Building on its 2050 Transmission Study, ISO-NE plans to study the effects of shifting two offshore wind points of interconnection (POIs) from Maine to Massachusetts and analyze regional offshore wind interconnection points, the RTO told its Planning Advisory Committee (PAC) on March 20.
The 2050 Transmission Study found the transmission upgrades to meet the region’s projected 57-GW 2050 peak load will cost $22 billion to $26 billion. One key constraint identified by the study was the region’s ability to send power from renewables in Maine and New Hampshire south to meet load in the Boston area. (See ISO-NE Prices Transmission Upgrades Needed by 2050: up to $26B.)
These results are partially contingent on where ISO-NE has modeled offshore wind projects connecting to the grid, locations that are hardly set in stone.
The finalized Gulf of Maine Wind Energy Area released March 15 (see BOEM Designates Gulf of Maine Wind Energy Area.) is located farther south than ISO-NE initially expected, with much of the lease area “as close, or closer, to Boston as it is to Maine,” Dan Schwarting of ISO-NE told the PAC.
In response to stakeholder feedback, ISO-NE is proposing to essentially rerun the 2050 Transmission Study with two POIs shifted from Maine to Massachusetts to see if it would reduce the scale and cost of transmission upgrades.
“These changes result in very little change in the mileage of offshore cables but are expected to significantly reduce stress on the Maine-New Hampshire and North-South interfaces,” Schwarting said.
Schwarting added that ISO-NE does not expect the changes to eliminate the need for north-to-south upgrades, but that the RTO anticipates “at least some of the upgrades would fall off the list.”
Additionally, ISO-NE will conduct a “high-level screening of various offshore wind points of interconnection” to provide general information on transmission constraints at different POIs and outline “how much offshore wind can realistically be interconnected into different parts of New England before major transmission upgrades are required.”
This analysis will be based on loads projected for 2033, instead of projections out to 2050, given the uncertainty of projecting generation and load data beyond 10 years. While the 2050 Transmission Study modeled offshore wind at reduced output levels “to ensure that load could be reliably served during low-wind peak conditions,” the POI screening will study wind projects at their full nameplate capacity.
ISO-NE will study the POIs up to a capacity of 2,400 MW to determine “an approximate maximum interconnection size before major transmission upgrades are required.”
While ISO-NE’s loss-of-source limit constrains single points of interconnection to 1,200 MW, the RTO is leading an effort with PJM and NYISO to study raising the limit to 2,000 MW.
ISO-NE is planning to study sites independently and then consider combinations of feasible POIs to see which can be used concurrently and which are “mutually exclusive,” Schwarting said.
Schwarting emphasized that the screening “is not a full interconnection study and does not replace the need for such a study.”
Several stakeholders supported the proposals but cautioned that transmission-system constraints are just one factor in the selection of a POI.
“There’s a whole lot that goes into interconnecting offshore wind at a particular site,” said Dave Burnham, director of transmission policy at Eversource. “[ISO-NE] is really only looking at a sliver at what it’s going to take.”
Bob Stein of Signal Hill Consulting Group said moving interconnection points from Maine to Massachusetts could bring political challenges due to the local economic benefits that are expected to accompany POIs.
“There’s a potential political problem with what good engineering suggests we should do,” Stein said.
ISO-NE is asking for stakeholder feedback on the proposal by April 4, and anticipates results “at some point in quarter three of 2024.”
The federal government is teeing up a second wind energy auction in the Gulf of Mexico.
The U.S. Bureau of Ocean Energy Management on March 20 proposed a lease of four areas totaling 410,060 acres off the Texas and Louisiana coastlines.
The proposed sale notice will be published in the Federal Register on March 21, triggering a 60-day public comment period in which BOEM hopes to receive feedback on the size and location of the proposed lease areas, and on potential lease revisions to include hydrogen production with the electricity generated there.
Also, BOEM is considering lease stipulations requiring that historically underserved communities be considered and engaged early and often in the development process.
If BOEM decides to go through with this second auction, it would publish a final sale notice.
BOEM and some industry observers had expressed optimism for the first Gulf of Mexico wind auction, in August 2023, but it drew minimal interest. (See Gulf of Mexico Wind Energy Auction Falls Flat.)
Only one of the three lease areas offered drew bids, and the winning bid by RWE Offshore US Gulf was just $5.6 million — much less than winning bids submitted for lease areas off the Atlantic and Pacific coasts.
August 2023 was not a good time for the emerging U.S. offshore wind industry — early movers off the Northeast Coast were struggling mightily with supply chain, financial and infrastructure constraints.
But beyond that, the Gulf of Mexico presents challenges of its own: weaker winds, softer seabed geology and an annual hurricane threat.
After the first Gulf auction fizzled, research firm Clearview Energy Partners flagged other factors for its clients: Electricity is relatively inexpensive in the Gulf Coast region and there is not a strong push by state leaders to get electrons flowing from sea to land.
Production of green hydrogen might be a key motivator for offshore wind development in the region, Clearview wrote, but at the time, the IRS had not issued guidance on the Inflation Reduction Act’s clean hydrogen tax credit.
The IRS has since issued proposed guidance and may finalize it before a second auction. This could offer developers a clearer picture of the potential economics of offshore wind in the Gulf.
BOEM said it would use new, more efficient software for the second Gulf auction.
BOEM Director Elizabeth Klein said in a news release: “We look forward to receiving feedback from tribes, other government agencies, ocean users, local communities and others to minimize any impacts to natural and cultural resources, reduce potential conflicts with ocean uses, and maintain a healthy marine ecosystem.”
