Energy storage can be the “Swiss-army knife” of the electricity grid. Reports for more than a decade have demonstrated the value storage can provide. But now that states have moved from piloting energy storage to adopting it at scale, there is a need to rethink standard electricity processes to integrate energy storage onto the distribution grid. Energy storage is a unique resource - it acts as both load and generation; can participate as a retail and wholesale resource; and it is subject to both state and federal jurisdiction. As something new, it needs new processes and procedures to be integrated cost effectively — while aiding reliability, not hurting it. This paper focuses primarily on solutions for integrating BESS owned by third parties, as it is among the harder solutions to implement.
Whether battery energy storage systems (BESS) provide a grid benefit or a system liability depends upon perspective and regulatory policies. The technology is proven, but regulatory policy is still catching up and trying to ensure the technology is implemented in a manner that benefits all ratepayers.
Energy policy makers often view BESS as a “Swiss-army knife” capable of delivering many services to the distribution grid including enabling rapid load growth; providing backup power for residents; and facilitating renewable energy integration onto the grid. In contrast, EDCs, who own and operate the distribution system, are responsible for the safety of their line workers, and required to meet state-specific reliability metrics. From their perspective, BESS is seen as an unpredictable liability on the grid. It can be either load or generation, which means it doesn’t fit well into traditional distribution system modeling and planning processes, leading to scenarios where BESS can compete with load growth. BESS may not be under their direct operational control if it is owned by a third party, which puts the EDC in a difficult position as it may have no assurance or resource if the BESS does not perform as planned. A BESS developer sees the potential to use BESS to provide multiple, monetizable services to the distribution grid, and potentially the wholesale market as well. BESSs are expensive assets that require multiple revenue streams to make them financially viable. A BESS developer wants to maximize all available revenue streams and looks to stack wholesale market capacity, energy, and ancillary services revenue and/or state compensation structures. This means they want as much flexibility as possible and the option to change from providing retail to wholesale services at a moment’s notice.
State electricity regulators are tasked with balancing these three perspectives by implementing policy in a manner that achieves legislative goals, improves system reliability, enables BESS developers to achieve commercial viability, and maintains affordable electricity prices for ratepayers.
This white paper focuses on the integration of third-party-owned BESS with the distribution grid, as it is the most challenging use case. However, EDC-owned, and rate-based BESS are certainly an option for regulators to consider. The latter scenario works best in states where EDCs are allowed to own generation, as BESS are cost effective when they can provide energy and capacity. Using a BESS as a distribution-only asset often leads to limited utilization and uneconomic applications.
CHALLENGE
For BESS to deliver value to ratepayers it must reduce peak load - either by operating behind-the-meter and directly reducing load, or in-front of the meter at a highly loaded substation. While the focus of this paper is on the distribution system, BESS can similarly be located “behind” (on the load side) a transmission constraint. However, if the commission approved, EDC planning processes require the EDC to add capacity to the distribution system to integrate BESS onto the grid, ratepayers will suffer instead of seeing a benefit.
A BESS located behind-the-meter can either reduce load on demand or based on a predictable schedule. For example, a BTM battery can be discharged to provide power when an industrial process starts, minimizing power that must be drawn from the grid. Or an aggregation of residential batteries can be predictably discharged during peak time-of-use hours on the distribution grid. Alternatively, a distribution-connected front-of-meter BESS can discharge during peak load hours at the substation, thereby reducing the peak. Finally, BESS can be located within transmission constrained zones reducing the need for transmission imports to the region.
However, in most states, current EDC distribution planning practices do not allow BESS to be built into planning scenarios and included as a resource that can reduce peak load. There are two core challenges that must be resolved:
1) The ability, or lack thereof, of the EDC to rely upon a third-party owned asset to meet peak load obligations, and therefore be included in distribution planning.
2) Process to incorporate hourly assumptions regarding load and BESS operational characteristics (e.g. charge or discharge), and the availability of historical and projected hourly data to design BESS solutions.
EDCs typically require assets to be under direct EDC control for those assets to be considered a reliable solution in the distribution planning process. If the BESS is to be owned and operated by a third party, the EDC planning process may ignore any value the BESS can provide and assume the BESS may charge during peak load hours, thereby increasing the load at the substation and accelerating the need for an upgrade.
