Opportunities for Demand in Ancillary Service Market

Transcription

1 Opportunities for Demand in Ancillary Service Market November 5, 2014 Philadelphia, Pennsylvania Christopher Parent Manager, Market Development, ISO New England or

2 New England s Regional Wholesale Markets

3 Annual Value of Wholesale Electricity Markets $16 New England s Wholesale Markets Annual Value ($ billions) $14 $ $10 $8 $6 $ $2 $ Energy Market Ancillary Markets Capacity Market Source: 2013 Report of the Consumer Liaison Group, Appendix C

4 Regulation Purpose: Maintain steady-state frequency within defined limits by balancing demand and supply Accomplished by maintaining adequate regulation and continuously dispatching (4 to 10 seconds) demand and supply to ensure the Area Control Error (ACE) complies with NERC Control Performance Standards (CPS): Area Control Error reflects the system s actual frequency relative to the scheduled frequency (normally 60 Hz) NERC Standards (BAL-001) CPS1 Measures a Balancing Area s 1- minute average ACE variability in combination with frequency error. 12 month rolling average CPS1 score must be >= 100% CPS2 90% of ten-minute averaged ACE values in a month are within a specific limit Proposed new Balancing Area ACE Limit 1-minute average ACE must not exceed a specified limit for more than 30 consecutive minutes

5 Contingency Reserves Purpose: Balance supply and demand and return interconnection frequency within defined limits following a system disturbance Reportable Disturbances are contingencies that are > 80% of the most severe single contingency Accomplished by maintaining sufficient contingency reserves to respond to the largest single source loss on the system within 15 minutes of the event occurring and being able to restore contingency reserves within 90 minutes NERC Standards (BAL-002) Within 15-minutes a Balancing Authority shall return its ACE to zero if its ACE just prior to the Reportable Disturbance was positive or equal to zero. For negative initial ACE values just prior to the Disturbance, the Balancing Authority shall return ACE to its pre- Disturbance value A Balancing Authority in the Eastern Interconnection shall fully restore its Contingency Reserves within 90 minutes.

6 NERC, NPCC and Regional Reliability Standards Apply to ISO New England NPCC Northeast Power Coordinating Council Basic criteria for the design and operation of interconnected power systems Western Interconnection NERC North American Electric Reliability Corporation (includes all 3 interconnections) Reliability standards for the bulk power system in North America ERCOT Interconnection Eastern Interconnection Reliability standards for the New England bulk power system

7 Region s Regulation Market Designed to Meet NERC Standards Regulation resources are cleared to ensure sufficient capacity to meet the regulation requirement Hourly requirements are set based upon historical analysis of performance against CPS, and range from MW The ISO dispatches regulation resources within the hour based upon their physical characteristics to meet the Control Performance Standards (CPS) Resources are compensated based on uniform clearing prices for capacity which include opportunity costs and movement (i.e., mileage ) in each hour

8 Reserve Requirements are Developed to Meet NERC and NPCC standards System ten-minute reserve (TMR) is used in response to a contingency and can be met by spinning (TMSR) or non-spinning (TMNSR) Requirement is set at the size of the largest contingency adjusted for historical non-performance (~2,200MW) A minimum level of TMSR is specified between 25%-50% System thirty-minute operating reserve (TMOR) is used to recover TMR within 90-minute requirement Requirement is set at half of the size of the second largest contingency May be increased for replacement reserve (total requirement: ~950MW) Local thirty-minute operating reserve requirement is used in response to a localized contingency Requirement is set based upon second contingency requirements and available interface support within a reserve zone

9 Demand Technologies Can Provide Regulation Controllable loads (treated on the demand-side) are able to provide regulation by managing consumption in response to 4- second AGC dispatch instructions Individual small loads may be aggregated into a single regulation resource across the system The ISO dispatches the aggregated resource The aggregator then dispatches the individual loads to produce the required aggregate response Participants can modify their regulation capacity, performance characteristics, and offer prices of regulation resources hourly to reflect consumption patterns that change throughout the day

