Fulbright Partner to Co-Chair IEL 4th Annual Law of Shale Plays Conference

Barclay Nicholson, partner in the Fulbright Houston office, has been chosen to co-chair the Institute for Energy Law’s (IEL) 4th Annual Law of Shale Plays Conference.

The conference will be held June 6-7, 2013 in Fort Worth, Texas, where Range Resource’s Senior Vice President and General Counsel David Poole will also serve as the other co-chair of the conference.

In conjunction with the conference there are several upcoming planning meetings. These planning meetings will be held over lunch and are key events in developing the program for the conference, allowing conference chairs to gather ideas for topics and speakers from practitioners.

These meetings will be held in the following locations:

Fort Worth: 
Register
Wednesday, November 28th from Noon-2 p.m.
Petroleum Club
777 Main Street, Suite 4000
Fort Worth, TX 76102
Houston: 
Register
Thursday, November 29th from Noon-2 p.m.
Downtown Club at Houston Center
1100 Caroline Street
Houston, TX 77002
Southpointe: 
Register
Thursday, January 10, 2013 from Noon-2 p.m.
Fulbright & Jaworski, Southpointe Energy Complex
370 Southpointe Boulevard, Suite 300
Canonsburg, PA 15317

Learn more about Fulbright’s Shale and Hydraulic Fracturing Task Force at www.fulbright.com/fracking.

U.K. Lifts Ban on Hydraulic Fracturing

On December 13, 2012, Edward Davey, the U.K.’s Secretary of State for Energy and Climate Change, announced that hydraulic fracturing could resume in the U.K., subject to new controls to mitigate the risks of seismic activity. This follows the European Parliament’s rejection of a Europe-wide moratorium on hydraulic fracturing on November 21, 2012.

In the U.K., hydraulic fracturing was banned in May 2011 after two small earthquakes occurred near Lancashire, England.

In mid-2012, the U.K. Department of Energy and Climate Change (DECC), the Royal Society, and the Royal Academy of Engineering concluded that “the health, safety, and environmental risks associated with [hydraulic fracturing] can be effectively managed” with new controls.

Under the new rules, in addition to obtaining all other necessary permits and consents before fracking, the operator must:
  • Conduct a pre-fracking review of all information on seismic risks and the existence of faults in the area; 
  • Submit to the DECC a progressive fracking plan showing how seismic risks will be addressed; 
  • Perform seismic monitoring before, during, and after the frac; and 
  • Implement a “traffic light” system which will be used to identify unusual seismic activity requiring reassessment or halting of operations. 
Secretary Davey also announced that the recently formed Office for Unconventional Gas and Oil will be overseeing the regulation of hydraulic fracturing and that a study will be commissioned to investigate possible impacts of shale gas development on greenhouse gas emissions and climate control.

Read Secretary Davey's complete statement.

This article was prepared by Barclay R. Nicholson (bnicholson@fulbright.com or 713 651 3662) from Fulbright's Energy Practice.

CAPP Releases Hydraulic Fracturing Operating Practice on Anomalous Induced Seismicity: Assessment, Monitoring, Mitigation and Response

In November 2012 the Canadian Association of Petroleum Producers (CAPP) released it's seventh Hydraulic Fracturing Operating Practice, entitled Anomalous Induced Seismicity: Assessment, Monitoring, Mitigation and Response.

The Operating Practice outlines the requirements for CAPP member companies to assess the potential for anomalous induced seismicity—also known as earthquakes—and where necessary, establish appropriate monitoring procedures and procedures to mitigate and respond to anomalous induced seismicity in shale gas and tight gas development areas.

CAPP is the industry association representing members which account for about ninety percent of Canada's natural gas and crude oil production.

Under the Operating Practice, companies are required to assess the potential for anomalous induced seismicity for each hydraulic fracturing program. Given the unique geologies where hydraulic fracturing takes place, each hydraulic fracturing program or location requires a tailored approached that draws from the Operating Practice.

The Operating Practice includes:
  • Assessing the potential for anomalous induced seismicity using available engineering, geologic and geophysical data.
  • Complying with applicable regulatory requirements and employing sound wellbore construction practices.
Where assessment indicates the potential for anomalous induced seismicity exists companies are to:
  • evaluate wellbore placement and drilling design to account for geologic conditions;
  • communicate with onsite personnel and establish procedures and preparedness for the possibility of anomalous induced seismicity;
  • establish procedures to monitor for induced seismicity during hydraulic fracturing operations; and
  • establish procedures to mitigate and respond to anomalous induced seismicity
The Operating Practice follows previous Operating Practices dealing with fracturing fluid additive disclosure, fracturing fluid additive risk assessment and management, baseline groundwater testing, wellbore construction and quality assurance, water sourcing, measurement and reuse, and fluid transport, handling, storage and disposal. The Operating Practices are built upon CAPP's Hydraulic Fracturing Guiding Principles and Operating Practices published in January 2012.

Read: CAPP Hydraulic Fracturing Operating Practice: Anomalous Induced Seismicity: Assessment, Monitoring, Mitigation and Response.

This article was prepared by Alan Harvie (alan.harvie@nortonrose.com or +1 403.267.9411) from Norton Rose - Canada's Energy Practice.

Alberta's Energy Resources Conservation Board Releases draft Hydraulic Fracturing Directive

On Thursday, December 6, 2012 Alberta's Energy Resources Conservation Board (ERCB) released for public comment a draft Hydraulic Fracturing Directive.

The ERCB is Alberta's primary energy regulator and establishes the rules under which oil and gas development can take place.

The ERCB already has in place numerous directives that apply to hydraulic fracturing. However, given the increasing use of hydraulic fracturing technologies with horizontal drilling, the ERCB is proposing additional rules on subsurface activity during hydraulic fracturing operations.

The draft Hydraulic Fracturing Directive is proposing:
  • new requirements to prevent the loss of well integrity during hydraulic fracturing operations; 
  • new requirements for a well licensee to assess, plan for, and mitigate the risks of interwellbore communication with offset wells; 
  • new requirements to protect freshwater aquifers from hydraulic fracturing operations at depths less than 100 metres (m) below the base of groundwater protection; 
  • increased vertical setback distances for hydraulic fracturing operations near water wells; 
  • increased vertical setback distances for hydraulic fracturing operations near the top of the bedrock surface; 
  • pumping volume restrictions and exemptions to setback distances for nitrogen fracturing operations for coalbed methane wells; and 
  • new notification requirements to ensure that well licensees notify the ERCB prior to commencing hydraulic fracturing operations and in the event that hydraulic fracturing operations cause an unintended communication event with an offset well or a nonsaline aquifer. 
The ERCB is accepting public comments until January 18, 2013. 

This article was prepared by Alan Harvie (alan.harvie@nortonrose.com or +1 403.267.9411) from Norton Rose - Canada's Energy Practice.

Republican Congressional Leaders Question Objectivity of Shale Gas Study

In a letter dated November 30, 2012, members of the House Energy and Commerce Committee urged the Secretary of Health and Human Services (HHS) to ensure the objectivity of a study on the health impacts of hydraulic fracturing and other shale development activities.

The committee members are concerned that the scientific objectivity of the HHS is being “subverted” because of, among other things, the alleged predisposed bias against hydraulic fracturing of the Director of the Agency for Toxic Substances and Disease Registry (ATSDR) within the Centers for Disease Control (CDC), the agency tasked with this study. 

The Director has previously stated that shale gas development “has been a disaster in some communities,” that fracturing fluid contains “potentially hazardous chemicals,” and that work near drilling sites “is turning up data of concern.” 

Further, in prior studies related to oil and gas activities, the ATSDR has referred to naturally occurring groundwater substances as “contaminants” and has failed to consider all data available from other sources or consult with state regulatory and public health officials, such as the United States Geological Survey, Groundwater Protection Council, and state environmental and/or oil and gas agencies.

