From:

"Higgins, Cortney" <Cortney_Higgins@omb.eop.gov>

To:

RobertJ Wayland/RTP/USEPA/US@EPA, Jim Eddinger/RTP/USEPA/US@EPA, David Cozzie/RTP/USEPA/US@EPA, Amy 

Hambrick/RTP/USEPA/US@EPA, Thomas Gillis/DC/USEPA/US@EPA, Nick Hilosky/DC/USEPA/US@EPA, Jim 

Berlow/DC/USEPA/US@EPA

Date:

06/12/2012 03:16 PM

Subject:

FW: Recommendations to OMB

Hi all,

Consistent with EO 12866, attached are comments we received on the rules under review.

Regards,

Cortney

From: Echols, Mabel E. 

Sent: Tuesday, June 12, 2012 1:32 PM

To: Higgins, Cortney

Subject: FW: Recommendations to OMB

From: Sharon Daniels [mailto:SharonDaniels@gephardtgroup.com] ( 

mailto:%5Bmailto:SharonDaniels@gephardtgroup.com%5D )

Sent: Tuesday, June 12, 2012 12:46 PM

To: Echols, Mabel E.

Subject: FW: Recommendations to OMB

Dear Mabel:

Attached are some documents that Waste Management felt prudent to send in advance of our meeting tomorrow at 2:00 pm with Mr. Mancini 

and his team. There are two documents from Waste Management to the EPA, they have included these as background and because they 

contain cited studies that Waste mentions in their recommendations.

Many thanks again for your help and assistance in setting up this meeting. I look forward to meeting you.

Best regards,

Sharon

Sharon Daniels

Senior Vice President

Gephardt Government Affairs

1101 K Street, Suite 310

Washington, DC 20005

Phone: 202-403-2064

(See attached file: Recommendations for OMB on Reconsideration Rules June 13 2012 

WM-DSWA.docx) 

(See attached file: WM Final CISWI-NHSM Rule Reconsideration comments.DOCX) 

(See attached file: WM Final Boiler Reconsideration comments.DOCX)
1 

Recommendations for OMB 

Landfill Gas (LFG) Issues in Non-Hazardous Secondary Materials (“NHSM”) 

Commercial and Institutional Solid Waste Incineration (“CISWI”) and Boiler 

MACT Rules 

EPA should clarify in the NHSM and CISWI regulations that uncontained gases, 

including landfill gas (LFG), are not solid waste under RCRA when combusted. 

The definition of “solid waste” under RCRA includes only “contained gaseous material” and 

does not include uncontained gaseous material. Agency statements in the Responses to 

Comments Document for the Final NHSM Rule (February 2011) at (3b-13-1; 3b-13-2; and 3b-13-

4) created confusion over the regulatory status of process gases, including landfill gas (LFG), 

that are not contained in a container when combusted. EPA’s response indicated that the 

Agency had changed long-standing interpretation of what constitutes “contained gaseous 

material” an element of the definition of “solid waste,” as well as the regulatory status of LFG. 

EPA has since provided “comfort letters” to WM and the paper industry (AF&PA) clarifying that 

EPA has not changed its prior interpretations regarding “contained gas” and affirmed generally 

that gaseous material is not solid waste unless held in a container when combusted, consistent 

with the regulatory definition and interpretations of “contained gaseous material” EPA has 

used over many years and in various contexts. EPA’s letter to WM clarified that it did not 

intend to change prior interpretations of the regulatory status of LFG. (Attachment A – August 

5, 2011 Letter from EPA to Waste Management) 

In addition, EPA offered further clarification in the CISWI Reconsideration and Proposed 

Amendments to the NHSM Rule: 

“Accordingly, the proposed CISWI reconsideration rule includes the same definition of 

"contained gaseous material" that was removed from the final CISWI rule. 

This definition is consistent with the definition in the subparts cited above. Moreover, our 

proposal to add the definition of "contained gaseous material" to the proposed CISWI 

reconsideration rule is consistent with the position in other sections of this preamble that 

address the NHSM rule where we make clear that the Agency is not changing any of its 

previous positions with regard to contained gas. The EPA is soliciting comment on the 

need to retain the definition of contained gaseous material.” (76 FR 80463)
2 

Despite these clear statements of Agency intent, other Agency statements have muddied the 

waters. As described in the attached letter to Mr. Stanislaus from multiple major 

manufacturing, energy generation and solid waste management sectors, the Agency has 

apparently refused to clarify to North Carolina air pollution control regulators that the burning 

of LFG and paper manufacturing process gases is not the burning of solid waste. As a result, the 

North Carolina Department of Air Quality has apparently taken the position that LFG 

combusted in landfill gas-to-energy projects must meet the legitimacy criteria enumerated in 

the NHSM Rule in order to avoid classification as solid waste combustion subject to CISWI. In 

this context, the Agency’s letter to WM has been misinterpreted, and throws into doubt EPA’s 

statements with respect to its unchanged interpretation of what constitutes a “contained gas” 

within the definition of solid waste under RCRA.. 

Given the confusion caused by the Agency’s various statements with respect to contained gas, 

both in its rulemaking preambles and letters to industry, we believe that it is imperative that 

the Agency affirmatively state in both the final CISWI Reconsideration Rule and the NHSM 

Rule Amendments that the longstanding definition of “solid waste” extends only to 

“contained gaseous material” as has been defined by EPA and to further clarify that the 

combustion of gaseous emission streams, including landfill gas, does not constitute the 

combustion of solid waste subject to the CISWI Rule.

WM and DSWA support the explanations in the CISWI Reconsideration and the NHSM Rule 

Amendments preambles that affirmed the language in the WM comfort letter, as well as a 

comfort letter written to the American Forest & Paper Association, and clearly stated that EPA 

did not intend to change its previous interpretations of what constitutes “contained gaseous 

material.” We strongly recommend that EPA finalize its clarifying language in the preambles 

to both final rules and add to the preamble discussions a further clarification that landfill gas 

is not a contained gas, and therefore not a solid waste when combusted in engines, turbines or 

other combustion devices that combust landfill gas. EPA could easily achieve this by adding 

landfill gas combusted in flares or other combustion devices to the list of examples of gaseous 

material combustion that does not involve the treatment or other management of a solid 

waste. EPA should add a statement to both preambles that its clarification with regard to 

combustion of uncontained gases, including landfill gas, supersedes the ambiguous and 

confusing NHSM Rule Response to Comments Document. 

WM and DSWA further support the Agency’s proposal to reinsert the definition of “contained 

gaseous material” into the CISWI Reconsideration Rule. WM agrees with the Agency that the 

inclusion of the definition will aid in clarifying that CISWI applicability has not changed with 

respect to gaseous emission streams that are combusted. 

To clarify the definitions of “solid waste” and “contained gaseous material” across both the 

CISWI Reconsideration Rule and the NHSM Rule, the two rules should contain both definitions. 

We therefore, recommend that EPA reinsert both the definition of solid waste as defined in 

40 CFR 258.2, and the definition of “contained gaseous material” into the CISWI 

Reconsideration Rule, and insert the definition of “contained gaseous material” in the NHSM 
3 

Rule Amendments in 40 CFR part 241.2. The inclusion of these important definitions in both 

rulemakings will enhance transparency and clarity for the regulated community, and further the 

Agency’s goal of developing clear, readable and comprehensible rules. 

Failure to clarify that LFG is not a solid waste subject to RCRA and the NHSM Rule will pose 

extremely severe consequences for the landfill management sector: 

• Regulating LFG as solid waste would have a dramatic and detrimental impact on use of 

LFG as a renewable fuel. 

• Regulation of LFG under CISWI would, for WM alone, exceed the total estimated costs 

of the CISWI Rule for its intended sources – about $412 million in capital, $50 

million/year in O&M. 

• Cost to DSWA alone is estimated to be about $4 in capital, $5/year in O&M and $3.5 

million/year in lost revenue. 

• Failure to recognize LFG as a legitimate fuel will undermine private, local government 

and federal sustainability initiatives. 

Failure to clarify that LFG is not a solid waste subject to RCRA and the NHSM Rule is also 

contrary to statutory and regulatory definitions and program policies that recognize LFG as a 

renewable fuel. For example: 

• EPA’s Landfill Methane Outreach Program (LMOP) promotes use of LFG as a renewable 

fuel for boilers, turbines and engines; 

• The Federal Renewable Energy Production Tax Credit rewards electricity production 

from LFG; 

• EISA 2007 and EPA’s Renewable Fuel Standard (RFS2) which specify that LFG is an 

advanced biofuel; 

• The Boiler MACT Rule defines LFG as a gaseous fuel; and 

• All 29 state Renewable Portfolio Standards define LFG as a renewable fuel for green 

electricity production. 

Treatment of LFG by the Boiler Rule 

EPA Should Identify LFG as a Gas 1 Fuel

LFG utilized for combustion in boilers should be categorized as Gas 1 Fuel under the Boiler 

MACT, and like natural gas, should not be subject to emission limits thereunder. The proposed 

Boiler MACT Reconsideration Rule offered no sound science or policy rationale for continuing to 

list LFG as a Gas 2 fuel, and thereby subjecting LFG combustion to stringent emission limits. 

Sufficient data were readily available for EPA to establish that LFG is comparable to natural gas 

and refinery gas with regard to HAP emissions, and that both emissions and raw gas analysis 

data support the conclusion that LFG should be classified as a Gas 1 fuel. Data developed by 

EPA in its 2008 BID support the conclusion that the mercury levels in LFG are consistently much 

lower than the Gas 1 fuel specification level of 40 μg/m3, which should serve as a basis for 

listing LFG in the same Gas 1 category as natural gas and refinery gas. 
4 

As previously stated, WM’s LFG customers have indicated that they may not be able to meet 

the Gas 2 emission limits, particularly in units designed and permitted to minimize NOx 

emissions (for ozone attainment). Therefore, they may be forced to switch to natural gas if 

LFG-fired boilers are subject to “Gas 2” emission limits. 

The environmental consequences of fuel switching from landfill to natural gas are very 

detrimental: 

As of September 20, 2011, EPA’s LMOP has data on 60 US boiler projects and 17 projects that 

utilize LFG in a boiler-steam turbine. EPA estimates that the 60 boiler projects utilize 

approximately 1900 Million British Thermal Units (MMBtu) per hour of LFG, and that the 17 

boiler-steam turbine projects utilize approximately 2400 MMBtu per hour of LFG. If the project 

owners switch from LFG to natural gas, LFG will still be generated by the landfills and therefore 

must be combusted in flares, increasing emissions of greenhouse gases and criteria pollutants. 

EPA calculated the net increase in overall fossil fuel based CO2 emissions from boiler and boiler 

–turbine projects would be 2,025,698 tons. The nation would also realize an additional 12,841 

tons of CO, 291 tons of PM and 684 tons of NOx. SO2 and Hg emissions would also increase 

slightly by 10.2 and 0.0052 tons, respectively. (See WM comments to EPA, EPA LMOP 

Environmental Analysis provided to WM)

The financial costs associated with switching from LFG to natural gas to comply with the 

Boiler MACT as promulgated, are also quite significant. For boiler and boiler-turbine projects 

now using LFG, the order-of-magnitude estimate of the total direct costs of fuel switching to 

natural gas is estimated to be $ 1.064 billion. 

In addition, project owners will lose the value of the LFG processing and transport equipment 

that must be abandoned when fuel switching from LFG. The total estimated capital assets lost 

for existing projects is $87 million. (See WM comments to EPA, CH2M Hill Boiler MACT 

Economic Impact Evaluation). The estimated capital loss associated with current and near 

future DSWA projects is approximately $25 million.
February 21, 2012 

Via Electronic Transmission: a-and-r-Docket@epa.gov

shrager.brian@epa.gov; 

Attention: EPA Docket ID No. EPA-HQ-OAR-2002-0058 

Mr. Brian Shrager 

Sector Policies and Programs Division 

Office of Air Quality Planning and Standards 

U.S. Environmental Protection Agency 

Research Triangle Park, NC 27711 

Dear Mr. Shrager: 

Waste Management (WM) is pleased to provide comments to the Proposed Reconsideration of 

the Final Rule for National Emission Standards for Hazardous Air Pollutants for Major Sources: 

Industrial, Commercial, and Institutional Boilers and Process Heaters (hereinafter referred to as 

the “Boiler MACT Reconsideration Rule”) (EPA-HQ-OAR-2002-0058), published at 76 Fed. Reg. 

80598 (December 23, 2011). As North America’s leading provider of integrated environmental 

solutions, WM is uniquely interested in ensuring that the Agency’s final Boiler Rule upon 

reconsideration reflects and supports ongoing and newly evolving efforts to reduce, reuse and 

manage waste, while recovering valuable resources and producing clean renewable energy. 

WM is engaged nationwide in waste and environmental services with a network of operations that 

includes collection operations, transfer stations, recycling plants, organic processing facilities, 

landfills, landfill gas-to-energy projects, waste-to-energy plants and independent power 

production facilities. Additionally Wheelabrator Technologies Inc. a wholly owned subsidiary of 

WM operates a biomass to energy facility that will be subject to the final Boiler MACT rules, as will 

potentially several other boilers owned or operated by WM. 

WM has been a constant advocate of landfill gas (LFG) as a renewable alternative fuel. WM 

operates 131 LFG-to-energy projects that produce enough renewable energy to power nearly half 

a million homes and replace use of about 2.4 million tons of coal per year. These projects offset 

criteria pollutants and hazardous air pollutants associated with coal use and also offset nearly 3 

million tons of carbon dioxide equivalent (CO2e) emissions each year. While most of our 

renewable energy projects involve combusting LFG in engines or turbines to produce electricity, 

about twenty percent of our projects involve treating and conveying LFG to third parties to use as 

fuel in their facility boilers. Some of our LFG customers include BMW, DuPont, Dow, GM, Ford, the 

University of New Hampshire and NASA Goddard Spaceflight Center. These organizations have 

chosen to utilize LFG as a viable replacement for fossil fuel, and as a key element of their corporate
2 

sustainability goals. Furthermore, investment in these projects has been strongly encouraged by 

Congress and EPA’s Landfill Methane Outreach Program (LMOP). Failure to harmonize the Boiler 

Reconsideration Rule with national renewable energy and greenhouse gas reduction goals will 

undermine significant sustainability investments by private companies, local governments, and 

federal agencies. In addition, the imposition of new and unreasonable regulatory burdens upon 

the combustion of LFG will conflict with existing Clean Air Act regulations governing LFG control 

and use as a renewable fuel, including the Standards of Performance for Municipal Solid Waste 

Landfills, 40 C.F.R. Part 60, Subpart WWW (the “Landfill NSPS”) and the National Emission 

Standards for Hazardous Air Pollutants: Municipal Solid Waste Landfills, 40 C.F.R Part 63, Subpart 

AAAA (the “Landfill MACT”). 

WM offers the following comments on the proposed Boiler MACT Reconsideration Rule, 

incorporating by reference WM’s Petition for Reconsideration of the National Emission Standards 

for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers 

and Process Heaters; Final Rule (Docket ID No. EPA-HQ-OAR-2002-0058), as well as comments filed 

on July 15, 2011 (Document ID No. EPA-HQ-OAR-2002-0058-3322).1

1. The Boiler Rule Should Not Create Barriers to Using Renewable Fuels Such as 

LFG 

From an environmental and economic perspective, the combustion of LFG in boilers is a positive 

alternative to control of LFG in flares. Failure to categorize LFG as a “Gas 1” fuel will subject LFG

boilers to stringent emission limits, thereby creating strong disincentives to the use of LFG in 

boilers and hampering many private, local government and federal government facilities’ 

sustainability efforts and significantly disrupting domestic renewable energy production. The U.S 

LFG to energy sector is a significant portion of the domestic renewable energy sector, producing 

more than 7 times the energy output of the entire domestic solar energy sector2. 

Under the proposed Boiler MACT Reconsideration Rule, units designed to burn Gas 1 fuel 

(including natural gas and refinery gas) are not subject to emission limits, while units designed to 

burn “Gas 2” fuels are subject to strict numeric emission limits for PM, HCL, Mercury and CO. By 

EPA’s own analysis, the control costs for Gas 2 boilers are estimated to be higher than the 

combined compliance capital costs for boilers and process heaters in all other categories. WM’s 

LFG customers have indicated that they may not be able to meet the proposed Gas 2 emission 

limits (e.g., for CO) particularly for units designed and permitted to minimize NOx emissions (for 

ozone attainment). Therefore, the boiler owners may be forced to switch to natural gas if LFGfired boilers are subject to “Gas 2” emission limits. EPA’s creation of such disincentive for use of 

LFG is contrary to the Agency’s own stated policy of encouraging the beneficial use of LFG3. 

 

1

 Additionally, WM offers these comments without waiver of any issues raised through its Petition for Review of the 

Boiler MACT rulemaking, at Docket No. 11-1147 in the U.S. Court of Appeals for the District of Columbia Circuit. 

2

 U.S. Energy Information Administration Independent Statistics and Analysis, 2009 

3

 USEPA, Landfill Methane Outreach Program, http://www.epa.gov/lmop/basic-info/index.html, February 2012 
3 

The environmental consequences of creating barriers to using LFG are very detrimental. As of 

September 20, 2011, EPA’s LMOP has data on 60 U.S. boiler projects and 17 projects that utilize 

LFG in boiler-steam turbines. EPA estimates that the 60 boiler projects utilize approximately 1900 

Million British Thermal Units (MMBtu) per hour of LFG, and that the 17 boiler-steam turbine 

projects utilize approximately 2400 MMBtu per hour of LFG. If the project owners switch from LFG 

to natural gas, LFG will still be generated by the landfills and therefore must be combusted, 

increasing emissions of greenhouse gases and criteria pollutants. 

EPA calculated the net increase in overall fossil fuel based CO2 emissions from boiler and boiler –

turbine projects would be 2,025,698 tons. The nation would also realize an additional 12,841 tons 

of CO, 291 tons of PM and 684 tons of NOx. SO2 and mercury emissions would also increase 

slightly by 10.2 and 0.0052 tons, respectively. (Attachment A –EPA LMOP Environmental Analysis 

provided to WM)

The financial costs associated with switching from LFG to natural gas to comply with the Boiler 

MACT Reconsideration Rule as proposed, are also quite significant. For boiler and boiler-turbine 

projects now using LFG, the order-of-magnitude estimate of the total direct costs of switching 

from LFG to natural gas is estimated to be $ 1.064 billion. In addition, project owners will lose the 

value of the LFG processing and transport equipment that must be abandoned when fuel 

switching from LFG. The total estimated capital assets lost for existing projects is $87 million. 

(Attachment B – CH2M Hill Boiler MACT Economic Impact Evaluation)

2. EPA Should Not Subject LFG to Additional Emission Limits When Used in 

Boilers 

EPA has already evaluated, and regulated, hazardous air pollutant (HAP) emissions that may result 

from the two circumstances under which LFG may be used in a boiler under the Landfill NSPS and 

the Landfill MACT. First, LFG fired directly to a boiler operating as a control device is subject to the 

non-methane organic compounds (NMOC) emission standard that was established pursuant to the 

Landfill NSPS and determined under the Landfill MACT to adequately address HAP emissions. 

Imposition of additional emission limits from such control devices would constitute an 

impermissible duplication of emission limits under Section 112 of the CAA. Second, the Landfill 

NSPS and the Landfill MACT require that LFG used as a fuel must be treated and processed in a 

manner that ensures proper combustion in accordance with specifications required by the 

receiving combustion unit. Imposition of emission limits under the Boiler MACT Reconsideration 

Rule, as proposed for this use of LFG, where natural gas and refinery gas are not subject to such 

limits, would create an extreme disincentive to the use of LFG for energy recovery. For these 

reasons, the Gas 2 emission limits in the Boiler Rule should not apply to LFG-fired boilers. The 

emission limits established for Gas 2 units are technically infeasible and cost prohibitive to 

promoting renewable sources of energy. As previously stated, WM’s LFG customers have 

indicated that they may not be able to meet the Gas 2 emission limits particularly units designed 
4 

and permitted to minimize NOx emissions (for ozone attainment). Therefore, they may be forced 

to switch to natural gas if LFG-fired boilers are subject to “Gas 2” emission limits. 

