September 10, 2009

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OTC CAIR Replacement Rule Recommendation Technical Support Document

The OTC is providing technical information in support of the recommendations to EPA on a CAIR

replacement rule included in the September 2, 2009 joint letter from OTC and LADCO and the additional

recommendations in the September 10, 2009 letter from OTC.  The supporting materials provided below

are organized as follows:

• Assessments and Rationale for Electricity Generating Units (EGUs)

o EGU Emission Rates

o Timing

o Cost of Controls

o Air Quality Benefits

• Assessments and Rationale for Other Sectors

o Other Stationary Source Measures

o Mobile Source Measures

• Appendix I –   EGU Rates

• Appendix II – Timing

• Appendix III – Cost of Controls

• Appendix IV – Air Quality Benefits

• Appendix V – Other Sectors

The technical information included in this support document is based on studies and analyses conducted

recently by the OTC, and where noted, by LADCO.

Assessments and Rationale for Electricity Generating Units (EGUs)

In its earliest response to EPA’s proposed transport rule ‐ first the Interstate Air Quality Rule (IAQR), and

later, the Clean Air Interstate Rule (CAIR) ‐ OTC provided comments and analyses showing that

additional NOx and SO2 reductions beyond those the rule provided would be needed for areas in the

OTR to come into attainment with the ozone and PM 2.5 National Ambient Air Quality Standards

(NAAQS). In response to the IAQR and CAIR, the OTC states developed a multi‐pollutant position in 2004,

using several different analyses of potential EGU control rates as a basis for developing national caps for

NOx and SO2 that were more stringent and earlier than those provided in CAIR.   

The analysis used in OTC’s recent review of the 2004 multi‐pollutant position, along with evaluations of

the current state of controls on EGUs and rate information extracted from recent American Electric

Power Service Corp. (AEP) settlements and consent decrees was provided to the state collaborative

process. Additional support for the timeframes and flexibility provisions in the OTC additional

recommendations are provided in a short case study on the experiences of the Maryland Department of

Environment (MDE) with its Healthy Air Act (HAA), as well as experiences in other states with their own

state rules and additional information contained in the AEP settlements/consent decrees. Recent

evaluations of control cost data that OTC has conducted for potential control strategies, including

analyses for industrial, commercial and institutional boilers and boilers serving EGUs, provide data for

relative cost/ton comparison between EGU and other sector NOx and SO2 controls. An additional

sensitivity analysis using OTC’s latest SIP modeling runs, in tandem with the results from the State
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Collaborative modeling runs, demonstrate the need for the air quality benefits that can be achieved

from the rates and structure of the OTC recommendations.

EGU Emission Rates

In developing its 2004 position, OTC relied heavily on an analysis conducted by the National Association

of Clean Air Agencies (NACAA) to support of its 2002 Principles for a Multi‐Pollutant Strategy for Power

Plants.  The NACAA analysis demonstrated that reductions in the range of 82‐88% by 2013 for SO2 and

73‐81% for NOx from a 2001 baseline were technologically feasible. Reductions within this range would

yield emission rates as follows:

• NOx: 0.07 for new source BACT; 0.10 for retrofit BACT; and

• SO2:  0.10 for new source BACT; 0.15 for retrofit BACT.

In comparison, the average emission rates for 2001 as reported by EPA were 0.37 lb/mmBtu for NOx and

0.84 lb/mmBtu for SO2 (the 2001 baseline would not have included the NOx SIP Call).

OTC continued to work on and refine its position on EGU rates, based on additional analyses.  In a 2007

review, the OTC Multi‐P Workgroup performed an analysis to determine revised NOx and SO2 cap levels.  

Assessment 1.  In the 2007 review of the OTC multi‐pollutant position for EGUs, the OTC Multi‐P

Workgroup performed an analysis using the EPA Acid Rain database and information from the

Department of Energy’s Energy Information Agency (EIA) to examine reasonably cost‐effective post‐

combustion EGU control technologies and determine fleet‐wide average NOx and SO2 emission rates for

the fossil fuel‐fired EGUs in the lower 48 states.   The OTC Multi‐P Workgroup concluded that for NOx, a

0.08 lbs/mmBtu fleet wide average emission rate would be achievable by 2018, along with an interim

hard cap in 2012 based on a 0.125 lbs/mmBtu fleet‐wide average. For SO2 the OTC Multi‐P Workgroup

concluded that a 0.15 lb/mmBtu fleet wide average emission rate was achievable by 2018, along with an

interim hard cap in 2012 based on a 0.25 lb/mmBtu fleet‐wide average. The methodology applied by the

OTC Multi‐P Workgroup included the assumptions in Table I‐1 below (also shown in Appendix I):

Table I‐1. Control Assumptions for the Methodology Applied by the OTC Multi‐P Workgroup  

EGU Size Emission reduction assumed

25MW‐

<100MW

100MW‐

<200MW

<50% input

capacity

100MW‐

<200MW

>50% input

capacity

200MW or

greater

For EGUs with existing

“assumed” add‐on

controls

For EGUs applying

“new” add‐on

controls

NOx  

SNCR SNCR SCR SCR Remains same as 2008

controlled level

90% SCR

355 SNCR

55% SNCR to SCR

increment

SO2   DSI DSI FGD FGD Remains same as 2008

controlled level

95% FGD

60% DSI

Control Technologies: DSI (Duct Sorbent Injection); FGD (Flue Gas Desulfurization); SCR (Selective Catalytic

Reduction); SNCR (Selective Non‐Catalytic Reduction)  

* For EGUs identified as already incorporating the technology applied in the OTC Multi‐P Workgroup’s

methodology their NOx emission rates were assumed to remain the same as their 2008 Ozone Season controlled
    September 10, 2009

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emission rates and their SO2 emission rates were assumed to remain the same as their annual 2008 controlled

emission rates.

**For each NOx and SO2 control technology a 0.06 lb/MMBTU “basement” level (i.e., maximum control level) was

assumed.

When these assumptions are applied to coal units (all coal and coal>100 MW) on a statewide average

ozone season basis in the Ozone Transport Region (OTR), the result is a range of rates for NOx between  

0.06 and 0.23 lb/mmBtu. A similar application in the LADCO states on a statewide average ozone season

basis yields NOx rates in the range of 0.06 and 0.14 lb/mmBtu. Similarly, when the SO2 assumptions are

applied in the OTR on a statewide annual basis, the result is a range of rates for SO2 between 0.06 and

0.32 lb/mmBtu. Following suit in the LADCO states on a statewide annual basis yields SO2 rates in the

range of 0.06 and 0.31 lb/mmBtu. Statewide rates for each state based on this analysis are outlined in

Tables I‐2 through I‐5 in Appendix I.

