Florida Municipal Power Agency

Florida Municipal Power Agency
Florida Municipal Power Agency
March 30,2007
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Ms. Blanca Bay0
Florida Public Service Commission
Bureau of Electric Reliability
Capital Circle Office Center
2540 Shumard Oak Blvd.
Tallahassee, FL 32399-0850
Dear Ms. Bayo:
Enclosed are 25 copies of Florida Municipal Power Agency's April 2007 Ten-Year Site Plan as
jointly prepared by R.W. Beck and FMPA and submitted by R.W. Beck on behalf of FMPA.
The Ten-Year Site Plan information is provided in accordance with Florida Public Service
Commission rule 25-22.070, 25-22.07 1, and 25-22.072, which require certain electric utilities in
the State of Florida to submit a Ten-Year Site Plan. The plan is required to describe the
estimated electric power generating needs and to identify the general location of any proposed
near-term power plant sites as of December 3 1, 2006.
If you should have any questions, please feel free to contact me at 321-239-1033.
Sincerely,
William May
Manager of Power Supply
CMP -,
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Michael Haff (FPSC)
Fred Bryant (FMPA)
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8553 Commodity Circle I Orlando, FL 32819-9002
T, (407) 355-7767 I Toll FM (888)774-7606
F. (407) 355-5794 I www.fmpa.com
bil I.mayCMmpa.com
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Table of Contents
FMPA 2007 Ten-Year Site Plan
Table of Contents
Executive Summary ................................................................................................................ e5-1
Description of FMPA .......................................................................................
1-1
Section 1
FMPA ................................................................................................................. 1-1
1.1
1.2
1.3
1.4
Section 2
2.1
2.2
Section 3
3.1
3.2
3.3
3.4
3.5
3.6
3.7
Section 4
4.1
4.2
4.3
Section 5
5.1
All-Requirements Project ...................................................................................
FMPA Other Generation Projects ......................................................................
Summary of Projects ..........................................................................................
Description of Existing Facilities.....................................................................
ARP Supply-side Resources ..............................................................................
ARP Transmission System.................................................................................
Member Transmission Systems ..........................................................
2.2.1
ARP Transmission Agreements ..........................................................
2.2.2
Forecast of Demand and Energy for the All-Requirements Power
Supply Project ..................................................................................................
Introduction ........................................................................................................
Load Forecast Process ........................................................................................
2006 Load Forecast Overview ...........................................................................
Methodology ......................................................................................................
3.4.1
Model Specification ............................................................................
3.4.2
Projection of NEL and Peak Demand .................................................
Data Sources.......................................................................................................
3.5.1
Historical Member Retail Sales Data ..................................................
3.5.2
Weather Data ......................................................................................
3.5.3
Economic Data ...................................................................................
3.5.4
Real Electricity Price Data ..................................................................
Overview of Results ...........................................................................................
3.6.1
Base Case Forecast .............................................................................
3.6.2
Weather-Related Uncertainty of the Forecast .....................................
Load Forecast Schedules ....................................................................................
Renewable Resources and Conservation Programs ......................................
Introduction ........................................................................................................
Renewable Resources .........................................................................................
Conservation Programs ......................................................................................
4.3.1
Energy Audits Program ......................................................................
4.3.2
High-pressure Sodium Outdoor Lighting Conversion ........................
4.3.3
PURPA Time-of-Use Standard...........................................................
4.3.4
Energy [email protected] ......................................................................................
4.3.5
Demand-Side Management ................................................................
4.3.6
Distributed Generation........................................................................
Forecast of Facilities Requirements ................................................................
ARP Planning Process ........................................................................................
TOC-1
1-2
1-6
1-8
2-1
2-1
2-2
2-3
2-5
3-1
3-1
3-1
3-2
3-2
3-3
3-4
3-5
3-5
3-5
3-6
3-6
3-6
3-6
3-6
3-7
4-1
4-1
4-2
4-2
4-3
4-3
4-3
4-4
4-4
4-4
5-1
5-1
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Table of Contents
FMPA 2007 Ten-Year Site Plan
5.2
5.3
5.4
Section 6
Planned A W Generating Facility Requirements ...............................................
Capacity and Purchase Power Requirements .....................................................
Summary of Current and Future ARF' Resource Capacity .................................
Site and Facility Descriptions ..........................................................................
5-1
5-2
5-3
6-1
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List of Figures, Tables and Required Schedules
Table ES-1
Table ES-2
Figure ES-1
Figure 1-1
Table 1-1
Table 1-2
Table 1-3
Table 1-4
Table 1-5
Table 2-1
Schedule 1
Figure 3-1
Schedule 2.1
Schedule 2.2
Schedule 2.3
Schedule 3.1
Schedule 3.2
Schedule 3.3
Schedule 3.la
Schedule 3.2a
Schedule 3.3a
Schedule 3.lb
Schedule 3.2b
Schedule 3.3b
Schedule 4
Table 5-1
Table 5-2
Schedule 5
Schedule 6.1
Schedule 6.2
FMPA Summer 2007 Capacity Resources ....................................................... ES-1
FMPA TYSP Planned Expansion Resources ................................................... ES-2
ARP Member and FMPA Power Supply Resource Locations ......................... ES-4
ARP Member Cities ........................................................................................... 1-2
St. Lucie Project Participants ............................................................................. 1-6
Stanton Project Participants ................................................................................
1-7
Tri-City Project Participants ............................................................................... 1-7
Stanton I1 Project Participants ............................................................................
1-8
Summary of FMPA Power Supply Project Participants..................................... 1-8
ARP Supply-side Resources Summer 2007 ...................................................... 2-1
ARP Existing Generating Resources as of December 3 1, 2006 ......................... 2-6
Load Forecast Process ........................................................................................ 3-1
History and Forecast of Energy Consumption and Number of Customers by
Customer Class ................................................................................................... 3-8
History and Forecast of Energy Consumption and Number of Customers by
Customer Class ................................................................................................... 3-9
History and Forecast of Energy Consumption and Number of Customers by
Customer Class ................................................................................................. 3-10
History and Forecast of Summer Peak Demand (MW) - Base Case ............... 3-1 1
History and Forecast of Winter Peak Demand (MW) - Base Case..................3-12
History and Forecast of Annual Net Energy for Load (GWh) - Base Case ..... 3-13
Forecast of Summer Peak Demand (MW) - High Case ................................... 3-14
Forecast of Winter Peak Demand ( M W )- High Case ..................................... 3-15
Forecast of Annual Net Energy for Load (GWh) - High Case ........................ 3-16
Forecast of Summer Peak Demand (MW) - Low Case ................................... 3-17
Forecast of Winter Peak Demand (MW) - Low Case ...................................... 3-18
Forecast of Annual Net Energy for Load (GWh) - Low Case ......................... 3-19
Previous Year and 2-Year Forecast of Peak Demand and Net Energy for
Load by Month ................................................................................................. 3-20
Summary of All-Requirements Project Resource Summer Capacity .................5-4
Summary of All-Requirements Project Resource Winter Capacity ...................5-5
Fuel Requirements - All-Requirements Project ................................................. 5-6
Energy Sources (GWh) - All-Requirements Project .......................................... 5-7
Energy Sources (%) - All-Requirements Project ............................................... 5-8
TOC-2
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Table of Contents
FMPA 2007 Ten-Year Site Plan
Schedule 7.1
Schedule 7.2
Schedule 8
Table 6-1
Schedule 9.1
Schedule 9.2
Schedule 9.3
Schedule 9.4
Schedule 9.5
Schedule 9.6
Schedule 9.7
Schedule 10
Forecast of Capacity, Demand, and Scheduled Maintenance at Time of
Summer Peak...................................................................................................... 5-9
Forecast of Capacity, Demand, and Scheduled Maintenance at Time of
Winter Peak ...................................................................................................... 5-10
Planned and Prospective Generating Facility Additions and Changes.............5-1 1
Proposed TEC Ownership Percentages .............................................................. 6-3
Status Report and Specifications of Proposed Generating Facilities .................6-4
Status Report and Specifications of Proposed Generating Facilities .................6-5
Status Report and Specifications of Proposed Generating Facilities .................6-6
Status Report and Specifications of Proposed Generating Facilities ................. 6-7
Status Report and Specifications of Proposed Generating Facilities ................. 6-8
Status Report and Specifications of Proposed Generating Facilities ................. 6-9
Status Report and Specifications of Proposed Generating Facilities ...............6-10
Status Report and Specifications of Proposed Directly Associated
Transmission Lines .......................................................................................... 6-1 1
Appendices
Appendix I
Appendix I1
Appendix I11
Appendix IV
List of Abbreviations ............................................................................................ 1-1
Other Member Transmission Information ..................,....,...................................II-1
Additional Reserve Margin Information. ...,..,..........................,...,.,..,.,...,.......... 111-1
IV-1
Supplemental Information .................................................................................
TOC-3
Executive Summary
FMPA 2007 Ten-Year Site Plan
Executive Summary
The following information is provided in accordance with Florida Public Service
Commission (PSC) Rules 25-22.070, 25-22.07 1, and 25-22.072, which require certain
electric utilities in the State of Florida to submit a Ten-Year Site Plan (TYSP). The
TYSP is required to describe the estimated electric power generating needs and to
identify the general location and type of any proposed near-term generation capacity and
transmission additions.
The Florida Municipal Power Agency (FMPA, or the Agency) is a project-oriented, jointaction agency. FMPA’s direct responsibility for power supply planning can be separated
into two parts. First, for the All-Requirements Project (ARP), where the Agency has
committed to supplying all of the power requirements of 15 cities, the Agency is solely
responsible for power supply planning. Second, for member systems that are not in the
ARP, the Agency’s role has been to evaluate joint action opportunities and make the
findings available to the membership whereby each member can elect whether or not to
participate. This report presents planning information for the ARP and on the existing
Agency projects.
The ARP and existing Agency summer capacity resources for the year 2007 total 1,786
MW. This capacity is comprised of “excluded” nuclear resources, member-owned
resources, ARP-owned resources, and purchase power, and is summarized below in Table
ES-I.
Table ES-1
FMPA Summer 2007 Capacity Resources
Resource Category
Nuclear
Summer
Capacity
(MW)
85
ARP Ownership
565
Member Ownership
666
Purchase Power
470
lTotal2007 ARP Resources
ES- 1
1,786
FMPA 2007 Ten-Year Site Plan
Executive Summary
FMPA has a total of 1,240 MW of power supply projects currently under construction or
planned for construction. Future ARP TYSP expansion resources are presented below in
Table ES-2.
Table ES-2
FMPA TYSP Planned Expansion Resources
Commercial
Operation
(MMW
Summer
Capacity (MW)
Southern Company Peaking Purchase
12/07
175
Treasure Coast Energy Center Unit 1
Peaking Units (or Power Purchase) [’I
06108
296
06110
90
Combined Cycle Unit (or Power Purchase) [’I
0611 1
296
Taylor Energy Center Unit 1
Peakina., Units
06112
06116
293
90
Unit Description
I
Total
1,240
[I]
FMPA is currently undergoing an RFP evaluation regarding potential power supply purchases
that may delay these resources.
FMPA issued a Request for Power Supply Proposals (Power Supply RFP) in November
2006. The purpose of the Power Supply RFP is to determine whether a sufficient and
cost-effective source of capacity and energy can be obtained as a replacement for the
peaking units and combined cycle facility that are planned for commercial operation in
2010 and 201 1, respectively. Based on the outcome of this decision, FMPA will
determine whether to delay the in-service dates for these units.
FMPA utilizes a variety of fuel sources to provide power to its members, including
generation from nuclear, coal-fired, natural gas-fired, oil-fired resources and renewable
resources. Worthy of note is FMPA’s awareness of the potential benefits of increased
fuel diversity among its generating portfolio, which has prompted FMPA to participate
with JEA, the City of Tallahassee, and Reedy Creek Improvement District in the
development of the Taylor Energy Center, a 754 MW supercritical coal unit to be located
approximately 5 miles southeast of Perry, in Taylor County, Florida. The primary
advantage of this publicly-owned, coal-fired project would be to diversify resources,
while supplying competitively priced power into the future.
The TEC “Need for Power” application (Need Determination) was submitted to the PSC
in September 2006. Hearings on the Need Determination have been held, with a decision
ES-2
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FMPA 2007 Ten-Year Site Plan
Executive Summary
expected from the PSC in the spring of 2007.
commercial operation in May 20 12.
TEC Unit 1 is scheduled to begin
FMPA will soon add capacity from two additional resources that utilize natural gas. The
first is the Treasure Coast Energy Center (TCEC), a 296 MW combined cycle unit that
FMPA is developing at a site near Fort Pierce. FMPA received site certification in June
2006, and physical construction began on TCEC Unit 1 in August 2006. Construction is
on schedule, with an in-service date for TCEC Unit 1 of June 2008. The second capacity
resource under construction is through a contract to purchase 175 MW of new peaking
power from Southern Company’s Oleander plant beginning in December 2007. The
purchase will have a term of 20 years.
FMPA participates in “Green Energy” through renewable power purchases and member
conservation programs. FMPA receives renewable energy from two renewable power
purchases FMPA receives power from a cogeneration plant owned and operated by U.S.
Sugar Corporation that is fueled by sugar bagass, a byproduct of sugar production. The
second renewable resource utilizes landfill gas provided by the Orange County Landfill
to supplement the coal requirements of the Stanton Energy Center, which is partially
owned by FMPA. FMPA and its members continue to investigate additional sources of
“Green Energy” through renewable power purchases or conservation programs.
A location map of the ARP members and FMPA’s power resources is shown in Figure
ES- 1 below.
ES-3
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Executive Summary
FMPA 2007 Ten-Year Site Plan
Figure ES-1
ARP Member and FMPA Power Supply Resource Locations
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FMPA 2007 Ten-Year Site Plan
Description of FMPA
Section1 Description of FMPA
1.1
FMPA
Florida Municipal Power Agency (FMPA) is a wholesale power company created to provide a
means by which its members could cooperatively gain mutual advantage and meet present and
projected electric energy requirements and is owned by 30 municipal electric utilities. FMPA
also provides economies of scale in power generation and related services to support communityowned electric utilities.
FMPA was created on February 24, 1978, by the signing of the Interlocal Agreement among its
original members to provide a means by which its members could cooperatively gain mutual
advantage and meet present and projected electric energy requirements. This agreement
specified the purposes and authority of FMPA. FMPA was formed under the provisions of
Article VII, Section 10 of the Florida Constitution, the Joint Power Act, Chapter 361, Part 11,
Florida Statutes, and the Florida Interlocal Cooperation Act of 1969, Section 163.01, Florida
Statutes.
The Florida Constitution and the Joint Power Act provide the authority for municipal electric
utilities to join together for the joint financing, constructing, acquiring, managing, operating,
utilizing, and owning of electric power plants. The Interlocal Cooperation Act authorizes
municipal electric utilities to cooperate with each other on the basis of mutual advantage to
provide services and facilities in a manner and in a form of governmental organization that will
accord best with geographic, economic, population, and other factors influencing the needs and
development of local communities.
Each city commission, utility commission, or authority, which is a signatory to the Interlocal
Agreement, has the right to appoint one member to FMPA’s Board of Directors, the goveming
body of FMPA. The Board has the responsibility of developing and approving FMPA’s budget,
approving and financing projects, hiring a General Manager and General Counsel, establishing
bylaws that govem how FMPA operates, and creating policies that implement such bylaws. At
its annual meeting, the Board elects a Chairman, Vice Chairman, Secretary, Treasurer, and an
Executive Committee. The Executive Committee consists of 13 representatives, which include
nine elected by the Board, the current Board Chairman, Vice Chairman, Secretary, and
Treasurer. The Executive Committee meets regularly to control FMPA’s day-to-day operations
and to approve expenditures and contracts. The Executive Committee is also responsible for
1-1
FMPA 2007 Ten-Year Site Plan
Description of FMPA
monitoring budgeted expenditure levels and assuring that authorized work is completed in a
timely manner.
1.2
All-Requirements Project
FMPA developed the All-Requirements Project (ARP) to secure an adequate, economical, and
reliable supply of electric capacity and energy to meet the needs of the ARP members. Fifteen
FMPA member municipals form the ARP. The locations of the ARP members are shown in
Figure 1-1.
Bushnell, Green Cove Springs, Jacksonville Beach, Leesburg, and Ocala were the original ARP
members, all joining at the formulation of FMPA in 1978. The remaining ten members joined as
follows:
0
199 1 - The City of Clewiston;
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1997- The Cities of Vero Beach and Starke;
1998 - Fort Pierce Utilities Authority (FPUA) and the City of Key West;
0
2000 - The City of Fort Meade, the Town of Havana, and the City of Newberry; and
0
2002 - Kissimmee Utility Authority (KUA) and the City of Lake Worth.
The City of Vero Beach has provided notice to FMPA to exercise their right to modify their ARP
full requirements membership beginning January 1, 20 10.
Figure 1-1
ARP Member Cities
1-2
Description of FMPA
FMPA 2007 Ten-Year Site Plan
ARP members are required to purchase all of their capacity and energy from the ARP. ARP
members that own generating capacity are required to sell the electric capacity and energy of
their generating resources to FMPA. In exchange for the sale of their electric capacity and
energy, the owners receive capacity and energy (C&E) payments. All ARP members are
supplied 100 percent of their ARP capacity and energy requirements from FMPA at the average
capacity and energy rate of the ARP.
Following is a brief description of each of the ARP member cities. The information provided is
based on the Florida Municipal Electric Association’s 2006 membership directory
(www.publicpower.com) and additional information obtained during 2006.
Bus hnell
The City of Bushnell is located in central Florida in Sumter County. The City joined the ARF’ in
May 1986. Vince Ruano is the City Manager and Bruce Hickle is the Director of Utilities. The
City’s service area is approximately 1.4 square miles. For more information about the City of
Bushnell, please visit www.cityofbushnellfl.com.
Clewiston
The City of Clewiston is located in southern Florida in Hendry County. The City joined the ARP
in May 1991. Kevin McCarthy is the Utilities Director. The City’s service area is approximately
5 square miles. For more information about the City of Clewiston, please visit www.clewistonfl.gov.
