Energy and Environment Monitor

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.

Public Nuisance: Will the Court System’s Attempt at a “Climate Change” Policy Get the Supreme Court’s Stamp of Approval?

    It seems that the future of public nuisance cases may soon be in the hands of the United States Supreme Court due to the “circuit split” that has resulted from a recent decision, or non-decision, by the 5^th Circuit Court of Appeals. The 5^th Circuit follows decisions in two other circuits reaching opposite results, giving us a trio of public nuisance cases that could possibly establish a “cap and trade” policy through tort litigation. 

 

Just two weeks ago, the 5^th Circuit was forced to dismiss the appeal in Comer v. Murphy Oil as a result of the recusal of half of the panel and the subsequent loss of quorum. In the appeal, the plaintiffs, most residents of Mississippi, attempted to link some of the nation’s leading energy producers with the damages they sustained from Hurricane Katrina by arguing that the damages were intensified by global warming resulting from defendants’ release of greenhouse gases. The 5^th Circuit’s dismissal resulted in the reinstatement of the holding of the lower court that the plaintiffs lacked standing because of the tenuous link between their claimed damages, the defendants’ emissions, and the alleged global warming. The plaintiffs will have 90 days to file a petition for review with the Supreme Court.

 

In September 2009, the 2^nd Circuit Court of Appeals reached an opposite conclusion in its decision in Connecticut v. AEP. The 2^nd Circuit found that plaintiffs, consisting of states, private land trusts, and New York City, had constitutional standing to bring a public nuisance claim against United States utility companies for their alleged contributions to “climate change”. Unlike in Comer, however, the plaintiffs did not sue for monetary damages, but for a court order requiring the utility companies to cap their emissions. The defendants were to file a petition for review with the Supreme Court by this week.

 

    Rounding out the trio of recent public nuisance cases is Native Village of Kivalina v. Exxon Mobil Corporation. In September 2009, the U.S. District Court for the Northern District of California dismissed a public nuisance claim filed by the Inupiat Eskimos of Alaska. The plaintiffs had argued that the ice barriers around their villages were melting due to the global warming caused by carbon emitters such as Exxon Mobil. The District Court held that the claims had justiciability problems due to the attenuated causation theories and the questionable scientific hypothesis at issue. This case is likely to be brought up to the 9^th Circuit Court of Appeals for review.

 

As a result of Comer and AEP, soon the Supreme Court will have the opportunity to decide whether the judicial branch through public nuisance tort litigation can effectively create its own “cap and trade” policy. When that time comes, the Supreme Court may experience the same recusal issues as were present in Comer v. Murphy Oil as two Supreme Court Justices, Justices Alito and Breyer, own stock in defendant companies and Justice Sotomayor was involved in the 2^nd Circuit review of Connecticut v. AEP. With their recusals, the court would be left with six justices, the minimum quorum requirement, and possibly an equally divided court. Looking back at how the court was divided in Massachusetts v. EPA, the 2007 decision granting the EPA the discretion to regulate greenhouse gas emissions, may provide an indication of how the remaining justices will side on the public nuisance cases.

 

Justices Scalia, Thomas, and Roberts, all Republican appointees, dissented in Massachusetts v. EPA, while Justice Ginsberg and Stevens, both Democratic appointees, and Justice Kennedy, appointed by President Reagan, were part of the majority decision. Justice Kennedy, often referred to as the swing vote of the Court, could be the deciding vote on the public nuisance issue. If he again sides with environmental regulation this could create the unique situation of an equally divided court which generally results in the Court affirming the lower decision. Which decision the Supreme Court chooses to review or whether they decide to hear the cases together may determine the final outcome should the Court choose to resolve this conflict under the current panel.

 

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. 

U.S. EPA Proposes to Amend the Mandatory Reporting of Greenhouse Gases by Adding Source Categories

The Mandatory Reporting of Greenhouse Gases Rule currently requires suppliers of fossil fuels or industrial greenhouse gases, manufacturers of vehicles and engines, and facilities that emit 25,000 metric tons or more per year of greenhouse gas (“GHG”) emissions to submit annual reports to U.S. Environmental Protection Agency (“USEPA”).  On March 22, 2010, (“USEPA”) signed several proposed rules to amend the Mandatory Reporting of Greenhouse Gases Rule by adding source categories.  These include:

 

·     Subpart A:  General Provisions: Corporate Parent/NAICS Amendments

·     Subpart W:  Petroleum and Natural Gas Systems

·     Subpart RR:  Carbon Dioxide Injection and Geologic Sequestration

·     Subpart I:  Electronics Manufacturing

·     Subpart L:  Fluorinated Gas Production

·     Subpart DD:  Imports and Exports of Equipment Precharged with Fluorinated GHGs or Containing Fluorinated GHGs in Closed-cell Foams

·     Subpart OOa:  Use of Electric Transmission and Distribution Equipment

·     Subpart SS: Manufacture of Electric Transmission and Distribution Equipment

 

These amendments expand the applicability of the Mandatory Reporting of Greenhouse Gases Rule.  Two of these proposed rules are particularly interesting and include the Subpart W:  Petroleum and Natural Gas Systems and Subpart RR:  Carbon Dioxide Injection and Geologic Sequestration.

