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DATE:

September 22, 2014

TO:

Office of Commission Clerk (Stauffer)

FROM:

Office of Industry Development and Market Analysis (Lewis, Breman, Hinton, Laux)

Division of Economics (Draper, Garl, Higgins)

Division of Engineering (Matthews, Vickery)

Office of the General Counsel (Lawson, Mapp)

RE:

Docket No. 140009-EI Ė Nuclear cost recovery clause

AGENDA:

10/02/14 Ė Special Agenda Ė Post-Hearing Decision Ė Participation is limited to Commissioners and Staff

COMMISSIONERS ASSIGNED:

Brisť, Balbis, Brown

PREHEARING OFFICER:

Brown

CRITICAL DATES:

None

SPECIAL INSTRUCTIONS:

None

 


Table of Contents

Issue†††††† Description†††††††††††††††††††††††††††††††††††††††††††††††††††††††††††††††††††††††††††††††††††††††††††††††††††††††††††††††††††† Page

†††††††††††††† List of Acronyms and Abbreviations. 3

†††††††††††††† Case Background. 4

†††††††††††††† DEF Issues

2†††††††††††† Whether DEF Reasonably Accounted for COL Costs. 8

3†††††††††††† Reasonableness of Levy Project Recovery Amounts. 12

4†††††††††††† Should DEF Make a $54 Million Credit 15

5†††††††††††† Proposed Conditions on DEF's Attempts to Dispose of LLE. 22

9†††††††††††† DEF Net 2015 Recovery Amount 26

†††††††††††††† FPL Issues

10†††††††††† Long-term Feasibility of Completing the TP Project 28

10A††††††† Estimated All-inclusive Costs for the TP Project 45

10B††††††† Estimated Commercial Operation Date of the TP Project 47

12†††††††††† Final True-up of 2013 TP Project Costs. 49

13†††††††††† Reasonableness of Estimated 2014 TP Project Costs. 52

14†††††††††† Reasonableness of Projected 2015 TP Project 55

17†††††††††† FPL Net 2015 Recovery Amount 57

†††††††††††††† Attachment I: DEF Ė Category II Stipulations. 59

†††††††††††††† Attachment II: FPL Ė Category II Stipulations. 61

 


List of Acronyms and Abbreviations

 


 

2013 Settlement Agreement

2013 Revised and Restated Stipulation and Settlement Agreement

AFUDC

Allowance for Funds Used During Construction

CCRC

Capacity Cost Recovery Clause

COL

Combined Operating License

Commission

Florida Public Service Commission

CPVRR

Cumulative Present Value of Revenue Requirements

CR3 Uprate Project

DEFís multi-phased uprate project at Crystal River Unit 3

CWIP

Construction Work In Progress

DEF

Duke Energy Florida, Inc.

DSM

Demand Side Management

EPC

Engineering, Procurement, and Construction

Uprate Project

FPLís multi-phased uprate project at St. Lucie Units 1 & 2 and Turkey Point Units 3 & 4

F.A.C.

Florida Administrative Code

FIPUG

Florida Industrial Power Users Group

FPL

Florida Power & Light Company

FRF

Florida Retail Federation

F.S.

Florida Statutes

Joint Intervenors or JI

OPC, FIPUG, FRF and PCS Phosphate

Levy Project or LNP

DEFís Levy Units 1 & 2 project

LLE

Long Lead Equipment

MW

Megawatt (1,000,000 watts)

NCRC

Nuclear Cost Recovery Clause

NRC

Nuclear Regulatory Commission

O&M

Operations and Maintenance

OPC

Office of Public Counsel

PCS Phosphate

White Springs Agricultural Chemicals Inc. d/b/a PCS Phosphate Ė White Springs

SACE

Southern Alliance for Clean Energy

TP Project

FPLís Turkey Point Units 6 & 7 project

WEC

Westinghouse Electric Company

 

 

 

 


Case Background

On March 3, 2014, Duke Energy Florida, Inc. (DEF) and Florida Power & Light Company (FPL) filed petitions seeking prudence review and final true-up of actual costs for certain nuclear power plant projects pursuant to Rule 25-6.0423, Florida Administrative Code (F.A.C.), and Section 366.93, Florida Statutes (F.S.).† On May 1, 2014, DEF and FPL filed additional petitions seeking approval of estimated future activities and costs.† Both companies made requests to recover certain costs in 2015 through the Capacity Cost Recovery Clause (CCRC).

DEFís petitions addressed two nuclear construction projects: the uprate of its existing nuclear generating plant, Crystal River Unit 3 (CR3 Uprate Project), and the construction of new nuclear generating units, Levy Units 1 and 2 (Levy Project). DEF obtained an affirmative need determination for the CR3 Uprate Project in 2007 by Order No. PSC-07-0119-FOF-EI.[1]† DEF obtained an affirmative need determination for the Levy Project in 2008 by Order No. PSC-08-0518-FOF-EI.[2]† In 2013, DEF determined it will no longer pursue construction of these projects.

FPLís petitions addressed continued development of two nuclear construction projects.† The first project includes uprate activities at its four existing nuclear generating units, Turkey Point Units 3 and 4 and St. Lucie Units 1 and 2 (Uprate †Project). FPL obtained an affirmative need determination for its Uprate Project in 2008 by Order No. PSC-08-0021-FOF-EI.[3]† The second project is the construction of two new nuclear generating units, Turkey Point Units 6 and 7 (TP Project).† FPL obtained an affirmative need determination for the TP Project in 2008 by Order No. PSC-08-0237-FOF-EI.[4]

Traditionally, all power plant construction costs were generally afforded the same regulatory accounting and ratemaking treatment.† That is, once the need for a power plant was determined, the utility would record 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 would be applied to the average balance in the account and the resulting dollar amount would then be added to the account balance.† This process continued until completion of the project.

Once a power plant is placed in commercial service, the CWIP account balance would be transferred to the appropriate plant-in-service accounts and become part of the utilityís rate base.† The impact of including the total project costs in a utilityís rate base, as well as the impact of additional plant operating expenses, would be addressed during a subsequent proceeding to determine whether customer base rates should be changed in order to provide the utility the opportunity to recover such costs.

Also under the traditional regulatory scheme, if a construction project is terminated prior to being placed in commercial service, the utility may petition to recover the related CWIP account balance as a regulatory asset that is amortized over a period of years.

In 2006, the Florida Legislature enacted Section 366.93, F.S., to encourage utility investment in nuclear electric generation in Florida by authorizing an alternative cost recovery mechanism for these projects.† Section 366.93, F.S., directed the Florida Public Service Commission (Commission) to allow investor-owned electric utilities to recover certain costs during the licensing and construction process.† 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. †In 2013, the Florida Legislature further amended the statute to change the applicable carrying costs, restrict cost recovery during the license application process, and require Commission approval prior to commencing certain activities and purchases.† The 2013 amendments also established timeframes within which utility activities must commence after obtaining a combined operating license.

The Commission adopted Rule 25-6.0423, F.A.C., to implement Section 366.93, F.S.[5]† Pursuant to Rule 25-6.0423(5) and (6), 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. Pursuant to Section 366.93(2), F.S., and Rule 25-6.0423(6), 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 CCRC.† Rule 25-6.0423(6)(c)5., F.A.C., requires a utility to submit, for Commission review and approval, an annual detailed analysis of the long-term feasibility of completing the power plant.

When a power plant is placed in commercial service a utility is allowed, pursuant to statute and rule, to increase its base rates.† Section 366.93(4), F.S., describes the method for calculating the increase and Rule 25-6.0423(8), F.A.C., 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, Section 366.93(6), F.S., and Rule 25-6.0423(7), F.A.C., allow a utility to recover its prudently incurred costs over at least a 5 year period.

Rule 25-6.0423(6), 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 CCRC pursuant to Section 366.93, F.S.† This is the seventh year the Commission has convened an evidentiary hearing to examine cost recovery for nuclear construction projects.

The following parties intervened: 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 Ė White Springs (PCS Phosphate), and Florida Retail Federation (FRF).† FPL, DEF, and Commission staff prefiled testimony.

In 2013, DEF filed a Petition for Limited Proceeding to Approve a Revised and Restated Stipulation and Settlement Agreement (2013 Settlement Agreement) that was signed by OPC, FRF, FIPUG, FEA, and PCS Phosphate. †DEF also filed a motion to defer its issues in the 2013 proceeding pending approval of the 2013 Settlement Agreement, which was approved as part of preliminary matters during the 2013 Nuclear Cost Recovery Clause (NCRC) hearing.[6]† The Commission approved the 2013 Settlement Agreement by Order No. PSC-13-0598-FOF-EI.[7]† This 2013 Settlement Agreement was a comprehensive settlement addressing issues from multiple dockets.† Requirements from the 2013 Settlement Agreement that affected this docket include:

        DEFís recovery amount for the Levy Project reflect the use of a prescribed fixed factor set by rate class.

        DEFís recovery of Levy Project costs is limited to only those costs associated with the activities identified in the 2013 Settlement Agreement unless otherwise agreed to by the signatory parties.

        DEF is allowed to recover its CR3 Uprate Project costs through the NCRC consistent with Section 366.93(6), F. S.

As a preliminary matter in the 2014 NCRC proceeding the Commission was presented with proposed stipulations between staff and DEF on uncontested Issues 1, 2A, 6, 7 and 8.[8] (TR 302-310; EXH 96)† Upon discussion with the parties, the Commission accepted and approved the proposed resolutions on each of these issues. (TR 310)† A copy of the resolved issues with position statements is included in Attachment I to this recommendation.

This recommendation addresses unresolved DEF Issues 2, 3, 4, 5 and 9.† Issues 2 and 3 address DEFís activities and costs related to the Levy Project for the reviewed period.† Issues 4 and 5 address matters stemming from the cancellation of the Engineering, Procurement and Construction (EPC) contract for the Levy Project.† In Issue 9 staff presents DEFís net NCRC amount for 2015 period based on the decisions made on all prior DEF issues and applicable prior Commission Orders.

On August 18, 2014, post-hearing briefs addressing Issues 2, 3, 4, 5 and 9, were filed by DEF, and jointly by OPC, FRF, FIPUG, and PCS Phosphate (Joint Intervenors).† On Issues 2 and 3, each intervenor affirmed its stated position without further discussion.†† The Joint Intervenorsí post-hearing brief focused on Issues 4, 5, and 9.

Regarding the FPL portion of the proceeding, on July 28, 2014, FPL filed a procedural motion addressing agreements between FPL, OPC, SACE, FIPUG, and FRF.† The procedural motion stated that upon Commission approval, FPL, OPC, SACE, FIPUG, and FRF would waive opening statements, cross-examination of witnesses, and filing of post-hearing briefs.† Also, the parties requested that the Commissionís final order show partiesí positions on certain issues as reflected in Attachment A of the procedural motion.† On August 4, 2014, the Commission convened the evidentiary hearing in this docket.† As part of its discussion of preliminary matters, the Commission addressed and approved the FPL procedural motion. (TR 9-12)

The Commission also approved the resolution of FPL Issues 11, 15, and 16 that were uncontested.[9] (TR 302-306; EXH 95)† A copy of the resolved issues with position statements is included in Attachment II to this recommendation.† Consequently, for FPL, this recommendation addresses unresolved Issues 10, 10A, 10B, 12, 13, 14, and 17.† The focus of Issues 10, 10A, and 10B is FPLís analysis of the feasibility of completing the TP Project, while Issues 12, 13, and 14 address project activities and costs for the reviewed period.† In Issue 17 staff presents FPLís net NCRC amount for the 2015 period based on the resolution of all prior FPL 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

DEF Issues

Issue 2: 

 Has DEF reasonably accounted for Combined Operating License (COL) pursuit costs pursuant to paragraph 12(b) of the 2013 revised and restated stipulation and settlement agreement?

Recommendation

 Yes, DEF has reasonably accounted for 2013 costs associated with the pursuit of a COL pursuant to paragraph 12(b) of the 2013 revised and restated stipulation and settlement agreement.† (Lewis, Laux)

Position of the Parties

DEF

 Yes. DEF reasonably and prudently incurred COL-related costs in 2013 that were necessary for the Levy COLA and consistent with the 2013 Settlement Agreement. In 2014, DEF has taken steps to ensure that COL related costs, as defined in the 2013 Settlement Agreement, are not included in the NCRC proceeding. DEF segregates project costs incurred by specific project code. Accordingly, for 2014, the team charges COL-related labor, NRC fees, vendor invoices and all other COL-related cost items to the applicable COL project codes. Thereafter, the Regulatory Accounting and Regulatory Strategy groups ensures that the COL-related project codes and associated costs incurred in 2014 and beyond are not included in the Companyís NCRC Schedules, and thus not presented for nuclear cost recovery. COL-related costs will however continue to be tracked for accounting purposes consistent with the 2013 Settlement Agreement.

OPC

 At this time, it appears that Duke has complied with the 2013 revised and restated stipulation and settlement agreement, insofar as the accounting for costs which it has directly attributed to or classified as COL pursuit and which were expended in 2013 and which the company has estimated for 2014.† At this point in the 2014 hearing cycle, given the uncertainty relating to the ongoing dispute with WEC and pending discovery, the OPC will be unable to formulate a position on, but does not waive any rights with respect to, whether Dukeís efforts to achieve the LNP COL might have other associated costs that have been or will be submitted for NCRC recovery, but which are appropriately attributable to Dukeís shareholders.

FIPUG

 Adopt position of OPC.

PCS PHOSPHATE

 No position.

SACE

 No position.

FRF

 Agree with OPC that it appears that Duke has complied with the 2013 Revised and Restated Stipulation and Settlement Agreement related to accounting for costs classified as COL pursuit costs expended in 2013 and estimated for 2014.† The FRF further agrees with OPC that, given the uncertainty relating to Dukeís ongoing dispute with WEC, the FRF cannot formulate a position on, but does not waive any rights with respect to, whether Dukeís efforts to achieve the LNP COL may have associated costs that have been or will be submitted for NCRC recovery, but which are appropriately attributable to Dukeís shareholders pursuant to the RRSSA.

Staff Analysis

 At issue is whether DEF has reasonably accounted for 2013 COL costs and done so in compliance with the 2013 revised and restated settlement agreement (2013 Settlement Agreement).[10]† The intervenors have either taken no position (PSC Phosphate, SACE) or indicated their agreement with OPC (FIPUG, FRF).

PARTIES ARGUMENTS

 

DEF

 

††††††††††† DEF argued that it has properly and reasonably accounted for all 2013 costs associated with pursuit of a COL in accordance with the terms of the 2013 Settlement Agreement. (DEF BR 5)† Witness Fosterís testimony explained that DEF utilizes project accounting and cost oversight controls which are consistent with best practices for capital project cost oversight and accounting controls in the industry and that are vetted by internal and external auditors. (TR 405)† DEFís practice of segregating project costs incurred by specific project code was used in 2013 and will continue in 2014 and going forward.† However, consistent with the 2013 Settlement Agreement, costs incurred in 2014 and beyond will not be included in DEFís NCRC Schedules or be presented for nuclear cost recovery. (TR 405)† Witness Fallon also testified to DEFís treatment of COL costs, including environmental permitting, wetlands mitigation, and conditions of certification associated with pursuit of a COL from the Nuclear Regulatory Commission (NRC).† Witness Fallon also stated that although DEF will continue to incur COL costs for the Levy Project in 2014 and 2015, DEF will not seek to recover these costs from customers through the NCRC pursuant to the 2013 Settlement Agreement. (TR 498)

 

OPC, FIPUG, FRF, and PCS Phosphate (Joint Intervenors), and SACE

 

††††††††††† The Joint Intervenors each maintains the position shown in the Prehearing Order on Issue 2. (JI BR 3)† OPCís prehearing position stated in part, ďAt this time, it appears that Duke has complied with the 2013 revised and restated stipulation and settlement agreement, insofar as the accounting for costs which it has directly attributed to or classified as COL pursuit and which were expended in 2013 and which the company has estimated for 2014.Ē† FIPUG adopted and FRF agreed with OPCís position.† PSC Phosphate and SACE took no position on Issue 2.