3. EPA Should Identify LFG as a Gas 1 Fuel 

In our Petition for Reconsideration of the Boiler MACT Rule, WM requested that the Agency 

reconsider its categorization of LFG as “Gas 2” and amend the rule to clarify that LFG constitutes a 

“Gas 1” fuel for which the imposition of emission limits is infeasible and impracticable. EPA’s 

proposed Boiler MACT Reconsideration Rule fails to do so. Furthermore, the proposed Boiler 

MACT Reconsideration Rule offers no sound science or policy rationale for continuing to list LFG 

as a Gas 2 fuel.

WM contracted with CH2M Hill to conduct a comparison of the emissions properties of boilers 

firing LFG as fuel to those of boilers firing Gas 1 fuels, and to examine the publicly available 

information to compare LFG to Gas 1 fuels, specifically natural gas and refinery gas. (Attachment 

C – Boiler MACT Fuel Classification Review for Landfill Gas) CH2MHill concluded that sufficient 

data were readily available for EPA to establish that LFG is comparable to natural gas and refinery 

gas with regard to HAP emissions, and that both emissions and raw gas analysis data support the 

conclusion that LFG should be classified as a Gas 1 fuel. A brief summary of the report conclusions 

follows. 

Table 3 from the CH2M Hill report provides a comparison of the readily available data for total 

mercury in LFG to comparable data for natural gas and refinery gas. As noted above, EPA’s 2008 

effort to establish an appropriate default parameter for Hg in LFG found no instances of LFG 

exceeding the fuel specification value of 40 micrograms per cubic meter (μg/m3) among the 

numerous tests conducted that EPA reviewed. 

Data developed by EPA in its 2008 BID support the conclusion that the mercury levels in LFG are 

consistently much lower than the Gas 1 fuel specification level of 40 μg/m3, which should serve 

as a basis for listing LFG in the same Gas 1 category as natural gas and refinery gas. The data for 

mercury in LFG supports its characterization as a Gas 1 fuel. Mercury levels in raw LFG from 15 

landfills reported in EPA’s BID (2008) indicated a range of total mercury levels comparable to levels 

found in the available data for mercury in natural gas. Because of the dearth of available data for 

HAP and surrogate parameters in the Gas 1 fuels, one cannot effectively compare the constituents 

of raw LFG to the recognized Gas 1 fuels for those parameters. However, a comparison of the 

readily available emissions data for boilers fueled by only LFG indicates that the ranges of reported 

results for mercury, PM, CO, and dioxin/furans are within or below the ranges of those parameters 

for one or both of the recognized Gas 1 fuels, natural gas and refinery gas. No HCl data were 

available for refinery gas for comparison to LFG. However, the few HCl emissions data available 

from LFG-fueled boilers (0.00321 to 0.00398 pounds per million British thermal units [lb/MMBTU]) 

are lower than the Boiler MACT emission limits for both new and existing solid fuel-fired units 

(0.022 lb/MMBTU). 
5 

Numerous Published Studies Have Measured Mercury Concentrations in LFG. 

A large dataset of mercury concentrations in LFG is available from numerous published studies and 

reports. In the proposed rule, however, it appears the Agency considered only three LFG samples 

and these were evaluated on a lb/MMBtu basis (Excel Spreadsheet. MACT Floor Memo Appendixes 

C, D, and E. Boiler Maximum Achievable Control Technology docket site, EPA Docket No. EPA-HQOAR-2002-0058-1388.1).4

 Although emission limits are evaluated on a lb/MMBtu basis, the fuel 

specification limit is based on the mercury concentration in LFG reported in units of micrograms 

per cubic meter (μg/m3). The published studies that have included sampling of mercury in LFG are 

shown in the table below. Samples have been collected from more than 30 landfills located 

throughout the United States and the United Kingdom. All of these studies are readily available 

through the internet and, in fact, several were conducted for EPA. This wealth of information 

should be considered by the Agency as part of this proposed rule. 

Studies of Total Mercury Concentrations in LFG

Study Location Number of 

Landfills Studied 

U.S. Environmental Protection Agency (USEPA). 2005. Measurement of 

Fugitive Emissions at a Bioreactor Landfill. Prepared by Arcadis. EPA600/R-05/096. 

Kentucky 1

U.S. Environmental Protection Agency (USEPA). 2007. Field Test 

Measurements at Five Municipal Solid Waste Landfills with Combustion 

Control Technology for Landfill Gas Emissions. Prepared by Arcadis. Final 

Report. April 2007. EPA/600/R-07/043. (a) 

Northeast and Midwest 

US 

5

U.S. Environmental Protection Agency (USEPA). 2008. Background 

Information Document for Updating AP42 Section 4.2 for Estimating 

Emissions from Municipal Solid Waste Landfills. Prepared by Eastern 

Research Group, Inc. EPA/600/R-08-116. 

California, Florida, 

Delaware, Washington, 

Northeast and Midwest 

US 

17

U.S. Environmental Protection Agency (USEPA). 2009. Quantifying 

Uncontrolled Landfill Gas Emissions from Two Florida Landfills. Prepared 

by Arcadis US. EPA/600/R-09/046. (a) 

Florida 2

U.S. Environmental Protection Agency (USEPA). 2012. Quantifying 

Methane Abatement Efficiency at Three Municipal Solid Waste Landfills. 

Final Report. Prepared by Arcadis US. EPA/600/R-11/033. 

Not stated 3

Frontier Geosciences Inc. 2003. Determination of Total and Dimethyl 

Mercury in Raw Landfill Gas with Site Screening for Elemental Mercury at 

Eight Washington State Landfills for the Washington State Department of 

Ecology. July 2003. (a) 

Washington 8

Lindberg, S.E., Southworth, G., Prestbo, E.M., Wallschlager, D., Bogle, M.A., 

and Price, J. 2005. Gaseous methyl and inorganic mercury in landfill gas 

from landfills in Florida, Minnesota, Delaware, and California. Atmos. 

Environ. 39:249-258. 

Florida, Minnesota, 

Delaware, California 

9

Netcen. 2003. Monitoring and Speciating Mercury in Landfill Gas. A Short 

Status Study on Emissions from UK Landfills. Prepared for the 

Environmental Services Association Research Trust. 

United Kingdom 6

UK Environmental Agency. 2004. Quantification of Trace Components in 

Landfill Gas. Waste Management Research Programme.

United Kingdom 6

 

4

 The three mercury measurements, collected from a single landfill gas unit at a BMW facility, were incorrect. EPA 

indicated in its response to comments that this error has been corrected (See comment and response on May 18, 

2011 reconsideration notice in 76 FR 28662 at EPA Docket Control No. EPA-HQ-OAR-2002-0058-2775.1). 
6 

(a) These studies were also included in USEPA’s 2008 AP42 Background Document. 

Mercury Concentrations in LFG Are Consistently Below the 40 μg/m3 Fuel Specification Limit. As 

noted above, a large dataset of mercury concentrations in LFG is available from numerous 

published studies and reports, including many studies conducted for EPA (USEPA 2005, 2007, 

2008, 2009, 2012; Frontier 2003; Lindberg et al. 2005; Netcen 2003; UKEA 2004). These data have 

been collected from 30 landfills located throughout the United States and 12 landfills in the United 

Kingdom. Overall, these studies provide a robust database of more than 150 measurements that 

reliably characterizes the levels of mercury in LFG. 

To demonstrate that a gaseous fuel other than natural gas or refinery gas qualifies as a Gas 1 fuel 

(76 FR 80633), the rule requires that a fuel specification analysis be conducted. The analysis must 

characterize mercury concentrations in the fuel, demonstrate that mercury concentrations do not 

exceed 40 μg/m3 , and address a variety of associated requirements related to sampling and 

analysis (e.g., descriptions of sample locations, procedures for collecting and analyzing samples). 

The existing database of mercury LFG measurements complies with the objectives of the proposed 

Boiler MACT Reconsideration Rule regarding a fuel specification analysis. In fact, this database 

presents a more comprehensive characterization of mercury in LFG than would be developed for 

any individual fuel source. The sample size of the existing dataset is substantially greater than the

number of samples that would be collected under the proposed rule. Indeed, the proposed rule 

appears to indicate that collection of three samples from each fuel type would be adequate for a 

fuel specification analysis and Section §63.7521(h) implies that even one sample may be adequate. 

In addition, each of the published LFG studies provides descriptions of sample locations, sample 

collection and analysis methods, and assessments of data quality. These elements address the 

fuel specification requirements laid out in §63.7521(g)(2). 

The mercury concentrations reported in the existing database provide sufficient evidence, in 

accordance with §63.7521(i) and without the need to conduct further studies, to qualify LFG as a 

Gas 1 fuel. These data consistently demonstrate that concentrations are below the 40 μg/m3 fuel 

specification limit. All of the measurements reported in the published literature are below 40 

μg/m3. Additionally, the mean concentration of mercury in LFG is 2 μg/m3 and the 95% upper 

confidence limit is 2.7 μg/m3, based on the individual data measurements reported in the many 

published studies noted above. The overall mean concentration of mercury in LFG and the highest 

95% upper confidence limit, calculated from one study which presents only summary statistics and 

not individual test results, is 4 μg/m3 and 12 μg/m3, respectively. 

In sum, the Agency should consider the abundant published data on mercury levels in LFG in this 

rulemaking, including the many studies that it has sponsored. These data demonstrate that 

mercury concentrations in LFG have been proven to be consistently below the 40 μg/m3 fuel 

specification limit and support the characterization of LFG as a Gas 1 fuel. 

Based on the above analysis, WM strongly recommends that LFG be categorized as Gas 1 under 

the Boiler MACT Reconsideration Rule. The data for mercury and hydrogen sulfide (H2S) in LFG 
7 

support its characterization as a Gas 1 fuel. Further, should boiler owners switch fuel from LFG to 

one of the currently defined Gas 1 fuels, increased pollution emissions will occur. Use of natural 

gas or refinery gas will increase criteria pollutant and greenhouse gas emissions compared to LFG. 

LFG has been shown to produce lower nitrous oxide emissions than natural gas, and using LFG 

lowers fossil carbon dioxide emissions as compared to both Gas 1 fuels. 

If EPA fails to list LFG in the Gas 1 category despite the abundant data showing that LFG mercury 

levels are substantially below the Gas 1 fuel specification limit for mercury, then EPA should 

provide a categorical determination for LFG. The categorical determination that LFG qualifies as 

an other gas 1 fuel should be granted based on available published data, including EPA’s own 

reports, that shows LFG meets the other Gas 1 fuel specification limit of 40μg/m3. We therefore 

recommend §63.7521(f) be modified as follows: 

§63.7521(f) To demonstrate that a gaseous fuel other than natural gas or refinery gas

qualifies as an other gas 1 fuel,.....except as specified in paragraph (f)(1) through (3) of this 

section. 

(1) You are not required to conduct the fuel specification analyses in paragraphs (g) 

through (i) of this section for natural gas or, refinery gas or landfill gas. 

4. EPA Should Revise the Other Gas 1 Fuel Specification 

To the extent that LFG or any gaseous fuel may only qualify for Gas 1 categorization through a fuel 

specification, WM requests that EPA revise the specification to ensure that it is established in a 

manner that will include LFG that is managed in accordance with existing CAA requirements as 

discussed above. For example, the Landfill MACT requires that LFG be routed to a treatment 

system that processes the gas for subsequent sale or use as fuel; this requirement would be an 

appropriate and adequate specification for demonstrating that LFG may be combusted as a Gas 1 

fuel. 

Although EPA has created a fuel specification for “other Gas 1 fuels” by which LFG and other gases 

may qualify for Gas 1 regulatory treatment, as proposed in the Boiler MACT Reconsideration Rule, 

the fuel specification does not provide a viable avenue by which LFG combustion in industrial 

boilers would be relieved of the regulatory burdens associated with unnecessarily stringent 

emission limits, sampling and testing. 

While problems exist with the fuel specification as proposed, WM commends the Agency and 

supports its proposed removal of the inappropriate hydrogen sulfide (H2S) limit from the Gas 1 

fuel specification. In the preamble to the proposed Boiler MACT Reconsideration Rule, EPA 

explains that: 

“EPA has reexamined the fuel specification and agrees that the key contaminant for 

demonstration of comparability from a HAP perspective is Hg and that the H2S fuel 

specification that was finalized does not provide a direct indication of potential HAP from 

combustion of gaseous fuel. Accordingly, the EPA is proposing a fuel specification based only 
8 

on the Hg level in the gaseous fuel, and that level is the same level that the EPA included in 

the March 2011 final rule.” 

Waste Management agrees with the Agency’s conclusion that use of an H2S limit is not an 

appropriate indicator of potential HAP emissions. As discussed above, WM contracted with 

CH2M Hill to conduct a comparison of the emissions properties of boilers firing LFG as fuel to 

those of boilers firing Gas 1 fuels, and to examine the publicly available information to compare 

LFG to Gas 1 fuels, specifically natural gas and refinery gas. 

In this report, CH2M Hill noted that EPA based its fuel specification in the March 21, 2011 rule on 

sweetened, pipeline-quality natural gas. However, refinery gas, the other named Gas 1 fuel, 

typically contains much higher levels of H2S than the Gas 1 fuel specification in that rule. CH2M 

Hill evaluation found that the H2S concentrations in refinery gas can range from 0 to 450,000 ppm. 

Based on this data evaluation, WM asserted that LFG should not be held to a higher H2S standard 

than refinery gas for qualification as a Gas 1 fuel. We also commented that as H2S is not a HAP, 

nor a HAP precursor, nor a surrogate for HAP emissions, it is therefore an inappropriate limit to 

use in a demonstration of comparability for HAP emissions. 

While we commend EPA for correcting its Gas 1 fuel specification related to the H2S limit, we 

continue to believe that the Boiler Reconsideration Rule, as proposed, creates a significant 

disincentive to using LFG as an alternative, renewable fuel. Our primary concern with the fuel 

specification is that despite the proposed correction to remove the H2S limit from use as a 

demonstration of comparability, the Gas 1 fuel specification requirements are still unworkable and 

burdensome. The requirements preclude its use as a viable mechanism for boiler 

owner/operators or fuel suppliers to demonstrate fuel comparability with the two designated Gas 

1 fuels. 

Certification and Testing Requirements

The certification requirements in proposed §63.7530(g) state: 

 

“If you elect to demonstrate that a gaseous fuel meets the specifications of an other gas 1 

fuel as defined in §63.7575, you must conduct an initial fuel specification analyses 

according to §63.7521(f) through (i). If the mercury constituents in the gaseous fuels will 

never exceed the specification included in the definition (40 ug/cm) you will include a signed 

certification with the Notification of Compliance Status that the initial fuel specification test 

meets the specification outlined in the definition of other gas 1 fuels. If your gas 

constituents could vary above the specification, you will conduct monthly testing according 

to the procedures in §63.7521(f)-(i) and §63.7540(c) and maintain records of results of the 

testing as outlined in §63.7555(g).” 

This provision would appear to require a certification that LFG “will never exceed the specification 

limit for mercury.” Such a certification, relating to unknown future conditions, is overly 
9 

burdensome, impractical and unworkable. A facility designated representative cannot sign such a 

certification without taking an undue legal/fiduciary risk, even for a highly unlikely circumstance 

that is out of the representative’s control. Such certification is inconsistent with RCRA and Clean 

Air Act NSPS, NESHAP and Title V operating permit certification requirements, which allow for 

certifications to be based on all credible evidence, generator knowledge, and which provide for 

certifications based on generator or operator knowledge, information, belief. 

While it can be demonstrated that a gaseous fuel consistently meets the mercury specification 

through all currently available data sets (as shown above with respect to LFG), it is unnecessary 

and impossible to demonstrate that a gaseous fuel will never exceed such specification in the 

future, especially where the content of future analyses and data sets cannot be known. Further, 

the “never exceed” specification for mercury in gas fuels other than natural gas or refinery gas is 

more stringent than typical compliance demonstration methods such as for emission limits and 

work practice standards. For example, we are not aware of any other circumstance in which EPA 

has required a facility to certify to future compliance with work practice standards, or to certify 

the contents of future emissions tests or analyses. Likewise, the certification requirement 

included in the proposed Boiler MACT Reconsideration Rule is inconsistent with the very definition 

of “other gas 1 fuel”, which states that such fuel “does not exceed the maximum concentration of 

40 micrograms/cubic meters of mercury.” (76 FR 80653). The definition does not discuss future 

events (nor should it), and therefore it is unreasonable based on this definition to impose a 

requirement to certify future conditions as a compliance tool in this case. Such requirement 

unfairly subjects all gaseous fuels other than natural gas or refinery gas to a fuel specification 

standard that these two Gas 1 fuels are not required to even address in the most cursory manner. 

The only alternative to this onerous certification requirement provided in the proposed Boiler 

MACT Reconsideration Rule is monthly testing of gaseous fuels to demonstrate compliance with 

the gas specification. This testing requirement is not supported by the consistently low levels of 

mercury from all available LFG analyses. Accordingly, in the case of LFG, the Initial Fuel 

Specification Analysis is sufficient to demonstrate Other Gas 1 status. Section 63.7530(g) states 

that you will conduct monthly testing if your gas constituents could vary above the specification. 

In addition, §63.7540(c) requires monthly fuel specification testing be conducted at each facility if 

a signed certification stating mercury fuel specification limit will never be exceeded cannot be 

submitted. As discussed above, it is unreasonable and inconsistent with other Federal Rules to 

require such certification. The requirement to conduct monthly testing is also unreasonable and 

inconsistent with other compliance requirements in the proposed Boiler MACT Reconsideration 

Rule (i.e., annual performance stack test, annual or biennial tune-ups). The proposed Boiler MACT 

Reconsideration Rule should allow, at the facility-specific level, a one-time certification, performed

following applicable EPA sampling guidance, rather than monthly monitoring to demonstrate 

compliance with the mercury fuel specification limit. 

However, the Boiler MACT Rule should not preclude subsequent testing to demonstrate 

compliance with the fuel specification where the results of the initial fuel specification 

demonstration did not meet the gas specification outlined in the definition of other gas 1 fuels. In 
10 

this case, a subsequent initial test followed by periodic testing, such as monthly sampling, to 

validate initial fuel specification demonstration results could be required. The proposed Boiler 

MACT Reconsideration Rule states that if “12 consecutive monthly fuel analyses demonstrate 

compliance, you may request decreased fuel analysis frequency by applying to the EPA.” (76 FR 

80631). We recommend the Agency also include a reduced testing frequency, such as annually or 

bi-annually where 12 consecutive monthly samples demonstrate that the fuel meets the gas 

specification outlined in the definition of other gas 1 fuels. 

Also, the reference to §63.7545(g) in §§63.7540(c) and 63.7555(g) is incorrect. The correct 

reference is §63.7530(g). 

Based on all of the above, WM recommends the EPA modify the certification requirements and 

testing frequency in §63.7530(g) as follows: 

(g) If you elect to demonstrate.....If the mercury constituents in the gaseous fuels will never

do not and are not reasonably expected to exceed the specification included in the 

definition, you will include a signed certification with the Notification of Compliance Status 

that the initial fuel specification test meets the gas specification outlined in the definition 

of other gas 1 fuels. The Notification of Compliance Status may include other relevant data 

or measurements that supports the certification that the mercury constituents are not 

reasonably expected to exceed the specificationsIf your gas constituents could vary above 

the specification, you will If your initial fuel specification test does not meet the gas 

specification outlined in the definition of other gas 1 fuels or would otherwise be 

reasonably expected to vary above the specification, then you must follow Gas 2 

subcategory requirements or you may conduct monthly testing according to the 

procedures in §63.7521(f) through (i) and §63.7540(c) and maintain records of the results 

of the testing as outlined in §63.7555(g). Where 12 consecutive monthly samples 

demonstrate that the fuel meets the specification for mercury for the other gas 1 

subcategory, you may decrease fuel specification testing frequency to annually. 

