15 minute read 15 Jun 2021
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Landmark FERC decision opens market for distributed energy resources

By Kimberly Johnston

Partner, Power & Utilities, Ernst & Young LLP

Builds better energy delivery services. Recognized as one of Houston’s Most Influential Women of 2016. The heart behind Good Works Houston and University of Utah virtual blockchain course.

15 minute read 15 Jun 2021
Related topics Power and utilities

FERC Order No. 2222 levels the playing field between DERs and traditional grid operators.

Two questions to ask:

  • How will FERC Order no. 2222 change the utility landscape?
  • How are utility companies being called to respond?

We are now a few months into the Biden administration and, based on the executive action taken to date, the President’s commitment to combating climate change and promoting a clean energy future is clearly a top priority. Notably, President Biden’s January 27 Executive Order “Ta ckling the Climate Change Crisis at Home and Abroad” sets a target for a carbon pollution-free power sector by 2035, and net-zero emissions economy-wide by 2050.

The race to net zero is sparking federal and state legislative plans to scale proven carbon-free technologies and promote innovation of new, commercially viable decarbonization solutions. The Biden American Jobs Plan proposes a $2.3 trillion infrastructure plan to boost the clean energy transition. The federal package is intended to stimulate investment, create jobs and put America on its path to become a carbon-free grid by 2035 and a carbon-free economy by 2050.

The US power sector

The US power sector, as represented by the Edison Electric Institute (EEI) and its member companies, achieved a major net-zero milestone, with approximately 40% of the total US electricity mix now being generated from carbon-free sources. EEI and its members are committed to leading a clean energy transformation and continue to lead the world in carbon reductions.

EEI and the investor-owned electric companies are committed to getting the energy we provide as clean as we can and as fast as we can, without compromising on the affordability and reliability that our customers value. That’s not new. What is new is that we are joining the growing call for a 100% clean energy future.
Tom Kuhn,
EEI President

The US regulated grid

For US regulated markets, setting new regulations is critical to eliminating market barriers for emerging decarbonization technologies and incentivizing investments to achieve a carbon-free, 24/7 power grid by 2035 while ensuring safety, reliability and affordability. As extreme weather continues to increase, causing massive outages, regulators are acting with a sense of urgency to combat threats of climate change while transitioning to a carbon-free grid and economy.

Today’s regulatory framework is based on the traditional centralized energy delivery model which is becoming outdated given the uptick in carbon-free technologies. The Federal Energy Regulatory Commission (FERC) and state public utility commissions continue to focus on modernizing regulations to promote a level playing field for new market participants, approve the rate recovery of pilot programs and offer incentives for grid performance enhancements. Co-developing the regulatory framework needed for tomorrow’s carbon-free economy is critical to a successful transition to the future customer-centric, decentralized and carbon-free operating model. 

There is going to be a lot more demand for electricity, both with electrification and demand for cleaner resources. We have to figure out policies that will hopefully promote a greater investment in the transmission grid to facilitate access to cleaner resources.
Rick Glick,
FERC Chairman

One recent monumental regulatory policy change occurred with the issuance of Order No. 2222 by FERC. This Order will essentially open the wholesale electricity markets to distributed energy resources. This is historic because the policy is ahead of the carbon-free technologies that will transform the way energy is produced and delivered across America.

FERC Order 2222

On September 17, 2020, FERC issued a landmark ruling, Order No. 2222, requiring Regional Transmission Organizations (RTOs) and Independent System Operations (ISOs) to amend their tariffs to allow distributed energy resources (DERs) to fully participate in the wholesale electricity markets and compete alongside traditional energy market players.

Order No. 2222 is intended to remove market barriers to participation of DERs in the RTO/ISO wholesale electricity markets, which represents two-thirds of customers across the US energy market. The Order enhances market competition while ensuring that RTO/ISO wholesale electricity markets produce just and reasonable rates.

Order No. 2222 presents a huge opportunity for investor-owned utilities and key stakeholders to design the future carbon-free, distributed operating model with the customer at the center.

