Energy Alert
(By Tim Miller, Jennifer Hicks and Austin Rogers)
The Fourth Circuit Court of Appeals released its decision in Corder, et al. v. Antero Resources Corp., No. 21-1715 (4th Cir. January 5, 2023) (https://www.ca4.uscourts.gov/opinions/211715.P.pdf), a dispute over royalties owed for the sale of gas and natural gas liquids (“NGLs”). In its opinion, the Fourth Circuit made several important rulings regarding the ongoing application of West Virginia’s seminal oil and gas royalty case, Estate of Tawney v. Columbia Natural Resources, LLC, 219 W. Va. 266, 633 S.E.2d 22 (2006) (“Tawney”).
The Court first explained that Tawney applies to all leases that calculate royalties “at the well,” including both “market value” and “proceeds” leases. The Court noted that the West Virginia Supreme Court of Appeals’ recent decision in SWN Prod. Co. v. Kellam, 875 S.E.2d 216 (W. Va. 2022) (“Kellam”) did not support the lessee’s argument that Tawney is solely restricted to proceeds leases. Corder at 16.
The Court further rejected the lessee’s argument that even where a lease is silent as to the deduction of post-production costs, Tawney does not apply to costs incurred after oil or gas becomes marketable but before the point of sale. The Court analyzed whether Tawney or any other West Virginia authority supported the argument that once gas reaches the point where it is first marketable, the presumption that the lessee bears all post-production costs no longer applies, and deductions can be taken for costs incurred between the point where it is first marketable and the point of sale. The Court concluded that although the Kellam court recently characterized the marketable product rule as narrower than the “point of sale,” when it stated that under the marketable product rule, “the lessee bears all post-production costs incurred until the product is first rendered marketable,” the Fourth Circuit was unable to ignore the express “point of sale” language in the syllabus points in Wellman, Tawney, and Kellam. The Court acknowledged that the existing West Virginia authorities do not specifically relate to NGLs and whether post-production costs may be deductible after a product first becomes first marketable but before the point of sale, but noted that Wellman and Tawney only use language about the point of sale and “[b]ecause the West Virginia Supreme Court has not adopted a contrary rule, we conclude that the Tawney requirements apply through the point of sale.”
Finally, and most importantly, the Court ruled that certain market enhancement provisions are sufficient to meet the requirements of Tawney, albeit the Court disagreed with both the lessors and the lessees in Corder regarding the meaning of the specific provisions in their leases. In Corder, some of the leases included a market enhancement clause that specified the producer must cover the costs to “transform the product into marketable form” but permitted deduction of the costs from royalties if they “result in enhancing the value of the marketable oil, gas or other products to receive a better price.” See Corder at 24 (emphasis in original). The lessors argued, and the lower court agreed, that the clause was ambiguous and did not satisfy Tawney’s specificity requirements. The Fourth Circuit disagreed, finding the leases were not ambiguous and satisfied Tawney, though they did not have the meaning lessee believed. The Court reasoned the market enhancement clause at issue specifically states it applies to marketable products and not unprocessed gas. Lessee argued that it was entitled to deduct post-production costs after unprocessed gas first becomes marketable, but the Court held the lease language unambiguously states it only applies to value achieved after a product becomes marketable and had Lessee “instead wished to make the marketability of ‘unprocessed gas’ the reference point, it should have said so.” See Corder at 26. The Court acknowledged that the parties’ dispute centered on NGLs, which the market enhancement clauses at issue did not expressly mention, but explained that even if NGLs are a form of “gas” rather than “other product,” the clause “is concerned when the particular gas product actually sold by the Lessee reaches a marketable form.” Corder at pg. 26 note 10 (emphasis added). Thus, the Court concluded that the determination of when and where the specific NGL products sold by the Lessee became marketable and whether the value was enhanced is a factual issue and remanded this limited question for further proceedings.
Also important, in what appears to be a confirmation of their decision in Young, the Fourth Circuit further rejected the Lessors’ argument that the market enhancement clause fails to meet Tawney’s “particularity” requirement and noted that Kellam did not establish a hard and fast rule for determining what language passes the Tawney test, confirming their reasoning that no particular degree of detail is needed to satisfy Tawney if the intent of the parties to allow deductions is clear. Corder at page 28.
Finally, the Court affirmed the District Court’s dismissal of the lessors’ fraud and punitive damage claims, concluding that the pleadings failed to satisfy the particularity requirements of Rule 9. The Court also noted that the District Court had dismissed the claims based on the Gist of the Action doctrine and, while that decision did not need to be reviewed based on the Rule 9 dismissal, the Court stated that application of the Gist the Action doctrine “seems well supported.” Corder at 34 note 12.
For further analysis and discussion, please contact Tim Miller at (681) 265-1361 or tmiller@babstcalland.com or Jennifer Hicks at (681) 265-1370 or jhicks@babstcalland.com.
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Environmental Alert
(By Lisa Bruderly)
The definition of “waters of the United States” (WOTUS) determines federal jurisdiction under the Clean Water Act (CWA). It affects U.S. Army Corps of Engineers (Corps) permitting for impacts from crossing, or otherwise disturbing, federally regulated streams and wetlands, as well as NPDES permitting, federal spill reporting and SPCC plans.
As one of their last actions for 2022, U. S. EPA and the Corps (the Agencies) released a pre-publication notice of a new definition of WOTUS on December 30, 2022. The new definition will become final 60 days after publication in the Federal Register. The definition was originally proposed in a December 7, 2021 rulemaking.
Although the Agencies have promoted this final rule as establishing a “durable definition” that will “reduce uncertainty” in identifying WOTUS, this definition does not appear to provide much-needed clarity. Rather, generally speaking, the new definition codifies the approach that the Agencies have already been informally utilizing, which entails relying on the definition of WOTUS from the late 1980s, as interpreted by subsequent U. S. Supreme Court decisions (e.g., Rapanos v. United States, 547 U.S. 715 (2006)). The Agencies reverted back to this definition in August of 2021, when the U.S. District Court for the District of Arizona vacated the definition of WOTUS promulgated by President Trump’s administration, referred to as the Navigable Waters Protection Rule.
The Agencies’ current approach to interpreting WOTUS relies heavily on both of the frequently discussed tests identified in the Rapanos decision. In Rapanos, Justice Antonin Scalia issued the plurality opinion, 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” (i.e., adjacent wetlands). 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.”
President Biden’s new definition directly quotes and codifies these tests as regulations that may be relied upon to support a WOTUS determination. Publication of this definition, at this time, is likely a preemptive move by the Agencies in advance of the Supreme Court’s impending decision in Sackett v. EPA, a case in which the Court is considering whether the Ninth Circuit “set forth the proper test for determining whether wetlands are ‘waters of the United States.’” Some have speculated that the U. S. Supreme Court’s opinion may support a more narrow interpretation of WOTUS than is currently being implemented by the Agencies. If true, this inconsistency would create even more uncertainty in identifying WOTUS.
While this new WOTUS definition may not, conceptually, be a significant change to how the Agencies approach federally regulating streams and wetlands, the new definition could expand how the Agencies evaluate whether a wetland is “adjacent” to a WOTUS and whether a waterbody will “significantly affect” a WOTUS, both of which would support federal jurisdiction of the stream/wetland. The preamble to the new definition includes lengthy discussion regarding adjacent wetlands. In addition, the new definition of “significantly affect” enumerates five factors to be assessed and five functions to be considered in evaluating whether a potentially unregulated water will have a “material influence” on a traditionally navigable water. Factors include distance from the traditionally navigable water, hydrologic factors (e.g., frequency, duration, magnitude of hydrologic connection) and climatological variables (e.g., temperature and rainfall). Functions include contribution of flow, retention and attenuation of runoff and provision of habitat and food resources for aquatic species in traditionally navigable waters. Both the factors and the functions are broad and open to interpretation, which could, arguably, provide the Agencies with additional justification for asserting federal jurisdiction over more waterbodies.
The new definition also codifies that the effect of the potentially regulated water must be evaluated “alone or in combination with similarly situated waters in the region,” which will likely broaden how the Agencies evaluate the potential regulation of ephemeral and isolated waterbodies.
If the fate of the new WOTUS definition follows the same path as President Obama’s Clean Water Rule and President Trump’s Navigable Waters Protection Rule, the new definition will be challenged quickly after it becomes effective. These challenges may result in the stay or vacatur of the new definition. If this occurs, the Agencies may, again, revert back to the current definition of WOTUS.
As a final note, while the Biden administration originally indicated that it would undertake a second rulemaking to advance another, more expansive definition of WOTUS following the finalization of this new definition, the December 30, 2022 notice does not mention this potential second proposed WOTUS rulemaking, raising uncertainty as to whether a second rulemaking is still contemplated.
Anyone whose activities may cause impacts to a waterbody or wetland, including land developers and those in the aggregates and energy industries should watch these developments so that they understand how the WOTUS definition may be interpreted and how it may affect their permitting strategies. Babst Calland will continue to follow these and other Clean Water Act developments. If you have any questions about these developments, contact Lisa Bruderly at 412-394-6495 or lbruderly@babstcalland.com.
