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.
The U.S. Department of Agriculture has announced $10.7 billion in funding from the Inflation Reduction Act to help rural electric cooperatives across the country stand up clean energy, zero-emission and carbon capture projects.
Agriculture Secretary Tom Vilsack described the funding, announced Tuesday, as “the single largest investment in rural electrification since the Rural Electrification Act of 1936.” That law, signed by President Franklin Delano Roosevelt, provided critical loans to farmers and rural communities forming electric cooperatives during the Depression.
The new funding “continues an ongoing effort to ensure that rural America is a full participant in this clean energy economy,” Vilsack said during an advance press briefing on Monday.
The largest chunk of the IRA dollars — $9.7 billion — will go to the Empowering Rural America (New ERA) program, offering “a mix of loans grants and loan modifications to support the purchase or ownership of renewable energy systems, zero-emissions and carbon capture systems,” Vilsack said.
Funding will be “exclusively for rural electric cooperatives,” he said, adding that the IRA allows for “stacking of benefits.” That means projects also can take advantage of production tax credits and investment tax credits in the IRA.
As nonprofit organizations, electric co-ops have previously not been able to take advantage of the ITC but are now able to under the IRA’s direct payment provisions.
The second program, with $1 billion in funding, is the Powering Affordable Clean Energy (PACE) program which will “provide loans — a portion of which can be forgiven — in connection with development of renewable energy projects or energy storage,” Vilsack said. These loans will be open to a broader range of applicants, including corporations, municipalities, co-ops and tribes, he said.
There are three categories of loan forgiveness, ranging from 20% to 60%, depending on where the project is located, Vilsack said. For example, projects in Puerto Rico, Micronesia, the Marshall Islands, Palau and tribal communities will be eligible for 60% forgiveness, according to the USDA announcement.
Micronesia, the Marshall Islands and Palau are island nations that together total more than 2,300 small islands, with loose affiliations with the U.S.
The goal of the program is “to make clean energy affordable for vulnerable, disadvantaged, tribal and energy communities to heat their homes, run their businesses and power their cars, schools [and] hospitals,” the announcement said.
Figuring in repayment of loans over time, Vilsack said, the $1 billion could be stretched to provide $2.7 billion in loans.
Letters of interest for New ERA are due between July 31 and Aug. 31, while letters of interest for PACE will be accepted from June 30 to Sept. 29, according to the USDA.
Jim Matheson, CEO of the National Rural Electric Cooperative Association (NRECA), was quick to praise the new programs as “an exciting and transformative opportunity for co-ops and their local communities, particularly as we look toward a future that depends on electricity to power more of the economy.”
Matheson called the programs “smartly structured … in a way that will help electric co-ops leverage new tools to reduce costs and keep energy affordable while meeting the future energy needs of their rural communities.”
He also noted that the wide range of eligible projects — including carbon capture, renewable energy, storage, nuclear, and generation and transmission efficiency improvements — will allow individual co-ops to tailor programs to their circumstances.
‘Proven Driver of Economic Growth’
At present more than 900 electric co-ops serve customers in 48 states, with service territories covering 56% of the continental U.S. land mass, including 92% of “persistent poverty counties,” according to the NRECA website.
Co-ops can range from several hundred members to tens of thousands, and because they are largely not regulated, some have been able to adopt aggressive and innovative clean energy programs. The Kit Carson Electric Cooperative in Taos, N.M., has been sourcing 100% of its daytime power from solar since June of 2022 and is exploring the feasibility of using its excess solar to produce green hydrogen to provide night-time power.
Holy Cross Energy, a Colorado co-op, has set a goal of providing 100% renewable power to its members by 2030 and offsetting all emissions to net zero by 2035.
As of 2021, renewable energy constituted about 22% of the power provided by co-ops across the country, while coal and natural gas accounts for 61% and nuclear 15%, according to NRECA.
With financing still a hurdle for many co-ops in rural areas, National Climate Advisor Ali Zaidi called renewable energy “a proven driver of economic growth” in rural communities. Citing an analysis from the nonprofit news site Stateline, Zaidi said that seven of the 10 counties nationwide with the highest increase in gross domestic product between 2019 and 2021 “had revenue that came from wind farm construction.”
The New ERA and PACE programs are “designed to begin the process of allowing the rural electric cooperatives to essentially reach parity, if you will, with the privately owned utility companies that have already begun significant investments” in clean energy, Vilsack said. The funding will “make it a little bit easier for [co-ops] to be able to accelerate plans they may have to transition away from fossil fuel[s].”
VALLEY FORGE, Pa. — PJM plans to allocate more than 2,000 MW of transmission headroom to generators that requested additional capacity interconnection rights (CIRs) under a transitional process as the RTO shifts to a new methodology for calculating CIRs for effective load carrying capability (ELCC) resources. (See FERC Approves Revisions to PJM’s ELCC Accreditation Model.)
Existing generators or those with signed ISAs may request higher accreditation through the transitional study process, which assigns a portion of available headroom on the grid to those resources. PJM’s Jonathan Kern said about 7,000 MW was eligible to participate in the studies, of which 2,073 MW was awarded, with the remaining 5,000 MW largely denied due to not being available for the upcoming delivery year. Those generators denied can receive access to headroom in future years once they are online.
“It’s just for this particular Base Residual Auction (BRA) that they didn’t achieve the particular milestones to participate,” he said.
