Chesapeake Appalachia, LLC, to pay large CWA 404 civil penalty

The U.S. Environmental Protection Agency and the Department of Justice announced on December 19, 2013, that Chesapeake Appalachia, LLC, will pay a $3.2 million civil penalty and spend an EPA-estimated $6.5 million to restore 27 sites damaged by discharges of fill material into streams and wetlands and to implement a Clean Water Act (CWA) 404 compliance plan at the company’s natural gas extraction sites in West Virginia.

Of the 27 sites, four are freshwater impoundments, one is a compressor station, six involve operations related to vertical wells, and the remaining 16 sites involve operations related to horizontal drilling.

In addition to a civil penalty of $3.2 million, the Consent Order requires restoration where feasible, mitigation, employee training for five years in West Virginia, Virginia, Maryland, and Pennsylvania, and integration of a CWA Section 404 compliance protocol into its operating procedures in West Virginia.

According to EPA’s press release, the civil penalty is one of the largest ever imposed for violations of CWA 404. The penalty will be divided between the United States and West Virginia. More information, including the Consent Order, is available on EPA’s web site.

The consent decree, lodged on December 19 in the Northern District of West Virginia, is subject to a 30-day public comment period and court approval.

This post was written by Janet McQuaid ( or +1 724 416 0427) from Norton Rose Fulbright's Energy Practice Group.

Pennsylvania Supreme Court strikes down major portions of Act 13 as unconstitutional

Late yesterday, the Pennsylvania Supreme Court, in a highly fractured set of opinions, struck down major portions of Act 13, the revised Oil and Gas Act. Four opinions (totaling more than 200 pages) were issued: a majority opinion, a concurring opinion, a dissenting opinion, and a second dissenting opinion. The newest member of the Supreme Court, Justice Stevens, did not author or join any opinion.

The Court's decision:
  1. Found all applicants to have standing to sue, including those the Commonwealth Court determined lacked standing;
  2. Found the matters not to be non-justifiable and not to be political questions;
  3. Found Sections 3215(b)(4) and (d) [allowing the DEP to grant setback waivers in certain situations], 3303 [the preemption provision of the Act], and 3304 [the uniformity provision of the Act] to be unconstitutional and enjoined (while a majority of the Court reached the conclusion that these Sections of the Act were unconstitutional, they could not agree as to why these provisions were unconstitutional, with three Justices holding that the Sections violated the Environmental Rights Amendment to the Pennsylvania Constitution and one Justice concluding that the Sections violated due process rights under that constitution);
  4. Found that the rest of Section 3215(b) was not severable from Section 3215(b)(4), which it found to be unconstitutional, and, therefore, was enjoined;
  5. Found Sections 3215(c) and (e) also to be not severable and, therefore, also enjoined;
  6. Found Sections 3305 through 3309 to be not severable to the extent they enforce or implement the unconstitutional portions of the Act and, therefore, also enjoined;
  7. Found that the Commonwealth Court improperly sustained the Commonwealth's preliminary objections to Count IV (claiming Act 13 was a special law) and Count V (claiming the eminent domain provision of Act 13 was improper) and remanded those issues for consideration by the Commonwealth Court;
  8. Affirmed the Commonwealth Court's decision finding that Section 3305 (conferring on the PUC the ability to review zoning laws for compliance with the Act) did not violate the separation of powers requirements of the Pennsylvania Constitution; and 
  9. Remanded to the Commonwealth Court for a determination as to whether the valid provisions of Act 13 are severable from those the Court found to be unconstitutional.
Norton Rose Fulbright lawyers are reviewing this lengthy and important decision and will issue a Client Briefing in the near future. In the meantime, if you have questions about this decision or its impact on unconventional gas development in Pennsylvania, do not hesitate to contact the authors.

This article was prepared by Jeremy Mercer ( or +1 724 416 0440) and Amy Barrette ( or +1 724 416 0430) from Norton Rose Fulbright's Energy Practice.

Do state energy laws preempt municipal zoning ordinances banning oil and gas development?: Briefs filed in NY CASE

On May 2, 2013, a New York state appeals court issued 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. The court affirmed the judgment of the lower court, entered on February 22, 2012, which held that certain amendments to the Town of Dryden zoning ordinance are not preempted by New York State’s Oil, Gas and Solution Mining Law (“OGSML”). New York State’s highest court (Case No. APL-2013-00245, New York State Court of Appeals) agreed to hear an appeal of this decision. See prior blogs, New York appeals court upholds local bans on hydraulic fracturing and NewYork Court of Appeals to consider local bans on hydraulic fracturing.

The movant filed its brief (see attached) on October 28, 2013, asserting that  “the Appellate Decision allows every municipality in the State of New York to ban any and all oil and gas development. The inevitable result is zero resource recovery, the ultimate in waste, and the obliteration of mineral owners’ correlative rights. This result starkly conflicts with the language and policies of the OGSML and the Energy Law and, therefore, cannot stand.”

The Town of Dryden responded in a brief dated December 13, 2013, arguing that the “OGSML does not expressly preempt a locality’s right to enact a zoning ordinance that regulates land use generally and designates oil and gas mining as a prohibited use within municipal borders.”  The Town urges that the two separate, distinct regulatory schemes (the Town’s zoning ordinances and the policies of the OGSML) can “harmoniously coexist.” 

On December 13, 2013, the court received an amici curiae brief (see attached) that was filed on behalf of 52 towns and villages in New York, the Association of Towns of the State of New York, the New York Conference of Mayors, and the New York Planning Federation. These interested parties asserted that a local municipality has “the constitutionally guaranteed right…to create and preserve its own community character through generally applicable land use planning and zoning laws.” New York’s energy law “preempts only local regulation of the operations of the oil and gas industry, not local land use laws that govern whether and where such operations may take place within a municipality’s borders.”

The reply brief is due January 6, 2014. Both sides have requested oral arguments.

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

Dallas City Council approves strict gas drilling regulations

On December 11, 2013, the Dallas City Council adopted revisions to the gas drilling and production regulations of the Dallas Development Code.  In a 9 to 6 vote, the Council approved regulations that require pad sites to be at least 1,500 feet from homes, schools, churches, daycare centers, hospitals, nursing homes, and other protected property.  Individual drilling permits may qualify for an exception to the 1,500 feet, but any exception must be approved by two-thirds of the Council.  Also, drilling on park land would be allowed if certain conditions are met and if the state Parks and Wildlife Department gives the required approval. 

The regulations contain provisions concerning neighborhood meeting requirements, baseline sampling and testing of air, soil , noise and water, limitations on hours of operation, spill prevention and tracking, site maintenance, emissions, and materials management.  All Material Safety Data Sheets (MSDS) for materials stored on site must be kept on site and submitted to the gas inspector.  An inventory statement identifying the quantities, volumes and concentrations of all hazardous materials and chemicals stored or used at the operation site must be provided to the city.

For hydraulic fracturing, the operator must post a sign at the main gate and send written notification to each property owner and each registered neighborhood association  within 1,500 feet of the well site at least 10 days before fracturing begins.  The operator must add non-radioactive tracing or tagging additives into all fracturing fluids used at the site.  For each site, the fracturing fluid non-radioactive tracing or tagging additives must be unique for each operation site.

These regulations come after years of public meetings, including 22 meetings of the Council’s Gas Drilling Task Force held between July 2011 and February 2012, eight meetings of the City Plan Commission, three public hearings, and over 100 hours of public testimony.  Council members supporting the new regulations believe that these rules  protect the health and safety of residents without foreclosing the opportunity to drill where appropriate.  Council opponents disagree, stating that the rules essentially bar any development of the Barnett Shale within Dallas city limits and may be reduced to one line – “there will be no drilling in Dallas.”  Opponents also point to the loss of tax revenue and direct income the city could earn by leasing its own land for development.

