FERC Order 2222: Experts offer cheers and jeers for first round of filings

Canary Media’s Down to the Wire column tackles the more complicated challenges of decarbonizing our energy systems. Canary thanks CPower for its support of the column.

The future of the power grid lies in tapping the gigawatts of capacity coming from distributed energy resources such as rooftop solar, home batteries, electric vehicles and energy-smart devices — DERs for short. Ultimately, this will radically reconfigure how the U.S. electricity grid works. But getting there will be a long and complicated process.

Grid operators in the U.S. are now required to develop plans to allow DERs to access their multibillion-dollar wholesale energy markets. These plans are being evaluated by the Federal Energy Regulatory Commission, which oversees interstate electricity markets and has made DER integration a centerpiece of its grid modernization policy.

But there is already plenty of disagreement about what the grid operators’ plans should look like. Advocates of distributed energy argue that the draft plans released so far would place too many limits on how DERs can participate in wholesale energy markets. Utilities and state regulators, meanwhile, worry that letting DERs participate in wholesale markets will wreak havoc on distribution grids and state-level policy.

What are the most hotly contested issues? First, let’s walk through the background, then we’ll dive into the details.

The 411 on FERC Order 2222

Back in September 2020, FERC approved Order 2222 — a landmark decision requiring regional transmission organizations and independent system operators, which manage the transmission grids that provide electricity to about two-thirds of the country, to figure out how to give DERs access to wholesale energy markets.

Supporters of distributed energy cheered the decision’s potential to unlock the value of a class of energy assets that are expected to grow to hundreds of gigawatts of scale over the coming decade. Let these distributed assets earn money for the grid services they can provide, the argument goes, and they’ll become a key tool for balancing the variable wind and solar power, electric vehicles and heating systems needed to decarbonize the grid.

Bar that access, these supporters warn, and we’ll miss out on the opportunity to get the most communal value out of DERs. These resources are going to be deployed either way because many states’ policies support them and customers want them. ​“They’ll still be developed, but they won’t be able to deliver services in the wholesale market to bring down costs to consumers, bring down prices, provide reliability and resiliency benefits, and all the other things that DERs can do,” Jeff Dennis, managing director and general counsel at the Advanced Energy Economy industry group, said in a February interview.

But support for Order 2222 isn’t universal. It has faced legal challenges from utilities and state regulators on the grounds that it’s an overreach into a part of the grid that’s traditionally been under state, not federal, authority: the low-voltage networks that connect the transmission grid to customers.

While the courts have sided with FERC so far on these and other related legal challenges, the dispute underscores a whole host of jurisdictional challenges that will loom large as grid operators work with states and utilities on sharing responsibility for connecting, monitoring and controlling devices at the edges of the distribution grid.

Meanwhile, some energy experts worry that it could be overwhelmingly complex to try to adapt wholesale energy markets, which were designed for big power plants, to manage tens of thousands or even millions of disparate devices.

But both opponents and supporters agree that grid operators, utilities and the companies looking to aggregate DERs to make money in wholesale markets have a lot of work ahead to realize Order 2222’s vision.

Just how much work has come into clearer view over the past few months, as the majority of the country’s grid operators have filed their plans to comply with Order 2222. First came last year’s filings from California grid operator CAISO and New York grid operator NYISO, which each happen to serve states that have taken the lead on implementing DER-friendly policies.

Last month, grid operator ISO New England submitted its plan for complying with the order across its six-state territory, as did PJM, the country’s largest grid operator, which serves a 13-state territory from the mid-Atlantic seaboard to Chicago. Two more grid operators, the Midcontinent Independent System Operator and Southwest Power Pool, are due to file their compliance plans later this year, while Texas grid operator ERCOT isn’t required to comply because its electricity business is not under FERC’s jurisdiction (as I’ve explained in greater detail elsewhere).

FERC has begun reviewing these plans and may choose to accept them as-is or request changes. The process won’t be swift. Even after FERC approves the plans, Order 2222 gives individual grid operators leeway to determine when they will be able to implement the mandated market changes, and their timelines for completing this work may be several years away.

What’s at stake in FERC Order 2222 compliance plans? 

These plans are getting mixed reviews from the groups with the most to win or lose from their outcomes. But just what’s wrong or right about them? Trying to explain that in detail is pretty tricky, given the immense complexity of the undertaking, even for the energy policy wonks who’ve been arguing over the finer points in FERC filings over the past year and a half.

