Conversion of the Escalante Generating Station into a hydrogen-fueled power plant would help support continued decarbonization of New Mexico’s electric system, a project proponent told state lawmakers recently.
“When you’re adding solar and wind … you need other resources, other decarbonized resources and clean resources that can help balance that out,” said Justin Campbell, vice president of power and transmission for Tallgrass Energy. “You need that so that the grid is still reliable and power is still affordable. That’s the role that this facility can serve.”
Campbell spoke during a meeting last month of the New Mexico Legislative Finance Committee. The committee spent a half day discussing progress in the state’s efforts to develop a hydrogen economy.
Tallgrass has a majority stake in a company called Escalante H2 Power (EH2), which wants to convert the Escalante Generating Station into a hydrogen-fueled plant. Escalante’s operator, Tri-State Generation and Transmission Association, shut down the 253 MW coal-powered plant in 2020.
EH2 plans to produce hydrogen at the Escalante site through reformation of methane from natural gas. Campbell said 97% or more of the CO2 produced in the process would be captured and stored, resulting in so-called blue hydrogen. The CO2 will not be used for enhanced oil recovery, he added.
Escalante is expected to provide about 265 MW of dispatchable power from hydrogen. Campbell said the hydrogen could also potentially be used in industry or for long-haul trucking.
EH2 is still analyzing the market for clean hydrogen in New Mexico, studying geological CO2 sequestration and looking for the best way to retrofit the Escalante facility, according to a report prepared for the Legislative Finance Committee by one of its analysts.
EH2 plans to eventually switch from blue hydrogen to green hydrogen, produced through the electrolysis of water using clean energy, the report said.
Hydrogen in Aviation
In addition to EH2, other hydrogen-focused businesses are setting up shop in New Mexico, said Alicia Keyes, cabinet secretary for the state’s Economic Development Department.
Universal Hydrogen, a company whose goal is to decarbonize aviation, announced in March that it would build a manufacturing hub in Albuquerque. One of the company’s projects is to develop powertrain conversion kits to allow existing regional turboprop aircraft to fly using hydrogen fuel.
BayoTech, a company that offers hydrogen production, transport, storage and fueling services, is headquartered in Albuquerque. The company’s model is to produce hydrogen at a smaller scale at local hydrogen hubs.
In December, the company announced an agreement to provide hydrogen to New Mexico Gas Co. from a hydrogen hub installed on the gas company’s property. In addition, BayoTech is working with San Juan College on a graduate-level program to train workers on hydrogen production systems.
“Obviously, what is going on here and with Escalante is going to be transformative for this area,” Keyes said.
Four-state Partnership
The business developments come as New Mexico is working with three other states — Colorado, Wyoming and Utah — to vie for a portion of $8 billion in federal hydrogen hub funding. (See Mountain States Partner to Secure Hydrogen Hub.)
Since the partnership was announced in February, the states have assembled an executive committee and working groups for the project and are developing a legal entity that would accept the funds if awarded, New Mexico State University Chancellor Dan Arvizu told the Legislative Finance Committee. New Mexico State is part of a team working on hydrogen hub strategies.
DOE last month released a notice of intent to issue a funding opportunity announcement (FOA) for hydrogen hub funding, with release of the FOA expected in September or October. (See DOE Hydrogen HUB Funding Program Announced.)
“There’s a lot of adjacent industries that will be enabled by having a hydrogen economy that’s robust in our state,” said Arvizu, who formerly headed the National Renewable Energy Laboratory.
Additional infrastructure will be needed, for transmission in particular, for the state to take full advantage of a hydrogen economy, Arvizu said.
Executive Order on Hydrogen
State officials are also working to meet directives of an executive order that Gov. Michelle Lujan Grisham issued in March to launch a clean hydrogen development initiative.
The order directs the Economic Development Department to include hydrogen in the state’s key economic sectors and “support the development of clean and zero-carbon hydrogen production.”
The order also directs the state’s Environment Department and the Energy, Minerals and Natural Resources Department (EMNRD) to craft a proposal for including zero-carbon hydrogen electric generation facilities in the definition of “zero-carbon resources” as used in state law. The proposal would then be considered by the New Mexico Public Regulation Commission.
In addition, the executive order instructs EMNRD to make recommendations on the development of carbon sequestration.
The departments will also provide recommendations to the governor before the 2023 legislative session on how to support a hydrogen industry in the state.
A 15-year-old consensus agreement for development on Maine’s Sears Island highlights potential challenges the Department of Transportation might face for its interest in building an offshore wind hub there.
The former Sears Island Planning Initiative steering committee executed an agreement in 2007 that said any future development in the Port of Searsport should consider Mack Point a priority location over the adjacent Sears Island.
