Southwest Power PoolSouthwest Power PoolITP-20 Generating ResourcesITP-20 Generating Resources
May 25, 2010
February 10, 2010
B&V - 2
Agenda
Study Purpose and Scope
Study Approach
Resources Considered
Base Case Results
Questions
February 10, 2010
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Study Purpose and Work Scope
Phase I. Develop resource plans for each of four future scenarios, as defined by the SPP System Planning Committee, to be used in the ITP Year 20 EHV analysis. The resources will be selected using an optimal generation expansion model, Strategist, configured to provide resource planning solutions on a regional basis. The resource list will be generic prototype generators representing available future resources.
Phase II. Spatially located the new resources within SPP with the aid of GIS databases showing locations of transmission lines, natural gas pipelines, railroads, waterways, substations, etc.
Phase III. The new generators will be entered into a PowerBase database and connected to buses in the transmission system. The information entered into the PowerBase will be used by SPP in future studies.
February 10, 2010
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Study Approach
February 10, 2010
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Review of Study Approach
Used Powerbase data model provided by SPP.
Developed capital cost and performance estimates for future candidate units.
Developed Annual Levelized Fixed Charge Rates to apply to capital cost estimated to account for financing costs, insurance, taxes, etc
Updated data model based on feedback from stakeholders.
Developed renewable energy build-out scenario.
SPP footprint divided into two areas due to model limits.
Developed least cost generation expansion using Ventyx Strategist.
February 10, 2010
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Topology Review SPP footprint broken down into two sub-regions because of
Strategist dimension limits.
Initial attempt was to model the entire SPP in one model with 2 zones. But, encountered Strategist dimension limit.
SPP footprint modeled using two separate Strategist models for 2 sub-regions: SPP North (SPPN) and SPP South (SPPS)
Approximate dividing line – Kansas-Oklahoma State line
200 MW of capacity flow from SPPS to SPPN was allowed until SPPS was not excess on capacity to meet their own load and reserve requirements.
February 10, 2010
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SPP North (SPPN) Control AreasSPP North (SPPN) Control Areas
Greater Missouri Operations Company.
Independence Power and Light
Kansas City BPU
KCP&L
Westar Energy
Sunflower Electric Power Corp.
Lincoln Electric System
NPPD
OPPD
City Utilities of Springfield, MO
Empire District Electric Company.
MKE
MWE
February 10, 2010
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SPP South (SPPS) Control Areas
• AEP West
• OG&E
• Western Farmers Electric Co-operative
• Southwestern Public Service Company
• Central Louisiana Electric Company
• City of Lafayette
• Louisiana Energy and Power Authority
• GRDA
• Southwestern Power Administration
February 10, 2010
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Economic Inputs – Development of Fixed Charge Rate Used a proprietary Black & Veatch model for development of FCR
Fixed Charge Rate (FCR) is used to estimate the annual capital carrying cost for new plants and for new capital improvements done on existing plants.
A levelized fixed charge rate is a single, uniform rate that is applied to a unit’s total installed capital cost to yield the revenue requirements needed to recover cost on a present value basis. FCR varies depending upon various economic and financial assumptions.
Black & Veatch model develops different FCR for IOU, and Municipal and Cooperative (M&C) utilities.
Blended FCR calculated for SPP to account for different types of LSE in SPP. Assumed an 80/20 mix of generating resources additions by IOUs/M&C.
Technology dependent unit lives were assumed for FCR calculations: peaking (20 years), combined cycle (25 years), coal/nuclear (30 Years), and wind (5 year tax life, assumes not M&C financed).
February 10, 2010
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Fixed Charge RateAssumptions for IOU Assumptions for Municipalities
and Cooperatives D/E ratio of 55:45
7 percent cost of debt and 12 percent cost of equity
39 percent effective tax rate and 0.5 percent adder for insurance and property taxes
20 tax life
20 year FCR – 13.83 %
25 year FCR – 12.74 %
Fully debt financed and tax exempted
5.5 percent bond financing rate
0.5 percent adder for insurance and property taxes
20 year debt life FCR – 8.87 %
25 year debt life FCR – 7.96 %
Blended 20 year FCR and 25 year book life FCRs for SPP
is 12.84% and 11.79% respectively.
