City of Tallahassee

City of Tallahassee
Juhltt~mria a.tnmmtmnnn
CAPITAL CIRCLE OFFICE CENTER •
2540 SHUMARD OAK BOULEVARD
TALLAHASSEE, FLORIDA 32399-0850
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-M-E-M-0-R-A-N-D-U-M-
(,,.)
P'O
DATE:
TO:
April 3, 2013
Cole, Commission Clerk., Office of Commission Clerk
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FROM:
Phillip 0. Ellis, Engineering Specialist III, Division of EngineeringfQt: .,.._
Kevin D. Dawkins, Engineering Specialist I, Division of Engineering ){D
RE:
2013 Ten-Year Site Plan from City of Tallahassee Utilities
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Attached is City of Tallahassee Utilities' 2013 Ten-Year Site Plan, submitted on April 1, 2013 ,
consistent with Rule 25-22.071 , Florida Administrative Code (F.A.C.). Please place this item in
Docket No. 130000 - Undocketed Filings for 2013 , as it relates to the annual undocketed staff
Ten-Year Site Plan Review project.
If you have any additional questions, please contact me.
POE
Attachment
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FPS C-COMHISSION CLERK
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FPSC- COMMISSION CLERK
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CITY OF TALLAHASSEE
TEN YEAR SITE PLAN FOR ELECTRICAL GENERA TING FACILITIES
AND ASSOCIATED TRANSMISSION LINES
2013-2022
TABLE OF CONTENTS
I. Description of Existing Facilities
1.0
I. I
1.2
Figure A
Table I. I
Introduction .... ...................... ......... .. .......... ........ ........ ....... .................. ..... ..... .......... ......... ............... ........ ............ I
System Capabi lity .... ................. ..... .... .... ...... ................ ..... .. .. ... .... .... ........... ...... ... .. ............... ........... ... ..... .... ....... I
Purchased Power Agreements ........ ....... ...... ...... ...... ..... .... ............ ... ...... ..... ..... ... .... ...... ... ....... ....... .......... ........... 2
Service Territory Map .. ....... ...... .. ....... ... .... .... ....... ........ ... .. .... ............ ..... ..... ..... ... .. .. ......... .... ...... ....... ..... .. ..... ...... 3
FPSC Schedule I Existing Generating Facilities .... .......... .. .. ....... .... ... ..... ..... ..... ........ .... ............ .......... .... ... ........ 4
II. Forecast of Energy/Demand Requirements and Fuel Utilization
2.0
2. 1
2. 1. 1
2. 1.2
2.1.3
2.2
Table 2.1
Table 2.2
Table 2.3
Figure Bl
Figure B2
Table 2.4
Table 2.5
Table 2.6
Table 2.7
Table 2.8
Table 2.9
Table 2. 10
Table 2. 11
Table 2.12
Table 2. 13
Tab le 2.14
Table 2.15
Figure B3
Table 2.16
Table 2.17
Table 2. 18
Table 2.19
Table 2.20
Figure B4
Introduction ....... ...... ..... .. ............... .... ..... .... .... .... ..... ..... ...... ..... ..... ..... .... .. ..... ..... ...... ....... ...... ....... ........ ... ... ....... .. 5
System Demand and Energy Requirements ..... ..... ................ ................ ...... ......... .......... ..... ... ........... .............. .... 5
System Load and Energy Forecasts ..... .... ... .... ...... ....... ......... ............ .. ... ...... .. .. ... .... ... ..... ... ......... ....... .. ..... ... ....... 5
Load Forecast Uncertainty & Sensitivities ...... ..... ............ ............... ....... .. ....... ........ .... .... ...... ....... ... ... ..... ........... 8
Energy Efficiency and Demand Side Management Programs ... .. .. ... ..... .... ..... .... ...... ....... .... .... ......... ... ..... ... ....... 9
Energy Sources and Fuel Requirements .. .... ........... ........ ........ ......... ...... ....... ... ... .. ............ ..... ....... ........ ....... .... . 11
FPSC Schedule 2. 1 History/Forecast of Energy Consumption (Residential and Commercial Classes) ....... ... . 12
FPSC Schedule 2.2 History/ Forecast of Energy Consumption (Industrial and Street Light Classes) ............ .. 13
FPSC Schedule 2.3 History/ Forecast of Energy Consumption (Utility Use and Net Energy for Load) .......... 14
Energy Consumption by Customer Class (2003-2022) .... ........ ..... .. ........ ........ ... .......... ........ .... ........ ......... .... ... 15
Energy Consumption: Comparison by Customer Class (2013 and 2022) ........... .. .. .... ......... ........ .. .... ........ ... .. 16
FPSC Schedule 3. 1.1 History/Forecast of Summer Peak Demand - Base Forecast. ... .. .... ............. ..... ......... .... 17
FPSC Schedule 3.1 .2 History/Forecast of Summer Peak Demand - High Forecast ...... ........... ........ .. ........ .... . 18
FPSC Schedule 3. 1.3 History/Forecast of Summer Peak Demand - Low Forecast ...... ..... .. ... ..... .. ..... ...... ...... . 19
FPSC Schedule 3.2.1 History/Forecast of Winter Peak Demand - Base Forecast... ... ......... ...... ... .... ..... ... ...... . 20
FPSC Schedule 3.2.2 History/Forecast of Winter Peak Demand - High Forecast... ... ... ........ .......... ... ....... ... .. . 21
FPSC Schedule 3.2.3 History/Forecast of Winter Peak Demand - Low Forecast .. ... .. ... ..... ........ ... .... ............ . 22
FPSC Schedule 3.3 . 1 History/Forecast of Annual Net Energy for Load - Base Forecast .. .... .. ......... .............. 23
FPSC Schedule 3.3.2 History/ Forecast of Annual Net Energy for Load - High Forecast.. .. .. ... .. ....... ...... ..... .. 24
FPSC Schedule 3.3.3 History/Forecast of Annual Net Energy for Load - Low Forecast... ... ...... .... ...... ........ .. 25
FPSC Schedule 4 Previous Year Actual and Two Year Forecast Demand/Energy by Month ...... ......... ......... 26
Load Forecast: Key Explanatory Variables ....... .... ... ...... .. .............. ........ ... ... .......... ... ........ .. ..... ........ ....... ...... .. 27
Load Forecast: Sources of Forecast Model Input Information ................... ........ ....... .... ... .. .. ....... ............. ....... 28
Banded Summer Peak Load Forecast vs. Supply Resources .... ............... .... ............. ........ ........ .......... ......... ..... 29
Projected DSM Energy Reductions .. ........ .. ................. ..... .... ....... ........ ....... .... ..... ...... .... ....... ... .......... .. ....... .. .... 30
Projected DSM Seasonal Demand Reductions ... ...... ... ....... .... .... .. ............ ..... .......... .... ..... ........... ......... ...... ..... . 31
FPSC Schedule 5.0 Fuel Requirements ..... ... ... ... ..... ... .............. .................... .... ... ... .. .. ..... ..... ... ... .... ... .. ... .... ...... 32
FPSC Schedule 6.1 Energy Sources (GWh) ... ... .... .... ........... ... ........... ....... ....... ....... ..... ... ... .... ..... ...... .. ............ 33
FPSC Schedule 6.2 Energy Sources(%) .. .... .... ... .... ....... ................. ... .... ..... ............. ... ....... .................. ........... . 34
Generation by Fuel Type (20 13 and 2022) ...... ... .... ........ ...... ..... .... ........ ..... ............ .... .... ... .. .. ... .. ...... ... .. ..... ..... 35
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III. Projected Facility Requirements
3.1
3.2
3.2.1
3.2 .2
3.2.3
3.2.4
3.2.5
3.2.6
.Figure C
Table 3.1
Table 3.2
Table 3.3
Table 3.4
Planning Process .... .... ... .... .... ........ .... ..... .... .......... ......... ... .. ........... .. ... .... ............ ........ ....... .. ...... .... ............ ........ 37
Projected Resource Requirements .. ..... .... .. ... ... .. .......... ....... .... ... ....... .............. ....... ..... ........ .... .. ....... ... ... ..... ...... 37
Transmission Limitations ... .. ... .... ... ..... ... .. .... ..... .... ....... ......... .............. ...... ... .. ........ ... ......... .... ........... .... ........... . 37
Reserve Requirements ......... .... ................. .... ........ ..... .... .. .... .. ............. .... .... ... ... ..... ....... ... ........... .. .. ...... ....... ..... 38
Recent and Near Term Resource Additions ..... .. ..... ..... .......... ..... ................. .............. .... ..... .......... ..... ..... ........ . 38
Power Supply Diversity ....... ........ ......... ............... ....... ... ........ ........ ... ....... .. .... ... ... .... .... ............. ........... ............. 39
Renewable Resources .. ......................... .... ... ....... ... ..... .... ....... ........ ... ......... .... ..... ......... .. ...... .... .. .... .... ... .... ..... ... 40
Future Power Supply Resources ....... ... ... ... ... ..... ...... ... ............ .... .... .. .............. .. ................ .... ........ ........ .... ........ 42
System Peak Demands and Summer Reserve Margins ... ... ..... ... .. ......... .. .... .. ... ... ..... .... .... ... ... ....... ....... .... .. .. ... . 43
FPSC Schedule 7.1 Forecast of Capacity, Demand and Scheduled Maintenance at Time of Summer Peak .. . 44
FPSC Schedule 7.2 Forecast of Capacity, Demand and Scheduled Maintenance at Time of Winter Peak ...... 45
FPSC Schedule 8 Planned and Prospective Generating Facility Additions and Changes ..... ...... .. .. ... .... ...... ... 46
Generation Expansion Plan ....... ..... .... .......... ... ........ .. ..... ... .... ......... ....... ... ..... ....... ..... ........... ...... .......... ...... ...... 47
IV. Proposed Plant Sites and Transmission Lines
4.1
4.2
Table 4. 1
Figure DI
Figure D2
Table 4.2
Table 4.3
Table 4.4
Proposed Plant Site .. .... ......... ... .. ..... ......... .... .... ... ....... ...... ... .. ......... ... ......... ................. .. ... .... ... .... .......... ............ 49
Transmission Line Additions/Upgrades ....... ............. ........ ............. ........ .... ................ ....... ..... .... .... ............ ...... 49
FPSC Schedule 9 Status Report and Specifications of Proposed Generating Facilities ......... .... ... .. ..... ..... .... ... 51
Hopkins Plant Site ...... .... .. .. .......... .................... ......... ............. ...... ..... .... ... ...... ... ..... .. .......... .... .. ..... ...... .... .... ... .. 52
Purdom Plant Site ..... ......... ........ .... ....... ............ ...... ................ ........... ..... .. ...... ...................... .. ... ... .... .... .... ..... ... 52
Planned Transmission Projects 2013 -2022 ... ...... ....... ...... ... .... .... ...... .. ... .......... ... ....... ... .. ....... .. ...... ..... .............. 53
FPSC Schedule 10 Status Report and Spec. of Proposed Directly Associated Transmission Lines ........... .. .. 54
FPSC Schedule 10 Status Report and Spec. of Proposed Directly Associated Transmission Lines ......... ...... 55
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Chapter I
Description of Existing Facilities
1.0
INTRODUCTION
The City of Tallahassee (City) owns, operates, and maintains an electric generation,
transmission, and distribution system that supplies electric power in and around the corporate
limits of the City. The City was incorporated in 1825 and has operated since 1919 under the
same charter. The City began generating its power requirements in 1902 and the City's Electric
Utility presently serves approximately 115,200 customers located within a 221 square mile
service territory (see Figure A). The Electric Utility operates three generating stations with a
total summer season net generating capacity of 794 megawatts (MW).
The City has two fossil-fueled generating stations, which contain combined cycle (CC),
steam and combustion turbine (CT) electric generating facilities.
The Sam 0. Purdom
Generating Station, located in the town of St. Marks, Florida has been in operation since 1952;
and the Arvah B. Hopkins Generating Station, located on Geddie Road west of the City, has been
in commercial operation since 1970. The City has also been generating electricity at the C.H .
