Tag: energy

President Biden Nominates Three FERC Commissioners

On February 29, 2024, President Biden nominated three new commissioners of the Federal Energy Regulatory Commission (“FERC”). The nominations will be reviewed and voted on by the Senate Energy and Natural Resources Committee and are subject to confirmation by the full Senate. If approved, the nominees will provide FERC with a full slate of five commissioners, including three Democrats and two Republicans.

Judy Chang is the Managing Principal of the Analysis Group in Boston and former Undersecretary of Energy and Climate Solutions of the Massachusetts Department of Energy Resources. She is a Democrat and will succeed Commissioner Allison Clements with a term ending June 30, 2029. Commissioner Clements has announced that she would not serve a second term, but she may remain on FERC after June 30, 2024, until replaced or through December 31, 2024. Ms. Chang was the keynote speaker at Pierce Atwood’s 2022 Energy Infrastructure Symposium.

Lindsay See is the Solicitor General of the State of West Virginia. Ms. See is a Republican, recommended to the President by Senate Minority Leader Mitch McConnell, and will succeed former Commissioner James Danly with a term ending June 30, 2028. Ms. See has represented West Virginia in many multi-state legal coalitions on a variety of national issues, including energy and environmental rules and policies.

David Rosner is a member of the FERC staff, an energy industry analyst who has been on loan to the majority staff of the Senate Energy and Natural Resources Committee, which is chaired by Senator Joe Manchin of West Virginia. Mr. Rosner will succeed former Chairman Richard Glick with a term ending June 30, 2027.

All three nominations have been received by the Senate and referred to the Energy and Natural Resources Committee, which will hold a hearing on each nominee. The Committee has not yet scheduled any hearings.

FERC Chairman Willie L. Phillips was designated as chairman on February 9, 2024. He was previously acting chairman. His term ends June 30, 2026. Commissioner Mark C. Christie’s term ends on June 30, 2025.

©2024 Pierce Atwood LLP. All rights reserved.

Taking Stock of a Big Month for Methane Policy

November has been a big month for methane policy, featuring announcements of new international, domestic, and private sector initiatives.  A common thread across all of the new initiatives is the aim of achieving more ambitious, credible, and internationally consistent standards for measurement, monitoring, reporting, and verification (MMRV) of methane emissions from the oil and gas sector.  Below is a review.

China’s Methane Pledge.  China is the world’s largest emitter of methane, accounting for 14% of the global total, and, for the first time, the government made an international announcement about methane policy.  At a November summit held in Sunnylands, California, President Joe Biden and Chinese President Xi Jinping announced a new agreement to address climate change. Previous Chinese pledges had only targeted carbon dioxide, but the new agreement includes a first-ever commitment by the country to tackle non-CO2 emissions, including methane.  Just prior to the Sunnylands summit, the Chinese government issued an action plan outlining goals to curb flaring and to develop a methane MMRV program.

EU Methane Regulation.  The European Union (EU) also broke new ground on methane policy this month.  After all-night talks, the EU’s governing entities finalized a new Methane Regulation, which targets not only domestic sources of methane but also emissions attributable to imports of natural gas into the Continent—including from the United States. For imports, the Regulation establishes phased requirements.  The first phase focuses on data collection coupled with a mechanism for detecting and rapidly addressing large leaks.  The second phase will condition imports on application of prescribed, uniform MMRV measures.  Starting in 2030, importers will be subject to a limit on their methane “intensity”—a metric that measures methane emissions per unit of gas throughput.  The methane intensity limit will apply across the entire value chain, from pre-production through final delivery.  The Regulation requires the EU Commission to promulgate the intensity standard by 2027.

International Working Group on MMRV for Natural Gas Markets.  To support not only these emerging governmental policies but also expanding private sector efforts to create a market for “Differentiated Gas,” a multilateral initiative was announced in November—the International Working Group to Establish a Greenhouse Gas Supply Chain Emissions Measurement, Monitoring, Reporting, and Verification (MMRV) Framework for Providing Comparable and Reliable Information to Natural Gas Market Participants (the Working Group). The Working Group’s members consist of the U.S. government, eleven other governments, the European Commission, and the Mediterranean Gas Forum.  The Working Group’s objective is to develop a consensus-based, consistent international framework for supply chain MMRV.  A consistent framework will make it easier for buyers to demand and suppliers to provide natural gas with a lower greenhouse gas profile.  The Working Group will not prescribe emission targets, but it acknowledges that governments may use its work products to inform regulatory processes.

The Working Group has stated that it will draw on input from expert stakeholders.  To that end, a consortium of three universities participating in the Energy Emissions Modeling and Data Lab (EEMDL) has convened a group of academic, think tanks, ENGO, and market experts to develop recommendations for MMRV standards for the Differentiated Gas market. (I am a participating expert in the EEMDL initiative.)  This month, a subset of the experts group published a paper in Nature Energy outlining the issues.

Financial Institutions Call for Industry Action.  Underscoring the increasing private sector demand for Differentiated Gas, two major financial institutions released reports in November calling for industry action.  JP Morgan, one of the world’s largest financiers of fossil fuel projects, issued a report underscoring its commitment to achieve a net zero-aligned emission intensity reduction target for its oil and gas sector portfolio. Methane reductions are a key element of its net-zero strategy.  To that end, the report identifies and exhorts the industry to adopt best-in-class practices for methane MMRV and mitigation.

In the same week, one of the world’s largest insurance underwriters for the oil and gas sector, Chubb, rolled out a Methane Resource Hub, a digital resource center for its clients. The site provides information on MMRV and mitigation techniques, technologies, studies, and policies.

Waiting for EPA.  Also expected in November is EPA’s proposed implementation rules for the “Methane Fee” that was enacted as part of the Inflation Reduction Act (IRA).  The IRA provisions apply a per-ton fee to facilities in the oil and gas sector that exceed specified methane intensity limits.  To implement the fee, EPA will need to promulgate methods for facility-level methane intensity measurements.  A significant issue in the rulemaking is the extent to which EPA will allow affected facilities to use advanced methane measurement technologies to calculate their annual emissions.

© 2023 Van Ness Feldman LLP
For more news on methane policy, visit the NLR Environmental, Energy & Resources section.