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Updated Firm Alert
(by Justine Kasznica, Susanna Bagdasarova and Gina Falaschi)
On November 14, 2022, the Department of Defense (DoD), General Services Administration (GSA), and National Aeronautics and Space Administration (NASA) published a proposed Federal Acquisition Regulation (FAR) rule that would require certain federal suppliers to annually disclose their greenhouse gas (GHG) emissions and climate-related financial risks, as well as set GHG emissions reduction targets, on an annual basis. 87 Fed. Reg. 68,312 (Nov. 14, 2022) (Proposed Rule). The Proposed Rule entitled the “Federal Supplier Climate Risks and Resilience Rule” implements President Biden’s Executive Order 14030, directing a number of federal agencies to take action to address climate-related risks and the Administration’s push toward net-zero emissions procurement by 2050.
The Proposed Rule would introduce a new FAR subpart 23.XX containing mandatory GHG emissions[1] disclosure and reporting requirements for major federal suppliers, which are divided into “significant” and “major” contractors for purposes of the applicable requirements. “Significant contractors,” defined as federal contractors receiving at least $7.5 million but less than $50 million in federal contract obligations in the prior fiscal year, must conduct a GHG inventory of their annual Scope 1[2] and Scope 2[3] emissions and report the total annual emissions in the System for Award Management (SAM). “Major contractors,” defined as federal contractors receiving more than $50 million in federal contract obligations in the prior fiscal year, are subject to the same requirement with respect to Scope 1 and Scope 2 emissions and must also conduct and report the results of a GHG inventory of their annual Scope 3[4] emissions.
Major contractors are also required to use the Carbon Disclosure Project (CDP)[5] Climate Change Questionnaire annually to complete a publicly available disclosure of their Scope 1, Scope 2, and Scope 3 emissions as well as their climate risk assessment process and any risks identified. In addition, major contractors must identify and publicly disclose science-based targets to reduce their GHG emissions.
Under the proposed regulatory framework, a federal supplier is presumed to be nonresponsible (and therefore ineligible for contract awards) until the relevant contracting officer confirms that the contractor has (itself or through its immediate owner or highest-level owner, as defined in the FAR), complied with the applicable requirements of the Proposed Rule.
Certain entities are exempted from the Proposed Rule’s reporting and disclosure requirements, including higher education institutions, nonprofit research entities, state or local governments and federal management and operating (M&O) contractors which derive at least 80 percent of their annual revenue from such M&O contracts. Additionally, if a major contractor qualifies as a “small business” or is a nonprofit organization, it is subject only to the reporting requirements of a significant contractor. The requirements may also be waived by the Senior Procurement Executive for emergencies, national security, or other mission essential purposes.
Significant and major contractors will be required to report Scope 1 and Scope 2 emissions one year following the publication of the final rule. Major contractor requirements to disclose Scope 3 emissions, climate-related risks, and science-based targets begin two years following the publication of the final rule.
If this Proposed Rule is finalized, many companies with government contracts, particularly small businesses, will be required to calculate and report GHG emissions and climate-related financial information for the first time. Preparations of such disclosures is costly and may require the hiring of new personnel or outside contractors to complete calculations and compile and organize information. In addition, companies without government contracts may be asked by customers or suppliers with government contracts to estimate or account for their GHG emissions as part of the supply chain. Finally, public disclosure of climate-related financial information could subject companies to litigation risk by shareholders, investors, or non-governmental organizations.
DoD, GSA, and NASA will accept comments on the Proposed Rule until January 13, 2023 (extended to February 13, 2023) on the Federal e-rulemaking portal (www.regulations.gov). If you have any questions about the Proposed Rule or submission of comments, please contact Justine M. Kasznica at (412) 394-6466 or jkasznica@babstcalland.com, Susanna Bagdasarova at (412) 394-5434 or sbagdasarova@babstcalland.com or Gina N. Falaschi at (202) 853-3483 or gfalaschi@babstcalland.com.
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[1] GHG is defined to include carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, nitrogen trifluoride, and sulfur hexafluoride.
[2] “Scope 1” emissions are GHG emissions from sources that are owned or controlled by the reporting company.
[3] “Scope 2” emissions are GHG emissions associated with the generation of electricity, heating and cooling, or steam, when these are purchased or acquired for the reporting company’s operations but occur at sources other than those owned or controlled by the entity.
[4] “Scope 3” emissions are GHG emissions that are a consequence of the operations of the reporting entity but occur at sources other than those owned or controlled by the entity.
[5] The CDP is a nonprofit organization that runs a disclosure system for companies, cities, states, and regions to manage environmental impact and scores these entities based on questionnaires submitted.
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Environmental Alert
(by Matt Wood)
On December 15, 2022, the U.S. Environmental Protection Agency (EPA) published a final rule amending its All Appropriate Inquiries (AAI) Rule to incorporate ASTM International’s E1527-21 “Standard Practice for Environmental Site Assessments: Phase I Environmental Site Assessment Process” (Final Rule).1 The Final Rule – effective February 13, 2023 – allows parties conducting due diligence to utilize the E1527-21 standard to satisfy the AAI requirements under the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), for the purpose of obtaining liability protections when acquiring potentially contaminated properties. Specifically, “bona fide prospective purchasers,” “contiguous property owners,” and “innocent landowners” can potentially obtain CERCLA liability protection by complying with the AAI Rule. More broadly, however, other regulating bodies, such as states, often require or recommend using the E1527 standard for evaluating potentially contaminated properties prior to purchase.
The Final Rule’s publication ends months of speculation and confusion about when and how EPA would address E1527-21 and its prior version, E1527-13. After ASTM issued E1527-21 in November 2021, EPA published an applicable direct final rule (and accompanying proposed rule, requesting comments on the direct final rule) in March 2022 incorporating E1527-21 into the AAI Rule, but also allowing parties to continue to use E1527-13 to satisfy AAI requirements. Many commenters opposed this approach, predicting confusion about which standard to use and pointing out that ASTM would eventually do away with E1527-13. In response to these comments, EPA withdrew the direct final rule in May 2022. The Final Rule addresses these concerns by removing the AAI Rule’s reference to the E1527-13 standard one year from the Final Rule’s publication in the Federal Register, i.e., December 15, 2023. Until then, any Phase I Environmental Site Assessment (ESA) conducted using E1527-13 will be considered compliant under the AAI Rule.
Among its many updates, E1527-21 adds definitions for certain terms (e.g., “significant data gap”) and updates other definitions for clarity and consistency (e.g., “recognized environmental condition”); it explains how long a Phase I ESA remains viable (no more than 180 days prior to property acquisition, or up to one year if certain components are updated); and expands the scope of the subject property’s historical review to include adjoining properties. One of the most notable and potentially significant updates is E1527-21’s discussion of “emerging contaminants,” or “substances not defined as hazardous substances under CERCLA,” which includes discussion of how and whether to address per- and polyfluoroalkyl substances (PFAS).
Specifically, E1527-21 categorizes PFAS and emerging contaminants not identified as hazardous under federal law as outside the scope of the E1527-21 standard. E1527-21 notes, however, that when such substances are defined as hazardous under applicable state law, and a Phase I ESA is being performed to satisfy federal and state requirements, analysis of such substances may be addressed in the Phase I ESA as “Non-Scope Considerations.” Non-Scope Considerations are potential environmental conditions at a property that might not give rise to CERCLA liability but may be relevant to a potential purchaser’s decision to acquire the subject property. Based on property-specific factors, a potential purchaser may also direct the environmental professional conducting the Phase I ESA to include analysis of PFAS or other emerging contaminants to provide a more fulsome understanding of potential risks associated with the subject property. Importantly, E1527-21 advises that when an emerging contaminant is designated a CERCLA hazardous substance, that contaminant must be evaluated within the scope of the Phase I ESA.
One commenter to the March 2022 direct final rule and proposed rule said that the emerging contaminants section threatened to lead to premature CERCLA liability for landowners and prospective buyers and requested a formal notice and comment period for the E1527-21 standard. Other commenters requested specific modifications to certain E1527-21 defined terms. In response, EPA noted in the Final Rule that E1527-21 is not an EPA regulation that it has authority to modify and that such requests should be directed to ASTM for consideration. Further, EPA said that because use of the E1527-21 standard is not required for complying with the AAI Rule, i.e., compliance can be achieved using other methods, the agency found no reason not to recognize E1527-21 as compliant with the AAI Rule. EPA’s response to comments document is available here.
With respect to PFAS, the timing of the Final Rule’s publication is particularly relevant to parallel rulemaking. In September 2022, EPA published a proposed rule designating PFOA and PFOS – the most common and well-studied PFAS – as CERCLA hazardous substances. The comment period for that proposed rule ended on November 7, 2022, and the final version is expected to be published in 2023. If EPA designates PFOA and PFOS as CERCLA hazardous substances as expected, they will fall within the scope of E1527-21. The same will apply to any other PFAS that EPA designates as CERCLA hazardous substances, which the agency has indicated it is considering via a future rulemaking.
