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November 8, 2024

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ERCOT Says ‘Sufficient’ Capacity to Meet Winter Demand

ERCOT has “sufficient” installed capacity to meet a forecast peak demand of 67.4 GW this winter, the ISO said Tuesday.

Based on its latest seasonal assessment of resource adequacy (SARA), the Texas grid operator expects to have about 87.3 GW of winter-rated capacity available during the upcoming cold months. Two thermal resources, a coal unit and a gas-fired unit comprising 685 MW, will be out of service all season, ERCOT said. The SARA report assumes “typical” thermal outages totaling almost 10 GW this winter.

The projected demand is based on average winter conditions for the 2007-2021 winter peaks that would include the devastating winter storm of February 2021, which still raises Texans’ anxiety levels. The SARA report assumes high demand, high thermal outages and low wind output in its various scenarios but not gas supply disruptions, which FERC and NERC said were responsible for most of the generation outages during the 2021 storm. (See FERC, NERC Release Final Texas Storm Report.)

ERCOT’s demand peaked at 77 GW during the 2021 winter storm before the outages became too much to handle. Texas A&M University’s Texas Center for Climate Studies has said demand would have reached 82 GW had there been enough generation to meet demand.

Pablo Vegas (Admin Monitor) Content.jpgPablo Vegas | Admin Monitor

But Public Utility Commission Chairman Peter Lake expressed optimism about the grid’s preparedness during a joint press conference Tuesday with ERCOT CEO Pablo Vegas. “The lights will absolutely stay on,” he promised.

Lake trumpeted new weatherization requirements and other reliability-focused operational reforms directed by lawmakers following the storm as the reason for his confidence. “We’re better prepared than ever,” he said.

“We are in a position where the elements that are within our control related to the reliability and the operation of the grid are as strong as they’ve ever been going into this winter season,” Vegas said. “The majority of the actions that we’ve taken over the course of this year-and-a-half are designed specifically to address any risk of load-shedding.”

The biggest change has been following up on weatherization requirements placed on generators and transmission facilities. After inspecting weatherization practices last winter at plants that experienced problems during the winter storm, ERCOT staff will check on about a third — or 350 — of the system’s resources this year. Vegas said the ISO plans to complete the inspections early next year.

“Those inspections and audits are showing that the work is getting done to keep those generators operating during the most extreme weather conditions,” he said.

Asked about NERC’s recent winter reliability assessment that found ERCOT’s reserve margin could fall as much as 21% below demand in the most severe scenario, Vegas transitioned to the PUC’s market redesign that is currently underway. (See Proposed ERCOT Market Redesigns ‘Capacity-ish’ to Some.)

“That doesn’t take into account things like winterization,” he said of NERC’s assessment. “We’re not trying to underplay it at all. It does reflect a very low-probability scenario.

“But the fact it exists calls out an issue that needs to be addressed … being able to continue to build dispatchable generation to ensure there will always be enough power. That’s why this [market redesign] work that we’re embarking on is so important,” Vegas added.

He and Lake both used a new message in pointing to the continued growth in ERCOT’s demand. They said Texas is adding a city the size of Corpus Christi — the eighth largest in the state at 317,863, according to the 2020 census — each year, placing additional pressure on developing generation resources.

The PUC’s proposed market designs rely on adding dispatchable thermal resources over intermittent renewable resources.

“We have the same amount of reliable dispatchable resources with no target, no reliability standard, which is a key part of the reforms that this commission has evaluated and discussed,” Lake said. “It’s getting harder and harder to do this, because we have more people … this is a long-term problem, the lack of a reliable reliability standard, but the future is coming.”

ERCOT on Tuesday also released its biannual capacity, demand and reserve report. It forecasts a summer peak demand of 82.7 GW, which would be a new record, and a winter peak of 69.4 GW.

The grid operator said next summer’s planning reserve margin will be 22.2%, a 14-point drop from the 36.2% margin in the May 2022 CDR report.

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FERC IDs Deficiencies in Western RA Program

FERC sent a deficiency letter to the Western Power Pool last week, asking it to provide more information on the tariff filing for its proposed Western Resource Adequacy Program, a first-of-its-kind effort to ensure large swaths of the Western Interconnection have sufficient resources to meet summer and winter peak demand.

The WRAP would have two main “time horizons,” a forward-showing program requiring participants to show they have sufficient capacity months in advance of summer and winter peaks, and an operational program, focused on the allocation of resources in real-time and day-ahead time frames.

The WRAP’s tariff filing said that to participate in the operational program, entities would have to have market-based rate authority to “engage in such transactions to the same extent they would require market-based rate authority if they conducted the same bilateral wholesale transaction for a non-WRAP purpose,” the commission noted.

FERC asked how “participants with market-based rate mitigation or those without market-based rate authority will be treated in the WRAP operations program” and asked WPP to explain “to the extent these procedures are not described in the tariff yet, please describe where WRAP might address the circumstances described above.”

