Proposed 

Delaware 

State Implementation Plan (SIP) Revision

Supplement to Delaware’s 

September 17, 2009 CAA Section 110 “Infrastructure” State Implementation Plan (SIP) 

Submission

Delaware Department of Natural Resources and Environmental Control

December 7, 2010
2

Table of Contents

1. Summary and Purpose ------------------------------------------------------------- 3

1.1 Background ----------------------------------------------------------------------------- 5

1.2 Responsibilities ------------------------------------------------------------------------- 7

2. Transport Rule Modeling and Contribution Assessment -------------------- 7

3. Emissions ------------------------------------------------------------------------------- 8

3.1 2005 Source Sector Discussion ------------------------------------------------------- 9

3.1.1 EGUs ------------------------------------------------------------------------------------- 9

3.1.2 Non-EGU Point ------------------------------------------------------------------------- 9

3.1.3 Nonpoint --------------------------------------------------------------------------------- 9

3.1.4 Nonroad ---------------------------------------------------------------------------------- 10

3.1.5 Onroad ----------------------------------------------------------------------------------- 11

4. 2012 Projections ----------------------------------------------------------------------- 11

4.1 2012 Source Sector Discussion------------------------------------------------------- 12

4.1.1 EGUs ------------------------------------------------------------------------------------ 12

4.1.2 Non-EGU Point ------------------------------------------------------------------------ 16

4.1.3 Nonpoint -------------------------------------------------------------------------------- 16

4.1.4 Nonroad --------------------------------------------------------------------------------- 18

4.1.5 Onroad ---------------------------------------------------------------------------------- 23

5. Delaware Meets Proposed Transport Rule Budgets -------------------------- 23

6. Monitoring Data Shows Attainment --------------------------------------------- 24

7. Control Measures -------------------------------------------------------------------- 29

8. Summary ------------------------------------------------------------------------------ 30

9. Appendices ---------------------------------------------------------------------------- 31
3

1. SUMMARY AND PURPOSE

A State Implementation Plan (“SIP”) is a state plan that identifies how that state will attain and 

maintain air quality that conforms to each primary and secondary National Ambient Air Quality 

Standard (”NAAQS”). The SIP is a complex, fluid document containing regulations, sourcespecific requirements, and non-regulatory items such as plans and emission inventories.

Delaware’s initial SIP was approved by the EPA on May 31, 1972. Since this initial approval, 

the Delaware SIP has been revised numerous times to address air quality non-attainment and 

maintenance issues. This was done by updating plans and inventories, and adding new and 

revised regulatory control requirements. Delaware’s SIP is compiled at 40 C.F.R. Part 52 

Subpart I. 

This document is a revision to Delaware’s SIP. The purpose of this SIP revision is to 

supplement our September 17, 2009 SIP revision that was submitted to satisfy the requirements 

of Section 110(a)(1) and 110(a)(2) of the Clean Air Act (the Act) pursuant to the National 

Ambient Air Quality Standards (NAAQS) for Fine Particles (PM2.5) promulgated by the United 

States Environmental Protection Agency (EPA) on October 17, 2006 (71 FR 61224). 

Under the CAA, States are required to submit SIP revisions to satisfy Section 110(a)(1) and 

110(a)(2) by no later than three years from the date EPA promulgates a new or revised NAAQS 

or face findings of failure to submit. Therefore, the September 17, 2009 SIP submission made 

by the Department was timely. However, on September 25, 2009, EPA issued a guidance 

document entitled, “Guidance on SIP Elements Required Under Sections 110(a)(1) and (2) for 

the 2006 24-Hour Fine Particle (PM2.5) National Ambient Air Quality Standards (NAAQS),” 

which provided guidance on addressing the “infrastructure” elements for SIPs required under 

Sections 110(a)(1) and 110(a)(2) of the Act for the 2006 24-hour PM2.5 NAAQS. According to 

this guidance document, any state’s SIP submission to address the infrastructure element related 

to interstate transport found at 110(a)(2)(D)(i)(I) must be supported by an “adequate technical 

analysis.” This guidance document further states that it is EPA’s intention to complete a rule to 

address interstate transport in the eastern portion of the continental United States (the Transport 

Rule). This rule would replace the vacated Clean Air Interstate Transport Rule (CAIR) and 

would assist states with obligations to address interstate transport that significantly contributes to 

nonattainment in another state. 

However, Delaware could not wait for EPA’s SIP guidance or the CAIR replacement rule 

without facing findings of failure to submit for not meeting the October 17, 2009 due date for 

submittal of the 110(a)(1) and 110(a)(2) infrastructure SIP elements pursuant to EPA’s October 

17, 2006 promulgation of the 24-hour NAAQS for PM2.5. Therefore, Delaware made a timely 

SIP submission in which the Department cited to its own SIP-approved regulations to reduce 

PM2.5 precursor emissions of sulfur dioxide (SO2) and nitrogen oxides (NOx) from electric 
4

generating units, industrial boilers, and peaking units to address the interstate transport 

requirements of 110(a)(2)(D)(i)(I). 

To be clear, Delaware’s September 17, 2009 SIP submittal did not include the “technical 

analysis” called for in EPA’s September 25, 2009 guidance document because 1) the EPA 

guidance was issued too late in the process, as discussed above, and 2) because after review of 

the guidance Delaware believed the EPA required technical analysis was in line with an analysis 

of whether or not emission from the state significantly impact any area, with the result of the 

analysis being either they do or they do not impact. And, if they do impact then the state must 

take action to address the impact.

In the development of Delaware’s SIP-approved regulations to reduce PM2.5 precursor emissions 

of SO2 and NOx from electric generating units, industrial boilers, and peaking units to address 

the interstate transport requirements of 110(a)(2)(D)(i)(I), Delaware started with the assumption 

that it did significantly impact downwind areas. With this assumption, Delaware moved forward 

and regulated NOx and SO2 emissions from its large EGU and industrial boilers, to include 

EGUs with small annual emission but high daily emissions (i.e., typically referred to as high 

energy demand day units) with Best Available Control Technology (BACT) level controls. 

Because of this Delaware believed it has clearly mitigated significant transport and adequately 

addressed CAA 110 requirements.1 

Since the time of our September 17, 2009 SIP submittal, EPA proposed the Transport Rule 

(August 2, 2010). In that proposal, EPA concluded that the State of Delaware was to be included 

among the states covered by the Transport Rule. Given Delaware’s stringent SIP-approved 

EGU, peaking unit and large boiler control regulations, this was not expected. On October 1, 

2010, the Department submitted timely comments to EPA’s rulemaking docket for the proposed 

Transport Rule including extensive technical data and information to support our contention that 

Delaware should not be included in the Transport Rule. It is our belief that the comments, data,

and information we submitted on the proposed Transport Rule are more than sufficient to satisfy 

EPA’s September 25, 2009 guidance that a SIP submitted to address 110(a)(2)(D)(i)(I) include 

an adequate technical analysis. 

Despite the above, in the best interests of the State of Delaware, the Department is hereby using 

the comments, data, and information we submitted on the Transport Rule to form the basis of a 

technical analysis in support of our September 17, 2009 SIP revision to comply with EPA’s 

September 25, 2009 guidance document. Upon completion of the CAA’s required public 

 

1 This does not imply that Delaware believes transport is limited to EGU and large boiler emissions. To the 

contrary, Delaware believes programs like reasonably available control technology (RACT), new source review 

(NSR), transportation conformity, etc. are needed in all upwind areas to mitigate transport. This position is 

portrayed clearly in Delaware’s December 2009 CAA 126 petition. However, in the context of EPA transport rule, 

which is the impetus for this SIP revision, BACT level controls on EGUs are clearly adequate to mitigate significant 

impact on downwind states.
5

participation procedures, the Department will formally submit this technical analysis as a 

supplement to its September 17, 2010 SIP submission to address satisfy 110(a)(2)(D)(i)(I) for 

interstate transport along with the associated administrative materials required by 40 CFR Part 

51 Appendix v. 

1.1 BACKGROUND

This document supplements our September 17, 2009 SIP by adding more detail as to how 

Delaware meets the requirements of Clean Air Act (“CAA”) §110(a)(2)(D)(i)(I),

2

addressing 

interstate transport by demonstrating that Delaware has fulfilled its requirements to control 

sources that contribute significantly to non-attainment in, or interfere with maintenance by, 

any other State with respect to any such national primary or secondary ambient air quality 

standard which address downwind contributions (interstate transport) from Delaware sources. 

