EPA and BSEE Team Up to Resolve Offshore Environmental Violations

By John Gray and Carlos Moreno

Recently, when there was talk about Houston-based ATP Oil and Gas’ (ATP) legal problems, it was inevitably about its bankruptcy and its effort to bring the overriding royalty interests it had conveyed back into the bankrupt estate as debt instruments. That should change now that the Department of Justice (DOJ), acting jointly on behalf of EPA and BSEE, has announced its settlement with ATP Infrastructure Partners (ATP-IP) in the first joint judicial enforcement action resolving alleged violations of both the Clean Water Act (CWA) and Outer Continental Shelf Lands Act (OCSLA).

This settlement should garner its own share of interest, if for no other reason, because BSEE and EPA are taking the issues serious enough to require all submittals to be signed by a responsible corporate official in addition to imposing a $1 million fine.

It highlights three trends that industry should be aware of: the willingness of EPA and BSEE to work together to address violations of environmental regulations off-shore, requiring corrective measures that include enhanced reporting and third-party auditing, and multiple mandated certifications by a designated officials.

The Violation

In March 2012, BSEE conducted an inspection of ATP’s floating production platform facility, known as the ATP Innovator, while it was moored to the sea floor about 45 nautical miles offshore of southeastern Louisiana (about 125 miles south of New Orleans) and engaged in the production of oil and natural gas. ATP operated a float cell on the platform as an essential part of its wastewater treatment system to separate and remove oil and suspended solids from its produced water prior to its discharge into the Gulf. During the inspection, BSEE officials discovered a metal tube “hidden in the rafters” that went from a tank holding Cleartron ZB-103, a water clarifier that the government alleges was used as a dispersant, to the outfall pipe at a location downstream of the designated NPDES sampling point; thus, making the added chemical undetectable in required NPDES samples.

According to the complaint (PDF) DOJ filed in February 2013, Cleartron ZB-103 was routinely “injected into the outfall pipe to mask oil sheen on the ocean surface resulting from ATP’s discharge of wastewater containing quantities of oil in excess of its NPDES permit limit.” DOJ further alleged that this setup was intended to allow ATP to mask any oil sheens resulting from the discharge of wastewater that exceeded the permit limit for oil content. Under the NPDES General Permit, the Oil & Grease content of produced water discharges is limited to a monthly average of 29 mg/L and a daily maximum of 42 mg/L, and the General Permit only requires the collection of Oil & Grease samples once per month.

However, permittees are also required to sample their produced water discharge for Oil & Grease any time that a sheen is observed in the vicinity of the discharge. Thus, the mere presence of a produced water sheen is not necessarily a permit violation, but it will necessitate additional sampling to determine if a violation has occurred. The government also noted that the Cleartron ZB-103’s MSDS states that it is harmful to aquatic life. For these reasons, the government claims that the discharge of Cleartron ZB-103 in this manner was an unlawful discharge of a CWA “pollutant.”

Following the BSEE inspection, the piping that ran from the Cleartron ZB-103 tank to the discharge pipe was removed, the ATP Innovator ceased operations and was removed from the deepwater. It now resides at the Port of Corpus Christi, Texas, sitting idle with no plans for future use in United States waters.

The DOJ filed its complaint against two entities—ATP and ATP-IP. ATP is the ATP Innovator’s operator and ATP-IP is the platform’s owner. Sometime after the BSEE inspection, but before DOJ filed its complaint, ATP declared bankruptcy citing reduced cash flows caused by the deepwater drilling moratorium instituted after the 2010 Deepwater Horizon oil spill. Normally, the automatic stay afforded to bankrupt entities would protect these entities against litigation, but the DOJ’s enforcement action was exempt from the automatic stay based on a “police and regulatory” exemption. ATP’s bankruptcy has not been resolved; therefore, the government’s claims against it await resolution.

The government’s Complaint alleges six causes of action:

  1. CWA § 309(d) civil penalties for violations of CWA § 301(a) for unauthorized chemical dispersant discharges;
  2. CWA § 309(d) civil penalties for permit violations;
  3. CWA § 311(b)(7)(A) and (D) civil penalties for oil discharge violations;
  4. Injunctive relief under OCSLA, 43 U.S.C. § 1350(a);
  5. Injunctive relief under CWA Section 309(b); and
  6. Declaratory judgment declaring the applicability of the police and regulatory exception to the Bankruptcy Code’s automatic stay pursuant to 11 U.S.C. § 362(b)(4).

ATP-IP unsuccessfully sought to have all of DOJ claims against it (Claims 3, 4, and 5) dismissed. See United States v. ATP Oil & Gas Corp., 955 F.Supp.2d 616 (E.D. LA. 2013).

The Relief Sought by the Government

Both EPA regulations and the General NPDES permit restrict the discharge of dispersants into the ocean or any other waters. See 40 C.F.R. § 110.4 & NPDES General Permit, Part I, Section C.3 (expressly stating that the “operator shall minimize the discharge of dispersants, surfactants and detergents except as necessary to comply with the safety requirements of [OSHA, BSEE, and BOEM]... .). The DOJ alleged that ATP had been discharging significant quantities of dispersants, i.e., Cleartron ZB-103, on a daily basis, from October 2010 to March 2012—a period of about 16 months which at a statutory maximum of $37,500 per day for each of the three violations listed above exposed ATP to a maximum potential fine of about $54 million.

In addition to statutory penalties, the DOJ sought injunctive relief measures under both the CWA and OCSLA for operational practices to prevent future unauthorized discharges of pollutants into the offshore waters. This included the pipe setup itself, which still exist, in part, because only the pipe itself was removed, leaving the tube for use in future permit violations.

ATP-IP’s Consent Decree

To resolve this enforcement action, ATP-IP agreed to pay a $1 million fine and perform corrective measures including the permanent elimination of the Cleartron ZB-103 access point in the wastewater discharge outfall pipe. More importantly, the Consent Decree (PDF) requires that at least 30 days before anyone uses the ATP Innovator again for exploration, development, or production activities in US waters, ATP-IP will certify to the government that:

  • The platform has sufficient wastewater treatment equipment and operational plans to meet and maintain CWA permit discharge limits and prevent unlawful discharge of pollutants.
  • The platform’s surface production-safety systems will be maintained in a manner that provides for protection of the environment in accordance with BSEE’s regulations.
  • All platform operations will be performed in a safe and workmanlike manner in accordance with BSEE’s regulations.

As a further safeguard, with respect to the platform, ATP-IP must notify the DOJ, EPA and BSEE if any of the following actions occur:

  • The addition of any wastewater treatment equipment or surface production-safety equipment before the requisite certification is made.
  • Removal of the tube and permanent sealing of the discharge pipe.
  • Plans for its sell or transfer of ownership.
  • Plans for its salvage or scraps.
  • Plans for its use or lease for exploration, development, or production activities.
  • The required third-party audit of its wastewater treatment operations and surface production-safety systems for compliance with the CWA and OCSLA.
  • After every six months, its location and ownership.

Each Notification, Certification and Report Must be Signed By a Responsible Corporate Official

In a showing of how serious BSEE and EPA are taking these alleged violations, the consent decree requires each of the above notices, certifications and audit reports submitted by ATP-IP to the government to be signed by a responsible corporate official with the following certification:

I certify under penalty of law that this document and all attachments were prepared under my direction or supervision in accordance with a system designed to assure that qualified personnel properly gather and evaluate the information submitted. Based on any personal knowledge I may have and my inquiry of the person or persons who manage the system, or those persons directly responsible for gathering the information, the information submitted is, to the best of my knowledge and belief, true, accurate, and complete. I am aware that there are significant penalties for submitting false information, including the possibility of fine and imprisonment for knowing violations.

The consent decree neither defines the term “responsible corporate official.” It is unclear whether this term will be interpreted as consistent with the similar provisions of the NPDES signatory rule. See 40 C.F.R. 122.22. The above certification language is almost identical to that which is required by NPDES regulations that must be signed by a responsible corporate officer or their duly authorized representative. See 40 C.F.R. § 122.22 (d). If the term “official” as used in the consent decree is equivalent to “officer,” then the only real difference is that the consent decree does not allow a “duly authorized representative” to sign the above-required certifications.


This consent decree is significant because it shows for the first time EPA, BSEE and DOJ working together, locally and in Washington D.C., to impose enhanced monitoring and auditing requirements on entities subject to enforcement actions for environmental violations in the Gulf of Mexico. The best means for avoiding liability in this case is to document compliance programs and due diligence in reviewing permit related submittals with those who prepared the documents to ensure their accuracy..

This is clearly an attempt by the government to change the corporate culture at ATP-IP and to send a message to the rest of the regulated community. While monetary penalties generally imposed upon a company may not sufficiently deter certain types of risk-taking within a corporation's culture, making a corporate official personally assume responsibility and even potential criminal liability for the accuracy of government submittals related to compliance with a consent decree should get every executives attention and hopefully their attention will radiate across their company and perhaps the industry.

Ultimately, this case underscores the government’s expectation that upper management be actively involved in ensuring corporate compliance with federal environmental laws. Corporate executives and in-house counsel in heavily regulated environments are well-advised to implement effective compliance programs and to ensure that such programs are actually followed in order to avoid even the specter of personal liability.

Sierra Club Asks Court to Ban Use of Legacy DOT-111 Tank Cars

By John Gray and Carlos Moreno

As if crude producers and midstream transportation companies don’t already have enough problems trying to get crude oil from production fields to refineries thanks to inadequate pipeline infrastructure, tank car supply, rail safety concerns, and new regulations, they now also have to address a new, potentially market-busting lawsuit. In September, the Sierra Club, one of the largest environmental organizations in the United States, filed a lawsuit seeking an immediate ban on the transportation of crude oil in allegedly outdated and unsafe tank cars despite the fact that the government has proposed regulations to address the same concerns.

The Proposed Regulations

Following a series of train accidents in 2013, and a number of petitions asking for more stringent railroad safety regulations, the Pipeline and Hazardous Materials Safety Administration (PHMSA) and Federal Railroad Administration (FRA) published an advance notice of proposed rulemaking (ANPRM) on September 6, 2013. At the requests of the Sierra Club, the government extended the comment period to allow additional time for more public participation and both the Sierra Club and ForestEthics (the NGOs) submitted comments relevant to the proposed rulemaking.

The Petition for an Emergency Ban

Not willing to wait for the wheels of government to turn, the two NGOs jointly filed a petition with the Secretary of Transportation on July 15, 2014, just before the proposed rules were to be published, asking DOT to issue an emergency order banning the use of unjacketed (legacy) DOT-111 tank cars to ship Bakken crude and other highly flammable crude oil. The petition claims that unjacketed DOT-111 are unsafe because in rail accidents the cars are prone to puncture, spill oil, and trigger fires and explosions. They argue that the continued use of these tank cars poses an “imminent hazard.”

Instead of directly responding to the NGOs’ petition, the government issued a Notice of Proposed Rulemaking, as planned, about two weeks later. We reported in our recent blog entry about the content and impact of these new rules, which proposes three options for phasing out of the legacy DOT-111 tank cars, none of which includes an immediate ban on their continued use. Thus, if finalized as proposed, the new rules would shippers to continue to use legacy DOT-111 tank cars to ship Bakken crude until October 2018.

The Writ of Mandamus

Although the proposed rule addresses many of the DOT-111 safety concerns by requiring retrofits and operational changes, the NGOs claim that the proposed four-year phase-out of legacy tank cars is a “glacial pace [that] is unacceptable.” Thus, they filed an original Writ of Mandamus with the United States Court of Appeals for the Ninth Circuit on September 11, 2014, seeking to force the DOT to respond their petition for an immediate ban. For a legal basis, the NGOs argue that the All Writs Act gives the Ninth Circuit Courts of Appeals jurisdiction and they claim that the DOT has violated the Administrative Procedure Act a number of ways by taking an unreasonable amount of time to respond to their Rail Car Petition.

First, the NGOs claim that threat posed by the continued use of legacy DOT-111 tank cars is so severe that the 2018 ban contemplated in the proposed rules is simply too extended. Second, they even argue that the threat of harm is so great that the rulemaking process itself will take too long and leave too much to chance. For these reasons, they claim that the DOT had an obligation to respond to their petition for emergency order within a reasonable time, i.e., 30 days. Third, the NGOs argue shippers, who own the legacy DOT-111 tank cars, lack the necessary incentives created by financial liability to stop using DOT-111 tank cars to ship Bakken crude because they generally do not bear liability for rail accidents once a rail carrier accepts a shipment. And finally, the NGOs claim that the DOT’s proposed delay banning the DOT-111 tank cars will cause prejudice because Canada has already banned the DOT-111 tank cars; thereby incentivizing North American marketers to use the unsafe DOT-111 tank cars in America and the newer and safer tank cars in Canada until after the 2018 ban.

The NGOs acknowledge that most “unreasonable delay cases” entail lengthier delays involving rulemaking proceedings that take years to complete, but argue that their petition is unique and different because it seeks an “emergency action” to abate an imminent hazard that cannot wait for a rulemaking because “lives are at stake.” Likewise, while the NGOs admit that “there is no per se rule as to how long is too long, [they nonetheless claim that] ‘a reasonable time for agency action is typically counted in weeks or months, not years,’ particularly when urgent health or environmental harms are at stake, as the case here.” Citing In re American Rivers, 372 F.3d 413, 419 (D.C. Circuit 2004).

A Case to Follow

On September 22, 2014, the Ninth Circuit denied the petitioners’ request for an expedited decision but ordered the DOT to respond to the NGOs’ writ. The court specifically directed the DOT to propose a timeline for its response to the Rail Car Petition. According to the briefing schedule, the Ninth Circuit’s ruling will likely come in early 2015.

Crude oil producers should keep an eye on how the Court and the agency address the NGOs’ request because if the DOT ultimately bans legacy DOT-111, the marketplace would immediately lose about 25 percent of tank cars available to transport crude oil in North America, creating an immediate shortage of rail cars until the industry can manufacture new tank cars using the newer standards.

Trans Energy Settlement Shows Need for E&P Wetlands Compliance Strategy

By Robert E. Holden and Lesley F. Pietras

On September 2, 2014, the Department of Justice announced a settlement in United States v. Trans Energy, Inc., No. 14-117 (N.D.W.Va.), requiring the oil and gas company to pay $3 million in civil penalties and to spend approximately $13 million to restore 15 sites in West Virginia that had been developed without dredge and fill permits. The United States and the West Virginia Department of Environmental Protection alleged that the company impounded streams and discharged dirt, sand, rocks and other materials into streams and wetlands without permits to construct well pads, pipeline stream crossings, surface impoundments, and other structures relating to natural gas extraction. According to the Justice Department, the violations affected 13,000 linear feet of stream and more than an acre of wetlands.

The Trans Energy settlement shows that exploration and production (E&P) companies need a rigorous compliance strategy for wetlands permit requirements. In this regard, the legal commentary has placed a high degree of emphasis on the jurisdictional question under Section 404 of the Clean Water Act of whether a planned activity will involve the discharge of dredged or fill material into “waters of the United States.” See our previous blog entry on the proposed rule redefining the “waters of the United States” covered by the Clean Water Act.

On the other hand, the legal commentary has virtually ignored the importance of Nationwide Permits (NWPs) 12 and 39 to E&P activities. The Army Corps of Engineers (Corps) issues NWPs for activities that have minimal individual and cumulative adverse effects on the aquatic environment. The most recent versions of the NWPs were reissued in 2012, and they will be valid for five years, until March 18, 2017. See 77 Fed. Reg. 10184 (Feb. 21, 2012).

NWP-12 is for “utility line activities.” It authorizes activities required for the construction, maintenance, repair, and removal of “utility lines 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.” 77 Fed. Reg. at 10271. “Utility lines” are defined broadly enough to include oil and gas gathering lines. In addition, NWP-12 expressly authorizes the construction of access roads for the construction and maintenance of “utility lines,” with certain limitations. NWP-12 requires pre-construction notification to the Corps only for seven specified types of circumstances, including where:

  • A Rivers and Harbors Act Section 10 permit is required;
  • The length of the “utility line” in “waters of the United States” exceeds 500 feet; or
  • The discharge results in a loss of more than 1/10th of an acre of “waters of the United States.”

Id. at 10272.

Moreover, NWP-39 authorizes discharges of dredged or fill material into non-tidal “waters of the United States” for the construction or expansion of commercial and institutional building foundations and building pads and attendant features necessary for the use and maintenance of the structures. The discharge must not cause the loss of greater than 1/2-acre of non-tidal “waters of the United States,” including the loss of no more than 300 linear feet of stream bed (unless for intermittent and ephemeral stream beds the Corps waives the 300 linear feet limit). Id. at 10279. Notably, the Corps has expressly stated that the construction of oil and gas well pads is a type of commercial development appropriate for authorization under NWP-39. Id. at 10223. Pre-construction notification is required for all NWP-39 permits.

The use of the NWPs also requires water quality certification under Section 401 of the Clean Water Act. The Louisiana Department of Environmental Quality has issued water quality certification (PDF) for NWP-12 without conditions, but it will issue such certification for NWP-39 only on a case-by-case basis. Likewise, the Texas Railroad Commission, which handles water quality certifications for federal permits covering activities associated with oil and gas exploration, development, and production operations, has issued water quality certification for activities under NWP-12 (PDF).

Individual Section 404 permits are not required when a nationwide permit is available. The E&P industry should utilize the NWP program as a way to streamline and simplify wetlands permit requirements. For more information about the NWP program, please contact Robert Holden or Lesley Pietras.

BSEE's Investigations and Review Unit Changes the Playing Field on the OCS

By Bob Holden, Dee Taylor, and Jillian Marullo

The Bureau of Safety and Environmental Enforcement’s (BSEE’s) Investigations and Review Unit (IRU) substantially enhances the civil and criminal enforcement of the Outer Continental Shelf Lands Act (OCSLA) and the regulations issued thereunder.


In 2010, in the wake of the Deepwater Horizon oil spill, the Department of Interior renamed the Minerals Management Service (MMS) the Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE). DOI then restructured BOEMRE into three new Bureaus: BSEE, the Bureau of Ocean Energy Management (BOEM) and the Office of Natural Resources Revenue. The reorganization gave BSEE regulatory authority (PDF) over safety and environmental affairs for OCS exploration and production activities.

As part of the restructuring of the MMS, DOI Secretary Salazar established the IRU within BOEMRE via Secretarial Order No. 3304, issued June 29, 2010. The IRU was established (PDF) “to root out internal problems and target companies that aim to game the system.” Its purpose was “to establish the internal capability in BOEMRE” to: (1) promptly and credibly investigate and respond to allegations or evidence of misconduct and unethical behavior by BOEMRE employees and industry; (2) oversee and coordinate BOEMRE’s internal auditing, regulatory oversight and enforcement systems and programs; and (3) assure the ability of BOEMRE to swiftly assess and respond to emerging issues and crises on a Bureau-wide level, including spills and other significant events. Secretary Salazar originally intended the IRU’s functions to continue within the three new bureaus; however, as of fiscal year 2013, the IRU was operating only within BSEE (PDF).

Questions Regarding the Composition and Functioning of the IRU

The IRU describes itself as “a team of professionals with law enforcement backgrounds or technical expertise.” The head of the IRU reports to the BSEE Director. The current head of the IRU was formerly a supervisory special agent with the EPA’s Criminal Investigation Division. The IRU staff includes a federal criminal prosecutor and experienced law enforcement agents.

The Natural Resources Committee for the House of Representatives has questioned DOI about the IRU’s composition and activities. Rep. Richard Hastings (R-Wash.), House Natural Resources Committee Chairman, on behalf of the Committee, said in a letter (PDF) to Secretary Salazar, dated March 4, 2013, “More than two years after its creation, little is known about the IRU’s personnel, organization, and activities.” In particular, Rep. Hastings raised concerns about the IRU’s makeup, pointing to (1) BOEMRE’s 2010 request for $5.8 million (PDF) to equip the IRU and staff it with twenty new employees; (2) a 2012 statement by BOEMRE Director Bromwich “that the IRU would be staffed by prosecutors, investigators, and scientists;” (3) BSEE’s description of the IRU as “a team of professionals with law enforcement backgrounds or technical expertise;” and (4) a 2012 job listing for IRU special investigators noting duties including collecting evidence and witness statements. According to Rep. Hastings, it was “unclear how many people actually work in the IRU, what their backgrounds and expertise are,” whether they “serv[e] in a law enforcement capacity” or are authorized to carry firearms, and “how they are to interact with witnesses or collect evidence. . . .”

Rep. Hastings was particularly concerned that the IRU had been acting as a law enforcement organization beyond its authority and without sufficient oversight by the DOI, Congress or the public, instead reporting only to the BSEE Director. Rep. Hastings requested that the DOI produce any policies and guidance concerning coordination between the IRU and the DOI’s Office of Inspector General (DOI-OIG) or Ethics Office, as well as any status reports or results of investigations provided by the IRU to the DOI-OIG. The Natural Resources Committee has received a response from the DOI, but the DOI response is not publicly available at this time.

IRU Investigations

The IRU shares BSEE’s regulatory jurisdiction. It investigates violations of safety and environmental regulations in parallel with and in addition to ordinary BSEE investigations. Typical BSEE investigations are conducted by BSEE district personnel and are fact-finding proceedings. These investigations may result in the issuance of Incidents of Noncompliance (INCs) with requirements for corrective actions and/or the imposition of civil penalties. See 30 C.F.R. §§ 250.191, 250.1404. In all but the most egregious cases, the typical civil enforcement action has in the past been resolved with the correction of the noncompliance and the payment of any required civil penalty.

