Solar farms are set to proliferate in a sun-soaked county in central Washington.
In May, a Yakima County Planning Division hearing examiner approved a conditional use permit for the 94-MW Black Rock Solar project, which will be able to power about 20,000 homes at full output.
Construction of the project is expected to begin in the first half of 2023 and be completed in mid- to late 2024, Brandon Reinhardt, development director for BayWa r.e. Americas said in an interview. Reinhardt declined to discuss the project’s budget.
The project is targeted for roughly 1,000 acres in eastern Yakima County, an area that has been attracting several solar ventures. BayWa plans to lease the land from a farmer, and the project’s solar panels will co-mingle with sheep that graze on the grass on the site. That would make the project Washington’s second agrivoltaic site, in which panels are located among crops and lands dedicated to grazing livestock.
The state’s first agrivoltaic projectis scheduled to go online this month on the Colville Indian Reservation north of the Grand Coulee Dam. Two geodesic domes filled with various crops will be located adjacent to solar panels used to power the domes’ heat and water as well as some nearby homes.
At least four solar projects have targeted eastern Yakima County, a dry shrub-steppe area. “It’s essentially the strength of the sunshine,” Reinhardt said.
In December, Gov. Jay Inslee approved the 80-MW Goose Prairie project on 625 acres in eastern Yakima County at the recommendation of the state’s Energy Facilities Siting Evaluation Council (EFSEC).
Two more projects are going through reviews by EFSEC. In April, Cypress Creek Renewables applied to EFSEC for permission to build two 80-MW solar farms — High Top Solar and Ostra Solar — in the same eastern Yakima County region.
In Washington, solar and wind developers have the option of choosing to handle project permitting through either EFSEC or the appropriate county government.
While three of the projects chose the EFSEC route, BayWa wanted to work with the Yakima County government. “We had a supportive county staff. We didn’t feel much in the way of opposition,” Reinhardt said.
MISO stakeholders say the grid operator’s plan to fold a stakeholder group dedicated to loss-of-load estimates into its resource adequacy subcommittee by year’s end will result in papering over a full risk picture.
They said there’s good reason to keep the Loss of Load Expectation Working Group (LOLEWG) because it helps shape the annual LOLE study and the Resource Adequacy Subcommittee (RASC) reviews the results with little opportunity for stakeholder input.
Travis Stewart, representing the Coalition of Midwest Power Producers, said LOLE discussions are “proactive” in the working group and “reactive” in the subcommittee.
“The intention is not to decrease transparency, but this move certainly will,” Stewart said. “Stakeholders are not asking for a yeoman’s work here. We’re really just asking for three to four meetings per year.”
Lynn Hecker, MISO’s senior manager of resource adequacy policy, said there’s substantial overlap of LOLE issues between both groups. She said MISO would be more efficient if it retires the LOLEWG by the end of the year and rolls discussion into RASC meetings, adding that staff already double-posts its study progress to both groups. (See MISO Moves to Disband Stakeholder Loss of Load Group.)
“This is not intended to reduce transparency or discussion by any means,” Hecker told the working group during a teleconference Thursday. She said MISO could schedule additional workshops to tackle the LOLE study’s more technical aspects.
Multiple stakeholders asked that MISO host the LOLEWG for at least another year.
Xcel Energy’s Kari Hassler pointed out that the RTO has already cut the number of RASC meetings from 12 to eight each year and that the meetings frequently run over agenda timeslots. She said she didn’t see how the RASC could take on another working group’s tasks.
“It seems like we have a lot of LOLE issues to address if the [seasonal auction and accreditation] is approved,” she said. “I very much want to maintain the LOLE working group.”
Hecker said staff will collect more stakeholder feedback on retiring the working group over the next two weeks and factor that into a final decision.
The grid operator is morphing its LOLE study into a seasonal calculation that includes four separate planning reserve margin requirements. It’s adding seasonal inputs to its LOLE model for the 2023/24 planning year, assuming FERC approval of seasonal capacity auction and resource-accreditation design proposals.
MISO resource adequacy engineer Darius Monson said staff will now calculate additional cold-weather outages by adding a forced outage adder for extremely cold temperatures. Previous LOLE estimates didn’t include extra generation outages brought on by plummeting temperatures, leading to an undercount of generation outages.
Some stakeholders said it’s still unclear how MISO will crunch LOL estimates to wind up with four separate planning reserve margin requirements.
With its recent capacity auction shortfall, MISO has an annual value of a one-day-in-5.6 years loss-of-load risk instead of its one-day-in-10 years target.
A Pennsylvania judge on Friday blocked Gov. Tom Wolf’s effort to enter the Regional Greenhouse Gas Initiative (RGGI), saying opponents were likely to win their argument that the administration’s plan required legislative approval.
Commonwealth Court Judge Michael Wojcik issued a temporary injunction in response to petitions by the coal industry, operators of the Keystone and Conemaugh plants, and others.
Wolf in 2019 ordered the state’s Department of Environmental Protection (DEP) to develop a rulemaking to enter RGGI, and the Environmental Quality Board (EQB) adopted it in July 2021. But the Republican-dominated Senate and House of Representatives approved resolutions rejecting the rulemaking under the Regulatory Review Act. Their action prompted a veto by Wolf, which the GOP was unable to override.