Although many states have been regulating PFAS for years under various regulatory programs, similar efforts by the federal government are more recent. In addition to the Final Rule and the anticipated PFOA and PFOS CERCLA hazardous substance rule, EPA is also in the process of developing a proposed national drinking water regulation for PFOA and PFOS and is also considering regulatory actions to address other PFAS. These changes and others likely to occur in the coming months and years underscore the importance of understanding the various risks associated with PFAS contamination and how to comply with current and forthcoming requirements.
Babst Calland attorneys will continue to track these developments and are available to assist you with PFAS-related matters. For more information on this development and other remediation-related matters, please contact Matthew C. Wood at (412) 394-6583 or mwood@babstcalland.com, or any of our other environmental attorneys.
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1ASTM International develops technical standards for numerous areas and industries, including metals, paints, plastics, construction, energy, the environment, consumer products, devices and electronics, and advanced materials. Among other things, the standards are intended to enhance health and safety, improve product quality, and create consensus processes for achieving specific outcomes. The standards, which can be voluntarily adopted, are often referenced by governments in statutes, regulations, and/or codes.
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Environmental Alert
(Tim Bytner and Colleen Donofrio)
On December 5, 2022, the U.S. Environmental Protection Agency (EPA) published a proposed rule titled “Changes to Reporting Requirements for Per- and Polyfluoroalkyl Substances and to Supplier Notifications for Chemicals of Special Concern; Community Right-to-Know Toxic Chemical Release Reporting” (the “Proposal”) at 87 Fed. Reg. 74379-74387. The Proposal would amend the Emergency Planning and Community Right-to-Know Act (EPCRA) reporting requirements in 40 C.F.R. 372 to: (i) add per- and polyfluoroalkyl substances (PFAS) subject to reporting under EPCRA to the list of Lower Thresholds for Chemicals of Special Concern (the “List”) in 40 C.F.R. 372.28; and (ii) eliminate the de minimis exemption for all chemicals on the List under the Supplier Notification Requirements in 40 C.F.R. 372.45.
PFAS Reporting
PFAS subject to EPCRA reporting requirements already have a lower reporting threshold (100 pounds). By adding PFAS to the List, facilities are precluded from using the de minimis exemption at 40 C.F.R. 372.38(a), which would otherwise allow a facility to exclude PFAS found in chemical mixtures at concentrations less than one percent in determining whether the applicable reporting threshold has been met. Also, inclusion on the List prevents facilities from using the more simplistic, streamlined Form A for reporting. EPA believes these amendments will increase the data collected for PFAS and will result in a better understanding of PFAS waste management and release quantities.
Supplier Notifications
Generally, 40 C.F.R. 372.45 requires a chemical supplier to provide notification to certain facilities or persons (usually through Safety Data Sheets) of its products containing EPCRA 40 C.F.R. Part 372 toxic chemicals. 40 C.F.R. 372.45(d)(1) provides a de minimis exemption from this requirement. However, the Proposal would eliminate the de minimis exemption from the Supplier Notification Requirements for all chemicals on the List. The EPA expects this amendment will ensure that purchasers of products containing any chemicals found on the List will be better informed of the presence of those chemicals and their resultant reporting responsibilities under EPCRA, as well as other environmental programs.
If finalized as proposed, these amendments will increase the reporting burden for the regulated community. The public comment deadline is February 3, 2023. Written comments can be submitted using the Federal e-rulemaking portal (www.regulations.gov).
If you have any questions about the Proposal or submission of comments to the EPA, please contact Timothy S. Bytner at (412) 394-6504 or tbytner@babstcalland.com, or Colleen Grace Donofrio at (856) 256-2495 or cdonofrio@babstcalland.com.
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Public Sector Alert
(by Michael Korns and Ember Holmes)
On Thursday, November 3, 2022, Governor Tom Wolf signed PA Senate Bill 696, also known as Act 151 of 2022 or the Breach of Personal Information Notification Act. Act 151 amends Pennsylvania’s existing Breach of Personal Information Notification Act, strengthening protections for consumers, and imposing stricter requirements for state agencies, state agency contractors, political subdivisions, and certain individuals or businesses doing business in the Commonwealth. Act 151 expands the definition of “personal information,” and requires Commonwealth entities to implement specific notification procedures in the event that a Commonwealth resident’s unencrypted and unredacted personal information has been, or is reasonably believed to have been, accessed and acquired by an unauthorized person. The requirements for state-level and local entities differ slightly; this Alert will address the impact of Act 151 on local entities. While this law does not take effect until May 22, 2023, it is critical that all entities impacted by this law be aware of these changes.
For the purposes of Act 151, the term “local entities” includes municipalities, counties, and public schools. The term “public school” encompasses all school districts, charter schools, intermediate units, cyber charter schools, and area career and technical schools. Act 151 requires that, in the event of a security breach of the system used by a local entity to maintain, store, or manage computerized data that includes personal information, the local entity must notify affected individuals within seven business days of the determination of the breach. In addition, local entities must notify the local district attorney of the breach within three business days.
The definition of “personal information” has been updated, and includes a combination of (1) an individual’s first name or first initial and last name, and (2) one or more of the following items, if unencrypted and unredacted:
- Social Security number;
- Driver’s license number;
- Financial account numbers or credit or debit card numbers, combined with any required security code or password;
- Medical information;
- Health insurance information; or
- A username or password in combination with a password or security question and answer.
The last three items were added by this amendment. Additionally, the new language provides that “personal information” does not include information that is made publicly available from government records or widely distributed media.
Act 151 defines previously undefined terms, drawing a distinction between “determination” and “discovery” of a breach, and setting forth different obligations relating to each. “Determination,” under the act, is defined as, “a verification or reasonable certainty that a breach of the security of the system has occurred.” “Discovery” is defined as, “the knowledge of or reasonable suspicion that a breach of the security of the system has occurred.” This distinction affords entities the ability to investigate a potential breach before the more onerous notification requirements are triggered. A local entity’s obligation to notify Commonwealth residents is triggered when the entity has reached a determination that a breach has occurred. Further, any vendor that maintains, stores, or manages computerized data on behalf of a local entity is responsible for notifying the local entity upon discovery of a breach, but the local entity is ultimately responsible for making the determinations and discharging any remaining duties under Act 151.
Another significant update afforded by Act 151 is the addition of an electronic notification procedure. Previously, notice could be given: (1) by written letter mailed to the last known home address of the individual; (2) telephonically, if certain requirements are met; (3) by email if a prior business relationship exists and the entity has a valid email address; or (4) by substitute notice if the cost of providing notice would exceed $100,000, the affected class of individuals to be notified exceeds 175,000, or the entity does not have sufficient contact information. Now, in addition to the email option, entities can provide an electronic notice that directs the individual whose personal information may have been materially compromised to promptly change their password and security question or answer, or to take any other appropriate steps to protect their information.
Act 151 also provides that all entities that maintain, store, or manage computerized personal information on behalf of the Commonwealth must utilize encryption – this provision originally applied only to employees and contractors of Commonwealth agencies, but was broadened in Act 151. Further, the act provides that all entities that maintain, store, or manage computerized personal information on behalf of the Commonwealth must maintain policies relating to the transmission and storage of personal information – such policies were previously developed by the Governor’s Office of Administration.
Finally, under Act 151, any entity that is subject to and in compliance with certain healthcare and federal privacy laws is deemed to be in compliance with Act 151. For example, an entity that is subject to and in compliance with the Health Insurance Portability and Accountability Act of 1996 (HIPAA) is deemed compliant with Act 151.
Although Act 151 is an amendment to prior legislation, the updates create potential exposure for local entities and the vendors that serve them. For local municipalities, schools, and counties, compliance will require a proactive approach – local entities will have to familiarize themselves with the new requirements, be mindful of the personal information they hold, and ensure that their vendors are aware of their obligations. Further, local entities will be required to implement encryption protocols, and prepare and maintain storage and transmission policies. If you have questions about how Act 151 will impact your organization, please contact Michael Korns at 412-394-6440 or mkorns@babstcalland.com or Ember Holmes at 412-394-5492 or eholmes@babstcalland.com.
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Energy Alert
(by Gary Steinbauer, Gina Falaschi and Christina Puhnaty)
On November 11, 2022, the U.S. Environmental Protection Agency (EPA) released a pre-publication version of its supplemental proposal for Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review (Supplemental Proposal). The Supplemental Proposal has been highly anticipated since EPA published its initial proposal on November 15, 2021. EPA, 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. 63110 (Nov. 15, 2021) (Initial Proposal).
EPA currently regulates emissions from oil and natural gas facilities under 40 C.F.R Part 60 Subparts OOOO[1] and OOOOa.[2] As part of the Initial and Supplemental Proposals, EPA would regulate oil and natural gas facilities constructed, modified, or reconstructed after November 15, 2021, under a new Subpart OOOOb. With the Supplemental Proposal, EPA has released proposed regulatory language for Subpart OOOOb. In addition, EPA released proposed regulatory text for emissions guidelines in a new Subpart OOOOc. These emissions guidelines are intended to inform states in the development, submittal, and implementation of state plans to establish standards of performance for greenhouse gases (in the form of limitations on methane) from sources existing on or before November 15, 2021. Under the Supplemental Proposal, states and tribes would be required to submit plans to EPA for review within 18 months of the publication of a final rule, with a compliance deadline for existing sources that is no later than 36 months after the deadline to submit the plan to EPA. The Supplemental Proposal also includes an updated proposed “Appendix K,” which is a protocol for determining leaks using optical gas imaging that EPA is now proposing to limit to natural gas processing plants.