 

The proposed Subpart W Petroleum and Natural Gas Systems rule will require petroleum and natural gas facilities emitting more than 25,000 metric tons or more of CO₂ equivalent per year to report their greenhouse gas emissions to USEPA.  Facilities will be required to begin data collection January 1, 2011 and submit their first reports to USEPA on March 31, 2012 for their 2011 emissions.  The definition of “facilities” differs from the remainder of the rule and for this subpart facilities will include: offshore petroleum and natural gas production, onshore natural gas production, onshore natural gas processing, gas transmission, underground natural gas storage, LNG storage and LNG import and export facilities, onshore production and natural gas distribution facilities.  USEPA expects the estimated average cost to be $18,000 per facility for the first year and $8,000 in subsequent years.  This proposal will be open for public comment for 60 days after publication in the Federal Register. A public hearing will be held on this proposal on April 19, 2010 in Arlington, Virginia.

 

Proposed Subpart RR Carbon Dioxide Injection and Geologic Sequestration will require mandatory reporting of greenhouse gases from facilities that inject carbon dioxide underground for the purposes of geologic sequestration or enhanced oil recovery (“EOR”) adding this new source category to the Mandatory Reporting of Greenhouse Gases Rule.  According to USEPA, this “proposal is complementary to and builds on [US]EPA’s proposed rule for Federal Requirements under the Underground Injection Control (UIC) Program for Carbon Dioxide Geologic Sequestration Wells;” however, it will not change any requirements for obtaining or complying with UIC permits.  It will require a monitoring strategy for detecting potential emissions to the atmosphere and reporting of data to verify the total amount of CO₂ sequestered.  Long-term geologic sequestration facilities will also be required to:

 

• Develop and implement a USEPA approved site-specific monitoring, reporting, and verification (MRV) plan
• Report the amount of CO₂ geologically sequestered using a mass balance approach. 

However, these two additional provisions would not apply to EOR operations or geologic sequestration research and development projects unless the facility chooses to opt-in.  USEPA estimates the annual cost of reporting for each facility to be $4,000.  The first annual reports will be due March 31, 2012 to USEPA for 2011.  This proposal will be open for public comment for 60 days after publication in the Federal Register. A public hearing will be held on this proposal on April 19, 2010 in Arlington, Virginia.

 

The addition of new source categories to Mandatory Reporting of Greenhouse Gases Rule is quite interesting and will require time to see the full effect of this rulemaking. 

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

2008 TRI National Analysis

On December 8, 2009 US EPA released its annual analysis of the Toxic Release Inventory of 2008 information.  The TRI database contains information on chemical releases into the air, land and water, as well as waste management and pollution prevention activities.  The analysis of 2008 data shows that 3.86 billion pounds of toxic chemicals were released into the environment, a 6 percent decrease from 2007. 

 

More than 21,000 facilities reported information on 650 chemicals in 2008.  There was a 5% decrease in the number of facilities reporting in 2008.  This could be due to the economic downturn.  Some facilities that reported in 2007 did not report in 2008.  EPA is planning to investigate. 

 

Air releases were decreased 14% from 2007 and decreased 30% from 2001.  Surface water releases increased 3% from 2007 and 1% from 2001.  It is believed that the surface water increase is due to the Tennessee Valley Authority coal ash spill.  Land releases were virtually unchanged with a 0.1% increase from 2007.  Land releases decreased 40% from 2001 levels.

 

The report shows decreases in the releases of persistent, bioaccumulative, and toxic (PBT) chemicals such as lead, dioxin, and mercury.  Mercury was down 11% from 2007 report.  Dioxin was down 77% from the 2007 report.  Lead was down 2% from the 2007 report.  PCBs increased 121% from 2007.  PCBs are longer manufactured in the United States.  The increase is due to the removal and treatment of legacy PCBs.  

 

3.86 billion pounds were disposed or otherwise released in 2008.  87% was released on-site through air releases (30%), surface water (6%), on-site underground injection wells (5%) and land disposal (46%).   The remaining 13% were disposed or otherwise released off-site.

 

In 2008, the production-related waste managed was 22.57 billion pounds.  Of the production-related waste managed, 38% was recycled, 12% was used for energy recovery, 33% was treated, and 17% was disposed of or otherwise released.  The waste management hierarchy establishes that once the waste is generated the preferred management methods are recycling, followed by burned for energy recovery, treatment and, as a last resort, disposal or otherwise released.

 

The quantity disposed of or otherwise released from the production-related waste management is 3.94 billion pounds while the TRI disposal or other release value is 3.86 billion pounds.  Why are these values different?  When looking at total production-related waste, the quantity disposed of or otherwise released includes all reported disposal or other releases except those due to remedial, catastrophic or one-time releases.  On the other hand, total disposal or other releases, discussed above, excludes amounts that were sent to other TRI facilities and reported as disposed or otherwise released (to avoid double-counting).

 

There were 179 carcinogens on the TRI list for 2008; 35 of the 179 carcinogens were not reported for 2008.  Total disposal or other releases of carcinogens reported was 776 million pounds in 2008.  92% were disposed of or otherwise released on-site and 8% were disposed of or otherwise released off-site.  From 2007 to 2008, total disposal or other releases of carcinogens decreased by 60 million pounds or 7%.  Air releases decreased by 16 million pounds or 18%.  From 2001 to 2008, total disposal or other releases of carcinogens decreased by 33% (388 million pounds), including a decrease of 44% (59 million pounds) in air releases. 

 

In addition to the traditional analysis of the TRI database, EPA conducted a TRI Chemical Hazard Analysis.  EPA used the Risk Screening Environmental Indicators (RSEI) “toxicity-weighted-pounds” methodology to conduct additional analysis.  The idea is to provide additional insights that go beyond simple pounds analysis and reflect some basic measure of chemical toxicity.  More information on RSEI is available at www.epa.gov/oppt/rsei

 

For this analysis, EPA included all TRI chemicals that have RSEI hazard weights and addresses total disposal or other releases to all media.  RSEI toxicity weights are available for both cancer and non-cancer health effects.  Two analyses are done, one using the cancer toxicity weights and one using the non-cancer toxicity weights. 