Renewable Energy Tax Credits under the Inflation Reduction Act: Opportunities for Exempt Organizations

The Inflation Reduction Act of 2022 (the “IRA” or “Act”) added and modified several renewable energy tax provisions under the Internal Revenue Code of 1986, as amended (the “IRC”).[1] These changes provide many opportunities for exempt organizations, investors, and developers in clean energy projects to lower their costs by monetizing previously unavailable tax credits and thereby increase their business. Among them:

  • Solar facilities are now eligible for the Section 45 Production Tax Credit
  • An Investment Tax Credit for stand-alone energy storage technology with a minimum capacity of 5 kWh
  • A new two-tier credit system consisting of a base credit and an additional bonus credit for eligible projects that satisfy new prevailing wage and apprenticeship requirements
  • New “domestic content,” “energy community,” and “low-income community” bonus credits
  • New “technology neutral” tax credits
  • New ways to monetize tax credits

There has been significant interest in the energy credits by tax exempt organizations, in particular by universities and hospitals. Indeed, these organizations have been looking to minimize their greenhouse gas impact or carbon footprint with the goal of achieving clean energy even prior to the enactment of the IRA. The direct pay option which is now available under the IRA has accelerated the interest in clean energy. Commentators also note that private foundations have been interested in addressing climate change and taking advantage of these newly enacted credits to help spread the use of clean technologies.

Section 6417, discussed below, could be a “game changer” in this regard. Even though certain of the credits have been in existence, unless tax exempts have had a significant amount of unrelated business income tax (“UBIT”), they previously could not avail themselves of the credits prior to the enactment of Section 6417 which provides the direct payment alternative.

The below will outline the new and modified renewable energy tax credits under the IRA, and summarize recent guidance issued by the Treasury Department.

CHANGES TO EXISTING TAX CREDITS

Section 45 Production Tax Credit

Before the enactment of the IRA, the Section 45 Production Tax Credit (“PTC”) was available to electricity produced from certain renewable resources, including wind, biomass, geothermal, hydropower, municipal solid waste, and marine and hydrokinetic energy. Under the Act, solar facilities and are now also eligible for the PTC. In order to qualify for the PTC, eligible facilities must be placed in service and start construction before the end of 2024. Facilities which begin construction after December 31, 2024, will fall under the new technology-neutral tax credit regimes (discussed below).

Section 48 Investment Tax Credit[2]

Prior to the Act, the Section 48 Investment Tax Credit (“ITC”) was not available to stand-alone energy storage projects. The IRA created an ITC for stand-alone energy storage technology with a minimum capacity of 5 kWh. The term “energy storage technology” includes any technology that receives, stores, and delivers energy for conversion to electricity, or to most technology that thermally stores energy.

Like the PTC, under the Act, eligible facilities can qualify for the ITC as long as they are placed in service and begin construction before the end of 2024. Facilities which begin construction after December 31, 2024, will fall under the new technology-neutral tax credit regimes (discussed below).

STRUCTURAL CHANGES TO THE TAX CREDIT SYSTEM

The IRA created a new two-tier credit system consisting of a base credit and an additional bonus credit that is only available for eligible projects that satisfy the new prevailing wage and apprenticeship requirements (discussed below). The new ITC base rate will be 6 percent, and the bonus rate will increase it to 30 percent. The new PTC base rate will be 0.3 cents/kwh and the bonus rate will increase it to 1.5 cents/kwh.

Prevailing Wage Requirement

Taxpayers must pay laborers, mechanics, contractors, and subcontractors a prevailing wage during the construction of the project and with respect to subsequent alterations or repairs of the project following its placement in service. The prevailing wage is based on the pay rates published by the Department of Labor (“DOL”) for the geographic areas and type of job or labor classification. If relevant pay rates are not published, the taxpayer must request a wage determination or wage rate from the DOL.[3]

Apprenticeship Requirement

Taxpayers must also ensure that, with respect to the construction of a qualified facility, no fewer than the “applicable percentage” of total labor hours are performed by qualified apprentices. The “applicable percentage” is: (i) 10 percent for projects beginning construction before 2023, (ii) 12.5 percent for projects beginning construction during 2023, and (iii) 15 percent for projects beginning construction thereafter. Each contractor and subcontractor who employs four or more individuals to perform construction on an applicable project must employ at least one qualified apprentice. A “qualified apprentice” is an individual who is employed by the taxpayer or any contractor or subcontractor and who is participating in a registered apprenticeship program.

If a taxpayer fails to satisfy the apprenticeship requirement during a particular year, the taxpayer may correct the failure by paying a penalty to the IRS equal to $50 ($500 if the apprenticeship requirement was intentionally disregarded) multiplied by the total number of labor hours that did not satisfy the apprenticeship requirement. However, the IRA also includes a “good faith effort” exception if the taxpayer requests qualified apprenticeships from a registered apprenticeship program and either the request is denied, or the program fails to respond within five business days after receiving the request.

ADDITIONAL BONUS CREDITS

The IRA established the “domestic content,” “energy community,” and “low-income community” bonus credits.

Domestic Content

Projects qualifying for certain PTC and ITC credits could qualify for a 10 percent increase to the base and bonus credits if they satisfy the IRA’s new “domestic content” requirements. To qualify for this bonus credit, all steel, iron, and manufactured products that are components of the completed facility are to be produced in the United States.

Energy Community

Facilities located in an “energy community” will also qualify for a 10 percent increase to the base and bonus credits. An “energy community” includes brownfield sites, certain areas with significant employment related to, or local tax revenues generated by, coal, oil, or natural gas, and where there is high unemployment, or a census tract where a coal mine has recently closed or a coal-fired electric plant was retired or removed.

NEW “TECHNOLOGY NEUTRAL” TAX CREDITS

The IRA added new tax credits that apply to qualified facilities placed into service after December 31, 2024, and which yield zero greenhouse gas emissions. The Section 45Y Clean Electricity Production Credit (“CEPTC”) and the Section 48E Clean Electricity Investment Credit (“CEITC”) will replace the PTC and ITC, respectively, and are intended to be technology neutral. The credit amounts for the CEPTC and CEITC are calculated similarly to the PTC and ITC and are subject to similar prevailing wage and apprenticeship bonus requirements.

NEW WAYS TO MONETIZE TAX CREDITS UNDER THE IRA

The Act established the following two novel methods to monetize energy tax credits.

Direct Pay Available to Tax Exempt Organizations

For tax years beginning after December 31, 2022, and before January 1, 2033, certain “applicable entities” can make an election to receive a cash payment equal to the value of otherwise allowable tax credits. This option allows for the applicable entities to utilize and monetize the tax credits via a refund, even though the entities generally do not incur tax liabilities. The term “applicable entities” includes tax-exempt organizations, state and local governments, tribal governments, and the Tennessee Valley Authority.

The direct pay option is also available to taxpayers claiming the Sections 45V, 45Q, and 45X credits even if they do not meet the definition of an “applicable entity.”

Third-Party Sales

For tax years beginning after December 31, 2022, taxpayers (“transferee”) that do not meet the definition of an “applicable entity” may transfer all or a part of their eligible credits to an unrelated taxpayer (“transferor”) in exchange for cash. The cash consideration is not includible in the income of the transferor and is not deductible by the transferee. Credits may not be transferred more than once. In the case of any transfer election, the transferee taxpayer will be treated as the taxpayer for all purposes under the IRC with respect to such credit. With respect to a project held by a partnership, only the partnership itself (and not its partners) can elect to transfer the eligible credits. (Emphasis added.) Then it is likely to be treated as unrelated trade or business.

