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EPA Launches Comprehensive New Internet Tool That Gives Public “Quick and Easy Access” To Vast Nationwide Water Discharge Data

On January 26, 2012, EPA unveiled a new internet database, called the Discharge Monitoring Report (DMR) Pollutant Loading Tool, which for the first time in history makes available to the public detailed information about water discharges from facilities across the country.  In the words of EPA’s Carey Johnston from EPA’s Office of Compliance, EPA’s newest creation is “designed to identify who is discharging what, where, and how much.” 

The tool allows users to search the vast amount of DMR and Toxics Release Inventory data collected from facilities across the country. Users can mine this database with easily designed queries that allow one to search for specific discharge facilities, types of pollutant, discharge locations, and pollutant amounts.  For example, a search of selenium discharges in West Virginia quickly returned a list of 939 facilities that discharge that pollutant as well as a “Top Ten” list of the largest dischargers.  Many of the facilities listed have individual profiles with a Google Maps link so users can get a bird’s-eye view of the facility. Many of these individual profiles also contain the facility’s discharge permit limits, compliance history, and recent inspection and enforcement data. 

EPA intends this database to give “quick and easy access” to citizens and researchers as well as permit writers and regulatory agencies.  While this data can be downloaded, copies of the actual DMRs and NPDES permits cannot currently be viewed using the tool.  If states make this information available online, however, the tool provides a link to the state websites so users can access this information more readily. 

A few qualifiers regarding the data are worth noting.  Currently, the data stretches from 2007 to 2010.  Results for 2011 are expected to be uploaded in the coming months, but the agency has no plans to make data available from earlier years. The data will include all discharge monitoring reports (DMRs) from all major sources and all data generated by the Toxics Release Inventory program.  States are not required to provide EPA with information about non-major facilities, so the tool currently lacks much of this information. Since 2007, however, States have been increasingly willing to provide EPA with data on non-major facilities, and it is not hard to envision EPA’s database becoming significantly more expansive over time. 

Percentage of DMR Data for Non-Major Facilities Voluntarily Shared with EPA:
State:	Percent Shared in 2007	Percent Shared in 2010
West Virginia	20	65
Kentucky	59	90
Pennsylvania	1	100
Ohio	83	100
Colorado	77	95
Indiana	91	100
Virginia	0	100
Maryland	43	82

Acknowledging that the process of converting the data from handwritten DMRs into the digital realm is fraught with errors, the new tool has a process whereby anyone can bring errors to EPA’s attention.  Once an error report is generated, it is forwarded to the appropriate state or federal agency which will verify the accuracy of the data and notify the concerned party if the data is ultimately changed.  EPA has indicated that it hopes to update the database monthly with error corrections. 

In its current state, EPA’s new tool is a bit clunky and plagued by significant gaps in data.  As more data becomes available and the states continue to share more information with EPA regarding non-major facilities, however, this database will likely become an increasingly sophisticated tool used by citizens to challenge water discharge permits both at the permitting stage and in court. 

This article was authored by Aaron S. Heishman, Jackson Kelly PLLC. For more information on the author see here.

Sierra Club Seeks to Impose Conductivity and Sulfate Limits on Discharges from Kentucky Mines

The Sierra Club and Kentuckians for the Commonwealth have appealed an NPDES permit issued to a coal operator in Kentucky which could have industry-wide implications in that State.  The appeal raises two issues that should concern everyone in the coal business. 

Chronic vs. Acute Water-Quality Based Effluent Limits

The appeal claims that the permit should likely include water quality based limits for the chronic water quality criteria, but instead includes limits based only on the higher acute criteria.  The appeal says that chronic standards are based on 96 hours of exposure, and that a “reasonable potential” (to violate the standard) analysis must show that there will not be 96 hours or discharge before it can impose limits only to meet the acute standards. 

Conductivity, TDS and Sulfate Limits

The appeal claims that the permit should include limits for total dissolved solids (TDS), specific conductance (conductivity) and sulfate to prevent a violation of the narrative water quality standard.  This claim is apparently similar to one raised in a challenge in West Virginia to an NPDES permit in West Virginia. There, the Sierra Club relied on testimony from Margaret Palmer (U. Md.), Emily Bernhardt (Duke) and Ryan King (Baylor) to argue that there is a high degree of correlation between unacceptable benthic impacts and conductivity at levels as low as 277 μS/cm.  The in-stream limits that the Sierra Club seeks to impose through this process are generally considered unachievable by the mining industry without reverse osmosis—a technology not affordable to the surface mining industry.  

