Interconnection Issues with Distributed Energy Resources June 25, - - PowerPoint PPT Presentation

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Interconnection Issues with Distributed Energy Resources

Wisconsin Public Utility Institute June 25, 2019 Andrew Hanson, Senior Counsel

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Overview

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 Status of DER Deployment  Federal Policies and FERC Orders on DER Interconnection and Market Participation  DER Interconnection Issues in Wisconsin  Grid Modernization Case Law Update

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Distributed Energy Resources

• Traditionally referred to small, geographically

dispersed generation resources located on the distribution system (e.g., solar or combined heat and power).

• Now also includes energy storage, energy efficiency,

and demand response resources.

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Battery storage pictures aren’t that interesting…

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Source: https://www.greentechmedia.com/articles/read/distributed-energy-poised-for-explosive-growth-on-the-us-grid

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Annual Installed DER Power Capacity by DER Technology, United States 2015-2024

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Source: FERC, Distributed Energy Resources: Technical Considerations for the Bulk Power System, Staff Report, Docket No. AD18-10-000, February 2018, quoting Navigant, Take Control of Your Future, Part II: The Power of Customer Choice and Changing Demands, May 9, 2016, available at https://www.navigantresearch.com/blog/take-control-of-your-future-part-ii-the-power-of-customer-choice-and-changing-demands

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Source: U.S. Energy Information Administration, Release Date: February 2017 for December 2016 data, available at https://www.eia.gov/electricity/reports.php#/T194

U.S. DER Deployments

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Federal Policies and FERC Orders Affecting DER Deployment

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Energy Policy Act (EPAct) of 2005

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• Section 1223(a) of the Act defines ‘advanced transmission

technology’’ to mean a technology that increases the capacity, efficiency, or reliability of an existing or new transmission facility, including…

• (11) energy storage devices (including pumped hydro, compressed air,

superconducting magnetic energy, flywheels, and batteries;

• (13) distributed generation (including PV, fuel cells, and microturbines);
• (16) fiber optic technologies;…” [and]
• And (19) “any other technologies the Commission considers appropriate.”
• Section 1223(b) directs FERC to “encourage, as appropriate, the

deployment of advanced transmission technologies.”

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In re Western Grid Development LLC, Order on Petition for Declaratory Order, January 21, 2010 (Western Grid)

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Summary and Holding:

• Western Grid proposed NaS battery storage projects ranging in size from 10 to

50 MW, intended to provide voltage support and address thermal overload situations.

• FERC held that Western Grid’s battery storage projects would qualify as

wholesale transmission facilities; but FERC’s holding was limited to the facts presented by Western Grid.

• Commission further noted that energy storage devices “do not readily fit into
• nly one of the traditional asset functions of generation, transmission or
• distribution. Under some circumstances, they can resemble any of these

functions or even load.”

• Accordingly, the Commission would make determinations of whether energy

storage could be a transmission asset on a case-by-case basis.

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In re Western Grid (cont.)

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Factors considered by FERC:

• Western Grid proposed to operate the Projects under the direction of the

CAISO in a similar manner to the way in which high-voltage wholesale transmission facilities are operated by PTOs under the direction of the CAISO. Western Grid will operate the Projects, at the CAISO’s direction, only as transmission assets.

• Western Grid’s proposed operation of the projects share some important

characteristics with capacitors.

• Western Grid would be responsible for all operating functions, including

maintenance, communication, and system emergencies. Most importantly, Western Grid would be responsible for energizing the NaS batteries used in the Projects.

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In re Western Grid (cont.)

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Factors considered by FERC:

• CAISO would not be responsible for buying power to energize the batteries or

physically operating them when they are being charged and discharged.

• As with other transmission assets, and unlike traditional generation assets,

Western Grid would not retain revenues outside of the transmission access charge, and would credit any revenues it may accrue as a result of charging/discharging the Projects through its PTO tariff.

