NYISOupdated the Operating Committee on Thursday that 89 MW of nameplate behind-the-meter solar was added onto the grid in June. The month’s peak load was 22,867 MW and the minimum was 11,999 MW.
Mark Younger, president of Hudson Energy Economics, referred to the growing megawatts of energy storage resources in New York and asked what percentage of them can sell capacity resource interconnection service. (See “May Operations Report,” NYISO Operating Committee Briefs: June 22, 2023.) CRIS rights are needed to take part in NYISO’s capacity market and can be obtained either through a transfer from a facility with existing rights or from ISO deliverability studies.
Aaron Markham, NYISO vice president of operations, responded, “I believe only half is available to sell capacity.”
Matt Cinadr, a power systems operations specialist with The E Cubed Co., asked whether NYISO has observed any issues with intermittent production and the amount of reserve fuel available.
Markham said, “we’ve definitely seen the levels of intermittent production increasing the volatility on the system, but at this point, it hasn’t been a driver of any reserve shortages.”
“As the amount of intermittents increases, however, I think we’re definitely going to see greater magnitudes of error and need to procure some market products to help manage that going forward,” he added.
DER Manuals
The OC also approved six revised manuals presented by NYISO that will support the implementation of distributed energy resources in New York’s markets.
These DER manuals include revisions to market procedures like ancillary services, control center requirements and emergency operations, and have been reviewed by all other applicable working or stakeholder groups. (See “DER Manual Updates,” NYISO Discovers Market Problem, Opens Confidential Investigation.)
NYISO still anticipates these approved manuals will become effective in parallel with other related DER tariff and market models.
The competing goals of reliability, sustainability and affordability converged Thursday as the New York state Public Service Commission wrestled with the mounting costs of the state’s energy transition.
Department of Public Service staff provided the first of what is expected to be a series of annual reports on the agency’s efforts to implement New York’s Climate Leadership and Community Protection Act (CLCPA).
The landmark 2019 law is intended to decarbonize the state over the next quarter century and simultaneously counter decades of environmental injustice.
The costs will be massive, but the details are unknown and likely unknowable at this point.
The figure $270 billion has been thrown around, which is not as big as it sounds when spread over 25 years in a state whose gross domestic product is $2 trillion a year.
But it does not reflect the rampant cost increases of late, nor the delays and cancellations being seen in New York’s renewable energy development pipeline.
Also, the costs will not be spread evenly among the state’s 20 million people.
The federal dollars everyone is counting on to help cover the cost may not last forever, and presumably someday will have to be paid back with interest by federal taxpayers, including those in New York.
Finally, the benefits from all that spending are unknown and will not be reflected entirely in utility bills. Reduced medical expenditures, prevented societal costs, energy efficiency/conservation and increased economic activity are a few of the presumed positives being counted against capital costs as the state calculates a net benefit of more than $100 billion from CLCPA spending.
The PSC and the staff of the DPS will play a key role in much of this spending, as they regulate the infrastructure by which electricity is delivered and the utility rates by which New Yorkers pay for it.
The three primary topics of discussion at Thursday’s PSC meeting all revolved around that theme, and the escalating costs entailed.
Building Electrification
The commissioners unanimously voted to adopt a strategic framework to redirect and streamline the state’s energy efficiency and building electrification efforts (Cases 14-M-0094 and 18-M-0084).
Both cases predate the CLCPA, but they are an indispensable part of any decarbonization and net-zero strategy. Thursday’s order will update the efficiency efforts to better align with the overarching goals of the CLCPA.
Efforts to date have been inadequate in meeting the needs of low- and middle-income New Yorkers, the DPS staff concluded during its review. The new framework will give greater responsibility to the New York State Energy Research and Development Authority for reaching disadvantaged communities.
The order directs NYSERDA and utilities to file within 90 days proposals totaling $1 billion a year from 2026 through 2030, and to look beyond ratepayers for funding.
