact conditions that may be placed on the amounts the Commission approves in this issue.  However, there is no dispute regarding FPL’s estimated 2012 activities and costs.

PARTIES’ ARGUMENTS

FPL

FPL stated that “by the end of 2012, FPL will have successfully completed another three EPU implementation outages, plus a mid-cycle outage at St. Lucie Unit 1, bringing on-line 336 MW of nuclear power in addition to the 31 MW that were added in 2011.” (FPL BR 46; TR 1027, 1030)  FPL asserted that the costs it has incurred and is incurring are necessary for the successful completion of these implementation activities as well as to prepare for and begin implementing the final EPU outage that will begin in November of 2012. (FPL BR 46; TR 1039; EXH 67)   FPL argued that non-binding cost estimate increases are entirely reasonable for a project as complex as a nuclear uprate, which requires a great investment of human capital to resolve complex design and engineering issues.  Further, the specific challenges FPL will face on such a complex project cannot all be known in advance; indeed, many require some degree of project completion as unique implementation challenges are by their nature discovered during the actual implementation and may be resolved based in part on lessons learned during the implementation.  (TR 1053-1054; EXH 68)

OPC and SACE

OPC’s position on this issue relied on arguments it presented in Issue 29A.  OPC asserted that FPL was imprudent in 2010 when it ignored predictions by its consulting engineers that the costs of the Turkey Point Units 3 & 4 Extended Power Uprate activities would reach levels near FPL’s current projections.  Consequently, the Commission should hold FPL to its current estimate of the costs of completing the Turkey Point Units 3 & 4 Extended Power Uprate activities. (OPC BR 6-7) SACE agreed with OPC’s position but did not provide additional discussion or argument in its post-hearing brief. (SACE BR 19)

FIPUG and FEA

FIPUG’s position on this issue relied on arguments it presented in Issue 29A.    FIPUG argued that not all of the 2011-12 delays were NRC-related, and FPL’s request should be reduced by $1 million per day for delays attributable to FPL.  Alternatively, FIPUG supports OPC’s suggestion.  (FIPUG BR 2-3, 8-9)  FEA agreed with FIPUG but in its brief offered no additional discussion on this issue. (FEA BR 2, 9)

FRF

As stated in Issue 30, FRF opined that it shared the concerns raised by OPC regarding the approximate $500 million increase in the Uprate project activities at the Turkey Point site and supported holding FPL to its current cost estimate for the Turkey Point activities.  (FRF BR 2-3, 12)

ANALYSIS

In Issue 28, the Commission addresses the feasibility of completing the Uprate project.  If completing the project is not found to be feasible, then the activities and amounts FPL has identified for 2012 should be found unreasonable and subject to true-up, because the 2012 costs reflect the costs of completing the project, rather than termination.  However, pursuant to Issue 28, staff believes completing the Uprate project is feasible.

 As previously discussed, Issue 29A addresses FPL’s use, or lack of use, of a 2010 cost estimate provided by High Bridge.  If the Commission determines that FPL was imprudent, consistent with the position of OPC in Issue 29A, then in this issue, the Commission should find that FPL’s amounts are reasonable, because FPL’s estimated 2012 construction balance does not exceed FPL’s current estimate to complete the project.  However, staff believes FPL was prudent with respect to the Turkey Point Uprate matters addressed in Issue 29A.  No adjustments to FPL’s estimated 2012 costs result from the resolution of prior issues.

