california

By Lee Vail

New projects require air permits and projects at major stationary sources that will emit (or increase) a significant amount of a regulated NSR pollutant, must conduct a control technology review.  In order to receive a permit, the applicant must determine the level of control considered Best Available Control Technology (“BACT”) and the permit issuing authority must agree.  This has been the rule for a long time and nothing is new.

As it relates to greenhouse gas (“GHG”) emissions, facilities that have a significant increase of a non-GHG and a significant increase in GHG must conduct a GHG BACT review.  Typically these reviews conclude that add-on controls, such as Carbon Capture and Sequestration (“CCS”), are infeasible. As a result, BACT may be a combination of good-engineering/good-combustion practices, low carbon fuels, or an emission limit.  The lack of feasible add-on controls is typically based on the high associated cost, the lack of controlling legal mechanisms, and the dearth of actual experience.  California has started a process that may start to address the last two issues.  As for the excessive cost of CCS, that will likely remain.  However experience usually results in some reduction of cost.

A little over a year ago, The California Air Resource Board (“CARB”) initiated a series of public workshops[1] with the goal of better understanding of “the ability of CCS to contribute to climate goals, the limitations or advantages of the technology, and the innovation and incentives necessary for adoption.”[2] Six additional “Technical Meetings” have occurred since that time and on May 8, 2017, CARB conducted a public workshop where CARB staff presented “an initial concept of a Quantification Methodology (QM) and Permanence Protocol for CCS.”[3] CARB is signaling the intent to establish QM and permanence requirements into California’s Low Carbon Fuel Standard (LCFS) in the near term with possible inclusion into the California Cap-and-Trade (“C&T”) regulation sometime in the future.

Following the May 8, 2017 workshop, CARB has received multiple substantive comment letters.  Many of these comments were from industry groups that provided significant positive technical comments.  That said general concerns with the current proposal were expressed:

  • Inability of moving carbon dioxide from one well to another (i.e., reuse carbon dioxide used for enhanced recovery).
  • Post-closure should not prohibit future activity in an oil reservoir if it can be shown that carbon dioxide is not released.
  • Well construction (cemented to the surface) will not allow use of existing wells and may be counterproductive with leak monitoring and mitigation.
  • Inclusion of QM for C&T should occur expeditiously.

California has unique laws concerning GHG control that create incentives to investigate CCS as an add-on technology.  CARB’s development of protocols (and eventually regulations) is clearly intended to spur activity along CCS activity.  Whereas, non-California projects are not constrained with C&T requirements, prolific expansion of CCS in California may make the infeasible argument more difficult. Close attention should be paid to this process.

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[1] CARB, Carbon Capture and Sequestration Meetings, found at https://www.arb.ca.gov/cc/ccs/meetings/meetings.htm.

[2] Workshop Notice and Draft Agenda, from Elizabeth Scheehle, Oil and Gas and Greenhouse Gas Mitigation Branch, CARB (January 21, 2016); found at https://www.arb.ca.gov/cc/ccs/meetings/Workshop_Notice_1-21-16.pdf.

[3] Workshop Notice and Draft Agenda, from Elizabeth Scheehle, Oil and Gas and Greenhouse Gas Mitigation Branch, CARB (April 18, 2017); found at https://www.arb.ca.gov/cc/ccs/meetings/Workshop_Notice_5-8-17.pdf

air

By Maureen N. Harbourt

EPA is required by Section 109(d) the Clean Air Act to review the adequacy of each National Ambient Air Quality Standard (“NAAQS”) every five years to determine if new scientific evidence justifies a change to the standard.  The current primary[i] NAAQS for nitrogen dioxide (“NO2”) is 53 ppb annual mean and 100 ppb NO2 as 98th percentile of 1-hour daily maximum concentrations, averaged over 3 years.  The annual average was first adopted in 1971, and was not changed during (overdue) reviews completed in 1985 and 1996.  In the next completed review in 2010, EPA added the 1 hour NO2 NAAQS to the standard based on a conclusion that the annual standard alone was not protective enough due to potential health impacts associated with short term exposures.[ii]  The 2010 review also indicated that there was a lack of data concerning near roadway exposures, which was of concern given that 34% of NO2 emissions are estimated to be generated from roadway vehicles.  Thus, the 2010 review led to EPA requiring states to install near-roadway monitors in urban areas during the 2014-2017 period.

