Fewer Wires, More Power, Big Problems?

Rolling blackouts—that was a prospect many faced as the United States simmered during the summer of 2022, the hottest on record. To make the electrical grid more robust without being cost prohibitive, many clean energy advocates are pushing for widespread adoption of distributed energy resources (DERs): devices that, when commanded, can inject power into a grid, absorb power from it, or modulate a load’s power consumption. How could DERs help, and will regulatory fights kill them in their infancy?

Distributed networks, like those that allow us to use cell phones and the Internet, support a host of services: online shopping, cloud storage, ride share, electronic payments, vacation rentals, and more. And it’s not just computers and phones—the operators of our electrical grids also use networking technologies to ensure that power supplied to homes and businesses always matches demand.

But as they exist today, many grids can’t deliver the energy needed for critical services, such as maintaining power to homes and hospitals during heat waves and cold snaps—and this problem will only get worse as the country shifts toward electrifying its cars, buildings, and industry. One possible solution is to build more of what we have now: large power plants, long-distance transmission lines, and local distribution stations. But this is expensive, and in some parts of the country (especially on the East Coast), even if new power plants are built, it could still take years to connect them to the grid.

A less costly approach is to fortify our grids using networked groups of DERs. Given the advanced state of networking technology, some might claim that aggregating DERs to stabilize the grid and lower costs for consumers is an easy task.

But the energy world has its bickering tribes, like the rest of society; and regulatory issues associated with DERs may be insurmountable. The Federal Energy Regulatory Commission’s (FERC) Order 2222—which requires most electrical grid operators to make wholesale energy markets available to DER aggregators that can supply at least 100 kilowatts (kW) of power—has created a firestorm of controversy, with clean energy advocates pushing to remove nearly all restrictions on aggregated DERs, and utilities and grid operators fighting to maintain a system that is closer to the status quo. How these disputes play out could have life or death consequences as extreme weather events become more common.

Control of the Electrical Grid(s)

Electrical grids—the machines that supply power to most people in the country—have physical, digital/control, and market-related components. The physical portions of the grid include things that we can see: generation equipment (traditionally large coal, nuclear, gas, or hydroelectric power plants), transmission equipment (including high-voltage wires that carry power away from the generation plants), and distribution equipment (electrical substations that step down the voltage plus lower-voltage wires that carry power to homes and businesses).

A grid’s digital/control components are designed to keep it operating within its limits while delivering power that consumers demand. These include electronics and software that track market transactions, monitor the health of the physical components, and control the location and timing of power flows (matching supply with demand in real time). But it’s not always possible to successfully match supply with demand, especially when temperatures are extreme. If demand exceeds supply (or if it exceeds the grid equipment’s ability to transmit the demanded power), the digital/control components will shut the power off to prevent the grid equipment from destroying itself. This happened in early 2021, when a winter storm pounded the state of Texas, leaving “millions freezing in the dark.” Patrick Svitek, Texas Puts Final Estimate of Winter Storm Death Toll at 246, Tex. Trib., Jan. 2, 2022. It happened again in the summer of 2022, when Texas and California faced rolling blackouts as hot weather and high demand pushed portions of the grid to their limits and beyond.

Grid operators in certain parts of the country also use wholesale energy markets (that is, markets where electricity distributors purchase electricity and other services from the entities that generate electricity) to match supply with demand. These commonly include separate markets for energy, capacity (ability to provide power at a specific time), and ancillary services (functions that serve to stabilize the grid, such as frequency and voltage regulation).

In response to FERC Orders issued in the 1990s, regional aggregations of power generators and utilities called “independent system operators” (ISOs) and “regional transmission operators” (RTOs) began to manage these wholesale markets. Six of these operators are subject to FERC jurisdiction: California Independent System Operator (CAISO), Southwest Power Pool (SPP), Independent System Operator–New England (ISO-NE), New York Independent System Operator (NYISO), Midcontinent Independent System Operator (MISO), and Pennsylvania–New Jersey–Maryland Interconnection (PJM). (Download Regional Transmission Organizations Map (FERC, 2015).)

