Task Force Feature: The DERTF Bill of Rights
When the Task Force puts its collective brain to something, the results are pretty incredible
Hello DER Task Force! We are back after a quick week off with a very special featured post — the DER Task Force’s own DER Bill of Rights. Since October of 2021, a dedicated group from the community (shoutout policy team!) has come together almost every week to conceptualize and draft this document, and we are very proud to be sharing it with you all.
Following the release of this Bill of Rights, we will publish a series of discussion topics that naturally emerge from these rights, the FeDERalist Papers. The first and most important of these discussions, on the topic of equity and how DERs will enable a more equitable grid, will be published in the coming weeks. We look forward to sharing that as well as additional topics with you all
If you are interested in writing a FeDERalist Paper yourself or otherwise getting involved in our policy efforts, please reach out to us via Slack!
THE DER TASK FORCE BILL OF RIGHTS:
Advancing a Distributed Energy Resources 'Bill of Rights' for Local & Regional Grid Planning
DISTRIBUTED ENERGY RESOURCES (DERs) & OUR ENERGY FUTURE
Electrification is rapidly increasing demand for electricity, creating challenges in building the distribution infrastructure needed to manage the new demand. Existing infrastructure will be unable to scale quickly enough, driving the need for innovative methods to fill the gap. Distributed energy resources (DERs), and the various ways in which they can be deployed, are one way to address this challenge. Successful adoption of DERs will be key to addressing challenges posed by climate change and aging infrastructure, while creating a more resilient, modern, and equitable grid. Yet, the existing patchwork of DER policies leads to inconsistent capture of potential DER value streams and makes it difficult to unlock the full potential of DER deployment.
THE DER TASK FORCE (DERTF)
The DER Task Force (“DER Task Force” or “DERTF”) is a community dedicated to unlocking the immense promise of distributed energy resources in the electric power system. Unlike many industry groups, DERTF is not sponsored or influenced by the largest of its members – all participation is from individual volunteers who are highly informed and enthusiastic about DERs. Since the founding of DERTF in 2020, membership has grown rapidly, with over 2,000 individuals active in the DER industry, including project developers, engineers, analysts, community organizers, utility employees, policy experts, academics, and investors from some of the most forward-thinking grid edge organizations in the country. DERTF seeks to be a resource and ideas hub for the DER community and an advocate for community members in advancing DER policy.
DERTF BILL OF RIGHTS
Given the wide variation of DER policies from state to state (even from agency to agency), working with a common set of principles - and ones that place consumers first - will be important to help guide the transition, or at the least, reduce duplicative or contradictory efforts1. This Whitepaper seeks to provide a framework for federal, state, and local regulators and planners in managing ongoing DER deployment efforts. The DER Task Force identifies the following four (4) key rights of customers that must be incorporated into all DER policymaking, as well as specific policy recommendations that can be used as building blocks for successful DER programs across existing regulatory frameworks and regional grid demands. If adopted effectively, the DER Task Force believes the result will be a far cleaner, lower cost, and more resilient and equitable grid.
Right to Ownership. Customers have a right to own distributed energy technology, and a corresponding right to interconnect that technology to the grid without undue burden or delay.
Right to Compensation. Customers have the right to participate in all possible markets and be compensated for all potential value streams, reflecting the true and full value that their DERs provide to the grid.
Right to Choice. Prohibitions on private DER interconnection and ownership should be driven only by technical and safety limitations, not utility incumbency.
Right to Data. As in the telecommunications and financial sectors, energy consumers have the right to access their own data in real-time, and share that data with third-parties.
RIGHT TO OWNERSHIP
The future framework for DER ownership has critical implications across the electricity sector. While behind-the-meter (BTM) resources, such as residential solar, are individually negligible, they can be a powerful force if aggregated – both for injecting energy onto the grid and for demand response during energy shortages. Ensuring that grid-connected customers are able to build, own, and connect to the grid is therefore a critical piece of the energy management puzzle. Policies that limit customer ownership serve to reduce competition and hinder grid flexibility and resilience, innovation, and equity. It is essential to adopt policies that remove roadblocks and enable customers to build, interconnect, and export electricity. These policies include uncapped exports of energy - limited only by physical grid constraints - prevention of arbitrary and/or prejudicial rates, streamlined interconnection and permitting processes, financial incentives, and expansion of third-party ownership models.
