Energy and Environment Monitor

U.S. EPA Region 3 and WV Chamber Discuss Waste Issues in Face-to-Face Meeting

On July 21, 2010, members of the West Virginia Chamber of Commerce (Chamber) traveled to Philadelphia to meet with U.S. EPA Region 3 and discuss various environmental issues, including water, waste, and air issues. The hazardous and solid waste issues discussed included: (1) the status of a possible Memorandum of Understanding (MOU) between U.S. EPA and West Virginia concerning the state Voluntary Remediation Program insofar as it pertains to the Resource Conservation and Recovery Act (RCRA) Corrective Action Program; (2) the safety aspect of U.S. EPA’s proposal for regulation of coal combustion residuals from electric utilities; (3) the status of U.S. EPA’s reconsideration of the definition of solid waste under RCRA; (4) West Virginia’s administration of the RCRA Corrective Action Program; and (5) U.S. EPA’s procedures for debriefing applicants whose brownfields grant application are denied.

 

    RCRA MOU: In response to the Chamber’s question concerning the status of a possible MOU between U.S. EPA and West Virginia concerning the state Voluntary Remediation Program insofar as it pertains to RCRA, Abraham Ferdas, Director of U.S. EPA Region 3 Land and Chemicals Division, stated that U.S. EPA had sent its comments to Ken Ellison, Director of the Division of Land Restoration West Virginia Department of Environmental Protection (WVDEP) and that the WVDEP has not yet responded. Director Ferdas stated that 99 percent of the West Virginia Voluntary Remediation Program was acceptable for purposes of the RCRA Corrective Action Program but identified “minor corrections” concerning groundwater off site as being needed. For U.S. EPA’s written comments comparing the West Virginia Voluntary Remediation Program and the federal RCRA Corrective Action Program, click here. 

 

    U.S. EPA’s Proposal for Regulation of Coal Combustion Residuals from Electric Utilities: The Chamber inquired concerning the safety aspect of U.S. EPA’s proposal that was published June 21, 2010, (75 Fed. Reg. 35,128). In particular, the Chamber asked whether US. EPA contemplates that its federal program will take into consideration well-developed state dam safety programs such as West Virginia’s long-standing and active dam safety program. Director Ferdas responded that U.S. EPA will be proposing dam safety requirements similar to the requirements under the Mine Safety and Health Administration Program for mine by-product impoundments and acknowledged that in some areas West Virginia’s dam safety requirements are more stringent than the federal Mine Safety and Health Administration Program requirements. He noted that the comment period on U.S. EPA’s June 21, 2010 proposed rule closes September 20, 2010 and that it “may be awhile” before U.S. EPA promulgates a final rule. 

 

    U.S. EPA Definition of Solid Waste: The Chamber inquired concerning U.S. EPA’s plans for the rulemaking on the definition of solid waste that the agency is reconsidering. Director Ferdas stated that the regulations dealing with the definition of on-site waste would not change but that the regulations dealing with the definition of off-site waste and transportation of waste may change, explaining that the issue with off-site waste and waste transportations is the loss of control by the generator. In addition, Director Ferdas stated that U.S. EPA planned to include an expanded analysis of environmental justice issues in the rulemaking on the definition of solid waste. Director Ferdas stated that U.S. EPA may issue a proposal by June 2011.

 

    RCRA Corrective Action in West Virginia:    The Chamber asked if U.S. EPA was focusing on any specific issues with respect to the West Virginia Department of Environmental Protection’s administration of the RCRA Corrective Action Program. Director Ferdas responded that although West Virginia was authorized to administer the RCRA Corrective Action Program more than forty years ago, U.S. EPA and its remedial project managers are still doing “100 percent” or at least “most of the work”. He acknowledged that West Virginia needs more permit writing capability and that West Virginia is not in a position to take on the RCRA corrective action work. He stated that there are less than forty sites in the RCRA Corrective Action Program in West Virginia and that U.S. EPA’s goal is to achieve 95% completion at those sites by 2020.

 

    U.S. EPA Debriefing Process for Applicants for Brownfields Grants: The Chamber asked about U.S. EPA’s process for notifying applicants for brownfields assessment, cleanup, and revolving loan fund grant that their applications have been denied and the reasons for their denial. U.S. EPA Region 3’s representative explained that a debriefing is provided only upon request. U.S. EPA will send an e-mail to the applicant whose application has been denied with information as to who to contact to request a debriefing. If the debriefing is not satisfactory from the applicant’s perspective, the applicant may pursue the matter utilizing U.S. EPA’s grant dispute procedures that are set forth in 40 CFR Part 30 for institutions of higher education, hospitals, and other non-profit organizations and 40 CFR Part 31 for state and local governments. 

 

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

US EPA 2008 National U.S. Greenhouse Gas Inventory

On April 15, 2010, the US Environmental Protection Agency (EPA) released the 15^th annual US greenhouse gas inventory report, which shows a drop in overall emissions of 2.9 percent from 2007 to 2008. The downward trend is attributed to a decrease in carbon dioxide emissions associated with fuel and electricity consumption.

 

The report is available at the following website: www.epa.gov/climatechange/emissions/usinventoryreport.html

 

Due to the size of the report, segments of the report are available for download as pdf files.

 

The inventory tracks annual greenhouse gas emissions at the national level and presents historical emissions from 1990 to 2008. The inventory also calculates carbon dioxide emissions that are removed from the atmosphere by “sinks,” which occurs through the uptake of carbon by forests, vegetation and soils. 

 

Total emissions of the six main greenhouse gases in 2008 were equivalent to 6,957 million metric tons of carbon dioxide. The gases include carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride. Though overall emissions dropped in 2008, emissions are still 13.5 percent higher than they were in 1990.

