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www.environmental integrity.org

CHIEF CLERKS OFFICI,December 7 ̂ 2007

LaDonna Castafruela. Chief ClerkMC-10sTexas Commission on Environmental QualityP.O. Box 13087Austin, Texas 7 87 1 l-3087

Via Hand Delivery

RE: Sierra Club Comments on NRG Limestone Unit 3 Draft Air Permit;SOAH Docket No. 582-08-0861; TCEQ Docket No. 2007-1820-AIR(Proposed Permit Nos. 79188 and PSD-TX-1072)

Dear Ms. Castairuela:

Pursuant to the Notice of Public Meeting issued on November20,2007, and theNotice of Direct Referral issued on Decemb er 3,2007 , Sierra Club hereby submits theenclosed comr-nents and requests a contested case hearing on the above-referenced matter.

Please f-eel free to call me if you have any questions. Thank you for yourattention to tl-ris matter.

Sincerelv. , tA . , . /

M,-A/'r I

I lan M. LevinEnvironmental h-rtegrity Proj ect1002 West Avenue, Suite 300Austin, Texas 78701Ph: (512) 619-7287Fax: (512) 479-8302i levi ni4)env i ron rnentaI i nte gli ty.olg

COUNSEL FOR SIERRA CLUB

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Preliminary Comments and Request for Contested Case Hearing NRG Limestone Unit 3 (Limestone County, Texas)

SOAH Docket No. 582-08-0861; TCEQ Docket No. 2007-1820-AIR Proposed Permit Nos. 79188 and PSD-TX-1072

Sierra Club’s Interests and Request for Contested Case Hearing

The Sierra Club, founded in 1892 by John Muir, is one of the oldest and largest grassroots environmental organizations in the country, with more than 700,000 members nationwide. Sierra Club is a nonprofit corporation organized under California law, with offices, programs and members in Texas.

Among the goals of the Sierra Club are preserving and enhancing the natural environment and protecting public health. The Sierra Club has the specific goal of improving outdoor air quality.

The Sierra Club and its members have a significant interest in ensuring that any permits issued for the proposed new unit comply with all applicable statutory and regulatory requirements. Sierra Club members own property, reside, and/or recreate nearby and downwind of the Limestone plant. Sierra Club members reside in Jewett, Donie, Groesbeck, Mexia, Buffalo, Fairfield, Marquez, Centerville, Robbins, and several other towns in the direct vicinity of the Limestone plant.

One such Sierra Club member is Betty Durrenberger. Ms. Durrenberger has been a Sierra Club member since April 2002. She resides just outside of the town of Jewett, on approximately ten acres of land located on Lake Limestone. Ms. Durrenberger estimates that she resides approximately five or six miles from the plant. Ms. Durrenberger and her husband, Robert, enjoy nature and spend a great deal of time outdoors, including fishing for catfish and sand bass on Lake Limestone. Ms. Durrenberger is concerned about the air emissions from the proposed Limestone Unit No. 3. She is concerned about how this plant is going to affect her community, neighbors, land, health, the health of her family and her way of life, and enjoyment and use of her property. We request a contested case hearing.

Provided below are Sierra Club’s non-exhaustive preliminary comments on the Application and Draft Permit. I. The BACT Limits and BACT Analysis are Flawed

Over the years, EPA has issued policy guidance on the BACT process several times. Most notably, in 1980 EPA published the Prevention of Significant Deterioration Workshop Manual1, and in 1990 it published the (Draft) New Source Review Workshop

1 Leigh Hayes, et al, TRW Incorporated, Prevention of Significant Deterioration Workshop Manual (Oct. 1980) EPA 450/2-80-081.

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Manual2 accompanied by the “Top-Down” Best Available Control Technology Guidance Document.3 The following description reflects the process generally used to perform a BACT analysis today. The Top-Down methodology consists of a number of steps.

STEP 1: IDENTIFY ALL POTENTIAL AVAILABLE CONTROL TECHNOLOGIES. The first step in a “Top-Down” analysis is to identify, for the emission unit in question, “all available” control options. Available control options are those air pollution control technologies or techniques with a practical potential for application to the emissions unit and the regulated pollutant under review. This includes technologies employed within or outside of the United States. Air pollution control technologies and techniques include the application of production processes or available methods, systems, and techniques, including fuel cleaning or treatment or innovative fuel combustion techniques for control of the affected pollutant.

STEP 2: ELIMINATE TECHNICALLY INFEASIBLE OPTIONS. The technical feasibility of the control options identified in Step 1 is evaluated with respect to the source-specific (or emission unit specific) factors. In general, a demonstration of technical infeasibility should be clearly documented and should show, based on physical, chemical, and engineering principles, that difficulties would preclude the successful use of the control option on the emission unit under review. Technically infeasible control options are then eliminated from further consideration in the BACT analysis. STEP 3: RANK REMAINING CONTROL TECHNOLOGIES BY CONTROL EFFECTIVENESS. All remaining control alternatives not eliminated in Step 2 are ranked and then listed in order of over-all control effectiveness for the pollutant under review, with the most effective control alternative at the top. A list should be prepared for each pollutant and for each emissions unit subject to a BACT analysis. The list should present the array of control technology alternatives and should include the following types of information:

control efficiencies; expected emission rate or expected emission reduction; collateral environmental impacts; collateral energy impacts; and collateral economic impacts.

2 Office of Air Quality Planning and Standards, U.S. EPA, New Source Review Workshop Manual: Prevention of Significant Deterioration and Nonattainment Area Permitting (Draft Oct. 1990). Although this is designated as an EPA draft document, it is widely considered to be an authoritative source of EPA thinking regarding the PSD program and is widely used as such by practitioners. 3 Office of Air Quality Planning and Standards, U.S. EPA, “Top-Down” Best Available Control Technology Guidance Document (Mar. 15, 1990).

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STEP 4: EVALUATE MOST EFFECTIVE CONTROLS AND DOCUMENT RESULTS. The applicant then presents the analysis of the associated impacts of the control option in the listing. For each option, the applicant is responsible for presenting an objective evaluation of each impact. Both beneficial and adverse impacts should be discussed and, where possible, quantified. In general, the BACT analysis should focus on the direct impact of the control alternative. The applicant proceeds to consider whether impacts of unregulated air pollutants or impacts in other media would justify selection of an alternative control option. In the event the top candidate is shown to be inappropriate, due to collateral energy, environmental, or economic impacts, the rationale for this finding should be fully documented for the public record. Then the next most stringent alternative in the listing becomes the new control candidate and is similarly evaluated. This process continues until the technology cannot be eliminated. STEP 5: SELECT BACT. The most effective control option not eliminated in Step 4 is proposed as BACT for the emission unit to control the pollutant under review.

The important point in the discussion above is that the support for rejecting an otherwise “top” control technology, based on its ability to achieve the maximum degree of emissions reduction, should be reasoned, supported via technical analysis and thorough. It is clear, of course, that this analysis is, inherently, conducted on a case-by-case basis. Although the BACT selection process can seem complicated, its purpose is simple: “to promote the use of the best control technologies.” In re General Motors, Inc., 10 E.A.D. at 378 (EAB 2002), citing Knauf I, 8 E.A.D. at 140. Congress chose to require an emission limit based on the “maximum degree of reduction … achievable for such source” at the time the source is constructed. 42 U.S.C. §§ 7475(a)(4) (new sources are subject to BACT), 7479(3) (BACT definition). A BACT analysis should always default to the best pollution control option available. Citizens for Clean Air v. EPA, 959 F.2d 839, 845 (9th Cir. 1992), citing In re: Spokane Regional Waste-to-Energy Applicant, PSD Appeal No. 88-12 (EPA June 9, 1989), at 9 (internal quotation marks omitted) (emphasis in original); see also In re: Inter-Power of New York, Inc. 5 E.A.D. 130, 135 (EAB 1994) (“Under the ‘top-down’ approach, permit applicants must apply the most stringent control alternative, unless the applicant can demonstrate that the alternative is not technically or economically achievable.”); In re Pennsauken County, New Jersey Resource Recovery Facility, 2 E.A.D. 667 (Adm’r 1988), available at 1988 EPA App. LEXIS 27, 28 (Nov. 10, 1988) (“Thus, the ‘top-down’ approach shifts the burden of proof to the applicant to justify why the proposed source is unable to apply the best technology available.”) Therefore, by design, BACT results in increasingly stringent limits as technology advances and improves the ability to reduce or capture pollutants.

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Regardless of how BACT is determined by EPA or the State of Texas, it is clear that (1) BACT is technology-forcing or technology-driving;4 (2) as a result, BACT determinations made over time tend to be increasingly more stringent;5 and (3) the outcome of correctly implemented BACT methodology should result in the same BACT, whether using EPA methodology or Texas methodology.6 There are numerous flaws in how the Limestone project BACT determinations were conducted, collectively leading to incorrect BACT determinations. At the outset it is important to note that the Limestone analysis appears to have stopped at Tier I. Within this, NRG’s BACT determination (and TCEQ’s acquiescence) mainly rested on permit limits for already issued plants and, in some cases permit limits in applications for permits. In many cases, direct comparisons are made to two Texas permit applications – namely the Sandy Creek application in 2004 and the Spruce 2 application in 2005.7 Such a “backward” looking BACT determination is improper on numerous grounds. The BACT definition clearly requires a consideration of cleaner production processes and innovative fuel combustion techniques such as gasification.

NRG did not follow EPA’s Top-Down BACT analysis methodology. Although this is not necessarily a problem – that is, if TCEQ’s own Three-Tier methodology was also not followed. As noted earlier, only a Tier I analysis was done relying on already issued permits. The explicit condition cited in the Tier I guidance is that recent limits can be accepted as BACT only if “…no new technical developments have been made that indicate additional reductions are economically or technically reasonable.” Tier I goes on to state that “…evaluation of new technical developments may also be necessary.” It has been assumed by NRG and TCEQ that this “no new technical development” condition was met. I will show later, on a pollutant by pollutant basis that this is not so. Suffice it to say that there are significant developments in air pollution controls (resulting in lower and lower limits being achieved) for power plants throughout the US and worldwide on almost a monthly basis. We are witness to fast moving developments in the case for controlling almost every major pollutant including SO2, NOx, PM10, mercury, etc. None of these new technical developments was reviewed or even noted even in the most recently updated June 2007 analysis that supports the BACT determinations, both by NRG and the TCEQ. TCEQ’s own guidance speaks to this very aspect. In the TCEQ RG-383 guidance document Flow Diagram, please note that Box 3 deals with reduction efficiency and Box 7 requires that APD identify “…other emission reduction options with greater performance that should be evaluated…”). TCEQ did not consider these before accepting NRG’s BACT proposals. 4 See Hendrickson deposition in the TXU Case, rough transcript, page 267, lines 22-23. 5 See e-mailed memo from Mr. Randy Hamilton of TCEQ to Ms. Kathy French of dated April 9, 2004 dealing with emissions limits proposed for the Sandy Creek application. Mr. Hamilton states “As background to some of our thinking, the BACT regulatory approach is designed to result in downward-moving emission targets over time, reflecting improvements in control technology.” 6 See Hendrickson deposition in the TXU Case, rough transcript, page 179, lines 10-23. 7 See sub-sections entitled “Analysis of Permit Limits” provided under each pollutant in the BACT discussion in the application.

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In any case, BACT is a case by case analysis. Relying solely on past analysis, no matter how recent or how correct, will not lead to correct BACT selections for new projects; instead new developments have to be noted, considered, and set aside only based on careful and supported case by case analysis. Only in this manner can the technology-forcing goals of BACT be met. TCEQ’s own guidance states that “…[G]enerally, any emission reduction options that you request an applicant to evaluate should have been successfully demonstrated in Texas and the United States. However, there may be cases when you request an applicant to investigate options that are used outside of Texas or that have not yet been successfully demonstrated…..The identified emission reduction option(s) may have been demonstrated for the same industry or different industries with similar emission streams.” Specifically, the Guidance notes that “…[T]he BACT for any particular industry is not static. Instead, BACT progresses as technology progresses or as process developments occur. Subsequent to the most recent permit reviews for the same industry, it is possible that information has become available to indicate that even better performance can be achieved than that proposed…”

In summary, NRG has not conducted a proper BACT analysis either by Federal or by Texas standards. As a result the emissions limits purportedly selected as BACT in the permits for the project are flawed and should be set aside.

SO2

The proposed permit contains two different BACT emission rates as follows: 0.06 lb/MMBtu (annual average) and 0.10 lb/MMBtu (30-day rolling average). The input SO2 contents in each of the fuels proposed are shown (in lb/MMBtu) as 1.23 (sub-bituminous); 6.58 (bituminous); and 8.35 (petroleum coke).8 The estimated SO2 inputs for each of the mix of fuels to be used, along with the calculated efficiencies for each of the two time periods is as follows:

Fuel Mix Input SO2 (lb/MMBtu)

Efficiency, Annual (BACT = 0.06)

Efficiency, 30-day (BACT = 0.10)

100% sub-bituminous coal

1.23 95.12% 91.87%

20% petroleum coke/80% sub-bituminous

2.65 97.7% 96.23%

40% bituminous/60% sub-bituminous

3.37 98.2% 97.03%

NRG notes that the controls for SO2 will be wet flue gas desulfurization (WFGD). While this is the best technology choice for SO2 controls, the emissions limits that are proposed as BACT do not represent the maximum reductions from applying WFGD, given the calculated control efficiencies in the table above. 8 See table entitled “Typical Fuel Properties for Subbituminous Coal, Bituminous Coal, and Petroleum Coke” in the permit application.

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NRG should be able to obtain 99% removal of SO2 using WFGD. Many different types of WFGD technologies have been demonstrated to provide this level of removal and many vendors have provided guarantees at this level as well. This is being achieved today. Assuming that a 99% efficient WFGD is used, the SO2 BACT limit, even for the worst case fuel combination should be 0.034 lb/MMBtu. More than twenty years ago, Allegheny Power’s Mitchell power station, near Pittsburgh, was retrofitted in 1982 with a magnesium-enhanced lime (“MEL”) wet FGD system pursuant to a Consent Decree. Data for four months during 1983 and 1984 for that unit show that the daily average SO2 emission rate was 0.009 lbs/MMBtu and the daily average SO2 removal efficiency was 99.76%. The maximum monthly average during these four months was 0.029 lb/MMBtu, corresponding to a 99.72% SO2 reduction. Thus, over 99% reduction of SO2 was being achieved more than two decades ago. A recent paper discussing the actual operating performance of the Chiyoda JBR or CT-121 wet scrubber technology in Japan notes that SO2 removal efficiency of greater than 99% was achieved for all load levels and that a “[s]table SO2 removal efficiency of over 99 percent” was achieved.9 Mitsubishi Heavy Industries, a reputable vendor of wet scrubbers, has a design called the High Efficiency Double Contact Flow Scrubber (“DCFS”), which has achieved SO2 removal efficiencies as high as 99.9%. A presentation on the DCFS scrubber highlights the fact that it can be designed to achieve SO2 removal efficiencies as high as 99.9% on a unit that burns high sulfur coals without the use of buffer additives.10 The manufacturer guarantees SO2 removal of 99.8%.11 A 2004 paper discussing the DCFS scrubber technology notes that this technology was recently selected at least two years ago by TVA for their Paradise Plant Unit 3, which will start up in early 2007.12 This paper also reports on several recent commercial operating successes with this technology “including super high desulfurization performance (i.e., 99.9%) with a single absorber.”13 The paper also notes that the COSMO oil Yokkaichi unit is an outstanding example of high SO2 removal by a single counter current DCFS. Commercial operation at COSMO began in 2003, and the FGD system has achieved a cumulative availability of 100 percent since startup. The system is designed at 99.5% and operates at 99.9% SO2 removal efficiency. Another vendor, Alstom, recently discussed high efficiency scrubbing on high sulfur fuels. As noted in the paper “[t]o date, the wet flue gas desulfurization system has achieved 100% availability while achieving the plant SO2 emissions limits throughout the

9 Commercial Experience of the CT-121 FGD Plant for 700 MW Shinko-Kobe Electric Power Plant, Paper #27, by Yasuhiko Shimogama, et al., MEGA Symposium, Washington DC, May 22, 2003. 10 High Efficiency Double Contact Flow Scrubber for the U.S. FGD Market, Paper No. 135, by Dr. Jonas S. Klingspor, et al, MEGA Symposium, Washington DC, May 22, 2003. 11 Id. 12 Commercial Experience and Actual-Plant-Scale Test Facility of MHI Single Tower FGD Paper #33, by Yoshio Nakayama, et al, MEGA Symposium, Washington DC, August, 2004. 13 Id.