Com Hydroelectric Station, located on Lake Talquin west of Tallahassee, since August of 1985.
1.1
SYSTEM CAPABILITY
The City maintains six points of interconnection with Progress Energy Florida
("Progress"); three at 69 kV, two at 115 kV, and one at 230 kV; and a 230 kV interconnection
with Georgia Power Company (a subsidiary of the Southern Company ("Southern")).
As shown in Table 1.1 (Schedule l), 222 MW (net summer rating) of CC generation, 48
MW (net summer rating) of steam generation and 20 MW (net summer rating) of CT generation
facilities are located at the City's Sam 0. Purdom Generating Station. The Arvah B. Hopkins
Generating Station includes 300 MW (net summer rating) of CC generation, 76 MW (net
summer rating) of steam generation and 128 MW (net summer rating) of CT generation
facilities.
Ten Year Site Plan
April 2013
Page 1
The City's Hopkins 1 steam generating unit can be fired with natural gas, residual oil or
both while the Purdom 7 steam unit can only be fired with natural gas. The CC and CT units can
be fired on either natural gas or diesel oil but cannot bum these fuels concurrently. The total
capacity of the three units at the C.H. Com Hydroelectric Station is 11 MW. However, because
the hydroelectric generating units are effectively run-of-river (dependent upon rainfall, reservoir
and downstream conditions), the City considers these units as "energy only" and not as
dependable capacity for planning purposes.
The City's total net summer installed generating capability is 794 MW. The
corresponding winter net peak installed generating capability is 870 MW. Table 1.1 contains the
details of the individual generating units.
1.2
PURCHASED POWER AGREEMENTS
The City has no long-term firm capacity and energy purchase agreements. By mutual
agreement the former purchase agreement with Progress for 11.4 MW was terminated on
December 31, 2012.
Ten Year Site Plan
April 2013
Page 2
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Figure A
City of Tallahassee, Electric Utility
Service Territory Map
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Ten Year Site Plan
April 2013
Page 3
.....
Ci!Y Of Tallahassee
Schedule I
Existing Generating Facilities
As of December 31 , 2012
( I)
Unit
No.
Plant
Sam 0. Purdom
_,
ct>
(2)
7
8
GT-I
GT-2
A. B. Hopkins
(3)
Location
Waku lla
-<
GT-I
GT-2
GT-3
GT-4
-u "O ct>
ru ~ ~
ct> rv S!l
0
.,,.
~
w
ro-u
(8)
Pri
Alt
ST
NG
NG
NG
NG
NA
F02
F02
F02
PL
PL
PL
PL
GT
GT
ST
GT
GT
GT
GT
Fuel
(7)
L'fil
cc
Leon
(6)
Fuel Transpo11
Pri
Alt
cc
<O
(5)
Uni t
:J
)>
(4)
NG
NG
NG
NG
NG
NG
F06
F02
F02
F02
F02
F02
PL
PL
PL
PL
PL
PL
NA
TK
TK
TK
(9)
(10)
( II )
(12)
Alt.
Fuel
Days
Use
Commercia l
In-Service
MonthNear
Expected
Retirement
MonthNear
Gen. Max.
Name plate
[I]
[2, 3]
[2, 3]
(2, 3]
6166
7/00
12/63
5164
12/1 3
12/40
10/15
10/ 15
50,000
247,743
15,000
15,000
48
222
10
10
48
258 (8]
10
10
Plant Total
290
326
75,000
358,200 (6]
16,320
27,000
60,500
60,500
76
300
12
24
46
46
78
330 [8]
14
26
48
48
Plant Total
504
544
0
0
0
0
0
0
0
0
1.2±
lli
TK
TK
TK
TK
TK
TK
[4]
[3]
[3]
[3]
[3]
[3]
5171
6/08 [5]
2170
9172
9105
11 /05
3120
Unknown
3/15
3/17
Unknown
Unknown
ii)
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C. 1-1. Com
Hydro Station
[7]
Leon/
Gadsden
HY
HY
HY
WAT
WAT
WAT
WAT
WAT
WAT
WAT
WAT
WAT
WAT
WAT
WAT
NA
NA
NA
9/85
8/85
1/86
Unknown
Unknown
Unknown
f.kW
( 13)
( 14)
Net Capabilit}
Winter
Summer
(MW)
(MW)
4,440
4,440
3,430
Plant Total
Total System Capacity as of December 3 1, 2012
Notes
[I]
[2]
(3)
Purdom Unit 7 is limited 10 natural gas fuel only.
Due to the Purdom facility-w ide emissions caps, utili zation of liquid fuel at this facility is limited.
The City maintains a minimum distillate fuel oil swrage capacity equivalent to approximately 12 peak load days at the Purdom plant and approximately 21 peak load days at
the Hopkins plant.
[4]
[5)
The City maintains a minimum residual fuel oil storage capacity equivalent to approximately 19 peak load days at the Hopkins plant.
Reflects the commercial operations date of Hopkins 2 repowered to a combined cycle generati ng unit w ith a new General Electric Frame 7A combustion turbine. The
original commercia l operations date of the existing steam turbine generator was October 1977.
[6]
Hopkins 2 nameplate rating is based on combustion turbine generawr (CTG) nameplate and mode led steam turbine generator (STG) output in a Ix I combi ned cycle (CC)
configuration with supplemental duct firing.
[7]
Because the C. H. Corn hydroelectric generating units are effective ly run-of-river (dependent upon rainfall, reservoir and downstream conditions), the City considers these
units as "energy only" and not as dependable capacity for planning purposes.
[8]
Summer and winte r ratings are based on 95 °F and 29 °F ambient temperature, respecti ve ly.
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CHAPTER II
Forecast of Energy/Demand Requirements and Fuel Utilization
2.0
INTRODUCTION
Chapter II includes the City's forecasts of demand and energy requirements, energy
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sources and fuel requirements. This chapter also explains the impacts attributable to the City's
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City expects to continue its commitment to the DSM programs that prove beneficial to the City's
current Demand Side Management (DSM) plan. The City is not subject to the requirements of
the Florida Energy Efficiency and Conservation Act (FEECA) and, therefore, the Florida Public
Service Commission (FPSC) does not set numeric conservation goals for the City. However, the
ratepayers.
2.1
SYSTEM DEMAND AND ENERGY REQUIREMENTS
Historical and forecast energy consumption and customer information are presented in
Tables 2.1, 2.2 and 2.3 (Schedules 2.1, 2.2, and 2.3). Figure Bl shows the historical total energy
sales and forecast energy sales by customer class. Figure B2 shows the percentage of energy
sales by customer class (excluding the impacts of DSM) for the base year of 2013 and the
horizon year of 2022. Tables 2.4 through 2.12 (Schedules 3.1.1 - 3.3 .3) contain historical and
base, high, and low forecasts of seasonal peak demands and net energy for load. Table 2.13
(Schedule 4) compares actual and two-year forecast peak demand and energy values by month
for the 2012-2014 period.
2.1.1
SYSTEM LOAD AND ENERGY FORECASTS
The peak demand and energy forecasts contained in this plan are the results of the load
and energy forecasting study performed by the City.
The forecast is developed utilizing a
methodology that the City first employed in 1980, and has since been updated and revised every
one or two years. The methodology consists of thirteen multi-variable linear regression models
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Ten Year Site Plan
April 2013
Page 5
based on detailed examination of the system's historical growth, usage patterns and population
statistics. Several key regression formulas utilize econometric variables.
Table 2.14 lists the econometric-based linear regression forecasting models that are used
as predictors.
Note that the City uses regression models with the capability of separately
predicting commercial customers and consumption by rate sub-class: general service nondemand (GS), general service demand (GSD), and general service large demand (GSLD).
These, along with the residential class, represent the major classes of the City's electric
customers. In addition to these customer class models, the City's forecasting methodology also
incorporates into the demand and energy projections estimated reductions from interruptible and
curtailable customers. The key explanatory variables used in each of the models are indicated by
an "X" on the table.
Table 2.15 documents the City's internal and external sources for historical and forecast
economic, weather and demographic data. These tables summarize the details of the models
used to generate the system customer, consumption and seasonal peak load forecasts. In addition
to those explanatory variables listed, a component is also included in the models that reflect the
acquisition of certain Talquin Electric Cooperative (Talquin) customers over the study period
consistent with the territorial agreement negotiated between the City and Talquin and approved
by the FPSC.
The customer models are used to predict the number of customers by customer class,
which in turn serve as input into the customer class consumption models. The customer class
consumption models are aggregated to form a total base system sales forecast. The effects of
DSM programs and system losses are incorporated in this base forecast to produce the system net
energy for load (NEL) requirements.
Since 1992, the City has used two econometric models to separately predict summer and
winter peak demand. Table 2.14 also shows the key explanatory variables used in the demand
models. The seasonal peak demand forecasts are developed first by forecasting expected system
load factor. Based on the historical relationship of seasonal peaks to annual NEL, system load
factors are projected separately relative to both summer and winter peak demand. The predictive
variables for projected load factors versus summer peak demand include maximum summer
temperature, maximum temperature on the day prior to the peak, annual degree-days cooling and
real residential price of electricity.
For projected load factors versus winter peak demand
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April 2013
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minimum winter temperature, degree-days heating the day prior to the winter peak day, deviation
from a base minimum temperature of 22 degrees and annual degree-days cooling are used as
input. The projected load factors are then applied to the forecast of NEL to obtain the summer
and winter peak demand forecasts.
Some of the most significant input assumptions for the forecast are the incremental load
modifications at Florida State University (FSU), Florida A&M University (F AMU), Tallahassee
Memorial Hospital (TMH) and the State Capitol Center.
approximately 16% of the City's 2012 energy sales. Their incremental additions are highly
dependent upon annual economic and budget constraints, which would cause fluctuations in their
demand projections if they were projected using a model. Therefore, each entity submits their
proposed incremental additions/reductions to the City and these modifications are included as
submitted in the load and energy forecast.
The rate of growth in residential and commercial customers and energy use has decreased
in recent years. The City's energy efficiency and demand-side management (DSM) programs
(discussed in Section 2.1.3) played a role in these decreases along with the economic conditions
during and following the 2008-2009 recession.
According to the U.S. Energy Information
Administration's 2013 Annual Energy Outlook recovery from the recession is expected to
continue on a slow path. The slower economic growth in the near term has implications for the
long term, with a lower economic growth rate leading to a slower recovery in employment.
Therefore, it is not expected that base demand and energy growth will return to pre-recession
levels in the near future.
The City believes that the routine update of forecast model inputs, coefficients and other
minor model refinements continue to improve the accuracy of its forecast so that they are more
consistent with the historical trend of growth in seasonal peak demand and energy consumption.
The changes made to the forecast models for seasonal peak demands and annual sales/net energy
for load requirements has resulted in 2013 base forecasts for these characteristics that are lower
than the corresponding 2012 base forecasts.
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These four customers represented
Ten Year Site Plan
April 2013
Page 7
2.1.2
LOAD FORECAST UNCERTAINTY & SENSITIVITIES
To provide a sound basis for planning, forecasts are derived from projections of the
driving variables obtained from reputable sources. However, there is significant uncertainty in
the future 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 load can be
expected to vary from the forecast.
For various purposes, it is important to understand the
amount by which the forecast can be in error and the sources of error.
To capture this uncertainty, the City produces high and low range results that address
potential variance in driving population and economic variables from the values assumed in the
base case. The base case forecast relies on a set of assumptions about future population and
economic activity in Leon County. However, such projections are unlikely to exactly match
actual experience.
Population and economic uncertainty tends to result in a deviation from the trend over the
long term.
Accordingly, separate high and low forecast results were developed to address
population and economic uncertainty. These ranges are intended to capture approximately 80%
of occurrences (i.e. , 1.3 standard deviations). The high and low forecasts shown in this year' s
report use statistics provided by Woods & Poole Economics, Inc. (Woods & Poole) to develop a
range of potential outcomes. Woods & Poole publishes several statistics that define the average
amount by which various projections they have provided in the past are different from actual
results.
