Marcellus operator unable to stay administrative proceeding regarding alleged water pollution

On October 7, 2014, the Pennsylvania Department of Environmental Protection (“DEP”) filed a complaint against a Marcellus operator with the Pennsylvania Environmental Hearing Board (“the Board”), alleging that the operator had violated Pennsylvania’s Clean Streams laws.  Prior to the complaint, the operator had filed a declaratory judgment action in Pennsylvania state court.  In the declaratory judgment action, the operator sought to establish the number of days that alleged violations occurred.  The operator alleged that an offer of settlement by the DEP, which the operator said miscalculated the number of days, constituted sufficient grounds to find that a controversy existed such that a declaratory judgment action was appropriate.

In response to the DEP’s October 7 complaint, the operator filed a motion to stay the administrative proceedings relating to the complaint.  The operator argued that resolving parts of the dispute before the Board will be a waste of time because any finding will be appealed to the court in which the declaratory judgment action is pending.  In response, the DEP noted that it has filed a motion to dismiss the operator’s declaratory judgment action on the grounds that the operator had failed to exhaust administrative remedies and was simply forum shopping.

On October 28, 2014, the Board denied the operator’s motion to stay.  The Board said that the “case is precisely the sort of case that is the raison d’ĂȘtre for the [Board],” and noted that a stay of Board proceedings is “an extraordinary measure that should only be granted for compelling reasons.”  The Board then opined that there was “significant value and efficiency in allowing . . . discovery [in the Board proceedings] because that factual development will eventually be needed one way or the other.”  Ultimately, the Board was skeptical that that motion to stay was anything other than a dilatory tactic and refused to grant a stay that, in the Board’s opinion, would have little benefit to the administration of justice.

Seismic activity and fracking concerns prompt new rules for oil and gas disposal wells in Texas

On October 28th, the Railroad Commission of Texas (“RRC”) amended its existing oil and gas disposal well regulations to require seismic activity data in permit applicants, provide for more frequent monitoring and reporting for certain wells, and allow modification, suspension, or termination of permits on grounds that a disposal well is contributing to seismic activity.  Specifically:
  • Applicants for a disposal permit must provide U.S. Geologic Survey (“USGS”) data regarding seismic events within a circular 100 square mile area centered on the well (a radius of approximately 5.64 miles).
  • The RRC may require additional information, including logs, geologic cross-sections, pressure front boundary calculations, and structure maps.
  • The RRC may require more frequent monitoring and reporting for disposal wells for which conditions may exist that would prevent fluids from being confined to the injection interval.
  • The RRC may modify, suspend, or terminate a permit if disposal is contributing to seismic activity, after notice and an opportunity for a hearing.
The amendments will be published in the Texas Register on November 14, 2014, and will go into effect on November 17, 2014.  The new rules are unlikely to pose a significant additional burden for most new wells and the estimated 50,000 existing oil and gas disposal wells in Texas.  However, if seismicity increases in the area of a well, the RRC will now have explicit regulatory provisions allowing it to impose injection pressure and rate limits, a temporary injection ban, or even outright cancellation of a disposal well permit.  


The amendments are the result of growing public scrutiny of hydraulic fracking and concerns over the past several years of a connection between earthquakes and the disposal of frack flowback and produced water.  Although disposal by underground injection is not new—the first federal Underground Injection Control regulations were promulgated in 1980—opposition to fracking, new wells, and certain seismic events have spurred many recent studies and debates. 
In March 2014, the RRC hired a seismologist to assist the agency in understanding the potential impact of oil and gas extraction activities and to clarify the root causes of earthquakes that some contend are connected to fracking.  RRC Commissioner David Porter commented that bringing a seismologist on board would allow the agency “to further examine any possible correlation between seismic events and oil and gas activity and gain a more thorough understanding of the science and data available.”[1]
In its introduction of the text of the now-final amendments, the RRC states that “[w]hile few earthquakes have been documented over the past several decades relative to the large number of disposal wells in operation, seismic events have infrequently occurred in areas where there is coincident oil and gas activity.”[2]  Therefore, the amendments incorporate several provisions that require additional collection and evaluation of seismic activities near proposed disposal wells, and the potential to impose additional monitoring and reporting of seismic data for areas surrounding existing disposal wells.