The West Virginia Environmental Quality Board originally ruled that the West Virginia Department of Environmental Protection (WVDEP) should impose effluent limits on conductivity, TDS and sulfate, but the case has been remanded to the Board by the Circuit Court of Kanawha County.  See http://eem.jacksonkelly.com/2011/12/wv-eqb-lifts-conductivity-stay-but-probably-provides-no-real-help-to-mine-operators.html. 

This article was authored by Robert G. McLusky, Jackson Kelly PLLC. For more information on the author see here.

West Virginia’s Agriculture Commissioner Criticizes EPA Enforcement Actions Against Poultry Farms

The Chesapeake Bay Total Maximum Daily Load (“TMDL”) is tasked with reducing pollution (specifically nitrogen, phosphorous, and sediment) in the Bay’s 64,000 square mile watershed.  EPA has described the project as the largest and most complex TMDL ever attempted. Last month, EPA notified four poultry farms in West Virginia’s eastern panhandle that they are concentrated animal feeding operations (“CAFO’s”) that must obtain NPDES permits. 

EPA officials had toured these farms and found man-made ditches leading from poultry houses and manure sheds to local waterways.  After a storm event, EPA claimed, these ditches would discharge pollutants, including nitrogen and phosphorus, into nearby waterways.  It does not appear from EPA’s press release that these operations were actually discharging pollutants at the time of the inspection, but were instead designed in such a way that EPA anticipated that they might discharge pollutants during future storms.  EPA conducted similar site visits in the summer of 2010 in Virginia’s Shenandoah Valley, resulting in administrative orders commanding two CAFO’s to cease discharges into local waterways. 

Commenting on its recent actions, EPA claimed that educating farmers about their responsibilities to reduce stormwater runoff under the CWA is necessary.  “Based on our experience, educating farmers on the requirements of the Clean Water Act goes a long way in helping them to protect and improve local water quality and increase compliance.”   

West Virginia’s Commissioner of Agriculture, Gus R. Douglass, released a statement on December 15, 2011 that characterized EPA’s recent enforcement actions in West Virginia as “unnecessary, misguided, and potentially outside of EPA’s authority.” Commissioner Douglass went on to say that “EPA is loosely using technicalities in the Clean Water Act – not evidence of pollution – to put these farms under a command and control regime. Simply having an arbitrary number of animals on a farm is no reason to have to get a NPDES permit.”
Douglass also took issue with EPA’s insistence that it is simply trying to educate farmers of their responsibilities under the CWA.  “If they were really trying to help farmers, they would find specific instances of farm pollution and provide funding to implement best management practices (BMPs) that alleviate those problems, rather than hiring an army of permit writers and inspectors.” 

As detailed in a previous article on this blog, the United States Court of Appeals for the Fifth Circuit recently ruled that EPA lacks authority under the CWA to order CAFO’s to apply for NPDES permits unless they are  actually observed discharging pollutants.  Current EPA policy requires CAFO’s that “propose to discharge” (i.e., are designed or operated in a way that EPA believes they will likely discharge pollutants at some indefinite point in the future) to obtain NPDES permits. 

This article was authored by Aaron S. Heishman, Jackson Kelly PLLC. For more information on the author see here.

Judge Allows Citizen Suits to Proceed in Federal Court Despite Parallel Enforcement Actions in State Court

On December 7, 2011, Judge Robert Chambers denied Defendants’ Motion to Dismiss and ruled that Clean Water Act (“CWA”) citizen suits against three subsidiaries of Patriot Coal Corporation (Apogee Coal Company, LLC, Catenary Coal Company, LLC, and Hobet Mining, LLC) could proceed in spite of ongoing enforcement actions by the West Virginia Department of Environmental Protection (“DEP”).  See OVEC v. Patriot Coal, Case 3:11-cv-00115.   Pursuant to the CWA, a citizen suit is precluded where the “State has commenced and is diligently prosecuting a civil or criminal action in a court of the United States, or a State to require compliance with the standard, limitation, or order [that the citizen alleges to have been violated].” 33 U.S.C. § 1365(b)(1)(B).  Although Judge Chambers found that DEP had commenced an action in West Virginia state court at the time the citizen suits were filed, he found that they lacked diligence. 