10 Reserves are Procured Through Forward Market and Subject to Co-Optimized Dispatch ISO procures a portion of the TMR and all the TMOR expected requirements through the forward reserve market Summer (June-September) and winter (October-May) seasons for on-peak weekday hours ( ) Participants that take-on a forward obligation are compensated at the forward price and are expected to be available and deliver in real-time (forgoing the real-time reserve price) Subject to penalties for non-performance ISO commits resources prior to operating day to ensure adequate reserve capability to meet requirements, and designates in realtime resources to meet reserve through co-optimized energy and reserve dispatch Resources that are designated to provide reserves in real-time are compensated at the real-time reserve price (positive prices occur about 5%-15% of the hours in a year)

11 Demand Can Participate in Energy and Reserve Markets To provide reserves whether the demand is on the demandor supply-side of the market it must be capable of being dispatched in real-time based upon its economic offers Offers can be modified throughout the day to reflect changes in resource capability, performance characteristics and some offer prices Demand-Side Load Able to provide reserves by participating in the markets as a dispatchable asset related demand Individual small loads within an electrical location can aggregate to achieve the 1MW consumption threshold Supply-Side Demand Response Starting in 2017, are able to provide reserves by participating in the markets as a demand response resource Individual small loads within a single dispatch/reserve zone can aggregate to achieve the 100kW demand reduction threshold 11

12 Ancillary Services Market Opportunities for Demand Response PJM Perspective Michael Olaleye Senior Engineer, Real-Time Market Operations PJM Interconnection November 5, 2014 Philadelphia, Pennsylvania

13 PJM as Part of the Eastern Interconnection 27% of generation in Eastern Interconnection 28% of load in Eastern Interconnection 20% of transmission assets in Eastern Interconnection KEY STATISTICS PJM member companies 900+ millions of people served 61 peak load in megawatts 165,492 MWs of generating capacity 183,604 miles of transmission lines 62, GWh of annual energy 791,089 generation sources 1,376 square miles of territory 243,417 area served 13 states + DC externally facing tie lines % of U.S. GDP produced in PJM 11/5/ As of 4/1/

14 Demand Response in PJM Markets Demand Response can participate within the various PJM markets: Dispatch Capacity Settlements Offer into auction up to 3 years in advance Energy Day Ahead Real Time Dispatched RPM Ancillary Services Day Ahead Scheduling Reserve Regulation Synchronized Reserve 11/5/

15 Demand Response Market Participants 11/5/

16 Demand Response Synchronized Reserve Market In 2006, PJM qualified its first DSR to provide synchronized reserve Current reliability council rules limit demand resources to 33% (raised from 25%) of the synchronized reserve requirement in the ReliabilityFirst Corporation region The floor offer MW is set at 100 kw (0.1 MW) The 0.1 MW is achievable by aggregating multiple end-use sites Option for hourly (inflexible) and intra-hour (flexible) clearing Request to curtail only when system condition requires 10-minutes response All synchronized reserve service requirement must be met which include the metering information at no less than a one-minute scan rate and must be uploaded to PJM within 2 business days of the event to ensure compliance Synch Reserve Electronic Notification to CSP (elrs Web Services), All Call, Director and elrs 11/5/

17 Demand Response Regulation Market PJM added capability for Demand Response participation in the Regulation Market in 2011 Current reliability council rules limit demand resources to 25% of the regulation requirement in the ReliabilityFirst Corporation region All regulation service requirement must be met which include the real-time telemetry The floor offer MW is set at 100 kw (0.1 MW) bi-directional relative to a base point The 0.1 MW is achievable by aggregating multiple end-use sites Regulation telemetry signal, only registration is in elrs 11/5/