Amendments to Section 3.9 and Section 3.46

The new amendments modify Title 16, Sections 3.9 and 3.46 of the Texas Administrative Code, relating respectively to Disposal Wells and to Fluid Injection into Productive Reservoirs.  Although these sections regulate disposal into different types of formations, the language in both sections adopts the same new requirements and provides the RRC with the same level of authority. 
Section 3.9 governs disposal of saltwater or other oil and gas waste by injection into formations not productive of oil, gas, or geothermal resources.[3]  Section 3.46 governs fluid injection operations, including disposal, involving reservoirs productive of oil, gas, or geothermal resources.[4]  Of note, although Section 3.46 regulates injection into productive formations for both enhanced recovery and disposal, the new language relating to seismic activity applies only to wells permitted for disposal.
The new requirements for applicants are found in Sections 3.9(3)(B) and 3.46(b)(1)(C).  The amendments to these two subsections require applicants for disposal permits to include with the application a printed copy or screenshot showing the results of a survey of information from the USGS regarding the locations of any historical seismic events within a circular area of 100 square miles centered around the proposed disposal well location.
The above provisions are the primary difference between the amendments proposed by the RRC in August 2014 and the final amendments that are now adopted.  The proposal would have required that applicants include USGS historical seismic event information for within the estimated radius of the 10-year, five pounds per square inch (“psi”) pressure front boundary of the proposed disposal well location.  Ultimately, the RRC agreed with several comments that this requirement was too complex and had the potential for error and, instead, adopted the 100 square mile area language discussed above.[5]
The other amendments formally recognize the RRC’s authority to regulate seismic activity related to the disposal wells.  For example, if the well is to be located in certain areas seen as having an increased risk that fluids will not be confined to the injection interval,[6] the amendments authorize the RRC to request additional information during the permitting process (Sections 3.9(3)(C) and 3.46(b)(1)(D)) and more frequent monitoring and reporting of injection pressure and injection rates (Sections 3.9(11)(A)–(B) and 3.46(i)(1)–(2)).  For certain wells, the RRC might impose additional monitoring as a condition of the issued permit.  One would also expect that, after identifying an increase in seismic events, the agency would impose increased monitoring on existing wells in the area.
Additions to Sections 3.9(6)(A)(vi) and 3.46(d)(1)(F) amend the RRC’s existing authority to modify, suspend, or terminate a disposal permit to allow such an action based on grounds that the injection is likely to be or has been determined to be contributing to seismic activity.  These actions would require notice to the well operator and a hearing.  This amendment could allow the RRC to terminate permits, but could also be used to impose limits on injection rates and pressures, or other conditions intended to mitigate any contribution to seismic activity.

Read the final rule.
[3] 16 Tex. Admin. Code § 3.9.  
[4] 16 Tex. Admin. Code § 3.46(a). 
[5] Of note, the RRC may still require that applicants submit pressure-front data; however, this data would likely be requested only if the well is an area “where conditions exist that may increase the risk that fluids will not be confined to the injection interval.”  See infra text accompanying note 6.  A “pressure front” is defined as the zone of elevated pressure that is created by the injection of fluids into the subsurface.  A “10-year, five psi pressure front boundary” is defined as the boundary of increased pressure of five psi after 10 years of injection at the maximum requested permit injection volume. 
[6] The RRC identifies the following conditions as several factors that may increase the risk that fluids will not be confined to the injection interval: complex geology, proximity of the basement rock to the injection interval, transmissive faults, and/or a history of seismic events in the area shown by information from the USGS.

This post was written by Eva Fromm O'Brien ( or +1 713.651.5321), Jennifer Caplan ( or +1 713.651.5372) and  Bob Greenslade ( / 303 801 2747) from Norton Rose Fulbright's Environmental Practice Group

Environmental groups lose court challenge over fracking water use

The British Columbia Supreme Court has dismissed a legal challenge to decisions of the B.C. Oil and Gas Commission (OGC) to grant successive, short-term approvals to EnCana Corporation to withdraw fresh water from B.C.'s lakes, rivers and streams for use in hydraulic fracturing operations. Under B.C.'s Water Act, all surface water is owned by the government and diversions are only allowed pursuant to a two year approval or a long-term license. A two year approval application is subject to less regulatory scrutiny than a long-term license application, and does not require the same public notice requirements.