Each RTO/ISO grid operator must submit FERC compliance filings by July 19, 2021. A filing must propose an implementation plan tailored for its region and must outline how the final rule will be implemented in a timely manner.

Order No. 2222 presents a huge opportunity for investor-owned utilities and key stakeholders to design the future carbon-free, distributed operating model with the customer at the center.

Forward -thinking regulations

Historically, most of the electricity generated in the US originated from traditional-generation, carbon-emitting sources, such as coal, oil or natural gas. Today, however, DERs are rising as emerging carbon-free technologies become increasingly more commercially viable.

One of FERC’s primary responsibilities is to regulate the sale of electricity in the wholesale power markets, which are composed of the organized capacity, energy and ancillary services markets that are run by the regional grid operators in the US. The role of FERC is to ensure that the competition in US wholesale power markets is just and reasonable.

Accordingly, FERC took action to remove market barriers for advanced clean energy technologies. Below is a summary of the history of FERC actions that are intended to create a level playing field across both traditional and new market players:

  • On March 15, 2011, FERC issued Order No. 745, providing demand response compensation in organized wholesale markets.
  • On November 17, 2016, FERC, in agreement with Advanced Energy Economy, issued a Notice of Proposed Ruling (NOPR), proposing to remove market barriers to the participation of both energy storage and aggregated DERs in wholesale electricity markets operated by RTOs/ISOs. FERC received 109 comments on the NOPR proposals from a diverse set of stakeholders.
  • On February 15, 2018, FERC issued Order No. 841, directing RTOs/ISOs to remove barriers to the participation of energy storage resources, but it opted to continue evaluation of DERs.
  • On March 19, 2020, FERC issued an NOPR (Docket No. RM20-10-000), seeking to revise its electric transmission incentive policy to stimulate the infrastructure development needed to support the evolving generation mix, technological innovation and shifts in load patterns. The proposed incentives amount to a 250-basis-point cap on total return on equity (ROE) incentives.
  • On September 17, 2020, FERC issued Order No. 2222, requiring grid operators to revise their tariffs for DERs to compete alongside traditional market players in wholesale energy markets.
  • On April 15, 2021, FERC filed a Supplemental NOPR to the previously issued NOPR (Docket
    No. RM20-10-000), seeking to revise its electric transmission incentive policy. The Supplemental NOPR focused solely on the ROE adder and proposes to codify FERC’s current practice of granting a 50-basis-point ROE increase as an incentive for RTO/ISO participation.

FERC recognizes that competition in US electricity markets is critical to the clean energy transition. The issuance of Order No. 2222 is viewed as a historic, forward-thinking ruling where regulation is providing direction to grid operators on the evolving energy market ecosystem, along with the other forward-thinking regulations advancing demand response, energy storage and ROE incentives.

The emerging energy technologies

Distributed energy resources are small-scale power generation or storage technologies that can provide an alternative to, or an enhancement of, the traditional electric power system. DERs include storage, vehicle-to-grid integration (VGI) solutions, micro grids, distributed rooftop solar and other technologies located on the electric utility’s distribution system or behind a customer meter. In Order No. 2222, FERC defines DERs as:

“[S]mall-scale power generation or storage technologies (typically from 1 kW to 10,000 kW) that can provide an alternative to or an enhancement of the traditional electric power system. These can be located on an electric utility’s distribution system, a subsystem of the utility’s distribution system, or behind a customer meter. They may include electric storage, intermittent generation, distributed generation, demand response, energy efficiency, thermal storage or electric vehicles and their charging equipment.” 

Since DERs were previously nebulous, this definition is helpful. However, because the text is broadly stated, it lends itself to varying interpretations and is anticipated to evolve. Order No. 2222 enables market opportunities for new sources of energy and grid services, presenting a huge market opportunity for investor-owned utilities and key stakeholders to co-design the energy market ecosystem of the future.

The benefits of DERs

FERC has stated that DERs will help provide a variety of benefits, including lower costs for customers through enhanced competition, more grid flexibility and resilience, and more innovation within the electric power industry. The rule allows several sources of DERs to aggregate in order to satisfy the minimum size and performance requirements that each may not be able to meet individually. 

