Selected Findings from Scenario Analysis Conducted To...
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Selected Findings from Scenario Analysis Conducted To Date Power Committee Webinar June 26, 2014
Transcript of Selected Findings from Scenario Analysis Conducted To...
Selected Findings from Scenario Analysis
Conducted To Date
Power Committee Webinar June 26, 2014
Progress Since The June Council Meeting – Model Inputs
RPM inputs have been updated: Revised peak load forecast to reflect historical
relationship between weather and other factors (e.g., day of week) a peak loads Include announced retirement of Valmy coal
plants in 2026 Resource adequacy penalty was increased This guarantees that paying the penalty every
period is more expensive than building any of the resources that are available for selection in the model
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Progress Since The June Council Meeting – Model Structure
RPM has been revised: Resource expansion logic modified to reflect need
for capacity resources and contract status Resource adequacy penalty was changed to only
apply to capacity shortfalls that can be addressed by the resources in the model, i.e. penalties are not added into the NPV unless it’s possible for the model to avoid them All graphs used in this presentation show NPV
without any penalties added 3
Progress Since The June Council Meeting – Model Structure
RPM has been revised: Resource expansion logic modified to reflect need
for capacity resources and contract status The model was given close to “perfect foresight” so that
in each future it forecast close to exact need for capacity that will be needed in that future. While this reduces the risk associated with “forecast error” it was deemed acceptable given the short lead times for new resource development.
Resource adequacy penalty was changed to only apply to capacity shortfalls that can be addressed by the resources in the model, i.e. penalties are not added into the NPV unless it’s possible for the model to avoid them 4
Progress Since The June Council Meeting – Model Structure (2)
RPM revisions “in progress”: Testing of revised peak load forecast inputs and RPM
model revisions revealed the need for additional modifications
The hourly time-step of the GENESYS model allows it to use of hydro-system for peaking and dispatch other resources to provide energy (e.g., replaces water used for “peaking” with energy generated by wind and gas turbines)
RPM is being revised to allow peak/energy substitution to reflect NW system operation that is more consistent with GENESYS This is done by adjusting all resources to reflect their “System
Capacity Contribution”
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What Is “System Capacity Contribution”? (2)
System Capacity Contribution is the capacity credit of resources (e.g. wind, solar PV, CCCT) when integrated into an existing power system.�
The System Capacity Contribution may exceed the nameplate capacity of a plant in power systems that have storage Example:
A standalone battery can supply 10 MW, but without a system to charge it cannot provide either capacity or energy.
Coupling this battery to 100 MW thermal plant that supplies both the energy to charge the battery and 100 MW of capacity provides the system with 110 MW of capacity
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Why Does System Capacity Contribution Matter in the RPM?
NW Hydro-generation can be used to provide “peaking” and/or “energy” capability
There are “tradeoffs” Adding resources, like DR, that primarily provide
peaking capacity, allows the hydro system to be used more for energy production
Adding resources, like conservation and CCCTs, that can provide both energy and capacity, allows the hydro system to be used either more for peaking capacity or for energy production
Adjusting resources to reflect their capacity contribution allows the RPM to recognize resource that provide energy to “release” hydro-generation to meet short term peaking requirements
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Now, On To Scenario Comparisons and Observations Net System Cost
Least Cost Strategies for 1B, 2B, 2C and 3 A
53 97 123 135 167 178 266Net System Cost (Billions 2012 $)
Prob
abili
ty
Scenario1B2B2C3A
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The Average Present Value Net System Cost and Risk for Least Cost Strategies Under All Carbon Reduction
Are Similar
$-
$50
$100
$150
$200
$250
Average System Cost
System Risk (TailVar90)
Pres
ent V
alue
Net
Sys
tem
Cos
t (b
illio
ns 2
012$
)
Scenario 1B - Current Policy, No Carbon Risk
Scenario 2B - Carbon Reduction - Social Cost of Carbon Scenario 2C - Carbon Risk
Scenario 3A - Maximum Carbon Reduction, Existing Technology
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Observations from Scenarios To Date: Demand Response
Demand Response is the preferred resource to meet short-term peaking capacity requirements*
Why It is lowest cost option for maintaining capacity reserves It has a shorter lead-time and comes in more “modular”
sizes than generation About 1000 MW of DR resources can be optioned and built before
SCCT can be built (Q1 2018) DR defers the size of the SCCT build until after 2030.
It does not have fuel price risk It does not produce significant “energy” in an already
surplus market
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*Assumes that the limits to reliance on external market imports for winter capacity used in the Regional Resource Adequacy are constraining additional market purchases.
Observations from Scenarios To Date: Energy Efficiency
All least cost resource strategies rely heavily on conservation to meet both winter capacity and energy needs
Under 90 percent of the futures energy efficiency meets all load growth through 2030 and under 60 - 70 percent of the futures all load growth through 2035.
