Demand Response Issues Facing ISO New England. August 2016

Transcription

1 Demand Response Issues Facing ISO New England August

2 Demand Response Issues Facing ISO New England Key Facts and Concerns about the New Market Full implementation of FERC Order 745, with the start of the new market on June 1, 2018, will affect three markets: capacity, energy and ancillary services (specifically operating reserves). Participants will continue to make forward commitments to provide demand response in the forward capacity market. In the new market, such capacity will be used to dispatch energy (like today) and provide reserves (new) 1. A common dispatch model will be used to co-optimize resources and designate them as energy or reserves depending on market needs at the moment. Under this approach, separate assets at a facility are modeled and dispatched together, with ramp rates and other operating characteristics applicable to the collective asset 2. New Market Opens June 1, 2018 Measurement of performance in the new market will depend on the amount of energy or reserves provided during scarcity conditions. Penalties for under-performance will more severe than today, which is a source of concern for participants with unreliable assets in their portfolio. Demand response in the current market requires 5-minute telemetry data. Although this is sufficiently granular for a 30-minute reserve product, in the new market it will not suffice for 10-minute reserves. More frequent data readings will be needed to assess resource ability to dispatch energy within the 1 2 To properly designate resources as energy or reserves, market offers must include not only price and quantity (like today), but also operational characteristics. These include the dispatch range (minimum and maximum kw) and fast start capabilities so the system operator can assess the potential of the resource to provide 10-minute or 30-minute reserves. The collective asset at a location is appropriate because co-optimization algorithms assume that resources act independently. Otherwise, situations could arise in which facility load is reduced as a result of ISO dispatch instruction, but on-site generation is not immediately available (they cannot both ramp quickly). 2

3 designated time frame, and to monitor performance after dispatch. Consequently, 1-minute telemetry data will be required for resources that provide 10-minute reserves. ISO-NE Tasks Remaining FERC approved a high level framework for ISO-NE s new market design back in January 2015, and another set of proposed rules will be submitted in June The ISO still needs to develop business practices, software and hardware to complete the integration of demand response. These include modifying Pay-for-Performance to fully capture avoided losses, developing rules surrounding subhourly settlements, developing new processes for registering assets and qualifying resources, implementing baseline measurement changes and finalizing auditing procedures. Development of the hardware and software necessary to implement the new market will commence in early 2017, with testing to begin in early Duality Demand response has a perplexing attribute that of duality. Demand response can modify (reduce) demand for electricity and also be used as a source of supply. On the grid, electric supply and demand must remain in perpetual balance. Demand response can provide both. The same resource that serves as supply can also provide compensation to a customer through a reduced electric bill. The dilemma is that a customer can offer demand into the wholesale market at a price lower than the cost of supplying it, potentially displacing a different lower cost resource (generation). Dispatchable Demand Response in Decline The forward capacity market could use an infusion of dispatchable demand response. A total of 371 MW of new demand resources cleared the ten annual FCM (February 2016), and 2,746 MW of combined new and existing resources cleared. This is a continuation in the decline since FCA #6 in which 3,645 MW cleared. No new Price Responsive Demand cleared. Fully 90% of new demand resources (330 MW) are non-dispatchable (passive) assets from state sponsored energy efficiency programs. The market clearing price was $7.03/kW-month, down from $9.55/kW-month in Residential Demand Response in the FCM Residential demand response may have difficulty participating in the new market unless certain rules are changed. Demand response providers have been making progress with new technologies that improve response time and reliability. However, many will be unable to meet the 5-minute telemetry requirements to participate in the new market because the cost of metering equipment is prohibitive due to low savings per home. These programs can have significant savings in aggregate and offer a potentially valuable resource in the wholesale market. The current approach to estimating performance is based on run time data and equipment nameplate capacity. A transition to interval metering is going to need to allow some form of statistical sampling. 3