WASHINGTON — EPA still wants U.S. automakers to cut greenhouse gas emissions from their light-duty vehicles almost in half by 2032, but the agency’s final rule released March 20 aims to give the industry more time and flexibility on how to reach that ambitious target compared to the proposed rule issued in May.
Whereas the proposed rule predicted electric vehicles would comprise 67% of new car sales by 2032, the final rule sees a broader mix, with about 56% EVs and 13% plug-in hybrid electric vehicles (PHEVs), according to a senior administration official speaking on background. The rule covers the model years 2027 to 2032.
In addition to light-duty vehicles (LDVs) — passenger cars, SUVs and light trucks — the rule also calls for a 44% reduction in emissions from medium-duty vehicles (MDVs), defined as delivery trucks and vans weighing between 8,501 and 14,000 lbs.
At a rollout event in D.C., EPA Administrator Michael Regan hailed the final rule as “the strongest vehicle pollution technology standard ever finalized in the United States,” targeting GHG emissions of 85 g ― just under a fifth of a pound ― per gallon for LDVs by 2032.
“This technology-neutral and performance-based standard gives the auto industry the flexibility to choose the combination of pollution control technologies best suited to their customers,” Regan said. “Whether it is battery electric, plug-in hybrid, advanced hybrid or cleaner gasoline vehicles, we understand that consumer choice is paramount.”
John Bozzella, Alliance for Automotive Innovation | EPA
EPA’s current LDV standard for 2026 is 168 g/gallon, edging up to 170 g/gallon in 2027 before tapering off to 85 g/gallon by 2032 ― a decrease of 17 g/gallon per year. The 2032 target for MDVs is 274 g/gallon, down from 461 g/gallon in 2027.
The “multipollutant emission standards” also will result in a 95% decrease in tiny particulate matter, commonly referred to as PM2.5, which has been linked to heart and lung disease, according to EPA. Nitrogen oxides and other pollutants are expected to drop 75%.
Promoting the final rule, Regan, President Joe Biden and other administration officials have repeatedly said major cuts in vehicle emissions will not mean higher costs for consumers, lost jobs in the auto industry or snowballing effects on the economy in general.
“These technology standards … will avoid more than 7 billion tons of carbon pollution,” Regan said. “That’s four times the total carbon pollution from the entire transportation sector in the year 2021.”
Those reductions will translate to “fewer hospital visits and premature deaths … fewer illnesses like lung cancer and heart disease,” he said.
In a statement from the White House, Biden said the new rule would allow the U.S. to meet his “ambitious target that half of all new cars and trucks sold in 2030 would be zero-emission … and race forward in the years ahead.”
Citing the billions of dollars in private investments announced for new EV and EV battery manufacturing plants ― buoyed by tax incentives in the Inflation Reduction Act ― Biden said the U.S. “will lead the world in autos, making clean cars and trucks, each stamped ‘Made in America.’”
National Climate Advisor Ali Zaidi also stressed the benefits for workers, consumers and the economy. “On factory floors across the nation, our autoworkers are making cars and trucks that give American drivers a choice — a way to get from Point A to Point B without having to fuel up at a gas station. From plug-in hybrids to fuel cells to fully electric, drivers have more choices today. Since 2021, sales of these vehicles have quadrupled, and prices continue to come down.”
Zaidi noted that U.S. drivers now can choose from more than 100 EV and PHEV models.
EPA estimates reduced emissions will generate $99 billion per year of economywide benefits, including $13 billion in public health savings from improved air quality and $62 billion in lower fuel, maintenance and repair costs for consumers. The average savings for individual consumers buying EVs are estimated at $6,000 over the life of the vehicle.
Not a Rollback
When released in April 2023, the proposed rule triggered immediate pushback from many in the auto industry, mostly based on its call for a sharp ramp-up in EV sales beginning in 2027.
Albert Gore III, Zero Emission Transportation Association | EPA
With EV sales not increasing as fast as some automakers had predicted, the industry has been pumping the brakes on how quickly it will get new EV models to market.
During a recent earnings call, General Motors CEO Mary Barra said her company is targeting 200,000 to 300,000 EV sales for 2024 and is considering introducing a PHEV model for certain markets, all depending on consumer demand. GM’s last PHEV, the Chevy Volt, was discontinued in 2019.
Administration officials, however, framed the changes to the final rule not as a rollback resulting from industry pressure, but as a way to make the rule more robust and durable. The fast increase of EV sales envisioned in the proposed rule had been based primarily on computer models, a senior official said. The final rule leverages data from automakers and dealers, which indicated the same result in emission reductions could be achieved if the industry had a longer lead time and more flexibility in the mix of vehicles that automakers would produce.
It also takes into account increased efficiency and lower emissions resulting from technological advances in gas-powered cars.
The more industry-friendly rule didn’t pass muster with Sen. John Barrasso (R-Wyo.), who criticized the rule and the Biden administration as out of touch and “trying to force Americans into expensive electric vehicles they don’t want, don’t need and can’t afford.”
“Republicans will fight to overturn the Biden car mandate and put Americans back in the driver’s seat,” Barrasso said.
Speaking in D.C., John Bozzella, president and CEO of the Alliance for Automotive Innovation, was more conciliatory, acknowledging he had been a thorn in the administration’s side for months, advocating for changes in the rule.
“Automakers are committed to electrification, and we want this transformation to EVs … to succeed over the long haul,” he said. “The reason we had strong views on the feasibility of the original proposal and what it required in terms of EV sales is because we know the challenges of [a] choppy EV sales market, public charging still coming online, new supply chains that must be built, all while preserving a customer’s ability to choose the vehicle that works for them and their families. …
“Our message was not whether this can be done ― it can ― but how fast can and should it be done,” he said.