FERC did not give specific examples, but in 2016 it denied Berkshire Hathaway Energy subsidiaries permission to sell wholesale power at market-based rates in four neighboring balancing authority areas, including the PacifiCorp East, PacifiCorp West, Idaho Power and NorthWestern Energy areas. Berkshire had failed to prove that its units did not exercise horizontal market power in the region, the commission said. (See Berkshire Market-Based Sales Restricted in 4 Western BAAs.)

The BHE subsidiaries included PacifiCorp and NV Energy, which together cover much of the interior West. Both have been active in designing the WRAP and are among the 26 participants that signed up for its current non-binding phase, which did not require FERC approval.

Whether FERC might allow the utilities to participate in WRAP with market-based rate authority remains in question. In 2017, the commission gave PacifiCorp and NV Energy permission to sell power into CAISO’s Western Energy Imbalance Market at market-based rates, reversing its previous finding that had restricted the companies to submitting only cost-based offers. That reversal partly hinged on the utilities providing analysis that showed there was little congestion between WEIM BAAs after NV Energy’s energy into the market, supporting the argument that member BAAs should not be considered submarkets subject to market power.  (See PacifiCorp, NV Energy Gain EIM Market-Based Rate Authority.)

Other questions FERC asked WPP to respond to dealt with the WRAP’s requirement that participants secure transmission rights in the forward-showing program and WRAP’s intention to hire an “independent evaluator to provide an independent assessment of WRAP’s performance.”

WPP filed the proposed WRAP tariff with FERC on Aug. 31 and had been hoping to win FERC approval by the end of the year. WPP asked would-be participants to confirm their commitments to the binding phase of the program within the next few weeks. (See Western Power Pool Board Approves WRAP Tariff.)

“While this may alter the timeline for FERC approval of the tariff, it does not change our timeline for securing additional commitment from our participants by mid-December,” WPP CEO Sarah Edmonds said in an emailed statement. “This is an important deadline and next step toward implementing the WRAP and addressing urgent resource adequacy concerns.”

As for FERC’s questions, “we knew this was a possible, if not expected outcome and were prepared for it,” Edmonds said. “These letters are common in complex tariff filings. They simply seek more information and are not a reflection – good or bad – on the merits of the application. Our team is compiling the requested information, and we will respond by the deadline. I remain confident we can resolve the process and ultimately gain approval.”

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PNNL: ‘Households Do Not Make Rational Decisions’ on EE Upgrades

WASHINGTON, D.C. — Neither cost nor environmental impact is the top driver or deal breaker for people deciding whether to make an energy-efficient upgrade to their property, according to a new study from the Pacific Northwest National Laboratory (PNNL).

Rather, the survey of almost 10,000 homeowners and renters across the U.S. found that the comfort and safety of children and pets head the list of motivating factors, with repairing or replacing broken appliances or other equipment a close second, said Chrissi Antonopoulos, a senior analyst at PNNL. Reducing energy bills came in fourth, behind improving their homes’ appearance, Antonopoulos said, presenting the still unpublished survey results at the recent Behavior, Energy and Climate Change (BECC) Conference.

When it comes to residential energy efficiency and electrification — and the Inflation Reduction Act’s billions in rebates for consumers to upgrade their homes — “households do not make rational decisions, and they don’t make decisions based on cost-benefit analysis or something that is going to give them a kickback,” she said.

While consumer education seems to be an effective strategy for motivating energy efficiency upgrades, “technology patterns and behavior and decision-making are really difficult to predict, and we have decades of research and policies to kind of uphold that,” Antonopoulos said.

A joint effort of the American Council for an Energy Efficient Economy and environmental and energy programs at the University of California, Berkeley, and Stanford University, BECC looks at the drivers and roadblocks to individual and community action on climate change. IRA implementation was a central theme at this year’s event, with a special focus on how to ensure low- and middle-income consumers take advantage of the law’s rebates and incentives.

The potential for savings is huge, Antonopoulos said. “Our buildings are woefully inefficient,” she said. PNNL has estimated that about 68% of the U.S. housing stock, 130 million homes, were built before energy codes were widely enacted in the 1990s, she said.

These older homes may have high heating bills because they may not be well insulated and “they have huge HVAC systems … to make them comfortable,” she said.

The PNNL study looks at how to leverage consumer concerns into better energy-efficiency decisions. Safety, health and comfort may be more important in messaging than environmental impact, Antonopoulos said, with the notable exception of HVAC systems, where energy efficiency is a top priority.

“People are installing central air conditioning in huge numbers,” she said. “That is a touchpoint for installing heat pumps. … You’re going to install [air conditioning] anyway; let’s go for a heat pump technology.”  

Space heating accounts for up to 29% of energy costs for many households, according to the U.S. Environmental Protection Agency. Geothermal or air-source heat pumps, which use heat-exchange technologies, can provide more efficient heating and cooling, as well as significant savings. The IRA offers rebates of $2,000 to $8,000 for heat pumps, depending on household income.  

