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July 7, 2024

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NEPOOL Markets Committee Briefs: April 9-10, 2024

ISO-NE continued work on resource capacity accreditation (RCA) changes at the Markets Committee on April 9 and 10, outlining how changes to the overall resource mix could affect the reliability value of different resource types.  

Dane Schiro of ISO-NE detailed additional results related to the RCA impact analysis. ISO-NE in February presented the analysis’ initial results, which showed how the RCA changes would affect the amount of accredited capacity for different resource types. (See NEPOOL Markets Committee Briefs: Feb. 6, 2024.) 

Building on the impact analysis, ISO-NE conducted sensitivity analyses looking at the effects of three scenarios changing the resource profile: the addition of renewables, the replacement of oil capacity with renewables and the replacement of coal capacity with renewables. 

The RTO in March presented the first phase of these analyses to the MC, focusing on how the scenarios would affect overall system reliability. (See NEPOOL Markets Committee Briefs: March 13, 2024.) At the April MC, Schiro outlined how the scenarios would affect the seasonal reliability benefits of different resource types.  

While the reliability contributions of resources including gas, oil and hydro remained consistent throughout the scenarios, wind, solar and energy storage varied significantly. 

For energy storage, reliability value increased in the summer in every scenario, with the greatest increase shown when renewables replaced oil resources, the scenario with the greatest reliance on renewables.  

Schiro noted that the value of energy storage is “closely related” to the duration of reliability risk events, increasing as the events get shorter. The addition of renewables in the summer reduced the length of risk periods by delaying the onset of the risks, Schiro said.  

In contrast, replacing coal and oil with renewables hurt the value of energy storage in winter because the duration of reliability risk events generally increased in these scenarios.  

The analysis also showed scenarios with greater renewable penetration hurt the value of wind resources. Wind resources typically all have high output at similar times, reducing the likelihood that periods of high wind generation face reliability risks, Schiro said. Therefore, the modeling found that adding wind capacity would produce diminishing reliability benefits.  

The modeling showed a similar reduction to the reliability benefits of solar resources as solar generation increased, Schiro added.  

Accreditation Calculation Updates

ISO-NE also provided additional details on its plans to calculate the accredited capacity of demand resources. For active demand capacity resources (ADCRs), the RTO will construct a “seasonal energy profile that represents their historical hourly availability over the last three years’ real-time offer data in the energy market.” 

ISO-NE then will use this profile to assess ADCRs’ performance during periods with reliability risks. Unlike passive demand resources (PDRs), ADCRs will have an annual opportunity to challenge their energy profile.  

The accreditation values of PDR resources will be based on “a single, common system-wide profile (different for each month) that represents the demand reduction associated with a given hour,” and will use reconstitution data from the previous five years, Christopher Parent of ISO-NE said.  

For energy storage resources, duration and round-trip efficiency will be the key factors in accreditation, Parent said. Market participants with energy storage resources will have one opportunity to challenge these values.  

Stakeholder Proposals

Tom Kaslow of FirstLight expressed concern that ISO-NE’s accreditation proposal may overvalue gas resources that lack firm fuel contracts.  

Kaslow said ISO-NE should consider increasing the daily operating hours requirement from 12 hours to 16 for gas resources. This would increase the amount of firm gas a resource would need to procure to receive its maximum possible accreditation value, and would reduce the value of nonfirm gas, Kaslow said.  

Meanwhile, Ben Griffiths of LS Power proposed changes to how ISO-NE is proposing to model resource outages. Griffiths argued that relying solely on historical data to estimate future outage rates could cause prolonged outages from abnormal equipment failures to have outsized impacts on individual resources’ accreditation values. 

“Resources can have equipment-related outages of extended duration that, once resolved, should not be expected to occur again,” Griffiths said. “In these instances, historic performance is a poor predictor of future performance. … Nevertheless, the ISO’s current proposal will include that outage for three to five years.” 

To prevent these distortions, Griffiths said a resource that deals with an extended, abnormal outage “should be able to challenge its default value and propose a substitute that better reflects expected output.” 

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ERCOT to Host Summit on Grid Transformation

ERCOT has attracted a full house for its first Innovation Summit, featuring thought leaders in energy research and innovation exploring “solutions that use innovation to impact grid transformation.” 

The grid operator says in-person attendance has been filled for the May 21 event in Austin, Texas. However, streaming is available. 

ERCOT CEO Pablo Vegas said the summit is necessary to address the grid’s rapid transformation and changes to the resource mix, decentralization of generation, electrification, emerging prosumers and digitization. 

“The summit is an opportunity for stakeholders from Texas and around the country to collectively discuss these transformation opportunities and challenges,” he said in a news release. 

Panel discussions will feature industry executives and subject matter experts on essential reliability services, demand flexibility, uncertainty management, energy storage resources, transmission planning and technology trends. The summit is open to ERCOT market participants, vendors, grid operators, academia and research labs interested in understanding how the transformation is shaping the grid’s future, the ISO said. 

“The summit will be an invaluable opportunity for stakeholders wanting to immerse in discussion, network with industry peers and brainstorm solutions for using innovation to impact transformation,” said Venkat Tirupati, ERCOT’s vice president of DevOps and grid transformation. 