Albert Gore III, executive director of the Zero Emission Transportation Association, noted that the best-selling car in the world in 2023 was electric, Tesla’s Model Y. Tesla also claimed the top four spots on Cars.com’s American-Made Index, with its models Y, 3, X and S.
“We have everything we need today in terms of technology and know-how to meet and exceed this standard,” Gore said. “And if all the manufacturers [at the event] dedicate themselves to meeting and exceeding these goals, like America always does, we will firmly secure our future in a position of global leadership.”
The PEF Calculation
Getting a jump on EPA, the Department of Energy on March 19 also released a final rule on the petroleum equivalent fuel (PEF) calculation, which is a measure of the “fuel efficiency” of EVs; that is, the amount of petroleum-based fuel needed to produce the same amount of energy an EV uses
How the PEF is calculated is important — and political — because it is used by EPA in determining automakers’ compliance with the Corporate Average Fuel Economy (CAFE) standards — the federal fuel efficiency levels for automakers. The calculation first was set in the 1980s and has been reviewed periodically, most recently in 2000.
In 2021, the Sierra Club and the Natural Resources Defense Council petitioned DOE to update the two-decade-old calculation. “By overstating the miles per gallon equivalent of any EVs in automakers’ fleets, the prior calculation enabled automakers to continue to sell far more [gas powered vehicles],” the Natural Resources Defense Council said in a press release welcoming the new calculation.
“The old calculation included a multiplier of nearly seven that significantly inflated the calculated fuel economy of electric vehicles. DOE’s final rule phases out the multiplier while updating other data used in the calculation with more current figures,” NRDC said.
The Sierra Club noted that the PEF calculation “is wholly separate and has no impact on compliance” with EPA’s final vehicle emissions standards.
The updated PEF calculation is based on a complicated formula taking into account factors such as average electricity generation and transmission efficiency and average petroleum refining and distribution efficiency.
The PEF is measured in watts-hours per gallon. The current standard, 82,049 Wh/gallon, will be in effect through the end of 2026. DOE’s final rule ramps down the PEF to 79,989 Wh/gallon in 2027 and bottoms out at 28,996 Wh/gallon in 2030 and beyond.
Average load-weighted electricity prices in PJM fell by about half in 2023, the Independent Market Monitor said in its annual State of the Market Report, finding the lower prices came largely from a drop in natural gas prices that reversed a record-high spike last year.
The decrease brought real-time load-weighted LMPs to an average of $31.08/MWh in 2023, down from $80.14 the previous year. In a briefing ahead of the March 14 report, Monitor Joe Bowring said the correlation between declining electricity and natural gas prices demonstrates PJM’s markets are working to translate lower fuel costs into savings for consumers. (See PJM Monitor: Rise in Fuel Costs Led to Record-high Prices in 2022.)
Bowring said it’s unclear how the March 12 ruling from the 3rd U.S. Circuit Court of Appeals partially vacating FERC’s order permitting PJM to revise the reliability requirement for the DPL South zone will be implemented and how it may affect prices. (See 3rd Circuit Rejects PJM’s Post-auction Change as Retroactive Ratemaking.)
The Monitor’s report found PJM’s energy and capacity markets were competitive in 2023, though local and aggregate markets within both had the potential for market power to be exercised, and the capacity market design’s effectiveness was mixed. The regulation and financial transmission rights markets both were found to have flawed market designs limiting competitiveness, and while the reserve markets performed well, some subzones saw high supply concentration.
In the local energy market, transmission constraints created opportunities for market power, and the Monitor said not all resources that fail the three-pivotal-supplier (TPS) test are being properly mitigated to their cost-based offers.
“The goal of competition in PJM is to provide customers reliable wholesale power at the lowest possible price, but no lower. The PJM markets have done that. The PJM markets work, even if not perfectly,” the Monitor wrote.
The Monitor identified future economically and policy driven generation retirements as a leading challenge PJM will have to face, with up to 58 GW of generation at risk of deactivation through 2030. But Bowring said the actual number may be lower if a drop in the number of resources available to offer capacity leads to higher prices. If clearing prices double in coming auctions and a portion of the economic retirements are delayed, he said the number of resources going offline could be about 43 GW. PJM’s February 2023 “4R’s” report found about 40 GW of generation is at risk. (See “PJM White Paper Expounds Reliability Concerns,” PJM Board Initiates Fast-track Process to Address Reliability.)
“PJM stands by the estimates in our 2023 report, ‘Resource Retirements, Replacements and Risks,’ which documents that 40,000 MW of generation are at risk of retirement by the end of this decade. The IMM’s higher at-risk retirement numbers are the result of more conservative assumptions,” spokesperson Jeff Shields said.
“Our greatest concern remains the pace at which new generation projects are getting built once the PJM process is complete. Currently there are approximately 40,000 MW in new generation projects that have been cleared for interconnection by PJM but are not being built; a number of a factors outside of PJM’s influence, including siting, financing and supply-chain, continue to hold up the completion of projects.”
Bowring said several changes to PJM’s rules around resource deactivations could correct market signals and limit costly reliability-must-run (RMR) contracts. Because transmission needs aren’t a factor in the reliability metrics used to determine Base Residual Auction procurement needs, he said it’s possible for a generator to not clear the auction and file for deactivation only to be told it’s needed to prevent transmission issues.