The higher accreditation will be added onto resources’ CIRs when running calculations for the 2025/26 BRA and future auctions until the transitional period has ended. Should FERC grant PJM’s request to delay that auction — currently scheduled for next month — Kern said many of the figures calculated could change significantly, including headroom allocations. (See PJM Seeks to Delay Capacity Auctions Through 2028 Delivery Year.)
Most resources received either no increase in their accreditation or the full amount they asked for, with some receiving in between based on locational factors. Kern said there was no queue-based determination in the headroom allocation.
Stakeholders Seek Discussion on CIR Transfers
Denise Foster Cronin, of the East Kentucky Power Cooperative, and Tonja Wicks, of Elevate Renewable Energy, presented a problem statement and issue charge to open a discussion on streamlining the process of transferring CIRs from a deactivating generator to a replacement resource.
“Our motivation to bringing this forward is to add some certainty to something that is currently uncertain,” Cronin said.
The current rules allow CIRs to be used at a resource seeking to interconnect at the same site as the retiring generator or at a different point of interconnection. Transferring CIRs also requires a study of the grid upgrades that may be necessary to support the capacity offered by the new generator, part of the interconnection queue process.
The status quo process assumes studies can be completed relatively quickly, but the queue is backlogged as PJM transitions to a new process meant to complete studies quicker, potentially creating a “timing misalignment.” The problem statement says resources seeking to retire between 2023 and 2026 may expect a delay of four years before they’re able to transfer CIRs to new resources, affecting reliability and cost.
“Inefficiency in the CIR transfer process results in unnecessary additional cost to customers served by these generation capacity resources. Load serving entities may need to seek alternatives and may find inadequate hedges to mitigate market price exposure should CIR transfers not be efficiently executed,” the problem statement reads. “Also, the inefficiency could result in PJM needing to rely on [reliability-must-run] agreements and/or the transmission reinforcements to address reliability issues resulting from generation deactivation that otherwise would not be necessary if CIR transfers could be more efficient. These measures result in cost to load, and the allocation of such costs may extend beyond the zone in which the deactivating generation is located.”
The problem statement also calls for clarifying the resources the CIR transfer rules apply to, noting the status quo language refers to “generation capacity resources.” The document states that more explicit inclusion of energy storage or hybrid resources may be warranted.
The issue charge states that any changes to the current process for transferring CIRs to a replacement resource located at a different interconnection site would be considered out of scope. The sponsors’ presentation said the new standard interconnection process would not be affected.
Stakeholders asked questions on the implementation timeline and expressed concerns regarding possible queue jumping, generators being able to avoid grid upgrade cost allocations and any impact to generators already in the interconnection queue should resources receiving CIR transfers be studied first.
Reliability Requirement Study to Use New Software
PJM plans to use new software to conduct the 2023 Reserve Requirement Study (RRS), the annual process that resets the forecast pool requirement (FPR) and the installed reserve margin (IRM) for the following three delivery years and establishes an initial value for the fourth year out, 2027/28 in this case. The study will also set the winter weekly reserve target for the 2023/24 delivery year. (See “Stakeholders Endorse 2022 Reserve Requirement Study Results,” PJM PC/TEAC Briefs: Oct. 4, 2022.)
Past studies were conducted with the PRISM modeling software, but PJM’s Patricio Rocha Garrido said this year the software developed for the hourly loss-of-load modeling used for the ELCC study will be used in parallel with PRISM. Two separate sets of assumptions will be generated to correspond with the different approaches, and both sets of results will be presented to stakeholders after the study is done, with PJM planning to recommend one of the results for endorsement. PJM plans to ultimately shift to using the hourly loss-of-load modeling software by default in the future.
PJM will also be including data from the 2014 polar vortex based on experience gathered through the December 2022 winter storm. Previously, the polar vortex had been replaced with other data. The capacity benefit of ties will also be averaged over the past several years, rather than using annual data, due to value volatility.
The PC is slated to vote on the RRS approach at its June meeting.
Advocates Push for More Transmission Cost Details
State consumer advocates are seeking more insight into the development of cost estimates for supplemental transmission projects when they are presented to the Transmission Expansion Advisory Committee (TEAC). A presentation by the Consumer Advocates of PJM States (CAPS) said questions to transmission owners about their proposals have not yielded substantive information. (See “CAPS Pushes for More Transmission Upgrade Data,” PJM PC/TEAC Briefs: April 11, 2023.)
For the 22 projects presented at the April TEAC, the presentation said transmission owners were asked how they developed the estimated cost, to provide a breakdown of the project budget and if the relevant state utility commission would have planning oversight. None of the responses regarding project budgets provided a breakdown, instead pointing to processes for receive cost breakdowns after the work is done. None of the responses specifically addressed the question of oversight, the presentation said.
Exelon’s Alex Stern rejected CAPS’ complaint.
“We have enhanced the planning process, and the TOs are providing more transparency in a timely manner than anywhere else in the country,” he said. “We’re also providing the best, most accurate cost estimates that we can based on industry experience when we bring solutions to needs forward followed by cost updates posted on pjm.com quarterly from project inception to project completion.”
The estimates provided to TEAC can significantly change before a project goes to development and is completed based on state and local siting processes, Stern added.
Tom Schmidt of Buckeye Power said the nuances of each state’s oversight provisions can make providing a yes or no answer “very, very difficult,” giving Ohio as an example of a state where oversight depends on specific voltages and project length.
