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![Page 1: Demand Response Cost- effectiveness Protocols Thursday, January 6, 2011 Eric Cutter, Snuller Price, Nick Schlag: E3.](https://reader035.fdocuments.in/reader035/viewer/2022062511/551a765b5503463e778b61d8/html5/thumbnails/1.jpg)
Demand Response Cost-effectiveness Protocols
Thursday, January 6, 2011
Eric Cutter, Snuller Price, Nick Schlag: E3
![Page 2: Demand Response Cost- effectiveness Protocols Thursday, January 6, 2011 Eric Cutter, Snuller Price, Nick Schlag: E3.](https://reader035.fdocuments.in/reader035/viewer/2022062511/551a765b5503463e778b61d8/html5/thumbnails/2.jpg)
Agenda
10:00 - Introductions
10:15 – Avoided Cost Calculator
11:30 – DR Reporting Template
12:30 – Lunch
1:30 – Adjustment Factors
3:00 – Break
3:15 – Utility Proposals
3:45 – Administrative Costs
5:00 - AdjournJanuary 7, 2011
2
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DR Process
November DR Workshop
• Overview of Avoided Costs, DR Reporting Template
Proposed Decision
Comments
Reply Comments
Final Decision
Today’s January Workshop
• Updates since November DR Workshop based on comments
3
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INTRODUCTION
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Two Tools
Avoided Cost Model
• Publicly available data
• Non-proprietary tool
DR Reporting Template
• Standardized inputs
• Non-proprietary tool
• Common metrics for output
5
2010 Dollars Benefits Costs
Net $/kW-Yr. Ratio
TRC $134,835,506 $42,860,823 $154 3.15PAC $56,128,584 $132 2.40RIM $56,524,967 $131 2.39PCT $55,678,548 $41,758,911 $23 1.33
Base Case Results
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Exp
orte
d to
DR
R
epor
ting
Tem
plat
e
Avoided Cost Model and Relationships
Benefits Included
• Energy purchases or generation cost
• Generation Capacity
• T&D Capacity
• GHG Emissions
• Losses
• Ancillary Services Procurement Reduction
• Reduced RPS procurement
• Renewable Integration
• Reducing overgen, Ramp
CPUC proceedings with similar approach
• Energy Efficiency
• DG Cost-effectiveness
• Permanent Load Shifting
CEC proceedings with similar model
• Title 24 Time-Dependent Valuation for evaluation of building standards
6
Under DevelopmentCal
cula
ted
by A
void
ed C
ost
Mod
el
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Use of Avoided Costs Across Proceedings
Same avoided costs from Avoided Cost Model
• DG Avoided Cost Framework
Each proceeding determines how to apply avoided costs
• Used for DG (CSI, SGIP) and DR
• EE still using previous approach
ALJ will provide guidance regarding application of avoided costs and DR protocols to PLS
7
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DR Reporting Template
Increased emphasis on consistency and transparency
Single, transparent Excel workbook for calculating and reporting cost-effectiveness results
Easy to compare and aggregate results
8
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AVOIDED COST
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Avoided Cost Calculator Updates
Key Changes to Avoided Cost Calculator
• CT dispatch
• Allocation of generation capacity value
• Financing assumptions and pro forma calculation
CT Dispatch Example
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Changes to the CT Dispatch Calculations
Several stakeholders were concerned that the capacity factor of the CT was too high
Added a 10% minimum bid margin to the CT dispatch algorithm, similar to CAISO methodology
• CAISO Market Performance Report http://www.caiso.com/2777/277789c42ac70.html
Adjusted CT operations based on historical temperature profiles
• Heat rate adjustment
• Reduced output
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Integration of Temperature Effects into Capacity Value
Temperature affects the operations—and hence the capacity residual—of a new CT in three ways:
• Operating Cost: High temperatures result in increases in the heat rate, which in turn increases the cost of generating a unit of energy
• Operating Performance Penalty: At high temperatures, the output of a CT is reduced, lowering the revenues the unit can earn by selling into the real-time market
• Peak Performance Penalty: During peak periods, when temperatures are also high, the output of the CT is reduced below nameplate, which increases the CT’s residual value per kW generated during the peak