The IRU has an investigatory role greater than that of BSEE inspectors. The IRU investigation may be triggered by an accident, a whistleblower, or an INC. The IRU concentrates on matters involving serious personal injury or harm to the environment, or serious risks of such harm. If after a detailed investigation, the IRU determines that a criminal violation may have occurred (i.e., a willing and knowing violation of the statute, regulations, or lease provision, see 43 U.S.C.§ 1350(c)), the IRU may refer the investigation to the DOI-OIG for further investigation. With respect to an investigation that has been triggered by an INC, the IRU or DOI-OIG investigation may continue regardless of whether the INC has already been resolved or any civil penalty paid.

In contrast to the IRU, the DOI-OIG has criminal enforcement authority within the agency. (The DOI-OIG agent is the counterpart to an FBI agent in a regular criminal investigation.) The DOI-OIG may then refer the case to the United States Attorney’s Office for criminal prosecution, which in turn may bring the matter before a grand jury to seek an indictment.

The IRU investigation of an INC may not be apparent to an operator. An operator that has been issued an INC can no longer assume that the matter is closed simply because it corrected the noncompliance and paid a civil penalty—an investigation could be ongoing within the IRU. For example, an operator might only learn of the IRU investigation when it receives a request from the IRU to provide documents and/or make its employees available for interviews. Operators should know that if an investigation proceeds to IRU interviews of the operator’s employees and contractors, the IRU considers the violation to be a serious issue with possible criminal implications. Failure to cooperate in an IRU investigation could itself be construed as a violation of the OCSLA.

The IRU has the authority to interview and take oral statements from employees and contractors. The IRU may tape record the interviews (generally the operator will only receive copies of the tapes after indictment). For reasons of logistics, the interviews are unlikely to take place offshore. The individual who is subject to an IRU interview has a clear right to have his or her attorney present; however, the IRU will have discretion about allowing company attorneys to be present. The interview process itself raises a number of concerns, such as: (1) a government interview is intimidating and scary to employees; (2) the employees may be unaware of their right not to be interviewed; (3) the employees may be unaware of their right to their own counsel at the interview; (4) the employees may be unaware of the possible use of the interviews in a future criminal case; and (5) many employees may not be sophisticated about complex technical terms and actions on a rig or platform, creating a risk of miscommunication of regulatory significance. For these reasons, when the IRU is conducting interviews, it makes sense for the operator to implement a pro-active legal response.


We recommend that operators respond to and treat accident investigations and INCs more carefully than ever. Accidents involving serious injuries and INCs involving serious environmental and safety risks will receive heightened scrutiny by BSEE’s District Office and the IRU. It is not only actual harm, but also the risk of harm, either to an individual or to the environment, that triggers criminal enforcement. The IRU is now a mature organization, staffed with highly capable and experienced investigators tasked with ensuring more active enforcement of BSEE regulations. OCS operators and their counsel should be aware of the heightened risk of criminal investigations and possible prosecution. 

Proposed Railroad Rules May Impact Crude Oil Producers: Proposed DOT/PHMSA Oil Tank Car Rules

By John S. Gray and Carlos J. Moreno

Prompted by concerns heightened by several recent high profile train derailments and accidents, coupled with the boom in the number of oil-carrying trains, the Obama administration, through the Pipeline and Hazardous Materials Safety Administration (PHMSA), has proposed two new sets of rules aimed at addressing the perceived risks posed by the increase in rail transportation of crude oil primarily from the Bakken shale. These rules are similar to ones just issued in Canada that will also require the phase-out of older rail tank cars. See 79 Fed. Reg. 45,016 (Aug. 1, 2014) (comments are due on September 30, 2014).

Notice of Proposed Rulemaking

According to Transportation Secretary Anthony Foxx, the "Bakken crude oil is on the high end of volatility compared to other crude oils,…[and] its production is skyrocketing, up from 9,500 rail car loads in 2008 to 415,000 last year, a more than 4,000 percent increase." To address their concerns, PHMSA, through a Notice of Proposed Rulemaking (NPRM), is seeking to require the phase-out of tens of thousands of tank cars now in High-Hazard Flammable Train service (defined as a single train containing 20 or more tank carloads of Class 3, i.e., flammable liquid material), within as little as two years, unless they are retrofitted to meet new safety standards. For trains transporting crude oils that exhibit certain physical properties, the new rules, if promulgated, will also require lower speed limits, better braking, and a formal sampling and testing program for volatile liquids, including oil.

These new speed limits—40 mph for trains with tank cars that do not meet the new standards, 50 mph maximum for those that do, and a 30-mph restriction for those that do not comply with stricter braking requirements—may affect the oil and gas industry mainly by slowing down transportation of crude. On the other hand, the tank car phase-out may pose real issues if it causes a shortage of transportation options before industry is able to meet the demand for new or retrofitted tank cars.

Under the proposed rules, the rail cars facing retrofit or phase-out—known as DOT-111 cars—account for 228,000 of the 335,000 active tank car fleet, and 92,000 of them move flammable liquids, such as crude oil and ethanol. Of these 92,000 tank cars, only 18,000 have been built to the industry's latest safety standards. These older-model DOT-111 tank cars used to transport both crude oil have long been known to be vulnerable to failure in derailments. The Obama Administration has rejected calls from some for an immediate ban on shipping volatile crude in the older DOT-111 tank cars, claiming that the proposed phase-out appropriately balances the need to transport crude, but doing it safely.

The need for safer tank cars is not new. The rail industry voluntary took steps in 2011 to improve tank car design and since then all the tank cars built for this service meet a new industry standard, known as CPC-1232. However, two of the three options proposed by PHMSA for a new agency standard, to be known as DOT-117, require a greater shell thickness than CPC-1232 requires. But even when 55,000 of the newer CPC-1232 cars are in service by 2015, there will still be 45,000 older ones being used to meet demand.

Cost and Other Implications to Shippers

It would be a mistake to think that these rules would only have a significant impact on manufacturers of tank cars and rail carriers. On the contrary, oil and gas companies could be significantly affected by these rules. Almost all tank cars are owned or leased by the shippers of the crude oil. Those companies that own their tank cars would have to pay for their retrofit, repurposing, or disposal, and/or the cost of new tank cars. Although PHMSA expects that lease rates would not increase as a result of the new standard, it is hard to imagine that the lessor would not pass on some of these additional costs to the lessee. Finally, the agency acknowledges that rail carriers are likely to pass on additional fees to the shippers as a result of increased fuel and track maintenance required by the added weight of new or retrofitted tank cars.

Another potential cost to oil and gas companies is related to potential delays from slower speeds and reduced tank car capacity. As to the latter issue, the agency argues that the new tank cars would be allowed to have a higher Gross Rail Load (maximum weight) than the regular DOT 111 tank cars; therefore, there would not be a loss in oil capacity. The agency also expects industry to come up with new materials that weigh less but still meet their requirements. While those assumptions regarding capacity are debatable, there is no argument that reduced speeds will result in delays. The agency estimates the rail carrier’s cost of delay at $500 per hour. Regardless of the hourly cost, one would suspect that some of those costs will be passed on to the shipper.

Shippers will also have increased regulatory liability in at least one aspect of the rule. Current rules require the shipper to certify that it has properly assessed the hazards of the material and selected the appropriate shipping classification. Under the proposed rules, this certification will also include certifying that the newly-required written sampling and testing program is in place and properly implemented. Therefore, knowing violations of this sampling and testing program requirement could subject the shipper to civil penalties under 49 C.F.R. §171. The new sampling and testing program must include information about and justification of testing frequency, methods used, and quality assurance measures. This program also has its own costs to prepare and implement, which would have to be covered solely by the shipper.

Advance Notice of Proposed Rulemaking

In addition to the notice of newly proposed rules on tank cars, PHMSA also issued an Advance Notice of Proposed Rulemaking (ANPRM) seeking comments on plans to propose new regulations regarding the need for most trains carrying crude oil to prepare comprehensive oil-spill response plans. Currently, railroads do not have to create such plans, but PHMSA claims that derailments in Quebec, Alabama, North Dakota, Virginia, and elsewhere since last year have revealed gaps in emergency response training, equipment and staff. Specifically, PHMSA seeks comments about the volume of crude oil carried by a train that would trigger oil spill response planning, i.e., trains with 1 million gallons or more of crude, trains with 20 or more tank cars of crude oil, 42,000+ gallons of crude per train or another threshold.

Currently, railroads are not required to tell communities where they are shipping crude oil. Instead, railroads provide limited information on hazardous materials shipments to emergency response agencies by request. Even then, they only have to disclose what hazardous products they are shipping, not how much or when. State and local officials, however, are beginning to demand to know more details about hazardous shipments. Some railroads are cooperating, while others cite security and competitive concerns for not providing the requested information. It is unclear at this time whether the response plan requirements will impact only the railroad companies or whether they may also place some burden on the companies whose crude oil the trains will carry.

Air Permitting Update: D.C. Circuit Decision Helps E&P Facilities

By Carlos J. Moreno

On May 30, 2014, in an unanimous decision in National Environmental Development Association’s Clean Air Project v. U.S. Environmental Protection Agency, the United States Court of Appeals for the District of Columbia Circuit vacated EPA’s policy limiting the reach of the Sixth Circuit’s decision in Summit Petroleum Corp. v. EPA.

In Summit, the Sixth Circuit concluded that EPA’s interpretation of the term “adjacent” in the context of source aggregation under the Clean Air Act’s Title V and NSR permitting was unreasonable in its application to geographically dispersed oil and gas facilities. The EPA had argued that an operationally interdependent relationship (in the Summit case, spanning a 43-square mile area) was enough to find that pollutant-emitting activities were “adjacent.” For more on this decision, see our previous blog entry here.

Several months after the Summit decision was published, EPA issued a policy directive stating that it would continue to consider interrelatedness in determining adjacency when making source determinations in areas outside the jurisdiction of the Sixth Circuit. For more on the Summit directive, see our previous blog entry here.

An industry group brought suit in the D.C. Circuit against EPA, arguing that its Summit directive resulted in a competitive disadvantage for industries located outside of the Sixth Circuit. EPA raised procedural arguments related to standing, ripeness, and finality of agency action. The agency also argued that it is not required to ensure national uniformity in response to judicial decisions.

At the outset, the Court dismissed the agency’s procedural arguments. On the merits, the Court pointed to EPA’s “Regional Consistency” regulations which require the agency to “[a]ssure fair and uniform application by all Regional Offices of the criteria, procedures, and policies employed in implementing and enforcing” the Clean Air Act. See 40 C.F.R. § 56.3 (a). Thus, the Court concluded that EPA’s own regulations require it to achieve national uniformity in how CAA permitting rules are applied, and that nothing in the regulations exempted inconsistencies created by a judicial decision. See National Environmental Development Association’s Clean Air Project v. U.S. Environmental Protection Agency, No. 13-1035, slip op. at 17 (D.C. Cir. May 30, 2014).

The Court disagreed with EPA’s contention that the doctrine of intercircuit nonaquiescence required a different result. The doctrine has been raised by agencies refusing to acquiesce to a decision of an individual circuit court that contravenes other circuits, in the hope that the individual court’s decision will ultimately be overturned by the Supreme Court or Congress. The Court stated that the doctrine “does not allow EPA to ignore the plain language of its own regulations.” Id. at 19. The Court noted that EPA may 1) revise its regulations to require aggregation when there is functional interdependence, or 2) revise its uniformity regulations. Finally, the Court noted that the agency chose not to appeal the Sixth Circuit decision to the U.S. Supreme Court. Id. at 18.

The Court’s decision is good news for the oil and gas industry. Now, on a nationwide basis, exploration and production facilities will only need to be aggregated for major source determinations if they are “adjacent” in an ordinary sense of the word—bearing in mind, of course, that there may still be some uncertainty about what “adjacent” means in the oil patch.

In addition, as a practical matter, the Court’s decision places an even greater emphasis on the choice of forum for litigation challenging CAA permitting regulations or policy. If EPA loses in one federal appeals court, the agency would be forced to eliminate any regional inconsistency, with its only other recourse being an appeal to the Supreme Court or formal agency rulemaking.

EPA and Army Corps of Engineers Propose Significant Revisions to Definition of "Waters of the United States"

By Lesley Foxhall Pietras

On March 25, 2014, the Environmental Protection Agency (“EPA”) and the Army Corps of Engineers (“Corps”) jointly released a proposed rule purporting to clarify the scope of the “waters of the United States” protected under the Clean Water Act. The agencies claim that, as a result of the Supreme Court’s decision in Rapanos v. United States, 547 U.S. 715 (2006), the scope of regulatory jurisdiction in the proposed rule is narrower than under the existing regulations. It appears, however, that the proposed rule actually expands the scope of the waters regulated by the Act.

Rapanos considered whether wetlands, located near ditches or man-made drains that emptied into traditional navigable waters, fell within the scope of the Clean Water Act. A four-justice plurality interpreted the term “waters of the United States” as covering those “relatively permanent, standing or continuously flowing bodies of water,” Rapanos, 547 at 739, that are connected to traditional navigable waters, and wetlands with a “continuous surface connection” to such relatively permanent water bodies, id. at 742. In contrast, in a concurring opinion, Justice Kennedy concluded that “waters of the United States” includes wetlands with a “significant nexus” to traditional navigable waters. Id. at 779. He further stated that wetlands possess the requisite nexus if they “either alone or in combination with similarly situated lands in the region, significantly affect the chemical, physical, and biological integrity” of traditional navigable waters. Id. at 780.

EPA and the Corps have imported the “significant nexus” standard from Justice Kennedy’s concurring opinion into the proposed rule, applying it not only to adjacent wetlands (the subject of Rapanos), but also to other categories of water bodies, such as tributaries of traditional navigable waters or interstate waters, and to “other waters” (that is, waters not fitting in another category). For example, the agencies represent that all tributary streams are physically and chemically connected to downstream traditional navigable waters, interstate waters, and the territorial seas via channels and associated alluvial deposits. Based on this assertion, the agencies propose that all waters that meet the new regulatory definition of “tributary” are “waters of the United States” by rule, without the need for a case-specific analysis. The agencies propose to define tributaries in reference to physical characteristics (the presence of a bed and banks and an ordinary high water mark) and contribution of flow to traditional navigable waters, interstate waters, territorial seas, and impoundments. The proposal specifies that a tributary “can be a natural, man-altered, or man-made water” and includes waters “such as rivers, streams, lakes, ponds, impoundments, canals, and ditches” not otherwise excluded. Moreover, contrary to the plurality opinion in Rapanos, the proposal provides that the flow “may be ephemeral, intermittent or perennial.”

Based on the “significant nexus” standard, the proposed rule also defines “waters of the United States” to include all waters – not just wetlands – adjacent to a traditional navigable water, interstate water, the territorial seas, impoundment or tributary. The proposed rule defines “adjacent” as bordering, contiguous, or “neighboring,” and then expansively defines “neighboring” as including waters located within the “riparian area” or “floodplain” of traditional navigable waters, interstate waters, territorial seas, covered impoundments, or covered tributaries, or waters with a shallow subsurface hydrological connection to such a jurisdictional water.

Finally, based on Justice Kennedy’s “significant nexus” standard, the proposed rule modifies the definition of “other waters” (that is, those waters not fitting in another category under “waters of the United States”). In the current regulation at 40 C.F.R. § 122.2, “other waters” are defined based on whether they could affect interstate or foreign commerce. The proposed rule deletes this language. Instead, it states that “other waters” are “waters of the United States” on a case-specific basis, where those waters alone, or in combination with other similarly situated waters located in the same region, have a “significant nexus” to – that is, significantly impact the chemical, physical, or biological integrity of – a traditional navigable water, interstate water, or the territorial seas.

Thus, in some aspects, the proposed rule expands the scope of waters protected under the Clean Water Act, and industry may wish to comment on the rule. Comments will be accepted for 90 days after the proposed rule is published in the Federal Register. EPA has submitted the proposed rule for publication in the Federal Register, but it has not been published yet. An unofficial version of the proposed rule is available here.

TCEQ Updates Penalty Policy Document to Incorporate Legislative Enactments and Current Enforcement Practices

By Carlos J. Moreno

On January 6, 2014, TCEQ requested comments on a proposal to revise the agency’s penalty policy. See Revised Penalty Policy (PDF). According to TCEQ, the proposed revision to its Policy simply incorporates recent statutory changes and documents existing enforcement practices.

Recent Statutory Changes

House Bill 2615 (PDF) (83rd Legislature, 2013) significantly increased the administrative penalties for a water right holder’s failure to submit an annual water use report to TCEQ. Under the new statutory structure, a large water rights holder may have to pay as much as $500 per day for this violation. TCEQ has revised its penalty policy to incorporate this change.

Similarly, the Texas Legislature gave TCEQ the ability to assess administrative penalties to aggregate production operations that fail to register with the agency. Here, “aggregate” refers to commonly recognized construction materials. TCEQ can now assess penalties of up to $10,000 per year for this violation. The revised penalty policy incorporates this change.

Documenting Existing Practices

The revised penalty policy includes information about specific conditions that must be met for the agency to consider a request for payment deferral for an administrative penalty. In addition, the executive director is given discretion to recommend a conditional deferral of up to 100% for certain violations. Penalty deferral is contingent on compliance with the corresponding Administrative Order.

The revised penalty policy will allow for consideration of good faith efforts to comply in the penalty assessment for each violation, regardless of whether it is a discrete or continuous violation. Finally, the penalty policy has been reorganized to better correlate with the TCEQ Penalty Calculation Worksheet.

The deadline for submitting comments to these Policy revisions is February 5, 2014. 

New Texas Law Encourages Recycling of Wastewater From Oil and Gas Operations by Clarifying Ownership and Limiting Tort Liability

By Jillian Marullo

House Bill 2767, which took effect on September 1, 2013, was enacted to encourage recycling of the wastewater produced in hydraulic fracturing (or “fracking”) and other oil and gas operations.

A hotly contested issue is the consumption of water by fracking activities. Fracking involves the injection of several millions of gallons of water, combined with sand and small amounts of chemicals, into underground formations to fracture the rock in order to release deposits of oil and gas trapped in the rock. On average, over 83,000 barrels (or 3.5 million gallons) of water is required to frack one horizontal well, many of which are fracked multiple times. Much of this water returns to the surface as wastewater, along with underground saltwater known as produced water. In addition, for every barrel of oil or gas produced by a well, it is estimated that 7-9 barrels of wastewater are generated.

The wastewater produced in fracking operations is considered unusable because it contains chemicals, salt, leached minerals and other oil and gas wastes. Thus, instead of being reused in a subsequent frack job, it is most commonly disposed of deep underground by injection into disposal wells. In 2011, 3.5 billion barrels of wastewater were disposed of in Texas injection wells. When fracking wastewater is disposed of in injection wells, it is permanently lost to the water cycle. HB 2767 was intended to lessen this burden on water resources in Texas.

According to the bill’s author, Rep. Phil King, one obstacle to recycling fracking wastewater is the legal ambiguity about the ownership of oil and gas waste transferred for treatment. HB 2767 adds Chapter 122 to the Natural Resources Code to remove this barrier so that fracking wastewater may be more easily recycled and reused in subsequent operations.

The bill shifts ownership from the producer of the wastewater (i.e., the driller) to the company engaged to treat it for subsequent reuse (a “recycler”). Specifically, the bill provides that, unless otherwise provided by contract, ownership of the wastewater will be determined by possession and the purpose of the transfer. When the wastewater is transferred to a recycler “for the purpose of treating the waste for a subsequent beneficial use,” it becomes the property of the recycler and remains so until the recycler transfers the wastewater to another person “for disposal or use.” When the recycler transfers the treated wastewater or any byproduct to another person “for the purpose of subsequent disposal or beneficial use,” the transferred product or byproduct becomes the property of the person to whom it is transferred.

HB 2767 also limits the tort liability of recyclers who take possession of wastewater and produce from it “a treated product . . . suitable for use in connection with the drilling for or production of oil or gas.” Once the recycler transfers the treated product to another person who agrees to use the product in oil and gas activities, the recycler is immune from liability for any “consequence of the subsequent use of that treated product” by the transferee or any other person, except for personal injury, death or property damage resulting from exposure to the initial waste or treated product.

The bill requires the Railroad Commission of Texas to adopt rules to govern the treatment and beneficial use of oil and gas waste. 

Texas Legislature Allows Saltwater Pipeline Operators to Build Pipelines Along Public Roadways for Disposal of Fracking and Other Drilling Wastewater

By Jillian Marullo

Senate Bill 514, signed into law on June 14, 2013, authorizes saltwater pipeline operators in Texas “to install, maintain, and operate” saltwater pipelines “through, under, along, across, or over a public road” in order to transport the wastewater produced by hydraulic fracturing operations to disposal sites. The bill, which was introduced by Sen. Wendy Davis, D-Fort Worth, received widespread support from environmental groups and the energy industry alike, including groups as diverse as the Sierra Club and the Texas Oil and Gas Association, and was unanimously approved by the Senate.

SB 514 was enacted to ease the burden placed on public roads by trucks transporting oil and gas waste produced by hydraulic fracturing. Hydraulic fracturing (or “fracking”) is a drilling process whereby water mixed with small amounts of chemicals and sand is injected under extreme pressure into deep underground rock formations to fracture the rock in order to break up the trapped oil and gas deposits and aid in their flow to the surface. A large portion of the millions of gallons of freshwater used in fracking operations returns to the surface as wastewater, along with the highly saline water contained in the formations.

The wastewater produced at fracking production sites is generally disposed of in underground disposal or injection wells. According to the Railroad Commission of Texas, there are more than 50,000 injection and disposal wells in Texas, with approximately 35,000 actively servicing the more than 295,000 active drilling wells. Currently, vacuum trucks are used to transport the millions of gallons of fracking wastewater generated at production sites to disposal or injection wells. This truck traffic has damaged roads, particularly those in rural counties. In an effort to address community concerns over the use of roadways by heavy trucks, the Texas legislature passed SB 514 to shift the transportation of fracking wastewater from the roads to pipelines, reducing the need for overweight trucks.

