Articles, Alerts & Perspectives Archive

Pa. Allows Oil and Gas Operators to Drill Cross-Unit Wells

The Legal Intelligencer

(by Megan Mariani and Nicholas Habursky)

On Nov. 7, Pennsylvania Gov. Tom Wolf signed into law Senate Bill No. 694 that permits cross-unit drilling for unconventional oil and gas wells. This new law takes effect on Jan. 6, 2020. A cross-unit well (also known as an allocation well) is a lateral wellbore that crosses between two or more pooled units.

Benefits of Cross-Unit Wells

Standard oil and gas lease forms commonly contain acreage limitations regarding the maximum size of a pooled unit within which development can occur. As a result, prior to the passage of this new cross-unit well legislation, operators in Pennsylvania faced inefficiencies in the form of limitations on the length of laterals and required additional surface locations to develop the entirety of the resource. Operators may desire to utilize cross-unit wells because the wells can increase drilling efficiencies and allow for more strategic operations. Landowners also benefit from cross-unit wells because the use of longer lateral wellbores reduces the surface impact of horizontal drilling by limiting the number of surface locations and vertical wellheads needed to produce from the various units. Lawmakers hope this bill will allow operators to maximize the benefits of drilling technologies and practices. Additionally, legislators believe the passage of the bill will increase tax revenue and reduce the workload on the Department of Environmental Protection.

What Does the Law Do?

Senate Bill No. 694 amended the act of July 20, 1979 (P.L. 183, No. 60—known as The Oil and Gas Lease Act) by adding Section 2.2 that expressly allows an operator to drill a cross-unit well if two conditions are met. First, an operator may drill and produce a cross-unit well if the operator reasonably allocates production from the well to or among each unit the operator reasonably determines to be attributable to each unit. The operator may allocate production from the cross-unit well on an acreage basis if the allocation has a reasonable correlation to the portion of the horizontal wellbore in each unit. Second, an operator may drill a cross-unit well as long as the well is not expressly prohibited by the terms of a lease.

Further, the bill mandates that the 330-foot spacing requirement of the Oil and Gas Conservation Law (the act of July 25, 1961-P.L. 825, No. 359), which requires that a well be located at least 330 feet from an outside boundary line, shall not apply to unit lines traversed by a cross-unit well. The bill also explicitly states that it does not authorize an operator to drill an oil and gas well without a valid lease or royalty agreement. Additionally, the bill does not impact the current surface rights of an operator to include operations related to any existing unit or any well drilled between existing units.

Future Trends and Considerations

The production allocation language in Senate Bill No. 694 is likely to be the most significant portion of the law. Prior to Senate Bill No. 694, there was limited authority in Pennsylvania as to the appropriate production accounting method since no Pennsylvania court or legislative body had fully addressed how cross-unit royalties should be allocated. Senate Bill No. 694 attempts to provide operators with guidance on cross-unit production accounting.

The new law employs a reasonableness standard by emphasizing that the operator must be able to “reasonably” allocate the production that it reasonably determines to be attributable to each unit. Senate Bill No. 694 further states that an operator may allocate production on an acreage basis for cross-unit wells, provided the allocation has a reasonable correlation to the portion of the horizontal wellbore in each unit.

Based upon the law’s usage of the word “may,” it appears that an operator could potentially use accounting methods not necessarily tied to acreage. However, aside from applying the “reasonable” standard to production allocation, the new law does not specifically explain any other nonacreage based accounting methods that an operator could utilize. Senate Bill 694 provides operators with the freedom to determine how best to reasonably allocate production between the units.

The new law eliminates any question as to whether Pennsylvania permits cross-unit wells. Although operators may still have to decide how best to allocate production from cross-unit wells, the ability to drill cross-unit wells should lead to increased efficiencies that will benefit both operators and landowners. As the industry’s technological evolution continues, it is likely that cross-unit wells will be a new tool for future oil and gas operations in Pennsylvania.

For the full article, click here.

Lawmakers introduce the Pennsylvania Carbon Dioxide Cap and Trade Authorization Act

The PIOGA Press

(by Kevin Garber and Jean Mosites)

On November 20, members of the Pennsylvania House and Senate referred bipartisan companion bills House Bill 2025 and Senate Bill 950, both known as the Pennsylvania Carbon Dioxide Cap and Trade Authorization Act, to their respective Environmental Resources and Energy Committees for consideration.

Sponsors Senator Joe Pittman (R-Armstrong) and Representative Jim Struzzi (R-Indiana) announced the bills in a press conference on November 19 in response to Governor Tom Wolf’s October 3 Executive Order 2019-07. That order directed the Environmental Quality Board to propose, by July 31, 2020, a carbon dioxide cap-and-trade program for fossil fuel-fired electric power generators which is at least as stringent as that developed under the Regional Greenhouse Gas Initiative (RGGI). (For more detail on RGGI, see the October issue of The PIOGA Press.)

The bills each provide a declaration of policy, procedures for the proper introduction of any program governing carbon dioxide emissions by the Pennsylvania Department of Environmental Protection and the process for submitting that program to the General Assembly for approval.

No current authority to regulate CO2 emissions

Section 2 of the bills finds there is currently no statutory or constitutional authority allowing a state agency to regulate or impose a tax on carbon emissions, and therefore the General Assembly, in consultation with DEP and other agencies, must determine whether and how to do so.

No rulemaking without specific statutory authority
Other than a measure required by federal law, Section 4 prohibits DEP from adopting any measure or taking any action to abate, control or limit carbon dioxide emissions (including joining or participating in RGGI or other state or regional greenhouse gas cap-and-trade program) or establishing a greenhouse gas cap-and-trade program unless the General Assembly specifically authorizes it by statute.

If DEP plans to propose such an action, Section 5 directs the agency to publish proposed legislation in the Pennsylvania Bulletin for at least 180 days and hold at least four public hearings in locations where regulated sources of carbon dioxide emissions would be directly economically affected by the proposal.

Following the public comment period, DEP must prepare a detailed report for both the Senate and House Environmental Resources and Energy Committees that addresses the ramifications of the proposal on affected facilities and Pennsylvania’s economy. The report must identify the individual facilities, by county, that would be subject to the proposed action and must include:

The amount of carbon dioxide emitted from each facility;
The estimated cost of compliance;
The effect the proposed action would have on the price of electricity;
A list of facilities that would be unlikely to continue operating;
An assessment of the decrease of electricity that would be exported from Pennsylvania; and
An assessment of any impact on the resilience and diversity of Pennsylvania’s electric generation fleet if an identified facility is forced to close.

The report must also address effects on the statewide economy, including:

Direct and indirect costs to the Commonwealth, political subdivisions and the private sector;
The wholesale and resale prices of electricity for residential, commercial, industrial and transportation consumers;
Adverse effects on the prices of goods and services, productivity and competition; and
The administrative, legal, consulting and accounting costs imposed by the proposal.

The report must also: i) estimate the net carbon dioxide reduction that the proposal would engender within PJM Interconnection (the regional transmission organization that coordinates the movement of wholesale electricity within Pennsylvania and 12 other states), considering electric generation in other PJM members that are not a part of RGGI or do not regulate or tax carbon dioxide emissions; ii) summarize and justify actions that would address leakage (an increase in emissions by facilities outside Pennsylvania in response to reductions in Pennsylvania); and iii) evaluate whether less costly or less intrusive alternative methods to achieve the goal of the proposed action have been considered for an employer or facility otherwise subject to the action.

Other implications

Although the sponsors centered the implications of their bills on the governor’s attempt to unilaterally join RGGI, the bills were written broadly enough to require a General Assembly review and authorization process for any proposed cap-and-trade program, which would include any rulemaking that would result from the economy-wide cap-and-trade petition currently under consideration by DEP or the Environmental Quality Board. (For more information on the cap-and-trade petition, see the April PIOGA Press.)

Next steps

The bills will be discussed and voted on by their respective committees before reaching the floor of each chamber. As of this writing, there are no Environmental Resources and Energy Committee meetings scheduled for either the House or Senate through the end of the year.

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Carl A. Ronald – Intellectual Property Attorney

Emerging Technologies Profile

What do you do? As an intellectual property attorney, I get to work with amazing and creative people to identify and protect what they have imagined and created. Some of these people are also business owners and I work with them to protect and enforce the reputational goodwill that they have earned with their customers and in the marketplace.

Why do you do what you do? I have always been interested in how things work and as an IP practitioner, I get to learn about new and developing technologies on a daily basis.

Describe your most memorable client interaction. Testing a semi-robotic bone shaver to be used in partial knee replacement on a disembodied leg in a cadaver lab.

Describe a client project (transaction/negotiation/dispute) that you are proud of. I handled a trade dress dispute relating to after-market grip tape for tennis rackets, in which a competitor was claiming they “owned” a large spectrum of the color blue for any grip tape. Facing an insurance coverage rejection, we were able to convince the carrier to reverse course and provide a defense in the infringement case. At the conclusion of a non-jury trial, the case resolved with a much narrower scope of protection for the competitor than they were claiming, which was a win for the client.

When you are not at work, you can be found… Working on house projects, exploring other cities, watching my kids play sports, or playing paddle.

Tell us something about yourself that most people wouldn’t know or guess. A few years ago, I had my own startup called “Othovibe”, which developed a shoe insert that helped train children not to walk on their toes. We had a prototype made, but ultimately realized the market was both too niche and too fragmented to support outside investment. This experience helps me relate in a unique way to my start-up clients.

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Deferring to U.S. EPA’s Interpretive Statement, Court Finds That Groundwater Discharges are Not Regulated by Clean Water Act

Environmental Alert

(by Lisa Bruderly and Gary Steinbauer)

Another district court has weighed in on the continuing debate as to whether the Clean Water Act (CWA) regulates discharges to groundwater that then flow into a surface water. However, unlike previous decisions, the federal district court in Massachusetts has deferred to EPA’s Interpretive Statement on the subject, 84 Fed. Reg. 16810 (April 23, 2019), as its basis for holding that releases of pollutants to groundwater are categorically excluded from the CWA’s permitting requirements. Conservation Law Foundation v. Longwood Venues & Destinations, Inc., Civil Action No. 18-11821 (D. Mass. Nov. 26, 2019).

The Longwood Venues decision comes less than one month after the U.S. Supreme Court heard oral argument in the County of Maui v. Hawai’i Wildlife Fund matter, a pending case addressing this same subject. With the highly anticipated County of Maui decision expected in the summer of 2020, the decision in Longwood Venues provides defendants in citizen suits with a new basis for contesting alleged CWA liability for discharges that travel through groundwater before reaching a jurisdictional surface water. Neither the United States nor any other party in the Supreme Court’s County of Maui case has argued that EPA’s Interpretive Statement is entitled to deference as a reasonable interpretation of the CWA. Rather, these parties contend that the CWA unambiguously provides that discharges to groundwater are not within its scope. Reliance on the Interpretive Statement injects new fodder into the ongoing debate and litigation over the scope of the CWA’s National Pollutant Discharge Elimination System (NPDES) permit program.