 

ANALYSIS

 

††††††††††† No party challenged DEFís position.† DEF has provided testimony and exhibits to support its position that COL costs for 2013 have been reasonably accounted for in accordance with the 2013 Settlement Agreement.

†††††††††††

††††††††††† DEF witness Fallon testified that DEF was continuing work necessary to obtain a COL from the NRC and environmental permitting work necessary to obtain a Section 404 permit from the U.S. Army Corp of Engineers, and that these efforts were consistent with the 2013 Settlement Agreement. (TR 501-502)† In discussion of DEFís project management and cost control oversight, witness Fallon explained that in 2014 DEF continues to ensure that all COL-related costs are segregated by specific project code and that they will not be included in the NCRC.† These costs will continue to be tracked for accounting purposes consistent with the 2013 Settlement Agreement. (TR 519-520; 552)† Joint Intervenorsí cross examination of witness Fallon did not identify any inappropriate COL-related activities or expenditures in DEFís recovery request. (TR 559-560; 562-565)

 

††††††††††† DEF witness Foster testified that the project accounting and cost oversight controls that DEF utilized in 2013 to ensure proper accounting treatment for the Levy Project have been reviewed by the Commission staff in annual financial audits and found to be reasonable and prudent in Docket Nos. 090009-EI, 100009-EI, 110009-EI, and 120009-EI. (TR 399)† Witness Foster also testified that going forward in 2014 and beyond, established procedures remain in place to require review of COL-related cost accounting project codes by internal DEF Regulatory Accounting and Regulatory Strategy groups. (TR 415)† The Joint Intervenorsí cross- examination of witness Foster did not reveal any improper or unreasonable accounting methods with regard to COL-related activities or expenditures.† (TR 440-443)

 

††††††††††† Commission audit staff witness Mavridesí testimony examined recorded costs for the Levy Project as of December 31, 2013.† Witness Mavrides testified that the staff audits verified the costs incurred were posted to the proper accounts; sorted the costs by generation and transmission costs; reconciled the beginning balances of the costs with the ending balances of the prior year filing; tested selected samples for compliance with contracts, correct paid amounts, and correct recording periods; reconciled the detail amounts to the filing and to the general ledger; sorted operations and management expense by functional expense category and reconciled to the filing; selected costs and reviewed them for the proper period, amounts, and whether they were allowable NCRC costs; and verified a sampling of labor costs for hours worked and proper calculation of labor charges by DEF.† There were no findings in the audit report filed by witness Mavrides.† (TR 353-354; EXH 5)

 

††††††††††† Audit staff also filed testimony that included the annual management audit report.† The management audit covering 2013 activities was conducted by witnesses Coston and Fisher.† The audit team examined key areas of project activity including planning, management and organization, cost and schedule controls, contractor selection and management, and auditing and quality assurance associated with the Levy Project during 2013.† The audit report made no findings that indicated that DEF had not reasonably accounted for COL pursuit costs. (TR 364-365, EXH 31)

 

††††††††††† No intervenors cross-examined the staff witnesses or challenged their testimony.† ††††††††† There was no testimony filed by other parties on this issue.†

 


CONCLUSION

 

††††††††††† DEF has provided substantial evidence that DEF has properly accounted for 2013 costs associated with its pursuit of the COL for the Levy Project, and that it has done so in accordance with the 2013 Settlement Agreement.† No party has disputed the adequacy of DEFís accounting procedures and staffís review of the evidence confirms that DEF has reasonably accounted for COL pursuit costs.† Consequently, the Commission should find that DEF has reasonably accounted for COL pursuit costs pursuant to paragraph 12(b) of the 2013 revised and restated stipulation and settlement agreement.

 

 


Issue 3: 

 Should the Commission approve DEF's Levy Project exit and wind down costs and other sunk costs as specifically proposed for recovery or review in this docket?

Recommendation

 Yes.† The Commission should approve DEFís Levy Project exit and wind-down costs of $14,679,680 for recovery in 2015.† (Lewis, Laux)

Position of the Parties

DEF

 Yes. DEF dispositioned the LLE in active fabrication and consequently reduced ongoing contractual costs, resulting in savings compared to the committed contractual payments, for DEF and its customers. DEF further reduced WECís activities and costs to assist with the LLE disposition and wind down the project.† DEF terminated the EPC Agreement when it was unable to obtain the COL by January 1, 2014, and, does not owe a termination fee under the EPC Agreement.† DEF closed out its relationship with S&W in a timely and cost-effective manner for DEF and its customers. DEFís actions have been and will continue to be reasonable and prudent for DEF and its customers.

 

DEFís testimony and exhibits only present for recovery those costs that are recoverable consistent with the 2013 Settlement Agreement. There has been no evidence presented that any cost presented for recovery does not comply with the NCRC statute or rule or the 2013 Settlement Agreement. Accordingly, the Commission should approve the following costs presented for recovery in this docket.

Based on DEFís May 1, 2014 filing 2014 Est/Act:

 

Wind-Down / Exit Costs (Jurisdictional) $25,216,773

Carrying Costs $13,534,781

 

The under-recovery of $7,990,738 should be included in setting the allowed 2015 NCRC ††††††† recovery.

 

The 2014 variance is the sum of under-projection exit/wind-down costs of $12,627,988 †††††††††† plus an over-projection of carrying costs of $4,637,250.

Based on DEFís May 1, 2014 filing 2015 Projection:

Wind-Down / Exit Costs (Jurisdictional) $1,209,912

Carrying Costs $5,479,030

 

For the LNP, an amount necessary to achieve the rates included in Exhibit A ††† ($3.45/1,000kWh on the residential bill) of the Settlement Agreement approved in Order †††† No. PSC-13-0598-FOF-EI page 176 should be included in establishing DEFís 2015 ††††††††† CCRC.

OPC

 No position.

FIPUG

 Potential, future wind-down or long lead equipment disposition costs or credits that cannot be reasonably quantified at this time should not be approved, and the Commission should expressly state that it is taking no action related to such disposition costs or credits at this time.

PCS PHOSPHATE

 No position.

SACE

 No position.

FRF

 No position.

Staff Analysis

 This issue addresses whether the Commission should approve DEFís 2014 and 2015 Levy Project exit and wind-down costs and other sunk costs as specifically proposed for recovery or review in this docket.† With the exception of FIPUG, the intervenors have taken no position on this issue.†

PARTIES ARGUMENTS

DEF

††††††††††† DEF argued that it had appropriately managed exit and wind-down costs and other sunk costs such as the disposition of long lead equipment (LLE), termination of the engineering, procurement and construction (EPC) agreement, and closing out its relationship with Stone & Webster, Inc.† DEF maintained that its actions have been cost-effective for customers and both reasonable and prudent.† In addition, DEF presented for recovery only those costs that are recoverable consistent with the 2013 Settlement Agreement, the NCRC statute, and Commission rules.† (TR 499-500, 502-503; BR 6-7)

OPC, PCS Phosphate, SACE and FRF

††††††††††† Intervenors OPC, PSC Phosphate, SACE, and FRF have each taken no position on this issue. (JI BR 3)

FIPUG

FIPUG maintained that DEFís potential, future wind-down or LLE dispostion costs or credits that cannot be reasonably quantified at this time should not be approved and the Commission should expressly state that it is taking no action related to such dispostion costs or credits at this time. (JI BR 3)

ANALYSIS

DEF witness Fallon testified that DEF has actual/estimated costs in 2014 as a result of Levy wind-down activities. (TR 502-503)† Categories of costs that were incurred and will be incurred according to witness Fallon were provided as follows: (1) storage, insurance, and quality assurance of the completed and partially completed Levy LLE components until disposition; (2) internal DEF labor to assist with disposition of LLE; (3) external WEC support to gather information from LLE suppliers and assist with disposition of the LLE; and (4) regulatory and administrative wind-down support.† (TR 502-503)† Witness Fallon also testified that while DEF expects to conclude its LLE disposition efforts in 2014, DEF is currently projecting minimal wind-down costs for 2015.† DEF witness Fallon also testified that the 2015 cost ď. . . projection does not take into account any costs that DEF simply is not able to reasonably quantify at this time.Ē (TR 507, EXH 5)

FIPUG believes future costs cannot be reasonably quantified at this time and therefore the Commission should expressly state that it is taking no action related to the disposition costs or credits in this docket.† However, FIPUG has presented no record evidence supporting a claim that the costs DEF has quantified and presented for recovery are unreasonable.† Witness Fallon testified, ďDEF does not include in this filing potential, future wind-down or LLE disposition costs or credits that DEF cannot reasonably quantify at this time.Ē (TR 503)† Staff believes DEFís request that the Commission approve the costs presented in its petition is not in conflict with FIPUGís position, as DEF did not assert it was requesting Commission action on matters that cannot be reasonably quantified at this time.†

For 2014, DEFís actual/estimated wind-down and exit costs are $25,216,773 (jurisdictional).† DEFís previous projection of 2014 costs was underestimated by $12,627,988, and carrying costs were overestimated by $4,637,250, resulting in an expected underrecovery of $7,990,738 for 2014.† For 2015, DEFís projected wind-down/exit costs are $1,209,912 plus carrying costs of $5,479,030, for a total of $6,688,942 (jurisdictional).† The total amount that should be approved for determining the 2015 NCRC recovery is $14,679,680 ($7,990,738 + $6,688,942 = $14,679,680). (EXH 5, DEF BR 6-7, TR 502-507)† The total jurisdictional amount to be included in establishing DEF's 2015 Capacity Cost Recovery Clause Factor is discussed in Issue 9.

CONCLUSION

 

††††††††††† The Levy Project exit and wind-down costs and other sunk costs DEF has presented for recovery or review in this docket are in compliance with the NCRC statute, Commission rules and the 2013 Settlement Agreement.† In addition, no intervenors have disputed the costs or presented evidence that such costs were not reasonably quantified.† Based upon staffís review of the record evidence, the Commission should approve DEFís Levy Project exit and wind-down costs of $14,679,680 for recovery in 2015.

 


Issue 4: 

 What action, if any, should the Commission take in the 2014 hearing cycle with respect to the $54,127,100 in Long Lead Equipment milestone payments, previously recovered from customers through the NCRC, which were in payment for Turbine Generators and Reactor Vessel Internals that were never manufactured?

Recommendation

 Staff recommends that the Commission take no action on this Issue. ††(Laux, Lewis, Lawson)

Position of the Parties

DEF

 None. The $54 million referenced by OPC was incurred by DEF in 2008 and 2009 based on the circumstances of the project at that time and was determined by the Commission to be a prudent cost incurred by DEF. To the extent OPC or any party suggests by this issue that the Commission can review the prudence of a cost it previously determined to be prudent, that is contrary to law and Commission rule.† See Fla. Admin. Code R. 25-6.0423(6)(a)(3).

 

DEF is actively pursuing litigation in federal court against WEC in order to recover any and all costs that it can for customers, including the $54 million payment.† If and when a court determines, after appropriate appeal or further review, that DEF is entitled to recover from WEC the $54 million previously paid WEC for LLE, DEF will credit the amount of the court award to customers. As such, the Commission should take no action in the 2014 NCRC on this issue.

JOINT INTERVENORS

 (OPC, FRF, FIPUG and PCS Phosphate) The Commission should direct Duke to recognize a credit in favor of Dukeís customers for $54,127,100 in Schedule TGF-4, effective January 28, 2014, to reflect Dukeís position taken in a federal lawsuit that it used that amount of customer-provided funds to pay Westinghouse Electric Company (WEC) for the manufacture of equipment which never occurred.† The Commission has authority and jurisdiction over these dollars and its order directing the credit is both necessary under the nuclear cost recovery rule and appropriately signals to Duke that it is the utilityís responsibility to retrieve these funds for its customers. Intervenors request that the Commission direct Duke to cease collecting the LNP portion of the NCRC charge in mid-2015 as dictated by the fallout of recording the assumed refund on January 28, 2014.

SACE

 No position.

Staff Analysis

 This issue addresses the appropriate Commission action concerning $54,127,100 that DEF is attempting to collect from Westinghouse Electric Company (WEC) following DEFís termination of the Levy Project Engineering, Procurement, and Construction contract (EPC).

PARTIESí ARGUMENTS

DEF

††††††††††† DEF stated that the Commission should not take any action to credit customers for a $54 million refund that has not yet occurred and is the subject of claims pending at this time in a North Carolina Federal District Court. (DEF BR 8)† DEF further stated that if the Court determines DEF is entitled to recover from WEC $54 million of previously paid milestone payments under the EPC agreement, DEF will credit the full amount of the Court award to customers.† Therefore, DEF argued, the Commission does not need to take any action on this issue at this time. (DEF BR 8)

††††††††††† DEF also argued that there is no factual or legal justification for the Commission to grant what the Joint Intervenors are requesting. (DEF BR 9)† DEF stated that witness Foster testified that DEF did not receive a payment from WEC of $54 million in January 2014, or at any other time. (DEF BR 9)† DEF argued that it cannot legally record in its financial schedules a cash credit that it has not received.† To do so would be inconsistent with Generally Accepted Accounting Procedures (GAAP) financial standards. (DEF BR 9)† DEF stated its firm belief that it is entitled to the $54 million refund from WEC.† The fact that DEF is vigorously pursuing this claim in the litigation does not create the certainty required for a refund to be recorded on the Companyís books, even as an accrual.† However, DEF acknowledged that the actual outcome of the litigation is speculative and therefore cannot be recorded on DEFís books. (DEF BR 10)

††††††††††† DEF also stated that the Joint Intervenorsí request that the Commission order a $54 million refund to customers for prudently incurred LLE payments violates Commission rule. DEF argued that Commission rule precludes the Commission from revisiting its determination that a NCRC cost was prudently incurred.† Similar, long standing Commission and judicial authority precludes using hindsight as a basis in prudence reviews. (Rule 25-6.0423(6)(a)2. and (c)., Florida Administrative Code). (DEF BR 12)† Given this, DEF argued there is no legal authority for the Commission to grant the Joint Intervenorsí requested refund. (DEF BR 12)

††††††††††† DEF further stated that the Joint Intervenors relied on changed circumstances to assert that the Commission should order DEF to credit customers with a refund of $54 million in prudently incurred LLE payments. (DEF BR 13)† DEF stated that the Joint Intervenorsí request that the Commission order DEF to credit customers $54 million before the court has awarded DEF any refund is in effect asking the Commission to disallow costs it had previously determined to have been prudently incurred. (DEF BR 14)

††††††††††† For these reasons, DEF argued that the Commission cannot and should not take any action at this time with respect to DEFís pending claims against WEC in Federal District Court. (DEF BR 15)

Joint Intervenors

The Joint Intervenors stated that this issue involves correcting the customersí side of the ledger in the NCRC for two significant payments that DEF made to WEC for work that DEF subsequently cancelled and WEC never performed. (JI BR 4)†† The Joint Intervenors stated that when DEF terminated the Levy Project EPC contract it finally became apparent that the fabrication work would never be performed, and a credit of the amount previously charged to customers became due. (JI BR 4)† Given this, the Joint Intervenors argued that customers are entitled to receive their $54 million back in the form of a credit.† In addition, if the credit is approved, a mid-2015 termination of the Levy portion of the cost recovery charge should be ordered. (JI BR 2)

The Joint Intervenors further stated that the Commission has all the facts it needs, and that none of the relevant facts are in dispute. (JI BR 4) ††They argued that the Commission has both the obligation to correct DEFís nuclear cost recovery to account for this known change, and the authority to order the refund to be recognized as of January 28, 2014.† As a result, the Levy Project NCRC fixed monthly rate should cease to be charged to customers by mid-2015. (JI BR 4-5)