Identify and work with state advocate to revise state legislation barring third-party ownership
Take special consideration in determining whether utilities offering financing/ownership of DERs is anti-competitive
State regulators should consider adopting 'fast-track' programs, or financial incentives, or other models that allow third-party owners of DERs to pay for necessary distribution upgrades
Customers have the Right to Non-Utility Owned DER Models
Most regulated markets define electric utilities as the retail sellers of electricity, thus prohibiting third-party owned generators. Similarly, some states define electric utilities as those that use power generation equipment for anything other than personal use; in these markets, third-party owners may also be barred from owning assets and selling power directly to customers. The DERTF supports efforts to pass third-party ownership-enabling legislation, which can accelerate DER deployment by improving project economics. In addition to amending state regulations, improving financial incentives can also remove barriers to DER adoption and deployment. Financial incentives can include permitting fee reduction or elimination, grants, low interest loans, and on-bill financing. These ownership models are an alternative to direct ownership and allow customers to benefit from the federal investment tax credit and similar state tax credits.
Customers have the Right to Export Their Power without Prejudicial Tariffs
Many existing rates and utility tariffs harm the economic case for DERs in a manner that is either arbitrary or prejudicial, e.g. special rates and charges for customers with solar, regardless of how the customer utilizes their solar and its impact on their load profile. The DERTF position is that importing and exporting of power should be treated equally, and corresponding rates reflective of only the underlying physical, techno-economics of the grid. The rate design for a customer class should be able to properly allocate costs against any load profile, and when export is compensated properly through a value stack approach, there is no reason to limit DER generation other than for specific distribution grid engineering and safety reasons.
Customers have the Right to Interconnect without Undue Delay
Lengthy interconnection approval and permitting cycles are delaying DER deployment, increasing costs, and, in some cases, halting projects. A lack of policy to compensate customers’ excess electricity, such as uncapped net metering or a value stack, can greatly diminish the economics of a customer-owned project. These processes need to be simplified and streamlined for accelerated customer adoption. It is the position of the DERTF that export structures should be uncapped, i.e. that there is no limit to the number and size of customer-sited DERs. In cases where actual physical capacity constraints make this impossible, regulators should create a framework that the DER owners can pay for distribution upgrades that would make the project technically feasible, which would in turn benefit all grid participants.
RIGHT TO COMPENSATION
All grid users, whether customers, utility providers, or third-parties, are entitled to participate in the wholesale market and to receive full and fair compensation for all services provided to both the wholesale market and distribution grid. In its Order 2222, FERC confirmed that states and utilities cannot restrict customers from accessing the wholesale markets and that customers have the right to participate in multiple retail and wholesale programs simultaneously. Fairly compensating DERs makes them more affordable, in turn increasing the use of DERs and the cost and reliability benefits they provide.
Regulators should consider preventing utilities from applying technology-specific tariffs, without showing that such tariffs are necessary for grid safety
State regulators should explore 'Value-Stack' compensation to succeed NEM programs in the context of “Avoided Costs” to both infrastructure and energy/capacity
Such Value-Stack compensation should also include a 'Resilience' value
All DERs Should be Able to Participate in All Power Markets
Federal law has established that a single resource can simultaneously participate in multiple retail and wholesale programs that “serve different purposes, provide different benefits, and compensate distinctly different services”2 and that any restrictions on dual participation must be narrowly designed to prevent double counting. Regulatory entities should continue efforts to ensure that DERs can participate - and receive compensation for - value both behind and in front of the meter as well as at the distribution and wholesale level3. Utilities should only be granted the customers’ wholesale market rights that are absolutely necessary to administer the retail program; otherwise, value streams like capacity and energy should be within the jurisdiction of wholesale markets and available to be serviced by third-parties in deregulated markets4.