The City's load forecasting consultant, SAIC, interpreted these statistics to develop
ranges of the trends of economic activity and population representing approximately 80% of
potential outcomes. These statistics were then applied to the base case to develop the high and
low load forecasts presented in Tables 2.5, 2.6, 2.8, 2.9, 2.11 and 2.12 (Schedules 3.1.2, 3.1.3 ,
3.2.2, 3.2.3, 3.3.2 and 3.3.3).
Sensitivities on the peak demand forecasts are useful in planning for future power supply
resource needs. The graph shown in Figure 83 compares summer peak demand (multiplied by
117% for reserve margin requirements) for the three forecast sensitivity cases with reductions
from proposed DSM portfolio and the base forecast without proposed DSM reductions against
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effect of load growth and DSM performance variations on the timing of new resource additions.
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April 2013
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the City ' s existing and planned power supply resources. This graph allows for the review of the
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The highest probability weighting, of course, is placed on the base case assumptions, and the low
and high cases are given a smaller likelihood of occurrence.
2.1.3
ENERGY EFFICIENCY AND DEMAND SIDE MANAGEMENT PROGRAMS
The City currently offers a variety of conservation and DSM measures to its residential
and commercial customers, which are listed below:
Residential Measures
Commercial Measures
Energy Efficiency Loans
Energy Efficiency Loans
Gas New Construction Rebates
Demonstrations
Gas Appliance Conversion Rebates
Information and Energy Audits
Information and Energy Audits
Commercial Gas Conversion Rebates
Ceiling Insulation Grants
Ceiling Insulation Grants
Low Income Ceiling Insulation Grants
Solar Water Heater Rebates
Low Income HVAC/Water Heater Repair Grants
Solar PV Net Metering
Neighborhood REACH Weatherization Assistance
Demand Response (PeakSmart)
Energy Star Appliance Rebates
High Efficiency HV AC Rebates
Energy Star New Home Rebates
Solar Water Heater Rebates
Solar PV Net Metering
Duct Leak Repair Grants
Variable Speed Pool Pump Rebates
Nights & Weekends Pricing Plan
The City has a goal to improve the efficiency of customers' end-use of energy resources
when such improvements provide a measurable economic and/or environmental benefit to the
customers and the City utilities. During the City's last Integrated Resource Planning (IRP) Study
potential DSM measures (conservation, energy efficiency, load management, and demand
response) were tested for cost-effectiveness utilizing an integrated approach that is based on
projections of total achievable capacity and energy reductions and their associated annual costs
developed specifically for the City. The measures were combined into bundles affecting similar
end uses and /or having similar costs per kWh saved.
Ten Year Site Plan
April 2013
Page 9
An energy services provider (ESP) is under contract to assist staff in deploying a portion
of the City' s DSM program. This contract was renewed for an additional one-year term in
September 2012 and the ESP's work continues. Staff has worked with consultants and the ESP
to develop operational and pricing parameters, craft rate tariffs and solicit participants for a
commercial pilot DR/DLC measure.
This measure is currently at about 40% of targeted
enrollment and the system is scheduled for testing in the coming months. Implementation of the
City ' s residential demand response/direct load control (DR/DLC) measures has been delayed as
some of the technology to be employed is still evolving. Otherwise, work continues with the
City's Neighborhood REACH/Low-Income Assistance measure and participation in the City's
other existing DSM measures continues to increase. Future activities include development of
residential DR/DLC and expanding commercial demand reduction and energy efficiency
measure offerings.
As discussed in Section 2.1.1 the growth in customers and energy use has been negatively
impacted by the economic conditions observed during and following the 2008-2009 recession. It
appears that many customers have taken steps on their own to reduce their energy use and costs
in response to the changing economy - without taking advantage of the incentives provided
through the City's DSM program. These "free drivers" effectively reduce potential participation
in the DSM program in the future. And it is questionable whether these customers ' energy use
reductions will persist beyond the economic recovery. History has shown that post-recession
energy use generally rebounds to pre-recession levels. In the meantime, however, demand and
energy reductions achieved as a result of these voluntary customer actions as well as those
achieved by customer participation in City-sponsored DSM measures appear to have had a
considerable impact on forecasts of future demand and energy requirements .
For these reasons estimates of the actual demand and energy savings realized from 20072012 attributable to the City ' s DSM efforts are below those projected in the last IRP study. Due
to reduced load and energy forecasts and based on the City's experience to date DSM program
participation and thus associated demand and energy savings are not expected to increase as
rapidly as originally projected, at least not in the near term. Therefore, the City has revised its
projections of DSM demand and energy savings versus those reported in the 2012 TYSP. These
revised projections reflect a slower growth of DSM savings in the near term while maintaining
the program demand and energy savings objectives in the long-term.
Ten Year Site Plan
April 2013
Page 10
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Staff will continue to periodically review and, where appropriate, update technical and
economic assumptions, expected demand and energy savings and re-evaluate the costeffectiveness of current and prospective DSM measures. The City will provide further updates
regarding its progress with and any changes in future expectations of its DSM program in
subsequent TYSP reports.
Energy and demand reductions attributable to the DSM portfolio have been incorporated
into the future load and energy forecasts .
Tables 2.16 and 2.17 display, respectively, the
cumulative potential impacts of the proposed DSM portfolio on system annual energy and
seasonal peak demand requirements . Based on the anticipated limits on annual control events it
is expected that DR/DLC will be predominantly utilized in the summer months. Therefore,
while Table 2.17 reflects expected winter DR/DLC capability, Tables 2.7-2.9 reflect no expected
utilization of that capability to reduce winter peak demand.
2.2
ENERGY SOU RCES AND FUEL REQU IREMENTS
Tables 2.18 (Schedule 5), 2. 19 (Schedule 6. 1), and 2.20 (Schedule 6.2) present the
projections of fuel requirements, energy sources by resource/fuel type in gigawatt-hours, and
energy sources by resource/fuel type in percent, respectively, for the period 2013-2022. Figure
B4 displays the percentage of energy by fuel type in 2013 and 2022 .
The
City's
generation portfolio
includes
combustion
turbine/combined cycle,
combustion turbine/simple cycle, conventional steam and hydroelectric units.
The City's
combustion turbine/combined cycle and combustion turbine/simple cycle units are capable of
generating energy using natural gas or distillate fuel oil. Natural gas and residual fuel oil may be
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burned concurrently in one of the City's steam units. This mix of generation types coupled with
opportunities for firm and economy purchases from neighboring systems provides allows the
City to satisfy its total energy requirements consistent with our energy policies that seek to
balance the cost of power with the environmental quality of our community.
The projections of fuel requirements and energy sources are taken from the results of
computer simulations using the PROSYM production simulation model (provided by Ventyx)
and are based on the resource plan described in Chapter III.
Ten Year Site Plan
April 2013
Page 11
Cit:y Of Tallahassee
Schedule 2.1
Histo ry and Forecast of Energy Consumption and
Number of Customers by Customer Class
Base Load Forecast
(!)
(2)
(3)
(4)
(5)
(6)
(7)
Rural & Residential
Population
-I
co
:::i
-u
l> -<
Ol ""Cl co
co -~. cu
~
N en
N~~
w
CO
-u
ill
:::i
Members
Per
Household
(GWh)
Average
No. of
Customers
m
(8)
Commercial [4]
Average
No. of
Customers
(9)
(GWh)
LlJ
Average kWh
Consumption
Per Customer
m
LlJ
Average kWh
Consumption
Per Customer
Year
ill
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
258,627
265,393
269,619
272,648
273,684
274,926
275,059
275,783
277,014
278,438
1,035
1,064
1,088
1,097
1,099
1,054
1,050
1, 136
1, 117
1,032
82,219
85 ,035
89,468
92,017
93,569
94,640
94,827
95,268
95 ,794
96,479
12,583
12,512
12,164
11 ,927
11,744
11,132
11 ,071
11,928
11,665
10,694
1,555
1,604
1,622
1,601
1,657
1,626
1,611
1,618
1,598
1,572
17,289
17,729
18,3 12
18,533
18,583
18,597
18,478
18,426
18,418
18,445
89,942
90,447
88,564
86,394
89, 169
87,421
87, 180
87,812
86,772
85 ,235
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
280,372
282, 112
284, 154
286,716
289,303
291,911
294,542
297,121
299,588
302,076
1,096
1,096
1,098
1, 102
1, 107
1, 111
1, 116
1, 120
1, 125
1, 129
97,337
98,061
98,910
99,972
IO 1,045
102 , 126
103,217
104,287
105,310
106,342
11,258
11 , 178
11 , 100
11 ,025
10,952
10,88 0
10,8 11
10,744
10,679
10,6 15
1,6 11
1,622
1,638
1,645
1,651
1,657
1,662
1,666
1,669
1,670
18,563
18,647
18,745
18,867
18,99 1
19, 115
19,241
19,364
19,482
19,601
86,781
86,964
87,378
87, 168
86,951
86,692
86,394
86,052
85,657
85,223
[l]
[2]
[3]
(4]
Population data represents Leon County population.
Values include DSM Impacts.
Average end-of-month customers for the calendar year. Marked increase in residential customers between 2004 and 2005 due to change in
internal customer accounting practices.
As of2007 "Commercial" includes General Service Non-Demand, General Service Demand, Genera l Service Large Demand
Interruptible (FSU and Goose Pond), Curtailable (TMH), Traffic Control, Security Lights and Street & Highway Light ~
-I
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co
N
- -- - - - - - - - - - - - - - - - City Of Tallahassee
Schedule 2.2
History and Forecast of Energy Consumption and
Number of Customers by Customer Class
Base Load Forecast
(1)
(2)
(3)
Industrial
Average
No. of
Customers
Year
-I
Cl)
:::>
"'O )>
-<
Q)
"O
Cl)
C1l
N
(/)
co ~
- . cu
,
~~~
(;.l
"'O
Q)
:::>
ill
(4)
Average kWh
Consumption
Per Customer
(5)
Railroads
and Railways
(GWh)
(6)
Street &
Highway
Lighting
(7)
(GWh)
Other Sales
to Public
Authorities
ill
CGWh)
(8)
Total Sales
to Ultimate
Consumers
(GWh)
ill
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
12
14
14
15
0
0
0
0
0
0
2,602
2,682
2,724
2,714
2,756
2,679
2,661
2,754
2,716
2,604
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
0
0
0
0
0
0
0
0
0
0
2,707
2,718
2,736
2,747
2,758
2,768
2,778
2,787
2,793
2,799
[1]
[2]
[3]
Average end-of-month customers for the calendar year.
As of 2007 Security Lights and Street & Highway Lighting use is included with Commercial on Schedule 2.1.
Values include DSM Impacts.
City Of Tallahassee
Schedule 2.3
History and Forecast of Energy Consumption and
Number of Customers by Customer Class
Base Load Forecast
-I
CD
::J
lJ )>
Ql
"O
CD
N
0
cc -~ .
~
~ ~
-<
CD
Q)
~
en
- ·
ro
lJ
ti)
::J
(1)
(2)
(3)
Year
Sales for
Resale
CGWh)
Utility Use
& Losses
(GWh)
2003
2004
2005
2006
2007
2008
2009
20 10
20 11
20 12
0
0
0
0
0
0
0
0
0
0
20 13
20 14
20 15
20 16
20 17
20 18
20 19
2020
202 1
2022
0
0
0
0
0
0
0
0
0
0
(4)
Net Energy
for Load
(GWh)
(5)
(6)
Total
No. of
Customers
ill
Other
Customers
(Average No.)
153
160
164
154
158
154
140
177
83
106
2,755
2,84 1
2,887
2,868
2,9 14
2,834
2,80 1
2,93 1
2,799
2,7 10
0
0
0
0
0
0
0
0
0
0
99,508
102,764
107,780
11 0,550
11 2, 152
11 3,237
11 3,305
113,693
11 4,2 12
11 4,924
16 1
162
163
163
164
165
165
166
166
166
2,868
2,879
2,898
2,910
2,922
2,933
2,943
2,952
2,959
2,966
0
0
0
0
0
0
0
0
0
0
11 5,90 1
11 6,708
117,655
11 8,839
120,036
12 1,242
122,459
123,65 1
124,793
125,944
ill
-I
Ql
[l]
[2]
Va lues include DSM Impacts.