Unlike other distributed energy resources (e.g. solar), the operational characteristics of BESS introduce time-dependent load and generation variability that is not adequately represented in the assumptions made in the traditional interconnection study process (e.g. assumptions regarding when the BESS will charge vs discharge, charging rates, time the resource flips between charge and discharge, etc.). Layered on top of the inherently complex process of long-range load growth and retirement at a substation, this hourly variability, and lack of hourly data, leads the EDC to make highly conservative solutions during the planning process.
From a BESS developer perspective, the result of the conservative assumptions embedded in the EDC distribution planning process is that the project is charged a heavy interconnection cost for upgrades that do not align with its intended operation, or overly restrictive limitations placed on charging and discharging that do not allow the BESS to successfully monetize all revenue streams available to it. This often becomes the critical hurdle in the development process where the interconnection queue is likely to experience heavy attrition.
EMERGING SOLUTIONS
Commissions must work with their EDCs to change distribution planning processes to require and allow BESS to be included in the long-term plan. To be included in the plan, EDCs will also need to have some assurance when BESS will charge and discharge. The spectrum of what the EDC may be willing to consider as performance assurance can be quite broad - ranging from contractual assurance on the light side, all the way to the ability of the EDC to remotely monitor and disconnect the BESS, with many solutions in between.
Include BESS peak load reduction in EDC Distribution Planning Process:
For BESS to achieve policy objectives, EDCs need a methodology to include BESS contribution to the expected peak load at a substation during the load forecasting and distribution planning process.
Typically, on an annual basis, EDCs will go through their distribution planning process to determine necessary upgrades required to serve forecasted load growth. In that process, EDCs can make one of three assumptions regarding the impact of BESS connected at the substation - either the BESS reduces the expected peak load (i.e. the BESS will be discharging during peak hours), has no impact on peak load, or increases the expected peak load (charging during peak hours). As discussed below, operational envelopes and profiles are a necessary step to allow the EDC to model BESS charge/discharge during the planning process.
Additionally, EDCs may be concerned about relying upon BESS owned/operated by third parties and be reluctant to assume 100% of BESS connected to the substation will reduce load. Certainly, outages will occur, and it is a reasonable assumption to derate the total BESS nameplate capacity that will be available during peak hours. State commissions may want to require their EDCs to develop a methodology for derating the expected BESS reduction of peak load.
Many EDCs already have a methodology for derating the expected distribution generation connected at a substation in the distribution planning process. For example, to account for solar connected to the distribution system, the existing planning process may allow the EDC to reduce the forecasted peak load by 25% of the total solar nameplate. A similar process can and should be developed for BESS to determine the percent of total BESS nameplate that can be used to reduce expected peak load during the planning process.
State commissions may also need to explore updating the standard Interconnection Service Agreement signed by the EDC and developer to ensure that risk is appropriately shared between the EDC and third-party BESS developer for performance. For example, there may be exclusions that preclude third party owners from performing maintenance during anticipated peak load times, or penalties for not meeting expected performance levels.
Require predefined operational envelopes and operating profiles:
For EDCs that lack DERMS and the ability to remotely communicate with third party BESS, the primary solution to ensure predictable charge/discharge behavior are pre-determined operational envelopes that are fixed for the duration of the Interconnection Services Agreement. Operational envelopes are essentially a capacity allocation for both charge and discharge that varies seasonally and by time of day.
To be useful, operational envelopes should be as granular as possible. Ideally, they should include at least three components - a ceiling on the amount of capacity that can be withdrawn or injected onto the grid, windows of time during the day (e.g. 4 PM - 8 PM, 8 PM to 12 AM, etc.), and time of year. The seasonality and time windows remain fixed during the interconnection study process and the EDC determines the capacity allocation that is available and can be assigned to the BESS.
A further improvement is distinguishing between constrained zones and non in designing the operational envelopes. For example, urban areas are often characterized by density and high loads, creating constrained pockets on the distribution grid. An EDC that serves an entire state, or a portion thereof, will likely serve a handful of urban, constrained zones while the rest of its footprint is less constrained. It is excessively conservative to design the operating envelope (seasons and time windows) for the entire EDC footprint based on a substation in a constrained zone. If two categories (constrained and non-constrained) were considered in developing operating envelopes this will likely lead to greater granularity and improved performance in these predetermined operational envelopes.
Operational envelopes allow the BESS operator to retain flexibility to optimize within these constraints, for example adding on regulation services, responding to real-time price signals, or preparing for emergency conditions to the planned daily charge/discharge schedule. An operational envelope essentially provides for off-peak charging when substation capacity exists, without penalizing the BESS projects for providing ancillary services that don’t materially impact distribution loading.