Why Significant amounts are available below projected future market prices
(e.g., 1200 aMW by 2021 and 3500 aMW by 2035 <$30/MWh It produces 2.0 MW/MWh saved during winter It has a shorter lead-time and comes in more “modular” sizes than
generation It does not have fuel price risk It does not have carbon price risk Its development is essential to attaining carbon emissions reductions, but
the quantity developed under least cost resources strategies does not significantly increase when carbon risk is considered
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Average Conservation Development Across Scenarios Increases When Carbon Risk Are Considered
But Does Not Increase With Full Coal Retirement or Consideration of the Social Cost of Carbon
-
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
5,000
Scenario 1B - Current Policy, No Carbon
Risk
Scenario 2B - Carbon Reduction - Social
Cost of Carbon
Scenario 2C - Carbon Risk
Scenario 3A - Maximum Carbon Reduction, Existing
Technology
Aver
age
Reso
urce
Dev
elop
men
t (aM
W)
2021
2026
2035
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5% Increase No Difference
Average Conservation Winter Peak Development in Least Cost Resource Strategies for Scenarios 1B, 2B, 2C and 3A
-
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
2021 2026 2035
Win
ter P
eak
Capa
city
(MW
)
Scenario 1B - Existing Policy, No Carbon Risk
Scenario 2B - Carbon Reduction - Social Cost of Carbon
Scenario 2C - Carbon Risk
Scenario 3A - Maximum Carbon Reduction, Existing Technology
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Regional Net Load After Conservation Remains “Flat On Average” Through 2035 Under the Least Cost
Strategy in Scenarios 1B, 2B, 2C and 3A
10,000
12,000
14,000
16,000
18,000
20,000
22,000
2015 2020 2025 2030 2035
PNW
Sys
tem
Loa
d (a
MW
)
Median - Scenario 1B - Existing Policy, No Carbon Risk
Median - Scenario 2B - Carbon Reduction - Social Cost of Carbon
Median - Scenario 2C - Carbon Risk
Median - Scenario 3A - Maximum Carbon Reduction, Existing Technology
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This Result is Very Similar To The 6th Plan Net Load After Conservation Scenarios 1B, 2B, 2C and 3A Least
Cost Strategy and 6th Plan
0
5,000
10,000
15,000
20,000
25,000
2010 2015 2020 2025 2030 2035
PNW
Pow
er S
yste
m L
oad
(aM
W)
6th Plan - Medium Forecast
Median - Scenario 1B - Existing Policy, No Carbon Risk
Median - Scenario 2B - Carbon Reduction - Social Cost of Carbon
Median - Scenario 2C - Carbon Risk
Median - Scenario 3A - Maximum Carbon Reduction, Existing Technology
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Observations from Scenarios To Date: Renewable Resources
All least cost resource strategies build renewable resources to satisfy state RPS requirements
Why REC banking delays the need for constructing RPS resources
until well past the action plan period Renewable resources are not deployed to mitigate future
carbon risk/cost even when the Social Cost of Carbon and future resource cost reductions (15% for solar PV and 5% for wind by 2030) are assumed
Why GHG gas reductions are achievable at a lower cost through
energy efficiency and the substitution of (mostly existing) natural gas for existing coal generation
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Average Renewable Resource Development for Energy Occurs After RECs are Used and Loads Begin To Increase
-
50
100
150
200
250
300
2021 2026 2035
Annu
al E
nerg
y Co
ntrib
utio
n (a
MW
) Scenario 1B - Existing Policy, No Carbon Risk
Scenario 2B - Carbon Reduction - Social Cost of Carbon
Scenario 2C - Carbon Risk
Scenario 3A - Maximum Carbon Reduction, Existing Technology
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Observations from Scenarios To Date: Thermal Resources
Thermal resource construction is driven by announced coal plant retirements
Why Energy efficiency and demand response meet most near
term capacity needs Combined cycle combustion turbines appear to be
favored over less efficient “peakers.” Why Future carbon risk, and to some extent fuel price risk, favor
more efficient gas-fired generation technologies Note: This finding is limited to meeting the
region’s capacity and energy needs and does not address the need for flexibility and balancing resources
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Observations from Scenarios To Date: Carbon Emissions Reduction
The least cost resource strategies that meet proposed CO2 Emissions Limits at the regional level: Meet all (or nearly all) load growth with energy efficiency Meet near term needs for capacity with demand response Replace retiring existing coal plans with increase gas-fired