FPL’s Estimated 2012 Uprate Project Costs

FPL witness Jones provided descriptions of the 2012 EPU project activities, costs, and variances. (TR 1055-1066; EXH 67; EXH 73)  Witnesses Powers and Jones co-sponsored Exhibit 64, which includes a series of schedules detailing FPL’s 2012 Uprate costs and its calculation of its requested 2012 recovery amount. (Power TR 952; Jones TR 1072)

            In Exhibit 64, FPL witnesses Powers and Jones identified the estimated 2012 EPU construction capital costs of $1,058,854,365 ($1,017,306,408 jurisdictional net of participants), and O&M costs of $15,000,523 ($14,546,749 jurisdictional net of participants).  (TR 950, 964-965; EXH 64)  Staff notes that FPL’s amount includes a $4,786 interest true-up in its calculation of the jurisdictional O&M amount. (TR 965; EXH 64, p. 14)  FPL estimated that by year-end 2012, it will have incurred Uprate project construction expenses totaling $2,373,762,484 ($2,269,525,324 jurisdictional net of participants). (EXH 64)

 

            FPL witness Jones asserted that the Uprate project is on schedule for completion. (TR 1031)  However, FPL estimated there will be a net cost increase relative to FPL’s 2011 estimate. (TR 1046)  Witness Jones attributed $110 million of the total project cost increase to modifications necessary to meet NRC requirements and schedule changes in response to delays in NRC’s approvals. (TR 1046)  He attributed another $150 million to design evolution. (TR 1046)  He described design evolution as an iterative engineering process that responds to discoveries during engineering design. (TR 1046)  He attributed another $220 million of the increase to construction implementation and logistics. (TR 1047)  As discussed in Issue 29A, the parties focused on the size of the total projected project cost relative to 2011.  Staff notes that no party argued that the Uprate project should not be completed.

 

            FPL witness Jones provided an overview of activities planned for 2012, identified the associated contracts, and listed documents FPL relied on in its decisions. (TR 1055-1058; EXH 72)  He also provided a summary of 2012 project costs by cost category. (TR 1060-1065; EXH 73)  In supplemental testimony filed August 1, 2012, witness Jones updated the Commission regarding the completion of the St. Lucie Unit 1 EPU, and completion of several internal and external audits. (TR 1073-1075)  The capacity of St. Lucie Unit 1 was increased by approximately 144 megawatts as a result of the completed uprate. (TR 1074)

 

            Staff notes no party argued that FPL’s estimate of 2012 activities and 2012 costs were unreasonable or unnecessary to complete the project.

 

 

 

 

FPL’s Estimated True-up of the 2012 Uprate Project Recovery Amount

FPL witness Powers provided support for the 2012 EPU project costs and methods used to determine the requested estimated true-up recovery amount. (TR 950, 955-56, TR 962-965; EXH 49; EXH 50; EXH 64)  Witness Powers asserted that FPL’s estimated 2012 nuclear cost recovery true-up amount is $45,615,272 because the 2012 estimate was higher, on a net basis, than the prior estimate. (TR 950, 964; EXH 49; EXH 64, p. 5)  In addition to Exhibit 64, FPL witness Powers provided support for the variance in estimated base rate revenue requirements for portions of the Uprate project that were planned to enter service during 2012. (TR 965-967; EXH 50; EXH 64, pp. 19-26)

The requested 2012 estimated true-up amount includes the following items: under-estimated carrying costs of $37,645,274, under-estimated O&M costs of $9,085,552, and over-estimated base rate revenue requirements for 2012 of $1,115,554, including associated carrying charges. (TR 950, 963-964; EXH 49)  FPL requested that these amounts be used in determining the 2013 total NCRC recovery amount. (TR 963)

Consistent with staff’s recommendations in Issues 28 and 29A, staff’s verification of FPL’s calculations, and a preponderance of the evidence in the record, staff believes FPL has demonstrated the reasonableness of its requested estimate of 2012 incurred costs and true-up amounts for the Extended Power Uprate project.

CONCLUSION

            Staff recommends that the Commission approve as reasonable estimates of 2012 costs of $1,058,854,365 ($1,017,306,408 jurisdictional net of participants) for the Extended Power Uprate project capital costs and $15,000,523 ($14,456,749 jurisdictional net of participants) for O&M costs.  The estimated 2012 true-up amount of $45,615,272 should be used in determining the total net 2013 Nuclear Cost Recovery Clause amount.

 

Issue 32: 

 What system and jurisdictional amounts should the Commission approve as reasonably projected 2013 costs for FPL's Extended Power Uprate project?

