With its 2035 greenhouse gas reduction goal in sight, the state of Oregon is looking for ways to reach that same target in 2030 instead.
The state is analyzing two pathways. One would rely on electrification to hit the goal of reducing GHG emissions 45% below 1990 levels by 2030.
The second pathway would maximize the use of alternative fuels — RNG and hydrogen in particular — with some electrification actions included. This so-called hybrid scenario was developed because relying on RNG and hydrogen alone would not be enough to reach the GHG reduction target, according to projections.
The alternatives were discussed last week during a meeting of the Oregon Global Warming Commission. The OGWC is working with the Oregon Department of Energy (ODOE) and consultants on a plan called the Transformational Integrated Greenhouse Gas Emissions Reduction, or TIGHGER. (See Oregon Effort Seeks to ‘Close the Gap’ on GHG Goals.)
The commission plans to complete a Roadmap to 2035 report by the end of the year, in time to submit to the state’s 2023 legislature. The report could recommend implementing the electric or hybrid alternative, or some combination of the two.
Accelerated Goal
TIGHGER initially set 2035 as the target date for reducing GHG emissions 45% relative to 1990 levels. The target is an interim step toward the state’s long-term GHG reduction goal of 80% by 2050.
But an analysis found that the state would hit the 2035 target through programs and regulations already adopted and under development.
“That was great to see,” said OGWC Chair Catherine Macdonald. “Because we found out that we are on track to meet our goal for 2035 by 2035, we are looking at an accelerated goal.”
Efforts that will contribute to meeting the target in 2035 include last year’s HB 2021, which aims to reduce GHG emissions from electricity generation 80% by 2030, 90% by 2035 and 100% by 2040. There’s also the Climate Protection Program from the Oregon Department of Environmental Quality, which sets a declining cap on GHG emissions from fossil fuels used in transportation, residential, commercial and industrial settings. (See Oregon Adopts GHG Cap-and-invest Program.)
With those two major programs being implemented, remaining steps to reduce GHG emissions will be relatively small in scope, said Alan Zelenka, assistant director for planning and innovation at ODOE.
Additional steps to reduce GHGs might include heat pump installation in new and existing buildings, all new electric vehicle sales by 2035, a shift of drivers to car-sharing and public transit, and a reduction in food waste.
“It’s a combination of all these little projects that make up the ability to … meet the goal,” Zelenka said.
Rating Cost Effectiveness
The scenario analysis included development of marginal abatement cost curves, which rank GHG-reduction actions by their cost effectiveness.
For both the electrification and hybrid scenarios, new commercial building codes, followed by a transition in medium- and heavy-duty vehicles, were found to be the most cost-effective measures. Residential and commercial building retrofits were the least cost-effective actions.
Zelenka said that under a least-cost planning approach, the most cost-effective measures would be implemented first. By the time the least cost-effective actions are implemented, their costs may have come down, he added.
But when developing a final ranking of GHG reduction actions, officials may consider co-benefits, such as job creation or healthcare cost reductions. OGWC will further discuss co-benefits next month.
IRA Impact
Some meeting participants said the Inflation Reduction Act that President Biden signed into law this month could improve the cost-effectiveness of certain GHG reduction actions. The new law will provide incentives for energy-efficient home retrofits and electric home appliances.
“That’s definitely very relevant to how we’re framing costs,” said commission member Nora Apter.
Zelenka said the impact of the IRA could be included in updates to the analysis.
During a public comment period, Karen Harrington with The Climate Reality Project’s Portland chapter said she was thrilled that OGWC was looking at an accelerated 2030 target. But Harrington questioned the commission’s consideration of the alternative fuels-focused hybrid scenario.
“To get us there, we have to look at all-electric,” Harrington said. “The hybrid system isn’t going to get us there.”
Commission member Tom Potiowsky responded by saying it’s “more robust” to keep the hybrid scenario in the analysis. And technology may change as time goes on, he said.
“As we go down the road, these things may become more … economically viable alternatives for us to use to reduce emissions,” Potiowsky said.
Serious cybersecurity vulnerabilities continue to plague U.S. critical infrastructure — including the power grid — despite their owners’ commitment to protecting their assets, according to a report released this week by the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA).
The report was prepared by the President’s National Security Telecommunications Advisory Committee (NSTAC), a body of leaders from the telecommunications, information technology, finance and aerospace industries that advises the federal government on maintaining secure and reliable communications. It is part of a broader federal response to the Colonial Pipeline hack and other cybersecurity incidents ordered last year by President Biden. (See Biden Directs Federal Cybersecurity Overhaul.)
Biden’s order directed NSTAC to study three key cybersecurity topics:
software assurance in the commercial information and communications technology supply chain;
zero trust and trusted identity management; and
the convergence of IT and operational technology systems.