Opponents — including the Pennsylvania Coal Alliance, the United Mine Workers and other unions — then turned to the court.
The challenge centers on whether the proceeds resulting from the rulemaking’s required purchases of CO2 allowances constitute a tax or a regulatory fee. The rulemaking required fossil fuel-fired electric generating units (EGUs) of 25 MW or larger to purchase allowances for each ton of CO2 emitted through quarterly auctions, with a declining CO2 allowance trading budget.
Pa. Department of Environmental Protection
The Air Pollution Control Act (APCA) allows the executive branch to impose fees to cover the costs of administering its air pollution control program, but only the General Assembly has the authority to levy taxes.
“We reject [former DEP] Secretary [Patrick] McDonnell’s argument that the allowance auction proceeds do not constitute a tax because covered sources pay RGGI Inc. for the allowances purchased and not the commonwealth,” Wojcik wrote. “It is undisputed that the auction proceeds are remitted to the participating states.”
Wojcik said McDonnell was “unpersuasive” because the auction proceeds will go to the Clean Air Fund “and DEP anticipates significant monetary benefits from participating in the auctions.” He cited DEP’s estimate that only 6% of the proceeds from the CO2 allowances auctions would be for the costs of administering the CO2 Budget Trading Program: 5% for DEP and 1% for RGGI.
From 2016 to 2021, the Clean Air Fund annually maintained between $20 million and $25 million. But estimated receipts for the 2022/23 budget year, with RGGI, exceed $443 million — more than double DEP’s total budget of about $169 million.
The court considered several questions, including whether the injunction is necessary to prevent immediate harm that cannot be compensated by money damages. The petitioners said their injuries would not be recoverable because DEP and EQB have sovereign immunity. They also had to show that refusing the injunction would cause more harm than granting it.
The petitioners said the rule would have compliance costs of about $200 million that would be passed along to consumers, and that RGGI supporters’ claims that the rulemaking would cause meaningful GHG reductions were undercut by DEP’s modeling.
“There is no dispute that petitioners will face increased costs as a result of the rulemaking,” Wojcik wrote. “There is also no dispute that this increase in costs will ultimately be passed on to consumers.” A DEP witness testified that the rulemaking would increase wholesale power prices by 2.4% and retail prices by 1.2%.
Wojcik cited the rulemaking’s recognition that it would result in “leakage” of additional fossil fuel emissions outside of the state. DEP’s modeling found that a reduction of 97 million short tons of CO2 by 2030 in Pennsylvania would result in only a net 28 million ton reduction across PJM.
Crucially, the respondents needed to show that they were likely to prevail on the merits.
Wojcik said he agreed with the petitioners. “While the General Assembly may delegate the power to tax, the delegation must be clearly conferred via statute, and any such delegation appears absent from the APCA.”
Appeal Expected
Wojcik dismissed as “insufficient” testimony by environmental groups on the effects of CO2 emissions on climate change and human health.
While Keystone and Conemaugh emitted about 15.5 million tons of CO2 in 2021, “the record lacks evidence of the CO2 emission levels of the remaining Pennsylvania-covered sources or suggesting that the covered sources would be required to reduce emissions based on the available allowances,” Wojcik said.
“Even accepting for preliminary injunction purposes that implementation of the rulemaking would result in an immediate reduction in CO2 emissions from Pennsylvania’s covered sources, we conclude that implementation and enforcement of an invalid rulemaking would cause greater harm if the rulemaking is determined to violate the constitution or a statute.”
“While only temporary, the court’s decision is yet another roadblock and stalling tactic from RGGI opponents,” responded Jessica O’Neill, lead attorney for PennFuture, Clean Air Council, Sierra Club, Environmental Defense Fund and Natural Resources Defense Council. “The impact that RGGI will have on the health, safety and welfare of our members, our climate and our environment cannot be overstated. Simply put, RGGI will save lives, create jobs and lower Pennsylvania’s carbon footprint at a time when we need it most.”
O’Neill said the groups expect DEP to appeal the ruling, “which means the Supreme Court will have the opportunity to reinstate the RGGI rule.”
A new proposed federal rule released Thursday aimed at cutting greenhouse gas emissions from the nation’s highways raised immediate questions about whether it would pass muster under the new judicial review standards for regulations set by the Supreme Court’s decision in West Virginia v. EPA.
The Federal Highway Administration (FHWA) issued a Notice of Proposed Rulemaking (NPRM) that would require state departments of transportation and municipal planning organizations (MPOs) to set goals for reducing greenhouse gas emissions from motor vehicles traveling on any parts of the National Highway System (NHS) within their states.
The NHS includes about 2,200 miles of interstate and other key highways across the country and is the most heavily used of the nation’s 4 million miles of public roads, according to Joung Lee, deputy director and chief policy officer of the American Association of State Highway and Transportation Officials (AASHTO).
Based on 2019 figures, the NPRM says, transportation accounts for 34.6% of total U.S. carbon dioxide emissions, with 83.2% of that total coming from on-road sources. The FHWA anticipates that transportation will continue to be the nation’s largest source of GHG emissions through 2050. The proposed rule would set a national framework for measuring carbon emissions from vehicle travel on the NHS, a performance standard that would be integrated into existing federal performance standards that states already report on to the FHWA, according to an agency press release. The NPRM lays out the FHWA’s argument for the new standard, noting that existing law authorizing it to set and collect data on highway performance standards includes “environmental sustainability” as a key goal.