The Supplemental Proposal includes several significant changes or updates, which EPA describes as improvements, and additional proposed requirements for sources that were not covered in the Initial Proposal. Several consequential aspects of the Supplemental Proposal include:
- Super-Emitter Response Program: EPA is proposing to allow regulatory agencies and approved “qualified” third parties to monitor well sites, centralized production facilities, and compressor stations for “super-emitter emission events,” which are defined as emission events resulting in 100 kilograms (220.5 pounds) per hour or more of methane. Upon receipt of a notification by a third party, owners and operators of these facilities would be required to initiate a prescribed root cause analysis within five days and complete the root cause analysis and initial corrective actions within 10 calendar days. If initial corrective actions do not rectify the identified cause of the event, facility owners and operators will be required to prepare and submit a corrective action plan to EPA. In addition, recipients of “super-emitter emission event” notifications would also be required to notify EPA within 15 days of completing corrective actions. EPA plans to host a public website that will include information related to the proposed Super-Emitter Response Program.
- Abandoned and Unplugged Well Monitoring: The Supplemental Proposal includes new suite of well closure requirements. Under these proposed requirements, owners and operators of well sites would be required to submit a closure plan to EPA within 30 days of the cessation of production. The contents of this plan would need to include the steps necessary to permanently plug all wells, a description of financial requirements and assurance to complete closure, and the schedule for completing closure. Fugitive emissions monitoring would be required until closure, and an Optical Gas Imaging survey would be required to confirm that closure eliminated any emissions from the well.
- Fugitive Emissions Monitoring for All Wells: Contrary to its Initial Proposal, in which EPA proposed to require fugitive emissions monitoring (i.e., leak detection and repair or LDAR monitoring) at wells with estimated emissions of 3 tons per year or more, the Supplemental Proposal would require LDAR monitoring at all well sites, regardless of estimated fugitive emissions from the well sites. The type (audio, visual, or olfactory versus instrument) and frequency of LDAR monitoring will vary depending on whether the facility in question is a single wellhead-only well site, wellhead only well site with two or more wellheads, or a well site or a centralized production facility that contains “major production and processing equipment.”
These are only some of the numerous additional requirements that EPA is proposing in the Supplemental Proposal. Due to the breadth and complexity of the Supplemental Proposal and the long-awaited release of proposed regulatory text, EPA has also published a memorandum and accompanying chart that summarizes where, throughout the proposal, the agency is soliciting public comment (Summary of Comment Solicitations). In the Summary of Comment Solicitations, EPA has organized the agency’s 142 solicitations for comment by topic, preamble section, and issue to assist the public in understanding on which aspects of the proposal the agency specifically seeks input and guidance. Examples of the topics on which EPA solicits comment include: the potential of advanced methane detection technologies; the “equivalence determination” now required by Clean Air Act Section 136(f)(6)(A)(ii), a provision added to the per the Biden Administration’s Inflation Reduction Act of 2022; and the proposed Super-Emitter Response Program.
Although the Supplemental Proposal has not been published in the Federal Register, EPA has established a public comment deadline of February 13, 2023, and will hold virtual public hearings on January 10 and 11, 2023. Comments can be submitted to EPA by registering to speak at the public meeting or in writing on the Federal e-rulemaking portal (www.regulations.gov). The agency plans to issue a final rule in 2023.
EPA’s efforts to advance CAA regulations to reduce methane emissions from the oil and gas industry sector are separate from the inspections and anticipated rulemaking by the Pipeline and Hazardous Materials Safety Administration (PHMSA) under Sections 113 and 114 of the PIPES Act of 2020. While PHMSA has stated that EPA’s regulations may satisfy some Section 114 PIPES Act requirements, it has provided little guidance on this issue.
If you have any questions about the Supplemental Proposed Rule or submission of comments to EPA, please contact Gary E. Steinbauer at (412) 394-6590 or gsteinbauer@babstcalland.com, Gina N. Falaschi at (202) 853-3483 or gfalaschi@babstcalland.com, or Christina Puhnaty at (412) 394-6514 or cpuhnaty@babstcalland.com.
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[1] Specified affected facilities constructed, reconstructed, or modified after August 23, 2011 and on or before September 18, 2015 are regulated under Subpart OOOO.
[2] Specified affected facilities constructed, reconstructed, or modified after September 18, 2015 and on or before November 15, 2021 are regulated under Subpart OOOOa.
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Infrastructure Alert
(by Jim Curry, Sean McGovern and Lee Banse)
On November 3, 2022, Pennsylvania Governor Tom Wolf approved legislation that will provide up to $50 million of annual tax credits for facilities located in a Pennsylvania regional clean hydrogen hub that use clean hydrogen produced at the hub in manufacturing.[1] The tax credits are available between January 1, 2024 until December 31, 2043, providing up to $1 billion of credits over the life of the program.[2]
The Pennsylvania tax credits complement federal efforts to foster a clean hydrogen industry through the development of regional clean hydrogen hubs. The federal Bipartisan Infrastructure Law, enacted in November 2021, provided $7 billion for the Department of Energy (DOE) to establish between six to ten regional clean hydrogen hubs for the development of a domestic clean hydrogen industry.[3]
Under the new Pennsylvania program, the credits are available to taxpayers who have made a capital investment of at least $500 million to construct a facility in a Pennsylvania regional clean hydrogen hub, have satisfied certain job creation and employment requirements, and who purchase clean hydrogen produced in the Pennsylvania hub for use in manufacturing at the facility.[4] The tax credits will be applied at a rate of 81 cents per kilogram of clean hydrogen purchased.[5] Qualifying taxpayers may also apply for a tax credit of 47 cents per thousand cubic feet of natural gas purchased for use at the manufacturing facility.[6] A qualified taxpayer may assign the tax credits, subject to certain requirements in the statute.[7]
In a press release on the bill, Governor Wolf stressed the role clean hydrogen will play in reducing carbon emissions, and his support for applications for a regional clean hydrogen hub in Pennsylvania.[8] Governor Wolf also addressed the natural gas tax credits, expressing his belief that these will serve as an interim solution in case clean hydrogen is not immediately available for manufacturing facilities in the hub, and that the credits will likely not be used after a one to two-year period.[9]
The Pennsylvania tax credits also complement the new clean hydrogen tax (45V) credit in the recent federal Inflation Reduction Act (IRA), which became law in August 2022.[10] The IRA provides a tax credit of up to $3 per kilogram of clean hydrogen produced.[11]
Hydrogen hub concept papers were due to DOE on November 7, 2022, with complete applications due April 7, 2023. DOE anticipates notifying selected applicants in the Fall of 2023.[12] As DOE evaluates proposals over the next year, these new Pennsylvania tax credits may strengthen the various Pennsylvania-related proposals and help drive development of the use of hydrogen within the state.
If you have any questions about this legislation or need additional information about the Pennsylvania clean hydrogen tax credits, please contact Jim Curry at (202) 853-3461 or jcurry@babstcalland.com, Sean McGovern at (412) 394-5439 or smcgovern@babstcalland.com, or Lee Banse at (202) 853-3463 or lbanse@babstcalland.com.
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[1] General Assembly of Pennsylvania, H.B. 1059, Subarticle D, Sec. 1753-L(D)(2) (Oct. 26, 2022).
[2] Id. at Sec. 1761-L (B).
[3] Infrastructure Investment and Jobs Act, Pub. L. 117-58, Sec. 813, 135 Stat. 429, 1008 (Nov. 15, 2021).
[4] H.B. 1059, Subarticle D, Sec. 1752-L.
[5] Id. at Sec. 1753-L(A).
[6] Id.
[7] Id. at Sec. 1756-L.
[8] https://www.governor.pa.gov/wp-content/uploads/2022/11/20221103-1059.pdf.
[9] Id.
[10] Inflation Reduction Act of 2022, Pub. L. 117-169, 136 Stat. 1818 (Aug. 16, 2022).
[11] Id., 136 Stat. 1936.
[12] https://oced-exchange.energy.gov/Default.aspx#FoaId4dbbd966-7524-4830-b883-450933661811.
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Environmental Alert
(by Sean McGovern and Marley Kimelman)
On September 30, 2022, the U.S. Environmental Protection Agency published final definitions of “cumulative impacts” and “cumulative impact assessment” in response to an agency-wide directive to “take steps to better serve historically marginalized communities using cumulative impact assessment.”[1] Cumulative impacts are defined as “the totality of the exposures to combinations of chemical and non-chemical stressors and their effects on health, well-being and quality of life outcomes.” A cumulative impact assessment is “a process of evaluating both quantitative and qualitative data representing cumulative impacts to inform a decision.” Both definitions were published in a final report released by EPA’s Office of Research and Development (ORD).