Average number of customers fo r the calendar year.
O"
ro
N
w
------------------History and Forecast Energy Consumption
By Customer Class (Including DSM Impacts)
Gigawatt-Hours (GWh)
3,200
2,800
2,400
-I
CD
2,000
::l
-u
QJ
<C
CD
~
t1l
)>
~
I\.)
0
~
(;.)
-<
CD
~
(fJ
~
•- •.... -• • • •
• - - • •.... •-
-
- -
--
- - - - -
nm
:i:i:
118
- - - -- -- --
-
-• -•
-
- - - -
-
- -
~
.;..
'T
1,600
-u
m
::l
1,200
~
:::::
::::
~
T..
llill
~
Tim
i±
till
~
:; :::
J
m::
0 w 1w
~
TI8
i,;i;i
IT!
~
lllli
4
:::::
.....
~
7
~
Jill
Jill
7
lili
""'
·11:1
"'"'
.;ill
7
~
800
400
0
R:J(o
R:JC)
R:J'\
R:J%
~~
R:J'?
~"v
~ R:J':i
"v\:S
"v\:S
"v\:S
"v\:S
"v\:S
"v\:S
"v\:S
"v~
"v~~" "v\;;)
Calendar Year
• Traffic/Street/Security Lights
CJ Curtail/Interrupt
CJ Large Demand
DDemand
ON on-Demand
D Residential
Figure 82
Energy Consumption By Customer Class
(Excluding DSM Impacts)
Calendar Year 2013
1%
Total 2013 Sales = 2, 722 GWh
Calendar Year 2022
1%
3%
Total 2022 Sales= 2,967 GWh
D Residential
DNon-Demand
DDemand
~
D Curtail/Interrupt
• Traffic/Street/Security Lights
Large Demand
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Ten Year Site Plan
April 2013
Page 16
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--------------------City Of Tallahassee
Schedule 3.1.1
History and Forecast of Summer Peak Demand
Base Forecast
(MW)
( I)
--i
(1)
:J
l l )>
-<
OJ
"'Cl
(1)
<1l
N
(/)
cc ~ ~
~ (;.)
~
;:
ll
Qi"
:J
(2)
(3)
Retail
(5)
(6)
(7)
Residential
Load
Residential
Management Conservation
Year
Total
2003
2004
2005
2006
2007
2008
2009
2010
201 1
20 12
549
565
598
577
62 1
587
605
60 1
590
558
549
565
598
577
62 1
587
605
60 1
590
558
0
2013
2014
20 15
20 16
2017
20 18
20 19
2020
202 1
2022
59 1
597
604
609
615
621
627
633
639
645
591
597
604
609
615
62 1
627
633
639
645
0
0
5
11
16
21
23
24
24
24
[1]
[2]
[3]
Wholesale
(4)
Interruptible
Va lues include DSM Impacts.
Reduction estimated at bus bar. 20 12 DSM is actual at peak.
2012 values reflect incremental increase from 20 11 .
ill
111.IB
2
4
6
8
IO
12
15
17
19
22
(8)
Comm.find
Load
Management
(9)
( I0)
Comm.find
Conservation
Net Firm
Demand
ill
111.IB
ill
0
0
549
565
598
577
62 1
587
605
601
590
557
8
17
17
17
17
17
17
17
17
18
2
4
5
7
10
12
15
18
21
I
579
574
572
567
564
56 1
560
560
560
560
City Of Tallahassee
Schedule 3.1.2
History and Forecast of Summer Peak Demand
High Forecast
(MW)
(1)
-I
CD
::i
OJ "O
-<
CD
CD
(/)
-0 )>
co ~ ~
N
00 w
~ ~
-0
ii)
::i
(2)
(3)
(4)
(5)
(6)
(7)
Residential
Load
Residential
Management Conservation
Year
Total
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
549
565
598
577
621
587
605
601
590
558
549
565
598
577
621
587
605
601
590
558
0
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
605
614
624
634
644
654
664
674
684
694
605
614
624
634
644
654
664
674
684
694
0
0
5
11
16
21
23
24
24
24
[1]
[2]
[3]
Wholesale
Retail
Interruptible
Values include DSM Impacts.
Reduction estimated at bus bar. 2012 DSM is actual at peak.
2012 values reflect incremental increase from 2011 .
ill
m...m
2
4
6
8
10
12
15
17
19
22
(8)
Comm./lnd
Load
Management
ill
(9)
(10)
Comm./lnd
Conservation
Net Firm
Demand
m...m
ill
0
0
549
565
598
577
621
587
605
601
590
557
8
17
17
17
17
17
17
17
17
18
2
4
5
7
10
12
15
18
21
593
591
592
592
593
594
597
601
605
609
------------
-----
City Of Tallahassee
Schedule 3.1.3
History and Forecast of Summer Peak Demand
Low Forecast
(MW)
(I)
-I
Cl>
:J
"U l>
Q)
<O
Cl>
"'O
-<
Cl>
~ ~
N en
tO ~ ;:
(>.)
"U
al
:J
(2)
(3)
Retail
(5)
(6)
(7)
Residential
Residential
Load
Management Conservation
Interruptible
m
Year
Total
2003
2004
2005
2006
2007
2008
2009
20 10
20 11
2012
549
565
598
577
621
587
605
601
590
558
549
565
598
577
621
587
605
60 1
590
558
0
20 13
20 14
2015
2016
2017
20 18
2019
2020
202 1
2022
578
580
583
585
587
589
590
592
594
595
578
580
583
585
587
589
590
592
594
595
0
0
5
11
16
21
23
24
24
24
[I]
[2]
[3]
Wholesale
(4)
Values include DSM Impacts.
Reduction estimated at bus bar. 20 12 DSM is actual at peak.
2012 va lues reflect incremental increase from 20 11.
J11..ill
2
4
6
8
10
12
15
17
19
22
(8)
Comm.find
Load
Management
(9)
(10)
Comm./lnd
Conservation
et Firm
Demand
J11..ill
ill
0
0
549
565
598
577
62 1
587
605
601
590
557
8
17
17
17
17
17
17
17
17
18
1
2
4
5
7
10
12
15
18
21
566
557
55 1
543
536
529
523
519
515
510
m
City Of Tallahassee
Schedule 3.2.1
History and Forecast of Winter Peak Demand
Base Forecast
(MW)
( 1)
(2)
Year
-I
CD
:::J
"'O )>
OJ
(Q
CD
N
o
"'O
-<
CD
~ ~
N
0
~
en
- ·
CD
31
OJ
:::J
Total
(3)
Wholesale
(4)
Retail
(5)
Interruptible
(6)
(7)
Residential
Load
Residential
Management Conservation
Ll1..ill
Illli1
(8)
Comm./Ind
Load
Management
(9)
(10)
Comm .find
Conservation
Net Firm
Demand
Ll1..ill
Illli1
ill
2003
2004
2005
2006
2007
2008
2009
20 10
20 11
20 12
-2004
-2005
-2006
-2007
-2008
-2009
-20 10
-2011
-20 12
-2013
590
509
532
537
528
526
579
633
584
518
590
509
532
537
528
526
579
633
584
518
0
2
0
0
590
509
532
537
528
526
579
633
584
5 16
20 13
20 14
2015
2016
2017
2018
20 19
2020
2021
2022
-2014
-2015
-20 16
-2017
-2018
-20 19
-2020
-2021
-2022
-2023
547
554
559
564
570
575
581
586
591
597
547
554
559
564
570
575
581
586
59 1
597
0
0
0
0
0
0
0
0
0
0
5
7
10
12
14
16
18
20
23
25
0
0
0
0
0
0
0
0
0
0
2
3
4
5
7
9
11
13
16
19
540
544
546
547
549
550
552
552
552
554
[l]
[2]
[3]
[4]
Values include DSM Impacts.
Reduction estimated at busbar. 2012 DSM is actual at peak.
Reflects no expected utilization of demand response (DR) resources in winter. Winter DR capability presented in Table 2. 17.
20 12 values reflect incremental increase from 20 11.
-I
OJ
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ro
N
-.J
------------------City Of Tallahassee
Schedule 3.2.2
History and Forecast of Winter Peak Demand
High Forecast
(MW)
(I)
(2)
Year
-;
ct>
:J
-u
Q)
co
)>
"O
~ ~
Ul
ct>
I\.)
I\.)
0
...J.
-<
ct>
c:;
- ·
Ci)
-u
OJ
:J
Total
(3)
Wholesale
(4)
Retail
(5)
Interruptible
(6)
(7)
Residential
Load
Residential
Management Conservation
ru...ru
UL.HJ
(8)
Comm./lnd
Load
Management
(9)
(I 0)
Comm./Ind
Conservation
Net Firm
Demand
ru...ru
UL.HJ
ill
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
-2004
-2005
-2006
-2007
-2008
-2009
-2010
-2011
-2012
-2013
590
509
532
537
528
526
579
633
584
518
590
509
532
537
528
526
579
633
584
518
0
2
0
0
590
509
532
537
528
526
579
633
584
516
2013
20 14
2015
2016
2017
2018
2019
2020
2021
2022
-20 14
-20 15
-2016
-2017
-2018
-2019
-2020
-2021
-2022
-2023
563
573
582
591
600
609
618
628
637
647
563
573
582
591
600
609
618
628
637
647
0
0
0
0
0
0
0
0
0
0
5
7
10
12
14
16
18
20
23
25
0
0
0
0
0
0
0
0
0
0
2
3
4
5
7
9
II
13
16
19
556
563
569
574
579
584
589
594
598
604
[I]
[2]
[3]
[4]
Values include DSM Impacts.
Reduction estimated at busbar. 2012 DSM is actual at peak.
Reflects no expected utilization of demand response (DR) resources in winter. Winter DR capability presented in Table 2.17.
2012 values reflect incremental increase from 2011.
City Of Tallahassee
Schedule 3.2.3
History and Forecast of Winter Peak Demand
Low Forecast
(MW)
(1)
(2)
Year
-I
Cl)
:::J
-0 )>
tll "'D
-<
Cl)
co ~ ~
Cl)
" ' Ul
"'0
-·
~~CD
-0
Q)
:::J
Total
(3)
Wholesale
(4)
Retail
(5)
Interruptible
(6)
(7)
Residential
Load
Residential
Management Conservation
l11.ll1
I21H1
(8)
Comm./Ind
Load
Management
(9)
(10)
Comm./lnd
Conservation
Net Firm
Demand
l11.ll1
I21H1
ill
2003
2004
2005
2006
2007
2008
2009
20 10
2011
20 12
-2004
-2005
-2006
-2007
-2008
-2009
-2010
-2011
-2012
-2013
590
509
532
537
528
526
579
633
584
518
590
509
532
537
528
526
579
633
584
518
0
2
0
0
590
509
532
537
528
526
579
633
584
5 16
20 13
2014
20 15
2016
20 17
2018
20 19
2020
2021
2022
-2014
-20 15
-20 16
-20 17
-2018
-20 19
-2020
-2021
-2022
-2023
532
535
537
538
540
542
544
545
546
548
532
535
537
538
540
542
544
545
546
548
0
0
0
0
0
0
0
0
0
0
5
7
10
12
14
16
18
20
23
25
0
0
0
0
0
0
0
0
0
0
2
3
4
5
7
9
11
13
16
19
525
525
524
521
5 19
517
515
511
507
505
[I]
[2]
[3]
[4]
Values include DSM Impacts.
Reduction estimated at busbar. 2012 DSM is actual at peak.
Reflects no expected utilization of demand response (DR) resources in winter. Winter DR capability presented in Table 2.17.
20 12 values reflect incremental increase from 20 11.
