As we previously covered in our blog last week, both the Federal and certain State governments are proposing legislation to subsidize or otherwise enhance the use of hydrogen as an alternative fuel to reduce greenhouse gas emissions from selected “hard to abate” industrial sectors such as heavy industry, transportation and marine shipping.  Last week’s blog focused on federal legislation. This week, we focus on California legislation.

In an effort to lead on the transition to low carbon energy by supporting the use of hydrogen, the California Legislature is considering two bills that require commissions to establish assessment goals for hydrogen use in certain applications and prioritize the use of clean hydrogen statewide.

First, SB-414 would require the State Air Resources Board, in consultation with the State Energy Resources Conservation and Development Commission (Energy Commission) and the Public Utilities Commission, to complete an assessment of the use of hydrogen in certain applications, including light-, medium-, and heavy-duty vehicles, including long-distance trucks and trains, household and commercial appliances, and electricity generation. The assessment must evaluate the potential for reductions in emissions of greenhouse gases using hydrogen, the cost associated with replacing fossil fuels with hydrogen, the energy efficiency of using hydrogen, and the climate risk associated with the transportation, storage, and use of hydrogen for the application. The bill would then require these findings be used when considering the “planning, implementation, or regulation of hydrogen production, distribution, storage, or usage in the state.” After passing the Senate Floor on May 24, 2023, and the Assembly Committee on Natural Resources on June 19, 2023, the bill was re-referred to the Committee on Appropriations on June 20, 2023.

Second, though not a bill per se, Senate Concurrent Resolution (SCR) 21 acknowledges the importance of hydrogen in the clean energy transition and urges the Alliance for Renewable Clean Hydrogen Energy Systems (aka ARCHES, a public-private partnership organization) to prioritize the use of renewable, clean hydrogen for California in its effort to create “Hydrogen Hubs.” These hubs are a part of President Biden’s Infrastructure Investment and Jobs Act (IIJA) in which Congress has allocated $8 billion toward establishing a network of hydrogen hubs. ARCHES is leading California’s regional application of the project. Existing California law already defines the different types of hydrogen, including green electrolytic, clean hydrogen, and renewable hydrogen. The definitions of these terms can be found in the Senate Floor Analysis of the resolution from March 22, 2023. This resolution specifically is intended to further support the use of hydrogen derived from eligible renewable energy resources, including wind, solar thermal, and biomass. The resolution passed the Senate Floor on April 27, 2023, and was adopted and ordered to the Assembly Consent Calendar by the Assembly Committee on Transportation on July 5, 2023.

The above legislation reflects California’s continued attempts to reduce greenhouse gas emissions through the use and assessment of hydrogen. Other states are watching closely and are considering similar measures as well. We will continue to closely monitor the status of hydrogen bills throughout the legislative process at both the federal and state level.

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Federico Beccari, Unsplash

As economies pivot away from reliance on petroleum, the use of hydrogen is increasingly considered as a key component in a portfolio of alternative fuels and developing technologies to reduce greenhouse gas emissions. This is the first of a multi-part blog series on federal and state legislation being considered to stimulate “energy transition.”  This blog post addresses selected U.S. federal legislation.

To help stimulate critical end-use demand in particularly “hard to abate” industrial sectors (e.g., heavy industry, transport and marine shipping), Senators Chris Coons (D) and John Cornyn (R), along with a group of bipartisan cosponsors have introduced the Hydrogen Infrastructure Initiative. This package combines four pieces of legislation that will have potentially industry-wide implications by supporting both the adoption of hydrogen and the creation of infrastructure needed to transport, store, and deliver hydrogen.

The first bill in the package is S-646, known as the Hydrogen for Industry Act of 2023. This bill would amend the Energy Policy Act to establish a Hydrogen Technologies for Heavy Industry Demonstration Program. This program would support “commercial-scale” demonstration projects for industrial applications of hydrogen, including in the production of steel, cement, glass, and chemicals. Such processes have specific technical requirements that limit the options for substituting heat sources. The use of hydrogen would ensure that the necessary temperatures would still be supplied to the industrial sector, but with reduced emission rates. Hydrogen could also serve as a feedstock for the production of ammonia, methanol, or other bulk chemicals. $1.2 billion was authorized to be appropriated to the Secretary to carry out the program for each fiscal year from 2024 through 2028. On March 2, 2023, the bill was referred to the Senate Energy and Natural Resources Committee.