• Distinguished Nevada Hydro: In that case, CAISO would have controlled the

charge and discharge of that pumped hydro storage facility, and there was no mechanism with potential costs and revenues from market operations.

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FERC Order 792: Small Generator Interconnection Agreements and Procedures (Nov. 22, 2013)

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• Revisions to the proforma Small Generator Interconnection Procedures (SGIP)

and Small Generating Interconnection Agreement (SGIA), which establish the terms and conditions under which public utilities must provide interconnection service to Small Generating Facilities of no more than 20 MW.

• Revised the SGIP and SGIA to specifically include energy storage devices
• Spurred by significant increase in distributed resources
• Just 79 MW of grid-connected PV in 2006, with first SGIP and SGIA
• 3,300 MW of grid connected PV in 2012
• Approximately 8 GW expected to come online in 2019 alone, per EIA:

https://www.eia.gov/todayinenergy/detail.php?id=37952

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Policy Statement: Utilization of ESRs for Multiple Services When Receiving Cost-Based Rate Recovery (Jan. 19, 2017)

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• Purpose was to provide guidance on the ability of electric storage

resources to provide services at and seek to recover costs through both cost-based and market-based rates concurrently.

• Western Grid should not be read to require entities to forgo market

sales in order to receive cost-based rate recovery.

• Three main issues addressed by the Policy Statement:
• Potential for combined cost-based and market based rate recovery to

result in double recovery of costs by ESR;

• Potential for cost-based rates to suppress competitive prices;
• Level of control in the operation of the ESR could jeopardize RTO/ISO

independence.

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Policy Statement: Utilization of ESRs for Multiple Services When Receiving Cost-Based Rate Recovery (Jan. 19, 2017)

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Double recovery:

• Address through market revenue crediting back to customers or using market revenues to

reduce the revenue requirement.

No risk of adverse impacts to wholesale electric markets:

• “If we were to deny electric storage resources the possibility of earning cost-based and

market-based revenues on the theory that having dual revenue streams undermines competition, we would need to revisit years of precedent allowing such concurrent cost- based and market-based sales to occur as described above.”

RTO/ISO Independence:

• “[T]he provision of market-based rate services should be under the control of the electric

storage resource owner or operator, rather than the RTO/ISO, to ensure RTO/ISO independence.”

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FERC Order 841: Electric Storage Participation in Markets Operated by Regional Transmission Organizations and Independent System Operators (Feb. 15, 2018)

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• Remove barriers to the participation of electric storage

resources in the capacity, energy, and ancillary service markets operated by Regional Transmission Organizations and Independent System Operators (RTO/ISO markets), with a view to expand the existing market for storage resources.

• Enhance competition and help ensure that RTO/ISO markets

provide just and reasonable rates.

• Support the resilience of the bulk power system.

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FERC Order 841

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Significance:

• Creates a clear legal framework for storage resources to operate in all

electric markets and provides clarity around market access;

• Establishes a participation model that recognizes the physical and
• perational characteristics of storage resources;
• Expands the universe of solutions that can compete to meet electric

system needs;

• Represents necessary steps on the path to a more flexible electricity

system.

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FERC Order 841

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Defines “electric storage resource” or ESR as:

• A resource capable of receiving electric energy from the grid and

storing it for later injection of electric energy back to the grid.

• Does not differentiate location on grid (e.g. transmission, distribution,
• r behind-the-meter).
• Storage resources currently participating in demand-response

programs can continue doing so under the new rule.

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FERC Order 841

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Reach of FERC’s jurisdiction over ESRs:

• FERC Order 841 “applies to [ESRs] that are capable of receiving

electric energy from the grid and storing it later for injection of electric energy back to the grid, irrespective of where the resource is

• interconnected. The sale of charging energy to an [ESR] that the

resource then resells into the RTO/ISO markets is a sale for resale in interstate commerce and thus subject to the Commission’s jurisdiction.” (FERC Order 841 ¶ 295) (emphasis added)

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FERC Order 841

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Participation Model:

• By end of 2018, RTO/ISOs were required to propose updates to their

tariff and pricing schemes to establish a participation model consisting of market rules that facilitate electric storage resource participation in the RTO/ISO markets.

