PIOGA Press
(By Gary Steinbauer and Christina Puhnaty)
The U.S. Environmental Protection Agency’s highly anticipated November 2021 Clean Air Act (CAA) proposal regulating methane and volatile organic compound (VOC) emissions from the oil and gas sector drew a reported 400,000 individual submissions. Through the methane proposal (Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review, 86 Fed. Reg. 63,110 (Nov. 15, 2021)), EPA seeks to expand the current VOC and methane emissions regulations that apply to new, modified, and reconstructed sources within the crude oil and natural gas production sector that were promulgated by EPA in 2012 (40 C.F.R. Part 60, Subpart OOOO) and 2016 (40 C.F.R. Part 60, Subpart OOOOa). In addition, the methane proposal includes the first nationwide methane emissions guidelines for existing sources within the oil and gas sector.
It is no surprise that EPA received a significant number of comments on the methane proposal, especially considering the relatively brief and tumultuous history of the agency’s regulation of methane emissions from the oil and gas sector under the CAA. The commenters’ views on the proposal differ considerably. Many commenters, primarily those representing the oil and gas industry and certain states, raised serious legal concerns and also questioned the technical aspects and propriety of several key components of issues with the proposal. On the other hand, commenters from other states, local governments and environmental groups urged EPA to impose even more stringent requirements, beyond those included in the methane proposal. Several key themes and legal issues emerged from these comments. This article highlights some of the potentially pivotal legal issues raised by commenters, including those related to EPA’s proposed community- based monitoring program.
Comments addressing legal issues related to EPA’s methane proposal
Commenters raised numerous legal issues with the methane proposal, ranging from foundational issues on whether the CAA allows EPA to regulate methane emissions from the oil and gas in this manner to legal concerns about the way EPA is proposing to regulate specific sources in the proposal. In particular, several commenters assert that the methane proposal compounds EPA’s previous error in failing to make the requisite findings required by the CAA to regulate methane emissions from the oil and gas sector and EPA’s legal authority to regulate emissions from sources in the transmission and storage segment.
The legal issues surrounding EPA’s addition of methane to Subpart OOOOa and the transmission and storage segment to Subparts OOOO and OOOOa were raised previously when EPA promulgated Subpart OOOOa in 2016 and in subsequent legal challenges that are currently stayed. Notably, the Trump administration finalized a rule in September 2020 removing methane from Subpart OOOOa and the transmission and storage segment from Subparts OOOO and OOOOa, but in June 2021 Congress rescinded this rule using its Congressional Review Act authority. The House of Representatives issued a report that accompanied its disapproval of the Trump administration’s rule. Notably, in the House’s report, it openly disagreed with the interpretation of the CAA advanced by the Trump administration to support the removal of methane from Subpart OOOOa.
Commenters on the methane proposal, however, suggested that the House’s report is of limited import and the sole effect of Congress’ action was limited to rescinding the Trump administration’s rule and preventing EPA from promulgating a substantially similar rule in the future. In other words, these commenters state that EPA must still meet the CAA requirements for regulating methane emissions from the oil and gas sector, suggesting that these long-standing legal issues are unlikely to resolve themselves.
Several commenters also raise three additional legal issues with the methane proposal that could prove to be critical:
- Due process and fair notice. Many commenters took issue with the listed applicability date of November 15, 2021, for the new CAA § 111(b) performance standards included in the methane proposal. When EPA published the methane proposal it did not provide proposed regulatory text for the proposed new CAA § 111(b) performance standards or CAA § 111(d) emission guidelines for existing sources. Therefore, several commenters questioned EPA’s use of the Federal Register publication date as having any legal import, given the importance of the proposed regulatory text in understanding proposed legal obligations and governing statutory language.
- Modification definitions. Commenters also took issue with EPA’s proposed source-specific definitions of “modification” for the new proposed requirements for centralized production facilities, tanks and tank batteries, and well liquids unloading. Section 111 of the CAA defines a “modification” as “any physical change in, or change in the method of operation of, a stationary source which increases the amount of any air pollutant emitted by such source or which results in the emission of any air pollutant not previously emitted.” 42 U.S.C. § 7411(a)(3). EPA, however, proposes to promulgate source-specific “modification” definitions for the above- referenced sources or facilities that, some commenters argue, are inconsistent with the CAA’s definition of “modification.”
- “Legally and practicably enforceable limits.” On page 92 of the 154-page methane proposal, EPA proposes to create a new definition to “clarify” the term “legally and practicably enforceable limits” as it relates to the regulation of storage vessels in the oil and gas sector. This term embodies the long-established and applied concept of allowing sources to account and take credit for emission reductions when assessing applicability of air regulatory requirements. This concept is used across several major CAA stationary source programs and is not specific to EPA’s CAA regulations for the oil and gas sector. Several commenters urged EPA to issue a broad- based rulemaking should it wish to clarify this key term by regulation.
While many commenters have raised critical threshold legal concerns with EPA’s methane proposal, other commenters, particularly those from certain states and environmental groups, not only expressed support for the underlying legal interpretations advanced by EPA in the proposal, but encouraged EPA to expand the proposal further to impose more stringent requirements and regulate additional sources of methane and VOC emissions.
Comments on the proposed community-based monitoring program
In the methane proposal, EPA directly solicits input and comments on how to design and implement a pro- gram through which communities could use methane detection systems to identify large emissions events and provide that information to facility owners and operators. According to EPA, data and information collected in this community-based monitoring program would be used to require operators to investigate emissions events over a defined emissions threshold, conduct a root cause analysis and take appropriate action to mitigate the emissions. EPA’s proposed community- based monitoring program is novel. We are unaware of any other CAA regulations that expressly allow and authorize third-parties to monitor and measure emissions and use this data and information to force action by the regulated facility.
While some states, including Pennsylvania, and environmental groups voiced support for the proposed program and offered implementation suggestions, industry group commenters in particular raised several legal concerns with the conceptual program. One industry group questioned EPA’s authority to directly allow, by regulation, the proposed community-monitoring program, noting that the information-gathering authority provided to EPA in CAA § 114 is limited to certain types of entities, none of which would cover a third-party community-member. Other commenters noted that EPA’s proposed community-monitoring program would encourage trespass and unsafe practices, as well as raise significant data validation concerns.
Conclusion
The widely divergent views on the legality of EPA’s methane proposal suggest that future litigation is inevitable. Because EPA has indicated that it will release a supplemental proposal, which is expected to include the proposed regulatory text, stakeholders should know soon whether EPA will change or alter course in an effort to subdue potential challengers.
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Reprinted with permission from the April 2022 issue of The PIOGA Press. All rights reserved.
The Wildcatter
(By Nikolas Tysiak)
There is much to report in Leg/Reg land this go around! Let’s dive right in…
PENNSYLVANIA
Murrysville Watch Committee v. Municipality of Murrysville Zoning Hearing Board, 2022 WL 200112 (Comm. Ct. Pa. January 24, 2022). The Murrysville Watch Committee sued appealing a decision of the Zoning/Hearing Board on the validity of the municipality zoning ordinances relating to oil and gas development. Specifically, the MWC alleged that the use of property zoned as residential for oil and gas development was improper – oil and gas development should have been reserved for industrial zoned property, indicated that allowing oil and gas development in residential zones was unconstitutional “spot zoning” (the “unreasonable or arbitrary zoning classification of a small parcel of land, dissected or set apart from surrounding properties, with no reasonable basis for the differential zoning . . .”), and that the allowance of oil and gas development in residential districts violated the Environmental Rights Amendment to the Pennsylvania Constitution (“ERA”). The Commonwealth Court found that the MWC failed to introduce evidence to establish that the oil and gas drilling was incompatible with the “uses or overall character” of the residential zoning districts in question and failed to adduce competent evidence that the ordinances at issue were unreasonable. The court further found that the MWC failed to present any credible evidence that the zoning ordinance violated the rights established under the ERA. The Commonwealth Court accordingly affirmed the decision by the Zoning/Hearing Board and denied the MWC’s legal challenges to the zoning districts.
