EPA lowers its estimate of methane gas leaks during natural gas production

The U.S. Environmental Protection Agency (EPA) issued a new report relating to greenhouse gas emissions from natural gas production and hydraulic fracturing. This report dramatically lowers the EPA’s estimate of how much methane gas leaks during natural gas production. Methane is the main component of natural gas. According to the agency, tighter pollution controls resulted in an average annual decrease of 41.6 million metric tons of methane emissions from 1990 through 2010, or more than 850 million metric tons overall. That is a reduction of about 20% from previous estimates even though natural gas production has grown by nearly 40% since 1990 and remains the leading source of methane emissions in the U.S., at about 145 million metric tons in 2011. The EPA converts the methane emissions into their equivalent in carbon dioxide, following standard scientific practice.

Oil and gas representatives state that this report shows that emissions from hydraulic fracturing can be managed and that leaks can be controlled by fixes, such as gaskets, maintenance and monitoring, which allow for the production and sale of more natural gas. The EPA said that it was seeking more data and feedback on methane leaks and that the report may change in the future. The report, which is based on expert reviews and new data from several sources, including an oil and gas industry-funded report, has been criticized as not being based on independent field tests of actual emissions. Environmentalists believe that the EPA is wrong and that, regardless, the revisions do not change the bigger picture that damage from greenhouse gas emissions, including methane gas, needs to be limited.

The EPA’s report entitled “Inventory of U.S. Greenhouse Gas Emission and Sinks” has international implications because, in mid-April, the report was submitted to the United Nations Framework Convention on Climate Change.


This post was prepared by Barclay Nicholson (bnicholson@fulbright.com or 713 651 3662) from Fulbright's Energy Practice and Heather M. Corken (hcorken@fulbright.com or 713 651 8386) from Fulbright's Environmental Law Practice Group.

BLM faces new NEPA challenge for granting leases without evaluating fracking risks

Monterrey Formation
In our April 10th blog post, BLM Violated NEPA by Granting Leases without Evaluating Fracking Risks (Hyperlink), we reported on a recent federal court ruling that the Bureau of Land Management (BLM) violated the National Environmental Policy Act (NEPA) by leasing 2,700 acres of federal land in the Central California Monterrey Shale Formation for oil and gas extraction without assessing the risks posed by hydraulic fracturing. It was the first court decision to find a federal lease sale invalid on this basis.

The ruling cast into doubt another recent BLM auction in the central California as BLM allegedly conducted a similar review before proceeding with the auction. As expected, the Center for Biological Diversity and the Sierra Club moved to contest this auction.

On April 18th, the groups filed suit in the federal court (Case No. CV-13-1749, in the United States District Court for the Northern District of California, San Jose Division). As in the prior suit, the groups assert that a detailed environmental impact study (EIS) was needed to investigate how potential hydraulic fracturing could affect the local groundwater and endangered species living in the area. They allege that the BLM unreasonably and arbitrarily relied on an environmental assessment that only looked at the environmental impact of a single well on one acre of land, even though the lease covered almost 18,000 acres. It remains to be seen how BLM will approach this litigation in consideration of the outcome of the earlier challenge.

The recent legal challenges to the BLM auctions, however, complicate ongoing efforts to develop the Monterrey Shale Formation and secure access to its estimated 15.5 million barrels of recoverable petroleum.

View the Complaint

This post was prepared by Barclay Nicholson (bnicholson@fulbright.com or 713 651 3662) from Fulbright's Energy Practice and Ted Bosquez (tbosquez@fulbright.com or 724 416 0423) from Fulbright's Environmental Law Practice Group.

Scientists rebut study linking hydraulic fracturing and groundwater contamination

Last year, hydrologic geologist Tom Myers’ conclusion that hydraulic fracturing of deep shale gas wells can be expected to impact shallow groundwater aquifers in less than ten years received much publicity, especially among environmental groups who had funded the work. Myers' findings appeared in an article entitled, “Potential Contaminant Pathways from Hydraulically Fractured Shale to Aquifers,” which appeared in the November/December 2012 issue of Groundwater, the journal of the National Groundwater Association. In response, a group of scientists from the Pennsylvania Geological Survey and the Pennsylvania Council of Professional Geologists have published a rebuttal of Myers’ work.

These scientists found many deficiencies with Myers’ modeling simulation, including a lack of objectivity and a” lack of understanding how to develop a credible hydrogeological conceptual site model.” They questioned Myers’ conceptual site model as not comprising the following (1) an accurate representation of the study area’s geology; (2) how hydraulic fracturing can be expected to modify the shale reservoir’s natural fracture characteristics; and (3) proper insight into the hydrodynamic and pore conditions of the rocks through which the water and hydrocarbons flow. As a result of their findings, the scientists have determined that Myers’ is fatally flawed with misinformation. Some examples include:

  • The geology overlying the Marcellus Shale formation is an alternating series of sandstones, siltstones, shales, and carbonate rocks that vary in thickness, extent, and rock physical properties depending on location. Myers incorrectly based his model on “predominantly sandstone” overlying the formation. 
  • Fracture orientations in rock vary with both depth and lithography and cannot be presumed to be vertical throughout an entire sequence of sedimentary rock. Unsupported by empirical data, Myers assumed a continuous 19.7 ft. wide, vertical, high-permeability fault extending from the Marcellus Shale formation at depth to ground surface.
  • Myers’ assumption of continuous upward flow from the Marcellus Shale to shallow groundwater aquifers would require that the sedimentary sequence between the shale and the aquifers be completely saturated with water. Extensive oil and gas drilling and production as well as geological studies have demonstrated that the shale is highly under-saturated with water. “There is no evidence to suggest that upward fluid migration has been continually occurring in the Appalachian basin. In fact, were this an active process throughout geologic time, the fresh groundwater aquifers currently sourcing more than one million private water supplies in Pennsylvania alone would not be fresh – instead, they would be unpotable.”

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

Agencies to collaborate in natural gas drilling air impact research

On April 22, 2013, the Office of Fossil Energy’s National Energy Technology Laboratory (“NETL”) and the National Institute for Occupational Safety and Health (“NIOSH”) entered into a memorandum of understanding to “perform collaborative research related to airborne emissions and air quality at natural gas drilling sites.” The agencies will strive to improve scientific understanding of the pollutants by identifying and monitoring the potential impact of shale gas activities on air quality and greenhouse gas emissions.