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

Spain amends environmental rules to encourage energy development

On December 11, 2013, the Spanish government amended its environmental rules to address the development of shale resources and to limit the environmental review process to six months. Spain’s review process often took three, four or five years to complete a final environmental impact statement. With the shortening of the review process period to six months (four months for review, with the possibility for a two-month extension), Spain hopes to encourage energy companies to develop its resources. While not endorsing hydraulic fracturing, the central government sends a signal that it is willing to consider the process in an objective, timely, and efficient manner. A request for hydraulic fracturing must meet standard review demands, which is the same level of scrutiny given to nuclear power plants.

Hydraulic fracturing is not without criticism in Spain. The shale-rich region of Cantabria banned hydraulic fracturing in April 2013, stating concerns about earthquakes and water contamination. But, with the country’s severe economic downturn marked by high unemployment and the fact that Spain imports more than three-quarters of its energy needs, the central government wants to encourage shale gas development to boost its economy and to decrease its reliance on foreign sources of fuel.

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

Canada's National Energy Board asks companies to voluntarily publically disclose frac fluids

Canada's National Energy Board (NEB) regulates oil and gas exploration of certain Canadian frontier lands and offshore areas, including the Northwest Territories, the Arctic, the west coast offshore and the Gulf of St. Lawrence. The NEB has announced that it will begin to request companies drilling in such areas to voluntarily publically disclose the chemicals used in hydraulically fracturing on, the Canadian version of

Presently, under the Canadian Petroleum Resources Act, certain well-related information, including the composition of hydraulic fracturing fluids, is protected from public disclosure for up to two years. NEB-regulated companies will be asked to sign a waiver allowing public disclosure of their hydraulic fracturing chemicals on prior to the end of the two year confidentiality period. Hence, the public disclosure of the fracturing fluid information will be at the discretion of each company, at least until the end of the two year confidentiality period. If a well operator does not voluntarily agree to the disclosure the NEB will publically release the information via at the end of the two year period.

View a copy of the NEB press release

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

Oil and gas association challenges fracking bans in two Colorado cities

In November, the citizens of Fort Collins, Colorado and Lafayette, Colorado voted to ban hydraulic fracturing from their cities. See prior blog, “Voters in three Colorado cities ban hydraulic fracturing.” In Fort Collins, a five-year ban on hydraulic fracturing was approved with 55% of the vote. Sixty percent (60%) of the voters in Lafayette approved an indefinite ban on all oil and gas development, including the deposit, storage, or transportation of fracking wastewater through “the land, air or waters” of the city. In both cities, the City Councils had opposed the bans.

On December 3, 2013, the Colorado Oil & Gas Association (COGA) filed a lawsuit against each city, challenging the validity of the bans (Fort Collins lawsuit and Lafayette lawsuit). COGA argues that a conflict exists between the bans and state law since the cities have no constitutional or statutory authority to implement regulations on oil and gas development techniques, such as hydraulic fracturing. COGA points to Colorado Supreme Court precedent and state law to support its stance that hydraulic fracturing cannot be blocked by municipalities.

According to COGA, the state’s General Assembly has declared it to be in the public’s interest for the state to “foster the responsible and balanced development, production, and utilization of the natural resources of oil and gas in Colorado in a manner consistent with protection of public health, safety, and welfare, including protection of the environment and wildlife resources.” The Oil and Gas Conservation Act created the Colorado Oil and Gas Conservation Commission (COGCC) to administer all “rules, regulations and orders with respect to operations for the production of oil and gas,” including “permitting, drilling production, plugging, spacing and chemical treatment of wells.”

Both COGA and COGCC are currently embroiled in lawsuits against the city of Longmont, which banned fracking in 2012. For more information on the Longmont lawsuits, see latest analysis of fracking-related litigation attached to this blog.

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

Pennsylvania courts determine that gas lessee has no implied obligation to develop deeper shale formation

On November 26, 2013, the Pennsylvania Supreme Court denied an appeal of a Superior Court decision which held that a gas lessee has no obligation to drill into the Marcellus Shale formation. In Caldwell v. Kriebel Resources Co., LLC, et al., filed in 2012 in the Clearfield County Court of Common Pleas, Case No. 2012-14-CD, 2012 WL 8745184 (C.P. Clearfield County, Aug. 3, 2012), the plaintiff landowners sought a declaratory judgment that would allow them to terminate their lease agreement with the defendant gas company. Id. The company had drilled a series of shallow wells on the plaintiffs’ property, which produced gas in paying quantities, but did not drill deeper wells into the Marcellus Shale formation. Id. The Court of Common Pleas dismissed the suit, holding that the company was developing the property as required by the lease. Id. The court also rejected plaintiffs’ argument that minimum royalty payments should be based on the natural gas potentially available in all strata underlying the property, finding instead that a well should be deemed to have produced in paying quantities if it resulted in any profit whatsoever. Id.

The Pennsylvania Superior Court affirmed the trial court holding by stating:

Under Pennsylvania law, we are not authorized to impose an implied duty on the lessee to develop the various strata in light of the language contained in their contract. This is so particularly in light of the fact that defendants are producing gas pursuant to the agreement, a fact that appellants acknowledge.

Caldwell v. Kriebel Res. Co., LLC et al., 72 A.3d 611 (Pa. Super. Ct. 2013). With the state Supreme Court denying the appeal, the Superior Court’s decision based on the strict language of the lease remains controlling Pennsylvania law.

Environmental group and congresswoman want to halt California offshore hydraulic fracturing operations

In October, the Associated Press reported that hydraulic fracturing activities off the coast of California were more extensive than previously thought. Interviews and public records revealed that oil companies had used fracking more than 200 times at six different sites over the last 20 years near Long Beach, Seal Beach and Huntington Beach.

The Center for Biological Diversity (CBD), an environmental activist group, took up the issue of offshore fracking and urged a moratorium on these activities in an October 3, 2013 letter addressed to the Bureau of Ocean Energy Management and to the Bureau of Safety and Environmental Enforcement, Pacific Region. See prior blog dated October 14, 2013, “Environmental Group Urges Moratorium on California Offshore Hydraulic Fracturing Operations.”

According to the CBD, without a supplemental National Environmental Policy Act (NEPA)review, these operations violate NEPA, the Outer Continental Shelf Lands Act and other environmental statutes. Continuing its efforts to stop offshore fracking operations, the CBD sent a letter dated November 14, 2013 to the California Coastal Commission requesting that it “take immediate action to halt hydraulic fracturing and other unconventional techniques for extracting oil and gas off the California coast.”

Representative Lois Capps (D-Calif.) has now requested a moratorium on California offshore fracking activities. In a letter dated November 19, 2013, she asked the Department of the Interior and the Environmental Protection Agency to halt these operations in federal waters “until a comprehensive study of their impacts on the marine environment and public health is conducted and considered.” According to Rep. Capps, there have been at least 15 fracking operations performed at wells in federal waters off California since the early 1990s, with some of these fracks occurring- near the National Marine Sanctuary and other sensitive marine areas.

These offshore activities need to be in compliance with regulations under the Endangered Species Act and the Marine Mammal Protection Act. Rep. Capps asserts that these operations were “approved with overly broad and outdated plans” that do not adequately assess the current offshore environmental risks. "There is a great deal we do not yet know about the environmental and public health impacts of fracking onshore, let alone offshore.”

