Ten Year Power Plant Site Plan

2015-2024

Submitted To:

Florida Public

Service Commission

Miami, Florida

April 2015
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Table of Contents

List of Figures and Tables............................................................................................................ iii

List of Schedules .......................................................................................................................... iv

Overview of the Document ........................................................................................................... 1

List of Abbreviations ..................................................................................................................... 3

Executive Summary ...................................................................................................................... 5

I. Description of Existing Resources .............................................................................. 13

A. FPL-Owned Resources ..................................................................................... 15

B. Capacity and Energy Power Purchases ......................................................... 19

C. Demand Side Management (DSM).................................................................... 24

II. Forecast of Electric Power Demand ............................................................................. 27

A. Overview of the Load Forecasting Process .......... ..................................29

B. Comparison of FPL’s Current and Previous Load Forecasts ....................... 30

C. Long-Term Sales Forecasts ............................................................................. 31

D. Net Energy for Load .......................................................................................... 34

E. System Peak Forecasts .................................................................................... 35

F. Hourly Load Forecast ....................................................................................... 37

G. Uncertainty ........................................................................................ 37

H. DSM ..................................................................................................................... 38

III. Projection of Incremental Resource Additions ........................................................... 47

A. FPL’s Resource Planning ................................................................................. 49

B. Projected Incremental Resource Additions/Changes in the 

Resource Plan .............................................................................................................59

C. Discussion of the Projected Resource Plan and Issues Impacting

FPL’s Resource Planning Work................................................................... 59

D. Demand Side Management (DSM) ..........................................................................66

E. Transmission Plan.......................................................................................................68

F. Renewable Resources................................................................................................75

G. FPL’s Fuel Mix and Fuel Price Forecasts ........................................................ 82

IV. Environmental and Land Use Information ................................................................. 115

A. Protection of the Environment ...................................................................... 117

B. FPL’s Environmental Policy ........................................................................... 118

C. Environmental Management .......................................................................... 120

D. Environmental Assurance Program .............................................................. 121

E. Environmental Communication and Facilitation ......................................... 121

F. Preferred and Potential Sites ......................................................................... 122

Preferred Sites.................................................................................................. 122

1. Preferred Site # 1 - Port Everglades Plant, Broward County ........... 123

2. Preferred Site # 2 - Babcock Ranch Solar Energy Center,

Charlotte County .................................................................................... 128

3. Preferred Site # 3 - Citrus Solar Energy Center, DeSoto County ..... 131

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4. Preferred Site # 4 - Manatee Solar Energy Center, Manatee 

County ..................................................................................................... 133

5. Preferred Site # 5 - Lauderdale Plant Peaking Facilities,

Broward County ..................................................................................... 136

6. Preferred Site # 6 - Ft. Myers Plant Peaking Facilities, Lee 

County ..................................................................................................... 140

7. Preferred Site # 7 - Okeechobee Site, Okeechobee County .............. 144

8. Preferred Site # 8 - Turkey Point Plant, Miami-Dade County............. 148

Potential Sites for Generating Options.......................................................... 156

9. Potential Site # 1 - Hendry County ....................................................... 156

10. Potential Site # 2 - Martin County ......................................................... 157

11. Potential Site # 3 - Putnam Plant Site, Putnam County .................. 158

V. Other Planning Assumptions and Information .............................................................. 213

 Introduction ................................................................................................................... 215

Discussion Item #1 ................................................................................................. 215

Discussion Item #2 ................................................................................................. 216

Discussion Item #3 ................................................................................................. 216

Discussion Item #4 ................................................................................................. 217

Discussion Item #5 ................................................................................................. 217

Discussion Item #6 ................................................................................................. 218

Discussion Item #7 ................................................................................................. 218

Discussion Item #8 ................................................................................................. 218

Discussion Item #9 ................................................................................................. 219

Discussion Item #10 ................................................................................................. 220

Discussion Item #11 ................................................................................................. 220

Discussion Item #12 ................................................................................................. 221

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List of Figures and Tables

Table ES-1 Projected Capacity & Firm Purchase Power Changes................................... 11

Figure I.A.1 FPL Generating Resources by Location (Map)............................................... 16

Table I.A.1 Capacity Resource by Unit Type ..................................................................... 17

Figure I.A.2 FPL Substation & Transmission System Configuration (Map) ..................... 18

Table I.A.3 Purchase Power Resources by Contract......................................................... 21

Table I.B.1 FPL’s Firm Purchased Power Summer MW ................................................... 22

Table I.B.2 FPL’s Firm Purchased Power Winter MW........................................................ 23

Figure III.A.1 Overview of FPL’s IRP Process........................................................................ 50

Table III.E.1 List of Proposed Power Lines .......................................................................... 69

Table IV.E.1 2014 FPL Environmental Outreach Activities ............................................... 121

Preferred Site # 1 - Port Everglades Maps..................................................... 161

Preferred Site # 2 - Babcock Maps................................................................. 167

Preferred Site # 3 - Citrus Maps...................................................................... 171

Preferred Site # 4 – Manatee Maps................................................................. 175

Preferred Site # 5 – Lauderdale Maps ............................................................ 179

Preferred Site # 6 – Ft. Myers Maps .............................................................. 185

Preferred Site # 7 – Okeechobee Maps.......................................................... 191

Preferred Site # 8 – Turkey Point Maps ......................................................... 195

Potential Site # 1 - Hendry Maps .................................................................... 201

Potential Site # 2 – Martin Maps ..................................................................... 205

Potential Site # 3 – Putman Maps................................................................... 209

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List of Schedules

Schedule 1 Existing Generating Facilities........................................................................... 25

Schedule 2.1 History and Forecast of Energy Consumption & Number of 

Customers by Customer Class (Rural & Residential).................................... 39

Schedule 2.2 History and Forecast of Energy Consumption & Number of 

Customers by Customer Class (Industrial)..................................................... 40

Schedule 2.3 History and Forecast of Energy Consumption & Number of 

Customers by Customer Class (Sales for Resale) ......................................... 41

Schedule 3.1 History and Forecast of Summer Peak Demand............................................. 42

Schedule 3.2 History and Forecast of Winter Peak Demand................................................ 43

Schedule 3.3 History and Forecast of Annual Net Energy for Load GWh........................... 44

Schedule 4 Previous Year Actual and Two-Year Forecast of Retail Peak

Demand and Net Energy for Load (NEL) by Month ........................................ 45

Schedule 5 Fuel Requirements............................................................................................. 90

Schedule 6.1 Energy Sources.................................................................................................. 91

Schedule 6.2 Energy Sources % by Fuel Type ...................................................................... 92

Schedule 7.1 Forecast of Capacity, Demand, and Scheduled Maintenance at

Time of Summer Peak........................................................................................ 93

Schedule 7.2 Forecast of Capacity, Demand, and Scheduled Maintenance at

Time of Winter Peak........................................................................................... 94

Schedule 8 Planned and Prospective Generating Facility Additions and Changes ....... 95

Schedule 9 Status Report and Specifications of Proposed Generating Facilities.......... 97

Schedule 10 Status Report and Specifications of Proposed Transmission Lines ......... 105

Schedule 11.1 Existing Firm and Non-Firm Capacity & Energy by Primary Fuel Type

- Actuals for the Year 2014.............................................................................. 113

Schedule 11.2 Existing Non- Firm Self-Service Renewable Generation Facilities

- Actuals for the Year 2014.............................................................................. 113

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Overview of the Document

Chapter 186, Florida Statutes, requires that each electric utility in the State of Florida with a minimum 

existing generating capacity of 250 megawatts (MW) must annually submit a Ten Year Power Plant Site 

Plan (Site Plan). This Site Plan should include an estimate of the utility’s future electric power generating 

needs, a projection of how these estimated generating needs could be met, and disclosure of information 

pertaining to the utility’s preferred and potential power plant sites. The information contained in this Site 

Plan is compiled and presented in accordance with Rules 25-22.070, 25-22.071, and 25-22.072, Florida 

Administrative Code (F.A.C.).

Site Plans are long-term planning documents and should be viewed in this context. A Site Plan contains 

uncertain forecasts and tentative planning information. Forecasts evolve, and all planning information is 

subject to change, at the discretion of the utility. Much of the data submitted is preliminary in nature and is 

presented in a general manner. Specific and detailed data will be submitted as part of the Florida site 

certification process, or through other proceedings and filings, at the appropriate time.

This Site Plan document is based on Florida Power & Light Company’s (FPL’s) integrated resource

planning (IRP) analyses that were carried out in 2014 and that were on-going in the first Quarter of 2015. 

The forecasted information presented in this plan addresses the years 2015 through 2024.

This document is organized in the following manner:

Chapter I – Description of Existing Resources

This chapter provides an overview of FPL’s current generating facilities. Also included is information on 

other FPL resources including purchased power, demand side management, and FPL’s transmission 

system.

Chapter II – Forecast of Electric Power Demand

FPL’s load forecasting methodology, and the resulting forecast of seasonal peaks and annual energy 

usage, is presented in Chapter II. Included in this discussion is the projected significant impact of federal 

and state energy efficiency codes and standards.

Chapter III – Projection of Incremental Resource Additions

This chapter discusses FPL’s integrated resource planning (IRP) process and outlines FPL’s projected 

resource additions, especially new power plants, based on FPL’s IRP work in 2014 and early 2015. This 

chapter also discusses a number of factors or issues that either have changed, or may change, the 

resource plan presented in this Site Plan. Furthermore, this chapter discusses FPL’s previous and planned 

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demand side management (DSM) efforts, the projected significant impact of the combined effects of FPL’s 

DSM plans and state/federal energy efficiency codes and standards, FPL’s previous and planned 

renewable energy efforts, projected transmission planning additions, and FPL’s fuel cost forecasting 

processes.

Chapter IV – Environmental and Land Use Information

This chapter discusses environmental information as well as Preferred and Potential site locations for 

additional electric generation facilities.

Chapter V – Other Planning Assumptions and Information

This chapter addresses twelve “discussion items” which pertain to additional information that is included in 

a Site Plan filing.

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FPL

List of Abbreviations

Used in FPL Forms 

Reference Abbreviation Definition

Unit Type

CC Combined Cycle

CT Combustion Turbine

GT Gas Turbine

ST Steam Unit (Fossil or Nuclear)

PV Photovoltaic

Fuel Type

NUC Uranium

BIT Bituminous Coal

FO2 #1, #2 or Kerosene Oil (Distillate)

FO6 #4,#5,#6 Oil (Heavy)

NG Natural Gas

No None

Solar Solar Energy

SUB Sub Bituminous Coal

Pet Petroleum Coke

Fuel Transportation

No None

PL Pipeline

RR Railroad

TK Truck

WA Water

Unit/Site Status

OT Other

L Regulatory approval pending. Not under construction

P Planned Unit

T Regulatory approval received but not under construction

U Under construction, less than or equal to 50% Complete

V Under construction, more than 50% Complete

Other ESP Electrostatic Precipitators

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Executive Summary

Florida Power & Light Company’s (FPL’s) 2015 Ten Year Power Plant Site Plan (Site Plan) presents FPL’s 

current plans to augment and enhance its electric generation capability (owned or purchased) as part of its 

efforts to meet FPL’s projected incremental resource needs for the 2015 - 2024 time period. By design, the 

primary focus of this document is on projected supply side additions; i.e., electric generation capability and 

the sites for these additions. The supply side additions discussed in this document are resources projected 

to be needed, based on FPL’s load forecast, after accounting for FPL’s demand side management (DSM) 

resource additions. New DSM Goals for FPL for the time period 2015 through 2024 were set in November 

2014 by the Florida Public Service Commission (FPSC). Consequently, the level of DSM additions 

reflected in the 2015 Site Plan is consistent with these newly approved DSM Goals. DSM is discussed 

later in this summary and in Chapters II and III. 

In addition, FPL’s load forecast accounts for a significant amount of efficiency that results from federal and 

state energy efficiency codes and standards. The projected impacts of these codes and standards are

directly accounted for in FPL’s load forecast and are discussed in Chapter II. 

The resource plan presented in FPL’s 2015 Site Plan contains both similarities and differences when 

compared to the resource plan presented in FPL’s 2014 Site Plan. There are a number of factors that have 

either contributed to the differences between the resource plan presented in this Site Plan and the 

resource plan that was previously presented in FPL’s 2014 Site Plan, or which may influence FPL’s ongoing resource planning efforts. These factors could result in future changes to the resource plan 

presented in this document. A brief discussion of these similarities, differences, and factors is provided

below. Additional information regarding these topics is presented in Chapters II and III.

I. Similarities Between the Current Resource Plan and the Resource Plan Previously 

Presented in FPL’s 2014 Site Plan:

There are three key similarities between the current resource plan presented in this document and the 

resource plan that was discussed in the 2014 Site Plan. 

Similarity # 1: Modernizations of Existing Power Plant Sites.

As discussed in previous Site Plans, FPL has been in the process of modernizing several existing power 

plant sites during the last few years. These modernizations consist of replacing old existing steam 

generating units with modern, highly efficient combined cycle (CC) generating units. The modernizations

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of FPL’s existing Cape Canaveral and Riviera Beach plant sites were completed in 2013 and 2014, 

respectively. The last of the previously approved modernization projects, the modernization of FPL’s 

existing Port Everglades plant site, is underway and projected to be completed in 2016.

Similarity # 2: Specific generating units are projected to be retired and/or converted to 

synchronous condenser operation. 

In the last several years, FPL has retired a number of older, less efficient generating units including: 

Sanford Unit 3, Cutler Units 5 & 6, Cape Canaveral Units 1 & 2, Riviera Beach Units 3 & 4, and Port 

Everglades Units 1 – 4. In addition, Turkey Point Unit 2 has been converted to operate in synchronous 

condenser mode to provide voltage support for the transmission system in Southeastern Florida.

This trend is projected to continue. As discussed in FPL’s 2014 Site Plan, Putnam Units 1 & 2 were retired 

at the end of 2014. In addition, similar to the earlier conversion of Turkey Point Unit 2, FPL projects that 

Turkey Point Unit 1 will be converted to run in synchronous condenser mode starting in 2016.

Similarity # 3: A number of older gas turbine peaking units are projected to be retired and replaced 

with modern combustion turbine peaking units.

In FPL’s 2014 Site Plan, FPL projected that it would retire all of its existing gas turbine (GT) units in 

Broward County at its Lauderdale and Port Everglades sites (a decrease in peaking generating capacity of 

1,260 MW) and partially replace this peaking capacity with the installation of 5 new combustion turbine 

(CT) units at the Lauderdale site (an increase of 1,005 MW). These changes were projected to be 

completed in 2019. These changes to FPL’s generating system were based on concerns regarding 

whether the older, existing GTs would allow FPL to be able to meet the new EPA 1-hour standards for 

nitrogen dioxide and sulfur dioxide. Economic analyses now indicate that it is cost-effective to retire and 

replace a number of the existing GTs at an earlier date. Based on these analyses, FPL currently projects 

the retirement of a number of its existing GTs, including: 22 of 24 GTs at the Lauderdale site, all 12 GTs at 

the Port Everglades site, and 10 of 12 GTs at the Fort Myers plant site. Two of the existing GTs at the 

Lauderdale site, and two of the existing GTs at the Ft. Myers site, will be retained for black start capability. 

In conjunction with the retirement of these peaking units, FPL is adding a number of new, larger, and more 

efficient CTs: 5 at the Lauderdale site and 2 at the Fort Myers site. Also, the two existing CTs at the Fort 

Myers site will undergo capacity upgrades. In total, the net effect of the GT retirements, plus 

new/upgraded CTs, is a net reduction of approximately 40 MW in net peaking capability. All of these 

changes are projected to be completed by the end of 2016. 

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II. Differences Between the Current Resource Plan and the Resource Plan Previously 

Presented in FPL’s 2014 Site Plan:

There are four key differences between the current resource plan presented in this document and the 

resource plan previously presented in the 2014 Site Plan. These differences are discussed below in 

chronological order as they pertain to FPL’s current resource plan.

Difference # 1: FPL no longer projects that it will serve Vero Beach’s electrical load.

Difficulties in the negotiations among the parties involved have led FPL to no longer project that it will 

serve Vero Beach’s electrical load as had been assumed in FPL’s most recent Site Plans and load 

forecasts. This factor results in a reduction of FPL’s forecasted load. To the extent circumstances change 

and a consummation of the sale once again seems likely, FPL will reincorporate this load into its forecast.

Difference # 2: FPL’s power purchase agreement with Cedar Bay will be terminated in 2015.

FPL anticipates terminating its existing power purchase agreement for 250 MW of coal-fired capacity from 

the Cedar Bay generating facility at the end of August 2015 as a result of a Purchase and Sale Agreement 

between FPL and Cedar Bay Generating Company, L.P. FPL would then own the unit starting on 

September 1, 2015. FPL currently anticipates that it will not need the unit for economic purposes after 

2016 and, if that proves to be the case, would retire the unit at that time. FPL filed for FPSC approval of 

the Purchase and Sale Agreement in the first quarter of 2015.

Difference # 3: FPL will approximately triple its solar generating capacity by the end of 2016.

FPL will be adding three new photovoltaic (PV) facilities by the end of 2016. Each of the PV facilities will 

be approximately 74.5 MW (nameplate rating, AC). As a result, FPL’s solar generation capacity will 

increase from its current 110 MW to approximately 333 MW. The new PV installations are projected to be 

sited in Manatee, Charlotte, and DeSoto counties. The economics of these specific PV projects are aided 

by the fact that the sites are located close to existing electric infrastructure, including tranmission lines and 

electric substations, and by the fact that bringing these solar facilities into service prior to the end of 2016 

will allow the facilities to take advantage of the current 30% investment tax credit that is scheduled to be 

reduced to 10% beginning in 2017. 

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Difference # 4: The projected in-service dates of FPL’s planned two new nuclear units, Turkey 

Point 6 & 7, have now been moved outside of the 10-year reporting period of this document.

In recent Site Plans, the earliest practical deployment dates for the new Turkey Point 6 & 7 nuclear unit 

were identified as 2022 and 2023, and these two dates were used as the projected in-service dates for 

these units. However, in the second half of 2014, the Nuclear Regulatory Commission (NRC) issued a new 

schedule for completing its review of FPL’s Combined Operating License Application (COLA) for Turkey 

Point 6 & 7. The NRC’s new schedule now projects that its review will not be completed until late 2016. As 

a consequence of the NRC delay, and the impacts of the recently amended Florida nuclear cost recovery 

(NCR) statute, FPL now projects that the earliest practical deployment dates for Turkey Point 6 & 7 will fall 

outside of the 10-year time period of 2015 through 2024 that is addressed in this Site Plan document.

However, emissions-free, baseload capacity and energy from nuclear power remains an important part of 

FPL’s resource plans. For that reason, Chapter IV provides detailed information regarding the Turkey 

Point site for these two new nuclear units.

III. Factors Which Have Impacted, or Which Could Impact, FPL’s Resource Plan:

In addition to these key similarities and differences, there are a number of factors which have impacted, or 

which may impact, FPL’s resource plan. Six (6) such factors are summarized in the text below and these

are presented in no particular order. These factors, and/or their corresponding impacts on FPL’s resource 

plan, are further discussed in Chapters II and III.

The first and second of these factors are on-going system concerns that FPL has considered in its 

resource planning work for a number of years. The first factor is the objective to maintain/enhance fuel 

diversity in the FPL system. Diversity is sought both in terms of the types of fuel utilized by FPL and how 

these fuels are supplied to FPL. (Related to the fuel diversity objective, FPL also seeks to enhance the 

efficiency with which it uses fuel to generate electricity.) The second factor is the need to maintain a 

balance between load and generating capacity in Southeastern Florida, particularly in Miami-Dade and 

Broward counties. This balance has both reliability and economic implications for FPL’s system.

The third factor is also a system concern that FPL has considered in its resource planning for several 

years. This factor addresses system reliability and focuses upon the desirability of maintaining an 

appropriate balance of DSM and supply resources from a system reliability perspective. FPL addresses 

this through the use of a 10% generation-only reserve margin (GRM) reliability criterion in its resource 

planning work to complement its other two reliability criteria: a 20% total reserve margin criterion for 

Summer and Winter, and an annual 0.1 day/year loss-of-load-probability (LOLP) criterion. Together, these 

three criteria allow FPL to address this specific concern regarding system reliability in a comprehensive 

manner.

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The fourth factor is the significant and increasing impact that federal and state energy efficiency codes and 

standards are having on FPL’s projected demand and energy load forecasts. The incremental impacts of 

these energy efficiency codes and standards during the 2015 through 2024 time period are projected to 

reduce FPL’s forecasted Summer peak load by more than 2,000 MW, and reduce annual energy 

consumption by more than 6,800 GWh, by 2024. In addition, this mandated energy efficiency significantly 

reduces the potential for cost-effective energy efficiency that might otherwise have been obtained through 

FPL’s DSM programs. 

The fifth factor is the increasing cost competitiveness of utility-scale PV facilities due to the continued 

decline of the cost of PV modules. Utility-scale PV facilities are the most economical way to utilize PV 

technology and the declining costs of PV modules have resulted, for the first time, in utility scale PV now 

being competitive on FPL’s system at specific, highly advantaged sites. As a result, FPL’s current resource 

plan presented in this year’s Site Plan includes approximately 223 MW (nameplate, AC) of new PV 

facilities at three specific sites that offer particular cost advantages. The projected new PV facilities are 

also presented in Table ES – 1 at the end of this executive summary.

The sixth factor is environmental regulation, particularly the U.S. Environmental Protection Agency’s (EPA) 

proposed Clean Power Plan issued in June 2014. The intent of the Clean Power Plan is to set carbon 

dioxide (CO2) emission limits for each state. The EPA is scheduled to issue final rules and emission limits 

in June 2015 (several months after this Site Plan is filed). The current draft rules call for each state to 

submit its compliance plan by June 2016 (although a delay of at least one year is possible). FPL’s 

resource planning work will account for the CO2 limits as they are finalized and FPL expects to be actively 

engaged in the development of Florida’s statewide compliance plan. 

Each of these factors will continue to be examined in FPL’s on-going resource planning work during the 

rest of 2015 and in future years.

Table ES-1 presents a current projection of major changes to specific generating units and firm capacity 

purchases for 2015 – 2024. Although this table does not specifically identify the impacts of projected DSM 

additions on FPL’s resource needs and resource plan, FPL’s projected DSM additions that are consistent 

with its new DSM Goals have been fully accounted for in the resource plan presented in this Site Plan.

In addition, this table shows the addition of an FPL CC unit in 2019. This potential new unit represents 

FPL’s most economic self-build generation option for 2019 and it appears in this table and this Site Plan as 

a placeholder for that year. In March 2015, FPL issued a capacity request for proposals (RFP) that

solicited proposals from interested parties for generation that could supply firm, dispatchable capacity 

starting in mid-2019. Proposals are due in May 2015. At that time, FPL and an independent evaluator will 

conduct separate reviews of proposals received in response to the RFP and of FPL’s potential self-build

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CC unit. At the conclusion of the analyses, FPL will file for a determination of need, or approval of cost 

recovery, from the Florida Public Service Commission for the generation option(s) that was determined in 

these analyses to be the best selection for FPL’s customers beginning in 2019.

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Table ES-1: Projected Capacity & Firm Purchase Power Changes

Summer

Summer Reserve

Year * Projected Capacity & Firm Purchase Power Changes MW Date Margin **

2015 Turkey Point (22) January-15

Fort Myers (5) January-15

Lauderdale GT (8) January-15

Lauderdale GT (8) January-15

Port Everglades GT (8) January-15

Palm Beach SWA - additional firm capacity 70 June-15

Martin (3) June-15

Scherer (9) June-15

Total of MW changes to Summer firm capacity: 6 26.7%

2016 Cedar Bay -PPA retirement (250) October-15

Cedar Bay -FPL Ownership 250 October-15

UPS Replacement (928) December-15

Fort Myers 2 37 June-16

Fort Myers GTs 1 -10 (540) June-16

Lauderdale GTs 1- 12 (412) June-16

Martin 2 June-16

Port Everglades Next Generation Clean Energy Center 1,237 June-16

Sanford 3 June-16

Total of MW changes to Summer firm capacity: (601) 21.3%

2017 Babcock Solar Energy Center (Charlotte) *** 38 September-16

Citrus Solar Energy Center (DeSoto) *** 38 September-16

Manatee Solar Energy Center *** 38 September-16

Lauderdale GTs 13- 22 (343) October-16

Turkey Point Unit 1 synchronous condenser (396) October-16

Port Everglades GTs (412) December-16

Cedar Bay (250) December-16

Lauderdale GTs - 5 CT 1,155 December-16

Fort Myers GTs - 2 CT 462 December-16

Fort Myers 3A&B - upgraded 50 December-16

Martin 2 January-17

Sanford 1 January-17

Sanford 4 January-17

Turkey Point #5 23 June-17

Manatee 4 June-17

Total of MW changes to Summer firm capacity: 415 20.9%

2018 Unspecified Short-Term Purchase 207 May-18

Turkey Point Nuclear Unit #3 20 June-18

Turkey Point Nuclear Unit #5 3 June-18

Total of MW changes to Summer firm capacity: 227 20.0%

2019 Unspecified Short-Term Purchase (207) September-18

SJRPP suspension of energy (382) 2nd Quarter

Turkey Point Nuclear Unit #4 20 June-19

Okeechobee Next Generation Clean Energy Center **** 1,622 June-19

Total of MW changes to Summer firm capacity: 1,053 22.8%

2020 --- --- ---

Total of MW changes to Summer firm capacity: 0 21.3%

2021 Eco-Gen PPA firm capacity 180 January-21

Cape Next Generation Clean Energy Center 88 June-21

Total of MW changes to Summer firm capacity: 268 22.0%

2022 Riviera Beach Next Generation Clean Energy Center 86 June-22

Total of MW changes to Summer firm capacity: 86 20.9%

2023 Unsited CC 1,317 June-23

Total of MW changes to Summer firm capacity: 1,317 24.4%

2024 --- --- ---

Total of MW changes to Summer firm capacity: 0 22.2%

* Year shown reflects when the MW change begins to be accounted for in Summer reserve margin 

calculations.

** Winter Reserve Margins are typically high than Summer Reserve Margin. Winter Reserve Margin are shown

on Schedule 7.2 in Chapter III.

*** MW values shown represent the firm capacity assumption for each 74.5 MW nameplate (AC) PV facility.

**** The Okeechobee generating is FPL's best self-build option for 2019. During 2015 it will be evaluated versus 

 

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CHAPTER I

Description of Existing Resources

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I. Description of Existing Resources 

FPL’s service area contains approximately 27,650 square miles and has a population of 

approximately 9.1 million people. FPL served an average of 4,708,829 customer accounts in 35 

counties during 2014. These customers were served by a variety of resources including: FPLowned fossil-fuel, renewable, and nuclear generating units, non-utility owned generation, demand 

side management (DSM), and interchange/purchased power.

I.A. FPL-Owned Resources 

The existing FPL generating resources are located at 14 generating sites distributed 

geographically around its service territory, plus one site in Georgia (partial FPL ownership of one 

unit) and one site in Jacksonville, Florida (partial FPL ownership of two units). As of December 31, 

2014, FPL’s electrical generating facilities consisted of: four nuclear units, three coal units, 15

combined cycle (CC) units, five fossil steam units, 48 combustion gas turbines, two simple cycle 

combustion turbines, and two photovoltaic facilities1

. The locations of these 79 generating units 

are shown on Figure I.A.1 and in Table I.A.1. 

FPL’s bulk transmission system, including both overhead and underground lines, is comprised of 

6,888 circuit miles of transmission lines. Integration of the generation, transmission, and 

distribution system is achieved through FPL’s 596 substations in Florida.

The existing FPL system, including generating plants, major transmission stations, and 

transmission lines, is shown on Figure I.A.2. 

1 FPL also has one 75 MW solar thermal facility at its Martin plant site. This facility does not generate electricity as the other units 

mentioned above do. Instead, it produces steam that reduces the use of fossil fuel to produce steam for electricity generation. 

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Figure I.A.1: Capacity Resources by Location (as of December 31, 2014)

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Table I.A.1: Capacity Resource by Unit Type (as of December 31, 2014)

Number Summer

Unit Type/ Plant Name Location of Units Fuel MW

Nuclear

St. Lucie 1/ Hutchinson Island, FL 2 Nuclear 1,821

Turkey Point Florida City, FL 2 Nuclear 1,632

Total Nuclear: 4 3,453

Coal Steam

Scherer Monroe County, Ga 1 Coal 643

St. John's River Power Park 2/ Jacksonville, FL 2 Coal 254

Total Coal Steam: 3 897

Combined-Cycle 

Fort Myers Fort Myers, FL 1 Gas 1,436

Manatee Parrish, FL 1 Gas 1,143

Martin Indiantown, FL 3 Gas 2,073

Sanford Lake Monroe, FL 2 Gas 2,010

Cape Canaveral Cocoa, FL 1 Gas/Oil 1,210

Lauderdale Dania, FL 2 Gas/Oil 884

Riviera Beach City of Riviera Beach, FL 1 Gas/Oil 1,212

Turkey Point Florida City, FL 1 Gas/Oil 1,192

West County Palm Beach County, FL 3 Gas/Oil 3,657

Total Combined Cycle: 15 14,817

Oil/Gas Steam

Manatee Parrish, FL 2 Oil/Gas 1,618

Martin Indiantown,FL 2 Oil/Gas 1,649

Turkey Point Florida City, FL 1 Oil/Gas 396

Total Oil/Gas Steam: 5 3,663

Gas Turbines(GT)

Fort Myers (GT) Fort Myers, FL 12 Oil 648

Lauderdale (GT) Dania, FL 24 Gas/Oil 840

Port Everglades (GT) Port Everglades, FL 12 Gas/Oil 420

Total Gas Turbines/Diesels: 48 1,908

Combustion Turbines 

Fort Myers Fort Myers, FL 2 Gas/Oil 319

Total Combustion Turbines: 2 319

PV

DeSoto 3/ DeSoto, FL 1 Solar Energy 25

Space Coast 3/ Brevard County, FL 1 Solar Energy 10

Total PV: 2 35

Total System Generation as of December 31, 2013 = 79 25,092

 System Firm Generation as of December 31, 2013 = 25,072

1/ Total capability of St. Lucie 1 is 981/1,003 MW. FPL's share of St. Lucie 2 is 840/860. FPL's ownership share of St. Lucie

 Units 1 and 2 is 100% and 85%, respectively.

2/ Capabilities shown represent FPL's output share from each of the units (approx. 92.5% and exclude the Orlando Utilities

Commission (OUC) and Florida Municipal Power Agency (FMPA) combined portion of approximately 7.44776% per unit.

Represents FPL's ownership share: SJRPP coal: 20% of two units).

3/ Approximately 46% of the 25 MW of PV at DeSoto, and 32% of the 10 MW of PV at Space Coast, are considered as firm 

generating capacity for Summer reserve margin purposes.

Florida Power & Light Company 17
Figure I.A.2: FPL Substation and Transmission System Configuration 

Florida Power & Light Company 18
Description of Existing Resources

I.B Capacity and Energy Power Purchases

Firm Capacity: Purchases from Qualifying Facilities (QF)

Firm capacity power purchases are an important part of FPL’s resource mix. FPL currently has 

contracts with seven qualifying facilities; i.e., cogeneration/small power production facilities, to 

purchase firm capacity and energy during the 10-year reporting period of this Site Plan. This is 

shown in Table I.A.3, Table I.B.1, and Table I.B.2. 

A cogeneration facility is one that simultaneously produces electrical and thermal energy, with the 

thermal energy (e.g., steam) used for industrial, commercial, or cooling and heating purposes. A

small power production facility is one that does not exceed 80 MW (unless it is exempted from this 

size limitation by the Solar, Wind, Waste, and Geothermal Power Production Incentives Act of 

1990) and uses solar, wind, waste, geothermal, or other renewable resources as its primary 

energy source.

Firm Capacity: Purchases from Utilities

FPL has a Unit Power Sales (UPS) contract to purchase 928 MW from the Southern Company 

(Southern) through the end of December 2015. This capacity is being supplied by Southern from a 

mix of gas- and coal-fired units.

In addition, FPL has contracts with the Jacksonville Electric Authority (JEA) for the purchase of 

382 MW (Summer) and 389 MW (Winter) of coal-fired generation from the St. John’s River Power 

Park (SJRPP) Units No. 1 and No. 2. However, due to Internal Revenue Service (IRS) regulations, 

the total amount of energy that FPL may receive from this purchase is limited. FPL currently 

assumes, for planning purposes, that this limit will be reached in the second quarter of 2019. Once 

this limit is reached, FPL will be unable to receive firm capacity and energy from these purchases. 

(However, FPL will continue to receive firm capacity and energy from its ownership portion of the 

SJRPP units.)

These purchases are shown in Table I.A.3, Table I.B.1, and Table I.B.2. FPL’s ownership interest 

in the SJRPP units is reflected in FPL’s installed capacity shown on Figure I.A.1, in Table I.A.1, 

and on Schedule 1.

Florida Power & Light Company 19
Firm Capacity: Other Purchases

FPL has two other firm capacity purchase contracts with non-QF, non-utility suppliers. These 

contracts with the Palm Beach Solid Waste Authority were previously listed as QFs. However, the 

addition of a second unit in 2015 will cause both units to no longer meet the statutory definition of 

a QF. Therefore, these contracts are listed as “Other Purchases” following the estimated inservice date of the new unit. Table I.B.1 and I.B.2 present the Summer and Winter MW, 

respectively, resulting from these contracts under the category heading of Other Purchases.

Non-Firm (As Available) Energy Purchases

FPL purchases non-firm (as-available) energy from several cogeneration and small power 

production facilities. Table I.A.3 shows the amount of energy purchased in 2014 from these 

facilities.

Florida Power & Light Company 20
Firm Capacity Purchases (MW) Location Summer

(City or County) Fuel MW

I. Purchase from QF's: Cogeneration/Small Power Production Facilities

Cedar Bay Generating Company Duval Coal (Cogen) 250

Indiantown Cogen LP Martin Coal (Cogen) 330

Broward South Broward Solid Waste 4

Broward North Broward Solid Waste 11

Palm Beach SWA - extension Palm Beach Solid Waste 40

Total: 635

II. Purchases from Utilities

UPS from Southern Company Various Georgia Coal/Gas 928

SJRPP Jacksonville Coal 382

Total: 1,310

 1,945

Non-Firm Energy Purchases (MWH)

Project County Fuel

 Energy (MWH) 

Delivered to FPL 

in 2014 

Okeelanta (known as Florida Crystals and New Hope P Palm Beach Bagasse/Wood 87,690

Broward South* Broward Solid Waste 93,548

Broward North* Broward Solid Waste 57,806

Waste Management Renewable Energy* Broward Landfill Gas 34,265

Waste Management - Collier County Landfill* Broward Landfill Gas 24,928

Tropicana Manatee Natural Gas 7,172

Georgia Pacific Putnam Paper by-product 8,606

Rothenbach Park (known as MMA Bee Ridge)* Sarasota PV 286

First Solar* Dade PV 409

Customer Owned PV & Wind Various PV/Wind 1,505

INEOS Bio* Indian River Wood 325

Miami Dade Resource Recovery* Dade Solid Waste 146,417

*These Non-Firm Energy Purchases are renewable and are reflected on Schedule 11.1, rows 8 and 9, column 6.

Total Net Firm Generating Capability:

Table 1.A.3: Purchase Power Resources by Contract (as of December 31, 2014)

Florida Power & Light Company 21
Table I.B.1: FPL's Firm Purchased Power Summer MW

I. Purchases from QF's

Cogeneration Small Power 

Production Facilities

Contract 

Start Date

Contract

End Date 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Broward South 01/01/93 12/31/26 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4

Broward South 01/01/95 12/31/26 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5

Broward South 01/01/97 12/31/26 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6

Broward North 01/01/93 12/31/26 7 7 7 7 7 7 7 7 7 7

Broward North 01/01/95 12/31/26 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5

Broward North 01/01/97 12/31/26 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5

Cedar Bay Generating Co. 01/25/94 08/31/15 250 0 0 0 0 0 0 0 0 0

Indiantown Cogen L.P. 12/22/95 12/01/25 330 330 330 330 330 330 330 330 330 330

U.S.EcoGen Clay2/ 01/01/21 12/31/49 0 0 0 0 0 0 60 60 60 60

U.S.EcoGen Okeechobee2/ 01/01/21 12/31/49 0 0 0 0 0 0 60 60 60 60

U.S.EcoGen Martin2/ 01/01/21 12/31/49 0 0 0 0 0 0 60 60 60 60

595 345 345 345 345 345 525 525 525 525

II. Purchases from Utilities

Contract 

Start Date

Contract

End Date 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

UPS Replacement 06/01/10 12/31/15 928 0 0 0 0 0 0 0 0 0

SJRPP3/ 04/02/82 2nd Qtr/2019 382 382 382 382 0 0 0 0 0 0

1,310 382 382 382 0 0 0 0 0 0

1,905 727 727 727 345 345 525 525 525 525

III. Other Purchases

Contract 

Start Date

Contract

End Date 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Palm Beach SWA - Extension1/ 01/10/12 04/01/32 40 40 40 40 40 40 40 40 40 40

Palm Beach SWA - Additional 06/01/15 04/01/32 70 70 70 70 70 70 70 70 70 70

Unspecified Purchases4/ 05/01/18 09/30/18 0 0 0 207 0 0 0 0 0 0

110 110 110 317 110 110 110 110 110 110

1,420 492 492 699 110 110 110 110 110 110

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

2,015 837 837 1,044 455 455 635 635 635 635

Summary of FPL's Firm Capacity Purchases: Summer MW (for August of Year Shown)

1/ When the second unit comes into commercial service at the Palm Beach SWA, neither unit will meet the standards to be a small power producer, and 

it will then be accounted for under "Other Purchases"

2/ The EcoGen units will enter service in 2019, however firm capacity will only be delivered starting in 2021.

4/ These Unspecified Purchases are short-term purchases for the summer of 2018 that are included for resource planning purposes. No decision 

regarding such purchases is needed at this time.

Total "Non-QF" Purchases =

Total of QF and Utility Purchases =

QF Purchases Subtotal:

Utility Purchases Subtotal:

Other Purchases Subtotal:

Summer Firm Capacity Purchases Total MW:

3/ Contract end date shown for the SJRPP purchase does not represent the actual contract end date. Instead, this date represents a projection of the 

earliest date at which FPL's ability to receive further capacity and energy from this purchase could be suspended due to IRS regulations.

Florida Power & Light Company 22
Table I.B.2: FPL's Firm Purchased Power Winter MW

I. Purchases from QF's

Cogeneration Small Power 

Production Facilities

Contract 

Start Date

Contract

End Date 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Broward South 01/01/93 12/31/26 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4

Broward South 01/01/95 12/31/26 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5

Broward South 01/01/97 12/31/26 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6

Broward North 01/01/93 12/31/26 7 7 7 7 7 7 7 7 7 7

Broward North 01/01/95 12/31/26 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5

Broward North 01/01/97 12/31/26 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5

Cedar Bay Generating Company 01/25/94 08/31/15 250 0 0 0 0 0 0 0 0 0

Indiantown Cogen L.P. 12/22/95 12/01/25 330 330 330 330 330 330 330 330 330 330

Palm Beach SWA - extension1/ 01/10/12 04/01/32 0 0 0 0 0 0 0 0 0 0

U.S.EcoGen Clay2/ 01/01/21 12/31/49 0 0 0 0 0 0 60 60 60 60

U.S.EcoGen Okeechobee2/ 01/01/21 12/31/49 0 0 0 0 0 0 60 60 60 60

U.S.EcoGen Martin2/ 01/01/21 12/31/49 0 0 0 0 0 0 60 60 60 60

595 345 345 345 345 345 525 525 525 525

II. Purchases from Utilities

Contract 

Start Date

Contract

End Date 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

UPS Replacement 06/01/10 12/31/15 928 0 0 0 0 0 0 0 0 0

SJRPP3/ 04/02/82 2nd Qtr/2019 389 389 389 389 389 0 0 0 0 0

1,317 389 389 389 389 0 0 0 0 0

1,912 734 734 734 734 345 525 525 525 525

III. Other Purchases

Contract 

Start Date

Contract

End Date 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Palm Beach SWA - Extension1/ 01/10/12 04/01/32 40 40 40 40 40 40 40 40 40 40

Palm Beach SWA - Additional 06/01/15 04/01/32 0 70 70 70 70 70 70 70 70 70

40 110 110 110 110 110 110 110 110 110

1,357 499 499 499 499 110 110 110 110 110

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

1,952 844 844 844 844 455 635 635 635 635

Summary of FPL's Firm Capacity Purchases: Winter MW (for January of Year Shown)

Winter Firm Capacity Purchases Total MW:

Other Purchases Subtotal:

Total "Non-QF" Purchases =

3/ Contract end date shown for the SJRPP purchase does not represent the actual contract end date. Instead, this date represents a projection of the earliest date at 

which FPL's ability to receive further capacity and energy from this purchase could be suspended due to IRS regulations.