NETL is a U.S. Department of Energy national laboratory. Thus, NIOSH joins the U.S. Department of Energy, Department of the Interior and the Environmental Protection Agency’s team of scientists. This Multi-Agency Collaboration on Unconventional Oil and Gas Research was created through an April 13, 2012 Executive Order.

This article was prepared by Kristen Hulbert (khulbert@fulbright.com or 713 651 5303) from Fulbright's Environmental Law Practice Group.

Florida House passes bill requiring disclosure of hydraulic fracturing fluids

In our April 16th blog post, Florida lawmaker proposes bills requiring disclosure of hydraulic fracturing fluids, we discussed two bills before the Florida House of Representatives requiring the disclosure of fluids used in hydraulic fracturing operations.

On April 24, 2013, one of the bills, H.B. 743, knowing as “the Fracturing Chemical Usage and Disclosure Act,” passed by a 92-19 vote. The bill requires owners and operators of wells on which hydraulic fracturing is performed to disclose the chemicals used to the Florida Department of Environmental Protection (“DEP”), which would then post them to FracFocus.org, a national chemistry registry website. The bill is largely preemptive, as Florida lacks major tight oil and gas plays that would require hydraulic fracturing. The bill has now been sent to the Florida Senate, where it was referred to the Senate’s Environmental Preservation and Conservation Committee.

The bill’s companion measure, H.B. 745, was temporarily postponed after it was criticized for contradicting many of the requirements in H.B. 743. The bill proposes to exempt trade secrets involving hydraulic fracturing from the public records requirements H.B. 743. No official reason was given for the postponement.

This article was prepared by Lauren Brogdon (lbrogdon@fulbright.com or 713 651 5375) from Fulbright’s Litigation Practice Group.

Pennsylvania Supreme Court upholds the continuing vitality of the 177 year old Dunham rule

The Pennsylvania Supreme Court has upheld the continuing vitality of the 177 year old Dunham rule in Pennsylvania, reiterating that a rebuttable presumption arises in any private deed or land conveyance that natural gas is not a "mineral" unless it is expressly designated as such in the document. To rebut that presumption, the party seeking to have it so considered must present "clear and convincing evidence that the parties intended to include natural gas or oil within" the word minerals.

This decision reaffirming the Dunham rule was made in relation to a deed executed in 1881 which reserved to the grantor the subsurface and removal rights of "one-half [of] the minerals and Petroleum Oils" contained beneath the property. The Court applied the rule and determined that this reservation did not include natural gas, including that contained in Marcellus Shale, beneath the property. 

The Pennsylvania Supreme Court turned aside several challenges to the application of the rule, including an argument that the "trapped" nature of the gas in the Marcellus Shale converted it to a mineral. Additionally, the Court reiterated that any inquiry into the intent as to whether oil and gas would be considered a mineral, e.g., for attempting to rebut the presumption, "may only be shown through parol evidence that indicates the intent of the parties at the time the deed was executed." Moreover, the Supreme Court rejected that this intent can be shown through scientific evidence - "the common, layperson understanding of what is and is not a mineral is the only acceptable construction of a private deed." 

In its unwavering affirmation of the Dunham rule, the Pennsylvania Supreme Court found no "compelling reasons of public policy or the imperative demands of justice" to overrule or limit the Dunham rule "that has formed the bedrock for innumerable private, real property transactions for nearly two centuries."

View the Opinion
View the Concurring Opinion

This article was prepared by Jeremy Mercer (jmercer@fulbright.com or 724 416 0440) and Barclay Nicholson (bnicholson@fulbright.com or 713 651 3662) from Fulbright's Energy Practice Group.

Flowback fluid recycling regulation in the Marcellus Shale

This is the second article in a series of blog posts evaluating the current status of flowback and produced water recycling regulations in the major shale play states. These waters are generated through the hydraulic fracturing process, and this blog post continues the discussion of the manner in which these waters are disposed. The Marcellus Shale, the largest in the country by geographic area, extends throughout much of the Appalachian Basin, under Maryland, New York, Ohio, Pennsylvania, Virginia, and West Virginia. However, this post will focus on flowback and produced water recycling regulation in the most active hydraulic fracturing states, specifically, Ohio, Pennsylvania, and West Virginia. Recycling of flowback and produced waters is a growing trend in the Marcellus Shale, as off-site disposal facilities are not often available in close proximity to oil and gas wells.


Ohio’s Department of Natural Resources (“ODNR”) regulates the disposal of flowback and produced water from oil and gas drilling. ODNR also regulates the design and operation of lagoons/pits and tanks that are used at the drill site to temporarily store fluids that are either being recycled or collected. Long-term storage of these fluids in on-site pits is not authorized in Ohio. Ohio prohibits the discharge of any produced and flowback waters directly to waters of the state and also prohibits disposal of brine at any location other than an ODNR-permitted Class II injection well. However, the state strongly encourages recycling of flowback water.

Currently, Ohio’s regulations pertaining to the recycling of flowback and produced waters from hydraulic fracturing activity fall in the context of permitting the surface application of brine collected during the production of a well to roads, streets, highways, and other land surfaces owned or controlled by a county, township, or municipal corporation. Such application would be utilized to control surface dust or ice. However, flowback water and other fluids from well stimulation may not be applied to roadways or the land surface.


In April 2011, the Pennsylvania Department of Environmental Protection (“PADEP”) instructed 15 Publicly Owned Treatment Works (“POTWs”) to stop handling flowback fluids from the Marcellus Shale. At the time of the order, around two-thirds of flowback and produced waters were recycled in Pennsylvania.

The reuse of produced water is managed by the PADEP’s Residual Waste Division. This division has developed general permits for the beneficial use of residual waste, including WMGR123, a 2012 consolidation of General Permits WMGR119 and WMGR 121, that permits the processing, transfer and beneficial use of oil and gas liquid waste to develop or hydraulically fracture an oil or gas well. Oil and gas liquid waste is defined to include liquid wastes from the drilling, development and operation of oil and gas wells and includes contaminated water from well sites.

Pennsylvania also sets forth wastewater treatment requirements specifically for the handling of flowback and produced water from fracturing and other natural gas well operations. Under the requirements, well operators must develop a wastewater source reduction strategy and submit it to the PADEP upon request. Within the strategy, the operator must identify the methods and procedures that will be utilized to maximize the recycling and reuse of flowback and production fluids either to (1) fracture other natural gas wells or (2) for other beneficial uses approved under the regulations. According to a May 2012, NRDC study, the recycling of flowback and produced waters for use in additional hydraulic fracturing has increased by 10% between 2011 and 2012.