More Time on CPS Shutdowns

ERCOT said April 10 it needs additional time to conduct its reliability analysis of CPS Energy’s planned retirement of three aging gas-fired units in 2025. 

The grid operator’s protocols require it to complete a reliability assessment when an entity notifies staff that it intends to shut down a resource. Market participants had until April 3 to submit comments on the utility’s proposal. 

The San Antonio municipality notified ERCOT in March that it intended to “indefinitely suspend operations” of three steam turbines at its V.H. Braunig facility. The units have a combined summer seasonal net maximum sustainable rating of 859 MW. (See CPS Energy Plans to Retire 859 MW of Gas Resources.)

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Scandal-ridden Former PUCO Chair Sam Randazzo Found Dead

Former Public Utilities Commission of Ohio Chair Sam Randazzo, who faced multiple criminal counts for taking millions of dollars in bribes from FirstEnergy, died by suicide April 9, according to multiple news reports. 

The Franklin County, Ohio, coroner’s office said Randazzo, 74, was found dead just before noon Central Time in a Columbus warehouse he owned, the Columbus Dispatch reported.  

Local NBC news affiliate WCMH said the coroner confirmed the death was by suicide. WCMH said the building where the former PUCO chair was found was owned by Sustainability Funding Alliance of Ohio, a Randazzo-owned consulting firm cited as a shell company in court documents in state charges filed against him. 

Randazzo became caught up in one of Ohio’s biggest political scandals in history after the FBI raided his home in November 2020, prompting his resignation from the commission shortly after. In July of that year, FirstEnergy had entered a deferred prosecution agreement in which it admitted to bribing Randazzo and former Ohio House Speaker Larry Householder. Householder is serving 20 years in federal prison. 

Randazzo avoided prosecution for years but was indicted on federal bribery charges in November. (See Former Ohio PUC Chair Charged with Bribery.) 

According to that indictment, before assuming the top role at PUCO in 2019, Randazzo solicited $4.3 million in bribes from former FirstEnergy CEO Charles Jones and Michael Dowling, the company’s former senior vice president of external affairs, in exchange for helping the company win a $1 billion bailout for its financially distressed nuclear plants.   

Randazzo allegedly arranged the payment after meeting with the two executives at his home in December 2018. The executives then lobbied for his appointment to the commission. The indictment included messages between the executives and Randazzo. 

The federal indictment also alleged Randazzo embezzled at least $1 million from an industry group representing large industrial energy users in Ohio through Sustainability Funding Alliance of Ohio going as far back as 2010. 

Randazzo was indicted a second time in February by the state of Ohio, along with Jones and Rowling. The indictment covered 27 charges, including bribery, engaging in a pattern of corrupt activity and money laundering, WCMH reported.  

If convicted, Randazzo faced a potential 20-year prison sentence. 

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DC Circuit Rejects Challenge to California Car Emissions Waiver

The D.C. Circuit Court of Appeals on April 9 rejected a challenge from Republican state attorneys general and others against California’s ability to set its own regulations on automobile emissions under the Clean Air Act (22-1081). 

The three-judge panel threw out arguments that EPA’s decision reinstating stricter requirement was against the law, finding that the petitioners lacked standing to bring up such arguments. But the panel did address their argument that EPA violated the constitutional requirement that the federal government treat states equally in terms of their sovereign authority, rejecting it on the merits. 

States generally have broad discretion in regulating emissions under the CAA, but when it comes to standards for new automobiles, that is generally not the case. The law allows the EPA administrator to grant exemption to states that passed their own emissions controls before March 30, 1966, if the state standards are at least as protective of public health and welfare as the federal rules. 

California is the only state that has taken advantage of that, and EPA has to approve the waiver as long as the state standards are not arbitrary and capricious and do not require extraordinary conditions. 

“The federal regulations continue to act as the floor for emissions regulations, but California can seek to enact its own, more stringent regulatory program above those federal requirements,” the court said. 

California was the only state to have enacted its own standards when the CAA was enacted in 1967, and its air quality and pollution issues would not have been addressed by the laxer federal standards proposed back then. 

“At the same time, automobile manufacturers were growing concerned that other states might begin regulating automobile emissions, subjecting them to a patchwork of regulatory obligations and significantly increasing manufacturing costs,” the court said. “Congress enacted Sections 209(a) and (b) to balance the fears of automobile manufacturers, California’s need for bespoke regulation and the federal interest in allowing California to test new emissions regulations.” 

California still has more problems with air pollution than most of the country, being home to seven of the 10 worst areas for ozone pollution and six of the 10 worst areas for particulate matter. Those conditions are worsened by climate change, which also impacts the large agricultural business in California, its water supply and wildfire susceptibility. 

The Golden State first tried to get a waiver to cover greenhouse gas emissions in 2005; it was updated in 2012 when the state sought to promulgate a new set of regulations called the Advanced Clean Car Program. That included a requirement that 15% of manufacturers’ fleets be electric cars by model year 2025. 