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

President Obama promises to veto hydraulic fracturing bill and other energy-related legislation

On November 20, 2013, the U.S. House of Representatives approved two energy-related bills – one bill concerning hydraulic fracturing regulations on federal lands (H.R. 2728) and the second relating to applications for permits to drill (H.R. 1965). Two other energy bills are pending, one dealing with the permitting of natural gas pipelines (H.R. 1900) and the other with the standards to be used by the EPA in disseminating its report on the impacts of hydraulic fracturing on drinking water resources (H.R. 2850).

President Obama has threatened to veto at least three of these measures in the unlikely event they pass the Democratic-controlled Senate and reach his desk. The Administration believes that these bills would sabotage its environmental protection efforts.

H.R. 2728, was introduced by Bill Flores (R-TX) and approved by a vote of 235 to 187. This bill entitled “Protecting States’ Rights to Promote American Energy Security Act,” is a reaction to the Department of Interior, Bureau of Land Management’s proposed rules to regulate hydraulic fracturing on federal lands. The bill supports state-based regulations for fracking and the development of oil and gas. It would require “the Department of Interior…[to] recognize and defer to State regulations, permitting, and guidance, for all activities related to hydraulic fracturing, or any component of that process, relating to oil, gas, or geothermal production activities on Federal land…” See prior blog article dated July 30, 2013, “House subcommittee meeting on “Protecting States’ Rights to Promote American Energy Security Act.”

In a Statement of Administration Policy: H.R. 2728, the White House expressed its strong opposition to this bill, arguing that it prohibits the BLM “from ensuring that hydraulic fracturing activities taking place on Federal and Indian lands are managed in a safe and responsible manner.” The Administration points to the Mineral Leasing Act as requiring the BLM to oversee oil and gas operations on these lands. The bill is seen as undermining the DOI’s trust responsibilities to protect Indian lands and will “require BLM to defer to existing State regulations on hydraulic fracturing on Federal lands, regardless of the quality or comprehensiveness of the State regulations – thereby preventing consistent environmental protections.”

H.R. 1965, the “Federal Lands Jobs and Energy Security Act, introduced by Doug Lamborn (R-CO) was approved 228 to 192. This bill provides a strict timeline for the issuance of permits to drill by the DOI. The DOI would be required to issue or deny a permit within 30 days of receipt of the application, with some provision for a 30-day extension. The application will be “deemed approved” if the DOI has not made a decision after 60 days. According to the bill’s supporters, this legislation will “provide for onshore leasing certainty and give certainty to oil shale development for American energy security, economic development, and job creation.”

In its Statement of Administration Policy: H.R. 1965, the Administration faults the bill for undermining the nation’s energy security and for setting “an arbitrary standard for leasing in open areas over leasing on the basis of greatest resource potential…” According to the White House, this “legislation would also remove the environmental safeguards that ensure sound Federal leasing decision-making by eliminating appropriate reviews under the National Environment Policy Act and undermine public resource planning efforts that have established a balanced approach to responsible oil and gas development while providing protection valuable surface and subsistence resources…”

H.R. 1900, sponsored by Mike Pompeo (R-KS), would amend the Natural Gas Act to direct the Federal Energy Regulatory Commission (FERC) to approve or deny a certificate of public convenience and necessity for a pre-filed project within 12 months after receiving a complete application. If the agency responsible for issuing the permit or approval does not do so within 120 days after FERC issues its final environmental document, the permit or approval will take effect after 30 additional days. The White House sees this bill as forcing the agencies to make decisions based on incomplete information within “rigid, unworkable timeframes.”

H.R. 2850 was introduced by Lamar Smith (R-TX). This bill, the “EPA Hydraulic Fracturing Study Improvement Act,” requires the EPA to “adhere to” and “meet the standards and procedures for the dissemination of influential scientific, financial, or statistical information” relating to its research for its up-coming report on the impacts of hydraulic fracturing on drinking water resources. The report would be peer-reviewed to assure compliance with the EPA’s “Guidelines for Ensuring and Maximizing the Quality, Objectivity, Utility, and Integrity of the Information Disseminated by the Environmental Protection Agency.” The report would also be required to include “objective estimates of the probability, uncertainty, and consequence of each identified impact, taking into account the risk management practices of the States and industry.” The deadline for the final report would be September 30, 2016. The Administration has not yet issued a statement relating to this bill.

Broomfield, Colorado re-count - Voters approve hydraulic fracturing ban

On November 5, 2013, Broomfield, Colorado voters considered a ban on  the use of hydraulic fracturing and open-pit storage of solid or liquid hydraulic fracturing waste for five years within the city and county of Broomfield. At the end of the day, it appeared that the ban had failed by 13 votes.

However, a re-count flipped the results, showing that the ban passed by 17 votes. There will be another re-count to confirm these results. This means that the voters in four Colorado towns have now voted for and approved hydraulic fracturing bans.

For information on these votes, see prior blog posting dated November 12, 2013. "Voters in three Colorado cities ban hydraulic fracturing for five years."

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

Illinois and California issue proposed administrative rules to implement hydraulic fracturing legislation

In Illinois, Governor Pat Quinn approved hydraulic fracturing legislation on June 17, 2013. The Illinois Department of Natural Resources (DNR) released proposed administrative rules to implement this legislation on November 15, 2013 – Proposed Administrative Rules for the Hydraulic Fracturing Regulatory Act and Proposed Administrative Rules for Seismicity to monitor Class II UIC wells receiving any hydraulic fracturing fluids.

The rules require oil and gas companies to disclosure chemicals used in fracking operations both before and after drilling and to test water before, during and after drilling. The rules also require the operators to provide information as to how the well will be drilled, how much fluid will be used, what pressures will be used, how water will be obtained, and how flowback fluids will be disposed. Before finalizing these rules, the DNR will hold two public hearings (November 26, 2013 in Chicago and December 3, 2013 in Ina) and will accept comments on the proposed rules through January 3, 2014.

In California, Governor Jerry Brown approved hydraulic fracturing legislation on September 20, 2013. Proposed regulations to implement the legislation were issued by the California Department of Conservation, Division of Oil, Gas and Geothermal Resources (DOGGR) on November 15, 2013. These regulations are open for public comment for 60 days (until mid-January), with five public hearings scheduled for early next year.

Under the proposed regulations, oil and gas companies would be required to apply for and obtain permits before starting hydraulic fracturing activities, notify near-by landowners of these activities, disclose all chemicals used during fracking, watch pressures and flow rates during well stimulation, and monitor groundwater quality before, during and after drilling. For the chemical disclosures, the oil and gas companies would be required to identify in the permit application what chemicals are anticipated to be used and then, within 60 days of fracking completion, to disclosure what chemicals were actually used during the operation. This information must be disclosed publicly through the Chemical Disclosure Registry (

The proposed regulations also require operators to continuously monitor pressures and flow rates during well stimulation, evaluate the condition of the well’s cement, and analyze surrounding wells and earthquake faults to prevent hydraulic fracturing fluids from migrating to other areas. While these proposed regulations will not go into effect until January 1, 2015, the DOGGR announced that emergency regulations will be in place by January 1, 2014.

International Energy Agency predicts that the US will become world's top energy producer in 2015 but will relinquish that position by 2020

The International Energy Agency (IEA), which was formed in the 1970s to keep track of trends and improve energy security, released its World Energy Outlook 2013 in London on November 12, 2013. The 2013 Outlook provides a review of key trends that IEA believes will shape the future of global energy through 2035. For the US, the IEA projects that it will pass Saudi Arabia and Russia as the world’s top oil producer by 2015 due to the use of hydraulic fracturing and other unconventional technologies in developing its shale gas resources. This will bring the US closer to energy self-sufficiency. But, according to the IEA, the US will lose its dominant position by 2020 due to decline in production from Texas and North Dakota fields. Continuous investment in drilling new wells will be required to compensate for the declines in existing wells and to maintain a high output. For the countries seeking to replicate the success of the US with hydraulic fracturing, the IEA cautions that “good geology alone is not sufficient.” These countries do not have the US’s legal environment and oil services capabilities to make shale oil and gas development worth the cost.

