Energy and Environment Monitorwww.eem.jacksonkelly.com

Split Decision in OVEC v. Apogee

     The coal industry received a split decision earlier this week in another case targeting the discharge of selenium. In OVEC v. Apogee Coal Company, the United States District Court for the Southern District of West Virginia ruled that Apogee Coal was discharging selenium in violation of its NPDES permit.  When it re-issued the permit to Apogee Coal in August, 2006, the West Virginia DEP acknowledged that had mistakenly included final effluent limits in the permit, and that it should have included an interim period to attain compliance with the limits.  To correct its mistake and to enforce a policy that it was implementing across the coal industry, DEP postponed the effective date of the final limits until 2009 and required the company to monitor for selenium for a three year period.  The district court held this order issued in January 2007 to be a modification of the permit that had been implemented without public notice and in violation of DEP’s regulations.

     A more surprising outcome, however, and one in favor of industry came in the second major claim in the case involving Hobet Mining, LLC.  Hobet had also been sued for violating its NPDES permit, again for the discharge of selenium.  OVEC claimed that the discharges violated both the Clean Water Act and the state surface coal mining act known as SCMRA.  For procedural reasons the Clean Water Act claim was dismissed. The single Hobet outfall was discharging selenium within the terms of its NPDES permit, but allegedly in excess of state water quality standards.  OVEC claimed that this intermittent discharge violated the SCMRA as it allowed discharges in excess of state water quality standards and thereby contributed to material damage in the receiving stream and off of the mine permit.

     The district court disagreed and granted summary judgment to Hobet on this claim.  The court ruled that “If such a discharger cannot be held liable under the CWA [Clean Water Act], a finding of liability under WVSCMRA would impose discharge limits more stringent than those required under the CWA.”  Concluding that such an outcome would mean that the surface mining act’s requirements would supersede those of the CWA,  the court granted summary judgment to Hobet. 

     Whether this interpretation is settled or is still open for review is uncertain.   The court further explained that “The issue of whether or not a discharger can be held liable for water quality standards violations even while complying with its NPDES effluent limitations is not directly before the Court, but a finding in Plaintiffs’ favor requires an answer to the question.  The Court refuses to decide such an important issue in an indirect challenge.” Given OVEC’s proclivity to test novel legal theories, it is entirely foreseeable that it will find a way to make this “important issue” a direct challenge.

     For additional information about this decision contact Bob McLusky at rmclusky@jacksonkelly.com (304 340-1381) or Blair Gardner at bgardner@jacksonkelly.com

(304 340-1146).

EPA Issues Report on Environment Highlighting National and Regional Trends

On May 20, 2008, the U.S. Environmental Protection Agency issued a 2008 EPA Report on the Environment (ROE). The 2008 ROE updates a draft report released by EPA in 2003 and provides information on trends in the condition of air, water, and land and related changes in human health in the United States.

In addition to national scale indicators, the ROE provides data broken out by EPA Regions. Indicators presented include air pollutant emissions and concentrations, acid deposition, drinking water quality, land use patterns, population, fertilizer use, cardiovascular and pulmonary disease, forestland, fish populations, carbon storage, temperature and precipitation, and more.

EPA says it will use the 2008 ROE to inform and focus its activities to improve and protect America’s environment. The report frames key questions related to the protection of human health and the environment, and addresses each issue using indicators that were developed with extensive public input and which EPA characterizes as “scientifically sound.”

            

EPA states that:

“[t]he environmental indicators analyzed are quantifiable and provide valuable information on the condition of air, land, water, human health, or ecological condition. For example, one water ROE environmental indicator is the percentage each year of public or community water systems that have reported no violations of EPA health-based standards. This report and the indicators it contains were created in an open and transparent manner. The Agency took the extraordinary step of having the proposed indicators reviewed in a public forum to determine if citizens- -not just scientists- -believed the proposed indicators provided the kind of information that was useful, and were supported by technically sound data. From the ROE, EPA and the public will know better where the U.S. needs to focus future work and resources.”

EPA notes that its 2008 ROE is not intended as a “report card,” adding that, while there are both positive and negative trends contained in the report, its purpose is to “create a reliable set of information that can be used for year-to-year comparisons as well as planning.” EPA says the report may also lead to the development of new indicators, new monitoring strategies, and new programs and policies based on measured environmental trends.

Later this year, EPA intends to publish a 2008 Report on the Environment: Highlights of National Trends, which will summarize highlights of the EPA 2008 ROE without all of the technical detail.

To download EPA’s 2008 Report on the Environment, go to: http://www.epa.gov/roe

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

Corps of Engineers/EPA Compensatory Mitigation for Losses of Aquatic Resources

     The Corps of Engineers (COE) and EPA issued the final rule (33 CFR 332 and 40 CFR 230) for implementing the compensatory mitigation program on April 10, 2008 for losses of aquatic resources from dredge and fill activities. The effective date of the rule is June 9, 2008. The most significant change to the regulation is the reversal of the COE on the use of in-lieu fee programs for compensatory mitigation (the proposed rule was issued with a 90 day phase out date for these types of programs).

     Highlights of the rule are summarized below:

Where a project is located within the service area of an approved mitigation bank and credits in the bank are available for the type of resource impacted – mitigation requirements may be met by the purchase of an appropriate number of credits from the bank.

