Pittsburgh Business Times
In March, the Securities and Exchange Commission (SEC) released a proposed rule entitled Enhancement and Standardization of Climate-Related Disclosures for Investors. If finalized, this rule would become some of the first mandatory Environmental, Social and Governance (ESG) reporting requirements for U.S. companies, requiring the disclosure of climate-related risk information in registration statements and periodic reports.
This proposed regulation has significant consequences not just for public companies, but private companies as well. Babst Calland Environmental Attorney Gina N. Falaschi explains the implications of the proposed rules, should they take effect.
What requirements could the rules introduce?
Under the SEC proposal, public companies would be required to disclose the oversight and governance of climate-related risk by their board and management; how any climate-related risk has a material effect on business and consolidated financial statements; the process 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 transitional risks to its operations; the effect of severe weather events and related natural conditions; and information regarding any publicly set climate-related targets or goals.
The SEC’s proposal also requires the disclosure of certain greenhouse gas emissions. These emissions are divided into three categories based on the Greenhouse Gas Protocol definitions. Scope 1 emissions are the direct greenhouse gas emissions that occur from sources that a company owns or controls, such as emissions from manufacturing activities and vehicles. Scope 2 emissions are the indirect greenhouse gas emissions that occur from the generation of energy that a company buys and consumes in its operations. Scope 3 emissions are the result of assets not owned or controlled by a company that the company indirectly impacts in its value chain, both upstream and downstream, from the company’s operations, such as the purchased goods and services, waste generation, business travel, downstream transportation, distribution and use of products sold, and the end-of-life treatment of products sold. Scope 3 emissions would have to be disclosed only if considered “material.”
What do companies need to do to prepare?
While the regulation has not yet been finalized, many companies could be required to begin compliance in the near future, so it’s prudent that both publicly traded and privately held companies consider the implications of this proposed rule.
Publicly traded companies may need to consider how the disclosed information will be used. The assumption is that forced disclosure will make companies change their behavior and reduce emissions. But it could also open companies to significant liability, including shareholder litigation.
Climate disclosures are surrounded by a degree of uncertainty, especially in anticipating climate impact. Scope 3 emissions calculations require many assumptions about human behavior and estimates to derive at a final number. These emissions also may be counted multiple times by different companies in the same value chain for a particular product.
This rule also requires companies to submit extensive amounts of information, which may require them to hire new personnel or outside consultants to analyze and report the required data to the SEC.
How are private companies affected?
Private companies may be asked by their publicly traded customers to estimate or account for their greenhouse gas emissions, which may also require them to hire outside consultants to assist with calculations and data gathering.
Additionally, this new rule will likely become a standard by which all companies are evaluated. Having ESG disclosures may make companies more attractive to customers and put private companies without ESG disclosures at a competitive disadvantage.
Although intended to drive companies to become greener, the new required disclosures may discourage companies from going public. ESG matters also will likely become a meaningful component of M&A transactions, and due diligence efforts will need to take into account the impact that a potential merger or acquisition will have on its climate disclosures.
ESG is a rapidly developing area of law. Business leaders should work with legal counsel and sustainability consultants when developing both voluntary and mandatory climate-related disclosures to mitigate risks related to these disclosures.
To view the full video with Gina Falaschi on this topic and other articles on current business issues and trends, visit www.pittsburghbusinesstimes.com/babstcalland. To learn more about Babst Calland and its environmental practice, go to www.babstcalland.com.
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Business Insights is presented by Babst Calland and the Pittsburgh Business Times.
Smart Business
(By SBN Staff featuring Gina Falaschi)
In March, the Securities and Exchange Commission (SEC) released a proposed rule entitled Enhancement and Standardization of Climate-Related Disclosures for Investors. If finalized, this rule would become some of the first mandatory Environmental, Social and Governance (ESG) reporting requirements for U.S. companies, requiring the disclosure of climate-related risk information in registration statements and periodic reports.
This proposed regulation has significant consequences not just for public companies, but private companies as well.
Smart Business spoke with Gina N. Falaschi, an associate at Babst Calland, about the implications of the proposed rule, should it take effect.
What requirements could the rule introduce?
Under the SEC proposal, public companies would be required to make a number of disclosures related to their climate-related risks and impact. Those include disclosures regarding the oversight and governance of climate-related risk by their board and management, how any climate-related risk has a material effect on business and consolidated financial statements, and information regarding any publicly set climate-related targets or goals.
The SEC’s proposal also requires the disclosure of certain greenhouse gas emissions, which are divided into three categories. Scope 1 emissions are the direct greenhouse gas emissions that occur from sources that a company owns or controls. Scope 2 emissions are the indirect greenhouse gas emissions that occur from the generation of energy that a company buys and consumes in its operations. Scope 3 emissions are the result of assets not owned or controlled by a company that the company indirectly impacts in its value chain, both upstream and downstream from the company’s operations. Scope 3 emissions would have to be disclosed only if considered ‘material.’
What do companies need to do to prepare?
While the regulation has not yet been finalized, many companies could be required to begin compliance in the near future, so it’s prudent that both publicly traded and privately held companies consider the implications of this proposed rule.
Publicly traded companies may need to consider how the disclosed information will be used. The assumption is that forced disclosure will make companies change their behavior and reduce emissions. But it could also open companies to significant liability, including shareholder litigation.
Climate disclosures are surrounded by a degree of uncertainty, especially in anticipating climate impact. Scope 3 emissions calculations require many assumptions about human behavior and estimates to derive at a final number. These emissions also may be counted multiple times by different companies in the same value chain for a particular product.
This rule also requires companies to submit extensive amounts of information, which may require them to hire new personnel or outside consultants to analyze and report the required data to the SEC.
How are private companies affected?
Private companies may be asked by their publicly traded customers to estimate or account for their greenhouse gas emissions, which may also require them to hire outside consultants to assist with calculations and data gathering.
Additionally, this new rule will likely become a standard by which all companies are evaluated. Having ESG disclosures may make companies more attractive to customers and put private companies without ESG disclosures at a competitive disadvantage.