 

The following factors were primary contributors to this decrease:

1.   A decrease in electricity demand and a resulting decrease in energy consumption.

2.   Higher energy prices leading to a decrease in energy consumption, and

3.   Cooler summer conditions in 2008 compared to 2007 reducing energy demand and offsetting the increased energy demand for heating in the colder winter.

4.   Higher gasoline prices and economic downturn led to a significant decline in petroleum consumption by the transportation sector in 2008.

 

The report follows the United Nations Framework Convention on Climate Change format. Emissions are reported from the following categories: Energy; Industrial Processes; Solvent and Other Product Use; Agriculture; Land Use; Land-Use Change; and Forestry, Waste and Other. Separate reports for each segment is available at the above website.

 

Each year, emission sink estimates are recalculated and revised for all years in the Inventory, as attempts are made to improve both the analyses themselves, through the use of better methods or data, and the overall usefulness of the report.  In general, recalculations are made to the U.S. greenhouse gas emission estimates either to incorporate new methodologies or, most commonly, to update recent historical data.

This article was excerpted from publically available information, and was authored by Joyce Gentry, Acacia Environmental Group LLC. For more information on the author see here.

EPA Issues Greenhouse Gas Reporting Requirements for Underground Coal Mines and Three Other Source Categories

The U.S. Environmental Protection Agency (EPA) announced on June 29, 2010, that it is finalizing requirements under its national mandatory greenhouse gas (GHG) reporting program for underground coal mines, industrial wastewater treatment systems, industrial waste landfills and magnesium production facilities. EPA intends to use the data from these sectors to “provide a better understanding of GHG emissions” and that the data “will help EPA and businesses develop effective policies and programs to reduce them.”

 

EPA noted that methane is the primary GHG emitted from coal mines, industrial wastewater treatment systems and industrial landfills and that it is more than 20 times as potent as carbon dioxide at warming the atmosphere. The EPA announcement continued to say that the main fluorinated GHG emitted from magnesium production is sulfur hexafluoride, “which has an even greater warming potential than methane, and can stay in the atmosphere for thousands of years.”

 

These affected source categories must begin collecting emissions data on January 1, 2011, and submit initial annual reports to EPA by March 31, 2012.

 

EPA also, in a separate proposed rule, opened a public comment period regarding which industry related GHG information would be made publicly available and which would be considered confidential. All emission data are public under the Clean Air Act, However; some non-emission data may be considered confidential if it relates to information which, if made public, could harm the competitiveness of a business. EPA provided as an example of data that may be confidential data under its proposal information reported by fossil fuel and industrial gas suppliers related to production quantities and raw materials.

 

The GHG reporting program requires suppliers of fossil fuels or industrial GHGs and large direct emitters of greenhouse gases to report to EPA. EPA asserts that collecting GHG data “will allow businesses to track emissions and identify cost effective ways to reduce emissions.”

 

Under the Greenhouse Gas Reporting Program, owners and operators of facilities that are subject to quarterly sampling of mine ventilation systems by the Mine Safety and Health Administration (MSHA) must report emissions from underground coal mines and all other source categories located at the mine for which methods are defined in the rule.  Owners and operators are required to collect emission data; calculate GHG emissions; and follow the specified procedures for quality assurance, missing data, recordkeeping, and reporting. Total annual methane emissions are to be calculated as the sum of quarterly methane that is liberated from ventilation wells and shafts and degasification systems, less the quantity that is collected and destroyed.

 

Each underground coal mine meeting the MSHA threshold must monitor the following parameters for their mine ventilation air:

 

1)   Quarterly volumetric flow rate of gas for each ventilation monitoring point;

2)   Quarterly methane concentration for each ventilation monitoring point;

3)   Quarterly temperature values at the time, location, and conditions for which measurements are made;

4)   Quarterly pressure values at the time location, and conditions for which measurements are made; and

5)   Quarterly moisture content at the time, location, and conditions for which measurements are made.

 

Each underground coal mine using a degasification system (deployed before, during, or after mining operations) must also monitor the following parameters:

 

1)   Weekly volumetric flow of methane liberated from each degasification monitoring point;

2)   Weekly methane concentration from each degasification monitoring point;

3)   Weekly temperature values at the time, location, and conditions for which measurements are made;

4)   Weekly pressure values at the time, location, and conditions for which measurements are made; and

5)   Weekly moisture content at the time, location, and conditions for which measurements are made.

 

For methane liberated from degasification systems, companies are not required to monitor each well. Rather, Continuous Emissions Monitoring Systems (CEMS) may be used to monitor aggregate methane from more than one well, as long as methane from all wells is monitored and the methodology for estimating total emissions from all wells is documented.

 

Each underground coal mine where methane is destroyed or transported offsite for destruction must monitor the following parameters:

 

1)   Continuous volumetric flow of gas at each destruction device or point of offsite transport for destruction;

2)   Continuous methane concentrations of gas at each destruction device or point of offsite transport for destruction;

3)   Continuous temperature values of gas at each destruction device or point of offsite transport for destruction;

4)   Continuous pressure values of gas at each destruction device or point of offsite transport for destruction; and

5)   Continuous moisture content of gas at each destruction device or point of offsite transport for destruction.

 

A 60-day public comment period on the proposed rules will begin when the notice is published in the federal register. For more information on the final rule to add reporting requirements for four source categories, see:

http://www.epa.gov/climatechange/emissions/remaining-source-categories.html, and for more information on the proposal on data confidentiality, see:

http://www.epa.gov/climatechange/emissions/CBI.html 

 

This article was co-authored by Skipp Kropp and Matthew S. Tyree, Jackson Kelly PLLC. For more information on the authors see (Kropp) here and (Tyree) here.

