The PIOGA Press
This article is an excerpt of The 2020 Babst Calland Report, which represents the collective legal perspective of Babst Calland’s energy attorneys addressing the most current business and regulatory issues facing the oil and natural gas industry. A full copy of the Report is available by writing info@babstcalland.com.
The momentum to propose and adopt new legislation, regulation, policies and programs to address climate change steadily increased during 2019 and only subsided in early 2020 as the nation struggled to address the COVID-19 pandemic. As described below, the Trump administration continued its regulatory reform, reducing various obligations related to greenhouse gas (GHG) emissions, while state and federal courts continue to evaluate claims against both the government and industry regarding their risks, roles and responsibilities to confront the impacts of climate change.
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EmTech Law Blog
(by Gina Falaschi)
Significant funding will soon be available in California to support the expansion of zero-emission trucks in the heaviest weight class that has previously relied on diesel engine technologies. On August 18, 2020, California will start to parcel out $27 million in funding from the Volkswagen (VW) Environmental Mitigation Trust program to replace higher polluting trucks with zero-emission vehicles.
The VW Environmental Mitigation Trust provides about $423 million for California to mitigate the excess nitrogen oxide emissions caused by VW’s use of emissions defeat devices in certain of its diesel passenger vehicles. The trust is a component of partial settlements with VW and provides earmarked funding opportunities for actions like “scrap and replace” projects for the heavy-duty sector, including on-road freight trucks, transit and shuttle buses, school buses, forklifts and port cargo handling equipment, commercial marine vessels, and freight switcher locomotives. As required by the settlement, California developed a Beneficiary Mitigation Plan that was approved by the trustee in June 2018.
As part of the Beneficiary Mitigation Plan, $90 million was made available for the Zero-Emission Class 8 Freight and Port Drayage Trucks category to replace freight trucks (including drayage), waste haulers, dump trucks, and concrete mixers. The first $27 million installment of the total $90 million has been approved and applications for funding will be available on August 18. Eligible applicants will be awarded funding on a first-come, first-served basis.
To qualify, existing vehicles must be powered by engine built in model years 1992 to 2012, in compliance with all applicable regulations, and scrapped in exchange for a zero-emission replacement vehicle certified or approved by the California Air Resources Board or eligible under the Hybrid and Zero-Emission Truck and Bus Voucher Incentive Project. Applicants must be able prove ownership for at least one year, and the old and new vehicles must operate within California at least 75% of the time. Applicants granted an award must submit annual usage reports for the term of the contract.
Maximum funding will not exceed $200,000 per eligible replacement vehicle and funding is available for both public and private entities. Non-government entities, however, may only receive an incentive up to 75% of the cost of the vehicle, while government-owned vehicles are eligible for 100% of the cost up to the $200,000 cap.
VW Environmental Mitigation Trust funding for this and other projects, in California and in many other states, promotes the development of and investment in cleaner transportation technologies and the infrastructure that supports them. While the total $90 million is simply a drop in the bucket when it comes to meeting California’s goal of phasing out diesel trucks completely by 2045 under its newly passed Advanced Clean Trucks regulation, it is a start.
Tags: Funding, Vehicles, Zero-Emission
Environmental Alert
(by Lisa Bruderly and Ben Clapp)
The U.S. Army Corps of Engineers (Corps) has recently pre-published a proposed rule to issue and modify its Nationwide Permits (NWPs) in a move aimed at clarifying the NWPs and reducing the regulatory burden associated with certain authorized activities. NWPs are issued pursuant to Section 404 of the Clean Water Act and Section 10 of the Rivers and Harbors Act of 1899. They authorize an array of activities that result in a discharge of dredged and fill material into waters of the United States, provided that the activities meet the threshold criteria and fulfill the general and specific conditions of the particular NWP.
Scope of Proposed Rule
The Corps typically reissues the NWPs approximately every five years, with the last publication in 2017, when 52 NWPs were issued. The Corps is proposing to reissue the permits after only three years to incorporate modifications identified in response to Executive Order 13783, which directed federal agencies to review existing regulations that “potentially burden the development or use of domestically produced energy resources.” Nine NWPs were identified as result of this review and are modified in the proposed rule. Modifications generally pertain to changes in thresholds for requiring pre-construction notifications or Corps approvals, elimination of linear foot thresholds for certain NWPs, and expansion of criteria for using certain NWPs.
In addition, five new NWPs are being proposed. The remainder of the existing NWPs are being reissued, without change, to keep all permits on the same five-year cycle.
Proposed Modifications to NWP 12
Of particular interest to the oil and gas industry and utilities is the Corps’ proposal to split NWP 12 (Utility Line Activities) into three NWPs, depending on the type of utility line: oil and gas (NWP 12), electric utilities and telecommunications (Proposed NWP C) and water, sewage and other substances (Proposed NWP D). NWP 12 currently permits eligible discharges of dredged or fill material in connection with the construction, maintenance, repair and removal of utility lines, including oil and gas pipelines, water and sewer pipes, and electric, internet, and cable lines.
If adopted as proposed, NWP 12 would only apply to activities required for the construction, maintenance, repair, and removal of oil and natural gas pipelines and associated facilities in waters of the United States, provided the activity does not result in the loss of greater than 1/2-acre of waters of the United States for each single and complete project.
While the proposed rule does not modify the maximum allowable amount of disturbance to waters of the United States, the proposal would narrow the criteria for requiring a NWP 12 pre-construction notification (PCN) to the Corps to the following three circumstances: (1) a Section 10 permit is required (existing criteria), (2) the discharge will result in the loss of greater than 1/10 of an acre of waters of the United States (existing criteria) or (3) the pipeline activity is associated with an overall project that is greater than 250 miles in length and has the purpose to install new pipeline along the majority of the overall length (new criteria).
The Current Status of Nationwide Permit 12
Oil and gas pipeline permitting under NWP 12 has come under significant scrutiny since mid-April, when, as described in a prior Alert, a Montana district court judge, hearing a challenge to the Keystone XL Pipeline, appeared to vacate NWP 12 in its entirety across the United States and later clarified that the intent to vacate NWP 12 was intended to apply to the construction of only new oil and gas pipelines. Both of these decisions were based on the judge’s determination that the Corps failed to comply with the Endangered Species Act (ESA) when NWP 12 was last issued in 2017. On July 6th, the Supreme Court limited the scope of the district court’s vacatur solely to the construction of the Keystone XL Pipeline pending an appeal of the district court’s decision to the Ninth Circuit. This decision allowed pipeline developers to return to utilizing NWP 12 for new oil and gas pipeline projects throughout the United States while the litigation is ongoing, or until the Corps addresses the ESA issues identified by the district court. The Corp’s proposed modifications to NWP 12 do not address the ESA concerns that are at issue in the Keystone XL Pipeline challenge, and are therefore not expected to have an impact on the ongoing litigation.
