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/U S@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 f elt prudent to send in advance of our meeting tomor row at 2:00 pm with Mr. Mancini
and his team. There are two documents from Waste Ma nagement to the EPA, they have included these as ba ckground and because they
contain cited studies that Waste mentions in their recommendations.

Many thanks again for your help and assistance in se tting up this meeting. I look forward to meeting yo u.

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 Reco nsideration Rules June 13 2012 WM-DSWA.docx) (See attached file: WM Final CISWI-NHSM Rule Recons ideration comments.DOCX) (See attached file: WM Final Boiler Reconsideration comments.DOCX)

### 1 Recommendations for OMB

Landfill Gas (LFG) Issues in Non-Hazardous Secondar y Materials (“NHSM”)
Commercial and Institutional Solid Waste Incinerati on (“CISWI”) and Boiler
MACT Rules

EPA should clarify in the NHSM and CISWI regulation s 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. Age ncy 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 combuste d. 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 wa ste,” 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 regar ding “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 regul atory status of LFG. **(Attachment A – August 5, 2011 Letter from EPA to Waste Management)** 

In addition, EPA offered further clarification in t he CISWI Reconsideration and Proposed
Amendments to the NHSM Rule:

**“Accordingly, the proposed CISWI reconsideration ru le includes the same definition of**  **"contained gaseous material" that was removed from the final CISWI rule.**  **This definition is consistent with the definition i n the subparts cited above. Moreover, our**  **proposal to add the definition of "contained gaseou s material" to the proposed CISWI**  **reconsideration rule is consistent with the positio n 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. T he 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, ot her Agency statements have muddied the
waters. As described in the attached letter to Mr. Stanislaus from multiple major manufacturing, energy generation and solid waste ma nagement 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 appare ntly taken the position that LFG combusted in landfill gas-to-energy projects must m eet the legitimacy criteria enumerated in
the NHSM Rule in order to avoid classification as s olid waste combustion subject to CISWI. In this context, the Agency’s letter to WM has been mi sinterpreted, and throws into doubt EPA’s statements with respect to its unchanged interpreta tion 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 in dustry, we believe that it is imperative that the Agency affirmatively state in both the final CI SWI 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 l andfill gas, does not constitute the combustion of solid waste subject to the CISWI Rule

.

WM and DSWA support the explanations in the CISWI R econsideration 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 & Pap er Association, and clearly stated that EPA did not intend to change its previous interpretatio ns of what constitutes “contained gaseous
material.” We strongly recommend that EPA finalize its clarify ing language in the preambles to both final rules and add to the preamble discuss ions 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 combustio n devices to the list of examples of gaseous
material combustion that does not involve the treat ment or other management of a solid waste. EPA should add a statement to both preamble s 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 t o reinsert the definition of “contained gaseous material” into the CISWI Reconsideration Ru le. 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 combus ted.

To clarify the definitions of “solid waste” and “co ntained gaseous material” across both the CISWI Reconsideration Rule and the NHSM Rule, the t wo 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 gase ous 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 bot h rulemakings will enhance transparency and clarity f or the regulated community, and further the Agency’s goal of developing clear, readable and com prehensible rules.

Failure to clarify that LFG is not a solid waste su bject to RCRA and the NHSM Rule will pose extremely severe consequences for the landfill mana gement 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 c apital, $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 su bject to RCRA and the NHSM Rule is also contrary to statutory and regulatory definitions an d program policies that recognize LFG as a renewable fuel. For example:

• EPA’s Landfill Methane Outreach Program (LMOP) prom otes 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 L FG 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 ca tegorized as Gas 1 Fuel under the Boiler MACT, and like natural gas, should not be subject t o emission limits thereunder. The proposed
Boiler MACT Reconsideration Rule offered no sound s cience or policy rationale for continuing to list LFG as a Gas 2 fuel, and thereby subjecting LF G combustion to stringent emission limits. Sufficient data were readily available for EPA to e stablish 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 clas sified 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/m 3 , which should serve as a basis for listing LFG in the same Gas 1 category as natural g as and refinery gas.

### 4

As previously stated, WM’s LFG customers have indic ated that they may not be able to meet the Gas 2 emission limits, particularly in units d esigned 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 l imits.

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 estimat es that the 60 boiler projects utilize approximately 1900 Million British Thermal Units (M MBtu) 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 sti ll be generated by the landfills and therefore must be combusted in flares, increasing emissions o f greenhouse gases and criteria pollutants.

EPA calculated the net increase in overall fossil f uel based CO2 emissions from boiler and boiler –turbine projects would be 2,025,698 tons. The nat ion would also realize an additional 12,841 tons of CO, 291 tons of PM and 684 tons of NOx. SO 2 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 signific ant. For boiler and boiler-turbine projects now using LFG, the order-of-magnitude estimate of t he 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 comment s to the Proposed Reconsideration of
the Final Rule for National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers a nd 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 lead ing provider of integrated environmental solutions, WM is uniquely interested in ensuring th at the Agency’s final Boiler Rule upon reconsideration reflects and supports ongoing and n ewly evolving efforts to reduce, reuse and manage waste, while recovering valuable resources a nd 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-t o-energy plants and independent power production facilities. Additionally Wheelabrator T echnologies 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 (LF G) as a renewable alternative fuel. WM operates 131 LFG-to-energy projects that produce en ough renewable energy to power nearly half a million homes and replace use of about 2.4 millio n tons of coal per year. These projects offset criteria pollutants and hazardous air pollutants as sociated with coal use and also offset nearly 3 million tons of carbon dioxide equivalent (CO 2 e) 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 treati ng 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 Spacef light Center. These organizations have chosen to utilize LFG as a viable replacement for f ossil fuel, and as a key element of their corporate

### 2

sustainability goals. Furthermore, investment in t hese projects has been strongly encouraged by Congress and EPA’s Landfill Methane Outreach Progra m (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 n ew and unreasonable regulatory burdens upon the combustion of LFG will conflict with existing C lean Air Act regulations governing LFG control and use as a renewable fuel, including the Standard s of Performance for Municipal Solid Waste Landfills, 40 C.F.R. Part 60, Subpart WWW (the “Lan dfill NSPS”) and the National Emission Standards for Hazardous Air Pollutants: Municipal S olid Waste Landfills, 40 C.F.R Part 63, Subpart AAAA (the “Landfill MACT”).

WM offers the following comments on the proposed Bo iler MACT Reconsideration Rule, incorporating by reference WM’s Petition for Recons ideration of the National Emission Standards for Hazardous Air Pollutants for Major Sources: Ind ustrial, 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-2002-0 058-3322). 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 t o categorize LFG as a “Gas 1” fuel will subject LFG boilers to stringent emission limits, thereby creat ing strong disincentives to the use of LFG in boilers and hampering many private, local governmen t 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 th e domestic renewable energy sector, producing more than 7 times the energy output of the entire d omestic solar energy sector 2

.

Under the proposed Boiler MACT Reconsideration Rule , units designed to burn Gas 1 fuel (including natural gas and refinery gas) are not su bject to emission limits, while units designed to burn “Gas 2” fuels are subject to strict numeric em ission limits for PM, HCL, Mercury and CO. By EPA’s own analysis, the control costs for Gas 2 boi lers are estimated to be higher than the combined compliance capital costs for boilers and p rocess heaters in all other categories. WM’s LFG customers have indicated that they may not be a ble to meet the proposed Gas 2 emission limits (e.g., for CO) particularly for units design ed and permitted to minimize NOx emissions (for ozone attainment). Therefore, the boiler owners ma y be forced to switch to natural gas if LFGfired boilers are subject to “Gas 2” emission limit s. EPA’s creation of such disincentive for use of LFG is contrary to the Agency’s own stated policy o f encouraging the beneficial use of LFG 3

.

1 Additionally, WM offers these comments without wai ver of any issues raised through its Petition for R eview of the Boiler MACT rulemaking, at Docket No. 11-1147 in th e U.S. Court of Appeals for the District of Columbi a 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 t he 60 boiler projects utilize approximately 1900 Million British Thermal Units (MMBtu) per hour of L FG, 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 criter ia pollutants.

EPA calculated the net increase in overall fossil f uel based CO 2 emissions from boiler and boiler – turbine projects would be 2,025,698 tons. The nati on would also realize an additional 12,841 tons of CO, 291 tons of PM and 684 tons of NOx. SO 2 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 qui te significant. For boiler and boiler-turbine projects now using LFG, the order-of-magnitude esti mate 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 as sets lost for existing projects is $87 million. **(** Attachment B – CH2M Hill Boiler MACT Economic Impac t Evaluation **)**



### 2. EPA Should Not Subject LFG to Additional Emission L imits 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 u sed 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 stand ard that was established pursuant to the
Landfill NSPS and determined under the Landfill MAC T 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 natura l 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 Ru le should not apply to LFG-fired boilers. The
emission limits established for Gas 2 units are tec hnically infeasible and cost prohibitive to promoting renewable sources of energy. As previous ly 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 s ubject to “Gas 2” emission limits.



### 3. EPA Should Identify LFG as a Gas 1 Fuel

In our Petition for Reconsideration of the Boiler M ACT 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 l imits 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 o r policy rationale for continuing to list LFG
as a Gas 2 fuel.

WM contracted with CH2M Hill to conduct a compariso n 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, specific ally natural gas and refinery gas. ( Attachment C – Boiler MACT Fuel Classification Review for Land fill Gas **)** CH2MHill concluded that sufficient data were readily available for EPA to establish th at LFG is comparable to natural gas and refinery gas with regard to HAP emissions, and that both emi ssions 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 compar ison of the readily available data for total mercury in LFG to comparable data for natural gas a nd refinery gas. As noted above, EPA’s 2008 effort to establish an appropriate default paramete r for Hg in LFG found no instances of LFG exceeding the fuel specification value of 40 microg rams per cubic meter (μg/m3) among the
numerous tests conducted that EPA reviewed.

