PJM PC/TEAC Briefs: June 6, 2023

Planning Committee

Stakeholders Endorse Discussion on Deactivating Generators’ CIRs

VALLEY FORGE, Pa. — The PJM Planning Committee on June 6 approved a problem statement and issue charge to explore possible improvements to the existing process of transferring capacity interconnection rights (CIRs) from a retiring generator to a replacement resource at the same interconnection point.

Tonja Wicks, Elevate Renewable | © RTO Insider LLC

Proposed by East Kentucky Power Cooperative and Elevate Renewables, the problem statement says transfer requests currently have to go through the same backlogged interconnection study queue as new generators to determine if any grid upgrades are required, which can result in replacements for retired facilities taking years to begin construction.

The companies said the long turnaround increases the commercial risk for generation owners seeking replacements; incentivizes speculative projects being submitted in the queue in anticipation of retirements; and contributes to PJM’s concerns about the balance between retiring resources and new entry over the next decade. The problem statement pointed to a February white paper PJM published finding that the pace of renewable development has been slower than anticipated while legislation and economics are leading to more deactivations.

The scope of the issue charge includes only discussion of transfer requests for the same point of interconnection, which EKPC’s Denise Foster Cronin said can often use existing infrastructure and should require no material transmission upgrades. The current process is envisioned to remain for transfers involving different points of interconnection, as those are more likely to require transmission upgrades. The issue charge also aims to develop a solution that specifies that the CIR transfer process applies for all energy-injecting resources, including thermal, renewable and storage.

Responding to stakeholders questioning how a system that allows replacement resources to go through the interconnection process faster would not be skipping other projects in the queue, Paul Sotkiewicz, president of E-Cubed Policy Associates, said the CIRs the replacing resource is seeking are held by the generation owner and are already being modeled as existing on the grid.

“Why can’t those projects be moved forward, because again they’re already being modeled; it doesn’t change anything for anyone else; … it’s not jumping the queue for anyone else; those CIRs are being modeled for everyone else,” he said.

Other PC Business

Stakeholders endorsed PJM’s plan for how it will conduct the 2023 reserve requirement study, the annual process for determining the forecast pool requirement and the installed reserve margin for the following three delivery years and establish the figures for the fourth year out. The study will also set the winter weekly reserve target for the 2023/24 delivery year. (See “Reliability Requirement Study to Use New Software,” PJM PC/TEAC Briefs: May. 9, 2023.)

PJM also provided a first read of the manual changes required to codify the overhaul of the interconnection study process FERC approved in November 2022. (See FERC Approves PJM Plan to Speed Interconnection Queue.)

Transmission Expansion Advisory Committee

Brandon Shores Deactivation to Require $786M in Grid Upgrades

yum-phil-at-pjm-pc-teac-2018-06-07-rto-insider-fi-1.jpg

Phil Yum, PJM | © RTO Insider LLC

The planned deactivation of the coal-fired Brandon Shores Generating Station, near Baltimore, will require an estimated $786 million to resolve several voltage and thermal violations, PJM’s Phil Yum told the Transmission Expansion Advisory Committee last week.

The violations would spread from the BGE zone to also impact PEPCO, Dominion, PECO, APS, PPL and Met-Ed. The work to the 500-kV grid is estimated at $333 million and includes two new lines between the Peach Bottom and Graceton substations, as well as additional projects throughout the BGE, PECO and PEPCO zones. The 230- and 115-kV upgrades are estimated at $453 million and include three new substations and additional work throughout the BGE and APS zones.

The deactivation is scheduled for June 1, 2025, but Yum said the work is unlikely to be complete before that date. PJM Director of Operations Dave Souder said it will likely be necessary to seek to continue operating the generator under a reliability-must-run contract while the transmission work is ongoing.

“There’s a significant need to import to serve the load,” Souder said, adding that new high-voltage lines will be required into Baltimore to avoid voltage collapse under outage conditions.

Dominion Proposes Substations and New Lines Throughout Northern Va.

Dominion Energy has proposed several line extensions and installations to serve new substations in Northern Virginia, in part fueled by data center growth.

Two new substations in Louisa County requested by Rappahannock Electric Cooperative would be served by a $55 million project to extend the North Anna-Desper line.

Meanwhile, Northern Virginia Electric Cooperative requested a new substation to serve a new data center complex with more than 100 MW of load in Bristow. The 230-kV Gainesville-Wheeler line would be extended at a $15.75 million cost.

Another substation in the area, Daves Store, would be served by extending a 230-kV line terminating at the existing Heathcote substation to the new facility at a $40 million cost. The new lines would connect to a GIS 230-kV four-breaker arrangement.

Dominion has also proposed a $33.5 million project to address a 300-MW load drop violation related to the Daves Store, Youngs Branch and Catharpin substations. The work would extend a 1.7-mile, double-circuit 230-kV line from the new Trident substation to Daves Store and install associated 230-kV equipment at both. The bulk of the cost is to acquire rights of way for the new line at $18.5 million.

Two additional substations, Gemini and Atlas, would be constructed in Gainesville to serve data center loads exceeding 100 MW. Dominion estimates each project would cost just over $15 million to construct, including 230-kV lines to interconnect them.

