summary of proposed market rules for transition period price-responsive demand and active demand...

Summary of Proposed Market Rules For Transition Period Price-Responsive Demand and Active Demand Resources in the Forward Capacity Market

Henry Yoshimura, Director, Demand Resource StrategyISO New England

January 2012

© 2012 ISO New England Inc.

Background

The Commission’s Final Rule and Compliance Filing Requirements


Summary of Final Rule• On March 15, 2011, the Federal Energy Regulatory Commission

(“Commission”) issued its final rule on demand response compensation in Docket No. RM10-17-000.

– See Demand Response Compensation in Organized Wholesale Energy Markets, Final Rule, 134 FERC ¶ 61,187, Order No. 745, Docket No. RM10-17-000 (March 15, 2011).

• The Commission’s order requires ISOs/RTOs with tariff provisions permitting demand response resources to participate as a resource in the energy market by reducing consumption of electric energy from their expected levels in response to price signals to address:

– Demand response resource compensation

– Measurement and verification

– Cost allocation

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The Commission’s Final Rule

• Compensation: demand-response providers must be paid the full LMP when:– Demand-response resources have the capability to balance

supply and demand, and

– Payment when it is cost effective, as defined by a net-benefits test, to dispatch demand-response resources.

• Net-Benefits Test: the net-benefits test is satisfied when the overall reduction in customer energy payments from reduced LMPs exceeds the cost of paying demand-response providers.

– The net-benefits test can be implemented by establishing a price threshold level, updated on a monthly basis, at which the dispatch of demand-response resources will be cost-effective.

– Each ISO/RTO must study the integration of the net-benefits test into the dispatch algorithm and to file results by September 21, 2012.

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The Commission’s Final Rule (cont)

• Baseline evaluation: Each ISO/RTO directed to evaluate its current measurement and verification rules and to develop appropriate modifications, if necessary, to ensure that baselines remain accurate.

• Cost allocation: ISO/RTO’s must allocate the costs associated with demand response “proportionally to all entities that purchase from the relevant energy market in the area(s) where the demand response reduces the market price for energy at the time when the demand response resource is committed or dispatched.”

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Summary of the ISO’s Compliance Approach


The ISO’s Overall Compliance Approach

• The ISO’s ultimate goal is to fully integrate demand response into the energy markets.

• The ISO’s August 19, 2011 compliance filing included two areas of market rule changes:– Rules for the fully-integrated solution: New market rules that

fully integrate demand response into energy markets and system infrastructure that conform to the Commission’s Final Rule.

– Rules for the transition period: Because full integration is a multi-year project, a transitional program will be implemented and will remain in place until the fully-integrated approach is implemented.

• Current price-response programs sunset after May 31, 2012.

• Current programs will be replaced by a single transitional program, which will remain in place until the fully-integrated solution is implemented.

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The ISO’s Overall Compliance Approach (cont)• June 1, 2016: Target date for implementation of the fully-

integrated solution – date is coincident with the start of the 2016/2017 Capacity Commitment Period (FCA #7).– Effective date was recently changed given the delay in compliance

filing approval.

• June 1, 2012: Target date for implementation of the transition period solution.– Pending Commission approval.– Conforming changes to the FCM rules are required.

• Original plan was to file these changes with the Commission in the January 2012 timeframe.

• Delay in compliance filing approval will delay this filing.• Stay tuned….

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To replace current price-response programs and to remain in place until the fully-integrated approach can be implemented.

Transition Period: Energy Market Changes


Approach for the Transition Period

• Achieving full integration of demand response into the energy markets will take several years.

• In the interim, will replace current price-programs with a single program described herein.

• Changes are needed to comply with Order No. 745:– Change Threshold Price to reflect the Net-Benefits Test.– Change compensation approach to reward quantities of demand-

response delivered in real-time that are consistent with amounts offered and scheduled in response to LMPs.

• Balancing supply and demand requires amounts delivered be consistent with the amounts offered and scheduled.

– Improve the existing baseline methodology.– Change allocation of resulting program costs.

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Eligibility, Metering and Communication

• Any Real-Time Demand Response Asset that is part of a resource with a Capacity Supply Obligation can participate. – A Real-Time Demand Response Asset is essentially an individual

end-use customer.

• 5-minute interval metering reported in real time at the retail delivery point will be required.

• Energy injected into the grid not eligible for payment as demand response.– If registered as a generator, energy injections will be paid the LMP.

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Day-Ahead Demand Reduction Offers

• Demand-reduction offers must be submitted day ahead as in the current DALRP.– Offers consist of a single $/MWh price (≤ $1000/MWh) and a

single demand reduction amount (in MW to the nearest 0.1 MW).– Offers may also include:

• A curtailment initiation price – a fixed cost that must be recovered per interruption/start-up, and

• A minimum interruption duration period (up to four hours) – the minimum amount of time for which the energy consumption of the asset must be interrupted if scheduled.

– Offers valid during hours ending 0800 through 1800 on non-holiday operating days.

– Offer prices must exceed a Demand Reduction Threshold Price, which will be based on the Net-Benefits Test.

– Offers are cleared and scheduled as in the current DALRP.

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Net-Benefits Test

• The ISO will determine and publish a system-wide Demand Reduction Threshold Price at least once per month.– Consideration would be given to more frequent threshold price

updates during periods of highly volatile fuel prices.