MaineDOT, however, said last fall that, after evaluating four sites at the Port of Searsport, an undeveloped parcel on Sears Island would be its preferred location for an OSW marshalling and fabrication facility and a component staging area. The study also determined that Mack Point could provide support facilities for the Sears Island hub.
“The history and discussion of appropriate uses for the Port of Searsport, including Sears Island, have a long, detailed and potentially contentious history,” MaineDOT Commissioner Bruce Van Note told the recently established Maine OSW Port Advisory Group on Thursday.
MaineDOT established the 19-member advisory group in March to advise the department on port facility planning and development. The advisory group functions as a companion effort to Maine’s OSW roadmap initiative, which includes a working group that is making recommendations for port development.
At the time the Sears Island consensus agreement was signed, OSW was not on the horizon for Maine, but similar activities, such as a marine cargo or container port, were considered viable for the island’s western shore.
MaineDOT “concluded that a … marshalling port facility to support offshore wind does meet the requirements of acceptable uses on Sears Island” as set out in the agreement, Van Note said.
The Maine Department of Transportation’s proposed location on Sears Island for the Searsport Offshore Wind Hub. | Maine Department of Transportation
Steve Miller, speaking on behalf of the Islesboro Islands Trust, disagreed with Van Note during the meeting, saying that identifying Sears Island as the preferred alternative for the OSW hub goes against the planning initiative’s intentions.
“I think it makes sense to give preference to Mack Point, thoroughly exhaust those kinds of possibilities there … and if it’s necessary in a deeper application or in any other way, to then explore the possibility of other sites,” Miller said.
Language in the agreement relating to what is acceptable for development on Sears Island raises certain questions, according to Miller. For example, he said that the agreement allows “compatibly managed marine transportation, recreation, education and conservation” as appropriate uses for the island, but it offers no definition of “compatible.”
While Miller was uncertain whether the consensus agreement is legally binding, he said it represents an opportunity for the state’s institutions to build trust with residents.
“The constituents that I represent are eager to see this offshore wind initiative get legs in the right time at the right place, but there’s very, very deep concern about the negative impacts to Sears Island and Upper Penobscot Bay,” he said.
Conservation
While the Sears Island Planning Initiative set out to determine the best use of the island, the resulting consensus agreement did nothing to solve the Sears Island “saga,” David Gelinas, a Penobscot Bay pilot and steering committee member, said during the meeting. Instead, it “kicked the can down the road 15 years” by calling for the permanent conservation of two-thirds of the island without setting a clear plan for MaineDOT’s development of the remaining one-third.
Former Gov. John Baldacci signed an executive order in 2009 directing MaineDOT to grant a conservation easement for 600 acres of the island, as recommended by the steering committee. The state did not, however, make the conservation “contingent upon getting the necessary permits that would allow the remaining 330 acres ever to be used for marine transportation, which is why we’re here now,” Gelinas said.
The island, he added, can host a variety of uses.
“I wholeheartedly embrace the concept of conservation and recreation uses coexisting with a marine transportation facility on Sears Island,” he said.
The advisory group will meet again in September to consider the state’s proposed purpose and need for an OSW hub and the reasonableness of proposed alternatives for the project.
WESTMINSTER, Colo. — SPP set a new mark for peak demand Monday, wiping out a record that was less than a week old.
The grid operator’s 14-state footprint met 51.4 GW of demand at 4:44 p.m. CT. That betters the previous mark of 51.1 GW set July 5. (See SPP Sets Demand Record amid Midwest Heat.)
The new mark is expected to be as equally short-lived as the previous record. Staff are projecting demand will hit 53 GW next Monday, when forecasters are expecting triple-digit temperatures and muggy weather as a high-pressure ridge moves from the Rockies to the Plains.
“Summer’s not over,” Bruce Rew, senior vice president of operations, told the Markets and Operations Policy Committee meeting Tuesday.
Rew said SPP would remain in a resource advisory until at least Wednesday, “if not longer.” On Wednesday, the RTO extended the advisory for its entire 14-state balancing authority to Friday at 10 p.m. It said this was necessary “because of the persistence of extreme heat, high electricity use across its region and uncertainty in its wind forecast.”
SPP issues resource advisories when it expects extreme weather, significant outages, and/or wind- and load-forecast uncertainty in its service territory. They do not require public conservation.
MISO is insisting to FERC that it’s appropriate to take until 2030 before beginning the complicated task of opening its markets to distributed energy resource aggregators.