18 Regulation and Synchronized Reserve Participation Manufacturing 6% Regulation Offer MW Participation By Reduction Method HVAC 11% Water Heaters 3% Refrigeration 2% Batteries 42% Synchronized Reserve Offer MW HVAC 2% Lighting 1% By Reduction Method Generator 12% Water Heaters 0% Refrigeration 0% Plug-In Load 0% Generators 36% Manufacturing 85% Max Actual Reg Offer MW in 2014 = 8.3 MW Max Actual Tier2 Offer MW in 2014 = 232 MW Retail Service Hospitals Residential Others MW Office Building Services Office Building MW Transportation Schools Schools Agric/Forestry/Fishery Industrial/Manufacturing Industrial/Manufacturing /5/

19 Regulation Market Participation in /5/

20 Synchronized Reserve Participation in /5/

21 Using Transactive Load for Ancillary Services VCHARGE Turn It On PLMA Nov 5, 2014

22 Can You Find The 15MWh Battery? 22

23 Grid Balancing: On Many Time Scales Load can play a role at all time scales. 23

24 High-Quality Fast Frequency Regulation 800kW Reg Up Baseline in Hour 1: 800kW 800kW Reg Down 24

25 The Power of Aggregation Individually controlled assets

26 Future Distributed Energy Services Indicates Demand-Side Capability Grid Location Minimum Continuous Service Duration Short (< 2 min) Medium (2 min 1 hour) Long (1 hour+) Generation Transmission Spin/Non-Spin Res. Ramping Frequency Regulation Smooth intermittent resource output Provide system inertia Capacity Firm renewables Shift energy Avoid dump energy Avoid minimum load Black start In-basin generation Avoid congestion fees Defer system upgrades Improve system reliability Distribution End User Improve power quality Maintain power quality Defer system upgrades Mitigate outages Integrate distributed generation Optimize energy/carbon costs Source: Jesse Berst, SmartGrid News, Southern California Edison Provide uninterruptible power supply 26

27 MW of Wind New Service Example: Optimize Carbon 900 Carbon Intensity of ISO-NE Generation Mix Feb 15 - Feb 19,

28 Lbs per MWH and MW of Wind New Service Example: Optimize Carbon 900 Carbon Intensity of ISO-NE Generation Mix Feb 15 - Feb 19, Carbon Intensity of Fuel Mix 500 MWH of of Wind on on the the System

29 Orkney, UK: Next-Generation Ancillary Services Testbed Frequency regulation using EVs, thermal storage Distributed generation integration Wind curtailment mitigation Distribution constraint modeling Simulated inertia 29

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31 Demand Response Opportunities for Electric Vehicle Charging Stations Moving the Demand Response Cheese: How DR's Value Proposition is Evolving Mahi Reddy, Founder & CEO, SemaConnect Ryn Hamilton, Ryn Hamilton Consulting Tom Ashley, PlugShare 31

32 Introduction The focus of this presentation is opportunities for commercial grade PEV charging stations to provide demand response and ancillary services. Concept Opportunity Frame The idea of PEV charging loads offering a resource that could be monetized has not been thoroughly tested although there have been some small studies. The demand response resource is created by modulating charging rates up and down in response to external control or price signals. This opportunity will expand as the penetration of PEVs increases, lessons from early studies are distilled and the regulatory environment evolves. This presentation frames a discussion around key opportunities and market drivers for commercial chargers to provide demand response and ancillary services. Challenges SemaConnect and PlugShare have achieved the proof of concept stage. Although much of the necessary hardware and software have been developed, real world utility and grid experience is still required. 32

33 Introduction Changes in electric usage by end-use customers from their normal consumption patterns in response to changes in the price of electricity over time, or to incentive payments designed to induce lower electricity use at times of high wholesale market prices or when system reliability is jeopardized. Federal Energy Regulatory Commission The definition of demand response has broadened to specifically include ancillary services which address grid contingencies and short term imbalances in energy markets.. Amount curtailed Source: ISO-New England 33