-I
tll
O"
ro
"'
(o
____
__________
_
---,
City Of Tallahassee
Schedule 3.3.1
History and Forecast of Annual Net Energy for Load
Base Forecast
(GWh)
--i
Cl)
::i
"U )>
OJ
"
-<
Cl)
cc ~ ~
C1l
N
rv o
w
w
(/)
;:::+:
Ct>
"U
ti)
::i
(I)
(2)
Year
Total
Sales
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2,602
2,682
2,724
2,714
2,756
2,679
2,661
2,754
2,716
2,611
20 13
2014
2015
2016
2017
2018
2019
2020
2021
2022
2,722
2,746
2,778
2,804
2,831
2,859
2,887
2,914
2,940
2,967
[I]
[2]
[3]
(3)
(4)
(5)
Residential
Conservation
Comrn./lnd
Conservation
Retail
Sales
mm
mm
ill
7
0
2,602
2,682
2,724
2,714
2,756
2,679
2,661
2,754
2,716
2,604
11
20
30
39
48
58
67
76
86
95
4
8
13
19
25
33
41
51
61
72
2,707
2,718
2,736
2,747
2,758
2,768
2,778
2,787
2,793
2,799
Values include DSM Impacts.
Reduction estimated at customer meter. 2012 DSM is actual.
2012 values reflect incremental increase from 2011.
(8)
(9)
Net Energy
for Load
Load
Factor %
ill
ill
153
160
164
154
158
154
140
177
83
106
2,755
2,841
2,887
2,868
2,914
2,834
2,801
2,931
2,799
2,710
57
57
55
57
54
55
53
56
54
56
161
162
163
163
164
165
165
166
166
166
2,868
2,879
2,898
2,910
2,922
2,933
2,943
2,952
2,959
2,966
57
57
58
59
59
60
60
60
60
61
(6)
(7)
Wholesale
Utility Use
& Losses
City Of Tallahassee
Schedule 3.3.2
History and Forecast of Annual Net Energy for Load
High Forecast
(GWh)
-I
(!)
:J
Ll l>
QJ
"O
-<
(!)
cc ~ ~
" ' Ul
"'0
-·
~ ~ CD
(!)
Ll
OJ
:J
( 1)
(2)
Year
Total
Sales
2003
2004
2005
2006
2007
2008
2009
20 10
20 1 l
20 12
2,602
2,682
2,724
2,7 14
2,756
2,679
2,661
2,754
2,7 16
2,6 11
20 13
20 14
20 15
20 16
20 17
20 18
20 19
2020
202 1
2022
2,783
2,825
2,873
2,9 17
2,963
3,009
3,057
3,103
3, 149
3,196
[l]
[2]
[3]
(3)
(4)
(5)
Residential
Conservati on
Comm .find
Conservation
Retail
Sales
ru.,_ru
ru.,_ru
ill
7
0
2,602
2,682
2,724
2,7 14
2,756
2,679
2,66 1
2,754
2,7 16
2,604
11
20
30
39
48
58
67
76
86
95
4
8
13
19
25
33
41
51
61
72
2,768
2,796
2,83 1
2,860
2,890
2,9 19
2,949
2,975
3,002
3,028
Values include DSM Impacts.
Reduc ti on estimated at customer meter. 20 12 DSM is actual.
20 12 values reflect incremental increase fro m 20 11 .
(6)
(7)
Wholesale
Util ity Use
& Losses
(8)
(9)
Net Energy
for Load
Load
Factor %
ill
ill
153
160
164
154
158
154
140
177
83
106
2,755
2,84 1
2,887
2,868
2,9 14
2,834
2,80 1
2,93 1
2,799
2,7 10
57
57
55
57
54
55
53
56
54
56
164
166
168
170
172
173
175
177
178
180
2,932
2,962
2,999
3,030
3,062
3,092
3,124
3,152
3,180
3,208
56
57
58
58
59
59
60
60
60
60
--------------- ·- --City Of Tallahassee
Schedule 3.3.3
History and Forecast of Annual Net Energy for Load
Low Forecast
(GWh)
_,
Cl>
:J
IJ
Q)
co
Cl>
N
01
)>
-<
"O
Cl>
N
0
(n
-·
~ ~
~
co
IJ
iii""
:J
(I)
(2)
Year
Total
Sales
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2,602
2,682
2,724
2,714
2,756
2,679
2,661
2,754
2,716
2,611
20 13
2014
2015
2016
2017
20 18
20 19
2020
2021
2022
2,661
2,668
2,684
2,692
2,700
2,710
2,718
2,727
2,734
2,740
[1]
[2]
[3]
(3)
(4)
(5)
Residential
Conservation
Comm./lnd
Conservation
Retail
Sales
J11...ill
J11...ill
ill
7
0
2,602
2,682
2,724
2,714
2,756
2,679
2,661
2,754
2,716
2,604
II
20
30
39
48
58
67
76
86
95
4
8
13
19
25
33
41
51
61
72
2,646
2,640
2,641
2,635
2,627
2,619
2,609
2,600
2,587
2,573
Values include DSM Impacts.
Reduction estimated at customer meter. 2012 DSM is actual.
2012 values reflect incremental increase from 201 I.
(8)
(9)
Net Energy
for Load
Load
Factor %
ill
ill
153
160
164
154
158
154
140
177
83
106
2,755
2,84 1
2,887
2,868
2,9 14
2,834
2,801
2,931
2,799
2,710
57
57
55
57
54
55
53
56
54
56
157
157
157
157
156
156
155
155
154
153
2,804
2,797
2,798
2,791
2,783
2,775
2,765
2,755
2,741
2,726
57
57
58
59
59
60
60
61
61
61
(6)
(7)
Wholesale
Utility Use
& Losses
_,
Q)
o-
m
N
City Of Tallahassee
Schedule 4
Previous Year and 2-Year Forecast of Retail Peak Demand and Net Energy for Load by Month
(1)
-i
Cl>
:J
lJ )>
-<
Q)
"O
Cl>
<O
Cl>
N
Ul
~ ~
~ (;)Cl>
~;::;:
lJ
ti)
:J
Month
January
February
March
April
May
June
July
August
September
October
November
December
TOTAL
[l]
[2]
(2)
2012
Actual
Peak Demand
(MW)
516
494
394
469
515
518
557
528
493
432
400
395
(3)
NEL
(GWh)
(4)
(5)
2013
Forecast [I )[2]
Peak Demand
NEL
(MW)
(GWh)
213
195
206
204
244
245
276
265
247
219
192
205
539
470
384
452
535
579
579
579
538
454
359
421
2,710
233
211
209
21 l
249
272
288
294
261
219
197
224
2,868
Peak Demand and NEL include DSM Impacts.
Represents forecast values for 2013 .
(6)
2014
Forecast [1]
Peak Demand
(MW)
541
471
386
454
537
574
574
574
540
456
360
422
(7)
NEL
(GWh)
234
212
210
212
250
273
290
295
262
219
198
225
2,879
-i
Q)
CJ
ro
N
~
(;)
________ __________ _
,
- ----------------City of Tallahassee, Florida
2013 Electric System Load Forecast
Key Explanatory Variables
Leon
Cooling
County Residential Degree
Ln.
Days
__Q, ~~~~~~M.
~
o_de_l_N
_a_m~
e ~~~~~- Population Customers
Residential Customers
Residential Consumption
Florida State University Consumption
Florida A&M. University Consumption
General Service Non-Demand Customers
General Service Demand Customers
General Service Non-Demand Consumptio1
General Service Demand Consumption
General Service Large Demand Consumption
Summer Peak Demand
11 Winter Peak Demand
2
3
4
5
6
7
8
9
I0
x
x
x
x
x
x
x
Tal lahassee
Minimum Maximum
Heating Per Capita
State of
Winter Summer
Degree Taxable
Florida Peak day Peak day Appliance R Squared
Price of
Days
Sales
Temp. Saturation
ill
Electricity Population Temp.
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
[I] R Squared, sometimes called the coefficient of determination, is a commonly used measure of goodness of fit of a linear model. If the observations fa ll on
the model regression line, R Squared is 1. If there is no linear relationship between the dependent and independent variable, R Squared is 0. A rea sonably
good R Squared value could be anywhere from 0.6 to I.
0.994
0.920
0.930
0.926
0.996
0.987
0.956
0.979
0.933
0.914
0.880
Table 2.15
City of Tallahassee
2013 Electric System Load Forecast
Sources of Forecast Model Input Information
Energy Model Input Data
1.
2.
3.
4.
5.
6.
7.
8.
9.
I 0.
11.
12.
13.
14.
15.
16.
17.
18.
19.
20.
21.
22.
Leon County Population
Talquin Customers Transferred
Cooling Degree Days
Heating Degree Days
AC Saturation Rate
Heating Saturation Rate
Real Tallahassee Taxable Sales
Florida Population
State Capitol Incremental
FSU Incremental Additions
F AMU Incremental Additions
GSLD Incremental Additions
Other Commercial Customers
Tall. Memorial Curtailable
System Peak Historical Data
Historical Customer Projections by Class
Historical Customer Class Energy
GDP Forecast
CPI Forecast
Interruptible, Traffic Light Sales, &
Security Light Additions
Historical Residential Real Price of Electricity
Historical Commercial Real Price Of Electricity
Bureau of Economic and Business Research
City Power Engineering
NOAA reports
NOAA reports
Appliance Saturation Study
Appliance Saturation Study
Florida Department of Revenue, CPI
Bureau of Economic and Business Research
Department of Management Services
FSU Planning Department
FAMU Planning Department
City Utility Services
City Utility Services
System Planning/ Utilities Accounting
City System Planning
System Planning & Customer Accounting
System Planning & Customer Accounting
Blue Chip Economic Indicators
Blue Chip Economic Indicators
System Planning & Customer Accounting
Calculated from Revenues, kWh sold, CPI
Calculated from Revenues, kWh sold, CPI
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
Ten Year Site Plan
April 2013
Page 28
I
I
------------------Banded Summer Peak Load Forecast Vs. Supply Resources
(Load Includes 17°/o Reserve Margin)
Megawatts (MW)
950
900 850 800 -
~
750 700 650 -
..
-
~
-
--.
-.
...~
.
~
-
-.
600 -
~
~
.
-=-
-
--
-
-.
-.
-
~
~
~
-
.
2017
2018
-
--
-.
550 500
I
2013
2014
2015
2016
I
I
2019
2020
I
2021
2022
Calendar Year
"TI
c:::::JSupply
-+-Base w/ DSM
---High w/ DSM
___._Low w/ DSM
~Base w/o DSM
c0·
c
Cil
OJ
w
Table 2.16
City Of Tallahassee
2013 Electric System Load Forecast
Projected Demand Side Management
Energy Reductions [1]
Calendar Year Basis
Commercial
Impact
Tota l
Impact
Year
Residentia l
[mpact
(MWh)
(MWh)
(MWh)
20 13
20 14
20 15
20 16
20 17
20 18
20 19
2020
202 1
2022
11 ,345
2 1,306
3 1,265
4 1,222
51, 178
6 1, 131
71,083
81,03 4
90,982
100,929
4,556
8,632
13,692
19,736
26,764
34,776
43 ,772
53 ,75 1
64,7 15
76,663
15,902
29,938
44,957
60,958
77 ,941
95,907
114,8 55
134,785
155 ,698
177,592
[ 1]
Reducti ons esti mated at generator busbar.
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
Ten Year Site Plan
April 2013
Page 30
I
I
------------------City Of Tallahassee
2013 Electric System Load Forecast
Projected Demand Side Management
Seasonal Demand Reductions [1]
Year
-I
Cl>
:J
IJ l>
tlJ ""CJ
<C
-<
Cl>
Residential
Commercia l
Residential
Commercia l
Demand Side
Energy Efficiency
Energy Effic iency
Demand Response
Demand Response
Management
Impact
Impact
Impact
Impact
Total
Summer
Winter
Summer
Winter
Summer
Winter [2]
Summer
Winter [2]
Summer
Winter
(MW)
(MW)
(MW)
(MW)
(MW)
(MW)
(MW)
(MW)
2
0
0
8
17
12
23
32
Summer
Winter
(MW)
(MW)
2013
2013-2014
2
5
2014
20I4-2015
4
7
2
3
0
5
17
17
23
2015
2015-2016
6
IO
4
4
5
11
17
17
32
42
20 16
2016-2017
8
12
5
5
II
16
17
17
42
51
2017
2017-2018
IO
14
7
7
16
21
17
17
51
59
2018
2018-2019
12
16
10
9
21
23
17
17
60
66
2019
2019-2020
15
18
12
11
23
24
17
17
67
71
2020
2020-2021
17
20
15
13
24
24
17
17
73
75
2021
2021 -2022
19
23
18
16
24
24
17
18
79
80
2022
2022-2023
22
25
21
19
24
24
18
18
85
85
~ ~
Cl>
N (/)
0;::;:
~ ~ (t)
(.,J
IJ
ti)
:J
[ l]
Reductions estimated at bus bar.
