March 31, 2014 Florida Public Service Commission Office of the Commission Clerk

March 31, 2014 Florida Public Service Commission Office of the Commission Clerk
 March 31, 2014
FILED MAR 31, 2014
DOCUMENT NO. 01411-14
FPSC - COMMISSION CLERK
Florida Public Service Commission
Office of the Commission Clerk
2540 Shumard Oak Blvd.
Tallahassee, FL 32399-0850
Dear Sir/Madam:
Attached please find the City of Tallahassee’s (City) 2014 Ten Year Site Plan report provided for
electronic filing pursuant to Section 186.801, F.S. This cover letter is followed by an electronic
copy of the report in Adobe Acrobat format.
If you should have any questions regarding this report, please feel free to contact me at (850)
891-3130 or paul.clark@talgov.com. Thank you.
Sincerely,
/s/ Paul D. Clark, II
Principal Engineer
Attachments
Ten-Year Site Plan: 2014-2023
City of Tallahassee Utilities
Photo: Substation 32
Report prepared by: City of Tallahassee Electric Utility System Planning
CITY OF TALLAHASSEE
TEN YEAR SITE PLAN FOR ELECTRICAL GENERATING FACILITIES
AND ASSOCIATED TRANSMISSION LINES
2014-2023
TABLE OF CONTENTS
I. Description of Existing Facilities
1.0
1.1
1.2
Figure A
Table 1.1
Introduction ........................................................................................................................................................ 1
System Capability ............................................................................................................................................... 1
Purchased Power Agreements ............................................................................................................................ 2
Service Territory Map......................................................................................................................................... 3
FPSC Schedule 1 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 B1
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
Table 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 ........................................................................................................... 12
FPSC Schedule 2.1 History/Forecast of Energy Consumption (Residential and Commercial Classes) ........... 13
FPSC Schedule 2.2 History/Forecast of Energy Consumption (Industrial and Street Light Classes) .............. 14
FPSC Schedule 2.3 History/Forecast of Energy Consumption (Utility Use and Net Energy for Load) .......... 15
Energy Consumption by Customer Class (2004-2023) .................................................................................... 16
Energy Consumption: Comparison by Customer Class (2014 and 2023) ....................................................... 17
FPSC Schedule 3.1.1 History/Forecast of Summer Peak Demand – Base Forecast......................................... 18
FPSC Schedule 3.1.2 History/Forecast of Summer Peak Demand – High Forecast ........................................ 19
FPSC Schedule 3.1.3 History/Forecast of Summer Peak Demand – Low Forecast ......................................... 20
FPSC Schedule 3.2.1 History/Forecast of Winter Peak Demand – Base Forecast ........................................... 21
FPSC Schedule 3.2.2 History/Forecast of Winter Peak Demand – High Forecast ........................................... 22
FPSC Schedule 3.2.3 History/Forecast of Winter Peak Demand – Low Forecast ........................................... 23
FPSC Schedule 3.3.1 History/Forecast of Annual Net Energy for Load – Base Forecast ............................... 24
FPSC Schedule 3.3.2 History/Forecast of Annual Net Energy for Load – High Forecast ............................... 25
FPSC Schedule 3.3.3 History/Forecast of Annual Net Energy for Load – Low Forecast ................................ 26
FPSC Schedule 4 Previous Year Actual and Two Year Forecast Demand/Energy by Month ........................ 27
Load Forecast: Key Explanatory Variables ..................................................................................................... 28
Load Forecast: Sources of Forecast Model Input Information ........................................................................ 29
Banded Summer Peak Load Forecast vs. Supply Resources ............................................................................ 30
Projected DSM Energy Reductions .................................................................................................................. 31
Projected DSM Seasonal Demand Reductions ................................................................................................. 32
FPSC Schedule 5.0 Fuel Requirements ............................................................................................................ 33
FPSC Schedule 6.1 Energy Sources (GWh) .................................................................................................... 34
FPSC Schedule 6.2 Energy Sources (%) .......................................................................................................... 35
Generation by Fuel Type (2014 and 2023) ...................................................................................................... 36
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 ....................................................................................................................................... 41
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 D1
Figure D2
Table 4.2
Table 4.3
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 2014-2023 ....................................................................................................... 53
FPSC Schedule 10 Status Report and Spec. of Proposed Directly Associated Transmission Lines ............... 54
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 115,700 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 746 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 O. Purdom
Generating Station, located in the City 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.
Corn Hydroelectric Station, located on Lake Talquin west of Tallahassee, since August of 1985.
1.1
SYSTEM CAPABILITY
The City maintains seven points of interconnection with Duke Energy Florida (“Duke”,
formerly Progress Energy Florida); three at 69 kV, three 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 1), 222 MW (net summer rating) of CC generation and
20 MW (net summer rating) of CT generation facilities are located at the City's Sam O. Purdom
Generating Station. The former Purdom Unit 7, a conventional gas-fired steam turbine generator
originally placed into service in June 1966, was officially retired as of December 31, 2013. The
Arvah B. Hopkins Generating Station includes 300 MW (net summer rating) of CC generation,
Ten Year Site Plan
April 2014
Page 1
76 MW (net summer rating) of steam generation and 128 MW (net summer rating) of CT
generation facilities.
The City's Hopkins 1 steam generating unit can be fired with natural gas, residual oil or
both. The CC and CT units can be fired on either natural gas or diesel oil but cannot burn these
fuels concurrently. The total capacity of the three units at the C.H. Corn 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.
Following the retirement of Purdom Unit 7 the City’s total net summer installed
generating capability is 746 MW. The corresponding winter net peak installed generating
capability is 822 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. Firm retail
electric service is purchased from and provided by the Talquin Electric Cooperative (“Talquin”)
to City customers served by the Talquin electric system. The projected amounts of electric
service to be purchased from Talquin is included in the “Annual Firm Interchange” values
provided in Table 2.19 (Schedule 6.1) Reciprocal service is provided to Talquin customers
served by the City electric system. Payments for electric service provided to and received from
Talquin and the transfer of customers and electric facilities is governed by a territorial agreement
between the City and Talquin.
Ten Year Site Plan
April 2014
Page 2
Figure A
City of Tallahassee, Electric Utility
Service Territory Map
)
I
CllD
- .-
r
GEORGrA
·t...•..
~
•
F
Ten Year Site Plan
April 2015
Page 3
.
City Of Tallahassee
Schedule 1
Existing Generating Facilities
As of December 31, 2013
(1)
(2)
Unit
No.
Plant
Sam O. Purdom
Ten Year Site Plan
April 2014
Page 4
A. B. Hopkins
8
GT-1
GT-2
1
2
GT-1
GT-2
GT-3
GT-4
(3)
Location
Wakulla
Leon
(4)
(5)
(6)
Unit
Type
Pri
Alt
CC
GT
GT
NG
NG
NG
FO2
FO2
FO2
ST
CC
GT
GT
GT
GT
Fuel
NG
NG
NG
NG
NG
NG
FO6
FO2
FO2
FO2
FO2
FO2
(7)
(8)
Fuel Transport
Primary
Alternate
PL
PL
PL
PL
PL
PL
PL
PL
PL
TK
TK
TK
TK
TK
TK
TK
TK
TK
(9)
(10)
(11)
(12)
Alt.
