FERC on Thursday approved NERC’s proposed plan for registering owners and operators of inverter-based resources (IBRs) (RD22-4).
While the commission declined to incorporate any of industry stakeholders’ suggested changes to the plan, it reminded them there is still considerable work left to shape the final registration framework and encouraged them to raise their concerns during the ERO’s stakeholder process.
NERC’s registration proposal originated from a FERC order in November requiring the ERO to develop a work plan for identifying and registering owners and operators of IBRs that are connected to the grid and “in the aggregate have a material impact” on reliable operation but are not currently required to register with NERC. (See FERC Addresses IBRs in Multiple Orders.)
The commission was motivated by concerns over the ongoing transition from conventional generation resources to IBRs like wind and solar facilities. Specifically, current rules defining which resources qualify as part of the Bulk Electric System — and thus must register with NERC, follow its reliability standards and respond to its alerts — do not apply to many smaller IBRs.
NERC submitted its registration strategy in February, proposing a three-stage process: revise its Rules of Procedure (ROP) to create a new registered entity function, generator owner-IBR (GO-IBR), within 12 months of FERC’s approval of the plan; identify candidates for GO-IBR registration with 24 months of approval; and register GO-IBRs within 36 months of approval.
The GO-IBR category would include IBRs that have an aggregate nameplate capacity of 20 to 75 MVA interconnected at a voltage of at least 100 kV, or an aggregate nameplate capacity of at least 20 MVA interconnected at less than 100 kV. IBRs connected to the local distribution system would not be included; neither would IBRs that are distributed energy resources. NERC said it would also consider developing reliability standards to apply to GO-IBRs.
The ERO’s original submission neglected to mention registration of generator operators; at FERC’s prodding, NERC said in March that it intended GO-IBR to refer to both owners and operators of IBRs, but it acknowledged that this practice would differ from its use of separate terms for existing registered generators and could create confusion. NERC pledged to consider “other potential designations” when revising the ROP.
Stakeholders were generally supportive of NERC’s proposal, but some asked the commission to modify the ERO’s plans. For example, the American Clean Power Association (ACP) and the Solar Energy Industries Association (SEIA) objected to the idea of only registering IBRs with an aggregate material impact on reliability, suggesting that this measure could result in the registration of IBRs that “use equipment and settings that ensure that they ride through grid disturbances and avoid reliability concerns that were observed in past events.”
Solar energy developer Pine Gate Renewables urged the commission to ensure that NERC’s work plan does not place IBRs at a competitive disadvantage compared to conventional generation, noting that the commission has previously ordered that reliability standards not create undue advantages for one competitor over another. Pine Gate, along with SEIA and ACP, also argued that older IBRs may be unable to meet the standards’ performance requirements and asked for a registration exemption for IBRs with older equipment that cannot be easily updated.
In response to these objections, FERC determined that issuing specific restrictions on NERC’s ROP or standards development processes would be outside its authority. Instead, it urged stakeholders to participate in the normal feedback process to influence the ERO’s actions.
During FERC’s monthly open meeting Thursday, acting Chair Willie Phillips said reliability is “job No. 1 for the commission” and described the IBR order as an important step in dealing with the “projected addition over the next decade of an unprecedented proportion” of IBRs.
Commissioner Allison Clements said she looks forward to “engaging” with the ERO as work continues on the registration framework.
“I hope that NERC’s substantive filing on its registration approach, which is still to come, ensures an effective registration framework but does not compromise IBRs’ ability to provide the reliability services they are capable of providing, including … reactive power, black start and fast frequency response,” Clements said.
President Joe Biden on Tuesday made good on his pledge to veto a proposed resolution that would have rolled back a two-year moratorium on solar tariffs imposed on cells and panels produced in Cambodia, Malaysia, Thailand and Vietnam.
Passed with bipartisan support in the House of Representatives and the Senate, the bill, H.J. Res. 39, “disapproved” the moratorium and declared it “shall have no force or effect.”
The House passed the resolution on April 28, by a vote of 221-202, with 12 Democrats joining the GOP majority and eight Republicans opposing the measure.
Nine Democratic senators supported the measure in the Senate, where it passed on a 56-41 vote on May 3. The Democrats voting for the resolution were senators Joe Manchin, (W.Va.), Sherrod Brown (Ohio), Ron Wyden (Ore.), Bob Casey (Pa.), Jon Tester (Mont.), Debbie Stabenow (Mich.), Gary Peters (Mich.), John Fetterman (Pa.) and Tammy Baldwin (Wis.).
Because neither house is likely to muster the two-thirds majority needed to override the veto, the House and Senate votes and the resolution itself were mostly political posturing, giving Democrats and Republicans cover to appear tough on China and the solar industry’s ongoing reliance on overseas suppliers. About 80% of solar panels used in the U.S. come from the four Asian countries in question, according to the Commerce Department.
In his veto message to the House, Biden characterized the moratorium, which the Commerce Department issued in June 2022, as a “24-month bridge” to allow the buildout of a domestic solar supply chain that will break the industry’s dependence on Southeast Asian countries and China.
Since the passage of the Inflation Reduction Act, Biden said, “private companies have announced commitments to build enough solar panel manufacturing capacity to power nearly six million homes.
“America is now on track to increase domestic solar panel manufacturing capacity eight-fold by the end of my first term. But that production will not come online overnight,” he said. “The Department of Commerce’s rule supports American businesses and workers in the solar industry and helps provide sufficient, clean and reliable electricity to American families, while continuing to hold our trading partners accountable.”
The veto message also repeated Biden’s commitment that he will not extend the moratorium when it expires in June 2024.
The president ordered the waiver on tariffs on solar panels and cells imported from Cambodia, Malaysia, Thailand and Vietnam last year, after the Commerce Department announced an investigation into whether panels and cells from those countries contain components from China that would be subject to tariffs. (See Biden Waives Tariffs on Key Solar Imports for 2 Years.)
Reactions
Industry trade groups and individual installers were quick to back the president’s action.
“President Biden’s veto has helped preserve our nation’s clean energy progress and prevented a bill from becoming law that would have eliminated 30,000 American jobs, including 4,000 solar manufacturing jobs,” said Abigail Ross Hopper, CEO of the Solar Energy Industries Association (SEIA). “This action is a reaffirmation of the administration’s commitment to business certainty in the clean energy sector and a signal to companies to continue creating jobs, building domestic manufacturing capacity and investing in American communities.”