“Today’s action establishes this framework where we can streamline and scale program delivery,” PSC Chair Rory Christian said, “by moving away from what we previously looked at as individual utility-level goals towards a focus on more statewide outcomes.”
Commissioner Diane Burman spoke at length about previous efficiency initiatives being a series of good-faith efforts marred by missteps and poor coordination.
Commissioner James Alesi countered with a comparison to the race to put a man on the moon. “There’s going to be failures and there’s going to be frustration,” he said.
Along the way, predicted costs will change and unanticipated costs will arise; new legislation and technology may move the goal line and the path by which it is reached. “But there will be no retreat,” he said. “There cannot be a retreat.”
Commissioner John Howard drilled down on hidden and undisclosed costs. About 20,000 housing units are being weatherized per year across the state, he noted. To meet CLCPA goals, that needs to be 200,000 a year for many years, at a cost of far more than $1 billion a year.
Nonetheless, he called it the first reality-based order he had seen in a long time.
CLCPA Update
DPS Director of Policy Implementation Jessica Waldorf summarized the agency’s inaugural report on the CLCPA implementation (Case 22-M-0149).
The staff-generated review was loaded with technical details such as greenhouse gas emission reductions since 1990 (46%) and a summary of the PSC orders that will help carry out the CLCPA.
There also was a summary of estimated costs authorized as of mid-2023 in support of CLCPA goals: $43.76 billion.
Waldorf said the figures are conservative estimates, and some of the spending was authorized before CLCPA.
The figures will evolve over time, be incurred and paid over an unknown amount of time, and be recovered through a variety of means, not just incremental costs to ratepayers.
Commissioner Tracey Edwards said: “I want to see how we can, for the next annual report, do a little bit more of a deep dive on what you expect to happen.”
Berman, too, asked for something more than a retrospective report, as costs are escalating rapidly and are disproportionately being recovered through rates.
“Folks need to understand what it means, and the challenges going forward,” she said. “We have an obligation to look at the total.”
Howard said: “New Yorkers are desperate to know what this is going to cost. The rhetoric around the CLCPA writ large is, don’t worry, it pays for itself. I think we see from our brief snapshot in 2022 … no, it doesn’t pay for itself.”
Commissioner John Maggiore said there are three enormous challenges at play: Keeping energy affordable and reliable while achieving CLCPA goals. “I don’t think achieving any of these things is going to be easy.”
Waldorf said the state has the advantage of a long head start in planning and early results.
“There’s a lot of anxiety out there about how we can actually achieve the goals of the CLCPA but I think we’ve learned a lot through the decades of work.”
The goals will be difficult to achieve, and the shift of investment will need to be significant, she added, but multiple agencies will use every means available to reduce the cost to ratepayers.
One Case of Many
Spiraling consumer costs came to fore yet again in a rate case before the PSC on Thursday, sparking some of the most passionate comments in the lengthy meeting.
The utility with the most customers in the state, Con Edison, in early 2022 sought an increase of 17.6% in delivery charges for electricity and 28.1% for gas, which it calculated would boost customers’ total bills 11.2% and 18.2%, respectively, and give it a combined $1.7 billion in new revenue (Cases 22-E-0064 and 22-G-0065).
It justified the request, in part, by saying it will be spending money on CLCPA-related projects.
This did not go over well with the public and public advocates. The two cases generated more than 7,500 comments.
After investigation and negotiation, the utility, DPS and stakeholders agreed to a pair of rate plans that will give Con Ed a revenue hike of $1.93 billion — 13.5% more than it asked for — but spread that over three years instead of one.
Edwards cast the lone vote against approving the deal.
“I have a tremendous concern about the structure and the process, because we do have a responsibility for balance,” she said, especially with CLCPA looming — “what are all the other investments that have to be made?”
Many families in New York City are still rebounding from the economic crisis wrought by COVID, and have not reached stability, Edwards said.
“My biggest concern, that I just cannot get past, is that the starting point that the utility put in here,” she said. “I just don’t get it. I don’t understand the world they are living in. … We have to change this process.”