[2]
Represents projected winter peak reduction capability associated with demand response (DR) resource. However, as reflected on Schedules 3.1.13.2.3 (Tables 2.4-2.9), DR utilization expected to be predominantly in the summer months .
-I
tlJ
rr
ro
N
City Of Tallahassee
Schedule 5
Fuel Requirements
(2)
(3)
Fuel Reguirements
Nuclear
-j
C1l
Coal
(4)
(5)
(6)
(7)
(8)
(9)
(10)
( 11)
(12)
(13)
( 14)
( 15)
(16)
Units
Actual
2011
Actual
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
Billion Btu
0
0
0
0
0
0
0
0
0
0
0
0
1000 Ton
0
0
0
0
0
0
0
0
0
0
0
0
1000
1000
1000
1000
1000
BBL
BBL
BBL
BBL
BBL
4
4
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
0
0
0
0
0
0
0
0
0
0
0
0
0
1000
1000
1000
1000
1000
BBL
BBL
BBL
BBL
BBL
I
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
0
0
0
0
0
0
0
0
0
0
0
1000
1000
1000
1000
1000
MCF
MCF
MCF
MCF
MCF
21 ,745
1,746
19,209
790
0
20,691
2,209
17,621
862
0
22, 121
1,299
19,436
1,386
0
22 ,770
I ,233
19,006
2,531
0
22 ,062
851
20,082
1,129
0
22, 163
949
19,894
1,320
0
22 ,089
1,085
19,811
1,193
0
22 ,194
867
20,243
1,084
0
22 ,150
966
19,925
1,259
0
21 ,863
32
20, 16 1
1,670
0
21 ,830
0
21 ,028
802
0
21 ,845
0
21 ,402
443
0
Trillion Btu
0
0
0
0
0
0
0
0
0
0
0
0
:J
-<
-u )>
tll "O C1l
<O ~ ~
Residual
ro
"' en
w 0""
N
Total
Steam
cc
~Ct>
-u
CT
Diesel
OJ
:J
Distillate
Total
Steam
cc
CT
Diesel
Natural Gas
Tota l
Steam
cc
CT
Diesel
Other (Specify)
0
0
I
-j
tll
0-
ro
!'.l
CXl
------------------City Of Tallahassee
Schedule 6.1
Energy Sources
(!)
(2)
(3)
(4)
(5)
(6)
Actu al
Actual
2Qll
WU
Energy Sources
(8)
(7)
(10)
(9)
( 12)
( 11)
(13)
(15)
( 14)
(16)
(!)
Annual Finn lnterchange
GWh
97
98
24
25
25
28
29
27
28
36
27
27
(2)
Coal
GWh
0
0
0
0
0
0
0
0
0
0
0
0
(3)
Nuclear
GWh
0
0
0
0
0
0
0
0
0
0
0
0
(4)
(5)
(6)
(7)
(8)
Residual
G Wh
GWh
GWh
GWh
GWh
2
2
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
(9)
Distillate
GWh
GWh
GWh
GWh
GWh
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
GWh
GWh
GWh
GWh
GWh
2,703
131
2501
71
0
2,509
168
2265
76
0
2,867
105
2,632
130
0
2,884
104
2,571
209
0
2,896
71
27 18
107
0
2,903
80
2697
126
2,911
92
2694
125
0
6
10
IO
10
Total
Steam
cc
CT
Diese l
(IO)
Total
Steam
cc
(!!)
(12)
(13)
CT
Diese l
Tota l
Steam
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2,928
82
2714
132
0
2,929
3
2751
175
0
2,946
0
2,928
74
2,74 1
113
0
10
10
10
10
10
10
0
0
2,954
0
2908
46
(1 4)
( 15)
(16)
( 17)
( 18)
Natura l Gas
( 19)
Hydro
GWh
(20)
Economy Interchange( I]
GWh
-8
97
-34
-41
-33
-29
-28
-33
-23
-22
-24
-25
(2 1)
Renewables
GW h
0
0
0
0
0
0
0
0
0
0
0
0
(22)
Net Energy for Load
GWh
2,799
2,710
2,868
2,879
2,898
2,9 10
2,922
2,933
2,943
2,952
2,959
2,966
(!]
Negative values reflect expected need to sell off-peak power to satisfy generator minimum load requirements, primarily in winter and sho ulder months.
cc
CT
Diesel
0
2862
84
0
0
City Of Tallahassee
Schedule 6.2
Energy Sources
(I)
(2)
(3)
(4)
Energy Sources
(5)
(6)
(7)
Actual
2010
Actual
(8)
(JO)
(9)
(I I)
(I 3)
(12)
( 15)
(14)
(16)
llil
(!)
Annual Firm Interchange
%
3.5
3.6
0.8
0.9
0.9
1.0
1.0
0.9
1.0
1.2
0.9
0.9
(2)
Coa l
%
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
(3)
Nuc lear
%
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
(4)
(5)
(6)
(7)
(8)
Residua l
%
%
%
%
%
0.1
0.1
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
0.0
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
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
(9)
(JO)
Distillate
%
%
%
%
%
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
0.0
00
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
0.0
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
%
%
%
%
%
96.6
4.7
89.4
2.5
0.0
92.6
6.2
83.6
2.8
0.0
100.0
3.7
91.8
4.5
0.0
100.2
3.6
89.3
7.3
0.0
99.9
2.4
93.8
3.7
0.0
99.8
2.7
92.7
4.3
0.0
99.6
4.3
0.0
99.8
2.5
93.5
3.8
0.0
99.5
2.8
92.2
4.5
0.0
99.2
0.1
93.2
5.9
0.0
99.6
0.0
96.7
2.8
0.0
99.6
0.0
98.0
1.6
0.0
Total
Steam
cc
CT
Diesel
Total
Steam
cc
(II)
(12)
(13)
CT
Diesel
(14)
(15)
(16)
(I 7)
(18)
Natural Gas
(19)
Hydro
%
0.2
0.2
0.4
0.4
0.3
0.3
0.3
0.4
0.3
0.4
0.3
0.3
(20)
Economy In terchange
%
-0.3
3.6
-1.2
-1.4
-I I
-1.0
-1.0
-I.I
-0.8
-0.8
-0.8
-0.8
(21)
Renewab les
%
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
(22)
Net Energy for Load
%
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
Total
Steam
cc
CT
Diesel
3. I
92.2
-I
Ol
CT
ro
rv
N
0
I
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Figure 84
IGeneration By Resource/Fuel Type I
Calendar Year 2013
10 GWh or 0.3%
2,632 GWh or 91.8%
-9 GWh or -0.3%
130 GWh or 4.5%
105 GWh or 3.7%
\
Total 2013 NEL = 2,868 GWh
Calendar Year 2022
2,908 GWh or 98%
10 GWh or 0.3%
·-,·-.....__""---."
2 GWh or0.1%
\
46 GWh or l .6%
'\
Total 2022 NEL = 2,966 GWh
D CC - Gas
D Steam - Gas
D CT/Diesel - Gas
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Ten Year Site Plan
April 2013
Page 35
D Net Interchange
I]
Hydro
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Chapter III
Projected Facility Requirements
3.1
PLANNING PROCESS
In December 2006 the City completed its last comprehensive IRP Study. The purpose of
this study was to review future DSM and power supply options that are consistent with the City's
policy objectives. Included in the IRP Study was a detailed analysis of how the DSM and power
supply alternatives perform under base and alternative assumptions.
The preferred resource plan identified in the IRP Study included the repowermg of
Hopkins Unit 2 to combined cycle operation, renewable energy purchases, a commitment to an
aggressive DSM portfolio and the latter year addition of peaking resources to meet future energy
demand.
Based on more recent information including but not limited to the updated forecast of the
City's demand and energy requirements (discussed in Chapter 11) the City has made revisions to
its resource plan . These revisions will be discussed in this chapter.
3.2
PROJECTED RESOURCE REQUIREMENTS
3.2.1 TRANSMISSION LIMlTATTONS
The City's projected transmission import capability continues to be a major determinant
of the need for future power supply resource additions. The City's internal transmission studies
have reflected a gradual deterioration of the system's transmission import (and export) capability
into the future, due in part to the lack of investment in the regional transmission system around
Tallahassee as well as the impact of unscheduled power flow-through on the City's transmission
system. The City has worked with its neighboring utilities, Progress and Southern, to plan and
maintain, at minimum, sufficient transmission import capability to allow the City to make
emergency power purchases in the event of the most severe single contingency, the loss of the
system's largest generating unit.
Ten Year Site Plan
April 2013
Page 37
The prospects for significant expansion of the regional transmission system around
Tallahassee hinges on the City's ongoing discussions with Progress and Southern, the Florida
Reliability Coordinating Council's (FRCC) regional transmission planning process, and the
evolving set of mandatory reliability standards issued by the North American Electric Reliability
Corporation (NERC.
Unfortunately, none of these efforts is expected to produce substantive
improvements to the City's transmission import/export capability in the short-term.
In
consideration of the City's limited transmission import capability the results of the IRP Study
and other internal analysis of options tend to favor local generation alternatives as the means to
satisfy future power supply requirements. To satisfy load, planning reserve and operational
requirements in the reporting period, the City may need to advance the in-service date of new
power supply resources to complement available transmission import capability.
3.2.2
RESERVE REQUIREMENTS
For the purposes of this year's TYSP report the City uses a load reserve margin of 17%
as its resource adequacy criterion. This margin was established in the 1990s then re-evaluated
via a loss of load probability (LOLP) analysis of the City ' s system performed in 2002. The City
periodically conducts LOLP analyses to determine if conditions warrant a change to its resource
adequacy criteria.
The results of more recent LOLP analyses suggest that reserve margin may
no longer be suitable as the City's sole resource adequacy criterion. This issue is discussed
further in Section 3.2.4.
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3.2.3
RECENT AND NEAR TERM RESOURCE ADDITIONS
At their October 17, 2005 meeting the City Commission gave the Electric Utility
approval to proceed with the repowering of Hopkins Unit 2 to combined cycle operation. The
repowering was completed and the unit began commercial operation in June 2008 . The former
Hopkins Unit 2 boiler was retired and replaced with a combustion turbine generator (CTG) and a
heat recovery steam generator (HRSG). The Hopkins 2 steam turbine and generator is now
powered by the steam generated in the HRSG. Duct burners have been installed in the HRSG to
provide additional peak generating capability.
The repowering project provides additional
capacity as well as increased efficiency versus the unit's capabilities prior to the repowering
Ten Year Site Plan
April 2013
Page 38
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project. The repowered unit has achieved official seasonal net capacities of 300 MW in the
summer and 330 MW in the winter.
No new resource additions are expected to be needed in the near term (2013-2017).
Resource additions expected in the longer term (2018-2022) are discussed in Section 3.2.6,
"Future Power Supply Resources".
3.2.4
POWER SUPPLY D IVERSITY
Resource diversity, particularly with regard to fuels, has long been a priority concern for
the City because of the system's heavy reliance 'on natural gas as its primary fuel source. This
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11
issue has received even greater emphasis due to the historical volatility in natural gas prices.
The City has addressed this concern in part by implementing an Energy Risk Management
(ERM) program to limit the City's exposure to energy price fluctuations. The ERM program
established an organizational structure of interdepartmental committees and working groups and
included the adoption of an Energy Risk Management Policy. This policy identifies acceptable
risk mitigation products to prevent asset value losses, ensure price stability and provide
protection against market volatility for fuels and energy to the City's electric and gas utilities and
their customers.