Fuel
Days
Use
Commercial
In-Service
Month/Year
Expected
Retirement
Month/Year
Gen. Max.
Nameplate
(kW)
[1, 2]
[1, 2]
[1, 2]
7/00
12/63
5/64
12/40
10/15
10/15
247,743
15,000
15,000
222
10
10
258 [7]
10
10
Plant Total
242
278
76
300
12
24
46
46
78
330 [7]
14
26
48
48
504
544
0
0
0
0
0
0
0
0
746
822
[3]
[2]
[2]
[2]
[2]
[2]
5/71
6/08 [4]
2/70
9/72
9/05
11/05
3/20
Unknown
3/15
3/17
Unknown
Unknown
75,000
358,200 [5]
16,320
27,000
60,500
60,500
Plant Total
C. H. Corn
Hydro Station
[6]
1
2
3
Leon
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
(13)
Net Capability
Summer
Winter
(MW)
(MW)
4,440
4,440
3,430
Plant Total
Total System Capacity as of December 31, 2013
Notes
[1]
[2]
[3]
[4]
[5]
[7]
Due to the Purdom facility-wide emissions caps, utilization of liquid fuel at this facility is limited.
The City maintains a minimum distillate fuel oil storage capacity sufficient to operate the Purdom plant approximately 9 days and the Hopkins plant and approximately 3 days
at maximum output.
The City maintains a minimum residual fuel oil storage capacity sufficient to operate Hopkins 1 approximately 8 days at maximum output.
Reflects the commercial operations date of Hopkins 2 repowered to a combined cycle generating unit with a new General Electric Frame 7A combustion turbine. The original commercial
operations date of the existing steam turbine generator was October 1977.
Hopkins 2 nameplate rating is based on combustion turbine generator (CTG) nameplate and modeled steam turbine generator (STG) output in a 1x1 combined cycle (CC) configuration with
supplemental duct firing.
Because the C. H. Corn 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.
Summer and winter ratings are based on 95 oF and 29 oF ambient temperature, respectively.
Table 1.1
[6]
(14)
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
sources and fuel requirements. This chapter also explains the impacts attributable 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
City expects to continue its commitment to the DSM programs that prove beneficial to the City’s
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 B1 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 2014 and the
horizon year of 2023. 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 2013-2015 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
Ten Year Site Plan
April 2014
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
Ten Year Site Plan
April 2014
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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 (FAMU), Tallahassee
Memorial Hospital (TMH) and the State Capitol Center. These four customers represented
approximately 15% of the City’s 2013 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 is driven by the projected
growth in Leon County population. While population growth projections decreased in the years
immediately following the 2008-2009 recession the current projection shows a slightly higher
growth in population versus last year. Leon County population is projected to grow from 20142033 at an average annual growth rate (AAGR) of 0.82%. This growth rate is below that for the
state of Florida (1.15%) but is higher than that for the United States (0.71%).
Total and per customer demand and energy requirements have also decreased in recent
years. There are several reasons for this decrease including but not limited to the issuance of 18
new or updated federal appliance and equipment efficiency standards since 2009 and the 2010
modifications to the State of Florida Energy Efficiency Code for Building Construction. The
City’s energy efficiency and demand-side management (DSM) programs (discussed in Section
2.1.3) and the economic conditions during and following the 2008-2009 recession have also
contributed to these decreases. The decreases in per customer residential and commercial
demand and energy requirements are projected to offset the increased growth rate in residential
and commercial customers. 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.
Ten Year Site Plan
April 2014
Page 7
The changes made to the forecast models for seasonal peak demands and annual sales/net energy
for load requirements have resulted in 2014 base forecasts for these characteristics that are
generally lower than the corresponding 2013 base forecasts.
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, Leidos Engineering, 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).
Ten Year Site Plan
April 2014
Page 8
Sensitivities on the peak demand forecasts are useful in planning for future power supply
resource needs. The graph shown in Figure B3 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
the City’s existing and planned power supply resources. This graph allows for the review of the
effect of load growth and DSM performance variations on the timing of new resource additions.
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 HVAC 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
Ten Year Site Plan
April 2014
Page 9
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 load 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.
In 2012 the City contracted with a consultant to review its efforts with DSM and
renewable resources with a focus on adjusting resource costs for which additional investment
and overall market changes impacted the estimates used in the IRP Study. DSM and renewable
resource alternatives were evaluated on a levelized cost basis and prioritized on geographic and
demographic suitability, demand savings potential and cost. From this prioritized list the
consultant identified a combination of DSM and renewable resources that could be costeffectively placed into service by 2016. The total demand savings potential for the resources
identified compared well with that identified in the IRP Study providing some assurance that the
City’s ongoing DSM and renewable efforts remained cost-effective.
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 2013 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 60% 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 slowed in
recent years due in part to the economic conditions observed during and following the 2008-2009
recession as well as due to changes in the federal appliance/equipment efficiency standards and
state building efficiency code. 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
Ten Year Site Plan
April 2014
Page 10
advantage of the incentives provided through the City’s DSM program – as well as in response to
the aforementioned standards and code changes. 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.
Estimates of the actual demand and energy savings realized from 2007-2013 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 2013 TYSP. These revised projections
reflect DSM savings increasing at a steady rate that is more consistent with historical experience
and level of annual program expenditures to date.
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,
Tables 2.7-2.9 and 2.17 reflect no expected utilization of DR/DLC capability to reduce winter
peak demand.
Ten Year Site Plan
April 2014
Page 11
2.2
ENERGY SOURCES AND FUEL REQUIREMENTS
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 2014-2023. Figure
B4 displays the percentage of energy by fuel type in 2014 and 2023.
