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HEARING REPORT 

 

Prepared Pursuant to

40 Code of Federal Regulations Section 51.102 

Regarding a State Implementation Plan Revision concerning 

Visibility Protection 

Hearing Officer: 

Merrily A. Gere 

Date of Hearing: August 27, 2009 

On July 27, 2009, the Commissioner of the Department of Environmental Protection 

(CTDEP) published a notice of intent to revise the State Implementation Plan (SIP) for air 

quality to: (1) address the visibility protection requirements of section 169A of the federal 

Clean Air Act (CAA); and (2) update RACT requirements, given the promulgation of eleven 

federal control techniques guidelines (CTGs) in 2006 through 2008. Pursuant to such notice, 

a public hearing was held on August 27, 2009, with the public comment period closing on 

August 28, 2009. This report addresses only the visibility protection proposal, comment and 

recommended final SIP revision. 

I. Hearing Report Content

This report describes the revision to the SIP as proposed for hearing; a statement of the 

principal reasons in support of the SIP revision; all comments made and responses thereto 

regarding the proposed revision to the SIP; and the final recommendation based on the 

proposal and comments received. 

II. Summary and Purpose of Proposal

The visibility protection SIP revision is a plan to serve the national goal of restoring natural 

visibility conditions to mandatory Class I Federal Areas by 2064. The proposed SIP revision 

also satisfies the Regional Haze Rule (40 Code of Federal Regulations (CFR) 51.300-309), 

which seeks to protect mandatory Class I Federal Areas by addressing the aggregate visibility 

impact of various air pollution sources over a large geographic region. 

The SIP revision includes an assessment of baseline and natural visibility conditions, an air 

monitoring strategy, an alternative program for Best Available Retrofit Technology (BART), 

a set of reasonable progress visibility goals and a long-term strategy for achieving those goals. 
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III. Summary of Comments

Written comments were received from the following persons: 

1. Anne Arnold, Manager 

Air Quality Planning Unit 

U.S. Environmental Protection Agency 

Region 1 

1 Congress Street, Suite 1100 

Boston, MA 02114-2023 

Mcwilliams.anne@epamail.epa.gov 

2. Holly S. Salazer 

Northeast Region Air Resources Coordinator 

National Park Service 

207 Buckhout Lab 

University Park, PA 16802 

Holly_Salazer@nps.gov

3. Ralph Perron, Air Quality Specialist 

U.S. Department of Agriculture Forest Service 

Allegheny, Green Mountain, Finger Lakes and White Mountain National Forests 

626 E. Wisconsin 

Suite 800 

Milwaukee, WI 53202 

rperron@fs.fed.us

4. Chuck Carlin (oral comment only) 

chuckcarlin@hotmail.com

All comments submitted are summarized below with CTDEP’s responses. Commenters are 

associated with the individual comments below by the number assigned above. 

General

1. Comment: The Department of Interior (DOI), which includes the U.S. National Park 

Service (NPS) and U.S. Fish and Wildlife Service (FWS), is satisfied that the issues raised in 

preliminary comment in April 2009 have been addressed in the proposed SIP revision. NPS 

and FWS were particularly interested in how concerns regarding additional information and 

analysis on alternatives to BART were addressed. Both DOI agencies are satisfied that the 

draft SIP revision accurately documents how overall emissions will be decreasing in the near 

future. For future planning efforts, DOI recommends highlighting even more this important 

relationship between the change in emissions and the change in visibility in Class I areas. [2] 

Response: CTDEP appreciates the commitment shown by DOI staff on the issue of 

regional haze and notes that DOI’s participation is of great value to the interagency 

process needed to bring about visibility improvements to Class I areas. In response to 

DOI, CTDEP will take the relationship between emissions and visibility into account 

in future planning efforts. 

2. Comment: The U.S. Department of Agriculture Forest Service (USDA-FS) looks forward 

to working with CTDEP and MANE-VU in the future. [3] 
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Response: As is the case with DOI, the CTDEP also appreciates the commitment 

shown by USDA-FS’s staff on the issue of regional haze and welcomes their 

continued participation in future SIP planning efforts. 

3. Comment: Chuck Carlin commends CTDEP’s proposal because regional haze is 

appropriately addressed and fits well within CTDEP’s current plans and programs. Mr. Carlin 

cautions that the Federal government should not adopt a requirement for Connecticut sources 

to meet the same emissions limits but in a way that it is not now doing, which would create an 

additional limitation. [4] 

Response: CTDEP notes Mr. Carlin’s approval and comment of caution. 