Although intended to drive companies to become greener, the new required disclosures may discourage companies from going public. ESG matters also will likely become a meaningful component of M&A transactions, and due diligence efforts will need to take into account the impact that a potential merger or acquisition will have on its climate disclosures.
ESG is a rapidly developing area of law. Business leaders should work with legal counsel and sustainability consultants when developing both voluntary and mandatory climate-related disclosures to mitigate risks related to these disclosures.
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The American College of Environmental Lawyers (ACOEL)
(By Donald C. Bluedorn II)
On November 3, 2022, Pennsylvania Governor Wolf signed House Bill 1059, which amends the Commonwealth’s Tax Reform Code and, among other things, establishes the Pennsylvania Economic Development for a Growing Economy (“PA EDGE”) program, consisting of tax credits for four economic areas. https://www.legis.state.pa.us/cfdocs/billinfo/billinfo.cfm?sYear=2021&sInd=0&body=H&type=B&bn=1059.
Much of the publicity around the bill has focused on the tax credits available to promote a “hydrogen hub” and the use of hydrogen-based technologies. Indeed, the bill provides for tax credits up
to $50 million per year, or a total of $1 billion over a 20-year period.
In explaining his support for House Bill 1059, Governor Wolf started by noting his belief in the importance of the role of hydrogen in addressing the effects of climate change. “In its most recent report, the Intergovernmental Panel on Climate Change notes that ‘hydrogen is a promising energy carrier for a decarbonized world,’ and highlights hydrogen’s potential to ‘provide low-carbon heat for industrial processes or be utilized for direct reduction of iron ore.’” https://www.governor.pa.gov/wp-content/uploads/2022/11/20221103-1059.pdf.
The Governor then went on to note his belief that the use of hydrogen must be tied responsibly to the reduction of emissions and the consideration of Environmental Justice.
That said, I recognize that in order for hydrogen to play a meaningful role in reducing emissions, we must ensure that hydrogen used is truly “clean” through stringent emissions standards. We must also commit to strong and equitable community protections to prevent impacts to already overburdened communities and to guide benefits to communities that need them.
Perhaps the most controversial provisions of the bill, or at least those that drew the most attention in much of the press, were the provisions that also authorized a tax credit for the use of natural gas in the manufacturing of petrochemicals or fertilizers. In explaining his support for these provisions, the Governor highlighted his belief that these were stop-gap measures to help build a bridge to the future.
Relatedly, [the bill] also authorizes a tax credit based on the use of natural gas. This provision was included as a short-term fail-safe in the event that a manufacturing facility is constructed and clean hydrogen is not initially available. While I do not believe that it would be possible for a project facility that has been funded as part of a DOE regional clean hydrogen hub to utilize natural gas instead of hydrogen for a significant duration of time, the bill requires a company applying for the credit to sign a commitment letter stating the date by which it will begin to purchase clean hydrogen. It is my expectation that this period of time would not exceed a year or two.
In addition to its focus on hydrogen technology, House Bill 1059 also provides tax credits for Pennsylvania milk processing, biomedical manufacturing and research, and semiconductor manufacturing. In his statement, the Governor expressly recognized the need for even more support of semiconductor manufacturing in the Commonwealth. “This program is a first step to help chip manufacturers and their suppliers build new facilities in Pennsylvania, but we need to continue to invest in order to make Pennsylvania a leader in this industry.”
Founding Father Benjamin Franklin reportedly wrote that “in this world nothing can be said for certain, except death and taxes.” With the benefit of 21st Century hindsight, perhaps we can add hydrogen, natural gas, and climate change to the list . . . ?
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Reprinted with permission from the November 28, 2022 ACOEL Blog.
Legal Intelligencer
(by Alex Farone and Janet Meub)
Navigating the Family and Medical Leave Act (FMLA) in the COVID era, including the pandemic-related amendments, has felt like a minefield for many employers. Now that the surge of COVID-related uses of FMLA leave has largely passed, a new aspect of statutory compliance is emerging as a hot-button issue: treatment of remote workers under the FMLA.
The FMLA provides eligible employees with up to 12 weeks of protected, unpaid leave per year for qualifying family or medical reasons. In order to be eligible for FMLA coverage, four elements must be met:
- The employer is a covered employer under the Act, meaning it has at least 50 employees for at least 20 weeks in the current or previous year;
- The employee must have worked for the employer for at least 12 months, not necessarily consecutively;
- The employee must have worked at least 1250 hours in the last 12-month period; and
- The employee must be employed at a worksite where the employer employs at least 50 employees within a 75-mile radius.
Many employers do not pay much consideration to the last element, also known as the “50/75 Rule,” likely because the first element requires 50 employees and in the majority of instances those 50 employees are by default going to work within a 75-mile of the employer’s office. However, in the COVID era and beyond, more and more employees are permitted to work remotely on a full-time basis, and employers are hiring remote employees all over the country, regardless of the location of the employer’s physical office or operations.
The FMLA itself does not address remote workers, but the Department of Labor’s regulations specify that an employee’s personal residence is not a worksite for employees who work at home by telecommuting. 29 C.F.R. § 825.111(a)(2). Further, “[f]or employees with no fixed worksite … the worksite is the site to which they are assigned as their home base, from which their work is assigned, or to which they report.” Id.
In many instances, the remote employee’s home base, worksite from which their work is assigned, and worksite to which they report are one and the same—a single location such as a main office. For example, suppose a new data processing company has 100 employees and one physical office, located in Pennsylvania from which all management employees operate on-site. The company’s low-level data entry employees work remotely, and the company has been rapidly hiring employees nationally without regard to their state of residence. If a remote data entry employee in California seeks FMLA leave, the Company must determine her eligibility. Does the Company employ 50 employees within 75 miles of the office, which is the employee’s home base, the location from which her work is assigned, and to which she reports? If 20 employees work in the office, 10 more work remotely nearby in Pennsylvania, and 70 work remotely throughout the country, more than 75 miles away from the Office, then the 50/75 Rule has not been met, and the employee is not eligible for FMLA coverage.
