Yes, the Inflation Reduction Act passed — hooray! — which is transformative for the U.S. solar industry. Now it’s time for ISOs/RTOs to implement FERC Order 2222. Here is a peek at an article from our Q3 edition, sizing up some of the opportunities and challenges that lay ahead for solar + storage in the wholesale market. Be sure to subscribe (print, digital or both) for free today.
Solar PV customers are increasingly being spotlighted as prime candidates for many other electrification upgrades and grid services, mostly involving load shifting and demand response (DR). The spotlight is shining especially bright for two reasons:
- Technology integrations. Load control software providers are integrating with every smart home device there is, from thermostats to EV chargers to, most importantly, energy storage systems. After adding battery storage to a PV system to better manage home electric bills and/or provide backup, that system can be aggregated with thousands of others and be called upon by grid operators to perform a variety of services.
- Regulatory changes. The Federal Energy Regulatory Commission (FERC) issued Order 2222 in 2019 to open up the wholesale energy market to all of that cool tech tied to distributed energy resources (DER) in order to alleviate grid congestion, modernize a fossil-fuel-heavy electricity mix and compensate all of these DER owners accordingly
Unfortunately, beyond the spotlight, looming in the rafters, are the independent system operators (ISOs) and regional transmission organizations (RTOs) that have to revise their policies and procedures to implement the promise of FERC Order 2222. Will they?
FERC Order No. 2222 is the pathway to greater wholesale market participation and compensation for distributed energy resources (DER). It was ordered to reduce the barriers for DER to access RTO/ISO markets and includes energy storage, distributed generation, demand response, energy efficiency, thermal storage and electric vehicles. Wholesale market participation/compensation complements other values and revenue streams that DERs currently access (customer benefits, retail programs). This means:
- Customers can deploy DERs more affordably because DERs receive compensation for all the services they can provide.
- DERs already being deployed add more value to the grid by offering all the services they are technically capable of providing.
- DERs are deployed more rapidly and more efficiently because they are responding to transparent market signals.
- Reliability improves because grid operators gain visibility and control as DERs participate in wholesale markets.
- Wholesale competition is enhanced as DERs participate.
Likely near-term use cases
- Frequently dispatched DERs — electric buses, battery storage
- Residential demand response and energy efficiency, like smart thermostats
- Residential behind-the-meter and EVs
- Front-of-the-meter distribution connected resources.
Key compliance requirements
- Eligibility of DER aggregators and DER types. DER aggregators must be eligible market participants; RTOs/ISOs must allow all technology types and multi-technology combinations; rules must prevent “double counting” in retail and wholesale markets; no broad state “opt-out.”
- Geographic scope of aggregation. Encourages broad geographic scope of aggregation, but allows RTOs/ISOs to propose to limit aggregations to a single pricing node.
- Distribution factors and bidding parameters. Must account for physical and operational characteristics of DER aggregations and ensure they are able to fully offer their aggregations into RTO/ISO markets.
- Information and data. RTOs/ISOs are required to transparently state the information and data that DER aggregators must provide them about the performance, physical parameters and components of their aggregations.
- Metering and telemetry. RTOs/ISOs have flexibility to set these, including whether to require metering and telemetry of individual DER; must justify why they are necessary and explain why they do not result in undue barriers to participation.
- Coordination. RTOs/ISOs are required to establish procedures for coordination between RTOs/ISOs, DER aggregators, distribution utilities and state and local regulators.
(click ^ to expand for more info on FERC 2222 if needed)
In this edition of the Buzz, we’ll give an overview of the opportunities and challenges. First, let’s dream a little.
Additions by reduction
This summer, RTOs including the Midcontinent Independent System Operator (MISO), California Independent System Operator (CAISO) and the Electric Reliability Council of Texas (ERCOT) issued warnings to energy customers in anticipation of grid capacity shortages. ERCOT has already issued two warnings and asked people to conserve power.
These warnings are one reason DR is particularly in vogue right now. DR is nothing new, but after early DR utility programs dragged the concept through the mud for many homeowners, tech companies have cleaned it up and repackaged it. Leap and OhmConnect are two examples of new school DR providers. They integrate with various smart home hardware and software companies to amass arsenals of DER that can be dispatched in all sorts of clever combinations.
“There are now millions of smart devices in homes and businesses that can serve as grid resources,” said Connor Waldoch, senior manager of policy and regulatory affairs at Leap. “We’re making it easy for technology providers to connect their networks of DERs to wholesale energy markets and get paid for providing flexible support to the grid. By aggregating these resources, we’re creating virtual power plants [VPPs] — a modern solution to balance the grid.”