The OGC granted various two year approvals to EnCana. The Western Canada Wilderness Committee and the Sierra Club filed a petition in the Supreme Court seeking to vacate the OGC's decisions to issue successive, two year approvals for water withdrawals from the same source. The petitioners claimed that although no one approval was for more than two years, multiple approvals were granted back to back over multiple years to EnCana for the same purpose and for diversions at the same locations, thereby effectively violating the two year term limit. The petitioners said that the OGC should have required EnCana to apply for long-term licenses instead of successive two year approvals.
The Court found that the Water Act did not prohibit the OGC's practice and deference should be given to the OGC in how it manages the issuance of approvals and licenses. The Court dismissed the claim.

This post was written by Barclay Nicholson ( or 713 651 3662) and Alan Harvie ( or +1 403.267.9411)from Norton Rose Fulbright's Energy Practice Group.

The New York Court of Appeals rules on local ban on fracking

The New York Court of Appeals recently denied an energy company’s motion for rehearing in Matter of Wallach v. Dryden. Matter of Wallach was a consolidated appeal in which the court heard challenges to local fracking bans enacted in the Towns of Dryden and Middlefield. The parties challenging the bans argued that the local laws were preempted by state law.

The court held that the Oil, Gas and Solution Mining Law (OGSML) did not preempt local bans on hydraulic fracturing. The court reasoned that the towns had authority to enact the zoning laws banning fracking under the doctrine of home rule. In the court’s view, the OGSML only regulated oil and gas operations. Although the local laws would impact hydraulic fracturing, the court concluded that the ordinances were focused primarily on zoning and, thus, not preempted.

In its motion, the energy company relied on several cases in Colorado holding that state law preempted similar local fracking bans. A court in West Virginia has also found that state law precludes a city from prohibiting hydraulic fracturing. The energy company’s position was that the precedential value of Matter of Wallach is limited. The parties challenging the ban in Middlefield did not file a motion for rehearing.

Read the court’s decision in Matter of Wallach.

This post was written by Barclay Nicholson ( or 713 651 3662) and Johnjerica Hodge ( or 713 651 5698) from Norton Rose Fulbright's Energy Practice Group.

Proposed class action filed in Illinois state court challenging denial of fracking permits

Amy Pollard and a number of mineral rights owners have filed a proposed class action against the state of Illinois in the Circuit Court for the Second Judicial Circuit of Illinois. Plaintiffs allege that Illinois’s refusal to grant fracking permits violates their rights under the Fifth Amendment of the United States Constitution as well as their rights under the Illinois constitution. Specifically, Plaintiffs argue that the state’s conduct constitutes an unconstitutional taking without just compensation.

Although Illinois law permits fracking, the state has failed to issue regulations governing fracking permits. Oil and gas operators have therefore been unable to obtain drilling permits. Plaintiffs allege that their mineral rights are worthless without a permit because they cannot receive any royalties until drilling commences. In the complaint, Plaintiffs state that mineral rights owners have already leased thousands of acres to oil and gas operators.

Plaintiffs request attorney fees and at least $50,000 in damages for each member of the class. The class is limited to owners of mineral rights in the New Albany Shale formation in Wayne County. Plaintiffs estimate that the class could ultimately include more than one thousand mineral rights owners.

Pennsylvania bill requiring monthly reporting of natural gas production heads to the Governor

On October 15, 2014, Pennsylvania legislators approved a bill that would require monthly reports of natural gas production from wells in unconventional formations. Operators of such wells are currently required to report natural gas production to the Pennsylvania Department of Environmental Protection on a semi-annual basis.

The legislative impetus to approve the bill may be connected to recent royalty complaints. In particular, one operator has come under increased scrutiny from the Governor, who recently called on the state’s attorney general to investigate allegations of royalty underpayment. Complainants have also filed suit against the operator regarding those allegations.