Transmission Expansion Advisory Committee
Data Center Growth in Ohio Contributing to Nearly $600 Million in Transmission Upgrades
American Electric Power presented about $579.5 million in transmission upgrades throughout Ohio to accommodate several new load interconnection requests. AEP’s Nicolas Koehler told the Transmission Expansion Advisory Committee (TEAC) that much of the load stems from a surge in plans to construct data centers, with new announcements over the past few months estimated to consume around 3,000 MW.
The bulk of the expense would be direct connection costs at $498 million, while the remaining $81.6 million are system upgrade costs.
Responding to stakeholders who questioned why the AEP projects weren’t following the same competitive process as the data center alley in Northern Virginia, PJM’s Dave Souder said the Virginia load growth has necessitated upgrades to the regional 500-kV transmission system. PJM has opened a third window to its 2022 Regional Transmission Expansion Plan (RTEP) to address “unprecedented growth” from data centers. (See “Load Forecast for Northern Virginia Data Centers Continues to Climb,” PJM PC/TEAC Briefs: Jan. 10, 2023.)
The largest portion of the Ohio work would involve significantly expanding the grid in the New Albany region and adding about a dozen new substations:
The existing Corridor — the Conesville 345-kV line would have two new substations, Curleys and Bermuda, and it would be rerouted to tie into the existing Innovation substation, which would be upgraded to handle both the new 345-kV capability and its current 138-kV lines. The Curleys facility would serve an ultimate load of 968 MW and would come with a $55.2 million price tag, while the Bermuda substation would serve an ultimate demand of 337 MW and would cost around $60.3 million.
The Corridor — the Jug Street 138-kV line would have four substations added along its run: Souder, which would serve a projected future load of around 100 MW at a $14.3 million cost estimate; Fiesta (up to 300 MW/$22.3 million); Horizon (200 MW/$11 million); and Badger (290 MW/$18 million).
The Green Chapel — the Innovation 138-kV line would be cut and extended around 0.75 miles to connect to the new Tasjan substation, which would serve an ultimate load of 150 MW. The work would cost around $19 million.
The Innovation — the Kirk 138-kV line would be cut with two single-circuit lines terminating around 0.35 miles at the new Jorden substation, which would serve a 270-MW load. The project would cost an estimated $12.5 million. A new line would be constructed from the Innovation facility to the Brie substation with around 1.75 miles of double-circuit 138-kV line. New equipment would be installed at the Brie site, addressing potential load drop and overload risks at a $10.8 million expense.
The existing Innovation substation in the New Albany area would receive $53.7 million in upgrades to serve 247 MW of additional load. The proposed project includes cutting into the Corridor-Conesville 345-kV circuit and building a new 345-kV ring bus at the site.
Additional substations would be built in the area of Union County and Columbus:
The Cyprus substation outside Columbus would be upgraded with 345-kV infrastructure, in addition to the existing 138-kV equipment, and cut into the Beatty-Bixby 345-kV line at a $46.9 expense.
The proposal would build the new 138-kV and 345-kV Celtic substation in Union County to serve 461 MW of load at an estimated $60 million. The substation would cut into the Hayden-Hyatt 345-kV line and the Amlin-Hyatt 138-kV line and would also include a new 138-kV line to the existing Kileville line.
The Beacon substation would be built for $40 million to supply an ultimate load of 328 MW in the Columbus area. The facility would cut into the Hayden-Roberts 345-kV circuit.
The Jerome substation in Plain City would serve an initial load of 106 MW, which could grow as high as 203 MW at a $30 million price tag. The facility would connect to the proposed Celtic substation and the existing Hyatt-Amlin line via new 138-kV lines.
Several Generators Announce Deactivation
PJM’s Phil Yum presented an update on the status of deactivating generators, highlighting seven facilities that have recently requested to go offline.
The new deactivations include the 1,884-MW Homer City coal plant in Pennsylvania, the 1,282-MW Brandon Shores coal plant near Baltimore, and the 167-MW Vienna oil-fired generator in Maryland.
The PJM Board of Managers referenced the Homer City deactivation request in a May 1 letter responding to environmental groups that said the RTO’s analysis of future resource adequacy concerns overstated the issue.
“In performing the analysis discussed in this study, the PJM team made assumptions it believes are conservative, meaning that PJM did not try to overstate resource retirements … In fact, just recently, the largest Pennsylvania coal-fired generating plant, Homer City, announced its retirement. Homer City was not included in our retirement assumptions because the policy drivers underlying its retirement were not known at the time of the study,” the board wrote.
Changes to NJ Offshore Wind Transmission Add $128 Million
Several portions of the transmission planned to connect 6,400 MW of offshore wind to the PJM grid have been changed since the approval of the State Agreement Approach, leading to a $128 million increase in the expected project cost from $1.064 billion to $1.192 billion.
The scope of the work in the Jersey Central Power & Light (JCPL) zone has increased to include the removal of existing equipment to accommodate new lines for $17.47 million, while updated cost projections for previously expected JCPL work has increased by $31.71 million. Work in the Public Service Enterprise Group (PSEG) region has increased by $12.25 million, while a case correction in the PECO zone has reduced cost estimates by $5.6 million.
The expected construction cost for the Larrabee Collector Station, as well as procuring and preparing land adjacent to the site, has increased from $121.1 million to $193.3 million, with the new figures including costs that were explicitly excluded from the original estimate but have been determined to be required for the project.
Kern said additional work was identified after the approval of the project and will require the approval of the PJM Board of Managers. The New Jersey Board of Public Utilities is also aware of the changes.