2.0 Areas Contributing to Regional Haze

4. Comment: The reference to 40 CFR 51.308(3)(iii) should be revised to 40 CFR 

51.308(d)(3)(iii). [1] 

 Response: In the final SIP revision, the reference has been revised as recommended 

in the comment. 

9.0 Best Available Retrofit Technology

5. Comment: EPA asks that CTDEP provide some discussion of how costs were considered 

in establishing the BART benchmark for SO2 and NOx. [1] 

Response: To Section 9.2.3 of the final SIP revision, CTDEP has added a subsection 

that specifically addresses the costs of SO2, NOx and PM controls for electric 

generating units and industrial boilers as well as a subsection that addresses costs of 

compliance with Connecticut’s existing NOx and SO2 regulations. The text of the new 

material is as follows: 

Costs of SO2, NOx and PM Controls for EGUs and Industrial Boilers

According to NESCAUM’s Assessment of Control Options for BART-Eligible 

Sources (Attachment Z), SO2 control for previously uncontrolled EGU boilers is 

highly cost effective with operational costs in the range of $100-200 per ton of SO2

removed. Costs for NOx removal range from $200-500/ton for some of the low yield 

techniques to $1000 to $1500/ton for SCR with 90-95 percent removal efficiency. A 

cost-effectiveness indicator (e.g., $/ton) is difficult to address for PM control because 

the range of PM reductions for different fuels and processes is very wide. One of the 

main parameters dictating the “sizing” and hence, costs of a PM control device, is the 

quantity of flue gas it must handle. As a result, it is more appropriate to generalize 

capital costs per actual cubic feet per minute (ACFM) of gas flow and is given on a 

“$/ACFM” basis. PM control costs range from $1-$40/ ACFM of gas flow. 

Many of the same control technologies for EGUs are applicable to industrial boilers, 

but industrial boilers have a wider range of sizes than EGUs and often operate over a 

wider range of capacities. Cost estimates for the same technologies will generally 

range, depending on the capacity of the boiler and typical operating conditions, with 

high end cost estimates for NOx removal going over $10,000/ton. 

Costs of Compliance with Connecticut’s Existing Regulations: RCSA section 22a174-19a (Control of SO2 Emissions from Power Plants and other large stationary 
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sources of air pollution), RCSA section 22a-174-22 (Control of NOx Emissions) and 

RCSA section 22a-174-22c (CAIR NOx Ozone Season Trading Program)

Residual oil is a byproduct of the refining process and is produced in several grades 

that can be blended to meet a specified fuel sulfur content limit. The premium cost for 

lower sulfur residual fuel oil (<1%S) has averaged approximately 15 % over the past 

three years, however, on occasion, the price for low and higher sulfur residual fuel has 

been minimal. For example, according to the U.S. Energy Information 

Administration, the August average U.S. wholesale price of lower sulfur residual fuel 

oil was $66.61 /barrel while the higher sulfur residual fuel oil (>1%) was priced at 

$65.81 /barrel (http://tonto.eia.doe.gov/dnav/pet/pet_pri_spt_s1_d.htm). 

For NOx, sources complying with RCSA Section 22a-174-22 and RCSA Section 22a174-22c through emissions trading, costs of compliance are directly related to costs of 

NOx discrete emission reduction credits (DERCs) and/or allowances. NOx DERC and 

allowance prices vary because they are currencies of market-based programs. In 

March 2004 NOx allowance prices were approximately $2000/ton; CAIR NOx Ozone 

Season allowance prices as of November 2009 are approximately $130/ton. 

 

6. Comment: CTDEP should include a table to accompany Figure 9.6 quantifying the tons 

of NOx reduced by Connecticut’s BART alternative versus BART-eligible sources alone, 

similar to Table 9-8 provided for SO2 reductions. [1] 

Response: To the final SIP revision, CTDEP has added Tables 9.16 and 9.17 and 

accompanying text, comparing NOx emissions reductions (actual and potential) for the 

NOx Budget Program sources versus the BART-eligible sources, as follows: 

Table 9.16 shows the NOx reduction in potential emissions between 2002 and 2006 

from all Post-2002 NOx Budget Program sources as compared with the reduction in 

NOx potential emissions from BART-eligible sources alone. The “low end” and “high 

end” numbers referenced in the “Year-2012” column in Table 9.16 are based on the 

MANE-VU BART workgroup’s recommended emission limit range of 0.1 lb/MMBtu 

(low end) to 0.25 lb/MMBtu (high end) for non-CAIR EGUs and 0.1 lb/MMBtu (low 

end) to 0.4 lb/MMBtu (high end) for industrial boilers, depending on coal and boiler 

type. 
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Table 9.16: Comparison of NOx Potential Emissions and Reductions since 2002 from all 

