Search
`
October 8, 2024

Posted on

SPP Issues Resource Advisory for the Week

[EDITOR’S NOTE: This story has been updated to reflect SPP’s conservative operations declaration Wednesday, June 22.]

SPP issued a resource advisory for its entire 14-state Eastern Interconnection footprint Monday because of higher-than-normal temperatures. The advisory is effective 4 p.m. CT on Tuesday and is expected to end at 8 p.m. Friday.

On Wednesday, the RTO upped the advisory in calling for conservative operations from 10 a.m. to 10 p.m. Wednesday. It said the advisory was declared because of high loads and wind generation’s availability.

Temperatures are forecasted to hit triple digits in Kansas, where heat stress has been blamed for the recent deaths of thousands of cattle.

The advisory does not require the public to conserve energy but does allow the RTO’s balancing authority to use greater unit commitment notification timeframes. That includes making commitments prior to day-ahead market and/or committing resources in reliability status.

SPP issues resource advisories when extreme weather, significant outages, and wind-forecast or load-forecast uncertainty is expected in its reliability coordination service territory. Generation and transmission operators have already been provided instructions on applicable procedures that include reporting any limitations, fuel shortages or concerns.

Conservative operations advisories are issued when weather, environmental, operational, terrorist, cyber or other events require the RTO to operate its system conservatively.

Posted on

Carbon Capture Navigating Path into Clean Energy Mainstream

Energy Secretary Jennifer Granholm came to the Global CCS Institute Forum in D.C. on Thursday to tell a roomful of executives, engineers, financiers and other advocates that the Biden administration is all in on carbon capture and storage (CCS) as a critical technology in the fight against climate change.

Jennifer Granholm 2022-06-16 (RTO Insider LLC) Content.jpgEnergy Secretary Jennifer Granholm | © RTO Insider LLC

“The climate science on this is unequivocal,” Granholm said. “Yes, we need to accelerate clean generation, and yes, we need to decarbonize because the goal of getting to 1.5 degrees Centigrade to meet the Paris Agreement, it just can’t happen without carbon removal. It can’t happen without carbon capture.”

While acknowledging public skepticism about the expense and feasibility of CCS, Granholm argued that “carbon-management technologies offer us tools, and these tools can be helpful or hurtful depending on how carefully or responsibly you can use them.”

Granholm’s use of the term “carbon management” reflects the repositioning of CCS that is underway both within traditional fossil fuel companies and CCS startups bringing their technologies to market, as the industry continues to negotiate a path into the clean energy mainstream. The underlying message at the conference was not if CCS will be effective, functional and affordable, but when that level of development will occur and what’s needed to accelerate the process.

Figures from the International Energy Agency (IEA) show that the existing 27 CCS facilities worldwide have the capacity to take about 40 million tons of CO2 per year out of the air. The industry saw a record growth spurt in 2021 with 97 new projects announced and 66 more in advanced stages of development. But even if all these projects were to come online, the IEA says, they would not provide the 1.7 billion tons of CCS capacity that will be needed by 2030 as a foundation for a global net-zero economy by 2050.

In her keynote at the forum, Granholm focused on the environmental and economic imperatives for CCS. It will decarbonize the “things we cannot live without and yet whose carbon emissions we cannot live with,” such as steel, cement and chemicals, she said.

It will also be a job creator, Granholm said, providing new opportunities for fossil fuel workers and communities that “have powered this nation for over 100 years … and should empower us into the future.”

Jarad Daniels 2022-06-16 (RTO Insider LLC) Content.jpgJarad Daniels, GCSSI CEO | © RTO Insider LLC

But scaling CCS will require both government and industry to step up, said Jarad Daniels, CEO of the Global CCS Institute. Federal programs and incentives are vital “during those first-of-a-kind [projects],” he said. “But it’s really industry and the private sector that are going to get this deployed at commercial scale.”

The Biden administration’s support for CCS includes $12.1 billion in funding for demonstration projects and other research and development activities in the Infrastructure Investment and Jobs Act. Expanding tax credits for CCS — specifically, the 45Q tax credit — is also part of the clean energy incentives the administration and the industry still hope to get through Congress before the upcoming midterm elections.

The energy sector as a whole is also beginning to shift, Daniels said, toward “providing diverse energy services, and it should be [technology] agnostic … as long as it moves toward sustainability” and reducing greenhouse gas emissions.

Traditional oil and gas companies can and should take a leadership role to accelerate the transition “to move away from just the energy sector being based on hydrocarbons to being based on this broader suite of technologies that all have lower carbon footprints,” Daniels said. “They have the infrastructure; they have the balance sheet to allow all of us to work together at scale.”

Occidental Petroleum (NYSE:OXY) CEO Vicki Hollub reminded CCS skeptics that “technology can be improved over time, as we’ve seen in the case for solar and wind. … You can’t make it better until you build the first one and improve it over time,” she said.

With market disruptions from the war in Ukraine, Hollub sees a more pressing question for the industry: how to accelerate the energy transition to meet the 2050 goals of the Paris Agreement, “but also ensure that we’re not putting any countries or regions at risk from a security standpoint and that we’re not leaving … developing countries behind.”

The Last Barrel of Oil

For Hollub the answer is Occidental’s commitment to enhanced oil recovery (EOR): injecting CO2 into existing wells to increase their output, while decreasing the fuel’s carbon footprint.

Traditional extraction methods leave 50 to 60% of oil in the ground, Hollub said. But once injected, CO2 expands into porous rock where oil is trapped, pushing it out and then filling the empty space, which sequesters it “forever,” she said.

Vicki Hollub 2022-06-16 (RTO Insider LLC) Content.jpgOxy CEO Vicki Hollub | © RTO Insider LLC

“It takes more CO2 injected into a reservoir than what the incremental oil that that CO2 generates will emit with use,” Hollub said. “So, you can actually generate net-negative or net-neutral carbon oil from an enhanced oil recovery project.”

Occidental currently has three EOR projects online in the Permian Basin in Texas and is also looking to expand into direct air capture to have enough CO2 for widespread adoption of enhanced recovery. Hollub sees a global market for the technology, especially in developing countries that “have all these resources to develop, so they can achieve the same quality of life we have here in the United States,” she said. “We need to allow them to be able to develop, but in a carbon-neutral way.”

Hollub also anticipates a huge corporate market for EOR. “There are more than 5,000 corporations in the world that have committed to be net zero by 2050,” she said. “And what that means is there are not enough natural ways to sequester CO2, so, we’re going to need carbon capture and sequestration.”  

The goal, she said, is to reduce the carbon footprint of future oil development and production. “The last barrel of oil produced in the world should come from a CO2 enhanced oil recovery reservoir,” she said.

