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 Capps asserts that these operations were “approved with overly broad and outdated plans” that do not adequately assess the current offshore environmental risks.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 (barclay.nicholson@nortonrosefulbright.com 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.
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
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.
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
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 (barclay.nicholson@nortonrosefulbright.com 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 (FracFocus.org).
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.
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 (FracFocus.org).
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.
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
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:
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
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 (barclay.nicholson@nortonrosefulbright.com 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
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
- 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.
- 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.
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 (barclay.nicholson@nortonrosefulbright.com 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.”
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 (barclay.nicholson@nortonrosefulbright.com 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.
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.
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
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 (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
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 (barclay.nicholson@nortonrosefulbright.com 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.
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
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.
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.
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
- 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.”
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.”
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
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.”
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
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 (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
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 (barclay.nicholson@nortonrosefulbright.com 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.
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 (barclay.nicholson@nortonrosefulbright.com 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
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 (lauren.brogdon@nortonrosefulbright.com 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 (lauren.brogdon@nortonrosefulbright.com or 713 651 5375) from Norton Rose Fulbright's Energy Practice Group.
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 (lauren.brogdon@nortonrosefulbright.com or 713 651 5375) from Norton Rose Fulbright's Energy Practice Group.
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