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CT Dispatch: Summer Peak Performance Penalty
13
Output curve based on GE LM6000 with SPRINT technology and dry cooling: http://www.hilcoind.com/images/ftp/SFPUC/7/A/LM6000%2060%20Hz%20Grey%202008%20Rev%202.pdf
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CT Dispatch: Heat Rate Adjustment Based on Temperature
14
Heat rate curve based on GE LM6000 with SPRINT technology and dry cooling
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Capacity Allocation
Several stakeholder suggested that using a single year of historical load data to allocate capacity value was not representative
After the December workshop, E3 provided several alternatives including utility LOLP and four years of historical data
Final decision allocates capacity value based on four years of historical load data (2006-2009)
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11%
73%
9% 6%
0%
20%
40%
60%
80%
100%
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2006
2%
25%
56%
17%
0%
20%
40%
60%
80%
100%
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2007
4%
19% 24%
37%
15%
2%0%
20%
40%
60%
80%
100%
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2008
2%
39%26%
34%
0%
20%
40%
60%
80%
100%
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2009
Capacity Allocation Based on Four Historical Years
16
Per
cen
t o
f T
ota
l Cap
acit
y V
alu
e b
y M
on
th
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ComparisonCapacity Allocation
The allocators used to value DR peak impacts are based on the average of the allocators calculated for the period 2006-2009
In most months, this serves as a reasonable approximation of PG&E’s LOLP
17
0.9%8.8%
40%32%
18%
0.5%0%
20%
40%
60%
80%
100%
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Four Year Average(Used in DR Cost Effectiveness)
1.3% 1.0% 0.3%12%
3.2%
32% 34%
14%
1.3%0%
20%
40%
60%
80%
100%
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
PG&E LOLP(Shown for Comparison)
Per
cen
t o
f T
ota
l Cap
acit
y V
alu
e b
y M
on
th
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Financial Pro Forma Updates
18
Correction of CT MACRS term from 20 to 15 years
Addition of property tax and insurance costs
• Property tax: 1.1% of capital costs per year
• Insurance: 0.6% of capital costs per year
Addition of Manufacturing Tax Credit
• 9% of half of plant W2 wages (4.5%), based on CEC COG Model
Adjustment of debt/equity shares to reflect current financing climate – still assuming 3rd party owned CT
• Increased debt share in capital structure from 50% to 60%
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Example CT Dispatch
To calculate the value of capacity, E3 assumes that a CT will participate in the CAISO real-time market
• Consistent with CAISO Annual Market Report
The parameters that determine the CT’s net revenues include the real-time prices, the cost of fuel, the unit’s heat rate and O&M, and ambient temperature
19
Central Station Plant AssumptionsCT
Operating DataHeat rate (BTU/kWh) 9,300Cap Factor 5.5%Lifetime (yrs) 20
Plant CostsIn-Service Cost ($/kW) $1,365Fixed O&M ($/kW-yr.) $17.40Variable O&M ($/MWh) $4.17Cost Basis Year for Plant Costs 2009
Levelized Costs (2012)Annual Fixed Cost ($/kW-yr) 192.72 Real-Time Energy Revenue (89.01) AS Revenue (9.86) Operating Cost 31.90 Residual Capacity Value 125.76 Summer Output 92%Summer Capacity Value 136.99
FinancingDebt-to-Equity 60%Debt Cost 7.7%Equity Cost 12.0%Marginal Tax Rate 40.7%
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Example CT Dispatch
Step 1: Forecast hourly real-time market prices based on heat rates from July 2009 through June 2010
20
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Example CT Dispatch
Step 2: Calculate operating cost ($/MWh) for a CT in each month as a function of the gas price, heat rate, and variable O&M
21
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Example CT Dispatch
Step 3: Sort real-time market prices (and corresponding CT operating costs) in descending order (top 1000 hours shown below)
22
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Example CT Dispatch