The role of states and DERs

It is important to understand that interconnection of DERs with the grid remains subject to local utility interconnection rules set and governed at the state level by state legislatures and state public utility commissions. The existing rules at the state jurisdictional level can either encourage or discourage DER market participation. 

Order No. 2222 impacts wholesale power markets involved in buying and selling power between generators and resellers. The Order does not cover retail markets, which presents complications for deregulated energy markets. The US has six deregulated electricity markets that have unique rules for energy market participation, and, today, customers in 26 states have a choice of a retail energy provider for electricity, natural gas or both, presenting complications in adopting the Order.

Since the FERC final rule instructs grid operators to revise their tariffs to enable DERs as market participants across RTO/ISO regional markets, stakeholders will need to tailor the Order No. 2222 compliance filing to the state and local market realities.

FERC declines to exercise jurisdiction over the interconnection of a DER to a distribution facility when the DER interconnects for the purpose of participating in RTO/ISO markets exclusively through a DER aggregation. Therefore, state or local law will govern distribution-level through interconnections for DERs participating in RTO/ISO markets exclusively through aggregation. 

  • Colorado DER environment

    In 2004, Colorado passed the first voter-led standard in the United States, requiring electricity providers to obtain a minimum percentage of their power from renewable energy sources. Today, legislation under HB10-1001 requires investor-owned utilities (IOUs) to generate 30% of their electricity from renewable energy by 2020, of which 3% must come from DERs.

    In late 2019, Colorado legislators directed the Colorado Public Utilities Commission (Colorado PUC) to create rules that require the state’s two IOUs, Xcel Energy and Black Hills Energy, to file plans for investment in electrical distribution systems. In Colorado, regulators will now provide oversight over distribution networks and evaluate whether investment plans will be cost-efficient and effective.

    CRS § 40-3-117, a statutory provision developed by legislators, requests that the Colorado PUC issue a report to the legislature by November 2020 that examines: 

    “financial performance-based incentives and performance-based metric tracking to identify mechanisms for aligning utility operations, expenditures, and investments with various public benefit goals, including safety, reliability, cost efficiency, emissions reductions, and expansion of distributed energy resources.”

    The Colorado PUC issued Decision No. C19-0969 in December 2019, which called for multiple rounds of comments and workshops to consider “emissions reductions and expansion of distributed energy resources.” Per the filing, it appears that the most recent workshop was conducted in September 2020 and that the proceeding is ongoing.

  • Minnesota DER environment

    In 2001, Minnesota statute 216B.1611 established that the Minnesota PUC should develop utility tariffs “for the interconnection and parallel operation of distributed generation fueled by natural gas or a renewable fuel, or another similarly clean fuel or combination of fuels … of interconnected capacity.” Under this statute, utilities submit an annual report on distributed generation interconnected to the utility’s distribution system.

    Minnesota and federal laws allow customers to install DERs and use the electricity they generate to offset electricity that customers would otherwise purchase from their utility, which also includes cooperatives and municipal utilities. As of 2019, there were approximately 9,200 DER systems in Minnesota.

    The Institute for Local Self-Reliance submitted a September 2020 letter to the Minnesota PUC, arguing that, while the 2001 statute intended to encourage distributed generation projects, little development has occurred. In a 2018 docket filed with the Minnesota PUC, a solar energy policy group commented that FERC created a distributed generation tariff framework in 2004, but it appears that no distributed generation facility has taken service under the tariff.

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.

The views reflected in this article are the views of the author and do not necessarily reflect the views of the global EY organization or its member firms.


FERC  Order No. 2222 presents a huge opportunity for investor-owned utilities and key stakeholders to design the future carbon-free, distributed operating model with the customer at the center. Because 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 achieving a carbon-free future.

About this article

By Kimberly Johnston

Partner, Power & Utilities, Ernst & Young LLP

Builds better energy delivery services. Recognized as one of Houston’s Most Influential Women of 2016. The heart behind Good Works Houston and University of Utah virtual blockchain course.

Related topics Power and utilities