FERC last week approved a partial settlement that resolves some city and state commissions’ longstanding allegations of overcharging at Entergy’s (NYSE:ETR) Grand Gulf Nuclear Station.
Under the agreement approved April 4, Entergy subsidiary System Energy Resources Inc. (SERI) will pay an $18 million refund and commit to rate reductions that go back to October 2022 (ER23-435).
SERI operates and owns 90% of the 1,400-MW Grand Gulf plant in Port Gibson, Miss. It sells the plant’s output under a unit power sales agreement (UPSA) to Entergy’s Arkansas, Louisiana, Mississippi and New Orleans affiliates.
The refund will be split among the Louisiana (26.86%), New Orleans (32.87%) and Arkansas (40.27%) subsidiaries. Mississippi regulators last year accepted a separate settlement offer from Entergy that resolves the state’s complaints about Grand Gulf’s performance and billing. (See Entergy Offers Regulators $588M to End Grand Gulf Complaints.)
The partial settlement also contains provisions that reduce the Entergy companies’ monthly UPSA bills’ base rate.
Louisiana, New Orleans, Arkansas and Mississippi regulators have for years accused Entergy and SERI of mismanaging the nuclear plant, massaging accumulated deferred income tax numbers to overcharge customers, overbilling ratepayers for Grand Gulf’s sale-leaseback arrangement, and recovering the costs of lobbying, image advertising and private airplane use in the sales agreements’ rates.
The UPSA bills will now exclude recovery of executive bonuses, restrict advertising cost collections to only safety-related advertising, and limit the recovery of employees’ air travel costs to those directly linked to SERI.
Revised SERI UPSA bills will also include a line item that reduces the base rate for the advanced collection of Grand Gulf’s semiannual lease payments. FERC trial staff argued that the management company should “return to its customers the monthly lease payments’ time value that is held until SERI makes the lease payment.”
As part of the deal, SERI will include money pool borrowings in its short-term debt, which is used to work out its cost-of-capital calculation used in the UPSA.
SERI has also committed to making additional refunds, with interest, in UPSA bill credits to the Entergy companies for a 15-month period dating back to September 2020. Those refunds will reflect UPSA formula rate reductions.
Additional generator companies have filed complaints with FERC alleging that PJM violated its governing documents during its response to the December 2022 winter storm in its assigning of nonperformance penalties.
Independent power producer Nautilus Power filed one of the first complaints March 30, arguing that PJM did not follow the correct process for initiating an emergency, depriving gas generators of notice that they could be called on and to procure fuel. (See IPP Asks FERC to Dismiss PJM Performance Penalties over Elliott Outages.)
Nautilus’ filing was followed by several more in the following week, alleging that PJM violated its tariff by exporting energy during emergency conditions, failing protocols for declaring an emergency and penalizing generators not scheduled.
ComEd Generators: Region was not in Emergency
Several independent power producers within the ComEd zone filed a joint complaint arguing that conditions in the region throughout most of the performance assessment interval (PAI) during the storm, also known as Winter Storm Elliott, did not warrant emergency conditions and that the penalties faced by generators there should be eliminated (EL23-54).
The companies argued that PJM was exporting as much as 6,000 MW to the Tennessee Valley Authority and the SERC Reliability footprint during emergency conditions, in violation of the Operating Agreement and suggesting that emergency procedures were not warranted. It argued that there was not a capacity shortage by pointing out that LMPs were below the rest of PJM throughout much of the assessment intervals.
“Simply put, no emergency conditions existed in the ComEd zone: There was no capacity shortage in the ComEd zone, prices were low, and constraints precluded the generation in the ComEd zone from helping the rest of PJM and, if anything, signaled to PJM to back down in-zone generation. Further, PJM committed several tariff, OA and manual violations, such as failing to curtail exports,” the IPPs said.
Prior to the declaration of the Dec. 24 PAI around 4:30 a.m., PJM’s net exports to TVA and SERC were approximately 5,000 MW. Exports had fallen to under 1,000 MW by 6 a.m. but began to increase three hours later and had reached 4,000 MW by noon.
Drawing off an affidavit supplied by Scott Harvey of FTI Consulting, the complaint said that reserve shortages “disappeared” when exports were cut and argued that that shows they were the driver of the shortages leading to the emergency declaration.
“Dr. Harvey concludes that the effect of the increases in exports on PJM prices and reserve levels suggests that emergency actions in other regions of PJM may have been needed (though not needed in ComEd) precisely because of the exports that were supposed to be curtailed before emergency actions were invoked,” the IPPs said.
