Articles, Alerts & Perspectives

Illegal parts: The crackdown on aftermarket defeat devices on vehicles

Smart Business 

(by Jayne Gest with Julie Domike and Gina Falaschi)

Recent enforcement efforts by the Environmental Protection Agency (EPA) have resulted in a marked upswing in cases — civil and criminal — against parts manufacturers and installers of aftermarket defeat devices on vehicles, including some 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.

“Business owners need to ensure their company-owned vehicles and engines are legal,” says Julie Domike, shareholder at Babst Calland. “Many of these 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; therefore, liability could extend to other aftermarket suppliers.”

Smart Business spoke with Domike and Gina Falaschi, associate at Babst Calland, about the EPA’s enforcement efforts.

Where might businesses be at risk?

Mechanics sometimes look to increase fuel economy, boost the performance of the vehicle, reduce maintenance costs, or reduce vehicle downtime associated with routine maintenance, such as regenerating diesel particulate filters. The illegal methods of doing this involve removing or disabling emissions control devices on vehicles, such as the diesel particulate filter, exhaust gas recirculation valve and selective catalytic reduction system. Because removing vehicle hardware will result in a check engine notification or may put the vehicle into ‘limp home’ mode, severely limiting power, these changes must be accompanied by an illegal alteration of the software to override its response to missing or disabled hardware.

It is important to realize when employees add aftermarket defeat devices to company vehicles, businesses could have significant Clean Air Act liability, and right now the EPA is actively looking for these violations.

Why is the EPA so concerned?

The EPA has significant enforcement power under the Clean Air Act to ensure that national air quality standards are maintained. The EPA is particularly concerned about the increase in air pollution from the transportation sector. While EPA enforcement against stationary sources has recently decreased, the EPA has increased enforcement against vehicle and equipment manufacturers in both criminal and civil venues. When vehicles are tampered with, they have significantly increased emissions, especially nitrogen oxide (NOx), which contributes to ground level ozone, a criteria pollutant regulated by the EPA.

The EPA reports its enforcement efforts have uncovered over half a million vehicles that have been tampered with, potentially increasing emissions by the equivalent of 9 million trucks.

Who exactly could be liable?

The EPA has historically brought civil enforcement actions against vehicle and engine manufacturers for engine software that allowed NOx emissions to increase. The agency, however, has expanded enforcement to manufacturers, retailers and installers of tuners, as well as individuals who remove emissions control systems from vehicles, especially trucks. Those who modify vehicle fleets by adding equipment may also violate the Clean Air Act by causing excess emissions due to weight increases. The EPA sees this as tampering.

With the EPA’s current emphasis on enforcement, retailers could be subject to civil enforcement for selling aftermarket defeat devices. Additionally, those who manufacture and sell devices that they know or should know are being used to tamper with emissions control equipment could be targeted by EPA enforcement.

What action should business owners take?

Be aware of the issue; ensure it is not happening in your organization or with your vehicles. Inform your employees that this is not condoned behavior and if anyone has touched a vehicle in this fashion, it needs to be fixed. Beyond that, add education about the Clean Air Act, and what’s permissible under it, to your company’s environment, health and safety training.

For the full article, click here.

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.

Reprinted with permission from the December 12, 2019 edition of The Legal Intelligencer  © 2019 ALM Media Properties, LLC. All rights reserved. 

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.

Click here for PDF. 

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

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 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.

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.

For the PDF, click here.

For the full article, click here.

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.

Reprinted with permission from the November 7, 2019 edition of The Legal Intelligencer © 2019 ALM Media Properties, LLC. All rights reserved. 

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.

Click here for PDF. 

PHMSA Proposes Allowing Liquefied Natural Gas Transport by Rail

Transportation Safety Alert

(by Boyd Stephenson and James Curry)

On October 24, 2019, the Pipeline and Hazardous Materials Safety Administration (PHMSA) published a notice of proposed rulemaking (NPRM) proposing to amend 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, 2019, 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, 2019.

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% 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 only be transported by railcar 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 are already 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 on August 7, 2019, with PHMSA receiving nearly 3,000 comments.  PHMSA has not yet acted on the special permit 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 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 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?

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PHMSA Publishes Long-Awaited Mega Rule for Gas Transmission Lines: Recordkeeping Requirements

Pipeline Safety Alert

(by James Curry, Keith Coyle and Brianne Kurdock)

This is the third alert in a four-part Babst Calland series on the Pipeline and Hazardous Materials Safety Administration’s (PHMSA or the Agency) final rule amending the federal safety standards for gas pipeline facilities (Rule). PHMSA published the Rule 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 provided a summary of the integrity assessment requirements for areas outside of high consequence areas. This alert will summarize the new Part 192 recordkeeping requirements. Finally, Babst Calland will survey the remaining Rule topics.

New Part 192 Recordkeeping Requirements – 49 C.F.R. §§ 192.5, 192.67, 192.205, 192.127, 192.227, 192.517, 192.607, 192.619, and 192.624

At an earlier point in the rulemaking process, PHMSA proposed to establish several new retroactive recordkeeping requirements in Part 192. PHMSA also took the position that all records had to satisfy the reliable, traceable, verifiable, and complete (TVC) recordkeeping standard. A version of this standard was used by the National Transportation Safety Board (NTSB) in its recommendations after the 2010 San Bruno pipeline incident. PHMSA did not propose a definition of the TVC recordkeeping standard but instead referred to the agency’s TVC guidance issued in 2012.

In the Rule, PHMSA made significant changes to its proposed recordkeeping requirements including clarifying that the new recordkeeping requirements are prospective only and removing ‘reliable’ from TVC since that term was never used by the NTSB. PHMSA also drew distinctions in several regulations between the obligations that apply to operators of pipelines installed prior to July 1, 2020, which only require retention of existing records, and those installed after this date, further emphasizing the prospective nature of the new obligations.