The grid operator filed a defense of its Order 2222 compliance plan with the commission last week, calling its proposed effective dates for registration (October 2029) and aggregations’ market participation (March 2030) “reasonable and appropriately tailored for the MISO region.” (See MISO Finalizes Plan for DER Market Participation in 2030.)
This comes after several members, state regulators and stakeholders said they were perplexed as to why MISO couldn’t accept DER aggregations after it replaces its market platform in 2024 or 2025. (See MISO Stakeholders Protest RTO’s Order 2222 Implementation Timeline.)
The RTO reminded FERC that its Order 2222 “recognized regional differences and directed each ISO/RTO to propose an implementation timeline that is reasonable for its respective markets” (ER22-1640).
Responding to the Organization of MISO States’ criticism that its plan is too drawn out, MISO said regulators can encourage participation in existing retail DER programs. The grid operator said retail regulatory authorities “have both the ability and authority to further develop and promote these programs” while MISO develops the systems and software necessary to implement Order 2222’s requirements.
MISO contended the “time between now and 2029 will be best used to work on other market and underlying system enhancements that it believes will make the full DER implementation process seamless and able to provide the most value.”
It also addressed arguments from clean energy and solar trade associations that the lengthy delivery time is tantamount to seeking a waiver of FERC compliance obligations. The RTO said that in addition to completing its market platform replacement, it needs another four years to overhaul its registration and enrollment system that is more than 10 years old. It also explained it must first introduce a multi-configuration resource participation model before it can tackle offers from DER aggregations.
MISO plans to use elements of its electric storage participation plan for DER aggregations. The aggregations must self-commit in the RTO’s markets based on their own forecasts and will be limited to a single pricing node.
Stakeholders on Monday urged New York regulators to defer approval, outright reject or refer to NYISO’s public policy transmission planning process Consolidated Edison’s (NYSE:ED) proposal for a new substation in Brooklyn to integrate up to 6 GW of offshore wind energy (20-E-0197).
The utility would build the Brooklyn Clean Energy Hub on land it already owns adjacent to its Farragut Substation on the East River waterfront, a move it claims would save time and money, and also reduce interconnection costs compared to alternatives.
Stakeholders claimed that Con Ed’s proposal was long on optimism and short on details; complicated risk assessment for offshore wind developers preparing to respond to an imminent state solicitation; and should go through a competitive bidding process.
The Long Island Power Authority (LIPA) said that Con Ed’s April petition did not address the Public Service Commission’s January order that the utility provide specific information regarding why its existing substations cannot accommodate future offshore wind projects.
“The petition discussed and rejected a few alternative points of interconnection (Gowanus and Staten Island) but did not provide a comprehensive review of alternative points of interconnection (POIs) with associated cost estimates. Although the petition discussed the addition of a feeder and ring bus costs as being time- and cost-prohibitive elements associated with transmission interconnection at Gowanus, it provided few details associated with this analysis,” LIPA said.
In addition, NYISO’s Long Island OSW export public policy transmission need (PPTN) solicitation process is nearly complete and may result in a solution that itself creates interconnection headroom, thereby possibly reducing the need for the new hub. “The commission, therefore, should consider deferring its approval of costs of this magnitude until a PPTN proposal is selected,” LIPA said.
LS Power Grid and NextEra Energy Transmission New York reiterated calls for the PSC to refer Con Ed’s hub proposal to the NYISO planning process as a regional transmission project, calls that the commission rejected in its January order. (See NYPSC Mandates Meshed Offshore Tx Grids.)
While agreeing that the commission has significant authority over planning and siting, the NYISO competitive process nonetheless “is a powerful tool to achieve the goal of meeting [state] mandates at the least cost to ratepayers,” LS Power said.
The project as proposed by Con Ed is infeasible and presents significant challenges for OSW developers to permit and construct the necessary transmission lines, said NextEra.
“Con Edison assumes that OSW developers would utilize HVDC cables to reduce the number of cables required under the Verrazzano-Narrows Bridge and will site multiple converter stations near the water in New Jersey, Staten Island and/or Brooklyn. However, under Con Edison’s assumed scenario, the OSW developers would be required to install up to three HVAC cables from each converter station to connect to the hub project. Moreover, Con Edison assumes that the HVAC cables will connect to the hub project by water,” NextEra said.
To accommodate 6,000 MW of OSW generation, five HVDC and 15 HVAC cables will need to be installed in the Upper Bay; that many cables, as well as the requirement to site and install converter stations near the water as Con Ed has proposed, presents significant coordination, permitting and construction challenges, NextEra said.
“Independent developers should not be ignored in considering the Clean Energy Hub and its many surrounding implications,” said Anbaric Development Partners.