Other key trends noted in IEA’s World Energy Outlook 2013 include:
  • After 2020, Middle East oil will regain its dominance.
  • By 2020, China will be the largest oil-consuming country, overtaking the US 
  • Fossil fuels will be providing 75% of global energy by 2035.
  • Demand for oil will increase 27% between 2012 and 2035, to 111 million barrels per day.
  • Demand in the US, Europe and other developed countries will decrease between 2013 and 2035 due to improved energy efficiencies, such as tougher automotive fuel standards.
  • Oil use is increasingly concentrated in transport and petrochemicals. 
  • The demand for diesel will grow three times faster than the demand for gasoline.
  • Over the past ten years, more super-giant off-shore fields have been discovered in Brazil than in any other country. By 2035, Brazil will produce 6 million barrels of oil per day and become the world’s sixth largest oil producer.

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

Public Health England releases draft study of health impacts from shale gas extraction

Public Health England (PHE) is an agency under the UK’s Department of Health tasked with ensuring that the public is protected from infectious disease and environmental hazards. In October 2013, PHE released for public comment its draft Review of the potential public health impacts of exposures to chemical and radioactive pollutants as a result of the shale gas extraction. Due to the limited amount of shale gas drilling in the UK, PHE relied on literature and data from countries, such as the U.S., which already have commercial scale shale gas extraction operations. From the review of these materials, PHE identified several shale gas extraction activities that may impact surface and ground water, including
  • The production and storage of fracking fluid, flowback water, and other drilling by-products which may be spilled and then seep into subsurface aquifers or surface water resources.
  • Well blow-outs that may result in contamination of surface and ground water.
  • Injection of fracking fluids which may lead to contamination of aquifers if well integrity fails.
  • The improper treatment or disposal of wastewater during transportation off-site that may result in pollution of surface waters.
After analyzing these risks, PHE concluded that “the potential risks to public health from exposure to the emissions associated with shale gas extraction are low if operations are properly run and regulated. Most evidence suggests that contamination of groundwater, if it occurs, is most likely to be caused by leakage through the vertical borehole.” Additional findings include:
  • Good on-site management (well integrity, post operations, and appropriate storage and maintenance of hydraulic fracturing fluids and wastes) and appropriate regulation of all phases of gas exploration and development are “essential to minimize the risk to the environment and public health.”
  • Emissions which can impact local air quality come from a variety of shale gas extraction activities and sources, including drilling, flaring, diesel engines, storage tanks, and vehicles. 
  • All chemicals used in a hydraulic fracturing operation must be disclosed for a meaningful risk assessment.
PHE recognizes the need for continued work to more specifically define the potential health impacts of hydraulic fracturing and shale gas development. For this continued work, PHE recommends baseline environmental monitoring in the vicinity of shale gas activities, broadening the review to encompass socio-economic impacts (i.e., increased traffic, impacts on local infrastructure, and worker migration), the disclosure of all fracking fluid chemicals, and the identification of potentially mobilized natural contaminants.

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

Texas Court of Appeals interprets Horizontal Pugh Clause in oil and gas lease

On January 26, 2005, Community Bank of Raymore, as Trustee or Agent (“CBR”) entered into an oil and gas lease with Chesapeake Exploration L.L.C. and Anadarko Petroleum Corporation (collectively “Companies”). The lease covered approximately 16,000 acres in Loving County, Texas, which was divided into four blocks. During the primary term, the Companies drilled thirteen (13) producing wells on Block 2, to a formation at 5,672 feet below the surface. When the primary term expired on January 26, 2010, CBR requested the Companies to release the mineral rights to all formations below 5,672 feet. When the Companies refused, CBR sued for declaratory judgment and breach of contract.

CBR argued that the Horizontal Pugh Clause in the lease had been triggered because there was no production in paying quantities from the deeper formations when the primary term expired.

Horizontal Termination: At the expiration of the Primary Term or the conclusion of the continuous development program, this Lease shall terminate as to all of the leased Oil and Gas rights in all formations below the depth of 100 feet below the stratigraphic equivalent of the base of the deepest formation from which the Lessee is then producing Oil and/or Gas in paying quantities from a well or wells located on such proration or producing unit.

The Companies countered that the clause had not been triggered because they had maintained the lease beyond the primary term by securing production in paying quantities from Block 2’s existing wells and by developing Block 2 in accordance with the lease’s continuous development clause.[1]

The trial court ruled for the Companies, finding that the Companies were continuously developing the acreage in accordance with the lease, and therefore, the lease “remains valid and in effect as to all of the Leased Lands in Block 2…so long as [the Companies] engage in a continuous development program…” This decision was affirmed by Texas’ Eighth Court of Appeals. While stating that,“[i]n general, a horizontal Pugh clause holds a lease only to the stratum or level from which production has been secured in the unit during the primary term of the lease and, thus, frees the mineral interests below that depth absent additional development,” the Court of Appeals found that the Pugh clause in this case was different, operating “[a]t the expiration of the Primary Term or the conclusion of a continuous development program” (emphasis added). This Pugh clause provides a choice between two mutually exclusive possibilities.

Because the Companies have continuously developed Block 2, the Court of Appeals determined that the Pugh clause had not been triggered; and giving full effect to all the lease provisions, including the habendum clause,[2] the Court of Appeals concluded that the lease was not terminated.

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

[1] Continuous Development of Undeveloped Acreage: This Lease shall terminate as to the undeveloped Leased Land at the expiration of the Primary Term of this Lease unless Lessee commences a continuous development program on the undeveloped Leased Land and in accordance with terms and provisions hereinafter set forth: 
(1) If at the expiration of the Primary Term, a producing well or well capable of producing is located on the Leased Land or if Lessee is engaged in the actual drilling of a well in search of Oil and/or Gas…, then Lessee shall thereafter have the option to continuously develop the undeveloped acreage with no cessation of more than one hundred eighty (180) days…Should Lessee not opt to continuously develop the undeveloped acreage…, this Lease shall terminate as to the undeveloped acreage at such time as Lessee fails [sic] continuously develop as so provided herein. 
[2] According to the Court of Appeals, “[t]he lease’s habendum clause reflects the general principle that production from any part of the land included in an oil and gas lease will perpetuate the lease beyond the primary term as to all of the land covered by the lease.”

Pennsylvania Waste Treatment Facility sued for alleged discharges into Allegheny River

On October 28, 2013, the environmental group Clean Water Action filed a U.S. District Court lawsuit against Waste Treatment Corporation (WTC) alleging violations of the Clean Water Act, including illegal discharges of 200,000 gallons per day of drilling wastewater into the Allegheny River. Clean Water Action claims that these daily discharges contain harmful concentrations of chloride, lithium, strontium, radium-226, radium-228, and other chemicals.

Pointing to the Pennsylvania Department of Environmental Protection (DEP) and its January 10, 2013 Aquatic Biology Investigation of the plant’s discharges on the river, the group stated that high levels of salts, metals and radioactive compounds were found downstream – more than 100 times the levels found upstream of the plant. The investigation indicates that the plant puts over 125,000 pounds of salt into the river every day. Besides contaminating the water, these pollutants are building up in the river bed sediment where the DEP found radioactivity and oily residue, which is, according to Clean Water Action, endangering the Northern Riffleshell mussel, fish, and other river inhabitants.

The environmental group wants WTC to install proper technology to remove the contaminants before discharging any wastewater into the river. In addition, Clean Water Action claims that WTC’s National Pollutant Discharge Elimination System (NPDES) permit from 2003 does not authorize WTC to discharge oil and gas wastewater.