EPA initially granted the waiver in 2013, then rescinded it under the Trump administration. The agency reversed itself in 2022 under President Joe Biden. 

The state attorneys general put forward an argument that EPA could not grant California the waiver because the 15th Amendment prohibits Congress from using its Commerce Clause power in a way that withdraws sovereignty from some states, but not others. The same argument has been brought up in two other circuit courts, which also rejected it. 

EPA, and several Democratic state attorneys general who joined in the defense, argued that the petitioners were not trying to increase their own sovereign authority, but instead limit California’s authority.  

While the D.C. Circuit noted that the Supreme Court has accepted that kind of “leveling down” remedy when states have invoked the right to equal treatment, no court has ever applied the equal sovereignty principle as a limit on the Commerce Clause or other powers allocated to Congress. 

The Republican attorneys general argued that the principle bars Congress from enacting legislation under the Commerce Clause that leaves some states with more sovereign authority than others, regardless of its reasons. That might apply to the 15th Amendment, the court said, but not the Commerce Clause, which gives Congress the power to regulate commerce between states, foreign nations and tribes. 

“The fact that some constitutional clauses explicitly contain an equality-based guarantee therefore supports a negative inference — though perhaps only a mild one — that the Commerce Clause is not so constrained,” the court said. 

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Grid Operators Report Reliable Operations During Eclipse

Grid operators reported zero issues managing the bulk electric system April 8 as a total eclipse briefly shaded solar panels across ISO-NE, NYISO, MISO, SPP and ERCOT.  

MISO reported that it and its members “successfully managed” grid conditions as the solar eclipse moved through its footprint, cutting a path of totality over its offices in Little Rock, Ark., around 1:51 p.m. CT, and Carmel, Ind., at 3:06 p.m. ET.  

The grid operator said it increased its short-term, 30-minute reserves, regulation reserves and ramp requirements to manage the eclipse’s impacts. MISO said prior to the eclipse, its solar fleet was producing nearly 4 GW, which dropped to just below 300 MW during totality and returned to about 3.8 GW afterwards.  

“We accessed our increased regulation reserves to manage the rapid changes in system conditions,” MISO spokesperson Brandon Morris said in an emailed statement to RTO Insider. 

Southern Renewable Energy Association Executive Director Simon Mahan captures the eclipse in Heber Springs, Ark. | Simon Mahan

ERCOT said it operated normally through reduced solar generation. Its solar fleet slowed to about 800 MW around 1:30 p.m. CT. Fifteen minutes earlier, ERCOT recorded a 5-GW contribution from its solar fleet. By 2 p.m. CT, ERCOT’s solar production was back to 5 GW and spiked to more than 13 GW by 3 p.m. CT, supplying more than 25% of the fuel mix. ERCOT relied on a combination of natural gas, wind production and energy storage during the temporary darkness.

The ERCOT fuel mix on April 8 showed a drop in solar generation | ERCOT

ISO-NE said operations went smoothly as the moon crossed in front of the sun in New England. Preliminary estimates from the system operator indicate the eclipse led to about a 4-GW reduction in solar production, with 3 to 3.5 GW coming from behind-the-meter sources and 650 MW from grid-connected installations.

“Our preparations paid dividends. The work done ahead of time to understand how the eclipse would impact the regional power system was crucial to a smooth operating day,” said Steven Gould, ISO-NE’s director of operations.

NYISO said it maintained reliable operations while the sun’s corona was observable to crowds. Prior to the eclipse, NYISO said its front-of-meter and behind-the-meter solar resources collectively generated a little more than 3 GW. When New York went dark around 3:30 p.m. ET, solar output dwindled to just under 600 MW. By 4 p.m. ET, solar generation in NYISO had ramped back up to 1.2 GW. 

NYISO said it dispatched thermal generation and hydropower to make up for the loss of solar output. 

The Indianapolis area plunged into darkness just after 3 p.m. on April 8 | © RTO Insider LLC

Before the eclipse, SPP said it expected no significant grid impacts and a dip in grid-connected and distributed solar generation no greater than 1 GW. It said it had ample output from other types of generation available to compensate. SPP said most of its footprint experienced 50 to 75% eclipse coverage. Afterward, SPP shared photos of the “mesmerizing” event captured by its employees on X.

Jon Lamson and Tom Kleckner contributed to this report.

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Bill Would Exempt Md. Data Centers with Fossil Fuel Backup from PSC Approval

Getting bills through the Maryland General Assembly often involves compromises and tradeoffs, even with Democrats controlling the House of Delegates, the Senate and the governorship. 

So, compromises and some controversy were very much in the mix for energy bills and programs as the General Assembly raced toward the official close of its 2024 legislative session at 11:59 p.m. April 8. 

The passage of S.B. 474, aimed at allowing data centers to use fossil fuel-powered backup power, was achieved via a controversial compromise. Introduced by Senate President Bill Ferguson (D), the bill would exempt facilities, such as data centers, using fossil-fuel generation for emergency backup power from having to apply to the Maryland Public Service Commission for a certificate of public convenience and necessity (CPCN). 