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operating duration….as indicated…the WFGD system has achieved SO2 removal efficiencies up to 99+% without the use of organic additives.”14 There are probably additional instances of greater than 99% removal that have occurred and are occurring, however, the examples provided above show that numerous reputable vendors, with a variety of designs, can achieve and can guarantee 99% removal efficiency on a sustained basis. The Coal Utilization Research Council within the Electric Power Research Institute (CURC/EPRI), concluded in its September 2006 Roadmap that up to 99% SO2 removal for FGD was commercially available in 2005.15 The CURC/EPRI Roadmap also projects removals of up to 99.6% in 2010 and 99.9% in 2015.16 If NRG is ordered to install BACT level controls for SO2, the FGD system will likely begin construction in the 2009 time frame for Limestone. Therefore, the BACT emissions limit should be set, assuming that WFGD can achieve 99% reduction of SO2 across the WFGD, except for periods of startup, shutdown, and malfunction. Ideally, there should be separate limits for each of the three fuel mixes proposed by NRG. However, at the very least, considering the worst case fuel mix, the SO2 BACT emission limit should be no greater than 0.034 lb/MMBtu. This should be for the 30-day rolling average and therefore, a separate limit for a longer (i.e., annual) averaging time period is not required.

NOx The proposed permit contains 2 different BACT emission rates for NOx as follows: 0.05 lb/MMBtu (annual average) and 0.07 lb/MMBtu (30-day rolling average). NRG anticipates achieving these limits using a combination of in-boiler controls (such as low NOx burners and over-fire air) and post-boiler control using Selective Catalytic Reduction (SCR). However, NRG does not directly discuss what level of NOx it anticipates out of the boiler and, consequently, at the inlet to the SCR. But, since the 1-hour permit limits include periods of startup, shutdown, and malfunction of the control device (i.e., SCR), we assume that NRG and TCEQ believe that the boiler-out or NOx emissions will be 0.20 lb/MMBtu.17 This implies that a catalyst NOx removal efficiency of 75% (i.e., 0.20 down to 0.05 lb/MMBtu) is implicit in NRG’s analysis. While we do not agree with the proposed BACT limits for NOx, we believe that the choice of control technologies by NRG is appropriate. As shown below, in combination, the controls specified can achieve lower emissions than the 0.05 lb/MMBtu NOx annual average assumed by NRG and TCEQ. 14 State of the Art Wet FGD System for High-Sulfur Fuels in Florina/Greece, by G. Catalano, et al., Power Gen Europe, 2005. 15 CURC/EPRI Technology Roadmap Update, September 20, 2006, Available at www.coal.org/PDFs/jointroadmap2006.pdf. 16 Ibid.. 17 See Section 3.2.1 in the June 2006 permit application.

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It is widely recognized that NOx emissions produced in the boiler are generally lower using sub-bituminous (PRB) coals than other fuels such as Eastern bituminous coals, for example.18 Over the years, most of the major boiler and burner manufacturers have developed combustion control technologies to minimize NOx formation in the boiler itself using PRB coals. Many of these are retrofit technologies on existing units, where emissions reductions are usually more difficult (as compared to new units). Examples of NOx emissions actually achieved by several PRB fired coal units is discussed later. Much lower boiler outlet NOx levels, as low as 0.1 lb/MMBtu, have been achieved and maintained on a continuous basis for numerous sources burning PRB coals and using only combustion controls.19 20 21 22 23 24 25 26 Even TCEQ is aware that lower levels have been achieved without the use of SCR.27 The EPA Acid Rain database data includes many older subcritical units operating at lower boiler outlet NOx levels with the proposed combustion controls, including Scherer Units 3 and 4 in Georgia, Labadie Units 1-4 in 18 NOx Emissions Produced with Combustion of Powder River Basin Coal in a Utility Boiler, WRI-97-033. Report by the Western Research Institute for the Dept. of Energy, April 1997. The Paper notes (page v) that “…PRB coal offers an advantage for utilities meeting NOx limitations because it…can produce 20% less NOx than burning an eastern bituminous coal.” 19 G.T. Bielawski, et. al., How Low Can We Go? Controlling Emissions in New Coal Fired Power Plants. BR-1715. Presented to the U.S. EPA/DOE/EPRI Combined Power Plant Air Pollutant Control Symposium: “The Mega Symposium,” August 20-23, 2001 Chicago, Illinois, U.S.A. This paper states that “For PRB coal, emission levels down to 0.008 lb/MMBtu NOx , 0.04 lb/MMBtu SO2, and 0.006 lb/MMBtu particulate with a high level of mercury capture can be achieved.” 20 A. Kokkinos et al., Which is Easier: Reducing NOx from PRB or Bituminous Coal, Power 2003. This paper discuses retrofits at Georgia Power Company’s Plant R.W. Scherer Units 3 and 4 (which burn PRB coal) with separated over fire air. The paper shows that Units 3 and 4 achieved 0.13 lb/MMBtu of NOx after the retrofit, with CO ranging from 114 to 121 ppm (3% O2 basis). 21 Robert Lewis, et al., Summary of Recent Achievements with Low NOx Firing Systems and Highly Reactive PRB and Lignite Coal: as Low as 0.10 lb NOx/MMBtu; Patrick L. Jennings, Low NOx Firing Systems and PRB Fuel; Achieving as Low as 0.12 LB NOx/MMBtu, ICAC Forum 2002. 22 T. Whitfield, et al., Comparison of NOx Emissions Reductions with PRB and Bituminous Coals in 900 MW Tangentially Fired Boilers, 2003 Mega Symposium. 23 Robert von Hein, Reducing NOx Emissions on a Mid-Western Utility Boiler Firing PRB Coal with Low-NOx Burners and Overfire Air, Powergen 2002. 24 James Topper and others, Maximize PRB Coal Usage in Conjunction with In-Furnace NOx Solutions to Minimize Cost of NOx Compliance, Mega 2001. 25 Galen Richards, et al., Development of an Ultra Low NOx Integrated System for Pulverized Coal Fired Power Plants. “Baseline NOx emissions increased with coal rank 0.49, 0.56, and 0.66 lb/MMBtu for the PRB, hvb, and mvb coals, respectively. The optimized TFS 2000TM firing system achieved NOx emissions of 0.11, 0.15, and 0.22 lb/MMBtu for the 3 fuels for approximately 70-75% reduction over the baseline NOx emissions. Additional NOx reduction of approximately 0.03 lb/MMBtu over the optimized TFS 2000TM levels was achieved using the Ultra-Low NOx firing system technology.” 26 A. D. LaRue et al., Lower NOx/Higher Efficiency Combustion Systems, BR-1714. Presented to the U.S. EPA/DOE/EPRI Combined Power Plant Air Pollutant Control Symposium: “The Mega Symposium,” August 20-23, 2001 Chicago, Illinois, U.S.A. This paper discusses the deployment of Babcock’s DRB-4Z burners at W.A Parish Units 5 and 6. It notes that “NOx emissions were even lower on Unit 5…Full load emissions were reduced to 0.15 lb/MMBtu…” 27 See e-mailed memo from Mr. Randy Hamilton of TCEQ to Ms. Kathy French of dated April 9, 2004 dealing with emissions limits proposed for the Sandy Creek application. Mr. Hamilton states “Your proposed emission rates are…near the best emission performance of Texas units constructed in the 1980s, such as the NOx of LCRA’s Sam Seymour Unit 1 at 0.11 lb/MMBtu…(data from EPA, third quarter, 2003). It is notable that LCRA’s Unit 1 achieves this rate without using SCR…”

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Missouri,28 and Rush Island Units 1-2 in Missouri. Thus, the expected proposed boiler outlet NOx of 0.2 lb/MMBtu for the new, Limestone unit is not credible, given the use of low NOx burners and staged overfire air. Analysis of NOx CEMS data for some PRB burning units from the acid rain database for 2005 reported to the EPA demonstrates that these low limits are not only achievable, but in fact have been achieved. Similar data are also available for 2006 and 2007. These data are summarized in the Table below.

Achieved NOx Emission Rates Using Low NOx Burners and Over Fire Air (2005)

Plant

Average of Monthly

NOx (lb/MMBtu)

J.T. Deely Unit 1 and 2, TX 0.132 Newton Unit 1, IL 0.122 Newton Unit 2, IL 0.123 Labadie Unit 1, MO 0.110 Labadie Unit 2, MO 0.112 Labadie Unit 3, MO 0.115 Labadie Unit 4, MO 0.114

The data demonstrates that much lower boiler outlet NOx levels have been achieved in practice. In summary, it is quite clear that the boiler-out NOx emissions that should be possible at the new proposed Limestone unit 3 should be well below the 0.20 lb/MMBtu range – in fact, they should be below 0.15 lb/MMBtu. Of course, assuming that boiler-out emissions are 0.15 lb/MMBtu makes the SCR removal efficiency 67% in order to achieve the proposed permit NOx limit of 0.05 lb/MMBtu. NRG’s BACT analysis did not consider readily available data from the EPA Acid Rain database. NRG fails to provide, in the Application, any details regarding the design of this SCR other than that it will use ammonia as the reducing reagent. Although it is typical for fluid dynamic modeling of the boiler and gas path to be conducted during design, it is not discussed in NRG’s application. There is very little specific information about the catalyst material and no information on catalyst quantities, number and size of catalyst layers, the configuration of the catalyst reactors in relation to the gas flow path, and the presence of trapping and cleaning devices such as screens, soot blowers, or sonic horns. There is also no detail provided regarding how the ammonia injection grid will be configured, how many injectors will be located, and where the injectors will be located. Finally, there is no discussion of catalyst management planning over time. The application does not reflect any discussions with SCR or catalyst vendors. It is surprising 28 Mark Stiller, et al., Long-term Commitment to Improve Plant Performance of AmerenUE’s Labadie Station, Units 1-4.

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that TCEQ was able to conduct its technical review of the application with such a complete absence of almost any relevant design detail. There is certainly no justification for accepting NRG’s implicit 75% or even 67% NOx removal value for the SCR. Another deficiency in the Application (and TCEQ’s review) is that there is no recognition or discussion of the tremendous amounts of new information from SCR operations and catalyst vendors that was available to NRG and its consultants in 2006, when the application was prepared and submitted. This is clearly new information that is explicitly required to be included in Tier I BACT analysis, yet it was not. In effect, by not providing a discussion of these developments, NRG’s analysis rests on older, and now outdated information. Modern SCRs routinely achieve NOx removal efficiencies greater than 90%.29 Detailed analyses of EPA’s Acid Rain database indicate that “90% removal efficiency was currently being achieved by a significant portion of the coal-fired SCR fleet…”30 at the time of preparation of the Limestone permit application. More than 30 units have achieved greater that 90% NOx reduction based on 2005 data.31 Ninety percent NOx removal was achieved on 10,000 MW of coal-fired generation in 2004.32 Many coal-fired units have been guaranteed to achieve greater than 90% NOx reduction and are achieving greater than 90% reduction.33 The McIlvaine reports, one of the sources that EPA states should be considered in a BACT analysis,34 indicate three of Haldor Topsoe’s SCR installations averaged over 95% NOx reduction during the 2005 ozone season.35 Given this impressive track record, NRG must demonstrate why the Limestone Unit 3 SCR cannot achieve a minimum of 90% NOx reduction when SCR retrofits on old subcritical boilers fired on PRB coals are doing better.

29 Clayton A. Erickson et al., Selective Catalytic Reduction System Performance and Reliability Review, The 2006 MEGA Symposium Paper #121, pages. 1, 15; Clayton A. Erickson et al., Selective Catalytic Reduction System Performance and Reliability Review Slides, page 30; Competitive Power College, PowerGen 2005. Selective Catalytic Reduction – From Planning to Operation, page 77. 30 Clayton A. Erickson et al., Selective Catalytic Reduction System Performance and Reliability Review, The 2006 MEGA Symposium Paper #121, page 15. 31 Clayton A. Erickson et al., Selective Catalytic Reduction System Performance and Reliability Review, The 2006 MEGA Symposium Paper #121, page. 1. 32 Competitive Power College, PowerGen 2005. Selective Catalytic Reduction – From Planning to Operation, p. 77, page 77. 33 Based on a comparison of ozone season (monthly average for June) and non-ozone season (monthly average for January) 2006 data from EPA’s acid rain data base, these include the following: Chesapeake Energy Center Unit 3 (94.51%); John E. Amos Unit 1 (94.27%); John E. Amos Unit 2 (94.06%); Elmer Smith Unit 1 (93.6%); Mount Storm Unit 2 (93.53%); Dallman Unit 2 (93.39%); Dallman Unit 1 (93.24%); New Madrid Unit 1 (93.24%) and New Madrid Unit 2 (93.24). 34 Draft 1990 NSR Workshop Manual, B 12. 35 McIlvaine Utility e-Alert, No. 798. November 3, 2006. Mr. Nate White of Haldor Topsoe provided the following information: “Topsoe has over 100,000 hours of operating experience on PRB coal. In fact, three Topsoe supplied SCRs achieved the highest NOx efficiency for all U.S. coal-fired high dust SCRs, averaging over 95 percent NOx reduction over the 2005 Ozone season.”

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Based on review of the current state of catalyst technology and based on discussions with SCR and catalyst vendors36 NRG should be able to obtain a 90% removal guarantee for NOx removal at the SCR. As noted above, SCRs are commonly guaranteed with 90% NOx removal for bituminous coals. While there have been challenges associated with operating SCRs with popcorn ash and higher than usual calcium content common in PRB coals, almost all of the catalyst vendors and SCR designers have been developing technologies to accommodate these characteristics of PRB coals in SCR designs since 2000 or earlier. Pluggage by ash is mitigated by positioning the reactors in relation to the gas path vertically in a manner that allows for ash to fall into hoppers; additionally screens can also be used to minimize ash pluggage. TCEQ staff themselves have elaborated on these and additional methods that are in use to mitigate ash pluggage in SCRs in other instances.37 Concerns due to catalyst deactivation by calcium sulfate at the surface layers of the catalyst have been mitigated by providing for cleaning devices such as soot blowers and sonic horns. Additionally, SCR’s are designed with additional catalyst capacity, based on coal characteristics, in order to achieve necessary reactor life, prior to regeneration or change-out. In short, there is no technical reason NRG cannot obtain a 90% removal guarantee for NOx at the SCR. Based on the discussions above, Sierra Club suggests that the NOx BACT that is appropriate for the Limestone Unit 3 is 0.02 lb/MMBtu, excluding periods of startup, shutdown, and malfunction. This level should be readily achievable by: either a combination of 0.20 lb/MMBtu from the boiler (as assumed by NRG), followed by 90% reduction at the SCR; or less than 0.20 lb/MMBtu from the boiler (as is likely) followed by a lower than 90% reduction at the SCR. Either way, this level can be met on a 30-day average. There is therefore no need for any longer (i.e., annual) averaging period.

PM/PM10 Proposed Limits for PM/PM10 Are Not BACT The Draft Permit contains 2 different BACT emission rates for PM/PM10 as follows: 0.015 lb/MMBtu for the filterable portion (same for any averaging time) and 0.035 lb/MMBtu for total38 PM/PM10 (again, for any averaging time). There is literally no 36 Generally, these vendors include Haldor Topsoe, CERAM, Cormetech, Babcock Power, etc. 37 See analysis entitled “Technical Feasibility of Achieving 0.07 lb/MMBtu on Texas Lignite-Fired Utility Boilers” by Mr. Randy Hamilton in the Oak Grove case. Item No. 7 states that “[M]any techniques are available for mitigating ash deposition. Techniques in use include screens or baffles placed in the duct above ash hoppers and upstream of the SCR, to collect large particles; streamlining the internal ductwork and supports to eliminate flow stagnation where ash accumulates; sonic or steam blowers to remove accumulation on the catalyst face or between layers; using anhydrous ammonia and bypass dampers to reduce the potential for water droplets or condensation to cause plugging.” 38 Total PM10 is the sum of the filterable particulate matter plus particulate matter that is in a form other than solid form at the point of emissions, but that condenses to particulate matter smaller than 10 microns. The filterable fraction is the PM collected on filter paper, while condensable fraction consists of mostly gases that condense in the sampling equipment during an EPA Method 202 test. Condensable PM consists of mainly SAM. However, condensible PM can also include ammonia, hydrogen chloride, hydrogen fluoride, and volatile organic compounds (“VOCs”).

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technical justification other than that these limits “…as stringent as that for other recent PC boiler projects, including projects in Texas”39 meaning Sandy Creek and Spruce Unit 2. The application notes that there are eight final permits with lower filterable PM10 limits of 0.0012 lb/Mmbtu but rejects these are being not comparable because they use a different combination of control systems (such as dry scrubbers and fabric filters). There is no discussion of why this limit cannot be met with the controls proposed at Limestone. There is no detailed discussion of source test data that have achieved lower limits; and why such limits should/should not apply to the Limestone Unit 3. The limits proposed are not BACT. Lower total PM/PM10 emission rates have been permitted as BACT. NRG’s limits must be at least as low as these other limits. Second, operating experience at other plants demonstrates that much lower PM/PM10 limits are achievable and BACT must be established based on such evidence. There have been a number of recent permits with total PM/PM10 limits at or below 0.018 lb/MMBtu. Two examples are the Elm Road Generating Station in Oak Creek, Wisconsin, and the Weston Generating Station Unit 440 in Rothschild, Wisconsin.41 Both have total PM10 limits of 0.0018 lb/MMBtu. The Elm Road permit also has a total PM (of any diameter) of 0.018 lb/MMBtu, while the Weston Unit 4 permit also has a total PM (of any diameter) limit of 0.02 lb/MMBtu. The Hawthorn plant was permitted with a total PM10 BACT limit of 0.018 lb/MMBtu and is meeting that limit.42 An older permit, for the Council Bluffs Energy Center in Iowa43, has a total PM10 limit of 0.025 lb/MMBtu, based on a 3-hour average.44 This plant is operating and stack tests—including Method 202-- demonstrate that it is complying with its total PM10 limit. The Thoroughbred PSD permit, which was challenged extensively through a contested case hearing covering several months, has a total PM10 limit of 0.018 lb/MMBtu.45 The Longview plant, in West Virginia, also has a total PM10 permit limit of 0.018 lb/MMBtu.