Step 4: Calculate the CT’s revenue assuming it operates when the real-time price exceeds its variable cost plus the 10% bid adder
23
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Resulting California Net Cost of CT
Calculation of the final residual value includes several further adjustments
• Energy revenues reduced by 7% for plant outages
• A/S market participation assumed to increase gross revenues by 11% (based on CAISO market report)
24
2010 2011 2012 2013 2014 2015 2016CT Annualized Fixed Cost 185$ 189$ 193$ 197$ 201$ 205$ 209$
Real-Time Dispatch Revenue 63$ 81$ 89$ 96$ 102$ 106$ 111$ Ancillary Services Revenue 7$ 9$ 10$ 11$ 11$ 12$ 12$ Operating Cost (23)$ (29)$ (32)$ (35)$ (37)$ (39)$ (40)$
CT Net Revenue 47$ 61$ 67$ 72$ 76$ 79$ 83$ Capacity Residual 138$ 128$ 126$ 125$ 124$ 125$ 126$ Temperature Adjusted Capacity Residual 151$ 139$ 137$ 136$ 135$ 136$ 137$ Capacity Factor 4.7% 5.3% 5.5% 5.7% 5.9% 5.9% 5.9%All costs in $/kW-yr
Current DR Program Cycle
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Data Sources and References
25
Cost Effectiveness Methodology E3 Demand Response Documents (including Distributed Generation Avoided Cost Calculator)(Note: outputs from calculator are modified for DR in this spreadsheet)www.ethree.com\public_projects\cpucdr.html
R 08-03-008, D. 09-08-026http://docs.cpuc.ca.gov/word_pdf/FINAL_DECISION/105926.pdf
CSI Cost Effectiveness Report based on Distributed Generation Cost Effectiveness Frameworkhttp://www.ethree.com/public_projects/cpuc.html
CT Cost and Performance 2008 & 2009 CAISO Market Issues and Performance Reportwww.caiso.com/2390/239087966e450.pdf
http://www.caiso.com/2777/277789c42ac70.html
2007 CEC Cost of Generation Reporthttp://www.energy.ca.gov/2007publications/CEC-200-2007-011/CEC-200-2007-011-SF.PDF
Planning Reserve Margin R. 08-04-012, D. 04-01-050 and Proposed Decision mailed August 23, 2010 closing the proceeding. http://docs.cpuc.ca.gov/efile/PD/122343.pdf
CT Summer Capacity Derate LM6000 - 60Hz Gas Turbine Generator Set Product Specificationhttp://www.hilcoind.com/images/ftp/SFPUC/7/A/LM6000%2060%20Hz%20Grey%202008%20Rev%202.pdf
http://www.gepower.com/prod_serv/products/tech_docs/en/downloads/ger3695e.pdf
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DR REPORTING TEMPLATE
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DR Reporting Template
Avoided Cost Model
• Publicly available data
• Non-proprietary tool
DR Reporting Template
• Standardized inputs
• Non-proprietary tool
• Common metrics for output
27
2010 Dollars Benefits Costs
Net $/kW-Yr. Ratio
TRC $134,835,506 $42,860,823 $154 3.15PAC $56,128,584 $132 2.40RIM $56,524,967 $131 2.39PCT $55,678,548 $41,758,911 $23 1.33
Base Case Results
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Using the DR Template
1. Make sure latest inputs are copied from the Avoided Cost Calculator
2. Create a new tab for your program
• Note! One tab for each ‘DR program’
3. Input load impacts for the DR program
4. Input costs for the DR program
5. Review cost-effectiveness results
6. Run sensitivity analysis
28
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DR Reporting Template
Avoided Cost Inputs
Program Impacts
Program Costs
Results
Optional Benefits
T&D Costs
Adjustment Factors
What constitutes a program
Adding New Program
29
LEGEND
Utility Input
Do Not Alter
Avoided Cost Input
CPUC Input
Formula
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DR Reporting Template Inputs from Avoided Cost Calculator
Avoided Cost Values (Nominal) LEGEND
2012 2013 2014Market Price ($/MWh) $51.15 $54.24 $57.11Ancillary Services ($/MWh) $0.51 $0.54 $0.57On-Peak Multiplier 141% 141% 141%On-Peak Market Price ($/MWh) $72.10 $76.46 $80.55Nameplate Generation Capacity ($/kW-yr) $125.76 $124.65 $124.11Summer Generation Capacity ($/kW-yr) $136.99 $135.78 $135.19Transmission Deferral ($/kW-yr) $19.58 $19.97 $20.37Distribution Deferral ($/kW-yr) $57.03 $58.17 $59.33Emissions ($/ton) $15.37 $16.89 $19.87Avoided cost values above have not been adjusted for losses
Avoided Cost Input
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DR Reporting Template Inputs that are IOU Specific
31
On-Peak Losses Transmission Deferral ($/kW-yr) Distribution Deferral ($/kW-yr)Gen. T&D D 2012 2013 2014