What is in the Rule?

New Record Requirements for Pipelines Installed on or before July 1, 2020

            Class Location Records (§ 192.5(d)). An operator must retain records documenting how it determined the current class location of its pipeline, but does not need to have historical records for prior class locations. Unlike many of the other recordkeeping requirements, PHMSA did not limit this provision to transmission pipelines.

            Material Records (§ 192.67). For steel transmission pipelines installed on or before July 1, 2020, an operator must retain records for the life of the pipeline that document tests, inspections, and attributes required by the manufacturing specifications applicable at the time the pipe was manufactured or installed, but only if the operator has such records. PHMSA notes that if the operator does not have these records and needs them to establish MAOP, then the operator could be subject to the new MAOP reconfirmation requirements.

            Pipeline Components (§ 192.205(b)). An operator of a steel transmission pipeline installed on or before July 1, 2020, must retain records documenting the manufacturing standard and pressure rating valves, flanges, fittings, branch connections, extruded outlets, anchor forgings, and other components with material yield strength grades of 42,000 psi or greater and with nominal diameters of greater than 2 inches for the life of the pipeline but only if the operator has such records. PHMSA notes that if an operator of an existing pipeline does not have these records and needs them to establish MAOP, then the operator could be subject to the new MAOP reconfirmation requirements.

            Design Records (§ 192.127(b)). An operator of a steel transmission pipeline installed on or before July 1, 2020 must retain records documenting pipe design and the determination of design pressure in accordance with §§ 192.103 and 192.105, for the life of the pipeline but only if the operator has such records. PHMSA notes that if an operator of an existing pipeline does not have these records and needs them to establish MAOP, then the operator could be subject to the new MAOP reconfirmation requirements.

            Test Records (§ 192.517). An operator must make and retain for the life of the pipeline a record of each test conducted under §§ 192.505, 192.506, and 192.507.

            Material Verification Records (§ 192.607). An operator subject to § 192.607 must document the physical pipeline characteristics and attributes, including diameter, wall thickness, seam type, and grade (e.g., yield strength, ultimate tensile strength, or pressure rating for valves and flanges, etc.) and retain these records for the life of the pipeline. These records must meet the TVC standard.

            Establishing Maximum Allowable Operating Pressure (§ 192.619). An operator of a pipeline in operation as of July 1, 2020, must retain any existing records establishing the MAOP for the life of the pipeline. If an operator does not have these records and is required to reconfirm MAOP in accordance with § 192.624, the company must retain the reconfirmation records for the life of the pipeline.

            Reconfirmation of Maximum Allowable Operating Pressure Records ((§ 192.624). An operator subject to the MAOP reconfirmation requirements must retain records of investigations, tests, analyses, assessments, repairs, replacements, alterations, and other actions taken in accordance with the requirements of § 192.624 for the life of the pipeline.

Recordkeeping Requirements for Pipelines Installed After July 1, 2020.

            Material Records (§ 192.67). For steel transmission pipelines installed after July 1, 2020, an operator must make records that document the physical characteristics of the pipeline. The operator must retain these records for the life of the pipeline.

            Design Records (§ 192.127). Operators of a steel transmission pipeline installed after July 1, 2020 must make records documenting that the pipe is designed to withstand external pressures and loads in accordance with § 192.103 and made in accordance with § 192.105. The operator must retain these records for the life of the pipeline.

            Components ((§ 192.205(a)). Operators of a steel transmission pipeline installed after July 1, 2020, must make records documenting the manufacturing standard and pressure rating to which each valve was manufactured and tested in accordance with Subpart D of Part 192. Flanges, fittings, branch connections, extruded outlets, anchor forgings, and other components with material yield strength grades of 42,000 psi (X42) or greater and with nominal diameters of greater than 2 inches must have records documenting the manufacturing specification in effect at the time of manufacture, including yield strength, ultimate tensile strength, and chemical composition of materials. The operator must retain these records for the life of the pipeline.

            Welding Records (§ 192.227(c)). An operator of a steel transmission pipeline installed after July 1, 2021, must have records demonstrating each individual welder qualification at the time of construction. An operator must retain these records for five years following construction. This is a change from the lifetime requirement that PHMSA had initially proposed. PHMSA has also adjusted the effective date of this requirement to apply to pipelines installed one year from the effective date of the Rule.

            Plastic Pipe (§ 192.285(e)). An operator of a plastic transmission pipelines installed after July 1, 2021, must have records demonstrating each individual’s plastic pipe joining qualifications at the time of construction. An operator must retain those records for a minimum of five years following construction. This is a change from the lifetime requirement that PHMSA had initially proposed. PHMSA has also adjusted the effective date of this requirement to apply to pipelines installed one year from the effective date of the Rule.

            Establishing Maximum Allowable Operating Pressure (§ 192.619). An operator of a pipeline placed in operation after July 1, 2020, must make and retain records establishing the MAOP for the life of the pipeline.

What is not in the Rule?

            Definition of traceable, verifiable, and complete. PHMSA declined to define TVC stating that “changing that standard could potentially derail work being done by operators to meet that traceable, verifiable, and complete record standard.” Instead, the Agency referenced its definitions of the TVC standard published in guidance from 2011 and 2012. In comparing the language in the preamble of the Rule with the previous Advisory Bulletins, the Firm notes several changes to the description of TVC. PHMSA has added that the individual who observed the test and thereafter signed an affidavit as to the test conducted would have to be ‘qualified’. In the preamble, the Agency did not recognize prior interpretations which allowed for a single record, rather than complementary records to meet the TVC standard. Finally, PHMSA added mechanical and chemical properties to its description of pipe mill records.

            General Duty Clause of § 192.13(e). The Agency eliminated the proposed general duty clause of § 192.13(e) which would have required that all records meet the TVC standard.

