Search
`
November 6, 2024

Posted on

New Jersey Bill Would Offer Help to Delayed Solar Projects

A New Jersey bill designed to help solar developers who say that delays beyond their control are threatening the viability of some projects has raised concerns about the costs to ratepayers.

The bill, which the Senate Energy and Environment Committee backed 5-0 on June 9, would automatically extend the completion deadline for qualified projects. The extension would be available for projects that are in danger of failing to be completed by the designated deadline because of a “tolling” event and would continue as long as the event continues.

The definition of a “tolling event” includes: any action or inaction by PJM or an electric utility; a PJM or utility moratorium on new applications; any “new application process, study, report or analysis established” by the RTO or a utility; or an “undue” delay caused by local government planning board or other entity in supplying a required permit.

The bill, S2732, would cover 33 projects — mainly on landfills and brownfields — that together would total 500 MW, says Sen. Bob Smith (D), one of two bill sponsors and the committee chairman.

The bill touches an ongoing concern among solar developers that New Jersey projects can be derailed, and deadlines broken, by factors beyond their control, such as equipment delays stemming from supply chain issues, labor shortages, delays in getting municipal permits and difficulties getting projects connected to the grid.

“These problems have been devastating to the industry,” Lyle Rawlings, president of the Mid-Atlantic Solar & Storage Industries Association, told a hearing into the bill. “They’ve caused delays; they’ve caused tremendous price increases … it could be an existential threat to some businesses if they are not provided relief.”

The problem is complicated by a reshaping of the state’s solar incentive programs by the Board of Public Utilities (BPU) in recent years as it has sought to reduce the cost to ratepayers of solar subsidies, which has increased the consequences of a project missing a completion deadline. The BPU in May 2020 replaced the state’s long-time solar incentive program, the Solar Renewable Energy Certificate (SREC) program, which paid about $250/MWh, with the temporary Transition Renewable Energy Certificate (TREC) program, which granted incentives of $90 to $150/MWh. In July, the TREC program ended and was replaced by the Successor Solar Incentive (SuSi) program, which pays incentives of $70 to $100/MWh depending on the project.

The changes mean that a project with a TREC incentive that fails to meet its completion deadline could lose the incentive and have to apply for another under the less lucrative SuSi program. The only remedy would be to apply for a deadline extension to the BPU, which has been reluctant to grant extensions.

Evaluating such extension requests, the BPU has to consider, for example, whether the delay is genuinely because of circumstances beyond the developer’s control, or the applicant’s project was from the beginning unlikely to make the deadline and they are is seeking to remedy the problem with an extension.

During the hearing, Smith recounted that the BPU told him that about 75% of the 4,000 applications for TREC incentives were “bogus, meaning that it was just somebody putting in a slip to keep their name in line for a TREC, but not necessarily with any intention to build.”

The proposed legislation, however, would remove the need for a BPU deadline extension and instead grant qualified applicants an “automatic extension.”

Extension Questions

In a June 8 letter to the committee, the New Jersey Division of Rate Counsel opposed the bill, saying it “will inevitably result in increased rates for utility ratepayers.”

The bill would remove the BPU’s ability to deny extensions and prohibit it “from even investigating the factual accuracy of the certification” by a developer claiming that a tolling event had delayed its project, the Rate Counsel said. The legislation also would prevent the board from setting the length of an extension, if it concluded one was warranted, and replace its expertise in judging whether a project deserved the extension with an automatic extension award, the agency said.

That would enable projects to continue, and eventually receive incentives, that otherwise would fail because they otherwise would not meet the deadline, the counsel said.

“It would eliminate the board’s ability to enforce any deadlines and result in the payment of substantial excess incentives,” it said. “And since ratepayers ultimately fund these financial incentives, this bill will increase utility rates.”

Developers testifying before the committee, however, outlined the kind of scenarios that highlight the need for the legislation.

Melissa Sims, owner of Ecological Systems, a Manalapan-based solar development company, said she has two projects underway that will be finished within the deadline, except that each will be missing a small part. In one, she has waited several months for a circuit breaker that she was initially told would take 70 days to arrive.

Sims said she feared that because of the delay, she will fail to meet the deadline of the TREC grant awarded for the project.