Tuesday’s report, a working draft, focused on the third issue; a later, comprehensive report is planned that will cover all three areas.
Common Risks in OT Systems
In the document, NSTAC identified three common deficiencies that enable potential attackers to cross over from businesses’ IT networks — which are used for data-centric computing and communications — into their OT systems, which monitor and control events, processes, and devices in enterprise and industrial operations. Cybersecurity researchers have warned that cybercrime groups around the world are actively developing such crossover capability. (See Dragos Warns Malware Developers Building Skills Fast.)
The first security issue cited by the report’s authors is the lack of an effective “air gap”: an isolation of a business’s OT and IT assets that prevents any communication, either physically or wirelessly. Air gapping is essential to OT security because attackers can use any contact with an IT system to gain access to and control over the OT system. But the report said that even this basic level of security seems to be a major challenge for many businesses.
“While there are many OT engineers that may rely on the idea of an air gap to protect their environments, asset operators should recognize that in most environments, the air gap is a myth,” the NSTAC said, adding that many of its members “have 25 years-plus experience and have never seen a true ‘air-gapped’ OT system.”
What prevents an effective air gap, the report said, is usually the sheer convenience of connecting OT networks to the internet. Putting systems online rather than limiting access to those who are physically present allows a wider range of employees to monitor and step in if anything goes wrong.
However, it also means that an organization’s security staff lose some control and visibility into who has access to the OT systems. The NSTAC calls this phenomenon “accidental convergence,” and it comprises the second major theme of the report, defined as when “the system owner does not even realize or have visibility into which devices reside where on their networks.” This is especially the case in systems where OT assets have been connected to cloud services, which is increasingly common in the U.S.
While the authors acknowledged efforts are underway to mitigate the security risks of connecting to the open internet, they cautioned that even these advanced security controls cannot entirely remove the “fundamental availability risks of services delivered over the internet.”
The final vulnerability is the existence of “shadow IT,” in which OT systems are “added and modified without official IT change management control and approval.” While the report noted that OT systems usually are designed to “limit the ability to effect changes to assets in the environment,” as with air gapping, such precautions often lapse without highly disciplined change management processes. This can create problems when, for instance, employees use workarounds during urgent troubleshooting that are never removed from the environment afterward, or engineers use off-the-shelf components with unauthorized connectivity capabilities instead of following proper procurement protocol.
NSTAC provided several recommendations for the president and other government agencies, including CISA, to help “further reduce risk and secure the nation’s critical infrastructure.” While these mainly concern government OT networks, they also include measures on communication and information sharing. The report’s authors called on CISA, the National Security Council and the Office of the National Cybersecurity Director to develop “interoperable, technology-neutral, vendor-agnostic information-sharing mechanisms” to allow the sharing of real-time data “between authorized stakeholders involved with securing U.S. critical infrastructure.”
“NSTAC also recognizes that the federal government alone cannot uniquely resolve all the challenges surrounding OT cybersecurity, and readers from all stakeholder groups will benefit from the additional findings, best practices and general guidance contained in the appendices,” the report said.
Maine and Rhode Island will join New York, Connecticut, Massachusetts and New Jersey to create a consortium that will apply for federal funding this fall to develop a regional hydrogen hub, New York Gov. Kathy Hochul announced Thursday.
The coalition — which includes 14 private sector industry leaders, 12 utilities, 20 hydrogen technology original equipment manufacturers (OEMs), 10 universities and two transportation companies — will compete for $2 billion matching grants from the U.S. Department of Energy early next year.
It has agreed to work with the New York State Energy Research and Development Authority, the New York Power Authority and Empire State Development on a proposal to advance clean hydrogen projects in the Northeast, according to Hochul’s office. The proposal will center climate and environmental justice while also looking to boost the economies and quality of life in each state involved, it said.
New York Gov. Kathy Hochul | Darren McGee, Office of Governor
“Building a robust and connected clean hydrogen market across the Northeast will provide a game-changing clean energy alternative that will transform our ability to meet our shared climate goals while advancing 21st century innovation and stimulating strong economic growth throughout the region,” Hochul said in a statement.
The hydrogen hub grants were authorized in the $1.2 trillion Infrastructure Investment and Jobs Act signed into law in November 2021, providing $8 billion for four regional hydrogen hubs, $1 billion for research to bring down the cost of hydrogen electrolysis and $500 million to support equipment manufacturing.
DOE said it will issue a request for proposals in September or October, with final applications due in the first quarter of 2023. The department issued an initial request for information earlier this year.