In an attempt to clarify this morass, it might be useful to separate the issues about the grid operators’ Order 2222 compliance plans into two categories: 

1) Transmission-scale issues

Grid operators are tasked with trying to make DERs, which are by their nature small-scale, fit into structures that were set up for large-scale grid assets like power plants. Questions to be resolved include:

• Do DERs in buildings and scattered across the low-voltage grid need the same second-by-second communications and metering as power plants, or can their contributions to energy markets be measured in simpler, more cost-effective ways? 
• Should DERs be limited to aggregating their capacity only for geographically narrowly defined parts of the transmission grid, or should aggregators be allowed to cast a wider net across bigger regions?
• Should DERs be required to bid into markets as different technologies in isolation from one another? For example, should batteries, generators and EVs, which can inject power into the grid, be aggregated separately from devices like smart home thermostats and efficient appliances, which reduce grid demand? Or should the rules for participating make room for ​“heterogeneous” mixes of technologies?

2) Distribution-related issues

There’s tension between, on one side, state regulators and utilities, which want to regulate and control what happens on the distributed side of the grid, and, on the other, DER aggregators, which want to leap into serving the bulk transmission grid markets. Questions to be resolved include:

• How much control should utilities have over how DERs serving wholesale market needs are allowed to connect to the grid in the first place? 
• How much control should utilities have over how often and at what scale DERs are dispatched to serve the bulk power grid, particularly when those actions could disrupt the lower-voltage grids utilities are responsible for? 
• What hard boundaries should be established between payments for wholesale energy market activities and payments for retail-level (i.e., state-regulated and utility-administered) programs — like, for example, solar net-metering regimes that value stored battery power, or utility demand-response programs that reward batteries, EV chargers or controllable loads such as smart thermostats, water heaters and appliances? 
• When these jurisdictional or economic boundaries are in question, who gets to decide how to resolve them?

Each grid operator’s Order 2222 compliance filing contains a mix of good, bad and downright ugly approaches to handling these issues, according to stakeholders. Here’s a short — and admittedly incomplete — tally of some of the biggest issues at stake.

Digging in on transmission-scale issues

Forcing DER-shaped pegs into power-plant-sized holes? 

Each of the Order 2222 compliance plans filed so far has earned its share of criticism for its approach to adapting rules designed for big power plants to serving DERs. Interestingly enough, the plan from California’s CAISO, the first grid operator to create a working structure for adopting distributed energy into its markets, has garnered some of the harshest criticism from DER supporters.

Since 2017, CAISO has allowed aggregated DERs into its markets under its Distributed Energy Resources Provider tariff. Its Order 2222 compliance plan largely retained that structure with a few modifications, such as scaling down the minimum size of a DER aggregation from its previous 500 kilowatts to match Order 2222’s mandated minimum of 100 kilowatts.

But so far, not a single aggregator has enrolled in CAISO’s tariff. Critics say the tariff’s rules and restrictions have made it largely unworkable as a way to earn money with DERs in the state.

One of the biggest deal-breakers is its ​“24/7 settlement requirement” that essentially forces any DERs that want to participate to make themselves constantly available for CAISO dispatch and thus forgo providing any other services to the grid. In a state that offers DERs multiple ways to make money by serving grid needs, such a restriction is simply ​“not practical,” Rachel McMahon, director of public policy for leading U.S. residential solar installer Sunrun, said in an email.

Another key barrier under CAISO’s plan relates to how individual DERs are metered, said Jennifer Chamberlin, executive director of market development for CPower, a demand-response and distributed-energy aggregator. Right now, CAISO allows aggregations of up to 10 megawatts to use an estimation methodology that avoids the need to meter DERs via second-by-second communications links, unless they’re bidding into the kind of fast-response ​“ancillary services” markets that need that level of granularity.

But if an aggregation expands beyond 10 megawatts, CAISO can require that real-time telemetry and metering be attached to every device that’s in it. That’s far too costly and complicated a task for smart thermostats and other residential load-control devices, and it could end up pushing aggregators to artificially split up their market power into chunks of 10 megawatts or less, she said.

There are ways to get around these kinds of problems. Other grid operators have proposed simpler strategies to allow DER aggregators to measure and verify the contribution from lots of devices, Allison Wannop, director of legal and regulatory affairs for Voltus, a demand-response and distributed-energy aggregator, said in an October webinar.

That’s important, because ​“the more stringent the telemetry and metering requirements, the fewer devices can participate,” she said. ​“Residential devices, or maybe even fleet vehicles, could be boxed out of the market.”

