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Chapter 8

Other Configurations and Fuels

Contents

8.1 General............................................................................................................................................. 2

8.2 Combined Heat and Power and Industrial Cogeneration................................................................. 2

8.3 Biomass............................................................................................................................................ 9
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8.1 GENERAL

Comment 8.1-1: One commenter (9471) stated that the proposed standards do not account for combined 

cycle units that have a two-on-one or three-on-one configuration that may operate while one combustion 

turbine is out of service for maintenance, which reduces efficiency due to reduced heat input into the 

steam cycle. Though the mass emissions may decrease during this mode of operation, the lbs CO2 /MWh 

will increase, resulting in a violation of the standard despite the lower total emissions.

One commenter (10693) stated that EPA should not exempt power plants that combust solid waste, 

which contains a diverse mix of waste materials, some benign and some very toxic including trace 

metals and trace organics. Additionally, landfill gas consists primarily of carbon dioxide, methane, and 

non-methane organic compounds.

Response 8.1-1: The purpose of this rulemaking is to establish CO2 standards for fossil fuel-fired EGUs. 

Municipal waste combustors have not been typically included in this source category. Therefore, even if 

one of those units meets the general heat input and electric sales criteria, we are not finalizing CO2

emission standards for municipal waste combustors subject to subpart Eb of 40 CFR part 60.

8.2 COMBINED HEAT AND POWER AND INDUSTRIAL COGENERATION

Comment 8.2-1: Citing the environmental benefits and efficiency of adding cogeneration to an 

industrial steam system and generating electricity from excess steam, one commenter (9201) agreed with 

EPA's proposal to exempt most industrial cogeneration units.

Response 8.2-1: The intent of this rulemaking is to cover utility CHP units since they serve essentially

the same purpose as electric-only EGUs (i.e., the sale of electricity to the grid), but not industrial CHP 

units since they serve a different primary purpose (i.e., providing useful thermal output with electric 

sales as a byproduct). Based on public comments and after further analysis, the EPA makes two 

adjustments to the definition of applicability of this rule to CHP units. See section III.D.2 of the final 

rule preamble.

Comment 8.2-2: Several commenters (1898; 8994; 8952; 9002; 9503; 9665; 9592; 10682; 9201; 10038; 

10095; 10239; 10869) stated they were strong supporter of CHP plants and approved of EPA's support 

of CHP sources and their increased deployment and excluding them from the emission standards. 

Commenter (10095) stated that they support EPA specifically providing CHP facilities a 5% credit for 

avoided energy loss in the transmission of electricity. 

Two commenters (8944, 8952) stated that while recognizing that the proposed provisions for CHP 

reward the higher efficiency, the commenters stated the industry would be far better served and 

incentivized through an exemption of the technology from the proposed rule. 

Two commenters (9194; 9592) supported excluding CHP units that generate greater than 25 MWs with 

an overall efficiency greater than 70%. According to the commenter, CHP units have been built by

several utilities and have provided combined heat and power energy with equivalent CO2 emissions well 

below the proposed standard. It would be counterproductive to subject these units to a GHG NSPS 

standard. 
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One commenter (9665) believes that the agency should exempt from the GHG NSPS new CHP facilities 

that achieve a system efficiency of 75% (lower heating value) or higher regardless of how much 

electricity it supplies to the grid. According to the commenter, an exemption would not create a 

regulatory loophole as any CHP facility that could achieve a system efficiency of 75% would easily

meet the proposed emission limits. The benefit to a qualifying facility would be avoided time and 

expense of monitoring, recordkeeping, reporting, etc.

One commenter (8952) stated that by not exempting CHP units, the proposed rule incentivizes the 

development of capacity that will remain outside the current grid system. The commenter stated that it 

would be a burden on the end-user to catalog each unit of thermal energy reduced or estimate the 

resistive losses in the transmission system. Because the rule would only apply to grid-connected

generation, the rule could cause CHP facilities to not connect to the grid system so as not to be captured 

by this requirement. This would result in the additional negative consequence that CHP facilities deny

their capacity to the grid foregoing their potential role as system support in unusual events.

Several commenters (10098, 10085, 9733, 10239) stated that given their energy efficiency and 

environmental benefits and the fact that the Administration is actively promoting CHP in other contexts, 

EPA should exclude CHP units from the rule.

One commenter (7990) recommended that the Proposed Rule be modified to establish a reasonable level 

of CHP efficiency.

One commenter (10098) stated that for EPA to impose regulations here that could discourage new

facilities. At a minimum, if EPA regulates CHP, it must fully recognize the benefits it offers by applying

an appropriate discount for avoided electricity losses through transportation and by counting all thermal 

energy toward gross energy output.

Several commenters (9733, 10098, 10239) stated that if EPA maintains, however, that industrial, 

commercial, and institutional CHP units should be included under the rule, the commenters supports the 

Agency's proposal to apply a discount for avoided electricity losses through transmission. However, 

based on data from the U.S. Energy Information Administration, the discount should be increased from 

5% to 7%.

One commenter (9733, 9002) stated that the final rule should exempt all CHP units where useful thermal 

output accounts for at least 20 percent of the total useful output as EPA had considered in its April 2012 

proposed rule. According to commenter 9733, the lower emission rates for CHP facilities means that 

new CHP boilers and new turbines will already meet subpart D/KKKK/TTTT requirements. With the 

right policy and economic conditions, CHP can represent a significant portion of U.S. electric capacity. 