The watershed approach for compensatory mitigation requires use of an applicable or existing watershed plan. Where practicable and appropriate, the District Engineer (DE) will require the mitigation plant “compensatory mitigation” to be consistent with an established watershed plan or be determined using the principles of a watershed approach.

Where a plan is not available, the watershed approach should be based on information provided by the project sponsor or available from other sources.

Where a watershed approach is not practical – the DE will consider opportunities to offset anticipated aquatic resource impacts by requiring on-site and in-kind compensatory mitigation.

If in-kind compensation mitigation is determined not practicable, or unlikely to compensate for the permitted activity, or will be incompatible with the proposed project, and an alternative practicable offsite and out of kind mitigation opportunity is identified that has a greater opportunity for offsetting the permitted impacts (or it is environmentally preferable) – the DE “should require that this alternative mitigation be provided.”

In-kind mitigation is preferable to out-of-kind mitigation because it is most likely to compensate for the functions, services and values of the impacted site. If the DE determines using the watershed approach that out of kind compensatory mitigation will serve the aquatic resource needs of the watershed, the DE may authorize use of such out of kind compensation mitigation.

The amount of compensatory mitigation is to be sufficient to replace lost aquatic resource functions. Where available-functional or condition assessment or other suitable metric methods should be used to determine how much compensation mitigation is required. If such methods are not used, a minimum of one to one acreage or linear foot replacement ratio must be used for mitigation. The DE must require a mitigation ratio greater than one-to-one where necessary to account for the method of compensatory mitigation, the likelihood of success, difference between the functions lost at the impact site and functions expected to be restored by the project, temporary losses or aquatic resources, the difficulty of restoration or establishment of desired aquatic resources, and/or the distance between the affected aquatic resource and the compensation site.

Mitigation banks and in-lieu fee programs can be used to compensate for impacts to aquatic resources authorized by general permit or individual permits.

Preservation may be used to provide compensatory mitigation provided that: the resources provide important physical, chemical, or biological functions for the watershed, the resources contribute significantly to the ecological sustainability of the watershed, and the resources are under threat of destruction or adverse modification. Aquatic resource restoration is to be done in conjunction with preservation to the extent practicable and appropriate.

Buffers may be required by the DE around aquatic resources as well as maintenance of riparian areas around aquatic resources to ensure long term viability of the resources as part of compensation mitigation. If required, there will be credit provided for the establishment and maintenance of riparian areas or upland buffers.

Compensation mitigation may be used in conjunction with other program environmental impacts, such as SMCRA, provided that the project is consistent with the terms and conditions of the program; includes appropriate compensatory mitigation for unavoidable impacts to aquatic resources authorized by the COE permit; and does not use the same credits to provide mitigation for more than one permitted activity.

An individual permit is required to specify the mitigation bank or in-lieu fee program that will be used. A general permit is to identify the specific mitigation bank or in-lieu fee program, or state that the specific mitigation bank or in-lieu fee program is to be approved by the DE before credits are secured. Implementation of the mitigation project is to be in advance of or concurrent with the activity causing the impacts to the maximum extent possible.

Financial assurance must be sufficient to ensure that the compensation mitigation project will be successfully completed in accordance with the applicable performance standards. If financial assurances are required, the permit must include this as a condition to be in place prior to the activity. Financial assurance can be performance bonds, escrow accounts, casualty insurance, letters of credit, legislative appropriations for government sponsored projects, or other instruments approved by the DE. The permit or banking instrument must clearly specify the conditions under which the financial assurances will be released.

Financial assurances are to be phased-out once compensatory mitigation is successful as determined by the DE in accordance with the performance standards.

A project requiring an individual 404 permit must explain how the impacts associated with the activity will be avoided, minimized, and compensated for in the public notice. Activities under a general permit require a compensatory mitigation plan which meets the requirements of the rules, or the DE has the option of addressing requirements as permit conditions. Mitigation plans must contain objective and verifiable performance standards that will be used to assess whether the project is achieving its objectives.

Mitigation plans must identify how monitoring will be conducted, including parameters to be monitored, the length of the monitoring period (not less than 5 years), the party responsible for conducting the monitoring, and for submitting reports, and the frequency for submitting reports.

Documents required to be submitted to the DE include: mitigation plan, objectives, site selection, site protection instrument, baseline information, determination of credits, mitigation work plan, maintenance plan, performance standards, monitoring requirements, long-term management, adaptive management plan, and financial assurance.

All mitigation banks and in-lieu fee programs are to have an approved instrument signed by the sponsor and the DE prior to being used to provide compensatory mitigation. Mitigation banks/in-lieu fee programs are expected to be self-sustaining. An Interagency Review Team (IRT) is established by the DE to facilitate the establishment of mitigation banks or in-lieu fee programs through the appropriate instruments. The team is an advisor to the DE in assessing monitoring, recommending remedial measures, approving credit release, and approving modifications to a banking instrument. The mitigation banking instrument provides the authorization for the mitigation bank to provide credits to be used for compensatory mitigation.

The sponsor is responsible for preparing all documentation: the prospectus, mitigation plan, and the mitigation banking instrument.

Public Review Process: Public notice of the complete prospectus is provided to the public within 30 days by the DE. The comment period for review of the complete prospectus and providing any comments to the Corps is generally 30 days, unless a different period of time is determined appropriate. If the standard permit process is used for the project, then the public notice of the prospectus can be satisfied with the standard permit public notice and comment period (as long as all information is provided as required by the rule).