This analysis does not include emissions from units in the states that use other fuels, such as natural gas,

that would lower the overall statewide average emission rate.  It also shows that some states with

higher percentages of coal in their overall fuel mix will need flexibility in the regulatory structure and

timing to achieve those rates.   

Assessment 2.  In a second assessment of potential EGU rates, OTC compiled information for each of the

states in the eastern U.S. to show the average NOx and SO2 emission rates from EPA’s 2008 Clean Air

Market Division (CAMD) database, based on units 25 MW and above for all fuels. Then the incremental

NOx and SO2 rates within the ranges discussed by the State Collaborative were calculated for each state,

from 0.07 ‐ 0.125 lb/mmBtu for NOx and from 0.15 ‐ 0.30 lb/mmBtu for SO2. The tons reduced at each

control level increment and the percent reduction from 2008 levels is calculated for each state. The

results are shown in Tables I‐6 and I‐7  in Appendix I, along with  Tables  I‐8 and I‐9  showing LADCO’s

data on achievable average annual emission rates based on their plant‐level, unit‐level analysis of coal

fired units greater than 100 MW, and the timing of projected post‐combustion controls installations.  

Comparing the OTC tables based on the CAMD data with the LADCO table, the 2008 rates are very close,

despite the fact that the CAMD data includes all fuels and the LADCO data is for coal units only.  

Assessment 3. Using a third data set to assess potential EGU emission rates,  the OTC examined the

recent consent decree signed by American Electric Service Corp. (AEP) which requires the installation of

SCR and FGD controls on EGUs in a number of states including Indiana, Kentucky, Ohio, Virginia and

West Virginia. The consent decree requires several of these units to meet a federally‐enforceable 30‐day

rolling average emission rate of 0.100 lb/mmBtu for NOx and a 30‐day rolling average emission rate of

0.100 lb/mmBtu for SO2.  Furthermore, repowering requirements as stipulated in the consent decree

state that the technology achieve “equivalent environmental performance that at a minimum achieves

and maintains a 30‐day rolling average emission rate of 0.100lb/mmBtu or a 30‐day rolling average

removal efficiency of at least 95% for SO2 and a 30‐day rolling average emission rate of 0.070 lb/mmBtu

for NOx.

The limits specified in the AEP consent decree provide additional support for the technical feasibility and

cost effectiveness of the NOx and SO2 emission rates “observed by” the State Collaborative EGU

Technical Workgroup presented at the State Collaborative meetings held on October 7, 2008 and April

27‐28, 2009.  AEP would not have signed this consent decree if it was not certain that it could comply

with all of its terms.  Note that the NOx and SO2 emission rates in the consent decree are more stringent

than the NOx and SO2 emission rates in the OTC recommendations because they are based on unit
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specific, 30‐day rolling average emission rates rather than statewide average emission rates.  If EGU

retrofits can achieve the NOx and SO2 rates specified in the AEP consent decree on a unit specific basis,

then it should be feasible for other EGUs to achieve these emission rates on a statewide average basis.

Timing

Timing flexibility is a key issue in developing  an EGU control strategy. If the regulatory structure is

designed correctly, it will provide incentives to get controls installed quickly. One example of this is

provided by the Maryland Department of Environment’s (MDE) experience with their Healthy Air Act

(HAA), which was passed in 2006, with final rules issued in January 2007 (see MDE case study in

Appendix II).  MDE’s experience with the HAA demonstrates that it is possible to achieve simultaneous,

rather than sequential, installation of controls in less than 3 years after promulgation of the rules

requiring those controls.

• In Maryland, 3 SCRs and 6 SNCRs on coal units ranging in size from 125 ‐ 600 MW, and 6 FGD on

9 coal‐fired units ranging in size from 200 ‐700 MW are installed or will have completed

installation by the end of 2009, or less than 3 years after the HAA rules were promulgated.  Four

SCRs had been installed on coal‐fired power plants in Maryland prior to the HAA.

• MDE included a waiver for units that could not meet the control levels by the date required,

providing additional time for them to install controls. The waiver was not utilized by any EGU.

• The installations responding to the HAA rules occurred at the same time that controls were

being required for CAIR and a number of consent decrees on EGUs. Despite these competing

interests, there were no delays in construction or installation due to labor or equipment

constraints.

More specific information can be found in Appendix II, Example 1 on the MDE HAA case study, including

a schematic of the timeline of installations on specific EGUs in response to the rule.

In another example from Delaware, the state established phased NOx and SO2 limits in Regulation 1146,

promulgated in December 2006, with the first phase of controls required to be operational in May 2009.

This provided a 2.5‐year window from promulgation of the rule to installation and operation of controls

for the first phase of NOx and SO2 controls. The emission rates and timing for the reductions required by

Delaware’s Regulation 1146 is applicable to coal‐fired and residual oil‐fired units 25 MW and above are

as follows:

• NOx = 0.15 lb/mmBtu on all units beginning May 1, 2009 through December 2011, with a

second, more stringent limit on the same units of 0.125 lb/mmBtu for the period January 1,

2012 and beyond (limits are on a rolling 24‐hour basis);

• SO2 = 0.37 lb/mmBtu on all units beginning May 1, 2009 through December 2011, with a second,

more stringent limit on coal‐fired units of 0.26 lb/mmBtu for the period January 1, 2012 and

beyond (limits are on a rolling 24‐hour basis);  and

• Residual oil‐fired units may not accept residual fuel oil for combustion that has a sulfur content

in excess of 0.5% by weight from January 1, 2009 and beyond.

More information on Delaware’s Regulation 1146 can be found at:  

http://regulations.delaware.gov/AdminCode/title7/1000/1100/1146.shtml
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Finally, data collected on controls resulting from EPA’s NOx SIP Call show that a over 75 percent of the

SCR units installed  occurred within a 4‐year window, between 2003 to 2007, with more than 50 percent

of the installations occurring in the 2003‐2004 timeframe.  More information on the installation of SCR

controls in response to EPA’s NOx SIP Call can be found in Appendix II, Example 2.  

Cost of Controls

EPA needs to perform a comprehensive cost analysis for the CAIR replacement rule; however, in the

interim the data show that aggressive controls on EGUs continues to be the most cost‐effective option

available to the states in meeting the ozone and PM 2.5 standards.

Table III‐1 in Appendix III provides recently developed cost estimates for various NOx and SO2 controls in

2008 dollars, including selective non‐catalytic reduction (SCR), selective catalytic reduction (SCR), flue

gas desulfurization, low NOx burners (LNB)and combinations of these controls on coal‐fired, residual oil‐

fired, distillate oil‐fired and natural gas‐fired boilers. The data shows that the cost for controls caps out

at $4,900 per ton of NOx removed for an SCR and $3,600 per ton of SO2 removed for a dry FGD system

(dry scrubber) installed on a 250 mmBtu/hr (approximately 73 MW) coal‐fired boiler operating at 66

percent capacity. The NOx control costs for 250 mmBtu/hr fossil fuel‐fired boilers serving EGUs range

from $1,100 to $8,700 per ton of NOx removed and the SO2 control costs for 250 mmBtu/hr coal‐fired

boilers serving EGUs range from $1,400 to $3,600 per ton of SO2 removed.