Delaware’s September 17, 2009 submittal indicated that its implementation plan and recently 

submitted SIP revisions presently contain adequate provisions prohibiting sources from emitting 

air pollutants in amounts which will contribute significantly to non-attainment or interfere with 

maintenance with any NAAQS and to prevent interference with measures related to preventing 

significant deterioration of air quality or which have to date proved adequate to protect visibility 

and to address interstate and international pollutant abatement. Specifically, under 

110(a)(2)(D)(i)(I) major stationary sources for the annual and 24-hr PM2.5 NAAQS are currently 

subject to Nonattainment New Source Review (NNSR) and Prevention of Significant 

Deterioration (PSD) permitting programs under the PSD and EOP provisions of 7 DE Admin. 

Code 1125, Preconstruction Review. As provided in the PM2.5 NSR Implementation Rule (73 

FR 28321), NNSR in New Castle County for PM2.5 will continue to be administered under the 

provisions of Appendix S until no later than May 16, 2011 when the EOP section of 7 DE 

Admin. Code 1125 and the Delaware SIP have been revised to reflect the provisions of 73 FR 

28321. Also, in Kent and Sussex counties, PM2.5 PSD activities will continue to be administered 

using PM10 as a surrogate for PM2.5, without consideration of precursors, until no later than May 

16, 2011 when changes to 7 DE Admin. Code 1125 and the SIP have been completed. Delaware 

has complied with §110(a)(2)(D) through promulgation of 7 DE Admin. Code 1146, Electric 

Generating Unit Multi-Pollutant Regulation; 7 DE Admin. Code 1142, Section 2, Control of 

NOX Emissions from Industrial Boilers and Process Heaters at Petroleum Refineries; and 7 DE 

Admin. Code 1148, Control of Stationary Combustion Turbine Electric Generating Unit 

 

2

§110(a)(2)(D)(i)(I) states, “Contain adequate provisions – (i) prohibiting, consistent with the provisions of this 

title, any source or other type of emissions activity within the State from emitting any air pollutant in amounts 

which will - (I) contribute significantly to non-attainment in, or interfere with maintenance by, any other State

with respect to any such national primary or secondary ambient air quality standard, or (II) interfere with 

measures required to be included in the applicable implementation plan for any other State under part C to prevent 

significant deterioration of air quality or to protect visibility, (ii) insuring compliance with the applicable 

requirements of sections 126 and 115 (relating to interstate and international pollution abatement).”
6

Emissions; which significantly reduce emissions from Delaware’s largest EGUs, industrial 

boilers, and peaking units. These regulations impose BACT level controls, and have been 

approved by the EPA as revisions to Delaware’s SIP.

As mentioned previously, on September 25, 2009 EPA issued a Memo3 which includes guidance 

on the technical analysis. The Memo discusses the analysis, elements therein and states, 

“Information to support the states determination with respect to significant contribution to 

nonattainment might include, but not limited to, information concerning emissions in the state, 

meteorological conditions in the state and the potentially impacted states, monitored ambient 

concentrations in the state and the potentially impacted states, the distance to the nearest area 

that is not attaining the standard, and air quality modeling.” Therefore, this analysis will 

discuss:

Evaluation of EPA’s proposed Transport Rule (TR) modeling to help provide weight-ofevidence that Delaware is not a significant contributor to downwind states 

Delaware vs. EPA TR emissions analysis to help provide weight-of-evidence that 

Delaware is not a significant contributor to downwind states

Monitoring data

Recent and significant Delaware control measures that mitigate transport 

While reading this analysis, we ask the reader to remember that: 

1. Delaware EGU projections are less than the EGU budgets in the proposed TR. 

Since those budgets are the level of SO2 and NOx emissions that states must meet to 

remedy their “significant contribution,” based on EPA modeling, and we 

demonstrate Delaware EGUs will meet those budgets in 2012, it follows that 

Delaware has met its requirements to address downwind transport. 

2. Delaware does not have the staff or resources to gather regional data, project emissions, 

and subsequently model downwind contributions from sources to every downwind 

county in the eastern U.S. Delaware further believes that expectation for such an analysis 

to be conducted by every state is entirely unreasonable and technically impractical.

Therefore, for purposes of this technical analysis Delaware Division of Air Quality 

(DAQ) will combine an EPA-Delaware emission analysis with EPA’s modeling used 

for the TR.

 

3 Guidance on SIP Elements Required Under Sections 110(a)(1) and (2) for the 2006 24-Hour Fine Particle (PM2.5) 

National Ambient Air Quality Standards (NAAQS),”
7

1.2 Responsibilities.

The agency with direct responsibility for preparing and submitting this document is Delaware 

Department of Natural Resources and Environmental Control (DNREC), Division of Air Quality

(DAQ), under the Division Director, Ali Mirzakhalili, P.E. The working responsibility for 

Delaware’s air quality planning falls within DAQ’s Planning Branch, under the Program 

Manager, Ronald Amirikian. The Planning Branch is instrumental in completing this document. 

Specifically, 

Jack Sipple, M.S., is the project leader and responsible for emission projections, as well 

as principal author of this SIP revision;

Ron Amirikian, Planning Branch Manager, QA 

Dave Fees, P.E., Managing Engineer, DAQ Emission Inventory Program, is the 

supporting lead for the 2005 base year emission inventory;

Bob Clausen, EGU analysis and projections;

Betsy Frey, M.S., is the supporting lead for PM2.5 monitoring data;

Mark Prettyman, Environmental Scientist, supporting staff and data management 

2. TRANSPORT RULE MODELING AND CONTRIBUTION ASSESSMENT 

On August 2, 2010 EPA proposed the TR to address downwind contributions of sulfur dioxides 

and nitrogen oxides. In that Rule, EPA 2012 “Base Case” emissions were modeled to determine 

whether States met a threshold for “linkage” and thus meet the criteria for “significant 

contribution to, and/or interference with maintenance” to downwind areas. The results of EPA’s 

modeling in Table 1 suggest that Delaware’s downwind contribution exceeds one or both of 

these thresholds. The “significant” thresholds are 0.20 and 0.35 ug/m3 for the annual and 24-hr 

NAAQS, respectively. 

Table 1. Delaware’s largest contribution to downwind areas based on EPA modeling in the TR

NAAQS Largest 

Downwind 

Contribution to 

Nonattainment 

(ug/m3)

Largest 

Downwind 

Contribution to 

Maintenance 

(ug/m3)

Affected Counties 

(Linkages) for 

Nonattainment

Affected Counties 

(Linkages) for 

Maintenance
8

Annual 0.20 0.14 Lancaster, PA

York, PA

None

Daily 0.50 0.36 Union, PA

Dauphin, PA

Cumberland, PA

New York, NY

As we will show later in this document, the 2005 base year that EPA used in the projections was 

flawed, because those emissions were significantly higher than what Delaware submitted in its 

2005 Periodic Emissions Inventory. Furthermore, the EPA 2012 projections were based on those 

EPA 2005 inflated numbers, which resulted in inflated 2012 numbers. And finally, because 

recent Delaware control initiatives were not included in the EPA’s 2012 projections they were

even further inflated. Subsequently, these inflated projections were used by EPA to model and 

assess whether states significantly contribute. But inflated projections used in any contribution 

assessment yields inflated contributions. Therefore, Delaware believes that if EPA used up-todate and accurate emissions data (i.e. the Delaware PEI and recent Delaware control measures), 

EPA modeling would have shown that Delaware does not significantly contribute to downwind 

areas. 

3. EMISSIONS

Delaware compared its 2005 Periodic Emissions Inventory (PEI) with EPA’s 2005 NEI (and 

2002) emissions used in their assessment of significant contributions for the TR. Delaware then 

projected its 2005 PEI emissions to 2012, and compared them to EPA’s 2012 Base Case 

emissions. Delaware’s sulfur dioxide (SO2) and nitrogen oxides (NOx) emissions are 

significantly overstated in the TR contribution assessment. 2005 and 2012 emissions can be 

found in the attachments to this document (attachment 1 contains the emission summary tables). 

EPA used the 2005 National Emissions Inventory (NEI), Version 2 for point sources, and 2002 

emissions for a few other categories, such as nonpoint sources. Alternatively, DAQ used a more 

recent and refined 2005 inventory PEI for the 2005 emissions analysis. EPA also used NMIM 

and MOVES, which are discussed in more detail below. The results of our comparison show 

that 2005 emissions differences between EPA’s TR 2005 emissions and DAQ’s 2005 PEI are 

insignificant for EGUs and non-EGU point sources, but significant in the nonpoint and nonroad 

categories. EPA apparently used a “top-down” approach for the nonpoint and marine vessels. 

Delaware used state-specific data, i.e. a “bottom-up” approach. Bottom-up approaches have 
9

always been the preferred method for emission calculations. Table 2 summarizes the 2005 

differences, with a discussion of each sector afterwards. 