Solar Developer Argues Penalties Run Contrary to Purpose
SunEnergy1, which operates about 1 GW of solar generation, filed a complaint arguing that the nonperformance charges and the overall Capacity Performance construct are unjust and unreasonable by creating penalties that do not incentivize a change in behavior for solar units that have no capability to operate at night. The company said that 87% of the charges it has been assigned were accrued during evening hours (EL23-58).
The company argued that both PJM and FERC discussed the need for incentives for capacity resources to invest in performance during emergencies as one of the justifications for creating CP following the 2013/14 polar vortex. PJM’s effective load-carrying capability (ELCC) structure already accounts for solar resources’ output fluctuations in class accreditations, the company argued, and imposing penalties could drive resources out of the capacity market.
Because PJM staff are aware of and plans around the limitations of solar, the company argued that nighttime operations should be treated similarly to planned outages.
“How does it further the goals of PJM’s capacity market, and how is it just and reasonable, to excessively penalize such resource for nonperformance during times when such resource is physically incapable of performing ― particularly when PJM’s operators know such resource cannot operate during such times, and do not rely upon it to operate during such times in order to maintain the reliability of the bulk power system?” SunEnergy1 said.
The complaint asks FERC to “direct PJM to explore more holistic and comprehensive reforms to its capacity market design to specifically ensure that the risks of participating in PJM’s capacity market do not materially outweigh revenue opportunities for solar resources in PJM’s capacity market moving forward.”
Generator Coalition Files Complaint
Several companies representing 27,500 MW of generation jointly filing as the Coalition of PJM Capacity Resources argued that PJM should be required to determine which resources would not have been dispatched had the RTO curtailed non-firm exports during the PAI and excuse them from penalties. The group also recommended that FERC require PJM to recalculate the balancing ratio to include all exports and to use those figures to reassess penalties (EL23-55).
The coalition said PJM’s low load forecast resulted in insufficient capacity being procured, which the RTO was slow to make up for through reliability assessment and commitment (RAC) runs that did not secure any systemwide capacity on Dec. 22 and less than a third of the forecast error the next day.
It also argued that PJM continued exporting throughout emergency declarations, constituting a tariff violation and effectively holding generators to the capacity needs of outside regions.
“To be clear, complainants do not object to PJM providing assistance to neighboring regions when that assistance is needed and when PJM has available resources to assist (as PJM apparently did during Winter Storm Elliott),” the coalition said. “Rather, complainants object to PJM declaring emergency operations and imposing penalties on PJM resources to support other systems.”
Talen Generators not Dispatched
In addition to joining the coalition’s complaint, Talen Energy filed its own, arguing that PJM is seeking to improperly assign penalties against several of its generators that were available to operate but were not dispatched (EL23-56).
“These generators had available staffing, access to fuel and start times that would have allowed them to provide power during the Dec. 23 and Dec. 24 PAIs had PJM scheduled them in a timely manner,” Talen said. “Assessing nonperformance charges against the Talen PJM generators in this circumstance would amount to penalizing them for following PJM’s instruction, which was to remain ready to operate if dispatched.”
Talen argued that generators are normally excused from CP charges if they are not dispatched or are scheduled down by PJM, with an exemption to allow penalties for units not scheduled solely based on their operating parameter limitations or market-based offers that are higher than their cost-based offers. This was not the case for at least two of the company’s generators, as similarly configured facilities in its fleet were dispatched, it said.
“Simply put, PJM made a judgment call, or perhaps even a mistake, at the time of the PAIs and did not dispatch Martins Creek,” Talen said referring to its 1,719 MW gas-fired generator. “PJM must take responsibility for its own management of the grid during Winter Storm Elliott — including its decision not to dispatch the Martins Creek units.”
Lincoln Power Declares Bankruptcy Because of Penalties
Delaware-based Lincoln Power declared bankruptcy on March 31 because of about $39 million in nonperformance penalties assigned to two of its combustion turbine generators: the 480-MW Elgin Plant and the 330-MW Rocky Road Plant, both in Illinois. Like Nautilus, the company is an affiliate of Cogentrix Energy Power Management.
In an affidavit filed with the U.S. Bankruptcy Court in Delaware, Chief Restructuring Officer Justin Pugh stated that PJM has been withholding $350,000 weekly from the company’s revenues and demanding about $2 million in collateral. While it has been disputing the validity of the penalties with PJM, Pugh told the court that the company cannot continue to operate through the withholdings.
Lincoln has been experiencing a liquidity crunch because of low clearing prices in recent capacity auctions, Pugh said, but the company likely would have otherwise remained profitable.