West Virginia

A recent study in West Virginia found that 81 percent of recovered flowback water was able to be recycled and re-used. A 2010 Memorandum of Agreement between the West Virginia Division of Highways and the West Virginia Department of Environmental Protection allowed for the beneficial use of natural gas well brines for roadway pre-wetting, anti-icing, and deicing. Such use is limited to natural gas well brines that fall within certain allowable levels.

West Virginia’s oil and gas regulations do set forth construction and maintenance requirements for flowback and produced water pits and freshwater impoundments. However, they do not contain any specific rules governing recycling of that water.

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

Florida lawmaker proposes bills requiring disclosure of hydraulic fracturing fluids

Currently pending before the Florida House of Representatives are two bills that would require the disclosure of various fluids used in hydraulic fracturing operations. H.B. 743, known as “the Fracturing Chemical Usage Disclosure Act,” requires owners and operators of wells on which hydraulic fracturing is performed to disclose the chemicals used to the Florida Department of Environmental Protection (“DEP”). The DEP will then post them to FracFocus.org, a national chemistry registry website. The bill’s companion measure, H.B. 745, would create an exemption from the public records requirement for trade secrets.

Representative Ray Rodrigues (R-Estero), who sponsored the bills, said they were modeled after similar laws in Texas. The Florida measure is largely a precautionary one, however, as the state lacks major tight oil and gas plays that would require hydraulic fracturing. In a March 28 legislative State Affairs Committee meeting, Rodrigues said, “[i]t [is] better to do this now, before we have fracturing than waiting until after fracturing actually occurs.”

This article was prepared by Lauren Brogdon (lbrogdon@fulbright.com or 713 651 5375) from Fulbright’s Litigation Practice Group.

Texas publishes new hydraulic fracturing fluid recycling rules

On April 12, 2013 the Texas Railroad Commission’s (“RRC”) hydraulic fracturing fluid recycling rules were published in the Texas Register. The new rules, adopted by the RRC on March 26, 2013, amend the state’s commercial recycling rules and are discussed in greater length in our prior blog post, Texas Adopts New Hydraulic Fracturing Fluid Recycling Rules.

This article was prepared by Kristen Hulbert (khulbert@fulbright.com or 713 651 5303) from Fulbright's Environmental Law Practice Group.

EPA has no current plans to use FIFRA to increase oversight of hydraulic fracturing

In March 2013, the Deputy Director of the Antimicrobials Division of the United States Environmental Protection Agency (EPA) stated the agency is not considering using its authority under the Federal Insecticide, Fungicide & Rodenticide Act (FIFRA) to regulate hydraulic fracturing beyond mandated registration responsibilities.

The statement represents an effort by EPA to respond to industry concerns the agency was evaluating the use of FIFRA to expand its oversight of hydraulic fracturing operations and initiate enforcement actions against operators. The concern is understandable as FIFRA, unlike the Clean Water Act and Safe Drinking Water Act, does not contain an exemption for oil and gas activities.

The recent actions of federal and state regulators have fed into this anxiety by emphasizing the role of FIFRA in the regulation of hydraulic fracturing. For example, in its most recent set of National Enforcement Initiatives, EPA highlighted FIFRA as a major component of the regulatory toolbox supporting its increased oversight of oil and gas operations.

In October 2012, members of the Association of American Pesticide Control Officers (AAPCO), an association of state pesticide regulators, publicly questioned whether the use of biocides in fracturing fluids constituted a violation of FIFRA. Montana even went so far as to urge its oil and gas industry to collaborate with the state agricultural department to develop state-specific registration and labeling requirements to shield operators from potential EPA enforcement actions.

In this environment, it is understandable oil and gas operators have grown uneasy about their potential liability under FIFRA. The inclusion of biocides in hydraulic fracturing fluids is a common practice among operators to control algal and microbial growth. The commonly used biocides (e.g., acrolein or dazomet) are classified as pesticides and therefore regulated under FIFRA.

EPA, however, sees no present need to change labeling provisions or otherwise expand its use of FIFRA to oversee extraction operations. It remains to be seen if this position will change as state regulators press for further evaluation of the adequacy of biocide labeling provisions and the need for special certification requirements for their use in hydraulic fracturing fluids.

The ultimate resolution of this issue may be influenced by EPA’s Study of Hydraulic Fracturing and Its Potential Impact on Drinking Water Resources. The drinking water study plan includes an assessment of biocides utilized in hydraulic fracturing fluids. EPA anticipates the final results of this study will be released in 2014. The results could have a significant impact on the regulation of hydraulic fracturing in the United States, including the role of FIFRA.

This post was prepared by Heather Corken (hcorken@fulbright.com or 713 651 8386) and Ted Bosquez (tbosquez@fulbright.com or 724 416 0423) from Fulbright's Environmental Law Practice Group.

California air quality district adopts new notification and reporting requirements for hydraulic fracturing

In California, the South Coast Air Quality Management District (SCAQMD) has adopted comprehensive notification and reporting requirements to provide information needed to assess air quality and health effects from oil and gas drilling, including hydraulic fracturing, in the region. SCAQMD is the air pollution control agency for Orange County and major portions of Los Angeles, San Bernardino and Riverside counties.

Rule 1148.2 applies to any operator who is conducting oil or gas well drilling, well completion, well reworks, or well production stimulation and treatment activities, including acidizing, gravel packing, hydraulic fracturing, or any combination of treatments.