EPA has just completed a final Policy Assessment reviewing the adequacy of the 2010 NAAQS and has concluded that no change to the existing standard is recommended.  82 Fed. Reg. 17947, April 14, 2017. The EPA Clean Air Science Advisory Committee (“CASAC”) also recommended no change to the standard.  The EPA’s Policy Assessment indicated that the additional roadway monitors installed as a result of the 2010 NAAQS rule have not been gathering data for a sufficient period (only 1-2 years) to fully evaluate such information, although the data that was available showed higher NOx concentrations near roadways than at nearby non-roadway monitors.[iii]  The Policy Assessment is the last step of the periodic NAAQS review process before any final EPA decision to revise or not revise the existing standards. It considers the Integrated Science Assessment, the Risk/Exposure Assessment, and the advice of the CASAC.

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[i] The primary NAAQS are set at a level to protect human health with an adequate margin of safety.  A secondary NAAQS is set at a level to protect human welfare, including decreased visibility and damage to animals, crops, vegetation, and buildings.  The secondary NAAQS for NO2 is currently equivalent to the annual primary standard (53 ppb annual mean).  EPA has recently completed an integrated science assessment for the secondary standards for NO2, sulphur oxides and particulate matter and has requested that the CASAC review that assessment.  82 Fed. Reg. 15701, March 30, 2017.

[ii] The EPA’s decision to add the 1-hour NO2 NAAQS was upheld in American Petroleum Institute v. Environmental Protection Agency, 684 F.3d 1342 (D.C. Cir. 2012), cert. den. 133 S.Ct. 1724 (2013).

[iii] The full EPA Policy Assessment is available here.

 

 

 

EPA

By Brittany Buckley Salup

On March 2, 2017, the EPA withdrew its information collection request (ICR) regarding methane emissions from existing oil and gas facilities.  EPA finalized and issued the underlying ICR on November 10, 2016.  Since that time, EPA sent letters to thousands of owners and operators in the oil and gas industry, requiring them to complete surveys regarding their existing facilities.  EPA’s withdrawal of the ICR is effective immediately.  According to the EPA’s website,  industry members who previously received a letter requiring a survey response associated with this particular ICR are “no longer required to respond.”

Additional information is available here.

 

EPA

By Brittany Buckley Salup

The Environmental Protection Agency (EPA) announced in March that it is in the process of developing new regulations to curb methane emissions from existing oil and gas facilities.  The EPA will formally require companies operating existing oil and gas sources to provide information to assist in the development of comprehensive regulations to reduce methane emissions.  Methane is a potent greenhouse gas with a higher global warming potential than carbon dioxide.  As a preliminary step in the process of developing methane regulations for already-existing oil and gas facilities, EPA plans to present an Information Collection Request (ICR) for public comment (via notice in the Federal Register) by the end of April 2016.

An ICR is a formal records request that requires the recipient(s) to provide reporting, records, or other specified information directly to the EPA.  Such ICRs are authorized by Section 114(a) of the Clean Air Act (CAA), which provides EPA broad authority to request information, provided the requested information is for one of three approved purposes: (1) to assist the Agency in developing rules or regulations; (2) to determine whether “any person is in violation” of any CAA requirement; or (3) to carry out “any provision of this chapter[.]” The EPA is in the process of developing an ICR that will help it identify and target significant sources of methane emissions at existing facilities.  The ICR will likely call for mandatory record-sharing, equipment surveys, and/or emissions monitoring.  Recipients of the ICR will generally be required to provide the requested information to EPA and will be required to attest that their responses are accurate.  Members of the oil and gas industry can expect to receive this ICR later this year, after public comment and final administrative approval.

EPA’s recently-announced plan is the latest in a series of moves to limit methane emissions from oil and gas facilities; however, this is the first significant proposal to target already-installed wells and other existing oil and gas equipment.  In 2012, EPA adopted regulations that limit methane and other emissions from new hydraulically fractured and re-fractured natural gas wells. EPA proposed rules for reduction of methane and volatile organic carbon emissions from new oil and gas facilities on September 18, 2015.  80 Fed. Reg. 56593.  The proposed rules for new facilities imposed methane reduction measures on oil and natural gas well sites, natural gas gathering and boosting stations, gas processing plants and natural gas transmission compressor stations.  The March 2016 announcement for existing facilities indicates that the ICR will apply to these same types of sources “as well as additional sources.”  This latest announcement has fueled concerns that the forthcoming regulations could, as a practical matter, require the industry to retrofit or replace existing production and processing equipment to achieve compliance.