Leap sits in the middle of a tech provider and its customer network, and it does the heavy lifting to set up grid service revenue opportunities by aggregating those customers together. Last year, Leap partnered with Optiwatt, which manages EV charge times, and in June, Leap partnered with Lumin, a smart circuit hardware / software provider. Lumin has gained traction in the solar + storage market by being paired with systems as a load manager and to facilitate simpler battery storage installations (by helping to avoid a subpanel installation). Thanks to Leap, Lumin customers in California can now enroll selected loads — EV chargers, pool pumps, HVAC and so on — and create schedules for bidding that capacity as DR.
Lumin is still learning how much customers can earn from this, but early estimates are $200 to $400 in an average year. That figure does not include any benefits from battery storage (we’ll get to that later).
“The old DR kill switch lacked any data,” says Alex Bazhinov, founder and CEO of Lumin. “They just deployed a radio signal. We’re adding a real time data component, which is telling the utility ‘you may want to turn off that HVAC but really you want to turn off the pool pump, which will have a better impact now than HVAC.’”
The consumer-first focus in today’s DR programs is important. OhmConnect takes a gamified approach to engage users and respond to grid events, paying households to reduce electricity usage during times of peak demand. OhmConnect is currently integrated with appliances and devices from 30 companies, which includes SunPower and its batteries as of March (SunPower also became an investor). OhmConnect recently banked a $55 million Series D funding round.
“Customers decide when they’d like to participate in DR events — or Ohmhours — and can opt out for certain devices or overall,” says Cisco DeVries, CEO at OhmConnect. “We leave each customer in control of their home energy use. Most people will allow us to control their smart energy devices, but some do like to actively participate in the events themselves.”
OhmConnect is approved to provide about 150 MW to the California grid at peak during summer. “We were the first to do this,” DeVries tells us. “We’ll say, ‘we have 50 MW available,’ they show us the price and we get dispatched instead of a powerplant turning on. We can take 200,000 California homes, get them directly to reduce their use from what they normally would use based on their profile, and then make sure we come up with the right amount of MWs for the grid at that time.”
The peak use case
Now, let’s add batteries to the mix.
Traditional DR means you are turning demand down. With solar and batteries, you aren’t turning demand down, but instead feeding the grid what’s in that battery.
“That core functionality has to be kept in mind because most batteries can be around 5 kW of power, and at any time an average home is using maybe 2 or 3 kW? So, you have about half of that battery ready to deploy for a neighbor,” says Chris Rauscher, senior director, market development and policy at Sunrun.
The opportunity is literally world changing. In August 2020, during California’s first rolling blackouts since 2001, solar + storage owners provided more than 300 MW of power to the electricity grid, the same amount of energy as a gas-fired power plant, making the blackouts less severe.
Sunrun has 12 home battery programs across California, Hawaii, New York, Massachusetts and other states in the Northeast to use battery capacity to reduce the severity of grid shortages and blackouts. New England provides the best example of how these programs can benefit the grid and battery owners. National Grid’s Bring Your Own Device (BYOD) program launched five years ago to use home battery capacity on the grid. The batteries are treated as traditional DR and funded out of the energy efficiency budget. The program recognizes the value of batteries and credits battery owners for any energy that crosses the inverter during the grid event — whether it goes to reduce load or injects to the grid.
A homeowner with one or two batteries could see annual payments in the range of $1,000 to $3,000.
“And then with the F-150 Lightning — that’s the size of 10 Tesla Powerwalls — you can multiply that program value by 5 or 10 depending on the performance and the resource available to grid operators from these trucks,” Rauscher notes. Sunrun is the official solar installer for Ford’s highly anticipated electric truck.
Sunrun also bid into the ISO-NE wholesale market three years ago and its VPP is operational this summer — making it the first residential VPP operational in a wholesale market in the country. With more than 150 MW of battery capacity standing by across the United States, though, these Sunrun programs barely scratch the surface.
The picture painted here is alluring. So much can be accomplished for so many, nearly at the flip of a switch, just by orchestrating a dance of DER.
“If I was a solar installer, I would really start to look at how to create an offering that helps take advantage of these regulatory changes already in the works,” Bazhinov says. “NEM is no longer a sure thing, and that may be OK. There may be fuller monetization options out there that work on a market value.”
That’s what I was initially thinking too. Unfortunately, the implementation of FERC Order 2222 is no sure thing either.
“We don’t think FERC 2222 compliance filings have met the spirit of the 2222 order, nor do we think they’ve met the letter of it either,” Rauscher says. “We’ll see what FERC does in the final decision but 2222 was meant to open up these markets for DER aggregations of all types and these filings do not do that.
FERC order poo-pooed
The dream of selling energy from a battery on the wholesale market is that those electrons will be assessed their real market value in time and space while offering the grid valuable relief.