VALLEY FORGE, Pa. — PJM last week proposed creation of a new cost of new entry (CONE) area for the Commonwealth Edison (ComEd) zone during discussions about how to account for local factors in calculating net CONE.
PJM’s Gary Helm said the discussion arose out of concerns raised in the RTO’s quadrennial review filing at FERC about the impact of the Illinois Climate and Equitable Jobs Act on net CONE. An issue charge and problem statement were adopted following the approval of that filing to evaluate how asset life and net CONE are determined. (See “Amortization Period,” FERC Approves PJM Quadrennial Review.)
“What we are looking at proposing here in this package is addressing that specific item through making ComEd, that [locational deliverability area], its own CONE area. So we currently have four CONE areas; this would be a fifth,” Helm said. He added that PJM is also considering what other areas could be impacted by approved state and local legislation or other localized factors.
Stakeholders Continue Discussion on Co-located Load Packages
Several packages seeking to create new rules for generators with co-located load were discussed by the Market Implementation Committee during its May 10 meeting. PJM’s Tim Horger worked with package sponsors to create a comparison of the five current proposals. (See “Discussion on Co-located Load Packages,” PJM MIC Briefs: April. 12, 2023.)
Much of the ongoing discussion of the proposals has centered on configurations in which the co-located load isn’t directly connected with the grid and whether those loads should be considered FERC jurisdictional or falling under state regulation. The discussion has also focused on whether generators should be permitted to retain their full capacity interconnection rights (CIRs) for the balance of their output consumed by the load and what service fees, if any, should be allocated to the load or generator.
The Independent Market Monitor proposal would follow the status quo of requiring generators to reduce their CIRs corresponding to the co-located load consumption, while the other four would not. The PJM, Constellation/Brookfield and Exelon packages specify that CIRs can be retained so long as the load is capable and willing to curtail within 10 minutes and that output be able to shift over to the grid.
The Advanced Energy Management Alliance (AEMA) package considers all co-located load to be FERC jurisdictional and as taking services from the grid. It would permit generators to retain their full CIRs.
The Constellation/Brookfield proposal is the only one to not charge any grid services to the configuration. The PJM package would assess regulation, reserve and black start fees to the entire load by assigning them to the generator. Exelon’s would consider the generator to be a load-serving entity for the co-located load and levy all LSE credits and charges. The Monitor proposal would include charges for regulation, reactive power, frequency control, reserves and black start via the generator, and the AEMA proposal includes all firm point-to-point transmission charges.
All proposals except the Monitor’s would permit the inclusion of curtailment costs in their market-based energy market offers, but not their cost-based offers. The monitor would not permit any inclusion.
The Constellation/Brookfield and Exelon proposals are silent on configurations in which the load is receiving service from the grid, while the AEMA proposal has the same rules for all configurations.
Under configurations with grid service, both the PJM and Monitor proposals would require CIRs to be reduced and consider the load to be FERC-jurisdictional. The Monitor also applies all LSE charges and credits, while PJM does not.
Exelon presented minor changes to its proposal since its last presentation, clarifying that the co-located load could participate as either demand response or price-responsive demand, incorporating PJM feedback to lengthen the initial public notice to 10 days and adding a provision to grandfather PJM’s market rules for co-located load configurations that were approved by the relevant electric retail regulatory authority prior to 2024.
MIC Chair Foluso Afelumo said the committee will likely be continuing first reads at the June meeting to accommodate a data center developer that plans to present an additional package at that meeting. Voting on endorsement could begin at the July meeting.
PJM will also give additional thought to how voting will be structured, as four of the proposals have separate provisions for co-located load with and without service from the grid, while the AEMA proposal addresses both.
Other MIC Business
The committee endorsed by acclamation a PJM problem statement, issue charge and proposal to clarify that smoothened supply curves will only be generated after Base Residual Auctions and not Incremental Auctions. Tariff revisions will move on for consideration at the Markets and Reliability Committee and the Members Committee. The proposal was brought under the quick fix process, allowing solutions to be voted on simultaneous with the problem statement and issue charge. (See “First Read on Smooth Supply Curve Quick Fix,” PJM MIC Briefs: April. 12, 2023.)
Stakeholders endorsed revisions to Manual 11 to allow PJM to reduce the Transmission Constraint Penalty Factor under a set of circumstances when it is believed the penalty cannot incentivize actions that would reduce constraints. The proposal codifies a package previously approved by stakeholders and a FERC order in March. (See FERC Approves PJM Proposal to Reduce Congestion Penalty During Grid Upgrades.)
The MIC endorsed revisions to Manuals 11, 27 and 28 to add market rules for hybrid resources. The proposal will go before the MRC for endorsement on May 31, followed by a FERC filing with a requested effective date of June 1.
Stakeholders endorsed revisions to Manual 15, which PJM’s Glen Boyle described as minor updates to clarify current processes related to heat input guidelines and the IMM Opportunity Cost Calculator.
The Consumer Advocates for PJM States gave a first read on a proposal to amend the issue charge for the Reactive Power Compensation Task force, reducing the items considered out-of-scope to permit discussion of “any existing FERC approved or pending reactive service rates.”
ALBANY, N.Y. — The Independent Power Producers of New York’s (IPPNY) annual Spring Conference on Wednesday highlighted the challenges New York faces as it decarbonizes.