“Measuring and reporting complete, consistent and timely information on GHG emissions from on-road mobile source emissions is necessary so that all levels of government and the public can monitor changes in GHG emissions over time and make more informed choices about the role of transportation investments and other strategies in achieving GHG reduction targets,” the NPRM says.
At the same time, states would have the flexibility to set their own declining emission goals, based on a reference year of 2021, the most recent for which complete data are available, according to the NPRM. But the targets would have to be in line with the U.S. commitments of reducing GHG emissions 50 to 52% by 2030 and to net zero by 2050.
The targets would have to be reviewed and possibly updated every two years for the state DOTs and every four years for the MPOs.
The notice has been submitted to the Federal Register, and a 90-day comment period will begin once it has been published, according to the FHWA.
“With today’s announcement, we are taking an important step forward in tackling transportation’s share of the climate challenge, and we don’t have a moment to waste,” Transportation Secretary Pete Buttigieg said. “Our approach gives states the flexibility they need to set their own emission-reduction targets, while providing them with resources from [the Infrastructure Investment and Jobs Act] to meet those targets and protect their communities.”
The FHWA pointed to the IIJA’s Carbon Reduction Program, which will provide $6.4 billion in formula funding to states and local governments “to develop carbon-reduction strategies and fund a wide range of projects designed to reduce carbon emissions from on-road highway sources.”
Lee praised the U.S. Department of Transportation and FHWA for being “forthright about this not being a one-size-fits-all approach.” But, he said, AASHTO and its members would be using that 90-day comment period to drill into the details of the proposed rule and talk with federal officials.
“I think state DOTs recognize that the transportation sector is the largest sector when it comes to GHG emissions in the United States, and we all want to be part of the solution when it comes to the climate change imperative,” he said during a Thursday media call. While noting the diverse nature of AASHTO’s membership, Lee said, “we are generally in alignment with the U.S. DOT that transportation-focused GHG-reduction efforts have to be done in a holistic way that involves all stakeholders in the community. …
“We hope what we come up with will be reflected in the final rule,” he said.
Defining ‘Performance’
The rule issued Thursday is essentially an update of a proposed rule the FHWA released in the closing days of the Obama administration in 2017, which was put on hold and then rolled back by the Trump administration in May 2018. At the time, the agency justified the rollback on the grounds that it had reconsidered the legal basis of the proposed rule and found that it was too expensive and replicative of other federal GHG-reduction efforts.
In West Virginia v. EPA, the Supreme Court ruled that federal agencies could not repurpose yearsold legislation to justify new rules for issues not covered in the original law. Lee was careful in answering questions as to whether the new rule is specifically authorized under current law.
“We have to look to see if their statutory rationale is consistent with the Federal-aid Highway Program,” he said. “That’s part of what we’re trying to figure out.”
Lee cited two laws that could be critical in that determination: the Moving Ahead for Progress in the 21st Century Act (MAP-21) passed in 2012, and last year’s IIJA. According to the NPRM, MAP-21 allowed the FHWA to develop “national performance management measure rulemakings,” which resulted in standards on highway safety performance, infrastructure performance and system performance to assess freight movement, traffic congestion and on-road mobile source emissions affecting air quality.
While acknowledging that Congress did not specifically define “performance” to include environmental sustainability, the agency argues in the NPRDM “that Congress has directed FHWA to determine the nature and scope of the specific performance measures. … Accordingly, FHWA is proposing that the performance of … the NHS includes environmental performance.”
In support of this interpretation, the agency also cites the IIJA, which includes highway resilience and protection as one of the performance goals for federally funded highway aid programs.
Kate Zyla, executive director of the Georgetown University Climate Center, believes that “the FHWA’s proposed GHG performance measure is part of its well established Transportation Performance Management program. … FHWA has issued performance measures for safety, congestion, bridge and pavement conditions, for example. The newly proposed GHG performance measure would be similar.”
But at an online panel sponsored by the Climate Center on Tuesday, environmental law experts cautioned that following West Virginia v. EPA, such arguments will have to be strategically made. “Policies that look like the agency is doing one thing, but it’s doing it for the reason of reducing greenhouse gas emissions” could be a red flag for the conservative justices now dominating the Supreme Court, said Jonathan H. Adler, a law professor at Case Western Reserve University in Cleveland.
Federal agency officials may need to scrub “every document, every speech, every talking point to make sure that any climate benefits are ancillary, secondary,” Adler said.
Deron Lovaas, senior advocate at Natural Resources Defense Council, said the rule a “would help states and localities move toward a transportation system that’s equitable and clean. By measuring emissions and developing plans to cut them, states and localities can determine how to build a resilient and efficient transportation system that will serve us all for decades to come.”
But Sen. Shelley Moore Capita (R-W.Va.) called the new rule “unauthorized.”
The IIJA “included provisions to address climate change and the resiliency of transportation infrastructure in a bipartisan way,” Capito said. “This greenhouse gas performance measure announced today was not part of that legislation. Unfortunately, this action follows a common theme by both DOT and the administration, which is implementing partisan policy priorities they wish had been included in the bipartisan bill that the president signed into law.”