As for CAISO’s 24/7 settlement requirement, most other grid operators have come up with workarounds, Chamberlin said. New York grid operator NYISO’s Order 2222 compliance plan, for example, includes structures that allow DERs to participate in both wholesale energy markets and the retail-level moneymaking opportunities available from utility demand-response and grid-support programs, for example.

Mixing and matching different technologies 

That’s not to say that NYISO’s plan doesn’t have its own flaws, according to proponents of distributed energy. One of the biggest problems is how it treats ​“heterogeneous” mixes of multiple types of DER technologies, according to Chris Rauscher, Sunrun’s senior director of market development and policy.

NYISO’s Order 2222 compliance filing calls for different market structures for load-reducing DERs like smart thermostats or controllable loads on the one hand, and assets like batteries or generators that can actively inject power into the grid on the other, Rauscher explained in an interview.

That means NYISO’s plan has ​“no market rules or pathways today that allow behind-the-meter aggregations to participate in such a way that they can both inject energy onto the grid and modify consumption,” he said.

Grid operators have traditionally treated generators that provide electrons to the grid very differently than the demand-response programs that recruit customers to reduce electricity use when power grids are facing summertime or wintertime peak demands. So it’s understandable why NYISO would create separate approaches to handling those differences when it comes to DERs, Rauscher said.

But taking that route ​“kind of ignores the entire value of batteries,” he said. That’s because batteries can both reduce a customer’s load to nothing by meeting their entire power needs, and then add more value by injecting power onto the grid. ​“Without the ability to do both, batteries don’t have a meaningful way to participate,” he said.

“Was this an impossible task for NYISO? No,” he said. Other grid operators have solutions to this problem. For example, ISO New England allows battery-equipped virtual power plants, like the one Sunrun is developing in Massachusetts, to measure load reduction and grid injection as a single value, Rauscher explained.

Advanced Energy Economy’s Jeff Dennis pointed out in an October tweet that FERC’s initial response to NYISO’s compliance filing focused on this potential shortcoming; the commission asked the grid operator to ​“please explain how [its] proposal would not present a barrier to the formation of heterogeneous aggregations.”

Trying to solve the ​“baseline erosion” problem, and getting the most out of DERs 

Let’s return to ISO New England. While it may be doing well on how it treats mixed-technology DERs, it’s not winning high marks for how it proposes to manage another bugbear of the DER world, however: its baselining methodology.

“Baselining” is a term of art in the demand-response and energy-efficiency worlds that describes the process of estimating what a customer’s load profile would have been if an intervention — say, dispatching DERs to meet grid needs — hadn’t taken place.

That’s an inherently fuzzy metric subject to all kinds of assumptions, and it has caused major disputes in DER-rich markets such as California. But it becomes particularly problematic when it’s applied to resources that grid operators actually want to be in use more frequently, said Caitlin Marquis, a director at Advanced Energy Economy who’s been studying ISO New England’s Order 2222 compliance process.

“The concept of a baseline is that you have some steady baseline performance, and then you have some event where you’re deviating” from the norm, Marquis said in a February interview. But if the resource is ​“dispatched multiple times per week, that baseline becomes normalized and becomes relatively useless” — a process known as ​“baseline erosion,” she said.

That’s a big problem for resources that could do a lot of good if they’re continually adjusting themselves to reduce their load on the grid, said Greg Geller, head of regulatory affairs for Enel North America, the demand-response and distributed-energy arm of Italian utility Enel. This graphic from his presentation at an October webinar illustrates how baseline erosion can degrade the energy-market value for resources that are doing the right thing by reducing load consistently, not just in response to grid emergencies.

“What’s going to happen is that dotted black line becomes much lower, and there’s no way to get credit for your performance,” he said. ​“If you have an electric school bus that’s dispatching every day at the same time, with this approach, they’re no longer able to participate in the markets.”

Once again, solutions to this problem are being proposed by other grid operators. AEE’s Marquis cited NYISO’s proposal to ​“accommodate this type of demand response that’s regularly dispatched, in which you add back in the regular performance” to adjust for baseline erosion.

These kinds of adaptations are going to be critical to capture the full spectrum of value that DERs can provide, said Ben Hertz-Shargel, head of the grid-edge research team at Wood Mackenzie.

“DERs today basically participate almost exclusively [in wholesale energy markets] as emergency capacity,” he said. That means ​“they’re doing little, so they’re earning little” — and ​“they’re only accessible when things get bad.” That needs to change, in Hertz-Shargel’s estimation. ​“You want to have DERs and flexible demand participating regularly, so that even in blue-sky conditions, there’s more slack in the system” — in other words, so that DERs can help mitigate the conditions that can lead to grid emergencies, rather than just responding after they happen.