39 See page 4-8 of June 2007 permit application. 40 This facility is a 500-MW supercritical pulverized coal-fired boiler. It will burn a PRB sub-bituminous coal. Wisconsin Bureau of Air Management, Analysis and Preliminary Determination for the Construction and Operation Permits for the Proposed Construction of a 500 MW Pulverized Coal Electric Generation Facility for Wisconsin Public Service Corporation -- Weston Power Plant, July 2, 2004, p. 4, Fuel Specifications. 41 Air Pollution Control Construction Permit, Elm Road Generating Station, Issued by Wisconsin DNR, page 6; and Air Pollution Control Construction Permit, Wisconsin Public Service Corporation, Weston Unit 4, Issued by Wisconsin DNR, page 4. 42 KCPL Hawthorne Unit 5 Stack Test Results. 43 This facility is a 750-MW pulverized coal-fired boiler that will burn a PRB sub-bituminous coal. Iowa Department of Natural Resources, Prevention of Significant Deterioration (PSD) Permit Review Technical Support Document for Issuance of PSD Permits for Project Number 02-528, Plant Number 78-01-026, April 21, 2003. 44 Iowa Department of Natural Resources, Air Quality PSD Construction Permit, Notice of MACT Approval, MidAmerican Energy Company, CBEC 4, Original Permit Issued June 17, 2003. 45 Kentucky Natural Resources and Environmental Protection Cabinet, Department for Environmental Protection, Division for Air Quality, Title V Air Quality Permit, Thoroughbred Generating Station, Permit No. V-02-001 Revision 1, December 6, 2002.

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Furthermore, the Table below shows additional numerous units that have been permitted with the listed total (filterable and condensable) PM and PM10 limits.

Table – Additional Facilities with Lower PM/PM10 Limits46

Note that these recent permits range from 0.02 to 0.027 lb/MMBtu for total (both condensable and filterable) PM and from 0.018 to 0.0275 lb/MMBtu for total PM10. Additionally, performance tests confirm that the Limestone Unit 3 can achieve much lower emission rates than proposed as BACT in the permit issued by the TCEQ. At least 225 performance tests at coal-fired plants in Florida, as early as May 2004, measured filterable PM/PM10 at less than 0.015 lb/MMBtu.47 Of these, 147 (65%) recorded PM/PM10 emissions less than 0.010 lb/MMBtu and 82 (36%) recorded PM/PM10 emissions less than 0.005 lb/MMBtu. The lowest reported PM/PM10 emission rate was 0.0004 lb/MMBtu. Similar results have been reported for Georgia Power’s coal-fired units, including: 0.003 lb/MMBtu at Scherer Unit 4;48 0.004 lb/MMBtu at Scherer Unit

46 Florida Department of Environmental Protection, Technical Evaluation and Preliminary Determination for Seminole Generating Station Unit 3, August 21, 2006 p. 12. 47 See Excel Spreadsheet entitled PM/PM10 Source Test Results, State of Florida. 48 Spectrum Systems Inc., Compliance Particulate Emissions Testing Performed at Georgia Power Company Plant Scherer Units 1, 2, 3 and 4, Juliette, Georgia, 1998.

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4;49 0.006 lb/MMBtu at Plant Yates Unit 7; 0.008 lb/MMBtu at Yates Unit 650 and Hammond Unit 4.51 In view of this data discussed above, NRG and TCEQ should defend why the proposed limits for PM/PM10 in the permits are BACT. If not, TCEQ should review the data provided, collect additional similar data, and make a proper BACT determination for the proposed plants.

Lead Lowering the PM/PM10 limits will also result in lower emissions of lead as well since these are assumed to be controlled by the baghouse similar to PM/PM10. As a result, the permit limits for lead should be proportionally reduced when the PM/PM10 BACT limit is reduced. Of course, TCEQ should use only the coal lead content data provided by TXU for mines that will likely supply this project.

Sulfuric Acid Mist (SAM, H2SO4) A small amount of the sulfur content of coal is converted into sulfur trioxide, or SO3, in the boiler and in the SCR. The SO3 is then converted into SAM when it contacts water in the scrubber. This SAM is emitted from the stack as small liquid droplets. The Draft Permit sets a SAM emission limit from the Unit at 0.0075 lb/MMBtu. The basis for the limit seems to be the uncontrolled SO2 input into the boiler along with unsupported assumptions regarding conversion of SO2 to SO3. This is not a top-down BACT analysis and does not satisfy the requirements of the applicable regulations including the Clean Air Act. Moreover, the proposed limit appears to assume an unstated and therefore unsupported conversion rate of SO2 to SO3 and does not account for the reductions achievable with even the pollution controls proposed for the Limestone Unit. The limit does not represent BACT. The permit application does not even attempt to identify all available BACT control options. I am aware of at least two control options that are applicable and must be considered in a BACT analysis for SAM. First, a lower conversion SCR catalyst could be used, one achieving less than 0.5% SO2 to SO3 conversion, rather than the unspecified conversion assumed in the NRG analysis. This would lower the SAM created in the SCR. Second, a wet electrostatic precipitator designed to remove at least 90% of the SAM exiting the SDA baghouse could be used. This would further lower the SAM BACT level. 49 Spectrum Systems Inc., Compliance Particulate Emissions Testing Performed at Georgia Power Company Plant Scherer Units 1, 2, 3 and 4, Juliette, Georgia, 2000. 50 Spectrum Systems Inc., Compliance Particulate Emissions Testing Performed at Georgia Power Company Plant Yates Units 6 and 7, Whitesburg, Georgia, 2001. 51 Spectrum Systems Inc., Compliance Particulate Emissions Testing Performed at Georgia Power Company Plant Hammond Unit 4, Coosa, Georgia, 1998.

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Other facilities have been permitted with lower SAM limits. The Newmont Mining plant in Nevada has a BACT limit for SAM of 0.001 lb/MMbtu. (Exhibit III). NRG’s own Parish Unit 8 in Texas has a SAM limit of 0.0015 lb/MMBtu. The Santee Cooper Cross plant has a limit of 0.0014 lb/MMBtu. The SEI Birchwood plant has a limit of 0.002 lb/MMBtu. The AES Puerto Rico facility has a limit of 0.0024 lb/MMBtu. Therefore, it must be presumed that BACT for the NRG Limestone Unit 3 is no greater than 0.001 lb/MMBtu.52 Furthermore, an emission rate even lower than 0.001 lb/MMBtu limit can be achieved by either a wet electrostatic precipitator (“wet ESP”) or sorbent injection.53 Wet ESPs can be used in conjunction with baghouses. A BACT analysis must determine the best control option for each pollutant, and must consider higher-ranked, more effective control options like wet ESP and sorbent injection. However, as indicated no BACT analysis was even attempted for the Limestone Unit 3. This permit record fails to demonstrate “how the [BACT] decision satisfies the regulatory criteria.”54 Therefore, the permit must be denied until a complete BACT analysis is performed and the public has an opportunity to comments on that analysis. There are a number of facilities that use wet ESP to control SAM emissions, including the We Energies Elm Road Generating Station and two 750 MW units at the Northern State Power/Xcel Energy's Sherbourne County Station. Sherbourne County burns low-sulfur subbituminous coal similar to that proposed for the TXU Units. In addition to greater SAM control, use of a wet ESP also removes 95% to 97% of the PM10 as well as mercury and other HAPs.55 In summary, NRG and TCEQ should provide a thorough BACT analysis in support of the SAM BACT. It is my opinion that such an analysis will indicate a BACT level of less than 0.001 lb/MMBtu. 52 In re Newmont Nevada Energy Investment, LLC, TS Power Plant, PSD Appeal No. 05-04, Slip Opinion at 16 (E.A.B. Dec. 21, 2005) (in the absence of differences between the proposed source and previously permitted sources, the permit agency should conclusion that a lower emission limit is representative for the control alternative at issue) (hereinafter “Newmont”); NSR Manual B.24 (“when reviewing a control technology with a wide range of emission performance levels, it is presumed that the source can achieve the same emission reduction level as another source unless the applicant demonstrates that there are source-specific factors or other relevant information that provide a technical, economic, energy or environmental justification to do otherwise.”). 53 R.K. Srivastava, C.A. Miller, C. Erickson and R. Jabhekar, Emissions of Sulfur Trioxide from Coal-Fired Power Plants, Journal of the Air & Waste Management Association, v. 54, 2004 pp. 750-762. Also published in the Power-Gen International 2002 Proceedings, December 10-12, 2002; Richard C. Staehle, et al., The Past, Present and Future of Wet Electrostatic Precipitators in Power Plant Applications, Mega Symposium, May 19-22, 2003; AEP, Feasibility of Alternative SO3 Plume Mitigation Strategies, General James M. Gavin, June 1, 2002; Carl V. Weilert, Burns & McDonnel, Wet ESP vs. Sorbent Injection for SO3 Control, Mega Symposium, August 30-September 2, 2004; Katherine Dombrowski, Gary Blythe, and Richard Rhudy, SO3 Mitigation Guide and Cost Estimating Workbook, Mega Symposium, August 30-September 2, 2004. 54 Knauf, 8 E.A.D. at 134. 55 Richard C. Staehle, et al., The Past, Present and Future of Wet Electrostatic Precipitators in Power Plant Applications, Combined Power Plant Air Pollutant Control Mega Symposium, May 19-22, 2003.

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Carbon Monoxide(CO) and Volatile Organic Compounds (VOCs) The Draft Permit sets limits for CO and VOC as 0.15 lb/MMBtu (30-day average) and 0.0036 lb/MMBtu (annual average), respectively. In each instance the means of achieving these limits is good combustion practices. One of the arguments stated for not having lower CO emissions is the so-called “…balancing needed between NOx and CO in low NOx burners…”56 This is a baseless and spurious argument. NOx is not only controlled by the low-NOx burners but by the SCR. Thus, even if there was some increase in NOx at the burners in order to achieve lower CO levels, the additional NOx can be reduced at the SCR, not affecting final stack NOx levels. Of course, modern low NOx burners do not create additional NOx while minimizing CO. NRG and TCEQ should quantify this so-called balancing between NOx and CO, if they want to advance the argument. The BACT analysis for CO and VOC does not address any of the potential pollution control methods for CO control at Limestone Unit 3. Controls such as oxidation catalysts, thermal oxidizers, and catalytic oxidizers are not discussed. Thermal oxidation is an available pollution control technology. At least one Portland cement kiln, in Midlothian, Texas, uses thermal oxidation to control CO emissions. Thermal oxidation is widely used in ethanol plants, refineries, and other sources to control VOC and CO emissions. Therefore, thermal oxidation is an available control technology that must be considered in a top-down BACT analysis. Even if good combustion practices is used, 0.15 lb/MMBtu does not represent BACT. A number of plants have permitted CO BACT limits lower than the proposed 0.15 lb/MMBtu limit. See Table below. For example, the proposed permit issued by U.S. EPA for the Desert Rock facility contains a CO limit of 0.10 lb/MMBtu, averaged over 24 hours. Thus, the BACT for CO must be set a lower level than the proposed limit of 0.15 lb/MMBtu.

56 See Section VI of the Preliminary Determination Summary.

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Similar to the CO limit, even if the VOC BACT limit for Limestone Unit 3 is established based on combustion controls alone, the limit must be lower than the 0.0036 lb/MMBtu limit proposed in the draft permit. A number of previously issued permit contain lower limit. These include Bull Mountain, MT (0.0030 lb/MMBtu) and Springerville, AZ (0.0033 lb/MMBtu). Additionally, the draft permit issued by U.S. EPA for the Desert Rock facility in Arizona includes a limit of 0.0030 lb/MMBtu averaged over 24 hours. Thus the proposed limit is not BACT.

Mercury BACT for mercury must be specifically designed to control mercury emissions. Rather than requiring controls aimed at mercury, however, the Draft Permit relies on co-benefits of technologies designed to remove other pollutants. NRG and TCEQ must perform a case-specific BACT analysis including an analysis of mercury-specific controls. All indications are that a proper BACT analysis for mercury will show that tighter mercury limits should be required for Limestone 3.

Activated Carbon Injection

Activated carbon and other types of sorbents as well as carbon injection systems are readily available for long-term use at Limestone 3. Sorbent injection is an available and effective mercury control technology that could be utilized at the proposed new unit. Sorbent injection involves the introduction of a compound into the flue gas stream that adsorbs mercury and facilitates its capture by a downstream particulate control device (such as a fabric filter). The sorbent most commonly applied for mercury removal is activated carbon.

Activated carbon injection is currently available as a mercury control technology. In a submittal to the EPA during its public comment process for its proposed NSPS mercury standards, the Institute of Clean Air Companies (ICAC), an industry group of air pollution control technology manufacturers, stated:

Activated carbon injection is commercially available and has been demonstrated on at least four full-sized coal-fired plants to-date with additional full-sized tests scheduled later this year (see details below). Outside of the United States, the Berrenrath 275 MW and the Wachtberg 166 MW plants in Germany operate on carbon injection technology to control mercury.

Letter to Michael Leavitt, EPA Administrator from David C. Foerter, ICAC, June 29, 2004. OAR-2002-0056 (Attachment 18). In sworn testimony before the United States Congress, ICAC stated:

One technology in particular, activated carbon injection, has been used for at least a decade in the waste to energy industry to achieve mercury reductions of at least 80 to 90 percent. This technology has been

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successfully transferred to the power sector for commercial use. Activated carbon injection provides a relatively low cost solution, with very little capital investment and relatively low operating costs. In addition, control performance can be increased and operating cost decreased, if activated carbon injection is coupled with fabric filter particulate control devices. . . . As we have informed EPA and others, a growing number of companies offer commercially available mercury control technologies for sale to the electric power sector. In fact, there are an increasing number of electric utilities actively procuring these technologies and services. . . .

Senate Democratic Policy Committee, Hearing on EPA Proposal to Regulate Mercury Emissions from Power Plants, Testimony of ICAC, Presented by David C. Foerter, Executive Director, Friday, July 9, 2004 (Attachment 19). In a subsequent letter to EPA in 2005, ICAC stated:

Companies are providing firm price proposals with performance guarantees for every coal and boiler type. Activated carbon injection equipment is currently being sold to utilities. ACI equipment is identical for all coal types including bituminous, subbituminous, lignite and blends. Therefore, ACI equipment can be purchased for all coals.

Letter to Michael Leavitt, EPA Administrator from David C. Foerter, ICAC, January 3, 2005. OAR-2002-0056 (Attachment 20). Further, since EPA promulgated the mercury NSPS in 2004, activated carbon injection systems have been required and/or installed at several new coal-fired power plants. The ICAC’s “Commercial Electric Utilities Mercury Control Technology Bookings” shows that, as of September 18, 2007, there have been 61 contracts for activated carbon injection at electric utility boilers.57 ACI has been required and/or committed to be installed at several existing and new coal-fired power units including, among others, the existing Units 1 and 2 and new Unit 3 at the Comanche power plant in Colorado,58 Units 3 and 4 of the San Juan power plant in New Mexico,59 the new Hardin plant in Montana,60 the proposed new Newmont Nevada Power Plant in Nevada61, and the

57 This is available at www.icac.com. We have also included a copy of this table as Attachment 21 to this letter. 58 See December 3, 2004 Comprehensive Settlement Agreement Before the Public Utilities Commission of the State of Colorado, Attachment A: Settlement Agreement between Public Service Company of Colorado and Concerned Environmental and Community Parties, at 6. 59 See Consent Decree in The Grand Canyon Trust and Sierra Club, Plaintiffs, The State of New Mexico, Plaintiff-Intervenor, v. Public Service Company of New Mexico, Defendant, (CV 02-552 BB/ACT (ACE)), lodged in the United States District Court, District of New Mexico, on March 10, 2005, at 15-16. See also Report SL-008695 entitled “San Juan Generating Station Units 3 and 4 Mercury Reduction Study, prepared for Public Service Company of New Mexico,” May 9, 2006 by Sargent and Lundy (S&L). On page 9, S&L refer to sorbent-based mercury reduction technologies as the best "commercially available" technologies to reduce mercury. 60 See Hardin Generating Station Settlement Agreement, April 2005, between Rocky Mountain Power Inc., the Montana Environmental Information Center, William J. Eggers III, Margaret Eggers, Tracy Small, and the Montana Department of Environmental Quality; See also http://www.billingsgazette.com/newdex.php?display=rednews/2005/05/04/build/state/40-plant.inc.

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Highwood Generating Station in Montana62. Further, ACI systems have been installed and are operating at Unit 4 of the Council Bluffs power plant in Iowa and the Hardin Generating Station in Montana. The use of sorbent injection technology at these facilities indicates that other states have determined that sorbent injection is capable of proven mercury removal.