Arizona Public Service (APS) is soliciting proposals for energy projects providing up to 1,500 MW to help meet the utility’s reliability and clean energy goals.
The 1,500 MW of new resources will include up to 800 MW of renewable energy. APS issued the request for proposals in May and applications are due July 8.
Arizona’s summers are getting hotter while the state’s population and economy are growing rapidly, increasing the demand for electricity, the company said.
In addition, APS made a commitment to provide 100% carbon-free electricity by 2050, with an interim goal of 65% clean energy and 45% renewable energy by 2030. APS’s current energy mix is 50% clean.
“This broad market solicitation will help APS exit from coal-fired generation by 2031 and maintain adequate power supply to serve customers,” APS said in a release.
The company’s clean energy transition is “anchored by the Palo Verde Generating Station’s carbon–free nuclear power,” APS said in a clean energy report. Palo Verde is the largest nuclear plant in the U.S., with a capacity of 3,990 MW.
Storage Projects Welcome
APS is accepting applications for projects such as solar, wind, biomass, geothermal, landfill gas or storage, as well as combination projects such as solar plus storage.
In its request for proposals, APS said it would accept proposals providing at least 5 MW per site, but that it prefers projects larger than 200 MW.
The utility is looking for projects that will be in service starting in 2025 or 2026. Proposals will be accepted for projects being completed in phases, starting as soon as Dec. 1, 2024, and as late as Dec. 31, 2026.
According to the RFP, the resources may be offered through a power purchase agreement, a build-transfer agreement or a load management agreement. Examples of load management projects include behind-the-meter demand response programs or energy efficiency programs.
APS is seeking projects that would interconnect directly to the utility’s transmission system.
For renewable resources, APS said it would prefer projects that maximize the amount of energy generated and delivered from June through September and between 3 p.m. and 9 p.m. For energy efficiency proposals, APS would prefer projects that reduce demand during those same periods.
For storage projects, APS said it would prefer a project that can deliver the full proposed capacity for more than four consecutive hours.
“In addition, clean, flexible, dispatchable resources are increasingly important in helping APS meet its clean energy goals [and] maintain system reliability, and will be valued accordingly,” the RFP said.
Clean Energy Additions
The new resources that APS acquires from this year’s request for proposals will be in addition to 1 GW of clean energy secured through an all-source RFP and separate battery energy storage solicitation issued in 2020.
Those new resources, which will be in service by 2024, include 425 MW of solar power nameplate capacity, 238 MW of wind power nameplate capacity and 635 MW of battery storage nameplate capacity.
The Resource Planning Advisory Council, an APS stakeholder group, helped design the RFP. The group includes representatives of environmental groups, public interest organizations and universities, as well as consumer advocates.
In addition, an independent third party is monitoring the RFP process.
For this year’s RFP, APS plans to notify short-list applicants in August and make a final selection in September.
Ohio, Pennsylvania and West Virginia will have a better chance of winning a $2 billion U.S. Department of Energy grant to develop a “hydrogen hub” if they apply together, say top directors at the Battelle Institute, the world’s largest independent research and development organization and manager of eight DOE national labs.
“Battelle believes very strongly, and we’re not alone in this belief, that the best opportunity for success for Ohio and the region is for the three states to work together,” Don LaMonaca, a veteran Battelle director, told Ohio Gov. Mike DeWine and Lt. Gov. Jon Husted Wednesday in a public virtual meeting organized by the 150-member Ohio Clean Hydrogen Hub Alliance.
The purpose of the meeting was to give the governor’s office an update, and, as it turned out, ask for an assist in creating a tristate DOE grant application.
DeWine said his administration is “very interested” in the project and the efforts of Battelle and the hydrogen coalition but did not give a clear commitment to work with the governors of Pennsylvania and West Virginia to win the massive DOE grant.
“Our policy has been, in regard to energy, ‘all of the above.’ We’re very, very interested in in the work that you’re doing in regard to hydrogen and certainly want to hear or more about that. And we’re going to be very, very, very supportive,” he added.
The problem is that a coalition of West Virginia elected officials, including Gov. Jim Justice (R) and U.S. Senator Joe Manchin (D) have already said in an initial filing to the DOE that any hydrogen hub in the region should be in West Virginia.
“West Virginia is the place where this all-important hydrogen hub belongs. As one the world’s energy powerhouses for generations, West Virginia has long served as the home of all kinds of cutting-edge technological advances in energy production, thanks to our rich natural resources and our skilled and dedicated workforce,” Justice wrote in March. (See DOE Gets Hydrogen Hub Advice from Industry and Others.)
Better Together …
That assertion has not been overlooked by the DeWine administration.
LaMonaca asked DeWine and Husted “to help us get Ohio, Pennsylvania and West Virginia on the same page.”
In response, Husted wanted to know how interested Pennsylvania and West Virginia were in joining with Ohio. He said he suspected Manchin would not have voted for the infrastructure bill “without some kind of reassurance that his state was going to be funded.”
“We’re making good progress,” LaMonaca responded. “I would say Pennsylvania is very interested in a tristate collaborative approach. West Virginia is as well,” he said of businesses that Battelle had already contacted.