34 Introduction Scott Baker, PJM Willett Kempton U of Delaware (PJM) Mahi Reddy SemaConnect Tom Ashley PlugShare The grid operator sees electric vehicles as potential stabilizers for the system, helping to keep frequencies smooth, especially as intermittent alternative energy sources like solar are added to the grid. We re not earning enough money to get rich, but it earns more money than it costs to do it. Demand Response will emerge as a "killer app" as we see more electric vehicles on the road, and using charging infrastructure. This is a perfect example of a flexible load that can be controlled to optimize grid capacity, and will give utilities a whole new market and capability. Passenger vehicles are parked for 96% (on average) of their lives. Using electric vehicles for grid balancing and other energy services is a no brainer. 34

35 Introduction This discussion concerns the potential use of SemaConnect charging stations as a fast responding and calibrated form of demand response. While there has been some early stage research into the use of charging stations for this purpose, most pilots have focused on the use of PEV batteries. A key distinction is that PEV charging statins provide unidirectional control, whereas vehicle battery storage systems (onboard and added components) will eventually be commercially capable of also pushing power into the grid. Industry Studies SemaConnect / PlugShare Dept. of Defense Fort Carson Dept. of Defense LA Air Force Base PJM / University of Delaware CAISO / California utilities Grid to Charger PEV battery The focus of our research is SemaConnect Level II chargers. (Level I chargers are still standard in residential applications.) Level II chargers deliver 240 Volts and 30 Amps, and have become the industry standard for charging away from home. They offer superior charging speed, networking capability, signaling and communications. 35

36 Introduction Loads from individual charging sessions are quite small and must be aggregated to provide a viable grid resource. A curtailment service provider would be an essential link between the charging station and the utility or grid, sending and receiving signals. Load Aggregator Commercial PEV charging stations, source: SemaConnect Grid operator, source: PJM 36

37 Opportunity Opportunities are expanding for PEV charging loads to participate in utility programs and ISO/RTO markets. Utilities and Jurisdictions: Offering more demand response programs that could potentially permit PEV loads. Although 37 states have a program or commitment to increase the number of zero emission vehicles on the road, there has been huge progress. Demand Response Ancillary Services ISO/RTO ISO/RTO: Rule changes in organized markets are permitting demand-side resources to participate in capacity, energy, regulation and reserves markets. (This may change depending on the outcome of the legal challenge FERC Order 745.) Aggregators: The market for curtailment service providers has matured and new kinds of loads are being pursued as the C&I market becomes increasingly saturated. Smart Grid and Technology. PEV capabilities are enabled by advanced metering and communication technologies, as well as standards such as OpenADR protocols that are becoming the international standard for DR communications. States Renewable generation. Accelerated adoption of distributed energy resources (e.g., rooftop solar, PEV) are altering electric load profiles. Greater amounts of grid-scale renewable generation (e.g., solar, wind) with intermittent output are complicating grid operations. 37

38 Demand Response s 1990s Beyond Declining electric load factors due to rapid adoption of air conditioning. High peak demands relative to average demand is increasing electricity cost and reducing reliability. Utilities introduce first generation of demand response programs to provide electric load reductions during system emergencies. These situations include needle peaks and pockets of T&D congestion. Electric industry restructuring ends many vertical utility monopolies, and demand response programs are abandoned. The legal framework for demand response in wholesale power markets emerges. Utility demand response programs are resuscitated the advent of DR 1.0. Energy Policy Act requires changes to wholesale power markets that put DR on an equal footing with generation. Regulations establish specific rules and payment structures for DR. DR 2.0 brings enhanced communication automation making DR feasible for more kinds of resources. Legal challenge to FERC jurisdiction over demand response. As DR programs expand, the role of ancillary services expands in certain markets. DR 3.0 and smart grid introduce 2- way communicatio ns and intelligent load management to the distribution network. Depends on outcome of FERC Order 745, and alternative options for DR. Demand response provides a greater share of ancillary services. PEV charging loads will eventually provide demand response to utilities and grid operators. Regulations and standards are facilitating adoption of enabling technologies. 38