NORIT Americas, Inc., which is the largest producer of powdered activated carbons worldwide63, announced in June 2007 that it had contracted to supply 12 activated carbon injection systems for mercury control at coal-fired power plants in Illinois and that the systems would be delivered in 2008.64 Clearly if ACI was not available, NORIT could not provide 12 ACI systems in a year’s time. Sorbent Technologies Corporation provided a similar delivery time for an ACI system,65 as did ADA-ES, Inc.66 ADA-ES, Inc., has also announced plans to obtain air quality permits to construct activated carbon production plants in Louisiana and North Dakota.67

A BACT determination for mercury must also consider the use of lower-mercury coal, coal cleaning, and alternative combustion methods, such as IGCC. Lower mercury-content fuel and a different coal combustion technique can dramatically reduce mercury emissions, and, if used in combination with the controls described above, can achieve even greater mercury reductions. Additionally, EPA notes that “[a]n existing IGCC unit has demonstrated a process, using sulfur-impregnated AC carbon beds, which has proven to yield 90 to 95 percent Hg removal from the coal syngas.” 69 Fed. Reg. at 4676. This corresponds to a similar finding presented by ChevronTexaco, that an IGCC facility could achieve greater than 90% mercury control by a method that is less expensive and more reliable than removal processes available for pulverized coal units.

Additionally, coal cleaning can remove mercury prior to combustion. A study by the Commonwealth of Massachusetts indicates that advanced and commercially available coal cleaning technologies, such as Microcel and Ken-Flote, can remove 40 to 82 percent of mercury. Commonwealth of Massachusetts, Evaluation of Technological and Economic Feasibility of Controlling and Eliminating Mercury Emissions From the Combustion of Solid Fossil Fuel, at 19 (December 2002). From the record, it appears that coal cleaning was not considered as a basis for mercury BACT.

61 See May 5, 2005 Class I Air Quality Operating Permit to Construct issued by the Nevada Bureau of Air Pollution Control to Newmont Nevada Energy Investment, LLC, No. AP4911-1349, Section V.A.1.a.(4) at V-1. 62 See May 30, 2007 Montana Air Quality Permit issued to Highwood Generating Station, Permit No. 3423-00, Sections I.C. and II.C.14.b. 63 According to their website at http://www.norit-americas.com/6.0.cfm?id=28. 64See http://www.norit-americas.com/6.0.cfm?id=28. 65 See “Sorbent Technologies Receives Order for Two More Mercury Control Systems,” October 16, 2007, at http://www.sorbenttechnologies.com/. 66 See “ADA-ES Awarded a Contract for a Mercury Control System at a New Power Plant,” October 9, 2007, at http://www.adaes.com/. 67 See “ADA-ES Files Air Permit Application for New Activated Carbon Manufacturing Facility in Louisiana,” August 2, 2007, at http://www.adaes.com/.

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NRG’s two-page mercury BACT analysis simply notes that the NSPS limit is the BACT limit since the former was established based on the same air pollution equipment configuration as what is proposed for Limestone Unit 3, namely fabric filter followed by WFGD. There is no technical discussion of the roles that the various emission control techniques (i.e., SCR or WFGD or additional potential controls such as sorbent injection) will play in removing or transforming mercury. In fact sorbent injection to achieve lower mercury emissions is not discussed as a BACT option for this Unit. NRG and its consultants must be aware that there is a fair amount of active testing and validation work that is in progress by mercury control vendors, the Dept. of Energy, and EPA that pertain directly to the issue of mercury emissions reduction from sub-bituminous (and other) coal-fired units. In a paper presented in 2005,68 Durham discusses the research underway in the 2004-2005 timeframe, prior to preparation of the permit application. The paper describes tests involving “…full-scale evaluations to determine the capabilities of activated carbon injection, coal blending, and coal additives for mercury control on different coals and air pollution equipment configurations. This paper will present results from four sites: Sunflower Electric’s Holcomb Station, AmerenUE’s Meramec Station, Basin Electric Power Cooperative’s Laramie River Station, and DTE Energy’s Monroe Power Plant.” These plants were chosen in order to determine the effect of mercury reduction by various combinations of air pollution control equipment. NRG should be required to evaluate the mercury removal efficacies of various air-pollution control equipment combination including wet FGDs and wet ESPs. Only at the conclusion of such an analysis is a choice of BACT appropriate. NRG’s current proposed BACT should therefore be set aside. II. TCEQ Must Address Carbon Dioxide Emissions in the Limestone 3 Permit It is clear with every passing day that the climate change impacts due to the emissions of greenhouse gases is real and likely irreversible.69 In fact, NRG seems to be well aware of the impact of greenhouse gas emissions on the climate.70 Based on this, good public policy and public disclosure are two of the many reasons for quantifying emissions of the

68 Michael D. Durham, Mercury Control for PRB and PRB/Bituminous Blends. 69 See the recently released AR4 Synthesis Report by the Intergovernmental Panel on Climate Change (IPCC) available at http://www.ipcc.ch/. November 2007.

70 See Press Release dated June 18, 2007 announcing that NRG joins the United States Climate Action Partnership (USCAP), an alliance of major businesses and leading climate and environmental groups calling for federal legislation requiring significant reductions of greenhouse gas emissions. In the press release, Mr. David Crane, President and CEO of NRG Energy, Inc., is quoted as stating that "The time is now for decisive action to address climate change and decisive action requires clear and unequivocal leadership." http://www.snl.com/irweblinkx/file.aspx?IID=4057436&FID=4335202

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various greenhouse gases71 from NRG’s proposed limestone project. However, the application does not contain any such analysis. Considering just CO2, using the AP-42 factor of 4810 lb/ton of coal for sub-bituminous coal,72 and using the coal usage rate of 493.8 tons/hr in each new proposed unit,73 CO2 emissions from the proposed new Unit 3 will be 2,375,178 lb/hour and 10,403,280 tons/year. That’s more than half a billion tons of carbon dioxide over the next 50 years! The Clean Air Act prohibits the construction of a new major stationary source of air pollutants in areas designated as in attainment of the National Ambient Air Quality Standards (NAAQS) except in accordance with a prevention of significant deterioration (PSD) construction permit. 42 U.S.C. § 7475(a); 40 C.F.R. § 52.21(a)(2)(iii). Section 165 of the Act requires that a PSD permit include a BACT emission limit “for each pollutant subject to regulation under this chapter emitted from, or which results from” the facility. 42 U.S.C. § 7475(a)(4).

On April 2, 2007, the Supreme Court held that carbon dioxide (CO2) and other greenhouse gases are “pollutants” within the definition of the Clean Air Act. Massachusetts v. EPA, 127 S.Ct. 1438, 1460. Accordingly, the Court held that EPA has authority to regulate emissions of greenhouse gases (including CO2) under the Act and, in fact, must regulate greenhouse gas emissions if they endanger public health, welfare or the environment—which they undeniably do, as discussed in more detail in Subsection A. Because carbon dioxide is a “pollutant subject to regulation”, TCEQ must conduct a BACT analysis and include an emissions limit for CO2 in the Limestone Unit III permit.

Global Warming is a Threat to Public Health, Welfare, and the Environment. The Intergovernmental Panel on Climate Change (“IPCC”) was established by the World Meteorological Organization (“WMO”) and the United Nations Environment Programme (“UNEP”) in 1988. The IPCC’s mission is to comprehensively and objectively assess the scientific, technical and socio-economic information relevant to human-induced climate change, its potential impacts, and options for adaptation and mitigation. See http://www.ipcc.ch/about/about.htm. The IPCC completed its First Assessment Report in 1990, its Second Assessment Report in 1995, and its Third Assessment Report in 2001. Id. The IPCC is currently finalizing its Fourth Assessment Report, “Climate Change 2007.” Id. In advance of public release of the finalized Fourth Assessment Report, the IPCC has recently released summaries of its three working groups that are contributing to the Fourth Assessment Report.

The summaries include the following significant conclusions:

71 Several known greenhouse gases including carbon dioxide (CO2), methane (CH4), and nitrous oxide (N2O) will be emitted from the proposed Units and ancillary sources. Methods for quantifying these gases are readily available in EPA documents such as AP-42, Section 1.1, Tables 1.1-19 and 1.1-20. 72 AP-42, Table 1.1-20 73 See Table 1 (revised 6/6/07) – Estimated Emissions from Combustion of Solid Fuel.

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• By mid-century, annual average river runoff and water availability are

projected to decrease by 10-30% over some dry regions at mid-latitudes and in the dry tropics, some of which are presently water stressed areas;

• In the course of the century, water supplies stored in glaciers and snow

cover are projected to decline, reducing water availability in regions supplied by meltwater from major mountain ranges, where more than one-sixth of the world population currently lives;

• Warming in the mountains of western North America is projected to

cause decreased snowpack, more winter flooding, and reduced summer flows, exacerbating competition for over-allocated water resources;

• Disturbances from pests, disease and fire are projected to have increasing

impacts on North American forests, with an extended period of high fire risk and large increases in area burned;

• In North America, major challenges are projected for crops that are near

the warm end of their suitable range or depend on highly utilized water resources;

• Approximately 20-30% of plant and animal species assessed so far are

likely to be at increased risk of extinction if increases in global average temperatures exceed 1.5-2.5 Degrees Celsius;

• Even the most stringent mitigation efforts cannot avoid further impacts of

climate change in the next few decades, which make adaptation essential, particularly in addressing near-term impacts. Unmitigated climate would, in the long term, be likely to exceed the capacity of natural, managed and human systems to adapt.

• Global greenhouse gas (GHG) emissions have grown since pre-industrial

times, with an increase of 70% between 1970 and 2004;

• The largest growth in global GHG emissions between 1970 and 2004 has come from the energy supply sector (an increase of 145%);

• Fuel switching from coal to gas, renewable heat and power (hydropower,

solar, wind, geothermal and bioenergy), and early applications of carbon capture and storage (e.g. storage of removed carbon dioxide from natural gas) are key mitigation technologies and practices currently commercially available.

The reports authoritatively document the adverse environmental and socio-economic impacts of global warming at local, regional, national and global scales, and the primary

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role of the burning of fossil fuels, including coal, in causing global warming. The evidence in the IPCC reports conclusively shows that greenhouse gases, including CO2, endanger public health, welfare, and the environment. According to Massachusetts v. EPA, that means the EPA and States must regulate greenhouse gas emissions under the CAA.

Many researchers have highlighted the severity of the threats posed by global warming. A recent study found that from 2000 to 2006, the average emissions growth rate was 3.3% per year, compared to 1.3% per year during the 1990s.74

The study estimates that global warming is happening faster than expected, and attributes this to recent growth in the world economy, increasing carbon intensity, and decreasing efficiency in carbon sinks on land and in oceans.75

This evidence suggests that even the estimates of the IPCC are too conservative, and that the threat of global warming may be even more imminent than originally anticipated. The World Health Organization reported in 2005 that, over the past 30 years, global warming has contributed to 150,000 deaths annually.76

EPA has already recognized this and other potentially adverse effects of climate change on public health:

Throughout the world, the prevalence of some diseases and other threats to human health depend largely on local climate. Extreme temperatures can directly lead to loss of life, while climate-related disturbances in ecological systems, such as changes in the range of infective parasites, can indirectly impact the incidence of serious infectious diseases. In addition, warm temperatures can increase air and water pollution, which in turn harm human health.77

One threat identified by EPA is fatalities due to extreme temperatures. Indeed, increased heat waves lead to heart failure and other heat-related deaths. Global warming makes it more difficult to achieve the NAAQS for ground-level ozone, intensifying the public health dangers associated with air quality violations. Breathing ozone can trigger a variety of health problems, including chest pain, coughing, throat irritation, and congestion, and repeated exposure can lead to bronchitis, emphysema, asthma, and permanent scarring of lung tissue.78

In addition, global warming will result

74 Canadell, J.G., C.L. Quere, M.R. Raupach, C.B. Field, E.T. Buitehuis, P. Ciais, T.J. Conway, N.P. Gillett, R.A. Houghton, and G. Marland, Contributions to accelerating atmospheric CO2 growth from economic activity, carbon intensity, and efficiency of natural sinks, Proc. Natl. Acad. Sci. USA, doi 10.1073, 2007. 75 Id. 76 Patz, “Impact of Regional Climate Change on Human Health,” Nature, 438, 310-317, available at http://www.nature.com/nature/journal/v438/n7066/full/nature04188.html. 77 EPA, Climate Change, Health and Environmental Effects, available at http://www.epa.gov/climatechange/effects/index.html. See also Ex. 276, CDC, “Policy on Climate Change and Public Health,” available online at http://www.cdc.gov/nceh/climatechange/. 78 EPA, Ground-Level Ozone: Health and Environment (2007), available at http://www.epa.gov/air/ozonepollution/health.html.

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in increased surface water evaporation, which in turn could lead to more wildfires and increased dust from dry soil, both of which generate particulate matter emissions. Particulate matter triggers a host of health problems, including aggravated asthma, development of chronic bronchitis, irregular heartbeat, nonfatal heart attacks, and premature death in people with heart or lung disease.79 Carbon Dioxide is a Pollutant Subject to Regulation under the Texas and Federal Clean Air Acts. Even prior to Massachusetts v. EPA, CO2 was a pollutant subject to regulation under the Clean Air Act. Section 821(a) of the 1990 Clean Air Act Amendments (Pub. L. 101-549; 104 Stat. 2699; now codified in a note to 42 U.S.C. § 7651k, emphasis added) provides:

Monitoring. – The Administrator of the Environmental Protection Agency shall promulgate regulations within 18 months after the enactment of the Clean Air Act Amendments of 1990 to require that all affected sources subject to the Title V of the Clean Air Act shall also monitor carbon dioxide emissions according to the same timetable as in Sections 511(b) and (c). The regulations shall require that such data shall be reported to the Administrator. The provisions of Section 511(e) of Title V of the Clean Air Act shall apply for purposes of this section in the same manner and to the same extent as such provision applies to the monitoring and data referred to in Section 511.80

The language is clear: In the 1990 CAA Amendments, Congress ordered EPA “to promulgate regulations” requiring that hundreds of facilities covered by Title IV monitor and report their CO2 emissions. EPA promulgated regulations in response, finalized on January 11, 1993, requiring CO2 emissions monitoring. See, e.g., 40 C.F.R. §§ 75.1, 75.13, 75.57(e). While Section 821 of the Clean Air Act Amendments of 1990 and implementing regulatory requirements plainly qualify CO2 as a pollutant subject to regulation under the Act, greenhouse gases such as CO2 and methane are also regulated as a component of landfill gases. EPA has promulgated emission guidelines and standards of performance for “municipal solid waste landfill emissions.” 40 CFR §§ 60.33c, 60.752. Landfill emissions are defined as “gas generated by the decomposition of organic waste deposited in an MSW landfill or derived from the evolution of organic compounds in the waste.” 40 CFR § 60.751. The pollutants regulated by these standards, “MSW landfill emissions, or LFG, is composed of methane, CO2, and NMOC.” Air Emissions from Municipal Solid Waste Landfills – Background Information for Final Standards and Guidelines, EPA-453/R-94-021, December 1995, available at

79 EPA, Particulate Matter: Health and Environment (2007), available at http://www.epa.gov/air/particlepollution/health.html. 80 According to the Reporter’s notes, these references to Title V are meant to refer to Title IV, and the references to Section 511 are meant to refer to Section 412.

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http://www.epa.gov/ttn/atw/landfill/landflpg.html. Thus, CO2 is regulated through the landfill emission regulations at 40 C.F.R. Part 60 Subparts Cc, WWW. See also 56 Fed. Reg. 24468 (May 30, 1991) (“Today's notice designates air emissions from MSW landfills, hereafter referred to as "MSW landfill emissions," as the air pollutant to be controlled”). In Section 165, Congress required a BACT limit for “any pollutant subject to regulation” under the Act. The only consistent reading of this statutory mandate, with reference to Section 821 and the landfill regulations, is that Congress intended for EPA to apply BACT limits to CO2 pursuant to Section165. Even if CO2 is not currently regulated under the CAA, TCEQ must impose carbon dioxide limits because CO2 is a “pollutant subject to regulation.” Moreover, emissions of a pollutant need not be limited by existing emissions regulations for the pollutant to be “subject to” regulation under the Clean Air Act. “Subject to regulation” means “capable of being regulated” and is not limited to pollutants that are “currently regulated.” The plain meaning of Section 165(a)(4) of the Clean Air Act’s mandate that BACT applies to “each pollutant subject to regulation under [the Clean Air Act]” extends not only to air pollutants for which the Act itself or EPA or the States by regulation have imposed requirements, but also to air pollutants for which EPA and the States possess but have not exercised authority to impose such requirements.

EPA has recognized the general principle that “[t]echnically, a pollutant is considered regulated once it is subject to regulation under the Act. A pollutant need not be specifically regulated by a section 111 or 112 standard to be considered regulated. (See 61 FR 38250, 38309, July 23, 1996.)” See 66 Fed. Reg. 59161, 59163, 40 CFR Part 70, Change to Definition of Major Source (Nov. 27, 2001) (emphasis added).