Recommendation: 

 Staff recommends the Commission approve as reasonably projected 2013 Extended Power Uprate project capital costs of $163,996,072 ($161,047,828 jurisdictional net of participants) and O&M costs of $5,170,770 ($5,077,869 jurisdictional net of participants).  The recommended projected 2013 amount of $85,249,950 should be used in determining the total net 2013 Nuclear Cost Recovery Clause amount.  (Lewis)

Position of the Parties

FPL: 

 The Commission should approve 2013 projected EPU expenditures of $163,996,072 (system), $161,047,828 (jurisdictional, net of participants); projected O&M costs, including interest, of $5,170,770 (system), $5,077,869 (jurisdictional, net of participants); and $15,433,878 in carrying charges.  In addition, the Commission should approve as reasonable EPU base rate revenue requirements of $64,738,202.  The total amount of $85,249,950 should be included in setting FPL’s 2013 NCR amount.  FPL’s 2013 projected construction expenditures are supported by comprehensive procedures, processes and controls which help ensure that these projected costs are reasonable.

OPC: 

 OPC adopts and incorporates by reference its position on Issue 29A and the argument that follows below.

SACE: 

 Agree with OPC.

FIPUG: 

 Considerably less than sought by FPL.  See FIPUG briefing below.

FEA: 

 Agree with FIPUG.

FRF: 

 See position on Issue 30.

Staff Analysis: 

 This issue addresses FPL’s request concerning the reasonableness of its 2013 Uprate project costs and the estimated true-up of its 2013 recovery amount.  Decisions in Issues 28 and 29A could impact conditions that may be placed on the amounts the Commission approves in this issue.  However, there is no dispute regarding FPL’s 2013 projected activities and costs.

PARTIES’ ARGUMENTS

FPL

In its brief, FPL asserted that the costs the Company will incur in 2013 are necessary to complete the EPU project, and the 2013 projections were developed using a robust system of internal processes, procedures and controls similar to the manner in which the company developed its 2012 estimates.  FPL argued that OPC’s request that Turkey Point-related EPU costs be capped based on OPC’s claim that FPL did not properly act on information provided by a consultant should be rejected.  FPL believes that all of its 2013 EPU costs are reasonable, supported by the record, and should be approved. (FPL BR 48-49)

OPC and SACE

OPC’s position on this issue relied on arguments it presented in Issue 29A.  OPC asserted that FPL was imprudent in 2010 when it ignored predictions by its consulting engineers that the costs of the Turkey Point Units 3 & 4 Extended Power Uprate activities would reach levels near FPL’s current projections.  Consequently, OPC believes that the Commission should hold FPL to the current estimate of the costs of completing the Turkey Point Units 3 & 4 Extended Power Uprate activities. (OPC BR 7)  SACE agreed with OPC’s position but did not provide additional discussion or argument in its post-hearing brief. (SACE BR 19)

FIPUG and FEA

FIPUG’s position on this issue relied on arguments it presented in Issue 29A.  FIPUG argued that not all of the 2011-12 delays were NRC-related, and FPL’s request should be reduced by $1 million per day for delays attributable to FPL.  Alternatively, FIPUG supports OPC’s suggestion. (FIPUG BR 2-3, 8-9)  FEA agreed with FIPUG but in its brief offered no additional discussion on this issue. (FEA BR 2, 9-10)

FRF

As stated in Issue 30, FRF opined that it shared the concerns raised by OPC regarding the approximate $500 million increase in the Uprate project activities at the Turkey Point site and supported holding FPL to its current cost estimate for the Turkey Point activities.  (FRF BR 2-3, 12)

ANALYSIS

In Issue 28, the Commission addresses the feasibility of completing the Uprate project.  If completing the project is found to be infeasible, activities and amounts FPL has identified for 2013 should be found unreasonable and subject to true-up, since the requested 2013 costs reflect those of completing the project, rather than termination.  However as stated in Issue 28, staff concludes that the Uprate project remains feasible and therefore believes the Uprate project should be completed.