39 Demand Response Demand response has evolved into a more dynamic resource and ancillary services become part of the conversation. Demand response can be categorized as reliability products (capacity market), price responsive demand (energy) ancillary services which safeguard reliability. Our focus Reliability (Capacity) Commitments to deliver energy at some forward date, such as three years When this capacity becomes available it is dispatched to meet system reliability needs Load shedding is normally required within 1-3 hours of notification Dispatchable (Supply-side) Price Responsive Demand Price Responsive Demand is predictable change in electricity consumption in response to electricity prices in the energy market Demand Response Ancillary Services Grid balancing services have been historically provided by ancillary fossil fuel generators Response required within seconds to minutes of notification Demand response provides only a small percent of this resource now, but this will increase Non-Dispatchable Time Varying Rates Energy Efficiency Rate structures offered by utilities that reflect cost of service at different times Customers respond by reducing electric use based on time of use or critical peak pricing structures 39

40 Demand Response There is emerging interest in supporting PEVs through various mechanisms. The examples below show diverse areas of interest, but also the gap that SemaConnect intends to fill (charging station loads for demand response). Utility pilot programs Wholesale market ISO/RTO State and local EVSE initiatives Joint ventures, collaboratives Grants* Austin, Texas pilot with 10 charging stations Pilots at DTE Energy, PSEG, Dominion, National Grid, Florida P&L, Duke Energy PJM: with University of Delaware, Honda and NRG ISO-NE: with Vermont exploratory paper California ISO: State roadmap San Francisco $5M EV charging programs South Carolina subsidization of 80 charging stations Connecticut funding 56 charging stations Lawrence Berkeley Lab: SEEDZ pilot commercial scale EVSE Department of Defense Vehicle to Grid project ARRA funding Idaho National Laboratory 200 fast chargers in 21 cities ARRA $115M for public power company partnerships * Grants have typically been from state and local governments. With the exception of ARRA funding, the federal government s emphasis has been to make EVSEs more appealing to customers (branding rather than incentives). 40

41 Ancillary Services Regulation and reserves have historically been provided by generation resources, but are now being supplemented in some jurisdictions by demand resources. SemaConnect envisions a future in which PEV charging stations provide these services. PEV charging stations can provide ancillary services by modulating the rate of charging in response to external signals and control. Aggregation Required The ISO/RTO control room assess moment to moment options and dispatches resources. Generators have historically provided ancillary services. Power production is ramped up and down for grid balancing. 41

42 Ancillary Services Changes in the power industry are creating a greater need for demand-side resources to support moment-to-moment grid operational needs. The use of demand response for ancillary services is a refinement of an existing tactic. Ancillary service must respond as quickly as an ancillary power plant would, from seconds to 30 minutes. Controlled PEV charging loads that can be finely modulated can provide the same quality of operating reserves and regulation resource as a generating unit. Ancillary services are under the purview of FERC which has issued several orders intended to create a larger role for demand side resources to participate. Ancillary services support the reliable operation of the transmission system as it moves electricity. The kinds that could potentially be provided by PEV charging loads: Regulation Market. Corrects for short term changes in electricity use that could affect the stability of the power system. This is part of normal system operations. Spinning and Non-Spinning Reserves. Supplies electricity when the grid has an unexpected need for more power (reduced use) on short notice in contingency situations. 42

43 Ancillary Services Many ISOs/RTOs have demand response in their ancillary services markets, including PJM, NY- ISO, MISO, CAISO and ISO-NE. A handful of grid-tied electric vehicle projects are online or in process, including: Partners University of Delaware NRG Department of Defense Los Angeles Air Force Base Southern California Edison Southwest Research Institute Pilot Frequency Regulation Frequency Regulation Frequency Regulation Demand Response 43

44 Ancillary Services MW PEV loads not suitable Source: Regulatory Assistance Project, adapted from NERC, et al Required time between notification and demand response dispatch 44