The Battelle Institute, which administers nine National Laboratories, said earlier this summer that multistate applications would have a better chance of winning funding. The independent research lab is working with Ohio, Pennsylvania and West Virginia in an effort to plan a regional hub creating and using hydrogen made from natural gas, which is plentiful in the region.
There are also efforts to create hydrogen hub groups in Oregon and Washington state, and a Gulf Coast hub from Louisiana to Texas, centered in Houston. Four Western states — New Mexico, Colorado, Utah and Wyoming — announced intentions in February to create a hub. And New Mexico is considering switching a power plant to hydrogen. Southern California Gas unveiled a plan in February to build a pipeline to transport hydrogen from Mojave Desert to customers in the Los Angeles Basin.
“I am proud to have Rhode Island join the New York-led Regional Clean Hydrogen Hub as we explore the amazing potential that hydrogen offers, not only as an additional clean energy resource, with broad applications across our transportation and industrial sectors, but also by adding new jobs to our economy,” Gov. Dan McKee said in a statement.
Dan Burgess, director of the Maine Governor’s Energy Office, said clean hydrogen is “an exciting technology with potential for economic growth that can reduce greenhouse gas emissions from fossil fuels.”
The Northeast Clean Energy Council, a major policy player in the region, is another of the coalition’s new partners. So are Rensselaer Polytechnic Institute, Siena College and the University of Connecticut. And energy companies including EDP Renewables North America, Equinor and Edgewise Energy have joined as well.
An Oregon renewables company wants to construct two hydrogen manufacturing plants and a network of hydrogen pipelines in eastern Oregon and Washington later this decade.
Obsidian Renewables of Lake Oswego, Ore., plans to build hydrogen production plants at existing industrial parks in Hermiston, Ore., and Moses Lake, Wash. The plants would use electrolyzers to separate hydrogen from water and wastewater.
These would supply a proposed pipeline system that would terminate at points in The Dalles, Pendleton and Prineville in Oregon, and in Wenatchee and Spokane in Washington. Another pipeline would extend to Lewiston, Idaho. One connecting pipeline would go through the Tri-Cities, which is the second-most populated area in eastern Washington behind Spokane.
The network would be powered by electricity from new wind and solar farms, with each type of renewable resource expected to supply 800 MW.
The company believes the project will cost roughly $3 billion, Obsidian President David Brown said in an interview.
Obsidian is still putting together the pieces of the project, with Brown declining to name potential partners. He said different partners will likely tackle different aspects of the project. For example, one might build the plants, while another constructs the pipeline. Other partners would build the wind and solar farms.
Obsidian hopes to tap into the $8 billion fund that the U.S. Department of Energy has set aside to create four to eight regional hydrogen hubs across the nation. Each hub would get $1 billion to $2 billion. Washington is aggressively pursuing that money to create a Northwest hydrogen hub, including passage of legislation this year to help organize the effort. (See Wash. Looks to Boost Prospects for Winning Hydrogen Hub.)
In Washington, one hydrogen manufacturing plant owned by the Douglas County Public Utility District is scheduled to go online in East Wenatchee in mid-2023. The Port of Seattle is studying whether it wants to get into hydrogen manufacturing and distribution. Refueling stations for hydrogen-powered vehicles are in the works for East Wenatchee and the transit authority in Chehalis and Centralia
DOE expects to receive roughly 100 proposals by September, after which it will begin winnowing through them. No timetable is set for DOE’s decisions on how to allocate the $8 billion.
Brown said the earliest that the hydrogen plants might be built is 2025 but added that completion could be later this decade. The pipelines could likely take three years to build after Obsidian obtains all the needed permits, he said.
Potential customers would be fertilizer plants, hydrogen-powered vehicles and other agricultural uses. Also, Eastern Washington is home to several data farms, which could use hydrogen as fuel for their backup generators.
Brown did not rule out trying to connect with any potential western Oregon and Washington hydrogen customers that might want to build pipelines across the Cascade Mountains.
An article in the Aug. 23 RTO Insider newsletter incorrectly reported that ERCOT’s Board of Directors had approved a protocol change that reduced counterparties’ limit for unsecured credit to $30 million from $50 million. However, the measure actually eliminated unsecured credit entirely. (See “Board Agrees to Lower Unsecured Credit Limit for Counterparties,” ERCOT Board of Directors Briefs: Aug. 16, 2022.)
The motion’s language incorporated the Technical Advisory Committee’s approval of a reduction to $30 million in April, as suggested by its Protocol Revision Subcommittee. However, it then added “as amended by” ERCOT comments from March.
In the comments, staff disagreed with the reinstatement of unsecured credit limits to the nodal protocol revision request (NPRR1112), saying the credit limit “translates directly to a cost that must be borne by other market participants” should there be a default.
