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Management of PCBs in Schools

During the last several years, the USEPA has been focusing attention on the potential presence of PCBs in various materials used to construct schools.  For example, in September 2009, the USEPA issued guidance about the potential presence of PCBs in the caulk of pre-1978 buildings.  In addition, USEPA also announced that it was conducting additional research into the potential for PCBs in caulk to be released to the air, which is ongoing.  Recently, USEPA released an on-line guide for School Administrators and Maintenance Workers entitled Proper Maintenance, Removal, and Disposal of PCB-Containing Fluorescent Light Ballasts.  This document is available at http://www.epa.gov/epawaste/hazard/tsd/pcbs/pubs/ballasts.htm.  

Until the late 1970s, PCBs were used as insulators in electrical equipment.  USEPA banned the manufacture of PCBs in the United States in 1977, and then the processing and distribution in commerce of PCBs in 1979, except in totally enclosed equipment as per the Toxic Substances Control Act (TSCA).  Use of PCB-containing ballasts was allowed to continue provided that the ballasts had not failed and PCBs were not leaking.  USEPA notes that the pre-1979 light ballasts are well past their expected useful life and pose an excess risk due to fires, leakage of PCBs, and breakage.  

USEPA states that the purpose of the on-line website is to provide information for school administrators and maintenance personnel about the risks posed by PCBs in light ballasts in schools and “how to properly handle and dispose of these items, and how to properly retrofit the lighting fixtures in your school to remove potential PCB hazards.”  USEPA also states that “while intact PCB-containing light ballasts pose no immediate health threat, they are likely to fail over time.”  

USEPA’s on-line guide is relatively short, only eight pages long, and is written for the non-scientist.  When reviewing the guide it is clear that USEPA’s intent is to encourage schools to remove all older light ballasts containing PCBs whether they are leaking or not, and to assume that they are PCB-containing if there is any question at all as to whether they may contain PCBs.  To reinforce their point, USEPA provides several stories of how PCB-containing light ballasts have leaked or caught on fire, thereby exposing students and teachers to PCBs.   Finally, USEPA argues that replacing the older light ballasts with new high efficiency, Energy Star lighting that will pay for the retrofit, generally in less than seven years.  In general, the USEPA guide provides the following information:

• Background on PCBs and potential health risks.
• Identifying fluorescent light ballasts that may contain PCBs.
• Whether PCB-containing fluorescent light ballasts should be removed.
• How to handle ballasts containing PCBs.
• Risks and potential costs if PCB ballasts are not replaced.
• Dangers to students and teachers from PCB-containing ballasts.
• Cleanup and decontamination as a result of a ballast leak or fire.
• Procedures for replacing ballasts.
• Procedures and regulations for managing PCB cleanup wastes and PCB-containing ballasts.
• Governmental and non-governmental resources to pay for a retrofit.

Finally, after reviewing this guidance if the school administrator or maintenance personnel have not concluded that they must remove all old fluorescent light ballasts from their facilities, USEPA states that “Postponing a lighting retrofit and betting on the structural integrity of old ballasts may result in health and educational impacts for your students and staff and serious cost impacts for your budget.” 

This article was authored by Greg Tieman, Acacia Environmental Group LLC. For more information on the author see here. 

EPA Proposes 91% National Reduction for Mercury As Well As Reductions of Other Toxics from Power Plants And Claims That Program Will Reduce Future Cost Of Power

Citing what it terms significant human health impacts and a court mandated deadline, US EPA on March 16, 2011, announced a proposal to reduce emission of mercury and other toxics, including arsenic, chromium, nickel and acid gases. The EPA announcement is short on specifics, other than to say that its proposal will reduce mercury emissions by 91%, but EPA nonetheless states that it projects that the new standards will prevent “as many as 17,000 premature deaths and 11,000 heart attacks a year.” EPA adds that “the new proposed standards would also provide particular health benefits for children, preventing 120,000 cases of childhood asthma symptoms and about 11,000 fewer cases of acute bronchitis among children each year. The proposed standards would also avert more than 12,000 emergency room visits and hospital admissions and 850,000 fewer days of work missed due to illness.”  

 

EPA projects that construction of controls by EGUs to comply with the new standards will result in 31,000 short term construction jobs and 9,000 long term utility jobs. Significantly, EPA also estimates that the cost of compliance with the new standards will result in retirement of only 1% of the utility coal fleet, estimating that 10 GW of generating capacity will be retired out of a current total of 1104 GW of capacity. However, that retirement figure is much lower than percentages estimated by the EGU regulated community. Moreover, the estimated benefits of the program are difficult to analyze since the EPA announcement provides no details on reductions of any of the other toxics to be regulated. 

 

EPA’s proposed rule provides up to 4 years for EGU facilities to meet the standards and EPA notes that, once the standards are fully implemented, they will prevent 91 percent of mercury in coal from being released into the air. The announcement does not specify the amounts of reductions of any of the other toxics the standard will cover.   

 

EPA estimates in its proposal announcement that, for every dollar spent to reduce EGU emissions, there will be a concomitant health and economic benefit of up to $13. Total health and economic benefits of the proposed standard are estimated by EPA at as much as $140 billion on an annual basis. EPA future cost of power projections also predict that the cost of power as a result of compliance with the new standards will be lower by 2030 than the EIA 2030 future cost projections without the proposed rule in place. Those cost estimates will undoubtedly be the subject of voluminous public comment since it is difficult to understand how the estimated cost of power in 2030 without the rule can be higher than the estimated cost of power with the rule in place as shown on EPA slides used during the announcement.