  

OTC is conducting an extensive examination of potential control measures to consider as additional

strategies in their ozone and PM 2.5 SIPs. The costs of several of these controls on a $/ton basis far

exceed the cost of EGU controls, as shown in Tables III‐2 and III‐3 in Appendix III.

  

Air Quality Benefits

The State Collaborative effort has produced modeling analyses to examine the impact that a CAIR

replacement rule might have on air quality in the Eastern United States.  These regional modeling results

show that an EGU based strategy would have a positive impact on PM2.5 and ozone air quality in the

region and that while nearby sources have by far the greatest impact, significant contribution to levels

of ozone and PM2.5 can come from states several hundred miles away.  This effort also shows that with

an EGU strategy that approximates CAIR and other currently adopted measures many areas are still

above the current ozone (0.075 ppm) and PM2.5 NAAQS.   

Furthermore, the State Collaborative modeling also show that even with the most stringent NOx (0.07

lb/mmBtu) and SO2 (0.10 lb/mmBtu) emission control rates applied on a unit‐by‐unit basis, a number of

areas remain in non‐attainment .  Under these emission limits the modeling shows 23 counties in non‐

attainment for the 75 ppb ozone standard, 10 counties not meeting the PM2.5 daily standard, and 3

counties in non‐attainment for the PM 2.5 annual standard. The State Collaborative modeling is not “SIP

quality,” so it was conducted to provide, at best, ballpark estimates that are only meant to be

directionally correct. Even with the substantial improvement in air quality shown in the 2018 modeling

results, however, approximately 37 million people will still be exposed to unhealthy levels of air

pollution. Results from the State Collaborative air quality modeling are summarized in the charts and

maps on pages 1‐2 of Appendix IV.

To ascertain the level of reductions that might be necessary to meet the current ozone NAAQS, the OTC

performed sensitivity modeling.  This sensitivity modeling employed across‐the‐board reduction in NOx
    September 10, 2009

6

emissions (point, area and mobile sources).  This sensitivity modeling indicates that by reducing NOx

emissions by 40 % from all sectors attainment with the current ozone NAAQS is possible.  While it is

likely impossible to reduce NOx emissions by 40 % from all sectors, this provides a pathway to

determine the level of emissions reductions needed for planning purposes.  The ultimate decision on the

measures chosen will be based on feasibility (both technical and cost) and effectiveness.  Results from

the OTC sensitivity modeling are summarized in the maps and charts on pages 3‐5 of Appendix IV.

Assessments and Rationale for Other Sectors

The states in the eastern U.S. have affirmed that emission reductions beyond what is achievable from

EGU sources alone will be necessary to comply with the ozone and PM 2.5 standards, and to address

transport and regional haze.  Both the joint OTC‐LADCO recommendation of September 2, 2009 and the

additional recommendations provided by OTC in the September 20, 2009 letter put forward potential

EGU emission rates for consideration by EPA that go beyond the original CAIR levels.  It is important that

significant reductions are also obtained from sources in the area and mobile source sectors to bring

areas into attainment with air quality standards and mitigate transport of air pollutants and their

precursors from one part of the country into another.

Other Stationary and Area Source Measures

  

The OTC states have taken actions beyond the EGU sector during the past 10 years to reduce NOx and

VOC emissions from non‐EGU stationary and area sources including consumer products, architectural

and industrial maintenance coatings,  adhesives and sealants, solvents, portable fuel containers, asphalt

paving, distributed generators, cement kilns, glass furnaces  and industrial, commercial and institutional

(ICI) boilers.  The model rules developed in 2001 and 2006 for these source categories have been

developed and implemented by many of the OTC states as outlined in Tables V‐1 through V‐4 in

Appendix V.   

The OTC has long advocated to EPA that these rules be applied nationally, and EPA has taken national

action in some areas, e.g., consumer products. The ICI boiler model rule was used in last year’s State

Collaborative discussions with LADCO to help develop a joint set of recommendations for a national ICI

boiler strategy to EPA. Further,  in the current planning work occurring in the OTR for the new ozone and

PM 2.5 SIPs, the OTC is continuing to drill down into other non‐EGU stationary and area source categories

to find additional reductions, as outlined in the potential measures illustrated in Tables III‐2 and III‐3  in

Appendix III.

Mobile Source Control Measures

   

The OTC states have also implemented numerous programs to reduce ozone precursor emissions from

mobile sources.  The majority of the states have adopted California Low Emission Vehicle standards

applicable to new vehicles, which are more stringent than federal standards.  To address emissions from

in‐use vehicles, the states have implemented Inspection and Maintenance Programs and aggressive

diesel retrofit programs.

States have also exercised their option to opt‐in to federal reformulated gasoline as part of their State

Implementation Plans (SIPs).  To counter growth in vehicle miles traveled, states in the region have

included transportation control measure in their SIPs (e.g., improved public transit) and have
    September 10, 2009

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implemented many air quality improvement projects through the conformity review process to ensure

mobile source emission budgets are met.   

The OTC Mobile Source Committee is currently working on additional mobile measures as part of the

2008 ozone standard regional attainment planning process. It is supporting the adoption of national

measures in areas where the states are pre‐empted from taking action.  For example, it has submitted a

letter of support for the ocean going vessels Emission Control Areas (ECA) designation to reduce

emissions from port areas.  And it has encouraged EPA to issue guidance from EPA on its Aftermarket

Catalyst Replacement Standards policy.   The OTC is also advocating for EPA to address backsliding with

regard to the Renewable Fuel Standard (RFS), to ensure that phase 2 of the program does not further

exacerbate criteria pollutant impacts that have occurred in Phase 1 of the program.

Other mobile measures that are under review in the OTC and NESCAUM states are:

• Offshore lightering for ships (VOC  reductions)  

• Seaports strategy (PM strategy primarily)  

• Adoption and enforcement of non‐road idling requirements (VOC, NOx and GHG reductions)  

• Regional fuel for OTC states/areas that have not yet adopted RFG (i.e. large parts of PA and NY))  

• Heavy duty diesel strategies such as Inspection and Maintenance Programs for Diesels and

expansion of diesel retrofit programs

• Additional VMT‐reduction strategies that will result in ozone precursor and GHG reductions     

In the context of Greenhouse Gas Emissions, the OTC states have been involved in numerous actions

that will result in the overall reduction of ozone precursors as well as GHG emissions.  The litigation of

Mass v. EPA, joined by many OTC states, and the active support of OTC‐member states for the

integration of motor vehicle efficiency standards and GHG emission standards into a new federal policy

endorsed by President Obama are examples.   The RGGI States, with PA, are also working on the

development of a  low carbon fuel standard (LCFS ), including the potential to improve the infrastructure

for electric vehicles that may be part of that strategy, and smart growth/VMT and land use measures to

reduce mobile emissions.   
   