The Joint Intervenors also stated that DEFís demand to WEC for the return of the LLE payments is an admission by DEF that those costs are no longer eligible for NCRC recovery. (JI BR 7)† They argued that Section 366.93 F.S., and Commission Rule 25-6.0423† F.A.C., does not authorize the recovery of costs for which no work is performed. In addition, they argued that the provisions of Section 403.519(4)(e), F.S., does not apply because DEF has admitted that in cancelling the EPC, the $54 million in payments relates to work that never was and never will be performed.† Therefore, the Joint Intervenors argued it would now be imprudent to continue to engage in the fiction that this $54 million relates to NCRC recoverable costs. (JI BR 7)

The Joint Intervenors suggested that DEFís admissions in its Federal Court claims provide ample basis for a Commission order directing that a credit be given immediate accounting and ratemaking recognition. (JI BR 10)† They argued that the only plausible reason for postponing the implementation of the refund/credit through the NCRC is to ascertain whether and to what extent DEF eventually is successful in recovering the $54 million from WEC.† In this regard, the Joint Intervenors argued that the passage of time will not alter the operative facts that ratepayers erroneously paid for work that was never performed.† Therefore, ratepayers are not obliged under the nuclear cost recovery rule to insure DEFís litigation risk in a contract dispute. (JI BR 10)

† The Joint Intervenors stated that if the Commission grants their request to effectuate the credit as of January 2014, the Commission will ensure that customers will receive the full amount of the requested refund.† The Joint Intervenors stated the amount of the refund should not be compromised by litigation with WEC and will make clear to DEF that consumers are not mere insurers of whatever litigated or settled outcome that may eventually transpire. (JI BR 12)

ANALYSIS

This issue concerns certain scheduled milestone payments for LLE items DEF made to WEC under the Levy Project EPC contract.† DEFís witness Fallon testified that these scheduled milestone payments concerned the material procurement and manufacturing of two of the fourteen Levy Project LLE items, namely the reactor vessel internals and turbine generators. (TR 603)† The payments in question included $2,348,660 made in 2008 and $51,778,440 made in 2009.† (TR 537, 558, 580)††† Staff notes that these identified payments where part of a series of scheduled payments, made over time that would have concluded with the delivery of the items in question.† Witness Fallon testified that work by WEC had not begun on these two items due to the suspension of work agreement as provided for within the third amendment to the EPC contract in 2010. (TR 505, 568, 572-573, 575, 580, 604)† Witness Fallon further indicated that, as of March 2014, the return/refund of these milestone payments is part of the on-going litigation between DEF and WEC concerning breach and termination of the EPC contract. (TR 580, 610)

Expenses incurred in prior years are typically considered sunk costs or costs that are no longer retrievable or avoidable.† However, there are instances where contract terms and conditions provide the opportunity to seek refunds if one of the parties does not provide the services or goods that were under contract.† Staff believes a similar contract-based opportunity is what has given rise to the $54,127,100 at issue.† The Joint Intervenors urge Commission action regarding the timing of a credit as well as the termination of the Levy Project NCRC fixed monthly charge.† Staff addresses these topics below and explains why staff believes the actions requested by the Joint Intervenors are not supported by record evidence or the 2013 Settlement Agreement.

DEFís Activities Associated With the $54,127,100 Sunk Cost Amount

The $54,127,100 amount originated when DEF made two scheduled milestone payments to WEC pursuant to the Levy Project EPC contract. (JI BR 5)† The first payment of $2,348,660 occurred in 2008 and the other of $51,778,440 was made in 2009. (TR 603)† DEF stated that WEC had not begun work associated with these payments in 2010 due to the partial suspension of work requested by DEF and agreed to by WEC. (TR 505, 568, 572-573, 575, 580, 604)

In August 2013, the Joint Intervenors and DEF presented the 2013 Settlement Agreement for Commission approval that in section 12.a. stated:

At the earliest reasonable and prudent time, DEF will be terminating the EPC contract for the Levy nuclear power plants because DEF is unable to obtain the LNP Combined Operating Licenses (ďCOLĒ) from the NRC by January 1, 2014.† Regarding the LNP, DEF will exercise the provisions of Section 366.93(6), F.S., and will elect not to complete the construction of the LNP.[11]

In December 2013, DEF requested WEC refund an amount of $54,127,100 concerning work not performed under the EPC contract. (JI BR 6)† On January 28, 2014, DEF cancelled the EPC contract and in March, DEF sued WEC, requesting in part that WEC refund the milestone payments for which work had not begun. (JI BR 6)

In this proceeding, staff observes that there is no dispute regarding the prudence of DEFís original activities when making the scheduled milestone payments in 2008 and 2009, totaling $54,127,100.† Consequently, all prior expenditures, including the $54,127,100 amount addressed in this issue, are potentially sunk costs absent actions by DEF to extract as much value as reasonably practical through reasonable means.† Based on staffís review, no evidence was presented that demonstrated DEFís actions to date were unreasonable in this regard.† However, the Joint Intervenors stated in their post-hearing brief that by suing WEC for the return of funds, DEF has effectively withdrawn the basis for the original prudence determination. (JI BR 7)† Staff cannot agree with the factual basis of the Joint Intervenorsí statement.† Based on a review of the record established for this docket, staff could not find where DEF has made such a declaration, or for that matter, where DEFís actions could be reasonably interpreted in a way such as suggested by the Joint Intervenors.† In addition, for the Commission to modify its prior decision of prudence by relying on changed circumstances that resulted many years after the original determination was made would be inconsistent with Commission practice. Staff believes that Commission practice dictates that prudence determinations are only revisited upon a showing of fraud, perjury, or intentional withholding of key information.[12]† Staff believes there has been no showing by the Joint Intervenors that would require the Commission to order DEF to make the credit as requested at this time.

Timing of a $54,127,100 Cash Credit

The Joint Intervenors asserted that a $54,127,100 cash credit should be recognized as of January 28, 2014. (JI BR 4, 11) †As previously noted, this date coincides with DEFís termination of the EPC contract.† Concerning the timing of a cash credit, the Joint Intervenors state:

Dukeís demand to WEC for the return of the payment, and Dukeís suit against WEC in federal court for the paymentís return are admissions by Duke that, with its termination of the EPC agreement earlier this year, those costs are not eligible for NCRC recovery.† Section 366.93, F.S., and Commission Rule 25-6.0423 F.A.C., do not authorize the recovery of costs for which no work is performed.

(JI BR 7)

The Joint Intervenors further argued that if a $54,127,100 cash credit were recorded in this manner, then the Levy Project NCRC charge should cease in mid-year 2015 as a result. (JI BR 5)† Staff notes no other argument or actual evidence concerning the effective date of the refund was offered by any party to this docket.† Concerning the timing of a cash credit DEF stated in its post-hearing brief:

All parties concede that the $54 million ďcreditĒ that OPC and the interveners claim for the benefit of customers has never been paid to DEF in January 2014, or on any other date for that matter.† There is no factual basis in the record for this ďcreditĒ to customers. It is simply a fiction to designate this sum as a ďcreditĒ for the benefit of customers in January 2014 (or on any other date).

(DEF BR 2)

DEF argued there is no legal basis for the Commission to credit customers these payments when the Commission previously found that these payments were prudently incurred. (DEF BR 3)† DEF did contend that the record evidence demonstrates, however, that engaging in this fictional credit is a violation of Generally Accepted Accounting Procedures (GAAP). (DEF BR 2)†

In response to a number of questions concerning the revenue and accounting impacts of recognizing a hypothetical cash credit in January of 2014, DEFís witness Foster testified, ďI think one thing thatís important to consider is that, yes, if there was an actual payment in January, thatís how the math would work.Ē (TR 455)† He further clarified:

[ . . . ] if you had to record something in an actual period where cash hadnít been received, you would have to record it as an accrual.† We wouldnít be able to do it on our accounting books because GAAP doesnít allow that for potential gains of this type, if you will.

(TR 459)† Staff notes that one of the GAAP standards is that an accounting entry (either for revenue or expense) must represent something that is reasonably known or knowable.†

The only testimony concerning the certainty of the refund was presented by witness Fallon.† Witness Fallon opined that the refund was part of a contested litigation and until the final resolution occurs the outcome remains unknown. (TR 627)† However, witness Fallon did state in response to a question concerning implementation of a refund that it is DEFís position that when the litigation is complete and final and there is a judgment rendered by the Court in North Carolina, DEF will refund to customers any monies they are awarded out of the litigation. (TR 568)

††††††††††† Based on its review of the record, staff believes that a $54,127,100 cash credit as recommended by the Joint Intervenors is not supported by the greater weight of the record evidence.†

Termination of the Levy Project NCRC Fixed Charge

††††††††††† As noted in the Joint Intervenors' arguments, the 2013 Settlement Agreement includes an explicit provision to end the fixed monthly rates for the Levy Project through a final true-up before the expiration date of the Agreement.† Staff notes that Order No. PSC-13-0598-FOF-EI, page 31, paragraph 12.c., states in part, ďTo the extent full recovery of all LNP costs is achieved prior to 2017, DEF will file the final true-up in the applicable prior period.† The final true-up amount will be recovered or refunded to customers in the following year through the NCRC.Ē

††††††††††† The Joint Intervenors stated that witness Foster, under cross examination, confirmed that if the refund amount claim by the Intervenors is recorded in the manner the Joint Intervenors suggested, an over-recovery of between $40-50 million would occur if recovery continued at the fixed monthly rates for the Levy Project. (JI BR 11; TR 458-459) †Therefore, the Joint Intervenors argued:

If the Commission allows the current LNP charge to continue while resolution of the federal lawsuit awaits years of litigation and appeals, the Commission will be allowing Duke to recover $100 million on an annual, on-going basis for costs that have not been approved by the Commission.††††††††† † Terminating the $3.45 sometime during 2015, based on the known Commission-reviewed and Commission-approved costs and taking into consideration the 2015 impact of Dukeís $54 million refund claim, will avoid this unfair result while not precluding Duke from asking the Commission to establish or re-establish a charge (or credit) for any final true-up.†

(JI BR 17)

††††††††††† Staff notes that the only testimony addressing whether DEF would fully recover its Levy Project costs in 2015, absent crediting the proposed $54 million credit, was provided by DEF witness Foster, who testified that ďDEF currently shows a net unrecovered balance of $6.1 million at year end 2015.Ē (TR 419)† Witness Foster went on to clarify why a final true-up should not take place in 2015:

Additionally, there are several areas of potential costs that DEF has not included in its actual/estimated 2014 and projected 2015 costs because, as of the preparation date of this testimony, DEF is unable to accurately estimate, but very well may incur them, as explained by Mr. Fallon.

(TR 419)

Staff observes that with the exception of the proposed $54 million dollar credit, no party disputed DEFís testimony concerning the reasonableness of its estimated 2014-2015 costs (Issue 3).†† Staff acknowledges that if, hypothetically, a large cash credit were recorded at any time before the termination of the 2013 Settlement Agreement, then the possibility of a final true-up consistent with the requirements of the Agreement could likely occur before 2018.† While the Joint Intervenors speculated that DEFís current projections of the Levy Project costs identify all known remaining costs, staff observes that DEF does not support this conclusion nor make similar representations in their un-rebutted testimony.† Given the actual testimony presented at hearing, staff does not believe that the Joint Intervenor assertion is sufficient to conclude that all Levy Project costs have been recovered consistent with the requirements of the 2013 Settlement Agreement.† Consequently, staff believes the Commission should not require the termination of the Levy Project NCRC fixed monthly charge in mid-year 2015.

CONCLUSION

Staff believes the basis offered by the Joint Intervenors to require DEF to record a $54,127,100 cash credit as of January 28, 2014 is not supported by the greater weight of the record evidence.† Without this credit, termination of the fixed monthly Levy Project NCRC charge by mid-year 2015 would be inconsistent with the requirements of the 2013 Settlement Agreement.† Therefore, staff recommends that the Commission take no action on this Issue.

 


Issue 5: 

 What restrictions, if any, should the Commission place at this time on DEF's attempts to dispose of Long Lead Equipment?

Recommendation

 Staff recommends that the Commission place no additional restrictions at this time on DEFís attempts to dispose of Long Lead Equipment.† (Laux, Lewis, Lawson)

Position of the Parties

DEF

 None. First, as a factual matter, DEF stipulates that DEFís disposition of the Levy Long Lead Equipment (LLE) is separate and independent from DEFís pursuit of the Levy COL. DEF, accordingly, will disposition the LLE without regard to the status of the Levy COL. DEF will disposition the LLE based solely on the reasonable and prudent decisions with respect to the LLE. In no way, will these decisions depend on DEFís decisions with respect to the COL. DEF will continue to pursue the Levy COL consistent with the requirements in the 2013 Settlement Agreement.

Second, as a legal matter, this proposed issue appears to suggest that the Commission can issue some sort of prospective injunctive action against DEF to restrain DEF from actions that it may or may not take in the future.† Pursuant to the NCRC statute and rule, the Commission is empowered to review DEFís actual activities and costs to determine if DEFís LNP costs were prudently incurred; however, the Commission has no authority to prospectively enjoin DEF from some unknown, speculative future action, nor does the Commission have continuing jurisdiction in this docket related to DEFís pursuit of the COL post-2013 based on the 2013 Settlement Agreement, which removed post-2013 COL costs from the NCRC. Accordingly, the Commission should take no action in the 2014 NCRC on this issue.

JOINT INTERVENORS: 

 (OPC, FRF, FIPUG, and PCS Phosphate) The Commission should require Duke to take the necessary time and expend all necessary effort to cost-effectively dispose of LLE for the maximum benefit of customers.† As part of implementing this requirement, the Commission should adopt a rebuttable presumption that any disposition of LNP LLE to WEC should reflect the original cost of those items charged to Duke consumers.† Additionally, Duke should not compromise the value of LLE assets for the benefit of Dukeís shareholders.

SACE

 No position.

Staff Analysis

 This issue addresses whether the Commission should consider placing conditions on or otherwise restricting actions DEF may take concerning the disposition of Long Lead Equipment (LLE) items.

PARTIESí ARGUMENTS

DEF

In its post-hearing brief DEF argued that no evidence was presented at hearing regarding any restrictions on DEFís LLE disposition decisions. It is therefore, in DEFís opinion, impossible for them to respond to what ďrestrictionsĒ the Joint Intervenors may or may not propose for the Commission to impose on DEFís disposition of Levy LLE.† In addition, DEF argued that the Commission cannot fairly consider any proposed restrictions that DEF has not been provided notice of and given the opportunity to fairly respond to any such proposed restrictions. Given this, DEF stated that the Commission should take no action at all on this issue. (DEF BR 16)

DEF further stated that, as a matter of law, the Commission should decline to address any proposed prospective restrictions on DEFís LLE disposition decisions because the Commission does not have the power to issue injunctive relief.† DEF argues that injunctive relief is a judicial power, not a Commission power. (DEF BR 16-17)† Given this lack of authority, DEF concluded that the Commission should take no action on this issue at this time. (DEF BR 16-17)

JOINT INTERVENORS

In its brief, the Joint Intervenors argued the Commission should impose conditions on the disposal of the LLE assets to safeguard the value of these assets for the benefit of DEFís consumers. (JI BR 2-3, 13-15)† The Joint Intervenors stated:

Duke, however, is contractually obligated under the EPC to work with WEC to dispose of LLE.† Duke also needs WECís intellectual property rights to achieve the Combined Construction and Operating License (ĎCOLĒ) which is the responsibility of Duke shareholders pursuant to the terms of the RRSSA.† Consequently, Duke and WEC are embroiled in litigation in federal court over the termination of the Levy EPC while simultaneously pursuing other ongoing, mutually beneficial commercial interests unrelated to the NCRC or the interests of Florida customers . . .†

(JI BR 3)† Given this view of events, the Joint Intervenors concluded that ďDuke shareholder and Florida consumer interests are not aligned at all, which is why affirmative action by the Commission is required.Ē (JI BR 3)† The Joint Intervenors proposed that to protect DEF consumersí interests, the Commission should take affirmative action by adopting a rebuttable presumption that any disposition of LLE equipment to WEC should reflect the original cost of those items charged to DEFís consumers.† In addition, they proposed that the Commission should require DEF to seek and obtain advance Commission approval for any final action to dispose of any and all remaining LLE items. (JI BR 3, 14-15, 17-18).