 

The EPA announcement also notes that the proposed standard “puts a premium on important input and feedback from stakeholders to inform any final standard,” adding that “the public comment period, which will last 60 days after appearing in the Federal Register, will allow stakeholders including the public, industry and public health communities, to provide important input and feedback, ensuring that any final standard maximizes public health benefits while minimizing costs.”

 

EPA will hold public hearings in Philadelphia, Atlanta, and Chicago on the proposal on dates yet to be determined.

 

This article was authored by Skipp Kropp, Jackson Kelly PLLC. For more information on the author see here. 

EPA Pressed to Meet Deadline for Boiler Emission Standards

January 20, 2011 the federal District Court for the District of Columbia issued an order extending by 30 days EPA’s January 16, 2011 deadline to issue emission standards for large and small boilers and solid waste and sewage sludge incinerators in a set of three inter-related rules as well as a re-definition of solid waste for the purpose of the incineration standard. 

The rule impacts almost 200,000 boilers and 176 solid waste incineration units across the U.S. EPA had requested a deadline of April 13, 2011 to allow EPA to re-propose its April 29, 2010 proposed rules to reflect the changes made as a result of the 4,800 comments it received. The comments raised issues that EPA stated it had not fully considered and which provided substantial additional data that raise questions about some of the Agency’s initial conclusions.  EPA argued to the Court that the comments materially affected important decisions relating to source categorizations and coverage for the final emission standards. 

EPA expressed concern that because of intended changes to the rule on the basis of submitted comments promulgating a final rule without  re-proposing the rule, would make it susceptible to invalidation if the rule was not a “logical outgrowth” of the proposed rule citing  Small Refinery Lead Phase-Down Task Force v. EPA, 705 F.2d 506, 549 (D.C. Cir. 1983) which held that EPA  cannotpromulgate a final rule that materially differs from the proposal unless the changes are a “logicaloutgrowth” of the proposal. EPA requested to publish the revised proposals for these three rules no later than June 1, 2011, and promulgate the final emission standards no later than April 13, 2012. 

EPA expressed is disappointment over the truncated schedule imposed by the Court, but stated that it would employ its best efforts to meet the deadline. Unfortunately, the Court’s decision may cause EPA to fail to make changes it would have otherwise have made in the rules in response to the new information in the comments in order to avoid the rule being invalidated on the basis of the “logical outgrowth” principle. 

The April 29, 2010, EPA proposed regulations included the following inter-related set of regulations: 

• Emission standards for Industrial Commercial and Institutional Boiler and Process Heater Major Sources [major source has potential to emit 10 or more tons per year (tpy) of any single air toxic or 25 tpy or more of any combination of air toxics.] The rule applies to boilers, which burn natural gas, fuel oil, coal, biomass (e.g., wood), refinery gas, or other gas to produce steam used to produce electricity or provide heat and to .process heaters, which heat raw or intermediate materials during an industrial process. Most major source boilers and process heaters are located at industrial facilities such as refineries, chemical and manufacturing plants, and paper mills. Commercial boilers may service shopping malls or other commercial facilities and institutional facilities service universities and hospitals and are usually “area sources” discussed below.  
•  EPA has identified 11 different subcategories of boilers and process heaters based on the design of the various types of units. The proposed rule would include specific requirements for each subcategory. 
• Emission standards for area sources (non-major sources) of industrial, commercial and institutional boilers and process heaters.The majority of area source boilers covered by the proposed rule are located at commercial and institutional facilities and burn coal, oil, or biomass, or non-waste materials. Units that burn solid waste are regulated under the solid waste incineration rule discussed below.  EPA proposed to regulate area source boilers based on boiler design. Boilers are designed differently depending on what kind of fuel they burn: coal, oil or biomass. Also, the proposal would set different requirements for large and small boilers. Large boilers have a heat input capacity equal to or greater than 10 million Btu per hour and small boilers have heat input capacity of less than 10 million Btu per hr. 
• Revisions to the December 2000 new source performance standards (NSPS) and emission guidelines (EG) for new and existing commercial and industrial solid waste incineration (CISWI) units.A CISWI unit is any device used to burn solid waste at a commercial or industrial facility and does not include municipal solid waste incinerators, which are covered under separate rules. Examples of CISWI units include:

  -     units designed to discard solid waste;

  -     energy recovery units designed to recover heat that combust solid waste;

  -     waste burning kiln that combust solid waste in the manufacture of a product; and

  -     burn-off ovens that combust residual material off racks, parts, drums, or hooks so those items can be re-used in various production processes. 

• Incinerators were the only subcategory covered in the December, 2000 rule. The proposed rule would cover five CISWI subcategories: 

  -     incinerators

  -     energy recovery units

  -    waste burning kilns

  -     burn-off ovens; and

  -     small, remote incinerators. 

• Aspart of this action, EPA is also proposing which non-hazardous secondary materials would be considered solid waste and which would be considered fuel. This distinction would determine whether a material can be burned in a boiler or whether it must be burned in a solid waste incinerator. EPA   proposed a definition of solid waste, under the Resource Conservation and Recovery Act (RCRA) which could affect some units currently considered boilers by moving them into category of commercial and industrial solid waste incinerators if they burn solid waste. This proposed rule seeks to clarify which non-hazardous secondary materials are, or are not, solid wastes when burned in combustion units. Under the proposal:

  -     Units that burn non-hazardous secondary materials that are considered solid waste under RCRA would be subject to the section 129 Clean Air Act (CAA) requirements, and 

  -     Units that burn non-hazardous secondary materials that are not considered solid waste under RCRA would be subject to the section 112 CAA requirements. 