Valuing Carbon

Getting to that last barrel is a matter of both technology and finance, said Jonathan Pershing, environment program director at the William and Flora Hewlett Foundation. Prices must come down, scale must go up, and “somehow, you’ve got to value the carbon,” he said in an afternoon keynote.

Jonathan Pershing 2022-06-16 (RTO Insider LLC) Content.jpgJonathan Pershing, William and Flora Hewlett Foundation | © RTO Insider LLC

“We have to figure out how to bridge the gap between the economic return [on CCS], which is a pretty small share of the total, and the price, which is a much larger number,” Pershing said. At present, he sees prices of $50/ton for industrial CCS and $200/ton for direct air capture as good targets.

Current 45Q tax credits are either below or just equal to those benchmarks — with no direct-pay option — with credits for EOR projects receiving credits starting at $10/metric ton, increasing over time to $35/MT, while the credit for carbon sequestered in salt caverns or other underground formations ranges from $20 to $50.

The incentives proposed in the original Build Back Better Act would have increased tax credits for carbon stored in geological formations to $85/MT, and the credits for direct air capture projects would have jumped to $130 to $180. (See No Net Zero Without Carbon Capture.)

An earlier panel on project finance zeroed in on direct-pay incentives as a key solution to bridging the gap. “Tax credits don’t incentivize because basically no corporations pay taxes … and if they do, they have excess tax credits,” said Jeff Brown, managing director of the Energy Futures Financing Forum. Furthermore, tax credits are not cash, so they cannot be used to pay off debt, he said. (See 3 Keys to Fixing the Cash-flow Dilemma in CO2 Capture.)

Mike Belenkie 2022-06-16 (RTO Insider LLC) Content.jpgEntropy CEO Mike Belenkie | © RTO Insider LLC

But Mike Belenkie, CEO of Canadian startup Entropy Inc., sees a more fundamental problem. However generous, government subsidies and private philanthropy generally result in pilot projects, but climate change is a massive problem requiring more ambitious goals.

“It doesn’t get solved by showing you can do it,” he said. “It gets solved by actually putting a market together, understanding the cost of doing it and doing it.”

Belenkie was one of three startup executives speaking on a panel on the CCS technologies and business models now moving the industry forward. Entropy’s strategy, he said, is to “come up with a full business [model that] can be emulated over and over again around the world and develop a lot of market.”

Putting carbon in the ground “with the lowest possible cost is always going to be the best solution,” Belenkie said. “Avoid pipelines; we do not need a network of pipelines around North America or around the world to store carbon.”

With an investment of $300 million from Brookfield Renewable, the company is about to bring its first commercial-scale project online in Alberta, sequestering 47,000 metric tons of CO2 per year at a cost of $50/ton.

Posted on

Utilities Could Double US Nuclear Capacity by 2050, NEI Chief Says

A recent poll of chief nuclear officers at the Nuclear Energy Institute’s (NEI) member utilities found that they plan to add 90 GW of nuclear generation to the U.S. grid, with the “bulk” of that capacity coming online by 2050, CEO Maria Korsnick said Tuesday.

That level of generation would double U.S. nuclear output and does not include “the growing list of utilities who are new to nuclear and demonstrating interest in advanced technologies,” she said in a State of the Industry address at NEI’s Nuclear Energy Assembly in D.C.

Maria Korsnick (Nuclear Energy Institute) Content.jpgMaria Korsnick, President and CEO of the Nuclear Energy Institute | Nuclear Energy Institute

Korsnick expects the new U.S. nuclear fleet to include “some” small modular reactors (SMRs). Supporters of the SMR approach, which limits traditionally large generating capacities to under 300 MW, say it offers the possibility of nimble nuclear deployment.

She also sees those new smaller plants that are based on advanced technologies, together with an expansion of existing nuclear technology, as an important part of addressing climate change.

“Nuclear is the key to unlocking a zero-carbon future,” she said, adding that she has observed a “sea change in the perception of nuclear energy … as an indispensable tool for driving down emissions.”

A growing vision for SMRs moves nuclear beyond ensuring grid reliability to helping decarbonize hard-to-abate industries, such as oil and gas chemical manufacturing, steelmaking and production of synthetic materials.

“Advanced reactors are the solution that they’ve been searching for,” Korsnick said. “They can provide the reliable, cost-effective carbon-free generation needed to decarbonize their supply chains, and they enable manufacturers to sell to companies like Ford, GM, Tesla and others who are committed to a lower-carbon future.”

In addition, she said that manufacturing and transportation sectors could decarbonize with hydrogen generated from the off-peak capacity of nuclear reactors.

Credit for ESG

To realize a role for nuclear in a decarbonizing the economy, the industry must navigate a future where investors are increasingly screening for environmental, social and governance (ESG) factors.

“Nuclear should be getting credit for ESG,” Korsnick said. “I’d like to tell you that it’s that simple, but it’s not, and there are some financial institutions that look at nuclear and look at ESG, and they struggle to say that nuclear actually supports that.”

As an example of the challenge, Korsnick pointed to the current controversy over inclusion of nuclear in the EU’s sustainable finance strategy (or “green taxonomy”). ESG investors are watching the EU’s strategy as an important standard for defining what makes a green investment.

The EU issued rules in April 2021 for activities that can be defined as “green,” but it chose to wait on its decision about whether to include nuclear and natural gas on the list. A final decision for the two resources is due in early July.

“It’s really important that we all stand up for nuclear … because one of the things we need to unlock is financial investment,” Korsnick said.

The U.N.’s 27th Climate Change Conference of the Parties (COP) in Egypt this fall is an opportunity for industry members to represent nuclear’s potential for decarbonizing the economy, according to Korsnick.

“At COP 27 … and every other forum where official critical decisions are being made about our climate and our energy future, we need to be crystal clear,” she said. “If we don’t commit to the next generation of nuclear now, our hesitation will cost our electric grid, our economy and our environment.”

Posted on

PJM Capacity Prices Crater

Capacity prices dropped by one-third to almost one-half in PJM’s Base Residual Auction for 2023/24, likely depressed by the effective elimination of the minimum offer price rule (MOPR), a tougher cap on generator prices and robust forward energy prices, which reduced revenue pressures on generators.

BRA Clearing Prices (RTO Insider LLC using PJM data) Content.jpg

BRA clearing prices ($/MW-day)

|

© RTO Insider LLC using PJM data

 

Prices in most of the MAAC region (Atlantic City Electric, Jersey Central Power & Light, Met-Ed, PECO Energy, Penelec, Pepco, PPL, Public Service Electric and Gas, PPL, Rockland Electric and Delmarva Power’s northern territory) dropped to $49.49/MW-day, a nearly 50% drop, while those in rest-of-RTO fell to $34.13, a nearly one-third reduction.