4

Table 2 2005 Emissions

2005 SO2 EGU NonEGU Nonpoint Nonroad Onroad Total

Transport Rule 32,378 34,859 5,859 11,648 422 85,166

DE PEI Emissions 31,745 34,686 1,034 2,755 422 70,642

DE Emission Difference (tpy) -633 -173 -4,825 -8,893 0 -14,524

% Difference 2% 0% 82% 76% 0% 17%

2005 NOX EGU NonEGU Nonpoint Nonroad Onroad Total

Transport Rule 11,917 5,567 3,259 15,567 22,569 58,879

DE PEI Emissions 11,397 5,999 2,317 11,728 22,569 54,010

DE Emission Difference -520 432 -942 -3,839 0 -4,869

% Difference 4% -8% 29% 25% 0% 8%

3.1 2005 Source Sector Discussion

3.1.1 EGUs: EPA and Delaware PEI EGUs emission differences are insignificant for 2005.

3.1.2 Non-EGU Point: No difference in 2005. 

3.1.3 Nonpoint: The nonpoint category in Table 2 shows significant differences between EPA 

and DAQ 2005 emissions. The large discrepancy most likely lies with differences in how the 

several fuel combustion categories (industrial, commercial, and residential) were calculated. 

EPA assumed 2002 emissions for the TR 2005 fuel combustion sources, without growth.

5

 

DAQ calculated its emissions using Delaware-specific 2005 fuel sales data obtained from the US 

Department of Energy’s Energy Information Administration (EIA) publications and emission 

factors obtained from AP-42 and other EPA documents. Delaware also backs out fuel usage 

already reported under the point source or nonroad source sectors. EPA may have doublecounted the fuel combustion emissions.

Another possible reason for the difference between DAQ methods for fuel combustion and those 

employed by EPA, is that we concluded (since the 2002 inventory ) that fuel used by industrial 

and commercial non-stationary equipment (forklifts, aerial lifts, floor sweepers/scrubbers, etc.) 

was contained in the EIA state energy industrial and commercial sector usages, instead of in the 

 

4 DAQ emission tables can be found in the attachments (summaries, EGUs, non-EGUs, marine vessels and fuel 

combustion).

5

Technical Support Document (TSD) for the Transport Rule Docket. ID No. EPA-HQ-OAR-2009-0491. Table 2-1. 

Sectors Used in the TR Emissions Modeling Platform.
10

off-highway sector. Since emissions from these equipment types are included in the NONROAD 

model, we needed to back their fuel usage out of the EIA total. This did have a fairly significant 

effect.

3.1.4 Nonroad: 

The nonroad 2005 emission differences were very large, particularly for SO2 as shown in Table 

2. As will be discussed later, this is due to differing methods for marine vessel calculations. 

However, all of the non-road categories are addressed here: 

1. Nonroad equipment (the NMIM model): EPA used NMIM, but Delaware could not find 

data on EPA’s website whereby we could “separate” non-road equipment emissions from 

marine, aircraft and locomotive (MAR). However, since DAQ also used NMIM for 2005

(and national defaults for the bigger NOx sub-categories), we believe that 2005 EPA vs. 

DAQ emissions differences in nonroad equipment (NMIM) category are most likely 

insignificant, and thus not a key factor in the total nonroad emissions differences. 

2. Locomotives and non-C3 Marine: EPA used 2002 emissions.6 Delaware has refined the 

2005 PEI to use more recent emission factors and activity data. 

3. Aircraft Emissions: EPA used the 2005 NEI version. Delaware has refined its 2005 PEI 

to use more recent emission factors and/or activity data. 

4. C3 Marine Vessels: This is the sub-category likely responsible for the large differences 

between EPA and DAQ nonroad 2005 numbers (and thus 2012), i.e., EPA 2005 SO2 is 

11,648 tpy while DAQ is 2,755 tpy. EPA 2005 NOx is 15,567 tpy and DAQ’s is 11,728 

tpy. Delaware knows from experience that this category is largely responsible for SO2

emissions from nonroad sources, and a little less so for NOx. In fact, marine vessel SO2

emissions rank only behind EGUs and large industrial boilers. 

EPA obtained their 2005 emissions for the TR from the EPA rule called “Control of Emissions 

from New Marine Compression-Ignition Engines at or Above 30 Liters per Cylinder”, usually 

described as the Emissions Control Area (ECA) study, originally called SO2 (“S”) ECA.7 

Because EPA relied on rule development emissions, DAQ believes EPA’s method is a “topdown” approach, and does not estimate emissions to the level of detail undertaken by Delaware 

DAQ staff, which uses local activity data. More importantly, Delaware has learned from

discussions with OAQPS that EPA allocated C3 marine vessels to States out to 200 nautical 

miles. That is well beyond our state boundaries. Below is a summary of Delaware’s methods, 

 

6

Technical Support Document (TSD) for the Transport Rule Docket. ID No. EPA-HQ-OAR-2009-0491. Table 2-1. 

Sectors Used in the TR Emissions Modeling Platform. 

7

Technical Support Document (TSD) for the Transport Rule Docket. ID No. EPA-HQ-OAR-2009-0491. Table 2-1. 

Sectors Used in the TR Emissions Modeling Platform.
11

including improvements to the methodology for 2005 as compared to Delaware’s 2002 

inventory. 

The Delaware inventory for CMVs includes exhaust emissions from ocean-going vessels, tow 

and tug boats, ferries, and dredges, and is reported to EPA under the following SCCs: 

2280002100, 2280002200, 2280003100, and 2280003200. Delaware accounts for vessel 

cruising, maneuvering, and hoteling time-in-mode and engine energy output in kilowatt-hours.

For most of the length of the Delaware Bay and River, emissions are split between Delaware and 

New Jersey since the state boundary coincides with the shipping channel. The state boundary for 

the northern portion of New Castle County extends to low mean time on the New Jersey side of 

the river and thus all emissions from vessel traveling this stretch of river are included in 

Delaware’s inventory.

Delaware obtains individual ship movement data from the Maritime Exchange, and is able to use 

this information to determine which vessels berth at Delaware ports and which vessels transit 

Delaware waters on their way to ports in Philadelphia, Camden, and other ports north of the 

Delaware state line. The use of individual ship movement data was first obtained and used for 

the 2005 inventory. Previous inventories relied on annual ship movement data obtained from 

the US Army Corps of Engineers’ (USACE) Waterborne Commerce of the United States 

publication. The use of the Maritime Exchange data enabled Delaware to determine vessels that 

made multiple berths within the Delaware River and Bay. Prior to 2005, each vessel movement 

provided by the USACE publication was treated as a separate transit of Delaware waters from 

the mouth of the Delaware Bay to the Delaware/Pennsylvania state line.

A second important change to the methodology was to eliminate the assumption that every vessel 

traveling up and down the Delaware River and Bay was escorted by a tug boat. In conversations 

with personnel at the Maritime Exchange, few vessels receive an escort the length of the bay. 

CMVs are met by a tug a few miles before reaching port in order to assist the vessel 

maneuvering into port and up to its berth.

As a result of these important changes, the 2005 emissions were reduced by 40% or 

more from 2002 estimates, suggesting another reason why the large discrepancies exist 

between the EPA TR 2005 and DAQ’s PEI.

3.1.5 Onroad: Delaware does not have the ability to run MOVES in time for the comment due 

date. Therefore, we accept EPA’s 2005 onroad emissions as-is for purposes of this analysis.

4.0 Delaware 2012 Projections (as projected by DAQ)

DAQ used our 2005 PEI as the base year for the 2012 projections. EPA used the 2005 NEI 

version 2, 2002 emissions, MOVES and NMIM in the base year, as described above. Because 

we have shown that EPA’s nonroad and nonpoint emissions are significantly higher for SO2 and 
12

NOx in 2005, it follows that EPA’s 2012 projections for those categories would likely be higher 

too. Table 3 illustrates the magnitude of those differences. Each source sector is discussed 

afterwards in more detail. 

Table 3 2012 Projected Emissions

2012 SO2 EGU NonEGU Nonpoint Nonroad Onroad Total

Transport Rule 7,841 10,974 5,858 14,193 98 38,964

DE Projections 7,356 5,941 1,034 2,201 98 16,630

DE Emission Difference -485 -5,033 -4,824 -11,992 0 -22,334

% Difference 6% 46% 82% 84% 0% 57%

2012 NOX EGU NonEGU Nonpoint Nonroad Onroad Total

Transport Rule 4,639 5,567 3,248 15,511 10,700 39,665

DE Projections 2,418 4,504 2,315 10,370 10,700 30,307

DE Emission Difference -2,221 -1,063 -933 -5,141 0 -9,358

% Difference 48% 19% 29% 33% 0% 24%

4.1 2012 Source Sector Discussion

4.1.1 EGUs

EPA used IPM, which is a tool for predicting future regional strategies and emissions. DAQ’s 

understanding of the IPM used for the TR is that it projects current controls using an outdated Delaware NEEDS database, regional growth as well as non-enforceable controls (ex. new 

units that we know won’t come online or current units shutting down that we know won’t 

shutdown, such as Unit 3 at Conectiv). DAQ EGU projections used essentially the same 

methods inherent to IPM, except we have state specific data and information based on 

discussions with Delaware sources, which we believe is better than the EPA data.