The impetus for the bill was the PSC’s refusal last year to approve a CPCN for a proposed data center with 168 backup diesel generators in Frederick County, which prompted the center’s developer to pull out of the project. 

The bill had strong support from Gov. Wes Moore (D), who is seeking to draw data centers to Maryland as their development booms in Northern Virginia, but it ran into opposition from environmental groups. The Maryland League of Conservation Voters had opposed the bill and said it would include lawmakers’ votes on it in its annual legislative scorecard. 

But the LCV was mollified with an amendment that would channel 15% of the tax revenues raised from data centers in the state into a fund for clean energy projects, according to a report on Maryland Matters. Both houses of the legislature passed the bill unanimously. 

Compromise amendments also secured passage of the Distributed Renewable Integration and Vehicle Electrification (DRIVE) Act (H.B 1256), which seeks to promote “beneficial electrification” via time-of-use (TOU) rates for residential customers and bidirectional electric vehicle charging. 

TOU rates set high per-kilowatt-hour prices during times of peak demand and significantly lower prices for off-peak hours, with the goal of encouraging residential customers to shift their energy use.  

As originally introduced by Del. David Fraser-Hidalgo (D), the bill would have required default TOU rates, with an opt-out choice for residential customers, but was amended to allow Maryland’s investor-owned utilities to launch pilot, voluntary TOU programs with specific targets for customers to opt in to the rates. By July 1, 2026, the utilities would have to report to the PSC on whether TOU rates had helped defer distribution system upgrades and on the feasibility of making TOU rates the default choice for residential customers.  

The bill would also direct the PSC to establish “expedited processes for interconnecting” bidirectional EV chargers. Utilities would also be required to develop rates for compensating customers who feed power back into the grid via a bidirectional charger. 

The vote was 100-39 in the House and 47-0 in the Senate. 

A House-Senate conference committee was needed to hash out final amendments for H.B. 864, which would update the state’s energy efficiency and conservation plans ― in particular, the EmPOWER Maryland program for low-income consumers. 

The bill would require both electric and gas utilities to meet energy savings and emission-reduction targets that are in line with the state’s goals while expanding the definition of efficiency to include both demand response and electrification. It would set 2016 as the base year and require utilities to develop efficiency programs that cut emissions from retail sales 2% below the base in 2024, 2.25%/year in 2025 and 2026, and 2.5%/year beyond. 

Other provisions call on the state Department of Housing and Community Development to develop energy efficiency programs specifically for low-income residents and direct the PSC to establish a working group to examine how efficiency programs can be extended to moderate-income residents. 

H.B. 864 had strong support from environmental groups, passing 100-36 in the House and 32-12 in the Senate. 

Environmental advocates and the Maryland Energy Administration (MEA) called foul over an amendment slipped into the must-pass budget bill that would block funding for the agency to set building performance standards, as reported in Maryland Matters. 

The amendment would put a hold on funding for MEA to set a metric of building energy efficiency called energy use intensity (EUI), which expresses energy use as a function of building size and other characteristics. The amendment would delay the setting of EUIs ― and building performance standards ― until MEA completes a study on the feasibility of the state’s greenhouse gas reduction goals for the building sector, set at 20% by 2030 in the Climate Solutions Now Act (CSNA) of 2022. 

The budget bill (S.B. 360) passed April 5, 44-0 in the Senate and 124-9 in the House. 

OSW Reset, Geothermal Pilot

H.B. 1296 is aimed at boosting Maryland’s flagging offshore wind industry, which has faced the same inflation and supply chain challenges that have stalled out other offshore wind projects along the East Coast. 

The bill would direct the PSC to open a new proceeding by June 1 to re-evaluate “certain offshore wind projects” while allowing developers to resubmit their applications with revised schedules, sizes and pricing, including prices for the state’s offshore renewable energy certificates (ORECs). 

Danish offshore developer Ørsted canceled its agreement with Maryland for the 966-MW Skipjack Wind project, saying the OREC price it had previously negotiated was no longer economically viable. When it announced the cancellation in January, Ørsted said it would continue to develop the project in the hopes of getting a better deal in the future. (See Ørsted Cancels Skipjack Wind Agreement with Maryland.) 

The bill passed the House 97-36 and the Senate 34-11. 

The Working for Accessible Renewable Maryland Thermal Heat (WARMTH) Act (H.B. 397) is a first step in exploring the use of geothermal energy to replace natural gas. The bill would require gas companies with more than 75,000 customers to develop and submit to the PSC plans for pilot geothermal networks, which are closed-loop geothermal systems that tap the planet’s natural warmth to provide heat and cooling to multiple homes. 

Gas companies with fewer than 75,000 customers can — but are not required to — submit geothermal plans. After the pilot, the PSC, MEA, the Office of People’s Counsel and other stakeholders would decide whether to make the projects permanent. 

With minor amendments, the House passed the WARMTH Act by a 98-34 vote, and the Senate by 36-9. 

Green Buildings and Power

S.B. 258 was passed without major amendments. Despite the budget cuts to MEA’s work on building performance standards, the bill would raise energy savings targets for state buildings from 10% in 2029 to 20% in 2031. 

