Energy and Environment Monitorwww.eem.jacksonkelly.com

FutureGen Update

     Senators Dick Durbin (D-IL) and Kitt Bond (R-MO) called on U.S. Secretary of Energy Samuel Bodman to support extending the current budget period for the Cooperative Agreement between the Department of Energy (DOE) and the FutureGen Alliance. The agreement is set to expire on June 15. As detailed previously on this site, Bodman announced last spring that DOE would not fund the project. Once completed, the plant would be the world’s first near zero emissions coal fueled electricity plant. DOE had committed to partially fund construction of the plant in partnership with the FutureGen Alliance, a private consortium of leading coal and electricity producers. 

     The uncertainty of the FutureGen project is disappointing; however, the march towards clean coal technology continues.  West Virginia Governor Joe Manchin, the first keynote speaker at the spring meeting of the West Virginia Coal Association mentioned clean coal technology numerous times during his address.  Gov. Manchin suggested a partnership with China, wherein China would invest in technology being developed in West Virginia for use in Asia.  Given China's growing energy needs and its' pollution concerns, such a partnership seems like a no-brainer.  Gov. Manchin also told the crowd he has spoken to Senators Obama and Clinton, as well as Speaker of the House, Nancy Pelosi, about investing in clean coal technology.

   The interest in clean coal technology extends beyond Appalachia.  The International Energy Agency (IEA) recently referred to DOE’s Regional Carbon Sequestration Partnerships and their large-scale CO2 tests as the world’s most ambitious carbon capture and storage projects.  The regional projects have entered Phase Three and are now focused on large-scale tests involving a million tons or more of CO2 injected each year.  The IEA’s findings validate carbon capture and storage projects as being pragmatic and attainable.  The fact that no other country is pursuing a project as ambitious as DOE’s indicates that the U.S. will be the leader in clean-coal technology.   

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

What do you know about the Marcellus shale?

     The Marcellus shale has been talked about in the Oil & Natural Gas field for years. The geological setting of the Marcellus shale has been both an advantage and a disadvantage. Due to expanding technologies in drilling methods, the Marcellus shale is now a hot topic. Within the last five years, residents of New York, Pennsylvania, and West Virginia have learned what the Marcellus Shale could mean for them both economically and environmentally.

The geology of the Marcellus shale.

     Shales are sedimentary rocks which are very fragile. Shales are very thinly laminated and are known to break easily along the thin bedding layers as well as along irregular fractures. This property of shales is what allows the natural gas to be contained within as well as move throughout the bedding layers and fractures. The Marcellus shale is a “black shale” which merely refers to its high organic content. The Marcellus shale is located in the Hamilton Group, of the Middle Devonian epoch, of the Devonian period, in the Paleozoic era, of the Phanerozoic eon. The Middle Devonian epoch lasted from approximately 400 to 385 million years ago.

     Figure 1 shows where the Marcellus shale can be found in Kentucky, Maryland, New York, Ohio, Pennsylvania, Virginia, and West Virginia. Due to different depositional environments, different geological layers are not always laterally contiguous. Because of this fact, the Marcellus shale is more prevalent and productive in different areas. This is why the Marcellus shale is more economically viable in Pennsylvania than in Ohio. The Marcellus shale is a promising natural gas reservoir in locations where its position is between two impermeable layers of limestone, typically the Onondaga and Tully Limestones.

Why is the Marcellus shale important now?

     As indicated by the age of the Marcellus shale, it is found deep below the surface and therefore, very expensive to reach. The low permeability of the constraining limestone layers and the Marcellus shale also restricts the potential of the permeability within the Marcellus shale layer. Due to increase in demand and therefore price of natural gas as well as an improvement in drilling technologies, drilling horizontal wells in combination with more traditional vertical wells and hydrofracing, The Marcellus shale is an economically viable option to increase production of natural gas for the Eastern United States. Figure 2 shows how a fraced horizontally drilled well’s production would theoretically increase from the combination of the lateral constraints of the under- and over-lying limestone layers as well as the vertical fracturing of the shale material.

Problems with the Marcellus shale?