Appendix I – EGU Rates

Assessment 1

The methodology applied by the OTC Multi‐P Workgroup and used for this assessment is included the

assumptions in Table 1‐1 below:

Table I‐1. Control Assumptions for the Methodology Applied by the OTC Multi‐P Workgroup  

EGU Size Emission reduction assumed

25MW‐

<100MW

100MW‐

<200MW

<50% input

capacity

100MW‐

<200MW

>50% input

capacity

200MW or

greater

For EGUs with existing

“assumed” add‐on

controls

For EGUs applying

“new” add‐on

controls

NOx  

SNCR SNCR SCR SCR Remains same as 2008

controlled level

90% SCR

355 SNCR

55% SNCR to SCR

increment

SO2   DSI DSI FGD FGD Remains same as 2008

controlled level

95% FGD

60% DSI

Control Technologies: DSI (Duct Sorbent Injection); FGD (Flue Gas Desulfurization); SCR (Selective Catalytic

Reduction); SNCR (Selective Non‐Catalytic Reduction)  

* For EGUs identified as already incorporating the technology applied in the OTC Multi‐P Workgroup’s

methodology their NOx emission rates were assumed to remain the same as their 2008 Ozone Season controlled

emission rates and their SO2 emission rates were assumed to remain the same as their annual 2008 controlled

emission rates.

**For each NOx and SO2 control technology a 0.06 lb/MMBTU “basement” level (i.e., maximum control level) was

assumed.

Based on the above assumptions, the “predicted” statewide average ozone season NOx emission rates

are shown below:

Table I‐2. All Coal

State

Predicted

NOx

Mass

2008 O.S.

Heat Input

Predicted

Avg NOx

Rate

State

Predicted

NOx

Mass

2008 O.S.

Heat Input

Predicted

Avg NOx

Rate

CT 395 13,163,750 0.0600 IL 13,297 443,240,475 0.0600

DE 1,863 20,145,049 0.1850 IN 12,814 427,135,645 0.0600

MA 1,569 40,324,189 0.0778 MI 12,645 208,348,933 0.1214

MD 5,345 112,279,215 0.0952 OH 19,156 274,909,447 0.1394

NH 1,754 15,347,558 0.2286 WI 34,845 627,665,733 0.1110

NJ 2,438 30,586,717 0.1594        

NY 4,321 76,120,595 0.1135        

PA 25,880 446,215,793 0.1160        

VA 6,070 119,264,709 0.1018        

I-1
   

If only coal‐fired units with a nameplate rating of 100MW or greater are to be considered, the

“predicted” statewide average ozone season NOx emission rates are shown below:

Table I‐3.  >100 MW Coal

State

Predicted

NOx

Mass

2008 O.S.

Heat Input

Predicted

Avg NOx

Rate

State

Predicted

NOx

Mass

2008 O.S.

Heat Input

Predicted

Avg NOx

Rate

CT 395 13,163,750 0.0600 IL 12,817 417,656,155 0.0614

DE 1,863 20,145,049 0.1850 IN 23,368 492,447,671 0.0949

MA 1,298 35,899,623 0.0723 MI 13,082 278,933,070 0.0938

MD 5,127 110,241,907 0.0930 OH 26,348 519,802,282 0.1014

NH 1,362 11,735,819 0.2321 WI 7,293 185,704,212 0.0785

NJ 2,284 29,350,532 0.1556        

NY 3,828 68,614,070 0.1116        

PA 24,430 430,902,559 0.1134        

VA 4,918 107,929,830 0.0911        

Based on the above assumptions, the “predicted” statewide average annual SO2 emission rates for all

coal‐fired EGUs are shown below:

Table I‐4.  All Coal

State SO2Mass Heat Input SO2 Rate State SO2Mass Heat Input SO2 Rate

CT 915 30,494,774 0.0600 IL 52,260 1,032,913,414 0.1012

DE 6,877 53,729,573 0.2560 IN 184,979 1,183,751,273 0.3125

MA 15,976 101,700,315 0.3142 MI 30,911 714,421,520 0.0865

MD 12,891 255,974,177 0.1007 OH 149,190 1,291,957,283 0.2310

NH 3,560 38,335,281 0.1857 WI 21,100 453,687,252 0.0930

NJ 4,226 62,812,030 0.1346        

NY 20,848 181,042,512 0.2303        

PA 133,087 1,068,514,484 0.2491        

VA 18,790 279,184,954 0.1346        

If only coal‐fired units with a nameplate rating of 100MW or greater are to be considered, the

“predicted” statewide average annual SO2 emission rates are shown below:

Table I‐5.  >100 MW Coal

State SO2Mass Heat Input SO2Rate State SO2 Mass Heat Input SO2 Rate

CT 915 30,494,774 0.0600 IL 42,489 991,323,073 0.0857

DE 6,877 53,729,573 0.2560 IN 159,449 1,149,099,381 0.2775

MA 14,861 93,738,547 0.3171 MI 21,018 653,861,186 0.0643

MD 11,412 250,831,639 0.0910 OH 130,335 1,241,187,821 0.2100

NH 1,565 30,332,534 0.1032 WI 15,199 432,619,948 0.0703

NJ 3,582 59,793,990 0.1198        

NY 15,695 160,893,978 0.1951        

PA 119,772 1,034,993,798 0.2314        

VA 15,312 250,443,277 0.1223        

I-2
   

Assessment 2

Table I‐6.  NOx Table

State

NOx

Tons

NOx

Rate 0.125

Red.

0.125

%

Red.

0.125 0.1

Red.

0.10

%

Red.

0.10 0.07

Red.

0.07

%

Red.

