Supplement to Delaware’s

September 16, 2009 CAA Section 110 “Infrastructure” State Implementation Plan (SIP)

Submission

Delaware Department of Natural Resources and Environmental Control

April11, 2011
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3.1.5

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4.1.1

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4.1.4

4.1.5

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Emissions —----- —------. —-----------—-----—-

2005 Souroe Sector Discussion ------ --------—--

EGUs—------------- -----------_--------_-----------_-------

Non-EGUPoint------------------------—-—---------- - Noiipoint —-----------___

Nonroad-----------------------—----------—--------------

Onroad---------------------—— —----------------—____

2Ol2Projections----------—-----—-—---———------.----------—--——---------

2012 Source Sector Discussion—-—----------- .

--____

EGUs—------------------——

--•-—-----—---__

. Non-EGUPoint ----------— ..

Nonpoint

Nonroad — Onroad

Delaware Meets Proposed Transport Rule Budgets —

Monitoring Data Shows Attainment ---------- —----------------—

Control Measures — — — Summary — -_ —--------

Appendices--—---------------—-----—--------------—---

2
v

sed 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 11 0(a)(1) and 11 0(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 1 10(a)(1) and

11 0(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 1 10(a)(1) and (2) for

the 2006 24-Hour Fine Particle (PM25)National Ambient Air Quality Standards (NAAQS),”

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

Sections 1 10(a)(1) and 1 10(a)(2) of the Act for the 2006 24-hour PM2.5NAAQS. According to

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

to interstate transport found at 11 0(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 CAR replacement rule

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

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

17, 2006 promulgation of the 24-hour NAAQS for PM25.Therefore, Delaware made a timely

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

PM2.5precursor emissions of sulfur dioxide (SO 2)and nitrogen oxides (NOx) from electric

3
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 PM2.5precursor emissionsof SO2and NOx from electric generating units, industrial boilers, and peaking units to address

the interstate transport requirements of 11 0(a)(2)(D)(i)(I), Delaware started with the assumption

that it did significantly impact downwind areas. With this assumption, Delaware moved forwardand 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 highenergy 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.’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 proposedTransport Rule including extensive technical data and information to support our contention that

Delaware should not be included in the Transport Rule. It is our beliefthat 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 11 0(a)(2)(D)(i)(I) includean adequate technical analysis.

Despite the above, in the best interests ofthe 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

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 significantimpact on downwind states.

4
Delaware meets the requirements of Clean Air Act (

CAA

) § 11 0(a)(2)(D)(i)(I), 2addressing

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

1 10(a)(2)(D)(i)(I) major stationary sources for the annual and 24-hr PM2.5NAAQS 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 PM2.5NSR Implementation Rule (73

FR 28321), NNSR in New Castle County for PM25 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, PM2.5PSD activities will continue to be administered

using PM10 as

a surrogate for PM25,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 § 11 0(a)(2)(D) through promulgation of

7 DE Admin. Code 1146, Electric

Generating Unit Multi-Pollutant Regulation; 7 DE Aclmin. 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 § O(a)(2)(D)(i)(1) 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 nonattainment 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 ofsections 126 and 115 (relating to interstate and international pollution abatement).”

5
g

, 

g 

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

concenfrations in the state and the potentially impacted states, the distance to the nearest areathat 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 SO2and NOx emissions that states must meet to

remedy their “signfficant 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 downwindcounty 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.

Guidance on SIP Elements Required Under Sections 1 10(a)(1) and (2) for the 2006 24-Hour Fine Particle (PM25)

National Ambient Air Quality Standards (NAAQS),”

6
• Jack Sipple, M.S., is the project leader and responsible for emission projections, as well

as principal author ofthis 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 PM2.5monitoring 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

Largest Largest Affected Counties Affected Counties

Downwind Downwind (Linkages) for (Linkages) for

Contribution to Contribution to Nonattainment Maintenance

Nonattainment Maintenance

(uglm3) (uglm3)

NAAQS

7
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 Inventor)r. 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 significantly contribute to downwindareas.

3. EMISSIONS

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

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

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

emissions. Delaware’s sulfur dioxide (SO 2) 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 PET for the 2005 emissions analysis. EPA also used NMIMand 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

8
Difference (tpy) 

633 

173 

4,825 

8,893 C 44,521

%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 5,999T 2,317 11,728 22,569 54,010

DE Emission Difference -520 432 -942 -3,839 ( -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 (ETA) 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 industrialand commercial non-stationary equipment (forklifts, aerial lifts, floor sweepers/scrubbers, etc.)

