FERC last week said it needs more description behind MISO’s plan to adopt sloped demand curves for its capacity auctions before it decides the matter.
Among the commission’s questions in its deficiency letter: a request that MISO better explain how its opt-out provision would work (ER23-2977).
MISO’s provision to allow utilities to opt out of the auction for three years at a time drew the most criticism based on stakeholders’ mixed reactions to the filing. (See MISO Stakeholders Split on Sloped Demand Curve Proposal.)
FERC ordered MISO to justify how its plan to impose a “X% adder” on load-serving entities that opt out constitutes comparable treatment between utilities. The adder would require load-serving entities (LSEs) to secure more capacity than strictly necessary to meet MISO’s one-day-in-10-years system reliability standard. The adder would be based on how much excess capacity is procured through the auction using the sloped demand curve in previous years. FERC asked exactly how MISO would calculate the adder beyond the 2025/26 planning year, because MISO included detailed calculations only for the first planning year the sloped curve would be in play.
The commission asked MISO to shed more light on why LSEs electing to opt out of the auction would completely forgo the auction and not a portion of their resource adequacy requirements.
FERC was left curious as to how MISO would handle establishing planning reserve margin requirements (PRMRs), considering some LSEs would opt out and affect the remaining capacity requirements.
The commission also asked how MISO would establish PRMRs for LSEs in states that have overridden MISO’s planning reserve margin and how the opt-out provision would interact with the final figure. The commission said MISO’s tariff was silent regarding such circumstances and whether an LSE’s final PRMR would depend on its opt-out status.
FERC inquired after several other details around MISO’s proposal. It asked whether MISO would forgo an annual price cap or use a replacement annual clearing price cap for local resource zones. MISO proposed to remove its existing cost of new entry multiplied by 1.75 cumulative price cap on local resource zones when zones are in shortage or near-shortage conditions.
FERC also asked how MISO would line up the calculation of its cost of new entry with the calculation of the sloped demand curve.
The commission said it needed to know which components of MISO’s sloped demand curve would change every three years and which would be subject to change annually. MISO proposed to produce an entirely new sloped demand curve every three years after performing an analysis to see what’s changed in auction supply and demand.
Finally, FERC asked MISO what unit of measure it would use to express marginal reliability impact curves.
MISO’s sloped demand curve shape relies on marginal reliability impact curves, or the depiction of the diminishing reliability value of incremental capacity during abundant supply and the increasing importance of incremental capacity during scarce supply. FERC said it needed to know MISO’s schedule for determining both its marginal reliability impact curves and the resulting sloped demand curves.
DFW AIRPORT, Texas — Public Utility Commissioner Will McAdams made public his intention to resign before next year during an SPP stakeholder meeting Nov. 28.
Adams, whose departure has been rumored for several weeks, said his family and his health both became factors in his decision to step down.
“This has been a challenging duty. I’ve enjoyed it, it’s been meaningful, but there were considerable pressures on both the family and the health,” McAdams told RTO Insider during a break in the SPP meeting. “None of those pressures looked to resolve themselves in the near term. I have a young family and I need to be more attentive to them.”
McAdams and his wife have three children less than 10 years old. In addition to his responsibilities for the PUC, he also has chaired the Resource and Energy Adequacy Leadership (REAL) Team addressing SPP’s resource adequacy challenges and was elected last month to serve as president of the RTO’s Regional State Committee (RSC) in 2024.
In his spare time, McAdams has taken on a greater role in managing his family’s ranch in Southeast Texas.
“It’s multiple things all converging at the same time,” he said. “This decision has not been and was never going to be easy, but it’s been some of the most meaningful work of my life.”
McAdams’ term on the PUC expires Sept. 1, 2025. His resignation will leave the five-person PUC with two vacancies. Peter Lake resigned as chair in June and has been replaced by Kathleen Jackson as the commission’s interim chair.
Gov. Greg Abbott (R) appoints the PUC’s commissioners. Appointees must be confirmed by the Senate, which is in a fourth consecutive special session.
McAdams also leaves a sizeable hole in SPP’s initiative. His leadership of the REAL Team has been praised by the RTO’s CEO, Barbara Sugg, and members of the team.
Omaha Public Power District’s Colton Kennedy, chair of SPP’s Supply Adequacy Working Group and a key player on the REAL Team, said McAdams is a “pivotal force” in setting the direction of policy.
“Chairman McAdams has had an exceptional ability to steer discussions forward amidst uncertainty,” Kennedy said. “His leadership comes at a crucial time in the evolution of the electric grid.”
“I appreciate his leadership. He is very structured, he keeps people motivated, he keeps the conversation going and he keeps the issues moving forward,” Evergy’s Denise Buffington, the REAL Team’s vice chair, said. “I like the pace at which he does it. He does keep things moving and sets targets. It’s complex work, but the objective is not to spin out.”
McAdams said the RSC, composed of SPP state regulators, will “recompute” both the committee’s and the REAL Team’s leadership. A state commissioner will take over the REAL Team’s chairmanship; South Dakota’s Kristie Fiegen and Nebraska’s Chuck Hutchinson hold two of the three commissioners’ slots.
Buffington said McAdams was instrumental in setting the team’s work plans. “Now, it’s executing on that and making sure it stays on the rails. It’s constant monitoring, making sure we’re on track and not getting overwhelmed,” she said.