• This proposal would significantly narrow the current universe of non-hazardous secondary materials that when burned in combustion units would be subject to section 112 CAA requirements. Instead, they would be regulated by CAA 129 requirements if they are solid waste. The following non-hazardous secondary materials are not a solid waste under the proposal:

  -     Material used as a fuel that remains within the control of the generator (whether at the site of generation or another site the generator has control over) and it meets the legitimacy criteria;

  -     Material used as an ingredient in a manufacturing process (whether by the generator or a third party) that meets the legitimacy criteria;

  -     Material that has been sufficiently processed to produce a fuel or ingredient product that meets the legitimacy criteria; and

  -     Material that has been determined through a case-by-case petition process to not have been discarded and to be indistinguishable in all relevant aspects from a fuel product. 

• The inter-relationship of the rules is that they all involve sources which burn fuel or solid waste and the regulated hazardous air pollutants are the same. Mercury and lead are the air toxics of prime importance to EPA based on alleged adverse affects on children's developing brains -- including effects on IQ, learning, and memory. Other toxic air pollutants regulated are cadmium, dioxin, furans, formaldehyde and hydrochloric acid as carcinogens or otherwise causing  adverse health effects in adults and children. 
• Boiler and commercial/industrial solid waste incinerator (CISWI) regulations are closely related because similar units may be considered boilers or CISWI units based on whether or not they burn solid waste materials. 

This article was authored by Barbara D. Little, Jackson Kelly PLLC. For more information on the author see here.

European Union and United States Moving Closer Together With Chemical Management Issues

The European Chemicals Agency (ECHA) and the United States Environmental Protection Agency (EPA) released a Statement of Intent on December 17, 2010 related to chemical management activities. The Statement of Intent sets forth general goals that will require a formal agreement between the European Union and the United States.

 

The Statement of Intent identifies the following findings:

 

1.         It is within the Participants’ common interest as well as in the public interest to enhance their technical cooperation in contributing to a high level of protection of human health and of the environment;

 

2.         The Participants take note with satisfaction of their initial contacts dedicated to identifying possible areas of mutual interest and cooperation;

 

3.         The Participants remain conscious that issues reaching beyond technical cooperation and the exchange of views on regulatory tasks within their respective mandates and instead touching upon the implementation and further development of EU policies in this sector are to be covered by a separate tripartite accord to be established between the European Commission and the Participants;

 

4.         The Participants confirm their understanding that any exchange of information as described in Article 120 of the [REACH] Regulation (EC) No 1907/2006 will furthermore require an international agreement to be established between the European Union and the United States;

 

5.         The Participants, within these boundaries, agree that professional peer contacts between them should be strengthened.

 

The initial areas of cooperation may include: hazard and risk assessment of chemicals; registration of chemicals (i.e. inventory); training programs; exchange of operational experience; and dissemination of public information, including publications.

 

The ECHA and EPA plan to interact on many different levels, including missions and exchange of staff, sharing of training information and cooperation on activities to inform the general public and target groups with information regarding chemical safety.

 

The concern for many in the regulated community will be the confidentiality of chemical manufacturing processes and the potential for further regulatory changes. The current controversy regarding the EPA request for identification of all chemicals used in frac fluids used to develop natural gas fields by the natural gas producers is an issue that highlights disclosure concerns in this country. The Statement of Intent between ECHA and the EPA contains a brief paragraph indicating that the information exchange will be treated in accordance with applicable law, including safeguarding of the right of third parties - in particular, their intellectual property rights. 

This article was authored by William Chambers, Acacia Environmental Group LLC. For more information on the author see here.

EPA Issues Final Requirements Under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells

            On November 22, 2010, U.S. EPA issued the final rule Federal Requirements Under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO₂) Geologic Sequestration (GS) Wells. See prepublication Federal Register Notice available at http://water.epa.gov/type/groundwater/uic/upload/pre-FR_class6_2010-11-22.pdf. This rule establishes minimum Federal requirements under the Safe Drinking Water Act (SDWA) for underground injection of carbon dioxide (CO₂) for geologic sequestration (GS) purposes. GS is one option available to help mitigate climate change associated with the combustion of fossil fuels. U.S. EPA expects the following entities to be regulated by this action: owners or operators of CO₂ injection wells used for Class VI GS and owners or operators of existing CO₂ injection wells transitioning from Class I, II, or Class V injection activities to Class VI GS. These regulations have the potential to impact the following source sectors that U.S. EPA has identified to be amenable to CO₂ capture: electric power plants (existing and new), natural gas processing facilities, petroleum refineries, iron and steel foundries, ethylene plants, hydrogen production facilities, ammonia refineries, ethanol production facilities, ethylene oxide plants, and cement kilns. Id. at 22-23.