In addressing the actions against Catenary and Apogee, the Court referenced its decision from September of this year in Ohio Valley Envtl. Coal., Inc. v. Maple Coal Co., 2011 WL 3874576 (S.D.W. Va. 2011).  In Maple, the Court examined enforcement actions DEP brought against Maple Coal in Fayette County Circuit Court.  There, the Court noted that DEP would have granted Maple’s request to extend its selenium compliance deadline had EPA not objected to the modification.  Id. at 23.  According to the Court, DEP’s options to diligently prosecute an enforcement action against Maple consisted of either, (1) agreeing with EPA, acting as though the EQB stays had never been granted, and seeking to enforce the selenium limits from April 5, 2010 when they were scheduled to go into effect; or (2) disagreeing with EPA and requesting relief from the Fayette County court akin to that which DEP had initially planned to grant.  The Court characterized DEP’s enforcement action as failing to pursue either of these avenues.  Rather, according to the Court, DEP filed a vague complaint that sought neither to enforce the permit as is, inclusive of the selenium limits, nor to enforce the draft permit modification, with a compliance deadline of July 2012.  

In Patriot, the Court viewed DEP’s enforcement actions in Boone and Logan County against Catenary and Apogee in the same way: 

As in Maple, neither enforcement action appears to seek any enforcement whatsoever with regard selenium. Instead, as in Maple, both actions seek vague relief from the Logan and Boone County Circuit Courts that specifically excludes selenium from the request for immediate relief on the grounds that the selenium limitations are subject to the stay orders of the EQB and the Kanawha County Circuit Court. By acquiescing in the Stay Orders, excluding selenium from their claims for civil penalties on the basis of those Orders, and seeking in State Courts the delays already rejected by the Environmental Protection Agency, the WVDEP is not diligently prosecuting Defendants’ selenium violations. Based on their context, timing, and the relief sought, Court FINDS that these actions, like the one at issue in Maple, are not diligent prosecutions. 

OVEC v. Patriot, p. 12. 

Next, the Court addressed DEP’s Boone County enforcement action against Hobet for four NPDES permits at its mine in Boone County.  The Court had previously addressed the diligent prosecution issue as to the same four Hobet permits in  OVEC v. Hobet Mining, LLC, 3:08-cv-0088, 2008 WL 5377799 (“Hobet I”).  In Hobet I, although the Court found that the DEP’s prosecution was not diligent at the time the citizen suit was filed, it found that the September 5, 2008 consent decree entered by the Boone County Circuit Court mooted the citizen suit in federal court.  Id., at 4-5.  That consent decree, however, was modified by the parties in December 2009.  The Court addressed the impact of the modified consent decree on a separate NPDES permit in Ohio Valley Envtl Coalition v. Hobet Mining, LLC, 723 F. Supp. 2d 886 (S.D. W.Va. 2010) (“Hobet II”).  In Hobet II, the Court found that the amended consent decree was more lenient than the original and was, therefore, not a diligent prosecution.  Id., at 906-913.  In re-examining the modified consent decree in light of the four permits originally at issue in Hobet I and currently at issue in Patriot, the Court again found that the “regulatory climate for violations of selenium limitations is defined by continued extensions and enforcement actions that, rather than enforcing selenium limits, seek to accomplish in state courts the delays already rejected by the Environmental Protection Agency.”  Consequently, the Court ruled that DEP’s ongoing enforcement action against Hobet was not diligent. 

The decision in Patriot is yet another in a line of recent opinions demonstrating a willingness of West Virginia’s federal district courts to ignore DEP State Court enforcement actions in favor of allowing environmental groups to bring CWA citizen suits in federal court.  Any company entering into a consent decree with the State, who also has potential exposure to a citizen suit in federal court, should be aware of this trend. 

This article was authored by Chris M. Hunter, Jackson Kelly PLLC. For more information on the author see here.

Pesticide Use Near U.S. Waters Falls Within NPDES Permitting Program

There has long been a controversy over the obligation of pesticide and herbicide users to obtain NPDES permits under the Clean Water Act either for “residual” pesticides entering waterways by overspray or for their direct application to water environments to kill waterborne plants and pests.  In 2009, the Sixth Circuit Court of Appeals effectively ruled that these applications were subject to NPDES permitting requirements.  National Cotton Council of America v. EPA, 553 F. 3d 927 (6th Cir. 2009). There, the Court vacated a United States Environmental Protection Agency (USEPA) regulation that excluded discharges of biological pesticides that leave a residue from the application of pesticides to, or over, including near waters of the United States from the need to obtain an NPDES permit if the application was done in accordance with other laws.  The requirement to obtain a permit was stayed by the Court until October 31, 2011, at the request of USEPA, to allow USEPA time to develop a Pesticide General Permit.  As a result of this case, after October 31, 2011, NPDES permits are required for point source discharges of biological pesticides, and of chemical pesticides that leave a residue to waters of the United States. 