Although this approach provides the EDCs a guarantee that a BESS will limit charging and discharging to hours that do not contribute to further load growth and therefore grid upgrades, it does not guarantee that the BESS will charge or discharge to reduce the existing loads on the grid. For such a guarantee, in addition to operating envelopes the EDC and BESS project can agree on an operating profile, which guarantees peak coincidence commitments (e.g., discharges during system peak hours of 4 - 8 PM between June and September with 95% availability) and state-of-charge management protocols. Under a predetermined and fixed operating profile concept, the EDC mandates that the BESS shall discharge at a fixed capacity during either local or regional peak hours. This provides the EDCs operational certainty to model net distribution system impacts and allocate costs based on avoided capacity during coincident peak periods. In such a scenario the BESS accepts reduced operational flexibility but collects credits for guaranteed peak-period availability.
Finally, both pre-determined operating envelopes and operating profiles should be implemented autonomously, to ensure BESS comply with the requirements and provide EDCs with performance certainty, without the additional cost of EDC-specific SCADA, while the utility gains sufficient operational certainty to model net distribution system impacts and allocate costs based on avoided capacity during coincident peak periods. This approach credits BESS for guaranteed peak-period availability while imposing minimal incremental costs.
Update or modify flexible interconnection process to accommodate BESS:
Operating envelopes and profiles are similar to flexible interconnection studies which have been implemented in some states for solar or other DER. Flexible interconnections allow interconnection capacity to vary by hour of the day as long as data is shared with the EDC and capacity output is maintained below a cap. Flexible interconnections have allowed more distribution connected resources interconnect than a fixed interconnection, which often results in expensive distribution network upgrades.6 Flexible interconnections have historically focused on managing the output of a distributed energy resource such as solar and ensuring power quality is not impacted during high generation / low load hours, for example. However, for BESS, often the limiting use case is BESS charging, not discharge.
In some scenarios, with flexible interconnections, EDCs may control BESS operations until distribution upgrades are in place. The risk with flexible interconnections for developers is the additional costs imposed by EDCs stemming from added requirements such as a utility-side DER Gateway communicating with the customer’s power plant controller to regulate BESS power quality.
Flexible interconnections are not seasonal but capacity-constrained based on real-time distribution system loading. To avoid prolonged study processes, EDCs use standardized hosting capacity analysis7 and pre-defined curtailment protocols rather than project-specific studies. California, Hawaii and New York have implemented variations of this framework through Rule 21, Rule 14 (and Senate Bill S6570A) modifications, hosting capacity maps8, and ‘connect-and-manage’ procedures that allow rapid interconnection with operational restrictions until distribution upgrades are completed. The tradeoff for developers is speed versus certainty: interconnection occurs within months rather than years, but developers accept curtailment risk during constrained periods.
CHALLENGE:
A BESS connecting to the distribution grid needs to know what it will cost to charge from the grid and how it can be compensated for its services - regardless of whether it takes retail or wholesale service. To do so, a few tariffs or rates need to be in place first. It is important to know that distribution-connected BESS can participate in the ISO/RTO wholesale markets as established by FERC Orders 8419 in 2018 and 222210 in 2020. If the BESS is going to be a wholesale market participant, then a complicated set of tariffs, contracts and participation models need to be in place to allow that to happen. If the BESS is going to request service as a retail asset, then an EDC specific rate also needs to be in place to compensate the BESS for the services it provides.
For BESS accessing wholesale markets, the challenges have been clearly defined and solved, even if it requires a dizzying array of steps and documents that need to be in place. Typically, the BESS starts by going through the EDC interconnection study process and queue, not the ISO/RTO, and will indicate its plan to participate in wholesale markets in that step.11 Depending upon the BESS size, and the ISO, the BESS may also need to apply to the ISO interconnection queue.12 For the BESS to be able to charge from the distribution grid in this scenario, the EDC must have a Wholesale Distribution Access Tariff (WDAT) approved by FERC. The FERC Orders recognize the right of an EDC to access a “wholesale distribution charge” to recover costs associated with transmitting electricity across their distribution system to enable wholesale market participation for those resources, which in the context of BESS is the primary intent of these tariffs. In addition to the WDAT, the ISO/RTO must have a wholesale participation model for BESS defined in their Open Access Transmission Tariff (OATT), or equivalent, as well as means for a distribution asset to contract with ISO/RTO.13 Just as EDCs have WDATs, the ISO/RTO will have a pro-forma agreement included in their tariff allowing distribution-connected assets to participate in wholesale markets. Once all of these documents have been put in place and executed, the BESS participates in the wholesale market like any other resource and receives compensation for services provided when it clears the market.
