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September 15, 2024

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County Contests Tx Easement for NJ’s 1st OSW Project

New Jersey’s Cape May County has appealed a state Board of Public Utilities decision to grant Ørsted an easement to run a transmission cable from the state’s first offshore wind project to an onshore substation.

The appeal, filed with the state Appellate Division April 5, argues that the BPU committed a “legal error” in concluding that developer Ørsted’s application for the easement for Ocean Wind 1 was not a “contested” case, negating the need for full hearing before an administrative law judge.

The decision “effectively turned the matter into a summary proceeding with none of the procedural and substantive due process protections required in the context of the taking of real property by government … supplanting of the authority of duly elected officials,” the county said in its appeal.

“There was no opportunity for any party to cross examine the witnesses supporting the petition and no opportunity for formal discovery,” the appeal said. “Consequently, the proceedings were fundamentally unfair [and] deprived the Appellant County of due process of law and resulted in a legally unsupportable and unjust result.”

Testing a New Law

The appeal is the second filed against the BPU involving an easement approved for Ocean Wind 1 and is the second to test a new state law approved in July 2021 specifically to assist the advance of offshore wind projects. The law (S3926) allows the BPU to override local government agencies and give permission for developers to site, construct and operate “wires, conduits, lines and associated infrastructure” on public land if they are shown to be “reasonably necessary” to the project. (See NJ Lawmakers Back Offshore Wind Bills.)

Ørsted is seeking to run a 275-kV underground line through the Jersey Shore community of Ocean City, which is in Cape May County, to connect with the PJM grid at a substation sited on a now closed coal-fired power plant in neighboring Upper Township.

To move ahead, the developer needed a temporary 18-month easement and a permanent 30-foot-wide easement to run the same cable across county land in Ocean City, which the BPU granted. (See NJ BPU Grants Second Easement for OSW Project.)

In response to an inquiry about the appeal by Net Zero Insider, an Ørsted spokesperson said the company “will not comment on pending litigation.”

In the earlier case, Ocean City appealed the BPU’s approval of an easement and various environmental approvals allowing the cable to run through the town, including across land improved by state Green Acres funds, which are awarded to develop parks and open space. (See NJ BPU Approves Easement Plan for 1st OSW Project.)

In both cases, the BPU’s approval opens the way for Ørsted to seek easement and permit approval from the New Jersey Department of Environmental Protection, which is needed for the project to get federal backing.

Erasing Home Rule

The BPU’s decisions in the two cases followed several public hearings on each case in which testimony was provided by representatives of Ørsted, Cape May County, the New Jersey Division of Rate Counsel, Ocean City and others, including some local governments that also opposed the easement. Nine South Jersey municipalities in or around the shore opposed the granting of the easement, and the wind projects met opposition from residents, commercial fishermen and tourism sectors that worry about the impact of having visible turbines off the Jersey Shore, a major economic driver for the state.

Opponents raised questions about what other cable routes Ørsted had considered and why it did not opt for any of them. Another issue raised was the estimated cost of pursuing each of the alternatives and whether the developer picked the route it did simply because that route was the cheapest to execute, regardless of the potential disruption to the community. Ørsted argued that the cost was irrelevant because it would pay the bill itself, and not the public.

The Cape May appeal says the “decision of the BPU that easements and consents sought under the petition are reasonably necessary for the construction and operation of the offshore wind project was arbitrary, capricious, and/or unreasonable and must be reversed.”

The decision “effectuated the erasure” of Home Rule — a prized concept in New Jersey that gives local governments authority over municipal affairs — and “disenfranchised the voters of the county,” the appeal said.

The county argued that, prior to seeking the BPU’s approval of the easement, the developer “sent letters to the County of Cape May with vague, ambiguous and conditional demands that left the County incapable of determining what consents or property interests Ocean Wind was demanding from the County.”

The appeal said that Ørsted conducted no appraisal of the value of the county property needed for the easement and failed to give the county all the required documentation required in the procedure, leaving it “without the ability to assess whether consent would be appropriate or not.”

Ørsted testified in the hearing that it had repeatedly held talks with the county and tried to strike an agreement over the permits, but the effort was fruitless because the county apparently did not want a deal.

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New Jersey’s 3-year Energy Efficiency Plan Faces Scrutiny

A New Jersey plan to promote energy efficiency and provide measurable benefits to users encountered scrutiny over cost, impact and effectiveness at two Board of Public Utilities (BPU) hearings this month.

Speakers at the online hearings argued for the need for consumer education, a greater emphasis on heat pumps and larger incentives to persuade consumers to buy electric — rather than gas-fueled — appliances.

The straw proposal for the plan, known as the “second triennium” because it follows a similar plan crafted in 2020, would require the state’s utilities to administer core energy efficiency programs for residential, multi-family buildings and commercial industrial properties. The outline calls for establishing energy assessments and incentives for “whole home” electrification solutions for residential properties and incentives and energy management programs for commercial and industrial properties.

The most contentious issue was the plan’s proposal to change the current management responsibility for the agency’s “comfort program,” which provides energy efficiency upgrades to low-income households at no cost to homeowners. The straw proposal suggests the program should be almost entirely administered by utilities, with “continued oversight” by the BPU, instead of the current situation in which the BPU administers the program and the utilities simply provide the services.

Leila Banihani, vice president of operations at CMC Energy Services, a Pennsylvania clean energy efficiency contractor, said her company has seen the program up close for 15 years. She said utilities are a “trusted source” for the customer and are the best suited to provide advice on how to save energy and money.

“Having the utilities administer the comfort partners program will help create a seamless process for New Jersey customers. The utility and its representatives are in the best position to ensure that each customer maximizes the energy efficiency benefits that are available,” she said, and added that “having the utilities administer the comfort partners program would encourage efficiencies that could stretch the available funding to serve more customers in need.”