Proposed Boiler MACT – Energy Assessment Requirements

On June 4, 2010 National Emission Standards for Hazardous Air Pollutants for Major Sources; Industrial, Commercial, and Institutional Boilers and Process Heaters – Proposed Rule [Major Source Boiler/Process Heater MACT - Vol. 75, No. 107 page 32006) and National Emission Standards for Area Sources: Industrial, Commercial and Institutional Boilers – Proposed Rule [Area Source Boiler MACT - Vol. 75, No. 107 page 31896] were published in the Federal Register.   One feature of both proposed rules is the requirement that facilities conduct an energy assessment to identify cost-effective energy conservation measures.

 

US EPA identifies the energy assessments as a beyond-the-floor standard for existing sources. The energy assessment will be required for all boilers at major sources and boilers greater than 10 million Btu per hour for affected area sources. In the preamble to the Major Source MACT, US EPA indicates that boilers and/or process heaters are required to conduct this energy assessment, but the proposed language of the rule applies to boilers only. 

 

The Department of Energy has conducted energy assessments at selected manufacturing facilities and reports that facilities can reduce fuel/energy use by 10 to 15 percent by using best practices to increase their energy efficiency. The most common best practice is simply tuning the boiler to the manufacturer’s specification. 

 

The procedures for an energy assessment are:

a.    Conduct a visual inspection of the boiler system.

b.   Establish operating characteristics of the facility, energy system specifications, operating and maintenance procedures, and unusual operating constraints,

c.    Identify major energy consuming systems,

d.   Review available architectural and engineering plans, facility operation and maintenance procedures and logs, and fuel usage,

e.    Identify a list of major energy conservation measures,

f.     Determine the energy savings potential of the energy conservation measures identified, and

g.    Prepare a comprehensive report detailing the ways to improve efficiency, the cost of specific improvements, benefits, and the time frame for recouping those investments.

h.    A facility energy management program developed according to the ENERGY STAR guideline for energy management.

 

The energy assessment report, along with a signed certification that the assessment is an accurate depiction of your facility must be submitted to US EPA. 

 

US EPA is estimating that the energy assessment cost will range from $2500 to $55,000. The cost will depend on the size of the facility. US EPA estimates that 1,551 major source facilities will need to conduct the energy assessment. US EPA did not provide an estimated number of affected area source facilities. The estimated total cost of implementing the energy assessments is $25 million for major sources and $52 million for area sources. This is only the cost to conduct the energy assessment. The cost for implementing the suggestions is not included. 

 

In the proposed rule, US EPA is defining a cost-effective energy conservation measure to be any measure that has a payback (return on investment) period of 2 years or less. The proposed language defines cost-effective energy conservation but does currently require the implementation of the recommended measures. 

 

The energy assessment must be performed by qualified personnel. US EPA is defining qualified personnel a specialist in evaluating energy systems, such as those who have successfully completed the DOE Qualified Specialist program for all systems, Certified Energy Manager certified by the Association of Energy Engineers or the equivalent. 

 

The Department of Energy qualified specialist program has five areas for certification: steam systems, fan systems, process heater systems, compressed air systems and pump systems. When looking at the qualified specialist website http://www1.eere.energy.gov/industry/bestpractices/qualified_specialists/, qualified specialists can be searched by name, company or location. There are currently 144 compressed air systems qualified specialists, 170 pump system qualified specialists, 102 process heater systems qualified specialists, 142 steam systems qualified specialists and 32 fan systems qualified specialists in the United States. Currently no individual is a qualified specialist in all 5 areas. There 5 individuals that are qualified specialists in 4 of the 5 programs. The majority of the individuals currently recognized as qualified specialists by DOE are university professors. 

 

The Association of Energy Engineers (AEE) Certified Energy Manager (CEM) program is a certification program for energy engineers. A combination of education and energy experience is required to set for the examination. All CEM candidates must attend AEE’s preparatory CEM training seminars, and complete and pass a four-hour written open-book exam, proctored by an approved exam administrator. There are 17 AEE seminars, candidates must complete at a minimum of eleven, including three seminars that are required. 

 

The preamble does not provide any information on how a facility would determine if another certification program is “equivalent” to the DOE or AEE programs.

 

US EPA is specifically requesting comment on the following elements of the energy assessment:

1.   Whether estimates of the assessment costs are correct

2.   Is there adequate access to certified assessors

3.   Are there other organizations for certifying energy engineers

4.   Are online tools adequate to inform the facility’s decision to make efficiency upgrades

5.   Is the definition of “cost-effective” appropriate in this context since it refers to payback of energy saving investments without regard to the impact on HAP reduction

6.   What rate of return should be used

7.   Are there other guidelines for energy management beside ENERGY STAR’s that would be appropriate

 

Public comments must be received on or before July 19, 2010. 

This article was excerpted from publically available information, and was authored by Joyce Gentry, Acacia Environmental Group LLC. For more information on the author see here.

USEPA Releases Draft Dioxin Report for Peer Review

On May 21, 2010, the USEPA Office of Research and Development released as a draft for public review and response, EPA’s Reanalysis of Key Issues Related to Dioxin Toxicity and Response to NAS Comments (EPA/600/R-10/038A). The release of the EPA’s Reanalysis of Key Issues Related to Dioxin Toxicity and Response to NAS Comments (“EPA’s Reanalysis”) report is part of a larger effort by USEPA to complete USEPA’s assessment of dioxin, which was announced in May 2009 by Lisa P. Jackson in the USEPA Science Plan for Activities Related to Dioxins in the Environment. Specifically, EPA’s Reanalysis is intended to respond to comments prepared by the National Academy of Sciences (NAS), based on their review of USEPA’s 2003 report entitled Exposure and Human Health Reassesment of 2,3,7,8-Tetrachlorodibenzo-p-Dioxin (TCDD) and Related Compounds. EPA’s Reanalysis includes analyses of relevant new dioxin studies and addresses issues related to the TCDD dos-response assessment raised by the NAS, as well as three key recommendations made by the NAS to support a “scientifically robust characterization of human response to exposures of TCDD:”

 

1)   Improved transparency and clarity in the selection of key data sets for dose-response analysis.

