NYISO on Monday updated the Transmission Planning Advisory Subcommittee on a phased window approach to its generator interconnection queue to potentially replace the current process.
The construct would enable groups of overlapping projects, which proceed in separate phases in a single queue window, to be evaluated simultaneously throughout the interconnection process; add decision periods and milestone requirements to give developers more flexibility; and replace individual system reliability impact studies.
Since the 2019 passage of New York’s Climate Leadership and Community Protection Act, NYISO has been devising ways to hasten its existing three-part interconnection study process, including narrowing some study scopes, adding more staff and considering tariff revisions. (See NYISO Begins 2023 Class Year with Nearly 100 Projects.)
Thinh Nguyen, senior manager of interconnection projects, told stakeholders that the window approach seeks to reduce study times, increase efficiency without compromising reliability and give developers the ability to “get off the train” by opting out of the process without disrupting other studies.
Although encouraged that NYISO is investigating queue enhancements, stakeholders still sought clarity on many aspects of the approach.
Mark Younger, president of Hudson Energy Economics, asked whether a project would still “have another bite at a future queue window” and rejoin later if it decides to not proceed as part of their assigned queue window.
Nguyen responded it would but added that projects electing to withdraw from their current queue window “actually have no more bite but can jump to the next queue window.”
Doreen Saia, an attorney with Greenberg Traurig, asked how the approach would interface with state agencies, such as the New York State Energy Research and Development Authority (NYSERDA), and their solicitations.
Nguyen said that “it’s probably easy for NYSERDA to look at our new process and create the new rules that will be applicable for any solicitation,” to which Saia responded that she would “definitely encourage that those conversations happen in the relatively near team, because I don’t want [NYISO] to go too far down this path and then have [state agencies] say that it’s just not going to work.”
Stakeholders asked additional questions, such as about how study deposits would be treated if a project withdraws, whether the ISO could elaborate on certain definitions or terms, the role consultants would play and how elements of the current interconnection study process would fit into the new approach.
Nguyen addressed these lines of questioning but reiterated that NYISO was “not going to go too deep … because [stakeholders and the ISO] have not yet agreed to move forward with the new process.”
NYISO will continue soliciting feedback and spend part of the April 14TPAS meeting addressing any remaining questions or unresolved issues, Nguyen said.
Long Island PPTN Report
NYISO on Monday also released its draft public policy transmission planning report, which included sensitivity results for 16 offshore wind projects that participated in the Long Island public policy transmission needs (PPTN) process. (See “Offshore Wind,” NYISO Stakeholders Propose Three Areas for Public Policy Transmission.)
In the coming months, NYISO will continue to review the results with stakeholders, add further details on additional sensitivities for consideration and include ISO-recommended rankings for all the submitted projects.
Developers are invited to present their projects to NYISO’s Board of Directors on April 17; on June 13 the ISO will conduct an “appeal-like process” for stakeholders to raise concerns and provide other feedback directly to the board.
The North American Council for Freight Efficiency has concluded that hydrogen will be a factor in long-distance heavy-duty trucking by enabling the industry to reduce carbon emissions in a zero-emissions future envisioned by the Biden administration.
In a new report released Tuesday, a team of NACFE analysts reason that battery electric trucks, as currently designed, are not up to carrying heavy freight loads over long distances. The analysis concludes that both battery and fuel cell electric trucks will be needed, with battery trucks hauling freight locally and regionally, up to about 250 miles.
The report comes just days before the U.S. Department of Energy’s deadline for industries working with local and state governments to file applications for $7 billion in matching funds to develop regional hydrogen hubs decarbonizing heavy industry. DOE envisions beginning with six to 10 regional hydrogen hubs.
NACFE’s authors reason that hydrogen production levels will increase significantly over time with the development of the hydrogen hubs, becoming cost competitive with diesel fuel.
Battery electric, hydrogen fuel cells and sustainable liquid fuels will each have a role in transportation. | NACFE
What the report does not say is whether the long-anticipated heavy-duty hydrogen fuel cell systems will be superior to the just emerging re-engineered diesel engines designed to run on hydrogen.
“Two paths are emerging: fuel cell electric and new hydrogen internal combustion engines,” the study asserts. “Hydrogen is not optimum for all duty cycles. Hydrogen fuel cell tractors are, however, the only viable zero-emission solution currently proposed for one-for-one replacements for diesel in the future of long-haul heavy-duty trucks.”
In previous studies issued over the past five years, NACFE focused mainly on battery electric trucks, including large trucks. And in real over-the-road testing in which a small number of fleets participated, NACFE concluded that electric fleets making deliveries over prescribed routes not exceeding 250 miles could handle the job.