Fort Meade
The City of Fort Meade is located in central Florida in Polk County. The City joined the ARP in
February 2000. Katrina Powell is the City Manager. The City’s service area is approximately 5
square miles. FMPA serves capacity and energy requirements for the City via the h l l
requirements agreement currently in place with Tampa Electric Company (TECO). When the
Fort Meade/TECO agreement terminates in January 2009, FMPA will serve the City from the
ARP’s portfolio of power supply resources. For more information about the City of Fort Meade,
please visit www.state.fl.us/ftmeade/.
Fort Pierce Utilities Authority
The City of Fort Pierce is located on Florida’s east coast in St. Lucie County. FPUA joined the
ARP in January 1998. William Theiss is the Director of Ctilities and Thomas W. Richards is
Director of Electric &: Gas Systems. FPUA’s service area is approximately 35 square miles. For
more information about Fort Pierce Ctilities Authority, please \,isit nww.fpua.com.
1-3
FMPA 2007 Ten-Year Site Plan
Description of FMPA
Green Cove Springs
The City of Green Cove Springs is located in northeast Florida in Clay County. The City joined
the ARP in May 1986. Gregg Griffin is the Director of Electric Utility. The City’s service area
is approximately 25 square miles. For more information about the City of Green Cove Springs,
please visit www.greencovesprings.com.
Town of Havana
The Town of Havana is located in the panhandle of Florida in Gadsden County. The Town
joined the ARP in July 2000. Howard McKinnon is the Town Manager. The Town’s service
area is approximately 4.5 square miles. For more information about the Town of Havana, please
visit www.havanaflorida.com.
Jacksonville Beach
The City of Jacksonville Beach’s electric department, more commonly known as Beaches
Energy Services (Beaches), is located in northeast Florida in Duval and St. Johns Counties.
Beaches joined the ARP in May 1986. George D. Forbes is the City Manager and Don Ouchley
is the Utilities Director. Beaches’ service area is approximately 45 square miles. For more
information about Beaches, please visit www.beachesenergy.com.
Utility Board, City of Key West
The Utility Board of the City of Key West, also known as Keys Energy Services (KEYS),
provides electric service to the lower Keys in Monroe County. KEYS joined the A W in April
1998. Robert R. Padron is Chairman of the Utility Board and Lynne Tejeda is the General
Manager and CEO. KEYS’ service area is approximately 45 square miles. For more
information about Keys Energy Services, please visit www.keysenergy.com.
Kissimmee Utilitv A uthorit y
Kissimmee is located in central Florida in Osceola County. Kissimmee Utility Authority (KLA)
joined the ARP in October 2002. James C. Welsh is the President & General Manager, and A.
K. (Ben) Sharma is Vice President of Power Supply and plans to retire in the Spring of 2007.
After Mr. Sharma’s retirement, Larry Mattem m i l l replace him as Vice President of Power
Supply. KUA’s service area is approximately 85 square miles. For more information about
Ki ssimmee Uti 1it y Authority , p 1ease vi sit w w MI.kua .c om.
Lake Worth
Lake Worth is located on Florida’s east coast in Palm Beach County. Lake Worth joined the
ARP in October 2002. Laura Hannah is the Assistant City Managerhnterim City Manager. Lake
1-4
Description of FMPA
FMPA 2007 Ten-Year Site Plan
Worth’s service area is approximately 12.5 square miles. For more information about the City of
Lake Worth, please visit www.lakeworth.org.
Leesburg
The City of Leesburg is located in central Florida in Lake County. The City joined the ARF’ in
May 1986. Ron Stock is the City Manager and Paul Kalv is the Director of Electric Department.
The City’s service area is approximately 50 square miles. For more information about the City
of Leesburg, please visit www.leesburgflorida.gov.
Newberry
The City of Newberry is located in the northern part of Florida in Alachua County. The City
joined the ARP in December 2000. Blaine Suggs is the Utilities and Public Works Director.
The City’s service area is approximately 6 square miles. For more information about the City of
Newberry, please visit www.cityofhewberryfl.com.
Ocala
The City of Ocala is located in central Florida in Marion County. The City joined the ARP in
May 1986. Paul K. Nugent is the City Manager, and Rebecca Mattey is the Director of Electric
Utility. The City’s service area is approximately 161 square miles. For more information about
the City of Ocala, please visit www.ocalafl.org.
Starke
Starke is located in north Florida in Bradford County. The City joined the ARP in October 1997.
Ricky Thompson is the Project Director and Safety Director. The City’s service area is
approximately 6.5 square miles. For more information about the City of Starke, please visit
www .cityofstarke.org.
Vero Beach
The City of Vero Beach is located on Florida’s east coast in Indian River County. Vero Beach
joined the ARP in June 1997. James M. Gabbard is the City Manager. The City’s service area is
approximately 40 square miles.
On December 9, 2004, the City of Vero Beach sent FMPA their “Notice of Establishment of
Contract Rate of Delivery.” The effective date of the notice is January 1, 20 10. The effect of
the notice is that the ARP will no longer utilize the City’s generating resources, and the ARP will
commence serving Vero Beach on a partial requirements basis. The amount of the partial
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FMPA 2007 Ten-Year Site Plan
Description of FMPA
requirements will be determined in 2009. For more information about the City of Vero Beach,
please visit www.covb.org.
1.3
FMPA Other Generation Projects
In addition to the ARP, FMPA has four other power supply projects as discussed below.
St. Lucie Proiect
On May 12, 1983, FMPA purchased from Florida Power & Light (FPL) an 8.806percent
undivided ownership interest in St. Lucie Unit No. 2 (the St. Lucie Project), a nuclear generating
unit. The St. Lucie Unit No. 2 was declared in commercial operation on August 8, 1983, and in
Firm Operation, as defined in the participation agreement, on August 14, 1983. Fifteen of
FMPA’s members are participants in the St. Lucie Project, with the following entitlements as
shown in Table 1- 1.
Table 1-1
St. Lucie Project Participants
City
Alachua
Fort Meade
Green Cove Springs
Jacksonville Beach
Lake Worth
Moore Haven
New Smyrna Beach
Vero Beach
I
YOEntitlement
0.431
0.336
1.757
7.329
24.870
0.384
9.884
15.202
ICity
Clewiston
Fort Pierce
Homestead
Kissimmee
Leesburg
Newberry
Starke
I
% Entitlement
2.202
15.206
8.269
9.405
2.326
0.184
2.215
Stanton Proiect
On August 13, 1984, FMPA purchased from the Orlando Utilities Commission (OUC) a 14.8 193
percent undivided ownership interest in Stanton Unit No. 1 (the Stanton Project). Stanton Unit
No. 1 went into commercial operation July 1, 1987. Six of FMPA’s members are participants in
the Stanton Project with entitlements as shown in Table 1-2.
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FMPA 2007 Ten-Year Site Plan
Description of FMPA
Table 1-2
Stanton Project Participants
City
% Entitlement
Fort Pierce
Kissimmee
Starke
City
% Entitlement
12.195
16.260
32.521
24.390 Homestead
12.195 Lake Worth
2.439 Vero Beach
Tri-Citv Project
On March 22, 1985, the FMPA Board approved the agreements associated with the Ti-City
Project. The Tri-City Project involves the purchase from OUC of an additional 5.3012 percent
undivided ownership interest in Stanton Unit No. 1. Three of FMPA’s members are participants
in the Tri-City Project with the following entitlements as shown in Table 1-3.
Table 1-3
Tri-City Project Participants
Homestead
22.727
Stanton I/ Project
On June 6, 1991, under the Stanton I1 Project structure, FMPA purchased from OUC a 23.2367
percent undivided ownership interest in OUC’s Stanton Unit No. 2, a coal fired unit virtually
identical to Stanton Unit No. 1. The unit commenced commercial operation in June 1996.
Seven of FMPA’s members are participants in the Stanton I1 Project with the following
entitlements as shown in Table 1-4.
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FMPA 2007 Ten-Year Site Plan
Description of FMPA
Table 1-4
Stanton I1 Project Participants
City
% Entitlement
Fort Pierce
Key West
St. Cloud
Vero Beach
1.4
City
% Entitlement
16.4880 Homestead
9.8932 Kissimmee
14.6711 Starke
16.4887
8.2443
32.9774
1.2366
Summary of Projects
Table 1-5provides a summary of FMPA member project participation as of January 1,2007
Table 1-5
Summary of FMPA Power Supply Project Participants
[I]Other FMPA non-project participants include the City of Bartow, the City of Blountstown, the City of Chattahoochee,
Gainesville Regional Utilities, City of Lakeland Electric & Water, the City of Mt. Dora, Orlando Utilities Commission,
the City of Quincy, the City of Wauchula, and the City of Williston.
1-8
Description of Existing Facilities
FMPA 2007 Ten-Year Site Plan
Section 2
2.1
Description of Existing Facilities
ARP Supply-side Resources
The ARP supply-side resources consist of a diversified mix of generation ownership, purchase
power, and fuel supply. The supply side resources for the ARP for the 2007 summer season are
shown by ownership capacity in Table 2- I
Table 2-1
ARP Supply-side Resources Summer 2007
Resource Category
1) Nuclear
Summer
Capacity
(MW)
85
2) ARP Ownership
Existing
New
565
Sub Total ARP Ownership
3) Member Ownership
Fort Pierce
KES
KUA
Lake Worth
Vero Beach
565
110
41
291
Sub Total Member Ownership
4) Purchase Power
470
lTotal2007 ARP Resources
1,786
I
The resource categories shown in Table 2-1 are described in more detail below.
1) Nuclear Generation: A number of the ARP members own small amounts of capacity
in Progress Energy Florida’s Crystal River Unit 3. Likewise, a number of ARP members
participate in the St. Lucie Project, which provides them capacity and energy from
St. Lucie Unit No. 2. Capacity from these two nuclear units is classified as “excluded
resources” in the ARP. As such, the ARP members pay their own costs associated with
the nuclear units and receive the benefits of the capacity and energy from these units.
2-1
FMPA 2007 Ten-Year Site Plan
Description of Existing Facilities
The ARP provides the balance of capacity and energy requirements for the members with
participation in these nuclear units. The nuclear units are considered in the capacity
planning for the ARP.
2) ARP Owned Generation: This category includes generation that is solely or jointly
owned by the ARP as well as ARP member participation. Such ARP ownership capacity
includes the Stanton Energy Center (including the Stanton, Tri-City, and Stanton I1
projects, as well as Stanton A), Indian River, Cane Island, and Stock Island units.
3) Member Owned Generation: Capacity included in this category is generation owned
by the ARP members either solely or jointly. The ARP purchases this capacity from the
ARP members and then commits and dispatches the generation to meet the total
requirements of the ARP.
4) Purchase Power Generation: This category includes power purchased directly by
the ARP as well as existing purchase power contracts of individual ARP members which
were entered into prior to the member joining the ARP. Purchase power generation
includes capacity and energy received from other suppliers such as Progress Energy
Florida (PEF), FPL, Lakeland Electric, Calpine, and Southern Company.
Information regarding existing ARP generating facilities as of December 3 1, 2006, can be found
in Schedule 1 at the end of this section.
2.2 ARP Transmission System
The Florida electric transmission grid is interconnected by high voltage transmission lines
ranging from 69 KV to 500 KV. Florida’s electric grid is tied to the rest of the continental
United States at the Florida/Georgia/Alabama interface. Florida Power and Light Co, (FPL),
Progress Energy Florida (PEF), JEA and the City of Tallahassee own the transmission tie lines at
the Florida/Georgia/Alabama interface. ARP members’ transmission lines are interconnected
with transmission facilities owned by FPL, PEF, Orlando Utilities Commission (OUC), JEA,
Seminole Electric Cooperative, Florida Keys Electric Cooperative Association (FKEC), and
Tampa Electric Co. (TECO).
Capacity and energy (C&E) resources for the ARP are transmitted to the ARP members utilizing
the transmission systems of FPL, PEF, TECO, and OUC. C&E resources for the Cities of
Jacksonville Beach, Green Cove Springs, Clewiston, Fort Pierce, Key West, Lake Worth, Starke
and Vero Beach are delivered by FPL’s transmission system. C&E resources for the Cities of
Ocala, Leesburg, Bushnell, Newberry, and Havana are delivered by the PEF transmission
system. C&E resources for KUA are delivered by the transmission systems of FPL, PEF and
0
a
a
a
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a
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e
0
e
e
e
e
a
1
c
0
a
a
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0
e
8
e
0
e
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2-2
I.
e
FMPA 2007 Ten-Year Site Plan
Description of Existing Facilities
OUC. C&E resources for the City of Fort Meade are delivered by the PEF and TECO
transmission systems.
2.2.1 Member Transmission Systems
Fort Pierce Utility Authority
Fort Pierce Utility Authority (FPUA) is a municipally owned utility operating electric, water,
wastewater, and natural gas utilities. The electric utility owns an internal, looped, 69kV
transmission system for system load and a 118 MW local power generating plant. There are two
interconnections with other utilities, both at 138 kV. The FPUA’s Hartman Substation
interconnects to FPL’s Midway and Emerson Substations. The second interconnection is from
the FPUA’s Garden City (#2) Substation to County Line Substation No. 20 by a 7.5 mile, single
circuit 138 kV.line. FPUA and the City of Vero Beach jointly own County Line Substation, the
138 kV line connecting to Emerson Substation, and some parts of the tie between the two cities.
Keys Energy Services
The Utility Board of the City of Key West (KEYS) owns and maintains an electric generation,
transmission, and distribution system, which supplies electric power and energy south of Florida
Keys electric Cooperative’s (FKEC) Marathon Substation to the City of Key West. KEYS and
FKEC jointly own a 64 mile long, 138 kV transmission tie line from FKEC’s Marathon
Substation that interconnects to FPL’s Florida City Substation at the Dade/Monroe County Line.
In addition, a second interconnection with FPL was completed in 1995, which consists of a
jointly owned 21 mile 138 kV tie line between the FKEC’s Tavernier and Florida City
Substations at the Dade/Monroe County line and is independently operated by FKEC. KEYS
owns a 49.2 mile long 138 kV radial transmission line from Marathon Substation to KEYS’
Stock Island Substation. Two autotransformers at the Stock Island Substation provide
transformation between 138 kV and 69 kV. KEYS has five 69 kV and four 138 kV substations
which supply power at 13.8 kV and 4.16 kV to its distribution system. KEYS owns
approximately 227 miles of 13.8 kV distribution line.
City of Lake Worth Utilities
The City of Lake Worth Utilities (LWU) owns and maintains an electric generation,
transmission, and distribution system, which supplies electric power and energy in and around
the City of Lake Worth. The total generating capability, located at the Tom G. Smith powergenerating plant is rated at approximately 87 MW. LWU has one 138 kV interconnection with
FPL at the LWU owned Hypoluxo Switching Station. A 3-mile radial 138 kV transmission line
connects the Hypoluxo Switching Station to LWU’s Main Plant Substation. In addition, a 2.4mile radial 138 kV transmission line connects the Main Plant Substation to LWU’s Canal
2-3
FMPA 2007 Ten-Year Site Plan
Description of Existing Facilities
Substation. Two 138/26 kV autotransformers are located at the Main Plant, and one 138/26 kV
autotransformer is located at Canal Substation. The utility owns an internal 26 kV subtransmission system to serve system load.
Kissimmee Utility A uthoritv
KUA owned generation and purchased capacity is delivered through 230 kV and 69 kV
transmission lines. KUA serves a total area of approximately 85 square miles. KUA’s 230 kV
and 69 kV transmission system includes interconnections with PEF, OUC, TECO and the City of
St. Cloud. KUA owns 24.6 circuit miles of 230 kV and 46.9 circuit miles of 69 kV transmission
lines. KUA and FMPA jointly own 21.6 circuit miles of 230 kV lines out of Cane Island Power
Park. Electric capacity and energy supplied from KUA owned generation and purchased
capacity is delivered through 230 kV and 69 kV transmission lines to nine distribution
substations. KUA has direct transmission interconnections with: (1) PEF at PEF’s 230 kV
Intercession City Substation, 69 kV Lake Bryan Substation, and 69 kV Meadow Wood South
Substation; (2) OUC at OUC’s 230 kV Taft Substation and TECO / OUC’s 230 kV Osceola
Substation from Cane Island Substation; and (3) the City of St. Cloud at KUA’s 69 kV Carl A.
Wall Substation.
City of Ocala Electric Utility
Ocala Electric Utility (OEU) owns its bulk power supply system which consists of three 230 kV
to 69 kV substations, 13 miles radial 230 kV and 48 miles 69 kV transmission loop and 18
distribution substations delivering power at 12.47 kV. The distribution system consists of 773
miles of overhead lines and 302 miles of underground lines.
OEU’s 230kV transmission system interconnects with PEF’s Silver Springs Switching Station
and Seminole Electric Cooperative, Inc.’s (SECI) Silver Springs North Switching Station. OEU’s
Dearmin Substation ties at PEF’s Silver Springs Switching Station and OEU’s Ergle Substation
ties at SECI’s Silver Springs North Switching Station. OEU also has a 69 kV tie from the Airport
Substation with Sumter Electric Cooperative’s Martel Substation. In addition, OEU owns a 13
mile radial 230 kV transmission line from Ergle Substation to Shaw Substation. OEU is planning
to add a second 230 kV tie by rerouting the existing Shaw to Ergle 230 kV line from Shaw
Substation to a direct radial connecting to SECI’s Silver Springs North Switching Station.
City of Vero Beach
The City of Vero Beach (CVB) has a municipally owned electric utility. The utility owns an
internal, looped, 69 kV transmission system for system load and a 155 MW local power
generating plant. CVB has two 138 kV interconnections with FPL and one with FPUA. CVB’s
2-4
FMPA 2007 Ten-Year Site Plan
Description of Existing Facilities
interconnection with FPL is at CVB’s West Substation No. 7 . CVB also has a second FPL
interconnection from County Line Substation No. 20. County Line Substation No. 20 is
connected by two separate, single circuit, 138 kV transmission lines to FPL’s Emerson 230/138
kV substation and FPUA’s Garden City (No. 2) Substation. CVB & FPUA jointly own County
Line Substation No. 20, the connecting lines to FPL’s Emerson Station, and some part of the tie
between the two municipal utilities.