Two transmission zones within MAAC, Baltimore Gas and Electric and Delmarva Power’s south separated at prices of $69.95, which PJM attributed to transmission limitations.

PJM procured 144,871 MW of resources for the year beginning June 1, 2023. Including the fixed resource requirement (FRR) obligation of 31,346 MW, the RTO will have a 20.3% reserve margin, well above its 14.8% requirement.

PJM’s total capacity bill for the year is $2.2 billion, down from about $4 billion for the 2022/23 delivery year. It was the second year in a row that capacity prices have fallen, following last year’s sharp drop. (See Capacity Prices Drop Sharply in PJM Auction.)

“I did not see anything in this auction that was, ‘Wow. I didn’t expect that to happen!’” PJM Senior Vice President of Market Services Stu Bresler said at press conference to announce the results Tuesday. “I think the prevailing wisdom out there was that we were going to see lower clearing prices in this auction than we had in the last auction … given some of the rule changes; given some of the external things that have occurred in various states in PJM. I just don’t think any of us were really surprised by many of the results.”

Nuclear Resurgence, New Gas and Solar

Nuclear plants were big winners in the auction, clearing an additional 5,315 MW than last year.

Solar resources increased 25% to 1,868 MW, while wind resources cleared only 1,294 MW, a reduction of 434 MW, as fewer resources participated.

New capacity offered by year (RTO Insider LLC using PJM data) Content.jpg

New capacity offered by year

|

© RTO Insider LLC using PJM data

 

Natural gas resources cleared an additional 1,685 MW, with more efficient combined cycle units boosting their share by 3,627 MW and less efficient combustion turbines falling 1,012 MW. Combined cycle units cleared a total of 48,030 MW in the auction, and CT units cleared 19,080 MW.

Cleared capacity of steam units (primarily coal) dropped by 7,186 MW to 27,682 MW, reflecting a decrease of 7,813 MW offered into the auction because of plant retirements.

Energy efficiency resources jumped 660 MW to 5,471 MW, while demand response dropped 716 MW to 8,096 MW.

Hydro dropped from 4,157 MW to 3,677 MW.

New Variables

Bresler noted several rule and timing changes that may have impacted the results.

It was the first auction using the less restrictive MOPR, which was applied to only seven resources totaling 76 MW that had failed to file for exemptions in time.

The auction also used a lower unit-specific market seller offer cap to counter market power and a historical, rather than a forward-looking, energy and ancillary services revenue offset.

“I think the prevailing wisdom is that the impact of this implementation of the very narrow, less restrictive minimum offer price rule could have had a downward impact on prices in this auction,” Bresler said.

The replacement of the net cost of new entry-based offer cap with a unit-specific cap based on net avoidable costs “could have served to reduce the offer prices that some resources would have offered into this auction,” he added. “However, in both of these cases …  it’s extremely difficult, if not impossible, for PJM to say what resources would have offered if they hadn’t offered what they did. It would be purely speculative. So we don’t know the magnitude of any impacts.”

Also new was the application of the effective load-carrying capability method for determining the capacity value of wind, solar and storage resources.

“It could result in a lower capacity value for certain resources,” he said, suggesting it might have impacted the reduction in wind generation offerings.

Futures Prices

Bresler said spark spreads and dark spreads — respectively, the difference between the wholesale market price of electricity and its cost of production using natural gas and coal — have increased, especially in the forward markets. “You would expect, if market sellers are anticipating higher net revenues in the energy market, that they will be able to offer less into the capacity market,” he said.

Timing

Bresler said the reduction in demand response could have been a result of the shortened auction timeline.

The 2023/24 auction was originally scheduled for May 2020 but was delayed while FERC considered approval of new market rules, leaving only a one-year lead time to the delivery year instead of the usual three.

“Most of the time we’re [three] years in advance; even the last auction was more than a year in advance of the delivery year, which gives curtailment service providers the opportunity to offer planned demand response that they can then … go out and sort of sell to customers.”

The next BRA, for the 2024/25 delivery year, will be held in December to return to a three-year-forward basis.

Posted on

FirstEnergy’s Top Executives Face Job Reviews

Top FirstEnergy (NYSE:FE) executives are facing job performance reviews as required by the March settlement of several shareholder lawsuits alleging that the company was damaged by secretly funding a scheme to bribe Ohio politicians for nuclear power plant subsidies.

In a U.S. Securities and Exchange Commission filing June 15, the board announced it had formed a “special review committee” of directors to assess the performance of current top executives and report to the full board by mid-September.

The SEC filing did not identify what it described as “current C-suite executives,” which typically include a company’s CEO, CFO and COO. The company’s website identifies its current leadership team as having nine members, including a member of the board. A company spokeswoman said the committee will determine whose job performance it will evaluate.

The shareholder settlement also required the resignations of six longtime members of the company’s board of directors and a reconstituted board, elected in May, to oversee the company’s future lobbying. (See FirstEnergy Shareholder Settlement: 6 of 16 Board Members Must Leave.)

CEO Steven Strah was appointed in March 2021 after serving about six months as president and acting CEO. Strah began his FirstEnergy career at The Illuminating Co. in 1984.

CFO Jon Taylor was promoted to his position in May 2020 and given expanded responsibilities in August 2021. Taylor joined the company in 2009.

Samuel Belcher, senior vice president of operations, oversees FirstEnergy’s regulated electric utility operating companies in Ohio, Pennsylvania, New Jersey, West Virginia, Maryland and New York, as well as the company’s high-voltage transmission system. He joined the company in 2012.

In July 2021, FirstEnergy agreed to pay a $230 million fine in a deferred prosecution agreement with the U.S. Justice Department. By signing the agreement, the company admitted it conspired with former Ohio House Speaker Larry Householder and his associates by secretly contributing millions of dollars to a 501(c)(4) charity Householder allegedly used to fund efforts to win passage in 2019 of a nuclear bailout bill, H.B. 6, and then defeat a referendum petition drive to allow voters to decide the issue.

Former FirstEnergy CEO Charles Jones publicly admitted the company contributed about $60 million to the charity. Ohio lawmakers later revoked the bailout.

Jones and several other top executives were fired. Householder, expelled from the House, has pleaded innocent and faces a trial in January 2023. Two of his associates pleaded guilty and await sentencing.

Posted on

ERCOT Briefs: Week of June 13, 2022

The summer season may have officially begun early Tuesday morning, but ERCOT has already set three new marks for all-time peak demand this year.

