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Demand Response Cost-effectiveness Protocols. Thursday, January 6, 2011. Eric Cutter, Snuller Price, Nick Schlag: E3. Agenda. 10:00 - Introductions 10:15 – Avoided Cost Calculator 11:30 – DR Reporting Template 12:30 – Lunch 1:30 – Adjustment Factors 3:00 – Break

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demand response cost effectiveness protocols

Demand Response Cost-effectiveness Protocols

Thursday, January 6, 2011

Eric Cutter, Snuller Price, Nick Schlag: E3

agenda
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 - Adjourn
dr process
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
two tools
Two Tools
  • Avoided Cost Model
    • Publicly available data
    • Non-proprietary tool
  • DR Reporting Template
    • Standardized inputs
    • Non-proprietary tool
    • Common metrics for output
avoided cost model and relationships
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

Exported to DR Reporting Template

Calculated by Avoided Cost Model

Under Development

use of avoided costs across proceedings
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
dr reporting template
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
avoided cost calculator updates
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
changes to the ct dispatch calculations
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
integration of temperature effects into capacity value
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
ct dispatch summer peak performance penalty
CT Dispatch: Summer Peak Performance Penalty

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

ct dispatch heat rate adjustment based on temperature
CT Dispatch: Heat Rate Adjustment Based on Temperature

Heat rate curve based on GE LM6000 with SPRINT technology and dry cooling

capacity allocation
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)
capacity allocation based on four historical years
Capacity Allocation Based on Four Historical Years

Percent of Total Capacity Value by Month

comparisoncapacity allocation
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

Percent of Total Capacity Value by Month

financial pro forma updates
Financial Pro Forma Updates
  • 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%
example ct dispatch
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
example ct dispatch1
Example CT Dispatch
  • Step 1: Forecast hourly real-time market prices based on heat rates from July 2009 through June 2010
example ct dispatch2
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
example ct dispatch3
Example CT Dispatch
  • Step 3: Sort real-time market prices (and corresponding CT operating costs) in descending order (top 1000 hours shown below)
example ct dispatch4
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
resulting california net cost of ct
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)
dr reporting template2
DR Reporting Template
  • Avoided Cost Model
    • Publicly available data
    • Non-proprietary tool
  • DR Reporting Template
    • Standardized inputs
    • Non-proprietary tool
    • Common metrics for output
using the dr template
Using the DR Template
  • Make sure latest inputs are copied from the Avoided Cost Calculator
  • Create a new tab for your program
    • Note! One tab for each ‘DR program’
  • Input load impacts for the DR program
  • Input costs for the DR program
  • Review cost-effectiveness results
  • Run sensitivity analysis
dr reporting template3
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
program impacts
Program Impacts

Wtd. Avg.

Adjusted

program ratepayer costs
Program (Ratepayer) Costs
  • Administrative Costs
  • Incentive Costs
  • Equipment Costs (Amortized)
  • Net Bill/Revenue Reductions
  • Total Ratepayer Costs
program ratepayer costs1
Program (Ratepayer) Costs

4. By Category

1. Program Costs

2. Equipment Costs

3. Amortization

4. Total

participant costs
Participant Costs
  • Incentive Costs
  • Net Bill/Revenue Reductions
  • Equipment Costs (Amortized)
  • Total Ratepayer Costs

X 75%

participant costs1
Participant Costs

1. Program Costs

+

X 75%

4. Estimate Costs

-

2. Equipment Costs

3. Amortization

5. Total

avoided cost benefits
Avoided Cost Benefits

Capacity

Energy

T&D

GHG

sensitivities
Sensitivities

Sensitivity values (blue cells) set at discretion of CPUC Energy Division

add new program
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
portfolio results
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
factor analysis framework
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
adjustment factors
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 prices
adjustment factor examples
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
a factor availability
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
b factor notification time
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
c factor trigger
C Factor (Trigger)
  • 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
c factor trigger examples
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
c factor trigger1
C Factor (Trigger)

Trigger: CAISO System Load above 43,000 MW

d factor t d capacity value
D Factor (T&D Capacity Value)
  • 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
d factor adjustment t d
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
d factor t d capacity value1
D Factor (T&D Capacity Value)

Coincidence of system capacity needs and expected distribution peak loads for each climate zone.

e factor energy
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.
e factor energy example
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
allocation of administration costs
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