Notice of Technical Conference, 7703-7707 [2018-03649]

Download as PDF Federal Register / Vol. 83, No. 36 / Thursday, February 22, 2018 / Notices Dated: February 16, 2018. Frank T. Brogan, Principal Deputy Assistant Secretary and delegated the duties of the Assistant Secretary, Office of Planning, Evaluation and Policy Development Delegated the duties of the Assistant Secretary, Office of Postsecondary Education. [FR Doc. 2018–03686 Filed 2–16–18; 4:15 pm] BILLING CODE 4000–01–P DEPARTMENT OF ENERGY Federal Energy Regulatory Commission Notice of Technical Conference Docket Nos. daltland on DSKBBV9HB2PROD with NOTICES Participation of Distributed RM18–9–000 Energy Resource Aggregations in Markets Operated by Regional Transmission Organizations and Independent System Operators. Distributed Energy ReAD18–10–000 sources—Technical Considerations for the Bulk Power System. Take notice that Federal Energy Regulatory Commission (Commission) staff will hold a technical conference to discuss the participation of distributed energy resource (DER) aggregations in Regional Transmission Organization (RTO) and Independent System Operator (ISO) markets, and to more broadly discuss the potential effects of distributed energy resources on the bulk power system. The technical conference will take place on April 10 and 11, 2018 at the Commission’s offices at 888 First Street NE, Washington DC beginning at 9:30 a.m. and ending at 4:30 p.m. (Eastern Time). Commissioners will lead the second panel of the technical conference. Commission staff will lead the other six panels, and Commissioners may attend. The technical conference will address two broad set of issues related to DERs. First, the technical conference will gather additional information to help the Commission determine what action to take on the distributed energy resource aggregation reforms proposed in its Notice of Proposed Rulemaking on Electric Storage Participation in Markets Operated by Regional Transmission Organizations and Independent System Operators (NOPR).1 In the NOPR, the Commission proposed to require each RTO/ISO to define DER aggregators as a 1 See Electric Storage Participation in Markets Operated by Regional Transmission Organizations and Independent System Operators, FERC Stats. & Regs. ¶ 32,718 (2016) (NOPR). VerDate Sep<11>2014 20:10 Feb 21, 2018 Jkt 244001 type of market participant that can participate in the RTO/ISO markets under the participation model that best accommodates the physical and operational characteristics of its DER aggregation.2 As discussed in the Final Rule issued concurrently with this Notice, the Commission is taking no further action in Docket No. RM16–23– 000 regarding the proposed DER aggregation reforms.3 Instead, the Commission will continue to explore the proposed distributed energy resource aggregation reforms under Docket No. RM18–9–000. All comments previously filed in response to the NOPR in Docket No. RM16–23–000 will be incorporated by reference into Docket No. RM18–9–000, and any further comments regarding the proposed distributed energy resource aggregation reforms, including discussion of those reforms during this technical conference, should be filed henceforth in Docket No. RM18–9–000.4 Second, the technical conference will explore issues related to the potential effects of DERs on the bulk power system. Attached to this Notice is a description of the seven panels that will be conducted at the technical conference. Further details of this conference will be provided in a supplemental notice. Those wishing to participate in this conference should submit a nomination form online by 5:00 p.m. on March 15, 2018 at: https://www.ferc.gov/whatsnew/registration/04-10-18-speakerform.asp. All interested persons may attend the conference, and registration is not required. However, in-person attendees are encouraged to register on-line by April 3, 2018 at: https://www.ferc.gov/ whats-new/registration/04-10-18form.asp. In-person attendees should allow time to pass through building security procedures before the 9:30 a.m. start time of the technical conference. The Commission will transcribe and webcast this conference. Transcripts will be available immediately for a fee from Ace Reporting (202–347–3700). A link to the webcast of this event will be available in the Commission Calendar of Events at www.ferc.gov. The Capitol Connection provides technical support for the webcasts and offers the option of 2 Id. P 1. 3 See Electric Storage Participation in Markets Operated by Regional Transmission Organizations and Independent System Operators, Final Rule, 162 FERC 61,127, Notice of Proposed Rulemaking, FERC Stats. & Regs. ¶ 32,718. 4 Further comments regarding the proposed distributed energy resource aggregation reforms should no longer be filed in Docket No. RM16–23– 000. PO 00000 Frm 00050 Fmt 4703 Sfmt 4703 7703 listening to the conference via phonebridge for a fee. For additional information, visit www.CapitolConnection.org or call (703) 993–3100. Commission conferences are accessible under section 508 of the Rehabilitation Act of 1973. For accessibility accommodations please send an email to accessibility@ferc.gov or call toll free 1–866–208–3372 (voice) or 202–208–8659 (TTY), or send a fax to 202–208–2106 with the required accommodations. For more information about this technical conference, please contact David Kathan at (202) 502–6404, david.kathan@ferc.gov, or Louise Nutter at (202) 502–8175, louise.nutter@ ferc.gov. For information related to logistics, please contact Sarah McKinley at (202) 502–8368, sarah.mckinley@ ferc.gov. Dated: February 15, 2018. Nathaniel J. Davis, Sr., Deputy Secretary. Distributed Energy Resources Technical Conference Docket Nos. RM18–9–000 and AD18– 10–000 April 10 and 11, 2018 Tuesday, April 10, 2018 The purpose of this technical conference is to gather additional information to help the Commission determine what action to take on the distributed energy resource (DER) aggregation reforms proposed in the Commission’s Notice of Proposed Rulemaking on Electric Storage Participation in Markets Operated by Regional Transmission Organizations and Independent System Operators (NOPR), and to explore issues related to the potential effects of DERs on the bulk power system. Panels 1 and 3 on the first day focus on specific NOPR proposals that relate to DER participation and compensation. Panel 2 will provide a forum for Commissioners to discuss DER aggregation with a panel of state and local regulators. During the second day of the technical conference, operational issues associated with DER data, modeling, and coordination will be examined. Panel 1: Economic Dispatch, Pricing, and Settlement of DER Aggregations The objective of this panel is to discuss the integration of DER aggregations into the modeling, clearing, dispatch, and settlement mechanisms of RTOs and ISOs as considered in the NOPR. The NOPR proposed to require each RTO/ISO to revise its tariff to E:\FR\FM\22FEN1.SGM 22FEN1 7704 Federal Register / Vol. 83, No. 36 / Thursday, February 22, 2018 / Notices remove barriers to the participation of DER aggregations in its markets by, among other measures, establishing locational requirements for DER aggregations that are as geographically broad as technically feasible.1 The NOPR also addressed the use of distribution factors 2 and bidding parameters 3 for DER aggregations. In consideration of comments received in response to the NOPR, staff seeks additional information about how DER aggregations could locate across more than one pricing node. Staff would also like additional information about bidding parameters or other potential mechanisms needed to represent the physical and operational characteristics of DER aggregations in RTO/ISO markets. In particular, Commission staff expects to explore the following questions: • Acknowledging that some RTOs/ ISOs already allow aggregations across multiple pricing nodes, what approaches are available to ensure that the dispatch of a multi-node DER aggregation does not exacerbate a transmission constraint? • Because transmission constraints change over time, would the ability of a multi-node DER aggregation to participate in an RTO/ISO market need to be revisited as system topology changes? • Do multi-node DER aggregations present any special considerations for the reliability of the transmission system that do not arise from other market participants? How could these concerns be resolved? • What types of modifications would need to be made to the modeling and dispatch software, communications platforms, and automation tools necessary to enable reliable and efficient system dispatch for multi-node DER aggregations? How long would it take for these changes to be implemented? • If the Commission requires the RTOs/ISOs to allow multi-node DER aggregations to participate in their markets, how should a DER aggregation located across multiple pricing nodes be settled for the services that it provides? 