In accordance with the definition of EGU in the rule, Delaware’s population of EGU’s consists 

of the following units: Christiana Units 11 and 14, Edge Moor Units 1, 2, 3, and 4, Hay Road 

Units 1, 2, 3, 5, 6, and 7, VanSant 11, McKee Run Unit 3, NRG Dover Units 2 and 3, Indian 

River Units 1, 2, 3 and 4, and Beasley Unit 1. These units are principally comprised of 

municipal and merchant generating units that operate within the PJM network. Operation of the 

generating units is primarily on an economic dispatch basis, which includes operational incentive 

in the southern part of the Delmarva Peninsula that experiences transmission constraints during a 

significant portion of the year. The northern part of the state also suffers some transmission 

constraint issues, primarily during high demand periods. Delaware as a state is a net importer of 

electricity, typically generating less than 50% of the electric load within the Delaware borders.
13

For this review, 2009 was selected as the base year for two reasons; 1) 2009 represented the 

latest available data and included EGU operation in compliance with recent state regulatory 

requirements, and 2) region-specific information was available from PJM to predict 2012 

generation requirements. For determining the 2009 generation and emissions data for the 

population of Delaware’s generating units, data from EPA’s CAMD database was utilized. 

Generation data for each of the units came from annual CAMD data. In order to be more 

representative of emission controls that came into effect for some of the units on May 1, 2009 in 

response to Delaware regulatory requirements, NOx and SO2 emission data was taken to be the 

2009 CAMD ozone season data. To determine the electric demand increase, PJM’s January 

2010 Load Forecast Report was consulted. Delaware is part of PJM’s DPL region. In PJM 

report, PJM predicted increases in annual electric consumption for the: 1.4% above 2009 for 

2010, 1.4% above 2010 for 2011, and 1.5% above 2011 for 2012. These increases along with the 

2009 CAMD data were utilized to estimate the 2012 generation for the Delaware EGUs on a 

facility and unit basis.

For the purpose of this evaluation, the 2012 generation for the Christiana Units 11 and 14 was 

assumed to be that grown from the 2009 data. The 2012 NOx and SO2 emission rates were 

assumed to remain the same as the 2009 data, as there are no known plans for changes in 

emission controls for these units through 2012.

The recent new owner of Edge Moor Unit 3 has indicated that Edge Moor Unit 3 will no longer 

fire coal fuel, but will operate on its current alternate fuels of residual fuel oil, natural gas, and 

landfill gas. Because this unit also is the normal steam supply for an adjacent industrial plant, its 

operation is not as directly dependent upon economic dispatch as other units in the region. As 

the unit will already be on line for support of the industrial facility and not subject to 

startup/shutdown costs, it will remain able to pick up economic dispatch/opportunity load, 

tending to keep the overall capacity factor at approximately historic levels in spite of a change in 

fuel costs. Regarding NOx emissions, the unit was assumed to come in compliance with the 

requirements of Delaware’s 7 DE Admin Code 1146, 0.125 lb. /MMBTU. Regarding SO2

emissions, it was assumed that the SO2 emission rate would be that demonstrated by Edge Moor 

Unit 5 during 2009, as Edge Moor Unit 5 already fired the same set of fuels that Edge Moor 3

will be utilizing with similar fuel costs and constraints.

The recent new owner of Edge Moor Unit 4 has indicated that the Edge Moor Unit 4 will no 

longer fire coal fuel, but will operate in its current alternate fuels of residual oil, natural gas, and 

landfill gas. Because of the increase in fuel costs, it is assumed that this unit’s position in the 

economic dispatch hierarchy will change and the unit will be called on PJM less frequently. For 

this review, Edge Moor Unit 4’s annual capacity factor was assumed to be 3%, which is similar 

to other oil/gas steam units in the area. Regarding NOx emissions, the unit was assumed to come 

in compliance with the requirements of Delaware’s 7 DE Admin Code 1146, 0.125 lb. 

/MMBTU. Regarding SO2 emissions, it was assumed that the SO2 emission rate would be that 
14

demonstrated by Edge Moor Unit 5 during 2009, as Edge Moor Unit 5 already fired the same set 

of fuels that Edge Moor 4 will be utilizing with similar fuel costs and constraints. The drop in 

generation from the 2009 level for this unit is assumed to be picked up evenly by the adjacent six 

Hay Road 1-6 combustion turbines and associated combined cycle steam units.

For the purposes of this evaluation, the 2012 generation for Edge Moor Unit 5 was assumed to be 

that grown from the 2009 data. The 2012 SO2 emission rates were assumed to remain the same 

as the 2009 data, as there are no known plans for changes in SO2 controls for this unit through 

2012. Regarding NOx emissions, the unit was assumed to come in compliance with the 

requirements of Delaware’s 7 DE Admin Code 1146, 0.125 lb./MMBTU.

For the purposes of this evaluation, the 2012 generation for each of the six Hay Road units was 

the 2009 values increased for generation growth and to also include the generation dropped from 

Edge Moor Unit 4 as described above (the generation increase was evenly split between the six 

units). NOx and SO2 emission rates for 2012 were assumed to remain the same as the 2009 

values as there are no known plans for the addition of any controls prior to 2012.

Indian River Units 1 and 2 were assumed to be mothballed prior to 2012 in compliance with an 

existing consent decree.

For the purposes of this evaluation, generation levels for Indian River Unit 3 and 4 were 

evaluated together to account for the loss in generation associated with the Indian River Units 1 

and 2 due to IR 1&2 shutdown, and to account for transmission constraints during high electric 

demand with Indian River Units 1 and 2 out of service. Therefore the 2012 generation levels for 

both Indian River Units 3&4 increased noticeably due to both generation growth and to account 

for the makeup for the Indian River Units 1 and 2 shutdowns. The evaluation indicated that there 

were 1008 hours where the generation requirements appeared to exceed the ability of Indian 

River Units 3 and 4. It was assumed that this shortfall in generation had to be made up by Kent 

County units due to grid reliability, stability, and voltage control reasons. McKee Run Unit 3 

was evaluated to be able to assume 80,976 MWh of the estimated shortfall, and the remaining 

shortfall (16,267 MWh) was assigned evenly to the two NRG Dover CT units. The 2012 

generation values for McKee Run Unit 3 and NRG Dover Units 2 and 3 were revised to reflect 

these increases.

For the purposes of this evaluation, the 2012 Indian River Unit 3 SO2 and NOx emission rates 

were assumed to be unchanged from the 2009 values.

For the purposes of this evaluation, the 2012 Indian River Unit 4 NOx and SO2 emission rates 

were assumed to comply with an existing consent decree’s emission rate limitations of 0.2 

lb/MMBTU for SO2 and 0.1 lb/MMBTU for NOx.
15

For the purposes of this evaluation, the 2012 generation from McKee Run Unit 3 was assumed to 

increase from 2009 due to both generation growth and the shortfall related to the Indian River 

units, as discussed above. The 2012 NOx and SO2 emission rates were assumed to be the same 

as 2009 as there are no known plans for additional emission controls prior to 2012.

For the purposes of this evaluation, the 2012 VanSant Unit 11 generation was increased from 

2009 due to generation growth, and the 2012 NOx and SO2 emission rates were assumed to be 

the same as 2009 as there are no known plans for additional emission controls prior to 2012.

For the purposes of this evaluation, the 2012 generation for NRG Dover Units 2 and 3 was 

increased from 2009 due to both generation growth and the shortfall from the Indian River 

facility as discussed above (shortfall was evenly split between the two units). The 2012 NOx 

and SO2 emission rates were assumed to remain the same as 2009 as there are no known plans 

for additional emission controls prior to 2012.

For the purposes of this evaluation, the 2012 generation for the Beasley Unit 1 was increased 

from 2009 due to generation growth. The 2012 NOx and SO2 emission rates were assumed to 

remain the same as 2009 as there are no known plans for additional emission controls prior to 

2012. 

2012 EGU emissions are summed in Table 3. Detailed data is available in the attachment 1 to 

this document. 

Table 4 shows that even if DAQ EGU 2012 emissions are assumed to be the same as EPA’s

2012 IPM projections, which is not a good assumption given the Delaware specific data 

discussed above, the overall differences are still significant (The table also reflects removal of

OTW NOx CAPS at the refinery in the non-EGU sector). 