Some prominent figures in the industry shared their thoughts on how New York can achieve its ambitious energy and climate goals.
“We are literally experiencing this transition in every way across our economy every day,” said Doreen Harris, president of the New York State Energy Research and Development Authority. “We got our work cut out for us” because “when it comes to climate action and clean energy, all eyes are on New York. …
“But I am truly optimistic about the ways we can achieve [New York’s] goals and build a truly inclusive energy economy that sets the example for others to follow,” she added.
“We’re entering the period in our transition when it feels like a marathon,” New York Public Service Commissioner Diane Burman said, so in the near term, the state must “focus on being prepared and getting the right resources in place.”
“We need to look at every technology, because wind and solar aren’t going to get the job done,” State Sen. Mario Mattera (R) said. Constituents must demand more answers from their policymakers “about how this transition will get done and paid for” because “we want to make sure we’re creating jobs, not losing them.”
New York State Assemblymember Didi Barrett (D) agreed, saying, “This [transition] cannot be done on the back of ratepayers,” adding that the state “needs to be open to new technology opportunities” while “educating the public about the realities they’ll face.”
Keynote speaker Alexis Glick, CEO of biomethane producer Nature Energy, discussed the benefits from biofuels, saying, “We need an all-of-the-above approach because it’s what New Yorkers do really well.” They “recognize that innovation, investment, fresh thinking and an inclusive approach is critical to our combined success.”
Bart Franey, vice president of clean energy development at National Grid, noted the benefits from energy storage resources and how they can enable New York to connect other renewables to the grid at scale without the need to make as many transmission and distribution system upgrades.
Rudy Wynter, president of National Grid, commented on the importance of workforce training and development, saying, “We want to make sure that all the jobs that will be created during the energy transition are secure, because we know in previous [historical] transitions communities have been left behind … so [National Grid] works directly with communities to make sure they understand that those jobs are coming, and we help them get prepared for those jobs.” (See In Climate Leader NY, Energy Workforce Rising from Ground Up.)
Zach Smith, NYISO vice president of system and resource planning, commented on how dispatchable emissions-free resources are “not some unicorn technology.” New York can attract future resources with certain desirable attributes by sending the right price and market signals that encourage investment in new technologies.
In reference to the increasing risks posed by extreme weather events, Chris Wentlent, chair of the New York State Reliability Council’s Executive Committee, said the state needs to understand how every grid resource is impacted and correlated to natural disasters because without this knowledge, the state will struggle to successfully transition.
Aaron Markham, NYISO vice president of operations, said, “We need to keep our eyes open to how [New York’s] transition is progressing” because there is a concern that as the state decarbonizes, its energy supplies could become compromised and the ISO will find itself unable to reliably meet growing electricity demands.
Eastern Generation CEO Mark Sudbey said, “We need to be realistic to people about decarbonization’s timelines because I am concerned that our goals are too aspirational” and, in attempting to transition too quickly, the state may end “up doing something foolish.”
IPPNY President Gavin Donohue closed out the meeting by saying the challenge for New York will be to transition in a reasonable manner while ensuring that innovation is not compromised, investments are not discouraged and that environmental justice concerns are still considered.
ALBANY, N.Y. — There was no shortage of ideas on how to overcome the well known challenges to carrying out New York’s clean energy transition last week at the Independent Power Producers of New York’s 37th Spring Conference.
Much of the conference built on themes discussed last year, such as how to best implement New York’s climate legislation, the need to expand the grid without compromising reliability or hurting ratepayers, and that everyone needs to be involved in the transition. (See Overheard at IPPNY 2022 Spring Conference.)
Since New York passed the 2019 Climate Leadership and Community Protection Act (CLCPA), the state has set itself on an aggressive decarbonization timeline: 70% renewable electricity by 2030, 100% zero-emission electricity by 2040 and net-zero emissions statewide by 2050. The Climate Action Council (CAC) recently approved a Scoping Plan that laid out a roadmap for how New York can meet CLCPA goals. (See New York Climate Scoping Plan OK’d.)
These deadlines are fast approaching, and panelists agreed that New York needs to act quickly, but methodically. Many of New York’s fossil fuel plants are due to retire soon, and if the state has not installed enough reliable renewable capacity to replace that baseload generation, then those emissions-producing plants may need to stay online, which means that the state will not meet its objectives.
IPPNY President Gavin Donohue opened the meeting saying, “The purpose of this conference is to work together to identify innovative technologies that are zero-emitting and, ultimately, are going to bolster both reliability and affordability.”
Common refrains heard during the conference were that New York needs to encourage more collaboration and be more open to innovative ideas or resources because this will better position the state to achieve its mandates.
Corinne DiDomenico, director of regulatory affairs at NextEra Energy Resources, said “the state has very discrete goals with very rigid timelines” and as those deadlines approach, “things start to get messy, and so with that in mind, we need flexibility to address incoming challenges.”
The state’s grid currently has 37,520 MW of total installed capacity, according to NYISO, and about 70% of that capacity is fossil fuel, the majority of which are dual-fuel systems for downstate zones; many will retire soon.
NYISO’s 2022 Reliability Needs Assessment found that these retirements are leading to tightening transmission security and resource adequacy margins that could become deficient by 2025 if critical emissions-free projects — such as the Champlain Hudson Power Express, an immense transmission project to import hydroelectric power from Quebec to New York City — experience delays. (See Champlain Hudson Power Project Receives Landmark Delivery.)
New York is walking a tightrope between its lofty aspirations and reality on the ground.