 

For 2008, 493 TRI chemicals were reported on by TRI facilities.

· 33% of the chemicals have RSEI cancer toxicity weights

· 68% of the chemicals have RSEI non-cancer toxicity weights

· 24% of the chemicals have both cancer and non-cancer toxicity weights

· 23% of the chemicals reported on for 2008 do not have RSEI toxicity weights, including known or suspected carcinogens such as dioxins, creosote and polychlorinated alkanes.

 

Comparing the nationally aggregated total toxicity weighted pounds of disposal or other releases using the RSEI cancer toxicity weights to years past shows that for 2007 to 2008 there was an increase of 10% using RSEI cancer toxicity weighted pounds.  For 2001 to 2008 there was a decrease of 53% using RSEI cancer toxicity weighted pounds. 

 

For non-cancer RSEI toxicity weights, there was a decrease of 7% from 2007 to 2008.  For 2001 to 2008, there was a decrease of 55% using RSEI non-cancer toxicity weighted pounds. 

More information on the 2008 TRI analysis is available at http://www.epa.gov/tri

 

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.

Summary of EPRI Prism/MERGE 2009 Analyses Report: EPRI Presents One Roadmap to 2050 for Reduced-Carbon Electricity Generation

In 2007, the Electric Power Research Institute (EPRI) released its first “Prism” model and Model for Estimating the Regional and Global Effects of Greenhouse Gas Reductions (MERGE). According to EPRI, these analyses provided a technically and economically feasible roadmap for the electricity sector as it seeks to reduce its greenhouse gas emissions over the next four decades. The Prism analysis provided a comprehensive assessment of potential CO2 reductions in eight key technology areas of the electricity sector. The MERGE analysis identified the economically optimum technology portfolio in response to a given CO2 emissions constraint.  

EPRI updated both analyses in 2009 to reflect economic and technological changes that have the potential to affect projected emissions and the technologies to address them. This update is also more comprehensive in that it includes new technologies and analysis features.  

The Prism analysis determined that the electricity generating sector can potentially meet the challenges that confront each technology option and deploy “The Full Portfolio” of technologies to achieve meaningful emissions reductions. The full Prism graphic builds from the top down, utilizing the U.S. Energy Information Agency’s (EIA) 2009 Annual Energy Outlook reference case estimate of CO2 emissions from the U.S. electricity sector. This summary provides an overview of key factors, technical assumptions, and research, development, and demonstration (RD&D) priorities for each technology.  

The MERGE analysis determined the most economic combination of technologies over time to meet a specified CO2 emissions constraint. Based on current and projected technology costs, consideration of fuel costs and reserves, and competition for resources with other parts of the economy, MERGE projects electricity generation from different technologies, electricity costs, CO2 prices, and the overall cost of implementing CO2 emissions reductions. 

The 2009 Prism and MERGE analyses show that a full portfolio of electricity sector technologies could simultaneously address the challenge of growing load demand while meeting carbon constraints and limiting (in relative terms) increases in the cost of electricity. The research shows that the sector could potentially reduce annual carbon dioxide (CO2) emissions in 2030 by 41 percent relative to 2005 emissions levels, but that it will require sustained research, development and demonstration and aggressive deployment of the full technology portfolio.  

Full Portfolio 

The full portfolio includes coal-fired generation with carbon capture and storage, renewable resources, and nuclear generation, as well as significant efficiency improvements throughout the electricity production and delivery system and reduced consumption through end-use efficiency. It requires deployment of advanced technologies by 2030 comparable to those assumed in the Prism analysis; an 8 percent reduction in electricity consumption through improved end-use efficiency; 45 new nuclear units; new renewables generation equivalent to four-fold increase in current wind and solar generation capacity; and 100 million plug-in electric vehicles. 

The results indicate that the full portfolio could reduce the cost to the U.S. economy, of funds that would otherwise be expended, for CO2 emissions curtailment by more than $1 trillion by 2050. Deployment of the full portfolio could result in an 80 percent increase in the real wholesale cost of electricity by 2050 relative to current costs, compared with a projected increase of more than 210 percent with a limited portfolio.  

2009 Prism Analysis 

2009 Prism analysis assumption: Achieve “maximum achievable potential” as calculated in the 2009 EPRI efficiency study, resulting in a 2030 net consumption reduction of 8%. 

The 2009 Prism analysis estimates that the technical potential exists for the U.S. electricity sector to reduce annual CO2 emissions in 2030 by: 

·     The 2009 analysis estimates a potential CO2 emissions reduction in 2030 of 6.5% as a result of gains in energy efficiency.

·     41% relative to 2005 emissions, based on improvements to electric sector technologies;

·     58% relative to 2005 emissions, if reductions due to electrotechnologies and electric transportation are included; and

·     62% relative to the 2030 reference case projection in the Energy Information Administration’s 2009 Annual Energy Outlook1. (Emissions reduction potential for each technology area is also expressed as a percent reduction relative to this reference case.) 

The Prism analysis projects that by 2030, 60% of the total U.S. generation mix would consist of low- or non-CO2 emitting generation—provided that the required research, development, and technology demonstrations can be carried out and the technical assumptions can be met. 