2)   Further justification of approaches to dose-response modeling for cancer and noncancer endpoints.

3)   Improved transparency, thoroughness, and clarity in quantitative uncertainty analysis.

 

The draft report can be downloaded from the USEPA, National Center for Environmental Assessment (NCEA) home page under “Recent Additions and Publications” menus at http://www.epa.gov/ncea. The 90 day public comment period begins on May 21 and ends on August 19, 2010. Comments must be provided to the USEPA in writing and must be received by USEPA by August 19 for consideration. 

 

As part of the report review process, USEPA is submitting the draft report to its Science Advisory Board (SAB) for an independent external review. The SAB anticipates holding a public teleconference on or about June 24, 2010 and a public panel meeting from July 13 through 15, 2010. The USEPA intends to forward all public comments received in response to the Federal Register Notice by July 7 to the SAB for its consideration. To ensure that technical comments are provided to the SAB, responders can also submit their comments separately via email to Thomas Armitage, the SAB Designated Federal Officer at armitage.thomas.epa.gov. The Federal Register Notice with further details on the public comment process is available at http://www.gpo.gov/fdysys/pkg/FR-2010-05-21/html/2010-12280.htm. Following review by the SAB, the USEPA intends to finalize the document and publish it as a final report.

 

According to the American Chemistry Council (ACS), http://www.DioxinFacts.org, the term “dioxin” refers to a large family of chemical compounds that includes 17 chemical compounds of specific interest, which share a similar chemical structure and are thought to have similar mechanisms of toxicity to human health and the environment. However, the toxicity of the 17 compounds of interest varies by as much as a factor of 10,000. The ACS notes that the term “dioxin” is also used to refer to TCDD (2,3,7,8-Tetrachlorodibenzo-p-Dioxin), which is the most extensively studied and toxic form of dioxin. According to the NCEA, examples of dioxins include the following chemical compounds:

·     Polychlorinated biphenyls (PCBs)

·     Polychlorinated dibenzo dioxins (PCDDs)

·     Polychlorinated dibenzo furans (PCDFs)

 

PCBs were produced commercially in the United States from the 1930s until 1977 and have been regulated since that time under the federal Toxic Substances Control Act (TSCA). PCDDs and PCDFs are not commercially produced products, but are the unintentional byproducts of incineration, uncontrolled burning, and certain industrial chemical processes. The ACS notes on their web site that historically, the largest sources of dioxin were related to incineration, the manufacture of herbicides, and pulp and paper bleaching. However, releases from industry have decreased approximately 90% between 1987 and 2000 and are expected to further decrease during the next several years as new regulations are fully implemented. Therefore, the ACS reports that uncontrolled burning is now the primary source of dioxin release into the environment.

 

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

USEPA Proposes Technical Corrections & Clarifying Amendments to Mandatory Greenhouse Gas Reporting Rule: EPA Plans to Publish Final Rule Amendments Before End of 2010

The US Environmental Protection Agency (EPA) promulgated its final Greenhouse Gas (GHG) Reporting Rule on September 22, 2009, at 40 CFR Part 98 “Mandatory Greenhouse Gas Reporting”. The intent of the GHG Mandatory Reporting Rule (MRR), per EPA, was to provide a better understanding of where GHGs are coming from and to guide development of the policies and programs to reduce GHG emissions. The final Part 98 rule, published on October 30, 2009 (74 FR 56260), required reporting of GHGs from large emissions sources and suppliers in the US.

 

On May 27, 2010, EPA signed a proposed rulemaking and request for public comment on proposed amendments to the GHG Mandatory Reporting Rule.  Through EPA’s discussions with owners and operators of subject facilities, EPA has identified specific provisions of, or cross references in, the final rule that “were either wrong, would benefit from clarification, or did not have the intended effect.” 

 

Note that Subpart C (General Stationary Combustion) is not included in this proposed rule amendment package. Subpart C, which affects more sources than any other specific source category Subpart in the MRR, is still being considered by EPA for future revisions.

 

EPA says that they plan to publish the final MRR amendments before the end of 2010.

 

Once promulgated, owners and operators of subject facilities would be mandated to follow the requirements in this proposed rulemaking in the calendar year 2010 emissions reports, due to be submitted to EPA by March 31, 2011.

 

40 CFR Part 98 Proposed Revisions

 

A. Types of Changes – The proposed amendments consist of the following types of changes:

 

·     Changes to correct cross references within and between subparts.

·     Additional information to better or more fully understand compliance obligations in a specific provision.

·     Amendments to certain equations to better reflect actual operating conditions, such as the fact that some processes use a single abatement technology and some use multiple abatement technologies.

·     Corrections to the terms and definitions in certain equations.

·     Corrections to data reporting requirements so that they more closely conform to the information used to perform emission calculations.