            Table of Record Retention Requirements. PHMSA removed its proposed table (Appendix A) that summarized current and new recordkeeping retention requirements. Although PHMSA maintained that this table memorialized current recordkeeping requirements, it arguably had created new retention requirements that were not supported by the text or history of the regulations.

For a more detailed assessment and redline of the Rule, please contact a member of the Pipeline and HazMat Safety practice group.

Click here for PDF.

Final Repeal of the Clean Water Rule: the End or Another Beginning to the Regulatory Patchwork?

Environmental Alert

(by Lisa Bruderly and Gary Steinbauer)

On October 22, 2019, the U.S. Environmental Protection Agency (USEPA) and U.S. Army Corps of Engineers (Corps) published a final rule in the Federal Register repealing the Obama administration’s 2015 rule redefining “waters of the United States” (WOTUS) under the Clean Water Act, typically referred to as the “Clean Water Rule” (CWR).  In addition to repealing the CWR, the final rule will restore the regulatory definition of WOTUS that existed prior to the CWR for the 22 states (including Pennsylvania) where the CWR’s WOTUS definition is currently in effect.  The pre-CWR definition of WOTUS, along with agency guidance, are themselves controversial.  The final repeal rule becomes effective on December 23, 2019.

USEPA and the Corps released a pre-publication version of the final repeal rule on September 12, 2019.  Almost immediately, environmental groups and several states vowed to file lawsuits challenging the final repeal rule.  These lawsuits likely will be heard by multiple federal district courts throughout the country and could seek injunctions preventing the final repeal rule from taking effect.  While the intent of the final repeal rule is to end the existing regulatory patchwork where the CWR’s WOTUS definition currently is in effect in 22 states, the lawsuits challenging the final repeal rule could result in a different regulatory patchwork, further exacerbating the regulatory uncertainty surrounding the application definition of WOTUS.  In an interesting twist, the New Mexico Cattle Growers’ Association filed a lawsuit on October 22, 2019 in a federal district court in New Mexico, challenging the final repeal rule because the pre-CWR WOTUS definition and related agency guidance that it readopts are allegedly unlawful.

Babst Calland discussed the final repeal rule in detail in a previous Environmental Alert and will continue to actively monitor the shifting regulatory landscape involving the definition of WOTUS.  If you have questions about the final repeal rule, 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.

Click here for PDF. 

Fundraise with care: The pitfalls of hiring intermediaries to find additional investment

Smart Business

(by Jayne Gest with Sara Antol and Chris Farmakis)

When companies start running out of capital and executives are pulled in a million different directions, they often look to an outside party — a person who is well-connected but is not a licensed broker/dealer — to support the fundraising. The two parties may come to an arrangement where he or she will make introductions, help secure additional investment and only be paid a commission if the financing round successfully closes.

The problem is, this scenario is illegal under the rules of Securities and Exchange Commission (SEC). And the excuse — everyone else is doing it — will not work if you are caught, says Sara M. Antol, shareholder at Babst Calland.

“When it comes to broker-dealer territory, many times businesses do not realize how strict the current regulatory environment is, or how extreme the consequences can be when you violate the law,” she says.

Smart Business spoke with Antol and Christian A. Farmakis, shareholder and chairman of the board at Babst Calland, about fundraising compensation.

How common are these arrangements?

Raising money is difficult — it takes time and can be frustrating. Because fundraising is relationship-driven, it is easy to want to bring in a well-connected person in some capacity. And if a company is on a tight budget, it may seem logical to just pay someone if they have success. However, only registered broker-dealers are allowed to engage in this type of activity. And, it is illegal for persons who have not undergone the steps to be registered to act as brokers.

What is permissible?

A company can work with a finder as a consultant, hired under certain narrowly defined conditions. The company must pay a flat or monthly fee that might include helping the organization develop investment materials and making introductions, without negotiating or aiding in the investment’s completion. The compensation cannot be tied to fundraising success.

The other option is to work with a registered broker-dealer. Plenty of firms do this, but it will come at a cost.

How should companies handle these situations with their own employees?

Businesses cannot make someone’s employment or compensation contingent upon raising capital. For example, a CFO who gets equity or a bonus if he or she is successful at fundraising is not allowed. A salesperson paid on commission for finding investors is also not permitted.

Raising capital can be part of an employee’s duties, but it cannot be their sole job function, and they cannot get compensated directly for bringing in investors.

What can be the consequences of incorrectly using a finder or employee to raise capital?

Any companies — whether private or public — that improperly use a nonregistered finder or employee may have to rescind their offer to investors and refund the entire investment monies paid, even when those funds have already been spent.

If the company and its executives are sanctioned, they may not be allowed to do a private placement in the future, such as a Regulation D offering. The individuals named in a sanction may be labeled as “bad actors.” These bad boys, as they are often called, come under regulatory scrutiny for a number of years. There is also the potential of criminal penalties against the individual and the company. The reputational damage to a startup and founder can be severe, even if the violation was unintentional.

When fundraising, what else is important?

Many startups do not put together adequate disclosure documents that lay out all of the upside and downside of an investment. That is why, at least under the current regulatory landscape, it can be a good idea to only raise money from accredited investors. These investors have earned income exceeding $200,000 ($300,000 with a spouse), or a net worth of $1 million, excluding the value of the primary residence. The requirements must be met for the prior two years, with an expectation of the same for the current year.

Remember, fundraising rules are not black and white. The regulations and rules of the road have developed through court cases and on a case-by-case basis with the SEC, so check with your attorney before putting an intermediary between you and potential investors.

For the PDF, click here.

For the full article, click here.

PHMSA Publishes Long-Awaited Mega Rule for Gas Transmission Lines: Assessing Areas Outside of High Consequence Areas

Pipeline Safety Alert

(by James Curry, Keith Coyle and Brianne Kurdock)

This is the second alert in a four-part Babst Calland series on the Pipeline and Hazardous Materials Safety Administration (PHMSA or the Agency) final rule amending the federal safety standards for gas pipeline facilities 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).