Table 4 2012 Projected Emissions Substituting EPA IPM runs for DE projected EGUs

2012 SO2 EGU NonEGU Nonpoint Nonroad Onroad Total

Transport Rule 7,841 10,974 5,858 14,193 98 38,964

DE Projections 7,841 5,941 1,034 2,201 98 17,115

DE Emission Difference 0 -5,033 -4,824 -11,992 0 -21,849

% Difference 0% 46% 82% 84% 0% 56%

2012 NOX EGU NonEGU Nonpoint Nonroad Onroad Total

Transport Rule 4,639 5,567 3,248 15,511 10,700 39,665

DE Projections 4,639 4,934 2,315 10,370 10,700 32,958

DE Emission Difference 0 -633 -933 -5,141 0 -6,707

% Difference 0% 11% 29% 33% 0% 17%
16

4.1.2 Non-EGU Point Sources

DAQ followed EPA’s methods and assumed zero growth for non-EGU point sources, and then 

applied controls as discussed shortly. There is a significant difference in SO2 and NOx, as 

shown in Table 3. This is due to control strategies which will be discussed later in this 

document, which presumably the EPA was unaware of when developing the Rule. 

Non-EGU Point Source Controls 

The following is a list of significant SO2 and NOx controls, which Delaware has adopted to 

further reduce emissions by 2012. 

A May 2010 agreement between the Department and the Delaware City Refining 

Company placing a facility-wide NOx cap of 2,225 tons per year (TPY). This yields a 

10% reduction by 2012 and a 40% reduction by 2014. 

Dover Air Force Base - Ceased using residual fuel oil in March 2010; will replace central 

boiler plant with small natural gas-fired package boilers. Boilers No. 1 – 4 retired. 

DuPont Stine-Haskell Laboratory - Removed Boilers 3 and 4 (fuel oil # 6) 

DuPont Wilmington Office Building - Issued construction permits for natural gas 

conversion with # 6 fuel as back up (permitted up to 10% # 6 usage) 

Mountaire Farms of Delaware Inc. -Millsboro - Switching to Nat Gas

SPI Poly-OLs - Boiler No. 1 removed

Invista - Boilers 1 and 3 (coal) will be retired by 2012, Boiler 2 (coal/# 6) was retired on 

12/09 (Consent Decree)

Dow Reich hold Specialty Latex LLC – Shutdowns of: Flare, #6 Fuel Oil Fired Boiler, 

Natural Gas & #6 Fuel Oil Fired Boiler, Emergency Generator

4.1.3 Nonpoint Sources

Delaware did not grow or control nonpoint source emissions for the 2012 projections – our 2012 

projections are the same as our 2005 PEI. Previously, we discussed how SO2 and NOx were 

primarily from fuel combustion for Delaware area sources. 

Note that DAQ has historical sales information from the U.S. Energy Information Administration 

(EIA) which shows 2009 distillate and residual fuel-sales in Delaware have decreased by 45% 

and 57%, respectively since 2000. See Figures 1 and 2. Regardless, DAQ assumed zero growth 

for those categories to be conservative. If we included the negative growth in our projections, 

the 2012 emissions would be even less. But we took the conservative approach. 
17

Figure 1 

Figure 2 
18

4.1.4 Nonroad Mobile Sources

Locomotives and non-C3 Marine: Delaware assumed no growth and controls. Therefore, the 

2012 emissions are the same as 2005. This results in a conservative projection, since the 

Nonroad Rule is not taken into account. 

Aircraft Emissions: Delaware assumed no growth and controls, because the large majority of 

NOx is from Dover Air Force Base (aircraft SO2 emissions are insignificant). We determined a 

2007-2013 growth factor of 1.00 for Dover Air Force Base as part of our 2006 PM2.5 and Ozone 

SIP development process. Therefore, we assume 2012 emissions are the same as 2005. 

Nonroad Equipment

Nonroad equipment (NMIM): Delaware relied upon 2012 projections developed as part of 

MANEVU’s consultation process for Regional Haze SIPs for this category, due to time 

constraints. Those estimates were peer-reviewed by OTC/MANEVU states.

EPA’s NMIM2005 model and NONROAD2005 model was used to estimate annual emission 

projections of non-road engines in all MANE_VU states, including Delaware as part of the 

Regional Haze consultation process. A Contractor was hired to facilitate the projections 

(MACTEC). 

The controls for non-road mobile engines (except aircraft, locomotives, and marine vessels) that 

were applied when projecting 2012 emissions include all relevant federal rules, such as fuel 

sulfur content rule, gasoline Reid Vapor Pressure (RVP) requirements, and reformulated fuel 

programs. Controls for the 2012 emissions include all relevant federal rules and requirements, as 

outlined below.

(1) Phase I and Phase II Emissions Standards for Gasoline-Powered Non-Road Utility Engines, 

Federal Rule 

This standard promulgated by the EPA applies to VOC emissions from small non-road, 

spark-ignition (i.e., gasoline-powered) utility engines, as authorized under 42 U.S.C. 

§7547. The measure affects gasoline-powered (or other spark-ignition) lawn and garden 

equipment, construction equipment, chain saws, and other such utility equipment as 

chippers and stump grinders, wood splitters, etc., rated at or below 19 kilowatts (an 

equivalent of 25 or fewer horsepower). Phase 2 of the rule applied further controls on 

handheld and non-handheld outdoor equipment. See References 4-2, 4-3, and 4-4.

(2) Emissions Standards for Diesel-Powered Non-Road Utility Engines of 50 or More 

Horsepower, Federal Rule 
19

This standard promulgated by the EPA applies to VOC and NOX emissions from nonroad, compression-ignition (i.e., diesel-powered) utility engines, as authorized under 42 

U.S.C. § 7547. The measure affects diesel-powered (or other compression-ignition) 

construction equipment, industrial equipment, etc., rated at or above 37 kilowatts (37 

kilowatts is approximately equal to 50 horsepower). See References 4-5, 4-6, and 4-7.

(3) Emissions Standards for Spark Ignition (SI) Marine Engines, Federal Rule 

This standard promulgated by the EPA applies to exhaust PM, VOC and NOx emissions 

from new spark-ignition (SI) gasoline marine engines, including outboard engines, 

personal watercraft engines, and jet boat engines. Of nonroad sources studied by EPA, 

gasoline marine engines were found to be one of the largest contributors of hydrocarbon 

(HC) emissions (30 percent of the nationwide nonroad total). 

(4) Emissions Standards for Large Spark Ignition Engines, Federal Rule 

This EPA measure controls VOC and NOx emissions from several groups of previously 

unregulated nonroad engines, including large industrial spark-ignition engines. 

The starting point for the emission projections was Version 3 of the MANE_VU 2002 Nonroad 

emission inventory (Documentation of the MANE-VU 2002 Nonroad Sector Emission Inventory, 

Version 3, Draft Technical Memorandum, March 2006). MACTEC’s approach to developing 

emission projections for these sources was to use combined growth and control factors 

developed from emission projections for U.S. EPA’s Clean Air Interstate Rule (CAIR) 

development effort. MACTEC obtained emission projections developed for the CAIR rule.

MACTEC then calculated the combined growth and control factors by determining the ratio of 

emissions between 2002 and each of the MANE-VU projection years (2009, 2012, and 2018).

The CAIR emissions were available for 2001, 2010, 2015 and 2020. Thus, they developed 

intermediate year estimates using linear interpolation between the actual CAIR years and the 

MANE-VU years.

Using this approach MACTEC developed State/county/SCC/pollutant growth/control factors for 

use in projecting the MANE-VU base year data to the out-years. These values were then used to 

multiply times the base year value to obtain the projected values. Since the development of the 

CAIR factors included both growth and controls, no separate control factors were developed for 

these sources except where exceptions to this method were used for States that requested 

alternative growth/control methods. Because emissions from aircraft, commercial marine 

vessels, and locomotives are not projected by the NONROAD model, emission projections for 

these sources were developed separately, as described below. 
20

Commercial Marine Vessels:

C3 Marine Vessels: EPA grew base year 2002 emissions were grown to future years without 

Emissions Control Area (ECA) or International Marine Organization (IMO) global NOx and SO2

controls.8 Delaware grew 2005 emissions to 2012 to include growth and controls per EPA 

“Regulatory Impact Analysis: Control of Emissions of Air Pollution from Category 3 Marine 

Diesel Engines, EPA420-R-09-019.” 

For the purpose of emission regulations, marine engines are divided into three categories based 

on displacement (swept volume) per cylinder. Category 1 and Category 2 marine diesel engines 

typically range in size from about 500 to 8,000 kW (700 to 11,000 hp). These engines are used 

to provide propulsion power on many kinds of vessels including tugboats, push boats, supply 

vessels, fishing vessels, and other commercial vessels in and around ports. They are also used as 

stand-alone generators for auxiliary electrical power on many types of vessels. Category 3 

marine diesel engines typically range in size from 2,500 to 70,000 kW (3,000 to 100,000 hp). 