Inclusion of the Brooklyn Clean Energy Hub within Con Edison’s 345-kV system | Con Edison
Questioning the merits of interconnecting 4,500 to 6,000 MW of offshore wind “at essentially a single location,” New York City said that a climatic or other extreme event at that location could sever all of the offshore wind connections to the city, perhaps for an extended period of time.
As the state and city become more reliant on renewable resources and shut down its remaining fossil plants, a single interconnection location in Brooklyn for most offshore wind projects “could create unacceptable reliability and resilience risks,” the city said.
Con Ed also “creates a false sense of urgency” to support expedited approval of its petition, claiming the project is the only one that can be in service by 2027, LS Power said.
Even if the project could be completed by 2027, which is far from certain, there would not be anything to connect to it in that year. Rather, an OSW generator selected in the upcoming New York State Energy Research and Development Authority (NYSERDA) solicitation will most likely not be in service until after 2030, LS Power said.
The table lists NYISO published costs of interconnection for major generation facilities as compared to the Brooklyn Clean Energy Hub. | Con Edison
The New York Offshore Wind Alliance (NYOWA) said the commission should initiate a competitive procurement that examines the costs and benefits of a wider set of solutions, which should run in parallel with the third NYSERDA OREC solicitation, scheduled to be released imminently.
Developers preparing for the upcoming solicitation have been working to identify and de-risk interconnection options, and those efforts should not be overridden, NYOWA said.
Con Ed identified the site of the Hudson Avenue Units 3, 4 and 5 for the location of the project. LIPA said the company did not provide any comparative costs for using other in-city POI “that could be vacated by existing merchant steam plants at Astoria and Ravenswood, upon their future retirement. Consequently, the PSC’s decision would benefit from additional analysis as to whether alternative sites can be economically repurposed to interconnect offshore wind.”
LIPA also encouraged the commission to consider the risk of potential cost overruns, quoting Con Ed calling the new substation “a conceptual project that will require detailed engineering studies.” While the PSC requested an engineering cost estimate for the hub proposal, Con Ed provided no details about the studies behind or confidence level in the $1 billion cost estimate, LIPA said.
ERCOT flirted with potential disaster Monday after saying it was short on capacity, but system demand was reduced enough to keep the lights on.
Staff had initially projected demand to exceed available capacity by about 3 GW on Monday, with load totaling 80 GW for the first time. However, demand was as high as 78.4 GW before averaging 78.3 GW during the hour ending at 5 p.m. CT.
ERCOT’s capacity mix heading for Monday | ERCOT
That was enough to set a record for peak demand, just edging out the mark of 78.2 GW set Friday by 61 MW. It’s the seventh time since May that ERCOT has set a new mark for peak demand.
The grid operator’s peak load has averaged over 77 GW every day since July 4 and resulted in records for weekend peak demand Saturday and Sunday. Staff in May said they were expecting demand to peak at 77.3 GW in August.
Staff currently expect demand to crack the 80-GW threshold Tuesday.
ERCOT is operating under the summer season’s fifth operating condition notice (OCN), its lowest-level market communication in anticipation of possible emergency conditions. The OCN was effective Thursday and expires Tuesday.
On Sunday night, ERCOT made a conservation appeal asking Texans and Texas businesses to voluntarily conserve electricity Monday between 2 and 8 p.m. CT. It also issued a watch for market participants because of a projected reserve capacity shortage during the same time frame, saying there was a risk of an energy emergency alert (EEA).
The grid operator said record-high demand — fueled by sweltering heat that has settled over the region since May and led to numerous high-temperature records — and below-normal wind generation necessitated the conservation appeal. Staff said they only expected less than 3 GW of the more than 35 GW of installed wind capacity, about 8%, to show up Monday.
The load projects and available capacity for ERCOT Monday morning | ERCOT
Solar again provided more than 9 GW of energy during the day, about 81% of its capacity, before the wind picked up later in the afternoon. ERCOT also deployed 663 MW of non-spinning reserves, the third straight day it has called on the service. It was recalled at 4:38 p.m.
Operating reserves stayed comfortably above 3 GW during most of the day.
ERCOT’s operations center sent the watch notice to market participants at 9 p.m. Sunday. Underscoring the gravity of the situation, it followed by minutes the conservation appeal that was the first public communication since ERCOT tweeted out a conservation statement in May that was later termed “just a request.” (See ERCOT, PUC Say Texas Ready for Summer.)
The grid operator said conservation is a reliability tool that it has deployed more than four dozen times since 2008. It is issued when projected reserves may fall below 2.3 GW for 30 minutes or more.