2.2.2 ARP Transmission Agreements
OUC provides transmission service for delivery of power and energy from FMPA’s ownership in
Stanton Unit No. 1, Stanton Unit No. 2, Stanton A combined cycle (CC), and the Indian River
combustion turbine (CT) units to the FPL and PEF interconnections for subsequent delivery to
the ARP. Rates for such transmission wheeling service are based upon OUC’s costs of providing
such transmission wheeling service and under terms and conditions of the OUC-FMPA Firm
Transmission Service contracts for the ARP.
FMPA also has contracts with PEF and FPL to transmit the various ARP resources over the
transmission systems of each of these two utilities. The Network Service Agreement with FPL
was executed in March 1996 and was subsequently amended to both conform to FERC’s Pro
forma Tariff and to add additional members to the ARP. The FPL agreement provides for
network transmission service for the ARP member cities located in FPL’s service territory. To
provide transmission-wheeling service for ARP member cities located in PEF’s service territory,
FMPA operates under an existing agreement with PEF, which was executed in April 1985 and
provides for network type transmission services.
FMPA 2007 Ten-Year Site Plan
Description of Existing Facilities
Schedule 1
ARP Existing Generating Resources as of December 31,2006
ill
Plant Name
(21
I
iinr
,
\ '-1
Fue YPe
Primary
Alternate
Fuel Trai portation
Primary
Alternate
\/Ill
'SI
Commercial
In-Service
MMNY
Expected
Retirement
MMNY
Gen. Max
Nameplate
MW
(121
(131
Net C
iummer (MM
ibility
Winter (MW]
Unit No.
Location
Unit Type
3
2
Citrus
St. Lucie
NP
NP
UR
UR
TK
TK
03/77
08183
NA
NA
891
891
25
60
85
25
61
86
1
2
A
CT A
CT B
CT C
CT D
1
2
3
CT2
CT3
GT4
Orange
Orange
Orange
Brevard
Brevard
Brevard
Brevard
Osceola
Osceola
Osceola
Monroe
Monroe
Monroe
ST
ST
GT
GT
GT
BIT
BIT
NG
NG
NG
NG
NG
NG
NG
NG
DFO
DFO
DFO
RR
RR
PL
PL
PL
PL
PL
PL
PL
PL
WA
WA
WA
07/87
06/96
10103
06/89
07/89
08/92
10/92
01/95
06/95
01/02
06/99
06/99
06/06
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
465
465
671
41
41
112
112
40
122
280
21
21
61
102
101
21
14
14
22
22
17
54
123
15
15
45
565
103
101
23
18
18
26
26
15
60
125
18
18
45
596
Vero Beach
Municipal Plant
Municipal Plant
Municipal Plant
Municipal Plant
Municipal Plant
Sub Total Vero Beach
1
2
3
4
5
Indian River
Indian River
Indian River
Indian River
Indian River
ST
CA
ST
ST
CT
NG
NG
NG
NG
NG
11/61
08/64
09/71
08/76
12/92
NA
NA
NA
NA
NA
13
13
33
56
40
12
12
30
51
32
137
12
13
34
56
40
155
Fort Pierce Utilities Authority
H.D. King
H.D. King
H.D. King
H.D. King
H.D. King
H.D. King
Sub Total Fort Pierce
5
7
8
9
D1
D2
St. Lucie
St. Lucie
St. Lucie
St. Lucie
St. Lucie
St. Lucie
CA
ST
ST
CT
IC
IC
WH
NG
NG
NG
DFO
DFO
01/53
0 1164
05/76
05/90
04/70
04/70
05/08
05/08
05/08
05/08
05/08
05/08
8
32
50
23
3
3
8
24
50
23
3
3
110
8
32
50
23
3
3
118
uclear Capacity
Crystal River
St. Lucie
Total Nuclear Capacity
RP-Owned Generation
Stanton Energy Center
Stanton Energy Center
Stanton Energy Center
Indian River
Indian River
Indian River
Indian River
Cane Island
Cane Island
Cane Island
Stock Island
Stock Island
Stock Island
Total ARP-Owned Generation
cc
GT
GT
GT
GT
GT
cc
cc
DFO
DFO
DFO
DFO
DFO
DFO
DFO
DFO
TK
TK
TK
TK
TK
TK
TK
TK
lember-Owned Generation
RFO
RFO
RFO
RFO
RFO
PL
PL
PL
PL
PL
TK
TK
TK
TK
TK
RFO
RFO
DFO
PL
PL
PL
TK
TK
TK
TK
TK
~
~
~
~
~
~
~
~
~
~
~
~
~
~
~
w
w
~
w
~
Description of Existing Facilities
FMPA 2007 Ten-Year Site Plan
Schedule 1 (Continued)
ARP Existing Resources as of December 31,2006
!' I
Commercial
In-Sewice
MMNY
Expected
Retirement
MMNY
Gen. Max
Nameplate
MW
02/83
11/83
11/83
01/95
06/95
01/02
07/87
10103
06/89
06/89
12111
12/11
12111
NA
NA
NA
NA
NA
NA
NA
38
8
8
40
122
280
465
671
41
41
31
8
8
17
54
123
21
21
4
4
291
34
5
5
15
60
125
21
23
6
6
300
12/76
03/78
12/65
12/65
12/65
12/65
12/65
11/67
03/78
06/12
06/12
06/12
06/12
06/12
06/12
06112
06/12
06/12
31
20
2
2
2
2
2
27
10
26
20
2
2
2
2
2
22
31
22
2
2
2
2
2
24
11/76
01/65
01/65
01/65
06/91
06/91
NA
NA
NA
NA
NA
NA
20
2
2
2
9
9
41
43
)tal Member-Owned Generation
666
714
)tal Generation Resources
1,316
1,395
Plant Name
Kissimmee Utility Authority
Hansel Plant
Hansel Plant
Hansel Plant
Cane Island
Cane Island
Cane Island
Stanton Energy Center
Stanton Energy Center
Indian River
Indian River
Sub Total KUA
Lake Worth
Tom G. Smith
Tom G. Smith
Tom G. Smith
Tom G. Smith
Tom G. Smith
Tom G. Smith
Tom G. Smitk
Tom G. Smith
Tom G. Smith
Sub Total Lake Worth
Keys Energy Services
Stock Island
Stock Island HSD
Stock Island HSD
Stock Island HSD
Stock Island MSD
Stock Island MSD
Sub Total Keys
Fue Y Pe
Alternate
Primary
Unit No.
Location
Unit Type
21
22
23
1
2
3
1
A
CT A
CT B
Osceola
Osceola
Osceola
Osceola
Osceola
Osceola
Orange
Orange
Brevard
Brevard
CT
CA
CA
GT
cc
cc
GT
GT
NG
WH
WH
NG
NG
NG
BIT
NG
NG
NG
GT-I
GT-2
MU1
MU2
MU3
MU4
MU5
s-3
s-5
Palm Beach
Palm Beach
Palm Beach
Palm Beach
Palm Beach
Palm Beach
Palm Beach
Palm Beach
Palm Beach
GT
CT
IC
IC
IC
IC
IC
ST
CA
DFO
NG
DFO
DFO
DFO
DFO
DFO
NG
WH
CT1
IC1
IC2
IC3
MSDI
MSD2
Monroe
Monroe
Monroe
Monroe
Monroe
Monroe
GT
IC
IC
IC
IC
IC
DFO
DFO
DFO
DFO
DFO
DFO
ST
cc
Fuel Trai iortation
Primary
Alternate
DFO
PL
TK
DFO
DFO
DFO
PL
PL
PL
RR
PL
PL
PL
TK
TK
TK
DFO
DFO
DFO
TK
PL
TK
TK
TK
TK
TK
PL
DFO
RFO
WA
WA
WA
WA
WA
WA
2-7
TK
TK
TK
TK
TK
~
~
W
0
0
0
0
0
0
0
0
a
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0
0
0
e
0
0
0
0
e
0
0
e
0
0
0
0
0
0
e
0
Q
0
e
0
0
e
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0
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e
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a
__
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FMPA 2007 Ten-Year Site Plan
Forecast of Demand and Energy for the
All-Requirements Power Supply Project
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0
D
m
I)
0
0
0
0
I)
0
0
0
0
0
0
0
0
0
0
Section3 Forecast of Demand and Energy for the AllRequirementsPower Supply Project
3.1 Introduction
Under the ARP structure, FMPA agrees to meet all of the ARP members’ power
requirements. To secure sufficient capacity and energy, FMPA forecasts each ARP
member’s electrical power demand and energy requirements on an individual basis and
integrates the results into a forecast for the entire ARP. The following discussion
summarizes the load forecasting process and the results of the load forecast contained in
this Ten-Year Site Plan.
3.2 Load Forecast Process
FMPA prepares its load and energy forecast by month and summarizes the forecast
annually. The load and energy forecast includes projections of customers, demand, and
energy sales by rate classification for each of the ARP members. The forecast process
includes existing ARP member cities that FMPA currently supplies and ARP members
that FMPA is scheduled to begin supplying in the future. Forecasts are prepared on an
individual member basis and are then aggregated into projections of the total ARP
demand and energy requirements. Figure 3- 1 below identifies FMPA’s load forecast
process.
Figure 3-1
Load Forecast Process
8
0
0
0
0
0
I,
~.................
?:
$
VI
;
0
0
I,
NCP
omer Forecas
0
3)
3-1
.
A R P M em bers
FMPA Transmission
Pla n n in g
(I
Forecast of Demand and Energy for the
All-Requirements Power Supply Project
FMPA 2007 Ten-Year Site Plan
In addition to the Base Case load and energy forecast, FMPA has prepared high and low
case forecasts, which are intended to capture the majority of the uncertainty in certain
driving variables, for each of the ARP members. The high and low load forecast
scenarios are considered in FMPA’s resource planning process. In this way, power
supply plans are tested for their robustness under varying future load conditions.
3.3 2006 Load Forecast Overview
The load and energy forecast (Forecast) was prepared for a 20 year period, beginning
fiscal year 2006 through 2025. The Forecast was prepared on a monthly basis using
municipal utility data provided to FMPA by the ARP members and load data maintained
by FMPA. Historical and projected economic and demographic data were provided by
Economy.com, a nationally recognized provider of such data. The Forecast also relied on
information regarding local economic and demographic issues specific to each ARP
member. The Forecast reflects the City of Vero Beach Notice of Establishment of
Contract Rate of Delivery (CROD). The Forecast was performed assuming that Vero
Beach’s CROD becomes effective on January 1, 2010; however, the results of the
Forecast do not currently include the partial requirements load referred to in Section 1.2
of this document that may be served by FMPA beginning January 1,2010. The results of
the Base Case forecast are discussed in Section 3.6.1.
In addition to the Base Case forecast, FMPA has prepared high and low forecasts to
capture the uncertainty of weather. The methodology and results of the high (Severe) and
low (Mild) weather cases are discussed in Section 3.6.2.
3.4 Methodology
The forecast of peak demand and net energy for load to be supplied from the ARP relies
on an econometric forecast of each ARP member’s retail sales, combined with various
assumptions regarding loss, load, and coincidence factors, generally based on the recent
historical values for such factors, which are then summed across the ARP members.
Econometric forecasting makes use of regression to establish historical relationships
between energy consumption and various explanatory variables based on fundamental
economic theory and experience.
In this approach, the significance of historical relationships is evaluated using commonly
accepted statistical measures. Models that, in the view of the analyst, best explain the
historical variation of energy consumption are selected. The ability of a model to explain
historical variation is often referred to as “goodness-of-fit.” These historical relationships
are generally assumed to continue into the future, barring any specific information or
3-2
(I
a
0
0
0
0
a
0
0
0
a
(I
a
0
0
0
e
a
0
FMPA 2007 Ten-Year Site Plan
Forecast of Demand and Energy for the
All-Requirements Power Supply Project
assumptions to the contrary. The selected models are then populated with projections of
explanatory variables, resulting in projections of energy requirements.
Econometric forecasting can be a more reliable technique for long-term forecasting than
trend-based approaches and other techniques, because the approach results in an
explanation of variations in load rather than simply an extrapolation of history. As a
result of this approach, utilities are more likely to anticipate departures from historical
trends in energy consumption, given accurate projections of the driving variables. In
addition, understanding the underlying relationships which affect energy consumption
allows utilities to perform scenario and risk analyses, thereby improving decisions. The
Severe and Mild Cases are examples of this capability.
Forecasts of monthly sales were prepared by rate classification for each ARP member. In
some cases, rate classifications were combined to eliminate the effects of class migration
or redefinition. In this way, greater stability is provided in the historical period upon
which statistical relationships are based.
3.4.1 Model Specification
The following discussion summarizes the development of econometric models used to
forecast load, energy sales, and customer accounts on a monthly basis. This overview
will present a common basis upon which each classification of models was prepared.
For the residential class, the analysis of electric sales was separated into residential usage
per customer and the number of customers, the product of which is total residential sales.
This process is common for homogenous customer groups. The residential class models
typically reflect that energy sales are dependent on, or driven by: (i) the number of
residential customers, (ii) real personal income per household, (iii) real electricity prices,
and (iv) weather variables. The number of residential customers was projected on the
basis of the estimated historical relationship between the number of residential customers
of the ARP members and the number of households in each ARP member’s county.
The non-residential electricity sales models reflect that energy sales are best explained
by: (i) real retail sales, total personal income, or gross domestic product (GDP) as a
measure of economic activity and population in and around the member’s service
territory, (ii) the real price of electricity, and (iii) weather variables. For the majority of
models, total personal income was selected as the measure of economic activity, because
it performed better by certain statistical measures than other variables and is measured
historically with more accuracy at the local level. For the industrial class, GDP was more
3-3
FMPA 2007 Ten-Year Site Plan
Forecast of Demand and Energy for the
All-Requirements Power Supply Project
often the long-term driving variable, except in cases where the forecast was based on an
assumption to address a single, large customer (e.g., Clewiston and Key West).
Weather variables include heating and cooling degree days for the current month and for
the prior month. Lagged degree day variables are included to account for the typical
billing cycle offset from calendar data. In other words, sales that are billed in any
particular month are typically made up of electricity that was used during some portion of
the current month and of the prior month.
3.4.2 Projection of NEL and Peak Demand
The forecast of sales for each rate classification described above were summed to equal
the total retail sales of each ARP member. An assumed loss factor, typically based on a
5-year average of historical loss factors, was then applied to the total sales to derive
monthly NEL. To the extent historical loss factors were deemed anomalous, they were
excluded from these averages.
Projections of summer and winter non-coincident peak (NCP) demand were developed
by applying projected annual load factors to the forecasted net energy for load on a total
member system basis. The projected load factors were based on the average relationship
between annual NEL and the seasonal peak demand generally over the period 1996-2005
(i.e,, a 10-year average).
Monthly peak demand was based on the average relationship between each monthly peak
and the appropriate seasonal peak. This average relationship was computed after ranking
the historical demand data within the summer and winter seasons and reassigning peak
demands to each month based on the typical ranking of that month compared to the
seasonal peak. This process avoids distortion of the averages due to randomness as to the
months in which peak weather conditions occur within each season. For example, a
summer peak period can occur during July or August of any year. It is important that the
shape of the peak demands reflects that only one of those two months is the peak month
and that the other is typically some percentage less.
Projected coincident peak demands related to the total ARP, the ARP member groups,
and the transmission providers were derived from monthly coincidence factors averaged
generally over a 5-year period (200 1-2005). The historical coincidence factors are based
on historical coincident peak demand data that is maintained by FMPA. Similarly, the
timing of the total A W and ARP member group peaks was determined from an
appropriate summation of the hourly load data.
3-4
FMPA 2007 Ten-Year Site Plan
Forecast of Demand and Energy for the
All-Requirements Power Supply Project
3.5 Data Sources
3.5.1 Historical Member Retail Sales Data
Data was generally available and analyzed over January 1992, or the year a new member
joined the ARP, through the end of fiscal year 2005 (i.e., September 2005) (the Study
Period). Data included historical customers, sales, and revenues by rate classification for
each of the members. However, for a small part of the Study Period, only total revenues
were available.
3.5.2 Weather Data
Historical weather data was provided by the National Climatic Data Center (a division of
the National Oceanic and Atmospheric Administration) (NCDC), which was generally
used to supplement an existing weather database maintained by FMPA. Weather
stations, from which historical weather was obtained, were selected by their quality and
proximity to the ARP members. In most cases, the closest “first-order” weather station
was the best source of weather data. First-order weather stations (usually airports)
generally provide the highest quality and most reliable weather data. In three cases
(Beaches Energy Services, serving Jacksonville Beach, Fort Pierce, and Vero Beach),
however, weather data from a “cooperative” weather station, which was closer than the
closest first-order station, appeared to more accurately reflect the weather conditions that
affect the ARP members’ loads, based on statistical measures, than the closest first-order
weather station.
The influence on electricity sales of weather has been represented through the use of two
data series: heating and cooling degree days (HDD and CDD, respectively). Degree
days are derived by comparing the average daily temperature and a base temperature, 65
degrees Fahrenheit.
To the extent the average daily temperature exceeds 65
degrees Fahrenheit, the difference between that average temperature and the base is the
number of CDD for the day in question. Conversely, HDD result from average daily
temperatures which are below 65 degrees Fahrenheit. Heating and cooling degree days
are then summed over the period of interest, in this case, months. The majority of this
monthly data was obtained directly from the NCDC rather than calculated from daily
data.
Normal weather conditions have been assumed in the projected period. Thirty-year
normal monthly HDD and CDD are based on average weather conditions from 1971
through 2000, as reported by the NCDC.
3-5
Forecast of Demand and Energy for the
All-Requirements Power Supply Project
FMPA 2007 Ten-Year Site Plan
3.5.3 Economic Data
Economy.com, a nationally recognized provider of economic data, provided both
historical and projected economic and demographic data for each of the 16 counties in
which the Members’ service territories reside (the service territory of Beaches Energy
Services includes portions of both Duval and St. Johns Counties). These data included
county population, households, employment, personal income, retail sales, and gross
domestic product. Although all of the data was not necessarily used in each of the
forecast equations, each was examined for its potential to explain changes in the A W
members’ historical electric sales.
3.5.4 Real Electricity Price Data
The real price of electricity was derived from a twelve month moving average of real
average revenue. To the extent average revenue data specific to a certain rate
classification was unavailable, it was assumed to follow the trend of total average
revenue of the utility. Projected electricity prices were assumed to increase at the rate of
inflation. Consequently, the real price was projected to be essentially constant.