ANALYSIS

††††††††††† Staff observes that while the Joint Intervenors appear to vigorously argue this issue in post-hearing brief, no direct evidence or witness was presented concerning their proposed conditions and restrictions. Since the actual Joint Intervenorsí proposal on this issue was first presented in their post-hearing brief, DEF has not had an opportunity to respond specifically to the proposal.† With respect to the LLE assets, staff also notes that pursuant to paragraph 12.c. of the 2013 Settlement Agreement, DEF is under the obligation to use reasonable and prudent efforts to sell or otherwise salvage these assets, or otherwise refund any costs that can be captured for the benefit of customers. (TR 537, 541, 559-560)†††

DEF raises two arguments that bear some further discussion: it contends that it has not been given adequate due process to address the specific recommendations made in the Joint Intervenorsí post-hearing brief, and that the action they recommend is tantamount to injunctive relief, which the Commission does not have the authority to issue.

Due process consists of two fundamental elements: notice and the opportunity to be heard.† All parties to the proceeding were on notice that this issue asked what restrictions, if any, should be placed at this time on DEFís attempts to dispose of long lead equipment.† All parties were given the opportunity to present evidence on this issue at the hearing.† However, the Joint Intervenors presented no testimony or evidence at the hearing in support of the specific position ultimately presented in their post-hearing brief.† Furthermore, in their brief, the Joint Intervenors cite no rule, statute, or orders of the Commission or any court in support of the restrictions they recommend.† The record is therefore bereft of any evidentiary or precedential basis that supports the position urged by the Joint Intervenors.

DEF also contends that the Joint Intervenorsí proposals amount to injunctive relief, which the Commission does not have authority to issue.† DEF correctly points out that injunctive relief is reserved to the courts, and that pursuant to Rule 25-22.030, F.A.C., the Commission may seek injunctive relief in circuit court for violations of Commission rules and orders.† Traditionally, the Commission regulates by examining the prudence of utilitiesí management, financial, and operational activities prior to allowing cost recovery for those actions.† It is in a utilityís best interest to manage itself in a prudent manner and with consideration for its customersí interests; the failure to do so can result in the disallowance of cost recovery by the Commission.† Indeed, this docket operates on the premise that prudent costs are eligible for recovery under the statute, and that prudently incurred costs will not be subject to disallowance.[13]††† Speculation and hindsight review are not consistent with the prudence standard recognized by the Commission, and has been rejected as a basis for finding imprudence.[14]† Staff further notes that Commission practice dictates that prudence determinations are only revisited upon a showing of fraud, perjury, or intentional withholding of key information.[15]

The Joint Intevenors request that the Commission take pains to express to DEF that it is expected to aggressively pursue the sale of the LLE for the benefit of its customers.† Staff shares the concern that DEF secure the best deal possible for its customers, and believes DEF has obligated itself to do so through the 2013 Settlement Agreement.† However, staff also believes that the Joint Intervenors have provided no support for the particular relief they recommend, requiring prior notification and approval regarding the disposition of the LLE and imposition of a rebuttal presumption requiring original cost.

††††††††††† In reviewing the record, staff is not convinced that the Joint Intervenors identified any unfulfilled regulatory need regarding possible future DEF actions that would require immediate Commission attention.† As stated in DEFís brief:†

The Commission does have the authority to review and determine if DEFís LLE costs as a result of DEFís LNP LLE disposition decisions are reasonable and prudent.† DEF in fact has presented costs related to several LLE disposition decisions in this Docket and no party has disputed DEFís evidence that these costs were prudently incurred and these LLE disposition decisions were reasonable.

(DEF BR 17)

Staff agrees with DEF in that the Commission has the authority to review and determine if DEFís actual disposition decisions are reasonable and prudent.† Given the Commissionís review processes, pursuant to Rule 25-6.0423 F.A.C., customers are provided protections against unreasonable or imprudent actions DEF may take or any other inappropriate cost recovery request that DEF may file in the future.† Staff further believes that proposing specific actions only through a partyís post-hearing brief does not allow sufficient vetting of a proposal to assess all reasonable ramifications that approval of such actions may have.† Absent a complete review of the Joint Intervenor proposed action by all parties, staff believes the obligations found within paragraphs 11 and 12 of the 2013 Settlement Agreement provide DEF adequate guidance concerning the disposition of the assets in question.† Staff recommends that in the absence of any real, non-speculative showing of need, the Commission should not place any additional restrictions on DEFís attempts to dispose of LLE than those already included in the 2013 Settlement Agreement.

CONCLUSION

††††††††††† Based on staffís review of the record in this proceeding, staff recommends that the Commission place no additional restrictions at this time on DEFís attempts to dispose of Levy Long Lead Equipment.

 


Issue 9: 

 What is the total jurisdictional amount to be included in establishing DEF's 2015 Capacity Cost Recovery Clause Factor?

Recommendation

Staff recommends the Commission should approve as DEFís 2015 NCRC cost recovery an amount consistent with the rates approved in the 2013 Settlement Agreement for the Levy project and $63,204,163 for the EPU project. The total amount for use in establishing DEFís 2015 Capacity Cost Recovery Clause factor should be $167,195,304. †(Laux, Lewis)

Position of the Parties

DEF

 The total jurisdictional amount to be included in establishing DEFís 2015 Capacity Cost Recovery Clause factor should be $167,195,304 (before revenue tax multiplier). This consists of $63,204,163 for the EPU project and an estimated amount of $103,991,141 for the LNP.

For the LNP, the final amount necessary to achieve the rates included in Exhibit A ($3.45/1,000kWh on the residential bill) of the Settlement Agreement approved in Order No. PSC-13-0598-FOF-EI page 176 should be included in establishing DEFís 2015 CCRC revenue requirements.

JOINT INTERVENORS

 (OPC, FRF, FIPUG and PCS Phosphate) The Commission should approve the amounts resulting from the Revised and Restated Stipulation and Settlement Agreement (RRSSA). For the LNP project, the customer impact is fixed at the $3.45/month residential impact (with corresponding customer impacts as shown in Exhibit 5 to the RRSSA) and order the mid-year 2015 cessation of the LNP NCRC charge.† This includes the requirement that the charge cease once LNP costs have been recovered, subject to any allowable true-up.† [The CR3 portion of the position statement remains as stated in the Prehearing Order by the individual parties].

SACE

 No position.

Staff Analysis

 This issue addresses the amount the Commission should establish as DEFís 2015 NCRC cost recovery amount to be collected through the 2015 Capacity Cost Recovery Clause factor.†† With the exception of Issue 4, all cost related issues were either stipulated or not disputed by the parties.† If the Commission denies staffís recommendation and agrees with the Joint Intervenorsí position on Issue 4, the Joint Intervenors stated that DEF will, during 2015, fully recover its LNP cost. ††Therefore the Joint Intervenors argued that DEF should be required to file updated schedules and tariffs for staff verification showing the resulting date of termination of the fixed LNP charge.

PARTIESí ARGUMENTS

DEF argued that the Commission should grant DEF recovery of its prudently incurred actual costs and its reasonably estimated costs for the Levy and EPU Projects, since the evidence DEF presented to the Commission on these issues was uncontested by the parties at hearing. (DEF BR 1)†† For the EPU Project, DEF requests that $63,204,163 be authorized for collection as part of DEFís 2015 NCRC cost recovery. (DEF BR 19)† For the Levy Project, DEF stated the Commission should approve an amount that reflects the fixed monthly rates for the different rate classes (for example $3.45 per 1,000 kWh for the residential class) as contained within the 2013 Settlement Agreement. (DEF BR 20)† The estimated total NCRC recovery amount for inclusion in the 2015 Capacity Cost Recovery Clause factor is $167,195,304. (DEF BR 19)†

The Joint Intervenors did not contest DEFís requested cost recovery levels for both the Levy and EPU Projects.† However, the Joint Intervenors argued that given their position on Issue 4, DEF will at sometime during 2015 fully recover its LNP cost. Therefore, the Joint Intervenors argued that DEF should be required to file updated schedules and tariffs sheets for staff verification reflecting the resulting date of termination of the fixed LNP charge. (JI BR 15-17)

ANALYSIS

Staff does not believe that the resolution of Issue 4 will affect the establishment of the 2015 NCRC cost recovery amount.† At best the resolution of Issue 4, as requested by the Joint Intervenors, will only affect how long the approved NCRC cost recovery factor will remain in effect during 2015. Staff notes that the 2013 Settlement Agreement requires the use or application of specified fixed factors per rate class until the final true-up event.[16]† Staff further notes that all issues affecting the level of the 2015 recovery amount were uncontested or included as part of the approved Category II stipulated issues for DEF.

Summary of DEFís 2015 Recovery Amount

††††††††††† Staff notes all cost recovery related items concerning the EPU Project were stipulated.† As presented by DEFís witness Foster, the requested 2015 EPU cost recovery amount is $63,204,163. (EXH 6, p.3)† Regarding the LNP recovery amount, witness Foster explained that DEF is required under the 2013 Settlement Agreement to charge customers a fixed monthly rate per 1,000 kWh according to the customer class factors found within this Settlement.† By applying these factors to a forecast of 2015 sales, witness Foster estimated that $103,991,141 will be collected. (TR 418; EXH 5, p.3)† As noted, with the exception of the Joint Intervenorsí position on Issue 4, no parties opposed DEFís requested cost recovery amounts and no adjustments have been identified.

CONCLUSION

††††††††††† † Given staffís recommendation on Issue 4, evidence presented at hearing and the approval of DEF Category II stipulated issues, staff recommends the Commission should approve as DEFís 2015 NCRC cost recovery an amount consistent with the rates approved in the 2013 Settlement Agreement for the Levy project and $63,204,163 for the EPU project. The total amount for use in establishing DEFís 2015 Capacity Cost Recovery Clause factor should be $167,195,304.†

 


FPL Issues

Issue 10: 

 Should the Commission approve what FPL has submitted as its 2014 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?

Recommendation

 Yes. The evidence presented by 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 believes completion of the TP Project appears feasible at this time.† Staff recommends that the Commission should accept FPLís 2014 detailed analysis of the long-term feasibility of completing the Turkey Point Units 6 & 7 project.† (Garl, Higgins)

Position of the Parties

FPL

 Yes.† FPL used number of combinations of fuel and environmental compliance costs to serve as possible future scenarios with 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.† FPL evaluated seven future scenarios of fuel costs and environmental compliance costs assuming a conservative 40-year life of Turkey Point 6 & 7, as well as seven scenarios assuming a 60-year life of Turkey Point 6 & 7.† The breakeven capital costs are higher than FPLís non-binding cost estimate range (i.e., the results are favorable) in seven of the 14 fuel and environmental compliance cost scenarios analyzed.† In six of the remaining seven scenarios, the breakeven capital costs are within the non-binding cost estimate range.†† Based on this analysis, completion of Turkey Point 6 & 7 is projected to be solidly cost-effective for FPLís customers.† The results of the analysis fully support the feasibility of continuing the Turkey Point 6 & 7 project.

OPC

 In this hearing cycle, as in the past, FPL appears to have appropriately limited its expenditures on planned nuclear units Turkey Point 6&7 to those activities necessary to process its Combined Operating License Application (COLA). For that reason, OPC will not oppose the Turkey Point 6&7 -related amounts for which FPL seeks recovery in this proceeding.

However, based on FPL's own cost projections, the message of FPL's 2014 feasibility study is that the economic feasibility of Turkey Point 6&7 is dubious at the present time. As Dr. Sim acknowledges in his Exhibit SRS-1, of the seven comparisons between Turkey Point 6&7 and FPL' s alternative performed with a 40-year horizon, only two scenarios show the nuclear units as being cost-effective for customers. The results of FPL's studies improve when it employs a 60-year horizon, but this exercise requires FPL to project even farther into the future and, therefore, involves greater uncertainty regarding the future costs of fuel, materials, and labor; regulatory developments; customer demand; and other unknowns. Even when the 60-year analyses are taken into account, on an overall basis only half of the scenarios FPL studied are predicted to be cost-effective to customers.

In testimony and exhibits, FPL isolates the fuel savings portions from the comparisons of alternatives, uses "nominal" cumulative fuel savings values (that are not expressed in net present value), and presents them separately, as though fuel benefits are independent of the massive capital costs that must be incurred to achieve them. However, focusing on an individual component of the project's cost/benefit equation does not displace the importance of overall cost-effectiveness or change the outcome of FPL's studies.

The equivocal nature of FPL's 2014 feasibility study, the project's poorer showing relative to a year ago, and announcements of delays and projected cost increases elsewhere in the nuclear industry hardly instill confidence in FPL's enormously expensive nuclear undertaking. Fortunately, in addition to the annual updates required by Commission rule, the Legislature's 2013 amendment to the nuclear advance cost recovery statute now requires a utility to demonstrate economic feasibility anew when it seeks authority to incur post-COL preconstruction expenditures, and again when it seeks authority to begin construction. If it accepts FPL's less-than-compelling 2014 feasibility study for Turkey Point 6&7, the Commission should emphasize to FPL and its customers that it will use the additional milestones specified by the statute to protect customers in the event that future analyses based on better information fail to demonstrate that the project is economic.

FIPUG

 No.

SACE

 No. FPL has failed to complete and properly analyze a realistic feasibility analysis which includes the impact of demand side management and renewable energy in meeting demand and doesnít properly place those resources on a ďlevel playing fieldĒ in its analysis with supply side resources. The Commission should deny cost recovery for costs related to TP 6 & 7 and find projected 2015 costs related to TP 6 & 7 as not reasonable.

FRF

 Agree with OPC.

Staff Analysis

 In this issue staff provides the Commission with information necessary to decide whether the Commission should approve what FPL has submitted as its 2014 annual detailed analysis of the long-term feasibility of completing the Turkey Point Units 6 & 7 project, pursuant to Rule 25-6.0423, F.A.C.

PARTIESí ARGUMENTS

Pursuant to the Commission-approved procedural motion, the parties waived witness cross-examination and post-hearing briefs. (TR 10-12)† The parties, therefore, did not present arguments on this Issue, only positions.

ANALYSIS

Each of the four intervening parties opposed FPLís position.† OPC, joined by FRF, based its position on its interpretation that FPLís feasibility analysis showed only two of seven scenarios being cost-effective for a 40-year horizon and only half of the scenarios being cost-effective for a 60-year horizon.† OPC characterized the TP Projectís overall cost-effectiveness as ďdubiousĒ and ďequivocal,Ē and observed that the projectís cost-effectiveness has a poorer showing than a year ago.† OPC also critiqued the FPL analysis for use of nominal fuel savings comparisons of alternatives and presenting them separately, as though fuel benefits are independent of the massive capital costs that must be incurred to achieve them.† However, OPC offered no alternative analysis or evidence to support a remedy for the alleged faults.††

FIPUG took the position, ďNo.Ē †However in Issue 10A, FIPUG took the position that FPLís estimated cost was too low and the actual cost will exceed the estimated cost.† Likewise in Issue 10B, FIPUG took the position that the commercial operation dates will be later than FPLís estimate. However, FIPUG offered no alternative analysis or evidence to support a remedy for these alleged faults.††

SACEís position was that FPLís feasibility analysis is incomplete, improper, and unrealistic because it did not treat demand-side management and renewables the same as supply-side resources.† SACE concluded that the Commission should not approve FPLís analysis of the long-term feasibility of completing the TP Project and cost recovery should be denied.† However, SACE offered no alternative analysis or evidence to support a remedy for these alleged faults.

Staff further addresses the positions of OPC and SACE in related portions of staffís analysis below.

Required Elements

In 2006, the Florida Legislature enacted Section 366.93, F.S.† 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 statute states, ďSuch mechanisms shall be designed to promote utility investment in nuclear or integrated gasification combined cycle power plants . . .Ē† The Commission adopted Rule 25-6.0423, F.A.C., to satisfy the requirements of Section 366.93(2), F.S.† As amended on January 29, 2014, Rule 25-6.0423(6)(c)(5), F.A.C., states:

Along with the filings required by this paragraph, each year a utility shall submit for Commission review and approval a detailed analysis of the long-term feasibility of completing the power plant. Such analysis shall include evidence that the utility intends to construct the nuclear or integrated gasification combined cycle power plant by showing that it has committed sufficient, meaningful, and available resources to enable the project to be completed and that its intent is realistic and practical.