0.07 Heat Input

IL 119967 0.226 66295 53672 45 53036 66931 56 37125 82842 69 1060713465

IN 196135 0.306 80199 115935 59 64159 131975 67 44912 151223 77 1283188639

MI 103474 0.275 46998 56476 55 37598 65875 64 26319 77155 75 751966181

OH 235126 0.355 82817 152309 65 66254 168872 72 46378 188749 80 1325072026

WI 47343 0.190 31099 16244 34 24879 22464 47 17415 29927 63 497577808

LADCO

TOTAL 702043 0.285 307407 394636 56 245926 456117 65 172148 529895 75 4918518119

                                      

PA 175218 0.286 76626 98592 56 61301 113917 65 42911 132308 76 1226016925

NY 30871 0.109 30871 0 0 28384 2487 8 19869 11002 36 567686169

NJ 9143 0.096 9143 0 0 9143 0 0 6659 2483 27 190267033

MD 35922 0.263 17048 18875 53 13638 22284 62 9547 26376 73 272761427

VA 43017 0.237 22652 20365 47 18122 24895 58 12685 30332 71 362431406

MA 9353 0.068 9353 0 0 9353 0 0 9353 0 0 274620434

NH 4641 0.096 4641 0 0 4641 0 0 3373 1268 27 96364833

CT 3116 0.067 3116 0 0 3116 0 0 3116 0 0 92717786

DE 8936 0.279 4003 4934 55 3202 5734 64 2241 6695 75 64042015

ME 680 0.022 680 0 0 680 0 0 680 0 0 61863689

DC 94 0.280 42 52 55 33 60 64 23 70 75 668330

RI 462 0.017 462 0 0 462 0 0 462 0 0 55392442

VT 296 0.140 263 32 11 211 85 29 147 148 50 4214041

OTC

TOTAL 321749 0.197 204315 117434 36 163452 158297 49 114417 207333 64 3269046530

                                      

AL 112614 0.240 58697 53917 48 46958 65656 58 32870 79744 71 939155771

FL 155451 0.197 98770 56681 36 79016 76435 49 55311 100140 64 1580319063

GA 105894 0.221 59900 45994 43 47920 57974 55 33544 72350 68 958401269

KY 157847 0.319 61918 95929 61 49535 108312 69 34674 123173 78 990691497

MS 41917 0.237 22110 19807 47 17688 24229 58 12381 29535 70 353752142

NC 54652 0.144 47283 7369 13 37826 16826 31 26478 28174 52 756524591

SC 42045 0.190 27615 14430 34 22092 19953 47 15465 26581 63 441843531

TN 85543 0.294 36392 49151 57 29114 56430 66 20380 65164 76 582275154

WV 97331 0.228 53329 44002 45 42663 54668 56 29864 67467 69 853266499

Other

State

Total 853294 0.229 466014 387280 45 372811 480483 56 260968 592326 69 7456229518

                                      

TOTAL 1877087 0.240 977737 899350 48 782190 1094897 58 547533 1329554 71 15643794167

I-3
Table I‐7. SO2 Table

State 

SO2 

tons 

SO2 

Rate 0.3 Red. 0.3 

% 

Red.0.3 0.23 

Red. 

0.23 

% Red. 

0.23 0.2 

Red. 

0.20 

% Red. 

0.20 0.15 

Red. 

0.15 

IL 257431 0.485 159107 98324 38 121982 135449 53 106071 151360 59 79554 177877 IN 593154 0.925 192478 400676 68 147567 445587 75 128319 464835 78 96239 496915 MI 326501 0.868 112795 213706 65 86476 240024 74 75197 251304 77 56397 270103 OH 709995 1.072 198761 511234 72 152383 557611 79 132507 577487 81 99380 610614 WI 129695 0.521 74637 55058 42 57221 72473 56 49758 79937 62 37318 92376 LADCO TOTAL 2016775 0.820 737778 1278997 63 565630 1451145 72 491852 1524923 76 368889 1647886 PA 831915 1.357 183903 648012 78 140992 690923 83 122602 709313 85 91951 739964 NY 65427 0.231 65427 0 0 65284 143 0 56769 8658 13 42576 22850 NJ 21204 0.223 21204 0 0 21204 0 0 19027 2177 10 14270 6934 MD 227198 1.666 40914 186283 82 31368 195830 86 27276 199921 88 20457 206740 VA 125985 0.695 54365 71620 57 41680 84306 67 36243 89742 71 27182 98803 MA 46347 0.338 41193 5154 11 31581 14766 32 27462 18885 41 20597 25751 NH 36895 0.766 14455 22440 61 11082 25813 70 9636 27259 74 7227 29668 CT 3955 0.085 3955 0 0 3955 0 0 3955 0 0 3955 0 DE 31808 0.993 9606 22202 70 7365 24444 77 6404 25404 80 4803 27005 ME 1041 0.034 1041 0 0 1041 0 0 1041 0 0 1041 0 DC 212 0.634 100 111 53 77 135 64 67 145 68 50 162 RI 18 0.001 18 0 0 18 0 0 18 0 0 18 0 VT 2 0.001 2 0 0 2 0 0 2 0 0 2 0 OTC TOTAL 1392007 0.852 436183 955825 69 355648 1036359 74 326905 1065102 77 245178 1146829 AL 357547 0.761 140873 216673 61 108003 249544 70 93916 263631 74 70437 287110 FL 263745 0.334 237048 26697 10 181737 82008 31 158032 105713 40 118524 145221 GA 514539 1.074 143760 370779 72 110216 404323 79 95840 418699 81 71880 442659 KY 344356 0.695 148604 195753 57 113930 230427 67 99069 245287 71 74302 270055 MS 65317 0.369 53063 12254 19 40681 24635 38 35375 29941 46 26531 38785 NC 227030 0.600 113479 113551 50 87000 140030 62 75652 151378 67 56739 170291 SC 157190 0.712 66277 90914 58 50812 106378 68 44184 113006 72 33138 124052 TN 208069 0.715 87341 120728 58 66962 141107 68 58228 149842 72 43671 164398 WV 301574 0.707 127990 173584 58 98126 203449 67 85327 216248 72 63995 237579 Other State Total 2439368 0.654 1118434 1320933 54 857466 1581901 65 745623 1693745 69 559217 1880150 TOTAL 5848149 0.748 2292395 3555755 61 1778744 4069405 70 1564379 4283770 73 1173285 4674865 
   

LADCO Analysis

Based on this plant‐level, unit‐level analysis of coal‐fired units, the LADCO States identified the following

achievable annual average emission rates:  

   

Table I‐8. NOx and SO2 Analysis

NOx        

Year Illinois Indiana Michigan Ohio Wisconsin

2008 0.23 0.305 0.29 0.36 0.21

2013 0.11 – 0.12 0.297 0.18 0.24 0.13

2014 0.11 – 0.12 0.171 0.15 0.18 0.12

2015 0.11 – 0.12 0.165 0.13 0.17 0.10

2017 0.11 – 0.12 0.114 0.11 0.12 0.09

          

SO2        

Year        

2008 0.50 0.93 0.91 1.09 0.57

2013 0.24 – 0.44 0.67 0.58 0.75 0.39

2014 0.20 ‐0.43 0.66 0.45 0.65 0.39

2015 0.19 – 0.28 0.66 0.37 0.65 0.25

2017 0.15 – 0.23 0.25 0.25 0.256 0.16

It should be noted that the analysis is based on coal‐fired units.  Consideration of all units (coal, oil, gas,

and biomass) will result in emission rates slightly below those indicated above.

The number of post‐combustion controls assumed in this analysis is provided below.  The total amount

of mega‐wattage controlled in each state is on the order of 80‐90%.