We recommend the EPA modify the certification requirements and testing frequency in 

§63.7540(c) as follows: 

(c) If you elected to demonstrate that the unit meets the specification for mercury for the 

other gas 1 subcategory and you cannot submit a signed certification under § 63.753045(g) 

because the constituents could exceed exceeded the specification, you must follow Gas 2 

subcategory requirements or conduct monthly fuel specification testing of the gaseous 

fuels, according to the procedures in § 63.7521(f) through (i). Where 12 consecutive 

monthly samples demonstrate that the fuel meets the specification for mercury for the 

other gas 1 subcategory, you may decrease fuel specification testing frequency to 

annually.

We recommend the EPA modify the certification requirements and testing frequency in 

§63.7555(g) as follows: 
11 

(g) If you elected to demonstrate that the unit meets the specification for mercury for the 

other gas 1 subcategory and you cannot submit a signed certification under § 63.753045(g) 

because the constituents could exceed exceeded the specification, you must follow Gas 2 

subcategory requirements or maintain monthly and/or annual records of the calculations 

and results of the fuel specification for mercury in Table 6. 

This approach is consistent other NESHAP requirements such as 40 CFR Part 63, Subpart N (40 cfr 

63.344); Subpart GGG (see 40 CFR 63.1250). See also 40 CFR 261.10 (use of generator knowledge 

to certify to regulatory characteristics of materials) 

A Single Fuel Sample is Inappropriate 

Per §63.7521(h), you must obtain a single fuel sample for each fuel type. Table 6 requires the 

owner/operator or fuel supplier to measure mercury concentration in the fuel sample (emphasis 

added) and convert to units of ug/m3. The proposed fuel specification demonstration apparently 

ensures that even one aberrant or anomalous fuel measurement, even if it is not valid, would be 

sufficient basis for failing to demonstrate the mercury fuel specification is met. This sampling 

requirement is inconsistent with compliance methods presented elsewhere in the proposed Boiler 

MACT Reconsideration Rule, specifically in §63.7530, which directs that the arithmetic average 

mercury concentration in each fuel type should be used and also provides an equation for 

calculating a 90 percent upper confidence limit fuel concentration from sample data (referred to in 

the rule as the “90th percentile confidence level” 5). 

The fuel analysis based compliance method involves performing some type of statistical data 

analysis of multiple fuel samples. At a minimum, the approach used to demonstrate that a 

gaseous fuel qualifies as an other Gas 1 fuel should be consistent with compliance methods 

provided elsewhere in the proposed Boiler MACT Reconsideration Rule and standard EPA 

statistical guidance (e.g., EPA’s 2006 report, Data Quality Assessment: Statistical Methods for 

Practitioners. EPA QA/G-9S. EPA/240/B-06/003). We recommend that the proposed Boiler MACT 

reconsideration Rule be amended to ensure that compliance will not be determined based on one 

sample or by comparison to a single maximum value reported among a group of samples.

The Test Methods Proposed for Other Gas 1 Fuels are for Determining Mercury in Natural Gas; 

They Have Not Been Demonstrated in Practice for Other Gaseous Fuels. 

According to Table 6 of the Proposed Boiler MACT Reconsideration Rule, you must conduct fuel 

analysis for mercury using one of the four prescribed test methods, or equivalent method. 

However, §63.7521(g)(2)(vi) appears to prevent gaseous fuel suppliers from requesting approval 

to use alternative test methods. The boiler owner/operator on the other hand may request 

approval to use an alternative test method. No explanation or rationale is provided for this 

 

5

 The equation provided for calculating a “90th percentile confidence level” to compare to emission limits (Eq. 10 at 76 

FR 80641) does not appear to reflect EPA statistical guidance, for example, as provided in EPA’s 2006 report, Data 

Quality Assessment: Statistical Methods for Practitioners. EPA QA/G-9S. EPA/240/B-06/003. 
12 

inflexible requirement. Furthermore, it is likely to affect most of the analysis conducted under this

section of the rule. We believe it is highly likely that purchasers of gaseous fuels will require their 

fuel suppliers to develop the analyses and documentation necessary to qualify them as an “other 

Gas 1 fuel.” We strongly recommend EPA remove this language so that all analyses conducted 

for use of other Gas 1 fuels may utilize methods listed in §63.7521(f)-(i) or equivalent methods. 

WM requests that EPA incorporate additional test methods in the rule that can be used under 

§63.7521. §63.7521 states that a gaseous fuel other than natural gas or refinery gas can be 

qualified as a “Gas 1” fuel by conducting fuel testing according to methods laid out in Table 6. 

Specifically, Table 6 requires that the mercury concentration in the fuel must be measured using 

one of the following test methods: “ASTM D5954, ASTM D6350, ISO 6978–1:2003(E) or ISO 6978–

2:2003(E) (or an equivalent test method)”. The Agency states that the methods in Table 6 “shall 

be used” unless an alternative analytical method is specifically approved. 

The required test methods listed in EPA’s referenced table are typically used for natural gas 

analyses, and have not been proven to be appropriate for analyzing LFG for mercury. Further, 

because gaseous fuel suppliers are not allowed to use alternative methods, WM would be forced 

to use an unproven method to demonstrate our LFG compliance with the certification 

requirements. All four of the listed test methods were developed to determine mercury levels in 

natural gas, not LFG, but the composition and physical properties of LFG and natural gas differ. For 

example, natural gas is primarily methane with lower concentrations of related alkanes and 

carbon oxides, and trace quantities of other hydrocarbons. LFG typically contains 45% to 60% 

methane and 40% to 60% carbon dioxide. LFG also includes small amounts of nitrogen, oxygen, 

ammonia, sulfides, hydrogen, and carbon monoxide. The complexity of component fuels typically 

encountered in sampled LFG often renders the methods typically used for natural gas 

characterizations inappropriate. Either interferences or target analyte levels may disqualify 

natural gas methods when attempting to acquire representative Hg data in LFG. The performance 

of these methods in an LFG matrix has yet to be demonstrated. As a result, it is inappropriate for 

the Agency to categorically require that, in the absence of a pre-approval process, only the four 

methods listed in Table 6 may be used for mercury testing in LFG. 

Numerous studies have been conducted to measure mercury in LFG, including several conducted 

for EPA. The table below lists the test methods used in these studies, the methods specified in 

Table 6, and, for each method, whether it was included in the Agency’s proposed Boiler MACT 

Reconsideration Rule. This table shows that none of the methods used in the published mercury 

LFG studies, including those sponsored by EPA, were included in Table 6 of the proposed rule. 

Conversely, none of the methods in Table 6 were relied on in any of the mercury LFG studies. 
13 

Methods for Sampling and Analysis of Total Mercury in LFG 

Method 

Applications 

to Mercury in 

LFG 

Sampling Analysis Notes on Methods 

Included 

in EPA’s 

December 

23, 2011 

Proposed 

Rule (a) 

Frontier/ 

EPA Method 

1631 

4 landfills 

(Arcadis 

2009, USEPA 

2005, 

Lindberg 

2005) 

Iodated 

carbon 

matrix trap 

Cold-vapor 

atomic 

fluorescence 

spectrometer 

(CVAFS) 

Method developed to measure 

Hg at EPA Water Quality Criteria 

levels; for determination of Hg in 

water by oxidation, purge and 

trap, desorption, and cold-vapor 

atomic fluorescence 

spectrometry (CVAFS). 

No 

Lindberg/ 

Frontier 

Geosciences 

14 landfills 

(Frontier 

2003, 

Lindberg et 

al. 2005) 

Iodated 

carbon 

matrix trap 

Cold-vapor 

atomic 

fluorescence 

spectrometer 

(CVAFS) 

Method developed and applied in 

several LFG mercury research 

studies. Served as the basis for 

EPA Method 1631. 

No 

Frontier/ 

EPA Method 

30B 

7 landfills 

(USEPA 2007, 

Arcadis 2009) 

Iodated 

carbon 

matrix trap 

Cold-vapor 

atomic 

fluorescence 

spectrometer 

(CVAFS) 

Method developed to be used at 

coal-fired combustion sources as 

a reference method for relative 

accuracy test audits of vapor 

phase Hg CEMS and sorbent trap 

monitoring systems installed at 

coal-fired boilers; also 

appropriate for Hg emissions 

testing at such boilers. 

No 

Modified SW846 Method 

7473 and EPA 

Method 30B 

3 landfills 

(USEPA 2012) 

Iodated 

carbon tubes 

Atomic 

absorption 

spectrometer 

with Zeeman 

background 

correction 

SW-846 Method 7473: 

Developed to measure Hg in 

solids, aqueous samples, and 

digested solutions in both the 

laboratory and field 

environments by thermal 

decomposition, amalgamation, 

and atomic absorption 

spectrophotometry. 

Method 30B: Developed to be 

used at coal-fired combustion 

sources as a reference method 

for relative accuracy test audits 

of vapor phase Hg CEMS and 

sorbent trap monitoring systems 

installed at coal-fired boilers; also 

appropriate for Hg emissions 

testing at such boilers. 

No 
14 

Methods for Sampling and Analysis of Total Mercury in LFG 

Method 

Applications 

to Mercury in 

LFG 

Sampling Analysis Notes on Methods 

Included 

in EPA’s 

December 

23, 2011 

Proposed 

Rule (a) 

Gold 

adsorption 

tubes/ 

atomic 

fluorescence 

spectroscopy 

6 landfills in 

the UK 

(Netcen 

2003) 

Gold Amasilcoated tubes 

Atomic 

fluorescence 

spectrometry 

-- No 

Frontier/ 

ICP-MS 

6 landfills in 

the UK (UKEA 

2003) 

Frontier 

activated 

charcoal 

sorbent traps 

Inductively 

coupled 

plasma/mass 

spectroscopy 

(ICP/MS) 

-- No 

CARB 

Method 436 

1 landfill 

(USEPA 2008) 

Impingers

containing 

solution of 

acidic 

potassium 

permanganate

Cold vapor 

atomic 

absorption 

spectroscopy 

(CVAAS) 

Method developed to determine 

emissions of metals, including Hg, 

from air emission sources. 

No 

ASTM D5954 NA Gold-coated 

silica beads 

Atomic 

absorption 

spectroscopy 

Method developed to determine 

total Hg in natural gas. Yes 

ASTM D6350 NA Gold-coated 

silica beads 

Atomic 

fluorescence 

spectroscopy 

Method developed to determine 

total Hg in natural gas. Yes 

ISO 6978-

1:2003 NA 

Chemisorption on 

iodine 

impregnated 

silica gel 

Absorbance 

or 

fluorescence 

at 253.7 nm 

Method developed to determine 

total Hg content of pipeline 

quality natural gas. 

Yes 

ISO-6978-

2:2003 NA 

Amalgamatio

n on gold/ 

platinum 

alloy thread 

Absorbance 

or 

fluorescence 

at 253.7 nm 

Method developed to determine 

total Hg content of pipeline 

quality natural gas. 

Yes 

This examination of fuel testing methods clearly indicates that the Agency should expand Table 6 

to include additional options for measuring mercury in gas fuels. At a minimum, methods that 

have been tested and proven reliable in mercury LFG studies, particularly EPA Method 30B and 

EPA Method 1631, both of which are already approved EPA testing methods and have been 

evaluated for accuracy and precision in LFG studies, should be included as acceptable methods in 

the mercury fuel specification section in Table 6. Additionally, it is recommended that the Agency 

consider and evaluate the accuracy, precision, selectivity and sensitivity of the current methods 
15 

included in Table 6, taking into account their applicability to gas fuels other than natural gas or 

refinery gas. 

For example, Method 30B is a stack gas method approved for the characterization of Hg in various 

off-gas sources, including incinerators, boilers, and other thermal devices. EPA has conducted 

collection of LFG using Method 30B with success and has used that test data in its 2008 

Background Information Document for developing revised AP-42 emission factors for municipal 

waste landfills. (EPA/600/R-08-116. September). Some advantages of using Method 30B include: 

 

• Point source sampling can be conducted using relatively easy to operate and portable 

instruments; 

• The sampling technology is mature and familiar to most well-trained sampling technicians; 

• Analysis of samples is relatively inexpensive, and uses a standard EPA methodology; 

• Quality assurance/quality control and comparability of data are easily monitored; and 

• Data may be validated using standard auditing practices. 

WM recently conducted a field study using Method 30B and ASTMD5954 for several projects 

supplying LFG as fuel to industrial boilers to demonstrate the viability of both applications. We 

evaluated the sampling and analysis of LFG using Method 30B by employing both an Ohio Lumex 

mercury analyzer, and by digestion of the sampling tube fractions followed by analysis using 

Method 7470B (CVAA). The results of the Method 30B analysis range from 0.2 to 1.9 ug/m3, 

which are consistent with results presented in the published literature previously identified in our 

comments and validate that mercury concentrations in LFG are well below the fuel specification 

for other gas 1 fuels. 

We had difficulty identifying laboratories that have capability (equipment and experience) to 

perform the test methods listed in Table 6 for determining mercury in LFG, specifically 

ASTMD5954. After contacting several large accredited laboratories, including research 

laboratories and laboratories that service the oil and gas industry, we located only one laboratory 

that has the required equipment to run ASTM D5954 for mercury analysis in LFG. However, this 

laboratory has only performed analysis to determine mercury in LFG in a research capacity rather 

than for clients concerned with ongoing compliance obligations. Unfortunately, after contracting 

with the laboratory and sending them our samples, the equipment required to perform the 

sample analysis for ASTM D5954 broke down and will not be repaired for at least two weeks as it 

requires a replacement part that must be shipped from Japan. This circumstance prevents the 

laboratory from conducting analysis on collected LFG samples it received February 13. A further 

complication is that the laboratory’s quality control sample hold time is 30 days, which may render 

our samples unusable. This same laboratory also does not have capability (equipment) to perform 

ASTM D6350 on the collected samples and cannot identify another laboratory to complete timely 

analysis using ASTM D6350. This lack of laboratory capability and capacity across the nation 

amplifies the limitations with Test Methods prescribed in Table 6 of the proposed Boiler MACT 

Reconsideration Rule for LFG and other gaseous fuels. 
16 

WM would like to share lessons learned from this field study with EPA, specifically whether the 

test methods listed in Table 6 for determining mercury (in natural gas) are applicable to other 

gaseous fuels (e.g., LFG). Therefore, we respectfully request that the Agency accept information 

gathered as part of this field study as supplemental comments on the proposed Boiler MACT 

Reconsideration Rule if/once we receive the final ASTM D5954 results from the laboratory. 

We believe our comments demonstrate the appropriateness of incorporating other test methods 

in the proposed Boiler MACT Reconsideration Rule. 

5. The Affirmative Defense Provisions at §63.7501 for Malfunctions are 

Unnecessarily Burdensome 

Although EPA acknowledges that malfunctions occur in well operated and maintained facilities 

equipped with the best technologies, EPA’s affirmative defense concept essentially presumes that 

malfunctions never occur. Under the rule as written, any emissions occurring above the limits set 

using emission data obtained exclusively during normal operation (emphasis added) are 

considered deviations, regardless of the underlying root cause of the emissions. The reality is that 

malfunctions infrequently occur even on the best designed, maintained and operated units. 

Therefore, a facility should not be presumed guilty of having a deviation in the first place if it has

experienced a legitimate malfunction. 

EPA admits it does not have emissions data for startup and shutdown periods sufficient to 

establish numeric emission limits, and due to this dearth of data has sensibly adopted a work 

practice standard for these periods. Malfunction periods are no different and should be treated 

similarly. Since EPA also lacks emissions data for malfunction periods, and would find it difficult to 

obtain sufficient emission data for all the varying types of malfunction-related events, EPA should 

adopt work practice standards for malfunction periods. 

Malfunction work practice standards could include limitations on the duration to ensure quick and 

effective corrective action is taken, and if the malfunction cannot be quickly resolved the unit 

would be shut down for repair. Facilities should still be required to submit a notification of a 

malfunction excess emission event with the underlying root cause analysis. If EPA or the 

administering agency decides the excess emission event was not a malfunction, it would then be 

reported as a deviation of the limit and enforcement action, including imposition of penalties, 

would still apply consistent with the deviation definition in 63.7575. EPA could also choose to take 

enforcement action should a facility report “excessive” malfunction events. 

Finally, the sheer number of eligibility criteria that must be proven by a “preponderance of 

evidence and the vague terms such as “unpreventable,” “could not have been foreseen,” and “all 

possible steps were taken” all but guarantees that no malfunction event will ever meet the 

criteria. WM suggests modifying the eligibility criteria as follows to make it more reasonable and 

eliminate such vague language: 
17 

“To establish that an exceedance of an emission limit or operating standard was the result 

of a malfunction and therefore not a deviation you must timely meet the notification 

requirements in paragraph (b) of this section and demonstrate that: (1) the malfunction: (i) 

was not caused by a sudden infrequent and unavoidable failure of air pollution control 

equipment or failure of a process to operate in a normal or usual manner; (ii) was not 

caused by operator error or careless operation; (iii) was not the result of inadequate 

design, maintenance or operating procedures; and (2) Corrective actions were taken 

immediately to minimize the duration and amount of excess emissions; and (3) All emission 

monitoring and control systems were kept in operation if possible in a manner consistent 

with safety requirements and good air pollution control practices; and (4) Preventive 

measures were implemented to address the root cause of the malfunction; and (5) The 

root cause analysis and actions in response to the excess emission event were documented 

in signed contemporaneous log. (b)...” 

We also believe the notification requirements should be streamlined. The initial two-day 

notification should include telephone, facsimile or e-mail. Facsimile communications are rarely 

used having been essentially replaced by email correspondence. Email notifications are simple 

and direct, and can be tracked easily and archived for recordkeeping purposes. WM recommends 

that the initial two-day notification should include a brief summary of the nature of the 

malfunction, corrective action taken and root cause analysis. Often the initial notification will 

include enough information for the regulators to confirm a malfunction meets the criteria. For 

example, a lightning strike on a utility interconnect transformer that causes a temporary facility 

power outage would be easily discernible as a malfunction. If the agency needed more 

information, it could request a full report in 45 days, or ask the facility to include a full report in 

the next semiannual compliance report. Such streamlined requirements for malfunction events 

would be consistent with several states’ requirements and would ensure ample regulatory 

oversight. 

6. Stack Test Procedures in §63.7520 Should be More Flexible 

WM recommends that affected facilities be allowed the flexibility to conduct more than just three 

stack test runs to demonstrate compliance with applicable limits. Given the wide variety of fuels 

that boilers may combust, providing flexibility for more than three stack test runs allows for some 

variability among individual stack test runs while also ensuring the stack test average is below the 

limit for verification of long term performance and low emission levels. We suggest the following 

language be incorporated in the final rule: 

“You must conduct a minimum of three separate test runs for each performance test 

required in this section as specified in 63.7(e)(3)... The average of 3 or more test runs shall 

be used to determine compliance with the emission limits.” 
18 

This option to use more than three test runs would be specified in the site specific test plan under 

63.79 (c). It could be limited to total metals and HCl where variability is more likely to occur in 

various fuel combinations. 

Waste Management appreciates the opportunity to share our concerns and recommendations 

with the Agency, and we look forward to working with you as you reconsider and revise the Boiler 

MACT Rule. If you have any questions with our comments or with the attached materials, please 

feel free to contact me at (202) 639-1218 or by email at kkelly5@wm.com

Sincerely, 

Kerry Kelly, Director 

Federal Public Affairs 

 
19 

References 

U.S. Environmental Protection Agency (USEPA). 2005. Measurement of Fugitive Emissions at a 

Bioreactor Landfill. Prepared by Arcadis. EPA-600/R-05/096. 

U.S. Environmental Protection Agency (USEPA). 2007. Field Test Measurements at Five Municipal 

Solid Waste Landfills with Combustion Control Technology for LFG Emissions. Prepared by Arcadis. 

Final Report. April 2007. EPA/600/R-07/043. 

U.S. Environmental Protection Agency (USEPA). 2008. Background Information Document for 

Updating AP42 Section 4.2 for Estimating Emissions from Municipal Solid Waste Landfills. 