If any doubt remains that carbon dioxide is subject to regulation under the Clean Air Act following Massachusetts v. EPA, 127 S. Ct. at 1459-63, the President’s May 14, 2007, Executive Order laid that to rest.81

The Executive Order reconfirms that EPA can regulate greenhouse gases, including carbon dioxide, from motor vehicles, nonroad vehicles and nonroad engines under the Clean Air Act. It then directs EPA to coordinate with other federal agencies in undertaking precisely such regulatory action. The President’s action indicates clearly that even the Chief Executive is of the opinion that carbon dioxide is a “pollutant” and must be further regulated under the Clean Air Act. The language in the Texas regulations mirrors the language of the federal CAA regulations and requires a BACT limit for all pollutants “subject to regulation.” CO2 is a pollutant subject to regulation under the State and Federal CAA, thus TCEQ must impose a BACT limit in the Limestone Unit III permit.

TCEQ has the Duty and Authority to Protect Public Health by Regulating Carbon Dioxide in the Limestone Unit 3 Permit. 81 The Executive Order is available at www.whitehouse.gov/news/releases/200705/200705142.html.

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The Texas Clean Air Act makes it clear that CO2 produced by human industrial activities is an “air contaminant” and that any such air contaminant can constitute “air pollution” if the contaminant exists in a concentration and duration that “may tend to be injurious to or to adversely affect human health or welfare, animal life, vegetation, or property ….” Texas Health and Safety Code § 382.003(2) and (3)

Other provisions of the Texas CAA also direct the agency to consider public health and the protection of natural resources in its air permitting decisions. Furthermore, the Texas Legislature has provided explicit power to TCEQ to regulate global warming gases, including carbon dioxide. Section 382.0205 provides rulemaking powers to the TCEQ to deal with “special problems” for “air contaminants as necessary to protect against adverse effects related to … climatic changes, including global warming.” The statutes and TCEQ rules make it clear that CO2 is an “air contaminant” under Texas law. It is also an “emission” under the ordinary meaning of that term, and, given the current state of scientific knowledge about the effects of CO2 concentrations in the atmosphere, a pollutant that TCEQ has a duty to regulate in protection of public health.

Best Available Control Technologies are readily available for TCEQ to impose carbon dioxide emissions limits for Limestone Unit III. There are at least four readily available options for limiting a facility’s carbon dioxide emissions that could and should be considered in TCEQ’s top-down BACT analysis for Limestone Unit III. These options include: 1) setting output-based standards,82 2) using clean fuels, e.g. biomass and natural gas,83 3) requiring combined heat and power,84 and 4) mandating carbon capture and sequestration.

EPA recently pointed to available methods, systems and techniques to control carbon dioxide and other greenhouse gases. In its June 22, 2007 letter on the White Pine Energy Station Project, EPA directed the BLM to “discuss carbon capture and sequestration and other means of capturing and storing carbon dioxide as a component of the proposed

82 In the 1995 preamble to the draft New Source Performance Standards for Electric Steam Generating Units, the EPA explained that it was proposing to adopt output-based standards as a simple measure to promote efficient generation and reduce fuel use: “By relating emission limitations to the productive output of the process, output-based emission limits encourage energy efficiency because any increase in overall energy efficiency results in a lower emission rate . . . The use of more efficient technologies reduces fossil fuel use and leads to multi-media reductions in environmental impacts both on-site and off-site. 70 Fed. Reg. 9706, 9713 (Feb. 28, 2005). 83 Consistent with the statutory definition of BACT and the long-standing practice of the agency, a top-down BACT determination must include consideration of “clean fuels.” See http://www1.eere.energy.gov/biomass/electrical_power.html (last visited October 24, 2005) For a power plant this may include the use of natural gas, landfill gas, biomass, fuel oil, or a combination of any of these with coal, as various methods to reduce carbon dioxide emissions. 84 EPA has an entire website dedicated to promoting the benefits of combined heat and power because, as EPA explains, “[combined heat and power] reduces the emission of greenhouse gases, which contribute to global climate change.” http://www.epa.gov/chp (last visited on October 24, 2005).

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alternatives.”85 These comments represented EPA’s findings on the draft EIS for the White Pine project and were made public. Thus, EPA has previously determined that CCS is an available technology that should be considered, together with other means, for the control of carbon dioxide emissions.

The plain language of the CAA, EPA’s regulations, the Supreme Court’s decision in Massachusetts v. EPA, and a recent executive order make clear that CO2 is a pollutant “subject to regulation” under the CAA. As such, TCEQ must perform a top-down BACT analysis and set a CO2 emission limitation in the permit. The federal Clean Air Act, like the Texas Clean Air Act, defines “welfare” broadly:

All language referring to effects on welfare includes, but is not limited to, effects on soils, water, crops, vegetation, manmade materials, animals, wildlife, weather, visibility, and climate, damage to and deterioration of property, and hazards to transportation, as well as effects on economic values and on personal comfort and well-being, whether caused by transformation, conversion, or combination with other air pollutants.

42 U.S.C. § 7602(h). Of note, “public welfare” includes effects on both “weather” and “climate.” As demonstrated above, the IPCC’s Fourth Assessment Report documents the multiple threats to public welfare attributable to global warming. Negative impacts include air and ocean temperature increases, widespread melting of snow and ice, changes in precipitation amounts and wind patterns, and more frequent extreme weather events such as hurricanes, heat waves, floods, and droughts. Both federal and state clean air laws require the permitting authority to protect property from the adverse effects of air pollution. As global warming increases, the risks associated with catastrophic natural disasters, such as hurricanes, tornados, and tsunamis, also increase.86 One study predicts an 8% to 16% average increase in intensity of hurricanes, a threat that is well known to Texans.87

Another study predicts similar results for tornadoes and thunderstorms, with the most severe storms occurring more often.88

Increased frequency and/or severity of such storms endangers property, as well as public health.

85 See Letter from EPA Region IX to Jeffrey A Weeks, Bureau of Land Management (June 22, 2007). 86 See, e.g., Emanuel, K., Increasing destructiveness of tropical cyclones over the past 30 years, Nature, online publication; published online 31 July 2005 | doi: 10.1038/nature03906 (2005); Ex. 133, Knutson, T. K., and R. E. Tuleya, 2004: Impact of CO2-induced warming on simulated hurricane intensity and precipitation: Sensitivity to the choice of climate model and convective parameterization. Journal of Climate, 17(18), 3477-3495. 87 Knutson, T. K., and R. E. Tuleya, 2004: Impact of CO2-induced warming on simulated hurricane intensity and precipitation: Sensitivity to the choice of climate model and convective parameterization. Journal of Climate, 17(18), 3477-3495. 88 Del Genio, Yao, and Jonas, Geophysical Research Letters, v.34, L16703, doi: 10.1029/2007GL030525, 2007

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Based upon Massachusetts v. EPA and the known impacts of global warming, the Secretary of the Kansas Department of Health and Environment recently denied a permit to Sunflower Electric Power Corporation for two proposed 700 MW coal-fired boilers in western Kansas. Citing his duties to protect the public health and environment, the Secretary denied the permit on the basis that “[E]missions from the coal-fired power plant, specifically carbon dioxide emissions, presents a substantial endangerment to the health of persons or the environment.” See the letter from Roderick L. Bremby, Secretary of KDHE to Wayne Pernod of Sunflower dated October 18, 2007.89

The KDHE Secretary relied upon an opinion by the Kansas Attorney General, which concludes that if the Secretary makes a factual determination that an air pollutant

[P]resents a substantial endangerment to the health of persons or to the environment, then even in the absence of federal or state regulations setting limitations for a particular pollutant, K.S.A. 65-3012(a)(1) authorizes the secretary to take actions as necessary to protect the health of persons or the environment. Such actions may include denying an air quality permit application on the basis of anticipated emissions of a particular pollutant or modifying a proposed permit to address such pollutant.

Kansas Attorney General Opinion 2007-31 (September 24, 2007).90 Likewise, the Texas CAA gives TCEQ the power and the duty to protect its citizens from the threats posed by global warming. The carbon dioxide emitted over the lifetime of Limestone Unit III will significantly exacerbate the consequences of global warming. TCEQ must act, pursuant to its statutory authority to set BACT limits for carbon dioxide in the Limestone Unit III permit or deny the permit.

Alternatively, if TCEQ fails to set a BACT limit for CO2 in the proposed permit, the agency must act to protect the public welfare. One way for TCEQ to fulfill its statutory mandate, short to setting a BACT limit for CO2 or denying the permit would be to require CO2 offsets, thereby mitigating the damage caused by massive uncontrolled CO2 emissions. Such action is authorized under, among other provisions, Clean Air Act Section 165(a)(2).

TCEQ Should Conduct an Alternatives Analysis Under Section 165(a)(2)

Regardless of whether CO2 is currently a pollutant subject to regulation under the federal or state law, TCEQ as the permitting authority may require evaluation of CO2 emissions and establish appropriate permit conditions or otherwise address these emissions. EPA’s Office of Air and Radiation, Office of General Counsel, and the Environmental Appeals

89 See http://www.kdheks.gov/press_room.htm. 90 Available at http://www.kdheks.gov/download/KS_Atty_General_Opinion_10.17.07.pdf.

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Board have expressed the opinion that permitting authorities have broad discretion to consider alternatives, conduct or require analyses, and impose permit conditions to address issues under ACT section 165(a)(2) beyond the required BACT analysis. EPA has recognized that “a PSD permitting authority still has an obligation under section 165(a)(2) to consider and respond to relevant public comments on alternatives to the source,” and that a “PSD permitting authority has discretion under the Clean Air Act to modify the PSD permit based on comments raising alternatives or other appropriate considerations.” BRIEF OF THE EPA OFFICE OF AIR AND RADIATION AND REGION V, In re Prairie State, PSD Appeal 05-05, 12 E.A.D. __ (EAB, Aug. 24, 2006). Moreover, the EAB has made clear that a permitting authority has discretion to modify a permit based on consideration of “alternatives” whether or not the issues are raised by commenters:

Indeed, the permit issuer is not required to wait until an “alternative” is suggested in the public comments before the permit issuer may exercise the discretion to consider the alternative. Instead, the permit issuer may identify an alternative on its own. This interpretation of the authority conferred by CAA section 165(a)(2)’s reference to “alternatives” is consistent with the Agency's longstanding policy that, . . . “this is an aspect of the PSD permitting process in which states have the discretion to engage in a broader analysis if they so desire.”

See In re Prairie State, PSD Appeal 05-05 (Aug. 24, 2006) (quoting the NSR Workshop Manual at B.13).91 In fact, under this authority, a permitting authority can engage in a wide-ranging exploration of options, including fuel switching, and other generation and non-generation alternatives. Under this authority TCEQ clearly has the discretion to require specific evaluation and control of CO2 emissions, and/or to require other action to mitigate potential global warming impacts. Failure to do so in this case is a material breach of the agency’s obligations to the people of Texas and the United States. To date, there has been no specific assessment of available measures, alternatives, or options to address greenhouse gas emissions at the proposed Limestone Unit 3. TCEQ could require any number of possible actions to address the CO2 footprint of the proposed new unit. Options include requiring specific energy efficiency, conservation or demand-side-management activities to reduce energy consumption, requiring development of renewable energy sources, requiring a change to a less CO2-intensive fuel (like natural gas or biomass co-firing), requiring a construction of a smaller source, imposing limits on hours of operation, requiring the capture and sequestration of CO2, requiring construction of a more efficient facility, requiring the purchase of CO2 offsets, or some combination of these approaches or others. Additionally, TCEQ may also consider a no-build option under § 165(a)(2) of the Act, which gives TCEQ the authority to deny a PSD permit based on policy considerations related to CO2. The consideration of such options should be subject to a process of public discussion. Therefore, TCEQ should conduct an 91 One version of the NSR Workshop Manual is available at: http://www.epa.gov/Region7/programs/artd/air/nsr/nsrmemos/1990wman.pdf.

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alternatives analysis and make that analysis available to the public for comment and input. III. NRG’s Modeling and Impacts Analyses are Flawed Numerous deficiencies exist in NRG’s and TCEQ’s Impacts Analyses, including a complete lack of ambient monitoring and flawed modeling. It is clear that NRG cherry-picked its way through the impacts analyses to arrive at the results they wanted. The comments below provide numerous, though non-exhaustive, examples of the deficiencies and flaws in NRG’s and TCEQ’s analyses. The Waco, TX Airport Meteorological Data are Unreliable for Class II PSD and NAAQS Compliance Air Dispersion Modeling Both NRG and TCEQ assess compliance with the NAAQS and Class II PSD increments using five years of meteorological data (1985 and 1987 through 1990) from the Waco, Texas Airport. The airport data, collected at a location roughly 60 miles (96 km) from NRG’s proposed Limestone 3 unit is neither site-specific, nor is the quality of the data acceptable for air dispersion modeling. The NRG permit application and TCEQ review, which rely on these data for air modeling, are therefore flawed. For air dispersion modeling purposes, airport data are among the least desirable. Problems with location and the general quality of data are the primary concerns. The USEPA, in their Meteorological Monitoring Guidance for Regulatory Modeling Applications, summarizes these concerns about using airport data:

For practical purposes, because airport data were readily available, most regulatory modeling was initially performed using these data; however, one should be aware that airport data, in general, do not meet this guidance.92

The use of antiquated airport data was initially used for simpler, less-refined models such as MPTER, CRSTER, and COMPLEX-I/II. The NRG Limestone modeling, however, is performed using USEPA’s ISCST3 and ISCST3-Prime (“ISC3P”) models, which require specific parameters to characterize transport and dispersion in a meaningful fashion. The approximately 20-year old data collected at the Waco Airport are simply inadequate to provide ISCST3/ISC3P with the required parameters needed for realistic dispersion calculations. Just because one can run these models with distant airport data does not imply that one should do so. As stated above, the Waco Airport data are not site-specific to the NRG facility. The distance involved (about 60 miles) makes the airport data clearly not site-specific, with numerous land use classifications existing between NRG and the airport. Equally important, however, are the difference in land uses at NRG and the airport, respectively. 92 USEPA, Meteorological Monitoring Guidance for Regulatory Modeling Applications, EPA-454/R-99-05, February 2000, p. 1-1.

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The Waco Airport is comprised of concrete runways, parking lots, passenger terminals, and other structures associated with air travel activities. These surface and building characteristics in turn affect the boundary layer meteorology present at the airport.93 In addition, landings, takeoffs, and idling of airplanes affect the site-specific conditions at the airport such that the meteorological conditions are not representative of the area surrounding the NRG facility. Clearly, the Waco, Texas Airport site is too far from NRG Limestone to be meaningful. ISCST3 and ISC3P are never used to calculate air concentrations at distances of 60 miles from the source – the model dispersion parameters are not meant for that purpose. And neither should airport data from 60 miles (96 kilometers) away be used to drive dispersion parameters for the NRG site. In fact, NRG’s own modeling used ISCST3 out to maximum distances of only about 15 kilometers from the Limestone facility.94 In other words, TCEQ would never allow NRG to use ISCST3 or ISC3P to model Limestone impacts at the Waco Airport. Likewise, TCEQ should never allow NRG to use inappropriate meteorological data from Waco Airport to assess impacts in the vicinity of their Limestone facility. The other major issue is the quality of the meteorological data collected at the Waco Airport. It is important to remember that the airport data are not collected with the thought of air dispersion modeling in mind. For example, airport meteorological parameters are reported once per hour, based on a single observation (usually) taken in the last ten minutes of each hour. The USEPA recommends that sampling rates of 60 to 360 per hour, at a minimum, be used to calculate hourly-averaged meteorological data.95 Air dispersion modeling requires hourly-averaged data, which represents the entire hour being modeled, and not only a snapshot taken in one moment during the hour. In addition, data collected at the Waco Airport are not subject to the system accuracies required for meteorological data collected for air dispersion modeling. The USEPA recommends that meteorological monitoring for dispersion modeling use equipment that are sensitive enough to measure all conditions necessary for verifying compliance with the NAAQS and PSD increments. For example, low wind speeds (down to 1.0 meter per second) are usually associated with peak air quality impacts – this is because modeled impacts are inversely proportional to wind speed. Following USEPA guidance, wind speed measuring devices (anemometers) should have a starting threshold of 0.5 meter per second or less.96 And the wind speed measurements should be accurate to within plus or minus 0.2 meter per second, with a measurement resolution of 0.1 meter per second.97 The Waco Airport data used by NRG, rather than being measured in 0.1 meter per second increments, is based on wind speed observations that are reported in whole knots. This is 93 Oke T.R., Boundary Layer Climates, Halsted Press, 1978, pp. 240-241. 94 Discrete Cartesian receptors modeled, including property boundary, fine medium, and coarse grids. See model input file 103_90_PM10.DTA, for example. 95 USEPA, Meteorological Monitoring Guidance for Regulatory Modeling Applications, EPA-454/R-99-05, February 2000, p. 4-2. 96 Id., p. 5-2. 97 Id., p. 5-1.