Other Supplemental Projects

Exelon proposed the replacement of a circuit breaker on its 500-kV Conastone line, northeast of Baltimore near the Maryland-Pennsylvania border, at a $2.3 million cost. The company said the equipment was installed in 1992 and is now deteriorating, causing higher maintenance costs. The projected in-service date is Nov. 14, 2023.

Dominion provided an update on its proposed $40 million project to install new equipment at its Goose Creek substation in Loudoun County, Va. Because of an inability to procure a 1,440-MVA transformer to address real-time constraints, it plans to instead install an 840-MVA transformer and move up the in-service date from Dec. 15, 2026, to Dec. 15, 2023.

Dominion also proposed 230-kV projects to connect to its proposed Twin Creeks substation in Loudoun County, with a requested in-service date of Dec. 31, 2024. A line linking the new substation with the existing Pleasant View and Edwards Ferry stations comes with an estimated $20 million cost, while two lines to the Sycolin Creek substation have an estimated $28 million expense.

PJM Proposes New Standard for RTEP Window Submissions

PJM presented a new format for how projects being submitted to address needs identified in its Regional Transmission Expansion Plan (RTEP) should be organized.

The RTO’s Sami Abdulsalam said the change will be required for future RTEP windows and is expected to simplify the process for both staff and stakeholders.

The change asks submissions to eliminate the inclusion of existing infrastructure that is not relevant to the project being submitted and identify facilities that will be removed when submitting single-line diagrams. It also creates a standard format for how contingency files should be named to streamline compiling all the files PJM receives.

June 13, 2023June 14, 2023

PJM MIC Briefs: June 7, 2023

Stakeholders Reject Proposal to Expand Reactive Power Task Force Scope

VALLEY FORGE, Pa. — PJM’s Market Implementation Committee voted against endorsing a proposal by the Consumer Advocates of PJM States (CAPS) to expand the scope of the Reactive Power Compensation Task Force to include discussion of existing service rates.

CAPS Executive Director Greg Poulos argued that FERC’s January order eliminating the compensation for reactive power in MISO should force PJM to revisit the scope of the task force. That order found that generators participating in MISO’s markets do not have to be compensated for providing reactive service because it is a condition of interconnection. (See FERC Ends MISO Compensation for Reactive Power Supply.)

The proposal would have modified the task force’s issue charge to strike out a line in the “out-of-scope” section barring discussion of “any existing FERC-approved or pending reactive service rates.”

Paul Sotkiewicz, president of E-Cubed Policy Associates, said the comparison to MISO doesn’t hold up, as most of that region’s load is served by vertically integrated utilities. He added that FERC has already approved reactive rates in PJM.

Constellation Energy’s (NASDAQ:CEG) Adrien Ford said the change would have little impact on the task force’s work, as existing reactive charges are FERC-approved and could not be changed by proposals it may produce.

Carl Johnson, representing the PJM Public Power Coalition, said his members and CAPS approach the issue from the same common belief: that there isn’t a need to compensate generators operating within the common bandwidths for providing reactive power. However, he disagreed that the task force’s scope should be modified when it’s already far into its work.

Discussion Continues on Capacity Offers for Generators with Co-located Load

Package sponsors continued to refine their proposals on how generators can represent co-located load in their capacity offers to reflect how configurations with service from the grid would be handled.

Past discussions largely focused on arrangements without grid service — whether load in those circumstances would be under FERC or state jurisdiction and whether generators should be able to offer the energy supplied to that load as capacity. (See “Stakeholders Continue Discussion on Co-located Load Packages,” PJM MIC Briefs: May 10, 2023.)

PJM’s proposal would retain its status quo provisions, reducing generators’ capacity interconnection rights (CIRs) in line with the amount of co-located load, imposing transmission service payments to the load serving entity (LSE) and basing settlement on the net injection at the point of interconnection.

Proposals from the Independent Market Monitor (IMM), Exelon and Advanced Energy Management Alliance (AEMA) would all measure the generator and load separately to arrive at settlements for each. The IMM would follow the status quo for reducing CIRs and transmission service charges, while Exelon and the AEMA would not reduce generators’ CIRs.

Exelon’s proposal would classify the generator as an LSE for the co-located load and the AEMA package would require the generator to procure firm point-to-point transmission service with both injection and delivery set at the generator’s point of interconnection.

Much of the discussion around defining co-located load as not receiving transmission service centered on whether such load would then fall under state jurisdiction.

PJM Senior Counsel Chen Lu said the RTO considers such arrangements to be a retail sale directly from the generator to the load. Its proposal would define the load as being state jurisdictional but would pass charges for frequency regulation, reserves and black start service to the load through the generator.

Economist Roy Shanker said he doesn’t believe it’s appropriate to determine that load is state jurisdictional while still creating mechanisms to impose PJM charges on it through the generator.

Four proposals are on the table for co-located load without grid service — from PJM, the IMM, Exelon, and a joint package from Constellation Energy and Brookfield Renewable Partners.

MIC Chair Foluso Afelumo said a vote on the proposals is planned for next month, with separate votes for proposals addressing load with and without transmission service. The committee held a poll last November that found little support for either the Monitor or Constellation Energy/Brookfield Renewable Partners proposals. (See “Limited Support for Co-located Load Proposals,” PJM MIC Briefs: Dec. 7, 2022.)