Prepared by Eastern Research Group, Inc. EPA/600/R-08-116. 

U.S. Environmental Protection Agency (USEPA). 2009. Quantifying Uncontrolled LFG Emissions 

from Two Florida Landfills. Prepared by Arcadis US. EPA/600/R-09/046. 

U.S. Environmental Protection Agency (USEPA). 2012. Quantifying Methane Abatement Efficiency 

at Three Municipal Solid Waste Landfills. Final Report. Prepared by Arcadis US. EPA/600/R11/033. 

Frontier Geosciences Inc. 2003. Determination of Total and Dimethyl Mercury in Raw LFG with Site 

Screening for Elemental Mercury at Eight Washington State Landfills for the Washington State 

Department of Ecology. July 2003. 

Lindberg, S.E., Southworth, G., Prestbo, E.M., Wallschlager, D., Bogle, M.A., and Price, J. 2005. 

Gaseous methyl and inorganic mercury in LFG from landfills in Florida, Minnesota, Delaware, and 

California. Atmos. Environ. 39:249-258. 

Netcen. 2003. Monitoring and Speciating Mercury in LFG. A Short Status Study on Emissions from 

UK Landfills. Prepared for the Environmental Services Association Research Trust. UK 

Environmental Agency. 2004. Quantification of Trace Components in LFG. Waste Management 

Research Programme. 

 
Attachment A 

EPA Landfill Methane Outreach Program( LMOP) Environmental Analysis provided to WM 

sis

d in boilers

tural gas fired in boilers, LFG flared

LFG Energy Boiler-Steam Turbine Projects

f LFG Utilized = 1,896 Total Estimated MMBtu/hr of LFG Utilized = 2,499

Project Count = 17

Baseline New Scenario Increase Emissions Source Pollutant Baseline New Scenario Increase

0 873,972 873,972

Boiler 

Emissions 

(tpy)

Fossil CO2 0 1,151,726 1,151,726

same 0 CO same 0same 0 PM same 0same 0 NOx same 0

115 4.4 -111 SO2 152 5.8 -146

same 0 Hg same 0 - 0 0

Flare 

Emissions 

(tpy)

Fossil CO2 - 0 0 - 5,540 5,540 CO - 7,301 7,301 - 126 126 PM - 165 165 - 295 295 NOx - 389 389 - 115 115 SO2 - 152 152 - 0.0022 0.0022 Hg - 0.0030 0.0030

873,972

Overall 

Emissions 

Increase 

(tpy)

Fossil CO2 1,151,726

5,540 CO 7,301

126 PM 165295 NOx 389
Assumptions and Rationale: 1. To estimate boiler and flare emissions, emission factors were applied to the total estimated amount of LFG utilized (MMBtu

boiler-steam turbine projects from the LMOP database (as of Sept 20, 2011). Emissions for individual boilers and boiler project2. CO2 - All CO2 generated from LFG (combustion of CH4 and generation of CO2 from decomposition of MSW) was considered in the calculations. CO2 generated from combustion of natural gas as a fossil fuel (non-biogenic) was included in the calculationof 53.02 kg CO2/MMBtu (116.9 lb CO2/MMBtu) from Subpart C of the Greenhouse Gas Reporting Program (GHGRP).3. CO, PM & NOx - For combustion by-products CO, PM & NOx, emission factors for LFG-fired boilers and natural gas-fired boilstatistically unique and, in addition, they vary by individual boiler instead of fuel type. Therefore, for this analysis, it was assumemissions from boilers would not change when the fuel is switched from LFG to natural gas. Emissions of CO, PM & NOx were eflared using emission factors from AP-42 (Table 2.4-5) of 750 lb CO/million dscf methane, 17 lb PM/million dscf methane, and 4methane.4. SO2 emissions were estimated for the baseline and new emissions scenario because the amount of SO2 emitted from combvaries by the fuel type. The decrease in SO2 boiler emissions is a result of LFG typically containing higher levels of sulfur than nfor LFG-fired boilers and flares were estimated using a default sulfur content of 46.9 ppmv for raw LFG from AP-42 (pg 2.4-8) acompounds in LFG are converted to SO2 during combustion. SO2 emissions from natural gas-fired boilers were estimated using 

lb SO2/million scf from AP-42 (Table 1.4-2).5. Mercury (Hg) - Emission factors for Hg for LFG-fired boilers and natural gas-fired boilers were not found to be statistically un

LFG and natural gas was found to be very similar since Hg passes through combustion devices and the amount emitted varies bfuel itself. Therefore, for this analysis, it was assumed that Hg emissions from boilers would not change when the fuel is switchEmissions of Hg were estimated for LFG being flared using a default Hg concentraion of 2.92E-04 ppmv from AP-42 (Table 2.4-1

6. A gross capacity factor of 90% was applied to all of the emission calculations to account for loss of energy production due to collection system, problems with project equipment, weather related interruptions of the local utilities, and shutdowns at the the system.References: AP-42 (LFG) - Chapter 2 (Solid Waste Disposal), Section 2.4 (MSW Landfills), November 1998.

http://www.epa.gov/ttn/chief/ap42/ch02/final/c02s04.pdf

AP-42 (Natural gas) - Chapter 1 (External Combustion Sources), Section 1.4 (Natural Gas Combustion), July 1998.

http://www.epa.gov/ttn/chief/ap42/ch01/final/c01s04.pdf

Greenhouse Gas Reporting Program (GHGRP) - 40 CFR 98, Subpart C, Table C-1 (Default CO2 Emission Factors and High Heat VaFuel), Default natural gas (weighted U.S. average) CO2 emission factor.

http://ecfr.gpoaccess.gov/cgi/t/text/text-idx?c=ecfr&sid=4069608504fe50a3a5715cd4da0bae39&rgn=div6&view=text&node=
Attachment B 

CH2M Hill Boiler MACT Economic Impact Evaluation 

T E C H N I C A L M E M O R A N D U M

Boiler MACT Economic Impact Evaluation 

PREPARED FOR: Amy Banister, Waste Management, Inc.

PREPARED BY: Evan Griffiths, Dan Pitzler and Tom Kraemer, CH-M HILL

DATE: November /, -011

Introduction 

This Technical Memorandum summarizes the economic evaluation of the cumulative, nationwide financial impacts 

of switching from LFG (LFG) to natural gas at facilities currently using LFG as boiler fuel, if this were to occur in 

response to the requirements of the currently promulgated Boiler Maximum Achievable Control Technology 

(MACT) rule. The facilities used for this evaluation were those included in a database spreadsheet provided by 

USEPA’s Landfill Methane Outreach Program (LMOP) by email to Waste Management on September 26 of this year. 

This analysis is limited to the projected financial costs for existing projects utilizing LFG in boilers that would be 

affected by the Boiler MACT rule if it became effective. Additional economic impacts including projected loss of jobs 

have been projected by LMOP. Still more economic impacts would result from the inability to develop new projects 

that would use LFG in boilers. LMOP estimates there are over 500 landfills capable of development into LFG-toenergy projects. However, the number that would use LFG in boilers and the investments and returns for these 

prospective projects are too uncertain to estimate the financial impacts. 

Results 

Table 1 lists the estimated financial impacts of switching from LFG to natural gas for all LFG-fired boilers in the 

United States listed in USEPA’s LMOP database. Costs in Table 1 are rounded to the nearest million dollars 

TABLE 1. 

Summary Costs for Converting LFG Boiler and Boiler Steam Turbine Projects to natural gas 

Type of Project NPV of Natural Gas 

Supply 

Minus LFG 

O&M Costs 

NPV of Lost Royalty 

Payments 

Capital Cost (2011 dollars) Abandoned Value 

(Depreciated Value of 

Capital Cost) 

Boilers $797,000,000 $62,000,000 $156,000,000 $78,000,000 

Boiler Steam Turbines $190,000,000 $15,000,000 $94,000,000 $9,000,000 

Combined TOTAL (Boiler 

and Steam Turbine) 

$987,000,000 $77,000,000 $250,000,000 $87,000,000 
23 

The order-of-magnitude estimate of the total direct financial impact of fuel-switching from LFG to natural gas for the 

list of sites provided by LMOP is thus estimated to be $1.064 billion, the sum of the NPV of natural gas costs in 

excess of LFG O&M costs, and the NPV of lost royalty payments to landfill owners. 

The costs for utilizing natural gas to replace the LFG were calculated for each project. These costs were computed as 

the net present value of the cost differences between natural gas supply and estimated LFG operations and 

maintenance (O&M) costs over the remaining life of the project. Lost royalty payments to landfill owner and/or 

developer were estimated based on the amount of BTUs for which royalty payments would no longer be paid over 

the remaining life of the system. 

In addition to direct revenue impacts, project owners will lose the value of LFG processing and transport equipment 

that must be abandoned when switching from LFG to natural gas. To estimate this impact, the capital costs 

associated with constructing compressor systems and pipelines for utilizing LFG in the boiler projects were 

estimated for each project in the LMOP database, as described below under Methodology. The costs were 

depreciated based on the age of the project to estimate the depreciated value of the installed system that would be 

abandoned. These sunk costs must be written off as stranded assets before they are fully depreciated. The total 

estimated capital assets lost for all existing project is $87 million. 

In addition, Waste Management has estimated they could lose $4 to 5 million annually in revenue from third party 

developers and directly from large industries. This loss of revenue is likely only a portion of the total revenue that 

could be lost when all other factors such as end user costs are also factored. 

Methodology 

A list of projects that use LFG as boiler fuel was generated by LMOP. LMOP is a voluntary program of the U.S. 

Environmental Protection Agency that is intended to help reduce methane emissions from landfills by encouraging 

the recovery and beneficial use of LFG as an energy resource. LMOP maintains a database of projects that use LFG as 

boiler fuel. This database was downloaded to an Excel file and used as the basis for this financial evaluation. The 

database contains, among other data, the landfill name, location, start-up date, quantity of LFG used, and the length 

of pipeline used to pipe the LFG from the landfill to the boiler location (i.e. project site). This data was sufficient to 

form the basis for an order-of-magnitude estimate of the total capital costs, depreciated capital costs (that would be 

abandoned upon switching to natural gas), annual O&M costs for the LFG-to-boiler fuel projects and lost royalty 

payments. Additional tabs were added to the LMOP database Excel file to aid in conducting the evaluation. 

A “Base Project” capital cost estimate was prepared and used as the basis to extrapolate the capital costs for 

compressing, chilling, and transporting LFG to the receiving boiler for each of the projects in the LMOP database. 

The Base Project construction cost is based on previous CH2M HILL projects for LFG compressor systems at landfills 

and the pipelines between the landfills and the gas use site. O&M costs for the base project were similarly estimated 

based on previous projects. The O&M costs for the LMOP sites were calculated based on the LFG flow which was 

used to compute compressor power requirements. Labor and materials O&M costs were assumed based on 

previous project experience. 

Once the costs for each system were extrapolated from the base project, additional project costs (engineering, 

administrative, etc) were added based on a percentage (Table 2) of the subtotal capital costs to estimate the grand 

total based on 2011 dollars. 

The grand total cost calculated for 2011 was then used to estimate the current year cost for construction of the 

compressor, chiller, and pipeline reflective of the startup date presented for each project in the database. This was 

done by multiplying the grand total base project cost by the ratio between the historic (i.e. date of startup) and 

current ENR (Engineering New Record) City CCI values. This value was then depreciated to 2011 using the 

straightline method and an assumed project life of 20 years to estimate the abandoned value of the LFG system and 

pipeline that would occur upon switching to natural gas. 

The loss in royalty payments was calculated based on the amount of BTUs that would no longer be utilized by the 

end user over the remaining life of the LFG system and pipeline, multiplied by a factor that approximates typical 
24 

royalty payments to landfill owners for LFG-to-energy projects. The total cost reported in Table 1 is the net present 

value of payments projected over the remaining life of the project if fuel-switching had not occurred. 

The cost for utilizing natural gas instead of LFG was calculated by subtracting the displaced cost of operating and 

maintaining the LFG processing and transport system from the cost for purchasing natural gas. The total natural gas 

cost that would be paid in lieu of the LFG was then calculated based on Net Present Value (NPV) using the 

remaining life of the system assuming a 20 year project life and a real interest rate of 7%, which is assumed to 

approximate the private sector cost of capital. Although many of the landfills are publicly owned, almost all of the 

boiler operations using the gas are privately owned and would bear the cost of switching to natural gas. 

Assumptions 

The following assumptions were made in conducting this economic evaluation. 

1) The capital cost for the base project compressor and chiller system was estimated at $675,000 for a 750 cfm 

compressor system. The costs for systems that had flows less than or greater than this range were 

extrapolated from the base project using an extrapolation exponent of 0.75. The ratio of a given project 

capacity to the base project capacity is raised to the exponent and the result multiplied by the base project

cost to estimate the given project cost.6

2) The capital costs for the base project pipeline were estimated at $2/in diameter-ft of pipeline for flows less

than 2000 cfm and $6/in diameter-ft of pipeline for flows greater than 2000 cfm. Therefore, the installation, 

including labor and materials, of a 4 inch pipeline at 1000 cfm would be $8/ pipeline ft or approximately 

$42,000 per mile plus other additional costs as described below. 

3) If pipeline information was not listed for a project on the LMOP database, the median pipeline length (3.30 

miles) obtained from the boiler project tab was used. Just over half of the boiler site projects did not include 

pipeline length information. It is noted no pipeline information was provided on the Boiler-Steam Turbine

Tab. 

4) Project capital costs in addition to construction were added to the capital costs based on a percentage of the 

subtotal (compressor and pipeline) costs (Table 2). 

5) The cost of natural gas was assumed to be the latest available average U.S. retail natural gas price for 

industrial users of $5.40 per MMBTU, as published by the U.S. Energy Information Agency. 

(http://38.96.246.204/totalenergy/data/annual/showtext.cfm?t=ptb0608) 

 

TABLE 2. 

Additional Costs added to Capital Cost for Compressor System and Pipeline (Subtotal)

Item Percent Addition to Cost 

Road Crossing (s) 10% 

Engineering 10% 

Permitting 3% 

Administration and Legal 5% 

Construction Management 8% 

Mobilization/Demobilization 12% 
25 

6) The price per kilowatt-hour for Operation and Maintenance (O&M) of the LFG system was assumed to be the 

latest available average U.S. retail electricity price for industrial users of $0.0679/kw-hr, as published by the 

U.S. Energy Information Agency. (http://38.96.246.204/totalenergy/data/annual/showtext.cfm?t=ptb0810)

7) The pipeline costs for transporting natural gas from a high pressure supply pipe line to the project site were 

considered minor (i.e. a trivial distance between the project site and supply pipeline); therefore, they were 

not estimated or considered in this evaluation. 

8) Regional costs for capital investments including labor were not considered as part of the evaluation. It was 

assumed that the costs for varied capital and labor costs across the United States, which is covered by the 

LMOP program, would average out. Royalty payments were estimated at $0.75/MM BTU. 

9) The life cycle of the LFG project was assumed to be 20 years. 

10) The 20 City Construction Cost Index (CCI), which is calculated annually by The Engineering News Record 

(ENR), was used to calculate the capital costs of the LFG compressor and chiller based on the startup date 

from the estimated 2011 dollars (Grand Total) derived from the base project. The CCI values used in this 

estimation were an average of the 20 cities listed in the CCI. 

11) The energy content of natural gas was assumed to be approximately 1000 BTU/ft3. 

12) The methane content of LFG was assumed to be 50%; therefore, the energy content was assumed to be 500 

BTU/ft3. 

13) The Net Present Value (NPV) was estimated based on an inflation rate of 3% and a nominal discount rate of 

10%. Therefore, the ‘real discount rate’ is 7%. 

14) For projects older than twenty years, it is assumed there is no economic impact to fuel-switching. Projects at 

the end of their useful project lives are assumed to be replaced or abandoned in the near future. 

 
Attachment C 

R ep o rt 

Boiler MACT Fuel Classification 

Review for Landfill Gas 

Prepared for 

Waste Management, Inc. 

Revised December 2011 
mgm11-Waste Management/boiler mact/WM Final Boiler Reconsideration comments ii 

ES041211132050MGM 

Contents 

Acronyms and Abbreviations ................................................ Error! Bookmark not defined.

Boiler MACT Fuel Classification Review for Landfill GasError! Bookmark not defined.

Executive Summary ................................................... Error! Bookmark not defined.

Introduction ............................................................... Error! Bookmark not defined.

Comparison of Landfill Gas to Refinery Gas and Natural Gas 

 for General Properties, HAPs, and HAP Surrogates ........ Error! Bookmark not 

defined.

Landfill Gas ..................................................................................................... 2

Refinery Gas .................................................. Error! Bookmark not defined.

Natural Gas .................................................... Error! Bookmark not defined.

Comparison of HAP Precursors in the Boiler Fuel Raw Gases ........... Error! 

Bookmark not defined.

Comparison of HAP and HAP Surrogate Emissions from Combustion 

 of the Boiler Fuel Gases .......................... Error! Bookmark not defined.

Comparison of Landfill Gas, Refinery Gas, and Natural Gas to the Gas 1 

 Fuel Specification ................................................. Error! Bookmark not defined.

Conclusions ................................................................................................................ 25

References ................................................................... Error! Bookmark not defined.

Appendix 

Adapting Boilers to Utilize Landfill Gas: An Environmentally and Economically 

Beneficial Opportunity–EPA Landfill Methane Outreach Program (December 2009) 

Tables 

1. Fuel Gas Constituent Comparison ............................................................................. 5 

2. Emissions Comparisons .............................................................................................. 6 

3. Comparisons to the Gas 1 Fuel Specification ............................................................. 7 
mgm11-Waste Management/boiler mact/WM Final Boiler Reconsideration comments iii 

ES041211132050MGM 

Acronyms and Abbreviations 

API American Petroleum Institute 

BID Background Information Document 

BTU British thermal unit 

CFR Code of Federal Regulations

CH4 methane 

CO carbon monoxide 

EPA U.S. Environmental Protection Agency 

GCV gross calorific value 

gr grain 

H2S hydrogen sulfide 

HAP hazardous air pollutant 

HCl hydrochloric acid 

HHV higher heating value 

lb pound 

LFG landfill gas 

MACT maximum achievable control technology 

μg/m3 micrograms per cubic meter 

MMBTU million British thermal units 

NESHAPS National Emission Standards for Hazardous Air Pollutants 

NG natural gas 

PM particulate matter 

ppmv parts per million by volume 

RG refinery gas 

scf standard cubic feet 

SO2 sulfur dioxide 
mgm11-Waste Management/boiler mact/WM Final Boiler Reconsideration comments 1 

ES041211132050MGM 

Boiler MACT Fuel Classification Review for 

Landfill Gas 

Executive Summary 

Waste Management, Inc., has tasked CH2M HILL with identifying and reviewing available 

information to compare landfill gas (LFG) with gaseous fuels identified as Gas 1 fuels in the 

Boiler Maximum Achievable Control Technology (MACT) rule recently promulgated by the 

U.S. Environmental Protection Agency. Gas 1 fuels have a history of use as boiler fuels, and 

boilers using them are subject to work practice standards rather than to emission limits 

under the Boiler MACT rule. As described in this report, sufficient data were readily 

available to EPA to establish that LFG is comparable to natural gas (NG) and refinery gas 

(RG) with regard to HAP emissions. Emissions and raw gas analysis data support the 

conclusion that LFG should be classified as a Gas 1 fuel. We believe LFG is well qualified to 

be classified along with natural gas and refinery gas as a Gas 1 a priori because of the 

extensive LFG testing that has been done and published by EPA demonstrating that average 

LFG mercury levels are consistently less than the fuel specification proposed to establish 

other process fuels as Gas 1 fuels. 