2009 MERGE Analysis 

The 2009 MERGE analysis estimates the economically optimum portfolio of electricity sector technologies that will meet a CO2 emissions constraint comparable to those suggested in current policy proposals. MERGE analyzes the economywide impacts of climate policy in a global context. Under assumptions regarding CO2 emissions constraints and technology costs and availability, MERGE compares economic consequences of different technology scenarios. 

The 2009 MERGE analysis compares two technology scenarios: “limited portfolio” and “full portfolio.”   These two contrasting scenarios allow an assessment of the value of investing in RD&D. The limited portfolio assumes that CCS is not successfully deployed, and no expansion of the nuclear fleet. The full portfolio assumes availability of CCS, advanced nuclear (64 GWe New Build by 2030), significant improvement in costs of renewables (15% of Generation by 2030), availability of plug-in hybrid electric vehicles (PHEVs) to 100 Million PHEVs and 3x increase in non-road use by 2030, and accelerated improvements in end-use efficiency. The 2009 analysis adds several features to previous EPRI analyses: 

·     Emissions constraints indicative of current U.S. and international policy proposals (80% below 2005 levels for developed countries);

·     Updated technology costs based on EPRI’s Technical Assessment Guide;

·     Unconventional resources such as shale gas factored into natural gas supply;

·     CCS retrofit for up to 60 GW of existing coal plants;

·     Grid integration costs considered for high levels of variable output generation from renewables; and

·     Higher biomass feedstock costs for large-scale biofuels and/or biomass electricity production. 

Projected Costs Full vs Limited Portfolios 

If expended today these costs would represent an average of about $16,000 per household in the full portfolio scenario compared to $28,400 in a limited portfolio that excludes new nuclear generation or carbon capture and storage.  

The institute in 2007 published its first Prism and MERGE analyses, which laid out the U.S. electricity sector's potential for reducing CO2 emissions and an economically optimum technology portfolio that could meet demand growth and carbon emissions constraints. This 2009 research is based on reducing carbon emissions targets by 80 percent by 2050, consideration of new technology options, and inclusion of recent advances in technology and cost projections that take into account the impact of the current global economy. 

Summary & Conclusions 

According to EPRI, the 2009 Prism analysis estimates that the technical potential exists for the U.S. electricity sector to reduce annual CO2 emissions in 2030 by:

·     41% relative to 2005 emissions, based on improvements to electric sector technologies;

·     58% relative to 2005 emissions, if reductions due to electrotechnologies and electric transportation are included; and

·     62% relative to the 2030 reference case projection in the Energy Information Administration’s 2009 Annual Energy Outlook. 

The 2009 Prism and MERGE analyses underscore the importance of research, development, and demonstration leading to a full portfolio of electricity sector technologies.  No one technology can do the job; the full portfolio of technologies is required.  

The full portfolio comprises both supply- and demand-side technologies: end-use efficiency and plug-in hybrid electric vehicles supported by a smart grid; wind, biomass, solar, advanced nuclear, and coal with CO2 capture and storage. 

The MERGE analysis indicates that a technology portfolio similar to that outlined by the Prism can achieve CO2 emissions reductions at a considerably lower economic cost—as much as $1 trillion in some scenarios.  Much of the required technology is not yet available, and substantial, sustained research, development and demonstration is required.  Low-carbon electricity technologies drive growth in electricity demand even as CO2 emissions are reduced. 

For further details on EPRI’s Prism/MERGE 2009 Update Report, see the following sources: 

• Electric Power Research Institute (EPRI)  http://my.epri.com/  
• EPRI PRISM/MERGE Analyses - 2009 Update [EPRI Report 1019563], August 2009. 

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.

Geologic Carbon Sequestration News

In the United States alone, Geologic Carbon Sequestration has a multitude of projects at various stages of completion. Recently, the DOE Midwest Partnership announced successful completion of CO2 injection at the East Bend Site located near Rabbit Hash, Boone County, Kentucky. Now that the actual injection has been completed, the area will still be monitored to determine the suitability of future injection or whether the well should be capped for permanent closure. This project, although started three years ago, is just a small scale test site. For more information on the East Bend Project, the formal announcement (as seen in the Carbon Capture Journal) of successful injection has been included. For an overall picture of the project, see the Midwest Regional Carbon Sequestration Partnership (MRCSP) website at http://216.109.210.162/CincinnatiArch.aspx.

In addition, another article from the Carbon Capture Journal has been included. This article is about the CO2 Capture Project (CCP). Although there are many publicly funded programs, CCP is a partnership of the world’s leading energy companies. Just as publicly funded partnerships include other resources; this partnership utilizes academic institutions and government agencies. As apparent from this introduction, in order for Geologic Carbon Sequestration and Carbon Capture to be viable options for our future, all of these partnerships and projects are essential. Sharing this information is for the greater good of the technology and our future. The article about CCP details their recent findings and introduces a publication - Advances in CO2 Capture and Storage Technology.

DOE Midwest Partnership completes CO2 injection
Storage, Oct 21 2009 (Carbon Capture Journal)

- The Midwest Regional Carbon Sequestration Partnership (MRCSP) has successfully injected 1,000 metric tons of CO2 into the Mount Simon Sandstone.

The formation is a deep saline formation that is widespread across much of the Midwest.

Preliminary results indicate that the formation has good CO2 storage potential and could possibly serve as a repository for CO2 emissions captured from stationary sources in the region, says the DOE.

In the controlled test, members of the MRCSP research team injected liquefied CO2 at Duke Energy’s East Bend Generating Station, located along the Ohio River near the town of Rabbit Hash in Boone County, Kentucky.