 

Through this rule, U.S. EPA creates a new class of injection well (Class VI) within the existing UIC regulatory framework designed to address the “unique nature of CO₂ injection for GS.” Id. at 18. This rule establishes minimum technical criteria for Class VI wells, which are designed to protect underground sources of drinking water (USDWs).    The minimum technical criteria for Class VI wells will require:

 

• Site characterization that includes an assessment of the geologic, hydrogeologic, geochemical, and geomechanical properties of the proposed GS site to ensure that Class VI wells are located in suitable formations.
• Computational modeling of the AoR for GS projects that accounts for the physical and chemical properties of the injected CO₂ and is based on available site characterization, monitoring, and operational data.
• Periodic reevaluation of the AoR to incorporate monitoring and operational data and verify that the CO₂ plume and the associated area of elevated pressure are moving as predicted within the subsurface.
• Well construction using materials that can withstand contact with CO₂ over the life of the GS project.
• Robust monitoring of the CO₂ stream, injection pressures, integrity of the injection well, ground water quality and geochemistry, and monitoring of the CO₂ plume and position of the pressure front throughout injection.
• Comprehensive post-injection monitoring and site care following cessation of injection to show the position of the CO₂ plume and the associated area of elevated pressure to demonstrate that neither pose an endangerment to USDWs.
• Financial responsibility requirements to ensure that funds will be available for all corrective action, injection well plugging, post-injection site care (PISC), site closure, and emergency and remedial response. 

Id. at 19. 

 

            Since the rule was proposed on July 25, 2008, U.S. EPA has made the following changes:

 

• Additional description of the adaptive rulemaking approach. To ensure USDW protection and meet the potentially fast pace of GS deployment, EPA plans to continue its adaptive rulemaking approach for GS to incorporate new research, data, and information about GS and associated technologies.  See Section II.F.
• Elaboration on the rationale for allowing States to gain Class VI primacy independent of other well classes. To encourage States to take responsibility for implementation of Class VI regulations and foster a more comprehensive approach to managing GS projects within a broader framework for managing CCS issues, §145.21 of today’s rule allows States to gain primacy for Class VI wells independent of other well classes. See Section II.G.
• Explanation of the considerations for permitting wells that are transitioning from Class II to Class VI. To clarify the point at which the purpose of CO₂ injection transitions from ER (i.e., a Class II well) to long-term storage (i.e., Class VI) and the risk posed to USDWs increases and is greater than traditional ER projects injecting CO₂ today’s rule at §144.19 contains specific, risk-based factors to be considered by owners or operators and by Directors making this determination.  See Section II.H.
• Incorporation of a process to allow Class VI well owners or operators to seek a waiver from the injection depth requirements. To provide flexibility to address concerns about geologic storage capacity limitations, address injection depth on a site-specific basis, and accommodate injection into different formations types, today’s rule, at §146.95, allows owners or operators to seek a waiver of the Class VI injection depth requirements provided they can demonstrate USDW protection. Today’s final rule also limits the use of aquifer exemptions for Class VI well injection activities (§144.7(d)). See Section III.D.
• Clarification of the requirements for submitting materials to support Class VI permit applications. Today’s rule specifies separate requirements for information to be submitted with the permit application (§146.82(a)) and information that must be submitted before well operation is authorized (§146382(c)). This modification addresses comments that not all of the information to support the proposed Class VI permit application requirements will be available at the time the operator develops their initial permit application, See Section III.A.
• Addition of requirements for updating project-specific plans. To ensure that management of GS projects reflect up-to-date information, today’s rule requires periodic reviews of the AoR and corrective action, testing and monitoring, and emergency and remedial response plans (§146.84(e)), §146.90(j), and §146.94(d)). Any significant changes to the plans require a permit modification (under §144.39(a)(5)). See Sections III.F and III.K.
• Increasing the frequency of AoR reevaluations. To address concerns about the inherent uncertainties in modeling CO₂ movement, the emerging nature of GS technology, and the importance of targeting monitoring activities where risk to USDWs is greatest, today’s rule at §146.84(e) requires that the AoR for GS projects be reevaluated at a fixed frequency, not to exceed five years as specified in the AoR and corrective action plan, or when monitoring and operational conditions warrant.  See Section III.B.
• Clarification and expansion of financial responsibility requirements for Class VI well owners or operators. To ensure that financial resources are available to protect USDWs from endangerment, today’s rule (at §146.85) identifies qualifying financial instruments, the time frames over which financial responsibility must be maintained, procedures for estimating the costs of activities covered by the financial instruments, procedures for notifying the Director of adverse financial conditions, and requirements for adjusting cost estimates to reflect changes to the project plans. See Section III.I.
• Revisions to the GS site monitoring and plume tracking requirements to ensure that the most appropriate methods are used to identify potential risks to USDWs posed by injection activities, verify predictions of CO₂ plume movement, provide inputs for modeling, identify needed corrective actions, and target other monitoring activities. Today’s rule, at §146.90(g), requires Class VI well owners or operators to use direct methods to monitor for pressure changes in the injection zone and to supplement these direct methods with indirect, geophysical techniques unless the Director determines, based on site-specific geology, that such methods are not appropriate. See Section III.F. 

Id. at 63-66. As written, despite receiving comments opposing an arbitrary injection pressure limit, the final rule retains the requirement from the proposed rule that pressure in the injection zone must not exceed 90 percent of the fracture pressure of the injection zone (§146.88(a)). 