45 Ancillary Services Regulation is the method by which the grid operator continuously maintains optimal balance on the system. Historically this has been provided by ramping generators (natural gas) up and down in response to a dispatch signal. Demand-side resources are now permitted to participate in certain frequency regulation and regulation reserve markets. Frequency regulation manages the quality of energy on the grid, balancing generation and load, to keep the system frequency reliably at 60 Hz. Resources are compensated for the ability to modulate demand up or down. To participate, PEV charging stations must possess fast response capabilities and perform for specified durations (15 minutes to 1 hour). 45

46 Ancillary Services Resources are bid into the market on a regular basis, whether hourly or every five minutes. Bids are organized by price and key operating characteristics. These include ramp rates, power factors, maximum and minimum limits, length of time the resource can be available. Better forecasting and dispatching of power (five or fifteen minutes instead of every hour) is reducing the need for regulation service. Better forecasting is also reducing the cost of integrating wind and solar into the grid. The size of the regulation market varies by region. ISO-NE, for example, dispatches every five minutes, which keeps the system fairly well balanced. As a result, the regulation market is comparably small and prices for regulation service low compared with regions that have hourly dispatch. 46

47 Ancillary Services Operating reserves consist of spinning (synchronized) reserves and non-spinning (supplemental) reserves. These terms are carried over from the generation side to indicate the state of readiness of units that are either in an online state (available now) or offline state (available soon). Resources participating in synchronized reserve programs are generally dispatched a few times a month. Spinning reserves are a first strategy for maintaining reliability following a contingency such as a loss of a generation or transmission. The typical required response time is 10 minutes to 30 minutes. Demand response participates by providing a predetermined amount of energy in order to meet a reliability standard. PJM has a synchronized reserve market and a day-ahead scheduling reserve. Most of the demand side ancillary services are bid into the market by aggregators. One estimate is that this represents about 18 percent of PJM s synchronized reserves. 47

48 Regulatory The markets and programs that PEV charging loads will one day participate in are regulated at the Federal and State level. This shapes rules for participation. FERC regulates independent system operators and regional transmission operators. These ISOs and RTOs file individual tariffs that must be approved by FERC. For example Market rules are based on CAISO s tariffs with FERC. Shapes CAISO markets, pilots and initiatives, some of which are in collaboration with other regulatory authorities State regulatory commissions govern utility operations. Utilities, including those with statewide programs, file individual program tariffs with their respective commissions. For example PG&E s program rules and timevarying rates are based on their tariffs with the California PUC. PG&E programs DR programs, pilots initiatives, collaborations 48

49 Regulatory FERC regulates the nation s Independent System Operators and Regional Transmission Operators. Together they serve two-thirds of all electric customers. [not under FERC jurisdiction] 49

50 Regulatory FERC has been a strong proponent of demand response, creating rules intended to provide a level playing field with generation. FERC Orders ISO/RTO Tariffs Capacity Markets ISO/RTO Differences Landmark Order 745 (compensation based on locational marginal price, 2011), Order 890 (regulation services market, 2007), Order 719 (comparable treatment of DR with generation, 2008), Order 755 (greater compensation for fast-acting resources, 2011), Order 1000 (transmission alternatives, 2012), Order 784 (pay-for-performance, 2013). ISOs/RTOs file individual program tariffs with FERC, which govern rules for demand response participation and compensation. Three ISOs/RTOs have capacity markets ISO New England, New York ISO and PJM). These pay incentives to attract investment in exchange for a commitment to stand ready to provide energy into the market. The remaining regions have energy-only markets that pay only for the actual energy provided. Differences exist between various ISOs/RTOs, as well as within individual states in a particular market. ISO New England includes the six northeast states that have a tradition of collaborative action on energy matters. The largest grid operator, PJM spans 13 states that are not closely affiliated. 50