The caveat is that consumers value durability, repairability and low maintenance when replacing HVAC and other systems, Antonopoulos said. Having the latest technology or smart phone app is not a major concern, and contractors can play a huge role. They “have a big influence and can make something go either way, positive or negative,” she said.

Another intriguing finding from the study is that stove preferences appear to be linked to income level. “High-income households tend to prefer gas stoves because they want the super fancy range,” Antonopoulos said. “Lower and moderate incomes tend to prefer electric.

Both homeowners and renters are most likely to adopt “interactive, visible technologies,” like changing to LED lightbulbs, followed by technologies that improve comfort but are “behind the scenes,” like adding insulation or a new hot water heater, Antonopoulos said.

Upgrades with longer-term paybacks, like electrical system upgrades or installing solar panels, are harder sells and made less frequently, she said.

‘Fix the House First’ 

With inflation still high, President Joe Biden is banking on consumers seeing real cost savings from the IRA’s energy-efficiency funding starting in 2023. Speaking to a group of business leaders on Nov. 18, Biden pointed to the 30% investment tax credit for solar, noting it could bring down the cost of installing panels on a residential rooftop by up to $7,500.

“And when you get to keep savings money on your electric bills for the remainder of the year, it’s about $300 a year on average,” Biden said.

But even with effective messaging, low- and moderate-income (LMI) homeowners most in need of those savings may face significant obstacles in accessing the IRA funds, according to several speakers at the BECC conference.

Based on figures from the U.S. Department of Energy, “there are 26 million households in the United States earning less than 80% of the area median income, burning fossil fuels inside their homes today,” said Mark Kresowik, senior policy director at ACEEE, “[For] first-time low-income home buyers, utilities are the third-highest cost that they pay to afford their housing, behind only property taxes and home repairs.”

Many of these homes may need other, more basic upgrades to their roofing or electricity systems before they can even begin to take advantage of the IRA’s energy efficiency rebates.

“Poor housing conditions [are] the most critical and most important barrier that right now is being underfunded in this space,” said David Becker, marketing program manager for energy efficiency at DTE Energy in Detroit. “If we’re going to deliver energy efficiency, if we’re going to deal with historic redlining and historic underinvestment in these communities, we have to address the housing conditions. … When we layer on electrification efforts, solar panels, all those issues, we need to fix the house first.”

In 2020, DTE launched a Health and Safety Pilot with local community groups to identify and repair low-income homes, Becker said. The program, which started with $2 million in funding, has been extended through 2023.

The DTE pilot is upgrading about 300 to 350 homes per year, with roof repairs and electrical system upgrades absorbing the largest shares of home repair dollars, he said.  

DTE has also partnered with two health care nonprofits, the Gilbert Family Foundation and ProMedica, on a $20 million Detroit Home Repair Fund to provide health and safety home repairs for 1,000 homes over the next three years, Becker said.

“This allows us to more deeply impact these homes,” he said. “We can handle trip hazards and grab bars and anything that’s needed in the home [to make] the home healthier.” Following the May program announcement, DTE received more than 120,000 calls about the program in the first 24 hours, Becker said.  

Reducing Barriers

Melanie Santiago-Mosier, vice president for climate, energy and equity at the nonprofit Green and Healthy Homes Initiative, also stressed the need to get low-income households and communities “to the starting point,” where they can take advantage of energy-efficiency funding in the IRA and Infrastructure Investment and Jobs Act.

Her organization sees the federal dollars as a new funding source that can be “braided” with other funding streams, she said, during a keynote panel.

Community engagement upfront is critical, Santiago-Mosier said. “A rebate just kind of implies there’s an initial outlay of money in order to get some money back,” she said. “For a low-income family or an owner of affordable housing, it may be very challenging to actually make that initial investment.”

Henry McKoy, director of DOE’s new Office of State and Community Energy Programs, said the department is trying to close the finance gap with a new $250 million revolving loan fund that will be available to states. Echoing Santiago-Mosier, he also sees an equally critical “information gap” in ensuring people understand what the IRA provisions mean for them.

It “is important for us to make sure we have that outreach, that engagement, those communication channels that actually connect to people and meet people where they are,” McKoy said. “We can’t just look at communities as receivers of services, of benefits. We have to see them as true partners in this work going forward.”

Implementation of the IRA must be “effective, efficient and impactful,” he said. “If we go through this process now where we invest these dollars and at the end of the day we haven’t stood up and invested in institutions that will survive, that will serve as vehicles for this work going forward and that will really be transformational … we will have failed.”

Eligibility Requirements

Dan Burgess, director of Maine’s Energy Office, said meeting people where they are is also a pressing challenge for states, which will be doing much of the difficult work of translating the complex provisions of the IRA so they can be easily understood by homeowners.

He pointed to Maine’s current campaign to install 100,000 heat pumps in homes across the state by 2025, aimed at reducing the state’s reliance on home heating oil. To date, 80,000 heat pumps have been installed, Burgess said.  

“We have reduced barriers and made the program not too complicated. We’ve empowered contractors across the state … and I think it’s working because we’re not requiring folks to jump through 10 hoops.”