Things get much more complicated, however, if the employer has multiple locations or if supervisors themselves work remotely. When passing the FMLA, the Senate indicated that the term “worksite” was intended to be interpreted in the same manner as the term “single site of employment” under the Worker Adjustment and Retraining Notification Act (WARN) and its regulations. See Sen. Rep. No. 103-3 at 23 (1993). So, when a remote employee’s worksite is not obvious, we look to case law interpreting the WARN Act to determine what it means for a worksite to be the site: (1) to which the employee is assigned as their home base; (2) from which their work is assigned; or (3) to which they report.
The Third Circuit provided a clear interpretation in Ciarlante v. Brown & Williamson Tobacco Corp., 143 F.3d 139 (3d Cir. 1998). Per Ciarlante, a remote employee’s “home base” must be, at a minimum, a location at which the employee would be physically present at some point during a typical business trip. It refers to the physical base of the employee, rather than to the physical base of the employer’s operations. A remote employee’s “assigning site” is the source of the day-to-day instructions given to the employee. It is not determined by the location of centralized payroll or other centralized managerial or personnel functions. Instead, it is the location of the workers who are ultimately responsible for creating work tasks—the source of instructions, rather than a mere conduit location through which instructions are passed to the employee. Finally, a remote employee’s “reporting site” is the location of the personnel who are primarily responsible for reviewing reports and other information sent by the employee to assess performance, record tasks completion, etc.
Needless to say, determining a remote employee’s worksite for purposes of analyzing FMLA eligibility under the 50/75 Rule is fact-intensive and case-specific. Employers who are particularly at risk of incorrectly applying the 50/75 Rule or granting FMLA leave to employees who are not actually eligible are: (1) employers with over 50 employees, all of whom work on-site, but are spread out over multiple locations that may not be within 75 miles of one another; and (2) employers with few physical locations but many remote employees who live in multiple states. The Third Circuit has not yet analyzed the 50/75 Rule for remote workers in the current era of now-standard employment of remote employees. The U.S. District Court for the Eastern District of Pennsylvania analyzed the issue back in 2013, but in the context of a remote employee’s transfer to another position and reporting location around the time of her requested FMLA leave. O’Donnell v. Passport Health Communs., 2013 U.S. Dist. LEXIS 51432, 2013 WL 1482621 (E.D. Pa. Apr. 10, 2013). Therefore, employers in this jurisdiction are left largely without guidance from controlling case law as to the legal worksite of remote employees under the FMLA.
It is more than just best practice for employers to get up to speed on the FMLA’s 50/75 Rule application to remote workers—their legal defense of any potential claim depends on it. In a claim for FMLA violation (typically either interference or retaliation), employers may assert the defense of good faith, which means the act or omission that allegedly violated the FMLA was done in good faith and that the employer had reasonable grounds for believing the act or omission was not a violation of the FMLA. See 29 U.S.C. § 2617(a). The FMLA does not define “good faith,” so courts look to the Fair Labor Standards Act for its interpretation of this phrase. Under this interpretation, good faith requires a duty to investigate potential liability and more than reliance on ignorance.
One recent case in another jurisdiction underscored just how substantial the burden is on employers to successfully invoke the good faith defense. See Landgrave v. ForTec Med., Inc., 581 F. Supp. 3d 804 (W.D. Tex. 2022). In January of 2022, a District Court in the Fifth Circuit granted an FMLA-leave-seeking plaintiff’s partial motion for summary judgment to deny her employer’s affirmative defense of good faith. The plaintiff was a remote employee, and the employer had denied her request for FMLA leave, deeming her ineligible under the 50/75 Rule based on their interpretation of the plaintiff’s worksite. Despite this denial, the plaintiff took a leave of absence from work to care for her ailing mother. As she had no available leave to use, her employer deemed her to have voluntarily resigned her position when she failed to report to work by a date certain. The plaintiff claimed that the employer failed to investigate the FMLA’s applicability to remote workers before ending her employment.
The employer’s Human Resources Manager testified that she had no knowledge of the FMLA’s treatment of remote workers and that she did not seek legal counsel regarding FMLA eligibility. She did review the employee handbook’s requirements of FMLA eligibility, which mentioned a requirement of 50 “employees in the work or reported-to location” to reach the decision that the plaintiff did not qualify for FMLA protection. However, the court agreed with the plaintiff that this investigation into FMLA eligibility was insufficient to constitute “good faith” on the part of the employer. Specifically, the court stated that referring to an employee handbook for guidance on how to assess FMLA eligibility of a remote employee does not relieve an employer of its duty to investigate the employee’s rights where the handbook does not address the treatment of remote workers.
Employers should consult legal counsel any time a remote employee seeks FMLA leave to determine if the 50/75 Rule is met. In turn, counsel should specifically inform their employer clients of the 50/75 Rule and ensure that the 50/75 Rule is represented in company policies or handbooks concerning FMLA eligibility for remote workers specifically. Additionally, employers should keep a regularly-updated list of the cities and states in which all remote employees live, to more quickly calculate the number of employees within 75 miles of a particular worksite.
Alexandra Farone is an associate in the Litigation and Employment and Labor groups of Babst Calland. Ms. Farone’s employment and labor practice involves representing corporate clients, municipalities, and individuals on all facets of employment law, including restrictive covenants, discrimination claims, human resources counseling, grievances, and labor contract negotiations. Please contact her at 412-394-6521 or afarone@babstcalland.com.
Janet Meub is senior counsel in the Litigation and Employment and Labor groups of Babst Calland. Ms. Meub has significant experience in the areas of employment and labor law, professional liability defense, insurance coverage and bad faith litigation, toxic tort litigation, nursing home negligence, and medical malpractice defense. She has a diversified practice that includes defending employers, healthcare providers, law enforcement and other professionals, and non-profits, at all levels of civil litigation through trial. Contact her at 412-394-6506 or jmeub@babstcalland.com.
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Reprinted with permission from the November 17, 2022 edition of The Legal Intelligencer© 2022 ALM Media Properties, LLC. All rights reserved.