Data developed by EPA in its 2008 BID support the c onclusion that the mercury levels in LFG are consistently much lower than the Gas 1 fuel specifi cation level of 40 μg/m 3 , which should serve as a basis for listing LFG in the same Gas 1 catego ry as natural gas and refinery gas. The data for mercury in LFG supports its characterization as a G as 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, on e 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, natu ral 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 Co ncentrations 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 dock et site, EPA Docket No. EPA-HQOAR-2002-0058-1388.1). 4 Although emission limits are evaluated on a lb/MM Btu basis, the fuel specification limit is based on the mercury concent ration in LFG reported in units of micrograms per cubic meter (μg/m3). The published studies tha t have included sampling of mercury in LFG are shown in the table below. Samples have been collec ted 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 con ducted 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. Prepa red by Arcadis. EPA600/R-05/096. Kentucky 1

U.S. Environmental Protection Agency (USEPA). 2007 . Field Test Measurements at Five Municipal Solid Waste Landfill s with Combustion Control Technology for Landfill Gas Emissions. Pre pared 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. Pr epared by Eastern Research Group, Inc. EPA/600/R-08-116. California, Flo rida, Delaware, Washington,
Northeast and Midwest

US 17

U.S. Environmental Protection Agency (USEPA). 200 9. Quantifying
Uncontrolled Landfill Gas Emissions from Two Florid a Landfills. Prepared by Arcadis US. EPA/600/R-09/046. (a) Florida 2

U.S. Envi ronmental Protection Agency (USEPA). 2012. Quanti fying Methane Abatement Efficiency at Three Municipal Sol id Waste Landfills. Final Report. Prepared by Arcadis US. EPA/600/R-1 1/033. 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

L indberg, S.E., Southworth, G., Prestbo, E.M., Walls chlager, 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, Mi nnesota, Delaware, California 9

Netcen. 2003. Monitoring and Speciating Mercury i n Landfill Gas. A Short Status Study on Emissions from UK Landfills. Pre pared for the
Environmental Services Association Research Trust. United Kingdom 6

UK Environm ental Agency. 2004. Quantification of Trace Compo nents in Landfill Gas. Waste Management Research Programme. United Kingdom 6

4 T he three mercury measurements, collected from a sin gle landfill gas unit at a BMW facility, were incor rect. EPA indicated in its response to comments that this err or has been corrected (See comment and response on May 18,
2011 reconsideration notice in 76 FR 28662 at EPA D ocket Control No. EPA-HQ-OAR-2002-0058-2775.1).

### 6

(a) These studies were also included in USEPA’s 200 8 AP42 Background Document.

Mercury Concentrations in LFG Are Consistently Belo w the 40 μg/m 3 Fuel Specification Limit. As noted above, a large dataset of mercury concentrati ons in LFG is available from numerous published studies and reports, including many studi es conducted for EPA (USEPA 2005, 2007, 2008, 2009, 2012; Frontier 2003; Lindberg et al. 20 05; 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 d atabase of more than 150 measurements that reliably characterizes the levels of mercury in LFG

.

To demonstrate that a gaseous fuel other than natur al gas or refinery gas qualifies as a Gas 1 fuel (76 FR 80633), the rule requires that a fuel specif ication analysis be conducted. The analysis must characterize mercury concentrations in the fuel, de monstrate that mercury concentrations do not exceed 40 μg/m 3 , and address a variety of associated requirements related to sampling and analysis (e.g., descriptions of sample locations, p rocedures for collecting and analyzing samples). The existing database of mercury LFG measurements c omplies with the objectives of the proposed Boiler MACT Reconsideration Rule regarding a fuel s pecification analysis. In fact, this database presents a more comprehensive characterization of m ercury 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 sample s 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 prov ides descriptions of sample locations, sample collection and analysis methods, and assessments of data quality. These elements address the fuel specification requirements laid out in §63.752 1(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 th at concentrations are below the 40 μg/m 3 fuel specification limit. All of the measurements repor ted in the published literature are below 40 μg/m 3 . Additionally, the mean concentration of mercury in LFG is 2 μg/m 3 and the 95% upper confidence limit is 2.7 μg/m 3 , based on the individual data measurements reporte d in the many published studies noted above. The overall mean co ncentration of mercury in LFG and the highest 95% upper confidence limit, calculated from one stu dy which presents only summary statistics and not individual test results, is 4 μg/m 3 and 12 μg/m 3 , respectively.

In sum, the Agency should consider the abundant pub lished 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 b e consistently below the 40 μg/m 3 fuel specification limit and support the characterizatio n 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 (H 2 S) in LFG

### 7

support its characterization as a Gas 1 fuel. Furt her, 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 pollutan t and greenhouse gas emissions compared to LFG. LFG has been shown to produce lower nitrous oxide e missions 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 desp ite the abundant data showing that LFG mercury levels are substantially below the Gas 1 fuel speci fication 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 avai lable published data, including EPA’s own reports, that shows LFG meets the other Gas 1 fuel specification limit of 40μg/m 3

. We therefore recommend §63.7521(f) be modified as follows:

§63.7521(f) To demonstrate that a gaseous fuel oth er than natural gas or refinery gas qualifies as an other gas 1 fuel,.....except as speci fied in paragraph (f)(1) through (3) of this

section. (1) You are not required to conduct the fuel specif ication 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 Specificatio n

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 spec ification to ensure that it is established in a manner that will include LFG that is managed in acc ordance with existing CAA requirements as discussed above. For example, the Landfill MACT re quires that LFG be routed to a treatment system that processes the gas for subsequent sale o r use as fuel; this requirement would be an appropriate and adequate specification for demonstr ating 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 prop osed in the Boiler MACT Reconsideration Rule, the fuel specification does not provide a viable av enue 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 (H 2 S) limit from the Gas 1 fuel specification. In the preamble to the proposed Boiler MACT Recon sideration Rule, EPA explains that:

**“EPA has reexamined the fuel specification and agre es that the key contaminant for**  **demonstration of comparability from a HAP perspecti ve is Hg and that the H**  **2 S fuel**  **specification that was finalized does not provide a direct indication of potential HAP from**  **combustion of gaseous fuel. Accordingly, the EPA i s 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 conclusio n that use of an H 2 S 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 re finery 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 H 2 S than the Gas 1 fuel specification in that rule. CH2M
Hill evaluation found that the H 2 S concentrations in refinery gas can range from 0 t o 450,000 ppm. Based on this data evaluation, WM asserted that LFG should not be held to a higher H 2 S standard than refinery gas for qualification as a Gas 1 fuel . We also commented that as H 2 S is not a HAP, nor a HAP precursor, nor a surrogate for HAP emissi ons, it is therefore an inappropriate limit to use in a demonstration of comparability for HAP emi ssions.

While we commend EPA for correcting its Gas 1 fuel specification related to the H 2 S limit, we continue to believe that the Boiler Reconsideration Rule, as proposed, creates a significant disincentive to using LFG as an alternative, renewa ble fuel. Our primary concern with the fuel specification is that despite the proposed correcti on to remove the H 2 S limit from use as a demonstration of comparability, the Gas 1 fuel spec ification requirements are still unworkable and burdensome. The requirements preclude its use as a viable mechanism for boiler owner/operators or fuel suppliers to demonstrate fu el 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 me ets the specifications of an other gas 1**  **fuel as defined in §63.7575, you must conduct an in itial fuel specification analyses**  **according to §63.7521(f) through (i). If the mercu ry constituents in the gaseous fuels will**  **never exceed the specification included in the defi nition (40 ug/cm) you will include a signed**  **certification with the Notification of Compliance S tatus**  **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, yo**  **u 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 certificat ion 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/fiducia ry 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 c ertification requirements, which allow for
certifications to be based on all credible evidence , generator knowledge, and which provide for certifications based on generator or operator knowl edge, information, belief.

While it can be demonstrated that a gaseous fuel co nsistently 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 w ill never exceed such specification in the future, especially where the content of future anal yses 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 demonstratio n methods such as for emission limits and work practice standards. For example, we are not a ware of any other circumstance in which EPA has required a facility to certify to future compliance with work practice standards, or to cer tify
the contents of future emissions tests or analyses. Likewise, the certi fication requirement included in the proposed Boiler MACT Reconsideratio n 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 8065 3). The definition does not discuss future events (nor should it), and therefore it is unreaso nable based on this definition to impose a requirement to certify future conditions as a compl iance tool in this case. Such requirement unfairly subjects all gaseous fuels other than natu ral gas or refinery gas to a fuel specification standard that these two Gas 1 fuels are not require d 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 gas eous 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 c onstituents could vary above the specification. In addition, §63.7540(c) requires monthly fuel spec ification testing be conducted at each facility if a signed certification stating mercury fuel specif ication limit will never be exceeded cannot be submitted. As discussed above, it is unreasonabl e and inconsistent with other Federal Rules to require such certification. The requirement to con duct 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 o r 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 limi t.

However, the Boiler MACT Rule should not preclude s ubsequent testing to demonstrate compliance with the fuel specification where the re sults of the initial fuel specification demonstration did not meet the gas specification ou tlined in the definition of other gas 1 fuels. In

### 10

this case, a subsequent initial test followed by pe riodic testing, such as monthly sampling, to validate initial fuel specification demonstration r esults could be required. The proposed Boiler
MACT Reconsideration Rule states that if “12 consec utive 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 red uced testing frequency, such as annually or bi-annually where 12 consecutive monthly samples de monstrate that the fuel meets the gas specification outlined in the definition of other g as 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 mo dify the certification requirements and testing frequency in §63.7530(g) as follows:

(g) If you elect to demonstrate.....If the mercury co nstituents in the gaseous fuels will never
do not and are not reasonably expected to exceed the spec ification 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 Complian ce Status may include other relevant data or measurements that supports the certification tha t 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 me et the gas specification outlined in the definition of other g as 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 f or mercury for the other gas 1 subcategory, you may decrease fuel specification te sting frequency to annually.

We recommend the EPA modify the certification requi rements and testing frequency in §63.7540(c) as follows:

(c) If you elected to demonstrate that the unit mee ts the specification for mercury for the other gas 1 subcategory and you cann ot submit a signed certification under § 63.75 30 45 (g)
because the constituents could exceed exceeded the specification, you must follow Gas 2 subcategory requirements or conduct monthly fuel specification testing of the g aseous 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 spec ification testing frequency to annually

.
We recommend the EPA modify the certification requi rements and testing frequency in §63.7555(g) as follows:

### 11

(g) If you elected to demonstrate that the unit mee ts the specification for mercury for the other gas 1 subcategory and you cannot submit a sig ned certification under § 63.75 30 45 (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 i n Table 6.