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(6)(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.[17]

Staff believes FPL satisfied the requirements of Order No. PSC-08-0237-FOF-EI and Rule 25-6.0423, F.A.C., through various means. (EXH 77; EXH 78; EXH 81; EXH 83; EXH 84; EXH 89; EXH 90; EXH 91)

FPLís 2014 analysis of the long term feasibility of completing the TP Project remained consistent with the methodology it used in the 2007-2008 need determination proceeding and each subsequent NCRC proceeding.[18]† 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 was a new highly fuel-efficient natural gas-fired combined cycle generating unit similar to 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 fuel diversity, energy security and zero greenhouse gas emissions. (TR 83)† Staff examined each of these factors, as well as regulatory considerations, technical considerations, funding potential, joint ownership, reliability, renewable generation sources, and conservation to determine the acceptability of FPLís analysis of the long-term feasibility of completing the project.

Staff believes that the forecasts, cost estimates, and cost-effectiveness analyses are necessary filing requirements to review and assess FPL's 2014 analysis of the feasibility of completing the TP Project.† In addition, staff reviewed regulatory and technical aspects of the project, including evidence of FPLís intent to construct the new power plants, as required by Rule 25-6.0423(6)(c)(5), F.A.C.† These elements provide a holistic perspective for staff's recommendation regarding the acceptability of FPL's detailed long-term feasibility analysis.

Economic Analysis

Updated Fuel Forecast

FPL developed its updated fuel price forecasts from the same industry-accepted sources that it has used since the need determination proceeding.† The Company used a blended value of the natural gas pricing data from the October 7, 2013, Henry Hub natural gas commodity prices and the most current projections from The PIRA Energy Group (formerly Petroleum Industry Research Associates, currently an energy information provider specializing in global energy markets research, analysis, and intelligence).† The projections were for the period 2014 through 2030.† Beyond 2030, FPL used the real rate of escalation from the Energy Information Administration.† In addition, nominal price forecasts were prepared for transportation costs.† The projected transportation costs were added to commodity cost projections to arrive at the delivered price forecasts. (EXH 89, Bates No. 19)†

FPLís fuel price forecasting methodology provided a high, medium, and low cost projection.† While future fuel prices are inherently uncertain, the range FPL developed offers a plausible expectation that actual prices will fall somewhere within the range.† None of the intervenors contested FPLís updated fuel price forecasts.† Staff believes it is reasonable to accept FPLís updated fuel price data in this proceeding.†

Figure 10-1 depicts the price forecasts for the medium range of natural gas used from the 2009 NCRC proceeding through this yearís filing to support FPLís feasibility analysis.† Staff notes that natural gas price forecasts have trended slightly downward each year.† In addition, last yearís and this yearís forecasts show a greater increase in later years.†

Figure 10-1:† Forecasted Delivered Natural Gas Prices Ė Medium Fuel Forecast ($/MMBTU, $Nominal)

(Order No. PSC-13-0493-FOF-EI, p. 13; EXH 77)

Updated Environmental Forecast

Florida Statutes require the Commission to consider air emission compliance costs in evaluating new nuclear or integrated gasification combined cycle electrical generation.[19]† The absence of greenhouse gas emissions continued to be a benefit associated with nuclear generation.† Every increase in projected environmental compliance costs for emitting sulfur dioxide (SO2), nitrous oxide (NOx), and carbon dioxide (CO2) had the effect of making a nuclear plant more cost-effective as compared to fossil-fueled generation, such as natural gas, coal, and oil.

The updated forecasts FPL submitted were developed by consultant ICF International, the same industry-accepted source FPL has used since the need determination proceeding.† ICFís view was that nothing occurred on the legislative or regulatory fronts which would prompt a change from its projections made last year. (TR 259)† Table 10-1 below depicts the price forecasts for the medium range of environmental costs used from the 2009 NCRC proceeding through this yearís filing to support FPLís feasibility analysis.†

Table 10-1:† Forecasted Environmental Compliance Costs ($Nominal)

(Order PSC-13-0493-FOF-EI, p. 14-15; EXH 78)

In the 2011 NCRC proceeding, witness Sim explained the dramatic drop in emission compliance costs between 2010 and 2011.† The cost reductions were due to a projection that utilities would add control devices for these emissions in response to Environmental Protection Agency rules.† This, in turn, produces more emission allowances on the market in future years, thereby reducing the value of the allowances.[20]

None of the intervenors contested the credibility or accuracy of FPLís updated environmental cost forecasts.† Staff reviewed FPLís filings and observes the updated estimates are consistent with prior estimates.† Staff believes it is reasonable to accept FPLís environmental cost projections for the purposes of the feasibility study.

Updated Project Cost Estimate

FPLís all-inclusive in-service projected cost estimate range for the TP Project was $12.6 billion to $18.4 billion. (TR 78-79)† This estimated range included carrying costs of approximately $5.0 billion[21] and sunk costs of approximately $228 million. (EXH 81)† FPLís 2014 non-binding overnight capital cost estimate range was $3,750/kW to $5,453/kW. This represented a 20.1 percent increase from FPLís estimated maximum cost in the 2007 need determination proceeding and a 20.7 percent increase in the minimum cost.† The history of cost range estimates is shown in the figure below.

Figure 10-2: Range of Non-Binding Overnight Capital Cost Estimates ($/kW)

(Order No. PSC-13-0493-FOF-EI, p. 16; TR 78)

FPL witness Scroggs explained the necessity and rationale of estimating a cost range at the current stage of the project:†

The primary factors affecting the total project cost will be the actual labor and materials costs experienced during the Preparation and Construction periods.† The certainty around these costs will increase as preceding projects move through the early stages of construction and as FPL negotiates the principal contracts for engineering, procurement, and construction of the project. The pace of expenditures is also a critical factor that will impact total project costs.† Escalation of future costs and carrying costs on expended funds are time related factors.

(TR 81)

FPL used its updated project cost estimate in conducting its cost-effectiveness analysis below.† Staff believes FPLís 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 remained cost-effective.†

Project Cost-Effectiveness

FPL conducted its cost-effectiveness analysis using its updated fuel and environmental compliance costs, projected in-service dates of 2022-2023, and an overnight capital cost ranging from $3,750/kW to $5,453/kW.† Staff notes that all intervenors took a position doubting the estimated cost and in-service dates. †However, no evidence exists in the record to suggest the FPL estimates are erroneous.†

FPL asserted its project schedule showed 2022-2023 were the "earliest practicable" in-service dates, fully acknowledging that future events could impact the project schedule. (TR 31)† Furthermore, as witness Sim testified, ďAs long as a consistent set of assumptions, including in-service dates, is used to compare the competing resource options, the feasibility analysis will provide meaningful results.Ē (TR 265)† Staff believes FPLís response to a staff interrogatory demonstrated that delays of 5 or 10 years to the in-service dates would not alter the ultimate cost-effectiveness conclusion or render the Companyís analysis deficient. (EXH 89, Bates No. 52)†

FPLís cost-effectiveness analysis of the TP Project once again relied on the same breakeven analysis it has used since the need determination. The breakeven methodology first required a calculation of the cumulative present value of revenue requirements (CPVRR) for each of the alternative resource plans: (1) the plan with new nuclear units and (2) the plan with combined cycle units as a replacement for the nuclear units (Columns 3 and 4 in Table 10-2 below).† For the resource plan with the TP Project, a capital cost of zero was assumed as a basis.† Next the CPVRR cost differentials between the resource plans for each scenario were calculated (Column 5 in Table 10-2 below).† The next step was to set the capital cost for the TP Project equal to $1/kW.† The CPVRR of the TP Project was then calculated in 2014 dollars. The result, $2,536 million, was then divided into the cost differentials for each scenario. †(EXH 89, Bates No. 26)† Upon incrementing the capital cost from zero to $1/kW, the resulting value was a breakeven cost in terms of $/kW of capital cost for each scenario (Column 6 in Table 10-2 below). This calculation provided an estimate of the highest capital costs at which nuclear generation would still be cost-effective compared to the combined cycle alternative over the life of the project.[22]

FPL performed its analysis with a wide range of scenarios which combined varying fuel cost 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.† †A total of seven different fuel/environmenta1 cost scenarios were analyzed for each alternative resource plan.† The projected present value savings over the study period for each scenario were then used to calculate a breakeven capital cost estimate.† The breakeven capital cost estimate was 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 $3,750/kW to $5,453/kW to determine the likelihood of the nuclear project producing a net savings over the study period. (TR 267)† If the breakeven values were higher than the current capital cost-estimates, the nuclear plants would provide net savings over the life of the units compared to alterative base load units.† Staff believes FPLís approach in performing its breakeven analysis remained reasonable.†

A new addition to FPLís 2014 analysis was a consideration of the TP Project having an operating life of 60 years.† Previous analyses assumed an operating life of 40 years. †FPL witness Sim observed that ďFPL's Turkey Point Units 3 and 4 and St. Lucie 1 and 2 units have successfully extended the original license terms by 20 years. Therefore, it is reasonable to assume that a 20 year extension would be attainable for the Turkey Point Unit 6 & 7 project.Ē (TR 83)† FPL, therefore, presented a breakeven analysis for both a 40-year operating life, referred to as Case No.1, and a 60-year operating life, referred to as Case No. 2. (EXH 83, EXH 84)

The results of FPLís 40-year breakeven analysis, shown in Table 10-2 below, demonstrated that the TP Project is projected to remain cost-effective compared to the alternative combined cycle unit.† The results in two of the seven scenarios illustrated that the breakeven nuclear capital costs are above FPLís estimated range of costs. †This demonstrates a high likelihood of cost-effectiveness if fuel and environmental compliance costs remain high.† Conversely, the low fuel/low environmental cost scenario breakeven nuclear capital cost, $3,683/kW (greyed background), was below FPLís estimated cost range of $3,750/kW to $5,453/kW.† This indicates a possibility of the nuclear project not being cost-effective if the capital costs approach the middle to upper limit of the estimated cost range and long-term fuel and environmental costs remain low for the duration of the analysis period.† The remaining scenarios (bold print) showed the breakeven costs within the estimated range of costs.† These results indicate that the TP Project may or may not be cost-effective compared to the alternate resource plan without the TP Project at the fuel and environmental cost levels indicated.

††††††††† Table 10-2:† 2014 Breakeven Analyses Results for the TP Project:

Note:† The Column† 6 figures in bold are within the estimated cost range.

†(EXH 83)

Staff notes that FPLís 40-year breakeven analysis for 2014 compared to the 2013 analysis, shown in Table 10-3 below, demonstrated that the magnitude and range of the breakeven nuclear capital costs have decreased.† The low breakeven cost decreased 12.7 percent, and the high breakeven cost decreased 10.2 percent.† The range of the 2014 breakeven costs fell 5.9 percent from the 2013 breakeven cost range.† However, the 2014 analysis showed the project was cost-effective by having breakeven values above the cost estimate range in two of the seven scenarios, while† the 2013 analysis showed five scenarios as clearly cost-effective.†

††††††††† Table 10-3:† 2013 Breakeven Analyses Results for the TP Project

Note:† The Column† 6 figures in bold are within the estimated cost range.

(Order No. PSC-13-0493-FOF-EI, p. 19)

The results of the 60-year breakeven analysis, Case No. 2 shown in Table 10-4 below, demonstrate that the TP Project was projected to be cost-effective compared to the alternative combined cycle units.† The results in five of the seven scenarios illustrated that breakeven nuclear capital costs were above FPLís estimated range of costs, which demonstrate a high likelihood of cost-effectiveness across the full range of environmental compliance costs when fuel costs are in the medium to high ranges.† Conversely, the low fuel/low environmental cost and medium fuel/low environmental cost scenarios breakeven nuclear capital costs, $4,460/kW and $5,385/kW respectively (bold print), were within FPLís estimated range of costs, $3,750/kW to $5,453/kW.† This result indicated that the TP Project may or may not be cost-effective compared to the alternate resource plan without the TP Project if the fuel and environmental costs remain in the indicated ranges for the duration of the analysis period.†

†††††††† †Table 10-4:† 2014 Breakeven Analyses Results for the TP Project:

Note:† The Column† 6 figures in bold are within the estimated cost range.

†(EXH 84)

Staff believed it was necessary to have a comparison to the Case No. 2, 60-year operating life 2014 analysis.† In response to a discovery request, FPL provided a breakeven analysis using the same data used in the 2013 analysis, but for a 60-year operating life. (EXH 90, Bates No. 65) †Responding to another discovery request, FPL provided projected breakeven cost values that assumed the project was delayed 5 and 10 years for both the 40- and 60-year operating life. (EXH 89, Bates No. 52) †FPL did not project estimated capital cost ranges for the delayed periods.

Figure 10-3 below displays the migration of FPLís estimated breakeven costs and the estimated project costs for each year since its 2008 need determination. The figure also displays information provided through discovery for a 2013 analysis with a 60-year operating life and in-service delays of both 5 and 10 years.† If the estimated capital cost range increased into the range of the breakeven costs, the project becomes less cost-effective.† In 2013, the upper limit of breakeven costs was 25 percent greater and the lower limit was 21 percent below the highest estimated capital cost.† In 2014, the upper limit of breakeven capital costs for Case No. 1 was 9.3 percent greater and the lower limit was 32.5 percent below the highest estimated capital cost. This indicated that the magnitude and range of breakeven costs have decreased since 2013.† The lowest 2014 breakeven cost being below the range of the estimated costs suggest that the project may not be cost-effective if long-term fuel and environmental costs remain low.† Witness Sim explained in his testimony that:†

[T]he combination of assumptions included in this scenario are: (i) low natural gas costs each year through the year 2063; (ii) low environmental compliance costs each year through the year 2063; and (iii) the lower of the two operating life assumptions (40 years).

(TR 268)

Figure 10-3:† 2008 Ė 2014 Breakeven and Estimated Capital Cost Range Comparison

* The 2008 and 2009 capital cost estimate range values are reflected in 2007 dollars

 

(EXH 91, Bates No. 67)

Staff notes that 2014 is the first year the lowest breakeven cost has been below the range of estimated costs when considering a 40-year operating life of the project.† Witness Simís contended that:

Also, as evidenced by the CPVRR values for this single scenario, compared to the CPVRR values for all other scenarios, FPL' s customers would still benefit greatly if these assumed low costs for natural gas and/or environmental compliance were to materialize.

(TR 268)† However, staff does not support abandoning the project on the basis of a single scenario because doing so would ignore the potential for fuel and environmental costs to increase, as well as the qualitative advantages of the TP Project, such as fuel diversity, discussed further below.

Staff notes OPCís concern, expressed in its position, that breakeven values within the estimated capital cost range demonstrate the TP Project would not be cost-effective. †However as with the discussion of fuel price forecasts above, the cost of a project with such complexity and magnitude as the TP Project also is inherently uncertain.† The methodology FPL used in comparing the range of estimated costs with a range of breakeven costs offers a plausible expectation that the actual cost will fall somewhere within the ranges being compared.†††

Staff believes that FPL clearly considered projected costs of natural gas and emissions in its feasibility analysis, as evidenced by the decline in cost-effectiveness.† Nonetheless, the TP Project remains cost-effective at this time.† Staff recommends that the Commission should accept FPLís cost-effectiveness analysis.