“The provision of unsecured credit therefore means that the credit risk from the market activities of some market participants is subsidized by others,” staff said. “Elimination of unsecured credit will reduce the inconsistent cross-subsidization of credit exposure and provide a more level playing field for market participants.”
Staff and stakeholders had also debated the measure during TAC’s April meeting, when the committee voted in favor of the reduction to $30 million. (See “TAC Passes Contentious Outage Measure over Staff’s Objections,” ERCOT Technical Advisory Committee Briefs: April 13, 2022.)
“That was an incredibly confusing motion and could have been more clearly conveyed,” TAC Chair Clif Lange told RTO Insider.
ERCOT General Counsel Chad Seely referred to the motion’s language as “odd” before he offered it to the board for its unanimous approval.
Lange said he was told by the grid operator’s staff that the motion was crafted in the manner it was presented to capture the record developed in TAC’s report on the NPRR.
NERC and the regional entities signaled their support last week for FERC’s proposal to change transmission planning and cost allocation processes, calling such a move “essential for a reliable transition to a modern” bulk power system (RM21-17).
The ERO shared its views in comments on the Notice of Proposed Rulemaking FERC issued in April that would require transmission providers to identify infrastructure needs on a long-term, forward-looking basis through revisions to their planning processes, and to list the benefits they would use to select proposed projects. (See FERC Issues 1st Proposal out of Transmission Proceeding.) The commission said the rules would help planners cope with the growth of renewables, along with extreme weather events and new sources of demand such as electric vehicles.
In their response, NERC and the REs focused on the “immense transition” being experienced by the North American electric grid “as the generation resource mix and underlying transmission system evolve,” while changing weather patterns add stress for which the grid was never designed.
In particular, the ERO cited the ongoing adoption of wind and solar generators that deliver power to the grid through inverters, a major departure from traditional resources, which NERC said requires a new approach to transmission planning. Instead of using the models and studies devised for older technologies to connect this new generation fleet to the transmission system, NERC said FERC should encourage “long-term, forward-looking transmission planning to ensure” reliable connection to the BPS.
“Transmission will be the key to support the resource transformation enabling delivery of energy from areas that have surplus energy to areas which are deficient,” the ERO said in its filing. “The frequency of such occurrences [is] increasing as extreme weather conditions resulting from climate change impact the fuel sources for variable energy resources. Regional transmission planning can ensure that sufficient amounts of transmission capacity [are available] to address these more frequent extreme weather conditions.”
Noting that NERC’s reliability standards “apply together with commission transmission planning and interconnection requirements,” the ERO expressed appreciation for FERC’s understanding of its role in the bulk electric system. It urged the commission to continue including it in future discussions of the grid transformation, arguing that the ERO “is particularly equipped to assess the North American transmission system” because of its history of working with policy makers, regulators, utilities and other stakeholders across the electric industry.
WECC said the issue is “a particular area of concern” for the Western Interconnection because of the “interregional consequences” of its operation and the lack of any other “interconnection-wide organization” besides WECC that can help coordinate the development of the transmission system. The RE said it could play a leading role in mustering the efforts of various interests to build a more reliable grid for the entire interconnection.
NERC and the REs were careful to limit their comments to matters related to BPS reliability, declining to mention issues of cost allocation or other topics raised by the NOPR. Other commenters have been more ambivalent about FERC’s proposal; more than 180 respondents had replied by the deadline last week, with many expressing general support for the overall goal but hesitation about the specifics. (See Battle Lines Drawn on FERC Tx Planning NOPR.)
Hydrogen has been the fuel of the future for about 100 years. Now its moment may have arrived.
Initially investigated as an auto fuel, and later becoming a crucial rocket fuel in the NASA manned space program, hydrogen is seen today as the most promising replacement for fossil fuels in transportation, industrial processes and power generation.
The Biden administration’s June 2021 announcement of a hydrogen “Earthshot” by U.S. Energy Secretary Jennifer Granholm aimed at reducing the price of hydrogen to $1/ kg within this decade was the start of a frenetic drive both by government and industry to move away from carbon emissions.
The bipartisan Infrastructure Investment and Jobs Act passed in November 2021 allocated more than $9 billion for hydrogen development programs, including $8 billion in matching grants for the creation of multi-state “hydrogen hubs” by industry and government in which hydrogen would be used in the region in which it is produced.
The Inflation Reduction Act signed by the president onAug. 16 created a 10-year production tax credit (PTC)as high as $3/kg for hydrogenelectrolysis operations built by companies paying prevailing wages and offering apprentice training.The law also allows operations to choose an investment tax credit rather than a PTC.
The bill is expected to accelerate the already growing interest in hydrogen research, development and use.