The DE provides that an initial evaluation within 30 days of whether the proposed mitigation bank or in-lieu fee program will provide compensatory mitigation for the authorized activities and whether the sponsor may proceed with the preparation of the draft instrument.

Draft Mitigation Banking Instrument: A draft is to be prepared for the DE which includes:

• Geographic Service Area of the mitigation bank or in-lieu fee program;
• Accounting procedures;
• Legal responsibility;
• Default and closure provision;
• Reporting protocols; and
• Other information determined necessary by DE

A mitigation bank is required to include in the instrument:

• Credit Release Schedule
• Mitigation plan

An in-lieu fee program is required to include in the instrument:

• The compensation planning framework;
• Initial allocation of advance credits and a draft fee schedule by service area;
• Methodology for determining future project-specific credits and fees; and
• Description of the in-lieu fee program account

DE must inform sponsor of status of interagency review within 90 days of submittal of a complete draft instrument including any concerns which may lead to an objection of the final instrument.

The DE must notify the interagency team within 30 days of his intention to approve or disapprove the instrument. Within 45 days of receipt of the final. If there are no objections from the IRT after 45 days, the DE must notify the sponsor of his dispute decision. Objections are to be addressed through a resolution process.

A stream-lined review process or modification is allowed if determined appropriate by the DE. A single mitigation banking instrument may provide for future authorizations of additional banking sites. The inclusion of additional sites must go through the process of modification.

An in-lieu fee program account must be established at an FDC-member financial institution and can only be used for selection, design, acquisition, implementation and management of the in-lieu fee compensatory mitigation projects with a small percentage for administrative costs.

A COE permit is not be to issued until all relevant provisions of the mitigation banking instrument have been substantially determined. Credit Release Program: Principal units of measure are linear feet or acres and sometimes functional assessment units of particular resource types. Riparian areas, buffers, upland areas and non-aquatic resources can be used as compensatory mitigation only if these resources are determined essential to maintaining the ecological viability of adjoining aquatic resources. A higher mitigation ratio is to be applied to preservation credits based on relative important of the impact and the preserved aquatic resources in sustaining watershed functions.

Process for Release of Credit: Credit releases require approval of the DE through a recommended comment process established in the rule.

If the DE determines that the mitigation bank or in-lieu fee program is not meeting performance standards or complying with the terms of the instrument, the COE DE will take appropriate action such as reducing the number of available credits or suspending credit sales or utilizing financial assurances, and terminating the instrument.

Reporting: The sponsor is required to maintain a ledger to account for all credit transactions for the mitigation bank and notify the DE each time an approved credit transaction occurs.

All mitigation banks approved after July 9, 2008 will be required to meet the requirements of the new rule. Mitigation banks approved prior to July 9, 2008 may continue to operate in accordance with the existing instruments; however, any modification after July 9, 2008 (including authorization of additional sites) must be consistent with the new rule changes.

In-lieu programs operating prior to July 9, 2008 for compensatory mitigation will be permitted to continue to operate under the instruments approved prior to July 9, 2008 until June 9, 2010. After that date, the in-lieu fee program will be required to operate under the new rules unless the DE determines circumstances warrant an extension. Any approved project for which construction was complete under the terms of a previous instrument may continue to operate indefinitely under those terms if the DE determines that the project is providing appropriate mitigation substantially consistent with the new rule.

The most favorable benefit of this regulation is that it leaves inplace an allowance for all types of mitigation, including in-kind and off site out-of-kind mitigation. Unfortunately, the regulation has an expressed preference for mitigation banking. The regulation is anticipated to require an extensive Guidance Document to address many questions left unanswered by this complicated regulation.

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

Mountaintop Removal Uncertainty Looms as Valley Fill Permit Litigation Continues

     Citizen group challenges to nationwide and individual Clean Water Act permits for valley fills associated with coal mining operations continued to wind their way through federal courts in Kentucky reminiscent of the path followed in West Virginia.  A recent decision and appeal in the case challenging the use of the nationwide permitting process to authorize valley fills and a new case challenging the issuance of an individual valley fill permit foreshadow more uncertainty in the mountaintop removal permitting process. 

     Virtually all coal mines in central Appalachia create “excess spoil” from the rock and soil generated during mining.  When placed in a headwater stream or channel that technically qualifies as a “water of the United States,” this excess spoil creates a “fill.”  Each such fill requires a permit from the U.S. Army Corps of Engineers (“Corps”) pursuant to Section 404 of the Clean Water Act (“CWA”).  Since 1982, the Corps has authorized these activities through a “general” permit known as Nationwide Permit (“NWP”) 21 if the mining operation is also permitted under, and subject to the environmental restrictions imposed by, the federal Surface Mining Control and Reclamation Act of 1977 (“SMCRA”).

     In early 2005, various citizens groups brought an action in the United States District Court for the Eastern District of Kentucky, Judge David Bunning now presiding, seeking to invalidate NWP 21 as authority for valley fill permits associated with coal mining and to revoke 54 existing authorizations for mines permitted in Kentucky.  Kentucky Riverkeeper, Inc. v. Rowlette, Case No. 05-181-DLB (E.D.K.Y.).  The citizen groups had hoped to replicate a favorable ruling they had recently secured from the United States District Court for the Southern District of West Virginia, Judge Joseph Robert Goodwin, in Ohio Valley Environmental Coalition v. Bulen, 315 F.Supp. 821 (S.D.W.Va. 2004) (“OVEC”), rev’d, 429 F.3d 493 (4^th Cir. 2005).  In OVEC, the Judge Goodwin found that NWP 21 did not comply with either the language or the legislative history of the CWA. Specifically, the district court noted that Section 404(e) of the CWA authorizes the Corps to issue nationwide permits only for those activities determined to have minimal environmental impact before issuance of the permit.  Judge Goodwin court further found that NWP 21 requires a case-by-case, post-hoc determination of minimal environmental impact, which the court found runs afoul of Section 404(e).  The Corps appealed Judge Goodwin’s decision in OVEC to the 4^th Circuit.