For more information, see EPA Administrator, Gina McCarthy’s blog post on this topic here.

power

President Obama’s centerpiece of his climate policy agenda, the “Clean Power Plan,” has become one of the most heavily litigated environmental regulations ever. Twenty-seven states and numerous industry groups have filed more than fifteen separate lawsuits challenging the Environmental Protection Agency’s (“EPA”) statutory authority to promulgate the regulations.   Seventeen states, the District of Columbia, the cities of New York, Boulder, Chicago, Philadelphia, and South Miami, as well as Broward County, Florida and a number of public interest groups have intervened to support EPA.

The final rule[1] was published in Federal Register on October 23, 2015 titled “Standards of Performance for Greenhouse Gas Emission from New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units”.[2] The rule sets carbon dioxide emissions performance rates for affected power plants that reflect the “best system of emission reduction” (BSER), and requires each states to develop its own plan that will achieve those rates. However, if states do not submit approvable plans, EPA will substitute its own plan. Compliance is not required until 2030, although there are interim goals that must be met at 3 interim periods.

The Environmental Protection Agency refers to this regulation package as the “Clean Power Plan” and states that it is a “commonsense approach to cut carbon pollution from power plants.”[3] And that the “Clean Power Plan for Existing Power Plants and the Carbon Pollution Standards for New Power Plants” will maintain an affordable, reliable energy system, while cutting pollution and protecting our health and environment now and for future generations.”[4] However, many dispute whether the Clean Power Plan will have such positive effects, arguing instead concerns of economic feasibility with currently available technology, conflicting provisions, assumptions about renewable energy production that does not currently exist and potential for large loss of employment. “Every company that depends on electricity will be affected by this rule. It is fair to say that every American industry will be affected by this rule.” Karen Harbert of the U.S. Chamber of Commerce stated. The Clean Power Plan poses significant challenges for coal-fired power plants in particular, and the majority of states challenging the rule are coal producing states or rely heavily on coal-fired power plants.

The State of Louisiana and the Louisiana Department of Environmental Quality, are among the challengers to the rule. Petitioners argue that the final rule is in excess of the EPA statutory authority and otherwise is arbitrary, capricious, and abuse of discretion and not in accordance with the law. Among the primary arguments is that the rule may require states to mandate energy efficiency measures in addition to or in lieu of regulation of actual emissions limits. Other challenges include whether the rule will affect stability of the electrical grid.

The most recent notable ruling in the pending litigation is the recent Order denying the Motion for a Stay of the rule filed by several states, requesting that the Court halt the implementation of the Clean Power Plan until the pending litigation on the review of the final rule has concluded. On January 21, 2016 a three judge panel of the US Court of Appeals for the District of Columbia Circuit denied the motions to stay the implementation of the rule. The ruling is a victory for the EPA, which sought to begin implementation of the federal carbon regulations while they are under review in the courts. All U.S. states will now have until September 6, 2016[5] to submit preliminary strategies on cutting carbon emissions from their electrical power systems by thirty-two percent on average below 2005 levels – essentially mandating a massive conversion from coal-fired power generation to lower emitting natural gas and renewable energy sources as well as mandating some energy efficiency measures. EPA has published for comment, model state plans to assist the states, as well as versions of a proposed federal plan that will be implemented if states do not submit approvable measures.

The three judge panel that recently denied the request for a stay of the final rule includes the honorable Sri Srinivasan, Judith Roberts, and Karen Henderson, appointed by Presidents Obama, Clinton and Bush, respectively. The panel further ordered expedited review of the case, setting the matter for oral argument on June 2, 2016 at 9:30a.m. June 3, 2016 has also been reserved by the Court should oral arguments extend into the next day. The deadline for briefing is April 15, 2016 for initial briefs and final briefs to be filed by April 22, 2016.