 

The final rule Federal Requirements Under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO₂) Geologic Sequestration (GS) Wells shall become effective 30 days after publication in the Federal Register (which should be forthcoming). All CO₂ injection wells permitted after the effective date will have to meet the new Class VI technical requirements. Owners or operators of Class I wells previously permitted for the purpose of geologic sequestration and Class V experimental technology wells, no longer being used for experimental purposes that will continue injection of carbon dioxide for the purpose of GS, must apply for a Class VI permit pursuant to requirements at §146.81(c) within one year after the date of rule publication. In an effort to ease the transition from Class II and Class V wells to Class VI wells, U.S. EPA is allowing the constructed components of these wells to be grandfathered into the Class VI permitting regime at the discretion of the Director and pursuant to requirements at §146.81(c). The proposed rule had suggested that Class VI requirements would not apply to Class II enhanced recovery wells as long as any oil or gas production was occurring. However, in response to the comments it received, U.S. EPA has expanded the scope of the final rule to apply to any CO₂ injection project (regardless of formation type) when there is an increased risk to USDWs, as compared to traditional Class II operations using CO₂. 

 

U.S. EPA expects the nonquantified benefits from this final rule Federal Requirements Under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO₂) Geologic Sequestration (GS) Wells to result in the protection of USDWs (as required of U.S. EPA by the SDWA) and the mitigation of potential risk to surface ecology and human health through exposure to elevated levels of CO₂, while noting that U.S. EPA did not consider the potential benefits from climate change mitigation in its assessment. At the same time, U.S. EPA anticipates the costs of complying with this rule to be $108.3 million in annualized terms using a 3-percent discount rate. 

 

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

USEPA Proposed Guidelines – Biofuel Storage in USTs

On November 17, 2010, the USEPA published notice in the Federal Register (Volume 25, No. 221, pages 70241 – 70246) requesting public comments on a proposed guidance that is intended to clarify USEPA’s underground storage tank (UST) compatibility requirements as they apply to UST systems storing biofuels.  The proposed guidance applies to owners and operators of UST systems regulated under 40 CFR Part 280 who store the following biofuel blends: 

• Gasoline blended with greater than 10% ethanol.
• Diesel blended with biodiesel at a to-be-determined percentage. 

The USEPA regulates UST systems storing petroleum or hazardous substances under authority of Subtitle I of the Solid Waste Disposal Act.  Ethanol and biodiesel are not specifically regulated under Subtitle I; however, USEPA considers UST systems storing gasoline or diesel blended with any amount of ethanol or biodiesel as being regulated under its UST program. 

The UST regulations were designed to prevent and/or detect releases of petroleum or hazardous substances from UST systems to the environment.  One particular provision of the regulations under 40 CFR 280.32 – Compatibility, requires that “Owners and operators must use an UST system made of or lined with materials that are compatible with the substance stored in the UST system.”  The USEPA is concerned that as the US moves towards a greater use of biofuels in gasoline and diesel that these materials can compromise the integrity of the UST system materials.  In particular, USEPA is concerned about gasoline ethanol blends containing greater than 10% ethanol or diesel containing any percentage of biodiesel. 

Historically, owners and operators of UST systems have demonstrated that the components of their systems are compatible with the stored fluids by using equipment that has been certified by independent laboratories, such as Underwriters Laboratories (UL).  For gasoline ethanol blends, tanks and piping have been certified by the UL for years for blends greater than 10% ethanol (E10). However, many other components of the UST systems, such as leak detection devices, seals, and containment sumps may not be certified for gasoline ethanol blends greater than 10% ethanol.  With regard to biodiesel, the USEPA notes that no UST equipment has a UL-listing for use with biodiesel blends; although, the USEPA states that a number of states have already developed compatibility policies for biodiesel blends of up to B20 (20% biodiesel blend), since B20 is commonly used in government and military fleets.

As outlined in the Federal Register notice, the USEPA is specifically seeking input with regard to a broad range of questions, some of which are as follows: 

• Are there UST system components that should be added or removed from the list?
• Is it possible to demonstrate compatibility for these components?  How difficult will it be to demonstrate compatibility?
• Are USEPA’s three proposed methods for demonstrating compatibility appropriate and feasible for owners and operators?  These methods are as follows:
  • Certification or listing by an independent test laboratory.
  • Equipment manufacturer approval.
  • Another method determined by the USEPA and developed in conjunction with the States that is sufficiently protective of human health and the environment.
• Are there other reasonable methods available to determine compatibility?
• Are manufacturers willing and able to produce the approval?
• Should biodiesel blends be included in the guidance?  If so, what is the appropriate blend percentage? 

Finally, USEPA is seeking input regarding how many facilities in the US may not be able to demonstrate compatibility and what efforts might be necessary for owners and operators to come into compliance.  For example, USEPA is concerned whether equipment upgrades could range from replacement of seals or release detection probes up to replacement of the entire UST system. 

USEPA is accepting comments by December 17, 2010.  Comments can be submitted on-line, via e-mail, or by mail.  Directions for submitting comments are provided in the Federal Register notice. 

This article was authored by Greg Tieman, Acacia Environmental Group LLC. For more information on the author see here. 

U.S. EPA and Sierra Club Enter into Settlement in Definition of Solid Waste Rule Litigation

            U.S. EPA and Sierra Club have reached a settlement on issues raised by Sierra Club in its petition for reconsideration and petition for judicial review of U.S. EPA’s final rule titled “Revisions to the Definition of Solid Waste,” that was published October 30, 2008 (73 Fed. Reg. 64,668 (DSW Rule). Under the Settlement Agreement, U.S. EPA has agreed to sign a proposed rule no later than June 30, 2011 and a final rule making no later than December 31, 2012, addressing the issues raised in Sierra Club’s administrative petition for reconsideration, including, at a minimum, the definition of “contained,” notification before operating under the exclusion, the definition of “legitimacy,” and the transfer-based exclusion.