LaMonaca also noted that Battelle is aware of West Virginia’s previously announced position and knows that the DOE intends to make awards to proposals represented by a single entity.
He said Battelle understands that the DOE intends to make six to 10 initial grants (not just four) for the “initial launch” of about $400 million to $500 million, up to $1.25 billion, and will reserve $1 billion or $2 billion for future payments “depending on how impressed they are with the applicants,” he explained.
“There will be a 50% cost match that will need to come from the applicants’ team to match the government funding,” he said.
“So that’s why I think it’s important to get West Virginia, Pennsylvania and Ohio [governments] talking because all three states want to have a substantial presence as it relates to the hydrogen hub.
“But I think the only way that all three states get what they want is if all three states work together to coordinate an application that benefits the entire region and each of the three states individually as well.
“The strength of the region grows exponentially if you are able to pull together the resources … that exist within the three states for tristate unified application,” LaMonaca said.
… Or Going It Alone
Justice doesn’t seem to agree with that strategy. His press secretary Nathan Takitch said the governor is now focused on making sure West Virginia is awarded the DOE grant.
“Gov. Justice is one of several signatories to the West Virginia Hydrogen Hub Coalition’s official proposal to the DOE, which was submitted in March 2022,” Takitch said in an email. “The Coalition’s efforts are currently focused on working together to bring a Hydrogen Hub to West Virginia, as outlined in the agreement.”
A spokesperson for Sen. Manchin also pointed to the efforts the senator has made since February to help the West Virginia Hydrogen Coalition prepare to apply for the grant.
Pennsylvania Gov. Tom Wolf (D) is not ruling out a joint application. “Governor Wolf is certainly open to a joint application that builds on the strengths of the Appalachian [region],” Wolf’s press secretary Elizabeth Rementer said in an email. “The governor remains committed to working with industry stakeholders and partnering regionally to achieve this win for Pennsylvania’s economy, workers and the environment.”
The Biden administration’s objective is to incentivize the development of low-cost hydrogen production and use it in place of coal and natural gas in heavy industry, trucking, trains and buses. The $8 billion in initial funding was authorized by the bipartisan Infrastructure Investment and Jobs Act approved by Congress in 2021.
In Ohio, the Stark Area Regional Transit Authority (SARTA), which operates 20 hydrogen fuel cell buses in its fleet, and an alliance of Ohio industries and gas utilities organized initial support to apply for a hydrogen hub grant. An economic study produced by Cleveland State University found that by diverting just 15% of Ohio’s shale gas output to hydrogen production would meet initial demand. (See Ohio Hydrogen Study: Blue Now, Green in 2050.) Battelle is providing the technical assistance for the grant application.
The meeting with DeWine and Husted represented the first time the coalition had briefed the administration. “We are glad that they participated to learn more about our efforts and are willing to help us out in the future,” SARTA Executive Director Kirt Conrad said.
Another alliance called Appalachian Energy Future (AEF), organized by Pittsburgh-based non-profit IN-2-Market, is taking an industry-led approach to promoting a tri-state solution for a hydrogen hub. That group was founded with regional shale gas producers and heavy industries, including Marathon Petroleum (NYSE: MPC) which is headquartered in Ohio. Other members included gas producers Equinor (NYSE: EQNR) and EQT Corp. (NYSE: EQT); Mitsubishi Power, U.S. Steel (NYSE: X), GE Gas Power (NYSE: GE) and Shell Polymers (NYSE: Shell).
Michael Docherty, executive director of IN-2-Market and AEF, said that the three-state collaboration should be focused on addressing key enablers across the region.
“There’s going to be intense competition among companies and among the states for projects and funding, but there [are] also important foundational elements that we can work on together to help this region achieve its potential as an important clean-energy ecosystem,” he said.
Toby Rice, CEO of EQT, recently made a major pitch for liquified natural gas and hydrogen made from gas in the region before the D.C.-based Center for Strategic and International Studies. EQT has operations in all three states (See EQT CEO: Shale Gas Key to National Security, Hydrogen Economy.)
The plan in each state is to produce hydrogen from locally sourced natural gas for use in the region and sequester the resulting carbon dioxide in deep injection wells. At least one gas turbine power plant has already indicated it intends to blend small amounts of hydrogen with the natural gas it burns and heavy industry in the region has shown an interest as well.
NERC’s Board of Trustees voted to accept the organization’s 2022 State of Reliability report on Thursday, clearing the way for its release later this month.
The ERO produces the report each year to provide an analysis of the overall health of the bulk electric system, identify performance trends and emerging reliability risks, and measure the success of mitigation activities. Unlike NERC’s seasonal and long-term reliability assessments, the State of Reliability report is formatted as a review of the bulk power system’s overall performance the prior year along with specific incidents that impacted reliability.
Jim Robb, NERC | NERC
In Thursday’s board meeting, NERC CEO Jim Robb said the growing threat from severe weather, coupled with the shift to renewable and low-carbon energy sources, made it more important than ever that “reliability has a seat at the table” during conversations about the future of the BPS. He added that the Summer Reliability Assessment, issued in May, has already “catalyzed a very productive conversation” with Energy Secretary Jennifer Granholm.