Due to the complexity of the cases and the hundreds of parties involved, attorneys participating in the litigation do not expect a ruling on the merits until late 2016 or even 2017. Regardless of when the D.C. Circuit rules, observers widely expect that the case eventually will reach the Supreme Court. The high court may not rule until 2018. This is also complicated by the upcoming presidential election. Should a Republican take the White House, the new administration may direct the EPA to rescind the Clean Power Plan.

[1] 40 CFR Parts 60, 70, 71 and 98.

[2] Federal Register at 80 Fed. Reg. 64,510 (October 23, 2015). https://www.gpo.gov/fdsys/pkg/FR-2015-10-23/pdf/2015-22837.pdf.

[3] http://www.epa.gov/cleanpowerplan/fact-sheet-clean-power-plan-carbon-pollution-standards-key-dates.

[4] http://www.epa.gov/cleanpowerplan/fact-sheet-clean-power-plan-carbon-pollution-standards-key-dates.

[5] http://www3.epa.gov/airquality/cpptoolbox/technical-summary-for-states.pdf.

 

refinery_sunset_10212716

By Tokesha Collins and Lee Vail

On May 15, 2014, the Environmental Protection Agency (“EPA”) announced that it intended to publish a proposed rule to amend the national emission standards governing petroleum refineries. [1]  The emission standards impacted by this proposed rulemaking are:

  • National Emission Standards for Hazardous Air Pollutants (“NESHAP”) from Petroleum Refineries (40 CFR part 63, subpart CC) (Refinery MACT 1);
  • National Emission Standards for Hazardous Air Pollutants for Petroleum Refineries: Catalytic Cracking Units, Catalytic Reforming Units, and Sulfur Recovery Units (40 CFR part 63, subpart UUU) (Refinery MACT 2);
  • Standards of Performance for Petroleum Refineries (40 CFR part 60, subpart J) (Refinery NSPS J); and
  • Standards of Performance for Petroleum Refineries for which Construction, Reconstruction, or Modification Commenced After May 14, 2007 (40 CFR part 60, subpart Ja) (Refinery NSPS Ja).

The EPA’s stated reason for amending the petroleum refinery emission standards was to address the risk remaining after application of the standards promulgated in 1995 and 2002. The EPA proposes to amend the petroleum refinery emission standards to account for developments in practices, processes, and control technologies and also to include new monitoring, recordkeeping and reporting requirements. The EPA further proposes new requirements related to emissions during periods of startup, shutdown and malfunction (“SSM”) to ensure that the emissions standards are consistent with court opinions issued since promulgation of the standards.

The source categories affected by the EPA’s proposed rule include petroleum refineries engaged in converting crude oil into refined products, including liquefied petroleum gas, gasoline, kerosene, aviation fuel, diesel fuel, fuel oils, lubricating oils and feedstocks for the petrochemical industry.

Current regulations recognize the Delayed Coking Units (“DCU”) steam vent as a process vent; however, it is exempt at drum pressures below 15 psi, a pressure well in excess of industry practices. As a result, the EPA determined that direct atmospheric releases from the Delayed Coking Units (“DCU”) decoking operations are currently unregulated emissions and proposed a work practice standard of depressuring to 2 psi prior to opening the vessel. NSPS Subpart Ja currently allows a maximum pressure of 5 psi prior to depressuring. The EPA is requesting comment on whether depressurizing to 2 psig prior to venting to the atmosphere is the appropriate Maximum Achievable Control Technology (“MACT”) limit and whether it is appropriate to include restrictions for decoking operations draining, deheading and coke cutting, in the MACT requirements.