Mike Roeth, NACFE | NACFE
Previous NACFE studies did not include converted and re-engineered diesels because none was commercially available or even discussed publicly. Cummins, a long-time engine builder, has not only been designing an engine to burn hydrogen but has also begun building electrolyzers to produce clean hydrogen. President Biden visited a Cummins plant on Monday to mark that buildout.
Mike Roeth, executive chairman of NACFE, said that while the new study demarcated the distances each technology was capable of handling, the organization has not ruled out the use of hydrogen fuel cell trucks for use in short hauls.
“In rural areas, it might be easier to get a hydrogen truck to a [refueling] site than create electricity,” he said.
Asked whether the report included a cost comparison of the three technologies — battery, fuel cell or re-engineered engines — Roeth said it “is just to early to tell.”
He explained that fuel cell vehicles require additional cooling systems over vehicles with engines because fuel cells produce a lot of waste heat when producing electricity.
CAISO published a draft transmission plan Monday that identifies 46 transmission projects needed over the next decade to incorporate more than 40 GW of renewable resources essential for advancing the state’s transition to 100% clean energy and maintaining grid reliability.
“The need for additional generation of electricity over the next 10 years has escalated rapidly in California as it continues transitioning to the carbon-free electrical grid required by the state’s clean-energy policies,” CAISO said in the plan. “This in turn has been driving a dramatically accelerated pace for new transmission development in current and future planning cycles.
“To help ensure we have the transmission in place to achieve this transition reliably and cost-effectively, the ISO’s 2022-2023 Transmission Plan reflects a much more strategic and proactive approach to better synchronize power and transmission planning, interconnection queuing and resource procurement,” the plan says.
The more proactive approach was outlined in a memorandum of understanding that CAISO, the California Public Utilities Commission (CPUC) and the California Energy Commission (CEC) signed in December. It provided a “new blueprint for our state” with closer links between the planning processes of each entity, CAISO CEO Elliot Mainzer told the ISO Board of Governors in February. (See CAISO CEO Lauds Transmission Planning Agreement.)
The new transmission plan is the first to be prepared under the MOU.
It is based on the CPUC’s projections that the state needs to add at least 40 GW of new resources by 2032 in a base-case scenario and 70 GW in a “sensitivity” scenario “reflecting the potential for increased electrification occurring in other sectors of the economy, most notably in transportation and the building industry,” the plan says.
“The network upgrades are recommended in this plan to make all of the base amounts available and, in Southern California, to also make most of the sensitivity amounts available as well,” it says.
The CPUC has already indicated it will provide the 70GW scenario as its base case next year, so the “remaining network upgrades needed to achieve the sensitivity amounts will be approved next year” in CAISO’s annual update to its 10-year transmission plan.
Interconnection Zones
In preparing the plan, CAISO analyzed projected resource additions within 14 transmission interconnection zones. The Southern California Edison (SCE) Northern zone, for example, will need 11.6 GW of new resources under the base case scenario and 16.9 GW under the sensitivity portfolio, primarily through a buildout of utility-scale solar and battery storage.
Critical resources identified in the plan include:
17 GW of solar generation in the deserts of Southern California and the Central Valley, and in areas of Nevada and Arizona.
3.5 GW of in-state wind generation.
1 GW of geothermal development in the Imperial Valley of far Southern California and in southern Nevada.
Battery storage projects co-located with renewable generation projects and stand-alone storage near Los Angeles, San Francisco and San Diego.
4.5 GW of in-state transmission upgrades necessary to import out-of-state wind energy from Idaho, Wyoming and New Mexico.
3-5 GW of wind generation off the coast of Central California.
“To achieve these outcomes, the ISO has found the need for a total of 46 transmission projects, the vast majority of which would be built in California. They range in projected costs from $4 million to $2.3 billion, for a total infrastructure investment of an estimated $9.3 billion,” CAISO said.
Major projects include a new 500-kV transmission line from the Arizona border to Imperial County, a new 500 kV transmission line from southern Imperial County to San Diego and the Los Angeles Basin, and upgrades to existing 500-kV and 230-kV lines along the Interstate 10 corridor, which runs from Los Angeles toward Phoenix.
“Together, these upgrades provide access to east Riverside County, Imperial County and Arizona solar generation, Imperial Valley geothermal, and New Mexico wind generation,” the transmission plan says.
Other notable projects include a new 500-kV transmission line from southeastern Nevada to the Los Angeles Basin and “rebuilding of existing southeastern Nevada 230-kV transmission inside the ISO to 500 kV, providing access for Eldorado and Pisgah area solar generation, southeastern Nevada solar and geothermal generation, and Wyoming and Idaho wind generation.”
‘Next Major Installment’
CAISO identified 24 reliability-driven projects, totaling $1.76 billion and 22 policy-driven projects needed to meet the state’s climate goals, totaling $7.53 billion.
In addition, the ISO has been working with out-of-state transmission developers to bring wind from Wyoming via the planned TransWest Express line and from New Mexico via the planned Sunzia line to the CAISO boundary.