In response to the lawsuit, WTC’s vice president of operations stated that WTC has not processed or discharged any shale gas wastewater into the Allegheny River since May 2011 when the DEP requested all drilling operators not to dispose of their wastewater at 15 municipal treatment plants, including WTC’s facilities.

Wyoming requires groundwater testing before and after drilling

On November 12, 2013, the Wyoming Oil and Gas Conservation Commission (WOGCC) approved regulations to be effective on March 1, 2014, that will require oil and gas operators to conduct testing of water sources before and after drilling a well. With an Application for Permit to Drill or Deepen a Well, operators must identify all water sources within one-half mile of the surface location of the proposed oil or gas well and submit a plan to sample, analyze, and monitor at least four of these groundwater sources.

The plan must include “initial baseline water sampling and testing followed by a series of subsequent sampling and testing after setting the production casing or liner.” The baseline sampling must be done within a year prior to drilling. The first subsequent testing of the same water sources must be done within 12 to 24 months after installation of the production casing or liner, and the second subsequent sample to be taken within 36 to 48 months after the installation of the production casing or liner (but no less than 24 months after the first subsequent sample).

The new rule sets out a sampling and analysis protocol, requiring identification of various constituents including dissolved gases (methane, ethane, propane), alkalines, calcium, iron, potassium, sodium, and BTEX compounds (benzene, toluene, ethylbenzene and xylenes). The operator is required to provide the results of all analytical tests to the WOGCC and to the water source owner within 90 days of the sampling. If, however, the tests show any increases in thermogenic gas, methane, or BTEX compounds above certain thresholds, the operator must “provide verbal and written notification” within 24 hours to the Supervisor of the WOGCC, the Director of the Department of Environmental Quality, and the water source owner.

According to the rule, these sampling results “shall not create a presumption of or against liability, fault, or causation against the owner or operator of a well or multi-well pad who conducted the sampling, or on whose behalf sampling was conducted by a third-party. The admissibility and probative value of any such sampling that results in an administrative or judicial proceeding shall be determined by the presiding body according to applicable administrative, civil, or evidentiary rules.”

With this rule, Wyoming becomes the second state to require groundwater testing and monitoring both before and after drilling. Colorado was the first state, with its regulation taking effect in January 2013. Colorado requires operators to collect up to four water samples from aquifers, water wells, and other water sources within one-half mile of the oil or gas well site before the well is drilled and within 72 months after the well is placed in operation.

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

Sixth Circuit upholds "fair market value" agreements in Ohio oil and gas leases

From 2008 to 2010, numerous landowners in eastern Ohio entered into oil and gas leases with Anschutz Exploration Company, which were later assigned to Chesapeake Exploration LLC. These leases contain a “Preferential Right to Renew” or a “fair market value” provision (Paragraph 14 in the lease).

This clause provides that, “[i]f, at any time during the primary term…or within one year from the expiration, cancellation or termination of this Lease, Lessor receives an acceptable bona fide third-party offer to lease the Leasehold, in whole or in part, Lessor shall promptly provide the Lessee, in writing, of all of the verifiable particulars of such offer. Lessee shall have thirty (30) days…to advise Lessor, in writing, of its agreement to match said third-party offer…”

To settle disagreements about the meaning of this provision, Chesapeake filed a declaratory judgment action against numerous landowners who threatened to terminate the leases unless Chesapeake matched or “bettered” third-party offers that they had received.

On October 30, 2012, the Court found no ambiguity in the provision and ruled that Chesapeake has the right to match a bona fide offer and renew the lease; and if Chesapeake chose not to match the offer, the lease “run[s] its course.”

On October 30, 2013, the Sixth Circuit Court of Appeals affirmed the lower court’s decision. The Sixth Circuit rejected the landowners interpretation that Chesapeake was obligated to match any third-party offers and failing to do so constituted a breach of the lease, requiring Chesapeake to remove its equipment immediately.

The Circuit Court found that the language of the “preferential right to renew” clause does not require Chesapeake to “match” any third-party offer, but rather allows Chesapeake thirty (30) days in which to decide whether to accept or reject the offer. Chesapeake has a “right” to match, not an “obligation” to match a third-party offer. If Chesapeake decides not to exercise its right, the lease remains “ in force…so long as” Chesapeake is actively engaged in drilling operations.

For additional information on “fair market value” lawsuits, see “Analysis of fracking related litigation,” pages 59-61, which can be downloaded from this blog.

Voters in three Colorado cities ban hydraulic fracturing for five years

On November 5, 2013, Colorado voters in Boulder, Fort Collins and Lafayette agreed to ban hydraulic fracturing within their communities for the next five years while, in Broomfield, a close vote to allow hydraulic fracturing (a difference of 13 votes) is being re-counted. In Boulder, 77% of the voters agreed to extend a one-year moratorium for five more years. In Fort Collins and Lafayette, the anti-fracking votes were 55% and 60% respectively. The voters may have been influenced by September’s devastating floods during which there was grave concern about contamination from escaped fracking wastewater.

  • Broomfield – Prohibits the use of hydraulic fracturing and open-pit storage of solid or liquid hydraulic fracturing waste for five years within the city and county of Broomfield.
  • Fort Collins – Moratorium on hydraulic fracturing and the storage of fracking waste products for five years “in order to fully study the impacts of this process on property values and human health…”
  • Boulder – Extend the moratorium on hydraulic fracturing for five years in order for studies on hydraulic fracturing to be completed and for “pending litigation involving the legal authority of Colorado home rule cities to regulate oil and gas exploration…”
  • Lafayette – Prohibits any corporation or any person using a corporation
    • “to engage in the extraction of gas or oil within the City of Lafayette, with the exception of wells active and producing at the time of this Charter Provision…;”
    • “to deposit, store or transport waste water, ‘produced’ water, ‘frack’ water or other materials or chemical or by-products used in or resulting from the extraction of gas or oil, within, upon or through the land, air or waters of the City of Lafayette;”
    • “to engage in the creation of fossil fuel…and delivery infrastructures, such as pipelines, processing facilities, compressors or storage and transportation facilities that support or facilitate industrial activities related to the extraction of natural gas and oil;”
    • from asserting “state or federal preemptive law against the people of the City of Lafayette, or to challenge or overturn municipal ordinances or Charter provisions.”
These four ballot propositions follow the precedent set by Longmont, Colorado in 2012 where voters decided to amend the city charter to ban hydraulic fracturing, open-pit storage and disposal of fracking waste within its borders. In December 2012, the Colorado Oil & Gas Association (COGA) sued Longmont to invalidate the ban; and in July 2013, the Colorado Oil and Gas Conservation Commission (COGCC) joined COGA in the lawsuit. For more information on this lawsuit, see latest analysis of fracking-related litigation attached to this blog.

As with Longmont, it is very likely that the bans in Boulder, Fort Collins and Lafayette will be challenged in the courts. In the past, Colorado courts have upheld moratoria which include an opportunity to study the impact of hydraulic fracturing on the community. Opponents of these bans may argue that state and local governments have already completed extensive studies about hydraulic fracturing and that moratoria are not needed. See Voss v. Lundvail Bros., Inc., 830 P.2d 1051 (Colo. 1992)(“ We hold that while the Oil and Gas Conservation Act does not totally preempt a home-rule city's exercise of land-use authority over oil and gas development and operations within the territorial limits of the city, the statewide interest in the efficient development and production of oil and gas resources in a manner calculated to prevent waste, as well as in protecting the correlative rights of owners and producers in a common pool or source to a just and equitable share of the profits of production, prevents a home-rule city from exercising its land-use authority so as to totally ban the drilling of oil, gas, or hydrocarbon wells within the city.”)