The committee members want the HHS to adopt an approach based on sound scientific principles and analysis and to submit the report to a robust peer review process.

Seeking transparency, the Committee re-urged its September 12, 2012 request for a CDC briefing so that “Congress, the states, [and] the public” can be included in the reporting process and hold the CDC to “high standards of scientific objectivity and validity.”

Read the November 30, 2012 letter from the House Energy and Commerce Committee.

This article was prepared by Barclay R. Nicholson (bnicholson@fulbright.com or 713 651 3662) from Fulbright's Energy Practice.

NYDEC Publishes Revised Proposed High-Volume Fracking Regulations

On Thursday, November 29, 2012, the New York Department of Environmental Conservation (NYDEC) published revised proposed regulations relating to high-volume hydraulic fracturing (wells using more than 300,000 gallons of water as the base fluid).

The NYDEC developed these revisions and additions after receiving more than 66,000 public comments (most against hydraulic fracturing) on the original proposals that were released on September 28, 2011.

The 30-day public comment period on the revised proposed regulations begins on December 12, 2012, and allows a 90-day extension for completion of the New York Commissioner of Health’s review of the draft Supplemental Generic Environmental Impact Statement.

The NYDEC advised that it would not take any final action or make any final decision regarding hydraulic fracturing until after the health review and the work from three outside experts—Colorado School of Public Health professor John Adgate, George Washington University School of Public Health and Health Services professor Lynn Goldman, and University of California Los Angeles Fielding School of Public Health professor Richard Jackson—is completed.

According to the NYDEC, “the proposed regulations are to apply to the use [of fracking] statewide,” with the initial targets being the Marcellus and Utica shale formations.

The revised proposals include additional reporting requirements for drillers who want to re-fracture an existing well and allow for public and private water treatment plants to accept fracking waste water.

The proposed revised regulations for high-volume hydraulic fracturing include requirements for blow-out preventer use and testing plans, detailed mapping, enhanced disclosure of chemical additives, and well pad siting setbacks.

The chemical disclosure must identify each chemical constituent intentionally added to the base fluid and its proposed concentration. 

There are also new well construction, site preparation, operational, and maintenance requirements.

This article was prepared by Barclay R. Nicholson (bnicholson@fulbright.com or 713 651 3662) from Fulbright's Energy Practice.

European Parliament Calls for Shale Regulation, Rejects Ban

On November 21, 2012, the European Parliament comprised of 754 representatives from the 27 Member States of the European Union (EU) approved two resolutions relating to shale oil and gas development based on reports from its Environmental, Public Health and Food Safety Committee and its Industry, Research and Energy Committee, both of which studied shale gas and oil extraction activities.

These resolutions call for each member state to establish “robust regulations” for all shale activities and to use caution in developing shale gas and oil resources with hydraulic fracturing. 

The European Parliament decided that each member state should determine whether it wants to exploit shale gas development (vote: 492 for to 129 against) and rejected a proposed ban on hydraulic fracturing (vote: 391 against ban to 262 for ban).

Other provisions of these resolutions include:
  • Because of insufficient data on fracturing chemicals and the environmental and health risks associated with hydraulic fracturing, there is an on-going need for further and continuous research. 
  • The development of a comprehensive European Best Available Techniques Reference (BREF) for fracking based on robust scientific engineering practice is needed. 
  • Operators must meet certain seismic and microseismic standards to prevent seismic tremors. 
  • Operators must consider the need for advance water provision plans based on local hydrology, local water resources, the needs of other local water users, and capacities for wastewater treatment. 
  • The oil and gas industry must take measures to protect groundwater. Concerns over the potential of shale gas development damaging water supplies through leakage from wells can be addressed through the adoption of best practices in well development and construction, especially casing, cementing, and pressure management. Operators should test domestic water wells close to their oil and gas wells both before and during production, and to disclose the results to the public in an accessible, understandable and transparent manner. 
  • Chemicals used for hydraulic fracturing must be registered with the European Chemicals Agency and cannot receive approval unless it is ensured that they do not cause damage to the environment or that such damage is mitigated. 
  • EU shale gas operators should engage and build strong relationships with local communities, given that landowners in Europe do not own underground resources and thus do not benefit directly from shale gas extraction.
Read the text of  the two resolutions:

This article was prepared by Barclay R. Nicholson (bnicholson@fulbright.com or 713 651 3662) from Fulbright's Energy Practice.

Utah's Mining Board Approves Fracking Rule to Set Standards for Operation

On October 24, 2012, Utah’s Oil, Gas and Mining Board approved a hydraulic fracturing rule that requires chemical disclosure and sets standards for wellbore integrity and management of flowback water and surface protection.

Effective November 1, 2012, operators must report “the amount and type of chemicals used in a hydraulic fracturing operation . . . to www.fracfocus.org within 60 days of hydraulic fracturing completion for public disclosure.” Utah Admin. Code R. 649-3-39.1. 

While this rule contains no exemption for trade secrets, Utah’s trade secrets laws may protect some of the additives used during the hydraulic fracturing process from public disclosure. 

The Utah hydraulic fracturing rule can be found at https://fs.ogm.utah.gov.


This article was prepared by Barclay R. Nicholson (bnicholson@fulbright.com or 713 651 3662) from Fulbright's Energy Practice.

EIP Petitions EPA to Add Oil & Gas Industry to TRI


On October 24, 2012, the Environmental Integrity Project (EIP)and 16 other environmental groups petitioned the U.S. Environmental Protection Agency (EPA) to add the oil and gas industry to the list of facilities required to report pollutants released into the air, water, and land to the Toxics Release Inventory (TRI).

The TRI was enacted in 1986 in response to the disaster in Bhopal, India and initially applied only to manufacturing industries.

However, Congress vested the EPA with authority to include additional industry groups as needed; and since its inception, the EPA has added electricity producers, mining operators, and others.

The environmental groups petitioned the EPA to require the oil and gas industry to disclose the chemicals and other substances that are released during their operations, including hydraulic fracturing.

This disclosure is not tied to any permitting requirements and is sought by the groups to purportedly “give citizens information about air, water and land pollution.”

The 81-page petition is available at www.environmentalintegrity.com.


This article was prepared by Barclay R. Nicholson (bnicholson@fulbright.com or 713 651 3662) from Fulbright's Energy Practice.

New EPA Report Again Ties Wyo. Water Pollution To Fracking

On October 10, 2012, as a follow-up to its December 2011 draft report concerning allegations of groundwater contamination in Pavillion, Wyoming, the EPA released the methodology and results for additional water samples collected from two monitoring wells by the U.S. Geological Society, in cooperation with the Wyoming Department of Environmental Quality, in April 2012, a report that was highly criticized by industry.

The EPA announced that the results of the additional testing “are generally consistent with the monitoring data” in the draft report which indicates that the groundwater in the area contains chemicals (glycols, alcohols, and methane) linked to hydraulic fracturing.

The December 2011 draft report and this additional data are now available for public comment on the EPA website through January 15, 2013. These reports can be found here; and additional information about the comment period can be found here.

The EPA’s conclusion is being questioned by industry representatives, including Encana Corp., the operator of oil and gas wells near Pavillion. An Encana spokesman stated that the EPA has provided no sound scientific evidence that drilling has impacted domestic drinking water wells and that finding hydrocarbons in two monitoring wells is not surprising given that the wells were drilled into a gas production zone.


This article was prepared by Barclay R. Nicholson (bnicholson@fulbright.com or 713 651 3662) from Fulbright's Energy Practice.

EPA Requires Two-Day Notice of Hydraulic Fracturing Operations Effective October 15, 2012

In mid-April 2012, the EPA issued its new air emissions regulations relating to processes and equipment at natural gas well sites.