“We need to be able to adapt to the changes we see every day because, as exemplified by COVID, markets need to be able to react and respond,” DiDomenico said. “The state also needs a lot more coordination to happen to address the world changing around us.”
A desire for flexibility was also seen in a panel about climate change, resilience and reliability during extreme weather events, where natural gas was seen as critical to meeting current energy needs, particularly during emergencies like the December winter storm.
“We’ve had a surplus of fossil fuel resources, and that surplus not only offers flexibility and resiliency, but lets [NYISO] manage the grid as reliably as you see … and we don’t want to risk that,” said Aaron Markham, NYISO vice president of operations. “In New York there remain incentives to maintain dual-fuel capabilities because, particularly during high demands in the winter, we have to have fuel on site that can provide resiliency in case there is an emergency.”
The panel was supportive of renewable development but agreed that gas has a role in the transition.
“ISOs need be thoughtful about retiring [natural gas plants] too soon, because we don’t want to impact loads during the transition to a renewable future because we want to make sure we have sufficient resources available to meet resource adequacy needs,” Stephen George of ISO-NE said.
Chris Wentlent, chair of the New York State Reliability Council (NYSRC) Executive Committee, agreed. “Fortunately we went into this winter with a great fuel diversity that provided benefits when we started moving into the extremes for load,” he said.
This flexibility and desire for New York to think more creatively was best expressed by William Acker, executive director of the New York Battery and Energy Storage Technology Consortium, and Bart Franey, vice president of clean energy development at National Grid, during a panel on “The Future of the Electric Grid.”
“There are a lot of tools in our toolbox that can optimize [New York’s] transition going forward,” Acker said.
New York “needs to think about different kinds of solutions and be more flexible, and not always be applying standard practices to its transition,” Franey added.
Flexibility was not the only thing on panelists’ minds, and frequently, they cited the need for greater cooperation.
Franey said the state “needs to do a better job coordinating land use very purposefully” and engage with communities directly because New York does not have vast tracts of land to install large-scale renewable projects.
This call for greater cooperation was most observable during the fireside chat between State Sen. Mario Mattera (R) and Assemblymember Didi Barrett (D).
Mattera, the ranking minority member on the Senate’s Energy and Telecommunications Committee, said that “when I’ve worked with developers, they always come up to me saying that we need to get the local community involved, that we need to have open forums, and we need to involve everyone, because when you don’t do that, that’s when you have problems.”
Barrett, chair of the Assembly’s Energy Committee, concurred. “We’re not going to get to our goals by bullying people, by shaming people, by calling people names or lying, so my goal is to make sure that we do bring all of our communities, all of our producers and all of our businesses together, since they are important to our decarbonization”
Some still expressed skepticism about New York accomplishing its near- to medium-term goals, though they thought it was not too late to learn from any early mistakes and change course.
“I think New York has an aggressive but appropriate climate agenda,” Franey said, but he added that “with regards to 2030 goals, we got caught flatfooted, and to make sure 2040’s goals become real, we need to start thinking about planning and infrastructure that will be needed to address affordability and reliability concerns.”
Public Service Commissioner Diane Burman, agreed, saying, “We have to be clear that our near-term opportunities are not necessarily all going to be a done deal and that there will be significant challenges. …
“This transition does have fundamental risks, and we need to be open and transparent about that and work through those challenges together to figure out solutions,” she added.
Doreen Harris, president of the New York State Energy Research and Development Authority (NYSERDA), was more optimistic, saying, “We each have a critical role to play in this effort, and I believe change is not easy, but it is realizable. …
“This mid-transition point will have some messy spots on the way,” she added, but “I believe we are coming together in ways that not only get us from here to there but make our state the better in doing so.”
Panelists offered specific recommendations about how New York could be more flexible in its approach or better coordinate the transition.
NYISO’s Markham called for greater interregional cooperation among the RTOs/ISOs, saying, “Coordination amongst all [our neighbors] and state agencies as new polices are developed is critical to ensure there is an ability in those polices to keep resources around for reliability if necessary, because, in my opinion, that will minimize disruptions.”
Wentlent cited the NYSRC’s recent creation of an Extreme Weather Working Group, which was tasked with understanding how the grid is impacted by increasingly frequent and devastating disasters.
“We, and NYISO, are only at the cusp of understanding these [extreme weather events],” he said. He advised that New York study how every resource is correlated and impacted by these events because “until we understand all these pieces, we’re just at the beginning.”
Franey recommended that NYISO “could gain a lot of interesting efficiencies if [they] integrate storage with transmission … and, in some cases, could become more economical and efficient.”
“We have to make sure that we can be creative in our transmission-distribution system buildout, and that means looking at other technologies and not just traditional transmission technologies, since we want to make this as cost-effective as possible,” he said.
More than One Way to Skin a Cat
For decades New York’s clean energy sector has been dominated by nuclear and hydroelectric power, yet they do not produce nearly enough energy to achieve CLCPA mandates, speakers said.
That emissions-free generation has been bolstered recently, particularly by wind, which will soon make up a large part of New York’s total energy production once offshore projects being planned along the coast are connected. But still more renewables are needed if CLCPA goals are to be met.
The state’s future success will also heavily rely on distributed energy resources and dispatchable emissions-free resources, both of which are nowhere near at scale to meet the energy demands being asked of them and, to many observers at the conference, have yet to be fully fleshed out.