A watch indicates that reserves may fall below a 2.3-GW threshold and are not expected to be recovered within 30 minutes. The next step is a Level 1 EEA under which ERCOT can call on power supplies from other grids and anything else that is available.
The grid operator set four marks for peak demand in June, the last coming on June 23 at 76.6 GW. The previous record had been 74.8 GW, set in August 2019.
Much of the state remains under heat advisories as a ridge of high pressure sits over the Southwest. Houston smashed a record that dated back to 1909 on Sunday when temperatures reached 109 degrees Fahrenheit, 4 degrees higher than the previous mark.
Almost all of Texas saw triple-digit temperatures again on Monday.
Prices in the day-ahead market were going for $2,000/MWh. They hit a peak of nearly $745/MWh around 2 p.m.
Offshore wind projects on the East Coast could cut revenue in the $30 million surfclam industry by 3% to 15%, according to a new study from Rutgers University.
Atlantic City, which is home port for about half the Atlantic surfclam fleet, could see losses as high as 25%, Rutgers researchers found.
Unlike their smaller cousins ― including steamers and littleneck clams ― surfclams are large, hard-shelled bivalves that can measure between 4 and 8 inches wide and are generally processed for use in soups, stews and chowders, according to the National Oceanic and Atmospheric Administration (NOAA). They can live as long as 35 years.
The NOAA describes the Atlantic surfclam fishery as “sustainably managed and responsibly harvested under U.S. regulations,” with the most recent figures, from 2019, showing a harvest of 34.3 million pounds.
But the Rutgers study, which was funded by the Bureau of Ocean Energy Management (BOEM), says that the presence of the turbines in the water could mean that some clamming vessels will make fewer trips, go to different ― more distant ― fishing areas and so harvest fewer clams, cutting their earnings. Those changes could also increase average costs by 1% to 5%, according to the study, which was published in two parts (here and here) in the June 20 issue of the ICES Journal of Marine Science. Those findings provide support for the concerns of commercial fishing interests, among the most vocal critics of the offshore wind projects, which have long argued that the presence and density of the turbines will hurt the fishing industry. (See Fishermen Fear the Impact of NJ Wind Farms.)
The study also follows BOEM’s release of a draft environmental impact statement (DEIS) for the 1,100 MW Ocean Wind 1 project on June 17. That study said the project’s impact on the commercial fishing sector could range from “minor” to “major,” with some fishing operations deciding not to fish the project areas. (See BOEM Draft EIS Finds Potential Major Impacts from 1st NJ OSW Project.)
Thomas Dameron, a former clam ship captain who is now a lobbyist for Surfside Foods, which harvests and processes surfclams, said the Rutgers study “is bringing to light what the members of the surfclam industry suspected.”
“The big worry is that with loss of access to so much of our fishable habitat, the fleet is going to be forced to fish smaller areas,” Dameron said. “And [with] those smaller areas, you’ll have local overfishing occurring, which could lead to the collapse of the surfclam industry out of Atlantic City.
“As more boats have to fish smaller areas, those clams ― because they are in smaller areas ― are fished down quicker,” he said. “Captains will be forced to target clams that are smaller and that would just lead to the destruction of the industry.”
According to NOAA, the surfclam population is above targeted levels and is currently not at risk for overfishing.
Asked about the study, Danish developer Ørsted, which is developing two wind projects off the New Jersey coast, said it recognizes the need to develop offshore wind projects “in a responsible way, with a keen eye toward avoiding and minimizing environmental impacts.”
“Our approach strives for coexistence, which the Rutgers study envisions, as we build clean energy projects that will help combat climate change,” said Stephanie Francoeur, a spokeswoman for the developer.
“Ocean Wind 1’s layout was designed to facilitate coexistence with the commercial and recreational fishing industry,” she said. “We are working with the research team at Rutgers to conduct a survey within the Ocean Wind 1 lease area to better understand the potential impacts to the surfclam population.”
Atlantic Shores Offshore Wind, the developer for a third New Jersey offshore wind project, did not respond to a request for comment from NetZero Insider.
It’s All About the Dredging
The possible decline of commercial surfclam revenue would not be due to OSW developers restricting the movement of the shipping vessels around the turbines, which they don’t plan to do, said Daphne Munroe, an associate professor in Rutgers Department of Marine and Coastal Sciences, who led the study.
Rather, the projects will change fishing patterns, Munroe said. Ships’ captains will be discouraged from taking their vessels into project areas due to the difficulty of moving heavy ships and clamming dredges through the turbines, she said. Some captains would be wary that the dredges — which scrape along the ocean floor to dislodge clams — could potentially snag on undersea cables carrying electricity, she said.