PJM Presents Expected Impact of Creation of Fifth CONE Area

PJM’s Gary Helm said analysis shows that creating a fifth cost of new entry (CONE) area for the Commonwealth Edison region would not have a significant impact on the price of resources in that area for the 2025/26 delivery year (DY), but prices could increase by 2028/29. (See “PJM Proposes Creation of Fifth CONE Area,” PJM MIC Briefs: May 10, 2023.)

PJM analysis of the impact of creating a fifth cost of new entry (CONE) area for the Commonwealth Edison region, shown to the Market Implementation Committee on June 7, 2023. | PJM

The ComEd locational deliverability area (LDA) is located in CONE area 3, which has a gross CONE of $398/MW-day for the 2025/26 DY. If the ComEd region were carved out as its own area, PJM estimates that it would result in a $401/MW-day gross CONE value, a 0.7% increase. By the 2028/29 delivery, the difference between the two is estimated to be around 6%. Helm said staff are still discussing whether PJM will seek to implement the prospective change for 2025/26.

During the May 10 MIC meeting, Helm said the proposal arose out of comments on PJM’s quadrennial review FERC filing about the impact of the Illinois Climate and Equitable Jobs Act on net CONE.

Sotkiewicz said he plans to bring a second proposal before the committee during its July meeting.

June 12, 2023

NY State Reliability Council Executive Committee Briefs: June 9, 2023

Emergency Operating Procedures

ALBANY, N.Y. — New York’s installed reserves margin (IRM) study may be overly optimistic in its emergency assistance assumptions, according to a presentation given to the New York State Reliability Council’s Executive Committee (NYSRC EC) on Friday.

NYSRC Installed Capacity Subcommittee members said preliminary discussions about a forthcoming white paper, which examines how emergency operating procedures are implemented and modeled, indicate that “conditions are tight” and that NYISO and neighboring systems are all counting on one another to provide resources in the same emergency situations.

The IRM study shows New York requiring substantial assistance in emergencies, mainly from IESO in Ontario and ISO-NE. But during tight real-time conditions, PJM typically supports New York, while IESO and ISO-NE rely on New York for export support, which could create supply problems across the Northeast during future emergencies.

ICS Chair Brian Shanahan shared how “other area’s resource adequacy models generally have lower emergency assistance assumptions, compared to what we use,” adding that “that’s putting pressure on system and resource adequacy conditions.”

Industry participants are concerned that winter could emerge as a peak period, leading to increasingly tight conditions during the season, Shanahan said.

Some attendees at the EC meeting criticized the ICS’ characterization as being too unspecific.

One attendee said “generalizations are really fraught with danger, and so we need to look specifically at each area to understand what their circumstances are and what they model.”

Howard Kosel, manager of energy management resource analysis at Con Edison, said “the statement that we’re overly optimistic on what we’re relying on to get from our neighbors is a very broad statement.”

NYISO is developing ways to adjust its modeling to account for seasonal area-specific limits to minimize future interregional disruptions. It plans to present more details about the issue at the next ICS meeting.

NYSRC Elections

The EC unanimously reelected Chris Wentlent and Mark Domino as chair and vice chair, respectively.

The NYSRC EC consists of 13 members: six representatives of current transmission owners, one wholesale seller representative, one representative of the large consumers sector, one representative of the municipals and electric cooperatives sector, and four members unaffiliated with any market participant.

The four unaffiliated members also were reelected to serve another two-year term, and all other representatives — except for the wholesale seller representative — were approved.

Wholesaler sellers are still in the process of selecting their representative, and a vote remains pending.

OSW Wind Petitions

Wentlent updated the EC about petitions submitted to the New York Public Service Commission by several renewable developers who asked for permission to amend their offshore wind renewable energy certificate (OREC) agreements due to recent inflationary pressures (15-E-0302 and 18-E-0071). (See OSW Developers Seeking More Money from New York.)

ORECs are contracts in which the New York State Energy Research and Development Authority agrees to compensate developers for the environmental benefits stemming from the electricity generated by OSW projects.

Wentlent said the issue is important because it will affect how quickly New York can replace retiring resources with new, clean generation.

NYISO has repeatedly warned that retirements pose a threat to supply adequacy. (See NYISO CEO Warns of Tightening Resource Adequacy.)

“The timing of when new resources show up and how we deal with decisions on existing resources becomes even more critical,” he said.

Inverter-based Resources Standard

NYSRC’s Reliability Rules Subcommittee hopes to finalize a proposed rule establishing minimum requirements for inverter-based resources over 20 MW by September, according to a draft road map shared with the council.

The subcommittee will revise PRR-151 based on previous stakeholder comments and then consider reposting the draft rule for additional comments in early July. (See “Inverter-based Resources Standard,” NY State Reliability Council Executive Committee Briefs: May 12, 2023.)

“This is a big deal and has got the attention of everybody across the industry,” subcommittee Chair Roger Clayton said.

“We’re in the vanguard in implementing this thing, and so we need to be comprehensive and take our time to get it right,” he added.

June 12, 2023November 8, 2023

California PUC Grants PG&E $1B in Wildfire Costs

The California Public Utilities Commission on Thursday awarded Pacific Gas and Electric more than $1.1 billion in wildfire mitigation costs despite opposition from its own Public Advocates Office and consumer groups.

