The IESO has invited the public and stakeholders to comment on three new documents focused on how to enhance the participation of DERs (Distributed Energy Resources) in the IESO Administered Markets. The results will be integrated into a fourth document that will set the stage for the next phase of work including a demonstration project later this year.
“The IESO’s current discussion papers on integrating DERs are an important part of the process for determining how DERs will be treated in the future,” said Lou Colangelo of Toromont Energy Ltd., who Co-chairs APPrO’s Working Group on Distributed Energy Resources. “They are asking necessary questions about how to ensure DERs deliver the most value to the system, and on what tools and responsibilities the various agencies should have in terms of interacting with DERs.”
The initial white paper, “Exploring Expanded DER Participation in the IESO-Administered Markets,” sets out proposed baselines and common terms for the coming discussion. It is the first in a two-part series intended to identify high-level options for integrating DERs into the IESO-administered markets (IAMs). Released in draft form in October 2019, the paper begins with an acknowledgement that DERs already represent more than 10% of installed capacity in Ontario. Its focus is twofold: to set out the participation models that exist for DERs in wholesale markets in general and in the IAMs today, and to identify the range of options that exist for expanded participation in the future.
At its core, the paper outlines the major forms of market participation that are under consideration. It notes that “[g]enerally speaking, only directly participating generators, directly participating demand response (DR) and aggregated non-dispatchable DR resources currently have fully enabled participation models.” It also provides a working definition of DERs and overviews of how other jurisdictions are working to integrate DERs. It notes for example, that “Generally speaking, FERC’s regulatory goal is to ensure that ISO/RTO markets treat DERs equitably by enabling fair market participation and compensation for services they are technically capable of and willing to provide.”
The IESO explains that as a foundational principle, it is “committed to enhancing competition within the IAMs.” It explains, “[e]nhancing participation models would enable (DERs) to compete against traditional resources in offering cost-effective and reliable energy solutions within the IAMs. Eligibility to compete in the IAMs would also influence owners’ decisions to invest in new DERs, by enabling them to take advantage of revenue opportunities that were not previously available. DER integration can also allow existing contracted DERs, such as FIT and microFIT projects, to compete to deliver value to the electricity grid when their contracts expire.”
The paper acknowledges that DERs “have the potential to provide value across the entire electricity system, including at the Customer level, ... Distribution level (and) Transmission level.”
The IESO proposes a set of “Principles for integrating DERs into IAMs.” They fall into 7 categories as follows:
DER integration should seek to:
1. Provide an appropriate level of visibility into the resources operating within the distribution system
2. Enable increased competition by removing unnecessary barriers that limit the ability of DERs to compete in wholesale markets
3. Expose resources operating within the distribution system to economic signals reflecting the conditions and needs of the bulk system
4. Maintain an appropriate level of system reliability
5. Consider and respect the potential impacts on the distribution system
6. Prioritize initiatives with the greatest benefits
7. Support sector evolution that enables transparency and competition at all levels of the system.
The IESO notes that throughout these engagement processes the discussion papers are intended to stimulate discussion. They do not take positions on recommended solutions or commit the IESO to any particular course of action.
In addition to the two papers on integration models, the IESO has also released draft versions of two other papers that are expected to be used in the same engagement process: one on Non-Wires Alternatives and one on Transmission-Distribution Interoperability.
The IESO’s white paper on Non Wires Alternatives (NWA) addresses a range of issues facing planners and market participants working out systems through which DERs can effectively substitute for other types of grid infrastructure. It examines Market Design Considerations and how NWAs might operate in both Capacity Markets and Energy Markets. A range of implementation issues are explored including real time energy markets, market power, contracts and cost allocation. The paper assesses the implications of three hypothetical structures for allocating responsibility between the transmission and distribution system operators: The Total TSO model, the Total DSO model, and the “Explored Hybrid DSO model.”
The IESO’s white paper on “Transmission distribution interoperability” is ambitious. It sets out a series of milestones that illustrate how the province could analyze potential system architectures and assess the relative merits of each. In the process it begins to characterize some of the key features of high value DERs. For example, it says, “DERs used as NWAs need to operate when local demand is high and limits of the upstream network infrastructure is expected to be exceeded. The output of passive/non-dispatchable DERs used as NWAs must align with need. Active management of active/dispatchable DERs used as NWAs is needed.” This may be taken as a signal to developers and hosts of DERs that they should organize their systems to be actively managed to meet upstream needs, or if they are passive assets, to be fully assured of continuous operation during those same times of need.
The interoperability paper explains some of the challenges: Some types of DER integration, “will require greater levels of LDC operational control over the dispatchable DER, an expanded LDC role in specifying the desired parameters of the non-dispatchable resources (e.g., load shape impacts of energy efficiency) and greater information/data sharing (e.g., provision of telemetry) between these entities to ensure optimal asset performance.”
In addition, “Market transactions between the IESO (i.e., wholesale market operator) and DERs (both distribution-connected and customer DER) do not yet consider distribution system conditions, given the IESO’s limited visibility into the distribution system. As such, there must be mechanisms through the information/data exchange layer to coordinate distribution operations with the IESO, individual DERs and DER aggregators to ensure wholesale market participation does not compromise distribution system safety and reliability. For example, if LDC operations determine that a wholesale-participating DER must be taken offline due to distribution system conditions, it requires an established mechanism to communicate that information to ensure the IESO’s final dispatch does not include that DER. This form of active coordination does not exist today in Ontario. The LDC could serve this function, or there may be a desire to establish a new DSO entity to assume this and other roles and responsibilities that emerge as DER penetration increases to higher levels.”