     As with every new opportunity, there are some possible drawbacks to the development of the Marcellus shale. The cost of drilling a well with intentions of reaching the Marcellus shale can cost in excess of 1 million dollars. The upside to this money being spent is the fact that a significant portion of this money is being put back into the local economy of these areas which have typically be void of a major source of economic stimulus like this for some time. A recent development on the Marcellus shale front has been the realization that the Marcellus shale is actually contains naturally-occurring radioactive material and therefore adds further complexity to the drilling process. This is just one environmental concern posed by this new development of the Marcellus shale. To deal with these issues, the Pennsylvania Department of Environmental Protection, local soil & water conservation districts, and watershed management groups are constantly evolving with new regulations to protect the environment. In light of the potential problems, there are good things developing out of the Marcellus shale. A search on the website www.wikipedia.org on the Marcellus Formation leaves us with a show stopping quote, “State University of New York at Fredonia geology professor Gary Lash had calculated that more than 500 trillion cubic feet of natural gas may be contained in the Marcellus black shale beds that lie between New York state and West Virginia. At the present level of technology, he believes approximately 10 % of this, or 50 trillion cubic feet, could be recovered. This is enough to satisfy approximately two years’ of total U.S. consumption, or a total value of approximately 1 TRILLION United States dollars.”

These resources utilized for this information on the Marcellus shale are just the tip of the iceberg: 

News about Natural Gas from shale. <http://shaleblog.com/category/marcellus-shale/> July 14, 2008. (Accessed July 24, 2008)

Marcellus Shale: News, Videos, Maps, Lease and Royalty Information. <http://geology.com/articles/marcellus-leases-royalties.shtml> (Accessed July 24, 2008)

Interested in Devonian Shales? Selected References about Devonian Shales. <http://www.wvgs.wvnet.edu/www/datastat/devshales.htm> April 7, 2008. (Accessed July 24, 2008)

Marcellus Formation. <http://en.wikipedia.org/wiki/Marcellus_Formation#Named_members> (Accessed July 24, 2008)

Are you interested in learning about helping your business “go green?”  Two of the workshops have already passed, but there is still one remaining.  Do not miss it!

As published in Charleston’s Daily  Mail.

Free Environmental Management Systems workshops offered to businesses

“Speakers provide guidance on how businesses can ‘go green’.”

CHARLESTON - State businesses and organizations will have the opportunity to learn about "going green," how to improve their environmental performance and reduce the size of their environmental footprint by attending upcoming Environmental Management System workshops sponsored by the West Virginia Department of Environmental Protection and the National Pollution Prevention Roundtable.

There will be three, two-day workshops in two different locations. Each will be directed and instructed by Adolfson and Jeffrey Burke, Executive Director of the National Pollution Prevention Roundtable, both of whom are certified EMS Lead Auditors.  The EMS workshops also will include guest presenters from West Virginia industries that are going green and have also adopted EMS concepts and principles as their guide.  The representatives will share their EMS experiences and case studies to better educate workshop participants.

Three identical two-day EMS workshops are being offered as follows: 

July 8-9, 2008 (Registration Deadline: June 18, 2008)

Charleston, West Virginia

West Virginia Department of Environmental Protection Headquarters

601 57th Street, SouthEast
Charleston, WV   25304

(304) 926-0440

July 10-11, 2008 (Registration Deadline: June 18, 2008)

Charleston, West Virginia
West Virginia Department of Environmental Protection Headquarters

601 57th Street, South East
Charleston, WV  25304
(304) 926-0440

September 9-10, 2008 (Registration Deadline: August 20, 2008)
Martinsburg, West Virginia
Holiday Inn
301 Foxcroft Avenue

Martinsburg, WV  25401
(304) 267-5500

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

EPA Grants Available for Diesel Engine Emission Reduction Projects

     July 21, 2008 EPA announced plans to award approximately $3.4 million in grants to establish projects using emerging technologies to reduce emissions from the nation's existing fleet of diesel engines. Addressing the existing fleet is important because it pre-dates EPA's stringent new particulate and nitrogen oxide standards and diesels remain in use for decades. This sum was authorized by the Energy Policy Act of 2005 and funded for the first time this fiscal year.

     State, local, regional and tribal governments may apply for the grants, as well as non-profits and institutions with transportation, educational service, and air quality responsibilities. Emerging technology manufacturers must partner with an eligible applicant to receive this funding. The grants are targeting school or transit buses, medium and heavy-duty trucks, marine engines, locomotives and non-road engines. Grant proposals must be submitted by Sept. 21, 2008. The final awards will be announced in December.

     EPA's National Clean Diesel Campaign under the Emerging Technology Program (ETP) will administer the grants. An emerging technology is a device or strategy that reduces emissions from diesel engines or equipment that has not been verified or certified by EPA or the California Air Resources Board (ARB). To qualify as an emerging technology, manufacturers must submit an application and test plan to EPA or ARB.