 

            Hazardous waste generators engaged in on-site recycling will want to follow U.S. EPA’s rulemaking on these issues. Because Sierra Club opposes the transfer-based exclusion, the agreed timeline for U.S. EPA’s rulemaking will be of particular interest to third parties engaged in recycling hazardous secondary materials off-site. The Settlement Agreement was announced as part of a motion to sever Sierra Club’s petition for judicial review, 09-1041, from lead case American Petroleum Institute v. EPA, 09-1038, pending in the United States Court of Appeals for the District of Columba Circuit. 

 

The 2008 DSW Rule established three exclusions from the definition of solid waste and; therefore, from hazardous waste regulation, for hazardous secondary materials destined for recycling or reclamation.  The DSW Rule excludes materials from the federal hazardous waste management system that are: (1) generated and reclaimed under the control of the generator; (2) generated and transferred to another person or company for reclamation under specific conditions and provided certain conditions are met; and (3) determined by U.S. EPA or an authorized state to be non-wastes on a case-by-case basis pursuant to a petition process. The second exclusion is known as the transfer-based exclusion. Among the requirements for the transfer-based exclusion and other exclusions are containment, notification to U.S. EPA, and that the recycling be legitimate.

 

            For both recycling on-site and off-site, the DSW Rule requires that the hazardous secondary material be “contained”. Sierra Club argues that the Rule is vague because U.S. EPA failed to define “contained,” which is found in virtually every provision of the Rule that excludes hazardous secondary materials destined for recycling from the definition of solid waste. In the preamble, U.S. EPA stated that the word “contained” means “placed in a unit that controls the movement of the material out of the unit into the environment”. 73 Fed. Reg. 64,748. Sierra Club maintains that this definition does not solve the problem because U.S. EPA set no standards for what counts as “control”. 

 

            Under the Rule, both generators conducting on-site recycling and third parties conducting off-site recycling are required to notify the appropriate regulatory agency before conducting recycling activities under the exclusion; however, failure to notify does not affect the excluded status of the hazardous secondary materials. Sierra Club argues that notification should be one of the required elements for persons claiming that the hazardous secondary material is not being discarded. In other words, under Sierra Club’s view failure to notify would result in the material being considered hazardous waste. 

 

            In the 2008 DSW Rule, U.S. EPA codified a four-factor definition of “legitimacy” and made the codified definition a requirement for both the on-site and off-site recycling exclusions as well as petitions for non-waste determinations, but did not extend the definition to other existing recycling exclusions. Under the 2008 DSW Rule, “legitimate recycling” requires that a hazardous secondary material provide a useful contribution to the recycling process either as a product or intermediate and that the recycling process produce a valuable product or intermediate. In addition, recyclers must consider two other factors, but may not be required to meet them: (1) whether the hazardous secondary material is managed as a valuable commodity; and (2) whether the product of the recycling process contains hazardous constituents that are significantly elevated in comparison to analogous products. Id. at 64,701-705. Sierra Club wants U.S. EPA to make all four factors mandatory. 

 

            Finally, Sierra Club argues that U.S. EPA should regulate hazardous secondary materials generated and transferred to another company for recycling as discarded and solid waste under traditional RCRA requirements. Sierra Club argues that off-site recycling is inherently more dangerous than recycling on-site and does not produce compensatory benefits. Sierra Club uses statistics to argue that facilities operating without RCRA permits are far more likely to cause damage, off-site hazardous waste recycling facilities constitute the great majority of the damage cases, and transfer facilities or “middle men” represent another significant percentage of the contaminated sites. Sierra Club argues that the DSW Rule will not substantially increase hazardous waste site recycling and points to U.S. EPA’s estimate that the DSW Rule will result in only a 1.1% increase in recycling above 2005 levels.   

 

            This article was authored by Gale Lea Rubrecht, Jackson Kelly PLLC. For more information on the author, see here.

Pennsylvania Governor to Halt New Gas Drilling Leases in State Forests

Gov. Ed Rendell sought to restart talks over a natural gas extraction tax Monday, a day before he was poised to issue an executive order banning any further leasing of state forest land for Marcellus Shale drilling.

 

The Democratic governor's office said he will sign what was described as a "strategic moratorium" at an event in Philadelphia on Tuesday.

 

Rendell said Monday he wants Republicans who control the state Senate to resume negotiations over a prospective tax on the drilling.

 

He proclaimed the tax proposal dead last week, blaming legislative Republicans for what he described as their failure to offer a reasonable compromise on the rate - one of multiple issues that have stalled progress.

 

The governor, who is leaving office in January, said at a news conference that he would work "night and day" to reach a compromise if Senate Republicans were willing to hold a lame duck session after the Nov. 2 election.

 

"If they are willing to come back after the election ... then we'll find a room somewhere and we will sit together until there is a tax, until there is a reasonable tax," he said.

 

A Republican spokesman said Monday they would be "very willing participants" if there are talks with all four caucuses this week about a deal that would get to the governor's desk before the election.