Post-2002 NOx Budget Program sources vs. BART-eligible sources alone (tpy)* 

NOx potential emissions from all 

Post-2002 NOx Budget Program 

sources 

Year=2002 Year=2006 Reduction in 

potential 

emissions 

46,188 34,833 11,355 

NOx potential emissions from 

BART-eligible sources alone 

 

 Year=2012 

27,554 High end24,434 

Low end9,701 

3,120 

17,853 

*It should be noted that between 1994 and 2006 NOx potential emissions from all sources 

included in the Post-2002 NOx Budget Program were reduced from 89,812 tons to 34,833 tons 

(a difference of 54,979 tons). Assuming the high end and low end levels of control referenced 

above in 2012, NOx potential emissions from BART-eligible sources alone since 1994 would 

be reduced from 43,659 tons to 24,434 tons for the high end level of control (a difference of 

19,225 tons) and to 9,701 tons for the low end level of control (a difference of 33,958 tons). 

Table 9.17 shows the reductions in actual NOx emissions from all Post-2002 NOx

Budget Program sources and BART-eligible sources since 1994. Again, 

Connecticut’s existing NOx program has resulted in considerably more NOx reductions 

(3,114 tons) than BART control alone. 

Table 9.17: Comparison of NOx Actual Emissions and Reductions since 1994 from all 

Post-2002 NOx Budget Program sources vs. BART-eligible sources alone (tpy) 

NOx actual emissions from all 

Post-2002 NOx Budget Program 

sources 

Year=1994 Year=2002 Year=2006 Reduction in 

actual emissions 

since 1994 

13,411 6,150 5,346 8,065 

NOx actual emissions from 

BART-eligible sources alone 

8,594 4,054 3,643 4,951 

Additional reductions beyond 

BART-eligible sources alone 

3,114 

7. Comment: EPA notes that the asterisk on Table 9-14 indicates that the NOx potential 

emissions are “based on the lower of RCSA section 22a-174-22 regulatory limits or federally 

enforceable permit conditions.” CTDEP should specify the mechanism by which the 

referenced permit is federally enforceable (for example, New Source Review). [1] 

Response: CTDEP has two federally approved air quality permitting programs, new 

source review and Title V. EPA’s request for specificity in identifying the source of 
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the NOx emissions limit in Table 9.14 has been addressed by identifying the new 

source review program in the footnote, and CTDEP has made the same addition to 

Tables 9.5 and 9.13, which include the same footnote. In addition, the footnote 

language in Table 9.6 regarding this issue has been made consistent with the language 

in Tables 9.5, 9.13 and 9.14: 

Table 9.5: SO2 Annual Potential Emissions @ 8760 Hours (tpy) 

BART-eligible 

Unit/Location 

2001* 2002* 2006* MANE-VU 

BART 

workgroup 

presumptive 

BART 2012 

EPA 

presumptive 

BART 2012 

Middletown Unit 

3, Middletown 

5709** 5709 3426 3426 11419 

Middletown Unit 

4, Middletown 

11284** 11284 6770 6770 22568 

Montville Unit 6, 

Montville 

22442 11221 6733 6733 22442 

Norwalk Unit 2, 

Norwalk 

8557 4278 2567 2567 8557 

Bridgeport Harbor 

Unit 3, Bridgeport 

18212 9877 5926 2694 2694*** 

New Haven 

Harbor Unit 1, 

New Haven 

20508 10282 6169 6169 20508 

Cascades 

Boxboard Group 

PFI Boiler, 

Versailles 

1325 662 662 662 1325 

Total 88037 53313 32253 29021 89513 

*Based on the lower of RCSA section 22a-174-19a regulatory limits or federally enforceable 

permit (New Source Review) conditions. 