Howard tore into the magnitude of the taxes and fees levied on utilities by New York City. (DPS says property taxes account for 21% of a Con Ed electric bill and 15% of a gas bill.)
A majority of the City Council wrote to PSC, urging it to reject the rate proposal, but the council approved without debate an increase in the property tax charged to Con Ed, Howard said.
This will only get worse as Con Ed spends billions on infrastructure needed to electrify the nation’s largest city, he said.
“There is a boomerang of even greater revenue to the city of New York for that expense. As we clean up the environment, we put in this automatic enrichment to the city of New York.”
Christian spoke in more diplomatic terms about the need to pay now for future benefits, and the pain of doing so.
The 7,500 comments are written in different tones and perspectives, he said, but share a common theme: “Recognition that New Yorkers everywhere still face economic challenges coming out of the COVID pandemic. These hardships are only going to be exacerbated further by rising prices.”
Christian added: “I have solace in the fact that these investments are being used to reinforce much of the work we’ve already done in building the system of the future … and creating a better platform from which we can attain our climate goals and maintain reliability of the system.”
Can’t Pay/Won’t Pay
Con Ed’s monthly collections reports to the DPS quantify the trends Edwards and Christian discussed.
New York City suffered significant economic impacts from the COVID pandemic and continues to have a much higher unemployment rate (5.9% in June) than the rest of the state (3.0%) or nation (3.6%).
In June 2023, 473,000 Con Ed customers were more than 60 days in arrears for a total of $1.03 billion. This compares with 327,000 customers who owed $381 million in June 2019, before the pandemic.
Also telling are the numbers from June 2022, when 453,000 customers owed $1.35 billion. A one-time post-pandemic debt forgiveness program the state implemented would soon reduce the arrears by hundreds of millions of dollars — but more of Con Ed’s 3.6 million customers are behind on their bills now than a year ago.
An offshore wind trade association last week summarized a recent record of remarkable progress in the young U.S. industry but added a caveat: There are severe economic threats to its continued momentum, with project delays and supply chain disruptions likely to continue.
The second-quarter report by the Business Network for Offshore Wind (BNOW) covers a period that contained a major milestone: The first “steel in the water” for the nation’s first two commercial-scale OSW projects — South Fork Wind and Vineyard Wind — following a decade of development work.
The report notes several other measures of progress:
An 18% increase in OSW goals backed by legislative or regulatory directive, which reached 42.8 GW nationwide;
The formation of a domestic supply chain; the first U.S.-made substation, monopile and export cables installed in U.S. waters; and groundbreaking on a component steel facility in Baltimore;
Louisiana undertaking negotiations for wind farms in state waters, which is expected to be a faster development process than in federal waters;
Total market investment reaching $21.6 billion, compared with $5 billion in 2021;
The fleet of specialty vessels built or retrofitted in U.S. shipyards reaching 36, double the number in 2021;
A total of 1,478 contracts awarded, 272% more than in January 2021; 64% went to U.S. companies and 90% went to companies with a U.S. footprint; and
29 ports are under development for manufacturing, marshaling and maintenance.
But then there are the headwinds.
The early wave of OSW projects is concentrated between southern New Jersey and southern Massachusetts, and one after another, developers in that region are saying they no longer can proceed with the projects under terms agreed to years ago because of soaring costs.
The 1,200-MW Commonwealth Wind project has reached an agreement to terminate its power purchase agreements, and the 1,200-MW SouthCoast Wind project is seeking to do the same, both in Massachusetts.
In June, developers of New York OSW projects totaling 4,200 MW told state regulators they may not be able to obtain financing without inflation adjustments.
Projects in New Jersey and Connecticut have sought concessions, as well.
BNOW called this “the duality of the industry” in its report: great strides forward, and a fallback to reassess finances. The trade organization said U.S. and foreign analyses suggest the cost structure has increased at least 20% in the past two years. It expects to start seeing project delays as a result.
In announcing the report, founder and CEO Liz Burdock highlighted the promise of longer-term growth as a new industry takes shape onshore to support the work planned offshore.