Next Steps
The proposed NWPs are expected to be published in the Federal Register in a few weeks. The Corps has invited comment on these proposed modifications and specifically has asked for suggestions for national standards or best management practices for oil and natural gas pipeline activities that would be appropriate to add to NWP 12. Comments are due 60 days from publication of the proposed rule in the Federal Register.
We note that, in addition to proposed revisions to the NWPs that would be imposed for regulated activities across the United States, the Corps’ Districts may still impose specific region/state conditions and states may impose 401 Water Quality Certification special conditions that could require a PCN or other more stringent requirements.
Babst Calland’s environmental attorneys have substantial experience with Clean Water Act Section 404/River and Harbors Act Section 10 permitting. If you have questions about this proposed rule or Section 404 permitting in general, please contact Lisa Bruderly at (724) 910-1117 or lbruderly@babstcalland.com, or Ben Clapp at (202) 853-3455 or bclapp@babstcalland.com.
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Environmental Alert
(by Kip Power and Varun Shekhar)
Appalachian oil and gas operators were recently reminded that proper handling, management, disposal and transportation of technologically enhanced naturally occurring radioactive material (TENORM) wastes that are generated in connection with shale gas production activities remain the focus of significant regulatory and enforcement efforts.
W.Va. DHHR TENORM Regulation. On the regulatory side, the West Virginia Department of Health and Human Resources, Bureau of Public Health (DHHR), an agency primarily involved with protecting the public and employees from radiological health risks associated with the healthcare industry, recently released proposed revisions to its legislative rule, “Radiological Health,” 64 W. Va. C.S.R. 23 (Proposed Rule). The Proposed Rule includes an entirely new Section 16, entitled “Radiation Safety Requirements for Technologically Enhanced Naturally Occurring Radioactive Material.”
In some respects, DHHR’s proposal follows the recommendations in Part N (2014) of the Conference of Radiation Control Program Directors, Inc.’s (CRCPD) “Suggested State Regulations for Control of Radiation.” However, it also varies from the CRCPD recommendations in ways that may prove troublesome, such as the inclusion of inconsistent levels of risk-based exposure limits (allowing a total effective dose equivalent of 100 mrem/year for a maximally exposed individual in one provision but limiting exposure to 50 mrem/year and 25 mrem/year in other parts). Of equal concern, the Proposed Rule appears to exceed DHHR’s legislative mandate and allows for regulation of activities in a manner that is duplicative of existing rules administered by the West Virginia Department of Environmental Protection.
The West Virginia Oil and Natural Gas Association and the Independent Oil and Gas Association of West Virginia recently filed detailed joint comments expressing these and other concerns about this proposed new TENORM regulation. The comment period on the Proposed Rule closed on August 5, 2020. The DHHR will now prepare responses to all comments received and the Proposed Rule (or if deemed necessary, a revised version of the proposal) will be filed with the Secretary of State as the agency’s final recommended rule for consideration by the Legislature’s Rulemaking Review Committee.
Federal Grand Jury Indictment. DHHR’s Proposed Rule comes in the wake of a federal grand jury’s 27-count criminal indictment of Cory David Hoskins, the owner of a Kentucky-based TENORM transport and disposal company, which transported sludge from an oil and gas brine processing plant in West Virginia to Kentucky for solidification and disposal in 2015. In particular, the indictment alleges that Hoskins and his company, Advanced TENORM Services, LLC, made false representations to the brine processing company, Fairmont Brine Processing, LLC, in representing his expertise and its DOT-compliant method of transport and disposal of the TENORM waste material. Rather, Hoskins and his company are alleged to have known that the TENORM material qualified as a Class 7 hazardous material under the DOT’s Hazardous Materials Regulations (HMR), but intentionally did not transport the TENORM material in compliance with the HMR’s requirements for Class 7 materials (including using truck drivers who were not authorized to transport hazardous materials, and using improper placarding, marking, labeling, shipping papers, and manifests.) The United States seeks a penalty of imprisonment of up to 20 years, a fine of not more than $250,000, and forfeiture of more than $127,000.
The indictment and significant sanctions sought demonstrate the importance of understanding the applicable restrictions and regulations on handling, processing, and disposal of TENORM, as well as the need for generators of such wastes to perform appropriate inquiry and due diligence into the disposal contractors they select.
Babst Calland attorneys are prepared to assist your company in navigating these complex regulations. Should your company have questions about DHHR’s Proposed Rule or TENORM regulation in general, please contact Christopher B. (“Kip”) Power at (681) 265-1362 or cpower@babstcalland.com or Varun Shekhar at (202) 975-1390 or vshekhar@babstcalland.com.
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Environmental Alert
(by Robert Stonestreet)
On August 5, 2020, the United States Fish and Wildlife Service (Service) published a proposed regulation in the Federal Register to define the term “habitat” for purposes of the Endangered Species Act (ESA). 85 FR 47333. The ESA already defines the term “critical habitat,” which in general means areas designated as essential to preserve or promote recovery of threatened or endangered species regardless of whether those species are actually present in the area. The term “habitat,” however, is not itself defined in the ESA or existing regulations. The Service has been involved in years of litigation over efforts to designate as “critical habitat” certain areas where the listed species do not presently exist and could not survive under current conditions. This proposed definition of “habitat” follows a ruling by the United States Supreme Court that an area must first qualify as “habitat” for a listed species in order for the area to be designated as “critical habitat.” Weyerhaeuser Co. v. United States Fish and Wildlife Service, 139 S. Ct. 361 (2018).
The Service proposes to define “habitat” as follows:
The physical places that individuals of a species depend upon to carry out one or more life processes. Habitat includes areas with existing attributes that have the capacity to support individuals of the species. (emphasis added)
The Service also requests comments on the following alternative definition of “habitat”:
The physical places that individuals of a species use to carry out one or more life processes. Habitat includes areas where individuals of the species do not presently exist but have the capacity to support such individuals, only where the necessary attributes to support the species presently exist. (emphasis added)
Both of these regulatory definitions would narrow the scope of “critical habitat” designations from how the Service has previously interpreted that term. For example, Weyerhaeuser addressed a rulemaking by the Service that designated as “critical habitat” areas where the listed species at issue once lived, but could not survive under present conditions unless changes were made to certain physical features. The owner of the land designated as “critical habitat” challenged that designation as exceeding the scope of the ESA. Under either of the proposed definitions, areas where a listed species could not presently survive would not seem to qualify as “habitat,” and thus could not be designated as “critical habitat.”
