Reports show Bakken crude oil within safety standards

The North Dakota Petroleum Council (NDPC) and the American Fuel & Petrochemical Manufacturers (AFPM) recently released the results of studies relating to the characteristics of Bakken crude oil and the standards required to transport crude oil by rail.

These studies in part respond to a safety alert issued on January 2, 2014, by the Pipeline and Hazardous Materials Safety Administration (PHMSA), which notified “the general public, emergency responders, and shippers and carriers that recent derailments and resulting fires indicate that the type of crude oil being transported from the Bakken region may be more flammable than traditional heavy crude oil.”

The May 14, 2014 report prepared for AFPM presents testing data that demonstrates that “Bakken crude is well within the safety standards for current rail car designs.” The data also shows that “Bakken crude is comparable to other light crudes and does not pose risks that are significantly different than other crudes of flammable liquids authorized for rail transport.”

Because Bakken crude is within the regulatory limits for pressure, flashpoint, boiling point and corrosivity for use in Department of Transportation (DOT) approved railcars, AFPM concludes that Bakken crude is a Class 3 Flammable Liquid and there is no need to create a new DOT classification for crude oil transportation.

At a conference on May 20, 2014, the NDPC released a study in which Bakken crude was found to be a typical Class 3 flammable liquid, with little variation throughout the entire basin. The data shows that Bakken crude is similar to other light crudes in average API gravity, average vapor pressure, a flashpoint below 73° Fahrenheit, average initial boiling point, and average sulfur weight. These characteristics fall within the design thresholds for the current DOT-111 tanker car. According to the NDPC, this study confirmed that Bakken crude is not significantly differed from other crude oil and poses no greater risks than other Class 3 flammable liquids authorized for rail transport.

Transportation of crude oil by rail has increased dramatically with the development of shale oil plays throughout the United States. According to the U.S. Energy Information Administration, nearly 1.4 million barrels per day of petroleum products were transported by rail in the first half of 2013, an increase of nearly 50% over the 927,000 barrels shipped in the first half of 2012.

For additional information on the transportation of crude oil by rail, visit some of our previous blog posts:

New rule for rail cars carrying hazardous materials being reviewed

On May 20, 2014, before a Subcommittee of the House of Representatives’ Transportation and Infrastructure Committee, Cynthia Quarterman, the administrator of the Pipeline and Hazardous Materials Safety Administration (PHMSA) reported that a new rule relating to “tank car issues” and to operational and safety issues surrounding the transport of hazardous materials had been forwarded to the Office of Management and Budget (OMB) for review.

According to Ms. Quarterman, this new rule includes a “comprehensive approach to rail safety” and was written with the assistance of the Federal Railroad Administration. Currently PHMSA is responding to questions from the OMB concerning the practical and economic effects of the rule. It is anticipated that the OMB’s review will take approximately 90 days.

The meeting before the Subcommittee on Railroads, Pipelines and Hazardous Materials was held to address the implementation of the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 which was passed after the September 2010 California pipeline explosion in which eight people were killed and 38 homes were destroyed.

Industry spokesmen testified that they were concerned about the continuing “regulatory uncertainty” due to the lack of clear rules and a seeming lack of urgency to prepare those rules. Ms. Quarterman responded that, while a lack of funds has slowed PHMSA’s ability to develop the rules, PHMSA has completed 21 of the Act’s 42 mandates, with another 13 in progress and eight behind schedule. PHMSA is also in the process of finalizing a rule for gas transmission.

This post was written by Barclay Nicholson ( or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.

North Carolina lawmakers consider proposed Energy Modernization Act

In July 2012, North Carolina’s state assembly overrode the governor’s veto to enact a bill lifting a ban on hydraulic fracturing and requiring state regulators to pass and implement rules relating to hydraulic fracturing activities, including the disclosure of chemicals to state agencies and local emergency responders, by October 1, 2014.

On May 15, 2014, several state senators introduced a bill (S.B. 786 or Energy Modernization Act) to extend the deadline to January 1, 2015, and to modify certain provisions relating to oil and gas activities.

The bill provides for the confidentiality of hydraulic fracturing chemicals, “upon a showing satisfactory to the [North Carolina Oil and Gas] Commission by any person that [the] information…, if made public, would divulge methods or processes entitled to protection as confidential information…” § 113-391A(b). The designated custodian of the confidential information would be the state geologist. § 113-391A(b).

There are exceptions for health care providers and fire department officials who need the information for emergencies. If confidential information is given to the emergency personnel, the owner of that information must be notified within 24 hours. The owner may require the emergency personnel to sign a confidentiality agreement. § 113-391A(c)(2) and (3).

The bill provides for penalties if the confidential information is unlawfully disclosed. Any person who has access to the confidential information and who knowingly discloses that information is guilty of a Class I felony; and, if the information is knowingly or negligently disclosed, the person is subject to civil action for damages. § 113-391A(d).