     Meanwhile, the parties in Riverkeeper were briefing the citizen groups’ motion for a preliminary injunction and the parties’ cross motions for summary judgment.  Before Judge Bunning ruled in Riverkeeper, however, the 4^th Circuit reversed Judge Goodwin’s decision in OVEC.  OVEC v. Bulen, 429 F.3d 493 (4^th Cir. 2005).    The 4^th Circuit held that it was clear from the record that the Corps made the required minimum impact determination before it issued NWP 21.  The 4^th Circuit further held that the CWA is silent on whether the Corps may make its pre-issuance minimal impact determination by relying in part on the fact that its post-issuance procedures will ensure that the authorized projects will have only minimal impacts.  The 4^th Circuit found that the Corps may do so if that conclusion is permissible in light of statutory language and is reasonable.  The 4^th Circuit held that the Corps’ conclusion was both. 

     The parties in Riverkeeper quickly advised Judge Bunning of their respective spins on the 4^th Circuit decision in OVEC and awaited a ruling on cross motions.  In the meantime, the 5 year period for the validity of the 2002 NWP 21 expired as 2007 emerged.   Thus, by the time Judge Bunning issued his opinion almost a year and a half later on March 26, 2007, he had determined that the issues raised concerning the 2002 NWP 21 were moot.  After making that finding, Judge Bunning asked the citizen groups to file a notice indicating any issues with the 2002 NWP 21 that they believed were not moot and to identify whether they intended to pursue the same challenges with regard to the 2007 NWP 21. 

     On April 10, 2007, the citizen group plaintiffs filed a response to the order along with a motion for reconsideration and a motion to supplement their original complaint to address the newly issued 2007 NWP 21.  The Corps and all other defendants, including industry associations,  opposed the requested relief with filings completed in May 2007.  Ten months later, on March 21^st of this year, Judge Bunning denied the citizen groups’ motion for reconsideration, but granted their motion to file a supplemental complaint to incorporate challenges to the 2007 NWP 21.  Answers to the supplemental complaint are due shortly.  In addition, two weeks ago on May 8, 2008, the citizen groups filed a notice of appeal of Judge Bunning’s order finding the issues concerning the 2002 NWP 21 to be moot.   

     During the pendency of the NWP 21 litigation, the Sierra Club and the Kentucky Waterways Alliance initiated an action on December 6, 2007 in the United States District Court for the Western District of Kentucky at Louisville to challenge an individual permit issued to ICG Hazard, LLC in Kentucky Waterways Alliance, Inc. et al v. U.S. Army Corps of Engineers, Case No. 3:07-cv-00677-CRS, before Judge Charles R. Simpson, III.  ICG Hazard immediately intervened as a defendant in the case.  On January 16, 2008, the Court granted the Corps’ request for a stay of the action while it completed reconsideration of the permit, including an effort to obtain additional information from the permittee.  Apparently, this action has effectively stalled all pending applications for such permits until a determination is made on ICG Hazard’s permit.  In the meantime, permit applications for mountaintop removal operations in Kentucky remain in limbo.

     This article was co-authored by Kevin McGuire and Mary Beth Naumann, Jackson Kelly PLLC. For more information on the authors see (McGuire) here and (Naumann) here. 

The Economics of Endangered Species

     On May 14, 2008, Dirk Kempthorne, Secretary of the Interior, accepted the recommendation of Dale Hall, Director of the U.S. Fish and Wildlife Service, to list the polar bear as a threatened species under the Endangered Species Act (“ESA”).  The listing was based on observations of trends in sea ice over the last three decades, as well as 10 peer-reviewed climate models predicting a further, sometimes dramatic, decline in Arctic sea ice throughout the 21^st century.  This loss of habitat puts polar bears at risk of becoming endangered in the foreseeable future, which is the standard for designating a species as “threatened” under the ESA.

     Frustrated that he was forced to declare the bear threatened and that he couldn’t avoid the listing on the grounds that the economic costs would be too high, Kempthorne announced that he would use the authority provided in Section 4(d) of the ESA to issue a rule stating that if an activity is permissible under the stricter standards imposed by the Marine Mammal Protection Act, it will also be permissible under the ESA with respect to the polar bear.  The rule, to be effective immediately, is meant to protect the polar bear while allowing the environmentally sound development of natural resources in the arctic region.  The proposed rule can be viewed at www.doi.gov/issues/polar_bears.html for a 60-day public comment period.

     In fact, Kempthorne made plain that the listing of the polar bear as threatened “should not open the door to use of the ESA to regulate greenhouse emissions from automobiles, power plants, and other sources.”  President Bush agrees:  “There is a right way and a wrong way to approach reducing greenhouse gas emissions.  The American people deserve an honest assessment of the costs, benefits and feasibility of any proposed solution.”