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
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 2014
Page 12
City Of Tallahassee
Schedule 2.1
History and Forecast of Energy Consumption and
Number of Customers by Customer Class
Base Load Forecast
(1)
(2)
(3)
(4)
(5)
(6)
(7)
Rural & Residential
(8)
Commercial [4]
Average
No. of
Customers
[3]
(9)
Ten Year Site Plan
April 2014
Page 13
Year
Population
[1]
Members
Per
Household
(GWh)
[2]
Average
No. of
Customers
[3]
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
265,393
269,619
272,648
273,684
274,926
275,059
275,783
276,799
277,935
279,172
-
1,064
1,088
1,097
1,099
1,054
1,050
1,136
1,113
1,021
1,014
85,035
89,468
92,017
93,569
94,640
94,827
95,268
95,794
96,479
97,145
12,512
12,161
11,922
11,745
11,137
11,073
11,924
11,619
10,583
10,438
1,604
1,622
1,602
1,657
1,625
1,611
1,618
1,598
1,572
1,544
17,729
18,312
18,533
18,583
18,597
18,478
18,426
18,418
18,445
18,558
90,473
88,576
86,440
89,168
87,380
87,185
87,811
86,763
85,226
83,199
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
282,107
285,799
288,477
291,178
293,909
296,667
299,336
301,843
304,371
306,918
-
1,042
1,051
1,056
1,061
1,066
1,071
1,076
1,081
1,086
1,090
98,151
99,533
100,538
101,551
102,575
103,610
104,611
105,552
106,501
107,457
10,616
10,559
10,503
10,448
10,392
10,337
10,286
10,241
10,197
10,144
1,575
1,594
1,604
1,613
1,633
1,643
1,653
1,660
1,668
1,677
18,722
18,941
19,100
19,260
19,423
19,586
19,745
19,894
20,044
20,196
84,126
84,156
83,979
83,749
84,076
83,886
83,717
83,442
83,217
83,036
[1]
[2]
[3]
(GWh)
[2]
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 of 2007 "Commercial" includes General Service Non-Demand, General Service Demand, General Service Large Demand
Interruptible (FSU and Goose Pond), Curtailable (TMH), Traffic Control, Security Lights and Street & Highway Lights
Average kWh
Consumption
Per Customer
Table 2.1
[4]
Average kWh
Consumption
Per Customer
City Of Tallahassee
Schedule 2.2
History and Forecast of Energy Consumption and
Number of Customers by Customer Class
Base Load Forecast
(1)
Ten Year Site Plan
April 2014
Page 14
(2)
(3)
Year
(GWh)
Industrial
Average
No. of
Customers
[1]
Average kWh
Consumption
Per Customer
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
-
-
-
14
14
15
0
0
0
0
0
0
0
2,682
2,724
2,714
2,756
2,679
2,661
2,754
2,711
2,593
2,558
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
-
-
-
0
0
0
0
0
0
0
0
0
0
2,617
2,645
2,660
2,674
2,699
2,714
2,729
2,741
2,754
2,767
(5)
(6)
(7)
(8)
Railroads
and Railways
(GWh)
Street &
Highway
Lighting
(GWh)
[2]
Other Sales
to Public
Authorities
(GWh)
Total Sales
to Ultimate
Consumers
(GWh)
[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.
Table 2.2
[1]
[2]
[3]
(4)
City Of Tallahassee
Schedule 2.3
History and Forecast of Energy Consumption and
Number of Customers by Customer Class
Base Load Forecast
Ten Year Site Plan
April 2014
Page 15
(1)
(2)
(3)
(4)
(5)
(6)
Year
Sales for
Resale
(GWh)
Utility Use
& Losses
(GWh)
Net Energy
for Load
(GWh)
[1]
Other
Customers
(Average No.)
Total
No. of
Customers
[2]
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
0
0
0
0
0
0
0
0
0
0
159
163
154
158
155
140
177
88
117
126
2,841
2,887
2,868
2,914
2,834
2,801
2,931
2,799
2,710
2,684
0
0
0
0
0
0
0
0
0
0
102,764
107,780
110,550
112,152
113,237
113,305
113,694
114,212
114,924
115,703
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
0
0
0
0
0
0
0
0
0
0
144
145
146
146
149
149
149
151
151
151
2,761
2,790
2,806
2,820
2,848
2,863
2,878
2,892
2,905
2,918
0
0
0
0
0
0
0
0
0
0
116,873
118,474
119,638
120,811
121,998
123,196
124,356
125,446
126,545
127,653
Values include DSM Impacts.
Average number of customers for the calendar year.
Table 2.3
[1]
[2]
History and Forecast Energy Consumption
By Customer Class (Including DSM Impacts)
Gigawatt-Hours (GWh)
3,200
2,800
2,400
Ten Year Site Plan
April 2014
Page 16
2,000
1,600
1,200
800
400
0
Calendar Year
Non-Demand
Demand
Large Demand
Curtail/Interrupt
Traffic/Street/Security Lights
Figure B1
Residential
Figure B2
Energy Consumption By Customer Class
(Excluding DSM Impacts)
Calendar Year 2014
40%
7%
1%
3%
25%
24%
Total 2014 Sales = 2,630 GWh
Calendar Year 2023
41%
7%
1%
3%
24%
24%
Total 2023 Sales = 2,900 GWh
Residential
Non-Demand
Demand
Large Demand
Curtail/Interrupt
Traffic/Street/Security Lights
Ten Year Site Plan
April 2014
Page 17
City Of Tallahassee
Schedule 3.1.1
History and Forecast of Summer Peak Demand
Base Forecast
(MW)
(1)
(2)
(3)
(4)
(5)
(6)
(7)
Residential
Load
Residential
Management Conservation
Interruptible
[2]
[2], [3]
(8)
Comm./Ind
Load
Management
[2]
(9)
(10)
Comm./Ind
Conservation
[2], [3]
Net Firm
Demand
[1]
Ten Year Site Plan
April 2014
Page 18
Year
Total
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
565
598
577
621
587
605
601
590
557
545
565
598
577
621
587
605
601
590
557
545
0
2
0
0
565
598
577
621
587
605
601
590
557
543
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
571
581
587
593
601
609
614
620
625
631
571
581
587
593
601
609
614
620
625
631
0
0
5
11
16
21
23
24
24
24
1
3
4
6
7
9
10
11
13
14
8
12
12
12
12
12
12
12
12
13
1
3
5
7
9
11
13
15
17
19
561
563
561
557
557
556
556
558
559
561
Retail
Values include DSM Impacts.
Reduction estimated at busbar. 2013 DSM is actual at peak.
2013 values reflect incremental increase from 2012.
Table 2.4
[1]
[2]
[3]
Wholesale
City Of Tallahassee
Schedule 3.1.2
History and Forecast of Summer Peak Demand
High Forecast
(MW)
(1)
(2)
(3)
(4)
(5)
(6)
(7)
Residential
Load
Residential
Management Conservation
Interruptible
[2]
[2], [3]
(8)
Comm./Ind
Load
Management
[2]
(9)
(10)
Comm./Ind
Conservation
[2], [3]
Net Firm
Demand
[1]
Ten Year Site Plan
April 2014
Page 19
Year
Total
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
565
598
577
621
587
605
601
590
557
545
565
598
577
621
587
605
601
590
557
545
0
2
0
0
565
598
577
621
587
605
601
590
557
543
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
584
598
607
617
628
640
649
659
669
679
584
598
607
617
628
640
649
659
669
679
0
0
5
11
16
21
23
24
24
24
1
3
4
6
7
9
10
11
13
14
8
12
12
12
12
12
12
12
12
13
1
3
5
7
9
11
13
15
17
19
574
580
581
581
584
587
591
597
603
609
Retail
Values include DSM Impacts.
Reduction estimated at busbar. 2013 DSM is actual at peak.
2013 values reflect incremental increase from 2012.