Fuel Diversity, Reliability, Renewables, and Conservation

Section 403.519, F.S., requires the Commission to consider fuel diversity when determining the need for new power plants, nuclear or otherwise.† Although the need determination proceeding for the TP Project was completed in 2008, fuel diversity remains a priority of the Legislature.†† As FPL witness Sim stated, ďDiversification also improves system reliability.Ē (TR 249)†† The TP Project, therefore, remained a means of reducing a possible over-reliance on one fuel (natural gas) for power generation.† Witness Sim also testified that due to the possibility of new environmental regulations, coal was currently unfavorable in future generation planning, thus reducing options for other than natural gas fired generation.† (TR 272)

The two resource plans used by the Company for its 2014 feasibility analysis of the TP Project were identical through 2021, but began to differ in 2022. (EXH 82)† The first resource plan identified the TP Project for meeting the Companyís future generation needs from 2022 through 2024, and the other plan identified two natural gas-fired combined cycle plants as the generating resource.† In 2024, the year when either of the two resource plans would be implemented, the fuel mix percentage between nuclear and natural gas generation if the utility meets its need with two additional combined cycle plants was 21 percent and 72 percent respectively.† However, if the need was met with nuclear generation, the fuel mix will be approximately 35 percent nuclear and 58 percent natural gas, or approximately 14 percent less reliance on natural gas generation.† (TR 270 Ė 271)

††††††††††† Witness Sim further testified that additional nuclear capacity is an important aspect of FPLís balanced resource portfolio approach because itís ď. . . the only resource option available that can provide baseload, firm capacity at even lower fuel costs than natural gas and which does so using no fossil fuels and producing zero air emissions.Ē (TR 251)

†††††††††††

††††††††††† With respect to renewable energy resources and energy conservation, SACE contended that FPL failed to properly analyze the impact of DSM and renewables in meeting its future demand requirement, and that the Company did not place those resources on a ďlevel playing fieldĒ with supply side resource options. (Procedural Motion, Attachment A)† Staff notes that SACE did not proffer any testimony or other evidence on this issue.†

 

FPL took the view that renewables are ďcomplementary to firm capacity resource options.Ē (EXH 89, Bates No. 27)† FPL believed that to be considered a viable potential alternative to the TP Project, a renewable resource option would need to consist of 2,200 MW of capacity, all of which must be firm. (EXH 89, Bates No. 27)† The Company stated that currently, solar and wind options were not considered firm in Florida, but did believe biomass was a possible firm capacity resource option.† However, ďFPL does not believe there is 2,000 MW of untapped biomass potential in FPLís service territory. Therefore, FPL does not consider incremental biomass to be a viable potential alternative to Turkey Point 6 & 7.Ē† (EXH 89, Bates No. 27)

 

††††††††††† Through staff discovery, FPL was asked what efforts it had made in terms of identifying additional conservation measures that could be adopted as an alternative to completing the TP Project.† The Company responded by detailing that both resource plans (resource plan with the TP Project, and resource plan without the TP Project) presented in its 2014 feasibility analysis assumed approximately 34 MW per year of Demand Side Management (DSM) were added through 2024. (EXH 89, Bates No. 29)† However, for DSM to be considered as an alternative to the TP project, another 1,833 MW of DSM would need to be added to its system by 2023, as this would be the approximate amount of power provided by the TP project. (EXH 89, Bates No. 29)† The Company further stated it did not believe an additional 1,833 MW of cost-effective DSM was available.† FPL referenced as evidence its recent DSM Goals proceeding[23] before the Commission where the maximum achievable potential DSM was shown to range from 526 MW to 576 MW.† For this and other reasons, FPL did not view DSM as a viable replacement alternative to the TP Project. (EXH 89, Bates No. 29)† Staff agrees.†††

 

Regulatory Considerations

Permits and Licenses

The Federal permitting of the TP Project generally focuses on health, safety, and environmental related issues.† Various formal reviews of the proposed project are conducted with the ultimate goal of obtaining a COL.† Once issued, the TP Project COL authorizes FPL to construct and operate the nuclear power plant in accordance with established laws and regulations.†

According to FPL witness Scroggs in describing efforts in 2014 and 2015 relating to regulatory and permitting matters, ďthe focus will remain on completing the state site certification process and obtaining the federal licenses and permits necessary to construct and operate the Turkey Point 6 & 7 project.Ē (TR 73)† However, the witness also stated that:

Delays in the regulatory review process have been accommodated, but will impact the licensing timeline and, ultimately the projected commercial operation dates (CODs) of 2022 for unit 6 and 2023 for Unit 7. An updated schedule will be developed following receipt of a revised NRC COLA review schedule, which is the critical path for project completion.† Absent a revised NRC COLA review schedule, a project schedule including revised in-service dates would be of marginal planning value.

(TR 53Ė54)† Witness Scroggs testified that a schedule for completing review of the Companyís COL application will be issued by the NRC in 2014. (TR 67)†

Concerning the environmental review of the TP Project, the NRC was in the process of formulating its Environmental Impact Statement of the TP Project.† The results of the review focuses on examining the possible environmental impacts that could occur as a result of licensing the plant site.† Further, the EIS is relied upon by the U.S. Army Corps of Engineers in its review of wetland permitting, which is a separate and distinct step in the TP Project licensing process. (TR 75 Ė 76)††††

Concerning regulatory matters addressed by the State of Florida, Witness Scroggs testified that the Company expected a vote on its Site Certification Application in May of 2014. (TR 76) †A power plant site certification grants approval for the location of the power plant and its associated facilities. †Associated facilities includes structures for supplying fuel to the plant, transmission lines, and roadways. †The process for certifying the site of TP Project was coordinated by the Florida Department of Environmental Protection.

Evidence of Intent

As mentioned in the introduction of this issue, the January 29, 2014, amendment to Rule 25-6.0423(6)(c)5, F.A.C., requires that FPL provide evidence of intent to construct the power plant.†† The Rule specifies that the utility show ďit has committed sufficient, meaningful, and available resources to enable the project to be completed and that its intent is realistic and practical.Ē

FPL witness Reed, Chairman and Chief Executive Officer of Concentric Energy Advisors, Inc., summarized his firmís assessment of FPLís organizational structure:

Concentric believes the organizational structure appropriately assigned responsibility to those employees best equipped to respond to the project needs and properly reflected the project's focus on the licensing and permitting stage that the project is currently in.

(TR 171)† Witness Reed concluded his firmís observation of FPLís TP Project management by stating:

[T]he Company continues to develop PTN 6 & 7 through capable project managers and directors that are guided by detailed company procedures and appropriate management oversight.

(TR 187)†

FPL witness Scroggs testified that FPL intends to complete the TP Project. The witness went on to discuss the immediate requirements of its ďcritical path to completing Turkey Point 6 & 7,Ē which includes obtaining the necessary licenses and approvals for construction and operation of the TP Project. (TR 85)† In discussion of FPL having sufficient, meaningful, and available resources dedicated to the Turkey Point 6 & 7 project, witness Scroggs stated:

Yes. As demonstrated throughout this testimony, FPL had in place an appropriate project management structure that relied on both dedicated and matrixed employees, the necessary contractors for specialized expertise, and a robust system of project controls.

(TR 26)

Staff believes that FPL has demonstrated it has an effective process in place to provide its management with an ongoing, detailed analysis of the uncertainties and risks that could impact its permitting, licensing, approval, and certifications necessary, as well as shown evidence of its intent to complete the project.† Staff recommends that the TP Project is feasible from a regulatory standpoint.

Technical Considerations

The Company is planning two Westinghouse AP-1000 nuclear reactors for the TP Project.† In his testimony, witness Scroggs† discussed other utilities AP-1000 construction projects that are already underway.† These new build projects included Plant Vogtle in Georgia, and V.C. Summer Nuclear Station in South Carolina. (TR 69)† The Vogtle and V.C. Summer projects have advanced from preparation and non-nuclear construction into safety related construction authorized by their respective COLs.† This included foundational construction work and moving major equipment and pre-fabricated modules into position. (TR 69)† Witness Scroggs stated:

In general, the status of these projects continues to demonstrate that substantial and consistent progress is being made on deploying the next generation of nuclear projects. Further, it indicates that the construction phases of these complex projects can be managed within a predictable budget and scheduling parameters.

(TR 70)††

None of the intervenors contested any technical aspects of the project.† Staff believes the evidence supports that the TP Project is technically feasible.

Funding Potential

In addition to elements of economic feasibility, staff believes availability of funding for the project should also be considered.† While financing for the TP Project has not yet been obtained, FPL witness Scroggs testified that certain efforts to finance Georgia Powerís Vogtle project have been successful. (TR 70)† Georgia Power (45.7 percent ownership interest) and Oglethorpe Power (30 percent ownership interest) have closed on approximately $6.5 billion in loan guarantees from the Department of Energy (DOE) for the Vogtle Project.† The witness went on to state, ďTerms of the guarantees have not been disclosed, however, Georgia Power has projected approximately $225 million savings, on a present value basis, to its customers on reduced interest fees provided by the loan guarantee.Ē (TR 70)† FPL witness Scroggs testified that the Company is prepared to pursue a DOE loan guarantee if it is determined to benefit its customers.† (TR 71)

Staff views FPL's current access to capital markets, and possible loan guarantees from the DOE, as confirmation of continued funding feasibility.

Joint Ownership

The Company was asked through staff discovery for a status update as to the possibility of entering into joint ownership arrangements for the TP Project since its last NCRC proceeding.† FPL stated that it considers entering into ownership agreements at this time premature as it would negatively impact the COL review process with the NRC.†

The Commissionís need determination order directed the establishment of Docket No. 080271-EI for monitoring the status of joint ownership negotiations among interested parties.† The order directed, ďFPL will report the status of such ongoing status discussions to the FPSC every quarter thereafter.Ē[24]† To this end, the Company reported it held its last meeting on June 6, 2014. Representatives from Florida Municipal Electric Association (FMEA), Florida Municipal Power Agency (FMPA), Jacksonville Electric Authority (JEA), Seminole Electric Cooperative (Seminole), City of Homestead (Homestead), Lakeland Electric (Lakeland), and Ocala Electric Cooperative (Ocala) attended the meeting for an update by FPL on potential project participation.† (EXH 89 Bates No. 25)

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

CONCLUSION

Staff believes that the feasibility of completing the TP Project analysis should be based on multiple factors, not just one set of assumptions and estimates.† For the 2014 NCRC proceeding, staff recommends the evidence presented by 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 believes completion of the TP Project appears feasible at this time.† Staff recommends that the Commission should accept FPLís 2014 detailed analysis of the long-term feasibility of completing the Turkey Point Units 6 & 7 project.

 


Issue 10A: 

 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 current total estimated all-inclusive cost (including AFUDC and sunk costs) of the proposed Turkey Point Units 6 & 7 nuclear project ranges from $12.6 billion to $18.4 billion as identified in Issue 10.† (Matthews, Garl)

Position of the Parties

FPL

 FPLís current non-binding cost estimate range for Turkey Point 6 & 7 is $3,750/kW to $5,453/kW in overnight costs.† When time-related costs such as inflation and carrying costs are included, and in-service dates of 2022 and 2023 are assumed,† the total project cost estimate ranges from $12.6 to $18.4 billion.

OPC

 No position.

FIPUG

 FPLís current estimated costs are low and the ultimate cost of the proposed Turkey Point units 6 & 7 will likely exceed the cost figure FPL projected in last yearís proceeding, which was a range from $12.7 billion to $18.5 billion, and as projected in this yearís proceeding.

SACE

 The current estimated costs are too low, and the ultimate cost of the proposed Turkey Point Units 6 & 7 will likely exceed current estimates.

FRF

 Particularly in light of the fact that FPL will not guarantee the cost of its Turkey Point 6 & 7 project, the FRF doubts that FPLís estimated maximum cost of $18.4 billion is accurate.

Staff Analysis

 This issue addresses FPLís estimated current total all-inclusive cost for the TP Project as was previously discussed in Issue 10.

PARTIESí ARGUMENTS

Pursuant to the Commission-approved procedural motion, the parties waived witness cross-examination and post-hearing briefs. (TR 10-12)† The parties, therefore, did not present arguments on this Issue, only positions.

ANALYSIS

Staff notes that no intervenor offered an alternative analysis or evidence to support a different cost estimate than what was provided by FPL.† While OPC took no position, the other three intervenors took positions doubting the accuracy of FPLís cost estimate.† FIPUGís and SACEís positions are that the estimated cost is too low and the ultimate cost will exceed the current estimates.†

Staff also notes that, in this docket, the significance and usefulness of the total project cost estimate is with respect to assessing FPLís analysis of the long-term feasibility of completing the TP Project (Issue 10), pursuant to Rule 25-6.0423(6)(c), F.A.C.† No evidence or testimony, beyond that submitted by FPL, was presented concerning this issue.† Thus, all relevant matters of Issue 10A are addressed in Issue 10.

CONCLUSION

Based on staffís review in Issue 10, staff recommends that the Commission accept FPLís current TP Project all-inclusive cost estimate which ranges from $12.6 billion to $18.4 billion.

 

 

 


Issue 10B: 

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

Recommendation

 The current estimated commercial operation date of the planned Turkey Point Units 6 & 7 nuclear facility are 2022 and 2023, respectively, as identified in Issue 10.†††† (Matthews, Garl)

Position of the Parties

FPL

 FPLís current estimated commercial operation dates for Turkey Point Units 6 & 7 are 2022 and 2023, respectively.† As stated in the May 1, 2013 testimony of Steven Scroggs, delays in the regulatory review process will impact the licensing timeline and, ultimately, the current projected commercial operation dates.† An updated project schedule will be developed following receipt of a revised NRC COLA review schedule.†

OPC

 No position.

FIPUG

 The current estimated planned commercial operation dates of the planned Turkey Point Units 6 & 7, 2022 and 2023 respectively, are overly optimistic. The actual commercial operation dates of these units will occur later in time than these projected dates, if at all.

SACE

 The current estimated planned commercial operation dates of the planned Turkey Point Units 6 & 7, 2022 and 2023 respectively, are not realistic; in-fact, the Company has contingency plans for the delay of the units. The actual commercial operation dates of these reactors will occur further in time than these projected dates, if at all.

FRF

 In light of the fact that FPLís estimated in-service dates of 2022 and 2023 are based on NRC staff estimates that the NRC would be able to make a decision on the Turkey Point COL in September 2017, the FRF believes that FPLís estimated in-service dates are overly optimistic. Even FPL acknowledges in its 2014 Ten Year Site Plan that the 2022 and 2023 are the ďearliest deployment datesĒ for these units.

Staff Analysis

 This issue addresses FPLís estimated current commercial operation dates of the Turkey Point Units 6 & 7 nuclear facility as was previously discussed in Issue 10.

PARTIESí ARGUMENTS

Pursuant to the Commission-approved procedural motion, the parties waived witness cross-examination and post-hearing briefs. (TR 10-12)† The parties, therefore, did not present arguments on this Issue, only positions.

ANALYSIS

Staff notes that no intervenor offered an alternative analysis or evidence to support different estimated commercial operation dates than what was provided by FPL.† While OPC took no position, FIPUGís SACEís and FRF took positions doubting the accuracy of FPLís estimated commercial operation dates.†

Staff also notes that, in this docket, the significance and usefulness of the project estimated commercial operation dates is with respect to assessing FPLís analysis of the long-term feasibility of completing the TP Project (Issue 10), pursuant to Rule 25-6.0423(6)(c), F.A.C.† No evidence or testimony, beyond that submitted by FPL, was presented concerning this issue.† Thus, all relevant matters of Issue 10B are addressed in Issue 10.

CONCLUSION

Based on staffís review in Issue 10, staff recommends that the Commission accept FPLís current TP Project estimated commercial operation dates of 2022 and 2023.

 

 


Issue 12: 

 What jurisdictional amounts should the Commission approve as FPL's final 2013 prudently incurred costs and final true-up amounts for the Turkey Point Units 6 & 7 project?

Recommendation

 The Commission should approve $33,045,060 as FPLís final 2013 prudently incurred costs and an over recovery of $463,650 as the final 2013 true-up amount for the Turkey Point Units 6 & 7 project.† (Breman)

Position of the Parties

FPL

 The Commission should approve FPLís final 2013 prudently incurred Turkey Point 6 & 7 Preconstruction expenditures of $28,209,654 (jurisdictional), and the final 2013 true-up amount of ($539,308).† The Commission should also approve Turkey Point 6 & 7 Preconstruction carrying charges of $4,664,921 and Site Selection carrying charges of $170,485, and the final 2013 carrying charge true-up amount of $75,659. FPLís 2013 expenditures were supported by comprehensive procedures, processes and controls that help ensure those expenditures were prudent.† The net 2013 true up amount of ($463,650) should be included in FPLís 2015 NCR amount.

