We think you have liked this presentation. If you wish to download it, please recommend it to your friends in any social system. Share buttons are a little bit lower. Thank you!
Presentation is loading. Please wait.
Published byGillian Short
Modified over 2 years ago
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 Strategy ISO New England January 2012 © 2012 ISO New England Inc.
Background The Commissions Final Rule and Compliance Filing Requirements © 2012 ISO New England Inc.
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. RM –See Demand Response Compensation in Organized Wholesale Energy Markets, Final Rule, 134 FERC ¶ 61,187, Order No. 745, Docket No. RM (March 15, 2011). The Commissions 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 3 © 2012 ISO New England Inc.
The Commissions 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 ISO New England Inc.
The Commissions 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/RTOs 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. 5 © 2012 ISO New England Inc.
Summary of the ISOs Compliance Approach © 2012 ISO New England Inc.
The ISOs Overall Compliance Approach The ISOs ultimate goal is to fully integrate demand response into the energy markets. The ISOs 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 Commissions 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, Current programs will be replaced by a single transitional program, which will remain in place until the fully-integrated solution is implemented. 7 © 2012 ISO New England Inc.
The ISOs 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…. 8 © 2012 ISO New England Inc.
To replace current price-response programs and to remain in place until the fully-integrated approach can be implemented. Transition Period: Energy Market Changes © 2012 ISO New England Inc.
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. 10 © 2012 ISO New England Inc.
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. 11 © 2012 ISO New England Inc.
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. 12 © 2012 ISO New England Inc.
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. 13 © 2012 ISO New England Inc.
MWh LMP LTLT L0L0 PTPT P0P0 A B When A = B, P T is the Threshold Price Establishing the Threshold Price B 14 Supply P 0 = LMP before DR reductions P T = LMP after DR reductions L 0 = System Load before DR reductions L T = System Load after DR reductions A = Payment for DR reductions B = Savings from DR reductions © 2012 ISO New England Inc.
15 © 2012 ISO New England Inc.
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. 16 © 2012 ISO New England Inc.
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. 17 © 2012 ISO New England Inc.
3 of Last 10 Days Method Under the 3 of Last 10 Days method, the decision to include a resources 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 todays metered demand data are included in the baseline calculation regardless of whether the resource cleared for today or not. 18 © 2012 ISO New England Inc.
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. 19 © 2012 ISO New England Inc.
Transition Period: Capacity Market Changes 20 © 2012 ISO New England Inc.
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 ISOs Order No. 745 compliance filing may delay this filing and delay transition period implementation. 21 © 2012 ISO New England Inc.
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. 22 © 2012 ISO New England Inc.
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). 23 © 2012 ISO New England Inc.
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. 24 © 2012 ISO New England Inc.
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. 25 © 2012 ISO New England Inc.
New England Developments in Demand Response and Smart Grid 2010 National Town Meeting on Demand Response and Smart Grid Henry Yoshimura, Director, Demand.
PJM©2013www.pjm.com Economic DR participation in energy market ERCOT April 14, 2014 Pete Langbein.
Demand Resource Operable Capacity Analysis – Assumptions for FCA 5.
SEPTEMBER 12, 2012 | MARKETS COMMITTEE Aleks Mitreski MARKET DEVELOPMENT (413) Hourly Offer and Intraday.
Achieving Price-Responsive Demand in New England Henry Yoshimura Director, Demand Resource Strategy ISO New England National Town Meeting on Demand Response.
FEBRUARY 14, 2013 RELIABILITY COMMITTEE MEETING Steve Weaver SYSTEM OPERATIONS In-Day Reserves & Supplemental Procurement.
ISO New England Demand Resource Measurement & Verification Standards Manual Overview April 11, 2007 NAESB Development of DSM/EE Business Practices Washington,
DECEMBER 17, 2013 | WESTBOROUGH, MA Reliability Committee & Transmission Committee & Markets Committee Capacity Zone Modeling Al McBride MANAGER, AREA.
JANUARY 14-15, 2014 | NEPOOL MARKETS COMMITTEE Matthew Brewster MARKET DEVELOPMENT | Conceptual design.
Ancillary Services Market, Day-Ahead Load Response and Special Case Nodal Pricing Implementation Vamsi Chadalavada FERC Technical Conference March 4, 2005.
© 2013 Day Pitney LLP Overview and Update on the Ever-Evolving New England Wholesale Capacity Market presentation to Boston Bar Association May 23, 2013.
Demand Side Products in PJM Joseph BowringCornell University January 17, 2011.
OCTOBER 8, 2014 Bob Laurita INTERNAL MARKET MONITORING New Import Capacity Resource FCM Market Power Mitigation Order to Show Cause Compliance Filing.
Demand Resources: Challenges and New Initiatives for ISO New England Henry Yoshimura, ISO New England NEW DEMAND RESPONSE PRODUCTS IN ELECTRICITY MARKETS.