The commission granted PG&E 85% of the money it requested to be collected from ratepayers over the next year. The order, written by CPUC Administrative Law Judge Camille Watts-Zagha, was approved unanimously without discussion, along with rest of the Thursday voting meeting’s lengthy consent agenda.

The public advocates said the decision was arbitrary and capricious and that the commission committed legal errors by awarding PG&E its requested costs without determining their reasonableness first, as required by state law.

It is “unprecedented to grant a utility 85% of its recovery request in interim rates without a reasonableness review,” the advocates said. “Previously, the commission has explained in detail why a grant of 55% in interim rates was equitable. Here, the commission makes no attempt to demonstrate why 85% is reasonable.”

The office said the CPUC should award PG&E a maximum of 55% of its nearly $1.4 billion request, or $770 million.

Consumer groups The Utility Reform Network (TURN) and Direct Access Customer Coalition (DACC) urged the CPUC to reject PG&E’s request entirely.

“The proposed decision would authorize interim rate recovery for over $1 billion of costs PG&E has incurred but that have not yet been determined to be reasonable,” TURN said. “In the past, and as recently as last year, the commission has limited such rate relief to extraordinary circumstances.

“Rather than continue this practice, the proposed decision would grant PG&E the full extent of the requested relief, based on little more than general assertions regarding the utility’s financial condition and the likelihood that requiring customers to prepay $1 billion could reduce interest costs by approximately $30 million,” TURN said. “In doing so, it would downplay if not ignore the repeated and consistent [upbeat] statements PG&E has made to the financial community regarding its current financial condition.”

The utility’s credit rating remained below investment grade at the end of 2022, but its outlook has since improved as its stock price has been edging upward.

PG&E contended that interim rate recovery (IRR) would improve its credit rating and benefit customers in the long run with lower corporate borrowing costs.

“The [proposed decision] correctly grants IRR because it will provide direct interest savings of approximately $30 million to PG&E customers,” the utility said. “The IRR will also improve PG&E’s financial condition and credit metrics, which could yield additional customer savings and benefits through PG&E’s improved access to capital.”

Nearly $850 million of the award will cover PG&E’s vegetation management activities to prevent wildfires.

A tree falling on a PG&E distribution line caused the nearly 1 million-acre Dixie Fire, which burned through five counties in the Sierra Nevada foothills from July to October 2021. The Zogg Fire, which killed four people in September 2020, was also ignited by a downed tree on a PG&E line, the California Department of Forestry and Fire Protection (Cal Fire) found.

Branches and trees striking PG&E lines were among the causes of a spate of fires in October 2017 that ravaged Northern California wine country, Cal Fire determined.

The decision said that the reasonableness of PG&E’s costs would be reviewed later.

“PG&E is required to refund, with interest, any excess amount it collects in comparison to the commission’s final determination on the amount reasonably incurred,” it said. “Nothing in this decision shall be construed to relieve PG&E of the burden of proving that all costs it seeks to recover in this proceeding are just and reasonable.”

The decision agreed with PG&E that “interim cost recovery confers benefits of cost savings and risk minimization to the ratepayers and utility sufficient to justify departure from the commission’s statutory duty to put costs into rates after the commission determines the costs reasonable. Based on the totality of circumstances, commencing collection of costs through rates now is consistent with the commission’s constitutional and statutory duty to review and approve rate increases.”

Spread out over PG&E’s 5.5 million customers, the rate hike is expected to add $8.67 to the utility bills of typical consumers, whose average bills now range between $111 and $180/month.

June 12, 2023March 12, 2024

New England Stakeholders Discuss Clean Energy Market Mechanisms

PROVIDENCE, R.I. — As a haze of smoke and particulate matter from several massive Canadian wildfires engulfed the Northeast last week, energy industry leaders met in the 17th floor ballroom of the Graduate Providence hotel to discuss some of the challenges and opportunities of decarbonization.

Much of the discussion, hosted by the Northeast Energy and Commerce Association at the 29th annual New England Energy Conference and Exposition, centered around how the region can improve the financing of large clean energy projects, including potential market mechanisms to supplant the current reliance on power purchase agreements.

Over the past several years, New England states and stakeholders have discussed the potential for regionwide clean energy market mechanisms, such as a carbon price or a forward clean energy market (FCEM), but have struggled to come to a consensus on any such program. (See NECA Panel Ponders Forward Clean Energy Market.)

Joanna Troy, director of energy policy and planning at the Massachusetts Department of Energy Resources (DOER), said creating a market framework to incentivize large clean energy projects could help ratepayers across New England save money. She referenced the 2022 “pathways analysis,” commissioned by ISO-NE, that found the status quo of state-led PPAs to be more expensive than alternatives like a forward clean energy market, a carbon price or a hybrid.

The DOER under the administration of former Gov. Charlie Baker released a proposal for a regional FCEM in January; it outlined the creation of an independent nonprofit to oversee the market, with representatives from each New England state. Stakeholders including utilities, state agencies, municipalities and companies would voluntarily purchase different types of clean energy certificates, which would help provide financing for renewable resources.

In May, the Massachusetts Executive Office of Energy and Environmental Affairs, in consultation with the DOER and Department of Public Utilities, released a report on clean energy markets, concluding that the “use of a regional or multistate, market‐based approach to facilitate the development of clean energy generation resources — and, more broadly, to achieve and maintain a clean, reliable and affordable energy resource mix — could result in lower costs to consumers and would be beneficial for the commonwealth.”