PG&E 10.9% 8.3% 4.8% $19.58 $19.97 $20.37SCE 8.4% 5.4% 2.2% $23.85 $24.33 $24.82SDG&E 8.1% 7.1% 4.3% $21.50 $21.93 $22.37SDG&E 10.9% 8.3% 4.8% $19.58 $19.97 $20.37
Distribution Deferral ($/kW-yr) WACC2012 2013 2014
PG&E $57.03 $58.17 $59.33 8.8%SCE $30.71 $31.32 $31.95 8.8%SDG&E $53.28 $54.35 $55.43 8.4%SDG&E $57.03 $58.17 $59.33 8.8%
Avoided Cost Input
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Program Impacts
32
Wtd. Avg.Adjusted
Avoided Cost Input Utility Input
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Program (Ratepayer) Costs
Administrative Costs
Incentive Costs
Equipment Costs (Amortized)
Net Bill/Revenue Reductions
= Total Ratepayer Costs
33
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Program (Ratepayer) Costs
34
1. Program Costs
2. Equipment Costs
3. Amortization
4. By Category
4. TotalUtility Input
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Participant Costs
Incentive Costs
Net Bill/Revenue Reductions
- Equipment Costs (Amortized)
= Total Ratepayer Costs
35
X 75%
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Participant Costs
36
X 75%
+
1. Program Costs
2. Equipment Costs
3. Amortization
4. Estimate Costs
5. Total Utility Input
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Cost Tests
37
TRC PAC
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Cost Tests
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RIM PAC
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Avoided Cost Benefits
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Capacity
T&DEnergy
GHG
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Optional and CAISO Market Benefits
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Adjustment Factors & T&D Values
41
Adjustment Factors LEGEND
A) Availability adjustment 95.00% Utility Input
B) Notification adjustment 100.00% Do Not Alter
C) Trigger adjustment 100.00% Select Avoided Cost Input
D) T&D right time-right place adjustment 100.00% T&D Value--> D Only FormulaE) Energy price adjustment 100.00%
Program Annual Inputs Monthly InputsNominal Dollars
Adjusted Avoided Cost Values 2012 2013 2014 2012 2013 2014
Monthly Generation Capacity AllocationMonthly T&D Capacity Allocation
(Inputs override monthly inputs)
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Base Case Results
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Sensitivities
43
Sensitivities% Incentives as Participant Costs high value 100% Base Case 75% Central Station Plant Assumptions low value 50%Generation Capacity Costs - % -30% + % +30%T&D Capacity Costs - % -30% + % +30%Capital Ammortization Period Years 3 Years 15 Load Impact - % -30% + % +30%A Adjustment Factor - % -10% 100 % (No Adjustment) 100%+/- % Sensitivity values are multiplicative
e.g. for low case, the A Adjustment factor will be
multiplied by (1-10%) or 90%
-0.50 1.00 1.50 2.00 2.50 3.00 3.50 4.00 4.50 5.00
100% 50% -30% +30% -30% +30% 3 Years 15 Years -30% +30% 86% 100%
Base Case
% of Incentives as Participant Costs
Generation Capacity Value
T&D Capacity Value
Capital Amortization
Period
Load Impact A Factor
TRC Sensitivity Analysis
Sensitivity values (blue cells) set at discretion of CPUC Energy Division
CPUC Input
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Add New Program
Definition of Program
• Any program or sub-program with distinct features
• Availability, Notification Time, Trigger etc.
• Distinct A-E factors
Add Program
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Portfolio Results
Total DR portfolio cost and results entered in separate tab
• Account for dual participation
• DR Reporting Template cannot simply sum across programs automatically
Ensure that portfolio impact, costs and benefits are accurate and representative
• Calculation will need to be performed by utility outside of DR Reporting Template
• Back into representative average A-E factors to that portfolio impacts X avoided costs = portfolio benefits
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Questions and Excel Demo Example
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FACTOR ANALYSIS
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Factor Analysis Framework
Make appropriate adjustments for differences between DR resource and resources used to determine Avoided Costs
• Combustion Turbine, T&D infrastructure etc.