3.6 Overview of Results
3.6.1 Base Case Forecast
The results of the Forecast show that the Base Case 2007 forecast ARP winter peak
demand is 1,489 MW, forecast summer peak demand is 1,552 MW, and forecast annual
NEL is 7,668 GWh. The winter peak demand is projected to grow at an average annual
growth rate of 2.4 percent from 2007 through 2009, and then grow at an annual rate of
2.1 percent from 2010 through 2025. The summer peak demand is projected to grow at
an average annual growth rate of 2.3 percent from 2007 through 2009, and then grow at
an annual rate of 2.0 percent from 2010 through 2025. NEL is expected to grow at an
annual average growth rate of 2.3 percent from 2007 through 2009, and then grow at an
annual average rate of 2.0 percent from 2010 through 2025. Growth rates have been
shown separately for these periods to avoid distortion due to Vero Beach’s establishment
of CROD, effective January 1, 2010.
3.6.2 Weather-Related Uncertainty of the Forecast
While a forecast that is derived from projections of driving variables that are obtained
from reputable sources provides a sound basis for planning, there is significant
uncertainty in the fbture level of such variables. To the extent that economic,
demographic, weather, or other conditions occur that are different from those assumed or
provided, the actual member load can be expected to vary from the forecast. For various
3-6
FMPA 2007 Ten-Year Site Plan
Forecast of Demand and Energy for the
All-Requirements Power Supply Project
purposes, it is important to understand the amount by which the forecast can be in error
and the sources of error.
In addition to the Base Case forecast, which relies on normal weather conditions, FMPA
has developed high and low forecasts, referred to herein as the Severe and Mild weather
cases, intended to capture the volatility resulting from weather variations in the summer
and winter seasons equivalent to 90 percent of potential occurrences. Accordingly, load
variations due to weather should be outside the resulting “band” between the Mild and
Severe weather cases less than 1 out of 10 years. For this purpose, the summer and
winter seasons were assumed to encompass June through September and December
through February, respectively.
The potential weather variability was developed using weather data specific to each
weather station generally over the period 1971-2005. These weather scenarios
simultaneously reflect more and less severe weather conditions in both seasons, although
this is less likely to happen than severe conditions in one season or the other.
Accordingly, it should be recognized that annual NEL may be somewhat less volatile
than the annual NEL variation shown herein. Conversely, NEL in any particular month
may be more volatile than shown herein. Finally, because the forecast methodology
derives peak demand from NEL via constant load factor assumptions, annual summer and
winter peak demand are effectively assumed to have the same weather-related volatility
as annual NEL.
The weather scenarios result in bands of uncertainty around the Base Case that are
essentially constant through time, so that the projected growth rate is the same as the
Base Case. The differential between the Severe Case and Base Case is somewhat larger
than between the Mild Case and Base Case as a result of a somewhat non-linear response
of load to weather.
3.7 Load Forecast Schedules
Schedules 2.1 through 2.3 and 3.1 through 3.3 present the Base Case load forecast.
Schedules 3. l a through 3.3a present the high, or Severe weather case, and Schedules 3.1b
through 3.3b present the low, or Mild weather case. Schedule 4 presents the Base Case
monthly load forecast.
Forecast of Demand and Energy for the
All-Requirements Power Supply Project
FMPA 2007 Ten-Year Site Plan
Schedule 2.1
History and Forecast of Energy Consumption and Number of Customers by Customer Class
All-Requirements Project
(11
(2)
(3)
(4)
(7)
Rural and Resic ltial
Year [I]
PoDulation
Members
Per
Household
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
NA
NA
NA
NA
Average No.
Average kWh
Consumption
GWh
of Customers
per Customer
GWh
93,149
143,049
151,885
154,942
156,857
174,357
227,851
234,698
237,776
243,992
248,718
252,944
13,336
13,822
13,035
13,326
13,422
13,913
13,955
13,508
13,607
13,707
13,749
13,770
259,773
234,776
238,680
243,067
247,686
252,567
257,644
262,758
13,802
13,894
13,923
13,951
13,980
14,007
14,033
14,053
833
1,593
1,652
1,721
1,750
1,996
2,603
2,630
2,692
2,819
2,884
2,940
3,013
2,676
2,730
2,785
2,844
2,906
2,970
3,036
NA
NA
1,242
1,977
1,980
2,065
2,105
2,426
3,180
3,170
3,235
3,344
3,420
3,483
2009
NA
NA
3,585
2010
201 1
2012
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
3,262
3,323
3,391
3,463
3,538
3,616
3.693
2013
2014
2015
2016
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
[I] Amounts shown for 1997 through 2005 represent historical values. Amounts shown for 2006 through 2016 represent forecast values.
(8)
Commercial
Average No.
of Customers
(9)
Average kWh
Consumption
per Customer
16,710
26,001
27,774
28,456
29,015
32,415
42,132
42,914
44,405
44,968
45,533
46,074
49,829
61,276
59,465
60,480
60,298
61,589
61,791
61,274
60,614
62,696
63,348
63,810
47,188
42,112
42,614
43,123
43,649
44,193
44,754
45,332
63,849
63,538
64,053
64,578
65,149
65,753
66,373
66,962
Forecast of Demand and Energy for the
FMPA 2007 Ten-Year Site Plan
All-Requirements Power Supply Project
Schedule 2.2
History and Forecast of Energy Consumption and Number of Customers by Customer Class
All-Requirements Project
[I]
Amounts shown for 1997 through 2005 represent historical values. Amounts shown for 2006 through 2016 represent forecast values.
3-9
FMPA 2007 Ten-Year Site Plan
Forecast of Demand and Energy for the
All-Requirements Power Supply Project
Schedule 2.3
History and Forecast of Energy Consumption and Number of Customers by Customer Class
All-Requirements Project
(11
Sales for Resale
(3)
Utility Use & Losses
(4)
Net Energy for Load
Other Customers
(6)
Total No. of
GWh
GWh
GWh
(Average No.)
Customers
1997
0
152
2,850
0
110,803
1998
242
4,530
0
170,022
1999
0
0
271
4,657
0
180,690
2000
0
276
4,838
0
184,476
2001
0
0
0
0
0
246
4,877
0
186,977
301
5,532
0
207,904
414
7,008
0
271,I34
388
7,000
0
278,749
Year [I]
2002
2003
2004
2005
(5)
438
7,201
0
283,349
450
7,494
0
290,155
460
7,668
0
295,469
469
482
7,813
0
300,260
8,023
0
2010
0
0
0
0
0
444
7,342
0
308,224
278,173
2011
0
453
7,489
0
282,601
2012
0
462
7,645
0
287,518
2013
471
7,810
0
292,683
2014
0
0
482
7,984
298,128
2015
2016
0
0
492
503
8,164
8,344
0
0
0
2006
2007
2008
2009
[ I ] Amounts shown for 1997 through 2005 represent historical values. Amounts shown for 2006 through 2016 represent forecast values.
303,787
309,498
FMPA 2007 Ten-Year Site Plan
Forecast of Demand and Energy for the
All-Requirements Power Supply Project
Schedule 3.1
History and Forecast of Summer Peak Demand ( M W ) - Base Case
All-Requirements Project
[I]
Amounts shown for 1997 through 2005 represent historical values. Amounts shown for 2006 through 2016 represent forecast values.
Forecast of Demand and Energy for the
All-Requirements Power Supply Project
FMPA 2007 Ten-Year Site Plan
Schedule 3.2
History and Forecast of Winter Peak Demand (MW) - Base Case
All-Requirements Project
[I] Amounts shown for 1997 through 2005 represent historical values. Amounts shown for 2006 through 2016 represent forecast values.
r
r
r
r
r
~
~
~
~
~
~
~
~
~
~
~
~
~
Forecast of Demand and Energy for the
All-Requirements Power Supply Project
FMPA 2007 Ten-Year Site Plan
Schedule 3.3
History and Forecast of Annual Net Energy for Load (GWh) - Base Case
All-Requirements Project
(11
\
,
121
I
,
Year [I]
Total
1997
1998
1999
2000
2001
2002
2003
2,698
4,288
4,386
4,561
4,631
5,232
6,594
2004
2005
2006
2007
2008
2009
2010
201 1
2012
2013
2014
2015
2016
6,613
6,762
7,044
7,207
7,344
7,541
6,898
7,037
7,183
7,339
7,502
7,672
7.841
131
(41
(5)
Residential
Conservation
Commercial/
Industrial
Conservation
Retail
Wholesale
0
0
0
0
0
0
0
0
0
2,698
4,288
4,386
4,561
4,631
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
5,232
6,594
6,613
6,762
7,044
7,207
7,344
7,541
6,898
7,037
7,183
7,339
7,502
7,672
7,841
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
(7)
(8)
Utility Use
8 Losses
Net Energy
for Load
Load Factor %
152
242
271
276
246
30 1
414
388
438
450
460
469
482
444
453
462
471
482
492
503
2,850
4,530
4,657
4,838
4,877
5,532
7,008
7,000
7,201
7,494
7,668
7,813
8,023
7,342
7,489
7,645
7,810
7,984
8,164
8,344
51%
55%
54%
57%
55%
63%
54%
56%
54%
56%
56%
56%
56Yo
56%
56%
56%
56%
56%
56%
56%
[I] Amounts shown for 1997 through 2005 represent historical values. Amounts shown for 2006 through 2016 represent forecast values.
~
~
FMPA 2007 Ten-Year Site Plan
Forecast of Demand and Energy for the
All-Requirements Power Supply Project
Schedule 3.la
Forecast of Summer Peak Demand (MW) - High Case
All-Requirements Project tll
(1)
(3)
(4)
Residential
Load
Commercial/
Industrial Load
Management
Commercial/
Industrial Load
0
0
Year
Total
Wholesale
Retail
Interruptible
Management
Residential
Conservation
2007
2008
2009
1,618
1,649
1,694
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2010
201 1
2012
1,553
1,584
1,617
1,652
1,689
1,727
1,766
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2013
2014
2015
2016
0
0
[I] Values represent predicted summer peak demand under severe weather conditions.
Conservation
0
0
0
Net Firm
Demand
1,618
1,649
1,694
1,553
1,584
1,617
1,652
1,689
1,727
1.766
Forecast of Demand and Energy for the
All-Requirements Power Supply Project
FMPA 2007 Ten-Year Site Plan
Schedule 3.2a
Forecast of Winter Peak Demand ( M W )- High Case
All-Requirements Project [l]
Residential
Year
Total
Wholesale
2006107
2007108
2008109
2009110
2010111
2011112
1,553
1,582
1,628
1,462
1,491
1,523
2012113
2013114
1,556
1,590
1,627
1,663
201411 5
2015116
-
Commercial/
Commercial/
Residential
Conservation
Industrial Load
Management
Industrial Load
Conservation
Net Firm
Demand
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1,553
1,582
1,628
1,462
1,491
1,523
1,556
1,590
1,627
1,663
Load
Management
Retail
Interruptible
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
n
n
0
0
[I] Values represent predicted winter peak demand under severe weather conditions.
n
0
0
0
Forecast of Demand and Energy for the
All-Requirements Power Supply Project
FMPA 2007 Ten-Year Site Plan
Schedule 3.3a
Forecast of Annual Net Energy for Load (GWh) - High Case
All-Requirements Project 111
131
(4)
151
161
(71
181
\-I
191
Residential
Conservation
Commercial/
Industrial
Conservation
Retail
Wholesale
Utility Use
8 Losses
Net Energy
for Load
Load Factor %
7,512
7,654
7,859
7,195
7,338
7,491
7,652
0
474
483
496
457
466
475
485
496
507
517
7,986
8,137
8,355
7,651
7,804
7,966
8,137
8,318
8,505
8.692
56%
56%
56%
56%
56%
56%
56%
56%
56%
56%
\ - I
Year
Total
2007
2008
2009
2010
201 1
2012
2013
2014
7,512
7,654
0
0
0
0
7,859
7,195
7,338
7,491
0
0
0
2015
2016
7,652
7,822
7,999
8.175
0
0
0
0
0
0
0
0
0
0
0
0
0
[I] Values represent predicted net energy for load under severe weather conditions.
7,822
7,999
8.175
0
0
0
0
0
0
0
0
0
Forecast of Demand and Energy for the
All-Requirements Power Supply Project
FMPA 2007 Ten-Year Site Plan
Schedule 3.lb
Forecast of Summer Peak Demand (MW) - Low Case
All-Requirements Project 111
Residential
Year
Total
Wholesale
Retail
Interruptible
2007
2008
2009
2010
201 1
2012
2013
2014
2015
2016
1,502
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1,531
1,572
1,439
1,468
1,499
1,532
1,566
1,602
1.638
0
[l] Values represent predicted summer peak demand under mild weather conditions.
Commercial/
Commercial/
Load
Management
Residential
Conservation
Industrial Load
Management
Industrial Load
Conservation
Net Firm
Demand
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1,502
1,531
1,572
1,439
1,468
1,499
1,532
1,566
1,602
1.638
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
a,
2
W
3
s
I
w
0
Y
tn
m
v
a,
E
F4
-mIanl
~
f
a
U
0
0
0
0
0
0
0
0
0
0
FMPA 2007 Ten-Year Site Plan
Forecast of Demand and Energy for the
All-Requirements Power Supply Project
Schedule 3.3b
Forecast of Annual Net Energy for Load (GWh) - Low Case
All-Requirements Project 111
Commercial/
Year
Total
2007
2008
2009
2010
201 1
2012
2013
2014
2015
2016
6,971
7,103
7,292
6,668
6,802
6,944
7,094
7,253
7,417
7,581
Residential
Conservation
Industrial
Conservation
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Retail
Wholesale
Utility Use
8 Losses
Net Energy
for Load
Load Factor %
6,971
7,103
7,292
6,668
6,802
6,944
7,094
7,253
7,417
7,581
0
0
0
0
0
0
0
0
0
0
45 1
460
472
435
443
452
462
472
482
493
7,422
7,563
7,765
7,103
7,245
7,396
7,556
7,724
7,899
8,073
56%
56%
56%
56%
56%
56%
56%
56%
56%
56%
3-19
FMPA 2007 Ten-Year Site Plan
Forecast of Demand and Energy for the
All-Requirements Power Supply Project
Schedule 4
Previous Year and 2-Year Forecast of Peak Demand and Net Energy for Load by Month
All-Requirements Project
-
Foreca : 2007
Peak Demand
Peak Demand
NEL
January
(MW)
1,064
(GWh)
523
February
1,388
490
March
1,017
515
1,134
April
560
May
June
1,225
1,280
636
1,255
1,374
1,392
684
1,462
Month
Foreca
~
- 2008
NEL
Peak Demand
NEL
(MW)
(GWh)
(GWh)
1,489
599
(MW)
1,517
1,190
517
1,213
527
590
1,156
601
560
1,279
571
672
1,400
684
695
1,490
61 1
July
1,444
737
1,552
779
1,582
708
794
August
1,472
759
1,538
797
1,568
812
September
1,336
674
1,450
700
1,479
713
October
1,270
603
1,308
1,001
963
501
522
1,099
1,253
637
54 1
580
1,334
1,121
1,278
649
November
December
551
592
I
I)
D
FMPA 2007 Ten-Year Site Plan
Renewable Resources and Conservation Programs
I)
I,
B
*
I)
D
b
B
D
D
B
b
B
D
B
B
B
D
D
Y
D
B
b
#
D
D
B
D
D
b
D
B
b
b
b
D
b
D
b
Section 4 Renewable Resources and ConservationPrograms
4.1 Introduction
Renewable resources are considered resources that do not require the consumption of
additional fossil fuels in order to provide energy. Conservation resources are typically
those resources that reduce the amount of demand or energy being provided to the
customer. Both renewable resources and conservation programs are considered “Green
Resources”, or resources that include renewable resources and other significantly reduced
pollutant resources such as conservation programs.
FMPA provides renewable energy resources through dispatching renewable generation to
serve the ARP aggregate load requirements. FMPA offers services as needed to assist
members in increasing the promotion and use of conservation programs to customers and
will assist all of its members in the evaluation of any new programs to ensure their cost
effectiveness. As a wholesale supplier, FMPA does not directly provide demand side
programs to retail customers. The demand side programs are provided to the retail
customers by the ARP members.
FMPA is a member of the American Public Power Association’s Demonstration of
Energy-Efficient Developments (DEED) program. Through FMPA’s membership in this
program, all of FMPA’s members are also DEED members. DEED is a research and
development program funded by and for public power utilities. Established in 1980,
DEED encourages activities that promote energy innovation, improve efficiencies and
lower costs of energy to public power customers.
FMPA is also a member of a new group of Florida municipal utilities, called Florida
Municipal Efficiency Coalition (FMEC). This group was recently formed to explore new
options for efficiency programs that can result in greater energy conservation and savings
to customers. Other members of FMEC are GRU, JEA, Lakeland Electric, OUC,
Tallahassee, and Florida Municipal Electric Association. The utilities have agreed to
develop consistent data and share best practices as they evaluate demand-side
management programs to save energy that are specific to the state of Florida.
4- 1
FMPA 2007 Ten-Year Site Plan
Renewable Resources and Conservation Programs
4.2 Renewable Resources
FMPA and its members are reviewing Green Energy programs that may be a benefit to
their customers. Renewable sources include solar thermal, solar photovoltaic, wind
energy, and bioenergy.
FMPA receives power from two sources of renewable energy. FMPA receives power
from a cogeneration plant owned and operated by U.S. Sugar Corporation. Landfill gas
is received from the Orange County landfill which is used to supplement the fuel
requirements of Stanton Energy Center, which is partially owned by FMPA.
U.S. Sugar Cogeneration plant is a power plant fueled by sugar bagass. Bagass is a
biomass remaining after the sugar cane stalks have been crushed for their juice. U. S.
Sugar uses the bagass to fuel their generation plants to provide power for their processes.
FMPA purchases the excess unused power from these generators. During 2006, FMPA
purchased 3,876 MWh of energy from this renewable resource.
Orange County, Florida has a landfill located near the Stanton Energy Center, which is
jointly owned by OUC, FMPA, and KUA. Through its contract with OUC, the landfill
provides landfill gas as a supplemental fuel source to coal consumed by the Stanton
Energy Center. In 2006 the Stanton Energy Center consumed 769,843 MMbtu of landfill
gas.
FMPA’s forecast of renewable energy is provided in Schedule 6.1 of Section 5 (Forecast
of Facility Requirements).