51 Regulatory FERC s hallmark action on demand response was Order 745 (2011). This transformed energy markets by requiring that demand response be paid the locational marginal clearing price (same price as generation). The D.C. Circuit Court overturned Order 745 in May FERC and numerous other parties (state commissions, grid operators, demand response providers, industrial customers and consumer advocates) came together to request a rehearing by the entire eleven member court (the decision was based on the opinion of three justices). The court denied this request. FERC and the U.S. Solicitor General (Department of Justice) must decide by December 16, 2014 whether to appeal this ruling to the U.S. Supreme Court. This order was the result of a petition led by the Electric Power Supply Association based on objections to demand response compensation based on locational marginal cost. This court decision exceeded the scope of the plaintiff s case by ruling expansively on jurisdictional issues and the role of demand response in wholesale markets. There is no consensus about when this matter will be settled or what the outcome will be. ISOs/RTOs are responding differently to the possibility that Order 745 will not be reinstated. 51

52 Regulatory Federal Compliance Continued Investment Old Rules Expiring Rules in the New Market Initiating market design changes to comply with Order 745, as directed by FERC. These have been cascading into numerous resource-intensive ISO projects. Deciding in early 2015 whether to expend additional resources to meet the June 2017 date for full market integration given uncertainties. Current rules surrounding demand response will sunset on May 2017, the day before the new market begins. If Order 745 remains invalidated, demand response will have no role in the new energy (and reserves) market under construction. The crux of the problem is that under full integration the obligations that demand response resources take on can only be satisfied through performance in the energy market. Capacity resources must perform during scarcity events yet paradoxically will be unable to perform. This is because these demand response resources will not have access to the energy market if Order 745 is not restored. 52

53 Regulatory Federal PJM Position Current Situation Proposed Change Purpose Additional Challenge PJM released a white paper in October outlining a approach that would permit demand response to continue to participate in the market, but in a way that is compliant with the Circuit Court s ruling. Demand response is currently offered into PJM markets and paid as a supply-side resource alongside generation. The PJM markets would not separately compensate demand response. Under the new plan, it would be a demand-side load modifying resource with compensation that is detached from the market clearing locational marginal price that generation is paid. The market participants will be load serving entities and competitive suppliers. The PJM plan is intended to restore confidence, reduce litigation risk and avoid disrupting settled transactions from its capacity market. PJM has a workable plan for treatment of demand response that will be ready in time for the May 2015 RPM auction. ISO-NE has not proposed a plan or offered stakeholder guidance to prepare for the February FCM #9 auction. Further complicating matters, FirstEnergy has filed a legal challenge (which PJM responded to) to remove demand response from the capacity market as well. 53

54 Regulatory Federal Current PJM is the only ISO/RTO to have fully implemented Order 745. Demand response is offered into PJM markets and compensated the same as supply resources, as per Order 745. May 2014 The court invalidated Order 745 and ruled that FERC does not have jurisdiction over Demand response in energy markets. PJM proposes that demand response participate in the capacity market as a demand-side (not supply side) resource. Demand response providers will be load serving entities and competitive energy providers. Aggregators, which represent 70% of the demand response in the PJM market today, will still have a role but no longer be allowed to participate directly in the market. PJM will model demand-side bids as load modifiers. In time for May 2015 auction Compensation will be based on avoided energy cost to the load serving entity plus any state incentives (not locational market clearing price). 54

55 Regulatory Federal Capacity Market Energy Market Compensation Transition Mechanism Demand reductions are bid into the capacity auction at a price set by the load serving entity. Clear offers are treated as commitments to reduce load. PJM models this as a reduction in the capacity requirement (energy demand curve shifts to the left), which means that PJM procures less capacity for that load serving entity. If it performs when called upon there is no energy payment, only avoided payments by the load serving entity for energy it did not have to purchase. Demand reductions no longer get compensated in energy market. Instead, PJM will allow demand bids from load serving entities to specify a price at which they choose not to consume. For Price Responsive Demand, the load serving entity s forecast is modeled by PJM to calculate the amount of avoided generation dispatch. PJM created a method to handle existing capacity commitments that involves matching up demand offers with corresponding load serving entities. The obligation is then converted to a demand side curtailment commitment, with provisions for providers to be released from their obligations. 55