The cost of retaining a generator on an RMR contract can be steep; Bowring said the cost-of-service recovery rate for Indian River Unit 4 has been about 10 times the capacity revenues the 410-MW coal unit would have received since its RMR contract began in June 2022.
PJM’s practice of counting resources operating under an RMR contract toward reliability procurement targets in the capacity auction also could be suppressing market signals incentivizing generation needed for long-term resource adequacy.
Shields said PJM’s notification requirements for deactivating resources and its compensation structure for RMR contracts is under discussion at the Deactivation Enhancements Senior Task Force.
“We hope that the IMM will continue to work with us and capacity market participants to ensure that all market-seller costs, including risk, are includable in market offers so that economically viable resources can recover their costs and therefore remain in service,” he said.
Bowring argued that an ongoing stakeholder process to facilitate transferring capacity interconnection rights from a deactivating resource to replacement generation under the same ownership should be rejected and PJM instead should use any transmission headroom freed up by resources going offline to advance the interconnection of any planned resources that could resolve transmission violations that may be caused by the deactivation.
The report urged PJM to analyze the amount of firm gas capability in its region while expecting much of the needed new capacity will come from gas-fired generation. While it notes there is more than 200 GW of intermittent generation in the interconnection queue, the report argues that based on historical completion rates and capacity derates, that will amount to about 11 GW.
“PJM and federal and state regulators cannot hope to balance supply and demand without first having a clear and reasonably accurate measure of both existing and expected supply and demand. Providing clear information to regulators and market participants about the actual and expected supply-demand balance is essential so that decisions about market design, about the timing of environmental regulations, about pipeline siting and about transmission siting can all recognize the likely impact on the balance between supply and demand and therefore reliability,” the report says.
Maryland’s House of Delegates on March 18 approved an ambitious plan for introducing time-of-use (TOU) rates for residential customers of the state’s investor-owned utilities, but only after provisions for a default, opt-out introduction of TOU was amended to a voluntary, opt-in program.
The Distributed Renewable Integration and Vehicle Electrification (DRIVE) Act (H.B. 1256) instead calls for the state’s Public Service Commission (PSC) to conduct a study of the impacts of the voluntary TOU program, determine whether a default rate would be justified and deliver a report to the General Assembly by Dec. 31, 2027.
As originally drafted by Del. David Fraser-Hidalgo (D), H.B. 1256 was intended to combine the default TOU rates with incentives for distributed renewable energy technologies to promote electrification of homes and transportation, while also promoting load management and flexibility to minimize impacts on the grid as electricity demand grows.
The bill was one of several pared-down energy bills that passed in the House or Senate on or before March 18, the General Assembly’s “crossover day,” when bills introduced in one house must be approved and sent on for a committee hearing and possible vote in the second house.
One example, Del. Lorig Charkoudian’s (D) H.B. 505, would have prohibited the state’s utilities from including the costs of any lobbying, political activities, membership fees or sponsorships in industry trade groups in their rates. Maryland is one of 11 states that have been considering such legislation to curb utilities’ political spending with their customers’ funds. (See Utilities Facing Increased Scrutiny Over Political Activities.)
Those provisions were crossed out in the amended version of the bill, which the House passed 99-38 and was sent to the Senate Committee on Education, Energy and the Environment. But in an interview with NetZero Insider, Charkoudian said the bill’s remaining provisions still would provide consumer savings and utility accountability.
Specifically, H.B. 505 would require Maryland utilities to become members of PJM, rather than join voluntarily. Under FERC rules, voluntary members get a 50-basis-point return on equity adder, which, Charkoudian said, translates to an extra $20 million in costs for the state’s consumers. Mandating membership in state law would save consumers “a significant amount of money,” she said. (See Citing California Law, FERC Rejects PG&E Request for RTO Adder.)
The other remaining section of the bill would require utilities to submit yearly reports to the PSC, detailing all their votes at RTO meetings, regardless of whether the proceedings and voting records already had been reported publicly.
Another Charkoudian bill, H.B. 1112, would allow the PSC to require the state’s utilities to acquire or contract for utility-scale energy storage projects if the commission finds storage to be a more cost-effective and efficient alternative to a reliability must-run (RMR) contract to keep a power plant running past its planned retirement date.
Charkoudian sees the bill as a new way to respond to situations like the potential closure of the Brandon Shores coal-fired power plant in 2025 and PJM’s efforts to keep the plant open with an RMR until 2028. PJM recently rejected the idea of storage as an alternative solution, as proposed in a recent report from GridLab and Telos Energy. (See PJM Rejects Storage as Alternative to Brandon Shores RMR.)
Passage of H.B. 1112 could provide a new option for Maryland, Charkoudian said. “We could spend all this money on reliability must-run, and [at] the other end, all we have is more greenhouse gas emissions and more pollution. Or we could take that very same money and spend it on battery storage, and we get the same reliability.”
But, she acknowledged, even if the PSC were to decide that storage would be a better option, PJM still would have to sign off on it. The bill passed 101-37 and was sent to the Senate Committee on Education, Energy and the Environment.
Other Bills Crossing Over
S.B. 1, sponsored by Sen. Malcolm Augustine (D), would require the state’s retail electricity providers that offer “green power” to their customers to document whether they actually are selling electricity generated by a renewable power project or the renewable energy certificates (RECs) from a project that could be located outside the state.
To offer green power, a retail supplier must show that the electricity being provided is at least 51% from renewables or RECs or at least 1% more than the amount of clean power required under the state’s renewable portfolio standard. For 2024, the state’s RPS calls for about 37% of Maryland’s power to come from renewables, but Gov. Wes Moore (D) has committed the state to 100% clean power by 2031.