Hydrogen webinars, reports and conferences are now weekly events in the U.S. and in Europe, which is facing a critical shortage of natural gas. In Germany, where there is a commitment to move to 100%hydrogen, a natural gas storage company hasbeen testing the efficacy ofunderground salt caverns and salt domes for hydrogen storage, with results that U.S. counterparts will find useful.
RAG Austria AG, one of Europe’s largest gas storage companies with connections to major European gas pipelines, has preliminarily determined that hydrogen injected into former gas reservoirs stays put, doesn’t react with steel equipment any differently than natural gas and can be pumped back out upon demand.
The company successfully injected a 115,000-cubic-meter mixture of hydrogen and natural gas into storage and later retrieved it without incident, said Markus Pichler, a reservoir engineer, during a webinar produced earlier this month by Mission Hydrogen, an independent German proponent of hydrogen that has been hosting weekly webinars for a global audience.
Pichler said the company began hydrogen storage research in 2012, initially in laboratories. He said the mixture of hydrogen and gas injected into storage did not affect the steel piping and other equipment used in the gas reservoir, did not seep out of the reservoir and behaved much like methane. But he added that hydrogen storage is still in the R&D stage, with ongoing testing to confirm laboratory results in actual reservoirs.
The company, which maintains 66 TWh of gas storage, also discovered something else in its hydrogen tests, Pichler said; carbon dioxide injected into a reservoir containing hydrogen is converted to biomethane by microbes that exist naturally in the salt caverns.
To potential critics wondering why anyone would generate hydrogen and then convert it to methane, losing energy in the process, Pichler said: “If you think about it, all of our gas infrastructure is actually built for methane, for natural gas. If you then feed this [pipeline system] with biomethane, you basically need to change nothing.”
Pichler’s suggestion bypasses the question of pure hydrogen damaging gas pipelines, an issue confirmed in late July in a study commissioned by the California Public Utilities Commission. The study found that hydrogen blends above 5% could embrittle steel pipelines and raise the risk of leaks. (See Study Finds Adding More Hydrogen to Natural Gas Raises Risks.)
Collaborating Toward a Net-zero Carbon Future with Hydrogen
The question of whether existing utility pipelines can be used to ship hydrogen has not prevented gas turbine manufacturers from developing equipment capable of using hydrogen rather than only natural gas
Mitsubishi Power CEO Bill Newsom | Reuters
“A majority of the utilities in the United States have set a net-zero goal by 2050 or sooner, and [now] they have to assess how to get there. Our mission is to provide power generation and energy storage solutions for our customers which empowers them to affordably and reliably combat climate change,” said Bill Newsom, CEO of Mitsubishi Power Americas, in a webinar interview hosted earlier this month by Reuters. “We are investing hundreds of millions of dollars and partnering with our customers to enable them to be the heroes in this decarbonization journey.”
He said the company has been researching and developing electrolysis technologies for green hydrogen production, developing hydrogen storage and delivery standards, and modifying combined cycle turbines to burn hydrogen and hydrogen-gas mixtures.
Some designs have achieved a generation efficiency of at least 64%, according to the company. The long-term goal is to engineer a turbine capable of running on 100% hydrogen, Newsom said, a feat that company engineers have achieved with small gas turbines.
The R&D is not all in laboratories. Mitsubishi is building and already testing hydrogen-gas mixtures at a large power plant in the Netherlands. Its turbines will be used at power plants at several U.S. sites, including new plants in Utah, New York, Ohio, Virginia and Texas, according to Gas Turbine World.
Newsom said the company is looking at projects “across the U.S. that are utilizing salt domes [for storage]. As for converting pipelines to run hydrogen, that will take some time,” he said.
“We built the natural gas infrastructure here over the last 100 years,” he said. “We’re not going to in the next three decades be able to rebuild that entire infrastructure. What we want to do is look at how can we inject hydrogen into these existing pipelines. And which of these lines can be upgraded, maybe sleeved or coated, so that we can inject more than say, 20% hydrogen?”
Stressing that federal programs are crucial to accelerated development, Newsom said the passage of the Inflation Reduction Act means “there will be more real projects and more incentives, and this momentum will continue to bring real projects to fruition.”
He noted as an example that the Department of Energy in June awarded a $504.4 million loan guarantee to Mitsubishi Americas and partner Magnum Development for the creation of Advanced Clean Energy Storage in Utah, now considered the first hydrogen hub in the U.S. Creation of the hub took the cooperation of Colorado, Wyoming, Utah and New Mexico.
The hub will produce and store green hydrogen made with renewable power as fuel for two Mitsubishi gas turbines. The power will replace the output of two coal plants operated by the Intermountain Power Agency in Utah, which mostly serve utilities in Utah and California.