1 NOPR at P 139. Commission proposed to require each RTO/ ISO to revise its tariff to include the requirement that DER aggregators (1) provide default distribution factors when they register their DER aggregation and (2) update those distribution factors if necessary when they submit offers to sell or bids to buy into the organized wholesale electric markets. Id. P 143. 3 The Commission sought comment on whether bidding parameters in addition to those already incorporated into existing participation models may be necessary to adequately characterize the physical or operational characteristics of DER aggregations. Id. P 144. daltland on DSKBBV9HB2PROD with NOTICES 2 The VerDate Sep<11>2014 20:10 Feb 21, 2018 Jkt 244001 One approach to settling a multi-node DER aggregation could be to pay it the weighted average locational marginal price (LMP) across the nodes at which it is located. What are the advantages and disadvantages of this approach? Are there other approaches that should be considered? • The NOPR considered the use of ‘‘distribution factors’’ to account for the expected response of DER aggregations from multiple nodes. Are there other characteristics of DER aggregations that may not be accommodated by existing bidding parameters in the RTOs/ISOs? If so, what are they? Would new bidding parameters be necessary? If so, what are they? Panel 2: Discussion of Operational Implications of DER Aggregation With State and Local Regulators This panel will provide a forum for Commissioners to discuss the NOPR’s DER aggregation proposals with state and local regulators. The discussion will provide an opportunity for state and local regulators to provide their perspectives and concerns about the operational effects that DER participation in the wholesale market could have on facilities they regulate. In particular, Commissioners expect to explore the following questions: • What are the potential positive or negative operational impacts (e.g., safety, reliability, and dispatch) that DER participation in the wholesale market could have on facilities regulated by state and local authorities? How should the costs associated with monitoring and addressing such potential impacts on the distribution grid caused by the NOPR proposal be addressed, and fairly allocated? Are existing retail rate structures able to allocate costs to DER aggregations that utilize the distribution systems, and if not, what modifications or coordination are feasible? • Do state and local authorities have operational concerns with a DER aggregation participating in both wholesale and retail markets? If so, what, if any, coordination protocols between states or local regulators and regional markets would be required to facilitate DER aggregations’ participation in both retail and wholesale markets? Could the use of appropriate metering and telemetry address the ability to distinguish between markets and services, and prevent double compensation for the same services? What is the role of state and local regulators in monitoring and regulating the potential for such double compensation? How should regional flexibility be accommodated? PO 00000 Frm 00051 Fmt 4703 Sfmt 4703 • What entities should be included in the coordination processes used to facilitate the participation of DER aggregations in Regional Transmission Organization (RTO) and Independent System Operator (ISO) markets? Should state and local regulatory authorities play an active role in these coordination processes? Is there a need to modify existing RTO/ISO protocols or develop new protocols to accommodate state participation in this coordination? What should be the role of state and local regulators in the NOPR’s proposed distribution utility review of DER aggregation registrations? • Does the proposed use of market participation agreements address state and local regulator concerns about the role of distribution utilities in the coordination and registration of DERs in aggregations? Are the proposed provisions in the market participation agreements that require that DER aggregators attest that they are compliant with the tariffs and operation procedures of distribution utilities and state and local regulators sufficient to address such concerns? • What are the proper protections and policies to ensure that DER aggregations participating in wholesale markets will not negatively affect efficient outcomes in the distribution system? Panel 3: Participation of DERs in RTO/ ISO Markets DERs can both sell services into the RTO/ISO markets and participate in retail compensation programs. To ensure that that there is no duplication of compensation for the same service, in the NOPR the Commission proposed that individual DERs participating in one or more retail compensation programs, such as net metering or another RTO/ISO market participation program, will not be eligible to participate in the RTO/ISO markets as part of a DER aggregation.4 This panel will explore potential solutions to challenges associated with DER aggregations that provide multiple services, including ways to avoid duplication of compensation for their services in the RTO/ISO markets, potential ways for the RTOs/ISOs to place appropriate restrictions on the services they can provide, and procedures to ensure that DERs are not accounted for in ways that affect efficient outcomes in the RTO/ISO markets. In particular, Commission staff expects to explore the following questions: • Given the variety of wholesale and retail services, is it possible to 4 Id. E:\FR\FM\22FEN1.SGM P 134. 22FEN1 Federal Register / Vol. 83, No. 36 / Thursday, February 22, 2018 / Notices universally characterize a set of wholesale and retail services as the ‘‘same service’’? If so, how could the Commission prohibit a DER from providing the same service to the wholesale market as it provides in a retail compensation program? • In Order No. 719, the Commission stated that ‘‘[a]n RTO or ISO may place appropriate restrictions on any customer’s participation in an [aggregation of retail customers]aggregated demand response bid to avoid counting the same demand response resource more than once.’’ 5 How have the RTOs/ISOs effectuated this requirement or otherwise ensured that demand response participating in their markets is not being double counted? What would be the advantages and disadvantages of taking this approach for DER aggregations instead of the approach proposed in the NOPR for preventing double compensation for the same service? • What other options besides the NOPR’s proposed limits on dual participation exist to address issues associated with the participation of DERs or DER aggregations in one or more retail compensation programs or another wholesale market participation program at the same time as it participates in a wholesale DER aggregation? Is there a way to coordinate DER participation in multiple markets or compensation programs? Is a possible solution having a targeted prohibition, such as the limitation placed on netmetered resources in CAISO? 6 Are there other means? Wednesday, April 11, 2018 daltland on DSKBBV9HB2PROD with NOTICES Panel 4: Collection and Availability of Data on DER Installations To plan and operate the bulk power system, it is important for transmission planners, transmission operators, and distribution utilities to collect and share validated data across the transmissiondistribution interface. In September 2017, the North American Electric Reliability Corporation (NERC) published a Reliability Guideline on DER modeling (Guideline) that specified the minimum DER information needed by transmission planners and planning coordinators to assist in modeling and assessments.7 The Guideline references 5 Wholesale Competition in Regions with Organized Electric Markets, Order No. 719, FERC Stats. & Regs. ¶ 31,281, at P 158 (2008), order on reh’g, Order No. 719–A, FERC Stats. & Regs. ¶ 31,292 (2009), order on reh’g, Order No. 719–B, 129 FERC ¶ 61,252 (2009). 6 See CAISO Tariff, § 4.17.3(d). 