The Clean Power Plan’s Building Block 2. Generation Shifts Among Affected EGUs

(Clean Power Plan) Permanent link

This is the third in a series of posts explaining the “building blocks” that EPA used to determine emission goals for existing power plants in the Clean Power Plan. This post focuses on what EPA calls building block 2. In the final rule, building block 2 assumed a shift of generation—phased in gradually over the 2022 to 2030 interim period—from existing fossil-fuel fired steam generating units to existing natural gas combined cycle (“NGCC”) units, increasing the annual utilization rates of NGCC units, on average and within each region, to 75 percent on a net summer capacity basis.

EPA explained that “substituting generation from less carbon-intensive affected EGUs . . . for generation from the most carbon-intensive affected EGUs . . . is a component of the BSER for steam EGUs because generation shifts that will reduce the amount of CO2 emissions at higher-emitting EGUs . . . are technically feasible, are of reasonable cost, and perform well with respect to other factors relevant to” BSER.1 By carbon intensity EPA means the pounds of CO2 that are emitted for each MWh of electricity that is generated. 

In 2012, national average CO2 emission rates across the following technology types on a net generation basis were:  

  • Coal Steam: 2,217 lbs/MWh
  • Oil/Gas Steam: 1,435 lbs/MWh
  • NGCC: 905 lbs/MWh2  

Building block 2 only took “existing EGUs” utilizing NGCC into account, but for purposes of the final rule, the phrase “existing EGUs” included units that were under construction as of January 8, 2014.

EPA’s Basis for the Magnitude of Generation Shift

EPA concluded that “an annual average utilization rate of 75 percent on a net summer basis is a conservative assessment of what existing NGCC units are capable of sustaining for extended periods of time.” This is compared to EPA’s calculation that the NGCC fleet operated with an average annual capacity factor of 46% in 2012. EPA’s estimation of the amount of generation that can be shifted to NGCC was based on the assessment of two factors. First, EPA examined the ability of NGCC capacity to shift from its traditional use for peaking to serving as baseload generation with a higher utilization rate. Second, EPA examined the technical capacity of NGCC to sustain higher utilization rates.

To determine the extent to which generation could be shifted from existing coal to existing NGCC capacity, EPA looked at historical generation shifts to NGCC generation. Between 2005 and 2012, EPA determined that NGCC generation increased by approximately 439 TWh, representing an 83 percent increase. Importantly, while the GHG Mitigation Measures TSD was not explicit on this point, it appears that EPA’s evaluation of historical generation growth included both increased utilization of natural gas capacity that was already in existence, as well as the installation of new generation capacity over the period of analysis. EPA used this historical overall growth rate in NGCC as the basis for its expectation of the rate at which NGCC generation at existing units would grow under the Clean Power Plan. 

EPA compared its calculated 2005 to 2012 growth rate to the 2015 to 2022 time period (a time period of the same duration) to determine the potential growth in NGCC capacity that would result from the application of building block 2. Applying building block 2, total NGCC generation from these existing sources in 2022 was expected to be 1,498 TWh, which is an increase of approximately 44% over 2014 generation levels.

In addition to technical capability to support shifting generation, EPA concluded that the increase in NGCC generation assumed for building block 2 can be achieved without impairing power system reliability. EPA’s conclusion was based in large part on the fact that a shift in average annual utilization across existing EGUs will not interfere with the power sector’s ability to maintain adequate dispatchable resources to maintain reliability. Moreover, because sources are not required to achieve the full extent of building block 2, sources will have the flexibility they need to preserve reliability.

EPA also looked at the technical capability of existing natural gas infrastructure and the electricity transmission system to take on increased quantities of natural gas and to accommodate shifting generation. EPA determined that the natural gas pipeline system is already supporting national average NGCC utilization rates of 60 percent or higher during peak hours and concluded that it is reasonable to expect that similar utilization rates are possible in non-peak hours when constraints are typically less severe. 

EPA looked at projected natural gas production going forward and determined that the increase in NGCC generation contemplated under building block 2 is consistent with the production potential of domestic natural gas supplies. 

EPA evaluated the potential impact on the transmission planning process and concluded that the generation shift would not impose a significant additional burden on the transmission planning process and would not necessitate major construction projects. EPA’s conclusion was based in part on the fact that building block 2 does not call for the connection of any new capacity to the power grid. Moreover, EPA determined that regional grids are already supporting the operation of NGCC units at high capacity factors and for sustained periods of time. As such, EPA does not expect building block 2 to necessitate significant new construction beyond upgrades that are part of the normal planning process. 