generation, primarily from existing gas resources and later with combined cycle combustion turbines
Do not significantly expand the use of renewable resources
Why The lowest cost strategy to achieve CO2 reductions
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Scenario 2B and 2C Cost of Carbon Assumptions
$-
$20
$40
$60
$80
$100
$120
$140
$160
$180
$200
2015 2020 2025 2030 2035
Cost
of C
arbo
n (2
012$
/met
ric to
n)
Social Cost of Carbon (5% Discount) Scenario 2B - Social Cost of Carbon (3% Discount) Social Cost of Carbon (2.5% Discount) Social Cost of Carbon (3% Discount, 95th Percentile) Scenario 2C - Carbon Risk
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CO2 Emissions Across Least Cost Resources Strategies - 2030
-
5
10
15
20
25
30
35
40
45
50
Average 111(d) 90th Percentile 111(d)
Average PNWSystem
90th Percentile PNWSystem
MM
TE in
203
0
Scenario 1B - Existing Policy, No Carbon Risk
Scenario 2B - Carbon Reduction - Social Cost of Carbon
Scenario 2C - Carbon Risk
Scenario 3A - Maximum Carbon Reduction, Existing Technology
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EPA Proposed 111(d) Emissions Limits – 26.2 MMTE
Thermal Resource Dispatch without Carbon Risk – 1B
0
2,000
4,000
6,000
8,000
10,000
12,000
2016 2018 2020 2022 2024 2026 2028 2030 2032 2034
Annu
al D
ispa
tch
(aM
W)
Coal Natural Gas Solar Wind Must Run
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Thermal Resource Dispatch with Social Cost of Carbon – 2B
0
2,000
4,000
6,000
8,000
10,000
12,000
2016 2018 2020 2022 2024 2026 2028 2030 2032 2034
Annu
al D
ispa
tch
(aM
W)
Coal Natural Gas Solar Wind Must Run
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Thermal Resource Dispatch with Carbon Risk - 2C
0
2,000
4,000
6,000
8,000
10,000
12,000
2016 2018 2020 2022 2024 2026 2028 2030 2032 2034
Annu
al D
ispa
tch
(aM
W)
Coal Natural Gas Solar Wind Must Run
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Thermal Resource Dispatch with Coal and Inefficient Gas Retirement
0
2,000
4,000
6,000
8,000
10,000
12,000
2016 2018 2020 2022 2024 2026 2028 2030 2032 2034
Annu
al D
ispa
tch
(aM
W)
Coal Natural Gas Solar Wind Must Run
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Change in Coal Dispatch Scenarios 1B, 2B, 2C and 3A
0
1,000
2,000
3,000
4,000
5,000
2016 2018 2020 2022 2024 2026 2028 2030 2032 2034
Annu
al D
ispa
tch
(aM
W)
Scenario 1B - Existing Policy, No Carbon Risk Scenario 2B - Carbon Reduction - Social Cost of Carbon Scenario 2C - Carbon Risk Scenario 3A - Maximum Carbon Reduction, Existing Technology
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Change in Existing Gas Dispatch Scenario 1B, 2B, 2C and 3A
0
1,000
2,000
3,000
4,000
5,000
6,000
2016 2018 2020 2022 2024 2026 2028 2030 2032 2034
Annu
al D
ispa
tch
(aM
W)
Scenario 1B - Existing Policy, No Carbon Risk Scenario 2B - Carbon Reduction - Social Cost of Carbon Scenario 2C - Carbon Risk Scenario 3A - Maximum Carbon Reduction, Existing Technology
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Change in Renewable Resource Dispatch Scenarios 1B, 2B, 2C and 3A
0
500
1,000
1,500
2,000
2,500
3,000
3,500
2016 2018 2020 2022 2024 2026 2028 2030 2032 2034
Annu
al D
ispa
tch
(aM
W)
Scenario 1B - Existing Policy, No Carbon Risk
Scenario 2B - Carbon Reduction - Social Cost of Carbon
Scenario 2C - Carbon Risk
Scenario 3A - Maximum Carbon Reduction, Existing Technology
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Scenario 3B – Carbon Reduction with Emerging Technology
“The Energy Problem Statement”
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0
1,000
2,000
3,000
4,000
5,000
6,000
2016 2018 2020 2022 2024 2026 2028 2030 2032 2034
Annu
al D
ispa
tch
(aM
W)
Scenario 3A – Remaining Gas-Fired Generation ~ 5300 aMW of “Shaped Energy” That Must Be Supplied by Non-GHG Producing Resources or Additional Load Reduction from Conservation
Scenario 3B – Carbon Reduction with Emerging Technology
“The Capacity Problem Statement”
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0
2,000
4,000
6,000
8,000
10,000
12,000
2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036
Annu
al W
inte
r Pea
k D
ispa
tch
(MW
)
Scenario 3A – Remaining Gas-Fired Generation ~ 10,000 MW of “Peak Capacity” That Must Be Supplied by Non-GHG Producing Resources or Additional Peak Load Reduction from Conservation or Demand Response
Next Steps
Power Committee Meeting Revised analysis reflecting model input and
model structure changes for scenarios 1B, 2B, 2C, 3A – Updates S3 – No Demand Response
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