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evidenced by examining the meteorological data files used in the PSD Application modeling analysis. Every modeled hourly wind speed is an increment of 0.51479 meter per second (the units required for input to the air dispersion model), which exists because one knot equals 0.51479 meter per second. The once-per-hour observations at the Waco Airport (in whole knots, no fractions or decimals) were converted to meters per second and can therefore be back-converted to the whole knot measurements originally reported by the airport. To further exemplify the problem of using the airport data, the lowest wind speed included in the meteorological data files used in the PSD Application (with zero exceptions) is 1.54 meters per second (three knots). Out of a possible 43,824 hours in the five-year modeling data set, there are zero hours with reported wind speeds equal to 1.0 meters per second (two knots). All wind speeds lower than three knots are reported as calms, and are thus excluded from the PSD and NAAQS modeling analyses. There are 949 such calm hours in the meteorological data files used in the NRG LMS3 Application. Typically, when properly measured with modern anemometers, there are only a few calm hours in a meteorological data base per year.98 In no uncertain terms, the conditions most crucial for verifying compliance with the NAAQS and PSD increments (low wind speeds) are being excluded from the NRG analysis because of the choice to use the distant airport data. Sensitive and accurate measurements of wind speeds are necessary for measuring winds down to 0.5 meter per second (about one knot), which can then be used as 1.0 meter per second in the air dispersion modeling analyses. There would be no need to label such low wind speed hours as calm, which will greatly increase the number of hours included in the modeling analyses. Again, it is these low wind speed hours which must be included in the modeling data set to verify compliance with the NAAQS or PSD increments. The meteorological data used in the NRG NAAQS and PSD modeling includes zero hours out of five years with a wind speed below 1.54 meters per second, and to compound the problem, lists all other wind speeds less than three knots as calms, which are then excluded from the model calculations. Excluding calm winds from the data base is inappropriate and will significantly decrease modeled concentrations. This is very important for verifying compliance with applicable standards and increments, particularly when the applicant-modeled concentrations are already close to the threshold values. This is a serious concern for the NRG Limestone facility emissions, where modeled highest-second-high 24-hour PM10 concentration are already at 26.06 µg/m3. This is over 86% of the allowable Class II PSD increment of 30 µg/m3. Using distant airport meteorological data for modeling huge emitters of air pollutants, such as NRG, must not be allowed. Excluding the calm hours from modeled concentrations reduces the predicted impacts – a benefit to NRG and a detriment to the

98 For example, the pre-construction monitoring data set for the Newmont Nevada proposed coal-fired power plant has five calm hours (10 meter winds) in the one-year period from 9/1/2003 through 8/31/2004.

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surrounding air quality. This is very convenient for the applicant, and helps to explain why major sources of air pollutants still insist on using distant and poor-quality airport meteorological data. To remedy this unacceptable situation, NRG should have collected at least one-year of pre-construction meteorological data consistent with USEPA Meteorological Monitoring Guidance for Regulatory Modeling Applications. The pre-construction meteorological data should include both surface and profile measurements up to the effective stack height of the main boiler. Because of this failure, the current Limestone permit application modeling is unacceptable for NAAQS and PSD increment consumption analyses. Allowing NRG to use distant, low-quality data from Waco, instead of collecting on-site data that meet the EPA minimum requirements, has rendered all of NRG’s modeling analyses unreliable and flawed. Therefore, the entire basis for TCEQ’s permit issuance is equally flawed. Preconstruction Meteorological Monitoring Should Have Been Required TCEQ should have required NRG to collect pre-construction meteorological data for use in their permit modeling. NRG, which is a major emission source of many air pollutants, should not be assessed for NAAQS and PSD increment compliance using non site-specific meteorological data collected with none of the quality assurances necessary for air modeling data.99 Pre-construction meteorological data for projects that trigger PSD review is already being required for coal-fired power plants. Two recent projects in Nevada, Granite Fox Power (near Gerlach) and Newmont Nevada (Boulder Valley), have collected at least one year of pre-construction meteorological data. The data requirements, specific for input to air dispersion modeling for NAAQS and PSD increment analyses, are detailed by the State of Nevada.100 From the State of Nevada Guidelines: “Current on-site meteorological data are required for input to dispersion models used for analyzing the potential impacts from the air pollution sources at the facility.”101 Even smaller air regulatory agencies have been requiring pre-construction meteorological data for many years. As part of their PSD program, the Santa Barbara County (California) Air Pollution Control District requires at least one year of site-specific pre-construction air quality and meteorological monitoring.102 The meteorological monitoring requirements are specified in a detailed protocol that implements their PSD

99 USEPA, Ambient Monitoring Guidelines for Prevention of Significant Deterioration (PSD), EPA-450/4-87-07, May 1987, p. 55. 100 Nevada Bureau of Air Pollution Control, Ambient Air Quality Monitoring Guidelines, May 4, 2000. 101 Id., p. 6. 102 Santa Barbara County Air Pollution Control District, Rule 803, Prevention of Significant Deterioration.

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Rule.103 PSD sources in Santa Barbara County must collect site-specific hourly-averaged values for the following meteorological parameters:

• Horizontal wind speed and wind direction (both arithmetic and resultant) • Horizontal wind direction standard deviation (sigma-theta) • Standard deviation of wind speed normal to resultant wind direction (sigma-v) • Vertical wind speed • Vertical wind speed standard deviation (sigma-w) • Standard deviation of the vertical wind direction (sigma-phi) • Ambient air temperature • Shelter temperature104

The NRG Limestone facility air emissions are enormous and are released in a complex arrangement of point, area, and volume sources. Using an antiquated, low-quality, and non site-specific meteorological data set, for no other reason than to expedite the permitting process for the applicant, invalidates the entire air quality impact analysis. The permit application should be denied because of this poor modeling practice, and not resumed until NRG has collected at least one year of site-specific meteorological data consistent with USEPA’s Meteorological Monitoring Guidance for Regulatory Modeling Applications. Preconstruction Air Quality Monitoring Should Have Been Required TCEQ modeled PM10 and SO2 emissions from the proposed LMS3 facility to determine whether air concentrations exceed the PSD monitoring significance levels set forth in 40 CFR 52.21.105 TCEQ modeled highest 3-hour and 24-hour SO2 impacts from only the proposed LMS3 operations using the USEPA ISCST3 model; they modeled 24-hour PM10 impacts from only the proposed LMS3 operations using both the USEPA ISCST3 and ISC3P models. TCEQ’s own modeling showed that the maximum modeled concentrations exceed the monitoring thresholds for both PM10 and SO2. It is important to note the TCEQ’s modeling does not include any of the operational emissions from the existing LMS1 and LMS2 boilers, and associated equipment, haul roads, and other emission-creating activities. Instead of requiring pre-construction monitoring for PM10 and SO2, TCEQ determined that background concentrations from Travis County (130-plus miles distant) would be appropriate for conditions in Limestone County. This faulty determination was made even though there are no monitors whatsoever in Limestone County.106 Furthermore, NRG Limestone Units 1 and 2 currently emit thousands of tons per year of both PM10 and 103 Santa Barbara County Air Pollution Control District, Air Quality and Meteorological Monitoring Protocol for Santa Barbara County, October 1990. 104 Id., p. 57. 105 TCEQ, Preliminary Determination Summary, Permit Numbers 79188 and PSD-TX-1072, p.7. 106 Id.

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SO2 , and proposes to add another 2,102.3 tons per year of SO2 and 1,311.3 tons per year of PM10. Clearly, NRG’s existing Limestone facility is a hot spot of both PM10 and SO2 emissions. TCEQ is already delinquent in not requiring ambient air monitoring for current conditions near the Limestone facility, and is making matters worse by ignoring the PSD air monitoring requirement for NRG’s proposed incremental emissions. By not requiring monitoring of existing PM10 and SO2 air concentrations surrounding NRG Limestone, TCEQ has failed to verify whether NRG’s proposed LMS3 emissions will create, or exacerbate, potential NAAQS and PSD increment violations. In other words, given the magnitude of the existing NRG Limestone emissions, current air quality impacts near the facility may already exceed the NAAQS or are consuming the entire allowable PSD increment. It is disconcerting that TCEQ is reluctant to verify this rather simple, yet essential part of their permitting process. TCEQ Failed to Identify 24-Hour PM10 Class II PSD Increment Violations TCEQ modeled NRG’s Limestone facility PM10 emissions, predicting a highest-second-high (“HSH”) 24-hour PM10 concentration of 26.06 µg/m3. This is over 86% of the allowable Class II PSD increment of 30 µg/m3. TCEQ, however, made numerous errors and inappropriate assumptions in their PSD increment analysis. When corrected, NRG’s HSH 24-hour PM10 concentrations will exceed the Class II PSD increment of 30 µg/m3. This significant impact invalidates TCEQ’s preliminary decision. TCEQ Failed to Use Reliable Meteorological Data As discussed elsewhere in our comments, TCEQ used distant and unreliable meteorological data to assess NRG’s 24-hour PM10 Class II PSD increment consumption. TCEQ used a meteorological data location (Waco Airport) that was never intended for air dispersion modeling – one which excludes all wind speeds less that three knots (1.54 meters per second). By never modeling NRG’s 24-hour PM10 emissions with these critical low wind speed conditions, TCEQ has failed to verify compliance with the applicable Class II PSD increments. TCEQ Failed to Model Peak Impact Receptors In their PSD increment modeling analysis, TCEQ predicted a HSH 24-hour PM10 concentration of 26.06 µg/m3. This HSH concentration occurred at a receptor with UTM Coordinates 761419 (Easting) and 3480477 (Northing). This impact was modeled using existing and proposed PM10 emissions from NRG’s Limestone plant, as well as offsite PSD increment-consuming sources in the project vicinity.107 As an evaluation exercise, we removed the offsite PSD increment-consuming emission sources and remodeled TCEQ’s analysis with onsite Limestone emissions only. We found that the majority of the HSH 24-hour PM10 concentration (24.39 µg/m3) was caused by NRG’s emissions alone. 107 See ISCST3 input file 301_90_PM102H.DTA.

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TCEQ, however, did not include a complete array of receptors in their 24-hour PM10 PSD increment modeling analysis. TCEQ modeled 1,140 receptors, including some of the property boundary to the north of the project boilers. TCEQ failed to model the entire property boundary, however. In essence, TCEQ neglected to assess 24-hour PM10 concentrations at all ambient air locations surrounding the NRG plant. We again remodeled TCEQ’s 24-hour PM10 PSD increment modeling analysis, but this time we included all of the property boundary receptors that were generated by TCEQ. It is important to note that TCEQ did model the entire property boundary receptor array in some of their other compliance verification modeling, but for some reason chose to not do so for their 24-hour PM10 PSD increment modeling analysis. This was a serious mistake – one that invalidates their conclusion of NRG’s compliance with the 24-hour PM10 Class II PSD increment. By including all of NRG’s property boundary receptors, we found a HSH 24-hour PM10 concentration of 33.11 µg/m3. This HSH concentration occurred at a receptor with UTM Coordinates 761995 (Easting) and 3479464 (Northing). This concentration, which exceeds the 24-hour PM10 Class II PSD increment, was modeled using TCEQ’s own modeling inputs with the exception of including all of NRG’s property boundary receptors. We then remodeled this analysis using only onsite emissions from NRG’s existing and proposed emissions (e.g., removed all offsite emissions from TCEQ’s modeling file). In this analysis, we found a HSH 24-hour PM10 concentration of 32.75 µg/m3. By simply correcting TCEQ’s own modeling analysis, it is clear that NRG’s emissions will cause violations of the 24-hour PM10 Class II PSD increment. This is true even when excluding all offsite increment-consuming emissions. If TCEQ had modeled all of NRG’s property boundary receptors, they too would have identified this significant impact. TCEQ’s analysis, however, included an even-more serious modeling error – they failed to include all of NRG’s onsite emissions. TCEQ Failed to Include Any of NRG’s Road Dust Fugitive Emissions TCEQ performed two modeling analyses for verifying compliance with NRG’s PM10 Class II PSD increment consumption – for 24-hour and annual averages. In both these analyses, TCEQ used the same dispersion model (ISCST3) and the same meteorological data. In these two analyses, TCEQ used the same onsite and offsite inventory of PM10 increment-consuming sources, with one outstanding exception: TCEQ omitted every one of NRG’s road dust emission sources from their 24-hour modeling analysis. This omission is also true for the 24-hour PM10 NAAQS analyses performed by TCEQ. Onsite haul roads are a significant source of PM10 emissions, which must be included in all of the PSD increment-consumption analyses – there is no basis whatsoever for only

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including them in TCEQ’s annual-average PSD modeling. The importance of haul road emissions on offsite air impacts cannot be overstated. Road emissions are released near the ground and are non-buoyant, resulting in relatively high air impacts. In many coal-fired power plants, road dust emissions cause higher air impacts than the PM10 emissions from the project boilers. TCEQ’s annual-average PM10 PSD increment-consumption analysis included 593 road emission sources.108 Inexplicably, every one of these road emission sources were excluded from TCEQ’s 24-hour average PM10 PSD increment-consumption modeling.109 This is a very serious modeling error. Excluding these very sensitive emission sources from their 24-hour PM10 modeling makes TCEQ’s analysis and review incomplete and unreliable. TCEQ Failed to Assess Total PM10 Emissions from the Limestone 3 Boiler TCEQ calculated both filterable and total PM10 emissions from NRG’s proposed LMS3 boiler. These emissions are enforced as permit conditions and emission standards, verified by stack monitoring.110 TCEQ calculated LMS3 filterable PM10 emissions (also known as front-half PM10) using a heat input of 8,000 MMBtu/hour and a performance standard of 0.015 lb/MMBtu. The product of these two values is an emission rate of 120 pounds/hour. TCEQ also calculated total LMS3 PM10 emissions (including the condensable back-half PM10) using a heat input of 8,000 MMBtu/hour and a performance standard of 0.035 lb/MMBtu. The product of these two values is an emission rate of 280 pounds/hour. The total PM10 emission rate (280 pounds/hour) is the correct amount for model input, as it is the total emissions that will impact the surrounding air quality. TCEQ, however, only modeled the front-half (filterable) PM10 emissions of 120 pounds/hour in their PSD increment-consumption analyses. This error is also seen in all of TCEQ’s PM10 modeling, including their significance, PSD increment, and NAAQS analyses, and for all averaging periods. TCEQ has underestimated modeled PM10 air impacts by failing to include the total PM10 emissions in their modeling assessments. This clearly is an error which must be corrected before TCEQ can consider whether NRG’s proposed facility is in compliance with the applicable air regulations. To the extent that TCEQ made this same error with other NRG combustion sources (including LMS1 and LMS2), the modeled PM10 results will be further underestimated. TCEQ Used an Outdated Dispersion Model

108 See ISCST3 input file 302_90_PM10.DTA. 109 See ISCST3 input file 301_90_PM102H.DTA. 110 TCEQ, Special Conditions, Permit Numbers 79188 and PSD-TX-1072, pp. 3-5.

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NRG used the USEPA ISCST3 dispersion model in support of their permit application, as did TCEQ in their review and approval process. ISCST3 (also called “ISC3”) has since been replaced with AERMOD as the USEPA Guideline dispersion model for assessing air impacts from sources such as NRG Limestone. As of December 9, 2006, AERMOD was fully promulgated as the replacement to ISCST3.111 The official notice of this change was listed in the Federal Register on November 9, 2005. AERMOD has been in the development phase for many years; similarly, ISCST3 has been updated numerous times to reflect better modeling techniques and to correct shortfalls. One of these ISCST3 improvements included enhanced building downwash algorithms, known as PRIME. This version of ISCST3 is known as ISC-PRIME (also called “ISC3P”). The latest versions of AERMOD also include these PRIME downwash algorithms.112 In essence, TCEQ could have used any of these three models in assessing NRG Limestone compliance: ISC3, ISC3P, or AERMOD. The only roadblock to using AERMOD (the most state-of-the-art of these models) is the lack of reliable meteorological data to run it – NRG failed to collect the necessary site-specific pre-construction surface and profile level meteorological data. In the end, the majority of TCEQ’s modeling review was accomplished using ISC3, and was completed during October, 2006. TCEQ, however, remodeled NRG’s PM10 significance analysis in March, 2007. And at that time they used the USEPA ISC3P model. This is a reasonable change to make, given the improved building downwash capabilities of ISC3P over ISC3. TCEQ modeled the exact same emission sources (only LMS3 and other new emission sources), emission rates, receptors, and meteorological data for both their ISC3 and ISC3P analyses of NRG’s PM10 significance impact levels – the only difference is the dispersion model they used. Using ISC3, TCEQ calculated a peak 24-hour PM10 concentration of 13.01 µg/m3.113 Using ISC3P, the peak 24-hour PM10 concentration was 16.01 µg/m3 – a 23% increase over the ISC3 results.114 Given this increase in modeled impacts using ISC3P, TCEQ should have assessed all of NRG’s significance impacts, PSD increments, and NAAQS compliance analyses with ISC3P. Instead, they did nothing and chose to recommend permit issuance based on their outdated ISC3 results. TCEQ relied on ISC3 even when they knew that it was predicting lower concentrations than the improved and more capable ISC3P model. Since the ISC3-modeled SO2 and PM10 impacts from NRG are already approaching the allowable Class II PSD increments, this is an important decision to make. TCEQ, however, made the wrong decision, thus failing to prepare a reliable modeling analyses of NRG’s air impacts.