Comments on the proposed regulation are due by September 4, 2020 and may be submitted at www.regulations.gov under Docket No. FWS-HQ-ES-2020-0047.
If you have any questions about the proposed regulation, or the Endangered Species Act in general, please contact Robert M. Stonestreet at rstonestreet@babstcalland.com or 681.265.1364.
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Environmental Alert
(by Donald Bluedorn, Gary Steinbauer and Casey Snyder)
On July 29, 2020, United States Environmental Protection Agency (EPA) Administrator Andrew Wheeler signed a pre-publication version of a final rule (the Rule) revising portions of EPA’s 2015 coal combustion residuals (CCR) landfill and impoundment regulations. The Rule becomes final 30 days after publication in the Federal Register.
In 2015, EPA promulgated regulations implementing national minimum criteria for new and existing CCR landfills and surface impoundments. A federal appellate court partially vacated and remanded portions of these regulations on August 21, 2018 (the court’s decision is covered in more detail in our prior Alert). Following the court’s decision, EPA published proposed rules in the Federal Register on December 2, 2019 and August 14, 2019, to address the court’s remand order and make other changes (the Proposed Rules).
The Rule includes the following key changes for CCR units:
- Reclassifies compacted-soil lined or “clay-lined” surface impoundments to “unlined,” meaning these structures must be retrofitted or closed;
- Establishes a revised date, April 11, 2021, by which CCR units must cease receiving waste and initiate closure or retrofit because: (1) they are unlined or were formerly “clay-lined” CCR surface impoundments; or (2) they failed the minimum depth to aquifer location standard;
- Revises the alternative closure provisions that would grant certain facilities additional time to develop alternative capacity to manage their CCR and non-CCR waste streams;
- Updates the annual groundwater monitoring and corrective action report requirements to make the data easier to understand for public review, including adding an executive summary requirement; and
- Revises the CCR website requirements to ensure that relevant facility information required by the regulations is immediately available to the public.
As compared with the deadlines in the December 2, 2019 proposed rule, the Rule gives the regulated community additional time to use and for seeking a site-specific alternative for initiating closure of certain CCR surface impoundments. The amended deadlines are summarized in Table 1 of the Rule’s preamble and are found below.
- As discussed above, the new deadline to cease receipt of waste and initiate closure for surface impoundments that failed the minimum depth to aquifer location standard and unlined (now including clay-lined) surface impoundments, is April 11, 2021 (previously, August 31, 2020 in the December 2, 2019 proposed rule).
- The closure initiation deadlines under the site-specific alternative due to lack of capacity is no later than October 15, 2023 (the same as the December 2, 2019 proposed rule) and October 15, 2024 for eligible unlined CCR surface impoundments (previously, October 15, 2023 in the December 2, 2019 proposed rule).
- The deadline for site-specific alternative to initiate closure due to permanent cessation of a coal-fired boiler(s) by a date certain is October 17, 2023 for CCR surface impoundments 40 acres or smaller, or October 17, 2028 for surface impoundments larger than 40 acres (no change from the December 2, 2019 proposed rule).
The extended timelines for initiating closure of existing unlined CCR surface impoundments and those that do not meet the minimum depth to aquifer location requirements provide the regulated community some breathing room until April 2021 to prepare for initiating closure. Affected facilities without adequate alternative on- or off-site disposal capacity, however, will need to move quickly to continue using eligible CCR surface impoundments. The Rule imposes a November 30, 2020 deadline to submit extensive documentation for an alternative closure demonstration.
Legal challenges to the Rule are inevitable. The Sierra Club has already vowed to challenge the Rule, and other environmental groups may follow suit. State attorneys general, industry, or others could join the litigation fray. All eyes will be on the courts to see whether litigation impacts the Rule’s deadlines. In the meantime, facilities with affected CCR surface impoundments now know when they need to initiate closure or seek a site-specific alternative closure initiation deadline.
If you have any questions about the Rule and its implications, please contact Donald C. Bluedorn II at (412) 394-5450 or dbluedorn@babstcalland.com, Gary E. Steinbauer at (412) 394-6590 or gsteinbauer@babstcalland.com, or Casey J. Snyder at (412) 394-5438 or csnyder@babstcalland.com.
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The Legal Intelligencer
(by Julie Domike and Gina Falaschi)
The transportation sector is the nation’s largest source of greenhouse gas emissions. To reduce these emissions, cleaner transportation initiatives are on the rise nationwide, with new state programs being announced almost daily. While California has always been in the forefront of these enterprises, other states, including Pennsylvania, are not far behind. This is especially true of the new clean transportation initiatives for the medium- and heavy-duty vehicle market, which produces 25% of the transportation sector emission but only represents 4% of the vehicles on the road.
At a public hearing on June 25, the California Air Resources Board adopted a long-awaited Advanced Clean Trucks Regulation. California Air Resources Board, Notice of Decision (June 25, 2020). This program builds on California’s 2012 Advanced Clean Cars Regulation to further reduce emissions from the transportation sector by requiring truck manufacturers to sell a certain percentage of zero-emission vehicles beginning in model year 2024. The percentage will increase annually, meeting the ultimate goal of phasing out new diesel trucks by 2045.
The federal Clean Air Act affords California the ability to pass historic initiatives and to be at the forefront of setting new, more stringent, environmental standards. While Section 209 of the federal Clean Air Act generally preempts state and local emission standards for new motor vehicles, there are a few exceptions. See 42 U.S.C. Section 7543(a). The EPA can waive preemption for any state that had adopted standards for control of emissions from new motor vehicles or new motor vehicle engines prior to March 30, 1966. The only state that qualifies to receive such waivers is California, the only state to have adopted motor vehicle emission standards prior to March 1966.
Additionally, under Section 177 of the Clean Air Act, states that have EPA-approved plans to attain the national ambient air quality standards may adopt and enforce California’s emissions control standards for new motor vehicle and motor vehicle engines if the standards are identical to California’s standards and the state adopting the standards gives industry at least two years advance notice of their applicability. To date, 13 states—Colorado, Connecticut, Delaware, Maine, Maryland, Massachusetts, New Jersey, New York, Oregon, Pennsylvania, Rhode Island, Vermont, and Washington—and the District of Columbia have adopted some or all of California’s motor vehicle and engines standards under Section 177 (Section 177 states). Several more states have announced their intention to adopt them.