     These statements raise the question:  are species and the environment best served by economics?  Kempthorne noted, “I have now experienced the reality that the current ESA is among the most inflexible laws Congress has passed.  It prevents me, as Secretary, from taking into account economic conditions and adverse consequences in making listing decisions.”  However, some would argue that is why the ESA was enacted in the first place – to keep economics from trumping species.

     Virtually every government agency, industry and environmental group has crunched numbers on what it costs to address climate change and what it costs to ignore it.  This historic listing of the polar bear on the threatened species list – the first time a species has been listed due to global warming – will most surely prompt difficult discussions about balancing human welfare and activities with that of wildlife and the environment.

     Are environmental wares, whether they be polar bears or clean air, best protected with a dollar value assigned to them?  It remains to be seen.

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

DOE’s alternative FutureGen plans could mean federal tax dollars for WV

     The Energy Department announced May 7, 2008 it would spend up to $1.3 billion on multiple clean-coal power plants that would capture carbon emissions and permanently store them underground.  The announcement launches two weeks of public comment over the revised plan for the project known as FutureGen, which was detailed earlier on this blog. 

     The department decided it would be more prudent to spread the taxpayer money around to several smaller projects throughout the U.S. On Wednesday, Bud Albright, an undersecretary for the department, said Mattoon, Illinois — the site originally selected for the FutureGen project—was no long being considered.  DOE faces an uphill battle to implementing the revised plan, as Illinois Senator Rick Durbin has threatened to block White House appointments in an effort to keep FutureGen alive until the next administration takes office.

     Under DOE’s new plan, developers of power plants will have to apply to the Energy Department for a portion of the $1.3 billion this summer. To be eligible, each plant must permanently store underground at least 1 million metric tons of carbon dioxide a year. The sites also must capture at least 81 percent of the carbon dioxide, with a goal of reaching 90 percent.  The plants also must generate at least 300 megawatts of electricity.  The comment period on the Energy Department’s revised plan runs thru May 21.

     DOE’s decision to spread funding among various projects opens up the possibility that West Virginia may receive clean coal funding originally allocated to the Matoon, Illinois FutureGen project.  In 2003, DOE funded a $9 million project in which Consol began injecting CO2 into coal seams in the northern panhandle as part of a long-term carbon sequestration study.  A $2.2 billion “clean” coal-fired power plant proposed for West Virginia by AEP could potentially receive funding if carbon sequestration were added to its agenda.  The plant won’t initially include controls to capture and pump greenhouse gases underground. American Electric Power subsidiary Appalachian Power won state approval in March to build a 687-megawatt Integrated Gasification Combined Cycle plant in Mason County. The IGCC plant is considered cleaner because it produces electricity by burning gas made from coal. While the plant is expected to release less sulfur dioxide, nitrous oxide and mercury, it won’t be outfitted with a unit to capture and pump carbon dioxide underground.  The possibility remains that AEP could apply to DOE for funds originally allocated to FutureGen in order to add a carbon sequestration aspect to the Mason County plant. 

      While DOE’s decision to terminate the FutureGen project may present a temporary set-back to the development of clean coal technology on the whole, it could ultimately free up federal tax money for smaller projects here in West Virginia.  As the demand for energy coincides with increasing interest in controlling CO2 emissions, clean coal technology will most likely play a significant role in the coal industry and in West Virginia.  Moving forward, the challenge for our state will be to capitalize on these developments.

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

New Aerosol Coatings VOC Content/Ozone Reactivity Standard (40CFR59 Subpart E)

     The Clean Air Act (section 183(e)) directs EPA to list for regulation categories of consumer and commercial products that account for at least 80 percent of the volatile organic compound (VOC) emissions in areas that violate the national ambient air quality standards (NAAQS) for ozone.  Subsequent EPA rulemaking listed the aerosol spray paint category as a regulatory target for its VOC content. 

     On Nov. 15, 2007, EPA set national emission standards for aerosol spray paints, also known as aerosol coatings.  The reactivity-based VOC emission standards satisfy EPA’s Clean Air Act mandate to regulate VOC emissions from the aerosol spray paint category and to establish best available controls for this category.  The Direct Final Rule was recently published in the Federal Register (73 FR 15421-15425; March 24, 2008) as 40CFR59 Subpart E--National Volatile Organic Compound Emission Standards for Aerosol Coatings.  This direct final rule is effective on June 23, 2008, without further notice, unless EPA receives adverse comment.

     Per the EPA’s Fact Sheet on the new Aerosol Coatings VOC regulation:

• The compliance deadline for the rule is January 1, 2009. Companies subject to this rule must provide information about the amounts of each VOC in their products every three years, beginning with data for calendar year 2010. EPA will use this information to assess the effectiveness of the reactivity-based approach.

• Companies affected by the rule include manufacturers of lacquers, varnishes, enamels, epoxy coatings, oil and alkyd vehicle paints, plastisols, polyurethane, primers, shellacs, stains and water-repellant coatings.  Aerosol coating processors, can-filling operations and packaging services, and wholesale distributors also are affected by the rule.

• This national regulation, modeled after the California Air Resource Board (CARB) regulation for reducing ozone formed from aerosol coating emissions, establishes a uniform reactivity-based standard for aerosol spray paints.  The paints covered by this rule include both those used by the consumer and those used in industrial applications.

• Reactivity refers to a substance’s tendency to undergo a chemical change -- in this case, meaning a VOC’s potential to form ground-level ozone. Ozone forms when emissions of VOCs and nitrogen oxides react in the presence of sunlight.