Developers for the transmission projects have sold capacity on their lines to “resource developers seeking to access California markets,” the plan says. “That work is ongoing, and the timing of those projects is driven by the developers and their subscribers.”
CAISO said it had also studied the need for transmission for North Coast offshore wind based on the sensitivity portfolio provided by the CPUC.
“As the study was only informational and set the stage for future planning, no projects were recommended for approval in this 2022-2023 plan,” it said. But with “growing volumes” of offshore North Coast wind identified in the CPUC’s 2023/24 planning cycle, the “ISO expects to make a decision on North Coast transmission in next year’s transmission plan.”
In a blog post, Mainzer said the 2022/23 transmission plan “represents the next major installment of infrastructure investment required to meet California’s long-term clean energy goals. In close coordination with regulatory agencies, load-serving entities and other key stakeholders, we endeavored to address the state’s reliability and policy needs in the most cost-effective and efficient way possible.”
CAISO has scheduled a stakeholder meeting April 11 to discuss the draft plan and expects to seek approval from its Board of Governors in May.
A Nevada lawmaker has introduced a resolution urging the federal government to use Yucca Mountain, once proposed as a dumping ground for the nation’s nuclear waste, as a site for renewable energy.
Senate Joint Resolution 4, introduced by state Sen. James Ohrenschall (D), was heard last week by the Senate Natural Resources Committee. The committee took no action.
SJR 4 “urges the federal government to use Yucca Mountain for the development and storage of renewable energy.” If passed, the resolution would be sent to federal officials, including the president, vice president, House speaker and energy secretary.
Not long ago, Yucca Mountain faced a “scary future” as the nation’s disposal site for high-level radioactive waste, Ohrenschall told the committee.
Now, he said, there’s an opportunity for “positive uses,” such as renewable energy or research.
“And if these positive uses happen, then I think it becomes exponentially less likely that the federal government will be able to say, ‘No, we need to take all the nation’s high-level radioactive waste and spent nuclear fuel, transport it across the country and send it here to Yucca Mountain,’ which I think puts not only our constituents in danger, but citizens around the country,” Ohrenschall said.
Renewable energy at Yucca Mountain has been discussed previously, including in a 2011 report from the U.S. Government Accountability Office that looked at alternative uses for the site. The report said a potential challenge to energy-related uses was the lack of nearby transmission.
On Thursday, supporters of SJR 4 noted NV Energy’s plans for Greenlink West, a roughly 350-mile transmission line that will run past Yucca Mountain and the neighboring Amargosa Valley community.
“We are in what they call the sweet spot for Greenlink and all the transmission lines and such,” said Carolyn Allen, chair of the Amargosa Valley Town Board.
Renewable energy development at Yucca Mountain would bring an array of benefits to the town, said Allen, who called SJR 4 “an excellent bill.”
“It can bring research,” she said. “It can bring new people that want to live there and raise families there.”
One person spoke in opposition to the resolution. Dylan Keith, assistant director of government affairs for the Las Vegas Chamber of Commerce, said the chamber supports renewable energy research and development.
But “the chamber has had a long-standing opposition to any development with the Yucca Mountain project,” Keith said.
Committee member Sen. Ira Hansen (R) said the nation’s move toward electrification and the growing demand for electricity raise complex questions. He said one issue is what to do with used solar panels and asked whether Yucca Mountain could be used as a disposal site.
“In the next 20 or 30 years, we’re going to have hundreds of thousands of those,” Hansen said. “What are you going to do with the old panels?”
Yucca Mountain was designated as the sole location for a national nuclear waste dump when Congress amended the Nuclear Waste Policy Act in 1987. Since the 1980s, the U.S. Department of Energy has spent billions of dollars studying Yucca Mountain as a disposal site for nuclear waste. The 230-square-mile site is about 100 miles northwest of Las Vegas.
But faced with strong opposition from the state of Nevada and Native American tribes, Congress stopped funding Yucca Mountain in 2010. In 2021, the Biden administration stated its opposition to using Yucca Mountain as a nuclear waste site. Instead, the administration has shifted its focus to “consent-based siting,” in which nuclear waste is stored in communities that agree to accept it.
In preparing its 2011 report on alternative uses for Yucca Mountain, GAO interviewed experts who had a wide variety of suggestions. Those ranged from a command center for unmanned aircraft, weapons testing, public emergency communications or a secure data storage site.
Energy-related ideas included a commercial energy park, with nuclear, solar and wind power generation. Research was another suggested use, with potential topics including carbon capture or compressed air or pumped hydroelectric energy storage.
NERC CEO Jim Robb felt “sobered by the amount of work in front of us” but confident that the ERO can address the electric grid’s “hyper complex risk environment,” he said in a media call Wednesday to mark the five-year anniversary of his joining the organization.