On November 7, 2011, USEPA issued its final NPDES Pesticide General Permit (PGP).  See Final National Pollutant Discharge Elimination System (NPDES) Pesticide General Permit for Point Source Discharges from the Application of Pesticides, 76 Fed. Reg. 68750 (Nov. 7, 2011).  The PGP is for point source discharges from the application of pesticides to waters of the United States and is available at http://www.epa.gov/npdes/pubs/final_pgp.pdf.  The PGP regulates discharges to waters from the application of (1) biological pesticides, and (2) chemical pesticides that leave a residue [Note: for purposes of this permit USEPA assumes that all chemical pesticides have a residue and, therefore, would need a permit unless it can be shown that there is no residual] for the following pesticide use patterns: 

a.         Mosquito and Other Flying Insect Pest Control—to control public health/nuisance and other flying insect pests that develop or are present during a portion of their life cycle in or above standing or flowing water. Public health/nuisance and other flying insect pests in this use category include mosquitoes and black flies.

b.         Weed and Algae Pest Control—to control weeds, algae, and pathogens that are pests in water and at water’s edge, including ditches and/or canals.

c.         Animal Pest Control—to control animal pests in water and at water’s edge. Animal pests in this use category include fish, lampreys, insects, mollusks, and pathogens.

d.         Forest Canopy Pest Control—application of a pesticide to a forest canopy to control the population of a pest species (e.g., insect or pathogen) where, to target the pests effectively, a portion of the pesticide unavoidably will be applied over and deposited to water. 

The permit requires: 

•           All permittees to minimize pesticide discharges through the use of pest management measures and monitor for and report any adverse incidents;

•           Some permittees that apply pesticides in excess of specified annual treatment thresholds are also required to submit Notice of Intents (NOIs) prior to beginning to discharge and implement integrated pest management (IPM)-like practices requiring annul reports and maintain detailed records; and

•           Certain smaller owners are required to complete a pesticide discharge evaluation worksheet for each pesticide application (in lieu of the more comprehensive PDMP), an annual report, and detailed recordkeeping. 

West Virginia has its own delegated NPDES program; thus the USEPA PGP is not directly applicable to West Virginia.  The WVDEP, though, issued its own PGP on October 31, 2011.  See, WV NPDES Permit No. WV0116645 http://www.jacksonkelly.com/jk/pdf/C2211227.pdf.  This permit is similar to the USEPA PGP in that it is available to operators who discharge to waters of the State from the application of (1) biological pesticides or (2) chemical pesticides that leave a residue (hereinafter collectively “pesticides”).  The West Virginia permit defines pesticide to include both pesticides and herbicides as follows: 

“Pesticide” means (1) any substance or mixture of substances intended for preventing, destroying, repelling, or mitigating any pest, (2) any substance or mixture of substances intended for use as a plant regulator, defoliant, or desiccant, and (3) any nitrogen stabilizer, except that the term ‘‘pesticide’’ shall not include any article that is a “new animal drug” within the meaning of section 201(w) of the Federal Food, Drug, and Cosmetic Act (21 STATE.C. 321(w)), that has been determined by the Secretary of Health and Human Services not to be a new animal drug by a regulation establishing conditions of use for the article, or that is an animal feed within the meaning of section 201(x) of such Act (21 STATE.C. 321(x)) bearing or containing a new animal drug. The term “pesticide” does not include liquid chemical sterilant products (including any sterilant or subordinate disinfectant claims on such products) for use on a critical or semi-critical device, as defined in section 201 of the Federal Food, Drug, and Cosmetic Act (21 STATE.C. 321). For purposes of the preceding sentence, the term “critical device” includes any device that introduced directly into the human body, either into or in contact with the bloodstream or normally sterile areas of the body and the term ‘‘semi-critical device’’ includes any device that contacts intact mucous membranes but which does not ordinarily penetrate the blood barrier or otherwise enter normally sterile areas of the body. [FIFRA Section 2(u)]

The term “pesticide” applies to insecticides, herbicides, fungicides, rodenticides, and various other substances used to control pests.  The definition encompasses all uses of pesticides authorized under FIFRA including uses authorized under sections 3 (registration), 5 (experimental use permits), 18 (emergency exemptions), 24(c) (special local needs registrations), and 25(b) (exemptions from FIFRA).   