FERC Order 2222 had the overt intention of making that dream a reality, and with good reason: Those grid services will only become more important over time as the country moves to electrify everything while reducing fossil fuel use. All of these DER assets are here and more are coming. Let’s add to the value stack and use them.
Unfortunately, based on the filings from ISOs/RTOs thus far, you’ll want to grab a pillow and keep dreaming for a bit.
Without getting too deep in the weeds, here is just a sample of the complications.
The MISO region has an opt-out provision for DR, which 13 of its 15 states have used to block its adoption. MISO is proposing delaying DR implementation until 2030.
“That would take longer than a mission to Mars, yet 95 percent of what’s needed to implement 2222 exists today,” says Greg Dixon, CEO of Voltus, on an Advanced Energy Economy (AEE) webinar discussing this topic. “The remaining elements just require a set of creative IT solutions.”
PJM, MISO and SPP have all proposed single node aggregations.
FERC 2222 directed RTOs/ISOs to ensure that locational requirements are “as geographically broad as technically feasible.” But it allows RTOs/ISOs to propose limits on aggregations to a single pricing node, which PJM, MISO and SPP have all done. This matters because under FERC, these DER aggregations must hit a minimum of 100 kW.
“As the size of the pricing node shrinks, so does the number of ways that an aggregation can be created,” says Tamara Dzubay, senior manager, regulatory affairs and emerging markets with ecobee, explaining this complex subject on that AEE webinar. “With stringent metering requirements and stringent locational requirements, aggregators could have a problem meeting the 100-kW mark and leave assets stranded.”
This could also add a prohibitive administrative burden because aggregators will have more small aggregations rather than fewer bigger ones.
Solutions to this include: 1) enabling multi-nodal aggregations and 2) where single pricing node aggregations have been proposed, identifying aggregation zones where there are multiple price nodes with minimal congestion. CAISO, for example, allows aggregations within a sub-load aggregation point, which each serves about 1 GW of load.
Dual participation isn’t being addressed.
Dual participation is the ability to participate in both wholesale and retail programs as long as an asset owner is not receiving compensation for the same services as part of another program.
FERC required RTOs and ISOs to “allow DERs that participate in one or more retail programs to participate in its wholesale markets,” while allowing “appropriate restrictions” that are “narrowly designed to avoid counting more than once the services provided by distributed energy resources in RTO/ISO markets.”
ISO-NE has a great pathway to dual participation in its model for residential resources. Net metered solar with a battery or bidirectional EV can be dispatched for the ISO-NE capacity market but will not receive energy market revenues, which is fine for home solar owners as long as their excess generation (solar) still benefits from the retail program as usual.
“One reason that pathway exists is we are not subject to baseline because we have solar + a battery that’s measured at the inverter — whether it goes to reduce load in home or goes to the grid, we receive performance credit for that,” Rauscher says. “For batteries, getting away from baselining is the way to recognize the operational characteristics of batteries and the value they can provide.”
That pathway does not exist in other ISOs or RTOs around the country. In PJM, if you want to participate in the capacity market you must also be in the energy market.
“We’re not likely to see DER aggregations economically or operationally feasible if they can only participate in wholesale markets,” Rauscher says. “We have not seen that addressed in adequate ways in some of the compliance filings. This is important to note because solar is receiving revenue from net metering, offsetting load on the site, and the batteries or EVs are being dispatched for the capacity market. Some of the markets are looking at a battery, paired with net metered solar, as not being able to participate in wholesale market because of retail compensation, and we think that’s out of step with the spirit of 2222.
“If a small PV system was on the same site as a bidirectional truck, for example, for some of the markets, they would not allow the truck any capacity participation, and the trucks would provide zero value to the grid. That doesn’t make sense and isn’t consistent with 2222.”
Lack of viable submetering pathway.
Metering requirements are all over the place across RTOs/ISOs. Some require metering at the aggregation level only, others require data from individual DER. Granularity of metering data ranges from one-minute to one-hour requirements depending on the ISO.
Here is ISO-NE’s big short-coming, according to AEE. FERC Order 2222 says metering for DERs must be located at the retail delivery point (RDP), aka the customer meter, or at the point of interconnection for front-of-the-meter projects unless the host utility signs off on metering at the submeter.
ISO-NE (and PJM) will not allow customers to use embedded DER metering to measure performance. Additionally, ISO-NE will only allow for submetering if the host utility can accommodate it or parallel metering must be installed, except in the case of certain residential aggregations, like Sunrun’s.
“Utilities in New England have been very clear they cannot and will not sign off on submetering for the foreseeable future,” says Nancy Chafetz, senior director, regulatory and government affairs at CPower. “And most customers in New England do not have interval metering.”