4 Opportunity Cost of Demand Response Under new market rules, resources that clear the forward capacity market must be bid into the dayahead energy market. The bid price reflects the opportunity cost of demand response. This amount can be very high and can potentially trigger an action by the Independent Market Monitor. Real Time Emergency Generators in the FCM A change has taken place in how Real Time Emergency Generation may participate in the ISO-NE Forward Capacity Market. A ruling by the D.C. Circuit Court went into effect on May 4, 2016 that reversed certain EPA rules. Of specific interest are rules that pertained to the 100-hour EPA exemption for operation of emergency engines for purposes of emergency demand response. The only way that existing RTEG assets in the FCM may participate in the next auction (FCA #11) is if they are they are retrofitted (if necessary) to comply with EPA standards, and are also converted to into Real Time Demand Response (RTDR) assets. The only other option is to de-list these RTEG assets. Improved baselines More frequent baseline adjustments. FERC has approved an ISO-NE proposal for improved forecasting of demand response baseline energy consumption. The existing method adjusts baselines once per day after the operating day is over. This approach will not suffice for designating cleared resources as reserves. The new rules require that baselines be adjusted every ten minutes. This should provide an accurate account of what can be counted on to meet system reserve needs by location. When an energy dispatch occurs the adjusted baseline is used to determine resource performance. Afterwards, the adjusted baseline is restored and continues to be used by ISO software to monitor options. Adjustments for assets that provide net supply to the grid. The majority of assets in the market still cannot inject energy onto the grid. However, distributed resources are becoming more commonplace and a critical mass of facilities could become nets supplier of power. ISO rules currently specify that demand response baselines be adjusted on the day of an event based on usage in the hours preceding a dispatch. For demand response assets that cannot inject energy, these adjustments will never result in a negative baseline because rules specify a floor of zero. This is a problem if a facility becomes a net supplier. The proposed solution is to set the baseline floor equivalent to the MWs indicated on the customer s utility interconnection agreement. Rolling average baseline. ISO-NE rules historically specified a baseline methodology that created infinite tail in which old and erroneous telemetry data never disappears. The ISO-NE system was being taxed by the requirement that the entire baseline be recalculated and stored as a unique version every five minutes. ISO-NE is proposing to FERC a method that is based on a 10-day rolling average of historic usage, which was determined to be just as accurate. A variation of this approach 4

5 will be used for two new day types under full integration (Saturday and Sunday/holiday) starting in June Highly Variable Loads. ISO-NE has been pursuing ideas to better manage demand response resources characterized by highly variable load patterns. Baselines are a poor predictor of usage for HVL assets; estimates of performance can be off by an order of magnitude. DNV GL performed an analysis of HVLs and made some recommendations, but there is not yet a decision on how ISO-NE will proceed. Simultaneous Auditing of Real Time Demand Response and Real Time Emergency Generation ISO-NE has developed a proposed that would permit the first hour of an ISO dispatch to serve as a Real Time Demand Response seasonal audit. The seasonal audit for emergency generators would be performed at a later date. Performance data for RTEG would be capped to minimize any potential for market manipulation. Specifically, RTEG performance from the audit plus RTDR performance from ISO-NE cannot exceed total facility load. Simultaneous audits will still be necessary for specific RTDR and RTEG assets that are co-located, but the entire RTDR resource would not need to be audited. In the event that no demand response events are called the existing rules requiring combined audits will still apply. Limited Visibility of Distributed Energy Resources Demand response is a type of distributed energy resources. DERs are being deployed at an increasing pace. Much of this will be from on the customer side, and distribution systems will take on a greater role in control and dispatch of these resources. An important problem is the lack of real-time visibility and dispatch control over these resources. Uncoordinated changes may make the system less reliable, particularly in constrained areas. Additionally, DER located in an export-constrained area may not match the transfer capability of the T&D system, which can lead to potential overload. Scheduled and Unscheduled Outages Rules went into effect in 2014 to handle scheduled and unscheduled facility curtailments. These rules will carry over into the new market under full integration. Participants with such curtailments not make any offers into the day-ahead energy market and must submit adjustments to their resource availability data. Participants are required to submit unadjusted baseline data for any intervals that occur during such an outage unless it coincides with an ISO dispatch, in which case actual meter data should be provided. Net Commitment Period Compensation Net Commitment Period Compensation rules provide a mechanism to make generators whole when certain resources were dispatched out of economic-merit order for reliability purposes. ISO 5

6 payments ensure that generators do not experience losses when an ISO dispatch instruction is cancelled. In the new market, demand response will be treated comparably. Inadvertent Energy Real time demand response obligations need to be included in the allocation of inadvertent energy. This occurs as a byproduct of ISO transactions scheduled with neighboring systems to correct minor imbalances between supply and demand. The total amount of such energy last year was only $1.7 million in the $6 billion energy market Marginal Loss Revenue Fund Settlement imbalances are defined as the differences between what the ISO pays resources in the day-ahead energy market and what is collected from load. Settlement amounts are calculated based in part on the quantity of energy that clears the market times the applicable locational marginal price. The ISO charges load for such differences, and puts these collections into a into a marginal loss fund. In 2014, the fund averaged $6 million per month, which is only 1% of the total energy market. In the new market, demand response resources will be treated comparably. Self-funding Tariff This tariff provision involves payment of the costs associated with the ISO administration of the energy and reserves market. Demand response resources will be handled the like generators, with charges based on resource offer price and hours. Voluntary Load Reductions There are two problems with the way ISO-NE currently handles voluntary load reductions. First, ISO- NE does not have a satisfactory system in place for making decisions about when to call for such reductions or communicate this information. Second, voluntary demand response can be harmful for market participants with dispatchable assets that reduce load ahead of the curtailment period. This is because metered data in these pre-event hours is used to adjust customer baselines. A downward adjustment reduces measured performance and penalizes these resources. 6