OPC

 No position.

FIPUG

 No position.

SACE

 None. SACE argued in 2013 that FPL did not complete and properly analyze a realistic feasibility analysis. As such, requested cost recovery flowing from that feasibility analysis, are not prudently incurred and should be denied.

FRF

 No position.

Staff Analysis

 This issue addresses the prudence of FPLís 2013 Turkey Point Units 6 & 7 (TP Project) activities, incurred costs, and the associated final 2013 true-up amount FPL will either refund or collect during 2015.† The only party opposing FPLís position on this issue was SACE. †

PARTIESí ARGUMENTS

Pursuant to the Commission-approved procedural motion, the parties waived witness cross-examination and post-hearing briefs. (TR 10-12)† The parties, therefore, did not present arguments on this Issue, only positions.

ANALYSIS

The only party opposing FPLís position on this issue was SACE.† In its position statement, SACE maintained that FPL did not complete and properly analyze a realistic 2013 analysis of the long-term feasibility of completing the TP Project in the 2013 NCRC proceeding.† (EXH 95)† Thus, SACE concluded that FPLís 2013 recovery amount should be zero.† As noted above, both SACE and FPL waived witness cross-examination and the filing of post-hearing briefs on this issue. (TR 10-12)† Staff notes that the reasonableness of FPLís 2013 analysis was addressed by the Commission as part of the 2013 NCRC proceeding.[25]† In this proceeding, SACE did not identify any new information concerning FPLís 2013 analysis.† Additionally, SACE did not challenge the prudence of FPLís 2013 TP Project activities, oversight, management and controls in Issue 11. (EXH 95)† Consequently, staff believes SACEís stated position did not present new information concerning the reasonableness and prudence of FPLís 2013 TP Project activities and costs.

2013 TP Project Licensing and Permitting Activities and Costs

FPL witness Scroggs provided summary descriptions of the 2013 TP Project permit and license activities, associated engineering and design activities, resultant costs, and summary data on executed contracts in excess of $250,000. (TR 16-32, 46-49; EXH 34; EXH 39)† The licensing category of activities consisted of FPL employee, contractor labor, and specialty consulting services necessary to support the COL and the state certification applications. (TR 47; EXH 39)† The permitting category of activities consisted of additional support provided by employees and legal services. (TR 48; EXH 39) The engineering and design category of activities included employee and/or consulting services supporting the continued permitting of the underground injection exploratory well, and membership fees for EPRIís advanced nuclear technology working group and the AP1000 owners group. (TR 48-49; EXH 39)† Witness Scroggs explained that FPL did not incur any costs during 2013 for long-lead procurement advance payments, power block engineering and procurement, or transmission facilities. (TR 47, 49; EXH 34; EXH 39)

Witness Scroggs also provided, in Exhibit 35, a listing of 56 different federal, state and local licenses, permits and authorizations necessary for the TP Project.† One significant achievement towards securing the Florida Site Certification was completion of the hearing process and receiving a December 5, 2013 order recommending that the Siting Board grant final site certification approval.† (TR 17-18, 28, 171)† The Siting Boardís decision was expected in March 2014. (TR 171)

FPL provided a series of schedules in Exhibit 34 detailing its final 2013 project costs that included a calculation of its requested 2013 recovery amount.† In Exhibit 34, FPL witnesses Grant-Keene and Scroggs indicated that the jurisdictional expense amount was $28,209,654 and the associated carrying costs totaled $4,835,406. (Grant-Keene TR 194-195, 199-200; Scroggs TR 18-19)† FPLís total 2013 jurisdictional amount, including carrying costs, was $33,045,060 ($28,209,654 + $4,835,406 = $33,045,060).

FPL witness Reed, with Concentric Energy Advisors, Inc., presented an independent review of FPLís 2013 internal project controls, processes and procedures and opined that FPL appropriately and prudently managed the TP Project. (TR 137-139, 187)† FPL also retained witness Diaz with ND2 Group, a consulting firm, to review the reasonableness of FPLís continued pursuit of a COL for the TP Project. (TR 94)† Based on a review of FPLís 2013 decisions and management approaches, witness Diaz concluded that FPLís activities were prudent and consistent with a reasonable strategy for securing the COL. (TR 95)† Audit staff witnesses Rich and Hallenstein reported no findings based on their review of FPLís 2013 project management oversight and controls. (EXH 88)

Staff notes that no evidence of imprudent action was presented. Thus, staff believes no adjustment to FPLís final 2013 TP Project costs should be made.

Final True-up of the Recoverable Amount for 2013 TP Project Activities

In support of the final 2013 true-up recovery amount, witness Scroggs described variances in project activities compared to FPLís May 2013 filings. (TR 34, 47-49; EXH 34, p. 18)† FPL reported increased licensing activities due to NRCís requests for additional analysis and greater than expected contractor work associated with the Florida Site Certification application. (TR 47-48; EXH 34, p. 18)† Similarly, permitting activities increased due to the associated requirements for employee support and legal services. (TR 47-48; EXH 34, p. 18)† FPL witness Scroggs noted a decrease in engineering and design activities during 2013 associated with the underground injection well system and lower AP1000 Owner Group membership fees. (TR 48-49; EXH 34, p. 18)

FPL witness Grant-Keene provided additional support for the reported costs and methods used to determine the requested final 2013 true-up recovery amount. (TR 197-201; EXH 34, pp. 5, 10; EXH 65; EXH 66)† Witness Grant-Keene explained that the actual 2013 project costs were compared to the prior estimate of 2013 project costs to determine the final true-up amount of $463,650 over-recovery. (TR 194, 196,198-201; EXH 34; EXH 65; EXH 71)† The requested 2013 final true-up amount includes $539,308 over recovery of pre-construction expenses and an under recovery of $75,659 for associated carrying charges. (TR 199-201; EXH 65)† Audit staff witness Leon reported no findings based on a review of FPLís 2013 TP Project costs, true-up calculations, financial reporting procedures and controls. (EXH 87)

CONCLUSION

Consistent with staffís verification of FPLís calculations, a preponderance of the evidence in the record, and the resolution of Issue 11, staff believes FPLís final 2013 prudently incurred TP Project costs are $33,045,060 (jurisdictional).† Staff also believes FPL appropriately identified the final 2013 true-up amount as an over recovery of $463,650 for the TP Project.

 


Issue 13: 

 What jurisdictional amounts should the Commission approve as reasonably estimated 2014 costs and estimated true-up amounts for FPL's Turkey Point Units 6 & 7 project?

Recommendation

 The Commission should approve $24,268,636 as FPLís reasonably estimated 2014 costs and an under recovery of $958,251 as the estimated 2014 true-up amount for the Turkey Point Units 6 & 7 project.† (Breman)

Position of the Parties

FPL

 The Commission should approve as reasonable FPLís 2014 actual/estimated Preconstruction expenditures of $19,270,470 (jurisdictional), and the 2014 estimated true-up amount of $2,443,844.† The Commission should also approve as reasonable FPLís 2014 actual/estimated Preconstruction carrying charges of $4,839,764 and Site Selection carrying charges of $158,402, and the 2014 carrying charge estimated true-up amount of ($1,485,592).

FPLís 2014 actual/estimated expenditures are supported by comprehensive procedures, processes and controls which help ensure that these costs are reasonable.† The net 2014 true up amount of $958,251 should be included in FPLís 2015 NCR amount.

OPC

 No position.

FIPUG

 No position.

SACE

 None. SACE argued in 2013 that FPL did not complete and properly analyze a realistic feasibility analysis. As such, requested cost recovery flowing from that feasibility analysis are not prudently incurred, nor are such costs reasonable, and should be denied.

FRF

 No position.

Staff Analysis

 This issue addresses the reasonableness of FPLís 2014 estimated TP Project activities, incurred costs, and the associated estimated 2014 true-up amount FPL will either refund or collect during 2015.† The only party opposing FPLís position on this issue was SACE.

PARTIESí ARGUMENTS

Pursuant to the Commission-approved procedural motion, the parties waived witness cross-examination and post-hearing briefs. (TR 10-12)† The parties, therefore, did not present arguments on this Issue, only positions.

ANALYSIS

The only party opposing FPLís position on this issue was SACE.† Pursuant to the Commission-approved procedural motion, FPL and SACE waived witness cross-examination and the filing of post-hearing briefs. (TR 10-12)† Staff notes that SACEís opposition to FPLís recovery of 2014 costs is the same as itís opposition to FPLís recovery of 2013 costs in Issue 12.† SACE generally references arguments it made in the 2013 NCRC proceeding regarding FPLís 2013 analysis of the long-term feasibility of completing the TP Project.† The reasonableness of FPLís 2013 analysis was addressed by the Commission as part of the 2013 NCRC process.[26]† In this proceeding, SACE did not identify any new information concerning the reasonableness of FPLís 2013 analysis or FPLís 2014 activities and costs.

2014 TP Project Licensing and Permitting Activities and Costs

FPL witness Scroggsí May 1, 2014 testimony provided summary descriptions of the 2014 TP Project permit and licensing activities, associated engineering and design activities, resultant costs, and summary data on executed contracts in excess of $250,000. (TR 52, 73-78, 86-92; EXH 39; EXH 40)† In support of FPLís request, FPL witness Scroggs opined that the projected expenditures ďallow FPL to support and defend the applications requesting the required licenses and permits and to maintain permits that have been obtained.Ē (TR 52)† Staff observes that FPL expected the Siting Board would approve and issue the Site Certification later in May after the filing of its NCRC testimony. (TR 51, 69, 76)

Witness Scroggs asserted that FPL will take the necessary actions required by conditions of the Site Certification to maintain compliance. (TR 73, 76, 88)† Witness Scroggs further clarified that only those activities necessary to maintain compliance with the terms and conditions of the Site Certification will be undertaken without specific authorization of the Commission, consistent with Section 366.93, F.S. (TR 76)† Witness Scroggs also noted that possible appeals of the Site Certification could require 12 to 18 months to resolve. (TR 69, 76; EXH 44)† Witness Scroggs estimated that the NRC staff would issue a revised COL review schedule later in 2014. (TR 73)† Pending the issuing of that schedule, FPL estimated that the COL hearing would occur in late 2016 and that the NRC would be able to make a decision in September 2017. (TR 73-74)

FPL witnesses Grant-Keene and Scroggs co-sponsored Exhibit 40 which includes a series of schedules supporting FPLís estimated 2014 jurisdictional expense amount of $19,270,470 and associated carrying costs totaling $4,998,166. (Grant-Keene TR 225-227, 233; Scroggs TR 51-52; EXH 40, pp. 7, 10, 26, 29; EXH 93)† Thus, FPLís total 2014 jurisdictional amount, including carrying costs, is $24,268,636 ($19,270,470 + $4,998,166 = $24,268,636).

Staff notes that no evidence of unreasonable action was presented.† Thus, staff believes no adjustment to FPLís estimated 2014 TP Project costs should be made.

Estimated True-up of the Recoverable Amount for 2014 TP Project Activities

FPL witness Scroggs supported FPLís estimated true-up amount by describing variances from prior projections of 2014 activities. (TR 88-91; EXH 40, p. 33)† Licensing actions were estimated to increase due to extended site certification process, land exchange activity, and NRC staff requests for additional information. (TR 88-89; EXH 40, p. 33).† However, estimated permitting activities were decreased to reflect completion of the Florida Site Certification. (TR 89; EXH 40, p. 33)† Engineering and design work was estimated to increase due to 2013/2014 carry-over activity associated with the underground injection control well system that was not completed in 2013. (TR 90-91; EXH 40, p. 33)

FPL witness Grant-Keene explained and demonstrated that the updated estimate of 2014 project activities and costs were compared to the prior projection of 2014 to determine the estimated under recovery true-up amount of $958,251. (TR 221, 224-225, 229-230, 232-234; EXH 40; EXH 71; EXH 93)† Witness Grant-Keene noted that certain true-up amounts in the calculation of carryings costs were due to ongoing deferred tax affects as well as a reduction in the authorized Allowance for Funds Used During Contruction (AFUDC) rate that became effective January 1, 2014. (TR 233)

CONCLUSION

Consistent with staffís verification of FPLís calculations and a preponderance of the evidence in the record, staff believes FPLís reasonably estimated 2014 TP Project costs are $24,268,636 (jurisdictional).† Staff also believes FPL appropriately identified the estimated 2014 true-up amount as an under recovery of $958,251 for the TP Project.

 

 

 


Issue 14: 

 What jurisdictional amounts should the Commission approve as reasonably projected 2015 costs for FPL's Turkey Point Units 6 & 7 project?

Recommendation

 The Commission should approve $19,342,894 as FPLís reasonably projected 2015 costs for the Turkey Point Units 6 & 7 project.† (Breman)

Position of the Parties

FPL

 The Commission should approve as reasonable FPLís 2015 projected Preconstruction expenditures of $12,548,959 (jurisdictional).† The Commission should also approve as reasonable FPLís 2015 projected Preconstruction carrying charges of $6,634,789 and Site Selection carrying charges of $159,146.

FPLís 2015 projected expenditures are supported by comprehensive procedures, processes and controls which help ensure that these costs are reasonable.† The total amount of $19,342,894 should be included in FPLís 2015 NCR amount.

OPC

 No position.

FIPUG

 No position.

SACE

 None. FPL did not complete and properly analyze a realistic feasibility analysis. The technical feasibility analysis is heavily skewed towards an outcome favoring the TP 6 & 7 reactors.† Moreover, the reactors are not qualitatively feasible as they impose enormous costs on customers, many who may never realize a cumulative net fuel savings benefit from proposed reactors.

FRF

 No position.

Staff Analysis

 This issue addresses the reasonableness of FPLís 2015 projected TP Project activities and costs.† The only party opposing FPLís position on this issue was SACE.

PARTIESí ARGUMENTS

Pursuant to the Commission-approved procedural motion, the parties waived witness cross-examination and post-hearing briefs. (TR 10-12)† The parties, therefore, did not present arguments on this Issue, only positions.

ANALYSIS

Staff notes that SACEís opposition to FPLís recovery of 2015 costs stems from its concerns with FPLís 2014 analysis of the long-term feasibility of completing the TP Project.† The reasonableness of FPLís 2014 analysis is addressed in Issue 10.† Absent SACEís position concerning FPLís analysis of the feasibility of completing the project, no evidence was presented that identified unreasonable or unnecessary 2015 TP Project activities and costs.

 

FPLís 2015 TP Project Licensing and Permitting Activities and Costs

FPL witness Scroggs described FPLís 2015 TP Project activities and costs as only those associated with the permitting and licensing activities currently underway.† (TR 52-53, 87; EXH 40; EXH 41)† In Exhibit 44, witness Scroggs provided a summary timeline through 2017 depicting the remaining significant state and federal permitting and licensing efforts.† Witness Scrogges stated:

In 2014 and 2015 FPL will continue its progress on the project by concluding the state Site Certification Application (SCA) process and moving to the report review stage in the Nuclear Regulatory Commission's (NRC) Combined License Application (COLA) process.

(TR 53)

As noted in a prior issue, FPL filed its testimony prior to the Siting Board taking action on its Site Certification.† FPL assumed that its request would be approved but that there may be appeals that could require 12 to 18 months to resolve.† (TR 69, 76; EXH 44)† Regarding NRC approvals, FPLís current estimated date for a decision on the COL is late 2017. (TR 73-74, 84; EXH 44)† Witness Scroggs also expressed FPLís intent to pursue completion of the TP Project and a conviction that FPL had sufficient, meaningful, and available resources dedicated to the TP Project through the current licensing phase. (TR 85)

FPL witnesses Grant-Keene and Scroggs co-sponsored Exhibit 40, which includes a series of schedules detailing the projections of 2015 costs and calculation of FPLís requested jurisdictional recovery amount of $12,548,959 with associated carrying costs totaling $6,793,935. (Grant-Keene TR 225-228, 230; Scroggs TR 51-52; EXH 40, p 15, 17, 47, 50; EXH 71; EXH 93)† Thus, FPLís projected total 2015 recovery amount, including carrying costs, is $19,342,894 ($12,548,959 + $6,793,935 = $19,342,894).