“Thanks to supportive federal and state policies, we are seeing unprecedented growth in the U.S. offshore wind supply chain across the nation,” she said Thursday in a news release.
“New contracts are signed daily with a vast majority going to small- and medium-sized American companies creating thousands of new jobs. With $7.7 billion in new U.S. offshore wind investments since the Inflation Reduction Act was signed into law, this is just the beginning. We will see many more factory openings, port revitalizations and vessels under construction in the years to come.”
Initial assessment of the offshore wind energy research lease Maine is seeking shows it would cause minimal environmental impact.
The report, by the U.S. Bureau of Ocean Energy Management, is another step toward wind power development in the Gulf of Maine but does not authorize any construction or operation. It entails only surveys, monitoring and placement of meteorological buoys.
Potential negative factors resulting from this work could include air emissions, noise, lighting, seafloor disturbance, entanglements and routine vessel discharges.
Publication of the draft assessment in the Federal Register on Friday started a 30-day comment period, during which two virtual public meetings will be held as BOEM seeks further input before finalizing the assessment.
BOEM rates potential impact at four levels: negligible, minor, moderate and major. Every effect of the research lease was projected as either negligible or minor — including on commercial and recreational fishing, which has been predicted to sustain a major adverse effect in the environmental impact studies prepared for construction and operation of the other wind farms.
Maine is positioning itself to be a pioneer in floating wind and a leader in the industry expected to develop around it. One of its state university campuses has a robust research-and-development program, and it already has floated a small-scale offshore wind turbine in state waters.
A key part of this is the research array Maine is seeking permission to build within a 10,000-acre zone 20 nautical miles offshore — up to 12 turbines with a total nameplate capacity of up to 144 MW.
The offshore wind farm proposals in the pipeline so far are all on the Outer Continental Shelf off the middle and northeast Atlantic Coast, with towers on seabed foundations in relatively shallow waters. The Gulf of Maine, like most of the Pacific Coast, is too deep for fixed-bottom development and will need to rely on floating wind technology that still is being developed and has minimal worldwide operational history.
LANSING, Mich. — One of the state’s largest municipally owned utilities, the Lansing Board of Water & Light, said last week it will invest $750 million in renewables, storage and natural gas generation over the next decade and pledged to be carbon neutral by 2040.
The utility plans to add 658 MW of renewable energy and storage and at least 110 MW of natural gas. Its current portfolio has a nameplate capacity of 581 MW. It closed its last coal-fired plant in 2022, becoming the largest coal-free utility in Michigan.
“This is the largest planned growth in BWL’s nearly 140-year history,” General Manager Dick Peffley said in a statement.
The plan will add 2.5 to 3% to customer bills.
The clean energy projects are expected to be complete between 2025 and 2027, and include 160 MW of battery storage; 65 MW of local solar; 195 MW of additional solar outside of the Lansing region; and 238 MW of wind outside of the Lansing region. The projects were selected from among 96 offers totaling 8,330 MW in response to its “all source” request for proposals.
The utility also said it will continue its energy efficiency efforts and add demand response programs.
The electric storage facility could provide as much as 16% of the 1,000-MW storage capacity called for in Michigan’s MI Healthy Climate plan, an outsize contribution for a utility that has 100,000 electric customers and serves 6% of the state’s load.
BWL received $12 million from the Michigan Public Service Commission for the construction of 10 MW of solar and 40 MW of four-hour battery storage at Delta Energy Park, the former site of the coal-fired Eckert Power Station, which was retired in 2020.
Delta also will be the site for a new 110-MW reciprocating internal combustion engine (RICE) gas plant by 2026. BWL also called for “a possible additional gas plant at a location to be determined later dependent on future load requirements and regional energy regulations.”
The projects and estimated costs “are still under negotiations with the proposed developers and are subject to change pending contract agreements,” the utility said.
When all the new generation projects are online, a company spokesperson said, BWL will generate nearly twice as much electricity as it does now.