PJM, a regional transmission organization whose territory stretches across 13 mid-Atlantic states, gets a little bit closer to making this happen in its Order 2222 compliance filing, Hertz-Shargel said. The grid operator proposes a way for DER aggregators to avoid directly metering end devices by using calculated values that can be spot-checked for accuracy, he explained. ​“PJM believes that this approach will ensure that PJM has the operational visibility it needs, while simultaneously avoiding excessive costs to DER aggregators,” he said.

PJM is also proposing a structure that doesn’t differentiate between energy reduction and energy injection, he said. That’s something he thinks FERC will require the rest of the country’s grid operators to include in their Order 2222 compliance plans, since it’s an important step in allowing heterogenous aggregations to work effectively: ​“All the plans are going to end up compensating for exported energy.”

Dennis of AEE agreed that PJM is on the right track on this issue. AEE’s member companies — which include major tech companies with an appetite for clean energy including Amazon, Google and Microsoft along with some of the country’s biggest DER providers — view PJM’s proposal ​“as a step forward,” he said. ​“They do think it opens new opportunities,” unlike the plan from ISO New England.

What’s the right size for grid aggregations? 

Still, PJM’s plan does have some drawbacks, Dennis said. One that’s been highlighted by AEE and other stakeholders such as the Advanced Energy Management Alliance trade group is its proposal to limit aggregations to a relatively small geographic area, by requiring any grouping of DERs to bid together at a single ​“pricing node” on its transmission network.

These pricing nodes — the locations on the transmission grid where wholesale energy prices are determined — range from large to small in terms of how many electricity customers they serve, he said. But about half of PJM’s pricing nodes supply less than 7 megawatts of demand each, which is too small to support aggregations ​“at sizes that would make economic sense,” he said.

What’s more, customers served by those nodes wouldn’t be able to join aggregations elsewhere in PJM’s territory, preventing them from participating in the market opportunities Order 2222 is designed to create, Dennis said.

On this front, CAISO’s proposal is actually better than PJM’s, according to Dennis, since CAISO allows aggregations at a much larger scale: the two dozen sub-load aggregation points, or sub-LAPs, that the state’s grid is broken into. Those grid regions serve an average of 1 gigawatt of load apiece, making for a much more open field of play for aggregators, he said.

Digging in on distribution-related issues

These aforementioned issues exist on the transmission-grid side of the DER energy market equation. Where things start to get really complicated is where FERC Order 2222 pushes beyond that boundary and into the grid networks that carry power from transmission substations to customers — and into the domain of state regulators and the utilities that operate those networks.

A big job for utilities

Order 2222 does make it clear that states and utilities retain authority over the processes that allow DERs to be connected to the grid and oversee whether they’re operating safely once they’re hooked up to it. The order also requires grid operators to coordinate DER energy market activities with the utilities that have to manage how lots of batteries, EV chargers or controllable loads responding to wholesale market opportunities will affect the flow of power on those circuits.

But that’s a major lift for utilities, even those that have been investing heavily in technology to monitor and manage DERs, Wood Mackenzie’s Hertz-Shargel said. 

“There’s a lot of work in registering these aggregations, doing day-ahead and real-time coordination,” and potentially stepping in to override DERs when their actions could threaten grid stability, he said. ​“Who’s going to pay for it? Are [utilities] going to rate-base the costs? Or is it more fair that they’re borne by the DER participants?”

These questions and others like them are at the heart of two studies released this year: a joint report from AEE and nonprofit think tank GridLab, and a report from the nonprofit technical consultancy Energy Systems Integration Group. The ESIG report itemizes some of the key tasks that state regulators and utilities will need to take on to make sure they’re ready for Order 2222 compliance, shown in the following table.

The report from AEE and GridLab highlights the ​“unprecedented coordination” between grid operators, utilities and aggregators that will eventually be needed to manage DERs under Order 2222; it acknowledges that the technologies and methods to manage that coordination haven’t yet been put in place. But it also emphasizes that the need for full-scale coordination will increase over time as DERs grow in scale, which allows for a phased approach to managing them.

In the nearer term, however, proponents of distributed energy are more focused on another facet of the transmission-distribution divide: how to set the appropriate boundaries between state and federal jurisdiction over what DERs are allowed to do and how they are paid for those activities.

Dealing with the ​“double-counting” problem 

The concept of double-counting plays a large role in this discussion. ​“Double-counting” refers to paying for the same thing twice — for example, allowing a DER aggregation to receive both wholesale market compensation and payments from a state-approved, utility-administered retail program for performing the same action.