CONCLUSION

Consistent with staffís verification of FPLís calculations and a preponderance of the evidence in the record, staff believes FPLís request for recovery of $19,342,894 (jurisdictional) for 2015 TP Project licensing and permitting activities is reasonable and should be approved.

 

 


Issue 17: 

 What is the total jurisdictional amount to be included in establishing FPL's 2015 Capacity Cost Recovery Clause factor?

Recommendation

 The Commission should approve a total jurisdictional amount of $14,287,862 as FPLís 2015 NCRC recovery amount.† This amount should be used in establishing FPLís 2015 Capacity Cost Recovery Clause factor.† (Breman)

Position of the Parties

FPL

 The total jurisdictional amount of $14,287,862 should be included in establishing FPLís 2015 CCRC factor.† This amount consists of costs associated with the Turkey Point 6 & 7 project and the EPU project (including the impact through 2015 of truing-up prior period under/over-recoveries) as provided for in Section 366.93 and Rule 25-6.0423, Fla. Admin. Code.

OPC

 No position.

FIPUG

 This is a fallout amount derived from other substative issues.

SACE

 This is a fallout amount derived from other substative issues.

FRF

 No position.

Staff Analysis

 This issue addresses the amount the Commission should establish as FPLís 2015 NCRC recovery amount to be collected through the 2015 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 12, 13, 14, and 16 plus the effects of the final true-up of 2013 FPL Uprate Project costs (Issue 16) from the 2013 period through 2015.

ANALYSIS

This is a fall-out issue.† Regarding FPLís Uprate Project, staffís notes FPLís final true-up of 2013 Uprate Project costs (Issue 16) was not contested and the Commission approved the proposed resolution of Issue 16 at the August 4, 2014 hearing. (TR 305-306; EXH 95)† However, the effects of implementing the FPL Uprate Project final NCRC true-up results in the calculation of an additional true-up amount even though the FPL Uprate Project was completed in 2013. (TR 228)† FPL witness Grant-Keene provided these calculations in Exhibits 71 and 74. (TR 228, 230)† FPL demonstrated that the final Uprate Project true-up amounts, based on the resolution of Issue 16, results in additional NCRC over recoveries of $2,383,108 during 2014 and $233,220 during 2015, for a total additional net over recovery true-up amount of $2,616,328. (TR 221-222, 236-239; EXH 71; EXH 74; EXH 93)

For purposes of completeness, below are the effects of the positions taken by FPL, SACE, staffís recommendations on prior issues, the Issue 16 stipulated amount, and the additional EPU true-up amount previously discussed.† Staff notes that OPC, FIPUG and FRF are not shown on the following table because OPC, FIPUG and FRF did not contest any of FPLís requested TP Project and Uprate Project recovery amounts.

 

Table 17-1:† Summary of FPLís Net 2015 Nuclear Cost Recovery Clause Amount

 

FPL

SACE

Staff

TP Project

† Issue 12 - 2013 Final True-up

$†† -463,650

$††††††††††††††††† 0

$†† -463,650

† Issue 13 - 2014 Est. True-up

958,251

††††††††††††††††† 0

958,251

† Issue 14 - 2015 Projections

19,342,894

††††††††††††††††† 0

19,342,894

*TP Project Subtotal

$†† 19,837,496

$††††††††††††††††† 0

$†† 19,837,496

 

EPU Project

† Issue 16 - 2013 Final True-up

$†† -2,933,305

$†† -2,933,305

$†† -2,933,305

† 2014 and 2015 Add. True-up

-2,616,328

-2,616,328

-2,616,328

FPLís EPU Project Subtotal

$†† -5,549,633

$†† -5,549,633

$†† -5,549,633

 

Net NCRC Total 2014 Amount

$†† 14,287,862

$†† -5,549,633

$†† 14,287,862

*Subtotal does not add due to rounding.

CONCLUSION

Staff recommends the Commission approve a total jurisdictional amount of $14,287,862 as FPLís 2015 NCRC recovery amount.† This amount should be used in establishing FPLís 2015 Capacity Cost Recovery Clause factor.

 

 


DEF Ė Category II Stipulations on Issues 1, 2A, 6, 7, 8

 

ISSUE 1:†††††††† Should the Commission find that during the years 2012 and 2013, DEFís project management, contracting, accounting and cost oversight controls were reasonable and prudent for the Levy Units 1 & 2 project?

Position

 

††††††††††††††††††††††† Yes, for the year 2012 and 2013, DEFís project management, contracting, accounting and cost oversight controls for the Levy Units 1 & 2 project were reasonable and prudent. †††††††††††

 

ISSUE 2A:††††† What jurisdictional amounts should the Commission approve as DEFís final 2012 and 2013 prudently incurred cost for the Levy Units 1 & 2 project?

Position

 

DEFís Levy Units 1 & 2 project 2012 prudently incurred jurisdictional amounts are $25,335,581 in capital costs, $988,205 in O&M costs, and $48,424,466 in carrying costs.† The final 2012 net under-recovery of $3,644,953 is being recovered during 2014 and no further action is necessary.† DEFís final 2013 prudently incurred jurisdictional amounts are $88,441,047 in wind-down / exit costs, and $19,593,800 in carrying costs.† The final 2013 net over-recovery of $4,727,095 should be included in setting the allowed 2015 NCRC recovery.

 

ISSUE 6:†††††††† Should the Commission find that during the years 2012 and 2013, DEFís project management, contracting, accounting and cost oversight controls were reasonable and prudent for the Crystal River Unit 3 Uprate project?

Position

 

††††††††††††††††††††††† Yes, for the year 2012 and 2013, DEFís project management, contracting, accounting and cost oversight controls for the Crystal River Unit 3 Uprate project were reasonable and prudent.

 

The IRP (Investment Recovery Project) is an ongoing process that began in 2013 and continues to evolve through 2014 as seen in the stipulated Duke responses to Staff Interrogatories 2 and 3.  The NCRC is only concerned with the IRP process that is applicable to CR3 EPU project costs.  At this time, that process is not final as to methods, execution or timing. Additionally, the IRP process applies to both the EPU assets and the balance of assets that make up the CR3 Regulatory Asset, which are not the subject of NCRC cost recovery or prudence determinations.  For these reasons, the parties agree that the Commissionís determination of the prudence of the IRP process should occur in the 2015 hearing. The parties further agree that the costs of the initial designing and the inception of implementation of the IRP, incurred in 2013, as well as any EPU costs incurred in 2013 to disposition EPU assets consistent with the IRP, as proposed by Duke in the testimony of witnesses Foster and Delowery are prudent for cost recovery purposes. However, such determination of prudence of costs is not determinative, by itself, of the prudence of Dukeís overall efforts to design and implement the IRP for all CR3 asset disposition efforts.

 

 

ISSUE 7:†††††††† What jurisdictional amounts should the Commission approve as DEFís final 2012 and 2013 prudently incurred cost for the Crystal River Unit 3 Uprate project?

Position

 

DEFís Crystal River Unit 3 Uprate project 2012 prudently incurred jurisdictional amounts, net of joint owner and other adjustments are $34,217,595 in capital costs, $432,585 in O&M costs, $21,205,814 in carrying costs and a credit of $3,242,310. †The final 2012 net under-recovery of $2,596,849 is being recovered during 2014 and no further action is necessary.† DEFís final 2013 prudently incurred jurisdictional amounts are $12,399,539 in wind-down / exit costs, and $26,804,602 in carrying costs.† The final 2013 net over-recovery of $524,697 should be included in setting the allowed 2015 NCRC recovery.

 

ISSUE 8:†††††††† Should the Commission approve DEFís Crystal River Unit 3 Uprate Project exit and wind down costs and other sunk costs as specifically proposed for recovery or review in this docket?

Position

 

††††††††††††††††††††††† Yes. There has been no evidence presented that any cost presented for recovery does not comply with the NCRC statute or rule or the 2013 Settlement Agreement.† DEFís estimated / actual 2014 incurred jurisdictional amounts, net of joint owners adjustments, are $854,377 in wind-down / exit costs, and $23,872,966 in carrying costs.† An estimated 2014 net under-recovery of $155,210 should be included in setting the allowed 2015 NCRC recovery.† The projected 2015 jurisdictional amounts are $343,451 in wind-down / exit costs, $19,549,192 in carrying costs, and amortization of $43,681,007 which totals $63,573,650.

 

 


FPL Ė Category II Stipulations on Issues 11, 15, 16

 

ISSUE 11:†††††† Should the Commission find that FPLís 2013 project management, contracting, accounting and cost oversight controls were reasonable and prudent for the Turkey Point Units 6 & 7 project?

Position

 

††††††††††††††††††††††† Yes, for the year 2013, FPLís project management, contracting, accounting and cost oversight controls for the Turkey Point Units 6 & 7 project were reasonable and prudent.

 

ISSUE 15:†††††† Should the Commission find that FPLís 2013 project management, contracting, accounting and cost oversight controls were reasonable and prudent for the Extended Power Uprate project?

Position

 

††††††††††††††††††††††† Yes, for the year 2013, FPLís project management, contracting, accounting and cost oversight controls for the Extended Power Uprate project project were reasonable and prudent.

 

ISSUE 16:†††††† What jurisdictional amounts should the Commission approve as FPLís final 2013 prudently incurred costs and final true-up amounts for the Extended Power Uprate project?

Position

 

††††††††††††††††††††††† The Commission should approve as prudent FPLís final 2013 EPU expenditures of $175,307,949 (jurisdictional, net of participants).† The Commission should also approve as prudent FPLís final 2013 EPU O&M costs, including interest, of $10,599,767 (jurisdictional, net of participants); carrying charges of $19,866,836; the final true-up O&M costs including interest of $987,873; and final true-up† carrying charges of ($328,873). In addition, the Commission should approve as prudent FPLís final 2013 EPU base rate revenue requirements, including carrying charges, of $73,873,676; and the final true-up revenue requirements including carrying charges of ($3,592,305).† The net 2013 true up amount of ($2,933,305) should be approved and included in FPLís 2015 NCRC recovery amount.

 

 

 



[1] Order No. PSC-07-0119-FOF-EI, issued February 8, 2007, in Docket No. 060642-EI, In re: Petition for determination of need for expansion of Crystal River 3 nuclear power plant, for exemption from Bid Rule 25-22.082, F.A.C., and for cost recovery through fuel clause, by Progress Energy Florida, Inc.

[2] Order No. PSC-08-0518-FOF-EI, issued August 12, 2008, in Docket No. 080148-EI, In re: Petition for determination of need for Levy Units 1 and 2 nuclear power plants, by Progress Energy Florida, Inc.

[3] Order No. PSC-08-0021-FOF-EI, issued January 7, 2008, in Docket No. 070602-EI, In re: Petition for determination of need for expansion of Turkey Point and St. Lucie nuclear power plants, for exemption from Bid Rule 25-22.082, F.A.C., and for cost recovery through the Commission's Nuclear Power Plant Cost Recovery Rule, Rule 25-6.0423, F.A.C.

[4] Order No. PSC-08-0237-FOF-EI, issued April 11, 2008, in Docket No. 070650-EI, In re: Petition to determine need for Turkey Point Nuclear Units 6 and 7 electrical power plant, by Florida Power & Light Company.

[5] Order No. PSC-14-0022-FOF-EI, issued January 10, 2014, in Docket No. 130222-EI, In re: Proposed amendment of Rule 25-6.0423, F.A.C., Nuclear or Integrated Gasification Combined Cycle Power Plant Cost Recovery.

[6] Order No. PSC-13-0493-FOF-EI, issued October 18, 2013, in Docket No. 130009-EI, In re: Nuclear cost recovery clause, at page 5.

[7] Order No. PSC-13-0598-FOF-EI, issued November 12, 2013, in Docket No. 130208-EI, In re: Petition for limited proceeding to approve revised and restated stipulation and settlement agreement by Duke Energy Florida, Inc. d/b/a Duke Energy.

[8] Order No. PSC-14-0384-PHO-EI, issued July 24, 2014, in Docket No. 140009-EI, ISSUED: July 24, 2014, In re: Nuclear cost recovery clause, at pages 19, 21, 26-29.

[9] Order No. PSC-14-0384-PHO-EI, issued July 24, 2014, in Docket No. 140009-EI, issued July 24, 2014, In re: Nuclear cost recovery clause, at pages 32, 35, 36.

[10] Order No. PSC-13-0598-FOF-EI, issued November 12, 2013, in Docket No. 130208-EI, In re: Petition for limited proceeding to approve revised and restated stipulation and settlement agreement by Duke Energy Florida, Inc. d/b/a Duke Energy.

 

[11] Order No. PSC-13-0598-FOF-EI, issued November 12, 2013, in Docket No. 130208-EI, In re: Petition for limited proceeding to approve revised and restated stipulation and settlement agreement by Duke Energy Florida, Inc. d/b/a Duke Energy, at page 30.

[12] Rule 25-6.0423 F.A.C. and Order No. PSC-07-0816-FOF-EI, issued October 10, 2007, in Docket No. 060658-EI, In re: Petition on behalf of Citizens of the State of Florida to require Progress Energy Florida, Inc. to refund customers $143 million.

[13] Section 366.93(2), (3) and (6), F.S.,†† See also Rule 25-6.0423(6)(c) and (8)(a) F.A.C.

[14] Order No. PSC-11-0095-FOF-EI, issued February 2, 2011, in Docket No. 100009-EI, In re: Nuclear cost recovery clause, at page 9; Order No. PSC-11-0547-FOF-EI, issued November 23, 2011, in Docket No. 110009-EI, In re: Nuclear cost recovery clause, at page 57.

[15] Rule 25-6.0423 F.A.C. and Order No. PSC-07-0816-FOF-EI, issued October 10, 2007, in Docket No. 060658-EI, In re: Petition on behalf of Citizens of the State of Florida to require Progress Energy Florida, Inc. to refund customers $143 million.

[16] Order No. PSC-13-0598-FOF-EI, issued November 12, 2013, in Docket No. 130208-EI, In RE: Petition for limited proceeding to approve revised and restated stipulation and settlement agreement by Duke Energy Florida, Inc. d/b/a Duke Energy, at page 31.

[17] Order No. PSC-08-0237-FOF-EI, issued April 11, 2008, in Docket No. 070650-EI, In re: Petition to determine need for Turkey Point Nuclear Units 6 and 7 electrical power plant, by Florida Power & Light Company.

[18] Id.; Order No. PSC-13-0493-FOF-EI, issued October 18, 2013, in Docket 130009-EI, In re: Nuclear cost recovery clause, at page 17.

[19] Section 403.519 (4)(b)(3), F.S.

[20] Order No. PSC-11-0547-FOF-EI, issued November 23, 2011, in Docket 110009-EI, In re: Nuclear Cost Recovery Clause, at page 13.

[21] Id., p.16.

[22] Order No. PSC-13-0493-FOF-EI, issued October 18, 2013, in Docket 130009-EI, In re: Nuclear cost recovery clause, at page 18.

[23] Docket No. 130199-EI, In re: Commission review of numeric conservation goals (Florida Power & Light Company).

[24] Order No. PSC-08-0237-FOF-EI, Issued April 11, 2008, in Docket No. 070650-EI, In re: Petition to determine need for Turkey Points Nuclear Units 6 & 7 electrical power plant, by Florida Power and Light Company, at pages 3-4.

[25] Order No. PSC-13-0493-FOF-EI, issued October 18, 2013, in Docket No. 130009-EI, In re: Nuclear cost recovery clause, at pages 11-24.

[26] Order No. PSC-13-0493-FOF-EI, issued October 18, 2013, in Docket No. 130009-EI, In re: nuclear cost recovery clause, at† pages 11-24.