SPP said the RSC’s vice-president elect, Minnesota’s John Tuma, will serve as the group’s president in 2024. The committee will hold an election next year to fill the vice president’s open position.
“As we move into the spring, you’ll have a more defined outlook on how this organization will proceed forward,” McAdams told the REAL Team.
He said he will continue to chair the group’s final 2023 meeting. He said he wants to close out the team’s objectives for the year before turning the chairmanship over to his replacement.
“I’ve appreciated the work and effort that everybody’s put into this. I think everybody realizes that this is an important time in our industry and in our history,” McAdams said. “I was able to help guide part of that, but this was never going to be up to any one person, any one organization. It’s going to require a repeat rotation of good people into these jobs to help prepare for the next winter, to help prepare for the next summer, to help prepare for the next need, especially as those needs continue to grow.”
Abbott appointed McAdams to the PUC in April 2021, part of the commission’s overhaul after the deadly winter storm that killed hundreds of Texans and nearly imploded the ERCOT grid. The three incumbents all resigned or left the PUC, with McAdams and Lake appointed as the first two new commissioners. Texas lawmakers also increased the PUC’s membership from three to five commissioners.
“I am grateful to the governor for giving me the opportunity,” McAdams said. “It’s just that everybody comes to a time where they need to turn it over to fresh blood. And it’s that time.”
McAdams previously served as president of the Associated Builders and Contractors of Texas after spending more than 10 years in state government. He was an adviser to House Speaker Dennis Bonnen and held several senior staff positions within the Senate.
Following graduation from Texas A&M University, McAdams served four years as an infantry officer in the U.S. Army, retiring as a captain.
BALTIMORE, Md. ― Maryland officials like to point out the state now has the country’s most ambitious greenhouse gas emissions reduction goal — 60% by 2031 — and is also aiming for 100% clean power by 2035, with 14.5% coming from in-state solar.
Hitting those targets is doable, but hard, they say.
“It’s going to be incredibly complicated,” said Josh Tulkin, director of the Maryland Sierra Club, speaking at the Solar Focus conference sponsored by the Chesapeake Solar and Storage Association (CHESSA) on Nov. 16. “There’s a desire to often say because we have to do it, let’s also make it sound super easy. It won’t be super easy. We have 100 years of … using one particular system weighted toward a particular type of power generation.”
“There’s a lot of hard stuff we’ve got to face,” agreed Del. Lorig Charkoudian (D). “If we roll up our sleeves, we can do it, but it does mean we have to be willing to acknowledge the challenges along the way and be willing to be creative and be willing to sit down a lot of times with folks that we’re not usually sitting down with to sort through and find solutions together.”
As detailed in panel discussions at the conference, the obstacles to a decarbonized electric system include the siting and permitting problems many solar developers face, Maryland’s dependence on out-of-state wholesale power — still about 60% fossil fuels — and the need for grid modernization to interconnect the clean power coming online.
On the plus side are Maryland’s Democratic Gov. Wes Moore and Democratic control of both houses in the General Assembly, as well as a new Democratic majority on the state’s Public Service Commission.
But, Charkoudian cautioned, having political majorities may not translate into the policies or the market forces the state will need.
“Markets are … not real things in and of themselves,” she said. “They are things we created from policy; so, whatever we want the market to do, we can make the market do. So, if we’re saying the market’s not working, it’s our fault, our policy and results,”
The bigger question for Charkoudian is not if, but “how do we get [to 100%]? … How do we set up the market so there’s a regulatory framework that allows us to get there?”
Kristen Harbeson, political director of the Maryland League of Conservation Voters, said that incorporating environmental justice strategies into policymaking from the start will be critical and likely uncomfortable for many. Like Charkoudian, Harbeson called for expanding the stakeholder voices sitting at the tables where legislative and regulatory priorities are set and compromises forged.
“Even if your table is full … figure out who’s not at the table, who needs to be at the table, making sure any community that your project or your effort touches is being engaged,” she said.
“If you’re comfortable, you’re probably not doing it right,” Harbeson said. “You need to be ready to be uncomfortable because progress happens in the space between discomfort and sheer panic.”
Community Solar
Maryland’s Climate Solutions Now Act (CSNA), passed in 2022, set the 60% emissions reduction goal. As mandated in the law, the Department of the Environment will roll out its implementation plan before the end of the year. Speaking at a conference in October, Environment Secretary Serena McIlwain hinted the plan would focus on transportation, buildings and exploring options for expanding renewable energy. (See Chasing Goals, Facing Obstacles at Md. Clean Energy Summit.)
In Maryland, policymakers and project developers appear to be focusing on in-state initiatives, aimed at growing the local solar market, as they wait for PJM to clear its backlog of utility-scale solar and storage projects, which could take until 2026, (See Solar Developers Sing Mid-Atlantic Interconnection Blues.)
Maryland is behind on its efforts to reach the 14.5% solar target, according to former state Sen. Paul Pinsky, sponsor of the CSNA and now director of the Maryland Energy Administration. The passage of H.B. 908 in April, making Maryland’s community solar pilot program permanent, could help the state make up lost ground, he said, speaking at the two-day Solar Focus conference on Nov. 15.