Other provisions of the bill include:
  • At least 30 days before initiating any operations, an oil and gas developer or operator must provide the lessor with written notice that describes the exploration or development plan. § 113-420(b2).
  • There is a presumption that an oil and gas operator is responsible for contamination of all water supplies that are within one-half mile radius of a wellhead unless (1) the contamination existed prior to the commencement of drilling activities, (2) the landowner refused pre-drilling testing of the water, (3) the water supply is not within the one-half mile radius of the operator’s activities, or (4) the contamination was caused by something other than the operator’s activities. § 113-421(a). 
  • Any local ordinance that prohibits or has the effect of prohibiting oil and gas exploration, development, and production activities is invalid as being preempted by the Mining and Energy Commission. § 113-415A(a). However, a local zoning or land-use ordinance is presumed to be valid and enforceable to the extent the ordinance imposes requirements, restrictions, or conditions that are generally applicable to development, including but not limited to setback, buffer, and storm water requirements. § 113-421(f).
  • Subsurface injection of wastes from oil and gas operations including hydraulic fracturing treatments is prohibited. § 113-395B.
  • Persons collecting seismic and geophysical data may only conduct such activity by undershooting from an off-site location unless the landowner’s consent is given in writing. Persons conducting seismic activities are civilly liable for any physical or property damage caused by those activities. § 113-395D.

This post was written by Barclay Nicholson ( or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.

Environmental groups protest drilling in Utah and Nevada

On May 7, 2014, WildEarth Guardians filed a complaint in the US District Court, District of Utah, Central Division, against the US Forest Service and the US Bureau of Land Management, seeking to enjoin these agencies from approving oil and gas drilling in the Ashley National Forest, located in the Uinta Basin.

In a Record of Decision (ROD) based on a Final Environment Impact Statement (FEIS) and other documents, the Forest Service approved a 400-well project on February 12, 2012. This 400-well project on 162 well pads is being developed on 25,900 acres in the Ashley National Forest and will require the surface disturbance of 836 acres, 57 miles of new roads, 493 stripped acres for well pads, four four-acre compressor stations and 87 miles of natural gas pipeline.

WildEarth Guardians argue that the Forest Service and the Bureau of Land Management “failed in their legal obligations to take a hard look at the impacts of the 400-well Project on sage grouse [considered to be a threatened and endangered species], roadless areas and air and water quality and,…to prevent and mitigate the adverse consequences the project will have on these natural resource values.”

The agencies also failed to examine alternative actions that would allow development while still protecting sage grouse and roadless areas and while moving toward compliance with air and water quality standards.

On May 12, 2014, the Center for Biological Diversity filed a formal protest with the Bureau of Land Management, opposing an upcoming oil and gas lease sale in Nevada that could open up more than 174,000 acres for oil and gas development, including hydraulic fracturing.

The group complains that the Bureau failed to adequately analyze the project’s impacts to water resources, air, wetlands, riparian zones, climate and sensitive species of plants and wildlife, including the sage grouse. The Center wants the Bureau to cancel the Nevada lease sale or, at a minimum, defer the sale until deficiencies in the Bureau’s environmental assessment can be addressed.

On May 16, 2014, WildEarth Guardians issued a statement complaining about a proposed 5,000-well fracking project covering 1.5 million acres in the Powder River Basin of Wyoming, threatening the sage grouse population and greatly increasing greenhouse gas emissions.

This post was written by Barclay Nicholson ( or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.

Federal Judge in North Dakota dismisses thirteen gas-flaring royalty lawsuits

On May 14, 2014, US District Judge Daniel L. Hovland dismissed thirteen proposed class actions in which the plaintiffs sought payment of royalties for gas that was flared by oil and gas companies after flaring was permitted by North Dakota statute. The Judge ruled that the US District Court did not have subject matter jurisdiction because the plaintiffs had not exhausted their administrative remedies through the North Dakota Industrial Commission, the state agency that regulates oil and gas activities, including flaring violations.

The plaintiffs did not file a complaint with the Industrial Commission, arguing that exhaustion of administrative remedies was not required because the primary issues in the lawsuits concerned statutory construction or pure questions of law.

The Court disagreed, stating that the cases rest “upon the resolution of fairly technical and complex questions of fact and law,” including “(1) the volume of gas flared…, (2) the value of such flared gas; and (3) the application of the relevant Industrial Commission orders that pertain to each well.” The Court concluded that “[n]o decision-maker is better equipped to resolve such issues than the Industrial Commission itself which is possessed of the authority, experience and expertise to make such determinations.”

While recognizing “this may not be the Plaintiff’s preferred remedy, but it is the remedy nonetheless…,” the Court found no implied private right of action that would make the administrative remedy moot and that the plaintiffs could appeal any adverse decision from the NDIC in court.