WDATs are not a replacement for retail tariffs. Retail tariffs enable distribution utilities to recover the costs of assets that perform electric distribution functions, but they do not provide a mechanism for distribution utilities to recover the costs of delivering wholesale market access for distribution connected assets.
For BESS providing services only to the EDC or distribution grid, the rate that governs charging and compensation is less clearly defined. Compensation can take on many different forms including EDC entering into a contract with BESS as the result of an RFPs driven by state mandates; state incentive programs; or compensation built into the rate structure. Additionally, tariffs should address the issue of future tariff changes. The ideal solution for BESS developers is to grandfather an existing, interconnected BESS under the tariff that was in place when the BESS was placed in service.
While detailed discussion of rate design is beyond the scope of this paper, when it comes to BESS rate design there are some unique considerations for state commissions to consider. Currently, BESS projects typically undergo the Distributed Energy Resource (DER) interconnection process at the state level, where cost responsibilities are mostly assigned based on the principle of cost causation—that is, the project bears the costs directly attributable to infrastructure upgrades triggered load growth attributable to the project. A charging rate is a combination of distribution delivery charges (covering both load growth and distribution grid asset condition), transmission rate and any other statutorily prescribed rates that support state programs like Low Income Home Energy Assistance Program (LIHEAP), and energy efficiency and renewable energy program funds. It is important to structure a charging rate that takes into consideration the effects of interconnection upgrade costs already incurred by the project and that “double cost recovery” is not occurring. The methods and principles of rate design should not infringe on the viability of projects. As BESS adoption scales, a state’s regulatory authority must carefully balance cost-recovery mechanisms with the need to encourage efficient, equitable, and policy-aligned deployment of storage resources.In contrast, a BESS located behind the meter may not need BESS-specific rates. A BTM BESS will be used to modify the load and can provide value by reducing peak load and demand charges. The BESS can be designed to discharge during peak hours, reducing retail demand charges. However, a front of meter BESS will require a tariff designed specifically for batteries.
EMERGING SOLUTIONS
Wholesale service and compensation structures:
EDCs in several states have established wholesale charging rates, in the form of a WDAT. EDCs considering a WDAT should be aware of precedence established in a FERC docket for Southern California Edison.
With regards to compensation, all ISOs/RTOs have already established wholesale market participation models for BESS connected to the grid (transmission or distribution) and are in the midst of implementing Order 2222 (except for CAISO, which finished implementation in 2024). For example, ISO New England developed a variety of participation models to comply with Order 841. Distribution connected BESS can provide energy injection, energy withdrawal, regulation and demand reduction through a participation model called the continuous storage facility (CSF). It combines the attributes of the traditional model generator, Dispatchable asset related demand (DARD) and Alternative Technology regulation resources(ATTR). For DER aggregation, ISO-NE has established two participation models, i.e. Settlement only DER aggregation (SODERA) and Demand Response DER aggregation (DRDERA).
Some ISO/RTOs allow distribution-connected resources to participate in wholesale markets via a three-party agreement between the ISO, BESS operator, and EDC. For example, MISO uses an agreement called Electric Storage Resource Agreement - Attachment HHH of their OATT.17 PJM has a Wholesale Market Participation Agreement (WMPA).18 The WMPA process allows PJM to study a DER request for transmission system impacts like the MISO DER Affected Systems Study.19
Retail service and compensation structures:
For retail service, states have adopted a variety of approaches. Virginia and Maryland are encouraging their EDCs to contract with BESS via a RFP-based procurements. In Massachusetts, MassCEC released their Grid Services study20 in Sept 2025 which recommended implementing a location specific compensation in areas of congestion. Similarly in Maine, the Governor’s Energy Office produced a report21 under the directive of the legislation in December 2024 that assesses Storage Procurement Mechanisms and Cost Effectiveness. These reports assess the compensation structures and value for BESS pursuing a retail service.
The ConnectedSolutions program as implemented in MA and CT provide demand response compensation to participating Behind the Meter BESS.(See case study). When charging from the grid is enabled for third party owned BESS assets, it is important to establish a retail charging rate, or other tolling agreement. Rhode Island is in the midst of developing a bi-directional tariff for Front of the Meter BESS retail service.
CHALLENGE
As the “Swiss-army knife” on the grid, policy makers want to ensure BESS compliments and enables new load being added to the grid and doesn’t compete with it.