All of the tax credits eligible for the direct pay option, except for the Section 45W Clean Commercial Vehicles Credit, are also eligible for sale to a third-party.

NOTICES 2023-17 AND 2023-18

On February 13, 2023, the IRS issued Notices 2023-17 and 2023-18 which provide guidance on the administration of two allocation-based renewables tax credit programs under Sections 48(e) and 48C, respectively.

Notice 2023-17

The Act amended Section 48(e) to provide an increase in the ITC for qualified solar and wind facilities which are deployed in specified low-income communities or residential developments. To receive these increased credit amounts, a taxpayer must receive an allocation of “environmental justice solar and wind capacity limitation” (“Capacity Limitation”). A “qualified solar and wind facility” is any facility that (1) generates electricity solely from a wind facility, solar energy property, or small wind energy property; (2) has a maximum net output of less than five megawatts (as measured in alternating current); and (3) is described in at least one of the four categories described in the chart below.

Notice 2023-17 established the Low-Income Communities Bonus Credit Program under Section 48(e) and provided guidance on the procedures and information required to apply for an allocation of Capacity Limitation. For each of 2023 and 2024, the annual capacity limitation is 1.8 gigawatts of direct current capacity, which will be allocated among four categories of projects as follows:

Category

Required Facility Location

Category

Required Facility Location

Capacity Limitation Allocation (MW)

Bonus Percentage

1

Low-Income Community

700 MW

10%

2

Indian Land

200 MW

10%

3

Qualified Low-Income Residential Building Project

200 MW

10%

4

Qualified Low-Income Economic Benefit Project

700 MW

10%

A taxpayer must submit an application to the IRS in order to receive a Capacity Limitation allocation. Details regarding the application process are forthcoming, however, Notice 2023-17 states that applications will be accepted in a phased approach during a 60-day application window for calendar year 2023. Applications will be accepted for Category 3 and 4 projects beginning in the third quarter of 2023, and Category 1 and 2 project applications will be accepted thereafter.

The Department of Energy (“DOE”) will review applications for statutory eligibility and any other criteria provided by the IRS. On this basis, the DOE will provide recommendations to the IRS regarding the selection of applicants for an allocation of Capacity Limitation. If the selected applications exceed the capacity limitations for a given category, the DOE will use a lottery system or some other process to allocate Capacity Limitations. If accepted, the IRS will notify the applicant of its decision and specify the amount of Capacity Limitation allocated. Within four years of receiving such notification applicants must place the eligible property in service to claim the increased credit rate.

Notice 2023-18

The Act extended the Section 48C Advanced Energy Project Credit (“48C Credit” or “AEPC”), which was originally enacted as part of the American Recovery and Reinvestment Act of 2009. Section 48C provides a credit for investments in projects that fall into one of the following three general categories: (i) clean energy manufacturing and recycling projects, (ii) greenhouse gas emission reduction projects, and (iii) critical materials projects. The AEPC is subject to an aggregate cap of $10 billion, at least $4 billion of which will be allocated to census tracts (or tracts adjacent to census tracts) in which coal mines have been closed after 1999 or coal-fired generation facilities have been retired after 2009.

Notice 2023-18 provides guidance on the process and timeline for applying for an allocation of 48C Credits. The first allocation round of $4 billion began on May 31, 2023. Outlined below is an overview of the application, review, and approval process for the first allocation round of 48C credits:

The applicant submits a “concept paper” to the DOE between May 31, 2023, and July 31, 2023.

After reviewing the concept paper, the DOE will issue a letter to the applicant either encouraging or discouraging the submission of an application. All applicants that submit a concept paper during the above period may submit an application irrespective of the DOE’s response.

The applicant submits an application to the DOE for review. If the applicant intends to apply for a bonus credit because it will satisfy the prevailing wage and apprenticeship requirements, it must confirm this in the application.

The DOE then makes a recommendation as to whether to accept or reject the application and provides a ranking of the applications.

Based on the DOE’s recommendations and rankings, the IRS will make a decision regarding the acceptance or rejection of the application and notify the applicant of its decision.

Within two years after receiving an allocation from the IRS, the applicant must provide evidence to the DOE that the certification requirements have been met.

The DOE notifies the applicant and the IRS that it has received the applicant’s notification that the certification requirements have been met.

The IRS will provide a letter to the applicant certifying the project (“Allocation Letter”).

Within two years after receiving the Allocation Letter, the applicant must notify the DOE that the project has been placed in service. The applicant may claim the 48C Credit in the year in which the property is placed in service.

Additional guidance from the Treasury Department and IRS is expected to be released throughout the year.

FOOTNOTES

[1] Unless otherwise stated, all “Section” references are to the IRC.

[2] For any investment tax credit under Section 50(b)(3), an exempt organization could only avail itself of such credit to the extent the property in question was used in unrelated business income. So in effect, prior to the enactment of IRA, any property that was used consistent with the tax exempt organization’s mission presented an obstacle which Section 6417 expressly overrides. Section 50(b)(3).

[3] If a taxpayer fails to meet the prevailing wage requirement during a particular year, the taxpayer may cure the failure by paying each worker the difference between actual wages paid and the prevailing wage, plus interest and a penalty of $5,000. If a taxpayer’s failure to pay prevailing wages was due to “intentional disregard,” then the taxpayer must pay each worker three times the difference and pay the IRS a $10,000 penalty per worker.

© 2023 Blank Rome LLP

For more tax news, click here to visit the National Law Review.

European Commission Aims to Tackle Greenwashing in Latest Proposal

On March 22, the European Commission unveiled a proposal, the Green Claims Directive (Proposal), aimed at combating greenwashing and misleading environmental claims. By virtue of the Proposal, the EC is attempting to implement measures designed to provide “reliable, comparable and verifiable information” to consumers, with the overall high-level goal to create a level playing field in the EU, wherein companies that make a genuine effort to improve their environmental sustainability can be easily recognized and rewarded by consumers. The Proposal follows a 2020 sweep that found nearly half of environmental claims examined in the EU may be false or deceptive. Following the ordinary legislative procedure, the Proposal will now be subject to the approval of the European Parliament and the Council. There is no set date for entry into force at this time.

The Proposal complements a March 2022 proposal to amend the Consumer Rights Directive to provide consumers with information on products’ durability and repairability, as well as to amend the Unfair Commercial Practices Directive by, among other things, banning “generic, vague environmental claims” and “displaying a voluntary sustainability label which was not based on a third-party verification scheme or established by public authorities.” The Proposal builds on these measures to provide “more specific requirements on unregulated claims, be it for specific product groups, specific sectors or for specific environmental impacts or aspects.” It would require companies that make “green claims to respect minimum standards on how they substantiate and communicate those claims.” Businesses based outside the EU that make environmental claims directed at EU consumers will also have to respect the requirements set out in the Proposal. The criteria target explicit claims, such as “T-shirt made of recycled plastic bottles” and “packaging made of 30% recycled plastic.”