56 Regulatory Public utility commissions regulate utility demand response programs. PUC support for demand response and plug-in electric vehicles vary. Most states have load serving entities that are regulated by state commissions. Maine and Vermont have standalone state efficiency utilities that administer programs. Some states have transitioned previously separate utility programs into statewide programs. Utilities have historically developed and implemented programs to meet their own needs. The New England states have a somewhat different model insofar as they administer ISO-NE s demand response programs (fate is undetermined until FERC 745 resolved). Additional states, including California, are moving toward greater integration between retail and wholesale markets. 56

57 Control Capabilities M2M connectivity via cellular modem Central control from cloud-based network platform Up-to-date status and metering data Fast response to demand response dispatch instructions RFID Identification of PEV driver Account on network platform Messaging and Charging Preferences J1772-compliant charge connector Standardized dynamic load signaling to vehicle 57

58 Control Capabilities Power flow can be controlled for any designated charging station or grouping of stations selected for control 1.5 kw and 7.5 kw at a particular station. Power Levels Level I 120V, 12 Amps Level II 240V, 30Amps Fast Charging 480V, Greater than 100Amps Time to Charge (for 100 mile range battery) Level I 20 hours Level II 4 to 8 hours Fast Charging 20 minutes Standard Connector New connector called J1772, developed by Society of Automotive Engineers All major car companies have agreed to use Includes safety features to protect drivers and general public 58

59 Control Capabilities 59

60 0-1am 1-2am 2-3am 3-4am 4-5am 5-6am 6-7am 7-8am 8-9am 9-10am 10-11am 11-12pm 12-1pm 1-2pm 2-3pm 3-4pm 4-5pm 5-6pm 6-7pm 7-8pm 8-9pm 9-10pm 10-11pm 11-12am Control Capabilities MW Aggregated Resource Sub-group Station (n=1) 60

61 Control Capabilities 61

62 Control Capabilities Communicate with drivers about demand response and other grid events and opportunities in their region. Provide real-time opportunities to opt in or out of events or have preferences pre-programmed. Determine participation based on driver range/battery charge level needs. Communicate station participation in AutoDR programs. Non-invasive vehicle hardware installation can facilitate timed charging, charge curtailment, modulated charging (load smoothing), and help integrate with charging station management systems and aggregator signals. Integrate vehicles and charging stations into designed charging programs. 62

63 Control Capabilities PlugShare is working with a West Coast municipal utility and a sample group of drivers with its app-based communications technology. This app notifies drivers of upcoming and current demand response events for voluntary reductions. Driver responsiveness was robust, resulting in a 30% reduction in charging load during the events. The next step is to include an installation of the PlugShare ChargeManager device in a sample group of PEVs. PlugShare will signal these vehicles to charge at certain times of the day and to suspend/resume charging. Additional dispatch signals and instructions are also being tested. 63

64 Control Capabilities (illustrative) Station continuously meters energy flow through the cable. Syncs the power level and cumulative energy with the server. The vehicle detects the change in control signal on the J1772 cable and reduces its power. The aggregator confirms that the signal has been received. The aggregator confirms that the power matches the configured level. Settlement quality meter data is submitted to the utility or ISO. Start Utility or ISO dispatches signal from its secure communications system to the scheduling coordinator. The aggregator transmits a signal for load control to selected charging stations. The signal is transmitted to individual stations via a web service over a cellular data connection. Station software manipulates the control signal on the J1772 cable connected to the vehicle to indicate curtailment. The station signals the server that the control is being executed. *The aggregator and scheduling coordinator may not be the same entity. 64

65 Next Steps SemaConnect and PlugShare are in discussions with utilities and ISOs/RTOs to shape the development of pilot studies. We expect to have a few commence next year. We are open to conversations with utilities and other industry partners about opportunities to develop and commercialize demand response and ancillary services capabilities. 65

66 Thank you! Mahi Reddy, Founder & CEO, Ryn Hamilton, Tom Ashley, Director, Utility & Regulatory Affairs, 66