Other provisions call on the Maryland Green Building Council to update the High Performance Green Building Program to help the state meet the goal of cutting emissions 60% below 2006 levels by 2031, set in the CSNA. 

The bill would also require the state’s Department of General Services to identify state buildings that could benefit from energy performance contracts, in which third-party efficiency providers guarantee a certain level of energy and dollar savings. If the targets are not met, the provider pays a penalty. 

The vote was 37-9 in the Senate and 103-34 in the House. 

S.B. 1, sponsored by Sen. Malcolm Augustine (D), would require the state’s retail electricity providers that offer “green power” to their customers to document whether they actually are selling electricity generated by a renewable power project or the renewable energy certificates (RECs) from a project that could be located outside the state. 

To offer green power, a retail supplier must show that the electricity being provided is at least 51% from renewables or RECs or at least 1% more than the amount of clean power required under the state’s renewable portfolio standard. For 2024, the state’s RPS calls for about 37% of Maryland’s power to come from renewables, but Gov. Moore has committed the state to 100% clean power by 2031. 

Prices for green power would be set through a yearly proceeding before the PSC, and retailers would have to have visible disclosures on their websites explaining that the purchase of a REC did not necessarily mean renewable energy also had been purchased. 

The green power provisions are part of a larger bill focused on regulation of retail power suppliers. S.B. 1 passed 32-15 in the Senate and 96-39 in the House. 

H.B. 990 updates provisions in the 2016 Greenhouse Gas Reduction Act and the CSNA exempting the state’s manufacturing sector from complying with any state GHG-reduction goals. Cement manufacturing would be taken out of the definition of manufacturing — meaning cement manufacturers in the state would have to comply with GHG-reduction targets. 

Manufacturers that are producing renewable energy components or other technology that reduces greenhouse gas emissions would be exempted, as would companies producing alternative materials that reduce emissions. 

The bill passed in the House 103-34 and in the Senate 31-12. 

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Stakeholders Seek Clarity on CAISO Interconnection Process Plan

Stakeholders still are seeking clarity on details in CAISO’s plan to streamline its interconnection process after the ISO released its final proposal to address the issue after 10 intensive months. 

“I know it’s been a long haul and has felt a little bit like an endurance sport for a little while, and we’re not done,” Danielle Mills, CAISO principal of infrastructure policy development, said during an Interconnection Process Enhancements working group meeting April 4. “But we’re getting to a point where we’re ready to propose this set of reforms as the final proposal.” 

The 2023 Interconnection Process Enhancements final proposal is designed to deal with the “unprecedented volume” of interconnection requests the ISO received last year by reducing the number it will have to study. It will complement — but not replace — the ISO’s compliance filing for FERC Order 2023, which requires transmission providers to revise their interconnection rules. 

CAISO released the plan March 28, one day before it received FERC approval to close this year’s interconnection request window to allow it more time to study Cluster 15 applications. (See CAISO Can Close 2024 Interconnection Window, FERC Rules.) 

But stakeholders participating in the April 4 meeting sought clarity over a few key aspects of the proposal before it goes to a vote by the ISO’s Board of Governors, particularly around the plan’s “zonal approach” and the scoring criteria used to rank interconnection requests.  

Zonal Approach

A key feature of the CAISO proposal is its zonal approach, which prioritizes the interconnection of resources seeking to use available transmission capacity in areas where planned capacity additions were approved in the ISO’s 2022/23 transmission plan as determined by state and local regulatory authority resource planning portfolios.  

Zones are defined by available capacity based on constraints and the California Public Utilities Commission’s resource planning portfolio. A zone with at least 50 MW of available transmission capacity is identified as a Transmission Plan Deliverability (TPD) zone, while a zone with zero available capacity is called a “Merchant option” zone, indicating it could be available for interconnection by merchant projects. 

CAISO is defining zones based on available and planned capacity from the previous year’s transmission plan base portfolio, using the portfolio to calculate overall systemwide capacity. But some stakeholders have struggled to understand how the ISO determines available capacity and evaluates projects in each zone.  

Sushant Barave of Clearway Energy Group questioned how projects would be evaluated if an applicant is in a TPD zone but with a point of interconnection (POI) with no available capacity.  

“If a project is seeking to be studied in a zone that has available capacity, one of the tests we’re going to do is check the POI of the project to determine if it has available capacity or not,” said Bob Emmert, senior manager of interconnection resources at CAISO. “And if the answer is you’re in a TPD option zone but your POI is actually behind constraints that have no capacity to make your project deliverable, then your project will not be studied.”  

Mills emphasized that the amount of capacity identified for each zone doesn’t need to be exact.  

“This is really just a way of gauging relative LSE interest to align with their portfolios,” she said.  

Scoring Criteria

The ISO also is working on implementing scoring criteria to rank projects based on factors including project readiness, LSE interest and non-LSE — or commercial — interest.  

Stakeholders are concerned the scoring system gives an unfair advantage to projects backed by LSEs.  

Under the system, LSEs can award projects points based on a 1-to-100 scale, with the points representing the percentage of capacity the LSEs would assign to the projects, but non-LSEs can award only a maximum of 25 points. The primary reason for the difference, the ISO said, is that LSEs must meet specific resource adequacy and procurement requirements while non-LSEs have no such obligations, although they might be serving a commercial interest.  

