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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 De partment of Environmental Protection (CTDEP) published a notice of in tent to revise the State Implementation Plan (SIP) for air quality to: (1) address the visibility protecti on requirements of sect ion 169A of the federal Clean Air Act (CAA); and (2) update RACT requ irements, 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, w ith the public comment period closing on August 28, 2009. This report addresses only the vi sibility 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 revisi on; all comments made and responses thereto regarding the proposed revisi on to the SIP; and the fina l recommendation based on the proposal and comments received.

II. Summary and Purpose of Proposal The visibility protection SIP revi sion is a plan to serve the na tional goal of restoring natural visibility conditions to mandatory Class I Fe deral 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 Federa l Areas by addressing the aggregate visibility impact of various air pollution s ources over a large geographic region.

The SIP revision includes an assessment of ba seline and natural visibility conditions, an air monitoring strategy, an alternat ive program for Best Availa ble Retrofit Technology (BART), a set of reasonable progress visibi lity goals and a long-term stra tegy for achieving those goals.2

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 Agri culture 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 ad dressed 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 reco mmends highlighting even more this important relationship between the change in emissions and th e 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 participa tion is of great valu e to the interagency process needed to bring about visibility im provements to Class I areas. In response to DOI, CTDEP will take the relationship between emissions and visibi lity 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]3

Response: As is the case with DOI, the CT DEP also appreciates the commitment shown by USDA-FS’s staff on the issue of regional haze and welcomes their continued participation in futu re SIP planning efforts.

3. Comment: Chuck Carlin commends CTDEP’s proposal because regional haze is appropriately addressed and fits well within CT DEP’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 wa y 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)(ii i) should be revised to 40 CFR 51.308(d)(3)(iii). [1]

Response: In the final SIP revision, the refe rence has been revised as recommended in the comment.

9.0 Best Available Retrofit Technology 5. Comment: EPA asks that CTDEP provide some di scussion of how costs were considered in establishing the BART benchmark for SO 2 and NO x . [1]

Response: To Section 9.2.3 of the final SIP revision, CTDEP has added a subsection that specifically addresses the costs of SO 2 , NO x and PM controls for electric generating units and industrial boilers as we ll as a subsection that addresses costs of compliance with Connecticut’s existing NO x and SO 2 regulations. The text of the new material is as follows:

Costs of SO 2 , NO x and PM Controls for EGUs and Industrial Boilers According to NESCAUM’s Assessment of Control Options for BART-Eligible Sources (Attachment Z), SO 2 control for previously uncontrolled EGU boilers is highly cost effective with operational co sts in the range of $100-200 per ton of SO 2 removed. Costs for NO x 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., $/ton) is difficult to addr ess for PM control because the range of PM reductions for different fuel s and processes is very wide. One of the main parameters dictating the “sizing” and hence, costs of a PM control device, is the quantity of flue gas it must ha ndle. As a result, it is mo re appropriate to generalize capital costs per actual cubic feet per minut e (ACFM) of gas flow and is given on a “$/ACFM” basis. PM control costs range from $1-$40/ ACFM of gas flow.

Many of the same control technologies for E GUs 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 boile r and typical operati ng conditions, with high end cost estimates for NO x removal going over $10,000/ton.

Costs of Compliance with Connecticut’s Existing Regulations: RCSA section 22a174-19a (Control of SO 2 Emissions from Power Plants and other large stationary4

sources of air pollution), RCSA s ection 22a-174-22 (Control of NO x Emissions) and RCSA section 22a-174-22c (CAIR NO x 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 fo r low and higher sulfur residual fuel has been minimal. For example, according to the U.S. Energy Information Administration, the August averag e 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/dna v/pet/pet_pri_spt_s1_d.htm ).

For NO x , sources complying with RCSA Sec tion 22a-174-22 and RCSA Section 22a174-22c through emissions trading, costs of compliance are dire ctly related to costs of NO x discrete emission reduction credits (DERCs) and/or allowances. NO x DERC and allowance prices vary because they are cu rrencies of market-based programs. In March 2004 NO x allowance prices were a pproximately $2000/ton; CAIR NO x Ozone Season allowance prices as of Novemb er 2009 are approximately $130/ton.