Table 2.5
[1]
[2]
[3]
Wholesale
City Of Tallahassee
Schedule 3.1.3
History and Forecast of Summer Peak Demand
Low Forecast
(MW)
(1)
(2)
(3)
(4)
(5)
(6)
(7)
Residential
Load
Residential
Management Conservation
Interruptible
[2]
[2], [3]
(8)
Comm./Ind
Load
Management
[2]
(9)
(10)
Comm./Ind
Conservation
[2], [3]
Net Firm
Demand
[1]
Ten Year Site Plan
April 2014
Page 20
Year
Total
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
565
598
577
621
587
605
601
590
557
545
565
598
577
621
587
605
601
590
557
545
0
2
0
0
565
598
577
621
587
605
601
590
557
543
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
558
564
567
570
573
578
579
581
583
584
558
564
567
570
573
578
579
581
583
584
0
0
5
11
16
21
23
24
24
24
1
3
4
6
7
9
10
11
13
14
8
12
12
12
12
12
12
12
12
13
1
3
5
7
9
11
13
15
17
19
548
546
541
534
529
525
521
519
517
514
Retail
Values include DSM Impacts.
Reduction estimated at busbar. 2013 DSM is actual at peak.
2013 values reflect incremental increase from 2012.
Table 2.6
[1]
[2]
[3]
Wholesale
City Of Tallahassee
Schedule 3.2.1
History and Forecast of Winter Peak Demand
Base Forecast
(MW)
(1)
(2)
Year
Total
(3)
Wholesale
(4)
Retail
(5)
(6)
(7)
(8)
(9)
Residential
Comm./Ind
Load
Residential
Load
Comm./Ind
Management Conservation Management Conservation
Interruptible
[2], [3]
[2], [4]
[2], [3]
[2], [4]
(10)
Net Firm
Demand
[1]
Ten Year Site Plan
April 2014
Page 21
-2005
-2006
-2007
-2008
-2009
-2010
-2011
-2012
-2013
-2014
509
532
537
528
526
579
633
584
516
576
509
532
537
528
526
579
633
584
516
576
0
2
0
0
509
532
537
528
526
579
633
584
480
574
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
-2015
-2016
-2017
-2018
-2019
-2020
-2021
-2022
-2023
-2024
518
524
530
537
542
548
552
558
563
569
518
524
530
537
542
548
552
558
563
569
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
6
7
8
10
11
12
511
514
516
520
522
525
526
528
529
532
[1]
[2]
[3]
[4]
Values include DSM Impacts.
Reduction estimated at busbar. 2013 DSM is actual at peak.
Reflects no expected utilization of demand response (DR) resources in winter.
2013 values reflect incremental increase from 2012.
Table 2.7
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
City Of Tallahassee
Schedule 3.2.2
History and Forecast of Winter Peak Demand
High Forecast
(MW)
(1)
(2)
Year
Total
(3)
Wholesale
(4)
Retail
(5)
(6)
(7)
(8)
(9)
Residential
Comm./Ind
Load
Residential
Load
Comm./Ind
Management Conservation Management Conservation
Interruptible
[2], [3]
[2], [4]
[2], [3]
[2], [4]
(10)
Net Firm
Demand
[1]
Ten Year Site Plan
April 2014
Page 22
-2005
-2006
-2007
-2008
-2009
-2010
-2011
-2012
-2013
-2014
509
532
537
528
526
579
633
584
516
576
509
532
537
528
526
579
633
584
516
576
0
2
0
0
509
532
537
528
526
579
633
584
480
574
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
-2015
-2016
-2017
-2018
-2019
-2020
-2021
-2022
-2023
-2024
533
542
552
562
570
579
587
597
606
615
533
542
552
562
570
579
587
597
606
615
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
6
7
8
10
11
12
526
532
538
545
550
556
561
567
572
578
[1]
[2]
[3]
[4]
Values include DSM Impacts.
Reduction estimated at customer meter. 2013 DSM is actual.
Reflects no expected utilization of demand response (DR) resources in winter.
2013 values reflect incremental increase from 2012.
Table 2.8
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
City Of Tallahassee
Schedule 3.2.3
History and Forecast of Winter Peak Demand
Low Forecast
(MW)
(1)
(2)
Year
Total
(3)
Wholesale
(4)
Retail
(5)
(6)
(7)
(8)
(9)
Residential
Comm./Ind
Load
Residential
Load
Comm./Ind
Management Conservation Management Conservation
Interruptible
[2], [3]
[2], [4]
[2], [3]
[2], [4]
(10)
Net Firm
Demand
[1]
Ten Year Site Plan
April 2014
Page 23
-2005
-2006
-2007
-2008
-2009
-2010
-2011
-2012
-2013
-2014
509
532
537
528
526
579
633
584
516
576
509
532
537
528
526
579
633
584
516
576
0
2
0
0
509
532
537
528
526
579
633
584
480
574
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
-2015
-2016
-2017
-2018
-2019
-2020
-2021
-2022
-2023
-2024
504
506
509
512
515
517
517
520
522
523
504
506
509
512
515
517
517
520
522
523
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
6
7
8
10
11
12
497
496
495
495
495
494
491
490
488
486
[1]
[2]
[3]
[4]
Values include DSM Impacts.
Reduction estimated at customer meter. 2013 DSM is actual.
Reflects no expected utilization of demand response (DR) resources in winter.
2013 values reflect incremental increase from 2012.
Table 2.9
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
City Of Tallahassee
Schedule 3.3.1
History and Forecast of Annual Net Energy for Load
Base Forecast
(GWh)
Ten Year Site Plan
April 2014
Page 24
(1)
(2)
Year
Total
Sales
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2,682
2,724
2,714
2,756
2,679
2,661
2,754
2,711
2,593
2,567
9
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2,629
2,670
2,698
2,726
2,763
2,793
2,821
2,846
2,873
2,901
8
17
25
33
41
50
58
66
74
83
(4)
(6)
(7)
(8)
(9)
Wholesale
Utility Use
& Losses
Net Energy
for Load
[1]
Load
Factor %
[1]
0
2,682
2,724
2,714
2,756
2,679
2,661
2,754
2,711
2,593
2,558
159
163
154
158
155
140
177
88
117
126
2,841
2,887
2,868
2,914
2,834
2,801
2,931
2,799
2,710
2,684
57
55
57
54
55
53
56
54
56
56
4
8
13
19
23
29
34
39
45
51
2,617
2,645
2,660
2,674
2,699
2,714
2,729
2,741
2,754
2,767
144
145
146
146
149
149
149
151
151
151
2,761
2,790
2,806
2,820
2,848
2,863
2,878
2,892
2,905
2,918
56
57
57
58
58
59
59
59
59
59
Residential
Comm./Ind
Conservation Conservation
[2], [3]
[2], [3]
(5)
Retail
Sales
[1]
Values include DSM Impacts.
Reduction estimated at customer meter. 2013 DSM is actual.
2013 values reflect incremental increase from 2012.
