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.

We are not expecting further big climate reduction commitments from countries this year at COP27. The leaders of China and Russia (the world’s first- and fifth-largest climate polluters) are not attending the event, nor are officials from many of the largest economies, including India and Australia. U.S. President Joseph Biden will make only a short appearance on Nov. 11 along with a smaller-than-usual U.S. delegation. With such middling representation, expectations not surprisingly are muted.

This comes in spite of the fact that increased and more stringent climate reduction commitments are necessary. Countries around the world are failing to live up to their existing commitments to fight climate change, and of the 193 countries that agreed last year to step up their climate actions, only 26 have followed through with more ambitious plans. The world’s top two polluters – China and the United States – have taken some action, but without significant (or any) presences at COP27, we expect the climate negotiations between the two to remain at a standstill (as they have been for months).

An analysis by the World Resource Institute found that current promises by nations would reduce global greenhouse gas emissions by around 7 percent from 2019 levels, even though six times that, a reduction of 43 percent, would be necessary to limit global warming to 1.5 degrees Celsius (the reduction amount agreed to by nations at the Paris COP).

The United States, in passing the Inflation Reduction Act (IRA), has jumped forward in its ability to make good on its promise to cut emissions by as much as 52 percent below 2005 levels by the end of this decade. But still, the IRA will get the United States to only about 80 percent of its current pledge to cut emissions – so any new pledge by the U.S. is without legal basis.

Without climate reduction commitments, what will the nations’ focus be?

First thing to expect is discussions with regard to money, money, money. Money in climate talks usually takes the form of adaptation in two ways: (1) who will pay for moving away from polluting energy sources and toward renewables, and (2) who will pay to help nations adapt their defenses against inevitable climate impacts, such as rising seas and heavier rainfall. At COP27, developing countries will be expecting rich nations to outline how they will deliver on a pledge made at COP26 to “double” support for adaptation.

There has been keen interest in new ways to unlock that money. The UN released a series of four reports in advance of COP27 to address the finance gap. In short, these reports attempt to provide clarity on where the world stands in its efforts to mobilize the billions of dollars needed every year for green economies and to build resilience for the inevitable impacts of climate change.

The second issue will be the role of natural gas in a climate future. Russia’s war in Ukraine has put a spotlight on natural gas; it is increasingly obvious that nations must be clear-eyed about what is feasible, politically and socially, in delivering upon the agreements made at the Paris COP. Europe’s efforts to break its dependence on Russian gas has led to new plans for building ports and facilities for importing liquefied natural gas from the U.S. and elsewhere, including in parts of Africa. Building natural gas infrastructure (as opposed to renewable energy infrastructure) in Africa and other third-world nations could put the world on a path to even further and longer dependence on fossil fuels. Some African countries with oil and gas reserves say they are willing to develop this fossil fuel infrastructure: Senegal has been among the most vocal and is leading a push for investments in gas production. But right now there is no common Africa position, particularly around the energy transition and around flexibility in the use of natural gas in particular, to achieve African nations’ objectives around electrification. This lack of cohesion will impede progress on this point at COP27. Further, any development of fossil fuel infrastructure within Africa will necessarily have to acknowledge a further commitment to fossil fuels – and by implication a likely delay in meeting a clean energy future and the objectives of the Paris COP.

We will be watching these two issues carefully in the coming to weeks and will post as to progress at the end of COP27.

US EPA periodically issues compliance advisories and enforcement alerts that highlight the agency’s enforcement efforts related to specific regulations and regulatory provisions. One recent EPA enforcement alert targets air emissions from stationary engines subject to the RICE NESHAP under 40 CFR Part 63, Subpart ZZZZ and new source performance standards in 40 CFR Part 60, Subparts IIII and JJJJ. Stationary engines are widely used by a variety of industries, including the oil and gas and energy industries, and support equipment like pumps, compressors, and generators.

The enforcement alert states that noncomplying stationary engines emit excess volatile organic compounds (VOCs) and ozone precursors (e.g. NOx), which contribute to ground-level ozone and overall poor air quality. Common violations include a failure to retrofit existing engines with requisite pollution controls and missed testing. To resolve the alleged violations, US EPA has required equipment upgrades and replacement and has collected six-figure civil penalties in some cases.   

US EPA includes several recommendations to ensure compliance in the enforcement alert. Notable recommendations include:

  • Review engine specs to identify the applicable regulations (e.g. Subpart ZZZZ, Subpart IIII, Subpart JJJJ).  
  • Assess applicable emission and operating limits and recordkeeping and reporting requirements.
  • Evaluate options for upgrading or replacing older engines with newer engines or converting to the power grid.