6. Comment: CTDEP should include a table to accompany Figure 9.6 quantifying the tons of NO x reduced by Connecticut’s BART alternat ive versus BART-eligible sources alone, similar to Table 9-8 provided for SO 2 reductions. [1]

Response: To the final SIP revision, CT DEP has added Tables 9.16 and 9.17 and accompanying text, comparing NO x emissions reductions (actua l and potential) for the NO x Budget Program sources versus the BART-eligible sources, as follows:

Table 9.16 shows the NO x reduction in potential emi ssions between 2002 and 2006 from all Post-2002 NO x Budget Program sources as co mpared with the reduction in NO x potential emissions from BART-eligible sources alone. The “l ow 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 em ission 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 indus trial boilers, depending on coal and boiler type.5

Table 9.16: Comparison of NO x Potential Emissions and Re ductions since 2002 from all Post-2002 NO x Budget Program sources vs. BART-eligible sources alone (tpy)* NO x potential emissions from all Post-2002 NO x Budget Program

sources Year=2002 Year=2006 Reduction in potential emissions 46,188 34,833 11,355

NO x potential emissions from BART-eligible sources alone Year=2012

27,554 High end24,434Low end9,701 3,120

17,853

* It should be noted that between 1994 and 2006 NO x potential emissions from all sources included in the Post-2002 NO x 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, NO x potential emissions from BART-eligib le sources alone since 1994 would be reduced from 43,659 tons to 24,434 tons for th e high end level of cont rol (a difference of 19,225 tons) and to 9,701 tons for the low end le vel of control (a difference of 33,958 tons).

Table 9.17 shows the reductions in actual NO x emissions from all Post-2002 NO x Budget Program sources and BART-eligible sources since 1994. Again, Connecticut’s existing NO x program has resulted in considerably more NO x reductions (3,114 tons) than BART control alone.

Table 9.17: Comparison of NO x Actual Emissions and Reductions since 1994 from all Post-2002 NO x Budget Program sources vs. BART-eligible sources alone (tpy) NO x actual emissions from all Post-2002 NO x Budget Program

sources Year=1994 Year=2002 Year=2006 Reduction in actual emissions since 1994 13,411 6,150 5,346 8,065

NO x 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 NO x potential emissions are “based on the lower of RCSA s ection 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 of6

the NO x emissions limit in Table 9.14 has been addressed by identifying the new source review program in the footnote, a nd 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 ha s been made consistent with the language in Tables 9.5, 9.13 and 9.14:

Table 9.5: SO 2 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 contro l (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.7

Table 9.6: SO 2 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 contro l (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.8

Table 9.13: NO x 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 regulat ory limits or federally enforceable permit (New Source Review) conditions.9

Table 9.14: NO x 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 regulat ory limits or federally enforceable permit (New Source Review) conditions.

8. Comment: At page 9-34, EPA sugge sts 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 imp acts 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 emissi on limits, the Connecticut limits can be considered reasonable since the highest PM visib ility impact from any one BART unit is so low (0.0035 deciviews) compared to the 0.1 decivi ew impact considered in the MANEVU recommended limits. [1]

Response: In the final SIP revision, CTDEP ha s enhanced the discussion in Section 9.3.3 of the visibility impact reasonably expe cted from the BART-eligible sources as recommended in the comment. CTDEP ha s 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)10

The PM emission limits in RCSA section 22a -174-18 and Connecticut’s BART-eligible source permits (Middletown Unit 4, PSEG Br idgeport 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-V U 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 per cent (500 ppm) sulfur, by we ight, 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 per cent 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 St atute section 16a-21a, which limits the fuel sulfur content of heating distillate oil and off-road diesel oil to 500 ppm as of th e 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 wh ich 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 re vision as Attachment GG ( See Section 11.11 of the SIP revision). CTDEP will continue to work cl osely with NY, MA and RI in seeking to realize the fuel sulfur standard s of the MANE-VU strategy.

10. Comment: Page 11-27 states: “Connecticut in tends to adopt all reasonable control measures as expeditiously as practicable, in a manne r consistent with state law, so that they may be in place by the end of the ten-year pla nning period.” Connecticut’s SIP revision submittal should include a schedule for adoption of these measures. [1]

Response: CTDEP has added the following two se ntences 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 reducti on of distillate fuel su lfur content to 15 ppm by 2018, CTDEP commits to pursue adoption of legislation that will implement this measure by no later than 2018.11

The regulatory adoption and le gislative 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 Of ficer Comments Since July 2009, when the SIP revision was propos ed, MANE-VU has issued the final version of the report Documentation of 2018 Emissions from El ectric 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 “r evised final draft” that was proposed as Appendix H.

Also, CTDEP has made minor ed itorial revisions throughout Sec tion 9 of the SIP revision to incorporate the new elements a dded in response to comments.

V. Conclusion Based upon the comments submitted by interested part ies and addressed in this Hearing Report, I recommend that the SIP revision, revised as r ecommended in this report, be submitted to EPA for approval.

___________________ November 10, 2009 /s/Merrily A. Gere Date Hearing Officer