Pursuant to Article 3 of the Proposal, “environmental claims shall be based on an assessment that meets the selected minimum criteria to prevent claims from being misleading,” including, among other things, that the claim “relies on recognised scientific evidence and state of the art technical knowledge,” considers “all significant aspects and impacts to assess the performance,” demonstrates whether the claim is accurate for the whole product or only parts of it, provides information on whether the product performs better than “common practice,” identifies any negative impacts resulting from positive product achievements, and reports greenhouse gas offsets.

Article 4 of the Proposal outlines requirements for comparative claims related to environmental impacts, including disclosure of equivalent data for assessments, use of consistent assumptions for comparisons and use of data sourced in an equivalent manner. The level of substantiation needed will vary based on the type of claim, but all assessments should consider the product’s life-cycle to identify relevant impacts.

Pursuant to Article 10, all environmental claims and labels must be verified and certified by a third-party verifier before being used in commercial communications. An officially accredited body will carry out the verification process and issue a certificate of conformity, which will be recognized across the EU and shared among Member States via the Internal Market Information System. The verifier is required to be an officially accredited, independent body with the necessary expertise, equipment, and infrastructure to carry out the verifications and maintain professional secrecy.

The Proposal is part of a broader trend of governmental regulators, self-regulatory organizations, and standard setters across industries adopting a more formalized approach toward greenwashing. For example, as we recently reported, the UK’s Advertising Standards Authority (ASA) published rules on making carbon neutral and net-zero claims. Instances of enforcement actions over greenwashing allegations have also been on the rise. The Securities and Exchange Board of India recently launched a consultation paper seeking public comment on rules to prevent greenwashing by ESG investment funds, and the European Council and the European Parliament reached an agreement regarding European Green Bonds Standards aimed at, among other things, avoiding greenwashing.

Article By Sukhvir Basran and Rachel Rodman of Cadwalader, Wickersham & Taft LLP

Click here to visit the National Law Review for more environmental law news.

© Copyright 2023 Cadwalader, Wickersham & Taft LLP

H2 Production: A Shift Towards Electrolysis

Hydrogen production technology, according to the joint EPO-IEA report summarizing patent trends in the hydrogen economy (summarized here), accounts for the largest percentage of patenting activity since 2011 among the three primary stages of the hydrogen value chain (i.e., (i) production, (ii) storage, distribution, and transformation, and (iii) end-use industrial applications). Trends show a shift in hydrogen production from carbon-intensive methods to technologies that do not rely on fossil fuels. The bulk of recent increased patent activity is directed to electrolysis development, while patent activity related to production from biomass and waste has decreased.

Electrolysis

Electrolysis is attractive because it’s a low-emission source, meaning that hydrogen produced through electrolysis creates little to no greenhouse gas emissions. It is possible that water electrolyzers are powered by electricity derived from natural gas or fossil fuels, but unlike most other hydrogen production technology, electrolyzers do not produce greenhouse gas emissions and thereby offer the ability to produce hydrogen with net zero carbon emissions.

In this article, we will first briefly explain electrolysis and conventional concepts using electrolysis. Then, we will give an example of a technology that recently emerged from conventional electrolysis-based solutions. We will close with a brief description of alternative technologies for hydrogen production.

State of the Art

Electrolyzers use electricity to split water into hydrogen and oxygen. Specifically, an electrolyzer cell includes an anode and a cathode separated by a polymer electrolyte membrane. Water reacts at the anode to form oxygen and positively charged hydrogen ions. The hydrogen ions selectively move across the membrane to the cathode, where they combine with electrons from an external circuit to form hydrogen gas. A number of cells are assembled into a cell stack that efficiently produces hydrogen and oxygen. A standard electrolyzer stack includes membrane electrode assemblies, current collectors, and separator or bipolar plates.

Electrolyzers also range in size and type. Electrolyzer sizes range from small, appliance-size units to large-scale, central production facilities. Electrolyzer types include polymer electrolyte membrane (PEM) electrolyzers, alkaline electrolyzers, and solid oxide electrolyzers. Conventional electrolyzer stacks have capacities of 5 MW to 100 MW per stack, depending primarily on the membrane technology.

Emerging Technologies

EvolOh is a California-based startup planning to build the world’s largest hydrogen manufacturing plant in Massachusetts this year to manufacture its anion-exchange membrane (AEM) electrolyzers. The plant will be used for fabrication and assembly of the AEM electrolyzer stacks for producing green hydrogen1. These compact and high-power density electrolyzer stacks should allow for high-speed manufacturing using low-cost materials based on domestic supply chain and no precious metals. With anticipated power ratings of up to 5 MW for a single stack and 50 MW for a single module, EvolOH’s stacks are intended to be designed for large-scale facilities.

As disclosed in EvolOH’s IP, its electrolyzer stack features a bipolar plate assembly including a bipolar plate, a hydrogen seal, a water seal, and a fluid distribution frame. The fluid distribution frame serves multiple purposes within the electrolyzer stack, including containing a cathode flow field, distributing water flow from one water delivery window to a leading edge of the anode flow field, collecting water and oxygen flow from the anode flow field and distributing the flows to oxygen collection windows, and engaging and curing hydrogen seal between the frame and a bipolar plate adjacent to the cathode flow field and a water seal between the frame and a bipolar plate adjacent to the anode flow field.2 In contrast to conventional bipolar plates that include simple flow distribution channels, the bipolar plate assembly of the EvolOH electrolyzer stack is intended to provide for a scalable electrolysis cell that can be utilized in a variety of electrolyzer types.

Also as described in EvolOH’s IP, its electrolyzer stack includes a compression system having a lower wrap and an upper wrap connected at a joint to form a continuous vertical tension boundary around the cell stack and its end units while providing access to opposite lateral ends of the stack.3 Conventional electrolyzer stacks may apply a compressive load on the cell stack using end structural plates drawn together by tie rods and adjustable elements such as screws, nuts, and springs. Unlike the conventional tie rod compression, the compressive system of EvolOH’s electrolyzer stack is intended to maintain adequate compression on the stack over a range of temperatures taking into account thermal expansion and compression.

EvolOH is among many companies focused on the development of electrolyzer technology to scale-up hydrogen to reach a broader market. For example, Air Liquide and Siemens Energy recently teamed up to form a joint venture last year to produce large-scale hydrogen electrolyzers in Europe. Set to open in 2023, they intend to produce a large-scale electrolyzer with an intended capacity of 100 MW that may reduce costs per kW by 33% by 2030. The EPO-IEA study finds that Siemens is one of the leading applicants in electrolyzer patent families since 2011 and that Air Liquide is a top applicant in patent families directed to established hydrogen production technologies as well as hydrogen storage and distribution technologies.