Table I‐9. Analysis of Post‐combustion Controls by Year

NOx SO2

SCR SNCR ALL FGD

IL IN MI OH WI IL IN MI OH WI IL IN MI OH WI IL IN MI OH WI

2008

   

23 3 19 1

   

4 0 15 1 17 27 3 34 2 6 23 2 16 1

2013

   

23 7 25 5

   

7 0 11 8 32 30 7 36 13 20 29 7 25 6

2014

   

23 12 26 5

   

7 0 11 8 34 30 12 37 13 29 29 12 33 6

2015

   

23 17 27 5

   

17 0 11 15 36 40 17 38 20 35 29 17 33 6

2017

   

32 25 34 8

   

17 0 14 15 36 49 27 48 23 37 48 27 41 13

Note:  IL and OH numbers reflect number of units controlled, and IN and WI numbers reflect number of

installations (which may cover several units).

I-5
   

II-1 

APPENDIX II – Timing

Example 1: Case Study

Maryland Healthy Air Act

Deadlines and the Installation of Control Equipment

BACKGROUND

In April of 2006, the Maryland General Assembly adopted the Maryland Healthy Air Act.  The bill

was signed into law on April 6, 2006.  In general, the law required significant reductions in

Nitrogen Oxides (NOx), Sulfur Dioxide (SO2) and Mercury (HG) from electricity generating units

(EGUs) in Maryland.  It also required Maryland to join the Regional Greenhouse Gas Initiatve

(RGGI), the first cap‐and‐trade program to tackle CO2 in the Country.

Portions of Maryland are nonattainment for the federal Ozone and PM2.5 Standards.  NOx

reductions were a critical part of Maryland’s plan to reduce ground level ozone.  Reductions in

SO2 and NOx are both important to the States plans to lower fine particle levels.  Maryland also

had multiple issues with mercury and the Chesapeake Bay.

The Healthy Air Act was driven by the concept that the emission reductions from the Healthy Air

Act would be important to the States own efforts to solve its air quality problems.  It did,

however, recognize that Maryland had a responsibility under the Clean Air Act to reduce

pollution to also help downwind neighbors.  

The implementing regulations were put on a fast track and were adopted on January 18th, 2007.

The Healthy Air Act includes two phases of reductions: 2009 and 2012 for NOx and 2010 and

2012 for SO2 and mercury.  Table 1 below summarizes the additional NOx and SO2 reductions

required in 2009, 2010, 2012 and 2013.    

Table 1

Maryland Healthy Air Act Emission Reductions

      

2009 2010 2012 2013

NOx 70%    75%   

SO2    80%    85%

Mercury     80%    90%

Because of pre‐2006 control programs like the OTC NOx Budget Rule, total NOx reductions from

Maryland EGUs between 1990 and 2012 are estimated to be over 85%.
   

II-2 

THE DEADLINES

While the Healthy Air Act was being debated, there was considerable concern raised

over the issue of timing.  In general, Maryland’s two major power generators argued

that the 2 years to install NOx controls and the 2 1⁄2 to 3 years to install SO2 and Mercury

controls were a huge and perhaps impossible challenge.  Over 60% of Maryland’s

electricity comes from coal.   

Maryland’s largest generator (3 plants – 9 units) argued that the only feasible way to

install the controls required by the Healthy Air Act was to go in series (plant‐by‐plant)

and that a plant‐by‐plant approach could take over 6 years.

As a result of this debate, the law included several waiver provisions to allow affected

sources more time, without penalty, if such delays could be justified.  For Phase 1 (2009

for NOx and 2010 for SO2 and HG) there have been no requests for waivers.  Both of

Maryland’s major generators have installed their controls in parallel, not in series (plant‐

by‐plant).

Because of the Healthy Air Act, by 2010, over $2 Billion will have been invested in new

control equipment (6 scrubbers, 3 SCRs, 6 SNCRs).  Four SCRs and numerous combustion

modifications had been installed on coal fired power plants in the Maryland prior to the

Healthy Air Act.     

Table 2 below summarizes the planning and installation schedules for the six largest

plants in the State.

Construction schedules for the FGD ran approximately 28 months each.   Engineering

economies were realized by using the same size FGD for the four Mirant installations.  

While the number of units served by each FGD in the three plants in the Mirant system

varied, the total MW of capacity feeding each FGD was approximately the same at about

600 MW.  This allowed the same engineering design to be used for each FGD.  The two

FGD at Brandon Shores are also identical to each other.

While the use of two FGD designs assisted with the timely completion of the six

projects, material handling design and ductwork to and from the FGDs were different at

each site.  Three of the FGD projects had to deal with SCR construction occurring

simultaneous to the FGD construction, and accommodations for crane availability had to

be carefully scheduled. All of the FGD’s required new stacks with fiber glass liners.  The

liners were constructed on site and the equipment installed to fabricate the liners the

required permits to construct from MDE.  
   

II-3 
   

II-4 

OTHER MID‐ATLANTIC STATES

Between 2006 and 2009 there were other very significant efforts taking place in the Mid‐

Atlantic area to add scrubbers, SCRs and SNCRs.  Because of state programs and the Clean Air

Interstate Rule (CAIR), Virginia, New Jersey, Delaware, West Virginia and North Carolina all had

significant control technology installation efforts taking place between 2006 and 2009.

CONCLUSION

With the appropriate regulatory structure, very significant pollution control systems, including

FGDs, SCRs and SNCRs, can be installed in multiple plants owned by the same company, in

parallel, in a relatively short timeframe.   

Supplemental Information:

• Law: http://mlis.state.md.us/2006rs/bills/sb/sb0154e.pdf

• Regulation: http://www.mde.state.md.us/assets/document/26‐11‐

27_MD_Healthy_Air_Act.pdf
II-5 

Example 2: Installation of SCR Units from EPA’s NOx SIP Call

55.5%

of Units

22.3%

of Units

SCR Units Over Time

Phase I

Minimal SCR Units

Expect Minimal NOx

Reductions

Phase II

Large Number of SCR Units Installed

Expect SIGNIFICANT NOx Reductions

Especially after 2003-2004

Ground-level ozone

should decrease dramatically Data courtesy of The Institute of Clean Air Companies (ICAC).