111 http://www.epa.gov/scram001/guidance/guide/appw_05.pdf; Appendix W of 40 CFR Part 51, p. 68218. 112 Id., p. 68219. 113 See ISC3 output file 103_90_PM10.USF. 114 See ISC3P output file 103_90_OTHER.USF.

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TCEQ Ignores Significant Air Toxics Impacts As part of their compliance review analysis, TCEQ modeled air impacts from a number of non-criteria air pollutants (also called “air toxics”). TCEQ modeled these air toxics emissions using ISC3 and one-year of meteorological data – 1988. TCEQ’s modeling showed that coal dust, limestone dust, ammonia, and vanadium pentoxide air concentrations would exceed the State’s effects screening levels (“ESLs”). Rather than require mitigation of these findings of significant impacts, TCEQ found that “The exceedances have been reviewed by the Toxicology and Risk Assessment Section and are acceptable.115” TCEQ provides no meaningful support for this conclusion whatsoever. This raises two questions: Why did TCEQ even bother doing the air toxics analysis when any finding would apparently be deemed acceptable? And, at what level does TCEQ consider health effects to occur? Neither of these questions is answered by TCEQ. Beyond whitewashing over the significant air toxics impacts, TCEQ’s analysis underestimates the modeled air concentrations. First of all, TCEQ should have modeled the air toxics emissions using ISC3P. This model provides a better estimate of air impacts from building downwash than does ISC3. Also, TCEQ should have modeled all five years of available meteorological data to identify the highest impacts. By modeling only one year (1988), there is an 80% chance that TCEQ did not identify the peak modeled impacts. Furthermore, modeling multiple years of meteorological data (as TCEQ did for PSD and NAAQS analyses) would show whether the significant air toxics impacts would recur each and every year. This is an important matter that TCEQ should address before simply determining that modeled exceedances are acceptable. TCEQ Underestimates State Property Line Impacts In addition to their air toxics modeling analyses, TCEQ modeled SO2 and H2SO4 impacts to determine compliance with State property line regulations.116 The most sensitive of these property line results appears to be the one-hour NRG SO2 impacts of 954.88 µg/m3, which is over 93% of the of 1021 µg/m3 standard. As with their other air toxics modeling, TCEQ used modeling methods in this analysis that are likely to underpredict peak impacts. And without identifying peak impacts, a compliance assessment with State property line regulations is meaningless. TCEQ should have modeled the State property line impacts using ISC3P. As stated before, this model provides a better estimate of air impacts from building downwash than does ISC3. Also, TCEQ should have modeled all five years of available meteorological data to identify the highest impacts. By modeling only one year of data (1988), there is an 80% chance that TCEQ did not identify the peak modeled impacts. Furthermore, it must be remembered that the Waco Airport meteorological data specifically excludes any

115 TCEQ, Preliminary Determination Summary, Permit Numbers 79188 and PSD-TX-1072, p. 11. 116 Id., p. 8.

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wind speeds less than three knots (1.54 meters/second). Omitting these low wind speeds, which are critical for assessing compliance with short-term air impacts, renders this analysis completely unreliable. Since TCEQ used ISC3 and only one year of defective meteorological data, they failed to prepare a reliable modeling analyses of NRG’s property line air impacts. TCEQ Used Numerous Unreliable Modeling Assumptions Throughout their modeling analyses, TCEQ applied questionable assumptions that are likely to underpredict ambient air concentrations. TCEQ should either justify these assumptions, or remodel the analyses to correct these identified inadequacies. TCEQ Failed to Model Complete Receptor Arrays for all Air Impact Analyses As discussed in our comment on TCEQ’s 24-hour PM10 PSD increment-consumption modeling, TCEQ did not always model a complete receptor grid in their analyses. In the case of 24-hour PM10 PSD increment-consumption impacts, TCEQ failed to identify the peak modeled concentrations because of this practice. TCEQ’s complete receptor array includes 8,178 receptors.117 Most of TCEQ’s modeling analyses include fewer receptors, with some of their analyses assessing impacts at only 292 receptor locations.118 Without a complete receptor grid, it is easy for TCEQ to misidentify peak impacts, simply because they failed to perform a complete analysis. To address and correct this problem, TCEQ must remodel all of NRG’s air impact analyses with their complete receptor array. TCEQ Uses Inappropriate Cooling Tower Exhaust Temperatures TCEQ modeled all cooling tower cells as point source stacks, which include stack height and diameter, and stack gas temperature and exit velocity parameters. For all cooling tower “stacks,” TCEQ modeled a constant gas temperature of 303.71 Kelvin (about 87 degrees Fahrenheit).119 This assumption is inappropriate because cooling tower exhaust will vary as a function of ambient temperature and relative humidity (which effects evaporation and condensation rates). Cooling tower exhaust temperature is an important parameter in determining plume rise, which relates strongly to modeled air impacts. Overstating cooling tower exhaust temperature will overestimate plume rise, resulting in underpredicted ambient air impacts. This is particularly true for cold, stable atmospheric conditions that often occur in winter.

117 See ISC3 input file 103_90_PM10.DTA. 118 See ISC3 input file 302_90_PM10.DTA. 119 For example, see ISC3 input file 301_90_PM102H.DTA.

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To address this concern, TCEQ should remodel NRG’s analyses using cooling tower exhaust temperatures as a function of ambient air temperatures.120 TCEQ should justify any cooling tower exhaust temperatures they use, and give the public a chance to review and comment on this important input parameter. TCEQ Applies an Unjustifiable 0.6 Low-Level Fugitive Dust Adjustment Factor NRG’s low-level fugitive dust emission rates were modified using a TCEQ adjustment factor of 0.6.121 The TCEQ adjustment factor, which is not approved by USEPA, is essentially an undocumented and unsupportable impact reduction factor. TCEQ applies this factor because it feels the ISC3 model overpredicts air impacts from low-level fugitive dust emissions.122 TCEQ’s basis for their 0.6 low-level fugitive dust adjustment factor is without merit. TCEQ fails to consider that supporting their methodology will require a comparison of modeled to monitored air concentrations (which will vary for each site modeled), and that TCEQ has not performed any such analysis to confirm this claim. Furthermore, the most important model performance input parameter, calculated fugitive dust emission rates, is not even considered in TCEQ’s analysis of this issue. TCEQ developed their low-level fugitive dust adjustment factor by examining the relationship of modeled concentrations based on three-minute to 60-minute average dispersion coefficients.123 TCEQ fails, however, to verify this assumption in practice – an opportunity that has presented itself to them many times. For example, TCEQ could have performed a detailed inventory of existing NRG Limestone PM10 emissions, modeled them, and then compared them to monitored fenceline air concentrations. Since TCEQ has not done any such analysis, and has even stated that there are no air monitoring stations in Limestone County, their adjustment factor assumption remains unverified. To make matters worse, NRG’s proposed LMS operations triggered pre-construction PM10 air monitoring, but TCEQ waived that requirement, instead allowing NRG to use monitoring data from Travis County, some 130 miles west. To an outside observer, it appears that TCEQ does not want to verify their 0.6 low-level fugitive dust adjustment factor. In addition, TCEQ’s 0.6 low-level fugitive dust adjustment factor is derived from dispersion coefficients that were not developed for fugitive dust emission sources. In other words, there is no basis to apply this adjustment factor only to low-level fugitive dust sources. TCEQ is using a completely unrelated set of data to develop an arbitrary adjustment factor that has never been verified in practice. TCEQ must abandon this 120 This can be accomplished in ISC3/ISC3P by setting the stack gas temperature (TS) to a negative value. For example TS = -5. will assign a value to TS equal to 5 Kelvin greater than ambient temperature for each hour modeled. 121 TCEQ Interoffice Memorandum from Kimberly Krause to Jim Linville, August 24, 2007: Modeling Audit – NRG Texas LP (RN100542927), p. 6. 122 TCEQ Interoffice Memorandum from Dom Ruggeri to APD Technical Staff, March 6, 2002. 123 Id., p. 8.

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method as it leads to underpredicted and unreliable air concentrations and subsequent flawed permit-issuance decisions. Furthermore, TCEQ must reassess all of NRG’s fugitive PM10 emissions (for all averaging periods and scenarios) without applying their unreliable adjustment factor. NRG’s Modeled Road Dust Emission Rates Require Documentation TCEQ modeled PM10 air concentrations from NRG’s plant road emissions in their assessment of annual-average impacts, but failed to include these sources in the 24-hour impact analyses. TCEQ modeled these plant road emissions as a series of 593 volume sources, but we could not locate information to support the modeled emission rates. In their permit application, NRG mentions haul roads, but provides neither PM10 emission calculations, nor supporting assumptions for these sources.124 TCEQ must provide the NRG Limestone plant road emission calculations for public review and comment. Fugitive dust emissions from haul roads typically create high fenceline air impacts, due to the nature of their release and downwind dispersion. These impact-sensitive emission rates must be calculated with supportable methods and assumptions. TCEQ Modeled Road Dust Emissions Using Unreliable Release Parameters In addition to the inappropriate use of Waco meteorological data (see our associated comment) and unsupported road dust emission calculations, TCEQ applied incorrect modeling methods for the facility area source emissions. Low-level, non-buoyant sources, such as haul roads, are handled as area sources in dispersion models such as AERMOD, ISC3, and CALPUFF. NRG and TCEQ, however, chose the unorthodox approach of modeling haul roads as volume sources. The correct approach is to model these roads as a series of connected area sources that cover the precise locations of the haul roads. This can be done using AREAPOLY sources in ISC3, ISC3P, and AERMOD. Furthermore, TCEQ assumed a release height of 4.0 meters (13.2 feet) for fugitive dust emissions from haul roads. In reality, the emissions will occur at a much lower level, on the order of 1.0 meter. The excessively high release level modeled by TCEQ leads to underpredicted and unreliable downwind PM10 air concentrations. The TCEQ haul road modeling must be corrected using AERAPOLY sources (with 1.0 meter release height) that cover the true road locations. The TCEQ Draft Operating Permit is based on incorrect haul road modeling results; thus their decision to issue NRG’s air permit is flawed. TCEQ Failed to Account for Particulate Deposition and Subsequent Resuspension 124 Shaw Environmental, Inc., Prevention of Significant Deterioration Air Permit Application for Unit 3 Installation, Limestone Electric Generating Station, TCEQ Air Account No. LI-0027-L, June 2006, p. 3-10.

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NRG’s Limestone generating station emits thousands of tons per year of particulates from a variety of sources: e.g., coal combustion, storage piles, haul roads, cooling tower drift, and fuel and other material handling and conveying. TCEQ, however, failed to account for routine deposition of particulates from NRG’s existing and proposed emissions and the inevitable resuspension of these emissions back into ambient air by wind erosion and other means. TCEQ modeled wind erosion dust emissions from various sources, including fuel handling, and gypsum, limestone, and waste operations. These emissions were modeled using stability class and wind speed arrays to account for wind erosion under varying meteorological conditions. So, in this regard, TCEQ acknowledges that PM10 emissions from wind erosion need to be assessed. What TCEQ fails to address is that, to a certain extent, NRG’s particulate emissions will fall back to the ground (deposition) and then be resuspended back into the air via wind erosion or when disturbed by mechanical means such as road traffic. For example, cooling tower PM10 drift will fall back to the ground, creating a new source of air emissions that can later be reentrained into the atmosphere by wind erosion. In essence, TCEQ has incorrectly assumed that once NRG’s PM10 air emissions are released to the air they simply disappear. Since TCEQ has failed to account for any air impacts from deposition and resuspension of emitted PM10, their decision to issue NRG’s air permit is flawed and unreliable.

IV. Draft Permit Does Not Require Adequate Compliance with Emission Limits

Short-term Averaging Periods are Needed in Permit Special Condition 8

The Draft Permit lacks any meaningful short-term limits. Other than a 3-hour averaging period for NH3, BACT limits for all other pollutants are 30-day and/or annual averages. These long averaging periods are insufficient to protect public health and the environment.

The pound per hour limits in the MAERT are not meaningful short-term limits and have little, if any, pollution-limiting impact on operations. The pound per hour limits are grossly inflated, and can not be considered to reasonably limit air pollution or protect health and welfare. For example, many pollutants, including NOx, SOx, VOC’s, H2SO4, and CO, pose health and environmental risks (such as ozone-formation, lung and respiratory problems, or death) when large quantities are emitted in short duration. Our lungs do not average pollution over a year.

Monitoring to determine compliance with the Draft Permit’s PM Limits is Deficient and Should be Strengthened A once-a-year stack test under EPA reference Method 5 amounts to an average of just three hours’ worth of data. Viewed in light of the NRG’s proposed permitted full-time operation (i.e., 8,760 hours per year), it is clear that a once-a-year stack test presents a

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paltry snapshot of compliance. Continuous emissions monitoring systems (CEMS) are the preferred method for determining compliance with PM limits. 40 CFR §§ 60.42, et seq. PM CEMS should be utilized in conjunction with periodic stack sampling, as necessary, to determine compliance with applicable total PM (i.e., filterable and condensable) limits. Continuous opacity monitors (COMs) will be used to determine continuous compliance with the plant’s separate opacity limits. If TCEQ or NRG considers opacity to be a surrogate for PM, then the Draft Permit must include a specific provision describing the exact opacity level (expressed as percentage, e.g., 5% or 10% opacity) that corresponds to a PM exceedance. Absent a requirement for PM CEMS or a stated opacity level that pins the PM limit to a specific corresponding opacity level, Sierra Club asserts that any exceedance of the separate applicable opacity standard is evidence of an exceedance of the plant’s applicable PM limit. Sierra Club requests that TCEQ confirm that this is so.

If TCEQ does not requires PM CEMS and fails to add a provision describing the opacity level that corresponds to a PM exceedance, then, at the very least, TCEQ should require semi-annual stack testing for PM, in order to meet the minimum, semi-annual, compliance reporting requirements under Title V of the Clean Air Act.

V. Other Significant Issues

PM 2.5 is a Criteria Pollutant

Particulate matter (PM) is a mixture of extremely small particles and liquid droplets. PM is made up of a number of components, including acids (such as nitrates and sulfates), organic chemicals, metals, and soil or dust particles. Research studies have associated exposure to elevated levels of these particles in the air with damaging health effects, including lung and heart diseases. Particulate matter also settles onto homes, fields, and water bodies, and can cause damage to buildings, and crops, and can harm livestock.

PM 2.5 emissions should have been quantified separately. PM2.5, i.e., fine particulate matter, has been a regulated pollutant under the Federal Clean Air Act since 1997. EPA established a National Ambient Air Quality Standard (NAAQS) for PM2.5 in 1997.125 There is absolutely no separate recognition of this in the permit application materials submitted by NRG to the TCEQ. Initially, EPA allowed states and regulated industry to use PM10 as the surrogate pollutant for PM2.5 since technical methods for developing emissions inventories and modeling for PM2.5 were not available. But that was roughly 10 years ago; today, methods to quantify PM2.5 emissions are available.126 Therefore, it is disingenuous for NRG and TCEQ to still claim that it cannot estimate PM2.5 emissions 125 62 FR 38711 (1997); 40 CFR. Subpart 50.7. 126 For example, EPA’s emission inventory compilation document, AP-42, shows the various size fractions for PM emissions from coal fired power plants, including PM2.5. See AP-42 Volume 1, Section 1.1, Table 1.1-6.

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at the present time. If NRG feels that it needs to discuss uncertainties in such emissions estimates, it should feel free to do so in the public record. TCEQ’s decision to not require such quantification before granting a permit is also problematic. Emission calculations for PM2.5 should be provided and evaluated before any air permits are issued.

Hazardous Air Pollutants

NRG provided no calculations in its application (and TCEQ does not seem to have requested them) for a large number of hazardous air pollutants that are emitted by coal fired power plants. The emission factors for these pollutants are provided in readily available documents such as EPA’s AP-42.127 These toxics include dioxins, polyaromatic hydrocarbons (PAHs), and several other types of organic compounds. Most of these are generated in the combustion process itself. For example, AP-42 Section 1.1, Table 1.1-12 provides emission factors for dioxins and furans from sub-bituminous coal combustion.128 Similarly, Table 1.1-13 in AP-42 shows emission factors for polynuclear aromatic hydrocarbons (PAH).129 Finally, Table 1.1-14 in AP-42 provides emission factors for various organic compounds.130 NRG has not quantified any of these pollutants. As a result, the application is deficient. For example, since none of the emissions for these compounds have been quantified, none of the subsequent analysis comparing impacts for these compounds to the respectively, latest, TCEQ ESL values has been conducted. TCEQ’s review of the TXU applications seems to have overlooked these emissions.

NRG has not conducted a proper BACT analysis either by Federal or by Texas standards. As a result the emissions limits purportedly selected as BACT in the permits for the project are flawed and should be set aside.