So, while California is the first to adopt an electrification requirement for medium and heavy-duty trucks, because other states can adopt California’s standards under Section 177, many states are not far behind in considering adopting Advanced Clean Trucks in their own states.
In July, Pennsylvania Gov. Tom Wolf joined the governors of 14 other states (California, Connecticut, Colorado, Hawaii, Maine, Maryland, Massachusetts, New Jersey, New York, North Carolina, Oregon, Rhode Island, Vermont, and Washington) and the mayor of the District of Columbia in signing the multi-state medium- and heavy-duty zero emission vehicle memorandum of understanding (MOU). Available at https://www.nescaum.org/. This MOU commits the signatories to collaboratively foster a market for zero emission trucks, vans, and buses through the Multi-State ZEV Task Force, an existing program created by some Section 177 states to coordinate action to ensure the successful implementation of their state zero-emission vehicle (ZEV) programs. Within six months of the signing of the MOU, the task force will develop an action plan to consider funding, infrastructure, regulatory, data collection and other needs. As part of that action plan, the task force will consider the benefits associated with the adoption of California’s Advanced Clean Trucks rule under Section 177 of the Clean Air Act. The plan does not, however, commit the signatory states to adopt the Advanced Clean Trucks Rule.
In fact, under the MOU, the signatory states will strive to have all new medium- and heavy-duty vehicles purchased to be zero emission vehicles by 2050, five years later than the Advanced Clean Truck target. The signatory states will also focus on deploying zero emission trucks and buses to disadvantaged communities historically burdened with higher air pollution levels, and on working towards electrification of government and quasi-governmental agency fleets.
These initiatives will have substantial and beneficial environmental impacts in Pennsylvania and the other signatory states over the next three decades. There will be, necessarily, potentially significant growing pains associated with a dramatic shift in the industry long dependent on engines powered by diesel fuel. Instead, industry must scramble to adapt to electric or hydrogen fuel cell powered engines with their accompanying demand for new infrastructure and increased initial costs.
New charging infrastructure will be needed to support these medium- and heavy-duty vans, trucks and buses not only in Pennsylvania but throughout the signatory states, many of which are clustered in the Mid-Atlantic and Northeast. This will require coordination similar to that in The West Coast Clean Transit Corridor Initiative, a recent study commissioned by nine electric utilities and two agencies representing municipal utilities in California, Oregon and Washington. West Coast Clean Transit Corridor Initiative (June 2020), https://westcoastcleantransit.com/. The study provides a roadmap for states and public utilities to add electric vehicle charging for freight haulers and delivery trucks along Interstate 5 and adjoining highways to support the growth of the electric truck market. It contains recommendations regarding funding, locating charging stations, and capacity development. The phased approach suggested in the study would first involve installing 27 charging sites along the interstate at 50-mile intervals for medium duty-vehicles by 2025, and then expanding 14 of the 27 stations to accommodate electric big rig charging by 2030. Utilities will need to commission a similar study to support the development of infrastructure for an electric truck market in the Mid-Atlantic and Northeastern states.
In addition to the need for an expanded infrastructure, there will also be growing pains for the purchasers of medium- and heavy-duty vehicle fleets, especially small businesses and fleet owners. The initial cost of electric medium- and heavy-duty vehicles is anticipated to exceed that of today’s diesel-powered trucks and buses, though the cost differential likely will diminish over time as battery production ramps up and battery costs decrease. This increased cost could, however, prove to be too much for competitive industries struggling with tiny profit margins. The higher costs of vehicles will likely be passed on by fleet owners to those using their hauling services; ultimately, consumers may see increased costs of goods.
While the actual increase in cost can be disputed, what is not in dispute is that the cost of new trucks and the new infrastructure necessary to support them will be considerable. It remains to be seen whether and how the signatory states will jointly fund initiatives for widespread charging capabilities to be made available where buses and trucks need them. State funding will be critical to support the adoption of electric medium- and heavy-duty vehicles at the rapid rate at which these initiatives expect to fully replace diesel. Whether this adoption rate is possible without significant funding and incentives remains to be seen.
Julie R. Domike and Gina N. Falaschi are attorneys at Babst Calland Clements & Zomnir. Their practice focuses on regulatory issues arising under the Clean Air Act. They represent a variety of companies that have been the focus of the EPA’s regulations, including refineries, engine manufacturers, independent power producers, chemical plants, fuel producers, and construction and farm equipment makers. Contact Domike at 202-853-3453 or jdomike@babstcalland.com or Falaschi at 202-853-3483 or gfalaschi@babstcalland.com.
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Reprinted with permission from the July 30, 2020 edition of The Legal Intelligencer© 2020 ALM Media Properties, LLC. All rights reserved.
Pipeline Safety Alert
(by James Curry and Boyd Stephenson)
On July 24, 2020, the Pipeline and Hazardous Materials Safety Administration (PHMSA or the Agency) published a Final Rule (Rule) in the Federal Register allowing railroads to transport liquefied natural gas (LNG) in modified DOT-113C120W (DOT-113) railcars designed to hold cryogenic flammable liquids. The rule was prompted by a 2017 Association of American Railroads (AAR) rulemaking petition to allow LNG transport by rail and Executive Order 13868, directing PHMSA to conduct a rulemaking allowing LNG to travel by rail tank car. In developing the Rule, PHMSA relied on safety data from other cryogenic flammable liquid shipments and from an existing special permit that already allows limited transportation of LNG by rail to demonstrate LNG could safely be transported. The Rule follows PHMSA’s October 24, 2019, Notice of Proposed Rulemaking (NPRM). It takes effect on August 24, 2020, and PHMSA is allowing immediate voluntary compliance.
The rulemaking attracted significant attention from industry eager to meet increased natural gas demand, safety organizations such as the National Transportation Safety Board that raised concerns about transporting LNG, and from environmental groups. Numerous media reports on the Executive Order also increased public attention. Over 450 individuals and organizations submitted comments on the NPRM. In the NPRM and in the Rule, PHMSA noted that it lacks data about how many LNG rail shipments are likely to occur under the new rules. Currently, cryogenic flammable gases are transported rarely by railcar, but most commenters expect LNG rail shipments to quickly outstrip shipments of other cryogenic flammable gases.