Table 2.10
[1]
[2]
[3]
(3)
City Of Tallahassee
Schedule 3.3.2
History and Forecast of Annual Net Energy for Load
High Forecast
(GWh)
Ten Year Site Plan
April 2014
Page 25
(1)
(2)
Year
Total
Sales
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2,682
2,724
2,714
2,756
2,679
2,661
2,754
2,711
2,593
2,567
9
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2,689
2,747
2,790
2,835
2,891
2,938
2,984
3,026
3,071
3,119
8
17
25
33
41
50
58
66
74
83
(4)
(6)
(7)
(8)
(9)
Wholesale
Utility Use
& Losses
Net Energy
for Load
[1]
Load
Factor %
[1]
0
2,682
2,724
2,714
2,756
2,679
2,661
2,754
2,711
2,593
2,558
159
163
154
158
155
140
177
88
117
126
2,841
2,887
2,868
2,914
2,834
2,801
2,931
2,799
2,710
2,684
57
55
57
54
55
53
56
54
56
56
4
8
13
19
23
29
34
39
45
51
2,677
2,722
2,752
2,783
2,827
2,859
2,892
2,921
2,952
2,985
147
149
151
153
155
157
159
160
162
164
2,824
2,871
2,903
2,935
2,982
3,016
3,050
3,082
3,114
3,149
56
57
57
58
58
59
59
59
59
59
Residential
Comm./Ind
Conservation Conservation
[2], [3]
[2], [3]
(5)
Retail
Sales
[1]
Values include DSM Impacts.
Reduction estimated at customer meter. 2013 DSM is actual.
2013 values reflect incremental increase from 2012.
Table 2.11
[1]
[2]
[3]
(3)
City Of Tallahassee
Schedule 3.3.3
History and Forecast of Annual Net Energy for Load
Low Forecast
(GWh)
Ten Year Site Plan
April 2014
Page 26
(1)
(2)
Year
Total
Sales
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2,682
2,724
2,714
2,756
2,679
2,661
2,754
2,711
2,593
2,567
9
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2,569
2,593
2,606
2,617
2,638
2,651
2,660
2,668
2,677
2,686
8
17
25
33
41
50
58
66
74
83
(4)
(6)
(7)
(8)
(9)
Wholesale
Utility Use
& Losses
Net Energy
for Load
[1]
Load
Factor %
[1]
0
2,682
2,724
2,714
2,756
2,679
2,661
2,754
2,711
2,593
2,558
159
163
154
158
155
140
177
88
117
126
2,841
2,887
2,868
2,914
2,834
2,801
2,931
2,799
2,710
2,684
57
55
57
54
55
53
56
54
56
56
4
8
13
19
23
29
34
39
45
51
2,557
2,568
2,568
2,565
2,574
2,572
2,568
2,563
2,558
2,552
140
141
141
141
141
141
141
141
140
140
2,698
2,709
2,709
2,706
2,715
2,713
2,709
2,704
2,698
2,692
56
57
57
58
59
59
59
59
60
60
Residential
Comm./Ind
Conservation Conservation
[2], [3]
[2], [3]
(5)
Retail
Sales
[1]
Values include DSM Impacts.
Reduction estimated at customer meter. 2013 DSM is actual.
2013 values reflect incremental increase from 2012.
Table 2.12
[1]
[2]
[3]
(3)
City Of Tallahassee
Schedule 4
Previous Year and 2-Year Forecast of Retail Peak Demand and Net Energy for Load by Month
(1)
(2)
(3)
2013
Actual
Ten Year Site Plan
April 2014
Page 27
Month
Peak Demand
(MW)
NEL
(GWh)
January
February
March
April
May
June
July
August
September
October
November
December
427
471
480
409
472
543
535
537
535
464
379
427
204
193
208
200
222
257
254
272
256
218
194
206
TOTAL
(5)
2014
Forecast [1][2]
Peak Demand
NEL
(MW)
(GWh)
2,684
Peak Demand and NEL include DSM Impacts.
Represents forecast values for 2014.
508
481
419
455
517
561
561
561
532
450
386
418
225
198
207
208
237
262
272
282
253
217
194
206
2,761
(6)
(7)
2015
Forecast [1]
Peak Demand
NEL
(MW)
(GWh)
511
484
422
460
523
563
563
563
538
454
388
421
228
200
209
210
239
265
275
285
256
219
196
208
2,790
Table 2.13
[1]
[2]
(4)
City of Tallahassee, Florida
2014 Electric System Load Forecast
Key Explanatory Variables
Ten Year Site Plan
April 2014
Page 28
Ln.
No.
Model Name
1
2
3
4
5
6
7
8
9
10
11
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 Consumption
General Service Demand Consumption
General Service Large Demand Consumption
Summer Peak Demand
Winter Peak Demand
Tallahassee
Minimum Maximum
Leon
Cooling Heating Per Capita
State of
Winter Summer
County Residential Degree Degree Taxable Price of
Florida Peak day Peak day Appliance R Squared
Population Customers Days
Days
Sales
Electricity Population Temp.
Temp. Saturation
[1]
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
0.998
0.937
0.930
0.926
0.965
0.959
0.932
0.956
0.848
0.914
0.880
[1] R Squared, sometimes called the coefficient of determination, is a commonly used measure of goodness of fit of a linear model. If the observations fall 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 reasonably
good R Squared value could be anywhere from 0.6 to 1.
Table 2.14
Table 2.15
City of Tallahassee
2014 Electric System Load Forecast
Sources of Forecast Model Input Information
Energy Model Input Data
Source
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
18.
19.
20.
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
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
FAMU 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
21. Historical Residential Real Price of Electricity
22. Historical Commercial Real Price Of Electricity
Calculated from Revenues, kWh sold, CPI
Calculated from Revenues, kWh sold, CPI
Ten Year Site Plan
April 2014
Page 29
Banded Summer Peak Load Forecast Vs. Supply Resources
(Load Includes 17% Reserve Margin)
Megawatts (MW)
950
900
850
800
Ten Year Site Plan
April 2014
Page 30
750
700
650
600
550
500
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
Calendar Year
Base w/ DSM
High w/ DSM
Low w/ DSM
Base w/o DSM
Figure B3
Supply
Table 2.16
City Of Tallahassee
2014 Electric System Load Forecast
Projected Demand Side Management
Energy Reductions [1]
Calendar Year Basis
Year
Residential
Impact
(MWh)
Commercial
Impact
(MWh)
Total
Impact
(MWh)
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
8,719
17,439
26,158
34,878
43,597
52,316
61,036
69,755
78,475
87,194
4,537
8,595
13,633
19,651
24,563
30,077
35,756
41,600
47,609
53,783
13,256
26,034
39,791
54,529
68,160
82,393
96,792
111,355
126,084
140,977
[1]
Reductions estimated at generator busbar.
