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.
By Christy Walsh, Natural Resources Defense Council
Christy Walsh | NRDC
The climate crisis is putting the electricity system at risk. Our aging grid is straining to handle the stronger storms, hotter heat waves, extended drought and extreme flooding many parts of the U.S. are already seeing.
With these increasing threats, grid operators will need to use all the tools they can — especially demand response, energy efficiency and imports from surrounding areas — to curb stress on the system and limit the threat of blackouts.
But as important as those actions are, they are not enough. Congress also must act now to invest in a clean, resilient and affordable power grid.
Given the climate crisis before us, the conclusion is clear: We must transition away from fossil fuels that contribute to climate change and invest in a grid that’s resilient to storms, high heat and flooding. A recent NRDC policy brief shows how legislation under consideration in Congress would enhance reliability by:
expanding long-distance transmission lines;
encouraging more solar and wind power, especially in energy justice communities;
curbing energy demand through weatherization and energy efficiency programs;
investing in communities where coal mines or fossil fuel plants are closing; and
spurring the sale of electric vehicles, which can double as backup batteries for customers.
Fossil fuel defenders have been attempting to blame wind and solar for some of the strains to the grid we have seen this year, but that’s just ridiculous. As has been made clear time and time again, no single power source is perfect. Coal piles freeze, gas lines stop flowing, and nuclear plants shut down before a hurricane makes landfall.
And it’s not just the heat and storms: A recent NERC assessment noted that stressed supply chains are crimping coal supplies.
Congressional action, coupled with decisions by states, public service commissions, grid operators, and federal regulators can spur renewables, energy efficiency, demand response, electric storage, and new transmission lines to get us the clean, reliable, resilient electrical system we need.
What we all should be able to agree on is that we need to invest in a larger power grid. The bigger, wider and more flexible the grid, the more able it will be to respond to whatever comes its way.
The right transmission and interconnection rules are key to creating a better grid for years and decades to come.
In the MISO area and in PJM, the grid serving the mid-Atlantic, thousands of solar and wind projects are ready to be built yet remain in limbo. Consider the more than 100,000 MW of clean energy in MISO just waiting to supply the grid. That’s more than halfof total installed generating capacity in the MISO region. These and future additions can replace retiring fossil fuel generators. Even taking into account that some of this generation will not be built, getting these and future additions on line more quickly is vital to achieving a reliable energy transition and lowering energy costs.
We also need more high-voltage power lines that transport power from rural and offshore areas to cities and towns. Transmission is key to unlocking clean energy’s potential and ensuring lower energy prices and more reliable power. It also allows a regional grid struggling with extreme weather to import power from neighboring regions. According to a 2021 FERC-NERC report, importing power likely saved the residents of the Midwest and Great Plains from the disastrous consequences suffered by Texans during Winter Storm Uri.
We need to do it all. We need a system that can adapt and respond to whatever is thrown its way, while we move forward with the clean energy transition. In other words, we need to invest in transmission and other grid upgrades while enabling more clean energy to power our homes and businesses.
While states and grid operators have much to do in the short term, the single biggest thing we can do now is pass climate energy legislation under consideration in Congress. It would provide billions of dollars in incentives to transition to clean energy, while ensuring that the lights stay on when we need them most.
With the right investments now, we can build the future we want and need.
Christy Walsh is a senior attorney in the NRDC’s Climate & Clean Energy Program.
Pacific Gas and Electric (NYSE:PCG) has invited 25,000 of its customers who own Tesla (NASDAQ:TSLA) Powerwall batteries to be part of a virtual power plant (VPP) to reward customers financially and support grid reliability in California.
If most of the customers join, the aggregated storage project could eventually form the “world’s largest distributed battery,” generating the output of a small gas-fired power plant, PG&E said in a news release.
About 1,500 customers have signed up so far, and 3,000 have expressed interest, PG&E said.
“Our customers’ home batteries offer a unique resource that can positively contribute to our state’s electric grid and will become more significant as our customers continue to adopt clean energy technology,” Aaron August, PG&E vice president of business development, said in the statement. “In collaborating with Tesla, we are further integrating behind-the-meter battery-based VPPs on the largest scale yet.”
California has experienced energy emergencies during the past two summers and could continue to see shortfalls of more than 1,700 MW over the next four years, according to CAISO and the state’s Public Utilities Commission. The switch to clean energy has made CAISO’s grid especially vulnerable on hot summer nights after solar ramps down and during wildfires that curtail transmission.