That leaves parallel metering, which means customers must install interval metering at their retail delivery point (RDP). This is a cost prohibitive expense and inefficient considering the DER equipment has embedded metering. Chafetz believes this conflicts with 2222’s caveat that requirements cannot pose an “unnecessary and undue barrier to individual energy resources joining a distributed energy source aggregation,” and also noted that “metering and telemetry systems are often expensive, potentially creating a burden for small DER.”
“The other big problem with parallel metering is you are electrically separating the customer load from the DER, so you can no longer get any benefit from the DER,” Chafetz says. “You’re not reducing energy costs. You’re not managing demand charges because it is effectively putting the DER in front of the meter. Most customers are not putting in a DER just to participate in the ISO market.”
One fix Chafetz recommends is to allow load reduction to be measured at the device, or to allow for third-party metering like NYISO.
Sheesh. Got all of that?
That is just a sample of the issues solar and storage companies are finding in the filings. FERC is now reviewing all of the filings and can accept, reject or accept/reject in part. If anything is rejected, the ISO has to make a new filing. FERC will then issue decisions on the compliance filings. Then years down the road those plans will be implemented. Even in best case scenarios, much of Order 2222 is still many years away.
Why give a FERC?
This push for swift and DER-friendly FERC rule implementation isn’t some whiny power-grab by solar and storage companies. Studies are showing a DER-centric grid would be a huge economic boost as well as a technological advantage.
In its Distribution System Operator with Transactive (DSO+T) study, Pacific Northwest National Laboratory (PNNL) researchers analyzed the impact and value transactive energy capabilities can deliver if deployed at scale and managed in an intelligent and coordinated manner. Their findings show serious value for every stakeholder.
- Customer electric bills would be reduced by up to 17% for participants, and by 10% for non-participants, in a moderate renewables case.
- A transactive retail market showed a net economic benefit to a region the size of Texas of $3.3 billion to $5 billion (12 to 19 percent of total cost of electricity) per year depending on future renewable, DER, infrastructure growth, and market price scenarios.
“Given that ERCOT is approximately 10 percent of the national electrical load, we project a national benefit of $33 billion to $50 billion per year associated with the large-scale coordination of flexible distributed assets,” the analysts stated.
Most of the savings would result from lower capacity payments to hold generation capacity in reserve to meet peak load. Reserve capacity can help prevent steep increases in wholesale energy prices when power demand surges or when many generators go offline. The demand flexibility from real-time pricing would reduce peak load, reducing the need for reserve capacity and the amount of capacity payments, the study found. Additional savings would result from lower wholesale energy prices and greater consumption of energy when prices are lowest, like at times of high renewable generation.
Action items for today
OK, FERC dream bubble popped (for now). Back here on solid ground, you can still provide cool add-ons for your customers that could pay bigger dividends later.
Down the road, Lumin will start to present grid mix information. If the grid is sourcing an especially dirty fossil fuel mix at any particular time, customers could enroll to shave demand at those times or to meet certain personal carbon footprint markers. Lumin also has a more modular unit coming, Lumin Edge, that will only cost about $250 to cover one circuit. Each additional circuit is around $50. For about $500, your customers could control every major appliance in their house.
OhmConnect customers, in addition to any savings, receive “watts,” which function like reward points, to be redeemed for cash, more home automation devices, gift cards to Amazon or Walmart, or even money sent as a donation to a charity. Now tied to SunPower batteries in select states, these rewards could weirdly be a bigger selling point than anything we’ve already discussed.
“Surprisingly many people want a gift card, so we added tons of new gift cards,” DeVries says. “We’re constantly having an ongoing discussion with customers to understand what they are looking for.”
CalChoice, a California joint powers authority, just established fixed rates to purchase power from Leap’s DER aggregation during periods of high demand. Leap and CalChoice determine the days and times when wholesale energy prices are expected to be highest for users, and partners leverage Leap’s analytics to lock in energy payments for two hour periods, three days a week, during which CalChoice will purchase this power at the predetermined price. This seasonal program began in June and will run through October.
On the regulatory side, nothing is stopping interested utilities from implementing their own VPP pilot programs right now. Vermont’s boutique utility Green Mountain Power seemingly pilots a new future-focused idea every other day. Utilities, when motivated, can move much quicker than any FERC filing. While tedious, this is where Sunrun is seeing results.
“There are lot of utilities that think this stuff is theoretical, complex, and we need smart meters first and all of this software, but that’s not true,” Rauscher says, citing the utilities in Massachusetts that have being doing peak reduction with an army of aggregated home batteries for five years. No smart meters, just a contract with a third party for their software and batteries set to deploy on a timer.
“Utilities know when their peak times are — they have that data,” he notes. “We give performance data afterward, and they’ll pay the customer. They could cookie cutter this throughout the country, and that would be huge effort for combating these reliability issues.”
Chris Crowell is the editor of Solar Builder.