Del. Luke Clippinger (D), a sponsor of H.B. 908, sees the law as a first step. Making the program permanent has raised public interest in community solar, which could in turn lead to “creative opportunities for businesses and nonprofits to come together and work with individual neighborhoods and work with individual communities so that we can expand this program, especially in low- and moderate-income communities across the state,” Clippinger said.
The law requires that 40% of the output of community solar projects in the state goes to low- and moderate-income subscribers.
“The greatest potential for expanding the growth in renewable energy is in our low- and moderate-income population because they don’t generally have the ability to do this otherwise,” he said.
V2G, VPPs and TOU
Looking toward the 2024 legislative session beginning in January, Del. David Fraser-Hidalgo (D) is working on a new bill to promote the development of residential solar and storage, electric vehicle-to-grid (V2G) systems and virtual power plants (VPPs).
The Distributed Renewable Integration and Vehicle Electrification (DRIVE) Act will “encourage the PSC to craft incentives and reduce barriers for consumers hoping to participate in V2G charging and those who wish to participate in a VPP,” Fraser-Hidalgo said in an email to RTO Insider.
The PSC will also be authorized “to identify the most cost-effective way to roll out VPPs in coordination with FERC, PJM and other stakeholders” and to explore the introduction of default time-of-use rates at a future, not-yet-determined date, he said.
With V2G, an electric vehicle’s battery can be tapped to put power on the grid at a time of emergency or high demand. Similarly, VPPs are combinations of distributed energy resources — such as solar and storage — that either can connect to the grid when needed or operate off-grid in emergencies to keep the power on at community centers, hospitals or other critical facilities.
Time-of-use rates provide price signals to consumers to manage their energy use by charging increased rates during times of peak demand and lower rates in off-peak hours.
Previewing the bill at Solar Focus, Fraser-Hidalgo said the DRIVE Act would use a term like “discounted rates” rather than time-of-use. “I think everybody [at the conference] probably knows what time-of-use is … but when you’re trying to get people to change behavior, probably something like discounted rates makes a lot more sense.”
The bill aims to address questions about “how do we work with utilities and how do we diversify where we get electricity from, how we store electricity and how we distribute electricity,” he said, while also creating “a lot of resilience and redundancy we currently do not have.”
Charkoudian agrees that distributed resources, like V2G and VPPs, will be “a huge piece” of Maryland’s march to 100% clean energy, but she cautions that policy, regulation, technology and markets have to be aligned. “Storage is a perfect example of the mismatch,” she said.
“Precisely because storage can do so much … it’s not just generation and it’s not just ancillary services; it’s not just a balancing of load; but [because] it’s all those things … none of the markets really work for it,” she said.
“We’ve got to find a way to get the conversation happening in a way that allows us to really head in the right direction or else we could have all the technology, all the brilliant people and not get our policies right and miss the opportunity,” she said.
With artificial intelligence systems undergoing a rapid pace of development and deployment in recent years across multiple industries, and security often “a secondary consideration,” developers must be active in preventing “novel security vulnerabilities” from taking root in their software, cybersecurity agencies from multiple countries warned in new guidance issued over the weekend.
The “Guidelines for secure AI system development” document was published Nov. 26 by the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) and the U.K.’s National Cyber Security Centre (NCSC). Similar organizations in other countries also signed on, including Australia, Canada, Chile, France, Germany, Israel, Japan, Poland, South Korea and Singapore. In addition, multiple technology companies and groups contributed to the document, many with their own AI initiatives, such as Amazon, IBM, Google, OpenAI and Microsoft.
“We are at an inflection point in the development of artificial intelligence, which may well be the most consequential technology of our time. Cybersecurity is key to building AI systems that are safe, secure and trustworthy,” Homeland Security Secretary Alejandro Mayorkas said in a press release. “Through global action like these guidelines, we can lead the world in harnessing the benefits while addressing the potential harms of this pioneering technology.”
CISA and the NCSC’s goal with the document was to provide a framework for developers to “build AI systems that function as intended, are available when needed and work without revealing sensitive data to unauthorized parties.” The guidelines can be used by developers of AI systems created from scratch or by those adding AI to existing tools or systems, with a focus on machine learning applications that can detect patterns in data that are not explicitly programmed by humans and can generate predictions, recommendations or decisions based on statistical reasoning.
New Vulnerabilities in Software Stack
Along with known cybersecurity threats, the addition of AI and machine learning elements to a system introduces new vulnerabilities that malicious actors can exploit. Attackers’ strategies can include prompt injection attacks, which involve manipulating large language models to produce unintended responses and actions, or corrupting the system’s training data or user feedback. If successful, such actions may allow users to perform unauthorized actions, extract sensitive information about the model or alter the model’s classification or regression performance.
Complicating the security picture is the fact that modern software products, including AI applications, integrate components from third parties such as data, models and remote services, making it “harder for end users to understand where responsibility for secure AI lies.” CISA and the NCSC said component providers “should take responsibility for the security outcomes of users further down the supply chain” and, when known risks cannot be mitigated, inform users of the risks and advise them on how to use the components securely.
The agencies arranged the guidelines into four key areas with the aim of covering the entire life cycle of AI system development and ensuring a “secure by default” approach: secure design, secure development, secure deployment, and secure operation and maintenance.