Introduction 

On March 21, 2011, the U.S. Environmental Protection Agency (EPA) published the National 

Emission Standards for Hazardous Air Pollutants (NESHAPS) for Major Sources: Industrial, 

Commercial, and Institutional Boilers and Process Heaters, Final Rule, under 40 Code of 

Federal Regulations (CFR) Part 63 subpart DDDDD. The rule commonly is referred to as the 

Boiler Maximum Achievable Control Technology (MACT). EPA reconsidered the final 

Boiler MACT rule and on December 23, 2011 published the proposed rule/reconsideration 

of the final Boiler MACT rule in the Federal Register. The current revision of this report is 

specifically in response to EPA’s December 23, 2011 published proposed rules and updated 

fuel specification for Gas 1 demonstration. Although EPA has proposed removing the 

hydrogen sulfide requirement from the fuel specification that was in the March 21 rule, our 

previous conclusions, rationale and supporting data regarding the hydrogen sulfide 

requirement have been retained in this revision in support of the proposed removal of the 

requirement. 

The proposed rule requires owners of boilers and process heaters (referred to as “boilers” in 

this report) to control emissions of hazardous air pollutants (HAPs) to specified levels. An 

alternative requirement is established for boilers fired by NG or RG (defined as “any gas 

that is generated at a petroleum refinery and is combusted”). These boilers are described as 

Gas 1 units. Under the proposed rule, Gas 1 units do not have to control emissions to the 

specified levels, but instead must institute a “work practice standard” of good operation 

and maintenance. Boilers using other gaseous fuels, including LFG, are referred to as Gas 2 

units. A Gas 2 unit must meet the specified emission limits unless it can be demonstrated 
BOILER MACT FUEL CLASSIFICATION REVIEW FOR LANDFILL GAS

mgm11-Waste Management/boiler mact/WM Final Boiler Reconsideration comments 2 

ES041211132050MGM 

that the gas fuel meets a specification 40 micrograms per cubic meter (μg/m3) of mercury or 

less, in which case a work practice standard can be instituted for the unit. 

The HAPs regulated by 40 CFR Part 63 are a specific list of substances that might be emitted 

to the air. The emission parameters regulated by the Boiler MACT are as follows: 

• Mercury 

• Dioxins/furans 

• Particulate matter (PM) (as a surrogate for non-mercury metals) 

• Hydrochloric acid (HCl) (as a surrogate for acid gases) 

• Carbon monoxide (CO) (as a surrogate for non-dioxin organic air toxics) 

The purpose of this report is to compare the properties of emissions from boilers fired by 

LFG, specifically with respect to the Boiler MACT emission parameters, to establish that 

LFG is not different from the Gas 1 fuel sources and that enough information is publicly 

available (much of it published by EPA) for EPA to have made the determination that LFG 

should be included among the fuels designated as Gas 1 by the Boiler MACT. Sources of 

data are cited in the report and references. Sources include documents identified in an online docket search (Docket Number EPA-HQ-OAR-2002-0058) by CH2M HILL in May 2011, 

and followed up with an updated search for information on Gas 1 and Gas 2 fuels relevant 

to our analysis and findings in this report, in all documents posted between that time and 

December 18, 2011. 

In the following sections, first the general properties and HAP precursors of the recognized 

Gas 1 fuels (NG and RG) are compared to LFG, and then the emissions from these gases are 

similarly compared. The properties of the recognized Gas 1 fuels and LFG are then 

compared to the fuel specification requirements for establishing a gas that otherwise would 

be considered a Gas 2 as a Gas 1 gas. Finally, conclusions are presented as to how well the 

data support the case that LFG should have been considered as a Gas 1 under the Boiler 

MACT. 

Comparison of Landfill Gas to Refinery Gas and Natural Gas for 

General Properties, HAPs, and HAP Surrogates 

Landfill Gas 

The general properties of LFG have been well established in many studies and surveys 

because LFG emissions have been regulated under federal and many state and local statutes 

for a number of years. LFG is generated by the anaerobic decomposition of the organic 

fraction of waste material within landfill disposal sites. The average composition of LFG is 

approximately 50-percent methane and 50-percent carbon dioxide and LFG typically is 

saturated with water vapor , with trace contaminants including volatile organic compounds, 

chlorinated organics, and H2S. The methane percentage can vary from 40 to 60 percent

depending on several factors, including waste composition (carbohydrate and cellulose 

content and pH in the landfill). LFG has an average higher heating value (HHV) of 

approximately 500 British thermal units (BTUs) per standard cubic feet (scf) (about half the 

HHV of NG). 
BOILER MACT FUEL CLASSIFICATION REVIEW FOR LANDFILL GAS

mgm11-Waste Management/boiler mact/WM Final Boiler Reconsideration comments 3 

ES041211132050MGM 

LFG has been used as a boiler fuel in both industrial and commercial applications since the 

late 1970s. Approximately 70 boilers currently are fueled by LFG in the United States (EPA, 

2009). 

As part of the regulation of landfill emissions, EPA undertook a study of the constituents of 

LFG and published a compendium in 2008 based on a review of data from hundreds of 

analyses of raw LFG and LFG combustion emissions, including specifically combustion in 

boiler units. EPA used the data collected to establish mean and standard deviation values 

for many of the trace compounds in LFG and emissions. The Background Information 

Document (BID) contains a summary of emissions from boiler units for which LFG was 

used as a fuel (EPA, 2008). 

Refinery Gas 

RG is defined in the Boiler MACT as “any gas that is generated at a petroleum refinery and 

is combusted. Refinery gas includes NG when the NG is combined and combusted in any 

proportion with a gas generated at a refinery. Refinery gas includes gases generated from 

other facilities when that gas is combined and combusted in any proportion with gas 

generated at a refinery.” 

This definition includes a wide variety of gas compositions under the “any gas” 

characterization. In fact, the American Petroleum Institute (API) recognizes 62 different 

types of RGs (API, Appendix Table 2-1, 2009) and has published a table of the typical 

compositions. The constituents of the various RGs include a hydrogen content of up to 

88-percent, methane and other (C1 to C4) hydrocarbons from 0 up to 94 percent, and H2S 

from 0 up to 45 percent by volume, as well as other constituents including ammonia, carbon 

dioxide, and C5 and C6 hydrocarbons, that vary widely among the different RGs. 

The variation within the category of RG is much greater than the well-documented (by EPA) 

variation of constituent concentrations in LFG. LFG is produced by the same process–

biological decomposition by methanogenic organisms–in all landfills. Although the 

composition of trace constituents varies considerably depending on the materials placed in a 

particular landfill, the variation of wastes in municipal landfills is not as great as the 

variation among RGs, as described by API (2009). 

Delucchi (2003) explored the compositions of RGs as part of a study of greenhouse gas 

emissions. Delucchi cited several sources indicating that typical RG, at least as it is 

produced, contains 1- to 2-percent H2S by volume. “If refinery gas containing 1- to 2-percent

H2S is burned in uncontrolled boilers, sulfur dioxide (SO2) emissions from refineries will be 

quite large. It appears that before the most recent tightening of the regulations in Southern 

California (in 1994 and 1996), refinery gas contained on the order of 100 to 200 ppmv.” 

Natural Gas 

NG is defined as an odorless, colorless, tasteless, nontoxic clean-burning fossil fuel. NG is 

largely methane (CH4), a naturally occurring gas that also can be produced by coal 

gasification. NG is created thermogenically at great temperature and pressure from buried 

organic material. In addition to CH4, NG typically contains H2S and other sulfur 

compounds, ethane, propane, butane, pentane, hexane, and helium. 
BOILER MACT FUEL CLASSIFICATION REVIEW FOR LANDFILL GAS

mgm11-Waste Management/boiler mact/WM Final Boiler Reconsideration comments 4 

ES041211132050MGM 

The definition of “natural gas” in §72.2 of the May 26, 1999, revisions to 40 CFR Parts 72 and 

75 states that for a gaseous fuel to qualify as natural gas, the fuel must either be greater 

than 70-percent methane by volume or must have a gross calorific value (GCV) between 

950 and 1,100 BTU/scf. The definitions of “natural gas” and “pipeline natural gas” in § 72.2 

also limit the H2S content of these fuels to less than 1 grain (gr)/100 scf (16.4 ppmv) for 

“natural gas” and less than 0.3 gr/100 scf (4.9 ppmv) for “pipeline natural gas.” 

Comparison of HAP Precursors in the Boiler Fuel Raw Gases 

CO and dioxins/furans are emissions regulated under the proposed Boiler MACT, but they 

are products of the combustion of hydrocarbons and other organic compounds that can be 

controlled by boiler operational practices. EPA has recognized this by proposing a work 

practice standard for dioxins/furans rather than a specific emission limit. As such, there are 

no appropriate comparisons of fuel constituents for these parameters. HCl is a product of 

the combustion of chlorinated compounds in the fuel gas. Chlorinated compounds in the 

fuel gas will increase the potential for emissions of both HCl and dioxins/furans, so 

comparisons of chlorinated compounds in the fuel gases are appropriate. Metals 

compounds in fuel gas generally will affect emissions from combustion proportionately to 

the concentrations in the fuel gas. 

Therefore, the fuel gas precursor constituents relevant to the five HAP and precursor 

parameters covered under the Boiler MACT are as follows: 

• Total mercury 

• Other HAP metals 

• Chlorinated compounds 

RG and NG automatically are considered “Gas 1” fuels by the Boiler MACT; thus, boilers 

using them are not governed by the more difficult requirements of “Gas 2” burning units. 

Table 1 provides a summary of the ranges of available data for the HAP precursors listed 

previously in the two Gas 1 fuels, compared to LFG. No data were available in EPA’s Boiler 

MACT analyses for any of the HAP precursors in NG, RG, or LFG. (The data contained 

voluminous results for solid and liquid fuel analyses, but not for the fuel gases.) A search for 

other sources of these data indicated that EPA (2001) performed a study of mercury in NG 

and found that concentrations in NG extracted in the continental United States typically 

were less than 0.2 μg/m3. Another source (Malik and Slack, 2009) stated that arsenic (one of 

the HAP metals) in RG was in the “ppb range.” This is the only HAP metal for which any 

data were readily available through Internet searches. 

Voluminous data are available regarding chlorinated compounds in LFG. The most recent 

compilation by EPA is contained in the BID (EPA, 2008) for the most recent update of the 

AP-42 document, which establishes default emission factors for LFG . Table 1 lists the sums 

of the mean concentrations of all chlorinated trace compounds reported in the BID (EPA, 

2008). Although other chlorinated compounds might be present, this total is a rough 

approximation of the chlorinated compounds likely to be present in LFG, and in fact, is used 

by at least one air pollution control district, San Diego County, California, to derive the 

default HCl emission factor used to determine compliance with emission limits. 
BOILER MACT FUEL CLASSIFICATION REVIEW FOR LANDFILL GAS

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The EPA BID (2008) contained a chapter devoted to mercury in LFG. The range reported in 

Table 1 includes results of multiple analyses from 15 landfills as reported in the BID. 

Mercury levels in LFG provided in Table 1 are the same order of magnitude as the available 

data for mercury in NG. The upper end of the range reported in Table 1 was noted as an 

outlier in the BID, but is still only a fraction of the fuel specification for mercury as 

established for “other Gas 1” fuels as described later in this report. For the other parameters 

reported in Table 1, the lack of data for both NGs and RG prevent a comparison with LFG. 
BOILER MACT FUEL CLASSIFICATION REVIEW FOR LANDFILL GAS

mgm11-Waste Management/boiler mact/WM Final Boiler Reconsideration comments 6 

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TABLE 1 

Fuel Gas Constituent Comparison 

Boiler MACT Fuel Classification Review for Landfill Gas 

Parameter Unit Natural Gas Refinery Gas 

Landfill Gas 

(AP-42 BID) 

Mercury, total μg/m3

< 0.2 “typical” 

(note 1) no data 0.01 to 7.85 (note 2) 

Chlorine 

Compounds ppmv no data no data 34.7 (note 3) 

Arsenic ppb no data "ppb range" (note 4) no data 

Notes: 

1. Source: Table 7-20, Mercury in Petroleum and Natural Gas: Estimation of Emissions from Production, 

 Processing, and Combustion. EPA/600/R-01/066, 2001 

2. Reported as 0.0000012 to 0.00096 ppm total mercury. 

3. Total of all chlorinated compound mean concentrations listed in Table 2-8 of EPA/600/R-08-116, 

 33 compounds tested 

4. Source: Table 2, Malik, Z. I. and J. Slack. How to Treat Refinery Gases." Linde Process Plants, Inc. 

CO and dioxins/furans are emissions regulated under the Boiler MACT, but they are products of 

combustion of HCs and other organic compounds that can be controlled by boiler operational practices. As 

such, there are no appropriate comparisons of fuel constituents. 

μg/m3 = microgram per cubic meter 

ppb = parts per billion 

ppmv = parts per million by volume 

Comparison of HAP and HAP Surrogate Emissions from Combustion of the Boiler 

Fuel Gases 

Table 2 provides a comparison of the data available for the Boiler MACT HAP and HAP 

surrogate emissions from the combustion of NG, RG, and LFG. In all cases, the emissions 

are for the gas used as boiler fuel. In the first three columns of Table 2, all of the emissions 

reported are from the Boiler MACT Floor Memo Appendix C (Docket Number EPA-HQOAR-2002-0058-1388.1) assembled by EPA. Only three LFG emission tests were reported in 

these MACT Floor Memo data, and for only two of the five HAP and surrogate parameters, 

mercury and dioxin/furan. However, the BID (EPA, 2008) did report ranges for two of the 

other three HAPs and HAP surrogates, PM and CO. A previous EPA study in 2007 

(EPA/600/R-07/043) reported two tests for HCl from LFG-fueled boilers. Thus, numerous 

data were available for the comparison of LFG to the established Gas 1 fuels for all of the 

HAP and HAP surrogate parameters except HCl, for which only two test reports were 

available for LFG and none for refinery gas. Table 2 shows that, for all of the other 

parameters, the data for LFG are within or below the ranges for one or both of the 

recognized Gas 1 fuels. 
BOILER MACT FUEL CLASSIFICATION REVIEW FOR LANDFILL GAS

mgm11-Waste Management/boiler mact/WM Final Boiler Reconsideration comments 7 

ES041211132050MGM 

TABLE 2 

Emissions Comparisons 

Boiler MACT Fuel Classification Review for Landfill Gas 

Parameter Unit 

Natural Gas 

(note 1) 

Refinery Gas 

(note 1) 

Landfill Gas 

(note 1) 

Landfill Gas 

(AP-42 BID) 

Mercury lb/MMBTU 1.2e-8 to 9.9e-8 6.1e-8 to 1.6e-7 7.6e-8 to 1.0e-7 no data 

Hydrogen 

Chloride 

lb/MMBTU 7.6e-5 to 1.14e-4 no data 3.21e-3 to 3.98e-3 

(note 2)

no data 

Particulate 

Matter 

lb/MMBTU 3.7e-6 to 0.015 1.0e-4 to 0.1077 no data 6.0e-4 to 4.4e-3 

Carbon 

Monoxide 

ppm 

(3%O2)

0.08 to 56 9.0e-3 to 184 no data 2.0e-4 to 0.02 

Dioxin/Furan 

(Total Mass) 

ng/dscm 

(7% O2) 

0.012 to 0.062 no data 2.0e-3 to 3.8e-3 1.36e-6 to 1.53e-5 

(note 3) 

Notes: 

1. Unless noted otherwise, natural gas, refinery gas, and LFG values are from MACT Floor Memo 

 Appendix C spreadsheet (Docket Number EPA-HQ-OAR-2002-0058-1388.1) 

2. HCL data for LFG combusted in boilers were reported in Field Test Measurements at Five Municipal 

 Solid Waste Landfills with Landfill Gas Control Technology Final Report, EPA/600/R-07/043, April 2007, 

 Table 4-12 (EPA 2007). Data was converted to lb/MMBTU using raw gas inlet flow rate of 2430 SCFM 

 (Table 4-7) and average gas methane concentration of 49% (Table 4-1). The LHV of methane is 

 914 BTU/SCF. 

3. AP-42 dioxin/furan data expressed as ng/dscm of CH4 inlet gas versus flue gas; conversion to flue 

 gas basis would reduce by approximate factor of 20

Ranges reported are above detection limits. However, all LFG results from the MACT Floor memo 

spreadsheet had DLL flag 

lb/MMBtu = pounds per Million British thermal units 

ppm = parts per million 

O2 = oxygen 

ng/dscm = nanogram per dry standard cubic meter 

WM = Waste Management, Inc.

Comparison of Landfill Gas, Refinery Gas, and Natural Gas to 

the Gas 1 Fuel Specification 

In the preamble to the proposed Boiler MACT rule, EPA explains () that: 

“EPA has reexamined the fuel specification and agrees that the key contaminant for 

demonstration of comparability from a HAP perspective is Hg and that the H2S fuel 

specification that was finalized does not provide a direct indication of potential HAP from 

combustion of gaseous fuel. Accordingly, the EPA is proposing a fuel specification based only 

on the Hg level in the gaseous fuel, and that level is the same level that the EPA included in the 

March 2011 final rule.” 

Under §63.7521 (f) of the proposed reconsidered Boiler MACT rule, “To demonstrate that a 

gaseous fuel other than natural gas or refinery gas qualifies as an other Gas 1 fuel, as 

defined in §63.7575, you must conduct fuel specification analyses for mercury.” Monthly 

testing is required unless the fuel supplier or user certifies that the mercury fuel 
BOILER MACT FUEL CLASSIFICATION REVIEW FOR LANDFILL GAS

mgm11-Waste Management/boiler mact/WM Final Boiler Reconsideration comments 8 

ES041211132050MGM 

specification limit will never be exceeded. The Hg level in the March 2011 final rule is 40 

micrograms per cubic meter. 

Table 3 provides a comparison of the readily available data for total mercury in LFG to 

comparable data for NG and RG. As noted above, EPA’s 2008 effort to establish an 

appropriate default parameter for Hg in LFG found no instances of LFG exceeding the fuel 

specification value of 40 μg/m3 among the numerous tests conducted that EPA reviewed. 

TABLE 3 

Comparisons to the Gas 1 Fuel Specification 

Boiler MACT Fuel Classification Review for Landfill Gas 

Parameter Unit 

Fuel Gas 

Specification Natural Gas Refinery Gas 

Landfill Gas 

(AP-42 BID) 

Mercury μg/m3 40 

< 0.2 “typical” 

(note 1) no data 0.01 to 7.85 

H2S ppmv 4 15.3 (note 2) 

0 to 450,000 

(note 3) 1.02e-3 to 55.7 

Notes: 

1. Source: Table 7-20, Mercury in Petroleum and Natural Gas: Estimation of Emissions from Production, 

 Processing, and Combustion. EPA/600/R-01/066, 2001 

2. Per definition of natural gas fuel in 40 CFR Part 72 

3. Delucchi. 2003, p.46 established a range of 100 to 200 ppmv as the likely range of refinery gas burned 

 as fuel. However, the range of H2S in refinery gases meeting the boiler MACT definition includes up to 

 45% H2S, per API 2009. 

μg/m3 = micrograms per cubic meter 

ppmv = parts per million by volume 

Conclusions 

Following are the conclusions of this report: 

1. Data developed by EPA in its 2008 BID support the conclusion that the mercury level in 

LFG consistently is much lower than the Gas 1 fuel specification level of 40 μg/m3, 

which should a priori establish landfill gas in the same Gas 1 category as natural gas and 

refinery gas. The data for mercury in LFG support its characterization as a Gas 1 fuel. 

2. A comparison of the readily available data for LFG-only fueled boiler emissions 

indicates that the ranges of reported results for mercury, PM, CO, and dioxin/furans are 

within or below the ranges of these parameters for one or both of the recognized Gas 1 

fuels, NG and RG. No HCl data were available for RG for comparison to LFG. However, 

the few HCl emissions data available from LFG-fueled boilers (0.00321 to 

0.00398 pounds per million British thermal units [lb/MMBTU]) are lower than the Boiler 

MACT emission limits for both new and existing solid fuel-fired units (0.022 

lb/MMBTU). 