“While such liquidity constraints are substantial, the debtors could have sustained their current debt load had their business not been subjected to numerous issues caused by a severe winter storm that struck and inflicted record cold temperatures across most of the United States, from Dec. 22, 2022, through Dec. 27, 2022,” he said.
New Jersey’s permanent community solar program should approve projects with a combined capacity of at least 750 MW in its first five years, according to a straw proposal released by the state’s Board of Public Utilities (BPU) last week.
The proposal resists the effort by some legislators to dramatically ramp up capacity in light of what the plan calls the “tremendous market response” to two pilot programs in 2019 and 2021. Instead, it calls for much the same capacity allocation of 150 MW per year discussed in the past, with a 50% hike in available capacity suggested in the third and fourth years of the program to make up for any shortfalls in earlier years.
The much anticipated straw proposal limits the maximum size of projects eligible to participate in the program to 5 MW. It also requires eligible projects to be developed on rooftops, carports and canopies over impervious surfaces, contaminated sites and landfills and man-made bodies of water.
The proposal rejects the selection strategy used in two pilot community solar programs of awarding capacity through a competitive process. Instead, projects will be picked on a first come, first served basis, providing they meet heightened requirements to ensure readiness for development.
The release of the proposal, which will be the subject of a public hearing on April 24, provides insight into how the state wants to push forward a market sector that state officials regard as among the most successful in the state’s renewable energy portfolio.
In his push for New Jersey to reach 100% clean energy by 2050, Gov. Phil Murphy (D) has set a goal for the state to have 32 GW of solar by 2050, about 34% of the state’s generating capacity. The state had 4.36 GW of installed solar capacity at the end of February, according to the latest BPU figures available, and agency leaders see community solar as a potential growth driver.
“It is important to highlight the tremendous market response and overall interest in developing community solar projects,” the proposal states, noting that the board received more than 650 applications for the two temporary pilot programs.
Chasing Solar Goals
Community solar projects target users who either cannot or do not want to have solar on their roofs but seek to support a clean energy initiative. To make the projects work, the developer must sign up subscribers, who commit to using the clean energy and in turn receive a credit on their utility bill, reducing the electricity cost by a set percentage.
The BPU approved 45 projects totaling 75 MW in the first community solar pilot in 2019, and two years later approved 105 community solar projects totaling 165 MW in the second pilot. Both solicitations were substantially oversubscribed, with 412 applicant projects in the second phase and 252 applications in the first. (See NJ Selects 165 MW in Community Solar Projects.)
The interest in the program prompted two lawmakers to introduce a bill, S3123, that would have more than tripled the size of the planned permanent community solar program to 500 MW a year. The BPU had set an early target of 150 MW a year for the permanent program, for a total of 750 MW over five years. Some stakeholders also suggested that the program should award 300 MW of capacity in the first year of the program, to make up for the fact that the BPU had initially planned to have three pilot programs but abandoned the final pilot to create the permanent program.
But the BPU opposed the bill, saying the sector and grid could not handle such a rapid expansion. In fact, only 25 community solar projects in the two pilot solicitations have been installed so far, according to recent BPU figures. (See NJ BPU Opposes Community Solar Program Expansion.) And the agency has stuck to its original plan — albeit increasing the goal slightly by saying it will allocate “at least” 150 MW a year — and making some changes to program rules and requirements.
Encouraging LMI Participation
The straw proposal suggests that the state maintain the pilot program requirement that 51% of the subscribers to each community solar projects be reserved for low- and moderate-income households. That system has so far resulted in projects signing up more than 6,000 subscribers who have received more than $6 million in bill credits and saved more than $1 million, according to the proposal.
But it recommends that the agency relax pilot rules that required consumers to provide documentation of their income if they wanted to subscribe as low- or moderate-income participants.
In response to concerns from solar developers over the difficulties of getting documentations, the BPU recommends that such participants be allowed to self-attest to their income through the use of a standardized form.
“Staff believes that potential community solar subscribers should not be dissuaded from participation by having to produce a tax return, EBT card, or other documentation of income,” the proposal says. “Individuals may feel uncomfortable providing this personal information to subscriber organizations, and there is concern about subscriber organizations retaining such data.”
Replacing Competitive Selection
The proposal also changes the selection process by which projects are picked for the program. The agency concluded that the competitive process used in the two pilots, in which applicants were evaluated and ranked by the BPU staff, though effective, was also too time-consuming and so complicated that it took nine months to complete the process. During that time, some projects withdrew because the lease on the proposed project site expired, the proposal said. (See Slow Progress of NJ Community Solar Pilot Draws Fire.)