In 2008, the Department of Energy's Oak Ridge National Laboratory calculated that if CHP provided 20 

percent of U.S. electric capacity, carbon emissions could be reduced by more than 800 million metric 

tons (MMT) per year. In this 20 percent scenario, over 60 percent of the projected increase in CO2

emissions between now and 2030 could be avoided.

The commenter (9733) stated that by exempting CHP facilities meeting the proposed power and thermal 

energy minimum outputs, EPA would provide incentives for new generation facilities to consider colocating at manufacturing and other steam hosts and to develop highly-efficient CHP, as opposed to 

stand alone power generation. Such an exemption would provide a positive precedent for EPA's 
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guidelines for state plans for existing facilities under CAA section 111(d) as well as for policy makers 

who are continuously examining their policies to incentivize CHP. 

The commenter (9733) stated that if EPA does not exempt all CHP units from, it should at least exempt 

industrial units as fundamentally different than EGUs. While the commenter does not agree with the 

proposal to continue to subject non-utility units to other aspects of the standard of performance, such as 

recordkeeping, and relieving them only of their obligation to meet the emission limits, the commenter 

does appreciate that EPA is recognizing the distinctions between industrial and utility combustion 

turbines. The commenter stated that EPA should continue to make those distinctions in its EGU 

regulations, as appropriate, and that EPA's recognition of the distinction supports exempting industrial 

CHP units from regulation.

One commenter (10239) stated that in recognition of the benefits that CHP units offer, the DOE has 

adopted a number of initiatives to promote industrial distributed energy in the United States, and the 

Administration has set a national goal of increasing CHP deployment by 40 gigawatts (50%) by 2020. 

Exempting entirely industrial CHP units will promote adoption of efficient, reliable, and low-emission 

distributed generation. Because industrial CHP units must meet source-specific needs, the balance of 

thermal energy and electricity production vary and may shift over any given time period making 

calculation of thermal energy equivalence (conversion to kWh) extremely challenging for reporting and 

enforcement purposes. Regulation is further complicated by the use of third party-owned CHP units at 

adjacent industrial facilities. EPA also failed to assess whether industrial CHP units could meet the 

proposed standards relying instead on a hypothetical example of a CHP. EPA should exclude industrial 

CHP units from Section 111 until it can determine how CHP units could calculate their GHG emissions 

under real-world conditions and how the proposed emission limitation would impact those units.

One commenter (10239) stated that if EPA does not exempt all CHP units, EPA should exempt CHP 

units whose primary purpose is not the production of electricity for sale in the retail market. Industrial 

CHP facilities provide thermal energy and, to a lesser degree, electric energy for internal facility

operations and are typically designed to maximize thermal energy output. The electric output to a utility

power generation system is limited to residual electric power that cannot be used by the facility. The 

production of such electricity is not the primary purpose of the CHP unit. The EPA should recognize 

that these facilities are not fossil fired EGUs and exclude them from the subcategories to which the 

proposed rule applies. To provide greater certainty for facilities, the commenter urged EPA to adopt a 

quantitative test that ensures that industrial CHP units used for manufacturing or oil and gas facilities are 

excluded from fossil fuel-fired EGU subcategories.

One commenter (10239) stated that using a variety of methods, EPA could exclude from this 

rulemaking:

 Any CHP facility that supplies less than two thirds of its net combined thermal and electric 

output to a utility power generation distribution system or to a utility steam system distribution 

system on an annual MMBtu basis. 

 CHP units that simultaneously produce power and heat and, at the time the unit is placed into 

service, have an energy savings of 10% or more when compared to units that produce heat and 

power separately.

 CHP facilities based on Standard Industrial Classification or other codes to distinguish between 

the EGUs that are subject to the NSPS and manufacturing and oil and gas facilities that are 

excluded from it.
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 CHP units that have total thermal energy production that approaches or exceeds the unit's 

electricity production.

 Industrial CHP units by fuel type. For example, the EPA could exempt all industrial CHP unit 

that are fired predominantly with biomass, are fired with gaseous fuels (i.e., pipeline, natural, 

field, and refinery fuel bases).

One commenter (9774) stated that the potential applicability of the rule to CHP units creates a 

significant disincentive for new projects that would only be viable if they sell electricity to the grid. 

Applicability of the NSPS standard may also result in the loss of current CHP capacity. The commenter 

gave an example of a facility that currently operates solid fuel fired fluidized bed boilers to generate 

electricity and to supply thermal heat to nearby industry. CCS cannot be expected to be cost-effective 

for this type of electric supplier. Currently, the proposed regulation would likely prohibit the facility 

from replacing these units using the same fuels in the future. The result may be that the facility

discontinues operation instead of efficiently providing power and heat to end-users at lower CO2 rates 

than can be achieved by separated dedicated power systems serving each need. The commenter stated 

that EPA should exclude efficient CHP from regulation under the proposed NSPS rule. Exempt CHP 

could potentially be defined as projects achieving a 75% overall efficiency although the appropriate 

level should be further evaluated. This recommended approach will actually encourage the addition of 

CHP electricity to the grid.

One commenter (9002) stated that the proposal appropriately does not cover the forest products industry 

CHP units. This is appropriate due to the substantial energy efficiency and avoided GHG emission 

benefits provided by this industry's CHP units. 