SB 514 expands the use of saltwater pipelines to haul fracking wastewater from drill sites to disposal wells by providing the energy industry with a right-of-way to place new saltwater pipelines along public roads, eliminating the need to construct saltwater pipelines over private land. The bill amends Chapter 91 of the Natural Resources Code to allow “a saltwater pipeline operator to install, maintain, and operate a saltwater pipeline . . . through, under, along, across, or over a public road” if the pipeline facility complies with applicable Texas Transportation Commission and county and municipal regulations regarding the accommodation of utility facilities on public roads. In addition, the pipeline operator must “promptly restore[]” the road to its “former condition of usefulness” after the installation or maintenance of the pipeline. The pipeline operator must lease the right-of-way and pay the government the fair market value of the operator’s use of the right-of-way. The bill also provides that a pipeline operator may be required, on 30 days’ notice, to relocate a pipeline.

Subsequent Purchaser Doctrine Defeats Civil Code Art. 667 Claims by Neighbor

On September 13, 2013, the Louisiana Supreme Court denied Plaintiff-landowners’ writ application seeking review of an opinion of the Louisiana First Circuit Court of Appeal granting Defendants’ exception of no right or cause of action based on the subsequent purchaser doctrine. Day v. Northrop Grumman Ship Systems, Inc., 13-0952 (La. 9/13/13), 2013 La. LEXIS 1898. And on October 11, the Supreme Court denied Plaintiff-landowners procedurally rare Motion for Rehearing on the writ denial. Day v. Northrop Grumman Ship Systems, Inc., 13-0952 (La. 10/11/13), 2013 La. LEXIS ----. The Plaintiffs, who owned property adjacent to a former Superfund Site, sought damages under C.C. Art. 667 for alleged contamination of their property. The decision rejected Plaintiffs’ argument that C.C. Art. Code 667 rights of action are “real” rather than “personal” rights, outside of the scope of the subsequent purchaser doctrine.

For more information, please contact Bob Holden, Steve Wiegand, or Megan Spencer.

New Texas Legislation Authorizes TCEQ to Permit Greenhouse Gas Emissions

By Jillian Marullo

House Bill 788, signed into law on June 14, 2013, authorizes the Texas Commission on Environmental Quality (“TCEQ”) to regulate emissions of carbon dioxide and five other greenhouse gases (“GHG”) “[t]o the extent that greenhouse gas emissions require authorization under federal law.” The legislation gives TCEQ the authority to issue permits authorizing GHG emissions and develop rules governing the permitting process as well as rules for transitioning the process away from the United States Environmental Protection Agency (the “EPA”) to TCEQ. In a nod to the State of Texas’ opposition to the federal GHG permitting requirements, the law requires TCEQ to repeal any rules promulgated pursuant to this grant of authority should federal law cease to require permits for GHG emissions. Under the bill, the GHG permitting process will be exempt from TCEQ’s contested case hearing requirements in an effort to make the process more efficient.

Currently, major sources of GHG emissions in Texas are required to obtain a permit from the EPA. The federal Clean Air Act allows the EPA to delegate permitting authority to states that adopt and follow an EPA-approved State Implementation Plan (“SIP”). However, Texas lacks the authority to implement a GHG permitting program because at the time the EPA began requiring SIPs to cover GHG emissions, Texas law did not authorize TCEQ to regulate GHGs or other new pollutants identified solely by the EPA. Instead, TCEQ is only authorized to regulate those pollutants specifically identified by the Texas legislature. Because the legislature only meets every two years, TCEQ could not obtain authorization until the 2013 legislative session. Thus, because TCEQ missed the EPA’s 2011 deadline, the EPA imposed a Federal Implementation Plan (“FIP”) under which GHG permits for Texas sources are issued directly by the EPA.

HB 788 was enacted to allow TCEQ to take over and streamline the permitting process. Once TCEQ rules are enacted and approved by the EPA, they should eliminate the lengthy delays encountered by Texas applicants seeking GHG permits from EPA Region 6, which have allegedly resulted in millions in lost revenue. The bill was authored by Rep. Wayne Smith, an strong industry supporter, and is backed by environmentalists as well as industry leaders anxious to avoid the bottlenecking experienced at Region 6.

The transition of permitting authority from the EPA to TCEQ will take place in three phases. First, TCEQ will, in conjunction with public commenting, propose and adopt a regulatory program that will allow it to become the permit authority for sources of GHG emissions in Texas. HB 788 directs TCEQ to adopt rules to implement the permitting process and procedures for shifting review of applications pending before the EPA to TCEQ. Several chapters in the Texas Administrative Code relating to air permitting and public notice will need to be amended, including chapters 39, 55, 101, 106, 116 and 122. Once these changes are made, the new rules must be approved by the EPA as part of a revision to the Texas SIP. Finally, before TCEQ can begin reviewing applications and issuing permits for GHG emissions, the EPA must withdraw the FIP currently in place. Until this process is complete, the EPA will remain the permitting authority for GHG emissions in Texas.

Draft rules are expected to be made public by October 4, 2013, with responses to public comments being made by the end of 2013. The rules will likely be adopted in early 2014 and will become effective immediately. EPA approval of the adopted rules and withdrawal of the current FIP is expected to occur, if all goes as planned, in May or June 2014.

The State of Texas brought a lawsuit against the EPA challenging its authority to impose a FIP to issue GHG permits. In July 2013, the D.C. Circuit ruled for the EPA, upholding the district court’s dismissal of the suit on the grounds that the state lacked standing. Texas v. EPA, No. 10-1425, 2013 U.S. App. LEXIS 15210 (D.C. Cir. July 26, 2013). However, the case is still pending before the D.C. Circuit as the court has extended the time to file a petition for rehearing.

Louisiana's New Twenty-Day Deadline for Hydraulic Fracturing Reporting Requirements

By Sarah Y. Dicharry

On July 20, 2013, the Louisiana Department of Natural Resources amended its reporting and disclosure requirements for hydraulic fracturing stimulation operations. 39 La. Reg. 1824 (July 20, 2013). The amendment does not significantly alter the substance of the reporting requirements, but it imposes a new twenty-day reporting deadline (required by a 2012 statutory amendment). See La. Rev. Stat. § 30:4. The rule requires operators to report the types and volumes of hydraulic fracturing fluid used, the additives used, the chemical ingredients of the hydraulic fracturing fluid, and the concentrations of those chemical ingredients. Specifically, the new reporting deadline requires operators to report within twenty days from the date that hydraulic fracturing stimulation operations are completed. Before the amendment, the regulation did not specify a reporting deadline. The amendment is important due to the statutory penalties associated with noncompliance. Under La. Rev. Stat. § 30:18, violators of the rule are subject to mandatory civil penalties of “not more than five thousand dollars a day for each day of violation and for each act of violation.” 

Fifth Circuit Vacates $6 Million Clean Water Act Penalty

By Greg Johnson and Stephen Wiegand

In a July 17, 2013 decision, the United States Court of Appeals for the Fifth Circuit vacated a $6 million dollar penalty levied under the Clean Water Act (“CWA”) against CITGO Petroleum Corporation (“CITGO”) and remanded the matter to the Western District of Louisiana for further consideration. See U.S. v. CITGO Petroleum Corp., Case No. 11-31117 (5th Cir. July 17, 2013) (pdf).

The case relates to a 2006 oil spill which occurred at CITGO’s Lake Charles, Louisiana, refinery. After a two-week bench trial, the District Court found that CITGO was merely negligent (rather than grossly negligent) under the CWA; that approximately 54,000 barrels of oil had spilled; and that a penalty of $111 per barrel was reasonable in light of the evidence presented, for a total penalty of $6 million.

The Fifth Circuit vacated the District Court’s penalty determination, finding that the District Court failed to adequately quantify the economic benefit that CITGO realized from the spill as required under the CWA. The District Court determined that quantifying the economic benefit to CITGO was almost impossible given the conflicting evidence presented. The District Court concluded that the economic benefit was in the range of less that $83 million as argued by the government but more than $719 as argued by CITGO. The Fifth Circuit reasoned that consideration of economic benefit is integral to arriving at an appropriate damage award under the CWA penalty analysis, therefore, the District Court was required to make an actual estimate of economic benefit, even if it was difficult to do so in light of the conflicting evidence. The Fifth Circuit concluded that the broad range set by the District Court in actuality “left economic benefit as s non-factor.” Opinion, p. 7. Thus, the District Court erred in its penalty calculation.

The Fifth Circuit did not expressly reverse the District Court’s determination that CITGO was merely negligent rather than grossly negligent. However, the Court noted that on remand, the District Court “should reconsider all its findings with respect to CITGO’s conduct, giving special attention to what CITGO knew prior to the oil spill and its delays in addressing recognized deficiencies.” Opinion, pp. 13-14.

This opinion from the Fifth Circuit is likely to have wide-ranging effects on CWA penalty cases. At a minimum, it appears that a calculation of economic benefit will be a required element of any penalty determination by a district court. The CITGO case may continue to provide insight as it progresses on remand and any subsequent appeals.

You Cannot Just Read the Regulations to Understand Stormwater Permitting for Oil and Gas Activities!

By Carlos J. Moreno and Robert E. Holden

EPA’s most recent NPDES regulations for stormwater permitting of oil and gas facilities were vacated by the Ninth Circuit in 2008 and new regulations have not been promulgated. To understand the stormwater permit requirements for oil and gas activities, you need to review not only the regulations that remain in force, but also the Clean Water Act as amended by the Energy Policy Act of 2005.

The 1987 amendments to the Clean Water Act (“CWA”) added language creating a permitting exemption for uncontaminated runoff from Oil and Gas operations. CWA §402(l)(2). EPA subsequently issued regulations implementing this exemption. As a result, operators of oil and gas exploration, production, processing, or treatment operations, or transmission facilities, with a stormwater discharge only had to obtain a permit for this discharge if the facility (1) had a discharge of a reportable quantity of hazardous substance, (2) had a discharge of a reportable quantity of oil, or (3)contributed to a violation of a water quality standard. 40 CFR §122.26(c)(1)(iii).These three conditions became in essence EPA’s definition of “contaminated stormwater” for purposes of the Act. The regulations clarified that the permitting exemption only applied to oil and gas operational activities; thus, construction activities were not included in CWA §402(l).

In 2005, the Energy Policy Act changed the stormwater permitting requirements by redefining the term “operations” in CWA §402(l) to now include construction activities. The following year, EPA promulgated regulations implementing the expanded permitting exemption. The regulations, among other things, clarified that a stormwater stream with sediment as the only pollutant did not trigger permitting even if there was contribution to a violation of a water quality standard. Thus, under the 2006 regulations, stormwater from Oil &Gas sites that only contained sediment was always exempt from permitting.

The 2006 regulations were judicially challenged and eventually vacated. See Natural Resources Defense Council v. United States Environmental Protection Agency, 526 F.3d 591 (9th Cir. 2008). EPA has not promulgated new regulations to replace them. Therefore, the 2005 Energy Policy Act modifications, along with regulations already in place before then, are the “last word” on the question of stormwater permitting requirements for Oil and Gas sites.

If stormwater permitting is required, we suggest a careful review of NPDES stormwater delegation and the potential applicability of the 2008 Multi-Sector General Permit (“MSGP”) or the 2012 Construction General Permit (“CGP”). See 73 Fed. Reg. 56,572 (Sept. 29, 2008); 77 Fed. Reg. 12,286 (Feb. 29, 2012). Alternatively, in some cases, individual permits may be needed.

The Good Neighbor Provision on Steroids: Third Circuit Ruling Resurrects Clean Air Act Section 126(b)

By Lesley Foxhall Pietras

A recent opinion by the United States Court of Appeals for the Third Circuit has breathed new life into Clean Air Act Section 126(b), which allows downwind state and local governments to petition the Environmental Protection Agency (“EPA”) for immediate relief from interstate pollution caused by a major source (or a group of sources) in an upwind state. In the recent ruling, the Third Circuit held that it was reasonable for EPA to interpret Section 126(b) to be an “independent mechanism for enforcing interstate pollution control,” thereby giving EPA authority to directly regulate a specific source in an upwind state. See GenOn REMA, LLC v. EPA, No. 12-1022, slip op. at 29 (3d Cir. July 12, 2013) (pdf).

Specifically, Section 126(b) provides that:

Any State or political subdivision may petition the Administrator for a finding that any major source or group of stationary sources emits or would emit any air pollutant in violation of the prohibition of [the “good neighbor” provision] or this section. Within 60 days after receipt of any petition under this subsection and after public hearing, the Administrator shall make such a finding or deny the petition.

42 U.S.C. § 7426(b). The “good neighbor” provision, in turn, prohibits sources within one state from emitting air pollutants in amounts that significantly contribute to the nonattainment of the national ambient air quality standards (“NAAQS”) in another state. Id. § 7410(a)(2)(D)(i). If EPA finds, pursuant to a Section 126(b) petition, that the upwind source is violating the “good neighbor” provision, the polluting source must cease operations within three months of EPA’s finding. Id. § 7426(c). EPA may, however, allow the source to continue operations beyond three months if the source “complies with such emissions limitations and compliance schedules … as may be provided by the Administrator” to bring about compliance “as expeditiously as possible, but in no case later than three years after the date of such finding.” Id.

In the recent Third Circuit case, the New Jersey Department of Environmental Protection filed a petition under Section 126(b), requesting that EPA issue an order restricting sulfur dioxide emissions from Portland Generating Station (“Portland”), a coal-fired, electricity generating plant in Pennsylvania that is within 500 feet of Knowlton Township in Warren County, New Jersey. Following notice and comment, EPA granted the petition, concluding that Portland’s sulfur dioxide emissions significantly contribute to nonattainment and interfere with maintenance of the 1-hour sulfur dioxide NAAQS in New Jersey. EPA authorized the continued operation of Portland but imposed emissions limits and compliance schedules to bring Portland into compliance.

GenOn REMA, LLC (“GenOn”), the owner and operator of Portland, petitioned for review of EPA’s action, challenging the agency’s authority to impose direct regulations on Portland before the time that Pennsylvania is required to complete its Section 110 State Implementation Plan (“SIP”) for the 1-hour sulfur dioxide NAAQS. According to GenOn, EPA’s action offended the cooperative federalism structure of the Clean Air Act by undermining a state’s power to determine how to achieve air control standards.

The Third Circuit rejected this argument, concluding that the Clean Air Act is unambiguous that EPA can make a finding on a Section 126(b) petition without regard to the Section 110 SIP process. The court stated that “[t]he plain language of the relevant portions of the statute and the context in which such language is used convey that Congress intended Section 126(b) as a means for the EPA to take immediate action when downwind states are affected by air pollution from upwind sources.” GenOn REMA, No. 12-1022, slip op. at 18. Even if the statute were deemed ambiguous, however, the court found that EPA’s construction of the statute was reasonable. Based on the legislative history, the court concluded that “Section 126(b) was intended to allow the EPA, as a federal regulator, to intervene when states fail to adhere to the air pollution control process.” Id. at 22.

Finally, the court rejected GenOn’s argument that EPA’s action was arbitrary and capricious because it requires a reduction in sulfur dioxide emissions at Portland before requiring similar reductions from sources in New Jersey and prior to the time that SIPs addressing the new NAAQS are required. According to the court, once EPA independently determined that Portland was contributing to nonattainment and interfering with New Jersey’s air quality, “it reasonably abided by the Clean Air Act” in requiring Portland to undertake emissions reductions “as expeditiously as practicable, but in no case later than three years after the date of such finding.” Id. at 27 (quoting 42 U.S.C. § 7426(c)). Further, the court noted that it was satisfied that EPA had thoroughly examined the relevant scientific data.

In the wake of the Third Circuit’s ruling, it is possible that more states and local governments will file Section 126(b) petitions, and that EPA may be more receptive to such petitions.

Update: Supreme Court Will Review EPA's Cross-State Air Pollution Rule

By Lesley Foxhall Pietras

On June 24, 2013, the U.S. Supreme Court granted the petitions for writs of certiorari filed by the U.S. Environmental Protection Agency (“EPA”) and the American Lung Association in the litigation involving EPA’s Cross-State Air Pollution Rule (“CSAPR”). The CSAPR sets limits on sulfur dioxide and nitrogen oxides from power plants in 28 upwind states in the eastern part of the country. On August 21, 2012, in a 2-1 decision, the D.C. Circuit vacated the rule, concluding that EPA exceeded its authority under the Clean Air Act by forcing states to reduce their emissions by more than an amount determined to be their “significant contribution” to nonattainment in other states, and that EPA improperly issued federal implementation plans to implement the CSAPR without providing the states with an initial opportunity to implement the required reductions for sources within their borders.

The Supreme Court limited its review to the questions presented in EPA’s petition, which are: (1) whether the D.C. Circuit lacked jurisdiction to consider the challenges on which it granted relief; (2) whether states are excused from adopting state implementation plans prohibiting emissions that “contribute significantly” to air pollution problems in other states until after EPA has adopted a rule quantifying each state’s interstate pollution obligations; and (3) whether EPA permissibly interpreted the statutory term “contribute significantly” so as to define each upwind state’s “significant” interstate air pollution contributions in light of the cost-effective emissions reductions it can make to improve air quality in polluted downwind areas, or whether the Clean Air Act instead unambiguously requires EPA to consider only each upwind state’s physically proportionate responsibility for each downwind air quality problem.

The two consolidated cases the Supreme Court agreed to hear are EPA v. EME Homer City (No. 12-1182) and American Lung Association v. EME Homer City Generation (No. 12-1183). Both the Supreme Court’s order (pdf) and EPA’s petition (pdf) are available online. 

D.C. Circuit Upholds EPA Authority to Retroactively Veto CWA Section 404 Permits Issued by the U.S. Army Corps of Engineers

By Bob Holden and Jillian Marullo

On April 23, 2013, in a case of first impression, the D.C. Circuit Court of Appeals held that the EPA’s veto authority under section 404(c) of the Clean Water Act (CWA), 33 U.S.C.§ 134(c), “clearly and unambiguously” includes the power to retroactively revoke portions of a Section 404 dredge and fill permit issued by the U.S. Army Corps of Engineers (“Corps”). Mingo Logan Coal Co. v. EPA, 714 F.3d 608 (D.C. Cir. 2013). As provided in Section 404(a) of the CWA, Section 404 permits are more precisely permits “for the discharge of dredge and fill material into the navigable waters at specified disposal sites.” Section 404(c) of the CWA authorizes the EPA “to prohibit the specification (including the withdrawal of specification) of any defined areas as a disposal site, and . . . to deny or restrict the use of any defined area for specification (including the withdrawal of specification) as a disposal site whenever [it] determines” that the discharge will have an “unacceptable adverse effect” on environmental resources. The Mingo decision upheld the EPA’s withdrawal of disposal site specifications in a permit four years after the Corps had issued the permit.

The Mingo permit was issued in conjunction with one of the largest mountaintop coal mining projects ever authorized in West Virginia. In 2007, after a lengthy and litigious review process, the Corps, without objection from the EPA, issued a permit authorizing Mingo Coal to discharge material into three streams and their tributaries. Although the EPA had expressed its environmental concerns to the Corps during the permitting process, it did not exercise its veto power before or at the time of issuance. In fact, the EPA stated in an email to the Corps, “We have no intention of taking our [Mingo Coal permit] concerns any further from a Section 404 standpoint.”

In 2009, the EPA requested that the Corps revoke or modify the Mingo permit, but the Corps refused, finding no factors present requiring modification. The EPA then initiated its veto process through notice and comment action. In 2011, four years after the permit was issued, the EPA officially invoked 404(c) to veto the specification of two of the three streams as disposal sites in the Mingo permit, amounting to a nearly 88 percent reduction in the total authorized discharge area.

Louisiana Adopts EPA Revision to Condensable PM Requirements in its Definition of "Regulated NSR Pollutants"

By Megan J. Spencer

On October 25, 2012 the Environmental Protection Agency (EPA) published its corrected definition of “regulated NSR pollutant.” The Louisiana Department of Environmental Quality (LDEQ) adopted EPA’s revised definition of “regulated new source review (NSR) pollutant” at LAC 33:III.509.B in a May 20, 2013 Louisiana Register Notice. 39 La. Reg. 1280 (May 20, 2013). LDEQ’s definition of “regulated NSR pollutant” is now consistent with the corrected federal definition found at 40 C.F.R. § 51.166(b)(49). The revision to the federal and state rule “removes a general requirement in the definition of ‘regulated NSR pollutant’ to include condensable PM when measuring one of the emissions-related indicators for particulate matter (PM) known as ‘particulate matter emissions’ in the context of the PSD and NSR regulations.” 77 Fed. Reg. 65107 (Oct. 25, 2012). The revised definition of “regulated NSR pollutant” states:

PM2.5 emissions and PM10 emissions shall include gaseous emissions from a source or activity which condense to form particulate matter at ambient temperatures. On or after January 1, 2011, such condensable particulate matter shall be accounted for in applicability determinations and in establishing emissions limitations for PM2.5 and PM10 in PSD permits. Compliance with emissions limitations for PM2.5 and PM10 issued prior to this date shall not be based on condensable particulate matter. Applicability determinations made prior to this date without accounting for condensable particulate matter shall not be considered in violation of this Section.

LAC 33:III.509.B. Thus, the rule removes the unintended new requirement on state and local agencies and the regulated community to include condensable PM fractions in the measurement of “particulate matter emissions.”