“Once implemented, this will bring BWL’s total generational portfolio to around 58% renewable and reduce our carbon footprint by 75% compared to 2005,” Peffley said.
The utility says the additional power generation could help attract new businesses to the capital region and also could allow for sales of excess power to other utilities.
BWL provides power to several major corporate customers, including several large General Motors plants, along with state government and residential customers in Ingham, Eaton and Clinton counties. Michigan State University, in East Lansing, generates its own electricity, though most of the rest of the city is serviced by BWL.
In addition to gas-fired plants, BWL also has two wind sites and four solar sites.
Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee on Wednesday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be covering the discussions and votes. See next week’s newsletter for a full report.
Markets and Reliability Committee
Consent Agenda (9:05-9:10)
The committee will be asked to endorse as part of its consent agenda:
B. proposed conforming revisions to a slate of manuals and PJM practices addressing the interconnection process overhaul approved by FERC last year (ER22-2110). (See “Manual Revisions for Interconnection Process Overhaul Sent to MRC,” PJM OC Briefs: July 13, 2023.)
C. proposed revisions to Manual 13: Emergency Operations resulting from its periodic review.
Endorsements (9:10-9:25)
1. NERC TPL-001-5.1 Manual 14B Revisions
PJM’s Stanley Sliwa will present proposed revisions to Manual 14B: PJM Region Transmission Planning Process to conform to NERC’s TPL–001-5.1 standard. The proposal was endorsed by the Planning Committee earlier this month through the quick-fix process, which allows for a problem statement, issue charge and solution to be brought concurrently and voted on in the first meeting. (See “Stakeholders Endorse Quick Fix Manual Revisions to Conform to NERC Standards,” PJM PC/TEAC Briefs: July 11, 2023.)
The committee will be asked to endorse the proposed manual revisions upon first read.
Members Committee
Consent Agenda (11:35-11:40)
The committee will be asked to endorse as part of its consent agenda:
B. proposed clarifying revisions to PJM’s tariff, Operating Agreement and Reliability Assurance Agreement, which were approved by the Governing Documents Enhancements and Clarifications Subcommittee in April.
C. a proposed solution and corresponding tariff revisions related to calculating the smooth supply curves for the Base Residual Auctions. The changes are meant to clarify that PJM will publish only smooth supply curves following BRAs and not Incremental Auctions. (See “Stakeholders Approve Tariff Clarification on Smooth Supply Curves,” PJM MRC/MC Briefs: June 22, 2023.)
PJM’s Darrell Frogg will present a proposal to create a cost-of-service mechanism for generators designated as critical to the derivation of an interconnected reliability operating limit under NERC’s Critical Infrastructure Protection standards. (See “MRC Endorses IROL-CIP Cost Recovery,” PJM MRC/MC Briefs: June 22, 2023.)
The D.C. Circuit Court of Appeals dismissed a pair of challenges Friday to FERC’s authorization of the long-contested Weymouth, Mass., compressor station. The court determined that it lacks jurisdiction over the petitions, which were filed by a group of nearby residents to the compressor.
The ruling is the latest blow to the Fore River Basin residents and environmental justice organizations that have been fighting the compressor station for about nine years. The compressor became operational following FERC’s final authorization in September 2020.
One of the petitions challenged the FERC-issued Extension Order which gave Enbridge, the owner of the compressor station, additional time to build the project following delays to construction. The second petition asked the court to review FERC’s denial of rehearing of the In-Service Authorization Order (see FERC’s Handling of Environmental Justice Issues Debated in Court.)
“We lack jurisdiction to consider either petition, so we dismiss them both,” the D.C. Circuit wrote.
Opposition to the project has centered around the cumulative health consequences and acute dangers of siting the facility near residential neighborhoods and industrial facilities, including multiple fuel storage areas, the largest hazardous waste disposal site in New England, a natural gas plant and a chemical manufacturing facility.