In Longwood Venues, an environmental group sued the owner of a beach club located in southern Cape Cod, claiming that sanitary wastewater released to the groundwater from the club’s onsite wastewater treatment plant was an unpermitted discharge under the CWA. After undergoing treatment, the club’s sanitary wastewater is reportedly deposited into 22 perforated concrete leaching pits surrounded by crushed stone, which, at their bottom elevation, are four feet above the highest groundwater elevation. The parties agreed that it takes approximately 45 to 223 days for the undissipated nitrogen from the treated sanitary wastewater to reach a harbor located 100 to 500 feet from the wastewater treatment plant. A key fact in Longwood Venues is that the leaching pits are regulated under a state-issued groundwater discharge permit.

Like the County of Maui case, the facts in Longwood Venues included an intentional discharge of sanitary wastewater into the ground that could be traced to a jurisdictional surface water. The court in Longwood Venues, consistent with County of Maui, had little difficultly concluding that the perforated leaching pits were “point sources” under the CWA. Furthermore, the Longwood Venues court held that it did not see any meaningful difference between the pits and a “well” or “container,” both of which are listed as examples in the CWA’s definition of “point source.” Also, nitrogen from the leaching pits is “measurable to a high degree of accuracy,” persuading the court that the pits are “discrete” point sources. We note that the court did not find a prior categorization of the leaching pits as non-point sources in an EPA-approved total maximum daily load to be dispositive on the “point source” issue.

Notwithstanding its “point source” determination, the Longwood Venues court ultimately held that the CWA does not regulate discharges to groundwater that are hydrologically connected to a jurisdictional surface water. The court used the familiar Chevron agency deference test to determine whether the CWA was ambiguous on the issue of whether discharges to groundwater are regulated and whether the Interpretive Statement is an agency action worthy of deference. The Longwood Venues court was concerned with the “nearly limitless reach” of the CWA if it adopted the Ninth Circuit’s theory that CWA liability extends to groundwater discharges that reach surface water. See Hawai’i Wildlife Fund v. County of Maui, 886 F.3d 737 (9^th Cir. 2018). Relying on the CWA’s text, legislative history, and purposes, the court held that the CWA is ambiguous on whether it regulates discharges of pollutants into groundwater that ultimately reach a jurisdictional surface water. Although EPA had no legal obligation to do so, its use of full notice-and-comment procedures before publishing the Interpretive Statement in the Federal Register was a deciding factor in the Longwood Venues court’s finding that the Chevron agency deference doctrine applied, even though the Interpretive Statement is at odds with “EPA’s previous, longstanding interpretation” of the CWA.

The Longwood Venues court concluded that EPA’s Interpretive Statement was reasonable. Interpreting the CWA to categorically exclude discharges to groundwater avoided an interpretation of the CWA that would cause “unreasonable regulatory compliance burdens on millions of citizens” who own and operate on-site septic systems. The court also found that it was permissible for EPA to prioritize the statutory purpose of preserving and protecting states’ responsibilities to regulate surface water. Lastly, the Longwood Venues decision closed with several fact-specific determinations. For example, the fact that the leaching pits were regulated under a state-issued groundwater permit illustrated to the court that CWA regulation was unnecessary to protect surface waters. Ironically, the court cited the plaintiff environmental group’s success in other CWA litigation forcing EPA to address nitrogen pollution in the harbor and Cape Cod generally, as another reason for concluding that a CWA discharge permit was unnecessary.

Babst Calland will continue to track and evaluate the Interpretive Statement, the County of Maui case, and citizen suit litigation over whether the CWA regulates discharges to groundwater. For additional background information, please see our past Environmental Alerts covering related topics on our website. If you have questions about the Interpretive Statement or how recent court decisions could impact your operations, please contact Lisa M. Bruderly at (412) 394-6495 or lbruderly@babstcalland.com or Gary E. Steinbauer at (412) 394-6590 or gsteinbauer@babstcalland.com.

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A proactive approach: How to prepare for California’s sweeping privacy law

Emerging Technologies Legal Perspective

(by Justine Kasznica)

In 2018, California signed into law the first state-level comprehensive privacy act, the California Consumer Privacy Act of 2018 (CCPA), which will go into effect Jan. 1, 2020. In part due to the CCPA’s broad scope and reach beyond California, as well as the large fines and penalties for CCPA noncompliance, the law is influencing and setting a high bar for data protection practices nationwide. Since the CCPA was signed into law, several states have proposed or enacted similar legislation, turning privacy and cybersecurity into a patchwork of state-led experimentation.

We are seeing more states joining California and developing their own privacy laws, which will make it difficult for companies to track and comply with every state’s privacy act, not to mention the privacy regimes in non-U.S. jurisdictions, such as Europe’s General Data Protection Regulation (GDPR).

While some states are beginning to enact or consider uniform approaches to privacy and cybersecurity, such as the NAIC Model Law for Cybersecurity, it will take time for such models to emerge and achieve the requisite consensus. In the absence of a uniform federal and state approach to privacy, businesses need to take the initiative now and be aware of the various state, federal and foreign laws being introduced and enacted — even if their operations may not yet affected.

How does California’s privacy act work?

The California Consumer Privacy Act of 2018 (CCPA) protects consumers who are residents of California by giving them rights to disclosure, access, deletion, control (opt-out and portability rights) as well as imposing a prohibition on antidiscrimination. It also addresses the data privacy rights of children under the ages of 13 and 16. The CCPA is modeled on the GDPR, articulating similar individual consumer rights (even if their terms differ) and imposing business obligations and enforcement mechanisms. While compliance with GDPR may facilitate CCPA compliance, the two privacy regimes deviate in definitions of personal information/data, scope of the rights protected, affected organizations, and penalties and enforcement.

The CCPA applies to for-profit entities (and non-profits if they control, are controlled, or are under contract or relationship with an affected for-profit company) that that do business in California and collect or direct the collection of personal information of consumers, if such entity:

Has total annual gross revenues in excess of $25 million a year.
Receives, sells or shares the personal information of 50,000 or more consumers, households or devices of California residents.
Derives 50 percent or more of its annual revenue from selling personal information of California residents.

The regulations are expected to be finalized in the spring of 2020, with enforcement beginning July 1 (although the attorney general has indicated that his office may look back to the first half of the year for bringing enforcement actions). CCPA violations could lead to large cumulative fines, civil penalties and statutory damages, particularly where violations of the law are deemed to be intentional.

What should businesses do with regards to compliance?

In light of the rapidly changing privacy regulatory landscape, companies are encouraged to evaluate how they operate and collect, store and process personal information. Many U.S. companies, including those in the Pittsburgh region, will need to change their data privacy practices to comply with the CCPA, GDPR and other applicable privacy laws. Even those companies that are not themselves subject to a particular privacy law may be affected if they partner or do business with companies that need to comply with such a law, and the compliance obligations are passed on to them by contract.

The following is a pragmatic approach to privacy law compliance:

Perform a data privacy assessment, designed to capture whether and what kind of personal information an organization collects, for what purpose it is collected, and how the information is being used. Achieving consensus on the definition and categories of personal information/data will be critical to this exercise.
Take time to understand which privacy laws and regulations apply or will apply to your organization.
Make sure to work with legal counsel to modernize or update your terms and conditions, privacy policies, cookie and other data collection policies.
Compliance with CCPA may require the redesign and deployment of new internal and user-facing processes, safeguards and tools to enable individuals to exercise their rights with respect to their personal information. These may include the implementation of new communication tools, notices, banners and opt-in or opt-out features, as well as data access, correction and deletion procedures. Make sure to plan ahead and budget time and resources for such changes.
If you believe your organization is subject to the CCPA, reach out to experts in legal, risk and IT, who can work together to ensure the business is compliant.

Bottom line: Whether your organization falls within the scope of the CCPA or not, a wait-and-see approach is not a good strategy. Privacy laws are only going to become more important as the landscape evolves, and the GDPR and CCPA are just the beginning.

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The Pennsylvania General Assembly Introduces the Pennsylvania Carbon Dioxide Cap and Trade Authorization Act

Environmental Alert

(by Kevin Garber and Jean Mosites)

On Wednesday, November 20, 2019, members of the Pennsylvania House and Senate referred bipartisan companion bills HB 2025 and SB 950, both known as the Pennsylvania Carbon Dioxide Cap and Trade Authorization Act, to their respective Environmental Resources and Energy Committees for consideration.

Sponsors Senator Joe Pittman (R-41) and Representative Jim Struzzi (R-62) announced the bills in a press conference on November 19, 2019 in response to Governor Tom Wolf’s October 3, 2019 Executive Order 2019-07. That Order directed the Environmental Quality Board to propose, by July 31, 2020, a carbon dioxide cap and trade program for fossil-fuel-fired electric power generators which is at least as stringent as that developed under the Regional Greenhouse Gas Initiative (RGGI). For more detail on RGGI, see Wolf Administration Announces Plan to Join Northeast Carbon Market.

The bills each provide a declaration of policy, procedures for the proper introduction of any program governing carbon dioxide emissions by the Pennsylvania Department of Environmental Protection, and the process for submitting that program to the General Assembly for approval.

No Current Authority to Regulate CO2 Emissions

No Rulemaking Without Specific Statutory Authority

Other than a measure required by federal law, Section 4 prohibits DEP from adopting any measure or taking any action to abate, control or limit carbon dioxide emissions (including joining or participating in RGGI or other state or regional greenhouse gas cap-and-trade program) or establishing a greenhouse gas cap-and-trade program unless the General Assembly specifically authorizes it by statute.

the amount of carbon dioxide emitted from each facility,
the estimated cost of compliance,
the effect the proposed action would have on the price of electricity,
a list of facilities that would be unlikely to continue operating,
an assessment of the decrease of electricity that would be exported from Pennsylvania, and
an assessment of any impact on the resilience and diversity of Pennsylvania’s electric generation fleet if an identified facility is forced to close.

The report must also address effects on the statewide economy, including:

direct and indirect costs to the Commonwealth, political subdivisions, and the private sector,
the wholesale and resale prices of electricity for residential, commercial, industrial and transportation consumers,
adverse effects on the prices of goods and services, productivity and competition, and
the administrative, legal, consulting and accounting costs imposed by the proposal.

Other Implications

Although the sponsors centered the implications of their bills on the Governor’s attempt to unilaterally join RGGI, the bills were written broadly enough to require a General Assembly review and authorization process for any proposed cap-and-trade program, which would include any rulemaking that would result from the economy-wide cap-and-trade petition currently under consideration by DEP or the Environmental Quality Board. For more information on the cap-and-trade petition, see Pennsylvania EQB Advances a Cap and Trade Petition to Reduce Greenhouse Gas Emissions.

Next Steps

The bills will be discussed and voted on by their respective committees before reaching the floor of each Chamber. As of the publication of this alert, there are no Environmental Resources and Energy Committee meetings scheduled for either house through the end of the year.

Babst Calland continues to monitor HB 2025 and SB 950. If you have questions about how these bills may affect the governance of carbon dioxide emissions, please contact Kevin J. Garber at (412) 394-5404 or kgarber@babstcalland.com or Jean M. Mosites at (412) 394-6468 or jmosites@babstcalland.com.