“We’ve had a lot of stakeholder comments about different weighting factors that we should apply to the scores and how much influence the LSE or commercial interest should have on the scoring process as a whole,” Mills said. “The scoring process, and particularly the commercial interest process, is really intended to be a way of getting a ranking of projects that can processed.”  

In an interview with RTO Insider, Chris Devon, director of energy market policy at Terra-Gen, questioned if the scoring process was open and transparent given LSE influence. In particular, he highlighted that CAISO’s proposal calls for FERC-jurisdictional LSEs to outline how they would award points in their tariff. 

“I believe that it would be more appropriate to see the CAISO outline some guidelines and requirements within their tariff. But the final proposal lacks any detail on how those LSEs would need to administer those processes to award the points, other than just kind of indicating the time frame,” Devon said. “We would like to see that be more clearly defined to ensure that there is no negative impact to competition and open access.” 

Additionally, if projects aren’t local or long-lead time, such as offshore wind or geothermal energy, they will have to compete for megawatt allocation with LSEs, which are given priority, Devon said, potentially reducing competition. 

“We have seen the benefits of competition in California, where there’s a robust number of independent developers that have been able to develop projects cost-effectively in a manner that keeps cost borne by ratepayers down and kind of shares in the benefit of diversity of supply,” he said.

Margaret Miller, director of government and regulatory affairs at ENGIE North America, also expressed concern LSEs were given too much influence.

“I know there are a lot of competing interests in this category, and I appreciate what the ISO has done to try and balance the concerns here on the scoring criteria,” Miller said during the April 4 meeting. “But when I look at the scoring criteria, for project viability as a developer, I just don’t see a lot of actionable steps we can take to show our project is viable outside of LSE interest, which leads me to believe if we don’t get LSE interest we’re not going to be studied. We’re really struggling with this because I think there’s some commercially viable, good projects that just won’t get into the queue at all.” 

Emmert responded, emphasizing the role of LSE interest in ranking projects. 

“If we didn’t have a scoring mechanism, and if we got rid of this and what’s left of the scoring mechanism without a load-serving entity component, we think we’d have so many [scoring] ties that we’d have basically a process for auctions,” Emmert responded, noting that the proposed rules call for the ISO to conduct a market-clearing, sealed-bid auction for the right to be studied in a specific zone in the case of a tie in scoring points. 

“If we don’t have scoring, well, then we go to auction, and we heard pretty darn clearly that nobody wants an auction, not even the load-serving entities.” 

Stakeholders also expressed concern LSEs can pursue multiple projects, while non-LSE off-takers can submit only letters of interest for one.

“LSEs can allocate their points to any number of projects and in fact, multiple smaller projects, as long as they don’t exceed their points … but here, you’re imposing a limitation on non-LSEs,” said Susan Schneider of Phoenix Consulting. “There isn’t any apparent reason why they shouldn’t be allowed also to sponsor several smaller projects.”  

Mills said non-LSEs aren’t given priority because they fall outside the CPUC portfolio. 

“These non-LSE off-takers are not incorporated into the portfolios that we’re talking about here. We’re talking about basing a lot of this on available capacity and portfolios and where there is available transmission. The non-LSE off-takers are sort of outside that process,” Mills said. “This is an opportunity for them to participate and express any interest in going beyond those procurement needs, but it’s also not as central to the need for us to bring on resources to meet reliability needs.” 

The ISO expects to submit its Order 2023 filing in late April or early May. Starting January 2025, the ISO will begin evaluating interconnection requests based on proposed criteria.  

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FERC Approves PJM Involvement in 2nd NJ Offshore Tx Solicitation

FERC on April 1 approved the participation of PJM in New Jersey’s second solicitation for transmission to interconnect offshore wind, as the state Board of Public Utilities evaluates proposals submitted by the solicitation’s April 3 deadline (ER24-1187). 

The decision allows the two parties to work together under FERC Order 1000’s State Agreement Approach (SAA), enabling the BPU to “take advantage of PJM’s expertise and planning process to develop transmission improvements necessary to support the reliable interconnection of public policy resources,” the RTO said in a statement. 

PJM said the process would seek transmission solutions to serve an additional 3,500 MW of offshore wind energy as part of New Jersey’s goal of reaching 11,000 MW by 2040. 

A BPU spokesman said the agency has received four bids but declined to identify the bidders or to comment further. Under the solicitation schedule, the board will make a decision on which, if any, projects to pursue in the third quarter of this year. 

FERC’s approval follows the successful conclusion of the first SAA between PJM and BPU that resulted in the award of $1.07 billion in transmission upgrades that would deliver 6,400 MW of offshore wind generation. About half the funds were awarded for the construction of a new substation known as the Larrabee Tri-Collector Solution in Howell Township, and the other half for a series of smaller onshore transmission upgrades. (See NJ BPU OKs $1.07B OSW Transmission Expansion.) 