QF Purchases Subtotal:

Utility Purchases Subtotal:

Total of QF and Utility Purchases =

1/ When the second unit comes into service at the Palm Beach SWA, neither unit will meet the standards to be a small power producers, and will then be accounted for 

under "Other Purchases"

2/ The EcoGen units will enter service in 2019, however firm capacity will only be delivered starting in 2021.

Florida Power & Light Company 23
I.C Demand Side Management (DSM)

FPL has sought out and implemented cost-effective DSM programs since 1978. These programs 

include a number of conservation/energy efficiency and load management initiatives. FPL’s DSM 

efforts through 2014 have resulted in a cumulative Summer peak reduction of approximately 4,793

MW at the generator and an estimated cumulative energy saving of approximately 70,997 

Gigawatt-hour (GWh) at the generator. After accounting for reserve margin requirements, FPL’s 

DSM efforts through 2014 have eliminated the need to construct the equivalent of approximately 

14 new 400 MW generating units. New DSM Goals for FPL for the 2015 through 2024 time period 

were set by the FPSC in November 2014. The new DSM Goals are discussed in Chapter III. 

Florida Power & Light Company 24
Page 1 of 2

(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12) (13) (14)

Alt. Actual/

Fuel Fuel Commercial Expected Gen.Max.

Unit Unit Fuel Transport. Days In-Service Retirement Nameplate Winter Summer

Plant Name No. Type Pri. Alt. Pri. Alt. Use Month/Year Month/Year KW MW MW

Cape Canaveral Brevard County

19/24S/36E 1,295,400 1,355 1,210

3 CC NG FO2 PL TK Unknown Apr-13 Unknown 1,295,400 1,355 1,210

DeSoto 2/ DeSoto County

27/36S/25E 25,000 25 25

1 PV Solar Solar N/A N/A Unknown Oct-09 Unknown 25,000 25 25

Fort Myers Lee County

35/43S/25E 2,653,800 2,553 2,403

2 CC NG No PL No Unknown Jun-02 Unknown 1,721,490 1,491 1,436

3 CT NG FO2 PL TK Unknown Jun-03 Unknown 188,190 352 319

1-12 GT FO2 No TK No Unknown May-74 Unknown 744,120 710 648

Lauderdale Broward County

30/50S/42E 1,873,968 1,884 1,724

4 CC NG FO2 PL PL Unknown May-93 Unknown 526,250 483 442

5 CC NG FO2 PL PL Unknown Jun-93 Unknown 526,250 483 442

1-12 GT NG FO2 PL PL Unknown Aug-70 Unknown 410,734 459 420

13-24 GT NG FO2 PL PL Unknown Aug-70 Unknown 410,734 459 420

Manatee Manatee County

18/33S/20E 2,951,110 2,871 2,761

1 ST FO6 NG WA PL Unknown Oct-76 Unknown 863,300 819 809

2 ST FO6 NG WA PL Unknown Dec-77 Unknown 863,300 819 809

3 CC NG No PL No Unknown Jun-05 Unknown 1,224,510 1,233 1,143

Martin Martin County

29/29S/38E 4,317,510 3,866 3,722

1 ST FO6 NG PL PL Unknown Dec-80 Unknown 934,500 829 823

2 ST FO6 NG PL PL Unknown Jun-81 Unknown 934,500 832 826

3 CC NG No PL No Unknown Feb-94 Unknown 612,000 489 469

4 CC NG No PL No Unknown Apr-94 Unknown 612,000 489 469

8 3/ CC NG FO2 PL TK Unknown Jun-05 Unknown 1,224,510 1,227 1,135

Port Everglades City of Hollywood

23/50S/42E 410,734 459 420

1-12 GT NG FO2 PL PL Unknown Aug-71 Unknown 410,734 459 420

Riviera Beach City of Riviera Beach

33/42S/432E 1,295,400 1,344 1,212

5 CC NG FO2 PL WA Unknown Apr-14 Unknown 1,295,400 1,344 1,212

1/ These ratings are peak capability.

2/ Approximately 46% of the 25 MW (Nameplate, AC) PV facility at DeSoto is considered as firm generating capacity for Summer reserve margin purposes

 and 0% is considered as firm capacity for Winter reserve margin purposes.

3/ Martin Unit 8 is also partially fueled by a 75 MW solar thermal facility that supplies steam when adequate sunlight is available, thus reducing 

 fossil fuel use.

Location

Schedule 1

Existing Generating Facilities

As of December 31, 2014

Net Capability 1/

Florida Power & Light Company 25
Page 2 of 2

(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12) (13) (14)

Alt. Actual/

Fuel Commercial Expected Gen.Max.

Unit Unit Fuel Transport Days In-Service Retirement Nameplate Winter Summer

Plant Name No. Location Type Pri. Alt. Pri. Alt. Use Month/Year Month/Year KW MW MW

Sanford Volusia County

16/19S/30E 2,377,720 2,200 2,010

4 CC NG No PL No Unknown Oct-03 Unknown 1,188,860 1,100 1,005

5 CC NG No PL No Unknown Jun-02 Unknown 1,188,860 1,100 1,005

Scherer 2/ Monroe, GA 680,368 651 643

4 ST SUB No RR No Unknown Jul-89 Unknown 680,368 651 643

Space Coast 3/ Brevard County

13/23S/36E 10,000 10 10

1 PV Solar Solar N/A N/A Unknown Apr-10 Unknown 10,000 10 10

St. Johns River Duval County

Power Park 4/ 12/15/28E

 (RPC4) 271,836 260 254

1 ST BIT Pet RR WA Unknown Mar-87 Unknown 135,918 130 127

2 ST BIT Pet RR WA Unknown May-88 Unknown 135,918 130 127

St. Lucie 5/ St. Lucie County

16/36S/41E 1,743,775 1,863 1,821

1 ST Nuc No TK No Unknown May-76 Unknown 1,020,000 1,003 981

2 ST Nuc No TK No Unknown Jun-83 Unknown 723,775 860 840

Turkey Point Miami Dade County

27/57S/40E 3,380,960 3,322 3,220

1 ST FO6 NG WA PL Unknown Apr-67 Unknown 402,050 398 396

3 ST Nuc No TK No Unknown Nov-72 Unknown 877,200 839 811

4 ST Nuc No TK No Unknown Jun-73 Unknown 877,200 848 821

5 CC NG FO2 PL TK Unknown May-07 Unknown 1,224,510 1,237 1,192

West County Palm Beach County 

29&32/43S/40E 4,100,400 4,005 3,657

1 CC NG FO2 PL TK Unknown Aug-09 Unknown 1,366,800 1,335 1,219

2 CC NG FO2 PL TK Unknown Nov-09 Unknown 1,366,800 1,335 1,219

3 CC NG FO2 PL TK Unknown May-11 Unknown 1,366,800 1,335 1,219

Total System Generating Capacity as of December 31, 2014 6/ = 26,668 25,092

 System Firm Generating Capacity as of December 31, 2014 7/ = 26,633 25,072

1/ These ratings are peak capability.

2/ These ratings relate to FPL's 76.36% share of Plant Scherer Unit 4 operated by Georgia Power, and represent FPL's 73.923% owernership share available

 at point of interchange.

3/ Approximately 32% of the 10 MW (Nameplate, AC) PV facility at Space Coast is considered as firm generating capacity for Summer reserve margin purposes

 and 0% is considered as firm capacity for Winter reserve margin purposes.

4/ The net capability ratings represent Florida Power & Light Company's share of St. Johns River Park Units 1 and 2, excluding the

 Jacksonville Electric Authority (JEA) share of 80%.

5/ Total capability of St. Lucie 1 is 981/1,003 MW. FPL's share of St. Lucie 2 is 840/860.FPL's ownership share of St. Lucie Units 1 and 2

 is 100% and 85%, respectively, as shown above. FPL's share of the deliverable capacity from each unit is approx. 92.5% and exclude the 

 Orlando Utilities Commission (OUC) and Florida Municipal Power Agency (FMPA) combined portion of approximately 7.448% per unit.

6/ The Total System Generating Capacity value shown includes FPL-owned firm and non-firm generating capacity.

7/ The System Firm Generating Capacity value shown includes only firm generating capacity.

Fuel 

Existing Generating Facilities

As of December 31, 2014

Net Capability 1/

Schedule 1

Florida Power & Light Company 26
CHAPTER II

Forecast of Electric Power Demand

Florida Power & Light Company 27
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Florida Power & Light Company 28
II. Forecast of Electric Power Demand

II. A. Overview of the Load Forecasting Process

At FPL, long-term forecasts of sales, net energy for load (NEL), and peak loads typically are 

developed on an annual basis for resource planning work. FPL developed new long-term 

forecasts in late 2014 that replaced the previous long-term load forecasts used by FPL during 

2014 in much of its resource planning work and which were presented in FPL’s 2014 Site Plan. 

These new load forecasts are utilized throughout FPL’s 2015 Site Plan and are a key input to the 

models used to develop FPL’s integrated resource plan. 

The following pages describe how forecasts are developed for each component of the long-term 

forecast including: sales, NEL, and peak loads. Consistent with past forecasts, the primary drivers 

to develop these forecasts include economic conditions and weather.

The projections for the national and Florida economies are obtained from IHS Global Insight, a 

leading economic forecasting firm. Population projections are obtained from the Florida 

Legislature’s Office of Economic and Demographic Research (EDR). These projections are 

developed in conjunction with the Bureau of Economic and Business Research (BEBR) of the 

University of Florida. These inputs are quantified and qualified using statistical models in terms of 

their impact on the future demand for electricity. 

Weather is always a key factor that affects FPL’s energy sales and peak demand. Three sets of 

weather variables are developed and used in FPL’s forecasting models::

1. Cooling degree-hours based on 72o F, winter heating degree-days based on 66o F, and 

heating degree-days based on 45o F are used to forecast energy sales.

2. The maximum temperature on the peak day and the build-up of cooling degree-hours prior 

to the peak are used to forecast Summer peaks.

3. The minimum temperature on the peak day and the build-up of heating degree-hours 

based on 66o F on the morning of the peak are used to forecast Winter peaks.

The cooling degree-hours and winter heating degree-days are used to capture the changes in the 

electric usage of weather-sensitive appliances such as air conditioners and electric space heaters. 

Heating degree-days based on 45o F are used to capture heating load resulting from sustained 

periods of unusually cold weather that are not fully captured by heating degree-days based on 66o 

F. A composite hourly temperature profile is derived using hourly temperatures across FPL’s 

service territory. Miami, Ft. Myers, Daytona Beach, and West Palm Beach are the locations where 

temperatures are obtained. In developing the composite hourly profile, these regional 

Florida Power & Light Company 29
temperatures are weighted by regional energy sales. The resulting composite temperature is used 

to derive projected cooling and heating degree-hours and heating degree-days. Similarly, 

composite temperature and hourly profiles of temperatures are used to calculate the weather 

variables used in the Summer and Winter peak models.

II. B. Comparison of FPL’s Current and Previous Load Forecasts

While reflecting some fluctuations by year, FPL’s current load forecast is generally in line with the 

load forecast previously presented in its 2014 Site Plan. Three primary factors drive the current 

load forecast: projected population growth, the performance of Florida’s economy, and energy 

efficiency codes and standards. An additional fourth factor, which represents a change in 

assumptions from the 2014 Site Plan, pertains to FPL’s previously planned acquisition of the City 

of Vero Beach’s electric system.

In early 2013, FPL came to an agreement with the City of Vero Beach to purchase the City’s 

electric system. This agreement was approved by the City’s voters on March 12, 2013. FPL 

projected in its 2014 Site Plan that it would begin serving Vero Beach’s electric load in January 

2015. Accordingly, NEL, customers, and peaks for Vero Beach from 2015 through 2023 were 

included in FPL’s load forecasts in its 2014 Site Plan. However, lack of progress among 

negotiating parties has resulted in uncertainty regarding whether FPL will provide, or when it can 

begin providing, Vero Beach’s electric load. As a result, FPL’s current load forecast does not 

include electric service to Vero Beach. 

The customer forecast is based on recent population projections as well as the actual levels of 

customer growth experienced historically. Population projections are derived from the EDR’s July 

2014 Demographic Estimating Conference. This forecast is generally consistent with previous 

forecasts indicating steady growth in Florida’s population. On a percentage basis, the projected 

rates of population growth are expected to be somewhat below the state’s long-term historical 

averages. However, the absolute increases in population are projected to be significant. The 

state’s population is expected to reach 20 million by 2016 and exceed 22 million by 2023. Overall, 

the state’s population is expected to increase by approximately three million between 2014 and 

2024. 

FPL customer growth is expected to mirror the overall level of population growth in the state. 

From 2014 through 2024 the total number of customers is projected to increase at an annual rate 

of 1.3% resulting in a cumulative increase of more than 670,000 customers. By 2019, the total 

number of customers served by FPL is expected to exceed five million. By 2024, the total number 

of FPL customers is expected to reach approximately 5.4 million.

Florida Power & Light Company 30
The economic projections incorporated into FPL’s load forecast are provided by IHS Global 

Insight. IHS Global Insight projects solid growth in the Florida economy with relatively healthy 

increases in employment and income levels from 2015 through 2019. This firm projects 

particularly robust growth for the professional and business services, trade, tourism, and 

healthcare industries. Consistent with past projections, economic growth in the later years of the 

forecast is expected to moderate slightly.

Estimates of savings from energy efficiency codes and standards are developed by ITRON, a 

leading expert in this field. These estimates include savings from federal and state energy 

efficiency codes and standards, including the 2005 National Energy Policy Act, the 2007 Energy 

Independence and Security Act, and the savings resulting from the use of compact fluorescent 

bulbs and light-emitting diodes (LEDs)2

. The impact of these savings began in 2005 and their 

cumulative impact on the Summer peak is expected to reach 3,568 MW by 2024, the equivalent of 

an approximately 12% reduction in what the forecasted Summer peak load for 2024 would have 

been without these codes and standards. The cumulative impact on NEL from these savings is 

expected to reach 11,405 GWH over the same period while the cumulative impact on the Winter 

peak is expected to be 2,022 MW by 2024. This represents a decrease of approximately 8% in the 

forecasted NEL for 2024 and an 8% reduction in forecasted Winter peak load for 2024. 

Consistent with the forecast presented in FPL’s 2014 Site Plan, the total growth projected for the 

ten-year reporting period of this document is significant. The Summer peak is projected to 

increase to 26,771 MW by 2024, an increase of 3,836 MW over the 2014 actual Summer peak. 

Likewise, NEL is projected to reach 133,276 GWH in 2024, an increase of 17,308 GWH from the 

actual 2014 value.

II.C. Long-Term Sales Forecasts

Long-term forecasts of electricity sales were developed for the major revenue classes and are 

adjusted to match the NEL forecast. The results of these sales forecasts for the years 2015 

through 2024 are presented in Schedules 2.1 - 2.3 that appear at the end of this chapter. 

Econometric models are developed for each revenue class using the statistical software package 

MetrixND. The methodologies used to develop energy sales forecasts for each jurisdictional 

revenue class and NEL forecast are outlined below.

2

 Note that in addition to the fact that these energy efficiency codes and standards lower the forecasted load, these standards also 

lower the potential for efficiency gains that would otherwise be available through utility DSM programs.

Florida Power & Light Company 31

 
1. Residential Sales

Residential electric usage per customer is estimated by using an econometric model. 

Residential sales are a function of the following variables: cooling degree-hours, winter 

heating degree-days, twelve-month average Consumer Price Index for Energy, and Florida 

real per capita income weighted by the percent of the population that is employed. The impact 

of weather is captured by the cooling degree-hours and winter heating degree-days. The 

impact energy prices have on electricity consumption is captured through the Consumer Price 

Index for Energy variable. As energy prices rise, less disposable income is available for all 

goods and services, including electricity. To capture economic conditions, the model includes 

a composite variable based on Florida real per capita income and the percent of the state’s 

population that is employed. Residential energy sales are forecasted by multiplying the 

projected residential use per customer by the projected number of residential customers. 

2. Commercial Sales 

The commercial sales forecast is also developed using econometric models. The commercial 

class is forecast using three separate models, based on customer size, including: small 

accounts (less than 20 kW of demand), medium accounts (21 kW to 499 kW of demand), and 

large accounts (demand of 500 kW or higher). Commercial sales are driven by economic and 

weather variables. Specifically, the small commercial sales model utilizes the following 

variables: Florida real per capita income weighted by the percent of the population that is 

employed, cooling degree-hours, heating degree-hours, lagged cooling degree-hours, the 

Consumer Price Index, dummy variables for the month of December and for the specific 

months of January 2007 and November 2005, and an autoregressive term. The medium 

commercial sales model utilizes the same variables as the small commercial model with the 

exception of a January heating degree-day term rather than the heating degree-hours term. 

The large commercial sales model utilizes the following variables: Florida real per capita 

income, cooling degree-hours, heating degree-hours, lagged cooling degree-hours, dummy 

variables for the month of December and for the specific months of January 2007 and 

November 2005, and an autoregressive term. Cooling degree-hours, heating degree-hours, 

and the one-month lag of cooling degree-hours are used to capture weather-sensitive load in 

the commercial sector.

3. Industrial Sales

Like the commercial class, the industrial class is forecast using three separate models, based 

on customer size. The industrial class is comprised of three distinct groups: small accounts 

(less than 20 kW of demand), medium accounts (21 kW to 499 kW of demand), and large 

accounts (demands of 500 kW or higher). The small industrial sales model utilizes the 

Florida Power & Light Company 32
following variables: Florida real household disposable income, cooling degree-hours, heating 

degree-hours, and autoregressive terms. The medium industrial sales model utilizes the 

following variables: Florida real Gross State Product, the Consumer Price Index, cooling 

degree-hours, January heating degree-days, dummy variables for the specific months of 

February 2005 and November 2005, and autoregressive terms. The large industrial sales 

model utilizes the following variables: cooling degree-hours, Florida Gross State Product for 

manufacturing, the Consumer Price Index, the employee to population ratio, and dummy 

variables for the specific months of October 2004 and November 2004.

4. Railroad and Railways Sales and Street and Highway Sales

This class consists solely of Miami-Dade County’s Metrorail system. The projections for 

railroad and railways sales are based on a historical moving average.

The forecast for street and highway sales is developed by first developing a trended use per 

customer value, then multiplying this value by the number of forecasted customers. 

5. Other Public Authority Sales

This class consists of a sports field rate schedule, which is closed to new customers, and one 

government account. The forecast for this class is based on its historical usage 

characteristics.

6. Total Sales to Ultimate Customer

Sales forecasts by revenue class are summed to produce a total sales forecast.

7. Sales for Resale

Sales for resale (wholesale) customers are composed of municipalities and/or electric cooperatives. These customers differ from jurisdictional customers in that they are not the 

ultimate users of the electricity they buy. Instead, they resell this electricity to their own 

customers. There are currently seven customers in this class: Florida Keys Electric 

Cooperative, Lee County Electric Cooperative, New Smyrna Beach, Wauchula, Winter Park, 

Blountstown, and Seminole Electric Cooperative3

.

Beginning in May 2011, FPL began providing service to the Florida Keys Electric Cooperative 

under a long-term full requirements contract. FPL previously served the Florida Keys under a 

3 FPL continues to evaluate the possibility of serving the electrical loads of other entities at the time this Site Plan is being prepared. 

Because these possibilities are still being evaluated, the load forecast presented in this Site Plan does not include these potential 

loads.

Florida Power & Light Company 33

 
partial requirements contract. The sales to Florida Keys Electric Cooperative are based on 

customer-supplied information and historical coincidence factors.

Lee County contracted with FPL for FPL to supply a portion of the Lee County load through 

2013, then to serve the entire Lee County load beginning in 2014. This contract began in 

January 2010. Forecasted NEL for Lee County is based on an econometric model utilizing the 

following variables: cooling and heating degree-hours, January heating degree-days, real 

disposable household income, and autoregressive terms.

FPL sales to New Smyrna Beach began in February 2014 and will continue through 

December 2017.

FPL’s sales to Wauchula began in October 2011 and will continue through December 2016.

Sales to Winter Park began in January 2014 and will continue through December 2016.

Blountstown became an FPL wholesale customer in May 2012 under a contract that expires in 

April 2017.

FPL sales to Seminole Electric Cooperative are based on delivery of 200 MW that began in 

June 2014 and continues through May 2021.

II.D. Net Energy for Load (NEL)

An econometric model is developed to produce a NEL per customer forecast. The inputs to the 

model include Florida real per capita income weighted by the percent of the population that is 

employed, and a proxy for energy prices. The model also includes several weather variables 

including cooling degree-hours and heating degree-days by calendar month, and heating degreedays based on 45o F. In addition, the model also includes a variable for energy efficiency codes 

and standards. A dummy variable is included for the specific month of November 2005. There are 

also two autoregressive terms in the model.

The energy efficiency variable is included to capture the impacts from major codes and standards, 

including those associated with the 2005 National Energy Policy Act, the 2007 Energy 

Independence and Security Act, and savings resulting from the use of compact fluorescent bulbs 

and LEDs. The estimated impact from these codes and standards includes engineering estimates 

and any resulting behavioral changes. The impact of these savings began in 2005 and their 

cumulative impact on NEL is expected to reach 11,405 GWH by 2024. This represents an 

approximately 8% reduction in what the forecasted NEL for 2024 would have been absence these 

Florida Power & Light Company 34
codes and standards. From the end of 2014, the incremental reduction through 2024 is expected 

to be 6,808 GWH. An additional adjustment is made due to the impact of incremental distributed 

generation not otherwise included in the forecast. The adjustment to the forecast due to 

distributed generation begins in 2014 and is expected to reduce the NEL forecast by 444 GWH by 

2024. 

The forecast was also adjusted for the additional load estimated from hybrid vehicles, beginning in 

2014, which resulted in an increase of approximately 616 GWH by the end of the ten-year 

reporting period. The forecast was further adjusted for the incremental load resulting from FPL’s 

economic development riders which began in 2014 and this incremental load is projected to grow 

to 242 GWH before leveling off in 2020

The NEL forecast is developed by first multiplying the NEL per customer forecast by the projected 

total number of customers and then adjusting the forecasted results for the expected changes in 

load resulting from hybrid vehicles, new wholesale contracts, distributed generation, and FPL’s 

economic development riders. Once the NEL forecast is determined, total billed sales are 

computed using a historical ratio of sales to NEL. The sales by class forecasts discussed

previously are then adjusted to match the total billed sales. The forecasted NEL values for 2015 

through 2024 are presented in Schedule 3.3 which appears at the end of this chapter. 

II.E. System Peak Forecasts

The rate of absolute growth in FPL system peak load has been a function of the size of the 

customer base, varying weather conditions, projected economic conditions, changing patterns of 

customer behavior, and more efficient appliances and lighting. FPL developed the peak forecast 

models to capture these behavioral relationships. In addition, FPL’s peak forecast also reflects 

changes in load expected as a result of changes in wholesale contracts, distributed generation, 

and the expected number of hybrid vehicles. 

The savings from energy efficiency codes and standards incorporated into the peak forecast 

include the impacts from the 2005 National Energy Policy Act, the 2007 Energy Independence and 

Security Act, and the use of compact fluorescent light bulbs and LEDs. The impact from these 

energy efficiency standards began in 2005 and their cumulative impact on the Summer peak is 

expected to reach 3,568 MW by 2024. This reduction includes engineering estimates and any 

resulting behavioral changes. This reduction also represents significant energy efficiency that is 

not funded by FPL’s customers through the Energy Conservation Cost Recovery Clause. 

The cumulative 2024 impact from these energy efficiency codes and standards effectively reduces 

FPL’s Summer peak for that year by approximately 12%. From the end of 2014, the projected 

Florida Power & Light Company 35
incremental impact on the Summer peak from these energy efficiency codes and standards is 

projected to be a reduction of 2,035 MW through 2024. By 2024, the Winter peak is expected to 

be reduced by 2,022 MW as result of the cumulative impact from these energy efficiency 

standards since 2005. On an incremental basis, net of the reduction already experienced through 

2014, the impact on the Winter peak from these energy efficiency standards is expected to reach 

1,321 MW in 2024.

The forecast also was adjusted for additional load estimated from hybrid vehicles which is 

projected to be an increase of approximately 173 MW in the Summer and 86 MW in the Winter by 

the end of the ten-year reporting period. The incremental impact of distributed generation results 

in an expected decrease of approximately 105 MW in the Summer and a negligible reduction in 

the Winter by the end of the ten-year reporting period. The incremental impact from distributed 

generation is based on forecasted increases in rooftop photovoltaic (PV) installations not 

otherwise reflected in the load forecast. The ratio of the expected Summer Peak MW reduction 

relative to the installed nameplate MW (DC) capacity is appropriately 34% for residential PV 

installations and appropriately 37% for commercial PV installations. The ratio of the expected 

Winter Peak MW reduction to installed nameplate MW (DC) capacity is close to 0% for both 

residential and commercial PV installations. 

The forecasting methodology of Summer, Winter, and monthly system peaks is discussed below. 

The forecasted values for Summer and Winter peak loads for the years 2015 through 2024 are 

presented at the end of this chapter in Schedules 3.1 and 3.2, and in Chapter III in Schedules 7.1 

and 7.2. 

1. System Summer Peak

The Summer peak forecast is developed using an econometric model. The variables included 

in the model are the price of gasoline (lagged one month), Florida real household disposable 

income, cooling degree-hours two days prior to the peak day, the maximum temperature on 

the day of the peak, a variable for energy efficiency standards, and a dummy variable for the 

year 1990. The model is based on the Summer peak contribution per customer which is 

multiplied by total customers. This product is then adjusted to account for the expected 

changes in loads resulting from hybrid vehicles, new wholesale contracts, distributed 

generation, and FPL’s economic development riders to derive FPL’s system Summer peak.

2. System Winter Peak

Like the system Summer peak model, this model also is an econometric model. The model 

consists of two weather-related variables: the minimum temperature on the peak day and 

heating degree-hours for the prior day squared. The model also includes two dummy 

Florida Power & Light Company 36
variables; one for Winter peaks occurring on weekends and one for the year 1994. Also 

included in the model are a variable for housing starts per capita, and an autoregressive term. 

The forecasted results are adjusted for the impact of energy efficiency standards. The model

is based on the Winter peak contribution per customer which is multiplied by the total number 

of customers. This product then is adjusted for the expected changes in loads resulting from 

hybrid vehicles, new wholesale contracts, distributed generation, and FPL’s economic 

development riders.

3. Monthly Peak Forecasts

The forecasting process for monthly peaks consists of the following steps:

a. The forecasted annual summer peak is assumed to occur in the month of August which 

historically has accounted for more annual summer peaks than any other month.

b. The forecasted annual winter peak is assumed to occur in the month of January which 

historically has accounted for more annual winter peaks than any other month.

c. The remaining monthly peaks are forecasted based on the historical relationship between 

the monthly peaks and the annual summer peak. 

II.F. Hourly Load Forecast

Forecasted values for system hourly load for the period 2015 through 2024 are produced using a 

System Load Forecasting “shaper” program. This model uses years of historical FPL hourly 

system load data to develop load shapes for weekdays, weekend days, and holidays. The model 

generates a projection of hourly load values based on these load shapes and the forecast of 

monthly peaks and energy.

II.G. Uncertainty

Uncertainty is inherent in the load forecasting process. This uncertainty can result from a number 

of factors, including unexpected changes in consumer behavior, structural shifts in the economy, 

and fluctuating weather conditions. Large weather fluctuations, in particular, can result in 

significant deviations between actual and forecasted peak demands. The load forecast is based 

on average expected or normal weather conditions; i.e. a 50% probability (or P50) forecast. An 

extreme P90 cold weather event, however, can add an additional 3,000 MW to the Winter Peak 

and an extreme P90 hot weather event can add an additional 800 MW to the Summer Peak.

Florida Power & Light Company 37
In order to address uncertainty in the forecasts of aggregate peak demand and NEL, FPL first 

evaluates the assumptions underlying the forecasts. FPL takes a series of steps in evaluating the 

input variables, including comparing projections from different sources, identifying outliers in the 

series, and assessing the series’ consistency with past forecasts. As needed, FPL reviews

additional factors that may affect the input variables. 

Uncertainty is also addressed in the modeling process. Econometric models generally are used to 

forecast the aggregate peak demand and NEL. During the modeling process, the relevant 

statistics (goodness of fit, F-statistic, P-values, mean absolute deviation (MAD), mean absolute 

percentage error (MAPE), etc.) are scrutinized to ensure the models adequately explain historical 

variation. Once a forecast is developed, it is compared with past forecasts. Deviations from past 

forecasts are examined in light of changes in input assumptions to ensure that the drivers 

underlying the forecast are well understood. Finally, forecasts of aggregate peak demand and 

NEL are compared with the actual values as these become available. An ongoing process of 

variance analyses is performed. To the extent that the variance analyses identify large 

unexplained deviations between the forecast and actual values, revisions to the econometric 

model may be considered. 

The inherent uncertainty in load forecasting is addressed in different ways in regard to FPL’s 

overall resource planning and operational planning work. In regard to FPL’s resource planning 

work, FPL’s utilization of a 20% total reserve margin criterion, a Loss-of-Load-Probability (LOLP) 

criterion of 0.1, and a 10% generation-only reserve margin criterion, are designed to maintain 

reliable electric service for FPL’s customers in light of forecasting (and other) uncertainty. In 

addition, banded forecasts of the projected Summer peak and net energy for load are produced 

based on an analysis of past forecasting variances. In regard to operational planning, a banded 

forecast for the projected Summer and Winter peak days is developed based on historical weather 

variations. These bands are then used to develop similar bands for the monthly peaks.

II.H. DSM 

The effects of FPL’s DSM energy efficiency programs implementation through August 2014 are 

assumed to be embedded in the actual usage data for forecasting purposes. The following are 

accounted for as “line item reductions” to the forecasts as part of the IRP process: the impacts of 

incremental energy efficiency that FPL has implemented in the September 2014 through 

December 2014 time period, incremental energy efficiency that FPL plans to implement in the 

future based on the new DSM Goals set for FPL by the FPSC in November 2014, and the 

cumulative and projected incremental impacts of FPL’s load management programs. After making

these adjustments to the load forecasts, the resulting “firm” load forecast is then used in FPL’s IRP 

work as shown in Chapter III in Schedules 7.1 and 7.2.

Florida Power & Light Company 38
 

(1) (2) (3) (4) (5) (6) (7) (8) (9)

Members Average Average kWh Average Average kWh

per No. of Consumption No. of Consumption

Year Population Household GWh Customers Per Customer GWh Customers Per Customer

2005 8,469,602 2.21 54,348 3,828,374 14,196 43,468 469,973 92,490

2006 8,620,855 2.21 54,570 3,906,267 13,970 44,487 478,867 92,901

2007 8,729,806 2.19 55,138 3,981,451 13,849 45,921 493,130 93,121

2008 8,771,694 2.20 53,229 3,992,257 13,333 45,561 500,748 90,987

2009 8,732,591 2.19 53,950 3,984,490 13,540 45,025 501,055 89,860

2010 8,762,399 2.19 56,343 4,004,366 14,070 44,544 503,529 88,464

2011 8,860,158 2.20 54,642 4,026,760 13,570 45,052 508,005 88,685

2012 8,948,850 2.21 53,434 4,052,174 13,187 45,220 511,887 88,340

2013 9,025,275 2.20 53,930 4,097,172 13,163 45,341 516,500 87,786

2014 9,122,932 2.19 55,202 4,169,028 13,241 45,684 525,591 86,919

Historical Values (2005 - 2014):

Col. (2) represents population only in the area served by FPL. 

Col. (4) and Col. (7) represent actual energy sales including the impacts of existing conservation. 

These values are at the meter.

Col. (5) and Col. (8) represent the annual average of the twelve monthly values.

(1) (2) (3) (4) (5) (6) (7) (8) (9)

Members Average Average kWh Average Average kWh

per No. of Consumption No. of Consumption

Year Population Household GWh Customers Per Customer GWh Customers Per Customer

2015 9,306,139 2.20 57,634 4,230,063 13,625 45,958 532,023 86,384

2016 9,445,807 2.20 59,347 4,293,549 13,822 46,694 538,297 86,743

2017 9,586,474 2.20 60,613 4,357,488 13,910 47,162 544,230 86,659

2018 9,726,794 2.20 61,841 4,421,270 13,987 47,649 549,723 86,678

2019 9,866,497 2.20 62,967 4,484,771 14,040 48,078 554,918 86,640

2020 10,003,258 2.20 64,192 4,546,935 14,118 48,560 559,848 86,737

2021 10,137,730 2.20 65,090 4,608,059 14,125 48,581 564,581 86,048

2022 10,269,789 2.20 65,922 4,668,086 14,122 48,861 569,300 85,826

2023 10,400,493 2.20 66,903 4,727,497 14,152 49,225 573,828 85,784

2024 10,530,845 2.20 68,082 4,786,748 14,223 49,741 578,049 86,050

Projected Values (2015 - 2024):

Col. (2) represents population only in the area served by FPL. 

Col. (4) and Col. (7) represent forecasted energy sales that do not include the impact of incremental conservation. 

These values are at the meter.

Col. (5) and Col. (8) represent the annual average of the twelve monthly values.

Schedule 2.1

History of Energy Consumption

And Number of Customers by Customer Class

And Number of Customers by Customer Class

Rural & Residential Commercial

Rural & Residential Commercial

Forecast of Energy Consumption

Schedule 2.1

Florida Power & Light Company 39
 

(1) (10) (11) (12) (13) (14) (15) (16)

Railroads Street & Sales to Sales to

Average Average kWh & Highway Public Ultimate

No. of Consumption Railways Lighting Authorities Consumers

Year GWh Customers Per Customer GWh GWh GWh GWh 

2005 3,913 20,392 191,873 95 424 49 102,296

2006 4,036 21,211 190,277 94 422 49 103,659

2007 3,774 18,732 201,499 91 437 53 105,415

2008 3,587 13,377 268,168 81 423 37 102,919

2009 3,245 10,084 321,796 80 422 34 102,755

2010 3,130 8,910 351,318 81 431 28 104,557

2011 3,086 8,691 355,104 82 437 27 103,327

2012 3,024 8,743 345,871 81 441 25 102,226

2013 2,956 9,541 309,772 88 442 28 102,784

2014 2,941 10,415 282,398 91 446 24 104,389

Historical Values (2005 - 2014):

Col. (10) and Col.(15) represent actual energy sales including the impacts of existing 

conservation. These values are at the meter.

Col. (11) represents the annual average of the twelve monthly values.

Col. (16) = Col. (4) + Col. (7) + Col. (10) + Col. (13) + Col. (14) + Col. (15).

(1) (10) (11) (12) (13) (14) (15) (16)

Industrial Railroads Street & Sales to Sales to

Average Average kWh & Highway Public Ultimate

No. of Consumption Railways Lighting Authorities Consumers

Year GWh Customers Per Customer GWh GWh GWh GWh 

2015 2,929 11,265 260,033 91 461 22 107,096

2016 2,932 12,542 233,811 91 468 22 109,554

2017 2,914 13,496 215,931 91 473 22 111,275

2018 2,871 13,792 208,152 91 479 22 112,952

2019 2,820 13,687 206,006 91 483 22 114,461

2020 2,763 13,594 203,246 91 488 22 116,115

2021 2,696 13,455 200,356 91 492 22 116,971

2022 2,634 13,316 197,791 91 496 22 118,025

2023 2,566 13,138 195,327 91 499 22 119,307

2024 2,493 12,849 193,999 91 503 22 120,931

Projected Values (2015 - 2024):

Col. (10) and Col.(15) represent forecasted energy sales that do not include the impact 

of incremental conservation. These values are at the meter.

Col. (11) represents the annual average of the twelve monthly values.

Col. (16) = Col. (4) + Col. (7) + Col. (10) + Col. (13) + Col. (14) + Col. (15).

Schedule 2.2

History of Energy Consumption

And Number of Customers by Customer Class

Schedule 2.2

Industrial

And Number of Customers by Customer Class

Forecast of Energy Consumption

Florida Power & Light Company 40
 

(1) (17) (18) (19) (20) (21)

Utility Net Average 

Sales for Use & Energy No. of Total Average 

Resale Losses For Load Other Number of

Year GWh GWh GWh Customers Customers

2005 1,506 7,498 111,301 3,156 4,321,895

2006 1,569 7,909 113,137 3,218 4,409,563

2007 1,499 7,401 114,315 3,276 4,496,589

2008 993 7,092 111,004 3,348 4,509,730

2009 1,155 7,394 111,303 3,439 4,499,067

2010 2,049 7,870 114,475 3,523 4,520,328

2011 2,176 6,950 112,454 3,596 4,547,051

2012 2,237 6,403 110,866 3,645 4,576,449

2013 2,158 6,713 111,655 3,722 4,626,934

2014 5,375 6,204 115,968 3,795 4,708,829

Historical Values (2005 - 2014):

Col. (19) represents actual energy sales including the impacts of existing conservation. 

Col. (19) = Col. (16) + Col. (17) + Col. (18). Historical NEL includes the impacts of existing 

conservation and agrees to Col. (5) on schedule 3.3. Historical GWH, prior to 2011, are 

based on a fiscal year beginning 12/29 and ending 12/28. The 2011 value is based on

12/29/10 to 12/31/11. The 2012-2014 values are based on calendar year.

Col. (20) represents the annual average of the twelve monthly values.

Col. (21) = Col. (5) + Col. (8) + Col. (11) + Col. (20).

(1) (17) (18) (19) (20) (21)

Utility Net Average

Sales for Use & Energy No. of Total Average

Resale Losses For Load Other Number of

Year GWh GWh GWh Customers Customers

2015 6,021 6,595 119,713 3,858 4,777,210

2016 6,126 6,727 122,407 3,906 4,848,294

2017 5,882 6,788 123,946 3,947 4,919,162

2018 5,629 6,852 125,433 3,987 4,988,771

2019 5,659 6,950 127,070 4,024 5,057,400

2020 5,700 7,036 128,851 4,058 5,124,436

2021 5,256 7,011 129,237 4,090 5,190,185

2022 4,955 7,097 130,077 4,118 5,254,820

2023 5,013 7,176 131,495 4,145 5,318,608

2024 5,073 7,271 133,276 4,170 5,381,815

Projected Values (2015 - 2024):

Col. (19) represents forecasted energy sales that do not include the impact of incremental 

conservation and agrees to Col. (2) on Schedule 3.3.

Col. (19) = Col. (16) + Col. (17) + Col. (18). These values are based on calendar year.

Col. (20) represents the annual average of the twelve monthly values.

Col. (21) = Col. (5) + Col. (8) + Col. (11) + Col. (20).

Schedule 2.3

History of Energy Consumption

And Number of Customers by Customer Class

Schedule 2.3

Forecast of Energy Consumption

And Number of Customers by Customer Class

Florida Power & Light Company 41
(1) (2) (3) (4) (5) (6) (7) (8) (9) (10)

Res. Load Residential C/I Load C/I Net Firm

Year Total Wholesale Retail Interruptible Management Conservation Management Conservation Demand

2005 22,361 264 22,097 0 902 895 600 611 20,858

2006 21,819 256 21,563 0 928 948 635 640 20,256

2007 21,962 261 21,701 0 952 982 716 683 20,295

2008 21,060 181 20,879 0 966 1,042 760 706 19,334

2009 22,351 249 22,102 0 981 1,097 811 732 20,558

2010 22,256 419 21,837 0 990 1,181 815 758 20,451

2011 21,619 427 21,192 0 1,000 1,281 821 781 19,798

2012 21,440 431 21,009 0 1,013 1,351 833 810 19,594

2013 21,576 396 21,180 0 1,025 1,394 833 827 19,718

2014 22,935 955 21,980 0 1,010 1,444 843 840 21,082

Historical Values (2005 - 2014):

Col. (2) - Col. (4) are actual values for historical Summer peaks. As such, they incorporate the effects of conservation (Col. 7 & Col. 9), and may

incorporate the effects of load control if load control was operated on these peak days. Therefore, Col. (2) represents the actual Net Firm Demand.