This alert discusses PHMSA’s extension of integrity assessment requirements to areas outside high consequence areas (HCAs).  The third alert will review the new recordkeeping requirements.  Finally, Babst Calland will survey the remaining Rule topics.

Assessing Areas Outside of High Consequence Areas – 49 C.F.R. §§ 192.3 and 192.710

PHMSA has introduced new regulations requiring an operator to conduct integrity assessments outside of HCAs.  The Agency has categorized these areas as Moderate Consequence Areas (MCAs).

What is in the Rule?

• Moderate Consequence Area Definition.  A “moderate consequence area” is an onshore area that is within a potential impact circle containing either five or more buildings intended for human occupancy or any portion of the paved surface, including shoulders, of a designated interstate, freeway, or expressway, or principal arterial roadway with four or more lanes, as defined by the Federal Highway Administration.
• Initial Assessment and Reassessment Interval. Operators with an onshore, steel, transmission pipeline segment with a MAOP greater than or equal to 30% SMYS located in a Class 3 or Class 4 location or a piggable MCA segment must assess these segments by July 3, 2034 and every ten years thereafter at intervals of 126 months.  Although PHMSA has allowed a ten-year schedule for reassessments, the Agency has cautioned that an operator must assess its segments earlier depending on the type of anomaly, operational, material, or environmental conditions, or as necessary to ensure public safety.

For those segments that become a MCA in subsequent years, the operator must conduct the initial assessment as soon as practicable but prior to ten years from when the pipeline first meets the applicability conditions in § 192.710(a).

An operator may use a prior assessment to comply with the initial assessment requirement as long as the prior assessment was conducted before July 1, 2020.  An operator may also use an assessment conducted in response to § 192.624(c) as the initial or reassessment.

• Assessment Methods. Pursuant to § 192.710(c), acceptable assessment methods include in-line inspection (ILI) tools, pressure tests (including spike tests), direct examination, guided wave ultrasonic testing, direct assessment, and alternative technologies.
• Review of Assessment Data. Within 180 days, qualified personnel must examine the assessment data and determine if there are any conditions that present a potential threat to pipeline integrity, unless the operator can demonstrate that meeting that deadline is impracticable.  An operator must then remediate any conditions that could adversely affect the safe operation of the pipeline in accordance with 49 C.F.R. §§ 192.485, 192.711, and 192.713.
• Direct Assessment.  PHMSA confirmed that direct assessment may be used only if appropriate for the threat being assessed.

What is not in the Rule?

• Occupied Sites.  In response to numerous comments from stakeholders, PHMSA removed ‘occupied sites’ from the definition of MCAs.  The inclusion of ‘occupied sites’ would have required operators to evaluate where there are outside areas or open structures within the potential impact radius that are occupied by five or more persons for at least 50 days in a twelve-month period or buildings that are occupied by five or more persons on at least five days a week for ten weeks in any twelve-month period.  The Agency agreed that including these areas would be unnecessarily burdensome without a comparable decrease in risk.
• Rights-of-Way.  The Agency also modified its approach to highways limiting the definition of a MCA to include the pavement of the road and shoulders but not the more expansive right-of-way.
• Definition of Piggable.  PHMSA declined to define “piggable segment.”  PHMSA explained that this term is widely understood and means segments that can accommodate ILI tools “without the need for major physical or operation modification, other than the normal operational work required by the process of performing an ILI.”

For a more detailed assessment and redline of the Rule, please contact a member of the Pipeline and HazMat Safety practice group.

Click here for PDF. 

FMCSA’s Hours of Service Proposed Rule

Transportation Safety Alert

(by Boyd Stephenson and James Curry)

On August 22, 2019, the Federal Motor Carrier Safety Administration (FMCSA) published a notice of proposed rulemaking (NPRM) containing potential changes to the hours of service (HOS) regulations for all drivers operating in interstate commerce and for drivers transporting hazardous materials in intrastate commerce.  FMCSA initiated the rulemaking to update the HOS in light of compliance challenges revealed by the Agency’s 2017 electronic logging device mandate.  In the NPRM, FMCSA proposes to:

• Expand the current “short-haul” exception to the HOS rules;
• Expand the adverse driving exception to the HOS rules;
• Allow any 30-minute period of non-driving time to count towards the30-minute rest break;
• Expand access to the sleeper berth exception; and
• Allow a single off-duty break to extend the driver’s on-duty window by the length of the break.

The proposed changes will likely provide operational flexibility to every sector of the trucking industry.  Local drivers’ on-duty windows will expand to equal the time currently allotted for long-haul drivers.  At the same time, the rules would provide more options to long-haul operators, who will be able to use on-duty time for their required break and to expand their driving window by strategically taking optional breaks at times that allow them to avoid driving in heavy traffic.  Comments are due by October 21, 2019.

Current Daily Maximum Driving Times

While FMCSA proposes several exceptions to the basic daily rules, the Agency has not proposed changes to the daily base HOS requirement for property-carrying or passenger-carrying commercial motor vehicles (CMVs).

• A property-carrying CMV driver may drive up to 11 hours during a14-hour window beginning when the driver begins on-duty status. The driver is then prohibited from driving until a 10 consecutive hour period of off-duty time elapses.
• A passenger-carrying CMV driver may drive up to 10 hours in a 15-hour window. The driver isthen prohibited from driving until an eightconsecutive hour period of off-duty time elapses.

Proposed Changes

Short–Haul Exception – The existing short-haul exception exempts property-carrying drivers from the requirement to maintain records of duty status (RODS or logs) and supporting documents for their logs if:

• They report to and depart from the same location for a shift;
• They are on duty for 12 hours or less;
• They drive 11 hours or less;
• They remain within a 100 air-mile (115 mile) radius of their reporting location for their entire shift;
• They receive at least 10 consecutive hours off duty at the end of their shift; and
• Their employers maintain records going back six months demonstrating reporting time, departuretime, reporting/departure location, and the number of hours worked are consistent with the requirements above.