7 See NERC Distributed Energy Resource Modeling Reliability Guideline, at 5 (Sept. 2017), available at https://www.nerc.com/comm/PC_ VerDate Sep<11>2014 20:10 Feb 21, 2018 Jkt 244001 the importance of static data (such as the capacity, capabilities, and location of a DER installation) for the entities involved in the planning of the bulk power system. This panel will focus on understanding the need for bulk power system planners and operators to have access to accurate data to plan and operate the bulk power system, explore the types of data that are needed, and assess the current state of DER data collection. The panel will also address regional DER penetration levels and any potential effects of inaccurate long-term DER forecasting. A Commission Staff DER Technical Report is being issued concurrently with this Notice to provide a common foundation for the topics raised in this panel. For this panel, Commission staff expects to explore the following questions: • What type of information do bulk power system planners and operators need regarding DER installations within their footprint to plan and operate the bulk power system? Would it be sufficient for distribution utilities to provide aggregate information about the penetration of DERs below certain points on the transmission-distribution interface? If greater granularity is needed, what level of detail would be sufficient? Is validation of the submitted data possible using data available? • What, if any, data on DER installations is currently collected, and by whom is it collected? Do procedures and appropriate agreements exist to share this data with affected bulk power system entities (i.e., those entities responsible for the reliable operation of the bulk power system or for modeling and planning for a reliable bulk power system)? Is there variation by entity or region? • At various DER penetration levels, what planning and operations impacts do you observe? Do balancing authorities with significant growth in DERs experience the need to address bulk power system reliability and operational considerations at certain DER penetration levels? What are they? Is the MW level of DER penetration the most important factor in whether DERs cause planning and operational impacts, or do certain characteristics of installed DERs affect the system operator’s analysis? Is the point at which DER penetration causes bulk power system reliability and operational impacts the point at which it becomes necessary for distribution utilities to provide information on DERs to the bulk power system operator, or is there some other Reliability_Guidelines_DL/Reliability_Guideline_-_ DER_Modeling_Parameters_-_2017-08-18_-_ FINAL.pdf. PO 00000 Frm 00052 Fmt 4703 Sfmt 4703 7705 threshold that could trigger a need for sharing this information? How much might the answer to these questions vary on a regional basis, and what factors may contribute to this variance? • How are long-term projections for DER penetrations developed? Are these projections currently included in related forecasting efforts? Do system operators study the potential effects of future DER growth to assess changing infrastructure and planning needs at different penetration levels? • What are the effects on the bulk power system if long-term forecasts of DER growth are inaccurate? Are these effects within current planning horizons? Are changes in the expected growth of DERs incorporated into ongoing planning efforts? • How are DERs incorporated into production cost modeling studies? Do current tools allow for assessment of forecasting variations and their effects? • Noting that participation in the RTO/ISO markets by DER aggregators may provide more information to the RTOs/ISOs about DERs than would otherwise be available, should any specific information about DER aggregations or the individual DERs in them be required from aggregators to ensure proper planning and operation of the bulk power system? • Do the RTOs/ISOs need any directly metered data about the operations of DER aggregations to ensure proper planning and operation of the bulk power system? Panel 5: Incorporating DERs in Modeling, Planning and Operations Studies Bulk power system planners and operators must select methods to feasibly model DERs at the bulk power system level with sufficient granularity to ensure accurate results. The chosen methodology for grouping DERs at the bulk power system level could affect planners’ ability to predict system behavior following events, or to identify a need for different operating procedures under changing system conditions. Further, the operation of DERs can affect both bulk power systems and distribution facilities in unintended ways, suggesting that new tools to model the transmission and distribution interface may be needed. Staff is also aware of ongoing work in this area, for example efforts at NERC, national labs and other groups, to evaluate options for studies in these areas, which could also inform future work. This panel will focus on the incorporation of DERs into different types of planning and operational studies, including options for modeling E:\FR\FM\22FEN1.SGM 22FEN1 7706 Federal Register / Vol. 83, No. 36 / Thursday, February 22, 2018 / Notices daltland on DSKBBV9HB2PROD with NOTICES DERs and the methodology for the inclusion of DERs in larger regional models. The Commission Staff DER Technical Report issued concurrently with this Notice is intended to provide a common foundation for the topics raised in this panel. For this panel, Commission staff expects to explore the following questions: • What are current and best practices for modeling DERs in different types of planning, operations, and production cost studies? Are options available for modeling the interactions between the transmission and distribution systems? • To what extent are capabilities and performance of DERs currently modeled? Do current modeling tools provide features needed to model these capabilities? • What methods, such as net load, composite load models, detailed models or others, are currently used in power flow and dynamic models to represent groups of DERs at the bulk power system level? Would more detailed models of DERs at the bulk power system level provide better visibility and enable more accurate assessment of their impacts on system conditions? Does the appropriate method for grouping DERs vary by penetration level? • Do current contingency studies include the outage of DER facilities, and if they are considered, how is the contingency size chosen? At what penetration levels or under what system conditions could including DER outages be beneficial? Are DERs accounted for in calculations for Under Frequency Load Shedding and related studies? • What methods are used to calculate capacity needed for balancing supply and demand with large amount of solar DER (ramping and frequency control) and determining which resources can provide an appropriate response? Panel 6: Coordination of DER Aggregations Participating in RTO/ISO Markets In the NOPR, the Commission proposed to require each RTO/ISO to revise its tariff to provide for coordination among itself, a DER aggregator, and the relevant distribution utility or utilities when a DER aggregator registers a new DER aggregation or modifies an existing DER aggregation.8 The Commission proposed that this coordination would provide the relevant distribution utility or utilities with the opportunity to review the list of individual resources that are located on their distribution system that enroll in a DER aggregation before those 8 NOPR at P 154. VerDate Sep<11>2014 20:10 Feb 21, 2018 Jkt 244001 resources may participate in RTO/ISO electric markets. This panel will examine the potential ways for RTOs/ ISOs, distribution utilities, retail regulatory authorities, and DER aggregators to coordinate the integration of a DER aggregation into the RTO/ISO markets. In addition, because the use of grid architecture 9 can help identify the relationships among the entities involved in coordinating the integration of DER aggregations, this panel will also examine the potential architectural designs for the initial coordination processes from the point of view of the RTO/ISO markets. In particular, Commission staff expects to explore the following questions: • If the Commission adopts its proposal to require the RTO/ISO to allow a distribution utility to review the list of individual resources that are located on their distribution system that enroll in a DER aggregation before those resources may participate in RTO/ISO electric markets, is it appropriate for distribution utilities to have a role in determining when the individual DERs may begin participation? Should the RTO/ISO tariff provide the distribution utility with the ability to provide either binding or non-binding input to the RTO/ISO? Should the RTO/ISO provide the distribution utility with a specific period of time in which to consult before DERs may begin participation? Should the Commission require the RTO/ISO to receive explicit consent from the distribution utility before a DER is included in a DER aggregation? Are there other approaches to coordinate with the distribution utility? What are the advantages and disadvantages of these approaches? • Are new processes and protocols needed to ensure coordination among DER aggregators, distribution utilities, and RTOs/ISOs during registration of a new DER aggregations? How can the Commission ensure that any new processes and protocols occur in a way that provides adequate transparency to the interested parties and also occurs on a timely basis? • Should there be a coordination agreement in place prior to the participation of DER aggregation in RTO/ISO markets? Who should be 9 As an aid to thinking about the electric power grid, Pacific Northwest National Laboratory and others have coined the term ‘‘grid architecture,’’ which they define as the application of network theory and control theory to a conceptual model of the electric power grid that defines its structure, behavior, and essential limits. See, e.g., https:// gridarchitecture.pnnl.gov/. Expanding upon this concept, some thinkers have begun discussing different types of ‘‘grid