     Each technology will be reviewed on a case-by-case basis to determine if it qualifies as an emerging technology.

     Qualified emerging technologies will be added to the Emerging Technologies List. The first three qualifying technologies are: 1) Caterpillars' Marine Emissions Upgrade Group (EUG), the 3500 Marine EUG; 2) Johnson Matthey's urea-based selective catalytic reduction (SCR) system for on-highway applications, the SCRT-1000; 3) and Nett Technologies' urea-based SCR for nonroad applications, the BlueMAX. Specifics of each technology including the emission reductions and engine applications can be found on the Emerging Technology List: www.epa.gov/otaq/diesel/prgemerglist.htm

     For more information about this grant: http://www.epa.gov/otaq/diesel/grantfund.htm

     For more information about the Emerging Technology Program: http://www.epa.gov/otaq/diesel/prgemerg.htm

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

EPA 2008 Construction Stormwater General NPDES Permit

     July 14, 2008 EPA Regions 1, 3 (includes West Virginia, Virginia and Pennsylvania), 6, 7, 8, 9, and 10 issued the 2008 National Pollutant Discharge Elimination System (NPDES) general permits for stormwater discharges from new dischargers engaged in large and small construction activities. (“2008 construction general permit”') The EPA general permit is back-dated to be effective June 30, 2008 in those States without EPA-approved construction storm water general permit programs. States may revise their current stormwater construction general permits if they differ substantially from the new EPA general stormwater permit.

     “New dischargers” are those who did not file a notice of intent (“NOI'') to be covered under the 2003 construction general permit before it expired July 1, 2008. Existing dischargers who properly filed an NOI to be covered under the 2003 construction general permit continue to be authorized to discharge under that permit according to its terms. The 2008 construction general permit contains the same limits and conditions as the Agency's 2003 construction general permit with the exception of a few minor modifications which are detailed below. The 2008 construction general permit is available to new construction and unpermitted ongoing activities only. The 2008 permit will be issued only for 2 years due to the pending promulgation of effluent limitation guidelines and standards for the construction and development industry. EPA is required by court order to propose effluent limitations guidelines and new source performance standards for the construction and development industry by December 2008, and promulgate those effluent guidelines by December 2009. (See Natural Resources Defense Council, et al. v. EPA, (C.D. Cal. December 5, 2006). EPA projects that the Agency may publish a proposed rule ahead of the court-ordered deadlines. If EPA publishes the proposed rule ahead of schedule, this may allow the Agency to promulgate a final rule ahead of schedule as well. The Agency currently hopes to promulgate a final rule as early as December 2008.

     The 2008 construction general permit includes conditions and limits that are nearly identical to the 2003 construction general permit, with the exception that the 2008 construction general permit only applies to new and unpermitted ongoing construction projects. Discharges from ongoing projects (or “existing dischargers”) will continue to be covered under the existing 2003 permit. However, EPA clarifies that if an operator of a permitted ongoing project transfers ownership of the project, or a portion thereof, to a different operator, that subsequent operator is required to submit a complete and accurate NOI for a new project under the 2008 construction general permit.)

     Construction operators choosing to be covered by the 2008 construction general permit CGP must certify in their notice of intent that they meet the requisite eligibility requirements, described in Part 1.3 of the permit. If eligible, operators are authorized to discharge under this permit in accordance with Part 2. Permittees must install and implement control measures to meet the effluent limits applicable to all dischargers in Part 3, and must inspect such stormwater controls and repair or modify them in accordance with Part 4. The permit in Part 5 requires all construction operators to prepare a stormwater pollution prevention plan (SWPPP) that identifies all sources of pollution, and describes control measures used to minimize pollutants discharged from the construction site. Part 6 details the requirements for terminating coverage under the permit.

     The primary changes from the 2003 construction general stormwater permit is that the 2008 Permit was clarified to clearly distinguish between the effluent limits from the documentation requirements relating to the development of the SWPPP.

     The effluent limitations (in Part 3) are permit requirements to which all permittees are subject in order to minimize the discharge of pollutants from the site, while the SWPPP (in Part 5) is a planning document that must be prepared by all construction operators that describes the site and the pollutants discharged, and documents the control measures selected, installed, and maintained to meet the effluent limitations in Part 3. Additionally, the inspection requirements, which were previously included in the SWPPP section, have been moved to a separate section (Part 4) to highlight their importance. EPA emphasizes that though the permit has been reorganized, the requirements themselves have not been substantially changed.