OHIO
French v. Ascent Resources-Utica, L.L.C., 2022-Ohio-869 (March 24, 2022). In this case, the Ohio Supreme Court determined that a suit seeking the determination that an oil and gas lease expired by its own terms is a controversy “involving the title to or the possession of real estate” and therefore is exempt from arbitration clauses as a matter of Ohio law, overturning a decision of the 7th District Court of Appeals, and affirming a trial court case on the issue. The French family had executed a lease (as amended) containing an arbitration clause and sought to have the lease invalidated. Citing numerous cases, the Supreme Court determined that oil and gas leases clearly involve the use and title to real estate, and concluded that arbitration was not required, even if called for in the lease document.
Peppertree Farms, L.L.C. v. Thonen, 2022-Ohio-395 and 2022-Ohio-396 (February 15, 2022). It appears that the Ohio court system split the matter in controversy into two separate decisions. The first decision addresses the question of whether a reservation without language of inheritance creates merely a life estate benefiting the reserving party, or a “fee interest” in the real estate interests reserved. The second decision applies the Ohio Marketable Title Act (“MTA”) to the land in question. Landowners conveyed the land in question in 1916, excepting and reserving a portion of the oil and gas rights without words of inheritance benefitting the Landowners.
The Court in Peppertree I found that the interest retained by the Landowner in the 1916 deed was inheritable, because the interest she held prior to the deed reservation was already inheritable – the Landowner kept an interest in the same nature that she owned at the time of the conveyance. Nevertheless, in Peppertree II the court determined that the interest so reserved was not preserved in the Landowner’s separate chain of title. The only document at issue was a will executed by the successor to the original Landowner/reserving party from 1961. The will did not expressly devise the reserved oil and gas interest and did not include a residuary clause. Consequently, while any residual interests (including the reserved oil and gas in question) did pass by intestacy due to the failure of the will, the intestate succession at issue was not recorded within the necessary 40-year period, which was also required by the statute. Therefore, the surface owner was able to prevail on its claim that the MTA operated to his benefit and effectively divested the reserved oil and gas interest.
Siltstone Resources, L.L.C. v. Ohio Public Works Commission, 2022-Ohio-483 (February 23, 2022). The Ohio Public Works Commission (“OPWC”) oversees and administers a state environmental conservation program seeking to maintain green spaces within Ohio. As part of that program, the OPWC sometimes transfers land to county development corporations for the same purpose. In so doing, the OPWC places certain restrictions on the use and transfer of the properties to ensure that they are used in a manner consistent with the goals of the conservation program. In this case, OPWC conveyed land subject to various restrictions to a development corporation in Belmont County, OH (“CDC”). These restrictions included anti-transfer clauses and a restriction on the use and structures to be located on the land. The CDC subsequently leased the land for oil and gas production and conveyed out mineral interests from the land to other third party mineral purchasers. Upon realizing there were covenants on the land restricting its use, the oil and gas lessees and owners became concerned and sought a declaratory judgment as to their acquired oil and gas rights. The trial court found that the oil and gas rights so acquired did not violate the covenants and restrictions. On initial appeal, the 5th District overturned the trial court decision and found the covenants and restrictions did prevent oil and gas development. The Supreme Court analyzed the OPWC deed and determined that the 5th District was correct – the transfer of oil and gas rights by lease and by deed violated their restrictive covenants and were effectively nullified. The Court also found that the OPWC had statutory and contractual rights of damages from the parties that violated the restrictive covenants. The case was remanded for further consistent proceedings.
Fonzi v. Brown, 2022-Ohio-901 (March 24, 2022). Another Dormant Mineral Act (DMA) case. Here, surface owners argued that the 2006 amendments to the DMA actually created to separate ways to enforce the law. They could either go through the notice and administrative procedures or file a quiet title action. The administrative procedures give the severed mineral owners time to respond and preserve their severed minerals, while filing a quiet title action effectively would not. The Supreme Court rejected the argument of two parallel ways to utilize the DMA, finding that only the administrative procedural route is called for under the statute. Therefore, that method of enforcement is the only valid method under Ohio law. Applying this standard, the court concluded that the surface owners failed to meet the required notice requirements under the DMA and upheld the previous court’s decision to find title to the oil and gas at issue remained vested in the severed oil and gas owners.
WEST VIRGINIA
Significant legislative changes have arisen in West Virginia. The state house and senate passed Senate Bill 694. While it contains several changes to the West Virginia Oil and Gas laws, the biggest change would be the addition of Section 22C-9-7a to the West Virginia Code, entitled “Unitization of interests in horizontal well drilling units.” This new section establishes procedures and methodologies to created production units for all horizontal oil and gas wells, even in the face of opposition, recalcitrant, or unknown oil and gas owners. The law allows an operator to file for a unitization order with the West Virginia Oil and Gas Commission, after meeting various initial requirements.
First, the applicant must secure the consent or agreement to pool/unitize from at least 75% of the net acreage in the formation targeted for production. Second, the operator must control 55% of the operating interests in the proposed unit. Third, the operator must have made good faith offers and negotiated in good faith with all known and locatable royalty owners and operators to obtain the necessary consents to unitize and operate jointly. The application must include a significant amount of title information for all tracts in the proposed unit, whether controlled by the operator, controlled by other operators, or owned or controlled by unknown or unlocatable parties, including the names and last known addresses of all known or unknown royalty owners and operators. The application must include information relating to the proposed operator’s attempts to identify and unknown or unlocatable owners and must include a list of proposed allocation between all relevant owners. The Commission is also empowered to select an “independent third party” to perform an evaluation of the economic factors included in the application for completeness and accuracy. The new statute establishes that unknown or unlocatable royalty owners are to be treated as being leased upon approval of the unit application, and unknown working interest owners will be treated as having elected to participate in the well or wells within the unit. The statute also provides an avenue for surface owners to acquire the interests of unknown or unlocatable oil and gas owners whose rights underlie their surface land. The bill was sent to Gov. Jim Justice of West Virginia on March 15th. At the time of writing, he has not signed the bill, but it is anticipated that he will do so.
Senate Bill 650 also passed both houses on March 5, 2022. This bill would amend the Co-Tenancy Modernization and Majority Protection Act that was enacted in 2019. For those unfamiliar, the prior act serves to provide a way to operate for oil and gas on lands with uncooperative, unknown, or unlocatable oil and gas owners without the fear of committing statutory waste under West Virginia law. West Virginia is unique in that it has traditionally provided no avenue toward production for oil and gas operators who are unable to obtain appropriate leases from 100% of the owners of the oil and gas under any given tract of land. This law was designed to provide the opportunity for such production without 100% lease right acquired under certain limited circumstances, including control of at least 75% of the “royalty owners”, when there are 7 or more of such owners. The amendment under SB 650 eliminates the need for 7 royalty owners before the statute can be applied. In all other respects, the Co-Tenancy law would remain the same.
That sums it all up.
Regards,
Nik Tysiak – Legislative and Regulatory Committee Chair
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Reprinted with permission from the MLBC April 2022 issue of The Wildcatter. All rights reserved.