Click here for PDF.

A proactive approach: How to prepare for California’s sweeping privacy law

Smart Business

(by Jayne Gest with Justine Kasznica)

In 2018, California signed into law the first state-level comprehensive privacy act, the California Consumer Privacy Act of 2018 (CCPA), which goes into effect Jan. 1, 2020. Due to the CCPA’s broad scope and reach beyond California, as well as its large fines and penalties for noncompliance, the law is influencing and setting a high bar for data protection practices nationwide. Since the CCPA was signed, several states have proposed or enacted similar legislation, turning privacy and cybersecurity into a patchwork of state-led experimentation.

“More states are developing privacy laws, which will make it difficult for companies to track and comply with every state’s privacy act, not to mention the privacy regimes in non-U.S. jurisdictions, such as Europe’s General Data Protection Regulation (GDPR),” says Justine Kasznica, shareholder at Babst Calland.

In the absence of a uniform approach to privacy and cybersecurity, businesses need to be aware of the state, federal and foreign laws being introduced and enacted — even if their operations are not yet affected.

Smart Business spoke with Kasznica about how California’s privacy law, and others, will impact companies.

How does California’s privacy act work?

The CCPA protects consumers who are residents of California, giving them rights to disclosure, access, deletion and control (opt-out and portability rights), as well as imposing a prohibition on antidiscrimination. It also addresses the data privacy rights of children under the ages of 13 and 16.

The CCPA is modeled on the GDPR, articulating similar consumer rights (even if terms differ) and imposing business obligations and enforcement mechanisms. While compliance with GDPR may facilitate CCPA compliance, the two privacy regimes deviate in their definitions of personal information/data, scope of the rights protected, affected organizations, and penalties and enforcement.

The CCPA applies to for-profit entities (and certain nonprofits) that do business in California and collect or direct the collection of personal information of consumers, if such entity:

Has total annual gross revenue in excess of $25 million a year.

Receives, sells or shares the personal information of 50,000 or more consumers, households or devices of California residents.

Derives 50 percent or more of its annual revenue from selling personal information of California residents.

With the rapidly changing privacy regulatory landscape, how should businesses react?

Companies need to evaluate how they operate and collect, store and process personal information. Many U.S. businesses will need to change their data privacy practices to comply with the CCPA, GDPR and other privacy laws. Even those companies that are not subject to a particular privacy law may be affected if they partner or do business with companies that need to comply with a law, and the obligations pass on by contract.

A pragmatic approach to privacy law compliance would be to:

Perform a data privacy assessment that captures what kind of personal information an organization collects, for what purpose it is collected and how the information is being used. Achieving consensus on the definition and categories of personal information/data is critical.

Understand which privacy laws and regulations apply or will apply. If you believe your organization is subject to the CCPA, reach out to experts in legal, risk and IT who can help ensure compliance.

Work with legal counsel to modernize or update your terms and conditions, privacy policies, cookie and other data collection policies.

Redesign and deploy new internal and user-facing processes, safeguards and tools to enable individuals to exercise their rights, as required. This may include new communication tools, notices, banners and opt-in or opt-out features, as well as data access, correction and deletion procedures. Be sure to plan ahead; budget time and resources for the changes.

For the PDF, click here.

For the full article, click here.

Smarter Produced Water Management Options: Can the Regulatory Landscape Keep Pace?

Natural Resources & Environment

(by Gary Steinbauer and Kevin Garber)

Unconventional natural gas development in the Marcellus and Utica shale plays has seen unprecedented growth since 2012. Ohio, Pennsylvania, and West Virginia are now among the top gas-producing states, with Pennsylvania emerging as the second-largest natural gas producer in 2018, behind Texas. U.S. Energy Information Administration, Natural Gas Marketed Production, www.eia.gov/dnav/ng/ng_prod_sum_a_EPG0_VGM_mmcf_a.htm (last visited Aug. 8, 2019). The historic rise in production comes with increased volumes of produced water and waste streams that must be managed by natural gas operators. Produced water is naturally occurring brine brought up to the surface from the hydrocarbon reservoir during extraction of natural gas. Although the volume of produced water varies by well and formation, produced water is by far the largest water source by volume generated in the gas production process. U.S. Environmental Protection Agency (EPA), Management of Exploration, Development and Production Wastes: Factors Informing a Decision on the Need for Regulatory Action (Apr. 2019), at 3–11, www.epa.gov/sites/production/files/2019-04/documents/management_of_exploration_development_and_ production_wastes_4-23-19.pdf. Many unconventional natural gas operators treat, reuse, and recycle produced water to increase their water usage efficiency, cut down on the costs of disposal, and recover valuable materials.

Implementing the most effective strategy for produced water management requires compliance with a complex web of interrelated federal and state laws, which include state oil and gas-related laws, local laws and ordinances, and environmental laws. This article explores the most commonly used management strategies for produced water in the Marcellus and Utica shale plays in these three states and analyzes the federal and state environmental regulatory regimes governing such management alternatives. It begins by examining the chemical characteristics and volume of produced water from an unconventional natural gas well. It then analyzes the federal and state environmental regulatory landscape for the most common ways that produced water is managed: (1) reuse or recycling within or outside the gas field; (2) disposal in underground injection wells; and (3) treatment at commercial treatment facilities, some of which discharge pretreated effluent to publicly owned treatment works (POTWs). While the natural gas industry increasingly searches for ways to harness the full value of produced water, the environmental regulatory landscape for produced water in the Marcellus and Utica shale plays is evolving. It is unclear whether this evolution will keep pace with innovative solutions and technological advances that are being used to maximize produced water’s value.

Volumes and Chemical Composition of Produced Water in Appalachia

Understanding the complexities of produced water management options and their regulatory underpinnings would not be possible without first understanding the volumes and chemical composition of produced water. Since 2009, the volumes of produced water generated have increased considerably. In Pennsylvania alone, produced water volumes from unconventional operations have increased from roughly 10 to more than 50 million barrels per year. Lee Ann L. Hill et al., Temporal and Spatial Trends of Conventional and Unconventional Oil and Gas Waste Management in Pennsylvania, 1991-2017, 674 Sci. of the Total Env’t 623, 626 (2019).

Scientists often refer to produced water as being hypersaline, with some analyses showing total dissolved solids concentrations of more than 200,000 milligrams per liter for a well in the Marcellus Shale play. Hill et al., supra, at 624. These dissolved constituents primarily consist of sodium and calcium, but barium, strontium, and bromide have also been detected in produced water. Id. Naturally occurring radioactive material, particularly radium, can also be found in produced water from unconventional gas wells in the Marcellus and Utica shale plays. Id.

Produced water often shares the chemical characteristics of the brine located in the geologic formation from which natural gas is produced. While many contend that its chemical composition may be influenced by chemical additives used in the hydraulic fracturing process, a recent scientific study suggests that most of the injected water and chemical additives remain within the shale formations and the return flow consists primarily of naturally occurring brines. Andrew J. Kondash et al., Quantity of Flowback and Produced Waters from Unconventional Oil and Gas Exploration, 574 Sci. of the Total Env’t 314, 317 (2017).

Current technologies like crystallization can remove the various dissolved constituents in produced water, and the resulting salts have been sold commercially. Nonetheless nongovernmental organizations (NGOs) and academics have noted that EPA-approved analytical methods do not exist for many of the known constituents in produced water, prompting concerns that potentially harmful constituents could go unregulated or undetected. U.S. EPA, Study of Oil and Gas Extraction Wastewater Management Under the Clean Water Act, EPA-821-R19-001 (Draft, May 2019) (EPA May 2019), at 26, 28, www.epa.gov/sites/production/files/2019-05/documents/oil-and-gas study_draft_05-2019.pdf. Furthermore, residuals from produced water treatment may contain radioisotopes for which disposal can be costly. Id. at 20. Operators are forging ahead with creative solutions that maximize the value of produced water, often ahead of agency rulemaking or policy development. See Paul J. Gough, Water a Growing Part of Business for Natural Gas Company, Pittsburgh Business Times, Feb. 15, 2019; Daniel Gleeson, MGX and Eureka JV to Speed Up Petrolithium Recovery TechnologyDevelopments, Int’l Mining, June 11, 2019, https://im-mining.com/2019/06/11/mgx-and-eureka-jv-to-speed-up-petrolithium-recoverytechnology-developments/.

Produced water management strategies in the Marcellus and Utica shale plays vary based on the location of the well proximity to available treatment and disposal facilities, market forces, and operator preference. For underground injection and reuse or recycling of produced water, the governing environmental regulatory requirements are significantly different depending on the state. EPA is currently evaluating its existing rules concerning the discharge of treated produced water to surface waters and expected to announce any potential changes to the existing federal regulatory requirements in the summer of 2019. Below, we explore the applicable federal and state regulatory requirements for each of the most commonly utilized produced water management strategies and explain why the paradigm for produced water management appears to be trending away from disposal and toward reuse and recycling.

Disposal in Underground Injection Wells

At the beginning of the Appalachian natural gas boom, disposal in underground injection wells was the most common produced water management option. These wells are regulated under the Class II Underground Injection Control (UIC) program established by the Safe Drinking Water Act. 42 U.S.C. § 300h. EPA can delegate the authority to administer the UIC program to states, and Ohio and West Virginia have delegated authority to implement the Class II UIC program for brine or produced water disposal wells. 40 C.F.R. § 147.1800; see 40 C.F.R. § 147.2453. On the other hand, Pennsylvania has opted not to seek delegation to administer the UIC program. Therefore, EPA administers the UIC program, including the issuance of permits for Class II UIC wells, within Pennsylvania. 40 C.F.R. §§ 144.1(e), 147.1951(a).

Pennsylvania’s lack of implementation authority for the Class II UIC program and its relatively unique geology, have resulted in significantly fewer produced water disposal wells as compared to those located in Ohio and West Virginia. Ohio has the greatest number of active produced water disposal wells at 223. Ohio Dep’t of Nat. Resources, Class II Brine Injection Wells of Ohio, http://oilandgas.ohiodnr.gov/portals/oilgas/pdf/Class_II_Map/Class%20II%20Brine%20Injection%20Wells%20of%20Ohio%2007082019.pdf (last visited Aug. 8, 2019), almost four times as many as West Virginia, where there are 59 active Class II disposal wells. Groundwater Protection Council, State of West Virginia Class II UIC Program Peer Review (GWPC WV) (Nov. 2017), at 15. Comparatively, Pennsylvania has roughly ten Class II disposal wells, only one of which is a commercial UIC well. Pa. Dep’t of Envtl. Prot., Underground Injection Control Wells, www.dep.pa.gov/Business/Energy/OilandGasPrograms/OilandGasMgmt/Pages/Underground-Injection-Wells.aspx (last visited Aug. 8, 2019).