     The two new requirements of the 2008 construction general permit are:

(1) A requirement to educate employees or subcontractors as necessary so that they understand their role in implementing stormwater controls (Part 3.6); and

(2) A requirement to remove sediment from silt fences before the deposit reaches fifty percent of the above-ground fence height.

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

Current Selenium Issues Faced by the Mining Industry in West Virginia

     EPA’s current recommended water quality concentration for selenium in surface waters that support aquatic life is 5 ug/l (parts per billion) (chronic).  Selenium bioaccumulates in fish and, at certain levels, can cause birth defects and eradicate fish populations.  The current standard derives from studies done on Belews Lake in North Carolina, where the fish population suffered greatly after receiving selenium from decant water from a flyash disposal facility. 

     USEPA has since determined, however, that selenium bioaccumulates at slower rates in faster moving water, and that faster flowing streams can contain higher levels of selenium without apparent impacts to fish.  To account for the different bioaccumulation rates, USEPA is in the process of adopting a new aquatic life water quality criterion that is expressed in terms of fish tissue and/or fish ovary concentrations rather than water quality concentrations.  Its work, however, will not be finished until sometime in 2009.

     When the United States undertook a programmatic environmental impact statement on mountaintop mining in West Virginia early this decade, it discovered selenium levels exceeding 5 ug/l in a number of mined watersheds.  Subsequent work by West Virginia University’s National Mine Land Reclamation Center confirmed that the source of much of this selenium was excess spoil valley fills.  Later work by WVU and others determined that the source rock is typically certain coal seams and black shales located near those same seams.  In the past, this rock was not selectively handled and made its way into valley fills where water has leached out the selenium. 

     The identification of the source rock was crucial, because it allowed the regulatory agencies and industry to identify the material and to develop mechanisms for preventing future selenium discharges.  As a consequence, WVDEP now requires surface mine permit applicants to sample their overburden for selenium and to selectively handle any material that contains more than 1 mg/kg (ppm) of selenium—in much the same way that industry handles potentially acid-producing overburden.  Theoretically, this should prevent the creation of new long-term sources of selenium discharges.  Absent the development of this procedure, the West Virginia coal industry faced outright denials of permit applications (because WVDEP takes the position that mine operators must be able to demonstrate that they can reclaim a mine, and that reclamation means being able eventually to meet effluent limits without the need for perpetual treatment).  See USGS discussion: http://ky.water.usgs.gov/hydro_ws_2005/ppt_talks/Selenium_HydroWksp2.ppt.

     After WVDEP adopted a policy for preventing new sources of selenium, it turned to dealing with the existing sources.  It modified over 80 mining-related NPDES permits, adding selenium limits and requiring compliance within three years.  Because USEPA was then in the process of modifying the water quality standard from a water concentration to a fish tissue concentration, many believed that the change was imminent and would solve their compliance issues.  Some of these operators later learned, though, that fish downstream of their operations contained higher selenium levels than would be allowed by USEPA’s proposed fish tissue standard.  Others, undertaking to examine treatment options, soon became dismayed.  Selenium can take different forms, the two most common being: selenite and selenate.  Selenite is more toxic but more readily treatable.  Selenate is less toxic but resists easy treatment.  Most of the selenium emerging from valley fills proved to be selenate.

     The three-year compliance period originally imposed by WVDEP came and went without a solution in the form of either a change in the water quality criterion or a clearly feasible treatment technology.  As a result, in early 2007, WVDEP extended the compliance period for 80-plus permittees for up to another three years—until April 2010.  Environmental groups challenged those extensions in an appeal to the State Environmental Quality Board.  In June of 2008, the EQB issued an order that largely rejected those challenges, but it did remand the compliance orders to WVDEP to require that it make permit-specific findings about the need for the three-year compliance schedule.

     In the meantime, a couple of mine operators discovered that they had finally effective selenium limits for which WVDEP had not granted a compliance schedule.  They have found themselves subject to federal citizens’ suits by environmental groups under the Clean Water Act.  They are grappling with the need to come into immediate compliance with effluent limits set around 5 ug/l and are finding the challenge daunting.

     Dr. Ray Lovett, a chemist who worked with WVU under an OSM contract to explore feasible treatment technologies, has developed a “zero valent iron” technology which consists of running mine water through drums packed with iron wool.  Given the right topography, the system may not require power, and at lower flows may enjoy considerable advantages over other technologies.  The system has undergone pilot testing at some sites in West Virginia and is set to go into full-scale usage at some sites this summer.  However, Dr. Lovett recently acknowledged that at higher base flows (perhaps those over 200 gpm) his system may not be more cost effective than other technologies and will require substantial space for additional trains of iron wool-containing drums.   