• RTO/ISOs must ensure that an ESR using the participation model is

eligible to provide all capacity, energy, and ancillary services that the resource is technically capable of providing in the RTO/ISO markets.

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FERC Order 841

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Minimum Size Requirement:

• Each RTO/ISO must establish a minimum size requirement for

participation in the RTO/ISO markets that does not exceed 100 kW.

• Significantly expands number of storage resources eligible to

participate in markets.

• Potential software issues raised by MISO given the large number of

ESRs that may soon be participating.

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FERC Order 841

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Physical and operational characteristics of ESRs:

• Requirement to reflect and account for the physical and operational

characteristics of ESRs through bidding parameters or other means.

• RTO/ISOs have flexibility on determining whether this information will

be required of ESRs or whether it may be submitted at the ESR’s discretion.

• However, RTO/ISOs must allow the ESR to submit State of Charge in

both day ahead and real time markets, which will provide more accurate information and avoid assumptions by the RTO/ISO regarding state of State of Charge.

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FERC Order 841

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FERC Order 841

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Participation as Both Supply and Demand:

• Each RTO/ISO must ensure ESR can set the whole market clearing price as

both a wholesale seller and wholesale buyer.

• ESRs must be able to set the price in capacity markets;
• RTO/ISOs must accept wholesale bids from ESRs to buy energy;
• ESRs must be allowed to participate as price takers, consistent with rules for self-

scheduled resources.

• ESRs must be dispatchable by the RTO/ISO.
• Framework recognizes the “full bidirectional value of [ESRs], their fast

response times, and limited energy and allows for greater grid efficiency, greater competition, and downward pressure on wholesale prices and system costs.

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FERC Order 841

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Make-Whole Payments:

• Because ESRs can serve both supply and demand, and because ESRs must

be dispatchable and able to set the wholesale market clearing price as a buyer and a seller, RTO/ISOs must allow make-whole payments when:

• the ESR is dispatched as load and the wholesale price is higher than the ESR’s bid

price; or

• the ESR is dispatched as supply and the wholesale price is lower than the ESR’s
• ffer price.
• Goal is to hold the ESR harmless, as with any other dispatchable resource.
• “[ESRs] participating in the RTO/ISO markets are subject to the same system

conditions as other resources that may cause them to be dispatched out-of- market and unable to recover their operating costs.”

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FERC Order 841

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Price of Energy for Charging an ESR:

• The sale of electric energy from the RTO/ISO markets to an ESR that

the resource then resells back to those markets must be at the wholesale LMP.

• FERC found that the sale of energy from the grid used to charge an

ESR for later resale into the energy or ancillary service markets constitutes sale for resale in interstate commerce.

• As such, the just and reasonable rate for that wholesale sale of

energy used to charge the ESR is the wholesale LMP.

• FERC clarified that the sale is at the nodal LMP, not the zonal LMP.

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FERC Order 841

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State of Charge Management:

• ESRs must be able to manage the state of charge of their resources

to ensure that each ESR can manage its operations to provide all of the wholesale services that they are technically capable of providing, similar to the operational flexibility provided to traditional generation resources to manage the wholesale services they offer.

• While RTOs/ISOs may be in a better position to manage an ESR’s

state of charge (e.g. an ESR that exclusively provides frequency regulation), some ESRs may be able to provide multiple services to another entity or services outside of the RTO/ISO.

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FERC Order 841

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Transmission Charges:

• Transmission charges when acting as load:
• “When an ESR is charging to resell energy at a later time, then its

behavior is similar to other [LSEs], and we find that applicable transmission charges should apply.”

• No transmission charges when providing market services:
• ESRs dispatched to consume electricity to provide a service (e.g.,

frequency regulation or a downward ramping service) are not required to pay the same transmission charges as load during the provision of that service.