Note: drugs used to control diseases of humans or animals (such as livestock and pets) are not considered pesticides; such drugs are regulated by the Food and Drug Administration.  Fertilizers, nutrients, and other substances used to promote plant survival and health are not considered plant growth regulators and thus are not pesticides.  Biological control agents, except for certain microorganisms, are exempted from regulation under FIFRA. (Biological control agents include beneficial predators such as birds or ladybugs that eat insect pests, parasitic wasps, fish, etc).

[T]his permit uses the term “pesticide” when referring to the “pesticide, as applied.”  When referring to the chemical in the pesticide product with pesticidal qualities, the permit uses the term “active ingredient.”  

The West Virginia permit is applicable when the pesticide application is for the same pesticide use patterns as described in the USEPA PGP, and requires certain operators to submit a Notice of Intent to obtain coverage under this general permit for discharges to waters of the State resulting from the application of pesticides: 

a.   If you are in control over the financing for, or over the decision to perform pest control activities that will result in a discharge and know or reasonably should have known that those activities will exceed one or more of the annual (i.e., calendar year) treatment area thresholds listed in Table 1 below for the “treatment area,” as defined in the definition.  

b.   If you apply pesticides that result in a discharge and know or reasonably should have known that those activities will exceed one or more of the pesticide application annual (i.e., calendar year) treatment area thresholds listed in Table 1 below for the “treatment area,” as defined in the definition.  To determine whether an entity’s activities will exceed one or more of the annual treatment area thresholds, the entity should exclude from its calculation any pesticide application activities conducted under another entity’s NOI required under (a) above. 

	Table 1. Annual Treatment Area Thresholds
PGP Part	Pesticide Use	Annual Threshold
2.2.1	Mosquitoes and Other Flying Insect Pests	6400 acres of treatment area
2.2.2	Aquatic Weed and Algae Control:
	-In Water	80 acres of treatment area1
	- At Water’s Edge:	20 linear miles of treatment area at water’s edge2
2.2.3	Animal Pest Control:
	-In Water	80 acres of treatment area1
	- At Water’s Edge	20 linear miles of treatment area at water’s edge2
2.2.4	Forest Canopy Pest Control	6400 acres of treatment area

¹ Calculations should include the area of the applications made to: (1) waters of the State and (2) conveyances with a hydrologic surface connection to waters of the State. at the time of pesticide application. For calculating annual treatment area totals, count each pesticide application activity as a separate activity.  For example, applying pesticides twice a year to a ten acre site should be counted as twenty acres of treatment area.  

² Calculations should include the linear extent of the application made at water’s edge adjacent to: (1) waters of the State and (2) conveyances with a hydrologic surface connection to waters of the State at the time of pesticide application.  For calculating annual treatment totals, count each pesticide application activity and each side of a linear water body as a separate activity or area.  For example, treating both sides of a ten mile ditch is equal to twenty miles of water treatment area. 

As a result, an NPDES permit must be obtained for point source discharges of biological pesticides, and of chemical pesticides that leave a residue to waters of the United States.  Pesticide users who fall under the notification thresholds are still required to hold a permit and can do so simply by meeting the other requirements of the general permit as set out above.to waters of the United States, whose discharges are under the threshold limits, are automatically covered under the general permit and are not required to send an NOI to the agency, they must meet the terms of the general permit.   

This article was authored by Laura G. Swingle, Jackson Kelly PLLC. For more information on the author see here.

EPA Contemplating Discharge Limits for Wastewater Treatment Plants That Accept Hydraulic Fracturing Flowback

On November 16, 2011, the House Transportation and Infrastructure Subcommittee held a hearing to discuss potential regulations for the hydraulic fracturing of shale beds.  Among those testifying was James Hanlon, Director of EPA’s Office of Wastewater Management. Mr. Hanlon’s full testimony can be found at http://transportation.house.gov/hearings/Testimony.aspx?TID=6899.   Mr. Hanlon made clear that EPA is considering establishing new discharge standards for wastewater treatment plants that accept fracturing flowback water due to concerns of the potentially high concentrations of salts, radionuclides, heavy metals, and other materials that are potentially harmful to human health and the environment. These regulations would be in addition to the pre-treatment standards EPA is currently developing for fracturing flowback water before it can be sent to wastewater treatment plants. 