These are very large marine diesel engines used for propulsion power on ocean-going vessels 

such as container ships, oil tankers, bulk carriers, and cruise ships.

The majority of vessels in this category are powered by diesel engines that are either fueled with 

distillate or residual fuel oil blends. For the purpose of emission inventories, EPA has assumed 

that Category 3 vessels primarily use residual blends while Category 1 and 2 vessels typically 

used distillate fuels. 

EPA developed regional emission inventories for Category 1 & 2 vessel and Category 3 vessels 

for calendar years 2002 through 2040. The data DAQ used to develop the 2012 emission 

projections (for both a baseline and controlled scenario) are documented in Regulatory Impact 

Analysis: Control or Emissions of Air Pollution from Locomotive Engines and Marine 

Compression Engines Less than 30 Liters Per Cylinder, EPA420-R-08-001a 

(http://www.epa.gov/otaq/regs/nonroad/420r08001a.pdf), Regulatory Impact Analysis: Control 

of Emissions of Air Pollution from Category 3 Marine Diesel Engines, EPA420-R-09-019 

(http://www.epa.gov/otaq/regs/nonroad/marine/ci/420r09019.pdf )and Proposal to Designate an 

Emissions Control Area for Nitrogen Oxides, Sulfur Oxides, and Particulate Matter, EPA-420-R09-007 (http://www.epa.gov/otaq/regs/nonroad/marine/ci/420r09007-chap2.pdf). DAQ used the 

EPA data from these RIAs to develop separate growth and control factors for Category 1 &2 

vessels (diesel) and Category 3 vessels (residual). 

CMV Diesel Growth Factors

EPA used a variety of data sources to project fuel consumption by Category 1 & 2 engines, 

account for the impact of existing engine regulations (i.e., the 2004 Clean Air Nonroad Diesel 

 

8

Technical Support Document (TSD) for the Transport Rule Docket. ID No. EPA-HQ-OAR-2009-0491. Page 12.
21

Rule that will decrease the allowable levels of sulfur in fuel used in locomotives by 99 percent) 

and marine vessel fleet composition to develop baseline inventory projections for all years up to 

2040. Using the EPA-provided baseline inventory projections, we calculated growth factors for 

each pollutant based on the ratio of the future year baseline emissions (2012) to the 2005 

estimated emissions (emissions data from EPA 420-R-08-001a, May 2008). CMV Diesel 

Control Factors

In March 2008, EPA finalized a three part program that will dramatically reduce emissions from 

marine diesel engines below 30 liters per cylinder displacement. The 2008 final rule includes the 

first-ever national emission standards for existing marine diesel engines, applying to engines 

larger than 600kW when they are remanufactured. The rule also sets Tier 3 emissions standards 

for newly-built engines that are phasing in from 2009. 

Using the EPA-provided controlled inventory projections, we calculated controlled factors for 

each pollutant (emissions data from EPA 420-R-08-001a, May 2008). 

CMV Residual Oil Growth Factors

EPA’s Emissions TSD, states “Class 3 commercial marine vessel sector (seca_c3): base year 

2002 emissions grown to future years without Emissions Control Area (ECA) or International 

Marine Organization (IMO) global NOX and SO2 controls and did not apply sulfur controls for 

C3 marine engines in 2012. ” 9 

DAQ re-projected this category’s emissions using our 2005 PEI. EPA used a variety of data 

sources to project fuel consumption by Category 3 engines, to account for the impact of existing 

engine regulations (i.e., the 2003 Tier 1 Marine Diesel Engines rule and marine vessel fleet 

composition to develop baseline inventory projections for all years up to 2040. EPA projected 

emissions for nine U.S. regions. The East Coast Region extends roughly from the Florida Keys 

to the Maine/Canada border. Using the EPA-provided baseline inventory projections for the East 

Coast Region in EPA420-R-09-019, DAQ calculated growth factors for each pollutant based on 

the ratio of the 2012 East Coast baseline emissions in 2012 to the 2005 estimated emissions. 

CMV Residual Oil Control Factors

On December 22nd, 2009, EPA announced final emission standards under the Clean Air Act for 

new marine diesel engines with per-cylinder displacement at or above 30 liters (called Category 

3 marine diesel engines) installed on U.S.-flagged vessels. The final engine standards are 

equivalent to those adopted in the amendments to Annex VI to the International Convention for 

the Prevention of Pollution from Ships (a treaty called "MARPOL"). The emission standards 

apply in two stages: near-term standards for newly-built engines will apply beginning in 2011, 

 

9

Technical Support Document (TSD) for the Transport Rule Docket. ID No. EPA-HQ-OAR-2009-0491. Page 12, 

bullet 2. 
22

and long-term standards requiring an 80 percent reduction in nitrogen dioxides (NOx) will begin 

in 2016. EPA also adopted changes to the diesel fuel program to allow for the production and 

sale of diesel fuel with up to 1,000 ppm sulfur for use in Category 3 marine vessels. The 

regulations generally forbid production and sale of fuels with more than 1,000 ppm sulfur for use 

in most U.S. waters, unless operators achieve equivalent emission reductions in other ways. 

On March 26, 2010, the International Maritime Organization (IMO) officially designated waters 

off North American coasts as an emissions control area (ECA) in which stringent international 

emission standards will apply to ships. In practice, implementation of the ECA means that ships 

entering the designated area would need to use compliant fuel for the duration of their voyage 

that is within that area, including time in port as well as voyages whose routes pass through the 

area without calling on a port. The North American ECA includes waters adjacent the Atlantic 

extending up to 200 nautical miles from east coast of the United States. The quality of fuel that 

complies with the ECA standard will change over time. From effective date in August, 2012 

until 2015, fuel used by all vessels operating in designated areas cannot exceed 1.0 percent sulfur 

(10,000 ppm). (Beginning in 2015, fuel used by vessels operating in these areas cannot exceed 

0.1 percent sulfur (1,000 ppm. Beginning in 2016, NOx aftertreatment requirements become 

applicable).

Using the EPA inventory projections in EPA 420-R-09-019, we calculated 2005-2012 NOx 

combined growth and control factors. The growth and control factor calculations are provided in 

the spreadsheets. 

DAQ took a somewhat different approach for SO2, however. DAQ contacted U.S. EPA, Office 

of Transportation and Air Quality, Assessment and Standards Division (ASD) and learned that 

10,000 ppm (1%) sulfur limits will not “enter into force” until August 1, 2012. As a result, we 

used EPA 420-R-09-019 to determine growth, but developed our own control factor based on 

existing residual fuel averages of 2.7% sulfur.10 Dividing the 1% limits that take effect on 

August 1, 2012 by 2.7% gives a control factor of 0.37. DAQ multiplied the growth factor by the 

control factor (1.00) to 2005 PEI emissions to give 1,536 tpy from January 1 through July 31, 

2012, and the control factor (0.37) by the growth factor to give 406 tpy for the remainder of the 

year, for a total of 1,804 tpy. See Table 5.

 

10 U.S. Environmental Protection Agency Current Methodologies in Preparing Mobile Source Port-Related Emission 

Inventories, Final Report, Table 2-9. April 2009. ICF International
23

Table 5 C-3 Marine Engine SO2 Emissions from residual fuel oil

Date

2005 

Emissions

05_12 

Growth

Control 

Factor

Growth + 

Control 2012 tpy

Jan 1 - July 31 

tons 1,100 1.40 1.00 1.40 1,536

Aug 1 - Dec 31 

tons 786 1.40 0.37 0.52 406

Totals 1,886 1,942

4.1.5 Onroad Mobile Sources: 

EPA used the MOVES model to estimate Delaware 2005 emissions and 2012 projections. Due 

to time constraints, Delaware Division of Air Quality (DAQ) assumed for purposes of this study 

that the mobile emissions generated by MOVES are accurate for 2005 and 2012. Therefore, no 

differences occur as shown in Tables 2 and 3. 

5. DELAWARE MEETS PROPOSED TRANSPORT RULE BUDGETS

Despite that EPA inventories for DE are inflated, EPA’s TR indicates that Delaware has met its 

obligations to mitigate transport, i.e.: 

Without variability limits, EPA proposes at 40 CFR 97.410 a 2012 Delaware NOx budget 

of 6,206 TPY, and at 40 CFR 97.710 a 2012 Delaware SO2 budget of 7,784 TPY. EPA 

has indicted that a state’s emissions budget “...is the quantity of emissions that would 

remain in that state from covered sources after elimination of that portion of each state’s 

significant contribution and interference with maintenance that EPA has identified in 

today’s proposal, before accounting for the inherent variability in power system 

operations... The state emissions budget is a mechanism for converting the quantity of 

emissions that a state must reduce (i.e., the state’s significant contribution and 

interference with maintenance) into enforceable control requirements. In other words, it 

provides a quantity of emissions to use in developing a remedy..." 