The rapidly changing grid and its implications for reliability were a major theme of the call, which also featured Manny Cancel, a senior vice president at NERC and CEO of the Electricity Information Sharing and Analysis Center (E-ISAC), discussing physical and cybersecurity challenges. Robb said the switch from conventional spinning generation to solar, wind and other inverter-based resources (IBRs) should spur stakeholders to rethink how they provide “essential reliability services.”
“We really need to shift our thinking around reliability away from capacity installed plus reserve margin, which really accounts for random events that occur out on the grid, [and] to recognize that we now have a generation mix that’s increasingly impacted by common conditions,” Robb said. “Wind droughts, solar droughts — these things can affect a large amount of generation, and not in a random way. We really need to get our heads around that dynamic and the uncertainties around fuel as we think through the sector’s ability to serve [the] energy needs of customers.”
Shifting toward intermittent generation also means utilities nationwide have increasingly adopted natural gas as a balancing resource, Robb said, making coordination between the electric and gas industries critical. This is not always easy, he acknowledged, saying that while “the gas industry is amazing at what it does,” it “wasn’t designed to serve highly variable loads like electric power.”
E-ISAC CEO Manny Cancel | NERC
Using gas as a lynchpin for the generation fleet has therefore created strains that both industries need to work on together, with help from policymakers and regulators as well, Robb continued, adding that “it’s as hard to start a new gas pipeline … as it is to build electric transmission.”
“Because of electrification policies, electric transportation and moving space heating toward an electric fuel, we’re going to be growing load, and we’re having enough trouble just keeping up with where we are right now,” Robb said.
NERC has an important role to play in educating the various governmental agencies that oversee the development of the grid and gas system, Robb said; this takes the form of putting “steadfast protection … around NERC’s objectivity and rooting our perspectives in science and technology” as the ERO communicates with regulators.
Cancel also discussed the importance of cross-industry collaboration in the security space, calling the E-ISAC a “conduit to the industry” for government agencies, “not only for information sharing, but also to discuss policy and other issues.” He said the E-ISAC’s level of engagement with policymakers “has never been stronger,” while its relationship with its counterparts in other critical industry sectors has also become tighter since Russia invaded Ukraine last year.
Additionally, Cancel pointed to his organization’s efforts to combat supply chain weaknesses through its vendor affiliate program. The program, launched last year, is intended to give vendors a voice in the debates over supply chain issues and provide their “keen insights” on the risk landscape.
“They are doing things from a product perspective … to protect themselves too. We can certainly learn from them, and they can be a powerful voice, particularly the vendors that are used pervasively across the electricity sector,” Cancel said. “That’s not only going on through the [E-ISAC]; it’s going on through other venues [like] trade associations, [and] the government has [been] having dialogue with the vendor community. … I’m not declaring victory, and underscoring that has to continue, but [it’s] a very important step forward.”
A rest stop operator is negotiating with the New Jersey Turnpike Authority (NJTA) to install electric vehicle chargers along the state’s two main highway arteries under a $166 million program, according to the agency.
The NJTA board on March 28 authorized the continuation of talks with Applegreen NJ Welcome Centers, which operates restaurant facilities at rest stops along the New Jersey Turnpike and the Garden State Parkway, which also is managed by the authority. Applegreen, based in Ireland, sells food and fuel at 121 sites in the U.S. Northeast and South.
Service areas on the two highways currently host 76 chargers — 70 on the turnpike and six on the parkway, NJTA spokesperson Tom Feeney said. Of the turnpike chargers, 64 are operated by Tesla, six by EVgo, which also operates all six on the parkway, he said.
The authority’s announcement comes as the state seeks to increase the number of chargers statewide, believing — like other states — that a key element to jump-starting a broad embrace of EVs is to remove the fear that a vehicle could run out of power with no charging nearby to replenish the battery.
New Jersey has 943 public charging locations, 164 of which offer DC fast chargers and 802 offering Level 2 charging, according to the public EV charging locator run by the New Jersey Department of Environmental Protection. About 95% of the state is within a 25-mile radius of a DC fast charger, according to the site.
About 90,000 EVs are registered in New Jersey, a small fraction of the 6 million light-duty vehicles on the road, but a big jump up from approximately 30,000 EVs in the state at the end of 2019. New Jersey policy calls for 330,000 light-duty plug-in electric vehicles registered in state by 2025, along with 400 fast chargers and more than 1,000 Level 2 chargers by the same date.
Expanding the Charger Network
Feeney said the talks with Applegreen have not yet determined where and how many chargers would be installed if negotiations are finalized. But the deal would “greatly expand the number of EV charging stations at turnpike and parkway service areas,” he said.