“It’s not a question of restriction by rule, but rather, it just won’t be viable fishing grounds anymore,” Munroe said. “When we talked to a number of commercial captains about this, whether they would tow a dredge over electrified cable, most of them said by rule they tend to avoid that. It can be dangerous … very dangerous.”
In addition, the need for clamming ships to raise and lower the dredges to avoid cables and concrete foundations on the sea floor will eat into the amount of time available for fishing, Munroe said. The result could be less clamming time before the vessel has to return to port to ensure its harvest is delivered while still fresh, she said.
Whose Burden?
New Jersey’s Board of Public Utilities (BPU) has so far approved three projects on the state coast: the 1,100-MW Ocean Wind 1 and 1,148-MW Ocean Wind 2, both Ørsted projects, and the 1,510-MW Atlantic Shores. With Ocean Wind 1 scheduled to go online in 2024, the projects would generate about half of the state’s target of 7,500 MW by 2035. Three more solicitations are expected, with the first one beginning in early 2023. (See New Jersey BPU OKs 2nd Offshore Wind Solicitation).
Researchers on a commercial fishing ship sample surf clams for size and number as part of a federal study. | Daphne Munroe
The fishing sector’s concerns about the projects are shared by tourism interests, which fear fewer visitors will come to enjoy a shoreline with turbines on the horizon. Some residents also vigorously oppose the wind farms, saying that the turbines will mar their offshore views, and their construction will disrupt the local quality of life.
The BOEM DEIS for Ocean Wind 1 said that most of the 19 factors the agency studied would not be severely impacted by the OSW developments. The report concluded that although the fishing sector would be one of the sectors most affected, most vessels would only have to make a small adjustment due to the wind projects.
Still, the draft report added, it is “conceivable” that a small number of fishing operations “would choose to avoid these areas” entirely due to the disruption once the wind farms become operational. (See BOEM Draft EIS Finds Potential Major Impacts from 1st NJ OSW Project.)
In a related development, BOEM recently released draftGuidelines for Mitigating Impacts to Commercial and Recreational Fisheries, aimed at helping OSW developers minimize impacts from their projects. The agency began a series of virtual stakeholder meetings on Monday, with the focus on East Coast fisheries. Subsequent sessions will focus on the Pacific coast and the Gulf of Mexico.
Among concerns raised were how any impacts to fisheries would be monitored and reported.
“Whose burden is it to come and show [impacts]?” said Blair S. Bailey, general counsel for the New Bedford Port Authority in Massachusetts. “Is BOEM going to actively oversee whether there are these impacts? Or is it going to be on the fishermen to come back to BOEM and prove these impacts?”
Modeling Fishermen’s Behavior
The Rutgers study says the East Coast fishing sector is facing the effects of “increasing industrialization” and expanded uses of the coastal ocean, with existing fisheries and clean renewable energy projects competing for space just as the warming climate alters the “coastal ocean habitat and distribution of commercial fish stocks.”
The study looked at potential impacts from offshore wind projects on the surfclam industry from Virginia to Massachusetts and concluded that the greatest impact would be felt in Atlantic City, while New Bedford could see the least impact.
“The reason for that is that the two major wind projects that are slated to go off New Jersey, the Atlantic Shores project and the Ocean Wind [1] project, occupy areas that are actively being fished by the Atlantic City fleet right now,” Munroe said.
The study, directed by BOEM, focused on the surfclam industry because the nature of the clamming vessels and their dredging equipment made it likely to be one of the fishing industries “most vulnerable to conflict and displacement with wind development,” Munroe said.
Surfclams, the study said, are “vulnerable to warming bottom temperatures” and the surfclam population has been steadily shifting north as sea temperatures have risen over the last three or four decades.
The study created a model that combined data across many factors, including fish stocks, surfclam birth and mortality rates, the economics of processing plants, fishing fleet behavior and economics, and fishing behavior. The study looked at how those factors ― and especially how fish captains make key decisions ― would change with the arrival of the offshore wind farms.
Researchers based the model on the characteristics of the East Coast surfclam industry, which contains 33 fishing boats operating out of four ports. Atlantic City is home port for about half of the fleet, and New Bedford accounts for another third. The vessels employ about 130 crew members, and they support “many jobs in processing plants and ancillary industries,” the study said.
The industry, which is dominated by four seafood companies ― Atlantic Capes Fisheries, La Monica Fine Foods, Sea Watch International and Surfside Foods ― operates seven surfclam processing plants that turn the clams into a variety of products including soups and chowders, canned minced clams, sauces and breaded clam strips, the study said.