Passenger-carrying drivers operate under the same requirements except they may only drive 10 hours in the 12-hour workday.  Passenger-carrying and property-carrying short-haul drivers are not exempt from the maximum driving time restrictions, they are merely exempt from logging compliance with them.

FMCSA proposes to extend the qualification period from shifts up to 12 hours to shifts up to 14 hours and the qualification radius from 100 air-miles to 150 air-miles (172.5 miles).  Maximum driving times would remain unchanged.  FMCSA adds that it is considering further altering the exception to allow CMV drivers to utilize the short-haul exception even if they do not report to and depart from same location, so long as all of the other existing requirements are followed.  The NPRM does not provide proposed regulatory language implementing this possible change.

Adverse Driving Conditions Exception – The current adverse weather HOS exception allows a driver experiencing unexpected dangerous driving conditions to extend their driving time by up to two hours or until they reach a location safe for the vehicle occupants and secure for its cargo, whichever occurs first.  Presently, the exception extends the amount of time the driver can drive, but it does not extend the 14-hour on-duty window.  FMCSA proposes to extend the exception to cover both driving time and the driving window.  This expansion applies to both cargo-transporting and passenger-carrying CMVs, allowing up to 13 hours of driving in a 15-hour window for cargo-transporting CMVs and 12 hours of driving in a 17-hour period for passenger-carrying CMVs.

30-Minute Rest Break – Presently, all property-carrying CMV drivers are required to take a 30-minute off-duty period after eight hours of driving before they can drive again.  FMCSA proposes to expand access to the rest break by allowing any 30-minute period of off-duty, sleeper berth, or on-duty not driving time to qualify for the rest break.  Passenger-carrying CMV drivers are not required to take the 30-minute rest break, so FMCSA has not proposed any changes to their operations.

FMCSA is also considering eliminating the 30-minute rest break entirely.  However, the NPRM does not include proposed regulatory language.

Sleeper Berth – Today, HOS rules allow a property-carrying CMV driver to divide the 10 hours off-duty required to reset the daily driving limits between two separate, but consecutive, periods.  Drivers must take at least eight hours in the sleeper berth and a second period, of at least two hours, of off-duty time which can be in the sleeper berth or riding in the passenger seat.  It does not matter which of these two periods occurs first.  Driving time in the periods immediately before and after each rest period must not exceed 11 hours, nor may the total driving window, minus the time spent in the sleeper berth and in sleeper berth/optional passenger seat time, exceed 14 hours.  The sleeper berth exception applies only to drivers of property-carrying.

FMCSA proposes to add flexibility to this time by lowering the minimum sleeper berth time from eight to seven hours consecutive hours while retaining the requirement that 10 total hours of sleeper berth plus sleeper berth/optional passenger seat time elapses.  FMCSA notes that it is also considering adjusting this split to six hours in the sleeper berth and four hours that could be taken in the sleeper berth or in the passenger seat.  However, the NPRM does not provide proposed regulatory text for this option.

Drivers could not utilize the sleeper berth exception, in its present form or with FMCSA’s proposed changes, and the proposed break to extend the driving window (below) during the same driving period.

Break to Extend Driving Window – FMCSA proposes a new provision that would allow a driver to take a single break of between 30 minutes and three hours and to extend the 14-hour driving window by the length of the break.  Drivers could not utilize the break to extend the driving window and the sleeper berth exception during the same driving period.

FMCSA asks for input about the possibility of dividing the break to extend the driving window into multiple breaks of at least 30 minutes that could total up to three hours, but the Agency does not propose regulatory text.

Compliance Dates – Because drivers are now required to demonstrate compliance with the HOS via electronic logs, FMCSA has requested electronic logging device manufacturers to weigh in and explain how much time would be necessary to reprogram their devices to conform to a new set of rules.  FMCSA has requested comment on six-month and one-year implementation periods.

Rulemaking Petitions – FMCSA also responded to four rulemaking petitions in the NPRM, from the Owner-Operator Independent Driver Association (OOIDA), TruckerNation, the United Drivers Association (UDA), and the U.S. Transportation Alliance (USTA).  OOIDA’s petition requested that breaks could be used to extend the driving window, and FMCSA included that concept in the NPRM.  TruckerNation requested that FMCSA alter the 14-hour driving window to begin after the driver begins driving, rather than coming on duty, and to pool off-duty periods of three hours or longer to meet the 10 hour off-duty requirement to open a new 14-hour driving window.  FMCSA denied TruckerNation’s petition.  The USTA petition proposed allowing pooling of more than two off-duty sleeper berth periods, which could be as short as two hours, while the UDA proposed splitting the sleeper berth required periods into five sleeper berth hours and five optional hours.  Both the USTA and the UDA also proposed reducing the minimum off-duty time to restart a driver’s weekly maximum on-duty time from 34 hours to 24 hours.  FMCSA rejected both petitions, but noted that it would consider them as comments on relevant parts of the NPRM.