• Assessing transmission charges when the ESR is dispatched to provide a

service would create a disincentive to provide that service.

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FERC Order 841

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Ability to De-rate:

• Each RTO/ISO required to revise its tariff to allow ESRs to de-rate

their capacity to meet minimum run-time requirements.

• Example: a 10MW/20MWh ESR can offer 5 MW of capacity into a

capacity market with a 4-hour minimum run-time because that is the maximum output that the resource can sustain for the duration of the minimum run time.

• Absent the opportunity to de-rate, the 10 MW/20MWh ESR would not

be able to participate in that capacity market, despite its ability to reliably provide 5 MW of capacity for the duration of the minimum run- time.

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MISO Compliance with FERC Order 841

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• MISO and other RTOs/ISOs submitted compliance filings on Dec. 3,

2018

• FERC followed up with letters seeking additional information on April

1, 2019

• Asked MISO to clarify certain aspects of its filing, including to ensure that

distribution-connected ESRs will not be charged twice for the same charging energy (both retail and wholesale).

• MISO provided additional information on May 1, 2019
• Requested an extension to February 2021 for full implementation due to

complexity in managing and scheduling software changes, among other work.

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FERC Order 845: Reform of Generator Interconnection Procedures and Agreements (April 19, 2018)

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• Revises proforma Large Generator Interconnection Procedures

(LGIP) and proforma Lage Generator Interconnection Agreement (LGIA);

• Specifically defines “Generating Facility” in LGIP and LGIA to include

ESRs;

• Commission found no need for an additional GIP or GIA unique to ESRs;
• Allows interconnection customers to request a level of

interconnection that is lower than the full nameplate of their generating facility, which promotes controllable resources like ESRs;

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FERC Order 845

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• Requires transmission providers to create a process, separate

from the interconnection queue, for the use of surplus interconnection service;

• Reduce costs for interconnection customers by increasing the use of existing

interconnection facilities and network upgrades rather than requiring new ones;

• Improve wholesale market competition by enabling more entities to compete through

the more efficient use of surplus existing interconnection capacity, and

• Remove economic barriers to the development of complementary technologies such

as ESRs that may be able to easily tailor their use of interconnection service to adhere to the limitations of the surplus interconnection service that may exist.

• No specific modeling requirements for ESRs.

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DER Interconnection Issues in Wisconsin

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DER Interconnection Issues in Wisconsin

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Status of Battery Storage Projects in Wisconsin

• Battery storage projects in the MISO queue located in

Wisconsin: 10

• Total Capacity in the queue: 421.5 MW
• Study Cycle:
• DPP-2018-APR: 3 projects totaling 170 MW
• DPP-2019-Cycle-1: 7 projects totaling 251.5 MW

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DER Interconnection Issues in Wisconsin

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• Wis. Stat. § 196.496(1), Distributed Generation Facilities:
• Defines DG facility as a “facility for the generation of electricity with a

capacity of no more than 15 MW that is located near the point where the electricity will be used or is in a location that will support the functioning of the electric power distribution grid.”

• Directs the Commission to promulgate rules establishing

standards for the connection of distributed generation facilities to electric distribution facilities.

• To the extent technically feasible and cost-effective, the standards

shall be uniform and shall promote the development of distributed generation facilities.

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DER Interconnection Issues in Wisconsin

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• Wis. Admin. Code PSC Chapter 119:
• Implements Wis. Stat. § 196.496;
• Applies to all DG facilities with a capacity of 15 MW or less that

are interconnected or who seek to interconnect to a public utility’s distribution system;

• It applies to all electric utilities to whose distribution system a DG

facility is interconnected or to which interconnection is sought;

• Establishes uniform, statewide standards for interconnection.

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DER Interconnection Issues in Wisconsin

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• Wis. Admin. Code PSC Chapter 119:
• Defines the application process, application form, and

interconnection agreement;

• Sets timelines for engineering review and, as necessary, distribution

system studies by public utility and payment for any necessary system upgrades by applicant;

• Provides for the requirements for grounding, metering, use of

certified or non-certified equipment, safety equipment, power quality and testing, and compliance with applicable national, state, and local codes.