Gregory Wetstone, CEO of the American Council on Renewable Energy, agreed. “President Biden’s veto today is a welcome step to avoid a disastrous impact on the U.S. economy and ensure continuing progress toward the clean energy transition and our climate goals,” he said. “The [resolution] passed by Congress would have changed the rules renewable developers and manufacturers rely upon, resulting in many dozens of canceled solar projects, tens of thousands of lost jobs, and a dangerous increase in carbon emissions.”
George Hershman, CEO of SOLV Energy, a utility-scale solar contractor, said the veto would “provide clarity to domestic solar manufacturers and allow the industry to move forward on important projects that boost solar deployment.”
On the other side, Rep. Dan Kildee (D-Mich.), one of the Democrats who voted for the resolution in the House, expressed disappointment with the veto and called for an override vote.
“Failing to stand up to those who engage in unfair trade practices hurts American workers and manufacturers,” Kildee said in a statement Tuesday. “Our workers and businesses will never be able to compete globally unless we hold those who violate U.S. trade laws accountable. The Biden administration found, in its own investigation, that Chinese companies are violating the law. Yet the president’s position, and today’s veto, fails to hold China accountable and hurts American workers.”
Robbie Diamond, CEO of SAFE, a group focused on reducing U.S. dependence on foreign oil, appeared to favor a tariff rollback, as reported in The New York Times.
“We must back up the message of wanting to build a U.S. supply chain with action — even if it is difficult and complicates some deployments,” Diamond said. “If we’re going to talk the talk, we must walk the walk.”
The Supply Chain Buildout
Prior to the passage of the Infrastructure Investment and Jobs Act and Inflation Reduction Act, tariffs on Chinese solar panels and cells were not particularly effective in kickstarting a domestic supply chain. Even after former President Donald Trump approved the tariffs on Chinese solar panels and cells in 2018, the solar industry continued its dependence on Southeast Asian and Chinese manufacturers.
But the announcement of the Commerce Department investigation the following month threw the industry into an uproar, with more than 300 projects delayed or canceled, according to SEIA. Biden’s moratorium, and the IIJA’s and IRA’s tax credits, finally provided the impetus for companies to start investing in new facilities in the U.S.
The American Clean Power Association recently reported that more than $150 billion in domestic utility-scale clean energy investments have been announced in the last eight months. “This amount is equivalent to five years’ worth of American clean energy investments, surpassing total investment into U.S. clean power projects commissioned between 2017 and 2021,” ACP said.
Even so, there’s no guarantee that an adequate domestic supply chain will be up and running by June 2024, when the moratorium runs out.
The Commerce Department issued a preliminary finding in the investigation in December, stating that “certain Chinese solar panel manufacturers were indeed attempting to bypass the [tariffs] via transport through these investigated Southeast Asian partners.” A final decision has been pushed back from May to August.
Two recent reports quantify the rapid growth of the U.S. offshore wind sector, while a third flags technical and reliability challenges posed by the ever-larger scale of turbines being installed.
There are just seven turbines spinning in U.S. waters, but thousands more are being planned. The American Clean Power Association’s (ACP) May 2023 Offshore Wind Market Report puts the U.S. development pipeline at nearly 51,400 MW, while the Business Network for Offshore Wind’s (BNOW) first-quarter report puts the combined goals of oceanfront states at 83,900 MW.
A comparison shows the growth of offshore wind equipment through the years. | GCube Insurance
Meanwhile, GCube Insurance in its second-quarter report this month warned that the latest-model high-capacity wind turbines favored by many developers are showing an unprecedented number of component failures, mechanical breakdowns and serial defects.
And the National Offshore Wind Research and Development Consortium in an April update of its road map points out a shortage of operational experience and data that could guide development of the large turbines planned for U.S. waters.
The potential consequences of this concurrent push for size and speed are that standardized, modular construction and the resulting economies of scale become hard to achieve and that quality control suffers.
This has been flagged many times by stakeholders, analysts and manufacturers. But taken together, the spate of recent reports provides a new look at the issue with fresh data.
Big Plans
The U.S. is very late to the offshore wind sector.
Thirty-two years after the first offshore wind farm went online in Denmark with a 5-MW capacity rating, worldwide installed capacity is 63,200 MW, with just 42 MW of it in U.S. waters. But the country is trying to make up for lost time to reduce greenhouse gas emissions and limit harm to the environment. President Joe Biden has set a national goal of 30 GW of offshore wind capacity installed by 2030 and 15 GW of floating offshore wind by 2035.
Major logistical hurdles stand in the way of the first goal: Domestic infrastructure and capacity to fabricate and install 2,000 fixed-bottom wind turbines are virtually nonexistent, and today’s grid cannot carry all those electrons.
But U.S. developers and regulators can at least draw on the body of knowledge gained from the 63 GW of fixed-bottom wind power in foreign waters. There is no such operational history with floating wind.
ACP’s report notes there are now 32 offshore wind leases in active development nationwide, with 18 projects in early development and 18 in advanced development. They total 51,377 MW of nameplate capacity, 938 MW of which is now under construction.
Most of this is on the East Coast: New York and New Jersey lead the nation with 4,362 MW and 3,758 MW in their pipelines, respectively.
In its report, BNOW notes that numerous infrastructure upgrades and manufacturing expansions are being undertaken to help make all the megawatts envisioned a reality. It also notes that the federal government this year moved to streamline the yearslong review process for development.
So far, the only records of decision issued by the U.S. Bureau of Ocean Energy Management have been for the two projects totaling 938 MW now under construction: Vineyard Wind 1 and South Fork Wind off the New York/New England coast, which are both expected to come online this year.
Big Turbines
In this environment, and with costs spiraling, developers and manufacturers are trying to squeeze as many watts as possible out of each turbine to maximize return on investment.
One notable example: Avangrid in September said it was pushing the completion dates of its Park City Wind and Commonwealth Wind projects back one year to 2027 and 2028, respectively, in hopes that next-generation 17- to 20-MW turbines would be available in time. It said the cutting-edge turbines it would be installing in Vineyard Wind 1 in 2023 can produce only 13 MW.