Environmental Alert
(By Kevin Garber and Gina Falaschi)
On April 4, 2022, the Pennsylvania Senate failed by one vote to reach the two-thirds majority vote needed to override Governor Tom Wolf’s January 10th veto of Senate Concurrent Regulatory Review Resolution 1, which was intended to block the Pennsylvania Department of Environmental Protection’s regulation to join the Regional Greenhouse Gas Initiative (RGGI). However, the following evening, April 5, the Commonwealth Court issued a stay preventing the Legislative Reference Bureau from publishing the regulation as a final, immediately-effective rule in the Pennsylvania Bulletin and scheduling a hearing for May 4, 2022 on litigation that DEP initiated in February to force publication of the final regulation.
RGGI is the country’s first regional, market-based cap-and-trade program, designed to reduce carbon dioxide emissions from fossil-fuel-fired electric power generators with a capacity of 25 megawatts or greater that send more than 10 percent of their annual gross generation to the electric grid. Regulated sources must hold allowances equal to their CO2 emissions over a three-year compliance period. Each allowance is equal to one short ton of CO2. Regulated sources may purchase state-issued allowances at quarterly auctions or through secondary markets and can use allowances issued by any RGGI state to comply. Regulated sources may also use offsets awarded for certain environmental projects to meet a maximum of 3.3 percent of their allowances.
If the rule is published in the Pennsylvania Bulletin before July 1, 2022, the partial year emissions cap for Pennsylvania would be 40.7 million tons of CO2 for the remainder of 2022. The total annual emissions cap would gradually decline to 58 million in 2030. Affected units would need to start monitoring emissions on July 1, 2022 to be able to purchase allowances for CO2 emitted on or after that date.
RGGI operates on a three-year compliance schedule whereby only partial compliance is required within the first two years, and then full compliance is required after the end of the third year. The current RGGI three-year compliance period began in 2021, so 2021 and 2022 are interim compliance years while 2023 is a full compliance year. If the regulation is published before July 1, 2022, regulated sources must acquire 50 percent of the necessary CO2 allowances by March 1, 2023 and acquire 100 percent of their allowances by March 1, 2024. The allowance price was $13.50 at the last RGGI auction on March 11, 2022.
Litigation to challenge the regulation is expected after it is published in the Pennsylvania Bulletin, which cannot occur until after the May 4 hearing following the Commonwealth Court’s April 5 stay of publication.
If you would like further information about RGGI, please contact Kevin Garber at 412-394-5404 or kgarber@babstcalland.com or Gina Falaschi at 202-853-3483 or gfalaschi@babstcalland.com.
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The Legal Intelligencer
By Matthew Wood and Mackenzie Moyer
On Feb. 26, the Environmental Quality Board (EQB) took another meaningful step toward finalizing Pennsylvania’s first state-established maximum contaminant levels (MCLs) for regulating contaminants in drinking water. On that date, the EQB published a proposed rule to amend 25 Pa. Code Ch. 109 (Safe Drinking Water) to establish MCLs for perfluorooctanoic acid (PFOA) and perfluorooctanesulfonic acid (PFOS), two of the most common PFAS. PFOA and PFOS are just two of a group of thousands of PFAS, manmade chemicals used in various consumer, commercial and industrial manufacturing processes since the 1940s. PFAS have commonly been used to imbue products with water-, stain-, and heat-resistant properties and as ingredients in aqueous film forming foams (AFFF) used to extinguish flammable liquid fires (e.g., those that might occur on airports or military bases). PFAS do not break down naturally in the environment and have thus been called “forever chemicals.” Due to these properties and their ubiquitous nature, PFAS have been found in various environmental media, such as groundwater (including drinking water), plants, animals, and in humans, and evidence suggests that PFAS exposure can lead to adverse health effects. In the absence of definitive federal action to regulate PFAS, many states, including Pennsylvania, have in recent years taken steps to investigate, understand, and regulate PFAS.
Pennsylvania’s proposed rule is the result of years of investigation and evaluation. In 2018, Gov. Tom Wolf established by executive order (2018-08) Pennsylvania’s PFAS action team, which he tasked with the broad functions of, among other things, ensuring safe drinking water and managing environmental PFAS contamination. In June 2019, the Pennsylvania Department of Environmental Protection (PADEP) began sampling public drinking water systems within a half mile of potential PFAS sources such as manufacturing, fire training and military facilities. That sampling effort concluded in March 2021 and the final results were posted to PADEP’s PFAS webpage in June 2021.
Informed by those sampling results and other factors, the proposed rule sets maximum contaminant level goals (MCLGs) and MCLs for PFOA and PFOS. The proposed MCLGs— nonenforceable levels developed solely from health effects data that act as a starting point for determining MCLs—are 8 parts per trillion (ppt) for PFOA and 14 ppt for PFOS. The proposed rule sets MCLs—developed by considering factors outside of health effects data, including technical limitations and costs that could affect the feasibility of achieving the MCLGs—of 14 ppt for PFOA and 18 ppt for PFOS. As part of the MCL development process, PADEP considered other PFAS—PFNA, PFHxS, PFHpA, PFBS, and HFPO-DA—but decided not to propose MCLs for these at this time, primarily due to a lack of occurrence data and incomplete cost/benefit data and analysis. If finalized, Pennsylvania’s MCLs will apply to all 3,117 community, nontransient, noncommunity, bottled, vended, retail, and bulk water systems in the commonwealth and potentially affect other PADEP programs (e.g., groundwater cleanups under Act 2).
Pennsylvania’s proposed PFOA and PFOS MCLs are similar in concentration to their counterparts established in other states. For example, in 2018, New Jersey became the first state to adopt a drinking water regulation for any PFAS when it set a MCL of 13 ppt for perfluorononanoic acid (PFNA). New Jersey subsequently established MCLs for PFOA (14 ppt) and PFOS (13 ppt) and has designated all three of these PFAS as hazardous substances under state law. Other states, including Massachusetts, Michigan, New Hampshire, New York and Vermont have all established MCLs for one or more PFAS at similar concentrations.
Among the reasons states developed their own PFAS MCLs is the federal government’s delay to do so at the national level. Currently, the only federal drinking water guidance for PFAS is a Health Advisory Level (HAL) of 70 ppt for PFOA and PFOS combined, set by the U.S. Environmental Protection Agency (EPA) in 2016. EPA’s HAL is intended to identify the concentration of PFOA and PFOS in drinking water at or below which adverse health effects are not expected to occur over a lifetime of exposure. The HAL, however, it is not an enforceable standard and is considered by critics to be out-of-date and not sufficiently protective. In Pennsylvania, EPA’s HAL has served as the standard at which exceedances require public water systems to take certain actions, e.g., monitoring, notifying consumers and installing treatment technologies.
While states continue to establish their own PFAS regulations, the federal government has charted a path to address PFAS at the national level. On Oct. 18, 2021, the EPA announced its “PFAS Strategic Roadmap: EPA’s Commitments to Action 2021-2024,” (roadmap) which highlights EPA’s “whole-of-agency” approach to addressing the PFAS lifecycle, following three central directives: Research, restrict and remediate. The roadmap is available here. Among its goals, the EPA determined in March 2021 to regulate PFOA and PFOS and is currently in the process of developing National Primary Drinking Water Regulations for each, intending to publish a proposed rule in fall 2022 and a final rule in fall 2023. Consistent with the roadmap, the EPA also published the fifth unregulated contaminant monitoring rule (UCMR 5), which will require sampling for 29 PFAS in certain public water systems between 2023 and 2025. The EPA believes that the sampling data will “ensure science-based decision-making and help prioritize protection of disadvantaged communities.” See 86 Fed. Reg. 73131, 73132 (Dec. 27, 2021), available here. Under the roadmap, the EPA also intends to designate PFOA and PFOS as hazardous substances under CERCLA and build the technical foundation to address PFAS in air emissions.