The proposal instead suggests that projects be picked on a first come, first served basis, and that the quality of the projects would be ensured by raising “minimum maturity requirements” — such as having applied for certain permits and being viable for interconnection. Those details would ensure the selected projects had not been rushed too quickly into the application process and would be likely to succeed if picked.
That raising of the bar might help alleviate the scenario in the pilot programs in which only 44% of selected projects reached commercial operation before the BPU’s conditional approval expired, the proposal suggested.
“All projects would be required to meet certain criteria … to ensure key policy preferences are met,” the proposal says. “With strict prerequisites for application, the potential pool of applicants will be limited to those that are considered to be most beneficial from a policy perspective and are most mature and able to make progress toward completion soon after awarding.”
“An open enrollment process fairly allows for a diversity of projects to participate without being constrained by a scoring process that may favor certain types of project elements or developers,” the proposal states. “This procedure is more sustainable for a permanent program and limits the administrative burden associated with a competitive solicitation process.”
The proposal also offers a solution to a two-year-old discussion about how best to bill subscribers so that the program is simple and attractive to ratepayers. The proposal rejects the option that ratepayers receive separate bills for electricity from the utility and a community solar subscription from the developer, noting the confusion and increased risk of non-payment. (See Billing Key to NJ Community Solar Growth.)
Consolidating those elements into a single bill handled by the electric distribution company would be simpler, and “customers would be better served having only a single bill,” the proposal says.
Interconnection queues around the country are filled with over 2,000 GW of new generation, dominated by solar, storage and wind, according to updated analysis from the Lawrence Berkeley National Laboratory released Thursday.
The 2,000 GW number is up 40% from a year earlier, according to LBNL, which studied the seven ISO/RTOs and 35 additional utilities outside organized markets that altogether serve 85% of total electric load in the country. Over 10,000 projects representing 1,350 GW of generation and 680 GW of storage are in the queue.
The zero-carbon generation in the queues alone totals about 1,260 GW, which would be about equal to the total amount of generation operating around the country today.
The growth in projects reflects the real interest in transitioning the industry to a cleaner future, but it also represents growing backlogs as projects take five years to get through the processes, the lead author of the study, Joseph Rand, an energy policy researcher at LBNL, said in an interview.
“The queues illustrate both the opportunity and the challenges of rapid electric sector decarbonization in the United States because we see this unprecedented development interest in new clean energy,” Rand said. “But then, on the other hand, we do see the backlogs and delays and high withdrawal rates.”
Some of the trends in the queue are worthy of concern, but others represent a real opportunity, he added.
The continued growth in the queue reflects the reality that the industry wants to build a lot of renewables, which is because of demand from state mandates and commercial customers, Brattle Group Principal Johannes Pfeifenberger told RTO Insider. But only a fraction of those projects will ever lead to steel in the ground — and the fact that it is so hard to get through the queue contributes to that growth.
“You never know which location on the grid is a good location, or which is a bad location,” Pfeifenberger said. “So, if a developer hopes to develop 1,000 MW of renewables, they might submit 3,000 MW of interconnection requests, hoping to find a good location where it is cost-effective to interconnect.”
While the overall amount of capacity continued to rise in the year, the number of new requests fell from 2021, which LBNL said was caused by both CAISO and PJM pausing new applications as they dealt with significant backlogs that led to new rules in both markets. CAISO’s pause ends this year, but PJM will not take any new requests until 2025.
“The interest in solar, storage and wind is so widespread across the country that even if these two leading markets dip down or pause for a year, it’s surging everywhere,” Rand said.
PJM had the largest number of active projects in its queue at 3,042, followed by the non-ISO West at 1,879, MISO at 1,734, ERCOT at 902, and the Southeast (outside of ISO/RTOs) at 830. By total capacity the numbers are different — with the non-ISO west at 598 GW, MISO at 339 GW, and PJM at 298 GW.
Queue requests by technology type from around the country | Lawrence Berkeley National Laboratory
Solar represents the largest technology by volume in the queue, with 947 GW of the total, followed by storage at 680 GW. Both figures include hybrid projects made up of both technologies.
Solar is widespread across the country, but LBNL noted that both the Northeast and SPP had less of the resource type waiting to connect to the grid. Most of the wind is in the West, or offshore from the East Coast, while storage is centered around the CAISO and the West — although it is rapidly expanding to the east as well.
Offshore wind makes up 113 GW, which is more than enough to meet the Biden administration’s goal of 30 GW by 2030.