Some observers warn that this continual upscaling creates the risk that nothing ever really moves beyond the prototype stage; designs would be continuously being tweaked, upgraded and replaced.
GCube in its report said the largest turbines in production five years ago were rated at 8 MW.
The Siemens Gamesa SG 14-222 DD offshore wind turbine has a capacity of up to 15 MW. | Siemens Gamesa
Fresh off December certification of its Haliade-X turbine for 14.7-MW operation, a GE executive told investors in March the company is preparing a variant that will produce 17 to 18 MW.
The GCube report — titled “Vertical Limit: When is Bigger not Better in Offshore Wind’s Race to Scale?” — asserts that while this relentless upsizing has sharply reduced the cost of wind power and sharply increased the amount of power produced, there are negative consequences:
manufacturers competing for market share sign contracts for next-generation equipment years before it goes into production, sometimes without fully understanding the necessary processes and pricing;
with ever-evolving technology, every project can have its own unique learning curve;
turbines are becoming obsolete only a few years into a projected 25- to 30-year lifespan, and replacement parts are sometimes unavailable;
maintenance and repairs are incrementally more difficult, costly and time consuming as machines get larger;
support infrastructure has trouble keeping up — only three vessels in the world can install the newest 15-MW turbines; they cost up to $2 million a day to charter; and they are booked for years to come; and
insurance claims are escalating, but insurers, eager to burnish their environmental, social and corporate governance credentials (ESG), continue to enter the offshore wind market.
GCube, which insures 100 GW of renewable energy projects in 40 countries, analyzed a decade of proprietary data and determined that offshore wind claims increased significantly in frequency and severity over the decade from 2012 to 2021, with turbine component failures increasing sharply after 2017.
It also found that as a proportion of total claims, larger turbines are generating more claims during construction than their smaller, older cousins did. Then, once installed, turbines larger than 8 MW are sustaining component failures much sooner than smaller units.
In a May 2 announcement, GCube CEO Fraser McLachlan presented the study and its data as a cautionary tale.
“The push to rapidly develop more powerful machines is piling pressure on manufacturers, the supply chain and the insurance market,” he said. “Scaling up is an essential part of driving forward the energy transition, but it is now creating growing financial risks that pose a fundamental threat to the sector. We advise manufacturers to focus on improving the quality and reliability of a reduced number of products to put themselves back on a sustainable path of development.
“At the same time, developers must support manufacturers by sharing the risk of larger machines more equitably and open their lending books to supply chain companies.”
Recurring Message
The GCube report’s warning of too much, too fast is a message expressed in different ways for different reasons by both opponents and proponents of offshore wind.
In an email to NetZero Insider, BNOW wrote of the climate and economic benefits of this rapid technological evolution but also flagged some concerns.
“The scale and speed of the technological advancement, however, is challenging for the supply chain to keep pace, let alone expand to meet rising demand,” the organization wrote. “Standardization and optimization are keys to creating more supply chain capacity, ensuring deployment goals are met and even further driving down costs, but those benefits must be weighed against fostering innovation in this still evolving industry.”
The National Renewable Energy Lab told NetZero Insider there would be greater value in industrializing at the current scale than in upscaling beyond 15 MW. NREL in its January offshore wind supply chain road map said it expected some modularity to evolve in design and construction of turbine nacelles. But it also saw the potential upscaling of nacelles from 600 tons to nearly 1,000 tons.
The R&D Consortium in Version 4.0 of its road map last month said operations and maintenance costs constitute more than 30% of the cost of offshore wind, and it is imperative to control those costs at the design stage.
However, it noted, there are few test facilities that can accommodate components on the 15-MW scale and no record of operations data from which to draw insight, as 15-MW turbines are so new.
“The offshore wind industry has been focused on turbine megawatt upscaling, but optimization of the current generation of 15-MW turbines for performance and load reduction has been compromised as a result,” the report noted. “The consortium does not envision direct support of new turbine development. Rather, acceleration of turbine optimization solutions in harmony with the needed industrialization and standardization of the supply chain would better serve U.S. development.”
It is likely, the consortium added, that maintenance systems and protocols for 15-MW turbines will be developed and proved in U.S. waters.
Quality Control
One after another in the past year, the major turbine manufacturers have acknowledged sharply escalating quality-control problems and warranty claims in their wind power products. To judge by their statements to investors and analysts, they have already embraced some of the points in the GCube report.
The GE Haliade-X 14.7MW-220 offshore wind turbine prototype is shown in Rotterdam, Netherlands. | General Electric
In an October 2022 earnings call, GE CEO H. Lawrence Culp Jr. spoke of the warranty costs that were a drag on the financials of GE Renewables and blamed some of that on rapid product development over the preceding five years.
“Such rapid innovation strains manufacturing and the broader supply chain,” he said. “It takes time to stabilize production and quality on these new products, which in turn pressures fleet availability. We need to industrialize faster to counteract these dynamics, and we are.
“We’re drastically simplifying and standardizing too many variants into what we call workhorse products, so we and our suppliers can implement more repeatable manufacturing processes. This enhances product quality and reduces cost. In our existing fleet, we’re deploying corrective measures, enhancements and monitor-and-repair programs.”
Vestas reported in February that lost production factor — the measure of energy production not captured by the 56,400 wind turbines under its service — has been rising steadily for several years, surpassing 3% by the end of 2022. Warranty costs equaled 6.3% of Vestas’ 2022 revenue.
“Lost production factor continues at high level as a consequence of the extraordinary repair and upgrade level,” it said in a quarterly report May 10, but the numbers were better: Warranty costs equaled only 4% of first-quarter revenue, compared with 7.8% in the first quarter of 2022.
“Optimizing the complete value chain calls for increased focus on improving our existing platforms,” Vestas said in its annual report. “We believe strongly in this approach, because introducing new platforms too fast obstructs supply chain industrialization. As turbine components become larger and more efficient, they also create logistical challenges to the expansion of wind power around the world. For this reason, we are paving the way for scale through modularization and optimizing how our products are designed and produced.”
And in a quarterly report to investors in February, Siemens Gamesa wrote, “Service performance during Q1 [2023] was severely affected by the outcome of the periodic monitoring and technical failure assessment of the installed fleet, which revealed a negative trend in the failure rate of certain components. As a result, the estimated cost of fleet maintenance and warranty provisions is higher than initially estimated.”