This approach is consistent other NESHAP requiremen ts such as 40 CFR Part 63, Subpart N (40 cfr 63.344); Subpart GGG (see 40 CFR 63.1250). See als o 40 CFR 261.10 (use of generator knowledge to certify to regulatory characteristics of materia ls)

A Single Fuel Sample is Inappropriate

Per §63.7521(h), you must obtain a single fuel samp le 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 me asurement, even if it is not valid, would be sufficient basis for failing to demonstrate the mer cury 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 u sed and also provides an equation for calculating a 90 percent upper confidence limit fue l concentration from sample data (referred to in
the rule as the “90 th 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, t he approach used to demonstrate that a gaseous fuel qualifies as an other Gas 1 fuel shoul d be consistent with compliance methods provided elsewhere in the proposed Boiler MACT Reco nsideration 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). W e recommend that the proposed Boiler MACT reconsideration Rule be amended to ensure that comp liance will not be determined based on one sample or by comparison to a single maximum value r eported 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 Oth er Gaseous Fuels. According to Table 6 of the Proposed Boiler MACT Re consideration Rule, you must conduct fuel analysis for mercury using one of the four prescrib ed test methods, or equivalent method. However, §63.7521(g)(2)(vi) appears to prevent gase ous 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 exp lanation or rationale is provided for this

5 The equation provided for calculating a “90th perc entile confidence level” to compare to emission lim its (Eq. 10 at 76 FR 80641) does not appear to reflect EPA statistica l guidance, for example, as provided in EPA’s 2006 report, Data Quality Assessment: Statistical Methods for Practit ioners. 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 likel y that purchasers of gaseous fuels will require the ir fuel suppliers to develop the analyses and document ation necessary to qualify them as an “other
Gas 1 fuel.” We strongly recommend EPA remove this language so t hat all analyses conducted for use of other Gas 1 fuels may utilize methods li sted in §63.7521(f)-(i) or equivalent methods

.

WM requests that EPA incorporate additional test me thods in the rule that can be used under §63.7521 . §63.7521 states that a gaseous fuel other than n atural gas or refinery gas can be qualified as a “Gas 1” fuel by conducting fuel test ing according to methods laid out in Table 6. Specifically, Table 6 requires that the mercury con centration in the fuel must be measured using one of the following test methods: “ASTM D5954, AS TM D6350, ISO 6978–1:2003(E) or ISO 6978– 2:2003(E) (or an equivalent test method)”. The Age ncy 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 reference d table are typically used for natural gas analyses, and have not been proven to be appropriat e for analyzing LFG for mercury. Further, because gaseous fuel suppliers are not allowed to u se alternative methods, WM would be forced to use an unproven method to demonstrate our LFG co mpliance 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 physi cal properties of LFG and natural gas differ. For example, natural gas is primarily methane with lowe r concentrations of related alkanes and carbon oxides, and trace quantities of other hydroc arbons. LFG typically contains 45% to 60%
methane and 40% to 60% carbon dioxide. LFG also in cludes small amounts of nitrogen, oxygen, ammonia, sulfides, hydrogen, and carbon monoxide. The complexity of component fuels typically encountered in sampled LFG often renders the method s typically used for natural gas characterizations inappropriate. Either interferen ces or target analyte levels may disqualify natural gas methods when attempting to acquire repr esentative Hg data in LFG. The performance of these methods in an LFG matrix has yet to be dem onstrated. As a result, it is inappropriate for the Agency to categorically require that, in the ab sence of a pre-approval process, only the four methods listed in Table 6 may be used for mercury t esting in LFG.

Numerous studies have been conducted to measure mer cury in LFG, including several conducted
for EPA. The table below lists the test methods us ed in these studies, the methods specified in Table 6, and, for each method, whether it was inclu ded in the Agency’s proposed Boiler MACT
Reconsideration Rule. This table shows that none o f 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 rel ied 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 Chemi

sorption 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 in dicates 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, sele ctivity and sensitivity of the current methods

### 15

included in Table 6, taking into account their appl icability to gas fuels other than natural gas or refinery gas.

For example, Method 30B is a stack gas method appro ved for the characterization of Hg in various off-gas sources, including incinerators, boilers, a nd 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 revi sed AP-42 emission factors for municipal waste landfills. (EPA/600/R-08-116. September). So me advantages of using Method 30B include:

• Point source sampling can be conducted using relati vely easy to operate and portable instruments;

• The sampling technology is mature and familiar to m ost 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 pract ices.

WM recently conducted a field study using Method 30 B and ASTMD5954 for several projects supplying LFG as fuel to industrial boilers to demo nstrate the viability of both applications. We evaluated the sampling and analysis of LFG using Me thod 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 30 B 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 i n LFG are well below the fuel specification for other gas 1 fuels.

We had difficulty identifying laboratories that hav e capability (equipment and experience) to perform the test methods listed in Table 6 for dete rmining mercury in LFG, specifically ASTMD5954. After contacting several large accredit ed 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 f or 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, t he 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 fr om Japan. This circumstance prevents the laboratory from conducting analysis on collected LF G samples it received February 13. A further complication is that the laboratory’s quality contr ol sample hold time is 30 days, which may render our samples unusable. This same laboratory also do es not have capability (equipment) to perform ASTM D6350 on the collected samples and cannot iden tify 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 prescri bed in Table 6 of the proposed Boiler MACT Reconsideration Rule for LFG and other gaseous fuel s.

### 16

WM would like to share lessons learned from this fi eld study with EPA, specifically whether the test methods listed in Table 6 for determining merc ury (in natural gas) are applicable to other gaseous fuels (e.g., LFG). Therefore, we respectfu lly request that the Agency accept information gathered as part of this field study as supplementa l comments on the proposed Boiler MACT Reconsideration Rule if/once we receive the final A STM D5954 results from the laboratory.

We believe our comments demonstrate the appropriate ness 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 i n well operated and maintained facilities equipped with the best technologies, EPA’s affirmat ive defense concept essentially presumes that
malfunctions never occur. Under the rule as writte n, 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 de signed, 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 star tup 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 p eriods are no different and should be treated similarly. Since EPA also lacks emissions data for malfunction periods, and would find it difficult t o obtain sufficient emission data for all the varying types of malfunction-related events, EPA should adopt work practice standards for malfunction perio ds.

Malfunction work practice standards could include l imitations on the duration to ensure quick and effective corrective action is taken, and if the ma lfunction cannot be quickly resolved the unit would be shut down for repair. Facilities should s till be required to submit a notification of a malfunction excess emission event with the underlyi ng root cause analysis. If EPA or the administering agency decides the excess emission ev ent was not a malfunction, it would then be reported as a deviation of the limit and enforcemen t action, including imposition of penalties, would still apply consistent with the deviation def inition in 63.7575. EPA could also choose to take enforcement action should a facility report “excess ive” malfunction events.

Finally, the sheer number of eligibility criteria t hat 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 cr iteria as follows to make it more reasonable and eliminate such vague language:

### 17

“To establish that an exceedance of an emission lim it 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 d emonstrate that: (1) the malfunction: (i) was not caused by a sudden infrequent and unavoidab le failure of air pollution control equipment or failure of a process to operate in a n ormal or usual manner; (ii) was not caused by operator error or careless operation; (ii i) 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 operati on if possible in a manner consistent with safety requirements and good air pollution con trol 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 shoul d 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 corr espondence. 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 includ e 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 co nfirm a malfunction meets the criteria. For example, a lightning strike on a utility interconne ct transformer that causes a temporary facility power outage would be easily discernible as a malfu nction. If the agency needed more information, it could request a full report in 45 d ays, or ask the facility to include a full report i n the next semiannual compliance report. Such stream lined requirements for malfunction events would be consistent with several states’ requiremen ts and would ensure ample regulatory oversight.



### 6. Stack Test Procedures in §63.7520 Should be More Fl exible

WM recommends that affected facilities be allowed t he flexibility to conduct more than just three stack test runs to demonstrate compliance with appl icable 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 r uns 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 l imits**  .”

### 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 sha re our concerns and recommendations with the Agency, and we look forward to working wit h you as you reconsider and revise the Boiler MACT Rule. If you have any questions with our comm ents or with the attached materials, please feel free to contact me at (202) 639-1218 or by ema il 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 Techn ology 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). 200 9. 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 Re port. Prepared by Arcadis US. EPA/600/R**  **11/033.**

**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., Wall schlager, D., Bogle, M.A., and Price, J. 2005.**  **Gaseous methyl and inorganic mercury in LFG from la ndfills in Florida, Minnesota, Delaware, and**  **California. Atmos. Environ. 39:249-258.**