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

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

combustion).

Technical Support Document (75’D)for the Transport Rule Docket. ID No. EPA-HQ-OAR-2009-049 1. Table 2-1.

Sectors Used in the TR Emissions Modeling Platfoim.

9
However, all ofthe 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 PH to use more recent emission factors and activity data.

3. Aircraft Emissions: EPA used the 2005 NET version. Delaware has refined its 2005 PET

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 SO2emissions 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 (“5”) 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 fromdiscussions 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 (7’SD)for the Transport Rule Docket. ID No. EPA-HQ-OAR-2009-0491. Table 2-1.Sectors Used in the TR Emissions Modeling Platform.

Technical Support Document (7D)for the Transport Rule Docket. ID No. EPA-HQ-OAR-2009-049 1. Table 2-1.

Sectors Used in the TR Emissions Modeling Platform.

10
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 strçtch 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 obtainedfrom

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

publication. The use ofthe 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 ofthe Delaware Bay to the Delaware/Pennsylvania state line.

A second important change to the methodology was toeliminate 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 PET.

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 ofthis analysis.

4.0 Delaware 2012 Projections (as projected by DAQ)

DAQ used our 2005 PET 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 SO2and

11
Transport Rule 7,841. 10,974 5,852 14,193 98 38,964

DE Projections 7,356: 5941 1,034, 2,201 98 16,630

DE Emission Difference -425 -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 3,242 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 C -9,358

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

4.1 2012 Source Sector Discussion

4.1.1 EGUs

EPA used 1PM, which is a tool for predicting future regional strategies and emissions. DAQ’s

understanding of the 1PM used for the TR is that it projects current controls using an out

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

methods inherent to 1PM, 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 consistsof 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 ofthegenerating 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 &net importer of

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

12
p

g

y 

q

, 

SO2 e

ss

o

data was ta

e

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 tostartup/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 SO2emission 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 ofresidual 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 SO2emissions, it was assumed that the SO2emission rate would be that

13
g

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.IMMBTU.

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 fromEdge 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 anexisting 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 JR 1&2 shutdown, and to account for transmission constraints during high electric

demand with Indian River Units 1 and 2 out ofservice. 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 KentCounty 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 0.21bIMMBTU for SO2and 0.1 1bIMMBTU for NOx.

14
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 increasedfrom 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 1PM 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 refmery in the non-EGU sector).

Table 4 2012 Projected Emissions Substituting EPA 1PM runs for DE projected EGUs

2012502 EGU NonEGU Nonpoint Nonroad Onroad Total

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

DEProjections 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%

2012N0X EGU NonEGU NonpointNonroad 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 O% 11% 29% 33% 0% 17%

15
The following is a list of significant 502 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 ofDelaware Inc. -Milisboro -; Switching to Nat Gas

• SPI Poly-OLs -Boiler No. 1 removed

• Invista - Boilers 1 and 3 (coal) will be retired by 2012, Boiler 2 (coall# 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 wereprimarily 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.

16
50000

45000

40000

35000

30000

2000 2001 2002 2003 2004 2005 2006 2007 2008

Figure 2

. Delaware Residual Fuel Oil Adj SalesjDeliveries Total to End Users

(Thousand Gallons)

330000

8

30000 --——r————1-——

2000 2001 2002 2003 2004 2005 2006 2007 2008

17
2007-2013 growth factor of 1.00 for Dover Air Force Base as part of our 2006 PM25 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 theRegional 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,asoutlined 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

18
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 ofthe 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 ofthe 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 requestedalternative 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.

19
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 typicallyused 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, EPA42O-R-08-OOla(http://www.epa.gov/otaq/regs/nonroadJ42OrO800 1 a.pdf), Regulatory Impact Analysis: Control

of Emissions of Air Pollution from Category 3 Marine Diesel Engines, EPA42O-R-09-0 19

(http://www.epa.gov/otaq/regs/nonroad/marine/ci1420r090I 9.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/nonroadlmarine/ci1420r09007-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).

CMVDiesel 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

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

20
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-OOla, May 2008).