CAISO’s summer forecast looks better than last year’s thanks to the addition of thousands of megawatts of new resources and California’s record snowpack, which is expected to increase hydroelectric generation by 72% compared with drought conditions a year ago.
In its annual Summer Loads and Resources Assessment, published Tuesday, the ISO says it has made “sound progress towards meeting the conventional ‘one day every 10 years’ loss-of-load expectation planning target.”
“Under current high hydro conditions, the resource fleet scheduled to be online by June 1, 2023, exceeds the one-in-10 planning target with a margin of approximately 200 MW … [and with] the resource fleet scheduled to be online by Sept. 1, 2023, exceeds the one-in-10 planning target with a margin of approximately 2,300 MW,” the assessment says.
That compares with a 1,700-MW shortfall in meeting the planning target last year, CAISO management says in a slide presentation on the assessment.
“These results do not take into account more extreme events such as those demonstrated in the last several years, e.g., extreme drought, wildfires and the continued potential for widespread regional heating events and other disruptions that continue to pose a high risk of outages to the ISO grid,” it says.
California experienced energy emergencies caused by extreme heat and wildfires in the past three summers, when the state and much of the West endured worsening drought and decreased hydropower.
The ISO was forced to call for rolling outages in August 2020 during a Western heat wave that dried up imports. It declared an energy emergency in July 2021 when an out-of-control wildfire in Southern Oregon nearly shut down a major transmission pathway between California and the Pacific Northwest.
And it came within minutes of ordering blackouts during a record-setting heat wave in September 2022, when demand outpaced supply. (See CAISO Reports on Summer Heat Wave Performance.)
Since last summer, CAISO has been connecting thousands of megawatts of new battery and solar resources.
By June 1, the ISO expects to have connected 2,500 MW of solar and 2,300 MW of batteries since Sept. 1, 2022. By September of this year, it expects to add another 1,300 MW of solar and 2,000 MW of batteries, bringing the totals to 3,800 MW of solar and 4,300 MW of batteries and (8,100 MW total) added since September 2022, CAISO says in its slide presentation.
In addition, a series of atmospheric rivers this winter filled the state’s hydroelectric reservoirs and pushed the snow water content to approximately 240% of average on April 1, a key date for California’s measurement of snowpack in the Sierra Nevada. The snow melted slowly in April thanks to cloud cover and below-normal temperatures, the state Department of Water Resources said. (May, however, has been hotter than normal, including in the Sierra.)
“The year-to-date snow water content totals are significantly above average, which should result in above-average hydro energy generation in 2023,” the ISO’s summer assessment says.
The assessment does not include a projection of the amount of hydropower that could be generated, but it notes that the state has large and small hydroelectric facilities with more than 7,900 MW of installed capacity.
In the unusually wet winter of 2016/17, large and small hydro generated more than 43,000 GWh of hydroelectric power, compared with about 14,500 GWh in the drought of 2021, a 66% decrease, California Energy Commission records show.
On May 10, the U.S. Energy Information Administration forecast a 72% increase in hydropower generation in California this year compared to 2022.
“One source of uncertainty in our forecast is the possibility of warmer spring temperatures, which would melt the Sierra Nevada snowpack earlier than expected,” the EIA said. “In this case some of the melting snow may bypass power generating turbines for flood control purposes.
“Less snowpack also means less water available to supply hydropower plants during summer months, when electricity generation has historically been at its highest.”
CAISO management plan to present their findings to the Board of Governors at its meeting Thursday.
Senior officials from the U.S. and Canada were in Detroit on Tuesday to announce the first Binational Electric Vehicle Corridor, which will stretch from Kalamazoo, Mich., to Quebec City, Quebec.
The corridor will feature fast-charging stations every 50 miles along the roughly 900-mile stretch between the two cities. The announcement featured U.S. Transportation Secretary Pete Buttigieg, Michigan Gov. Gretchen Whitmer (D) and Canadian Minister of Transport Omar Alghabra.
“The U.S. and Canada have long enjoyed a productive partnership on transportation issues, and in that spirit we are proud to announce the first ever U.S.-Canada EV corridor,” Buttigieg said. “With historic investments in EV infrastructure from the Biden-Harris administration and the Canadian government, we are creating a new generation of good-paying manufacturing jobs, making it possible for drivers everywhere to reap the benefits and savings of these vehicles while helping us fight climate change.”
The Biden administration has a goal to have 50% of all new cars be electric vehicles by 2030 with support from the Inflation Reduction Act, Infrastructure Investment and Jobs Act, and CHIPS and Science Act, which have helped spur hundreds of billions of dollars in private-sector investment in EVs. The IIJA includes $7.5 billion in federal funding to help build a national network of 500,000 public EV chargers.
In Canada, one in 10 cars purchased is an EV.
Officials said the new binational corridor will help move passengers and goods along a key economic route.
“There’s nothing more ‘Pure Michigan’ than accidentally driving into Canada, and now that journey will be electric on either side of the border,” Whitmer said. “I am proud that we are working together to build up electric vehicle charging infrastructure. With the resources headed our way from [the IIJA] and the bold investments Michigan automakers are making right here in Michigan, we will build and lead the future of mobility.”
Michigan this month issued a request for qualifications seeking teams to design, build, operate and maintain EV charging stations across the state, the first part of its efforts to tap into $110 million through the National Electric Vehicle Infrastructure (NEVI) program. The deadline to submit applications is June 6.
In announcing the launch of the request, Whitmer said the program will help move NEVI funds into state communities to get the chargers set up efficiently.
Detroit also announced a change in its plans to roll out EV charging stations at 60 sites downtown and in recreation centers, saying the municipal government will lead the effort instead of leaving it to the private sector. The city is “going full bore” on EV charging development, Tim Slusser, Detroit’s director of mobility innovation, told Axios Detroit.
ALBANY, N.Y. — The New York State Reliability Council (NYSRC) Executive Committee on Friday indicated that the council’s Installed Capacity Subcommittee may increase the amount of 10-minute reserve assumptions from 350 MW to 400 MW in the next installed reserve margin (IRM) determination.
The NYSRC annually re-evaluates the state’s IRM and operating reserves requirements. NYISO’s summer net load variability, which used a new loss-of-load expectation window based on recently approved capacity accreditation requirements, was higher in some zones.