However, the state said additional collaboration with other New England states would be necessary to develop and implement this approach and cautioned that implementing an FCEM would take years.

Thus, “Massachusetts must collaborate with its regional partners and explore more expedient market‐based approaches to support the development of clean energy, the achievement of state decarbonization requirements and reduced consumer costs,” the state concluded.

From left: Bob Grace, Sustainable Energy Advantage LLC; Cyrus Tingley, Plug Power; Alberto Aguillon, FuelCell Energy; and Sara Harari, Connecticut Green Bank | © RTO Insider LLC

“All options are on the table for how we get to a world in 2050 where we have this innovative clean energy market,” Troy said.

Susannah Hatch, director of clean energy policy at the Environmental League of Massachusetts, said studies show it will be extremely difficult to reach net-zero emissions without placing a meaningful carbon price, which should not be limited to the electricity sector.

“Having an economywide carbon price will be really important to make sure that we’re not disincentivizing electrification in other sectors,” Hatch said.

Aleks Mitreski, senior director of regulatory affairs at Brookfield Renewable Energy, said issues related to cost allocation and “finance-ability” for developers of clean energy projects have come up while trying to design a carbon pricing scheme, but he called carbon pricing “probably the easiest and best thing to do from an economic standpoint, if we can get that done.”

Hatch said an FCEM could be a useful tool but expressed concerns that a cost-based mechanism could overlook other important factors.

“While markets are really amazing at getting the lowest-cost projects and driving down costs for consumers, which is really important, they do not do quite as good a job of valuing some of the things we care about, such as environmental protection; diversity, equity and inclusion; labor standards; environmental justice; etc.,” Hatch said.

Panelists also stressed that market mechanisms must account for the variable reliability attributes of different clean energy resources, over both short- and long-term horizons.

“If we define the services that we need, then that provides the revenue opportunities for the markets to procure those services, so that we get the sort of resource mixes that will ultimately provide the region with the reliability we need as we move towards a lot more non-carbon-emitting resources,” said Chris Geissler, manager of economic analysis at ISO-NE.

Geissler highlighted the RTO’s work on the Day-Ahead Ancillary Services Initiative, which would provide new incentives for short-term reliability resources within the day-ahead market. (See ISO-NE Plans 2025 Launch for Day-Ahead Ancillary Services Initiative.)

Verifying Clean Hydrogen

As federal investment spurs interest in hydrogen development, Bob Grace, president of consultancy Sustainable Energy Advantage, made the case for a comprehensive hydrogen tracking system to verify the emissions intensity of hydrogen, tracking it from production to end use.

“At present, there is no established system for green hydrogen to be tracked and attributed between source and use,” Grace said. “A clean or green hydrogen tracking system is needed — and it’s needed soon — to enable a credible landscape for hydrogen.”

The federal tax credits created in the Inflation Reduction Act are based on a tiered system of carbon intensity: the lower the lifetime carbon intensity of the hydrogen, the greater the tax credit received.

Grace said a centralized tracking system that is not limited by geography will be essential to ensuring that hydrogen is as clean as it claims to be and that parties investing in hydrogen can rely on a framework to support due diligence and contracting. He added that the system will need to be able to track hydrogen as it is transported, stored and blended with nonrenewable fuels, while accounting for losses along the way.

“Going forward, we’re looking to pull together interested stakeholders, create a stakeholder process and find the funding to take this to the next step,” Grace said.

Cyrus Tingley of Plug Power said that while the hydrogen market has not yet been overly concerned about verification, “for it to be sustainable and bankable long term, we need it. … There’s a big volume of projects and effort out there that will ultimately depend really strongly on this.”

Tingley agreed that a multistakeholder process will be needed to create a workable verification system, overseen by a trusted and independent organization.

June 12, 2023June 28, 2023

Experts Call for More Engagement, Shorter Timelines for Clean Projects

BOSTON — Building public support for clean energy projects and infrastructure will require increased community engagement and shorter timelines, a panel of energy experts told industry participants last week.

A variety of stakeholders, including industry insiders, government officials and climate advocates, gathered Friday at Raab Associates’ New England Electricity Restructuring Roundtable to discuss how the region can rapidly expand its clean energy infrastructure.

Stakeholders largely agreed that proactive and extensive community engagement is essential for building public buy-in for clean energy projects such as large-scale solar and onshore wind, as well as for new transmission infrastructure.

Eliza Donoghue, director of advocacy at Maine Audubon, said that more outreach to local communities is necessary to change the public narrative around renewable energy projects.

“Solar moratoriums are popping up all over the place in Maine,” Donoghue said. “Even die-hard climate advocates aren’t appreciating that rooftop solar alone isn’t gonna get us where we need to go.”

Donoghue said that focusing on local jobs can help win over communities that do not consider climate action to be a priority.

“We need to show the public using on-the-ground examples that we can have both,” Donoghue said. “We can rapidly deploy renewable energy resources at scale, and we can conserve our most high-value — and emphasis on high-value — natural resources.”

Don Jessome, CEO of Transmission Developers, Inc., agreed that extensive public engagement is an essential component of any successful project.

“You cannot do enough stakeholder engagement — it’s impossible,” Jessome said. “We will meet with anybody, anywhere, anytime. That’s the only way you’re ever going to get these projects built.”