In that context, many panelists called for a more inclusive approach to New York’s decarbonization.
Mattera was one of the most vocal, saying, “It seems like we’re not doing enough to consider other energy technologies,” citing the perceived lack of research into hydrogen, geothermal, carbon capture, storage or wastewater heating technologies.
Keynote speaker Alexis Glick, CEO of biomethane producer Nature Energy, called for greater usage of biofuels. She pointed to the EU as evidence for how there are many ways to reach net zero, noting how it was forced to think creatively about its transition after Russia’s invasion of Ukraine caused gas shortages and embrace renewable natural gas (RNG).
“RNG is seen as a key ingredient to [Europe’s] clean energy future,” Glick said. The union, via the RePowerEU program, has committed to annually produce 35 million cubic meters of biomethane to displace Russian gas by 2030. “I believe RNG needs to play a critical role in our energy transition to achieve our mutual goals,” she said.
New York currently uses 50 trillion BTU of RNG per year, according to an April 2022 report from NYSERDA, and bioenergy accounts for less than 2% of the state’s electric generation, according to the agency. Biofuels were one of the most contentious topics as the CAC was developing the Scoping Plan, as members disagreed on its environmental benefits and role in the transition. (See Natural Gas Debate Heats up Hearing on CAC Scoping Plan.)
The Scoping Plan would recognize these resources as ways to reduce state emissions, but it still faces stiff activist resistance, which is why hydrogen was also discussed during the conference and offered as alternative to fossil fuels.
During an industry fireside chat, panelists such as Tim Cortes, chief technology officer at Plug Power, which develops hydrogen fuel cell systems, noted that hydrogen can be an important piece to the transition puzzle.
“Because we are still in the early stages of this transition, it is critical that we not take any viable solutions that could decarbonize the economy off the table,” he said.
“In the long run, hydrogen gives us the ability to be part of the solution by lowering emissions while keeping generating facilities that would’ve been retired around for a longer period of time,” said Mark Sudbey, CEO of Eastern Generation.
Referencing the risks posed by the early retirement of many fossil fuels generators, Rudy Wynter, New York president of National Grid, said, “We’re going to need a lot of solutions to achieve our goals, and so we should keep an open mind to the many pathways to decarbonization. …
“Hydrogen can play a role in this transition, especially if you’re operating off natural gas distribution networks because it will help to decarbonize those fossil fuels,” he said. Furthermore, RNG and hydrogen “can help us decarbonize [natural gas] molecules, because let’s be clear, not everyone is going to be able to afford to electrify, and some customers may have a harder time finding alternative decarbonization fuels.”
There was some reluctance about hydrogen’s potential, however.
“I think it’s still pretty early to judge [hydrogen’s] effectiveness in New York,” Markham said, because the “the challenge is that, No. 1, we still need the infrastructure to support not only the production and transportation of hydrogen, but also the storage; and secondly, what will the cost of that hydrogen be? Because the costs vary wildly.”
Hydrogen’s fluctuating costs can be partially attributed to its many forms, where the price of blue hydrogen, which is produced from fossil fuels, and green hydrogen, which comes from the electrolysis of water to produce zero emissions, are dependent on the price of the resource that they are derived from.
More important, there is a hard push to develop technology to generate green hydrogen much more cheaply, and the degree to which it is successful will be a critical determinant of green hydrogen’s prospects for large-scale adoption as a fuel.
NYSERDA’s Harris, however, cited hydrogen as an example of the collaboration the transition can create, referring to the seven-state Northeast Regional Clean Hydrogen Hub that was led by New York but pooled everyone’s expertise. (See Vermont Joins Northeast Clean Hydrogen Hub.)
“I believe we put together not only a winning proposal, but one in which we can continue to think about this resource and the ways it can help us achieve decarbonization,” she said.
“We have to catch our breath and recognize that we’re all in this together,” Commissioner Burman concluded. “We need to keep focused on what can be helpful as we move forward and how do we accomplish our transition in a way that is helpful, and not just rip off the Band-Aid saying, ‘We got this,’ because we may not, and we cannot risk reliability, affordability or safety.”
New Jersey’s largest planned offshore wind farm would have a “major” effect on commercial fisheries and “scenic and visual resources,” but only a moderate impact in 13 other categories, the Bureau of Ocean Energy Management said Monday in its an environmental impact statement (EIS) for the Atlantic Shores project.
The 900-page draft report on the 1,510-MW project concluded that the wind farm would have “moderate to major” impact on navigation and vessel traffic and a “major” impact on visual aspects of the sea and on cultural resources, such as historic, archeological and geographically significant areas.
The project would also have “negligible to moderate” impact on most mammals, including the endangered North American right whale, the report found. But the cumulative impact of nearby OSW projects and non-wind projects, and Atlantic Shores itself, including decommissioning of the turbines, would be “negligible to major,” the EIS reported. It said adverse impacts would “result mainly from pile-driving noise, vessel noise and presence of structures.”
The impact of OSW projects on whales has emerged as a significant issue in recent months, after several dead whales washed up on the Jersey Shore. Project opponents and two area congressmen have questioned whether the deaths were linked to preliminary marine study work underway for the projects and called for a halt to the projects while the issue is investigated.
Federal and state authorities say there is no evidence that the deaths had anything to do with OSW projects. But poll results released Thursday by Fairleigh Dickinson University suggest the unfounded reports are having an impact on public opinion.