Draft definitions of the two terms were originally published in January 2020 in an EPA white paper on cumulative impacts that provided definitions, research gaps, barriers to implementing cumulative impact research, and recommendations for advancing cumulative impact research going forward within ORD’s FY23-26 Strategic Research Action Plans. Cumulative impacts were defined as “the totality of exposures to combinations of chemical and non-chemical stressors and their effects on health, well-being and quality of life outcomes.” Cumulative impact assessment was defined as “the process of accounting for cumulative impacts in the context of problem identification and decision-making” requiring “consideration and characteristics of total exposures to both chemical and non-chemical stressors, as well as the interactions of those stressors over time across the affected population.”[2] The final definitions reflect feedback given to ORD by the EPA Science Advisory Board (SAB) on the white paper, and its outlined approach to addressing cumulative impacts in environmental justice (EJ) communities.[3]
The final definitions, and EPA’s cumulative impact research, will impact communities and regulated entities across the country. For example, in an October 12, 2022 letter, EPA suggested that, by issuing air permits to two plastics facilities located close to black communities in an industrial corridor known as “cancer alley,” the Louisiana Department of Environmental Quality (LDEQ) and Department of Health (LDH) were failing to meet their civil rights obligations. Specifically, the letter raised concerns that the “methods of administering programs and activities related to air pollution control and health risk mitigation and communication . . . may have an adverse and disparate impact on Black residents who live and/or attend school” near the facilities.
Further, EPA recommended that LDEQ and LDH conduct cumulative impact analyses for currently overdue air permit renewals, 14 Title V permits in the area, and for the “next significant [Clean Air Act] permitting action in each of the Industrial Corridor Parishes.”[4] The letter was issued as a result of three Title VI investigation undertaken by EPA’s Office of Environmental Justice and External Civil Rights.[5] And, while the letter is not an enforceable agency action, EPA’s use of its federal civil rights authority under Title VI to threaten federal financial assistance to LDEQ and LDH serves as a strong source of leverage against the state agencies.
EPA’s increased focus on cumulative impacts and EPA’s willingness to weigh in on state permitting decisions, requiring additional analysis and stakeholder input, raises additional hurdles for permit applicants. While the four corners of a permit application may not expressly cover environmental justice considerations in the form of cumulative impact assessments, permittees should be prepared for this analysis to be a critical factor for federal, state, and local permitting agencies in their permit approval decisions. If you have any questions about how cumulative impact assessment or environmental justice considerations could impact your permitting process, please contact Sean McGovern at 412-394-5439 or smcgovern@babstcalland.com or Marley Kimelman at 202-853-3464 or mkimelman@babstcalland.com.
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[1] U.S. EPA. Cumulative Impacts Research: Recommendations for EPA’s Office of Research and Development. U.S. Environmental Protection Agency, Washington, D.C., EPA/600/R-22/014a, 2022. https://www.epa.gov/system/files/documents/2022-09/Cumulative%20Impacts%20Research%20Final%20Report_FINAL-EPA%20600-R-22-014a.pdf.
[2] U.S. EPA. External Review Draft, Cumulative Impacts: Recommendations for EPA’s Office of Research and Development, U.S. Environmental Protection Agency, Washington, D.C., https://www.epa.gov/system/files/documents/2022-01/ord-cumulative-impacts-white-paper_externalreviewdraft-_508-tagged_0.pdf.
[3] U.S. EPA. Consultation on Cumulative Impacts Assessments. U.S. Environmental Protection Agency, Washington, D.C., EPA-SAB-22-003, 2022.
[4] U.S. EPA. Letter of Concern, EPA Complaint Nos. 01R-22-R6, 02R-22-R6, and 04R-22-R6. U.S. Environmental Protection Agency, Washington, D.C., https://www.epa.gov/system/files/documents/2022-10/2022%2010%2012%20Final%20Letter%20LDEQ%20LDH%2001R-22-R6%2C%2002R-22-R6%2C%2004R-22-R6.pdf.
[5] https://www.epa.gov/system/files/documents/2022-10/2022.04.06%20Acceptance%20Letter%20Recipient%20-%20LDH%20EPA%20Complaint%20No.%2002R-22-R6%20FINAL.pdf; https://www.afslaw.com/sites/default/files/2022-04/RE-EPA-Complaint-Nos.-01R-22-R6-and-04R-22-R6.PDF.
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Energy Alert
(by Chelsea Heinz and Devlin Carey)
On November 3, 2022, the Pennsylvania General Assembly enacted Senate Bill 806, which amends the Oil and Gas Lease Act of 1979 (P.L. 183, No. 60). The new act seeks to increase transparency around the payment of royalties from oil and natural gas operators to landowners pursuant to their lease agreements.
Senator Gene Yaw (R-23), the prime sponsor of Senate Bill 806, believes the act will address recent concerns among landowners regarding the way in which royalties are being calculated, described and ultimately paid.
“Concerns have been expressed by land and mineral owners for some time now centered on the lack of transparency that can come with deductions from their royalty payments,” Yaw noted in January 2022, when the bill passed the Senate. “In some cases, general deductions with little to no description are subtracted from landowner’s checks, leaving them with a fraction of what was promised. My legislation would not impact lease agreements, but it would require entities making payments to landowners to provide more description, clarity and uniformity on their royalty check statements.”
Various agencies and organizations supported the bill in the months leading up to its passage, including the Pennsylvania Farm Bureau, the Pennsylvania Oil and Gas Landowner Alliance, the Marcellus Shale Coalition, Bounty Minerals, the Pennsylvania Independent Oil & Gas Association and the Pennsylvania Grade Crude Oil Coalition.
Oil and natural gas operators should be aware of the following provisions of the act, which will take effect on Friday, March 3, 2023:
Definitional Changes
Section 1 of the act clarifies the scope of ownership interests by replacing the 1979 act’s original, broadly defined “interest owner” term with a more precise “royalty owner” term. The act defines a “royalty owner” as “any owner of oil or gas in place or oil or gas rights, subject to a lease covering such oil or gas in place or oil or gas rights.” This includes owners who: (1) are entitled to share in the production of the oil or gas under their leasing agreements; or (2) have an interest in oil or gas in place or oil and gas rights but who have not entered into a lease (provided that such owner is not an “operator” under 58 Pa.C.S. §3203).
Expanded Check Stub Requirements
Section 2 of the act increases payors’ informational responsibilities for the check stubs they provide to royalty owners and differentiates these requirements for production of oil, natural gas and natural gas liquids from conventional and unconventional formations. For unconventional wells, these requirements include specifying:
- Total barrels of crude oil or number of Mcf or MMBtu of gas and volume of natural gas liquids produced and sold from each well;
- The price received by the payor per unit of oil, natural gas and natural gas liquids produced and sold;
- Aggregate amounts for each category of deductions for each well incurred by the payor which reduces the royalty owner’s payment, including all severance and production taxes;
- The net and gross value of the payor’s total sales of oil, gas and natural gas liquids from each well (minus any deductions); and
- The relevant royalty owner’s legal and contractual interest in the payor’s share, along with the royalty owner’s share of: (1) the gross value of the payor’s total sales before any deductions; and (2) the sales value minus the royalty owner’s share of taxes and any deductions.
Upon the mutual consent of the parties, the act notably requires payors to furnish royalty owners with summary statements setting forth each of the prescribed informational requirements. Once a royalty owner makes a written request for summary statements under the act, the payor must provide such statements from the month of the notice and each month thereafter, as well as for any prior period requested by the royalty owner.
If a payor fails to provide the payment information required by the act, a royalty owner may make a written request for the same. If a payor fails to respond within 60 days after receiving said request, the act gives royalty owners a cause of action for enforcing the provisions of the act and a right to recover attorneys’ fees and court costs.
The act permits payors to provide the required payment information electronically if a royalty owner has historically received such information electronically or upon mutual written consent by the parties.
Timing of Payments
Unless a lease specifies otherwise (and subject to select carve-outs in the act), payors must make payments to royalty owners: (1) no later than 120 days from the date of the first sale of oil, gas or natural gas liquids; and (2) for all subsequent sales, within 60 days after the end of the month when the production is sold. A payor’s failure to make timely payments in accordance with the act shall incur interest (unless otherwise provided for in the applicable lease).
If you have any questions about the new act, please contact Chelsea Heinz at 412-463-2702 or cheinz@babstcalland.com or Devlin Carey at 412-394-6543 or dcarey@babstcalland.com.
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Environmental Alert
(By Gary Steinbauer, Gina Falaschi and Christina Puhnaty)
On October 14, 2022, the U.S. Environmental Protection Agency published a proposed rule that would require all emission sources subject to the Agency’s major New Source Review (NSR) permitting program to consider fugitive emissions when evaluating whether a new source or physical or operational change triggers the stringent major NSR permitting requirements. 87 Fed. Reg. 62,322 (Oct. 14, 2022) (Proposed Rule). The treatment of fugitive emissions, i.e., those “which could not reasonably pass through a stack, chimney, vent, or other functionally equivalent opening,” under the major NSR permitting program has been controversial for decades. While EPA predicts that the Proposed Rule will have limited impact on the regulatory community, EPA and state air permitting authorities may now place even greater pressure on industry to predict and quantify “fugitive emissions” from physical or operational changes to their facilities.