EQB is currently accepting written comments on Pennsylvania’s proposed rule, and from March 21 through March 25, held five virtual public hearings on the proposed rule. Commenters ranged from members of environmental groups, to private citizens, to state and federal representatives. While many of the commenters supported PADEP’s actions toward establishing PFOA and PFOS drinking water regulations, most thought that PADEP’s efforts fell short, coalescing around three main points. First, because the proposed rule does not regulate private water wells throughout the commonwealth, a significant portion of Pennsylvania’s population will continue to be harmed by PFAS. Second, commenters believe that PADEP must regulate the PFAS “family” of constituents beyond PFOA and PFOS. Finally, many commenters criticized the MCLs as not low enough. Although opinions varied, the most consistent comment was that the MCLs should be no greater than 6 ppt for PFOA, 5 ppt for PFOS, and 13 ppt for PFOA and PFOS combined. Interested parties may submit written comments through April 27, using the methods outlined in PADEP’s announcement of the proposed rule.
When the proposed rule is finalized, Pennsylvania will have promulgated its first state-level MCLs and will become one of a handful of states outpacing the federal government’s efforts to regulate PFAS in drinking water. The proposed rule will set initial compliance monitoring requirements beginning Jan. 1, 2024, for community and nontransient noncommunity water systems serving a population greater than 350 persons and all bottled, vended, retail and bulk systems, and Jan. 1, 2025, for systems serving fewer than 350 persons.
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Reprinted with permission from the April 7, 2022 edition of The Legal Intelligencer© 2022 ALM Media Properties, LLC. All rights reserved.
Environmental Alert
(by Lisa Bruderly and Mackenzie Moyer)
On March 28, 2022, the United States Environmental Protection Agency (EPA) published a proposed rule to expand the types of non-transportation-related facilities that may need to develop Facility Response Plans (FRPs) under the Clean Water Act (CWA). 87 Fed. Reg. 17890. At present, FRPs are required for certain facilities[1] that are reasonably expected to cause “substantial harm” to the environment by discharging oil into navigable waters. The proposed rulemaking would require FRPs for facilities that could reasonably be expected to cause substantial harm to the environment by discharging CWA hazardous substances to navigable waters.
Background
The proposed rulemaking is in response to judicial challenges related to EPA’s failure to meet the requirements of § 311(j)(5) of the CWA, which requires the president to “issue regulations which require an owner or operator of a tank vessel or facility . . . to prepare and submit . . . a plan for responding, to the maximum extent practicable, to a worst case discharge, and to a substantial threat of such a discharge, of oil or a hazardous substance.” 33 U.S.C. § 1321(j)(5).
In 2019, the Natural Resources Defense Council filed suit in federal court, claiming that the EPA’s failure to issue the regulations required by § 311(j)(5), was a “failure to perform a non-discretionary duty or act in violation of the [CWA].” Complaint for Declaratory and Injunctive Relief, Environmental Justice Health Alliance for Chemical Policy Reform v. EPA, No. 1-19-cv-02516 (S.D.N.Y. Mar. 21, 2019). The plaintiffs and EPA resolved the litigation through the entry of a consent decree requiring EPA, by March 12, 2022, to sign a notice of proposed rulemaking relating to FRPs for CWA hazardous substances. EPA’s proposed rule reportedly satisfies EPA’s first obligation under the consent decree, with EPA’s second obligation being to sign a notice taking final action within 30 months after publication of the proposal.
Applicability of the Proposed Rulemaking
The proposed rule would apply to onshore non-transportation-related facilities “that could reasonably be expected to cause substantial harm to the environment by discharging CWA hazardous substances into or on the navigable waters, adjoining shorelines, or exclusive economic zone.” EPA proposes two screening criteria and four substantial harm criteria.
First, the facility must determine whether the maximum capacity onsite for any CWA hazardous substance meets or exceeds 10,000 times the reportable quantity (RQ) in pounds. EPA has designated a RQ for each of the approximately 300 CWA hazardous substances (i.e., the quantity above which a discharge to a navigable water of a CWA hazardous substance must be federally reported). The RQ is not the same for every CWA hazardous substance. In many instances, the RQ is 5,000 pounds, but for other substances, the RQ may be as low as 10 pounds (e.g., benzene) or even one pound (e.g., PCBs). Facility owners should determine the RQ of CWA hazardous substances on their sites to determine whether their facilities meet the first screening criteria of the proposed rulemaking.
Second, the facility owner or operator must determine whether the facility is within one-half (0.5) mile of a navigable water or a conveyance to a navigable water. This is an interesting criterion in that the definition of a “water of the United States” (i.e., a navigable water) has been heavily debated for more than a decade, with the Biden administration recently proposing a new definition and the U.S. Supreme Court expected to opine on the appropriate test to evaluate the existing definition during this term. More information on the definition of “waters of the United States” can be found here.
If these two screening criteria are met, the owner or operator of the facility would be required to determine whether the facility meets any of four substantial harm criteria: (1) the ability to adversely impact a public water system; (2) the ability to cause injury to fish, wildlife, and sensitive environments; (3) the ability to cause injury to public receptors; and/or (4) having a reportable discharge of a CWA hazardous substance within the last five years.
If any of these substantial harm criteria are met, the facility would be required to submit a CWA hazardous substance FRP to the EPA. Existing facilities that meet the criteria on the effective date of the rulemaking would be required to submit a FRP to EPA within 12 months of the effective date.
Environmental Justice and Climate Change Considerations
Consistent with the priorities of the Biden administration, EPA is seeking comments on ways to prioritize the needs of communities with environmental justice concerns and considerations related to climate change as part of this rulemaking. EPA stated that the proposed rulemaking was “inherently a climate change adaptation regulation” because it requires planning for worst case discharges in adverse weather conditions. EPA is also seeking comments on “methodologies to take climate change into account in both applicability criteria as well as response plan requirements.” With regard to communities with environmental justice concerns, EPA is proposing to allow “wide authority” to require CWA hazardous substance FRPs for facilities located in these communities.
The EPA is accepting public comment on the proposed rule until May 27, 2022. More information about EPA’s proposed rule can be found on EPA’s website here.
For more information on how the proposed rule may affect your business operations, please contact Lisa M. Bruderly at (412) 394-6495 or lbruderly@babstcalland.com or Mackenzie Moyer at (412) 394-6578 or mmoyer@babstcalland.com.
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[1] A facility meets the “substantial harm” threshold regarding oil discharges if it: (1) has a total oil storage capacity greater than or equal to 42,000 gallons and it transfers oil over water to/from vessels; or (2) has a total oil storage capacity greater than or equal to 1 million gallons and meets one of the four criteria identified in 40 C.F.R. § 112.20(f).
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Smart Business
(By Sue Ostrowski featuring Kevin Wills)
As the deal market has heated up, the timeline for transactions has contracted, with deals being negotiated and closed in as few as 30 days.
“Transaction timelines are being compressed, and that has an impact on both buyers and sellers when completing a transaction,” says Kevin T. Wills, a shareholder in the Corporate and Commercial and Emerging Technologies groups at Babst Calland. “Compressed deal timelines are likely here to stay, at least for the foreseeable future, and buyers and sellers must be prepared to hit the ground running when considering a transaction.”
Smart Business spoke with Wills about how deal timelines have shrunk and the impact that is having in the deal-making space.
How have compressed deal timelines impacted buyers?
Buyers have less time to review a deal and conduct due diligence before making a determination with respect to closing, potentially forcing them to take on more risk than they previously would.