IRA rebates for heat pumps will allow the state to build on its own program, he said.

States will also be wrestling with different eligibility requirements and low-income definitions for different provisions of the IRA and IIJA, Kresowik said. Some programs base eligibility on average mean income, while others use the federal poverty level.  

“How [do] you make this easy, so somebody doesn’t have to go through one, two [or] three different income verifications?” he said.

Maine has explored a couple of different approaches to this problem, Burgess said. “You don’t have to provide all of your taxes, but you can provide this page, or you can sign up to allow [the Department Health and Human Services] to provide your information,” he said.

“There are a lot of legal requirements both at the federal level and then oftentimes at the state level,” he said. “I think it’s incumbent on state agencies to work with one another to figure this out, so that it’s as easy as possible for the participants.”

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NERC Calls for Flexibility in CISA Cyber Reporting Rules

Any new cyber incident reporting requirements for critical infrastructure must be carefully drafted to avoid overlap with existing regulations, NERC and the regional entities told the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) in comments submitted earlier this month.

The ERO Enterprise was responding to the request for information that CISA issued in September. The RFI was inspired by the Cyber Incident Reporting for Critical Infrastructure Act of 2022 (CIRCIA), part of the omnibus spending bill passed by Congress and signed by President Biden in March.

CIRCIA requires entities in critical infrastructure sectors — including energy — to report relevant cyber incidents to CISA within 72 hours after they occur, as well as when they make a ransom payment to the perpetrators of a ransomware attack. (See Budget Mandates Cyber Reporting for Critical Infrastructure.)

But authority for defining which incidents are subject to reporting and which additional sectors, if any, are covered by the requirements, along with other details, is left to CISA’s director. The RFI said industry input would help to shape the agency’s final rule.

Worries Over Possible CIP Overlap

In their response, NERC and the REs pointed out that two of NERC’s reliability standards — CIP-008-6 (Cybersecurity — incident and reporting and response planning) and CIP-003-8 (Cybersecurity — security management controls) — require reporting of cyber incidents by various electric industry stakeholders. These requirements are “similar to the reporting requirements set out in CIRCIA,” the ERO said, requiring coordination between NERC and CISA “to ensure harmonization” between the two regimes.

CIP-008-6 requires responsible entities to create cyber incident response plans that they will follow to detect and respond to events affecting cyber systems connected to higher-risk transmission and generation assets, along with control centers. These plans must include reporting of certain cyber incidents to both CISA and the Electricity Information Sharing and Analysis Center (E-ISAC). CIP-003-8 deals with lower-risk transmission and generation assets and similarly requires entities to have response plans that may include reporting incidents to the E-ISAC.

NERC and the REs expressed concern about potential inconsistencies between NERC and CISA’s requirements; for example, CISA’s reporting regulations might have a different timeline for reporting than NERC’s standards, and may require different information. To “avoid duplicative and inconsistent reporting requirements … that could hinder incident response,” the ERO asked that CISA work with NERC and the E-ISAC to ensure the final rule does not cause unneeded friction.

In addition, the ERO drew on its experience with the critical infrastructure protection (CIP) standards to give CISA some advice as it drafts its final rule. The organizations counseled CISA that it should take care in defining “covered cyber incident” and “substantial cyber incident,” as these will play a role in determining what incidents must be reported under the new rules. Care is needed, the ERO said, to ensure these reports produce enough actionable information.

“In developing its incident reporting requirements, the ERO Enterprise initially required entities to report only incidents that had operational impact. … Over the years, however, there were very few incidents reported,” the ERO said. “While receiving few reportable incidents is a positive insofar as it means that there were very few cyber incidents that had an impact on electric utility operations, it could also miss reporting on significant cyber activity, leaving industry unaware of emerging threats and vulnerabilities that have yet to have operational impact.”

While defining reportable incidents too narrowly may prevent the agency from gathering useful data, NERC and the REs said that making the definition too broad would likely result in the opposite problem, with CISA “inundated with reports” that require “significant effort to separate the noise from actionable information.”

Finally, the ERO suggested that CISA’s final rule include “a mechanism for sharing the reports submitted” with the E-ISAC and its counterparts in other critical infrastructure sectors. The organizations pointed out that ISACs are “uniquely positioned … to amplify CISA’s analysis throughout their respective sectors” because of their “established communication mechanisms and protocols.”

If privacy is an issue with sharing sensitive information, the ERO said that CISA can develop a process for either obtaining consent to share such information or removing identifiable data before it is shared.

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IMM Offers Mixed Review of PJM Quadrennial Review Docket

PJM’s Independent Market Monitor offered limited support for major provisions in the RTO’s quadrennial review filing before FERC, while urging the commission to order revisions to some of the proposal’s methodologies and figures (ER22-2984).

In a Nov. 16 filing, IMM Joe Bowring signaled support for PJM’s plan to switch to the use of a forward-looking energy and ancillary services (EAS) offset, rather than relying on historical figures for the calculation, but said the use of long-term financial transmission rights (FTR) is unnecessarily complicated and inaccurate, and cannot be implemented because of the timing of the auctions.