“The importance of these assessments is clearly growing, given both the changing climate conditions that the grid is having to operate under, and the transformation of the grid itself,” Robb said. “And I don’t think there’s any better proof of that than all the attention that our summer assessment … has gotten, both in terms of the popular press as well as the trade press.” (See West, Texas, Midwest at Risk of Summer Shortfalls, NERC Says.)
Thursday’s discussion did not include a look at the full report; that is scheduled to be released during a media event on July 20, a spokesperson for NERC told ERO Insider. However, NERC staff had provided a preview at the board’s May meeting with some of the report’s key findings, which John Moura, NERC’s director of reliability assessment and performance analysis, referenced in his presentation to the board.
John Moura, NERC | NERC
“If there’s one question the State of Reliability really helps us answer, it’s ‘are we making a difference?’ … I think the answer is largely ‘yes, we are making a difference,’ and we do see incredible reliability improvements, specifically in how we keep the system stable,” Moura said. “On the other hand, when we look at our performance around resource adequacy and energy adequacy, we are seeing trends that really are leading to some concerns.”
One of the main challenges in 2021 was extreme weather, including the winter storms that knocked out power for thousands in Texas and the Midwest, Hurricane Ida’s impact on New Orleans and wildfires in the Western Interconnection. The winter storm in particular accounted for more than 23 GW of firm load shed, according to FERC and NERC’s joint report on the disaster, and was the sole reason for last year having the fewest hours without operator-initiated firm load shed since 2016. (See FERC, NERC Release Final Texas Storm Report.)
Trustee Roy Thilly said the report provided a strong reminder of the importance of planning for severe weather; he reminded listeners that “science tells us … we’re not dealing with a one-off situation.” Noting that “planning takes a long time to make changes,” he urged NERC to continue working to improve the grid’s preparation for the changing climate.
By contrast, Trustee Jim Piro suggested that while these issues must be recognized, the report also appears to tell an overall positive story. He said that although much work remains to build the grid of the future, NERC should be mindful of its successes so far so that it can properly build on them.
“There’s a lot of work that goes into making that happen, and sometimes we forget about how important that is and the work that’s been done. In fact, the system is pretty reliable, or very reliable, absent these severe events, and I think it’s important to note that for the industry,” Piro said.
Entergy’s New Orleans division unveiled a plan Tuesday aimed at hardening the bulk electric system in preparation for future storms in the city.
The proposal comes in light of the “increased frequency and severity” of extreme weather events that are causing “greater costs and disruptions” to electric customers on the Gulf Coast, the utility said.
In the proposal, submitted to the New Orleans City Council last week, Entergy (NYSE:ETR) identified nearly 900 projects across its distribution and transmission systems that would have a beneficial resilience effect. The planned upgrades would affect more than 33,000 structures and almost 650 line-miles and would cost almost $1.3 billion over the next 10 years.
Entergy’s filing repeatedly referenced the devastation wrought last year by Hurricane Ida, which struck the Gulf Coast in August and caused more than 1.2 million electricity customers across eight states to lose power, according to the Energy Information Administration. Nearly a million of those customers were in Louisiana, including a complete blackout of Greater New Orleans after a “catastrophic transmission failure” cut all eight transmission corridors into the city. (See Entergy Investigations Certain to Follow Hurricane Ida Restoration.)
Council Ordered Resilience Plan
Following the storm, the city council ordered Entergy to submit a “system resiliency and storm hardening plan” detailing how it would prevent future natural disasters from causing such severe impacts. The council’s resolution also referenced the high costs to Entergy’s ratepayers associated with repairing storm damage; this was a frequent cause of complaint among city officials in the weeks after Ida, who also asked why previous Entergy projects that were supposed to improve resilience seemed to have no effect in practice. (See New Orleans Seeks FERC Inquiry into Entergy Planning Practices.)
In its filing, Entergy avoided these adversarial characterizations, painting itself as a partner in suffering from recent storms’ destructive powers, and an ally to the city council in attempting to alleviate their impacts on the people of New Orleans.
“Over the last five years, major hurricanes have become more frequent and intense, and slower and wetter, further increasing the potential for devastation,” Entergy said. “Additionally, coastal erosion caused by severe storms, among other things, has increased the vulnerability of New Orleans by removing an important wetlands buffer. In short, the increasingly frequent threat of severe weather poses an existential threat to the region, including New Orleans.”
The grid hardening projects identified by Entergy include 184 “rebuild projects” in the distribution feeder category, which involve the “evaluation and potential rebuilding or replacement of every asset in the protection zone to bring such assets up to the company’s current design standards.” Another 674 rebuild candidates were found among distribution laterals, while the utility also noted 30 potential overhead line burial projects.
Among the distribution projects is a feeder rebuild in Algiers, involving the hardening of 324 structures along nearly four line-miles. Another is an overhead-to-underground project involving a third of a mile of line in the Treme/Lafitte area, affecting 611 customers.
Entergy also noted two transmission rebuild projects that would “have positive benefit to cost ratios and fall within the optimized budget.” These are the Front Street to Michoud 230-kV line, which would provide “an additional connection to the eastern interconnect … that allows for additional flexibility to operate during and after a major event.” The other project is the Gulf Outlet to Air Products 69-kV line, which would replace several structures along about a mile of transmission line.