Most Projects Drop Out
While the capacity in the queues would be enough to decarbonize the power sector if everything were built, that is not going to happen. For all the projects in queues between 2000 and 2017, just 21% (and 14% of capacity) entered service, LBNL said. The success rate of more recent proposals cannot be determined yet.
More recent projects are dropping out later in the queue process, which exacerbates delays for those left behind as grid operators must do significant restudies to determine who must pay for the transmission upgrades required to reliably interconnect generation.
FERC is working on a couple proposed rules meant to help the process. One would update the pro forma queue rules (RM22-14) to include revisions such as giving priority to projects farther along their development paths, and another on regional planning that would require planners take into account future sources of generation (RM21-17).
FERC’s reforms should help to streamline the queues a little bit, but they are far short of progress in Europe, which is generally farther along in its grid transition, Pfeifenberger said. He said ERCOT has a similar system to that of the United Kingdom and some other European countries, which can move renewables through the queue at a much quicker rate than the current FERC-regulated processes, which were designed over 20 years ago to connect natural gas plants to the grid.
Rand believes that, together, FERC’s NOPRs can have an impact on the queue and its backlog, but they both need to become final rules for that to happen.
“Either one of them in isolation just wouldn’t be sufficient to make a big dent in this problem,” Rand said. “But combined, they might they definitely have real potential to unlock this queue.”
‘Connect and Manage’
The interconnection NOPR would adopt on a national basis changes that some organized markets and individual utilities have already made to speed up their queue and minimize speculative projects, but it will not lead to new transmission being built to resource-rich areas. The transmission planning NOPR would handle that second part, but one key issue remains, Rand said.
“That’s cost allocation: Who pays?” Rand said. “If you’re a generator, trying to interconnect to the grid system, how much do you pay for the interconnection upgrades? And what determines what fraction that you pay? And what types of upgrades you pay for? That’s not really addressed in those two NOPRs, and it’s a very sticky issue that I think leads to a lot of projects ultimately withdrawing from the queue.”
The U.K. and ERCOT both use a process called “connect and manage,” compared with the “invest and connect” process used in FERC-regulated RTOs, and when the British adopted that system their queue times were cut from five years to one year, Pfeifenberger said.
“The idea is you let people interconnect. It might be non-firm, they might get curtailed, but then use … congestion management or proactive transmission planning, where congestion makes it worthwhile to upgrade the transmission system,” Pfeifenberger said.
Enel North America, a subsidiary of the Italian utility that develops renewables and is a major player in demand response, has written a whitepaper endorsing the basics of connect and manage, and it has made similar arguments to FERC as it weighs reforms, he added.
ERCOT does not have the regular, proactive transmission planning process to compliment the “connect and manage” process, Pfeifenberger said. The process has not been adopted elsewhere in the U.S. because it represents a major change from the normal of doing business.
“It’s very hard for an ISO to change it in the connection process,” Pfeifenberger said. “First of all, the ISO may not want to because they think the interconnection process is what is necessary. But even if they wanted to, they have to go through the stakeholder processes; they have to change the tariff; they have to get FERC approval. But I think it’s mostly a mindset issue, that the ISOs just like the way they’re doing it.”
ERCOT does have a record of more quickly connecting resources to the grid, but Rand said it was not a silver bullet because projects there face higher risks of curtailment as the Texas grid operator just offers energy-only service as opposed to the network interconnection service in other markets.
“You can connect without paying those upfront, interconnection upgrade costs,” Rand said. “But you face a curtailment risk. You face a lot more curtailment risk, perhaps, than you might get in MISO if you have a network interconnection service.”
CAISO’s Western Energy Imbalance Market pushed into a small part of Texas on Wednesday with the addition of El Paso Electric, which occupies the westernmost corner of the Lone Star State.
The Western Area Power Administration’s (WAPA) Desert Southwest Region and Avangrid (NYSE:AGR) also joined the WEIM on Wednesday, with the latter becoming the first generation-only participant in the interstate market.
The latest additions mean the WEIM now encompasses approximately 80% of electricity demand in the Western Interconnection and has a presence in every state in the West except Colorado. (Three Colorado utilities that had planned to join the WEIM instead joinedSPP’s Western Energy Imbalance Service last year.)
“Because of their varied resources and location, these new WEIM partners further strengthen regional collaboration and coordination in the West,” CAISO CEO Elliot Mainzer said in a news release. “It’s been a pleasure to work with them in support of their effort to achieve enhanced operational efficiencies while providing cost savings to their customers.”