“The more direct, simpler, more transparent, and more accurate approach starts with the forward curves and calculates hourly and nodal forward prices based on historical LMPs, which are a more reliable and more transparent method of calculating locational price differences. PJM should be required to use this approach rather than its proposed approach to the calculation of the forward-looking EAS offset,” the Monitor wrote.

In addition to reducing the overstatement of the net cost of new entry (CONE), and therefore capacity prices, the Monitor said the main benefit of a forward-looking EAS offset would be to better align with how investors look at the market. PJM’s proposal to use FTRs would conflict with that aim, he said.

The Monitor also said the RTO should be required to reconsider the static offset figure should FERC or PJM stakeholders make any significant changes to reactive ancillary service payments, given that revenues from that service factor into the EAS offset. PJM is proposing to set expected revenues using a payment estimate of $2,546 per MW-year.

The Monitor supported PJM’s proposal to calculate net CONE using a combined cycle (CC) power plant as the reference resource instead of a combustion turbine (CT) unit. The filing said that the change better reflects the type of facilities being added to the PJM fleet, noting that no significant number of CTs have been interconnected to the grid since 1999.

With respect to setting the variable resource requirement curve, the Monitor said PJM did not go far enough in its proposal to steepen the slope a quarter of the way towards vertical (effectively purchasing less additional capacity over the expected peak load), suggesting that the curve instead be rotated halfway toward vertical.

If the amount of capacity purchased in the 2023/24 Base Residual Auction was reduced in accordance with the IMM recommendation, a total of $1,790,941,751 in capacity would have been purchased, a decrease of $405,503,039 or 18.5% compared to the actual total of $2,196,444,791, according to IMM estimates. 

“The shape of the VRR Curve directly results in load paying substantially more for capacity than load would pay with a vertical demand curve,” the filing said.

PJM Response

In its response to the Monitor’s filing, PJM told FERC that the market designs drafted in collaboration with the consulting firm Brattle Group would provide the necessary reliability expected in the future. It also noted that the IMM had missed the docket’s comment deadline by nearly a month.

“Brattle cautioned against adopting a curve that is tuned to support exactly a one-in-ten Loss of Load Expectation (“LOLE”) at this time due to the lower net [CONE] and greater fleet turnover than observed in prior quadrennial reviews. In other words, the PJM proposed curve is just and reasonable because it avoids the untenable risk associated with a VRR Curve that barely meets the 0.1 LOLE standard given the current market conditions,” PJM said in its response, filed Nov. 17.

The response also says that many of the IMM concerns regarding the use of FTRs had already been addressed by the commission in its 2019 order on PJM’s Reserve Market Enhancements. (EL19-58)

“In short, the Market Monitor’s concerns with the use of long-term FTR have already been thoroughly litigated and should not be relitigated here,” PJM

Generators Expand on Protests

J-Power USA and the PJM Power Providers Group also filed responses to a PJM retort to their quadrennial review protests before FERC.

Arguing that PJM should use a shorter amortization period within the Commonwealth Edison Locational Deliverability Area (LMP), J-Power said that the RTO has been misunderstanding the Illinois Clean Energy Jobs Act (CEJA) and case law in the state. In its Nov. 18 protest, the company said that under CEJA, the reference resource would be required to cease operations within the amortization period outlined in the filing.

“Like PJM, Brattle improperly conflates the provision of CEJA prohibiting gas-fired resources from increasing their emissions above current levels, which contains an exception for publicly-owned resources, with the separate provision requiring all gas-fired resources to reduce their emissions to zero by January 1, 2045, which has no similar exception.”

Referencing a section of the PJM response detailing how CEJA would allow for a CC unit to remain in operation if needed to provide reliability, J-Power said it is not realistic for large numbers of facilities to be constructed and maintained for that sole purpose. In an affidavit submitted on behalf of J-Power, Paul Sotkiewicz of E-Cubed Policy Associates wrote that there are currently no technologies available to convert a gas-fired unit to run entirely on hydrogen and that current carbon capture and storage capabilities do not meet CEJA requirements.

“A Reference Resource is intended to be a representative example, rather than some kind of exceptional resource. It is downright absurd to imagine that it would be the ‘norm’ for gas-fired resources in Illinois to have to be retained for reliability, or that a rational developer would sink hundreds of millions of dollars of at-risk capital into a resource based on the hope that system conditions will miraculously work out so that the resource is required for system reliability years in the future,” J-Power wrote.

P3, a group that represents PJM power producers, also took aim at the RTO’s choice to use a CC facility as the reference resource, saying that a CT is more reflective of a “pure capacity unit” as opposed to a more frequently dispatched generator.

“By using a combustion turbine as the reference unit, the VRR curve response to changes in energy market conditions is only impacted by net energy revenues projected to be earned during scarcity hours when the combustion turbine operates,” P3’s Nov. 14 response says.