Secure design covers identifying risks and threat modeling, along with “specific topics and trade-offs to consider on system and model design.” Recommendations in this section for managers include ensuring staff members are aware of the risks facing AI and that threats to the system are understood and adequately modeled. Project leaders should ensure developers consider security as important as functionality and performance, judging the security benefits and trade-offs of elements as fundamental as the choice of AI model.
Under secure development, the authors grouped guidelines relating to supply chain security, documentation and asset management. Developers must identify, track and protect both their in-house assets and those from outside parties, ensuring third-party software is sourced from “verified commercial [and] open-source … developers” and prepared to switch to alternate solutions for mission-critical systems if outside components are compromised.
Technical debt management also falls in the second category; this concept applies to the practice of making engineering decisions for short-term results that fall short of best practices. The document’s authors acknowledged that “like financial debt, technical debt is not inherently bad, but [it] should be managed from the earliest stages of development” so numerous small decisions over rapid development cycles do not add up to major vulnerabilities.
Responsibilities Continue After Release
Secure deployment guidelines apply to the stage in which the AI system has been released to end users. Recommendations in this phase include releasing software only after subjecting it to thorough security evaluations; securing the infrastructure, such as application programming interfaces, models, data and the training and processing pipelines; and developing incident-management procedures.
Finally, once the system has been deployed, developers enter the secure operation and maintenance stage. A developer’s responsibility at this point is to monitor the system’s behavior in order to detect changes that could affect security, including malicious intrusions and natural data drift. Update procedures should be secure, the updates themselves must be tested before they are released, and developers should continue to participate in information-sharing communities to share lessons learned and best practices.
“As nations and organizations embrace the transformative power of AI, this international collaboration … underscores the global dedication to fostering transparency, accountability and secure practices,” said CISA Director Jen Easterly. “This joint effort reaffirms our mission to protect critical infrastructure and reinforces the importance of international partnership in securing our digital future.”
The Connecticut Department of Energy and Environmental Protection (DEEP) Nov. 20 issued a request for information regarding the state’s solicitation of energy storage to help electrify its diesel vehicle fleets.
The RFI is connected to a DEEP request for proposals aimed at replacing fossil generation and facilitating the interconnection of vehicle charging infrastructure. From the RFP, the state will select storage projects in three categories: projects that enable the electrification of vehicle fleets; projects that are co-located at the site of an existing fossil steam unit; or projects that are connected to the grid without co-location.
The RFI concerns the diesel fleet category of projects and is intended to “build [DEEP’s] understanding of the expected locations, charging profiles, fleet size and other pertinent information from potential bidders proposing to install an energy storage system supporting diesel fleet electrification.”
It is part of the state’s efforts to deploy 1 GW of energy storage by the end of 2030, a goal set by state legislation passed in 2021. The state has emphasized the need for projects that reduce emissions in designated environmental justice communities.
“The RFP will provide ratepayer support to cost-effective storage projects,” DEEP wrote. “Cost effectiveness will include health effects from displaced emissions.”
Along with the RFI, the state announced the allocation of nearly $1 million of federal Diesel Emission Reduction Act (DERA) funding to replace old diesel engines with electric alternatives or cleaner combustion engines.
“Diesel-related air pollution continues to harm public health in Connecticut, especially in the low- to moderate-income communities across the state that have borne a historic and disproportionate impact from air pollution,” DEEP Commissioner Katie Dykes said in a statement.
Dykes called the new storage and vehicle opportunities “important tools to cost-effectively and reliably reduce air pollution, support healthier communities and encourage further electrification of the heavy-duty vehicle sector.”
DEEP is aiming to release a draft RFP “shortly” that will select up to 450 MW of nameplate storage capacity, capped at 250 MW for any individual project. One point of contention that has emerged in the RFP stakeholder process is the co-location of storage with existing fossil generators.
For RFP applications of storage co-located with existing fossil generation, DEEP is “tying the category to amending the air permits to significantly reduce the plants running in the summer when emissions from the plants are most harmful,” a DEEP spokesperson told NetZero Insider. DEEP will also require projects to provide a date of the fossil fuel plant’s retirement, “so EJ communities benefit without hurting reliability.”
In comments following a July technical session, Cary Lynch, climate and energy policy manager for the Connecticut chapter of the Nature Conservancy, argued that incentivizing storage that is paired with existing fossil generation “will not help the state meet its decarbonization target and will only delay the retirement of older, dirty fossil fuel generation plants. … Pairing storage with Class I renewables should be prioritized. … Building and strengthening our renewable energy portfolio is critical to creating a clean, reliable and affordable electric grid.”
In other public comments after the meeting, several battery storage companies noted the difficulty of assessing and establishing fair and cost-effective compensation for co-located storage facilities within the context of ISO-NE market rules and the capacity commitments of fossil fuel generators.
Commenters including BlueWave, FirstLight Power and RENEW Northeast expressed concern about whether supporting co-located storage facilities would meaningfully decrease the site’s fossil generation beyond already existing policies and trends.
“We are concerned the current proposed structure may ask ratepayers to subsidize more expensive storage than is needed under the guise of emissions benefits when co-located storage is electrically indistinguishable from standalone storage,” RENEW wrote in July.
In BlueWave’s July comments, the company encouraged DEEP “to focus this solicitation on the deployment of cost-effective energy storage that will prepare the electric grid for the retirement of fossil plants and erode the economic rationale for all fossil generation in the state.”