  • Notification of oil and gas drilling activities. No more than 10 days and no less than 24 hours prior to any of these activities, the operator must notify SCAQMD of the following: (a) the well identification and owner/operator information; (b) the location of the subject well and the nearest sensitive receptor (i.e., private homes, apartments, schools, or health care facilities) within 1,500 feet; and (c) the expected start date and identification of general activities to be conducted. This information will be posted on the SCAQMD website within 24 hours of receipt.
  • Emissions reporting. Within 60 days of completing any drilling activity, the operator must electronically report to SCAQMD the following: (a) the well identification and owner/operator information; (b) combustion equipment (>50 hp) used during the activities; (c) type and amount of dry materials used for well drilling, well completion, and well reworks (including the method of how the dry materials were mixed and any air pollution control techniques, devices, and/or practices used to control fugitive emissions or odors); and (d) the volume of well completion fluids used and volume of flowback fluid recovered (including any method(s) used for collecting, storing, conditioning, separating, and/or treating drilling fluids and/or flowback fluids as they return to the surface, any air pollution controls; and final disposition of recovered drilling fluids and flowback fluids).
  • Identification of chemicals by supplier
  • - For all non-trade secret chemicals, within 10 days of delivery, the chemical supplier must provide the operator with (a) the name and chemical abstract service number of each chemical ingredient; and (b) the purpose, amount, maximum concentration and identification if air toxic.
    - For all trade secret chemicals, within 10 days of delivery, the chemical supplier must provide the operator with (a) the identification of chemical information claimed to be a trade secret; and (b) the basis for the claim of trade secret, chemical family, and identification of whether a chemical family is an air toxic.
    - Within 60 days of delivery, for trade secret chemicals, the supplier must electronically notify SCAQMD of the following: (a) the operator, name and the API number of the well where the chemicals are to be used; (b) the name and chemical abstract service number of each chemical ingredient, purpose of chemical, amount, maximum concentration and identification if air toxic; and (c) basis for claim of trade secret, chemical family, and identification if ingredient within chemical family is an air toxic.
  • Chemical use reporting required from operator. Within 60 days of the last activity, the operator must electronically report to SCAQMD the following: (a) the operator, name, and the API number of the well where the chemicals were used; (b) for non-trade secret chemicals, the name and chemical abstract service number of each chemical ingredient, purpose of chemical, amount, maximum concentration and identification if air toxic; and (c) for trade secret chemicals, the identification of chemical information claimed to be a trade secret and the basis for the claim of trade secret, chemical family, and identification of whether a chemical family is an air toxic.
  • SCAQMD website posting of chemicals. For each event, the SCAQMD website will identify the operator name, well name and API number, location, and date of activity. For non-trade secret chemicals, the website will show the name and chemical abstract service number of each ingredient, purpose of chemical, amount, maximum concentration, and identification if an air toxic. For trade secret chemicals, the website will show the chemical family and identification of the ingredient if the ingredient within the chemical family is an air toxic. 
These rules were passed by the SCAQMD Board on April 5, 2013 and will go into effect in 60 days. Within six months of collecting the first emissions report, the Board will convene a working group to discuss the results of the emissions and chemical use data. Within two years, the SCAQMD staff must report on the status of the data collection and notification requirements to determine whether new or additional rules are needed.

This post was prepared by Barclay Nicholson (bnicholson@fulbright.com or 713 651 3662) from Fulbright's Energy Practice and  Heather Corken (hcorken@fulbright.com or 713 651 8386) from Fulbright's Environmental Law Practice Group.

BLM Violated NEPA by Granting Leases without Evaluating Fracking Risks

On March 31, 2013, United States Magistrate Judge Paul S. Grewal ruled that the Bureau of Land Management (BLM) violated the National Environmental Policy Act (NEPA) by leasing land for oil and gas extraction without assessing the risks posed by hydraulic fracturing.

In April 2011, the BLM decided to sell four oil and gas leases for approximately 2,700 acres of federal land in the Central California Monterey Shale Formation and issued a draft Environmental Assessment (EA). During the 36-day public comment period, the BLM received comments from citizens, agencies, and environmental groups, such as the Center for Biological Diversity and the Sierra Club, who expressed concerns about the oil and gas development. After receiving these comments, the BLM issued its final EA and, on June 16, 2011, a Finding of No Significant Impact (FONSI), meaning that “the proposed action would not result in any significant environmental impact requiring further analysis under NEPA.”

On December 8, 2011, the Center for Biological Diversity and the Sierra Club filed a lawsuit against the BLM, complaining that the final EA did not adequately and fully analyze the impacts of oil and gas development on the surrounding area and the effects of hydraulic fracturing in particular. The environmental groups asserted that a detailed environmental impact study (EIS) was needed in order to consider the endangered species living in the area (e.g., San Joaquin kit fox, blunt-nosed leopard lizard, steelhead trout, and the California condor), the “highly controversial and dangerous drilling method” of hydraulic fracturing, and the impacts of oil spills, habitant contamination, and methane leaks. The BLM countered that it was premature to evaluate the impacts at this stage, that the impacts must be evaluated in the site-specific assessments conducted in relation to applications for permits to drill.

Disagreeing with the BLM, Magistrate Judge Grewal stated that NEPA required federal agencies to conduct the impact review at the earliest possible time to allow for proper consideration of environmental values. The court found that the BLM unreasonably relied on an earlier single-well development scenario and failed to take into account all reasonably foreseeable effects of its actions in categorically refusing to consider the effects of hydraulic fracturing. According to the court, the BLM could not shirk its NEPA responsibilities by labeling discussion of hydraulic fracturing as a “crystal ball” inquiry. Therefore, Magistrate Judge Grewal ruled that the BLM failed to conduct the “hard look” analysis required by NEPA by dismissing any development scenario involving hydraulic fracturing when used in combination with technologies such as horizontal drilling. The court further found the EA and the FONSI to be erroneous as a matter of law.

The ruling may be a setback for oil and gas development in central California and could cast into doubt a recent and much larger lease sale of 18,000 acres in the same region, which the BLM reportedly approved in a similar fashion.

OMB Reviewing Proposal to Allow Flowback Water to be Shipped on Barges

In March 2013, the United States Coast Guard (“USCG”) submitted a proposal to the White House Office of Management and Budget (“OMB”) to allow the shipment of flowback and produced water from hydraulic fracturing operations on barges. The OMB is currently evaluating this proposal.

The proposal is the subject of significant interest as parties debate the merits of using barges to transport this material.

Flowback and produced water generated at the well that is not recycled or reused in fracturing operations must be transported off-site for disposal. Such transportation typically occurs via truck or train to treatment or disposal facilities capable of accepting the shipment. The transport of this material can be costly and significantly increase the number of trucks on the roads.

In Pennsylvania, the Pennsylvania Department of Environmental Protection (“DEP”) discourages publicly owned treatment works (“POTWs”) from accepting flowback and produced water, limiting disposal options in a state with a paucity of underground injection wells. As a result, this water typically is shipped to neighboring Ohio for disposal, a state with significantly higher disposal capacity.