While many of these regulations have been highlighted by the EPA (such as the required use of “green completion” equipment after January 1, 2015), a notice requirement for hydraulically fractured or refractured operations has been practically ignored. 

Beginning October 15, 2012, the owner or operator of a natural gas well must provide the EPA (and in some cases, a state or local air quality agency) with at least two-day notice that hydraulic fracturing will take place at the well location. 

This notice, which can be submitted in writing or electronically, must include:
  1. the anticipated date of the well completion operation; 
  2. contact information for the owner or operator; 
  3. the API well number; 
  4. the “latitude and longitude coordinates for each well in decimal degrees to an accuracy and precision of five decimals of a degree using the North American Datum of 1983;” and 
  5. the planned date of the beginning of flowback. 
RESOURCES
Summary of the requirements relating to natural gas well sites
New Air Emission Regulations

Sections 60.5360, 60.5365, 60.5370, and 60.5420 provide information relating to the scope of the regulations, the effective date, and the reporting requirements.

This article was prepared by Barclay R. Nicholson (bnicholson@fulbright.com or 713 651 3662) from Fulbright's Energy Practice.

Federal vs. State Regulation

On September 10, 2012, members of the U.S. House of Representatives’ Committee on Natural Resources wrote to Secretary of the Interior Ken Salazar, requesting that the Bureau of Land Management’s proposed regulations governing hydraulic fracturing on federal land be made stronger.

The group wants the proposed regulations strengthened:
  1. to require the public disclosure of the pre- and post-fracturing chemicals and additives;
  2. to re-assess the use of FracFocus as the system for the public disclosure of chemicals and to consider a government-run system that would be subject to open records laws and that would allow the information to be published in an open, searchable format; 
  3. to prevent the use of open-air pits to store wastewater from hydraulic fracturing operations; 
  4. to set up strict guidelines for variances or waivers from the regulations; and 
  5. to include rules relating to set-backs in order to control air pollution. 
Read the U.S. House of Representatives' Committee on Natural Resources letter to Secretary of the Interior Ken Salazar.

Within one day of this letter, Governor Matt Mead of Wyoming expressed his opposing opinion, stating that federal hydraulic fracturing rules are unnecessary because the state regulations are already stronger. 

For example, current Wyoming state regulations require the pre-fracturing disclosure of all chemical identities and concentrations of each additive used in the hydraulic fracturing process.


This article was prepared by Barclay R. Nicholson (bnicholson@fulbright.com or 713 651 3662) from Fulbright's Energy Practice.

New Drilling and Recycling Regulations Proposed by Texas Railroad Commission Relating to Hydraulic Fracturing

In recent weeks, the Texas Railroad Commission (RRC) approved several amendments to the Administrative Code relating to drilling, casing, cementing, well control, and the commercial recycling of produced water and/or hydraulic fracturing flowback fluid.

On August 21, 2012, the RRC proposed regulations covering:
  1. casing, cementing, drilling, and completion requirements, 
  2. cathodic protection wells, and 
  3. seismic holes and core holes (16 Tex. Admin. Code §§ 3.13, 3.99, and 3.100 respectively). 
These changes reflect the transfer of the Texas Commission on Environmental Quality's Groundwater Advisory Unit to the RRC. Proposed § 3.13 details the RRC's requirements for all wells, consolidates the requirements for well control and blowout preventers, and updates the requirements for drilling, casing, cementing, and fracture stimulation. 

This section provides for the isolation of usable-quality water zones, potentially productive zones, and over-pressured zones in order to prevent contamination and the migration of fluids behind the casing. Important provisions include:
  • A proposal to set surface casing to a depth of 3,500 feet or greater must be in writing and requires prior approval of the appropriate district director. 
  • The proposal must detail how the operator plans to maintain well control during drilling, ensure successful circulation and adequate bonding of cement, and, if necessary, prevent upward migration of deeper formation fluids into protected water.
  • All casing installed in a well that will be subjected to fracture stimulation must have a minimum internal yield pressure rating designed to withstand at least 1.2 times the maximum pressure to which the casing may be subjected.
  • The operator must pressure test the casing or fracture tubing on which the pressure will be exerted during the fracturing.
  • All annuli must be monitored during stimulation operations. If the pressure deviates above the anticipated increases, the operator shall immediately suspend fracturing and notify the appropriate district director within 24 hours of the deviation.
  • An operator must set and cement sufficient surface casing to protect all usable quality water strata.
  • On bay and offshore wells, all tool pushers, drilling superintendents, and operators' representatives (when the operator is in control of the drilling) must furnish certification of satisfactory completion of API training or similar nationally recognized training program on well control equipment and procedures.
  • A mechanical integrity test of the surface casing must be conducted after total depth or the next casing depth is reached to ensure integrity of the casing after drilling.
On September 11, 2012, the RRC approved new regulations relating to the commercial recycling of produced water and/or hydraulic fracturing flowback fluid. (16 Tex. Admin. Code, Chapter Four, Subchapter B, Divisions I-VI). 

Proposed Division 5 sets out requirements for off-lease or centralized commercial recycling, while proposed Division 6 concerns stationary commercial recycling of produced water and/or hydraulic fracturing flowback fluid. 

Under the proposed regulations, a commercial recycling applicant must provide engineering, geological, and other information sufficient to show that the "issuance of the permit will not result in the waste of oil, gas, or other geothermal resources, the pollution of surface or subsurface water, or a threat to the public health or safety." 

On-lease, non-commercial recycling is to be authorized by concurrent amendments to 16 Texas Administrative Code § 3.8, relating to water protection, which states that "no person conducting activities subject to regulation by the commission may cause or allow pollution of surface or subsurface water in the state."

The amendments approved on August 21, 2012 can be found at http://www.rrc.state.tx.us/rules/prop-amend-3-13-Aug21-2012.PDF; and the September 11, 2012 amendments are at is http://www.rrc.state.tx.us/rules/prop-amend-3-8-comm-recycling-Sept2012.PDF.

The public comment periods for these proposed amendments end at noon on October 9, 2012 and October 29, 2012, respectively.


This article was prepared by Barclay R. Nicholson (bnicholson@fulbright.com or 713 651 3662) and Stephen C. Dillard (sdillard@fulbright.com or 713 651 5507) from Fulbright's Energy Practice and Fulbright's Litigation Practice.

Texas Railroad Commission's Proposed Regulations Regarding Hydraulic Fracturing Flowback Fluid

On September 4, 2012, the Texas Railroad Commission proposed new regulations relating to the commercial recycling of produced water and/or hydraulic fracturing flowback fluid. Division 5 of the proposed regulations sets out requirements for off-lease or centralized commercial recycling, and Division 6 concerns the stationary commercial recycling of produced water and/or hydraulic fracturing flowback fluid.

On-lease commercial recycling is to be authorized by concurrent amendments to 16 Texas Administrative Code § 3.8, relating to water protection. Section 3.8 states that “no person conducting activities subject to regulation by the commission may cause or allow pollution of surface or subsurface water in the state.”

Under the proposed regulations, a commercial recycling applicant must provide engineering, geological and other information sufficient to show that the “issuance of the permit will not result in the waste of oil, gas, or other geothermal resources, the pollution of surface or subsurface water, or a threat to the public health or safety.”

Review the proposed regulations

The public comment period ends at noon on October 29,  2012.


This article was prepared by Barclay Nicholson (bnicholson@fulbright.com / 713 651 3662) from Fulbright's Energy Law Practice.

Fracking Bills Fail in California Legislature

Since February 2011, the California legislature has been considering two bills that would regulate hydraulic fracturing operations throughout the state.

AB 591 would require operators to disclose fracking activities and the contents of all fracking fluids, subject to exemptions for proprietary and/or trade secret information. 