However, the monthly-reporting bill has another logical basis: landowners are paid royalties on a monthly basis, so monthly production reports could help serve as a way for those landowners to verify that their royalty payments match the actual production of natural gas. Thus, even for operators, the bill may have some benefits if it increases landowner confidence that the operators are properly compensating them for the use of their land and mineral resources.

Do UK regulatory changes signal large-scale shale gas exploitation?

The 14th onshore licensing round closes on October 28, 2014 for both conventional and ‘unconventional’ oil and gas exploration, including shale gas. The UK Department of Energy and Climate Change (DECC) expects about 50-150 unconventional licences to be awarded in the round.

There is general consensus across industry and Government that a more streamlined regulatory regime and improved land access rights would facilitate shale gas projects. DECC has recently considered proposed changes regarding land access and sub-surface rights to reduce barriers to shale gas development in the UK.

Petroleum Exploration and Development Licences (PEDLs) allow companies to pursue a range of activities involving energy reserves, including unconventional gas, subject to necessary drilling/development consents and planning permission. Some companies drilling mainly for conventional oil and gas are now drilling deeper than they might have to investigate the shale potential in their licenced areas (“coring” is foreseen in these cases but no fracking is currently involved).

Changes in planning permissions

Proposals for shale gas exploration or extraction (like all other reserves) are subject to approval by the Minerals Planning Authority (MPA) for the area where the reserve is located. Since January 2014, the requirement to notify individual owners and tenants of land where only underground operations will take place has been removed; only those where aboveground work is planned must be served notice.

In addition, although “material considerations” may be allowed in planning permission decisions, the Supreme Court held that issues such as loss of property value, loss of view and opposition to the principle of development are not “material” considerations. The MPA local planning authorities also have greater freedom to act on oil and gas extraction projects than they normally would because the Government excluded these projects from the aegis of the National Planning Policy Framework, the major infrastructure planning regime in the UK.

Proposed land access reforms

In the 2010 landmark Bocardo case[1], the Supreme Court found that an oil and gas company had committed trespass by drilling and installing pipelines under the landowner’s land, even though the deepest well was 2,800 ft below the surface.

The case confirmed that any activity on or under a landowner’s land, even deep underground, will constitute trespass. Under the current regime, coming to an agreement for access with multiple landowners or pursuing so-called ancillary rights under statutory law, can cause long delays. The Government’s proposed changes include:
  • granting automatic underground access rights to shale gas operators for horizontal drilling at least 300m below the surface;
  • a voluntary community payment of £20,000 for each unique horizontal well that extends more than 200m laterally (for projects benefitting the community);
  • public notification of drilling proposals and details of the voluntary payment.
The proposal does not apply to any work above 300m depth; therefore, access for the drilling pad itself will be subject to negotiation with the landowner or the ancillary rights regime.

Still it appears that legislation will be put before Parliament to implement a more streamlined system and rights of access. With the exploration licenses expected in the current licensing round, the outlook is positive for greater shale gas exploration and production in the UK.

[1] Bocardo SA v Star Energy [2010] UKSC 35

This post was written by Lucy Bruce Jones ( or +44 20 7444 5159) from Norton Rose Fulbright's Energy Practice Group.

Revisions to proposed fracking regulations in California

California recently circulated its third version of S.B. 4., a bill passed last year that sets forth rules regarding well stimulation operations. The California Department of Conservation’s Division of Oil, Gas and Geothermal Resources received over 100,000 comments from the public regarding the first version of S.B. 4. The second version of the bill also received a significant number of comments.

The third version of the bill features several changes from the previous versions. For example, the threshold for reporting seismic activity occurring near wells has been increased to require a magnitude of at least 2.7. In addition, whereas well operators initially had to apply for a water permit before applying for a fracking permit, operators may now apply for both permits simultaneously. The twenty-day deadline for requesting water quality testing has also been amended to permit residents to request testing irrespective of whether twenty days have passed since the resident received notification that well stimulation would occur. If the twenty-day period has passed, however, the resident would be responsible for paying for the testing.

Multiple groups have expressed displeasure with the bill. Some environmentalist groups have argued that the state should not permit fracking. Even members of the oil and gas industry have noted that aspects of the bill are problematic. The public has fifteen days to submit any comments on the bill.