3. Use of NG or RG will increase criteria pollutant and greenhouse gas emissions 

compared to LFG. LFG has been shown to produce lower nitrous oxide emissions than 

NG, and using LFG lowers fossil carbon dioxide emissions as compared to NG or RG. 
BOILER MACT FUEL CLASSIFICATION REVIEW FOR LANDFILL GAS

mgm11-Waste Management/boiler mact/WM Final Boiler Reconsideration comments 9 

ES041211132050MGM 

4. Mercury levels in raw LFG from 15 landfills reported in EPA’s BID (2008) indicated a 

range of total mercury orders of the same order of magnitude as the available data for 

mercury in NG. A comparison of the constituents of raw LFG to the recognized Gas 1 

fuels is inconclusive with respect to the other HAP and surrogate parameters because of 

the dearth of available data for the Gas 1 fuels. 

5. EPA based its fuel specification in the March 21, 2011 rule on sweetened, pipelinequality NG. However, RG typically contains much higher levels of H2S than the Gas 1 

fuel specification in that rule. LFG should not be held to a higher H2S standard than RG 

for qualification as a Gas 1 fuel, especially considering that H2S is not a HAP or a HAP 

precursor or a surrogate for HAP emissions. 

6. The data forH2S in LFG support its characterization as a Gas 1 fuel. 

References 

American Petroleum Refinery (API). 2009. Refinery Gases Category Analysis and Hazard 

Characterization. Submitted to the U.S. Environmental Protection Agency by the Petroleum 

HPV Testing Group. June 10. 

Delucchi, Mark. 2003. A Lifecycle Emissions Model (LEM): Lifecycle Emissions from 

Transportation Fuels, Motor Vehicles, Transportation Modes, Electricity Use, Heating and Cooking 

Fuels, and Materials. University of California, Davis, Institute of Transportation Studies. 

December 1. 

Eddinger, Jim (U.S. Environmental Protection Agency [EPA]). 2005. Memo regarding: 

“Re-Revised MACT Floor Analysis for the Industrial, Commercial, and Institutional Boilers 

and Process Heaters National Emission Standards for Hazardous Air Pollutants Based on 

Public Comments. June. 

Edgar, Thomas F. 2008. Evaluation of Environmental Emissions for Combustion of Landfill Gas in 

a Texas Petrochemical Plant. University of Texas–Austin. 

ERG (A. Singleton). 2011. Revised MACT Floor Analysis for the Industrial, Commercial 

Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air 

Pollutants–Major Source. January. 

ERG (A. Singleton). 2010. MACT Floor Analysis (2010) for the Industrial, Commercial, and 

Institutional Boiler and Process Heaters National Emission Standard for Hazardous Air Pollutants–

Major Source. April. 

Malik, Z. I. and J. Slack. 2009. How to Treat Refinery Gases. Linde Process Plants, Inc. 

U.S. Environmental Protection Agency (EPA). 2001. Mercury in Petroleum and Natural Gas: 

Estimation of Emissions from Production, Processing, and Combustion. EPA600/R-01/066. 

U.S. Environmental Protection Agency (EPA). 2007. Field Test Measurements at Five Municipal 

Solid Waste Landfills with Landfill Gas Control Technology Final Report, EPA/600/R-07/043, April .

U.S. Environmental Protection Agency (EPA). 2008. Background Information Document for 

Updating AP42 Section 2.4 Municipal Solid Waste Landfills. EPA/600/R-08-116. September. 
BOILER MACT FUEL CLASSIFICATION REVIEW FOR LANDFILL GAS

mgm11-Waste Management/boiler mact/WM Final Boiler Reconsideration comments 10 

ES041211132050MGM 

U.S. Environmental Protection Agency (EPA). 2009. Adapting Boilers to Utilize Landfill Gas: 

An Environmentally and Economically Beneficial Opportunity. Accessed online at: 

http://www.epa.gov/lmop/. Copy of brochure is attached. 

U.S. Environmental Protection Agency (EPA). 2011. Excel Spreadsheet. MACT Floor Memo 

Appendixes C, D, and E. Boiler Maximum Achievable Control Technology (MACT) docket 

site, EPA Docket Number EPA-HQ-OAR-2002-0058-1388.1. 

Waste Management, Inc. 2011. National Emission Standards for Hazardous Air Pollutants 

for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters; 

Final Rule (Docket ID No. EPA-HQ-OAR-2002-0058); Petition for Reconsideration. Letter 

from Eli Brill, Sr. Legal Counsel, to Lisa P. Jackson, EPA Administrator. May 19. 
1 

February 21, 2012 

Via Electronic Transmission: jones.toni@epa.gov

 a-and-r-Docket@epa.gov

Attention: EPA Docket ID. No. EPA-HQ-OAR-2003-0119 

 Faison.george@epa.gov

 Rcra-docket@epa.gov

Attention: EPA Docket ID. No. EPA-HQ-RCRA-2008-0329 

Ms. Toni Jones & Mr. George Faison 

Sector Policies and Programs Division 

Office of Air Quality Planning and Standards 

Program Implementation and Information Division 

Office of Resource Conservation and Recovery 

U.S. Environmental Protection Agency 

1200 Pennsylvania Ave., NW 

Washington, DC 20460 

Dear Ms. Jones and Mr. Faison: 

Waste Management (WM) is pleased to provide comments on the Agency’s proposed 

Commercial and Industrial Solid Waste Incineration Units: Reconsideration (hereinafter the 

“CISWI Reconsideration Rule”) and the Proposed Amendments: Non-Hazardous Secondary 

Materials Rule (hereinafter the “NHSM Rule Amendments”) published at 76 Fed. Reg. 80452 

(December 23, 2011). We are blending our comments on these regulatory proposals in one 

letter to reflect the Agency’s combining the two rulemakings in one Federal Register Notice, 

and the close interrelationship of the two rules for the regulated community. As North 

America’s leading provider of integrated environmental solutions, WM is uniquely interested in 

ensuring that the Agency’s final CISWI Reconsideration Rule and NHSM Rule Amendments 

reflect and support ongoing and newly evolving efforts to reduce, reuse and manage waste, 

while recovering valuable resources and producing clean renewable energy. 

WM is the largest provider of comprehensive waste and environmental services in North 

America, as well as North America’s largest municipal waste recycler and a leader in wastebased energy technologies. Headquartered in Houston, Texas, the company serves over 20 

million customers with environmentally sound management of solid wastes and transformation 

of wastes into usable resources. WM has been a constant advocate of landfill gas as a 

renewable alternative fuel, and as of the end of 2011 operates 131 landfill gas-to-energy 

projects that produce enough renewable energy to power nearly half a million homes. 
2 

Additionally, WM’s wholly-owned subsidiary, Wheelabrator Technologies, Inc. (“WTI”), owns or 

operates 17 waste-to-energy plants and five independent power production plants in the U.S. 

that generate enough energy to power more than 680,000 homes. Together these power 

production plants and projects replace use of about 5.3 million tons of coal per year. These 

projects offset criteria pollutants and hazardous air pollutants associated with coal use and also 

offset over 3.5 million tons of carbon dioxide equivalent (CO2e) emissions each year. One of 

these independent power plants operated by WTI, a biomass plant that burns landfill gas, yard 

waste and tires to produce electricity, will be subject to the CISWI Reconsideration Rule. 

Beginning in 2010, WM focused the company’s investment strategy on broadening the scope of 

materials we recover from waste streams and transform into resources such as compost, 

biogas, renewable fuels and green chemicals. Failure to harmonize the CISWI Reconsideration 

Rule and NHSM Rule Amendments with national materials management, renewable energy and 

greenhouse gas reduction goals will undermine significant sustainability investments by WM, 

other companies, local governments, and federal agencies. In addition, the imposition of any 

new and unreasonable regulatory burdens upon the combustion of landfill gas will conflict with 

existing Clean Air Act (CAA) regulations governing landfill gas control and use as a renewable 

fuel, including the Standards of Performance for Municipal Solid Waste Landfills, 40 C.F.R. Part 

60, Subpart WWW (the “Landfill NSPS”) and the National Emission Standards for Hazardous Air 

Pollutants: Municipal Solid Waste Landfills, 40 C.F.R Part 63, Subpart AAAA (the “Landfill 

MACT”). 

WM offers the following comments on the proposed CISWI Reconsideration Rule and NHSM 

Rule Amendments, incorporating by reference WM’s Petition for Reconsideration of the 

Standards of Performance for New Stationary Sources and Emission Guidelines for Existing 

Sources: Commercial and Industrial Solid Waste Incineration Units (Docket ID No. EPA-HQ-OAR2003-0119-2550, comments filed on July 15, 2011 (docketed at EPA-HQ-OAR-2003-0119-3355), 

and WM’s Petition for Administrative Stay Pending Judicial Review of the Identification of NonHazardous Secondary Materials That Are Solid Waste (Docket ID No. EPA-HQ-RCRA-2008-

0329).1 

EPA Must Clarify that the CISWI Rule Does Not Apply to Combustion of Landfill 

Gas 

First and foremost, EPA must clarify that the CISWI Rule does not apply to the combustion of 

landfill gas, either when combusted for control (as in an enclosed flare) or combusted as a 

fuel (as in a boiler). WM’s Petition for Reconsideration of the final CISWI Rule promulgated in 

 

1

Additionally, WM offers these comments without waiver of any issues raised through its Petitions for Review of 

the CISWI and NHSM rulemakings, at Docket No. 11-1149 and Docket No. 11-1148 in the U.S. Court of Appeals for 

the District of Columbia Circuit. 
3 

March of 20112 focused on EPA’s removal of the definition of “contained gaseous material” 

from the final CISWI Rule, and the significant change that action made to EPA’s established 

interpretation of the scope of Section 129 of the CAA, as it relates to the definition of “solid 

waste” under the Resource Conservation and Recovery Act (RCRA). 

EPA’s statements in a related rulemaking record suggested that EPA’s final CISWI rule departed 

significantly from EPA’s established interpretation of Section 129 of the CAA. Specifically, in its 

Response to Comments for the NHSM Rule, EPA cast significant doubt on the continued vitality 

of its past interpretation of “contained gaseous materials” that may be considered solid waste, 

and suggested that the combustion of gaseous emission streams for pollution control may 

constitute the combustion of solid waste subject to the CISWI Rule. Further, EPA suggested 

that landfill gas may constitute “solid waste” simply because landfill gas is extracted from a 

waste mass, and if used as fuel may be subject to a demonstration of legitimacy under the 

NHSM Rule. Docket Id. EPA-HQ-RCRA-2008-0329-1837 at pages 211-214. 

Taken together, these two Agency actions signaled a significant change in policy and regulatory 

precedent and were made without any prior notice to regulated entities, and without 

opportunity for comment. For over twenty years, EPA has developed a comprehensive 

regulatory structure to govern the collection, control and treatment of landfill gas under the 

CAA —a structure based on the correct determination that landfill gas is not a solid waste 

under RCRA. EPA’s deletion of the definition of contained gaseous material from CISWI and 

statements in the NHSM rulemaking record threaten to undercut the existing regulatory 

scheme established under the CAA by potentially subjecting landfill gas combustion to the 

CISWI Rule. Regulation of landfill gas as a solid waste also threatens to undermine the market 

for landfill gas as a fuel, in direct contradiction to the stated goals of EPA’s Landfill Methane 

Outreach Program and the administration’s broader goals to encourage domestic, renewable 

energy sources. 

Notwithstanding these actions, it is clear from a review of the CISWI rulemaking record that the 

Agency did not contemplate the possibility that landfill gas combustion units may be subject to 

CISWI. EPA’s evaluation of regulatory impacts did not identify massive costs associated with 

application of the rule to thousands of landfill gas combustion sources. Regulation of landfill 

gas under Section 129 of the CAA would dramatically affect the cost of capture and control of 

landfill gas and neither these costs nor these units were addressed. Likewise, CISWI did not 

include a subcategory that would apply to combustion units primarily utilizing landfill gas as 

fuel. 

WM provided cost estimates to EPA on July 15, 2011 to assist the Agency in its reconsideration 

of CISWI. See Docket Id. EPA-HQ-OAR-2003-0119-3355. We provided estimates of both capital 

expenditures for new control equipment and annual operations and maintenance costs 

associated with possible regulation of landfill gas capture and control as solid waste 

 

2

 Standards of Performance for New Stationary Sources and Emission Guidelines for Existing Sources: Commercial 

and Industrial Solid Waste Incineration Units, 76 Fed. Reg. 15704 (March 21, 2011) 
4 

incineration. As an initial matter, WM anticipated that current third party users of landfill gas 

would discontinue using landfill gas when faced with strict emission limits. Without an end 

market for the sale or transfer of gas, WM and other landfill owners /operators would be left 

with greater quantities of landfill gas to control. For example, landfill gas flares (which are 

approved pollution control devices under the Landfill NSPS and Landfill MACT) would need to 

be replaced with thermal oxidizers to meet Section 129 emission limits. For WM alone, we 

estimated our capital costs for installation of thermal oxidizers (about $412 million) to exceed 

the total EPA estimated costs identified in the CISWI Rule for all its intended sources. Based on 

EPA’s estimated annual costs of compliance for each facility ($186,000), we estimated WM’s 

annual compliance costs would exceed $50 million per year. Such costs would be a significant 

financial burden for WM, and would be ruinous to the many local governments that own and 

operate MSW landfills and combust landfill gas for control or as fuel. 

On August 5, 2011, the Director of the Office of Resource Conservation and Recovery wrote a 

letter to WM, to provide clarification of Agency statements made in the Response to Comments 

Document indicating a change in interpretation of what constitutes a “contained gaseous 

material.” The Office Director’s letter stated that the Agency has not changed its previous 

positions regarding what constitutes a “contained gaseous material,” nor had it changed its 

previous statements and interpretations concerning landfill gas. The letter affirmed that the 

Agency’s previous statements and interpretation remain effective. 

While WM is very appreciative of the Agency’s clarifying letter, we believe that it is imperative 

that the Agency confirm in both the CISWI Reconsideration Rule and the NHSM Rule 

Amendments the longstanding definition of “solid waste” as extending only to “contained 

gaseous material,” and to further clarify that the combustion of gaseous emission streams, 

including landfill gas, does not constitute the combustion of solid waste subject to the CISWI 

Rule.

WM supports the explanations in the CISWI Reconsideration and the NHSM Rule Amendments 

preambles that affirmed the language in the WM comfort letter, as well as a comfort letter 

written to the American Forest & Paper Association, and clearly stated that EPA did not intend 

to change its previous interpretations of what constitutes “contained gaseous material.” We 

strongly recommend that EPA finalize its clarifying language in the preambles to both final 

rules and add to the preamble discussions a further clarification that landfill gas is not a 

contained gas, and therefore not a solid waste when combusted in engines, turbines or other 

combustion devices that combust landfill gas. EPA could easily achieve this by adding landfill 

gas combusted in flares or other combustion devices to the list of examples of gaseous material 

combustion that does not involve the treatment or other management of a solid waste. EPA 

should add a statement to both preambles that its clarification with regard to combustion of 

uncontained gases, including landfill gas, supersedes the ambiguous and confusing NHSM Rule 

Response to Comments Document. Despite EPA’s clarifying letter to WM, there still remains 

some confusion among permitting agencies regarding the status of LFG combustion. We 

believe EPA should clarify this issue once and for all. 
5 

WM further supports the Agency’s proposal to reinsert the definition of “contained gaseous 

material” into the CISWI Reconsideration Rule. WM agrees with the Agency that the inclusion 

of the definition will aid in clarifying that CISWI applicability has not changed with respect to 

gaseous emission streams that are combusted. However, we note that while the preamble to 

the CISWI Reconsideration Rule proposed reinsertion of the definition, the rule language itself 

did not include the definition. Given that subsequent to the proposal of the CISWI 

Reconsideration Rule the March 21 2011 CISWI Rule became effective,3 EPA must actually 

reinstate the definition of “contained gaseous material” in the regulatory language of the CISWI 

Reconsideration Rule. 

Notwithstanding the proposed inclusion of the definition of “contained gaseous material” in the 

CISWI Reconsideration Rule, the Agency has not proposed to reinstate the definition of “solid 

waste” within CISWI. As a result, the term “contained gaseous material” would appear only in 

the definitions section and not appear elsewhere in the CISWI Rule. Nonetheless, the CISWI 

Reconsideration Rule does use the term “solid waste” in the definition of CISWI unit, Energy 

recovery unit, Incinerator, Small, remote incinerator, solid waste incineration unit, and Wasteburning kiln. In each of these definitions, the rule describes the term “solid waste” by saying 

“(as that term is defined by the Administrator in 40 CFR part 241).” In 40 CFR part 241.2 the 

term solid waste is defined as “Solid waste means the term solid waste as defined in 40 CFR 

258.2.” The definition in 40 CFR part 258.2 is identical to the definition of solid waste that was 

deleted from the original CISWI Rule, and reads as follows: 

Solid Waste means any garbage, or refuse, sludge from a wastewater 

treatment plant, water supply treatment plant or air pollution control 

facility and other discarded material, including solid, liquid, semi-solid, or 

contained gaseous material resulting from industrial, commercial, 

mining, and agricultural operations, and from community activities, but 

does not include solid or dissolved materials in domestic sewage, or solid 

or dissolved materials in irrigation return flows or industrial discharges 

that are point sources subject to permit under 33 U.S.C. 1342, or source, 

spent nuclear, or by-product material as defined by the Atomic Energy 

Act of 1954, as amended (68 Stat. 923). 

To clarify the definitions of “solid waste” and “contained gaseous material” across both the 

CISWI Reconsideration Rule and the NHSM Rule, the two rules should contain both definitions. 

We therefore, recommend that EPA reinsert both the definition of solid waste as defined in 

40 CFR 258.2, and the definition of “contained gaseous material” into the CISWI 

Reconsideration Rule, and insert the definition of “contained gaseous material” in the NHSM 

Rule Amendments in 40 CFR part 241.2. The inclusion of these important definitions in both 

 

3

 It is our understanding that the Agency used the original CISWI rule text, promulgated in 2000, as the base text 

for the CISWI Reconsideration Rule. However, EPA’s Delay Notice was vacated by the District Court, rendering the 

March, 2011 CISWI rule currently effective. 
6 

rulemakings will enhance transparency and clarity for the regulated community, and further the 

Agency’s goal of developing clear, readable and comprehensible rules. 

EPA Should Clarify the Provisions of CISWI that Reference Municipal Solid Waste 

Combustion

WM requests that EPA clarify the extent to which CISWI may apply to municipal solid waste 

combustion units. In this context, WM notes that both the final rule and the Reconsideration 

proposal include changes that are confusing and potentially inconsistent with respect to CISWI 

applicability for municipal waste combustors. 

By way of background, EPA has promulgated a series of regulations under Section 129 of the 

Clean Air Act, 42 U.S.C. §7429 (“CAA Section 129”) that would seem to cover the universe of 

sources that may be regulated as municipal waste combustion units. See, for example, 40 CFR 

Part 60 Subpart Ea, Standards of Performance for Municipal Waste Combustors for Which 

Construction is Commenced After December 20, 1989 and on or before September 20, 1994; 40 

CFR part 60 Subpart Eb, Standards of Performance for Large Municipal Waste Combustors for 

Which Construction is Commenced After September 20, 1994 or for Which Modification or 

Reconstruction is Commenced After June 19, 1996; 40 CFR Part 60, Subpart AAAA Standards of 

Performance for Small Municipal Waste Combustion Units for Which Construction is 

Commenced After August 30, 1999 or for Which Modification or Reconstruction is Commenced 

After June 6, 2001; and 40 CFR Part 60, Subpart EEEE Standards of Performance for Other Solid 

Waste Incineration Units for Which Construction is Commenced After December 9, 2004, or for 

Which Modification or Reconstruction is Commenced on or After June 16, 2006 (“OSWI”).4 

Under the current regulations identified above, large, small and very small municipal waste 

combustors would be regulated under CAA Section 129 standards. Note, however, that all of 

the above standards, including OSWI, exempt units that are subject to a federally enforceable 

limitation restricting the combustion of municipal solid waste to less than 30% of the total fuel 

input by weight, consistent with the language in CAA Section 129(g)(5). See e.g. 40 CFR 

§60.2887(b). 