At its March 20 meeting, the BPU approved a series of modifications to projects awarded in the first SAA that the agency said would shave $29 million from the cost. The downward adjustments included a series of projects that could be reduced in scope after new inspections or changes showed they were not needed. 

The first solicitation was seen in the industry as groundbreaking because it was the first use of the SAA. It drew 80 proposals by 13 developers, and BPU officials have frequently cited the approach — selecting lines that can serve multiple OSW projects, instead of one line per project — as cost effective. 

The board on Oct. 25 launched the second transmission solicitation to interconnect four OSW projects and land at the New Jersey National Guard Training Center in Sea Girt, where it would connect to the Larrabee station. The BPU planned to recover the cost of the infrastructure through the state’s Offshore Wind Renewable Energy Certificate (OREC) system, which also would fund the OSW projects. (See NJ Revamps Third Solicitation OSW Connection Plans.) 

In a note on the solicitation, the BPU said the scope of the “prebuild” includes “all cable vaults, duct banks and related facilities for four separate qualified projects, enabling qualified project developers to install their cables into the prebuild by pulling them through the completed prebuild infrastructure facilities.” 

Although the BPU would not identify the bidders, National Grid Ventures (NGV) and Con Edison Transmission on April 4 said they had submitted a 6-GW proposal called Garden State Energy Path. The bulk of the project would be underground, “allowing the cables to be protected from storms and other extreme weather that can cause customer outages,” the companies said in a statement. 

Will Hazelip, president of NGV US Northeast, said, “Prebuild infrastructure is a smart and coordinated approach to transmission for offshore wind, reducing the need to separately construct transmission infrastructure for each offshore wind project.” 

“New Jersey communities can rely on the Garden State Energy Path to provide a route that reduces community disruption and maximizes benefits,” he said. 

The companies said if the BPU picks their project, it could be in operation by early 2029.

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PJM OC Briefs: April 4, 2024

PJM Preparing to Open Black Start RFP

VALLEY FORGE, Pa. — PJM plans to open a solicitation window for black start service after the June 2023 request-for-proposal window did not yield fuel-assured black start generation for some transmission zones. 

PJM’s Ray Lee told the Planning Committee it believes part of the issue is a lack of understanding of the requirements and criteria for a black start generator to be considered fuel-assured, so PJM will schedule a special session of the OC for stakeholder education. The RFP window is expected to open April 29. 

Lee explained there are six ways to meet the minimum qualifications, including being connected to multiple interstate pipelines, on-site fuel storage and status as a nonhydro intermittent hybrid resource. Stakeholders voted in 2022 to adopt the fuel-assured black start criteria with the aim of increasing fuel availability for at least one generator, on top of existing regional black start requirements. (See “Black Start Fuel Requirements Advance to Members Committee,” PJM MRC Briefs: Oct. 24, 2022.) 

The black start RFP process occurs on a five-year cycle, with additional windows opened when deficiencies are identified. The current windows are to supply the service starting Jan. 1, 2027. 

First Read on Periodic Review Manual Revisions

PJM presented revisions to Manual 3 and Manual 36 drafted through the documents’ periodic review, both of which will be considered for endorsement at the May 2 OC meeting. 

The changes to Manual 3 added OC informational posting requirements for facilities adding dynamic line rating capability, language around the use of the Transient Stability Assessment to measure transient voltage response and rules for rescheduling canceled transmission outages. 

The list of transmission owners detailed in Manual 36 was updated, as well as the list of TOs and their deadlines for submitting their annual restoration plans. 

Operating Metrics and Security Update

PJM’s Joe Callis continued to sound the alarm on the threat posed by Volt Typhoon and other organized hacking groups that may be targeting utilities nationwide. He recommended members be cautious about the data they provide or make available to vendors, highlighting an attack in January that used a breach of Microsoft email to search for information shared by partner companies. 

PJM experienced an average hourly load forecast error of 1.35% in March, below its rolling 25-month average of just over 1.5%, Stephanie Schwarz presented to stakeholders. The RTO did not exceed its 3% benchmark for daily peak forecast error. One high-system voltage action was issued, along with a geomagnetic disturbance warning and six postcontingency local load relief warnings. Nine shortage cases were approved March 10 due to load, interchange and slow steam generation response. 

Grid Security Drill Scheduled

PJM has scheduled its biennial grid security drill for Oct. 29, 2024, and this month will begin sending invitations to members to participate. The drill focuses on physical and cybersecurity issues within PJM’s footprint and is open to government agencies to either participate or observe. 

PJM’s Rebecca Gerber said companies should reach out to her to ensure PJM has the correct contacts for invitations or relaying information about the drill. 

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PJM PC/TEAC Briefs: April 2, 2024

Planning Committee

Stakeholders Discuss Expanding CIR Transfer Issue Charge

VALLEY FORGE, Pa. — PJM’s Planning Committee is considering a change to an issue charge framing a discussion on how capacity interconnection rights (CIRs) can be transferred from a retiring generator to a planned resource in the interconnection queue. 