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DER Interconnection Issues in Wisconsin

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Wisconsin Distributed Interconnection Guidelines:

• Intended for retail electric customers, independent power producers

(IPPs), independently owned generators or any other parties interested in operating a DG facility;

• Provides a detailed description of the application process, equipment

and minimum protection requirements;

• Guidelines largely track PSC 119;
• Neither the guidelines nor the rules directly address interconnection
• f ESRs, as defined in FERC Order 841.

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DERs: Transmission vs. Distribution Issues

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Visibility/Metering:

• ESRs that participate directly in the RTO/ISO markets provide greater visibility to system operators

because they are modeled and dispatched as part of the market’s economic clearing mechanism.

• ESRs that participate solely in retail compensation programs are not always subject to modeling, dispatch

and metering and not necessarily reported to RTO/ISOs, which in turn limits RTO/ISO operational awareness of those ESRs.

• FERC Order 841:
• Requiring meters on all ESR units will ensure compliance with the wholesale LMP requirement for

ESRs and will increase visibility and RTO/ISO situational awareness, but imposes a cost on ESR

• perators.
• FERC recognizes that some distribution connected or BTM ESRs may be subject to other metering

requirements that can be used in lieu of direct metering by RTO/ISO.

• E.g., Wisconsin Interconnection Procedures provide that utility can require telemetry equipment for

facilities above 200 kW. (PSC 119.20(14))

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DERs: Transmission vs. Distribution Issues

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Coordination:

• Need for coordination between small generators and the bulk power

system to prevent system load imbalances during periods of ESR disconnection.

• FERC Order 828: Requirements for Frequency and Voltage Ride

Through Capability of Small Generating Facilities (July 21, 2016):

• Requires small generators subject to a SGIA to meet the same

requirements as large generators to ride through abnormal frequency and voltage events (i.e. not disconnect during voltage events).

• Only applies to facilities subject to an SGIA, but FERC indicated its hope

that its order would be helpful to states when updating their rules for interconnection to the distribution system.

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DERs: Transmission vs. Distribution Issues

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Distribution-connected ESRs in wholesale markets:

• What to do about ESRs that use the distribution system but pay the

wholesale LMP for energy to charge the ESR?

• FERC noted that it may be appropriate on a case by case basis for distribution

utilities to assess a wholesale distribution charge on ESRs.

• Stakeholder concerns about ability to arbitrage wholesale and retail rates.
• MISO Transmission Owners cautioned that state laws may affect an ESR’s

status as a seller or buyer, arguing that states and distribution utilities should retain authority to manage this aspect of ESRs.

• In addition, technology concerns associated with enforcing a requirement on

BTM ESRs to buy electricity at wholesale.

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DERs: Transmission vs. Distribution Issues

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Should BTM ESRs pay the LMP for charging energy? Or should they pay the retail rate applicable to them under state law?

• There no requirement that an ESR purchase all energy for charging from the

wholesale market; but if it does and will resell back to the market, it must be at the wholesale LMP.

• FERC stated that while each RTO/ISO is required “to allow [ESRs] to be able

to pay the LMP for their charging energy, it does not address whether they can pay some other rate, such as the retail rate or charging off of co-located generation.”

• In addition, ESRs (like any other market participant) that pay the wholesale

LMP can enter into bilateral transactions to hedge the purchase of that energy.

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Grid Modernization Update

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Recent Decisions on Grid Modernization

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• In re Petition of Virginia Electric and Power Company

(VEPCO), Case No. PUR-2018-00100 (Jan. 17, 2019)

• In re DTE Electric Company, MPSC Case No. U-20162 (May

2, 2019)

• In re Application of Ohio Edison Company, Slip. Op. No.

2019-Ohio-2401 (June 19, 2019)

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Questions?

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Andrew Hanson | Perkins Coie LLP

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