The Mitsubishi gas turbines will initially burn 30% green hydrogen and 70% natural gas when they begin operating in 2025. The goal is 100% hydrogen by 2045. The green hydrogen — produced by wind turbines, often at night when there is less power demand — will be stored in nearby salt domes.
Each of the two salt caverns, now being drilled, will hold 250 GWh of hydrogen, Newsom said. The gas plant will replace two old coal-fired power plants, Newsom said, adding that Mitsubishi has also announced partnerships with Entergy, Puget Sound and El Paso Electric.
“They have set their target to net zero. We are partnering with them to provide them with solutions to get there. Collaboration is absolutely critical,” he said, adding that Mitsubishi is also considering “sector partnering” with companies in steel manufacturing, transportation and agriculture.
State Efforts to Advance a Clean Hydrogen Economy
Efforts to move toward a hydrogen-based energy future vary by state. In addition to the multi-state partnered Utah project, organized efforts in Oregon and New York are preparing those states for a hydrogen future.
In a webinar organized by the National Association of State Energy Officials earlier this month, Rebecca Smith, a senior energy policy analyst at the Oregon Department of Energy, and Ian Latimer, program project manager with the New York State Energy Research and Development Authority (NYSERDA) outlined what their states are planning for a decarbonized future.
In any state, the process ought to start with the legislature, Smith said, which is what Oregon lawmakers did last year with the passage of legislation requiring a broad state study, which the agency expects to release in September.
Oregon’s statutes do not define renewable hydrogen, but the legislation requiring the study did: “renewable gas from energy sources that do not emit greenhouse gases.”
One of the goals of the study, she said, has been to figure out how a policy on renewable hydrogen would fit with existing policies on renewable and clean energy. The mandate has also been to inventory current hydrogen volume and use in the state and to propose how the production and use of green hydrogen might be integrated into the state’s power generation. The state has relied on national federal laboratories and academia rather than utilities or gas producers at this point in order to produce a neutral study.
Another goal in preparing the study has been to include groups that are not often included in energy studies, especially those focused on environmental justice or community issues, and the study has tried to include local governments. Smith said her department “went out of our way to especially ensure that those who might be skeptical of renewable hydrogen we’re invited to participate” in order to reflect their opinions and attitudes in the report.
“We’re really seeking to partner … with all stakeholders, not only those who are already excited about renewable hydrogen. With respect to the [hydrogen] hubs [DOE competitively grants], everyone expects us to be very competitive,” she said.
“I am limited in what I can say about what’s going on in Oregon. But what I can say is that Oregon is collaborating with Washington state on a Pacific Northwest hub concept,” Smith said. “We have teamed up with our state’s business development agency, Business Oregon, to convene interested Oregon stakeholders.”
Once the study is filed in September, the state DOE plans to hold a number of public workshops to continue to engage business, labor and the public about the future of hydrogen in the state, she said.
Latimer presented what looked like a fully developed environmental plan that will include hydrogen.
“We are looking to get an 85% reduction in emissions below 1990 levels, 40% emissions reductions by 2030, 100% zero-emission electricity sector by 2040, including an interim target of 70% renewables by 2030,” he said.
“And then a number of technology specific targets throughout the next 10 to 15 years, and that’s targets for everything from offshore wind, to distributed solar, to battery energy storage development, as well as different targets for building electrification and energy efficiency,” he said.
“All of these targets are courtesy of the Climate Leadership and Community Protection Act of 2019 [CLCPA],” he added.
The state has described CLCPA as “one of the most ambitious climate laws in the world,” and Latimer made that clear as he described development of a planning and enforcement bureaucracy in recent years.
“The question then becomes, well, goals are great. How do you get there?” he said.
“The climate act enabled a Climate Action Council [CAC] to negotiate and chart a path forward for New York to reach its ambitious climate and energy targets, including the adoption of a scoping plan, which will make the recommendations for achieving the greenhouse gas emissions reduction … set forth in the climate act,” he explained.
The CAC is co-chaired by NYSERDA CEO Doreen Harris and Basil Seggos, chair of the New York Department of Environmental Conservation.
The council “includes a number of state agencies, a number of Governor appointees and then assembly and senate appointees as well,” Latimer said. It is the organization now charting the future of energy, including the use of hydrogen in the state, he said.
“Ultimately, any path that we take towards hydrogen in New York state will be in conjunction with the scenario and with the scoping plan that is put in place by the Climate Action Council. The integration of hydrogen into the plan will be based on a complicated analysis and at this point includes a number of scenarios,” he said.
“It recognizes a number of critical roles that hydrogen can play in decarbonizing hard-to-electrify applications. In the near-term that might mean … medium- and heavy-duty vehicle decarbonization.