Observations & Questions

• The NPRM would forbid drivers from using a split-sleeper berth period and a break extending the14-hour driving window in the same driving period. But, FMCSA also explicitly states a driver need not declare whether they are taking the first half of a sleeper berth break or one extending the 14-hour window until choosing to take the second half of the sleeper break.  While this language is consistent with the NPRM’s proposed language, FMCSA is also considering allowing multiple breaks to extend the 14-hour window.  If FMCSA allows multiple breaks to extend the 14-hour window
  and doesn’t force drivers to choose whether they are extending their driving window or using sleeper berth break, how can enforcement agencies differentiate between the two until the driver begins the second period of the sleeper berth exception?  If FMCSA allows for shorter breaks to extend the driving window, could FMCSA allow drivers to combine them with split-sleeper time and still ensure a safety level at least equivalent to that under current regulations?
• FMCSA asks 39 specific questions in the NPRM. Combined with the Agency’s multiple proposals in areas like altering or eliminating the 30-minute rest break and minimum sleeper berth time, it is possible that FMCSA may need to issue a supplemental NPRM in the future to clarify itsproposal before promulgating a final rule.
• Several commenters submitted sleep science studies that they assert are contrary to FMCSA’s position that its proposed HOS changes will not increase driver fatigue. Similarly, the Insurance Institute for Highway Safety submitted data it claims demonstrates the safety risks of continuing a short-haul exception to the HOS at all are greater than previously understood.  FMCSA will need to grapple with these comments as it moves toward a final
• Carriers that transport hazardous materials that require a Pipeline and Hazardous Materials Safety Administration security plan most often satisfy their en route security requirement by directing their drivers to exercise constant attendance over their cargo. Drivers exercising constant attendance cannot log off-duty status, though FMCSA has granted an exemption from the 30-minute rest break requirement for these drivers.  Under the exemption, drivers exercising constant attendance over their cargo during their mandatory 30-minute break may log the time as on-duty not driving, but mayperform no other work and must keep a written copy of the exemption in the vehicle.  FMCSA’s,proposed changes to the 30-minute rest break mean that drivers exercising constant attendanceduring their rest break will now be compliant, even without the exemption.

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PHMSA Publishes Long-Awaited Mega-Rule for Gas Transmission Lines: Material Verification and MAOP Reconfirmation

Pipeline Safety Alert

(by James Curry, Keith Coyle and Brianne Kurdock)

On October 1, 2019, the Pipeline and Hazardous Materials Safety Administration (PHMSA or the Agency) published a final rule in the Federal Register amending the federal safety standards for gas pipeline facilities at 49 C.F.R. Part 192 (Rule). The Rule primarily addresses concerns identified in congressional mandates and National Transportation Safety Board (NTSB) recommendations for gas transmission lines.  The most significant provisions include 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), including in newly-defined moderate consequence areas (MCAs).  Other changes include amendments to the integrity management (IM) requirements, new requirements for reporting MAOP exceedances and the safety of inline inspection launcher and receivers, as well as related recordkeeping requirements.

This alert is the first in a four-part Babst Calland series on the Rule.  This first alert discusses the new MAOP reconfirmation and material verification requirements.  The next alert will cover MCAs and new assessment requirements for pipelines located outside of HCAs.  The third client alert will review the new recordkeeping requirements.  Finally, Babst Calland will survey the remaining Rule topics.

Materials Verification – 49 C.F.R. § 192.607

PHMSA established new materials verification requirements for certain kinds of gas transmission pipelines in response to a mandate in the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (2011 Act).  Operators must create procedures for conducting destructive and nondestructive tests if they do not have traceable, verifiable, and complete (TVC) records for pipeline attributes required by other regulations.  Specifically, materials verification may be triggered by MAOP reconfirmation, integrity management, or repair regulations applicable to onshore gas transmission pipelines in Class 3 or 4 locations or HCAs.

The Rule provides operators with flexibility and allows 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 materials verification rules.

What is in the Rule?

• Procedure. Operators that are missing adequate records for these pipeline attributes must develop and implement procedures for conducting nondestructive or destructive tests, examinations, and assessments to verify material properties of aboveground line pipe, buried line pipe, and components. These tests, examinations, and assessments must be conducted whenever the pipe is exposed for anomaly direct examinations, in situ evaluations, repairs, remediations, maintenance, and excavations that are associated with replacements or relocations of pipeline segments that are removed from service.  An operator’s procedure must address (1) the tests, examinations, and assessments that are appropriate for verifying the necessary material properties and attributes; (2) accepted industry methods for verifying toughness; (3) materials verification of components; and (4) minimum requirements for test locations.  Additional requirements apply to the use of nondestructive methods.
• Sampling Program.  An operator can also verify material properties and attributes by sampling similar locations and applying those results to comparable segments of pipe.  An operator may develop a sampling program in accordance with the requirements established by PHMSA, or may use an alternative approach after seeking a “no objection letter” from PHMSA.  Operators must develop an extended sampling program if test results are not consistent with available information, existing expectations, or assumed properties previously used.
• Components. Operators must develop and implement procedures for establishing and documenting the ANSI rating or pressure rating of certain non-line pipe components greater than two inches that are based on the manufacturing specifications of the components, or material pressure ratings and type if specifications are unknown.
• Recordkeeping.  Operators must maintain TVC records from the materials verification process for the life of the pipeline.
• Compliance Deadlines. PHMSA did not set a deadline for completion of materials verification.  The agency acknowledged that a deadline is not practical since it would be difficult to predict when the pipeline would be exposed.  However, operators may need material properties information to comply with other sections of the code which do impose compliance deadlines.  For instance, it is unclear whether all affected operators would be able to complete materials verification under the opportunistic approach by the MAOP reconfirmation deadline of July 3, 2028.

What is not in the Rule?

The text of the Rule has changed in important ways as a result of public comment, input from the Gas Pipeline Advisory Committee (GPAC) and input from the Office of Management and Budget (OMB).

• Applicability.  PHMSA removed the proposed applicability section and instead made material properties verification a process that operators must follow to obtain missing or inadequate information when  required by another Part 192 regulation.  PHMSA also removed the list of specific pipe attributes to be obtained.  Operators need only obtain  the attributes required for the triggering activity, e.g. MAOP reconfirmation.  PHMSA rejected industry arguments that material properties verification should not be required for pipeline segments tested to 1.25 times MAOP and should only apply to pipeline segments operating above 30 percent SMYS.
• Materials Verification Plan.  PHMSA removed the proposed obligation that all operators create a materials verification plan.
• Alternative and Extended Sampling Programs.  PHMSA changed the sampling program by allowing operators to propose an alternative sampling program and develop an extended sampling program to address inconsistencies between the gathered data and records.  PHMSA declined to remove the excavation standard of one excavation per mile or 150 if the population is greater than 150 miles, whichever is less.  PHMSA reduced the number of required test points for non-destructive tests from four to two quadrants.