But Mamie Purnell, an attorney with the New Jersey Division of Rate Council, suggested that putting utilities in charge could have a negative impact on program costs that fall on ratepayers.

“With that move, the board will retain less control over the budget and the program,” Purnell said. “Additionally, it is unclear whether this move will allow greater coordination with other New Jersey agencies that coordinate health and safety measures that often must be performed prior to weatherization for participants under this program.”

Richard Henning, CEO of the New Jersey Utilities Association, argued that utilities would be able to provide quality service to low- and moderate-income customers.

“Utility management of comfort partners program will allow the utilities to streamline customer entry to the energy efficiency programs,” he said. Such a setup, he said, would “also assist customers in finding the best lowest cost opportunity that they’re eligible for, which will assist in removing barriers to the energy efficiency programs.”

Protecting Ratepayers

The triennium proposal is part of New Jersey’s effort to reach 100% clean energy by 2050. The proposal seeks to create the most effective way to deliver the kind of energy efficiency and peak demand programs that the BPU and other stakeholders consider to be essential for the state to reach its emissions reduction goals.

A third public hearing on the issue was postponed while the agency evaluates the issues raised in the initial hearings and opinions submitted online and prepares answers to the questions raised.

The proposal would require electric and gas utilities to create “demand response” programs that would allow them to manage customer energy usage during periods of high demand, and it also encourages utilities’ “advanced metering infrastructure to the extent possible.” To ensure that elements of the proposal are carried out as planned and are effective, the draft calls for the creation of an Evaluation, Verification and Measurement work group.

Purnell urged the BPU to put more specific measures in the program rules to hold down costs, noting that the cost of the program and an additional 9.6% paid to the utilities is footed by ratepayers.

“Rate counsel believes that the board should in fact mandate rate caps for the cost of the energy efficiency programs,” she said. “The language in the straw, calling for financial discipline for the utilities, is too ambiguous to ensure compliance. In the wake of our current economic state of inflation and rising consumer costs, we urge the board to set guardrails for the utilities that will balance ratepayer costs with the energy efficiency goals of the program.”

Educating Consumers

Other speakers focused on how to create greater impact with the program. Randy Solomon, executive director of Sustainable Jersey and the Sustainability Institute at the College of New Jersey, said he saw figures that show less than 10% of residents eligible to benefit from the program actually do so. One way to improve penetration would be to enlist the help of municipal governments in promoting residential and the “small commercial” programs, he said.

“If you get a letter from your mayor, or from your town, you’re going to open it” and not throw it in the trash as may happen with other types of mail, he said.

Pat Miller, co-founder of building electrification advocacy group NJ 50 x 30 BE Team, said the triennium plan should provide greater education to consumers on the “advantages of electric heat pumps for space heating and cooling” because awareness of the equipment is so low.

“Education and incentives are the biggest factors that these programs must provide in our opinion,” she said. “The funding must be sufficient, both to incentivize consumers to take efficiency and electrification steps and to fund the work necessary for the utilities to run the programs.”

New Jersey incentives for installing a heat pump, for example, are much smaller than those offered by Maine, Massachusetts and New York, she said, adding that “it must be made easier for consumers to choose an electric appliance.”

Jennifer M. McCave, an attorney for Google Nest, encouraged the BPU to include “demand response” programs in the straw proposal, and consider the role of smart thermostats in the initiative. The reason, she said, is that the advanced metering infrastructure (AMI) cited as important in the proposal may take a while to become available.

“In light of the fact that the rollout of AMI meters is likely to take … at least another two or three years to be completed, it is very important to note that demand response programs can be accomplished using smart thermostats without AMI meters,” she said. “And therefore we shouldn’t wait for the complete rollout of AMI to launch demand response programs.”

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NY Steps Up Planning for Medium- and Heavy-duty EVs

New York is laying the groundwork to develop the charging infrastructure needed for the larger electric vehicles intended to replace internal combustion trucks and buses on the state’s roads.

The state’s Public Service Commission on Thursday began a proceeding (Case 23-E-0070) that will examine the needs of medium- and heavy-duty (MHD) electric vehicles. Most of PSC’s efforts to date have centered on the light-duty passenger vehicles that account for most of the EVs on the road today.

The proceeding also will try to develop proactive planning approaches to prepare the grid for the demands of charging these larger vehicles. Stakeholder input will help focus the proceeding, the PSC said, but regardless of the final details, it expects to prioritize development in disadvantaged communities that bear the burden of air pollution from diesel-powered trucks and buses.

About 28% of New York’s greenhouse gas emissions are attributed to transportation, the PSC said. The nearly 550,000 trucks and buses registered in the state account for a disproportionately large share of transportation emissions.

But electrifying those vehicles at a fleet scale will require vast amounts of electricity: A single busy highway truck stop would draw as many megawatts as an entire town or a professional sports stadium, by some estimates. (See Study Projects Power Demands of Highway EV Charging Network.)

The challenge in the new proceeding is to anticipate the location and size of the charging facilities and put in place the grid infrastructure to serve them before they begin to strain system capacity.

Case 20-E-0197, in which PSC ordered utilities to proactively plan for the transmission and distribution needs of renewable energy, has a similar goal at the other end of the grid.

PSC Chair Rory Christian noted a kind of circularity in Thursday’s meeting agenda, at which the commissioners unanimously approved construction of an $810 million energy hub in an area of New York City where power demand is expected to ramp up sharply, in part because of EV charging.

The MHD planning effort, he said, will continue that trend with “the goal of making sure that the efforts we put forth are supporting rather than hindering adoption of EVs and the deployment of charging stations throughout the state.”