4.3 Conservation Programs
The following is a combined list of conservation programs offered by or being reviewed
by FMPA members:
0
Energy Audits Program.
High-pressure Sodium Outdoor Lighting Conversion.
0
PURPA Time-of-Use Standard.
0
Energy [email protected] Program Participation.
0
Demand- Side Management (DSM).
0
Distributed Generation.
A brief description of each conservation program is provided in the following
subsections. The exact implementation varies somewhat from member to member and
not all programs are offered by all members.
0
4-2
FMPA 2007 Ten-Year Site Plan
Renewable Resources and Conservation Programs
4.3.1 Energy Audits Program
Energy audits are offered to residential, commercial, and industrial customers. The
program offers walk-through audits to identify energy savings opportunities. The audits
consist of a walk-through Home Energy Survey, with the following materials available
upon customer request:
0
0
Electric outlet gaskets.
Socket protectors.
0
Water flow restrictors.
Electric water heater jacket.
0
Low-flow shower heads.
0
Home Energy Surveys also include information on water heater temperature reduction
and the installation of the water heater insulating blanket upon customer request.
As a supplement to the Energy Audits program, some FMPA members offer online
energy surveys to their customers. These tools allow customers to enter specific
information on their homes and review specific measures that they can implement in their
homes to reduce energy consumption. FMPA also assists member cities with their Key
Accounts program, which is designed to build and maintain relationships between
members and their key customers. FMPA coordinates the relationship between
participating members and contractors to provide project-type services such as lighting
retrofits, HVAC upgrades, and energy management system services.
4.3.2 High-pressure Sodium Outdoor Lighting Conversion
This program involves eliminating mercury vapor street and yard lighting. The mercury
vapor fixtures are converted to high-pressure sodium fixtures whenever maintenance is
required.
4.3.3 PURPA Time-of-Use Standard
In order to assist members with complying with the Public Utilities Regulatory Policy
Act of 2005 (PURPA) Smart Metering standard, FMPA staff has initiated a work effort to
evaluate ARP members’ opportunities to provide time-based rates. Time-based meters
would allow utilities to provide time-of-use pricing, critical pricing, real time pricing and
provide credits for load interruptions.
The PURPA Smart Metering standard applies to any utility whose total sales of electric
energy, for purposes other than resale, exceeds 500 million kWh (FPUA, Beaches Energy
Services, Keys Energy Services, KUA, Ocala and Vero Beach). FMPA, however, will be
4-3
FMPA 2007 Ten-Year Site Plan
Renewable Resources and Conservation Programs
conducting this analysis for each ARP city. FMPA is continuing to promote energy
conservation with each of its member cities.
4.3.4 Energy [email protected]
FMPA has a partnership agreement with Energy [email protected], a government-backed program
helping businesses and individuals protect the environment and save energy through enduse products with superior energy efficiency characteristics. Partnering with Energy
[email protected] and working together through FMPA makes it convenient and cost-effective for
FMPA’s members to bring the benefits of energy efficiency to their hometown utility.
The Energy [email protected] program includes seasonal campaigns, each promoting different
conservation themes. Members are provided with promotional materials including
newsletter, posters, bill stuffers, and web banners to participate in the campaigns and
promote the conservation message to their customers.
4.3.5 Demand-Side Management
FMPA and its members are interested in demand-side initiatives that are of overall
benefit to the ARP, but they are not currently pursuing the implementation of specific
dispatchable DSM programs.
4.3.6 Distributed Generation
Distributed Generation (DG) involves the use of small generators with capacities
generally ranging between 10 and several thousand kilowatts spread throughout an
electric system. Because they are normally located at customer sites, and those
customers are generally demand customers, DG serves well as a vehicle for reducing
demands during peak periods.
At this point in time, there is no active DG program. However, if there are significant
advantages in DG technology or price, FMPA will review these possible benefits with
members as needed.
The risks associated with DG include fuel storage, maintainability, permitting, and
security. Control issues associated with DG include relinquishing customer control and
having remote startup and shutdown monitoring. Cost issues associated with DG include
high unit heat rates, high fuel costs, and redundant control equipment per location.
4-4
FMPA 2007 Ten-Year Site Plan
Forecast of Facilities Requirements
Section 5 Forecastof Facilities Requirements
5.1 ARP Planning Process
FMPA’s planning process involves evaluating new generating capacity, along with new
purchased power options and conservation measures that are planned and implemented
by the All-Requirements Project participants. The planning process has also included
periodic requests for proposals in an effort to consider all possible power options. FMPA
normally performs its generation expansion planning on a least-cost basis considering
both purchased-power options, as well as options on construction of generating capacity
and demand-side resources when cost effective. The generation expansion plan
optimizes the planned mix of possible supply-side resources by simulating their dispatch
for each year of the study period while considering variables including fixed and variable
resource costs, fuel costs, planned maintenance outages, terms of purchase contracts,
minimum reserve requirements, and options for future resources. FMPA currently plans
for an annual reserve level of approximately 18 percent of the summer peak. FMPA is
continually reviewing its options, seeking joint participation when feasible, and may
change the megawatts required, the year of installment, the type of generation, andor the
site at which generation is planned to be added as conditions change.
5.2 Planned ARP Generating Facility Requirements
FMPA is planning to add a 296 MW combined cycle unit at the Treasure Coast Energy
Center site in June 2008, 90 MW of combustion turbine capacity in 2010, an additional
296 MW combined cycle unit in 201 1, a 293 MW share of a jointly owned coal-fired unit
in June 2012, and an additional 90 MW of combustion turbine capacity in 2016. These
resources are described in additional detail below.
Treasure Coast Enerqv Center ITCEC): FMPA is constructing a 296 MW
combined cycle unit at the Treasure Coast Energy Center site near Fort Pierce.
FMPA received site certification in June 2006, and physical construction began on
TCEC Unit 1 in August 2006. Construction is on schedule, and the scheduled inservice date for TCEC Unit 1 is June 2008.
2010 PeakinCr Units: FMPA is currently planning to construct 90 MW of
combustion turbine (GT) peaking capacity with a planned in-service date of
summer 2010. FMPA anticipates that these LM6000 simple cycle GT units could
be installed at an ARP member owned generation site, most likely at the Tom G.
5- 1
FMPA 2007 Ten-Year Site Plan
Forecast of Facilities Requirements
Smith Power Plant site at Lake Worth, the Cane Island Power Park site at the
Kissimmee Utility Authority (KUA), or at FMPA’s TCEC site.
0
0
0
Cane Island Combined Cycle: FMPA is currently planning to construct a 296
MW combined cycle unit at the Cane Island Power Park site at KUA. The
scheduled in-service date for Cane Island Unit 4 is summer 201 1.
Taylor Enerqv Center (TEC): FMPA is currently participating with JEA, the
City of Tallahassee, and Reedy Creek Improvement District in the development of
the Taylor Energy Center, a 754 MW supercritical coal unit to be located
approximately 5 miles southeast of Perry, in Taylor County, Florida. The primary
advantage of this publicly-owned, coal-fired project would be to diversifL
resources, while supplying competitively priced power into the future. The TEC
“Need for Power” application (Need Determination) was submitted to the PSC in
September 2006. Hearings on the Need Determination have been held, and a
decision is expected from the PSC in spring 2007. TEC Unit 1 is scheduled to
begin commercial operation in May 2012.
2016 Peakinn Units: FMPA is currently planning to construct an additional 90
MW of GT peaking capacity with a planned in-service date of summer 2016.
These units are similar to the 201 0 Peaking Units described above.
FMPA issued a Request for Power Supply Proposals (Power Supply RFP) in November
2006. The purpose of the Power Supply RFP is to determine whether a sufficient and
cost-effective source of capacity and energy can be obtained as a replacement for the GT
units and Cane Island Unit 4 combined cycle facility that are planned for commercial
operation in 2010 and 201 1, respectively. Based on the outcome of this decision, FMPA
will determine whether to delay the in-service dates for these units.
Schedule 8 at the end of this section shows the planned and prospective ARP generating
resources additions and changes.
5.3 Capacity and Purchase Power Requirements
The current system firm power supply purchase resources of ARP include purchases from
PEF, FPL, Lakeland Electric, Calpine, and the Southern Company-Florida Stanton A
capacity that is purchased power. Additionally, FMPA is planning a peaking power
purchase from Southem Company’s Oleander plant beginning in December 2007 and a
capacity purchase from one or more suppliers for the summer of 2007. The existing and
future power purchase contracts are briefly summarized below:
5-2
FMPA 2007 Ten-Year Site Plan
Forecast of Facilities Requirements
PEF: FMPA has a power contract with PEF for Partial Requirements
(PR) Services. FMPA expects to take 30 MW in 2007 and 2008, 40 MW
in 2009, and 90 MW in 201 0. The PR capacity also includes reserves.
FPL: FMPA has two contracts with FPL, including a short-term 75 MW
purchase through 2007 and a long-term 45 MW purchase until June 2013.
The FPL short and long-term purchases include reserves.
Lakeland Electric: FMPA has a 100 MW contract with Lakeland
Electric. This contract originally extended through 2010, but it has been
renegotiated so that the capacity will be replaced with FMPA resources in
December 2007.
Calpine: FMPA has a contract with Calpine that provides 100 MW from
2007 until the contract expires in 2009.
Southern Companv-Florida: FMPA has a contract for 80MW of
purchase power including KUA’s share from Stanton A that extends to
2013 for the initial term and has various extension options.
Southern Company: FMPA has a contract to purchase 175 MW of
new peaking power from Southern Company’s Oleander plant beginning
in December 2007. The purchase will have a term of 20 years.
Seasonal Peakinq Purchase: FMPA is in the final stages of
negotiations for the purchase of 40 MW of capacity from various suppliers
for the summer of 2007.
5.4 Summary of Current and Future ARP Resource Capacity
Tables 5-1 and 5-2 provide a summary, ten-year projection of the ARP resource capacity
for the summer and winter seasons, respectively. A projection of the ARP fuel
requirements by fuel type is shown in Schedule 5. Schedules 6.1 (quantity) and 6.2
(percent of total) present the forecast of ARP energy sources by resource type. Schedules
7.1 and 7.2 summarize the capacity, demand, and resulting reserve margin forecasts for
the summer and winter seasons, respectively. Information on planned and prospective
ARP generating facility additions and changes is located in Schedule 8.
5-3
Forecast of Facilities Requirements
FMPA 2007 Ten-Year Site Plan
Table 5-1
Summary of All-Requirements Project Resource Summer Capacity
.ine
uo_
Resource Description
(a)
Summer I
2016
2012
2013
2014
2015
2008
2009
mq7T 2007
(k)
(h)
(i)
(1)
(9)
(d)
(C)
(b)
istalled Capacity
Existing Resources
1
Excluded Resources (Nuclear)
2
Stanton Coal Plant
(e)
85
85
85
74
224
224
224
186
I
78
78
78
78
78
78
186
186
186
186
186
186
3
Stanton CC Unit A
42
42
42
42
42
42
42
42
42
42
4
Cane Island 1-3
386
386
386
386
386
386
386
386
386
386
5
Indian River CTs
82
82
82
82
82
82
82
82
82
82
6
Key West Units 2&3
31
31
31
31
31
31
31
31
31
31
7
Key West Unit 4
45
45
45
45
45
45
45
45
45
45
8
Ft. Pierce Native Generation
110
9
Key West Native Generation
41
41
41
41
41
41
41
41
41
41
10
Kissimmee Native Generation
48
48
48
48
48
87
87
11
Lake Worth Native Generation
87
87
87
12
Vero Beach Native Generabon
137
137
137
1,316
1,207
1,207
1,021
1,025
891
891
891
891
891
296
296
296
296
296
296
296
296
296
293
293
293
293
293
90
90
90
90
13
Sub Total Existing Resources
--
---
--
Planned Additions
14
15
16
Treasure Coast Energy Center
Taylor Energy Center
New Peaking Capacity
17
New Baseilntermediate Capacity
18
Sub Total Planned Additions
19
90
Total Installed Capacity
9c
- 296 296 296
296 -
1,316
296
296
-
1,503
1,503
386
682
975
975
1,407
1,707
1,866
1,866
80
8C
8C
80
296
180
296
-
1,065
975 975 1,866
1,866
1,956
irm Capacity Import
Firm Capacity Import Without Reserves
20
Lakeland Purchase
100
21
Calpine Purchase
100
100
100
22
Stanton A Purchase
80
80
80
23
Peaking Purchase(s)
40
24
Southern Company Purchase
25
Sub Total Without Reserves
-
175 175
-
175
175
320
355
355
255
30
40
90
255
175
175
175
175
175
255
255
175
175
175
255
175
Firm Capacity Import With Reserves
26
PEF Partial Requirements
30
27
FPL Partial Requirements
75
28
FPL Long-Term Partial Requirements
29
Sub Total With Reserves
30
Total Firm Capacity Import
4E
45
45 45 45 -45
4E
45 75 150
85
135
470
430
440
390
30t
30C
irm Capacity Export
31
Vero Beach CROD Sale
(35)
(3i
32
Total Firm Capacity Export
(35)
(3!
1,762
1,97;
33
otal Available Capacity
5-4
3(3E (3E
(35
(35
(35
2,131
2,086
2,006
---
--
---
I
D
FMPA 2007 Ten-Year Site Plan
Line
No.
Forecast of Facilities Requirements
Table 5-2
Summary of All-Requirements Project Resource Winter Capacity
Resource Description
(ai
2007
-
(b)
(4
2008
2009
2010
id)
(e)
- ng(MWj
2011
19
2012
(9)
2014
2015
2013
(0
(h)
0)
nstalled Capacity
Existing Resources
1
Excluded Resources (Nuclear)
2
Stanton Coal Plant
8f
87
87
75
75
79
79
79
79
22r
224
224
186
186
186
186
186
186
4
79
186
3
Stanton CC Unit A
4t
4€
4E
46
46
46
46
46
46
46
4
Cane Island 1-3
40(
40C
40C
400
400
400
400
400
400
400
100
5
Indian River CTs
9:
1oc
1oc
100
100
100
100
100
100
6
Key West Units 283
3c
3€
3E
36
36
36
36
36
36
36
7
Key West Unit 4
4!
4:
45
45
45
45
45
45
45
45
8
Ft. Pierce Native Generation
lit
11E
9
Key West Natrve Generation
4:
4:
43
43
43
43
43
43
43
43
10
Kissimmee Native Generation
4:
4E
45
45
45
97
97
11
Lake Worth Native Generation
9i
97
97
12
Vero Beach Native Generation
155
155
155
1.39:
1,39€
1,278
1,073
1,073
1,032
935
935
935
935
318
318
318
318
318
318
318
318
305
305
305
305
90
90
90
90
318
318
318
318
13
Sub Total Existing Resources
97
-----
Planned Addieons
14
Treasure Coast Energy Center
15
Tayior Energy Center
16
New Peaking Capacity
17
New Baseilntermediate Capacity
18
19
90
318
318
408
-
726
1,031
1,031
1,031
-
1,031
1,396
1,596
1,391
1,481
1,758
1,967
1,967
1,967
1,967
80
80
80
80
Sub Total Planned Additions
Total Installed Capacity
1,395
90
318
-
irm Capacity Import
Firm Capacity Import Without Reserves
20
Lakeland Purchase
1oc
21
Caipine Purchase
100
100
100
22
Stanton A Purchase
80
80
80
23
Peaking Purchase(s)
24
Southern Company Purchase
195
195
195
195
195
195
195
195
195
25
Sub Total Without Reserves
280
375
375
275
275
275
275
195
195
195
30
40
90
Firm Capacity Import With Reserves
26
PEF Partial Requirements
30
27
FPL Partial Requirements
75
28
FPL Long-Term Partial Requirements
45
29
Sub Total With Reserves
150
30
Total Firm Capacity Import
430
45
45 - - 45 45
85 135
45 45 - - 75 45 45
45
450
460
410
320
320
320
195
195
195
irm Capacity Export
31
Vero Beach CROD Saie
-
32
Total Firm Capacity Export
---- -----
33
otal Available Capacity
- - (35 (35 (35 (35 (35 (35: (351
(35
(35
(35
(35
(351
(351
(35
- --1,825
1,846
2,056
1,766
2,043
2,252
2,127
2,127
2,127
1,766
-
5-5
Forecast of Facilities Requirements
FMPA 2006 Ten-Year Site Plan
Schedule 5
Fuel Requirements - All-Requirements Project
Unit
Type
.ine
1
(4)
Actual
Units
Fuel
1
Nuclear [I]
Trillion BTU
2
Coal
000 Ton
Steam
X
000 BBL
000 BBL
,T
Total
000 BBL
000 BBL
Steam
000 BBL
cc
000 BBL
CT
000 BBL
Fore
2008
2007
2006
;ted
2016
2015
2012
201 1
2010
2009
7
7
8
8
6
7
7
7
7
7
1
548
590
566
624
517
513
921
1,229
1,238
1,248
1,26:
0
0
0
0
0
G
0
0
80
8i
92
95
~~
41
63
75
75
80
8i
92
95
112
118
12
103
112
118
12
25,84
103
Total
000 BBL
41
63
Steam
000 MCF
412
86
60
9
0
0
0
18,534
27,485
30,463
27,810
31,472
217
263
27,858
202
26,772
29 1
27,508
32C
32,215
379
212
26:
28,060
27,063
27,720
26,IO.
221
210
199
18
C
;
T;
Total
000 MCF
000 MCF
000 MCF
Billion BTU
Trillion BTU
14,313
105
367
584
14,829
18,987
28,130
30,688
28,131
32,594
31,736
237
283
309
335
264
248
232
0
0
0
C
0
0
- --
0
O I
[I] Nuclear generation is not part of the All-Requirements Project power supply. It is owned directly by some Project participants.
[2] Includes landfill gas consumed by FMPA's ownership share of the Stanton Energy Center as a supplemental fuel source, as well as bagass consumed by U S . Sugar
cogeneration facility in the production of power purchased by FMPA.
5-6
I
--
~
w
w
w
~
w
~
~
~ w~
w
~
w~ w w ~
w
~
w ~ ~ w~
Forecast of Facilities Requirements
FMPA 2006 Ten-Year Site Plan
Schedule 6.1
Energy Sources (GWh) - All-Requirements Project
-
(3)
Line
Prime
No.