Ten Year Site Plan
April 2014
Page 31
City Of Tallahassee
2014 Electric System Load Forecast
Projected Demand Side Management
Seasonal Demand Reductions [1]
Ten Year Site Plan
April 2014
Page 32
Year
Residential
Commercial
Residential
Commercial
Demand Side
Energy Efficiency
Energy Efficiency
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)
Summer
Winter
(MW)
(MW)
(MW)
(MW)
(MW)
(MW)
2014
2014-2015
1
5
1
2
0
0
8
0
10
7
2015
2015-2016
3
7
3
3
0
0
12
0
18
10
2016
2016-2017
4
10
5
4
5
0
12
0
26
14
2017
2017-2018
6
12
7
5
11
0
12
0
36
17
2018
2018-2019
7
14
9
6
16
0
12
0
44
20
2019
2019-2020
9
16
11
7
21
0
12
0
53
23
2020
2020-2021
10
18
13
8
23
0
12
0
58
26
2021
2021-2022
11
20
15
10
24
0
12
0
62
30
2022
2022-2023
13
23
17
11
24
0
12
0
66
34
2023
2023-2024
14
25
19
12
24
0
13
0
70
37
Reductions estimated at busbar.
[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.
Table 2.17
[1]
City Of Tallahassee
Schedule 5
Fuel Requirements
(1)
(2)
(3)
Fuel Requirements
Ten Year Site Plan
April 2014
Page 33
(1)
Nuclear
(2)
Coal
(3)
(4)
(5)
(6)
(7)
Residual
(8)
(9)
(10)
(11)
(12)
(4)
(5)
(6)
(7)
(8)
(9)
(10)
(11)
(12)
(13)
(14)
(15)
(16)
Units
Actual
2012
Actual
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
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
Total
Steam
CC
CT
Diesel
1000 BBL
1000 BBL
1000 BBL
1000 BBL
1000 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
Distillate
Total
Steam
CC
CT
Diesel
1000 BBL
1000 BBL
1000 BBL
1000 BBL
1000 BBL
1
0
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
(13)
(14)
(15)
(16)
(17)
Natural Gas
Total
Steam
CC
CT
Diesel
1000 MCF
1000 MCF
1000 MCF
1000 MCF
1000 MCF
20,691
2,209
17,621
862
0
21,648
2,263
18,756
629
0
20,755
595
19,599
561
0
20,880
825
19,313
742
0
21,050
669
19,576
805
0
21,039
642
19,983
414
0
21,172
727
19,850
595
0
21,295
749
19,714
832
0
21,247
98
20,555
594
0
21,232
0
19,963
1,269
0
21,315
0
20,457
858
0
21,433
0
20,719
714
0
(18)
Other (Specify)
Trillion Btu
0
0
0
0
0
0
0
0
0
0
0
0
Table 2.18
City Of Tallahassee
Schedule 6.1
Energy Sources
(1)
(2)
(3)
Energy Sources
(4)
(5)
(6)
(7)
(8)
(9)
(10)
(11)
(12)
(13)
(14)
(15)
(16)
Units
Actual
2012
Actual
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
Ten Year Site Plan
April 2014
Page 34
Annual Firm Interchange
GWh
98
1
25
24
24
25
25
29
26
26
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
Total
Steam
CC
CT
Diesel
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
0
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)
(10)
(11)
(12)
(13)
Distillate
Total
Steam
CC
CT
Diesel
GWh
GWh
GWh
GWh
GWh
0
0
0
0
0
2
0
0
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
0
0
0
0
0
0
0
0
(14)
(15)
(16)
(17)
(18)
Natural Gas
Total
Steam
CC
CT
Diesel
GWh
GWh
GWh
GWh
GWh
2,509
168
2265
76
0
2,662
177
2433
52
0
2,761
51
2,656
54
0
2,779
70
2,633
76
0
2,801
57
2660
84
0
2,812
54
2714
44
0
2,835
62
2710
63
0
2,846
64
2,694
88
0
2,869
8
2798
63
0
2,871
0
2737
134
0
2,887
0
2797
90
0
2,903
0
2828
75
0
(19)
Hydro
GWh
6
23
11
11
11
11
11
11
11
11
11
11
(20)
Economy Interchange[1]
GWh
97
-3
-36
-24
-30
-28
-23
-23
-28
-16
-20
-23
(21)
Renewables
GWh
0
0
0
0
0
0
0
0
0
0
0
0
(22)
Net Energy for Load
GWh
2,710
2,684
2,761
2,790
2,806
2,820
2,848
2,863
2,878
2,892
2,905
2,918
[1]
Negative values reflect expected need to sell off-peak power to satisfy generator minimum load requirements, primarily in winter and shoulder mont
Table 2.19
(1)
City Of Tallahassee
Schedule 6.2
Energy Sources
(1)
(2)
(3)
Energy Sources
(4)
(5)
(6)
(7)
(8)
(9)
(10)
(11)
(12)
(13)
(14)
(15)
(16)
Units
Actual
2012
Actual
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
Ten Year Site Plan
April 2014
Page 35
(1)
Annual Firm Interchange
%
3.6
0.0
0.9
0.9
0.9
0.9
0.9
1.0
0.9
0.9
0.9
0.9
(2)
Coal
%
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)
Nuclear
%
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)
Residual
Total
Steam
CC
CT
Diesel
%
%
%
%
%
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
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)
(10)
(11)
(12)
(13)
Distillate
Total
Steam
CC
CT
Diesel
%
%
%
%
%
0.0
0.0
0.0
0.0
0.0
0.1
0.0
0.0
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
(14)
(15)
(16)
(17)
(18)
Natural Gas
Total
Steam
CC
CT
Diesel
%
%
%
%
%
92.6
6.2
83.6
2.8
0.0
99.2
6.6
90.7
1.9
0.0
100.0
1.8
96.2
2.0
0.0
99.6
2.5
94.4
2.7
0.0
99.8
2.0
94.8
3.0
0.0
99.7
1.9
96.2
1.6
0.0
99.5
2.2
95.2
2.2
0.0
99.4
2.2
94.1
3.1
0.0
99.7
0.3
97.2
2.2
0.0
99.3
0.0
94.6
4.6
0.0
99.4
0.0
96.3
3.1
0.0
99.5
0.0
96.9
2.6
0.0
(19)
Hydro
%
0.2
0.8
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
0.4
(20)
Economy Interchange
%
3.6
-0.1
-1.3
-0.9
-1.1
-1.0
-0.8
-0.8
-1.0
-0.6
-0.7
-0.8
(21)
Renewables
%
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
Table 2.20
Figure B4
Generation By Resource/Fuel Type
Calendar Year 2014
11 GWh or 0.4%
2,656 GWh or 96.2%
-11 GWh or -0.4.0%
54 GWh or 2.0%
50 GWh or 1.8%
Total 2014 NEL = 2,761 GWh
Calendar Year 2023
2,828 GWh or 96.9%
11 GWh or 0.4%
4 GWh or 0.1%
75 GWh or 2.6%
Total 2023 NEL = 2,918 GWh
CC - Gas
Steam - Gas
CT/Diesel - Gas
Ten Year Site Plan
April 2014
Page 36
Net Interchange
Hydro
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 repowering 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 II) 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 LIMITATIONS
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, Duke 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 2014
Page 37
The prospects for significant expansion of the regional transmission system around
Tallahassee hinges on the City’s ongoing discussions with Duke 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 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.