Proponents of the USCG’s proposal argue that if barges are used to ship flowback and produced water on the Ohio River, the number of trucks on the roads would be significantly reduced. They further argue that the use of barges would improve public safety by reducing congestion on the roads and increase the cost-effectiveness of hydraulic fracturing by reducing disposal costs.

If the OMB approves the proposal, the USCG will move forward with formal rulemaking. The proposed rule will then be published in the Federal Register and subject to public comment.

This post was prepared by Heather Corken (hcorken@fulbright.com or 713 651 8386) and Ted Bosquez (tbosquez@fulbright.com or 724 416 0423) from Fulbright's Environmental Law Practice Group.

Pennsylvania regulations require oil & gas companies to provide information to emergency responders

On April 4, 2013, Pennsylvania’s Department of Environmental Protection (“DEP”) proposed new rules required by the passage of Act 9 of 2012, a bill approved by the state’s General Assembly in February.
Act 9 authorized the Pennsylvania Emergency Management Agency (“PEMA”) and DEP to adopt emergency regulations relating to oil and gas wells, in particular unconventional wells which are often located in remote areas, in order to ensure the safety of all employees and emergency responders during incidents at the well site. The proposed rules, which were filed with Pennsylvania’s Independent Regulatory Review Commission (“IRRC”), require oil and gas drillers to develop detailed plans for emergency responders in order to allow easier access to these wells, many of which use hydraulic fracturing, in the event of blowouts or other disasters.

The operators must:
  • Adopt a unique GPS coordinate address for each unconventional well at both the access road entrance and well site.
  • Register the address with PEMA, DEP, and the county emergency management organization.
  • Develop an emergency response plan and file the plan with PEMA, DEP, and the county. The plan must provide for equipment procedures, training and documentation necessary to respond to emergencies. The plan must include a summary of unique risks and hazards within a half-mile radius of the well (such as schools, playgrounds, streams or creeks). The plan must be updated annually.
  • Post a reflective sign at the entrance to each unconventional well site with the specific address and coordinates for the site, the emergency contact number, and other appropriate information.
The DEP estimates that for existing unconventional well sites the cost to the industry to provide the required signage may run between $250,000 and $1.1 million, depending on the material used to manufacture the sign ($150 per sign for fiberboard and $600 per sign for aluminum). The DEP worked with oil and gas industry representatives on these regulations and found that these rules were the least burdensome. According to the DEP, companies that use industry best management practices already have many of these requirements in place.

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

Spain Bans Hydraulic Fracturing in Cantabria Region

Earlier today, in an unanimous vote and supported by a strong social movement, lawmakers in Spain’s northern Cantabria region voted to ban hydraulic fracturing on environmental concerns about risks to drinking water. A coalition of Spain’s three parties led by the majority ruling People’s Party joined forces to pass the ban. While the People’s Party in Cantabria favors the complete ban of hydraulic fracturing in the region, due to local citizens’ concerns, on the national level this party supports hydraulic fracturing, believing that the development of shale gas would transform Spain’s economy at a time when the country is struggling with a burgeoning debt, a deep rescission, and high unemployment. Spain also imports 76% of its energy needs The People’s Party could seek to appeal or overturn Cantabria’s ban at the Spanish Parliament level. Early estimates indicate that Spain has large shale gas reserves (1.4 trillion cubic meters), enough to cover the demand from the European Union for about three years.

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

West Virginia court to consider rights of surface owner

A key issue in the case of Richard L. Cain v. XTO Energy Inc. and Waco Oil & Gas Co. Inc., No. 1:11-cv-00111, (N.D. W. Va., July 22, 2011), is whether a severance deed gives natural gas companies the right to drill horizontal wells on a landowner’s property in order to extract oil and gas from a shared pool of oil and gas estates. Because the resolution of this question could have far-reaching legal and economic implications for West Virginia’s oil and gas industry and because there is no clear controlling West Virginia precedent, on March 28, 2013, the federal judge hearing the case has certified this question to the West Virginia Supreme Court of Appeals.

View a copy of the Order.

Richard L. Cain filed his lawsuit to block XTO Energy, Inc. and Waco Oil & Gas Co. Inc. from putting horizontal wells on his property to access and develop nearby shale resources that do not lie beneath his land. Cain concedes that XTO is entitled to the oil and gas beneath his property by way of a 1907 severance deed, but argues that XTO’s activities are beyond those in usage and custom of the natural gas industry at the time of the 1907 deed. He also claims that the planned horizontal wells would take up the “best” of his surface land, leaving him with steep hillsides and that he would not be sufficiently compensated for the burden of the wells being on his land rather than on the land of the residents living above the neighboring mineral deposits. Cain had sought to certify additional questions relating to damages to the West Virginia Supreme Court of Appeals, but the federal judge found that these damages questions were not yet ripe for disposition.

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

Texas legislature considers fee on disposal of fracking wastewater and name change for Railroad Commission of Texas

Proposed H.B. 379 would require oil & gas companies to pay a 1 cent per barrel fee on all hydraulic fracturing wastewater that is disposed of by injection into commercial wells. The legislators proposing this bill urged the House Energy Resources Committee to consider the increased revenues that would be generated by the fee and the incentive this would give to companies to recycle their wastewater. According to State Representative Lon Burnham of Fort Worth, in 2010, approximately 290 million barrels of waste were injected each month into commercial disposal wells. The 1 cent per barrel fee would have generated approximately $34.8 million in additional annual revenue for the state. The fees would be collected by the State Comptroller and all monies would be applied to the Railroad Commission of Texas’ oilfield cleanup fund. Currently the oilfield cleanup fund is statutorily capped at $20 million. Proposed H.B. 2166 would eliminate this cap.

View proposed H.B. 379

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

Pennsylvania Environmental Agency releases sampling and quality assurance plans for hydraulic fracturing radiation study

In our February 4th blog post, Pennsylvania, New York, and Texas Address Radioactivity Associated with Hydraulic Fracturing Operations, we discussed the Pennsylvania Department of Environmental Protection’s (“DEP”) comprehensive radiation study of oil and gas development. On April 3, 2013, the DEP released additional details regarding the study, including sampling and quality assurance plans.

The DEP’s released updated scope of work for the study proposes to focus the study on quantifying technologically enhanced radioactive materials in ambient air, drill cuttings (vertical and horizontal), natural gas, natural gas processing pipes and equipment, waste water generated on drilling sties, sludge resulting from the processing of waste water from the well pad development process, and landfill leachate.