Allow some flexibility for utility specific values and approaches
Reduce analysis to single percentage factor for easy comparison across programs and utilities
Must be supported by analysis and explanation
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Adjustment Factors
A Factor – Availability
• Maximum number, duration and timing of DR calls
B Factor – Notification Time
• Length of program notification time
C Factor – Trigger
• Flexibility in when DR calls may be made
D Factor – T&D Capacity value
• Marginal vs. Avoided T&D costs
• Right Time: Coincidence of DR calls with local T&D system peaks
• Right Place: Ability to target DR calls based on local conditions
• Right Certainty: Reliable enough for T&D deferral
E Factor – Energy Value
• Energy value when DR is call as compared to average On-Peak energy prices49
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Adjustment Factor Examples
E3 Produced example approaches for analysis supporting each factor
Suggested approaches only: utility may suggest/develop alternative approaches
Must support analysis with public data
• Can use proprietary data (e.g. LOLP), but also perform analysis with public data
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A Factor (Availability)
Percentage of Generation Capacity Value captured by maximum number of DR call hours permitted
Constraints
• Maximum Number of Calls per Year
• Maximum Number of Calls per Month
• Maximum Number of Hours per Call
Public Data
• 4 years of CAISO load data
Percentage of peak CAISO load hours captured by DR Program
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A Factor (Availability)
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Max
imum
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acity
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ue C
aptu
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acto
r)
Duration of Calls (Hours)
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B Factor (Notification Time)
Percentage of Generation Capacity Value captured with minimum notification time
Constraints
• Minimum advanced notification time
Public Data
• CAISO Load Forecasts (Day Ahead and Two Day Ahead)
• CAISO Actual Loads
Percentage of actual peak CAISO load hours predicted by forecasts
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B Factor (Notification Time)
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Four YearAverage
2006 2007 2008 2009
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aptu
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d on
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C Factor (Trigger)
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Percentage of Generation Capacity Value captured by DR Program Trigger
Constraints
• Conditions under which DR Call may be made
Public Data
• CAISO Day Ahead System Load Forecast
• Temperature Data
• Market Heat Rate
Percentage of actual peak CAISO load hours captured by Trigger
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C Factor (Trigger) Examples
Example Triggers
• CAISO System load above 43,000 MW
• Marginal heat rate above 15,000 BTU/kWh
• CAISO Stage 1 emergency imminent
• “Extreme or unusual” temperature conditions
C Factor Comparisons
• Historical comparison of trigger events to peak loads
• Real-time peak loads not captured by trigger
• Triggered calls when not needed in real-time
• Ratio of actual historical calls to allowable calls
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C Factor (Trigger)
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C-Factor: Trigger2006 2007 2008 2009
Critical Load (MW) 43,000 43,000 43,000 43,000 January - - - -
February - - - - March - - - -
April - - - - May - - - - June 0.03 - 0.06 - July 0.53 0.05 0.12 0.05
August 0.00 0.27 0.07 0.04 September 0.01 0.08 0.02 0.06
October - - - - November - - - - December - - - -
Total 0.57 0.40 0.28 0.15
Trigger: CAISO System Load above 43,000 MW
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D Factor (T&D Capacity Value)
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Percentage of T&D Capacity Value captured by DR Program
Constraints
• DR Calls made based on CAISO system conditions
Public Data
• CAISO Day Ahead System Load Forecast
• Temperature Data
Percentage of Climate Zone peak load hours captured by Trigger based on system conditions
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D Factor Adjustment (T&D)
Two Adjustment Factors
Marginal vs. Avoided T&D costs
• Reduced marginal cost for costs that are unavoidable in a shorter to medium time-frame
• Admin and General Expenses, O&M labor
‘Right time’ and ‘right place’ adjustment
• Alignment of DR calls to local distribution and regional transmission constraints
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Marginal vs. Avoided T&D Cost
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Marginal CostTransmission Distribution Total
PG&E $ 19.18 $ 55.91 $ 75.09
SCE $ 18.79 $ 21.07 $ 39.87
SDG&E $ 21.08 $ 52.24 $ 73.31
Avoided CostTransmission Distribution Total
PG&E $ 12.24 $ 39.70 $ 51.94
SCE $ 14.20 $ 12.05 $ 26.25
SDG&E $ 13.22 $ 35.43 $ 48.65
Adjustment FactorsTransmission Distribution Total
PG&E 64% 71% 69%SCE 76% 57% 66%SDG&E 63% 68% 66%
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D Factor (T&D Capacity Value)
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ent o
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0 Sy
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d H
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Climate Zone
Coincidence of system capacity needs and expected distribution peak loads for each climate zone.
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E Factor (Energy)
Percentage adjustment to average Summer On-Peak Energy Price
Constraints
• Expected hour of DR calls may have energy prices that are higher or lower than average On-Peak prices.
Public Data
• Hourly Avoided Costs
• CAISO Hourly Market Prices
Calculate Ratio of expected average energy prices during DR calls to average On-Peak energy prices.
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E Factor (Energy) Example
Example Adjustments for Energy Price
• 2-4 hour calls for AC program expected during hours with average price much higher than ~ $80/MWh
• DR program targeted to locally constrained area with congestion
• DR Program with more flexible calls (24/7/365) would have average price closer to $55/MWh
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UTILITY PROPOSALS
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ADMINISTRATION COSTS
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Allocation of Administration Costs
All costs that support individual programs should be included in individual program costs
General Overhead, Administration and Marketing budgets must be allocated by some method that is justified by the utility
Suggested Allocators:
• Actual program workload
• # of customers
• MWs
• Incentive Costs
• Avoided Cost Benefits
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Add example
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