WAPA’s Desert Southwest Region, based in Phoenix, “sells power in Arizona, Southern California and portions of the Southwest to wholesale customers such as towns, rural electric cooperatives, public utility and irrigation districts; federal, state and military agencies; Native American tribes; and U.S. Bureau of Reclamation customers,” WAPA says on its website. It operates transmission lines to deliver power from the Hoover Dam and the Parker-Davis Project, which includes two other hydroelectric dams on the Colorado River.
EPE is a regional utility that operates generating resources — including wind, solar and natural gas plants — and transmission and distribution systems that serve more than 460,000 customers in a 10,000-square-mile area of the Rio Grande Valley in West Texas and southern New Mexico.
Avangrid has operations that sprawl across 24 states. Avangrid Renewables, the arm of the company that joined the WEIM, operates a generation-only balancing authority area in Oregon and Washington that connects to the Bonneville Power Administration’s transmission system.
“Avangrid owns and operates 18 generation facilities and provides balancing services for one third-party generator, which are made up of primarily wind resources within the BAA,” CAISO wrote in a June 29, 2022, letter to FERC that accompanied Avangrid’s agreement to join the WEIM. “The total nameplate capacity is 2,763 MW, with an additional four facilities under construction.
“Also sitting within the BAA are pseudo-tied contracted hydro facilities and the Klamath Falls Cogeneration (535 MW) and peaking (100 MW) facilities,” it said.
In a news release Wednesday, Avangrid said that as a WEIM participant, it “will support and strengthen the energy system of 11 Western states with almost 2 GW of installed emissions-free capacity from facilities that the company operates in the region.”
“Joining the WEIM as the first generation-only entity represents a meaningful milestone for the CAISO and for us,” Avangrid CEO Pedro Azagra said in the news release.
Since it began in late 2014, the WEIM has generated more than $3.4 billion in benefits for its participants, including $1 billion in 2022, by supplying lower cost energy and avoiding curtailment of renewable resources.
CAISO has been working to add a day-ahead component to the real-time market. Its Board of Governors and the EIM Governing Body approved the extended day-ahead market (EDAM) proposal on Feb. 1. (See CAISO Approves Day-ahead Market for Western EIM.)
The ISO is developing tariff language that it plans to send to FERC before the end of June.
Maryland’s General Assembly on Tuesday overwhelmingly passed a bill that raises the state’s offshore wind target to 8.5 GW by 2031.
Lawmakers in the House of Delegates passed the Promoting Offshore Wind Energy Resources (POWER) Act on a 100-36 vote.
The state Senate passed a version of the bill on March 17 on a 33-12 vote. The two chambers now must review what the other passed to determine whether a conference is needed before sending the legislation to the governor to be signed.
Gov. Wes Moore (D) expressed support for the 8.5 GW target last week at the Business Network for Offshore Wind’s International Partnering Forum in Baltimore (See: US Offshore Wind Industry Set to Take Off).
“Today is a wonderful day for Maryland’s offshore wind industry as well as the workers and communities that power this industry,” Dan Taylor, regional field organizer for the BlueGreen Alliance, said in a statement. “By passing the POWER Act, Maryland has fast tracked their state towards its clean energy goals and tied good union jobs to future construction and manufacturing in local communities. The POWER Act delivers on the dual promise of good-paying, safe jobs and a reduction of the emissions driving climate change.”
In addition to raising the target, the bill would require the Maryland Public Service Commission to ask PJM to set up another State Agreement Approach planning process for offshore wind transmission, which the RTO did for New Jersey. The PSC would have to reach out to other PJM states to evaluate regional transmission cooperation that could help it meet its offshore wind goals, according to the legislature’s analysis of the bill.
The PSC, or PJM, will have to issue one or more competitive solicitations for transmission projects by July 1, 2025. Additional solicitations could be issued after that, if needed.
The bill requires PJM or the state regulator to study specific transmission solutions, including one that uses an open-access collector system to allow for the interconnection of multiple offshore wind projects at a single substation.
Transmission proposals could include upgrading the existing grid, extending the transmission grid both onshore and offshore, interconnecting between offshore substations, adding energy storage, and using high voltage direct current converter technology to support potential weaknesses in the transmission grid.
Proposals will have to maintain electric reliability, help achieve the state’s offshore wind and other environmental goals, demonstrate benefits to consumers and the environment, and foster economic development and job creation in Maryland.
The PSC will have to pick one or more transmission proposals by Dec. 1, 2027, and then work with the developers, PJM, FERC, potentially other states, and other stakeholders to ensure the lines get built.