PIOGA Press
Sources for below article: Pennsylvania Oil & Gas Landowner Alliance (POGLA) Post – November 6, 2022, Senator Yaw Press Release dated 11/7/22, and ‘Pennsylvania General Assembly Enacts Senate Bill to Amend Oil and Gas Lease Act’ alert by Babst Calland published on 11.8.22
(By Chelsea Heinz and Devlin Carey)
Legislation aimed at ensuring landowners are afforded a clear and distinct assessment of royalties paid to them through lease agreements with oil and natural gas operators has been signed by Governor Tom Wolf.
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) 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 said. “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, something I’ve heard a great deal about from leaseholders across our region,” Yaw said. “This proposal is designed to help ensure all parties feel their lease agreements are executed as intended, and it will help mitigate concerns that have developed in recent years.”
Senate Bill 806, now Act 153 of 2022, was supported by various agencies and organizations, 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.
“Pennsylvania Farm Bureau thanks Sen. Yaw for his diligent and persuasive advocacy on an issue of long-standing importance to our members,” said Rick Ebert, Pennsylvania Farm Bureau President. “Senate Bill 806 would provide much-needed clarity and certainty to Pennsylvania farmers about the royalties paid to them through lease agreements with oil and natural gas operators. We also thank the other stakeholders for their critical work throughout this process.” “The Pennsylvania Oil and Gas Landowner Alliance thanks Senator Yaw for sponsoring SB 806, which will provide check stub consistency and transparency for royalty owners,” said Robert Sher, POGLA president. “The Senator persistently sought input from all interested parties and advocated on behalf of the bill. Our organization is grateful for his efforts. “
“Senator Yaw has always been a tireless proponent for his constituents and all of the land and mineral owners of the Commonwealth,” said Bounty Minerals Director of Business Development Valerie M. Antonette. “Bounty Minerals was proud to partner with him to get SB 806 over the finish line after an eight-year campaign to bring more transparency to royalty statements. Ultimately, it was a cooperative effort between all stakeholders working together.”
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 conventional wells, these requirements include specifying:
- A name, number or combination of name/number that identifies the lease, property, unit or well(s) for which payment is being made; and the county in which the lease, property or well is located.
- Month and year of oil, gas or natural gas liquids production for which payment is being made.
- Total barrels of crude oil or number of Mcf of gas or volume of natural gas liquids sold.
- Price received per barrel, Mcf/gallon.
- Total amount of severance and other production taxes and other deductions permitted under the lease, with the exception of windfall profit tax.
- Net value of total sales from the property less taxes and deductions from paragraph (5).
- Royalty owner’s interest, expressed as a decimal or fraction, in production from paragraph (1).
- Royalty owner’s share of the total value of sales prior to deduction of taxes and deductions from paragraph (5).
- [Interest] Royalty owner’s share of the sales value less the royalty owner’s share of taxes and deductions from paragraph (5).
- Contact information, including an address and telephone number.
For unconventional wells, these requirements include specifying:
- Total barrels of crude oil or number of Mcf/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).
- 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 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, payors of royalties from production from unconventional formations 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).
For payors of royalties from production from conventional formations, the timing of payments continues to be governed by the leases.
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Reprinted with permission from the November 2022 issue of The PIOGA Press. All rights reserved.
PIOGA Press
(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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Reprinted with permission from the November 2022 issue of The PIOGA Press. All rights reserved.
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The 2023 Edition of “Best Law Firms” includes rankings in 75 national practice areas and 127 metropolitan-based practice areas. One “Law Firm of the Year” is named in each of the nationally ranked practice areas.
Click here to view the full ranking on U.S. News U.S. News & World Report-Best Lawyers® “Best Law Firms” list.
Smart Business
(By Sue Ostrowski featuring Chris Farmakis and Mike Matesic)
Finding the right match between investors and businesses needing capital can be hit or miss. How can investors reduce the challenges they face in identifying potential investment opportunities, and how can growing businesses attract the right partner?
“One of the most common barriers to bringing companies and investors together is mismatched expectations, where investors think a company is more mature, and the company is presenting itself that way, but after the investment, the investors find out the company is not as mature as they thought,” says Mike Matesic, President and CEO of Idea Foundry, which has helped launch more than 250 companies that have generated more than $1 billion in direct economic impact to the region over the last 20 years. Helping companies attract needed capital has been an essential part of Idea Foundry’s services and that required getting close to investors to understand their needs.
“The other challenge is that investors don’t like to immediately say ‘no’,” says Chris Farmakis, shareholder and Board Chair at law firm Babst Calland.
“It’s very dangerous for a business to think it’s getting funding and start spending before they have it,” says Farmakis. “It is very difficult for a company to recover when it finds out its promised funding fell through.”
An experienced funding program, however, can screen companies, ensure transparent communication, and bring companies together with a pool of investors.
Smart Business spoke with Farmakis and Matesic about how a third-party funding program can help both sides of the investment equation make the most of the deal.
What are the advantages of working with experienced organizations to find the right partner on both sides?
People want to invest in companies that sound exciting, but oftentimes it’s hard to find those at the right time and right deal terms. If you’re an investor looking for companies, you can’t spend all your time vetting and evaluating companies. Investing by individuals is inherently a risky, speculative venture. Affiliating with a competent investment group can lessen this risk.
IF Ventures is a group of successful entrepreneurs, experienced investors, and business owners. We seek companies with proven technology or products that have customers and revenue, and a strong management team. Many companies are just too early in the game to meet these criteria. And for more mature companies, better sources of capital probably exist. If a company meets all our criteria, we internally vet it. Only the best opportunities are brought to the investment group.
Businesses from any type of industry are eligible, from a traditional company to one focusing on technology or an innovative product.
Where is the void in the Pittsburgh market?
Pittsburgh does fairly well in the early stages of investments, attracting money from economic development organizations, friends and family, to get something going. It also does well after the company has matured to the point where it can attract private equity. But in that middle space, the angel space in which we transact, companies oftentimes run out of money and time, leading to the valley of death.
IF Ventures’ success hinges on the critical collaboration between the Idea Foundry and Babst Calland. Idea Foundry focuses on sourcing the deals, doing the initial due diligence and bringing companies forward. Babst Calland negotiates the investment terms for the investment group and attracts additional investors to the program.