architecture,’’ which presumably differ in structure, behavior or essential limits from current norms. PO 00000 Frm 00053 Fmt 4703 Sfmt 4703 parties to this coordination agreement? How would the coordination agreement be enforced? • What is the best approach for involving retail regulatory authorities in the registration of DER aggregations in the RTO/ISO markets? • What types of grid architecture could support the integration of DER aggregations into the RTO/ISO markets? Knowing that a variety of grid architectures are being explored in various regions, does it make sense for the Commission to consider specific architectural requirements for RTOs/ ISOs for the effective integration and coordination of DER aggregations? Panel 7: Ongoing Operational Coordination This panel will focus primarily on the operational considerations associated with both individual DERs and DER aggregations and with the interactions and communications between DERs, DER aggregators, distribution utilities, and transmission operators. In the NOPR, the Commission acknowledged that ongoing coordination between the RTO/ISO, a DER aggregator, and the relevant distribution utility or utilities may be necessary to ensure that the DER aggregator is dispatching individual resources in a DER aggregation consistent with the limitations of the distribution system.10 The Commission proposed that each RTO/ISO revise its tariff to establish a process for ongoing coordination, including operational coordination, among itself, the DER aggregator, and the distribution utility to maximize the availability of the DER aggregation consistent with the safe and reliable operation of the distribution system. To help effectuate this proposal, the Commission also proposed to require each RTO/ISO to revise its tariff to require the DER aggregator to report to the RTO/ISO any changes to its offered quantity and related distribution factors that result from distribution line faults or outages. The Commission also sought comment on the level of detail necessary in the RTO/ISO tariffs to establish a framework for ongoing coordination between the RTO/ISO, a DER aggregator, and the relevant distribution utility or utilities. To further explore these issues, Commission staff expects to explore the following questions: • What real-time data acquisition and communication technologies are currently in use to provide bulk power system operators with visibility into the distribution system? Are they adequate to convey the information necessary for 10 NOPR E:\FR\FM\22FEN1.SGM at P 155. 22FEN1 daltland on DSKBBV9HB2PROD with NOTICES Federal Register / Vol. 83, No. 36 / Thursday, February 22, 2018 / Notices transmission and distribution operators to assess distribution system conditions in real time? Are new systems or approaches needed? Does DER aggregation require separate or additional capabilities and infrastructure for communication and control? • What processes/protocols do distribution utilities, transmission operators, and DERs or DER aggregators use to coordinate with each other? Are these processes/protocols capable of providing needed real-time communications and coordination? What new processes, resources, and efforts will be required to achieve effective real-time coordination? • What are the minimum set of specific RTO/ISO operational protocols, performance standards, and market rules that should be adopted now to ensure operational coordination for DER aggregation participating in the RTO/ ISO markets? What additional protocols may be important for the future? Should the Commission adopt more prescriptive requirements with respect to coordination than those proposed in the NOPR? If so, what should the Commission require? • Should distribution utilities be able to override RTO/ISO decisions regarding day-ahead and real-time dispatch of DER aggregations to resolve local distribution reliability issues? If so, should DER aggregations nonetheless be subject to non-deliverability penalties under such circumstances? • Is it possible for DERs or DER aggregations participating in the RTO/ ISO markets to also be used to improve distribution system operations and reliability? If so, please provide examples of how this could be accomplished. • Can real-time dispatch of aggregated DERs address distribution constraints? If not, can tools be developed to accomplish this? • Should individual DERs be required to have communications capabilities to comply with control center obligations? What level of communications security should be employed for these communications? • How might recent and expected technical advancements be used to enhance the coordination of DER aggregations, for example, integrating Energy Management Systems (EMS) and Distribution Management Systems (DMS) for efficient operational coordination? [FR Doc. 2018–03649 Filed 2–21–18; 8:45 am] BILLING CODE 6717–01–P VerDate Sep<11>2014 20:10 Feb 21, 2018 Jkt 244001 DEPARTMENT OF ENERGY Federal Energy Regulatory Commission [Docket Nos. EL17–70–000; QF17–935–001; QF17–936–001] Zeeland Farm Services, Inc.; Notice of Amended Petition for Declaratory Order Take notice that on February 14, 2018, pursuant to Rule 215 of the Rules of Practice and Procedure of the Federal Energy Regulatory Commission (Commission),1 and section 292.203(d)(2) of the Commission’s regulations,2 Zeeland Farm Services, Inc. (Zeeland or Petitioner) submitted an amendment to its petition for declaratory order, filed on May 3, 2017, requesting that the Commission grant Zeeland limited waiver from the FERC Form 556 filing requirement 3 for two qualifying small power production facilities, as more fully explained in the petition. Any person desiring to intervene or to protest in this proceeding must file in accordance with Rules 211 and 214 of the Commission’s Rules of Practice and Procedure (18 CFR 385.211 and 385.214) on or before 5:00 p.m. Eastern time on the specified comment date. Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceeding. Any person wishing to become a party must file a notice of intervention or motion to intervene, as appropriate. Such notices, motions, or protests must be filed on or before the comment date. Anyone filing a motion to intervene or protest must serve a copy of that document on the Petitioner. The Commission encourages electronic submission of protests and interventions in lieu of paper, using the FERC Online links at https:// www.ferc.gov. To facilitate electronic service, persons with internet access who will eFile a document and/or be listed as a contact for an intervenor must create and validate an eRegistration account using the eRegistration link. Select the eFiling link to log on and submit the intervention or protests. Persons unable to file electronically should submit an original and 5 copies of the intervention or protest to the Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426. 1 18 CFR 385.215 (2017). CFR 292.203(d)(2). 3 18 CFR 292.203(a)(3). 2 18 PO 00000 Frm 00054 Fmt 4703 Sfmt 4703 7707 The filings in the above proceeding are accessible in the Commission’s eLibrary system by clicking on the appropriate link in the above list. They are also available for review in the Commission’s Public Reference Room in Washington, DC. There is an eSubscription link on the website that enables subscribers to receive email notification when a document is added to a subscribed docket(s). For assistance with any FERC Online service, please email FERCOnlineSupport@ferc.gov.or call (866) 208–3676 (toll free). For TTY, call (202) 502–8659. Comment Date: 5:00 p.m. Eastern time on March 7, 2018. Dated: February 15, 2018. Nathaniel J. Davis, Sr., Deputy Secretary. [FR Doc. 2018–03647 Filed 2–21–18; 8:45 am] BILLING CODE 6717–01–P DEPARTMENT OF ENERGY Federal Energy Regulatory Commission [Project No. 2804–035] Goose River Hydro, Inc.; Notice of Application Tendered for Filing With the Commission and Soliciting Additional Study Requests Take notice that the following hydroelectric application has been filed with the Commission and is available for public inspection. a. Type of Application: New minor license b. Project No.: P–2804–035 c. Date filed: February 2, 2018 d. Applicant: Goose River Hydro, Inc. e. Name of Project: Goose River Hydroelectric Project f. Location: On the Goose River, near Belfast, Waldo County, Maine. No federal or tribal lands would be occupied by project works or located within the project boundary. g. Filed Pursuant to: Federal Power Act 16 U.S.C. 791(a)–825(r). h. Applicant Contact: Nicholas Cabral, Goose River Hydro Inc., 67 Swan Lake Ave., Belfast, ME 04095, (207)– 604–4394, gooseriverhydro@gmail.com. i. FERC Contact: Julia Kolberg, 888 1st St. NE, Washington, DC 20426, (202) 502–8261, Julia.kolberg@ferc.gov. j. Cooperating agencies: Federal, state, local, and tribal agencies with jurisdiction and/or special expertise with respect to environmental issues that wish to cooperate in the preparation of the environmental document should follow the instructions for filing such requests E:\FR\FM\22FEN1.SGM 22FEN1