Col. (5) - Col. (9) represent actual DSM capabilities starting from January 1988 and are annual (12-month) values except for 2014 values which are

 through August. 

Col. (10) represents a HYPOTHETICAL "Net Firm Demand" as if the load control values had definitely been exercised on the peak. Col. (10) is 

derived by the formula: Col. (10) = Col.(2) - Col.(6) - Col.(8).

(1) (2) (3) (4) (5) (6) (7) (8) (9) (10)

August of Res. Load Residential C/I Load C/I Net Firm

Year Total Wholesale Retail Interruptible Management* Conservation Management* Conservation Demand

2015 23,286 1,231 22,054 0 1,020 46 862 25 21,334

2016 23,778 1,240 22,538 0 1,030 60 873 37 21,778

2017 24,252 1,186 23,066 0 1,040 71 885 50 22,206

2018 24,648 1,145 23,502 0 1,051 82 897 63 22,555

2019 25,045 1,149 23,896 0 1,061 94 909 77 22,904

2020 25,369 1,150 24,219 0 1,071 106 920 91 23,181

2021 25,497 953 24,544 0 1,082 118 932 106 23,260

2022 25,833 957 24,875 0 1,092 131 944 121 23,545

2023 26,286 965 25,321 0 1,102 144 956 136 23,948

2024 26,771 972 25,798 0 1,113 157 968 152 24,381

Projected Values (2015 - 2024):

Col. (2) - Col. (4) represent FPL's forecasted peak and does not include incremental conservation, cumulative load management, or 

incremental load management.

Col. (5) - Col. (9) represent cumulative load management, and incremental conservation and load management. All values are projected August 

values. 

Col. (8) represents FPL's Business On Call, CDR, CILC, and Curtailable programs/rates.

Col. (10) represents a 'Net Firm Demand" which accounts for all of the incremental conservation and assumes all of the load control is 

implemented on the peak. Col. (10) is derived by using the formula: Col. (10) = Col. (2) - Col. (5) - Col. (6) - Col. (7) - Col. (8) - Col. (9).

* Res. Load Management and C/I Load Management include MW values of load management from Lee County and FKEC.

Schedule 3.1

Forecast of Summer Peak Demand (MW)

Schedule 3.1

History of Summer Peak Demand (MW)

Florida Power & Light Company 42
(1) (2) (3) (4) (5) (6) (7) (8) (9) (10)

Firm Res. Load Residential C/I Load C/I Net Firm

 Year Total Wholesale Retail Interruptible Management Conservation Management Conservation Demand

2005 18,108 225 17,883 0 816 583 542 233 16,751

2006 19,683 225 19,458 0 823 600 550 240 18,311

2007 16,815 223 16,592 0 846 620 577 249 15,392

2008 18,055 163 17,892 0 868 644 636 279 16,551

2009 20,081 207 19,874 0 881 666 676 285 18,524

2010 24,346 500 23,846 0 895 687 721 291 22,730

2011 21,126 383 20,743 0 903 717 723 303 19,501

2012 17,934 382 17,552 0 856 755 722 314 16,356

2013 15,931 348 15,583 0 843 781 567 326 14,521

2014 17,500 890 16,610 0 768 805 590 337 16,142

Historical Values (2005 - 2014):

Col. (2) - Col. (4) are actual values for historical Winter peaks. As such, they incorporate the effects of conservation (Col. 7 & Col. 9), and may

incorporate the effects of load control if load control was operated on these peak days. Therefore, Col. (2) represents the actual Net Firm Demand.

For year 2011, the actual peaked occurred in December of 2010.

Col. (5) - Col. (9) for 2005 through 2014 represent actual DSM capabilities starting from January 1988 and are annual (12-month) values.

Col. (10) represents a HYPOTHETICAL "Net Firm Demand" as if the load control values had definitely been exercised on the peak. Col. (10) is 

derived by the formula: Col. (10) = Col.(2) - Col.(6) - Col.(8).

(1) (2) (3) (4) (5) (6) (7) (8) (9) (10)

January of Firm Res. Load Residential C/I Load C/I Net Firm

 Year Total Wholesale Retail Interruptible Management* Conservation Management* Conservation Demand

2015 21,136 1,195 19,941 841 12 593 5 19,684

2016 21,369 1,206 20,163 850 24 598 11 19,886

2017 21,485 1,151 20,334 858 28 603 20 19,976

2018 21,598 1,114 20,484 867 31 609 30 20,061

2019 21,792 1,125 20,667 875 35 614 40 20,227

2020 21,965 1,133 20,833 883 40 620 50 20,372

2021 22,096 1,141 20,956 892 44 625 61 20,475

2022 22,026 948 21,078 900 49 631 72 20,374

2023 22,202 956 21,246 909 53 636 83 20,520

2024 22,408 965 21,443 917 59 642 95 20,695

Projected Values (2015 - 2024):

Col. (2) - Col. (4) represent FPL's forecasted peak and does not include incremental conservation, cumulative load management, or 

incremental load management.

Col. (5) - Col. (9) represent cumulative load management, and incremental conservation and load management. All values are projected January

values. 

Col. (8) represents FPL's Business On Call, CDR, CILC, and Curtailable programs/rates.

Col. (10) represents a 'Net Firm Demand" which accounts for all of the incremental conservation and assumes all of the load control is 

implemented on the peak. Col. (10) is derived by using the formula: Col. (10) = Col. (2) - Col. (5) - Col. (6) - Col. (7) - Col. (8) - Col. (9).

* Res. Load Management and C/I Load Management include MW values of load management from Lee County and FKEC.

Schedule 3.2

History of Winter Peak Demand (MW)

Forecast of Winter Peak Demand (MW)

Schedule 3.2

Florida Power & Light Company 43
(1) (2) (3) (4) (5) (6) (7) (8) (9)

Net Energy Actual

For Load Residential C/I Net Energy Sales for Utility Use Total Billed

without DSM Conservation Conservation For Load Resale & Losses Retail Energy Load

Year GWh GWh GWh GWh GWh GWh Sales (GWh) Factor(%) 

2005 115,065 1,970 1,793 111,301 1,506 7,498 102,296 56.8%

2006 117,116 2,078 1,901 113,137 1,569 7,909 103,659 59.2%

2007 118,518 2,138 2,066 114,315 1,499 7,401 105,415 59.4%

2008 115,379 2,249 2,126 111,004 993 7,092 102,919 60.0%

2009 115,844 2,345 2,196 111,303 1,155 7,394 102,755 56.8%

2010 119,220 2,487 2,259 114,475 2,049 7,870 104,557 58.7%

2011 117,460 2,683 2,324 112,454 2,176 6,950 103,327 59.4%

2012 116,083 2,823 2,394 110,866 2,237 6,403 102,226 58.9%

2013 117,087 2,962 2,469 111,655 2,158 6,713 102,784 59.1%

2014 121,621 3,125 2,529 115,968 5,375 6,204 104,389 57.7%

Historical Values (2005 - 2014):

Col. (2) represents derived "Total Net Energy For Load w/o DSM". The values are calculated using the formula: Col. (2) = Col. (3) + Col. (4) + Col. (5).

Col. (3) & Col. (4) are DSM values starting in January 1988 and are annual (12-month) values. Col. (3) and Col. (4) for 2014

are "estimated actuals" and are also annual (12-month) values. The values represent the total GWh reductions experienced each year .

Col. (5) is the actual Net Energy for Load (NEL) for years 2005 - 2014.

Col. (8) is the Total Retail Billed Sales. The values are calculated using the formula: Col. (8) = Col. (5) - Col. (6) - Col. (7). These values are at the mete

Col. (9) is calculated using Col. (5) from this page and Col. (2), "Total", from Schedule 3.1 using the formula: Col. (9) = ((Col. (5)*1000) / ((Col. (2) * 8760

Adjustments are made for leap years.

(1) (2) (3) (4) (5) (6) (7) (8) (9)

Forecasted Net Energy Forecasted

Net Energy For Load Total Billed

For Load Residential C/I Adjusted for Sales for Utility Use Retail Energy

without DSM Conservation Conservation DSM Resale & Losses Sales w/o DSM Load

Year GWh GWh GWh GWh GWh GWh GWh Factor(%) 

2015 119,713 58 51 119,604 6,021 6,595 107,096 58.7%

2016 122,407 98 88 122,221 6,126 6,727 109,554 58.6%

2017 123,946 121 112 123,713 5,882 6,788 111,275 58.3%

2018 125,433 144 137 125,151 5,629 6,852 112,952 58.1%

2019 127,070 168 164 126,738 5,659 6,950 114,461 57.9%

2020 128,851 192 192 128,467 5,700 7,036 116,115 57.8%

2021 129,237 218 221 128,798 5,256 7,011 116,971 57.9%

2022 130,077 244 252 129,581 4,955 7,097 118,025 57.5%

2023 131,495 271 284 130,940 5,013 7,176 119,307 57.1%

2024 133,276 299 318 132,659 5,073 7,271 120,931 56.7%

Projected Values (2015 - 2024):

Col. (2) represents Forecasted Net Energy for Load and does not include incremental DSM from 2015 - on. The Col. (2) values are extracted from 

Schedule 2.3, Col(19). The effects of conservation implemented prior to September 2014 are incorporated into the load forecast values in Col. (2).

Col. (3) & Col. (4) are forecasted values of the reduction on sales from incremental conservation from Jan 2015 - on and are mid-year (6-month) 

values reflecting DSM signups occurring evenly thoughout each year.

Col. (5) is the forecasted Net Energy for Load (NEL) after adjusting for impacts of incremental DSM for years 2015 - 2024 using the formula: 

Col. (5) = Col. (2) - Col. (3) - Col. (4)

Col. (8) is the Total Retail Billed Sales. The values are calculated using the formula: Col. (8) = Col. (2) - Col. (6) - Col. (7). 

These values are at the meter.

Col. (9) is calculated using Col. (2) from this page and Col. (2), "Total", from Schedule 3.1. Col. (9) = ((Col. (2)*1000) / ((Col. (2) * 8760)

Adjustments are made for leap years.

Schedule 3.3

History of Annual Net Energy for Load (GWh)

(All values are "at the generator" values except for Col (8))

Schedule 3.3

Forecast of Annual Net Energy for Load (GWh)

(All values are "at the generator"values except for Col (8))

Florida Power & Light Company 44
(1) (2) (3) (4) (5) (6) (7)

Total Total Total

Peak Demand NEL Peak Demand NEL Peak Demand NEL

Month MW GWh MW GWh MW GWh

JAN 17,500 8,634 21,136 8,974 21,369 9,218

FEB 16,297 7,957 18,170 8,036 18,554 8,562

MAR 16,183 8,491 18,030 8,882 18,411 9,109

APR 19,934 9,230 19,033 9,214 19,435 9,414

MAY 20,295 10,400 21,262 10,556 21,712 10,750

JUN 21,786 10,438 22,600 10,974 23,078 11,146

JUL 22,935 11,392 23,001 11,759 23,488 11,920

AUG 22,900 12,125 23,286 11,914 23,778 12,089

SEP 21,673 10,641 22,498 11,057 22,974 11,233

OCT 21,079 10,074 21,145 10,427 21,593 10,616

NOV 17,830 8,129 18,588 8,804 18,982 9,015

DEC 16,095 8,457 18,027 9,115 18,408 9,336

Annual Values: 115,968 119,713 122,407

Col. (3) annual value shown is consistent with value shown in Col.(5) of Schedule 3.3.

Cols. (4) - (7) do not include the impacts of cumulative load management, incremental conservation, and incremental 

load management.

Cols. (5) and Col. (7) annual values shown are consistent with values shown in Col.(2) of Schedule 3.3.

FORECAST

Schedule 4

Previous Year Actual and Two-Year Forecast of 

Retail Peak Demand and Net Energy for Load (NEL) by Month

2014 2015

Actual FORECAST

2016

Florida Power & Light Company 45
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Florida Power & Light Company 46
CHAPTER III

Projection of Incremental Resource Additions

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Florida Power & Light Company 48
III. Projection of Incremental Resource Additions

III.A FPL’s Resource Planning:

FPL utilizes its well established integrated resource planning (IRP) process, in whole or in part as 

dictated by analysis needs, to determine: when new resources are needed, what the magnitude of 

the needed resources are, and what type of resources should be added. The timing and type of 

new power plants, the primary subjects of this document, are determined as part of the IRP 

process work. 

This section describes FPL’s basic IRP process. It also discusses some of the key assumptions, in 

addition to a new load forecast discussed in the previous chapter, that were used in developing 

the resource plan presented in this Site Plan.

Four Fundamental Steps of FPL’s Resource Planning: 

There are 4 fundamental steps to FPL’s resource planning. These steps can be generally 

described as follows:

Step 1: Determine the magnitude and timing of FPL’s new resource needs;

Step 2: Identify which resource options and resource plans can meet the determined 

magnitude and timing of FPL’s resource needs (i.e., identify competing options 

and resource plans);

Step 3: Evaluate the competing options and resource plans in regard to system 

economics and non-economic factors; and,

Step 4: Select a resource plan and commit, as needed, to near-term options.

Figure III.A.1 graphically outlines the 4 steps.

Florida Power & Light Company 49
Overview of FPL's IRP Process

Figure III.A.1: Overview of FPL’s IRP Process

Fundamental

IRP Steps

(1) Determine the 

magnitude and 

timing of FPL's new 

resource needs

(2) Identify DSM and 

generation

resource options, 

perform preliminary 

analyses, and develop 

resource plans which 

can meet the 

determined 

magnitude and

timing of FPL's 

resource needs

(3) Evaluate the 

competing resource 

plans in regard to 

system economics and 

non-economic factors

Load forecast update

Updating of 

other forecasts, 

data, and 

assumptions

System 

reliability

analyses

Preliminary analyses of 

individual DSM options

Packaging of DSM 

options

Develop resource plans 

for system analyses

System economic and 

non-economic analyses 

of competing resource 

plans

Finalize FPL's

Integrated Resource 

Plan

(4) Finalize FPL's 

Integrated Resource 

Plan & commit to nearterm options

FPL 

Commitment

to near-term 

options

Preliminary analyses of 

generation options

Overview of FPL's IRP Process

Figure III.A.1: Overview of FPL’s IRP Process

Fundamental

IRP Steps

(1) Determine the 

magnitude and 

timing of FPL's new 

resource needs

(2) Identify DSM and 

generation

resource options, 

perform preliminary 

analyses, and develop 

resource plans which 

can meet the 

determined 

magnitude and

timing of FPL's 

resource needs

(3) Evaluate the 

competing resource 

plans in regard to 

system economics and 

non-economic factors

Load forecast update

Updating of 

other forecasts, 

data, and 

assumptions

System 

reliability

analyses

Preliminary analyses of 

individual DSM options

Packaging of DSM 

options

Develop resource plans 

for system analyses

System economic and 

non-economic analyses 

of competing resource 

plans

Finalize FPL's

Integrated Resource 

Plan

(4) Finalize FPL's 

Integrated Resource 

Plan & commit to nearterm options

FPL 

Commitment

to near-term 

options

Preliminary analyses of 

generation options

Florida Power & Light Company 50
Step 1: Determine the Magnitude and Timing of FPL’s New Resource Needs:

The first of the four resource planning steps, determining the magnitude and timing of FPL’s 

resource needs, is essentially a determination of the amount of capacity or megawatts (MW) of 

load reduction, new capacity additions, or a combination of both load reduction and new capacity 

additions that are needed to maintain system reliability. Also determined in this step is when the 

MW additions are needed to meet FPL’s reliability criteria. This step is often referred to as a 

reliability assessment, or resource adequacy, analysis for the utility system.

Step 1 typically starts with an updated load forecast. Several databases are also updated in this 

first fundamental step, not only with the new information regarding forecasted loads, but also with 

other information that is used in many of the fundamental steps in resource planning. Examples of 

this new information include, but are not limited to: delivered fuel price projections, current 

financial and economic assumptions, current power plant capability and operating assumptions, 

and current demand side management (DSM) demand and energy reduction assumptions. FPL 

also includes key sets of projections regarding three specific types of resources: (1) FPL unit 

capacity changes, (2) firm capacity power purchases, and (3) DSM implementation.

Key Assumptions Regarding the Three Types of Resources:

The first set of assumptions, FPL unit capacity changes, is based on the current projection of new 

generating capacity additions and planned retirements of existing generating units. In FPL’s 2015

Site Plan, there are six (6) such projected capacity changes through the 10-year reporting time 

frame of this document. These changes are listed below in general chronological order:

1) Retirement of existing Putnam Units 1 & 2:

As explained in FPL’s 2014 Site Plan, analyses conducted during 2013 and early 2014 

showed that it would be cost-effective to retire two existing units, Putnam Units 1 & 2, and 

replace the capacity with new combined cycle (CC) capacity at a later date and at a site to 

be determined. The new CC capacity would have a significantly better heat rate, thus 

reducing FPL’s system fuel usage and system emissions. As a result, these two units 

were retired at the end of 2014.

2) CT upgrades at existing CC plant sites:

In the fourth quarter of 2011, FPL started upgrading the 7FA combustion turbines (CT) 

that are components at a number of its existing CC units. These upgrades will 

economically benefit FPL’s customers by increasing the MW output of these CC units. 221 

MW of the increased capacity from these CT upgrades is already in service. The work for 

Florida Power & Light Company 51
the remaining upgrades is continuing and the project is projected to be completed in early 

2016.

3) Modernization of the Port Everglades plant site:

The work to modernize the existing Port Everglades site by adding new combined cycle 

(CC) capacity continues. The new generating unit, called the Port Everglades Next 

Generation Clean Energy Center (PEEC), is projected to be in-service in mid-2016 and is 

projected to have a peak Summer output of 1,237 MW. The FPSC issued the final need 

order for this modernization project in April 2012 in Order No. PSC-12-0187-FOF-EI. The 

site certification order for the project, DOAH Case No. 12-0422EPP, was received for the 

Port Everglades project in October 2012.

4) New Solar Facilities:

FPL currently projects that it will add new photovoltaic (PV) facilities by the end of 2016 at 

three sites. These sites are FPL’s existing Manatee plant site in Manatee County, the 

Citrus site in DeSoto County, and the Babcock Ranch site in Charlotte County. Each of 

the PV facilities is projected to have a nameplate rating of approximately 74.5 MW (AC).

Therefore, the three PV facilities will have a combined total nameplate (AC) rating of

approximately 223 MW. FPL’s analyses of these three specific projects have led to a 

conclusion that approximately 52% of their nameplate (AC) rating can be accounted for as 

firm Summer capacity, and 0% for firm Winter capacity, in FPL’s reliability analyses. 

5) GT Replacement:

FPL plans, for economic reasons, to retire a number of its older gas turbine (GT) peaking 

units at its three GT sites (Lauderdale, Port Everglades, and Fort Myers) and partially 

replace this peaking capacity with new combustion turbine (CT) capacity at the 

Lauderdale and Fort Myers sites. In addition, the two existing CTs at the Fort Myers site 

will be upgraded, which will increase their capacity. These changes are projected to be 

completed by the end of 2016. The MW impact of these changes to FPL’s peaking 

capacity is a net decrease of approximately 40 MW.

6) New Combined Cycle Capacity:

FPL currently projects a need for a significant capacity addition in 2019. FPL’s best selfbuild option to meet this need is a new combined cycle (CC) unit that would be built in 

Okeechobee County. In order to ensure that the best generation option for FPL’s 

customers is chosen to meet this need, and in keeping with the FPSC’s Bid Rule, FPL 

issued a Request for Proposals (RFP) in March 2015 that invited generation proposals 

from outside parties. These proposals are scheduled to be received in May 2015. Once 

Florida Power & Light Company 52
these proposals and FPL’s self-build CC unit have been thoroughly evaluated by both FPL 

and an independent evaluator, FPL expects to file in mid-2015 for an FPSC determination 

of need approval, and/or for FPSC approval for cost recovery, for the best option(s).

In addition, FPL’s current resource plan presented in this Site Plan also shows potential 

new CC capacity being added in 2023. No decision on this potential addition is yet needed 

and FPL expects to make a decision on this capacity addition at an appropriate time in a 

manner similar to how the decision for the 2019 need will be reached.

The second set of assumptions involves firm capacity power purchases. There are two significant 

changes in firm capacity power purchases from those shown in FPL’s 2014 Site Plan. The first of 

those is due to the fact that FPL no longer is projecting that it will serve Vero Beach’s electrical 

load (as discussed in Chapter II). Thus FPL is no longer projecting that it will acquire the Vero 

Beach combined cycle unit (46 MW), or that it will acquire two of Vero Beach’s existing power 

purchase agreements which total approximately 37 MW of coal-fired capacity that were projected 

to run through the end of 2017. The second change is that FPL anticipates terminating its existing 

power purchase agreement for 250 MW of coal-fired capacity from the Cedar Bay generating 

facility at the end of August 2015 as a result of a Purchase and Sale Agreement between FPL and 

Cedar Bay Generating Company, L.P. FPL would then own the unit starting on September 1, 

2015. FPL currently anticipates that it will not need the unit for economic purposes after 2016 and, 

if that proves to be the case, would retire the unit at that time. FPL filed for FPSC approval of the 

Purchase and Sale Agreement in the first quarter of 2015.

None of the other purchase projections has changed from those in the 2014 Site Plan. FPL’s 

current projection includes an additional 70 MW of waste-to-energy capacity from the Palm Beach 

Solid Waste Authority (SWA) starting in mid-2015. In addition, FPL continues to project that 

Internal Revenue Service (IRS) regulations regarding the amount of energy that FPL can receive 

under its purchase agreement with Jacksonville Electric Authority (JEA) for St. Johns Regional 

Power Park (SJRPP) will result in the suspension of the delivery of capacity and energy to FPL in 

the second quarter of 2019.

4

 In addition, FPL projects that it will begin receiving a total of 180 MW 

of firm capacity in 2021 from biomass-based power purchase agreements with affiliates of U.S. 

EcoGen. 

In total, the projected firm capacity purchases are from a combination of utility and independent 

power producers. Details, including the annual total capacity values for these purchases, are 

presented in Chapter I in Tables I.B.1 and I.B.2. These purchased capacity amounts were 

incorporated in FPL’s resource planning work. 

4 FPL’s projected suspension date for the SJRPP purchase is based on a system reliability perspective and represents the earliest 

projected date at which the suspension of capacity and energy could occur.

Florida Power & Light Company 53

 
The third set of assumptions involves a projection of the amount of additional DSM that FPL 

anticipates it will implement annually over the ten-year period of 2015 through 2024. A key aspect 

of FPL’s IRP process is the evaluation of DSM resources. Since 1994, FPL’s resource planning 

work has assumed that, at a minimum, the DSM MW called for in FPL’s FPSC-approved DSM 

Plan will be achieved. In November 2014, the FPSC established new DSM Goals for FPL that 

address the years 2015 through 2024, a time period that matches the reporting period of this Site 

Plan. The FPSC’s DSM Goals Order No. PSC-14-0696-FOF-EU recognized that two key market 

forces currently were affecting the feasibility and cost-effectiveness of utility DSM programs. The 

first of these is the growing impact of federal and state energy efficiency codes and standards. As 

discussed in Chapter II, the projected incremental impacts of these energy efficiency codes and 

standards during the 2015 through 2024 time period are: a Summer peak reduction of 

approximately 2,035 MW, a Winter peak reduction of approximately 1,321 MW, and approximately 

6,808 GWh of energy reduction. As a result, these energy efficiency codes and standards 

significantly reduce the potential for cost-effective utility DSM programs. 

The second market force was lower generating costs with which DSM must compete. This is 

particularly noticeable in regard to current and projected fuel costs compared to those when 

Florida previously established DSM Goals in 2009. As an example, natural gas cost projections 

are 50% lower than natural gas costs projections were in 2009. Although lower generating costs, 

such as lower fuel costs, are very beneficial for FPL’s customers, they also negatively impact the 

economics of utility DSM programs. Therefore, fewer DSM programs are now cost-effective. In 

addition, for some DSM programs to remain cost-effective, incentive payments to participating 

customers have to be lowered, thus reducing the attractiveness of these programs to potential 

participants.

The FPSC recognized the impact these market forces have on utility DSM programs and set the 

new DSM Goals accordingly. Although the new DSM Goals are lower than the previous goals, the 

new goals will help ensure that the electric rate impacts to all of FPL’s customers from pursuing 

DSM are minimized. In March 2015, FPL filed for FPSC approval of its DSM Plan that presents 

specific DSM programs designed to achieve the new DSM Goals. A decision regarding FPL’s 

DSM Plan is expected by mid-2015. In this Site Plan, the resource plan that is presented assumes 

that the new DSM Goals will be met in each year of the reporting period. FPL’s DSM efforts are 

further discussed later in this chapter in section III.D.

The Three Reliability Criteria Used to Determine FPL’s Projected Resource Needs:

These key assumptions, plus the other updated information described above, are then applied in 

the first fundamental step: determining the magnitude and timing of FPL’s future resource needs.

This determination is accomplished by system reliability analyses which for FPL have traditionally 

Florida Power & Light Company 54
been based on dual planning criteria of a minimum peak period total reserve margin of 20% (FPL 

applies this to both Summer and Winter peaks) and a maximum loss-of-load probability (LOLP) of 

0.1 day per year. Both of these criteria are commonly used throughout the utility industry.

Beginning in 2014, FPL also implemented a third reliability criterion: a 10% generation-only 

reserve margin (GRM).

Historically, two types of methodologies, deterministic and probabilistic, have been utilized in 

system reliability analysis. The calculation of excess firm capacity at the annual system peaks 

(reserve margin) is the most common method, and this relatively simple deterministic calculation 

can be performed on a spreadsheet. It provides an indication of the adequacy of a generating 

system’s capacity resources compared to its load during peak periods. However, deterministic 

methods do not take into account probabilistic-related elements such as the impact of individual 

unit failures. For example: two 50 MW units that can be counted on to run 90% of the time are 

more valuable in regard to utility system reliability than is one 100 MW unit that can also be 

counted on to run 90% of the time. Probabilistic methods also recognize the value of being part of 

an interconnected system with access to multiple capacity sources.

For this reason, probabilistic methodologies have been used to provide an additional perspective 

on the reliability of a generating system. There are a number of probabilistic methods that are in

use for performing system reliability analyses. Among the most widely used is loss-of-load 

probability (LOLP) which FPL utilizes. Simply stated, LOLP is an index of how well a generating 

system may be able to meet its firm demand (i.e., a measure of how often load may exceed 

available resources). In contrast to reserve margin, the calculation of LOLP looks at the daily peak 

demands for each year, while taking into consideration such probabilistic events as the 

unavailability of individual generators due to scheduled maintenance or forced outages. 

LOLP is expressed in terms of the projected probability that a utility will be unable to meet its 

entire firm load at some point during a year. The probability of not being able to meet the entire 

firm load is calculated for each day of the year using the daily peak hourly load. These daily 

probabilities are then summed to develop an annual probability value. This annual probability 

value is commonly expressed as “the number of days per year” that the entire system firm load 

could not be met. FPL’s standard for LOLP, commonly accepted throughout the industry, is a 

maximum of 0.1 day per year. This analysis requires a more complicated calculation methodology 

than does the reserve margin analysis. LOLP analyses are typically carried out using computer 

software models such as the Tie Line Assistance and Generation Reliability (TIGER) program 

used by FPL.

Florida Power & Light Company 55
FPL’s integrated resource planning work over the last several years examined a projected 

fundamental change in FPL’s resource plans. This change was a significant shift in the mix of 

generation and DSM resources in which FPL was becoming increasingly reliant on DSM 

resources to maintain system reliability. As discussed in detail in FPL’s 2014 Site Plan, extensive 

analyses examined this shift from a system reliability perspective. 

In these analyses, FPL developed a new metric: a generation-only reserve margin (GRM). This 

GRM metric reflects reserves that would be provided only by actual generating resources. The 

GRM value is calculated by setting to zero all incremental energy efficiency (EE) and load 

management (LM), plus all existing LM, in another version of a reserve margin calculation. The 

resulting GRM value provides an indication of how large a role generation is projected to play 

each year as FPL maintains its 20% Summer and Winter “total” reserve margins (which account 

for both generation and DSM resources).

These analyses examined the two types of resources, DSM and Supply options, from both an 

operational and a resource planning perspective. Based on these analyses, FPL concluded that

resource plans for its system with identical total reserve margins, but different GRM values, are 

not equal in regard to system reliability. A resource plan with a higher GRM value is projected to 

result in more MW being available to system operators on adverse peak load days, and in lower 

LOLP values, than a resource plan with a lower GRM value, even though both resource plans 

have an identical total reserve margin. Therefore, in 2014 FPL implemented a minimum GRM 

criterion of 10% as a third reliability criterion in its resource planning process. 

The 10% minimum Summer and Winter GRM criterion augments the other two reliability criteria 

used by FPL: a 20% total reserve margin criterion for Summer and Winter, and a 0.1 day/year 

LOLP criterion. All three reliability criteria are potentially useful in terms of identifying the timing of 

the resource need. In terms of identifying the magnitude of the resource need on FPL’s system, 

the total reserve margin and GRM criteria are more useful although the projected magnitudes 

under each of these criteria may differ. In addition, the GRM criterion provides direction regarding 

the mix of generation and DSM resources that should be added to maintain and enhance FPL’s 

system reliability. 

 

Step 2: Identify Resource Options and Plans That Can Meet the Determined Magnitude 

and Timing of FPL’s Resource Needs: 

The initial activities associated with this second fundamental step of resource planning generally 

proceed concurrently with the activities associated with Step 1. During Step 2, preliminary 

economic screening analyses of new capacity options that are identical, or virtually identical, in 

Florida Power & Light Company 56
regard to certain key characteristics may be conducted to determine which new capacity options 

appear to be the most competitive on FPL’s system. These preliminary analyses can also help 

identify capacity size (MW) values, projected construction/permitting schedules, and operating 

parameters and costs. Similarly, preliminary economic screening analyses of new DSM options 

and/or evaluation of existing DSM options are often conducted in this second fundamental IRP 

step.

FPL typically utilizes a production cost model and a Fixed Cost Spreadsheet, and/or an 

optimization model and spreadsheet analyses, to perform the preliminary economic screening of 

generation resource options. For the preliminary economic screening analyses of DSM resource 

options, FPL typically uses its DSM CPF model which is an FPL spreadsheet model utilizing the 

FPSC’s approved methodology for performing preliminary economic screening of individual DSM 

measures and programs. In addition, a years-to-payback screening test based on a two-year 

criterion is also used in the preliminary economic screening of individual DSM measures and 

programs. Then, as the focus of DSM analyses progresses from analysis of individual DSM 

measures to the development of DSM portfolios, FPL uses two additional models. One of these 

models is FPL’s non-linear programming model that is used for analyzing the potential for lowering 

system peak loads through additional load management/demand response capability. The other 

model that FPL typically utilizes is its linear programming model, which FPL uses to develop DSM 

portfolios.

The individual new resource options, both Supply options and DSM portfolios, emerging from 

these preliminary economic screening analyses are then typically “packaged” into different 

resource plans which are designed to meet the system reliability criteria. In other words, resource 

plans are created by combining individual resource options so that the timing and magnitude of 

FPL’s projected new resource needs are met. The creation of these competing resource plans is 

typically carried out using spreadsheet and/or dynamic programming techniques. 

At the conclusion of the second fundamental resource planning step, a number of different 

combinations of new resource options (i.e., resource plans) of a magnitude and timing necessary 

to meet FPL’s resource needs are identified.

Step 3: Evaluate the Competing Options and Resource Plans in Regard to System 

Economics and Non-Economic Factors:

At the completion of fundamental steps 1 & 2, the most viable new resource options have been 

identified and these resource options have been combined into a number of resource plans that 

each meet the magnitude and timing of FPL’s resource needs. The stage is set for evaluating 

Florida Power & Light Company 57
these resource options and resource plans in system economic analyses that aim to account for 

all of the impacts to the FPL system from the competing resource options/resource plans. In FPL’s 

2014 and early 2015 resource planning work, once the resource plans were developed, FPL

utilized the UPLAN production cost model and a Fixed Cost Spreadsheet, and/or the EGEAS

optimization model, to perform the system economic analyses of the resource plans. Other 

spreadsheet models may also be used to further analyze the resource plans.

The basic economic analyses of the competing resource plans focus on total system economics. 

The standard basis for comparing the economics of competing resource plans is their relative 

impact on FPL’s electricity rate levels, with the objective generally being to minimize FPL’s 

projected levelized system average electric rate (i.e., a Rate Impact Measure or RIM 

methodology). In analyses in which the DSM contribution has already been determined through 

the same IRP process and/or FPSC approval, and therefore the only competing options are new 

generating units and/or purchase options, comparisons of competing resource plans’ impacts on 

electricity rates and on system revenue requirements will yield identical outcomes in regard to the 

relative rankings of the resource options being evaluated. Consequently, the competing options 

and resource plans in such cases can be evaluated on a system cumulative present value 

revenue requirement (CPVRR) basis.

Other factors are also included in FPL’s evaluation of resource options and resource plans. 

Although these factors may have an economic component or impact, they are often discussed in 

quantitative, but non-economic, terms such as percentages, tons, etc. rather than in terms of 

dollars. These factors are often referred to by FPL as “system concerns” that include (but are not 

limited to) maintaining/enhancing fuel diversity in the FPL system, system emission levels, and

maintaining a regional balance between load and generating capacity, particularly in the 

Southeastern Florida counties of Miami-Dade and Broward. In conducting the evaluations needed 

to determine which resource options and resource plans are best for FPL’s system, the noneconomic evaluations are conducted with an eye to whether the system concern is positively or 

negatively impacted by a given resource option or resource plan. These, and other, factors are 

discussed later in this chapter in section III.C.

Step 4: Finalizing FPL’s Current Resource Plan

The results of the previous three fundamental steps are typically used to develop FPL’s current 

resource plan. The current resource plan is presented in the following section.

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III.B Projected Incremental Resource Additions/Changes in the Resource Plan

FPL’s projected incremental generation capacity additions/changes for 2015 through 2024 are 

depicted in Table ES-1 which was previously presented in the Executive Summary chapter. These 

capacity additions/changes include the 6 generation additions/changes previously discussed in 

this chapter. 

Although FPL’s projected DSM additions that are developed in the IRP process are not explicitly 

presented in this table, these DSM additions have been fully accounted for in all of FPL’s resource 

planning work reflected in this document. The projected MW reductions from these DSM additions 

are also reflected in the projected total reserve margin values shown in Table ES-1 and in 

Schedules 7.1 and 7.2 presented later in this chapter. DSM is further addressed later in this 

chapter in section III.D.

III.C Discussion of the Projected Resource Plan and Issues Impacting FPL’s 

Resource Planning Work

As indicated in the Executive Summary, FPL’s resource planning efforts in 2014 and early 2015

resulted in a resource plan that has four (4) key differences compared to the resource plan 

presented in FPL’s 2014 Site Plan. These 4 key differences are discussed below in chronological 

order.

1. FPL No Longer Projects That It Will Serve Vero Beach’s Electrical Load:

Difficulties in the negotiations between the parties involved have led FPL to no longer project 

that it will serve Vero Beach’s electrical load which was assumed in FPL’s most recent Site 

Plans and load forecasts. This factor results in a lowering of FPL’s forecasted load and 

projected resource needs. To the extent circumstances change and a consummation of the 

sale once again seems likely, FPL will reincorporate this load into its forecast.

2. FPL’s Power Purchase Agreement with Cedar Bay Will Be Terminated in 2015:

FPL anticipates terminating its existing power purchase agreement for 250 MW of coal-fired 

capacity from the Cedar Bay generating facility at the end of August 2015 as a result of a 

Purchase and Sale Agreement between FPL and Cedar Bay Generating Company, L.P. FPL 

would then assume ownership of the facility starting on September 1, 2015. FPL currently 

anticipates that it will not need the unit for economic purposes after 2016 and, if that proves to 

be the case, would retire the unit at that time. FPL filed for FPSC approval of the Purchase 

and Sale Agreement in the first quarter of 2015.

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3. FPL Will Approximately Triple Its Solar Generation Capacity by the End of 2016:

FPL will be adding three new photovoltaic (PV) facilities by the end of 2016. Each of the PV 

facilities will be approximately 74.5 MW (nameplate rating, AC). As a result, FPL’s solar 

generation capacity will increase from its current 110 MW to approximately 333 MW. The new 

PV installations are projected to be sited in Manatee, Charlotte, and DeSoto counties. The 

economics of these specific PV projects are aided by the fact that the sites are located close 

to existing electric infrastructure, including tranmission lines and electric substations, and by 

the fact that bringing these solar facilities into service prior to the end of 2016 will allow the 

facilities to take advantage of the current 30% investment tax credit that is scheduled to be 

reduced to 10% beginning in 2017.

4. Turkey Point 6 & 7 Projected In-Service Dates Have Been Moved Outside of the 10-year 

Reporting Period of This Document.

In recent Site Plans, the earliest practical deployment dates for the new Turkey Point 6 & 7 

nuclear units were identified as 2022 and 2023 and these two dates were used as the inservice dates for these units. However, in the second half of 2014, the Nuclear Regulatory 

Commission (NRC) issued a new schedule for completing its review of FPL’s Combined 

Operating License Application (COLA) for Turkey Point 6 & 7. The NRC’s new schedule now 

projects that its review will not be completed until late 2016 which is a significant delay from 

the NRC’s previous projection of a 2014 completion of its COLA review. As a consequence of 

the NRC delay, and the impacts of the recently amended Florida nuclear cost recovery (NCR) 

statute, FPL now projects that the earliest practical deployment dates for Turkey Point 6 & 7

will fall outside of the 10-year time period of 2015 through 2024 that is addressed in this Site 

Plan document. However, emissions-free, baseload capacity and energy from nuclear power 

remains an important part of FPL’s resource plans. For that reason, Chapter IV provides 

detailed information regarding the Turkey Point site for these two new nuclear units.

In addition, there are six (6) significant factors that either influenced the current resource plan 

presented in this document or which may result in changes in this resource plan in the future. 

These 6 factors are discussed below (in no particular order of importance).

1. Maintaining/Enhancing System Fuel Diversity:

FPL currently uses natural gas to generate approximately two-thirds of the total electricity it 

delivers to its customers. In the future, the percentage of FPL’s electricity that is generated by 

natural gas is projected to remain at a high level. For this reason, and due to evolving 

environmental regulations, FPL is continually seeking opportunities to economically maintain 

and enhance the fuel diversity of its system. 

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In 2007, following express direction by the FPSC to do so, FPL sought approval from the 

FPSC to add two new advanced technology coal units to its system. These two new units

would have been placed in-service in 2013 and 2014. However, in part due to concerns over 

potential greenhouse gas emission legislation/regulation, FPL was unable to obtain approval 

for these units. Several other factors are currently unfavorable to new coal units compared to 

new natural gas-fired combined cycle (CC) units. The first of these factors is a significant 

reduction in the fuel cost difference between coal and natural gas when compared to the fuel 

cost difference projected in 2007 which favored coal; i.e., the projected fuel cost advantage of 

coal versus natural gas has been significantly reduced. Second is the continuation of 

significantly higher capital costs for coal units compared to capital costs for CC units. Third is 

the increased fuel efficiency of new CC units compared to projected CC unit efficiencies in 

2007. Fourth are existing and proposed environmental regulations, including those that 

address greenhouse gas emissions, which are unfavorable to new coal units when compared 

to new CC units. Consequently, FPL does not believe that new advanced technology coal 

units are currently economically, politically, or environmentally viable fuel diversity 

enhancement options in Florida.