     In a recent proceeding in one of the Clean Water Act citizens suits pending in West Virginia, a federal judge convened a hearing to determine if one mine operator should be required to comply with his earlier order that it meet its selenium limits of 5 ppb within 120 days.  The plaintiffs called two witnesses.  The first, a wastewater treatment engineer from New York, testified that Dr. Lovett’s technology was only in its infancy and likely would not work until it undergoes much more testing and “debugging.”  The second witness, Dr. Brad Culkin, is the founder and chief technology officer of New Logic Research (http://www.vsep.com), the manufacturer of a specialized reverse osmosis (“RO”) process that relies on a patented vibrating membrane to purify water without suffering the same degree of fouling to which many RO technologies succumb. 

     Culkin guaranteed that his technology will work; that it can be adjusted to produce a wastestream of concentrated brine constituting of less than 2% of the influent; and that he could have a set of plans prepared in about 4 weeks and a unit manufactured and installed 4 to 6 months thereafter.  He conceded, though, that the wastestream might be a hazardous waste, that he does not know what facilities there are to accept it and that the capital costs would run between $5.00-10.00 per gpm.  Thus, for a 1,000 gpm site, the capital costs alone would be between $5-10 million.  The Court did not order the operator to meet limits in 120 days, but will likely expect a plan that is designed to meet limits 4-6 months after a technology is identified. 

     Coal operators with selenium discharges face an uncertain and potentially expensive future.  Environmental groups will push hard to impose these costs on mine operators as soon as possible.  Prudent operators will enlist help now in exploring available treatment options.

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

D.C. Circuit Vacates CAIR

     On July 11, 2008, the D.C, Circuit dramatically changed the air regulatory landscape when it rendered its decision in North Carolina v. EPA, No. 05-1244, vacating U.S. EPA’s Clean Air Interstate Rule (CAIR). CAIR would have significantly reduced SO2 and NOx emissions from power plants in the eastern United States and helped states achieve the 1997 8-hour ozone and PM2.5 national ambient air quality standards (NAAQS). The D.C. Circuit vacated CAIR “in its entirety” because the court found “more than several fatal flaws” and because U.S. EPA adopted the rule as “one, integral action.” Slip op. at 4. Major issues addressed in the decision include: unrestricted interstate trading programs; U.S. EPA’s interpretation of the “interfere with maintenance” prong of Section 110(a)(2)(D)(i)(I) of the Clean Air Act; the 2015 compliance deadline for Phase 2 NOx and SO2 reductions; the NOx Compliance Supplement Pool; the SO2 and NOx budgets; U.S. EPA’s mandatory retirement ratios for Title IV allowances; and border state issues pertaining to Texas, Florida, and Minnesota.

     The D.C. Circuit agreed with North Carolina’s challenge to unrestricted interstate trading finding that Section 110(a)(2)(D)(i)(I) requires EPA to promulgate a rule that “achieves something measurable toward the goal of prohibiting sources ‘within the State’ from contributing to nonattainment or interfering with maintenance ‘in any other State’.” Slip op. at 16 & 17. Further, because U.S. EPA designed CAIR as a complete remedy to interstate transport, the court said “CAIR must do more than achieve something measurable; it must actually require elimination of emissions from sources that contribute significantly and interfere with maintenance in downwind nonattainment areas.” Id. at 17. CAIR did not do this because EPA calculated regionwide emissions budgets and not “state-specific quantitative contribution determinations or emission requirements”. The D.C. Circuit did not say that intrastate trading is unlawful, however.

     The D.C. Circuit further found that U.S. EPA nullified the “interfere with maintenance” language in Section 110(a)(2)(D)(i)(I) because CAIR “provides no protection for downwind areas that…still find themselves struggling to meet NAAQS due to upwind interference in 2010.” Id. at 22. On remand, U.S. EPA must reconsider the States included in CAIR and can reasonably be expected to expand the CAIR Region. Id. at 59.

     Regarding the 2015 compliance deadline, the D.C. Circuit agreed with North Carolina that EPA based the 2015 deadline “solely on reasons of feasibility’. Id. at 23. On remand, EPA must “harmonize CAIR’s Phase Two deadline for upwind contributors to eliminate their significant contribution with the attainment deadlines for downwind areas,” which is April 2010 for PM2.5 nonattainment areas. Id. at 24. Following remand, the compliance deadline for Phase 2 NOx and SO2 reductions may be sooner than 2015.