CMVResidual 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 SO2controls and did not apply sulfur controlsfor

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 EPA42O-R-09-0 19, DAQ calculated growth factors for each pollutant based on

the ratio ofthe 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,

Technical Support Document (7SD)for the Traiuport Rule Docket. ID No. EPA-HQ-OAR-2009-0491. Page 12, bullet 2.

21
(

) 

g

emission standards will apply to ships. In practice, implementation ofthe 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 thearea 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, Officeof 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-09-0l9 to determine growth, but developed our own control factor based onexisting residual fuel averages of 2.7% sulfur.’° 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 thecontrol factor (1.00) to 2005 PET 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.

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

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

22
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 SO2budget of 7,784 TPY. EPA

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

remain in that statefrom covered sources after elimination ofthat portion ofeach state ‘s

signj/Icant contribution and interference with maintenance that EPA has identjfIed 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 signflcant contribution andinterference with maintenance) into enforceable control requirements. In other words, it

provides a quantity ofemissions 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 thanits 2012 base case emissions, Delaware has already met its obligation to remedy downwind

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

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

EPA’s 1PM method (DAQ has first-hand knowledge of our sources plans, recent permits and

The difference between the EPA 2012 base case S02 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 S02 projections are inflated on the order of 57%, and 2) Delaware’s 2012 EGU projection will be

less than the budget.

23
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.’ 3 DNREC emphasises that all of these counties are in

attainment prior to:

• Delaware’s Phae II (SO 2controls) 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 ofthe final transport rule

Table 6 Delaware 2007-2009 annual monitoring data

New Castle Kent Sussex

PM2.5 values County County County

MLK Nwrk

Bllfte -a -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 Ml) 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

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).

24
a 

u

s 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 Kent Sussex

County County County

MLK- Nwrk

PM2.5 98th percentiles Blifte a a Lums Dover Killens Seaforci

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 I Kent Sussex

County County County

PM2.5 3-yr MLK- Nwrk- Lum Killen

Averages BIfte a a s Dover 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

.

. AQS 200 200 2009 2007-09 200 200 2009 2007-09

e ounty Monitor Site Monitor ID 7 8 * DV 7 8 * DV

13.6

NJ Camden Camden Trailer 34 34 37 35 12.2 13.7 (no 13.1

Camden Pennsauken 35 28 25 29 14.0 11.8 9.5 11.7

Gloucester Gibbstown f 31 27 22 27 13.4 11.5 9.3 11.4

25
Philadeiphi Elmwood,

a Amtrak

* 98th percentile for the year, not final** =Design Va(ue=average of three year period, not final. Three years of annual mean concentrations for PM2.5 areused to calculate the design value at a monitor.

NA = Data Not Available

SD = Monitor Shutdown - Data sources are either from the State Agency orAirData (EPA’s public query system.that accesses AQS)

Table 11 New York nonattainment area

09 001 Fairfield Roosevelt School 0010

42 045 Delaware Chester 30 14.5 14.7 12.1 13.7 0002 27

Montgomer Norristown 42 091 27 13.1 12.1 10.4 11.9

y 0013 30 24 27

Philadelphi LAB 42 101 35 35 26 32 13.7 13.0 10.9 12.5

a 0004

Philadelphi NEA 42 101 34 31 26 30 12.9 12.0 9.9 11.6

a 0024

Philadelphi CHS, Broad St. 32 14.4 13.5 11.1 13.0 a 42101

0047 35 33 29

Philadelphi RIT-F 42 101 NA 35 29 NA NA 13.5 11.3 NA

a 0055

Philadeiphi FAB-FA 42 101 33 33 28 31 12.0 13.3 11.1 12.1

a 0057

Notes

42 101

0136 32 NA NA NA 13.3 NA NA NA

NEW YORK NONATTAINMENT AREA

CT

AQS 07-09 State County Monitor Site Monitor 07 08 09* 07 08 09* 07-09 DV** ID

Daily PM2.5 Annual PM2.5

30 32 31 31 12.7 11.9 10.2 11.6

09001 Fairfield Danbury 30 28 32 30 12.0 11.7 9.6 11.1 1123 — 09 001 Fairfield Norwalk 32 26 31 30 11.9 11.8 9.9 11.2 3005 — 09 001 Fairfield Westport 29 31 34 31 10.9 10.2 9.5 10.2 9003 — 09 009 New Haven Woodward Avenue 30 31 34 31 11.6 11.5 9.8 11.0 0026