Here is a copy of the order in one of the thirteen lawsuits, Scott Wisdhal, et al. v. XTO Energy, Inc., Case No. 4:13-cv-136, In the US District Court for the District of North Dakota, Northwestern Division. For additional information on all thirteen lawsuits, see the White Paper: Analysis of Litigation Involving Shale and Hydraulic Fracturing which is attached to this blog.

It should be noted that a fourteenth lawsuit based on the same allegations is in state court, Vogel, et al. v. Marathon Oil Company, Case No. 31-2013-cv-00163 (In District Court of Mountrail County, North Dakota, Northwest Judicial District).

This post was written by Barclay Nicholson ( or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.

Three-year moratorium on disposal of fracking waste in Connecticut

On May 7, 2014, the Connecticut legislature passed a three-year moratorium on the storage, treatment, disposal and transportation of all hydraulic fracturing waste within the state even though no fracking is being done and there are no facilities handling drilling waste.

Noting that this bill is “pre-emptive action,” the bi-partisan sponsors expressed concern that near-by New York state which is considering lifting its moratorium on hydraulic fracturing “could send waste to Connecticut.”

The moratorium is to allow the state’s Department of Energy and Environmental Protection (DEEP) to research the materials used in hydraulic fracturing and to “submit regulations to the Regulations Review Committee for approval after June 30, 2017 and no later than July 1, 2018.”

The regulations “must (1) subject the [fracking] wastes to the state’s hazardous waste management regulations; (2) ensure any radioactive components of the wastes do not pollute the air, land, or waters or otherwise threaten human health or the environment; and (3) require disclosure of the composition of the wastes.”

This post was written by Barclay Nicholson ( or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.

Pennsylvania legislators propose statute relating to seismic testing

On May 13, 2014, several members of the Pennsylvania House of Representatives proposed a new statute relating to seismic testing (H.B. 2254).

The bill will make it “a rebuttable presumption of law that a person conducting seismic testing is liable and responsible for all damage within 1,000 feet of where the seismic testing was conducted without proof of fault, negligence or causation.” Any claim under the statute “must arise or be made within 90 days of the completion of seismic testing.”

The statute allows a defense to the presumption only if one of the following is established by clear and convincing evidence:

  1. The damages existed prior to the seismic testing.
  2. The damage was not within 1,000 feet of the seismic testing.
  3. The damages occurred as a result of some cause other than the seismic testing.
The bill has been referred to the Judiciary Committee for consideration.

This post was written by Barclay Nicholson ( or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.

Three railroad employees charged with criminal negligence in Quebec train derailment

The prosecutor’s office for the province of Quebec filed criminal negligence charges relating to the July 6, 2013 derailment of an unattended 72-car freight train in the town of Lac-Mégantic. The derailment caused tank cars carrying Bakken crude oil to rupture, explode, and burst into flame, resulting in the deaths of forty-seven people and environmental contamination.

On May 13, 2014, the bankrupt Montreal Maine and Atlantic Railroad, Ltd. (MMAR) and three of its employees (the train engineer, the railway traffic controller, and the train operations manager) were each charged with 47 counts of criminal negligence. In Canada, criminal negligence that results in death is punishable by up to life in prison.

Wrongful death lawsuits for the victims have been filed in US and Canadian courts, with the US lawsuits in the US District Court for Maine to proceed alongside MMAR’s bankruptcy case.

Questioning the safety of tanker cars and the flammability of Bakken oil, US and Canadian authorities have issued safety alerts, emergency orders, and protective directions relating to the testing and classification of crude oil transported by rail, notification to state emergency officials of the movements of trains carrying crude oil within each state, and the phase-out of the least crash-resistant DOT-111 tank cars from transporting oil.

This post was written by Barclay Nicholson ( or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.

Report prepared by UK Parliament Committee urges development of natural gas and the use of hydraulic fracturing

On May 8, 2014, the House of Lord s Economic Affairs Committee strongly endorsed the United Kingdom’s development of shale gas resources and the use of hydraulic fracturing in its report entitled “The Economic Impact on UK Energy Policy of Shale Gas and Oil.” Successful development would provide substantial economic benefits, reduce imports, and help maintain security of supply.

Pointing to the successful development of shale gas in the United States, the Committee states that “exploration and appraisal are urgently needed to establish the economic potential of the UK’s shale gas and oil resource.” Without timely development, the UK “runs a serious risk of losing the energy intensive and petrochemical industries which depend on competitively-priced energy and raw materials…”

While recognizing that the public’s concerns about environmental and human health issues “must be taken seriously and every possible effort made to reduce or eliminate risk and provide reassurance,” the Committee considers these risks to be “low if shale development is properly regulated…,” with wells properly constructed and sealed.

Urging that the UK “seize the opportunity” to develop its shale resources, the Committee expresses concern that “regulatory uncertainty is blocking development” because the UK Environment Agency has not received or approved any permit applications since the fracking moratorium was lifted in 2012.