Elements of the deal already have been agreed to, according to the authorization approved by the agency. Applegreen “will construct EV charging facilities and construct or secure the construction of related utility infrastructure at authority rest service areas,” the order says. The company also will operate and manage the facilities, the order says.
NJTA would pay $24 million in the deal, but there has been no agreement on “customer pricing structure or revenue sharing,” according to the order.
Pamela Frank, CEO of ChargEVC-NJ, a coalition of industry groups, consumer advocates and environmentalists that promotes EV adoption, welcomed the announcement and especially the authority’s $24-million commitment to the project.
“It’s a very good initiative,” Frank said, adding that she expects the deal to add hundreds of chargers along the two highways. “The good news is you’re going to see [chargers] on the parkway; you’re going to see [them] on the turnpike on all of these stops that are owned and operated” by the contractor, she said.
The biggest benefit, however, could be that the project will bring the power cables from the grid needed for chargers at the rest stop charging site, which is often the biggest cost to the charging station, she said. So even if there are not many plugs at the start, due to the limited demand at present, they can be easily added.
New Jersey ranks 15th among states in the number of publicly available non-Tesla fast chargers, according to an analysis of federal data by ChargEVC-NJ, Frank said, noting that seven East Coast states rank higher. The state has about one public EV plug per 24,000 vehicles of all kinds on the road, about the same as the U.S. as a whole, she said.
Multiple Incentive Programs
The federal government awarded the state $104 million in funds from the National Electric Vehicle Infrastructure (NEVI) program, which requires states to identify alternative fuel corridors (AFCs), major state and interstate highways where EV charging stations would be located every 50 miles. EVs can fully recharge in about an hour using the fast-charger ports now available.
Under the first phase of New Jersey’s NEVI plan, from 2022 to 2024, state officials designated 12 highways as AFCs, among them the turnpike and parkway. The plan calls for the state to use the NEVI funds to install four 150-kW chargers at least every 50 miles at locations less than a mile from the highway exit.
The state also has several of its own funding programs designed to stimulate the installation of chargers. The state Board of Public Utilities (BPU) in June expanded a program that awards incentives for chargers installed at tourist sites, in a bid to attract EV-driving visitors. The program offers up to $2,000 for a Level 2 charger and up to $5,000 for a fast charger, along with subsidies for make ready costs. (See NJ Boosts EV Charging Program for Tourist, Multifamily Locations.)
Another state program awards funds to support the installation of chargers at multi-family dwellings, and a third program, called It Pay$ to Plug In, provides incentives of up to $750 for a Level 1 charging port installed at workplaces, public places and other locations, and $4,000 for a Level 2 charging port.
In October, the BPU approved $16.15 million in funds from the Regional Greenhouse Gas Initiative to create the state’s first program designed to promote the installation of fast chargers for medium- and heavy-duty (MHD) electric vehicles. (See NJ BPU Approves $16M for 1st MHD EV Charger Program.)
PJM presented a draft proposal to delay the next four Base Residual Auctions (BRAs) to the Members Committee during a special meeting on Tuesday.
The alternative schedule would move the 2025/26 auction, currently scheduled for this June, to June 2024; the following three auctions would be held every sixth months thereafter. Auctions would return to their regular timing of being held three years in advance of the 2029/30 BRA, which would be held in May 2026. (See PJM Board of Managers to Seek Capacity Auction Delays.)
The tightened schedule would also continue the current practice of canceling incremental auctions (IAs) when they take place within 10 months of the BRA or would be within the same year as the corresponding delivery year. The first two IAs for the 2025/26 auction and following year’s would be canceled, leaving only the third IA in place. Two IAs would be held in the 2027/28 and 2028/29 delivery years, before going back to the normal three per year.
PJM’s tariff requires that it consult with the MC and Transmission Owners Agreement-Administrative Committee (TOA-AC) at least seven days prior to making a Federal Power Act Section 205 filing with FERC. The TOA-AC, whose meetings are closed to the public, met on Tuesday after the MC.
Pre-auction activities will continue until PJM has received an order from FERC to ensure that the 2025/26 BRA can still be held in June should the commission reject the filing. Should the commission approve the filing, PJM’s Tim Horger said those activities will be rerun leading up to the auction’s new date.
Horger said the filing is based on the premise that FERC will approve the capacity market overhaul that the Board of Managers plans to approve and have filed by Oct. 1 within 60 days. If the commission were to take longer and reach a decision as late as March, Horger presented a potential alternative that would delay the 2025/26 BRA to October 2024 and delay the following four auctions. The schedule would go back to normal with the 2030/31 auction in May 2027.
The draft filing shown to the MC only seeks the capability to change the timing of auctions through the 2028/29 delivery year, necessitating an additional FERC filing for the alternative Horger presented.
Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said requiring a filing by Oct. 1 and setting June 2024 in stone for the 2025/26 BRA would limit stakeholders’ ability to extend discussions on capacity market changes through the Critical Issue Fast Path (CIFP) process. He noted that PJM has delayed the release of its report on the December 2022 winter storm to July, which he argued also leaves little time for review and to incorporate findings into proposals. (See PJM Presents More Detail on CIFP Proposal.)
The report will be especially important for state consumer advocates, Poulos said, as they are not market participants and lack the insight into the storm’s impact that those directly affected by it possess. A short timeline for making these decisions could put advocates in the position of voting on proposals to recommend to the board without having all the necessary information, he said.
Poulos also questioned whether there is a plan for how PJM would act if FERC approves the auction delay but ultimately rejects the eventual capacity market proposal.
Horger responded that PJM is aware of that possibility and that the risk will have to be addressed should it manifest.
Vistra’s Erik Heinle asked if PJM will request expedited consideration of the filing to reduce the amount of pre-auction activities that market participants must engage in.
PJM Senior Counsel Chen Lu said the decision to make the filing under Section 205 was intended to reduce the amount of time to receive a determination, but PJM will consider asking for expedition.
Ian Oxenham, legal specialist for the New Jersey Board of Public Utilities, urged PJM to not seek expedited consideration, saying that it could deprive commenters of the time needed to evaluate the filing.
“PJM should be very hesitant to shorten that comment period,” he said.
Millions in new funding and bonus tax credits are heading to new clean energy projects in U.S. “energy communities” — the cities, towns and counties where the closure of coal mines, coal-fired power plants and other fossil fuel projects has meant lost jobs and tax revenue, according to Tuesday’s round of White House announcements,
Rolled out at the meeting of the Interagency Working Group on Coal and Power Plant Communities and Economic Revitalization (Energy Communities IWG), the announcements included:
new guidance from the Treasury Department on the Inflation Reduction Act’s 10% bonus credit for clean energy projects located in energy communities. A new map from Treasury and the IWG shows wide swaths of the country qualifying as energy communities, from Nevada to the Dakotas to Texas and the Mid-Atlantic coal belt in Pennsylvania, Ohio and Virginia;
$16 million in funding from the Infrastructure Investment and Jobs Act for demonstration projects in North Dakota and West Virginia that “will extract and separate rare earth elements and other critical minerals from coal ash, acid mine drainage and other mine waste,” according to a White House fact sheet;
another $450 million from the IIJA for additional clean energy demonstration projects on current and former mine lands. DOE estimates the U.S. has 17,750 mine land sites, covering 1.5 million acres, which could produce up to 90 GW of clean energy; and
an interagency memorandum of understanding that will set up rapid response teams to provide outreach and technical support to energy communities to ensure they can access funding and other opportunities.
The announcements are part of President Biden’s bigger drive to highlight the successes of his “Investing in America” agenda and the programs and projects funded by the IIJA and IRA. The IWG has “driven more than $14.1 billion in federal investments to energy communities” over the past two years, according to a report also issued Tuesday.
National Climate Adviser Ali Zaidi | Energy Communities IWG
“There’s enormous untapped potential in these communities, from fossil fuel workers whose skills we need to build the industries of the future, to existing facilities that can be retooled and repurposed, to local entrepreneurs and universities … working to attract talent and investment,” White House Senior Adviser John Podesta said at the IWG meeting.
National Climate Adviser Ali Zaidi stressed the importance of creating new jobs that will let residents stay in their coalmining communities. “It’s not just … we say, ‘Hey, we’ve got a job for you in a completely different geography,’” Zaidi said.
“It’s the places that folks have invested in, not just in this generation, but for many a culture, a community, a sense of place and purpose and dignity. That’s all embedded in geographies … places [that] will be the venue where we come up with the ideas that we forge together and implement together,” he said.
‘An Extra Dime’
The 10% bonus tax credit for energy communities could be a major draw for investment in energy communities, adding 10% on top of any other investment or production tax credits the IRA provides for clean energy projects, Treasury Secretary Janet Yellen said.
“Many energy communities have the knowledge, the infrastructure and the resources to take advantage of the clean energy transition, but in many cases these communities could benefit significantly from an initial public investment to jumpstart that process,” she said.
Treasury Secretary Janet Yellen | Energy Communities IWG
The bonus credit “generally means that if you’re a solar farm operator in a coal community, you get an extra dime on the dollar for your investment in a new facility,” Yellen said, adding that developers will also have to pay prevailing wages and have registered apprenticeship programs to take full advantage of the bonus.
The IRA provides a 30% investment tax credit or a 2.75-cent/kWh production tax credit for renewable energy projects. The impact of adding the 10% bonus credit to those incentives “is just going to be incredible,” said Tom Cormons, executive director of Appalachian Voices, a community nonprofit in Virginia. It will provide the boost needed to bring on “scores of projects that otherwise would not have penciled out or gotten over the finish line in places where it can be a little harder than others to get clean energy projects going on the ground,” he said.