Therefore, FPL has turned its attention to: nuclear energy and renewable energy to enhance 

its fuel diversity, diversifying the sources of natural gas, diversifying the gas transportation 

paths used to deliver natural gas to FPL’s generating units, and using natural gas more 

efficiently. In regard to nuclear energy, in 2008 the FPSC approved the need to increase 

capacity at FPL’s four existing nuclear units and authorized FPL to recover project-related 

expenditures that are approved as a result of annual nuclear cost recovery filings. FPL 

successfully completed the nuclear capacity uprate project. Approximately 520 MW of 

additional nuclear capacity were delivered by the project which represents an increase of 

approximately 30% more incremental capacity than was originally forecasted when the project 

began. FPL’s customers are already benefitting from lower fuel costs and reduced system 

emissions provided by this additional nuclear capacity.

FPL is continuing its work to obtain all of the licenses, permits, and approvals that are 

necessary to construct and operate two new nuclear units at its Turkey Point site in the future. 

These licenses, permits, and approvals will provide FPL with the opportunity to construct 

these nuclear units at Turkey Point for a time expected to be up to 20 years from the time the 

licenses and permits are granted, and then to operate the units for at least 40 years thereafter. 

However, as discussed below, a several year delay in the Nuclear Regulatory Commission’s 

(NRC) schedule for completing its review of FPL’s Combined Operating License Application 

(COLA) have resulted in the earliest deployment dates for the two new nuclear units, Turkey 

Point Units 6 & 7, moving beyond the 2015 through 2024 reporting time period of this Site 

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Plan. The projected new in-service dates for Turkey Point Units 6 & 7 are June 2027 and June 

2028, respectively.

FPL also has been involved in activities to investigate adding and/or maintaining renewable 

resources as a part of its generation supply. One of these activities is a variety of discussions 

with the owners of existing facilities aimed at maintaining or extending current agreements. In 

addition, FPL considers new cost-effective renewable energy projects such as the power 

purchase agreements with U.S. EcoGen which will result in FPL receiving 180 MW of firm 

capacity from biomass facilities beginning in 2021. 

FPL also sought and received approval from the FPSC in 2008 to add 110 MW of then new 

renewable facilities through three FPL-owned solar facilities: one solar thermal facility and two 

photovoltaic (PV) facilities. One 25 MW PV facility began commercial operation in 2009. The 

remaining two solar facilities, a 10 MW PV facility and a 75 MW solar thermal steam 

generating facility, began commercial operation in 2010. The addition of these renewable 

energy facilities was made possible by enabling legislation enacted by the Florida Legislature 

in 2008. FPL remains strongly supportive of federal and/or state legislation that enables 

electric utilities to add renewable energy resources and authorize the utilities to recover 

appropriate costs for these resources.

The capital costs for PV modules have steadily declined. In addition, FPL’s on-going analyses 

of its existing PV facilities have led FPL to develop a methodology with which to determine 

appropriate firm capacity values for PV facilities for use in reserve margin calculations. This 

methodology has concluded, in general, that it is possible on FPL’s system to develop a utilityscale PV project-specific non-zero firm capacity value for the Summer peak hour, but not for 

FPL’s Winter morning peak hour. Partly as a result of developing this methodology, FPL’s 

current resource plan that is presented in this Site Plan shows that FPL plans to add 

approximately 223 MW (nameplate, AC) of new PV generation by the end of 2016. These 3 

specific PV projects are projected to contribute a total of approximately 116 MW (or 52% of 

the nameplate AC value for each project) of firm Summer capacity, but no MW of firm Winter 

capacity. Significant cost advantages that exist at the 3 specific sites selected for the new PV 

facilities greatly assisted in being able to bring the PV facilities in-service in 2016. In addition, 

the fact that bringing these solar facilities into service prior to the end of 2016 allows the 

facilities to take advantage of the current 30% investment tax credit that is scheduled to be 

reduced to 10% beginning in 2017, also assisted in this regard. The PV facilities are further 

discussed later in section III.F of this chapter.

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In regard to diversity in natural gas sourcing and delivery, in 2013 the FPSC approved FPL’s 

contracts to bring more natural gas into FPL’s service territory through a 3rd natural gas 

pipeline system into Florida. The process by the pipeline companies to obtain approval for the 

new pipeline system from the Federal Energy Regulatory Commission (FERC) is currently 

underway. The new pipeline system will utilize an independent route that will result in a more 

reliable, more economic, and more diverse natural gas supply for FPL’s customers and the 

State of Florida.

In regard to using natural gas more efficiently, FPL received approvals in 2008 from the FPSC 

to modernize the existing Cape Canaveral and Riviera Beach plant sites with new, highly 

efficient CC units to replace the former steam generating units on each of those sites. The 

Cape Canaveral modernization was commissioned on April 24, 2013 and the Riviera Beach

modernization was commissioned on April 1, 2014. On April 9, 2012, FPL received FPSC 

approval to proceed with a similar modernization project at the Port Everglades site. The 

project is scheduled for completion in mid-2016. All three of these modernized sites will retain 

the capability of receiving water-borne delivery of ultra-low sulfur diesel (ULSD) oil as a 

backup fuel.

In the future, FPL will continue to identify and evaluate alternatives that may maintain or 

enhance system fuel diversity. In this regard, FPL is also maintaining the ability to utilize 

heavy oil and/or ULSD oil at existing units that have that capability. For this purpose, FPL has

completed the installation of electrostatic precipitators (ESPs) at the two 800 MW steam 

generating units at its Manatee site and at the two 800 MW steam generating units at its

Martin site. These installations will enable FPL to retain the ability to burn heavy oil, as 

needed, at these sites while retaining the flexibility to use natural gas when economically 

attractive. In addition, the new CTs that FPL plans to install at its existing Lauderdale and Fort 

Myers sites, which will replace older GT units that are being retired, will have the capability to 

burn either natural gas or ULSD oil.

2. Maintaining a Balance Between Load and Generation in Southeastern Florida:

An imbalance has existed between regionally installed generation and regional peak load in 

Southeastern Florida. As a result of that imbalance, a significant amount of energy required in 

the Southeastern Florida region during peak periods is provided by: importing energy through 

the transmission system from generating units located outside the region, operating less 

efficient generating units located in Southeastern Florida out of economic dispatch, or a 

combination of the two. FPL’s prior planning work concluded that, as load inside the region 

grows, either additional installed generating capacity in this region, or additional installed 

Florida Power & Light Company 63
transmission capacity capable of delivering more electricity from outside the region, would be 

required to address this imbalance. 

Partly because of the lower transmission-related costs resulting from their location in 

Southeastern Florida, four recent capacity addition decisions (Turkey Point Unit 5 and WCEC 

Units 1, 2, & 3) were determined to be the most cost-effective options to meet FPL’s capacity 

needs in the near-term. In addition, FPL has added increased capacity at its existing two 

nuclear units at Turkey Point as part of the previously mentioned nuclear capacity uprates 

project. The Port Everglades modernization project scheduled for completion in 2016 will also

assist in addressing this imbalance. Implementing the additional generation capacity through 

the projects mentioned above has contributed to addressing the imbalance between 

generation, transmission capacity, and load in Southeastern Florida for much, if not all, of the 

2015 through 2024 reporting time frame of this Site Plan. However, due to forecasted steadily 

increasing load in the Southeastern Florida region, the Southeastern Florida imbalance issue 

will remain an important consideration in FPL’s on-going resource planning work in future 

years.

3. Maintaining a Balance Between Generation and DSM Resources in Regard to System 

Reliability:

There is another system concern that FPL has considered in its resource planning for several 

years. This concern surfaced beginning in 2010 when FPL’s system was projected to become 

increasingly dependent upon DSM resources for system reliability in later years. FPL 

discussed this concern previously in its Site Plans from 2011 through 2014. As a result of this 

concern, FPL conducted extensive analyses of its system from both a resource planning 

perspective and a system operations perspective. Those analyses showed that system 

reliability risk increases, particularly from a system operations perspective, as dependence on 

DSM resources increases to a point where DSM resources account for more than half of 

FPL’s 20% total reserve margin criterion value. As a result, in 2014 FPL implemented a new 

reliability criterion of a minimum 10% generation-only reserve margin (GRM) in its resource 

planning work to complement its other two reliability criteria: a 20% total reserve margin 

criterion for Summer and Winter, and an annual 0.1 day/year loss-of-load-probability (LOLP) 

criterion. Together, these three criteria allow FPL to address this specific concern regarding 

system reliability in a comprehensive manner.

4. The Significant Impacts of Federal and State Energy Efficiency Codes and Standards:

As discussed in Chapter II, FPL’s load forecast includes projected impacts from federal and 

state energy efficiency codes and standards. The magnitude of energy efficiency that is now

projected to be delivered to FPL’s customers through these codes and standards is significant. 

Florida Power & Light Company 64
FPL currently projects a cumulative Summer peak reduction impact of 3,568 MW from these 

codes and standards beginning in 2005 (the year the National Energy Policy Act was enacted)

and extending through the year 2024 (i.e., the last year in the 2015 through 2024 reporting 

time period for this Site Plan) compared to what the projected load would have been without 

the codes and standards. The projected incremental Summer MW impact from these codes 

and standards during the 2015 through 2024 reporting period of this Site Plan; i.e., from yearend 2014 through 2024, is 2,035 MW compared to what the projected load would have been 

without the codes and standards. Both of these projections show the significant impact of 

these energy efficiency codes and standards.

In addition to lowering FPL’s load forecast from what it otherwise would have been, and thus 

serving to lower FPL’s projected load and resource needs, this projection of efficiency from the 

codes and standards also affects FPL’s resource planning in another way. The projected 

impacts from the efficiency codes and standards lower the potential for utility DSM programs 

to cost-effectively deliver energy efficiency for the appliances and equipment that are directly 

addressed by the codes and standards. This effect was taken into account by the FPSC in the 

new DSM Goals for the 2015 – 2024 time period set by the FPSC in November 2014.

5. The Economic Competitiveness of Utility-Scale Photovoltaics (PV):

A factor that is now significantly influencing FPL’s resource planning is the increasing 

attractiveness of utility-scale photovoltaic (PV) facilities. This is due largely to the continued 

decline of the cost of PV modules. Because utility-scale PV facilities are at least twice as 

economical on an installed $/kw basis than distributed PV, the declining costs of PV modules 

has resulted, for the first time, in utility-scale PV in specific locations now being cost 

competitive on FPL’s system. In addition, FPL’s analyses of the output from its existing PV 

facilities in DeSoto and Brevard counties have resulted in FPL establishing a methodology for 

determining Summer and Winter firm capacity values for utility-scale PV facilities.

Therefore, FPL’s current resource plan that is presented in this Site Plan shows that FPL 

plans to add approximately 223 MW (nameplate AC) of new PV generation by the end of 

2016. Details regarding the projected new PV facilities are discussed further in this chapter in 

section III.F.

6. Environmental Regulation in General and Specifically, the EPA’s Proposed Clean 

Power Plan:

Another important factor is environmental regulation in general and, specifically, the U.S. 

Environmental Protection Agency’s (EPA’s) proposed Clean Power Plan issued in June 2014. 

The intent of the Clean Power Plan is to establish carbon dioxide (CO2) emission limits for 

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each state. The process for finalizing all aspects of the proposed CO2 regulations will 

encompass several years at least. The EPA is scheduled to issue final rules and emission 

limits in the Summer of 2015 (i.e., several months after this Site Plan is filed). The current draft 

rules then call for each state to submit its state compliance plan by June 2016 (although a 

delay of at least one year is possible). Legal challenges to the proposed Clean Power Plan are 

expected and such challenges have the potential to delay the proposed timetable. 

FPL’s resource planning work will account for the CO2 limits as they are finalized. In addition, 

FPL expects to be actively engaged in the development of Florida’s statewide compliance 

plan.

 

Each of these 6 factors will continue to be examined in FPL’s on-going resource planning work 

during the remainder of 2015 and in future years.

III.D Demand Side Management (DSM) 

FPL has sought and implemented cost-effective DSM programs since 1978 and DSM has been a 

key focus of FPL’s IRP process for decades. During that time FPL’s DSM programs have 

included many energy efficiency and load management programs and initiatives. FPL’s DSM 

efforts through 2014 have resulted in a cumulative Summer peak reduction of approximately 4,793

MW (Summer) at the generator and an estimated cumulative energy saving of approximately 

70,997 Gigawatt Hour (GWh) at the generator. After accounting for the 20% total reserve margin 

requirement, FPL’s DSM efforts through 2014 have eliminated the need to construct the 

equivalent of approximately 14 new 400 MW power plants.

FPL consistently has been among the leading utilities nationally in DSM achievement. For 

example, according to the U.S. Department of Energy’s 2013 data (the last year for which the 

DOE ranking data was available at the time this Site Plan was developed), FPL ranked # 2 

nationally in cumulative DSM demand reduction. And, importantly, FPL has achieved these 

significant DSM accomplishments while minimizing the DSM-based impact on electric rates for all 

of its customers.

In November 2014, new DSM Goals for FPL for the years 2015 through 2024 were set by the 

FPSC. These DSM Goals were lower than the previous DSM Goals for FPL due to two factors. 

The first factor is the significant impact of federal and state energy efficiency codes and standards. 

The projected impact of these codes and standards has significantly lowered FPL’s projected load 

and resource needs. In addition, these codes and standards have removed a significant amount of 

potential energy efficiency that otherwise might have been addressed by utility DSM programs.

The projected impacts from these codes and standards are discussed in Chapter II.

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The second factor why FPL’s resource plan currently shows a diminished role for utility DSM is the 

decline in the projected cost-effectiveness of utility DSM measures and programs. The costeffectiveness of DSM is driven in large part by the potential benefits that the kW (demand) 

reduction and kWh (energy) reduction characteristics of DSM programs are projected to provide. 

The diminished cost-effectiveness of utility DSM programs can be illustrated by looking only at 

potential benefits that DSM’s kWh reductions can provide. There are at least two reasons for 

projections of lower kWh reduction-based benefits and thus projections of lower DSM costeffectiveness.

The first reason is lower fuel costs. For example, comparing the current fuel cost forecast (at the 

time this Site Plan was prepared) with the fuel forecast used in 2009 – the year when FPL’s DSM 

Goals were previously set by the FPSC – shows that current forecasts of fuel costs are now much 

lower than those forecasted in 2009. This can be seen by comparing the 2009 and current 

forecasted costs ($/mmBTU) for natural gas for two specific years addressed in this Site Plan and 

that were addressed in the 2009 DSM goals-setting: 2015 and 2019:

Year 2009 Forecast Current Forecast

 ----------- ----------- -----------

2015 $9.64 $4.02

2019 $12.63 $4.70

As shown from these values, natural gas prices are forecast to be less than 50% of what they 

were forecast to be in 2009 when DSM goals were previously set. Lower forecasted natural gas 

costs are very beneficial for FPL’s customers because they result in lower fuel costs and lower 

electric rates. At the same time, lower fuel costs also result in lower potential fuel savings benefits 

from the kWh reductions of DSM measures. These lowered benefit values result in DSM being 

less cost-effective.

A second reason for the decline in the cost-effectiveness of utility DSM on the FPL system is the 

steadily increasing efficiency with which FPL generates electricity. FPL’s generating system has 

steadily become more efficient in regard to its ability to generate electricity using less fossil fuel. 

For example, FPL used 20% less fossil fuel to generate the same number of MWh in 2012 than it 

did in 2001. This is a very good thing for FPL’s customers because it helps to significantly lower 

fuel costs and electric rates.

However, the improvements in generating system efficiency affect DSM cost-effectiveness in 

much the same way that lower forecasted fuel costs do: both lower the fuel costs of energy 

delivered to FPL’s customers. Therefore, the improvements in generating system efficiency further 

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reduce the potential fuel savings benefits from the kWh reduction impacts of DSM, thus further 

lowering potential DSM benefits and DSM cost-effectiveness.

The two reasons discussed above – lower forecasted fuel costs and greater efficiency in FPL’s 

electricity generation – are good for FPL’s customers because they will result in lower electric 

rates. Although beneficial for FPL’s customers, these factors also contribute to lowering the costeffectiveness of utility DSM programs. Therefore, the reduction in DSM cost-effectiveness, plus 

the growing impacts of energy efficiency codes and standards, led to the FPSC setting lower DSM 

Goals for FPL.

Although the new DSM Goals are appropriately lower due to these market forces, the projected 

cumulative effect of FPL’s DSM programs from their inception through 2024 is truly significant. 

FPL’s Summer MW Goals for the 2015 – 2024 time period were set at 526 MW. After accounting 

for the 20% total reserve margin requirements, the combination of this new Summer MW reduction 

value, and the Summer MW reductions from FPL’s DSM programs from their inception through 

2014, represent the equivalent of avoiding the need to build approximately sixteen (16) 400 MW 

power plants. The resource plan presented in this 2015 Site Plan accounts for the DSM MW and 

GWh reductions set forth in FPL’s new DSM Goals. The reductions from the new DSM Goals are 

accounted for in Schedules 7.1 and 7.2 which appear later in this chapter.

In the March 2015, FPL filed for FPSC approval of a DSM Plan that consists of numerous DSM 

programs to meet the new DSM Goals. A decision by the FPSC on these new DSM programs is 

expected in mid-2015.

III.E Transmission Plan

The transmission plan will allow for the reliable delivery of the required capacity and energy to 

FPL’s retail and wholesale customers. The following table presents FPL’s proposed future 

additions of 230 kV bulk transmission lines that must be certified under the Transmission Line 

Siting Act.

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Table III.E.1: List of Proposed Power Lines

(1)

Line 

Ownership

(2)

Terminals 

(To)

(3)

Terminals 

(From)

(4)

Line 

Length 

CKT. 

Miles

(5)

Commercial 

In-Service 

Date (Mo/Yr)

(6)

Nominal 

Voltage 

(KV)

(7)

Capacity

(MVA)

FPL St. Johns 1/ Pringle 25 Dec – 18 230 759

FPL Levee 2/ Midway 150 Jun – 23 500 2598

FPL Raven 3/ Duval 45 Dec – 19 230 759

1/ Final order certifying the corridor was issued on April 21, 2006. This project is to be completed in two phases. Phase I 

consisted of 4 miles of new 230 kV line (Pringle to Pellicer) and was completed in May-2009. Phase II consists of 21 miles 

of new 230 kV line (St. Johns to Pellicer) and is scheduled to be completed by Dec-2018.

2/ Final order certifying the corridor was issued in April 1990. Construction of 114 miles is complete and in-service. 

Remaining 36 miles are scheduled to be completed by Jun-2023. 

3/ TLSA is being initiated in 2015 for the Raven to Duval project.

In addition, there will be transmission facilities needed to connect several of FPL’s projected 

generating capacity additions to the system transmission grid. These transmission facilities 

(described on the following pages) are for the Port Everglades modernization that will be 

completed in mid-2016, the PV additions in late 2016, and the potential new CC unit in 2019 at the 

Okeechobee site. At the time the 2015 Site Plan was prepared, no site had been selected for the 

2023 combined cycle addition in the resource plan presented in this Site Plan. Therefore, no 

transmission information for this addition is presented.

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II.E.1 Transmission Facilities for Port Everglades Next Generation Clean Energy Center 

(Modernization)

The work required to connect the Port Everglades Next Generation Clean Energy Center to the 

FPL grid in 2016 is projected to be:

I. Substation:

1. Construct two string busses to connect two combustion turbines (CT) to the Port Everglades 

138 kV Substation. 

2. Construct two string busses to connect one CT, and one steam turbine (ST) to the Port 

Everglades 230 kV Substation.

3. Add four main step-up transformers (3-450 MVA, 1- 580 MVA), one for each CT, and one for 

the ST.

4. Replace ten (10) 138 kV breakers.

5. Replace eight (8) 230 kV breakers.

6. At Port Everglades Switchyard replace twenty-two 138 kV disconnect switches. Also upgrade 

associated jumpers, bus work, and equipment connections.

7. Expand switchyard relay vault and add relays and other protective equipment.

II. Transmission:

1. Upgrade of existing transmission facilities:

• An ampacity upgrade up to 1905 amps on the Port Everglades-Port Everglades Tap 

138kV line section. 

• An ampacity upgrade up to 1905 amps on the Port Everglades Tap-Port Everglades Tap 2 

138 kV line section. 

• An ampacity upgrade up to 1695 amps on the Port Everglades Tap 1-Dania 138 kV line 

section. 

• An ampacity upgrade up to 1695 amps on the Dania-Hollywood 138 kV line section. 

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III.E.2 Transmission Facilities for the PV Project at the Existing Manatee Plant Site

The work required to connect the approximate 74.5 MW (nameplate, AC) facility at the existing 

Manatee site is projected to be:

I. Substation:

1. Build a new 230 kV substation approximately 0.4 miles west of the existing FPL Manatee 230 

kV substation.

2. Add one main step-up transformer (80 MVA) to connect solar PV inverter array

3. Construct a new 230 kV breaker bay at the Manatee switchyard.

4. Add relays and other protective equipment.

5. Breaker replacements: None

II. Transmission:

1. Construct 0.4 mile 230 kV line from new substation to Manatee switchyard.

2. No upgrades are expected to be necessary at this time.

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III.E.3 Transmission Facilities for the Citrus PV Project in DeSoto County

The work required to connect the approximate 74.5 MW (nameplate, AC) Citrus PV facility in 

DeSoto County is projected to be:

I. Substation:

1. Construct a new 4-breaker 230 kV ring bus at Sunshine substation.

2. Add one main step-up transformer (80 MVA) to connect solar PV inverter array

3. Construct a string buss to connect the PV array to Sunshine 230 kV Substation 

4. Add relays and other protective equipment.

5. Breaker replacements: None

II. Transmission:

1. No upgrades are expected to be necessary at this time. 

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III.E.3 Transmission Facilities for the Babcock Ranch PV Project in Charlotte County

The work required to connect the approximate 74.5 MW (nameplate, AC) Babcock Ranch PV 

facility in Citrus County is projected to be:

I. Substation:

1. Build a new 230 kV Tuckers substation approximately 5 miles north of the planned FPL 

Hercules 230 kV substation.

2. Add one main step-up transformer (80 MVA) to connect solar PV inverter array

3. Add one (1) mid-breaker to complete bay 2 at Hercules

4. Add relays and other protective equipment.

5. Breaker replacements: None

II. Transmission:

1. Construct 5 miles of 230 kV line from new Tuckers substation to Hercules substation.

2. No upgrades are expected to be necessary at this time.

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III.E.4 Transmission Facilities for the Potential New Combined Cycle (CC) Unit in

Okeechobee County

The work required to connect the potential new CC unit in Okeechobee County by Summer 2019 

is projected to be:

I. Substation:

1. Build a new six breaker 500kV Okeechobee Substation switchyard on the Okeechobee 

generation site with a relay vault for the two generator string buses and the Martin and 

Poinsett line terminals.

2. Build new collector yard containing two collector busses with 4 breakers to connect the three 

CTs, and one ST. 

3. Construct two string busses to connect the collector busses and main switchyard to 

Okeechobee 500kV Substation.

4. Add five main step-up transformers (5-450 MVA) one for each CT, and two for the ST.

5. Add relays and other protective equipment.

6. Breaker replacements:

Poinsett Sub – Replace three (3) 230 kV breakers.

II. Transmission:

1. No upgrades are expected to be necessary at this time. 

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III.F. Renewable Resources

FPL’s Renewable Energy Efforts Through 2014:

FPL has been the leading Florida utility in examining ways to effectively utilize renewable energy 

technologies to serve its customers. FPL has been involved since 1976 in renewable energy 

research and development and in facilitating the implementation of various renewable energy 

technologies. For purposes of discussing FPL’s renewable energy efforts through 2014, those 

efforts will be placed into five categories. FPL’s plans for new renewable energy facilities during 

the 2015 through 2024 time period are then discussed in a separate section.

Two of these categories are Supply-Side Efforts – Power Purchases, and Supply-Side Efforts –

FPL Facilities. Since 2011, the combined total energy output (MWh) from these renewable energy 

sources has been greater than that produced from oil-fired generation. The comparable values for 

energy delivered by renewable and oil-fired sources for the year 2014 are presented in Schedule 

11.1 at the end of this chapter.

1) Early Research & Development Efforts:

In the late 1970s, FPL assisted the Florida Solar Energy Center (FSEC) in demonstrating the 

first residential PV system east of the Mississippi River. This PV installation at FSEC’s 

Brevard County location was in operation for more than 15 years and provided valuable 

information about PV performance capabilities in Florida on both a daily and annual basis. In 

1984, FPL installed a second PV system at its Flagami substation in Miami. This 10-kilowatt 

(kW) system operated for a number of years before it was removed to make room for 

substation expansion. In addition, FPL maintained a thin-film PV test facility at the FPL Martin 

Plant Site for a number of years to test new thin-film PV technologies.

 

2) Demand Side & Customer Efforts:

In terms of utilizing renewable energy sources to meet its customers’ needs, FPL initiated the 

first utility-sponsored conservation program in Florida designed to facilitate the implementation 

of solar technologies by its customers. FPL’s Conservation Water Heating Program, first 

implemented in 1982, offered incentive payments to customers who chose solar water 

heaters. Before the program ended (because it was no longer cost-effective), FPL paid 

incentives to approximately 48,000 customers who installed solar water heaters.

In the mid-1980s, FPL introduced another renewable energy program, FPL’s Passive Home 

Program. This program was created in order to broadly disseminate information about passive 

solar building design techniques that are most applicable in Florida’s climate. As part of this 

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program, three Florida architectural firms created complete construction blueprints for six 

passive home designs with the assistance of the FSEC and FPL. These designs and 

blueprints were available to customers at a low cost. During its existence, the program 

received a U.S. Department of Energy award for innovation and also led to a revision of the 

Florida Model Energy Building Code (Code). The Code was revised to incorporate one of the 

most significant passive design techniques highlighted in the program: radiant barrier 

insulation.

FPL has continued to analyze and promote the utilization of PV. These efforts have included 

PV research such as the 1991 research project to evaluate the feasibility of using small PV 

systems to directly power residential swimming pool pumps. FPL’s PV efforts also included 

educational efforts such as FPL’s Next Generation Solar Station Program. This initiative 

delivered teacher training and curriculum that is tied to the Sunshine Teacher Standards in 

Florida. The program provided teacher grants to promote and fund projects in the classrooms.

In addition, FPL assists customers who are interested in installing PV equipment at their 

facilities. Consistent with Florida Administrative Code Rule 25-6.065, Interconnection and Net 

Metering of Customer-Owned Renewable Generation, FPL works with customers to 

interconnect these customer-owned PV systems. Through December 2014, approximately 

3,241 customer systems (predominantly residential) have been interconnected.

 

As part of its 2009 DSM Goals decision, the FPSC imposed a requirement for Florida’s 

investor-owned utilities to spend up to a not-to-exceed amount of money annually to facilitate 

demand side solar water heater and PV applications. FPL’s not-to-exceed amount of money 

for these applications was approximately $15.5 million per year for five years. In response to 

this direction, FPL received approval from the FPSC in 2011 to initiate a solar pilot portfolio 

consisting of three PV-based programs and three solar water heating-based programs, plus 

Renewable Research and Demonstration projects. FPL’s analyses of the results from these 

programs since their inception have consistently shown that none of these pilot programs is 

cost-effective using any of the three cost-effectiveness screening tests used by the State of 

Florida. As a result, consistent with the FPSC’s November 2014 DSM Goals Order No. PSC14-0696-FOF-EU, these pilot programs will expire on December 31, 2015.

FPL also has been investigating fuel cell technologies through monitoring of industry trends, 

discussions with manufacturers, and direct field trials. From 2002 through the end of 2005,

FPL conducted field trials and demonstration projects of Proton Exchange Membrane (PEM) 

fuel cells with the objectives of serving customer end-uses while evaluating the technical 

performance, reliability, economics, and relative readiness of the PEM technology. The 

demonstration projects were conducted in partnership with customers and included five 

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locations. The research projects were useful to FPL in identifying specific issues that can 

occur in field applications and the current commercial viability of this technology. FPL will 

continue to monitor the progress of these technologies and conduct additional field 

evaluations as significant developments in fuel cell technologies occur.

3) Supply Side Efforts – Power Purchases:

FPL also has facilitated a number of renewable energy projects (facilities which burn bagasse, 

waste wood, municipal waste, etc.). Firm capacity and energy, and as-available energy, have 

been purchased by FPL from these types of facilities. (Please refer to Tables I.A.3, I.B.1, and 

I.B.2 in Chapter I).

FPL issued Renewable Requests for Proposals (RFPs) in 2007 and 2008 which solicited

proposals to provide firm capacity and energy, and energy only, at or below avoided costs,

from renewable generators. FPL also promptly responds to inquiries for information from 

prospective renewable energy suppliers either by e-mail or phone.

On April 22, 2013, in Order No. PSC-13-1064-PAA-EQ, the FPSC approved three 60 MW 

power purchase agreements with affiliates of U.S. EcoGen for biomass-fired renewable 

energy facilities. These facilities are expected to provide non-firm energy service beginning in 

2019 and to provide firm energy and capacity to FPL’s customers beginning in 2021.

In regard to existing contracts that have recently ended, FPL and the Solid Waste Authority of 

Palm Beach (SWA) agreed to extend their contract that expired March 31, 2010 for a 20-year 

term beginning in April 1, 2012 through April 1, 2032. However, the SWA refurbished their 

generating unit ahead of schedule and, as of January 2012, this unit began delivering firm 

capacity to FPL. In 2011, the FPSC approved a contract for an additional 70 MW between 

FPL and SWA for a new unit. The new unit is now delivering test energy and will begin 

delivering firm capacity and energy to FPL beginning in June 2015. At the end of December 

2011, the contract between FPL and Okeelanta (New Hope) expired. However, Okeelanta 

continues to deliver energy to FPL as an as-available, non-firm supplier of renewable energy.

4) Supply Side Efforts – FPL Facilities:

With regard to solar generating facilities, FPL currently has three such facilities: (i) a 75 MW 

steam generation solar thermal facility in Martin County (the Martin Next Generation Solar 

Energy Center); (ii) a 25 MW PV electric generation facility in DeSoto County (the DeSoto 

Next Generation Solar Energy Center); and (iii) a 10 MW PV electric generation facility in 

Brevard County at NASA’s Kennedy Space Center (the Space Coast Next Generation Solar 

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Energy Center). The DeSoto County project was completed in 2009 and the other two projects 

were completed in 2010. 

These three solar facilities were constructed in response to the Florida Legislature’s House Bill 

7135 which was signed into law by the Governor in June 2008. House Bill 7135 was enacted 

to enable the development of clean, zero greenhouse gas emitting renewable generation in 

the State of Florida. Specifically, the bill authorized cost recovery for the first 110 MW of 

eligible renewable projects that had the proper land, zoning, and transmission rights in place. 

FPL’s three solar projects met the specified criteria and were granted approval for cost 

recovery in 2008. Each of the three solar facilities is discussed below.

a. The Martin Next Generation Solar Energy Center: 

This facility began commercial operation in 2010 and provides 75 MW of solar thermal 

capacity in an innovative way that directly displaces fossil fuel usage on the FPL system. 

This facility consists of solar thermal technology which generates steam that is integrated 

into the existing steam cycle for the Martin Unit 8 natural gas-fired CC plant. This project 

is the first “hybrid” solar plant in the world and, at the time the facility came in-service, was 

the second largest solar facility in the world and the largest solar plant of any kind in the 

U.S. outside of California.

b. The DeSoto Next Generation Solar Energy Center: 

This 25 MW (nameplate, AC) PV facility began commercial operation in 2009 which made 

it one of the largest PV facilities in the U.S. at that time. The facility utilizes a tracking PV 

array that is designed to follow the sun as it traverses across the sky. 

c. The Space Coast Next Generation Solar Energy Center:

Located at the Kennedy Space Center, this facility is part of an innovative public/private 

partnership with NASA. This non-tracking, 10 MW (nameplate, AC) PV facility began 

commercial operation in 2010.

During 2014, FPL conducted analyses designed to develop a methodology with which to 

determine what firm capacity value at FPL’s Summer and Winter peak hours would be 

appropriate to apply to these existing, and potential future, utility-scale PV facilities. (Note that 

the Martin solar thermal facility is a “fuel-substitute” facility, not a facility that provides 

additional capacity and energy. The solar thermal facility displaces the use of fossil fuel to 

produce steam on the FPL system when the solar thermal facility is operating.) Based on the 

results of these analyses, FPL has concluded that its two existing utility-scale PV facilities can 

be counted on to contribute certain percentages of their nameplate (AC) ratings

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(approximately 46% for DeSoto and 32% for Space Coast) as firm capacity at FPL’s Summer 

peak hour (that typically occurs in the 4 p.m. to 5 p.m. hour), but contribute no firm capacity 

during FPL’s Winter peak hour (that typically occurs in the 7 a.m. to 8 a.m. hour). Future FPL 

utility-scale PV facilities will be evaluated for potential firm capacity contribution on a case-bycase basis using this methodology. Their potential capacity contribution will be dependent 

upon a number of factors including (but not necessarily limited to) site location, technology, 

and design. For example, the three new PV facilities that are planned to be added by the end 

of 2016 are each projected to provide approximately 52% of their nameplate (AC) rating as 

firm capacity at FPL’s Summer peak hour, but provide no firm capacity during FPL’s Winter 

peak hour.

5) Ongoing Research & Development Efforts:

FPL has developed alliances with several Florida universities to promote the development of 

emerging technologies. For example, FPL supports the newly formed Southeast National 

Marine Renewable Energy Center (SNMREC) at Florida Atlantic University (FAU), which will 

focus on the commercialization of ocean current, ocean thermal energy conversion, cold water 

air conditioning, and hydrogen technologies. FPL has supported FAU in discussions with the 

U.S. Department of the Interior’s Minerals Bureau of Ocean Energy Management Regulation 

and Enforcement (BOEMRE). BOEMRE is working to establish the permitting process for 

ocean energy development on the outer continental shelf.

 

FPL has also developed a “Living Lab” to demonstrate FPL’s solar energy commitment to 

employees and visitors at its Juno Beach office facility. FPL has installed five different PV 

arrays (using different technologies) of rooftop PV totaling 24 kW at the Living Lab. In addition, 

two PV-covered parking structures with a total of approximately 90 kW of PV are in use at the 

FPL Juno office parking lot. Through these Living Lab projects, FPL is able to evaluate 

multiple solar technologies and applications for the purpose of developing a renewable 

business model resulting in the most cost-effective and reliable uses of solar energy for FPL’s

customers. FPL plans to continue to expand the Living Lab as new solar products come to 

market.

FPL has also been in discussions with several private companies on multiple emerging 

technology initiatives, including ocean current, ocean thermal, hydrogen, fuel cell technology, 

biomass, biofuels, and energy storage.

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FPL’s Planned Renewable Energy Efforts for 2015 Through 2024:

FPL has concluded from its implementation and analyses of utility-scale PV and PV demand 

side pilot programs that utility-scale PV applications are the most economical way to utilize 

solar energy. In fact, FPL’s analysis suggests that utility-scale PV is at least twice as 

economical on an installed $/kw basis compared to distributed PV systems. This conclusion is 

supported by FPL’s recent analyses discussed above regarding the ability to assign firm 

capacity value at FPL’s Summer peak hour to utility-scale PV. Due to the fact that the price of 

PV modules has declined in recent years, utility-scale PV has become more cost competitive. 

However, only the most cost-advantaged sites for utility-scale PV are projected to be costeffective on FPL’s system at this time. Other sites may become cost-effective in later years if 

PV costs continue to decline as expected. Consequently, the resource plan FPL is presenting 

in this Site Plan includes three utility-scale PV facilities at specific, cost-advantaged sites

which also are able to take advantage of the current 30% investment tax credit (which is 

scheduled to be reduced to 10% in 2017). If/when utility-scale PV projects at other sites are 

projected to be cost-effective, additional PV generation sources will be discussed in future Site 

Plans.

1) FPL Utility-Scale PV Facilities:

In the resource plan presented in this Site Plan, FPL projects the addition of three separate 

utility-scale PV facilities by the end of 2016. Each PV facility is projected to be approximately 

74.5 MW (nameplate, AC). The sites of these three proposed PV additions are: FPL’s existing 

Manatee plant site, a site in DeSoto County, and a site in Charlotte County. These locations 

are expected to have cost advantages to support early development, including:

- Current ownership of land or low cost land purchase agreement in place;

- Proximity to existing transmission lines with sufficient injection capacity;

- Proximity to existing electric substations;

- Previously performed site development and permitting work;

- Proximity to existing FPL generating facilities which allows for lower operating 

expenses;

- Support from the associated counties and land developers, with the potential for 

further cost abatements;

As previously mentioned, bringing these three PV facilities in service before the end of 

2016 will also allow the facilities to capture the full benefit of the currently available 30% 

investment tax credit for such PV facilities. The investment tax credit is scheduled to 

revert back to a 10% credit for PV projects that are placed in service after 2016.

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2) FPL Distributed Generation (DG) PV Pilot Programs:

In regard to distributed generation (DG) PV, FPL is planning to implement two DG PV pilot 

programs in 2015. The first is a voluntary, community-based, solar partnership pilot to 

install new solar-powered generating facilities. The program will be at least partially

funded by contributions from customers who volunteer to participate in the pilot and will 

not rely on subsidies from non-participating customers. The second program will 

implement approximately 6 MW of combined DG PV and battery storage at large 

commercial customer sites. The objective of this program is to collect grid integration data

for DG PV and develop operational best practices for addressing potential problems that 

may be identified. A brief description of the two pilot programs follows:

a) Voluntary, Community-Based Solar Partnership Pilot Program:

FPL is introducing a Voluntary Solar Pilot Program to provide FPL customers with an 

additional and flexible opportunity to support development of solar power in Florida. 

The Commission approved FPL’s request for this three-year pilot program in Order 

No. PSC-14-0468-TRF-EI on August 29, 2014. This pilot program will provide all 

customers the opportunity to support the use of solar energy at a community scale 

and is designed to be especially attractive for customers who do not wish, or are not 

able, to place solar equipment on their roof. Customers can participate in the program 

through voluntary contributions of $9/month starting in mid-2015. 

In this respect, these DG-scale projects differ from FPL’s three new utility-scale PV 

projects proposed for 2016, which are not projected to introduce a net cost to 

customers over the life of these projects and, therefore, do not require additional 

contributions from FPL’s customers. In contrast, smaller DG-scale projects have a 

higher cost to construct, operate, and maintain. The cost per MW to construct DGscale facilities (whether utility-owned and operated or otherwise) is approximately 

double that of the more cost-efficient utility-scale PV projects. Furthermore, the 

operations and maintenance costs of DG-scale projects are projected to be three 

times as much as for utility-scale PV due to the distributed nature of the installations.

Thus a voluntary contribution is necessary for this DG-based pilot program so that net 

costs, and electric rates, do not increase for non-participants.

The first 200 kW of DG-scale PV projects will be built by FPL in the first half of 2015 at 

locations in the city of West Palm Beach and in Broward County. The first installation 

is scheduled to be at the Young at Arts Museum in Broward County. Additional PV

facilities under this pilot program will be built when the projected voluntary 

contributions are sufficient to cover on-going program costs without increasing electric 

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rates for all customers, including non-participating customers. The locations of these 

additional PV facilities will be determined at a later date. While the ultimate amount of 

PV that will be installed under this voluntary program cannot be known at this time, it 

is estimated that the project could result in approximately 2 MW (nameplate, DC) of 

community-located PV installations supported by over 10,000 customer participants 

by the end of the three-year pilot.

b) C&I Solar Partnership Pilot Program:

This is a research program that will be conducted in partnership with interested 

commercial and industrial (C&I) customers over an approximate five year period. 

Limited investments will be made in PV facilities located at customer sites in selected 

geographic areas of FPL’s service territory. The objective of this portion of the pilot 

program is to examine the effect of high DG PV penetration on FPL’s distribution 

system and to determine how best to address any problems that may be identified. 

FPL will site approximately 5 MW (nameplate, DC) of PV facilities in areas where DG 

PV already exists to better study feeder loading impacts. PV installations at Daytona 

International Speedway, and FIU’s Engineering Center campus in West Miami-Dade 

County have been selected based largely on their interconnection with targeted 

circuits. In addition, this pilot program will also install a battery storage facility of

approximately 1 MW capacity. This facility will be used to investigate the 

interoperability, and optimization, of multiple DG technologies. A multi-year research 

partnership agreement has been executed with FIU for the university to assist FPL in 

the battery storage research and development plan, and in the analyses that will 

subsequently be conducted.