That order was approved unanimously.

A list of 16 questions is included to guide stakeholder input toward key topics. Responses are due by May 22, and replies to those responses are due by June 25. Based on the input, Department of Public Service staff will prepare a white paper for recommendations for the PSC to consider as it moves the proceeding forward.

The PSC followed a similar path with the make-ready program that focused on light-duty EVs, in Case 18-E-0138, which is now undergoing midpoint review and revisions.

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Environmental Justice Issues on 2 LNG Facilities Split FERC Dems

The fate of two LNG developments in Texas that had their approvals remanded to FERC drew out some disagreements among the regulators’ two Democrats in orders posted Friday.

A three-vote majority during FERC’s monthly open meeting Thursday approved the Rio Grande LNG (CP16-454, et al.) and the Texas LNG Brownsville (CP16-116-002) projects to move ahead after the commission conducted some additional analysis on their impacts on local environmental justice communities. Both projects are being built close to each other along the Brownsville Shipping Channel, which is on the southern edge of Texas’ Gulf Coast.

The D.C. Circuit Court of Appeals had remanded FERC’s approvals of the projects in August 2021 in the case Vecinos Para El Bienestar de la Communidad Costera et al. vs FERC. The court directed the commission to do a better job justifying its determinations of public interest and convenience in the two cases.

The Rio Grande LNG is being developed by NextDecade, while Glenfarne Energy Transition is building the Texas LNG project. The Rio Grande facility is expected to go online in 2026 and Texas LNG the year after that.

Chair Willie Phillips filed concurrences to the two orders, saying that FERC adequately responded to the issues on remand by including the projects’ social costs of carbon and broadening the examination of environmental justice communities to those located within 50 km of either of the two power plants.

“While I recognize that certain of my colleagues would have preferred more process or less, I believe that the record assembled throughout the last year is an appropriate middle ground that represents an adequate basis to fully consider the issues the court remanded to us in Vecinos nearly two years ago,” Phillips wrote.

Despite expanding the EJ scope to communities within 50 km of the site instead of just 2 miles, FERC continued to find that neither project would have any significant impacts.

One area where FERC did make some changes was to require both projects to take additional steps after they start partial operations but are still under construction to avoid exceeding National Ambient Air Quality Standards, as two emissions-generating activities would be occurring at the same time.

That mitigation shows how FERC is starting to focus on a complaint it heard at its recent Environmental Justice Roundtable about cumulative impacts of projects, Phillips said. (See FERC Gets Advice, Criticism on Environmental Justice.)

“We heard from several stakeholders, including community groups, about the importance of considering cumulative impacts — i.e., not just the air emissions directly caused by a particular project, but also those emissions in conjunction with the emissions from other sources within the region,” Phillips wrote. “Today’s order takes a critical step toward addressing that concern by requiring that the project sponsors develop a plan to ensure that incremental emissions impacts associated with these projects, on top of all sources, do not cause a NAAQS exceedance, thereby helping to protect communities, including environmental justice communities, that may venture near the projects.”

Commissioner Allison Clements dissented on the orders, saying that FERC should have done supplemental environmental impact statements. Failing to do so renders the orders’ significance determinations unsupportable, she argued. The commission also should have held public meetings to address the projects’ environmental and other impacts.

Expanding the EJ scope identified hundreds of additional communities that never had a proper chance to weigh in on the project, warranting a new EIS, she said.

“The order imposes a new air pollution and monitoring condition that may prevent or reduce NAAQS violations,” she said in each of the orders. “Although I agree that imposing this condition is a beneficial step to take, I cannot conclude that it will be sufficient to reduce cumulative air emissions to an insignificant level because the condition itself is vague, and we have had no public comment on whether it will be effective or what additional mitigation may be needed.”

Clements also argued that FERC was missing a chance to implement its stated intentions from the recent Environmental Justice Roundtable.

“Considering our discussion at the roundtable of how to facilitate EJ communities’ full participation, it is especially disheartening that the order rejects requests to hold public meetings, with Spanish translation, to hear communities’ concerns about the project and our new analyses,” Clements said.

Clements also disagreed with the majority’s explanation for why FERC is not determining the significance of greenhouse emissions associated with the two projects.

The commission included social costs of carbon for the projects, but it said that tool was not designed to measure the impacts of individual projects, so it could not determine whether the emissions associated with the two LNG facilities are significant.

“I do not know whether the social cost of GHGs protocol or another tool can or should be used to determine significance,” Clements wrote. “That is because the commission has not seriously studied the answer to that question. The majority has simply decided the method does not work, with no explanation of why the commission departs from the approach so recently taken in other certificate orders.”

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NYISO Operating Committee Briefs: April 20, 2023

[EDITOR’S NOTE: This article has been corrected to report that NYISO said that new transmission into the Southeastern New York reserve region, not New York City, had increased capacity margins for capacity Zone J (NYC).]

Summer 2023 Capacity Assessment

NYISO on Thursday updated the Operating Committee about forecasted summer conditions, assessing that while it has enough capacity for this summer and the near future, margins are declining over time as the grid transitions to clean energy.

Under its baseline forecasted conditions, the ISO will have about 1,400 MW of surplus capacity. In the event of extreme conditions that would decrease that margin as low as ‑2,300 MW, the ISO is covered by up to 3,100 MW of emergency operating actions.

NYISO is currently conducting site visits to assess readiness for summer conditions and ensure potential outages coordinated with ISO staff to minimize any reliability impacts, said Aaron Markham, vice president of operations.