Customers Should Receive Compensation for Multiple Services & Multiple Value Streams
Net Energy Metering (NEM) policies have been revolutionary in incentivizing behind the meter generation. But NEM is a blunt instrument, only recognizing the kWhs generated and compensating them at a flat rate regardless of time and location. Overcompensation and lack of incentivizing storage can also lead to inequitable outcomes and problems like the Duck Curve. However, the increased digitization of energy has opened the door to new ways of valuing assets. DERTF encourages fair compensation to DER owners for multiple values, including energy injections, but also capacity, offsetting need for increased supply, reducing near term distribution upgrades, or producing cleaner sources of electricity. The most effective of these programs will separate transmission and distribution (T&D) benefits and wholesale market benefits, putting the former in the hands of the utility, and the latter in the hands of the ISO (in deregulated markets).
State Programs Should Compensate for the Value of Resilience
Even state programs that do compensate based on multiple value inputs still systematically undervalue resilience. This is largely because existing wholesale electricity markets are designed to keep bulk power (generation/supply) uptime or reliability in mind, and not endpoint (consumer/demand) uptime resilience5. This means that the value of resilience becomes an externality to the electricity market, and DERs are unable to capture the true value they provide. Since it is unlikely that wholesale markets will reform with resilience at the core of the compensation scheme for some time, the DERTF encourages local utilities to include resilience payments as a core part of the value stack.
RIGHT TO CHOICE
Utilities have an obligation to serve end-use customers within their service territory, and an obligation to protect infrastructure to ensure reliability for all customers; however, end-use customers do not have an obligation to take service from the utility. While this Whitepaper does not advocate for or support unregulated customer infrastructure, if end-use customers are free to self-generate, they should have a related right to build shared infrastructure for personal reliability and use where appropriate (provided system reliability is not negatively affected).
Public utility commissions should have a mechanism for developers to submit non-utility-owned distribution wires for approval on a case-by-case basis, in order to efficiently integrate DERs into the distribution grid
Regulators should encourage the ability of community microgrids to build shared, community-owned (non-utility) distribution infrastructure between DERs in order to enhance community and local resilience
Customers Should Have Options for Private Interconnection
Utility franchise rights should not prevent end-users from developing their own community microgrids, especially in situations where allowing customers, e.g. neighboring landowners, to connect with each other offers significant resiliency benefits to both the customers and the grid. Moreover, if the current distribution company is not providing adequate service (i.e. rolling blackouts, extreme energy price spikes), customers should not be summarily prohibited from accessing private wires. Where microgrids would be connected to the utility’s infrastructure, the interconnection process should evaluate the microgrid no differently than it would evaluate a facility with a similar number of connected load points located at similar distances from each other, utilizing similar equipment. Local municipal authorities, not the utility, should authorize the crossing of property lines, and customers should therefore be free to build shared infrastructure for personal use, provided there is no negative impact on the broader distribution system6.
Customer DER Technology Should be Regulated Equally
In essence, all DERs offer an ability to meet demand, store, and reduce demand to optimize electricity flow. As such, all DER technologies should be subject to the same regulatory framework. These frameworks can be designed to limit negative externalities but should allow customers the freedom to choose the technology most appropriate for their own needs and requirements for electricity generation, consumption, and resilience. For example, customers should be entitled to interconnect their chosen technologies and export electricity as long as the system operates within the same regulated standard for safety and function. These technologies include, but are not limited to, onsite renewable generators (e.g., solar and/or wind resources), onsite non-renewable generators (e.g., natural gas backup generation), battery storage, electric vehicle (EV) charging and discharging devices, load controls (e.g., smart thermostats, heat pumps, or electric hot water heaters) and any other microgrid technology. Special consideration may be given to emissions rules, but not in a way different to that given to a traditional wholesale power plant.
RIGHT TO DATA
There has been a rapid digitization of our grid over the last decade. Until recently, energy consumption was captured on a monthly basis; now it can be measured in real-time. Providing information in a readily accessible format to customers will help customers make more informed energy decisions; accordingly, DER owners should have the right to the associated data for their meter. Customers should also be able to easily share their data with third-parties of their choice, which provide important energy management tools and services not available to individual users. Lastly, customers have the right to use this data for financial settlement, and not be obligated to receive service under utility-designed profiled usage rates.