09 009 NewHaven JamesStreet 31 32 35 32 11.5 11.3 10.2 11.0 0027

09 009 New Haven State Street 31 32 35 32 12.3 12.1 10.4 11.6 1123

09 009 New Haven New Haven 29 25 29 28 10.8 10.6 8.9 10.1 2008

26
Mercer Washington 34 021 27 28 25 27 10.2 10.0 7.8 9.3 Crossing 8001

34 023 Middlesex New Brunswick 30 29 21 27 12.3 10.9 8.0 10.4

. 0006 — 34 027 Morris Morristown 32 24 22 26 11.5 9.4 8.1 9.7 0004

34 027 Morris Chester 31 24 21 26 10.4 8.8 7.1 8.8 3001

34 031 Passaic Paterson 37 29 26 30 13.5 11.4 8.9 11.3 0005

Elizabeth Turnpike 34039 Union 35 34 28 32 13.9 12.9 11.2 12.7 Primary 0004 — Elizabeth 34 039 Union 36 31 26 31 13.1 12.4 9.3 11.6 Downtown 0006

34 039

Union Rahway 33 30 25 29 13.2 12.0 9.3 11.5

2003 

— 

36 005 NY Bronx Morrisania 36 33 30 33 15.6 13.5 12.7 13.9 0080

200th Street And 36 005 — Bronx Southern Blvd, 00831013 33 NA 27 . 30 13.2 11.7 10.0 11.6

Botanical Garden 3 — 36 005 Bronx E. 156th St. 34 33 31 32 12.7 11.8 10.8 11.8 0110

36 047 Brooklyn JHS 126 0122 34 31 27 31 13.9 12.0 10.7 12.2

36 059 Nassau Cedarhurst 29 29 26 28 11.1 10.9 9.0 10.3 0008 — 36 061 New York PSS9 37 33 NA NA 16.1 15.9 NA NA 0056 — Post Office,350 36 061 New York 35 NA NA NA 15.8 NA NA NA Canal Street 0062 — 36 061 New York JHS45 34 33 29 32 13.6 12.4 10.5 12.2 0079 —

36 061 New York PS 19 38 26 29 31 15.6 13.1 12.0 13.6 0128 — 36 061 NewYork PS 124 37 32 29 33 13.3 13.2 11.6 12.7 0134

Queens Newburgh, 55 36 071 30 31 21 27 10.6 9.6 7.9 9.4 Broadway 0002

36 081 Queens Queens College 0124 32 31 27 30 11.4 11.0 9.6 10.7

Staten 36 085 Port Richmond 33 29 25 29 13.0 12.1 9.8 11.6 Island 0055 — Staten 36 085 Susan Wagner HS 29 28 23 27 11.5 10.8 8.5 10.3 Island 0067 — East 36 103 Suffolk FarmingdalelBabylo 0001 29 27 22 26 10.9 10.1 8.1 9.7

n — Westcheste 36 119 Mamaroneck 31 31 27 29 11.7 11.0 9.1 10.6 I 1002 

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

27
2007 2008 2009 2007-09 AVG

Union, NJ

32

3 4-03 9-0004

Dauphin, PA

35.6 34.3 NA 35(07-O8avg)

42-043-0401

Lancaster, PA

35

42-071-0007York, 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

14.28 13.28 NA

42-043-0401 (07-08 avg)

28
36

061

0079

From Table I, 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 uglrn 3(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 §1 10(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 NO 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.

‘

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

and Allegheny County. http:u/www.travelrnath.corn!flight-distance!frorn!Dover.±DE/to!Pittsburgh.±PA

29
g

have mitigated their signj/icant 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 DelawarePET), and projected recent Delaware control measures, the TR modeling would have shown that

Delaware does 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 years’ 5.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 PM2.5NAAQS.

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 andscrubbers for SO2..•

Delaware has complied with § 11 O(a)(2)(D) through promulgation of: 7 DE Admin. Code 1146,

Electric Generating Unit Multi-Pollutant Regulation;. 7 DE Adrnin. 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 beenapproved 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

11 0(a)(2)(D)(i)(I) requirements.

‘

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.

30
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 -UNREC and DE City Refmery

31