While PJM has not recently seen construction of CTs, P3 argued that the resource type offers a possible solution to the need for flexibility to complement the installation of renewables.

“P3 absolutely concedes and acknowledges that more CCs have been built in PJM than CTs over the last 10 years in PJM. While a historical fact, it says absolutely nothing about the resources PJM will need in the future. PJM’s future needs are going to require flexible units (likely in the form of natural gas and coal) — particularly if there is significant renewable energy penetration,” the group’s filing says.

P3 also noted recent comments by PJM CEO Manu Asthana that that the RTO could see 40 GW of generation in the RTO retire by 2030. With the region’s load expected to increase in the future, the group argued, FERC would undermine reliability by accepting a capacity market built on the assumption that PJM is oversupplied with capacity.

“To P3, this sounds like PJM is indeed on the cusp of a reliability crisis and the impact of the instant filing will coincide directly with the predicted reliability challenges in PJM,” the group wrote.

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SPP MOPC OKs ‘Late’ Tariff Change Related to EMS Upgrade

SPP members on Monday unanimously approved a revision request that will allow staff to complete an energy management system upgrade in a timely fashion and reduce project costs.

The Markets and Operations Policy Committee met briefly and virtually to approve the staff request. It still must be reviewed by the Reliability Compliance Advisory Group and the Operating Reliability Working Group after having already been endorsed by the Transmission and Regional Tariff working groups.

The revision request (RR524) updates Attachment C of SPP’s tariff to reflect revisions to the real-time response factor calculation process. The process is being updated to better align with industry best practices by using a standalone process and the Eastern Interconnection’s NERC interchange distribution calculator.

SPP COO Lanny Nickell said staff discovered late during the EMS upgrade that the tariff’s current requirements do not specify the use of certain software in the calculation. Their new language gives a “very detailed description,” as required by FERC, of SPP’s available flowgate capability calculations.

“We caught it late. Apologies for doing this,” Nickell said. “We would have loved to have covered this in October [during MOPC’s last meeting], but it was something we noticed late.”

SPP plans to file the tariff change with FERC in December, enough time to meet the new EMS cutover deadline of Feb. 21.

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NJ Backs $20 Million Spend on Tx Link for Offshore Wind Port

The board of the New Jersey Economic Development Authority (EDA) voted this month to back a $20 million purchase agreement with Atlantic City Electricity (ACE) to ensure the utility avoids potential supply chain delays in the delivery of construction materials needed to develop the 12-mile transmission line tying the New Jersey Wind Port to the grid.

The EDA also started the process of issuing $160 million in tax exempt bonds to pay for construction of the wind port through 2023. The agency’s board voted Nov. 16 to support an “Official Intent Resolution” that sets the bonding process in motion, but the board would have to take another vote for the bond issue to move ahead, according to the memo.

The project has so far obtained $478.2 million in state funds, and the bonded finance would “secure the balance of funding” needed for completion of the first two phases of the projects, according to a Nov. 16 memo from EDA CEO Tim Sullivan to the board.

The two board votes reflect the EDA’s commitment to pushing aggressively ahead with the project, which officials say will be the nation’s first custom-built port serving the wind. It is the cornerstone of the state’s drive to become a manufacturing and logistics hub for the nascent industry, not only in New Jersey but for other East Coast offshore wind projects as well.

The purchase agreement is designed to ensure the smooth advancement of the wind port project, which broke ground in September 2021. The agreement “is necessary to safeguard the purchase of materials with long lead times or are at risk of delays due to global supply chain disruption,” Sullivan said in the memo outlining the expenditure.

The deal will bring the total cost of the connection — a 69-kV transmission line on a greenfield site — to $25.88 million. The board in April approved an expenditure of $5.14 million for the utility to move ahead with a detailed design of the line. The design is 60% complete and on schedule, according to the memo.

Providing Power for Tenants

The wind port, located at Alloways Creek in Salem County, will include a 30-acre marshalling area for component assembly and staging; a dedicated, overland, heavy-haul transportation corridor; and a heavy-lift wharf with a dedicated delivery berth and an installation berth that can accommodate jack-up vessels.

The port was conceived to serve New Jersey’s own offshore wind industry. The state Board of Public Utilities (BPU) has so far awarded three wind projects in two solicitations since 2019: the 1,100-MW Ocean Wind 1 and 1,148-MW Ocean Wind 2, both developed by Ørsted, and the 1,510-MW Atlantic Shores, a joint venture between EDF Renewables North America and Shell New Energies US. The BPU is planning to hold a third solicitation early in 2023.

The developers of the three approved offshore projects have agreed to use the port, but the state also wants to attract business from non-New Jersey projects. The EDA said in October 2021 that it had received 16 non-binding offers for companies looking to become tenants at the port, among them Siemens Gamesa Renewable Energy (OTCMKTS:GCTAY). (See NJ Wind Port Draws Offshore Heavy Hitters.)

Nacelle manufacturers MHI Vestas and General Electric have committed to creating nacelle plants at the port, and German manufacturer EEW Group is building a monopile factory in the nearby Port of Paulsboro.