-
(4)
Actual
Units
2006
Fore sted
2008
2007
2009
2010
2011
2012
2015
2014
2013
2016
\nnual Firm Inter-
1
Region Interchange
GWh
2
W e a r [l]
GWh
684
678
706
720
594
648
657
3
:oal
GWh
1,450
1,561
1,482
1,619
1,343
1,333
2,450
0
0
0
0
0
0
648
625
678
627
3,302
3,323
3,348
3,372
48
55
55
60
60
64
64
3,614
21
3,634
3,385
26
3,410
lesidual
4
5
6
7
team
GWh
C
GWh
T
GWh
otal
GWh
team
GWh
C
GWh
T
GWh
otal
GWh
team
GWh
C
GWh
T
GWh
otal
GWh
)istillate
8
9
10
11
19
19
26
26
32
32
35
35
39
39
41
43
48
25
1.892
10
1,927
6
2,429
33
2,468
4
3,670
53
3,728
0
4,078
20
4,098
3,736
31
3,767
4,288
37
4,325
4,147
26
4,172
3,645
20
3,665
3,509
28
3,537
Jatural Gas
12
13
14
15
16
JUG
GWh
17
iydro
GWh
18
lenewables [2]
GWh
24
29
31
34
27
25
23
22
21
20
19
19
iterchange
GWh
3,100
3,003
1,933
1,617
1.742
1,289
478
304
605
61 1
1,043
20
let Energy for Load
GWh
7,204
7,764
7,912
8,123
7.51 1
7.662
7,824
7,990
8,166
8,352
8,535
-
[l] Nuclear generation is not part of the All-Requirements Project power supply. It is owned directly by some Project participants
[2] Includes power purchased from U S . Sugar cogeneration facility and power generated from FMPAs ownership share of the Stanton Energy Center using landfill gas.
5-7
Forecast of Facilities Requirements
FMPA 2006 Ten-Year Site Plan
Schedule 6.2
Energy Sources ( O h ) - All-Requirements Project
(2)
Line
(3)
(4)
Actual
Units
2006
Prime
Mover
Fore sted
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
Annual Firm Inter-
1
Region Interchange
2
Nuclear [ l ]
3
Coal
YO
YO
9.5
8.7
8.9
8.9
7.9
8.5
8.4
8.1
7.7
8.1
7.3
%
20.1
20.1
18.7
19.9
17.9
17.4
31.3
41.3
40.7
40.1
39.5
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.5
0.5
0.5
0.5
0.5
0.5
0.6
0.6
0.7
0.7
0.7
0.7
0.7
0.7
53.0
45.6
43.0
43.3
39.7
Residual
4
iteam
%
5
:C
%
6
7
:i
YO
otal
%
8
#team
%
9
:C
%
10
11
:T
otal
%
%
12
#team
13
14
:C
%
%
:T
15
otal
Distillate
0.3
0.3
0.3
0.3
0.4
0.4
0.4
0.4
0.1
46.4
0.0
50.2
0.2
49.7
0.4
56.0
0.7
Natural Gas
0.3
0.1
%
26.3
0.1
31.3
0.4
0.5
0.3
0.2
0.3
0.2
0.3
%
26.7
31 .a
47.1
50.5
50.2
56.4
53.3
45.9
43.3
43.5
40.0
16 NUG
%
17 Hydro
YO
18 Renewables [2]
%
0.3
0.4
0.4
0.4
0.4
0.3
0.3
0.3
0.3
0.2
0.2
19 Interchange
Yo
43.0
38.7
24.4
19.9
23.2
16.8
6.1
3.8
7.4
7.3
12.2
20
%
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
Net Energy for Load
-
-
[ I ] Nuclear generation is not part of the All-Requirements Project power supply. It is owned directly by some Project participants.
[2] Includes power purchased from US. Sugar cogeneration facility and power generated from FMPA's ownership share of the Stanton Energy Center using landfill gas.
Forecast of Facilities Requirements
FMPA 2006 Ten-Year Site Plan
Schedule 7.1
Forecast of Capacity, Demand, and Scheduled Maintenance at Time of Summer Peak
All-Requirements Project
Year
Installed
Capacity
(MW) [l]
Capacity
Import
(MW)
Capacity
Export
(MW)
1
Mainte
(&
(MW)
(MW) [2]
(MW)
I
Scheduled
Peak)
(MW)
I
Maintenance 3
;y;of
(MW)
Peak)
2007
1,316
470
1,786
1,573
213
15%
0
213
15%
2008
1,503
430
1,933
1,603
329
22%
0
329
22%
2009
1,503
440
1,943
1,646
296
19%
0
296
19%
2010
1,407
390
1,762
1,506
256
19%
0
256
19%
201 1
1,707
300
1,972
1,548
424
28%
0
424
28%
2012
1,866
300
2,131
1,581
551
36%
0
551
36%
2013
1,866
255
2,086
1,615
471
29%
0
471
29%
2014
1,866
175
2,006
1,651
355
22%
0
355
22%
201 5
1,866
175
2,006
1,689
318
19%
0
318
19%
2016
1.956
175
2,096
1,726
370
21%
370
2 1o/o
[l] See Table 5-1 for a listing of the resources identified as Installed Capacity and Firm Capacity Import.
[2] System Firm Summer Peak Demand includes transmission losses for the members served through FPL, PEF (beginning in 201 l), and KUA.
[3] Reserve Margin calcuated as [(Total Available Capacity - Partial Requirements Purchases) - (System Firm Peak Demand - Partial
Requirements Purchases)] I (System Firm Peak Demand - Partial Requirements Purchases). See Appendix HI to this Ten-Year Site
Plan for the calculation of reserve margins.
5-9
0
Forecast of Facilities Requirements
FMPA 2006 Ten-Year Site Plan
Schedule 7.2
Forecast of Capacity, Demand, and Scheduled Maintenance at Time of Winter Peak
All-Requirements Project
2006107
1,395
430
oi
2007108
1,396
450
0
2008109
1,596
460
0
2009110
1,391
410
(35)
2010111
1,481
320
2011112
1,758
320
2012/13
1,967
320
2013114
1,967
195
2014115
1,967
195
2015116
1,967
195
Year
Installed
Capacity
(MW) [I]
Capacity
Import
(MW) [l]
Capacity
Export
(MW)
\
Available
Capacity
I
System Firm
Winter Peak
Demand
(MW) [2]
(i:)
0
0
Peak)
Scheduled
Maintenance
(MW)
0
(%of
Peak)
1,825
1,509
316
23%
0
316
23%
0
1,846
1,538
309
21%
0
309
21%
0
2,056
1,581
475
32%
0
475
32%
0
1,766
1,419
347
27%
0
347
27%
1,766
1,456
310
22%
0
310
22%
2,043
1,487
556
39%
0
556
39%
2,252
1,519
732
50%
0
732
50%
2,127
1,553
574
37%
0
574
37%
(35)
2,127
1,589
538
34%
0
538
34%
(35)
2,127
1.625
502
31%
0
502
31%
;
[I] See Table 5-2 for a listing of the resources identified as Installed Capacity and Firm Capacity Import.
[2] System Firm Winter Peak Demand includes transmission losses for the members served through FPL, PEF (beginning in 201 l), and KUA.
[3] Reserve Margin calcuated as [(Total Available Capacity - Partial Requirements Purchases) - (System Firm Peak Demand - Partial
Requirements Purchases)] 1(System Firm Peak Demand - Partial Requirements Purchases). See Appendix 111 to this Ten-Year Site
Plan for the calculation of reserve margins.
1
Maintei nce;20f
Forecast of Facilities Requirements
FMPA 2006 Ten-Year Site Plan
Schedule 8
Planned and Prospective Generating Facility Additions and Changes
Plant Name
Unit
No.
Alt.
Fuel
Days
Use
Location
(County)
Commercial
Indewice
MMW
Expected
Retirement
MMW
Gen. Max.
Nameplate
kW
06/08
06/10
06110
NA
NA
NA
NA
NA
NA
06111
05/12
NA
NA
NA
NA
06116
06/16
NA
NA
NA
NA
8
32
esource Additions
Treasure Coast Energy Center
Unit 1
St. Lucie
PL
TK
NA
Unsited Combustion Turbine
CTI
Unknown
PL
TK
NA
Unsited Combustion Turbine
CT2
Unknown
PL
TK
NA
Cane Island
cc4
Osceola
PL
NA
Taylor Energy Center
Unit 1
Taylor
NA
Unsited Combustion Turbine
CT3
Unknown
TK
NA
Unsited Combustion Turbine
CT4
Unknown
RR
PL
PL
TK
NA
5
7
St. Lucie
St. Lucie
PL
TK
NA
01/53
01/64
05/08
H.D. King
H.D. King
8
St. Lucie
PL
TK
NA
05/76
05/08
H.D. King
9
St. Lucie
PL
TK
NA
05/90
05/08
H.D. King
D1
D2
21
St. Lucie
TK
NA
04/70
05/08
St. Lucie
TK
NA
04170
05/08
Osceola
PL
NA
22
Osceola
Osceola
02/83
11/83
11/83
12/76
03/78
12/65
12/65
12/65
12/65
12/65
12/11
12/11
12/11
06112
06/12
06/12
06/12
06/12
06/12
06/12
06112
06/12
hanges to Existing Resources
H.D. King
H.D. King
Hansel Plant
Hansel Plant
Hansel Plant
NA
TK
NA
NA
Tom G. Smith
23
GT-1
Palm Beach
Tom G. Smith
GT-2
Palm Beach
PL
Tom G. Smith
MU1
Palm Beach
TK
NA
Tom G. Smith
MU2
Palm Beach
TK
NA
Tom G. Smith
MU3
Palm Beach
TK
NA
Tom G. Smith
MU4
Palm Beach
TK
NA
Tom G. Smith
MU5
Palm Beach
TK
NA
Tom G. Smith
s-3
s-5
Palm Beach
PL
Tom G. Smith
TK
NA
TK
TK
NA
NA
NA
Palm Beach
5-11
11/67
03/78
05/08
50
23
3
3
38
0
8
31
20
2
2
2
2
2
27
10
FMPA 2007 Ten-Year Site Plan
Site and Facility Descriptions
Section 6 Site and Facility Descriptions
Florida Public Service Commission Rule 25-22.072 F.A.C. requires that the State of
Florida Public Service Commission Electric Utility Ten-Year Site Plan Information and
Data Requirements Form PSC/EAG 43 dated 11/97 govern the submittal of information
regarding Potential and Identified Preferred sites. Ownership or control is required for
sites to be Potential or Identified Preferred. The following are Potential and Identified
Preferred sites for FMPA as specified by PSC/EAG 43.
0
Treasure Coast Energy Center - Identified Preferred Site for Treasure Coast
Energy Center Unit 1 and Potential Site for additional future generation
Taylor Energy Center - Identified Preferred Site for Taylor Energy Center
Unit 1 and Potential Site for additional future generation
Cane Island - Identified Preferred Site for Cane Island Unit 4 and Potential
Site for additional future generation
0
Tom G. Smith - Potential Site
0
Stock Island - Potential Site
FMPA anticipates that the LM6000 simple cycle combustion turbines could be installed
at an ARP member owned generation site, most likely at the Tom G. Smith Power Plant
site at Lake Worth, the Cane Island Power Park site at KUA, or at FMPA’s Treasure
Coast Energy Center site. FMPA anticipates that combined cycle generation could be
installed at an existing ARP site, either at Cane Island or at the Treasure Coast Energy
Center. Additional coal generation could be located at the Taylor Energy Center site or
in joint ownership at another utility’s site. FMPA continuously explores the feasibility of
other sites located within Florida with the expectation that member cities would provide
the best option for future development.
Treasure Coast Eneray Center
FMPA is currently constructing a new 296 MW, 1x1 7FA combined cycle facility at the
Treasure Coast Energy Center site. The Treasure Coast Energy Center will be located in
St. Lucie County near the City of Fort Pierce. The site was certified in June 2006 and can
accommodate construction of future units beyond TCEC Unit 1, up to a total of 1,200
MW. Physical construction of TCEC Unit 1 commenced in August 2006, and
commercial operation is scheduled for June 2008.
Site and Facility Descriptions
FMPA 2007 Ten-Year Site Plan
Cane Island Power Park
FMPA is currently planning to construct a new 296 MW, 1x1 7FA combined cycle
facility at the Cane Island Power Park. FMPA has received alternative power supply
proposals which are currently being evaluated. Decisions are forthcoming on accepting
the alternative proposals and submitting the Need Determination request.
Cane Island Power Park is located south and west of KUA’s service area and contains
380 MW (summer) of gas turbine and combined cycle capacity. The Cane Island Power
Park currently consists of a simple cycle gas turbine and two combined cycle generating
units, each of which is 50 percent owned by FMPA and 50 percent owned by KUA.
Tom G. Smith Power Plant (Lake Worth1
The Tom G. Smith Power Plant is located in the City of Lake Worth’s service area in
Palm Beach County and currently consists of 88 MW of steam, combined cycle, and
reciprocating engine generation. The site is suitable for possible future repowering or
addition of new combustion turbines or combined cycle capacity.
Stock Island
The Stock Island site currently consists of five diesel generating units, as well as four
combustion turbines. The site receives water from the Florida Keys Aqueduct Authority
via a pipeline from the mainland, and also uses on-site groundwater. The site receives
delivery of fuel oil to its unloading system through waterborne delivery, and also has the
capability of receiving fuel oil deliveries via truck. The site has no adverse impact on
surrounding wetlands, threatened or endangered animal species, or any designated natural
resources.
Taylor Eneray Center
The TEC is being proposed as a joint development project by four municipal utilities,
including the FMPA, JEA, RCID, and the City of Tallahassee (The Participants). FMPA
is a wholesale supplier to 15 city-owned electric utilities throughout Florida. JEA is a
retail supplier in Jacksonville, Florida, and in parts of three adjacent counties. RCID is a
retail supplier in parts of Orange and Osceola counties. Tallahassee is the principal retail
supplier in Tallahassee, Florida.
The Participants are developing the proposed TEC to realize the benefits associated with
the economies of scale inherent in constructing and operating a large power plant. Table
6-2
FMPA 2007 Ten-Year Site Plan
Site and Facility Descriptions
6- 1 presents each Participant’s ownership percentage in TEC, with each Participant
responsible for the costs associated with TEC in proportion to its individual ownership
percentage.
Table 6-1
Proposed TEC Ownership Percentages
I
Participant
Percent Ownership
FMPA
38.9
JEA
31.5
RCID
9.3
City of Tallahassee
20.3
The TEC will be developed on a site consisting of approximately 3,000 acres to be
located approximately 5 miles southeast of Perry, in Taylor County, Florida. The land is
bordered by Highway 27 on the north and the Fenholloway River on the west. Though
the TEC project consists of one unit, the site will be designed and constructed with
consideration given to allowing the addition of a second unit. However, a second unit is
not planned at this time.
Schedules 9.1 through 9.7 present the status report and specifications for each of the
proposed ARP generating facilities. Schedule 10 contains the status report and
specifications for proposed ARP transmission line projects.
6-3
Site and Facility Descriptions
FMPA 2007 Ten-Year Site Plan
Schedule 9.1
Status Report and Specifications of Proposed Generating Facilities
All-Requirements Project
(Preliminary Information)
'lant Name and Unit Number
Treasure Coast Energy Center Unit 1
:apacity
a
a
a
a
a
0
a
(I
a
3.
Summer
I. Winter
296
318
4
4
rechnology Type
CC (1x1 GE 7FA)
(I
lnticipated Construction Timing
Field Construction Start Date
I, Commercial In-Service Date
3.