The major NSR permitting program is the Clean Air Act’s permit program that applies to the construction of new “major sources” and “major modifications” (i.e., qualifying physical or operational changes) to existing “major sources.” Applicability determinations under the major NSR program often rely heavily on predicted emissions from a new source or planned physical or operational changes to an existing source. When the new or existing source is located in an area that is in attainment with the Clean Air Act’s national ambient air quality standards (NAAQS), the major NSR program’s Prevention of Significant Deterioration (PSD) requirements apply. More stringent requirements, known as non-attainment NSR requirements, apply when the source will be or is located in an area that is not meeting one or more of the NAAQS. The Proposed Rule would impact all “major stationary sources,” regardless of whether they are located in areas that are meeting or not meeting the NAAQS.
The Proposed Rule would formally repeal EPA’s “2008 Fugitive Emissions Rule,” which provides that only “listed” industrial source categories are required to consider fugitive emissions when determining whether a physical or operation change is subject to major NSR permitting requirements. See 73 Fed. Reg. 77,881 (Dec. 19, 2008). The 28 “listed” industrial source categories referenced in the 2008 Fugitive Emissions Rule include, among others, iron and steel mills, Portland cement plants, petroleum refineries, coke oven batteries, certain fossil-fuel-fired power plants, and certain petroleum storage and transfer units. Effectively, the 2008 Fugitive Emissions Rule allowed non-listed industrial source categories to consider only non-fugitive emissions when evaluating major NSR permitting applicability.
Shortly after the 2008 Fugitive Emissions Rule went into effect in early 2009, environmental groups submitted a petition for reconsideration, after which EPA issued and extended multiple stays of the 2008 Fugitive Emissions Rule. As a result, since late-2009, the 2008 Fugitive Emissions Rule has been stayed and the regulations predating it have remained in effect.
In addition to proposing to formally repeal the 2008 Fugitive Emissions Rule, EPA is seeking to remove a regulatory exemption that has been on the books since 1980. This “1980 exemption” provides that a physical or operational change is not considered a “major modification” subject to NSR permitting requirements if the physical or operational change is considered “major” solely due to fugitive emissions and the change is occurring at a facility within a non-listed industrial source category. In the Proposed Rule, EPA states that the 1980 exemption was inadvertently retained between 1989 and 2008, despite other EPA interpretations providing that all “major” sources are to account for fugitive emissions when evaluating major NSR permitting applicability. EPA acknowledges that the 1980 exemption “has created significant uncertainty about the EPA’s treatment of fugitive emissions in the major modification context.” 87 Fed. Reg. at 62,328.
The Proposed Rule may be part of an emerging trend of EPA revisiting decades-long controversies related to fundamental aspects of the Clean Air Act permitting programs. In a late-September 2022 presentation to the Association of Air Pollution Control Agencies, EPA discussed the Proposed Rule, along with a spate of several other planned regulatory actions and guidance updates related to the major and minor NSR permitting program and its Title V permitting program.
EPA will accept comments on the Proposed Rule until December 13, 2022, on the Federal e-rulemaking portal (www.regulations.gov). If you have any questions about the Proposed Rule or submission of comments to EPA, please contact Gary E. Steinbauer at (412) 394-6590 or gsteinbauer@babstcalland.com, Gina N. Falaschi at (202) 853-3483 or gfalaschi@babstcalland.com, or Christina Puhnaty at (412) 394-6514 or cpuhnaty@babstcalland.com.
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Energy Alert
(by Austin Rogers and Robert Stonestreet)
On Wednesday, September 7, 2022, Judge John Preston Bailey of the federal District Court for the Northern District of West Virginia granted a motion to dismiss a lawsuit challenging the validity of Senate Bill 694, West Virginia’s new oil and gas unitization statute. The statute authorizes the West Virginia Oil and Gas Conservation Commission to issue orders authorizing certain oil and gas interests to be included in what are known as development units, even without the consent of the interest owner, under very narrow circumstances.
Plaintiffs, who owned mineral interests in property that could potentially be subject to the unitization procedure in SB 694, sought to prevent the statute from becoming effective by claiming that the law, among other things, allows the unconstitutional taking of private property without just compensation in violation of both the United States Constitution and the West Virginia Constitution. Plaintiffs also argued that the statute deprived them of due process in the taking of their property in violation of the Fifth and Fourteenth Amendment of the United States Constitution. The Court dismissed the challenge because (1) the plaintiffs lacked standing and (2) Governor Jim Justice, the sole defendant, has sovereign immunity under the Eleventh Amendment.
With respect to standing, the Court held that the plaintiffs failed to satisfy any of the three requirements: (1) an injury-in-fact; (2) that was traceable to the statute; and (3) that could be redressed by the Court. According to Judge Bailey, the plaintiffs did not suffer an injury in fact because their tract has not been unitized, and no operator has even applied to unitize their mineral tracts under SB 694. Second, the alleged injury is not traceable to the Governor’s conduct because the Governor has no power to enforce SB 694. Finally, plaintiffs failed to show that a favorable ruling against the Governor would provide any redress. To establish standing, a plaintiff must meet all three factors, but here plaintiffs failed to meet a single one.
The Court further held that, even if the plaintiffs had standing, sovereign immunity under the Eleventh Amendment shields the Governor from liability. In general, the Eleventh Amendment prevents states from being sued in federal court without their consent, and this includes state officials being sued in their official capacity. The exception to this general rule allows for suit against a state official when the state official has the ability to enforce the law in question. Here, the Court ruled that Governor Justice has no authority to enforce SB 694 because the law does not specifically allocate any authority to the Governor. Plaintiffs claim that the Governor has the general duty to ensure laws are faithfully executed, and by appointing members of the West Virginia Oil and Gas Conservation Commission, the Governor ensures the law is enforced. The Court pointed to numerous cases, however, which find that sovereign immunity cannot be overcome by (1) the Governor’s general duty to enforce the laws of a state; or (2) the appointment power enjoyed by a Governor.
While the Court dismissed the plaintiffs’ claims, it also granted plaintiffs leave to amend the Complaint by September 20, 2022. The plaintiffs indicated in the briefing on the Motion to Dismiss that they intended to include the West Virginia Oil and Gas Conservation Commission as a defendant. So we anticipate that a new challenge to SB 694 will be filed that names the Commission as a defendant. Plaintiffs also indicated in briefing that they do in fact own unitized mineral interests. Naming the Commission as a defendant coupled with identifying the plaintiffs’ unitized mineral interests will likely overcome the grounds for dismissal cited by the Court in its order.
Please contact either of the following attorneys to learn more: Austin Rogers at arogers@babstcalland.com or 681.265.1368 or Robert Stonestreet at rstonestreet@babstcalland.com or 681.265.1364.
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Environmental Alert
(By Matthew Wood and Mackenzie Moyer)
On August 26, 2022, the U.S. Environmental Protection Agency (EPA) issued a pre-publication version of its Proposed Rule which would designate two PFAS chemicals as “hazardous substances” under the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), commonly known as Superfund (Proposed Rule). Specifically, the Proposed Rule would list perfluorooctanoic acid (PFOA) and perfluorooctanesulfonic acid (PFOS) – the two most common and well-studied PFAS – and their salts and isomers as hazardous substances under CERCLA. This is the first time EPA is making such designations by exercising its authority under CERCLA Section 102, 42 U.S.C. § 9602. Until now, CERCLA has always defined hazardous substances by reference to other statutes (e.g., the Clean Water Act and the Resource Conservation and Recovery Act).
In the Proposed Rule, EPA identified five broad categories of potentially affected entities: (1) PFOA/PFOS manufacturers (including importers and importers of articles); (2) PFOA/PFOS processors; (3) manufacturers of products containing PFOA/PFOS; (4) downstream product manufacturers and users of PFOA/PFOS products; and (5) waste management and wastewater treatment facilities. Potentially affected industries include aviation operations, chemical manufacturing, firefighting foam manufacturers, fire departments and training facilities, polymer manufacturers, and waste management and remediation services.
In the lead-up to issuance of the Proposed Rule, certain entities, such as drinking water utilities, wastewater utilities, and landfill operators, expressed concerns that they could face significant new liabilities for contamination originating from others. In its accompanying announcement, EPA said, without identifying specific industries, that it is “focused on holding responsible those who have manufactured and released significant amounts of PFOA and PFOS into the environment” and intends to use its “enforcement discretion” to “ensure fairness for minor parties who may have been inadvertently impacted by the contamination.” EPA further said that it will continue to engage with impacted communities, wastewater utilities, businesses, farmers, and other parties throughout the consideration of the Proposed Rule.
If finalized, the Proposed Rule will immediately require parties to report to federal, state, tribal, and local authorities, as applicable, releases of PFOA and/or PFOS of one pound or more within a 24-hour period. The Proposed Rule also requires federal agencies to meet the property transfer requirements enumerated in CERCLA § 120(h), 42 U.S.C. § 9620(h), when selling and transferring federally-owned real property. This includes providing notice if PFOA/PFOS (or any other hazardous substance) was stored on-site for a year or more and/or was released or disposed of on-site, in addition to warranting in the property’s deed that remediation has been completed prior to the transfer (and any further necessary remediation will be completed by the United States). Finally, the Department of Transportation will have to list and regulate PFOA and PFOS as hazardous materials under the Hazardous Materials Transportation Act.