It is very much a seller’s market, both in the business and real estate deal space, and sellers are regularly in a position to move on to the next potential bidder if they don’t like the proposed deal terms. Buyers are offering compressed timelines and other concessions to be more attractive to sellers to give themselves a leg up on competitors and secure deals.
In order to mitigate the risk associated with compressed deal timelines, some buyers are starting due diligence while negotiating the purchase agreement, spending money on third-party reports to help manage the timeframe, but those are dollars lost if you can’t come to an agreement.
A risk associated more with real estate transactions specifically is that there are regularly deposits that become nonrefundable at the end of the due diligence period and, if a buyer’s third-party reports will not be completed timely, buyers run the risk of having their deposit become nonrefundable before their diligence is complete, forcing them to decide whether to put their deposit at risk or terminate the purchase agreement.
Buyers can ask for extensions, but that can be difficult if you made your pitch based on an expedited closing. However, sellers may agree to an extension, as opposed to forcing the buyer to terminate the purchase agreement and starting over with a new potential buyer.
Additionally, buyers are offering purchase agreements that are much more middle of the road and taking advantage of the increased availability of representations and warranties insurance in order to streamline negotiations and help shorten deal timelines.
What is the impact of compressed timelines on sellers?
Sellers need to be able to meet the timeline themselves. Sellers must be prepared and have their house in order. The more information a seller can gather in advance, the smoother the transaction will flow.
Compressed deal timelines add additional stress to sellers as well, as they have to wear two hats throughout the process. Sellers have to run the day-to-day operations of the business while also trying to facilitate a sale. The compressed timeline can lead to the seller being inundated with due diligence inquiries and follow-up questions that might have been more spread out with a longer due diligence period — which can lead to deal fatigue setting in faster than it might otherwise.
What role do outside advisers play?
Outside advisers are extremely helpful to both buyers and sellers. Experienced attorneys, accountants and investment bankers/brokers can help a seller determine what it needs to do to prepare the business for sale, determine the transaction structure, clean up its books and records and gather competitive bids. Additionally, an experienced attorney who is familiar with the business and the market is critical for both buyers and sellers in facilitating the transaction process more efficiently.
It can be a risky time to be a buyer, but if you hesitate, the deal may be gone.
To view the full article, click here.
To view the PDF, click here.
GO-WV News
(By Mychal Schulz)
After many years of attempting to pass legislation to allow for efficient unitization of mineral interests for production purposes, the West Virginia Legislature passed Senate Bill 694 in the last week of the recent legislation session, which Governor Justice is expected to sign. The legislation represents a compromise between producers, mineral owners, and surface owners, including the agricultural sector.
As technology drove producers towards increased use of horizontal drilling, West Virginia struggled to modernize its code to allow the combination or “pooling” of mineral interests within a defined area (or “unit”) that would allow the efficient drilling for oil or natural gas through horizontal wells. Prior efforts in West Virginia usually foundered upon how to deal with mineral owners who either refused to agree to the “pooling” of their minerals into a larger “unit” or who could not be located. As a result, a single mineral owner could prevent the formation of a larger “unit” for drilling, which drove up costs and resulted in less efficient extraction of the minerals.
Many months of stakeholder negotiations resulted in SB 694, which passed with minimal changes or opposition in the Senate and House.
SB 694 adds a new article to the West Virginia Code beginning at §22C-9-1, which includes a description of the public policy addressed by the legislation. Not surprisingly, the statute declares that the Legislature “finds that horizontal drilling is a technique that effectively and efficiently recovers natural resources and should be encouraged as a means of production of oil and gas[.]” Notably, however, in addition to identifying the “development, production, utilization, and conservation of oil and gas resources by horizontal drilling in deep and shallow formations” as in the public interest, the statute also recognizes the desire to “[s]afeguard, protect, and enforce the property rights and interests of surface owners and the owners and agricultural users of other interests in the land.” See §22C-9-7a(a).
Per §22C-9-7a(c), to obtain a horizontal well unit order from the Oil and Gas Conservation Commission, a producer must meet three conditions related to (1) a benchmark of royalty interests, (2) a benchmark of operator interests; and (3) negotiations with all mineral owners within the proposed unit.
First, as to royalty interests, a producer may obtain a unit order upon getting consent from the mineral interest owners of 75% or more of the “net acreage in the target formation to be included in the horizontal well unit[.]” The mineral interest owners include traditional royalty owners, “executive interest” owners, and “unknown and unlocatable interest owners.” Under this formula, therefore, a producer may utilize §55-12A-1, et al., (unknown heirs) or §37B-1-1, et al. (co-tenancy), to add acreage to get to the 75% participation threshold. §22C-9-7a(c)(2)(A).
Second, as for operator interests, a producer must control, by ownership, lease, or otherwise, “55% or more of the net acreage in the target formation proposed to be included in the horizontal well unit,” which threshold applies to both shallow and deep horizontal wells. §22C-9-7a(c) (2)(B).
Finally, the statute requires that a producer make “good faith offers to consent or agree to pool or unitize” to mineral owners and negotiate “in good faith” with all “known and locatable royalty owners having executory interests in the oil and gas” within the proposed unit, even those whose interests are not subject to development under §37B-1-1, et seq. §22C-9-7a(c)(2)(C).
Notably, for purposes of determining if these conditions have been met, the Commission may not consider overriding royalty owners, nonexecutive interest royalty owners, or acreage owned or held by unleased, unknown, and unlocatable interest owners whose acreage is not subject to development per §37B-1-1, et seq. In addition, acreage held by other operators within the proposed unit may not be included in the calculation of the thresholds unless such operators have consented or otherwise agreed to develop their operator interest in the net acreage in the target formation proposed to be included in the horizontal well unit. §22C-9-7a(c)(3).
The statute specifies what must be included in a horizontal well unit order. See §22C-9-7a(f). Perhaps most notably, the statute specifies how non-consenting mineral owners whose minerals will be included in the order must be compensated by the operator. For example, an order must require that non-consenting mineral owners with valid leases, whose minerals are included within the horizontal well unit, must be paid an amount equal to (1) 25% of the weighted average monetary bonus on a net mineral acre basis of the bonuses, and (2) 80% of the weighted average production royalty percentage paid to other executive interest owners of leased tracts within the horizontal well unit. §22C-9-7a(f)(6).
On the other hand, non-consenting mineral owners without a valid lease must be given the choice to either (1) surrender their oil and gas within the tract in the unit in exchange for an amount equal to the weighted average amount paid, per net mineral acre, by the applicant to executive interest owners in the same target formation underlying the horizontal well unit; or (2) elect to participate in the unitization. §22C-9-7a(f)(7)(A) and (B). If the non-consenting mineral owner consents to participation in the unitization, the amounts paid must either be (1) on agreed upon terms, or (2) for a bonus payment equal to the average bonus paid to other mineral owners by the applicant within the unit, and a production royalty equal to the highest royalty rate in any lease to a mineral owner within the unit dated in the previous 24 months. §22C-9-7a(f)(7)(B)(i) and (ii). Notably, in lieu of this method of calculating a production royalty, non-consenting mineral owners without a valid lease may make a one-time election to be paid production royalties for natural gas based on either an index price as of the beginning of a month published in an independent publication or on the weighted average sale price. This election must be made before the Commission issues its unit order. §22C-9-7a(f)(7)(B)(ii). If this election is made, the non-consenting mineral owner without a valid lease must receive production royalties for natural gas liquids calculated, at the election of the applicant, based on either the index price or the weighted average sales price. Importantly, production royalties for natural gas liquids must be calculated “using the sum of the proceeds received at the tailgate of the processing facility for each natural gas liquid product during each month divided by the volume of such natural gas liquid product that was sold during such month and shall not be reduced by post-production expenses.” 22C-9-7a(f)(7)(B)(ii). Finally, any mineral owner who simply refuses to make an election under the statute will be considered to have elected to participate in the unit per §22C-9-7a(f)(7)(B).