III.G FPL’s Fuel Mix and Fuel Price Forecasts 

1. FPL’s Fuel Mix

Until the mid-1980s, FPL relied primarily on a combination of fuel oil, natural gas, and nuclear 

energy to generate electricity with significant reliance on oil–fired generation. In the early 

1980s, FPL began to purchase “coal-by-wire.” In 1987, coal was first added to the fuel mix 

through FPL’s partial ownership (20%) and additional purchases (30%) from the St. Johns 

River Power Park (SJRPP). This allowed FPL to meet its customers’ energy needs with a 

more diversified mix of energy sources. Additional coal resources were added with the partial 

acquisition (76%) of Scherer Unit 4 which began serving FPL’s customers in 1991. 

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The trend since the early 1990s has been a steady increase in the amount of natural gas that 

FPL uses to produce electricity due, in part, to the introduction of highly efficient and costeffective CC generating units and the ready availability of natural gas. FPL placed into 

commercial operation two new gas-fired CC units at the West County Energy Center (WCEC) 

site in 2009. A third new CC unit was added to the WCEC site in 2011. In addition, FPL has 

completed the modernization of its Cape Canaveral and Riviera Beach plant sites and is 

currently modernizing its existing Port Everglades plant site by removing the steam generating 

units that previously operated at the site and replacing them with one highly efficient new CC 

unit. The new CC units at each of these three sites will provide highly efficient generation that 

will dramatically improve the efficiency of FPL’s generation system in general and, more 

specifically, the efficiency with which natural gas is utilized.

In addition, FPL increased its utilization of nuclear energy through capacity uprates of its four 

existing nuclear units. With these uprates, more than 520 MW of additional nuclear capacity 

have been added to the FPL system. FPL is also pursuing plans to obtain licenses, permits, 

and approvals to construct and operate two new nuclear units at its existing Turkey Point site 

that, in total, would add approximately 2,200 MW of new nuclear generating capacity.

In regard to utilizing renewable energy, FPL has 110 MW of solar generating capacity 

consisting of: a 75 MW solar thermal steam generating facility at FPL’s existing Martin site, a 

25 MW PV facility in DeSoto County, and a 10 MW PV facility in Brevard County. The DeSoto 

facility was placed into commercial operation in 2009. The other two solar facilities were 

placed into commercial operation in 2010. As discussed in the preceding section, FPL is 

planning to add three new approximately 74.5 MW (nameplate, AC) PV facilities by the end of 

2016.

FPL’s future resource planning work will continue to focus on identifying and evaluating 

alternatives that would most cost-effectively maintain and/or enhance FPL’s long-term fuel 

diversity. These fuel diverse alternatives may include: the purchase of power from renewable 

energy facilities, additional FPL-owned renewable energy facilities, obtaining additional access 

to diversified sources of natural gas such as liquefied natural gas (LNG) and natural gas from 

the Mid-Continent unconventional reserves, securing gas reserves, preserving FPL’s ability to 

utilize fuel oil at its existing units, and increased utilization of nuclear energy. (As previously 

discussed, new advanced technology coal-fired generating units are not currently considered 

as viable options in Florida in the ten-year reporting period of this document due, in part, to 

current projections of relatively small differences in fuel costs between coal and natural gas, 

significantly higher capital costs for coal units compared to CC units, greater efficiencies of CC 

units, and concerns over environmental regulations that would impact coal units more 

Florida Power & Light Company 83
negatively than CC units.) The evaluation of the feasibility and cost-effectiveness of these, and 

other possible fuel diversity alternatives, will be part of FPL’s on-going resource planning 

efforts.

FPL’s current use of various fuels to supply energy to customers, plus a projection of this “fuel 

mix” through 2024 based on the resource plan presented in this document, is presented in 

Schedules 5, 6.1, and 6.2 later in this chapter.

2) FPL’s Fossil Fuel Cost Forecasts

Fossil fuel price forecasts, and the resulting projected price differentials between fuels, are 

major drivers used in evaluating alternatives for meeting future resource needs. FPL’s 

forecasts are generally consistent with other published contemporary forecasts. A November

2014 fuel cost forecast was used in the analyses whose results led to the resource plan 

presented in this 2015 Site Plan.

Future oil and natural gas prices, and to a lesser extent, coal prices, are inherently uncertain 

due to a significant number of unpredictable and uncontrollable drivers that influence the 

short- and long-term price of oil, natural gas, and coal. These drivers include U.S. and 

worldwide demand, production capacity, economic growth, environmental requirements, and 

politics.

The inherent uncertainty and unpredictability of these factors today and in the future clearly 

underscores the need to develop a set of plausible oil, natural gas, and solid fuel (coal) price 

scenarios that will bound a reasonable set of long-term price outcomes. In this light, FPL 

developed and utilized Low, Medium, and High price forecasts for fossil fuels in some of its 

2014 and early 2015 resource planning work, particularly in regard to analyses conducted as 

part of the nuclear cost recovery filing work.

FPL’s Medium price forecast methodology is consistent for oil and natural gas. For oil and 

natural gas commodity prices, FPL’s Medium price forecast applies the following 

methodology: 

a. For 2015 through 2016, the methodology used the November 3, 2014 forward curve 

for New York Harbor 0.7% sulfur heavy oil, ultra-low sulfur diesel (ULSD) fuel oil, and 

Henry Hub natural gas commodity prices; 

b. For the next two years (2017 and 2018), FPL used a 50/50 blend of the November 3, 

2014 forward curve and the most current projections at the time from The PIRA 

Energy Group; 

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c. For the 2019 through 2035 period, FPL used the annual projections from The PIRA 

Energy Group; and, 

d. For the period beyond 2035, FPL used the real rate of escalation from the Energy 

Information Administration (EIA). In addition to the development of oil and natural gas 

commodity prices, nominal price forecasts also were prepared for oil and natural gas 

transportation costs. The addition of commodity and transportation forecasts resulted 

in delivered price forecasts.

FPL’s Medium price forecast methodology is also consistent for coal prices. Coal prices were 

based upon the following approach: 

a. Delivered price forecasts for Central Appalachian (CAPP), Illinois Basin (IB), Powder 

River Basin (PRB), and South American coal were provided by JD Energy; and,

b. The coal price forecast for SJRPP and Plant Scherer assumes the continuation of the 

existing mine-mouth and transportation contracts until expiration, along with the 

purchase of spot coal, to meet generation requirements.

The development of FPL’s Low and High price forecasts for oil, natural gas, and coal prices 

were based on the historical volatility of the 12-month forward price, one year ahead. FPL 

developed these forecasts to account for the uncertainty that exists within each commodity as 

well as across commodities. These forecasts reflect a range of reasonable forecast outcomes.

3. Natural Gas Storage

FPL was under contract through August 2014 for 2.5 billion cubic feet (Bcf) of firm natural gas 

storage capacity in the Bay Gas storage facility located in Alabama. The Bay Gas storage 

facility is interconnected with the Florida Gas Transmission (FGT) pipeline. FPL amended the 

transaction with Bay Gas on September 1, 2014 to increase the capacity to 4.0 Bcf of firm 

natural gas storage capacity. FPL has predominately utilized natural gas storage to help 

mitigate gas supply problems caused by severe weather and/or infrastructure problems. 

Over the past several years, FPL has acquired upstream transportation capacity on several 

pipelines to help mitigate the risk of off-shore supply problems caused by severe weather in 

the Gulf of Mexico. While this transportation capacity has reduced FPL’s off-shore exposure, 

a portion of FPL’s supply portfolio remains tied to off-shore natural gas sources. Therefore, 

natural gas storage remains an important tool to help mitigate the risk of supply disruptions. 

As FPL’s reliance on natural gas has increased, its ability to manage the daily “swings” that 

can occur on its system due to weather and unit availability changes has become more 

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challenging, particularly from oversupply situations. Natural gas storage is a valuable tool to 

help manage the daily balancing of supply and demand. From a balancing perspective, 

injection and withdrawal rights associated with gas storage have become an increasingly 

important part of the evaluation of overall gas storage requirements. 

As FPL’s system grows to meet customer needs, it must maintain adequate gas storage 

capacity to continue to help mitigate supply and/or infrastructure problems and to provide FPL 

the ability to manage its supply and demand on a daily basis. FPL continues to evaluate its

gas storage portfolio and is likely to subscribe for additional gas storage capacity to help 

increase reliability, provide the necessary flexibility to respond to demand changes, and 

diversify the overall portfolio.

4. Securing Additional Natural Gas:

The recent trend of increasing reliance upon natural gas to produce electricity for FPL’s 

customers is projected to continue due to FPL’s growing load. The addition of highly fuelefficient CC units at Cape Canaveral and Riviera Beach due to completed modernization 

projects, the on-going Port Everglades modernization project, plus the potential for additional 

CC capacity, will reduce the growth in natural gas use from what it otherwise might have been 

due to the high fuel-efficiency levels of these new CC units. In addition, FPL plans to add a 

significant amount of new PV facilities that utilize no fossil fuel. However, these efficiency 

gains do not fully offset the effects of FPL’s growing load. Therefore, FPL will need to secure 

more natural gas supply, more firm gas transportation capacity, and secure gas reserves in 

the future as fuel requirements dictate. The issue is how to secure these additional natural gas 

resources in a manner that is economical for FPL’s customers and which maintains and/or 

enhances the reliability of natural gas supply and deliverability to FPL’s generating units. 

FPL has historically purchased the gas transportation capacity required for new natural gas 

supply from two existing natural gas pipeline companies. As more natural gas is delivered 

through these two pipelines, the impact of a supply disruption on either pipeline becomes 

more problematic. Therefore, FPL issued a Request for Proposals (RFP) in December 2012 

for gas transportation capacity to meet FPL’s system natural gas requirements beginning in 

2017. The RFP encouraged bidders to propose new gas transportation infrastructure to meet 

Florida’s growing need for natural gas. A third pipeline would benefit FPL and its customers by 

increasing the diversity of FPL’s fuel supply sources, increasing the physical reliability of the 

pipeline delivery system, and enhancing competition among pipelines.

The RFP process was completed in June 2013, and the winning bidders were Sabal Trail 

Transmission, LLC (Sabal Trail) and Florida Southeast Connection, LLC (FSC). The contracts 

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with Sabal Trail and FSC were reviewed by the FPSC and approved for cost recovery in late 

2013. The order approving this cost recovery became final in January 2014. Sabal Trail and 

FSC are currently in the process of obtaining Federal Energy Regulatory Commission 

approval for the new pipelines. The planned in-service date for the pipelines is May 2017.

5. Nuclear Fuel Cost Forecast

This section reviews the various steps needed to fabricate nuclear fuel for delivery to the 

nuclear power plants, the method used to forecast the price for each step, and other 

comments regarding FPL’s nuclear fuel cost forecast.

a) Steps Required for Nuclear Fuel to be delivered to FPL’s Plants

Four separate steps are required before nuclear fuel can be used in a commercial nuclear 

power reactor. These steps are summarized below.

(1) Mining: Uranium is produced in many countries such as Canada, Australia, 

Kazakhstan, and the United States. During the first step, uranium is mined from the 

ground using techniques such as open pit mining, underground mining, in-situ leaching 

operations, or production as a by-product from other mining operations, such as gold, 

copper, or phosphate rocks. The product from this first step is the raw uranium delivered 

as an oxide, U3O8 (sometimes referred to as yellowcake). 

(2) Conversion: During the second step, the U3O8 is chemically converted into UF6 

which, when heated, changes into a gaseous state. This second step further removes any 

chemical impurities and serves as preparation for the third step, which requires uranium to 

be in a gaseous state. 

(3) Enrichment: The third step is called enrichment. Natural uranium contains 0.711% of 

uranium at an atomic mass of 235 (U-235) and 99.289% of uranium at an atomic mass of 

238 (U-238). FPL’s nuclear reactors use uranium with a higher percentage of up to almost 

five percent (5%) of U-235 atoms. Because natural uranium does not contain a sufficient 

amount of U-235, the third step increases the percentage amount of U-235 from 0.711% 

to a level specified when designing the reactor core (typically in a range from 

approximately 2.2% to as high as 4.95%). The output of this enrichment process is 

enriched uranium in the form of UF6.

(4) Fabrication: During the last step, fuel fabrication, the enriched UF6 is changed to a 

UO2 powder, pressed into pellets, and fed into tubes, which are sealed and bundled 

Florida Power & Light Company 87
together into fuel assemblies. These fuel assemblies are then delivered to the plant site 

for insertion in a reactor.

Like other utilities, FPL has purchased raw uranium and the other components of the nuclear 

fuel cycle separately from numerous suppliers from different countries.

b) Price Forecasts for Each Step

(1) Mining: The impact of the earthquake and tsunami that struck the Fukushima nuclear 

complex in Japan in March 2011 is still being felt in the uranium market. Current demand 

has declined and several of the production facilities have announced delays. Factors of 

importance are: 

• Hedge funds are still very active in the market. This causes more speculative 

demand that is not tied to market fundamentals and causes the market price to 

move up or down just based on news that might affect future demand.

• Some of the uranium inventory from the U.S. Department of Energy (DOE) is 

finding its way into the market periodically to fund cleanup of certain Department 

of Energy facilities.

• Although a limited number of new nuclear units are scheduled to start production 

in the U.S. during the next 5 to 10 years, other countries, more specifically China, 

have announced an increase in construction of new units which may cause 

uranium prices to trend up in the near future.

Over a 10-year horizon, FPL expects the market to be more consistent with market 

fundamentals. The supply picture is more stable, with laws enacted to resolve the import 

of Russian-enriched uranium, by allowing some imports of Russian-enriched uranium to 

meet about 20-25% of needs for currently operating units, but with no restriction on the 

first core for new units and no restrictions after 2020. New and current uranium production 

facilities continue to add capacity to meet demands. Actual demand tends to grow over 

time because of the long lead time to build nuclear units. However, FPL cannot discount 

the possibility of future periodic sharp increase in prices, but believes such occurrences 

will likely be temporary in nature.

(2) Conversion: The conversion market is also in a state of flux due to the Fukushima 

events. Planned production after 2018 is currently forecasted to be insufficient to meet the 

higher demand scenario, but it is projected to be sufficient to meet most reference case 

scenarios. As with additional raw uranium production, supply will expand beyond current 

Florida Power & Light Company 88
level once more firm commitments are made including commitments to build new nuclear 

units. FPL expects long term price stability for conversion services to support world 

demand.

 

(3) Enrichment: As a result of the Fukushima events in March 2011, the near-term price 

of enrichment services has been declining for the last three years. However, plans for 

construction of several new facilities that were expected to come on-line in the next few 

years have been delayed. Also, some of the existing high operating cost diffusion plants 

have shut down. As with supply for the other steps of the nuclear fuel cycle, expansion of 

future capacity is feasible within the lead time for constructing new nuclear units and any 

other projected increase in demand. Meanwhile, world supply and demand will continue 

to be balanced such that FPL expects adequate supply of enrichment services. The 

current supply/demand profile will most likely result in the price of enrichment services 

remaining stable for the next few years before starting to increase.

(4) Fabrication: Because the nuclear fuel fabrication process is highly regulated by the 

Nuclear Regulatory Commission (NRC), not all production facilities can qualify as 

suppliers to nuclear reactors in the U.S. Although world supply and demand is expected to 

show significant excess capacity for the foreseeable future, the gap is not as wide for U.S. 

supply and demand. The supply for the U.S. market is expected to be sufficient to meet 

U.S. demand for the foreseeable future. 

c) Other Comments Regarding FPL’s Nuclear Fuel Cost Forecast

FPL’s nuclear fuel price forecasts are the result of FPL’s analysis based on inputs from 

various nuclear fuel market expert reports and studies. The calculations for the nuclear 

fuel cost forecasts used in FPL’s 2014 and early 2015 resource planning work were 

performed consistent with the method then used for FPL’s Fuel Clause filings, including 

the assumption of refueling outages every 18 months and plant operation at current (i.e., 

power uprated) levels. The costs for each step to fabricate the nuclear fuel were added to 

come up with the total costs of the fresh fuel to be loaded at each refueling (acquisition 

costs). The acquisition cost for each group of fresh fuel assemblies were then amortized 

over the energy produced by each group of fuel assemblies. DOE notified FPL that, 

effective May 2014, all high level waste payments would be suspended until further notice. 

Therefore, FPL is no longer including in its nuclear fuel cost forecast a 1 mill per kilowatt

hour net to reflect payment to DOE for spent fuel disposal. 

Florida Power & Light Company 89
Fuel Requirements Units 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

 (1) Nuclear Trillion BTU 273 298 292 300 297 300 305 302 300 305 301 301

 (2) Coal 1,000 TON 3,540 2,649 2,585 2,376 2,131 2,061 2,288 1,984 2,081 2,056 2,097 1,962

 (3) Residual (FO6) - Total 1,000 BBL 150 409 239 270 6 23 84 52 67 92 73 57

 (4) Steam 1,000 BBL 150 409 239 270 6 23 84 52 67 92 73 57

 (5) Distillate (FO2) - Total 1,000 BBL 152 197 33 202 3 14 98 36 43 216 235 123

 (6) Steam 1,000 BBL 0 4 0 0 0 0 0 0 0 0 0 0

 (7) CC 1,000 BBL 140 123 3 43 3 12 80 29 38 147 157 83

 (8) CT 1,000 BBL 12 69 30 158 0 2 17 7 4 69 78 41

 (9) Natural Gas - Total 1,000 MCF 550,350 571,451 573,213 607,356 562,114 571,538 636,702 655,209 654,003 661,930 641,918 619,543

 (10) Steam 1,000 MCF 30,348 24,488 13,043 12,527 5,516 7,135 11,042 10,599 8,193 9,467 7,885 6,042

 (11) CC 1,000 MCF 514,793 542,409 559,815 593,301 552,012 557,972 611,146 636,305 639,200 644,223 624,799 607,913

 (12) CT 1,000 MCF 5,208 4,555 355 1,529 4,586 6,432 14,514 8,305 6,611 8,241 9,234 5,587

1/ Source: A Schedules.

Note: Solar contributions are provided on Schedules 6.1 and 6.2.

Actual 1/ Forecasted

Schedule 5

Fuel Requirements 

(for FPL only)

Florida Power & Light Company 90
Energy Sources Units 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

 (1) Annual Energy GWH 4,445 4,908 3,604 1,263 1,114 1,202 308 0 0 0 0 0

Interchange 2/

 (2) Nuclear GWH 25,243 26,812 27,800 28,527 28,249 28,500 29,048 28,710 28,553 29,048 28,626 28,637

 (3) Coal GWH 5,981 4,482 4,159 3,805 3,359 3,272 3,667 3,123 3,303 3,262 3,339 3,087

 (4) Residual(FO6) -Total GWH 75 231 155 171 4 15 52 33 43 58 46 36

 (5) Steam GWH 75 231 155 171 4 15 52 33 43 58 46 36

 (6) Distillate(FO2) -Total GWH 120 128 14 103 3 13 91 32 40 183 194 101

 (7) Steam GWH 2 2 0 0 0 0 0 0 0 0 0 0

 (8) CC GWH 114 102 3 41 3 12 83 29 38 144 151 78

 (9) CT GWH 5 23 11 62 0 1 8 3 2 38 43 22

 (10) Natural Gas -Total GWH 75,208 79,102 79,906 84,749 79,380 80,416 88,286 92,422 92,707 92,810 94,509 96,618

 (11) Steam GWH 2,472 1,906 1,279 1,214 537 684 1,077 1,001 790 912 763 577

 (12) CC GWH 72,308 76,857 78,594 83,405 78,404 79,108 85,809 90,628 91,279 91,100 92,854 95,500

 (13) CT GWH 428 340 33 130 439 623 1,400 793 638 797 893 540

 (14) Solar 3/ GWH 155 177 192 314 684 700 695 698 695 693 684 691

 (15) PV GWH 68 68 71 189 577 575 573 573 569 567 565 565

 (16) Solar Thermal GWH 87 109 121 126 107 125 122 126 125 125 119 126

 (17) Other 4/ GWH 428 127 3,882 3,474 11,152 11,315 4,923 3,833 3,896 4,023 4,097 4,107

-------------------------------------------- --------- --------- --------- --------- --------- --------- --------- --------- --------- --------- --------- ---------

Net Energy For Load 5/ GWH 111,656 115,968 119,712 122,407 123,945 125,433 127,070 128,851 129,237 130,077 131,495 133,276

1/ Source: A Schedules and Actual Data for Next Generation Solar Centers Report

2/ The projected figures are based on estimated energy purchases from SJRPP, the Southern Companies (UPS contract), and other utilities.

3/ Represents output from FPL's PV and solar thermal facilities.

4/ Represents a forecast of energy expected to be purchased from Qualifying Facilities, Independent Power Producers, net of 

Economy and other Power Sales.

5/ Net Energy For Load values for the years 2015- 2024 are also shown in Col. (19) on Schedule 2.3.

Actual 1/ Forecasted

Schedule 6.1

Energy Sources

Florida Power & Light Company 91
Energy Source Units 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

 (1) Annual Energy % 4.0 4.2 3.0 1.0 0.9 1.0 0.2 0.0 0.0 0.0 0.0 0.0

Interchange 2/

 (2) Nuclear % 22.6 23.1 23.2 23.3 22.8 22.7 22.9 22.3 22.1 22.3 21.8 21.5

 (3) Coal % 5.4 3.9 3.5 3.1 2.7 2.6 2.9 2.4 2.6 2.5 2.5 2.3

 (4) Residual (FO6) -Total % 0.1 0.2 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 (5) Steam % 0.1 0.2 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 (6) Distillate (FO2) -Total % 0.1 0.1 0.0 0.1 0.0 0.0 0.1 0.0 0.0 0.1 0.1 0.1

 (7) Steam % 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 (8) CC % 0.1 0.1 0.0 0.0 0.0 0.0 0.1 0.0 0.0 0.1 0.1 0.1

 (9) CT % 0.0 0.0 0.0 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 (10) Natural Gas -Total % 67.4 68.2 66.7 69.2 64.0 64.1 69.5 71.7 71.7 71.3 71.9 72.5

 (11) Steam % 2.2 1.6 1.1 1.0 0.4 0.5 0.8 0.8 0.6 0.7 0.6 0.4

 (12) CC % 64.8 66.3 65.7 68.1 63.3 63.1 67.5 70.3 70.6 70.0 70.6 71.7

 (13) CT % 0.4 0.3 0.0 0.1 0.4 0.5 1.1 0.6 0.5 0.6 0.7 0.4

 (14) Solar 3/ % 0.1 0.2 0.2 0.3 0.6 0.6 0.5 0.5 0.5 0.5 0.5 0.5

 (15) PV % 0.1 0.1 0.1 0.2 0.5 0.5 0.5 0.4 0.4 0.4 0.4 0.4

 (16) Solar Thermal % 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

 (17) Other 4/ % 0.4 0.1 3.2 2.8 9.0 9.0 3.9 3.0 3.0 3.1 3.1 3.1

100 100 100 100 100 100 100 100 100 100 100 100

1/ Source: A Schedules and Actual Data for Next Generation Solar Centers Report

2/ The projected figures are based on estimated energy purchases from SJRPP, the Southern Companies (UPS contract), and other utilities.

3/ Represents output from FPL's PV and solar thermal facilities.

4/ Represents a forecast of energy expected to be purchased from Qualifying Facilities, Independent Power Producers, net of 

Economy and other Power Sales.

Actual 1/ Forecasted

Schedule 6.2

Energy Sources % by Fuel Type

Florida Power & Light Company 92
(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12) (13) (14) (15) (16)

Total Firm

Firm Firm Firm Firm Total Summer

 Installed Capacity Capacity Firm Capacity Peak Peak Scheduled

August of Capacity Import Export QF Available Demand DSM Demand Maintenance

Year MW MW MW MW MW MW MW MW MW % of Peak MW MW % of Peak MW % of Peak 

2015 25,008 1,420 0 595 27,022 23,286 1,951 21,335 5,688 26.7 0 5,688 26.7 3,736 16.0

2016 25,585 492 0 345 26,421 23,778 2,000 21,779 4,643 21.3 0 4,643 21.3 2,643 11.1

2017 26,001 492 0 345 26,838 24,252 2,046 22,207 4,631 20.9 0 4,631 20.9 2,585 10.7

2018 26,024 699 0 345 27,067 24,648 2,092 22,555 4,512 20.0 0 4,512 20.0 2,420 9.8

2019 27,665 110 0 345 28,120 25,045 2,140 22,905 5,215 22.8 0 5,215 22.8 3,075 12.3

2020 27,665 110 0 345 28,119 25,369 2,188 23,181 4,938 21.3 0 4,938 21.3 2,750 10.8

2021 27,752 110 0 525 28,387 25,497 2,237 23,260 5,127 22.0 0 5,127 22.0 2,890 11.3

2022 27,838 110 0 525 28,472 25,833 2,287 23,546 4,926 20.9 0 4,926 20.9 2,640 10.2

2023 29,154 110 0 525 29,789 26,286 2,338 23,948 5,841 24.4 0 5,841 24.4 3,503 13.3

2024 29,154 110 0 525 29,789 26,771 2,389 24,381 5,407 22.2 0 5,407 22.2 3,018 11.3

Col. (2) represents capacity additions and changes projected to be in-service by June 1st. These MW are generally considered to be available to meet 

peak loads which are forecasted to occur during August of the year indicated.

Col. (6) = Col.(2) + Col.(3) - Col(4) + Col(5).

Col.(7) reflects the 2014 load forecast without incremental DSM or cumulative load management. 2014 load is an actual load value.

Col.(8) represents cumulative load management capability, plus incremental conservation and load management, from 9/2014-on intended for use with 

2014 load forecast.

Col.(10) = Col.(6) - Col.(9)

Col.(11) = Col.(10) / Col.(9)

Col.(12) indicates the capacity of units projected to be out-of-service for planned maintenance during the summer peak period.

Col.(13) = Col.(10) - Col.(12)

Col.(14) = Col.(13) / Col.(9)

Col.(15) = Col.(6) - Col.(7) - Col.(12)

Col.(16) = Col.(15) / Col.(7)

Schedule 7.1

Forecast of Capacity, Demand, and Scheduled

Maintenance At Time Of Summer Peak

Maintenance Maintenance

Total Generation Only 

Reserve Reserve Reserve

Margin Before Margin After Margin After

Maintenance

Total

Florida Power & Light Company 93
(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12) (13) (14) (15) (16)

Total Firm

Firm Firm Firm Firm Total Winter

 Installed Capacity Capacity Firm Capacity Peak Peak Scheduled

January of Capacity Import Export QF Available Demand DSM Demand Maintenance

Year MW MW MW MW MW MW MW MW MW % of Peak MW MW % of Peak MW % of Peak 

2015 26,758 1,357 0 595 28,710 21,136 1,452 19,684 9,026 45.9 0 9,026 45.9 7,574 35.8

2016 27,205 499 0 345 28,049 21,369 1,483 19,886 8,163 41.1 0 8,163 41.1 6,680 31.3

2017 27,842 499 0 345 28,686 21,485 1,510 19,976 8,710 43.6 0 8,710 43.6 7,201 33.5

2018 27,958 499 0 345 28,802 21,598 1,537 20,061 8,740 43.6 0 8,740 43.6 7,204 33.4

2019 27,978 499 0 345 28,822 21,792 1,565 20,227 8,595 42.5 0 8,595 42.5 7,030 32.3

2020 29,573 110 0 345 30,028 21,965 1,593 20,372 9,655 47.4 0 9,655 47.4 8,063 36.7

2021 29,573 110 0 525 30,208 22,096 1,622 20,475 9,733 47.5 0 9,733 47.5 8,111 36.7

2022 29,648 110 0 525 30,283 22,026 1,651 20,374 9,908 48.6 0 9,908 48.6 8,257 37.5

2023 29,737 110 0 525 30,372 22,202 1,682 20,520 9,852 48.0 0 9,852 48.0 8,170 36.8

2024 31,210 110 0 525 31,845 22,408 1,713 20,695 11,150 53.9 0 11,150 53.9 9,437 42.1

Col. (2) represents capacity additions and changes projected to be in-service by January 1st. These MW are generally considered to be available to

 meet winter peak loads which are forecasted to occur during January of the year indicated.

Col. (6) = Col.(2) + Col.(3) - Col(4) + Col(5).

Col.(7) reflects the 2014 load forecast without incremental DSM or cumulative load management. 2014 load is an actual load value.

Col.(8) represents cumulative load management capability, plus incremental conservation and load management, from 9/2014-on intended for use with

 the 2014 load forecast.

Col.(10) = Col.(6) - Col.(9)

Col.(11) = Col.(10) / Col.(9)

Col.(12) indicates the capacity of units projected to be out-of-service for planned maintenance during the winter peak period.

Col.(13) = Col.(10) - Col.(12)

Col.(14) = Col.(13) / Col.(9)

Col.(15) = Col.(6) - Col.(7) - Col.(12)

Col.(16) = Col.(15) / Col.(7)

Total Total Generation Only 

Schedule 7.2

Reserve Reserve Reserve

Forecast of Capacity, Demand, and Scheduled

Maintenance At Time Of Winter Peak

Margin Before Margin After Margin After

Maintenance Maintenance Maintenance

Florida Power & Light Company 94
Page 1 of 2

(2) (3) (4) (5) (5) (7) (8) (9) (10) (11) (12) (13) (14) (15)

 Const. Comm. Expected Gen. Max.

Unit Unit Start In-Service Retirement Nameplate Winter Summer

Plant Name No. Location Type Pri. Alt. Pri. Alt. Mo./Yr. Mo./Yr. Mo./Yr. KW MW MW Status

ADDITIONS/ CHANGES

2015

Cape Canaveral Energy Center 3 Brevard County CC NG FO2 PL TK - Jan-15 Unknown 1,295,400 77 - OT

Fort Myers 2 Lee County CC NG No PL No - Jan-15 Unknown 1,721,490 9 0 OT

Fort Myers 3 Lee County CT NG FO2 PL TK - Jan-15 Unknown 188,190 6 (5) P

FT. Myers GT 1-12 Lee County GT FO2 No TK No - Jan-15 Unknown 744,120 28 - OT

Lauderdale 4 Broward County CC NG FO2 PL PL - Jan-15 Unknown 526,250 17 - OT

Lauderdale 5 Broward County CC NG FO2 PL PL - Jan-15 Unknown 526,250 16 - OT

Lauderdale GT 1-12 Broward County GT NG FO2 PL PL - Jan-15 Unknown 410,734 (13) (8) P

Lauderdale GT 13-24 Broward County GT NG FO2 PL PL - Jan-15 Unknown 410,734 (13) (8) P

Manatee 3 Manatee County CC NG No PL No - Jan-15 Unknown 1,224,510 20 - OT

Martin 2 Martin County ST FO6 NG PL PL - Jun-15 Unknown 934,500 - (3) OT

Martin 3 Martin County CC NG No PL No - Jan-15 Unknown 612,000 16 - OT

Martin 4 Martin County CC NG No PL No - Jan-15 Unknown 612,000 14 - OT

Port Everglades GT 1-12 City of Hollywood GT NG FO2 PL PL Jan-15 Unknown 410,734 (13) (8) P

Riviera Beach Energy Center 5 City of Riviera Beach CC NG FO2 PL WA - Jan-15 Unknown 1,295,400 44 - OT

Sanford 4 Volusia County CC NG No PL No - Jan-15 Unknown 1,188,860 2 - OT

Sanford 5 Volusia County CC NG No PL No - Jan-15 Unknown 1,188,860 2 - OT

Scherer 4 Monroe, GA ST SUB No RR No - Jun-15 Unknown 680,368 - (9) OT

St. Lucie 1 St. Lucie County ST Nuc No TK No - Jan-15 Unknown 1,020,000 (22) - OT

St. Lucie 2 St. Lucie County ST Nuc No TK No - Jan-15 Unknown 723,775 (20) - OT

Turkey Point 3 Miami Dade County ST Nuc No TK No - Jan-15 Unknown 877,200 (28) - OT

Turkey Point 4 Miami Dade County ST Nuc No TK No - Jan-15 Unknown 877,200 (27) - OT

Turkey Point 5 Miami Dade County CC NG FO2 PL TK - Jan-15 Unknown 1,224,510 (24) (22) OT

West County 1 1 Palm Beach County CC NG FO2 PL TK - Jan-15 Unknown 1,366,800 11 - OT

West County 2 2 Palm Beach County CC NG FO2 PL TK - Jan-15 Unknown 1,366,800 11 - OT

West County 3 3 Palm Beach County CC NG FO2 PL TK - Jan-15 Unknown 1,366,800 11 - OT

2015 Changes/Additions Total: 125 (64)

2016

Cedar Bay (Ownership) 1 Duval County ST BIT No RR No - Oct-15 - - 250 250 P

Fort Myers 2 Lee County CC NG No PL No - Jun-16 Unknown 1,721,490 216 37 P

FT. Myers GT 1-12 Lee County GT FO2 No TK No - - Jun-16 744,120 - (540) P

Lauderdale GT 1-12 Broward County GT NG FO2 PL PL - - Jun-16 410,734 - (412) P

Martin 2 Martin County ST FO6 NG PL PL - - Unknown 934,500 (3) - OT

Martin 8 Martin County CC NG FO2 PL TK - - Unknown 1,224,510 - 2 OT

Port Everglades 1 City of Hollywood GT NG FO2 PL PL - Jun-16 Unknown 410,734 - 1,237 U

Sanford 4 Volusia County CC NG No PL No - - Unknown 1,188,860 - 3 OT

Scherer 4 Monroe, GA ST SUB No RR No - - Unknown 680,368 (16) - OT

2016 Changes/Additions Total: 447 577

2017

Babcock Solar Energy Center 1 Charlotte County PV Solar Solar N/A N/A - Sep-16 Unknown - - 38 P

Cedar Bay 1 Duval County ST BIT No RR No - - Dec-16 - (250) (250) OT

Citrus Solar Energy Center 1 DeSoto County PV Solar Solar N/A N/A - Sep-16 Unknown - - 38 P

Fort Myers 2 Lee County CC NG No PL No - Jan-17 Unknown 1,721,490 20 - P

Fort Myers 3 Lee County CT NG FO2 PL TK - Dec-16 Unknown 188,190 50 50 OT

Ft. Myers - 2 CT 2 Lee County CC NG No PL No - Dec-16 Unknown 1,721,490 446 462 P

FT. Myers GT 1-12 Lee County GT FO2 No TK No - - Jun-16 744,120 (615) - P

Lauderdale 5CT 5 Broward County CC NG FO2 PL PL - Dec-16 Unknown 526,250 1,115 1,155 P

Lauderdale GT 1-12 Broward County GT NG FO2 PL PL - - Jun-16 410,734 (446) - P

Lauderdale GT 13-22 Broward County GT NG FO2 PL PL - - Jun-16 410,734 (372) (343) P

Manatee 3 Manatee County CC NG No PL No - Jun-17 Unknown 1,224,510 - 4 OT

Manatee Solar Energy Center 1 Manatee County PV Solar Solar N/A N/A - Sep-16 Unknown - - 38 P

Martin 8 Martin County CC NG FO2 PL TK - Jan-17 Unknown 1,224,510 27 2 OT

Port Everglades 1 City of Hollywood GT NG FO2 PL PL - Jun-16 Unknown 410,734 1,429 - OT

Port Everglades GT 1-12 City of Hollywood GT NG FO2 PL PL - Dec-16 Unknown 410,734 (446) (412) P

Sanford 4 Volusia County CC NG No PL No - Jan-17 Unknown 1,188,860 52 1 OT

Sanford 5 Volusia County CC NG No PL No - Jan-17 Unknown 1,188,860 26 4 OT

Turkey Point(3) 1 Miami Dade County ST FO6 NG WA PL - - Oct-16 402,050 (398) (396) OT

Turkey Point 5 Miami Dade County CC NG FO2 PL TK - Jun-17 Unknown 1,224,510 - 23 OT

2017 Changes/Additions Total: 637 415

(1) Schedule 8 shows only planned and prospective changes to generating facilities and does not reflect changes to existing purchases. Those changes are 

reflected on Tables ES-1, I.B.1 and I.B.2.

(2) The Winter Total MW value consists of all generation additions and changes achieved by January. The Summer Total MW value consists of all generation additions and changes 

achieved by June. All MW additions/changes occurring after August each year will be picked up for reserve margin calculation purposes in the following year. 

(3) This generating unit will serve as a synchronous condenser and will not be included in reserve margin calculation.

Fuel Transport Net Capability (2)

Schedule 8

 Planned And Prospective Generating Facility Additions And Changes (1)

Fuel Firm

Florida Power & Light Company 95
Page 2 of 2

(2) (3) (4) (5) (5) (7) (8) (9) (10) (11) (12) (13) (14) (15)

 Const. Comm. Expected Gen. Max.

Unit Unit Start In-Service Retirement Nameplate Winter Summer

Plant Name No. Location Type Pri. Alt. Pri. Alt. Mo./Yr. Mo./Yr. Mo./Yr. KW MW MW Status

ADDITIONS/ CHANGES

2018

Manatee 3 Manatee County CC NG No PL No - - Unknown 1,224,510 40 - OT

Martin 8 Martin County CC NG FO2 PL TK - - Unknown 1,224,510 12 - OT

Sanford 5 Volusia County CC NG No PL No - - Unknown 1,188,860 25 - OT

Turkey Point 3 Miami Dade County ST Nuc No TK No - - Unknown 877,200 20 20 OT

Turkey Point 5 Miami Dade County CC NG FO2 PL TK - - Unknown 1,224,510 19 3 OT

2018 Changes/Additions Total: 116 23

2019

Okeechobee Energy Center 1 Okeechobee County CC NG FO2 PL TK Jun-17 Jun-19 Unknown - - 1,622 P

Turkey Point 4 Miami Dade County ST Nuc No TK No - - Unknown 877,200 20 20 OT

2019 Changes/Additions Total: 20 1,642

2020

Okeechobee Energy Center 1 Okeechobee County CC NG FO2 PL TK Jun-17 Jun-19 Unknown - 1,595 - P

2020 Changes/Additions Total: 1,595 0

2021

Cape Canaveral Energy Center 3 Brevard County CC NG FO2 PL TK - Jun-21 Unknown 1,295,400 - 88 OT

2021 Changes/Additions Total: 0 88

2022

Cape Canaveral Energy Center 3 Brevard County CC NG FO2 PL TK - - Unknown 1,295,400 75 - OT

Riviera Beach Energy Center 5 City of Riviera Beach CC NG FO2 PL WA - Jun-22 Unknown 1,295,400 - 86 OT

2022 Changes/Additions Total: 75 86

2023

Riviera Beach Energy Center 5 City of Riviera Beach CC NG FO2 PL WA - - Unknown 1,295,400 89 - OT

Unsited CC CC NG FO2 PL TK Jun-21 Jun-23 Unknown - - 1,317 P

2023 Changes/Additions Total: 89 1,317

2024

Unsited CC CC NG FO2 PL TK Jun-21 Jun-23 Unknown - 1,473 - P

2024 Changes/Additions Total: 1,473 0

(1) Schedule 8 shows only planned and prospective changes to generating facilities and does not reflect changes to existing purchases. Those changes are reflected on Tables ES-1, I.B.1 and I.B.2.

(2) The Winter Total MW value consists of all generation additions and changes achieved by January. The Summer Total MW value consists of all generation additions and changes. 

achieved by June. All MW additions/changes occurring after August each year will be picked up for reserve margin calculation purposes in the following year. 