 

B. List of Subparts to be Revised – EPA is proposing amendments to the following Part 98 subparts:

 

·     Subpart A – General Provisions

·     Subpart E – Adipic Acid Production

·     Subpart H – Cement Production

·     Subpart K – Ferroalloy Production

·     Subpart N – Glass Production

·     Subpart O – HCFC-22 Production and HFC-23 Destruction

·     Subpart P – Hydrogen Production

·     Subpart Q – Iron and Steel Production

·     Subpart S – Lime Manufacturing

·     Subpart V – Nitric Acid Production

·     Subpart Z – Phosphoric Acid Production

·     Subpart CC – Soda Ash Manufacturing

·     Subpart EE – Titanium Dioxide Production

·     Subpart GG – Zinc Production

·     Subpart HH – Municipal Solid Waste Landfills

·     Subpart LL – Suppliers of Coal-based Liquid Fuels

·     Subpart MM – Suppliers of Petroleum Products

·     Subpart NN – Suppliers of Natural Gas and Natural Gas Liquids

 

C. Specific Subpart Revisions – The EPA proposes to make the following specific revisions by subpart:

 

·      Subpart A (General Provisions)

o    Amend existing definitions of “carbonate-based mineral,” “carbonate-based mineral fraction,” “carbonate-based raw material,” “crude oil,” “gas collection system or landfill gas collection system,” “Mscf (thousand standard cubic feet)” and “non-crude feedstocks.”

o    Remove definition of argon-oxygen decarburization vessel and replace with a definition for decarburization vessel.

o    Introduce an additional standard for incorporation by reference for Glass Manufacturing.

 

·     Subpart E (Adipic Acid Production)

o    Amend equation to account for facilities that use only one nitrous oxide abatement technology and add an equation to account for facilities that have no abatement technologies.

o    Amend language to clarify that the Administrator approved alternative method is for determining N2O emissions rather than N2O concentration.

o    Clarify that the location of the test (sampling) point used for the performance test can occur before or after N2O abatement technology as long as the destruction efficiency of the N2O abatement technology is properly accounted for.

 

·     Subpart H (Cement Production)

o    Allow facilities, in determining the clinker weight fraction of MgO and CaO, the option to determine a monthly value based on the arithmetic average of daily samples.

o    Allow additional options for measuring clinker production.

o    Allow an additional option for determining the organic carbon content of raw materials.

 

·     Subpart K (Ferroalloy Production)

o    Clarify requirements for calculating methane emissions from electric arc furnaces.

 

·     Subpart N (Glass Production)

o    Add CO2 emission factors in Table N-1 to account for consumption of barium carbonate and potassium carbonate at glass facilities.

o    Provide an additional ASTM method for determining the carbonate mineral mass fraction of raw materials.

o    Clarify in the data reporting requirements that glass production must be reported both by furnace and from all furnaces combined, to be consistent with the calculation methods.

 

·     Subpart O (HCFC-22 Production and HFC-23 Destruction)

o    Amend the language in §98.154(l) to use the term “destruction device” rather than the narrower term “thermal oxidizer.”

o    Clarify which facilities are required to report data associated with flow rate of HFC-23 fed into the destruction device, at the outlet of the destruction device, and the emission rate at the device. Propose that owners or operators reporting this information also report the calculated destruction efficiency of the device.

o    Amend the due date of the one-time report for HFC-23 destruction facilities to March 31, 2011 or within 60 days of commencing HFC-23 destruction.

 

·     Subpart P (Hydrogen Production)

o    Amend the definition of this source category to clarify that hydrogen production processes located within facilities that are not petroleum refineries are also included within the definition.

o    Remove the requirement in §98.162(b) for owners or operators to report CO2, CH4 and N2O combustion emissions from each hydrogen production process unit using the emissions calculation methods in subpart C.

o    Clarify that each gaseous, liquid or solid fuel and feedstock must be calculated based on its respective equations detailed in the rule language.

o    Remove term “quarterly” and “kg” from §98.166 (c) to make reporting requirements consistent with the language in subpart PP (Suppliers of CO2).

 

·     Subpart Q (Iron and Steel Production)

o    Amend the language in §98.172(b) to clarify that for subpart Q facilities, flare emissions must be estimated only for flares burning blast furnace gas or coke oven gas. The missing data procedures in subpart Y (Petroleum Refineries) at §98.255(b) would be required to be followed for flares burning coke oven gas or blast furnace gas.

o    Amend the reporting requirements in §98.176(e)(3) to clarify that fuel consumption must be reported separately for each type of fuel and other process input and output material.

o    Add reporting requirements for the annual amount of coal charged to coke ovens.

o    Clarify the units and processes for which annual operating hours need to be recorded per the recordkeeping requirements.

o    Clarify that the requirements to estimate GHG emissions from argon-oxygen decarburization vessels also applies to any other type of vessel used to remove carbon from molten steel (decarburization) and result in the venting of similar GHG.

 

·     Subpart S (Lime Production)

o    Amend terminology throughout the subpart to (1) clarify whether the calculation and reporting requirements are referring to calcined byproducts and waste materials and (2) clarify where the calculation and reporting requirements apply to lime products that are produced at the facility.

 

·     Subpart V (Nitric Acid Production)

o    Clarify that the location of the test (sampling) point used for the performance test can occur before or after N2O abatement technology as long as the destruction efficiency of the N2O abatement technology is properly accounted for.

o    Provide a new equation for facilities that do not have N2O abatement technology located after the test (sampling) point.

 

·     Subpart Z (Phosphoric Acid Production)

o    Amend monitoring calculations to allow facilities to use the appropriate industry consensus standards available, in addition to the methods in the Association of Fertilizer and Phosphate Chemists Analytical Methods Manual.

o    Clarify that the grab sample must be collected prior to entering the mill for accurate analysis of inorganic carbon contents.

o    Clarify that the annual arithmetic average percent inorganic carbon in phosphate rock is to be reported as the percent by weight, expressed as a decimal fraction.

o    Specify that facilities need to report the total annual process CO2 emissions from the phosphoric acid production facility, in metric tons.