To make matters even more precarious, opponents argue, the compressor station was built on a flood-prone parcel of landfill that juts out into the water and is contaminated with a mix of diesel fuel, arsenic and coal ash. Opponents of the compressor expressed disappointment in the court’s ruling.
“This is a demoralizing outcome that makes it clear that health and safety play second fiddle to fossil fuels and profit,” said Braintree Town Councilor Elizabeth Maglio, a vocal opponent of the compressor.
A 2019 background health analysis conducted by the state found that communities in areas surrounding the compressor site have elevated concentrations of conditions related to air pollution, including asthma, heart attacks, COPD, heart disease and lung and bronchus cancer.
Meanwhile, a 2002 health survey of Weymouth residents found higher-than-expected levels of aplastic anemia, a bone marrow condition linked to benzene, a pollutant frequently found in uncombusted natural gas in the Greater Boston area.
Michael Hayden of Morrison Mahoney LLP, the attorney representing local residents, told RTO Insider that while the Court held that there is no jurisdiction for the appeal, “the Court’s decision does not comment upon our environmental justice concerns or arguments.”
In consideration of the first petition, regarding the Extension Order, the D.C Circuit ruling did acknowledge that the petitioners had demonstrated injuries related to the compressor station’s siting, including from air pollution and increased safety risks. However, it said FERC already reconsidered the Extension Order, and ruled “the Fore River Residents have already received all of the procedural relief they requested.”
“While we’re disappointed, we are not exactly surprised,” said Alice Arena of Fore River Residents Against the Compressor Station, one of the petitioners in the case. “This was the same court that totally ignored the fact that FERC violated its own regulations in allowing the Weymouth compressor without an [environmental impact statement].”
Hayden said he was unsure if the defendants would pursue further challenges to FERC’s approval of the compressor station.
“We need to study it and determine whether there’s any further appellate action warranted,” Hayden said, noting there’s a trial scheduled in October before the Massachusetts Department of Environmental Protection on the compressor station’s Chapter 91 waterways license.
The D.C. Circuit Court of Appeals on Friday upheld a FERC decision suspending the application of PJM’s transmission constraint penalty factor (TCPF) after it led to spiking prices that could not be addressed on Virginia’s Northern Neck Peninsula (22-1090).
The TCPF caused prices to spike on the peninsula in the Chesapeake Bay after a transmission line was taken out of service early last year so the local grid could be upgraded. Cheaper generation or demand response were not available in the area to offset its impact, so PJM requested it suspend the rule in this case as the higher prices were incapable of eliciting any kind of market response.
FERC approved PJM’s request, with a dissent from Commissioner James Danly. Energy trading firm Citadel FNGE appealed the decision to the D.C. Circuit. Judge Justin Walker (a Trump appointee) dissented from the majority in the case, saying the court should have remanded it to the commission. (See FERC Approves Pause of PJM Tx Constraint Penalty Factor in Va.)
Chief Judge Sri Srinivasan and Judge Patricia Millet (both Obama appointees) sided with FERC, saying it was reasonable to suspend the rule, which is meant to get a market response that ultimately would solve the congestion at issue.
“Because application of the penalty factor increased costs for consumers without a commensurate benefit, the commission reasonably found that its application in this context was unjust and unreasonable,” the court said.
The TCPF represents the maximum cost that PJM will incur to resolve the problem-causing congestion, with an algorithm seeking the least-cost way to relieve congestion, which if not available leads to prices of $2,000/MWh.
With the transmission line out, the peninsula’s customers could be served only by two other transmission lines and a set of combustion turbine units.
“That lack of available resources caused the local marginal price to fluctuate drastically in times of congestion,” the court said. “For example, even when the turbine units were fully operating in the early morning hours, they were insufficient to prevent congestion, so the penalty factor kicked in.”
Local solar plus those combustion turbines were able to mitigate prices when the sun was out, but the penalty factor was unable to send consistent or reliable signs about whether an investment or response to the congestion was needed.
“Material short-term investments would not occur, PJM explained, because new resources would not come online until after the Lanexa line upgrade was completed,” the court said. “At that point, the demand for the newly placed resource would evaporate.”