The regulatory process for permitting such wells changes drastically from state to state. As noted, EPA administers the Class II UIC well program in Pennsylvania, meaning that it is responsible for drafting permits, completing the public participation process on such permits, and issuing the permits. See 40 C.F.R. Part 124, Subpart A. Challenges to EPA-issued Class II UIC disposal well permits in Pennsylvania are heard by EPA’s Environmental Appeals Board, 40 C.F.R. § 124.19(a), which has, at times, scrutinized EPA regional offices for failing to address fully induced seismicity issues during the permitting process for Class II produced water wells. See, e.g., In re West Bay Exploration Co., 17 E.A.D. 204 (EAB 2016). In addition to an EPA permit, Class II UIC disposal wells in Pennsylvania require a separate permit from the Pennsylvania Department of Environmental Protection. 25 Pa. Code § 91.52. The dual federal-state permitting requirements for Class II disposal wells in Pennsylvania, in addition to obtaining the necessary and sometimes numerous local approvals needed to construct such a well, provide several avenues for third parties to oppose disposal wells.

Similarly, Class II UIC disposal wells in West Virginia require two separate permits, although both are issued by the Office of Oil and Gas in West Virginia’s Department of Environmental Protection (WVDEP). W. Va. Code, Ch. 22; W.Va. Code R. §§ 47-13, 35-4. In addition, WVDEP distinguishes between “commercial” and “noncommercial” UIC disposal wells. A commercial Class II disposal well is any permitted operating facility that accepts fluids produced by another oil or gas operator. WVDEP, Underground Injection Control Class 2 and 3 UIC Wells, Permit Application Package Instructions and Guidance, http://dep.wv.gov/oil-and-gas/GI/Forms/ Documents/UIC%20APPLICATION%20PACKAGE%20 06-25-2014.pdf. Commercial UIC disposal wells in West Virginia often are subject to additional permitting requirements, such as analytical testing, manifesting requirements, and increased security measures. Id. There are 14 active commercial and 45 active noncommercial UIC disposal wells in West Virginia. GWPC WV, at 15.

Ohio’s Class II UIC disposal program is unique for several reasons. By statute, the Ohio legislature has vested authority for permitting and implementing a specific regulatory program for produced water (i.e., brine) injection wells, known in Ohio as “saltwater injection wells,” in the Ohio Department of Natural Resources (ODNR), the same state agency that also is responsible for issuing permits for unconventional natural gas wells. Ohio Admin. Code § 1501:9-3. Ohio’s regulatory program requires disposal well operators to use state-of-the-art technology. As an example, each produced water disposal well in Ohio must be equipped with an automatic shut-off device that terminates operations if the maximum allowable surface injection pressure on the injection pump is exceeded. Ohio Admin. Code § 1509:9-3-07(G). Similarly, adapting to recent instances where oil and gas-related wells are believed to have caused seismic activity, the ODNR has the authority to require a disposal well operator to conduct a geologic investigation near the injection well, including the completion of seismic surveys. Ohio Admin. Code § 1501:9-3-06(C)(2)-(3). Recent permits issued by ODNR for produced water disposal wells require monitoring for “microseismicity” prior to injection and throughout the well’s operation. Williams Disposal LLC, API Well Number 34-121-2-4636-00-00 (Aug. 8, 2018).

The prevalence of available disposal wells gives natural gas producers in Ohio and the nearby counties of Pennsylvania and West Virginia a cost-effective means of managing produced water and other wastes generated in the natural gas production process. More recently, however, evidence shows that producers increasingly are turning to other management options, at least in Pennsylvania. Hill et al., supra, at 628. Transportation of produced water to disposal wells can drive up costs to the point where this management option is no longer viable. Transportation to UIC wells also comes with risks of spills and accidental discharges, increased traffic, and air emissions. EPA May 2019, at 19. Concerns over induced seismicity caused by underground injection and disposal wells becoming over-pressurized can pose challenges to siting new disposal wells. Id. at 20.

Reuse or Recycling In and Outside the Gas Field

The reported decline in the use and reliance on disposal wells has coincided with repeated and louder calls by natural gas producers, state regulatory agencies, and others to “rebrand” produced water as a valuable resource. Id. at 19. Reusing and recycling produced water in and outside of the gas field can take on many different forms, from simply storing and reusing produced water to stimulate production in another nearby natural gas well to utilizing treatment technology to produce distilled water and other usable products. The environmental regulatory requirements vary, ranging from relatively straightforward for simple storage and reuse to complex and nuanced for advanced treatment and reuse facilities.

Viewed from a federal waste management perspective, Congress temporarily exempted produced water from natural gas wells from the hazardous waste management requirements of the Resource Conservation and Recovery Act (RCRA) in 1980. 42 U.S.C. § 6921(b)(2)(A). At that time, Congress required EPA to conduct a study and publish a regulatory determination on whether produced water and other oil and gas exploration and production-related wastes require regulation under RCRA Subtitle C. EPA published its regulatory determination in 1988, concluding that regulation under RCRA Subtitle C was not warranted because existing federal and state laws were adequate to regulate, among other things, produced water. Regulatory Determination for Oil and Gas and Geothermal Exploration, Development and Production Wastes, 53 Fed. Reg. 25,447 (July 6, 1988). In 2019, following a lawsuit filed by environmental groups, EPA completed a more recent study and arrived at the same conclusion: produced water would remain exempt from RCRA’s nonhazardous waste program. EPA May 2019, at 9-4 to 9-5. Therefore, operators in the Marcellus and Utica shale plays are subject to state solid waste management programs and regulations regarding the management of produced water. These programs differ substantially among the states.

Pennsylvania has perhaps the most comprehensive set ofregulations governing storage, treatment, and transportation of produced water. Even when it is being reused or recycled,Pennsylvania treats produced water as a waste under its solid waste program. Consequently, temporary storage or processing of produced water in Pennsylvania requires a solid waste permit and facilities engaging in these activities are considered solid waste transfer facilities. Produced water destined to be used to complete wells is regulated as a residual waste until the moment it is placed down-hole, unless the produced water meets stringent quality standards. The Pennsylvania Department of Environmental Protection (PA DEP) has issued a beneficial reuse general permit for facilities that transfer, process, and use produced water to hydraulically fracture gas wells, known as WMGR123. The current version of the WMGR123 permit expires in October 2020, unless PA DEP renews it.

In addition to undergoing a comprehensive process to obtain coverage under the WMGR123 general permit, operators of produced water management facilities must then comply with the permit’s strict mandates. In addition to requiring compliance with the major Pennsylvania statutes for air pollution, water pollution, and solid waste management, WMGR123 requires operators to comply with (1) various requirements related to storage, including a one-year limitation on storage absent written approval that is based on proportional rates of accumulation and reuse; (2) a prohibition of a point or nonpoint source discharge or runoff from staging, processing, and storage areas to a water of the Commonwealth; (3) a prohibition on mixing beneficially reused produced water with other waste; (4) management requirements for produced water that is not beneficially reused as solid waste, including proper treatment or disposal; (5) a bond requirement to secure the estimated costs of cleanup; and (6) comprehensive cleanup and closure requirements. Recordkeeping requirements, similar to RCRA’s hazardous waste cradle-to-grave requirements, are also required under WMGR123.

WMGR123 also covers scenarios where the produced water facilities are processing or treating the liquid. Produced water ceases its status as a “waste” under WMGR123 when (1) it is transported to a well site, the owner or operator of the well site meets specific requirements, and it is beneficially reused to hydraulically fracture a gas well; or (2) it is treated so that the concentrations of nearly 40 separate parameters are below established levels and stored in an impoundment or other facility designed to hold water. Any facility or operator unable to exempt produced water from classification as a residual waste or unable to meet WMGR123 must apply for and obtain an individual solid waste permit from the PA DEP.

In Ohio, storage, recycling, treatment, and processing of produced water is subject to statutory requirements implemented by the state’s natural resources agency, ODNR. Ohio’s legislature granted ODNR exclusive authority to regulate the storage, recycling, treatment, and processing of brine or produced water. Ohio Rev. Code § 1509.22(C). ODNR has the authority to issue regulations that govern each of these activities, including procedures related to issuing permits. Id. However, to date, ODNR has not promulgated implementing regulations. Instead, it has been authorizing the storage, recycling, treatment, and processing of produced water through administrative orders for “temporary authorization” to manage produced water.

ODNR has issued more than 35 such orders, each of which temporarily authorize some combination of produced water storage, recycling, treatment, or processing. These orders require each facility to operate in accordance with Ohio Revised Code Chapter 1509. ODNR also typically incorporates regulations at Ohio Administrative Code § 1501:9, which contain various requirements for temporary storage of produced water in pits and tanks. Ohio Admin. Code § 1501:9-3-08. The Ohio Supreme Court recently affirmed a judgment in favor of ODNR in an environmental group’s lawsuit seeking to require ODNR to promulgate regulations governing produced water management, effectively allowing ODNR to continue issuing orders temporarily authorizing the storage, recycling, treatment, and processing of produced water for the time being. State ex rel. Food & Water Watch v. Ohio, 153 Ohio St. 3d 1 (Ohio S. Ct. 2018).

West Virginia explicitly allows the use of produced water for hydraulic fracturing. W. Va. Code R. § 35-8:5.6.f. West Virginia allows produced water to be brought to another well location, as long as the produced water is stored “in pits or tanks or centralized pit facilities” at the new location. Id. Centralized pits or impoundments are regulated in West Virginia based on whether they are included within a specific well work permit for an unconventional gas well and their capacity. Off-site centralized pits or impoundments are subject to more stringent requirements. See W. Va. Code R. §§ 35-8-16, 35-8-17. Siting restrictions, synthetic liner requirements, leak detection systems, groundwater and surface water monitoring requirements, and several related operational requirements are required for centralized pits and impoundments. Id.

Temporary storage of produced water in tanks is regulated under West Virginia’s Aboveground Storage Tank (AST) Act, W. Va. Code § 22-30, which was enacted following a 2014 chemical spill into the Elk River. West Virginia promulgated implementing regulations in August 2016. W. Va. Code R. § 47-63. Notably, tanks holding less than 210 barrels of produced water that are not located in a “zone of critical concern” and wastewater process tanks are excluded from the AST Act requirements. Finally, a non disposal solid waste permit is required to store and treat produced water in West Virginia. W. Va. Code R. § 33-1-3.5a.

Discharge Options for Produced Water

The most controversial produced water management option is the discharge of produced water, treated or otherwise. Any discharge to surface waters would be covered under the Clean Water Act’s National Pollutant Discharge Elimination System (NPDES) permit program. Ohio, Pennsylvania, and West Virginia are each delegated the responsibility to implement the NPDES permit program within their borders. The controversy over discharge options for produced water has centered primarily over two federal effluent limitation guidelines (ELGs) promulgated under the Clean Water Act.