Potential bidders for the diesel-fleet category of the RFP will need to submit responses to the RFI by Jan. 5 to be eligible for the RFP. Applications for the DERA funding are due by Dec. 15.
The Department of Energy on Nov. 27 said it would provide $275 million for seven projects around the country that are meant to bolster domestic clean energy supply chains.
The agency announced the funding at the inaugural meeting of the White House Council on Supply Chain Resilience, which includes Energy Secretary Jennifer Granholm and other administration officials.
DOE said the $275 million will leverage over $600 million in private-sector investments, which will help create 1,500 high-quality jobs. The projects are intended to address clean energy supply chain vulnerabilities by supporting key materials and components for batteries for grid and transportation uses, wind energy and energy-efficient buildings.
“President Biden’s Investing in America agenda is driving the manufacturing boom while preserving the communities and workforce that have powered our nation for generations,” Granholm said. “With these historic investments, DOE will bring new economic opportunities and ensure these communities continue their key role in strengthening America’s national and energy security.”
The projects aim to strengthen domestic clean energy supply chains by making them more resilient and cost competitive. The projects are with small and medium-sized manufacturers, and they address multiple needs in the domestic clean energy supply chain.
Alpine High-Performance Products will get $5.8 million to retrofit its existing facilities in Louisville, Colo., and Vandergrift, Pa., to produce ultra-thin, triple- and quad-pane insulated glass units for windows. The project will increase the firm’s production tenfold and create 100 good-paying jobs, DOE said.
Boston Metal is getting $50 million to build a new facility in Weirton, W.Va., to manufacture ultrapure chromium and high-temperature alloys used for clean power, fuel cell and green steel supply chains. The facility will be the only high-purity chromium and refractory metal alloy factory, and it will create 200 jobs.
Carter Wind Turbines is getting $20 million to build a new facility in Vernon, Texas, which will help scale production of hybrid wind turbine and energy storage systems that can be used to help power remote facilities. The firm expects to create 300 new jobs at the factory.
CorePower Magnetics is using its $20 million to help retrofit a retired coal plant in Pittsburgh for melting and casting of advanced magnetic amorphous alloys for grid components. The old plant is being used to leverage a significant network of utilities, transportation and facilities to create a factory that will install 10,000 tons of capacity for amorphous metals and magnetic component production. CorePower’s new facility is expected to increase domestic production by 20% and meet an estimated 10% of global demand for the materials.
FastCap Systems, doing business as Nanoramic Laboratories, is building a new facility in Bridgeport, Conn., to make new lithium iron phosphate battery electrodes for grid storage with help from $47.5 million in federal funds. The new manufacturing process at the plant is expected to cut costs, increase energy density and cut energy consumption.
LuxWall is getting $31.7 million to build a new facility in Detroit that will manufacture vacuum-insulated glass window units, which, when retrofitted onto buildings, provide one of the highest energy-efficient returns on investment. The facility is being built on the site of an old coal plant in the Delray neighborhood of Detroit and should create 277 jobs.
The biggest award from the announcements is the $100 million going to MP Assets Corp. to build a factory for lithium-ion battery separators that are important for electric vehicles, a sector dominated by China. The new facility will create 282 jobs on top of securing a domestic supply of the car components.
LA QUINTA, Calif. — Researchers are still in the early stages of determining the challenges, efficacy and cost of using hydrogen for both transportation fuel and blending with natural gas as part of the effort to transition to green energy.
Katie Jereza, vice president of corporate affairs at the Electric Power Research Institute (EPRI), discussed the viability of blending hydrogen into natural gas infrastructure during a Nov. 14 panel at the annual meeting of National Association of Regulatory Utility Commissioners.
“As we’re looking to decarbonize the economy, fuel blends with higher hydrogen content can result in lower carbon emissions per megawatt hour,” Jereza said.
According to the U.S. Department of Energy, hydrogen can play a role in decarbonizing up to 25% of global energy-related carbon emissions. But the details are still being worked out in tests and demonstrations done by EPRI and other research facilities.
EPRI recently completed a series of four tests blending different percentages of hydrogen into reciprocating internal combustion engine (RICE) natural gas units to see if hydrogen could lower emissions without compromising structural integrity. While each test yielded different results, overall takeaways concluded that hydrogen blending could be one key piece of a larger puzzle to reach a net zero economy.
One of the tests conducted by EPRI in May, in collaboration with WEC Energy Group and Wärtsilä Energy, found that blending 25% hydrogen into RICE units reduced carbon emissions by up to 10% with no significant impact to the efficiency of the system.
Jereza and other engineers say that making the most out of the infrastructure that’s already in place will save time and resources; EPRI made no modifications to the gas turbines used in their tests.
“Using hydrogen can enable natural gas assets and infrastructure to be leveraged as a resource for decarbonization in this integrated energy network,” Jereza said.
She added that while recent innovations in burner design and fuel staging enhanced the ability of gas turbines to accommodate fuels with high hydrogen content, more work is needed to develop turbine components suitable for 100% hydrogen combustion.
Uncertainties Remain
Argonne National Laboratory published findings in October on modeling that found blending 30% hydrogen into pipelines yielded only a 6% decrease in emissions. Its study also concluded that blending at that level significantly increased leakage and compromised the integrity of the pipeline.