The second bill in the package is S-647, known as the Hydrogen for Ports Act of 2023. Sponsors highlight that, “ports are well-suited to be early adopters of hydrogen fuel, with multi-modal transportation applications converging on a single location that can share hydrogen infrastructure at scale.” The bill would require the Secretary of Transportation to establish a grant program to support the use of hydrogen- or ammonia-fueled equipment at U.S. ports and in other shipping applications. The bill would also require that a study be conducted regarding the “feasibility and safety of using hydrogen and ammonia as fuels in maritime applications.” $100 million was authorized to be appropriated to the Secretary to carry out the program for each fiscal year from 2024 through 2028. On March 2, 2023, the bill was referred to the Senate Committee on Commerce, Science and Transportation.

Third, S-648, aka the Hydrogen for Trucks Act of 2023, would require the Secretary of Transportation, in consultation with the Secretary of Energy, to establish a grant program to “demonstrate the performance and reliability of heavy-duty fuel cell vehicles that use hydrogen as a fuel source.” This program would incentivize private investment support the overall development of hydrogen trucking infrastructure while collecting critical data to inform future investments in hydrogen trucking infrastructure. $200 million was authorized to be appropriated to the Secretary to carry out the program for each fiscal year from 2024 through 2028. On March 2, 2023, the bill was referred to the Senate Committee on Commerce, Science and Transportation.

Finally, S-649, aka the Hydrogen Infrastructure Finance and Innovation Act (HIFIA), would require the Secretary of Energy to create a grant program that provides loans for hydrogen infrastructure projects. The bill would also require a study be conducted to address questions related to transporting and storing hydrogen. $100 million was authorized to be appropriated to the Secretary to carry out the HIFIA pilot program for each fiscal year from 2024 through 2028. On March 2, 2023, the bill was referred to the Senate Energy and Natural Resources Committee.

Collectively, this package represents an important step in the adoption of hydrogen infrastructure across various important industries. We will continue to closely monitor the status of these bills throughout the legislative processand the topic of hydrogen across the United States.

Next week, look for an analogous blog we are drafting regarding hydrogen legislation in California.

The Washington State Department of Labor and Industries (L&I) issued a proposed rule updating process safety management (PSM) standards for petroleum refineries. Washington’s current PSM rule is identical to the federal standard issued by OSHA in 1992 – over 30 years ago. More recently, in late 2017, California revised their regulations on PSM for petroleum refineries, increasing requirements for refiners beyond those of general industry and federal OSHA regulations. L&I aimed for consistency with California’s regulations when drafting the proposal due to the large percentage of refiners who operate in both states; 80% of Washington’s refiners also operate in California. L&I indicated they believe having similar regulations to California will improve safety outcomes for employees and contractors who work at petroleum refineries in both states.

The New Requirements

Given that the proposed regulation is largely aligned with California’s PSM, the following Washington PSM requirements (while new to the state of Washington) are similar to the deviations from the federal requirements that were introduced in California in 2017:

  • Process Hazard Analyses (PHA): L&I’s proposed regulation increases the scope of PHAs by adding requirements to (1) perform a safeguard protection analysis, (2) address damage mechanism reviews during the PHA, and (3) require a Hierarchy of Hazard Controls Analysis (HCA) for PHA recommendations. All initial PHAs for processes not previously covered by federal PSM regulations must be completed within three years of the rule’s effective date.
  • Management of Organizational Changes (MOOCs): A team must be designated by the employer to perform MOOC assessments.  Written MOOCs with findings and recommendations are needed for changes with a duration longer than 90 days which will affect operations, engineering, maintenance, health and safety, or emergency response, including staffing levels, shift duration, or employee responsibilities.
  • Human Factors: Within 18 months of the effective date of the final rule, refiners must develop and maintain a written human factors program. Employers must include a human factors analysis as part of major changes examinations (i.e., Management of Change (MOC)), incident investigations, PHAs, MOOCs, and HCAs. Examples of human factors to be considered include staffing levels and turnover, training, fatigue, and task complexity.
  • Root Cause Analyses (RCA): Employers must conduct RCAs after significant accidents. Further, refiners must establish effective methods for conducting an RCA in written procedures for both investigating and reporting incidents. The RCA must include causes of the incident as well as information to prevent the recurrence of the specific incident, or incidents of a similar nature.
  • Workplace Safety Culture: Employers are required to perform an effective process safety culture assessment and produce a written report within 18 months of the proposed PSM’s effective date, and at least every five years thereafter. The proposed rule includes language that promotes the inclusion of employee collaboration when performing these assessments.
  • Recognized and Generally Accepted Good Engineering Practices (RAGAGEP): Washington has adopted a definition for RAGAGEP, which deviates from federal guidance, in that it points solely to codes, standards, technical reports or recommended practices published by recognized industry organizations.  It specifically excludes employers’ internal guidelines and procedures, which federal OSHA has often interpreted as binding RAGAGEP.