Retailers also would have to have visible disclosure statements on their websites, explaining the purchase of a REC would not necessarily mean renewable energy also has been purchased.
The green power provisions are part of a larger bill focused on regulation of retail power suppliers. S.B. 1 passed in the Senate 33-14 on March 8 and was referred to the House Committee on Economic Matters.
Fraser-Hidalgo also is a lead sponsor on H.B. 689, which would replace Maryland’s $3,000 excise tax credit for electric or fuel cell vehicles with a rebate of the same amount, which auto dealers would provide at the point of sale. The original bill would have limited rebates based on consumers’ income, but those requirements were stripped out. The bill also includes $1,000 rebates for electric motorcycles and $2,000 rebates for three-wheeled motorcycles or “autocycles.”
The bill passed 103-36 on March 18 and has been referred to the Senate Committee on Budget and Taxation.
In a 20-day ballot period that ended March 18, industry stakeholders voted down NERC’s proposed reliability standard that would require entities to implement internal network security monitoring (INSM) on certain cyber systems.
As a result of the ballot, which saw the proposed CIP-015-1 receive a 48.52% segment-weighted vote for approval — a two-thirds majority is required for passage — the standard will be sent back to the standard drafting team for Project 2023-03 for revision. Future ballot periods for the standard may be shortened in accordance with a decision by NERC’s Standards Committee at its February meeting to authorize reducing additional comment and ballot periods to as little as 10 days. (See NERC Committee Greenlights Shortened INSM Comments.)
The SDT created CIP-015-1 after a previous proposed standard, CIP-007-X (Cybersecurity — systems security management), failed to pass its initial comment and ballot period in January with only a 15.42% segment-weighted approval. Due to feedback received during that comment period, team members said they felt creating a new standard would “ensure that the purpose and requirements [of the standard] are clear and allow for future expansion if necessary.”
Although this technically was the first ballot for CIP-015-1, NERC elected not to form a new ballot pool, keeping the same stakeholders that voted on CIP-007-X. The project’s page on NERC’s website said no changes will be made to CIP-007, which “will revert to the currently enforced version,” CIP-007-6.
Respondents generally were supportive of breaking out the security monitoring requirements into a new standard, although some commenters asked why the SDT hadn’t gone further. James Keele and Gail Golden, both representing Entergy, pointed out that “other standards already require [cybersecurity] monitoring,” naming CIP-003-8 (Security management controls), CIP-005-7 (Cybersecurity — electronic security perimeter(s)), CIP-007-6 and CIP-010-4 (Cybersecurity — configuration change management and vulnerability assessments).
Keele and Golden suggested the SDT consolidate the security monitoring requirements from those standards into the new standard as well. An unnamed commenter representing the Tennessee Valley Authority shared similar sentiments — though only mentioning CIP-007 and CIP-003 to be consolidated — as did Alain Mukama from Hydro One Networks.
Keele and Golden also expressed reservations about requirement R1 of the proposed standard, which provides guidance to help registered entities “identify network data collection location(s) and method(s) by implementing a risk-based approach focused on network security risks.” Their comments said the wording of the requirement was not “clearly aligned with expectations in the measures [section of the standard] and the technical rationale,” putting entities at risk of being found noncompliant in audits.
“The wording of CIP-015-1 R1.1 … appears to provide entities the latitude to identify [data collection locations and methods] based on risk, but without an expectation of an exceedingly robust methodology and without an expectation to consider all possible network data collection locations,” Keele and Golden said. “The requirement should be updated to … start with a list of all/many [network monitoring] locations and apply well-defined risk criteria … against that list to arrive at the final locations subject to the program.”
Cain Braveheart, writing on behalf of the Bonneville Power Administration, also suggested the requirement’s language “leaves it open for auditor interpretation” and “some level of deference must be offered to an entity’s risk management approach,” or that NERC should “create auditor guidance on what a risk-based approach looks like.” He also asked the SDT “clarify the term ‘locations’ in the requirement, adding context currently only found in the technical rationale.”
NERC’s Standards Committee will hear an update on Project 2023-03 at its upcoming meeting on March 20; the SDT will meet the following day to consider its next steps. The ERO considers the INSM effort a high-priority project because FERC has ordered it to submit standards requiring INSM by July 9 of this year. (See FERC Orders Internal Cyber Monitoring in Response to SolarWinds Hack.)
The upcoming April 8 solar eclipse will run a course from central Mexico to Newfoundland, but grid operators far from its 124-mile-wide path of totality will be dealing with its impact as it cuts output from solar power generation coast-to-coast.
According to NASA, major cities including Dallas and Indianapolis will feel the full brunt of the eclipse that afternoon, but RTO and ISOs are preparing for system challenges as far west as California.
While it is too early to accurately predict the weather, the National Weather Service noted that six selected cities in its path typically see temperatures in the 60s on that date.
ERCOTsaid the eclipse will affect its territory from 12:10 p.m. to 3:10 p.m., peaking about 1:40 p.m., when solar production likely will drop to about 7.6% of the maximum expected under clear conditions. ERCOT has 22,463 MW of installed capacity and has received about 7% of its power from solar this year, according to its latest data.
The Texas grid operator is working with solar forecast vendors to ensure their models accurately forecast the eclipse’s impact. ERCOT plans to receive and review ad-hoc forecasts March 29 and then start to prepare for major generation ramps caused by the eclipse, which will occur on a Monday.
ERCOT said it would review its day-ahead market results the day before the event to ensure its system is ready.