Alternative Hydrogen Production Options

In addition to electrolysis, hydrogen can be produced from other methods such as biomass or waste via gasification or pyrolysis, recovery of by-product hydrogen from chlor-alkali electrolysis, and methane pyrolysis. Hydrogen can be produced from natural gas through methods such as steam reforming, which emits carbon dioxide in the process. Widespread natural gas infrastructure makes hydrogen production from natural gas appealing, and developments in carbon capture, utilization, and storage technology may make this option even more appealing.

In our next post on the EPO-IEA’s report, “Hydrogen Patents for a Clean Energy Future: A Global Trend Analysis of Innovation Along Hydrogen Value Chains,” we will dive into the second technology segment of the hydrogen value chain—hydrogen storage, distribution, and transformation.

Article By Jason A. Engel, Dr. Benjamin Fechner, and Clare Frederick of K&L Gates

For more energy and environment legal news, click here to visit the National Law Review.

Copyright 2023 K & L Gates

Nigeria’s Energy Sector: Looking Back at 2022 and Looking Ahead in 2023

We review the key events of 2022 in Nigeria’s energy sector – a year that saw significant steps in the implementation of PIA, intermittent M&A activity and the continuing effects of crude theft. We also consider what we can expect in 2023, ahead of what appears to be Nigeria’ closest presidential election yet.

2022: What happened in legal matters?

The Petroleum Industry Act (PIA) entered its second year of effectiveness and continued its slow march of implementation . The most notable step was the official “relaunch” of The Nigerian National Petroleum Corporation as NNPC Limited in July in a high profile ceremony led by President Buhari. As mandated in the PIA, NNPC Limited was incorporated as a new CAMA company which is wholly owned by the Nigerian government. Key consequences of this transition include:

  • Commercial entity: NNPC Limited is a limited liability company (rather than a state-owned and state-funded corporation) and is intended to operate as a commercial entity. It is expected to publish annual reports and audited accounts and declare dividends to its shareholders – the Nigerian government, and therefore should remain a vital contributor to state revenues.

  • Independence from government and self supporting: The new NNPC Limited is independent and should not depend on government support for its operations. It is expected to raise its own funds, which may lead to wider adoption of the incorporated joint venture model (as provided for, but is not mandatory, under PIA). Whether this will help unlock NNPC’s capability to be a functioning and cash call paying partner in its joint operations remains to be seen. The extent of actual government control and direction over NNPC Limited will also only become clear through practice. PIA retains (for now) total government ownerships of NNPC Limited and control over the selection of its management team.

  • Royalty-paying entity: NNPC Limited is, like any other oil and company operating in Nigeria, required to pay its share of all fees, rents, royalties, profit oil shares and taxes to the government in relation to any participating interests it holds in petroleum leases or licences.

NNPC Limited’s first actions as a commercial entity were notable: these included exercising pre-emption rights over a 40% stake in OML 86 and OML 88 and buying OVH Energy’s downstream assets (giving NNPC access to 380 fuel stations and eight liquefied petroleum gas plants), along with other purported pre-emptions over upstream M&A transactions. NNPC Limited has partnered with Afreximbank to raise US$5 billion to support NNPC Limited’s upstream business and energy transition plans.  NNPC Limited also made senior appointments in 2022 with Senator Margery Chuba Okadigbo as chair and Mele Kyari continuing as CEO.

Another consequential step in PIA implementation was the promulgation of the Nigeria Upstream Petroleum Host Communities Development Regulations in June, setting out the requirements for the establishment and funding of host community development trusts. The new trust structure was one of the more controversial parts of PIA, with licence holders required to pay into the trust a levy of 3% of their actual annual operating expenditure of the preceding financial year in the upstream petroleum operations affecting the host communities for which the fund was established.

What happened in politics / regulatory matters?

The continuing impact of the global pandemic, the war in Ukraine, rising energy costs and the consequences of crude theft and spills made for a challenging final year in office for President Buhari.

Progress was made on some of Nigeria’s key gas projects that form part of the “Decade of Gas” programme. Construction is under way on Nigeria LNG’s Train 7 project, which promises to increase LNG production capacity by 35%. The Assa North-Ohaji South Gas project moves closer to completion and promises to accelerate Nigeria’s transition towards cleaner fuels and improve availability of natural gas for power generation.

New projects were also lined up: Nigerian Minister of State for Petroleum Resources Timipre Sylva, alongside the Ministers of Energy of Niger and Algeria signed a memorandum of understanding to build an over 4,000km trans-Saharan gas pipeline at an estimated cost of US$13 billion. The pipeline is intended to start in Nigeria and end in Algeria and be connected to existing pipelines that run to Europe.

The government launched its energy transition plan in 2022 as it works towards Nigeria’s commitment to reach net zero by 2060 and provide access to affordable, reliable and sustainable energy to all of its citizens by 2030. Vice President H.E Yemi Osinbajo said that Nigeria would need to spend an additional US$10 billion per annum on energy projects. Nigeria’s federal minister of power, Engr. Abubakar D. Aliyu also announced new renewable energy policies: the national renewable energy and energy efficiency policy, the national renewable energy action plan, the national energy efficiency action plan and the sustainable energy for all action agenda.

Crude theft was rampant in 2022 and remains a huge critical and unresolved issue for Nigeria, resulting in the shutdown of two of Nigeria’s major pipelines in July. Its impact is significant: the petroleum regulator estimated that Nigeria suffered a US$1 billion loss in revenue in the first quarter of 2022 as a result, and the (attempted) flight of international oil companies from the worst-affected onshore acreage has continued.

What deal activity happened?

Panoro Energy received government approval for the sale of its interest in OML 113 to PetroNor at the start of the year. The Majors divestment plans continued but encountered significant delays, with some being indefinitely postponed and others becoming mired in regulatory approval roadblocks and facing the new appetite of NNPC to assert purported pre-emptory rights.

What is expected in 2023?

  • Politics: The 2023 elections loom large, with the Presidential and National Assembly elections commencing on 25 February and Governorship and State House elections following on 11 March. The Presidential election is presently too close to call and we make no predictions. The onset of electioneering will slow regulatory decision making. International investments may pause until the election outcome is decided, key appointments made and the direction of economic and energy policies are explained.

  • Legal: Industry participants will continue to grapple with the new PIA regime, while its implementation continues over the coming year. Expected key steps include:

    • The deadline for voluntary conversion of existing OPLs and OMLs into their new forms was set for February 2023. Licence holders will need to decide whether to adopt early conversion, balancing the extent of improved PIA fiscal terms against the consequences, including termination of all outstanding arbitration and court cases related to the relevant OPL / OML, removal of any stability provisions or guarantees given by NNPC, and relinquishment of no less than 60% of the acreage. If not converted by this date, then it becomes mandatory on licence expiry / renewal.