Previously, LNG could only be transported by rail tank car with a special permit, or in smaller, portable tanks loaded onto a railcar. However, other cryogenic liquids that that pose risks similar to LNG, such as ethylene and hydrogen, can be transported on DOT-113 railcars under the current Hazardous Materials Regulations. In the NPRM, PHMSA proposed allowing railroads to transport LNG on DOT-113 rail tank cars, and sought comment on additional design requirements and other safety measures the Agency should consider. In response to public comments, the Rule allows LNG to be transported in DOT-113 tank cars that meet additional design requirements, indicated by adding a “9” at the end of the DOT-113C120W Standard name. This will differentiate LNG railcars from existing DOT-113 railcars. The Rule also requires railroads and entities offering LNG to implement additional operational controls over LNG shipments.
What Did PHMSA Change in the Final Rule?
PHMSA is allowing LNG shipment by rail tank car, subject to additional design requirements for DOT-113 railcars:
- LNG may be transported by rail in DOT-113 railcars, provided that they meet the following additional design requirements:
- The outer shell must be made of AAR TC 128, Grade B normalized steel plate, previously required only for railcars transporting hazmat that presents poisonous inhalation hazards and toxic inhalation hazards.
- The outer steel jacket thickness is increased from 7/16 inches to 9/16 inches and the outer jacket head thickness is increased from1/2 inch to 9/16 inches.
- PHMSA is designating this enhanced standard as DOT-113C120W9 and requiring railcars that meet it to be marked to distinguish them from DOT-113 railcars designed to transport other cryogenic flammable liquids.
- Railcars transporting LNG must meet the following railcar design and loading requirements:
- A start-to-discharge pressure valve setting of 75 psig
- A design service temperature of -260° F
- A maximum pressure when offered for transportation of 15 psig
- A filling density of 37.3% by weight, increased from 32.5% in the NPRM
- PHMSA is allowing DOT-113 railcars carrying LNG to be loaded up to a gross weight of 286,000 lbs., with approval from the Federal Railroad Administration (FRA), because an unladen railcar meeting the enhanced DOT-113 standard will weigh at least 138,050 lbs.
The Final Rule also imposes additional operational controls on LNG shippers and railroads:
- Shippers must remotely track and monitor railcars transporting LNG for pressure and location and inform the railroad if tank pressure rise exceeds 2 psig in a 24-hour period. Shippers must also notify the FRA if an LNG railcar does not reach its destination within 20 days.
- In the NPRM, PHMSA considered incorporating two AAR operating standards for hazmat trains by reference, OT-55 and HM-1. PHMSA chose not to, so that railroads would have the option to adopt operational practices that exceed those standards. FRA tracks railroad voluntary compliance with these standards, and PHMSA indicated it would reverse course if FRA finds railroads are not operating in accordance with these standards or exceeding them.
- Before a railroad may transport LNG, it must perform a routing analysis considering 27 safety and security risk factors listed in 49 C.F.R. Part 172, Appendix D. After the routing analysis is complete, railroads must comply with the safety and security plan requirements and commodity flow data gathering requirements currently required for High-Hazard Flammable Trains (HHFT).
- A train with a block of 20 or more LNG tank cars, or 35 or more total LNG tank cars, must be equipped with an end of train device or a distributed power system to facilitate faster breaking, as is required for HHFTs.
Commentary
- The Hazardous Materials Regulations prescribe requirements for separation between railcars carrying hazmat based on the type of hazmat carried, whether a car is occupied by a crewperson, the distance from the locomotive or other power unit, and other factors. Several commenters proposed that PHMSA should adopt more stringent railcar separation requirements for LNG shipments. PHMSA declined to do so, and cited several ongoing research projects into hazardous materials railcar separation safety. PHMSA indicated it might impose more restrictive separation requirements for LNG if that research demonstrates a safety benefit in doing so. In the Rule, PHMSA also noted that it lacks an effective method for estimating the number of LNG railcars that may be loaded onto a train. PHMSA stated that the number of railcars could also affect potential future separation requirement changes.
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Smart Business
(by Sue Ostrowski with Boyd Stephenson)
The rules of international investment in U.S. real estate have changed, and failure to understand these new rules — issued by the Committee on Foreign Investments in the United States (CFIUS) in February — could cause huge headaches.
“If you’re not aware of or don’t understand the rules, that could cause a real estate deal to be undone by CFIUS, potentially resulting in financial harm or making a business liable to a foreign entity,” says Boyd A. Stephenson, an attorney at Babst Calland.
The president has the authority to reverse certain business transactions involving a foreign entity if it is determined they pose a national security risk. CFIUS advises the president on when to do that. In February 2020, that authority was extended to real estate ownership.
Smart Business spoke with Stephenson about the impact of the new rules.
What is CFIUS, and how does it work?
CFIUS is an interagency committee of the federal government that advises the president about mergers and acquisitions, financings, and real estate transactions that involve foreign actors. If a foreign entity wants to invest in or buy a cardboard box manufacturer, it’s generally not a concern. But if it wants to invest in a U.S. startup that’s developing technology with better AI, such an investment would result in a review from CFIUS to determine whether the deal should be cancelled based on national security concerns. This authority is retroactive, so if your deal consummates on April 15 and the transaction is reversed on May 1, you lose that equity stake.
How does the new rule extend into real estate transactions?
The new rule applies to real estate acquisitions that are a certain distance from an airport or seaport, or, for a military installation, up to being within the same county. You need to be aware of the rules, because if you are selling property to a foreign entity, you want to make sure that transaction can be completed. The last thing you want is to go through the negotiating process and have a transaction called back because of a ruling by CFIUS.
For most transactions, companies can submit a five-page declaration with the government, identifying who they are and who the foreign investor is and describing terms of the deal. CFIUS will either say it’s good to go, or it’s not happening, or initiate a notice process, which is a significantly longer filing for transactions that attract scrutiny. Transactions that involve an entity from Canada, Australia or the United Kingdom are exempted from this rule.
What are the dangers of being unaware of the new rule?
The worst-case scenario would be to close a sale of real estate to a foreign entity, only to find out later that the transaction fell within the scope of the rules and should have been reviewed, then have the government force you, as the seller, to undo the transaction. The risks and potential liability to the seller, both from having to walk back the sale and potential claims by the foreign investor buyer, are substantial.