 

·     Subpart CC (Soda Ash Manufacturing)

o    Clarify that soda ash production is reported for each line.

o    Clarify that the information for producers using the liquid alkaline feedstock process is reported for each manufacturing line or stack, when using a site specific emission factor, and clarify that the elements required are for the periods during the performance test.

 

·     Subpart EE (Titanium Dioxide Production)

o    Clarify that monitoring requirements for the quantity of carbon-containing waste generated from each titanium dioxide production line is determined on a monthly basis, consistent with the calculation procedures in §98.313(b)(3).

o    Amend the data reporting requirements for determining monthly carbon content to be consistent with the calculation and monitoring methods.

o    Clarify that the data reporting requirements for determining carbon content for carbon-containing waste are applied to each process line, consistent with calculation and monitoring requirements.

 

·     Subpart GG (Zinc Production)

o    Amend definitions of the terms for (Electrode)k and (C_Electrode)k in Equation GG-1 to remove the references to kilns.

o    Clarify that identification numbers need to be reported for both Waelz kilns and electrothermic furnaces.

o    Clarify that the carbon content of each input to a kiln or furnace would be required to be reported as a calculation parameter regardless of whether the data are collected from the supplier or by self measurement.

 

·     Subpart HH (Municipal Solid Waste Landfills)

o    Amend the source category definition to clarify that it does not include certain hazardous waste landfills, dedicated construction and demolition waste landfills, or industrial waste landfills.

o    Amend Equation HH-1 and the definition of the terms in that equation to clarify the method for calculating the methane generation rate and the meaning of the terms in the equation.

o    Amend the methods for measuring the waste quantity brought to a landfill to provide alternative methods for landfills that do not have truck scales and to not require the use of scales for measuring waste brought in passenger vehicles or light-duty pick-up trucks.

o    Make technical corrections to Equations HH-2, HH-3, and HH-4, and to make them consistent with Equation HH-1.

o    Amend the moisture content measurement requirements in Equation HH-4 to correctly allow for daily or weekly measurements, and to allow for gas volume and CH4 concentration to be measured differently from each other on a dry or wet basis.

o    Amend the definition of “gas collection system or landfill gas collection system” in §98.6 of subpart A to differentiate between active and passive systems and to clarify in subpart HH that monitoring with flow meters is only required for active systems.

o    Amend the monitoring and QA/QC requirements, recordkeeping and reporting requirements to clarify those requirements and to make them consistent with the calculation procedures.

 

·     Subpart LL (Suppliers of Coal-based Liquid Fuels)

o    Clarify that fossil-fuel products that enter the facility would not be reported when exiting the facility if they are not further refined or otherwise used on site (e.g. products stored in a tank).

 

·     Subpart MM (Suppliers of Petroleum Products)

o    Add a new definition for “batch”.

o    Clarify crude oil reporting requirements and provide flexibility for associated recordkeeping requirements.

o    Clarify that GHG emissions should not be calculated for products leaving the refinery if those products had entered the refinery but were not further refined or otherwise used on site (e.g. products stored in a tank).

o    Provide an optional method for reporters to calculate CO2 emissions resulting from complete oxidation or combustion of a blended product or blended non-crude feedstock.

o    Amend the calculation procedures for biomass-based fuels under §98.393(h) to exclude denaturant in ethanol.

 

·     Subpart NN (Suppliers of Natural Gas and Natural Gas Liquids)

o    Clarify throughout that “mscf” refers to “thousand standard cubic feet”.

o    Clarify several terms in the equations of subpart NN.

o    Update the HHVs and default CO2 emission factors in Table NN-1 and NN-2 to be consistent with the emission factors in Tables C-1 and MM-1.

 

Recommendations

 

The author recommends that affected sources closely review EPA’s future final amendments to Part 98 for any GHG reporting impacts to your subject facilities.

 

For further details on EPA’s GHG Reporting Rule, see the following web site:

 

EPA Mandatory Reporting of Greenhouse Gases Rule

http://www.epa.gov/climatechange/emissions/ghgrulemaking.html  

 

This article was partially excerpted from publically available information, and was authored by Rick Wilson, Acacia Environmental Group LLC.  Any opinions expressed in this article are those solely of the author, and are not intended as legal or professional guidance to any specific readers. For more information on the author see here.

Corporate Parent and NAICS Codes Required for All Sources Covered By GHG Reporting Rule

April 12, 2010, EPA is proposing to amend the Mandatory Greenhouse Gas (GHG) Reporting Rule, to require reporters subject to the rule to provide:   The name, address, and ownership status of their U.S. parent company; their primary and all other applicable North American Industry Classification System (NAICS) code(s); and an indication of whether or not any of their reported emissions are from a cogeneration unit. (40 CFR 98; 75 FR 18455-18468).

 

The Mandatory GHG Reporting Rule, published on October 30, 2009 (74 FR 56260), requires reporting by facilities that emit GHGs (“facilities'') and by suppliers of fuels and industrial gases (“suppliers”').The Mandatory GHG Reporting Rule requires greenhouse gas emitting facilities and suppliers of fuels and industrial gases from all sectors of the economy to report their greenhouse gas emissions and to provide certain additional supporting data in annual reports submitted to EPA. This rule requires facilities with direct GHG emissions over 25,000 metric tons of carbon dioxide equivalent (CO2e), suppliers of petroleum, natural gas, and industrial gases as well as vehicle and engine manufacturers outside the light duty sector to report to EPA annually. 