AB 972 would impose a moratorium on all fracking operations in the state pending adoption of regulations being developed by the California Department of Conservation, Division of Oil, Gas and Geothermal Resources. 

This week both bills failed to make it out of the Senate Appropriations Committee, effectively killing both bills for the current legislative session, if not permanently. 

AB 972 was strongly opposed by industry and found little or no support from the Brown administration. 

This lack of support was due in part to the estimate that, if enacted, the moratorium would cost the state approximately $9 million in delayed or lost revenues. 

In essence, by placing these proposed bills into the Senate’s Appropriations Suspense File, the legislature has simply deferred to the Department of Conservation regulation of all oil and gas activities in California, including hydraulic fracturing.

This article was prepared by Barclay Nicholson (bnicholson@fulbright.com / 713 651 3662) from Fulbright's Energy Law Practice.

Summit Petroleum (6th Cir. Aug. 7, 2012): EPA’s Aggregation of Oil and Gas Emissions Based on “Mere Functional Relatedness” is Unreasonable

A three-judge panel of the U.S. Court of Appeals for the Sixth Circuit* in Summit Petroleum Corporation v. U.S. Environmental Protection Agency (Nos. 09-4348; 10-4572) vacated EPA's order aggregating Summit's sour gas wells and sweetening plant into a single major source.

The Court agreed with American Petroleum Institute and American Exploration and Production Counsel that EPA’s determination that the physical requirement of “adjacency” in an aggregation determination can be established through mere functional relatedness is unreasonable and contrary to the plain meaning of the term “adjacent.” 

The court remanded the case to EPA for a reassessment of Summit's Title V source determination in light of the proper, plain-meaning application of the requirement that Summit's activities be aggregated only if they are located on physical contiguous properties. 

Judge Moore dissented from the opinion, stating that EPA’s consideration of functional interrelatedness was “both reasonable (and thus worthy of deference) and correct,” and that she would have affirmed the agency’s decision to aggregate Summit’s stationary sources.

It is not yet known whether EPA will seek a rehearing en banc or a petition for certiorari from the U.S. Supreme Court.


* The states within the geographic boundaries of the Sixth Circuit are Ohio, Kentucky, Michigan, and Tennessee.

This article was prepared by Barclay Nicholson (bnicholson@fulbright.com / 713 651 3662) from Fulbright's Energy Law Practice.

Pennsylvania Commonwealth's Decision in Robinson Township

The Pennsylvania Commonwealth Court released its decision this morning in Robinson Township et al. v. Commonwealth of Pennsylvania (284 M.D. 2012).

The Commonwealth Court:
  1. found that the municipalities and two individual council members had standing, but that the other petitioners (an environmental group and a physician) did not; 
  2. held that Act 13, Section 3304--which would have established uniform, statewide zoning standards--violated substantive due process because it allowed incompatible uses, which did "not serve the police power purpose of the local zoning ordinances, relating to consistent and compatible uses in the enumerated districts of a comprehensive zoning plan"; 
  3. declared Section 3304 "unconstitutional and null and void, and permanently enjoin[ed] the Commonwealth from enforcing it"; 
  4. declared Section 3215(b)(4) (relating to Department of Environmental Protection waivers from water body and wetland setbacks) null and void; and 
  5. dismissed the remaining counts. 
Read the Marcellus Shale Coalition’s statement on the decision

Ohio’s Governor Issues An Executive Order Relating to Underground Injection Activities

Ohio Governor John Kasich
On July 10, 2012, with the ink barely dry on the signing into law of S.B. 315, which requires water testing within 1500 feet of proposed horizontal wells and the disclosure of chemicals used in hydraulic fracturing, Ohio Governor John Kasich issued Executive Order 2012-09K.

This Executive Order immediately implements regulations and requirements on deep-injection wells.

The Executive Order authorizes the head of the Division of Oil and Gas Resources Management in Ohio’s Department of Natural Resources to require seismic testing before well drilling, regulations regarding sites that do not pass certain tests, set maximum injection pressures, require installation of an automatic shut-off device, and require continuous monitoring of the annulus between the casing and tubing in a well.

With the increase in the number of underground injections of brine and other waste products from drilling, exploration, and production operations, the Governor asserted that these steps were necessary to update the regulations relating to underground injection control activities and “to provide the greatest degree of citizen protection possible without causing irreparable harm to an industry important to the economy.”

This article was prepared by Barclay Nicholson (bnicholson@fulbright.com / 713 651 3662) from Fulbright's Energy Law Practice.

BLM Extends Public Comment Period on Proposed Rules until 9/10/12

Acting BLM Director
Mike Pool
On June 27, 2012, the Bureau of Land Management announced that it had extended the public comment period on its proposed rules (issued on May 4, 2012) to require companies to publicly disclose the chemicals used in hydraulic fracturing operations on federal and Indian lands.

Comments from the public, industry groups, and other stakeholders will now be accepted until September 10, 2012

The decision to extend the comment period for an additional 60 days was made to allow greater public participation. 

As of June 25, 2012, the Bureau had received more than 170 comments on the proposed rules. 

Acting Director Mike Pool explained that “it is critical that the public have full confidence that the right safety and environmental protections are in place…and additional time was warranted so that all parties had an opportunity to participate.”

In addition to the required disclosure of hydraulic fracturing chemicals, the proposed rules include new guidelines for how drillers case drilled wells and require that oil and gas operators have a water management plan in place for handling fracturing fluids that flow back to the surface. 

According to the Bureau, these rules will modernize the management of well stimulation activities, including hydraulic fracturing, to make sure that oil and gas operations conducted on federal and Indian lands follow common sense industry best practices. 

The Bureau asserts that these rules will build public confidence, while ensuring continued access to valuable resources needed for the country’s energy economy.

This article was prepared by Barclay Nicholson (bnicholson@fulbright.com / 713 651 3662) from Fulbright's Energy Law Practice.

Senate Hearing on Induced Seismicity

On June 19, 2012, the U.S. Senate’s Energy and Natural Resources Committee heard testimony from members of the Committee on Induced Seismicity Potential in Energy Technologies.

 The chair of the Induced Seismicity committee, Dr. Murray W. Hitzman of the Colorado School of Mines, advised the Senators that, since the 1920s, it has been recognized that pumping fluids into or out of the ground has the potential to cause seismic events that can be felt. 

These induced seismic events, though small in scale, concern the public and raise questions about increased seismic activity and its potential consequences. Dr. Hitzman reported the following findings:
  • Induced seismicity associated with fluid injection or withdrawal in energy development is “caused in most cases by change in pore fluid pressure and/or change in stress in the subsurface in the presence of faults with specific properties and orientations and a critical state of stress in the rocks.” 
  • The total balance of fluid introduced into or removed from the subsurface is the factor that has the most direct consequence in regard to induced seismicity. 
  • The very low number of felt seismic events (one unconfirmed in the U.S. and one confirmed in England) relative to the large number of hydraulically fractured wells for shale gas (more than 35,000 in the U.S.) is “ likely due to the short duration of injection of fluids and the limited fluid volumes used in a small spatial area.” 
  • “The majority of…waste water disposal wells do not pose a hazard for induced seismicity.” The few induced seismic events that have been attributed to disposal injection wells are causally linked between the injection zones and previously unrecognized faults in the subsurface. 
Dr. Mark Zoback, a Geophysics professor at Stanford University, in his written testimony, stated that, while the risks of induced seismicity posed by injection of waste water are extremely low, these risks can be effectively managed by taking five (5) steps:
  1. avoid injections into brittle rock faults; 
  2. select formations to minimize pore pressure changes; 
  3. install local seismic monitoring arrays; 
  4. establish protocols “to define how operations would be modified if seismicity were to be triggered;” and 
  5. reduce injection rates or abandon injection wells if triggered seismicity poses any hazard.
Additional information is available at the U.S. Senate's Energy and Natural Resources Committee web site.