Another important consideration in the City's planning process is the number and
diversity of power supply resources in terms of their sizes and expected duty cycles. To satisfy
expected electric system requirements the City assesses the adequacy of its total capability of
power supply resources versus the 17% load reserve margin criterion. But the evaluation of
reserve margin is made only for the annual electric system peak demand and assuming all
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power supply resources are available. Resource adequacy must also be evaluated during other
times of the year to determine if the City is maintaining the appropriate amount and mix of
power supply resources.
Currently, about two-thirds of the City's power supply comes from two generating units,
Purdom 8 and Hopkins 2. The outage of either of these units can present operational challenges
especially when coupled with transmission limitations (as discussed in Section 3.2.1). Further,
the projected retirement of older generating units will reduce the number of power supply
resources available to ensure resource adequacy throughout the reporting period.
Ten Year Site Plan
April 2013
Page 39
For these
reasons the City has evaluated alternative and/or supplemental metrics to its current load reserve
margin criterion that may better balance resource adequacy and operational needs with utility
and customer costs. The results of this evaluation suggest that the City's current deterministic
load reserve margin criterion may need to be supplemented by a probabilistic criterion that takes
into account the number and sizes of power supply resources to ensure adequacy and reliability.
One such criterion that the City might consider adopting is an LOLP of one day in ten years (or
0.1 days per year). An update of the City ' s efforts in this regard will be provided in a future
TYSP report(s).
Purchase contracts can provide some of the diversity desired in the City's power supply
resource portfolio. The City's last IRP Study evaluated both short and long-term purchased
power options based on conventional sources as well as power offers based on renewable
resources. A consultant-assisted study completed in 2008 evaluated the potential reliability and
economic benefits of prospectively increasing the City ' s transmission import (and export)
capabilities.
The results of this study indicate the potential for some electric reliability
improvement resulting from addition of facilities to achieve more transmission import capability.
However, the study's model of the Southern and Florida markets reflects, as with the City's
generation fleet, natural gas-fired generation on the margin the majority of the time. Therefore,
the cost of increasing the City's transmission import capability could not likely be offset by the
potential economic benefit from increased power purchases from conventional sources.
As an additional strategy to address the City ' s lack of power supply diversity, planning
staff has investigated options for a significantly enhanced DSM portfolio. Commitment to this
expanded DSM effort (see Section 2.1.3) and an increase in customer-sited renewable energy
projects (primarily solar panels) improve the City ' s overall resource diversity. However, due to
limited availability and uncertain performance, studies indicate that DSM and solar projects
would not improve resource adequacy (as measured by LOLP) as much as the addition of
conventional generation resources.
3.2.5
RENEWABLE RESOURCES
The City believes that offering green power alternatives to its customers is a sound
business strategy: it will provide for a measure of supply diversification, reduce dependence on
fossil fuels , promote cleaner energy sources, and enhance the City's already strong commitment
Ten Year Site Plan
April 2013
Page 40
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to protecting the environment and the quality of life in Tallahassee. As part of its continuing
:I
commitment to explore clean energy alternatives, the City has continued to invest in
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"green power" to our customers. There are ongoing concerns regarding the potential impact on
opportunities to develop viable solar photovoltaic (PV) projects as part of our efforts to offer
service reliability associated with reliance on a significant amount of intermittent resources like
PV on the City's relatively small electric system.
proliferation of PV and other intermittent resources and work to integrate them so that service
reliability is not jeopardized.
As of the end of calendar year 2012 the City has a portfolio of 137 kW of solar PV
operated and maintained by the Electric Utility and a cumulative total of 1,397 kW of solar PV
has been installed by customers.
The City promotes and encourages environmental
responsibility in our community through a variety of programs available to citizens.
The
commitment to renewable energy sources (and particularly to solar PV) by its customers is made
possible through the Go Green Tallahassee initiative, that includes many options related to
becoming a greener community such as the City's Solar PV Net Metering offer. Solar PV Net
Metering promotes customer investment in renewable energy generation by allowing residential
and commercial customers with small to moderate sized PV installations to return excess
generated power back to the City at the full retail value.
In 2011, the City of Tallahassee signed contracts with SunnyLand Solar and Solar
Developers of America (SDA) for over 3 MWs of solar PV. These demonstration projects are to
be built within the City's service area and will utilize new technology pioneered by Florida State
University.
As of December 31, 2012 both of these projects have been delayed due to
manufacturing issues associated with the technology.
Such delays are to be expected with
projects involving the demonstration of emerging technologies. The City remains optimistic that
the technology will mature into a viable energy resource.
The City continues to seek out suitable projects that utilize the renewable fuels available
within the big bend and panhandle of Florida.
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The City will continue to monitor the
Ten Year Site Plan
April 2013
Page 41
3.2.6
FUTURE POWER SUPPLY RESOURCES
The City currently proj ects that additional power supply resources will be needed to
maintain electric system adequacy and reliability through the 2022 horizon year. The City has
identified the need for additional capacity in the summer of 2020 following the retirement of
Hopkins 1 in order to sati sfy its 17% reserve margin criterion.
The timing, site, type and size of
any new power supply resource may vary dependent upon the metric(s) used to determine
resource adequacy and as the nature of the need becomes better defined. Any proposed addition
could be a generator or a peak season purchase.
The suitability of this resource plan is
dependent on the performance of the City ' s aggressive DSM portfolio (described in Section
2.1.3 of this report) and the City' s projected transmission import capability. If only 50% of the
projected annual DSM peak demand reductions are achieved, the City would require less than 10
MW of additional power supply resources to meet its planning reserve requirements in the
summer of 2018.
The City continues to monitor closely the performance of the DSM portfolio and, as
mentioned in Section 2.1.3 , will be revisiting and, where appropriate, updating assumptions
regarding and re-evaluating cost-effectiveness of our current and prospective DSM measures.
This will also allow a reassessment of expected demand and energy savings attributable to DSM.
Tables 3.1 and 3.2 (Schedules 7.1 and 7.2) provide information on the resources and
reserve margins during the next ten years for the City ' s system. The City has specified its
planned capacity changes on Table 3.3 (Schedule 8).
These capacity resources have been
incorporated into the City's dispatch simulation model in order to provide information related to
fuel consumption and energy mix (see Tables 2. 18, 2.19 and 2.20). Figure C compares seasonal
net peak load and the system reserve margin based on summer peak load requirements. Table
3.4 provides the City's generation expansion plan for the period from 2013 through 2022.
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Ten Year Site Plan
April 2013
Page 42
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Figure C
System Peak Demands
(Including DSM Impacts)
800
700
600
500
~
~
-
-
-
-
-
-
-
D Summer
D Winter
--
-...._
-
--
-- -- --
400
300
I'
,,
200
100
0
20 13
20 14
20 15
20 16
201 7
20 18
20 19
2020
202 1
Year
ISummer Reserve Margin (RM) I
(!)
i::
(!)
(/]
(!)
p::::
I::
(!)
....
(!)
(.)
p...
50
45
40
35
30
25
20
15
10
5
0
c:::::::J RM w I DSM
--
-
-
,......
-
C1!l!:::::J RM WO
I DSM
-
-
-
--,--
20 13
20 14
20 15
-
17o/c0 RM C ntenon
.
-
~
~
--,--
20 16
20 17
20 18
Year
Ten Yea r Site Plan
April 20 13
Page 43
20 19
2020
-
-
202 1 2022
2022
City Of Tallahassee
Schedule 7.1
Forecast of Capacity, Demand, and Scheduled Maintenance at Time of Summer Peak [1]
-0
Firm
Capacity
Export
(MW)
QF
(MW)
Total
Capacity
Available
(MW)
System Firm
Summer Peak
Demand
(MW)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
794
746
734
714
690
690
690
660
660
660
579
574
572
567
564
561
560
560
560
560
(4)
Year
Total
Installed
Capacity
(MW)
Firm
Capacity
Import
(MW)
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
794
746
734
714
690
690
690
660
660
660
0
0
0
0
0
0
0
0
0
0
:J
(I)
(7)
(3)
<ll
-<
<ll
(6)
(2)
_,
lJ )>
(5)
(1)
(8)
(9)
(LO)
Reserve Margin
Scheduled
Maintenance
Before Maintenance
(MW)
(MW)
% of Peak
(11)
(12)
Reserve Margin
After Maintenance
(MW)
% of Peak
co ~ ~
<ll
t\.)
(/)
-!>- 0;::;:
~~ct>
lJ
ti)
:J
[1]
215
172
162
147
126
129
130
100
100
100
37
30
28
26
22
23
23
18
18
18
0
0
0
0
0
0
0
0
0
0
All installed and firm import capacity changes are identified in the proposed generation expansion plan (Table 3.4).
215
172
162
147
126
129
130
100
100
100
37
30
28
26
22
23
23
18
18
18
------------------City Of Tallahassee
Schedule 7.2
Forecast of Capacity, Demand, and Scheduled Maintenance at Time of Winter Peak [1]
(I)
Ql
CJl
-0
(5)
(6)
(7)
Firm
Firm
Total
System Firm
Capacity
Capacity
Capacity
Winter Peak
Year
Capacity
(MW)
Import
(MW)
Export
(MW)
QF
(MW)
Avai lable
(MW)
Demand
(MW)
2013/14
2014/15
2015/16
2016/17
2017/18
2018119
2019/20
2020/21
2021 /22
2022/23
822
822
788
788
762
762
762
732
732
732
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
822
822
788
788
762
762
762
732
732
732
540
544
546
547
549
550
552
552
552
554
:::i
co
Cl>
+>
(4)
Total
Cl>
-<
Cl>
(3)
Installed
-I
lJ )>
(2)
(8)
(9)
Reserve Margin
(10)
Scheduled
Before Maintenance
Maintenance
(MW)
(MW)
% of Peak
(11)
(12)
Reserve Margin
After Maintenance
(MW)
% of Peak
~ ~
~
0
~
UJ
ro- ·
lJ
ii)
:::i
[I]
282
278
242
241
213
212
210
180
180
178
52
51
44
44
39
38
38
33
33
32
0
0
0
0
0
0
0
0
0
0
All installed and firm import capacity changes are identified in the proposed generation expansion plan (Tab le 3.4).
282
278
242
241
213
212
210
180
180
178
52
51
44
44
39
38
38
33
33
32
City Of Tallahassee
Schedule 8
Planned and Prospective Generating Facility Additions and Changes
(14)
( 15)
(9)
(I 0)
( 11)
( 12)
Const.
Start
Mo/Yr
Commercial
In-Service
Mo/Yr
Expected
Retirement
Mo/Yr
Gen. Max.
Nameplate
(kW)
NA
NA
6166
12/13
50,000
-48
-48
RT
PL
TK
NA
2170
3/ 15
16,320
-12
-14
RT
DFO
PL
TK
NA
12/63
10115
15,000
-IO
-IO
RT
NG
DFO
PL
TK
NA
5164
10/ 15
15,000
-IO
-10
RT
GT
NG
DFO
PL
TK
NA
9172
3/ 17
27,000
-24
-26
RT
Leon
ST
NG
RFO
PL
TK
NA
5171
3/20
75,000
-76
-78
RT
Leon
GT
NG
DFO
PL
TK
5117
5/20
NA
50,000
46
48
p
(I)
(2)
(3)
(4)
(5)
Plant Name
Unit
No.
Location
~
Pri
Alt
Purdom
7
Wakulla
ST
NG
NA
PL
Hopkins
CT-I
Leon
GT
NG
DFO
Purdom
CT-I
Wakulla
GT
NG
Purdom
CT-2
Wakulla
GT
(fJ
Hopkins
CT-2
Leon
~
-u
Hopki ns
Unit
(6)
Fuel
(7)
(8)
Fuel Transgort
Pri
Alt
( 13)
Net Cagability
Summer
Winter
(MW)
(MW)
Status
--i
CD
:J
-u
Q}
cc
CD
+>
OJ
)>
CD
-g_ -<
N
0
(;.)
~
Ci)
:J
Hopkins
5 [1]
[I] For the purposes of this report, the City has identified the addition of a GE LM 6000 combustion turbine generator (similar to the City's existing Hopkins CT3 and CT4) at
its existing Hopkins Plant site. The timing , site, type and size of this new power supp ly resource may vary as the nature of the need becomes better defined. Alternative ly,
this proposed addition could be a generator(s) of a different type/size at the same or different location or a peak season purchase.