As originally promulgated,5 CISWI contained a provision in 40 CFR §60.2020(c) that exempted 

municipal waste combustion units that were either (1) regulated under existing municipal 

waste combustor standards (at that time, Subparts Ea, Eb, and AAAA and their Emission 

Guidelines counterparts), or (2) that combust greater than 30% municipal solid waste or refusederived fuel, and had the capacity to burn less than 35 tons per day of municipal solid waste. 

Subsequently, EPA promulgated the OSWI standards, which regulated very small municipal 

waste combustion units (those with the capacity to combust less than 35 tons per day of 

municipal solid waste or refuse-derived fuel). In the currently effective CISWI rule, 

 

4

 Note that EPA has also promulgated Emission Guidelines for certain categories of municipal waste combustors at 

40 CFR Part 60, Subparts Cb, BBBB and FFFF. 

5

 CISWI was originally promulgated on December 1, 2000 at 65 Fed. Reg. 75350.
7 

promulgated on March 21, 2011 (76 Fed. Reg. 15704), section 60.2020(c) was revised to 

remove the second part of the exemption that previously applied to municipal waste 

combustion units combusting greater than 30% municipal solid waste and with the capacity to 

combust less than 35 tons per day of municipal solid waste (which are now regulated under 

OSWI). The removal of this provision created some confusion within CISWI with respect to the 

scope of CISWI relative to other CAA Section 129 standards governing municipal solid waste 

combustion, because section 60.2020(c) does not reference OSWI, and it does not expressly 

maintain the 30% municipal solid waste exemption. 

In the CISWI Reconsideration Rule proposal, EPA identifies the proposed addition of the 

definition of “municipal solid waste” to the CISWI rule definition as a “technical correction” that 

would “further clarify applicability for MWC owners who question whether CISWI or MWC rules 

are applicable to their solid waste combustion unit.” 76 Fed. Reg. at 80465. As an initial 

matter, the Reconsideration proposal rule text does not include a definition of “municipal solid 

waste” and therefore the proposed technical correction creates an ambiguity within the rule 

and does not provide an opportunity for review of the proposed revision. Further, addition of 

the “municipal solid waste” definition, without additional clarification relating to the scope of 

CISWI relative to other CAA Section 129 standards, does not provide clarity to the regulated 

community. Specifically, EPA should clarify that CISWI does not apply to any municipal solid 

waste combustion unit that is regulated under any of the municipal waste combustor 

standards, including OSWI. Further, EPA should clarify that CISWI does not apply to any 

combustion unit that is otherwise exempt from the municipal waste combustion standards 

because it is subject to a federally enforceable permit condition limiting the combustion of 

municipal solid waste to less than 30% of the total fuel input by weight. WM suggests that 

EPA clarify these concepts through the following revision to 40 CFR §60.2020: 

(c) Municipal Solid Waste Combustion Units. The following municipal solid waste 

combustion units are exempt from this subpart: 

(1) Combustion units that are subject to subpart Ea of this part (Standards of 

Performance for Municipal Waste Combustors); subpart Eb of this part 

(Standards of Performance for Large Municipal Waste Combustors); subpart Cb 

of this part (Emission Guidelines and Compliances Time for Large Municipal 

Waste Combustors); subpart AAAA of this part (Standards of Performance for 

Small Municipal Waste Combustion Units); subpart BBBB of this part (Emission 

Guidelines for Small Municipal Waste Combustion Units); subpart EEEE of this 

part (Standards of Performance for Other Solid Waste Incineration Units); or 

subpart FFFF of this part (Emission Guidelines and Compliance Times for Other 

Solid Waste Incineration Units). 

(2) Any combustion unit that is exempt from the standards identified in paragraph 

(c)(1) above on the basis that it is subject to a federally enforceable permit 

condition limiting the combustion of municipal solid waste to 30% of the total 

fuel input by weight. 
8 

In addition to the above-referenced revision to 40 CFR §60.2020, WM suggests that EPA revise 

the definition of “commercial and industrial solid waste incineration unit” to include the 

following clarifications: “The definition of CISWI unit does not include municipal solid waste 

combustion units identified within 40 CFR §60.2020(c), and does not include internal combustion 

engines, gas turbines or other combustion devices that combust landfill gases collected by 

landfill gas collection systems.” WM believes these changes will further clarify the scope of 

CISWI relative to the CAA Section 129 municipal solid waste combustion standards. 

Additionally, the clarification with respect to landfill gas fired combustion units is consistent 

with existing CAA Section 129 municipal waste combustion unit standards, and will 

appropriately reflect EPA’s long-standing interpretation with respect to the regulation of landfill 

gas as an uncontained gaseous material rather than as a solid waste. 

EPA Should Amend its Definition of CISWI Unit and its Application of CISWI 

Requirements to Units that Cease Burning Solid Waste 

The CISWI Reconsideration Rule preamble at (76 FR 80459) states – “For sources that cease 

burning solid waste, the effective date for the waste-to-fuel switch is a date that is at least 6 

months after the last date on which solid waste is added to the combustion unit.” The effect of 

this provision is to require a combustion unit to comply with CISWI for six months after the 

conditions triggering CISWI applicability cease to exist. We believe this is an inappropriate 

application of Section 129 requirements to units that have ceased to meet the fundamental 

premise for the CAA’s regulation of solid waste-burning units – that they are actually burning 

solid waste. We have not seen such a requirement in other Section 129 standards for MSW or 

hazardous waste incinerators. The Agency is provided ample advance notice of the fuel switch 

with the requirement that a source must submit an advanced notification of the date of the 

waste-to-fuel switch. Further, sources anticipating a fuel switch must remain in continuous 

compliance with CISWI until the effective date of the switch from waste-to fuel. Both of these 

provisions provide abundant safeguards that units burning solid waste will be subject to 

protective environmental requirements designed for such units. Given the stringent 

requirements of the CISWI Reconsideration Rule, units are highly unlikely to engage in frequent 

fuel-switching without first obtaining a comfort letter or other Agency determination that the 

material they intend to burn is considered a legitimate fuel. 

We respectfully recommend that the Agency strike the clause “or has combusted in the 

preceding 6 months” from the CISWI definition in parts 60.2265 and 60.2875. We further 

recommend that at part 60.2710 (a)(2) the Agency strike “you are subject to the requirements 

of this subpart at least 6 months following the last date of solid waste combustion.” 
9 

EPA should establish a separate a SO2 limit for an Energy Recovery Unit (ERU) 

subcategory that combusts biomass and tires.

WM through its wholly owned subsidiary, Wheelabrator Technologies Inc. (WTI), is a member 

of the Energy Recovery Council (ERC) and participated in the development of the ERC 

comments to the CISWI Reconsideration and NHSM Amendment Rules. WM endorses ERC’s 

comments and incorporates them by reference. 

In response to EPA’s March 21, 2011 notice of reconsideration of CISWI, WTI submitted 

additional information for EPA’s consideration in revising the final CISWI rules. This information 

focused on the need to establish an alternative SO2 limit for a subcategory of solid fuel ERUs 

that combust tires or Tire Derived Fuel (TDF) in combination with both NHSM and solid waste 

derived biomass fuels. This information was submitted via email on July 8, 2011 to Brian 

Shrager and Toni Jones (See Attachment A) and is summarized below. 

WTI operates the Wheelabrator Ridge Energy Facility (WREF) in Polk County Florida. The facility 

began operation in 1994 and consists of a 630 MMBtu/hr multi-fuel stoker fired boiler 

providing steam to a 50 MW generator for sale of electricity to the local utility. The boiler is 

fueled by a mixture of municipal solid waste including yard waste and tires, non-municipal 

biomass including clean cellulosic biomass (agricultural waste and forest debris), biomassderived solid waste, and landfill gas. The facility typically combusts between 30,000-40,000 

tons of tires annually. Tires are received whole and chipped on site (belts are not removed) or 

as direct deliveries of chipped tires. Tires may or may not be derived from tire collection 

programs. Chipped tires are fired simultaneously with the biomass fuels to ensure optimum 

combustion and boiler heat input. Tire combustion is limited by the air permit to 18,505 lbs/hr 

or approximately 40% of total boiler heat input. 

The boiler is equipped with selective non-catalytic reduction (SNCR) for NOx control, a lime 

slurry spray dryer absorber (SDA) for SO2 or acid gas control and a fabric filter. The SDA was 

designed for the control of SO2 associated with combustion of tires. WTI conducted a 

variability analysis of the SO2 hourly data to determine an achievable SO2 emission limit for cocombustion of tires and biomass fuels. The findings are summarized below. 

WTI compiled hourly average CEM SO2 outlet data in ppm @7%O2 for the period of January 1, 

2011 to June 6, 2011. Three different types of averages were used for variability analysis—30-

day rolling averages, 24-hour block averages, and 3-hour rolling averages. The averaging times 

were based on the on the following: 1) use of 30 day rolling average SO2 CEM compliance 

option in CSIWI rule, 2) 24 hour block average consistent with MACT CEM based limit for MWCs 

and 3) 3- hour rolling average provides variability associated with running 3-1 hour stack tests 

to demonstrate compliance. The 99% upper confidence limit (UL) was calculated for three 

different averages in accordance with the following equation: 

= 	x ̄	 + 	 ∗ 	(0.99,  − 1)
10 

Results of the averaging time variability analyses and 99% UL are summarized in the table 

below: 

Wheelabrator Ridge SO2 Variability Analysis 

January 1 to June 6, 2011 

Parameter 30-Day 

Rolling 

Average

24-

Hour 

Block 

Average

3-Hour 

Rolling 

Average

2011 

CISWI 

Limit 

Count 106 135 3252 

Mean 45.6 45.5 45.6 

Median 45.7 46.4 46.5 

Std. Dev. 0.8 7.1 31.0 

Minimum 44.0 13.4 0.0 

Maximum 47.1 67.5 179.2 

99% tvalue 2.362 2.355 2.328 

99% UL 48 62 118 6.2 

* All concentrations are in units of 

ppmd@7%O2 

Despite being equipped with a high efficiency SDA the variability analysis demonstrates the 

revised solid fuel ERU SO2 limit of 7.3 ppm 7% O2 is not achievable even using the alternative 

30 day average provided in the revised rule. An achievable SO2 limit for the subcategory of 

solid Fuel ERUs combusting tires and biomass derived fuel based on the 99% UL would be 48 

ppm 7% O2 using the 30 day rolling average alternative. This proposed revised limit is an 

order of magnitude below 650 ppm limit allowed for coal fired solid fuel ERUs. The facility 

meets or exceeds all other limits for solid fuel fired ERUs. We believe incorporating a separate 

SO2 limit for a solid fuel subcategory for ERUs co- combusting tires and biomass derive fuels is 

consistent with EPA’s intent for granting reconsideration of the sub-categorization approach. 

EPA Should Correct the CISWI Data Base for Energy Recovery Units 

WTI noted that EPA had made adjustments to the CISWI ERUs population based on 

supplemental data submitted by the Biomass Power Association. This data set identified 

Wheelabrator Shasta Energy Company as a possible CISWI facility based on the plant’s past 

combustion of small amounts of creosote treated wood. As result of this outdated information, 

EPA moved the Wheelabrator Shasta Energy units from the Boiler MACT to CISWI unit 

population. We respectfully request that EPA remedy this error. The Wheelabrator Shasta 

Energy facility no longer combusts any non hazardous secondary materials (NHSM) that may 
11 

now be considered solid waste under NHSM rule and has not done so for the past two years. 

This facility will continue to combust non waste materials and therefore will not be subject to 

final CISWI rules. 

The Affirmative Defense Provisions for Malfunctions are Unnecessarily 

Burdensome 

Although EPA acknowledges that malfunctions occur in well operated and maintained facilities 

equipped with the best technologies, EPA’s affirmative defense concept essentially presumes 

that malfunctions never occur. Under the rule as written, any emissions occurring above the 

limits set using emission data obtained exclusively during normal operation (emphasis added) 

are considered deviations, regardless of the underlying root cause of the emissions. The reality 

is that malfunctions infrequently occur even on the best designed, maintained and operated 

units. Therefore, a facility should not be presumed guilty of having a deviation in the first place 

if it has experienced a legitimate malfunction. 

EPA admits it does not have emissions data for startup and shutdown periods sufficient to 

establish numeric emission limits, and due to this dearth of data has sensibly adopted a work 

practice standard for these periods. Malfunction periods are no different and should be 

treated similarly. Since EPA also lacks emissions data for malfunction periods, and would find it 

difficult to obtain sufficient emission data for all the varying types of malfunction-related 

events, EPA should adopt work practice standards for malfunction periods. 

Malfunction work practice standards could include limitations on the duration to ensure quick 

and effective corrective action is taken, and if the malfunction cannot be quickly resolved the 

unit would be shut down for repair. Facilities should still be required to submit a notification of 

a malfunction excess emission event with the underlying root cause analysis. If EPA or the 

administering agency decides the excess emission event was not a malfunction, it would then 

be reported as a deviation of the limit and enforcement action, including imposition of 

penalties, would still apply consistent with the deviation definition in 63.7575. EPA could also 

choose to take enforcement action should a facility report “excessive” malfunction events. 

Finally, the sheer number of eligibility criteria that must be proven by a “preponderance of 

evidence and the vague terms such as “unpreventable,” “could not have been foreseen,” and 

“all possible steps were taken” all but guarantees that no malfunction event will ever meet the 

criteria. WM suggests modifying the affirmative defense eligibility criteria in 40 CFR § 

60.2685(a) as follows to make it more reasonable and eliminate such vague language: 

“To establish that an exceedance of an emission limit or operating standard was the 

result of a malfunction and therefore not a deviation you must timely meet the 

notification requirements in paragraph (b) of this section and demonstrate that: (1) the 

malfunction: (i) Was caused by a sudden infrequent and unavoidable failure of air 

pollution control equipment or a process to operate in a normal or usual manner (ii) was 
12 

not caused by operator error or careless operation (iii) was not the result of inadequate 

design, maintenance or operating procedures; and (2) corrective actions were taken 

immediately to minimize the duration and amount of excess emissions; and (3) all 

emission monitoring and control systems were kept in operation if possible in a manner 

consistent with safety requirements and good air pollution control practices; and (4) 

preventive measure were implemented to address the root cause of the malfunction; 

and (5) the root cause analysis and actions in response to the excess emission event 

were documented in signed contemporaneous log. (b)...” 

We also believe the notification requirements should be streamlined. The initial 2-day 

notification should include telephone, facsimile or e-mail. Facsimiles are all but nonexistent in 

this day and email notifications are simple and direct, and can be tracked easily and archived 

for recordkeeping purposes. WM recommends that the initial 2-day notification should include 

a brief summary of the nature of the malfunction, corrective action taken and root cause 

analysis. Often the initial notification will include enough information for the regulators to 

confirm a malfunction meets the criteria. For example, a lightning strike on a utility 

interconnect transformer that causes a temporary facility power outage would be easily 

discernible as a malfunction. If the agency needed more information, a request could sent to 

the facility to provide a full report in 45 days or to include a full report in the next semiannual 

compliance report. Such streamlined requirements for malfunction events would be consistent 

with several states’ requirements and would ensure ample regulatory oversight. 

EPA Should Revise the CO Monitoring Requirements to Reflect Differing 

Combustion Technologies 

Through the CISWI rulemaking process, EPA has considered whether emission standards must 

apply at all times, including during periods of startup, shutdown and malfunction (SSM). The 

Agency’s evaluation stems from a 2008 court decision (Sierra Club v. EPA, 551 F.3d 1019(DC Cir. 

2008)) related to SSM exemptions contained in the General Provisions under 40 CFR Part 63. 

EPA has acknowledged that the Court’s decision did not specifically address category-specific 

SSM provisions including those established under CAA Section 129. We therefore believe that 

EPA is over-stepping its authority by voiding longstanding category-specific and Section 129 

SSM provisions. 

Nonetheless, in the absence of separate startup/shutdown specific limits, we do support EPA’s 

provisions within the CISWI Reconsideration Rule to eliminate the O2 correction bias during 

startup and shutdown periods when high levels of excess air are encountered. We are 

concerned, however, that eliminating the O2 correction for only a four-hour startup and a onehour shutdown period (derived from a single coal fired unit) is not sufficient for all the CISWI 

unit types and technologies. Further, elimination of the O2 correction should be applied to all 

CEM based emission limits during startup and shutdown periods. 
13 

As an alternative to hourly limits for startup/shutdown periods EPA could incorporate the 

startup/shutdown definitions in the related proposed Boiler MACT Reconsideration rule to 

define the period when the O2 correction is not applied to hourly CO averages. Applying the 

Boiler MACT startup/shutdown definitions would be a reasonable approach since many CISWI 

and boiler MACT units share the same technology. In the proposed Boiler MACT revisions 

startup “means the period between the state of no combustion in the unit to the period where 

the unit first achieves 25% load (i.e. cold start).” Shutdown means: “period that begins when 

unit last operates at 25% load and ending with no fuel combustion in unit.” We believe 25% 

load should be a nominal requirement that may be adjusted to accommodate plant specific 

technology differences. For example, gaseous and liquid fuel burners have lower percent 

thresholds than solid stoker boilers or fluidized bed combustors. Additionally, the term “load” 

should be defined as “maximum design load” to eliminate any ambiguity in the meaning. 

Without conducting a comprehensive data analysis on startup/shutdown periods for all 

different CISWI combustor/boiler technologies, EPA should not force all CISWI units into a one 

size fits all startup/shutdown time period. EPA should instead gather the data necessary to 

develop technology or category appropriate startup/shutdown periods. EPA might also modify 

the startup/shutdown definitions to allow sources and State regulators to specify the numerical 

percent values in their State 129/111d Plans appropriate for the technology used by the 

permitted source. Alternatively, EPA could define an appropriate percent load for each 

combustion technology. 

As provided in the startup provisions of the large municipal waste combustion rule, we 

recommend that startup should not include the period when only natural gas or No.2 fuel oil 

“auxiliary” fuels are being fired to safely warm the furnace and boiler in advance of solid waste 

fuel combustion. Importantly, the use of auxiliary burners during these periods to maintain 

furnace temperature minimizes emissions from incomplete combustion of solid waste. 

Facilities should not be penalized or otherwise discouraged from using auxiliary burners that 

actually minimize or prevent emissions. Auxiliary fuels are combusted using small independent, 

auxiliary fuel burners that are separate from the solid waste fuel combustion control system. 

WTI Supports the Agency’s CO CEM Option for Demonstrating Compliance 

We support the proposal to allow facilities to use CO CEMs for demonstrating compliance with 

the CO limit using a 30 day average. Many potential CISWI units are required to operate CO 

CEMS in accordance with Title V and/or state requirements. 

WTI Supports EPA Revisions to the Continuous Monitoring Provision for Large 

ERUs 

WTI supports EPA’s decision to eliminate the mandatory use of particulate matter CEMS (PM 

CEMs) for continuous particulate monitoring. EPA has acknowledged that the PM CEM 
14 

technology is not sufficient to accurately monitor PM concentrations in the ranges emitted by 

large ERUs. EPA’s decision is consistent with Section 129(c), which requires that monitoring and 

test methods be validated on solid waste incinerators. For these reasons we also do not believe 

EPA can require the installation and certification of continuous parameter monitoring systems 

(PM CPMS) on large ERUs. A PM CPMS is for all practical purposes a PM CEMs. Importantly PM 

CPMS have not been validated on solid waste incineration units as required by CAA 129 (c). PM 

CPMS requires the use of light scatter, light scintillation or beta attenuation measurement 

techniques- the same measurement techniques used by PM CEMs. Thus, there is no basis to 

believe that a “PM CPMS” will achieve greater measurement accuracy. Further we are not 

aware of any PM CPMS performance specification that would allow a CISWI to verify the 

accuracy or representativeness of measured data for purposes of certification. We believe that 

the latest continuous opacity monitoring system (COMS) technology combined with other 

parameter monitoring (e.g., ESP power levels, baghouse leak detectors) are sufficient to 

maintain peak efficiency of particulate control devices and to assure that the PM limit is being 

continuously achieved. 