    • The deadline for segregation of upstream, midstream and downstream operations also falls in February. Any midstream and downstream activities that were being carried out as part of upstream operations require the grant of a new midstream / downstream licence.

  • Regulatory: A new licensing round covering seven deepwater blocks has been announced for 2023, marking Nigeria’s first offshore bid round in 15 years. A pre-bid conference is taking place this month with pre-qualification applications due by the end of January.

  • Transaction activity: Upstream deals may need to wait for the dust from the 2023 election to settle, but there should be a resumption of the divestment programmes of the Majors in 2023.  Outside of M&A, Nigeria is due to go to trial in London in January 2023 as it seeks to overturn an approximately US$11 billion (including interest) arbitration award won by Process and Industrial Developments Ltd in relation to a 2010 gas project agreement. The award is now worth about a third of Nigeria’s foreign reserves.

  • Projects: Following significant delays, in part due to the COVID-19 pandemic, we understand that the Dangote refinery is expected to be officially commissioned by President Buhari in January and start up mid-2023. First gas from both the Ajaokuta-Kaduna-Kano pipeline and from Seplat’s Assa North-Ohaji South Gas project is forecast for the first half of 2023.

© 2023 Bracewell LLP

U.S. Fish & Wildlife Service Proposes New Regulations Creating General Eagle “Take” Permits for Certain Wind Energy and Power Line Infrastructure Projects

The U.S. Fish and Wildlife Service recently published a proposed rule revising regulations that authorize permit issuance for eagle incidental take and eagle nest take under the Bald and Golden Eagle Protection Act (the “Act”). In addition to retaining the individual permits already available under the Act, the new rule proposes creation of a “general” permit for qualifying wind energy and power line infrastructure projects.

The Act generally prohibits the “take,”[1] possession, and transportation of bald eagles and golden eagles, except pursuant to federal regulations. However, the Act also authorizes the Secretary of the Interior to issue regulations to permit the take of these eagle species for various purposes. Under the current regulations, there are 2 permit types for the incidental take of eagles and eagle nests, which are issued on an individual, project-specific basis. Due, in part, to inefficiencies in the application review and approval process, issuance of these project-specific eagle take permits has – historically – been relatively rare. The Service acknowledges that, while participation in the permit program by wind energy projects has increased since 2016, it still remains well below the Service’s expectations.

According to the Service, the purpose of the new regulations is to: (i) increase the efficiency and effectiveness of permitting; (ii) facilitate and improve compliance with the regulations; (iii) and increase the conservation benefit for eagles. The Service proposes to do this by creating a general permit program to streamline the permitting process and provide more timely and cost-effective coverage for affected industries.

General permits would be available to authorize incidental take by activities that occur frequently enough for the Service to have developed a standardized approach to permitting. Specifically, the Service proposes activity-specific eligibility criteria and permit requirements in 4 new sections based on activity and type of take: (i) incidental eagle take for permitting wind energy; (ii) incidental eagle take for permitting power lines; (iii) bald eagle disturbance take; and (iv) bald eagle nest take. As part of the revised application process, a general permit applicant would self-identify as eligible and register with the Service. The applicant is then required to submit an application containing all requested information and fees, as well as certification that the applicant meets the eligibility criteria and would implement permit conditions and reporting requirements.

Two particular proposed general permits – for wind energy and power line projects – could prove particularly useful for renewable energy developers.

Wind Energy Projects

The core general permit eligibility criterion for wind energy projects would be a relative eagle abundance threshold, which a project would need to be below in order to qualify for a general permit. The proposed rule includes specific abundance thresholds for bald and golden eagles, applicable during 5 defined portions of the year. For project eligibility, seasonal bald or golden eagle abundance at all existing or proposed turbine locations must be lower than all 5 seasonal thresholds listed. Presently, the Service estimates that nearly 80% of all existing wind-energy turbines in the coterminous United States are located in areas under the proposed relative abundance thresholds for both species and thus eligible for a general permit under this proposal. The Service plans to offer publicly available online mapping resources depicting areas that qualify. However, at this time, we note that under the proposed rule, Alaska would be excluded from the general permitting program.

In addition to falling below the relative eagle abundance thresholds, wind energy projects would also need to be sited more than 660 feet from bald eagle nests and more than 2 miles from golden eagle nests to be eligible for a general permit.

For existing projects where not all turbines are located within an area below the designated thresholds of relative abundance, the project operator would need to apply for an individual permit and request consideration for a general permit in the application. The Service would review the project and issue a letter of authorization if it determines it is “appropriate” to extend general permit coverage.

Although the Service has not yet promulgated a complete set of conditions for wind energy project general permits, the proposed rule requires permittees to implement all practicable avoidance and minimization measures to reduce the likelihood of take. Permittees would also be subject to a 4 discovered-eagle permit condition, under which discovery of 4 eagle mortalities at a wind energy project covered by a general permit would prohibit the project from reapplying for additional 5-year general permits. Such a project would have to apply for an individual permit.

Power Lines

In the proposed rule, the Service acknowledged that it has sufficient understanding of how eagles interact with power lines to develop a general permit for eagle take resulting from power-line infrastructure.

While the proposed rule does not include detailed eligibility criteria, the Service contemplates 6 key conditions for the new power line general permit:

  1. All new construction and reconstruction of pole infrastructure must be electrocution-safe for bald eagles and golden eagles, except as limited by human health and safety.
  2. All new construction and reconstruction of pole infrastructure must be electrocution-safe for bald eagles and golden eagles, except as limited by human health and safety. All new construction and reconstruction of transmission lines must consider eagle nesting, foraging, and roosting areas in siting and design, as limited by human health and safety. Specifically, the Service recommends siting utility infrastructure at least 2 miles from golden eagle nests, 660 feet from a bald eagle nest, 660 feet from a bald eagle roost, and 1 mile from a bald eagle or golden eagle foraging area.
  3. A reactive retrofit strategy must be developed that governs retrofitting high-risk poles when an eagle electrocution is discovered. A reactive retrofit strategy responds to incidents in which eagles are killed or injured by electrocution.
  4. A proactive retrofit strategy must be developed and implemented to convert all existing infrastructure to be electrocution-safe, prioritizing poles identified as the highest risk to eagles.
  5. A collision-response strategy must be implemented for all eagle collisions with power lines. If an eagle collision is detected, a strategy must outline the steps to identify and assess the collision, consider options for response, and implement a response.
  6. An eagle shooting response strategy must be developed and implemented when an eagle shooting is discovered near power-line infrastructure.

