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

3:15 – Utility Proposals

3:45 – Administrative Costs

5:00 - AdjournJanuary 7, 2011

2

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

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INTRODUCTION

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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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

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Under DevelopmentCal

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by A

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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

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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

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AVOIDED COST

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

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

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

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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

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

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%

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Capacity Allocation Based on Four Historical Years

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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

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0.9%8.8%

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Four Year Average(Used in DR Cost Effectiveness)

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PG&E LOLP(Shown for Comparison)

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Financial Pro Forma Updates

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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

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

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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%

Example CT Dispatch

Step 1: Forecast hourly real-time market prices based on heat rates from July 2009 through June 2010

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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

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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)

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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

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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)

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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

Data Sources and References

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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

DR REPORTING TEMPLATE

DR Reporting Template

Avoided Cost Model

• Publicly available data

• Non-proprietary tool

DR Reporting Template

• Standardized inputs

• Non-proprietary tool

• Common metrics for output

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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

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

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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

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LEGEND

Utility Input

Do Not Alter

Avoided Cost Input

CPUC Input

Formula

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

DR Reporting Template Inputs that are IOU Specific

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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

Program Impacts

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Wtd. Avg.Adjusted

Avoided Cost Input Utility Input

Program (Ratepayer) Costs

Administrative Costs

Incentive Costs

Equipment Costs (Amortized)

Net Bill/Revenue Reductions

= Total Ratepayer Costs

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Program (Ratepayer) Costs

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1. Program Costs

2. Equipment Costs

3. Amortization

4. By Category

4. TotalUtility Input

Participant Costs

Incentive Costs

Net Bill/Revenue Reductions

- Equipment Costs (Amortized)

= Total Ratepayer Costs

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X 75%

Participant Costs

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X 75%

+

1. Program Costs

2. Equipment Costs

3. Amortization

4. Estimate Costs

5. Total Utility Input

Cost Tests

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TRC PAC

Cost Tests

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RIM PAC

Avoided Cost Benefits

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Capacity

T&DEnergy

GHG

Optional and CAISO Market Benefits

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Adjustment Factors & T&D Values

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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)

Base Case Results

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Sensitivities

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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

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

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

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

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

A Factor (Availability)

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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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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

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

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

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%

D Factor (T&D Capacity Value)

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

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

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

Add example

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