77.8% of Units Installed

between 2003-2007 Scheduled Startup Unit
Appendix III – Cost of Controls

Table III‐1. Available Emission Control Devices, Emission Reductions and Estimated Costs1

Fuel Type Pollutant Available Control Device Expected Emission

Reduction (%)

C

Coal‐Fired NOx Selective Non‐Catalytic Reduction (SNCR)

Selective Catalytic Reduction (SCR)

45%85%

SO2 Flue Gas Desulfurization (FGD) system (dry scrubber)

Wet FGD system (wet scrubber)

95%95%

Residual

Oil‐Fired

NOx Low NOx Burners (LNB)

LNB plus Flue Gas Recirculation (FGR)

Selective Non‐Catalytic Reduction (SNCR)

LNB plus SNCR

Selective Catalytic Reduction (SCR)

50%60%50%65%85%

Distillate

Oil‐Fired

NOx Low NOx Burners (LNB) 50% 

Gas‐Fired NOx Low NOx Burners (LNB) 50% 

Note: aCost estimates shown are in 2008 dollars for a 250 MMBtu/hr boiler (≈ 73 MW) operating at 66 percent capacity a

hours per year

1New Hampshire Department of Environmental Services (October 2008) Draft ICI Boiler NOx and SO2 Control Cost Estima

(Andy Bodnarik, 2009)
Table III‐2 Stationary and Area Source Measures

NOx Measure State Rules National

Measure

Emissions 

Reduction

Boilers serving EGUs DE, NJ,MA, MD * 413 TPD OTR $1,100 

New Small Gas Boilers CA, TX * 53 TPD OTR $3,300 to 

Municipal waste 

incinerators NJ, MD * 14 TPD OTR $2,140 

HEDD EGUs NJ * TBD $45,000 to 

Stationary Generator 

Regulation (DG) 

DE, MA, 

MD, NJ

* TBD $39,700 to 

Minor New Source 

Review

DE, CT, MD, 

MA, NJ, RI

* TBD $600 to 

Energy security / 

Energy efficiency TBD * TBD 
Table III‐3 Stationary and Area Source VOC Measures

VOC Measure State Rules National

Measure

Emissions 

Reduction

AIM rule CA * 50 TPD OTR $2

Auto Refinishing CA * 21 TPD OTR $2

Consumer Products 

2006 CA * 19 TPD OTR $7

Lower VOC Solvent 

Degreaser MD, CA * 13 TPD OTR $1

Gas Stations TBD * TBD 

Large VOC Storage 

Tanks MD, NJ * TBD $2,288 t

Minor New Source 

Review

DE, CT, 

MD, MA, 

NJ, RI

* TBD 
Appendix IV – Air Quality Benefits

State Collaborative Modeling Results

19

Ozone 8-Hour

Concentrations

2009

2012 2018

DRAFT DRAFT DRAFT

Based on 2005 meteorology

   

17

PM2.5 Daily

Concentrations

2009

2012 2018

DRAFT DRAFT DRAFT

Based on 2005 meteorology

IV-1
15

PM2.5 Annual

Concentrations

2009

2012 2018

DRAFT DRAFT DRAFT

Based on 2005 meteorology

IV-2
OTC Sensitivity Modeling Runs: 40% NOx Emission Reduction, All Sectors

DVF 2012 BOTB/BOTW “NOC

40% Across‐the‐Board Anthro
MANE-VU Annual Total NOx Emissions by Source Category

262,477 265,925 265,925 261,057 261,057 263,033 431,630 353,219 353,219 321,934 321,934 280,006

1,376,365

745,736 745,736

551,846 551,846

303,957

673,505

406,721

547,432

381,248

537,673

374,947

0

500,000

1,000,0001,500,0002,000,0002,500,0003,000,000

2002 2009 CAIR 2009 No CAIR 2012 CAIR 2012 No CAIR 2018 201

tons/yr
MANE-VU Annual Total NOx Emissions (All Categories) and Highest O3 8-hr Design Value in t

2,744,133

1,774,443

1,518,927

1,221,945

1,003,506

98.3

90

86

80

74

0

500000

10000001500000200000025000003000000

2002 2009 2012 2018 2012 NoCAIR

N40V00

NOx Emissions (tons/year)

020406080100120

O3 Design Value (ppb) 
Appendix V – Other Sectors

Table V‐1. Status Report on OTC State Efforts to Promulgate Regulations Based on OTC 2001 Model Rules (as of May 19

Consumer Products 

Architectural and Industrial Maintenance Coatings 

Portable Fuel Containers 

Mobile Equipment Repair and Refinishing 

Solvent Cleaning 

Additional NOx Controls 

Distributed Generation Standards 

State Contacts and Links to Ru

C T Effective Effective Effective Effective (similar rule) Effective Alternative requirements in effect Effective Contact: Susan Amarello 860-424-3442 http://www.ct.gov/dep/cwp/view.asp?D E 

Effective See 2006 rule 

Effective See 2006 rule Effective Effective Effective Effective 1/11/06 Contact: Gene Pettingill 302-323-454

http://www.dnrec.state.de.us/air/aqm

http://www.dnrec.state.de.us/air/aqm

D C Effective Effective See 2006 rule Effective Effective NOx RACT Already in place In progress l (202) 535M E Effective Effective See 2006 rule Effective Effective Effective Contact: Jeff Crawford 207-287-2437 http://www.maine.gov/dep/air/regulatM D 

Effective (COMAR 26.11.32) 

Effective (COMAR 26.11.33) 

See 2006 rule 

Effective (similar rule) 

Effective (similar rule) In progress In progress 

Contact: Gene Higa 410-631-3353 PFC: Eddie Durant Consumer Products: Husain Waheed 410-537-3240http://www.dsd.state.md.us/comar/su

M A 

Adopted CP rule (Phase II) 10/19/2007; new standards effective 1/1/2009 

Rule adopted 10/19/2007; new standards effective 1/1/2009 

See 2006 rule 

Effective (similar rule) 

Rule adopted 3/06/2009; new standards effective 9/06/2009. 

Effective (similar rule) 

Rule finalized 9/2005 

Contacts: Consumer products; AIM Coatings; s

azin.kavian@state.ma.us

Distributed Generation: Robert.donaProposed regulations: http://www.m

Final regulations: http://www.mass.g

N H 

Adopted (Effective January 1, 2007) 

Adopted (7/27/06) 

See 2006 rule 

Not considering Adopted Under review

Effective (not based on OTC model rule) 

Contact: Mike Fitzgerald 603-271-63http://www.des.state.nh.us/rules/env-http://www.des.state.nh.us/rules/env-
Table V‐2. Status Report on OTC State Efforts to Promulgate Regulations Based on OTC 2001 Model Rules (as of Ma

Consumer Products 

Architectural and Industrial Maintenance Coatings 

Portable Fuel Containers 

Mobile Equipment Repair and Refinishing 

Solvent Cleaning 

Additional NOx Controls 

Distributed Generation Standards 

State Contacts and Links t

N J Effective Effective Effective Effective Effective Effective Effective Contacts: CP, PFCs: Judy Rand 

Additional NOx Controls, DG: Al

N Y Effective Effective See 2006 rule Effective Effective Effective 

In progress (Target effective date 07/01/10) 

Contact: Ron Stannard 518-402

http://www.dec.state.ny.us/webshttp://www.dec.state.ny.us/webshttp://www.dec.state.ny.us/websftp://www.dec.state.ny.us/dar/libhttp://www.dec.state.ny.us/websftp://www.dec.state.ny.us/dar/lib