Although unshaded portions of the above map include no ISOs or RTOs, the Commission does have jurisdiction to regulate interstate wholesale power sales and transmission within these areas. Finally, the map shows three other grid operators—the Electric Reliability Council of Texas (ERCOT) and two in Canada, which are not subject to FERC jurisdiction.

Grid-Connected “Battery” Participation in Wholesale Markets

In its role as regulator of interstate electricity markets, FERC has issued orders to ensure that consumers benefit—both financially and in improved quality of service—from advances in grid technology. One example of this took place in 2018, when the Commission issued Order 841, which required the six grid operators under its jurisdiction (the RTO/ISO markets) to revise their tariffs and make other changes that would allow certain energy storage resources (ESRs)—essentially batteries that can both store energy from and inject energy into the grid—to participate in wholesale electricity markets. In the Order, FERC said that existing market rules (which were designed for traditional, large power generation plants) presented barriers to electric storage resources in those markets, reducing competition and hurting consumers.

The RTO/ISO markets did not object to allowing large ESRs to inject power into interstate transmission (high-voltage) grids. But an aligned trade organization called the National Association of Regulatory Utility Commissioners (NARUC) argued in a Request for Clarification and Rehearing (Docket Nos. RM16-23-000 and AD16-2-000) that local ESRs that have no effect on interstate commerce—those that operate at the distribution (front of meter) level or home/business (behind the meter) level—are much more difficult to predict and manage. According to NARUC, state regulators should be able to ban such local ESRs from participating in the relevant wholesale energy, capacity, and ancillary services markets, and FERC exceeded its jurisdiction by prohibiting states from doing this.

After the Commission declined the Request, NARUC filed a petition with the U.S. Court of Appeals for the District of Columbia Circuit. The appeals court sided with FERC, concluding that the Commission’s “prohibition of state-imposed participation bans directly affects . . . rates” in the interstate wholesale electricity markets, and that FERC was within its authority (under the Federal Power Act) to issue the Order. Nat’l Ass’n of Regulatory Comm’rs v. FERC, 964 F.3d 1177 (D.C. Cir. 2020).

The impact of Order 841 is not simply limited to keeping rates low. Then-FERC Chairman Neil Chatterjee celebrated the D.C. Circuit’s decision by claiming that the Order “will be seen as the single most important act we could take to ensure a smooth transition to a new clean energy future.” He expressed this view because wind, solar, and other clean energy sources are intermittent. Large, grid-connected batteries, made economically viable by Order 841, could store excess energy generated when it’s windy and sunny, then deliver that power to the grid later, reducing the need to rely on power plants that spew soot and carbon dioxide.

Next for FERC: Order 2222 and Aggregated DERs

FERC’s victory in the Order 841 litigation—and the court’s clarification of the Commission’s jurisdiction—spurred the agency to take further action in the form of Order 2222. This Order requires regional grid operators to allow entities that control aggregations of distributed energy resources of at least 100 kW (DER aggregators) to participate in the interstate wholesale electricity markets. Footnote 1 of the Order broadly defines a DER as “any resource located on the distribution system, any subsystem thereof or behind a customer meter . . . [such as] electric storage resources, distributed generation, demand response, energy efficiency, thermal storage, and electric vehicles and their supply equipment.”

Why did FERC want to give DER aggregators access to these wholesale electricity markets? To answer this, it’s important to understand what DERs can do, why homes and businesses would want them, and the value they can add to the grid. Although there are many types of DERs, they generally perform one or more of the following functions: absorbing power from the grid, injecting power back into it, or modulating the amount of power drawn from it. Three important types of DERs are (1) batteries/ESRs, (2) distributed generation, and (3) demand response programs.

Batteries/ESRs

Tesla’s Powerwall and Sunrun’s Brightbox are two examples of grid-connected, behind-the-meter batteries. One of the functions batteries perform is simple: They store energy from the grid (or from another source of energy, such as co-located solar panels) and discharge that energy later to wherever it is needed. Historically, their owners used these batteries as backup during power failures or to save money by drawing power from them when grid electricity prices are high. But with the development of networking technology, companies like Tesla and Sunrun can aggregate and control thousands of batteries as if they were a single, large power plant. These virtual power plants (VPPs) have begun to operate in markets where local utilities have allowed them. And participating as a part of a VPP can be quite lucrative: A program in California offers Tesla Powerwall owners $2 per kilowatt hour (kWh)—far higher than the typical kWh rate of between 20 and 50 cents—to supply power during periods of grid stress, such as when CAISO issues an energy alert, warning, or emergency.