Phase-In Schedule

EPA established the building block 2 phase-in schedule in two steps. The Agency first determined the generation shift that would be feasible by 2022, the first year of the interim period. It then considered how quickly that amount could grow until the full amount of NGCC generation (all existing plants operating at 75% of peak summer load) could be achieved as part of the BSER. EPA based both determinations on historical growth rates.

To determine the 2022 level, EPA identified the single largest annual increase in power sector gas-fired generation since 1990. The largest annual increase occurred between 2011 and 2012 and was equal to 22 percent. Therefore, EPA assumed that between 2012 and 2022 gas-fired generation would increase by 22 percent. For each year after 2022, EPA applied the average annual growth in gas-fired generation in the power sector between 1990 and 2012: approximately 5 percent per year.

Applying each of the above quantities, the final rule provided that for purposes of calculating BSER:  

  • NGCC generation in 2022 is limited to a maximum of a 22% increase from 2012 levels in each region.
  • In each subsequent year, NGCC generation is limited to a maximum of a 5% increase from the previous year.
  • The phase-in continues until the full level (75%) is reached in each region.  
BSER Maximum NGCC Generation by Region and Year (TWh).

1 Preamble, Pg. 429. 
2 Greenhouse Gas Mitigation Measures Technical Support Document, Pg. 3 – 4.

Posted by Margaret Peloso and Lauren Sidner at 10/05/2015 4:25 PM

The Clean Power Plan’s Building Block 1: Efficiency Improvements at Affected Coal-Fired Steam EGUs

(Clean Power Plan) Permanent link

This is the second in a series of posts explaining the “building blocks” that EPA used to determine emission goals for existing power plants in the Clean Power Plan. This post focuses on what EPA calls building block 1. Building block 1 consists of measures that improve heat rate at coal-fired steam electric generating units (“EGUs”). In the final rule, EPA concluded that “a well-supported and conservative estimate of the potential heat rate improvements” achievable through best practices and equipment upgrades is a 4.3% improvement in the Eastern Interconnection, a 2.1% improvement in the Western Interconnection and a 2.3% improvement in the Texas Interconnection.

An EGU’s heat rate refers to the amount of fuel energy input required (Btu) to produce 1 kWh of electrical output, and EPA described heat rate improvements as “changes that increase the efficiency with which an EGU converts fuel energy to electric energy, thereby reducing the amount of fuel needed to produce the same amount of electricity.” Because fuel combustion is the primary source of GHG emissions from EGUs, decreasing the amount of fuel required to produce a particular amount of electricity through heat rate improvements would also reduce the carbon intensity of a source’s generation.  

To calculate heat rate improvement potential for coal-fired EGUs, EPA employed three different analytical approaches to determine the degree of heat rate improvements reasonably achievable by each interconnection through the application of best practices and equipment upgrades.  EPA described the three analytical approaches as follows:  

  1. The “efficiency and consistency improvements under similar conditions” approach;
  2. The “best historical performance” approach; and
  3. The “best historical performance under similar conditions” approach.
For all three approaches, EPA used a dataset comprised of 11 years’ worth (from 2002 – 2012) of hourly gross heat rate for 884 coal-fired EGUs, and EPA reportedly employed a unit-specific approach, comparing each EGU’s performance against its own historical performance, rather than comparing an EGU’s performance against other EGU’s with similar characteristics.

Additionally, in each of the three approaches, EPA assessed potential heat rate improvements regionally, within the Eastern, Western, and Texas Interconnections. The Texas Interconnection generally corresponds to the portion of the state of Texas covered by the Electric Reliability Council of Texas.  

Each of the approaches resulted in heat rate improvement values that differed by several percent. According to EPA, the different values all represented reasonable estimates of the potential for heat rate improvements by EGU’s in the three interconnections, but EPA ultimately selected the most conservative value (meaning the smallest heat rate improvement) for each region. In all three regions, the most conservative values were generated using the “efficiency and consistency improvements under similar conditions” approach. As such, this approach is described detail below.