Agencies

[Federal Register Volume 83, Number 36 (Thursday, February 22, 2018)]
[Notices]
[Pages 7703-7707]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2018-03649]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission


Notice of Technical Conference

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                                                     Docket Nos.
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Participation of Distributed Energy         RM18-9-000
 Resource Aggregations in Markets Operated
 by Regional Transmission Organizations
 and Independent System Operators.
Distributed Energy Resources--Technical     AD18-10-000
 Considerations for the Bulk Power System.
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    Take notice that Federal Energy Regulatory Commission (Commission) 
staff will hold a technical conference to discuss the participation of 
distributed energy resource (DER) aggregations in Regional Transmission 
Organization (RTO) and Independent System Operator (ISO) markets, and 
to more broadly discuss the potential effects of distributed energy 
resources on the bulk power system. The technical conference will take 
place on April 10 and 11, 2018 at the Commission's offices at 888 First 
Street NE, Washington DC beginning at 9:30 a.m. and ending at 4:30 p.m. 
(Eastern Time). Commissioners will lead the second panel of the 
technical conference. Commission staff will lead the other six panels, 
and Commissioners may attend.
    The technical conference will address two broad set of issues 
related to DERs. First, the technical conference will gather additional 
information to help the Commission determine what action to take on the 
distributed energy resource aggregation reforms proposed in its Notice 
of Proposed Rulemaking on Electric Storage Participation in Markets 
Operated by Regional Transmission Organizations and Independent System 
Operators (NOPR).\1\ In the NOPR, the Commission proposed to require 
each RTO/ISO to define DER aggregators as a type of market participant 
that can participate in the RTO/ISO markets under the participation 
model that best accommodates the physical and operational 
characteristics of its DER aggregation.\2\ As discussed in the Final 
Rule issued concurrently with this Notice, the Commission is taking no 
further action in Docket No. RM16-23-000 regarding the proposed DER 
aggregation reforms.\3\ Instead, the Commission will continue to 
explore the proposed distributed energy resource aggregation reforms 
under Docket No. RM18-9-000. All comments previously filed in response 
to the NOPR in Docket No. RM16-23-000 will be incorporated by reference 
into Docket No. RM18-9-000, and any further comments regarding the 
proposed distributed energy resource aggregation reforms, including 
discussion of those reforms during this technical conference, should be 
filed henceforth in Docket No. RM18-9-000.\4\ Second, the technical 
conference will explore issues related to the potential effects of DERs 
on the bulk power system.
---------------------------------------------------------------------------

    \1\ See Electric Storage Participation in Markets Operated by 
Regional Transmission Organizations and Independent System 
Operators, FERC Stats. & Regs. ] 32,718 (2016) (NOPR).
    \2\ Id. P 1.
    \3\ See Electric Storage Participation in Markets Operated by 
Regional Transmission Organizations and Independent System 
Operators, Final Rule, 162 FERC 61,127, Notice of Proposed 
Rulemaking, FERC Stats. & Regs. ] 32,718.
    \4\ Further comments regarding the proposed distributed energy 
resource aggregation reforms should no longer be filed in Docket No. 
RM16-23-000.
---------------------------------------------------------------------------

    Attached to this Notice is a description of the seven panels that 
will be conducted at the technical conference.
    Further details of this conference will be provided in a 
supplemental notice.
    Those wishing to participate in this conference should submit a 
nomination form online by 5:00 p.m. on March 15, 2018 at: https://www.ferc.gov/whats-new/registration/04-10-18-speaker-form.asp.
    All interested persons may attend the conference, and registration 
is not required. However, in-person attendees are encouraged to 
register on-line by April 3, 2018 at: https://www.ferc.gov/whats-new/registration/04-10-18-form.asp. In-person attendees should allow time 
to pass through building security procedures before the 9:30 a.m. start 
time of the technical conference.
    The Commission will transcribe and webcast this conference. 
Transcripts will be available immediately for a fee from Ace Reporting 
(202-347-3700). A link to the webcast of this event will be available 
in the Commission Calendar of Events at www.ferc.gov. The Capitol 
Connection provides technical support for the webcasts and offers the 
option of listening to the conference via phone-bridge for a fee. For 
additional information, visit www.CapitolConnection.org or call (703) 
993-3100.
    Commission conferences are accessible under section 508 of the 
Rehabilitation Act of 1973. For accessibility accommodations please 
send an email to [email protected] or call toll free 1-866-208-
3372 (voice) or 202-208-8659 (TTY), or send a fax to 202-208-2106 with 
the required accommodations.
    For more information about this technical conference, please 
contact David Kathan at (202) 502-6404, [email protected], or 
Louise Nutter at (202) 502-8175, [email protected]. For 
information related to logistics, please contact Sarah McKinley at 
(202) 502-8368, [email protected].

    Dated: February 15, 2018.
Nathaniel J. Davis, Sr.,
Deputy Secretary.