One commenter (10554) stated that CHP facilities should be subject to the same requirements as 

electric-only generators under any NSPS for GHGs. The CO2 standard of performance should apply to 

all systems including CHP facilities that supply more than one-third of their energy output as electricity.

One commenter (9503) urged EPA to add a fourth criterion for excluding CHP facilities for CHP 

facilities that are highly efficient. This exclusion could make use of the definition of CHP already set 

forth in the Proposed Rule, and include an efficiency benchmark. The commenter's recommendation is 

to set the benchmark for highly efficient at 65 percent or greater overall plant efficiency, including 

thermal, mechanical and electric output. The reason is that this number is in use by several federal and 

state policies aimed at promoting efficient CHP.

One commenter (8952) prefers to exempt a SC turbine, the prime mover in the CHP.

One commenter (8918) stated that given the infinite potential heat-to-power ratios of CHP facilities, the 

equivalency approach used by EPA may limit the development of CHP facilities because the approach 

cannot fairly assess all of the potential ratio configurations and requires that a separate heat and power 

base case be developed. In many cases, an accurate base case cannot be established. Lastly, the EPA's 

equivalency approach is predicated on the assumption that the steam host would have installed new 

equipment subject to a NSPS. 

Response 8.2-2: See section III.D.2 of the final rule preamble for the EPA’s response to this comment.

Comment 8.2-3: One commenter (9042) agreed that an affected facility should be able to use its nonemitting energy generation to comply with the emission standards. They suggested that EPA also 
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consider allowing affected facilities to utilize their off-site non-emitting energy generation to comply 

with the emission standards to the extent that it can be quantified and verified.

Response 8.2-3: The final rule permits the use of integrated non-emitting technologies as a means of 

reducing emission rates. 

Comment 8.2-4: One commenter (9733) stated that two recent distributed generation rules use different 

approaches than the 50% credit for thermal output used by the FERC and the 1997 utility NSPS. Stating 

that CHP is more environmentally beneficial than the existing NSPS approach, the commenter 

recommended the Regulatory Assistance Project (RAP) approach using information such as the desired 

standard, total emissions, thermal emissions and electric output. They stated that one benefits of this 

approach is that CHP units that produce primarily electricity would have to operate at an input-based 

emissions rate that is close to what utility units must achieve. CHP units producing primarily thermal 

output would be able to operate at an input-based emissions rate that is close to what industrial boilers 

must achieve. 

Response 8.2-4: Based on further consideration and review of the comments submitted, the EPA is 

finalizing 100 percent credit for useful thermal output for all newly constructed, modified, and 

reconstructed CHP sources. Full credit for useful thermal output appropriately recognizes the 

environmental benefit of CHP. See sections III.F.2 and III.D.2 of the final rule preamble. 

Comment 8.2-5: One commenter (9733) stated that they are very concerned about the precedent of a 

75% factor for useful thermal output. Congress is considering an overhaul of tax incentives for clean 

energy and is deliberating whether CHP should receive tax credits, and whether and how to credit CHP 

thermal output. Congress likely will look to the final rule as an important precedent on this subject. 

Further, there are 42 states with either a Renewable Portfolio Standard (RPS) or an Energy Efficiency

Resource Standards (EERS), 21 allow CHP to be used for compliance. CHP supporters continually are 

seeking to expand CHP opportunities in other states. EPA is well aware of these efforts and agency staff 

have helped provide technical resources to further the education of participants engaged in the 

legislative deliberations. It makes no sense for EPA to support these efforts on the one hand, but then to 

set an adverse national precedent for CHP on the other.

Response 8.2-5: See Response 8.2-4 for the EPA’s response to this comment. 

Comment 8.2-6: One commenter (10682) stated that the vast majority of CHP projects will not be 

subject to the rule. The standard only applies to a facility that supplies more than one-third of its 

potential electricity output and more than 219,000 MWh net electric output to the grid per year. Net 

electric output excludes power purchased by the facility during the year. As EPA recognizes, CHP 

systems are often owned and operated by third-party developers, who are distinct from the thermal host. 

This arrangement is necessary because of the substantial upfront cost and ongoing maintenance 

responsibilities for a CHP or WHP system. The commenter supports EPA's proposed solution of 

clarifying that applicability of the rule will be based on gross electric sales to the utility minus purchased 

power of the thermal host facility. This recognizes the reality that such sales do not constitute sales to 

the grid.

One commenter (10095) stated they also support EPA's intent to subtract purchased power of adjacent 

facilities in calculating the 219,000 MWh applicability criteria threshold for CHP facilities. In order to 

subtract the purchased power of adjacent facilities, the commenter believes it is EPA's intent not to 
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require the direct transmission of electricity to the adjacent facility. EPA needs to provide clarification 

regarding this calculation.

One commenter (10095) stated that CHP facilities will potentially be dependent on third parties for 

applicability and compliance determinations. Due to uncontrollable third party risks, EPA needs to 

provide flexibility to CHP facilities in the event an adjacent facility stops purchasing electricity and/or 

thermal output or has an outage/malfunction. For example, if an issue arises with a CHP facility's 

electricity and/or thermal off-taker, EPA should allow the CHP facility time to find a new off-taker or 

reconfigure the facility prior to making applicability and/or compliance determinations.

Response 8.2-6: Based on public comments and after further analysis, the EPA makes two adjustments 

to the definition of applicability of this rule to CHP units. See section III.D.2 of the final rule preamble.