Fuel Transport Net Capability (2)

Schedule 8

 Planned And Prospective Generating Facility Additions And Changes (1)

Fuel Firm

Florida Power & Light Company 96
Page 1 of 8

Schedule 9

Status Report and Specifications of Proposed Generating Facilities

(1) Plant Name and Unit Number: Port Everglades Next Generation Clean Energy Center

(2) Capacity

a. Summer 1,237 MW

b. Winter 1,429 MW

(3) Technology Type: Combined Cycle

(4) Anticipated Construction Timing

a. Field construction start-date: 2014

b. Commercial In-service date: 2016

(5) Fuel

a. Primary Fuel Natural Gas

b. Alternate Fuel Ultra-low sulfur distillate

(6) Air Pollution and Control Strategy: Dry Low Nox Burners, SCR, Natural Gas, 

0.0015% S. Distillate and Water Injection on Distillate

(7) Cooling Method: Once-through cooling water

(8) Total Site Area: Existing Site Acres

(9) Construction Status: U (Under construction, less than or equal to 50% complete)

(10) Certification Status: ---

(11) Status with Federal Agencies: ---

(12) Projected Unit Performance Data:

Planned Outage Factor (POF): 3.5%

Forced Outage Factor (FOF): 1.1%

Equivalent Availability Factor (EAF): 95.4%

Resulting Capacity Factor (%): Approx. 90% (First Full Year Base Operation) 

Average Net Operating Heat Rate (ANOHR): 6,330 Btu/kWh

Base Operation 75F,100%

(13) Projected Unit Financial Data *,**

Book Life (Years): 30 years

Total Installed Cost (2016 $/kW): 928

Direct Construction Cost ($/kW): 841

AFUDC Amount ($/kW): 87

Escalation ($/kW): Accounted for in Direct Construction Cost

Fixed O&M ($/kW-Yr): (2016 $) 30.00

Variable O&M ($/MWH): (2016 $) 0.10

K Factor: 1.51

 * $/kW values are based on Summer capacity.

** Fixed O&M cost includes capital replacement.

Note: Total installed cost includes gas expansion, transmission interconnection and integration,

 escalation, and AFUDC. Demolition costs of existing plant are not included.

Florida Power & Light Company 97
Page 2 of 8

Schedule 9

Status Report and Specifications of Proposed Generating Facilities

(1) Plant Name and Unit Number: Fort Myers CT (2 CTs will be added)

(2) Capacity (for each CT)

a. Summer 211 MW plus 20 MW of peaking capacity

b. Winter 223 MW

(3) Technology Type: Combustion Turbine

(4) Anticipated Construction Timing

a. Field construction start-date: 2015

b. Commercial In-service date: 2016

(5) Fuel

a. Primary Fuel Natural Gas

b. Alternate Fuel Ultra-low sulfur distillate

(6) Air Pollution and Control Strategy: Dry Low NOx Burners, SCR, Natural Gas, 

0.0015% S. Distillate and Water Injection on Distillate

(7) Cooling Method: Water to Air Heat Exchangers

(8) Total Site Area: Existing Site Acres

(9) Construction Status: P (Planned Unit)

(10) Certification Status: ---

(11) Status with Federal Agencies: ---

(12) Projected Unit Performance Data:

Planned Outage Factor (POF): 3.0%

Forced Outage Factor (FOF): 1.0%

Equivalent Availability Factor (EAF): 96.0%

Resulting Capacity Factor (%): Approx. 3% (First Full Year Base Operation) 

Average Net Operating Heat Rate (ANOHR): 10,075 Btu/kWh 

Base Operation 75F,100%

Average Net Incremental Heat Rate (ANIHR): 7,644 Btu/kWh 

Peak Operation 75F,100%

(13) Projected Unit Financial Data *,**

Book Life (Years): 30 years

Total Installed Cost (2016 $/kW): 441

Direct Construction Cost ($/kW): 422

AFUDC Amount (2016 $/kW): 19

Escalation ($/kW): Accounted for in Direct Construction Cost

Fixed O&M ($/kW-Yr): 2.63

Variable O&M (2016 $/MWH): 0.00

K Factor: 1.38

 * $/kW values are based on Summer capacity.

** Levelized value includes Fixed O&M and Capital Replacement

Note: Total installed cost includes transmission interconnection and integration,

 escalation, and AFUDC. Demolition costs of existing GTs are not included.

Florida Power & Light Company 98
Page 3 of 8

Schedule 9

Status Report and Specifications of Proposed Generating Facilities

(1) Plant Name and Unit Number: Lauderdale CT (5 CTs will be added)

(2) Capacity (for each CT)

a. Summer 211 MW plus 20 MW of peaking capacity

b. Winter 223 MW

(3) Technology Type: Combustion Turbine

(4) Anticipated Construction Timing

a. Field construction start-date: 2015

b. Commercial In-service date: 2016

(5) Fuel

a. Primary Fuel Natural Gas

b. Alternate Fuel Ultra-low sulfur distillate

(6) Air Pollution and Control Strategy: Dry Low NOx Burners, SCR, Natural Gas, 

0.0015% S. Distillate and Water Injection on Distillate

(7) Cooling Method: Water to Air Heat Exchangers

(8) Total Site Area: Existing Site Acres

(9) Construction Status: P (Planned Unit)

(10) Certification Status: ---

(11) Status with Federal Agencies: ---

(12) Projected Unit Performance Data:

Planned Outage Factor (POF): 3.0%

Forced Outage Factor (FOF): 1.0%

Equivalent Availability Factor (EAF): 96.0%

Resulting Capacity Factor (%): Approx. 3% (First Full Year Base Operation) 

Average Net Operating Heat Rate (ANOHR): 10,203 Btu/kWh 

Base Operation 75F,100%

Average Net Incremental Heat Rate (ANIHR): 7,528 Btu/kWh 

Peak Operation 75F,100%

(13) Projected Unit Financial Data *,**

Book Life (Years): 30 years

Total Installed Cost (2016 $/kW): 433

Direct Construction Cost ($/kW): 411

AFUDC Amount (2016 $/kW): 22

Escalation ($/kW): Accounted for in Direct Construction Cost

Fixed O&M ($/kW-Yr): 3.26

Variable O&M (2016 $/MWH): 0.00

K Factor: 1.39

 * $/kW values are based on Summer capacity.

** Levelized value includes Fixed O&M and Capital Replacement

Note: Total installed cost includes transmission interconnection and integration, 

 escalation, and AFUDC. Demolition costs of existing GTs are not included.

Florida Power & Light Company 99
Page 4 of 8

Schedule 9

Status Report and Specifications of Proposed Generating Facilities

(1) Plant Name and Unit Number: Citrus Solar Energy Center (DeSoto County)

(2) Capacity (for each CT)

a. Nameplate (AC) 74.5 MW

b. Summer Firm (AC) 38.7 MW

c. Winter Firm (AC) -

(3) Technology Type: Photovoltaic (PV)

(4) Anticipated Construction Timing

a. Field construction start-date: 2015

b. Commercial In-service date: 2016

(5) Fuel

a. Primary Fuel Sun

b. Alternate Fuel Sun

(6) Air Pollution and Control Strategy: Not applicable

(7) Cooling Method: Not applicable

(8) Total Site Area: 841 Acres

(9) Construction Status: P (Planned Unit)

(10) Certification Status: ---

(11) Status with Federal Agencies: ---

(12) Projected Unit Performance Data:

Planned Outage Factor (POF): Not applicable

Forced Outage Factor (FOF): Not applicable

Equivalent Availability Factor (EAF): Not applicable

Resulting Capacity Factor (%): 26% (First Full Year Operation) 

Average Net Operating Heat Rate (ANOHR): Not applicable

Base Operation 75F,100%

Average Net Incremental Heat Rate (ANIHR): Not applicable

Peak Operation 75F,100%

(13) Projected Unit Financial Data *

Book Life (Years): 30 years

Total Installed Cost (2016 $/kW): 1,835

Direct Construction Cost ($/kW): 1,835

AFUDC Amount (2016 $/kW): 0

Escalation ($/kW): Accounted for in Direct Construction Cost

Fixed O&M ($/kW-Yr): (2016 $) 5.39 (First Full Year Operation) 

Variable O&M ($/MWH): (2016 $) 0.00

K Factor: 0.96

 * $/kW values are based on nameplate capacity.

Note: Total installed cost includes transmission interconnection.

Florida Power & Light Company 100
Page 5 of 8

Schedule 9

Status Report and Specifications of Proposed Generating Facilities

(1) Plant Name and Unit Number: Manatee Solar Energy Center (Manatee County)

(2) Capacity (for each CT)

a. Nameplate (AC) 74.5 MW

b. Summer Firm (AC) 38.7 MW

c. Winter Firm (AC) -

(3) Technology Type: Photovoltaic (PV)

(4) Anticipated Construction Timing

a. Field construction start-date: 2015

b. Commercial In-service date: 2016

(5) Fuel

a. Primary Fuel Sun

b. Alternate Fuel Sun

(6) Air Pollution and Control Strategy: Not applicable

(7) Cooling Method: Not applicable

(8) Total Site Area: 762 Acres

(9) Construction Status: P (Planned Unit)

(10) Certification Status: ---

(11) Status with Federal Agencies: ---

(12) Projected Unit Performance Data:

Planned Outage Factor (POF): Not applicable

Forced Outage Factor (FOF): Not applicable

Equivalent Availability Factor (EAF): Not applicable

Resulting Capacity Factor (%): 26% (First Full Year Operation) 

Average Net Operating Heat Rate (ANOHR): Not applicable Btu/kWh 

Base Operation 75F,100%

Average Net Incremental Heat Rate (ANIHR): Not applicable Btu/kWh 

Peak Operation 75F,100%

(13) Projected Unit Financial Data *

Book Life (Years): 30 years

Total Installed Cost (2016 $/kW): 1,835

Direct Construction Cost ($/kW): 1,835

AFUDC Amount (2016 $/kW): 0

Escalation ($/kW): Accounted for in Direct Construction Cost

Fixed O&M ($/kW-Yr): (2016 $) 5.39 (First Full Year Operation) 

Variable O&M ($/MWH): (2016 $) 0.00

K Factor: 0.96

 * $/kW values are based on nameplate capacity.

Note: Total installed cost includes transmission interconnection.

Florida Power & Light Company 101
Page 6 of 8

Schedule 9

Status Report and Specifications of Proposed Generating Facilities

(1) Plant Name and Unit Number: Babcock Solar Energy Center (Charlotte County)

(2) Capacity (for each CT)

a. Nameplate (AC) 74.5 MW

b. Summer Firm (AC) 38.7 MW

c. Winter Firm (AC) -

(3) Technology Type: Photovoltaic (PV)

(4) Anticipated Construction Timing

a. Field construction start-date: 2015

b. Commercial In-service date: 2016

(5) Fuel

a. Primary Fuel Sun

b. Alternate Fuel Sun

(6) Air Pollution and Control Strategy: Not applicable

(7) Cooling Method: Not applicable

(8) Total Site Area: 443 Acres

(9) Construction Status: P (Planned Unit)

(10) Certification Status: ---

(11) Status with Federal Agencies: ---

(12) Projected Unit Performance Data:

Planned Outage Factor (POF): Not applicable

Forced Outage Factor (FOF): Not applicable

Equivalent Availability Factor (EAF): Not applicable

Resulting Capacity Factor (%): 26% (First Full Year Operation) 

Average Net Operating Heat Rate (ANOHR): Not applicable Btu/kWh 

Base Operation 75F,100%

Average Net Incremental Heat Rate (ANIHR): Not applicable Btu/kWh 

Peak Operation 75F,100%

(13) Projected Unit Financial Data *

Book Life (Years): 30 years

Total Installed Cost (2016 $/kW): 1,835

Direct Construction Cost ($/kW): 1,835

AFUDC Amount (2016 $/kW): 0

Escalation ($/kW): Accounted for in Direct Construction Cost

Fixed O&M ($/kW-Yr): (2016 $) 5.39 (First Full Year Operation) 

Variable O&M ($/MWH): (2016 $) 0.00

K Factor: 0.96

 * $/kW values are based on nameplate capacity.

Note: Total installed cost includes transmission interconnection.

Florida Power & Light Company 102
Page 7 of 8

Schedule 9

Status Report and Specifications of Proposed Generating Facilities

(1) Plant Name and Unit Number: Okeechobee Clean Energy Center

(2) Capacity

a. Summer 1,622 MW 

b. Winter 1,595 MW

(3) Technology Type: Combined Cycle

(4) Anticipated Construction Timing

a. Field construction start-date: 2017

b. Commercial In-service date: 2019

(5) Fuel

a. Primary Fuel Natural Gas

b. Alternate Fuel Ultra Low Sulfur Light Distillate

(6) Air Pollution and Control Strategy: Dry Low Nox Burners, SCR, Natural Gas,

0.0015% S. Distillate and Water Injection on Distillate

(7) Cooling Method: Mechanical Draft Cooling Towers

(8) Total Site Area: 2,842 Acres

(9) Construction Status: P (Planned Unit)

(10) Certification Status: ---

(11) Status with Federal Agencies: ---

(12) Projected Unit Performance Data:

Planned Outage Factor (POF): 2.2%

Forced Outage Factor (FOF): 1.1%

Equivalent Availability Factor (EAF): 96.7%

Resulting Capacity Factor (%): Approx. 80% (First Full Year Base Operation)

Average Net Operating Heat Rate (ANOHR): 6,304 Btu/kWh

Base Operation 75F,100%

Average Net Incremental Heat Rate (ANOHR): 7,731 Btu/kWh

Peak Operation 75F,100%

(13) Projected Unit Financial Data *,**

Book Life (Years): 30 years

Total Installed Cost ( 2019 $/kW): 737

Direct Construction Cost ($/kW): 668

AFUDC Amount (2019 $/kW): 69

Escalation ($/kW): Accounted for in Direct Construction Cost

Fixed O&M ($/kW-Yr): 16.89

Variable O&M (2019 $/MWH): 0.28

K Factor: 1.45

 * $/kW values are based on Summer capacity.

** Levelized value includes Fixed O&M and Capital Replacement

Note: Total installed cost includes transmission interconnection and integration,

 and AFUDC. 

Florida Power & Light Company 103
Page 8 of 8

Schedule 9

Status Report and Specifications of Proposed Generating Facilities

(1) Plant Name and Unit Number: Unsited 3x1 CC

(2) Capacity

a. Summer 1,317 MW

b. Winter 1,473 MW

(3) Technology Type: Combined Cycle

(4) Anticipated Construction Timing

a. Field construction start-date: 2021

b. Commercial In-service date: 2023

(5) Fuel

a. Primary Fuel Natural Gas

b. Alternate Fuel Ultra-low sulfur distillate

(6) Air Pollution and Control Strategy: Dry Low NOx Burners, SCR, Natural Gas, 

0.0015% S. Distillate and Water Injection on Distillate

(7) Cooling Method: Mechanical Draft Cooling Towers

(8) Total Site Area: TBD Acres

(9) Construction Status: P (Planned Unit)

(10) Certification Status: ---

(11) Status with Federal Agencies: ---

(12) Projected Unit Performance Data:

Planned Outage Factor (POF): 2.3%

Forced Outage Factor (FOF): 1.1%

Equivalent Availability Factor (EAF): 96.6%

Resulting Capacity Factor (%): Approx. 80% (First Full Year Base Operation) 

Average Net Operating Heat Rate (ANOHR): 6,307 Btu/kWh

Base Operation 75F,100%

(13) Projected Unit Financial Data *,**

Book Life (Years): 30 years

Total Installed Cost (2023 $/kW): 923

Direct Construction Cost ($/kW): 839

AFUDC Amount ($/kW): 84

Escalation ($/kW): Accounted for in Direct Construction Cost

Fixed O&M ($/kW-Yr): 39.5

Variable O&M (2023 $/MWH): 0.37

K Factor: 1.51

 * $/kW values are based on Summer capacity.

** Levelized value includes Fixed O&M and Capital Replacement

Note: Total installed cost includes transmission interconnection and integration,

 and AFUDC. Actual transmission and interconnection costs are unknown for 

 an unsited unit. The transmission interconnection and integration costs 

 for the unsited unit are based on the costs for the Okeechobee Clean

 Energy Center

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Schedule 10

Status Report and Specifications of Proposed Transmission Lines

Port Everglades Next Generation Clean Energy Center

The Port Everglades Next Generation Clean Energy Center which will result from the modernization of the 

Port Everglades power plant site does not require any “new” transmission lines.

Florida Power & Light Company 105
Schedule 10

Status Report and Specifications of Proposed Transmission Lines

Fort Myers Plant Gas Turbine Replacement and CT Upgrade

The Fort Myers Plant gas turbine replacement and CT upgrade projects do not require any “new” 

transmission lines.

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Schedule 10

Status Report and Specifications of Proposed Transmission Lines

Lauderdale Plant Gas Turbine Replacement

The Lauderdale Plant Gas Turbine Replacement project does not require any “new” transmission lines.

Florida Power & Light Company 107
Schedule 10

Status Report and Specifications of Proposed Transmission Lines

Citrus Solar Energy Center (DeSoto)

The Citrus Solar Energy Center (DeSoto) will require one new line to connect the PV inverter array to the 

expanded Sunshine Substation.

(1) Point of Origin and Termination: Skylight – Sunshine Substation

(2) Number of Lines: 1

(3) Right-of-way FPL – Owned

(4) Line Length: 1.5 miles 

(5) Voltage: 230 kV

(6) Anticipated Construction Timing: Start date: 2015

End date: 2016

(7) Anticipated Capital Investment: Included in total installed cost on schedule 9

 (Trans. and Sub.)

(8) Substations: Skylight Substation and Sunshine Substation

(9) Participation with Other Utilities: None

Florida Power & Light Company 108
Schedule 10

Status Report and Specifications of Proposed Transmission Lines

Manatee Solar Energy Center (Manatee)

The Manatee Solar Energy Center will require one new line to connect the PV inverter array to the 

expanded Manatee Switchyard.

(1) Point of Origin and Termination: Helios – Manatee Switchyard

(2) Number of Lines: 1

(3) Right-of-way FPL – Owned

(4) Line Length: 1.5 miles 

(5) Voltage: 230 kV

(6) Anticipated Construction Timing: Start date: 2015

End date: 2016

(7) Anticipated Capital Investment: Included in total installed cost on schedule 9

 (Trans. and Sub.)

(8) Substations: Helios Substation and Manatee Switchyard

(9) Participation with Other Utilities: None

Florida Power & Light Company 109
Schedule 10

Status Report and Specifications of Proposed Transmission Lines

Babcock Solar Energy Center (Charlotte)

The Babcock Solar Energy Center (Charlotte) will require one new line to connect the PV inverter array to 

the planned Freeland Substation.

(1) Point of Origin and Termination: Webb – Freeland Substation

(2) Number of Lines: 1

(3) Right-of-way FPL – Owned

(4) Line Length: 5 miles 

(5) Voltage: 230 kV

(6) Anticipated Construction Timing: Start date: 2015

End date: 2016

(7) Anticipated Capital Investment: Included in total installed cost on schedule 9

 (Trans. and Sub.)

(8) Substations: Webb Substation and Freeland Substation

(9) Participation with Other Utilities: None

Florida Power & Light Company 110
Schedule 10

Status Report and Specifications of Proposed Transmission Lines

Okeechobee Next Generation Clean Energy Center

The Okeechobee Next Generation Clean Energy Center does not require any “new” transmission lines.

Florida Power & Light Company 111
Schedule 10

Status Report and Specifications of Proposed Transmission Lines

Unsited 3x1 CC

No site has been determined, therefore no transmission analysis is possible.

Florida Power & Light Company 112
(1) (2) (3) (4) (5) (6) (7)

NEL Fuel Mix

Generation by Primary Fuel Summer (MW) Summer (%) Winter (MW) Winter (%) GWh (2) %

(1) Coal 897 3.3% 911 3.2% 4,482 3.9%

(2) Nuclear 3,453 12.8% 3,550 12.4% 26,812 23.1%

(3) Residual 3,663 13.5% 3,697 12.9% 231 0.2%

(4) Distillate 648 2.4% 710 2.5% 128 0.1%

(5) Natural Gas 16,396 60.6% 17,765 62.1% 79,102 68.2%

(6) Solar (Non-Firm) 35 0.1% 35 0.1% 177 0.2%

(7) FPL Existing Units Total (1) : 25,092 92.8% 26,668 93.2% 110,933 95.7%

(8) Renewables (Purchases)- Firm 55.0 0.2% 55.0 0.2% 473 0.4%

(9) Renewables (Purchases)- Non-Firm Not Applicable --- Not Applicable --- 445 0.4%

(10) Renewable Total: 55.0 0.2% 55.0 0.2% 918 0.79%

(11) Purchases Other : 1,890.0 7.0% 1,890.0 6.6% 4,117 3.6%

(12) Total: 27,037.0 100.0% 28,613.0 100.0% 115,968 100.0%

Note:

(1) FPL Existing Units Total values on row (7), columns (2) and (4), match the System Firm Generating Capacity values found on 

Schedule 1 for Summer and Winter.

(2) Net Energy for Load GWh values on row (12), column (6), matches Schedule 6.1 value for 2014.

Schedule 11.1

Actuals for the Year 2014

Existing FIRM and NON-FIRM Capacity and Energy by Primary Fuel Type

Net (MW) Capability

Existing NON-FIRM Self-Service Renewable Generation Facilities

Actuals for the Year 2014

(1) (2) (3) (4) (5) (6) = (3)+(4)-(5)

Type of Facility Installed Capacity DC 

(MW)

Renewable Projected 

Annual Output (MWh)

Annual Energy 

Purchased from FPL 

(MWh)

Annual Energy Sold 

to FPL (MWh)

Projected Annual 

Energy Used by 

Customers

Customer-Owned 

Renewable Generation 

(0 kW to 10 kW)

17.25 21,548 191,676 634 212,590

Customer-Owned 

Renewable Generation 

(> 10 kW to 100 kW)

8.77 11,087 217,985 661 228,411

Customer-Owned 

Renewable Generation 

(> 100 kW - 2 MW)

12.76 36,645 91,007 210 127,442

Totals 39 69,279 500,668 1,505 568,443

Notes:

(1) There were 3241 customers with renewable generation facilities interconnected with FPL on December 31, 2014.

(2) The Installed Capacity value is the sum of the nameplate ratings (DC MW) for all of the customer-owned renewable generation facilities 

 connected as of December 31, 2014. Three systems do not have a DC rating. These are 3 non-solar facilities:

 Tropicana - Landfill gas reciprocating generator: 1600 kW AC

 Manatee Landfill gas: 1600 kW AC 

 Bio Mass - Palm Beach County: 750 kW AC

 These AC values are included in the (> 100 kW < 2 MW) row.

(3) The Projected Annual Output value is based on NREL's PV Watts 1 program and the Installed Capacity 

 value in column (2), adjusted for the date when each facility was installed and assuming each facility

 operated as planned.

(4) The Annual Energy Purchased from FPL is an actual value from FPL's metered data for 2014.

(5) The Annual Energy Sold to FPL is an actual value from FPL's metered data for 2014.

(6) The Projected Annual Energy Used by Customers is a projected value that equals:

 (Renewable Projected Annual output + Annual Energy Purchased ) minus the Annual Energy Sold to FPL.

Schedule 11.2

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CHAPTER IV 

Environmental and Land Use Information

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IV. Environmental and Land Use Information

IV.A Protection of the Environment

Florida’s climate can be described as a combination of humid subtropical and tropical savanna 

supporting an environment which includes a diverse number of distinct ecosystems with many 

endangered or threatened plant and animal species. These distinct ecosystems, the residents, 

and industries of Florida compete for the same resources that are necessary for the generation, 

transmission, and distribution of electricity. FPL is a corporation which practices strong 

environmental stewardship evidenced by the creation and management of the Everglades 

Mitigation Bank and the preservation of the Barley Barber Swamp. FPL desires to meet public 

expectations of such stewardship and conducts their business in a responsible manner by 

minimizing impacts to Florida’s natural environment. 

FPL and its parent company, NextEra Energy, Inc. have continuously been recognized as leaders

among electric utilities for their commitment to the environment. That commitment is ingrained in 

FPL’s corporate culture. FPL has one of the lowest emissions profiles among U.S. utilities and in 

2014 its carbon dioxide (CO2) emission rate was 38% lower (better) than the industry national 

average.

On March 3, 2014 NextEra Energy was named No. 1 in its sector on Fortune Magazine’s “Most 

Admired Companies” list for the eighth year in a row. In determining the industry rankings, 

approximately 15,000 senior executives, outside directors, and industry analysts are surveyed and 

companies are rated on the following nine attributes:

1.) Ability to attract and retain talented people

2.) Quality of management

3.) Social responsibility to the community and the environment

4.) Innovativeness

5.) Quality of products or services 

6.) Wise use of corporate assets 

7.) Financial soundness 

8.) Long-term investment value

9.) Effectiveness in doing business globally

Fortune recognized that “in 2013, the output from NextEra Energy’s power plants resulted in 

emissions rates of sulfur dioxide, nitrogen oxide and carbon dioxide that were 97 percent, 80 

percent and 53 percent lower, respectively, than the U.S. electric industry’s average. In addition, 

the company provides grants to teachers of science, technology, engineering and math (STEM) 

Florida Power & Light Company 117
classes, partners with community colleges on wind technology training, and protects threatened 

and endangered species where it has operations, including the Florida manatee, American 

crocodile, and osprey and desert tortoise.”

In March 2014, FPL received the 2014 Florida House Conservation Award in recognition of its 

extraordinary commitment to the environment. In presenting the award, Bart Hudson, president of 

the Florida House, declared “From preserving wildlife and natural resources to bringing the public 

and private sectors together to support long-term restoration efforts in the Everglades, the 

southeast Florida marshes and Biscayne Bay, conservation is at the core of FPL’s mission”.

Other conservation efforts noted by the Florida House include FPL's focus on reducing 

greenhouse gas emissions while helping to keep customer bills low through the use of fuelefficient power generation and other innovative technologies. Since 2001, FPL has reduced its use 

of foreign oil by 99 percent by modernizing existing power plants into cleaner, more fuel-efficient 

plants. It is the first utility to bring commercial-scale solar power to Florida, including the world's 

first solar-natural gas hybrid.

On April 2, 2014, the Environmental Protection Agency presented Florida Power & Light Company 

with its Clean Air Excellence Award in recognition of the company’s “green” vehicle fleet and 

customer education programs featuring its electric vehicles and their benefits. The awards 

recognize innovative programs that protect Americans' health and the environment, educate the 

public, serve their communities and stimulate the economy.

In 2014, FPL supported a broad base of environmental organizations with donations and 

memberships totaling in excess of $290,000. The organizations included, but were not limited to, 

the Everglades Foundation, the Conservancy of Southwest Florida, the Busch Wildlife Sanctuary, 

Inc., the Arthur R. Marshall Foundation and the Loggerhead Marinelife Center, Inc. In addition, 

part of the charitable giving was the result of an FPL employee 2014 Power to Care Event that 

raised funds dedicated to the Friends of MacArthur Beach State Park.

FPL employees serve as board members for many organizations that focus on environmental 

restoration, preservation, and stewardship. A partial list of these organizations includes: 

Loggerhead Marinelife Center, Inc., the Everglades Foundation, the Arthur R. Marshall 

Foundation, The Nature Conservancy, Grassy Waters Preserve, and the Palm Beach Zoo.

IV.B FPL’s Environmental Policy

At FPL and its parent company, NextEra Energy, Inc., we are committed to being an industry 

leader in environmental protection and stewardship, not only because it makes business sense, 

Florida Power & Light Company 118
but because it is the right thing to do. Our commitment to compliance, conservation, 

communication, and continuous improvement fosters a culture of environmental excellence and 

drives the sustainable management of our business planning, operations, and daily work.

 

In accordance with our commitments to environmental protection and stewardship, FPL and 

NextEra Energy, Inc. endeavor to:

Comply

• Comply with all applicable environmental laws, regulations, and permits 

• Proactively identify environmental risks and take action to mitigate those risks 

• Pursue opportunities to exceed environmental standards 

• Participate in the legislative and regulatory process to develop environmental laws, 

regulations, and policies that are technically sound and economically feasible 

• Design, construct, operate, and maintain our facilities in an environmentally sound and 

responsible manner

Conserve

• Prevent pollution, minimize waste, and conserve natural resources 

• Avoid, minimize, and/or mitigate impacts to habitat and wildlife 

• Promote the efficient use of energy, both within our company and in our communities

Communicate

• Communicate this policy to all employees and publish it on the corporate website 

• Invest in environmental training and awareness to achieve a corporate culture of 

environmental excellence 

• Maintain an open dialogue with stakeholders on environmental matters and performance

Continuously Improve

• Establish, monitor, and report progress toward environmental targets 

• Review and update this policy on a regular basis 

• Drive continuous improvement through ongoing evaluations of our environmental 

management system to incorporate lessons learned and best practices.

FPL’s parent company, NextEra Energy, Inc. updated this policy in 2013 to reflect changing 

expectations and ensure that employees are doing the utmost to protect the environment. FPL 

complies with all environmental laws, regulations, and permit requirements. FPL designs, 

constructs, and operates its facilities in an environmentally sound and responsible manner. It also 

Florida Power & Light Company 119
responds immediately and effectively to any known environmental hazards or non-compliance 

situations. FPL’s commitment to the environment does not end there. FPL proactively pursues

opportunities to exceed current environmental standards, including reducing waste and emission 

of pollutants, recycling materials, and conserving natural resources throughout its operations and 

day-to-day work activities. FPL also encourages the efficient use of energy, both within the 

Company and in communities served by FPL. These actions are just a few examples of how FPL 

is committed to the environment.

To ensure that FPL is adhering to its environmental commitment, it has developed rigorous 

environmental governance procedures and programs. These include its Environmental Assurance 

Program and Corporate Environmental Governance Council. Through these programs, FPL

conducts periodic environmental self-evaluations to verify that its operations are in compliance 

with environmental laws, regulations, and permit requirements. Regular evaluations also help 

identify best practices and opportunities for improvement.

IV.C Environmental Management

In order to successfully implement the Environmental Policy, FPL has developed a robust 

Environmental Management System program to direct and control the fulfillment of the 

organization’s environmental responsibilities. A key component of the system is an Environmental 

Assurance Program, which is described in section IV.D below. Other components of the system 

include: executive management support and commitment, a dedicated environmental corporate 

governance program, written environmental policies and procedures, delineation of organizational 

responsibilities and individual accountabilities, allocation of appropriate resources for 

environmental compliance management (which includes reporting and corrective action when noncompliance occurs), environmental incident and/or emergency response, environmental risk 

assessment/management, environmental regulatory development and tracking, and environmental 

management information systems.

As part of its commitment to excellence and continuous improvement, FPL created an enhanced 

environmental data management information system (EDMIS) which was fully implemented by the 

end of 2014. Environmental data management software systems are increasingly viewed as an 

industry best-management practice to ensure environmental compliance. FPL’s top goals for this 

project are to: 1) improve the flow of environmental data between site operations and corporate 

services to ensure compliance, and 2) improve operating efficiencies. In addition, the EDMIS will 

help standardize environmental data collection, thus improving external reporting to the public.

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IV.D Environmental Assurance Program

FPL’s Environmental Assurance Program consists of activities that are designed to evaluate 

environmental performance, verify compliance with corporate policy as well as legal and 

regulatory requirements, and communicate results to corporate management. The principal 

mechanism for pursuing environmental assurance is an environmental audit. An environmental 

audit may be defined as a management tool comprising a systematic, documented, periodic, and 

objective evaluation of the performance of the organization and of the specific management 

systems and equipment designed to protect the environment. The primary objective of performing 

an environmental audit is to facilitate management control of environmental practices and assess 

compliance with existing environmental regulatory requirements and FPL policies. In addition to 

FPL facility audits, through the Environmental Assurance Program, FPL performs audits of thirdparty vendors used for recycling and/or disposal of waste generated by FPL operations. Vendor

audits provide information used for selecting candidates or incumbent vendors for disposal and 

recycling needs. 

FPL has also implemented a Corporate Environmental Governance System, in which quarterly 

reviews are performed by each business unit deemed to have potential for significant 

environmental exposures. Quarterly reviews evaluate operations for potential environmental risks 

and consistency with the company’s Environmental Policy. Items tracked during the quarterly 

reviews include processes for the identification and management of environmental risks, metrics,

and indicators and progress / changes since the most recent review.

IV.E Environmental Communication and Facilitation

FPL is involved in many efforts to enhance environmental protection through the facilitation of 

environmental awareness and in public education. Some of FPL’s 2014 environmental outreach 

activities are summarized in Table IV.E.1. 

 

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Table IV.E.1: 2014 FPL Environmental Outreach 

Activities

Activity Count (#)

Visitors to FPL’s Energy Encounter at St. Lucie 2,669

Visitors to Manatee Park, Ft. Myers 216,401

Number of website visits to FPL’s Environmental & 

Corporate Responsibility Websites 580,000

Visitors to Barley Barber Swamp

(Treasured Lands Partnership) 8,517

Martin Energy Center Solar Tours 600

Solar Schools Program 

• 92 schools and 10 demo sites completed 

as of 12/31/14

• Installed capacity for the 102 sites is 921 

kW and can produce more than one 

million kWh annually

• An additional 24-28 school/demo sites 

will come online by the end of 2015

IV.F Preferred and Potential Sites

Based upon its projection of future resource needs, FPL has identified eight (8) Preferred Sites 

and three (3) Potential Sites for future generation additions. Preferred Sites are those locations 

where FPL has conducted significant reviews, and has either taken action, is currently committed 

to take action, or is likely to take action, to site new generating capacity. Potential Sites are those 

sites that have attributes that support the siting of generation and are under consideration as a 

location for future generation. Some of these sites are currently in use as existing generation sites 

and some are not. The identification of a Potential Site does not indicate that FPL has made a 

definitive decision to pursue generation (or generation expansion or modernization in the case of 

an existing generation site) at that location, nor does this designation indicate that the size or 

technology of a generator has been determined. Analyses of any modernization candidates would 

include evaluation of numerous factors including: fuel delivery, transmission, permitting, etc. The 

Preferred Sites and Potential Sites are discussed in separate sections below.

IV.F.1 Preferred Sites

For the 2015 Ten Year Site Plan, FPL has identified eight (8) Preferred Sites. These include a 

combination of existing and new sites for the development of natural gas combined cycle, 

combustion turbines, and/or solar generation facilities.

The Port Everglades site is a location where a modernization project is in progress. This work

consists of replacing the former steam generating units and replacing them with new combined 

cycle (CC) technology. The modernization work is scheduled to be completed in mid-2016. In 

addition, all of the existing gas turbines (GTs) at the Port Everglades site, and all but two of the 

existing GTs at the nearby Lauderdale site, are projected to be retired by the end of 2016. The two 

GTs that will remain will serve to provide black start capability. Five new combustion turbines 

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(CTs) are projected to be added at the Lauderdale site by the end of 2016 to partially replace the 

retired peaking capacity at these sites. These actions, taken to lower FPL’s long-term costs, will 

also aid in addressing compliance with new air emissions standards.

Similarly, and as part of this GT replacement effort, all but two of the existing GTs at the Ft. Myers 

site will be retired and two new CTs will be added. In addition, the two existing CTs at the Ft. 

Myers site will be upgraded to increase their capacity. All of the Ft. Myers work is scheduled to be 

completed by the end of 2016.

The Okeechobee County site has been identified as a Preferred Site for new natural gas CC 

technology. As discussed in the Executive Summary, the new natural gas CC at this site 

represents FPL’s best self-build generation option in 2019, and it will compete with proposals 

received in response to a capacity request for proposals (RFP) that was issued in March 2015.

The Okeechobee County site is also under consideration for future new photovoltaic (PV) facilities. 

In regard to PV, Charlotte, DeSoto, and Manatee Counties have been identified as the locations

for new PV facilities that are expected to go in-service by the end of 2016.

Finally, the Turkey Point site is the location at which FPL plans to construct two new nuclear units, 

Turkey Point Units 6 & 7. The Nuclear Regulatory Commission recently announced a several year 

delay in their schedule to make a decision on FPL’s pending Turkey Point Units 6 & 7 Combined 

Operating License Application (COLA). Due to this delay in the COLA schedule, and to changes in 

Florida’s nuclear cost recovery rule, the earliest practical date for bringing the Turkey Point 6 & 7 

units in-service is now beyond the 2015 through 2024 time period addressed in this Site Plan. 

Despite this change in timing of the two new nuclear units, this Site Plan continues to present the 

Turkey Point site as a Preferred Site for the new units. 

Preferred Site # 1: Port Everglades Plant, Broward County

FPL is in the process of modernizing the Port Everglades Plant located within the City of 

Hollywood in Broward County with construction anticipated to be completed in 2016. Previously 

the site consisted of two 200 MW (approximate) and two 400 MW (approximate) steam generating 

units. The four units were taken out of service, dismantled, and removed from the site as part of 

the modernization project. The modernized site, named the Port Everglades Next Generation 

Clean Energy Center (PEEC), will consist of a single new Combined Cycle unit that replaces the 

original four steam units. The modernized unit will be highly efficient and have a lower-emission 

rate and will use less water than the original units at the site. 

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a. U.S. Geological Survey (USGS) Map 

A USGS map of the PEEC site is found at the end of this chapter. 

b. Proposed Facilities Layout

A general layout of the PEEC generating facilities is found at the end of this chapter. 

c. Map of Site and Adjacent Areas

An overview map of the site and adjacent areas is also found at the end of this chapter.

d. Existing Land Uses of Site and Adjacent Areas

The Port Everglades Plant formerly consisted of two 200 MW (approximate) and two 400 MW 

(approximate) generating units with conventional dual-fuel fired steam boilers and steam 

turbines which were demolished in the Summer of 2013 to make way for the new Port 

Everglades Next Generation Clean Energy Center. The plant site includes minimal vegetation. 

Adjacent land uses include port facilities, barge access via port infrastructure, a rail line and 

associated industrial activities, as well as light commercial and residential development.

e. General Environment Features On and In the Site Vicinity

There are environmental benefits of replacing the former steam units at the Port Everglades 

Site with a new CC unit including a significant reduction in system air emissions and improved 

aesthetics at the site such as lower stack heights.

1. Natural Environment

The site is located adjacent to the Intracoastal Waterway (ICW) and is comprised of 

facilities related to electric power generation. It is located within a highly industrialized port 

that has active material and fuel handling facilities. 

2. Listed Species

No adverse impacts to federal- or state-listed terrestrial plants and animals are expected 

in association with construction at the site, due to the existing developed nature of the site 

and lack of suitable onsite habitat for listed species. The plant provides warm water to the 

ICW pursuant to the facility’s Manatee Protection Plan, which is a benefit to the area’s 

manatees. 

3. Natural Resources of Regional Significance Status

The Port Everglades Next Generation Clean Energy Center is located adjacent to the 

ICW. The construction and operation of a natural gas-fired CC generating facility at this 

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location is consistent with the existing use at the site and is not expected to have any 

adverse impacts on the ICW, parks, recreation areas, or environmentally sensitive lands.

4. Other Significant Features

FPL is not aware of any other significant features of the site.

f. Design Features and Mitigation Options

The design is to replace the four former units, with one new unit of approximately 1,200 MW

Summer capacity. The new unit will be a single CC unit that consists of three new CTs, three 

new heat recovery steam generators (HRSG), and a new steam turbine. 

In addition, all of the existing GTs at the Port Everglades site are projected to be removed by 

the end of 2016 as part of the gas turbine replacement project discussed in the Lauderdale 

and Fort Myers Preferred Site discussions.

g. Local Government Future Land Use Designations

Local government future land use designation for the site is a combination of “Electrical 

Generating Facility” and “Utilities Use”. A land use map of the site and adjacent areas is also 

found at the end of this chapter.

h. Site Selection Criteria Process

The Port Everglades site has been selected due to consideration of multiple factors including 

system load, ability to provide generation in the Miami-Dade/Broward region to help balance 

load and generation in that region, and economics. Environmental issues were considered,

but because the site has been previously utilized for power generation facilities, no

environmental impacts will result from this modernization.

i. Water Resources

Water from the Intracoastal Waterway via Port Everglades Slip No. 3 is currently used for 

once-through cooling water supply. The new plant will only utilize portions of the existing oncethrough cooling water intake and discharge structures due to reduced water demand. Process 

and potable water for the modernized plant will come from the existing City of Ft. Lauderdale

potable water supply. 

j. Geological Features of Site and Adjacent Areas

FPL’s Port Everglades Next Generation Clean Energy Center site is underlain by the Surficial 

Aquifer System (SAS). The SAS in eastern Broward County is primarily composed of sand, 

sandstone, shell, silt, calcareous clay (marl), and limestone deposited during the Pleistocene 

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and Pliocene ages. The sediments forming the aquifer system are the Pamlico Sand, Miami 

Oolite, Anastasia Formation, Key Largo Formation, and Fort Thompson Formation 

(Pleistocene) and the Tamiami Formation (Pliocene). The sediments in the eastern portion of 

Broward County where the plant is located are appreciably more permeable than in the west. 