If the solicitation does not lead to any beneficial or cost-effective proposals, the PSC can end it without picking one and would then have to notify the legislature of its decision by Dec. 1, 2027.
The Department of General Services will have to consult with the PSC in issuing a sealed procurement for contracts of up to 5 million MWh of offshore wind energy and associated renewable energy credits from one or more projects by July 31, 2024. Contracts of at least 20-year terms would be issued by Sept. 1, 2025, barring unforeseen circumstances that delay the procurement.
The bill also includes language for the 2 GW of offshore wind developments that have already cleared earlier procurements, allowing developers to ask the PSC for an exemption to the requirement that they pass along to ratepayers 80% of the value of any state or federal grants, rebates, tax credits, loan guarantees, or other benefits. Developers must prove that the exemption is needed to meet their contractual obligations.
The North American electric grid remains under threat from “capable adversaries” around the world, staff from the Electricity Information Sharing and Analysis Center (E-ISAC) told a forum hosted by the Texas Reliability Entity on Thursday.
“I think it’s important to consider that in the season of Easter, Passover and Ramadan that there’ll be a number of guardians of the grid watching over us all, making sure the lights stay on and those holidays can proceed peacefully, because suffice to stay, the threat landscape is quite active,” E-ISAC Director Matthew Duncan said during the Talk with Texas RE webinar.
Duncan’s presentation focused on the rise of malware variants, often connected with state-sponsored hacking groups, that target an organization’s operational technology networks, potentially allowing them to affect the target’s physical infrastructure. While most of the malware strains seen in the past could only interfere with entities’ information technology systems, which don’t typically interface with operations, an attack on electric utilities with OT-targeting malware could pose a grave threat to grid reliability.
Among the latest of these new threats is the Bad VIB(E)s malware, detected and named last year by security firm Mandiant. The company describes it as a “malware ecosystem” primarily targeting virtual machines — that is, when a computer is used to provide the functionality of a different architecture — and the computers that control them, also called hypervisors.
Matthew Duncan, E-ISAC | Texas RE
Duncan warned that Bad VIB(E)s, which Mandiant has attributed “with low confidence … to a China-linked actor,” seems to target hypervisors “that are prevalent in IT and OT environments,” and that detecting it may be more challenging than other attacks.
“This type of malware was designed to avoid detection, to avoid your EDR [endpoint detection and response] solutions,” Duncan said. “So you can see the adversaries are evolving to counter the defenses that we put out there to stop them and detect them.”
The good news, Duncan said, is that Bad VIB(E)s does not seem to have been used in any attacks against the U.S. energy sector based on information gathered by the E-ISAC. In this regard it is like another OT-targeting malware strain identified last year by security firm Dragos and dubbed Pipedream, which appeared designed to attack industrial infrastructure. (See E-ISAC Warns of Escalating Russian Cyber Threats.) Mandiant has attributed Pipedream to Russia-sponsored actors; Dragos, as a matter of policy, does not link malware to specific nations.
Also like Pipedream, Duncan noted, the attacker needs access to the target machine to deploy Bad VIB(E)s. However, he said, this does not mean there is no danger; utilities must ensure their staff are vigilant against any potential infiltration attempts while also preparing backup solutions for those times when something gets through.
“I know we all think about cyber hygiene as a very basic and obvious thing to do, but those phishing drills, having your software and hardware enumerated, is really important because you’re essentially protecting the front and the back door,” Duncan said. “Still, mitigations need to be in place inside the house, as it were, on the off chance that they get through those initial screenings.”
Ransomware also continues to be a concern for utilities, Duncan added. While statistics from the FBI’s 2022 internet crime report showed that the energy sector accounted for relatively few victims of ransomware attacks last year, an incident in which the Royal ransomware affected a utility’s supervisory control and data acquisition (SCADA) network provided clear evidence of the seriousness of the threat.
“I think it is important to make the community aware that the adversaries are no longer coming after OT in the abstract,” Duncan said. “It is really important to get … the east-west mitigations inside company networks and utility networks to keep an eye on what might be traversing, so that we can stop adversaries from gaining access and stopping critical operational processes.”
OAKDALE, Wash. — Backers of a proposal designed to attract billions in federal funding to create a hydrogen hub in the Pacific Northwest say their application is set to be submitted this week.
They also express confidence that the region has a good shot to win a piece of the $8 billion being made available by the U.S. Department of Energy to develop four to eight hydrogen production and distribution networks across the country.
“We think we’re perfect because we’re a high-tech hub,” Washington Gov. Jay Inslee (D) told NetZero Insider following a series of speeches celebrating the application at the Confederated Tribes of the Chehalis Reservation.