MAOP Reconfirmation – 49 C.F.R. § 192.624

Since 1970 operators have established the MAOP of gas transmission lines using either of two methods.  The first method requires MAOP to be based on the lowest of the following four pressures: (1) the design pressure of the pipeline, (2) a percentage of the test pressure the pipeline experienced after construction, (3) the highest actual operating pressure that certain pipelines experienced during a five-year historical window, or (4) the maximum safe operating pressure given the pipeline’s history.  The second method, which is commonly referred to as the grandfather clause, allows MAOP to be based solely on the highest actual operating pressure that pipelines installed before the original effective date of PHMSA’s regulations experienced during a five-year historical window.

In the 2011 Act, Congress directed PHMSA to establish regulations for reconfirming the MAOP of certain higher-risk gas transmission lines.  That mandate was primarily based on NTSB safety recommendations issued in response to the 2010 San Bruno incident.  The Rule prescribes the applicability, methods, compliance deadlines, and recordkeeping requirements for MAOP reconfirmation.

What’s in the Rule?

• Applicability.  The Rule requires operators to reconfirm the MAOP of onshore gas transmission pipelines that meet either of two criteria.  First, MAOP reconfirmation is required if a segment is located in an HCA or Class 3 or 4 location, and the operator does not have TVC records to substantiate the current MAOP.  PHMSA declined to define TVC in the Rule, and referenced the guidance that the Agency provided in advisory bulletins issued in 2011 and 2012.  Second, MAOP reconfirmation is required if a segment is located in an HCA, a Class 3 or 4 location, or an MCA (only if the segment is piggable); the current MAOP exceeds 30 percent of specified minimum yield strength (SMYS); and the operator established that MAOP using the grandfather clause.
• Methods.  The Rule provides gas transmission line operators with six methods for reconfirming the MAOP of covered segments.  First, the operator can perform a pressure test in accordance with subpart J.  The reconfirmed MAOP is established based on the test pressure, divided by 1.25 or the applicable class location factor, whichever is greater.  If the operator lacks TVC records for diameter, wall thickness, of grade the pipe, the operator must obtain the missing information by complying with the new materials verification requirements.  Second, the operator can implement a pressure reduction and base the reconfirmed MAOP on the highest actual operating pressure experienced during the five years preceding October 1, 2019, divided by 1.25 or the applicable class location factor, whichever is greater.  The five-year historical operating pressure must have been sustained for “a cumulative minimum duration of eight hours during a continuous 30-day period” Additional requirements apply to reconfirming MAOP through a pressure reduction in response to a class location change.  Third, the operator can conduct an engineering critical assessment in accordance with the new requirements in 49 C.F.R. § 192.632.  Fourth, the operator can replace the pipe.  Fifth, the operator can implement a pressure reduction for small potential impact radius (PIR) (150 feet or less) pipelines based on the highest actual operating pressure experienced during the five years preceding October 1, 2019, divided by 1.1.  The operator must perform increased patrols and conduct instrumented leakage surveys to reconfirm MAOP under the small PIR method.  Finally, the operator can use an alternative technical evaluation process, provided the operator notifies and receives a no objection letter from PHMSA.
• Compliance Deadlines.  The Rule provides several compliance deadlines for reconfirming the MAOP of covered segments.  Operators must develop MAOP reconfirmation procedures by July 1, 2021, and perform MAOP reconfirmation for at least 50 percent of covered pipeline mileage by July 3, 2028.  Operators must complete MAOP reconfirmation 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.
• Recordkeeping.  The Rule establishes a lifetime recordkeeping requirement for MAOP reconfirmation records, including records of investigations, test, analyses, assessments, repairs, replacements, alterations, and other actions.

What’s Not in the Rule?

As with materials verification, PHMSA made several important changes to the rule based on public comments and input from the GPAC and OMB.

• Grandfather Clause Repeal.  PHMSA chose not repeal the grandfather clause in its entirety.  While requested by certain commenters, the Agency concluded that a complete repeal of the grandfather clause would be impractical due to its applicability to other pipelines, including gathering lines, and significant cost-benefit concerns.
• In-Service Incidents.  PHMSA originally proposed to apply MAOP reconfirmation to pipeline segments that had experienced reportable, in-service incidents.  PHMSA did not include that provision in the Rule, concluding that the casual factors leading to such incidents are already addressed by the integrity management provisions of Part 192.
• Reliable.  The Agency decided to remove the word “reliable” from the proposed TVC standard to maintain consistency with the 2011 and 2012 PHMSA advisory bulletins.
• Low-Stress Lines.  PHMSA decided against applying the reconfirmation requirement to grandfathered pipelines operating below 30 percent SMYS, finding that extending the requirement to such pipelines would not be cost-effective and that such lines present lesser risk to public safety.

For a more detailed assessment and a redline of the Rule, please contact a member of the Pipeline and HazMat Safety practice group.

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PHMSA Publishes Long-Awaited Final Rule for Hazardous Liquid Pipelines

Pipeline Safety Alert 

(by James Curry, Keith Coyle and Brianne Kurdock)

On October 1, 2019, the Pipeline and Hazardous Materials Safety Administration (PHMSA) published a final rule in the Federal Register amending the federal safety standards for hazardous liquids pipelines at 49 C.F.R. Part 195 (84 Fed. Reg. 52260) (Rule).  The publication of the Rule ends a nearly decade-long rulemaking process that began in the wake of a significant pipeline accident in Marshall, Michigan.  A prior version of the Rule, released in the closing days of the Obama administration, was returned to PHMSA for further review pursuant to a White House memorandum issued at the start of the Trump administration.  This version of the Rule reflects changes that PHMSA made after receiving input from the current administration, the most significant of which is the removal of new requirements for performing pipeline repairs. The effective date of the Rule is July 1, 2020.