The study found that when offshore wind projects were introduced into the model, reducing the area that was fishable and through which fishing vessels could safely pass, the number of fishing trips declined by between 4% and 14.5%. Average trip length increased by between 1.2% and 12.5%, the study said.
“The current fleet fishes year-round, with boats frequently making one to two trips per week,” the study concluded. “Increased travel time reduced the number of opportunities available for fishing trips, leading to reduced [surfclam] landings revenues as well as increased average production costs.”
Yet the adverse impact on the profitability of the Atlantic surfclam fishing industry may be a short- to medium term phenomenon, the study said.
“Over the longer-term, it is likely that the Atlantic surfclam industry will adjust to new conditions, adapting to maximize profits with added constraints on fishing behavior related to development of offshore wind energy or failing to continue operations,” the study said.
NERC, WECC and the California Mobility Center (CMC) recently agreed to form a working group to assess the risks to the bulk power system of the anticipated increase in electric vehicle charging loads across the U.S. and the steps that could be taken to mitigate those risks.
Early participation in the working group includes representatives from the Sacramento Municipal Utility District (SMUD), Southern California Edison, General Motors and members of the CMC, a partnership of government and industry that supports clean mobility innovation such as electric buses and EV charging.
“Electricity consumption by plug-in electric vehicles across North America will grow exponentially over the next decade,” Arlen Orchard, CMC chair and former SMUD CEO, said in a joint announcement of the agreement June 29. “The rapid rate of growth poses significant implications to electric system reliability if left unaddressed. This significant collaboration will support electric system reliability and importantly, a successful transition to mass electric vehicle adoption.”
The effort with NERC and WECC “is precisely the type of inter-industry collaboration the CMC seeks to foster,” Orchard said.
As the nation increases its efforts to electrify transportation and reduce carbon emissions, the working group will “increase information sharing and knowledge among the growing EV equipment, software and services system, the electricity industry and other stakeholders about reliability risks and mitigation strategies,” the joint statement said.
The formation of the working group follows a CMC webinar in March on reliability risks from EV charging.
“The North American grid must adapt and prepare for … changes, and this type of cross-sector collaboration … is critical if we are all to be successful,” NERC CEO Jim Robb said in the statement. “NERC is committed to working with stakeholders to unify our efforts in these areas, and this is a great example of us working with others in the ecosystem to advance our shared reliability goals.”
WECC CEO Melanie Frye said the “West is at the forefront of the nation’s efforts to decarbonize the grid and electrify the transportation sector. The collective and interdependent impact of these actions will significantly alter energy usage profiles in a way that could substantially affect the reliability of the bulk power system.”
“Bringing together grid reliability experts with vehicle manufacturers creates an opportunity to proactively address the range of reliability implications,” Frye said.
Massachusetts Attorney General Maura Healey and consumer group Public Citizen are raising market power concerns over a Japanese company’s plan to buy three gas-fired power plants in New England.
The investment firm Stonepeak asked FERC June 1 for approval to sell two units at Canal Generating Station in Sandwich, Mass., totaling 1,457 MW, and another 160-MW unit in Bucksport, Maine, to JERA, a joint venture between two Japanese utilities (EC22-71).
The AG and Public Citizen say the acquisition would give JERA, which already owns 50% of two other gas units totaling more than 400 MW in Massachusetts, too large a share of the generation market.
“The proposed transaction would by definition result in some degree of increased concentration of power generation ownership in New England and New York, and significant concentration of power generation capacity ownership in the import constrained SENE Capacity Zone of ISO-NE,” Healey wrote in a comment.
After the transaction, JERA would own more than 18% of the capacity cleared in the Southeastern New England zone.
The application also didn’t consider whether JERA would try to get reliability-must-run or other out of market payments, Healey wrote.
She called on FERC to comprehensively review the application — and to take its time by rejecting a request from the companies for expedited consideration and approval by Aug. 1.
The deal “looks like a pretty big bet to make lots of money off ISO-NE’s capacity market, and likely prolong the life of some fossil fuel power plants,” Public Citizen’s Energy Director Tyson Slocum wrote in an email to RTO Insider.
Slocum said that the deal raises questions about the concentration of voting in ISO-NE’s NEPOOL stakeholder process.
“Since NEPOOL membership conveys the ability to influence market design in ISO-NE (and therefore directly impacts rates), details on how exactly JERA plans to participate as a voting member in NEPOOL post-transaction is needed to determine whether the transaction is in the public interest,” the protest says.
Public Citizen says the company should disclose its plans for NEPOOL representation, as well as sharing the transaction price.
“We object to the confidential treatment of the sales price of the transaction, and ask the commission to release it,” Slocum wrote. “The purchase/sales price of power generation transactions reveal information essential to the public interest about the buyer’s expectation of economic return of the asset.”