Aug-06
4
1
Jun-08
(I
-uel
3, Primary Fuel
Natural Gas
4
4
I. Alternate
No. 2 Oil
Fuel
l i r Pollution Control Strategy
Low NO2 Combustors, Water Injection
2ooling Method
Mechanical Draft
Total Site Area
69 Acres
2onstruction Status
Under construction, less than or equal to 50% complete
2erlification Status
Approved
Status with Federal Agencies
Approved
'rejected Unit Performance Data
>Ianned Outage Factor (POF)
5.7%
-arced Outage Factor (FOF)
Equivalent Availability Factor
Resulting Capacity Factor
4verage Net Operating Heat Rate (ANOHR)
6.3%
88.3%
34.9%
7,582 BtuikWh
Projected Unit Financial Data
AFUDC Amount ($/kW) [I]
30
$1,072
$891
$1 04
Escalation ($/kW)
$77
Fixed O&M ($/kW)
Variable O&M ($/MWh)
6.91 $/kW-yr
Book Life (Years)
Total Installed Cost (In-Service Year $/kW)
Direct Construction Cost (2006 $/kW)
a
1
4
4
1
4
4
II
3
d
4
4
4
1
1
4
1
(1
4
d
(I
[I]
Includes AFUDC and bond issuance expenses
6-4
4
4
1
4
a
I
FMPA 2007 Ten-Year Site Plan
Site and Facility Descriptions
Schedule 9.2
Status Report and Specifications of Proposed Generating Facilities
All-Requirements Project
(Preliminary Information)
Plant Name and Unit Number
Unsited Combustion Turbine Unit 1
Capacity
a. Summer
45
b. Winter
45
Technology Type
GT (General Electric LM6000 PC-SPRINT)
Anticipated Construction Timing
a. Field Construction Start Date
b. Commercial In-Sewice Date
2008
Jun-IO
Fuel
a. Primary Fuel
b. Alternate Fuel
Natural Gas
Air Pollution Control Strategy
Water Injection
Cooling Method
Air
Total Site Area
Unknown
Construction Status
Planned
Certification Status
Existing Site
Status with Federal Agencies
Existing Site
No. 2 Oil
Projected Unit Performance Data
Planned Outage Factor (POF)
1.9%
Forced Outage Factor (FOF)
Equivalent Availability Factor
3.0%
Resulting Capacity Factor
Average Net Operating Heat Rate (ANOHR)
1.8%
10,136 BtuikWh
95.2%
Projected Unit Financial Data
Book Life (Years)
Total Installed Cost (In-Sewice Year $/kW)
30
Direct Construction Cost (2006 $/kW)
AFUDC Amount ($/kW) [ I ]
$1,027
$121
Escalation ($/kW)
Fixed O&M ($/kW)
IVariable O&M ($/MWh)
$151
31.17 $/kW-yr
$3.00
[ I ] Includes AFUDC and bond issuance expenses
$1,299
~
a
FMPA 2007 Ten-Year Site Plan
Site and Facility Descriptions
Schedule 9.3
Status Report and Specifications of Proposed Generating Facilities
All-Requirements Project
(Preliminary Information)
lant Name and Unit Number
Unsited Combustion Turbine Unit 2
apacity
Summer
45
Winter
45
schnology Type
GT (General Electric LM6000 PC-SPRINT)
nticipated Construction Timing
Field Construction Start Date
Commercial In-Service Date
2008
Jun-IO
(I
a
a
a
a
4
4
4
(I
(I
4
(I
(I
(I
(I
1
Jel
Primary Fuel
Alternate Fuel
Natural Gas
No. 2 Oil
r Pollution Control Strategy
Water Injection
(I
(I
2oling Method
Air
4
)tal Site Area
Unknown
mstruction Status
Planned
a
3rtification Status
Existing Site
(I
atus with Federal Agencies
Existing Site
1.9%
rced Outage Factor (FOF)
luivalent Availability Factor
3.0%
w l t i n g Capacity Factor
95.2%
1.6%
Ierage Net Operating Heat Rate (ANOHR)
10.136 BtuikWh
ojected Unit Financial Data
ita1 Installed Cost (In-Sewice Year $/kW)
rect Construction Cost (2006 $/kW)
WDC Amount ($/kW) [ I ]
d a t i o n ($/kW)
ted O&M ($/kW)
iriable OBM ($/MWh)
4
4
4
4
ojected Unit Performance Data
anned Outage Factor (POF)
jok Life (Years)
(I
30
$1,299
$1,027
$121
$151
31.17 $/kW-yr
$3.00
[ I ] Includes AFUDC and bond issuance expenses
6-6
I
d
4
4
4
4
4
4
4
4
4
4
4
4
(I
1
FM PA 2007 Ten-Year Site Plan
Site and Facility Descriptions
Schedule 9.4
Status Report and Specifications of Proposed Generating Facilities
All-Requirements Project
(Preliminary Information)
Plant Name and Unit Number
Cane Island Unit 4
Capacity
3. Summer
296
5. Winter
318
Technology Type
cc
4nticipated Construction Timing
3. Field Construction Start Date
I. Commercial
In-Service Date
2009
Jun-I 1
%el
3. Primary Fuel
I. Alternate Fuel
Natural Gas
No. 2 Oil
4ir Pollution Control Strategy
Low NO2 Combustors, Water Injection
2ooling Method
Mechanical Draft
rota1 Site Area
Unknown
:onstruction Status
Planned
:edification Status
Existing Site
Status with Federal Agencies
Existing Site
2rojected Unit Performance Data
'lanned Outage Factor (POF)
5.7%
'orced Outage Factor (FOF)
Iquivalent Availability Factor
6.3%
88.3%
iesulting Capacity Factor
4verage Net Operating Heat Rate (ANOHR)
36.8%
7,516 BtuikWh
)rejected Unit Financial Data
3ook Life (Years]
30
rota1 Installed Cost (In-Service Year $/kW)
$1,154
lirect Construction Cost (2006 $/kW)
$891
$104
4FUDC Amount ($/kW) [ I ]
iscalation ($/kW)
7xed O&M ($/kW)
/ariable O&M ($/MWh)
[ I ] Includes AFUDC and bond issuance expenses
$159
6.91 $/kW-yr
$2.74
.
0
Site and Facility Descriptions
FMPA 2007 Ten-Year Site Plan
Schedule 9.5
Status Report and Specifications of Proposed Generating Facilities
All-Requirements Project
(Preliminary Information)
lant Name and Unit Number
Taylor Energy Center
apacity
Summer
Winter
echnology Type
754.1 (31
785.3 [SI
ST (Supercritiwl Pulverized Coal)
ntictpated Construction Timing
Field Construction Start Date
Apr-08
Commercial In-Service Date
May12
uel
,
Primary Fuel
Bituminous Coal / Petroleum Coke
Alternate Fuel
NA
ir
Pollution Control Strategy
BACT Compliant
ooling Method
Mechanical Draft
otal Site Area
Approximately 3,000 Acres
onstruction Status
Not Started
edification Status
Underway
tatus with Federal Agencies
Underway
rojected Unit Performance Data
0
0
0
0
0
0
0
a
0
0
0
0
0
0
0
0
0
0
0
0
0
e
0
0
0
quivalent Availability Factor (EAF)
4,38%
5.23%
90%
esulting Capacity Factor (%)
90%
verage Net Operating Heat Rate (ANOHR) [I]
9,238 BtulkWh
a
0
a
otal Installed Cost (In-Service Year $/kW) [I]
30
$2,664
a
iirect Construction Cost ($/kW) [I]
$2,152
,FUDC Amount ($/kW) [I]
$208
$304
$24.31
$1.43
lanned Outage Factor (POF)
orced Outage Factor (FOF)
0
rojected Unit Financial Data
ook Life (Years)
scalation ($/kW) [I]
ixed O&M ($/kW) [I] [2]
ariable O&M ($/MWh) [I] [2]
[I] Based on operation at average ambient conditions
[2] In 2007 dollars.
[3] FMPA owneship share is 38.9%.
0
0
a
a
Site and Facility Descriptions
FMPA 2007 Ten-Year Site Plan
Schedule 9.6
Status Report and Specifications of Proposed Generating Facilities
All-Requirements Project
(Preliminary Information)
[Plant Name and Unit Number
Unsited Combustion Turbine Unit 3
Capacity
a. Summer
45
b. Winter
45
Technology Type
GT (General Electric LM6000 PC-SPRINT)
Anticipated Construction Timing
a. Field Construction Start Date
2014
b. Commercial In-Service Date
Jun-16
Fuel
a. Primary Fuel
Natural Gas
b. Alternate Fuel
No. 2 Oil
Air Pollution Control Strategy
Water Injection
Cooling Method
Air
Total Site Area
Unknown
Construction Status
Planned
Certification Status
Existing Site
Status with Federal Agencies
Existing Site
Projected Unit Performance Data
Planned Outage Factor (POF)
Forced Outage Factor (FOF)
Equivalent Availability Factor
10.4%
1.7%
Resulting Capacity Factor
88.1%
1.2%
Average Net Operating Heat Rate (ANOHR)
10,136 BtuikWh
Projected Unit Financial Data
Book Life (Years)
30
Total Installed Cost (In-Service Year $/kW)
$1,506
Direct Construction Cost (2006 $/kW)
AFUDC Amount ($/kW) [ I ]
$1,027
$121
Escalation ($/kW)
Fixed O&M ($/kW)
IVariable O&M ($/MWh)
$358
31.17 $/kW-yr
$3.00
[ I ] Includes AFUDC and bond issuance expenses
_______
a
Site and Facility Descriptions
FMPA 2007 Ten-Year Site Plan
Schedule 9.7
Status Report and Specifications of Proposed Generating Facilities
All-Requirements Project
(Preliminary Information)
0
0
0
a
0
a
0
0
'lant Name and Unit Number
Unsited Combustion Turbine Unit 4
:apacity
. Summer
. Winter
45
45
echnology Type
GT (General Electric LM6000 PC-SPRINT)
0
2014
Jun-16
0
nticipated Construction Timing
Field Construction Start Date
,
,
Commercial In-Service Date
uel
, Primary Fuel
Natural Gas
,Alternate Fuel
No. 2 Oil
ir Pollution Control Strategy
Water Injection
ooling Method
Air
otal Site Area
Unknown
onstruction Status
Planned
edification Status
Existing Site
tatus with Federal Agencies
Existing Site
rojected Unit Performance Data
lanned Outage Factor (POF)
10.4%
orced Outage Factor (FOF)
1.7%
quivalent Availability Factor
esulting Capacity Factor
88.1%
1.1%
verage Net Operating Heat Rate (ANOHR)
10,136 BtuikWh
rojected Unit Financial Data
ook Life (Years)
otal Installed Cost (In-Service Year $IkW)
lirect Construction Cost (2006 $/kW)
FUDC Amount ($/kW) [ I ]
scalation ($/kW)
ixed O&M ($/kW)
ariable O&M ($/MWh)
30
$1,506
$1,027
$121
$358
31.17 $/kW-yr
$3.00
a
e
a
0
0
0
0
0
0
0
0
a
0
a
a
e
0
0
e
0
0
a
0
0
a
[ I ] Includes AFUDC and bond issuance expenses
0
6-10
0
a
FMPA 2007 Ten-Year Site Plan
Site and Facility Descriptions
Schedule 10
Status Report and Specifications of Proposed Directly Associated Transmission Lines
All-Requirements Project
(1)
Point of Origin and Termination
TCEC (FMPA) to Ralls (FPL) [I]
(2)
Number of Lines
One
(3) Right-of-way
New Transmission Right-of-way
(4)
Line Length
500 feet
(5)
Voltage
230 kV
(6) Anticipated Construction Timing
February 2007
(7) Anticipated Capital Investment
$12,484,000 [2]
(8)
Substations
TCEC
(9)
Participation with Other Utilities
FPL
B
D
D
D
D
D
B
D
D
B
D
B
B
D
B
D
D
D
D
B
D
B
D
B
D
B
D
D
D
D
B
D
D
B
D
B
D
B
D
B
D
B
B
L
Appendix I
FMPA 2007 Ten-Year Site Plan
Appendix I
List of Abbreviations
Generator Type
Steam Portion of Combined Cycle
CA
cc
Combined Cycle (Total Unit)
Combustion Turbine Portion of Combined Cycle
CT
GT
Combustion Turbine
IC
Internal Combustion Engine
NP
Nuclear Power
ST
Steam Turbine
Fuel Type
BIT
DFO
NG
RFO
UR
WH
Bituminous Coal
Distillate Fuel Oil
Natural Gas
Residual Fuel Oil
Uranium
Waste Heat
Fuel Transportation Method
PL
Pipeline
RR
Railroad
TK
Truck
WA
Water Transportation
Status of Generating Facilities
Planned Unit (Not Under Construction)
P
Regulatory Approval Pending. Not Under Construction
L
Existing Generator Scheduled for Retirement
RT
Under Construction, Less Than or Equal to 50% Complete.
U
Other
NA
Not Available or Not Applicable
a
0
a
0
a
0
0
0
0
e
0
(I)
0
0
0
0
a
0
0
*0
(I)
0
0
a
a
a
0
0
0
0
0
0
0
a
0
0
0
a
0
0
0
Appendix II
FMPA 2007 Ten-Year Site Plan
Appendix II
Other Member Transmission Information
Table 11-1 presented on the following pages contains a list of planned and proposed
transmission line additions for member cities of the Florida Municipal Power Agency
who participate in the All-Requirements Project, as well as other (non-ARP) member
cities that are not required to file a Ten-Year Site Plan.
11-1
Appendix II
FMPA 2007 Ten-Year Site Plan
Table 11-1
Planned and Proposed Transmission Additions for FMPA Members
2007 through 2015 (69 kV and Above)
I
I
City
FMPA
From
TCEC (FMPA)
TCEC Substation
Hartman Auto-Xfmrl Upgrade
Hartman Auto-Xfmr2 Upgrade
Southwest Sub Auto-Xfmr Addition
Southwest Sub Auto-Xfmr Addition
Southwest Substation
Redland Substation
Renaissance Substation
Redland
Renaissance
Jacksonville Beach Substation (Reconductor)
SIS 3rd Ave Transformer
Tavernier
lslamorada
Florida City
Tavemier
Hansel (Reconductor)
Pleasant Hill Substation
Pleasant Hill Substation
Pleasant Hill Substation
Cane Island (Reconductor)
Cane Island (Reconductor)
C.A.Wall
Neptune Road Substation
Neptune Road Substation
Osceola Parkway Substation
Lake Bryan
Ft. Pierce
Homestead
Jacksonville Beach
Key West 8 FKEC
Kissimmee
I
To
Ralls (FPL)
MVA
759
100
100
20
20
Lucy
Lucy
JEA Neptune Substation
lslamorada
Marathon
Tavemier
C.A.Wall
Hansel
Clay Street
Tie Point (Taft)
Tie Point (Osceola)
Turnpike
Tie Point with St.Cloud
Osceola Parkway
Voltage
230 kV
230 kV
138169 kV
138169 kV
138113.2 kV
138113.2 kV
138113.2 kV
138113.2 kV
138113.2 kV
138 kV
138 kV
138 kV
69113.8kV
138 kV
138 kV
138 kV
ring bus
69 kV
69 kV
69 kV
69 kV
230 kV
230 kV
Circuit
1
Estimated
In-Service Date
912007
912007
512008
512008
912010
9/2010
912010
512007
612007
212009
212009
612011
312009
612015
612015
612015
612015
612008
612008
612008
612008
1212009
1212009
612010
612010
612010
61201 1
612011
Table 11-1 (Continued)
Planned and Proposed Transmission Additions for FMPA Members
2007 through 2016 (69 kV and Above)
:ity
(issimmee (continued)
.ake Worth
Jew Smyrna Beach
lcala
'ero Beach
From
Lake Cecile
Clay Street (Reconductor)
Clay Auto-Txfmr
Upgrade 69 kV Breakers at Cane Island Substation
Marydia Auto-Txfmr (Upgrade)
Canal Transformer
Hypoluxo
30 MVA Txfmr (Smyrna Substation)
115 kV Loop Field St - Airport
30 MVA Txfmr (Field Street Substationl
Richmond 2 Station
Nuby's Corner Substation
Nuby's Corner
Nuby's Corner
Shaw
Ergle
Shaw Auto-Txfmr
Ergle Substation Third Breaker
Ergle
Dearmin
Dearmin IBaseline Substation (Improvements)
Fore Comers Substation
Fore Corners
Fore Comers
Shaw Second 30 MVA Transformer
Shaw
Sub #7 (2nd Auto-Transformer)
ro
MVA
Osceola Parkway
Airport
200
200
60
Sanal
30
30
5
25
Silver Springs
3aseline Rd
Silver Springs North
Silver Springs North
150
Silver Springs
3aseline Rd
30
Ergle
3cala North
30
Silver Springs
100
11-3
Voltage
69 kV
69 kV
230169 kV
69 kV
230169 kV
138126 kV
138 kV
115/23 kV
115 kV
115123 kV
69 kV
69 kV
69 kV
69 kV
230 kV
230 kV
230169 kV
69 kV
69 kV
69 kV
69 kV
69 kV
69 kV
69 kV
69 kV
230 kV
138169 kV
Circuit
1
1
2
1
2
1
1
1
1
1
1
1
2
2
1
1
1
1
1
2
Estimated
In-Service Date
612011
612011
612011
612011
612012
1212009
1212009
1212008
1212008
1212011
512007
812007
812007
1012007
10l2007
1012007
1012007
1012008
1012008
612009
612009
612009
612009
612009
612009
612012
612007
a
e
FMPA 2007 Ten-Year S i t e P l a n
Appendix Ill
Appendix 111
Add itio naI Reserve Margin Inf ormat ion
FMPA excludes Partial Requirements (PR) purchases that are being supplied by the PR
utility in the calculation of reserves being supplied in Schedules 7.1 and 7.2. The PR
utility is required to serve the ARP load equivalent to that of the PR utility's own native
load. Thus, the PR purchase by FMPA is equal to the purchase capacity plus equivalent
reserves of the selling utility and therefore does not require additional reserves to be
carried by FMPA. Tables 111-1 and 111-2 below are provided as supplements to Ten-Year
Site Plan Schedules 7.1 and 7.2 to demonstrate how the reserve margin percentages were
calculated for the summer and winter peaks, respectively.
Table 111-1
Calculation of Reserve Margin at Time of Summer Peak
All-Requirements Project
Total
Available
Capacity
Year
(MW)
System
Firm Peak
Demand
fMWI
(a)
2007
2008
2009
2010
201 1
2012
2013
2014
2015
2016
(b)
(4
1,786
1,933
1,943
1,762
1,972
2,131
2,086
2,006
2,006
2.096
Partial
Requirements
Purchases
fMWI
Reserve
Margin
Reserve
Margin
(MW) 111
("/PI [21
(4
(e)
(9
1,573
1,603
1,646
1,506
1,548
1,581
1,615
1,651
1,689
1.726
150
75
85
135
45
45
0
0
0
0
21 3
329
296
256
424
551
471
355
318
370
[I]
Reserve Margin MW calculated as follows: (Total Available Capacity - Partial Requirements
Purchases) - (System Firm Peak Demand - Partial Requirements Purchases)
[2] Reserve Margin % calculated as follows: [(Total Available Capacity - Partial Requirements
Purchases) - (System Firm Peak Demand - Partial Requirements Purchases)] / (System Firm
Peak Demand - Partial Requirements Purchases)
111-1
15%
22%
19%
19%
28%
36%
29%
22%
19%
21Yo
m
A p p e n d i x 111
FMPA 2007 T e n - Y e a r S i t e Plan
Table 111-2
Calculation of Reserve Margin at Time of Winter Peak
All-Requirements Project
Total
Available
Capacity
System
Firm Peak
Demand
Partial
Requirements
Purchases
Year
(MW)
(MW)
(a)
2006107
2007108
2008109
2009110
201011 1
201 1112
2012113
201 3/14
201411 5
201 5116
(b)
(c)
(MW)
(d)
1,825
1,846
2,056
1,766
1,766
2,043
2,252
2,127
2,127
2,127
(MW) 111
Reserve
Margin
(%I
316
309
475
347
310
556
732
574
538
502
[ I ] Reserve Margin MW calculated as follows: (Total Available Capacity - Partial Requirements
Purchases) - (System Firm Peak Demand - Partial Requirements Purchases)
[2] Reserve Margin % calculated as follows: [(Total Available Capacity - Partial Requirements
Purchases) - (System Firm Peak Demand - Partial Requirements Purchases)] 1 (System Firm
Peak Demand - Partial Requirements Purchases)
111-2
[21
(9
(e)
150
75
85
135
45
45
45
0
0
0
1,509
1,538
1,581
1,419
1,456
1,487
1,519
1,553
1,589
1,625
Reserve
Margin
230,
21 0,
325
270,
220,
399
509
379
349
319
a
D
D
D
FMPA 2007 Ten-Year Site Plan
Appendix IV
Appendix IV
Supplemental Information
This appendix presents information typically requested by and provided to the PSC in a
supplemental filing.