 

"However, (a) lame duck session - particularly with a lame duck governor - is not the time to impose any sort of tax increase," said Erik Arneson, spokesman for Senate Majority Leader Dominic Pileggi, R-Delaware. "The Senate announced more than eight months ago that there will not be a regular lame duck session, and that fact has not changed."

 

Less than a year ago, the state Department of Conservation and Natural Resources announced it was making nearly 32,000 acres of state forest land available for leasing by gas drilling companies.

 

The Marcellus Shale, a rock bed about a mile beneath New York, Pennsylvania, West Virginia and Ohio, has produced a rush of exploration and land deals in the state, and could become the nation's most valuable natural gas field. Its production employs a process known as hydraulic fracturing, in which water and chemicals are pumped underground to create fissures in the rock and release the gas. 

This article includes publically available information, and was assembled by Rachel Shanteau, Acacia Environmental Group LLC. For more information on the author see here.

EPA Extends Date by Which SOME Facilities with Oil Storage Capacity Need to Implement Spill Prevention, Control, and Countermeasure Plans

On October 14, 2010, the U.S. Environmental Protection Agency published a final rule that extends the deadline by which many facilities that store or handle large amounts of oil need to complete a Spill Prevention, Control, and Countermeasure (SPCC) plan. The new compliance date for many facilities will now be November 10, 2011.  

 

Oil Pollution Prevention regulations promulgated by EPA are wide in scope. Gas stations, oil production facilities, mining operations, and many types of manufacturing plants are generally required to have SPCC plans. Under the regulations, “oil” ranges from petroleum to cooking oil, while “facility” is defined to encompass everything from storage tanks to pipelines to buildings.

 

Which Facilities are Affected and What are the New Deadlines?

           

            Facilities that have aboveground oil storage capacity greater than 1,320 gallons or underground oil storage capacity greater than 42,000 gallons are required to implement a SPCC plan.    Depending on a facility’s characteristics, however, the date by which a facility must fully implement a SPCC plan varies.  

 

·        Offshore drilling, production, or workover facilities have not received a deadline extension and must implement a SPCC plan by November 10, 2010.

 

·         Onshore facilities that are required to have a Facility Response Plan (FRP) must implement a SPCC plan by November 10, 2010. 

 

o       A FRP is needed if a facility:

 

1)      transfers oil across water or to or from vessels and has over 42,000 gallons of oil capacity; or

 

2)      has total oil storage capacity of 1 million gallons or greater, and one of the following is true:

 

a)      facility does not have secondary containment for each above-ground storage area sufficiently large to contain the capacity of the largest above-ground storage tank within each area; or

 

b)      facility is located in an area where a discharge could cause damage to fish and wildlife and sensitive environments; or

 

c)       facility is located in an area where a discharge could shut down a public drinking water intake; or

 

d)      facility has reported a spill of 10,000 gallons of oil or more in the past five years.

 

·        Facilities that have been in operation since August 16, 2002 must already have a SPCC plan. These facilities should keep their existing plan in place and implement an updated SPCC plan by November 11, 2011.

 

·        Facilities that opened between August 16, 2002 and November 10, 2011 must complete a SPCC plan by November 10, 2011.

 

·        Facilities opening after November 10, 2011 must prepare a SPCC plan before they begin operations. New oil production facilities, however, will have six months after starting operations to develop a SPCC plan.

 

What is an SPCC Plan?

             

SPCC plans require facilities with the greatest chance to spill oil into U.S. waters to develop containment systems and protocols to prevent oil from reaching waters of the U.S. Each facility’s plan must be customized to the facility, although EPA regulations have numerous standardized requirements for each general type of facility. 

 

            EPA officials evaluate a facility’s SPCC plan when they conducting on-site visits. EPA officials are allowed to interview facility employees about their familiarity with the plan and their role in its implementation. If a facility has more than two spills in a twelve-month period, EPA will officially review a facility’s plan. In the event a facility fails to develop an SPCC plan or is not properly implementing one, EPA has authority to issue administrative penalties.

 

SPCC plans must be approved by the managers of a facility and must be allocated sufficient resources to be fully implemented. The plans generally need to be reviewed and certified by a licensed professional engineer, although an exception allows a facility to self-certify its SPCC plan if: 1) the facility has aboveground oil storage capacity of 10,000 gallons or less; 2) the facility has never had a spill exceeding 1,000 gallons; and 3) the facility has not had two spills over forty-two gallons in any twelve month period in the three years prior to self-certification.

 

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

D.C. Circuit Interprets U.S. EPA’s Definition of Spent Material

The D.C. Circuit recently interpreted the definition of “spent material” found in U.S. EPA’s hazardous waste regulations at 40 CFR §261.1(c) in Howmet Corporation v. EPA, 615 F.3d 544 (D.C. Cir. 2010). The case involved a manufacturer of precision investment castings for aerospace and industrial gas turbine applications. The castings manufacturer used potassium hydroxide (KOH) solution to clean castings parts. When the KOH became so contaminated that it no longer effectively cleaned the parts, the manufacturer typically sent the used KOH offsite for disposal. The used KOH was corrosive and would be managed as hazardous waste under U.S. EPA’s regulations. However, during one thirteen month period between August 1999 and September 2000, the castings manufacturer sent the KOH to a fertilizer producer who incorporated the KOH into its fertilizer product to control pH and provide a source of potassium. The castings manufacturer did not prepare any hazardous waste manifest or otherwise treat the KOH as a hazardous waste.  