Inverter-based Resources Standard
The NYSRC received several questions and comments on its proposed rule establishing minimum requirements for inverter-based resources (IBRs) over 20 MW.
According to the NYSRC, the feedback will be reviewed to determine what changes, if any, should be made to the draft rule; if changes are made, it is likely the draft will be reposted for additional comments. The length of the posting and comment period will depend on the changes proposed. The council will publicly note if the comment period is reopened.
PRR-151 would establish standards for IBRs, as NYISO presently has no specific interconnection criteria for these resources. (See “Inverter-based Resources Standard,” NYISO Operating Committee Briefs: April 20, 2023.)
Stakeholder comments range from general questions on language, to more procedural or technical concerns about implementation, cost and new requirements.
The range of comments “reinforces that this a serious issue that we need to work through,” committee Chair Chris Wentlent said. He said he thought that New York “appears a bit ahead of our neighboring jurisdictions on implementation,” referring to a panel at the Independent Power Producers of New York’s Spring Conference last week that he participated in with PJM and ISO-NE staff. (See IPPNY Panelists Urge Collaboration, Coordination in Transition.)
Cap and Invest
Wentlent told attendees that the New York Department of Environmental Conservation (DEC) confirmed it would be taking the lead in implementing the state’s cap-and-invest program and plans to have draft regulations completed by the end of this year. The New York State Energy Research and Development Authority will assist.
Most details of the program have not been determined or announced by the DEC, but based on details in the state’s approved budget, it would charge companies for their carbon emissions to pay for clean energy projects and low-income utility payment assistance via an auction of credits. (See NY Budget Plan Details Cap-and-invest Proposal.)
Wentlent said he learned about the DEC’s intentions during a recent meeting he attended with it, the Department of Public Service and several other relevant agencies. He said that “realistically, [we’re] probably looking at a 2025 time frame” for the program to be implemented.
WESTBOROUGH, Mass. — The preliminary results of a joint study by ISO-NE and the Electric Power Research Institute (EPRI) found that the risks of a supply shortfall in ISO-NE during extreme winter weather events are “manageable” through 2027, even without the Everett Marine Terminal and the New England Clean Energy Connect (NECEC) transmission line in service.
But the results also showed that while shortfall risks were similar with or without Everett because of counterbalancing factors, scenarios with the NECEC in service consistently showed less energy adequacy risk, as well as decreased magnitude of the shortfall when it did occur.
ISO-NE presented the results, focused on the projected impacts of extreme weather on grid reliability in the winter of 2027, to the NEPOOL Reliability Committee on Tuesday. The study is part of a larger project with EPRI looking at historical and projected extreme weather events in New England and modeling the risks these events pose to energy infrastructure and grid reliability.
The modeling assessed reliability both with and without Everett and the NECEC, two major sources of uncertainty for the region’s 2027 energy mix.
“In the near term, the energy shortfall risk appears manageable,” said Stephen George, director of operational performance, training and integration for ISO-NE. “The risks are mitigated by incremental imports from New England Clean Energy Connect.”
The research team produced the results from a series of severe weather scenarios based on historical data going back to 1950, adjusted for 2027 based on five climate models and two emissions pathways. For each modeled event, the analysts looked at 21-day energy analysis results from 720 individual cases that differed based on variables including forced outages, LNG inventory, fuel oil inventory, imports and fuel prices.
Expected energy from stored fuels used in a long-duration severe cold-weather scenario, with and without NECEC and EMT | ISO-NE
In the weather scenario with the highest average system risk — modeled after an extreme cold stretch in the winter of 1961, the coldest 21-day period since 1950 — the probability of an energy shortfall ranged from 0.64% (with the NECEC and without Everett) to 7.6% (without the NECEC and with Everett).
ISO-NE noted that some scenarios with the Everett terminal in service are projected to have increased shortfall margins and risks because of faster depletion of LNG. Scenarios without the Everett terminal projected an increase in burning fuel oil and coal.
George highlighted how this model could be built upon and refined to look at future reliability scenarios.
“This energy adequacy study framework provides a much-needed foundation to study the system as it continues to evolve,” George said. “The ISO will continually monitor the energy adequacy risk, particularly as the changes in the regional supply and demand profiles ramp up.”
The RTO a year ago presented the findings of EPRI’s extreme weather modeling, which were used as an input to produce the study results.
This earlier portion of the study found that the frequency of extreme heat has increased over the past century, while extreme cold has decreased. The study defined extreme heat as daily maximum temperatures above the 95th percentile and extreme cold as daily minimum temperatures below the 5th percentile.
The study also noted that in general, winter temperatures have increased faster than summer temperatures, though cold extremes remain more common than heat extremes.
EPRI projected that these trends will continue in the coming decades, accompanied by a modest increase in precipitation. Wind speeds also are projected to increase in some locations. The study found that scenarios with higher emissions would amplify warming trends, with impacts differentiating for extreme cold around 2040 and for extreme heat around 2050.
George said the RTO will continue to assess the outputs of the 2027 winter study. The organization is also working on projections for the summer of 2027, as well as for the summer and winter of 2032. It hopes to present the results for summer 2027 prior to FERC’s New England Winter Gas-Electric Forum on June 20.
Using renewable natural gas (RNG) as a feedstock offers hydrogen producers a shortcut to claiming the full federal tax credit created by the Inflation Reduction Act (IRA) to incentivize hydrogen production.
That translates into a tax credit of $3/kg of clean hydrogen produced, or 2.6 cents/kWh of power generated using that clean hydrogen as fuel.
RNG is made from landfill gas or from biogas produced by anaerobic digesters that process municipal sewage or animal manure. Indistinguishable from fossil-based natural gas, RNG is also now more valuable as a fuel itself because the IRA expanded the federal production tax credit (PTC) to include biogas projects that begin construction before 2025. Previously, the PTC applied to only wind and solar projects.
Even before the IRA passed last year, interest in biogas had increased among companies looking for ways to increase their environmental commitments by purchasing electricity made by biogas-powered generators or by purchasing carbon credits associated with biogas.
The potential for producing hydrogen by steam reforming RNG has burnished the image of biogas as an important, if interim, fuel that could be critical to boosting hydrogen production as the industry works to build the massive numbers of electrolyzers needed to make clean hydrogen from water and determine where along the nation’s grid to locate them.