At the same time, Jessome said, reducing procurement timelines is essential to limiting project risks and keeping costs low.

“Anything that can be done to cut those timelines is going to be incredibly important, because without it projects just won’t go forward,” Jessome said. “You just can’t take that risk.”

Massachusetts state Sen. Michael Barrett (D), co-chair of the Senate Joint Committee on Telecommunications, Utilities, and Energy, said that Massachusetts legislators lack information about the specific obstacles that are holding up project timelines at the state level.

Barrett said bills he has read in the current legislative session have failed to detail the regulatory roadblocks that are slowing down clean energy deployment. The only proposals include a “simple blanket suspension of the Massachusetts Wetlands Protection Act,” and a plan to “completely suspend review by regional planning agencies” such as the Cape Cod Commission and the Metropolitan Area Planning Council.

“We need more thought given to exactly where the state-level obstacles lay, and we need a concrete set of proposals,” Barrett said. “We need substitutes that are more thoughtful, more diagnostic, and more concrete.”

Offshore Development

Katie Dykes, commissioner of the Connecticut Department of Energy and Environmental Protection, said states need to “take a hard look at the competitive [request for proposal] and [power purchase agreement] model for driving investment in offshore wind.”

She said that Connecticut does not plan to abandon PPAs but is working to improve the process by aligning and coordinating procurements with other states, indexing PPA prices to account for inflation, and finding other funding mechanisms for the transmission costs that are currently part of the PPAs.

“Unique to offshore wind, we’re financing a bundled product of generation and transmission in one power purchase agreement, and so if there’s a way to pull costs out of a PPA through a regionally shared investment in transmission, I think that will help to mitigate some of these cost pressures,” Dykes said.

Dykes called on states to “engage in more conversations about sharing the costs — or investments as we like to say — in offshore wind on a regional basis,” adding that “transmission and interconnection costs are really well-suited for that kind of sharing.”

José Antonio Miranda, CEO of Avangrid Renewables, said flexibility in procurement contracts is essential to preventing unforeseen issues. Avangrid has moved to terminate its 1,200 MW PPA for the Commonwealth Wind Project in Massachusetts, while SouthCoast Wind Energy recently announced its intention to terminate its 1,200 MW proposal. (See Developer Seeks to Terminate SouthCoast Wind PPAs.)

Miranda said that a combination of supply chain constraints, inflation and rising interest rates have caused project costs to skyrocket, and that future contracts should account for these uncertainties.

“With these complex projects, you need to be flexible,” Miranda said. “You need to understand that something unexpected may happen, and it did happen the last two or three years.”

Amanda Lefton, policy director of Foley Hoag and the former director of the U.S. Bureau of Ocean Energy Management, said that while inflation is significantly impacting offshore wind, cost increases are “an industry-wide problem” affecting both renewable and fossil fuel projects.

“This is not because renewable energy is not viable; this is not because renewable energy can’t compete,” Lefton said. “This is because all energy projects are facing these challenges.”

Lefton said she expects states will put greater emphasis on project viability in future agreements, along with including inflation adjustment mechanisms.

The impact of global supply chain constraints on U.S. offshore wind will require creation of a massive domestic supply chain, said Sam Salustro of the Business Network for Offshore Wind.

“We’re going to see a ton more new manufacturing investments not only tied to procurements in New Jersey, New York, Massachusetts and Connecticut, but also unlinked investment decisions, so new factories are popping up regardless of whether a state is under a procurement process,” Salustro said.

He added that the industry will also need to invest in workforce development, which will rely on labor unions and state agencies.

Unions “are already spending millions and millions of dollars setting up new training facilities in union halls all across America to make sure that their members are ready,” Salustro said.

June 12, 2023June 14, 2023

NYISO CEO Warns of Tightening Resource Adequacy

NYISO CEO Rich Dewey on Wednesday told reporters that anticipated fossil fuel-fired plant retirements could shrink reliability margins to the point that they may have to be delayed.

“We’ve got to be really careful not to prematurely retire resources if we don’t have replacement supplies at the ready,” Dewey said.

The comments came as part of Dewey’s presentation of the ISO’s annual Power Trends report, the findings of which were similar to those of last year’s: NYISO has its hands full as state public policies drive rapid fossil plant retirements, while the interconnection of new clean resources is not keeping up. (See NYISO 2022 Power Trends Report: Reliable Clean Energy Needed Quickly.)

“We’re mindful that the number of interconnection requests has quadrupled, but this is a priority for us, and we are doing everything we can to make sure this process is as efficient and effective as possible,” Dewey said.

To meet the goals of New York’s Climate Leadership and Community Protection Act, which mandates 70% of the state’s energy come from renewables by 2030 and its grid be 100% net-zero by 2040, more must be invested in the research and development of emissions-free resources that will be needed to replace the capabilities of the retiring traditional plants, the report says.

Dewey last month told attendees at a conference hosted by NY-BEST, a battery storage consortium, that dispatchable emission-free resources must be quickly introduced onto the grid, and NYISO is committed to developing the right price signals that incentivize these technologies to enter New York’s markets. (See New York Fine-Tuning its Market for Energy Storage.)