The statute also contains provisions related to an operator whose interests are included within the proposed unit, including both consenting and non-consenting operators. §22C-9-7a(f)(9) and (10).
Notably, HB 694 received support from the West Virginia Surface Owners Rights Organization, in part, because it provides a mechanism by which surface owners may acquire the mineral interests of unknown and unlocatable interest owners in oil and gas underlying a horizontal well unit. Specifically, if an action under §55-12A-1, et seq., has not commenced, and the taxes are not delinquent, the applicant must inform the surface owner that the underlying interest of the unknown and unlocatable interest owners may obtained from the applicant pursuant to the process detailed in §22C-9-7a(o).
This article only highlights unique features of the new statute. Any operator or landowner affected by a potential unitization order is urged to carefully consult the statute for further details. For now, however, West Virginia finally has a unitization mechanism in place.
Click here, to view the article online in the April issue of GO-WV News.
Environmental Alert
(By Kevin Garber, Ben Clapp and Joe Yeager)
In an overhaul of reporting requirements 10 years in the making, the Securities and Exchange Commission on March 21, 2022 proposed far-reaching and controversial climate-related disclosure obligations for publicly-traded companies as part of the Biden administration’s emphasis on climate change. The SEC is proposing to force companies to formally disclose their exposure to and management of climate-related risks that are reasonably likely to have a material effect on their business, operations and financial condition. SEC’s goal is to provide investors with “consistent, comparable, and decision-useful information for making their investment decisions.” If finalized, the rule would require publicly-traded companies to provide climate-related financial references as notes to their audited financial statements and disclose their direct Scope 1 greenhouse gas emissions and their indirect Scope 2 GHG emissions. They also may have to disclose their upstream and downstream Scope 3 GHG emissions if they are material to the business or if they have established a GHG emissions target. Reporting obligations would begin in 2024 for large accelerated filers and be phased in for all covered companies by 2026.
Overview of the Proposed Rule
The proposed rule would add a new subpart to Regulation S-K of the SEC’s regulations (17 CFR Part 229) that would require a registrant to disclose climate-related risk information in its registration statements and periodic reports, such as on annual Form 10-K submissions and quarterly Form 10-Q reports. The proposed rule draws heavily from existing disclosure frameworks including the Task Force on Climate-Related Financial Disclosures (regarding climate-related reporting) and the Greenhouse Gas Protocol (regarding accounting standards). Key areas for disclosure include:
- the oversight and governance of climate-related risks by the registrant’s board and management;
- how any climate-related risks identified by the registrant have had or are likely to have a material effect on its business and consolidated financial statements;
- the registrant’s processes for identifying, assessing and managing climate-related risks, and how to integrate those processes into the company’s overall risk management;
- whether the company has adopted a transition plan to deal with climate-related risks and how to measure any physical or transition risks to its operations; and
- the effect of severe weather events and related natural conditions on the registrant’s consolidated financial statements, together with financial estimates and assumptions used in the financial statements.
The proposal requires registrants to disclose information about their Scope 1 and Scope 2 greenhouse gas emissions. Scope 1 refers to direct GHG emissions that occur from sources the registrant owns or controls, such as emissions from fuel combustion in the registrant’s boilers, furnaces, vehicles, and manufacturing activity. Scope 2 emissions are indirect GHG emissions from the generation of electricity, steam, heat, or cooling the registrant buys or acquires and consumes in its operations. Scope 2 emissions physically occur at the offsite point of generation but are accounted for in the registrant’s GHG inventory because they result from its energy use.
A registrant also would be required to disclose its Scope 3 GHG emissions from upstream and downstream activities in its value chain if material or if the registrant has set a GHG emissions target or goal that includes Scope 3 emissions. Scope 3 emissions result from activities and assets the registrant does not own or control but indirectly affects in its value chain, either upstream in the form of raw materials it buys to make its products and downstream as emissions from its customers’ use of its products. Sometimes referred to as “value chain emissions,” Scope 3 emissions often represent the majority of a company’s total GHG emissions. As a safe harbor, a Scope 3 emissions disclosure would not be considered to be a fraudulent statement unless it was shown to have been made without a reasonable basis or disclosed other than in good faith. SEC-defined smaller reporting companies (generally those with less than $100 million in annual revenue) would be exempt from disclosing Scope 3 emissions.
Issues for Comment and Clarification
The SEC is asking registrants to do a top to bottom review of their impact on climate, and while not mandating any changes to behavior, the agency apparently anticipates that by making this information available to investors, companies will attempt to reduce their GHG emissions. The SEC acknowledges that using financial statement metrics to estimate and disclose climate-related uncertainties is driven by judgment and assumptions, similar to other financial statement disclosures. Accordingly, for each type of financial statement metric, the proposed rule would require the registrant to disclose contextual information to enable a reader to understand how it derived the metric, including a description of significant inputs and assumptions used, and if applicable, policy decisions the registrant made to calculate the specified metrics.
The breadth of Scope 3 emissions reporting will be a key issue during the public comment period. Despite the safe harbor, it is unclear how companies should determine whether Scope 3 emissions from their upstream supply chain and from their downstream product life are “material” (and in particular which such emissions are material), and how that determination will align with current SEC requirements to disclose other material risks, defined as information a reasonable investor would consider important. The proposed rule also affects privately-held companies who will be asked by their publicly traded customers to estimate or account for their GHG emissions, something likely to be new to many privately-held organizations. Although intended to drive companies to become greener, the new required disclosures may burden companies with increased compliance costs and discourage private companies from going public.
Public Comment Period
The public comment period will be open for 30 days after publication in the Federal Register (which hasn’t happened as of the date of this Client Alert) or May 20, 2022, whichever is later. There is a phase-in period for all registrants as the rules are currently proposed. Deadlines for filing disclosures including Scope 1 and Scope emissions metrics range from filing year 2024 for FY 2023 (for large accelerated filers) to filing year 2026 for FY 2025 (for smaller reporting companies). Both publicly-traded and privately-held companies should review the SEC’s proposed rule and submit comments asking the SEC to revise or clarify the proposed rule as appropriate.
Babst Calland attorneys are closely following these and other climate-related developments. If you have questions or need additional information about SEC’s proposed rule on disclosure requirements, please contact Kevin Garber at 412-394-5404 or kgarber@babstcalland.com; Ben Clapp at 202-853-3488 or bclapp@babstcalland.com; or Joe Yeager at 412-394-5698 or jyeager@babstcalland.com.
To view the PDF, click here.
The American College of Environmental Lawyers (ACOEL)
(By Chester Babst)
In 2022, the on-going debate will continue over the hotly contested definition of “waters of the United States” (WOTUS), a phrase that determines the scope of federal jurisdiction over streams, wetlands and other waterbodies under the Clean Water Act (CWA). The WOTUS definition is included in 11 federal regulations and affects, among others, NPDES and Section 404 permitting, SPCC plans and spill reporting. This year, both the executive and judicial branches of the federal government are expected to weigh in on this definition, without any guarantee that their interpretations will be consistent.
Proposed Rule 1
USEPA and the Corps have already taken the first step to revise the WOTUS definition, as promised by President Biden during his campaign, by publishing a proposed rulemaking on December 7, 2021 (Rule 1). While this proposed definition is similar to the pre-2015 definition of WOTUS, which is currently in effect, it also reflects relevant Supreme Court decisions (e.g., Rapanos v. United States) that occurred in the early 2000s.