**Netcen. 2003. Monitoring and Speciating Mercury i n LFG. A Short Status Study on Emissions from**  **UK Landfills. Prepared for the Environmental Ser vices Association Research Trust. UK**  **Environmental Agency. 2004. Quantification of Tra ce Components in LFG. Waste Management**  **Research Programme.**Attachment A**EPA Landfill Methane Outreach Program( LMOP) Enviro nmental Analysis provided to WM** AnalysisBaseline Emissions = LFG fired in boilersNew Emissions Scenario = Natural gas fired in boilers, LFG flaredLFG Energy Boiler-Steam Turbine ProjectsTotal Estimated MMBtu/hr of LFG Utilized =1,896Total Estimated MMBtu/hr of LFG Utilized =2,499Project Count=17BaselineNewScenarioIncreaseEmissionsSourcePollutantBaselineNewScenarioIncrease0873,972873,972BoilerEmissions(tpy)Fossil CO201,151,7261,151,726same0COsame0same0PMsame0same0NOxsame01154.4-111SO21525.8-146same0Hgsame0-00FlareEmissions(tpy)Fossil CO2-00-5,5405,540CO-7,3017,301-126126PM-165165-295295NOx-389389-115115SO2-152152-0.00220.0022Hg-0.00300.0030873,972OverallEmissionsIncrease(tpy)Fossil CO21,151,7265,540CO7,301126PM165295NOx38921Assumptions and Rationale:1. To estimate boiler and flare emissions, emission factors were applied to the total estimated amount of LFG utilized (MMBtu/hr) for boiler projects andboiler-steam turbine projects from the LMOP database (as of Sept 20, 2011). Emissions for individual boilers and boiler projects were not analyzed.2. CO2 - All CO2 generated from LFG (combustion ofCH4 and generation of CO2 from decomposition of MSW) was considered biogenic and not includedin the calculations. CO2 generated from combustionof natural gas as a fossil fuel (non-biogenic) wasincluded in the calculations using an emission factorof 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 andnatural gas-fired boilers were not found to bestatistically unique and, in addition, they vary byindividual boiler instead of fuel type. Therefore,for this analysis, it was assumed that CO, PM & NOxemissions from boilers would not change when the fuel is switched from LFG to natural gas. Emissions of CO, PM & NOx were estimated for LFG beingflared using emission factors from AP-42 (Table 2.4-5) of 750 lb CO/million dscf methane, 17 lb PM/million dscf methane, and 40 lb NOx/million dscfmethane.4. SO2 emissions were estimated for the baseline and new emissions scenario because the amount of SO2emitted from combustion in a boiler or flarevaries by the fuel type. The decrease in SO2 boileremissions is a result of LFG typically containinghigher levels of sulfur than natural gas. SO2 emissionsfor 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) and assumes all sulfurcompounds in LFG are converted to SO2 during combustion. SO2 emissions from natural gas-fired boilerswere estimated using an emission factor of 0.6lb 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 unique. The amount of Hg inLFG and natural gas was found to be very similar since Hg passes through combustion devices and the amount emitted varies by the amount of Hg in thefuel itself. Therefore, for this analysis, it was assumed that Hg emissions from boilers would not change when the fuel is switched from LFG to natural gas.Emissions of Hg were estimated for LFG being flaredusing 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 lossof energy production due to problems in the gascollection system, problems with project equipment,weather related interruptions of the local utilities, and shutdowns at the energy consumer end ofthe 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.pdfAP-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.pdfGreenhouse Gas Reporting Program (GHGRP) - 40 CFR 98, Subpart C, Table C-1 (Default CO2 Emission Factors and High Heat Values for Various Types ofFuel), 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=40:21.0.1.1.3.3&idno=40Attachment 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 evaluat ion of the cumulative, nationwide financial impacts of switching from LFG (LFG) to natural gas at facilitie s currently using LFG as boiler fuel, if this were to occur in response to the requirements of the currently promu lgated Boiler Maximum Achievable Control Technology (MACT) rule. The facilities used for this evaluation w ere those included in a database spreadsheet provided b y USEPA’s Landfill Methane Outreach Program (LMOP) by e mail to Waste Management on September 26 of this year.

This analysis is limited to the projected financial cos ts for existing projects utilizing LFG in boilers th at would be affected by the Boiler MACT rule if it became effecti ve. Additional economic impacts including projected loss of jobs have been projected by LMOP. Still more economic im pacts 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-to

energy projects. However, the number that would use LFG in boilers and the investments and returns for t hese prospective projects are too uncertain to estimate the financial impacts.



### Results
Table 1 lists the estimated financial impacts of switchin g from LFG to natural gas for all LFG-fired boilers in the
United States listed in USEPA’s LMOP database. Costs i n 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 $78,0 00,000

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 fi nancial 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 w ere calculated for each project. These costs were comp uted as the net present value of the cost differences betwee n 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 f or which royalty payments would no longer be paid ove r the remaining life of the system.

In addition to direct revenue impacts, project owners will lose the value of LFG processing and transport e quipment that must be abandoned when switching from LFG to natu ral gas. To estimate this impact, the capital costs associated with constructing compressor systems and pi pelines for utilizing LFG in the boiler projects wer e estimated for each project in the LMOP database, as desc ribed below under Methodology. The costs were depreciated based on the age of the project to estimat e the depreciated value of the installed system that wo uld be
abandoned. These sunk costs must be written off as st randed assets before they are fully depreciated. The t otal estimated capital assets lost for all existing project is $87 million.

In addition, Waste Management has estimated they could l ose $4 to 5 million annually in revenue from third part y developers and directly from large industries. This loss of revenue is likely only a portion of the tota l 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 ge nerated by LMOP. LMOP is a voluntary program of the U .S. Environmental Protection Agency that is intended to h elp reduce methane emissions from landfills by encour aging the recovery and beneficial use of LFG as an energy res ource. LMOP maintains a database of projects that use LFG as boiler fuel. This database was downloaded to an Excel fi le and used as the basis for this financial evaluation. T he database contains, among other data, the landfill name, lo cation, start-up date, quantity of LFG used, and the len gth of pipeline used to pipe the LFG from the landfill t o the boiler location (i.e. project site). This data was sufficient to form the basis for an order-of-magnitude estimate of th e total capital costs, depreciated capital costs (that wou ld be abandoned upon switching to natural gas), annual O&M cost s for the LFG-to-boiler fuel projects and lost royalt y 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 us ed as the basis to extrapolate the capital costs for compressing, chilling, and transporting LFG to the re ceiving boiler for each of the projects in the LMOP database. The Base Project construction cost is based on previ ous CH2M HILL projects for LFG compressor systems at landfills and the pipelines between the landfills and the gas us e site. O&M costs for the base project were similarl y estimated based on previous projects. The O&M costs for the LM OP sites were calculated based on the LFG flow which w as used to compute compressor power requirements. Labo r 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 (engineeri ng, administrative, etc) were added based on a percentage (Tab le 2) of the subtotal capital costs to estimate the gra nd
total based on 2011 dollars.

The grand total cost calculated for 2011 was then used to estimate the current year cost for construction of th e 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 start up) 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 ye ars to estimate the abandoned value of the LFG system an d 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 t he end user over the remaining life of the LFG system a nd pipeline, multiplied by a factor that approximates ty pical

### 24 royalty payments to landfill owners for LFG-to-energy projects. The total cost reported in Table 1 is the n et 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 cal culated by subtracting the displaced cost of operating and maintaining the LFG processing and transport system fr om the cost for purchasing natural gas. The total natural gas cost that would be paid in lieu of the LFG was then c alculated 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 o f 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 thi s economic evaluation.

1) The capital cost for the base project compressor and ch iller system was estimated at $675,000 for a 750 cfm compressor system. The costs for systems that had flo ws less than or greater than this range were extrapolated from the base project using an extrapolatio n exponent of 0.75. The ratio of a given project capacity to the base project capacity is raised to the e xponent 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 e stimated at $2/in diameter-ft of pipeline for flows less than 2000 cfm and $6/in diameter-ft of pipeline for flows g reater 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 i nclude 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 t he subtotal (compressor and pipeline) costs (Table 2).

5) The cost of natural gas was assumed to be the latest availab le average U.S. retail natural gas price for industrial users of $5.40 per MMBTU, as published by t he U.S. Energy Information Agency. ( http://38.96.246.204/totalenergy/data/annual/showtext.cfm?t=ptb 0608 ) TABLE 2.

Additional Costs added to Capital Cost for Compress or 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 Maintenan ce (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 sit e were considered minor (i.e. a trivial distance between the project site and supply pipeline); therefore, they w ere 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 wer e 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 LF G 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 t he CCI.
11) The energy content of natural gas was assumed to be appro ximately 1000 BTU/ft 3

. 12) The methane content of LFG was assumed to be 50%; the refore, the energy content was assumed to be 500 BTU/ft 3

. 13) The Net Present Value (NPV) was estimated based on an i nflation 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 th ere is no economic impact to fuel-switching. Projec ts 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 2011mgm11-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 Gas Error! 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 G ases ........... Error! Bookmark not defined. Comparison of HAP and HAP Surrogate Emissions from Com bustion
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 Environmen tally and Economically Beneficial Opportunity–EPA Landfill Methane Outreach Pr ogram (December 2009)

Tables

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

................................................... ........ 5 2. Emissions Comparisons ............................

................................................... ............... 6 3. Comparisons to the Gas 1 Fuel Specification ........

................................................... .. 7mgm11-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
CH 4 methane
CO carbon monoxide EPA U.S. Environmental Protection Agency GCV gross calorific value gr grain
H 2 S hydrogen sulfide HAP hazardous air pollutant HCl hydrochloric acid HHV higher heating value lb pound LFG landfill gas MACT maximum achievable control technology μg/m 3 micrograms per cubic meter
MMBTU million British thermal units
NESHAPS National Emission Standards for Hazardous Air Pol lutants NG natural gas PM particulate matter ppmv parts per million by volume RG refinery gas
scf standard cubic feet
SO 2 sulfur dioxidemgm11-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 ident ifying 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) r ule 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 stand ards rather than to emission limits
under the Boiler MACT rule. As described in this re port, sufficient data were readily available to EPA to establish that LFG is comparable to n atural gas (NG) and refinery gas (RG) with regard to HAP emissions. Emissions and raw g as analysis data support the
conclusion that LFG should be classified as a Gas 1 fue l. 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 publishe d by EPA demonstrating that average LFG mercury levels are consistently less than the fue l specification proposed to establish other process fuels as Gas 1 fuels.


## Introduction

On March 21, 2011, the U.S. Environmental Protection Agen cy (EPA) published the National Emission Standards for Hazardous Air Pollutants (NESHAPS) for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heater s, Final Rule, under 40 Code of Federal Regulations (CFR) Part 63 subpart DDDDD. The rule commonly is ref erred 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 publi shed proposed rules and updated fuel specification for Gas 1 demonstration. Although EPA has proposed removing the hydrogen sulfide requirement from the fuel specific ation that was in the March 21 rule, our previous conclusions, rationale and supporting data reg arding the hydrogen sulfide requirement have been retained in this revision in su pport of the proposed removal of the requirement.