Read S.B. 4.

This post was written by Barclay Nicholson ( or 713 651 3662) and Johnjerica Hodge ( or 713 651 5698) from Norton Rose Fulbright's Energy Practice Group.

DOJ and Pipeline Operator spar over the proper way to calculate a Clean Water Act penalty

On October 8, 2014, the U.S. Department of Justice (the “DOJ”) filed a motion regarding the proper way to calculate a Clean Water Act (“CWA”) penalty.  The dispute turns on whether the penalty for a prohibited discharge of oil should be based simply on the amount of oil discharged or instead on the amount of discharged oil that makes its way into a navigable body of water.  In its motion, the DOJ argues that the plain language of the CWA calls for penalties based on the amount of oil “discharged” without any requirement that the oil reach a navigable body of water.  The pipeline operator has previously argued in court filings that such a measure improperly extends the CWA beyond its terms and would represent a Congressional overstep of the Federal government’s Commerce Clause authority.

While at its heart the dispute is a matter of statutory interpretation and constitutional law, its result may well have major impacts on the rest of the litigation.  If the court determines that the DOJ’s reading of the CWA is correct, proving the amount of oil discharged may not be too complicated.  The DOJ could prove the amount by, for example, showing the volume of oil pumped into the pipeline and the volume of oil that reached its intended destination, with the difference approximating the amount of oil discharged.  However, if the court follows the pipeline operator’s reading of the CWA, the DOJ will likely be presented with significant evidentiary challenges, because once the oil was discharged, it likely dispersed in complex, difficult-to-track ways.

The dispute is currently before the U.S. District Court for the Eastern District of Arkansas.

This post was written by Barclay Nicholson ( or 713 651 3662) and Jim Hartle ( or 713 651 5695) from Norton Rose Fulbright's Energy Practice Group.

Middle District of Pennsylvania holds lessor is bound by change of ownership provision, lessee properly extended lease

In a case of first impression in Pennsylvania, Judge Matthew Brann of the United States District Court for the Middle District of Pennsylvania held that an extension payment made by a predecessor-in-interest of the lessee to a predecessor-in-interest of the lessor was sufficient to extend the lease, where the lessee did not have notice of the change in ownership as required by the lease.

In Danko Holdings, LP v. EXCO Resources (PA), LLC, the lease at issue provided that the lessee was not bound by a change in ownership “until furnished with such documentation as Lessee may reasonably require.”  The original parties to the lease made several assignments of interest, but neither the lessors nor their successors provided the lessee or its successors with notice of the change in ownership.  The plaintiff, Danko, was a successor of the lessor.  Danko sought a declaration that the lease had expired by its own terms because the predecessor of defendant EXCO made the extension payment to the original lessors who, at the time of the payment, had already assigned their interest.
Judge Brann held that because EXCO and its predecessors had not been provided with notice of the change in ownership, the payment made to the original lessors was sufficient to extend the lease under the change in ownership provision.  As the issue was novel under Pennsylvania law, Judge Brann relied on authority from other state and federal courts, as well as prominent oil and gas treatises, to conclude that change of ownership clauses are valid features of oil and gas leases and are strictly construed.  Moreover, Judge Brann held that constructive or actual notice of the change in ownership will not obviate a change of ownership clause.  The plain language of the lease required Danko or its predecessors to provide documentation of the change in ownership.

Judge Brann's opinion.

This post was written by Barclay Nicholson ( or 713 651 3662) and Michael Gaetani ( or 724 416 0400) from Norton Rose Fulbright's Energy Practice Group.

Pennsylvania Department of Environmental Protection proposes changes to oil and gas enforcement policies

On October 4, 2014, the Pennsylvania Department of Environmental Protection (“PADEP”) published notice of a draft policy titled "Standards and Guidelines for Identifying, Tracking, and Resolving Oil and Gas Violations" (the “Proposed Policy”).  The Proposed Policy contains new processes and revises existing guidelines and will have an impact on how operators interact with the PADEP.