The development of oil and gas within the state will be impacted by these bans even though these areas have less than 2% of the existing wells in Colorado.

California's new hydraulic fracturing law cited as basis for motion to dismiss

On October 21, 2013, the Western States Petroleum Association (WSPA) filed a motion to dismiss citing the provisions of the state’s new law (S.B. 4) which sets out tough restrictions on the use of hydraulic fracturing and other acidizing processes.

The WSPA is an intervener-defendant in an October 2012 lawsuit filed in the California Superior Court for Alameda County by several environmental groups seeking an injunction prohibiting any new oil and gas permit approvals until the California Department of Conservation, Division of Oil, Gas, and Geothermal Resources (“DOGGR”) “complies with its legal requirements to evaluate and mitigate the significant environmental and public health impacts caused by hydraulic fracturing.”

The Plaintiffs claim that the DOGGR has issued permits “without any environmental analysis” of “contamination of domestic and agricultural water supplies, the use of massive amounts of water, the emission of hazardous air pollutants, and the potential for induced seismic activity” allegedly created by hydraulic fracturing.

In its motion to dismiss, the WSPA argues that the complaint is now irrelevant because the law requires the DOGGR “to conduct an EIR [environmental impact report] addressing any potential environmental impacts from hydraulic fracturing in the state” by July 15, 2015. According to the WSPA, the law releases oil and gas companies from any need to go through California Environmental Quality Act (CEQA) until the EIR is completed. “Accordingly, there is no basis for the granting of any effective relief that is not already provided by the passage of S.B. 4, and thus the case should be dismissed.”

The DOGGR has filed pleadings concurring with WSPA, stating that “the regulatory framework adopted in S.B. 4, including new provisions for well stimulation permits and for environmental review, render plaintiff’s claims regarding the Department’s alleged past pattern and practices for environmental review of hydraulic fracturing moot.”

Pennsylvania State Senator plans to introduce legislation to restrict hydraulic fracturing

Pennsylvania State Senator Jim Ferlo (D-Allegheny), who introduced legislation to place a moratorium on hydraulic fracturing in September 2013, plans to introduce legislation to restrict provisions of Act 13 of 2012, which established impact fees for drilling and banned local governments from using zoning regulations to ban hydraulic fracturing.

The proposed legislation would replace Act 13’s impact fee with a severance tax on natural gas of $0.25 per thousand cubic feet of gas. This tax would be adjusted as the price of gas increases. The first $200 million of taxes collected would be divided between counties and municipalities (60%) and the state (40%); and thereafter, the monies collected would go into the state’s general fund.

Under the new provisions, prior to submitting a permit application to the Department of Environmental Protection (DEP), the driller would be required to provide notice to landowners and municipal officials that are within 5,000 feet of the well site. Set-backs from the well pad would be increased, requiring 1,500 feet from buildings, 2,500 feet from drinking water sources, 1,000 feet from exceptional value water sources, and 500 feet from any body of water. These set-backs cannot be waived by the DEP.

The proposed legislation would place a moratorium on any additional leasing of state forest land for two years. As for trade secrets, the proposed law would allow doctors to have immediate access to any and all information (including trade secrets) needed to treat a patient, and doctors would be allowed to share this information with the patient and health agencies without signing a confidentiality agreement.

This last provision to allow doctors to obtain and share trade secrets is a direct result of a court dismissing a doctor’s lawsuit relating to Act 13’s “gag order.” See “Physician’s challenge to Pennsylvania’s “fracking gag order” dismissal.”

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

North Dakota mineral owners file ten class actions relating to royalties owed for flaring natural gas

Ten class actions were filed in North Dakota by mineral owners alleging lost income due to the flaring of natural gas by various oil and gas producers. According to a July 2013 report by Ceres, the flaring of natural gas in North Dakota has doubled in the past two years.

The lawsuits allege that  the producers have violated several North Dakota Industrial Commission rules relating to flaring and paying royalties for flared gas. After an oil well begins to produce, North Dakota allows limited flaring during the first year. After one year, the producer must apply for a written exemption for any future flaring. If the producer does not ask for the exemption, royalties and state taxes on the flared gas must be paid.

The lawsuits allege that these various producers have flared gas without the proper authorization and therefore, owe royalties on “(a) gas flared from a well one year after the first production without applying for and obtaining a flaring exemption; (b) gas flared from a well within the first year of production under an order issued by the Industrial Commission limiting the maximum barrels of oil to be produced per day until the well is connected to a gathering system and processing plant…; and (c) gas flared within the first year of production even though the operator reported the well was physically connected to a gathering system and processing plant.”

The plaintiffs claim that they lost millions of dollars in royalties due to producers’ practice of burning off large quantities of gas rather than selling it.

For an example of one of these ten class actions, see attached case filed in District Court, Northwest Judicial District, County of Williams, State of North Dakota.

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

Canadian regulatory board approves application for hydraulic fracturing in northwest territories

On October 30, 2013, the Canadian National Energy Board (“NEB”) approved an application for exploratory horizontal drilling and hydraulic fracturing in the Northwest Territories. The decision marks the first time such activity will be allowed in the remote region, which straddles the Arctic Circle. The authorization will remain in effect until October 2018.

Specifically, NEB has approved two wells, which were granted land and water permits earlier this year, to be drilled in Norman Wells, located in the Canol Shale Play and approximately 100 miles south of the Arctic Circle. NEB’s approval was based, in part, on the operator’s risk assessment of hydraulic fracturing in the area, which included the following:
  • Review of geology and fault identification 
  • Proposed mitigation measures regarding microseismic monitoring 
  • Proposed commitments regarding wellbore integrity, including casing design 
  • Proposed cementing program 
  • Proposed cement bond log evaluations 
  • Proposed casing integrity pressure tests 
The operator has also agreed to abide by the Mackenzie Valley Resource Management Act and other applicable laws and regulations, including those requiring measures to ensure local water supplies are not affected. NEB and the operator also set an expected maximum daily gas flow rate, and the operator must report any exceedances of that rate to the NEB. The operator has stated that drilling is slated to begin in late December 2013, with hydraulic fracturing to potentially follow in late January 2014.

NEB is an independent, federal Canadian agency established by the Parliament of Canada to regulate international and interprovincial aspects of the oil, gas and electric utility industries. In the last few years, NEB has conducted over 25 public information and community engagement sessions in Northern Canada on the regulation of hydraulic fracturing. In a statement, the NEB said, “the board recognizes the importance of fostering better understanding and communication with all stakeholders that take part in board processes and engaging Canadians is a priority.”

This article was prepared by Lauren Brogdon ( or 713 651 5375) from Norton Rose Fulbright's Energy Practice Group.

EPA request for information related to hydraulic fracturing study to close November 15

The deadline for submitting information to the US Environmental Protection Agency (EPA) for its ongoing study on hydraulic fracturing is November 15, 2013.

Although such information was originally due on April 30, 2013, EPA extended the deadline to “ensure that [it] is up-to-date on evolving hydraulic fracturing practices and technologies.”

Notice of the deadline extension was published in the Federal Register. It is expected that the extension will not delay release of the final report in 2014.

Although EPA is conducting a “thorough literature search,” it solicited additional information from the public in an attempt to also gather and review “studies or other primary technical sources that are not available through the open literature.”

Specifically, EPA asked “interested persons” to provide “scientific analyses, studies, and other pertinent scientific information, preferably information which has undergone scientific peer review.”

EPA has stated that it will consider all submissions but that preference will be given to peer-reviewed data and literature sources.

EPA issued a progress report on its hydraulic fracturing study in December 2012, after holding five technical roundtables in November 2012.