• The emission limits in the national standard are expressed in terms of the amount of ozone generated per unit of coating material rather than in terms of the amount of VOCs per unit of product, as traditionally has been the case for mass-based standards. Organic compounds that are less reactive than ethane and make up less than 7.3 percent of a product’s formulation will not be counted toward the applicable limits of this rule.

• This new national rule will help reduce ozone formation by encouraging reductions of higher reactivity VOCs, rather than treating all VOCs in a product alike through a mass-based approach. EPA estimates that this regulation will result in reductions of 3,100 tons of VOCs per year.

• Nearly 85 percent of the spray paints used in the U.S.are produced by three companies, which already are meeting the CARB requirements. EPA may grant a two-year special compliance extension to manufacturers who certify that they previously have not produced aerosol coatings that comply with the existing CARB rule.

• Small U.S.manufacturers -- those that can demonstrate they produce aerosol paints containing less than 7,500 kilograms (about 8.3 tons) of VOCs annually -- are not covered by this regulation.

• The new requirements also apply to paint imported for sale in the U.S.  [Note: Per 40CFR59.501(d), the rule does not apply to aerosol coatings products that are manufactured (in or outside of the U.S.) exclusively for sale outside the U.S.].

     It’s important to keep in mind that a significant consequence (likely intended by EPA) of this rule will be to reduce demand for those coating formulation basic chemicals deemed to be highly reactive as regards ozone generation, and conversely will favor low ozone-generating organic chemical coating components. 

     The rule defines the concept of ozone reactivity at 40CFR59.503 as follows:

     Reactivity Factor (RF) is a measure of the change in mass of ozone formed by adding a gram of a VOC to the ambient atmosphere, expressed to hundredths of a gram (g O3/g VOC). The RF values for individual compounds and hydrocarbon solvent mixtures are specified in Tables 2A, 2B, and 2C of this subpart.

     Product-Weighted Reactivity (PWR) Limit means the maximum allowed "product-weighted reactivity," as calculated in §59.505, of an aerosol coating product that is subject to the limits specified in §59.504 for a specific category, expressed as grams of ozone per gram (g O3/g of product).

For more details on the revised NAAQS, see the new regulatory text at 40CFR59 Subpart E, as published in the Federal Register 73 FR 15421-15425 (March 24, 2008).

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

Fourth Circuit Remands Case for Determination of Environmental Groups’ Standing

     The United States Court of Appeals for the Fourth Circuit recently remanded a case for a factual determination regarding two environmental groups’ standing to bring a Clean Water Act citizens’ suit.  In Friends of the Earth, Inc. v. Gaston Copper Recycling Corp., 2008 WL 344689 (4^th Cir. 2008), the Friends of the Earth, a national environmental group, and Citizens Local Environmental Network (“CLEAN”) brought a citizens’ suit against Gaston Copper Recycling, Inc. for violations of Gaston’s NPDES permit.  The permit was issued by the South Carolina Department of Health and Environmental Control (“DHEC”) and authorized discharges into Boggy Branch, an indirect tributary of the Edisto River.

     The District Court originally dismissed the suit for lack of standing because the plaintiffs failed to show that any of their members suffered an injury fairly traceable to Gaston’s conduct.  The Fourth Circuit affirmed.  Friends of the Earth, Inc. v. Gaston Copper Recycling Corp., 173 F. 2d 107, 116 (4^th Cir. 1999).  The appeals court granted a rehearing en banc and reversed holding that CLEAN had established standing through one of its members, William Shealy.  Friends of the Earth, Inc. v. Gaston Copper Recycling Corp., 204 F. 3d 149 (4^th Cir. 2000) (en banc).  Shealy owned a lake and a home four miles downstream of Gaston’s discharges.  The Court’s decision was based on DHEC’s written response to a landowner stating “runoff” would reach his property and travel 16.5 miles downstream of Gaston’s discharge to the confluence of Bull Swamp and the Edisto River.  On remand, the district court found Gaston violated effluent limits on 91 days and imposed a civil penalty of $2,340,000. 

     Unfortunately, Mr. Shealy died prior to the judgment and the plaintiffs filed a post-trial motion contending that they still had standing through two members who used waters downstream of the confluence of Boggy Run and the Edisto River.  One of the members, Jones, was a boating and outdoor equipment retailer who provided canoe trips to the public including trips on the Edisto River downstream of Gaston’s discharge point.  Jones testified that his guides and clients tended to go into the water in the downstream area.  Jones asserted that his business was dependent on water quality and he understood that heavy metals may be present in the water adversely affecting his enjoyment of canoeing and swimming.  The other member, McCulloch, testified that he scuba dived and planned to go canoeing in downstream areas.  He stated that he would be less likely to engage in these activities if he knew the water was polluted.

     The District Court held that Jones and McCulloch provided standing for Friends of the Earth and CLEAN and denied the plaintiffs’ motion to supplement the record with the testimony of other members.

     The Court of Appeals disagreed.  The Court rejected Gaston’s argument that “concern” for the waters used by the plaintiffs’ members absent evidence of actual contamination was insufficient to establish standing citing its earlier en banc opinion that scientific proof of harm to the environment is not necessary where there is a direct nexus between the plaintiff and the area of environmental impairment.  However, the Court held that the evidence did not establish whether Jones and/or McCulloch used the waters referenced by DHEC as receiving run-off or, whether other downstream waters they used may have also received run-off.  The Court of Appeals remanded the case for determination of these issues.