Seeing the development of shale oil and gas as “an urgent national priority,” the Committee recommends that the Government “go all out for shale” by streamlining its regulatory structure and by reassuring the public that environmental and health risks are low with proper regulation. Also the Committee suggests that energy companies should improve their presentation and communication skills to help secure public support.

This post was written by Barclay Nicholson ( or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.

Do state oil and gas laws trump local bans on hydraulic fracturing? Briefing continues in NY case

On August 29, 2013, New York state’s highest court agreed to hear an appeal of an order upholding a local ordinance banning all activities related to the exploration for, and production or storage of, natural gas and petroleum in the Town of Dryden, New York and affirming a lower court’s decision that certain amendments to the Town’s zoning ordinance were not preempted by the state’s Oil, Gas and Solution Mining Law (“OGSML”). Oral arguments are scheduled for June 3, 2014 (Case No. APL-2013-00245, New York State Court of Appeals).

A number of interested parties on both sides of the question have filed amicus briefs with the Court of Appeals.
  • On behalf of the 1.6 million residents of Manhattan, the Manhattan Borough President asserted that “municipalities are far better situated than the State to discern what land use is appropriate for their territory.”  
  • According to the Independent Oil and Gas Association of New York, Inc., the OGSML “unequivocally states that all local ordinance relating to oil and natural gas development are preempted.”
  • A group of 26 businesses argued that “a municipality’s home rule authority to protect sustainable enterprises through the exercise of State-delegated zoning powers over potentially detrimental land uses” must be preserved.
  • The American Petroleum Institute and the Chamber of Commerce of the United States of America assert that the town’s ordinance is invalid because it conflicts with the structure and purpose of the OGSML which vests exclusive authority over drilling operations to the state’s Department of Environmental Conservation and because it puts “at risk the efficacy of drilling across the State…”
  • Several groups of landowners, farmers, labor unions, municipalities, and businesses joined to file an amicus brief urging that “decisions regarding the production of New York’s natural resources must be made by the experts at the State level and not by New York’s municipalities, each possessing varying degrees of expertise, and each making decisions in an individual vacuum without consideration for the important State interests and policies at issue.” 
  • Siding with the Town of Dryden, a group of land-use legal experts opined that a “presumption against preemption of local zoning laws is especially strong where the allegedly preemptive state law makes no provision for protecting the quiet enjoyment of land. It is simply implausible to infer that the state legislature intentionally conferred on the gas and oil extraction industry a statutory right to site a towering drill and accompanying truck traffic, waste pits, compressor stations, and the like next door to a quaint bed-and-breakfast in a rural hamlet or single-family home in a quiet residential suburb.”
For additional information, see prior blog articles “Two New York Courts Uphold Local Bans on Hydraulic Fracturing,” “New York appeals court upholds local bans on hydraulic fracturing,” and “Do state energy laws preempt municipal zoning ordinances banning oil and gas development?

This post was written by Barclay Nicholson ( or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.

EPA requests public comment on disclosure of chemicals and mixtures used in hydraulic fracturing

On May 9, 2014, the U.S. Environmental Protection Agency (EPA) released an advance notice of proposed rulemaking (ANPR) seeking public and stakeholder “comment on the information that should be reported or disclosed for hydraulic fracturing chemical substances and mixtures and the mechanism for obtaining this information. This mechanism could be regulatory (under the Toxic Substances Control Act (TSCA), section 8(a) and/or section 8(d)), voluntary, or a combination of both and could include best management practices, third-party certification and collection, and incentives for disclosure of this information.”

In addition, the EPA requests comments on ways of minimizing reporting burdens and costs and of avoiding duplication of state and other federal agency information collections while “maximizing the data available for EPA risk characterization, external transparency, and public understanding.”

The data required to be disclosed could include identity (trade name, chemical identity, and molecular structure), quantity, and category of use, as well as studies of environmental and health effects, for each of the chemicals, mixtures, and substances used in hydraulic fracturing activities.

The ANPR identifies questions for the public to consider relating to the overall approach on the reporting and disclosure of hydraulic fracturing chemicals, who should report or disclose the information, the scope of reporting, the use of third-parties, the threshold for and frequency of reporting, data collection efficiency, health and safety studies of the chemicals used, and safer chemicals and transparency. The EPA will collect comments for 90 days, which period will not begin until the ANPR is published in the Federal Register.

This ANPR is in response to a citizen petition from Earthjustice and 114 other groups dated August 4, 2011, requesting that the EPA issue rules under the TSCA requiring toxicity testing of chemicals used in oil and gas exploration. On November 23, 2011, the EPA limited the scope of inquiry to chemicals and mixtures used in hydraulic fracturing and indicated that it would publish an ANPR identifying key issues for further discussion and analysis.

This post was written by Barclay Nicholson ( or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.