Significant Increment Consumption Warrants Heightened Scrutiny According to NRG and TCEQ’s analysis, the source consumes significant amounts of increment for SO2 3-hr (over 83%), SO2 24-hr (over 81%), PM10 24-hr (almost 87%). This is additional evidence that a greater degree of control should be required by for this source. Additional Impacts Analyses Are Required Pursuant to 40 C.F.R. § 51.166 (o)(2), the permit applicant “shall provide an analysis of the air quality impact projected for the area as a result of general commercial, residential, 127 Emission factors for the various compounds discussed in this section are available in several AP-42 sections relating to sub-bituminous coal (Section 1.1), oil (Section 1.3), and natural gas (Section 1.4) combustion. 128 Dioxins and furans are extremely potent toxics; for example, TCEQ 2003 ESL for 2,3,7,8 TCDD is 3.0 x 10-8 micrograms per cubic meter. 129 There are 2003 TCEQ ESL values for many, if not all of these compounds as well. 130 Although TXU has included emissions of the generic class of compounds known as Volatile Organic Compounds (or VOCs), it should quantify specific organic compound emissions as well. Individual 2003 TCEQ ESL values exist for almost all of these compounds.

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industrial, and other growth associated with the source or modification.” As discussed in the NSR Manual (at D.3 to D.4), this analysis must include an assessment of the amount of residential growth the source will bring to the area, which depends on the number of new employees and the available workforce in the area as well as housing. The analysis must then evaluate the associated commercial and industrial growth associated with the new employees as well as the new unit. Further, the analysis must evaluate the growth due to construction activities and mobile sources, both permanent and temporary. NRG failed to meet these requirements in its analysis of the growth associated with its proposed power plant. In its permit application, NRG simply concludes that “secondary growth from this project is not expected to be substantial, and thus an analysis of such growth is not proposed.” This is unacceptable. The PSD regulations do not leave the choice whether to conduct a growth analysis within the applicant’s discretion—they clearly state that the applicant “shall” provide a growth analysis. TCEQ, however, has abdicated its responsibility to require this analysis, and concludes—without any basis for doing so—that “any commercial or industrial growth associated with this project is expected to be insignificant.”131 In addition, NRG (and TCEQ) did not consider and evaluate the increase in air emissions due to the industrial growth associated with the operation of the Limestone 3 Unit. Such growth could include the additional rail traffic and associated emissions to bring coal to the facility, any necessary increase in limestone production in the region and the associated increase in vehicular emissions (either train or truck) to transport the limestone to the Limestone facility for its SO2 controls, and the associated increase in vehicular emissions for the transport of fly ash off-site. TCEQ further failed to consider residential growth that will be facilitated by construction of unit 6. TCEQ should determine the number of additional households and businesses the proposed unit will serve and should evaluate the air quality impacts of activities associated with that growth, including construction and commuting traffic. To fail to do this in the context of construction of an 800-megawatt unit is to purposely, and possibly significantly, underestimate the air impacts of the unit. TCEQ must require NRG to conduct a thorough growth analysis and assess the increase in air emissions associated with both the construction and operation of the facility (from both direct operation of the facility and from associated industrial, commercial and residential growth) on air quality.132 Next, the Clean Air Act’s PSD requirements include a specific obligation for permitting authorities and permit applicants to evaluate soils and vegetation (in addition to ambient air quality) in any area that will be affected by any aspect of the proposed project (including construction):

131 See Preliminary Determination Summary, Section XI. 132 See 40 CFR 51.166(o)(2).

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[T]he analysis required under this subsection . . . shall require an analysis of the ambient air quality, climate and meteorology, terrain, soils and vegetation, and visibility at the site of the proposed major emitting facility and in the area potentially affected by the emissions from such facility for each pollutant regulated under this chapter which will be emitted, or which results from the construction or operation of, such facility.133

To facilitate this analysis, the PSD regulations require the permit applicant to provide information on the proposed source’s impacts on soils and vegetation:

The owner or operator shall provide an analysis of the impairment to visibility, soils, and vegetation that would occur as a result of the source or modification and general commercial, residential, industrial, and other growth associated with the source or modification. The owner or operator need not provide an analysis of the impact on vegetation having no significant commercial or recreational value.134

The obligation to consider impacts on soils and vegetation is a long-standing requirement of the PSD program, and includes an obligation to perform a site-specific inventory of soils and vegetation before the issuance of a draft permit and prior to the date of any public hearing. Such analysis must consider the variety of soils and vegetation in the area, the possibility of adverse impacts on soils and vegetation for PSD-regulated pollutants (including the possibility of adverse impacts at ambient concentrations that are lower than the applicable NAAQS, the impact of PSD pollutants – like fluoride – for which there is no NAAQS, and impacts from concentrations of pollutants that are lower than generalized screening levels),135 the possibility of adverse impact from non-PSD regulated pollutants, and the potential for any other site-specific environmental effects. See In re Indeck-Elwood, PSD Appeal 03-04, slip op. at 31-52 (EAB Sept. 27, 2006).136 As a result, permitting authorities (including TCEQ) are obligated to perform (or require of applicants) an analysis that specifically inventories the various soils and plant life (including but not limited to threatened or endangered species) in the vicinity of the proposed facility and in any other area affected by the construction or operation of the proposed facility. The analysis must then determine whether these soils or vegetation will be adversely affected by any of the plant’s emissions (during construction or operation). This analysis must include the full range of PSD pollutants (including

133 See CAA § 165(e)(3)(B), 42 U.S.C. § 165(e)(3)(B). 134 See 40 CFR 51.166(o)(1). 135 In particular, permitting authorities cannot blindly rely on the 1980 Screening Procedure for the Impacts of Air Pollution Sources on Plants, Soils, and Animals (“1980 Screening Levels”). For example, EPA’s NSR Manual specifically recognizes that “there are sensitive species which may be harmed by long term exposure to low concentrations of pollutants for which there are no NAAQS” and that under certain circumstances soil and vegetation analysis “has to go beyond a simple screening.” See In re Indeck-Elwood, PSD Appeal 03-04, slip op, at 38 (EAB Sept. 27, 2006). 136 It is worth noting that the requirement to evaluate impacts on soil and vegetation apply not only to the coal-fired steam boilers but to all sources at the proposed plant, individually and in the aggregate.

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fluoride), as well as any relevant non-PSD pollutants (including sulfuric acid mist, mercury, beryllium, etc.).137 An air quality impact analysis is critical because power plant emissions contribute to numerous adverse impacts on soils and vegetation. For example, sulfur dioxide emissions are associated with acid precipitation and deposition, leading to tree damage and death.138 Research has shown that exposure to sulfur dioxide in acid mist and ambient air was associated with short needles, premature needle drop, bud failure and stunted growth in commercially grown Christmas trees.139 Significantly, the degree of growth abnormalities in the trees decreased with increasing distance from a coal burning power plant. Ozone also has adverse effects on vegetation, reducing yields of timber and agricultural crops.140 In fact, “[i]njury to vegetation is one of the earliest manifestations of photochemical air pollution, and sensitive plants are useful biological indicators of this type of pollution.” 2002 IEPA Air Quality Report at 1. In 1997, EPA revised the secondary NAAQS for ozone precisely because the 1-hour standard “does not provide adequate protection to vegetation from the adverse effects of O3.” 62 Fed. Reg. 28855, 38875 (July 18, 1997). Moreover, ozone “concentrations within the range of 0.05 to 0.10 ppm have the potential over a longer duration of creating chronic stress on vegetation that can result in reduced plant growth and yield * * * and injury from other environmental stresses.” Id. Even more alarming, “[a]dverse effects on sensitive vegetation have been observed from exposure to photochemical oxidant concentrations of about 100 ug/m3 (0.05 ppm) for 4 hours.” Illinois EPA, 2002 Illinois EPA Annual Air Quality Report at 1 (2002). In addition, there “are sensitive vegetation species . . . which may be harmed by long-term exposure to low ambient air concentrations of regulated pollutants for which there are no NAAQS.” NSR Manual at D-4. As an example, U.S. EPA notes that “exposure of sensitive plant species to 0.5 micrograms per cubic meter of fluorides (a regulated, non-criteria pollutant) for 30 days has resulted in significant foliar necrosis.” Id. Here, TCEQ concludes that satisfying the NAAQS automatically satisfies the requirements for this analysis. This conclusory assumption is facially inadequate. Simple reliance on the NAAQS as evidence that proposed major modification will not harm soils or vegetation would essentially write the soils and vegetation analysis out of the Act – making it an unnecessary redundancy. This reading is contrary to fundamental

137 Among other things, acidic pollutants (or precursors), such as SO2, NOx, and hydrogen chloride can directly affect soil chemistry and have significant impacts on important habitat, vegetation, and potentially animal life (especially aquatic life). The applicant must examine the full range of these possible effects in connection with this PSD permit application. 138 69 Fed. Reg. at 4571-72, 4642-43, and 4645-47. 139 Hindawi, I.J. and Ratsch, H.C., Growth abnormalities of Christmas trees attributed to sulfur dioxide and particulate acid aerosol, Proc., Annu. Meet., Air Pollut. Control Assoc., 67:74-252 (1974). 140 Rule to Reduce Interstate Transport of Fine Particulate Matter and Ozone (Interstate Air Quality Rule) (Proposed Rule), 69 Fed. Reg. 4566, 4571 (January 30, 2004).

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principles of statutory interpretation; rather, DAQ must require or conduct an actual, site-specific analysis of potential impacts on soil and vegetation.141 The 1990 NSR Manual, which reflects EPA’s guidance about how to evaluate impacts on soil and vegetation, states that such analysis “should be based on an inventory of the soils and vegetation types found in the impact area,” and an applicant must “determine the sensitivities of the plant species listed in the inventory to the applicable pollutants that would be emitted from the facility and compare this information to the estimates of pollutant concentrations calculated in the air quality modeling analysis (conducted pursuant to 40 C.F.R. § 52.21(m)) in order to determine whether there are any local plant species that may potentially be sensitive to the facility’s projected emissions. . . . For those plants that show potential sensitivity, a more careful examination would be conducted. The Limestone Unit 3 draft permit is defective because there was an inadequate analysis of the effect of emission of pollutants on soils and vegetation. For example, it appears from the permit application and Preliminary Determination Summary that there was no site specific inventory of soils or vegetation performed as part of the permit application. Therefore, it is impossible to know whether any endangered, threatened, or sensitive species are located in or around the plant site. Further, the permit application failed to analyze the potential impacts of emissions of sulfur dioxide, nitrogen oxides (and ozone), fluorine, sulfuric acid, mercury, beryllium, and hydrogen chloride. In summary, TCEQ has not fully evaluated the impact on soils and vegetation of this new major pollution source. TCEQ thus has no basis for its assumption that the proposed unit will not adversely affect soil and vegetation and, given its failure to analyze the issue, and thus has denied the public the right to meaningfully comment on its decision-making process and contribute constructively to the permit determination.

The permit should clarify that all material representations provided with the Permit Application and relied upon by TCEQ in its technical review of the application, are enforceable conditions.

Federal and state law have for years specified that application representations are enforceable permit conditions. See, e.g., 30 TAC 116.116. Proposed Special Condition 41 (“As-Built Information”) is vague and confusing, and purports to allow NRG to essentially change engineering specifications, including control equipment, after permit issuance. This Special Condition flies in the face of long-held TCEQ and EPA policy and rules, and denies public notice and comment. The Application and Draft Permit simply can not be a moving target, yet this is exactly what proposed Special Condition 41 appears to allow.

141 Nor can a permitting authority (or the permit applicant) rely on vague generalizations, such as assertions that emission of a particular kind are “trivial,” without evaluating what those emissions will be and why they are expected to have no adverse impacts. See Indeck-Elwood, slip op. at 40.

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A 30-day averaging period for the heat input limitation in Special Condition 6 is too long for determination of the maximum heat input.

A 30-day averaging period for the heat input limitation in Special Condition 6 is too long for determination of the maximum heat input. This should be established by the rating of the boiler.

The 155 MW Auxiliary Boiler is a substantial source of pollution. (Special Condition 11)

BACT for the boiler includes the use of natural gas, low NOx burners, Flue gas recirculation, and catalytic converters. The Draft Permit establishes a limit of 0.36 lb/MMBtu for the auxiliary boilers. However, this is not BACT. A number of gas-fired boilers achieve much lower emission rates. The Calpine Company’s Turner Energy Center has NOX limit of 0.011 lb/MMBtu using Selective Catalytic Reduction, the Philadelphia Naval Shipyard’s Natural gas boiler has a NOx limit of 0.035 lb/MMBtu using low-NOx burners and natural gas, and Pine Bluff Energy, LLC, has a boiler with an emissions limit of 0.037 lb/MMBtu using low NOx burners, flue gas recirculation and good combustion practices. Each of these units is listed in the EPA’s RACT/BACT/LAER Clearinghouse as having a lower emission limit than the limit proposed for the boiler at Limestone.

Initial Demonstration of Compliance (Special Condition 25)

TCEQ should consider and require a longer period than 1-hour for each test run for H2SO4, HCl, HF, PM, PM10, NH3, Pb, and Hg in order to increase accuracy of the measurements.

Continuous Demonstration of Compliance (Special Condition 27)

As discussed in another section of these comments, the Draft Permit should be revised to require the use of CEMS for PM. Special Condition 31 should define “reasonable.” In addition, the permit should specify the procedures that will be used to determine emissions in the event the CEMS are non-operational. Special Condition 34 (Compliance with emission rates in the MAERT), applicable to periods of startup and shutdown, should not rely on surrogates. Instead, the Draft Permit should require direct measurement of VOC, H2SO4, HF, and HCl.

Draft Permit Provisions Regarding Startup, Shutdown, Maintenance, And Malfunction are Vague, and Should be Clarified

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The Draft Permit, Special Condition 8, purports to exempt Unit 3 from Compliance with BACT limits during planned startup and shutdown. This is not allowed under the Clean Air Act, and should be revised.

Emission limits defined as BACT may not include exemptions for excess emissions due to startup or shutdown, or malfunction, or maintenance/planned outage. Emission limits defined as BACT under the PSD program are established under Title I of the Clean Air Act and are intended to be protective of ambient air standards as well as to be technology forcing. The ambient air quality standards are to be met on a continuous basis. Thus compliance with the BACT limits must also be on a continuous basis.142

Indeed, Section 302(k) of the Clean Air Act expressly defines the term “emission limitation” as a limitation on emissions of air pollutants “on a continuous basis.” Section 169(3) of the Clean Air Act, in turn, defines BACT as an “emission limitation.” Accordingly, the Clean Air Act mandates that BACT continuously limit emissions of air pollutants.

EPA’s January 28, 1993, guidance memo, “Automatic or Blanket Exemptions for Excess Emissions During Startup, and Shutdowns Under PSD,” specifically disallows automatic exemptions from BACT emission limits. EPA’s policy also indicates that alternative emission limits for startup and shutdown “could effectively shield excess emissions arising from poor operation and maintenance or design, thus precluding attainment.” EPA’s January 28, 1993 guidance memo at 3. Instead, EPA policy indicates that enforcement discretion is the preferred approach for addressing the occurrence of excess emissions. EPA states:

. . .infrequent periods of excess emissions during startup and shutdown need not be treated as violations where the source adequately shows that the excess could not have been prevented through careful planning and design and that bypassing of control equipment was unavoidable to prevent loss of life, personal injury, or severe property damage. Startup and shutdown of process equipment are part of the normal operation of a

142 As the EAB has recently explained, “because routine startup and shutdown of process equipment are considered part of the normal operation of a source . . . [e]xcess emissions (i.e., air emission that exceed any applicable emission limitation) that occur during these periods are generally not excused and are considered illegal.” In re Indeck-Elwood, PSD Appeal 03-04, slip op at 72-73, (EAB, Sept. 26, 2006), 13 E.A.D. __, Thus, sources must be subject to emission limitations during startup and shutdown and such limitation must “be equivalent to BACT, and the permitting authority must provide a methodology for compliance.” Id. slip op at 74. Moreover, the Board has held that even where the permitting authority can demonstrate that less stringent “secondary limits” are appropriate (which it has not done here), such limits “must be, nonetheless, justified as BACT.” Id, slip op at 71 n.100 (noting that the permitting authority must determine “that compliance with the permit’s BACT and other emission limits cannot be achieved during startup and shutdown despite best efforts” before establishing alternative limits, and even then such limits “must be . . . justified as BACT”) quoting In re Tallmadge Generating Station, PSD Appeal No. 02-12, at 28 (EAB, May 21, 2003). Accordingly, to the extent that ADEQ has included exemptions in the permit for the Turk Plant that apply during startup or shutdown, or has included alternative secondary limitations in the PSD permit, it has failed to justify those permit conditions and therefore must either remove them or specifically justify them and provide an opportunity for public comment on such justifications.

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source and should be accounted for in the planning, design and implementation of operating procedures for the process and control equipment. Accordingly, it is reasonable to expect that careful and prudent planning and design will eliminate violations of emission limitations during such periods.

Id. at 2.

VI. Conclusion The Sierra Club appreciates the opportunity to provide these detailed preliminary comments.

Respectfully submitted, this 7th day of December, 2007,

By: ______________________________

Ilan Levin Environmental Integrity Project 1002 West Avenue, Suite 300 Austin, Texas 78701 Ph: (512) 619-7287 Fax: (512) 479-8302 Email: ilevin@environmentalintegrity.org COUNSEL FOR SIERRA CLUB