The CO2 was injected into the lowest 100 feet of the Mount Simon Sandstone, which is present at the East Bend site at approximately 3,230 to 3,530 feet below ground. The formation has properties that are considered conducive to CO2 storage, such as the appropriate depth, thickness, porosity, and permeability; in addition the formation is overlain by layers of low-permeability rock that should keep the CO2 safely and permanently confined.

Before drilling the test well, the partnership conducted a seismic survey at the site and obtained permits for the injection test from the U.S. Environmental Protection Agency (EPA) and the Kentucky Division of Oil and Gas. The research team then injected clean brine, as required in the permit issued by the EPA, to determine formation properties such as the maximum safe injection pressure.

Following brine injection, a total of approximately 1,000 metric tons of CO2 were injected in two 500-metric-ton steps, concluding on September 25th. The injection rate, pressure, temperature, and quantity of CO2 in the formation were measured throughout the test to confirm that the injection proceeded as planned.

Over the next two years, the MRSCP team will monitor groundwater at the site to ensure that it is unaffected by the CO2. Underground sources of drinking water are located within a few hundred feet of the surface in the region, far above the injection zone. The Eau Clair Shale provides approximately 450 feet of containment above the injection zone, thereby ensuring the safety of drinking water supplies.

*******

CO2 Capture Project releases latest findings
Projects / Policy, Oct  20  2009 (Carbon Capture Journal)

- The CO2 Capture Project (CCP) presented 'breakthrough findings' gained from the last five years of its research at the third Carbon Sequestration Leadership Forum (CSLF).

The studies undertaken by the CCP confirm that the safe, long-term geological storage of CO2 is achievable; they draw on the decades of experience that the oil & gas industry has of storing and monitoring gases and liquids underground.

Capture of CO2 emissions is shown to be technically and economically possible using a range of methods which have undergone thorough testing.

The CCP’s findings, from the second phase of its work, are set out in a new book - Advances in CO2 Capture and Storage Technology - part of a series entitled CO2 Capture for Storage in Deep Geologic Formations.

Highlights include:

R&D studies that addressed outstanding issues confirm that CO2 can be stored underground safely and securely. They include:

- A Well Integrity Field Study shows that selecting the correct drilling and installation procedures is more important than the choice of materials for long term well stability, and thus secure long-term subsurface storage

- A Certification Framework, developed to provide a simple, transparent guide to site certification; essential to help decision makers to manage the CO2 storage process

- Outstanding technical progress was achieved following an in-depth review of more than 200 capture technologies. About 10 technologies, covering the whole range of techniques (post-combustion, precombustion, oxy-fuel), and applicable to varied point sources, were developed from concept and are now being evaluated for potential demonstration:

- Identification of a preferred CO2 capture method for oil refineries - Oxy-fuel combustion has been shown to offer the greatest potential, both technically and economically, for capturing CO2 emitted by the largest source in oil refineries, the Fluid Catalytic Cracking unit (FCC). A pilot test in an industrial scale refinery is scheduled for next year

- Potential for CO2 capture from extraction of heavy oil and tar sands – a novel advanced oxy-firing technology - chemical looping combustion (CLC) - has been developed, which has the technical and economical potential in the mid-term for scaling up to capture CO2 from heavy oil and tar sand steam extraction processes

- Post-combustion identified as most likely short-term option for capturing CO2 from gas fired power stations, although pre-combustion may be more viable in the medium-term.

The findings are the result of a major collaborative effort between the members of CCP including eight oil & gas majors and government bodies including the EU, the US Department of Energy, the Norwegian Research Council and 60 academic institutions, industry and leading environmental groups.

Over 150 projects have been undertaken by the CCP, to date, to increase understanding of the science, engineering applications and economics of CCS.

The CCP is now entering its third phase – using insights from the first two phases to further test and trial high potential technologies. This work will prepare the ground for widespread deployment of these technologies throughout the oil and gas industry and the power sector.

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

Recent GHG Case Breaks from 2nd Circuit

In the case of Kivalina et al. v. Exxon Mobil Corp. et al., case number 4:08-cv-01138 (N.D. Cal. Sept. 30, 2009), the U.S. District Court for the Northern District of California dismissed a public nuisance lawsuit brought by the Alaskan village of Kivalina against 24 energy and utility companies, finding that the Eskimo village who brought the suit could not establish that the threat to its existence from rising sea levels was “fairly traceable” to the defendants’ greenhouse gas (GHG) emissions and thus lacked standing. Judge Saundra Brown Armstrong of the U.S. District Court for the Northern District of California further ruled that the plaintiffs’ federal common law nuisance suit touched on a political question properly reserved for the legislative or executive branch. This was a break from the current trend in the federal courts of holding companies liable for historic GHG emissions that contribute to global warming.  

In Connecticut v. American Electric Power Co., the Second Circuit revived a similar nuisance suit filed by a coalition of states and environmental groups against American Electric Power Co. Inc., the Tennessee Valley Authority, Xcel Energy Inc. and other power companies. The suit, brought under a federal common law claim of nuisance, alleged that by contributing to global warming, AEP and the other defendants were harming the environment, the states’ economies and public health. It was originally tossed by a district court, but then revived last month by a two-judge panel of the Second Circuit, which said the district court had wrongly read the plaintiffs’ claims as seeking a change in national policy rather than protection from immediate harm. 

“Nowhere in their complaints do plaintiffs ask the court to fashion a comprehensive and far-reaching solution to global climate change, a task that arguably falls within the purview of the political branches,” the judges said. “Instead, they seek to limit emissions from six domestic coal-fired electricity plants on the ground that such emissions constitute a public nuisance that they allege has caused, is causing and will continue to cause them injury.”  