More broadly, the federal government is currently limited in how it can respond to PFOA/PFOS contamination in the environment. That is, it may be authorized to clean up PFOA/PFOS when it finds an imminent and substantial danger to public health or welfare. If the Proposed Rule is finalized as written, however, EPA and other agencies with delegated CERCLA authority could have additional remedial options, including to: (1) respond to PFOA/PFOS releases without making an imminent and substantial danger finding; (2) require potentially responsible parties (PRPs) to clean up PFOA/PFOS contamination; and (3) recover cleanup costs from PRPs. Private parties who conduct cleanups consistent with the National Contingency Plan could also recover cleanup costs from other PRPs. Among other things, EPA believes that the Proposed Rule will increase transparency with respect to the scope of PFOA/PFOS releases and allow the government to conduct faster cleanups.
The Proposed Rule’s costs have been targeted by industry stakeholders and for further analysis by the Office of Management and Budget (OMB). Earlier this year, OMB designated the rule as “other significant,” meaning the direct costs of the rule – the reporting requirements – were not expected to exceed more than $100 million. On August 12, 2022, OMB redesignated the rule as “economically significant,” i.e., the rule is expected to impose costs of $100 million or more annually, which requires EPA to conduct a more robust cost-benefit analysis of the indirect and direct costs of the Proposed Rule and issue a regulatory impact analysis (RIA). EPA has not yet issued the RIA, but stakeholders concerned about the Proposed Rule’s costs have conducted their own analyses. For example, a study by the U.S. Chamber of Commerce found that private sector cleanup costs at Superfund sites could cost between $700-800 million a year.
Announcement of the Proposed Rule comes on the heels of EPA’s June 2022 release of interim updated drinking water health advisories for PFOA and PFOS, which are non-regulatory thresholds below which adverse health effects are not expected to occur. EPA lowered the health advisories from 70 parts per trillion (ppt) combined for PFOA and PFOS to 0.004 ppt for PFOA and 0.02 ppt for PFOS. EPA also issued final health advisories for Hexafluoropropylene Oxide (HFPO) Dimer Acid and its Ammonium Salt (GenX chemicals; 10 ppt) and Perfluorobutane Sulfonic Acid and its Potassium Salt (PFBS; 2,000 ppt).
The Proposed Rule will be published in the Federal Register within the next several weeks, which will start the 60-day public comment period. At the close of the public comment period, EPA also anticipates issuing an Advance Notice of Proposed Rulemaking seeking input on designating other PFAS chemicals as CERCLA hazardous substances.
The Proposed Rule is one of many goals EPA set for addressing all stages of the PFAS lifecycle, as further detailed in the agency’s “PFAS Strategic Roadmap: EPA’s Commitments to Action 2021-2024,” available here. As the federal and state governments take action to address PFAS, Babst Calland attorneys will continue to track these developments and are available to assist you with PFAS-related matters (including preparing and submitting comments on the Proposed Rule). For more information on this development and other remediation matters, please contact Matthew C. Wood at (412) 394-6583 or mwood@babstcalland.com, Mackenzie M. Moyer at (412) 394-6578 or mmoyer@babstcalland.com, or any of our other environmental attorneys.
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Pipeline Safety Alert
(by Keith Coyle, Chris Hoidal and Brianne Kurdock)
On August 24, 2022, the Pipeline and Hazardous Materials Safety Administration (PHMSA) published a new final rule for onshore gas transmission pipelines (the Rule). The Rule marks the completion of a three-phase rulemaking process, commonly referred to as the Gas Mega Rule, that began more than a decade ago. While this part of the Gas Mega Rule is commonly known as the “Repair Rule,” there are numerous other safety provisions that are included in the new regulation that should not be overlooked. The Rule amends or adds various provisions in 49 C.F.R. Part 192 and will become effective on May 24, 2023.
In the Rule, PHMSA added, clarified, or modified the following sections of the natural gas pipeline safety regulations:
- definitions in section 192.3;
- the management of change process;
- corrosion control requirements;
- inspections of pipelines following extreme weather events;
- integrity management provisions;
- integrity management assessment requirements;
- revised repair criteria in high-consequence areas; and
- new repair criteria for non-high consequence areas.
Definitions and Standards Incorporated by Reference
PHMSA added new definitions referenced in the new regulations, including close interval survey, distribution center, dry gas or dry natural gas, hard spot, in-line inspection (ILI), in-line inspection tool or instrumented internal inspection device, and wrinkle bend. Furthermore, the definition of transmission pipelines was revised to include a “connected series” of pipelines to clarify that transmission pipeline can be downstream of other transmission pipelines, and to allow operators to voluntarily designate their pipelines as transmission lines.
The rule also incorporates by reference two NACE standards, NACE SP0204-2008 and NACE SP0206-2006, for stress corrosion cracking direct assessments and internal corrosion direct assessments. These new IBR standards support the new corrosion amendments to the Rule.
Management of Change
PHMSA extended management of change requirements to onshore gas transmission pipelines not currently subject to integrity management requirements. The Agency also amended the existing management of change process in § 192.911(k) to codify specific attributes listed in ASME/ANSI B31.8S, section 11.
Operators of all onshore gas transmission pipelines must now evaluate and mitigate any significant changes that pose a risk to safety or the environment through a management of change process. The process must include the reasons for the change, the authority for approving changes, an analysis of the implications, the acquisition of required work permits, and evidence documenting communication of the change to affected parties, time limitations, and the qualification of staff. Although the Gas Pipeline Advisory Committee had recommended a two-year phased in compliance period, the Agency mandated an 18-month time frame to incorporate the management of change process for pipelines in non-HCAs. For pipeline segments not covered by Subpart O, operators must implement this management of change process by February 26, 2024. Operators may seek a technically justified extension of this deadline of up to one year through the section 192.18 notification process. PHMSA specifically noted that these changes do not apply retroactively and do not cover gathering or distribution pipelines.
Corrosion Control and Related Construction Requirements
The Rule amends numerous corrosion control requirements for onshore gas transmission pipelines, addressing the monitoring and remediation, if needed, of both external and internal corrosion. The Agency issued new requirements to conduct pipe coating assessments soon after construction, determine protective coating strength, survey for interference currents, and monitor gas streams for internal corrosivity. In conjunction with the enhanced corrosion monitoring for internal and external corrosion, PHMSA established new corrosion control remediation criteria and timelines to correct deficiencies found. PHMSA acknowledged that these new construction and corrosion control requirements do not apply to gathering or distribution pipelines.
Pipe Coating
PHMSA added new construction requirements concerning the installation of pipe in a ditch (section 192.319). If a construction project involves 1,000 feet[1] or more of continuous backfill length along the pipeline, the operator must promptly (but not later than six months after placing the pipeline in service) perform an above-ground indirect assessment to identify any coating damage using direct current voltage gradient, alternating current voltage gradient, or other technology. If an operator chooses to use alternative technology, it must notify PHMSA at least 90 days in advance and seek a letter of no objection through the process described in section 192.18. An operator must repair any severe coating damage within six months after the pipeline is put in service (or as soon as practicable after obtaining the necessary permits). The operator must retain records documenting the coating assessment findings and repairs for the life of the pipe.
PHMSA made similar modifications to section 192.461 requiring an onshore gas transmission operator to conduct an above-ground indirect assessment if the backfill length of a repair or a replacement project is 1,000 feet or more. The operator would need to conduct the assessment promptly but no later than six months after the backfill. The operator may also notify PHMSA of its intent to use alternative technology by following the process in section 192.18. The operator must develop a remedial action plan within six months of completing the assessment and repair any severe coating damage within six months of the assessment or as soon as practical upon obtaining the necessary permits. The operator must retain records of the assessment findings and remedial actions for the life of the pipe.
Interference Surveys and Remediation
PHMSA amended section 192.473 to require interference surveys for pipelines subject to stray currents. Currently, an operator with a pipeline subject to stray currents must have a program to minimize the detrimental effect of these currents. An operator with such a pipeline will now have to conduct an interference survey to quantitatively determine the presence and level of interference currents. PHMSA provides in the Rule that an interference survey must be conducted when the monitoring indicates a significant increase in stray current or when new potential stray current sources are introduced. An operator must analyze the results of the survey to determine the cause of the interference and develop a remedial action plan to correct any deficiency if the current is greater than or equal to 100 amps per meter squared or if it impedes the safe operation of the pipeline or if it may cause a condition that would adversely impact the environment or the public. The operator must complete the remediation promptly but no later than the earlier of (1) 15 months of completing the survey or (2) as soon as practicable but not to exceed six months after obtaining the necessary permits.
Cathodic Protection Remediation
Although operators already have a general obligation under § 192.465(d) to promptly remediate any corrosion control deficiencies discovered during cathodic protection (CP) monitoring, PHMSA has now added a requirement for onshore gas transmission operators to develop a remedial action plan for both localized/non-systemic and widespread/systemic corrosion control deficiencies found by the CP monitoring within six months of discovery. The operator must complete the remedial action promptly but no later than the earlier of (1) the next inspection or test interval; (2) within one year, not to exceed 15 months, or (3) as soon as practicable, not to exceed six months after obtaining any necessary permits.