Citadel challenged PJM, saying the RTO failed to prove a link between the temporary $2,000/MWh prices and what consumers in the area actually paid. It also argued that PJM failed to prove that nothing could respond to the price signals and argued suspending the rule would inject regulatory uncertainty into the market.
The court said FERC was not required to show the spiking congestion costs would impact retail rates because the Federal Power Act refers only to the unjustness and unreasonableness of rates.
“The commission concluded that increased prices on one side of the balance without any value on the other side of the scale — all pain and no gain — were unjust and unreasonable,” the court said.
While customers pay a zonal rate, the higher congestion costs would go into that calculation, leading to overall higher rates, and Citadel failed to show any offsetting impacts, it added.
The firm also argued the suspension would harm the financial transmission rights market, in which it participates.
“But the temporary suspension of the penalty factor in one geographically unique area does not stop financial firms from benefiting from congestion pricing,” the court said. “Financial firms will still receive congestion costs, albeit less in one small part of the grid, during the temporary suspension of the penalty factor.”
Walker’s Dissent
Judge Walker said the court should have remanded the order to FERC for further proceedings, with Citadel’s arguments having convinced him. Transmission expansion was sped up after FERC’s order, which Citadel argued showed the constraint was working.
“Yet when FERC was later given evidence that the penalty factor was incentivizing transmission investment, FERC moved the goalposts,” Walker said. “Instead of reasoning, as it had before, that the rate was providing no benefit, FERC instead said any benefit it provided wasn’t big enough.”
That shift in standards was arbitrary and capricious, so the order should have been remanded, he added.
PJM CEO Manu Asthana thanked a group of Ohio legislators in a letter Friday for their “constructive engagement” on the cost allocation implications of Illinois’ climate policies that will require fossil plants to start shutting down starting in 2030. (See Ohio Legislators Raise Concerns About Cost Impact of Illinois’ CEJA.)
Ohio House Public Utilities Committee Chair Dick Stein (R) and Senate Energy and Public Utilities Committee Chair Bill Reineke, along with 10 other colleagues, sent PJM a letter raising concerns about a preliminary estimate the RTO produced saying Illinois’ policy of retiring thermal power plants would lead to about $2 billion in transmission upgrades. In the letter and in meetings with RTO staff, they asked for a more formal estimate, including the assumption that Ohio is left out of that cost allocation.
“We appreciated the frank and open discussion regarding your concerns and your understanding of the limitations PJM faces in conducting exclusionary transmission studies,” Asthana wrote back. “The model that PJM uses for transmission analysis is not configured in a way that would let us exclude Ohio from the study results. The high-voltage transmission system is an interstate system, and electrons travel without consideration for state boundaries.”
Asthana said PJM is working to reform its markets and transmission planning, and in that effort, it hopes to better understand the impacts of federal and state policies on its system. “PJM pledges to work with Ohio policymakers to keep you fully informed of the transmission project development and cost allocation implications of our ongoing planning efforts related to this dynamic system.”
The Ohio legislators had written that the state has had success with PJM’s competitive markets, and Stein repeated that assertion in an interview with RTO Insider last week. But he said his constituents and others should not have to pay for the effects of another state’s policies.
“Ohio residents — and Pennsylvania and other surrounding states that are going to have to feed that power to them — shouldn’t be responsible for a policy another state makes that is that costly across the region,” Stein said.
Stein said he and his colleagues would continue to work with stakeholders in other states to ensure that reliability and affordability are maintained as the grid becomes more clean.
Illinois is not the only state shifting away from fossil fuel power plants to cleaner generation, the latter of which is exclusively being paid for by those state’s ratepayers. That new, renewable generation is going to add cheap power to the grid, which would tend to lower wholesale prices everywhere in PJM.