Comment 8.2-7: One commenter (10681) supports that an appropriate thermodynamic calculation be 

made to determine the useful energy used rather than a simplified approach based on what could be 

possible. The thermodynamic calculations for each CHP plant can be submitted in a report to the 

permitting authority for review. The report would propose the equations and justifications supporting 

thermal energy used and thermal energy lost. The report and the calculation methodology would then be 

approved for use by the owner/operator of the unit. Simplified methods will provide a disincentive to a 

CHP facility or cogeneration facility from taking maximum benefit of the steam produced or energy

contained in hot flue gases.

Response 8.2-7: The EPA believes the final calculation is adequate. See final preamble.

Comment 8.2-8: Several commenters (8918; 8972; 9503; 9665; 8972; 10038; 10682) stated that they

encourage EPA to account for and encourage useful heat output from CHP and recommended that the 

rule should increase the thermal credit from 75 to 100% to account for all of the useful thermal output 

from a combined heat and power or waste heat to power system. One commenter (9665) stated that no 

reasons are given to limit to 75 percent the amount of useful thermal output that facilities can count 

towards its gross energy output, despite allowing 100% of electric and mechanical output to be counted. 

EPA also solicits comment on whether the thermal "discount should instead be set "on a range of twothirds to three-fourths." According to commenter 9665, EPA has offered no justification for why thermal 

output should be discounted at all. According to commenter 9665, anything less than 100% under values 

the true efficiency of the facility and runs counter to EPA's goal of maximizing energy efficiency.

Multiple commenters (9733, 10239) stated that they oppose the provision that would only count 75% of 

the useful thermal output of CHP units and if EPA does regulate CHP units, they should count 100% of 

useful thermal output for compliance determinations.

One commenter (9733) stated that it is unclear why EPA discounted useful thermal output. EPA may 

have relied on previous CAA rulemakings in which it was concerned about so-called "sham" CHP. The 

commenter stated that EPA had noted that the Federal Energy Regulatory Commission (FERC) provided 

only a 50% credit for thermal output for "Qualifying Facilities." EPA may have believed that FERC was 

attempting to dissuade "sham CHP" units by not providing overly generous benefits to them. If EPA 

included a 75% factor to help prevent "sham" CHP units, the Proposal already has such provisions. First, 

to qualify as a CHP unit, 20% percent of the total gross useful energy output must consists of useful 

thermal output. Further, proposed section 60.4373(d) requires that "[i]f the affected stationary

combustion turbine is a CHP stationary combustion turbine, you must also install, calibrate, maintain, 
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and operate meters to continuously determine and record the total useful recovered thermal energy." By

requiring continuous monitoring, this provision should help preclude so-called "sham" CHP.

One commenter (10239) stated that EPA recognizes that this may be incorrect and seeks comment on 

the appropriateness of crediting a range of two-thirds to three-fourths of the useful thermal output in the 

final rule. The commenter does not believe that any discount is appropriate. The commenter stated that 

the 2006 NSPS for Stationary Combustion Turbines awarded a full (100%) thermal credit and several 

states have awarded a 100% thermal credit. The EPA is aware of this precedent. The Proposed 

Stationary Combustion Turbine Rule favorably cited Texas' permit-by-rule regulation, which gives 

facilities 100% credit for steam generation thermal output. Second, the Associations agree that a 

discount for avoided electricity losses through transmission and distribution is warranted. However, as a 

practical matter, average national transmission and distribution losses are closer to 7%. Thus, if the EPA 

includes CHP in the final rule, the Associations urge EPA to increase the discount factor from 5% to 

7%.

One commenter (7990) recommends that EPA align its regulation with the CHP performance standard 

under the Public Utility Regulatory Policies Act (PURPA) program, which uses a thermal discount 

factor of 0.5 for thermal energy output.

Response 8.2-8: See Response 8.2-4 for the EPA’s response to this comment.

Comment 8.2-9: Several commenters (9503, 8972, 9665, 10682) favor increasing the line loss credit for 

CHP. Commenters (8972-180; 9503-6748) stated that the proposed line-loss credit does not accurately

reflect avoided line losses and suggested that, based on information from the EIA, it be increased to 7 

percent to reflect national average line losses. One commenter (9665; 10038) stated that EPA should 

increase the credit from 5 percent to 6 percent to reflect EIA's estimated national average line losses. 

The commenter (9665) stated that EPA does not explain why 5 percent is an appropriate credit in light 

of EIA's estimate and other studies that estimate losses at times to be as much as three times higher than 

the national average. One commenter (8918) urges EPA to continue to recognize this benefit with its 

transmission factor in the proposed NSPS.

One commenter (7990) stated that the transmission and distribution (T&D) loss factor should apply only

to the electricity used on-site. The electricity supplied to the grid should not be discounted as this 

exported electricity will experience T&D losses similar to other central station power generation.

Response 8.2-9: CHP units are located closer to load centers than remote non-CHP EGUs. This final 

rule only includes CHP units that sell a significant portion of their potential electric output to the grid. 

While it is not possible to precisely identify the line loss benefits, but 5 percent is a reasonable 

approximation.

Comment 8.2-10: One commenter (10681) questioned the including an adjustment factor for avoided 

line losses. Being able to account for avoided line losses only makes sense when it is legally possible for 

a plant with a CHP unit to utilize net metering. If EPA wants to further encourage, CHP, it could draft 

this rule to allow for the avoided line loss adjustment in states where large-scale (in terms of 10s of 

MWs) net metering is allowed.