For onshore gas development, EPA prohibited direct discharges of produced water when it revised the ELGs for the Oil and Gas Extraction Wastewater Point Source Category in 2016. 40 C.F.R. Part 435. EPA has imposed a zero-discharge requirement for oil and gas extraction wastewaters, including produced water, from onshore oil and gas activities. 40 C.F.R. § 435.32. When EPA revised these ELGs in 2016, it then prohibited indirect discharges of produced water to POTWs. 40 C.F.R. § 435.33(a)(1). Following a petition for reconsideration filed by the Pennsylvania Grade Crude Oil Coalition in the U.S. Court of Appeals for the Third Circuit in November 2016, EPA extended the deadline of the prohibition until August 29, 2019. Effluent Limitations Guidelines and Standards for the Oil and Gas Extraction Point Source Category– Implementation Date Extension, 81 Fed. Reg. 88,126 (Dec. 7, 2016). On July 5, EPA published notice of its decision to not revise its 2016 rule imposing a zero-discharge requirement for wastewaters from onshore unconventional oil and gas extraction facilities. Decision on Supplemental Information on the Effluent Limitations Guidelines and Standards for the Oil and Gas Extraction Point Source Category, 84 Fed. Reg., 32,094 (July 5, 2019).

Although 40 C.F.R. Part 435 prohibits direct discharges of produced water to surface water and indirect discharges to POTWs, the ELGs for Centralized Waste Treatment (CWT) facilities at 40 C.F.R. Part 437 provide an avenue to treat and discharge produced water. The CWT ELGs were last revised in 2003, several years before the proliferation of unconventional natural gas production in the Marcellus and Utica shale plays. However, the unconventional gas industry does not fit well within the current structure of these ELGs. The present subcategories of the CWT ELGs regulate wastewater from metals treatment and recovery, oils treatment and recovery, organics treatment and recovery, and multiple waste streams. 40 C.F.R. §§ 437.10–437.47. Produced water from unconventional natural gas operations does not fit into any of these subcategories as currently defined. That has caused uncertainty and often the excessively stringent application of the ELGs by state agencies as they develop NPDES for CWTs, which in turn has limited the number of CWTs available to accept produced water for treatment. As an example, one state agency has selected the most stringent effluent limits from the various CWT subcategories and included those in a draft NPDES permit. 47 Pa.

Bull. 3995 (July 22, 2017) (publishing notice of a draft NPDES permit and the proposed effluent limits for the FRS Kingsley Facility).

Divergent opinions have emerged on whether additional discharge options should be available for produced water. Industry, some state agencies, and some NGOs generally supported increased opportunities for produced water discharge alternatives, while environmental NGOs and academics have raised concerns. In late 2018, EPA began a comprehensive review to evaluate the management of oil and gas onshore facilities and to determine whether there is a need for additional discharge options under the CWA. As discussed above, EPA released a draft Study of Oil and Gas Extraction Wastewater Management under the Clean Water Act on May 15. This study was designed to evaluate “produced water generation, management, and disposal options at regional, state, and local levels for both conventional and unconventional onshore oil and gas extraction.” EPA May 2019, at 1. EPA reviewed various produced water management strategies, assessed various treatment technologies, and solicited input from a variety of stakeholders related to produced water management and whether additional discharge options were warranted under the CWA. The public comment period EPA provided for the study was open through July 1, and EPA encouraged interested parties to provide input on (1) nonregulatory steps EPA could take to encourage the reuse and recycling of produced water, (2) whether it should revise 40 C.F.R. Part 435 to allow for discharge of produced water considering the cost of transporting and treating produced water, and (3) the steps EPA could take to incentivize the reuse of produced water within and outside the gas field. EPA will use the information in the study and comments received to determine the appropriate course of action, with the goal of announcing any next steps later in 2019.

Produced water management will continue to be an issue for natural gas producers as natural gas production in the Marcellus and Utica shale plays continues to increase, especially if the pace of drilling and completing new wells does not keep up with generation of produced water from producing wells. The paradigm for produced water management appears to be shifting from disposal toward a recognition that produced water is a potentially valuable resource. Efforts to make reuse and recycling options more readily available, and even increasing the availability of discharge options, would be welcomed by unconventional natural gas operators and could prove to be environmentally beneficial. Market drivers, however, will only shift the outlook for increased produced water management options so much. Federal and state regulatory regimes must keep pace with the available science and technological advancements.

©2019 by the American Bar Association. Reprinted with permission. All rights reserved. This information or any or portion thereof may not be copied or disseminated in any form or by any means or stored in an electronic database or retrieval system without the express written consent of the American Bar Association.

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EPA’s Initiative Against Illegal Aftermarket Parts: Deleting Defeat Devices

Emerging Technologies Alert

(by Julie Domike and Gina Falaschi)

One of the hottest topics of discussion at the November 12, 2019, National Enforcement Conference held by the American Bar Association’s Section on Environment, Energy and Resources was enforcement concerning aftermarket defeat devices. The Environmental Protection Agency’s (EPA) recent efforts have resulted in a marked upswing in cases – both civil and criminal – against parts manufacturers and installers of the devices, including some entities that are less than obvious targets.

Aftermarket parts are replacement or additional vehicle or engine parts not made by the original equipment manufacturer. Most aftermarket parts do not violate the Clean Air Act, but some are designed to reduce or eliminate the effectiveness of required emissions controls on vehicles and engines. These are defeat devices, and there is a market for such devices as they can dramatically increase fuel efficiency or boost engine power. Among the most common users of these defeat devices are truck fleet owners and the shops that service them. Many of the recent enforcement cases have been against companies or individuals that produce or install “tuners” – engine control module reprogrammers that disable emission control systems with preloaded software (“tunes”). These defeat devices are obvious enforcement targets. However, other devices or software could also fall in this category, and therefore liability could extend to other aftermarket suppliers.

EPA’s Enforcement Against Aftermarket Defeat Devices

The EPA released its Fiscal Year 2020 – 2023 National Compliance Initiatives on June 7, 2019. The memorandum from Assistant Administrator for Enforcement and Compliance Assurance Susan Parker Bodine explains the agency’s selection of “Stopping Aftermarket Defeat Devices for Vehicles and Engines” as a new compliance initiative. The memorandum emphasizes that the Clean Air Act prohibits “tampering with emissions controls, as well as manufacturing, selling, and installing aftermarket devices intended to defeat those controls. The EPA has found numerous companies and individuals that have manufactured and sold both hardware and software specifically designed to defeat required emissions controls on vehicles and engines used on public roads as well as on nonroad vehicles and engines.” Enforcement focuses on “stopping the manufacture, sale, and installation of these defeat devices.”

During the national enforcement conference, Ms. Bodine and her enforcement staff informed participants that it is “astonishing how much noncompliance” is being found in the mobile source sector, confirming the need for this compliance initiative. According to the EPA, their enforcement efforts have uncovered at least half a million vehicles that have been tampered with, potentially increasing emissions by the equivalent of nine million additional trucks on the road.

Clean Air Act Liability

The EPA can take two approaches to enforcement under the Clean Air Act – criminal enforcement or civil enforcement. Although criminal enforcement has historically been less prevalent, the EPA has increased enforcement against vehicle and equipment manufacturers in recent years across both civil and criminal venues. Title II of the Clean Air Act, which addresses mobile sources, does not contain provisions for criminal enforcement. To find criminal liability, the EPA relies on Section 113 of the Clean Air Act, which allows for criminal prosecution of an individual who knowingly “falsifies, tampers with, renders inaccurate, or fails to install any monitoring device or method required to be maintained[.]” 42 U.S.C. §7413(c). If convicted, an individual may be subject to a fine or up to two years in prison for a first offense, or both.

By contrast, Title II of the Clean Air Act expressly defines prohibited acts against which the EPA can initiate civil enforcement, including the manufacture, sale, or installation of aftermarket defeat devices. Section 203 of the Clean Air Act prohibits any person from rendering inoperative or removing any emissions control devices on a motor vehicle prior to or after its sale to the ultimate purchaser, and prohibits any person from manufacturing, selling, offering to sell or installing any part or component intended for use on a motor vehicle where the principal effect of the part is to bypass, defeat, or render inoperative any emission controls. 42 U.S.C. §7522. The statute thus authorizes the EPA to hold liable anyone who knows or should know that a part or component is being sold or installed for such use. Id. Civil penalties for violations of this section could be as high as $4,735 per unit produced or $47,357 per vehicle altered; one recent settlement required payment of $1.1 million in penalties, in addition to other injunctive relief. Resolution of violations in the civil context does not prevent criminal prosecution.

Who could be liable?

The Clean Air Act creates a broad scope of potentially liable parties. The EPA has historically taken enforcement against manufacturers and retailers of tuners and those individuals who install them in motor vehicles. The EPA has also taken enforcement against those individuals who remove emissions control systems from vehicles, especially trucks, after they are delivered to the ultimate purchaser. Other activities giving rise to liability may be less obvious. Those who modify fleets of vehicles with additional equipment may violate the Clean Air Act by causing excess emissions due to vehicle weight increases, causing the vehicle to operate outside of its manufacturer certified parameters. The agency views this activity as tampering.

With the EPA’s current emphasis on enforcement, liability risk can extend beyond the manufacturers and installers of tuners and other defeat devices. Retailers who neither manufacture nor install defeat devices could also be subject to civil enforcement for selling aftermarket defeat devices in their stores or online. Additionally, those who manufacture and sell devices that they know or should know are being used as defeat devices to tamper with emissions control equipment could also find themselves the target of an EPA enforcement action. This additional liability could even extend to manufacturers of equipment that is known to be used improperly as a defeat device but has other legitimate uses, as well as to authors of software programs that could alter the manufacturer-installed software as certified by the EPA.

California: Liability and Compliance

EPA’s increased enforcement activity against manufacturers and sellers of aftermarket parts, as well as individuals who utilize or install those parts, follows decades of similar enforcement by California’s Air Resources Board (CARB).

Section 27156 of the California Vehicle Code states that “[n]o person shall install, sell, offer for sale, or advertise any device, apparatus, or mechanism intended for use with, or as a part of, a required motor vehicle pollution control device or system that alters or modifies the original design or performance of the motor vehicle pollution control device or system.” Unlike the Clean Air Act, however, California allows for CARB review of aftermarket parts and the grant of exemptions in the form of Executive Orders, allowing for the sale of parts that are certified not to increase vehicle emissions. As part of recent settlements, EPA has required companies to demonstrate that their future products do not alter vehicle emissions by obtaining such Executive Orders from CARB.

For a more detailed assessment of these provisions or assistance in determining any potential liability, please contact a Julie Domike at 202-853-3453 or jdomike@babstcalland.com or Gina Falaschi at 202-853-3483 or gfalaschi@babstcalland.com

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PHMSA proposes allowing liquefied natural gas transport by rail

The PIOGA Press

(by Boyd Stephenson and James Curry)

On October 24, the Pipeline and Hazardous Materials Safety Administration (PHMSA) published a notice of proposed rulemaking (NPRM) amending the Hazardous Materials Regulations (HMR) to allow the bulk transport of liquefied natural gas (LNG) in DOT-113C120W (DOT-113) specification railcars.

PHMSA issued the NPRM in response to a petition for rulemaking filed by the Association of American Railroads (AAR). Also, an April 10 Executive Order directed PHMSA to issue a final rule on bulk transportation of LNG by rail by May 2020. Comments on the NPRM are due by December 23.