MISO’s Carmel, Ind., headquarters and its southern operations center in Little Rock, Ark., both are in the path of totality and respectively should experience darkness for 3 minutes, 29 seconds and 2 minutes, 30 seconds. The impact on solar will depend on cloud cover. With clear skies, solar output in the RTO could plunge quickly by about 4,000 MW, but clouds could limit that to a drop of less than 1,000 MW.
At the event’s start, solar generation will roll off the system rapidly and increase rapidly near the conclusion, resulting in the need for ramping capacity and possibly causing congestion-management challenges, MISO said. The temperature drop associated with darkness could lower demand, the RTO noted.
In a presentation to Entergy’s Regional State Committee last year, MISO noted it learned from eclipses in 2017 and 2023 that balancing and congestion management are the most challenging issues.
SPP did not have recent analysis on its website and did not return a request for comment. In a report covering the August 2017 eclipse, it noted this year’s event would be another test of its ability to balance renewable energy because solar penetration has grown.
PJM
PJMsaid March 18 the path of totality will enter its footprint northwest of Cincinnati and exit over three counties in Northwest Pennsylvania. The total eclipse will cover the 124-mile path for up to several minutes, but the RTO said almost its entire 13-state footprint will see some impact over about 2.5 hours.
Regardless of cloud cover’s effects, PJM is expecting to lose at least 80 to 85% of the output from its 8,200 MW of grid-connected solar and is preparing for the potential temporary loss of up to 4,800 MW of behind-the-meter solar.
The dimming sunlight could lower temperatures by 4 to 10 degrees, but the impact will depend on how warm the weather is absent the eclipse. Under cool conditions, a temperature drop could lead to higher demand, but in warm conditions, the decrease likely would reduce loads.
PJM said it would provide an update of the eclipse’s anticipated impacts under a clearer weather forecast at its April 4 Operating Committee meeting.
Northeast
NYISO said in a presentation last September that the total eclipse will affect its territory from 3:16 to 3:29 p.m., but the event will leave some impact for about 2.5 hours. New York City and Long Island are expected to see between 60 to 90% obscuration of the sun, while Albany should see 96%.
Both Buffalo and Rochester will have several minutes of total eclipse. Those cities typically have about 60 to 65% cloud cover that time of year, NYISO said. With clear skies, solar output from both behind-the-meter and grid-connected solar could fall by more than 3,110 MW at the eclipse’s peak.
Impacts to wind power also are expected, as seen during the 2017 eclipse, when wind speeds and output dropped at the start of the event and increased as it ended, the ISO said.
ISO-NEsaid the eclipse could cut solar production in its territory by thousands of megawatts from 2:15 to 4:40 p.m. when all of New England will see at least 80% obscuration, with some northern areas seeing 100%.
Most of New England’s solar power comes from small-scale, distributed systems that either are connected to retail customers or utilities’ distribution systems and not the ISO-operated grid. Those systems effectively cut demand for wholesale power when the sun is out.
The eclipse’s impact will make solar output drop off much more quickly than it normally would at sunset but, as in other areas, ISO-NE said impacts will depend on cloud cover.
Out West
The eclipse’s effects will even be observed in the Western Interconnection.
CAISO’s balancing authority area will experience a partial eclipse from about 10 a.m. to 12:30 p.m. PT. Relative to the eclipse of Oct. 14, 2023, the sun will be less obscured in CAISO territory: about 25 to 59% on April 8 compared to roughly 72 to 80% on Oct. 14.
And the profile of impacts will be different because the April 8 eclipse will start later in the morning, during greater solar generation. The Oct. 14 eclipse lasted from about 8 to 11 a.m. in California, with maximum impact about 9:30 a.m.
CAISO’s April 8 forecast shows utility-scale solar dropping 6,349 MW between 10 a.m. PT, a peak at 11:20 a.m. and a 6,718-MW surge in solar generation by 12:40 p.m.
The predicted upward ramp of 84 MW per minute is less than the Oct. 14 rate of 131 MW per minute.
The projections for April 8, based on clear-sky conditions, are in a technical bulletin released this month. CAISO has been planning for the April 8 eclipse since February. Once again, coordination will be key to eclipse preparations.
CAISO plans to use quick-ramping resources, including natural gas plants, battery storage and hydropower, to respond to rapid changes in solar generation.
“To manage the solar ramps, the ISO has done extensive outreach to scheduling coordinators and market participants to emphasize the importance of following dispatch operating targets (DOTs) in real time,” especially for solar and battery resources, CAISO said in a frequently asked questions document.
CAISO will coordinate with gas plants and gas suppliers to ensure sufficient supply during the eclipse.
In response to the ramping needs, CAISO said it expects to commit an increased amount of regulation up and regulation down. But adjustments, especially to regulation up, likely will be smaller than in October due in part to lessons learned from that event.
CAISO is holding meetings on the event with WEIM entities.“Coordination across the WEIM is crucial so that the market can optimally dispatch during the eclipse conditions,” the ISO said.
ALBANY, N.Y. — Building decarbonization is at once critical for the environment, expensive for building owners and potentially taxing for the power grid.
Four people helping plan and direct decarbonization in New York acknowledged the complicated nature of the task and offered insight on how it is being approached March 19 at the Independent Power Producers of New York’s 2024 Clean Energy Spring Conference.
The clean energy transition New York leaders are pursuing will not happen without a high percentage of the state’s 6 million buildings using less energy and cleaner energy. Buildings are the largest source of greenhouse gas emissions in New York City, and second-largest by a narrow margin in the rest of the state.
And therein lies the difficulty: Millions of building owners need to take action to make it happen, in many cases at their own cost, to get New York to its 2050 goal of 85% GHG emissions reduction.