From the perspective of the seller, it can be dangerous to sell to a foreign entity without a thorough review of the CFIUS rules to determine if they apply, and if there is any question, a review and recommendation by the committee. It is a good idea to address the potential outcomes of a CFIUS ruling in your real estate sales agreement to protect both parties.
How do you know if your transaction with a foreign entity requires review?
At a minimum, any transaction involving a foreign investor should include an analysis by legal counsel of the risks and applicability of the rules. For CFIUS review, even an American buyer with a minor stake held by a foreign entity could be treated as a foreign entity. The good news is that the transactions likely to attract scrutiny are pretty common sense. If you are a box company, it’s probably not an issue, unless you are located next to a military installation. But if you are a cutting-edge data processing firm, doing AI, lasers or technology, you should be aware of the rules. If not, this is an area where ignorance could really come back and bite you.
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Babst Calland is a member of the Solar Energy Industries Association (SEIA). A national trade association within the electric power industry, SEIA facilitates education, research, standards and collaboration with utilities, solution providers, and other energy industry leaders.
The PIOGA Press
This article is an excerpt of The 2020 Babst Calland Report, which represents the collective legal perspective of Babst Calland’s energy attorneys addressing the most current business and regulatory issues facing the oil and natural gas industry. A full copy of the Report is available by writing info@babstcalland.com.
Increasing industry headwinds have resulted in a slowdown of new permitting activity and an increase in ordinance restrictions on oil and gas development. Substantive validity challenges to zoning ordinances seeking to limit development to industrial areas have continued despite Pennsylvania Commonwealth Court’s clear pronouncements that local considerations control legislative decisions as to the location of development. Pennsylvania courts have also dealt with issues such as the legal standing and the timing of ordinance challenges.
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Breaking Ground
(by Marc Felezzola)
The COVID-19 pandemic has resulted in a “new normal” that was likely not accounted for in pricing and scheduling for projects awarded prior to the pandemic (“existing projects”). As owners and contractors move forward with new projects in a post-pandemic world, there is incredible uncertainty to what extent COVID-19-related requirements will impact future projects (“Future Projects”). This article addresses some of the major risks that owners and contractors face on both existing projects and future projects.
Existing Projects
A. Impacts
The forced COVID-19 shutdown and subsequent resumption of existing projects will likely result in costs to contractors for demobilization and remobilization, downtime/standby, possible material and labor escalation costs, and extended general conditions (“primary impacts”). These primary impacts typically arise with every suspension or delay to a project and are not unique to COVID-19 forced stoppages. Whether and to what extent these costs are recoverable by contractors depends on the terms of the applicable contract, and in particular its force majeure language. However, because a force majeure event is by definition an event not caused by the owner or contractor, the parties typically bear their own costs associated with the delay caused by the force majeure event. The contractor cannot recover its delay/suspension costs but does get a schedule extension; and the owner cannot recover any costs it incurs as a result of the delay. If nothing else, the contractor will almost certainly be entitled to a change order extending the project schedule for at least the length of the forced shutdown.
Beyond the primary impacts are the costs and schedule impacts associated with resuming work under drastically different circumstances. These impacts range from new social distancing requirements and correlating prohibitions (e.g., limiting use of an elevator at the job site to one worker at a time; prohibitions on sharing equipment) and potential manpower caps (e.g., limits on workers allowed in enclosed portions of a job site in counties that remain in the red or yellow phase; government imposed limits on gathering sizes) to added direct job costs for handwashing stations, thermal scanners, and additional sanitization and personal protection equipment (“secondary impacts”). The aggregate result of these secondary impacts will be a reduction in efficiency, a forced change to contractors’ as-planned means and methods, and an increase in contractors’ direct job costs, all of which will result in a contractor seeking a change order for additional costs, additional time, or both.
On top of the primary and secondary impacts are indirect jobsite impacts in the form of material and equipment supply chain disruptions due to factory and manufacturing facility shutdowns or slowdowns, potential workforce shortages due to pandemic-related illness or concerns, and corresponding increases in materials, equipment, and labor prices (collectively, “tertiary impacts”). Some of these tertiary impacts will not be fully realized immediately, and each will further magnify the schedule impacts and additional costs discussed above.
At the same time, the post-pandemic world will look very different for owners. Certain projects previously fast-tracked as guaranteed revenue generators may lose their luster (e.g., movie theaters, certain restaurant projects, and some energy-related projects) prompting owners to voluntarily suspend the project even though construction may resume, or even terminating the project for convenience. For other projects, owners will want to consider whether to pay for acceleration measures to recover the time lost to the forced shutdown, or at least maintain the as-planned durations for construction work and limit any delay in completion to the time of the forced shutdown (i.e., pay for acceleration efforts necessary to offset schedule impacts of secondary and tertiary impacts). Social distancing requirements, potential manpower caps, and uncertainties surrounding available workforce members may hinder acceleration efforts; at the very least, it will likely make them more difficult and expensive than they would have been pre-pandemic.
Moreover, there remains significant potential for the forced shutdown of a particular project due to a potential or confirmed COVID-19 case at the jobsite. Similarly, the potential for another industry-wide shutdown looms with the threatened resurgence of the coronavirus in the fall. On the other hand, as the number of new COVID-19 cases continue to drop and restrictions are eased, contractors may begin to return to more and more pre-pandemic efficiencies and practices. Needless to say, the path forward remains uncertain.
B. Steps Owners and Contractors Can Take to Mitigate Impacts and Future Risks
What steps can owners and contractors take to address the above impacts and mitigate against future risks for existing projects?
Project owners, contractors, and all major subcontractors should meet to discuss the “new normal” of the post-pandemic landscape and reset project expectations. During this meeting, the parties should establish new safety protocols and procedures that comply with all relevant OSHA, CDC, state, and local governmental mandates. The Construction Industry Safety Coalition published a model COVID-19 Exposure Prevention, Preparedness, and Response Plan for Construction (available here: http://www.buildingsafely.org/wp-content/uploads/2020/04/CISC-COVID-19-Exposure-PreventionPreparedness-and-Response-PlanVersion-2-4838-8641-5802-3.docx) that may serve as a good starting point. The parties should also establish a new, workable construction schedule in light of the currently known circumstances and impacts. The parties could also consider what, if any, equitable price adjustment(s) they agree upon to address the secondary and tertiary impacts to contractors along with any owner-desired acceleration efforts the owner wants. As part of the equitable adjustment discussion, contractors and subcontractors should be prepared to discuss any mitigation efforts (and associated costs) available to overcome disruptions to supply chains, including alternative sourcing for key equipment to alleviate or overcome any delivery delays due to pandemic-related factory closures. Finally, the parties should consider establishing a contingency to account for potential future shutdowns and a plan for how to share savings, if any, realized by continued loosening of pandemic-related limitations.