The SAS is underlain by at least 600 feet of the Hawthorn formation (a confining unit). The 

Floridan Aquifer System (FAS) underlies the Hawthorn formation.

k. Projected Water Quantities for Various Uses

Approximately 600 million gallons per day (mgd) of cooling water will be cycled through the 

once-through cooling water system which is a reduction of more than 51% in cooling water 

when compared to that of the previous steam units. The estimated quantity of process water 

required is approximately 0.24 mgd for uses such as process water and service water. Potable 

water demand is expected to average 0.001 mgd.

l. Water Supply Sources by Type

The modernized plant will continue to use the Intracoastal Waterway as the source of oncethrough cooling water. Process and potable water for the new plant will come from the existing 

City of Ft. Lauderdale potable water supply. 

m. Water Conservation Strategies Under Consideration

No additional water resources will be required as a result of the modernization project. The 

combined cycle technology will result in 51% less water used compared to the traditional 

steam generation units. Recovery and reuse of steam generator blowdown by mixing with 

cooling water flow also recycles water reducing need for fresh water. Therefore, no additional 

water resources will be required as a result of the modernization project.

n. Water Discharges and Pollution Control

The modernized plant will utilize portions of the existing once-through cooling water system for 

heat dissipation prior to discharge to the Intracoastal Waterway. The heat recovery steam 

generator blowdown will be reused to the maximum extent practicable or mixed with the 

cooling water flow before discharge. Reverse osmosis (R/O) reject will be mixed with the 

plant’s once-through cooling water system prior to discharge. Stormwater runoff will be 

collected and routed to stormwater ponds. The facility will employ a Best Management 

Practices (BMP) plan and Spill Prevention, Control, and Countermeasure (SPCC) plan to 

prevent and control the inadvertent release of pollutants. 

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o. Fuel Delivery, Storage, Waste Disposal, and Pollution Control

Natural gas for the new unit would be transported to the site via an existing natural gas 

pipeline to the site. New gas compressors to raise the gas pressure of the pipeline to the 

appropriate level for the new unit will be installed either at the existing site or off-site. Ultra-low 

sulfur light fuel oil, which is used as a backup fuel, would be received by truck, pipeline, or 

barge and stored in a new above-ground storage tank.

p. Air Emissions and Control Systems

The regulated air emission rates at the new plant would be approximately 90 % lower than the 

previous Port Everglades Plant’s emission rates, resulting in significant annual emissions 

reductions and air quality benefits per unit of energy produced. The use of natural gas, ultralow sulfur light fuel oil, and combustion controls would minimize air emissions of sulfur dioxide 

(SO2), particulate matter, and other fuel-bound contaminates from the unit and ensure 

compliance with applicable emission standards. Combustion controls similarly minimize the 

formation of nitrogen oxides (NOx), and the combustor design will limit the formation of carbon 

monoxide and volatile organic compounds. When firing natural gas, NOx emissions will be 

controlled using dry-low NOx combustion technology and selective catalytic reduction (SCR). 

Water injection and SCR will be used to reduce NOx emissions during operations when using 

ultra-low sulfur light fuel oil as backup fuel. Greenhouse gas emissions (GHGs) from 

combustion of natural gas at PEEC will achieve an emission rate substantially lower than the 

EPA proposed new source performance standard for GHGs. The CC design is equivalent to 

the Best Available Control Technology for air emissions, and minimizes such emissions while 

balancing economic, environmental, and energy impacts. Taken together, the design of PEEC 

will incorporate features that will make it among the most efficient and cleanest power plants 

in the State of Florida. 

q. Noise Emissions and Control Systems

Noise from unit construction and operation at the site is expected to be below existing noise 

levels for residents near the site. 

r. Status of Applications

FPL filed a need determination with the FPSC on November 21, 2011. The FPSC’s final need 

order was issued on April 9, 2012. The project’s Site Certification Application (SCA) was 

submitted January 24, 2012 resulting in the issuance, by the Siting Board of the State of 

Florida, of the Final Order PA 12-57 on October 9, 2012. FPL received a Prevention of 

Significant Deterioration (PSD) permit on May 1, 2012 and an Industrial Wastewater Facility 

permit on December 16, 2012. No other permits are required.

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Preferred Site #2: Babcock Ranch Solar Energy Center, Charlotte County

The Babcock Ranch Solar Energy Center facility will be sited on approximately 443 acres in 

Charlotte County. The solar facility will be located approximately 10.5 miles north of the 

intersection of SR-80 and SR-31 and 0.7 miles east of State Road 31 and north of Tucker’s Grade

road. The Babcock Ranch Preserve, owned by the State of Florida, borders the facility directly to 

the north and northwest. The Babcock Ranch Community is located east and south of the facility. 

The facility is an approximately 74.5 MW (nameplate, AC) photovoltaic (PV) facility.

a. U.S. Geological Survey (USGS) Map

A USGS map of the Charlotte Solar site is found at the end of this chapter.

b. Proposed Facilities Layout

The proposed facilities layout is currently in development and not available at this time.

c. Map of Site and Adjacent Areas

An overview map of the site and adjacent areas is found at the end of this chapter.

d. Existing Land Uses of Site and Adjacent Areas

The Charlotte Solar site and adjacent lands are predominantly used for agricultural production. 

Currently, the site includes fallow sod fields, improved and unimproved pasture with a portion 

in a combination of pine flatwoods and freshwater marsh. The existing land use and zoning 

designations are Babcock Ranch Overlay and Overlay Zoning District. This land use and 

zoning allows for solar facilities. 

e. General Environmental Features On and In the Site Vicinity

1. Natural Environment

The majority of the site is comprised of lands dedicated to agricultural production. FPL will 

mitigate for unavoidable wildlife and/or wetland impacts that occur from facility 

construction as required. 

2. Listed Species

Although the site is predominately in agricultural production, results of protected species 

surveys performed in 2006, 2007 and 2009 reveal the project limits and surrounding 

landscape are utilized and/or have the potential to be utilized by a number of listed 

species. The project is located within the US Fish and Wildlife Service (USFWS) Panther 

Focus Area and is also located within the Core Foraging Area of known wood stork 

colonies. 

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Any impacts to the habitat of protected species associated with the PV facility are included 

within the mitigation plan for the Babcock Ranch Community. To compensate for the loss 

of habitat, mitigation activities will be performed in an area known as the “Curry Preserve” 

which is located on a portion of the Babcock Ranch Preserve owned by the State of 

Florida.

3. Natural Resources of Regional Significance Status

The Charlotte Solar site is in the area of the Babcock Preserve and east of the Cecil 

Webb Wildlife Management Area. Both of these natural areas are managed by the Florida 

Fish and Wildlife Conservation Commission. However, the construction and operation of a

PV facility at this location is not expected to have any adverse impacts on parks, 

recreation areas, or environmentally sensitive lands.

4. Other Significant Features

FPL is not aware of any other significant features on the site.

f. Design Features and Mitigation Options

The design includes construction of a PV facility, onsite transmission substation, and site 

stormwater system to accommodate approximately 74.5 MW (nameplate AC) of power 

generation. 

g. Local Government Future Land Use Designations

The existing and future land use on this site consists of agriculture and barren land. A land 

use map of the site and adjacent areas is also found at the end of this chapter.

h. Site Selection Criteria Process

The Charlotte site has been selected as the location of the PV facility based on various factors 

including system load, transmission interconnection, and economics.

i. Water Resources

Minimal amounts of water, if any, would be required for cleaning the PV panels. This water 

would be trucked to the site or obtained from existing onsite permitted water resources.

j. Geological Features of Site and Adjacent Areas

In general, the soil profile of the Surficial Aquifer System (SAS) consists of loose to medium 

dense fine sands with occasional thin stratum of slightly clayey fine sand. Groundwater can be 

encounter at the surface to a depth of a few feet below with fluctuations throughout the year 

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due to seasonal variations in rainfall and other factors. As is typical of the rest of south Florida 

this site is underlain by the Intermediate Confining Unit and the Floridan Aquifer System.

k. Projected Water Quantities for Various Uses

Solar requires minimal amounts of water, if any, for cleaning the PV panels and would only be 

required in the absence of sufficient rainfall. 

l. Water Supply Sources by Type

A water source is not required for this site. Any needed water may be brought to the site by 

truck or obtained from permitted water sources.

m. Water Conservation Strategies Under Consideration

The PV site does not require a permanent water source. Water conservation strategies may 

include selection and planting of low-to-no irrigation grass or groundcover.

n. Water Discharges and Pollution Control 

The facility will employ Best Management Practices (BMP) to prevent and control the 

inadvertent release of pollutants.

o. Fuel Delivery, Storage, Waste Disposal, and Pollution Control

Fuel is not required and no waste products will be generated at the site.

p. Air Emissions and Control Systems

This technology does not generate air emissions.

q. Noise Emissions and Control Systems

This technology does not generate noise.

r. Status of Applications

FPL has obtained the required federal USACE 404 permit allowing for impact with mitigation 

to 9.3 acres of onsite wetlands during construction. The state Environmental Resources 

Permit (ERP) for the existing on-site facilities will be modified to incorporate revisions to the 

site layout and stormwater management system. Application will be made to Charlotte County 

for the local development approval.

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Preferred Site #3: Citrus Solar Energy Center, DeSoto County

The Citrus Solar Energy Center site consists of approximately 841 acres and is located at 4051 

Northeast Karson Street, approximately 0.3 miles east of U.S. Highway 17 and immediately north 

of Bobay Road in Arcadia, Florida. The site has been chosen for an approximately 74.5 MW 

(nameplate, AC) PV facility.

a. U.S. Geological Survey (USGS) Map 

A USGS map of the Citrus Solar Energy Center site is found at the end of this chapter. 

b. Proposed Facilities Layout

The proposed facilities layout is currently in development and not available at this time.

c. Map of Site and Adjacent Areas

An overview map of the site and adjacent areas is found at the end of this chapter.

d. Existing Land Uses of Site and Adjacent Areas

Existing land use on the site is agricultural. The adjacent areas include agriculture, forested 

and non-forested uplands.

e. General Environment Features On and In the Site Vicinity

1. Natural Environment

The approximate 841 acre site is comprised of lands dedicated for agricultural production 

with some wetland areas throughout the property.

2. Listed Species

Burrowing owls and gopher tortoises may be present within the proposed project area. If 

so, burrows of these species will be relocated to adjacent portions of the FPL property 

prior to construction under permits from Florida Fish and Wildlife Conservation 

Commission. Previous wildlife surveys have identified Audubon’s Crested caracara 

foraging within the property, but no nests are located within the project area, and caracara 

have been rarely seen since the removal of cattle from the project area. Based on this 

information, no negative impacts to threatened or endangered species are anticipated as 

a result of the PV project.

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3. Natural Resources of Regional Significance Status

There are no natural resources of regional significance at, or adjacent to, the site. The 

construction and operation of a PV generating facility is not expected to have any adverse 

impacts on parks, recreation areas, or environmentally sensitive lands.

4. Other Significant Features

FPL is not aware of any other significant features of the site.

f. Design Features and Mitigation Options

The design includes construction of a PV facility, onsite transmission substation, and site 

stormwater system to accommodate approximately 74.5 MW (nameplate, AC) of PV. 

g. Local Government Future Land Use Designations

In 2009, DeSoto County instituted an Ordinance amending the Land Development 

Regulations by adding Utility Grade Solar Plant as a permitted use within an Agriculture-10 

zoning district and an Ordinance amending the Future Land Use Map to change the FPL land 

from the Rural Agricultural category to the Electrical Generating Facility category. Solar 

facilities are allowed within this category.

A land use map of the site and adjacent areas is also found at the end of this chapter.

h. Site Selection Criteria Process

The site has been selected as the location of a PV facility based on various factors including 

system load, transmission interconnection, and economics.

i. Water Resources

Minimal amounts of water, if any, would be required for cleaning the PV panels and would only 

be required in the absence of sufficient rainfall. This water would be trucked to the site or 

obtained from existing onsite permitted water resources.

i. Geological Features of Site and Adjacent Areas

The Surficial Aquifer System soil types found on the Site include Anclote mucky fine sand 

(depressional), Basinger fine sand, Basinger fine sand (depressional), Eau Gallie fine sand, 

Immokalee fine sand, Myakka fine sand, Smyrna fine sand, and Valkaria fine sand. As is 

typical of the rest of south Florida this site is underlain by the Intermediate Confining Unit and 

the Floridan Aquifer System.

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k. Projected Water Quantities for Various Uses

Solar requires minimal amounts of water, if any, for cleaning the PV panels in the absence of 

sufficient rainfall.

l. Water Supply Sources by Type

A water source is not required for this site. Any needed water may be brought to the site by 

truck or obtained from permitted water sources.

m. Water Conservation Strategies Under Consideration

The PV site does not require a permanent water source. Water conservation strategies will be 

implemented through the selection and planting of low to no irrigation grass or groundcover.

n. Water Discharges and Pollution Control 

The facility will employ Best Management Practices (BMP) to prevent and control the 

inadvertent release of pollutants.

o. Fuel Delivery, Storage, Waste Disposal, and Pollution Control

Fuel is not required and no waste products will be generated at the site.

p. Air Emissions and Control Systems

Solar technology does not generate air emissions.

q. Noise Emissions and Control Systems

Solar technology does not generate noise.

r. Status of Applications

Application will be made to FDEP for state Environmental Resources Permit (ERP), USACE 

for federal wetlands permit, and Desoto County for local development approval.

Preferred Site #4: Manatee Solar Energy Center, Manatee County

The Manatee Solar Energy Center site consists of approximately 762 acres and is located in 

unincorporated north-central Manatee County. The PV site lies approximately 5 miles east of 

Parrish, Florida, approximately 5 miles east of U.S. Highway 301 and 9.5 miles east of Interstate 

Highway 75 (I-75). This site has been chosen for the addition of an approximately 74.5 MW

(nameplate, AC) PV facility.

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a. U.S. Geological Survey (USGS) Map 

A USGS map of the Manatee Solar site is found at the end of this chapter.

b. Proposed Facilities Layout

The proposed facilities layout is currently in development and not available at this time.

c. Map of the Site and Adjacent Areas

A map of the site and adjacent areas is found at the end of this chapter.

d. Existing Land Uses of Site and Adjacent Areas

Existing land use on the site is agricultural. A portion of the site is zoned Planned 

Development / Public Interest (PD-PI), which will allow for electrical generation. The remainder 

of the site will be zoned from agriculture to PD-PI. The adjacent areas include agricultural, 

upland non-forested, forests, transportation, communication, and utilities.

e. Environmental Features

1. Natural Environment

FPL will mitigate for unavoidable wildlife and/or wetland impacts as needed as a result of 

a PV project constructed at this site.

2. Listed Species

The site is predominately agriculture and minimal impacts to federal- or state-listed 

terrestrial plants or animals are expected in association with construction at the site, due 

to the existing disturbed nature of the site and lack of suitable onsite habitat for listed 

species. In accordance with Florida Fish and Wildlife Conservation Commission, the 

project will be designed to maintain an adequate buffer from the active bald eagle nest 

located west of the site.

3. Natural Resources of Regional Significance Status

There are no natural resources of regional significance at, or adjacent to, the site. The 

construction and operation of a PV facility at this location is not expected to have any 

adverse impacts on parks, recreation areas, or environmentally sensitive lands.

4. Other Significant Features

FPL is not aware of any other significant features of the site.

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f. Design Features and Mitigation Options

The design includes construction of a PV facility, onsite transmission substation, and site 

stormwater system to accommodate approximately 74.5 MW (nameplate, AC) of power 

generation.

g. Local Government Future Land Use Designations

Existing land use on the site is agricultural. In 2009, Manatee County instituted an ordinance 

amending the Manatee County Official Zoning Atlas to rezone approximately 620 acres from 

General Agriculture (A) to Planned Development Public Interest (PD-PI), as well as approve a 

General Development Plan to allow solar development. The project area has since been 

expanded north (approx. 383 acres) and new approvals will be sought to change the Official 

Zoning Atlas to allow solar development within the additional area.

A land use map of the site and adjacent areas is also found at the end of this chapter.

h. Site Selection Criteria Process

The site has been selected as the location of the PV facility based on various factors including 

system load, transmission interconnection, and economics.

i. Water Resources

Minimal amounts of water, if any, would be required for cleaning the PV panels. This water 

would be trucked to the site or obtained from existing onsite permitted water resources and 

would only be required in the absence of sufficient rainfall.

j. Geological Features of the Site and Adjacent Areas

The soil types found on the site include Anclote mucky fine sand (depressional), Basinger fine 

sand, Basinger fine sand (depressional), Eau Gallie fine sand, Immokalee fine sand, Myakka 

fine sand, Smyrna fine sand, and Valkaria fine sand.

k. Projected Water Quantities for Various Uses

Solar requires minimal amounts of water, if any, for cleaning the PV panels in the absence of 

sufficient rainfall. 

l. Water Supply Sources by Type

The PV site does not require a permanent water source. Any needed water may be brought to 

the site by truck or obtained from permitted water sources.

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m. Water Conservation Strategies Under Consideration

Water conservation strategies may include the selection and planting of low-to-no irrigation 

grass or groundcover.

n. Water Discharges and Pollution Control

The facility will employ Best Management Practices (BMP) to prevent and control the 

inadvertent release of pollutants.

o. Fuel Delivery, Storage, Waste Disposal, and Pollution Control

Fuel is not required and no waste products will be generated by site.

p. Air Emissions and Control Systems

This technology does not generate air emissions.

.

q. Noise Emissions and Control Systems

This technology does not generate noise.

r. Status of Applications 

Applications will be submitted to rezone the northern extent of the site, to obtain County site 

plan approval, to modify an Environmental Resources Permit (ERP) to include the expanded 

project area, and to modify the USACE 404 permit to include the expanded project area.

Preferred Site # 5: Lauderdale Plant Peaking Facilities, Broward County

This site is located at the existing Lauderdale Plant property and consists of approximately 392 

acres, within the Cities of Dania Beach and Hollywood in Broward County, Florida, east of U.S. 

Highway 441, north of Griffin Road, west of SW 30th Avenue, and south of Interstate 595. 

The Lauderdale Plant currently includes two combined cycle units and two banks of 12 first 

generation simple cycle gas turbines (GTs) that began operation in the early 1970s. These GTs 

are used to serve peak and emergency demands in a quick-start manner. Each bank of GTs has a 

net capacity of 420 megawatts (MWs) and are authorized to operate on natural gas and distillate

oil. FPL plans to retire 22 of the 24 existing GTs and partially replace this peaking capacity with 5 

new combustion turbines (CTs). This GT removal with CT replacement is assumed to occur by the 

end of 2016.

a. U.S. Geological Survey (USGS) Map 

A USGS map of the Lauderdale site and adjacent areas is found at the end of this chapter. 

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b. Proposed Facilities Layout

A facilities plot plan of the Lauderdale generating facilities is found at the end of this chapter. 

c. Map of Site and Adjacent Areas

A USGS map of the Lauderdale site and adjacent areas is found at the end of this chapter.

d. Existing Land Uses of Site and Adjacent Areas

The existing land use at the site is commercial and the adjacent areas are a mixture of low to 

high density urban, transportation, communication, utilities, commercial, water, and some 

open land. The site is zoned general industrial by the City of Dania Beach.

e. General Environment Features On and In the Site Vicinity

1. Natural Environment

The majority of the project site is comprised of facilities related to electric power 

generation. The project site also includes approximately 14 acres of surrounding forested 

wetlands and upland spoil piles.

2. Listed Species

Based upon field assessments conducted in 2013, review of United States Fish and 

Wildlife (USFWS) and Florida Fish and Wildlife Conservation Commission (FWC) 

literature and databases, the Florida Natural Areas Inventory (FNAI) database of 

documented listed species occurrences, the lack of suitable habitat, and the land use of 

the surrounding areas, federally listed species are not anticipated to utilize the CT Project 

area.

3. Natural Resources of Regional Significance Status

There are no natural resources of regional significance adjacent to the site. The 

construction and operation of the CT Project at this location is consistent with the existing 

use at the site and is not expected to have any adverse impacts on parks, recreation 

areas, or environmentally sensitive lands.

4. Other Significant Features

FPL is not aware of any other significant features of the site.

f. Design Features and Mitigation Options

The project is to retire 22 of the 24 gas turbines (GTs) at the existing Lauderdale Plant (plus 

retire an additional 12 simple cycle GTs at the nearby Port Everglades Plant) and partially 

replace this capacity with 5 new highly efficient simple cycle CTs. The CTs operate in simple 

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cycle mode and produce electrical energy by direct connection to an electric generator. The 

CTs will operate using natural gas and ultra-low sulfur distillate (ULSD) oil as fuel.

g. Local Government Future Land Use Designations

The site is zoned General Industrial by the City of Dania Beach, a designation intended to 

provide for light and medium intensity industrial, research, and assembly fabrication uses. 

Electrical power plants are permitted within a General Industrial zoning designation as a 

special exception use only, see Section r.

A land use map of the site and adjacent areas is also found at the end of this chapter.

h. Site Selection Criteria Process

The Lauderdale Plant site has been selected for the location of new CTs based on various 

factors including maximizing opportunities to utilize existing utility infrastructure, system load, 

transmission interconnection, and economics. 

i. Water Resources

The CT Project will require a marginal increase in demineralized water that will be obtained 

from the existing Lauderdale Plant’s water treatment system. 

j. Geological Features of Site and Adjacent Areas

The geological layers beneath the site include the Surficial Aquifer System (SAS), the 

Intermediate Confining Unit (ICU), and the Floridan Aquifer System (FAS). According to the 

Natural Resource Conservation Service (NRCS) Soil Survey of Broward County, the SAS in the 

proposed facilities area is dominated by Okeelanta series muck.

The Okeelanta series consists of very deep, very poorly drained, rapidly permeable soils in 

large fresh water marshes and small depressional areas. In un-drained areas the water table is 

at depths of less than ten inches below the surface or the soil is covered by water 6 to 12 

months during most years.

k. Projected Water Quantities for Various Uses

The CT Project consists of installing new CTs that are operated in simple cycle mode and do 

not require a heat dissipation system. Raw water from the Broward County will continue to be 

used for process water treatment system influent and fire protection. Water used for CT inlet 

air cooling and water injection for NOx control when using ULSD oil will be demineralized 

water from the existing process water treatment system.

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l. Water Supply Sources by Type

The CTs do not require a heat dissipation system, therefore there are no associated cooling 

water uses. The proposed facility would continue to acquire water from existing water 

contracts with Broward County and would continue to use potable water from the City of 

Hollywood to provide drinking water for employees.

m. Water Conservation Strategies Under Consideration

No additional water resources would be required as a result of the CT Project. 

n. Water Discharges and Pollution Control

There would be no surface water discharges required for the operation of the proposed facility. 

The stormwater management system has been designed to prevent direct discharge to 

surface waters. 

The facility will employ a Best Management Practices (BMP) plan and Spill Prevention, 

Control, and Countermeasure (SPCC) plan to prevent and control the inadvertent release of 

pollutants.

o. Fuel Delivery, Storage, Waste Disposal, and Pollution Control

The fuel to be used in the CTs is natural gas and ULSD oil. Natural gas will be transported to 

the facility via existing pipeline. No onsite storage is provided for natural gas. ULSD oil would

be trucked or piped to the facility and stored in double walled ULSD oil tanks. 

p. Air Emissions and Control Systems

Air emission rates for NOx associated with the operation of the new CTs would be 

approximately 90 percent lower than the existing GT emission rates, resulting in significantly 

lower air quality impacts per hour of operation. In addition to lower air emissions, the 

maximum total air quality impacts for the site facility are predicted to be well below and in 

compliance with the National Ambient Air Quality Standards (NAAQS). For pollutants such as 

NO2, the new CTs’ total air quality impacts are predicted to be significantly reduced by 40 

percent or more compared to the existing GTs. 

The use of clean fuels (natural gas and ULSD oil) and combustion controls would minimize air

emissions of SO2, sulfuric acid mist (SAM), particulates (PM/PM10/PM2.5), and other fuelbound contaminants and ensure compliance with applicable emission-limiting standards. 

Combustion controls will minimize the formation of NOx and the formation of CO and VOCs by 

combustor design. Further NOx reduction will be achieved by water injection during oil firing. 

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q. Noise Emissions and Control Systems

The construction and operation of the new CTs will not exceed the maximum permissible 

sound levels in Section 17-86 of the City of Dania Beach.

r. Status of Applications

A 404 dredge and fill permit has been issued by the U. S. Army Corps of Engineers (USACE) 

to allow for wetland impacts with mitigation associated with the project and a Prevention of 

Significant Deterioration (PSD) air permit has been issued by the Florida Department of 

Environmental Protection (FDEP). A modification of the PSD permit to include GHG emissions

has been prepared by FPL for submittal to the FDEP. No other licenses or permits have been 

issued for the CT Project. FPL will submit applications to Broward County for a special 

exception use permitted within a General Industrial zoning designation and to the U.S. 

Environmental Protection Agency (EPA) for the Greenhouse Gas air permit. 

Preferred Site # 6: Ft Myers Plant Peaking Facilities, Lee County

Florida Power & Light Company (FPL) plans to retire, replace, and upgrade components of the 

peaking facilities at the Fort Myers Power Plant. This site consists of approximately 460 acres

located in the City of Tice (Fort Myers) in Lee County, Florida. The Plant property is located north 

of State Road 80 (Palm Beach Boulevard), south of the Caloosahatchee River, east of the 

Caloosahatchee Shores Community, and west of State Road 31. 

The existing Fort Myers Plant consists of one natural gas Combined Cycle (CC) units, two natural 

gas and oil fired Combustion Turbine (CT) units, and one bank of 12 oil fired Gas Turbines (GTs)

(peaking facilities) that have a combined capacity of 2,403 summer megawatts. 

Presently, the bank of 12 first generation GTs (which started operation in the early 1970s) provide 

power during periods of peak demand and black start capability in the event of a power outage. 

FPL plans to add two new CTs and retire ten of the existing GTs by the end of 2016.The two new 

CTs will be more efficient with cleaner air emissions than the existing GTs. In addition, the two 

existing CTs will be upgraded to produce additional generation capacity.

a. U.S. Geological Survey (USGS) Map

A USGS map of the Fort Myers site and adjacent areas is found at the end of this chapter. 

b. Proposed Facilities Layout

A general layout of the Fort Myers generating facilities is found at the end of this chapter. 

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c. Map of Site and Adjacent Areas

A USGS map of the Fort Myers site and adjacent areas is found at the end of this chapter.

d. Existing Land Uses of Site and Adjacent Areas

The existing land-use at the site is transportation, communication, utilities, barren land, and 

agricultural. Adjacent properties include low density urban, commercial, rangeland, open land, 

transportation, communication, and utilities. A Land Use / Land Cover Map is also found at the 

end of this chapter.

e. General Environment Features On and In the Site Vicinity

1. Natural Environment

The majority of the site is comprised of facilities related to electric power generation. 

2. Listed Species

Based on the results of a 2013 biological assessment, which included a field evaluation 

and review of data obtained from the Florida Natural Areas Inventory (FNAI), the U.S. Fish 

and Wildlife Service (USFWS), and the Florida Fish and Wildlife Conservation 

Commission (FWC), no threatened or endangered species are expected to be affected by 

the proposed Project.

3. Natural Resources of Regional Significance Status

The Caloosahatchee and Orange Rivers are adjacent to the site. The construction and 

operation of the CT Project at this location is consistent with the existing use at the site 

and is not expected to have any adverse impacts on the Caloosahatchee River, the 

Orange River, parks, recreation areas, or environmentally sensitive lands.

4. Other Significant Features

FPL is not aware of any other significant features of the site.

f. Design Features and Mitigation Options

FPL will retire 10 of 12 GTs at the existing Fort Myers Plant, and replace them with two new 

highly efficient simple cycle CTs. In addition, the two existing CTs will be upgraded to produce 

additional capacity and enhanced performance. The CTs operate in simple cycle mode with

associated stacks and produce electrical energy by direct connection to an electric generator. 

The CTs will operate using natural gas and ultra-low sulfur distillate (ULSD) oil as fuel. Two 

GTs may be retained for peaking and black start capabilities.

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g. Local Government Future Land Use Designations

The site is zoned Industrial Light (IL) by Lee County, a designation intended to provide for 

areas devoted to various light industrial and quasi-industrial commercial uses. Electrical power 

plants are permitted within an IL designation. A land use map of the site and adjacent areas is 

also found at the end of this chapter.

h. Site Selection Criteria Process

The Fort Myers Plant site has been selected for the location of the new and upgraded peaking 

units based on various factors including maximizing opportunities to utilize existing utility 

infrastructure, system load, transmission interconnection, and economics. 

i. Water Resources

The proposed facility will require a marginal increase in demineralized water that will be 

supplied by treating potable water obtained from Lee County. 

j. Geological Features of Site and Adjacent Areas

According to the Natural Resource Conservation Service Soil (NRCS) Soil Survey of Lee 

County, Florida (1991), two soil types have been mapped within the proposed Project site: 

Caloosa fine sand and Urban Land. Notably, the soils within the Project site have been 

previously excavated to the depth of several meters and refilled, effectively eliminating the 

natural soil profile. 

k. Projected Water Quantities for Various Uses

The project consists of CTs that are operated in simple cycle mode and do not require a heat 

dissipation system. Water used for CT inlet air cooling and water injection for NOx control 

when using ULSD oil will be demineralized water. Demineralized water will be obtained by 

treating potable water provided from Lee County.

l. Water Supply Sources by Type

As stated in the previous section the CTs do not require a heat dissipation system, therefore 

there are no associated cooling water uses. For all other water supply requirements, the 

proposed facility would acquire potable water from Lee County. 

m. Water Conservation Strategies Under Consideration

No additional water resources would be required as a result of the CTs project. 

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n. Water Discharges and Pollution Control

There would be no surface water discharges required for the operation of the proposed facility. 

The stormwater management system has been designed to prevent direct discharge to 

surface waters. 

The facility will employ a Best Management Practices (BMP) plan and Spill Prevention, 

Control, and Countermeasure (SPCC) plan to prevent and control the inadvertent release of 

pollutants.

o. Fuel Delivery, Storage, Waste Disposal, and Pollution Control

The fuel to be used in the CTs is natural gas and ULSD oil. Natural gas will be transported to 

the facility via existing pipeline. No onsite storage is provided for natural gas. ULSD oil would 

be trucked or barged to the facility and stored in existing ULSD oil tanks. 

p. Air Emissions and Control Systems

Air emission rates for NOx with the new and upgraded CTs would be approximately 90 

percent lower than the existing GT emission rates, resulting in significantly lower air quality 

impacts during operating hours. In addition to lower air emissions, the maximum total air 

quality impacts for the CT Project are predicted to be well below and in compliance with the 

National Ambient Air Quality Standards (NAAQS). For pollutants such as NO2, the CT 

Project’s total air quality impacts are predicted to be significantly reduced by 40 percent or 

more compared to the existing GTs. 

The use of clean fuels (natural gas and ULSD oil) and combustion controls would minimize air 

emissions of SO2, sulfuric acid mist (SAM), particulates (PM/PM10/PM2.5), and other fuelbound contaminants and ensure compliance with applicable emission-limiting standards. 

Combustion controls will minimize the formation of NOx and the formation of CO and VOCs by 

combustor design. Further NOx reduction will be achieved by water injection during oil firing. 

q. Noise Emissions and Control Systems

Noise from the new and upgraded CTs will not exceed the maximum permissible sound levels 

in Lee County noise control ordinance No. 93-15. The design of these new and upgraded CTs 

includes components and an enclosure which mitigate the emission of noise to the 

surrounding environment. Noise expected to be caused by unit construction at the site is 

expected to be below current noise levels for the residents nearest the site. 

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r. Status of Applications

FPL will apply for FDEP ERP for stormwater impacts and a PSD permit for air emissions. A 

Development Order Approval will be obtained from Lee County.

Preferred Site # 7: Okeechobee Site, Okeechobee County

FPL owns 2,800 acres of land in Northeast Okeechobee County. FPL plans to use approximately 

200 acres of this land for development of a combined cycle (CC) unit at this site. A CC unit at this 

site has been determined to be FPL’s best self-build generation option for meeting its capacity 

needs beginning in 2019. In March 2015, FPL issued a capacity request for proposals (RFP) to 

solicit proposals from outside parties for meeting this capacity need. FPL’s CC unit at the 

Okeechobee site, and the proposals received in response to the RFP, will be evaluated by FPL 

and an Independent Evaluator to determine which option(s) is the best selection for FPL’s 

customers. 

Natural gas-fired CC generation at the site is possible due to the proximity to existing and planned 

natural gas pipelines. In addition, FPL currently views the Okeechobee site as one of the most 

likely sites to be used for future large-scale solar using photovoltaic (PV) generation facilities.

a. U.S. Geological Survey (USGS) Map 

A USGS map of the Okeechobee site and adjacent areas is found at the end of this chapter. 

b. Proposed Facilities Layout

The proposed facilities layout is currently in development and not available at this time.

c. Map of Site and Adjacent Areas

A USGS map of the Okeechobee site and adjacent areas is found at the end of this chapter.

d. Existing Land Uses of Site and Adjacent Areas

The Okeechobee site is predominantly used for agricultural production (cattle and citrus). 

Adjacent land uses include agriculture and conservation. The site is in an unincorporated, 

rural area of the county. FPL’s Poinsett-Martin transmission line corridor abuts the property 

along the northern boundary.

e. General Environment Features On and In the Site Vicinity

1. Natural Environment

The majority of the 2,800 acre site is comprised of lands dedicated to agricultural 

production (unimproved pasture and fallow citrus). Approximately 400 acres consist of 

pine flatwoods, mixed forested wetlands, saw palmetto prairie, and freshwater marsh. 

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2. Listed Species

Minimal impacts to federal- or state-listed terrestrial plants or animals are expected in 

association with construction at the site, due to the previously disturbed nature of the site 

and lack of suitable onsite habitat for listed species. 

3. Natural Resources of Regional Significance Status

The Okeechobee site abuts the western boundary of the Ft Drum Marsh, a water 

conservation area managed by the Saint Johns River Water Management District. The 

construction and operation of a power generating facility at this location is not expected to 

have any adverse impacts on that area or any other parks, recreation areas, or 

environmentally sensitive lands.

4. Other Significant Features

FPL is not aware of any other significant features of the site.

f. Design Features and Mitigation Options

Options include construction of CC and/or PV technologies. Mitigation for unavoidable 

impacts, if required, could occur through a combination of on- and off-site mitigation.

g. Local Government Future Land Use Designations

Local government future land use designation for the site is predominantly unimproved 

pasture. A land use map of the site and adjacent areas is also found at the end of this chapter.

h. Site Selection Criteria Process

The Okeechobee County site was selected as Preferred based on various factors including 

system load, transmission interconnection, proximity of the proposed Florida Southeast 

Connection and other natural gas pipelines, and economics. Expected environmental issues 

are minimal because the site has been previously disturbed and contains few wetlands that 

will be impacted by the construction and operation of the planned facilities. 

i. Water Resources

Groundwater from the Surficial and Floridan Aquifers is anticipated to supply water to the 

Northeast Okeechobee County site for the combined cycle unit. Minimal amounts of water, if 

any, will be required for cleaning the PV panels. This water will be obtained from onsite water 

resources permitted for the CC unit.

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j. Geological Features of Site and Adjacent Areas

The geological features of the Northeast Okeechobee County site are similar to that of most of 

South Florida. In general, the groundwater system underlying Okeechobee County consists of 

the SAS, the Intermediate Confining Unit (ICU), and the FAS. In this area, the SAS consists of 

approximately 100 to 250 feet of undifferentiated deposits of sand, shell, clay and silt. The ICU 

consists of approximately 200 feet of carbonate rocks interbedded with sandy and silty clay. 

The multiple layers of the FAS extend thousands of feet below the ICU.

k. Projected Water Quantities for Various Uses

Approximately 9 mgd of cooling water will be used in cooling towers, which reduces water use 

by 95 to 98% compared to once through cooling, for a CC unit at the Okeechobee site. The 

estimated quantity of water required for processing at a CC unit is approximately 0.24 million 

gallons per day (mgd) for uses such as process water and service water. Potable water 

demand is expected to average 0.001 mgd. Only minimal amounts of water, if any, would be 

required for cleaning the PV panels, and would only be required in the absence of sufficient 

rainfall. This water would be obtained from onsite water resources permitted for the CC unit.

l. Water Supply Sources by Type

The potential water supply source is groundwater from the SAS and the FAS. Additional 

evaluations are necessary to determine the exact source. Process and potable water for the 

new plant are also not determined and may come from the surficial aquifer.

m. Water Conservation Strategies Under Consideration

Combined cycle technology utilizes less water by design than traditional steam generation 

units. PV facilities are expected to have no water demands. Specific water conservation 

strategies will be evaluated and selected during the detailed design phase of any development 

project.

n. Water Discharges and Pollution Control

The CC plant is anticipated to utilize a closed cycle cooling (towers) system for heat 

dissipation. The heat recovery steam generator blowdown will be reused to the maximum 

extent practicable or mixed with the cooling water flow before discharge. Reverse osmosis 

(R/O) reject will be mixed with the plant’s cooling water flow prior to discharge. A deep 

injection well system known as an Underground Injection Control system (UIC) is proposed for 

disposal of non-hazardous industrial wastewater from the power generation process and nonhazardous construction-related water. Stormwater runoff would be collected and routed to 

stormwater ponds. The facility will employ Best Management Practices (BMP) and Spill 

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Prevention, Control, and Countermeasure (SPCC) plans to prevent and control the inadvertent 

release of pollutants. 

o. Fuel Delivery, Storage, Waste Disposal, and Pollution Control

Natural gas for a new CC unit will be transported to the site via a new natural gas pipeline 

lateral. New gas compressors to raise the gas pressure of the pipeline to the appropriate level 

for the new unit may be necessary. Back-up fuel supplies of ultra-low sulfur light fuel oil will be 

received by truck or pipeline and stored in an above-ground storage tank to ensure reliability 

of operations.

p. Air Emissions and Control Systems

The use of natural gas, ultra-low sulfur light fuel oil, and combustion controls will minimize 

regulated air emissions of sulfur dioxide, particulate matter, and other fuel-bound 

contaminates from a CC unit and ensure compliance with applicable emission standards. 

Combustion controls similarly minimize the formation of NOx, and the combustor design will 

limit the formation of CO and VOCs. When firing natural gas, NOx emissions will be controlled 

using dry-low NOx combustion technology and selective catalytic reduction (SCR). Water 

injection and SCR will be used to reduce NOx emissions during operations when using ultralow sulfur light fuel oil as backup fuel. The CC facility emissions of GHGs from combustion of 

natural gas achieve an emission rate substantially lower than the EPA’s proposed new source 

performance standards for GHGs. These design alternatives are equivalent to the Best 

Available Control Technology for air emissions, and minimize such emissions while balancing 

economic, environmental, and energy impacts. Taken together, the design of a CC unit would 

incorporate features that would make it among the most efficient and cleanest power plants in 

the State of Florida. PV generation does not produce air emissions. 

q. Noise Emissions and Control Systems

Noise from unit construction is expected to be minimal. Noise from unit operation will not 

exceed Okeechobee County maximum permissible sound levels in an agricultural area.

r. Status of Applications

FPL has filed an UIC Exploratory Well and associated Dual Zone Monitoring Well for the 

Northeast Okeechobee County site. The application has been deemed complete and the 

Public Notice for the Draft Permit was published in early February 2015. A permit for the 

construction of the Exploratory Well and Dual Zone Monitoring Well is expected in Summer 

2015. FPL will submit applications to the State of Florida for Site Certification as well as other 

permits needed to support the construction and operation of the project. The applications will 

be prepared as the planning and development of the project proceeds.