Distributed Generation

Distributed generation takes many forms, the most common of which is rooftop solar. Currently, many users of these systems view them as a money-saving tool that enables them to participate in local retail “net metering” programs. Those with solar arrays can sell excess power into the grid at the same price they would pay a utility. But as with grid-connected batteries, aggregators can control hundreds or thousands of rooftop arrays to form VPPs that send power into the grid when it’s needed, such as during extreme weather events.

Demand Response

Finally, demand response programs pay homes and businesses that participate in these programs to reduce their energy use when the grid is under stress. For example, during a heat wave, a utility might send electronic commands to a factory, instructing it to cut its electric load by 10 kW for the next two hours. In response to the commands, equipment at the factory would automatically cut its electric load by the requested amount, and the factory owner would be compensated for this.

It’s important to note that these three types of DERs—batteries, distributed generation, and demand response—may overlap in their functionality. For instance, distributed generation and batteries could participate in demand response programs by (at least partially) powering a home or business during times of peak demand. This way, even if the home uses the same amount of power, the net power taken from the grid decreases.

The value of a DER depends on where, when, and how it is used. DERs can serve multiple purposes and provide value that is both time and location dependent. For instance, if a rooftop solar array feeds power into the grid on a sunny, cool day, the only real benefit is to the array’s owner, who is compensated under a retail net energy metering program. But if power use spikes during a heat wave, aggregations of DERs can inject power into the grid (like solar and batteries) or reduce power consumption (like demand response), or both, which could make the difference between grid stability and blackouts.

But, again, why is FERC forcing grid operators to allow DER aggregations to participate in interstate wholesale energy markets? Order 2222 itself says the reason for the change is to increase competition in those markets and ensure just and reasonable rates. Others see grid stability and lowering the grid’s overall carbon footprint as more important advantages. But whether any of those benefits come to pass depends on how FERC reacts to the wildly varying compliance plans submitted by the RTO/ISO markets.

The Tea on 2222

The number of disputes over Order 2222 are numerous; this article can only cover a small fraction. In interviews, industry insiders shared their views on how the Order will ultimately impact the power markets. For example, Gregg Dixon, chief executive officer of Voltus (a DER aggregator), said that Order 2222 is “the most important FERC Order of all time” because, as he explained, it could help unleash hundreds of gigawatts of energy resources that are now “lying fallow.” Interview with Gregg Dixon, CEO of Voltus (July 1, 2022) (notes on file with the author). In other words, DERs purchased by homes or businesses for one purpose (like battery backup power) could earn their keep performing other functions, like selling into energy or capacity markets. Dixon is likely supportive because his company, which he calls “Airbnb for DERs,” will help them do it. Id.

But as with everything else, Mr. Dixon indicated, the devil is in the details. And in these details, he advised that FERC has given the regional grid operators so much leeway in establishing their compliance plans that DER aggregators may have no economically viable path to participate in the wholesale energy markets. Id.

One example of this is MISO, which has claimed that incorporating thousands of DERs into its grid is so complex—and could lead to such severe safety and reliability problems—that it won’t be able to comply with the Order until nearly 2030. But according to Mr. Dixon, this is not true because “95% of what we need [grid networking technology] exists now,” and, as he explained, the rest is IT/networking technology that already exists in other areas. Id. In response to MISO’s concerns about safety and reliability, Voltus requested that FERC hold a technical conference to educate the grid operators on how simple it would be to incorporate DER aggregations into their grids—and how those extra resources could benefit the grid operators, the utilities, and the ratepayers they both serve. The RTO/ISO markets have opposed this conference (at least its timing), and as of early December 2022, the Commission has not ruled on Voltus’s request.

Mr. Dixon claims that the real problems faced by grid operators (and the utilities that strongly influence them) are financial rather than technical. Utilities, he says, make money in part by “selling megawatt hours” (energy) and want “as simple a market as possible.” Because widely deployed DERs typically mean that a utility will sell less energy, Dixon says they “pose a fundamental threat to their business model.” Id.