This article was prepared by Barclay Nicholson (bnicholson@fulbright.com / 713 651 3662) from Fulbright's Energy Law Practice.

National Research Council Releases Study On Seismicity Potential In Energy Technologies

At the direction of the U. S. Congress, the DOE requested the NRC to examine the scale, scope, and consequences of induced seismicity (earthquakes attributable to human activities) relating to energy technologies that involve fluid injection or withdrawal from the earth’s subsurface, including activities such as shale gas recovery and its use of hydraulic fracturing as well as disposal of waste water into the subsurface.
The NRC released its report on June 15, 2012 (download a prepublication version of the report).

The main findings of the NRC study relating to shale oil development and waste water disposal are, to quote the study:
  1. the process of hydraulic fracturing a well as presently implemented for shale gas recovery does not pose a high risk for inducing felt seismic events; [and] 
  2. injection for disposal of waste water derived from energy technologies into the subsurface does pose some risk for induced seismicity, but very few events have been documented over the past several decades relative to the large number of disposal wells in operation… 
The study points out that there has only been one possible case of felt seismicity in the United States and one confirmed case in England related to hydraulic fracturing activities.
The NRC recommends the development of a detailed methodology to assess the risk of induced seismicity; the collection by state and federal agencies of data related to fluid injection (well location, injection depths, volumes, and pressures); the adoption of best practices protocols relating to induced seismicity; and the coordination of federal and state agencies, such as the EPA, USGS, land management agencies, oil and gas commissions, geological surveys, and environmental agencies, to address induced seismic events.

The NRC’s findings will be presented to the U.S. Committee on Energy and Natural Resources at a hearing on June 19, 2012, at 10 a.m. EST . This hearing will be webcast live on the Committee’s website.

This article was prepared by Barclay Nicholson (bnicholson@fulbright.com / 713 651 3662) from Fulbright's Energy Law Practice.

USFWS Withdraws Proposed Endangered Status for Dunes Sagebrush Lizard

Today, the United States Fish and Wildlife Service (“FWS”) withdrew its proposed rule to list the dunes sagebrush lizard as endangered under the Endangered Species Act of 1973 (“ESA”), finding that the best scientific and commercial data available indicate that the threats to the species and its habitat have been reduced to the point that the dunes sagebrush lizard does not meet the statutory definition of an endangered or threatened species.

According to FWS, the withdrawal is based on its conclusion that the threats to the species as identified in the proposed rule no longer are as significant as believed at the time of the proposed rule.

FWS originally proposed the dunes sagebrush lizard for listing on the Federal Lists of Endangered and Threatened Wildlife and Plants (commonly referred to as the “Endangered Species List”) on December 14, 2010. 

On December 5, 2011, FWS extended its final determination on whether or not to list the dunes sagebrush lizard as endangered until June 14, 2012, due to significant scientific disagreement regarding the sufficiency or accuracy of the available data relevant to the proposed listing.

Under the ESA, it is unlawful for any person to “take” an endangered and threatened species, which means “to harass, harm, pursue, hunt, shoot, wound, kill, trap, capture, or collect, or to attempt to engage in any such conduct.” 

FWS regulations define “harm” for purposes of the Act to include “significant habitat modification or degradation where it actually kills or injures wildlife by significantly impairing essential behavioral patterns, including breeding, feeding or sheltering.”

Environmental groups had been pressuring FWS for years to list the dunes sagebrush lizard on the endangered species list, claiming that the lizard was endangered primarily as a result of rapidly expanding oil and gas development in the Permian Basin of New Mexico and Texas. 

Placement of the lizard on the endangered species list would have greatly limited oil and gas activities in its habitat, thus significantly impacting oil and gas production in southeastern New Mexico and west Texas.


This article was prepared by Heather M. Corken (hcorken@fulbright.com or 713 651 8386) and Kristen Roche (kroche@fulbright.com or 713 651 5303) from Fulbright's Environmental Law Practice.

New Study Shows EPA Overestimation of GHG Emissions

A new study, released on June 1, 2012, indicates that EPA has significantly overestimated greenhouse gas (GHG) emissions for the natural gas industry, including emissions from the hydraulic re-fracturing of unconventional gas wells.

Where EPA reported 712.6 thousand metric tons of methane emissions from gas well workovers (including hydraulic re-fracturing) in its 2010 national inventory of GHGs, the study estimated emissions of 197.3 thousand metric tons.

Prepared by URS Corp. and The LEVON Group, the study was sponsored by the American Petroleum Institute and America’s Natural Gas Alliance (collectively, API/ANGA) in response to EPA’s revised calculation methodology for GHG emissions from natural gas systems.

The revised methodology was first adopted in 2011 for preparation of the 2009 national inventory and resulted in a 204% increase to estimated GHG emissions for the natural gas production sector.

The API/ANGA study analyzed data for nearly 91,000 natural gas wells and is being touted as the most comprehensive data set compiled for natural gas operations.

The data did not include measured emissions and, therefore, the study does not challenge the EPA’s assumptions regarding emission rates for various emission activities.

However, the API/ANGA data do indicate that the frequency and duration of these activities are much lower than assumed by EPA.

For hydraulic re-fracturing events, EPA had assumed a re-fracture rate of 10%, meaning 10% of fracture-completed gas wells are re-fractured every year. In contrast, the API/ANGA study found an average well re-fracture rate of 1.6% to 2.3%.

The study scope included emission activities other than those associated with the re-fracturing of natural gas wells. In particular, API/ANGA found that EPA appears to be overestimating the frequency and duration of liquid unloading events resulting in emissions to the atmosphere. EPA’s 2010 national inventory estimated 4.5 million metric tons of methane from unloading events.

In comparison, the API/ANGA study found only 0.64 million metric tons of emissions. Coupled with the hydraulic fracturing results discussed above, the study estimated total production sector emissions of 4.4 million metric tons of methane versus EPA’s estimate of 8.8 million metric tons.

The API/ANGA study was not prepared as a challenge to the EPA’s recently-issued New Source Performance Standards (Subpart OOOO) and National Emission Standards for Hazardous Air Pollutants (Subparts HH and HHH) for the oil and gas sector.

Therefore, the study does not discuss the VOC or HAP emission assumptions underlying those rules. Nevertheless, the API/ANGA study highlights the limited information regarding upstream emissions upon which EPA has historically relied and generally supports the positions taken by parties challenging the rules.


This article was prepared by Bob Greenslade (bgreenslade@fulbright.com / 303 801 2747) from Fulbright’s Environmental Law Practice.

Ohio Passes New Energy and Hydraulic Fracturing Legislation

Ohio Governor John Kasich
The Ohio General Assembly passed SB 315 last week, which contains changes to Ohio's oil and gas conservation program.

The bill was sent to Governor Kasich on May 24, 2012. The Act will become law on June 5, unless vetoed by the Governor, which is not likely given his support for the bill.

The new law will then be filed with the Secretary of State and become effective 91 days after it is filed.

The bill contains various changes to Ohio’s oil and gas law, including changes to pooling and unitization appeals, increased liability insurance requirements, increased radius (to 1,500 feet) for pre-drilling groundwater sampling, disclosure requirements relating to hydraulic fracturing fluids, identification requirements regarding water sourcing and volumes used in production operations, measures to encourage renewable and alternative energy, changes to Ohio's underground injection control (e.g., brine disposal) program and fees, and changes to various other fees, among other provisions.

A summary of SB 315 is available on the Ohio Department of Natural Resources' web site.

This article was prepared by Janet McQuaid (jmcquaid@fulbright.com or 724 416 0427) from Fulbright's Environmental Law Practice.

Survey of Flaring Regs for Arkansas, Colorado, Louisiana, North Dakota, Pennsylvania, Texas and Wyoming

Natural gas production is booming in the United States.