The region continues to develop more business opportunities for investment. But the capital base hasn’t expanded accordingly. So, initiatives like IF Ventures are designed to attract additional investors and additional investment to companies to help the region broadly, and it couldn’t be timelier.
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Pittsburgh Business Times
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Business Insights is presented by Babst Calland and the Pittsburgh Business Times.
Legal Intelligencer
(by Max Junker and Anna Jewart)
Municipalities face many restrictions on how they may use real property, and Pennsylvania law places additional statutory restrictions on a municipality’s conveyance of property which has been used as a “public facility.” The Donated or Dedicated Property Act, 53 P.S. §§3381-3386 (DDPA), states that “[a]ll lands or buildings… donated to a political subdivision for use as a public facility, or dedicated to the public use or offered for dedication to such use… shall be deemed to be held by such political subdivision, as trustee, for the benefit of the public with full legal title in the said trustee.” “Lands” include all real estate, whether improved or unimproved, and a “public facility” includes, without limitation “any park, theater, open air theater, square, museum, library, concert hall, recreation facility or other public use.” Any such lands or buildings are required to be used only for the purpose or purposes for which they were originally donated or dedicated, unless modified by court order.
Consequently, a municipality cannot simply sell or change the use of real property donated for or dedicated to use by the public. This concept may seem familiar to the lay person and land use practitioner alike because, in essence, the DDPA codifies the common law of the “public trust doctrine” which requires that public property dedicated to public use be held by the municipality, as a trustee, for the benefit of the community.
However, the DDPA allows the municipality to dispose of public trust property in certain specific circumstances if approved by the court. Specifically, under Section 4 of the DDPA, a municipality may apply to the orphan’s court for certain enumerated relief if, in the opinion of the municipality, the continuation of the original use of the property held in trust as a public facility is no longer practicable or possible and has ceased to serve the public interest. Under the DDPA, the orphan’s court may permit the trustee to:
- substitute other lands or property of at least equal size and value in exchange for the trust property in order to carry out the trust purposes;
- sell the property and apply the proceeds to carry out the trust purposes, but only if other property is not available;
- apply the property or proceeds therefrom to a different public purpose, but only if the original trust purpose is no longer practicable or possible or in the public interest; or
- relinquish the land and buildings if there has been no formal acceptance, and only if the court is satisfied that no acceptance by implication arising out of public use occurred.
Recently, in the case of In re Township of Jackson, 280 A.3d 1074 (Pa. Cmwlth, 2022), the Commonwealth Court revisited several seminal cases interpreting the DDPA to consider whether the orphan’s court had properly denied the petition of Jackson Township, Lebanon County, to sell a parcel donated to the Township for use as a public park. In part, the Court considered whether the orphan’s court or the municipality had the discretion to determine whether the trust purpose was no longer practicable, possible, or in the public interest under Section 4 of the DDPA.
Like many municipalities in Pennsylvania, Jackson Township’s Subdivision and Land Development Ordinance (SALDO) requires a developer to either dedicate land to the Township for public recreational use or pay fees in lieu thereof. When the developer of a residential plan sought Township approval, it opted to donate land to the Township, and chose a 5.7 acre parcel identified as Lot 107 (“Park Lot”). In 2005, the developer conveyed the Park Lot by deed to the Township to be used “for ever [sic] as a public park or [for] other public purpose.” At the time of donation, however, there existed conditions on the Park Lot which rendered it less than ideal for use as a public park including a drainage easement, a private road easement, steep slopes, limited public access, and heavily wooded areas. Although the Township Recreation Board recommended against accepting the Park Lot, the Board of Supervisors accepted the donation as a public park.
Later, the Township studied how to develop the Park Lot as a trail system, basketball court, or nature preserve. Although the Township budgeted for improvements, none ever occurred. Eventually, at the recommendation of the Recreation Board, the Township Supervisors voted to pursue a sale of the Park Lot. The Township filed a petition for leave of court to sell the Park Lot for the stated reason that “[d]ue to the topography of the land as well as the cost to maintain said lot,” it was not practicable to develop it as a public park and that the continued use does not “serve the general public interest.”
In the orphan’s court, the Township Engineer testified that although the Park Lot could not accommodate sports fields or recreational buildings, it could be used as a walking trail and a flat portion could be used as a playground or basketball court at a cost of $80,000. Neighbors testified against the sale of the parcel, stating the lot connected two ball-fields and that a trail through the Park Lot would allow children to walk to the fields without crossing the roads. Residents showed that the Township had advertised and developed plans for the Park Lot as a neighborhood park with a walking path and basketball court. In addition, the developer had charged a premium for lots located adjacent to the Park Lot, touting it as a public park. The Township argued that a walking trail could affect pedestrian safety, that the excavation and grading required would cost more than it would on a flat lot, and that it was in the best economic interest of the Township to sell the Park Lot.
The orphan’s court denied the Township’s petition. Although it recognized the Park Lot was not ideal for recreational development, it found that the Township failed to establish that it was entitled to relief under Section 4 of the DDPA. The orphan’s court noted that the Park Lot had been dedicated for recreation purposes and the Township had accepted that use for the public. It found that the vacant and unimproved nature of the Park Lot did not change the nature of the dedication or its use for recreation purposes, defining recreation as “refreshment of strength and spirits after work,” or a “means of refreshment or diversion.”
On appeal, the Township argued the orphan’s court was bound by the Township’s determination that the original use of the property was no longer practicable or possible and no longer served the public interest. Relying on In re Erie Golf Course, 992 A.2d 75 (Pa. 2010) and In re Borough of Downington, 161 A.3d 844 (Pa. 2017), the Court found that the orphan’s court has final discretion about how the property should be used, and that the Township, as trustee, had a fiduciary obligation to maintain donated and dedicated land for public use. As stated by the Court: “Section 4 of the [DDPA] does not vest controlling discretion in the political subdivision; rather, it merely authorizes the municipality, as trustee, to file an application for relief in the trial court.” The Court noted that the Supreme Court in Erie Golf Course made it clear that “the sale of the property was not discretionary with the [municipality] in the first instance in light of its fiduciary obligations,” and that “essential discretion lay in the [trial] court, to which appellate court deference is due.” Therefore, Section 4 of the DDPA does not vest controlling discretion in the municipality, but rather merely authorizes the municipality to file a petition for relief.