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 2014
Page 38
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 (2014-2018).
Resource additions expected in the longer term (2019-2023) are discussed in Section 3.2.6,
“Future Power Supply Resources”.
3.2.4
POWER SUPPLY DIVERSITY
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
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.
Other important considerations in the City’s planning process are the diversity of power
supply resources in terms of their number, sizes and expected duty cycles as well as expected
transmission import capabilities. To satisfy expected electric system requirements the City
currently assesses the adequacy of its 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 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. For these
Ten Year Site Plan
April 2014
Page 39
reasons the City has evaluated alternative and/or supplemental probabilistic metrics such as loss
of load expectation, or LOLE, 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 confirmed that the City’s current capacity mix and limited transmission import
capability are the biggest determinants of the City’s resource adequacy and suggest that there are
risks of potential resource shortfalls during periods other than at the time of the system peak
demand. Therefore, the City’s current deterministic load reserve margin criterion may need to
be increased and/or supplemented by a probabilistic criterion that takes these issues into
consideration. Toward this end the City intends to contract with a consultant to perform an
economic resource adequacy study during calendar year 2014. The study will give consideration
to the capital carrying costs and potential production cost savings associated with new generating
units, the costs associated with power purchases from the external bulk power market (including
potential investments to improve transmission import transfer capability) during normal
operations, emergencies and during periods of scarcity, and the cost of unserved energy from the
customer’s perspective. From the results the level of reserves that best balances resource
adequacy and economics consistent with the City’s risk tolerance will be identified. 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 the 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
Ten Year Site Plan
April 2014
Page 40
limited availability and uncertain performance, studies indicate that DSM and solar projects
would not improve resource adequacy (as measured by LOLE) 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
to protecting the environment and the quality of life in Tallahassee. As part of its continuing
commitment to explore clean energy alternatives, the City has continued to invest in
opportunities to develop viable solar photovoltaic (PV) projects as part of our efforts to offer
“green power” to our customers. There are ongoing concerns regarding the potential impact on
service reliability associated with reliance on a significant amount of intermittent resources like
PV on the City’s relatively small electric system. The City will continue to monitor the
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 2013 the City has a portfolio of 223 kW of solar PV
operated and maintained by the Electric Utility and a cumulative total of 1,500 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, 2013 both of these projects have been delayed due to
manufacturing issues associated with the technology. Such delays are to be expected with
Ten Year Site Plan
April 2014
Page 41
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.
3.2.6
FUTURE POWER SUPPLY RESOURCES
The City currently projects that additional power supply resources will be needed to
maintain electric system adequacy and reliability through the 2023 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 satisfy 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. Alternatively, the planned retirement of
Hopkins 1 could be postponed. The suitability of this resource plan is dependent on the
performance of the City’s 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 about 25 MW of additional power
supply resources to meet its planning reserve requirements in the summer of 2020.
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 2014 through 2023.
Ten Year Site Plan
April 2014
Page 42
Figure C
System Peak Demands
(Including DSM Impacts)
800
Summer
700
Winter
600
MW
500
400
300
200
100
0
2014
2015
2016
2017
2018
2019
2020
2021
2022
Year
Percent Reserve
Summer Reserve Margin (RM)
50
45
40
35
30
25
20
15
10
5
0
RM w/ DSM
2014
2015
2016
2017
RM w/o DSM
2018 2019
Year
Ten Year Site Plan
April 2014
Page 43
17% RM Criterion
2020
2021
2022
2023
2023
City Of Tallahassee
Schedule 7.1
Forecast of Capacity, Demand, and Scheduled Maintenance at Time of Summer Peak [1]
Ten Year Site Plan
April 2014
Page 44
(1)
(2)
(3)
(4)
Year
Total
Installed
Capacity
(MW)
Firm
Capacity
Import
(MW)
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
746
734
714
690
690
690
660
660
660
660
0
0
0
0
0
0
0
0
0
0
[1]
(5)
(6)
(7)
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
746
734
714
690
690
690
660
660
660
660
561
563
561
557
557
556
556
558
559
561
(8)
(9)
(10)
Reserve Margin
Scheduled
Before Maintenance Maintenance
(MW)
% of Peak
(MW)
185
171
153
133
133
134
104
102
101
99
33
30
27
24
24
24
19
18
18
18
0
0
0
0
0
0
0
0
0
0
(11)
(12)
Reserve Margin
After Maintenance
(MW)
% of Peak
185
171
153
133
133
134
104
102
101
99
33
30
27
24
24
24
19
18
18
18
All installed and firm import capacity changes are identified in the proposed generation expansion plan (Table 3.4).
Table 3.1
City Of Tallahassee
Schedule 7.2
Forecast of Capacity, Demand, and Scheduled Maintenance at Time of Winter Peak [1]
Ten Year Site Plan
April 2014
Page 45
(1)
(2)
(3)
(4)
Year
Total
Installed
Capacity
(MW)
Firm
Capacity
Import
(MW)
2014/15
2015/16
2016/17
2017/18
2018/19
2019/20
2020/21
2021/22
2022/23
2023/24
822
788
788
762
762
762
732
732
732
732
0
0
0
0
0
0
0
0
0
0
[1]
(5)
(6)
(7)
Firm
Capacity
Export
(MW)
QF
(MW)
Total
Capacity
Available
(MW)
System Firm
Winter Peak
Demand
(MW)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
822
788
788
762
762
762
732
732
732
732
511
514
516
520
522
525
526
528
529
532
(8)
(9)
(10)
Reserve Margin
Scheduled
Before Maintenance Maintenance
(MW)
% of Peak
(MW)
311
274
272
242
240
237
206
204
203
200
61
53
53
47
46
45
39
39
38
38
0
0
0
0
0
0
0
0
0
0
(11)
(12)
Reserve Margin
After Maintenance
(MW)
% of Peak
311
274
272
242
240
237
206
204
203
200
61
53
53
47
46
45
39
39
38
38
All installed and firm import capacity changes are identified in the proposed generation expansion plan (Table 3.4).
Table 3.2
City Of Tallahassee
Schedule 8
Planned and Prospective Generating Facility Additions and Changes
(1)
(2)
Ten Year Site Plan
April 2014
Page 46
(3)
(4)
(5)
(6)
(9)
(10)
(11)
(12)
Plant Name
Unit
No.
Location
Unit
Type
Const.
Start
Mo/Yr
Commercial
In-Service
Mo/Yr
Expected
Retirement
Mo/Yr
Gen. Max.