Distributed Energy Resources Technical Conference

Docket Nos. RM18-9-000 and AD18-10-000

April 10 and 11, 2018
Tuesday, April 10, 2018
    The purpose of this technical conference is to gather additional 
information to help the Commission determine what action to take on the 
distributed energy resource (DER) aggregation reforms proposed in the 
Commission's Notice of Proposed Rulemaking on Electric Storage 
Participation in Markets Operated by Regional Transmission 
Organizations and Independent System Operators (NOPR), and to explore 
issues related to the potential effects of DERs on the bulk power 
system. Panels 1 and 3 on the first day focus on specific NOPR 
proposals that relate to DER participation and compensation. Panel 2 
will provide a forum for Commissioners to discuss DER aggregation with 
a panel of state and local regulators. During the second day of the 
technical conference, operational issues associated with DER data, 
modeling, and coordination will be examined.
Panel 1: Economic Dispatch, Pricing, and Settlement of DER Aggregations
    The objective of this panel is to discuss the integration of DER 
aggregations into the modeling, clearing, dispatch, and settlement 
mechanisms of RTOs and ISOs as considered in the NOPR. The NOPR 
proposed to require each RTO/ISO to revise its tariff to

[[Page 7704]]

remove barriers to the participation of DER aggregations in its markets 
by, among other measures, establishing locational requirements for DER 
aggregations that are as geographically broad as technically 
feasible.\1\ The NOPR also addressed the use of distribution factors 
\2\ and bidding parameters \3\ for DER aggregations. In consideration 
of comments received in response to the NOPR, staff seeks additional 
information about how DER aggregations could locate across more than 
one pricing node. Staff would also like additional information about 
bidding parameters or other potential mechanisms needed to represent 
the physical and operational characteristics of DER aggregations in 
RTO/ISO markets. In particular, Commission staff expects to explore the 
following questions:
---------------------------------------------------------------------------

    \1\ NOPR at P 139.
    \2\ The Commission proposed to require each RTO/ISO to revise 
its tariff to include the requirement that DER aggregators (1) 
provide default distribution factors when they register their DER 
aggregation and (2) update those distribution factors if necessary 
when they submit offers to sell or bids to buy into the organized 
wholesale electric markets. Id. P 143.
    \3\ The Commission sought comment on whether bidding parameters 
in addition to those already incorporated into existing 
participation models may be necessary to adequately characterize the 
physical or operational characteristics of DER aggregations. Id. P 
144.
---------------------------------------------------------------------------

     Acknowledging that some RTOs/ISOs already allow 
aggregations across multiple pricing nodes, what approaches are 
available to ensure that the dispatch of a multi-node DER aggregation 
does not exacerbate a transmission constraint?
     Because transmission constraints change over time, would 
the ability of a multi-node DER aggregation to participate in an RTO/
ISO market need to be revisited as system topology changes?
     Do multi-node DER aggregations present any special 
considerations for the reliability of the transmission system that do 
not arise from other market participants? How could these concerns be 
resolved?
     What types of modifications would need to be made to the 
modeling and dispatch software, communications platforms, and 
automation tools necessary to enable reliable and efficient system 
dispatch for multi-node DER aggregations? How long would it take for 
these changes to be implemented?
     If the Commission requires the RTOs/ISOs to allow multi-
node DER aggregations to participate in their markets, how should a DER 
aggregation located across multiple pricing nodes be settled for the 
services that it provides? One approach to settling a multi-node DER 
aggregation could be to pay it the weighted average locational marginal 
price (LMP) across the nodes at which it is located. What are the 
advantages and disadvantages of this approach? Are there other 
approaches that should be considered?
     The NOPR considered the use of ``distribution factors'' to 
account for the expected response of DER aggregations from multiple 
nodes. Are there other characteristics of DER aggregations that may not 
be accommodated by existing bidding parameters in the RTOs/ISOs? If so, 
what are they? Would new bidding parameters be necessary? If so, what 
are they?
Panel 2: Discussion of Operational Implications of DER Aggregation With 
State and Local Regulators
    This panel will provide a forum for Commissioners to discuss the 
NOPR's DER aggregation proposals with state and local regulators. The 
discussion will provide an opportunity for state and local regulators 
to provide their perspectives and concerns about the operational 
effects that DER participation in the wholesale market could have on 
facilities they regulate. In particular, Commissioners expect to 
explore the following questions:
     What are the potential positive or negative operational 
impacts (e.g., safety, reliability, and dispatch) that DER 
participation in the wholesale market could have on facilities 
regulated by state and local authorities? How should the costs 
associated with monitoring and addressing such potential impacts on the 
distribution grid caused by the NOPR proposal be addressed, and fairly 
allocated? Are existing retail rate structures able to allocate costs 
to DER aggregations that utilize the distribution systems, and if not, 
what modifications or coordination are feasible?
     Do state and local authorities have operational concerns 
with a DER aggregation participating in both wholesale and retail 
markets? If so, what, if any, coordination protocols between states or 
local regulators and regional markets would be required to facilitate 
DER aggregations' participation in both retail and wholesale markets? 
Could the use of appropriate metering and telemetry address the ability 
to distinguish between markets and services, and prevent double 
compensation for the same services? What is the role of state and local 
regulators in monitoring and regulating the potential for such double 
compensation? How should regional flexibility be accommodated?
     What entities should be included in the coordination 
processes used to facilitate the participation of DER aggregations in 
Regional Transmission Organization (RTO) and Independent System 
Operator (ISO) markets? Should state and local regulatory authorities 
play an active role in these coordination processes? Is there a need to 
modify existing RTO/ISO protocols or develop new protocols to 
accommodate state participation in this coordination? What should be 
the role of state and local regulators in the NOPR's proposed 
distribution utility review of DER aggregation registrations?
     Does the proposed use of market participation agreements 
address state and local regulator concerns about the role of 
distribution utilities in the coordination and registration of DERs in 
aggregations? Are the proposed provisions in the market participation 
agreements that require that DER aggregators attest that they are 
compliant with the tariffs and operation procedures of distribution 
utilities and state and local regulators sufficient to address such 
concerns?
     What are the proper protections and policies to ensure 
that DER aggregations participating in wholesale markets will not 
negatively affect efficient outcomes in the distribution system?
Panel 3: Participation of DERs in RTO/ISO Markets
    DERs can both sell services into the RTO/ISO markets and 
participate in retail compensation programs. To ensure that that there 
is no duplication of compensation for the same service, in the NOPR the 
Commission proposed that individual DERs participating in one or more 
retail compensation programs, such as net metering or another RTO/ISO 
market participation program, will not be eligible to participate in 
the RTO/ISO markets as part of a DER aggregation.\4\ This panel will 
explore potential solutions to challenges associated with DER 
aggregations that provide multiple services, including ways to avoid 
duplication of compensation for their services in the RTO/ISO markets, 
potential ways for the RTOs/ISOs to place appropriate restrictions on 
the services they can provide, and procedures to ensure that DERs are 
not accounted for in ways that affect efficient outcomes in the RTO/ISO 
markets. In particular, Commission staff expects to explore the 
following questions:
---------------------------------------------------------------------------

    \4\ Id. P 134.
---------------------------------------------------------------------------