Much of the controversy surrounding the WOTUS definition relates to the two tests identified in the Rapanos decision. Justice Antonin Scalia issued the plurality opinion in Rapanos, holding that WOTUS would include only “relatively permanent, standing or continuously flowing bodies of water” connected to traditional navigable waters, and to “wetlands with a continuous surface connection to such relatively permanent waters.” Justice Anthony Kennedy, however, advanced a broader interpretation of WOTUS in his concurring opinion, which was based on the concept of a “significant nexus,” meaning that wetlands should be considered as WOTUS “if the wetlands, either alone or in combination with similarly situated lands in the region, significantly affect the chemical, physical, and biological integrity of other covered water.”
If promulgated, the December 2021 proposed WOTUS definition would incorporate Justice Kennedy’s significant nexus test into the regulations. Practically speaking, however, the impact is not expected to be significant because, in interpreting the current definition of WOTUS, the Corps has already largely been relying on its 2008 guidance, which reflects Justice Kennedy’s significant nexus concept.
Proposed Rule 2
A more expansive definition of WOTUS is expected when the Biden administration unveils its second proposed WOTUS rulemaking (Rule 2), planned for publication later this year. While the language of Rule 2 is currently unknown, as stated in the Fall 2021 Unified Agenda, Rule 2 is expected to reflect “additional stakeholder engagement and implementation considerations, scientific developments, and environmental justice values. This effort will also be informed by the experience of implementing the pre-2015 rule, the 2015 Clean Water Rule, and the 2020 Navigable Waters Protection Rule.” The effect of identifying federally-regulated waters based on concepts such as environmental justice and, potentially, climate change is uncertain. However, it is expected that this proposed definition will broaden the scope of WOTUS.
Sackett v. USEPA
In addition to the Biden administration’s planned changes to the WOTUS definition, the U.S. Supreme Court, in January 2022, signaled that it would, again, weigh in on the WOTUS debate, when it agreed to hear the case of Sackett v. USEPA. In Sackett, landowners in Idaho have had a long-standing challenge to an administrative order issued against them for allegedly filling wetlands without a permit. The Sacketts assert that Justice Kennedy’s significant nexus test in Rapanos is not the appropriate test to delineate wetlands as WOTUS, and that, under the test identified by Justice Scalia, the wetlands on their property are not WOTUS.
In 2021, the Ninth Circuit ruled against the Sacketts’ position and held that the “significant nexus” test in the Kennedy concurrence was the controlling opinion from Rapanos. The Sacketts petitioned the U.S. Supreme Court to consider whether Rapanos should be revisited to adopt the plurality’s test for wetland jurisdiction under the CWA. However, the Court, instead, will consider the narrow issue of whether the Ninth Circuit “set forth the proper test for determining whether wetlands are ‘waters of the United States.’”
The Supreme Court’s opinion as to whether the significant nexus test is the “proper test” for identifying WOTUS is expected to be very significant in future interpretations of WOTUS. In addition, this ruling could create direct conflicts and further uncertainty if the Court holds that the significant nexus test is not appropriate while the Rule 1 or Rule 2 regulatory definition incorporates the significant nexus test. One thing is clear: the seemingly never-ending debate over WOTUS is not going away anytime soon.
To view the full article, click here.
Reprinted with permission from the March 30, 2022 ACOEL Blog.
Firm Alert
(By Justine Kasznica and Ember Holmes)
On March 21, 2022, President Biden issued a statement in response to evolving intelligence that Russia is exploring options for malicious cyberattacks against the United States. The statement highlights the measures taken by the Administration to strengthen cyber defenses within the federal government and, to the extent that it has authority, within critical infrastructure sectors. Additionally, President Biden called on private sector critical infrastructure owners and operators to accelerate and enhance their cybersecurity measures, urging them to take advantage of public-private partnerships and initiatives, including those administered by the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA). Appended to President Biden’s statement was a Fact Sheet, which outlines specific steps that companies can take to bolster cybersecurity across the nation, and refers readers to various resources compiled by CISA, as part of a cybersecurity campaign.
Background
In November 2021, the Biden administration began ramping up its cybersecurity and defense measures in response to Russian President Vladimir Putin’s escalating aggression toward Ukraine. On January 11, 2022, CISA, the Federal Bureau of Investigation (FBI), and the National Security Agency (NSA) issued Alert AA22-011A, “Understanding and Mitigating Russian State-Sponsored Cyber Threats to U.S. Critical Infrastructure,” which provided an overview of Russian state-sponsored cyber operations; commonly observed tactics, techniques, and procedures (TTPs); detection actions; incident response guidance; and mitigations. The Biden administration, CISA, FBI, and NSA continued to monitor the level of risk posed by Russia, which recently escalated based on intelligence indicating that Russia is planning cyberattacks against the United States in response to economic sanctions that the United States has imposed.
What is Shields Up?
Shields Up is a cybersecurity campaign formed out of the combined efforts of CISA and the FBI to help organizations prepare for, respond to, and mitigate the impact of cyberattacks by Russia. Although the campaign is focused on critical infrastructure, CISA has emphasized that all organizations, regardless of sector or size, must be prepared to defend against and respond to disruptive cyber incidents.
On March 22, 2022, CISA hosted an Unclassified Broad Stakeholder Call to brief attendees on the escalating threat of cybersecurity attacks by Russia. Jen Easterly (Director of CISA), Matt Hartman (Deputy Executive Assistant Director of Cybersecurity of CISA), and Tonya Ugoretz (Deputy Assistant Director of the FBI Cyber Division) addressed attendees, focusing their comments on the Shields Up campaign, and highlighting most important actions that organizations can take to prevent, detect, and respond to possible cyberattacks. A condensed list of these actions includes:
- Familiarize yourself with your networks and actively patrol systems, including informational and operational technology, for perceived threats or unexpected events (identified TTPs, malware signatures, etc.);
- Regularly scan public-facing programs, systems, and software for vulnerabilities;
- Secure your systems and credentials by using complex passwords, two-factor authentication, encryption, patching, etc.;
- Maximize resilience to cyberattacks by strengthening security of operating systems, software, and firmware, and by scheduling automatic updates of these systems;
- Prepare a cyber incident response plan that includes FBI contact information for reporting, as well as contact information for an incident response firm and outside legal counsel; and
- Report any incidents immediately, and maintain a low threshold for reporting.
In addition to the foregoing broad, categorical guidance and advice, the Shields Up website has valuable resources to assist those in the private sector with the development and implementation of enhanced security measures. These resources include technical guidance, a catalog of known exploited vulnerabilities, a catalog of free cybersecurity services and tools provided by the federal government, a catalog of free cyber hygiene services, a ransomware guide, and many other preparedness and response resources.
Babst Calland attorneys are closely following these developments. If you have questions or need additional information, please contact Justine M. Kasznica at 412-394-6466 or jkasznica@babstcalland.com or Ember K. Holmes at 412-394-5492 or eholmes@babstalland.com.
To view the PDF, click here.
HART Energy
(By Gary Steinbauer and Sean McGovern)
Methane emissions are a chief concern across the oil and gas value chain. Gary Steinbauer and Sean McGovern, both shareholders with Babst Calland, discuss methane mitigation and how players in the energy space can best handle it in this three-part video.
In the first segment, Steinbauer discusses the Biden administration’s approach to methane emissions in the energy sector, including proposed regulatory changes in the EPA’s Methane Rule.
In the second segment McGovern discusses abandoned and orphaned wells, how they are being plugged, and the help that operators can receive from the Bipartisan Infrastructure Law that passed in 2021.
In the final segment, both attorneys offer step-by-step advice to operators in Appalachia trying to navigate a slew of updated regulations.