Although collaboration and agreement on equitable adjustments will likely result in a more harmonious project, we anticipate some owners (and contractors with respect to their subcontractors) will cite no damage for delay language and force majeure language in their contracts to refuse price adjustments as a result of schedule impacts resulting from the pandemic. Contractors and subcontractors will respond by pointing to differing site conditions language, change in law clauses (to the extent their contracts have them), or other contract provisions entitling them to equitable price adjustments. In the event the parties do not agree about whether an equitable adjustment in price is warranted (or cannot agree on the amount of adjustment), contractors and subcontractors should strictly comply with any claims notice provisions in their contracts and keep track of all additional expenses, including expenses due to loss of efficiency or changes to as-planned means and methods, using a force account.
The outcome of disputes over the propriety and amount of equitable price adjustments will ultimately turn on a number of factors, including the relevant contract language. However, owners and contractors should expect judges, juries, and arbitrators to be sympathetic that contractors’ and subcontractors’ pricing did not contemplate and account for COVID-19 impacts and it may be unfair to saddle them with those costs when they are incurred for the benefit of constructing the owner’s project. Thus, owners should expect courts, juries, and arbitrators to look for ways to provide at least some price relief to contractors and subcontractors even in situations where the owners have the most stringent contract language in their favor.
Future Projects
Parties to contracts for future projects will no longer be able to claim that they could not expect or foresee pandemic-related impacts. Beyond that, the impact of COVID-19 on future projects remains uncertain. Will new cases of COVID-19 continue to drop? Is a vaccine or therapeutic treatment on the horizon that would enable an even more accelerated return to the status quo? Will loosening of restrictions and cooler temperatures result in a “second wave” of infections?
Because of these uncertainties, in addition to agreeing upon safety protocols and procedures for addressing COVID-19 risks and potential exposure at the jobsite, parties negotiating construction contracts should include a pandemic contingency specifically earmarked for addressing and covering unanticipated costs due to pandemic-related causes. The parties can negotiate language to address how and when the contingency monies are to be distributed; how to distribute any unspent contingency monies (i.e., “savings”); and whether, and to what extent, the owner is obligated for pandemic-related costs over and above the contingency amount. This can also be considered a learning experience to highlight that “force majeure” clauses should be considered carefully and drafted to reflect the true intent of the parties.
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Emerging Technologies in a Time of Pandemic
(by Ben Clapp, Julie Domike, Gina Falaschi, Justine Kasznica and Boyd Stephenson)
COVID-19 restrictions are both easing and tightening in cities around the country, and a nationwide return to work seems further off than it did a month ago. But it is never too early to plan ahead. As the United States looks to safely return to work, offices are preparing for a radical shift, accelerating a need for emerging technologies to address challenges in the workplace. Separation, space, health, and cleanliness concerns are paramount, in an abrupt about-face from the pre-virus trends towards flexible workspaces and open floor plans. This has created a host of novel issues for business administrators, who are leveraging technology to keep work environments safe while maintaining a semblance of business normalcy in these unprecedented times.
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RMMLF Water Law Newsletter
(By Lisa M. Bruderly)
On September 4, 2020, the U.S. Army Corps of Engineers (Corps) published, for 30-day public comment, draft Pennsylvania State Programmatic General Permit 6 (PASPGP-6). See Corps, Special Pub. Notice SPN 20-57 (Sept. 4, 2020). The public notice was jointly issued by the Corps’ Baltimore, Philadelphia, and Pittsburgh Districts. PASPGP-6 would replace the current PASPGP-5, which was issued on July 1, 2016, and will expire on July 5, 2021, unless suspended or revoked prior to that date.
PASPGP-6 would be issued under section 404(e) of the Clean Water Act, 33 U.S.C. § 1344(e), which allows the Corps to issue general permits on a statewide basis for categories of activities involving discharges of dredged or fill material to “waters of the United States” (WOTUS) if the Corps determines that the activities (1) are similar in nature, (2) will cause only minimal environmental impact when performed separately, and (3) will have only minimal cumulative adverse impacts on the environment. In Pennsylvania, the Corps relies primarily on the state programmatic general permit, rather than nationwide permits, to authorize impacts to regulated waters that meet the criteria of the general permit. Projects impacting WOTUS that do not qualify for coverage under the programmatic permit must obtain an individual permit under section 404.
As discussed below, PASPGP-6 would revise PASPGP-5 in several ways that would likely impact energy projects in Pennsylvania, especially natural gas pipelines. Generally, PASPGP-6 is expected to ease permitting obligations for projects with temporary impacts, and to impose more stringent threshold eligibility and reporting requirements for projects with permanent impacts to regulated waters. The proposed general permit would also require consideration of cumulative effects of the overall project when determining whether the project required additional Corps review.
Revised Project Eligibility
Eligibility Thresholds. PASPGP-6 would change the eligibility thresholds for projects with temporary and/or permanent impacts. Currently, projects that would result in greater than one acre of temporary and/or permanent impacts to WOTUS are not eligible for coverage under PASPGP-5. PASPGP-6 would reduce the eligibility threshold for permanent impacts to 0.5 acre but would eliminate the eligibility threshold for temporary impacts. Consequently, projects involving more than one acre of temporary impacts or “non-adverse permanent impacts,” which are not eligible for PASPGP-5, could be eligible for PASPGP-6. However, projects involving permanent im-pacts of between 0.5 and one acre, which are currently eligible for PASPGP-5, would no longer be eligible for PASPGP-6, thereby potentially requiring more projects to obtain individual permitting.
Eligible Waters. In addition to the eligibility thresholds based on the extent of impacts, PASPGP-6 would expand its coverage to certain section 10 waters, which are currently ineligible for coverage under PASPGP-6. “Section 10 waters” are waters that are considered as navigable under section 10 of the River and Harbor Act of 1899, 33 U.S.C. § 403.
Under PASPGP-5, projects impacting certain segments of 12 section 10 waters are ineligible for general permit coverage. However, 10 of those waterbodies (i.e., all of the Ohio, Beaver, Little Beaver, Mahoning, and Monongahela Rivers, and certain portions of the Youghiogheny, Allegheny, and Kiskiminetas Rivers, Tenmile Creek, and Lake Erie) would be eligible under PASPGP-6. Thus, projects impacting these waterbody segments could obtain coverage under PASPGP-6 if other applicable criteria are met. The remaining two waterbodies (i.e., certain segments of the Delaware River and the Schuylkill River) would remain ineligible for programmatic permitting.