The field sampling plan explains the types of samples that the DEP will collect, as well as their locations and methods of analysis. The quality assurance plan details how the agency will collect, transport, and analyze the samples.

The plans go on to show exactly how the DEP is conducting its study of (1) the transportation, storage, and disposal of drilling wastes, and (2) the radioactivity levels in flowback waters, treatment solids, drill cuttings, and drilling equipment. After Pennsylvania Governor Corbett directed the DEP to undertake the study in January, the DEP sought peer review of the sampling and quality assurance plans and expects sampling to begin sometime this month.

The site surveys checklist also provided by the DEP includes the estimated number of facilities tested, as well as the estimated total number of samples, solids, and liquids for the study. In conjunction with this study, the DEP will continue to maintain its statewide monitoring network that protects the public from exposure to radiation at unsafe levels.

This post was prepared by Kristen Hulbert (khulbert@fulbright.com or 713 651 5303) from Fulbright's Environmental Law Practice Group.

Wyoming Court finds fracking formula protected by Trade Secret Law

In the case of Powder River Basin Resource Council, et al. v. Wyoming Oil and Gas Conservation Commission and Halliburton Energy Services, Inc., in the Seventh Judicial District Court, County of Natrona, State of Wyoming, Civil Action No. 94650-C, four environmental plaintiffs challenged the trade secret exemption of the Wyoming Oil and Gas Conservation Commission’s hydraulic fracturing fluid disclosure rules. The plaintiffs asserted that the Commission had unlawfully withheld the identification of hydraulic fracturing chemicals used by various oil and gas producers, including Baker Hughes, BJ Services Company, CESI Chemical, Champion Technologies, Core Laboratories, Halliburton Energy Services, Inc., NALCO Company, SNF, Inc., and Weatherford International. They complained that the oil and gas producers did not provide sufficient factual support to uphold their claim of trade secret and want all the chemicals publicly disclosed. Halliburton Energy Services, Inc., who intervened in this litigation, warned that uncovering the hydraulic fracturing formula could hamstring project development efforts in the state.

On March 21, 2013, the Court ruled that the Commissioner “acted reasonably when he established a policy for evaluating trade secret requests and that policy is in accordance with the Wyoming Public Records Act” and that the plaintiffs failed to demonstrate that the Commissioner’s “decisions to grant trade secret protection requests were arbitrary, capricious, or not in accordance with the law.” The Commission’s decision to withhold the hydraulic fracturing formula information was upheld by the Court. In its conclusion, the Court expressed its awareness of the “important issues of public policy” implicated in the parties’ positions. The plaintiffs’ position that the “identity of hydraulic fracturing chemicals is key to understanding the potential environmental and health impacts of hydraulic fracturing” and the defendant’s position that hydraulic fracturing has a positive economic impact on Wyoming and that disclosure would adversely affect the industry have “substantial merit, however the Court feels these competing concerns are best addressed through legislative action, or further rule promulgation and are not properly within the Court’s purview.”

Wyoming’s hydraulic fracturing disclosure rules require owners, operators or service companies to disclose to the Commission the chemical additives, compounds and concentrations or rates proposed to be mixed and injected. The required information includes additive type, compound name and Chemical Abstract Service (CAS) numbers, and proposed rate or concentration for each additive. The Commission retains discretion to request the formulary disclosure for the chemical compounds. However, this formulary information only needs to be disclosed to the Commission and confidentiality protection shall be provided for trade secrets. Before granting trade secret exemptions, the Commission requires the party seeking the exemption to submit details of the chemicals whose identities they want to withhold, along with a cover letter justifying their trade secret position. The Commission staff then reviews the chemical information and the justification to ensure compliance with the disclosure rule and the Wyoming Public Records Act. If there is compliance, the Commission withholds the information.

Read The Court’s Order

This post was prepared by Barclay Nicholson (bnicholson@fulbright.com or 713 651 3662) fromFulbright's Energy Practice.

Texas adopts new hydraulic fracturing fluid recycling rules

In our March 11th blog post, Flowback Fluid Recycling Regulation in the Barnett and Eagle Ford Shale Plays, we discussed the Texas Railroad Commission’s (“RRC”) proposed hydraulic fracturing flowback fluid recycling rules. On March 26, 2013, the RRC adopted these proposed rules with amendments.

In February, 2012 the RRC distributed a draft of proposed amendments to its commercial recycling rules, since the current set of rules did not contemplate flowback fluid recycling. The RRC used feedback from informal comments and a workshop to release the proposed rules on September 28, 2012.

The proposed rules’ official comment period ended on October 29, 2012, and the rules were considered and voted on at the RRC hearing on March 26th. During the comment period, the RRC received 10 comments, one from the Texas Parks and Wildlife, four from groups or associations, and five from companies.

The RRC’s original rules contemplated only two categories of commercial recycling facilities: mobile and stationary facilities. An increasing number of applications, however, were for facilities that did not fall into either category. As such, the adopted rules establish five categories of permitted commercial recycling activity:

  • On-lease Commercial Solid Oil and Gas Waste Recycling 
  • Off-lease or Centralized Commercial Solid Oil and Gas Waste Recycling 
  • Stationary Commercial Solid Oil and Gas Waste Recycling 
  • Off-lease Commercial Recycling of Fluid; and 
  • Stationary Commercial Recycling of Fluid

One of the biggest changes between the proposed and adopted rules relates to flowback fluid recycling without a permit. First, the RRC decided to use the broader term “fluids”, as it relates to recycling, instead of the narrower term “produced water and/or hydraulic fracturing flowback fluid” found in the proposed rule.

Relatedly, under the proposed rules, non-commercial on-lease produced water and/or hydraulic fracturing flowback fluid recycling could be conducted without a permit if the fluids were either (1) recycled for use as hydraulic fracturing fluid or other oilfield fluid to be used in the wellbore of an oil, gas, geothermal, or service well; or (2) treated to national drinking water standards under the federal Safe Drinking Water Act. Stating that federal drinking water standards alone do not fully address all potential risks form treated fluids, the RRC revised these provisions to create a tiered approach to the reuse of treated fluids.