Nameplate
(kW)
Pri
Alt
Hopkins
CT-1
Leon
GT
NG
DFO
PL
TK
NA
2/70
3/15
16,320
-12
-14
RT
Purdom
CT-1
Wakulla
GT
NG
DFO
PL
TK
NA
12/63
10/15
15,000
-10
-10
RT
Purdom
CT-2
Wakulla
GT
NG
DFO
PL
TK
NA
5/64
10/15
15,000
-10
-10
RT
Hopkins
CT-2
Leon
GT
NG
DFO
PL
TK
NA
9/72
3/17
27,000
-24
-26
RT
Hopkins
1
Leon
ST
NG
RFO
PL
TK
NA
5/71
3/20
75,000
-76
-78
RT
Hopkins
5
Leon
CT
NG
DFO
PL
TK
5/17
5/20
NA
50,000
46
48
P
Gas Turbine
Steam Turbine
Pri
Alt
NG
DFO
RFO
PL
TK
Fuel
(7)
(8)
Fuel Transportation
Pri
Alt
(13)
(14)
Net Capability
Summer
Winter
(MW)
(MW)
(15)
Status
Acronyms
GT
ST
Primary Fuel
Alternate Fuel
Natural Gas
Diesel Fuel Oil
Residual Fuel Oil
Pipeline
Truck
kW
MW
RT
P
Kilowatts
Megawatts
Existing generator scheduled for retirement.
Planned for installation but not utility authorized. Not under construction.
Table 3.3
City Of Tallahassee
Generation Expansion Plan
Year
Load Forecast & Adjustments
Forecast
Net
Peak
Peak
Demand
DSM [1]
Demand
(MW)
(MW)
(MW)
Existing
Capacity
Net
(MW)
Ten Year Site Plan
April 2014
Page 47
2014
2015
2016
2017
2018
571
581
587
593
601
10
18
26
36
44
561
563
561
557
557
746
734
714
690
690
2019
2020
2021
2022
2023
609
614
620
625
631
53
58
62
66
70
556
556
558
559
561
690
614
614
614
614
Notes
[1]
[2]
[3]
[4]
[5]
[6]
Firm
Imports
(MW)
[2]
[3]
[4]
[5]
Firm
Exports
(MW)
Resource
Additions
(Cumulative)
(MW)
0
0
0
0
0
0
0
0
0
0
46
46
46
46
[6]
Total
Capacity
(MW)
Res
%
746
734
714
690
690
33
30
27
24
24
690
660
660
660
660
24
19
18
18
18
Demand Side Management includes energy efficiency and demand response/control measures.
Hopkins CT 1 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
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 or the planned retirement of Hopkins 1 could be
postponed .
Table 3.4
This page intentionally left blank.
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 or
the planned retirement of Hopkins Unit 1 could be postponed.
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,
Duke 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 Duke 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 affordable
Ten Year Site Plan
April 2014
Page 49
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. As the first phase of this
transmission project, the City tapped its existing Hopkins-Duke Crawfordville 230 kV
transmission line and extended a 230 kV transmission line to the east terminating at the existing
Substation BP-5. 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 BP4. 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 2015 is currently ongoing, and any revisions to
project budgets in the electric utility will not be finalized until the summer of 2014. 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 2014
Page 50
Table 4.1
City Of Tallahassee
Schedule 9
Status Report and Specifications of Proposed Generating Facilities
(1)
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)
Hopkins 5
May-17
May-20
Fuel
a.) Primary fuel:
b.) Alternate fuel:
NG
DFO
(6)
Air Pollution Control Strategy:
(7)
Cooling Status:
Unknown
(8)
Total Site Area:
Unknown
(9)
Construction Status:
Not started
(10)
Certification Status:
Not started
(11)
Status with Federal Agencies:
Not started
(12)
Projected Unit Performance Data
Planned Outage Factor (POF):
Forced Outage Factor:
Equivalent Availability Factor (EAF):
Resulting Capacity Factor (%):
Average Net Operating Heat Rate (ANOHR):
5.89
3.22
89.37
4.0
9,877
Projected Unit Financial Data
Book Life (Years)
Total Installed Cost (In-Service Year $/kW)
Direct Construction Cost ($/kW):
AFUDC Amount ($/kW):
Escalation ($/kW):
Fixed O & M ($kW-Yr):
Variable O & M ($/MWH):
K Factor:
30
1,218
1,050
NA
168
7.51
15.83
NA
(13)
Notes
[1]
[2]
[3]
[4]
[5]
[1]
BACT compliant
[2]
[3]
[4]
[5]
[5]
[5]
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 or the planned retirement of Hopkins 1 could be postponed.
Expected first year capacity factor.
Expected first year net average heat rate.
Estimated 2020 dollars.
Estimated 2014 dollars.
Ten Year Site Plan
April 2014
Page 51
Figure D-1 – Hopkins Plant Site
Figure D-2 – Purdom Plant Site
Ten Year Site Plan
April 2014
Page 52
City Of Tallahassee
Planned Transmission Projects, 2014-2023
Ten Year Site Plan
April 2014
Page 53
Number
Expected
In-Service
Date
Voltage
(kV)
Line
Length
(miles)
Project Type
Project Name
From Bus
Name
Number
New Lines
Line 55
Sub 14
7514
Sub 7
7507
6/1/15
115
6.0
Line Rebuild/
Reconductor
Line 15B
Line 15A [1]
Line 17 [1]
Sub 5
Sub 5
Sub 4
7505
7505
7605
Sub 9
Sub 4
Sub 7
7509
7504
7607
5/1/14
12/1/14
6/1/16
115
230
230
6.0
9.0
3.8
Transformers
Sub 4 230/115 Auto
Sub 4 230
7604
Sub 4 115
7504
12/1/14
NA
NA
Substations
Sub 22 (Bus 7522)
Sub 23 (Bus 7523)
NA
NA
NA
NA
NA
NA
NA
NA
1/1/17
1/1/17
115
115
NA
NA
To Bus
Name
[1] The second phase of the 230 kV loop project. Current 115 kV lines 15A and 17 will be operated at 230 kV after their respective in-service dates.
Table 4.2
Table 4.3
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 [1]
(2)
Number of Lines:
1
(3)
Right-of -Way:
TAL Owned
(4)
Line Length:
12.8 miles
(5)
Voltage:
230 kV
(6)
Anticipated Capital Timing:
See note [2]; target in service May 2015
(7)
Anticipated Capital Investment:
See note [2]
(8)
Substations:
See note [3]
(9)
Participation with Other Utilities:
None
Notes
[1]
[2]
[3]
Rebuilding/reconductoring existing Line 15A and Line 17 and changing operating voltage
from 115 kV to 230 kV.
Anticipated capital investment associated with rebuilding/reconductoring associated existing
transmission and substation facilities has not been segregated from that related to other
improvements being made to these facilities for purposes other than that of establishing this
230 kV transmission line.
North terminus will be existing Substation 7; south terminus will be existing Substation 5;
intermediate terminus will be existing Substation 4.
Ten Year Site Plan
April 2014
Page 54
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