From the EDC perspective, it is well known that the EDC planning process, regulatory approval cycle, and the timeline required to build and connect new, or upgraded utility-owned infrastructure is slow, while the projected load at a substation can change quickly. However, the EDC wants to accommodate hard to predict spot loads connecting to the grid - such as a new shopping complex, crypto mining operation, apartment building, or EV charging station. If a BESS isn’t treated as a load-reduction resource, due to changes in EDC planning processes and by implementing operating envelopes, there is the potential for a large BESS placed at the same substation to be viewed as competition for capacity on the system. Some states are facing this “load versus BESS” competition because they haven’t implemented the solutions discussed in previous sections.
Additionally, it is an open secret that EDCs are financially motivated to build EDC assets and include them in their rate-base, in lieu of leveraging 3rd party owned assets. Discussing the challenges associated with utility compensation tied to rate base is beyond the scope of this paper, but it is a contributing factor. Finally, EDCs are responsible for reliability. It may be difficult for the EDC to share some responsibility for reliability, particularly if the EDC doesn’t have any recourse to pursue third parties that have the potential to negatively impact their performance. Taking these two factors into consideration, it places examples of EDCs creating artificial limits for BESS in context. There are examples of EDCs creating artificial limits for BESS, below the real thermal limits at the substation, in order to reserve capacity for potential load growth. There are also instances where the EDC allows load additions to effectively “jump ahead” of ESS projects under study in the queue and consume remaining feeder or substation capacity. Ultimately, ratepayers lose if EDCs perpetuate this “load versus BESS” conflict.
EMERGING SOLUTIONS
Colocation of load and BESS:
One possible solution to address the - “load versus BESS” competition is co-locating BESS at substations with new spot load additions. In this way, the PUC does not have to decide between economic development associated with load growth and meeting policy goals through BESS-related charge load growth. The EDC benefits by designing a single optimized distribution upgrade that serves both BESS and load, rather than separate plans for each. Co-location allows the EDC to conduct a single interconnection study with consistent assumptions, including the pre-determined operational envelope, and/or predictable operational dispatch, leading to a unified cost-allocation framework. Developers also benefit because BESS is studied alongside load, rather than being sequenced behind it.
This solution can be hard to implement in practice. Developers look to site projects based on available land located close to highly loaded substations, and often are not even aware of plans for load growth at the substation. Similarly, spot loads are focused on getting through the study process as quickly as possible and are not considering BESS as a solution to enable their goals.
However, there is the possibility of state commissions and EDCs learning from changes in regulations being discussed among FERC, the ISO/RTO, and Transmission Owners (TOs) to accommodate data centers. A recent FERC order,24 and DOE letter,25 is encouraging ISO/RTOs to develop solutions that allow load to connect more quickly, by proposing tariff changes that allows load to “bring their own generation” among other solutions. If interconnection study rules encouraged spot loads to work with technologies that can reduce peak, such as BESS, both BESS developers and load would be incited to work together.
CHALLENGE
Although it is rapidly changing, many distribution grids lack the ability to provide real-time, two-way information from the grid edge to EDC control rooms. While most distribution grids can absorb a low level of interconnected distributed energy resources, higher levels of penetration require some level of communication and control of DER, even if it is just autonomous control. If flexible interconnection, and EDC control will be used, two-way information flow is critical. Utilities across the US are rapidly deploying SCADA at their substations, feeders, and other critical points on the grid, and rolling out DERMS for all rate payers.
However, any commercially available DER, or BESS in this case, will automatically come with an inverter that is capable of autonomous control settings (such as voltage control), as well as the ability to send and receive information and commands from an EDC control room using secure encryption. From the perspective of perfect policy, it would be ideal if the EDCs used the intelligence built into every commercially available BESS controller and inverter to communicate information about the distribution system to the EDC. Any BESS connected to the distribution system has real-time information about voltage, frequency, power outages, and other data critical to the EDC. It would be more cost effective for ratepayers for BESS to share that information with EDC control rooms, in lieu of distribution utilities requiring new, bespoke, and redundant SCADA on BESS.
EDCs operate secure control rooms, are required to be concerned about security, customer data privacy, and ensure grid-edge resources will integrate with the control systems. The idea of collecting data from thousands of assets, possibly in different formats, with little ability to verify the accuracy of the data and try to use that information to make decisions seems impossible for EDCs to even consider. As a result, EDCs are working on deploying Distributed Energy Resource Management Systems (DERMS) and putting company-owned assets across the distribution grid, regardless of the cost to ratepayers.