Pennsylvania legislators propose separate regulations for conventional and unconventional drilling operations

Three Pennsylvania state representatives plan to introduce legislation that would separate regulations for conventional and unconventional drilling operations, asserting that “conventional drilling is, without question, far different than drilling in the Marcellus Shale, and it simply makes no sense to apply the same standards to these operations.”

They argue that conventional drilling has been overlooked in the rush to develop horizontal wells to extract natural gas.

According to the legislators, the proposed substantial re-write of the state’s Oil and Gas Act, Act 13, P.L. ___, 58 Pa. C.S. §§2301-3504, puts small-scale drilling companies that provide “good, family-sustaining jobs” at risk financially.

For conventional wells, the Environmental Quality Board (EQB), part of the state’s Department of Environmental Protection (DEP), estimated annual costs between $5 and $12 million, while the Pennsylvania Grade Crude Oil Coalition puts the estimate at between $181 million and $387 million.

Even the state’s Independent Regulatory Review Commission (IRRC) has expressed concerns over the gap in these estimates, stating that “there appears to be a basic misunderstanding of what this proposal will require and when those requirements will become effective.”

To analyze and clarify the financial and regulatory differences, the IRRC suggests that the EQB meet with trade organizations, oil and gas operators, and any interested stakeholders.

For information on Act 13, see “Pennsylvania Supreme Court strikes down major portions of Act 13 as unconstitutional.” For briefs filed in the remanded lawsuit, Robinson Township, et al v. Commonwealth of Pennsylvania, et al, 284 MD 2012, In the Pennsylvania Commonwealth Court, click here and here.

This post was written by Barclay Nicholson ( or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.

EPA reviews states’ solid waste management regulations for oil and gas operations

In an April 1, 2014 memorandum, the U.S. Environmental Protection Agency (EPA) summarized state regulatory programs concerning the management of solid waste from oil and natural gas exploration, development and production (E&P) operations.

In reviewing each state’s regulations, the EPA focused on surface storage and disposal facilities managing produced waters, drilling muds, drilling cuttings, hydraulic fracturing return fluids, and various other waste liquids and materials intrinsically related to oil and gas E&P.

The EPA found that the state regulations were primarily concerned with the “technical requirements associated with the design, construction, operation, maintenance, closure, and reclamation of surface pits, ponds, lagoons or tanks, as well as financial assurance requirements associated with such facilities.”

Among the common parameters are state requirements for liners in pits and impoundments, secondary containment requirements for tanks, set-back requirements, and various inspection requirements. However, the EPA did find gaps in regulations relating to groundwater monitoring, leachate collection, air monitoring, and waste characterization.

Overall, with the review, the EPA had developed an understanding of the wide-range of state regulatory programs currently in place in the twenty-six (26) oil and gas producing states covered in the summary.

This post was written by Barclay Nicholson ( or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.

Senators question EPA’s proposed research into states’ efforts to regulate hydraulic fracturing

In a letter dated May 8, 2014, five U.S. senators urged the Office of Inspector (OIG) of the U.S. Environmental Protection Agency (EPA) to discontinue its “preliminary research on the EPA’s and states’ ability to manage potential threats to water resources from hydraulic fracturing,” arguing that such a review is “well outside the mission and expertise of the OIG…[and] duplicative of numerous other federal efforts.”

The OIG announced its proposed research in a memorandum dated February 5, 2014, stating that it would evaluate the regulatory authority that is available to the EPA and the states, identify potential threats to water resources from fracturing operations, and evaluate how the EPA and the states have responded to these threats. According to the OIG, this research would improve preventative and response measures and improve coordination among the EPA, states and industry to ensure that water resources are protected.

The senators from Louisiana, Oklahoma, and Texas complain that the EPA has previously “conducted a number of indisputably flawed and unscientific investigations attempting to link hydraulic fracturing to water contamination and has continued to come up empty handed.” Moreover, the senators state that, with this additional research, the EPA is trying to “manufactur[e] a need for new regulations on a production technique that has been safely and effectively regulated at the state level for the better half of a century.” According to the senators, only state regulators with knowledge and expertise of their state’s geology, ecology, and hydrology and who have a vested interest in protecting their state’s water supplies from contamination are qualified to tailor regulatory programs to meet their state’s needs.

Pointing to extensive studies of hydraulic fracturing from the Department of Energy, the Department of the Interior, the Government Accountability Office, and the EPA, the senators urge that this research be stopped and that the OIG focus on “a more relevant and needed inquiry into fraud, abuse, and waste at the EPA.”

Denton, Texas City Council approves moratorium on oil and gas drilling permits

On May 6, 2014, in a 7-0 unanimous vote, the City Council of Denton, Texas approved an extension of its moratorium on oil and gas drilling permits until September 9, 2014, in order to allow the city to re-work and improve its gas well ordinances by adding provisions for notice to landowners of hydraulic fracturing activities, clustering of wells, and requiring companies to pay a bond and provide certification of insurance .