Operators, aided by advances in hydraulic fracturing, have ramped up production, whether by reworking old oil wells or exploiting new formations altogether.

However, just because an operator has the ability to produce natural gas does not necessarily mean that it can sell the gas; compressors, pipelines, treatment plants, and other infrastructure must be prepared in order to get the gas to market. 

In some cases, this lack of infrastructure has led operators to vent or flare gas at the wellhead. 

In order to get a better understanding of where the law stands and in what direction it may head, below is a survey of the major gas-producing states’ regulations regarding flaring. 

Note:  this survey covers only the regulations that speak directly to the question of whether an operator may flare the gas on private lands. Flaring has other potential legal repercussions, such as the particles that are emitted in the process that could call into question state or federal clean air laws or endangered species, and different regulations apply to wells located on state- or federally-owned land. Those concerns are beyond the scope of this survey.

Arkansas

Arkansas allows operators to vent or flare gas within 7 days of when gas is first encountered in a well. After that time, gas may not be vented or flared unless the operator obtains an exception from the Arkansas Oil and Gas Commission.

Colorado

In Colorado, all flaring must be authorized by the Colorado Oil and Gas Conservation Commission unless it is done during an upset condition, well maintenance, well stimulation flowback, purging operations, or a productivity test.

Louisiana

In Louisiana, flaring of natural gas is prohibited unless the Louisiana Office of Conservation finds upon written application that such a prohibition would result in an economic hardship on the operator. The regulations further note that no such economic hardship can be found if the current market value—at the point of delivery for the gas proposed to be vented—exceeds the cost involved in making the gas available to market.

North Dakota

Gas may be flared during the first year of production from a well. N.D. Century code 38-08-06.4. After the one-year grace period, the well must be either connected to a pipeline or used at the wellhead to power an electrical generator, unless the producer applies for and obtains an exception. Id

Producers can obtain exceptions from the Industrial Commission for additional flaring if the producer presents evidence demonstrating the economic infeasibility of piping gas from the well. Id. 

It is economically infeasible to connect the well to a natural gas gathering line if the direct costs of connecting the well to the line and the direct costs of operating the facilities connecting the well to the line during the life of the well are greater than the amount of money the operator is likely to receive for the gas, less production taxes and royalties, should the well be connected to the gathering line. N.D. Century Code 43-02-03-60.2.

Oklahoma

In Oklahoma, an operator may vent or flare up to 50 mcf/day without a permit if: (i) it is not economically feasible to market the gas; (ii) a suitable stand, line, or stack is used to prevent a hazard to people; and (iii) there is less than 100 ppm of hydrogen sulfide in the gas. For venting or flaring at rate greater than 50 mcf/day, the operator must seek an administrative permit from the Conservation Division of the Oklahoma Corporation Commission.

Pennsylvania

Pennsylvania’s oil and gas conservation regulations do not address flaring, other than to say that it may be done so long as it does not endanger people.

Texas

Texas producers have a grace period of 10 days after the initial completion, recompletion in another field, or workover operations in the same field, during which they may flare natural gas. 16 TAC 3.32(f)(1)(A). Releases of gas that are not routinely measured (such as small amounts that escape during the initial completion of a well) are exempt from flaring requirements and need not be measured for the purposes of well allowables. 16 TAC 3.32 (d)(1)

Producers may also vent or flare gas when a well must be unloaded or cleaned-up to atmospheric pressure, but may only do so for fewer than 24 hours in one continuous event or a total of 72 hours in one calendar month. 16 TAC 3.32(f)(1)(B). Texas producers may obtain exceptions from the railroad commission for the release of gas when the operator presents information to show the necessity of the release. 16 TAC 3.322(f)(2)

However, such administrative exceptions shall not be granted for periods exceeding 180 days, though they may be renewed. 16 TAC 3.32(h).

Wyoming

Wyoming allows for flaring without any additional regulatory authorization in the following situations: 
  1. During emergencies or upset conditions, which are temporary situations that result in the unavoidable short-term venting or flaring of gas; 
  2. For well purging and evaluation tests;
  3. During initial or recompletion evaluation tests which shall not exceed 15 days unless otherwise authorized; or 
  4. If it is a venting or flaring of casinghead gas from an oil well that produces less than 60 MCF of gas per day, unless the Wyoming Oil & Gas Conservation Commission determines that waste is occurring.
If an operator wishes to vent or flare gas in any other circumstance, it must apply for authorization from the Oil and Gas Conservation Commission, and the application must include the information required by Section 39.

Texas RRC Press Release, May 23, 2012


Texas Railroad Commissioner David Porter discussed the possibility of new regulations in a May 23 news release. Noting that gas drilling activity “is outstripping capacity and awaiting pipeline infrastructure,” Commissioner Porter asserted that Texas “must proactively address flaring.” The only specifics provided in the news release were: 
  1. that the Railroad Commission is seeking to work in partnership with Texas electrical energy regulators to use excess gas for strategic generation in light of the threat of weather-induced power curtailment; and
  2. that the Railroad Commission is studying a pilot program for using gas as a source of power for on-lease operations in lieu of flaring the gas.

This article was prepared by Barclay Nicholson (bnicholson@fulbright.com / 713 651 3662) from Fulbright's Energy Law Practice.

ABA Energy Litigation: Fracking's Alleged Links to Water Contamination and Earthquakes

The American Bar Association's Section of Litigation- Energy Litigation Committee released its Vol. 11, No. 2 Newsletter for Spring 2012.

Fulbright attorneys Barlcay Nicholson, Kadian Blanson and Andrea Fair, contributed the article Frackings Alleged Links to Water Contamination and Earthquakes.

EPA's Final Rule Limiting Air Emissions From Fracking Operations

On April 17, 2012, the US EPA released a final rule that establishes, under new Subpart OOOO in the New Source Performance Standards (NSPS) program of the Clean Air Act (CAA), the first-ever federal emissions standards for hydraulically fractured or re-fractured completions for natural gas wells, as well as new or revised rules relating to controlling other emission sources associated with oil and natural gas industry activities.

Starting 60 days after the final rule is published in the Federal Register (probably in early- to mid-July), owners or operators of fractured or re-fractured natural gas wells must reduce flowback emissions through flaring and route salable quality gas to a flowline “as soon as practicable.”

Starting January 1, 2015, owners or operators must, where feasible, utilize reduced emission completions (also known as “green completions”) for non-wildcat, non-delineation wells with sufficient pressure.

The proposed version of the rule faced significant opposition due, in part, to concerns regarding a lack of available equipment for conducting green completions.

Although the EPA has added significant flexibility to the timing of rule requirements, such as pushing the applicability of the green completion requirement to 2015, a number of criticisms remain. Prominent issues include the application of NSPS to temporary, construction-related emissions and allegations that the EPA’s true intent is to regulate methane, a greenhouse gas, and not VOCs.

Another issue that bears watching is how the regulation of flowback emissions under NSPS factors into preconstruction permit authorizations under the New Source Review (NSR) program. Generally, new stationary sources that are subject to the NSPS program are also subject to NSR.

New Subpart OOOO has placed in the forefront for the first time the issue of whether flowback emissions following the hydraulic fracturing of a natural gas well or other wellhead activities are subject to NSR permitting requirements.

Historically, the EPA has not explicitly required such emissions to be authorized in a NSR permit, apparently viewing these emissions as temporary and de minimis in nature. Some states do require NSR authorization for well emissions; many have assumed that these emissions are covered under permits by rule or exemptions.

At this time, the EPA has provided no real indication of whether it will now consider flowback emissions to be subject to NSR preconstruction review.

The agency did provide an exemption in the rule to prevent automatic major source NSR permitting due to NSPS applicability from re-fracturing of an existing well. (Rather paradoxically, the exemption requires doing everything that the rule would have required if it were applicable).