EPA’s 2012 base case emissions for Delaware EGU’s are 4,639 TPY for NOx and 7,841 TPY 

for SO2, Since the EPA is establishing Delaware’s EGU budgets at a level that is not less than 

its 2012 base case emissions, Delaware has already met its obligation to remedy downwind 

contributions for NOx and SO2, using EPA’s own numbers.

11

Furthermore, Delaware calculated its own 2010 EGU projections, which are more accurate than 

EPA’s IPM method (DAQ has first-hand knowledge of our sources plans, recent permits and 

 

11 The difference between the EPA 2012 base case SO2 inventory and the budget for Delaware is 57 TPY. By 

Delaware correcting the problems with the inventory 1) overall modeled contributions would be much less given 

that EPA’s 2012 SO2 projections are inflated on the order of 57%, and 2) Delaware’s 2012 EGU projection will be 

less than the budget.
24

agreeements). As can be seen in table 3, DAQ 2012 projections are 7,356 tpy and 2,418 for SO2

and NOx, respectively. These are less than EPA’s budgets in the TR (7,784 tpy SO2 and 6,206

tpy NOx), and thus provide additional evidence to EPA’s projections of our EGUs, that 

Delaware has mitigated its significant contribution to downwind sources.

6. MONITORING DATA SHOWS ATTAINMENT 

The EPA Guidance Memo suggests that States include a discussion of monitors in their analysis. 

As can be seen from Tables 6 - 11 all monitors in DE, NJ, Southeastern PA and the NY CMSA 

are attainment using 2007-2009 design values,

12 including those counties for which the TR 

showed a linkage to Delaware.13 DNREC emphasises that all of these counties are in 

attainment prior to:

Delaware’s Phase II (SO2 controls) multi-pollutant regulation taking effect in 2012

Invista coal unit shutdown for Units 1 and 2

Indian River Units 1, 2 and 3 coal-unit shutdowns

Connectiv Edgemoor Power Plant – Unit 3 and 4 switching from coal to natural gas/# 6 

oil backup

Reductions from implementation of the final transport rule 

Table 6 Delaware 2007-2009 annual monitoring data

PM2.5 values

New Castle 

County

Kent 

County

Sussex 

County

Bllfte

MLK

-a

Nwrk

-a Lums Dover Killens Seaford

2007 13.4 14.4 13.4 12.5 12.1 12.1 13.2

2008 13.0 13.5 12.6 11.6 11.2 11.3 12.2

2009 10.2 11.2 10.6 10.0 9.4 9.5 9.7

 

12 A few monitors in PA, NY and NJ were either shut down or had incomplete data for one year. However, the 

latest data shows those monitors in attainment nonetheless. Also, all monitors in MD are in attainment, based on 

discussions with MARAMA. 

13 The Dauphin County, PA monitor was not operational in 2009 so DAQ averaged 2007-2008 for purposes of this 

analysis. NOTE: this average is not meant to mean “design value” for that monitor. Nonetheless the data shows

compliance with the NAAQS for 2009 (see Tables 12 and 13). 
25

Table 7 Delaware annual 3-yr design values 2007-2009 

PM2.5 design values

New Castle 

County

Kent 

County

Sussex 

County

Bllfte

ML

K-a

Nwrk

-a Lums Dover Killens Seaford

2007-2009 12.2 13.0 12.2 11.3 10.9 11.0 11.7

Table 8 Delaware 24-hr 2007-2009 monitoring data

New Castle 

County

Kent 

County

Sussex 

County

PM2.5 98th percentiles Bllfte

MLKaNwrka Lums Dover Killens Seaford

2007 32.3 33.6 31.0 29.6 30.2 30.9 32.5

2008 30.1 34.8 28.6 28.1 28.7 27.6 27.0

2009 23.2 28.4 23.4 20.6 19.4 20.7 20.2

Table 9 Delaware 24-hr 3-yr design values 2007-2009

New Castle 

County

Kent 

County

Sussex 

County

PM2.5 3-yr 

Averages Bllfte

MLKaNwrkaLum

s Dover

Killen

s Seaford

2007-2009 29 32 28 26 26 26 27

Table 10 Philadelphia CMSA monitoring data – daily and annual

PHILADELPHIA NONATTAINMENT AREA Daily PM2.5 Annual PM2.5

Stat

e

County Monitor Site AQS 

Monitor ID

200

7

200

8

2009

*

2007-09 

DV**

200

7

200

8

2009

*

2007-09 

DV**

NJ Camden Camden Trailer 34 007 

0003 34 34 37 35 12.2 13.7

13.6 

(no 

Q4)

13.1

Camden Pennsauken 34 007 

1007 35 28 25 29 14.0 11.8 9.5 11.7

Gloucester Gibbstown 34 015 

5001 31 27 22 27 13.4 11.5 9.3 11.4
26

DE New 

Castle Bellefonte 10 003 1003 32 30 23 29 13.4 13.0 10.2 12.2

New 

Castle MLK-a

10 003 

2004 34 35 28 32 14.4 13.5 11.2 13

New 

Castle Nwrk-a

10 003 

1012 31 29 23 28 13.4 12.6 10.6 12

New 

Castle Lums 10 003 1007 30 28 21 26 12.5 11.6 10.0 11

PA Bucks Bristol 42 017 

0012 35 31 26 31 13.0 13.5 10.8 12.4

Chester New Garden 42 029 

0100 38 32 31

34 14.1 14.7 14.2 14.3

Delaware Chester 42 045 

0002 35 29 27

30 14.5 14.7 12.1 13.7

Montgomer

y

Norristown 42 091 

0013 30 24 27 27 13.1 12.1 10.4 11.9

Philadelphi

a

LAB 42 101 

0004 35 35 26 32 13.7 13.0 10.9 12.5

Philadelphi

a

NEA 42 101 

0024 34 31 26 30 12.9 12.0 9.9 11.6

Philadelphi

a

CHS, Broad St.

42 101 

0047 35 33 29

32 14.4 13.5 11.1 13.0

Philadelphi

a

RIT-F

42 101 

0055 NA 35 29 NA NA 13.5 11.3 NA

Philadelphi

a

FAB-FA 42 101 

0057 33 33 28 31 12.0 13.3 11.1 12.1

Philadelphi

a

Elmwood, 

Amtrak

42 101 

0136 32 NA NA NA 13.3 NA NA NA

Notes

* = 98th percentile for the year, not final

** =Design Value=average of three year period, not final. Three years of annual mean concentrations for PM2.5 are 

used to calculate the design value at a monitor.

NA = Data Not Available

SD = Monitor Shutdown

Data sources are either from the State Agency or AirData (EPA's public query system that accesses AQS)