The Proposed Policy introduces a new, detailed process for how the PADEP will handle water supply contamination complaints.  The Proposed Policy contemplates that an onsite investigation will be conducted within 4 business days of receiving the complaint, and a final determination made within 45 calendar days, unless there are extenuating circumstances.  The PADEP may order the operator to provide temporary water supplies to the complainant either before or after the final determination on contamination is made, depending on whether the water supply is located within the “rebuttable presumption area” (1,000 feet for a conventional well and 2,500 feet for an unconventional well).  If a final positive determination of contamination is made, the PADEP shall issue a notice of violation (“NOV”) to the operator and, after allowing an opportunity for the operator to respond, shall issue an administrative order to replace or restore the affected water supply unless (1) the water supply has already been replaced or restored, (2) the investigation request has been withdrawn, (3) the operator and water supply owner have reached an agreement, or (4) the water supply is no longer contaminated or diminished.

The Proposed Policy also addresses existing guidelines and policies.  One of these changes provides for more aggressive issuance of NOVs, which will now be issued for all violations noticed during an inspection, unless the violation is corrected by the end of the inspection visit.  Currently, an NOV will issue only if the violation is not corrected within 14 days of the inspection visit.  Other topics addressed by the Proposed Policy include a revised well inspection schedule, the process for on-site inspections, the issuance of administrative orders, permit suspension and revocation, the imposition of civil penalties, and a 180-day negotiation deadline for certain enforcement documents.

The PADEP is accepting public comments on the Proposed Policy until November 2, 2014. View the Proposed Policy.

This post was written by Barclay Nicholson ( or 713 651 3662) and Michael Gaetani ( or 724 416 0400) from Norton Rose Fulbright's Energy Practice Group.

Eighth Circuit refuses to overturn jury verdict despite allegations that verdict was tainted

In Hiser v. XTO Energy, Inc., the Eighth Circuit affirmed a jury verdict against XTO Energy, Inc. (XTO) and rejected XTO’s argument that the district court should have granted its motion for a new trial. The appeal was heard by Judge Duane Benton, Judge Michael J. Melloy, and Judge Bobby E. Shepherd. Hiser involved allegations by the plaintiff that she suffered damages due to XTO’s drilling operations on a neighbor’s property.

During deliberations, the jury asked the district court whether XTO’s drilling operations included fracking or only drilling. The judge responded that the jury could only consider evidence presented by the parties. After XTO moved for a new trial, the parties submitted affidavits from multiple jurors. The jurors stated that they discussed fracking before the court’s instruction; however, those discussions ceased after the court instructed them to only consider the evidence presented at trial.

The jurors disagreed on the extent of their fracking discussion. Whereas one juror stated that they discussed the potential negative effects of fracking on the plaintiff, another juror stated that there was no discussion of the negative impact of fracking. Indeed, another juror stated that they merely discussed fracking generally. The jurors also disputed whether they discussed earthquakes, a topic that was mentioned only briefly at trial.

The Eighth Circuit rejected XTO’s argument that the district court abused its discretion by not ordering a new trial. The panel reasoned that the district court’s instruction adequately reduced any potential risk of prejudice. Moreover, the panel noted that there was no evidence of prejudice. Even assuming that the jury discussed earthquakes before the court’s instruction, the panel concluded that the discussion did not impact the verdict or prejudice XTO. 

Furthermore, if the jury discussed earthquakes after the court’s instruction, the panel reasoned that there was no prejudice because the discussion did not reference the plaintiff or XTO. Lastly, the panel held that even if the jurors discussed extraneous information, XTO did not demonstrate that it suffered any prejudice or that the verdict was impacted.

IPAA response to proposed rule on transportation of crude oil by rail

The Independent Petroleum Association of America (IPAA) and the North Dakota Petroleum Council (NDPC) recently submitted comments regarding the proposed rule concerning the shipping of crude oil by rail. In the rule, the Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) specified, among other things, that the tanker car fleet currently used must be retrofitted within a two-year period to comply with heightened standards specified in the rule.