Projects impacting the relevant segments of the Allegheny, Monongahela, and Ohio Rivers and Lake Erie would become “Reporting Activities” under PASPGP-6.
Revised Reporting Requirements
Reporting Thresholds. Many eligible projects are authorized by the programmatic general permit without further notification to the Corps (i.e., “Non-Reporting Activities”). Other projects, referred to as “Reporting Activities,” must undergo a project-specific review by the Corps prior to receiving authorization. PASPGP-6 identifies several changes to the “Non-Reporting Thresholds,” under which projects qualify as Non-Reporting Activities.
- Permanent Impacts. Under PASPGP-6, projects involving less than 0.25 acre of permanent impacts would qualify as Non-Reporting Activities, while projects involving from 0.25 to 0.5 acre of permanent impacts would generally be classified as Reporting Activities. This revision would make PASPGP-6 more stringent that PASPGP-5, which does not require reporting unless permanent impacts are greater than 0.5 acre. In addition, projects involving more than 250 linear feet of permanent impacts to WOTUS (excluding wetlands) would generally continue to be a Reporting Activity under PASPGP-6, with certain exceptions for state-permitted restoration activities. Projects proposing the permanent conversion of more than 0.1 acre of forested and/or scrub-shrub wetland would no longer be a Reporting Activity under PASPGP-6.
- Temporary Impacts. Under PASPGP-6, projects involving less than one acre of temporary impacts would qualify as Non-Reporting Activities, while projects involving greater than one acre of temporary impacts would be considered as Reporting Activities. This change would make PASPGP-6 less stringent than PASPGP-5, under which temporary impacts greater than 0.5 acre would require reporting. Finally, under PASPGP-5, projects involving temporary impacts lasting longer than one year are a Reporting Activity, while under PASPGP-6, such projects only require reporting if the temporary impacts are greater than 0.1 acre.
Utility Line-Specific Reporting and Non-Reporting Activities. PASPGP-6 would change the classification of certain Reporting and Non-Reporting Activities for utility lines, which would directly impact natural gas pipeline construction and operation in Pennsylvania. Specifically, utility line crossings of WOTUS (including wetlands) exceeding 500 linear feet are currently Reporting Activities under PASPGP-5. However, they would not be Reporting Activities under PASPGP-6. Instead, under PASPGP-6, a utility line stream crossing is non-reporting provided the project is authorized by Pennsylvania Department of Environmental Protection General Permit 5 (GP-5 – Utility Line Stream Crossing).
Buried utility lines in WOTUS (including wetlands), where a utility line runs parallel to or along a stream bed, would no longer be a Reporting Activity under PASPGP-6.
Single and Complete Project Versus Overall Project. PASPGP-6 reintroduces a distinction between the impacts that determine eligibility with PASPGP-6, and the impacts that determine reporting to the Corps. Such a distinction was removed from PASPGP-5, but has been added to the draft PASPGP-6. Under PASPGP-6, the eligibility threshold would be based on the impacts associated with the “Single and Complete Project.” However, the reporting threshold would be based on the cumulative effects associated with the “Overall Project.” For linear projects (e.g., pipelines), when crossing a single (or multiple) waterbody several times at separate and distant locations, each crossing is considered a Single and Complete Project for purposes of PASPGP-6 verification. The Overall Project is more broadly defined to include “all regulated activities that are reasonably related and necessary to accomplish the project purpose, including those activities that may occur in the reasonably foreseeable future.” The anticipated effect of this change in identifying Reporting Activities is that more projects would be required to be reported to the Corps for review, likely causing delays in obtaining permitting approval.
Takeaways and Next Steps
In many respects, PASPGP-6 would likely benefit developers of energy projects in Pennsylvania, particularly natural gas pipeline operators, by removing the one-acre eligibility threshold for temporary impacts, allowing use of PASPGP-6 for certain section 10 waters, and reclassifying certain projects as non-reporting. However, other projects may be adversely delayed or impacted by the reduced eligibility threshold for permanent impacts, as well as the consideration of the cumulative effects of the overall project in determining reporting activities. The final PASPGP-6 draft is expected to be released for public comment this spring.
Copyright © 2020, The Foundation for Natural Resources and Energy Law, Westminster, Colorado
Environmental Alert
(by Robert Stonestreet and Kip Power)
On May 18, 2020, we reported on a “notice of intent to sue” letter sent to the West Virginia Department of Environmental Protection (WVDEP) on behalf of three environmental interest groups concerning West Virginia’s program for bonding of coal mining operations. As more fully explained in our May 18, 2020 article, available here, those groups demanded that WVDEP formally notify the federal Office of Surface Mining (OSM) of three events that they claimed would significantly affect the financial condition of the bonding program: (1) the insolvency of coal mine permittee “ERP Environmental Fund” and the associated receivership proceeding commenced by WVDEP; (2) an alleged lack of sufficient funding in the bonding program to cover the reclamation and water treatment costs at ERP’s operations; and (3) the potential insolvency of other mining companies.
On July 8, 2020, WVDEP formally notified OSM of the ERP proceedings, but denied that the circumstances surrounding ERP significantly affect the WVDEP bonding program. The very next day, the three groups filed suit against WVDEP in the federal District Court for the Southern District of Virginia. The complaint acknowledges WVDEP’s July 8, 2020 letter addressing the ERP proceedings, but alleges that the letter improperly failed to formally notify OSM of two other events the groups claim significantly affect the bonding program: (1) the bankruptcy proceedings of two other coal operators and the purported threatened insolvency of a third operator; and (2) WVDEP’s alleged inability to complete the required reclamation work at ERP’s operations with available funds.
The complaint requests that the court declare that WVDEP has failed to administer its regulatory program in accordance with the federal Surface Mining Control and Reclamation Act, and further requests entry of an order commanding WVDEP to do so. The groups also request payment of their attorney fees and costs associated with the lawsuit.
WVDEP’s response to the complaint will be due 21 days after the agency is formally served.
Should you have questions about the WVDEP coal mine regulatory program or other environmental permitting matters, please contact Robert M. Stonestreet at (681) 265-1364 or rstonestreet@babstcalland.com, or Christopher B. “Kip” Power at (681) 265-1362 or cpower@babstcalland.com.
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