The idea has sparked the interest of biogas producers, as evidenced last week when the American Biogas Council (ABC) organized a webinar to announce it had retained Iowa-based engineering company EcoEngineers to create an accounting methodology as a tool to help biogas producers understand carbon accounting in fuels.
About 1,000 organizations registered for the webinar, the highest ever for an ABC event, said Patrick Serfass, the trade group’s executive director.
Getting the Right Score
A day after the webinar, an EcoEngineers representative participating in an unrelated online biogas event sponsored by Spain-based ATA Insights explained the importance of carbon accounting to companies trying to qualify for a tax credit under the IRA.
“I’m sure most of us are aware that the carbon intensity score [of hydrogen] is key,” said Tanya Peacock, a managing director at EcoEngineers.
“One way of making sure that you can maximize the available value from all of these [federal] credits and incentives is to make sure that you design your projects to achieve, from the outset, your desired target CI score,” she said.
To receive the full tax credit, $3/kg of hydrogen produced over 10 years, a hydrogen producer must prove the technology used to make that single kilogram of hydrogen generates no more than .45 kilograms of CO2, she explained.
Most hydrogen produced today from natural gas uses high heat and high-pressure steam to break the molecular bonds of methane (CH4), releasing the hydrogen and allowing the carbon to combine with oxygen in ambient air. It’s a process that fails the strict CI score but could work financially, say some analysts, if that CO2 is captured and sequestered — or if steam methane reforming could be made more efficient.
Clockwise from top left: Andy Dvoracek, Amp Americas; Gabriel Olson, BayoTech Hydrogen; Alyse Bordelon, Constellation; Belen Gallego, ATA Insights; and Tanya Peacock, EcoEngineers | ATA Insights & RENMAD Events
Gabriel Olson, former innovation director at SoCalGas and now director of carbon strategy and head of hydrogen markets for Texas-based BayoTech Hydrogen, said his company produces hydrogen with steam methane reforming but uses 20% to 30% less energy, thanks to a modular steam methane reformer developed by Sandia National Laboratory.
More importantly, BayoTech also uses RNG rather than conventional fossil gas as a portion of its feedstock, making its hydrogen competitive, he said, adding that the process does not require 100% RNG.
Using 100% dairy-sourced RNG in the modular steam reformer produces hydrogen with a carbon intensity (CI) of -300, he said, well under the minimum CI required by the IRA.
“That might be amazing and impressive, but it’d be kind of expensive, because you’re using a lot of a deeply negative [CI] and a highly valuable feedstock,” Olson said. “What we do is more cost-effective,” by using a blend of 30% dairy RNG and 70% pipeline natural gas.
The value of federal tax credits to produce hydrogen will depend on the carbon emissions created to produce the hydrogen. | The U.S. Hydrogen Demand Action Plan, EFI
“We’re effectively able to [produce] a cost-effective hydrogen product that’s both valuable and eligible for the incentive credits that are available,” including the PTC, he said.
“We see RNG as kind of the linchpin for doing this cost-effectively,” Olson said. “There are other pathways — carbon capture and things like that. But RNG for us is the most cost-effective, and the most flexible in terms of deployment, for multiple facilities in multiple locations. We see it as a great way to offset the fossil natural gas that we typically use as a feedstock.”
‘Next Wave’
Another company with a similar strategy that should have little trouble meeting federal CI standards is Illinois-based Amp Americas, which began producing RNG in 2011 from cow manure as a fuel for an electricity producer but then turned to providing the gas to an Indiana dairy for use as a fuel in its delivery trucks. The company then began producing and selling dairy-based RNG as a motor fuel in California.
“In 2022, we produced 1.3 million BTUs of renewable natural gas from dairy manure. That’s about 11% of market share of total dairy gas produced in the United States. The gas has an ultra-low CI net … a -250 to -300 score,” said Andy Dvoracek, the company’s vice president of business development.
The calculation for that ultra-low CI rests on how much methane the company’s operation has prevented from entering the atmosphere had the manure not been converted to biogas in an anaerobic digester, Dvoracek said.
<img src=”https://rtowww.com/wp-content/uploads/2023/06/140620231686776292.jpeg” data-first-key=”caption” data-second-key=”credit” data-caption=”Renewable natural gas made in an anaerobic digester from cow manure has a negative carbon score since the methane produced in the digester is captured and hydrogen produced from that methane qualifies for a maximum federal tax credit.” data-caption-html=”Renewable natural gas made in an anaerobic digester from cow manure has a negative carbon score since the methane produced in the digester is captured and hydrogen produced from that methane qualifies for a maximum federal tax credit.” data-credit=”
BayoTech Hydrogen
” data-description=”Renewable natural gas made in an anaerobic digester from cow manure has a negative carbon score since the methane produced in the digester is captured and hydrogen produced from that methane qualifies for a maximum federal tax credit.” data-id=”5548″ style=”margin: auto;” alt=”Generating-Hydrogen-from-RNG-(BayoTech-Hydrogen)-Content.jpg” data-uuid=”YTAtOTMwOTc=”>Renewable natural gas made in an anaerobic digester from cow manure has a negative carbon score since the methane produced in the digester is captured and hydrogen produced from that methane qualifies for a maximum federal tax credit. |
BayoTech Hydrogen
The company has 14 projects operating across the country and others in development.
“We think we’ll produce somewhere around 2.5 million metric tons of carbon dioxide abatement by 2027. We are about a half a million at a run rate right now. Collectively, we’ve got about 200,000 cows across the country that are producing this gas,” he said.
Most of that RNG is injected into pipelines and sent to states such as California and Oregon that have emphasized using the gas as a motor fuel for several years, he said. Revenues from the sale of the gas are augmented by renewable energy credits in the markets that developed under EPA rules. Called renewable identification numbers, the credits travel with the gas.
The company is now looking seriously at hydrogen.
“Hydrogen is an area of particular interest because hydrogen is seen as a next wave of energy usage in the transportation space, as well as just global energy transfer as a whole,” Dvoracek said.
Parties filing comments with FERC on expanding interregional transfer capability on the grid mostly supported the concept, though opinions were split on how to get there.
Due Monday, the comments came in response to a FERC technical conference on the subject late last year, and they could inform another Notice of Proposed Rulemaking in its broader efforts to revise transmission policy (AD23-3). (See FERC Considers Interregional Transfer Requirements.)