 

The data collection started on January 1, 2010, and the first reports to EPA are due on March 31, 2011. As part of that first report, EPA is proposing that reporters also include the name of their Corporate Parent and North American Industry Classification System (NAICS) code. In developing the final rule, EPA received comments that this type of information would be useful to the public and EPA, particularly in assisting corporations in assessing emissions at their different facilities and operations. EPA is proposing to add three data elements to the list of data elements specified in 40 CFR 98.3. These data elements would be included in the annual GHG reports that facilities and suppliers subject to the Mandatory GHG Reporting Rule are required to submit.

 

Specifically, this proposed rule amendment would require each reporter to: 

 

(1) provide the legal name and physical address of its highest-level U.S. parent company and to indicate its ownership status by selecting from a list of codes provided by EPA;

 

(2) provide its primary and other applicable North American Industry Classification System (NAICS) code(s); and

 

(3) indicate whether any of its reported emissions are from a cogeneration unit. EPA is also taking comment on whether or not to have reporters list the existence of a co-generation unit at their facility.

 

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

EPA Finalizes GHG Tailoring Rule

    EPA announced on May 13 that is finalizing its Greenhouse Gas (GHG) Tailoring Rule, which will affect major stationary source emitters of GHGs.   EPA’s press release states that “[t]he phased-in, common-sense approach will address facilities like power plants and oil refineries that are responsible for 70 percent of the greenhouse gases from stationary sources that threaten American’s health and welfare.”

 

    EPA continues saying “[a]fter extensive study, debate and hundreds of thousands of public comments, EPA has set common-sense thresholds for greenhouse gases that will spark clean technology innovation and protect small businesses and farms,” quoting EPA Administrator Lisa P. Jackson.

 

    EPA’s phased-in approach will start in January, 2011, and will require GHG permits for facilities emitting 75,000 tons per year (tpy) of GHGs if they are already obtaining permits for other regulated air pollutants.

 

    In July 2011, GHG permitting requirements will expand, covering all new facilities with GHG emissions of at least 100,000 tpy and modifications at existing facilities that would increase GHG emissions by at least 75,000 tpy. Sources requiring GHG permits must demonstrate use of Best Available Control Technology (BACT) to minimize GHG emission increases when facilities are constructed or significantly modified.

 

    EPA estimates that about 900 additional permitting actions covering new sources and modifications to existing sources would be subject to review each year. EPA also estimates that about 550 sources will need to obtain operating permits for the first time because of their GHG emissions.

 

    The final rule addresses six specific greenhouse gases: carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF6).

 

    EPA notes that it issued a proposed rule in October of 2009 and held a 60-day public comment period. It says it received about 450,000 comments during the comneht period and states that the comments “were carefully reviewed and considered during the development of this final rule.” We marvel at EPA’s ability to “carefully review and consider” 450,000 comments on the tailoring rule inasmuch as that number of comments received means that EPA had to “carefully review and consider” 2,500 comments every single day since October, including Saturdays and Sundays, in order to be able to make the announcement May 13.  For more information on this issue, see: http://www.epa.gov/nsr/actions.html

 

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

Competing Bills Setting Forth a Clean Energy Portfolio Standard Filed in Kentucky General Assembly: Part II; House Bill 3

On February 9, 2010, State Representatives Harry Moberly (D-Madison), Dennis Horlander (D-Jefferson), Mary Lou Marzian (D-Jefferson), and Jim Wayne (D-Jefferson) filed House Bill 408 in the Kentucky General Assembly. HB 408 purports to encourage greater energy efficiency, conservation, and the use of renewable resources in the Kentucky energy sector. State Representative Rocky Adkins (D-Sandy Hook) filed a competing Bill, House Bill 3, in the Kentucky General Assembly on March 2, 2010. Both Bills were referred to the House Natural Resources & Environment Committee. As of the writing of this article, only HB 3 has been posted for consideration by the Committee. On March 17, 2010, HB 3 was taken from the Committee for its first reading on the floor of the House. The Bill was subsequently returned to the Committee. The Bill did not progress any further before the 2010 Regular Session ended on April 15, 2010.  

Like its competitor, HB 3 would create new sections of KRS Chapter 278 to define renewable forms of energy that may be used to satisfy requirements of a renewable energy portfolio standard. However, while HB 408 focuses on comprehensive low-income residential energy efficiency programs, HB 3 focuses on low-carbon energy generation as the primary method to meet the benchmark requirements. HB 3 establishes two sets of benchmarks for nonindustrial sales of electricity in the state as set forth in the table below.¹  

Year	Percent of Electricity Generation from Renewable Sources	Percentage of Electricity from Low-Carbon Sources and/or Savings from Efficiency Programs
2012	-	4%
2014	2%	8%
2018	6%	14%*
2022	10%	20%
2026	10%	28%
2030	10%	36%
2034	10%	44%

*After 2017, efficiency programs must account for at least 12% of the total.

The first set of benchmarks requires utilities to meet a portion of nonindustrial demand for power from Kentucky-based renewable sources such as solar energy, geothermal energy, wind energy, biomass, and hydro power in place after January 1, 1992, anaerobic digestion, combined heat and power, and landfill gas. The second set of benchmarks requires electric utilities to meet a portion of nonindustrial demand from low carbon resources and efficiency measures.

 

Low carbon alternatives could be electricity produced from a coal plant equipped with carbon capture technology or power generated from a coal gasification facility. Efficiency measures include load shifting and programs designed to encourage customers to reduce electric consumption. In addition, improvements to generation, transmission, or distribution facilities that result in a measurable energy improvement and investments made to promote electric vehicles qualify for the energy efficiency benchmark. With the second set of benchmarks, utilities may choose to pursue efficiency programs, low-carbon sources of electricity, or some combination of the two in order to meet the requirements. By 2017 and beyond, efficiency programs must account for at least 12% of the total, but no further efficiency improvements are required past 2017.

