Order No. 2222 tariff revisions
Pursuant to Order No. 2222, each RTO/ISO grid operator must modify its tariff provisions to:
- Allow DER aggregations to participate directly in RTO/ISO markets and establish DER aggregators as a type of market participant
- Allow DER aggregators to register DER aggregations under one or more participation models that accommodate the physical and operational characteristics of the DER aggregations
- Establish a minimum size requirement for DER aggregations that does not exceed 100 kW
- Address locational requirements for DER aggregations
The RTOs/ISOs grid operators must address:
- Distribution factors and bidding parameters for DER aggregations
- Information and data requirements for DER aggregations
- Metering and telemetry requirements for DER aggregations
- Prescribed coordination frameworks between relevant entities, including an established process for ongoing coordination and involvement with the utility, regional grid operator and DER aggregator, along with state regulators and other relevant entities
- Modifications to the list of resources in a DER aggregation
- Market participation agreements for DER aggregators
DER rate design options
The National Association of Regulatory Utility Commissioners (NARUC) issued DER guidance on rate design and compensation in November 2016. Below are the potential rate design options for investor-owned utilities to assess and analyze when establishing the DER operating model:
Option 1: Traditional rate designs (flat rates, block rates, time variant rates, three-part rate/demand charges)
Option 2: Maintenance of the current rate design or implementation of another option, such as decoupling
Option 3: Demand charges based on customers’ rate of usage, measured in kW, rather than the total volume of usage, measured in kWh
Option 4: Fixed charges to recover a base floor of revenue from customers for connection to the grid
Option 5: Minimum monthly reliability contribution to be included on electric bills for utilities to avoid loss of revenue from customers “off the grid” and for the utility to ensure grid reliability
Option 6: Stand-by charges and backup services used to meet additional load requirements when utilities with DER aggregation systems have capacity constraints or unplanned outages
Option 7: Interconnection fees that enable DERs to connect to the electric grid for which the utility can charge an interconnection fee to recover the one-time cost that the utility incurs to set up the DER on its system
Option 8: Metering charges to recover costs for meters that measure the energy from the DER delivered to the electric grid
Customer compensation options
It is common for customers to receive some form of compensation for the energy produced from DER solutions that are put on the grid. Such customer DER solutions include residential rooftop solar systems, electric vehicles with dual flow to the grid capabilities or micro grid communities. There are generally two customer compensation options: net metering or valuation methodology. Each customer option has its own set of rewards, complexities and risks.
Energy resiliency and public safety
Beyond the commercial viability aspects of DERs, energy reliability, public safety and customer affordability must be top of mind to achieve a successful DER transition, especially given the grid vulnerabilities from climate change threats. The aftermath of Winter Storm Uri prompted reform measures that demonstrate how critical a sound policy around DERs at the outset is, given the complexities and risks inherent in energy delivery services.
The Institute for Policy Integrity raises concerns of DERs impacting reliability, such as interconnection of an installation creating a risk of exceeding local distribution system capacity constraints. Installing 10,000 distributed residential solar panels will present unique load-balancing challenges compared to the installation of 10 offshore wind turbines.
It is critical to understand the impact of each potential DER aggregation solution on electric load management, along with the associated costs and future revenue streams based on its unique market realities across the service territory footprint.
Perspectives on DERs
On November 17, 2016, FERC issued the NOPR on proposed reform measures to facilitate participation in electric storage resources prior to its issuance of Order No. 841 on February 15, 2018. FERC received 109 comments on the NOPR from a diverse set of stakeholders, which prompted it to gather more information before the issuance of its final policy on DERs: Order No. 2222. Xcel Energy Services Inc. submitted comments, along with EEI, NARUC, MISO and other interested parties.
Of the issues raised, Xcel’s comment letter aligned with the position taken by other key stakeholders on the following matters:
- FERC Jurisdiction Authority — Both Xcel and NARUC questioned FERC’s authority to implement this requirement, and EEI expressed its concerns over the potential impacts to the distribution utilities and systems. FERC has expressly stated that the DC District Circuit Court’s recent ruling on Order No. 841 affirmed FERC’s exclusive jurisdiction over the regional wholesale power markets and the criteria for market participation to ensure just and reasonable rates.
- Information and Data Requirements — Both Xcel and MISO support the requirements for DER aggregators to maintain aggregate settlement data, with EEI and Xcel both stating that information and data requirements should be consistent or comparable for all wholesale market participants.
- Metering and Telemetry System Requirements — Xcel, MISO, EEI and NARUC all expressed concerns related to any lowered metering and telemetry system requirements or standards to facilitate DER aggregation participation in the market.
Notably, some of the comments submitted by new market players expressed viewpoints and support for positions that did not align with the traditional market players:
- Minimum and Maximum Size of Aggregation — Xcel expressed concerns over a minimum size of 100 kW for single DER aggregations, with others advocating for 100 kW for all DER aggregations, regardless of the model in which they elect to participate.
- Role of Distribution Utilities — Xcel supports a greater decision-making role for distribution utilities in reviewing DER registrations, while others argue that having the appropriate level of communication between RTO/ISO and the distribution utility eliminates the need for distribution utility review altogether.
The comments submitted in advance of Order No. 841 and Order No. 2222 shed light on the alignment and divergent perspectives across the varied stakeholders on DER market participation. The early stages of DER present opportunities, risks and challenges that will continue to evolve as FERC and state public utility commissions work closely with investor-owned utilities and new market players in reforming existing regulations to accommodate the future carbon-free grid of America.
It is also important to note that, even though FERC has issued its final rule and the DC Circuit Court affirmed FERC’s exclusive jurisdiction over the regional wholesale power markets, Order No. 2222 is subject to interpretation and application, not to mention subject to state jurisdiction market rules and state DER plans.
Actions to be taken now on Order No. 2222
Now is the time to assess the impact of Order No. 2222 and co-design the early stages of the DER operating model necessary to implement its requirements by July 19, 2021. The FERC compliance filing must include a proposed implementation plan that is appropriately tailored for the region and must outline how the FERC final rule will be implemented in a timely manner.
This policy impacts the entire energy delivery value chain from generation, transmission and distribution, and technology operations to customers. Applying a strategic and disciplined approach across impacted market players and regulators will position the U.S. Power & Utility sector for greater success in adopting the new policy stemming from Order No. 2222 and lead America in achieving a carbon-free future.