**Fuel sulfur limited to 0.5% in Consent Order no. 7024. 

***While this level of control (95% removal or 0.15 lb SO2/MMBtu) is not required by EPA 

guidelines, it is recommended that such level of control be considered when determining 

BART. 
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Table 9.6: SO2 Daily Potential Emissions @ 24 Hours (tpd) 

BART-eligible 

Unit/Location 

2001* 2002* 2006* MANE-VU 

BART 

workgroup 

presumptive 

BART 2012 

EPA 

presumptive 

BART 2012 

Middletown Unit 3, 

Middletown 

15.6 15.6 9.4 9.4 31.3** 

Middletown Unit 4, 

Middletown 

30.9 30.9 18.5 18.5 61.8** 

Montville Unit 6, 

Montville 

61.5 30.7 18.4 18.4 61.5 

Norwalk Unit 2, 

Norwalk 

23.4 11.7 7.0 7.0 23.4 

Bridgeport Harbor 

Unit 3, Bridgeport 

49.9 27.1 16.2 7.4 7.4*** 

New Haven Harbor 

Unit 1, New Haven 

56.2 28.2 16.9 16.9 56.2 

Cascades Boxboard 

Group PFI Boiler, 

Versailles 

3.6 1.8 1.8 1.8 3.6 

Total 241.1 146 88.2 79.4 245.2 

*Based on the lower of RCSA section 22a-174-19a regulatory limits or federally enforceable 

permit (New Source Review) conditions. 

**Fuel sulfur limited to 0.5% in Consent Order no. 7024. 

***While this level of control (95% removal or 0.15 lb SO2/MMBtu) is not required by EPA 

guidelines, it is recommended that such level of control be considered when determining BART. 
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 Table 9.13: NOx Potential Emissions* (tpy) 

BART-eligible 

Unit/Fuel 

1994 

(tpy)

 2002 

(tpy)

2006 tons 

per ozone 

season 

2006 tons 

per nonozone season 

2006 annual 

tons 

Middletown Unit 

3/No. 6 oil 

8329 3980 1668 806 2474 

Middletown Unit 

4/No. 6 oil 

5691 4742 1988 1653 3641 

Montville Unit 6/No. 

6 oil 

6121 5101 2138 1778 3916 

Norwalk Unit 2/No. 

6 oil 

2334 1945 815 678 1493 

Bridgeport Harbor 

Unit 3/coal 

16162 6824 2860 1565 4425 

New Haven Harbor 

Unit 1/No. 6 oil 

4661 4661 1959 1629 3588 

Cascades Boxboard 

PFI Boiler/No. 6 oil 

361 301 126 105 231 

Total 43659 27554 11554 8214 19768 

*Based on the lower of RCSA section 22a-174-22 regulatory limits or federally enforceable permit (New 

Source Review) conditions. 
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 Table 9.14: NOx Potential Emissions (tons per day)* 

BART-eligible 

Unit/Fuel 

 1994 2002 2006 Ozone 

Season 

2006 Non-ozone 

Season 

Middletown Unit 

3/No. 6 oil 

22.8 10.9 10.9 3.80 

Middletown Unit 

4/No. 6 oil 

15.6 13.0 13.0 7.80 

Montville Unit 

6/No. 6 oil 

15.9 13.3 13.3 7.97 

Norwalk Unit 

2/No. 6 oil 

6.48 5.40 5.40 3.24 

PSEG Bridgeport 

Unit 3/coal 

44.3 18.7 18.7 7.38 

PSEG New 

Haven Unit 

1/No. 6 oil 

12.8 12.8 12.8 7.68 

Cascades PFI 

Boiler/No. 6 oil 

0.989 0.84 0.84 0.495 

 Total 119.7 75.2 75.2 38.6 

*Based on the lower of RCSA section 22a-174-22 regulatory limits or federally enforceable permit (New 

Source Review) conditions. 

8. Comment: At page 9-34, EPA suggests that CTDEP elaborate on the lack of significant 

visibility impact on any Class I area due to PM emissions from BART-eligible sources. CTDEP 

should include a table of the PM visibility impacts from the BART-eligible sources. The table 

will help to demonstrate that, although the PM emission limits imposed by CTDEP are less 

stringent than the MANEVU recommended emission limits, the Connecticut limits can be 

considered reasonable since the highest PM visibility impact from any one BART unit is so low 

(0.0035 deciviews) compared to the 0.1 deciview impact considered in the MANEVU 

recommended limits. [1] 

Response: In the final SIP revision, CTDEP has enhanced the discussion in Section 

9.3.3 of the visibility impact reasonably expected from the BART-eligible sources as 

recommended in the comment. CTDEP has added Table 9.19, which sets out the 

modeled PM10 impact on Class I areas from seven BART-eligible units and expanded 

the discussion to take into account Table 9.19, as follows: 

Table 9.19: MANE-VU modeling of individual unit emissions for 2002 

Federal Class 1 area with maximum 

simulated impact 

Highest simulated PM10 impact on 20% 

best days (delta-deciview) with impacting 

BART-eligible unit 

Brigantine Wilderness 0.0000 (Middletown Unit 3) 