Ultimately, the Court found no error in the orphan court’s judgment that the Township had not established that recreational use of the Park Lot was no longer practicable, either physically or financially. The Court noted the Park Lot could be left unimproved or the Township could develop a walking trail and basketball court at a cost of $80,000 for which the Township had sufficient funds. In addition, the Court rejected the Township’s argument that the orphan’s court had abused its discretion because the proceeds from the Park Lot could be better used by improving another recreational facility which would benefit a wider group of residents. The Court reasoned that the DDPA focuses on whether the original use has ceased to serve the public interest, not whether another use would better serve the same.
Max Junker is a shareholder in the public sector, energy and natural resources and employment and labor groups of Babst Calland. Anna S. Jewart is an associate in Babst Calland’s Public Sector Services group and focuses her practice on zoning, subdivision, land development, and general municipal matters.
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Reprinted with permission from the October 20, 2022 edition of The Legal Intelligencer© 2022 ALM Media Properties, LLC. All rights reserved.
PIOGA Press
(By Brianne Kurdock and Keith Coyle)
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. The Rule focuses mainly on transmission pipelines and amends or adds various provisions to 49 C.F.R. Part 192. The Rule will become effective on May 24, 2023. There are six key areas that owners and operators of gas transmission pipelines should be aware of:
Definitions and Standards Incorporated by Reference
PHMSA added new definitions for terms referenced in the 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. 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.
Management of Change
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. 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 discovered deficiencies. PHMSA acknowledged that these new construction and corrosion control requirements do not apply to gathering or distribution pipelines.
Inspections and Remedial Action Following Extreme Weather Events
Similar to the requirements for hazardous liquid pipeline operators, PHMSA is now requiring gas operators to perform an initial inspection following extreme weather events 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 operator must take prompt remedial action to ensure the safe operation of a pipeline based on the information obtained from the inspection. PHMSA explains that such remedial actions may include reducing the operating pressure, shutting down the pipeline, modifying, repairing, or replacing any damaged pipeline facilities, or performing additional patrols, surveys, tests, or inspections.
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 now identical to those in Subpart O. 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.
Other Considerations
On September 23, 2022, the Interstate Natural Gas Association of America, the American Petroleum Institute, and the American Gas Association submitted petitions for reconsideration on this rule.
If you have any questions about PHMSA’s new final rule, contact Brianne Kurdock at 202-853-3462 or bkurdock@babstcalland.com or Keith Coyle at 202-853-3460 or kcoyle@babstcalland.com.
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Reprinted with permission from the October 2022 issue of The PIOGA Press. All rights reserved.
The Wildcatter
(By Nikolas Tysiak)
Welcome back to the real world! Now that summer is over, and Russian gas is being abandoned by many around the world, the oil and gas industry, and particularly the operators and land professionals in the Appalachian Basin, find themselves with more to do than ever before. There was not a lot of activity over the summer, but a few interesting developments arose.
SWN Production Company v. Kellam, 875 S.E.2d 216 (W. Va. 2022). Certified question to W. Va. Supreme Court from federal district court for the Northern District of West Virginia. Primarily, the Supreme Court was asked whether the 2006 case Estate of Tawney v. Columbia Natural Resources remained good law, and, if so, how to apply the requirements regarding deduction and calculation of royalties contained in that lease. After a lengthy discussion of the history behind royalty litigation in West Virginia and comparing the circumstances of Tawney to Leggett v. EQT Production Co., 239 W. Va. 264 (2017), the Court concluded that Tawney remains good law and is applicable to contractually created royalty provisions, while Leggett applies to statutorily created royalties.
Senterra Limited v. Winland, 2022-Ohio-2521. Marketable Title Act case. In a unique twist, the surface owner attempted to utilize the Duhig rule (a Texas case regarding repeated, identical reservations of oil and gas interests) to indicate that a ¼ oil and gas reservation was void at its inception, and therefore should be vested with the surface owners. The court disagreed, pointing to the unbroken chain of title of the severed mineral owners effectively preserving the reserved oil and gas interest. The court further found that reliance upon Duhig would not resolve the issue in favor of the surface owner in any case and found in favor of the severed mineral owner.
In addition to the above cases, the new West Virginia statutory pooling statute became active as of June 30, 2022 (W. Va. Code §22C-9-7a). This allows oil and gas operators to bring unleased interests into an oil and production unit without landowner consent under certain circumstances. As a threshold issue, at least 75% of the net acreage in a unit must be under lease/control of oil and gas operators, and 55% of the working interest must be vested in the operator making the petition for a statutory unit. Operators can effectively establish joint operations with other, minority operators using the statute. However, the applying operator must first go through an extensive application process that includes (among other things) a significant investment in time and effort to compile title for the entire proposed unit. The application process must be heard by the Oil and Gas Conservation Commission in Charleston and is subject to extensive accounting oversight before approval will be given. As of the date of this writing, we understand that only one application has been made and no approvals have yet been given.
Also, effective June 30, 2022, West Virginia removed the prior requirement under the Cotenancy Modernization and Majority Protection Act (W. Va. Code §37B-1-1, et seq.) that, as a threshold matter, there needed to be at least 7 “royalty owners” before the act could be utilized. The only threshold matter as to whether the Act applies now is whether the operator seeking protection under the Act has at least 75% of the oil and gas leased or otherwise controlled. Finally, West Virginia instituted new reporting requirements for well production and payments for royalty owners (W. Va. Code §37C-1-1, et seq.). Failure to make timely payments and reports under this new act will result in fines against Operators on a percentage basis, calculated as prime rate plus 2% in interest charges against the amount unpaid.
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Reprinted with permission from the MLBC October 2022 issue of The Wildcatter. All rights reserved.