The rule, however, preserves the requirement to include condensable PM measurements for “particulate matter emissions” where required by other regulations. EPA provided three cases where it may be necessary for sources to count condensable PM fraction for “particulate matter emissions:”

  1. Sources subject to New Source Performance Standard (NSPS) for which condensable PM fraction must be included in the determination of compliance with the standard of performance for PM (see, e.g. 40 C.F.R. § 60.50Da);
  2. Sources where the applicable State Implementation Plan (SIP) already requires the condensable fraction to be included in the measurement of “particulate matter emission;” and
  3. Sources required by the reviewing authority to include condensable PM fractions in the measurement of “particulate matter emission.”

Additionally, measurement of condensable PM continues to be required in all cases for emissions of PM10 and PM2.5. Thus, PM is currently regulated under the Prevention of Significant Deterioration (PSD) program as three separate regulated pollutants: (1) PM10; (2) PM2.5; and (3) particulate matter emissions. Proposed new and modified sources must treat each indicator of PM as a separate regulated pollutant and must consider when measurements of condensable PM are required.

Perhaps the greatest benefit of this rule change will be to permittees whose emission limits were written prior to widespread consideration and measurement of condensable PM. Many facilities found themselves in the position of having to count condensable PM against a limit that had been set only for filterable PM, but this change will provide relief from what may have otherwise been permit violations. The rule should serve as a reminder to those same permittees and permit applicants that condensable PM must be considered in setting emission limits in future permits or renewals.

EPA to Improve Oil and Gas Sector Air Emissions Data in Response to Inspector General's Report

By Lesley Foxhall Pietras

On April 18, 2013, the U.S. Environmental Protection Agency (EPA or Agency) committed to improving air emissions data for the oil and natural gas production sector. EPA made this commitment in response to the Office of Inspector General’s February 20, 2013 report, “EPA Needs to Improve Air Emissions Data for the Oil and Natural Gas Production Sector” (pdf) (Report). The Office of the Inspector General is an independent office within EPA that promotes “economy, efficiency, effectiveness” and prevents and detects fraud and abuse.

In the Report, the Inspector General concluded that EPA’s directly measured air emissions data on criteria and air toxic pollutants for important oil and gas production processes and sources is very limited. This type of data is used to develop emissions factors, which EPA and states rely on to estimate air emissions. According to the Inspector General, “[l]imited data from direct measurements, poor quality emissions factors, and incomplete [National Emissions Inventory] data hamper EPA’s ability to assess air quality impacts from oil and gas production activities.” Report at p. 10. The Report indicates that the Inspector General is particularly concerned about emissions factors for the following oil and gas production processes and sources: internal combustion engines, process heaters, flares and enclosed combustors, dehydrators, tanks (condensate, storage, oil, etc.), amine treaters, evaporative ponds, produced water tanks, well completions, and pneumatic devices. Id. at 13-14.

Based on its findings, the Inspector General recommended that EPA develop and implement a comprehensive strategy for improving air emissions data for the oil and gas production sector; prioritize which oil and gas production emissions factors need to be improved; develop additional emissions factors as appropriate; and ensure that the National Emissions Inventory data for this industry sector is complete.

EPA responded to the Report in an April 18, 2013 memorandum from Gina McCarthy (Assistant Administrator for the Office of Air and Radiation) and Lek G. Kadeli (Principal Deputy Assistant Administrator for the Office of Research and Development). Specifically, EPA promised to:

  • Develop a strategy for improving oil and gas sector emissions data, emissions factors, and measurement techniques by the first quarter of 2014, and begin implementing that strategy by the third quarter of 2014;
  • Finalize revised emissions factors development procedures for data collected from traditional test methods by the fourth quarter of 2014 and finalize such procedures with regard to non-traditional measurement techniques by the fourth quarter of 2019;
  • Ensure that the 2011 National Emissions Inventory has a complete estimate for the oil and gas sector for both criteria air pollutants and hazardous air pollutants, by the first quarter of 2014; and
  • Issue final guidance on the method for calculating default nonpoint emission estimates to enter into the National Emissions Inventory when states do not submit nonpoint data for oil and gas production, by the third quarter of 2014.

EPA further noted in its response, however, that the Agency’s “timely execution of the corrective actions is directly dependent upon the availability of resources.”

The bottom line is that EPA will be scrutinizing air emissions factors for the oil and gas sector. Industry thus should be alert to the possibility of data requests from EPA and, in the long-term, changes to emissions factors, which may impact air permitting compliance strategy.

EPA Grants Reconsideration of Certain Oil and Gas Storage Tank NSPS Provisions Issued in August 2012

By Stephen W. Wiegand

On August 16, 2012, EPA issued new source performance standards (NSPSs) for the oil and gas sector. The standards applied to various sources including storage tanks used in crude oil and natural gas production. On April 12, 2013, EPA announced proposed amendments to the rule pertaining to storage tanks.

The proposed rule clarifies that the new NSPS standard applies only to vessels containing crude oil, condensate, intermediate hydrocarbon liquids, or produced water (i.e., vessels likely to emit volatile organic compounds (VOCs)).

Additionally, EPA explains in the proposed rule that it had initially underestimated the number of tanks that would be impacted by the final rule. Further, based on the agency’s revised estimation, there is currently an insufficient supply of control devices available to meet the October 15, 2013, deadline for compliance. Thus, EPA adjusted the compliance schedule as follows:

  • For tanks constructed after April 12, 2013, the proposed rule extends the deadline for compliance to April 15, 2014, or within sixty days after startup, whichever is later.
  • For tanks constructed prior to April 12, 2013, tank owners have until October 15, 2013 to report that the tank is on line and to provide the tank’s geographic coordinates. Further, if there is a change that would potentially increase the tank’s emissions, the owner or operator must install the required controls within sixty days of the change or by April 15, 2014, whichever is earlier.

The proposed rule also includes streamlined monitoring requirements for tanks that have already installed VOC controls and certain alternative emissions limits. Finally, the rule extends the deadline for submitting annual reports from thirty days to ninety days after the end of the compliance period.

Comments on the proposed rule must be submitted by May 13, 2013. EPA anticipates that it will take final action on the proposed rule by July 31, 2013.

For more information, click here

OCS Operators Need to Consider EPCRA Reporting in their Release Reporting Plans

By Robert E. Holden

The recent decision by the U.S. Court of Appeals for the Fifth Circuit in Center for Biological Diversity, Inc. v. BP America Production Co., et al, no. 12-30136 (5th Cir. Jan. 9, 2013) (“CBD”), reversed in part the district court’s dismissal of citizen suit claims against BP in connection with the Deepwater Horizon incident, upholding the citizen suit cause of action seeking to have BP submit EPCRA reports regarding the Macondo spill. CBD remains to be fully adjudicated, but CBD highlights the need for OCS operators to include EPCRA reporting in their release reporting plans.

Under EPCRA, any release that requires CERCLA reporting to the National Response Center requires EPCRA reporting, and any reportable quantity release of EPCRA-listed “extremely hazardous substances” also requires EPCRA reporting. The EPA EPCRA regulations specify that immediate emergency release notification must be provided to: 1) the “community emergency coordinator for the [Local Emergency Planning Committee (LEPC)] of any area likely to be affected by the release,” or if there is no LEPC, “the relevant local emergency response personnel;” and 2) the State Emergency Response Commission of any State “likely to be affected by the release.” 40 C.F.R. § 355.42(a). The EPCRA reporting regulations require both immediate reporting and follow-up written reporting “as soon as practicable.” 40 C.F.R. § 255.43. The CBD suit is focused on the written report provisions.

OCS operators may want to review their emergency release reporting programs to ensure EPCRA compliance.

Air Permitting Update: EPA Ignores Summit Outside Sixth Circuit

By Lesley Foxhall Pietras

On December 21, 2012, the Environmental Protection Agency (EPA) issued a policy announcement addressing how it will deal with source aggregation following the Sixth Circuit’s decision in Summit Petroleum Corp. v. EPA, 690 F.3d 733 (6th Cir. Aug. 7, 2012). (Our previous blog entry on this decision is available here.) In Summit, the Sixth Circuit concluded that the term “adjacent” implies only physical proximity, and EPA’s consideration of functional interrelatedness to combine geographically distant facilities into a single source for air permitting purposes was unlawful. EPA sought panel rehearing of that decision, but its request was denied. Summit Petroleum v. EPA, 2012 U.S. App. LEXIS 23988 (6th Cir. Oct. 29, 2012).

In the recent policy announcement, EPA stated that, due to Summit, the agency “may no longer consider interrelatedness in determining adjacency when making source determination decisions in its title V or NSR permitting decisions in areas under the jurisdiction of the 6th Circuit; i.e., Michigan, Ohio, Tennessee and Kentucky.” Memorandum from Stephen D. Page, Director, Office of Air Quality Planning and Standards, to Regional Air Division Directors, Regions 1-10, at 1 (Dec. 21, 2012), available here (PDF). EPA further declared, however, that it will continue to consider functional interrelatedness in areas outside of the Sixth Circuit. Id. (“Outside the 6th Circuit, at this time, the EPA does not intend to change its longstanding practice of considering interrelatedness in the EPA permitting actions in other jurisdictions.”).

Thus, although there was some hope that the Summit decision would restore adjacency to its plain meaning in all areas of the country, it appears that additional circuit courts will be required to weigh in before this administration adopts such a policy. In the meantime, industry likely will continue to point to Summit for persuasive authority for state or local permitting authorities.

EPA concluded the policy announcement by noting that it “is assessing what additional actions may be necessary to respond” to the Summit decision. Id. EPA therefore is likely still considering whether to file a petition for certiorari with the U.S. Supreme Court. 

DOI Promulgates a New Final Rule for Increased Safety Measures on the OCS

By Sarah Y. Dicharry and Robert E. Holden

After Deepwater Horizon, the President directed the Secretary of the Interior to develop a report concerning safety on the Outer Continental Shelf (“OCS”). In response, the Secretary of the Interior drafted a report entitled, “Increased Safety Measures for Energy Development on the Outer Continental Shelf,” which recommended a number of actions to increase safety. Following the report, the Secretary of the Interior directed BOEMRE to adopt and implement the report’s recommendations. Initially, BOEMRE implemented the recommendations through an interim final rule. In August 2012, BSEE promulgated a new final rule entitled “Oil and Gas and Sulphur Operations on the Outer Continental Shelf--Increased Safety Measures for Energy Development on the Outer Continental Shelf,” to tighten safety measures on the OCS. 77 Fed. Reg. 50856 (Aug. 22, 2012).

One example of the significant changes made by the new rule is the alteration to the decommissioning requirements, located in 30 CFR 250, subpart Q. As with the other areas of change, the changes to the decommissioning regulations seek to implement additional safety measures and promote consistency through the regulations. Specifically, the new final rule adds a section to 30 CFR 250, subpart Q regarding submission of decommissioning applications and reports when a blowout preventer (“BOP”) is used for abandonment operations, 250.1704(g)(1)(ii). 77 Fed. Reg. 50856, 50882 (Aug. 22, 2012). The new section extends the information requirements under section 250.1705 to decommissioning when the abandonment operations involve a BOP and allows operators to use the same BOP equipment in abandonment operations that they use in operations under other subparts of the regulations. 77 Fed. Reg. 50856, 50882, 50897 (Aug. 22, 2012). To promote consistency, it also imposes on operators the same regulatory oversight in decommissioning required in other subparts. 77 Fed. Reg. 50856, 50882 (Aug. 22, 2012). As such, operators must now provide additional information in their decommissioning applications when using a BOP during abandonment operations, including a description of their BOP system components as well as a schematic of the BOP system. 77 Fed. Reg. 50856, 50883 (Aug. 22, 2012). Operators must also incorporate third-party verification that: “blind-sheer rams installed in the BOP stack are capable of shearing any drill pipe under maximum anticipated surface pressure”; “the BOP stack is designed for the specific equipment on the rig and for the specific well design; the BOP stack has not been compromised or damaged from previous service; and the BOP stack will operate in the conditions in which it will be used.” Id. To satisfy the requirements of section 250.1705, operators must include evidence of the third-party’s qualifications, specifically showing that he is “a registered professional engineer, or technical classification society, or a licensed professional engineering firm capable of providing” the required verifications.

The rule makes multiple significant changes, including adoption of methods to assure sufficient redundancy of BOPs, promotion of well integrity, enhancement of well control, and integration of safety considerations at the management level. 77 Fed. Reg. 50856, 50857 (Aug. 22, 2012). The specific informational change regarding decommissioning discussed in this blog is only a glimpse into the new final rule. The implementation of this new final rule concludes the rulemaking efforts begun by the interim final rule in response to the recommendations of the Secretary of the Interior to improve safety on the OCS following the Deepwater Horizon incident.

Implications of NTL 2012-N06 on OSRP Preparation and Review

By Sarah Y. Dicharry and Robert E. Holden

In August 2012, the Bureau of Safety and Environmental Enforcement (“BSEE”) published a Notice to Lessees (“NTL”) seeking to clarify a number of ambiguities regarding BSEE’s interpretation and application of the Oil Pollution Act (“OPA”) regulations that require offshore lessees to prepare and submit regional Oil Spill Response Plans (“OSRPs”). United States Dep’t of the Interior Bureau of Safety and Environmental Enforcement, GUIDANCE TO OWNERS AND OPERATORS OF OFFSHORE FACILITIES SEAWARD OF THE COAST LINE CONCERNING REGIONAL OIL SPILL RESPONSE PLANS, NTL No. 2012-N06 (2012), available here (PDF) [hereinafter NTL 2012-N06]. With this NTL, BSEE seeks to clarify the OPA requirements for OSRPs and encourage lessees to include inventive and flexible response techniques in their OSRPs. Many of the clarifications are based on lessons learned from the Deepwater Horizon incident. To further BSEE’s goals, the NTL provides lessees with instructions for preparing their OSRPs, which are presented in an outline suggesting the organization and contents of OSRPs. While BSEE claims that compliance with the NTL’s instructions is not required for OSRP approval, BSEE strongly recommends compliance and indicates that its review of OSRPs will follow the guidelines established by the NTL.

Among other significant clarifications that BSEE makes in the NTL, the changes relating to the information that operators must include in the “Emergency Response Plan” section of their OSRPs are particularly important. For instance, the regulations require that the Emergency Response Plan identify a qualified individual who has “full authority to implement removal actions. . . .” 30 CFR 254.23. The NTL emphasizes that authority over “removal actions” must specifically include the authority to deploy “surface and subsea containment resources.” NTL 2012 N-06, 3. To demonstrate that a qualified individual listed in the OSRP can adequately respond to a Worst Case Discharge (“WCD”) scenario, the OSRP now must identify the response resources available, including personnel, materials, equipment, and support vessels. Also, 30 CFR 254.23(g) requires that, in the information submitted regarding the Emergency Response Plan, the operator identify procedures that will be used in the event of an actual or threatened spill, which must include “the methods to monitor and predict spill movement.” 30 CFR 254.23(g)(2). The NTL clarifies that “when identifying adequate provisions for monitoring the movement of a spill, you should use the distance of facilities farthest from shore.” NTL 2012 N-06, 5.

In the NTL, BSEE also makes some more minute clarifications in significant areas, including the calculation of WCD scenarios. For instance, 30 CFR 254.26 requires that the WCD discharge scenario be calculated according to the criteria in section 254.47. Section 254.47(a) requires that for “an oil production platform facility, the size of your worst case discharge scenario is the sum” of the factors listed in that section. The NTL provides, “[i]f the WCD scenario is an oil discharge from an oil production facility, calculate the initial volume of the WCD in accordance with the requirements of § 254.47(a).” NTL 2012-N06, at 28 (emphasis added). The NTL goes on to state, “[i]f operating from a production platform, also include the volume of all storage tanks and flowlines, and the volume of oil calculated to leak from a break in any pipelines connected to the facility.” Id. at 28-29 (emphasis added). Thus, for oil production facilities other than platforms, the NTL is consistent with the regulation; however for oil production platform facilities, the NTL seemingly includes additional requirements for calculating the WCD scenario oil volume. Also, Regarding its review of WCD scenarios in OSRPs, BSEE emphasizes that it will now evaluate not only the Effective Daily Recovery Capacity for particular equipment identified in the OSRP but also the availability of other technologies that could effectively respond to WCD scenarios. Further, while the regulations require that a WCD scenario response plan support a spill lasting up to thirty days, BSEE now strongly encourages that lessees identify supplies and materials that can sufficiently respond to a spill lasting longer than thirty days.

After a lessee submits an OSRP, BSEE’s Oil Spill Response Division analyzes the OSRP and determines whether or not it is sufficient to rectify the anticipated WCD scenarios identified therein. After BSEE approves an OSRP, the lessee is responsible for reviewing it every two years. If modifications are made after review, then lessees must submit the modifications to BSEE. Specifically, if a modification results in alteration of a regional OSRP, then the lessee must submit the revision within fifteen days of the change. If no modifications are made after review, then lessees must submit a writing to BSEE indicating that no changes were made. 

Fifth Circuit Reverses District Court's Imposition of Attorneys Fees on DOI for Reissuance of Drilling Moratorium in GOM Following Deepwater Horizon Incident

By Sarah Y. Dicharry and Robert E. Holden

Following the Deepwater Horizon incident in May 2010, the DOI imposed a six-month moratorium on the issuance of new drilling permits in deep water and directed then-operating lessees to stop operations at the soonest time practicable. The DOI implemented the moratorium on issuance of new leases through a directive and Notice to Lessees (NTL), explaining that the DOI would not review applications for leases in deep water for the following six months. The DOI further implemented the moratorium on then-current leases by issuing letters to the lease operators.

In response to the moratorium, Hornbeck (an owner and operator of vessels that support deepwater operations) sued the DOI seeking declaratory and injunctive relief. Specifically, Hornbeck claimed that by issuing the directive and the NTL, the Secretary of the Interior violated the Administrative Procedure Act and exceeded his authority under the Outer Continental Shelf Lands Act. The district court granted the preliminary injunction, which prohibited the DOI from enforcing the Moratorium without providing greater explanation for its authority to do so. The DOI rescinded the initial moratorium and replaced it with second moratorium. The second moratorium was substantively identical to the first, but the DOI provided a more extensive explanation for the moratorium.

After the DOI issued its second moratorium, Hornbeck filed a motion to enforce the preliminary injunction. Specifically, Hornbeck argued that the DOI’s rescission and re-issuance of the moratorium disobeyed the court’s order enjoining enforcement of the initial moratorium. The court denied the motion. Shortly thereafter, the Secretary lifted the second moratorium, effectively mooting Hornbeck’s case.

Hornbeck then sought attorneys fees based on civil contempt and bad-faith litigation tactics. Hornbeck supported the civil contempt claim by demonstrating: (1) the DOI’s failure to seek a remand to the agency before taking additional administrative action; (2) the DOI’s continued public indications that it would reinstate the moratorium; and (3) the DOI’s continued communications to the industry that efforts to establish a new moratorium were underway. The district court found that, through those three actions, the DOI had failed to comply with the injunction. Thus, the district court concluded that Hornbeck established civil contempt by clear and convincing evidence and awarded attorneys fees of approximately $530,000. The district court did not reach the bad-faith litigation tactics issue.

The DOI appealed the district court’s decision to the United States Fifth Circuit Court of Appeals, which considered whether the DOI’s actions, taken without seeking a remand to the agency, violated the written order enjoining the enforcement of the initial moratorium. Hornbeck Offshore Servs., L.L.C. v. Salazar, __F.3d__, 2012 U.S. App. LEXIS 24355 (5th Cir. Nov. 27, 2012). The Fifth Circuit agreed with the district court that the DOI’s actions demonstrated its clear intent to overcome the injunction issued by the district court. However, the Fifth Circuit determined that for the DOI to have been in contempt of the order, the injunction would have had to require that the DOI seek a remand to the agency. Instead, the injunction only mandated that the DOI describe the manner and form of compliance with the injunction within 21 days; it contained no explicit obligation that the DOI seek to remand the decision to the agency before re-implementing a moratorium. Thus, the Fifth Circuit found that neither intending to overcome the injunction nor re-issuing the moratorium actually violated the district court’s order. On this basis, the Fifth Circuit overturned the district court’s award of attorneys fees based on civil contempt.

This Fifth Circuit decision significantly demonstrates that injunctions of regulatory action are limited to their express terms on review. Here it is arguable that the DOI effectively evaded the purpose of the district court’s injunction, and the Fifth Circuit upheld the agency’s actions. Clearly, unless injunctions anticipate and provide for the government’s potential opportunities to evade them, the injunctions may not achieve their purpose.

EPA Finalizes NPDES Permit for Oil and Gas Facilities in the GOM OCS

By Robert E. Holden and Carlos J. Moreno

On October 1st, 2012, the Environmental Protection Agency (“EPA”) released the final NPDES general permit for discharges from oil and gas facilities in the western and central portion of the Outer Continental Shelf of the Gulf of Mexico (the “final permit”). The final permit has yet to be published in the Federal Register, but it is available here.

Operators already covered under the 2007 permit have until January 31, 2013 to file new Notices of Intent (“NOIs”) for continuous coverage. Permit coverage and compliance under the terms of the 2012 permit start when the new NOI is filed.

While many of the changes were already spelled out in the proposed permit, and summarized in our April 12, 2012 blog entry, operators should pay close attention to new provisions related to permit coverage. The final permit defines “Operator” as a party that falls in one of three categories: (1) Primary Operator (leaseholder or designated operator registered with BOEM), (2) Day-to-day Operator, and (3) vessel operator. The Primary Operator is the one that submits the NOI for coverage by block. However, other operators or vessel operators must file separate NOIs for discharges directly under their control but beyond the Primary Operator’s control (unless the Primary Operator already covered those discharges in its NOI).

This new language creates important changes in how discharges from Mobile Offshore Drilling Units (“MODUs”) are permitted in most of the Gulf of Mexico.