     Given the variety of wholesale and retail services, is it 
possible to

[[Page 7705]]

universally characterize a set of wholesale and retail services as the 
``same service''? If so, how could the Commission prohibit a DER from 
providing the same service to the wholesale market as it provides in a 
retail compensation program?
     In Order No. 719, the Commission stated that ``[a]n RTO or 
ISO may place appropriate restrictions on any customer's participation 
in an [aggregation of retail customers]-aggregated demand response bid 
to avoid counting the same demand response resource more than once.'' 
\5\ How have the RTOs/ISOs effectuated this requirement or otherwise 
ensured that demand response participating in their markets is not 
being double counted? What would be the advantages and disadvantages of 
taking this approach for DER aggregations instead of the approach 
proposed in the NOPR for preventing double compensation for the same 
service?
---------------------------------------------------------------------------

    \5\ Wholesale Competition in Regions with Organized Electric 
Markets, Order No. 719, FERC Stats. & Regs. ] 31,281, at P 158 
(2008), order on reh'g, Order No. 719-A, FERC Stats. & Regs. ] 
31,292 (2009), order on reh'g, Order No. 719-B, 129 FERC ] 61,252 
(2009).
---------------------------------------------------------------------------

     What other options besides the NOPR's proposed limits on 
dual participation exist to address issues associated with the 
participation of DERs or DER aggregations in one or more retail 
compensation programs or another wholesale market participation program 
at the same time as it participates in a wholesale DER aggregation? Is 
there a way to coordinate DER participation in multiple markets or 
compensation programs? Is a possible solution having a targeted 
prohibition, such as the limitation placed on net-metered resources in 
CAISO? \6\ Are there other means?
---------------------------------------------------------------------------

    \6\ See CAISO Tariff, Sec.  4.17.3(d).
---------------------------------------------------------------------------

Wednesday, April 11, 2018
Panel 4: Collection and Availability of Data on DER Installations
    To plan and operate the bulk power system, it is important for 
transmission planners, transmission operators, and distribution 
utilities to collect and share validated data across the transmission-
distribution interface. In September 2017, the North American Electric 
Reliability Corporation (NERC) published a Reliability Guideline on DER 
modeling (Guideline) that specified the minimum DER information needed 
by transmission planners and planning coordinators to assist in 
modeling and assessments.\7\ The Guideline references the importance of 
static data (such as the capacity, capabilities, and location of a DER 
installation) for the entities involved in the planning of the bulk 
power system. This panel will focus on understanding the need for bulk 
power system planners and operators to have access to accurate data to 
plan and operate the bulk power system, explore the types of data that 
are needed, and assess the current state of DER data collection. The 
panel will also address regional DER penetration levels and any 
potential effects of inaccurate long-term DER forecasting. A Commission 
Staff DER Technical Report is being issued concurrently with this 
Notice to provide a common foundation for the topics raised in this 
panel. For this panel, Commission staff expects to explore the 
following questions:
---------------------------------------------------------------------------

    \7\ See NERC Distributed Energy Resource Modeling Reliability 
Guideline, at 5 (Sept. 2017), available at https://www.nerc.com/comm/PC_Reliability_Guidelines_DL/Reliability_Guideline_-_DER_Modeling_Parameters_-_2017-08-18_-_FINAL.pdf.
---------------------------------------------------------------------------

     What type of information do bulk power system planners and 
operators need regarding DER installations within their footprint to 
plan and operate the bulk power system? Would it be sufficient for 
distribution utilities to provide aggregate information about the 
penetration of DERs below certain points on the transmission-
distribution interface? If greater granularity is needed, what level of 
detail would be sufficient? Is validation of the submitted data 
possible using data available?
     What, if any, data on DER installations is currently 
collected, and by whom is it collected? Do procedures and appropriate 
agreements exist to share this data with affected bulk power system 
entities (i.e., those entities responsible for the reliable operation 
of the bulk power system or for modeling and planning for a reliable 
bulk power system)? Is there variation by entity or region?
     At various DER penetration levels, what planning and 
operations impacts do you observe? Do balancing authorities with 
significant growth in DERs experience the need to address bulk power 
system reliability and operational considerations at certain DER 
penetration levels? What are they? Is the MW level of DER penetration 
the most important factor in whether DERs cause planning and 
operational impacts, or do certain characteristics of installed DERs 
affect the system operator's analysis? Is the point at which DER 
penetration causes bulk power system reliability and operational 
impacts the point at which it becomes necessary for distribution 
utilities to provide information on DERs to the bulk power system 
operator, or is there some other threshold that could trigger a need 
for sharing this information? How much might the answer to these 
questions vary on a regional basis, and what factors may contribute to 
this variance?
     How are long-term projections for DER penetrations 
developed? Are these projections currently included in related 
forecasting efforts? Do system operators study the potential effects of 
future DER growth to assess changing infrastructure and planning needs 
at different penetration levels?
     What are the effects on the bulk power system if long-term 
forecasts of DER growth are inaccurate? Are these effects within 
current planning horizons? Are changes in the expected growth of DERs 
incorporated into ongoing planning efforts?
     How are DERs incorporated into production cost modeling 
studies? Do current tools allow for assessment of forecasting 
variations and their effects?
     Noting that participation in the RTO/ISO markets by DER 
aggregators may provide more information to the RTOs/ISOs about DERs 
than would otherwise be available, should any specific information 
about DER aggregations or the individual DERs in them be required from 
aggregators to ensure proper planning and operation of the bulk power 
system?
     Do the RTOs/ISOs need any directly metered data about the 
operations of DER aggregations to ensure proper planning and operation 
of the bulk power system?
Panel 5: Incorporating DERs in Modeling, Planning and Operations 
Studies
    Bulk power system planners and operators must select methods to 
feasibly model DERs at the bulk power system level with sufficient 
granularity to ensure accurate results. The chosen methodology for 
grouping DERs at the bulk power system level could affect planners' 
ability to predict system behavior following events, or to identify a 
need for different operating procedures under changing system 
conditions. Further, the operation of DERs can affect both bulk power 
systems and distribution facilities in unintended ways, suggesting that 
new tools to model the transmission and distribution interface may be 
needed. Staff is also aware of ongoing work in this area, for example 
efforts at NERC, national labs and other groups, to evaluate options 
for studies in these areas, which could also inform future work. This 
panel will focus on the incorporation of DERs into different types of 
planning and operational studies, including options for modeling

[[Page 7706]]

DERs and the methodology for the inclusion of DERs in larger regional 
models. The Commission Staff DER Technical Report issued concurrently 
with this Notice is intended to provide a common foundation for the 
topics raised in this panel. For this panel, Commission staff expects 
to explore the following questions:

     What are current and best practices for modeling DERs in 
different types of planning, operations, and production cost studies? 
Are options available for modeling the interactions between the 
transmission and distribution systems?
     To what extent are capabilities and performance of DERs 
currently modeled? Do current modeling tools provide features needed to 
model these capabilities?
     What methods, such as net load, composite load models, 
detailed models or others, are currently used in power flow and dynamic 
models to represent groups of DERs at the bulk power system level? 
Would more detailed models of DERs at the bulk power system level 
provide better visibility and enable more accurate assessment of their 
impacts on system conditions? Does the appropriate method for grouping 
DERs vary by penetration level?
     Do current contingency studies include the outage of DER 
facilities, and if they are considered, how is the contingency size 
chosen? At what penetration levels or under what system conditions 
could including DER outages be beneficial? Are DERs accounted for in 
calculations for Under Frequency Load Shedding and related studies?
     What methods are used to calculate capacity needed for 
balancing supply and demand with large amount of solar DER (ramping and 
frequency control) and determining which resources can provide an 
appropriate response?
Panel 6: Coordination of DER Aggregations Participating in RTO/ISO 
Markets
    In the NOPR, the Commission proposed to require each RTO/ISO to 
revise its tariff to provide for coordination among itself, a DER 
aggregator, and the relevant distribution utility or utilities when a 
DER aggregator registers a new DER aggregation or modifies an existing 
DER aggregation.\8\ The Commission proposed that this coordination 
would provide the relevant distribution utility or utilities with the 
opportunity to review the list of individual resources that are located 
on their distribution system that enroll in a DER aggregation before 
those resources may participate in RTO/ISO electric markets. This panel 
will examine the potential ways for RTOs/ISOs, distribution utilities, 
retail regulatory authorities, and DER aggregators to coordinate the 
integration of a DER aggregation into the RTO/ISO markets. In addition, 
because the use of grid architecture \9\ can help identify the 
relationships among the entities involved in coordinating the 
integration of DER aggregations, this panel will also examine the 
potential architectural designs for the initial coordination processes 
from the point of view of the RTO/ISO markets. In particular, 
Commission staff expects to explore the following questions:
---------------------------------------------------------------------------

    \8\ NOPR at P 154.
    \9\ As an aid to thinking about the electric power grid, Pacific 
Northwest National Laboratory and others have coined the term ``grid 
architecture,'' which they define as the application of network 
theory and control theory to a conceptual model of the electric 
power grid that defines its structure, behavior, and essential 
limits. See, e.g., https://gridarchitecture.pnnl.gov/. Expanding 
upon this concept, some thinkers have begun discussing different 
types of ``grid architecture,'' which presumably differ in 
structure, behavior or essential limits from current norms.
---------------------------------------------------------------------------

     If the Commission adopts its proposal to require the RTO/
ISO to allow a distribution utility to review the list of individual 
resources that are located on their distribution system that enroll in 
a DER aggregation before those resources may participate in RTO/ISO 
electric markets, is it appropriate for distribution utilities to have 
a role in determining when the individual DERs may begin participation? 
Should the RTO/ISO tariff provide the distribution utility with the 
ability to provide either binding or non-binding input to the RTO/ISO? 
Should the RTO/ISO provide the distribution utility with a specific 
period of time in which to consult before DERs may begin participation? 
Should the Commission require the RTO/ISO to receive explicit consent 
from the distribution utility before a DER is included in a DER 
aggregation? Are there other approaches to coordinate with the 
distribution utility? What are the advantages and disadvantages of 
these approaches?
     Are new processes and protocols needed to ensure 
coordination among DER aggregators, distribution utilities, and RTOs/
ISOs during registration of a new DER aggregations? How can the 
Commission ensure that any new processes and protocols occur in a way 
that provides adequate transparency to the interested parties and also 
occurs on a timely basis?
     Should there be a coordination agreement in place prior to 
the participation of DER aggregation in RTO/ISO markets? Who should be 
parties to this coordination agreement? How would the coordination 
agreement be enforced?
     What is the best approach for involving retail regulatory 
authorities in the registration of DER aggregations in the RTO/ISO 
markets?
     What types of grid architecture could support the 
integration of DER aggregations into the RTO/ISO markets? Knowing that 
a variety of grid architectures are being explored in various regions, 
does it make sense for the Commission to consider specific 
architectural requirements for RTOs/ISOs for the effective integration 
and coordination of DER aggregations?
Panel 7: Ongoing Operational Coordination
    This panel will focus primarily on the operational considerations 
associated with both individual DERs and DER aggregations and with the 
interactions and communications between DERs, DER aggregators, 
distribution utilities, and transmission operators. In the NOPR, the 
Commission acknowledged that ongoing coordination between the RTO/ISO, 
a DER aggregator, and the relevant distribution utility or utilities 
may be necessary to ensure that the DER aggregator is dispatching 
individual resources in a DER aggregation consistent with the 
limitations of the distribution system.\10\ The Commission proposed 
that each RTO/ISO revise its tariff to establish a process for ongoing 
coordination, including operational coordination, among itself, the DER 
aggregator, and the distribution utility to maximize the availability 
of the DER aggregation consistent with the safe and reliable operation 
of the distribution system. To help effectuate this proposal, the 
Commission also proposed to require each RTO/ISO to revise its tariff 
to require the DER aggregator to report to the RTO/ISO any changes to 
its offered quantity and related distribution factors that result from 
distribution line faults or outages. The Commission also sought comment 
on the level of detail necessary in the RTO/ISO tariffs to establish a 
framework for ongoing coordination between the RTO/ISO, a DER 
aggregator, and the relevant distribution utility or utilities. To 
further explore these issues, Commission staff expects to explore the 
following questions:
---------------------------------------------------------------------------

    \10\ NOPR at P 155.
---------------------------------------------------------------------------

     What real-time data acquisition and communication 
technologies are currently in use to provide bulk power system 
operators with visibility into the distribution system? Are they 
adequate to convey the information necessary for

[[Page 7707]]

transmission and distribution operators to assess distribution system 
conditions in real time? Are new systems or approaches needed? Does DER 
aggregation require separate or additional capabilities and 
infrastructure for communication and control?
     What processes/protocols do distribution utilities, 
transmission operators, and DERs or DER aggregators use to coordinate 
with each other? Are these processes/protocols capable of providing 
needed real-time communications and coordination? What new processes, 
resources, and efforts will be required to achieve effective real-time 
coordination?
     What are the minimum set of specific RTO/ISO operational 
protocols, performance standards, and market rules that should be 
adopted now to ensure operational coordination for DER aggregation 
participating in the RTO/ISO markets? What additional protocols may be 
important for the future? Should the Commission adopt more prescriptive 
requirements with respect to coordination than those proposed in the 
NOPR? If so, what should the Commission require?
     Should distribution utilities be able to override RTO/ISO 
decisions regarding day-ahead and real-time dispatch of DER 
aggregations to resolve local distribution reliability issues? If so, 
should DER aggregations nonetheless be subject to non-deliverability 
penalties under such circumstances?
     Is it possible for DERs or DER aggregations participating 
in the RTO/ISO markets to also be used to improve distribution system 
operations and reliability? If so, please provide examples of how this 
could be accomplished.
     Can real-time dispatch of aggregated DERs address 
distribution constraints? If not, can tools be developed to accomplish 
this?
     Should individual DERs be required to have communications 
capabilities to comply with control center obligations? What level of 
communications security should be employed for these communications?
     How might recent and expected technical advancements be 
used to enhance the coordination of DER aggregations, for example, 
integrating Energy Management Systems (EMS) and Distribution Management 
Systems (DMS) for efficient operational coordination?

[FR Doc. 2018-03649 Filed 2-21-18; 8:45 am]
BILLING CODE 6717-01-P

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