Response 8.2-10: The line loss credit accounts for CHP units being located close to electric load 

centers, thus avoiding transmission losses. It is not related to net metering.
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Comment 8.2-11: One commenter (9665) supports EPA's proposal to amend the definition of "net 

electric output" to ensure that third-party CHP developers are treated the same as CHPs and adjacent 

"thermal host" facilities that are under common control. The commenter agrees that this addresses an 

existing inequity found in the existing NSPS and would serve to further promote additional installations 

of CHP facilities.

Response 8.2-11: The EPA appreciates the support of the commenter.

Comment 8.2-12: One commenter (9665) recommends that EPA revise the definition of "potential 

electric output," to allow CHP facilities to determine their potential electric output based not just on a 

unit's "maximum design heat input capacity," but on its total system efficiency. Such an approach would 

reward units that maximize the efficient use of their fuel inputs and encourage others to do the same. 

Under the current definition, there is no incentive for facilities to improve overall system efficiency. 

Response 8.2-12: See Response 8.2-6 for the EPA’s response to this comment.

Comment 8.2-13: One commenter (10682) was very supportive of CHP and Waste Heat to Power 

(WHP) as cleaner, more cost-effective and more efficient alternatives to traditional power generation. 

The commenter stated that maximizing waste heat capture and use from power generation (CHP) and 

industrial operations (WHP), and improving supply-side energy efficiency, including both CHP and 

WHP, can reduce power sector greenhouse gas emissions while at the same time saving families and 

businesses money, cutting co-pollutant emissions, stimulating local economies, and creating jobs. 

Mobilizing demand-side energy efficiency, expanding renewable energy generation and shifting use to 

cleaner generation sources similarly offer significant potential to reduce emissions from conventional 

power plants. The commenter recommended that EPA adopt a system-wide approach to carbon 

reduction from existing power plants reflecting the full range of solutions that can secure meaningful 

and cost-effective emissions reductions. The commenter cited the findings from a 2008 DOE study 

quantifying the environmental benefits of an increasing the presence of CHP and WHP capacity. The 

commenter provided examples of how CHP plants have both provided power to the grid and steam to 

nearby industrial plants.

Response 8.2-13: In making reference to carbon reduction from existing power plants, the comment 

appears to address the proposed carbon pollution emission guidelines for existing EGUs (79 FR 34830, 

June 18, 2014) rather than the proposed standards of performance for GHG emissions from new EGUs.

As such, a response is not provided here as this comment is outside the scope of this rule.

8.3 BIOMASS

Comment 8.3-1: Several commenters (9409; 9733; 9425; 10031; 10045; 10095; 10052; 11056) 

supported treating emissions from biomass differently than fossil fuels including exempting emissions 

from the combustion of biomass.

One commenter (9733) stated that based on the GHG avoidance from the use of forest products 

manufacturing residuals, EPA should not regulate biogenic CO2 emissions from the combustion of 

biomass in affected CHP units. The commenter recommended that EPA clarify that the rule is intended 

to exclude all biogenic CO2 associated with burning biomass under the NSPS until EPA has completed 

its science review of biogenic CO2 emissions. The commenter provided references to characterize the 

benefits of using biomass residuals for energy production, including the NCASI study providing 
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evidence of the impact of using residual biomass as fuel versus their disposal on global warming. They

stated that disposal will produce more GHG than using the residuals for energy production.

One commenter (9425) stated that in setting standards for units burning natural gas, EPA must recognize 

that a unit converted to gas from coal or oil will not be physically capable of meeting the same standards 

as a new, green-field natural gas unit. Conversion to lower carbon intensive and/or carbon neutral fuels 

is being considered within our industry as an option to meet other non-GHG regulations. New NSPS 

GHG standards should not discourage conversions to these other fuels. The commenter specifically 

requested that biomass be exempted and considered a carbon neutral fuel.

One commenter (10031) stated that EPA should continue to exempt biomass-fired units from the 

standards in the rule. Moreover, EPA should develop an approach for crediting new units that co-fire 

with biomass, thereby equitably accounting - in the final rule - for the amount of CO2 sequestered by the 

applicable biomass fuel.

One commenter (10095) stated that they support EPA's proposal that an EGU that primarily fires 

biomass would not be subject to the proposed CO2 emissions standards. This exclusion incentivizes the 

use of biomass; however, EPA should further incentivize its use by excluding all biogenic CO2

emissions from an affected facility's compliance calculation. Such an exclusion is consistent with 40 

C.F.R. part 98 (the mandatory GHGRP) which requires separate reporting of CO2 emissions from fossil 

fuels and biogenic sources. EPA should allow the use of the 40 C.F.R. part 98 calculation methodologies 

to determine a unit's biogenic CO2 emissions for compliance with this proposal to be consistent with the 

metric tons of CO2 that the unit will report to EPA under 40 C.F.R. part 98. Indeed, [a] long standing 

inventory convention adopted by the IPCC, the UNFCCC [United Nations Framework Convention on 

Climate Change], the U.S. GHG Inventory, and many other reporting programs is separate treatment of 

emissions of CO2 from combustion of biomass and biomass-based fuels from emissions of CO2 from the 

combustion of fossil-based products.