BESS developers want the lowest cost solution. If sharing information with the utility enables a lower cost and doesn’t come at too great of a cost to provide the data, they will. Developers just want to avoid bespoke solutions for each utility and seek common solutions and the use of templates and software standards. Nothing is worse than having to reinvent the wheel for the 100th time, just because each utility wants things slightly different in their footprint.
EMERGING SOLUTIONS
While it is tempting for the EDC to require resources that will connect to the distribution grid to install EDC-specific SCADA, this approach comes at a cost, and ignores existing solutions available today.
California is the largest market in the U.S. for grid-connected BESS. As such, California has been the leader in defining communication and performance requirements that are now built into every commercially available BESS. Often domestic, and international, standards start with California rules, which are then expanded upon when they get adopted by IEEE, UL, or other standards bodies. For example, California Rule 21 was one of the base documents that resulted in the 2018 update to IEEE 1547. Similarly, California has been leading the way in developing standards that ensure inverters can communicate securely with EDC control rooms and use standard protocols that allow EDCs to remotely control BESS.
Nearly all BESS sold in California, and as such the rest of the U.S., are built to comply with IEEE-1547 2018, UL 1741 SB,26 IEEE-2030.5, and the SunSpec Common Smart Inverter Profile (CSIP).27 These are powerful standards that ensure all the EDC needs for communication, control, and cybersecurity are already built into today’s inverters and independent power control systems. Companies that build inverters don’t build customized inverters, BESS controllers, or even power control systems for one specific market. They upgrade their hardware and software to comply with new standards once, and sell that new product into all markets, whether that market calls for the capability or not. BESS built in Texas, Massachusetts, Virginia or Maryland will include functionality required by the three standards outlined above, even if the state hasn’t adopted the standard. In those scenarios the functionality will be turned off and an EDC-specific, customized solution will be placed on top, creating unnecessary cost for ratepayers.
EDCs that have developed and are running customized software in their control room will likely need to specify gateway computers that can translate information from one protocol (i.e. the one that is compliant with relevant standards) to another (the EDC’s highly customized or even self-built software that it uses in its control room). Protocols are common in the software industry to ensure that computers can communicate using standard interfaces (e.g. a Linux machine sharing information with a Windows based computer). The standards mentioned above ensure these protocols are secure and meet standards for cybersecurity.
The solutions exist, and it is up to PUCs and the EDCs they regulate to ensure they upgrade to the most recent standards to enforce the use of inverters/controls that can provide the desired functionality. But, as can be seen in the Case Study, EDCs have achieved success with basic solutions such as email and phone calls.
State commissions have the responsibility of ensuring that state policy is implemented in a manner that is cost effective and does not impact reliability. There are challenges associated with integrating BESS onto the distribution grid, and selected states have been leading the way developing their own solutions, including:
1. Treatment of BESS in the EDC distribution planning process. The BESS must reduce substation load at peak hours to provide a benefit to the grid. Emerging solutions include operating envelopes that provide assurance the BESS will be discharging and reducing load, flexible interconnection, and discounting BESS nameplate to accommodate outages and other factors.
2. BESS charging and compensation rates or tariffs. Structures must be in place to allow BESS to know the cost of charging and compensation levels. Much of this has been defined for distribution-connected BESS participating in wholesale markets because of FERC Order 841. Yet, in many states, retail rates are still being developed that include both the cost to withdraw electricity from the grid and compensation for injections.
3. BESS interaction with load queue. Load and BESS should not be allowed to compete for the same capacity at a substation. Processes need to be put into place to ensure the BESS acts as a resource and reduces the impact of new load. State commissions should look at ongoing actions at FERC and ISO/RTOs to allow large loads to “bring their own generation” and be studied as one combined resource (load + BESS) on the electrical system.
4. Communication between BESS and EDC. Some of the more advanced solutions suggested in this paper, such as flexible interconnection, require real-time communication between BESS and EDC. It can be tempting for EDCs to require customized solutions that are unique to their footprint but this overlooks the standard capability already built into BESS inverters and power control systems. Commissions should ensure EDCs are adopting the latest applicable standards (IEEE-1547 2018, IEEE-2030.5 and SunSpec CSIP which is in the process of being adopted by IEEE and will be published as IEEE-2030.5.1) instead of requiring customized solutions.
Authors: Mrinmayee Kale (DER Interconnection Expert, Pure Power Engineering) | Kerinia Cusick | Rao Konidena
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