The proposed rule requires owners of boilers and pr ocess heaters (referred to as “boilers” in this report) to control emissions of hazardous air poll utants (HAPs) to specified levels. An alternative requirement is established for boilers fir ed by NG or RG (defined as “any gas that is generated at a petroleum refinery and is combus ted”). 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, in cluding LFG, are referred to as Gas 2 units. A Gas 2 unit must meet the specified emissio n limits unless it can be demonstratedB OILER MACT F UEL C LASSIFICATION R EVIEW FOR L ANDFILL G AS

mgm11-Waste Management/boiler mact/WM Final Boiler Reconsideration comments 2 ES041211132050MGM that the gas fuel meets a specification 40 micrograms pe r cubic meter (μg/m 3 ) of mercury or less, in which case a work practice standard can be insti tuted 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 Bo iler MACT are as follows:

• Mercury

• Dioxins/furans

• Particulate matter (PM) (as a surrogate for non-mercury m etals)

• Hydrochloric acid (HCl) (as a surrogate for acid gases)

• Carbon monoxide (CO) (as a surrogate for non-dioxin or ganic air toxics)

The purpose of this report is to compare the propert ies of emissions from boilers fired by LFG, specifically with respect to the Boiler MACT em ission parameters, to establish that
LFG is not different from the Gas 1 fuel sources and t hat 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 in clude documents identified in an online docket search (Docket Number EPA-HQ-OAR-2002-0058) by C H2M 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 d ocuments posted between that time and December 18, 2011.

In the following sections, first the general propert ies and HAP precursors of the recognized Gas 1 fuels (NG and RG) are compared to LFG, and then th e emissions from these gases are similarly compared. The properties of the recognized G as 1 fuels and LFG are then compared to the fuel specification requirements for e stablishing a gas that otherwise would be considered a Gas 2 as a Gas 1 gas. Finally, conclusion s are presented as to how well the data support the case that LFG should have been conside red as a Gas 1 under the Boiler
MACT. 

## Comparison of Landfill Gas to Refinery Gas and Natu ral Gas for General Properties, HAPs, and HAP Surrogates

Landfill Gas
The general properties of LFG have been well establis hed 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 anaerobi c 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 di oxide and LFG typically is saturated with water vapor , with trace contaminants inc luding volatile organic compounds, chlorinated organics, and H 2 S. The methane percentage can vary from 40 to 60 percent depending on several factors, including waste composit ion (carbohydrate and cellulose content and pH in the landfill). LFG has an average high er heating value (HHV) of approximately 500 British thermal units (BTUs) per standar d cubic feet (scf) (about half the HHV of NG).B OILER MACT F UEL C LASSIFICATION R EVIEW FOR L ANDFILL G AS

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 b y LFG in the United States (EPA, 2009).

As part of the regulation of landfill emissions, EPA u ndertook 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, incl uding 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 b oiler 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 gen erated at a petroleum refinery and is combusted. Refinery gas includes NG when the NG i s 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 combust ed in any proportion with gas generated at a refinery.”

This definition includes a wide variety of gas compo sitions under the “any gas” characterization. In fact, the American Petroleum Institu te (API) recognizes 62 different types of RGs (API, Appendix Table 2-1, 2009) and has publi shed a table of the typical compositions. The constituents of the various RGs in clude a hydrogen content of up to 88-percent, methane and other (C1 to C4) hydrocarbons fro m 0 up to 94 percent, and H 2 S from 0 up to 45 percent by volume, as well as other con stituents including ammonia, carbon dioxide, and C5 and C6 hydrocarbons, that vary widely am ong 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 H 2 S by volume. “If refinery gas containing 1- to 2-percent
H 2 S is burned in uncontrolled boilers, sulfur dioxide (SO 2 ) emissions from refineries will be quite large. It appears that before the most recent tig htening of the regulations in Southern California (in 1994 and 1996), refinery gas contained on the o rder of 100 to 200 ppmv.”



### Natural Gas

NG is defined as an odorless, colorless, tasteless, n ontoxic clean-burning fossil fuel. NG is largely methane (CH 4 ), a naturally occurring gas that also can be produced b y coal gasification. NG is created thermogenically at great temp erature and pressure from buried organic material. In addition to CH 4 , NG typically contains H 2 S and other sulfur compounds, ethane, propane, butane, pentane, hexane, and helium.B OILER MACT F UEL C LASSIFICATION R EVIEW FOR L ANDFILL G AS

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, r evisions 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 “p ipeline natural gas” in § 72.2
also limit the H 2 S 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 “pip eline 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 ot her organic compounds that can be controlled by boiler operational practices. EPA has re cognized this by proposing a work practice standard for dioxins/furans rather than a speci fic emission limit. As such, there are no appropriate comparisons of fuel constituents for th ese 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 gase s 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 rele vant to the five HAP and precursor parameters covered under the Boiler MACT are as follow s:

• Total mercury

• Other HAP metals

• Chlorinated compounds

RG and NG automatically are considered “Gas 1” fuels by t he Boiler MACT; thus, boilers using them are not governed by the more difficult re quirements of “Gas 2” burning units.

Table 1 provides a summary of the ranges of available data fo r the HAP precursors listed previously in the two Gas 1 fuels, compared to LFG. N o 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) perf ormed a study of mercury in NG
and found that concentrations in NG extracted in the co ntinental United States typically were less than 0.2 μg/m 3 . 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 compo unds in LFG. The most recent compilation by EPA is contained in the BID (EPA, 2008) fo r the most recent update of the AP-42 document, which establishes default emission fact ors for LFG . Table 1 lists the sums of the mean concentrations of all chlorinated trace comp ounds reported in the BID (EPA, 2008). Although other chlorinated compounds might be pre sent, this total is a rough approximation of the chlorinated compounds likely to b e present in LFG, and in fact, is used by at least one air pollution control district, San Di ego County, California, to derive the default HCl emission factor used to determine complian ce with emission limits.B OILER MACT F UEL C LASSIFICATION R EVIEW FOR L ANDFILL G AS

mgm11-Waste Management/boiler mact/WM Final Boiler Reconsideration comments 5 ES041211132050MGM 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 lan dfills 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 rep orted in Table 1 was noted as an outlier in the BID, but is still only a fraction of t he fuel specification for mercury as
established for “other Gas 1” fuels as described later i n this report. For the other parameters reported in Table 1, the lack of data for both NGs and RG prevent a comparison with LFG.B OILER MACT F UEL C LASSIFICATION R EVIEW FOR L ANDFILL G AS

mgm11-Waste Management/boiler mact/WM Final Boiler Reconsideration comments 6 ES041211132050MGM 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/m 3 < 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 mercu ry. 3. Total of all chlorinated compound mean concentration s 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 t he Boiler MACT, but they are products of combustion of HCs and other organic compounds that can b e controlled by boiler operational practices. As such, there are no appropriate comparisons of fuel constit uents. μg/m 3 = 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, an d LFG. In all cases, the emissions are for the gas used as boiler fuel. In the first th ree columns of Table 2, all of the emissions reported are from the Boiler MACT Floor Memo Appendi x 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) di d report ranges for two of the other three HAPs and HAP surrogates, PM and CO. A pre vious EPA study in 2007 (EPA/600/R-07/043) reported two tests for HCl from LFG-fuel ed boilers. Thus, numerous data were available for the comparison of LFG to the estab lished Gas 1 fuels for all of the HAP and HAP surrogate parameters except HCl, for whic h 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 ran ges for one or both of the recognized Gas 1 fuels.B OILER MACT F UEL C LASSIFICATION R EVIEW FOR L ANDFILL G AS

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%O 2 ) 0.08 to 56 9.0e-3 to 184 no data 2.0e-4 to 0.02

Dioxin/Furan (Total Mass) ng/dscm

(7% O 2 ) 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, a nd LFG values are from MACT Floor Memo Appendix C spreadsheet (Docket Number EPA-HQ-OAR-20 02-0058-1388.1) 2. HCL data for LFG combusted in boilers were reporte d in Field Test Measurements at Five Municipal Solid Waste Landfills with Landfill Gas Control T echnology Final Report, EPA/600/R-07/043, April 2007, Table 4-12 (EPA 2007). Data was converted to lb/MM BTU 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 CH 4 inlet gas versus flue gas; conversion to flue gas basis would reduce by approximate factor of 20

Ranges reported are above detection limits. However, al l LFG results from the MACT Floor memo spreadsheet had DLL flag lb/MMBtu = pounds per Million British thermal units ppm = parts per million O 2 = oxygen ng/dscm = nanogram per dry standard cubic meter WM = Waste Management, Inc.



## Comparison of Landfill Gas, Refinery Gas, and Natur al Gas to the Gas 1 Fuel Specification

In the preamble to the proposed Boiler MACT rule, EP A explains () that:

“EPA has reexamined the fuel specification and agrees tha t the key contaminant for demonstration of comparability from a HAP perspectiv e is Hg and that the H2S fuel specification that was finalized does not provide a dir ect indication of potential HAP from combustion of gaseous fuel. Accordingly, the EPA is p roposing a fuel specification based only on the Hg level in the gaseous fuel, and that level is t he same level that the EPA included in the March 2011 final rule.”

Under §63.7521 (f) of the proposed reconsidered Boiler M ACT rule, “To demonstrate that a gaseous fuel other than natural gas or refinery gas quali fies 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 us er certifies that the mercury fuelB OILER MACT F UEL C LASSIFICATION R EVIEW FOR L ANDFILL G AS

mgm11-Waste Management/boiler mact/WM Final Boiler Reconsideration comments 8 ES041211132050MGM specification limit will never be exceeded. The Hg l evel in the March 2011 final rule is 40 micrograms per cubic meter.

Table 3 provides a comparison of the readily available data f or total mercury in LFG to comparable data for NG and RG. As noted above, EPA’s 2008 ef fort to establish an appropriate default parameter for Hg in LFG found no ins tances 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/m 3 40 < 0.2 “typical” ( note 1 ) no data 0.01 to 7.85

H 2 S 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 H 2 S in refinery gases meeting the boiler MACT definitio n includes up to 45% H 2 S, per API 2009.

μg/m 3 = 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 conclus ion that the mercury level in LFG consistently is much lower than the Gas 1 fuel spe cification level of 40 μg/m 3

, 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 it s characterization as a Gas 1 fuel.