“That’s a lot of people to get engaged in this transition, and that’s really challenging, but also a great opportunity to reach everyone in the state and bring them into what this transition is going to mean for them,” said Susanne DesRoches, vice president for clean and resilient buildings at the New York State Energy Research and Development Authority.
A sticky problem is that many buildings in New York predate modern efficiency standards. Constructing highly efficient, all-electric buildings — which is gradually being mandated in the state — can cost a bit more but is relatively straightforward. Electrifying an existing building and making it more efficient can be much more complicated and expensive.
“Most of the buildings that we will have in 2050 and beyond are already built, so the real challenge is figuring out how to tackle emissions reductions in those buildings,” said Danielle Manley, policy manager at the Urban Green Council.
But efficiency is an indispensable part of the process, she added. She showed a map of Consolidated Edison’s 70 network areas under three electrification scenarios. Electrification by itself would put numerous areas into grid constraint, based on their current capacity. Electrification with efficiency would reduce the number of areas in constraint.
“The third scenario — that’s our smart electrification scenario: buildings electrify; they make energy efficiency upgrades; and they incorporate load shifting, thermal storage and electric battery storage — we see most of the areas back in the blue,” Manley said.
Much of the discussion centered on New York City. Because of its lack of heavy industry and its extensive public transit system, the city’s buildings have an outsized influence on its carbon footprint compared with the rest of the state.
The city also has some of the nation’s most expensive real estate and highest electric utility rates. And for all its glitz and wealth, it also has a poverty rate 50% higher than the U.S. as a whole.
So, who is going to pay for all these upgrades?
Zachary Steinberg, policy lead at the trade association Real Estate Board of New York, said the city’s Local Law 97, which will penalize building owners who do not electrify their property, is not an effective incentive; the return on investment is just too small. “Yes, the penalties are significant, but they’re only a fraction of the cost of what it’s actually going to take to improve buildings and decarbonize, particularly if we’re combining building electrification with efficiency work,” he said.
There need to be more incentives to perform the work and more assistance paying for it, he added — fewer sticks and more carrots. Kathleen Schmid, deputy executive director of the New York City Mayor’s Office of Climate and Environmental Justice, said the city recognizes sticks are needed as it pursues decarbonization but wants to focus on carrots.
“We need a program that gets to emissions reductions,” she said. “We will see this as a failure if we instead levy significant amounts of fines.”
Local Law 97 sets an ambitious target: a 40% reduction in emissions from the largest buildings by 2030 and net zero by 2050. “We know there’s challenges, and we’re working through those challenges,” Schmid said. “We know the 2030 targets are going to be hard to achieve, particularly for those buildings with complex ownership structures in the residential space.
“To Zach’s point, we know that it is a problem to shift the cost of heating from a building owner to a tenant. … There are significant equity and financial concerns. … The city is looking at all those ramifications.” Healthier, better-performing building stock is a high-value proposition for New York City, Schmid said, so Local Law 97 should be seen as a tool for modernizing buildings rather than a burden for their owners.
“It’s not a thing that we’ve successfully figured out how to do across the board,” she acknowledged.
Three conservative- and libertarian-leaning organizations have filed a federal lawsuit to block construction of the Coastal Virginia Offshore Wind (CVOW) project.
The complaint, filed March 18 with the U.S. District Court for D.C., alleges federal regulators conducted a flawed review of the proposed project’s potential impact on the critically endangered North Atlantic right whale and that other federal agencies accepted this flawed analysis.
The plaintiffs — the Committee for a Constructive Tomorrow (CFACT), the National Legal and Policy Center (NLPC) and The Heartland Institute — assert this was a violation of the Endangered Species Act and the Administrative Procedure Act and ask the court to halt work on CVOW until the flawed review is supplanted by a legally compliant review and a valid “biological opinion” about the impact on marine life is issued.
The defendants are the Department of the Interior, the Bureau of Ocean Energy Management, Commerce Secretary Gina Raimondo, the National Marine Fisheries Service and project developer Dominion Energy.
In a statement, Dominion said the complaint is baseless and that full measures are in place to protect whales and other marine wildlife.
With 176 turbines rated at a combined 2.6 GW, CVOW is the nation’s largest offshore wind proposal and one of the most mature: BOEM greenlit it Oct. 31. (See BOEM Approves Coastal Virginia Offshore Wind.) Onshore assembly and staging of components has been underway for months, and offshore installation will begin in May.
Multiple lawsuits have been filed under multiple theories of law against projects along the Northeast coast that form the vanguard of what proponents hope and opponents fear will become a major new clean energy sector. A few thousand turbines rated at a few dozen gigawatts are envisioned from Canada to the Carolinas — along the migratory route of the North Atlantic right whale.
The complaint against CVOW charges that federal regulators are looking at the impact of all these projects individually rather than as a whole. This ignores the cumulative potential impact on whales, it says.
“Playing politics with such an iconic species as the right whale is a truly pathetic example of the Biden administration’s allegiance to climate alarmism,” Heartland President James Taylor said in a statement.
“This project is not in the interests of Dominion Energy shareholders or customers,” NLPC CEO Peter Flaherty said. “It was only approved because Dominion Energy has undue influence on Virginia politics through outsized contributions to both Democrats and Republicans.”
And CFACT President Craig Rucker said: “This piecemeal, incremental step analysis by BOEM is a textbook violation of the Endangered Species Act. Every court, including the District of Columbia, has held this individual approach to be illegal.”