Earning retail payments could allow DER aggregations to subsidize lower-priced bids into wholesale markets, which would be unfair to other market participants and undermine the price-discovery role that the markets are supposed to serve. States also want to limit the risk of double-counting to reduce the costs borne by state budgets or utility ratepayer-funded programs meant to support DERs.

But DER supporters say that some of the double-counting restrictions being proposed by grid operators could cross the line into preventing DER aggregations from earning fair compensation for retail-level participation. CPower’s Jennifer Chamberlin cited CAISO’s 24/7 settlement requirement as an extreme version of taking the goal of preventing double-counting too far.

“There’s a lot of local value in DERs that can be provided at the same time you’re providing wholesale market services,” she said. ​“It’s definitely not appropriate to be paid twice for the same service. But if you can offer multiple values during the same time period” — say, by reducing systemwide demand on the transmission grid and helping a utility reduce strain on local distribution circuits — ​“the unilateral removal of that [revenue stream] is a little inappropriate.”

AEE’s Dennis also cited examples of what he described as misapplications of the double-counting concept. For example, some grid operators are proposing to prohibit DERs that earn net-metering compensation from utilities — a category that includes many rooftop-solar-connected batteries in states such as California — from participating in wholesale energy markets, he said.

But it’s not clear that the money earned by customers for feeding their excess solar generation to the grid represents a direct one-for-one equivalent to the value that solar-charged batteries could provide stressed-out transmission networks by reducing household grid demand or feeding power to the grid at times of peak demand, he said. A blanket ban against any participation of those resources might not only be unfair but also restrict a major class of resources in the country’s fastest-growing DER markets, according to Dennis.

PJM’s Order 2222 compliance plan attempts to address this complex issue, he said. PJM got rid of its initial proposal to ban net-metered resources from participating in its energy and capacity market, and replaced it with a process that will task utilities with determining whether the resources in question are in fact being compensated for their energy or capacity benefits, he said.

Who gets to set the rules for DERs?

Of course, this raises another uncomfortable set of disputes between DER supporters and utilities: Who’s in charge of deciding the ways DERs are and aren’t allowed to participate in wholesale energy markets?

U.S. utilities have a long history of opposing solar net-metering policies and have at times sought to block customers from interconnecting batteries to those solar systems or to make it more costly to add batteries. But utilities also have the responsibility to ensure that DERs being added to their grids won’t cause safety or reliability problems, which involves investing time and spending money to examine interconnection requests.

Hertz-Shargel said that FERC Order 2222 gives precedence to state-level policies on DER interconnection, which is actually a lower-cost and less complicated process than the FERC-jurisdictional interconnection processes that grid operators use. ​“But now, of course, you have to realize that the jurisdiction you’re in will determine the wait and cost you’re dealing with,” he said.

Dennis noted that the Order 2222 compliance filings submitted so far have yet to lay out many specifics on how grid operators might interact with utilities in reviewing and registering DERs for wholesale market participation.

“There are still ambiguities about how that process would work, how transparent it will be and what the dispute resolution process will work like,” he said. ​“That’s an item that FERC will need to pay particular attention to. […] This is an area where jurisdiction overlaps.”

All together now

To successfully carry out FERC Order 2222, DER aggregators, utilities, grid operators and regulators at the state and federal levels must all come together to work through the complications.

Dennis doesn’t assume that utilities will necessarily oppose working on solutions to get DERs interconnected and supporting the grid. After all, ​“there are many utilities that look at Order 2222 and say, ​‘My customers want access to DERs. They also want to work with aggregators to access those markets. How do I become a platform for that?’”

Hertz-Shargel agreed that the various parties all have a big interest in figuring out DER integration. ​“When the intermittency of renewables, outages and weather are going to happen all the time, we need to all be participating and modulating energy regularly,” he said. ​“The entire industry needs to find a way to get customers and businesses off the sideline on a day-to-day basis and to be more grid-responsive.”

There’s a lot at stake. Distributed solar and batteries, smart-charging electric vehicles, and homes and businesses that can reduce and shift their energy use are all vital tools for balancing a high-renewables grid in a cost-effective way. The trick will be finding the best ways to pay for that value. 

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This column is sponsored by CPower. CPower is a leading national energy solutions provider guiding customers toward a clean and dependable energy future. We maximize the value of our customers’ DERs by facilitating and optimizing participation in demand-side management programs, forming virtual power plants that are good for the grid and great for the community. CPower works with over 11,000 sites across North America to provide superior economics while delivering the highest-rated customer experience in the industry.