Because hydrogen is a smaller molecule than methane and is substantially lower in density, it can easily crack solid metals. As a result, fuel supplies and other system components, such as the materials used in pipelines, may need to be re-sized to account for the increased volume of fuel and pressure needed to reach the same output, Jereza said.
Jeffery Preece, director of research and development at EPRI, told NetZero Insider that gas infrastructure materials start to become impacted when a blend exceeds about 20% hydrogen.
Critics also question hydrogen’s ability to decrease greenhouse gas emissions along the supply chain. The most commonly used hydrogen is “blue” hydrogen, which is produced by combining natural gas with high-temperature steam, a highly energy-intensive process that results in carbon emissions unless combined with a carbon capture system.
Engineers and power producers are looking to green hydrogen produced through electrolysis — and without GHG emissions — as an alternative.
Preece said the goal of most hydrogen blending tests, including EPRI’s, is to ensure that all emissions are accounted for in the value chain process associated with the production and use of the fuel. Using hydrogen produced with fossil fuels could divert from the goal.
“The focus is, of course, can hydrogen be produced from low-carbon pathways, so we use the ‘green’ moniker to demonstrate the hydrogen made from electricity and then that electricity comes from renewables,” Preece said. “So depending on the economics and use case, carbon capture and sequestration technologies can be used on the hydrogen facilities, and then it’s just a matter of the economics and the viability of how much CO2 is captured from that process.”
Preece pointed out there is little low-carbon hydrogen production occurring in the U.S. today, with most still being produced from natural gas.
More work is needed to understand the cost and efficacy of integrating hydrogen into the energy system, according to Preece and Jereza.
“When we look at the total energy economy, we’ll be able to find ways to reduce the total energy wallet,” Jereza said. “But I’d say that there’s a lot of uncertainties still around how affordable it will be.”
The New Jersey Senate Environment and Energy Committee took testimony last week on a bill that would put into law the state’s goal to reach 100% clean energy by 2035, sparking business concerns that the state is overreaching and union fears that it could create jobs outside of the state.
Gov. Phil Murphy (D) put the target into effect by executive order, committee Chair Bob Smith (D) said at the start of a hearing on S2978 on Nov. 20. Murphy’s successor could simply change it by enacting their own executive order, said Smith, the sole sponsor of the bill. Making it the state’s renewable portfolio standard (RPS) would make it more likely to remain in effect.
“There are no guarantees that the next governor will be as green as the current governor,” Smith said. “An executive order is only a rule. … When state government is making decisions about investments, what we should be doing or not doing, you need a guiding principle.”
But Ray Cantor, senior lobbyist for the New Jersey Business and Industry Association (NJBIA), said he received the latest version of the bill only four days before and had not had time to analyze the implications. He urged the committee to hold off voting until a later date.
“We have concerns generally with setting artificial deadlines to meet artificial goals in a period of time that may not be practical or implementable,” Cantor said. “When you do that, you end up making decisions that may not be the most cost effective, the most technologically feasible and the best public policy. You’re driving decisions based on deadlines put in law and not necessarily what’s realistic economically or on the ground.”
The committee did not vote on the bill at the end of the five-hour hearing, most of it focused on S2978. Smith said he would review the testimony and adjust the bill, and the committee would vote on it Dec. 18.
It was one of two Smith-sponsored bills considered, but not voted on by the committee, that could bring sweeping changes to the state’s clean energy efforts. The second, S3992, would require the New Jersey Board of Public Utilities (BPU) to create a plan to modernize the state’s electric transmission and distribution system and would allocate $300 million to do so. Smith said at the hearing that he does not expect the bill to be ready by the time the legislative session ends in January and that it will be introduced in the next session.
New Clean Energy Certificates
The RPS bill states that New Jersey is on track to satisfy 75% of its annual energy use with clean energy by 2025 and 84% by 2030. Smith said the bill would help the state reach 100%.
“Rapidly increasing clean electricity generation to achieve 100% of retail sales of electricity in New Jersey by 2035 will help displace fossil-fueled electricity generation and thereby reduce greenhouse gas and co-pollutant emissions,” the bill says.
It outlines a mechanism to reach that goal by creating Clean Electricity Attribute Certificates (CEACs), each of which represents “1 MWh of generation from a clean electricity production facility whose electricity is produced in New Jersey or acquired through the PJM Interconnection.”
Electricity generation providers and suppliers would be certified and “procure and retire” CEACs to meet a set of goals: at least 80% matched by June 1, 2027; 85% by June 1, 2030; and 100% by June 1, 2035. The bill would also allow CEACs to be replaced by clean energy certificates generated by existing state programs, including solar renewable energy certificates, Zero Emission Certificates from nuclear plants and offshore wind Renewable Energy Certificates.
The bill also sets a goal of in-state clean energy sources meeting 65% of New Jersey’s electricity demand, with the remainder supplied from out of state. If the state does not appear ready to reach the 65% target, the bill allows the BPU to “procure additional electricity” out of state.
Investment and Jobs
Jesse Jenkins, an assistant professor and energy systems engineer at Princeton University, said a team he heads had modeled New Jersey’s clean energy plans, including the impact of S2978, and believes it would “help meet our climate goals, and all while maintaining affordability and reliability of New Jersey’s electricity supply.”