  • Typically, the MODU operator will now have to obtain coverage for discharges that are solely controlled by it. These could include deck drainage, sanitary and domestic waste, and Cooling Water Intake Structure (“CWIS”) requirements.
  • To address this issue, Oil and Gas Operators and Drilling Contractors may want to review their contractual provision on NPDES responsibility for all types of discharges.
  • The MODU operator would have to obtain coverage in each lease block they plan to discharge in. The NOI for each new location must be submitted before the MODU commences drilling operations.
  • The OCS operator’s existing discharges must be reauthorized by submission of a new NOI before January 31, 2013. This change may severely impact drilling in the event of expiration of coverage without timely NOI submission, undercutting permit continuation theories under the Administrative Procedures Act.
  • NOI submittal must be done electronically and will require identification of the types of discharges under the control of the operator requesting coverage.

EPA Seeks Rehearing En Banc of D.C. Circuit Panel Decision on Cross-State Air Pollution Rule

By Lesley Foxhall Pietras

On October 5, 2012, EPA filed a petition for en banc rehearing of the D.C. Circuit’s August 21, 2012 panel decision vacating EPA’s Cross-State Air Pollution Rule (CSAPR). The panel, in a 2-1 decision authored by Judge Kavanaugh, held that CSAPR exceeded EPA’s statutory authority under the Clean Air Act (CAA) in two independent respects. First, the panel concluded that CSAPR may require upwind States to reduce their emissions by more than their own significant contributions to a downwind State’s nonattainment, contrary to the statute. Second, the panel concluded that EPA lacked authority to implement the required emissions reductions through Federal Implementation Plans (FIPs), rather than affording the States an initial opportunity to implement the reductions through State Implementation Plans. Read our previous blog entry on this decision here.

In its petition, EPA argues that the panel’s FIP holding conflicts with other D.C. Circuit decisions by reaching out to “invalidate EPA actions that were not before the Court and for which the statutory review period had previously run” and by “exceeding the Court’s proper role in statutory interpretation by rewriting the plain language of the Act.” Petition for Rehearing En Banc at 3 (pdf). Additionally, EPA contends the panel’s “‘significant contribution’ analysis misapplies the Act’s waiver and exhaustion requirements and ignores settled Circuit precedent in finding an unwritten proportionality requirement in the statute.” Id. at 9.

Rehearing en banc “is not favored and ordinarily will not be ordered” unless necessary to “maintain uniformity of the court’s decisions” or the proceeding involves a question of “exceptional importance.” Fed. R. App. P. 35(a). No response may be filed to a petition for an en banc reconsideration unless ordered by the court. Fed. R. App. P. 35(e). 

D.C. Circuit Vacates EPA's Cross-State Air Pollution Rule

By Stephen W. Wiegand

On August 21, 2012, the United States Court of Appeals for the District of Columbia Circuit vacated EPA’s Cross-State Air Pollution Rule (CSAPR). EPA issued CSAPR in August 2011 pursuant to Sec. 110(a)(2)(D)(i)(I) of the Clean Air Act (the “good neighbor” provision) which requires that State Implementation Plans contain adequate provisions to prevent a state’s emissions from affecting another state’s air quality. The CSAPR rule was promulgated in response to the D.C. Circuit’s remand in 2008 of EPA’s Clean Air Interstate Rule (CAIR), which was EPA’s prior attempt at implementing the good neighbor provision.

Under the rule, certain “upwind” states were required to reduce emissions of sulfur dioxide (SO2) and nitrogen oxides (NOx), based on those states’ contributions to downwind states’ air quality problems. Industry strongly criticized CSAPR for its draconian reductions in allowable power plant emissions. CSAPR would have required many states, including Louisiana and Texas, to reduce power plant emissions of SO2 and NOx, particularly during the summer ozone season. Industry challenged EPA’s data and methodology in formulating the CSAPR.

In a 2-1 decision, the Court vacated CSAPR on two main grounds. First, CSAPR required that upwind states reduce emissions by more than their own significant contributions to the downwind states’ nonattainment. Specifically, only states that contributed a threshold amount to the air pollution in a downwind state were subject to the provision. The restrictions placed on those states, however, were based on region-wide air quality monitoring projections. Thus, the rule could require states to reduce emissions by more than the amount of their actual contribution. Second, after quantifying the states’ obligations under the rule, EPA set forth those obligations in Federal Implementation Plans rather than giving the states the initial opportunity to implement the required reductions.

In vacating CSAPR, the Court ordered EPA to continue to administer CAIR pending the promulgation of a valid replacement.

The full opinion can be viewed here (pdf).

Fifth Circuit Vacates EPA's Disapproval of the Texas Flexible Permits Program

By Carlos J. Moreno

On August 13, 2012, the United States Court of Appeals for the Fifth Circuit vacated the Environmental Protection Agency’s (“EPA”) disapproval of revisions to the Texas State Implementation Plan (“SIP”) dealing with the state’s Flexible Permits program. State of Texas v. U.S. Environmental Protection Agency, No. 10-60614 (5th Cir. Aug. 13, 2012). Under the Clean Air Act (“CAA”), EPA sets National Ambient Air Quality Standards (“NAAQS”) but states determine the specific control strategies that the individual state will use to achieve NAAQS. 42 U.S.C. § 7410(a)(1). The states do this by formulating and administering a SIP. 42 U.S.C. § 7410(a)(2). EPA has the authority to approve or disapprove SIP language proposed by the states. 42 U.S.C. § 7410(k). Petitioners challenged the EPA’s disapproval of the Texas SIP revisions relating to the Flexible Permits program under the CAA and the Administrative Procedure Act (“APA”).

In 1994, Texas revised its SIP to include a Flexible Permits Program and submitted the revisions to EPA for approval. The Flexible Permit Program allowed facilities that were minor sources for criteria pollutants to obtain a minor NSR permit setting an emissions cap for the whole facility. To determine the amount of the emissions cap, the state agency (Texas Natural Resource Conservation Commission, which later became the Texas Commission on Environmental Quality (“TCEQ”)) would first determine the corresponding emissions from each emissions unit under the cap if it had pollution controls at the BACT level. The cap amount was then set at the sum of the BACT emission values for the emission units within the facility. Facilities with flexible permits could make some modifications without the need for further agency review, as long as the resulting emissions total was still less than the emissions cap.

The EPA failed to take any formal action on the Flexible Permit Program for over a decade. In 2008, industry petitioners filed suit to force EPA to perform its nondiscretionary duty to act on the SIP revisions. The following year, EPA proposed disapproving the Program (final disapproval was issued on July 15, 2010). In the meantime, a number of facilities in Texas had obtained permit coverage under the Flexible Permit Program. In disapproving the SIP revisions, EPA argued that: (1) the Flexible Permit Program could allow major sources to evade NSR requirements applicable to major sources (Major NSR), (2) the monitoring, reporting and recordkeeping (“MRR”) provisions were inadequate, and (3) the methodology for calculating the emissions caps was not replicable.

The court examined EPA’s decision to disapprove the Flexible Permit Program under the usual APA standards for judicial review of agency action. In a 2-1 decision, the court found that in order for EPA to disapprove a SIP revision, it must demonstrate that the revision would “interfere with any applicable requirement concerning attainment of NAAQS or any other applicable requirement of the CAA.” See State of Texas v. U.S. Environmental Protection Agency, No. 10-60614, slip op. at 8 (5th Cir. Aug. 13, 2012) (quoting in part from 42 U.S.C. § 7410(l)). The court concluded that provisions in the Flexible Permit regulations requiring compliance with Prevention of Significant Deterioration (“PSD”) and Nonattainment review were sufficient to prevent major sources from using flexible permits to evade Major NSR, and that EPA’s insistence on an express negative statement to that effect had no basis in the CAA or applicable regulations. As to the MRR provisions, the court concluded that EPA’s concerns were solely based on misgivings about the level of discretion given to the state agency’s director when setting specific MRR permit requirements, and also had no basis in the CAA or applicable regulations. Finally, the court concluded that the CAA provisions and regulations for minor NSR do not require that the methodology for calculating emissions be identical from permit to permit.

The court vacated EPA’s disapproval of the SIP revisions and remanded it back to the agency for further consideration. Texas will probably submit new revisions to the SIP in an effort to address EPA’s concerns. In fact, TCEQ has already issued rules clarifying the scope of the Flex Permit Program, and has pledged to do rulemaking to address any MRR issues. However, many flex permit facilities have already switched to “non-flex” permits or are in the process of doing so. Regardless, this court opinion may prove to be a milestone for how future courts will review EPA’s decisions about SIP approval. 

New Air Standards for Oil & Gas Industry May Force HAP Area Sources into Major Source Status

By Robert E. Holden and Carlos J. Moreno

On August 16, 2012, EPA published a new rule that revises the NESHAP Subpart HH standards for the oil and gas industry. 77 Fed. Reg. 159 (Aug. 16, 2012). The Final Rule wassigned on April 17, 2012, but publication in the Federal Register did not occur until August 16, 2012, making the rule effective on October 15, 2012. The new rule contains many changes and new requirements for the industry. One important change is how the new definition of “associated equipment” modifies the aggregation rule for Hazardous Air Pollutants (HAP), which in turn modifies the applicability of the “major source” definition for oilfield operations, in particular as it applies to oil and gas wells, tanks and glycol dehydrators. Under the new rules, storage tank emissions will not be aggregated with well emissions, and storage tank and glycol dehydrator emissions may be aggregated separately.


Section 112(n)(4) of the Clean Air Act, 42 U.S.C. § 112(n)(4), establishes a non-aggregation standard for exploration and production facilities, specifying that HAP emissions from oil and gas wells and compressor stations should not be aggregated for major source determinations. (Note that this rule does not apply to major source determinations for new source review or Title V.)42 U.S.C. § 7412 (n)(4)(A).Section 112(n)(4) provides:

[E]missions from any oil or gas exploration or production well (with its associated equipment) and emissions from any pipeline compressor or pump station shall not be aggregated with emissions from other similar units, whether or not such units are in a contiguous area or under common control, to determine whether such units or stations are major sources, and in the case of any oil or gas exploration or production well (with its associated equipment), such emissions shall not be aggregated for any purpose under this section.

42 U.S.C. § 7412(n)(4) (emphasis added); see also 40 C.F.R. § 63.761 (definition of “major source”).

The 1999 EPA NESHAP standard for oil and natural gas production facilities (Subpart HH) specified the equipment to be considered to be “associated” with oil and gas wells for purposes of the regulation. 64 Fed. Reg. 116 (Jun. 17, 1999). The 1999 standard defined the term “associated equipment” as:

Associated equipment, as used in this subpart and as referred to in section 112(n)(4) of the Act, means equipment associated with an oil or natural gas exploration or production well, and includes all equipment from the wellbore to the point of custody transfer, except glycol dehydration units and storage vessels with the potential for flash emissions.

Id. (emphasis added). For purposes of the rule, the point of custody transfer is defined as the point where hydrocarbon liquids or natural gas enter a pipeline or any other form of transportation, or the point where hydrocarbon liquids or natural gas enter a natural gas processing plant. Id.

Focusing on wells and storage tanks, the 1999 rule allowed the aggregation with well emissions of HAP emissions from tanks that do not have the potential for flash emissions (e.g., pressurized tanks).

New Oil & Gas Rule

The new rule modifies the definition of “associated equipment” by removing the “potential for flash emissions” qualifier after “storage vessels.” The definition now reads as follows: “Associated equipment, as used in this subpart and as referred to in section 112(n)(4) of the Act, means equipment associated with an oil or natural gas exploration or production well, and includes all equipment from the wellbore to the point of custody transfer, except glycol dehydration units and storage vessels.” Now the emissions of a larger universe of storage tanks, including those with no potential for flash emissions, may potentially be considered part of (and thus aggregated with) compressor station and pump station emissions, including those from glycol dehydrators.

EPA acknowledges that some “existing” production field facilities (constructed before August 23, 2011, the date of proposal of the new rules) that were previously “area sources” (i.e., non-major sources under Section 112), but that may now be major sources once the HAP emissions from storage tanks without the potential for flash emissions, are included. Thus, the new rule gives these facilities three (3) years from the effective date of the rule to comply with the relevant emission standards. Therefore, these facilities must be in compliance no later than October 15, 2015.

In light of the new rules, oil and gas operators should perform compliance reviews of their operations. As part of those reviews, industry should be alert to the effects of the modification of the aggregations rules for storage tanks. It remains to be seen what effect the recent decision from the Sixth Circuit on aggregation of Oil & Gas sources in the Title V context could have on future major source determinations under the revised NESHAP Subpart HH. See Lesley Foxhall Pietras, Air Permitting: Sixth Circuit Vacates Single Stationary Source Aggregation Determination for E&P Facilities Due to EPA’s Unreasonable Interpretation of Adjacent, The Energy Law Blog, Aug. 16, 2012.

Air Permitting: Sixth Circuit Vacates Single Stationary Source Aggregation Determination for E&P Facilities Due to EPA's Unreasonable Interpretation of Adjacent

By Lesley Foxhall Pietras

On August 7, 2012, in a 2-1 decision in Summit Petroleum Corp. v. U.S. Environmental Protection Agency, the United States Court of Appeals for the Sixth Circuit vacated the Environmental Protection Agency’s (EPA) determination that a natural gas sweetening plant and sour gas production wells commonly owned by Summit Petroleum Corporation (Summit) but dispersed over forty-three square miles constituted a single stationary source under the Clean Air Act Title V permitting program. Specifically at issue was EPA’s finding that the plant and the wells were “adjacent” based on their operationally interdependent relationship.

When making single stationary source determinations without the protection of the non-aggregation provision in Section 112 of the Clean Air Act, 42 U.S.C. § 7412(n)(4)(A), multiple pollutant-emitting activities can be aggregated together and considered a single stationary source only if, among other things, they “are located on one or more contiguous or adjacent properties.” See, e.g., 40 C.F.R. §§ 51.166(b)(6); 71.2. The question of what is “contiguous or adjacent” has long been vexing for the exploration and production industry. Under different administrations, EPA has changed its guidance on the meaning of this phrase. In 2007, in guidance specifically addressing oil and gas activities, EPA stated that “proximity is the most informative factor in making source determinations.” See Memorandum from William L. Wehrum, Acting Assistant Administrator, EPA, to Regional Administrators I-X, at 3 (Jan. 12, 2007). Two years later, EPA withdrew that guidance, reemphasizing the criteria set out in the regulations. See Memorandum from Gina McCarthy, Assistant Administrator, EPA, to Regional Administrators I-X (Sept. 22, 2009).

In Summit, the court concluded that the regulatory term “adjacent” is unambiguous and implies only physical proximity, citing the dictionary definition of “adjacent,” the term’s etymological history, and caselaw. In light of this determination, the court applied no deference to EPA’s interpretation of the term. See Summit Petroleum Corp. v. U.S. Environmental Protection Agency, No. 09-4348, slip op. at 15 (6th Cir. Aug. 7, 2012). EPA had argued that because “it has an established history of supplementing the traditional definition of adjacency with the concept of activities’ functional relatedness,” the court must review its interpretation with heightened deference. Id. at 16. The court rejected this argument, noting that “adjacent” is unambiguous and that “an agency may not insulate itself from correction merely because it has not been corrected soon enough, for a longstanding error is still an error.” Id. at 18.

Based on the plain meaning of “adjacent,” the court also rejected EPA’s interpretation “that activities can be adjacent so long as they are functionally related, irrespective of the distance that separates them.” See id. at 15. The court thus vacated EPA’s stationary source determination, directing EPA to reassess the aggregation of Summit’s facilities “under the ordinary understanding of its requirement that Summit’s plant and wells be located on adjacent, i.e., physically proximate, properties.” See id. at 16 (emphasis added).

While EPA performed the single stationary source determination in Summit because Summit’s plant and gas production wells are located on Indian territory, most other stationary source determinations are made by state and local regulators. Nonetheless, Summit should provide more clarity for all relevant permitting authorities, as it teaches that physical proximity must be considered in determining whether activities are “contiguous or adjacent.”


Louisiana Legislature Modifies Oilfield Cleanup Legislation

By Rob McNeal

Updated June 15, 2012

Significant revisions and amendments to Louisiana’s oilfield cleanup legislation, La. R. S. 30:29 (commonly known as Act 312) obtained final legislative approval on May 31, 2012 and are expected to become law shortly. Procedures have been added to expedite the remediation of oilfield contamination, the procedures for the formulation of remediation plans by the Office of Conservation in the Louisiana Department of Natural Resources have been modified, and new provisions have been added to deal with various issues, including the admission of remediation evidence at trial. Generally, the legislation furthers the public interest in prompt remediation in accordance with Louisiana’s regulatory standards by encouraging the prompt assessment and remediation of contamination, rather than delaying cleanup activity until after trial in legacy lawsuits. These changes are summarized below. 


Act 312 of the 2006 legislative session was enacted in response to judicial decisions that awarded significant damages for remediation costs with no obligation for landowners to actually use such awards for cleanup work. Defendants in such cases could avoid additional cleanup responsibility by operation of law as well as doctrines of res judicata and issue preclusion. The result was that contaminated property at issue in litigation was left unremediated despite conditions that exceeded regulatory standards. The courts recognized the negative public policy considerations created by this jurisprudence, but the Louisiana Supreme Court concluded that the solution was a legislative issue. The legislature responded by enacting Act 312. 

Act 312 applies to private lawsuits which seek relief for oilfield contamination. In general, when a defendant is found liable for environmental damage, Act 312 provides that the court shall seek a recommendation from the Louisiana Department of Natural Resources, office of conservation (“LDNR”) with the parties’ input for the most feasible plan to remediate the contamination to regulatory standards and shall thereafter adopt the most feasible plan. The responsible party is required to deposit sufficient funds to implement the plan and thereafter the court and Louisiana Department of Natural Resources shall oversee the remediation. If necessary, the court can require the responsible party to provide additional funding or, conversely, the responsible party is reimbursed any excess funds not used for remediation. 

However, a landowner can pursue a remedy or award for private claims suffered as a result of environmental damage with some limitations. Also, a landowner can receive damages for the implementation of additional remediation in excess of the requirements of the plan adopted by the court as may be required in accordance with the terms of an express contractual provision. 


Litigation over the application and interpretation of Act 312 had effectively delayed remediation of oilfield sites until after trial and impeded the prompt resolution of contamination claims. In addition, regulators were criticized for their handling of Act 312 issues. Due to both plaintiffs’ and defendants’ dissatisfaction with the existing law, two bills were passed that modify Act 312: House Bill 618 and Senate Bill 555.

House Bill Number 618 modifies Act 312 by amending the Louisiana Code of Civil Procedure. It enacts two new articles, 1552 and 1563. These articles provide for environmental management orders to expedite testing and a limited admission of environmental liability to allow defendants to remediate sites using the existing Act 312 procedure before trial on the merits. 

Senate Bill Number 555 contains a variety of amendments to La. R.S. 30:29. It limits the timing of discovery of LDNR plan formulation evidence, creates a preliminary hearing to test the existence of environmental damage and liability for such damage, extends prescription for plaintiffs who perform environmental testing after giving notice, prohibits ex parte communications with LDNR and agency personnel prior to the issuance of a remediation plan, provides for additional agency review of LDNR’s plan, and adds a waiver of indemnity rights for punitive damage claims by any defendant who makes a limited admission of liability for environmental damage. 

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EPA Issues New Air Regulations for the Oil and Natural Gas Industry

By Stephen Wiegand


On April 17, 2012, the United States Environmental Protection Agency (EPA) finalized New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAP) for natural gas wells that are hydraulically fractured.


The rule aims to reduce levels of volatile organic compounds (VOCs) released during well completion.  Prior to January 1, 2015, operators may use flaring to reduce such emissions.  Beginning January 1, 2015, however, operators must reduce emissions by installing equipment that captures natural gas during completion and makes it available for use or sale. 


The rule also establishes new notification and reporting requirements for well completions.  It requires that owners or operators of hydraulically fractured and refractured natural gas wells notify EPA by e-mail no later than two days before completion work begins.  Additionally, each year owners or operators must submit a report on their well completions that is certified by a senior company official attesting to the report’s truth, accuracy, and completeness.


The rule retains existing NESHAP standards for large glycol dehydrators at well sites and also sets new NESHAP standards for small glycol dehydrators (ones with an annual average natural gas throughput of less than 85,000 standard cubic meters per day, or actual annual average benzene emissions of less than 1 ton per year).  Small dehydrators must meet a unit-specific limit for emissions of BTEX (benzene, toluene, ethylbenzene, xylene) that is based on the unit’s natural gas throughput and gas composition.


In addition to the new standards for hydraulically fractured wells, the rule also updated existing standards for natural gas processing plants, storage tanks, and transmission lines. 


For more information, see www.epa.gov/airquality/oilandgas/actions.html

EPA Proposes Significant Changes to NPDES Permit for Oil and Gas Facilities in the GOM OCS

By Carlos J. Moreno

On March 7, 2012, the Environmental Protection Agency (“EPA”) published in the Federal Register a proposed NPDES general permit for discharges from oil and gas facilities in the western and central portion of the Outer Continental Shelf of the Gulf of Mexico (the “proposed permit”). See 77 Fed. Reg. 13601 (Mar. 7, 2012), available at http://www.epa.gov/region6/water/npdes/genpermit/index.htm. Affected companies may wish to comment on proposed changes to the permitting and reporting process, and to the effluent limitation and monitoring requirements.  Comments are due by May 7,2012. Some of the most significant proposed changes are described below.

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Update to the December 20, 2011 Liskow & Lewis E-Newsletter

By Megan Spencer

In our December 20, 2011 E-Newsletter, we reported on the status of: (1) EPA’s Cross-State Air Pollution Rule; and (2) the EPA Inspector General’s report, “EPA Must Improve Oversight of State Enforcement.” Some recent developments in those areas merit an update: 

(1) On December 30, 2011, the United States Court of Appeals for the D.C. Circuit stayed EPA’s Cross-State Air Pollution Rule (CSAPR). The Court stayed CSAPR until it could resolve the petitions for review. In the meantime, EPA will continue to administer the Clean Air Interstate Rule. Click here for the complete ruling (PDF).