The progress report stated that EPA is conducting 18 research projects on the relationship between hydraulic fracturing and drinking water and reviewing data on fracking fluids, well construction, chemical spills, and water quality from wells around the country.

The progress report is discussed in our February 27, 2013 blog post, EPA Technical Roundtables Concerning Potential Impacts of Hydraulic Fracturing on Drinking Water Resources.

This article was prepared by Lauren Brogdon ( or 713 651 5375) from Norton Rose Fulbright's Energy Practice Group.

US Coast Guard proposes rules allowing fracking waste water to be transported by barge

The disposal of large volumes of wastewater produced during shale gas extraction has posed challenges for companies, regulators, and communities, especially in the Marcellus Shale region.

In 2012, the U.S. Coast Guard received two requests for approval for the bulk shipment of wastewater resulting from hydraulic fracturing operations in Pennsylvania and the northern Appalachia area. 

On October 30, 2013, in the Federal Register, the Coast Guard published proposed rules to allow barges to transport wastewater in bulk; thus, providing companies an alternative to storing the waste at the drilling site or transporting it by rail or truck to remote facilities.

The Coast Guard regulates the shipment of hazardous materials on the nation’s rivers and classifies cargoes for bulk shipment. 
[U]nder certain circumstances a bulk liquid hazardous material may be transported by a tank vessel if it is a ‘listed cargo’ (listed in any of several specified tables in Coast Guard regulations, [wastewater], however, cannot be treated as a ‘listed cargo’ because the specific chemical composition of [wastewater] varies from one consignment load to another and may contain one or more hazardous materials . . . , including radioactive isotopes such as radium-226 and radium-228.
Under the proposed rules, in order to carry wastewater, a barge owner must request approval from the Coast Guard prior to shipping, provide additional information and comply with new policies. 

To address concerns about the shipment of wastewater, the Coast Guard has issued a proposed policy letter entitled “Carriage of Conditionally Permitted Shale Gas Extraction Waste Water in Bulk,” which specifies the conditions under which a barge owner may request and be granted a Certificate of Inspection endorsement in order to transport wastewater. 

This proposed policy letter will be open for public comment through November 29, 2013. The Coast Guard specifically requests information about disclosing proprietary information to the government and testing the wastewater for radioactive material.

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

Physician's challenge to Pennsylvania's “fracking gag order” dismissed

On February 14, 2012, the Pennsylvania Governor signed into law Act 13 of 2012 which regulates the disclosure of hydraulic fracturing chemical components.
Pa. Governor Tom Corbett

Section 3222.1(b)(10) of the Act requires that companies engaged in hydraulic fracturing disclose information regarding chemicals used in the process to medical providers contingent on the medical providers executing “a confidentiality agreement and provid[ing] a written statement of need for the information indicating all of the following:

  1. the information is needed for the purpose of diagnosis or treatment of an individual; 
  2. the individual being diagnosed or treated may have been exposed to a hazardous chemical; and 
  3. knowledge of information will assist in the diagnosis or treatment of an individual.” 
Dr. Alfonso Rodriguez, a licensed medical physician “who has treated patients that have been exposed to toxic fluids and/or environmental contamination caused by oil and gas operations,” filed a lawsuit on July 27, 2012, complaining that the “medical gag” provisions of Pennsylvania’s Act 13 of 2012 improperly restricted his First Amendment freedom of speech rights.

He argued that the “practice of medicine requires a free and open exchange of questions, answers and information between” the doctor and the patient, medical community, researchers and insurance companies, among others. Plaintiff sought an injunction from requiring him to sign any confidentiality agreement.

On October 23, 2013, the Court granted Defendants’ motions to dismiss, ruling that Plaintiff lacked standing because his “alleged injury…is too conjectural to satisfy the injury in fact requirement of [U.S. Constitution] Article III standing.”

The court continued, “Plaintiff has not alleged that he has been in a position where he was required to agree to any sort of confidentiality agreement under the act. Therefore…he has not yet…been prevented from engaging in any sort of communication as a result of the act. Similarly, plaintiff has failed to indicate that he has been forced to waive any of his fundamental constitutional rights.”

The case has been dismissed.

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

Michigan to tighten Its hydraulic fracturing rules

The Michigan Department of Environmental Quality (“DEQ”) plans to strengthen its hydraulic fracturing rules by adding provisions to protect water resources and to require additional chemical data submissions. This announcement comes after roughly 200 public meetings held since 2011 and attended by the DEQ. 

Michigan’s current fracturing rules went into effect on June 22, 2011 and require the operator or the service company of a high volume hydraulic fractured (HVHF) well (using more than 100,000 gallons of fracking fluid) to provide:
  1. Material Safety Data Sheets for the chemical additives used, 
  2. the volume of each additive, and 
  3. the records and associated charts showing fracturing volumes, rates, and pressures. 
This information must be submitted to the DEQ within 60 days after completion of the well. The rules also require a water withdrawal plan and information showing the total volume of flowback water generated.

The proposed revisions would add the following requirements:
  • Water withdrawal assessment and monitoring – In the application for a drilling permit, the operator will be required to use the state’s water withdrawal assessment tool. Withdrawal will not be approved if the review indicates that the withdrawal may cause an adverse impact to rivers or streams. Also if there is a water supply within 1,320 feet of a proposed withdrawal, the operator must install a monitor well and report water levels. There will be specifications for water storage pits.
  • Water quality sampling – Oil and gas operators will be required to collect baseline samples from up to 10 water supply wells within 1,320 feet of a proposed withdrawal, six months or less before drilling begins.
  • Monitoring and reporting – Operators will be required to state in the permit application whether HVHF will be used, submit separate applications for HVHF operations on existing wells, notify the DEQ at least 48 hours in advance before starting the process, and monitor and report fluid pressures and volumes for all HVHF operations.
  • Chemical additive disclosures – Operators will be required to submit information regarding HVHF chemical additives on The information must include chemical constituents and maximum concentrations. For trade secrets, the chemical family and trade name must be identified.
There will be a period of public comment after Michigan’s rules committee reviews the DEQ’s proposed rules and finalizes a draft. It is anticipated that these new rules will be in place sometime in 2014.

As these new rules are being proposed, the anti-fracking group Ban Michigan Fracking is trying to get more than 258,000 signatures by May 2014 in order to have its initiative on the ballot in November 2014. The Michigan Chamber of Commerce is opposed to the fracking ban and has launched its own campaign to defeat the initiative.

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

Pennsylvania proposes 60% increase in drilling fees

On September 14, 2013, the Pennsylvania’s Environmental Quality Board proposed changes to the structure of oil and gas well permit fees, including increased flat fees for unconventional well permits. The Independent Regulatory Review Committee is currently studying these proposed changes which would replace the current sliding fee structure based on wellbore length with flat fees. The current average fee for a Marcellus Shale well is $3,200. The proposed flat fees would be $5,000 for horizontal unconventional wells and $4,200 for vertical unconventional wells - an average fee increase of $1,000 to $1,800 per well or an average 60% increase per well. The Pennsylvania Department of Environmental Protection has stated that the permit fee increases are needed to maintain current staffing levels and to support permit reviews and other regulatory oversight obligations because of a 22% decrease in the number of new wells permitted since 2010.

Some energy companies have expressed opposition to the permit fee increases, stating that Pennsylvania’s gas industry will be adversely affected. They dispute whether the increases are necessary to maintain staff for permit reviews, pointing to the 22% decrease in well permits and the likelihood that this decline will continue with the fee increases and Pennsylvania’s stringent regulatory oversight.