U.S. EPA brought an enforcement action against the castings manufacturer, claiming that the spent KOH met the definition of a spent material that was being used to produce products that are applied to the land (i.e., use constituting disposal). According to U.S. EPA, the contaminated KOH was a solid waste and a hazardous waste because of its corrosivity. Id. at 548. The manufacturer challenged the agency’s action before a U.S. EPA administrative law judge, the agency’s Environmental Appeals Board, the United States District Court for the District of Columbia, and finally the United States Court of Appeals for the District of Columbia Circuit. Id. at 549.  

The dispute focused on the interpretation of the phrase “the purpose for which it was produced” in the regulatory definition of spent material at 40 CFR §261.1(c), which reads: “A ‘spent material’ is any material that has been used and as a result of contamination can no longer serve the purpose for which it was produced without processing.” Under U.S. EPA’s regulations, hazardous waste is a subset of solid waste. A material cannot be a hazardous waste unless it is first determined to be a solid waste. Further, a spent material is a solid (and potentially hazardous) waste when “[a]pplied to or placed on the land in a manner that constitutes disposal” or “[u]sed to produce products that are applied to or placed on the land ….”   40 CFR §261.2(c)(1)(A)-(B).  

The castings manufacturer urged the D.C. Circuit to adopt an interpretation of “purpose” in the above-quoted definition of spent material that would allow a product with multiple uses, such as KOH, to be used first as a cleaning agent and then as a fertilizer ingredient without being “spent” because both uses are consistent with KOH’s purpose as a concentrated source of hydroxide ions and of potassium. U.S. EPA countered that “the purpose for which [a product] was produced” must be related to its original use. Id. at 548.  

In a 2-to-1 decision, a majority of the D.C. Circuit first found that the word “purpose” was ambiguous. Id. at 550. The majority then upheld U.S. EPA’s interpretation, finding the agency’s interpretation was reasonable and consistent with the regulatory history of its “spent material” definition and RCRA’s overall purpose. With respect to how U.S. EPA intended to determine a material’s “purpose,” the majority found the preamble language in the earlier regulations defining spent material “informative” and noted the following example of a product used for a subsequent purpose not identical to its original use that would not be considered a spent material in the preamble to the final 1985 regulation adopting the current definition of “spent material”:  

“[W]here solvents used to clean circuit boards are no[] longer pure enough for that continued use, but are still pure enough for use as metal degreasers. These solvents are not spent materials when used for metal degreasing. The practice is simply continued use of a solvent.

Id. at 551-52.  

The majority found that the above “example makes clear the EPA was . . . associating the concept of ‘purpose’ with ‘initial use.’” Id. at 552. Relying upon this preamble language, the majority upheld U.S. EPA’s position that for a used material not to be considered a spent material, the continued use would have to be “sufficiently similar to or consistent with the material’s initial use . . . .” Id. (emphasis in original). Because the castings manufacturer was taking a material that had been used as a solvent and using it for a completely different purpose (an ingredient in fertilizer), the majority found that the used solvent met the definition of spent material.  

The majority also rejected the manufacturer’s argument that it had not been given fair notice of U.S. EPA’s interpretation. Id. at 553-54. In rejecting the manufacturer’s fair notice argument, the majority focused on the following statement from a 1986 guidance manual that U.S. EPA announced in the Federal Register:  

[A] spent material is any material that has been used and as a result of contamination can no longer serve the purpose for which it was produced without processing. EPA interprets “the purpose for which a material was produced” to include all uses of the product that are similar to the original use of the particular batch of material in question. For example, EPA cites the case of materials used as solvents to clean printed circuit boards.... If the solvents become too contaminated for this use but are still pure enough for similar applications (e.g., use as metal degreasers), they are not spent materials. Use of slightly contaminated solvents in this way is simply continued use of the original material rather than recycling of a spent material. However, the solvents would be spent materials if they had to be reclaimed before reuse or if the manner in which they were used was not similar to their original application.... As [an] example, used plating baths reused directly in other plating processes would not be spent materials. If used for a purpose other than plating, however, the used plating baths would be a spent material.

Id. at 554 (emphasis in original). 

The majority concluded that the guidance manual, the availability of which was announced one year after the regulatory definition of spent material was promulgated and thirteen years before the conduct at issue, sufficed to provide fair notice of U.S. EPA’s interpretation of its spent material definition. Id.  

The dissent relied upon 40 CFR §260.3(b) that “[w]ords in the singular include the plural” to assert that the “purposes for which a material is produced are not limited to how the material is initially used by a purchaser.” Id. at 555. The dissent further argued that U.S. EPA’s current interpretation contradicted the agency’s statement in the 1985 regulation that it was not extending its regulatory authority to “situations where a material can be used further without being reclaimed, but the further use is not identical to the initial use.” Id. (quoting 50 Fed. Reg. 614, 624 (January 4, 1985)). The dissent also offered that U.S. EPA’s authority under RCRA only reaches “discarded material” but that EPA’s interpretation in this case reached material that had not been discarded but was being used as anticipated. Because the manufacturer had challenged U.S. EPA’s interpretation solely on the regulatory language, the dissent found no basis for considering if U.S. EPA’s interpretation exceeded its statutory authority. Id. at 556. 

This article was authored by Gale Lea Rubrecht, Jackson Kelly PLLC. For more information on the author, see here.