The ISO expects 652.3 MW of generation to be deactivated by July 1, mostly in Zone J (New York City) as a result of New York state’s peaker rule. About 940 MW of new wind and solar generation is expected to come online throughout the summer. Markham also said that new transmission into the Southeastern New York reserve region
resulted in increased margins for the zone.

March Operations Report

NYISO informed the OC that March was a “pretty quiet month.”

The grid experienced a peak load of 19,881 MW on March 14, which Markham said was “quite a bit lower than the capability period peak.” There were no high-level curtailments.

Installed behind-the-meter solar also “keeps ratcheting up,” according to NYISO, with 84 MW added since the last OC meeting.

Inverter-based Resources Standard

The New York State Reliability Council (NYSRC) briefed the OC about a proposed rule establishing minimum requirements for inverter-based resources (IBRs) over 20 MW.

The NYSRC said their draft rule, PRR-151, is necessary because more IBRs have sought interconnection in New York and recent problems seen in other RTOs show that without sufficient regulatory guidance, these resources can have outsized negative impacts across the grid when not performing properly. (See New York Considering Standards for IBRs.)

It asked that comments and questions be sent to herb@poweradvisorsllc.com by this Thursday.

Renewable Regulation Requirements

The committee approved NYISO’s proposed updates to the regulation requirements for renewable resources and their proposed implementation timelines.

Renewable Resources Regulation Requirements (NYISO) Content.jpg

Current and proposed regulation requirements for renewable resources

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NYISO

 

The ISO said the updated requirements will help balance bulk power concerns as net load grows and intermittent resources increasingly make up most of the state’s energy mix. (See related story, “Renewable Regulation Requirements,” NYISO Seeking to Increase Emissions Transparency.)

The first set of new regulation requirements, Scenario 1, will be implemented on June 1, and the second set, Scenario 2, will be effective June 1, 2025.

NYISO promised to update its presentation to specify Scenario 2’s implementation date and to provide stakeholders with advanced notices should timelines change.

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DOE Ramps up Support for LMI Community Solar

WASHINGTON ― With the largest community solar project in the nation’s capital as a backdrop, Energy Secretary Jennifer Granholm on Thursday announced new funding opportunities and projects aimed at expanding access to solar for low- and moderate-income (LMI) consumers and communities.

At 1.8 MW, the D.C. Water Brentwood Reservoir Community Solar Project sits on top of a capped reservoir and, when it comes online in June, should cut electric bills in half for 500 low- and moderate-income households in D.C and support the construction of more affordable housing in the city.

Granholm called it a “dazzling success” that the U.S. Department of Energy wants to replicate all over the country through programs like the Community Power Accelerator Prize, which aims to build out a network of community solar developers. DOE on Thursday named the first 25 teams that will compete for a chance to tap into $5 billion in project financing.

The teams are located in 16 states, D.C. and Puerto Rico. Together, they have the potential to put up to 150 MW of new community solar online, Granholm said. In the initial round of funding, each team receives $50,000, according to DOE.

In subsequent rounds, the teams will compete for prizes of $200,000 and $150,000, DOE said. The program is part of the department’s larger Community Solar Partnership, which has set a target of deploying an estimated 17 GW of community solar projects across the U.S. by 2025, enough to provide a total of $1 billion in savings.

Thursday’s announcement was the latest in the Biden administration’s efforts to show its commitment to an equitable and just transition to clean energy, with 40% of the benefits of federal funds going to low-income and disadvantaged communities. (See IRA Tax Credits Draw Clean Energy Projects to Coal Communities.)

The Brentwood project “is proof that that’s not just a pie-in-the-sky concept,” said National Climate Advisor Ali Zaidi, who joined Granholm at the event. “It’s not a plan on a piece of paper. This is steel in the ground. It’s a real project. It’s going to make a real, visible difference in the lives of people who live in this community, in the bottom lines of families around the kitchen table.”

Solar for All

Community solar projects were initially developed as an alternative to rooftop solar, providing access to clean energy for apartment dwellers or anyone who couldn’t or didn’t want to put panels on their roofs. Early projects offered consumers options to either buy one or more panels or specific blocks of power — 100 kWh/month, for example — and receive a credit for that power on their electric bills.

D.C.’s Brentwood Reservoir project is part of the city’s Solar for All program, which has the ambitious goal of cutting electric bills in half for 100,000 low-income households in the city by 2032. Rather than buying panels or blocks of power, subscribers to a project simply receive a credit of up to 50% on their electric bills, and projects often provide other “community benefits.”

For example, during the COVID-19 pandemic, some of the proceeds from a project built in 2020 on the roofs of five buildings at George Washington University were channeled into an emergency fund to help low-income residents at risk of power shutoffs.

To date, Solar for All has helped to complete 207 community solar projects — called community renewable energy facilities (CREFs) — totaling 29.3 MW of power, according to the D.C. Sustainable Energy Utility (DCSEU), which administers the program.

DOE also recognized the program with one of its first rounds of Sunny Awards for Equitable Community Solar, announced in January. The program received a $10,000 cash prize as part of its award, which has been “redirected back to nonprofits in the city,” said Richard Jackson, interim director of the D.C. Department of Energy and Environment.

EPA is hoping to replicate D.C.’s success with its own federal Solar for All program, funded with $7 billion from the Inflation Reduction Act. Deputy Administrator Janet McCabe was also on hand Thursday to announce the release of her agency’s implementation plan for the program, which is part of the larger $27 billion Greenhouse Gas Reduction Fund.

“We’re going to be able to provide grants to 60 grassroots [groups], tribal governments, municipalities and other recipients to expand the number of low-income and disadvantaged that are primed for investment in residential and community solar,” McCabe said.