NYISO has a “robust portfolio of new market enhancements that recognize the pricing signals that are necessary to attract the right resources to the right locations on the grid,” Dewey said Wednesday.

Transition to winter peaking system (NYISO) Content.jpg

Figure showing transition to winter peaking system | NYISO

Other findings discussed during the conference also were familiar: a rise in carbon dioxide emissions partly attributed to the deactivation of the Indian Point nuclear power plant (21-01188); an acknowledgement that electrification will create higher demand and shift the grid to a winter-peaking system; and that unbottling intermittent resources via transmission upgrade investments can help bring upstate energy downstate to offset fossil fuel retirements.

“New York has enjoyed a surplus of energy supply over the last few decades, and that surplus has allowed us to manage the grid through contingencies and severe weather events,” Dewey said, “but as supply margins shrink, it has become more complicated and tighter operationally to make sure we can maintain and balance reliability.”

“Given that the number of deactivations has outpaced the number of new additions, that balance has come into sharper focus, and as [NYISO] looks forward, we are mindful of assessing and evaluating planned deactivations to ensure we maintain the tight balance necessary to operate the power grid,” he added.

NY Historical generating capacity (NYISO) Content.jpg

Historical generating capacity for New York from 2000 to 2023 | NYISO

Multiple reporters asked NYISO about thinning reliability margins across the state and what is the level of concern.

Dewey conceded that NYISO expects to see available megawatts shrink as fossil fuel plants retire and that the ISO needs to better understand whether these plants may need to remain in operation.

“It seems likely that some component of those peakers that are targeted for retirement would need to stay on,” Dewey added, “because it seems unlikely that we’ll have enough market-based solutions to eliminate the need for some element of those peakers to be extended for some period of time.”

In response to a question about the Public Service Commission opening a review process that could expand the role of nuclear and other technologies (15-E-0302), NYISO Executive Vice President Emilie Nelson said, “The incredible diversity [New York] has on supply-side technologies today is something that [NYISO] looks forward to seeing in the future years. We need a combination of technologies that can operate on the grid to really continue providing reliability day-in and day-out, so we look forward to exploring all technologies.” (See NY Renewable Portfolio May Come up Short on Getting to Net Zero.)

June 12, 2023June 14, 2023

Ex-ERCOT CEO Kahn Returning to Austin Energy as GM

Austin Energy announced Friday that it has brought former ERCOT CEO Bob Kahn back to the utility as general manager.

Kahn is currently general manager of the Texas Municipal Power Agency (TMPA), which represents 72 municipal utilities. He was ERCOT’s CEO from 2007 to 2009, and he replaces Jackie Sargent, who retired after controversial extended power outages in February.

“I’m very excited to return to Austin Energy and look forward to working with the community and the hardworking, dedicated staff at Austin Energy to accomplish the City Council’s goals,” Kahn said in a statement.

Bob Kahn, TMPA | TMPA

Before taking the ERCOT leadership role, Kahn was Austin Energy’s deputy general manager, general counsel and vice president for legal services. He served on ERCOT’s Board of Directors from 2002 to 2006, and returned to the board in 2021 following the disastrous winter storm, but resigned shortly thereafter over a conflict of interest with his TMPA leadership position. (See Former ERCOT CEO Kahn Resigns from Board.)

Kahn’s first day back with the utility will be July 3.

Interim City Manager Jesús Garza, who returned to the Austin government after Spencer Cronk was fired for the utility’s response to the storm, announced other leadership changes as well.

“I am confident the changes announced … will strengthen the City of Austin as we continually work to improve the services we provide to our residents,” he said.

June 11, 2023December 7, 2023

FERC Approves PJM Capacity Auction Delay to 2024

FERC on Friday approved PJM’s request to delay its Base Residual Auction for the 2025/26 delivery year, directing the RTO to submit a compliance filing that sets a June 2024 date (ER23-1609).

The commission’s ruling came just a day before its 60-day deadline to act; the RTO had said it would hold the auction as originally scheduled this Wednesday if the commission did not rule on its request. (See PJM Capacity Auction Weeks away with No Answer on Delay.)

PJM sought the delay to give itself more time to craft changes to its capacity market through its Critical Issue Fast Path process in reaction to the December 2022 winter storm. In its filing, it included a potential, “illustrative” schedule for the 2025/26 auction and three subsequent auctions, along with their respective Incremental Auctions, until it could resume its normal schedule beginning with the 2029/30 BRA in May 2026.

FERC approved the request, conditioned on PJM using that schedule.

“We find that the potential scope and magnitude of the capacity market-related reforms PJM is considering in its stakeholder process provide sufficient justification under [Federal Power Act] Section 205 to delay the auctions until after the commission has an opportunity to act on any proposals that PJM may file following that stakeholder process,” FERC said. But “we agree with commenters that the proposed tariff revisions afford PJM with overly broad discretion to set the auction schedule and fail to provide market participants with sufficient certainty as to the auction start dates for the [2025/26 through 2028/29] delivery years. … PJM must include the [illustrative] schedule in addition to PJM’s proposed tariff language stating that it will post the revised auction schedule on its website.”

The RTO’s schedule is based on it filing revisions by Oct. 1 and winning FERC approval of them without material changes by Dec. 1.