For areas where an annual test station reading indicates inadequate cathodic protection below the required levels in Appendix D, operators must investigate the geographical extent and causes of the low CP levels to determine whether there is systemic/widespread or non-systemic/localized areas of deficient CP. Operators must conduct close interval surveys (CIS) to delineate the pipe segments requiring CP remediation. The CIS must be conducted with the protective current interrupted unless it is impractical to do so for technical or safety reasons. An operator must promptly remediate pipe segments with insufficient cathodic protection, and, following the remediation, confirm the restoration of sufficient cathodic protection.
Internal Corrosion Monitoring and Mitigation
While section 192.477 includes requirements to monitor for internal corrosion if corrosive gas is transported, PHMSA is now adding requirements to continually monitor the gas stream for corrosive constituents. The Rule requires operators to develop a monitoring and mitigation plan for pipelines that transport gas with corrosive constituents. The Rule includes specific content requirements for the plan including an obligation to evaluate the gas monitoring data and review and adjust the plan, if necessary, once each calendar year (not to exceed 15 months).
Remedial Measures
Finally, the Rule amends § 192.485, requiring operators to determine whether remedial measures for general or localized corrosion pitting are necessary by calculating remaining pipe wall thickness using the analysis of predicted failure pressure requirements in § 192.712. While the addition of §192.712 was part of the first phase of the Mega Rule, which focused on MAOP Reconfirmation, this revision to § 192.485 clarifies that determination of remaining strength of pipe in corroded areas must be completed and documented in accordance with § 192.712 for all transmission pipelines, not just those lines that are reconfirming their MAOP.
PHMSA expanded section 192.712 to include dents and other mechanical damage. The expanded analytical requirements will include evaluation of dent and other mechanical damage that could cause a stress riser, exceed the critical strain threshold, or otherwise degrade the integrity of the pipeline.
Inspections and Remedial Action Following Extreme Weather Events
Similar to the requirements for hazardous liquid pipeline operators, PHMSA has now expanded continuing surveillance requirements for an operator to perform an initial inspection following extreme weather events. Numerous examples of extreme weather events are listed and include geohazards such as earthquakes, river channel migration, and landslides. The operator must conduct the inspection 72 hours after it reasonably determines that the affected area can be safely accessed by personnel and equipment and the equipment and personnel are available. The Rule also requires operators to take prompt remedial action discovered during the inspection.
Integrity Management
A significant portion of the Rule focuses on the integrity management (IM) program requirements in 49 C.F.R. 192 Subpart O. The Rule prescribes new or amended requirements for identifying and analyzing threats, performing direct assessments, repairing pipelines, and implementing preventive and mitigative measures (P&MM).
Threat Identification and Data Integration
PHMSA has added certain pipeline attributes from ASME/ANSI B31.8S directly into the pipeline safety regulations. Current IM regulations require operators to conduct a risk assessment using the identified threats to determine what additional P&MM are needed to ensure the safe operation of the pipeline. Operators must begin to integrate all pertinent data elements starting on May 24, 2023, with all available attributes integrated by February 26, 2024. An operator may request an extension of up to one year by submitting a notification to PHMSA at least 90 days before February 26, 2024, in accordance with § 192.18.
Internal Corrosion Direct Assessment and Stress Corrosion Cracking Direct Assessment
The rule addresses direct assessments by incorporating NACE SP0204-2008 and NACE SP0206-2006 by reference. These standards concern stress corrosion cracking direct assessment and internal corrosion direct assessment, respectively.
Repair Criteria
Finally, the Rule provides a robust overhaul of current repair criteria regulations. The Rule applies integrity-related repair criteria to pipelines not subject to the integrity management requirements in Subpart O. Repair criteria for immediate conditions, which include certain crack, dent, and corrosion anomalies, are identical to those in Subpart O (as revised by the final rule and summarized in the chart below). Operators of non-Subpart O pipelines have two years to repair “one-year conditions,” which vary slightly from those in Subpart O, and must monitor certain conditions. The Rule requires operators to use these repair criteria when making permanent repairs on transmission lines located outside of HCAs.
The chart below provides a high-level summary the new requirements:
| Immediate Repair Conditions |
One-year Conditions |
Monitored Conditions |
Metal loss anomaly with failure pressure
≤ 1.1 x MAOP |
*Smooth dent in upper 2/3 of the pipe with depth > 6% of OD |
**Dent in bottom 1/3 of pipe with depth > 6% of OD |
| *Dent in upper 2/3 of the pipe with metal loss, cracking, or a stress riser |
*Dent with depth > 2% of OD that affects girth or long seam weld |
**Dent in upper 2/3 of the pipe with depth
> 6% of OD |
| Metal loss > 80% of nominal wall |
*Dent in lower 1/3 of the pipe with metal loss, cracking, or a stress riser |
**Dent with depth > 2% that affects girth or long seam weld |
| Metal loss preferentially affecting certain long seams and failure pressure < 1.25 x MAOP |
Metal loss with failure pressure < 1.39 x MAOP |
**Dent with metal loss, cracking, or a stress riser |
| Crack plus any metal loss > 50% wall thickness |
Metal loss located at a crossing with another pipeline and certain failure pressure based on class location |
Metal loss preferentially affecting certain long seams and certain failure pressure based on class location |
| Crack plus any metal loss > inspection tool’s max measurable depth |
Metal loss preferentially affecting certain long seams and certain failure pressure based on class location |
Crack with certain failure pressure based on class location |
| Crack with failure pressure < 1.25 x MAOP |
Crack with certain failure pressure based on class location |
|
| Any anomaly that requires immediate action |
|
|
| *Exception if an engineering analysis performed in accordance with § 192.712(c) demonstrates that critical strain levels are not exceeded |
| **An engineering analysis performed in accordance with § 192.712(c) must demonstrate that critical strain levels are not exceeded. |
Other Considerations
In accordance with 49 C.F.R. § 190.335, any interested party may seek reconsideration of the rule by filing a petition with PHMSA by September 23, 2022. Petitions for judicial review must be filed no later than 89 days after the regulation is prescribed.
For a more detailed assessment or to discuss the implications of the final rule, please contact Keith Coyle at 202.853.3460 or KCoyle@babstcalland.com, Chris Hoidal at 202-853-3455 or CHoidal@babstcalland.com, or Brianne Kurdock at 202.853.3462 or BKurdock@babstcalland.com.
[1] PHMSA stated in the preamble that §§ 192.319 and 192.461 apply to segments “greater than 1,000 feet in length” but used “1,000 feet or more” in the rule text.
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Environmental Alert
(By Jean Mosites and Amanda Brosy)
On August 16th, President Joe Biden signed the Inflation Reduction Act of 2022 (the Act) into law. The Act, as part of a larger budget reconciliation package, provides roughly $370 billion in investments in energy and climate reform geared towards lowering greenhouse gas emissions by 40 percent, based on 2005 levels, by 2030.
Among other things, the Act resurrects a long-expired Hazardous Substance Superfund Trust Fund (Superfund) excise tax on oil and petroleum products, effective as of January 1, 2023. In 1980, Congress had established the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). CERCLA is commonly referred to as “Superfund”. It allows EPA to clean up contaminated sites. It also requires the parties responsible for the contamination to either perform cleanups or reimburse the government for EPA-led cleanup work. When there is no viable responsible party, Superfund gives EPA the funds and authority to clean up contaminated sites.
The purpose of the petroleum excise tax is to replenish the Superfund, which provides the federal government with resources to respond to environmental threats related to hazardous substances not otherwise addressed by responsible parties. The petroleum excise tax applies to crude oil received at a U.S. refinery (which tax must be paid by the operator of the refinery) and to petroleum products entering the U.S. for consumption, use, or warehousing (which tax must be paid by the person importing the product into the U.S. for any of those purposes). In addition, if any domestic crude oil is used in or exported from the U.S., and before such use or exportation no tax was imposed on such crude oil at the refinery (as described above), then a separate tax is imposed. That tax would be paid by the person using or exporting the crude oil, as the case may be.
The tax rate is 16.4 cents per barrel on crude oil and petroleum-product imports, indexed to the inflation rate. This is an increase from the rate of 9.7 cents that applied the last time this petroleum excise tax was effective over 25 years ago. It is estimated that the tax will raise $11.7 billion in revenue over 10 years, until the tax is set to expire on December 31, 2032.
The reinstatement of the Superfund excise tax on oil and petroleum products marks the resumption of two of the three original Superfund taxes that were allowed to expire in 1995 (the third was an environmental income tax). As previously reported by Babst Calland, a separate Superfund excise tax on chemical feedstocks was reinstated with the adoption of the federal Infrastructure Bill last November. The reinstatement of these Superfund taxes, with attendant revisions and new provisions, has raised and will raise a multitude of tax implications, questions and uncertainties that are beyond the scope of this alert. The IRS has issued and will continue to issue guidance regarding the applicability of the tax to taxable substances.
Babst Calland’s environmental attorneys continue to track Superfund developments and their implications for industry as developments occur in the coming months. If you have questions or need additional information, please contact Jean Mosites at (412) 394-6468 or jmosites@babstcalland.com or Amanda Brosy at (202) 853-3465 or abrosy@babstcalland.com.
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