Many parties, including clean energy trade groups and environmentalists, want FERC to set minimum transfer requirements, based on either a flat megawatt amount or a percentage of peak load, between each neighboring region in the Lower 48 (except ERCOT, which was left out of the proposal as it is outside commission jurisdiction). Many of them pointed to a study by Grid Strategies that Americans for a Clean Energy Grid (ACEG) filed with its comments.
“Adopting a strong minimum requirement for Interregional Transfer Capability is the single most important step the commission can take to make the power system more reliable and resilient in the face of increasing threats from severe weather and other unexpected events,” ACEG said. “Interregional transmission is the most effective solution because the largest impacts from all of these threats tend to be localized in relatively small areas, so expanding interregional transmission provides a lifeline when a region’s electricity supply and demand is being affected by an unexpected event.”
Grid Strategies’ report, which looked into transfer capability among the Eastern Interconnection’s regions and ERCOT, found that all regions would benefit from a minimum transfer requirement of 20 to 25%. That would cut the need for peaking resources across the two interconnections by 137 GW.
“This 137-GW geographic diversity benefit translates to $113 billion in economic savings based on the avoided capital cost of an equivalent amount of gas combustion turbine capacity,” ACEG said.
Grid Strategies did not factor in likely changes such as the growth of renewables and increased electrification of home heating and other new sources of demand, or a growing reliance on natural gas plants — all of which would tend to increase the value of interregional transfers.
“Interregional transmission functions like an insurance policy against unexpected events, in that it is impossible to precisely predict when, where, or for what that insurance policy will be needed,” ACEG said. “Over the long term, all regions will be affected by such an event and will benefit from that interregional transfer capacity.”
Natural Resources Defense Council, Sustainable FERC Project, Rocky Mountain Institute, Environmental Defense Fund, Sierra Club and others said the need for more interregional transfer capacity has only grown since FERC’s December conference because of the outages in the Southeast around Christmas last year.
“Transmission can deliver electricity in both directions, so both connected regions benefit,” the environmentalists said. “For example, transmission flows flipped from westward to eastward as Winter Storm Elliott moved eastward across the country, as has happened during past severe weather events.”
Such minimum transfer capacity can be viewed as insurance against outages caused by extreme weather and thus should have its costs spread widely, they said. The industry likewise spreads the costs of resource adequacy widely because meeting the one-day-in-10-year resource adequacy standard is viewed as good for all, the environmentalists said.
The Department of Energy also filed comments urging FERC to move forward on increasing interregional transfers, highlighting that its own recent draft study on transmission needs found increasing needs for such transfer in some regions by 2030 and in nearly all regions by 2040. DOE is also working on a National Transmission Planning Study focused on interregional transmission, which is expected to come out by the end of 2023.
“Recent work shows that large amounts of interregional transmission coming online between now and 2030 will enable the economic and consumer energy cost reduction benefits of the significant investments in clean energy manufacturing and generation, and the electrification of homes, businesses, and vehicles made by the Infrastructure Investment and Jobs Act and the Inflation Reduction Act,” DOE said. “Recent modeling by the Department of Energy and NREL finds that between 17 and 36 TW-miles … of new transmission capacity will be needed between 2023 and 2030 to connect the vast amount of new generation and storage resources enabled by both laws.”
It would be possible to tailor transfer requirements between specific pairs of regions, but that entails factoring in weather and climate patterns, generation mix and location, load patterns, the gas pipeline network, and hard-to-predict extreme weather, ACEG said. That could lead to “analysis paralysis” and also does not factor in that different parts of an interconnection are impacted by power flows all across it, the group added.
DOE said FERC should base any standards on well-defined processes that take into account clearly defined planning assumptions such as demand, weather events, contingencies, geographic and temporal scope to ensure consistent results around the industry.
While some argued for the simplicity of setting a minimum transfer percentage that applies everywhere, others said FERC can take the time to have regional and interregional planners study the issue and come up with more tailored solutions.
Support for Improved Interregional Planning
The Eastern Interconnection Planning Collaborative, which is made up of planning authorities from the interconnection and dates back to the last big push for interregional transmission 10 years ago, filed comments suggesting such a planning process. That process should involve DOE and the national labs, as well as the National Oceanic and Atmospheric Administration to quantify the needs addressed and benefits produced by interregional transfers.
“Although the metrics and analysis should be common across the interconnections for the reasons stated below, the application of those metrics and analysis to any particular interregional seam would reflect the specific locational and regional characteristics of the two adjoining regions,” EIPC said.
Common analytics would reflect the fact that the Eastern Interconnection is “one large, interconnected machine,” and would avoid having different regions rely on others too much to the detriment of joint reliability.
“EIPC does not support requiring transmission planning regions to use a simplistic ‘easily quantifiable’ minimum Interregional Transfer Capability requirement that cannot demonstrate a true need, and which may not stand up to a prudency review during state CPCN proceedings,” its filing said. “The development of a range of appropriate transfer capabilities that respects regional differences would be more defensible.”
PJM agreed with EIPC (of which it is a member), saying that it is unlikely that a common minimum requirement would be practical given the differences in planning and balancing authority size, topology and extreme weather exposure.
“A ‘range’ would be more appropriate since it could reflect these regional differences,” the RTO said. “As discussed above, PJM supports the EIPC’s proposed analysis to develop a range of transfer capabilities needed to offset the impacts of extreme events.”
PJM also pointed out that one cannot just build lines between different regions without ensuring that their regional grids are capable of supplying them. While it was able to help bail out some of its southern neighbors during winter storms around Christmas last year, the RTO’s aid was limited because of regional transmission constraints.
“PJM’s ability to transfer power between regions was often limited by facilities internal to the region receiving the electricity, and not necessarily by facilities along the seam,” the RTO said. “That is, PJM had additional energy available to be transferred, but could not due to internal congestion in neighboring systems.”
MISO made a similar point, noting that its large footprint at the center of the Eastern Interconnection has required it to work with PJM and other neighbors on formal joint operating agreements (JOAs) that have already improved interregional coordination.