In Issue 29A, staff addresses the concerns surrounding FPL’s use of a 2010 cost estimate provided by the High Bridge consulting firm.  If the Commission determines that FPL’s actions concerning this estimate was imprudent, consistent with the position offered by OPC in Issue 29A, the Commission should still find that FPL’s requested amounts in this issue are reasonable since FPL’s projected 2013 construction cost balance does not exceed FPL’s current estimate to complete the project.  However, staff believes FPL was prudent with respect to the Turkey Point Uprate matters addressed in Issue 29A.  Given the recommended resolution of prior issues, staff does not recommend that any adjustments be made to FPL’s 2013projected costs.

FPL’s Projected 2013 Uprate Project Costs

FPL witness Jones provided descriptions of the 2013 EPU project activities and costs. (TR 1067-1072; EXH 73; EXH 74)  Witnesses Powers and Jones co-sponsored Exhibit 64, which includes a series of schedules detailing FPL’s 2013 Uprate costs and its calculation of its requested 2013 recovery amount. (Power TR 952; Jones TR 1072)

            In Exhibit 64, FPL witnesses Powers and Jones identified the estimated 2013 EPU construction capital costs of $163,996,072 ($161,047,828 jurisdictional net of participants), and O&M costs of $5,170,770 ($5,077,869 jurisdictional net of participants).  Staff notes that FPL’s amount includes a $3,152 interest true-up in its calculation of the jurisdictional O&M amount.  FPL estimated that by year-end 2013, it will have incurred Uprate project construction costs totaling $2,537,756,556 ($2,430,573,152 jurisdictional net of participants). (EXH 64, p. 124)

 

            FPL witness Jones asserted that the 2013 Uprate project will be completed.  He provided an updated timeline estimating the last Uprate-related outage will end in March 2013, with ongoing project close-out activities extending to the July/August 2015 timeframe. (EXH 67)  Similar to the information provided for the 2012 period, witness Jones provided a summary of planned 2013 activities, identified the respective contracts, and listed documents FPL relied on in its planning decisions. (TR 1067-1071; EXH 74)  He also provided a summary of 2013 project costs by cost category. (TR 1067-1071; EXH 75)  Staff notes that, similar to the reviews for 2011 and 2012, no party argued that FPL’s estimate of 2013 activities and costs were unreasonable or unnecessary to complete the project.  Additionally, no adjustments were identified.

 

FPL’s Projected 2013 Uprate Project Recovery Amount

FPL witness Powers provided support for the 2013 EPU project costs and methods used to determine the requested recovery amount of $85,249,950. (TR 950, 967-968; EXH 49; EXH 50; EXH 64)  In addition, FPL witness Powers provided support for the estimated base rate revenue requirements for portions of the Uprate project scheduled to enter service during 2013. (TR 950, 967; EXH 50; EXH 64)

The requested 2013 recovery amount includes the following items: carrying costs of $15,433,878, O&M costs of $5,077,869, and estimated base rate revenue requirements for 2013 of $64,738,202. (TR 950, 967; EXH 49)  FPL requested that these amounts be used in determining the 2013 total NCRC recovery amount. (TR 950, 969)

            Consistent with staff’s recommendations in Issues 28 and 29A, staff’s verification of FPL’s calculations, and a preponderance of the evidence in the record, staff believes FPL has demonstrated the reasonableness of its requested estimate of 2013 incurred costs and true-up amounts for the Extended Power Uprate project.

CONCLUSION

            Staff recommends that the Commission approve as reasonably projected 2013 Extended Power Uprate project capital costs of $163,996,072 ($161,047,828 jurisdictional net of participants) and O&M costs of $5,170,770 ($5,077,869 jurisdictional net of participants).  The recommended projected 2013 amount of $85,249,950 should be used in determining the total net 2013 Nuclear Cost Recovery Clause amount.

 

Issue 33: 

 What is the total jurisdictional amount to be included in establishing FPL's 2013 Capacity Cost Recovery Clause factor?