The Texas grid operator confirmed demand peaked at a record 75.1 GW Thursday afternoon, breaking the previous record of 74.9 GW set on June 12. Those records were surpassed at 4:30 p.m. Monday, when demand hit 76,743 MW, less than 1,000 MW short of staff’s 77.3 GW peak forecast for the summer. (See ERCOT, PUC Say Texas Ready for Summer.)

Average peaks will remain above 75.7 GW for the rest of the week as the state continues to bake in extreme drought conditions that exacerbate the heat. The Houston area was expected to see temperatures approaching 107 degrees Fahrenheit Monday; widespread temperatures at 108 degrees or above would trigger a heat advisory.

ERCOT’s meteorologist says the footprint’s temperatures will be hotter this week than they were last week, with most of Texas seeing highs of 100 degrees or greater. He said temperatures of 103 to 105 degrees will be common later in the week; the European weather model is forecasting highs of 110 degrees or greater across North Texas this weekend.

Extreme to exceptional drought — defined as widespread crop and pasture losses, exceptional fire risk, and water shortages in reservoirs, streams and wells causing water emergencies — covers 70% of the state’s Southwestern region, which includes Austin, San Antonio and El Paso, according to the National Weather Service.

Sunday’s demand topped out at 73.8 GW Sunday, the 11th straight day it has exceeded 72.4 GW.

The grid continues to rely on wind and solar resources to provide between 25 and 30 GW of energy a day. ERCOT said it has more than 92 GW of expected capacity to meet the demand and has been able to avoid asking Texans to reduce their usage since an informal conservation appeal in May.

Since April, the grid operator has issued three operating condition notices, its lowest-level communication to the market in anticipation of possible emergency conditions. Thermal outages that topped 20 GW near the end of the maintenance season had dropped to 5.3 GW as of Monday.

ERCOT says it has enough capacity to meet demand as it continues to maintain a conservative operations posture by procuring up to 6.5 GW of operating reserves. However, the Independent Market Monitor said in its annual market report that the practice has cost the market up to $845 million year to date.

The Monitor is presenting its report to the grid operator’s Board of Directors Tuesday and a state House committee hearing Wednesday. The ERCOT directors will begin their bi-monthly board meeting Tuesday several hours after the summer solstice officially marks the beginning of summer at 4:14 a.m.

Securitization Bonds are Issued

A special-purpose entity, Texas Electric Market Stabilization Funding, will issue more than $2.1 billion in bonds to cover short pays to the market, a result of legislation last year to compensate market participants for $2.9 billion in debt incurred during the February 2021 winter storm. (See Securitization Offers Texas a Way Forward.)

ERCOT will distribute the bonds’ proceeds to load-serving entities that have demonstrated to regulators that they were exposed to extraordinary costs because of the supply and demand imbalance caused by generation outages during the severe cold.

The bonds will be issued in four tranches, totaling $2.12 billion, with weighted average lives of approximately seven, 16, 22 and 26 years. Their interest rates range between 4.264% and 5.167%.

The four tranches (ERCOT) Content.jpgThe four tranches of ERCOT’s securitization bonds | ERCOT

Moody’s Investors Service assigned a provisional rating of Aaa (sf) for each of the four tranches; a final rating will occur at closing, ERCOT said

The Texas Public Utility Commission authorized ERCOT to assess a monthly “default charge” on qualified scheduling entitles (QSEs) and congestion revenue right account holders to repay the default balance. The grid operator will post miscellaneous invoices to the QSEs Tuesday, and funds will be distributed Wednesday. ERCOT will distribute initial uplift charge invoices beginning in August. Until then, it will use market notices to provide the daily securitization uplift total.

Biannual interest payments to bondholders will begin Feb. 1, 2023, and occur every August 1 and February 1 of the first bank business day thereafter if those dates are not bank business days.

TAC Reviews Structure, Procedures

The Technical Advisory Committee held a workshop last week to review its structure and procedures as it continues to address stakeholder concerns about how it interacts with the new ERCOT board.

“I know there’s been a lot of angst amongst stakeholders as it pertains to what the stakeholder process will be like as we go forward,” TAC Chair Clif Lange said in opening the June 14 discussion. “We want to provide a menu of options, when appropriate.”

Lange said he and vice chair Bob Helton had recently met with director Bob Flexon, who chairs the board’s new Reliability and Markets Committee (R&M) that some stakeholders say is stepping on TAC’s toes. Lange said he and Helton were urged to streamline TAC’s subcommittees and to think of ways to change the structure and reporting relationships of the committee and its participation in the stakeholder process.

“The board is looking for opportunities for the R&M to provide input and recommendations to the board on items bubbling up through TAC,” Lange said. “[The board] sees this as a way to strengthen [the stakeholder] relationship. They see this as an opportunity to improve communications and understanding of the core areas of ERCOT.”

The committee discussed creating a liaison committee that would meet with the R&M as needed to inform the directors on coming ruling changes but failed to reach consensus on how the liaisons would be appointed. Members did agree that a proposal requiring them to be employees of the companies they represent made no sense when some organizations and stakeholder groups rely on outside consultants.

“[The experience proposal] gives the board some degree of certainty that TAC has the expertise membership can draw on,” Lange said.

Lange and Helton will continue the discussion at TAC’s June 27 meeting. They will then meet with the board and get its feedback.

RPG Recommends 345-kV Project

Staff told the Regional Planning Group last week that they will recommend to the board and TAC that a $477 million 345-kV transmission line addition in West Texas go forward as a Tier 1 project.

ERCOT said its independent review of the project indicates the additional pathway will address rapid load growth in the Delaware Basin area. The project includes 71 miles of double-circuit 345-kV lines from the existing Bearkat substation to the existing North McCamey substation and another 94-mile stretch from the North McCamey substation to the existing Sand Lake substation.

A final report for the project is expected to be released next month and will then go to TAC and the board in August for their endorsement.

The Lower Colorado River Authority, Wind Energy Transmission Texas and Oncor jointly submitted the Bearkat-North McCamey–Sand Lake 345-kV addition to the RPG in April, requesting critical designation. It is scheduled to go in service in June 2026.

Posted on

Court Strikes a Blow to ISO-NE Winter Plan

The D.C. Circuit Court of Appeals on Friday took a scalpel to ISO-NE’s Inventoried Energy Program, finding that it would unfairly incent resources for storing energy in a way they already do (Belmont Municipal Light Department v. FERC, 19-1224). 

Approved by FERC in 2020 over the objections of then-Commissioner Richard Glick, the IEP is set to be in place for the 2023-2025 winter seasons to compensate resources for the inventoried energy they hold on winter days that hit a certain low-temperature threshold.