     U.S. EPA created the NOx Compliance Supplement Pool “under the assumption that 2015 was an appropriate deadline for CAIR compliance.” Because it is not, the D.C. Circuit directed U.S. EPA on remand to “determine what level of emissions constitutes an upwind state’s significant contribution to a downwind nonattainment area,…includ[ing] the deadlines for attainment of NAAQS” and to “set the emissions reduction levels accordingly.” Id. at 27.

     The D.C. Circuit also agreed with petitioners challenging EPA’s SO2 and NOx budgets. The court said that the SO2 trading program with its retirement ratios for Title IV allowances was unlawful “because it does not connect states’ emissions reductions to any measure of their own significant contributions.” Id. at 59. The court found the NOx budgets based on fuel-adjustment factors to be similarly arbitrary “because EPA distributed allowances simply in the interest of fairness.” Id.

     Finally, the D.C. Circuit denied the petitions of the Florida and Texas petitioners but granted the petition of the Minnesota petitioner because U.S. EPA had failed to address.

     U.S. EPA now has 45 days to petition for rehearing. Remand proceedings may take 18 months or longer. States and/or Congress may take action. In the meantime, the NOx SIP Call trading program will continue. In addition, downwind states may file Section 126 petitions with U.S. EPA seeking immediate relief from interstate pollution. Id. at 59-60.

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

EPA Proposes to Create New Class of Regulated Underground Injection Well To Address Carbon Capture and Storage and Geologic Sequestration

     EPA has proposed to create a new category of injection well under its existing Underground Injection Control (UIC) Program with new Federal requirements to allow for permitting of the injection of CO2 for purposes of GS.  This proposal builds on existing UIC regulatory components for key areas including siting, construction, operation, monitoring and testing, and closure for injection wells that address the pathways through which underground sources of drinking water (USDWs) may be endangered.  EPA proposes to tailor existing UIC program components so that they are appropriate for the unique nature of injecting large volumes of COs into a variety of geological formations to ensure that USDWs are not endangered.

     This proposal does not require any facilities to capture and/or sequester CO2, rather, this proposal focuses on underground injection of CO2 and outlines requirements that, if finalized, would protect USDWs under the SDWA.  The SDWA provides EPA with authority to develop regulations to protect USDWS.  The SDWA does not provide authority to develop regulations for all areas related to GS.  These areas include, but are not limited to, capture and transport of CS2, determining property rights (i.e. to permit its use for GS and for possible storage credits); transfer of liability from one entity to another; and accounting or certification for Greenhouse gas reductions. EPA is not proposing regulations for COs under the Clean Air Act in this rulemaking.

     Estimates based on DOE and IEA studies indicate that areas of the U.S. with appropriate geology could theoretically provide storage potential for over 3,000 gigatons (or 3,000,000 megatons; Mt) or geologically sequestered CO2.  Theoretically, this capacity could be large enough to store a thousand years of CO2 emissions from nearly 1,000 coal-fired power plants.  Worldwide, there appears to be significant capacity in subsurface formations both on land and under the seafloor to sequester CO2 for hundreds, if not thousands of years.  CCS technologies could potentially represent a significant percentage of cumulative effort for reducing CO2 emissions worldwide.

     With this proposal, EPA seeks comment on any aspects of the ongoing State efforts to regulate the GS of CO2 and how these efforts might be used to better inform a final rulemaking.  Although EPA believes that the most effective approach for the comprehensive management of CO2 GS projects would be achieved at the state and tribal level, it is recognized that some injection activities may raise cross-state boundary issues that are beyond the scope of this rulemaking.  EPA is aware that some states with primacy for the UIC program are actively engaged in the process of developing their own regulatory frameworks for GS or CO2.  In some cases, these frameworks include capture, transportation and injection requirements.  While EPA encourages states to move forward with iniatives to protect USDWs and public health, it is important to note that states wishing to retain UIC primacy will need to promulgate regulations that are at least as stringent as those that will ultimately be finalized.  EPA is seeking comment on any aspects of the ongoing state efforts to regulate the GS of CO2 and how these efforts might be used to better inform a final EPA rulemaking.

     The technical aspects of the rule build upon the existing UIC regulatory framework tailored to address the unique nature of full-scale CO2 GS.  The tailored requirements incorporates flexibility or the discretion of the permitting authority to limit unnecessary burden on owners or operators or permitting agencies and provides for national consistence in permitting GS projects.  Because the volumes of CO2 being anticipated for long-term storage, the buoyant and viscous nature of the injectate, and its corrosivity when mixed with water, EPA is proposing changes to the existing UIC approach or requirements in several program areas, including site characterization, area of review, well construction, mechanical integrity testing, monitoring, well plugging, post-injection site care, and site closure.