Over the last decade, the number of LNG facilities and total storage and vaporization capacities have drastically increased. And, according to PHMSA, total liquefaction capacity increased by 939 percent due to new LNG export terminals. With this growth, PMHSA has recognized there may be a need for greater flexibility in the modes of transporting LNG.

While LNG is already authorized for transportation by highway and in maritime vessels, LNG may be transported by railcar only with a special permit from PHMSA or in smaller, portable tanks loaded onto a railcar. However, other cryogenic liquids that are chemically similar to LNG already are authorized to be transported by rail under the HMR.

Currently, there is a pending special permit renewal application to transport bulk LNG in DOT-113 specification railcars using requirements identical to those proposed in the NPRM. The comment period ended August 7, with PHMSA receiving nearly 3,000 comments. The agency has not yet acted on the application.

Proposed changes

In the NPRM, PHMSA proposes to:

• Amend the LNG entry on the Hazardous Materials Table (UN 1972, Methane, refrigerated liquid (cryogenic liquid), 2.1) to allow transportation of bulk LNG in rail tank cars under the terms of 49 C.F.R. § 173.319
• Amend the railcar provisions in the cryogenic liquid table in 49 C.F.R. § 173.319, to add the following requirements for bulk railcars transporting LNG:

― Using a DOT-113 specification rail tank car.
― A start-to-discharge pressure valve setting of 75 psig.
― A design service temperature of -260˚F.
― Maximum pressure when offered for transportation of 15 psig.
― A filling density of 32.5 percent by weight.

PHMSA did not propose any changes to the DOT-113 tank car design for transporting bulk LNG, or for handling bulk LNG in transit, but the agency solicits comments about:
• Whether there is a reason to set a maximum length PHMSA proposes allowing liquefied natural gas transport by rail November 2019 | The PIOGA Press 13 of trains transporting LNG and, if so, what that maximum length should be.
• Whether there is a reason to limit the number of LNG railcars that can be in one consist (the lineup or sequence of cars in a unit) or to limit where LNG tank cars may be placed within the train.
• Whether PHMSA should apply its high-hazard flammable train (HHFT) rules to trains transporting bulk LNG, including:
― Speed restrictions and tightened speed restrictions in high-threat urban areas.
― Two-way end-of-train devices for faster air brake deployment in emergency situations.
• Whether PHMSA should adopt the AAR’s Circular
OT-55, “Recommended Railroad Operating Practices for Transportation of Hazardous Materials,” which all Class I and II freight railroads operating in the United States currently observe, into the rules for transporting bulk LNG
• Whether the additional route analysis requirements currently applied to HHFTs and to trains transporting explosives, toxic inhalation hazards or radioactive cargo should also be applied to trains transporting bulk LNG

Questions and commentary

Canada already allows the transport of bulk LNG in DOT-113 railcars, but, according to the NPRM, Mexico “does not provide explicit authorization for bulk transportation of LNG in rail tank cars.” Yet, PHMSA cites increased Mexican demand for LNG as one reason why rail transport demand is rising.

Ethylene is a cryogenic liquid that is already approved to be transported in the same type of DOT-113 specification railcars proposed for LNG. But, according to AAR data, only 356 ethylene tank car movements originated in 2015. PHMSA notes that “the numbers of DOT-113 tank cars in operation under the proposed regulatory change could increase well beyond the numbers of DOT-113 tank cars currently in operation.”

In addition to the DOT-113C120W railcar proposed for transporting bulk LNG, AAR’s petition requested PHMSA also authorize the DOT-113C140W (140W) railcar. The 140W is not widely deployed and PHMSA elected not to include it in the NPRM due to a paucity of safety data. Rather, the agency proposes to further study the 140W tank car’s technical standards and performance. The 140W better insulates the tank car’s inner compartment from thermal creep and is designed to allow the railcar to travel for longer periods before the cryogenic liquid can vaporize into gas. Would also authorizing the 140W expand shippers’ options for exporting LNG directly instead of delivering for transfer to a vessel at a maritime port?

PHMSA states that the NPRM does not impose costs or provide benefits exceeding $100 million annually, but the Office of Management and Budget chose to designate it a significant rulemaking, subject to additional review, anyway. At the same time, an executive order mandates PHMSA take final action considering allowing bulk LNG by rail by May 2020. With such an accelerated timeline, will PHMSA be able to resolve public comments and conduct the necessary economic analysis?

The proposed rulemaking can be found at www.govinfo.gov/content/pkg/FR-2019-10-24/pdf/2019-22949.pdf.

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PHMSA publishes three final rules substantially amending the federal pipeline safety regulations

The PIOGA Press

(by Ashleigh Krick and Boyd Stephenson)

On October 1, the Pipeline and Hazardous Materials Safety Administration (PHMSA) published three long-awaited final rules amending the federal pipeline safety regulations. The first rule amends the federal safety standards for gas transmission lines. The second amends the federal safety standards for hazardous liquid pipelines. The third updates procedures for issuing emergency orders. These rules are summarized below.

Safety of gas transmission pipelines

The gas transmission rule, commonly referred to as the “Mega Rule,” is the first in a three-part series of rules that PHMSA will be issuing to substantially revise the current federal safety standards and establish new requirements for gas pipeline facilities. This rule responds to congressional mandates and National Transportation Safety Board recommendations that arose from the investigation a 2010 gas transmission line incident in San Bruno, California. The rule adopts new requirements for verifying pipeline materials, reconfirming maximum allowable operating pressure (MAOP) and performing periodic assessments of pipeline segments located outside of high consequence areas (HCAs). The rule also amends the integrity management (IM) requirements, establishes requirements for reporting MAOP exceedances, for using inline inspection (ILI) launcher and receivers, as well as related recordkeeping requirements. The rule takes effect on July 1, 2020, but includes staggered compliance deadlines that extend as far out as 15 years.

Materials verification. Operators will be required to conduct destructive and nondestructive tests to verify pipeline attributes when they do not have traceable, verifiable and complete records for such attributes in certain situations, such as MAOP reconfirmation, IM or repair requirements. The new requirements allow for collection of missing pipe attributes over time, whenever a pipeline segment is exposed for maintenance or repairs, until a minimum number of excavations are performed. Gathering and distribution lines are not subject to the new materials verification rules.

MAOP reconfirmation. Operators must reconfirm the MAOP of certain onshore gas transmission pipelines by using one of six methods spelled out in the new regulations. Operators must develop MAOP reconfirmation procedures by July 1, 2021, perform MAOP reconfirmation for at least 50 percent of covered pipeline mileage by July 3, 2028, and for all pipeline mileage by July 2, 2035, or four years from the date that a segment becomes subject to the regulation, whichever is later.

Assessing areas outside of HCAs. Operators must conduct an integrity assessment of certain onshore, steel, gas transmission pipeline segments with a MAOP above 30 percent specified minimum yield strength located in a Class 3 or 4 location or pipeline segments that can accommodate ILI tools and are located in the newly-defined moderate consequence area, which is an onshore area within a potential impact circle containing either five or more buildings or any portion of the paved surface of an interstate, freeway, expressway, or principal arterial roadway with four or more lanes.

Recordkeeping. The rule established a variety of new recordkeeping requirements, including records pertaining to class location, materials, design, components, welding, plastic pipe, testing and MAOP. The new requirements distinguish between the obligations that apply to operators of pipelines installed prior to July 1, 2020, which only require retention of existing records, and pipelines installed after then, which require operators make certain records.
Miscellaneous. PHMSA incorporated a series of ILI pipeline assessment industry consensus standards and expanded the array of assessment methods that operators may use in HCAs and in non-HCA areas. PHMSA also added requirements for protecting ILI launcher and receivers. The agency formally adopted the six-month grace period to the sevencalendar year maximum period for performing IM reassessments and requirements for reporting MAOP exceedances. Additionally, operators must consider seismicity as part of the threat evaluation under the IM program.

Safety of hazardous liquid pipelines

Ending a nearly decade-long rulemaking process, PHMSA issued a final rule amending the federal safety standards for hazardous liquid pipelines. A prior version was released in the last days of the Obama administration, but was sent back to PHMSA at the start of the Trump administration under a White House memorandum. This version of the rule incorporates input from the current administration, the most significant of which is removing new requirements for performing pipeline repairs. The rule takes effect on July 1, 2020. The most noteworthy provisions are summarized below.

Reporting requirements. Operators of gravity lines (with exception to lines that travel no farther than one mile from a facility boundary without crossing any waterways used for commercial navigation) and previously unregulated gathering lines must submit annual, accident and safety-related condition reports to PHMSA.

72-hour inspections after extreme weather events. Within 72 hours after the cessation of the event (unless the operator notifies PHMSA that personnel or equipment are unavailable), operators are required to perform inspections of all pipeline facilities potentially affected by an extreme weather event that has a likelihood of scouring damage or moving soil surrounding the pipeline. Extreme weather events include tropical storms; hurricanes; floods exceeding river, shoreline or creek-high water banks; landslides; or earthquakes. Operators must take remedial action based upon inspection results.

Pipeline assessments for non-IM segments. Operators of onshore pipeline segments that can accommodate ILI tools and which are not currently subject to IM program requirements must perform integrity assessments, using ILI or an acceptable alternative technique if ILI is impracticable, at least once every 10 years, including an initial assessment by October 1, 2029.

Leak detection. All hazardous liquids pipelines, except for offshore gathering lines and regulated onshore gathering lines, must have an effective leak detection system.
Accommodation of ILI tools. All hazardous liquid pipelines in HCAs and areas that could affect HCAs must be capable of accommodating ILI tools within 20 years, unless the basic construction of the pipeline will not accommodate ILI tools or the operator determines that the high cost of compliance would force it to abandon the pipeline, subject to PHMSA approval.

Emergency order procedures

In response to authority granted in the 2016 PIPES Act, PHMSA published a final rule updating the regulations for issuing emergency orders to address unsafe operating conditions. Under the rule, PHMSA may impose restrictions, prohibitions, or safety measures on an operator or a group of operators to address an imminent hazard, without first providing prior public notice or the opportunity for a hearing. An emergency order could be triggered after a natural disaster, the discovery of serious flaws in pipelines or in equipment manufacturing processes, or when an accident reveals an unsafe industry practice. The new regulations limit the duration of emergency orders to 365 days, at which time PHMSA must determine whether to initiate a rulemaking or rescind the emergency order. The new regulations provide affected pipeline owners or operators a process to seek review of the emergency order. The rule takes effect on December 2, 2019.

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Potential Changes to Title VII Protections Against Discrimination ‘Because of … Sex’

The Legal Intelligencer

(by Stephen Korbel and Anna Skipper)

On Oct. 8, the U.S. Supreme Court heard oral argument on three cases addressing the scope of sex discrimination protections under Title VII of the Civil Rights Act of 1964 Section 7, 42 U.S.C. Section 2000e-2 (1964). Title VII makes it an unlawful practice for an employer to “fail or refuse to hire or to discharge any individual, or otherwise to discriminate against any individual with respect to his … sex,” or “to limit, segregate, or classify his employees or applicants for employment in any way which would deprive or tend to deprive any individual of employment opportunities or otherwise adversely affect his status as an employee, because of such individual’s … sex.”