To meet its reliability challenges, CAISO has required aging gas plants as small as 27.5 MW to postpone retirement, and state agencies have approved the continued operation of once-through-cooling natural gas plants that harm marine life and had been ordered to close.
FERC and CAISO have made it easier in recent years for distributed energy resources to participate in wholesale electricity markets. DER aggregations are seen as resources that could help offset summer shortfalls in CAISO and other organized markets.
Tesla’s Powerwall batteries manufactured after 2016 have a 13.5-kW capacity, bringing the potential total capacity from all 25,000 PG&E customers to 337.5 MW.
PG&E’s resource portfolio already includes some DER aggregations. As of last year, the utility said its supply included about 150 MW of VPPs used as dispatchable demand response resources, including as part of its Emergency Load Reduction Program. About a dozen aggregators already qualify to participate in PG&E’s Capacity Bidding Program.
The joint effort between PG&E and Tesla could boost such efforts to a new level. Under the program, PG&E will call load-management events, directing participants’ batteries to discharge during high demand from 4 to 9 p.m., May through October. Participating customers will receive a generous $2/kWh.
PG&E residential customers are eligible for the program if they own a Powerwall, have an interconnection agreement with PG&E and are not enrolled in other DR programs. Customers can use a Tesla app to reserve enough backup power to meet their own needs or opt out of an event, PG&E said.
While the U.S. Supreme Court decision in West Virginia v. EPA has been called “devastating” for the agency’s ability to curb carbon emissions from existing power plants, its impact could also place tight constraints on congressional efforts to address major issues such as climate change, a panel of legal experts said last week.
Lisa Heinzerling, Georgetown Law | Georgetown University Climate Center
“The most dangerous point of the court’s decision actually is the court’s seizure of power from Congress, not the agency,” Lisa Heinzerling, a professor at Georgetown University Law Center, said during a webinar hosted by the school’s Climate Center on July 5. “Under the opinion, Congress may no longer enlist agencies’ help in addressing major issues, as it’s done throughout U.S. history, unless it speaks clearly enough for a hostile Supreme Court to hear it. It’s perverse.”
Heinzerling was one of five environmental lawyers on the panel parsing out the details of the decision, the court’s motivations and reasoning, and how environmental and other federal regulations may be able to overcome the obstacles the court’s conservative justices have now put in place.
The 6-3 decision released June 30 ruled that EPA lacks authority to compel generation shifting to reduce carbon emissions, saying the agency failed to provide “clear congressional authorization” for the rulemaking, specifically under the decades-old Clean Air Act. (See Supreme Court Rejects EPA Generation Shifting.)
William W. Buzbee, Georgetown Law | Georgetown University Climate Center
But Heinzerling and other panelists also said the decision will have impacts beyond congressional or EPA efforts to regulate carbon emissions. William W. Buzbee, who also teaches at Georgetown Law, sees the case as “a major arrogation of power by the Supreme Court to itself and the courts, undercutting the power of agencies to do as Congress instructs.”
“This is a terrible problem,” Buzbee said. “The court sort of hamstrings agencies and actually makes it hard for Congress.
“The court repeatedly says Congress had to be more clear and more specific,” he said. “The problem there is that agencies often need flexibility, so you don’t want to have very particularized language. And then second, to pass laws, compromises are often needed, and so sometimes, broader language is a way for Congress to pass laws that are needed.”
Jonathan H. Adler, Case Western | Georgetown University Climate Center
Jonathan H. Adler, director of the Coleman P. Burke Center for Environmental Law at Case Western Reserve University, said the decision sends a message to all federal courts to be “very wary when federal agencies seek to pour new wine out of old bottles. That is to say, when a federal agency takes a statute that may have been last enacted or reauthorized or amended years ago and seeks to use the provisions to address a new or contemporary problem … that has not been addressed before or to do something in a way that has not been done before.”
“This is an enormously important case when it comes to administrative law,” agreed Jeffrey Holmstead, who served at EPA under former President George W. Bush and now leads the Environmental Strategies Group at Bracewell. “In terms of the current debate over climate change, I think it could end up being important for the [Securities and Exchange Commission] in terms of its efforts to mandate additional disclosures regarding greenhouse gas emissions. Maybe it could impact what FERC is trying to do with natural gas pipelines.”