February 10, 2010
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Additional FCR Calculations
Calculated a single FCR for renewable resources assuming 5 year tax life and 20 year book life. Assumed all investors are
taxable due to preferential depreciation status
11.53% Calculated a blended FCR for
coal and nuclear resources assuming 20 year tax life and 30 year book life. 11.51%
Technology Tax Life (years)
Book Life
(years)
Blended FCR (%)
Combustion Turbine
20 20 12.84
Combined Cycle
20 25 11.79
Coal and Nuclear
20 30 11.51
Wind 5 20 11.53
(not blended)
February 10, 2010
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Generating Resources Considered
February 10, 2010
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Cost & Operating Assumptions for Conventional Alternatives
Asset Type Combined Cycle Combustion Turbine Nuclear Coal
Steam
Model Designation1x1
7FA.052x1
7FA.05 7FA.05 LM6000LMS100P
A AP1000SCPC (PRB)
Generation Fuel Gas Gas Gas Gas Gas uranium CoalStart Fuel Gas Gas Gas Gas Gas n/a GasTotal installed Cost (including Owner's Cost and IDC, $000s) 440,000 710,000 160,000 60,000 130,000 9,000,000 2,520,000Total installed Cost (including Owner's Cost and IDC, $/kW) 1,571 1,291 889 1,594 1,820 7,826 3,150Summer Ratings[Summer = 95F] Capacity (average degradation, MW) 280 550 180 38 71 1150 800 Heat Rate (degraded, HHV, Btu/kWh) 7,000 6,970 10,400 10,000 12,340 10,680 9,610Winter Ratings[Winter = 20 F] Capacity (average degradation, MW) 304 617.5 210 45 96 1150 800 Heat Rate (degraded, HHV, Btu/kWh) 6,960 6,930 10,080 9,460 8,950 10,680 9,610Variable O&M ($/MWh) 4.00 4.00 16.00 3.70 3.30 0 2.10Variable O&M ($/MWh) without MM 1.00 1.00 0.80Fixed O&M ($/kW-year) 8.10 6.90 6.80 12.50 18.50 60.00 26.50Maintenance Rate (hours per year) 444 444 168 168 168 500 438Forced Outage Rate (hours per year) 263 263 175 175 175 306 438Ramp Rate (%/minute) 5% 5% 18% 18% 18% 6% 6%Start Costs Cash Start Costs ($/start) 500 1,000 250 25 50 n/a 35,000 Cash Start Costs ($/start) incl MM 14,000 28,000 13,750 Fuel Start Costs (MMBtu start fuel/start) 1,100 1,900 250 26 44 n/a 22,800 CO2 Emission Rates (lbs/mmbtu) 115 115 115 115 115 0 210 SO2 Emission Rates (lbs/mmbtu) 0.0006 0.0006 0.0006 0.0006 0.0006 0 0.1 NOx Emission Rates (lbs/mmbtu) 0.0075 0.0075 0.0075 0.0075 0.0075 0 0.07 Hg Emission Rates (lbs/mmbtu) 0 0 0 0 0 0 1.3E-06
February 10, 2010
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Different Conventional Prototypes Modeled in Strategist
2x1 Generic Combined Cycle with maximum capacity of about 600 MW
800 MW Supercritical Pulverized Coal Unit without CCS
1100 MW Nuclear Unit
Baseload Resources
Generic frame CT with maximum capacity of about 200 MW
Peaking Resources
In addition, wind resources for meeting RPS requirements were added.
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Addition of Wind Resources
Wind Resource addition based on the Futures for Integrated Transmission Planning Process year 20 Assessment, Revision 3.
Business as Usual (Base case) wind additions assumes no RES requirements (as per Appendix 1 of the aforementioned document)
42,000 GWh of renewable generation is achieved by 2020 for the whole SPP area
At 40 percent capacity factor, this equates to about 11.9 GW of nameplate capacity
Capacity value (Firm Capacity) of wind resources is assumed to be 5 percent of the name plate capacity.
Wind resources capital cost assumed to be $2,150/kw (2010 dollars)
Operating costs of wind resources assumed to be $51/kw-year.