Encourage AMI & interval meter rollout - or equivalent upgrades - to all customers
Develop standards for data formatting, reports, security, and authorization where no current standards exist (which also recognize the consumer right to share data)
Access to data should be secure, and not unreasonably burdensome to set up through utility-led APIs or secure protocols to allow third-parties to query data directly from the meter at no cost
Open access to third-party rate-design – i.e. “settling to the meter”
Customers have a Right to their Own Data in Real-Time
To unlock and measure the value created by DERs, DER owners and authorized third-parties should be able to access, export, and share real-time and historical interval data generated by DER owners’ meters without undue burden. Such data should be made available in a manner that can be automated in common and well-documented formats, and DER owners should be able to share usage data as it is generated in real time7.
Customers have a Right to Share their Own Data through Common DER Data Standards
DER owners should be able to export their data for a selectable time period to third parties via API. While electricity usage data may be anonymized on a larger scale, the individually collected data is uniquely linked to each customer account and smart meter, but that does not mean it is inherently higher risk given a customer’s consent. Individual-level data can be anonymized, through various encryption methods; in fact, such encryption has occurred for years with respect to personal financial data and has generally not produced outsized security risks for the individual. And in the absence of a common definition and protocols for shareable 'customer data', the creation of a DER data standard would create certainty among third-party service providers and give electricity providers the ability to demonstrate compliance with any regulatory standards.
Customers with Interval Meters Should Always be Settled Using Interval Data
To realize the value created by DERs, DER owners must be billed for their true, individualized load shape and usage, rather than on the basis of a generalized load shape for a customer class. For energy settlement it allows for customers to select rates that reward them for flexibility (and does not penalize flat-fixed-rate customers). For transmission, distribution, and capacity charges, this ensures that customers who shift load during critical periods realize the value of that load shifting, rather than simply subsidizing customers who elect not to do so. Such “financial settlement to the meter” ensures the fair treatment of electricity users both within and across customer classes: load behavior is more precisely measured and credited, and residential customers are able to benefit to the same extent as commercial and industrial customers from load shifting and DER deployment. Settling to the meter is critical to create incentives to support grid stability during peak hours, and given that more than 75% of U.S. households are already equipped with smart meters, will help recoup rate-payer investment8.
In the coming year, the DER Task Force will expand on the recommendations outlined in this Whitepaper, through select policy deep dives and topical discussions. It will also look to identify - and participate in - public service dockets across the country that are addressing issues relevant to the DERTF community. In the meantime, the DERTF invites any interested individuals and organizations to learn more about the Task Force and become involved in its work.
This Whitepaper defines "customer" and "consumer" as a rate-paying end-user of electricity. As there is currently no one accepted definition of ‘DER’; this Whitepaper uses the FERC definition, which applies an appropriately broad scope: “Any resource located on the distribution system, any subsystem thereof or behind a customer meter. These resources may include, but are not limited to, electric storage resources, distributed generation, demand response, energy efficiency, thermal storage, and electric vehicles and their supply equipment.”
N.Y. Pub. Serv. Comm’n v. N.Y. Indep. Sys. Operator, Inc., 158 FERC ¶ 61,137, at P 33 (2017)
For example, a customer might receive a utility rebate to purchase an energy storage resource in exchange for the utility using that resource to manage peaks. That customer should not be restricted from using that energy storage resource for a different service in the wholesale market that does not present a risk of double compensation.
E.g. A utility contract should not grant the utility a net-metering customer’s ancillary services rights unless the utility has a plan to use that customer’s resource to provide ancillary services.
Concepts like the Value of Lost Load (VOLL) in ERCOT create an administratively set price ($5,000/mwh) for the value that consumers can lose during an outage, despite an original report detailing values up to $40,000/mwh.
E.g., an entire housing development built with its own shared infrastructure and a single point of interconnection into the local utility. Each house could have its own DERs and submeter, but the development is viewed by the utility in aggregate as a single, bidirectional interconnection. With a transfer switch included, the development could isolate from the grid to ensure resilience for the community.
Real time depends on the method that is being used to query the data. When querying from the utility’s APIs, real time typically means 15 minutes. When querying the data directly from the meter, or other device being used to handle meter data, then real time means less than one second when technically possible.
For regions where the cost to ratepayers might be significant, lower-cost sensors can be added to existing meters.