However, this exemption does not apply to new wells and the EPA’s discussion in the rule preamble falls far short of a declaration that minor NSR permitting should not apply to these types of emissions.

Additional information regarding control requirements imposed by the rule can be found in Fulbright’s Client Alert.


EPA Proposes Permitting Guidance for Diesel Fuels Use in Hydraulic Fracturing

On May 4, 2012, the U.S. Environmental Protection Agency (“EPA”) published draft UIC Program permitting guidance for oil and gas hydraulic fracturing activities using diesel fuels.

The Energy Policy Act of 2005 exempted hydraulic fracturing operations from requirements to obtain an underground injection control (“UIC”) permit under the federal Safe Drinking Water Act ("SDWA"), except when diesel fuels are used as a fracturing fluid. However, the Act did not define the term “diesel fuels.”

The proposed guidance attempts to provide clarity for EPA permit writers issuing UIC permits under the SDWA.

Environmental groups had lobbied for EPA to broadly define the term “diesel fuels” to include any material containing benzene, toluene, ethylbenzene, and xylene compounds (“BTEX”).

Industry advocated for a narrower, more traditional definition of diesel fuels. In the proposed guidance, EPA has adopted an approach based on the Chemical Abstract Service Registry Numbers (“CASRNs”) for diesel fuels.

In determining whether a hydraulic fracturing activity requires a UIC permit, EPA permit writers are to determine whether the injection fluid has any of the following six CASRNs:

  • 68334-30-5 Primary Name: Fuels, diesel Common Synonyms: Automotive diesel oil; Diesel fuel; Diesel oil (petroleum); Diesel oils; Diesel test fuel; Diesel fuels; Diesel Fuel No. 1; Diesel fuel [NA199311]; Diesel fuel oil; EINECS12 269-822-7
  • 68476-34-6 Primary Name: Fuels, diesel, no. 2 Common Synonyms: Diesel Fuel No. 2; Diesel fuels no. 2; EINECS 270-676-1, No. 2 Diesel Fuel
  • 68476-30-2 Primary Name: Fuel oil No. 2 Common Synonyms: Diesel fuel; Gas oil or diesel fuel or heating oil, light [UN1202] #2 Home heating oils; API No. 2 fuel oil; EINECS 270-671-4; Fuel Oil No. 2; Home heating oil No. 2; Number 2 burner fuel; Distillate fuel oils, light; Fuel No. 2; Fuel oil (No. 1,2,4,5 or 6) [NA1993];
  • 68476-31-3 Primary Name: Fuel oil, no. 4 Common Synonyms: Caswell No.13 333AB; Cat cracker feed stock; EINECS 270-673-5; EPA Pesticide Chemical Code 063514; Fuel oil no. 4; Diesel Fuel No. 4
  • 8008-20-6 Primary Name: Kerosene Common Synonyms: JP-5 navy fuel/marine diesel fuel; Deodorized kerosene; JP5 Jet fuel; AF 100 (pesticide); Caswell No. 517; EINECS 232-366-4; EPA Pesticide Chemical Code 063501; Fuel oil No. 1; Fuels, kerosine; Shell 140; Shellsol 2046; Distillate fuel oils, light; Kerosene, straight run; Kerosine, (petroleum); Several others
  • 68410-00-4 Primary Name: Distillates (petroleum), crude oil, Common Synonyms: Fuel, diesel (VDF) (EPA SRS14), Straight PWN diesel (EPA SRS), Aruba gas oil; EINECS 270-072-8 
The proposed guidance will be subject to public notice and comment.

The prepublication Federal Register notice has been posted on EPA’s website. Notice of the draft guidance was published in the Federal Register on May 10, 2012. The comment period ends on July 9, 2012.

This article was prepared by Heather M. Corken (hcorken@fulbright.com or 713 651 8386) and Kristen Roche (kroche@fulbright.com or 713 651 5303) from Fulbright's Environmental Law Practice.

DOI Releases Long-Awaited Proposed Rules on Hydraulic Fracturing on BLM and Indian Lands

On May 4, 2012, the Department of Interior released long-awaited proposed rules concerning hydraulic fracturing on Bureau of Land Management and Indian lands.

These proposed rules stems from a forum in November 2010 covering hydraulic fracturing on federal and Indian lands, followed by several meeting with interested stakeholders.

The draft rules were leaked to the media in February 2012, which is discussed in Fulbright’s Client Briefing, Department of Interior Releases Draft Rule of Well Stimulation.

Recently, President Obama issued an Executive Order calling for safe and responsible development of unconventional domestic natural gas resources, which created an interagency task force comprised of 13 agencies and offices, including, but not limited to:
The goal of the task force is to coordinate agency policy, share scientific, environmental, and related technical and economic information, and engage in long-term planning to ensure coordination amongst the agencies.

The DOI has indicated that these proposed rules received feedback from these agencies.

Oil and gas operators will be required to disclose chemicals in hydraulic fracturing operations, but this disclosure of chemicals only needs to be provided after drilling has begun. 

Previously, the draft rules required that the disclosure of chemicals occur before any proposed stimulation of the well. Additionally, the goal of the proposed rules are to improve assurances of well-bore integrity and ensure that a water management plan is in place for handling flow back fracturing fluids.

Fulbright's Shale and Hydraulic's Task Force is preparing a more detailed Client Alert concerning the revisions from the draft rules and the proposed impact to oil and gas operators.

DOI Resources


Hydraulic Fracturing as a Subsurface Trespass, Part 5 in a Series of 5

This article is the final post in a series of five posts.

Hydraulic fracturing activities continue to rise, and are at the center of much debate and litigation focusing on the potential health risks associated with the process. But an emerging issue with fracturing activities, and one that only the Texas courts has addressed with any significance, is whether hydraulic fracturing activities can, or should, lead to actionable subsurface trespass claims.

The Texas Supreme Court has decided a handful of cases dealing with subsurface trespass claims over the years, but only one of those cases, Coastal Oil v. Garza, 268 S.W.3d 1 (Tex. 2006), presents subsurface trespass as it relates specifically to hydraulic fracturing.

However, the Texas Supreme Court’s opinions in the other subsurface trespass cases provide valuable insight to the competing interests involved in the issue, and help to inform the Garza decision.


Conclusion 

Outside of Texas, where hydraulic fracturing activities are not as prevalent and courts have yet to consider how these activities relate to claims of subsurface trespass, courts can look to the Texas Supreme Court’s opinions for guidance. 

As the Garza Court’s internal debate illustrates, the impact of hydraulic fracturing and its importance to states’ economies are sure to be considered by future courts in considering whether to impose liability on fracturing activities, especially in absence of actual damages.   


Prepared by Fulbright Fracking Blog Contributing Editor and energy partner Barclay Nicholson and Fulbright energy attorney Brian Albrecht.

Hydraulic Fracturing as a Subsurface Trespass, Part 4 in a Series of 5

This article is the fourth in a series of five posts.

Hydraulic fracturing activities continue to rise, and are at the center of much debate and litigation focusing on the potential health risks associated with the process. But an emerging issue with fracturing activities, and one that only the Texas courts has addressed with any significance, is whether hydraulic fracturing activities can, or should, lead to actionable subsurface trespass claims.

The Texas Supreme Court has decided a handful of cases dealing with subsurface trespass claims over the years, but only one of those cases, Coastal Oil v. Garza, 268 S.W.3d 1 (Tex. 2006), presents subsurface trespass as it relates specifically to hydraulic fracturing.

However, the Texas Supreme Court’s opinions in the other subsurface trespass cases provide valuable insight to the competing interests involved in the issue, and help to inform the Garza decision.