Recommendation: 

 Staff recommends the Commission approve $151,491,402 as the total jurisdictional amount to be included in establishing FPL’s 2013 Capacity Cost Recovery Clause factor.   (Breman)

Position of the Parties

FPL: 

 The total jurisdictional amount of $151,491,402 should be included in establishing FPL’s 2013 Capacity Cost Recovery Clause factor.  This amount consists of carrying charges on site selection costs, pre-construction costs, and associated carrying charges for continued development of Turkey Point 6 & 7; and carrying charges on construction costs, O&M costs, and base rate revenue requirements for the EPU project, all as provided for in Section 366.93 and the Nuclear Cost Recovery Rule.

OPC: 

 OPC adopts and incorporates by reference its position on Issue 29A and the argument that follows below.

SACE: 

 The total jurisdictional amount will be a fall out from other decisions.  There should be no recovery of TP 6 & 7 related costs, as FPL has failed to demonstrate the requisite intent to build and as such is not engaged in the “siting, design, licensing, and construction” of TP 6 & 7.  Furthermore, FPL has failed to demonstrate that completion of TP 6 & 7 is feasible in the long term.  As to EPU costs, the Commission should hold FPL to the current estimate of costs of completing the Turkey Point Uprate project.

FIPUG: 

 This is a fall out issue.

FEA: 

 Agree with FIPUG.

FRF: 

 See positions on Issues 25-27 and Issue 30.

Staff Analysis: 

 This issue addresses the amount the Commission should establish for FPL’s 2013 Nuclear Cost Recovery Clause and the amount to be approved for collection through the 2013 Capacity Cost Recovery Clause factor.  No new arguments or concerns are addressed in this issue.  The total jurisdictional amount is the sum of recovery amounts decided in Issues 25, 26, 27, 30, 31, and 32.

PARTIES’ ARGUMENTS

FPL

FPL asserted in its brief, that it prudently incurred 2011 costs for both the Turkey Point Units 6 & 7 project and the Uprate project, and that its estimated 2012 and projected 2013 costs for both projects are reasonable.  FPL opined that the Commission should approve its request for recovery of $151,491,402. (FPL BR 49)

 

OPC, SACE, FIPUG, FEA and FRF

In their respective briefs, OPC, FIPUG, FEA, and FRF did not raise any concerns with FPL’s Turkey Point Units 6 & 7 project and costs (Issues 20-27). (OPC BR 1; FIPUG BR 6-7; FEA BR 5-6; FRF BR 2) 

In its brief SACE recommended that the Commission find FPL’s Turkey Point Units 6 & 7 project activities do not qualify for recovery under Section 366.93, F.S., FPL failed to demonstrate the long-term feasibility of completing the project, and no costs are eligible for recovery. (SACE BR 20-21)

As addressed in Issues 28-32, OPC recommended in its brief that the Commission should determine that in 2011 FPL imprudently disregarded a 2010 High Bridge Associates’ estimate that construction costs would reach more than $1.4 billion. (OPC BR 10, 20)  OPC further argued the Commission should use FPL’s current estimate as the basis to measure costs associated with FPL’s imprudence. (OPC BR 20)  All other intervenors supported OPC’s arguments and recommendation. (SACE BR 18-19; FIPUG BR 2; FEA BR 2, 10; FRF BR 3, 12)

ANALYSIS

This is a fall-out issue.  The total jurisdictional amount is the sum of the recovery amounts decided in Issues 25, 26, 27, 30, 31, and 32.  For purposes of completeness, the effects of each of the parties’ positions in preceding issues are shown below.

Table 33-1:  FPL’s Net 2013 Nuclear Cost Recovery Clause Amount

 

 

CONCLUSION

Staff recommends the Commission approve a total jurisdictional amount of $151,491,402 as the 2013 Nuclear Cost Recovery Clause amount.  This amount should be used in establishing FPL’s 2013 Capacity Cost Recovery Clause factor.