While stationary engines may appear to be marginal contributors to air pollution compared to other sources, US EPA’s enforcement alert highlights the need for companies to evaluate their stationary engines to ensure compliance. This is particularly true for oil and gas, energy, and mining companies that appear to be US EPA’s primary enforcement targets in this context. Companies in these industries may tend to focus compliance efforts on seemingly more significant sources of air pollution, but the stationary engine enforcement alert should serve as a reminder to take a comprehensive approach to evaluating and ensuring compliance with applicable air regulations.

California Governor Gavin Newsom recently signed three bills addressing carbon capture, utilization and storage (“CCUS”) and carbon dioxide removal (“CDR”).  Collectively, these bills create a pathway for new regulation of CCUS and CDR projects, enabling them to become part of a solution for the State to meet aggressive carbon reduction / neutrality goals in 2030, 2038 and 2045. Below is a summary of each bill.

Senate Bill 905

Among other things, SB 905 requires the California Air Resources Board (“CARB”) to establish a “Carbon Capture, Removal, Utilization and Storage Program to evaluate the efficacy, safety, and viability of CCUS.” CARB will also be required to enhance monitoring procedures for leakage.

By January 1, 2025, regulations for a unified permit application, for the construction and operation of CCUS projects (including an expedited review process), must be adopted. All CCUS projects within California will be required to use this application process and CARB will develop a centralized public database to track all in-state projects.

In addition to permitting procedures, CARB must publish a framework for governing agreements regarding two or more tracts of land overlying the same geologic storage reservoir or reservoirs. The agreements will set out to manage, develop, and operate CCUS or CDR projects. SB 905 ensures that title to any geologic storage reservoir for CO2 is vested in the owner of the overlying surface estate (unless it has been severed and separately conveyed).

CCUS project operators must provide at least a 60 day written notice to each surface or subsurface owner adjacent to a geologic storage complex or reservoir before commencing development. Project operators must also prove and maintain financial responsibility for the project. Agreements between operators and relevant parties, that any drilling or extraction be prohibited in the geologic storage reservoir for at least 100 years after the CO2 is injected, must be made for every project. All project operators also need to create an air monitoring and mitigation plan that is submitted to CARB.

Senate Bill 1314

Critics of CCUS projects utilizing underground sequestration are concerned that such injections can increase pressures in storage locations proximate to oil and gas reserves, (in)directly enhancing further recovery of carbon-based fuels. SB 1314 “plugs this hole” in part by prohibiting a CCUS project operator from injecting a concentrated CO2 fluid produced by a CO2 capture project or a CO2 capture and sequestration project into a Class II injection well for purposes of enhanced oil recovery, including the facilitation of enhanced oil recovery from another well.

Assembly Bill 1757

While some readers may associate CCUS with controlling industrial sources, the State has also shown a growing interest in utilizing forests and other underutilized lands as “carbon sinks” to absorb and permanently store CO2 already in the atmosphere. AB 1757 requires the California Natural Resources Agency (“NRA”) to set an ambitious range of targets for natural carbon sequestration. Targets will be designed to be achieved by 2030, 2038 and 2045 and will be integrated into the State’s Climate Change Scoping Plan. The NRA must update the techniques for natural carbon capture to include: planting trees and shrubs, using compost and cover crops on farmland, creating green spaces in urban areas and restoring wetlands. By January 1, 2025, the NRA must also develop methods to consistently track greenhouse gas emissions and reductions, carbon sequestration, and, additional benefits from natural and working lands over time. While tracking emissions, the NRA must take into account, where feasible, the potential impacts of climate change on the ability to reduce greenhouse gas emissions and sequester carbon from natural and working lands.

The value of this bill may depend in part on whether CARB expands its palette of approved “compliance offset protocols.”  At present, CARB has approved three potentially relevant protocols:  (a) rice cultivation projects; (b) urban forest projects; and (c) U.S. Forest projects.  The scope of potential projects envisioned under AB 1757 could warrant CARB approving additional protocols.  Historically, that has been a controversial process in terms of varying views as to what type of project warrants a state-approved protocol, which ultimately could allow an industrial source to emit additional CO2 because it has generated or purchased offsets under a protocol.

On balance, the above bills create regulatory controls but also predictability for CCUS project developers and entities interested in offtake agreements relating to such projects. Bills enacted on or before October 2 will generally take effect January 1, 2023 unless otherwise specified.

Bills enacted on or before October 2 will generally take effect January 1, 2023 unless otherwise specified.