     EPA is seeking comment on this proposal. 

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

Citizens’ Groups Claim that Seeps from Underground Mine are “Point Sources” Subject to NPDES Permitting and Antidegradation Limitations

     Representatives of the Taylor Environmental Advocacy Membership, Inc. (“T.E.A.M.”) are challenging the issuance of a surface mining permit for an underground mine to be operated by ICG Tygart in Taylor County, West Virginia.  There is no dispute that after the mine is abandoned and fills with water that there will be seeps to the surface through the rock overburden.  The permit applicant and the West Virginia DEP contend that the seeps are not subject to NPDES permitting requirements as “point sources,” but rather subject only to the surface mining restrictions that prohibit “material damage” to the hydrologic balance, a term that is regarded as synonymous with meeting numeric water quality standards.  In this case, WVDEP takes the position that iron concentrations in the seeps must be low enough to prevent a rise in the concentration of iron in receiving streams above the numeric criterion established by state water quality standards.

     T.E.A.M., however, claims that the seeps are “point sources” because they emerge from rock fractures.  Under the state antidegradation program, discharges from new point sources cannot utilize more than 10 percent of the remaining assimilative capacity of a stream absent a detailed socio-economic study of the need to discharge higher concentrations of the relevant pollutant.  Thus, T.E.A.M. claims that the iron levels in ICG’s seep cannot exceed this lower level, that there is no way ICG could ever meet these greater restrictions and, therefore, that its permits should be denied.

     The Surface Mine Board is expected to reach a decision on this issue sometime in September, and the ruling could have dramatic implications for all deep mines that cause seeps to the surface.

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

Updating the Midwest Governors Association Greenhouse Gas Stakeholder Process

     The Midwest Governors Association continues in its initiative to develop a state-based program to establish a cap-and-trade program limiting carbon dioxide and other greenhouse gas emissions. The principle purpose of this initiative is to develop targets for greenhouse gas reductions and a time table consistent with state targets by July, 2008 and to complete the development of a regional cap-and-trade agreement by November 2008.  One of the design principles behind the cap-and-trade program is to enable linkage to other systems in other jurisdictions with similarly rigorous accounting to create economies of scale, increased market efficiencies, diversity and liquidity while reducing costs. 

     Highlights of the recent developments in the MGA process are as follows: 

     1.  Process – Some controversy has arisen in connection with the MGA process by virtue of its refusal to allow full and free participation in the process by observers.  The MGA has historically allowed observers of its meetings but has precluded observers from participating in its conference calls.  At its most recent plenary session in Minneapolis.  I asked that observers be allowed to participate in some fashion in future conference calls of the various committees.

     2.  Targets – The advisory committee has made a tentative decision to establish the following targets for its cap-and-trade program: 

     15, 20 or 25% below 2005 levels by 2020

     60 to 80% below 2005 levels by 2050

The MGA currently has a process underway in an effort to try to synchronize its selection of the 2005 base case with those states that have previously selected 1990 as a baseline.  The MGA seems to appreciate that there is much uncertainty about what carbon emissions would have been in 1990, making it attractive for them to use a more current base year. There was some discussion about the possibility of establishing a “stabilization” target at a near term date.  This stabilization target would be the date after which carbon emissions would no longer increase.  It is not clear what date might be selected for this purpose.  Undoubtedly, that will get discussion in the future. 

     3.  Scope – The discussions at the Minneapolis meeting indicate that the cap-and-trade program will include the electric sector (constituting 33% of total emission in the region) and the large stationary combustion source sector (constituting 13% of the total emissions in the region).  There was much discussion about the potential for the leakage of jobs out of the region as a result of the imposition of these programs with much interest in knowing how the model would project the impact of such a cap-and-trade program.  There was much discussion about transportation fuels (24% of the total emissions for the region).  It was very clear that the group was concerned about the political expediency of including transportation fuels within this program.  There was also concern about the market implications of such and what the effect would be of imposing the controls on refineries where there was a belief that those refineries would simply pass the cost on to the customers.  The group has agreed to model transportation fuels, but to take no action with respect to placing them under the cap-and-trade until completion of modeling work.