“These decisions side by side I think show the great disagreements both in the law and in society about how to handle these claims,” said Steven F. Napolitano, a partner at Skadden Arps Slate Meagher & Flom LLP. “They are 180 degrees different.” 

The Kivalina case is one of the many recent public nuisance lawsuits brought against energy and utility companies. The Kivalina decision falls in line with prior decisions coming out of the district courts, whereas the Second Circuit’s decision is an outlying decision right now in the field of global warming. 

“The district court judges pretty consistently seem to be going with the view that these are difficult cases to entertain, that they run into problems of fundamentally political judgments,” added Ronald J. Tenpas, co-chair of the environmental practice at Morgan Lewis & Bockius LLP and a former assistant attorney general at the U.S. Department of Justice. “And now you have one court of appeals going in a different direction. So it definitely leaves things in a bit of a flux right now.” 

While the Second Circuit relied on comparisons to water pollution and air pollution nuisance cases, Judge Armstrong criticized the Second Circuit in the Kivalina decision, questioning whether water pollution and air pollution cases provided appropriate guidance in assessing global warming nuisance cases, pointing to the admitted and significant distinctions between a nuisance claim based on water or air pollution and one based on global warming.  

“While a water pollution claim typically involves a discrete, geographically definable waterway, plaintiffs’ global warming claim is based on the emission of greenhouse gases from innumerable sources located throughout the world and affecting the entire planet and its atmosphere,” Armstrong said. 

Armstrong further said that the nuisance claim required the judiciary to make a policy decision about who should bear the cost of global warming. “Though alleging that defendants are responsible for a ‘substantial portion’ of greenhouse gas emissions, plaintiffs also acknowledge that virtually everyone on Earth is responsible on some level for contributing to such emissions,” she said.” Yet, by pressing this lawsuit, plaintiffs are in effect asking this court to make a political judgment that the two dozen defendants named in this action should be the only ones to bear the cost of contributing to global warming.” 

In yet another similar case, a proposed class of property owners alleged that dozens of oil and chemical companies made Hurricane Katrina worse through their contributions to global warming, and that they were therefore liable for damages from the storm. In Comer v. Murphy Oil, the Fifth Circuit held that the plaintiffs had Article III standing to assert state law nuisance and trespass claims for the resulting damage to their property and that the political question doctrine did not apply to this “ordinary tort suit.” 

In contrast to Judge Armstrong’s criticism of the AEP decision, the Fifth circuit lauded AEP’s “careful analysis” of the political question doctrine and sharply criticized the AEP trial court’s “serious error of law.”  

“It’s clear that these cases are hardly the last word, that there will be continued litigation and that there are still plenty of … good arguments from the defendant’s perspective as to why the [cases don’t] withstand scrutiny and full proof,” Tenpas said in reference to the AEP and Kivalina cases. 

The green light given to the federal judiciary by the Second and Fifth Circuits, combined with the EPA’s recent steps to regulate GHGs under the Clean Air Act, could place additional pressure on Congress and the relevant stakeholders to pass comprehensive climate change law for fear of courts (and juries) being involved in the business of climate change regulation. 

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

GHG Mandatory Reporting Rule

On September 22, 2009 the U.S. Environmental Protection Agency issued a final rule for mandatory reporting of greenhouse gases (GHG) from large GHG emissions sources in the United States.  

Changes from the April 2009 proposal:  

There are significant changes from the April 2009 proposal.  

Applicability – Reduced the number of source and supply categories that facilities and suppliers must report under this final rule. The following source and source categories are not required to report at this time:

Electronic manufacturing	Oil and natural gas systems
Ethanol production	SF6 from electrical equipment
Fluorinated GHG production	Underground coal mines
Food processing	Wastewater treatment
Industrial landfills	Suppliers of coal
Magnesium production

Exiting the Program – Added a mechanism for facilities and suppliers to cease annual reporting by reducing their GHG emissions.

o    Cease reporting after 5 consecutive years of emissions below 25,000 metric tons CO₂e/year.

o    Cease reporting after 3 consecutive years of emissions below 15,000 metric tons CO₂e /year.

o    Cease reporting if the GHG-emitting processes or operations are shut down.

 

Measuring Devices – Added a provision to allow use of best available monitoring methods in lieu of the required monitoring methods for January – March 2010. Facilities can request a date extension beyond March 2010, but EPA will not approve any requests for an extension beyond 2010.

 

Monitoring Equipment – In several subparts, added monitoring options, changed monitoring locations, or allowed engineering calculations to reduce the need for installing new monitors.

 

Sampling Frequency – For fuel combustion and some other source categories reduced the required frequency for sampling and analysis.

 

Exemption – Excluded R&D activities from reporting.

 

Quality Assurance – Added calibration requirements for flow meters and other monitoring devices including a five percent accuracy specification.

 

Report Revision – Added provision to require submittal of revised annual GHG reports if needed to correct errors.

 

Records Retention – Changed the general records retention period from 5 years to 3 years.

 

Verification – In several subparts, required more data to be reported rather than kept as records to allow EPA to verify reported emissions.

 

Combustion Sources – Added exemptions for unconventional fuels, flares, hazardous wastes, and emergency equipment. Reduced the need for mass flow monitors for some units or fuels. Allowed more facilities to aggregate reporting of emissions from smaller units rather than report emissions for each individual unit.

 

Manure Management Systems – Added an animal population threshold to reduce the burden of determining applicability. Reduced the monitoring requirements. 

Highlights of GHG reporting rule 

Categories that will need to report under the final GHG reporting rule:  

There are three types of sources that will need to report GHG emissions: upstream sources, downstream sources and mobile sources. The tables below provide details for each of these sources. 