The poll found that when the whale deaths were mentioned in the question, 35% of New Jersey residents said they favored continued offshore wind development, while 39% said development should be halted. When the whales were not mentioned in the question, 42% of those polled were in favor and 33% opposed.
The BOEM report says the impact to the whales of not approving the projects would be “negligible to major,” the same as if the projects go ahead because of issues such as “coastal and offshore development, marine transportation, fisheries use and climate change,” with a warmer ocean and strong storms affecting the sea mammals.
BOEM has scheduled two public hearing to solicit public comments on the draft on June 26 at 1 p.m. and June 28 at 5 p.m., with a 45-day comment period that ends on July 3.
Assessing Impacts
The New Jersey Board of Public Utilities picked the Atlantic Shores project in the state’s second OSW solicitation in 2021, when it also backed the 1,148-MW Ocean Wind II project being developed by Denmark-based Ørsted. The BPU picked Ørsted’s Ocean Wind I project in the state’s first solicitation in 2019. (See NJ Awards Two Offshore Wind Projects.)
The Atlantic Shores EIS covers the project’s first phase, which has been approved by the BPU, and a second phase for an additional 1,327 MW, which has not. Together, the two projects would involve installation of 200 wind turbines.
The draft EIS for Atlantic Shores, a joint venture between EDF Renewables North America and Shell New Energies US, assesses the potential biological, socioeconomic, physical, cultural and other impacts of the project, which at its closest is 8.7 miles from the Jersey shoreline.
The study assesses impacts of six different scenarios if the project is approved. These included approval of the entire proposal, along with several scenarios in which the project is modified, including a reduction in the number of turbines and offshore substations to minimize the impact on certain habitats; a reduction of the number of turbines to reduce the visual impact; modification of the project to create a “setback” between the project and neighboring Ocean Wind I; and an adjustment in the type of monopoles used in the foundation to reduce the impact.
The draft EIS then assesses the impact of each scenario and defines them as negligible, minor, moderate or major.
The EIS, for example, concluded in all the scenarios that the impact was either moderate or lower for air; water; birds, coastal habitats and fauna; fish, invertebrates and essential fish habitat; sea turtles; wetlands; demographics, employment, economics; environmental justice; land use and coastal infrastructure; and recreation and tourism.
Increased Vessel Traffic
The study found that the commercial and recreational fishing sectors would be impacted by increased anchoring of boats working on the turbines, marine disturbance caused by cable emplacement and maintenance, and the additional noise generated by construction. Those factors could disrupt fishing trips and make it difficult to fish, as well as prompting some commercial companies to avoid fishing in certain areas — all of which could reduce revenue, the report said.
The effect might also be to push all commercial fishing operations into the same, smaller fishing area, resulting in smaller catches, the report concluded.
“BOEM expects that increased vessel traffic associated with the proposed action would cause long-term, localized, moderate impacts on commercial and for-hire recreational fisheries,” the report concluded. BOEM also found that the overall impact on commercial fishing operations could be “major” in many scenarios.
The study found that the area’s cultural resources would be affected whether BOEM approved the wind projects or not and labeled the impact in the long term “major” in all scenarios, but only “moderate” if the projects were not approved.
“The primary sources of onshore impacts from ongoing activities include ground-disturbing activities and the introduction of intrusive visual elements, while the primary source of offshore impacts includes activities that disturb the seafloor,” the report found. “While long-term and permanent impacts may occur as a result of offshore wind development, impacts would be reduced” through a consultation process to reduce the effects on historic properties, the study concluded.
Navigation and Visual Impacts
The study found that navigation and vessel traffic would experience moderate impact regardless of whether the projects went ahead, in part because of rising traffic in the area and also traffic generated by other offshore wind projects. New Jersey’s OSW projects, if approved, would have a moderate to major impact when added to the cumulative impact of vessel traffic from nearby OSW projects and general water transportation traffic.
“Impacts from the proposed action alone would include increased vessel traffic in and near the project area and on the approach to ports used” by the OSW vessels, the report found. Vessels in the area would also experience “obstructions to navigation” caused by the projects.
During construction, the project would cause “short-term increase in project-related construction vessel traffic, short-term presence of partially installed structures, and short-term safety zone implementation,” the study found.
“Impacts on navigation and vessel traffic would also include changes to navigational patterns and to the effectiveness of marine radar and other navigation tools,” the report said. “This could result in delays within or approaching ports, increased navigational complexity, detours to offshore travel or port approaches.”
The study found that scenic and visual resources would suffer a “major” impact in the longer term, whether the New Jersey wind farms were built or not, because of other wind farms nearby being built and as a result of other marine activities, such as dredging and port improvements, marine minerals extraction and marine transportation, the report found.
If the state’s OSW projects don’t go ahead, “the character of the coastal landscape would change in the short term and long term through natural processes and planned activities that would continue to shape onshore features, character, and viewer experience,” BOEM said.
“Ongoing activities in the geographic analysis area that contribute to visual impacts include construction activities and vessel traffic, which lead to increased nighttime lighting, visible congestion, and the introduction of new structures,” the report concluded. The cumulative impact of other OSW projects and general marine activities would create a “major” impact, the study said. As a result, the cumulative effects of the projects and others in the area would be “appreciable,” the study concluded.
“The main drivers for this impact rating are the major visual impacts associated with the presence of structures, lighting and vessel traffic,” the study found.
Expected energy from stored fuels used in a long-duration severe cold-weather scenario, with and without NECEC and EMT | ISO-NE
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