It summarizes developmental concerns by saying, “The distribution system will need to become more dynamic, flexible and resilient to effectively integrate new DER technologies and manage a system increasingly characterized by two-way power flows. Importantly, since these drivers of distribution system change are location-specific, the pace and scope of change will vary geographically across Ontario. Figure 6 illustrates a three-stage evolutionary framework for the distribution system assuming a combination of top-down drivers like public policy and bottom-up drivers such as customer preference.”
The paper makes detailed comparisons between some of the models for allocating responsibilities between the TSO and the DSO, each of which has its own advantages and disadvantages. Further variations are possible, as the paper notes: “Even in a system structure where the IESO is not responsible for distribution system planning and operations, it could assume this responsibility on a selective basis for smaller or less capable LDCs managing T-D interfaces characterized by high DER penetration.”
The authors observe at one point that “a single T-D interoperability approach may not be appropriate for the entirety of Ontario. Since each T-D interface serves as a separate unit of analysis when considering T-D interoperability, Ontario may instead allow for a future industry structure characterized by a set of alternative approaches both across and within LDCs. This setup would require active coordination between the IESO, LDCs and other parties to determine where alternative approaches are appropriate.”
The authors continue, saying that “many of the largest LDCs in Ontario – including Hydro One, Alectra, Toronto Hydro, Ottawa Hydro, London Hydro and Oakville Hydro – have or are in the process of implementing distribution operational systems, including SCADA, GIS, DMS, OMS and network model as part of an advanced distribution management system (ADMS) deployment. Additionally, some of the smaller LDCs may also be investing in some of these capabilities, tending towards a software-as-a-service (SaaS) subscription basis rather than full ownership of the systems, given their resources are likely more limited. These SCADA and ADMS systems … are primarily implemented to address reliability, resilience and operational efficiency. ... However, these systems also provide crucial information, analytics and automation to more broadly support DER integration, the use of DERs to provide distribution services and T-D interoperability.”
The authors go further, exploring models for upgrading the suite of communication and management systems used by the IESO and LDCs for management of grid resources. “One conceptual approach, which largely builds upon the status quo, involves each LDC and the IESO individually identifying and implementing the technologies they require to support high volumes of DERs (i.e., both distribution-connected and behind the customer’s meter), and interconnection and utilization for bulk power and distribution services (i.e., both deferral and operations services). A second conceptual approach is based on leveraging a common platform for Ontario to unify market and operational coordination to support a variety of T-D interoperability structures as well as vastly simplify the protocols for establishing various interfaces.”
With respect to the common platform, the paper notes that “[s]hared DER lifecycle management platforms like the one being analyzed in Australia could provide flexibility to Ontario in a few critical ways, starting with flexibility in how the IESO and LDCs obtain the functionalities they need to support T-D interoperability in a high-DER environment. Ontario could extend this type of platform as needed to include SaaS-based operational systems functionality to augment the IESO’s or an LDC’s existing systems.”
The authors explain how the shared platform would be well suited to Ontario with its diversity of LDCs. “Leveraging this type of platform would drastically reduce the scale of interface points that exist. Rather than having to maintain separate coordination links with each other (e.g., a DER aggregator having to communicate separately to the IESO and LDC to facilitate wholesale market participation), each entity would be able to have one direct link to the shared platform where all parties could input and extract all required information. This benefit grows significantly as the numbers of DER grow.”
The paper identifies “Key takeaways” and makes a number of observations including the following:
• “The fundamental decision Ontario faces is whether to pursue a more centralized or layered T-D interoperability architecture. Setting objectives for electricity grid evolution can help guide this decision by identifying and designing the most suitable T-D interoperability models to further those goals.”
• One of the most critical initial steps to further the evolution of the electricity system will be “identifying, designing and selecting a primary T-D interoperability model.”
Key steps are identified as follows:
1. Define Ontario’s system objectives and enable regulatory changes
2. Identify and describe T-D interoperability models of interest to Ontario and apply the Ontario-specific decision framework to choose the interoperability architecture
3. Conduct a detailed grid architecture assessment of the selected model
4. Continue efforts to integrate DER and reflect their value in market opportunities
5. Facilitate collaboration between the IESO, LDCs and DER providers on operational coordination requirements and systems
6. Design and implement pilots and demonstration projects to test key aspects of T-D interoperability.
At an informational webinar hosted by the IESO on January 30, an update was provided on the engagement process. The second paper on DER integration is currently being prepared based on input from stakeholders. It will address areas not covered by the first paper including minimum size thresholds for market participation, and rules governing the participation of aggregated DERs. Some of the challenges include regularly identifying hosting capacity and opportunities for aggregation points and coordination with regional plans and the Annual Planning Outlook. The second paper on expanded models for DER participation is expected to be released shortly.
IESO staff noted that several IESO engagements proceeding in parallel will be relevant to the integration of DERs. The IESO will be careful to ensure that there is no duplication of work between the parallel processes. Participants should be aware of the following initiatives also underway that may impact DER participation in IAMs:
• Energy Efficiency auction pilot
• Storage design project (SDP)
• Demand Response Working Group
• EPOR-E (Expanding participation in operating reserve – Energy) being carried out by the Market Development Advisory Group.
All three white papers are available on the IESO website in a section dedicated to its engagement process on “Innovation and Sector Evolution,” at this location.
For further information, see also the following articles published by APPrO:
“New business opportunities in the York Region Local Electricity Market,” published in APPrO magazine and on LinkedIn, October 2019.
“IESO releases conceptual design and timeline for Local Energy Market demo,” from IPPSO FACTO, January 2020
“It’s time to resolve the ownership options for DERs,” on LinkedIn, September 2019.