The implementation plan says at least one award will go to each state and territory, with one to three grants reserved for tribal groups and governments. The plan does not include specific award amounts but said grants would be “based on program need and vision including geographic factors, solar deployment potential factors, program design components and impacts, and other merit-based factors.”

LPO’s VPP Loan

DOE’s Loan Program Office (LPO) added another announcement to the list on Thursday, with a conditional commitment for a $3 billion loan to Sunnova Energy for a company initiative to install rooftop solar and storage systems for low-income homeowners or those with low credit scores.

If finalized, the money will be used to provide loans for solar-plus-storage systems for approximately 75,000 to 115,000 homeowners throughout the U.S. and its territories, the LPO announcement said. Over the next 25 years, the project could install an estimated 568 MW of solar, while avoiding 7.1 million metric tons of carbon dioxide.

The Sunnova systems also come with “virtual power plant-ready” software that can “give customers insight into their household’s energy usage and greenhouse gas emissions, allowing customers to reduce electricity use — or even contribute electricity to the system in markets that allow such contributions — when the grid is under stress,” according to the LPO announcement.

Dan DeSnyder, Sunnova’s vice president for capital markets, described the software as “a Fitbit” for energy, encouraging consumers to use energy more efficiently and during off-peak hours when rates are lower.

The DOE loan could help the company be a bridge to build out a market for solar projects in low-income communities “by demonstrating to the rating agencies that these people pay their bills, and it can be a benefit,” DeSnyder said. “We think that we’re going to be able to drive more activity in the space for these people.”

The loan would be LPO’s first in support of virtual power plants, which combine smart software with aggregated distributed energy resources.

Announcing the conditional commitment on LinkedIn, LPO Director Jigar Shah said the loan is intended “to induce two key behavioral changes in the current residential appliance market: the inclusion of virtual power plant technologies to unlock demand shifting as a tool to reduce electricity bills across the United States; and to expand the availability for all households to access affordable financing for residential energy equipment so that Americans don’t have to pay 30% interest for capital improvements and appliance replacements [that] will lower their energy burden.”

Solar Innovation

Granholm’s other announcements focused more on promoting innovative solar technologies and their integration into the nation’s power systems, while building out U.S. solar supply chains.

According to DOE, $52 million will go to “research, development and demonstration projects [that] aim to enhance domestic solar manufacturing, support the recycling of solar panels and develop new American-made solar technologies.”

Among the 19 projects receiving these funds are:

  • Solarcycle of Oakland, Calif., which will receive $1.5 million to develop technologies that can “recover key materials from end-of-life solar panels with high purity by developing a mechanical method to concentrate the materials, followed by an environmentally friendly chemical process to recover them.”
  • First Solar of Perrysburg, Ohio, receiving $7.3 million to develop a tandem module combining thin-film and silicon to create “a new residential rooftop product that is more efficient than silicon or thin-film modules on the market today.”
  • Mission Drives of Potsdam, N.Y., which is receiving $1.2 million to develop an inverter that can “switch electricity input 100 times faster than conventional products using silicon carbide and gallium nitride wide bandgap components.”

The other $30 million will be awarded through the new Operation and Planning Tools for Inverter-Based Resource Management and Availability for Future Power Systems (OPTIMA) program.

According to DOE, the program will target “projects that address emerging challenges and opportunities for grid planning and operation engineers and technicians arising from the power system’s transition to variable renewable energy sources and inverter-based power electronic grid interfaces.”

The department expects it will fund between nine and 13 projects, with awards ranging from $2 million to $4 million.

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PJM MRC Preview: April 26, 2023

Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee on Wednesday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

Consent Agenda (9:05-9:15)

B. The committee will be asked to endorse proposed revisions to Manuals 1, 13 and 36 associated with future energy management system (EMS) updates and to meet NERC certification requirements.

Endorsements (9:15-10:50)

3. Manual 11 Revisions (9:15-9:40)

PJM’s Joey Tutino will present proposed revisions to Manual 11: Energy & Ancillary Services Market Operations as part of a periodic review. The committee will be asked to endorse the revisions.

4. Renewable Dispatch (9:40-10:05)

PJM’s Darrell Frogg will review a proposal on renewable dispatch, which aims to increase visibility on what the relevant resources can be dispatched down to. (See “PJM, Monitor Present Renewable Dispatch Proposal,” PJM MRC/MC Briefs: March. 22, 2023.)

Issue Tracking: Renewable Dispatch

5. Capacity Performance (CP) Penalties (10:05-10:50)

A. Tom Hoatson of LS Power will present a problem statement, issue charge and solution that would modify when generators are subject to Capacity Performance penalties and how much they could owe.

B. Lynn Horning of American Municipal Power will present an alternate solution that would use the locational deliverability area clearing price under the Base Residual Auction to calculate penalties in lieu of the net cost of new entry.

C. Independent Market Monitor Joseph Bowring will present an alternate issue charge and solution that would link penalties to BRA clearing prices.

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FERC Tells PacifiCorp to Fix its Tx Rate Protocols

Aspects of PacifiCorp’s (NYSE:BRK.A) transmission formula rate protocols limit transparency and the ability of interested parties to obtain information, FERC said Thursday in its latest ruling on last year’s show-cause orders for five Western utilities to correct deficiencies (EL22-38).

Formula rate protocols provide customers and regulators with the ability to review and challenge formula rates for transmission service. In PacifiCorp’s case, FERC found its protocols failed to adequately define the term “interested party,” which partly determines who can participate in the formula rate information exchange.

“Without such a definition, PacifiCorp’s formula rate protocols may not provide sufficient clarity and may provide PacifiCorp with the discretion to determine who is an interested party, and therefore appear to be unjust and unreasonable,” FERC said in April 2022. It ordered PacifiCorp to justify its protocols or explain how it can alleviate the commission’s concerns. (See FERC Opens Probes on Western Tx Rate Protocols.)