• Demand Reduction Threshold Price will be based on the estimated supply curve for the month where reduced LMPs times MWh consumed equals payment to the dispatched demand-response resources.– See footnote 162 of the Order 745.

• Demand-reduction offers must be at or above the Demand Reduction Threshold Price, else the offer is rejected from consideration.

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MWh

LMP

LT L0

PT

P0

A

B

When A = B, PT is the Threshold Price

Establishing the Threshold Price

B

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SupplyP0 = LMP before DR reductionsPT = LMP after DR reductionsL0 = System Load before DR reductionsLT = System Load after DR reductionsA = Payment for DR reductionsB = Savings from DR reductions


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Table 1: 2010 Demand Reduction Threshold Prices Estimated by the ISO 1 2

Reference Month

Demand Reduction Threshold

Price ($/MWh)

January, 2010 55.5 February, 2010 51.4 March, 2010 43.6 April, 2010 40.1 May, 2010 38.6 June, 2010 43.2 July, 2010 40.9 August, 2010 38.9 September, 2010 36.0 October, 2010 33.8 November, 2010 37.7 December, 2010 47.0

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Real-Time Demand Reductions When Day-Ahead Offer is Not Accepted

• Demand reduction offers not scheduled day-ahead are eligible for payment in real-time if the offer price (not including the curtailment initiation price) is ≤ the provisional hourly Real-Time LMP published in the Operating Day for the Load Zone in which a Real-Time Demand Response Asset is located.– Will not be charged if a demand reduction offer does not clear

Day-Ahead and the Real-Time Demand Response Asset produces a negative Real-Time demand reduction amount.

• Assets intending to reduce ≥ 5 MW of load must contact the system operator prior to initiating the reduction.

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Baseline Changes

• The present Customer Baseline methodology will be used with the following changes to improve baseline accuracy:– Initial baselines computed from ten days of meter data.

– Baselines will be symmetrically adjusted on days with load-reduction events.

– Implementing a method to minimize baseline bias by requiring that the calculated baseline be periodically refreshed with contemporary meter data using the “3 of Last 10 Days” baseline refreshment method.

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3 of Last 10 Days Method

• Under the “3 of Last 10 Days” method, the decision to include a resource’s metered demand data in the baseline calculation on any given day is made by counting the number of days, over the past 10 days of the same day type (e.g., weekdays), on which metered demand data was included in the baseline calculation.

• If the number of “included” days over the past 10 days is less than three (3) days, then today’s metered demand data are included in the baseline calculation regardless of whether the resource cleared for today or not.

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Settlement and Cost Allocation

• Settlement based on the difference between the Adjusted Customer Baseline and metered load during the intervals the resource was scheduled to curtail day-ahead, or intervals where the bid price ≤ the provisional hourly Zonal Real-Time LMP.

• Day-Ahead Payment = Day-Ahead Scheduled Amount x Day-Ahead LMP for the location of the asset (Load Zone).

• Real-Time Payment/Charge = (Real-Time Demand Reduction – Day-Ahead Scheduled Amount) x the final hourly Real-Time LMP for the location of the resource (Load Zone).– The Real-Time demand reduction amount adjusted for net supply is limited to

200% of Demand Reduction Offer amount (loss adjusted).

• Payments/charges grossed-up to reflect distribution losses (estimated at 6.5%).• Payments and charges will be allocated proportionally on an hourly

basis to system-wide RTLO, excluding RTLO at external nodes.

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Transition Period: Capacity Market Changes

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Transition Period FCM Changes

• Demand Response Dispatch Triggers

• Energy Compensation for FCM Demand Reductions

• PRD Baseline Methodology

• NOTE: THESE CHANGES ARE CURRENTLY BEING DISCUSSED WITH STAKEHOLDERS AND HAVE NOT YET BEEN FILED WITH THE COMMISSION.– An extended delay in the issuance of a Commission order

on the ISO’s Order No. 745 compliance filing may delay this filing and delay transition period implementation.

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Demand Response Dispatch Triggers

• At the present time, RTDR are dispatched through two actions:– Forecasted Capacity Deficiency– Actual Capacity Deficiency

• The ISO is proposing to remove the dispatch associated to a Forecasted Capacity Deficiency.

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Energy Compensation

• Assets associated to RTDR and RTEG resources will be compensated for energy when demand is reduced pursuant to a Dispatch Instruction in response to OP4 or capacity audit (“Capacity Event”).

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Energy Compensation Rules

• When a RTDR or RTEG is dispatched for a Capacity Event, the associated assets’ demand reductions will be eligible for payments or charges at the Real-Time Zonal LMP based upon the following rules;– Asset is only eligible for the duration of the Capacity Event.– Demand reductions measured at the customer meter will be

grossed-up by the percent average avoided peak distribution losses (e.g., 6.5%) – the same factor as proposed in PRD rules.

– Any “push-back” associated to the asset is not eligible for payments.

• The “push-back” continues to be eligible to provide capacity during the transition period.

• Generation assets registered with the ISO will be paid for “push-back”.

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PRD Baseline Methodology

• The baseline methodology proposed under the Order 745 compliance filing (see Section III.8 of Market Rule 1) will be applied to all assets associated to RTDR and RTEG resources participating in the FCM.– All RTDR and RTEG, for purposes of measurement and

verification will be obligated to comply with this baseline methodology.

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summary of proposed market rules for transition period price-responsive demand and active demand...

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