The “efficiency and consistency improvements under similar conditions” approach:

EPA determined that there are three sets of factors that influence an EGU’s heat rate (1) ambient temperature, (2) hourly capacity factor at the unit in question, and (3) unit-specific factors that are within the control of the operator. To control for the factors that are outside of the operator’s control, EPA structured its analysis of heat rate improvements under the “similar conditions” approach by segmenting each unit’s performance based on historical emissions in a series of capacity factor and ambient temperature combinations. To do so, EPA created a matrix comprised of 168 “bins,” each of which represented a 10-degree Fahrenheit range in ambient temperature, and a 10-percent range in capacity factor. EPA then distributed each hour of gross heat rate data for each EGU into the matrix. For example, one bin would contain all of an EGU’s hourly gross heat rate data generated from 2002 through 2012 while that EGU was operating at an 80- to 89-percent capacity while the ambient temperatures were between 70oF and 79oF.

EPA determined that its matrix appropriately controls for variations in temperature and capacity factor and that any remaining variation in each bin’s data would be primarily driven by factors within the EGU operator’s control, representing the possible range of heat rate improvements. EPA then established a benchmark for each bin based on each EGU’s 10th percentile hourly gross heat rate for each capacity-temperature bin. In other words, the benchmark was demonstrated by 10 percent of all measurements in each capacity-temperature bin. The Agency reportedly “chose the 10th percentile because it represents a demonstrably achievable gross heat rate indicating efficient operation of the EGU, but ignores unusually low outlier values.” EPA excluded outlier values that were greater than ±2.6 standard deviations from the EGU’s mean gross heat rate.

EPA then assessed the effect on overall heat rate that would occur if EGUs achieved more consistently efficient operation. To do so, EPA compared the data in each bin to the bin’s benchmark value and identified all hourly gross heat rate values that were greater than the benchmark. EPA then adjusted each hourly gross heat rate that was greater than the benchmark downward by a specific percentage, which EPA referred to as a “consistency factor.” EPA reportedly employed a statistical assessment of the overall variability of heat rate in each region to come up with the following consistency factors: 38.1% for Eastern Interconnection; 38.4% for the Western Interconnection; and 37.1% for the Texas Interconnection. For greater detail on the Agency’s procedure for calculating the applicable consistency factor, refer to page 2-48 of EPA’s Greenhouse Gas Mitigation Measures Technical Support Document (“GHG Mitigation Measures TSD”).

The Agency’s general approach is “based on the principle that a coal-fired EGU following best practices should be able to consistently operate closer to the demonstrated and achievable benchmark heat rate.” GHG Mitigation Measures TSD, pg. 2-46.

Applying this process to all 884 coal-fired EGUs in the dataset, EPA determined that it would be reasonable to conclude that, on average, EGUs are capable of improving heat rate by:
  • 4.3 percent in the Eastern Interconnection;
  • 2.1 percent in the Western Interconnection; and
  • 2.3 percent in the Texas Interconnection.
Example Equipment Upgrades and Best Practices for Heat Rate Improvements

EPA’s GHG Mitigation Measures TSD provides the following non-exhaustive lists of equipment upgrades and best practices that could be used to improve heat rates:

Equipment upgrades:
  • Install intelligent sootblowing system
  • Replace feed water pump steam turbine seals
  • Overhaul high pressure feed water pumps
  • Upgrade main steam turbine seals
  • Upgrade steam turbine internals
  • Install variable frequency drives for motors
  • Retube or expand the condenser
  • Install sorbent injection system to reduce flue gas sulfuric acid to allow lower temperature exhaust gas
  • Upgrade air heater baskets for lower temperature operation
  • Upgrade and repair flue gas desulfurization systems
  • Refurbish the economizer
  • Upgrade ESP components to lower auxiliary power consumption
  • Improve SCR and FGD system components to lower draft loss
Best practices 
  • Adopt training for O&M staff on heat rate improvements
  • Perform on-site appraisals to identify areas for improved heat rate performance
  • Install neural network software for combustion/optimization with monitoring system for heat rate optimization
  • Repair steam and water leaks – replace leaking valves and steam traps
  • Replace / repair worn air heater seals
  • Manage feed water quality
  • Chemical clean boiler to remove scale build-up from water side
  • Install and operate condenser tube cleaning system
  • Repair boiler furnace and ductwork cracks to prevent boiler air in-leakage
  • Clean air preheater coils to restore performance
  • Adopt sliding pressure operation to reduce turbine throttling losses
  • Reduce activation of attemperator which compensates for over-firing the unit
  • Remove deposits on turbine blades
Cost of Building Block 1

According to EPA, the cost attributable to emissions reductions under Building Block 1 is equal to the cost of achieving heat rate improvements less any savings from reduced fuel expenses. EPA expects that the savings in fuel cost associated with the percentage heat rate improvements identified for each region will cover much of the associated costs and predicts that even if EGUs were to rely primarily on equipment upgrades (rather than cheaper-to-implement best practices) to reduce heat rate, reductions could generally be achieved at $100 or less per kW, or approximately $23 per ton of  CO2 removed.