Important Dates

L&I intends to have the updated PSM rule in place before the end of the year. The public comment period is now open with comments due no later than August 24. L&I has scheduled hearings for August 10 and 17 in Bellingham, near most Washington refineries, with a virtual hearing to be held on August 15.

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On May 25, 2023, the U.S. Supreme Court issued a 9-0 decision ending a nearly 16-year battle over the Clean Water Act’s (CWA) applicability to certain wetlands. In a five-justice majority opinion, the Court found that the CWA applies only to wetlands that are “as a practical matter indistinguishable” from “relatively permanent, standing or continuously flowing bodies of water” which are more traditionally considered navigable waters. The decision rejected the longstanding “significant nexus” test applied by the U.S. Environmental Protection Agency (EPA) and the U.S. Army Corps of Engineers (USACE) since 2006 when it was announced by Justice Anthony Kennedy in a concurring opinion in Rapanos v. United States. While it is not clear how many acres of wetlands are no longer subject to CWA applicability, many believe the decision will provide greater clarity to project proponents in determining which wetlands are subject to federal regulation.   

In 2007, Michael and Chantell Sackett (the Sacketts) began backfilling their Idaho property in preparation for building a new home. Their backfilling was interrupted when the Sacketts received a notice from the EPA stating that their property contained wetlands covered by the CWA. The CWA prohibits the discharge of pollutants, including backfilling, into navigable waters, which are considered “waters of the United States” (WOTUS). EPA took the position that the wetlands on the Sacketts’ property were “adjacent to” an unnamed tributary to Priest Lake, an interstate body of water, and therefore subject to the CWA prohibition. The wetlands were on the other side of a 30-foot road from the unnamed tributary. Both the district court and the Ninth Circuit ruled in favor of EPA, applying the “significant nexus” test. 

Ruling in favor of the Sacketts, the Supreme Court majority relied heavily upon the volume of wetlands subject to CWA restrictions, the use of “open-ended” factors in the application of the “significant nexus” test, the CWA’s statement that it intended to preserve the states as the primary regulators of water resources, and the possibility of criminal liability for violating the CWA. A four-justice concurring opinion found the majority’s position too narrow, stating they would preserve CWA applicability for wetlands “adjacent” to traditionally navigable waters, “whether touching or not” if separated only by a barrier, such as a dike or a dune. 

Supporters of the decision believe that it properly checks EPA’s authority under the CWA and curtails government power over property rights. However, environmentalists, including President Biden, fear that by limiting the CWA’s scope and the definition of WOTUS, waterways are now at additional at risk of pollution. The ruling will require the Biden administration to revise its WOTUS rule, which became effective in March of this year, though it had been enjoined in roughly half of the country.

Exactly how EPA and USACE will proceed with respect to adoption of a new WOTUS rule and in permitting regimes that rely upon the WOTUS rule is unclear at this time. The regulated community should continue to keep a close eye on WOTUS developments and anticipate potential delays as EPA and USACE respond to the decision. 

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When the UK finally left the EU on 31 January 2020, it kept virtually all EU laws on the UK statute book. This was not straightforward and a detailed set of provisions was fought over in the withdrawal agreement with the EU and in the UK’s domestic withdrawal legislation. This left a great deal of EU regulation still part of UK law (as Retained EU law) unless and until amended by the UK legislature in the usual way.  

Given that the UK had been an EU member since 1972, the vast bulk of the UK’s modern environmental legislation consists of Retained EU law. However, a group of Conservative Brexiteer MPs keen to eradicate EU rules that may restrict the UK’s new found ‘freedom’ to act alone, proposed that all remaining Retained EU Law should be examined and if not saved by a ‘sunset’ date (the end of 2023) should fall away and cease to apply. This would be the case even if Parliament simply ran out of time to give them each due consideration. A bill was introduced by Government to Parliament to that effect and has reached its final stages.