The issue charge modification, brought by the East Kentucky Power Cooperative (EKPC), would allow consideration of solutions that would include planned resources sited at a different, but electrically equivalent, point of interconnection (POI) from the original generator by striking a paragraph designating such solutions as out of scope. The issue charge was proposed by EKPC and Elevate Renewables and approved by the PC on June 6. (See “Stakeholders Endorse Discussion on Deactivating Generators’ CIRs,” PJM PC/TEAC Briefs: June 6, 2023.) 

Denise Foster Cronin, EKPC’s vice president of federal and RTO regulatory affairs, said ongoing discussion at the Interconnection Process Subcommittee revealed the issue charge could prevent solutions permitting CIR transfer to a planned resource whose POI is on a different breaker, but which is otherwise electrically the same. She said the cooperative’s intent in bringing the issue charge was to ease the process of passing CIRs onto a new resource that would have minimal impacts to the grid, but that the current language ignores the realities of the grid. 

Several stakeholders said just removing the out-of-scope language would open the door to market participants creating their own interpretations of what an electrically equivalent POI could be.  

Vitol’s Jason Barker said the proposed issue charge edits would result in unbounded solution options for CIR transfers, rather than solutions that permit swift transfers at the same, or electrically equivalent, POI as originally intended. He questioned PJM about how it determines electrical equivalence in assessing CIR transfers, to which PJM said it does not have a standard measure.  

Barker expressed concern that, in the absence of agreement on the definition of electrical equivalence, eliminating consideration of expedited CIR transfers only at the same tariff-defined POI could impede the most competitive solutions. 

Independent Market Monitor Joe Bowring said a core focus should be on ensuring competition in the transmission grid and not providing undue access.

Bowring also pointed out that: “The proposal would undermine the newly revised PJM queue process by creating a bilateral queue process that could override the PJM process. CIRs are not a property right. Retiring units should not retain CIRs after the day of retirement. CIRs have value as a result of the upgrades to the transmission system paid for by all transmission customers. In addition, the proposers have failed to address whether they would even agree to offer the replacement resources into the capacity market as renewable resources and storage do not have the same must offer obligation as thermal resources.”

Paul Sotkiewicz, president of E-Cubed Policy Associates, responded that CIRs are property rights that have been paid for by the generation owner seeking to transfer them. 

Asked how PJM would define “electrically equivalent,” the RTO’s Jason Connell said the meaning has not been determined and that should be left up to stakeholders, either through the issue charge or packages to come out of it. 

Transmission Expansion Advisory Committee

PJM Preparing 2 Competitive Transmission Windows in July

PJM is shifting its timeline for running the first competitive window for the 2024 Regional Transmission Expansion Plan and the second round of transmission projects to deliver 3,742 MW of New Jersey offshore wind through the State Agreement Approach (SAA). PJM had planned to open both simultaneously during the first week of July, but Director of Transmission Planning Sami Abdulsalam said the RTO now is targeting the middle of the month and will have a gap of a few days between opening them. (See NJ Opens 2nd State Agreement Approach to Connect OSW with PJM.) 

During recent TEAC meetings, stakeholders suggested that staggering the two windows would allow proposals submitted in the second window to be informed by the projects PJM selected in the first and would avoid straining transmission owner resources in forming proposals for two concurrent solicitations. 

PJM closed the second competitive window for the 2023 RTEP on April 5 and will post window statistics by the April 30 TEAC meeting. The window sought proposals to address concentrated load growth around Columbus, Ohio, thermal violations in the PSEG transmission zone around the Hinchmans substation and the 500-kV Fentress-Yadkin line in the Dominion zone nearing its end of life. The window was shortened to 30 days due to the urgency of the thermal violations in PSEG.

Supplemental Projects

FirstEnergy presented an $18.7 million project to replace a 500/138-kV transformer at its Bedington substation in the APS transmission zone. The unit is about 47 years old and experiencing increasing maintenance issues, the utility said. The project is in the pre-engineering phase with an expected in-service date of Dec. 31, 2027. 

Inspections of three FirstEnergy 345-kV lines in the ATSI transmission zone found deteriorating wood and steel structures, as well as insulators approaching their end of life. The 19-mile Niles-Shenango line has experienced two unscheduled outages due to failed equipment since 2015, the Beaver Valley-Hanna line has had one outage and the Hanna-Mansfield line had two unscheduled outages over that period. The condition of the lines was presented as a future need. 

PPL presented a $244 million project to build a new 500-kV substation, named Bernheisel, to serve a 1,275-MW customer service request in New Kingston, Pa. The project would cut the proposed substation into the Juniata-Three Mile Island 500-kV line, rebuilding the 13.3-mile segment between the new facility and the Juniata substation in the process. The Bernheisel site would include four 500/138-kV transformers, two 138-kV capacitors, a six-bay 138-kV yard and six 138-kV lines. The new load is expected to come online in March 2026 at 40 MW, ramping up to 1 GW in 2030. 

Dominion presented a $23 million project to construct a new 230-kV substation, named Edsall, to serve a data center complex with load exceeding 100 MW in Fairfax County, Va. The new facility would be connected to the Van Dorn substation by two existing 230-kV lines between Van Dorn and the Ox and Hayfield substations. The data centers have an expected in-service date of Oct. 1, 2027.