(2) Peggy Hatch, Secretary of the Louisiana Department of Environmental Quality (LDEQ), sent a response letter to the Inspector General of the EPA responding to the publication of EPA’s report, entitled “EPA Must Improve Oversight of State Enforcement.” The purpose of the response letter was to highlight some of the errors and omissions in the report criticizing Louisiana’s enforcement record. In her response, Secretary Hatch identified 14,454 enforcement actions that EPA did not take into account in evaluating the LDEQ’s enforcement record, and stated that Louisiana has seen tremendous improvement in ambient air and water quality in the recent past. Click here for the complete ruling (PDF).


EPA Proposes Modifications to Oil & Gas Air Pollution Standards

By Carlos J. Moreno:

On August 23, 2011, the Environmental Protection Agency (EPA) published in the Federal Register a proposed rule that significantly expands the applicable air emissions standards for the Oil and Natural Gas Sector. See 76 Fed. Reg. 52738 (Aug. 23, 2011), available at http://epa.gov/airquality/oilandgas/actions.html. Specifically, EPA is proposing changes to the New Source Performance Standards (NSPS) in 40 CFR part 60 and technology-based National Emissions Standards for Hazardous Air Pollutants (NESHAP) in 40 CFR part 63 that apply to oil and gas production, processing, transmission and storage facilities.  According to EPA, the rules would result in a net savings for industry of $29 million because of the increased natural gas and condensate available for sale. The public comments period for the proposal ends on October 24, 2011.

New Source Performance Standards

Currently, two New Source Performance Standards apply to the oil and gas industrial category. Subpart KKK covers Volatile Organic Compound (VOC) emissions from leaking components in onshore natural gas processing plants, while Subpart LLL covers SO2 emissions from onshore natural gas processing plants. EPA conducted reviews of both standards as required by the Clean Air Act, and is now proposing changes to each. Specifically, EPA is proposing to update the Leak Detection and Repair (LDAR) requirements in Subpart KKK, and modify Subpart LLL to require greater SO2 control in facilities that process natural gas with high sulfur content.  

In addition, the proposal would create a new NSPS Subpart OOOO to regulate VOC emissions from all oil and gas operations not already covered under Subpart KKK that commence construction, reconstruction, or modification after August 23, 2011.  The new Subpart OOOO would include operational standards for completions of hydraulically-fractured gas wells. Non-exploratory and non-delineation wells would need to use reduced emission completion, commonly referred to as “green completion,” while exploratory and delineation wells would be allowed to use pit flaring. For purposes of the rule, a completion associated with refracturing performed at a well existing prior to August 23, 2011 is considered a modification, subjecting the well to the new standards. The rule also requires a 30-day advance notification for each completion or recompletion of a hydraulically fractured gas well. EPA is also proposing VOC emissions limits for gas-driven pneumatic devices, equipment standards for centrifugal compressors, operational standards for reciprocating compressors, and a 95% VOC emission reduction requirement for some condensate and crude oil storage tanks. Finally, the proposal exempts some “non-major” sources that would be subject to Subpart OOOO from having to obtain Title V permits.

NESHAP Technology-Based Standards

Under 40 CFR part 63, there are two technology-based NESHAP standards that apply to sources in the Oil and Gas sector.  Subpart HH covers oil and natural gas production facilities that are major or area sources of Hazardous Air Pollutants (HAP). The rule includes standards for the following emission points: glycol dehydrator vents, storage vessels, and natural gas processing plant equipment leaks. On the other hand, Subpart HHH covers natural gas transmission and storage facilities that are major sources of HAP, and only includes standards for emissions from glycol dehydrator process vents. These NESHAP standards require major sources to use Maximum Achievable Control Technology (MACT). As required by the Clean Air Act, EPA conducted technology reviews and residual risk assessment reviews for both standards. Based on the findings from the reviews, EPA is proposing changes to both MACT standards for major sources. 

The proposal establishes new emissions limits for small glycol dehydrators at major sources, which were previously exempted under Subpart HH and HHH. EPA is also proposing to eliminate the alternative compliance option under Subpart HH and HHH, which allows sources to reduce benzene emissions from large glycol dehydrators to less than 0.9 Mg/yr in lieu of achieving 95% emissions control. In addition, the rule proposes to eliminate the existing Startup, Shutdown and Malfunction (SSM) exemption that made emission standards inapplicable during periods of SSM.  However, EPA proposes to add an affirmative defense to civil penalties and exceedances of emission limits caused by malfunctions.  Finally, the proposal would modify Subpart HH to require all crude oil and condensate tanks at major sources to control their HAP emissions by at least 95%, and requires inclusion of all tank emissions when performing major source determinations.

EPA's Cross-State Air Pollution Rule Will Have A Dramatic Impact on Texas and Louisiana

By: Lesley Foxhall Pietras

On August 8, 2011, the Environmental Protection Agency (EPA) published a far-reaching Clean Air Act rule intended to address the interstate transport of sulfur dioxide (SO2) and nitrogen oxides (NOx) from upwind to downwind states. See 76 Fed. Reg. 48208 (Aug. 8, 2011). Specifically, the Cross-State Air Pollution Rule (CSAPR) requires 27 states, including Louisiana and Texas, to make dramatic cuts in power plant emissions. Emissions reductions will take effect quickly, starting January 1, 2012 for SO2 and annual NOx reductions, and May 1, 2012 for ozone season (May-September) NOx reductions. Texas power plants must meet the January 1, 2012 deadline for SO2 and annual NOx emissions, and the May 1 deadline for ozone season NOx emissions. Louisiana power plants must meet the May 1 deadline to reduce ozone season NOx emissions.

As promulgated, CSAPR will have dramatic impacts on Texas and Louisiana. According to the Texas Commission on Environmental Quality, CSAPR requires Texas power plants to lower SO2 emissions by 46 percent and NOx emissions by 7 percent compared with 2009 levels. See Kate Galbraith and Ari Auber, Controversial Pollution Rule Still on Track for Texas, The Tex. Tribune, Sept. 5, 2011. As for Louisiana, the Louisiana Public Service Commission’s consultant notes that CSAPR requires Louisiana power plants to reduce NOx emissions by 42 percent compared to 2010 levels. See David E. Dismukes, Acadian Consulting Group, Commissioner Briefing & Proposed Staff Recommendation: EPA’s Recently-Proposed Cross State Air Pollution Rule, Louisiana Public Service Commission Business & Executive Meeting (Sept. 7, 2011). Making these cuts by the highly compressed deadline could jeopardize the ability of the Texas and Louisiana electric grids to supply sufficient power to businesses and consumers. The reductions could even lead to rolling blackouts. For example, the Electric Reliability Council of Texas (ERCOT), the independent power system operator for the state, estimates that implementing CSAPR could result in a power generation capacity reduction of as much as 1,400 MW during the summer peak months. A reduction of that magnitude would have resulted in rotating outages during some days in August 2011. See ERCOT, Impacts of the Cross-State Air Pollution Rule on the ERCOT System at 5 (Sept. 1, 2011). Additionally, Luminant, the largest power generator in Texas, recently announced that it will need to close certain facilities to comply with CSAPR, which will cause the loss of approximately 500 jobs. See Luminant News Release, Luminant Announces Facility Closures, Job Reductions in Response to EPA Rule (Sept. 12, 2011). Moreover, in light of the substantial capital that power plants will need to spend on pollution control technology to comply with CSAPR, the rule will significantly increase the cost of electricity for all consumers, including businesses and individuals.

Numerous parties are considering challenges to CSAPR. Under the Clean Air Act, the deadline to file petitions for review of the rule is October 7, 2011. Petitions for reconsideration also must be filed by that same date.

EPA and Army Corps of Engineers Issue Draft Guidance on Waters Protected by Clean Water Act

By Lesley Foxhall Pietras

On April 27, 2011, the Environmental Protection Agency (EPA) and the U.S. Army Corps of Engineers (the Corps) released new proposed guidance on how the agencies will identify waters protected by the Clean Water Act (CWA) in light of Solid Waste Agency of Northern Cook County v. U.S. Army Corps of Engineers, 531 U.S. 159 (2001) (SWANCC) and Rapanos v. United States, 547 U.S. 715 (2006). Although EPA and the Corps have previously issued guidance interpreting SWANCC and Rapanos (EPA’s earlier guidance on Rapanos is discussed at www.theenergylawblog.com/2007/07/articles/environmental/epa-and-army-corps-of-engineers-publish-joint-guidance/ ), the agencies believe “previous guidance did not make full use of the authority provided by the CWA to include waters within the scope of the Act, as interpreted by the Court.” Guidance at 2. The agencies therefore expect that, under the new proposed guidance, “the number of waters identified by the [CWA] will increase compared to current practice.” 76 Fed. Reg. 24479, 24479 (May 2, 2011). Accordingly, the proposed guidance appears to substantially expand the agencies’ jurisdiction when compared to the prior guidance. Public comment on the proposed guidance must be received on or before July 1, 2011. Id.

In SWANCC, the Supreme Court addressed the question of CWA jurisdiction over isolated, non-navigable, intrastate ponds, and concluded that CWA jurisdiction could not be based solely on the presence of migratory birds. In Rapanos, the Court addressed CWA protections for wetlands adjacent to non-navigable tributaries, but issued five opinions with no single opinion commanding a majority. The proposed guidance emphasizes that the plurality opinion concluded that “waters of the United States” extends beyond traditional navigable waters to include “relatively permanent, standing or flowing bodies of water.” Rapanos, 547 U.S. at 731-32; see also id. at 739. The proposed guidance also highlights the plurality opinion’s conclusion that only wetlands with a “continuous surface connection” to other jurisdictional waters are considered “adjacent” and protected by the CWA. Id. at 742. In contrast, Justice Kennedy’s concurring opinion, the proposed guidance notes, concluded that “waters of the United States” includes wetlands with a “significant nexus” to traditional navigable waters. Rapanos, 547 U.S. at 780. The agencies continue to believe that they can assert jurisdiction over waters that satisfy either the plurality standard or Justice Kennedy’s standard, because a majority of justices would support jurisdiction under either standard. Guidance at 2.

Under the proposed guidance, the following waters are protected by the CWA: traditional navigable waters (including water bodies that have been found to be navigable-in-fact by a federal court, and waters which are currently used, historically have been used, or are susceptible to being used for commercial navigation); interstate waters (even if such waters are not traditional navigable waters); and wetlands adjacent to either traditional navigable waters or non-wetland interstate waters.

Moreover, the proposed guidance determines which waters are covered by the CWA pursuant to the standard set out in the Rapanos plurality opinion. In this vein, non-navigable tributaries are subject to CWA jurisdiction, if the tributary is connected to a downstream traditional navigable water, and flow in the tributary is at least seasonal. Guidance at 13. Wetlands that directly abut relatively permanent waters are also covered by the CWA. Id. at 15.

Additionally, the following types of waters are covered by the CWA if a fact-specific analysis determines they have a “significant nexus” to traditional navigable waters or interstate waters:
• tributaries to traditional navigable waters or to interstate waters;
• wetlands adjacent to jurisdictional tributaries to traditional navigable waters or interstate waters; and
• waters that fall under the “other waters” category of the regulations, including intrastate lakes, rivers, and mudflats. The proposed guidance divides these waters into two categories (those that are physically proximate to other jurisdictional waters and those that are not) and discusses how each category should be evaluated.
According to the proposed guidance, waters have the requisite “significant nexus” “if they, either alone or in combination with similarly situated waters in the region, significantly affect the chemical, physical, or biological integrity of traditional navigable waters or interstate waters.” Guidance at 7.

Under the proposed guidance, waters that are not covered by the CWA include artificially irrigated areas which would revert to upland if the irrigation ceased; artificial lakes or ponds which are used for stock watering, irrigation, settling basins, or rice growing; artificial reflecting pools or swimming pools excavated in uplands; water-filled depressions created in dry land incidental to construction activity and pits excavated in dry land for the purpose of obtaining fill; groundwater drained through subsurface drainage systems; and erosional features, swales and ditches that are not tributaries or wetlands. Guidance at 21.

The proposed guidance will apply to all CWA programs, including section 303 water quality standards, section 311 oil spill prevention and response, section 401 water quality certification, section 402 National Pollutant Discharge Elimination System permits, and section 404 permits for discharges of dredged or fill material.

After the agencies receive comment on the proposed guidance, they plan to finalize the guidance and then propose revisions to the existing regulations to further clarify which waters are covered by the CWA.

For more information on the proposed guidance, see water.epa.gov/lawsregs/guidance/wetlands/CWAwaters.cfm

Latest Chapter in the "EPA v. Texas" GHG Permitting Saga: EPA Publishes Final Rule Partially Disapproving Texas SIP and Promulgates FIP for GHG Emissions

by: Carlos J. Moreno

On May 3, 2011, the U.S. Environmental Protection Agency (EPA) promulgated a final rule partially disapproving the Texas State Implementation Plan (SIP) and issuing a Federal Implementation Plan (FIP) for Texas. The action prolongs EPA's authority to issue Prevention of Significant Deterioration (PSD) permits for Greenhouse Gas Emissions (GHG) emissions in Texas. Under the Clean Air Act (CAA), states have authority to implement the federal National Ambient Air Quality Standards (NAAQS) if the state submits, and EPA approves, a State Implementation plan (SIP). The SIP must include implementation of preconstruction PSD permitting requirements for NAAQS pollutants and, according to EPA, non-NAAQS pollutants. The CAA authorizes EPA to call for revisions to a SIP ("SIP Call") if the agency later finds that a SIP is inadequate. Following a series of EPA regulatory actions, GHG emissions became subject to PSD requirements as a non-NAAQS pollutant beginning on January 2, 2011. Since then, the EPA Tailoring Rule has required sources that trigger PSD for pollutants other than GHGs to also permit GHG emissions if they are 75,000 tpy or more.

On December 1, 2010, EPA issued a SIP Call for 13 states, including Texas, whose SIPs needed revisions in order to regulate GHG emissions under their PSD permitting program. Contrary to the other states, Texas refused to set a timeline for a SIP revision, effectively telling EPA that it would not revise its SIP to cover GHG emissions. To ensure that sources could obtain GHG permits, EPA issued an interim final rule and a "mirror" rule proposal in December 2010 that partially disapproved the Texas SIP and promulgated a FIP authorizing EPA to issue GHG permits under PSD. EPA stated that it erred in approving the Texas SIP 18 years earlier because the SIP does not contain assurances of adequate legal authority for the application of PSD to newly regulated non-NAAQS pollutants. The interim final rule was set to expire on April 30, 2011. Texas has filed several judicial challenges to EPA's GHG regulations in the DC Circuit, as well as a challenge in the 5th Circuit to EPA's SIP Call finding the Texas SIP inadequate. After issuance of the final interim rule, Texas requested a stay of the rule in the DC Circuit. The DC circuit granted a 30-day stay that was subsequently lifted on January 12, 2011. Since then, EPA has effectively been the permitting authority for GHG emissions in Texas. On May 3, 2011, EPA finalized the December 2010 rule proposal partially disapproving the Texas State Implementation Plan (SIP) and issuing a Federal Implementation Plan (FIP) for Texas. The action was made effective on May 1st to ensure no gap in permitting coverage.

One of the arguments that Texas has pursued is that EPA issued the December 2010 error correction FIP without proper notice and comment. By essentially reissuing the FIP under this final rule after notice and comment, EPA has addressed this argument. Under the FIP, EPA continues to be the PSD permitting authority for GHG emissions in Texas, while Texas continues to be the permitting authority for non-GHG emissions. Therefore, a project that is currently subject to PSD may require two PSD permits: a Texas Commission on Environmental Quality (TCEQ) PSD permit for pollutants other than GHG, and a EPA PSD permit for GHG emissions if the project has 75,000 tpy or more of GHG emissions. Currently, GHG PSD permits are only required if New Source Review is triggered by a non-GHG pollutant. But, starting on July 1, 2011, EPA's GHG Tailoring Rule will also require PSD permits for sources that trigger PSD solely because of their GHG emissions (100,000 tpy or more of GHG's for new projects; 75,000 tpy or more of GHG's for modifications). For these projects, EPA will be the PSD permitting authority for all pollutants. The final error correction FIP will remain in place until Texas submits, and EPA approves, a SIP revision including GHG permitting. Under EPA's standing SIP Call, Texas still has until December 1, 2011 to submit a SIP revision that includes application of PSD program requirements to GHG emissions. EPA has already stated that if Texas does not submit a revision by this date, EPA is prepared to promulgate a new FIP associated with the SIP Call, which would replace the May 3rd FIP, but be "fully consistent" with it. In the meantime, litigation regarding EPA's authority to regulate GHGs, error correction FIP for Texas, and the GHG SIP Call is continuing in the DC Circuit and 5th Circuit.

Supreme Court of Texas Reverses Appeals Court in Oil and Gas Waste Injection Well Permitting Case

By: Carlos J. Moreno

In Railroad Commission of Texas v. Texas Citizens for a Safe Future and Clean Water, No. 08-0497, 2011 WL 836827 (Tex. Mar. 11, 2011), the Supreme Court of Texas reversed the Austin Court of Appeal’s finding that the Railroad Commission (the “Commission”) has to consider broad public safety concerns in the permitting of proposed oil and gas waste injection wells.

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EPA Denied Extension to Promulgate Boiler MACT Rule

By: Megan J. Spencer

EPA first issued its Boiler MACT Rule on September 13, 2004. However, these standards were vacated by the United States Court of Appeals for the District of Columbia Circuit after the Court found EPA’s definition of “commercial or industrial waste” conflicted with the language of the Clean Air Act in NRDC v. EPA, 489 F. 3d 1250 (D.C. Cir. 2007). The deadline for EPA to issue its Boiler MACT Rule was judicially imposed on EPA in Sierra Club v. Johnson, 444 F. Supp. 2d 46 (D.D.C. 2006), requiring EPA to fulfill its statutory duties of promulgating emissions standards by June 15, 2009. However, the United States District Court for the District of Columbia granted several unopposed motions to extend this deadline for the Boiler MACT Rule, resulting in an eventual deadline of January 21, 2011. EPA requested another extension of this deadline through April 13, 2012, but this request was opposed by the plaintiff, the Sierra Club.

EPA argued that it needed a fifteen-month, or alternatively a five-month, further extension of the January 21, 2011, deadline because: (1) in light of the comments received after the proposed rules, EPA must re-propose the rules to ensure that the final rules are a logical outgrowth of the proposed rules; and (2) in the alternative, EPA needs a five-month extension to fulfill its statutory duty of responding to all significant comments. However, the court agreed with the plaintiff that EPA had failed to satisfy the impossibility standard for the setting of emissions standards within the previous deadline set by the court. Thus, the court denied EPA’s request for an extension until April 13, 2012 so that EPA could re-propose the rules before issuing the final rules. The Court also denied the five-month extension requested by EPA to respond to all comments and instead gave EPA one-month to promulgate its Boiler MACT Rule finding that EPA had not provided sufficient evidence on why it needed five months to respond to comments it had already began reviewing.   

Although EPA argued to the District Court that it wanted an extension to re-propose the rules including another round of public comment, EPA submitted the final rules to the White House Office of Management and Budget for review on January 21, 2011, the same day the court denied the request for an extension. www.nytimes.com/gwire/2011/01/21/21greenwire-with-extension-denied-epa-sends-boiler-rules-t-75622.html 

It is likely that EPA will use section 307(d)(7)(B) of the CAA for administrative reconsideration of the rules without postponing the effectiveness of the rules. 42 U.S.C. § 7607(d)(7)(B). Additionally, because of the far reaching nature of the Boiler MACT Rule, it is also possible that the rules could face judicial challenges. 


Congress has also indicated that it may get involved in EPA’s deadline to promulgate its Boiler MACT Rule. At a January 26 hearing of the House Energy & Commerce Committee, Rep. Fred Upton (R-MI) offered to advance legislation that would provide EPA with more time to issue its final Boiler MACT Rule. 

See full opinion at: Sierra Club v. Jackson, No. 01-1537, 2011 U.S. Dist. LEXIS 5316 (D.D.C. Jan. 20, 2011). 

Fifth Circuit Reverses District Court Ruling Protecting Mineral Owner's Rights of Ingress and Egress Over National Park Service Land

by: Megan J. Spencer


            In its decision, filed January 7, 2011, the United States Court of Appeals for the Fifth Circuit reversed, vacated and remanded the opinion of a Texas district court that had found that the National Park Service’s Oil and Gas Management Plan was invalid under the Administrative Procedure Act (“APA”) because it denied Plaintiffs rights of ingress and egress established in the state and federal law creating the park.  Dunn-McCampbell Royalty Interest Inc. v. Nat’l Park Serv., 09-40187 (5th Cir. 2011).  The case involved land in the Padre Island National Park, created in 1963.  The conflict arose between the National Park Service (“Service”), owner of surface estates, and Plaintiffs who were owners of mineral estates.  The Service appealed the decision of the district court.     

            The Service made two arguments on appeal.  First, it advanced a plain language argument based on the text of the Texas law creating that park.  The Texas law made an exception for the use of the surface of the land for the reasonable development of oil, gas, and other minerals –  including the right of ingress and egress.  However, this right was only granted to the “grantors or successors in title” of surface land to the United States.  Plaintiffs argued that this language in the statute was ambiguous, and thus even though they were not grantors or successors in title, the right of ingress and egress applied to them.  The Service argued that the language of the statute was clear, and the right of ingress and egress was only granted to the mineral owners who conveyed surface land to the Service.  The Court agreed with the Service’s plain language interpretation, finding that the right of ingress and egress did not apply to the Plaintiffs here. 