Posted by Margaret Peloso and Lauren Sidner at 10/05/2015 11:25 AM

Introduction to the Clean Power Plan’s Three “Building Blocks”

(Clean Power Plan) Permanent link

This is the first in a series of posts on the U.S. Environmental Protection Agency’s (“EPA”) Clean Power Plan, establishing emission guidelines for existing fossil fuel-fired electricity generating units (“EGUs”) under section 111(d) of the Clean Air Act (“CAA”). In particular, these posts will take a closer look at the three “building blocks” that form the basis for the CO2 emissions performance rates established in the final rule and how EPA uses those building-blocks to calculate the state-specific goals in the Clean Power Plan.

The Clean Power Plan establishes CO2 emissions performance rates that purportedly represent the best system of emissions reduction (“BSER”) for two subcategories of existing fossil fuel-fired EGUs—fossil fuel-fired electric utility steam generating units and stationary combustion turbines. Section 111 of the CAA requires standards of performance to be based on the BSER, which must account for a variety of factors, including the amount of reductions, costs, any non-air health and environmental impacts, energy requirements technical feasibility, and the advancement of technology. EPA determined the BSER for fossil fuel-fired EGUs through the application of three “building blocks.”

The three building blocks are:

  1. Improving heat rate at affected coal-fired steam EGUs.
  2. Substituting increased generation from lower-emitting existing natural gas combined cycle units for reduced generation from higher-emitting affected steam generating units.
  3. Substituting increased generation from new zero-emitting renewable energy generating capacity for reduced generation from affected fossil fuel-fired generating units.
In the posts that follow, we will provide a more in depth analysis of EPA’s formulation of and basis for each of the three building blocks, but in general, each building block encompasses a category of measures that could be implemented to reduce CO2 emissions from the electric generation sector. Building Block 1 contemplates heat rate improvements at coal-fired steam-generating units through application of both operational improvements and equipment upgrades, while Building Blocks 2 and 3 assume increases in low- or zero-emitting generation to substitute for generation from the affected EGUs.

EPA’s “building block” approach results in emission guidelines that are lower than what it actually expects any affected EGU to achieve because EPA chose to look at the system of electricity generation as a whole. While this approach may have serious legal vulnerabilities, the intention of this series of posts is to explain how EPA calculated the emissions reductions of each of the building blocks and used these building blocks to calculate both national and state-based goals. As we will describe in more detail in the coming posts, EPA relies on the three building block measures outlined above, but emphasizes that there are numerous other measures available to reduce CO2 emissions, and the Agency’s determination of BSER on the basis of these three building blocks does not necessitate their use by the states in developing state plans to implement the Clean Power Plan.

Posted by Margaret Peloso and Lauren Sidner at 10/02/2015 3:25 PM

The Clock has Started on EPA’s Newly Proposed Rules for the Oil and Gas Sector

(Federal GHG Regulations) Permanent link

On September 18, 2015, EPA published two proposed rules for the oil and gas sector in the Federal Register: (1) New Source Performance Standards for methane and volatile organic compound (“VOC”) emissions, and (2) new methods of defining the terms “source” and “adjacent” that that may significantly affect the applicability of major source permitting programs to activities in the oil and gas sector. This publication is significant because it starts the clock for the 60-day public comment period, which will close on November 17, 2015.  The date is also significant because once the rules are finalized they will apply retroactively to any oil or gas “affected facility” built or modified after September 18. More information about these proposals and the impacts that they could have on the oil and gas sector is available here and here.