The moratorium applies to the receipt, processing and approval of gas well permits and specific use permits in Denton. Operators would be allowed to continue extracting gas from the approximate 275 wells currently in the area, and there is a process for oil and gas companies to seek a variance from the moratorium.

The day after the City Council meeting, the anti-fracking group Denton Drilling Awareness delivered a petition signed by more than 1,800 citizens to ban hydraulic fracturing. Upon certification, the City Council has 60 days to have a hearing and vote on the proposed ban. If voted down, the ban would appear on the November 2014 ballot. Also the group wants more protections incorporated into the city’s oil and gas ordinances, including prohibitions on open pits, compressor stations, and flaring as well as required notification to area residents of the presence of near-by wells and the possibility of hydraulic fracturing activities.

View the discussion and vote of the Denton City Council (go to 01:51:07 on the video)

U.S. Department of Transportation issues emergency order concerning trains carrying Bakken crude oil

On May 7, 2014, the U.S. Department of Transportation (USDOT) issued an Emergency Order requiring all railroad carriers “transporting 1,000,000 gallons or more of Bakken crude oil” (approximately 35 tank cars) to notify state emergency officials of the train’s expected movements and operations in each state.

Within 30 days of the Order, the carriers must provide written notice of the expected volume and frequency of train traffic to each state’s Emergency Response Commission (ERC), including
  • A reasonable estimate of the number of trains carrying 1,000,000 gallons or more of Bakken crude oil that are expected to travel, per week, through each county within the state;
  • Identification, description and classification of the petroleum crude oil expected to be transported, 49 CFR part 172, subpart C;
  • All applicable emergency response information required by 49 CFR part 172, subpart G; 
  • Identification of the routes over which the trains will travel; and
  • Identification of at least one railroad person to be a point of contact for emergency officials.
Updated notifications must be made when there is a material change in the volume of the trains. The USDOT considers any increase or decrease of 25% or more in the number of trains per week to be a material change.

With the required information, each state’s ERC and local responders can prepare for the possibility of an accident. To enhance emergency response efforts, the USDOT recommends that “railroads continue to commit resources to develop specialized crude oil by rail training and tuition assistance program for local first responders” through the Transportation Community Awareness and Emergency Response program and other initiatives.

Also, on May 7, 2014, the Federal Railroad Administration (FRA) and Pipeline and Hazardous Materials Safety Administration (PHMSA) issued a Safety Alert recommending that carriers “use tank car designs with the highest level of integrity,” including “tank shell jacket systems, head shields, and top fittings protection.”

According to Transportation Secretary Anthony Foxx, “[t]he safety of our nation’s railroad system, and the people who live along rail corridors is of paramount concern. All options are on the table when it comes to improving the safe transportation of crude oil, and today’s actions, the latest in a series that make up an expansive strategy, will ensure that communities are more informed and that companies are using the strongest possible tank cars.”

Read additional information on transporting Bakken crude oil by rail.

Canadian Council of Academies releases major research paper of the environmental impacts of shale gas development in Canada

A multi-disciplinary panel of experts assembled by the Canadian Council of Academies has released a major study on the environmental impacts of shale gas development in Canada. The Council is an independent research organization of the Royal Society of Canada, the Canadian Academy of Engineering and the Canadian Academy of Health Sciences. The Council is funded by the Canadian federal government.

The Study was commissioned in 2012 by the federal Environment Minister to provide an evidence-based and authoritative assessment of the following question:

What is the state of knowledge of potential environmental impacts from the exploration, extraction and development of Canada's shale gas resources, and what is the state of knowledge of associated mitigation options?

Further to this question, the Council was also asked:
  • Based on existing research, what new or more significant environmental impacts may result from shale gas extraction relative to conventional gas extraction?
  • What are the science and technology gaps in our understanding of these impacts and possible mitigation measures/strategies, and what research is needed to fill these gaps?
  • What monitoring approaches could inform the effective understanding and mitigation of impacts, what is the current state of the art and state of practice for such monitoring, and what science and technology gaps may act as barriers to effective monitoring?
  • What technical practices exist to mitigate these impacts, and what are international best practices? What science underpins current policy or regulatory practices internationally? 
The Study does not make recommendations, but rather presents observations and conclusions on what is known and not known about the environmental impacts of shale gas development, the options to mitigate them and opportunities for research to fill gaps in monitoring and understanding.