View the three-part video, here.
Renewables Law Blog
(By Bruce Rudoy)
While long term goals of lowering greenhouse gas emissions and employing sustainable energy sources have gained momentum across all industries, Chevron Corp., through its New Energies division, has stated it has shorter term goals as well – it says its planned growth in renewable fuels, hydrogen and carbon capture is expected to enable about 30 million tones of annual CO2 equivalent emission reductions by 2028. Technology adoption, policy and consumer behavior will drive energy choices, says a top sustainability executive, as companies focus on carbon management along the path to net zero. All three factor into whether one form of energy or another is sought to supply demand created by income and population growth, according to Bruce Niemeyer, vice president of strategy and sustainability for Chevron Corp. “Keeping supply and demand balanced through the transition is important so the transition works for all and doesn’t become a negative event for those most vulnerable,” Niemeyer said earlier this month during UT Energy Week. He added, “We’re going to need many forms of energy, which means we need to work on reducing the carbon intensity of all of them.” Chevron is among the many companies working to lower its emissions amid a heightened focus on global warming and future energy supplies. Like the smartphone, technologies with features that meet consumers’ needs or low-cost technologies will gain market share, he said, noting consumer preference is a strong factor. Take, for example, the automotive sector. EVs are expected to play a key role in the energy transition, giving their lower emissions, compared to vehicles with internal combustion engines. However, “last year, our best estimate is there were 6.6 million electric vehicles sold. At the same time, there were 35 million SUVs. It doesn’t mean it will be that way forever, but consumer preferences are strongly important to how energy is demanded by the world and then the choices of whether it’s provided from one form or another.” Most consumers do not appear willing to give up their gasoline-fueled vehicles, however, falling electric vehicle (EV) prices with improved battery technology are contributing to an uptick in sales. Citing data from Wards Intelligence, the U.S. Energy Information Administration said in February that hybrid, plug-in hybrid, and EVs collectively accounted for 11% of light-duty vehicle sales in the United States in fourth-quarter 2021. Several countries and automakers have set ambitions to increase EV sales, including in the U.S. where there is a target of 50% EV sales share in 2030.
Like many of its peers, Chevron is advancing technologies to reduce the carbon intensity of its operations. Its targets include a 35% reduction in upstream CO2 intensity by 2028, a more than 5% reduction in its portfolio carbon intensity by 2028 and net-zero Scope 1 and Scope 2 emissions by 2050. Chevron’s 2030 new energies targets also include producing 150 ktpa in hydrogen, which Niemeyer said could be used to decarbonize the heavy-duty transportation sector; and 25 MMtpa in carbon capture and offsets. The company has formed several partnerships, including with Hydrogenious, a developer of liquid organic hydrogen carrier technology. Speaking during Chevron’s analyst day in March, Chief Technology Officer Eimear Bonner said the technology could deliver affordable and efficient storage and transport of hydrogen. The company has said its planned growth in renewable fuels, hydrogen and carbon capture to these shorter term goals is expected to enable CO2 equivalent emission reductions by 2028.
View the full article here: Chevron Exec Shares Insight on Energy Transition, Oil Major’s Strategy | Hart Energy.
Tags: carbon capture, emission reductions, Hydrogen, renewable energy
Marley R. Kimelman recently joined Babst Calland as an associate in the Environmental Group. Mr. Kimelman assists clients with matters encompassing a broad range of environmental issues, including those related to state and federal permitting, regulatory compliance, and environmental litigation.
Prior to joining the Firm, Mr. Kimelman worked as an Environmental, Health, and Safety Regulatory Consultant at Enhesa, Inc. In this role, he was responsible for analyzing federal and state EHS regulations and drafting legal compliance reports used to advise clients on a course of action to achieve regulatory compliance. Mr. Kimelman is a 2021 graduate of George Washington Law School.
Environmental Alert
(By Robert Stonestreet, Kip Power and Ben Clapp)
During its 2022 60-day Session, the West Virginia Legislature took action to promote development of “rare earth element” recovery in the state, although it failed to deliver on all of the proposed legislative action on the last day of the Session.
On March 10, 2022, the Senate unanimously approved House Bill 4003, which is intended to clarify the ownership of rare earth elements present in mine drainage. The bill creates a new section of the West Virginia Abandoned Mine Lands Act, addressing valuable materials (not limited to rare earth elements) that may be produced through treatment of mine drainage. The new statute declares that these materials are part of the “waters of the state” and that they “can only be separated from the water with expensive and continuing investments of resources which may last for decades.” The new statute provides that any materials extracted through treatment of mine drainage “which have economic value” may be used, sold, or transferred for commercial gain by whoever successfully removes the materials from the mine drainage. To the extent the West Virginia Department of Environmental Protection is engaged in such activity through its mine drainage treatment activities, any proceeds the agency derives from the use, sale, or transfer of extracted materials must be deposited in the Special Reclamation Water Trust Fund or the Acid Mine Drainage Set-Aside Fund. Governor Jim Justice is expected to sign the bill into law.
A related bill that would have suspended for five years the severance tax on recovery of specifically identified rare earth elements (House Bill 4025) failed to complete legislative action before the end of the Session. On Friday March 11, 2022, the Senate amended the bill to include an unrelated change to the taxing authority of county governments. The Senate amendment would authorize county governments to impose up to a two percent “admission or amusement tax upon any public amusement or entertainment conducted within the limits of the county for private profit or gain.” During the final hour of the Session late on Saturday night, the House debated the procedural merits of coupling the “amusement tax” amendment to the severance tax bill, as well as the merits of the amendment itself. According to comments made by House members during debate, the genesis of the Senate amendment was a desire by Tucker County, West Virginia to impose a tax on skiing activity and other outdoor recreation to raise money to improve emergency services in the county. The large number of visitors to Tucker County has, according to certain lawmakers, placed a strain on emergency services in the area. The county also claimed an inability to raise additional money through property taxes due to a large percentage of the land in the county being owned by the state or federal governments. Ultimately, the House rejected the Senate’s amended version of the bill by a vote of 76 to 21, with some legislators referring to the Senate amendment as a “tax on fun.” The Senate did not take further action in response to the House vote before midnight.
As detailed in a prior Alert, the federal Department of Energy will soon be awarding hundreds of millions of dollars in funding associated with research, recovery, and refining of various “critical materials” including rare earth elements. Application opportunities for the various grants under the federal Infrastructure Bill are projected to begin opening in the fall of 2022.
Babst Calland has a team of lawyers following state and federal activities related to rare earth element development opportunities and implementation of the Infrastructure Bill. Please contact any of the following attorneys to learn more: Robert M. Stonestreet at rstonestreet@babstcalland.com or 681.265.1364; Christopher B. “Kip” Power at cpower@babstcalland.com or 681.265.1362; or Ben Clapp at bclapp@babstcalland.com or 202.853.3488.
To view the PDF, click here.
Ember K. Holmes and Audra E. Hutter recently joined Babst Calland as associates in the Corporate and Commercial Group.
Ember Holmes focuses primarily on corporate and transactional matters, including commercial contracts, corporate structuring, mergers and acquisitions, and copyright and trademark issues. Prior to joining Babst Calland, she was an associate with Dickie, McCamey & Chilcote, P.C. Ms. Holmes is a 2018 graduate of the University at Buffalo School of Law.
Audra Hutter focuses primarily on corporate and transactional matters, including commercial contracts, corporate structuring, mergers and acquisitions. Prior to joining Babst Calland, she was an associate with Leech Tishman Fuscaldo & Lampl, LLC. Ms. Hutter is a 2019 graduate of the University of Pittsburgh School of Law.