The ACE agreement is important to the wind port because it is located in a remote part of South Jersey, adjacent to three nuclear plants operated by PSE&G, and has no tie to the grid, according to the EDA.

“The approval of long lead items ahead of full construction is necessary to safeguard the construction schedule with materials facing long lead times or risks of disruption due to broader supply chain volatility,” according to Sullivan’s memo. “It also recognizes the authority’s negotiated cost obligations to staff’s recommended inaugural subtenant should a power line connection not be in place by the start of the sublease.”

If the link isn’t ready on time, the project could have no power supply to provide tenants and would have to share the cost of providing temporary power solutions, “such as diesel generators,” the memo said.

Sullivan laid out the expenditures anticipated to be made from the $20 million, which include: $16.9 million for steel poles and anchor bolt cages; $204,00 for conductors; $71,000 for circuit breakers and $62,000 for static wire.

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ISO-NE Finalizing Changes to Economic Study Process

ISO-NE is finalizing changes to its economic study process as it works through the NEPOOL stakeholder gauntlet.

The changes are intended to improve responses to stakeholder requests for economic studies to fill gaps not covered by the ISO’s reliability studies. Such requests have evolved to more and more complex topics, such as ancillary services, resource adequacy, high-level transmission reliability and capacity markets.

Under the current process, ISO-NE puts together a rough scope for all the studies requested by stakeholders and then prioritizes them based on the region’s needs.  

The new proposal would change that process by setting up an analysis framework and using it to run “consistent reference scenarios.” After that initial run, stakeholders and the ISO could request new sensitivities to test the effect of a specific change to the study’s assumptions.

ISO-NE is also proposing to change the cycle of economic studies to align with the regional system plan (RSP) cycle, moving from every year to every two years.

At the NEPOOL Transmission Committee meeting on Tuesday, ISO-NE presented some minor revisions to its proposed tariff changes, which were approved by the committee.

The grid operator is aiming to get a final vote on the study changes at the January Participants Committee meeting, with a FERC filing to follow shortly after.

DECR Tariff Changes

Also at the TC meeting, ISO-NE presented its latest work on aligning buyer-side mitigation rules to allow distributed energy capacity resources (DECR) to take part in Forward Capacity Auction 18, set for Feb. 5,  2024.

The tariff updates will reflect the minimum offer price rule (MOPR) changes accepted by FERC in May and the ISO’s compliance filing for FERC Order 2222, which has not yet been approved by the federal agency.

The tariff changes would modify buyer-side mitigation rules throughout the post-MOPR process to ensure that DERs can be included in the FCA.

They would also modify proposed DECR qualification rules in Section III.13.4A and address the qualification process cost reimbursement deposit requirement.

The tariff changes also clean up some definitions, dates and cross references related to the 2222 compliance proposal.

The ISO is working to get those changes finalized by March 2023 to be ready for FCA 18.

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Former Regulators: Demand Response Key to Midwest Capacity Crisis

Two former FERC chairmen and a state commissioner are pessimistic that MISO will be able to rein in shortages or high capacity prices anytime soon and said demand-side management would assuage the situation.

Former FERC chair and Voltus Chief Regulatory Officer Jon Wellinghoff said during a Nov. 21 webinar, sponsored by his company, that today’s grid fragility in the Midwest can be traced to an increased amount of renewable energy and extreme weather conditions.

“We’ve got a situation now in which our grid is being increasingly tested by extreme weather events that are being driven by climate change, but the steps that we need to take to combat climate change and mitigate our emissions include increased dependency on weather-dependent resources,” former FERC chairman Neil Chatterjee said. “This is a challenging conundrum, and it’s one that policymakers and grid operators have really been wrestling with.”

Voltus CEO Gregg Dixon said an ongoing transition to renewable resources and increased electrification demand alongside severe weather are “putting an even greater strain on an already antiquated grid.”

“We are a month away from winter, and the headline is: ‘It does not look good’ … And summer of 2023 does not look a whole lot better,” Dixon said, referencing NERC’s recent reliability assessment.

The agency has warned that MISO risks winter blackouts after its most recent capacity auction uncovered a 1.2-GW deficit heading into the June 1, 2023, planning year. The Independent Market Monitor has said the footprint’s real risk lies in summer 2023.

Chatterjee said with “the absence of federal legislative guidance” on decarbonization, states must devise their own strategies to cut carbon while ensuring resource adequacy.

Ted-Thomas-2021-11-17-(RTO-Insider-LLC)-FI.jpgFormer Arkansas PSC Chairman Ted Thomas | © RTO Insider LLC

Former Arkansas Public Service Commission chairman Ted Thomas said MISO’s role as reliability coordinator and states’ obligation to ensure resource adequacy can never be “cleanly” separated.

“So, there’s always this tension that plays out with all of these policy issues,” he said.

Thomas said until now, state regulators have always resisted the downward-sloping demand curve in the MISO capacity auctions, viewing it as a “slippery slope” to a mandatory, PJM-style auction.