     Interestingly, the Court referenced a Fifth Circuit Court of Appeals case, Friends of the Earth v. Crown Central Petroleum Corp., 95 F. 3d 358 (5^th Cir. 1990), which held that downstream water users, some 18 miles from the discharge point, could not use the truism that water flows downstream to establish an injury that could fairly be attributable to the upstream discharge and therefore have standing.

     The Court of Appeals’ decision is curious.  On one hand it rejects the need for scientific evidence that area used by the plaintiff is affected.  On the other, it seems to require exactly that type of evidence for downstream water users to have standing.

     This article was authored by Janes R. Snyder, Jackson Kelly PLLC.  For more information on the author see here.

New Lead Rules: Major Impact for Building Trades

     April 22, 2008 EPA issued a new final rule, effective June 23, 2008 likely to have a similar impact as the asbestos rules on the building industry sector, specifically on renovation, repair and painting. The new rule, promulgated pursuant to section 402(c)(3) of the Toxic Substances Control Act (TSCA) addresses lead-based paint hazards created by renovation, repair, and painting activities that disturb lead-based paint in "target housing" and child- occupied facilities. "Target housing" is defined in TSCA section 401 as any housing constructed before 1978, except housing for the elderly or persons with disabilities (unless any child under age 6 resides or is expected to reside in such housing) or any 0-bedroom dwelling. Under this rule, a child-occupied facility is a building, or a portion of a building, constructed prior to 1978, visited regularly by the same child, under 6 years of age, on at least two different days within any week (Sunday through Saturday period), provided that each day's visit lasts at least 3 hours and the combined weekly visits last at least 6 hours, and the combined annual visits last at least 60 hours. Child- occupied facilities may be located in public or commercial buildings or in target housing. The broad definition will easily cover locations such as churches which provide for child care and even those churches where children come for Sunday morning and evening services and Wednesday night services (easily 6 hours of time). 

     Persons performing renovations for compensation of "target housing" or "child-occupied facilities" are affected by the rule which establishes requirements for training renovators, other renovation workers, and dust sampling technicians; for certifying renovators, dust sampling technicians, and renovation firms; for accrediting providers of renovation and dust sampling technician training; for renovation work practices; and for recordkeeping. The rule will affect paid renovators who work in pre-1978 housing and child-occupied facilities, including:

• Renovation contractors
• Maintenance workers in multi-family housing
• Painters and other specialty trades.

     The requirements apply to renovation, repair or painting activities. The rule does not apply to minor maintenance or repair activities where less than six square feet of lead-based paint is disturbed in a room or where less then 20 square feet of lead-based paint is disturbed on the exterior. Window replacement is not minor maintenance or repair.

     By NAIC code potentially affected entities may include, but are not limited to:

• Building construction (NAICS code 236), e.g., single family housing construction, multi-family housing construction, residential remodelers.

• Specialty trade contractors (NAICS code 238), e.g., plumbing, heating, and air-conditioning contractors, painting and wall covering contractors, electrical contractors, finish carpentry contractors, drywall and insulation contractors, siding contractors, tile and terrazzo contractors, glass and glazing contractors.

• Real estate (NAICS code 531), e.g., lessors of residential buildings and dwellings, residential property managers.

• Child day care services (NAICS code 624410).

• Elementary and secondary schools (NAICS code 611110), e.g., elementary schools with kindergarten classrooms

     Interested States may apply for and receive authorization to administer and enforce all of the elements of these new renovation requirements. The full rule may be viewed at 78 FR 21691-21769 (April 22, 2008).

     In conjunction with the new rule EPA has provide a new lead hazard information pamphlet for renovation activities, "Renovate Right: Lead Hazard Information for Families, Child Care Providers and Schools" (Renovate Right). This new pamphlet gives information on lead-based paint hazards, lead testing, how to select a contractor, what precautions to take during the renovation, and proper cleanup activities. After June 23, 2008, the new pamphlet or Protect Your Family From Lead in Your Home may be used for compliance with the Pre- Renovation Education Rule under TSCA section 406(b). After December 22, 2008, the new pamphlet must be used exclusively.

     The regulation and new pamphlet as well as other relevant information may be accessed at http://www.epa.gov/oppt/lead/pubs/renovation.html.

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

GHG Reporting: The Climate Registry Releases Its Final General Reporting Protocol

     On March 31, 2008, the Climate Registry released its final General Reporting Protocol (GRP) for measuring, reporting, and verifying emissions of greenhouse gases (GHGs).  The Registry is a 501(c)(3) organization founded by participating U.S. states, Native American tribes, Canadian provinces, and Mexican states.  While West Virginia is not a participating state, currently at least 39 U.S. states and the District of Columbia are members.  It is hoped by some that U.S. EPA will consider the Registry’s GRP in developing the Agency’s GHG reporting rule that Congress recently mandated the Agency propose by September 2008 and finalize by June 2009.

     The GRP is expected to support both voluntary and mandatory GHG reporting policies. It outlines reporting requirements and tools that apply to all participating entities for GHG reporting, including policy guidelines, technical guidelines, quantification methodologies, and administrative deadlines.  The Registry is developing additional industry-specific protocols for GHG reporting in sectors with specialized sources, such as electric utilities. 

    Highlights of the Registry’s GRP include the following: 

1.                  Geographic Boundaries:  The Registry requires participants to report all emissions in Canada, New Mexico, and the U.S. Reporting of worldwide emissions is optional.