One commenter (10045) stated that emissions of Crop-Derived CO2 and any indirect CO2 emissions 

associated with production and gathering of crop residues as EGU fuel are harmless to the global 

warming process and, therefore, emissions of Crop-Derived CO2 must be excluded from compliance 

determinations under the instant NSPS once finalized. The commenter (10045) stated that they analyzed 

the changes in atmospheric CO2 for four different industries: corn wet milling, corn dry milling, corn 

stover combustion, and wastewater treatment. For the industries studied, the changes are all positive, 

i.e., the cumulative effect of processing biogenic carbon at these facilities is to reduce atmospheric CO2

levels. As part of their submittal, the commenter provided details of these analyses.

One commenter (9676) stated that EPA cannot on the one hand defer regulation of biogenic emissions 

under the Tailoring Rule because of the necessity to study the science while on the other hand adopt a 

regulation that draws an arbitrary limit on how much fossil fuel can be used at an affected facility under 

NSPS.

One commenter (9409) stated that as the focus of the proposal is fossil fuel-fired electric utility steam 

generating units and stationary combustion turbines, biomass-fired EGUs do not fit within either of the 

source categories that EPA seeks to regulate here. Subpart Da applies only to EGUs that combust 

minimum quantities of fossil fuels and biomass-fired EGUs fall outside of the applicability requirements 

of subpart KKKK. Supra, biogenic CO2 emissions are distinct from fossil fuel CO2 emissions because 

biomass is part of the natural carbon cycle and the carbon emitted from biomass-fired EGUs is rapidly

cycled between atmospheric and terrestrial carbon pools. Given these important distinctions, there is no 

basis to expand these source categories to include biomass-fired facilities in this proposed rule. Also, it 
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would be premature for EPA to impose standards on biomass-fired EGUs under any source category at 

this time because EPA is still in the process of developing a policy for how, if at all, it will account for 

biogenic CO2 emissions in regulations designed to reduce atmospheric GHG concentrations. 

International and domestic regulators also have consistently recognized that biogenic CO2 emissions 

have no net impact on atmospheric CO2 concentrations. Until EPA completes this process and issues a 

final rule addressing how to account for biogenic CO2 emissions, the Agency simply has no scientific or 

technical basis on which to set standards of performance for CO2 emissions from biomass-fired EGUs. 

One commenter (9409) stated that EPA's proposed Tailoring Rule directed that sources should rely on 

EPA's GHG Inventory to calculate a source's GHG emissions. The GHG Inventory does not count CO2

emissions from combustion of biomass at stationary sources. The final Tailoring Rule reversed course to 

regulate biogenic and fossil CO2 emissions in the same manner. The commenter has petitioned EPA to 

reconsider the Tailoring Rule's treatment of biomass combustion. EPA granted petition for 

reconsideration of its biogenic policy. EPA's decision to reconsider its Tailoring Rule appropriately was 

met with broad endorsement by the Obama Administration. EPA is conducting a thorough scientific 

review of the climate impacts of biogenic CO2 emissions and plans to develop a new regulatory

approach to biogenic CO2 emissions. 

One commenter (9409) described the uncertainty resulting from the proposed NSPS for sources using or 

considering using biomass as fuel. EPA's proposal to treat biogenic and fossil CO2 emissions from cofiring EGUs in the same manner raises significant uncertainty for existing facilities that may consider 

co-firing biomass in the future and has the potential to foreclose any further expansion of biomass cofiring at coal-fired EGUs. The commenter stated that until EPA establishes GHG standards for modified 

and reconstructed sources, fossil fuel-fired EGUs that make changes to accommodate co-firing of 

biomass will be at risk of triggering the proposed GHG emissions limits. The uncertainty caused by such 

a provision could, as a practical matter, deter any expansion of biomass co-firing until the regulatory 

status of modified sources is clarified. Treating biogenic and fossil CO2 emissions in the same manner 

will mask the GHG emission benefits that co-firing with biomass can offer. The commenter also 

summarized the events surrounding EPA's deferred application of PSD and Title V to biogenic CO2

emissions for three years to allow a scientific review of biogenic CO2 emissions and the court challenges 

to that deferral.

One commenter (9409) stated that EPA and the states should incorporate, to the fullest extent possible, 

the GHG emission mitigation benefits that biomass has to offer in forthcoming existing source NSPS 

rules. Recognizing the potential climate benefits, the commenter urges EPA to account for the role that 

biomass energy can play in reducing net GHG emissions, both at a facility-by-facility level through cofiring with fossil fuels and at a broader utility or state level through construction of biomass-fired EGUs 

in lieu of fossil fuel-fired EGUs. The commenter stated that policies that promote additional 

afforestation or reforestation increase the amount of land that is actively sequestering carbon from the 

atmosphere. Wood products store carbon throughout the entire life of the product, and in many cases, 

they can be substituted for more carbon intensive alternatives, such as concrete or steel. Thus, promoting 

a strong and healthy forest products industry is an effective way of reducing net GHG emissions. As it 

develops standards, regulations, or guidelines to address GHG emissions from existing sources under 

Section 111(d), the commenter urges EPA to work closely with the USDA and in particular the U.S. 

Forest Service to ensure that it fully and appropriately incorporates the GHG mitigation benefits of 

forest biomass. The commenter also urges EPA to accommodate and promote existing state programs 

that recognize the climate benefits of forest biomass.
8-12

Some commenters (10119; 10693) do not support the combustion of biomass for electricity generation

nor an exemption of biomass-fueled power plants.