“It may mean decarbonizing high-temperature industrial applications where electrification is not a viable or cost-effective alternative in the longer term. The integration analysis sees a role for low-carbon fuels such as hydrogen and decarbonizing,” Latimer said.
But in the long run, he said, the plan sees “an accelerated transition away from combustion, which means you are not looking at the combustion of hydrogen for power generation or heat. You’re focused on accelerating electrification for buildings and transportation, and so there’s … a decreased role for hydrogen in that scenario.”
The plan includes a role for hydrogen consumed by fuel cells powering “microgrids as a potential resilience solution for disadvantaged communities, looking to displace fossil fuel backup deployment,” he added.
The state is also analyzing the economic development created by the use of hydrogen, Latimer said.
MISO and SPP on Monday laid out a percentage-based cost allocation for their $1-billion Joint Targeted Interconnection Queue (JTIQ) transmission study that will assign most costs to interconnecting generation.
The grid operators plan to assign 90% of project costs to interconnection customers and 10% to an aggregate of MISO and SPP load. The RTOs said they will allocate a fixed, per-megawatt charge to interconnection customers that have a 5% or greater impact on a facility in the neighboring region to pay for the portfolio.
“We think a 90-10 split would work well for this portfolio and for future portfolios,” MISO’s Andy Witmeier told stakeholders during a JTIQ study teleconference Monday.
National Grid Renewable’s Rafik Halim said he thought a 50-50 allocation between load and new generation would be more suitable. He asked for a rationale behind the cost split.
“If MISO and SPP believe a 90%-10% split is appropriate, we need to see why. This is a billion dollars of investment,” he said.
Halim also asked for an analysis to show how the grid operators arrived at the 5% impact threshold for new generators.
American Clean Power Association’s Daniel Hall seconded the ask for the 90-10 cost allocation’s justification.
The RTOs staff remained steadfast in asserting that the JTIQ’s main purpose is to enable new generation, making it only fair that interconnection customers bear the brunt of the costs. They also said the 5% impact factor is a well-established approach that both grid operators use today.
Other stakeholders asked whether the RTOs plan to create protections that ensure transmission facilities get built should generation developers balk at network upgrade costs and withdraw from the queue. How would the portfolio remain funded, they asked.
SPP’s Neil Robertson said staff’s plan is to assign a fixed, one-time upfront charge to eliminate unexpected sticker shock and cut down on the number of queue dropouts. He said the process will ensure the upgrades’ expense is spread evenly across generation and that no project is encumbered with an eye-popping upgrade bill.
David Kelley, SPP’s director of seams and market design, said the RTOs are confident that enough generation developers will continue to construct projects near the seams and fund JTIQ projects.
The study’s portfolio was initially priced at $1.65 billion. However, it contained two project duplicates with MISO’s recently approved $10.3-billion long-range transmission portfolio. Staff said SPP’s benefits from the projects were negligible and independently pursued the duplicates under its regional process, reducing the JTIQ to about a billion-dollar investment. (See MISO, SPP Finalize JTIQ Results with MISO Tx Duplicates.)
The current JTIQ portfolio includes:
the $476-million Bison-Hankinson-Big Stone South 345-kV line located in MISO’s footprint that touches both Dakotas and Minnesota;
the $331-million Brookings County-Lakefield 345-kV line from South Dakota into Minnesota in MISO territory;
the $144.4-million Raun-S3452 345-kV line on the Iowa-Nebraska border, straddling both MISO and SPP;
the $90.5-million Auburn-Hoyt 345-kV line from Nebraska into Kansas in SPP’s region; and
the nearly $19 million Sibley 345-kV bus reconfiguration in SPP’s portion of northwest Missouri.
The RTOs announced in late June that they plan to ditch their current affected systems study process for more interregional transmission studies like the JTIQ study. (See MISO, SPP Commit to Replacing Affected System Studies.)
Robertson said the portfolio began as a “one-off” process and has since evolved into an “enduring, repeatable” design.
The grid operators plan to hold another meeting Sept. 30 to finalize cost-allocation details. Kelley asked stakeholders to send their improvement suggestions for the concept to the RTOs.
The D.C. Circuit Court of Appeals issued rulings Tuesday on a variety of petitions relating to the Mystic Generating Station, granting review to a group of state regulators and rejecting several requests from the plant’s owner (20-1343).
First, Mystic argued that FERC mistakenly applied the “original cost test” to calculate the rate base for Units 8 and 9, which were kept operating by the agreement.
The original cost test says that a utility “may only earn a return on (and recovery of) the lesser of the net original cost of the plant or, when plant assets change hands in arms-length transactions, the purchase price of the plant.”