Posted by Corinne Snow at 09/18/2015 5:15 PM

Time for Comments Ending on EPA Proposed Rule and Supplemental Proposed Rule Limiting Methane Emissions Limits from Landfills

(Federal GHG Regulations) Permanent link

On August 14, 2015, EPA released two rule proposals to reduce methane emissions from municipal solid waste (“MSW”) landfills. First, the agency issued a proposed rule regarding the threshold at which existing MSW landfills must install gas collection and control systems. The proposed rule would lower that threshold from 50 tons per year (“tpy”) of non-methane organic compounds to 34 tpy. It also expanded the control requirements for existing MSW landfills that exceed the threshold. Second, EPA issued a supplemental proposal for the New Source Performance Standards (“NSPS”) for new or modified landfills EPA issued on July 17, 2014. The supplemental proposal lowers the applicability threshold for the 2014 ANPR from 40 to 34 tpy.

The Federal Register published the two rule proposals on August 27, 2015. The notice-and-comment period for both documents will close on September 28, 2015.


MSW landfills receive non-hazardous wastes from homes and businesses. The waste creates methane bearing landfill gas as it decomposes. The EPA reports that landfills are the third-largest source of human-related methane emissions in the U.S., accounting for 18 percent of national methane emissions in 2013. EPA regulates methane as a greenhouse gas (“GHG”). According to EPA, the comparative impact of methane on climate change is 25 times greater than COover a 100-year period. EPA has also recently proposed new regulations for methane emissions from the oil and gas sector.

Proposed Rule and Supplemental Proposal

The proposed rule for existing sources would apply to MSW landfills that accepted waste after November 8, 1987, and commenced construction, reconstruction, or modification on or before July 17, 2014. The supplemental proposal for new sources would apply to MSW landfills that commenced construction, reconstruction, or modification after July 17, 2014.

Under the proposed rule and the supplemental proposal, the same 34 tpy threshold for installing emissions controls would apply to new and existing sources. New and existing landfills that exceed the threshold would need to install gas collection and control systems within 30 months after landfill gas emissions reach the 34 tpy threshold.

After EPA publishes the final existing landfills rule in the Federal Register, States will have nine months to prepare a plan implementing the rule. EPA’s Federal plan to implement the rule will be due six months after the State plans are due. EPA will have four months to review and approve the plans. If the process progresses on schedule, the emissions guidelines for existing landfills will become effective in March 2018.

Under the existing landfills proposed rule, an owner/operator may meet the control requirements of applicable State or Federal plans by routing its landfill gas to a non-enclosed flare, an enclosed combustion device, or a treatment system that processes the collected gas for subsequent sale or beneficial use. If owner/operators choose to treat the landfill gas for beneficial use, the proposal would require them to develop a site-specific treatment system monitoring plan that would include filtration, de-watering, and compression of the gas. In addition, the proposed rule would require regulations obliging owner/operators of existing landfills to conduct surface emissions monitoring of all surface penetrations on a quarterly basis and perform visual inspections to identify distressed vegetation, cracks, or seeps in the landfill’s cover. Finally, the proposed standards for existing landfills would apply at all times, including periods of startup, shutdown, and malfunction.

EPA based its supplemental proposal regarding new landfills on additional data it reviewed since it issued its proposed rule on July 17, 2014. That additional data included updated technical information regarding more than 1,200 landfills the agency received through its Greenhouse Gas Reporting Program, increased estimates of the methane emissions the supplemental proposal would prevent, and a lower estimated cost of compliance. Based on these inputs, the agency’s models show that landfill owner/operators can achieve the proposed methane emission reductions at a reasonable cost.

This diagram shows the major parts of a system for capturing and using methane from a landfill. Numbers on the diagram correspond with the steps listed on the page.

Source: Image from EPA

The current regulations regarding new and existing landfills apply to approximately 1,000 facilities, but only require 574 of these landfills to collect and control their emissions. The agency estimates that, compared to the current regulations, its supplemental proposed NSPS for new or modified landfills would require an additional 127 landfills to begin controlling their emissions of landfill gas by 2025 and would reduce methane emissions by 51,400 tpy by 2025 compared to current requirements. The regulations would only apply to new or modified landfills with a design capacity of 2.5 million metric tons and 2.5 million cubic meters of waste.

The EPA expects the proposed rule regarding existing landfills to have a greater impact than the supplemental proposed NSPS for new landfills. The EPA estimates that the proposed rule will increase the number of existing landfills that must install emissions collection and control systems from 574 to 680. Furthermore, the agency predicts that the proposed rule would reduce methane emissions from landfills by 436,000 tpy beginning in 2025. Landfills that closed on or before August 27, 2015, would remain subject to the current threshold of 50 metric tpy.