Two consolidated cases, Altitude Express v. Zarda, 883 F.3d 100 (2d. Cir. 2018), cert. granted, 139 S. Ct. 1599, 203 L. Ed. 2d 754 (U.S. Apr. 22, 2019) (No. 17-1623) and Bostock v. Clayton County Board of Commissioners, 723 Fed. Appx. 964 (11th cir. 2018), cert. granted, 139 S. Ct. 1599, 203 L. Ed. 2d 754 (U.S. Apr. 22, 2019) (No. 17-1618), address whether discrimination on the basis of sexual orientation is a form of discrimination “because of … sex.” A third case, R.G. & G.R. Harris Funeral Homes v. Equal Employment Opportunity Commission, 884 F.3d 560 (6th Cir. 2018) cert. granted in part, 139 S. Ct. 1599, 203 L. ED. 2d 754 (U.S. Apr. 22, 2019) (No. 18-107), addresses discrimination on the basis of gender identity and transgender status.

In Zarda, the U.S. Court of Appeals for the Second Circuit held that an employee was entitled to bring a Title VII claim for discrimination based on sexual orientation as a subset of sex discrimination. The employee alleged he was fired due to his failure to conform to sex stereotypes referring to his sexual orientation, by making clients aware of his homosexuality. The court noted that under the Supreme Court Holding in Price Waterhouse v. Hopkins, 490 U.S. 228, 250-51 (1989), Title VII prohibits not just discrimination based on sex itself, but also discrimination based on nonconformity with gender norms. The Zarda court reasoned that sexual orientation discrimination is a subset of sex discrimination for three reasons. First, citing Rivera v. Rochester Genesee Regulation Transportation Authority, 743 F.3d 11, 23 (2d Cir. 2014), the court noted that because Title VII’s prohibition on sex discrimination applies to any practice in which sex is a motivating factor, and sexual
orientation is defined by one’s sex in relation to the sex of those to whom one is attracted. Thus, it is impossible for an employer to consider sexual orientation without considering the employee’s sex, resulting in a decision in which sex was a motivating factor. Second, the court noted that under Price Waterhouse, sex discrimination may be based on assumptions or stereotypes about how members of a particular gender should be, including to whom they should be attracted. It concluded that where a man who is attracted to men is treated differently than a woman who is attracted to men, sex discrimination has occurred. Finally, the court noted that sexual orientation discrimination is associational discrimination, similar to race discrimination based on the race of an employee’s spouse, rather than the race of the employee himself as stated in Holcomb v. Iona College, 521 F.3d 130, 139 (2d Cir. 2008).

In the accompanying case, Bostock, an employee of the Clayton County, Georgia, Child Welfare Services alleges he was terminated from his position in violation of Title VII due to sex, sexual orientation and failure to conform to a gender stereotype, after he promoted his participation in an LGBTQ softball league. The U.S. Court of Appeals for the Eleventh Circuit affirmed the district court dismissal of Gerald Bostock’s Title VII suit for failure to state a claim, in accordance with its holding in Evans v. Georgia Regional Hospital, 850 F.3d 1248, 1256 (11th Cir. 2017), cert denied, 138 S. CT. 557, 199 L. ED. 2d 446 (2017), which rejected the argument that Supreme Court precedent in Oncale v. Sundowner Offshore Services, 523 U.S. 75, 79 (1998) and Price Waterhouse supported a cause of action for sexual orientation discrimination under Title VII.

The final case, R.G. & G.R. Harris Funeral Homes, considers whether Title VII prohibits discrimination against employees either because of their failure to conform to sex stereotypes under Price Waterhouse, or based on their transgender and transitioning status. In R.G. & G.R. Harris, the U.S. Court of Appeals for the Sixth Circuit considered the case of a transgender woman, who was terminated shortly after notifying her employer that she intended to transition from male to female and would represent herself and dress as a woman while at work. The court, citing Zarda, stated that under Price Waterhouse, an employer engages in unlawful discrimination on the basis of sex when it expects either biologically male or biologically female employees to conform to certain notions of how each should behave. The court reasoned that it is analytically impossible to fire an employee based on that employee’s status as a transgender person without being motivated, at least in part, by the employee’s sex, and thus, discrimination on the basis of transgender or transitioning status violates Title VII. In addition, the court held that “because of sex” inherently includes discrimination against employees because of a change in their sex.

The outcome of these cases will shape the landscape of federal protections for employees who experience discrimination based on sexual orientation and gender identity. In addition, a bill known as the “Equality Act” was introduced to the U.S. House of Representatives on March 13 by Rep. David Cicilline (D-RI-1). The bill notes that the absence of explicit prohibitions of discrimination on the basis of sexual orientation and gender identity under federal statutory law has created uncertainty for employers and other entities covered by
federal nondiscrimination laws and proposes to amend Title VII by striking sex” in each place it appears and inserting “sex (including sexual orientation and gender identity)”. The bill has been received in the Senate, read twice and was referred to the Committee on the Judiciary.

At this time, there are no statewide statutory protections for discrimination based on sexual orientation or gender identity in Pennsylvania, and no relevant bills currently pending. However, more than 50 local municipalities and counties (including: Allegheny and Erie counties; Philadelphia and Pittsburgh; the municipalities of Mount Lebanon, Ross Township and State College among others) have ordinances in place prohibiting discrimination based on sexual orientation or gender identity in employment, housing and
public accommodations. In addition, in 2018, the Pennsylvania Human Relations Commission issued guidance stating that for the purpose of persons filing complaints alleging discrimination under the Pennsylvania Human Relations Act, 43 P.S. Section 953 (1955), the commission will interpret “sex” to include sex assigned at birth, sexual orientation, transgender identity, gender transition, gender identity, or gender expression, see Pennsylvania Human Relations Commission, Guidance on Discrimination on the Basis of
Sex Under the Pennsylvania Human Relations Act (2018).

The current momentum at the local, state and federal level is to extend discrimination protections to individuals based on sexual orientation as well as gender identity. Employers should be prepared to revise policies and handbooks to reflect a broader definition of discrimination because of sex. In addition, for some employers, it may, from employee relations and morale perspective, make sense to proactively expand protections prior to any Supreme Court ruling, or state or federal statutory change. When making this decision, employers should carefully consider their organizational culture to determine whether such a proactive change would benefit their organization.

For the full article, click here.

PHMSA Publishes Long-Awaited Mega Rule for Gas Transmission Lines: Remaining Rule Topics

Pipeline Safety Alert

(by James Curry, Keith Coyle and Brianne Kurdock)

This is the last alert in a four-part Babst Calland series on PHMSA’s final rule amending the gas pipeline safety regulations at 49 C.F.R. Part 192 (Rule), published in the Federal Register on October 1, 2019. The first alert reviewed new requirements for materials verification and reconfirmation of maximum allowable operating pressure (MAOP). The second alert discussed PHMSA’s extension of integrity assessment requirements to areas outside high consequence areas (HCAs). The third alert reviewed the new recordkeeping requirements. This alert discusses the remaining rule topics: strengthening assessment requirements, extending the integrity management (IM) reassessment schedule, adding safety features to launchers and receivers, evaluating seismicity, and reporting MAOP exceedances.

Strengthening Assessment Requirements

PHMSA has incorporated a series of industry consensus standards regarding the use of in-line inspection (ILI) tools for pipeline assessments. PHMSA has also expanded the array of assessment methods that operators may use, both for covered segments in HCAs and in non-HCA areas.

What’s in the Rule?

Incorporation by reference of NACE SP0102-2010, Inline Inspection of Pipelines, which relates to the design and construction of pipeline facilities to accommodate the passage of ILI devices, as well as the performance of ILI assessments (§§ 192.150 and 192.493). Operators may use tethered or remotely controlled tools not explicitly noted in NACE SP0102, as long as they comply with the sections of that standard that are applicable given the technology.
Incorporation by reference of API STD 1163, In-Line Inspection Systems Qualification Standard, which sets out performance-based requirements for ILI procedures, personnel, equipment and software and ANSI/ASNT ILI-PQ, In-Line Inspection Personnel Qualification and Certification (§ 192.493).
Operators may continue to use direct assessment (DA) for IM covered segments, but its use is now explicitly limited to those internal and external corrosion and stress corrosion cracking (SCC) threats that DA is capable of assessing (§ 192.921).
Spike hydrostatic pressure tests can be used to assess for time-dependent threats (SCC, selective seam weld corrosion, manufacturing and related defects (pipe body and seams) and other cracks and crack-like defects) on covered segments and elsewhere (§§ 192.921 and 192.506).
Excavation and in situ DA can be used to assess a threat on a covered segment if the selected method is capable of evaluating the threat. PHMSA lists a variety of technologies that can be used (§ 192.921).
Guided Wave Ultrasonic Testing (GWUT) may be used for IM assessments on covered pipe without prior notification to PHMSA, and the agency has adopted a modified version of its prior guidance on GWUT as a new Appendix F to Part 192.

What’s not in the Rule?

PHMSA struck the proposal that operators comply with both the “requirements and recommendations” of the ILI-related industry consensus standards proposed for incorporation into Part 192 (§§ 192.150 and 192.493), based on comments and a GPAC recommendation. This change allows operators to implement those consensus standards as drafted, and to use their discretion in determining whether to apply the recommendations.
PHMSA had proposed to limit DA only to pipelines that could not be assessed with ILI, but based on industry comments and GPAC recommendations, the Agency decided to allow the continued use of DA (including on ILI-piggable lines) as long as it is suitable for the threat being evaluated.
PHMSA rejected numerous industry comments related to ILI tool selection for specific threats and ILI tool capabilities and tolerances on the basis that these comments were out of scope.
The Agency removed language from proposed § 192.921 that was duplicative of existing § 192.915 regarding the qualifications of persons reviewing ILI data.

Six-Month Extension to IM Reassessment Schedule

PHMSA modified its regulations to allow for the possibility of a six-month extension to the seven calendar year maximum reassessment schedule. This extension was authorized through self-executing language in the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (2011 Act). Although operators have been able to apply for an extension since 2011, PHMSA is now updating the regulations for consistency purposes. The new regulations will become effective on July 1, 2020.

What’s in the Rule?

Operators that are unable to perform the required pipeline IM assessment on a covered segment within seven calendar years can apply for a six-month extension by providing sufficient justification in writing to PHMSA.

What’s not in the Rule?

PHMSA did not clarify what “sufficient justification” means, but stated that “at a minimum, must demonstrate that the extension does not pose a safety risk.”
PHMSA did not specify a processing time for these applications.

Launchers and Receivers

PHMSA added new requirements for pipeline launchers and receivers used for ILI tools and cleaning pigs. The new rule is intended to prevent inadvertent system breaches due to incorrect operation. These requirements take effect on July 1, 2021.

What’s in the Rule?

Launchers and receivers must include a suitable means to relieve pressure in the barrel and indicate either the barrel pressure or prevent opening if the pressure has not been relieved. Most launchers and receivers are already equipped with such devices. PHMSA asserts this change is “consistent with current industry practice” and expects it will affect at most 20 of the 1,205 operators subject to the rule (§ 192.750).