Defending the Deal
In the application, the companies laid out why they believe the acquisition is not a threat to competition, using analysis from consultant Julie Solomon of Guidehouse.
Solomon found de minimis effects on competition in the market, while acknowledging that it would increase the market share of generators affiliated with JERA to 6.4% in ISO-NE and 18% in the Southeast zone.
“Public Citizen does not raise any issues that would prevent the commission from authorizing the transaction as requested in the application,” the filing says. “Instead, Public Citizen seeks to use this proceeding to address other matters, including by means of imposing conditions that have no place in a proceeding under [Federal Power Act] Section 203.”
Residential customers will be charged about $55/month to participate in community solar programs in Dominion Energy (NYSE:D) territory in Virginia, a fee that solar advocates say will cripple the nascent program.
The Virginia State Corporation Commission on July 7 approved the $55.10 monthly minimum fee for residential customers using 1,000 kWh/month (PUR-2020-00125).
Low-income customers will be exempt from the minimum. But others will be dissuaded from participating because the fee is among the highest in the country, solar supporters say.
“If shared solar is going to work, Virginians need to pay less than $660/year just to be plugged into the grid before netting a single electron off it,” tweeted Sen. Scott Surovell (D), who co-sponsored the bipartisan 2020 bill establishing the shared-solar program (HB 1634/SB 629).
The Coalition for Community Solar Access (CCSA) called the commission’s order “an anti-consumer, anti-business” ruling “that does not align with the legislative intent and undermines the economics and accessibility of the shared-solar program for participating subscribers, while perpetuating a culture of egregious overcollections by Dominion Energy.”
“The SCC’s decision will decrease crucial investments in the commonwealth’s economy and lock out thousands of consumers and businesses from accessing local, clean energy generation,” the group said in a statement.
The commission’s order accepted the minimum monthly fee recommended by a commission hearing officer in February. It is substantially less than Dominion’s proposed charge but more than double that urged by CCSA. (See Advocates Offer Compromise on Minimum Charge for Va. Shared Solar.)
The commission said the fee includes costs “relevant to ensure subscribing customers pay a fair share of the generation, transmission, distribution and fixed costs of providing electric service.”
The minimum charge comprises fixed customer ($6.58) and administrative ($1) charges and volumetric costs, including non-bypassable generation charges ($3.37); base distribution charges ($19.26); distribution rate adjustment clause (RAC) charges ($4.62); base transmission charges ($9.70); and transmission RAC charges ($10.59).
The order also adopted Dominion’s proposed bill credit of 11.7650 cents/kWh for residential customers, 7.1200 cents/kWh for commercial customers and 5.9010 cents/kWh for industrial customers. The commission said the bill credit rates reflect generation, transmission and distribution revenues and “generally offsets the full costs typically included in the customer’s bill.”
The 2020 legislation required the SCC to approve a shared-solar program of 150 MW, with a minimum requirement of 30% low-income customers. The program can be expanded by 50 MW once the 30% low-income participation threshold is reached.
Dominion said that a residential customer who consumes 1,000 kWh should receive a minimum bill of $74.90 (distribution service charges: $29.45; transmission service charges: $20.29; generation balancing service charges: $25.16), not including administrative overhead costs, which it estimated at $10 to $20/month per customer. Anything less than that would result in cost shifts to nonparticipating customers, the utility said.
Commission staff proposed two alternatives: $10.95/month, which excludes transmission and distribution charges, or $55.10/month, which includes them. “Staff believes that, ultimately, the determination of the appropriate minimum bill is a policy question for the commission’s determination,” a staffer testified in a hearing last year.
Dominion Energy says it has received applications for 11 shared solar projects totaling almost 43 MW. | Dominion Energy
Former Texas regulator Karl Rabago, CCSA’s witness at the hearing, said, “Dominion’s approach appears specifically designed to make shared-solar subscription unattractive to potential subscribers and, therefore, renders the shared-solar program unworkable.”
In a letter to the SCC in April, Surovell, Sen. Emmett Hanger (R) and Del. Rip Sullivan (D) protested the hearing examiner’s recommendation, saying “we did not pass legislation to create a program that exists in name only.”
Surovell said the commission’s ruling “highlights why the SCC vacancy is critical.”
The SCC currently has only two members after Democrats were unable to win a full term for Angela Navarro, who was appointed by former Gov. Ralph Northam to replace Mark Christie when he left to join FERC. Navarro herself left in March.
Dominion did not respond to a request for comment Monday. The company reports having received applications for 11 shared-solar projects totaling almost 43 MW.