2.                  Greenhouse Gases:  Reporters are required to report the six internationally recognized GHGs regulated under the Kyoto Protocol:  carbon dioxide (CO₂); methane (CH₄); nitrous oxide (N₂O); hydrofluorocarbons (HFCs); perfluorocarbons (PFCs); and sulfur hexafluoride (SF₆).  Emissions of each gas must be reported separately.  There is no de minimis provision.  Entities must report 100% of their emissions.  Reporting of additional GHGs is optional. 

3.                  Organizational Boundaries:  The Registry requires members to report their entity-wide emissions for their organization.   The organization must be a legal entity as defined by U.S., Canadian, or Mexican law.  In addition, government agencies may report as separate legal entities.  The GRP encourages organizations and state and municipal governments to report at the highest organizational level.  In defining organizational boundaries, the Registry takes two approaches: the “equity share” approach and the “control” approach.  Under the equity share approach, the organization must report all emissions sources that are wholly owned and partially owned according to the entity’s equity share in each.  Under the control approach, the organization is required to report 100% of the emissions from sources that are under its control, including both wholly owned and partially owned sources.  When using the control approach, emissions must be consolidated under either operational control or financial control. 

4.                  Operational Boundaries:  To provide an accounting framework, the Registry categorizes direct and indirect emissions into “scopes” and requires members to report as “scope 1” all direct GHG emissions (with the exception of direct CO₂ emissions from biomass combustion) and as “scope 2” all indirect GHG emissions associated with the consumption of purchased or acquired electricity, steam, heating, or cooling.  All other indirect emissions not covered in “scope 2,” such as upstream and downstream emissions, emissions resulting from the extraction and production of purchased materials and fuels, transport-related activities in vehicles not owned or control by the reporting entity, are categorized as “scope 3”.  CO₂ emissions from biomass combustion must be reported separately from the scopes.  Reporting of “scope 3” emissions is optional.   

5.                  Facility-Level Reporting:  Entities are required to report emissions separately for each of their facilities within their organizational boundary.  A facility is generally defined as a single physical premise.  Each pipeline, pipeline system, or electricity transmission and distribution (T&D) system is also treated as a single facility.  If a pipeline or transmission and distribution system crosses a state, provincial, or national boundary, then the system is to be subdivided into two separate facilities along the boundary if it is possible to determine emissions separately for the two, newly defined facilities.  If it is not possible to determine emissions separately for the two facilities, then the Registry explains how to report the emissions from the pipeline or T&D system. The Registry allows optional aggregation of emissions from certain types of facilities, such as commercial buildings and mobile sources.

6.                  Base Year:  Entities are required to establish a base year.  Base year is defined as the first reporting year the entity submits complete GHG data to the Registry. 

7.                  Transitional Reporting: For entities that do not have complete GHG data, transitional reporting is allowed the first two reporting years.  Several options are available.  Transitional Reporters may opt to limit their emissions report to one or more countries, states, or provinces, rather than reporting all North American emissions, or in the alternative, may opt to report fewer than the six internationally recognized GHGs and/or fewer than all of their emission sources.  While the Registry offers some reporting flexibility, there are certain minimum reporting requirements.  A transitional reporter must report at least all CO₂ emissions from stationary combustion for all of its operations in at least one state or province.  In addition, all transitional reports must be third-party verified by a Registry-approved verifier, and once verified and accepted by the Registry, transitional reports will be disclosed to the public.

8.                  Reporting Historical Data:  The Registry offers an option for reporting historical data, defined as all years prior to the first reporting year.  If an entity opts to report historical data, then the Registry requires that consecutive years of data through the first reporting year be included.  Gaps in historical time series or between historical data and the first reporting year are not acceptable.  As in the case of transitional reports, the Registry has set certain minimum reporting requirements for historical data.  All historical emission reports must include at least entity-level emissions of CO₂ from stationary combustion for all operations in at least one state or province and be third-party verified.  If the data has already been verified under another program, the data does not need to be verified by a Registry-approved verifier.  The Registry requires that a formal written attestation of verified data by a credible verifier accompany the historical emission report.  Like transitional and complete data, historical data is also subject to public disclosure.

9.                  Quantifying Emissions:  Reporters may use Registry-approved calculation methods or a simplified estimation method for a portion of their emissions that fall below a threshold.  The threshold is 5% of their total entity emissions. 

10.              Third-Party Verification:  Emission reports must be verified by accredited third-party verifiers.  The Registry allows the Reporter to select a Registry-approved verifier.  The verifier is required to conduct a case-specific evaluation of conflict of interest assessment.  If the risk of a conflict of interest between the parties is “low,” then the verifier and the Reporter finalize their contract and the verifier submits a verification notification form to the Registry.  The verifier then conducts core verification activities, prepares verification documentation for the Reporter, and submits the verification documentation to the Registry via CRIS.  The Registry then reviews and evaluates the submission.

11.              Public Disclosure:  The Registry requires Reporters to disclose their entity- and facility-level GHG emission reports to the public.  Once accepted by the Registry, verified annual emission reports are available to the public through CRIS.  If disclosing facility-level data publically will jeopardize confidential business information, then Reporters may apply for an exemption.  Reporters who are granted exemption will be required to disclose to the public entity-level emissions, by gas and emissions category and state/province-level emissions by CO₂ equivalent (CO₂-e).

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