“The law would ensure more clean electricity would be generated in-state in 2035 than is generated by all resources —both fossil power plants and clean sources — today,” he said. “That ensures a steadily expanding market for clean energy, investment and jobs in the state. … We estimate that under the proposed law, New Jersey electricity customers would pay less for their electricity supply and 2035 than we did in 2019.”
The law would support 24,000 jobs building, operating and maintaining electricity generators, including in the solar and offshore wind sectors, Jenkins said. More than 90% of the subsidies provided by state programs would go to generators within New Jersey, supporting investments and jobs in the state, he added.
Jenkins said the bill would also keep the state’s three nuclear plants open and would “not require natural gas plants to retire until clean, reliable replacements are available.” Gas plants could remain open until 2045, so they could be “called upon by the grid operator to meet reliability needs, while substantially reducing their generation overall and therefore their pollution,” he said.
Artificial Deadlines
But NJBIA’s Cantor said he believed gas-powered plants would be used for far more than just providing “reliability” services for when renewables could not cover demand. He argued that the grid is not ready for the amount of new clean electricity proposed in the bill. And he said NJBIA has concerns that the jobs created may actually be out of the state.
“If we don’t have the infrastructure to be able to hook up to solar developments, we’re really just driving those jobs, money, everything else out of state,” he said.
Jennifer Mancuso, director of government affairs for NJ LECET, a labor management cooperative that is part of the New Jersey Laborers Union (LIUNA), said the organization is also concerned about where the new jobs would go. She said LIUNA agrees with the state’s decarbonization goals but is concerned by the “considerable discretion” the legislation gives the BPU to seek energy out of state if New Jersey does not meet the 65% goal of in-state clean energy production.
Eric Miller, director of New Jersey energy policy for the Natural Resources Defense Council, said the committee should consider the impact of not adopting the legislation and where it would get its energy in that scenario. New Jersey is currently an energy importer and so already relies on out-of-state sources to meet demand, in large part, he argued, because fossil fuel-fired power is more expensive in the state.
“But for policies like this legislation that we’re considering, we would produce even less electricity in New Jersey,” he said. “[In] a purely competitive market, we buy it from PJM, almost every time. The only way to shift that needle back into New Jersey is through policies like this legislation.
“With this legislation, we could be a clean energy powerhouse.”
Hydrogen hasn’t gotten this much publicity since the Hindenburg. And never more U.S. taxpayer money, now estimated at $137 billion over the next 10 years.[1] And of course, federal policymakers waving wands over hydrogen, begging the question posed by The Lovin’ Spoonful, “Do You Believe in Magic?”[2]
Here we’ll cover some reality about hydrogen in the electricity sector.
Hydrogen does not exist on Earth as a standalone atom. You have to make it by separating it from a molecule it is part of, like water or a fossil fuel.
There are different ways of making hydrogen, and each way has been given its own color – nine and counting.[3] I’m not going to get into the debates about grey hydrogen (from fossil fuels), blue hydrogen (from fossil fuels with carbon capture), or myriad other colors. Here we’ll just talk about pure green hydrogen, from electrolysis of water using green electricity. Basically you use green electricity (from wind, solar, etc.) to separate the hydrogen and oxygen atoms that are in water molecules.
Green hydrogen electricity is very inefficient. You need a supply of electricity (and ultrapure water[4]) for the electrolysis, a way to store and transport the hydrogen (or an intermediary carrier like ammonia), and then a generator to turn the hydrogen back into electricity. Essentially two round trips.
The pure energy equivalence between electricity and hydrogen is 39.4 kWh to produce 1 kg of hydrogen,[5] and the most efficient electrolysis technology is around 80%,[6] so best case it takes 49.3 kWh to produce 1 kg of hydrogen. That creates the hydrogen. If the green source of electricity costs say $30/MWh,[7] then with the most efficient electrolysis the hydrogen costs $37.5/MWh equivalent.
Now we need to store and transport the hydrogen.[8] The most efficient storage and transportation method is probably converting hydrogen to ammonia, storing and transporting ammonia, and converting ammonia back to hydrogen.[9] The round-trip efficiency is 34%.[10] So that $37.50/MWh hydrogen equivalent from the prior paragraph becomes $110.30/MWh hydrogen equivalent from the ammonia round trip.
Now we’ll use this hydrogen to generate electricity. The most efficient turbine I can find for turning hydrogen back into electricity is the GE turbine 9F.04 in the 1×1 combined cycle configuration at 443 MW, which GE’s calculator says would require 22,307 kg/hour,[11] which converts on a pure energy basis to 879 MWh,[12] for a conversion loss of 50% (output of 443 MWh divided by input of 879 MWh). So if the cost of the hydrogen input is $110.30/MWh, the cost of the converted electricity output is $220.60/MWh. Thus, the initial $30/MWh electricity supply we started with has a delivered electricity cost of $220.60/MWh.
Just so we’re clear, $30/MWh green electricity becomes $220.60/MWh green electricity, a cost increase of 735%. Put another way, it would take 7 MWh of green electricity at the source to end up with 1 MWh of green electricity delivered to consumers.[13] So for every 1 MWh used, 6 MWh are wasted.
The foregoing is just about the energy conversion losses. The capital and non-fuel operating costs of the water purifier, electrolyzer, storage, transportation and generation facilities are extra. And those costs are, to use a technical term, ginormous.