Acronyms
GT
ST
Gas Turbine
Steam Turbine
Pri
Alt
NG
DFO
RFO
PL
TK
Primary Fuel
Alternate Fuel
Natural Gas
Diese l Fuel Oi l
Residual Fuel Oil
Pipeline
Truck
kW
MW
RT
P
Kilowatts
Megawatts
Existing generator schedu led for retirement
Planned for installation but not uti lity authorized. Not under construction
------------------City Of Tallahassee
Generation Expansion Plan
Year
...,
Cl)
:J
-0 )>
-<
Q)
Cl)
"
co ~ ~
Cl>
N
Ul
w
0;::;:
-J
CD
.io.
-0
Cl
:J
Load Forecast & Adjustments
Forecast
Net
Peak
Peak
Demand
DSM[!]
Demand
(MW)
(MW)
(MW)
Existing
Capacity
Net
(MW)
2013
2014
2015
2016
2017
591
597
604
609
615
12
23
32
42
51
579
574
572
567
564
794
746
734
714
690
2018
2019
2020
2021
2022
621
627
633
639
645
60
67
73
79
85
561
560
560
560
560
690
690
614
614
614
Notes
[I]
[2]
[3]
[4]
[5]
[6]
[7]
Firm
Imports
(MW)
Firm
Exports
(MW)
Resource
Additions
(Cumulative)
(MW)
[2]
[3 ,4]
[5]
[6]
46
46
46
[7]
Total
Capacity
(MW)
Res
794
746
734
714
690
37
30
28
26
22
690
690
660
660
660
23
23
18
18
18
~
Demand Side Management includes energy efficiency and demand response/control measures. Identified as maximum achievable reductions in the City's integrated resource
planning (IRP) study completed in December 2006.
Purdom ST 7 official retirement currently scheduled for December 2013.
Hopkins CT I official retirement currently scheduled for March 2015.
Purdom CTs 1 and 2 official retirement currently scheduled for October 2015.
Hopkins CT 2 official retirement currently scheduled for March 2017.
Hopkins ST 1 official retirement currently scheduled for March 2020.
For the purposes of this report, the City has identified the addition of a GE LM 6000 combustion turbine generator (similar to the City's existing Hopkins CT3 and CT4) at its
existing Hopkins Plant site. The timing, site, type and size of this new power supply resource may vary as the nature of the need becomes better defined. Alternatively, this
proposed addition could be a generator(s) of a different type/size at the same or different location or a peak season purchase.
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Chapter IV
Proposed Plant Sites and Transmission Lines
4.1
PROPOSED PLANT SITE
As discussed in Chapter 3 the City currently expects that additional power supply
resources will be required in the reporting period to meet future system needs (see Table 4.1).
For the purposes of this report, the City has identified the addition of a GE LM 6000 combustion
turbine generator (similar to the City's existing Hopkins CT3 and CT4) at its existing Hopkins
Plant site. The timing, site, type and size of this new power supply resource may vary as the
nature of the need becomes better defined.
Alternatively, this proposed addition could be a
generator(s) of a different type/size at the same or different location or a peak season purchase.
4.2
TRANSMISSION LINE ADDITIONS/UPGRADES
Internal studies of the transmission system have identified a number of system
improvements and additions that will be required to reliably serve future load. The majority of
these improvements are planned for the City's 115 kV transmission network.
As discussed in Section 3.2, the City has been working with its neighboring utilities,
Progress and Southern, to identify improvements to assure the continued reliability and
commercial viability of the transmission systems in and around Tallahassee. At a minimum, the
City attempts to plan for and maintain sufficient transmission import capability to allow for
emergency power purchases in the event of the most severe single contingency, the loss of the
system's largest generating unit.
The City's internal transmission studies have reflected a
gradual deterioration of the system's transmission import (and export) capability into the future.
This reduction in capability is driven in part by the lack of investment in facilities in the
panhandle region as well as the impact of unscheduled power flow-through on the City's
transmission system. The City is committed to continue to work with Progress and Southern as
well as existing and prospective regulatory bodies in an effort to pursue improvements to the
regional transmission systems that will allow the City to continue to provide reliable and
Ten Year Site Plan
April 2013
Page 49
affordable electric service to the citizens of Tallahassee in the future. The City will provide the
FPSC with information regarding any such improvements as it becomes available.
Beyond assessing import and export capability, the City also conducts annual studies of
its transmission system to identify further improvements and expansions to provide increased
reliability and respond more effectively to certain critical contingencies both on the system and
in the surrounding grid in the panhandle.
These evaluations indicate that additional
infrastructure projects are needed to address (i) improvements in capability to deliver power
from the Hopkins Plant (on the west side of the City's service territory) to the load center, and
(ii) the strengthening of the system on the east side of the City's service territory to improve the
voltage profile in that area and enhance response to contingencies.
The City's transmission expansion plan includes a 230 kV loop around the City to be
completed by summer 2016 to address these needs and ensure continued reliable service
consistent with current and anticipated FERC and NERC requirements.
For this proposed
transmission project, the City intends to tap its existing Hopkins-PEF Crawfordville 230 kV
transmission line and extend a 230 kV transmission line to the east terminating at the existing
Substation BP-5 as the first phase of the project to be in service by December 2013. The City
will then upgrade existing 115 kV lines to 230 kV from Substation BP-5 to Substation BP-4 to
Substation BP-7 as the second phase of the project completing the loop by summer 2016. This
new 230 kV loop would address a number of potential line overloads for the single contingency
loss of other key transmission lines in the City's system. Additional 230/115 kV transformation
along the new 230 kV line is expected to be added at Substations BP-5 and BP-4. Table 4.2
summarizes the proposed new facilities or improvements from the transmission planning study
that are within this Ten Year Site Plan reporting period.
The City's budget planning cycle for FY 2014 is currently ongoing, and any revisions to
project budgets in the electric utility will not be finalized until the summer of 2013. Some of the
construction of the aforementioned 230 kV transmission projects is currently underway. If these
improvements do not remain on schedule the City has prepared operating solutions to mitigate
adverse system conditions that might occur as a result of the delay in the in-service date of these
improvements.
Ten Year Site Plan
April 2013
Page 50
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Table 4.1
City Of Tallahassee
Schedule 9
Status Report and Specifications of Proposed Generating Facilities
(I)
Plant Name and Unit Number:
(2)
Capacity
a.) Summer:
b.) Winter:
46
48
(3)
Technology Type:
CT
(4)
Anticipated Construction Timing
a.) Field Construction start - date:
b.) Commercial in-service date:
(5)
Fuel
a.) Primary fuel:
b.) Alternate fuel:
NG
DFO
BACT compli ant
Air Pollution Control Strategy:
(7)
Coolin g Status:
Unknown
(8)
Total Site Area:
Unknown
(9)
Construction Status:
Not started
( I 0)
Certifi cation Status:
Not started
( 11)
Status with Federal Agencies:
Not started
( 12)
Projected Unit Performance Data
Planned Outage Factor (POF):
Forced Outage Factor:
Equivalent Avai labi li ty Factor (EAF):
Resul ting Capacity Factor(%):
Average Net Operating Heat Rate (ANOHR):
Notes
[I]
(2]
[3]
[4]
[5]
[I]
May-17
May-20
(6)
( 13)
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Hopkins 5
Projected Unit Financia l Data
Book Life (Years)
Tota l Installed Cost (In-Service Year $/kW)
Direct Construction Cost ($/kW):
AFUDC Amount ($/kW):
Esca lation ($/kW):
Fixed 0 & M ($kW-Yr):
Vari able 0 & M ($/ MWH):
K Factor:
5.77%
3.33%
89.57%
4.86
9,877 Btu/ kWh
30
1216
1023
NA
193
7.33
15.44
NA
[2]
(3]
(4]
(5]
[5]
[5]
For the purposes of thi s report, the City has identified the addition of a GE LM 6000 combustion
turbine generator (similar to the City's ex isting Hopkins CT3 and CT4) at its existing Hopkins
Plant site. The timing, site, type and size of this new power supply resource may vary as the
nature of the need becomes better defined. Alternatively, this proposed additi on could be a
generator(s) of a different type/size at the same or different location or a peak season purchase.
Expected first year capacity factor.
Expected first year net average heat rate.
Estimated 2020 dollars.
Estimated 20 13 dollars.
Ten Year Site Plan
April 2013
Page 51
Figure D-1 - Hopkins Plant Site
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l_
Figure D-2 - Purdom Plant Site
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3000 ft
I
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1000 m
Ten Year Site Plan
April 2013
Page 52
I
----------------- - City Of Tallahassee
Planned Transmission Projects, 2013-2022
-I
CD
Project Type
Project Name
New Lines
230 Loop Phase I - Line33
Line S3
Line S4
Line SS
230 Loop Phase II
Line Rebuild/
Reconductor
Line IS A
Line ISB
Line ISC
Transformers
Substations
:::>
Cl "O
-<
CD
CD
en
"U )>
co ~ ~
(Jl
N
0
- ·
w ~CD
"U
OJ
From Bus
Number
Name
To Bus
Name
Number
Expected
In-Service
Date
Voltage
(kV)
Line
Length
(miles)
Hopkins S
Sub 21
Sub 17
Sub 14
Sub S
7610
7S21
7Sl7
7S l4
760S
Sub S
Sub I 7
Sub 14
Sub 7
Sub 7
760S
7S l 7
7Sl4
7S07
7607
12/31 / 13
3/31 / 14
3/31/14
6/30/ IS
6/ 1/16
230
I IS
I IS
llS
230
8.0
6.0
4.0
6.0
12 .8
Sub S
Sub S
Sub 9
7SOS
7SOS
7S09
Sub 4
Sub 9
Sub 4
7S04
7S09
7S04
6/30/ 14
6/30/ 14
6/30/ 14
I IS
I lS
I lS
9.0
6.0
4.0
Sub S 230/ I IS Auto
Sub 4 230/ 11 S Auto
Sub S 230
Sub 4 230
760S
7604
Subs llS
Sub4 llS
7SOS
7S04
12/31/13
6/ 1/ 16
NA
NA
NA
NA
Sub 17(Bus7Sl7)
Sub 23 (Bus 7S23)
Sub 22 (Bus 7S22)
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
12/30/13
12/30/ 14
6/30/ 1S
llS
I lS
I lS
NA
NA
NA
:::>
Table 4.3
City Of Tallahassee
Schedule 10
Status Report and Specifications of Proposed
Directly Associated Transmission Lines
Substation 32 - Substation 5
(I)
Point of Origin and Termination:
(2)
Number of Lines:
(3)
Right-of -Way:
T AL Owned and New Acquisitions
(4)
Line Length:
8 miles
(5)
Voltage:
230 kV
(6)
Anticipated Cap ital Timing:
Start - 2009
End - 2013
(7)
Anticipated Capital Investment:
$7.3 million
(8)
Substations:
Substation 32 (tap Hopkins-Crawfordville 230 kV) [ l]
(9)
Participation with Other Utilities:
None
Notes
[I]
New substation to serve as west terminus for new 230 kV line. Existing Substation 5 will be east terminus.
Ten Year Site Plan
April 2013
Page 54
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Table 4.4
City Of Tallahassee
Schedule 10
Status Report and Specifications of Proposed
Directly Associated Transmission Lines
(1)
Point of Origin and Termination:
Substation 5 - Substation 4 - Substation 7
(2)
Number of Lines:
(3)
Right-of -Way:
TAL Owned
(4)
Line Length:
12.8 miles
(5)
Voltage:
230 kV
(6)
Anticipated Capital Timing:
Not yet determined; target in service summer 2016
(7)
Anticipated Capital Investment:
$ 19.2 million
(8)
Substations:
See note [l]
(9)
Participation with Other Utilities :
None
Notes
[l]
North terminus wi ll be existing Substation 7; south terminus will be existing Substation 5;
intermediate terminus will be existing Substation 4.
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Ten Year Site Plan
April 2013
Page 55
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