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.

A Key Decision: Supreme Court of Texas Sides with Liskow Amicus Brief on Behalf of TXOGA

By Butch Marseglia and Jillian Marullo

On June 20, 2014, the Supreme Court of Texas ruled in Key Operating & Equipment, Inc. v. Hegar (PDF) that a mineral lessee in a pooled oil and gas unit has the right to use the entire surface of the pooled acreage, regardless of the location of the producing well or whether actual production from beneath the accessed surface can be proven. Key Operating is a significant, though not surprising, victory for the Texas oil and gas industry. Liskow & Lewis attorneys Butch Marseglia and Jillian Marullo submitted an Amicus Curiae brief (PDF) on behalf of the Texas Oil and Gas Association.

Key Operating involved the surface rights of a mineral lessee operating in a pooled unit. Key Operating & Equipment, Inc. (“Key”) held oil and gas leases on two contiguous tracts, the Hegar Tract and the Richardson Tract. Key built a road across the Hegar Tract to access wells located on both tracts. In 2000, the only well located on the Hegar Tract stopped producing, and Key’s lease on that tract expired. That same year, Key’s owners purchased an undivided 12.5% interest in the mineral estate of the Hegar Tract and immediately leased that interest to Key in a lease which gave Key the right to pool the minerals. Key then pooled the Hegar and Richardson Tracts and continued to use the road across the Hegar Tract to access a producing well on the Richardson Tract. Soon after, Will and Loree Hegar purchased the surface of the Hegar Tract, and they later brought suit, claiming that Key’s use of the road constituted a trespass. The trial court enjoined Key from using the road on the Hegars’ property, finding that Key’s use was a trespass because it was not reasonably necessary to extract minerals from beneath the Hegar Tract.

The First Court of Appeals initially reversed, but on rehearing withdrew its opinion and affirmed, basing its decision on the trial testimony of a petroleum engineer that no minerals were being extracted from beneath the Hegar Tract by the well located on the Richardson Tract. The court first found that because Key’s lease and pooling agreements were not part of the Hegars’ chain of title (because they were not executed at the time of severance), they did not bind the Hegars and could not “contractually expand Key’s right to use the Hegars’ surface.” The court further reasoned that Key’s implied right to use the surface of the Hegar Tract was conditioned on proof of actual production from beneath that tract. Disconcertingly, the court of appeals held that the case was “decided under the accommodation doctrine,” which neither Key nor the Hegars contended applied.

The Texas Supreme Court unanimously reversed, holding that a mineral lessee has the right to use the entire surface of a pooled unit to produce minerals from anywhere on the unit. Noting that pooling serves the important Texas policy of preventing waste and relying on the longstanding legal principle that production anywhere on a pooled unit is treated as taking place on every pooled tract, the Court reasoned that

. . . once pooling occurred, the pooled parts of the Richardson and Hegar Tracts no longer maintained separate identities insofar as where production from the pooled interests was located. . . . Because production from the pooled part of the Richardson Tract was legally also production from the pooled part of the Hegar [T]ract, Key had the right to use the road to access the pooled part of the Richardson [T]ract.

The Court further reasoned that, as owners of 12.5% of the minerals beneath the Hegar Tract, Key’s owners had the right to use the surface to develop those minerals as well as the right to pool those minerals. Key’s owners’ inherent rights as mineral interest owners, therefore, which they leased to Key, “include[d] the right to ingress and egress over the surface of any pooled acreage for the purpose of producing minerals from any part of the pooled acreage.” Because the Court concluded that its decision turned on Key’s implied surface rights, it declined to address the court of appeal’s chain of title reasoning. However, the Court did note that “the Hegars took their surface title subject to the mineral lease assigned by Key’s owners to Key” which gave Key the right to pool and “gave rise to Key’s right to use the road.” The Court also declined to address the accommodation doctrine because it was not raised in the trial court and thus was not properly before the court of appeals.

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.