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

The European Parliament seeks to restrict hydraulic fracturing while France's Constitutional Council upholds hydraulic fracturing ban

On October 9, 2013, the European Parliament meeting in Strasbourg, France, voted (with 328 for and 311 against) to tighten rules on hydraulic fracturing by requiring a full environmental impact assessment from oil and gas companies seeking permits to use the process. An assessment would even be required for exploratory drilling. Another round of voting in the Parliament is required to finalize the rules. In the environmental assessment, the oil and gas companies must identify and describe the direct and indirect effects of the project on the population, human health, biodiversity, land, soil, water, air, and the landscape. The member state’s oil and gas authority must make a decision about issuing a permit within 90 days of receipt, and only after considering comments from the public and other interested parties, including independent, qualified and technically competent experts.

The European Parliament’s proposed rules are being met with opposition from oil and gas companies who see the rules as an expensive hurdle to doing business with the member nations. These companies may turn to other areas of the world to develop shale gas in order to avoid the extensive assessment reporting requirements, which may take as much as one year to prepare. It is thought by some that the rules are a reaction to a recent report (released September 30, 2013) from the United Nation’s Intergovernmental Panel on Climate Change (IPCC) which stated that methane gas is 86 times more damaging to the climate than carbon dioxide over a 20-year period.

Two days after the European Parliament vote, on October 11, 2013, the French Constitutional Council, which is made up of judges and former French presidents and has the power to deem a law unconstitutional, reviewed the French legislature’s 2011 ban on hydraulic fracturing. The Council upheld the ban. France’s environmental minister applauded the decision as an environmental and political victory while oil and gas industry groups complained that the ruling deprives the country of needed oil and gas exploration and development. The U.S. Energy Information Administration (EIA) has estimated that France has 137 trillion cubic meters of technical recoverable shale gas and 4.7 billion barrels of technical recoverable shale oil in the Paris basin and the Rhone Valley.

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

Environmental group urges moratorium on California offshore hydraulic fracturing operations

In a letter dated October 3, 2013, the Center for Biological Diversity (CBD) urged federal offshore regulators at the Bureau of Ocean Energy Management and the Bureau of Safety and Environmental Enforcement, Pacific Region, “to place an immediate moratorium on new oil and gas approvals” and to suspend existing approvals “involving hydraulic fracturing (fracking) and other unconventional extraction techniques to protect our marine environment and comply with your statutory stewardship duties.” The CBD states that these agencies are violating federal environmental statutes, including the National Environmental Policy Act (NEPA) and the Outer Continental Shelf Lands Act (OCSLA), by allowing hydraulic fracturing and unconventional drilling in the Pacific Ocean without conducting a supplemental NEPA review to analyze the risks to human health and endangered marine life and a full environmental impact statement. The group points to records which indicate that at least a dozen wells in California state waters have been fracked in the past three years using dangerous substances such as “2-Butoxyethanol, methanol and other cancer causing chemicals.”

The Center for Biological Diversity was recently successful in a similar case involving hydraulic fracturing on federal land in the central California Monterey Shale Formation, finding that the federal agency failed to assess the risks of fracking before issuing the leases. On March 31, 2013, in Center for Biological Diversity and Sierra Club v. The Bureau of Land Management and Ken Salazar, Secretary of the Department of the Interior, No. CV-11-06174 (N.D. Cal., December 8, 2011), the Court ruled that the BLM failed to conduct the “hard look” analysis required by NEPA by dismissing any development scenario involving hydraulic fracturing when used in combination with technologies such as horizontal drilling. See prior blog entitled “BLM Violated NEPA by Granting Leases without Evaluating Fracking Risks,” dated April 10, 2013.

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

Marcellus Shale Coalition releases drilling and hydraulic fracturing guidelines

On October 9. 2013, the Marcellus Shale Coalition (MSC), whose members include some of the major operators in the Marcellus Shale, issued guidelines for drilling and completion of shale gas wells, covering the topics of (1) planning, (2) general health and safety considerations, (3) well control, (4) high pressure equipment, (5) drilling operations, and (6) hydraulic fracturing and flow back operations. The MSC considers “the drilling phase and hydraulic fracturing and completions process [to be] two of the most crucial” steps to bring a shale well into production. These guidelines are not binding requirements but are a continuation of recommended practices developed by the MSC since April 2012, beginning with 11 key steps to help operators improve site planning, development and restoration. The new guidelines include the following recommendations:

  • Planning: The guidelines provide a check list of items that must be considered before moving the rig and other completions equipment into place. Operators need to consider regulatory requirements, traffic, lighting, noise, water management and recycling, erosion and sediment controls and secondary containment.
  • Health and Safety: Operators must ensure that all personnel are properly trained.
  • Well Control: Two mechanical barriers in the flow path should be used during all phases of drilling and completions operations when feasible. The mechanical barrier equipment would include blow-out preventers which must be carefully tested, inspected and maintained.
  • High Pressure Equipment must be routinely tested and inspected to ensure proper operation.
  • Drilling Operations: Operators should identify the depth of groundwater aquifers and other oil and gas wells within 1000 feet of the surface location and 500 feet of the horizontal portion of the wellbore.
  • Hydraulic Fracturing and Flow Back Operations: “Operators should commit to transparency in their operations by disclosing the composition of hydraulic fracturing fluid additives to the extent permitted by suppliers, while respecting related intellectual property rights, and proprietary and confidential business information.” Operators should monitor adjacent oil and gas wells during the fracturing process. During flow back operations, operators should minimize the release of produced gases and contain produced liquids through capture or temporary flaring. Venting is discouraged.

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

Ohio advises drillers to comply with EPA chemical reporting requirements

In September 2012, the Ohio legislature passed regulations requiring oil and gas well operators to report the contents of fracking fluids, recycling fluids, and wastewater to the state’s Department of Natural Resources. These reporting regulations went into effect on September 11,2012, and require the disclosure of the trade name and volume of all “products, fluids, and substances,” maximum concentrations of additives in the fluid, Chemical Abstract Service (CAS) numbers, and maximum concentrations of ingredients intentionally added to the fluid. The total volume of any recycled hydraulic fracturing fluids must also be disclosed. Ohio Rev. Code Ann. § 1509.10(A). This information must be made available to the public on the FracFocus website or by other means approved by the Department. Ohio Rev. Code Ann. § 1509.10(F) The regulation does allow for the protection of trade secrets, but it requires operators to share chemical information with medical professionals in emergencies. § 1509.10(H). It also allows for disclosure of trade secrets in the event of spills and investigations (with confidentiality protections).

In addition to abiding by these Ohio regulations, on September 11, 2013, the Ohio State Emergency Response Commission (SERC) advised oil and gas well owners and operators that they must also comply with the federal Emergency Planning and Community Right-To-Know Act (EPCRA) by reporting all hazardous chemicals (any substance requiring a Material Safety Data Sheet under the Occupational Safety & Health Administration) over the 10,000 pound threshold that are stored at the well site. Written notification of these hazardous chemicals must be given to SERC, the Local Emergency Planning Committee (LEPC), and the local fire department within 90 days of receiving the shipment or producing the substance on site. For any “Extremely Hazardous Substances” (EHS) in amounts from 1 to 500 pounds, depending on the substance, notice must be given within 60 days. The EPCRA also requires annual reports identifying all hazardous chemicals and/or EHS at or above the threshold weights at any time on the site during the calendar year. This information must be provided to the SERC, the LEPC, and the local fire department. Under the EPCRA, there is a procedure for claiming that a reportable chemical is a trade secret. To protect trade secrets, the well owner or operator will have to apply to both the EPCRA and SERC for protection. The SERC points out that failure to comply with EPCRA requirements may result in an enforcement action by the U.S. Environmental Protection Agency with the possibility of civil penalties up to $32,500 per day.