What’s in the Rule?

The Rule includes the following changes to Part 195:

• Extension of reporting requirements to previously-unregulated gravity lines. Operators of gravity lines must submit annual, accident, and safety-related condition reports to PHMSA.  The accident and safety-related reporting requirements become effective on January 1, 2021, whereas the annual reporting requirement become effective on March 31, 2021.  The Rule contains a narrow exemption from the reporting requirements for low-stress gravity lines that travel no farther than one mile from a facility boundary without crossing any waterways used for commercial navigation.  The requirements to provide immediate notification of certain accidents, to submit information to the National Pipeline Mapping System, and to provide safety data sheets after a release do not apply to gravity lines.
• Extension of reporting requirements to previously-unregulated gathering lines. Operators of previously-unregulated gathering lines must submit annual, accident, and safety-related condition reports to PHMSA.  As with the reporting requirements for gravity lines, the accident and safety-related condition reporting requirements become effective on January 1, 2021, and the annual reporting requirement become effective on March 31, 2021.  The requirements to provide immediate notification of certain accidents, to submit information to the National Pipeline Mapping System, and to provide safety data sheets after a
  release do not apply to previously-unregulated gathering lines.
• 72-hour inspections after extreme weather events.  Operators are required to perform inspections of all pipeline facilities that are potentially affected by  an extreme weather event that has a likelihood of damage to infrastructure by scouring or movement of soil surrounding the pipeline.  Examples of extreme  weather events include tropical storms, hurricanes, floods exceeding river, shoreline, or creek-high water banks, landslides, or earthquakes.  The operator has 72 hours after the cessation of the event (i.e., when the affected area can be safely accessed by personnel and equipment necessary to perform an inspection)  to perform the inspection, unless the operator notifies PHMSA that it is unable to commence inspection due to the unavailability of necessary personnel or equipment.  The inspection method is to be determined by the operator based upon consideration of the nature of the event and characteristics of the pipeline.  Appropriate remedial action must be taken based upon the results of the inspection and may include reducing the operating pressure, repairing or replacing damaged pipeline facilities, or shutting down the pipeline.
• Pipeline assessments for non-IM segments.  Operators of onshore pipeline segments that are piggable and which are not currently subject to integrity management (IM) program requirements must perform integrity assessments at least once every 10 years, including an initial assessment by October 1, 2029.  Integrity assessments must be performed using inline inspection (ILI) tools or, where impracticable based on operational limits, an acceptable alternative technique such as pressure testing, external corrosion direct assessment, or other technology (upon notification to Office of Pipeline Safety).  Qualified personnel must analyze the results within 180 days after the assessment to determine whether a condition exists that could adversely affect safe operation of the pipeline, unless the operator notifies PHMSA that meeting the 180-day is impractical. Conditions that could adversely affect the safe operation of a pipeline must be remediated pursuant to the existing repair criteria in Part 195.
• Leak detection.  All hazardous liquids pipelines, except for offshore gathering lines and regulated onshore gathering lines, must have an effective leak detection system.  The compliance deadline for pipelines constructed on or after October 1, 2019, is October 1, 2020.  The compliance deadline for pipelines constructed prior to October 1, 2019, is October 1, 2024.  In implementing these requirements, operators must perform an evaluation to determine what kinds of systems are necessary to adequately protect the public, property, and the environment.
• Accommodation of ILI tools.  All hazardous liquids 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 the passage of an ILI tool or if the operator determines that it would abandon the pipeline due to the cost of compliance (subject to PHMSA approval).  This requirement does not apply to manifolds, station, tank farm, or storage piping, cross-overs, select offshore piping, other piping for which ILI tools are not commercially available, and for emergencies.
• Incorporation of PIPES Act provisions.  Pursuant to statutory mandates in the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (PIPES Act), operators must provide the Federal On-Scene Coordinator and emergency responders with a safety data sheet associated with spilled hazardous liquids within six hours of notice to the National Response Center.  Operators of underwater hazardous liquid pipeline facilities greater than 150-feet depth within HCAs and which are not offshore must also conduct annual integrity assessments.
• Verification of pipeline segment identification.  Operators must verify the identification of segments in or that could affect HCAs on an annual basis.  Verification does not necessarily require operators to perform a new segment analysis.  Rather, operators must identify the factors used in the original analysis, determine whether any of those factors have changed, and assess whether that change would likely affect the results of the initial identification.
• Updates to IM programs.  Operators must perform additional activities relating to information obtained from its IM program, including integration of information and consideration of any spatial relationships among anomalous information, including, for example, evidence of potential corrosion in an area with foreign pipeline crossings, interference from power lines, or evidence of land movement.

What’s not in the Rule?

The Rule does not include two changes to Part 195 that PHMSA proposed at earlier points in the proceedings:

• Pipeline repair requirements.  Operators will not be required to comply with the new criteria and remediation schedules for performing pipeline repairs. PHMSA will be considering that issue in a separate rulemaking proceeding.
• Engineering critical assessments.  Operators will not be required to perform engineering critical assessments (analytical procedures to determine maximum tolerable flaw sizes in steel pipe to maintain safe operations) in relation to the remediation of certain defects.

What’s next?

Interested parties may petition PHMSA for reconsideration of the Rule by October 31, 2019, or may file a petition in the U.S. Court of Appeals for judicial review by December 29, 2019.

Contact one of the members of Babst Calland’s Pipeline and HazMat Safety team to obtain more information about the implications of PHMSA’s Part 195 Rule or for a redline of the rule.

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