Cost Recovery Rider Proposed
To pay for the proposed upgrades, Entergy proposed a cost recovery rider to “provide a stable, long-term recovery mechanism that could be used over the 10-year period of the projects.” The rider — dubbed the “Resiliency Rider” by Entergy — is patterned on the Purchased Power and Capacity Acquisition Cost Recovery Rider and the Securitized Storm Cost Recovery Rider, which Entergy used to recover its investment in the Union Power Block 1 and the Hurricane Isaac storm restoration, respectively.
Perhaps anticipating further complaints about passing along the costs of resilience investments to customers, the utility noted that credit ratings agencies downgraded Entergy New Orleans “several times” after Hurricane Ida, with further downgrades a possibility “if financial pressures are not mitigated and system resiliency is not enhanced.” Entergy argued that accomplishing the latter without alleviating the former may not be possible with the resources currently available.
“Credit ratings directly affect [Entergy’s] cost of capital investment and overall customer rates,” Entergy said. “Without timely and efficient cost recovery for the projects presented herein, [Entergy’s] financial health likely would be further compromised given the amount of the expenditures involved over an extended period.”
Entergy executives sought to position the proposal as a proactive measure to upgrade and modernize the grid ahead of future storms, while attempting to soften expectations by pointing out that “no amount of infrastructure investment can make an electric system completely resistant to the impacts of extreme weather conditions.” In a press release Deanna Rodriguez, CEO of Entergy New Orleans, said the utility expects to work with the city council to finalize the project list and its financial backing.
“While investments to harden the grid carry a significant cost, they result in substantial customer benefits in the long run,” Rodriguez said. “Robust investments in grid resiliency will reduce the duration of power outages following major storms and will also reduce future storm restoration costs. Our objective is two-fold: the hardening of the New Orleans grid and how quickly we get power back on for customers.”
A high-ranking ISO-NE official sat down with some of the RTO’s biggest critics last week, who pushed her on the RTO’s clean energy efforts, market rules and transparency.
Anne George, ISO-NE vice president for external affairs, defended the organization and answered questions lobbed at her by a group of stakeholders in the energy industry and from environmental groups at a roundtable put together by U.S. Sen. Ed Markey (D-Mass.), who himself has offered frequent critiques of the grid operator. (See Mass. Democrats Take on ISO-NE over MOPR.)
“Instead of a renewable energy superhighway for the modern era, our grid is a one-lane road that would still be recognizable to Henry Ford,” Markey said in kicking off the meeting.
George said that ISO-NE is “committed to having full conversations with the region” about the markets and decarbonization goals of the states, touting the grid operator’s recent vision statement and its work on the Pathways to the Future Grid study.
Who’s Responsible for Fixing the Markets?
George defended the role of the markets in growing the region’s renewable energy footprint, arguing that siting has been a primary challenge and that states need to step up in finding ways to get projects built.
“There’s a lot that has come on in places where it’s easier to site,” she said.
Another factor George cited: developer recalcitrance.
“Our markets are open to all of these resources to come in. It’s just a question of when the developers want to come in,” she said.
And she repeated a frequent ISO-NE refrain about the importance of natural gas for the region’s near future.
“Natural gas isn’t necessarily an evil thing. It’s providing reliability. It’s oftentimes at lower cost, and it’s going to be here for the foreseeable future. We don’t have enough [clean energy] resources ready to go. They haven’t even tried to come into the market because of their development timelines,” George said.
Greg Cunningham, a vice president at the Conservation Law Foundation, pushed back by noting ISO-NE’s failure to move forward on requests from the states to create a central clean energy mechanism.
“I blanch a little bit when I hear ISO-NE saying the region needs to act,” he said. “The states have, in essence, petitioned ISO-NE to make change, to make it happen. And it’s not. And that’s where principal frustration lies.”
“When we do make a decision, we get criticized,” George shot back. “When we say we’re going to listen to people, we get criticized. At some point, you have to reconcile those positions.”
She reiterated that the RTO has been supportive of a net carbon pricing solution for the region, which would rely primarily on states to enact; the states have been reluctant because of political challenges associated with carbon pricing.
Jeremy McDiarmid, vice president at the Northeast Clean Energy Council, floated a solution at a higher level: add the transition to clean energy to the list of legal responsibilities of RTOs, in addition to maintaining reliability and markets.
“ISO could provide leadership to the states with their voice and their actions,” he said.
Transparency at the Forefront
An oft repeated subject at the meeting was transparency, an area where ISO-NE is widely thought to trail behind its counterparts in other regions of the country. NEPOOL’s stakeholder meetings are not open to the public.
“It saddens me to say that ISO-NE is an outlier in terms of public accessibility,” said Tyson Slocum, a consumer advocate and director of Public Citizen’s Energy Program. “At PJM, any member of the public can attend any of the meetings for free and be able to speak at the meetings where deliberations about tariff design and market design are taking place.”
Amy Boyd, director of policy at the Acadia Center, said that it’s “crucially important for the communities who are going to be … ultimately the consumers of both the energy and air that all of this affects to be involved in a lot of those discussions.”
“Right now, most meetings on regional decisions are not public, nor understandable by the public. Statements made in those meetings are not publicly reported,” Boyd said.