The commission also found a lack of transparency in the utility’s protocols because they do not “do not require PacifiCorp to make a posting of the docket number assigned to its informational filing on its website.”

PacifiCorp challenged both assertions. It argued that its protocols “contain a clear definition of ‘interested party’ because the preamble to the protocols states that ‘interested party’ means ‘a transmission customer of PacifiCorp, a state commission in a state where PacifiCorp serves retail customers, any entity having standing in a [FERC] proceeding investigating the formula rate … and [FERC] staff.’”

FERC said that was insufficient. “The definition is limited to only those entities listed and also fails to include entities such as consumer advocacy agencies and state attorneys general,” it said.

PacifiCorp also challenged FERC’s finding that the utility’s protocols “do not require [it] to make a posting on its website.” It argued that it posts its annual update on its Open Access Same-time Information System (OASIS) website, pursuant to its protocols, which require the utility to put its annual update “in an accessible location” on its OASIS site.

FERC said that too was not enough. The utility’s protocols must contain a specific provision for “posting on its website.”

“Lacking such a provision is inconsistent with [an order in which] the commission directed MISO to provide notification of its informational filing through the email ‘exploder’ list to be maintained by MISO, and by posting the docket number assigned to each transmission owner’s informational filing on the MISO website and OASIS within five days of such filing,” FERC said.

“PacifiCorp’s protocols do not contain a provision that requires PacifiCorp to post the docket number assigned to its informational filing on both PacifiCorp’s website and OASIS within five days of such filing,” the commission continued. “We find that posting the docket number assigned to PacifiCorp’s informational filing on PacifiCorp’s website, in addition to its OASIS site, is necessary to provide transparent access to the informational filing to interested parties that may not be familiar with PacifiCorp’s OASIS site.”

FERC ordered PacifiCorp to file a compliance filing within 30 days with proposed tariff revisions to rectify the shortcomings.

The four other utilities named in last year’s compliance filings were Idaho Power, Public Service Company of Colorado, Public Service Company of New Mexico and Puget Sound Energy. FERC accepted tariff revisions from Idaho Power, PSCo and PSE, subject to further compliance filings, and concluded its proceedings against PNM. (See PSCo, Idaho Power Comply with Show-cause Order.)

The five cases are the latest in a series of numerous proceedings that FERC has initiated to investigate formula rate protocols since 2012, when it ordered MISO transmission owners to “file revisions to their formula rate protocols regarding the following areas of concern: the scope of participation (i.e., who can participate in the information exchange); the transparency of the information exchange (i.e., what information is exchanged); and the ability of customers to challenge transmission owners’ implementation of the formula rate as a result of the information exchange (i.e., how the parties may resolve their potential disputes).”

The commission has repeatedly stressed the importance of ensuring the formula rate protocols meet those standards.

“The commission permits transmission service rates to be established through formulas,” FERC explained in its April 2022 show-cause order to PacifiCorp. “Under a formula rate, the formula itself is the rate, not the particular components of the formula.”

TOs adjust the formula inputs yearly, requiring “safeguards … to ensure that the input data is correct; that calculations are performed consistent with the formula; that the costs to be recovered in the formula rate are reasonable and were prudently incurred; and that the resulting rates are just and reasonable,” FERC said in the show-cause order.

Formula rate protocols “provide transmission customers with specific procedures for reviewing and challenging rates,” the commission said. “In order to fulfill this purpose, formula rate protocols must afford adequate transparency to affected customers, state regulators or other interested parties, as well as provide mechanisms for resolving potential disputes. Formula rate protocols therefore play an important role in ensuring just and reasonable rates.”

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FERC Denies Rehearing of Tenaska Curtailment Complaint

FERC on Thursday denied Tenaska’s rehearing request over the alleged curtailment of its Clear Creek Wind Farm, maintaining that the company did not provide sufficient evidence (EL22-59).

Tenaska alleged that SPP, MISO, Associated Electric Cooperative Inc. (AECI) and the Tennessee Valley Authority adopted operating guides that resulted in unduly discriminatory curtailment of the Missouri wind farm it owns and operates. FERC disagreed, denying the complaint in December. (See FERC Denies Tenaska’s Complaints over Wind Curtailments.)

The developer argued that FERC lacked substantial evidence to conclude that the operating guides limit the wind farm pending network upgrades assigned to Tenaska. It said the commission’s conclusion was a “post hoc rationalization” and asserted that the order was an unexplained departure from precedent, relying on SPP and AECI documents as supporting the operating guides.

FERC said that it was not persuaded by Tenaska’s argument, saying it was up to the complainant to present evidence supporting its assertions that the curtailments were unjust and unreasonable, unduly discriminatory or preferential, or inconsistent with the operators’ tariffs. It pointed out that SPP and AECI said the curtailments were consistent with congestion requiring network upgrades assigned to Tenaska and the reason behind the project’s limited operation status.

Tenaska’s argument that the original order was inconsistent with precedent was “misplaced,” the commission said. It said Tenaska’s reliance on Iberdrola v. Bonneville overlooked the fact that the curtailed wind generators in that proceeding “were not responsible for incomplete network upgrades.”

The commission found the project’s curtailments after the required upgrades were identified in an SPP restudy were consistent with the RTO’s generator interconnection procedure (GIP) and not unduly discriminatory.

“Adopting Tenaska’s position would be inconsistent with the structure set forth in the text of SPP’s GIP … and the purposes underlying that provision,” FERC wrote.

The commission said if Tenaska believed that FERC erred because there were curtailments prior to a subsequent restudy that was not justified, it was incumbent on the developer to identify the relevant curtailments and demonstrate that alleged error. “It did not do so,” the commission said.