P A Effective Effective 

See 2006 status report; Will rely on Fed PFC rule adopted by EPA on February 26, 2007. 72 FR 8427 

Similar rule is already in place 

Effective Effective Will consider 

Contact: Susan Hoyle, shoyle@

Additional NOx Controls http://www.pabulletin.com/secur

MERR: http://www.pacode.com/secure/dSC: http://www.pacode.com/sec

PFC: http://www.pacode.com/secure/d

CP: http://www.pacode.com/secure/dAIM: http://www.pacode.com/secure/d

R I Effective 7/09, Effective 7/09 See 2006 rule Effective (similar rule) 

Effective (similar rule) Updated 10.08 

Will consider Effective (similar rule) Contact: Barbara Morin 401-222

V T Will consider RACT** See 2006 rule RACT** RACT** RACT** In progress V A Effective Effective See 2006 rule Effective Effective 

Contact: Gary Graham (804) 69AIM: http://www.deq.virginia.gov

PFC: http://www.deq.virginia.gov

MERR: http://www.deq.virginia.g

SC: http://www.deq.virginia.gov/

CP: http://www.deq.virginia.gov/CP Info: http://www.deq.virginia.

** RACT determination required at the time of renewal of operating permit by state law 
Table

V‐3. Status Report on OTC State Efforts to Promulgate Regulations Based on OTC 2006 Model Rules (as of Ma

Consumer Products (Phase II) 

Adhesives and Sealants 

Portable Fuel Containers (w/ Kerosene) 

Diesel Chip Reflash 

Asphalt Paving 

Regional Fuel 

Additional NOx Controls 

State Contacts and Links t

C T Effective Effective Effective 

Developing an integrated heavy-duty diesel truck strategy 

Rule adoption proceeding. 

Effective statewide 

Under evaluation as part of a multi-pollutant planning effort 

Contact: Susan Amarello 860-424-3442 http://www.ct.gov/dep/cwp/vieD=1619 

D E 

Effective April 11, 2009 

Effective April 11, 2009 

Relying on federal rule 

Developing strategy 

Similar rule already in effect 

Already in effect statewide 

Effective on July 11, 2007 

Adhesives, PFC, Asphalt, Con323-4542 Regional Fuel, Chip Reflash: PAdditional NOx Controls: Franhttp://regulations.delaware.go

ml#TopOfPage

D C 

Proposed May 2007; addressing public comments 

Proposed May 2007; addressing public comments 

Proposed May 2007 No Action No Action No Action No Action Contact: Cecily Beall (202) 53

M E 

Rule adopted, Standards effective Jan 1, 2009 

Scheduled for adoption 5/21/09 

Draft rule under development 

No action 

Scheduled for public hearing 6/18/09 

No Action No Action Contact: Jeff Crawford 207-28

http://www.maine.gov/dep/air/

M D 

Proposal publication 03/31/07; Hearing 5/1/07; Final Reg Pub 06/08/07; Effective 06/18/07 

Rule adopted February 5, 2008; new standards effective April 7, 2008. Single Ply Roof Amendment: Adopted 04/29/09; Published 05/22/09; Effective 06/01/09 

Proposal publication 03/31/07; Hearing 5/1/07; Final Reg Pub 06/08/07; Effective 06/18/07 

No action Under review 

Presently in nonattainment areas, will consider regional fuel for attainment areas 

Distributed Generation regulation: Proposal publication 10/24/08; Hearing 11/25/08; Final Reg Pub 05/08/09; Effective 05/18/09 Partial HEDD consent order 2008. 

Contacts: PFC: Eddie Durant Consumer Products, AdhesiveDG: Randy Mosier 410-537-3240

M A 

Rule adopted 10/19/2007; new standards effective 1/1/2009 

Rule under development.

Will rely on 2007 Federal PFC rule (72 FR 8427) . 

No action Rule under development. Already have RFG statewide Under review 

Contacts: 

Consumer products; Adhesives 

Kavian azin.kavian@state.ma.

Proposed regulations: http://w

Final regulations: http://www.
Table

V‐4. Status Report on OTC State Efforts to Promulgate Regulations Based on OTC 2006 Model Rules (as of May 19

Consumer Products (phase II) 

Adhesives and Sealants 

Portable Fuel Containers (w/ Kerosene) 

Diesel Chip Reflash 

Asphalt Paving 

Regional Fuel 

Additional NOx Controls 

State Contacts and Links to 

N H 

Draft rule under development (on hold) 

Draft rule under development (on hold) 

Adopted No action Under review Under consideration Under review 

Contact: Mike Fitzgerald 603-2http://www.des.state.nh.us/rule

http://www.des.state.nh.us/ruleSend annual date code update 

N J 

Adopted 10/30/08 

Adopted 10/30/08 

Adopted 10/30/08 No action Adopted 3/20/09 RFG in place state wide Adopted 3/20/09 

http://www.state.nj.us/dep/a

Contacts: CP, PFCs, Adhesiv

Asphalt Paving: Stella Oluwas

Diesel Chip Reflash: John Go

Additional NOx Controls: Allan 

N Y 

Proposed Hearings 7/09 In progress Adopted 06/30/09 Evaluating court decision In progress Under consideration In progress Contact: Ron Stannard 518-40

P A 

Final rulemaking scheduled for Environmental Quality Board consideration June 16, 2008; Anticipated effective date for new categories is Jan 1, 2009 

Proposed Rulemaking schedule for Environmental Quality Board consideration August 17, 2008; Anticipated effective date is May 1, 2009 

Will rely on Fed PFC rule adopted by EPA on February 26, 2007. 72 FR 8427 

No plans to pursue at this time. 

Under consideration 

Under consideration 

Cement Kiln and Glass Furnace regulations’ public comment periods close June 23, 2008; Anticipated effective date is May 1, 2009 

Contact: Susan Hoyle 717-77shoyle@state.pa.us

www.depweb.state.pa.us/pubp

www.pacode.com/

www.pabulletin.com/

R I 

Rule Adopted May 2009, limits effective 7/1/09 

Rule Adopted May 2009, limits effective 7/1/09 

Will rely on federal rule. 

No plans to pursue 

Hearing on rule 2/09, limits will be effective 5/10 

RFG in place state wide 

No plans at this time to implement this measure. 

Contact: Barbara Morin 401-22

V T 

No plan to adopt Plan to pursue Plan to pursue 

Plan to pursue depending on legal basis 

Considering 

Under consideration, would adopt if truly regional 

No plans at this time to implement this measure. 

V A 

Notice of intended regulatory action 

Notice of intended regulatory action 

Notice of intended regulatory action 

No current plans to pursue. 

No current plans to pursue. 

No current plans to pursue. 

No current plans to pursue. 

Contact: Gary Graham (804) 6