She laid out one concrete idea for starting to address the lack of transparency: that ISO-NE include in all of its proposals information about the expected impacts on state policy, including decarbonization, consumer costs and environmental justice.
“Including a short assessment of the impacts that ISO sees would help states and consumers openly discuss the benefits and tradeoffs of proposals on the table before them,” Boyd said.
Rebecca Tepper, chief of the energy and environment bureau in the Massachusetts Attorney General’s Office, said that ISO-NE should find ways to bolster participation from the states, including possibly funding a position through its tariff to serve as an interface with consumer advocates.
George noted that NEPOOL is a separate entity from ISO-NE, and one that actually predates it, with its own governing rules.
But Slocum, Markey and others in the room didn’t accept that fact as absolving the grid operator from responsibility.
“ISO-NE could say publicly and firmly, we need a stakeholder process that any member of the public could participate in,” Slocum said. Or the grid operator could ask FERC to change the stakeholder process to prioritize inclusion, he said.
Markey called the New England energy stakeholder process one that is “controlled by the priesthood of experts.”
“We’ve got to break up NEPOOL. They’ve got a vice-like grip over this secretive process,” said Markey, saying he’d like to see a poll of NEPOOL members to find out which of them are opposed to more transparency and public participation.
Looking Forward at 25
As George was facing down questions about ISO-NE’s future, the grid operator itself was preparing to release a document looking ahead and painting its role in a rosier light.
New England’s major new and retiring resources. | ISO-NE
The presentation lays out four key pillars for the region’s future: “significant amounts of clean energy resources, sufficient balancing resources to ensure reliability, a reliable fuel supply or energy storage reserve, and a robust transmission system.”
It puts forward graphics about the resources that are coming to the grid in New England and leaving it. And it describes the vulnerabilities that ISO-NE has been worrying over and working on fixing, like fuel constraints and extreme weather.
“Over the last 25 years, ISO New England has laid the foundation to support the four pillars discussed in this report, and the region is already well along the path to a clean energy future,” wrote CEO Gordon van Welie and Board of Directors Chair Cheryl LaFleur. “As we keep our eyes on the horizon, New England has an opportunity to serve as a model for what a sustainable, reliable and efficient transition can look like.”
The U.S. Department of Energy approved rule changes Thursday meant to allow California’s last nuclear plant to apply for federal aid so it can keep operating beyond its scheduled retirement date.
Pacific Gas and Electric plans to shut down its Diablo Canyon Power Plant in phases starting in 2024, but Gov. Gavin Newsom is hoping to keep it running to deal with potential capacity shortfalls over the next four summers.
Newsom’s cabinet secretary Ana Matosantos wrote to Energy Secretary Jennifer Granholm in May, asking that DOE amend its eligibility criteria for the Biden Administration’s $6 billion Civil Nuclear Credit Program (CNC), funded under November’s Infrastructure Investment and Jobs Act. The program is meant to assist nuclear plants at risk of closure for economic reasons.
In an April guidance, DOE had said CNC funding is for nuclear plants that participate in competitive energy markets and do not recover more than 50% of their costs from cost-of-service ratemaking. PG&E recovers its Diablo Canyon costs from customers under rate cases approved by the California Public Utilities Commission and would not qualify for CNC funding under that interpretation.
In her letter, Matosantos requested that DOE’s guidance be changed to exclude the cost-of-service requirement. The state is facing a shortfall of 1,800 MW during peak summer hours after solar goes offline, she wrote. Diablo Canyon provides 8.5% of in-state generation and is needed beyond its planned retirement date to maintain reliability as it transitions to 100% carbon-free energy, she said.
The department’s April guidance was “overly broad, especially where cost-of-service does not cover the costs for which funding is being sought.” For Diablo Canyon to “extend operations, it would incur significant transition costs over the next four years to perform necessary studies, invest in plant enhancements, and obtain licenses and permits. Yet there is no existing cost recovery mechanism for those transition costs” when PG&E sells output from the plant into CAISO’s wholesale electricity market, she said.
Extending operations at Diablo Canyon would “cause significant economic losses” for PG&E “of the sort that the Civil Nuclear Program was designed to address,” Matosantos contended.
DOE issued a proposed guidance amendment for public comment by June 17, and on Thursday it announced it was making the changes requested by Newsom’s office “given the request’s potential applicability to reactors nationwide.”
“The amended guidance revises the eligibility criteria to replace the requirement that a nuclear reactor applying for credits under the CNC Program not recover more than 50% of its costs from cost-of-service regulation or regulated contracts,” the department’s Office of Nuclear Energy said in a statement. “This change affects the eligibility of reactors who may apply in the first round of awards.”
DOE also extended the application deadline for the first round of CNC funding to Sept. 6.
“The amended CNC Guidance supports the intent of President Biden’s bipartisan infrastructure law to keep the reactors online that sustain local economies and today provide our nation’s single largest source of carbon-free electricity,” Assistant Secretary for Nuclear Energy Kathryn Huff said in DOE’s statement.
PG&E has yet to commit to keeping Diablo Canyon open and has previously said it plans to move forward with the plant’s scheduled retirement, but in comments to DOE it agreed with the governor’s requested rule changes and asked for a 75-day extension to apply for CNC funding. A budget trailer bill signed last week by Newsom allocates $75 million toward keeping the plant open.