Q1.
Provide all data requested on the attached forms. If any of the requested
data is already included in FMPA’s Ten-Year Site Plan, state so on the
appropriate form.
See Tables IV-1 through IV-7.
42.
Illustrate what FMPA’s generation expansion plan would be as a result of
sensitivities to the base case demand and fuel price forecast. Include the
cumulative present worth revenue requirements of each sensitivity case.
FMPA’s Base Case generation expansion plan was held constant for the
sensitivities to the demand forecast. FMPA performed sensitivities to the Base
Case demand forecast using the Severe and Mild weather forecasts as discussed in
Section 3 of the Ten-Year Site Plan. Some adjustments to the timing of certain
planned resources could be made in the event that a material change in demand
was to occur in the future.
FMPA’s Base Case generation expansion plan was also held constant for the
various sensitivities to the fuel price forecast. In addition to the Base Case,
FMPA has performed High and Low Fuel Price sensitivities, as well as an
additional sensitivity that held non-nuclear fuel prices constant over the study
period (the “Constant Fuel” case).
The cumulative present worth revenue requirements (CPWRR) over the period
2007-2036 for the Base Case were approximately $12.4 billion. The CPWRR for
the Severe and Mild weather sensitivities were approximately $12.6 billion and
$11.9 billion, respectively. The CPWRR for the High and Low Fuel Price
sensitivities were approximately $17.9 billion and $9.2 billion, respectively. The
CPWRR for the Constant Fuel case was approximately $12.6 billion.
IV-1
FMPA 2007 Ten-Year Site Plan
43.
Appendix IV
Describe the nature of FMPA’s options to continue purchasing capacity
under its existing contracts.
FMPA has options in several power agreements to purchase additional power if
required.
44.
For each of the generating units contained in FMPA’s Ten-Year Site Plan,
discuss the “drop-dead” date for a decision on whether or not to construct
each unit. Provide a time line for the construction of each unit, including
regulatory approval, and final decision point.
Typical project schedules for coal, combined cycle and peaking units are shown
below. There may moderate to significant costs associated with cancelling a
decision to build a unit at any time in the project schedule. Typical “drop-dead’’
dates for a schedule may be just prior to when construction begins, or just after
the final permitting stages. This would allow for resale of any equipment without
having been installed. The construction period typically begins four years prior to
the in-service date of coal plants, two years prior to the in service date of
combined cycle units and one year prior to the in-service date of peaking units.
Regulaloiy B n d Permiliing
inserin
and Procuremanl
0
0
a
IV-2
FMPA 2007 Ten-Year Site Plan
Q5.
Appendix IV
Discuss whether FMPA anticipates any problems with purchasing capacity
and energy from Calpine given Calpine Corporation’s bankruptcy
proceedings.
FMPA expects Calpine to provide capacity and energy as contracted.
46.
Provide, on a system-wide basis, historical annual heating degree day (HDD)
data for the period 1997-2006 and forecasted HDD data for the period 20072016. Describe how FMPA derives system-wide temperature if more than
one weather station is used.
FMPA forecasts demand and energy data for each All-Requirements participant
using temperature data. Demands are then combined using historical coincident
information to produce a coincident peak demand for the All-Requirements
Project as a whole. Data reported in Table IV-8 is from the Orlando International
Airport weather station, which may be used as an indicator of weather conditions
over FMPA’s geographically diverse service area.
47.
Provide, on a system-wide basis, historical annual cooling degree day (CDD)
data for the period 1997-2006 and forecasted CDD data for the period 20072016. Describe how FMPA derives system-wide temperature if more than
one weather station is used.
Available cooling degree-day information is contained in Table IV-8.
question 6 regarding the use of temperature data.
Q8.
See
Provide, on a system-wide basis, historical annual average real retail price of
electricity in FMPA’s service territory for the period 1997-2006. Also,
provide the forecasted annual average real retail price of electricity in
FMPA’s service territory for the period 2007-2016. Indicate the type of price
deflator used to calculate the historical and forecasted prices.
FMPA provides wholesale power to its members. Individual member cities are
responsible for setting their own retail price of electricity.
IV-3
FMPA 2007 Ten-Year Site Plan
Q9.
Appendix IV
Provide the following data to support Schedule 4 of FMPA’s Ten-Year Site
Plan: the 12 monthly peak demands for the years 2004, 2005, and 2006; the
date when each of these monthly peaks occurred; and the temperature at the
time of these monthly peaks. Describe how FMPA derives system-wide
temperature if more than one weather station is used.
See Table IV-9 for monthly peak demand information. Temperature data reported
in Table IV-9 is form the Orlando International Airport weather station, which
may be used as an indicator of weather conditions over FMPA’s geographically
diverse service area.
QlO.
Discuss how FMPA compares its fuel price forecasts to recognized,
authoritative independent forecast.
FMPA utilizes independent fuel forecasting consultants as well as information
from general consultants, other utilities, market exchanges, trade literature, FMPA
members and staff to evaluate the reasonableness of a given fuel forecast.
Qll.
Discuss the actions taken by FMPA or its members to promote and
encourage competition within and among coal transportation members.
FMPA. is a joint owner in existing coal capacity with OUC. OUC is FMPA’s
primary coal transportation manager for Stanton Units 1 and 2. Such information
may be obtained from OUC.
Q12.
Provide documents that support FMPA’s fuel price forecasts for natural gas,
residual fuel oil, and distillate fuel oil for the 2007-2016 period. Separate the
delivered price into commodity and transportation components.
The base case fuel price forecasts were provided by NewEnergy Associates, a
wholly owned subsidiary of Siemens Power Generation. The base case fuel price
forecast data for coal was provided by Platt’s, a division of the McGraw-Hill
Companies, Inc. It cannot be reproduced, distributed, or sold without the express
written permission of Platt’s. Fuel price sensitivities and fuel transportation costs
were developed by FMPA through internal resources. The commodity and
transportation components of the base, high and low fuel price forecast can be
found in Tables IV- 10, IV- 1 1, and IV- 12, respectively.
IV-4
i
a
e
e
S-AI
SS9'Ot
6OL'Pl
Yo I'S6
09L'Sl
[SI
[SI
[SI
[SI
[SI
[SI
[SI
9ES'L
OE1'8
08E'O 1
[PI
]E1 PaW!oJd
% t'S6
[SI
[SI
[SI
(1IHONVI
P
%6' 1
%6' 1
%6' 1
E
Z
[SI
a
[SI
3
[SI
[SI
[SI
[SI
[SI
[SI
[SI
[SI
[SI
a
v
v
%1'88
%0'9
%E'88
%€'E6
[PI
[E] PaW!OJd
%8'S
E
Z
% t'S6
(d
Z
1
%8'E
[PI
[E1 PaW!oJd
1
Z
'ON
wn
(4
(Z)
FMPA 2007 Ten-Year Site Plan
Appendix IV
Table IV-2
Nominal, Delivered Fuel Prices Base Case
(1 1
Year
Escalation (“h)
$/Mbtu
History:
2004
2005
2006
Forecast:
2007
2008
2009
2010
201 1
2012
201 3
2014
201 5
2016
1,235
1,106
931
786
799
802
810
818
841
870
-10.48%
-15.81%
-15.59%
1.67%
0.36%
0.99%
1.03%
2.77%
3.52%
[I] The base case fuel price forecast for coal was provided by Platt’s, a division of the McGraw-Hill Companies, Inc. It cannot be reproduced,
distributed, or sold without the express written permission of Platt’s.
Table IV-3
Nominal, Delivered Fuel Prices High Case
(11
(5)
Residual Oil
Year
$/Mbtu
Distill e Oil
Escalation (Yo)
$/Mbtu
(6)
(7)
(10)
Natural Gas
Escalation (%l
$/Mbtu
Coal [I]
Escalation (Yo)
Escalation (%)
$/Mbtu
(11)
Nuclear
I1 Escalation(x
$/Mbtu
History:
2004
2005
2006
Forecast:
2007
2008
2009
2010
201 1
2012
2013
2014
2015
2016
1,830
1,799
1,681
1,647
1,549
1,505
-1.69%
-6.59%
-1.98%
-5.99%
-2.82%
1,523
1,517
1,504
1,509
1.21%
-0.42%
-0.85%
0.32%
3,369
3,307
3,078
3,012
2,821
2,734
2,766
2,750
2,722
2,728
-1.83%
-6.92%
-2.16%
-6.34%
-3.07%
1.15%
-0.56%
-1.02%
0.20%
1,6E
1,61
1,5c
1,4E
1,37
1,3i
1,342
1,334
1,318
1.320
-1.92%
-7.13%
-2.28%
-6.57%
-3.22%
1.11%
-0.65%
-1.13%
0.13%
459
465
405
406
397
1.313
-12.983
0.273
-2.253
378
353
363
364
372
-4.593
-6.623
2.783
0.143
2.183
[I] The base case fuel price forecast for coal was provided by Platt's, a division of the McGraw-Hill Companies, Inc. It cannot be reproduced,
distributed, or sold without the express written permission of Platt's. Sensitivitiesto the base case forecast were developed by FMPA
through internal resources.
46
47
49
50
51
52
54
55
56
58
2.50'
2.50'
2.50'
2.50'
2.50'
2.50'
2.50'
2.50'
2.50'
FMPA 2007 Ten-Year Site Plan
Appendix IV
Table IV-4
Nominal, Delivered Fuel Prices Low Case
(1 1
(2)
(3)
(6)
Residual Oil
Natu I Gas
Year
Escalation (%)
$/Mbtu
Coal [I]
Escalation (%)
(IMbtu
$/Mbtu
Nuclear
Escalation
(“/I
Escalation (%)
(/Mbtu
listory:
2004
2005
2006
orecast:
2007
2008
2009
2010
201 1
2012
2013
2014
2015
2016
447
444
425
421
406
400
407
409
409
41 3
-0.700,
-4.390,
-0.820,
-3.710,
-1.310,
1.590,
0.460,
0.170,
1.000,
736
727
686
677
644
630
639
639
637
642
-1.21%
-5.53%
-1.41%
-4.87%
-2.07%
1.40%
0.02%
-0.33%
0.66%
33:
32;
30f
30’
28:
27f
27:
27f
27f
27;
-1.60%
-6.41Yo
-1.88%
-5.79%
-2.69%
1.24%
-0.34%
-0.76%
0.38%
205
208
181
181
177
169
158
162
162
166
[I] The base case fuel price forecast for coal was provided by Platt‘s, a division of the McGraw-Hill Companies, Inc. It cannot be reproduced,
distributed, or sold without the express written permission of Platt’s. Sensitivities to the base case forecast were developed by FMPA
through internal resources.
IV-8
1.31%
-12.98%
0.279
-2.25%
-4.59%
-6.62%
2.78Y
0.14%
2.18%
46
47
49
50
51
52
54
55
56
5a
2.50%
2.50%
2.50%
2.50%
2.50%
2.50%
2.50%
2.50%
2.50%
FMPA 2007 Ten-Year Site Plan
Appendix IV
Table IV-5
Financial Assumptions Base Case
5.00%
AFUDC Rate
Capitalization Ratios (Yo):
Debt
Preferred
Equity
100%
NIA
NIA
Debt
Preferred
Equity
NIA
NIA
NIA
State
Federal
Effective
NIA
NIA
NIA
Rate of Return (%):
Income Tax Rate (%):
NIA
Other Tax Rate:
5.0%
Discount Rate:
Tax Deweciation Rate (Yo):
NIA
IV-9
FMPA 2007 Ten-Year Site Plan
Appendix IV
Table IV-6
Financial Escalation Assumptions
(1)
(2)
(4)
(5)
Fixed O&M
cost
Year
General
Inflation
%
(3)
Plant
Construction
cost
%
YO
Variable O&M
cost
%
2007
2.50%
2.50%
2.50%
2.50%
2008
2.50%
2.50%
2.50%
2.50%
2.50%
2009
2.50%
2.50%
2.50%
2010
2.50%
2.50%
2.50%
2.50%
2011
2.50%
2.50%
2.50%
2.50%
2012
2.50%
2.50%
2.50%
2.50%
2.50%
2.50%
2.50%
2013
2.50%
2014
2.50%
2.50%
2.50%
2.50%
2015
2016
2.50%
2.50%
2.50%
2.50%
2.50%
2.50%
2.50%
2.50%
Table IV-7
Loss of Load Probability, Reserve Margin, and Expected Unserved Energy Base Case Load Forecast
~
(1)
(2)
Year
Loss of Load
Probability
(DaysNr)
(3)
(4)
(5)
Annual Isolated
Reserve Margin (%)
(Including Firm
Expected
Unserved Energy
Loss of Load
Purchases)
(MWh)
Probability
(DaysNr)
(6)
Annual Assisted
Reserve Margin (%)
(Including Firm
Purchases)
2007
2008
2009
2010
2011
(See note below)
(See note below)
2012
2013
2014
2015
2016
Note: FMPA does not develop projections of either Isolated or Assisted Loss of Load Probability nor Expected Unserved Energy.
(7)
Expected
Unserved Energy
(MWh)
FMPA 2007 Ten-Year Site Plan
Appendix IV
Table IV-8
Historical and Projected Heating and Cooling Degree Days
(1)
Year
(a)
(2)
Annual Heating
Degree Days
(b)
Annual Cooling
Degree Days
(c)
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
395
62 1
350
452
706
457
714
531
524
433
3,323
3,490
3,637
3,413
3,202
3,591
3,529
3,447
3,424
3,545
Projected Values
for 2007 to 2016
580
3.428
111
(3)
[I] Projections are based on normal heating and cooling degree day
data reported by the National Oceanic Atmospheric Administration
(NOAA) and are based on the historical period from 1971-2000inclusive.
Data reported is for the Orlando International Airport (OIA) annual
weather station, which may be used as an indicator of weather
conditions over FMPAs geographically diverse service area.
IV-I 2
BOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOO~
Appendix IV
FMPA 2007 Ten-Year Site Plan
Table IV-9
All-Requirements Project Monthly Peak Demand Information P I 121
[I]The historical hourly demand data maintained by FMPA has improved in numerical accuracy This may result in differences in the value and timing
of monthly peak demand shown above to similar data shown in prior Ten-Year Site Plans for the same year
[Z] Temperature data is taken from recordings of the Orlando InternationalAirport weather station, which may be used as an indicator of
weather conditions over FMPA’s geographicallydiverse service area
IV-I 3
Appendix IV
FMPA 2007 Ten-Year Site Plan
Table IV-10
Nominal, Delivered Fuel Price Components Base Case
[I]
Transportationcosts shown for natural gas reflect variable delivery charges and do not include fixed capacity charges.
[2] The base case fuel price forecast for coal was provided by Platt's, a division of the McGraw-Hill Companies, Inc. It cannot be reproduced,
distributed,or sold without the express written permission of Platt's.
IV-14
Table IV-11
Nominal, Delivered Fuel Price Components High Case
Residual Oil
Year
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
Natural Gas [I1
Distillate Oil
Coal [2]
Commodity
Transportation
Total
Commodity
Transportation
Total
Commodity
Transportation
Total
Commodity
Transportation
Total
$/Mbtu
$/Mbtu
$/Mbtu
$/Mbtu
$/Mbtu
$/Mbtu
$/Mbtu
$/Mbtu
$/Mbtu
$/Mbtu
$/Mbtu
$/Mbtu
1,701
1,667
1,545
1,508
1,406
1,359
1,373
1,363
1,347
1,348
129
132
136
139
142
146
150
153
157
161
1,830
1,799
1,681
1,647
1,549
1,505
1,523
1,517
1,504
1,509
3,240
3,175
2,943
2,873
2,678
2,588
2,616
2,597
2,565
2,567
12f
13;
13f
13f
142
14f
15C
152
157
161
3,369
3,307
3,078
3,012
2,821
2,734
2,766
2,750
2,722
2,728
1,620
1,588
1,471
1,436
1,339
1,294
1,308
1,298
1,283
1,283
[I] Transportation costs shown for natural gas reflect variable delivery charges and do not include fixed capacity charges.
[2]The base case fuel price forecast for coal was provided by Platt's, a division of the McGraw-Hill Companies, Inc. It cannot be reproduced,
distributed, or sold without the express written permission of Platt's. Sensitivities to the base case forecast were developed by FMPA
through internal resources.
2E
3c
31
3;
3:
32
34
3!
3f
3i
1,650
1,618
1,502
1,468
1.372
1,328
1,342
1,334
1,318
1,320
383
388
326
325
315
294
268
276
275
280
76
77
79
81
82
84
85
87
89
91
459
465
405
406
397
378
353
363
364
372
Appendix IV
FMPA 2007 Ten-Year Site Plan
Table IV-12
Nominal, Delivered Fuel Price Components Low Case
Residual Oil
Year
2007
2008
2009
2010
201 1
2012
2013
2014
2015
2016
Natural Gas [I]
Distillate Oil
Coal [Z]
Commodity
Transportation
Total
Commodity
Transportation
Total
Commodity
Transportation
Total
Commodity
Transportation
Total
$/Mbtu
$/Mbtu
$/Mbtu
$/Mbtu
$/Mbtu
$/Mbtu
$/Mbtu
$/Mbtu
$/Mbtu
$/Mbtu
$/Mbtu
$/Mbtu
318
312
289
282
263
254
257
255
252
252
129
132
136
139
142
146
150
153
157
161
447
444
425
42 1
406
400
407
409
409
41 3
607
594
551
538
501
485
490
486
480
480
129
132
136
139
142
146
150
153
157
161
736
727
686
677
644
630
639
639
637
642
303
297
275
269
25 1
242
245
243
240
240
29
30
31
32
33
33
34
35
36
37
333
327
306
301
283
276
279
278
276
277
129
131
102
100
95
85
73
75
73
75
76
77
79
81
82
84
85
87
89
91
205
208
181
181
177
169
158
162
162
166
[I] Transportation costs shown for natural gas reflect variable delivery charges and do not include fixed capacity charges.
[2]The base case fuel price forecast for coal was provided by Platt's, a division of the McGraw-Hill Companies, Inc. It cannot be reproduced,
distributed, or sold without the express written permission of Platt's. Sensitivitiesto the base case forecast were developed by FMPA
through internal resources.
IV-16
~ooooooeoooooooooooooooooooooooooooooooooooo
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