Dominion offered this rebuttal: “The issues raised in this lawsuit have no merit. The Bureau of Ocean Energy Management has done an extraordinarily thorough environmental review of the project and carefully considered potential impacts to marine wildlife and the environment. The overwhelming consensus of federal agencies and scientific organizations is that offshore wind does not adversely impact marine life. We’ve put in place strong environmental protections for this project and are confident the North Atlantic right whale will be protected.”
The role of renewable natural gas (RNG) and hydrogen in decarbonizing Massachusetts’ heating sector has been a major topic of debate for several years, with major implications for the state’s gas network and electrical grid.
Questions about alternative fuels were a major focus of the Department of Public Utilities’ three-plus-year investigation into the future of gas in Massachusetts, which ultimately concluded that the state’s gas utilities should not be able to recover costs associated with blending RNG or hydrogen into the gas supply from the general rate base (DPU 20-80). (See Massachusetts Moves to Limit New Gas Infrastructure.)
Despite the DPU’s order, arguments over alternative fuels have remained a main point of contention in the Department of Environmental Protection’s (DEP) development of a “clean heat standard” (CHS), a program aimed at incentivizing emissions reductions from the state’s buildings sector.
As proposed, the standard would apply to suppliers of heating energy at the retail level, including suppliers of oil, propane, natural gas and electricity. Residential suppliers would be required to obtain two types of credits — for full electrification projects and for emissions reductions — with the requirements increasing over time to keep up with state’s electrification and decarbonization goals.
Suppliers could meet the requirements by embarking on projects themselves, purchasing credits associated with other projects or making alternative compliance payments (ACPs).
In a reflection of the complexity of the program and the significant impacts it could have for the state’s clean energy transition, several questions have emerged in the stakeholder engagement process:
How should credit requirements be allocated between different suppliers? How should the state measure emissions reductions? What is the role of ACPs? How should the program work for industrial and commercial heating? And, finally, what heating technologies should be eligible to generate credits, and therefore be incentivized by the program?
In the draft framework released by the DEP in the fall, hydrogen and RNG are not eligible to generate credits, due to the state’s aim at focusing the CHS on incentivizing electrification. This direction was met with applause from climate advocacy organizations and outcry from industry and utility-aligned groups.
“We are surprised and concerned that the Draft CHS Framework does not include any crediting for renewable gaseous fuels as part of Massachusetts’ building decarbonization solution,” commented the Coalition for Renewable Natural Gas, whose membership includes several of the state’s gas utilities, RNG producers and fossil fuel companies.
“The portions of the gas system which currently serve the residential and commercial customers targeted for electrification will remain in place for a very long time, even with aggressive fuel-switching policies, and would be well-served by increasing renewable gases while that transition occurs,” the RNG coalition wrote.
Other companies and industry groups, including the American Biogas Council, the American Public Gas Association, the Associated Industries of Massachusetts and the Mass Coalition for Sustainable Energy, opposed the exclusion of alternative gases from credit generation.
Meanwhile, the omission of hydrogen and RNG from the program was praised by climate and environmental organizations, which have opposed policies that incentivize blending alternative fuels into the gas system.
“The ineligibility of gaseous biofuels and hydrogen under the CHS is absolutely essential for keeping the commonwealth on the most cost-effective trajectory towards building decarbonization,” wrote the Acadia Center.
Environmental organizations in the state have long expressed concerns that electrification is the most efficient pathway to decarbonizing the building sector and that blending alternative fuels into the gas network would deliver minimal climate and public health benefits at a high cost to gas ratepayers.
The Acadia Center made the case that making hydrogen and RNG blending eligible to generate credits would be in “direct conflict” with the DPU’s 20-80 Order on gas system decarbonization.
In the order, the DPU wrote that it “rejects the recommendation to change its current gas supply procurement policy to support the addition of renewable natural gas to LDC supply portfolios due to concerns regarding the costs and availability of RNG, as well as its uncertain status as zero-emissions fuel.”
The DPU added that gas system upgrades to support the blending of alternatives fuels must be entirely funded by the customers that procure the alternatives, instead of the general rate base.
The DEP said in a statement it’s committed to ensuring the standard is “consistent with the goals of DPU 20-80,” as well as the state’s existing Mass Save energy efficiency program. Energy efficiency measures are not eligible for clean heat credits “to avoid unnecessary complexity and redundancy with the Mass Save program.”
Under the draft framework, certain liquid biofuels would be eligible for the emission reduction credits. Waste-based biofuels that are eligible for the state’s Alternative Portfolio Standard would receive full credits, while fuels that are eligible only for the federal Renewable Fuels Standard would receive a half credit. As proposed, this half credit would end in 2030.
As with hydrogen and RNG, the biofuel industry has pushed to expand the range of fuels that are eligible for credits, while environmental groups have argued for tighter constraints around what fuels can be considered. Wood heating also would not be eligible for credits, drawing the ire of the wood pellet industry.
The DEP has indicated that “no final decisions have been made” on the CHS and is considering public feedback on all aspects of the standard. The department has committed to revisiting the credit eligibility of different heating options at the 2028 program review.
Beyond questions about credit eligibility, the proposed credit requirements for electricity suppliers have been met with pushback from both the utilities and environmental organizations, which have argued these obligations could undermine incentives for consumers to adopt heat pumps.
“As constructed, the framework will likely increase electric rates, increasing operating costs of electric heat, which is counterproductive to the commonwealth’s electrification goals,” Eversource commented.
The DEP is aiming to release a formal draft proposal of the CHS in the fall and has two stakeholder meetings scheduled in early April, along with a comment deadline April 5.