Facilities Agreements Approved, Rejected

The commission on Tuesday accepted SPP’s unexecuted facilities service agreement (FSA) that the grid operator filed for a 102.6-MW wind farm in West Texas (ER23-342).

SPP, the transmission provider, filed the generator interconnection agreement last year on behalf of transmission owner Southwestern Public Service (NASDAQ:XEL) and interconnection customer Panhandle Solar.

Panhandle protested the GIA’s 20-year term, saying it had proposed a three-year term that SPP rejected. It said that when an interconnection customer is willing to pay the money back faster, a longer term imposes added and unwanted financing costs that are not just and reasonable and merely serve to enrich the interconnecting TO’s shareholders. Panhandle said the 20-year FSA would double the overall amount it paid for the network upgrades under the GIA.

The commission found that the 20-year term was consistent with MISO’s pro forma FSA that FERC had previously approved as just and reasonable. It said that 20 years allow SPS to recover its return of and on capital invested in network upgrades based on the term over which the utility will likely provide interconnection service to Panhandle. It also gives Panhandle a shorter period to pay depreciation expenses than the recovery period based on useful service life, FERC said.

“We find it reasonable to expect interconnection service under the Panhandle GIA to match or exceed 20 years,” the commission said.

FERC noted that Panhandle acknowledged that the “initial terms of GIAs often do extend 20 years … based on how long the generating facility in question is expected to operate.” They pointed out that Panhandle had not expressed any intention to take interconnection service only over the GIA’s initial 10-year term.

FERC also on Tuesday rejected an FSA filed by SPP last year, this one for TO ITC Great Plains and interconnection customer Pixley Solar Energy (ER23-155).

The commission found the agreement to be unjust, unreasonable and unduly discriminatory or preferential. It disagreed with ITC’s assertion that the Mobile-Sierra doctrine, which mandates respect for private contracts by shielding them from regulatory interference except when necessary in the public interest, applied to the FSA as executed.

FERC said the ordinary just-and-reasonable standard applies when the parties “explicitly reserve their rights to seek modifications to their contracts,” indicating that they “specifically negotiated and contemplated that their contracts could be modified” based upon the ordinary J&R standard.

“Those findings apply here,” the commission said, pointing to the FSA’s language that states “nothing in this service agreement shall limit the rights of the parties or of FERC under Sections 205 and 206 of the [Federal Power Act] and FERC’s rules and regulations thereunder.”

The commission also said ITC’s recovery of additional expenses that included an allocated portion of its operations and maintenance expenses was not justified and that certain references and calculations in the formula rate lacked transparency and were inaccurate.

FERC rejected the FSA without prejudice, offering guidance to SPP and ITC in refiling the agreement.

Commissioner James Danly dissented, saying the other three commissioners failed to recognize and address the fact that under FERC’s “fairly recent precedent, system protection facilities may be network upgrades” in the SPP footprint.

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ISO-NE Planners Outline Potential Solutions for 2050 Tx Overloads

ISO-NE is studying line upgrades and new 345-kV and HVDC lines to address expected reliability violations in its 2050 Transmission Study.

Associate engineer Reid Collins briefed the Planning Advisory Committee April 20 on potential solutions for transmission overloads in Vermont and on north-south lines leading to Boston.

The 2050 Transmission Study, which resulted from a recommendation from the New England States Committee on Electricity’s October 2020 “New England States’ Vision for a Clean, Affordable, and Reliable 21st Century Regional Electric Grid,” will identify transmission needs required to satisfy NERC, Northeast Power Coordinating Council and ISO-NE reliability criteria in 2035, 2040 and 2050. (See States Demand ‘Central Role’ in ISO-NE Market Design.)

The RTO presented an initial round of proposed solutions in Boston and southwest Connecticut in December 2022.

Planners are primarily seeking solutions for scenarios that include a 2050 winter peak load of 51 GW. Some parts of those fixes also are expected to address needs in 2035 and 2040. The RTO is also considering additional solutions for a “high winter” 2050 peak of 57 GW.

Vermont Solutions

Planners are looking at three potential solutions for overloads resulting from large power transfers towards the Burlington area in northwestern Vermont.

Although many of the overloads can be resolved by rebuilding overhead lines, several underground or underwater sections would be very costly or difficult to rebuild, such as the PV-20 115-kV line running under Lake Champlain to Plattsburgh, New York, which cannot be fixed with the equipment that currently controls its flows.

The potential solutions are:

  • Upgrade the PV-20 line from New York from 115 kV to 230 kV and build a new 115-kV line parallel to line K43.  The underground and underwater segments of PV-20 are already built for 230 kV; only overhead segments would need to be upgraded. Collins said this would likely be the cheapest solution — involving the fewest miles — and could improve NYISO-ISO-NE transfer capability, reducing resource curtailments in northern New York. But it would be complicated by requiring construction in New York.
  • Build a new 345-kV line from Coolidge to Essex, which would limit construction to New England and avoid many overhead rebuilds and the most difficult underground rebuilds. However, it would involve significantly more new construction than other solutions, at a higher cost, even though much of the new transmission could follow existing rights-of-way.
  • Build a new 345-kV line from New Haven to Essex and a new 230-kV line from Granite to Essex. It would avoid many overhead rebuilds and most underground rebuilds and be limited to New England while requiring less new transmission construction than the Coolidge-Essex solution. But it would require the addition of two new transformers, rather than one, at Essex. It also would limit the use of the Granite 115-kV PARs to control flow on the existing 230-kV lines in Vermont and New Hampshire.