Aware of the growth potential of the shale gas extraction in many parts of the country, Mr. Hanlon stated that “EPA believes the initiation of a rulemaking, including the data collection necessary to better understand environmental impacts and available treatment options in support of such a rule, is an appropriate step.”  Hanlon went on to state that EPA’s wastewater treatment rules can be expected by 2014.  

Many states have already begun to regulate, or in some cases ban, the disposal of fracturing flowback through sewage treatment plants.  Already there have been responses that this is a matter that should be left to the individual states to regulate. 

This article was authored by Aaron S. Heishman, Jackson Kelly PLLC. For more information on the author see here.

SEAB Shale Gas Production Subcommittee Reports

Following President Barack Obama’s declaration that “recent innovations have given us the opportunity to tap large reserves – perhaps a century’s worth” of shale gas on March 31, 2011, he instructed Secretary of Energy, Steven Chu, to form a subcommittee of the Secretary of Energy Advisor Board (SEAB) “to make recommendations to address the safety and environmental performance of shale gas production.”  SEAB Shale Gas Production Subcommittee – 90 Day Report (August 18, 2011).  In response to that charge, the SEAB Shale Gas Production Subcommittee has produced two 90 Day Reports, on August 18, 2011 and November 18, 2011.  These reports are available at http://www.shalegas.energy.gov/. 

The first 90 Day Report issued on August 18, 2011 “focused exclusively on production of natural gas (and some liquid hydrocarbons) from shale formations with hydraulic fracturing stimulation in either vertical or horizontal wells.”  SEAB Shale Gas Production Subcommittee – 90 Day Report (August 18, 2011).  

A list of the Subcommittee’s findings and recommendations follows.

1. Improve public information about shale gas operations: Create a portal for access to a wide range of public information on shale gas development, to include current data available from state and federal regulatory agencies. The portal should be open to the public for use to study and analyze shale gas operations and results. 
2. Improve communication among state and federal regulators: Provide continuing annual support to STRONGER (the State Review of Oil and Natural Gas Environmental Regulation) and to the Ground Water Protection Council for expansion of the Risk Based Data Management System and similar projects that can be extended to all phases of shale gas development. 
3. Improve air quality: Measures should be taken to reduce emissions of air pollutants, ozone precursors, and methane as quickly as practicable. The Subcommittee supports adoption of rigorous standards for new and existing sources of methane, air toxics, ozone precursors and other air pollutants from shale gas operations. The Subcommittee recommends:

(1) Enlisting a subset of producers in different basins to design and rapidly implement measurement systems to collect comprehensive methane and other air emissions data from shale gas operations and make these data publically available; (2) Immediately launching a federal interagency planning effort to acquire data and analyze the overall greenhouse gas footprint of shale gas operations throughout the lifecycle of natural gas use in comparison to other fuels; and (3) Encouraging shale-gas production companies and regulators to expand immediately efforts to reduce air emissions using proven technologies and practices. 