“I cannot stress enough how serious and devastating it will be for anyone who has a solar project under construction who is experiencing these types of delays,” she said. “If I don’t have the breaker, I can’t call for my electrical inspection. And if I can’t call for my electrical inspection, I can’t get permission to operate from the utility. And if I can’t get permission to operate from the utility, I can’t get my TREC.”

Joshua Lewin, president of Helios Solar Energy, said he also has two projects in jeopardy because of similar problems, including a 1-MW project in Millville that could miss the completion deadline because he is still waiting for the arrival of the main distribution panel, which was ordered last July. He estimated that the customer would lose about $780,000 in revenue if the delay causes the project to miss its completion deadline.

“We’re constantly re-engineering some of the one-line diagrams and pieces of equipment to try to accommodate what might be available in the next couple of weeks or a couple of months,” he said. “But there are items that are just unavailable.”

Connection Obstacles

Business groups — among them the New Jersey Business and Industry Association and the South Jersey Chamber of Commerce — support the bill, as do environmentalists, including the New Jersey league of Conservation Voters.

Smith said the delays mean that New Jersey is “not keeping its promises” to provide a transition period between the SREC and the SuSi program, because developers find they can’t meet the deadlines of the temporary TREC program, which was meant to soften the transition.

“We said we would do lower [incentives] to have a transition, ultimately, to no subsidies,” he said. “But we were not performing.” Instead, he said, developers and their customers — through no fault of their own — face the loss of those incentives because of delays, and “we’re just saying, ‘Hey, tough, tough on you.’”

Lengthy delays connecting new projects to PJM are also common. The RTO said in February that it had 220 GW of capacity in the queue, of which renewables made up 95%. (See PJM Files Interconnection Proposal with FERC.)

“This is not an issue with New Jersey; this is an issue with PJM,” Doug O’Malley, director of Environment New Jersey, told the Senate Energy and Environment Committee as he offered support for the bill on June 9. “PJM is essentially throwing up the red stop sign and saying ‘do not proceed with solar,’ and that’s creating massive problems for the projects that have been teed up.”

The difficulty of connecting solar projects in the state to the grid is also well known. In May developers, testifying in support of a bill that would levy a fee that would raise funds to modernize the grid, said the grid is so old and its capacity so limited that new projects can’t be connected in some areas of the state. (See Solar Developers: NJ’s Aging Grid Can’t Accept New Projects.)

Awaiting Permission

A recent case before the BPU at its June 8 meeting, the latest in a series of deadline extension requests, highlighted the difficulties.

Project developer ESNJ-Key-Gibbstown, seeking to finish a 1.38-MW carport solar project located in Gibbstown, in South Jersey, had received three extensions since the project was approved for TREC incentives in June 2020. It then sought an additional extension to move the deadline to Dec. 31 because of the inability to connect the project to the grid through Atlantic City Electric (ACE).

The developer, according to the BPU order on the case, had “completed construction,” had a conditional permit to operate and was “capable of being fully energized and connected to the grid.” However, the order said, the developer could not get ACE to deliver the project’s full capacity to the grid because “ACE has not yet completed offsite upgrades necessary to allow interconnection for the full capacity of the project.” As a result, the project could only operate generating 50 kW.

The order said that BPU staff have “traditionally been reluctant to recommend that the board provide extensions for solar projects that miss their expiration dates because of supply chain issues, general interconnection processing delays and other factors that, while regrettable, do not rise to the level of warranting an extension.” Yet the staff recommended a deadline extension, and the board approved it.

“This does not appear to be a case of a project coming into the [TREC] program with an underdeveloped project development plan,” staff concluded, noting that the developer had done “everything in its power to complete its project” by the April deadline.

BPU President Joseph Fiordaliso said the board’s decision “struck the necessary balance of fairness to applicants whose projects are otherwise complete with a strong interest of the ratepayer who should always receive what they pay for, no more and no less.”

Still, he said, the case highlights the difficulties facing the state.

“When we’re talking to executives from utility companies, we are constantly talking about interconnection,” he said. “If anything keeps me awake at night, it is the fact that we’re going to have wind turbines out there; we have solar programs out there, and there’s no place to plug them in.”

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.