All new wind resources to meet RPS are expected to be online by 2020.
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Wind Resources (Total New plus Existing) by Year
-
2,000
4,000
6,000
8,000
10,000
12,000
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Year
Na
me
pla
te C
ap
ac
ity
(M
W)
Wind Capacity (New and Existing) By Year
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Other Key Assumptions
Model run for 20 years (2011-2030, inclusive)
No potential CO2 taxes considered for the base case
Coal PRB price forecast – No change to Ventyx forecast.
NG price forecast – HH forecast from Ventyx. Basis differentials updated base on SPP stakeholder feedback.
Uranium prices – Ventyx forecast updated based on stakeholder feedback.
Units are allowed to be added in intervals of 2/3 years, with the intervals increasing from 2 years to 4 years as we move further out into the study period.
200 MW of capacity is allowed to flow from SPPS to SPPN from 2010-2022 as SPPS has excess capacity at this time.
February 10, 2010
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EWITS and WWSIS data
Mesoscale modeled data
Modeled years are 2004, 2005, 2006
Used year 2005 profile because that year was judged as the best representative year.
10 minute data translated into 8760 hourly observations
Information presented in capacity factor (%) units
Profiles scaled accordingly to incorporate additional capacity factor information from actual project data
Wind Profile Data Collection Methodology
February 10, 2010
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Base Case Results
February 10, 2010
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Reserve Margin with No New Units – NPPN (Preliminary)
-
5,000
10,000
15,000
20,000
25,000
30,000
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
Year
Cap
acit
y (M
W)
-10.0%
-5.0%
0.0%
5.0%
10.0%
15.0%
20.0%
Res
erve
Mar
gin
(%
)
Existing Capacity RM Before Expansion FINAL PEAK
February 10, 2010
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Reserve Margin with No New Units – SPPN (Preliminary)
-
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
45,00020
11
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
Year
Cap
acit
y (M
W)
0.0%
5.0%
10.0%
15.0%
20.0%
25.0%
30.0%
35.0%
40.0%
45.0%
Res
erve
Mar
gin
(%
)
Existing Capacity RM Before Expansion FINAL PEAK
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Reserve Margin with No New Units – Whole SPP (Preliminary)
-
10,000
20,000
30,000
40,000
50,000
60,000
70,0002011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
Year
Cap
acit
y (
MW
)
-5.0%
0.0%
5.0%
10.0%
15.0%
20.0%
25.0%
30.0%
Reserv
e M
arg
in (
%)
Existing Capacity RM Before Expansion FINAL PEAK
February 10, 2010
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Expansion Plan – NPPN (Preliminary)
-
200
400
600
800
1,000
1,200
1,400
1,600
2011-2014 2015-2018 2019-2022 2023-2026 2027-2030
Period
Ca
pa
cit
y A
dd
ed
(M
W)
CC CT Coal Nuclear
February 10, 2010
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Expansion Plan – SPPN (Preliminary)
-
500
1,000
1,500
2,000
2,500
3,000
2011-2014 2015-2018 2019-2022 2023-2026 2027-2030
CC CT Coal Nuclear
February 10, 2010
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CO2 Emissions Intensity – SPPN and SSPP (Preliminary)
1,700
1,800
1,900
2,000
2,100
2,200
2,300
20
11
20
12
20
13
20
14
20
15
20
16
20
17
20
18
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
Year
(lb
s/M
Wh
)
February 10, 2010
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Reserve Margin with New Units – (Preliminary)
0%
5%
10%
15%
20%
25%
30%
35%
40%
45%
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
NSPP SSPP Whole SPP
February 10, 2010
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Base Case Results Observations
SPP North requires capacity additions early: 2014
SPP South requires capacity late: 2024
As wind resources are added in SPPN between 2013-2020, new baseload resources not justified. Lower capital cost intermediate and peaking units are added in this period.
Baseload resources are added in SPPN after 2020 when energy needs increase but additional wind resources are not added in the model.
SPP South needs intermediate and new baseload resources for the base case in the later half of the study period.
As no carbon legislation is assumed in the base case, coal units are selected in the later half of the study.
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