Over the last couple of years, the EPA has devoted significant enforcement resources to correcting alleged regulatory non-compliance of flares often citing federal requirements for equipment operator’s general duty under NSPS and NESHAPs. [2]  The EPA appears to be shifting away from its enforcement reliance on the general duty as the proposed rules acknowledge that existing “regulatory requirements are insufficient to ensure that refinery flares are operating consistently with the 98-percent HAP destruction efficiencies.” As a result, the EPA is proposing significant changes to standards for operations of flares, including that “refinery flares operate pilot flame systems continuously and with automatic re-ignition systems and that refinery flares operate with no visible emissions.” “Owners or operators of flares [must] monitor visible emissions at a minimum of once per day using an observation period of 5 minutes” with additional monitoring in the event of a single one minute visual observation. Further, the EPA is proposing to merge velocity requirements for steam and air assisted flares into a single standard and is proposing “new operational and monitoring requirements related to the combustion zone gas.” This requirement includes equipment that “fine-tune and control the amount of assist steam or air introduced at the flare tip such that combustion efficiency of the flare will be maximized.” “The proposed rule would allow the owner or operator flexibility to select the form of the combustion zone operational limit (i.e., net heating value, lower flammability limit, or total combustibles fraction) with which to comply in order to provide facilities the option of using monitors they may already have in place.” Also of interest, the EPA rejected including a requirement to maintain a maximum steam or air to fuel ratio in the standard as by itself it was inadequate to assure efficient operation.

The EPA is “proposing to revise Refinery MACT 1 for storage tanks to cross-reference the corresponding storage vessel requirements in the Generic MACT (including requirements for guidepole controls and other fittings as well as inspection requirements), and to revise the definition of Group 1 storage vessels to include storage vessels with capacities greater than or equal to 20,000 gallons but less than 40,000 gallons if the maximum true vapor pressure is 1.9 psia or greater and to include storage tanks greater than 40,000 gallons if the maximum true vapor pressure is 0.75 psia or greater.”

Also of significance, the EPA does not propose to change the fluid catalytic cracking unit (“FCCU”) limits found in the MACT standard other than to make them consistent with NSPS Subpart Ja. However, the EPA is proposing to require an FCCU performance test once every 5 years. The EPA also did not propose changes to the leak definitions applicable to the leak detection and repair (“LDAR”) program, changes to standards for gasoline loading racks, cooling towers/heat exchangers, wastewater treatment, reformer regenerations, and sulfur recovery units.

The EPA also recognizes that, in many cases, it is impractical to directly measure emissions from fugitive emission sources at refineries. For this reason, the EPA believes that it is appropriate under the Clean Air Act (“CAA”) section 112(d)(6) to require refiners to monitor, and, if necessary, take corrective action to minimize fugitive emissions, to ensure that facilities appropriately manage emissions of HAP from fugitive sources. The EPA proposes that a HAP concentration be monitored in the ambient air around a refinery that, if exceeded, would trigger corrective action to minimize fugitive emissions. The fenceline concentration action level would be set at a level such that no facility in the category would need to undertake additional corrective measures if the facility’s estimate of emissions from fugitive emissions is consistent with the level of fugitive emissions actually emitted. As part of the fenceline monitoring approach, the EPA seeks to develop a not-to-be exceeded annual fenceline concentration, above which refinery owners or operators would be required to implement corrective action to reduce their fenceline concentration. The EPA is soliciting comment on the application of the following alternative monitoring techniques that it has deemed to be “technically feasible and appropriate for monitoring organic HAP from fugitive emission sources at the fenceline of a petroleum refinery on a long-term basis”: (1) passive diffusive tube monitoring networks; (2) active monitoring station networks; (3) ultraviolet differential optical absorption spectroscopy (“UV-DOAS”) fenceline monitoring; and (4) open-path Fourier transform infrared spectroscopy (“FTIR”). Because there is no current EPA test method for passive diffusive tube monitoring, as part of this action, the EPA is proposing specific monitor citing and sample collection requirements as EPA Method 325A of 40 CFR part 63, Appendix A, and specific methods for analyzing the sorbent tube samples as EPA Method 325B of 40 CFR part 63, Appendix A.

The EPA is proposing to establish an ambient concentration of benzene at the fenceline that would trigger required corrective action. [Benzene is considered a surrogate for organic HAP from wastewater treatment systems at petroleum refineries, as it is present in nearly all refinery process streams.] Further, the EPA is proposing to require the reporting of raw fenceline monitoring data, and not just the highest fenceline concentration (“HFC”), on a semiannual basis. The EPA also proposes that facilities be required to conduct fenceline monitoring on a continuous basis, even if benzene concentrations, as measured at the fenceline, routinely are substantially lower than the concentration action level. To reduce the cost burden on facilities to comply with this rule, the EPA is soliciting comment on approaches for reducing or eliminating fenceline monitoring requirements for facilities that consistently measure fenceline concentrations below the concentration action level, and the measurement level that should be used to provide such relief.