The IRA provides a particularly broad definition of energy communities, and the Treasury Department guidance spells out the various ways a community can quality. Any community where a coal mine has closed since 2000, or any county adjacent to that area is identified as an energy community, as are areas where a coal-fired power plant has closed since 2010. So are “brownfield” sites where construction of any new projects or repurposing of existing infrastructure “may be complicated by the presence or potential presence of a hazardous substance, pollutant or contaminant,” the guidelines say.
Communities can also qualify if they have a minimum of .17% employment or 25% of tax revenue directly related to fossil fuel production or use and an unemployment rate higher than the national average.
Echoing Cormons, Hy Martin, chief development officer for D.E. Shaw Renewable Investment, said the IRA’s clean energy tax credits, including the 10% bonus, have “catalyzed several hundred millions of dollars in investment that we have committed to communities, specifically coal communities across the country …
“Without that kind of clear policy signal, those commitments wouldn’t have been made by us and certainly by our peers in the private sector,” Martin said.
‘Irresistible for Investment’
Energy Secretary Jennifer Granholm | Energy Communities IWG
Energy Secretary Jennifer Granholm also talked up the impact of the IRA, saying the law’s tax credits and other incentives are making energy communities “irresistible for investment.”
But Granholm’s main announcements Tuesday came with funding from the IIJA, the $16 million for the North Dakota and West Virginia demonstration projects and the $450 million for clean energy projects on mine lands.
The $16 million will be evenly split between North Dakota and West Virginia and used for “front-end engineering and design studies to determine how to extract critical minerals from coal mine waste streams, of which there are an abundant amount across the country,” Granholm said.
“Those efforts are going to help us stand up a first-of-its-kind facility that produces essential materials for solar panels, for EVs, for wind turbines … while at the same time cleaning up polluted land and water,” she said.
Sen. Joe Manchin (D-W.Va.) also welcomed the funding, saying that by reclaiming water from mining waste, “we will ensure that we are producing these materials in the cleanest way possible while addressing environmental liabilities.”
The $450 million will target projects using a “range of technologies — geothermal, energy storage, power plants [with] carbon capture,” Granholm said. “They’re going to show us how we can reactivate or repurpose existing infrastructure, like transmission lines and substations, while creating new opportunities for economic development.”
Granholm stressed that applicants chosen for this funding will also have to submit community benefit plans to ensure that projects are “designed in a way that uplifts the whole community.” Community benefits will constitute 20% of the scoring for the awards.
“We don’t think these projects are going to be successful unless they have meaningful community and worker engagement,” she said.
Concept papers for the $450 million opportunity are due May 11, with full applications to follow on Aug. 31, according to DOE.
Independent power producer Nautilus Power asked FERC to dismiss PJM’s penalties against three of its generators that failed to operate during the December 2022 winter storm, saying two of the units were not needed to address capacity shortages and that the RTO failed to implement processes to address natural gas supply constraints.
In a complaint filed March 30, the company argues that the generators had not been properly notified that they would be required to go online and that the penalties would not incentivize any behavior that could avoid future charges.
The company wholly owns Essential Power, which owns a 383-MW natural gas generator in Lakewood, New Jersey, and Essential Power Rock Springs, which owns a 773-MW gas-fired generator in Rising Sun, Maryland. It has majority ownership of Lakewood Cogeneration, which owns a 237-MW generator with dual fuel capability. All three plants were hit with penalties related to Winter Storm Elliott on Dec. 23 and 24 (EL23-53).
“Under these circumstances, where the adverse impact to PJM was minimal, where the Nautilus Entities were not needed by PJM during many intervals of both [performance assessment intervals], where PJM itself failed to follow its own emergency procedures and therefore prejudiced the Nautilus Entities’ ability to respond to PJM directives, and where the imposition of nonperformance charges on the Nautilus Entities will impose a significant economic burden on the Nautilus Entities, the nonperformance charges that PJM intends to impose on the Nautilus entities are unjust and unreasonable,” the complaint states.
PJM has stated that it expects at least $1 billion in capacity performance penalties to be assigned to generators following a peak of 46,000 MW of outages during Winter Storm Elliott, with the single largest cause being gas-fired generators being unable to procure fuel. PJM and stakeholders have raised concern that the scale of the penalties could lead to widespread defaults, leading PJM to ask FERC to permit a longer payment period of up to nine months. (See PJM Weighs Options for Winter Storm Elliott Follow-up.)
All three generators listed in the complaint had not cleared in the day-ahead market and were not listed as being required in the reliability assessment and commitment (RAC) period and were unable to obtain fuel when they were called on by PJM to operate during the storm. Though the Lakewood generator possesses dual fuel capability, it was not able to procure the natural gas it needs for startup.