But after the court’s ruling, it will be significantly blunted. The three-judge panel found that the program’s inclusion of coal, hydro, biomass and nuclear generators as eligible for compensation is arbitrary and capricious because they already maintain inventoried energy and would not change their behavior in response to the approximately $40 million in new payments that would be sent their way.

“In reviewing FERC’s June 2020 order, we conclude that FERC approved IEP without adequately considering legitimate objections from complainants who pointed out that it would result in windfall payments to nuclear, coal, biomass and hydroelectric resources,” wrote Judge Robert Wilkins in the court’s opinion. 

The court left the rest of the IEP in place, allowing the RTO to compensate oil, natural gas and refuse generators. 

The association representing generators in New England said the ruling is unfair and that the court “cherry-picked its own design, carving the market even further into haves and have nots.”

“At a moment of a national refocus on electric reliability, it flies in the face of logic to deliberately choose to not pay for an identified reliability service for some, but yes to others,” said Dan Dolan, president of the New England Power Generators Association. “With electric reliability in New England’s winters an ongoing focus, I simply hope this is not a harbinger of the future of the electricity market.”

ISO-NE spokesperson Matt Kakley said the grid operator is reviewing the decision.

In addition to throwing doubt on the efficacy of the program starting in 2023/24, the ruling could also affect the grid operators’ plans going forward for this winter. ISO-NE has been considering proposing a new version of the IEP as well as possibly bringing back its Winter Reliability Program. (See ISO-NE Weighs Reviving Reliability Programs for this Winter)

The court’s ruling — and the position of Glick, who in 2020 called the program “an ill-conceived giveaway” — seem to lower the chances that FERC would approve the IEP or a similar program for the winter of 2022/23. 

The petitioners challenging the program included New Hampshire and Massachusetts, municipally-owned electric utilities and environmental groups including the Sierra Club and the Union of Concerned Scientists. Some had asked for the program to be eliminated altogether, but the court rejected that, agreeing with FERC and ISO-NE that the overall program is not unreasonable.

Posted on

FERC Partially Accepts NYISO Order 2222 Compliance

FERC on Thursday accepted NYISO’s Order 2222 compliance filing but directed the ISO to file revisions related to small utility opt-in requirements, interconnection rules and other issues (ER21-2460).

The commission also asked NYISO to propose an effective date for its compliance filing in the fourth quarter of 2022 and further propose a reasonable effective date by which it will comply with the requirement to allow DERs to provide all the ancillary services they are technically capable of providing through aggregation while also addressing NYISO’s reliability and visibility concerns.

In its filing submitted last November, NYISO maintained that its existing distributed energy resources (DER) and aggregation participation model satisfactorily complies with the majority of directives in Order 2222. (See NYISO Shares Order 2222 Response with Stakeholders.)

The commission found that NYISO’s existing rules comply with Order 2222 requirements to establish a 100-kW minimum size requirement for DER aggregations (DERA); to propose a maximum capacity requirement for individual DERs participating in its markets through an aggregation; allow a single qualifying DER to avail itself of the proposed DERA rules by serving as its own aggregator; and address distribution factors and bidding parameters for DERAs.

Small Utility Opt-in

The commission found that NYISO complied with the requirement that it accept bids from a DERA if its aggregation includes resources that are customers of utilities that distributed more than 4 million MWh in the previous fiscal year.

However, it found the ISO only partially complied with the “small utility opt-in” provision, a requirement to reject bids from DERA’s that include customers of utilities that distributed less than 4 million MWh in the previous year, unless the relevant electric retail regulatory authority (RERRA) permits those customers to bid into RTO/ISO markets.

Protestors found fault with the ISO’s proposal to apply the opt-in rule to “load serving entities,” which in New York includes small competitive retail suppliers knows as “energy service companies.” The protestors argued that RERRA approvals would be complicated for those suppliers because they have no technical role in distribution system operations. FERC agreed with their argument and ordered NYISO to replace the term LSE with “distribution utility.”

FERC also required NYISO to clarify the aggregator’s responsibilities associated with changes to a RERRA’s opt-in determination and clarify the timing of a resource’s ineligibility when the small utility decides to prohibit its participation.

FERC additionally found that, in complying with Order 2222’s directive for RTOs/ISOs to exempt distribution-connected DERs from their interconnection rules, NYISO inadvertently exempted the interconnections of DERs on both the distribution and transmission system. The commission directed the ISO to fix that error and clarify that interconnection of DERA through the distribution system is exempt from the ISO’s small generator interconnection procedures.

Participation Model

The commission found that NYISO’s proposal complies with the requirement to establish DER aggregators as a type of market participant, but only partially complies with the requirement to allow such aggregators to register an aggregation under one or more participation models in NYISO’s tariff that accommodate its physical and operational characteristics.

FERC acknowledged NYISO’s reliability concerns related to allowing an aggregation to participate through a particular model when some of its resources may not satisfy all the requirements of that model.

“We believe, however, that NYISO could address its reliability concerns by means other than requiring that all individual DERs within the aggregation satisfy the relevant reliability requirements, such as the one-hour sustainability requirement. Therefore, so long as some of the DERs in the aggregation can satisfy the relevant requirements to provide certain ancillary services (e.g., the one-hour sustainability requirement), we find that those DERs should be able to provide those ancillary services through aggregation…” FERC said.

The commission agreed with NYISO that it should not be required to change its capacity market qualification requirements to enable energy efficiency resources or any other resource type that currently does not qualify to participate in its capacity market. Further, because Order 2222 does not require RTOs/ISOs to model energy efficiency in a certain way, FERC rejected as out of scope the arguments raised by various parties on whether energy efficiency should be modeled as supply- or demand-side participation.

Double Counting

NYISO’s existing model affords DERs the opportunity to participate simultaneously in one or more retail programs and the wholesale markets, and its proposal complies with the requirement to allow DERs to provide multiple wholesale services, the commission said.

But the ISO’s proposal only partially complies with the requirement to include appropriate restrictions on the participation of DERs through aggregations, if narrowly designed to avoid counting more than once the services provided by DERs, the commission said, directing a further compliance filing that specifies relevant tariff language.

The commission found that NYISO complied with the requirement to provide a detailed, technical explanation for the geographical scope of its proposed locational requirements.

“However, we find that NYISO does not comply with the requirement to revise its tariff to establish locational requirements for [DERs] to participate in a [DERA] that are as geographically broad as technically feasible,” FERC said regarding the compliance filing to specify the criteria NYISO will use to establish a set of transmission nodes at which individual DERs may aggregate.