Under this tiered approach, treated fluids reused in the wellbore of an oil, gas, geothermal, or service well are authorized by the RRC, and no further individual permit is needed. With the exception of discharges to waters of the state that require an individual permit by statute, non-wellbore uses of treated fluids are also authorized, so long as the reuse occurs pursuant to a permit issued by another state or federal agency. If fluid treatment results in distilled water, any reuse, other than discharge to waters of the state, is authorized. Other reuses will be considered and permitted on a case-by-case basis based on the volume and source of the fluids, the anticipated constituents of concern, and the proposed reuse of the treated fluid.

The adopted rules also established specific standards for the construction and operation of recycling pits that hold produced water and/or flowback fluid. The adopted rules have not yet been published in the Texas Register.

This article was prepared by Kristen Hulbert (khulbert@fulbright.com or 713 651 5303) from Fulbright's Environmental Law Practice Group.

Center for Sustainable Shale Development created

On March 20, 2013, after more than two years of discussions, several energy companies (Shell, Chevron, CONSOL Energy, and EQT Corporation), environmental groups (Environmental Defense Fund, the Clean Air Task Force, Group Against Smog and Pollution (GASP), Citizens for Pennsylvania’ Future
(PennFuture), and Pennsylvania Environmental Council), and philanthropic foundations (Heinz Endowments and William Penn Foundation) collaborated to form the Center for Sustainable Shale Development (CSSD) in Pittsburgh. The CSSD will provide oil and gas producers with certification of performance standards for shale development. Fifteen initial performance standards have been established to ensure safe and environmentally responsible development of the Appalachian Basin’s shale gas resources. These standards, which limit flaring, encourage maximum water recycling, and reduce the toxicity of fracking fluid, are the foundation for CSSD’s independent, third-party certification process.

Water Performance Standards include:
  • Operators shall maintain zero discharge of wastewater into the waters of Pennsylvania and surrounding states. 
  • Operators shall maintain a plan to recycle flowback and produced water, for usage in drilling or fracturing a well, to the maximum extent possible. Within two years of implementing these standards, operators must recycle a minimum of 90% of the flowback and produced water by volume. 
  • Within one year, operators must contain drilling fluid and flowback water in a closed loop system at the well pad, eliminating the use of pits for all wells. 
  • Operators must conduct a comprehensive characterization of subsurface geology that demonstrates the presence of an adequate confining layer(s) above the production zone that will prevent adverse migration of hydraulic fracturing fluids. 
  • Operators must develop and implement a plan for monitoring existing water sources. 
  • Operators shall design and install casing and cement to completely isolate the well and all drilling and produced fluids from surface waters and aquifers. Operators shall not use diesel fluid in their hydraulic fracturing fluids.
  • Operators will publically disclose the chemical constituents intentionally used in well stimulation fluids. If a chemical ingredient is entitled to trade secret protection, the operator shall note in its disclosure the trade secret protection and will disclose the relevant chemical family name. 
  • Operators shall design each well pad to minimize the risk that drilling related fluids and wastes come in contact with surface waters and fresh groundwater.
Air Performance Standards include:
  • Beginning on January 1, 2014, an Operators must direct all pipeline-quality gas during well completion of development wells and re-completion or workover of any well into a pipeline for sales. 
  • Operators must adhere to strict requirements relating to flares and flaring. 
  • CSSD encourages and supports the conversion of diesel drilling rig engines and diesel fracturing pump engines to either dual-fuel, electricity or natural gas. 
Review a complete set of the standards

This post was prepared by Barclay Nicholson (bnicholson@fulbright.com or 713 651 3662) fromFulbright's Energy Practice.

Town of Avon’s fracking moratorium stands

In the summer of 2012, the town of Avon, New York passed Local Law T-A-5-2012 entitled “Moratorium on and Prohibition of Gas and Petroleum Exploration and Extraction Activities Underground Storage of Natural Gas and Disposal of Natural Gas or Petroleum Extraction Exploration and Production Wastes.” The one-year moratorium on natural gas extraction and underground storage began in in June 2012 and includes a “grandfather clause” for existing wells. Lenape Resources, Inc. (“Lenape”) who operates 16 to 20 wells in the Avon area on about 5,000 acres, filed a lawsuit seeking to overturn the moratorium by asserting that the local law was preempted by state law, invalid, unreasonable, arbitrary, oppressive, and unconstitutional. Lenape requested an injunction to stop enforcement of the law and sought actual and compensatory damages of no less than $50 million.

On March 15, 2013, Judge Robert B. Wiggins of the State of New York, Supreme Court, County of Livingston, entered an order dismissing Lenape’s 10-count lawsuit. See Decision and Order/Judgment.

The Court determined that New York state court precedents have established that local bans based on zoning laws do not amount to attempts to regulate the oil and gas industry and therefore are not preempted by the state’s Oil, Gas and Solution Mining Law. This ruling follows recent decisions in other New York counties upholding a town’s home rule power to limit hydraulic fracturing. The moratoriums on fracking in the towns of Dryden and Middlefield are being appealed, with arguments scheduled for March 22, 2013.

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

Court determines that settlement agreement concerning drilling activities is public record

On March 20, 2013, Pennsylvania Court of Common Pleas Judge Debbie O’Dell-Seneca ordered that a settlement agreement entered in a case complaining of drilling activities be unsealed and made available to the public. The Court found that there is “a presumption of openness under the common-law rule of access to the courts” and there is “no business-entity right of privacy within the Constitution of the Commonwealth of Pennsylvania to prevent the operation of that rule.” View this 32-page Opinion and Order

On May 27, 2010, by Praecipe to Issue Writ of Summons, the Hallowich family initiated an action against several oil and gas companies and the Pennsylvania Department of Environmental Protection, alleging that the companies’ drilling activities interfered with their enjoyment of their property rights and violated the state’s environmental laws. They complained that their water was polluted by the wells, pipelines, processing operations and truck traffic that came into the rural area where they built their home. Before filing a complaint, the Hallowiches settled the dispute on July 11, 2011. With minor children involved, as required by state law, the Hallowiches filed a Petition for Approval of Settlement of Minors. A hearing was held on August 23, 2011, at which time the Court approved the settlement and the record was sealed. Immediately thereafter, two Pittsburgh newspapers sought to unseal the record. The newspapers’ initial petition to unseal the record was denied. On appeal, the Pennsylvania Supreme Court reversed and remanded the case. Back in the Court of Common Pleas of Washington County, briefs were filed and an evidentiary hearing held. The oil and gas companies argued that they had the right to negotiate a mutual confidentiality agreement under the privacy protections of the Commonwealth’s constitution. The Judge concluded that the companies’ privacy rights were trumped by the press and public’s right of access to the record. “Confidentiality runs only between defendants and the Hallowiches. Thus, the unsealing of this record leaves these obligations wholly intact, because the parties remain just as gagged from speaking of the terms and conditions of the settlement as they were prior to the unsealing.” A page from the unsealed settlement agreement shows that the Hallowiches were paid $750,000. See Secrecy Lifted in Fracking Case.