Legal Intelligencer
(by Gina Falaschi and Christina Puhnaty)
The Pennsylvania Environmental Quality Board (EQB) will soon publish amendments to the Department of Environmental Protection’s (PADEP) regulations in 25 Pa. Code Chapters 121 and 129 for all major stationary sources of nitrogen oxides (NOx) or volatile organic compound (VOC) emissions, commonly known as the RACT III rule. The rule would require major sources of either or both of these air pollutants in existence on or before August 3, 2018 to meet “reasonably available control technology” (RACT) emission limits and requirements by January 1, 2023.
These regulations are being promulgated to address Federal Clean Air Act (CAA) RACT requirements to meet the 2015 ozone National Ambient Air Quality Standards (NAAQS) in the Commonwealth. The CAA requires a reevaluation of RACT when new ozone NAAQS are promulgated. RACT is required in nonattainment areas, including the Ozone Transport Region which includes Pennsylvania. The RACT III rulemaking establishes presumptive RACT requirements and emission limits for specific source categories of affected facilities. The RACT III rulemaking also imposes additional requirements for all major sources of NOx and/or VOCs, not just those subject to the presumptive RACT requirements and limitations.
RACT III applies to all major sources of VOCs and NOx. Because the Commonwealth is in the Northeast Ozone Transport Region, the major source threshold is 50 tons per year of VOCs and 100 tons per year of NOx. PADEP estimates that 425 Title V facility owners and operators will be subject to the final rule. Affected source categories include combustion units; municipal solid waste landfills; municipal waste combustors; process heaters; turbines; stationary internal combustion engines; Portland cement kilns; glass melting furnaces; lime kilns; direct-fired heaters, furnaces or ovens; and other sources that are not regulated elsewhere under Chapter 129. The sources included in these categories are located at various facility types including: fossil fuel-burning and other electric generation; natural gas pipeline transport and distribution; petroleum refining; petroleum and coal products manufacturing; iron and steel milling; nonferrous metal smelting and refining; chemicals manufacturing; Portland cement manufacturing; pharmaceuticals manufacturing; and biotechnology. RACT III imposes presumptive RACT limitations and requirements on additional categories of facilities that were not previously subject to any presumptive RACT limitations or requirements. These categories include glass melting furnaces, lime kilns, and certain combustion units.
Owners and operators of existing major sources without presumptive requirements or limitations, or those unable to meet the presumptive RACT limitations or requirements may submit a proposed alternative RACT limitation or requirement (case-by-case RACT analysis). PADEP has established an aggressive deadline of December 31, 2022 by which case-by-case RACT proposals must be submitted.
Sources that previously proposed and obtained a case-by-case RACT under a prior rule (e.g., RACT II) are still required to address RACT III requirements. The final rulemaking does, however, provide an option for an owner or operator to demonstrate that the applicable RACT II requirements satisfy RACT III requirement in lieu of a full case-by-case analysis. PADEP reviews these analyses and submits those that are approved to the United States Environmental Protection Agency (EPA) as revisions to the Commonwealth’s State Implementation Plan (SIP).
The final rulemaking establishes presumptive RACT requirements at Section 129.112 for certain source categories of major NOx or VOC emitting facilities. For some source categories, such as fugitive VOC air contamination sources at natural gas compression and transmission facilities that have the potential to emit less than 2.7 TPY of VOC, PADEP determined that RACT requires only that these sources “install, maintain, and operate the sources in accordance with the manufacturer’s specifications and with good operating practices.” For several source categories, however, PADEP established NOx and/or VOC emission limitations as presumptive RACT. For example, at affected facilities, the following NOx emission limitations apply to the following source categories:
Glass Melting Furnaces (Section 129.112(i)(4))
- 4.0 pounds of NOx per ton of glass pulled for container glass and fiberglass furnaces
- 7.0 pounds of NOx per ton of glass pulled for pressed or blown glass and flat glass furnaces
- 6.0 pounds of NOx per ton of glass pulled for all other glass melting furnaces
Cement Kilns (Section 129.112(h))
- 3.88 pounds of NOx per ton of clinker produced for a long wet-process cement kiln
- 3.0 pounds of NOx per ton of clinker produced for a long dry-process cement kiln
- 2.30 pounds of NOx per ton of clinker produced for a preheater and precalciner cement kiln
Lime Kilns (Section 129.112(j))
- 4.6 pounds of NOx per ton of lime produced
The owner or operator of a NOx air contamination source with a potential emission rate equal to or greater than 5.0 tons of NOx per year for which presumptive RACT requirements are not outlined in Section 129.112 is required to propose a NOx RACT requirement or RACT emission limitation to PADEP. Similarly, the owner or operator of a VOC air contamination source with a potential emission rate equal to or greater than 2.7 tons of VOC per year for which presumptive RACT requirements are not outlined in Section 129.112 is required to propose a VOC RACT requirement or RACT emission limitation to PADEP.
Notably, Section 129.115 requires that all major VOC or NOx emitting facilities submit a written notification to PADEP or the appropriate local air pollution control agency by December 31, 2022, identifying air contamination sources at the facility as covered by—or exempt from—RACT III requirements. This written notification requirement applies to all major sources of NOx and VOC emissions, even if those facilities are not subject to the presumptive RACT provisions of Section 129.112. The written notification must include the following for each identified air contamination source:
- A description of each identified air contamination source at the facility, including make, model, and location;
- The applicable RACT requirement or RACT emission limitation;
- How the owner or operator shall comply with the application RACT requirement or RACT emission limitation; and
- The reason why a source is exempt from the RACT requirements and RACT emission limitations, if applicable.
Operators are not required to immediately amend operating permits to include RACT III, but as of January 1, 2023, the final rulemaking will apply to those sources covered by the rulemaking. As of this compliance date, RACT III’s requirements could supersede any conflicting requirements and emissions limitations in a facility’s permit or Pennsylvania regulations, unless those conflicting requirements are more stringent than RACT III. See Section 129.112(l)–(m). These superseded regulations include those that exempt glass manufacturing sources from emission requirements during periods of start-up, shutdown, or malfunction (SSM). PADEP has determined that such SSM exemptions do not contain enforceable emission limitations and, therefore, do not constitute RACT.