Oh, if you’ve been following hydrogen news you may note that the analysis I provide here is in terms of end-to-end MWh costs, whereas hydrogen costs are talked about in terms of $/kg with a moonshot, aka “Hydrogen Shot,” objective of getting green hydrogen’s current cost of $4-6/kg down to $1/kg.[14] I doubt that’s realistic but in any event it’s largely irrelevant to green hydrogen electricity. The dollar per kg cost is cost at the outlet of the electrolyzer, before the losses and other costs of storage, transportation and generation. What really matters for green hydrogen electricity is the cost per MWh you start with and the cost per MWh you end with.
By the way, few gas turbine models can burn 100% hydrogen, and many turbine models are limited to hydrogen percentages like 5%, 15% and 30%.[15] Since thousands of gas turbines are supplied by dozens of major interstate gas pipelines, it begs the question of how various custom hydrogen-natural gas blends would be mixed, stored and transported across the country. And that still leaves the carbon emissions from the natural gas in the blended stream — if carbon capture were economic for that then it would be economic without using any of the incredibly expensive hydrogen.
By the way, blending hydrogen into existing natural gas systems for transportation is unrealistic (as are total conversions). Not only are there many physical incompatibility issues, such as those the National Renewable Energy Laboratory has described,[16] but hydrogen requires three times the volume for the same energy content as natural gas,[17] so blending hydrogen reduces the amount of energy transported (and stored via line pack).[18] And millions of end-use appliances served by a given pipeline are incompatible with a hydrogen blend above 20-30%[19] which means either: (1) the dominant natural gas supply would continue to create carbon emissions (or be wasted), or (2) there would need to be a one-time total conversion to hydrogen entailing modifications/replacements of all these appliances at the same time. Good luck with those options.
And one more thing. Notwithstanding the Department of Energy’s claim that its recently announced “hydrogen hubs” will “slash harmful emissions,”[20] green hydrogen electricity creates more NOx emissions than natural gas electricity. As much as twice for equivalent energy content.[21] This does not mesh with public health and environmental justice concerns.
[8] Storage and transportation are necessary because all green electricity that could be used as electricity as generated should not involve hydrogen at all. Projects that would involve diverting grid-connected green electricity generation into hydrogen production, rather than simply consuming the green electricity as generated, make no sense.
[13] There are unusual situations where this analysis may not apply, such as where the green electricity source would otherwise be curtailed and efficient storage like salt caverns is available.
[18]https://www.nrel.gov/docs/fy23osti/81704.pdf. NREL points out (page 14) that it may be possible to compensate for lower energy content with increased flow via higher pressure, however higher pressure would be inconsistent with the lower pressure likely needed for steel integrity.
The Bureau of Ocean Energy Management last week approved the Empire Wind project for construction, making it the sixth commercial-scale offshore wind farm to receive approval from the federal government.
The Department of the Interior said the joint venture between Equinor and BP supports the Biden administration’s aim to deploy 30 GW of OSW by 2030 and would assist New York and New Jersey in achieving their respective targets of developing 9,000 MW and 7,500 MW of OSW energy by 2035.
The project consists of two farms, the 816-MW Empire Wind 1 and the 1,260-MW Empire Wind 2, about 12 nautical miles south of Long Island and about 16.9 nautical miles east of Long Branch, N.J., respectively. EW1 is anticipated to be operational by 2027 and EW2 a year later, according to the New York State Energy Research and Development Authority.
BOEM’s Record of Decision documents environmental mitigation strategies, including compensating fishers impacted by construction in the lease area.
The approval is a positive development for an industry beset by problems recently, including regulatory setbacks, local opposition and financial constraints stemming from rising inflation that has led to project cancellations.
Danish company Ørsted canceled its two New Jersey OSW projects, Ocean Wind 1 and 2 this month after it said surging interest rates and supply chain disruptions made them unfeasible. (See Ørsted Cancels Ocean Wind, Suspends Skipjack.) A week later, Eversource Energy cited inflation as the reason for divesting its stake in the Revolution, South Fork and Sunrise projects. (See Eversource Closer to Exiting OSW Venture with Ørsted.)
Empire itself appeared to be in jeopardy after the New York Public Service Commission last month denied a request to amend power purchase agreements because of inflation pressures. (See NY Rejects Inflation Adjustment for Renewable Projects.)
New York on Nov. 30 will launch a new OSW solicitation open to all, including those with existing contracts, allowing developers to re-propose their projects at higher prices and offering an option to withdraw from previous agreements.
“A New York parade of positive developments has lifted the industry over the past month,” Oceantic Network CEO Liz Burdock said. BOEM’s approval of Empire maintains “the industry’s forward momentum while still ensuring environmentally responsible development.”
Empire “will stimulate the regional economy, revitalize ports and create many new job opportunities — including new manufacturing, installation, maintenance and operations jobs,” said JC Sandberg, chief advocacy officer at the American Clean Power Association.
Clean Ocean Action, an environmental organization based in Long Island, said it was concerned about the approval, writing on Facebook that the government was “fast-tracking” OSW projects.
“Too many questions remain unanswered about the impacts of offshore wind projects, such as Empire Wind 1 and 2, to move so quickly and recklessly forward with massive ocean industrialization,” the group said. “The ocean deserves more care, especially since it’s a prime buffer for climate change impacts.”