The commission also found that NYISO did not comply with the requirement to require the DER aggregator to update its list of individual resources and associated information as it changes; the commission directed the ISO to revise the relevant tariff section, as well as include information and data requirements.

Metering and Telemetry

The commission found that NYISO’s proposal only partially complied with the requirement to establish market rules that address metering and telemetry hardware and software requirements necessary for DERAs to participate in RTO/ISO markets because its tariff lacks the deadline for meter data submission for settlements and does not include references to the specific documents that contain further technical details.

In addition, FERC found the ISO partially complied with the requirement to explain why its proposed metering and telemetry requirements for DERAs are just and reasonable and do not pose an unnecessary and undue barrier to individual DERs joining an aggregation.

“NYISO’s filing lacks clarity regarding its protocols for sharing metering and telemetry data and the meter data submission deadline,” the commission said, requesting the ISO to revise its tariff to include the meter data submission deadline for settlement and specify which entity must submit meter data.

FERC also directed a further compliance filing to include references to specific documents that contain further technical details with respect to telemetry.

The commission found that NYISO sufficiently supported the need for aggregations to provide six-second telemetry, consistent with its requirements for other suppliers, to meet the New York-specific local reliability rule that requires NYISO to respond to thermal overloads in under five minutes.

But the commission also directed a further compliance filing that establishes protocols for sharing metering and telemetry data and ensuring that such protocols minimize costs and other burdens and address privacy and cybersecurity concerns.

Market Rules

Order 2222 requires RTOs and ISOs to revise their tariffs to establish market rules that address coordination between the RTO/ISO, the DER aggregator, the distribution utility and the RERRAs.

NYISO’s proposal only partially complied with those requirements with respect to the role of distribution utilities, the commission found, directing the ISO to continue to coordinate with utilities in developing the further compliance filing.

Furthermore, given that NYISO’s tariff provides utilities with 60 days to review risks to the reliable and safe operation of the distribution system from DERA participation, the commission said it agreed with New York transmission owners that the tariff language lacks clarity regarding the circumstances in which the utility review process applies, directing a further compliance filing with tariff revisions consistent with the suggested alternative language that NYISO proposes in its answer.

The commission found that NYISO must address six of seven coordination requirements to ensure a fully comprehensive, non-discriminatory and transparent distribution utility review process.

First, the results of a distribution utility’s review must be incorporated into the DERA registration process and second, the tariff should include criteria by which the utilities will determine whether each proposed DER is able to participate in a DERA.

Third, the commission directed NYISO to clarify that the scope of distribution utility review of distribution system reliability impacts is limited to incremental impacts from a resource’s participation in an aggregation that were not previously considered by the utility during the interconnection study process for that resource.

Fourth, NYISO must propose in its tariff that a distribution utility provide a showing that explains any reliability findings as required by Order 2222, the commission said.

Fifth, FERC found that NYISO only partially complies with the Order 2222 requirement that a distribution utility have the opportunity to request that the RTO/ISO place operational limitations on an aggregation, or that the removal of a DER from an aggregation be based on specific significant reliability or safety concerns that the distribution utility clearly demonstrates to the RTO/ISO and DERA on a case-by-case basis.

Finally, the commission found that NYISO’s proposed distribution utility review process is only partially compliant with the information sharing requirements of Order 2222.

Coordination Requirements

The commission found that NYISO’s proposal partially complies with the operational coordination requirements of Order 2222 and fully complies with the requirement that the DER aggregator must report to the RTO/ISO any changes to its offered quantity and related distribution factors that result from distribution line faults or outages.

NYISO’s proposal complies with the requirement to revise its tariff to include coordination protocols and processes for the operating day that allow distribution utilities to override RTO/ISO dispatch of a DERA in circumstances where such override is needed to maintain the reliable and safe operation of the distribution system, the commission found.

“We recognize concerns that NYISO’s proposal may subject an aggregator to risk of penalties for situations beyond its control; however, … this requirement will incent [DER] aggregators to register individual [DERs] on less-constrained portions of distribution networks in order to minimize the likelihood of incurring non-performance penalties,” the commission said.

However, NYISO’s proposed tariff revisions lack specificity regarding the existing resource non-performance penalties that would apply to an aggregation when a utility overrides NYISO’s dispatch, prompting request for a further tariff revision to specify the existing non-performance penalties.

In addition, the commission found that NYISO’s tariff does not sufficiently address data flows and communication between NYISO, the aggregator and the distribution utility, and thus directed tariff revisions to describe what data and information will be communicated and to define more clearly the communication that will occur in this coordination process.

The commission also directed a further tariff revision to require that any information provided to NYISO by a RERRA about a specific aggregation must be shared with the aggregator, along with another revision to allow distribution utilities to review the reliability and safety impact of “any change to an aggregation.”

The commission found that NYISO’s proposal does not comply with the requirement that the DER aggregator must attest that its aggregation complies with the tariffs and operating procedures of the distribution utilities and the rules and regulations of any RERRA, and directed a further compliance filing that revises the tariff to specify that the aggregator must attest to its compliance with the tariffs and operating procedures of the distribution utilities and the rules and regulations of any RERRA.

The commission also directed NYISO to file a further compliance filing proposing an effective date by which it will allow DERs in heterogeneous aggregations to provide all of the ancillary services that they are technically capable of providing through aggregation, and to propose an effective date for its compliance filing in the fourth quarter of 2022 at least two weeks prior to the proposed effective date.

Separate Statements

Commissioner James P. Danly concurred with Thursday’s order in a separate statement, saying that NYISO made a good faith effort to comply with Order 2222, which he continues to disagree with, though he agreed that the ISO “failed to fully comply with its scores of dictates.”

“I do not envy NYISO the compliance task we imposed upon it. One hundred percent compliance probably is impossible in a first, or perhaps even second, attempt,” Danly said. “We shall see.”

Danly said NYISO’s failure to fully comply underscores his original concern about the commission’s interference in the administration of RTO markets and distribution-level systems, with Order 2222 not only supplanting many state powers but also permitting RTOs “extremely limited discretion to do anything other than step in line with the commission’s directives for how every little thing should work,” Danly said.

Commissioner Allison Clements issued a partial dissent, expressing concern that the commission allowed NYISO to exclude energy efficiency from DER aggregations because it does not meet the ISO’s general eligibility rules.

Clements argued that the finding “erodes the rule’s plain requirement that an RTO/ISO’s rules may not ‘prohibit any particular type of [DER] technology from participating in [DER] aggregations.’ It sets precedent that may, in the future, allow RTO/ISOs to prevent the participation of other resource types.”

“I remain hopeful that, as the commission evaluates future compliance filings of Order No. 2222, it will strike the right balance between offering flexibility and upholding its requirements as written,” she wrote.