The Study focused on:
  • water (groundwater and surface);
  • greenhouse gas emissions;
  • land impacts and seismic events;
  • human health; and
  • monitoring and research.
The Study calls for more research on the environmental impact of shale gas development in Canada. The Study concludes:
  • In nearly all instances, shale gas extraction has proceeded without important environmental baseline data being collected (e.g. nearby groundwater quality). This makes it difficult to identify and characterize environmental impacts that may be associated with (or incorrectly blamed on) this development.
  • There is a paucity of peer-reviewed articles in the scientific literature. The reasons include the fact that large-scale shale development is a young industry (some 20 years old in the United States and only half that in Canada), that the industry has kept some information proprietary (in part because technologies are evolving rapidly and are still being tested), and that U.S. federal legislation only indirectly regulates the chemical additives used in hydraulic fracturing and therefore industry has not had to monitor their impact.
  • A major environmental concern regarding shale gas development - regional groundwater contamination - hinges on the flow of fluids in low permeability but commonly fractured geological strata. However, because past scientific interest has largely focused on high permeability rocks (aquifers and petroleum reservoirs), fluid flow in low permeability rocks is poorly understood. Thus, the basic scientific knowledge needed to evaluate potential risks to groundwater on the regional scale is largely lacking.
  • In areas where peer-reviewed studies are available, they do not necessarily agree. For example, there is a substantial range of expert opinion on the extent of fugitive methane emissions from shale gas development.
  • Some of the possible environmental effects of shale gas development, such as the creation of sub-surface pathways between the shale horizons being fractured and fresh groundwater, gas seepage from abandoned wells, and cumulative effects on the land and communities, may take decades to become apparent. Similarly, monitoring information, and information on the effectiveness of mitigation measure, take time to acquire and assess. 
  • Much if not most of what can be said about the potential environmental impacts of shale gas development depends on assumptions made about the location, pace, and scale of development, all of which will be influenced by future natural gas prices, government policy, and technological improvements. None of these can be predicted with certainty.
Review a copy of the Study

This post was written by Alan Harvie ( or +1 403.267.9411) from Norton Rose Fulbright's Canadian Energy Practice Group.

Three oil companies voluntarily provide Bakken crude oil testing information to U.S. Department of Transportation

On May 2, 2014, the U.S. Department of Transportation (USDOT) announced that three oil and gas companies voluntarily provided testing data on the crude oil that they ship from North Dakota’s Bakken Shale. This data was supplied in response to the USDOT’s call for action in January 2014, asking that oil companies, shippers, railroads, and industry stakeholders focus on ways to improve accident prevention and mitigation.

The USDOT’s announcement follows months of evaluation and discussions relating to recent train derailments of tanker cars carrying Bakken crude oil, including incidents in Minnesota, Maryland, Pennsylvania, North Dakota, and at three sites in Canada, including Lac-Mégantic (where 47 people were killed). Since the Lac-Mégantic accident, both Canadian and U.S. agencies have urged rail safety and have issued several alerts and rules regarding the shipping of crude oil.
  • On September 6, 2013, the Pipeline and Hazardous Materials Safety Administration (PHMSA) published a proposed rule concerning “Hazardous Materials: Rail Petitions and Recommendations to Improve the Safety of Railroad Tank Car Transportation (RRR).” This proposed rule imposes requirements for DOT Specification 111 tank cars used to transport Packing Group (PG) I and II hazardous materials.
  • In November 2013, PHMSA and the Federal Railroad Administration (FRA) issued a joint safety alert to reinforce “the importance of proper characterization, classification, and selection” of the hazardous materials being transported. PHMSA issued a safety alert on January 2, 2014, “to notify the general public, emergency responders, and shippers and carriers that recent derailments and resulting fires indicate that the type of crude oil being transported from the Bakken region may be more flammable than traditional heavy crude oil.”
  • On February 21, 2014, the USDOT and the Association of American Railroads (AAR) announced a rail safety initiative to institute new voluntary operating practices for moving crude oil by rails. 
  • On February 25, 2014, the U.S. Department of Transportation (DOT) issued an emergency order requiring rail shippers of crude oil to test the crude’s makeup before shipping it and to classify the crude as Packing Group I (high danger) or Packing Group II (medium danger) hazardous material until further notice.
  • In April 2014, Canada’s Ministry of Transport issued Protective Direction No. 34 requiring the immediate phase out of the least crash-resistant DOT-111 tank cars from dangerous goods service. Along with Protective Direction, the Ministry issued an Emergency Directive and a Ministerial Order outlining further requirements, including maximum speeds for trains carrying one or more cars of crude oil and ordering a risk assessment for each train route.
With the dramatic increase of shipments of crude oil by rail (from 9,500 carloads in 2008 to more than 400,000 carloads in 2013, according to the AAR), there will undoubtedly be more safety and security regulations, orders and directives to protect the public and the environment.

For additional information on the transportation of crude oil by rail, click here and here.

This post was written by Barclay Nicholson ( or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.

Canada’s Ministry of Transport orders phase out or retrofitting of DOT-111 tank cars

On April 23, 2014, in response to recommendations made after the Lac-Mégantic train derailment in July 2013, Canada’s Ministry of Transport issued Protective Direction No. 34 requiring the immediate phase out of the least crash-resistant DOT-111 tank cars from dangerous goods service. There are approximately 5,000 DOT-111 tank cars without continuous bottom reinforcement that must be immediately removed from transporting dangerous goods such as crude oil and ethanol.