2. A comparison of the readily available data for LFG-only fu eled boiler emissions indicates that the ranges of reported results for merc ury, PM, CO, and dioxin/furans are within or below the ranges of these parameters for on e or both of the recognized Gas 1 fuels, NG and RG. No HCl data were available for RG for c omparison to LFG. However, the few HCl emissions data available from LFG-fueled bo ilers (0.00321 to 0.00398 pounds per million British thermal units [lb/MMBT U]) 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 g reenhouse gas emissions compared to LFG. LFG has been shown to produce lower nitrous oxide emissions than NG, and using LFG lowers fossil carbon dioxide emissi ons as compared to NG or RG.B OILER MACT F UEL C LASSIFICATION R EVIEW FOR L ANDFILL G AS

mgm11-Waste Management/boiler mact/WM Final Boiler Reconsideration comments 9 ES041211132050MGM 4. Mercury levels in raw LFG from 15 landfills reported i n EPA’s BID (2008) indicated a range of total mercury orders of the same order of ma gnitude as the available data for mercury in NG. A comparison of the constituents of r aw 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 ru le on sweetened, pipelinequality NG. However, RG typically contains much higher levels of H 2 S than the Gas 1 fuel specification in that rule. LFG should not be h eld to a higher H 2 S standard than RG for qualification as a Gas 1 fuel, especially consideri ng that H 2 S is not a HAP or a HAP precursor or a surrogate for HAP emissions.

6. The data forH 2 S 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 Age ncy 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 Transpo rtation Studies.
December 1.

Eddinger, Jim (U.S. Environmental Protection Agency [EPA]). 2005. Memo regarding: “Re-Revised MACT Floor Analysis for the Industrial, Co mmercial, and Institutional Boilers and Process Heaters National Emission Standards for Hazardou s 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, Commerc ial
Institutional Boilers and Process Heaters National E mission Standards for Hazardous Air Pollutants–Major Source . January.

ERG (A. Singleton). 2010. MACT Floor Analysis (2010) for the Industrial, Commercia l, and
Institutional Boiler and Process Heaters National Em ission 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. Merc ury 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 Techno logy 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 Landfi lls . EPA/600/R-08-116. September.B OILER MACT F UEL C LASSIFICATION R EVIEW FOR L ANDFILL G AS

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 Oppor tunity . Accessed online at: http://www.epa.gov/lmop/ . Copy of brochure is attached.

U.S. Environmental Protection Agency (EPA). 2011. Exce l 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 Instit utional Boilers and Process Heaters; Final Rule (Docket ID No. EPA-HQ-OAR-2002-0058); Petition f or Reconsideration. Letter from Eli Brill, Sr. Legal Counsel, to Lisa P. Jackson, EPA Administrator. May 19.

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February 21, 2012

Via Electronic Transmission: jones.toni@epa.gov a-and-r-Docket@epa.gov Attention: EPA Docket ID. No. EPA-HQ-OAR-2003-011 9 Faison.george@epa.gov Rcra-docket@epa.gov Attention: EPA Docket ID. No. EPA-HQ-RCRA-2008-03 29 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 comment s on the Agency’s proposed
Commercial and Industrial Solid Waste Incineration Units: Reconsideration (hereinafter the “CISWI Reconsideration Rule”) and the Proposed Amen dments: Non-Hazardous Secondary Materials Rule (hereinafter the “NHSM Rule Amendmen ts”) 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 ru lemakings in one Federal Register Notice, and the close interrelationship of the two rules fo r the regulated community. As North America’s leading provider of integrated environmen tal solutions, WM is uniquely interested in ensuring that the Agency’s final CISWI Reconsiderat ion Rule and NHSM Rule Amendments reflect and support ongoing and newly evolving effo rts to reduce, reuse and manage waste, while recovering valuable resources and producing c lean renewable energy.

WM is the largest provider of comprehensive waste a nd environmental services in North America, as well as North America’s largest municip al waste recycler and a leader in wastebased energy technologies. Headquartered in Housto n, Texas, the company serves over 20 million customers with environmentally sound manage ment of solid wastes and transformation
of wastes into usable resources. WM has been a con stant advocate of landfill gas as a renewable alternative fuel, and as of the end of 20 11 operates 131 landfill gas-to-energy projects that produce enough renewable energy to po wer nearly half a million homes.

### 2

Additionally, WM’s wholly-owned subsidiary, Wheelab rator Technologies, Inc. (“WTI”), owns or operates 17 waste-to-energy plants and five indepen dent 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 a ir pollutants associated with coal use and also offset over 3.5 million tons of carbon dioxide equi valent (CO 2 e) emissions each year. One of these independent power plants operated by WTI, a b iomass plant that burns landfill gas, yard waste and tires to produce electricity, will be sub ject to the CISWI Reconsideration Rule.

Beginning in 2010, WM focused the company’s investm ent strategy on broadening the scope of
materials we recover from waste streams and transfo rm into resources such as compost, biogas, renewable fuels and green chemicals. Failu re to harmonize the CISWI Reconsideration
Rule and NHSM Rule Amendments with national materia ls management, renewable energy and greenhouse gas reduction goals will undermine signi ficant sustainability investments by WM, other companies, local governments, and federal age ncies. In addition, the imposition of any new and unreasonable regulatory burdens upon the co mbustion 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 Mu nicipal Solid Waste Landfills, 40 C.F.R. Part 60, Subpart WWW (the “Landfill NSPS”) and the Natio nal 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 CI SWI Reconsideration Rule and NHSM Rule Amendments, incorporating by reference WM’s Pe tition for Reconsideration of the Standards of Performance for New Stationary Sources and Emission Guidelines for Existing
Sources: Commercial and Industrial Solid Waste Inci neration Units (Docket ID No. EPA-HQ-OAR2003-0119-2550, comments filed on July 15, 2011 (do cketed at EPA-HQ-OAR-2003-0119-3355), and WM’s Petition for Administrative Stay Pending J udicial 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 CI SWI Rule promulgated in

1 Additionally, WM offers these comments without waiv er of any issues raised through its Petitions for R eview of the CISWI and NHSM rulemakings, at Docket No. 11-11 49 and Docket No. 11-1148 in the U.S. Court of Appe als for
the District of Columbia Circuit.

### 3

March of 2011 2 focused on EPA’s removal of the definition of “con tained gaseous material” from the final CISWI Rule, and the significant chan ge that action made to EPA’s established interpretation of the scope of Section 129 of the C AA, 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 sug gested 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 si gnificant doubt on the continued vitality of its past interpretation of “contained gaseous ma terials” that may be considered solid waste, and suggested that the combustion of gaseous emissi on 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” simp ly 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 a t 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, EP A has developed a comprehensive regulatory structure to govern the collection, cont rol 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 co ntained gaseous material from CISWI and statements in the NHSM rulemaking record threaten t o undercut the existing regulatory scheme established under the CAA by potentially sub jecting 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 g oals to encourage domestic, renewable

energy sources.

Notwithstanding these actions, it is clear from a r eview of the CISWI rulemaking record that the Agency did not contemplate the possibility that lan dfill 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 ga s 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 unit s were addressed. Likewise, CISWI did not include a subcategory that would apply to combustio n 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 o perations 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. Re g. 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 wit h strict emission limits. Without an end market for the sale or transfer of gas, WM and othe r 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 Landfi ll 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 the rmal oxidizers (about $412 million) to exceed
the total EPA estimated costs identified in the CIS WI 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 pe r year. Such costs would be a significant financial burden for WM, and would be ruinous to th e 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 Re source Conservation and Recovery wrote a letter to WM, to provide clarification of Agency st atements made in the Response to Comments Document indicating a change in interpretation of w hat constitutes a “contained gaseous
material.” The Office Director’s letter stated tha t the Agency has not changed its previous positions regarding what constitutes a “contained g aseous material,” nor had it changed its previous statements and interpretations concerning landfill gas. The letter affirmed that the Agency’s previous statements and interpretation rem ain effective.

While WM is very appreciative of the Agency’s clari fying letter, we believe that it is imperative that the Agency confirm in both the CISWI Reconside ration Rule and the NHSM Rule
Amendments the longstanding definition of “solid waste” as ex tending only to “contained gaseous material,” and to further clarify that the combustion of gaseous emission streams, including landfill gas, does not constitute the co mbustion of solid waste subject to the CISWI
Rule.

WM supports the explanations in the CISWI Reconside ration and the NHSM Rule Amendments preambles that affirmed the language in the WM comf ort 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 cons titutes “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 o ther management of a solid waste. EPA should add a statement to both preambles that its c larification with regard to combustion of uncontained gases, including landfill gas, supersed es the ambiguous and confusing NHSM Rule Response to Comments Document. Despite EPA’s clari fying 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 reinse rt 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. Howev er, 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 subsequ ent to the proposal of the CISWI
Reconsideration Rule the March 21 2011 CISWI Rule b ecame effective, 3 EPA must actually reinstate the definition of “contained gaseous mate rial” in the regulatory language of the CISWI
Reconsideration Rule.

Notwithstanding the proposed inclusion of the defin ition of “contained gaseous material” in the CISWI Reconsideration Rule, the Agency has not prop osed to reinstate the definition of “solid waste” within CISWI. As a result, the term “contai ned 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 incinerat or, solid waste incineration unit, and Wasteburning kiln. In each of these definitions, the ru le describes the term “solid waste” by saying “(as that term is defined by the Administrator in 4 0 CFR part 241).” In 40 CFR part 241.2 the
term solid waste is defined as “Solid waste means t he term solid waste as defined in 40 CFR 258.2.” The definition in 40 CFR part 258.2 is ide ntical 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 fr om a wastewater**  **treatment plant, water supply treatment plant or ai r pollution control**  **facility and other discarded material, including so lid, liquid, semi-solid, or**  **contained gaseous material resulting from industria l, commercial,**  **mining, and agricultural operations, and from commu nity activities, but** 
**does not include solid or dissolved materials in do mestic sewage, or solid**  **or dissolved materials in irrigation return flows o r 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 “co ntained gaseous material” across both the CISWI Reconsideration Rule and the NHSM Rule, the t wo 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 gase ous 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 bot h

3 It is our understanding that the Agency used the o riginal CISWI rule text, promulgated in 2000, as th e base text for the CISWI Reconsideration Rule. However, EPA’s Delay Notice was vacated by the District Court, re ndering the March, 2011 CISWI rule currently effective.