WM Supports the Proposed NHSM Categorical Non-Waste Determination 

Process 

Proposed §241.4(b) provides a new rulemaking petition process for the Administrator to 

identify additional non-waste fuels under §241.4(a). Combustion units using listed non-waste 

fuels do not need to obtain site-specific non-waste determinations from their Regional 

Administrators or other NHSM requirements for demonstrating legitimacy, including 

recordkeeping requirements to document sufficient processing and conformance to the 

legitimacy criteria. WM commends EPA for developing the process, and for recognizing therein 

that it is appropriate to balance the legitimacy factors with other relevant factors when making 

a non-waste determination. EPA’s legitimacy analysis should focus on the heating value of the 

fuel product, whether material management and processing is conducted in a safe and 

protective manner, and whether the material’s use as a fuel will extract value from the material 

and reduce landfill disposal. In particular, extremely rigid adherence to contaminant 

comparisons, without consideration of other relevant factors, may unfairly eliminate otherwise 

viable and environmentally beneficial fuels. WM recommends that the Agency also clarify that 

the Regional Administrators should balance the legitimacy criteria with other relevant factors in 

considering petitions submitted pursuant to 40 CFR §241.3(c). 

EPA Should Add Clean C&D Wood to the List of Non-Waste Fuels Under 

§241.4(a) 

EPA has recognized in the initial NHSM Rule and in the NHSM Rule Amendment that scrap tires 

are not wastes and are not discarded when managed in tire collection programs. The Agency 

has also recognized that contractual arrangements can ensure that scrap tires are not discarded 

and are handled as valuable commodities through arrival at the combustion facility. So too 
15 

should clean construction and demolition (C&D) wood qualify and be listed as a non-waste fuel 

under §241.4(a). Many local governments as part of their recycling and landfill diversion 

initiatives operate programs or otherwise encourage collection and recycling of clean C&D 

wood. One such use is conversion to fuel. Purchasers of the clean wood fuel provide fuel 

specifications as part of their contracts with C&D recycling facilities. WM recommends that 

EPA list as non-waste fuel, clean C&D wood that has been processed to remove treated and 

painted wood and processed to meet contractual fuel specifications.

EPA has received and evaluated considerable information describing the processing and typical 

fuel specifications required by wood combustors as evidenced by its extensive preamble 

description and its Materials Characterization Paper In Support of the Proposed Rulemaking – 

Identification of Nonhazardous Secondary Materials That Are Solid Waste: Construction and 

Demolition Materials – Building-Related C&D Materials contained in the rulemaking docket. EPA 

has also evaluated analytical data on the comparable contaminant levels found in clean C&D 

wood versus the solid fossil fuels that it would replace. EPA’s preamble to the proposed NHSM 

Rule Amendments described the typical clean C&D wood processing operations and the 

likelihood that the fuel product meets the rule requirements to be deemed a non-waste fuel. 

(at 76 Fed. Reg. 80470) 

Additionally, construction and demolition wood that has been processed (e.g., sorted) 

to remove contaminants (such as lead-painted wood, treated wood containing 

contaminants such as arsenic and chromium, metals and other non-wood materials), 

and is size-reduced prior to burning likely meets the processing and legitimacy 

criterion for contaminants, and thus can be combusted as a non-waste 

fuel.[emphasis added]

We believe that EPA has demonstrated in its rulemaking record that the Agency has sufficient 

information to determine the legitimacy of clean C&D wood as a non-waste fuel. We 

respectfully urge the Agency to list clean C&D wood as a non-waste fuel under §241.4(a) when 

it finalizes its NHSM Rule Amendments 

The CISWI Reconsideration Rule recordkeeping and CISWI unit definition create considerable 

compliance risks for combustion sources burning non-hazardous secondary materials as fuels 

without sufficient comfort that EPA considers the materials to be legitimate fuel. The definition 

of CISWI unit (76 Fed. Reg. 80501) under §60.2265 states that “if the unit burns materials other 

than traditional fuels as defined in §241.2 that have been discarded, and you do not keep and 

produce records as required by §60.2175(v), the material is a solid waste and the operating unit 

a CISWI unit.” The record keeping requirements require records of how the secondary material 

meets each of the legitimacy criteria, how the operations that produced the fuel satisfy the 

definition of processing, and if the fuel received a non-waste determination, how the fuel met 

the requirements of the petition process. Under these provisions as written, a source could 

lose its status as a fuel-fired boiler, if it fails to maintain adequate records. WM believes that 

this recordkeeping requirement is therefore unduly burdensome, and is inconsistent with EPA’s 
16 

enforcement authority and practices established under the CAA. As an initial matter, a 

combustion unit that does not burn solid waste cannot be categorized as a CISWI unit and 

should not be subject to its provisions, recordkeeping or otherwise. Further these provisions 

would create a presumption of CISWI applicability as an automatic result of a recordkeeping 

violation. Such a result is inconsistent with EPA’s established enforcement response policies 

that would otherwise provide a framework for addressing such recordkeeping violations. 

Automatic CISWI applicability is not an appropriate result for such a violation. 

EPA Should Clarify that Comfort Letters Issued by the Agency Meet the 

Documentation Requirements of the CISWI Rule at §60.2175(v) and Boiler MACT 

Rule at §63.7555(d)(2) 

EPA has issued a number of “comfort letters,” which it has posted on the official NHSM 

Rulemaking web site. These letters have been carefully crafted to discuss how various 

secondary materials meet the processing definition and legitimacy criteria of the NHSM Rule. 

However, the preamble and rule language in the NHSM Final Rule and the proposed NHSM Rule 

Amendments do not discuss whether a combustion source may rely on the comfort letters to 

meet its recordkeeping requirements. We respectfully urge the Agency to address this issue in 

its final NHSM Rule Amendments and on its rulemaking web site. EPA should clarify that 

combustion sources burning a secondary material fuel that meets the processing and legitimacy 

criteria circumstances as described in an EPA “comfort letter” may use the letter to meet the 

recordkeeping requirements of §60.2175(v) and §63.7555(d)(2). Further, EPA should clarify 

that no additional petitions for a non-waste determination from either the Regional 

Administrator or Administrator are necessary where the secondary material fuel meets the 

circumstances described in the comfort letter. Failure to adequately clarify the status and use 

of comfort letters to demonstrate fuel legitimacy determinations will create enormous 

disincentives to recovering energy value from materials which otherwise would be landfilled. 

EPA Should Clarify that Secondary Material Fuels May be Processed from 

Municipal Solid Waste 

The NHSM Rule is clear on its face that secondary materials that have been discarded may be 

processed into legitimate non-hazardous secondary material fuels. See 40 CFR §241.3(b)(4). 

Because the definition of “secondary materials” is broad in scope, the NHSM Rule provides an 

opportunity for meaningful and innovative materials recovery and management. However, the 

rulemaking record indicates that the Agency has responded to questions and comments 

expressing concerns that the NHSM Rule would allow for the combustion of “solid waste” in 

contravention of CAA Section 129. In responding to comments about the application of the 

NHSM Rule to municipal solid waste streams, EPA has looked to the language of CAA Section 

129 to underpin its responses. EPA has stated that Section 129 of the CAA does not define 

“solid waste,” but instead provides under 129(g)(6) that the definition and scope of “solid 
17 

waste” will be established by the Administrator under RCRA. EPA has clearly promulgated the 

NHSM Rule precisely for the purpose of defining solid waste, and for providing a rigorous 

framework under which solid wastes may be sufficiently processed, managed as valuable 

commodities, and have comparable contaminant levels to those of traditional fuels, to be 

considered legitimate non-waste fuels. EPA has not applied the framework differently to 

various components of the solid waste stream. The Agency has established a framework in 

which the Agency maintains strict control and oversight over the use of secondary materials as 

fuels so that it may prevent sham recycling or combustion for the sake of disposal. 

As companies continue to work to recover value from spent materials that would otherwise be 

disposed, they will focus on all aspects of the solid waste stream as sources of valuable 

feedstock. These material streams will likely include components of the post-consumer 

municipal solid waste stream that are difficult to recycle, as well as pre-consumer industrial, 

commercial and other sorted waste materials. As part of its mission to support materials 

management and sustainability efforts of the public and private sectors, EPA should clarify that 

municipal solid waste, like any other solid waste fuel feedstock, is eligible for evaluation under 

the NHSM Rule legitimacy framework. WM has appended a legal analysis at Attachment B to 

assist in this effort. 

Waste Management appreciates the opportunity to share this additional information with the 

Agency, and looks forward to working with you as you reconsider and revise the CISWI 

Reconsideration Rule and the NHSM Rule Amendments. If you have any questions with our 

comments or with the attached materials, please feel free to contact me at (202) 639-1218 or 

by email at kkelly5@wm.com

Sincerely, 

Kerry Kelly, Director 

Federal Public Affairs 

 
18 

Attachment A 
19 
20 

 
21 

Attachment B 

Background and Regulatory Analysis

The following analysis demonstrates that the language of Section 129 does not prohibit a 

determination under the NHSM Rule that a fuel product processed from municipal solid waste is 

a legitimate fuel, rather than a solid waste. 

1. Section 129 requires EPA to set standards for categories of solid waste combustion. 

Section 129 applies generally to EPA’s authority to regulate “solid waste incineration 

units” and defines such units broadly in Section 129(g)(1) to include (in pertinent part) “a 

distinct operating unit of any facility which combusts any solid waste material from 

commercial or industrial establishments or the general public (including single and 

multiple residences, hotels and motels).”6 42 U.S.C. § 7429(g)(1). The broad definition 

of “solid waste incineration unit” in Section 129(g)(1) encompasses different types and 

sources of solid waste, but is clear that only a unit that combusts “solid waste” would be 

covered by Section 129 standards. 

2. Section 129(a) identifies specific categories of solid waste combustion for which EPA is 

required to establish standards, including municipal waste, hospital waste, medical waste, 

commercial and industrial waste, and other categories of solid waste incineration units. 

By the very structure and purpose of Section 129, these categories of combustion units 

would only be subject to Section 129 standards if they are first determined to combust 

“solid waste” and as such meet the definition of “solid waste incineration unit.” See 

Davis County Solid Waste Management v. EPA, 101 F.3d 1395, 1398-99 (D.C. Cir. 

1996) (explaining that Section 129 “directs the EPA to establish emission standards for 

solid waste incineration units” and that Section 129 further defines several “categories of 

solid waste incineration units,” including municipal waste combustors) (emphasis added). 

See also Northeast Maryland Waste Disposal Authority v. EPA, 358 F.3d 936, 939-40 

(D.C. Cir. 2004) (per curiam) (same). 

3. The inclusion of the definition of “municipal waste” in section 129(g)(5) does not alter 

the overall construct of Section 129. Instead, it merely defines one category of “solid 

waste” that is covered pursuant to Section 129 (and establishes an exemption from 

Section 129 standards for units combusting a fuel feed stream composed of less than 30% 

municipal waste in the aggregate). See Davis County, 101 F.3d at 1398 n. 4 (explaining 

that, although Section 129 refers to “‘municipal waste’ as opposed to MSW [municipal 

solid waste] . . . it is apparent from the fact that Section 129 addresses solid waste 

 

6

 The definition of “solid waste incineration unit” includes four express exemptions which are not relevant for this

purpose: (1) units requiring a permit under 42 U.S.C. §6925; (2) material recovery facilities which combust waste 

for the primary purpose of recovering metals; (3) small power production facilities or cogeneration facilities that

combust homogenous waste for the production of electric energy or steam; and (4) qualifying air curtain incinerators 

that burn only wood wastes, yard wastes and clean lumber. 
22 

incineration units that the type of municipal waste at issue is MSW”). Likewise, EPA’s 

promulgated regulations governing municipal waste combustion refer to and define 

“municipal solid waste” as a type of solid waste. See, e.g., 40 CFR § Part 60, Subpart 

Eb, defining “municipal solid waste or municipal-type solid waste” at 40 CFR §60.51b. 

See also USEPA, RCRA Orientation Manual 2011, at II-2 (“Municipal solid waste is a 

subset of solid waste.”) 

4. Notwithstanding the CAA’s identification within Section 129 of the types of solid waste 

incineration units for which EPA is required to establish standards, including units that 

combust municipal waste, Section 129 does not define “solid waste.” Instead, Section 

129(g)(6) provides that the term “solid waste” shall have the meaning established by the 

Administrator under the Solid Waste Disposal Act (now consolidated under the Resource 

Conservation and Recovery Act (“RCRA”) at 42 U.S.C. §6901 et seq.). 

5. EPA’s NHSM Rule was promulgated precisely for the purpose of defining “solid waste” 

so that combustion units may be properly classified as being regulated either under CAA 

section 112 categorical standards for fuel burning units, or under CAA Section 129 

standards for “solid waste incineration units.” The rulemaking was prompted by the 

decision of the D.C. Circuit in NRDC v. EPA, 489 F.3d 1250 (D.C. Cir. 2007), in which 

the Court vacated certain definitions contained in EPA’s standards for Commercial and 

Industrial Solid Waste Incineration Units (“CISWI),7 because such definitions allowed 

the combustion of solid waste for energy recovery to be regulated pursuant to Section 112 

of the CAA, rather than Section 129. 

6. In an excerpt from the NHSM Rule preamble, EPA states the following: 

In responding to the Court’s vacatur and remand of the CISWI Definitions 

Rule and the Boiler MACT Rule, EPA is establishing, under RCRA, which 

non-hazardous secondary materials are “solid waste.” This is necessary 

because, under the Court’s decision, any unit combusting any “solid 

waste” at all must be regulated as a “solid waste incineration unit,” 

regardless of the function of the combustion device. If a non-hazardous 

secondary material (also referred to as a “secondary material” in this 

rulemaking) is not a” solid waste” under RCRA, then a unit combusting 

that material must be regulated pursuant to CAA section 112 if it is a 

source of HAP. Alternatively, if such secondary material is classified as a 

“solid waste” under RCRA, then a unit combusting the material must be 

regulated under CAA section 129, unless it is within the scope of one of 

the exclusions from the definition of “solid waste incineration unit” in 

section 129(g)(1) of the CAA. 

 

7

 Standards of Performance for New Stationary Sources and Emission Guidelines for Existing Sources: Commercial 

and Industrial Solid Waste Incineration Units, 70 Fed.Reg. 55,568 (Sept. 22, 2005) (CISWI Definitions Rule), 

amending Standards of Performance for New Stationary Sources and Emissions Guidelines for Existing Sources: 

Commercial and Industrial Solid Waste Incineration Units, 65 Fed.Reg. 75,338 (Dec. 1, 2000) 
23 

76 Fed. Reg. at 15462. 

7. In discussing the history of the definition of “solid waste” under RCRA, EPA notes in the 

NHSM Rule preamble that “EPA has not promulgated detailed regulations defining solid 

waste for purposes of the subtitle D (non-hazardous) programs.” 76 Fed. Reg. at 15462. 

Further, EPA states that the express purpose of the NHSM rulemaking is to determine the 

“procedures for identifying non-hazardous secondary materials that are solid waste under 

RCRA subtitle D so that we can establish appropriate emission standards under CAA 

sections 112 and 129.” Id. Finally, EPA makes it abundantly clear that its definition of 

“solid waste” through the NHSM Rule is fundamental and primary to the application of 

CAA Section 129 standards, and cannot be “trumped” by any language in Section 129. 

In responding to a commenter’s concern that the NHSM Rule would allow the 

combustion of solid waste in contravention of Section 129, including with respect to 

NHSM derived from refuse, EPA states the following: 

EPA is establishing a definition of non-hazardous solid waste, which, as specified 

by CAA section 129(g)(6), governs the meaning of “solid waste” under section 

129. Because Congress specifically directed that “solid waste” have the meaning 

established by the Administrator under RCRA, instead of defining the term under 

RCRA, the CAA definition of “municipal waste” is not relevant to this action. 

If any or all of the commenter’s contentions are correct, section 129 would not 

provide that the term “solid waste” shall have the meaning promulgated by EPA 

under RCRA. There would simply be no reason for EPA to consider the RCRA 

definition, since section 129 would take care of the issue. Section 129(g)(6) would 

be meaningless. 

NHSM Rule, Response to Comment [3a-A1-5]. Further, in responding specifically to 

concerns surrounding Refuse Derived Fuel (“RDF”)8 identified in CAA Section 129, EPA 

states the following: 

The comment is incorrect that section 129, by excluding “refuse-derived fuel” 

from the exclusion in 129(g)(1)(B) was somehow defining the term as being 

included in the term, “solid waste,” under RCRA. Again, if that were the case, 

section 129(g)(6) would be superfluous. Nevertheless, today’s rule identifying 

which non-hazardous secondary materials that are solid wastes when combusted 

 

8

 RDF is identified in Section 129 as a type of municipal waste, and its combustion is regulated under municipal 

waste combustor standards promulgated under Section 129. See e.g. 40 CFR Part 60, Subpart AAAA, Standards of 

Performance for Small Municipal Waste Combustion Units for Which Construction is commenced After August 30, 

1999 or for Which Modification or Reconstruction is Commenced After June 6, 2001. RDF is specifically defined 

under such standards as follows: Refuse-derived fuel means a type of municipal solid waste produced by processing 

municipal solid waste through shredding and size classification. That includes all classes of refuse-derived fuel 

including two fuels: (1) Low density fluff refuse-derived fuel through densified refuse-derived fuel. (2) Pelletized 

refuse-derived fuel. 40 CFR §60.1465. 
24 

does not include fuel derived from municipal waste refuse under 129(g)(5). Some 

fuels may be processed from solid waste, but that determination by the Agency 

stands or falls based on the RCRA statute and case law, not the CAA. EPA is not 

defining “refuse derived fuel” in this RCRA rule. The validity of EPA’s 

interpretation on whether commodity fuels may be processed, or extracted, from 

a waste must stand or fall based on the RCRA definition, not provisions of the 

CAA.

Id. EPA’s statements here reflect its belief that Section 129 does not, and cannot, 

mandate that RDF be a “solid waste” under RCRA. Pursuant to Section 129(g)(6), only a 

RCRA rulemaking can determine the scope of the “solid waste” definition. However, 

because RDF is already subjected to municipal waste combustor standards under 

Section 129, the NHSM Rule does not attempt to determine the scope of RFD for those 

purposes. Further, EPA clearly states that fuels may be processed from solid waste, and 

the legitimacy of those fuels will determined based on the NHSM Rule, not the language 

of CAA Section 129. Accordingly, a material that is determined to be a legitimate fuel 

material under the NHSM Rule, and therefore is not a “solid waste,” cannot be 

considered RDF. 

8. The starting point for the application of the NHSM Rule framework for determining 

whether a material is a fuel or a waste is the definition of “secondary material”: 

Secondary material means any material that is not the primary product of 

a manufacturing or commercial process, and can include post-consumer 

material, off-specification commercial chemical products or 

manufacturing chemical intermediates, post-industrial material, and 

scrap. 

40 CFR §241.2. There is nothing in the NHSM rulemaking that would limit the universe 

of the materials that may be considered “secondary materials,” and the definition does not 

exclude municipal solid waste from its scope. By contrast, it appears that EPA attempted 

to define “secondary materials” as broadly as possible, and in a manner that clearly 

includes municipal waste, which is composed in primary part of “post-consumer” 

materials. Accordingly, municipal waste may be considered “secondary material” and 

thus fall within the NHSM framework for determining legitimacy. 

9. In the NHSM Rule, EPA has determined that secondary materials that have been 

discarded can be processed into non-waste fuels. Section 241.3(b) provides: 

(b) The following non-hazardous secondary materials are not solid 

wastes when combusted: 

..... 

(4) Fuel or ingredient products that are used in a combustion unit, and are 

produced from the processing of discarded non-hazardous secondary 

materials and that meet the legitimacy criteria specified in paragraph 
25 

(d)(1) of this section, with respect to fuels, and paragraph (d)(2) of this 

section, with respect to ingredients. The legitimacy criteria apply after 

the non-hazardous secondary material is processed to produce a fuel or 

ingredient product....