Given that over 1800 instruments are environmental in nature, environmental groups are alarmed at the prospect of important environmental protections being lost. We previously reported on a recent change to the proposals by the Government, to now identify approximately 161 EU-derived environmental instruments to be axed initially (out of a total of 600), whilst retaining a power for Government ministers to make decisions on the remainder after the end of the year. Read our analysis here.

The Biden administration just announced draft regulations that would require most coal-fired and gas power plants to capture and sequester up to 90 percent of their carbon emissions by the middle of the next decade, a move with the potential to transform the U.S. electricity sector and perhaps offer a boost to the fledgling domestic carbon capture and sequestration industry.

If approved in their current form, the proposed rules, under Section 111 of the Clean Air Act (CAA), would require new and existing gas plants — excepting those that only run part time — to capture and sequester 90 percent of their emissions by 2035. Existing coal-fired power plants would need to hit that 90 percent target in 2030, but only if operators plan to keep them in operation in 2040 and beyond.

How big a bump for CCS?

The US Environmental Protection Agency (EPA) believes that much of the reduction in greenhouse gases (GHG) emissions under Section 111 for the electricity sector can be accomplished through carbon capture and sequestration (CCS): collecting and isolating carbon emissions at the source, then injecting into subjacent formations, saline aquifers, depleted oil and gas reservoirs, or subsea geologic formations for permanent storage and sequestration. According to the draft EPA rules, CCS would be used for baseload power plants that generate a lot of electricity and are expected to be in operation after the year 2040. There is a lot of regulatory support for the technology despite a lack of proven facilities – to date there is only one power plant in the world using carbon capture at scale: the Boundary Dam Power Station near Estevan, Canada, located just across the North Dakota border. Operating since 2014, the Boundary Dam Power Station captures up to 90 percent of CO2 emitted from a coal plant, according to its operators. The primacy of CCS under the proposed rule could result in increased investor interest in the industry.

Likelihood of finalization and legal challenge?

We note that these are only proposed rules, subject to comment. The proposal will face scrutiny regarding, among other things, whether the EPA exceeded its statutory authority and Supreme Court restrictions on the agency’s powers. It has already received immediate criticism from lawmakers and officials in coal-heavy West Virginia. Since the announcement of the proposal on May 11, 2023, Democratic Sen. Joe Manchin has vowed to oppose any future EPA nominee in the Senate over the rule. Meanwhile, Manchin’s Republican colleague, Sen. Shelley Moore Capito, has called it an attempt to “kill American energy jobs” and has vowed to introduce a Congressional Review Act bill in an attempt to overturn it. However, it seems likely that the proposed rules will be finalized by the Biden administration.

Once finalized, the rule will face inventible legal challenge. EPA has a poor track record when it comes to legal challenges under CAA 111. The agency has tried and failed to promulgate regulations under Section 111 with regard to the electricity sector twice before. In both instances, federal courts threw out the rules — rejecting the Obama administration’s attempt to replace fossil fuels with renewable energy, while faulting the Trump administration for doing too little to confront climate change.

This time, the agency hopes its selection of a regulatory scheme that will push utilities to utilize CCS will withstand future legal challenges. EPA officials underscored they believed the rule comports with the Supreme Court’s recent decision in West Virginia v. EPA. However, whether the mandate for CCS in the manor proposed can be argued to be a “major question” that requires Congressional authority remains to be seen.

Fate of the CCS tax credit in light of proposed rule?

EPA has insisted the overall cost of the draft rules would be “negligible.” To do this math, EPA has projected up to $85 billion in benefits from avoided climate change and health impacts. Further, EPA officials also point to last year’s expansion of a lucrative tax credit for carbon capture from $50 per ton of CO2 to $85 per ton, which they said would offset the full cost of CCS retrofits at some plants.

CCS has traditionally been quite expensive to add to power plants, which may cause some utilities to choose to shut down gas- or coal-fired plants in favor of renewable energy like solar or wind. However, the Inflation Reduction Act (IRA) boosted subsidies for carbon capture, aiming to stimulate investment and offset the capital commitment necessary to implement the emission-cutting technology.

The fact that EPA is relying on the CCS tax credit does not guarantee the long-term survival of such a credit. EPA is an executive agency and the tax credit comes from Congress – there is no guarantee the two entities will remain in lockstep on coupling the two policies. However, if the rule is finalized as proposed, Congress will likely face pressure from both industry and constituents to keep the CCS tax credit in place, in order to subsidize the electricity sector’s compliance and to mitigate any adverse cost impacts from compliance efforts on consumer electricity costs.