Upstream Sources

Suppliers of Coal-based Liquid Fuels	Suppliers of Petroleum Products
Suppliers of Natural Gas and Natural Gas Liquids	Suppliers of Industrial GHGs
Suppliers of Carbon Dioxide (CO2)

 Downstream Sources

General Stationary Fuel Combustion Sources	Lime Manufacturing
Electricity Generation	Miscellaneous Uses of Carbonates
Adipic Acid Production	Nitric Acid Production
Aluminum Production	Petrochemical Production
Ammonia Manufacturing	Petroleum Refineries
Cement Production	Phosphoric Acid Production
Ferroalloy Production	Pulp and Paper Manufacturing
Glass Production	Silicon Carbide Production
HCFC-22 Production and HFC-23 Destruction	Soda Ash Manufacturing
Hydrogen Production	Titanium Dioxide Production
Iron and Steel Production	Municipal Solid Waste Landfills
Lead Production	Zinc Production
	Manure Management

 Mobile Sources – Vehicles and engines outside of the light-duty sector.

 Reporting Thresholds:

The emission based threshold is 25,000 metric tons of carbon dioxide equivalent (CO₂e) per year for most sources (other than mobile sources). The capacity based threshold will be used where appropriate and feasible. Approximately 85% of total U.S. greenhouse gas emissions covered by rule. It is estimated that there will be 10,000 reporters.  

There is an applicability tool online to help facilities assess whether they are required to report GHG, available here. 

Reporting Methodologies: 

Facilities already reporting and collecting emissions data for programs such as the Acid Rain Program must use direct measurement of emissions. Other source categories can use facility-specific calculations. Industrial gas ad fossil fuel suppliers use direct reporting of gas produced, imported and exported.  

Annual Reporting to EPA: 

Data collection will begin January 1, 2010 with the first reports submitted to EPA by March 31, 2011. Those facilities already reporting quarterly for existing mandatory programs (e.g. Acid Rain Program) will continue to report quarterly.  

Emission Verification: 

Reports will self-certify and submit emissions and activity data necessary for verification. EPA will have targeted audits. EPA can take enforcement action for non-compliance. This approach is consistent with most EPA programs.  

Mobile Sources: 

Emissions from mobile sources will be captured by reports from fuel suppliers and manufacturers of vehicles and engines. Note: There is no requirement for fleet operators or state and local governments to calculate GHG emissions from mobile sources.  

Confidential Business Information: 

EPA will protect any information claimed as confidential business information (CBI) in accordance with regulations in 40 CFR § 2, subpart B. In general, emissions data collected under CAA sections 114 and 208 shall be available to the public and cannot be withheld as CBI. The US EPA will undertake a separate notice and comment process next year on CBI status of data elements collected (comments received on the proposed rule will be considered as EPA develops the notice).  

Relationship to State and Regional Programs: 

This rule does not preempt States from regulating or requiring reporting of GHGs. USEPA will not delegate this program to the states. Reporting entities will report directly to EPA. For additional information on the relationship between the US EPA and the West Virginia GHG program is available in the following article.  

Electronic Data System: 

The USEPA is developing an electronic based reporting system. The system will be web-based. The web-based system will guide reporters through data entry and submission. There will be a mechanism to submit the electronic file directly using standard format (e.g. XML). There will be continued stakeholder input during system development. Once a system is developed, USEPA will provide training and hotline to assist reporters using the system.  

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.

Major Differences between West Virginia’s and USEPA’s GHG Reporting Rules

DAQ’s GHG Reporting Rule is more stringent than new federal counterpart in key aspects 

The WVDEP-Division of Air Quality (DAQ) has a relatively new GHG Reporting Rule – 45CSR42 “Greenhouse Gas Emissions Inventory Program” (effective June 1, 2008, known as Rule 42). Rule 42 requires mandatory reporting of specified greenhouse gases (GHG) over de minimis levels for Title V permittees in West Virginia. The first mandatory reporting of GHG for those sources subject to Rule 42 occurred earlier this year for calendar year 2008 emissions. 

The US Environmental Protection Agency (EPA) promulgated its final GHG Reporting Rule on September 22, 2009, at 40 CFR Part 98 “Mandatory Greenhouse Gas Reporting”. The EPA’s GHG Reporting Rule is much more detailed and specific than the DAQ’s Rule 42. 

The purpose of this article is not to discuss in depth each of these GHG reporting rules, but rather to highlight some of the areas in which the DAQ’s state reporting rule is more stringent than the federal rule. This matters for two reasons: 

1.   The West Virginia Air Quality Code (§22-5-4.(4)) contains the following “no more stringent than” federal counterpart provision: 

§22-5-4. Powers and duties of director; and legal services; rules.

 

…

(4) To promulgate legislative rules in accordance with the provisions of chapter twenty-nine-a of this code not inconsistent with the provisions of this article, relating to the control of air pollution: Provided, That no rule of the director shall specify a particular manufacturer of equipment nor a single specific type of construction nor a particular method of compliance except as specifically required by the "Federal Clean Air Act," as amended, nor shall any such rule apply to any aspect of an employer-employee relationship: Provided, however, That no legislative rule or program of the director hereafter adopted shall be any more stringent than any federal rule or program except to the limited extent that the director first makes a specific written finding for any such departure that there exists scientifically supportable evidence for such rule or program reflecting factors unique to West Virginia or some area thereof; 

2.   During the West Virginia rulemaking/legislative process in 2007 & 2008, industry groups were assured by WVDEP management that the DAQ GHG reporting rule would not be any more stringent than any future EPA GHG reporting rule. Industry was told by WVDEP that Section 4.3 of Rule 42 provided that assurance: 

4.3. The Secretary shall determine the form and format of the information reported by affected sources under subsection 4.1 to ensure that the information is consistent as possible with developing regional, national, or international greenhouse gas emissions programs. 