The EPA is also proposing to remove the SSM exemptions for the petroleum refinery emission standards. As a result, affected units would be subject to an emission standard during such events. The EPA believes that the applicability of a standard during such events will ensure that sources have ample incentive to plan for and achieve compliance and thus the SSM plan requirements are no longer necessary. However, the EPA is proposing alternate standards for startup and shutdown periods for a few select emission sources. Generally speaking, the EPA expects that facilities can meet “nearly all” of the emission standards in Refinery MACT 1 and 2 during startup and shutdown. For Refinery MACT 1 and 2, however, the EPA has identified three emission sources for which specific startup and shutdown provisions may be needed. First, due to safety concerns associated with operating an electrostatic precipitator (“ESP”) during startup of the FCCU, the EPA is proposing specific particulate matter (“PM”) standards for startup of FCCU controlled with an ESP under Refinery MACT 2. Second, as many FCCU operate in “complete combustion” mode without a post-combustion device (i.e., for FCCU without a post-combustion device, organic HAP are controlled by the FCCU itself, so there is no separate air pollution control device (“APCD”) that could be operating during startup), the EPA is proposing specific carbon monoxide (“CO”) standards for startup of FCCU without a post-combustion device under Refinery MACT 2. Third, the EPA is proposing specific standards for sulfur recovery units (“SRU”) during periods of shutdown. The SRU essentially acts as the ACPD for the fuel gas system at the facility and would be operating if the refinery is operating, including during startup and shutdown events. However, there are typically multiple SRU trains at a facility, and different trains can be taken off-line as sour gas production decreases to maintain optimal operating characteristics of the operating SRU during startup or shutdown of a set of process units. Thus, the sulfur recovery plant is expected to run continuously and would only shut down its operation during a complete turnaround or shutdown of the facility. In such situations, the 12-hour averaging time provided for the SRU emissions limitation under Refinery MACT 2 may not be adequate time in which to shut down the unit without exceeding the emissions limitation.

In several prior rules, the EPA had included an affirmative defense to civil penalties for violations caused by malfunctions, to ensure adequate compliance while simultaneously recognizing that, despite the most diligent of efforts, emission standards may be violated under circumstances entirely beyond the control of the source. Under the EPA’s regulatory affirmative defense provisions, if a source could demonstrate in a judicial or administrative proceeding that it had met the requirements of the affirmative defense in the regulation, civil penalties would not be assessed. However, the recent court decision NRDC v. EPA, No. 10-1371 (D.C. Cir. April 18, 2014), 2014 U.S. App. LEXIS 7281, vacated affirmative defense provisions in the CAA section 112(d). In NRDC, the D.C. Circuit found that the EPA lacked authority to establish an affirmative defense for private civil suits and held that, under the CAA, the authority to determine civil penalty amounts lies exclusively with the courts, not the EPA. In light of NRDC, the EPA has declined to include a regulatory affirmative defense provision in this rulemaking. If a source is unable to comply with emissions standards as a result of a malfunction, the EPA may use its case-by-case enforcement discretion to provide flexibility, as appropriate.

[1] Consolidated Petroleum Refinery Rulemaking Repository, found at http://www.epa.gov/ttn/atw/petref.html (last visited May 28, 2014).

[2] See EPA Enforcement Targets Flaring Efficiency Violations, Enforcement Alert, Vol. 10, No. 5, August 2012.

 

 

 

By Tokesha M. Collins

On July 28, 2011, the Louisiana Department of Environmental Quality (LDEQ) denied a petition for the adoption of a rule to regulate fossil fuel carbon dioxide (CO2) emissions and to establish an effective emissions reduction strategy that will achieve a concentration of 350 parts per million (ppm) atmospheric CO2 by the year 2100. The petition was filed on May 4, 2011, by Kezia Kamenetz, of New Orleans, and Kids vs Global Warming, a non-profit organization formed in Oak View, California.