            Second, the Service argued that a second exception in the law creating the park did not apply to the Plaintiffs because the Plaintiffs’ mineral estates were within the Seashore’s boundaries.  The act creating the park excluded from ingress and egress restrictions those minerals that were removed from outside the boundaries of the seashore.  Thus, Plaintiffs argued that because they privately owned the mineral estates, these mineral estates were technically not within the park boundaries.  The Fifth Circuit found that despite the private ownership of the mineral estates below the surface of the land, Plaintiffs’ mineral estates were within the park’s boundaries.     

            Although the case deals with laws specific to the Padre Island National Park and Seashore, it has broader implications for mineral estate owners who have mineral estates located partially or fully within national park boundaries.  The Fifth Circuit joined the position of three other circuit courts finding that “land that is not owned by the Service can still exist within the boundaries of a national park.” 


The full text of the opinion is available at the following link:   www.ca5.uscourts.gov/opinions/pub/09/09-40187-CV0.wpd.pdf

Fifth Circuit Reverses Summary Judgment in Oil Pollution Act Case

In Gabarick v. Laurin Maritime (America), Inc., 2010 WL 5421015 (5th Cir. Dec. 30, 2010), the Fifth Circuit reversed the district court’s finding of summary judgment on liability under the Oil Pollution Act of 1990 (“OPA”).  In doing so, the Court determined that at the summary judgment stage of a complex OPA case involving a number of different parties, it was improper for the court to rely solely on allegations made in the pleadings in order to find that one particular party was not liable under OPA. 


            The facts of the case are as follows:  In July 2008, an ocean-going tanker traveling on the Mississippi River collided with a barge which contained oil.  As a result, a large amount of oil spilled from the barge into the river near New Orleans.  Immediately after the spill, the owner of the barge denied liability; however, as the owner of the discharging vessel, it agreed to coordinate the removal and cleanup efforts with the Coast Guard.  A number of lawsuits followed involving the owner of the barge (“Barge Owner”), the owners of the tanker (“Tanker Owner”), DRD Towing, LLC (“DRD”), which was the company that supplied the crew for the tug that was towing the barge, as well as other parties.  These lawsuits were then consolidated into the first-filed action.  The Tanker Owner moved for summary judgment arguing that it was not liable under OPA.


            OPA provides generally that each “responsible party” for a vessel or facility from which oil is discharged is liable for the damages caused by such an incident.  Further, the responsible party for a vessel is any person owning or operating the vessel.  OPA, however, also provides a responsible party with a complete defense to liability in the following circumstance:


A responsible party is not liable…if the responsible party establishes, by preponderance of the evidence, that the discharge or substantial threat of discharge of oil and the resulting damage or removal costs were caused solely by an act or omission of a third party, other than…a third party whose act or omission occurs in connection with any contractual relationship with the responsible party…. 


33 U.S.C. § 2703(a)(3).  The Tanker Owner argued that because the Barge Owner’s pleadings admitted that the Barge Owner was in a contractual relationship with DRD, and because the pleadings also admitted that DRD had some fault in causing the collision, as a matter of law, the Barge Owner could not shift liability to the Tanker Owner under OPA.  Accordingly, summary judgment was proper in favor of the Tanker Owner.  The district court granted the Tanker Owner’s motion finding that at least some fault was attributable to the Barge Owner and/or DRD.


            On appeal, the Fifth Circuit found that summary judgment was premature and, therefore, reversed the lower court’s ruling.  First, the Court found that the Barge Owner had taken inconsistent positions in its pleadings in the various district court actions.  Specifically, although the Barge Owner admitted in its pleadings that it had a contractual relationship with DRD, the Barge Owner had also filed a separate declaratory judgment action to have any contracts with DRD declared void ab initio.  Citing Fifth Circuit precedent, the Court reasoned that one of two inconsistent pleas cannot be used as evidence in the trial of another.  Accordingly, the district court erred in treating the allegations in any one of the Barge Owner’s pleadings as an admission sufficient to settle an issue of fact. 


            Given the complex nature of the case and the unresolved relationships between the parties, the Court also found that it was premature to treat any party’s mere allegations as sufficient evidence to conclude that a contractual partner of the Barge Owner had some fault in the collision such that summary judgment in favor of the Tanker Owner was warranted.  Further, there had not been sufficient factual development to conclusively assign fault to any of the parties.  Thus, the Court reversed the granting of summary judgment.


            The Gabarick opinion suggests that in certain OPA cases involving complex factual scenarios and numerous different parties, it may be improper for a court to rely solely on allegations made in the pleadings in order to grant summary judgment absolving a party of OPA liability. 


EPA Releases Guidance On Greenhouse Gas Permitting Leaving Many Questions Unanswered

by Megan Spencer

    On November 10, 2010, EPA released guidance for states and permitting authorities to begin including greenhouse gas (“GHG”) emissions in PSD and Title V permitting processes entitled PSD and Title V Permitting Guidance For Greenhouse Gases. (“Guidance”). This Guidance is scheduled to take effect January 2, 2011. EPA gave the public a short window to submit comments on the Guidance, with the comment period ending December 1, 2010. However, this Guidance left much to be interpreted by permitting authorities, leaving industries subject to the new Guidance wondering how it will be applied to them.
    The Guidance applies EPA’s “top down” analysis of best available control technology (“BACT”) to GHG emissions. BACT in Clean Air Act permitting actions for new and modified sources. This BACT analysis involves the following steps: 1) identify all available control technologies; 2) eliminate technically infeasible options; 3) rank remaining options by emissions control effectiveness; 4) evaluate economic, energy, and other environmental impacts; and, 5) select best option as BACT for the source. The Guidance provides a list of available control technologies under step 1 including inherently lower-emitting processes/practices/designs, add-on controls, and combinations of the two. Under step 2, a technology is “technically feasible” if it has been demonstrated in practice or is available and applicable to the source type under review. When ranking options under step 3, ranking should be based on total CO2e. Those available options are then evaluated under step 4. Under step 5, the goal of the BACT selection is to have the highest level of control that the applicant could not adequately justify its elimination based on the factors in step 4.
     The Guidance emphasizes energy efficiency as a means to achieve lower GHG emissions. (Guidance, p. 30). However, the Guidance does not provide definitive answers for how energy efficiency is to be determined. This uncertainty leaves those industries subject to the new guidance wondering whether energy efficiency will be applied to the entire facility, on an individual equipment basis, or across a production unit. With the discretion of how this energy efficiency goal will be interpreted left to the permitting authority, uniformity among states and permitting programs will be lacking. This uncertainty will likely lead to increased costs and delays in permit approvals.
One of the more controversial issues raised by the guidance is whether GHG BACT could force an applicant to redesign its source. Well-settled BACT procedures state that “EPA has recognized that a Step 1 list of options need not necessarily include inherently lower polluting processes that would fundamentally redefine the nature of the source proposed by the permit applicant. BACT should generally not be applied to regulate the applicant’s purpose or objective for the proposed facility.” However, the Guidance then continues with a statement that “permitting agencies must take a ‘hard look’ at the applicant’s proposed design in order to discern which design elements are inherent for the applicant’s purpose and which design elements may be changed to achieve pollutant emissions reductions without disrupting the applicant’s basic business purpose.” At best, this language is likely to lead to widely varying results between different permitting authorities.
     Another unanswered question involves the inclusion of carbon capture and sequestration in the Guidance. The Guidance suggests that carbon capture and sequestration is an available control technology that should be considered under step one of the BACT analysis. Notably, the Guidance recognizes in a footnote that carbon capture and sequestration is not yet ready for large-scale implementation. (Guidance, p. 33, fn. 82). This acknowledgment suggests that facilities should not be required to carry the use of carbon capture and sequestration past steps 1 or 2 when it is not “available” or “feasible” for large-scale implementation.

The full text of the Guidance is available at the following link:www.regulations.gov/search/Regs/home.html#documentDetail

EPA Encourages Consideration of Ocean Acidification in Clean Water Act Impairment Listings

By Carlos J. Moreno:

On November 15, 2010, the U.S. Environmental Protection Agency (EPA) issued a memorandum providing States with guidance on how to address ocean acidification in their Clean Water Act 303(d) impairment listings. 

Section 303(d) of the Clean Water Act requires States to list water bodies that will not meet Water Quality Standards, even after technology-based permit requirements are implemented. States must then identify every contributing source, including contributions from air emissions, and make plans to bring the impaired water body into compliance. This process results in the calculation of a Total Maximum Daily Load (TMDL). There is precedent for TMDLs addressing air emission sources, specifically in relation to atmospheric deposition of mercury. 

The EPA Memo is part of an EPA settlement with the Center for Biological Diversity (CBD), which sued EPA over 303(d) listing of coastal waters for ocean acidification. The CBD had argued that ocean acidification (the decrease in ocean pH caused by increasing CO2 concentration in the atmosphere) required EPA to modify its Recommended Marine pH Criteria and consider ocean acidification in 303(d) list approvals. The Memo encourages States to list coastal waters for ocean acidification, based on existing Marine pH Water Quality Standards, where there is enough data to support it. For example, Puerto Rico’s 2010 303(d) list already includes five coastal water segments impaired by marine pH. At the same time, the agency recognizes that many States do not yet have enough monitoring data to make such a listing. EPA pledges to issue TMDL-specific guidance related to ocean acidification once there is more information on air deposition of carbon in coastal waters.

The EPA memo only addresses ocean acidification from a 303(d) list perspective and does not modify EPA’s Recommended Marine pH Criteria. It is unclear how these developments may affect, if at all, future EPA Ocean Discharge Criteria evaluations under Section 403 of the Clean Water Act.

For more information on the Memorandum, see:


EPA Releases Final Rule Requiring Oil and Gas Sources to Report Emissions of Greenhouse Gases

By Carlos J. Moreno

On November 8, 2010, the U.S. Environmental Protection Agency (EPA) released its final Subpart W rule to cover petroleum and natural gas facilities under the agency’s Greenhouse Gas (GHG) Reporting Program. The original Subpart W rule for petroleum and natural gas facilities was proposed in March 2010. The industry segments covered by the rule are: offshore petroleum and natural gas production; onshore petroleum and natural gas production; onshore natural gas processing; onshore natural gas transmission compression; underground natural gas storage; liquefied natural gas (LNG) storage, import, and export; and natural gas distribution. The rule requires facilities emitting 25,000 metric tons or more of CO2 equivalents per year to report GHG emissions to EPA annually. Under the final rule, facilities are required to begin collecting emissions data on January 1, 2011, and the first annual report is due by March 31, 2012. Data submitted to EPA must be self-certified by facility reporters and is subject to EPA verification.

The final rule excludes gathering lines and boosting stations from the onshore petroleum and natural gas production source category. The rule also gives onshore petroleum and natural gas production facilities the option to use Best Available Monitoring Methods (BAMM) for specific sources during part of the 2011 calendar year. EPA may consider individual petitions to extend the use of BAMM if there are extreme or unusual circumstances.

One of the more controversial requirements in the proposed rule, the “basin-level” definition of an onshore production facility, remains largely unchanged in the final rule. For onshore production sources, the rule defines “facility” as “all petroleum or natural gas equipment on a well pad or associated with a well pad and CO2 E[nhanced] O[il] R[ecovery] operations that are under common ownership or common control including leased, rented, or contracted activities by an onshore petroleum and natural gas production owner or operator and that are located in a single hydrocarbon basin.” By defining the term “facility” this way, individual production wells that are under the reporting threshold may be pulled in if the owner or operator has additional wells in the same basin. In that case, the emissions from the individual wells would be aggregated and treated as one “facility” for reporting purposes. Although this definition departs from how “facility” is defined in other regulatory programs, EPA asserts that the basin-level definition is necessary to ensure appropriate emissions coverage and meet the intent of the GHG Reporting Program. EPA did include language that explicitly limits the basin-level definition to the GHG Reporting Rule.

Offshore petroleum and natural gas production facilities must include emissions from equipment leaks, venting, and flaring. Emissions from portable equipment and drilling operations (unless drilling is conducted from a production platform) are excluded for this industry segment. Reporting for offshore facilities is still based on the BOEM Gulfwide Emissions Inventory process.

For more information on the final rule, see: www.epa.gov/climatechange/emissions/subpart/w.html

Louisiana Third Circuit Court of Appeal Reverses District Court's Dismissal in Arsenic Land Damage Case

By Stephen Wiegand

In David v. Mosaic Global Operations, (La. App. 3 Cir. 10/27/10), the Louisiana Third Circuit Court of Appeal reversed the dismissal of land contamination claims brought against the manufacturer of a tick-killing agent used on cattle. The plaintiffs were landowners who alleged that the product had contaminated their land and water with arsenic. The trial court dismissed the plaintiffs’ claims on various grounds. Notably, the trial court determined that because the utility of the cattle dip outweighed the danger-in-fact, the cattle dip was not “dangerous per se” under Louisiana products liability law. Additionally, the trial court concluded that the plaintiffs had no standing to bring the action because they did not own the property when the original contamination occurred and because none of the plaintiffs acquired the right to pursue recovery for such damage from the previous landowners.

On appeal, the court reversed the dismissal and remanded the case to the trial court. The appellate court found that genuine issues of fact existed with regard to whether the cattle dip was dangerous per se. For example, there were no instructions for safe disposal of the dip and no instructions on how to decontaminate land saturated by the product. Further, it was improper for the trial court to determine that because the cattle dip effectively eradicated ticks that the utility necessarily outweighed the danger-in-fact. The trial court failed to undertaken a full and proper analysis of the risk utility test for determining whether the product was dangerous per se.

Most notably, the appellate court found that the plaintiffs had standing to assert their claims under Louisiana products liability law based on their allegations that they had been injured as a result of exposure to high levels of arsenic in the groundwater. In reaching this conclusion, the court found that the defendant’s reliance on LeJeune Bros., Inc. v. Goodrich Petroleum Co., LLC, (La. App. 3 Cir. 11/28/07), 981 So.2d 23, for the proposition that the plaintiffs lacked standing was misplaced. The court reasoned that the Lejeune holding was limited to a specific set of circumstance: the potential acquisition of a cause of action under a pre-existing mineral lease. Because the David plaintiffs’ claims, however, were not based on property law but instead on Louisiana products liability law, the Lejeune reasoning was not applicable. Accordingly, the fact that the plaintiffs did not own the property when the contamination occurred and that none of the plaintiffs acquired the right to pursue recovery from the previous landowners did not necessarily preclude their claims.

The full text of the opinion is available here: www.la3circuit.org/opinions/2010/10/1027/09-1237opi.pdf

Louisiana Supreme Court Issues Opinion in Marin v. Exxon Mobil Corp.


By Michael A. Mahone, Jr.

On October 19, 2010, the Louisiana Supreme Court issued its opinion in Marin v. Exxon Mobil Corp., a “legacy” lawsuit involving damage to property located in St. Mary Parish caused by historical oil and gas operations. The 4-3 ruling authored by Justice Victory clarified the law applicable to these lawsuits in a number of significant ways.

First, the Supreme Court found that the plaintiffs’ tort claims were prescribed. The courts below had held that, as a result of contra non valentem, prescription did not begin to run until plaintiffs received expert testing data showing contamination existed on their land and/or had full knowledge of the damage at issue. The Supreme Court, however, reaffirmed existing law and held that prescription begins to run when a plaintiff has sufficient information, which, if pursued, would have put him on notice that further inquiry and investigation was necessary, where such inquiry would have led to knowledge that contamination existed. Based on this standard, the Court found that plaintiffs’ knowledge of apparent damage triggered prescription without regard to when expert testing occurred. In addition, the majority rejected the argument that the plaintiffs were “lulled” into inaction by ExxonMobil’s representations. As for the applicability of the continuing tort doctrine, the Court held that prescription began to run on tort claims when the pits at issue were closed. Further, because plaintiffs’ tort claims were prescribed, plaintiffs were not entitled to recover punitive damages.

The Court also found that some claims for cleanup based upon breach of a mineral lease do not expire while the lease is in effect, given that some restoration obligations on lessees arise when a lease expires. As result, the Court held that some of the breach of lease claims, those brought by the Marin plaintiffs, were not prescribed because the surface lease and mineral lease were still in effect. On the other hand, the Breaux plaintiffs’ claims were prescribed because the lease on their land expired before suit was filed. The Breaux plaintiffs were also aware of damage more than 10 years before suit was filed while the Marin plaintiffs arguably would not have discovered damage until 1994, less than 10 years before suit was filed.

Regarding the restoration claims, the Court held that, in circumstances where a lease has excess wear and tear due to contamination, the remedy is clean up to regulatory standards absent an express lease provision requiring additional remediation. In addition, the majority reversed the lower courts and found that a surface lease on one of the pieces of property at issue in the case did not require cleanup to original condition because a 1994 amendment imposing such a requirement was a novation of an earlier lease and therefore the cleanup obligation did not apply to the contamination at issue because it predated 1994.

Lastly, the majority denied the plaintiffs' claim for groundwater remediation and upheld the lower courts’ finding that remediation was not required since useable groundwater was not at issue. The Court further noted that it was illogical to award money to a landowner to remediate unusable groundwater, with no oversight by Louisiana’s Department of Natural Resources, when the Louisiana statute enacted to protect groundwater did not require such a cleanup.

For more information, see www.lasc.org/opinions/2010/09c2368.opn.pdf

EPA Announces January 2011 as Likely Date for Regulation of Greenhouse Gases Under PSD Program

By Stephen Wiegand

EPA recently announced its position regarding the timing of the regulation of greenhouse gases under the Clean Air Act’s Prevention of Significant Deterioration (PSD) Program.

A PSD permit is required before a new industrial facility can be built or an existing facility can be modified in a way that significantly increases pollutant emissions. In Massachusetts v. EPA, 549 U.S. 497 (2007), the Supreme Court held that greenhouse gases are “pollutants” under the Clean Air Act but left open the specific question of whether greenhouse gases could be regulated under the PSD Program. In December 2008, then-EPA Administrator Stephen Johnson issued a memorandum indicating that the PSD Program applies to pollutants that are subject to either an actual provision in the Clean Air Act or a regulation adopted by the EPA under the Act which requires actual control of emissions of that pollutant. However, pollutants such as carbon dioxide, for which EPA regulations only require monitoring and reporting, are not subject to PSD permitting.

In October 2009, new EPA Administrator Lisa Jackson announced that EPA would reconsider and accept public comment on the Johnson memorandum. On March 29, 2010, EPA announced its final decision regarding the reconsideration. Specifically, EPA determined that PSD permitting is not triggered for pollutants such as greenhouse gases until a final nationwide rule requires actual control of emissions of the pollutant. Thus, in the case of greenhouse gases, EPA announced that the PSD requirements will likely not be triggered until January 2, 2011, the date upon which EPA’s rule limiting the greenhouse gas emissions for cars and light trucks is expected to take effect.

For more information on the announcement, see the EPA New Source Review.

Proposed EPA Rules Would Subject Oil and Gas Sources to Mandatory Reporting of Greenhouse Gas Emissions

By Stepehen Wiegand

In October 2009, EPA promulgated the Mandatory Reporting of Greenhouse Gases Rule. This rule required reporting of greenhouse gas emissions from a number of large sources including suppliers of fossil fuels or industrial greenhouse gases, manufacturers of vehicles and engines, and certain facilities that emit 25,000 metric tons or more per year of greenhouse gas emissions.

On March 22, 2010, EPA announced proposed rules to amend the Mandatory Reporting of Greenhouse Gases Rule to cover additional sources including petroleum and natural gas facilities emitting 25,000 metric tons or more of greenhouse gas emissions. Covered facilities would include onshore petroleum and natural gas production, offshore petroleum and natural gas production, onshore natural gas processing, natural gas transmission, underground natural gas storage, liquefied natural gas storage, liquefied natural gas import and export facilities, and natural gas distribution facilities. The proposed rules would require the reporting of fugitive and vented methane and carbon dioxide emissions, including carbon dioxide, methane, and nitrous oxide combustion emissions from flares.

In addition to the oil and natural gas sector, EPA is also proposing to collect emissions data from industries that emit fluorinated gases and from facilities that inject and store carbon dioxide underground for the purpose of geological sequestration or enhanced oil and natural gas recovery.

Under the proposed rules, the newly covered sources are required to begin collecting emissions data on January 1, 2011 and are required to submit the first annual reports to EPA on March 31, 2012.

The public comment period on the proposed rules will extend for 60 days after EPA’s publication of the proposed rules in the Federal Register. Additionally, two public hearings are currently scheduled on the proposed rules – April 19, 2010 in Arlington, Va. and April 20, 2010 in Washington, D.C.

For more information on the proposed rules, see:www.epa.gov/climatechange/emissions/proposedrule.html


Office of Conservation Publishes Proposed Amendments to Statewide Order 29-B

In early 2010, the Louisiana Office of Conservation published in the Louisiana Register a Notice of Intent to amend Statewide Order 29-B, the regulation governing the storage, treatment, and disposal of exploration and production waste at oilfield sites. The proposed amendments provide specific procedures for the evaluation and remediation of groundwater conditions and potential sources that may have contributed to those conditions at oil and gas exploration and production sites. Specifically, the amendments provide that agency submissions made pursuant to Statewide Order 29-B must demonstrate compliance with the conditions set forth in the Louisiana Department of Natural Resources Exploration and Production Site Evaluation and Remediation Procedures Manual (SERP Manual). The SERP Manual, which will become effective upon final promulgation of the amendments, will include site evaluation and remediation protocol and procedures established in conformance with the latest revision of the Louisiana Department of Environmental Quality’s Risk Evaluation/Corrective Action Program (RECAP) document.