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Preferred Site # 8: Turkey Point Plant, Miami-Dade County 

The Turkey Point Plant (Turkey Point) is located on the west side of Biscayne Bay, 25 miles south 

of Miami. Turkey Point is directly on the shoreline of Biscayne Bay and is geographically located 

approximately 9 miles east of Florida City on Palm Drive. The land surrounding Turkey Point is 

owned by FPL and acts as a buffer zone. Turkey Point is comprised of two natural gas/oil 

conventional steam units (Units 1 & 2), two nuclear units (Units 3 & 4), one combined cycle natural 

gas unit (Unit 5), nine small diesel generators, and the cooling canals. A capacity uprate project 

for the two nuclear units was successfully completed in 2013. The Everglades Mitigation Bank 

(EMB), an approximately 13,000 acres, FPL-maintained natural wildlife and wetlands area that 

has been set aside, is located to the south and west of the site.

On May 14, 2014, the Florida Power Plant Siting Board authorized the site certification, with 

conditions, of Turkey Point 6 & 7. Each of these two units would provide 1,100 MW of nuclear 

generating capacity. Due to a delay in the Nuclear Regulatory Commission’s (NRC) schedule to 

reach a decision in the Combined Operating License Application (COLA) submittal by FPL until 

late 2016, and to changes in Florida’s nuclear cost recovery rule, the projected earliest practical 

in-service dates for the two new units are June 2027 (for Turkey Point Unit 6) and June 2028 (for 

Turkey Point Unit 7). These in-service dates are outside of the current ten-year time period (2015 

through 2024) addressed in this Site Plan. However, because these two new nuclear units remain 

in FPL’s resource plans, the Turkey Point site is again presented as a Preferred Site in this year’s 

Site Plan.

In addition to the two new generating units, supporting buildings, facilities, and equipment will be 

located on the Turkey Point Units 6 & 7 site, along with a construction laydown area. Proposed 

associated facilities include: a nuclear administration building, a training building, a parking area,

an FPL reclaimed water treatment facility and reclaimed water pipelines, radial collector wells and 

delivery pipelines, an equipment barge unloading area, transmission lines (and transmission 

system improvements elsewhere within Miami-Dade County), access roads and bridges, and 

potable water pipelines.

a. U.S. Geological Survey (USGS) Map

USGS maps of the Turkey Point area, with the proposed location of Turkey Point Units 6 & 7 

identified, are found at the end of this chapter.

b. Proposed Facilities Layout

Maps of the general layout of Turkey Point Units 6 &7 are found at the end of this chapter. 

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c. Map of Site and Adjacent Areas

Land Use / Land Cover overview maps of the Turkey Point Units 6 & 7 site and adjacent areas 

are also found at the end of this chapter.

d. Existing Land Uses of Site and Adjacent Areas 

Turkey Point Plant is currently home to five generating units and support facilities that occupy 

approximately 150 acres of the approximately 9,400-acre Turkey Point property. Prominent 

features beyond the power block area include the intake system, cooling canal system, 

switchyard, spent fuel storage facilities, and technical and administrative support facilities The 

cooling canal system occupies approximately 5,900 acres.

Two 400-megawatt (MW) (nominal) fossil fuel-fired steam electric generation units at Turkey 

Point have been in service since 1967 (Unit 1) and 1968 (Unit 2). These units have historically 

burned residual fuel oil and/or natural gas with a maximum equivalent sulfur content of one

percent. Unit 2 is currently serving, not as a power generating unit, but as a synchronous 

condenser to provide voltage support to the southeastern end of FPL’s transmission system.

The two original 700-MW (nominal) nuclear units have been in service since 1972 (Unit 3) and 

1973 (Unit 4) and were uprated to a combined total of approximately 1,632 (Summer) MW in 

2013. Turkey Point Units 3 and 4 are pressurized water reactor (PWR) units. Turkey Point Unit 

5 is a net 1,148 (Summer) MW natural gas-fired combined cycle unit that began operation in 

2007. The site for the new Units 6 & 7 is south of existing Units 3 and 4 and occupies 

approximately 300 acres within the existing cooling canal system. 

Properties adjacent to Turkey Point property are almost exclusively undeveloped land. The 

FPL-owned EMB is adjacent to most of the western and southern boundaries of Turkey Point 

property. The South Florida Water Management District (SFWMD) Canal L-31E is also 

situated to the west of Turkey Point property. The eastern portions of Turkey Point property 

are adjacent to Biscayne Bay, the Biscayne National Park (BNP), and Biscayne Bay Aquatic

Preserve. The southeastern portion of Turkey Point property is bounded by state-owned land 

located on Card Sound. The Homestead Bayfront Park, owned and operated by Miami-Dade 

County, is situated to the north of the Turkey Point property.

e. General Environment Features On and In the Site Vicinity

1. Natural Environment

Turkey Point is located directly on the northwest, west, and southwest shoreline of 

Biscayne Bay and the Biscayne National Park, 25 miles south of Miami. Biscayne National 

Park was first established in 1968 as a National Monument and was expanded in 1980 to 

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approximately 173,000 acres of water, coastal lands, and 42 keys. A portion of Biscayne 

Bay Aquatic Preserve, a state-owned preserve, is adjacent to the eastern boundary of the 

Turkey Point plant property. The Biscayne Bay Aquatic Preserve is a shallow, subtropical 

lagoon consisting of approximately 69,000 acres of submerged State land that has been 

designated as an Outstanding Florida Water. 

The approximately 300-acre Turkey Point Units 6 & 7 site consists of the plant area and 

adjacent areas designated for laydown and ancillary facilities. The site includes 

hypersaline mud flats, man-made active cooling canals, man-made remnant canals, 

previously filled areas/roadways, mangrove heads associated with historical tidal 

channels, dwarf mangroves, open water /discharge canal associated with the cooling 

canals on the western portion of the site, wet spoil berms associated with remnant canals, 

and upland spoil areas.

2. Listed Species

Threatened, endangered, and/or animal species of special concern known to occur at the 

site, transmission line corridors, or in the nearby Biscayne National Park, include the 

peregrine falcon (Falco peregrinus), wood stork (Mycteria americana), American crocodile 

(Crocodylus acutus), roseate spoonbill (Ajaja ajaja), little blue heron (Egretta caerulea), 

snowy egret (Egretta thula), American oystercatcher (Haematopus palliates), least tern 

(Sterna antillarum), the white ibis (Eudocimus albus), Florida manatee (Trichechus 

manatus latirostris), eastern indigo snake (Drymarchon couperi), snail kite (Rostrhamus 

sociabilis plumbeus), white-crowned pigeon (Patagioenas leucocephala), and bald eagle

(Haliaeetus leucocephalus). No bald eagle nests are known to exist in the vicinity of the 

site. The federally listed, threatened American crocodile thrives at Turkey Point, primarily 

in and around the southern end of the cooling canals which lie south of the Turkey Point 

Unit 6 & 7 area. The majority of Turkey Point is considered American crocodile habitat due 

to the mobility of the species and use of the site for foraging, traversing, and basking. FPL 

manages a program for the conservation and enhancement of the American Crocodile 

and the program is credited with survival improvement and contributing to the downlisting 

of the American Crocodile from endangered to threatened.

Some listed flora species likely to occur at the site or vicinity include pinepink (Bletia 

purpurea), Florida brickell-bush (Brickellia mosieri), Florida lantana (Lantana depressa 

var. depressa), mullien nightshade (Solanum donianum), and lamarck's trema (Trema 

lamarckianum).

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The construction and operation after construction, of Turkey Point Unit 6 & 7 project is not

expected to adversely affect any rare, endangered, or threatened species.

3. Natural Resources of Regional Significance Status

Significant features within the vicinity of the site include Biscayne National Park, the 

Biscayne Bay Aquatic Preserve, Miami-Dade County Homestead Bayfront Park, and 

Everglades National Park. The portion of Biscayne Bay adjacent to the site is included 

within the Biscayne National Park. Biscayne National Park contains 180,000 acres, 

approximately 95 percent of which is open water interspersed with more than 40 keys. 

The Biscayne National Park headquarters is located approximately two miles north of 

Turkey Point and is adjacent to the Miami-Dade County Homestead Bayfront Park, which 

contains a marina and day-use recreational facilities.

4. Other Significant Features

FPL is not aware of any other significant features of the site.

f. Design Features and Mitigation Options

For Turkey Point Units 6 & 7, the technology proposed is the Westinghouse AP1000 

pressurized water reactor (PWR). This design is certified by the Nuclear Regulatory 

Commission (NRC) under 10 CFR 52 and incorporates the latest technology and more 

advanced safety features than today’s nuclear plants that have already achieved record safety 

levels. The Westinghouse AP1000 unit consists of the reactor, steam generators, pressurizer, 

and steam turbine/electric generator. Condenser cooling for the Units 6 & 7 steam turbines will 

be accomplished using six circulating water cooling towers. The makeup water reservoir is the 

reinforced concrete structure beneath the circulating water system cooling towers that will 

contain reserve reclaimed water capacity to be used for the circulating water system. The 

structures for the Westinghouse AP1000 are the nuclear island (containment building, shield 

building, and auxiliary building), turbine building, annex building, diesel generator building, and 

radwaste building. The plant area will also contain the Clear Sky substation (switchyard) that 

will connect Units 6 & 7 to FPL’s transmission system. Mitigation plans for Turkey Point Units 

6 & 7 include restoration areas as well as credits purchased from the Everglades Mitigation 

Bank. 

g. Local Government future Land Use Designations 

The Turkey Point Plant site is designated by the Miami-Dade County Comprehensive 

Development Management Plan as an IU-3 (Industrial, Utilities, and Communications) 

Unlimited Manufacturing District that carries a dual designation of MPA (Mangrove Protection 

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Area) in portions of the property. There are also areas designated GU – “Interim District.” 

Designations for the surrounding area are primarily GU – “Interim District.”

h. Site Selection Criteria Process

For Turkey Point Units 6 & 7, FPL conducted an extensive site selection analysis leading to 

the selection of the Turkey Point site as the site that, on balance, provided the most favorable 

location for developing new nuclear generation to serve FPL’s customers. The Site Selection 

Study employed the principles of the Electric Power Research Institute (EPRI) siting 

guidelines and is modeled upon applicable NRC site suitability and National Environmental 

Policy Act (NEPA) criteria regarding the consideration of alternative sites. The study convened 

a group of industry and FPL subject matter experts to develop and assign weighting factors to 

a broad range of site selection criteria. Twenty-three candidate sites were then ranked using 

the siting criteria. This review allowed the list of candidates to be reduced until the best site 

emerged. Key factors contributing to the selection of the Turkey Point site include the existing 

transmission and transportation infrastructure to support new generation, the large size and 

seclusion of the site while being relatively close to the load center, and the long-standing 

record of safe and secure operation of nuclear generation at the site since the early 1970s.

i. Water Resources

In regard to Turkey Point Units 6 & 7, the primary source of cooling water makeup will be 

reclaimed water from the Miami-Dade County Water and Sewer Department (MDWASD), with 

potable water also from MDWASD. When reclaimed water is not available in sufficient quantity 

and quality of water needed for cooling, makeup water will be saltwater supplied by radial 

collector wells that are recharged from the marine environment of Biscayne Bay. Horizontal 

collector wells (radial collector wells) have become widely used for the purpose of inducing 

infiltration from surface water bodies into hydraulically-connected aquifer systems in order to 

develop moderate to high capacity water supplies. Turkey Point Units 6 & 7 wastewater will be 

discharged via on-site deep injection wells.

j. Geological Features of Site and Adjacent Areas

Turkey Point lies upon the Floridian Plateau, a partly-submerged peninsula of the continental 

shelf. The peninsula is underlain by approximately 4,000 to 15,000 feet of sedimentary rocks 

consisting of limestone and associated formations that range in age from Paleozoic to Recent. 

Little is known about the basement complex of Paleozoic igneous and metamorphic rocks due 

to their great depth.

Generally in Miami-Dade County, the surficial aquifer (Biscayne Aquifer) consists of a wedgeshaped system of porous clastic and carbonate sedimentary materials, primarily limestone 

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and sand deposits of the Miocene to late Quaternary age. The Biscayne Aquifer is thickest 

along the eastern coast and varies in thickness from 80 to 200 feet thick. The surficial aquifer 

is typically composed of Pamlico Sand, Miami Limestone (Oolite), the Fort Thompson and 

Anastasia Formations (lateral equivalents), Caloosahatchee Marl, and the Tamiami formation. 

The lower confining layers below the surficial aquifer range in thickness from 350 to 600 feet 

and are composed of the Hawthorn Group. Beneath the Hawthorn Group, the Floridan Aquifer 

System ranges from 2,800 to 3,400 feet thick and consists of Suwannee Limestone, Avon 

Park Limestone, and the Oldsmar Formations.

k. Projected Water Quantities for Various Uses

The estimated quantity of water required for the new Turkey Point Units 6 & 7 for industrial 

processing is approximately 936 gallons per minute (gpm) for uses such as process water and 

service water. Approximately 55.3 million gallons per day (mgd) of cooling water would be 

cycled through the cooling towers. Water quantities needed for other uses such as potable 

water are estimated to be approximately 50,400 gallons per day (gpd) for Units 6 & 7.

l. Water Supply Sources and Type

The water for the various water needs of Turkey Point 6 & 7 will be obtained from a reclaimed 

water supply supplied by the Miami-Dade Water and Sewer Department, a saltwater supply, 

and a potable water supply from the Miami-Dade Water and Sewer Department. Reclaimed 

water will be used as makeup water to the cooling water system with saltwater from radial 

collector wells as a back-up water source to be used when reclaimed water is not available in 

sufficient quantity or quality.

Potable water will be used as makeup water for the service water system. The potable water 

supply will also provide water to the fire protection system, demineralized water treatment 

system, and other miscellaneous uses. 

m. Water Conservation Strategies

Use of reclaimed water from MDWASD Turkey Point Units 6 & 7 helps Miami-Dade County 

meet approximately half of its wastewater reuse goals and will provide environmental benefits 

by reducing the volume of wastewater discharged by the County. In the absence of reuse 

opportunities, this treated domestic wastewater would likely continue to be discharged to the 

ocean or into deep injection wells.

Miami-Dade County is required to eliminate ocean outfalls and increase the amount of water 

that is reclaimed for environmental benefit and other beneficial uses. Turkey Point Units 6 & 7

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will use reclaimed water 24 hours per day, 365 days per year when operating and when the 

reclaimed water is available in sufficient quantity and quality.

n. Water Discharges and Pollution Control

Turkey Point Units 6 & 7 will dissipate heat from the power generation process using cooling 

towers. Blowdown water or discharge from the cooling towers, along with other wastestreams, 

will be injected into the boulder zone of the Floridan Aquifer. Non-point source discharges are 

not an issue since there will be none at this facility. Stormwater runoff will be released to the 

closed-loop cooling canal system.

Turkey Point Units 6 & 7 will employ Best Management Practices (BMP) plans and Spill 

Prevention, Control, and Countermeasure (SPCC) plans to prevent and control the inadvertent 

release of pollutants. 

o. Fuel Delivery, Storage, Waste Disposal, and Pollution Control

The Turkey Point Units 6 & 7, reactors will contain enriched uranium fuel assemblies. 

New fuel assemblies will be transported to Turkey Point for use in Units 6 & 7 by truck from a 

fuel fabrication facility in accordance with U.S. Department of Transportation (DOT) and NRC

regulations. Spent fuel assemblies being discharged will remain in the permitted spent fuel 

pool while short half-life isotopes decay. 

After a sufficient decay period, the fuel would be transferred to a permitted on-site 

independent spent fuel storage installation facility or a permitted off-site disposal facility. 

Packaging of the fuel for off-site shipment will comply with the applicable DOT and NRC 

regulations for transportation of radioactive material.

The U.S. Department of Energy (DOE) is responsible for spent fuel transportation from reactor 

sites to a repository under the Nuclear Waste Policy Act of 1982, as amended. FPL has 

executed a standard spent nuclear fuel disposal contract with DOE for fuel used in Units 6 & 

7.

p. Air Emissions and Control Systems

Regarding Turkey Point Units 6 & 7, the units will minimize FPL system air pollutant emissions 

by using nuclear fuel to generate electric power. This includes avoiding emissions of 

particulate matter (PM), sulfur dioxide (SO2), nitrogen oxides (NOx), carbon monoxide (CO), 

carbon dioxide (CO2), and volatile organic compounds (VOC). The circulating water cooling 

towers will be equipped with high-efficiency drift or mist eliminators to minimize emissions of 

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PM to 0.0005 percent of the circulating water; which represents 99.99-percent control of 

potential drift emissions based on the circulating water flow. 

The diesel engines necessary to support Turkey Point Units 6 & 7 and fire pump engines will 

be purchased from manufacturers whose engines meet the EPA’s New Source Performance 

Standards (NSPS) Subpart IIII emission limits. 

q. Noise Emissions and Control Systems

Field surveys and impact assessments of noise expected to be caused by activities 

associated with the Turkey Point Units 6 & 7 project were conducted. Predicted noise levels 

associated with these projects are not expected to result in adverse noise impacts in the 

vicinity of the site.

r. Status of Applications

The Turkey Point Units 6 & 7 Need Determination for this additional nuclear capacity was 

issued by the Florida Public Service Commission in April 2008. The Site Certification 

Application (SCA), under the Florida Electrical Power Plant Siting Act, was filed in June 2009 

and on May 14, 2014, the Florida Power Plant Siting Board authorized the site certification, 

with conditions. In its final order, the Florida Power Plant Siting Board identified the West 

Consensus Corridor as the primary western corridor (comprising an alternate corridor 

proposed by the Miami-Dade Limestone Products Association and a portion of FPL’s West 

Preferred Corridor) and FPL’s West Preferred Corridor as a back-up western transmission line 

corridor. The use of the back-up western transmission line corridor will be necessary in the 

event the pending land exchange with the National Park Service and other agencies is not 

consummated on a timely basis.

A Combined Operating License Application for Units 6 & 7 was submitted to the NRC in June 

2009. There are two components to that application; one is the Environmental Assessment 

(EA) and the other is the Safety component. In 2014 the US Nuclear Regulatory Commission

informed FPL that their decision on the COLA was going to be delayed several years until late 

2016. As a result of this delay, and changes in Florida’s nuclear cost recovery rules, the 

earliest practical in-service dates of Turkey Point Units 6 & 7 (June 2017 and June 2028, 

respectively) have moved beyond the 10-year reporting window (2015 through 2024) of this 

Site Plan.

Besides the certification and the license, additional approvals have been issued for Turkey 

Point Units 6 & 7 including Miami-Dade County Unusual Use approvals that were issued in 

2007 and 2013 and a Land Use Consistency Determination that was issued in 2013. The 

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Prevention of Significant Deterioration (Air permit) was issued in 2009. In addition, a permit to 

construct an exploratory well and a dual zone monitoring well, under the Underground 

Injection Control Program, was issued in 2010, and a permit to convert the exploratory well, to 

an injection well and to operationally test the system, was issued in 2013. Permits from the 

Federal Aviation Administration (FAA) for the containment structure were originally issued in 

2009 and renewed in 2012.

IV.F.2 Potential Sites for Generating Options

Three (3) sites are currently identified as Potential Sites for future generation additions to meet 

FPL’s projected capacity and energy needs.

5

 These sites have been identified as Potential Sites 

due to considerations of location to FPL load centers, space, infrastructure, and/or accessibility to 

fuel and transmission facilities. These sites are suitable for different capacity levels and 

technologies, including both renewable energy and non-renewable energy technologies for 

various sites. 

Each of these Potential Sites offer a range of considerations relative to engineering and/or costs 

associated with the construction and operation of feasible technologies. In addition, each Potential 

Site has different characteristics that will require further definition and attention. 

Permits are presently considered to be obtainable for each of these sites. No significant 

environmental constraints are currently known for any of these sites. The Potential Sites briefly 

discussed below are presented in alphabetical order. At this time, FPL considers each site to be 

equally viable.

Potential Site #1: Hendry County

FPL has acquired an approximately 3,120-acre site in southeast Hendry County, off CR 833. The 

Hendry County site has been listed as a Preferred or Potential Site in previous FPL Site Plans as 

a possibility for a future PV facility and/or natural gas-fired CC generation. FPL currently views the 

Hendry site as one of the most likely sites to be used for future large-scale generation. A map of 

the property owned FPL and an overview map of the site and adjacent areas is found at the end of 

this chapter.

a. Geological Survey (USGS) Map

A USGS map of the site is found at the end of this chapter.

5 As has been described in previous FPL Site Plans, FPL also considers a number of other sites as possible sites for future 

generation additions. These include the remainder of FPL’s existing generation sites and other Greenfield sites. Greenfield sites that 

FPL currently does not own, or for which FPL has not currently secured the necessary rights to, are not specifically identified as 

Potential Sites in order to protect the economic interests of FPL and its customers. 

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b. Existing Land Uses of Site and Adjacent Areas

The existing and future land uses on the site are Agricultural and Upland Forest. The existing 

land uses adjacent to the site are predominately agricultural. The property to the south is the 

Seminole Big Cypress Reservation.

c. Environmental Features

The natural environment adjacent to the north, east, and west of the site are used 

predominately for agricultural activities such as improved, unimproved, and woodland pasture. 

The majority of the pasture lands include upland scrub, pine, and hardwoods.

FPL strives to have no adverse impacts on federal- or state-listed terrestrial plants and 

animals. Much of southwest Florida, including this area is considered habitat for the 

endangered Florida Panther. Although few or no impacts are expected in association with 

future construction at the site, FPL anticipates minimizing or mitigating for unavoidable wildlife 

or wetland impacts.

Future construction and operation of a solar and/or a natural gas-fired CC generating facility at 

this location is not expected to have any adverse impacts on parks, recreation areas, or 

environmentally sensitive lands.

d. Water Quantities Required

The estimated quantity of water required for processing at a CC unit is approximately 0.24 

million gallons per day (mgd) for uses such as process water and service water. Potable water 

demand is expected to average 0.001 mgd. Approximately 7.5 mgd of cooling water would be 

used in cooling towers for one CC unit. Minimal amounts of water would be required for a PV 

facility. 

e. Supply Sources

A Potential water supply source is groundwater, but additional evaluations are necessary to 

determine the exact source. Process and potable water for the new plant will come from the 

existing potable water supply. Specific water conservation strategies will be evaluated and 

selected during the detailed design phase of any development project.

Potential Site # 2: Martin County

FPL is currently evaluating potential sites in Martin County for a future PV facility. No specific 

locations have been selected at this time.

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a. U.S. Geological Survey (USGS) Map

A USGS map of the county has been included at the end of this chapter.

b. Land Uses 

This information is not available because a specific site has not been selected at this time.

c. Environmental Features

This information is not available because a specific site has not been selected at this time.

d. Water Quantities Required

Minimal amounts of water would be required for a PV facility.

e. Supply Sources

Minimal water would be required for a PV facility. A small amount, trucked in, may be needed 

to occasionally clean the PV panels in the absence of sufficient rainfall.

Potential Site # 3: Putnam Plant Site, Putnam County

FPL is currently evaluating the existing Putnam Plant site for future natural gas-fired generation. 

This 66 acre site is located on the east side of Highway 100 opposite the former FPL Palatka Plant 

in East Palatka. The Putnam site has been listed as a Potential Site in previous FPL Site Plans as 

a possibility for future natural gas-fired CC generation. FPL currently views the Putnam site as one 

of the most likely sites to be used for future large-scale generation. 

a. U.S. Geological Survey (USGS) Map 

A USGS map of the Putnam site is found at the end of this chapter. 

b. Existing Land Uses of Site and Adjacent Areas

The Putnam site is designated as Industrial land use. Adjacent land uses include power 

generation and associated facilities (the former Palatka Plant) as well as Mixed Wetland 

Hardwoods, Residential, and Mixed Hardwood-Coniferous.

c. Environmental Features

The majority of the site is developed and has facilities necessary for power plant operations. 

No significant environmental features have been identified at this time. It is anticipated that 

there will be minimal impacts (if any) to federal- or state-listed terrestrial plants and animals in 

association with construction at the site, due to the existing developed nature of the site and 

lack of suitable onsite habitat for listed species. The construction and operation of a power

generating facility at this location is not expected to have any adverse impacts on natural 

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resources of regional significance and FPL is not aware of any other significant features of the 

site.

d. Water Quantities Required

The St John’s River and/or regional water supply initiatives are potential water sources.

Potable water demand is expected to average .001 million gallons per day (mgd). The 

estimated quantity of water required at a CC unit is approximately 0.24 mgd for uses such as 

process water and service water. Approximately 7.5 mgd of cooling water would be used in

cooling towers for a CC unit. 

e. Supply Sources

A potential water supply source is the St. John’s River, but additional evaluation is necessary 

to determine the exact source. Process and potable water for the new plant will come from the 

existing potable water supply. CC and cooling tower technologies utilize less water by design 

than traditional steam generation units. Specific water conservation strategies will be 

evaluated and selected during the detailed design phase of the project development.

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CHAPTER V 

Other Planning Assumptions & Information

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Introduction

The Florida Public Service Commission (FPSC), in Docket No. 960111-EU, specified certain information 

that was to be included in an electric utility’s Ten Year Power Plant Site Plan filing. Among this specified 

information was a group of 12 items listed under a heading entitled “Other Planning Assumptions and 

Information.” These 12 items concern specific aspects of a utility’s resource planning work. The FPSC 

requested a discussion or a description of each of these items.

These 12 items are addressed individually below as separate “Discussion Items”. 

Discussion Item # 1: Describe how any transmission constraints were modeled and explain the 

impacts on the plan. Discuss any plans for alleviating any transmission constraints.

FPL’s resource planning work considers two types of transmission limitations/constraints: external 

limitations and internal limitations. External limitations deal with FPL’s ties to its neighboring systems. 

Internal limitations deal with the flow of electricity within the FPL system. 

The external limitations are important because they affect the development of assumptions for the amount 

of external assistance that is available to the FPL system as well as the amount and price of economy 

energy purchases. Therefore, these external limitations are incorporated both in the reliability analysis and 

economic analysis aspects of resource planning. The amount of external assistance that is assumed to be 

available is based on the projected transfer capability to FPL from outside its system as well as historical 

levels of available assistance. In the loss of load probability (LOLP) portion of its reliability analyses, FPL 

models this amount of external assistance as an additional generator within FPL’s system that provides 

capacity in all but the peak load months. The assumed amount and price of economy energy are based on 

historical values and projections from production costing models.

Internal transmission limitations are addressed by identifying potential geographic locations for potential 

new generating units that minimize adverse impacts to the flow of electricity within FPL’s system. The 

internal transmission limitations are also addressed by developing the direct costs for siting potential new 

units at different locations, evaluating the cost impacts created by the new unit/unit location combination on 

the operation of existing units in the FPL system, and/or evaluating the costs of transmission additions that 

may be needed to address regional concerns regarding an imbalance between load and generation in a 

given region. Both of these site- and system-related transmission costs are developed for each different 

unit/unit location option or groups of options. When analyzing DSM portfolios, such as in a DSM Goals 

docket, FPL also examines the potential for utility DSM energy efficiency programs to avoid/defer regional 

transmission expenditures that would otherwise be needed to import power into that region by lowering 

electrical load in Southeastern Florida. In addition, transfer limits for capacity and energy that can be 

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imported into the Southeastern Florida region (Miami-Dade and Broward Counties) of FPL’s system are 

also developed for use in FPL’s production costing analyses. (A further discussion of the Southeastern

Florida region of FPL’s system, and the need to maintain a regional balance between generation and 

transmission contributions to meet regional load, is found in Chapter III.)

FPL’s annual transmission planning work determines transmission additions needed to address limitations 

and to maintain/enhance system reliability. FPL’s planned transmission facilities to interconnect and 

integrate generating units in FPL’s resource plans, including those transmission facilities that must be 

certified under the Transmission Line Siting Act, are presented in Chapter III.

Discussion Item # 2: Discuss the extent to which the overall economics of the plan were 

analyzed. Discuss how the plan is determined to be cost-effective. Discuss any changes in the 

generation expansion plan as a result of sensitivity tests to the base case load forecast. 

 

FPL typically performs economic analyses of competing resource plans using as an economic criterion

FPL’s levelized system average electric rates (i.e., a Rate Impact Measure or RIM approach). In addition, 

for analyses in which DSM levels are not changed, FPL uses the equivalent criterion of the cumulative 

present value of revenue requirements its system 6

.

6 FPL’s basic approach in its resource planning work is to base decisions on a lowest electric rate basis. However, when DSM 

levels are considered a “given” in the analysis (i.e., when only new generating options are considered), the lowest electric rate basis 

approach and the lowest system cumulative present value of revenue requirements basis approach yield identical results in terms of 

which resource options are more economic. In such cases FPL evaluates resource options on the simpler-to-calculate (but 

equivalent) lowest cumulative present value system revenue requirements basis.

The load forecast that is presented in FPL’s 2015 Site Plan was developed in November 2014. The only 

load forecast sensitivities analyzed during 2014/early 2015 were high load forecast sensitivities developed 

to analyze the quality of FPL’s future reserves.

Discussion Item # 3: Explain and discuss the assumptions used to derive the base case fuel 

forecast. Explain the extent to which the utility tested the sensitivity of the base case plan to high 

and low fuel price scenarios. If high and low fuel price sensitivities were performed, explain the 

changes made to the base case fuel price forecast to generate the sensitivities. If high and low fuel 

price scenarios were performed as part of the planning process, discuss the resulting changes, if

any, in the generation expansion plan under the high and low fuel price scenario. If high and low 

fuel price sensitivities were not evaluated, describe how the base case plan is tested for sensitivity 

to varying fuel prices.

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The basic assumptions FPL used in deriving its fuel price forecasts are discussed in Chapter III of this 

document. FPL used three fuel cost, and three environmental compliance cost, forecasts in analyses 

supporting its 2014 nuclear cost recovery filing. Also, in response to a request from the FPSC Staff, FPL 

used three fuel cost forecasts in sensitivity case analyses for the 2014 DSM Goals docket.

A Medium fuel cost forecast is developed first. Then the Medium fuel cost forecast is adjusted, upwards 

(for the High fuel cost forecast) or downwards (for the Low fuel cost forecast), by multiplying the annual 

cost values from the Medium fuel cost forecast by a factor of (1 + the historical volatility in the 12-month 

forward price, one year ahead) for the High fuel cost forecast, or by a factor of (1 – the historical volatility of 

the 12-month forward price, one year ahead) for the Low fuel cost forecast.

The resource plan presented in this Site Plan is based, in part, on those prior analyses. For that reason, 

this resource plan has not been further tested for different fuel cost forecasts.

Discussion Item # 4: Describe how the sensitivity of the plan was tested with respect to holding 

the differential between oil/gas and coal constant over the planning horizon.

As described above in the answer to Discussion Item # 3, FPL used up to three fuel cost forecasts in its 

2014/early 2015 resource planning analyses. While these forecasts did not represent a constant cost 

differential between oil/gas and coal, a variety of fuel cost differentials were represented in these forecasts.

Discussion Item # 5: Describe how generating unit performance was modeled in the planning 

process.

The performance of existing generating units on FPL’s system was modeled using current projections for 

scheduled outages, unplanned outages, capacity output ratings, and heat rate information. Schedule 1 in 

Chapter I and Schedule 8 in Chapter III present the current and projected capacity output ratings of FPL’s 

existing units. The values used for outages and heat rates are generally consistent with the values FPL has 

used in planning studies in recent years. 

In regard to new unit performance, FPL utilized current projections for the capital costs, fixed and variable 

operating & maintenance costs, capital replacement costs, construction schedules, heat rates, and 

capacity ratings for all construction options in its resource planning work. A summary of this information for 

the new capacity options that FPL currently projects to add over the reporting horizon for this document is 

presented on the Schedule 9 forms in Chapter III.

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Discussion Item # 6: Describe and discuss the financial assumptions used in the planning 

process. Discuss how the sensitivity of the plan was tested with respect to varying financial 

assumptions.

During 2014, FPL used the following financial assumptions: i) an incremental capital structure of 40.38% 

debt and 59.62% equity; (ii) a 5.14% cost of debt; (iii) a 10.5% return on equity; and (iv) an after-tax 

discount rate of 7.54%. In February 2015, the cost of debt changed to 5.05% and the after-tax discount 

rate changed to 7.51%. No sensitivities of these financial assumptions were used in FPL’s 2014/early 2015

resource planning work.

Discussion Item # 7: Describe in detail the electric utility’s Integrated Resource Planning

process. Discuss whether the optimization was based on revenue requirements, rates, or total 

resource cost.

FPL’s integrated resource planning (IRP) process is described in detail in Chapter III of this document.

The standard basis for comparing the economics of competing resource plans in FPL’s basic IRP process 

is the impact of the plans on FPL’s electricity rate levels with the objective generally being to minimize 

FPL’s projected levelized system average electric rate (i.e., a Rate Impact Measure or RIM approach). As 

discussed in response to Discussion Item # 2, both the electricity rate perspective and the cumulative 

present value of system revenue requirement perspective yield identical results in terms of which resource 

options are more economical when DSM levels are unchanged between competing resource plans. 

Therefore, in planning work in which DSM levels were unchanged, the equivalent, but simpler-to-calculate, 

cumulative present value of revenue requirements perspective was utilized.

Discussion Item # 8: Define and discuss the electric utility’s generation and transmission 

reliability criteria.

FPL uses three system reliability criteria in its resource planning work that addresses generation, purchase, 

and DSM options. One criterion is a minimum 20% Summer and Winter reserve margin. Another reliability 

criterion is a maximum of 0.1 days per year loss-of-load-probability (LOLP). The third criterion is a 

minimum 10% generation-only reserve margin (GRM) criterion. These three reliability criteria are discussed 

in Chapter III of this document. 

In regard to transmission reliability analysis work, FPL has adopted transmission planning criteria that are 

consistent with the planning criteria established by the Florida Reliability Coordinating Council (FRCC). The 

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FRCC has adopted transmission planning criteria that are consistent with the Reliability Standards established 

by the North American Electric Reliability Council (NERC). The NERC Reliability Standards are available on 

the internet site (http://www.nerc.com/).

In addition, FPL has developed a Facility Connection Requirements (FCR) document as well as a Facility 

Rating Methodology document that are also available on the internet under the “Interconnection Request 

Information”, and “FPL Facility Ratings Methodologies”, directories respectively

at https://www.oatioasis.com/FPL/index.html.

Generally, FPL limits its transmission facilities to 100% of the applicable thermal rating. The normal and 

contingency voltage criteria for FPL stations are provided below:

Normal/Contingency

 Voltage Level (kV) Vmin (p.u.) Vmax (p.u.)

 69, 115, 138 0.95/0.95 1.05/1.07

230 0.95/0.95 1.06/1.07

500 0.95/0.95 1.07/1.09

 Turkey Point (*) 1.01/1.01 1.06/1.06

 St. Lucie (*) 1.00/1.00 1.06/1.06

(*) Voltage range criteria for FPL’s Nuclear Power Plants

There may be isolated cases for which FPL may have determined that it is acceptable to deviate from the 

general criteria stated above. There are several factors that could influence these criteria, such as the overall 

number of potential customers that may be impacted, the probability of an outage actually occurring, and 

transmission system performance.

Discussion Item # 9: Discuss how the electric utility verifies the durability of energy savings for 

its DSM programs.

The projected impacts of FPL’s DSM programs on demand and energy consumption are revised 

periodically. Engineering models, calibrated with current field-metered data, are updated at regular 

intervals. Participation trends are tracked for all of FPL’s DSM programs in order to adjust impacts each 

year for changes in the mix of efficiency measures being installed by program participants. For its load 

management programs, FPL conducts periodic tests of the load control equipment to ensure that the 

equipment is functioning correctly. These tests, plus actual, non-test load management events, also allow 

FPL to gauge the MW reduction capabilities of its load management programs on an on-going basis.

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Discussion Item # 10: Discuss how strategic concerns are incorporated in the planning process. 

The Executive Summary and Chapter III provide a discussion of a variety of system concerns/issues that 

influence FPL’s resource planning process. Please see those chapters for a discussion of those 

concerns/issues.

In addition to these system concerns/issues, there are other strategic factors that FPL typically considers 

when choosing between resource options. These include: (1) technology risk; (2) environmental risk, and 

(3) site feasibility. The consideration of these factors may include both economic and non-economic 

aspects.

Technology risk is an assessment of the relative maturity of competing technologies. For example, a 

prototype technology, which has not achieved general commercial acceptance, has a higher risk than a 

technology in wide use and, therefore, assuming all else is equal, is less desirable.

Environmental risk is an assessment of the relative environmental acceptability of different generating 

technologies and their associated environmental impacts on the FPL system, including environmental 

compliance costs. Technologies regarded as more acceptable from an environmental perspective for 

FPL’s resource plan are those that minimize environmental impacts for the FPL system as a whole through 

highly efficient fuel use, state-of-the-art environmental controls, generating technologies that do not utilize 

fossil fuels (such as nuclear and solar), etc.

Site feasibility assesses a wide range of economic, regulatory, and environmental factors related to 

successfully developing and operating the specified technology at the site in question. Projects that are 

more acceptable have sites with few barriers to successful development.

All of these factors play a part in FPL’s planning and decision-making, including its decisions to construct 

capacity or purchase power.

Discussion Item # 11: Describe the procurement process the electric utility intends to utilize to 

acquire the additional supply-side resources identified in the electric utility’s ten-year site plan.

As shown in this 2015 Site Plan, FPL’s resource plan currently reflects the following major supply-side or 

generation resource additions: the on-going modernization at Port Everglades, the replacement of existing 

GT capacity with new CT capacity, the on-going upgrading of CTs in several existing CCs throughout 

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FPL’s system, the implementation of the previously executed EcoGen PPA, the projected addition of new 

PV facilities, and the addition of new CC units.

In regard to the modernization project at Port Everglades, the project received a Florida Public Service 

Commission waiver from the Bid Rule due to attributes specific to the Port Everglades site and to 

modernization projects in general (such as use of existing land, water, transmission, etc.) plus other 

economic benefits to FPL’s customers. This waiver from the Bid Rule was granted in Order No. PSC-11-

0360-PAA-EI for Port Everglades.

CT upgrades are currently taking place at several CC units throughout the FPL system. FPL was 

approached by the original equipment manufacturer (OEM) of the CTs regarding the possibility of 

upgrading these units. Following negotiations with the OEM, and economic analyses that showed 

upgrading was cost-effective for FPL’s customers, the decision was made to proceed with the CT 

upgrades. That process is underway and is scheduled to be completed in 2015.

The EcoGen PPAs, which were approved by the Commission in Order No. PSC-13-0205-CO-EQ dated 

5/21/13, were the result of negotiations between U.S. EcoGen and FPL.

In regard to the planned PV facilities, the selection of equipment and installation contractors for these 

facilities will be done via competitive bidding.

Identification of projected self-build generation resources beyond those units already approved by the 

FPSC and Governor and Siting Board or units, such as the 2019 and 2023 CC units and the PV projects 

presented in this Site Plan, is required of FPL in its Site Plan filings. FPL’s identification of these resources 

represents FPL’s current view of alternatives that appear to be the best, most cost-effective self-build 

options at present. FPL reserves the right to refine its planning analyses and to identify and evaluate other 

options before making decisions regarding future capacity additions. Such refined analyses have the 

potential to yield a variety of self-build options, some of which may not require an RFP. If an RFP is issued 

for generation resources, FPL will choose the best alternative for its customers, regardless of whether it is 

a third party proposal to an RFP or an FPL self-build option. If an RFP for generation resources is not 

required, FPL will utilize a competitive bidding process to select equipment suppliers and installation 

contractors based on its assessment of price and supplier capability to realize the best generation option 

for its customers.

Discussion Item # 12: Provide the transmission construction and upgrade plans for electric 

utility system lines that must be certified under the Transmission Line Siting Act (403.52 – 403.536, 

F. S.) during the planning horizon. Also, provide the rationale for any new or upgraded line.

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FPL has identified the need for a new 230 kV transmission line that required certification under the 

Transmission Line Siting Act that was issued in April 2006. The new line will connect FPL’s St. Johns 

Substation to its Pringle Substation (shown on Table III.E.1 in Chapter III). The line will be constructed in 

two phases. Phase 1 was completed in May 2009 and consisted of a new line connecting Pringle to a new 

Pellicer Substation. Phase 2 will connect St. Johns to Pellicer and it is scheduled to be completed by 

December 2018. The construction of this line is necessary to serve existing and future customers in the 

Flagler and St. Johns areas in a reliable and effective manner.

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