1. Protection of water quality: The Subcommittee urges adoption of a systems approach to water management based on consistent measurement and public disclosure of the flow and composition of water at every stage of the shale gas production process. The Subcommittee recommends the following actions by shale gas companies and regulators – to the extent that such actions have not already been undertaken by particular companies and regulatory agencies: (1) Measure and publicly report the composition of water stocks and flow throughout the fracturing and clean-up process. (2) Manifest all transfers of water among different locations. (3) Adopt best practices in well development and construction, especially casing, cementing, and pressure management. Pressure testing of cemented casing and state-of-the-art cement bond logs should be used to confirm formation isolation. Microseismic surveys should be carried out to assure that hydraulic fracture growth is limited to the gas producing formations. Regulations and inspections are needed to confirm that operators have taken prompt action to repair defective cementing jobs. The regulation of shale gas development should include inspections at safety-critical stages of well construction and hydraulic fracturing.  (4) Additional field studies on possible methane leakage from shale gas wells to water reservoirs.  (5) Adopt requirements for background water quality measurements (e.g., existing methane levels in nearby water wells prior to drilling for gas) and report in advance of shale gas production activity. (6) Agencies should review field experience and modernize rules and enforcement practices to ensure protection of drinking and surface waters. 
2. Disclosure of fracturing fluid composition: The Subcommittee shares the prevailing view that the risk of fracturing fluid leakage into drinking water sources through fractures made in deep shale reservoirs is remote. Nevertheless the Subcommittee believes there is no economic or technical reason to prevent public disclosure of all chemicals in fracturing fluids, with an exception for genuinely proprietary information. While companies and regulators are moving in this direction, progress needs to be accelerated in light of public concern. 
3. Reduction in the use of diesel fuel: The Subcommittee believes there is no technical or economic reason to use diesel in shale gas production and recommends reducing the use of diesel engines for surface power in favor of natural gas engines or electricity where available. 
4. Managing short-term and cumulative impacts on communities, land use, wildlife, and ecologies. Each relevant jurisdiction should pay greater attention to the combination of impacts from multiple drilling, production and delivery activities (e.g., impacts on air quality, traffic on roads, noise, visual pollution), and make efforts to plan for shale development impacts on a regional scale. Possible mechanisms include:  (1) Use of multi-well drilling pads to minimize transport traffic and need for new road construction.  (2) Evaluation of water use at the scale of affected watersheds.  (3) Formal notification by regulated entities of anticipated environmental an community impacts.  (4) Preservation of unique and/or sensitive areas as off-limits to drilling and support infrastructure as determined through an appropriate science-based process.  (5) Undertaking science-based characterization of important landscapes, habitats and corridors to inform planning, prevention, mitigation and reclamation of surface impacts.  (6) Establishment of effective field monitoring and enforcement to inform ongoing assessment of cumulative community and land use impacts.  The process for addressing these issues must afford opportunities for affected communities to participate and respect for the rights of surface and mineral rights owners. 
5. Organizing for best practice: The Subcommittee believes the creation of a shale gas industry production organization dedicated to continuous improvement of best practice, defined as improvements in techniques and methods that rely on measurement and field experience, is needed to improve operational and environmental outcomes. The Subcommittee favors a national approach including regional mechanisms that recognize differences in geology, land use, water resources, and regulation. The Subcommittee is aware that several different models for such efforts are under discussion and the Subcommittee will monitor progress during its next ninety days. The Subcommittee has identified several activities that deserve priority attention for developing best practices: 
6. Air: (a) Reduction of pollutants and methane emissions from all shale gas production/delivery activity. (b) Establishment of an emission measurement and reporting system at various points in the production chain.
7. Water: (a) Well completion – casing and cementing including use of cement bond and other completion logging tools. (b) Minimizing water use and limiting vertical fracture growth. 
8. Research and Development needs. The public should expect significant technical advances associated with shale gas production that will significantly improve the efficiency of shale gas production and that will reduce environmental impact. The move from single well to multiple-well pad drilling is one clear example. Given the economic incentive for technical advances, much of the R&D will be performed by the oil and gas industry. Nevertheless the federal government has a role especially in basic R&D, environment protection, and safety. The current level of federal support for unconventional gas R&D is small, and the Subcommittee recommends that the Administration and the Congress set an appropriate mission for R&D and level funding. 

SEAB Shale Gas Production Subcommittee – 90 Day Report (August 18, 2011). 

The Draft SEAB Shale Gas Production Subcommittee – Second 90 Day Report (November 18, 2011) focuses on implementation of the recommendations (listed above) from the initial report.  The Shale Gas Production Subcommittee comments below on the perceived failure to implement its recommendations: 

The Subcommittee has the impression that its initial report stimulated interest in taking action to reduce the environmental impact of shale gas production by the administration, state governments, industry, and public interest groups. However, the progress to date is less than the Subcommittee hoped and it is not clear how to catalyze action at a time when everyone’s attention is focused on economic issues, the press of daily business, and an upcoming election. The Subcommittee cautions that whether its approach is followed or not, some concerted and sustained action is needed to avoid excessive environmental impacts of shale gas production and the consequent risk of public opposition to its continuation and expansion. 

DraftSEAB Shale Gas Production Subcommittee – Second 90 Day Report (November 18, 2011) at p. 10. 

This article was authored by Laura G. Swingle, Jackson Kelly PLLC. For more information on the author see here.