The IPAA and NDPC commented that, according to industry experts, at least six years are needed to replace the current fleet. Imposing a two-year phase-out would, in the IPAA and NDPC’s view, hinder oil producers from timely providing the market with crude oil. Additionally, the IPAA and NDPC argued that the PHMSA unnecessarily targeted Bakken crude oil because it does not impose a heightened safety risk. For support, the IPAA and NDPC relied on several reports that Bakken oil is not more dangerous that crude oil in other areas of the United States.

Read additional concerns raised by the IPAA and NDPC.

This post was written by Barclay Nicholson ( or 713 651 3662) and Johnjerica Hodge ( or 713 651 5698) from Norton Rose Fulbright's Energy Practice Group.

Twelve senators weigh in on rules for fracking on public lands

In a letter dated September 30, 2014, twelve Senate Democrats urged the implementation of “the strongest possible safeguards” for the use of hydraulic fracturing on Federal lands. The letter comes on the heels of the Department of the Interior sending rule(s) for “governing the practice of hydraulic fracturing on public lands” to the Office of Management and Budget (“OMB”) for finalizing.

While the letter does not have the level of specificity one would expect the eventual rule(s) to have, the Senators urged the inclusion of three requirements they deem “imperative”: 

  1. “[r]obust requirements for public disclosure of all [fracking fluid] chemicals and additives; 
  2. a free, searchable public database containing such disclosures; and 
  3. “[s]trong and consistent requirements for well construction and integrity and wastewater management for every well drilled on public lands . . . .” In the Senators’ words, the “rule should serve to build on existing state standards in a way that ensures there is a floor of protection in all states.”
The text of the rule(s) has not yet been released. However, you can review the May 2013 draft of the rule(s).”
This post was written by Barclay Nicholson ( or 713 651 3662) and Jim Hartle ( or 713 651 5695) from Norton Rose Fulbright's Energy Practice Group.

Bill proposal to prohibit entry of fracking drill cuttings waste into New York

Senator Ten O’Brien proposed a bill on Monday to prohibit landfills in New York from accepting drill cuttings waste. O’Brien, a member of the Senate’s Environmental Conservation Committee, voiced concerns of the potential environmental damage that could be caused by the waste. This measure is supported by groups such as the New York League of Conservation Voters.

O’Brien’s proposal is one of several proposals targeted at hydraulic fracturing waste in New York. Another proposed bill requires municipal wastewater treatment facilities to satisfy additional statutory requirements before accepting hydrofracking wastewater. Other legislation targets the transportation of hydraulic fracturing byproducts into and from water treatment plants. In fact, local laws in Niagara Falls and Buffalo prohibit the transportation of those products.

Attempts to impose additional regulations on fracking have failed, however, to garner sufficient support in the State Senate. For more information about the bill proposals discussed above, please visit the New York State Senate website and review Bill S7783-2013 and Bill S5123A-2013.
This post was written by Barclay Nicholson ( or 713 651 3662) and Johnjerica Hodge ( or 713 651 5698) from Norton Rose Fulbright's Energy Practice Group.

Oil rail safety transport improvements will be costly

Proposed federal regulations on oil rail transportation will be costly to implement. Responding to concerns about the increase of oil rail transport and several high profile accidents, the US Department of Transportation (“DOT”) has proposed new rules to strengthen the safety standards for the rail transport of crude oil and ethanol. These improvements include new tank car standards, oil spill response plans and requirements for securing unattended rail cars.

Over a 20-year period, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) estimates that it will cost billions of dollars for stakeholders to enact the improvements necessary to comply with the proposed regulations. Though rail carriers and rail car manufacturers and owners likely will shoulder most of the costs, oil and gas companies will experience rising costs in higher purchase prices, lease rates and additional fees as the rail industry seeks to offset its higher operating costs. Further, the proposed regulations include requirements for lower speed limits and rail routing risk analyses, which could lead to transportation delays and longer delivery routes.

Currently, the proposed rules do not require oil and gas producers to “stabilize,” or remove natural gas liquids, the crude oil from the Bakken Shale before shipping it by rail. However, because the DOT has concluded that Bakken crude oil has high volatility, analysts predict that a stabilization requirement may be forthcoming. Stabilizing crude oil prior to rail transport will significantly costs for oil and gas producers.

Read more about new federal oil rail safety regulations.