One commenter (10119) stated that even if net biogenic carbon cycle effects are taken into account, 

emissions from biomass power plants can increase atmospheric CO2 concentrations for decades to 

centuries depending on feedstocks, biomass harvest practices, and other factors. Multiple studies have 

shown that it can take a very long time to discharge the "carbon debt" associated with bioenergy

production, even where fossil fuel displacement is assumed, and even where "waste" materials like 

timber harvest residuals are used for fuel. One study, using realistic assumptions about repeat bioenergy

harvests of woody biomass, concluded that the resulting atmospheric emissions increase may even be 

permanent. EPA thus cannot assume that "biogenic" CO2 emissions have no effect on the climate. 

"Biogenic" and fossil CO2 are indistinguishable in terms of their atmospheric forcing effects. Rather, a 

full and scrupulously accurate life-cycle analysis is essential to understanding the greenhouse gas 

implications of burning biomass for energy.

One commenter (10693) stated that the environmental and health impact of biomass power is directly

related to the feedstock from which the energy is derived. For example, urban waste, such as 

construction or demolition debris, is usually inexpensive relative to other biomass feedstocks, and 

combusting this debris at a biomass plant diverts it away from landfills. However, such waste may be of 

low-quality, meaning that more feedstock is required to produce a given amount of electricity, or contain 

high-levels of impurities, resulting in greater air emissions. Biomass combustion increases the risk of the 

emission of noncarbon air pollutants releasing many of the same air pollutants as fossil-fuel generation, 

although the quantities may differ substantially on per MWh basis. Without controls, combustion of 

biomass for power production can result in PM emissions more than 20 percent higher than emissions 

from an uncontrolled coal plant. Emissions of carbon monoxide and VOCs can be more than 400 

percent and 2,000 percent higher than emissions from a coal plant, respectively. In contrast, NOx 

emissions may be nearly 60 percent lower and SO2 emissions are virtually eliminated. Combustion of 

wood wastes, such as construction and demolition debris, may also produce toxic air pollutants.

One commenter (9198) stated that they are concerned that the rule may have negative, unintended

consequences for renewable energy and materials management efforts, as well as their ability to market 

renewable alternative fuels to customers. The commenter was particularly troubled that the proposed 

treatment of biogenic CO2 emissions may set a precedent for CO2 emissions accounting in other Agency

actions, such as the Section 111 rules for modified and existing power plants, as well as for permitting 

under the GHG Tailoring Rule. EPA proposes to apply the same accounting method for biogenic CO2

emissions as is used for fossil fuel-derived CO2 emissions from new power plants for purposes of 

compliance with the NSPS. Although the Agency states that it is evaluating accounting for biogenic 

emissions from stationary sources, it does not indicate when it will complete its evaluation or how it will 

develop a biogenic accounting framework. Further, EPA does not explain how such a framework will be 

reflected in the GHG NSPS for new power plants, or other Agency actions.

The commenter (9198) stated that EPA's treatment of biogenic emissions has implications for new and 

existing power plants, and other stationary sources, as well as for federal and state renewable energy and 

fuels programs. The success of these regulatory programs will depend on EPA developing an accounting 

and compliance framework that can differentiate biogenic emissions from various biomass feedstocks 

(i.e., by using lifecycle analysis or another approach). The commenter states that the Science Advisory

Board (SAB) view that "EPA should not assume carbon neutrality for all biomass energy absent a 

consideration of a particular feedstock's production and consumption cycle" and that the panel 

recommended that "not all sources of biogenic CO2 emissions should be treated in the same manner." 
8-13

EPA has yet to initiate the promised rulemaking to address biogenic CO2 emissions. EPA's 111(b) 

proposal indicates that the Agency intends to treat biogenic- and fossil fuel-derived CO2 as equivalent in 

affecting the environment. The SAB conclusions do not support such an approach, and the commenter 

urges EPA to follow the SAB advice and promptly initiate a rulemaking to implement a workable and 

sound framework for accounting for the categories of emissions identified by the SAB as having a BAF 

of zero. If the Agency continues on its present course, it will significantly harm the ongoing 

development of the biogas industry, which are delivering significant GHG reductions, as recognized in 

EPA's most recent U.S. Inventory of Greenhouse Gas Emissions and Sinks, which documents that U.S. 

methane emissions fell by 30 percent between 1990 and 2012. The Administration, Congress and the 

international community recognizes that the use of LFG produced by the decomposition of organic 

waste materials is a cost-effective and environmentally beneficial way to reduce emissions of methane, a 

potent greenhouse gas. 

One commenter (9409) stated that EPA has committed to using the results of this scientific review 

process to develop new, permanent regulations that will address the applicability of PSD and Title V to 

biogenic CO2 emissions from stationary sources. However, EPA has offered no firm timeline for 

completing a policy or rulemaking process for biogenic CO2 emissions.

Two commenters (9675; 10029) stated that they along with the rest of the algae industry, urge the EPA 

to clarify that CO2 beneficial reuse technologies using algae may be applied by affected EGU's, alone or 

in combination with other technologies, to meet the proposed CO2 emission limits. The commenter 

supports the comments developed by Sapphire Energy. The commenters provide an extensive 

description of the benefits and opportunities of applying reuse technology using algae as a means of 

reducing and sequestering CO2:

- Algae efficiently converts CO2 and sunlight into green crude oil that, once refined, is fully 

compatible with the existing transportation infrastructure. Importantly, in its growth process, 

algae consume enormous amounts of CO2.