Posted by Ross Woessner at 09/17/2015 3:22 PM

What Midstream Businesses Need to Know About EPA’s Proposed Methane Air Emissions Rules

(Federal GHG Regulations, Renewable Fuel Standards and Biofuels, Clean Power Plan) Permanent link
Midstream Business recently published an article by V&E partner George Wilkinson and associate Corinne Snow discussing the key aspects of EPA’s recently proposed regulations for methane and volatile organic compound emissions from the oil and gas sector that will impact midstream operations. The article suggests particular issues that midstream businesses may want to comment on before the rule is finalized, including the method of monitoring “fugitive emissions” from equipment leaks, and replacing seals for centrifugal compressors. The article is available here.

Posted by Corinne Snow at 09/15/2015 3:00 PM

National Academies of Sciences to Review Social Cost of Carbon Metric Used by Federal Agencies to Value Greenhouse Gas Emissions

(Federal GHG Regulations, Climate Change Science) Permanent link

As discussed in this previous post, the administration has been making use of a tool known as the social cost of carbon (SCC) that attempts to place a present-dollar value on future climate benefits resulting from each ton of reduction in carbon dioxide emissions. Now the National Academies of Sciences will review the model currently used by federal agencies to determine the climate impacts of new regulations and certain federal actions under the National Environmental Policy Act.

Background on the Social Cost of Carbon
As discussed more fully here, economists have developed the SCC tool over the past two decades in an attempt to quantify the global costs associated with incremental changes in GHG emissions on a macro-level. The National Academies of Sciences describes the SCC as “an estimate, in dollars, of the long term damage caused by a one ton increase in carbon dioxide (CO2) emissions in a given year; or viewed another way, the benefits of reducing CO2 emissions by that amount in a given year. The SCC is intended to be a comprehensive estimate of climate change damages that includes, among other costs, the changes in net agricultural productivity, risks to human health, and property damages from increased flood risks.”

Under Executive Order 12866 federal agencies must, to the extent permitted by law, “assess both the costs and the benefits of the intended regulation and, recognizing that some costs and benefits are difficult to quantify, propose or adopt a regulation only upon a reasoned determination that the benefits of the intended regulation justify its costs.” By 2008, federal agencies had begun using SCC as part of their cost-benefit analysis. Originally, these agencies relied on differing models and estimates to assess SCC. These estimates ranged anywhere from approximately $0-150/ton CO2.

In 2010, the Interagency Working Group (IWG) released a report which created a uniform SCC value for federal agencies to use in assessing the impacts of their actions. The IWG’s model incorporates the three most well-known Integrated Assessment Models (IAMs) of climate change, known as DICE, FUND, and PAGE. The IWG revised its report in 2013, increasing the SCC estimates at the various discount rates for 2020 from $7, $26, $42 to $81 to $12, $43, $65, and $129/ton CO2 (in 2007 dollars) depending on the discount rate applied. The IWG revised these figures again in July 2015. For practical purposes, this means federal agencies are valuing the SCC at about based on a 3 percent discount rate.

Revised Social Cost of CO2, 2010 – 2050 (in 2007 dollars per metric ton of CO2)

The use of this model to measure the value of carbon emission reductions by federal agencies has been called into question from a number of sources. For example, this summer the United States House of Representatives’ Committee on Natural Resources held an oversight hearing on its use. Groups like the Electric Power Research Institute have also written about flaws in the models.

Review by the National Academies of Sciences
The IWG requested that the National Academies of Sciences review its SCC model. In response, the National Academies of Sciences’ Board on Environmental Change and Society has “assembled an interdisciplinary committee of experts to review the latest research on modeling the economic aspects of climate change to further inform future revision to the SCC estimates used in regulatory impact analyses.”

The review will be conducted in two phases. The first phase will examine the advantages and challenges of potential approaches to a near-term narrow update to the SCC. The committee anticipates issuing an interim report from the first phase in early 2016 and a final report in early 2017. The committee’s final report will also “examine potential merits of a range of alternative approaches to updating the SCC estimates, with the goal of ensuring that the estimates continue to reflect the best available science and evidence, and will highlight research priorities going forward.”

The committee has set up a website where the public can review the record and submit comments to the committee. 

Posted by Corinne Snow at 09/11/2015 1:15 PM