The public hearing for the proposed amendments will take place on April 5, 2010 at 9:00 a.m. in Baton Rouge, Louisiana. Written comments will be accepted until 4:30 p.m. on April 12, 2010.

To view the proposed amendments, go to:

EPA Issues Final Greenhouse Gas Endangerment Finding

By Stephen Wiegand

On December 15, 2009, EPA published in the Federal Register its final endangerment findings with respect to greenhouse gases. See 74 Fed. Reg. 66496 (Dec. 15, 2009) [http://www.epa.gov/climatechange/endangerment/downloads/Federal_Register-EPA-HQ-OAR-2009-0171-Dec.15-09.pdf]. This rulemaking is a response to Massachusetts v. EPA, 549 U.S. 497 (2007), in which the Supreme Court held that greenhouse gases were “pollutants” under the Clean Air Act and ordered EPA to determine whether greenhouse gases “may reasonably be anticipated to endanger public health or welfare” under Section 202 of the Act.
In its findings published on December 15, EPA concluded that six greenhouse gases taken in combination may reasonably be anticipated to endanger public health and public welfare. These gases include carbon dioxide, methane, nitrous oxide, hydroflourocarbons, perflourocarbons, and sulfur hexafluoride. In reaching these conclusions, EPA considered the extent to which elevated concentrations of greenhouse gases may cause changes in air quality, increases in temperature, changes in extreme weather events, increases in food- and water-borne pathogens, and changes in aeroallergens. EPA relied on assessments by the U.S. Global Climate Research Program, the Intergovernmental Panel on Climate Change, and the National Research Council.
While these findings do not in themselves impose any requirements on regulated entities, they are a prerequisite to future regulation of greenhouse gases under existing Clean Air Act authority. Many view the existing Clean Air Act as ill-suited to the regulation of greenhouse gases. This endangerment finding, along with EPA’s proposal to regulate greenhouse gases under existing Clean Air Act authority, see EPA Proposed PSD and Title V Greenhouse Gas Tailoring Rule [http://www.hss.energy.gov/nuclearsafety/env/rules/74/74fr55292.pdf], is being used as a forcing function to accelerate the passage of stand-alone greenhouse gas legislation by Congress.


Louisiana Supreme Court Holds that Act 136 of the Mineral Code is Inapplicable to Remediation Suits

By Matt Simone

In Broussard v. Hilcorp Energy Co., the Louisiana Supreme Court held that a plaintiff is not required, pursuant to Article 136 of the Louisiana Mineral Code, to provide a defendant with pre-suit written notice and an opportunity to perform prior to a judicial demand for property restoration related to oil and gas production contamination. Article 136 mandates these requirements for claims “arising from drainage of the property leased or from any other claim that the lessee has failed to develop and operate the property leased as a prudent operator….” The defendants argued that Article 136’s requirements should apply to any claim alleging that a lessee failed to act as a prudent operator. The court rejected the defendants’ position noting that the plain language of Article 136 is limited to claims regarding drainage of property or failure to develop and operate leased property. Since this case essentially involved a remediation/restoration claim, the court found that Article 136’s pre-suit requirements were inapplicable.

To read the case, go to http://www.lasc.org/news_releases/2009/2009-064.asp

Fifth Circuit Holds that Individual Citizens Have Standing to Sue Energy Companies for Global Warming

By April Rolen-Ogden

In Comer v. Murphy Oil, the Fifth Circuit left open the possibility that the oil and gas industry may be privately sued for alleged contributions to global warming. In this putative class action lawsuit, Plaintiffs claimed that the defendants’ operation of energy, fossil fuels, and chemical industries in the United States contributed to global warming. Plaintiffs further claimed that those contributions caused a rise in sea levels and added to the devastation wreaked by Hurricane Katrina, which destroyed Plaintiffs’ property and some public property. The Fifth Circuit concluded that Plaintiffs had standing for their nuisance, trespass and negligence claims, which were premised on the alleged causal link between global warming and Hurricane Katrina’s destruction of Plaintiffs’ property. The Fifth Circuit also held these claims were justiciable and thus ripe for determination by a court. Based on these findings, the Fifth Circuit reversed the District Court, which had dismissed Plaintiffs’ claims, and remanded for further proceedings.

To read further, please go to http://www.ca5.uscourts.gov/opinions/pub/07/07-60756-CV0.wpd.pdf

New Permit Requirements for Hydraulic Fracturing of the Haynesville Shale

By Stephen Weigand

The Shreveport Times reports that federal authorities have added additional permit requirements for companies who pump water from the Red River for hydraulic fracturing of the Haynesville Shale. The requirements were added after the U.S. Fish and Wildlife Service raised concerns that the pumping process could be disturbing the habitat of three federally endangered and threatened Red River species. These species include the pallid sturgeon as well as a bird known as the interior least tern and a plant known as earth fruit. According to the Times, one of the new requirements is that a pump not be placed within 600 feet of an active least tern colony. This requirement effectively forces companies to survey the area before submitting a permit application. Additionally, the Times reports that the Fish and Wildlife Service is also requesting the use of smaller pipes and a diffuser to eliminate the possibility of sucking in fish during the pumping process.

For the full story, see http://www.shreveporttimes.com/article/20090921/NEWS01/909200332

Louisiana Fourth Circuit Court of Appeals Affirms Denial of Class Certification in Alleged Chemical Exposure Case

By Jessica Gladney

In Thomas v. Mobil Oil Corp., No. 2008-0541 (La. App. 4 Cir. 3/31/09), the Fourth Circuit affirmed the trial court’s denial of class certification against the defendants, Exxon Mobil Corporation and Chalmette Refining, L.L.C. The proposed class consisted of approximately 7,000 claimants from Algiers and St. Bernard, and the plaintiffs alleged personal injury and property damages from emissions of petrochemical facilities operated by the defendants over a fourteen-year period. The claims forms submitted did not specify dates that claimants allegedly suffered from any of the alleged damages, and the trial court concluded that the claims among the purported class members varied so greatly that the putative class representatives could not adequately represent the class. The Fourth Circuit recognized that the Louisiana Supreme Court’s holding in Ford v. Murphy Oil, U.S.A., Inc., 1996-2913 (La. 9/9/97), 703 So. 2d 542 was controlling and affirmed the trial court’s holding denying class certification. The court noted that the wide variances in geographic location, claimed exposure, and types and degree of damages claimed by the putative class members demonstrated that the claims were too individualized and the certification of the class should therefore be denied.

EPA Self-Audit Policy Goes Online; Gives "Clean Start" to New Owners

The Environmental Protection Agency announced several updates to its Audit Policy this month that promise to make the system more convenient for users and more forgiving for new owners of regulated facilities. 

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DuPont and ConocoPhillips Settle Environmental Clean-Up Claims against U.S. Government for $52M


           In 1997, DuPont and ConocoPhillips sued the United States pursuant to the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), alleging entitlement to reimbursement of costs expended cleaning up hazardous waste from fifteen sites previously owned by the government during World Wars I and II, and the Korean War.  E.I. DuPont, et al v. USA, et al, United States District Court for the District of New Jersey, Docket No. 2:97-CV-00487-WJM-MF.  The decade-long dispute finally ended in a compromise wherein the government agreed to pay DuPont $51M and ConocoPhillips $1M for past and future clean-up costs.


            The settlement comes one year after the Supreme Court decision in U.S. v. Atlantic Research Corp. in which the Court established that a potentially responsible party can sue other responsible parties under Section 107 of CERCLA to recover voluntary clean-up costs.  The Third Circuit had previously held that DuPont could not recover under CERCLA.  Following the High Court’s decision in Atlantic Research, however, the Third Circuit remanded the case to the district court for reconsideration.  This settlement agreement was promoted by the Atlantic Research decision. 


            Under the terms of the settlement agreement, DuPont agreed to indemnify the United States up to $51M against any claims, past and future, arising from fourteen of the sites, and ConocoPhillips agreed to indemnity up to $1M for the remaining site.  The government, DuPont, and ConocoPhillips have admitted no liability in connection with the settlement. 

LDEQ May Require Louisiana Facilities Exempt From Air Permitting to Maintain Emission Records

By Clare Bienvenu

Pursuant to Act 547, passed by the Louisiana Legislature in the 2008 Regular Session and recently signed into law by the Governor, the Louisiana Department of Environmental Quality (LDEQ) may now require Louisiana facilities exempt from air permitting requirements to maintain records showing that the actual or potential emissions of the facility meet the exemption.  Under existing Louisiana law, a facility is exempt from air permitting requirements if its potential emissions are: (1) less than 5 tpy (tons per year) for each regulated air pollutant; (2) less than 15 tpy for all regulated pollutants combined; and (3) less than the minimum emission rate for each toxic air pollutant listed in LAC 33:III.5112, Table 51.1.  See La. R.S. 30:2054(B)(2)(b)(ix) (as enacted by Act 918 in 2003).  The original exemption did not authorize LDEQ to mandate the maintenance of emissions records for exempt sources.  Act 547 additionally defines “potential emissions” as “the emissions the facility is capable of emitting considering all control measures in place, utilized and properly maintained and historical practices, including hours of operation and number of employees at the facility.”  Act 547 itself does not require exempt facilities to maintain records, but allows LDEQ to promulgate standards or regulations to create such a requirement.  As such, exempt facilities in Louisiana should be on the lookout for the implementing rule from LDEQ. 

Ninth Circuit Vacates EPA Rule Excepting Oil and Gas Construction Discharges from NPDES Permitting

By Claire Bienvenu

On May 23, 2008, the Ninth Circuit vacated EPA’s rule exempting discharges of sediment resulting from oil and gas construction activities from National Pollutant Discharge Elimination System (NPDES) permit requirements. NRDC v. EPA, No. 06-73217 (9th Cir. 5/23/08).  The Ninth Circuit found EPA’s rule, which was a codification of a recent exemption added to the Clean Water Act (CWA or the Act), to be an impermissible interpretation of the Act. Unless overturned, the court’s decision to vacate the regulation imposes an unexpected obligation on the oil and gas industry to obtain NPDES permits for all construction activities disturbing land area greater than or equal to one acre in size. 

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Third Circuit interprets Act 312

 In Germany v. ConocoPhillips Co., 2007-1145 (La. App. 3 Cir. 3/5/08), -- So. 2d --,  the Third Circuit upheld the trial court’s ruling that under Act 312 a single trial of all issues should be held prior to referring a case to the Louisiana Department of Natural Resources (“LDNR”) for the development of a remediation plan. 

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Employee Lacked Personal Liability for Oilfield Environmental Damage Under Louisiana Law

By Kindall James

The issue of whether an individual employee is personally liable for oilfield environmental damages was recently addressed in Kling Realty Co., Inc. v. Texaco, Inc, 2007 WL 81665 (W.D. La. 2007).  The plaintiff mineral lessors claimed that their property had been damaged by oilfield operations, and sued not only the operator, but also a production supervisor.  The plaintiffs argued that the supervisor was individually liable because in his supervisory capacity he had the duty to prevent or limit hazardous pollution affecting the property.  Finding that the plaintiff failed to present any evidence that the supervisor’s responsibilities entailed more than general administrative responsibilities or that the supervisor knew or should have known of any ongoing activities hazardous to the property, the court held that the plaintiffs could not possibly establish that the supervisor was personally liable for their damages, and dismissed the plaintiffs’ claims against him. 

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Louisiana Supreme Court Denies Writ on Act 312 Procedure

In Duplantier v. BP Amoco, et al., the Louisiana Fourth Circuit Court of Appeal held that under Act 312 of 2006 (La. R.S. 30:29), there should be a single trial of both the regulatory remediation covered by the statute and the plaintiffs' separate damages claims (if any).  The Louisiana Supreme Court has now denied a writ application with respect to that opinion.  To view the Fourth Circuit's decision, click here.  Act 312, which became effective June 8, 2006, requires involvement of the Louisiana Department of Natural Resources (DNR) in litigation alleging environmental contamination, including submission of any remediation plan to DNR for approval and the deposit of remediation funds into the registry of the court to be spent on remediation, rather than payment of those funds to the plaintiffs.  However, the statute also preserves the plaintiffs' right to pursue any private cause of action - for example, a right under an express lease provision to a higher standard of clean-up.  Under the Duplantier decision, both the statutory remediation and any private claims will be addressed in a single trial before any plan is submitted to DNR.


Louisiana Extends Abandonment Period For Litigation Affected by Katrina or Rita

By Joe Giarrusso

In Louisiana, a lawsuit is generally deemed abandoned when the parties fail to take any step in its prosecution for three years.  This rule is operative without any formal order.  La. Code Civ. P. art 561.  However, Act 361 of 2007 extended the period for abandonment to five years where (1) the action was initiated prior to August 26, 2005, and was not previously declared abandoned under the general three year period, and (2) the party proves that the failure to take a step in the prosecution or defense of the suit was caused by or was a direct result of Hurricanes Katrina or Rita.  The revision became effective July 9, 2007.   Click here to read the Act.

OPA Does Not Preclude State Law Claims for Additional Compensation

By Drew Spaniol

The Eastern District of Louisiana recently held that the Oil Pollution Liability and Compensation Act (OPA), 33 U.S.C. § 2701 et seq., does not preclude a plaintiff from bringing state law claims for additional liability or compensation.  Isla Corp. v. Sundown Energy, LP, 2007 WL 1240212 (E.D. La. 4/27/07).  The case concerned oil tanks on a drill site owned and operated by Sundown, which were ruptured in Hurricane Katrina. The plaintiffs asserted claims under both OPA and state law.  Seeking to avoid the additional liability of the state law claims, Sundown argued in a motion to dismiss that OPA provided plaintiffs’ exclusive remedy. The court held, however, that while OPA provides the sole federal remedy for oil pollution claims, OPA expressly allows states to provide for "any additional liability or requirements with respect to the discharge of oil or other pollution by oil within such state."  Because of this provision, the court denied Sundown's motion to dismiss and allowed plaintiff's state law claims to go forward. 

EPA and Army Corps of Engineers Publish Joint Guidance

By Robert E. Holden and Monica Derbes Gibson


The Environmental Protection Agency (EPA) and U.S. Army Corps of Engineers have released long-awaited guidance addressing jurisdictional determinations under the Clean Water Act (CWA) in the wake of Rapanos v. United States, 126 S. Ct. 2208 (2006).  There is general agreement that Rapanos limited the reach of the CWA, but the Court did not articulate a clear standard for determining whether or not a wetland or body of water is covered by the CWA.  In the guidance, EPA and the Corps explain how they will approach jurisdictional determinations in light of the Rapanos decision.  Click here to view the guidance.  The agencies will take public comments on implementation of the guidance until December 5, 2007.  Comments may be submitted online at  www.regulations.gov, to Docket No. EPA-HQ-OW-2007-0282, or by email to OW-Docket@epa.gov, with the docket number in the “subject” line. 

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Fourth Circuit Opines on Act 312 Trial Procedure

In Duplantier v. BP Amoco, et al., the Louisiana Fourth Circuit court of appeal recently issued a ruling on trial court procedure under Act 312 of 2006, La. R.S. 30:29.  Click here to view the opinion.  Act 312, which became effective June 8, 2006, requires involvement of the Louisiana Department of Natural Resources (DNR) in litigation alleging environmental contamination, including submission of any remediation plan to DNR for approval, and the deposit of remediation funds into the registry of the court for expenditure on actual remediation rather than payment of those funds to the plaintiffs.  For more on Act 312, click on this blog's "Environmental" archive.

Louisiana DNR Promulgates Regulations Under Act 312

By Dana M. Douglas

On April 20, 2007, the Louisiana Department of Natural Resources (“DNR”) issued regulations establishing procedures for agency hearings and the submission and approval of remediation plans under Act 312 of 2006.  Act 312, which enacted La. R.S. 30:29, made sweeping changes to the procedures for litigation involving potential environmental damage to oilfield sites, in order to ensure that remediation awards are actually expended on remediation.  To view the new regulations, which are codified at La. Admin. Code tit. 43, § XIX, Ch. 6, click here.  Most significantly, the regulations establish that Statewide Order 29-B is the basis upon which the agency will evaluate such remediation plans.

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Act 312 Constitutionality Question Returns to Trial Court

As previously reported, the trial court in M. J . Farms v. ExxonMobil held Act 312 of 2006, governing remediation of oilfield sites, to be unconstitutional.  The Louisiana Supreme Court has now held that the plaintiff did not properly raise the issue of constitutionality at the trial court level, and remanded to allow the plaintiff to specifically plead the unconstitutionality of the act.  M. J. Farms, Ltd. v ExxonMobil Corp.,  No. 07-CA-0450 (La. 4/27/07).  The Court noted that appellate jurisdiction was not invoked because the issue was first raised in a memorandum rather than a pleading.

New EPA Air Toxics Rule Afflects Facilities with TEG Dehydrators

By:  Clare Bienvenu

On January 3, 2007, EPA promulgated a final rule amending 40 C.F.R. part 63, Subpart HH, “NESHAP (National Emission Standards for Hazardous Air Pollutants) for Source Categories from Oil and Natural Gas Production Facilities” to include the regulation of area sources. See 72 Fed.Reg. 26 (January 3, 2007).  The final rule is posted here.  Subpart HH has historically regulated various emissions points for major sources of air toxics in the oil and natural gas production industry. This amendment adds the regulation of benzene emissions from tetraethylene glycol (TEG) dehydration units at minor sources. The significance of this new rule is that all TEG dehydration units in the oil and gas production industry are now subject to Subpart HH unless they meet the exemption criteria provided in the regulations.  While the amendment adds the regulation of area sources, it does not alter any of the major source standards. Accordingly, any TEG dehydration unit already regulated under Subpart HH’s major source standards must continue to comply with those requirements. 

This article will first discuss control requirements for area source TEG dehydration units, which vary based on whether the unit is located within a high population density area, referred to as an “UA plus offset or UC.” The article will next discuss applicable compliance dates, which vary based on the date the TEG dehydration unit was constructed or modified and whether the unit is located in an “Urban 1 County” and/or a high population density area. Notably, this rule is immediately effective for any source constructed or modified on or after July 8, 2005 and for certain sources constructed or modified on or after February 6, 1998.

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Murphy Oil Spill Class Settlement Approved

On January 30, 2007, a class action settlement was approved in Turner v. Murphy Oil U.S.A., Inc., 05-4206 (E.D. La).  The Turner case asserted claims for property damage resulting from a release of oil from tanks located at Murphy's Meraux, Louisiana refinery after Hurricane Katrina.  The $330 million settlement includes a $55 million buyout program, a $120 million compensation program, a credit for $83 million in compensation already paid, and a $71 million remediation program (including credit for $51 million already expended for remediation).  In addition, Murphy agreed to pay plaintiffs' attorneys fees, which the court set at $33.7 million.  The Governor of Louisiana, Kathleen Blanco, testified in favor of the settlment at the Fairness Hearing.  To view the Court's order approving the settlement, click here. Continue Reading...

Louisiana DNR Issues Proposed Regulations Under Act 312

The Louisiana Department of Natural Resources has issued a proposed amendment to Statewide Order 29-B that details the procedures the Department will follow in implementing oilfield clean-up plans referred to the Department under Act 312 of 2006.  The Legislature passed Act 312 in 2006 to address the problem that damages awards in oilfield remediation litigation were not required to be expended on remediation.  Under the Act, the Department is involved in formulating a remediation plan, and the remediation funds are to be deposited in the registry of the court and actually spent on remediation.  The Commissioner of Conservation will conduct a hearing on the proposed regulations on Wednesday February 28, 2007.  Comments may be submitted at the hearing, or may be submitted in writing up to March 7, 2007.  To view the proposed regulations, click here.  Most notably, the draft regulations state that remediation plans must comport with the standards set forth in Order 29-B. 

Louisiana Trial Court Rules Act 312 Unconstitutional

On January 8, 2007, a Louisiana trial judge held Act 312 of 2006 to be unconstitutional.  The Louisiana Attorney General's office immediately filed notice that it will take a suspensive appeal directly to the Louisiana Supreme Court.  M.J. Farms, Ltd v. ExxonMobil Corporation 24,055 (La. 7th J.D.C. Jan. 8, 2007).  Act 312, which became effective June 8, 2006, requires involvement of the Louisiana Department of Natural Resources (DNR) in litigation alleging environmental contamination, including submission of any remediation plan to DNR for approval, and the deposit of remediation funds into the registry of the court for expenditure on actual remediation rather than payment of those funds to the plaintiffs.  For further information on Act 312, click here

The plaintiff in M.J. Farms argued that retroactive application of the Act to a suit pending at the time the statute was promulgated unconstitutionally divests the plaintiff of a property right, that is, the cause of action to recover money damages for environmental contamination.  The Louisiana Attorney General opposed that motion, asserting that the statute only concerns remediation of public harm, and does not deprive landowners of claims for redress of private harm.  The January 8, 2007 ruling by Judge Johnson of the Louisiana Seventh Judicial District Court held Act 312 to be unconstitutional and unenforceable.  The opinion is available here.

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Pipeline Canal Class Action Dismissed

In Barasich v. Columbia Gulf Transmission, et al., Judge Sarah Vance of the Eastern District of Louisiana dismissed a suit in which plaintiffs claimed that oil and gas production and pipeline companies’ activities in South Louisiana marshes contributed to the destruction wreaked by hurricanes Katrina and Rita. The plaintiffs alleged that dredging of pipeline canals and wellsite locations damaged the marshland, thereby weakening a protective barrier against storm surge and increasing the storm damage suffered by citizens of South Louisiana. Judge Vance held that the complaint failed to state a claim under the Louisiana obligations of neighborhood or Louisiana tort law, finding plaintiffs’ claims to be too “attenuated because they are suing for hurricane damage from storm surge allegedly magnified by coastal erosion caused by the canals, not for a direct loss of acreage due to erosion.” 


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