Those wholesale price impacts are part of the calculus going forward, but Stein said another concern is the capacity market and its continued ability to keep dispatchable generation that Ohio plans to keep using online. One option Stein said is off the table is state subsidies for those dispatchable plants, as the Ohio legislature does not want a repeat of House Bill 6, which was influenced by a bribery scheme by FirstEnergy. (See Former Ohio House Speaker Householder Sentenced to 20 Years in Prison.)
“All we’re trying to do is make sure we advocate for what we think is good policies here for Ohio; obviously, the people in Illinois are advocating [for] what they think the people in Illinois want,” Stein said. “And it really puts the most pressure on PJM because somehow they’ve got to bring all these elements together and make everybody happy. And as we well know, sometimes that’s not easy, if at all possible.”
CAISO issued its first energy emergency alert (EEA) of the summer Thursday evening after coming up short on the ramping capacity needed to meet its peak net load as solar output rolled off its system during sunset.
The California grid operator declared an EEA-1 at 7:30 p.m. PT on a day marked by largely normal summer temperatures in most of the state’s population centers, as well as an elevated but relatively moderate system peak load of 42,266 MW, which occurred at 6:30 p.m. An EEA-1 represents the lowest level of grid emergency, called by the ISO when it confronts capacity shortages after all available resources either are in use or have been committed to use, prompting the need for conservation.
CAISO data shows that the ISO’s net load — total system load minus output from wind and solar — began to exceed the ISO’s day-ahead forecasts at about 6:40 p.m. By 7:50 p.m., as system load tapered to 40,989 MW, net load simultaneously rose to its daily peak of 37,038 MW, exceeding the day-ahead net load forecast of 35,533 MW for that five-minute interval.
“The market went into the hour a bit thin on the interchange while net demand was increasing,” CAISO spokesperson Anne Gonzales told RTO Insider. “The amount of energy available within the hour was not as robust during net load peak as solar ramped off the system, compared to other similar days. As a result, within the hour, the market was not moving enough resources to balance supply and demand while solar was ramping down.”
CAISO called on demand response resources beginning at the 7:50 p.m. interval, quickly reducing net load to levels closer to forecast. The EEA-1 was concluded at 8:30 p.m.
“As soon as the operators became aware of the situation, they manually dispatched additional generation, deployed some demand response programs available to them and made adjustments in the market to increase energy output and the EEA-1 was soon canceled,” Gonzales said.
The role of imports in the emergency remains an open question. While much of California saw moderate weather that day, neighboring areas in the Southwest continued to endure a record-setting heat wave accompanied by high electricity demand.
Asked whether “thin” conditions on the interchange indicated that imports into the ISO were lower than expected during the event, Gonzales said, “We’re still doing analysis on that. Demand came in slightly higher than forecast and more energy was needed for about an hour during the net peak load. We will know more after market analysis, however.”
Gonzales said the emergency would cause CAISO to make “adjustments going into the net peak hours to account for this going forward,” but added that it did not expect to issue a flex alert, EEA watch or call for restricted maintenance operations over the weekend.
Real-time prices during the event surged to around $250/MWh at nodes across the ISO, after hovering around $30/MWh and lower in the preceding intervals.
The EEA-1 occurred about a week after CAISO announced that this year it hit a 5,000-MW milestone for installed battery capacity, reaching 5,600 MW on July 1. California has moved aggressively to install additional batteries to help meet evening ramps, and the ISO expects to bring on an additional 2,000 MW in the next couple of months, CEO Elliot Mainzer said Wednesday during the joint meeting of the CAISO Board of Governors and Western Energy Imbalance Market’s Governing Body.
During that joint meeting, Mainzer also lauded the performance of CAISO and the wider West for managing challenging conditions in the face of widespread and persistent heat.
“Fortunately, notwithstanding a few local challenges, I think the overall grid has held up well, which I think points to certainly a lot of work within California and across the West on resource adequacy, bringing new resources onboard. Obviously outstanding hydro conditions inside California, and a tremendous amount of operational coordination and communication coordination around the region” also helped, Mainzer said.
“Of course, we have a lot of summer left. Ever vigilant, ever watchful,” he added.