“The commission should be mindful that setting a target number for Interregional Transfer Capability may not necessarily achieve the desired result because adding transmission capacity nominally between two regions would not necessarily account for underlying operational constraints, including those across third party seams and across the interconnection,” MISO said. “In fact, enhancing transfer capacity between two regions may be best served by an upgrade or operating procedures in a third region.”
The JOAs MISO has with PJM and SPP have helped make the most efficient use of existing infrastructure and maximized interregional transfers. The most effective way to increase interregional transfer capability would be to enhance interregional operations and improve interregional planning, MISO said.
American Electric Power (NASDAQ:AEP) was somewhat in between the two sides, saying it would make sense to use a minimum requirement at first to deal with the immediate needs of the system and then switch to improved regional planning.
“With the electric system becoming more weather dependent, increased transfer capacity between regions offers less expensive electricity, the sharing of resource adequacy over wider areas, and improved resilience during extreme events,” AEP said.
Getting the planning process right will take time, so it may be necessary to set some minimum requirements at first, the utility said. The planning process will need to be changed because Order 1000 only required that regions discuss interregional lines, and the different regions use different assumptions, making it hard to agree on specific projects.
CAISO Weighs in from the West
CAISO told FERC that it was worried the commission was adopting a solution before it has clearly articulated a problem.
“Resource sufficiency and extreme event considerations can vary by region, as can reliability, economic, and public policy driven transmission needs,” CAISO said. “The more efficient and cost-effective solutions to address these needs may vary by region and may not necessarily involve increasing interregional transfer capability. Requiring the CAISO region to establish a minimum level of interregional transfer capability is unnecessary and may not provide material benefits to the CAISO system, particularly in times of extreme weather events.”
While it might make sense to increase transfer capabilities in the West given the growth of renewable energy, CAISO does not want FERC to set minimum requirements. The ISO argued its existing planning processes were good enough to handle the issue already, such as its 20-year planning process that calls for another 10 GW of transfer capability by the 2040s.
What About Cost?
One issue that came up in several comments, including from the National Rural Electric Cooperative Association, the Transmission Access Policy Study Group, and joint comments from NRG Energy (NYSE:NRG) and Vistra (NYSE:VST) was the potential costs of adding new lines.
“NRECA member cooperatives have seen significant transmission cost increases in recent years and share a concern that their member-consumers should not be burdened with unjust, unreasonable, or unduly discriminatory transmission cost increases in the years ahead,” it said.
NRG and Vistra said that a line connecting two regions could become one of their largest single contingencies, requiring it to carry extra reserves and thus pushing up prices for consumers. They argued that it would make the most sense to treat interregional lines like pipelines and build them when anchor customers sign up for them (a method that has been used by merchant transmission developers).
“Interregional projects can produce benefits through energy arbitrage,” the two utilities said. “Further, an external or interregional tie has transfer value allocable to the cost of capacity rights in the facility. For this reason, the commission should first try to satisfy any need for Interregional Transfer Capability through a framework that presents options-to-buy to those interested in voluntary purchases of capacity rights on these systems.”
A study conducted for the California Public Utilities Commission finds that without mitigation, the distribution grids of the state’s three large investor-owned utilities will require up to $50 billion in upgrades by 2035, mainly to accommodate electric vehicle charging.
The Electrification Impacts Study, performed by energy analytics firm Kevala, was commissioned by CPUC as part of its High Distributed Energy Resources Grid Planning rulemaking, which is intended to prepare the state for large-scale transportation and building electrification.
California law requires that all new vehicles sold in-state be zero-emitting by 2035, and the state Air Resources Board is weighing a ban on sales of new natural gas-powered space and water heaters for residential and commercial use. (See Calif. Considers Zero-emission Appliance Rules.)
The study takes these high-electrification scenarios into account. Kevala and CPUC released the findings from its first part May 9 and plan to review the results in a public workshop May 17.
The findings provide preliminary estimates of the impact of widespread transportation electrification on the grids of Pacific Gas and Electric (PG&E), Southern California Edison (SCE) and San Diego Gas & Electric (SDG&E) using a “highly granular load forecast” for more than 12 million homes.
“It is important to highlight that this Part 1 analysis was conducted under unmitigated planning scenarios, which assume only traditional utility distribution infrastructure investments,” the study says. The study also assumed that existing time-of-use rates and behind-the-meter solar tariffs would be in place throughout the study period.
“It did not consider alternatives or future potential mitigation strategies such as alternative time-variant rates or dynamic rates and flexible load management strategies,” the study says.
“Across these unmitigated load scenarios, Kevala estimates up to $50 billion in traditional electricity distribution grid infrastructure investments by 2035,” it says. “This estimate reflects distribution grid needs across the PG&E, SCE and SDG&E service territories under the policy assumptions used in this report.”
Two high transportation electrification scenarios would require the utilities to nearly double their current spending on feeder lines, transformer banks and substations, it says.
“Secondary transformer and service upgrades alone … [comprise] an estimated $15 billion of the $50 billion … and are currently not accounted for” in the investor-owned utilities’ annual assessments of grid needs, it says.
“PG&E’s distribution circuits are projected to reach capacity sooner than SCE and SDG&E,” it says. “SDG&E is expected to have the least number of feeders reaching full capacity by 2035, with 22% compared to SCE’s 36% and PG&E’s 48% of feeders.”
The study forecasts that peak load will increase on the utilities’ distribution systems an average of 56% from 2025 to 2035 under all high-electrification and base-case scenarios.
“This dramatic increase in peak load … is primarily due to transportation electrification impacts, with over 60% of this demand coming from light-duty vehicles,” it says. “The average percent change in peak load from 2025 to 2035 for the high transportation electrification scenarios is more dramatic for PG&E (69%), followed by SDG&E (53%) and SCE (44%).”
Among the study’s recommendations is that the utilities increase their distribution planning horizons to align with those of CAISO and the California Energy Commission, which stretch from 10 to 20 years. That would help them prepare more efficiently for a distribution grid that can incorporate DERs and manage load, it says.
“The substantial difference between the estimated capacity expansion costs, in the several tens of billions of dollars, in this study and the recent filings by the [utilities] suggest there is a disconnect between the data and the current planning process,” it says.
Another recommendation is for the utilities to better incorporate the state’s policy goals in their distribution planning.
A second part of the study will build on the first part’s findings, including by developing scenarios that reflect state policy goals, state agency targets and the Energy Commission’s demand forecast.