Posted on

Counterflow: Stuff That Ain’t So

tesla powerwallSteve Huntoon | Steve Huntoon

Yes, federal policy needs to advance rational transmission grid expansion. We need AC interconnections between ERCOT and the rest of the country.[1] We need more — not less — competition in transmission.[2] And as I wrote in my last column (and before), we should apply unique emergency line ratings for planning/interconnection studies and deploy technologies that increase physical capacity of grid elements.[3] These are no-brainers that FERC continues to eschew.

Which brings me to what FERC is doing in its massive April Notice of Proposed Rulemaking on transmission planning and cost allocation (RM21-17). FERC says it begins with “facts on the ground.” Yes, let’s do!

NOPR Claim #1: Transmission Expansion isn’t Happening on a Regular Basis Through Regional Processes

The NOPR asserts that transmission expansion isn’t happening through regional planning processes on a regular or consistent basis and, “instead,” significant expansion is happening through upgrades constructed as a result of generator interconnection requests.[4]

Wrong, as this PJM chart shows: “Baseline” are planning process upgrades and “Network” are generator interconnection upgrades.[5] The former is $32.4 billion and the latter is $6.6 billion.

Baseline vs network spending (PJM) Content.jpgPJM baseline planning process upgrades totaled $32.4 billion as of December 2021, while network generator interconnection upgrades totaled $6.6 billion. | PJM

Moreover, the $32.4 billion in Baseline upgrades does not include individual transmission owner “supplemental projects,” of which there was $3.3 billion last year alone.[6]

It’s hard to figure out how the NOPR could have this “fact” so wrong, but it may stem from assuming that Baseline upgrades that are not cost allocated across a region somehow only provide “local” benefits. This leads us to:

NOPR Claim #2: Upgrades not Regionally Cost Allocated Don’t Provide System Benefits

The only upgrades in PJM that are always regionally cost allocated are 500-kV and above facilities (and double circuit 345-kV lines). There are many upgrades not regionally cost allocated that provide non-local benefits, including many upgrades that are below 200 kV, cost less than $5 million, are needed in three years or less, and/or relieve contingency violations that would otherwise reduce flow on higher voltage facilities.[7] Nor is the NOPR correct that upgrades not regionally cost allocated are not regionally planned[8] — all $32.4 billion in Baseline upgrades were regionally planned by PJM.

And regarding individual TO “supplemental projects,” these too can provide system benefits as described by PJM to include: “enhancing grid resilience and security, promoting operational flexibility [and] addressing transmission asset health.”[9]

The relatively small number of regionally cost allocated upgrades is a good thing. Why spend billions on a large 500-kV project when an upgrade of an existing transmission facility can relieve the reliability violation?

And non-regionally cost allocated upgrades surely provide no less system benefit than generator interconnection upgrades, which tend to be localized around the point of generator interconnection.

Having created an invalid preference for regionally cost allocated projects over other upgrades, the NOPR follows up by eliminating competition for the former on grounds that eliminating competition will incent transmission owners to pursue more of them.[10] Yikes!

NOPR Claim #3: Generator Interconnection Costs Have Seen a ‘Dramatic Increase’

The NOPR claims that interconnection costs for new generation in $/kw have seen a “dramatic increase.”[11] It arrives at this conclusion based on data from a selected MISO subregion and from PJM that conflate the upgrade cost per kW of actual projects with that cost for proposed projects.[12] Instead, what this data suggest is that participant funding serves to weed out proposed projects with uneconomic interconnection costs. A good thing.

When apples (earlier actual projects) are compared to apples (later actual projects), the source study by Lawrence Berkeley presents this chart, and comes to the opposite conclusion about interconnection costs over time. [13]

In the study’s own words: “These results combine the MISO, PJM, and EIA data to assess how location and queue date correlate with transmission costs. … There is little evidence of significant cost trends over time ….”[14]

In other words, the source study relied on by the NOPR says the opposite of what the NOPR says it says.

As for the NOPR’s poster child for high generator interconnection costs, it cites a 120-MW solar project in PJM and says that the project faced interconnection costs of $1.5 billion, including rebuilding 500-kV lines.[15] Needless to say it is easy to cherry pick one interconnection request out of 8,509 interconnection requests in PJM over the past 25 years.[16]

And lest we forget, those opposed to participant funding would force consumers to pay that $1.5 billion — rather than incent the project developer to find a lower cost interconnection point (or perhaps pursue another project).[17]  Yikes!

NOPR Claim #4: Transmission Customers Unfairly Benefit from Generator Interconnection Upgrades

Here’s another “fact” that drives me up a wall. The NOPR says that generator-paid upgrades can create system benefits for transmission customers who don’t pay for the upgrades.[18] This claimed benefit is more capacity, aka “headroom” on transmission circuits.

This is possible but, as I’ve pointed out before,[19] ignores the fact that a generator benefits for free from all the headroom that already exists on circuits because of past upgrades paid for by transmission customers. There is zero point zero evidence that the headroom created by generator upgrades is more valuable to transmission customers than the headroom created by transmission customers’ upgrades that generators benefit from.[20]

Bottom Line

We need rational transmission policies (like the ones I identified at the outset). Let’s base policies on real facts.

[4] Docket No. RM21-17-000, issued April 21, ¶ 36: “Significant expansion of the transmission system instead appears to occur through interconnection-related network upgrades constructed as a result of generator interconnection requests.” (emphasis added, footnote omitted).

[6] https://pjm.com/-/media/documents/ferc/filings/2022/20220613-pjm-supplemental-comments-on-doe-noi-on-tfp.ashx, page 7, footnote 17. By one tally, supplement project costs since 2005 have exceeded $41 billion.

[7] This last category may be a result of the change in 2013 to a solution-based DFAX methodology that allocates costs based on loadings of the lower voltage solution instead of loadings on the higher voltage facility whose outage causes the violation. https://elibrary.ferc.gov/eLibrary/filedownload?fileid=01A68F74-66E2-5005-8110-C31FAFC91712 The loadings on the lower voltage solution tend to be limited to a single transmission owner zone.

[8] “ … regional transmission planning and cost allocation processes generally have resulted in few regionally planned transmission facilities being selected and ultimately built.” NOPR ¶ 245.

[9] Footnote 6, pages 6-7.

[10] NOPR ¶ 353.

[11] NOPR ¶ 37, 38, 162.