PJM© Demand Response in PJM 2009 NASUCA Mid-Year Meeting June 30, 2009 Boston, MA Panel: Price Responsive Demand – A Long-Term Bargain.
03/11/2013 MARKETS COMMITTEE Aleks Mitreski MARKET DEVELOPMENT (413) Overview of Market Rule revisions.
Allowing Events To Be Used As Audits When RTEG Is Not Activated Robert B. BurkeNew Asset Auditing Discussions Principal AnalystSeptember 27, 2012 Market.
Ramping and CMSC (Congestion Management Settlement Credit) payments.
Ancillary Services Update NEPOOL Markets Committee October 14, 2003 Jim Milligan ISO-NE Markets Development.
T&D Losses Reflecting Losses in DR within ERCOT August 22, 2012.
1 New England Demand Response Resources: Present Observations and Future Challenges Henry Yoshimura Demand Resources Department ISO New England, Inc. Holyoke,
Energy Storage Definitions/Definitions ETWG 18 Feb 2013.
Demand Response: What It Is and Why It’s Important 2007 APPA National Conference San Antonio, Texas June 26, :00 a.m. to Noon Glenn M. Wilson Director.
© 2013 McNees Wallace & Nurick LLC October 17, 2013 Robert A. Weishaar, Jr. ON SITE ENERGY – INTERPLAY WITH PJM DEMAND RESPONSE PROGRAMS Harrisburg, PA.
Demand Response in MISO Markets NASUCA Panel on DR November 12, 2012.
1 Calculation of BGS-CIEP Hourly Energy Price Component Using PJM Hourly Data for the PSE&G Transmission Zone.
Overview of Governing Document for Weather-Sensitive ERS Pilot Project Stakeholder Workshop Mark Patterson, ERCOT Staff March 1, 2013.
Grabbing Balancing Up Load (BUL) by the Horns December 2006.
Enhancing Interruptible Rates Through MISO Demand Response: WIEG Annual Meeting June 19, 2008 Presented by: Kavita Maini, Principal KM Energy Consulting,
Congestion Management Settlement Credits December, 2002.
MARCH 13, 2014 | NEPOOL MARKETS COMMITTEE Jonathan Lowell PRINCIPAL ANALYST | MARKET DEVELOPMENT Updates to Market Rule 1 and Appendix F.3 to Address the.
Overview of CAISO Stakeholder Process for FERC Order 764 Compliance Implementation of 15 minute scheduling and settlement Jim Price, CAISO Presentation.
National Grids Involvement in New Englands Forward Capacity Market Helping to Bring Demand Resources into the Supply Mix Tim Roughan Director, Distributed.
Welcome New York Independent System Operator. (Pre-NYISO) Regulated Market Physical contracts Regulated industry Cost Based System Two Party Deals Bundled.
Overview of the North American and Canadian Markets 2008 APEX Conference in Sydney, Australia October 13, 2008 Hung-po Chao Director, Market Strategy and.
Demand Response: Keeping the Power Flowing in Southwest Connecticut Presented by: Henry Yoshimura Manager, Demand Response ISO New England September 30,
G 200 L 200 ISO NEW ENGLAND T H E P E O P L E B E H I N D N E W E N G L A N D ’ S P O W E R. Southwest Connecticut RFP Markets Committee November 14, 2003.
Spring 2008, King Saud University Cash Flow Analysis Dr. Khalid Al-Gahtani 1 Payment schedule Materials Mobilization Monthly payments Final Payment Contract.
California’s Proposed DR Cost-Effectiveness Framework January 30, 2008.
ERCOT Public 1 AS Demand Curves for Real-Time Co-optimization of Energy & Ancillary Services.
In the Post 06 Environment November 9, 2006 Jim Eber Demand Response.
Business Case NPRR 351 Floyd Trefny Amtec Consulting Brenda Crockett Champion Energy Services.
Legal Framework, Investment Opportunities and Technical Innovation in the Electricity Sector Security of Supply through competitive markets: Design of.
Highlights of AESC 2011 Report Vermont Presentation August 22, | ©2011 Synapse Energy Economics Inc. All rights reserved.
“Demand Response: Completing the Link Between Wholesale and Retail Pricing” Paul Crumrine Director, Regulatory Strategies & Services Institute for Regulatory.
Demand Response in Midwest ISO Markets February 17, 2008.
Utah Schedule 37 Update June 25, Schedule 37 Background Schedule 37 – Published rates for standard power purchase agreements with qualifying facilities.
Standard Market Design (SMD) in New England Federal Energy Regulation Commission Conference on Standard Market Design January 22, 2002 David LaPlante Vice.
Al McBride MANAGER, AREA TRANSMISSION PLANNING Existing Import Interfaces: Transmission Transfer Capabilities and The Calculation of Tie Benefits DECEMBER.
MEPCO Update (11/15/07 revision) TC Meeting - November 16, 2007.
© 2017 SlidePlayer.com Inc. All rights reserved.