Continue Reading Louisiana Department of Environmental Quality Declines to Regulate Carbon Dioxide Emissions

By Maureen Harbourt

As of July 3, 2011, the air quality measured at the official ozone monitor at 1425 Airport Drive, which is within Shreveport, but located in Bossier Parish, indicated that the design value for the parish is now 76.7 parts per billion (ppb) which exceeds the 75 ppb standard set by EPA in 2008. 40 C.F.R. §50.15. The design value for each monitor is the 3 year average of the 4th highest ozone reading at that monitor each year. The exceedance of the current standard will likely cause the Louisiana Department of Environmental Quality (LDEQ) to propose that EPA designate Bossier Parish, and perhaps Caddo and DeSoto Parishes, as an ozone nonattainment area.

LDEQ was required to submit its recommendation for nonattainment designations under the 2008 ozone standard by March 12, 2009. EPA was then required to act on the proposals and make final designations no later than March 12, 2010. 73 Fed. Reg. 16436, 16503 (Mar. 27, 2008). In its 2009 recommendation, LDEQ did designate Caddo, but not Bossier or DeSoto, parishes as nonattainment. (1) However, when air quality in Caddo parish improved to compliance status over the past several years, LDEQ amended that recommendation in January 2010 to classify Caddo as attainment. (2)

Continue Reading Shreveport-Bossier Area Exceeds Current Ozone National Ambient Air Quality Standard – Triggers Potential Consequences for Air Emission Sources

by R. Lee Vail

New major and modified existing stationary sources require air permits prior to beginning construction. Where increases of criteria pollutants  such as sulfur dioxide, nitrogen dioxide, carbon monoxide, particulate and volatile organic compounds exceed a “significance” threshold, the permittee is required to analyze available and technically feasible control technology with the goal of selecting the best available control technology (BACT) for new or modified emissions units. With agency agreement, the selection of BACT becomes an enforceable part of the permit. 

We now have a new “pollutant,” greenhouse gas (“GHG”) equivalents for the six regulated greenhouse gases (carbon dioxide, methane, nitrous oxide, sulfur hexafluoride, perfluorocabons, and hydrofluorocarbons). GHGs are measured as equivalents to carbon dioxide, the most common GHG (CO2e). Starting January 2, 2011, permits issued for facilities that otherwise trigger PSD (as above) and have a new or increased potential to emit (PTE) of CO2e of 75,000 TPY, must address GHG emissions. Following July 1, 2011, a PSD permit may be required for significant increases in GHGs alone (100,000 tpy for a new source or 75,000 tpy for` a modification), even where there is no significant increase of any other regulated criteria pollutant. 

As with other pollutants, once PSD is triggered for GHGs, the permittee must evaluate and propose that which constitutes BACT to control the CO2e. Although the general scheme for selecting BACT is familiar, a top down ranking of available and technical feasible technologies, the available options are not. There are no conventional CO2e scrubbers or waste heat boilers, or filter traps to capture CO2e.  While some technologies are emerging, the process of determining BACT for CO2 control is a new frontier, and lack of guidance can cause permitting delays. To address some of the uncertainties,  EPA issued guidance on November 10, 2010 concerning permitting GHGs explaining the process for determining the required emission control technology – BACT.


 

Continue Reading EPA Issues Greenhouse Gas (GHG) Permitting Guidance

By Tokesha M. Collins

During the 2010 Session, the Louisiana Legislature enacted Act 986 to amend La. R.S. 30:2022, the state law concerning the Louisiana Department of Environmental Quality’s (LDEQ) permit process. The legislation began as House Bill 1169 and was authored by Representative Karen St. Germain. Governor Bobby Jindal signed the legislation on July 7, 2010, as Act 986. The Act became effective that same day.

The Act enacted La. R.S. 30:2022(D), which requires greater transparency from LDEQ regarding changes made to permits, renewals, extensions, and modifications. First, Act 986 requires that, if requested by a permit applicant, LDEQ provide the applicant with a written summary of the specific changes to the existing permit whenever LDEQ prepares a draft database permit for the renewal, extension, or substantial permit modification of an existing hazardous waste permit, solid waste permit, Louisiana Pollutant Discharge Elimination System (LPDES) permit, or air quality permit. The database is LDEQ’s Tools for Environmental Management and Protection Organization (TEMPO) database system. Previously, LDEQ was under no obligation to inform a permit applicant of each and every change that had been made in the renewal, extension, or substantial modification of an existing permit.
 

Continue Reading Legislature Changes Permit Process at the Louisiana Department of Environmental Quality