North-South Solutions

Many of the major lines running from Maine and New Hampshire into Massachusetts face overloads from excess generation in the north and large loads in southern New England.

In the primary solution set, and in the 2035 and 2040 solution subset, all the overloads can be fixed with rebuilds. In the 57 GW scenario, many of the overloads would be too severe to be addressed by rebuilding.

The potential solutions include:

  • Re-route lines 375 and 3038 to avoid Surowiec and go straight from Maine Yankee to Buxton with a new 345-kV line for Surowiec-Timber Swamp-Ward Hill. A second 345-kV line for Timber Swamp-Ward Hill might be needed to fix the high winter scenario. In addition to reducing the need for rebuilds on existing lines, the new 345-kV line across major interfaces should improve voltage and stability performance. However, right-of-way (ROW) for some segments of the project would be cramped, and it would result in increased reliance on a single 345-kV ROW for moving power north to south.
  • Add an HVDC line between the Surowiec 345-kV line and the Mystic 345-kV line. The solution also requires re-routing of lines 375 and 3038 to form a new Maine Yankee-Buxton 345-kV AC line. It would resolve many of the north-south transfer and Boston import issues while avoiding increased reliance on a single 345-kV ROW. This solution, combined with several 345-kV line rebuilds would solve north-south overloads as well as most Boston overloads in the primary solution set as well as the 2035 and 2040 solution subset. But additional solutions — possibly multiple point-to-point or offshore network HVDC lines — will be needed to meet the high winter peak for 2050.
  • HVDC lines between Orrington or Surowiec, Maine, and Ludlow or Manchester, Vermont also are being tested to address north-south and east-west constraints in the high winter scenario. Although it would fix “significant numbers” of north-south overloads, it would not solve the Boston import issues, and the lengthy line could be expensive and difficult to site.

Boston Import Solutions

Boston is expected to experience import constraints during high flows into the area under both summer and winter peaks. Each season and each year studied found underground violations in at least some scenarios.

Planners project more overloads for the 2040 winter peak than for 2050 because the growth in wind injections into Boston will outpace the increased load.

Among the options being considered are:

  • Building an HVDC line from Ward Hill to Mystic, which would significantly reduce the number of overloaded underground elements in Boston without needing to upgrade them directly. It would avoid possible short-circuit impacts of new 345-kV AC lines. But it could be “quite expensive,” the ISO said, and finding space for HVDC converter stations near Ward Hill and Mystic could be difficult.
  • Adding a 345-kV AC line from Ward Hill-Wakefield Junction-Mystic could be cheaper than the HVDC option but it would be less effective at solving underground overloads in Boston.

To fix overloads on lines serving Boston from the south, planners are considering adding series reactors on the two existing Stoughton-K Street cables or adding a third Stoughton-K Street line, which would be more effective but also more expensive.

HVDC Line Configurations

The 2050 Transmission Study also is considering multiple options for HVDC lines, some with a point-to-point configuration (e.g., Surowiec-Mystic). “Others are implied through wind injections modeled as large generators at transmission-level buses,” the RTO said. Although the study is considering the lines individually, “it is also possible that these lines could be connected together to form an offshore grid,” the RTO added.

ISO-NE has hired Electrical Consultants Inc. to develop detailed cost estimates for some of the complex solutions. The RTO told ECI to avoid creating double-circuit towers, especially on the 345-kV network. The RTO also requested undergrounding lines as needed to avoid using eminent domain or displacing residents. It hopes to ease siting by placing new overhead lines along existing highway and railroad corridors.

“Detailed cost estimates will help to inform the region on both the costs and physical impacts of the projects examined,” the RTO said.

Next Steps

The RTO asked for feedback on the 2050 study presentation by May 5, with submissions to pacmatters@iso-ne.com.

Solution development work will continue through the end of this year in parallel with ECI’s cost estimates. The RTO’s next presentation will be in late summer or early fall, and a draft 2050 Transmission Study report is scheduled for release in November.

Asset Condition Projects

Also at the PAC meeting, National Grid (NYSE:NGG), Eversource Energy (NYSE:ES) and Vermont Electric Power Co. (VELCO) outlined plans to spend a combined $169 million on transmission line refurbishments:  

Damaged wood utility pole (National Grid) FI.jpgNational Grid plans to spend an estimated $138 million to replace 178 wood structures with new steel structures on its 115-kV transmission line between the Harriman #8 substation in Readsboro, Vt. and the Adams #21 substation in Adams, Mass., including this damaged wood utility pole. | National Grid
  • National Grid estimates it will spend $138.3 million on its 12-mile E-131 115-kV line between the Harriman #8 substation in Readsboro, Vermont, and the Adams #21 substation in Adams, Massachusetts, in an area with steep terrain. Constructed in 1925 and updated in 1971, it includes 209 structures, including a tap to the Bear Swamp substation. The company will install new steel structures to replace three lattice towers and almost 200 wood structures that showed signs of top splitting and woodpecker damage. The project, which will also include access road improvements, has an estimated in-service date in the third quarter of 2027.
  • Eversource will replace wood structures with light-duty steel poles on a 5.4-mile section of 115-kV lines 1132 and 1505 on a shared right-of-way between Canterbury Switchyard and Killingly Station and the Brooklyn Tap in Connecticut. “If you replace [some structures] with wood, the woodpeckers will just find the next piece of wood out there,” said Eversource’s Chris Soderman. The estimated cost is $13.4 million, and the proposed in-service date is the first quarter of 2024.
  • VELCO will replace 105 of 245 wood H-frame structures, most with steel H-frames, on its K43 115-kV line from Williston to New Haven. The 21-mile line was built in 1954 and originally operated at 69 kV. The cost is estimated at $16.9 million, and the company is targeting a 2026 completion.