However, the affordability of CCS remains a challenge. A utility industry source said that even if IRA subsidies bring the costs down, the lack of sufficient pipeline and storage infrastructure for captured carbon in the U.S. remains an unavoidable obstacle. Nevertheless, the proposed rule acknowledges this by incorporating long lead times and extended timelines, with the majority of GHG reduction not required until after 2040. This approach grants some flexibility to the industry, considering the infrastructure limitations. The issue of the cost of CCS is a complex subject; stay tuned for further analysis on this point.

The US Environmental Protection Agency (EPA) recently proposed a significant addition to its Renewable Fuel Standards (RFS) program—the renewable electricity RIN (eRIN). The eRIN is a new kind of renewable identification number (RIN) obligated parties could obtain to meet their renewable volume obligations and comply with the RFS program.

Under the current RFS program, obligated parties must blend renewable fuels into transportation fuel or obtain RINs to achieve compliance. Renewable fuels eligible for RIN generation include cellulosic biofuel, biomass-based diesel, advanced biofuel, and non-advanced/conventional biofuels. RINs are generated when a producer makes an eligible biofuel and may be traded between parties depending on compliance needs.   

The eRIN proposal adds a new RIN to the menu of eligible renewable fuels, but the generation pathway for eRINs would be notably different from traditional biofuels. In short, EPA’s proposal provides that electric vehicle manufacturers (identified as OEMs in the proposed rule) would generate eRINs based on their electric vehicle fleets. OEMs would quantify the renewable electricity used by their electric vehicle fleets (new and existing electric vehicles). OEMS would then contract with renewable electricity generators to purchase the amount of renewable electricity needed to power their fleet, which would result in the generation of eRINS. Notably, only OEMs would be eligible to generate eRINs.

EPA recognizes in the proposal that a variety of parties may be involved in the eRIN generation and disposition chain including biogas producers, biogas distributors, the renewable electricity generator, and OEMs among others. Based on the variety of parties involved, EPA considered various options for structuring the eRINS program. Ultimately, however, EPA concluded that regulation of just three core parties—OEMs, renewable electricity producers, and biogas generators—is needed to ensure that the eRIN program results in the production of renewable electricity from biogas and used as transportation fuel in a manner consistent with the Clean Air Act.

This arrangement leaves the other parties involved in the eRIN generation and disposition chain outside the scope of regulation. While such parties are not eligible to generate eRINs under EPAs proposal, there are still opportunities for a windfall. For example, electricity generators contracting OEMs must produce renewable electricity from qualifying biogas (i.e. biogas made from renewable biomass under an EPA-approved pathway). As a result, the eRIN proposal may result in greater demand for qualifying biogas and may result in new business opportunities for generators of qualifying biogas and their business partners, including third-party aggregators. The applicability of the proposed regulation with regard to these business opportunities is complex and in some cases unclear even if the regulations are finalized as proposed.

We note that EPA’s eRIN proposal is not yet final. Although eRIN generation is set to begin January 1, 2024, the eRIN program may look markedly different from EPA’s current proposal based on EPA’s solicitation for feedback. Interested parties should therefore continue to closely track developments with this rulemaking and consult with counsel regarding the likely form of the final regulations.

The Occupational Safety and Health Administration (OSHA) recently released two memos instructing enforcement officers on “instance-by-instance” citations and de-grouping violations to deter infractions. 

OSHA’s prior policy on instance-by-instance citations, published in 1990, applied just to willful citations. The new guidance identifies several scenarios where such citations may be issued, including high-gravity serious violations specific to falls, trenching, machine guarding, respiratory protection, permit required confined space, lockout tagout, and other-than-serious violations specific to recordkeeping. OSHA states that a more expansive application of instance-by-instance citations “will incentivize employers to proactively prevent workplace fatalities and injuries and provide OSHA another tool to use on its mission to ensure safe and healthful working conditions for America’s workforce.” 

Similarly, OSHA released a memo reiterating existing policy that allows staff to de-group violations. The de-grouping memo reminds OSHA staff of its “discretion to not group violations in appropriate cases to achieve a deterrent effect” and warns that “OSHA enforcement activity may lose its deterrent effect when citations are grouped.” Despite the emphasis on de-grouping violations to promote deterrence, the memo also states that Grouping violations should be considered when:

  • Two or more serious or other-than-serious violations may overall be classified by the most serious item;
  • Grouping two or more other-than-serious violations considered together create a substantial probability of death or serious physical harm; or
  • Grouping two or more other-than-serious violations results in a high gravity other-than serious violation.