 

The benchmark requirements are the same for both regulated electric utilities (privately owned and rural electric cooperatives) and the municipally-owned electrics. However, the state agencies charged with oversight of the Clean Energy Portfolio Standards differs. The Public Service Commission will oversee program compliance of the regulated electric utilities and the Energy and Environment Cabinet will oversee program compliance for the municipal electric utilities, both generators and retail distributors. If after an annual review by the respective agency it is determined that renewable energy or low carbon resources are not reasonably available, the agency may require the electric supplier to purchase clean energy certificates or may reduce the obligation of the electric supplier for a particular year. The Bill would permit deviations from the benchmarks under some circumstances outside of the electric supplier’s control, such as weather-related noncompliance, equipment or resource shortages, or if the cost of compliance would exceed 3% of otherwise purchasing or producing the electricity.

 

As mentioned above, a market for clean energy certificates is to be developed that would allow one Kentucky electric supplier to purchase "credit" from another Kentucky electric supplier. A clean energy certificate would represent one megawatt hour of electricity generated from a Kentucky renewable energy resource or low carbon resource that is not needed by that Kentucky electric supplier to meet the benchmarks.

 

HB 3 also amends various loan and grant programs to include energy efficiency projects, renewable energy projects, and alternative fuel facilities. A tax incentive equal up to 80% of the severance taxes paid on natural gas is established if used as a feedstock for an alternative fuel facility.

 

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. 

______________________

 

¹Nonindustrial sales represent approximately one-half of the electricity sales in the state.

Sierra Club Vows to “Shut Down Big Coal”: Wants End to All Existing Coal-Fired Electricity Generation by 2030

Talk about hitting the ground running, the Sierra Club’s new Executive Director Michael Brune recently vowed on his first day on the job that the “Sierra Club staff, volunteers, and our allies across the country will work to retire the existing fleet of more than 500 dirty coal plants and replace them with the efficient use of clean, renewable energy resources” within the next twenty years. 

 

To say that’s an aggressive goal would be an enormous understatement. USDOE reports that 44.7% of all US electricity generation in 2009 was from coal-fired power plants. And given America’s still-battered economy, it is a curious goal indeed.

 

Mr. Brune, age 38, the sixth executive director of the organization, came to the Sierra Club after leading the Rainforest Action Network for seven years.  Brune also spent four years as a Greenpeace activist, a brief stint as an activist at the Coastal Rainforest Coalition, and in 1993 earned B.A. degrees in Economics and Finance at West Chester University in Pennsylvania.  He is also the author of Coming Clean -- Breaking America's Addiction to Oil and Coal (Sierra Club Books, 2008).

 

Capital Cost to Replace All Existing US Coal-Fired Power Plants:

 

Even if we assume that all new US electricity generation will be from non-coal energy sources, an expensive and doubtful proposition unto itself, the Sierra Club is calling for the replacement of all current coal-fired power generation facilities, approximately 350 gigawatts (GW) generation capacity. And since the Sierra Club is demanding the construction of “clean, renewable energy resources” to replace the existing coal plants, they would presumably rule out the construction of nuclear fuel or other fossil fuel plants.

 

If one were to develop a rough estimate of the capital costs required to replace all of the nation’s existing coal power plants with renewable energy power plants, the following facts would be relevant. 

 

The least expensive renewable fuel power plant technology to construct is onshore wind-power, per the U S Energy Information Administration (EIA) Assumptions to the Annual Energy Outlook 2010 (April 2010) report referenced below. Note that geothermal is somewhat less expensive than wind, but since geothermal power is not practical in many areas of the country, onshore wind power would be the logical basis of this cost estimate:

 

·     Wind generated electricity – Total Cost for new projects initiated in 2009 (2008 $/kW) = $1,966/kW of generation capacity.

 

·     Total existing coal-fired power generation capacity = 350 GW = 350,000 MW   = 350,000,000 kW

 

·     Total capital cost to replace all existing US coal-fired power generation with onshore wind power = 350,000,000 kW x $1,966/kW = $688 billion

 

Summary & Conclusions:

 

Beyond the initial capital cost of approximately $700 billion, there would need to be roughly 3,500 new wind farms (assuming 100 MW capacity per wind farm) constructed. This massive effort would have to average 175 new wind farms constructed and operational each year over the next 20 years. 

 

Even with a mix of wind, solar, geothermal and hydro, it is inconceivable that all existing US coal-fired electric plants could be retired within two decades. And this would be in addition to all of the new electricity generating plants that will need to be constructed by 2030 to meet the increased electric power demands of our growing nation.

 

Are Americans ready to abandon coal, currently the predominant, cost-effective and reliable source of the nation’s electricity, for expensive and potentially unreliable sources of energy? Renewable energy, as well as nuclear energy, should be an increasingly important component of the country’s energy mix in the coming decades, but only in a reasonable and cost-effective manner.

 

For further details on US coal-fired power generation, and the Sierra Club’s efforts to oppose it, see the following sources:

 

• Sierra Club Press Release (March 16, 2010)

http://action.sierraclub.org/site/MessageViewer?em_id=165381.0

 

• US Department of Energy Report No.: DOE/EIA-0226 (2010/03), Table 1.1. Net Generation by Energy Source: Total (All Sectors), 1995 through December 2009.

 

• U S Energy Information Administration/Assumptions to the Annual Energy Outlook 2010 (April 2010), Table 8.2. Cost and Performance Characteristics of New Central Station Electricity Generating Technologies.

 

This article was partially excerpted from publically available information, and was authored by Rick Wilson, Acacia Environmental Group LLC.  Any opinions expressed in this article are those solely of the author, and are not intended as legal or professional guidance to any specific readers. For more information on the author see here.