Four state governments, two tribes and several private sector firms, utilities and unions have created a coalition — the public-private Pacific Northwest Hydrogen Association (PNWH2) — to submit that application. Inslee noted that the coalition’s members range from British Petroleum to the Sierra Club. The four states are Washington, Oregon, Idaho and Montana
“It’ll help us launch a clean energy economy that would be a model for the rest of the country,” said Janine Benner, director of the Oregon Department of Energy and vice-chair of the association’s board.
The U.S. Department of Energy is looking at 22 “encouraged applicants” — meaning finalists — who each have a chance of getting a slice of the $8 billion pie.
Like other applicants nationwide, PNWH2 is being closemouthed about the details of its roughly 1,000-page application. The association believes it can meet a DOE target of producing 50 to 100 metric tons of hydrogen per day.
Chris Green, assistant director of the Washington Department of Commerce and PNWH2 board chair, said the secrecy is an effort to keep the Northwest’s application competitive with those from other regions and also because of several nondisclosure agreements signed with hydrogen companies involved.
The association has trimmed an original 140 Northwest-oriented projects to “a few dozen” to shrink the field to the most technologically advanced and financially feasible, Green said.
Green said PNWH2 is not concentrating on hydrogen cars or stations to fuel them. Instead, he said, “We want to concentrate on the industries that are harder to decarbonize,” including manufacturing, shipping and aviation.
On March 1, Los Angeles-based Universal Hydrogen flew a hydrogen-fueled De Havilland Canada Dash 8-300 commuter plane for the first time for 15 minutes at 3,500 feet around an airfield in Central Washington’s Moses Lake. Inslee cited that as a venture that the coalition wants to help develop.
Coal-to-H2
Participants at the Chehalis Reservation event indicated that another plank in the application is Australia-based Fortescue Future Industries’ intention to build a hydrogen production facility next to the TransAlta coal-fired power plant in Centralia in Lewis County, Washington, the last coal plant in the state, which is scheduled to close in 2025. Fortescue is also a member of the PNWH2.
“We were considered a coal community. We were considered a big polluter. What people don’t realize is that we’re an energy community. Transferring from coal to hydrogen is a natural fix,” said Richard DeBolt, president of the nonprofit Lewis County Economic Development Corp.
Event participants also mentioned Seattle-based First Mode, another PNWH2 member, which is developing a hydrogen fuel cell generator designed to replace diesel engines to power huge vehicles capable of carrying 150 to 290 tons of platinum-laced ore in one trip from an open pit mine to a processing plant in South Africa.
The Cowlitz and Chehalis tribes are also participating in the coalition. So far, the Chehalis tribe is interested in setting up hydrogen fueling stations along Washington Highway 12 north of the reservation in Lewis County, said tribal board Chair Dustin Klatush. The tribe has land that could be used for yet-to-be-determined hydrogen-related projects, he said.
A Cowlitz tribal representative did not elaborate on his tribe’s plans beyond a general interest in developing a hydrogen industry.
The ports of Tacoma and Seattle — also members of the association — are brainstorming development of fuel production facilities, Green said. The Douglas County Public Utility District in Central Washington — another member — is in the final stages of building an electrolyzer complex along the Columbia River to use river water to create hydrogen.
Washington has also signed a memorandum of understanding with South Korea to cooperate on developing hydrogen production and distribution along the North Pacific Rim.
Wednesday’s event gave no clue as to whether the application includes Oregon-based Obsidian Renewables’ plans to build hydrogen production plants at existing industrial parks in Hermiston, Oregon, and Moses Lake. These would supply a proposed pipeline system that would terminate at points in The Dalles, Pendleton and Prineville in Oregon, and in Wenatchee and Spokane in Washington. Another pipeline would extend to Lewiston, Idaho. One connecting pipeline would go through the Tri-Cities, which is the second-most populated area in Eastern Washington behind Spokane.
The association would have to provide matching funds for much of the money it is seeking from DOE.
Most of the Northwest matching funds are supposed to come from the individual companies pursuing hydrogen projects in the application, Green said. The Washington legislature allocated $2 million in potential matching funds in 2022. Another $20 million in potential matching funds are working their way through the legislative session that ends April 23.
At the event, Inslee declared that developing a hydrogen industry will require new engineering, construction, operating and logistical construction jobs. “You can’t have anything more broad-based than a hydrogen hub,” he said.
“This would create tens of thousands of good jobs,” said April Sims, president of the Washington State Labor Council of the AFL-CIO.
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.