The complaint requests that FERC prevent PJM from assessing nonperformance charges to Essential Power and Rock Springs after 12 p.m. on Dec. 24, arguing that they were not needed during those periods. It also requests that Rock Springs not be subject to charges on Dec. 23 and for the first two hours of the Dec. 24 performance assessment interval (PAI), during which it states that it was not scheduled to operate.
As an alternative remedy, the complaint asks that all three generators be relieved of penalties for settlement intervals in which they were not running during both the Dec. 23 and 24 PAIs.
The argument that Essential Power and Rock Springs were not needed for reliability stems from LMPs falling around noon on the 24th, with prices being half what they were earlier in the day by 1 p.m. The complaint argues this shows that shortage conditions had alleviated and the maximum generation emergency and corresponding PAIs should have been lifted. However they remained in place until 10 p.m.
“Imposing substantial nonperformance charges on OPP and Rock Springs for nonperformance during intervals when they were not needed by PJM is highly unreasonable and arbitrary,” the complaint states.
The complaint also states that Rock Springs was not contacted for dispatch for two hours after the maximum generation emergency was initiated at 4:25 a.m. on Dec. 24, which it argued was an intentional decision by PJM dispatchers due to the likelihood that the generator coming online would have exacerbated a constraint and could have led to an outage. It noted that PJM has previously rejected self-schedule requests for that reason.
Nautilus argued that PJM failed to provide enough notice for generators to procure fuel by not declaring a winter weather alert giving generators 24 hours’ notice that they would be expected to be available. Instead it said the RTO “abruptly” jumped into emergency conditions and left gas generators to compete for limited pipeline capacity with elevated fuel costs. It argued the justification for high nonperformance penalties when the construct was proposed in 2015 was that generators would be given sufficient ability to prepare for emergencies and the risk would incentivize behaviors to avoid being charged.
“In its initial filing of the nonperformance charge proposal, PJM itself cited this progression of incremental steps as a justification for the severity of the proposal … However, in the course of the two days at issue in this complaint, PJM skipped right over these interim steps, going from a preliminary notice that a cold weather alert might be needed (that is, the cold weather advisory) straight to an emergency action,” the complaint argues.
It also said that due to firm day-ahead fuel service being sold in a package over weekends and the timing of the holiday weekend, generators would have had to purchase four days’ worth of fuel or vie for scarce single-day packages that might not be filled by pipeline operators giving preference to residential and commercial customers. Since both the PJM dispatch and the forecast the RTO relies upon, as well as pipeline operator practices, are outside of the control of generation owners, the complaint argues that the charges don’t incentivize any behavior other than potentially exiting the capacity market.
“The existing rules allow burdensome nonperformance charges to be imposed on natural gas-fired generators in circumstances where those generators have no reasonable opportunity to avoid those charges,” the complaint says.
SPP said Tuesday that 31 utilities, public interest groups and other entities have officially joined the grid operator’s effort to develop and launch its Markets+ offering in the Western Interconnection.
The parties met an April 1 deadline to execute agreements allowing their participation in the first phase of the market’s development. That effort began last month after funding reached critical mass a month ahead of schedule. (See SPP Moving Quickly on Markets+’s Development.)
The funding agreements also give the participants voting rights in the first developmental phase.
“We’re encouraged to see such a varied group of entities taking an active role in the development of Markets+,” Antoine Lucas, SPP’s vice president of markets, said in a statement. “From utilities looking to improve reliability and reduce energy costs, to public interest organizations advocating for natural resources and policy outcomes, these diverse perspectives are a benefit to the value, effectiveness and efficiency of our products and services. There’s room for all those voices to have a say in the design and implementation of our market.”
SPP said that in exploring the potential benefits of regional day-ahead and real-time markets in the West, it has worked to ensure its market design would reflect all stakeholders’ perspectives. It recently rolled out the Markets+ independent governance structure that “gives meaningful say to several key audiences.” (See SPP Unveils Markets+ Governance Structure.)
Those audiences include:
utilities that serve load or own generation and will have assets participating in Markets+;
organizations representing public interests, and other groups that won’t participate in the market but will be affected by its design and operation; and
Western states and regulatory bodies, which can nominate representatives to a state committee.
Markets+ participant and stakeholder representatives will collaborate in committees and working groups to develop market protocols and governing documents that SPP will eventually file with FERC for approval.
“SPP’s independent governance, past experience accommodating participation of federal power marketing administrations and commitment to engage with stakeholders to ensure a balanced market between buyers and sellers are all encouraging aspects of Markets+ going into this next phase of development,” Public Power Council CEO Scott Simms said. “PPC looks forward to working with SPP and other stakeholders to further develop Markets+ and to build on the promising service offering developed last year.”
Visual representation of NYISO’s proposed interconnection queue window approach | NYISO