What’s not in the Rule?

Operators do not need to upgrade existing launchers and receivers now but an operator must make the modifications before using the launcher and receiver.

Seismicity and Other Threat Evaluation Clarifications

As required in the 2011 Act, PHMSA amended the requirements for the IM threat evaluation process by requiring operators to consider seismicity. PHMSA also added new requirements for pipeline segments with crack or crack-like defects and will require operators to determine if cyclic fatigue analyses remain valid on seven-year intervals.

What’s in the Rule?

Operators must consider seismicity, geology, and soil stability when identifying potential threats to covered segments.
Every seven years, operators are required to determine if cyclic fatigue analyses remain valid, or must be revised based on changes to operating pressure cycles or other loading conditions.
Operators may only consider manufacturing, fabrication, or construction (MFC) defects as stable threats if the covered segment has been subject to a hydrostatic pressure test of 1.25 times MAOP and has not experienced a reportable incident due to a MFC defect since that pressure test. If the segment has experienced a reportable incident, the operator must prioritize the segment for baseline assessment or reassessment.
Operators must evaluate and remediate, if necessary, all similar pipeline segments if a crack or crack-like defect on a covered pipeline is identified.

What’s not in the Rule?

PHMSA deleted the proposed reference to the MAOP reconfirmation requirements for pipeline segments with MFC threats that have experienced a reportable incident, an MAOP increase, or an increase in stresses leading to cyclic fatigue. Instead, PHMSA has referenced the new fracture mechanics requirements.
PHMSA did not agree with industry comments and a GPAC recommendation to consider removing “hydrostatic” and allow other testing media in § 192.917(e)(3) for evaluating MFC threats. PHMSA observed that such change would be contrary to a National Transportation Safety Board recommendation that MFC threats can only be considered as stable threats if the pipeline segment had a hydrostatic pressure test of at least 1.25 times MAOP.

Reports of MAOP Exceedances

PHMSA amended the safety-related condition reporting requirements by adding a reporting requirement for owners and operators of gas pipeline facilities that exceed their MAOP beyond the build-up allowed for the operation of pressure-limiting or control devices. The change updates the regulations to reflect the self-executing provision in the 2011 Act and add detail on how to make the report. PHMSA first notified operators about the requirement in 2012 in Advisory Bulletin ADB-2012-11. This requirement will take effect on July 1, 2020.

What’s in the Rule?

Operators of transmission pipelines must make a report of each MAOP exceedance to PHMSA within 5 business days and will not be able to use the exceptions from reporting listed in § 191.23(b).

In contrast, as required by current regulation, operators of gathering or distribution pipelines, LNG facilities, or underground natural gas storage facilities must report pressure exceedances due to malfunctions or operating error. However, operators of those pipelines will have 5 to 10 days to report, as opposed to 5 days, and may use the § 191.23(b) exception to reporting, if applicable.

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Babst Calland – A Founding Partner of the Pittsburgh Legal Diversity & Inclusion Coalition

Babst Calland has joined with area law firms, in-house legal departments, and law schools to form the Pittsburgh Legal Diversity and Inclusion Coalition (PLDIC). The Coalition’s mission is to attract and retain people of all races and backgrounds to Pittsburgh, and assist employers in the legal industry for the purpose of increasing the hiring, retention and inclusion of diverse legal professionals. Managing Shareholder Donald C. Bluedorn II serves as an officer on the Coalition’s Board. The firm will work collaboratively with PLDIC and other member organizations to foster diversity and inclusion in the legal community.

In addition to Babst Calland, other current Coalition members include: Alcoa, Allegheny County Bar Association, Chevron, Duquesne Light Company, FedEx Ground, FHL Bank Pittsburgh, Highmark Health, Mine Safety Appliances, PPG, and U. S. Steel, and 18 other prominent law firms in Pittsburgh.

Click here to view a video with attorneys and law firms, discussing the legal profession in Pittsburgh and the importance of the Coalition’s work in the city.

Wolf Administration Announces Plan to Join Northeast Carbon Market

The Legal Intelligencer

(by Kevin Garber and Hannah Baldwin)

On Oct. 3, Gov. Tom Wolf issued Executive Order 2019-07 signifying his intention for Pennsylvania to join the Regional Greenhouse Gas Initiative (RGGI). The order instructs the Pennsylvania Department of Environmental Protection to “develop and present to the Pennsylvania Environmental Quality Board a proposed rulemaking package to abate, control or limit carbon dioxide emissions from fossil-fuel-fired electric power generators,” by no later than July 31, 2020. The order directs the proposed rulemaking to be “sufficiently consistent with the Regional Greenhouse Gas Initiative (RGGI) model rule,” such that allowances may be traded with holders of allowances from other RGGI states. Under the order, the DEP must also conduct a “robust public outreach process” ensuring the program results in reduced emissions, economic gains, and consumer savings, and must consult with PJM, the regional transmission organization that coordinates the movement of wholesale electricity within Pennsylvania and 12 other states, to promote the integration of the program.

What Is RGGI?

RGGI is the country’s first regional, market-based cap and trade program designed to reduce carbon dioxide emissions from power plants. The program was created through a memorandum of understanding (MOU) signed by the governors of Connecticut, Delaware, Maine, New Hampshire, New Jersey, New York and Vermont on Dec. 20, 2005. The MOU committed the signatory states to propose a carbon dioxide budget trading program for legislative and regulatory approval, by setting the initial base annual emissions cap for each state and providing that each state’s annual allocation would decline by 2.5% each year after 2015.
The MOU also provided for the creation of the regional organization, which has an executive board comprised of two members from each signatory state that serves as a forum for collective deliberation, emissions and allowance tracking, and technical support for determining offsets. The regional organization is funded, at least in part, through payments from each signatory state. The MOU also provides for periodic monitoring and review of the program facilitated by the regional organization.

RGGI currently has nine state members: Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island and Vermont. New Jersey, an original participant when the program started in 2005, withdrew from the program in 2011 but is in the process of rejoining. Virginia has also taken steps toward joining RGGI but the current state budget prohibits the state from joining the program this year.
Under RGGI, fossil-fuel-fired electric power generators with a capacity of 25 megawatts or greater (regulated sources) are required to hold allowances equal to their carbon dioxide emissions over a three-year compliance period. Each allowance is equal to one short ton of carbon dioxide. Regulated sources must purchase carbon dioxide allowances issued by a RGGI state in order to comply. Regulated sources may also use offsets, allowances awarded to certain acceptable environmental projects, to meet a maximum of 3.3% of its allowances.

The proceeds from the allowance auctions are allocated back to the participating states in proportion to the amount of carbon subject to regulation in each state.

Legal Authority to Join in Pennsylvania

To date, all RGGI states except New York have enacted both authorizing statutes and regulations to join and implement RGGI. In Pennsylvania, Wolf may have the authority to negotiate with the RGGI states and sign an amendment to the RGGI MOU, but like other RGGI states, a statute and regulation is likely required to bind the commonwealth to a cap and trade program.

RGGI would not be Pennsylvania’s first cap and trade program. Like many states, Pennsylvania instituted a cap and trade program in the early 2000s in response to federal requirements under the Clean Air Act to regulate nitrogen oxides and sulfur dioxide. However, since RGGI was not created in response to a specific federal requirement, instituting a cap and trade program for carbon dioxide and participating in RGGI would likely require express legislative authorization.

RGGI Member Requirements

The MOU does not outline specific procedures for how new states can join RGGI. In the past, however, new signatory states have been added through amendment to the MOU. Section 8 of the MOU provides for general amendments, which must be in writing and have the collective agreement of the authorized representatives of the signatory states. The Second Amendment to the MOU added Maryland as a signatory state, set its initial base carbon dioxide emissions budget, and increased the regional emissions budget to include the new Maryland base budget.

The current RGGI participating states offer a “potential path forward” to RGGI participation in the new state participation in RGGI guidance document, available on RGGI’s website. The guidance suggests that interested states start the process by initiating communication with current RGGI states. Initial discussions should include program compatibility, timing of new state participation, and stringency of the new state’s proposed program. One critical aspect of these discussions is the development of the proposed carbon dioxideallowance budget for the incoming state. According to Maryland’s RGGI coordinator, initial state allowance caps are determined by looking at historic emissions from power generators over 25 megawatts and using the integrated planning model (an model platform developed by the International Climate Foundation and used by both USEPA and FERC to evaluate utility air emissions and cost-benefits for regional transmission organizations) to analyze the projected impact of a state’s entrance into RGGI on the price of allowances across all RGGI states. Pennsylvania’s initial allowance would be the largest of any current RGGI participant, as Pennsylvania is the only major fossil fuel producing state to consider joining. In 2017 Pennsylvania’s power sector emitted 76.8 million metric tons of carbon dioxide, compared to regional RGGI cap for all member states in the same year of 84.3 metric tons.

The guidance includes nine other steps, including the identification of legislation and executive action needed to authorize participation, establishing a carbon dioxidebudget trading program and an auctioning procedure for carbon dioxide allowances using the RGGI model rule as a template, and completing the necessary state rulemaking process. Other steps include signing a contract with RGGI, Inc., a 501(c)(3) nonprofit corporation created to provide administrative and technical support to the development and implementation of each RGGI state’s carbon dioxide budget trading program.

To become an official participating state under RGGI’s bylaws, the RGGI board of directors will enter into a service contract with the participating state under which RGGI, Inc. will provide technical and scientific advisory services to the participating state. In Pennsylvania, the governor or DEP would likely sign the contract, with approval by the attorney general, depending on the authority granted in the implementing legislation.

Other Considerations

If Pennsylvania joins RGGI, one important question is how RGGI revenue generated by the carbon dioxide allowance auctions will be spent in the commonwealth. The MOU requires each signatory state to allocate 25% of its allowances to consumer benefit or strategic energy purpose, which includes measures promoting energy efficiency, directly mitigating electricity ratepayer impacts, promoting renewable or non-carbon emitting technologies or funding the administration of the program itself. Other than a provision in the 2017 model rule stating that the regional organization must be funded, at least in part, by the signatory states, nothing in the MOU or model rule specifically restricts how additional RGGI revenue can be spent.

There is also another cap and trade initiative pending in Pennsylvania resulting from a petition for rulemaking submitted by a group of non-profit organizations and individuals in November 2018. On April 16, the Pennsylvania Environmental Quality Board voted 14-5 in favor of directing the DEP to develop a report and recommendation on the cap and trade petition. The petition borrows heavy from the California cap and trade program and is far broader than RGGI cap and trade programs, covering multiple sectors of the economy, not just electricity generators. On June 18, the DEP reported to the EQB that it expects to present an outside consultant’s evaluation of the cost and benefits of the petition in early 2020.

The impact of joining RGGI in Pennsylvania is unclear but is certain to affect pricing for residential and commercial consumers. The effect on future greenhouse gas emissions is also unclear because Pennsylvania emissions of greenhouse gases have already declined from 324 million metric tons in 2000 to 286 million metric tons in 2015.

For the full article, click here.

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