[12] The discussion of MISO and PJM costs in NOPR ¶ 38 relies on Figure 2 of a MISO document here, https://cdn.misoenergy.org/20200520%20AC%20Item%2004%20Current%20Issue%20-%20Generator%20Interconnection%20Queue447230.pdf, and Table 2 of the Lawrence Berkeley National Laboratory study here, https://www.sciencedirect.com/science/article/abs/pii/S0301421519305816?via%3Dihub. (click on “View Open Manuscript”). Regarding the MISO data please note that data for most of the other MISO subregions do not support the NOPR’s claim — even if the data were apples to apples (which they’re not).

[13] Figure 6, page 46, of the above Lawrence Berkeley study.

[14] Page 17 of the above Lawrence Berkeley study (emphasis added).

[15] NOPR ¶ 38 and footnote 58. The subject feasibility study is here, https://pjm.com/pub/planning/project-queues/feas_docs/ae1135_fea.pdf.

[18] NOPR ¶ 165.

[19] Column referenced in footnote 17.

[20] Conversely, if generators can shift interconnection costs to consumers on the assumption of headroom benefit to consumers then generators should pay for the headroom they presently get for free.

Posted on

CAISO Order 2222 Filing Needs Some Work, FERC Says

FERC on Thursday accepted CAISO’s Order 2222 compliance filing but told the ISO to submit an update addressing concerns about its model for aggregated distributed energy resources, rules for participation of DERs that are customers of small utilities and other matters.

Order 2222, issued in September 2020, is meant to clear the way for distributed energy resource aggregations (DERAs) to participate in organized wholesale markets. Many DERs, such as rooftop solar arrays, are too small to participate in wholesale markets by themselves and must be grouped together by aggregators.

CAISO’s compliance filing was one of the first two FERC ruled on under Order 2222 (ER21-2455). The commission also conditionally accepted NYISO’s compliance plan Thursday. (See related story, FERC Partially Accepts NYISO Order 2222 Compliance.)

In its filing, originally submitted in July 2021, CAISO said that in 2016 it was the first ISO or RTO to establish a model for DERAs and that it had allowed DERs to participate in its market more than a decade before that.

“Because the CAISO was the first RTO/ISO to establish a DERA model, the CAISO already complies with the vast majority of the mandates in Order No. 2222,” it said. “This filing generally describes the CAISO’s current tariff revisions, and the few incremental changes the CAISO proposes to implement to align its tariff with the final rule.”

FERC was not completely satisfied that CAISO’s existing tariff with small changes met Order 2222’s requirements.

Last October, it asked CAISO for additional details about its compliance plans, including its market participation model for DERAs. (See FERC Asks Details from CAISO, NYISO on Order 2222 Compliance.)

Even after CAISO responded to the request in November 2021, FERC continued to have questions, which it detailed in Thursday’s order while telling CAISO to revise its filing.

DER Participation Model

In Order 2222, FERC required each RTO/ISO to establish DERAs as a type of market participant and to allow them to register under a participation model that accommodated their physical and operational characteristics.

“The commission explained that each RTO/ISO can comply with the requirement … by modifying its existing participation models to facilitate the participation of distributed energy resource aggregations, by establishing one or more new participation models for distributed energy resource aggregations, or by adopting a combination of those two approaches,” FERC wrote.  

The commission said it would evaluate each RTO/ISO proposal to determine if it met Order 2222’s goals of allowing distributed energy resources to “provide all services that they are technically capable of providing through aggregation.”

CAISO said in its compliance filing that it already complies with Order 2222 by allowing DERAs to participate in its market.

In a protest, CPower Energy Management said that “for reasons neither explained nor apparent, CAISO proposes to prohibit aggregations consisting of only demand response resources,” FERC said.

“CPower contends that this decision creates an artificial barrier that is inappropriate and begs the question of why aggregators may only participate in the distributed energy resource aggregation model if the aggregation includes one or more resources with injection capability,” FERC said.

In a separate protest, Advanced Energy Economy and the Sustainable FERC Project raised additional concerns with CAISO’s DERA participation model.

FERC found that CAISO had complied with the requirement to establish DERAs as a type of market participant but found “that CAISO only partially complies with the requirement to allow distributed energy resource aggregators to register distributed energy resource aggregations under one or more participation models in CAISO’s Tariff that accommodate the physical and operational characteristics of the distributed energy resource aggregation.”

FERC also found that CAISO’s proposal to not allow aggregators of “only demand response resources (i.e., homogeneous demand response aggregators) to participate as distributed energy resource aggregators does not comply with Order No. 2222.”

It ordered CAISO to revise its DERA model to allow a homogeneous aggregation of what CAISO called “distributed curtailment resources” to participate or to show that its existing demand response models comply with Order 2222.

Small Utility Opt-in

FERC also had concerns about CAISO’s treatment of Order 2222’s “small utility opt-in” provisions.  

The order requires each RTO/ISO to accept bids from a DERA if it includes resources that are customers of utilities that distributed more than 4 million MWh in the previous fiscal year. But it prohibits RTOs/ISOs from accepting bids from an aggregator if it includes resources that are customers of small utilities that distribute less than 4 million MWh per year — unless the relevant electric retail regulatory authority (RERRA) permits such customers to be bid into RTO/ISO markets by an aggregator.

The commission said CAISO’s proposal essentially complied with the order’s requirement but “lacks necessary precision” because it “deviates without explanation” from the order’s specific wording of the requirement and exception. It told CAISO to revise its proposed tariff language and resubmit it.

“We also find that CAISO’s proposal partially complies with the requirement to explain how it will implement the small utility opt-in … [but] we find that CAISO does not clearly explain the process by which a distributed energy resource provider must notify CAISO of a change in the RERRA’s opt-in determination — specifically, when a RERRA that previously authorized the participation of a resource that is a customer of a small utility decides to bar such participation,” FERC said.

FERC also found that CAISO’s proposal inappropriately allows a local regulatory authority to prevent participation in the CAISO markets by a DER aggregator “that aggregates in utilities that distributed over 4 million MWh in the previous fiscal year.”

“Specifically, CAISO’s proposal requires a distributed energy resource provider that aggregates in utilities that distributed over 4 million MWh in the previous fiscal year to certify to CAISO that its participation is not prohibited by the local regulatory authority,” FERC said. “Order No. 2222 did not provide a mechanism for RERRAs to provide for such a limitation on participation. Rather, the commission specifically declined to provide an opt-out that enables RERRAs to prohibit all distributed energy resources from participating in the RTO/ISO markets through” DER aggregations.

Other Issues

FERC singled out other issues in CAISO’s compliance filing involving double counting of DERAs that participate in one or more retail markets, maximum and minimum sizes for DERAs, and metering and telemetry hardware and software requirements necessary for distributed energy resource aggregations to participate in RTO/ISO markets.

FERC directed CAISO to file an additional compliance filing with 60 days to address the issues it identified.