ORSANCO Agrees to Further Review TDS Standard

As a result of action of ORSANCO at its June 2011 meeting, a TDS standard of 500 mg/l was adopted with applicability to intakes to public water supplies located on the main stem of the Ohio River.  At that same meeting, the Commission authorized a study of various factors related to the TDS water quality standard.  The objectives of such a study are:  

(1)  to generate sufficient TDS data to define ambient background levels and annual TDS loads at selected locations in the Ohio River;  

(2)  to develop site-specific translators to convert commonly collected conductivity measurements to estimate TDS concentrations;  

(3) to quantify TDS constituent makeup to document temporal and special variability, as well as to aid in the characterization of dominant sources within selected reaches of the Ohio River;  and 

(4) to provide a basis for the development of an Ohio River bromide stream criterion.  

At the Commission meeting on October 13, 2011, the Commission expanded the TDS study to go from 5 to 15 sites to be sampled in conjunction with the study.  The samples collected under the study will be analyzed for the following dissolved solids parameters:  

• TDS
• Chloride
• Sulfate
• Sodium
• Potassium
• Calcium
• Bicarbonate
• Magnesium
• Bromide
• Lithium
• Fluoride 

It is expected that the results of this survey will be available in November 2012.  

The Commission rejected a motion presented by Commissioner David Paylor of Virginia to suspend the effectiveness of the current TDS standard pending completion of the study.  The Commission did, however, unanimously approve a motion calling upon its Pollution Control Standards Committee to report back to it on any action that might be appropriate for the Commission to take with respect to the TDS standard following the completion of the TDS study that it has commissioned.  

This article was authored by David M. Flannery, Jackson Kelly PLLC. For more information on the author see here.

Alan Vicory to Retire as Executive Director of ORSANCO

At the October 13, 2011 meeting of the ORSANCO Commission, it’s Executive Director and Chief Engineer, Alan H. Vicory, announced that he would be retiring from ORSANCO as of year’s end for purposes of entering the private sector.  

Alan has served ORSANCO as its Executive Director longer than any other person and has distinguished himself not only as an effective manager of ORSANCO, but also as a national and international leader on water quality and water resource management.  

The ORSANCO Commission immediately acted to elect Peter Tennant to serve as Acting Executive Director.  Peter has been with the Commission for many years and will provide the Commission with important continuity.  

This article was authored by David M. Flannery, Jackson Kelly PLLC. For more information on the author see here.

National Mining Association Obtains Judgment Over EPA and Army Corps of Engineers

In an order issued on October 6, 2011, Judge Reggie Walton of the United States District Court for the District of Columbia ordered that certain procedures issued by the EPA and the Army Corps of Engineers be set aside as unlawful agency actions. 

NMA had filed suit against the agencies in July 2010.  The suit specifically asserted that both agencies had essentially created new regulations without public comment and formal rulemaking procedures by issuing the June 2009 Enhanced Coordination Process Memo (“EC Process”), its associated Multi-Criteria Integrated Resource Assessment (“MCIR Assessment”), and the April 1, 2010 “Detailed Guidance” memorandum.  NMA claimed that the issuance of these documents served as an unlawful obstruction to the Clean Water Act permitting process for coal mining. 

The EC process posed as a screening device for all pending Section 404 permit applications.  The screening process, or MCIR Assessment, set a threshold of acceptable mining impacts.  Application of the MCIR Assessment was designed to generate a list of permits that did not meet EPA’s threshold, which then subjected permittees to additional requirements under the EC process, rather than the usual review under the Corps regulatory process.  The April 2010 Detailed Guidance memorandum contained several new requirements regarding the need for water quality-based limits in Section 402 and 404 permits, but was primarily designed to force states to impose conductivity limits on discharges associated with surface mines. 

In late 2010, the court denied NMA’s Motion for a Preliminary Injunction.  Citing Wagner v. Taylor, 836 F.2d 566, 575 (D.C. Cir. 1987), the court noted that it must balance “(1) the [movant’s likelihood] of success on the merits; (2) the threat of irreparable injury in the absence of an injunction; (3) the possibility of substantial harm to other interested parties from the issuance of an injunction; and (4) the interest of the public.”  NMA, 2011 WL 124194 at *8.  Although the court stated that NMA was likely to succeed on the merits, the court found that NMA had presented insufficient evidence of irreparable harm to sustain an injunction because NMA’s evidence was only a “prediction” that some members would be driven out of business or otherwise suffer economic harm.  Id. at *12-13.  This recent ruling is a considerable victory for the coal industry as it invalidates the procedures that had essentially caused a moratorium on new coal mining permits. 

This article was authored by Douglas J. Crouse, Jackson Kelly PLLC. For more information on the author see here.