### 6

rulemakings will enhance transparency and clarity f or the regulated community, and further the Agency’s goal of developing clear, readable and com prehensible rules.



### EPA Should Clarify the Provisions of CISWI that Ref erence Municipal Solid Waste
Combustion

WM requests that EPA clarify the extent to which CI SWI may apply to municipal solid waste combustion units. In this context, WM notes that b oth the final rule and the Reconsideration proposal include changes that are confusing and pot entially 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 co mbustion units. See, for example, 40 CFR Part 60 Subpart Ea, Standards of Performance for Mu nicipal Waste Combustors for Which Construction is Commenced After December 20, 1989 a nd on or before September 20, 1994; 40 CFR part 60 Subpart Eb, Standards of Performance fo r 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 Un its for Which Construction is Commenced After August 30, 1999 or for Which Modifi cation or Reconstruction is Commenced After June 6, 2001; and 40 CFR Part 60, Subpart EEE E 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 o n or After June 16, 2006 (“OSWI”). 4
Under the current regulations identified above, lar ge, 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 t hat 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 CA A 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 E a, Eb, and AAAA and their Emission Guidelines counterparts), or (2) that combust great er than 30% municipal solid waste or refusederived fuel, and had the capacity to burn less th an 35 tons per day of municipal solid waste. Subsequently, EPA promulgated the OSWI standards, w hich 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 previo usly applied to municipal waste combustion units combusting greater than 30% munici pal solid waste and with the capacity to combust less than 35 tons per day of municipal soli d 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 st andards governing municipal solid waste combustion, because section 60.2020(c) does not ref erence OSWI, and it does not expressly maintain the 30% municipal solid waste exemption.

In the CISWI Reconsideration Rule proposal, EPA ide ntifies 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 correct ion creates an ambiguity within the rule and does not provide an opportunity for review of t he proposed revision. Further, addition of the “municipal solid waste” definition, without add itional 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 no t apply to any municipal solid waste combustion unit that is regulated under any o f the municipal waste combustor standards, including OSWI. Further, EPA should cla rify that CISWI does not apply to any combustion unit that is otherwise exempt from the m unicipal waste combustion standards because it is subject to a federally enforceable pe rmit 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 re vision 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); subpar t Eb of this part (Standards of Performance for Large Municipal Waste Combustors); subpart Cb of this part (Emission Guidelines and Compliances T ime for Large Municipal Waste Combustors); subpart AAAA of this part (Stand ards of Performance for Small Municipal Waste Combustion Units); subpart BB BB of this part (Emission Guidelines for Small Municipal Waste Combustion Uni ts); subpart EEEE of this part (Standards of Performance for Other Solid Wast e 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 standar ds identified in paragraph (c)(1) above on the basis that it is subject to a f ederally enforceable permit condition limiting the combustion of municipal soli d 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 munic ipal solid waste**  **combustion units identified within 40 CFR §60.2020( c), and does not include internal combustion**  **engines, gas turbines or other combustion devices t hat 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 sol id waste combustion standards. Additionally, the clarification with respect to lan dfill gas fired combustion units is consistent with existing CAA Section 129 municipal waste combu stion unit standards, and will appropriately reflect EPA’s long-standing interpret ation 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 i ts Application of CISWI Requirements to Units that Cease Burning Solid Wast e

The CISWI Reconsideration Rule preamble at (76 FR 8 0459) states – “For sources that cease burning solid waste, the effective date for the was te-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 c omply 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 th at have ceased to meet the fundamental premise for the CAA’s regulation of solid waste-bur ning units – that they are actually burning solid waste. We have not seen such a requirement i n other Section 129 standards for MSW or hazardous waste incinerators. The Agency is provid ed ample advance notice of the fuel switch with the requirement that a source must submit an a dvanced notification of the date of the waste-to-fuel switch. Further, sources anticipatin g a fuel switch must remain in continuous compliance with CISWI until the effective date of t he switch from waste-to fuel. Both of these provisions provide abundant safeguards that units b urning solid waste will be subject to protective environmental requirements designed for such units. Given the stringent requirements of the CISWI Reconsideration Rule, uni ts are highly unlikely to engage in frequent fuel-switching without first obtaining a comfort le tter or other Agency determination that the material they intend to burn is considered a legiti mate fuel.

We respectfully recommend that the Agency strike th e clause “or has combusted in the preceding 6 months” from the CISWI definition in pa rts 60.2265 and 60.2875. We further recommend that at part 60.2710 (a)(2) the Agency st rike “you are subject to the requirements of this subpart at least 6 months following the las t 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, Wheelabrato r Technologies Inc. (WTI), is a member of the Energy Recovery Council (ERC) and participat ed in the development of the ERC
comments to the CISWI Reconsideration and NHSM Amen dment Rules. WM endorses ERC’s comments and incorporates them by reference.

In response to EPA’s March 21, 2011 notice of recon sideration of CISWI, WTI submitted
additional information for EPA’s consideration in r evising 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 co mbination with both NHSM and solid waste
derived biomass fuels. This information was submitt ed 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 el ectricity to the local utility. The boiler is fueled by a mixture of municipal solid waste includ ing yard waste and tires, non-municipal biomass including clean cellulosic biomass (agricul tural waste and forest debris), biomassderived solid waste, and landfill gas. The facilit y typically combusts between 30,000-40,000 tons of tires annually. Tires are received whole a nd chipped on site (belts are not removed) or as direct deliveries of chipped tires. Tires may o r may not be derived from tire collection programs. Chipped tires are fired simultaneously w ith 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 g as control and a fabric filter. The SDA was designed for the control of SO2 associated with com bustion of tires. WTI conducted a variability analysis of the SO2 hourly data to dete rmine an achievable SO2 emission limit for cocombustion of tires and biomass fuels. The finding s are summarized below.

WTI compiled hourly average CEM SO 2 outlet data in ppm @7%O 2 for the period of January 1, 2011 to June 6, 2011. Three different types of aver ages 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 da y rolling average SO2 CEM compliance option in CSIWI rule, 2) 24 hour block average cons istent 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 confidenc e 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 t he variability analysis demonstrates the revised solid fuel ERU SO2 limit of 7.3 ppm 7% O2 i s 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 derive d fuel based on the 99% UL would be 48 ppm 7% O2 using the 30 day rolling average alternat ive. 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 fi red 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 reconside ration of the sub-categorization approach.



### EPA Should Correct the CISWI Data Base for Energy R ecovery Units

WTI noted that EPA had made adjustments to the CISW I ERUs population based on supplemental data submitted by the Biomass Power As sociation. 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 woo d. 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 remed y this error. The Wheelabrator Shasta Energy facility no longer combusts any non hazardou s secondary materials (NHSM) that may

### 11

now be considered solid waste under NHSM rule and h as not done so for the past two years. This facility will continue to combust non waste ma terials 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 i n well operated and maintained facilities equipped with the best technologies, EPA’s affirmat ive defense concept essentially presumes
that malfunctions never occur. Under the rule as w ritten, any emissions occurring above the limits set using emission data **obtained exclusively during normal operation**  (emphasis added) are considered deviations, regardless of the underl ying 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 presume d 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 star tup 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 p eriods 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 al l the varying types of malfunction-related events, EPA should adopt work practice standards fo r malfunction periods.

Malfunction work practice standards could include l imitations on the duration to ensure quick and effective corrective action is taken, and if th e malfunction cannot be quickly resolved the unit would be shut down for repair. Facilities sho uld still be required to submit a notification of
a malfunction excess emission event with the underl ying root cause analysis. If EPA or the administering agency decides the excess emission ev ent was not a malfunction, it would then be reported as a deviation of the limit and enforce ment action, including imposition of penalties, would still apply consistent with the de viation 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 t hat 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 de fense eligibility criteria in 40 CFR § 60.2685(a) as follows to make it more reasonable an d eliminate such vague language:

“To establish that an exceedance of an emission lim it or operating standard was the
result of a malfunction and therefore not a deviati on 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 i n operation if possible in a manner consistent with safety requirements and good air po llution 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 resp onse to the excess emission event were documented in signed contemporaneous log. (b)... ”

We also believe the notification requirements shoul d 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 dir ect, 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, c orrective action taken and root cause analysis. Often the initial notification will incl ude enough information for the regulators to
confirm a malfunction meets the criteria. For exam ple, a lightning strike on a utility interconnect transformer that causes a temporary fa cility 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 f or 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 consi dered whether emission standards must apply at all times, including during periods of sta rtup, shutdown and malfunction (SSM). The Agency’s evaluation stems from a 2008 court decisio n (Sierra Club v. EPA, 551 F.3d 1019(DC Cir. 2008)) related to SSM exemptions contained in the G eneral 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 CA A Section 129. We therefore believe that EPA is over-stepping its authority by voiding longs tanding category-specific and Section 129 SSM provisions.

Nonetheless, in the absence of separate startup/shu tdown specific limits, we do support EPA’s provisions within the CISWI Reconsideration Rule to eliminate the O 2 correction bias during startup and shutdown periods when high levels of ex cess air are encountered. We are concerned, however, that eliminating the O 2 correction for only a four-hour startup and a onehour shutdown period (derived from a single coal fi red unit) is not sufficient for all the CISWI unit types and technologies. Further, elimination of the O 2 correction should be applied to all CEM based emission limits during startup and shutdo wn periods.

### 13

As an alternative to hourly limits for startup/shut down periods EPA could incorporate the startup/shutdown definitions in the related propose d Boiler MACT Reconsideration rule to define the period when the O 2 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. I n 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 f**  **uel combustion in unit** .” We believe 25% load should be a nominal requirement that may be ad justed to accommodate plant specific technology differences. For example, gaseous and l iquid fuel burners have lower percent
thresholds than solid stoker boilers or fluidized b ed combustors. Additionally, the term “load” should be defined as “maximum design load” to elimi nate 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 sh ould 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 a nd State regulators to specify the numerical percent values in their State 129/111d Plans approp riate 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 perio d when only natural gas or No.2 fuel oil “auxiliary” fuels are being fired to safely warm th e 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 incomp lete combustion of solid waste. Facilities should not be penalized or otherwise dis couraged 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 s olid waste fuel combustion control system.