He said that when the price “shot up” during the 2021-22 planning year auction, regulators’ response was, “MISO, what are you going to do about it?” Thomas said a few years ago, changing the demand curve’s slope would have been viewed by regulators as an overstep.

He said a sloped demand curve will produce gradually increasing capacity prices, instead of extremely low prices one year that skyrocket the next.

“To me, the issues we’re seeing in MISO are simple: There’s just not enough generation,” Chatterjee said. “States have made it clear that they are primarily responsible for resource adequacy … Yet for years, merchant generators have been sounding the alarm that they couldn’t continue to lose money year-over year and that market revenues were not sufficient.”

Chatterjee said some states and load-serving entities believed they could continue to buy capacity from the MISO auction at rock-bottom prices.

“Why pay to build or contract for generation when it’s available for a fraction of the cost in the MISO auction?” he said. “And the end result of that is that badly needed generation has retired, and now the entire region is going to be at an elevated risk of load loss for the foreseeable future.”

Dixon said Voltus expects that MISO Midwest capacity prices will continue to “cap out” at the cost of new generation entry, making Midwestern capacity “perhaps the most expensive in the world.”

“Which is really ironic because it used to essentially be for free,” Dixon said.

Thomas said MISO is better preparing for “oddball weather any time of the year” by shifting focus from a summer peak and switching to capacity accreditation based on unit availability.

He also said MISO South members’ continuing resistance to adding more transfer capability between MISO Midwest and the South regions “balkanizes the RTO footprint” to the detriment of resource adequacy.

Thomas prescribed large customer aggregation to leverage demand response to address reliability crises. He said residential and commercial customers need a combination of renewable energy, demand response and energy efficiency measures “to escape the hit of these commodity prices.” Third-party aggregators can apply competitive pressure to utilities to “up their game,” he said.

“I think utilities are going to have to recognize that they’re going to have to compete and evolve their business models or continue to face pressure. Pressure from regulators, pressure from consumers,” Chatterjee said.

Wellinghoff said customers in states that have opted out of demand response and are unable to participate in a wholesale market’s aggregation should register their displeasure with FERC. He said the commission should revoke the ability for states to opt-out, especially considering the flexible load that tomorrow’s electric vehicle fleets can supply.

Chatterjee agreed that FERC should remove the demand response opt out, saying that tight supply conditions are not going to resolve themselves.

“We tend to only react after bad things happen. And to me right now, we’re seeing FERC drag its heels on the DR opt out; we’re seeing resistance at the state level,” Chatterjee said. “To me, it’s going to take something negative to trigger change, to trigger movement.”

He added that there’s “real risk in MISO right now of not having enough capacity on one or two very, very hot days.”

“To me, it seems like a few factories turning off could make a real difference. Sadly, it will probably take an event like that to, in my view, lead to policy changes that are necessary,” Chatterjee said.  

Thomas said the Midwest could use universal access to advanced metering infrastructure and aggregation alongside a faster roll out of MISO’s proposed 2030 compliance with Order 2222, which allows aggregators of distributed resources into the wholesale energy markets. (See MISO Stakeholders Protest RTO’s Order 2222 Implementation Timeline.)

After that, Thomas said, the grid operator could probably “have a cold one and lean back and watch entrepreneurs and business looking out for their own interests” help decarbonize the grid, reduce costs and bolster system reliability.

“If you’re going to have scale-variable resources, you’ve got to have scale-variable load,” he said. “That’s the cheapest option, and we need to make that happen.”

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FERC Approves New England Generation Deal Over Competition Objections

Federal regulators last week signed off on a Japanese company’s plan to buy three gas-fired generators in New England, despite opposition from consumer advocates who had argued that the deal would lead to undue consolidation in the region.

The investment firm Stonepeak asked FERC this summer for approval to sell two units at Canal Generating Station in Sandwich, Mass., totaling 1,457 MW, and another 160-MW unit in Bucksport, Maine, to JERA, a joint venture between two Japanese utilities, Tokyo Electric Power’s TEPCO Fuel & Power and Chubu Electric Power (EC22-71).

Massachusetts Attorney General Maura Healey and the advocacy group Public Citizen had both challenged the acquisition saying that it would give JERA — which already owns 50% of two other gas units totaling more than 400 MW in Massachusetts — too large a share of the generation market. (See Mass. AG, Public Citizen Raise Alarm Over Proposed Generation Deal).

But FERC sided with the buyer and seller, accepting their argument that the transaction would not have an adverse effect on vertical or horizontal competition.

Although JERA will own more than 18% of the capacity cleared in the Southeastern New England zone, FERC wrote that “Applicants’ analysis shows that, when considering ISO-NE as a whole, the proposed transaction does not increase market concentration such that there will be an adverse effect on competition.”

FERC also shot down protests arguing that the deal could have adverse effects on rates and on regulations. And it refused a request from Public Citizen to make public the confidential purchase price of the deal, finding no reason to break with the standard of allowing the submitter to keep prices confidential.