This post was prepared by Barclay Nicholson (bnicholson@fulbright.com or 713 651 3662) fromFulbright's Energy Practice.

Eagle Ford Shale Task Force Report, March 2013

On March 12, 2013, Texas Railroad Commissioner David Porter released the Eagle Ford Shale Task Force Report. The Task Force was formed in 2011 with a diverse group of 24-members who represent community leaders, local elected officials, water representatives, environmental groups, oil and gas producers, pipeline companies, oil service companies (including a hydraulic fracturing company, a trucking company, and a water resources management company), landowners, mineral owners, and royalty owners. Meeting ten times from July 2011 to November 2012, the group studied eight basic issues which are set out below, along with summaries of the findings.
  1. Workforce Development: In 2011, the Eagle Ford Shale supported 38,000 full-time jobs in 14 counties; and the average income for an oilfield job was $117,000, an 18% increase from 2010. However, there is currently an acute shortage of well-trained, experienced labor in the area. Research indicates that the demand for oil and gas skilled labor will continue to remain strong. During the exploration phase, the companies need occupations dealing with mineral leasing, site construction and management, drilling rig support, and material transport. In the production and processing phase, the companies require a workforce composed of business management and administrative support personnel, as well as the processing gas, oil and condensates occupations. Area residents must acquire technical skills and training. A number of colleges and community colleges in the area are offering oil and gas-related programs. Even some high schools are developing industry- related programs.
  2. Infrastructure – Roads, Pipelines, Housing: The increase in Eagle Ford Shale drilling and production is the source of remarkable economic benefits. At the same time, the increased activity has heightened infrastructure challenges for the region’s communities. Truck traffic and road quality, pipeline placement and safety, and a shortage of affordable housing are top concerns. Traffic has increased by 86% on the main roads in the Eagle Ford Shale area, causing deterioration of the road bed and bridges. In addition, vehicular accidents in the area are on the increase. Heavy traffic is expected to increase until additional pipelines are completed. Demand for pipelines outpaces the supply. Research indicates that almost 1,200 loaded trucks are required to bring one gas well into production; over 350 are required per year for maintenance of a gas well; and almost 1,000 are needed every five years to re-fracture a well. The construction of one, 20-inch crude oil pipeline running 50 miles would displace 1,250 tank truck trips per day.
  3. Water Quality and Quantity: Common concerns about hydraulic fracturing include: (a) potential stress on surface water and groundwater supplies, resulting from withdrawal of large volumes of water for use in oil and gas operations; (b) potential contamination of drinking water aquifers, as a result of faulty well construction or other activities; and (c) potential compromised water quality due to challenges of managing surface activities and disposing of contaminated wastewaters which contain chemicals, salts, metals, and other residues from oil and gas activities. Railroad Commission records do not include a single documented groundwater contamination case associated with hydraulic fracturing, a process that has been employed in Texas for more than 60 years. The Commission’s strict well construction rules provide for several levels of protection for usable quality groundwater. Dr. Darrell Brownlow, a hydrologist and environmental consultant who spoke at a Task Force meeting, stated that the estimated average water use for drilling and hydraulically fracturing a well in the Eagle Ford Shale is 4,875,000 gallons. He advised that the Carrizo-Wilcox Aquifer which lies one mile above the shale was crucial to the success of the play. He anticipated that future demands on water for hydraulic fracturing can be met since the water for future drilling usage would come from about a dozen aquifers.
  4. Railroad Commission Regulations: The Railroad Commission (RRC) has statutory authority to regulate Texas’ energy industry, with primary responsibility over the oil and gas industry, pipelines moving oil and gas, and pipeline safety. Due to the increased oil and gas exploration within the Eagle Ford Shale, the RRC has directed more resources toward oversight of field operations and the timely processing of permit applications. The RRC regulates the discharge of produced water into surface water in the state. With the increase of drilling, there has been an increase in waste haulers. The RRC has partnered with the Texas Department of Public Safety to monitor waste haulers to be sure that they are properly permitted and the amount of waste being transported is not above the amount specified in the permit. The RRC has proposed amendments concerning recycling of solid waste and water.
  5. Economic Benefits: Since 2008, the number of drilling permits issued for the Eagle Ford Shale have increased (2008, 26; 2009, 94; 2010, 1,010; 2011, 2,826; and 2012, 4,145). Capital investments continue to pour into the area. One economic analyst predicts that the total Eagle Ford Shale capital expenditure for 2013 will be approximately $28 billion. From 2010-2011, oil production reached 28 million barrels and gas production exceeded 271 billion cubic feet. In 2011, a 20-county area in the Eagle Ford Shale supported 47,000 full-time jobs, paid $3.1 billion in salaries and benefits to workers, generated $12.63 billion in gross regional product, produced $257 million in local government revenues, and paid $358 million in state revenues, including $120.4 million in severance taxes.
  6. Flaring and Air Emissions: The Commissioner introduced his Flaring Initiative, which includes ensuring that operators fully comply with current flaring and venting rules, amending the rules to correspond with the increased production from the shale plays, encouraging the use of efficient and environmentally protective flares, and studying a pilot program to use gas as a source of power for on-lease operations in lieu of flaring the gas.
  7. Health Care, Education, and Social Services: Community and social service organizations are feeling the effects of rapid growth and the need to adapt and change. The Eagle Ford Shale counties do not have enough healthcare providers to handle the increased population, needing approximately 3,850 physicians, registered nurses, dentists, and pharmacists. The educational system has experienced surges in the number of special needs students and in students with limited knowledge of English. Traditionally “property poor” school districts have become “property wealthy” districts, creating numerous budgeting challenges, including the possibility of returning an estimated $12 million to the state in the form of recapture. Several oil and gas companies provide funding and targeted programs (such as sponsoring Science Technology Engineering and Math education, establishing a local science club, hosting field tours for teachers, and funding Project SHARP (Strategic, Hands-On After-School Resources and Progress)) to help meet community needs.

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