Kirti Datla, director of strategic legal advocacy at Earthjustice, a nonprofit environmental law firm, also sees the decision as having impacts on the regulatory process in general, well beyond EPA. “It’s going to affect everything, from what people ask [an] agency to do in their comment letters, to what agencies think that they can do, to the arguments people will raise when challenging what agencies end up doing,” she said.
The Major Questions Doctrine
At the core of West Virginia v. EPA is Chief Justice John Roberts’s invocation of “the major questions doctrine,” which all the panelists saw as problematic, though for different reasons.
“Precedent teaches that there are ‘extraordinary cases’ in which the ‘history and the breadth of the authority that [the agency] has asserted,’ and the ‘economic and political significance’ of that assertion, provide a ‘reason to hesitate before concluding that Congress’ meant to confer such authority,” Roberts wrote in the decision.
“The agency must point to ‘clear congressional authorization’ for the authority it claims,” Roberts said.
In terms of EPA’s ability to regulate carbon emissions through generation shifting, what this means, Adler said, is that the agency is not losing a power it didn’t exercise; “it’s rather that the court is expressing skepticism that the power ever existed.”
“The court automatically is skeptical of national regulations where agencies address a new problem,” Buzbee agreed. “That’s always the nature of national regulation; agencies step in to address a problem that hasn’t been handled. So, the whole frame of the major questions doctrine is a major problem.”
Kirti Datla, Earthjustice | Georgetown University Climate Center
Datla pointed to Justice Neil Gorsuch’s concurring opinion as potentially layering on even more constraints for regulation, noting that he said the major questions doctrine is important “because it prevents swings in policy” between different administrations.
“The administrative state, in his mind, should be a set of agencies carrying out very limited duties that are so detail oriented that they wouldn’t shift from one president to the next,” Datla said. Justice Elena Kagan’s dissent counters this narrow view as not “what the administrative state currently looks like,” Datla said.
But for Datla, the more pressing problem with the decision is that after setting out the major questions challenge, ‘the majority doesn’t provide any sort of test as to what might be adequate to overcome it. It’s hard to imagine a case where, when this doctrine applies, the agency will be able to overcome the kind of clear statement rule that is being put forth in this case,” she said.
“Congress has two options going forward,” said Heinzerling, who also served at EPA during the Obama administration. “One, it can make major policy decisions itself, or two, it can give clear congressional authorization to an agency to regulate in a particular manner. In fact, I don’t think there’s a real choice.”
The decision “would not allow Congress to pass off a major decision to an agency, even if it really, clearly, in crystal terms passed off that decision to an agency,” she said.
For example, if Congress passed a law specifically authorizing EPA to determine if and how to curb GHG emissions, “I think the court would say that such a statute does clearly authorize EPA to decide a major question,” Heinzerling said. “That would just take the regulatory action out of the statutory frying pan, so to speak, and hurl it into the constitutional fire.”
The Limits of Regulation
Adler sees yet another aspect of the decision’s approach to the major questions doctrine that could have significant impacts on future climate-related litigation. “This concern about showing clear warrant, clear authority in the statute for a major exercise of power is something [Roberts said] the courts should look at upfront” as part of a statutory analysis, he said. “It creates a much broader opportunity for litigants to try and invoke this theory. It gives courts more flexibility in terms of when to consider whether something is a major question.”
Still, Holmstead echoed many other industry analysts who have argued that the decision will have minimal immediate impact on EPA’s ability to regulate carbon emissions under the Clean Air Act. The decision’s rejection of limiting emission reduction regulations to “inside the fence line” of individual generation plants and its seeming endorsement of some form of emissions trading “actually give EPA more flexibility that they thought it had,” he said.
He also said the agency has solid authority to regulate carbon emissions from the transportation sector, provided it sticks with the incremental approach it has adopted in the new standards announced at the end of 2021. (See EPA Rules Will Slash Vehicle Emissions, Rev up EV Market by 2026.)
The challenge ahead for the agency is “if you look at the other industrial sectors,” Holmstead said. “There’s not some way that EPA can gradually shift production of cement or iron and steel to newer, cleaner plants. It’s a technological problem, not a regulatory problem, and I don’t think, beyond the power sector, EPA has really ever developed an effective way to do regulation of industrial sources.
“I don’t think the answer for all of the questions we face with climate change are necessarily regulatory,” he said.