EQB adopted the proposed rulemaking in May of 2021. The proposed rulemaking was published for public comment and PADEP held public hearing on the proposal. PADEP reviewed and responded to comments on the proposed rule and presented the final rule to the EQB at its August 9, 2022 meeting, where it was approved. Upon approval, the regulation was submitted to the House and Senate Environmental Resources & Energy standing committees of the General Assembly and the Pennsylvania Independent Regulatory Review Commission (IRRC). The House and Senate Committees approved the regulation on September 14, 2022 and IRRC approved the regulation on September 15, 2022. Once the regulation is approved by the Office of the Attorney General, the final rulemaking can be published in the Pennsylvania Bulletin. Thereafter, the PADEP will submit it to EPA for incorporation into Pennsylvania’s SIP.
The RACT III compliance date established by EPA is January 1, 2023 and this regulation will go into effect upon publication in the Pennsylvania Bulletin. As publication prior to the end of 2022 is likely, owners and operators should take note of the impending December 31, 2022 notification deadline described above.
Gina Falaschi is an associate in the Environmental Group of Babst Calland. Ms. Falaschi provides advice to clients in the energy, transportation, and technology sectors regarding compliance with state and federal environmental regulations. She has assisted companies with disclosure of regulatory violations to state and federal agencies and has counseled clients in negotiations with the U.S. Department of Justice, U.S. EPA, and California Air Resources Board. Contact her at 202-853-3483 or gfalaschi@babstcalland.com
Christina Puhnaty is an associate in the Environmental Group of Babst Calland. She assists clients with matters encompassing a broad range of environmental issues, including those related to state and federal permitting, regulatory compliance, and environmental litigation. Contact her at 412-394-6514 or cpuhnaty@babstcalland.com.
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Reprinted with permission from the October 6, 2022 edition of The Legal Intelligencer© 2022 ALM Media Properties, LLC. All rights reserved.
Smart Business
(By Sue Ostrowski featuring Matthew Moses)
Labor and supply shortages, combined with rising interest rates, have many owners reconsidering the timeline for their construction projects — and in some cases, they are deciding not to proceed.
“Materials that used to be available in the normal course of business — concrete, steel, aggregate, light fixtures, lumber — that go into construction projects are now not as readily available,” says Matthew Moses, attorney at Babst Calland. “With interruptions in foreign trade, domestic supplies and transportation, things that used to be viewed as completely dependable now may not be available as needed. And the construction labor supply is smaller than it used to be before COVID, in both in the trades and in unskilled labor.”
Smart Business spoke with Moses about what to consider before deciding when — and if — to move forward with a construction project.
How are rising interest rates impacting construction?
If owners have their own funds to spend on a project, that’s great. But if they need financing, the cost of borrowing has increased and is widely expected to continue to rise. That could have a significant impact on the cost of a project, as a 1.5 percent interest rate increase on a $5 million project could result in a six-figure cost increase.
There is some pressure to borrow now, before interest rates rise further. Ask your lender how long it can commit to a rate lock for a particular project. That has typically been a few months but is changing with interest rate volatility. And while that was not previously a major problem, it can be if the project is contingent on other actions that push out the closing date on the loan. If you are buying property, it may be difficult to get the acquisition signed and closed in a shorter time frame. In addition, government permits can take months, and that initial interest rate commitment could expire by the time permits are received.
Projects are costing more than anticipated, and as material and labor costs continue to rise, some businesses are moving forward quickly before they go higher. However, many large projects have been put on hold as owners re-evaluate their capital priorities and decide not to proceed on noncritical projects. But delay also risks interest rates being even higher in six months to a year.
How does force majeure play into the current situation?
Force majeure is a contract provision that affords a party temporary relief from liability if they can’t perform because of circumstances outside their control, such as adverse weather or interruptions in supplies or labor. Contracts should specify how long of a delay a contractor is allowed before the contractor becomes liable for failing to perform. Shortages of materials and labor are a serious problem, and some contractors are shifting their available resources among multiple projects to keep the projects moving forward. That, in turn, lengthens the timeline for the project.
Owners should also attempt to secure a firm contract price, or at least limit the components subject to fluctuation. If you don’t have a firm price, an increase in the cost of materials could result in a project budgeted at $10 million rising by several million dollars. However, contractors are impacted by circumstances they don’t control, and they may not be able to agree to a firm contract price.
What do you see going for construction going forward?
Theoretically, higher interest rates will cool construction activity somewhat and help stabilize costs of materials. As inflation comes under control, theoretically, interest rates would stabilize. Construction costs — both of materials and labor and of borrowing — are expected to remain higher than they were pre-pandemic, but at least they would be more predictable.
Before proceeding with a construction project, evaluate how mission critical it really is and how much project delays would affect operations. If you knock out a factory wall to add floor space for a new production line, certain areas could be unusable until construction is complete — which could impact operations if it goes on longer than expected.
Ask if you really need to it right now, and if you do, understand the potential increased costs as a result of increasing interest rates and a shortage of materials and labor, and the detrimental impact it will have if the project continues longer than expected.
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Babst Calland announced that Attorney Sloane Wildman has joined the firm’s Washington, D.C. office as a shareholder and member of its Environmental practice group.
Sloane Wildman’s practice involves CERCLA and RCRA site remediation and counseling clients in all aspects of environmental law and regulation, including RCRA, CERCLA/EPCRA release reporting, Safe Drinking Water Act, TSCA, FIFRA, green marketing, the Clean Water Act and the Clean Air Act. She represents clients in administrative, civil judicial and criminal enforcement cases. Her wide-ranging RCRA experience includes counseling, defense of enforcement actions and permitting and encompasses all aspects of federal and state hazardous waste regulation, including solid and hazardous waste identification, generation, transportation, treatment, storage, disposal, closure and corrective action matters.
Ms. Wildman earned her J.D. from the University of Virginia School of Law and received her undergraduate degree from Dartmouth College.
Ms. Wildman is admitted to practice in the District of Columbia and California (inactive) and before the U.S. District Courts for the Eastern and Southern Districts of California. She is a member of the District of Columbia Bar Association’s Environment, Energy and Natural Resources Section and the American Bar Association’s Natural Resources, Energy and Natural Resources Section.