Service review and approval would not be required prior to obtaining coverage under either of these general permits. Rather, according to the Service, the general permit authorization would be “generated” using permit conditions and reporting requirements for the proposed activity. Under the proposed rule, upon submitting an application, the Service will “automatically issue a general permit to authorize the take requested in the application.”

The Service intends to conduct annual audits for a small percentage of all general permits to ensure applicants are appropriately interpreting and applying eligibility criteria. The maximum term for wind energy and power line project general permits would be 5 years; after expiration, with certain narrow exceptions, projects could reapply for new 5-year general permits.

Finally, because the Service will undertake environmental review to support its final rule, obtaining coverage under the general permits would not require project-specific environmental review under the National Environmental Policy Act. However, applicants for the general permit must certify, among other things, that: (i) the activity for which take is to be authorized does not affect a property that is listed, or is eligible for listing, in the National Register of Historic Places; or (ii) that the applicant has obtained, and is in compliance with, a written agreement with the relevant State Historic Preservation Officer or Tribal Historic Preservation Officer that outlines all measures the applicant will undertake to mitigate or prevent adverse effects to the historic property.

The Service is accepting comments on the proposed rule until November 29, 2022. The Service hosted an initial listening session for the general public on October 20th, and will host an additional listening session on November 3, 2022.

FOOTNOTES

[1]Under the federal Endangered Species Act, “take” is defined as any action “to harass, harm, pursue, hunt, shoot, wound, kill, trap, capture, or collect, or to attempt to engage in any such conduct.”

Article By S. Keith Garner and Daniel S. Maroon of Sheppard, Mullin, Richter & Hampton LLP

For more environment and energy legal news, click here to visit the National Law Review.

Copyright © 2022, Sheppard Mullin Richter & Hampton LLP.

Supreme Court Questions Whether Highly Compensated Oil Rig Worker Is Overtime Exempt

On October 12, 2022, the Supreme Court of the United States heard oral arguments in a case regarding whether an oil rig worker who performed supervisory duties and was paid more than $200,000 per year on a day rate basis is exempt from the overtime requirements of the Fair Labor Standards Act (FLSA).

The case is especially significant for employers that pay exempt employees on a day rate. It could have a major impact on the oil and gas industry in the way that it recruits, staffs, and compensates employees who work on offshore oil rigs and at remote oil and gas work sites. In addition, depending on how the Supreme Court rules, its decision could have much broader implications.

During the arguments in Helix Energy Solutions Group, Inc. v. Hewitt, the justices questioned whether, despite the employee’s high earnings, he was eligible for overtime compensation because he was paid by the day and not on a weekly salary basis. There is no express statutory requirement that an employee be paid on a “salary basis” to be exempt from overtime requirements, but such a requirement has long been included in the regulations issued by the U.S. Department of Labor (DOL) applicable to the FLSA’s white-collar exemptions. Notably, Justice Brett Kavanaugh suggested during the arguments that the regulations may be in conflict with the text of FLSA, although Helix did not raise this issue in its petition for certiorari.

Background

The case involves an oil rig “toolpusher,” an oilfield term for a rig or worksite supervisor, who managed twelve to fourteen other employees, was paid a daily rate of $963, and earned more than $200,000 annually. Between December 2014 and August 2017, when Michael Hewitt was discharged for performance reasons, he worked twenty-eight-day “hitches” on an offshore oil rig where he would work twelve-hour shifts each day, sometimes working eighty-four hours in a week. After his discharge, Hewitt filed suit alleging that he was improperly classified as exempt and therefore was entitled to overtime pay. The district court ruled in favor of Helix.

In September 2021, a divided (12-6) en banc panel of the U.S. Court of Appeals for the Fifth Circuit held that Hewitt was not exempt from the FLSA because his payment on a day-rate basis did “not constitute payment on a salary basis” for purposes of the highly compensated employee (HCE) exemption that is found in the FLSA regulations.

The Fifth Circuit further concluded that the employer’s day-rate pay plan did not qualify as the equivalent of payment on a salary basis under another FLSA regulation because the guaranteed pay for any workweek did not have “a reasonable relationship” to the total income earned. In other words, the court found that the employee was not exempt because the $963 he earned per day was not reasonably related to the $3,846 the employee earned on average each week.

Oral Arguments

Oral arguments at the Supreme Court focused on the interplay between the DOL’s HCE regulation, 29 C.F.R. § 541.601, and another DOL regulation, 29 C.F.R. § 541.604(b), which states that an employer will not violate the salary basis requirement under certain limited circumstances even if the employee’s earnings are computed on an hourly, daily, or shift basis.

At the time of Hewitt’s employment, the HCE exemption required an employee to be paid at least $455 per week on a “salary or fee basis” and to earn at least $100,000 in total annual compensation. Those threshold amounts have since been increased to $684 per week and $107,432 per year.

The other regulation, 29 C.F.R. § 541.604(b), states that an employee whose earnings are “computed on an hourly, a daily or a shift basis” may still be classified as exempt if the “employment arrangement also includes a guarantee of at least the minimum weekly required amount paid on a salary basis regardless of the number of hours, days or shifts worked, and a reasonable relationship exists between the guaranteed amount and the amount actually earned. The reasonable relationship test will be met if the weekly guarantee is roughly equivalent to the employee’s usual earnings at the assigned hourly, daily, or shift rate for the employee’s normal scheduled workweek.”

Hewitt earned double the minimum total compensation level for the HCE exemption. Since the minimum salary level for the exemption was only $455 per week, and Hewitt was guaranteed that he would be paid at least $963 per week for each week he worked at least one day, Helix argued that he was exempt from the FLSA’s overtime requirements because the HCE exemption was completely self-contained and to be applied without regard to other regulations, including the “salary basis” test and the minimum guarantee regulation. Hewitt argued that the HCE exemption required compliance with either the “salary basis” test or the minimum guarantee regulation since he was admittedly paid on a day rate basis.

However, Justice Ketanji Brown Jackson suggested that it was not that simple. Justice Jackson said the question of salary basis is more about the “predictability and regularity of the payment” for each workweek. “What he has to know is how much is coming in at a regular clip so that he can get a babysitter, so that he can hire a nanny, so that he can pay his mortgage,” Justice Jackson stated. Justice Jackson echoed the language of the salary basis test requiring that an exempt employee be paid a predetermined amount for any week in which she performed any work.

Similarly, Justice Sonia Sotomayor asked Helix, “so what you’re asking us to do is take an hourly wage earner and take them out of 604, which is the only provision that deals with someone who’s not paid on a salary basis.” Justice Sotomayor additionally raised the FLSA’s goal of “preventing overwork and the dangers of overwork.”