His claim may be overstating the case a bit. After all, at least CAISO and ISO–New England have programs (independent of Order 2222) that allow Tesla’s and Sunrun’s VPPs to supply power—and be paid handsomely—during grid emergencies.

Others agree with Mr. Dixon that the grid operators’ plans for integrating DERs could make everyone worse off. One of his supporters is Nancy Chafetz, the Senior Director of Regulatory and Government Affairs at CPower, a company that manages demand response and other DER resources. Ms. Chafetz advised that ISO-NE’s 2222 compliance plan places such stringent metering and telemetry requirements on behind-the-meter DERs that it’s unlikely any aggregation of such resources will ever participate in that grid operator’s wholesale energy markets. Interview with Nancy Chafetz, Senior Dir. of Regul. & Gov’t Affs., CPower (July 7, 2022) (notes on file with the author). According to Ms. Chafetz, this hurts the region’s grid operator because there are already numerous DERs installed in New England, and others will likely be added soon to take advantage of existing retail (utility-level) programs for these distributed resources. Without visibility into the number and characteristics of those DERs—which will affect grid demand and performance—ISO-NE is essentially flying blind and will have to base its grid management decisions on guesses rather than real data. She claims this can only hurt the grid operator, especially during times of peak demand. Id.

Others in the field seem to see implementation of Order 2222 as only one alternative—and maybe not the best one—for making money while deploying aggregated DERs. Chris Rauscher, Senior Director of Market Development and Policy at Sunrun, explained that his company’s 2019 agreement with ISO-NE to sell into its wholesale capacity market (to help with peak loads during the summer of 2022) was completely independent of Order 2222 and predated it by about a year. Interview with Chris Rauscher, Senior Dir. of Market Dev. & Pol’y, Sunrun (July 5, 2022) (notes on file with the author). Mr. Rauscher advised that other market developments may ultimately be better options for DER owners and aggregators. One example of this is also in New England, where there are tentative plans to replace ISO-NE’s wholesale capacity market with a forward clean energy market and a carbon price. Such a radically different structure would be a tremendous boon to Sunrun and other companies that control hundreds of megawatts of distributed, zero carbon energy resources.

Mr. Rauscher further explained that when Order 2222 was first issued in 2020, industry was hopeful that it would be a radical shift that would lead to an explosion of DERs. Yet, the grid operators plainly never viewed the Order that way; if they did, they would have submitted compliance proposals that were much more forward-looking and expansive in their scope. Id.

The Remaining Work

Where does this leave DER owners and aggregators? That depends on the market. As mentioned earlier, there are programs in some locations that pay DER owners generously for the value they add to the grid. And in his July 1 interview with the author, Gregg Dixon of Voltus said that Texas grid operator ERCOT—after the catastrophic grid failures of early 2021—“worked to unleash the full power of DERs” by allowing additional distributed energy products to bid into the Texas wholesale energy market, and by increasing price points for all such resources there. There are some early signs of success: During the heat waves of summer 2022, ERCOT was able to avoid rolling blackouts at least in part by paying its large industrial customers to cut their electricity usage during times of peak demand.

Other parts of the world are experimenting with DER aggregations in wholesale markets as well. In Europe, DER aggregations participate in “flexibility” markets for electricity. Orlando Valarezo et al., Analysis of New Flexibility Market Models in Europe, 14 Energies 3521 (June 13, 2021). And in Australia, a nonprofit is working with a utility, DER aggregators, and an energy market operator to develop a new mechanism for DER owners to bid into wholesale markets. David Carroll, AEMO on Target to Trial DER Marketplace Platform,” PV Mag., Sept. 3, 2021.

Perhaps the long-term goal of all these approaches should not be to enable aggregated DERs to participate in wholesale (or retail) markets only to avert catastrophe, but to add enough controllable capacity to the grids so we’re never close to that. Gregg Dixon of Voltus is likely correct that we already have the technology we need. But aligning the financial and policy interests of the aggregators, utilities, and grid operators to make it happen may remain elusive.