FERC also granted PJM’s request for 10 business days of leeway for specific pre-auction deadlines, agreeing that it would be administratively burdensome to file new tariff revisions for each one if there is a need for a change. “However, we recognize PJM’s commitment to post the specific dates of pre-auction activities no later than eight months prior to the commencement of any associated BRA in order to ensure that all market participants are aware of the relevant deadlines,” it said.

Commissioner James Danly concurred with the order, but he highlighted the move as an “extreme measure.”

“I only support delay in this case because PJM’s existing Reliability Pricing Model mechanism is manifestly unjust and unreasonable, and continuing to run auctions under the current rules will continue to produce unjust and unreasonable rates,” Danly wrote. “My colleagues, however, have not to date supported my calls to issue a Federal Power Act Section 206 investigation into PJM’s markets and its administration of them. Thus delaying the unjust and unreasonable auctions for PJM to develop market ‘enhancements’ is an appropriate exercise of our Section 205 authority and, given my colleagues’ reticence to act, the best we can hope for at present.”

Commissioner Allison Clements dissented, saying PJM failed to demonstrate its proposal to delay the auctions was just and reasonable. While she said she appreciated that the majority required “at least a minimal level of clarity” by directing the RTO to file the illustrative schedule, the order “sets a dangerous precedent that may essentially allow RTOs to schedule auctions according to their own whims, undermining certainty and stakeholder confidence in market rules and utility tariffs across the country.”

“If the mere possibility of future market reforms constitutes grounds for delaying particular auctions, absent evidence that existing rules are in fact unjust and unreasonable, how can market participants have any confidence in auction schedules memorialized in their current tariffs?” Clements wrote in a lengthy dissent. “PJM’s proposed delay is predicated on the need to wait until its current market rules are reformed, but PJM does not even specifically detail what those market reforms will be, let alone make out a legal case for why those reforms are necessary.”

June 11, 2023

LPO Announces $850M Conditional Loan for Ariz. Battery Cell Plant

The Department of Energy’s Loan Programs Office (LPO) announced Friday it has made a conditional commitment for an $850 million loan to KORE Power to help the Idaho-based battery cell manufacturer construct a 1.3-million-square-foot plant in Arizona.

The KOREPlex facility, now under construction, will produce battery cells for both the electric vehicle and stationary storage markets. Located in Buckeye, Ariz., west of Phoenix, the plant will have an initial capacity to produce 6 GWh of battery cells, enough to power more than 28,000 EVs annually, according to the LPO.

“Onshoring battery manufacturing is critical to reducing America’s reliance on other nations, such as China, which currently dominates the industry and supplies many American companies with materials to resell foreign-made batteries,” the LPO announcement said.

Scheduled to begin commercial production in late 2024 or early 2025, the facility is being built with two manufacturing lines, one for lithium-ion nickel, manganese, cobalt (NMC) cells and one for lithium-ion iron phosphate (LFP) cells. While NMC batteries have been widely used in electric vehicles, some EV manufacturers are starting to use LFP cells, which are cheaper and do not use critical minerals such as cobalt.

The tradeoff is that they are not as energy dense as the NMC cells, which means EVs with LFP batteries may have a shorter range before they need recharging.

Tesla is now using LFP batteries in some of its Model 3 EVs, according to the company website. Ford is also planning to produce LFP batteries for some of its EV models at a plant in Michigan, the company announced in February.

KORE plans to target smaller EV equipment manufacturers requiring lower production volumes. It is working with local colleges and universities to train area residents for the 1,250 permanent jobs the factory is expected to create.

Domestic Content Controversy

The KORE Power conditional loan commitment is the seventh the LPO has made under its Advanced Technology Vehicles Manufacturing Program in the past year, the agency said, and comes at a time when EV and energy storage supply chains have become a political flashpoint.

Batteries are critical to the achievement of President Joe Biden’s goals to decarbonize the electric power grid by 2035 and to crank up EVs to 50% of all new car sales by 2030. Republicans in Congress — and some Democrats, such as Sen. Joe Manchin (D-W.Va.) — have criticized these targets as potentially increasing U.S. dependence on foreign supply chains for battery cells and other clean energy technologies.

China, in particular, dominates the lithium-ion battery supply chain, controlling 75% of all battery cell manufacturing and 90% of the manufacturing of anodes and electrolytes, key battery components, according to BloombergNEF.

Manchin crafted the EV tax credits in the Inflation Reduction Act with rigorous domestic content provisions intended to support the build-out of a domestic supply chain for lithium-ion batteries. To receive the full $7,500 tax credit, final assembly of an EV must be in North America and 50% of the value of battery components and 40% of the critical minerals in the battery must be produced, processed or manufactured in the U.S.

The domestic content percentages will increase every year, to 80% for critical minerals by 2027 and beyond and to 100% for battery components by 2029 and beyond, according to the Internal Revenue Service guidelines released in March.

Conditional commitments do not guarantee the LPO will award a loan. “Several steps remain for the project to reach critical milestones, and certain conditions must be satisfied before the department issues a final loan,” the agency said.

Other recent LPO conditional commitments have included a $2.5 billion loan to Ultium Cells to support new EV battery cell plants in Michigan, Ohio and Tennessee, and a $107 million commitment to Syrah Vidalia to expand a plant in Louisiana that produces graphite, another core component of lithium-ion batteries.

Ultium is a joint venture of General Motors (NYSE:GM) and LG Energy Solution.