### WTI Supports the Agency’s CO CEM Option for Demonst rating 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 potentia l CISWI units are required to operate CO CEMS in accordance with Title V and/or state requir ements.



### WTI Supports EPA Revisions to the Continuous Monito ring Provision for Large

ERUs

WTI supports EPA’s decision to eliminate the mandat ory use of particulate matter CEMS (PM CEMs) for continuous particulate monitoring. EPA h as 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 Sect ion 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 prac tical purposes a PM CEMs. Importantly PM
CPMS have not been validated on solid waste inciner ation units as required by CAA 129 (c). PM CPMS requires the use of light scatter, light scint illation 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 measu rement 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 (CO MS) technology combined with other parameter monitoring (e.g., ESP power levels, bagho use leak detectors) are sufficient to maintain peak efficiency of particulate control dev ices 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 petiti on 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 demon strating legitimacy, including recordkeeping requirements to document sufficient p rocessing and conformance to the legitimacy criteria. WM commends EPA for developin g the process, and for recognizing therein that it is appropriate to balance the legitimacy fa ctors with other relevant factors when making a non-waste determination. EPA’s legitimacy analys is should focus on the heating value of the fuel product, whether material management and proce ssing is conducted in a safe and protective manner, and whether the material’s use a s a fuel will extract value from the material and reduce landfill disposal. In particular, extre mely rigid adherence to contaminant comparisons, without consideration of other relevan t factors, may unfairly eliminate otherwise viable and environmentally beneficial fuels. WM re commends that the Agency also clarify that the Regional Administrators should balance the legi timacy 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-Wa ste 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 i n tire collection programs. The Agency has also recognized that contractual arrangements c an ensure that scrap tires are not discarded and are handled as valuable commodities through arr ival 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. Purchas ers 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 informa tion 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 comparabl e contaminant levels found in clean C&D
wood versus the solid fossil fuels that it would re place. EPA’s preamble to the proposed NHSM Rule Amendments described the typical clean C&D woo d processing operations and the likelihood that the fuel product meets the rule req uirements 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, t reated wood containing contaminants such as arsenic and chromium, metals a nd other non-wood materials), and is size-reduced prior to burning likely meets t he 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 rulemak ing 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 CI SWI unit definition create considerable compliance risks for combustion sources burning non -hazardous secondary materials as fuels
without sufficient comfort that EPA considers the m aterials to be legitimate fuel. The definition of CISWI unit (76 Fed. Reg. 80501) under §60.2265 s tates that “if the unit burns materials other than traditional fuels as defined in §241.2 that ha ve been discarded, and you do not keep and produce records as required by §60.2175(v), the mat erial is a solid waste and the operating unit a CISWI unit.” The record keeping requirements req uire records of how the secondary material meets each of the legitimacy criteria, how the oper ations 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 th ese 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 und er the CAA. As an initial matter, a
combustion unit that does not burn solid waste cann ot be categorized as a CISWI unit and should not be subject to its provisions, recordkeep ing or otherwise. Further these provisions would create a presumption of CISWI applicability a s 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 addres sing such recordkeeping violations. Automatic CISWI applicability is not an appropriate result for such a violation.



### EPA Should Clarify that Comfort Letters Issued by t he 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 caref ully 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 sour ce may rely on the comfort letters to meet its recordkeeping requirements. We respectful ly urge the Agency to address this issue in
its final NHSM Rule Amendments and on its rulemakin g web site. EPA should clarify that combustion sources burning a secondary material fue l that meets the processing and legitimacy
criteria circumstances as described in an EPA “comf ort letter” may use the letter to meet the recordkeeping requirements of §60.2175(v) and §63.7 555(d)(2). Further, EPA should clarify that no additional petitions for a non-waste determ ination from either the Regional Administrator or Administrator are necessary where the secondary material fuel meets the
circumstances described in the comfort letter. Fai lure to adequately clarify the status and use of comfort letters to demonstrate fuel legitimacy d eterminations will create enormous disincentives to recovering energy value from mater ials which otherwise would be landfilled.



### EPA Should Clarify that Secondary Material Fuels Ma y be Processed from Municipal Solid Waste

The NHSM Rule is clear on its face that secondary m aterials that have been discarded may be processed into legitimate non-hazardous secondary m aterial 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 res ponded 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 und er RCRA. EPA has clearly promulgated the NHSM Rule precisely for the purpose of defining sol id waste, and for providing a rigorous framework under which solid wastes may be sufficien tly 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 overs ight over the use of secondary materials as fuels so that it may prevent sham recycling or comb ustion 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 sol id waste stream as sources of valuable feedstock. These material streams will likely incl ude 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 pa rt 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 f uel feedstock, is eligible for evaluation under the NHSM Rule legitimacy framework. WM has appende d a legal analysis at Attachment B to assist in this effort.

Waste Management appreciates the opportunity to sha re this additional information with the Agency, and looks forward to working with you as yo u 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 fee l 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 proce ssed from municipal solid waste is a legitimate fuel, rather than a solid waste.

1. Section 129 requires EPA to set standards for categories o f 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 inc lude (in pertinent part) “a distinct operating unit of any facility which combusts a ny solid waste material from commercial or industrial establishments or the general publ ic (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) enc ompasses different types and sources of solid waste, but is clear that only a unit tha t combusts “solid waste” would be covered by Section 129 standards.

2. Section 129(a) identifies specific categories of solid wa ste combustion for which EPA is required to establish standards, including municipal waste, h ospital waste, medical waste, commercial and industrial waste, and other categories of s olid waste incineration units. By the very structure and purpose of Section 129, these cat egories of combustion units would only be subject to Section 129 standards if they are first dete rmined 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 establ ish emission standards for solid waste incineration units” and that Section 129 further defines se veral “ 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 establis hes 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 S ection 129 addresses solid waste

6 The definition of “solid waste incineration unit” incl udes four express exemptions which are not relevant for this purpose: (1) units requiring a permit under 42 U.S.C. §6925; (2) m aterial recovery facilities which combust waste for the primary purpose of recovering metals; (3) small pow er production facilities or cogeneration facilities that combust homogenous waste for the production of electric e nergy or steam; and (4) qualifying air curtain incinerato rs that burn only wood wastes, yard wastes and clean lumber

.

### 22

incineration units that the type of municipal waste at iss ue is MSW”). Likewise, EPA’s promulgated regulations governing municipal waste combustion r efer 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 w aste” 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 s tandards, including units that combust municipal waste, Section 129 does not define “solid w aste.” 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 co nsolidated 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 be ing regulated either under CAA section 112 categorical standards for fuel burning units, or unde r CAA Section 129
standards for “solid waste incineration units.” The rule making 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 b e 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 combu sting any “solid**  **waste” at all must be regulated as a “solid waste i ncineration unit,”**  **regardless of the function of the combustion device . If a non-hazardous**  **secondary material (also referred to as a “secondar y material” in this**  **rulemaking) is not a” solid waste” under RCRA, then a unit combusting**  **that material must be regulated pursuant to CAA sec tion 112 if it is a**  **source of HAP. Alternatively, if such secondary ma terial is classified as a**  **“solid waste” under RCRA, then a unit combusting th e material must be**  **regulated under CAA section 129, unless it is withi n 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 a nd 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 was te” under RCRA, EPA notes in the NHSM Rule preamble that “EPA has not promulgated detail ed regulations defining solid waste for purposes of the subtitle D (non-hazardous) pro grams.” 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 em ission standards under CAA sections 112 and 129.” Id . Finally, EPA makes it abundantly clear that its def inition 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 lan guage in Section 129. In responding to a commenter’s concern that the NHSM R ule would allow the combustion of solid waste in contravention of Sectio n 129, including with respect to NHSM derived from refuse, EPA states the following:

**EPA is establishing a definition of non-hazardous s olid waste, which, as specified**  **by CAA section 129(g)(6), governs the meaning of “s olid waste” under section**  **129. Because Congress specifically directed that “s olid waste” have the meaning**  **established by the Administrator under RCRA, instea d of defining the term under**  **RCRA, the CAA definition of “municipal waste” is no t relevant to this action.** 

**If any or all of the commenter’s contentions are co rrect, 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 th e 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 exclu ding “refuse-derived fuel”**  **from the exclusion in 129(g)(1)(B) was somehow defi ning the term as being**  **included in the term, “solid waste,” under RCRA. A gain, if that were the case,**  **section 129(g)(6) would be superfluous. Nevertheles s, today’s rule identifying**  **which non-hazardous secondary materials that are so lid 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 Commence d 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 t hrough 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 Age**  **ncy 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. T**  **he validity of EPA’s interpretation on whether commodity fuels may be pr**  **ocessed, or extracted, from a waste must stand or fall based on the RCRA defini**  **tion, not provisions of the**

**CAA.**

Id . EPA’s statements here reflect its belief that Se ction 129 does not, and cannot,
mandate that RDF be a “solid waste” under RCRA. Pu rsuant to Section 129(g)(6), only a RCRA rulemaking can determine the scope of the “sol id waste” definition. However, because RDF is already subjected to municipal waste combustor standards under Section 129, the NHSM Rule does not attempt to dete rmine 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 definit ion 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 w ould limit the universe of the materials that may be considered “secondary mater ials,” 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, a nd in a manner that clearly includes municipal waste, which is composed in primary part o f “post-consumer” materials. Accordingly, municipal waste may be cons idered “secondary material” and thus fall within the NHSM framework for determining legiti macy.

9. In the NHSM Rule, EPA has determined that secondary mate rials that have been discarded can be processed into non-waste fuels. Section 241.3(b) provides:

**(b) The following non-hazardous secondary material s 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-hazar**  **dous secondary materials and that meet the legitimacy criteria spe**  **cified in paragraph**

### 25 **(d)(1) of this section, with respect to fuels, and paragraph (d)(2) of this**  **section, with respect to ingredients. The legitima cy criteria apply after**  **the non-hazardous secondary material is processed t o produce a fuel or**  **ingredient product....**