Rule 42 More Stringent than EPA Part 98 in These Key Areas 

A. Emission Thresholds – The EPA rule threshold is 25,000 metric tons/year of CO2 equivalent (CO2e), while the DAQ rule is 10,000 short tons/year of CO2e. Note that one metric ton equals approximately 2,200 pounds, while one short ton equals 2,000 pounds. 

B. Source Category Exclusions – The EPA rule completely exempts the following stationary source categories at this time, while the DAQ rule has no specified stationary source category exemptions:

·     Electronic manufacturing

·     Ethanol production

·     Fluorinated GHG production

·     Food processing

·     Industrial landfills

·     Magnesium production

·     Oil and natural gas systems

·     SF6 from electrical equipment

·     Underground coal mines

·     Wastewater treatment

·     Suppliers of coal 

C. Combustion Source Exemptions – The EPA rule has exemptions for certain combustion sources - unconventional fuels, flares, hazardous wastes, and emergency equipment, while the DAQ rule has no specified exemptions for these types of combustion sources. 

Note that there are many other differences between the EPA rule and the DAQ rule. 

Conclusions & Recommendations 

Since EPA Part 98 is not effective until calendar year 2010 operations, West Virginia sources who are subject to DAQ Rule 42 will still need to report their facility GHG emissions per the requirements of Rule 42 for calendar year 2009 operations.  

The author recommends that WVDEP-DAQ provide written guidance which clarifies that those West Virginia stationary sources who are within the scope of the federal EPA GHG reporting rule do not have to report GHG emissions under Rule 42. The author requests that DAQ specify that any West Virginia facility which either reports GHG emissions to the EPA per 40 CFR Part 98, or is exempt per 40 CFR Part 98 from federal reporting of GHG emissions, should also be exempt from all provisions of DAQ Rule 42. The regulated community is still awaiting official guidance from DAQ on this matter. 

For further details on the DAQ and USEPA GHG Reporting Rules, see the following web sites: 

• 45CSR42 “Greenhouse Gas Emissions Inventory Program”

http://apps.sos.wv.gov/csr/search.asp [to obtain a copy of Rule 42, type 45-42 in the Search For box and press enter, then click the appropriate links to download]

http://www.wvdep.org/Docs/17114_CY2008%20%20WV%20GHG%20Emission%20Inventory%20Instructions.pdf 

• EPA Final 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.

PSD and Title V Greenhouse Gas Tailoring Rule

On September 30, 2009, EPA announced that it is proposing a greenhouse gas emissions regulatory program that will require large industrial facilities that emit at least 25,000 tons of GHGs a year to obtain construction and operating permits covering these emissions. The prepublication version of the rule can be found at the attached link http://www.epa.gov/nsr/documents/GHGTailoringProposal.pdf. These permits must demonstrate the use of best available control technologies and energy efficiency measures to minimize GHG emissions when facilities are constructed or significantly modified. EPA is proposing a two phase program. The first phase will be a five year program tailored to address the most significant emitters of GHGs. At the end of that five years, there would be a study and proposal as to how best to refine and expand the regulation. 

The large facilities impacted by the first phase would include power plants, refineries, and factories. Small businesses such as farms and restaurants, and many other types of small facilities, would not be included in this round of requirements. 

This proposal follows immediately after the Federal Register publication of the proposed fuel-economy rule to regulate GHGs from cars and trucks is finalized. As you may recall, the U.S. Supreme Court Case, Masssachusetts v. EPA, 549 U.S. 479 (2007), held that GHGs are air pollutants covered by the Clean Air Act. The Supreme Court ruled that EPA must determine whether or not emissions of GHGs from new motor vehicles or motog engines cause of contribute to air pollution wich may reasonably be anticipated to endanger public health or welfare, or whether the science is too uncertain to make a reasoned decision. When the light-duty vehicle rule takes effect in the spring of 2010, (see proposal of September 28, 2009, 74 Fed. Reg. 49454 (http://frwebgate6.access.gpo.gov/cgi-bin/PDFgate.cgi?WAISdocID=093894486446+31+2+0&WAISaction=retrieve ), Clean Air Act permits would automatically be required for stationary sources emitting GHGs. This proposed rule focuses these permitting programs on the largest facilities, responsible for nearly 70 percent of U.S. stationary source greenhouse gas emissions. With the proposed emissions thresholds, EPA estimates that 400 new sources and modifications to existing sources would be subject to review each year for GHG emissions. In total, approximately 14,000 large sources would need to obtain operating permits that include GHG emissions. Most of these sources are already subject to clean air permitting requirements because they emit other pollutants.

The proposed tailoring rule addresses a group of six greenhouse gases: carbon dioxide (CO₂), methane (CH₄), nitrous oxide (N₂O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF₆). In addition, EPA is requesting public comment on its previous interpretation of when certain pollutants, including CO2 and other GHGs, would be covered under the permitting provisions of the Clean Air Act. A different interpretation could mean that large facilities would need to obtain permits prior to the finalization of a rule regulating greenhouse gas emissions. 

This article was authored by Kathy G. Beckett, Jackson Kelly PLLC, (304) 340-1019 or kbeckett@jacksonkelly.com. For more information on the author see here.