 PROPOSED STIPULATIONS

DOCKET NO. 120009-EI

PROGRESS ENERGY FLORIDA, INC

 

ISSUE 2:         Should the Commission disallow recovery of any AFUDC on the Crystal River Unit 3 Uprate project in 2012 and 2013 due to the lack of a final decision to repair         or retire Crystal River Unit 3?  If yes, what amount should the Commission             disallow, if any? 

 

STIPULATION

 

            The questions presented in this issue are moot for the 2012 nuclear costs recovery clause (“NCRC”) hearing because on September 5, 2012 the Commission voted to approve PEF’s motion requesting deferral of the Commission’s review of the reasonableness of PEF’s 2012 and 2013 CR3 Uprate estimated and projected costs and associated carrying costs until the 2013 NCRC proceeding.

 

ISSUE 12:       Should the Commission approve what PEF has submitted as its 2012 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.?  If not, what action,     if any, should the Commission take?

 

STIPULATION

 

This issue is moot for the 2012 NCRC hearing because on September 5, 2012 the Commission voted to approve PEF’s motion requesting deferral of the Commission’s review of the long-term feasibility of completing the CR3 Uprate project until the 2013 NCRC proceeding.

 

ISSUE 16:       Is it reasonable for PEF to incur or expend all of the estimated and projected     Crystal River Unit 3 Uprate project expenditures in 2012 and 2013 in the absence   of a final decision to repair or retire CR3?

 

STIPULATION

 

This issue is moot for the 2012 NCRC hearing because on September 5, 2012 the Commission voted to approve PEF’s motion requesting deferral of the Commission’s review of the reasonableness of PEF’s 2012 and 2013 CR3 Uprate estimated and projected costs and associated carrying costs until the 2013 NCRC proceeding.

PROPOSED PARTIAL STIPULATION

 

The following is a proposed partial stipulation.  It addresses only one incident related to St. Lucie Unit 2 and the costs that flowed from that incident.  The remaining costs that will flow through Issue 29 are not addressed by this stipulation.  Specifically, the matters raised by OPC in Issue 29A and incorporated in Issue 29 by reference, are not addressed by this partial stipulation.  Florida Power & Light Company agreed with staff’s position.  The remaining parties do not object to this partial stipulation.

 

ISSUE 29:       Should the Commission find that FPL’s 2011 project management, contracting,             accounting and cost oversight controls were reasonable and prudent for FPL’s         Extended Power Uprate project?

 

PARTIAL STIPULATION

 

As to the testimony of staff witnesses Rich and Fisher regarding the St. Lucie Unit 2 nuclear plant stator core work:

 

In its 2012 actual/estimated costs for St. Lucie Unit 2, FPL included costs payable to Siemens for contract work at St. Lucie nuclear plant.  Commission Audit Staff recommended a $3.5 million disallowance of EPU costs with respect to the St. Lucie nuclear plant stator core work.  Commission audit staff noted that there was an additional 22 days of outage associated with the nuclear plant stator core work.  FPL filed rebuttal testimony controverting audit staff’s findings regarding FPL’s management of the St. Lucie nuclear plant stator core work.  FPL also responded to Staff discovery stating that the stator alignment pin issue added approximately 195 unplanned outage hours to the total duration of the outage. 

 

Subsequent to the filing of its rebuttal testimony, FPL filed supplemental testimony and exhibits in which it explained that FPL negotiated a new agreement related to FPL’s costs for the St. Lucie Unit 2 stator core repair work.  The new agreement removes the $3.5 million of costs FPL was responsible for paying to Siemens for the stator core work. 

 

An additional aspect of the new agreement between FPL and Siemens was a reduction of (confidential) of the amount owed by FPL to Siemens for other contractual work.  The basis for the reduction is the resolution of the nuclear stator core work. 

 

 Accordingly, staff recommends the Commission find that Audit Staff’s recommendation for the disallowance is now moot because FPL negotiated a resolution with its contractor which adequately addresses the considerations raised by Audit Staff.  Audit Staff will verify the removal of these costs in its next scheduled annual audit.

 

As to the remaining costs, staff takes no position at this time.