- While palm oil can yield 554 gallons of oil per acre, algae can yield 5,107 gallons per acretenfold more. Further, the production of algae-based fuel does not require arable land or potable 

water and therefore does not create significant indirect land use effects.

-There has been a sharp acceleration in the pace of algae-based fuel science and technology, 

which shows that the commercial-scale production of algae-based fuel is much more practical 

and is likely to occur much sooner than previously thought. 

- Construction began of the world's first commercial algae-based fuel facility, the Integrated 

Algal Biorefinery ("IABR") in Columbus, New Mexico.

One commenter (10681) stated that if EPA wants to exempt primarily biomass fueled facilities from 

applicability of these requirements, the fossil fuel fraction should be increased from 10% to someplace 

between 25 and 33% of the total heat input to the utility boiler or cogeneration boiler. They gave the 

example of a cogeneration facility at a pulp and paper mill that uses coal for 15 to 20% (up to 33%) of 

its heat input is not primarily fired by biomass. Because this cogeneration unit sells all of its electrical 

output (more than 219,000 MWh/year and more than 1/3 of its equivalent thermal output), it would be 

subject to the proposed rule, if it were proposed as a new source. We do not believe that this is the 

outcome that EPA was intending. 
8-14

One commenter (9409) stated that they are concerned that EPA mistakenly has proposed to treat 

biogenic CO2 emissions from fossil fuel-fired EGUs that co-fire biomass in the same manner as fossil 

fuel emissions. This will discourage the expansion of biomass co-firing and the carbon benefits that it 

can provide. We urge EPA to reconcile its position on co-fired facilities with its position on biomass 

generally and to defer regulation of these emissions until the Agency develops a final policy to account 

for biogenic CO2 emissions. Given the aggressive standards that EPA has proposed for both coal- and 

natural gas-fired EGUs, facilities may be unwilling to co-fire biomass out of concern that doing so will 

jeopardize their ability to comply with the proposed emissions limits. Thus, given EPA's recognition of 

the climate benefits of biomass energy, the proposed rule's treatment of co-fired biomass would likely 

have the perverse effect of increasing rather than decreasing atmospheric GHG concentrations.

One commenter (9733) states the combustion of biomass does not contribute to the "air pollution" that 

EPA intends to address through regulation of GHGs. Commenter concludes that biogenic CO2 

emissions would not add to atmospheric carbon levels unlike fossil fuel emissions and, therefore, should 

be excluded from this rule. Commenter continues it would be arbitrary and capricious to regulate 

biogenic CO2 emissions from CHP units that burn forest products manufacturing residuals for energy 

recovery because there is no scientific basis to do so. Commenter explains that burning forest products 

manufacturing residuals releases CO2 (and minor amounts of methane and nitrous oxide) into the 

atmosphere from the oxidation of the biomass. Burning avoids GHG emissions that would occur anyway

if these residuals were not burned because biodegradation can release more methane than combustion, 

and methane is considered to have a greater impact on global warming than CO2.

Response 8.3-1: Applicability and emissions from non-fossil sources are discussed in Section III.D of 

the preamble.

Comment 8.3-2: Commenter 10131 stated that the EGU GHG states that the SAB report (regarding 

biogenic emissions) is currently under review and that EPA will, "move forward as warranted once the 

review is complete." Commenter further stated that by enacting this rule, the EPA is moving forward in 

opposition to the recommendations made in 2012. Commenter further stated that Low carbon fuels are 

available for use now. Commenter further stated that their use is tried and true and do not require new 

technology or research to put into operation. Commenter further stated that in the EPA's efforts to 

reduce carbon emissions, it is important to use the resources at our disposal and to properly account for 

operations that lower GHG emissions. Commenter further stated that the EPA should act now on the 

EGU GHG to incorporate the SAB's recommendations.

Additionally, commenter 10131 stated that the EPA's Landfill Methane Outreach Program (LMOP) 

encourages the use of LFG as an energy resource. Commenter further stated that one of the primary

reasons EPA launched LMOP was to reduce GHGs. Commenter further stated that according to EPA's 

LMOP website, "CO2 emissions from MSW landfills are not considered to contribute to global climate 

change because the carbon was contained in recently living biomass. Commenter further stated that the 

same CO2 would be emitted as a result of the natural decomposition of the organic waste materials 

outside the landfill environment." Commenter further stated that the EPA change this proposed rule to 

be consistent with the SAB report and assign a BAF of zero for landfill gas.

Response 8.3-2: EPA developed the revised draft report, Framework for Assessing Biogenic CO2

Emissions from Stationary Sources, to continue advancing our understanding of the role the use of 

biomass can play in strategies to address greenhouse gas emissions. Specifically, the Framework was 

developed as a policy-neutral framework for assessing biogenic CO2 emissions from stationary

sources—it was not developed as technical guidance in conjunction with any specific policy or program. 
8-15

The EPA is engaging in a second round of targeted peer review of the revised draft Framework with the 

SAB in 2015.1 Applicability and emissions from non-fossil sources are discussed in Section III.D of the 

preamble.

 

1

For more information regarding the Framework, see: http://epa.gov/climatechange/ghgemissions/biogenic-emissions.html