Lye Brook Wilderness 0.0025 (Middletown Unit 4) 

Acadia National Park 0.0005 (Montville Unit 6) 

Brigantine Wilderness 0.0002 (Norwalk Unit 2) 

Brigantine Wilderness 0.0035 (PSEG Bridgeport Unit 3) 

Brigantine Wilderness 0.0012 (PSEG New Haven Unit 1) 

Acadia National Park 0.0004 (Cascades PFI Boiler) 
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The PM emission limits in RCSA section 22a-174-18 and Connecticut’s BART-eligible 

source permits (Middletown Unit 4, PSEG Bridgeport Unit 3 and PSEG New Haven Unit 

1) are less stringent than the MANE-VU BART workgroup’s recommended BART 

emission limits for PM. However, as can be seen in Table 9.19, the highest individual 

PM visibility impact (0.0035 delta-deciview) is significantly less than the 0.1 deciview 

individual impact MANE-VU warrants worthy of consideration of BART controls (see 

Section 4.1 of the MANE-VU Five-Factor Analysis of BART-Eligible Sources, 

Attachment W). 

 

11.0 Long-Term Strategy

9. Comment: The MANE-VU long-term strategy recommends the following fuel sulfur 

limitations for an "outer-zone" state such as Connecticut: 

• #2 distilate oil to 0.05 percent (500 ppm) sulfur, by weight, by no later than 2014; 

• #4 residual oil to 0.25 percent sulfur, by weight, by no later than 2018; 

• #6 residual oil to 0.5 percent sulfur, by weight, by no later than 2018; 

• Further reduction of the sulfur content of distillate oil to 15 ppm by 2018, contingent on 

supply and availability. 

With respect to the reduction of sulfur in #2 distillate by 2014, CTDEP’s proposed SIP revision 

references Connecticut General Statute section 16a-21a, which limits the fuel sulfur content of 

heating distillate oil and off-road diesel oil to 500 ppm as of the date on which the last of the 

states of New York, Massachusetts and Rhode Island limit the sulfur content of such fuels. EPA 

asks that CTDEP also explain the mechanism by which the state plans to make this fuel sulfur 

content limit federally enforceable. Also, CTDEP should work closely with the named states to 

ensure that the 2014 milestone is met. [1] 

Response: To make the referenced statute federally enforceable, CTDEP will submit the 

statute with the final SIP revision as Attachment GG (See Section 11.11 of the SIP 

revision). CTDEP will continue to work closely with NY, MA and RI in seeking to 

realize the fuel sulfur standards of the MANE-VU strategy. 

10. Comment: Page 11-27 states: “Connecticut intends to adopt all reasonable control 

measures as expeditiously as practicable, in a manner consistent with state law, so that they may 

be in place by the end of the ten-year planning period.” Connecticut’s SIP revision submittal 

should include a schedule for adoption of these measures. [1] 

Response: CTDEP has added the following two sentences to the second paragraph of 

Section 11.10 of the proposed SIP revision: 

In terms of a state-wide limitation of #4 residual oil to 0.25-0.5% by weight and 

of #6 residual oil to no greater than 0.5% sulfur by weight, CTDEP commits to 

pursue adoption of a regulation by 2012 with an implementation date of no later 

than 2014. Regarding reduction of distillate fuel sulfur content to 15 ppm by 

2018, CTDEP commits to pursue adoption of legislation that will implement this 

measure by no later than 2018. 
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The regulatory adoption and legislative adoption processes are beyond the direct control 

of CTDEP, and, therefore, CTDEP cannot be more specific about the adoption schedule 

at this time. 

IV. Hearing Officer Comments 

Since July 2009, when the SIP revision was proposed, MANE-VU has issued the final version of 

the report Documentation of 2018 Emissions from Electric Generating Units in the Eastern 

United States for MANE-VU’s Regional Haze Modeling (August 31, 2009). That final version of 

the report should replace the “revised final draft” that was proposed as Appendix H. 

Also, CTDEP has made minor editorial revisions throughout Section 9 of the SIP revision to 

incorporate the new elements added in response to comments. 

V. Conclusion

Based upon the comments submitted by interested parties and addressed in this Hearing Report, I 

recommend that the SIP revision, revised as recommended in this report, be submitted to EPA 

for approval. 

___________________ November 10, 2009

/s/Merrily A. Gere Date 

Hearing Officer