Mystic’s parent company valued Units 8 and 9 as part of a merger in 2012 around $925 million and claimed that “sale” price should determine its rate base.
The commission rejected that approach as inconsistent with the original cost test because of the units’ full purchase history.
The D.C. Circuit sided with FERC on that question and did not grant review, saying the decision “accorded with [the commission’s] precedent and was supported by reasoned explanation.”
The court also dismissed Mystic’s challenge to the capital structure adopted by the commission for ratemaking purposes, because a subsequent order made the challenge moot.
Another order examined in the court’s ruling was related to the cost recovery for Everett, an LNG terminal attached to the plant. Both Mystic and state regulators challenged FERC’s approach.
The regulators argued that the commission lacked jurisdiction to regulate the rates charged by Everett and that FERC’s decision to allocate 91% of Everett’s operating costs to Mystic — and therefore ultimately to ratepayers — was arbitrary and capricious.
The court agreed with those arguments but not with Mystic, which argued that “the commission erred in excluding Everett’s purchase price from Everett’s rate base.”
Next, both Mystic and the states challenged the “true up” mechanism approved by FERC, designed to allow parties to “reconcile cost projections with actual expenditures via surcharges and refunds as necessary.” Mystic argued that “the true-up mechanism will lead to relitigation of its historic costs.”
The court said that was unfounded. It accepted, however, the states’ arguments that FERC failed to address a request for clarification about how it calculated revenue credits and Everett’s tank congestion charges. Those issues were remanded by the court for clarification.
Finally, the states took issue with parts of a “clawback” provision that would require Mystic to reimburse ratepayers for some expenses if it re-enters the New England energy markets after the agreement is over.
The states argued that Everett’s costs shouldn’t have been excluded from the clawback rules, and the court agreed. It also granted review of the states’ claim that FERC “failed to address their argument that the Mystic agreement will induce Mystic to delay capital projects into the term of the agreement.”
Entergy has responded to criticism filed at FERC that the utility is purposefully undermining transmission planning in MISO South.
In a statement to RTO Insider, Entergy countered Southern Renewable Energy Association’s (SREA) claim that the company is deferring and hindering the region’s transmission planning by saying it “strongly supports” investment in transmission, but that it must pay attention to costs.
The company said that since joining MISO in late 2013, it has invested $6 billion in new transmission infrastructure, resulting in nearly 600 miles of new lines. Entergy said that level of investment is above the industry average.
“Entergy strongly believes that new transmission will play an important role in MISO South as we integrate additional solar resources and evolve our generation portfolio to be more sustainable,” it said. “We recognize that creating a carbon-free future calls for more investments in renewable energy.”
Commenting in FERC’s Notice of Proposed Rulemaking on transmission planning, SREA accused Entergy of habitually proposing new generation plants just in time to thwart MISO transmission recommendations, thus harming reliability in MISO South. (See SREA Criticizes Lack of MISO South Planning in FERC Tx Proceeding.)
Entergy said it’s working with its regulators and stakeholders to “responsibly expand access to renewable energy … under a framework that balances reliability, affordability and environmental stewardship.”
The company said MISO’s planning decisions have “major cost implications to our customers, nearly 30% of whom live in poverty and already struggle to pay their monthly bills.” It said the $30 billion to $100 billion of transmission investment that MISO expects with its long-range transmission plan’s (LRTP) four portfolios will invariably raise costs for its ratepayers.
The grid operator approved its first LRTP portfolio in late July. The $10.3 billion transmission investment in 18 projects is aimed at MISO Midwest only. It will be several years before their planners seek projects in MISO South. (See MISO Board Approves $10B in Long-range Tx Projects.)
“Even at the low end of that range, Entergy’s customers would be responsible for hundreds of millions of dollars per year in transmission costs. When we express our views, along with numerous other utilities and stakeholders, we do so based on what we believe is in our customers’ best interests — just as every other stakeholder does in MISO’s process,” Entergy said.
The utility pointed out that MISO ultimately decides which transmission projects to place before MISO’s Board of Directors for its approval.
Entergy also addressed the more potent storms that have formed in the Gulf of Mexico in recent years and their impact on its existing transmission infrastructure.
“Ultimately, Entergy and other utilities have to answer to our customers and our state regulators for the reliability and cost of the essential service we provide,” it said. “In a world where climate change is happening and we are experiencing more severe weather events and other challenges, there are important policy decisions to be made about what investment is needed to better prepare electric systems and other infrastructure to withstand those events.”
Entergy said it welcomes “a reasoned and fact-based discussion with our regulators and stakeholders about what that investment should look like and how to fund it, without imposing burdensome additional costs on our customers.”