In contrast, Justice Clarence Thomas suggested that Hewitt’s high annual compensation relative to the average worker is a strong indication that he was paid on a salary basis and should be exempt. “The difficulty is just, for the average person looking at it, when someone makes over $200,000 a year, they normally think of that as an indication that it’s a salary,” Justice Thomas stated.

Justice Kavanaugh asked if the issue of whether the DOL regulations conflict with the FLSA is being litigated in the courts. He said, “it seems a pretty easy argument to say, oh, by the way, or maybe, oh, let’s start with the fact that the regs [sic] are inconsistent with the statute and the regs [sic] are, therefore, just invalid across the board to the extent they refer to salary.” He further stated, “if the statutory argument is not here, I’m sure someone’s going to raise it because it’s strong.”

Key Takeaways

It is difficult to predict how the Supreme Court will rule in this case. A decision that requires strict adherence to the regulation’s reasonable relationship test, even when the minimum daily pay far exceeds the minimum weekly salary threshold, would have a significant negative impact on the manner in which certain industries compensate their workers. It also could lead to even more litigation by highly compensated employees, many of whom make more money without receiving overtime pay than what many people who currently are paid overtime compensation make.

Depending upon its breadth, a decision that the regulations are in conflict with the statutory text of the FLSA could provide a roadmap for additional challenges to other parts of the regulations. This could have a wide-ranging impact, as the DOL currently is in the process of preparing a proposal to revise its FLSA regulations. Then again, if a future litigant takes up Justice Kavanaugh’s invitation to challenge whether the salary regulations are overbroad compared to the language of the FLSA, the current effort to revise the regulations regarding exemptions for executive, administrative, and professional employees may be moot.

Article By Andrew P. Burnside, Steven F. Pockrass, and Zachary V. Zagger of Ogletree, Deakins, Nash, Smoak & Stewart, P.C.

For more supreme court and litigation legal news, click here to visit the National Law Review.

© 2022, Ogletree, Deakins, Nash, Smoak & Stewart, P.C., All Rights Reserved.

California PFAS Legislation Will Dramatically Impact Businesses

We previously reported on three significant pieces of California PFAS legislation that were before California’s Governor Newsom for ratification. Two of the bills were passed, which means that several categories of products will have applicable PFAS bans. The third bill was not signed by the Governor, which would have required companies to report certain data to the state for goods  sold in or otherwise brought into California that contain PFAS.

With increasing attention being given to PFAS in consumer goods in the media, scientific community, and in state legislatures, the California PFAS bills underscore the importance of companies anywhere in the manufacturing or supply chain for consumer goods to immediately assess the impact of the proposed PFAS legislation on corporate practices, and make decisions regarding continued use of PFAS in products, as opposed to substituting for other substances.  At the same time, companies impacted by the PFAS legislation must be aware that the new laws pose risks to the companies involvement in PFAS litigation in both the short and long term.

California PFAS Bills

One of our prior reports was on the first significant PFAS bill that Governor Newsom was expected to sign into law – AB 2771 – and which was indeed passed into law. The bill prohibits the manufacture, sale, delivery, hold, or offer for sale any cosmetics product that contains any intentionally added PFAS. The law would go into effect on January 1, 2025. The bill defines a cosmetics products as “an article for retail sale or professional use intended to be rubbed, poured, sprinkled, or sprayed on, introduced into, or otherwise applied to the human body for cleansing, beautifying, promoting attractiveness, or altering the appearance.”

The second bill signed into law by the Governor is AB 1817, which bans the use of PFAS in textiles manufactured and sold in California. More specifically, the bill prohibits, beginning January 1, 2025, any person from “manufacturing, distributing, selling, or offering for sale in the state any new, not previously owned, textile articles that contain regulated PFAS” and requires a manufacturer to use the least toxic alternative when removing PFAS in textile articles to comply with these provisions. The bill requires a manufacturer of a textile article to provide persons that offer the product for sale or distribution in the state with a certificate of compliance stating that the textile article is in compliance with these provisions and does not contain any regulated PFAS. The bill specifically regulates three categories of textiles:

(1) “Textile articles” means textile goods of a type customarily and ordinarily used in households and businesses, and include, but are not limited to, apparel, accessories, handbags, backpacks, draperies, shower curtains, furnishings, upholstery, beddings, towels, napkins, and tablecloths;

(2) “Outdoor apparel” means clothing items intended primarily for outdoor activities, including, but not limited to, hiking, camping, skiing, climbing, bicycling, and fishing; and

(3) “Apparel”, defined as “clothing items intended for regular wear or formal occasions, including, but not limited to, undergarments, shirts, pants, skirts, dresses, overalls, bodysuits, costumes, vests, dancewear, suits, saris, scarves, tops, leggings, school uniforms, leisurewear, athletic wear, sports uniforms, everyday swimwear, formal wear, onesies, bibs, diapers, footwear, and everyday uniforms for workwear…outdoor apparel and outdoor apparel for severe wet conditions.

The bill that California’s Governor vetoed was AB 2247, which would have established reporting requirements for companies that utilize products or substances that contain PFAS and which are used in California in the stream of commerce. “The bill would [have] require[d], on or before July 1, 2026, and annually thereafter, a manufacturer, as defined, of PFAS or a product or a product component containing intentionally added PFAS that, during the prior calendar year, is sold, offered for sale, distributed, or offered for promotional purposes in, or imported into, the state to register the PFAS or the product or product component containing intentionally added PFAS, and specified other information, on the publicly accessible data collection interface.”

Impact of California PFAS Legislation On Businesses

California PFAS legislation places some of the most significant and widely used consumer products in the crosshairs with respect to PFAS. While other states have banned or otherwise regulated PFAS in certain specific consumer goods, California’s bills are noteworthy given the economic impact that it will have, considering that California is the fifth largest economy in the world.

It is of the utmost importance for businesses along the whole cosmetics supply chain to evaluate their PFAS risk. Public health and environmental groups urge legislators to regulate these compounds. One major point of contention among members of various industries is whether to regulate PFAS as a class or as individual compounds.  While each PFAS compound has a unique chemical makeup and impacts the environment and the human body in different ways, some groups argue PFAS should be regulated together as a class because they interact with each other in the body, thereby resulting in a collective impact. Other groups argue that the individual compounds are too diverse and that regulating them as a class would be over restrictive for some chemicals and not restrictive enough for others.

Companies should remain informed so they do not get caught off guard. States are increasingly passing PFAS product bills that differ in scope. For any manufacturers, especially those who sell goods interstate, it is important to understand how those various standards will impact them, whether PFAS is regulated as individual compounds or as a class. Conducting regular self-audits for possible exposure to PFAS risk and potential regulatory violations can result in long term savings for companies and should be commonplace in their own risk assessment.

Article By John Gardella of CMBG3 Law

For more environmental legal news, click here to visit the National Law Review.

©2022 CMBG3 Law, LLC. All rights reserved.