     4.  Politics – It is apparent that there are certain states which are doubtful of the political merit of such a program.  Representatives of the state of Kansas Economic Development Office indicated that they did not believe that there would be significant political support in Kansas for the imposition of a climate change program that adversely affected the economic well-being of that state.  A similar comment was offered by a representative of the Ohio Environmental Protection Agency, that indicated that economic problems in that state would almost certainly cause the state’s political leadership to fear further job losses as a result of any climate change program. 

     5.  Allowances – The allowance committee focused much of its discussion on the need to have the modeling committee and others to identify those interests that would be economically disadvantaged by any cap-and-trade program that might be established.  There was also much discussion about using allowances to create incentives for the development of carbon capture and storage (CCS) or energy efficiency projects.  Specifically, there was a request made to the modeling committee to be certain that the outputs of the modeling would determine the impacts of the industrial sector, jobs, price impacts, consumer spending and power rates. 

     6.  Offsets – The offsets committee identified a variety of matters that they believed would be worthy of recognition under the program.  Among these offsets were: 

            a.         forestation / re-forestation

            b.         animal feeding operations

            c.         agricultural land conversion

            d.         soil sequestration

            e.         nitrogen fertilizer management

            f.          wastewater methane avoidance

            g.         carbon capture and storage

            h.         energy efficiency

            i.          mass transit

There was concern that the total of these offsets may well be enough to offset the entire 43% cap of greenhouse gas reductions from the electric utility and large industrial sectors without getting any direct greenhouse gas reductions.

     7.  Next Meeting – The next live meeting of the full advisory committee will be held in Milwaukee on July 28 and 29.

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

Selenium Policy Begins to Take Shape

     A selenium policy for the state’s coal industry began to emerge in a series of developments taken on July 1 and 3.

     First, on July 1 the West Virginia DEP appealed the June 12, 2008 decision of the Environmental Quality Board issued on the mass selenium hearing conducted over four days in November 2007.  DEP has appealed two issues in the EQB’s June decision to the Kanawha County Circuit Court.  The EQB order required DEP to examine each permit that was the subject of the decision and to identify steps that the coal companies must take to bring their selenium discharges into compliance with the schedules that DEP will issue for each of the NPDES permits. As part of this individualized review, DEP must first “certify” that the companies’ actions conform to their permits.  Second, the EQB has made those certifications or the refusal to issue them appealable decisions to the EQB. 

     The DEP appealed both of those decisions to the Circuit Court.  In the first instance, DEP asserts that the EQB has acted beyond the scope of its adjudicatory authority provided by the Administrative Procedures Act (“APA”, W. Va. Code § 29A-5-4(g)), as the Water Pollution Control Act does not grant DEP the authority to provide the certifications mandated by the EQB’s decision.  Second, in determining what decisions, or non-decisions, by DEP are appealable, the EQB has attempted to describe its own jurisdiction contrary to the limitation provided by the state APA. This statute limits appealable decisions to “final actions” of DEP.  Judge Bloom of the Kanawha County Circuit Court has set a hearing on the appeal for July 17.

     The second development came in the entry of a settlement and consent order submitted to the Circuit Court of Boone County on July 3.  The DEP and Hobet Mining, LLC concluded more than six weeks of negotiations to resolve a civil enforcement action filed in May 2007 to bring Hobet’s selenium discharges into compliance with four of its NPDES permits.  The settlement order requires Hobet to pay a total civil penalty of nearly $4.1 million which will be offset by projects that the company will fund to a maximum of $2.6 million.  Hobet is required to comply with the selenium effluent limitations in its permits no later than April, 2010.

     The third development also occurred on July 3 and involved Hobet’s sister company Apogee Coal Company, LLC.  Apogee was sued in federal district court by the Ohio Valley Environmental Coalition (OVEC).  The basis of its suit was an allegedly unlawful permit modification in January 2007 that gave Apogee additional time to comply with selenium limits. In a May 27 decision, Judge Robert Chambers determined that the NPDES permit modification did violate state law, and Apogee was ordered to submit a plan of treatment and to comply with the effluent limits within 90 days thereafter.  Over two days of hearing, Apogee testified what it had done to comply with final effluent limits, but why it could not do so within the time originally set by the court.  At the conclusion of the hearing, Apogee was ordered to prepare a report within three weeks for the Court to retain an engineering firm that will identify treatment systems for selenium and a time in which those systems will be installed.  Despite evident displeasure by the court over the pace of Apogee’s compliance, it stopped short of the relief requested by OVEC to set a timetable for final compliance or to order that a specific technology be installed.

     For more information about this issue, contact Blair Gardner or Bob McLusky.  (For more information on Robert G. McLusky, see here; for more information on Blair Gardner, see here.)