As for any tank cars on the move on the date of the Direction, these cars must reach their final destination within 30 days and then be immediately removed from service. All tank car owners must ensure that each of their DOT-111 tank cars is “marked with the words ‘Do not load with dangerous goods in Canada/Ne pas charger de marchandises dangereuses au Canada’ or similar words.”

In January 2014, Transport Canada proposed a new standard for “DOT-111 tank cars, including thicker steel and additional top fitting and head shield protection.” Working with U.S. regulatory agencies and other stakeholders, the Ministry plans to formalize updated DOT-111 standards in the summer of 2014. With Protective Direction No. 34, any tank cars built before the proposed standard and used to transport dangerous goods must be now phased out or retrofitted within three years.

In addition to the Protective Direction, the Ministry issued an Emergency Directive and a Ministerial Order outlining further requirements.
  • Trains carrying one or more cars of crude oil or ethanol (“Key Train”) must not exceed 50 mph, which speed may be lowered for some locations after specific risk assessments for particular urban populations and sensitive assets such as water sources.
  • Within six months, all companies must complete a risk assessment to determine the level of risk associated with each route over which Key Trains are operated. The assessment must identify safety and security risks associated with each route, including the volume of goods moved, the class of track, the maintenance schedule for the track, the curvature of the track, environmentally sensitive areas along the route, population density, emergency response capability, and any areas of high consequence along the track. Alternative routes must be identified and compared.
It must be noted that, in Lynchburg, Virginia, on April 30, 2014, at least 13 tank cars of a 105-car tank car train derailed and caught fire, with flames shooting 100 feet into the air. Three of the cars fell into the James River. According to officials, the train was traveling at just 24 miles per hour at the time of the accident. This incident comes just one week after the out-going chairwoman of the National Transportation Safety Board warned that the rail industry was falling behind on its oil shipping safety measures.

For additional information on transporting crude oil by rail, click here, here, and here.

This post was written by Barclay Nicholson ( or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.

Minnesotans seek two-year moratorium on frac sand mining

More than 6,000 residents of southeastern Minnesota signed a petition to enact a two-year moratorium on frac sand mining, declaring that “southeast Minnesota should be off-limits to the frac sand industry” in order to protect air and water quality. The Land Stewardship Project, the group sponsoring the petition, asserted that the governor had the authority to order the Environmental Quality Board to issue a moratorium under the state’s Critical Areas Act without legislation because the frac sand operations were threatening ecologically sensitive areas.

The petition was presented to the state’s governor on April 22, 2014, during Earth Day celebrations.

Governor Mark Dayton responded that, while he would “like to ban it [frac sand mining] entirely” because he believes that “the environmental risks are far greater than the economic benefits in terms of jobs and economic benefits for the area, but that’s not the law.” State legislators in 2013 decided against a state-wide ban. Stating that legal counsel advised him that he did not have the authority to unilaterally impose a moratorium, the governor reminded the citizens that “local jurisdictions, such as counties, cities, and townships, have authority under existing Minnesota Statutes to declare moratoriums on frac sand mining and processing within their jurisdictions.”

A poll taken in February 2014 showed that 64% of Minnesotans favor the two-year moratorium while 31% oppose the moratorium and 52% oppose increased frac sand mining in the state. Undoubtedly frac sand mining will continue to be a contentious issue among the citizens of Minnesota.

Oil and gas companies face shareholder resolutions relating to hydraulic fracturing

Shareholders, including the Sisters of St. Francis of Philadelphia, are calling for Chevron, ExxonMobil, EOG Resources, Occidental Petroleum, and Pioneer Resources to disclose their hydraulic fracturing risk assessments.

In their Proposal No. 6 on Chevron’s 2014 Proxy Statement which was filed with the U.S. Securities and Exchange Commission, the Sisters of St. Francis state that “Chevron does not provide investors with relevant metrics necessary to assess the company’s exposure to risks associated with the impacts of hydraulic fracturing operations and whether the company is effectively mitigating those risks.”

The Sisters propose that the company prepare an annual report containing information about each shale play, addressing the quantity and source of fresh water used in hydraulic fracturing operations, percentage of recycled water used, post-drilling groundwater quality assessments, goals to eliminate the use of open pits, a system to manage naturally occurring radioactive materials, and a method to assess and manage community and human rights impacts, including quantifying numbers and categories of community complaints of alleged impacts.

Similar resolutions have been proposed in the past by the Sisters (this is their fourth demand in as many years) and other shareholders, but all have failed. In 2011, the ExxonMobil resolution garnered 28% support from the shareholders while the Chevron resolution garnered 41% of the vote. In 2012, 29% of ExxonMobil’s shareholders supported the resolution. In 2012 and 2013, Chevron shareholders supported the resolutions 27% and 30% respectively.