Lessons from the Texas Supreme Court


In reviewing the Garza majority opinion, concurrence, and dissent, the Court’s concerns with the realities of hydraulic fracturing is evident. The majority opinion referred to numerous amicus curiae briefs filed by the RRC and various organizations and companies “from every corner of the industry,” and noted that all opposed liability for hydraulic fracturing, “almost always warning of adverse consequences in the direst of language.” Garza, 268 S.W.3d at 16-17.

Justice Willett’s concurrence refers to oil and gas as the “muscle” of Texas, id..at 27, and that imposing liability on fracturing activities would result in “exorbitant costs on society.” Id. at 30. And the dissent, while it argued for a finding of liability, proposed that courts should weigh the claim and the interests involved and allow such equitable considerations to influence the assessment of damages.

Additionally, the dissent was influenced by a practical concern for the rights of unsophisticated individuals who own small parcels of land and are unlikely to utilize such remedies as self help and pooling; the majority’s opinion reduces incentives for operators to lease from such property owners.

The Court similarly deferred to the importance of hydraulic fracturing in its Manziel opinion over forty years earlier. Clearly the impact of hydraulic fracturing activities is at the front of the Texas Supreme Court’s mind.

And reviewing Manziel, Garza, and FPL together provides further valuable insights, specifically as to when a subsurface invasion based on hydraulic fracturing activities can constitute an actionable trespass.

First, the Court has suggested that a subsurface invasion resulting in actual damages could constitute an actionable trespass; the Garza court noted that the plaintiff did not “claim that the hydraulic fracturing operation damaged his wells or the Vicksburg T formation beneath his property,” damages which would apparently be recoverable. Garza, 268 S.W.3d at 13.

Additionally, comparing the Manziel and FPL decisions provides evidence that actual damages could lead to an actionable trespass. Manziel declared that it is not a trespass when injected, secondary recovery forces move across leased lines if the RRC authorized the project, while FPL declared that the court of appeals was in error in determining that because the TCEQ permitted the injection wells, there was no trespass. 

While these are seemingly contradictory, the Manziel decision only authorized movement across leased lines of secondary injected forces, as opposed to authorizing any injurious movement of the forces.

Additionally, the Manziel court explicitly stated that it was not granting injecting operators a “protective cloak,” and the FPL ruling held that a permit does not preclude all liability for trespass. In both decisions, the Court seems to have left the door open for an actor to be found liable for subsurface trespass when actual damages result. 

Second, the Court has suggested that an actionable trespass may be based only on nominal damages if the plaintiff retains a possessory interest in the mineral rights. In FPL, the Court characterized its Garza opinion as holding that the plaintiff could not sue for trespass based on nominal damages because he was not in possession of the mineral rights.

The FPL court pointed to language in Garza stating that a trespass against a possessory interest “does not require actual injury to be actionable and may result in an award of nominal damages.” Garza, 268 S.W.3d at 13 n.36.

This article will be continued tomorrow.

Prepared by Fulbright Fracking Blog Contributing Editor and energy partner Barclay Nicholson and Fulbright energy attorney Brian Albrecht.

Hydraulic Fracturing as a Subsurface Trespass, Part 3 in a Series of 5

This article is the third in a series of five posts.

Hydraulic fracturing activities continue to rise, and are at the center of much debate and litigation focusing on the potential health risks associated with the process. But an emerging issue with fracturing activities, and one that only the Texas courts has addressed with any significance, is whether hydraulic fracturing activities can, or should, lead to actionable subsurface trespass claims.

The Texas Supreme Court has decided a handful of cases dealing with subsurface trespass claims over the years, but only one of those cases, Coastal Oil v. Garza, 268 S.W.3d 1 (Tex. 2006), presents subsurface trespass as it relates specifically to hydraulic fracturing.

However, the Texas Supreme Court’s opinions in the other subsurface trespass cases provide valuable insight to the competing interests involved in the issue, and help to inform the Garza decision.

FPL
In the 2011 case FPL Farming Ltd. v. Envtl. Processing Sys., L.C., 351 S.W.3d 306 (Tex. 2011) decided by the Texas Supreme Court, FPL, which owned two tracts of land used for rice farming, sued EPS, which operated a wastewater injection well on land adjoining FPL’s tracts.

EPS had a permit from the Texas Commission on Environmental Quality to drill and operate its well. FPL alleged that the injected wastewater likely migrated onto its property and contaminated its water supply, and filed suit based on subsurface trespass.

FPL lost in a jury trial and appealed. 

The appellate court did not address the merits of the trespass claim, and instead relied heavily on Manziel in holding that FPL could not recover because the wells were authorized by EPS’s permit. 

But the Texas Supreme Court did not give the same deference to the permit, stating that “a permit is not a get-out-of-tort-free card.” Id. at 311. 

The Court made clear that it was not deciding “whether subsurface wastewater migration can constitute a trespass, or whether it did so in this case,” and reversed the court of appeals’ judgment and remanded. Id. at 315.

This article will be continued Monday.

Prepared by Fulbright Fracking Blog Contributing Editor and energy partner Barclay Nicholson and Fulbright energy attorney Brian Albrecht.

Hydraulic Fracturing as a Subsurface Trespass, Part 2 in a Series of 5

This article is the second in a series of  five posts.

Hydraulic fracturing activities continue to rise, and are at the center of much debate and litigation focusing on the potential health risks associated with the process. But an emerging issue with fracturing activities, and one that only the Texas courts has addressed with any significance, is whether hydraulic fracturing activities can, or should, lead to actionable subsurface trespass claims.

The Texas Supreme Court has decided a handful of cases dealing with subsurface trespass claims over the years, but only one of those cases, Coastal Oil v. Garza, 268 S.W.3d 1 (Tex. 2006), presents subsurface trespass as it relates specifically to hydraulic fracturing.

However, the Texas Supreme Court’s opinions in the other subsurface trespass cases provide valuable insight to the competing interests involved in the issue, and help to inform the Garza decision.

Garza

In 2006, the Texas Supreme Court decided Garza, in which the plaintiff leased the mineral rights in his land to Coastal Oil and Gas Corp. (Coastal).

Coastal owned the mineral estate in an adjacent tract, and engaged in hydraulic fracturing on both tracts.  The plaintiff filed a suit in trespass, claiming that Coastal’s fracturing activities invaded the reservoir below his tract and caused substantial drainage of gas.

However, the Texas Supreme Court avoided directly ruling on the issue of whether hydraulic fracturing activities could result in an actionable subsurface trespass claim.

Instead, the Court declined to decide that “broader issue” and stated that an actionable trespass claim requires an injury, and that the plaintiff’s only injury—the drainage of gas from his subsurface—was precluded by the rule of capture.

According to the Court, the rule of capture only gave the plaintiff the right to capture the gas beneath his tract, as opposed to ownership of the gas itself.  With no actual damages, there could be no trespass.

The concurring Garza opinion, authored by Justice Willett, went a step further, arguing that instead of it being no “actionable trespass” as the majority found, it was no trespass at all, and plaintiffs could instead bring such suits in negligence.

Willett “would end definitively any lingering flirtation of Texas law with equating hydraulic fracturing with trespass,” and “say categorically that a claim for ‘trespass-by-frac’ is nonexistent in either drainage or nondrainage cases.” Garza, 268 S.W.3d at 29.

Throughout his opinion, Willett cited the importance of oil and gas to economy and industry of Texas.

The Garza dissent took the position that, until the issue of whether the hydraulic fracturing activities amounted to a subsurface trespass was decided, Coastal’s fracturing into the plaintiff’s tract must be considered an illegal trespass.  And, as Coastal conceded, the rule of capture only applies to gas obtained legally; thus, the rule of capture should not preclude the plaintiff’s trespass claim.


This article will be continued Monday.

Prepared by Fulbright Fracking Blog Contributing Editor and energy partner Barclay Nicholson and Fulbright energy attorney Brian Albrecht.