These two new directives signal OSHA’s intent to be more aggressive with respect to enforcement. Employers should therefore prepare for more aggressive enforcement action from OSHA and ensure their current health and safety policies are up-to-date and implemented in accordance with applicable standards.

As we previously covered, California has been working towards the development of “green hydrogen,” i.e., hydrogen fuel produced by splitting water into hydrogen and oxygen using renewable electricity.  Most stakeholders acknowledge that green hydrogen is a critical (but predominantly untapped) resource that offers many climate and energy benefits.[1]  In a significant step to advance this goal, the California Legislature and Governor recently adopted SB-1075 with some important revisions.

The bill still requires the California Air Resources Board (CARB), the California Energy Commission (CEC), and the California Public Utilities Commission (CPUC) to consider green electrolytic hydrogen as an eligible form of energy storage and to consider other potential uses of green electrolytic hydrogen in their decarburization strategies.  However, the bill no longer requires the creation of a “Clean Hydrogen Fund,” which was a large part of the earlier version (see here for our earlier analysis of the fund).   

The following summarizes the major provisions that ultimately were made law in California.

  1. Requires CARB, in consultation with the CEC and the CPUC, and consulting the Workforce Development Board and labor and workforce organizations, to prepare an evaluation (posted to its website by June 1, 2024) of:
    • Policy recommendations to accelerate production and use of hydrogen – particularly “green hydrogen,” which the bill describes but does not define – to help achieve the state’s climate, clean energy, and clean air objectives;
    • A description of strategies supporting hydrogen infrastructure development;
    • A description of the potential for “other forms of hydrogen,” outside of green hydrogen, to achieve greenhouse gas (GHG) emissions reductions;
    • An analysis of how curtailed electrical generation could be better used to meet state goals, including the production of green hydrogen;
    • An estimate of the comparative amount of GHG emissions reductions and air quality benefits the state could achieve through deploying green hydrogen;
    • An analysis of the potential for opportunities to integrate hydrogen production and application with drinking water supply treatment needs;
    • Policy recommendations for regulatory and permitting processes associated with transmitting and distributing hydrogen; and
    • An analysis of the life-cycle greenhouse gas emissions and air pollution and other environmental impacts from hydrogen.
  2. Requires the CEC, as part of the 2023 and 2025 editions of the Integrated Energy Policy Report, to study and model potential growth for hydrogen and its role in decarbonizing the electrical and transportation sectors of the economy, and helping to achieve the various state clean energy and environmental goals.

Ultimately, California intends to “develop a leading green hydrogen industry in California in order to provide accelerated clean air, climate, and energy benefits; better integrate existing and new renewable resources into the electrical grid; support forest management, short-lived climate pollutant and waste management goals; create jobs; and provide new clean technology to decarbonize challenging sectors.” This law is a critical step forward in meeting such goals, and we will continue to closely follow this important topic in California and abroad. 

[1] The legislature highlights the benefits of green hydrogen as follows:

*Green hydrogen offers many climate and energy co-benefits, including better utilizing curtailed electrical generation and better integrating eligible renewable energy resources into the electrical grid to achieve greater than 100 percent zero-carbon energy and putting renewable generation of electricity to use to decarbonize many other sectors of the economy.

*Green hydrogen offers an opportunity to reduce emissions of greenhouse gases, criteria air pollutants, and toxic air contaminants and improve the health of local communities located close to existing industrial hydrogen uses, including oil refining, production of ammonia, and other industrial chemical uses.

*Green hydrogen is a flexible resource that can be used for many things, including oil refining, ammonia and fertilizer production, and other industrial and chemical processes; net-zero or net-negative carbon chemicals, fuels, and polymers that can be produced when green hydrogen is combined with captured carbon dioxide; storing renewable and zero-carbon electricity for multiple days and seasons; powering a variety of on-road, off-road, rail, aviation, and maritime transport and materials handling applications; providing dispatchable electricity production including enhancing resiliency for behind-the-meter emergency backup generation and islanded microgrids; displacing coking coal used in the production of steel; fueling industrial thermal applications; and decarbonizing the existing natural gas pipeline.