Table 11 New York nonattainment area

NEW YORK NONATTAINMENT AREA Daily PM2.5 Annual PM2.5

State County Monitor Site

AQS 

Monitor 

ID

07 08 09* 07-09 

DV** 07 08 09* 07-09 DV**

CT Fairfield Roosevelt School 09 001 

0010 30 32 31 31 12.7 11.9 10.2 11.6

Fairfield Danbury 09 001 

1123 30 28 32 30 12.0 11.7 9.6 11.1

Fairfield Norwalk 09 001 

3005 32 26 31 30 11.9 11.8 9.9 11.2

Fairfield Westport 09 001 

9003 29 31 34 31 10.9 10.2 9.5 10.2

New Haven Woodward Avenue 09 009 

0026 30 31 34 31 11.6 11.5 9.8 11.0

New Haven James Street 09 009 

0027 31 32 35 32 11.5 11.3 10.2 11.0

New Haven State Street 09 009 

1123 31 32 35 32 12.3 12.1 10.4 11.6

New Haven New Haven 09 009 

2008 29 25 29 28 10.8 10.6 8.9 10.1
27

New Haven Bank Street 09 009 

2123 33 28 34 32 12.0 11.7 9.8 11.2

NJ Bergen Fort Lee 34 003 

0003

35 32 27 31 13.3 11.6 9.0 11.3

Essex Newark Cultural 

Center

34 013 

0015

35 29 SD NA 13.4 13.7 SD NA

Hudson Jersey City Primary 34 017 

1002 35 32 29 32 13.2 12.1 10.3 11.9

Hudson Union City 34 017 

2002 93 33 25 33 15.1 13.3 10.7 13.0

Mercer Trenton 34 021 

0008 33 31 23 29 12.1 11.2 9.2 10.8

Mercer Washington 

Crossing

34 021 

8001 27 28 25 27 10.2 10.0 7.8 9.3

Middlesex New Brunswick 34 023 

0006 30 29 21 27 12.3 10.9 8.0 10.4

Morris Morristown 34 027 

0004 32 24 22 26 11.5 9.4 8.1 9.7

Morris Chester 34 027 

3001 31 24 21 26 10.4 8.8 7.1 8.8

Passaic Paterson 34 031 

0005 37 29 26 30 13.5 11.4 8.9 11.3

Union Elizabeth Turnpike 

Primary

34 039 

0004 35 34 28 32 13.9 12.9 11.2 12.7

Union Elizabeth 

Downtown

34 039 

0006 36 31 26 31 13.1 12.4 9.3 11.6

Union Rahway 34 039 

2003 33 30 25 29 13.2 12.0 9.3 11.5

NY Bronx Morrisania 36 005 

0080 36 33 30 33 15.6 13.5 12.7 13.9

Bronx

200th Street And 

Southern Blvd, 

Botanical Garden

36 005 

0083/013

3

33 NA 27 30 13.2 11.7 10.0 11.6

Bronx E. 156th St. 36 005 

0110 34 33 31 32 12.7 11.8 10.8 11.8

Brooklyn JHS 126 36 047 

0122 34 31 27 31 13.9 12.0 10.7 12.2

Nassau Cedarhurst 36 059 

0008 29 29 26 28 11.1 10.9 9.0 10.3

New York PS 59 36 061 

0056 37 33 NA NA 16.1 15.9 NA NA

New York Post Office,350 

Canal Street

36 061 

0062 35 NA NA NA 15.8 NA NA NA

New York JHS 45 36 061 

0079 34 33 29 32 13.6 12.4 10.5 12.2

New York PS 19 36 061 

0128 38 26 29 31 15.6 13.1 12.0 13.6

New York PS 124 36 061 

0134 37 32 29 33 13.3 13.2 11.6 12.7

Queens Newburgh, 55 

Broadway

36 071 

0002 30 31 21 27 10.6 9.6 7.9 9.4

Queens Queens College 36 081 

0124 32 31 27 30 11.4 11.0 9.6 10.7

Staten 

Island Port Richmond 36 085 0055 33 29 25 29 13.0 12.1 9.8 11.6

Staten 

Island Susan Wagner HS 36 085 0067 29 28 23 27 11.5 10.8 8.5 10.3

Suffolk

East 

Farmingdale/Babylo

n

36 103 

0001 29 27 22 26 10.9 10.1 8.1 9.7

Westcheste

r

Mamaroneck 36 119 

1002 31 31 27 29 11.7 11.0 9.1 10.6

Notes

* = 98th percentile for the year, not final

** =Design Value=average of three year period, not final. Three years of annual mean concentrations for PM2.5 are used 
28

to calculate the design value at a monitor.

NA = Data Not Available

SD = Monitor Shutdown

Data sources are either from the State Agency or AirData (EPA's public query system that accesses AQS)

Table 12 Delaware Linkages 2007-2009 24-hr design values/average

2007 2008 2009 2007-09 AVG

Union, NJ

32

34-039-0004

Dauphin, PA

35.6 34.3 NA 35 (07-08 avg)

42-043-0401

Lancaster, PA

35

42-071-0007

York, PA

32

42-133-0008

Cumberland, PA

33

42-041-0101

New York, NY

32

36-061-0079

Table 13 Delaware Linkages 2007-2009 annual design value/average

2007 2008 2009 2007-09 AVG

Union, NJ

13

34-039-0004

Dauphin, PA

14.28 13.28 NA 14

42-043-0401 (07-08 avg)
29

Lancaster, PA

14

42-071-0007

York, PA

14

42-133-0008

Cumberland, PA

13

42-041-0101

New York, NY

12

36-061-0079

From Table 1, we saw that the TR says that Delaware will significantly contribute to Lancaster, 

PA; York, PA, Union, PA; Dauphin, PA, Cumberland, PA and New York, NY in 2012 (i.e. 

“Linkages”). However, these counties are already in attainment as shown in shown in Tables 13 

and 14. 

Futhermore, because all the monitors in Delaware, and the CMSAs for Philadephia and New 

York have a 2007-2009 design value meeting both the 1997 and 2006 PM2.5 NAAQS, we find it 

difficult to believe that we would contribute 0.50 ug/m3 in 2012 per table 1 - to any downwind 

area. To do so would require our worst year (2007-2009) to be much higher than MLK’s 2008 

98th percentile of 34.8 ug/m3(see Table 9). 

DAQ also notes that the nearest nonattaining monitor using 2007-2009 data is in Allegheny 

County, PA (approximately 250 mi from central Delaware). 14 However, Delaware is not 

“linked” to Allegheny County. 

7. CONTROL MEASURES

Delaware has complied with §110(a)(2)(D)(i)(I) through promulgation of:

7 DE Admin. Code 1146, Electric Generating Unit Multi-Pollutant Regulation, 

7 DE Admin. Code 1142, Section 2, Control of NOX Emissions from Industrial Boilers 

and Process Heaters at Petroleum Refineries, and 

7 DE Admin. Code 1148, Control of Stationary Combustion Turbine Electric Generating 

Unit Emissions

Each of the above is based on Best Available Control Technology (BACT), and significantly 

reduces emissions from Delaware’s largest EGUs, industrial boilers, and peaking units. These 

regulations have been approved by the EPA as revisions to Delaware’s SIP.

 

14 Based on air travel distance between Dover to Pittsburgh. Both cities are the approximate centroid to Delaware, 

and Allegheny County. http://www.travelmath.com/flight-distance/from/Dover,+DE/to/Pittsburgh,+PA
30

8. SUMMARY:

EPA-IPM 2012 EGU NOx emission projections for Delaware are less than the budgets in the 

EPA’s proposed Transport Rule. EPA-IPM 2012 EGU SO2 emission projections for Delaware 

are 57 tpy higher than the budgets in the EPA’s proposed Transport Rule (but we have shown 

EPA 2012 SO2 projections are also approximately 22,000 tpy over-estimated). Delaware DAQ 

2012 projections for NOx and SO2 are less than the budgets in the proposed Transport Rule. The 

EPA TR budgets are those 2012 EGU emission levels that when met; demostrate that States 

have mitigated their significant downwind contributions to nonattainment areas and/or 

interfere with maintenance of the NAAQS. Therefore, considering the transport budgets 

alone, Delaware has mitigated its significant contribution to downwind areas. 

Delaware believes that if EPA used up-to-date and accurate emissions data (i.e. the Delaware 

PEI), and projected recent Delaware control measures, the TR modeling would have shown that 

Delaware does not significantly contribute to downwind areas 

The counties shown in EPA’s TR that have “linkages” to Delaware have been in attainment for 

the last three years15. In fact, all counties in Delaware, and the New York and Philadelphia 

CMSAs have 2007-2009 design values that meet both the 1997 and 2006 PM2.5 NAAQS. 

Eight (8) of nine (9) coal units operating, that were operating in 2005, will be shut down or 

switching to cleaner fuels during the years 2009 to 2014. The remaining unit (Indian River Unit 

4) will be controlled by SCR for NOx and scrubbers for SO2.

Delaware has complied with §110(a)(2)(D) through promulgation of: 7 DE Admin. Code 1146, 

Electric Generating Unit Multi-Pollutant Regulation; 7 DE Admin. Code 1142, Section 2, 

Control of NOX Emissions from Industrial Boilers and Process Heaters at Petroleum Refineries;

and 7 DE Admin. Code 1148, Control of Stationary Combustion Turbine Electric Generating 

Unit Emissions; which significantly reduce emissions from Delaware’s largest EGUs, industrial 

boilers, and peaking units. These regulations impose BACT level controls, and have been 

approved by the EPA as revisions to Delaware’s SIP.

For the above reasons, and with the above technical analysis, Delaware believes it has 

demonstrated that it has mitigated its significant downwind transport and satisfied CAA 

110(a)(2)(D)(i)(I) requirements. 

 

15 Dauphin County did not have monitor data for 2009. However, 2007-2008 annual data was in attainment and in 

2008 (latest year of data) was in attainment for the 24-hr NAAQS, with trends going downward from 2006. 
31

Appendices

1.0 Emission Table Summaries, EGUs, and Projections

Fuel Combustion

2 a Commercial_Fuel_Combustion

2 b Residential_Fuel_Combustion

2 c Industrial_Fuel_Combustion

Nonroad (marine vessels)

3 a Commercial_Marine_Vessel

3 b Towboats_&_Tugboats

3 c Dredging

3 d Ferries

4. Permit Changes

Croda Boiler

Dupont Stine Haskell Blr 3

Montaire Farms fuel switch

Invista Permit Cancel

5 Invista Consent Decree

6 Final Agreement – DNREC and DE City Refinery