## Review of EPA’s Proposed Approval of a Revision to the State of Nevada’s State Implementation Plan to Implement the Regional Haze Program

Comments on Determination of Best Available Retrofit Technology

August 22, 2011

prepared by

Petra Pless, D.Env. Pless Environmental Consulting 440 Nova Albion Way #2 San Rafael, CA 94903

and

Bill Powers, P.E. Powers Engineering 4452 Park Blvd., Suite 209 San Diego, CA 92116ii 

### Table of Contents

I. EPA’s NOx BART Determinations fo r Reid Gardner Are Fundamentally Flawed ...................................................................................................................... 1

I.A NDEP’s NOx BART Determination for Reid Gardner Failed to Evaluate the Most Stringent NOx Emissi on Control Level for SCR ............................... 3

I.A.1 SCR Can Meet an Emission Limit of 0.05 lb/MMBtu NOx and ≥ 90% Control Efficiency .................................................................................................................... ............. 5

I.A.2 Cost-Effectiveness at Other Facili ties Must Be Considered .................................... 20

I.B The Reid Gardner NOx Cost Analysis Is Fundamentally Flawed ................... 21

I.B.1 The Costs to Install SCR on Reid Gardner Are Overestimated ............................ 22

I.B.2 NDEP Improperly Modi fied the Ba seline ...................................................................... 29

I.B.3 NDEP’s Cost Rejection Me thodology Is Invalid .......................................................... 30

I.C EPA Fails to Provide Enforcea ble Compliance Pr ovisions .............................. 36

I.C.1 Averaging Time................................................................................................................. ... 36

I.C.2 Monitoring and Re cordkeeping ....................................................................................... 38

I.C.3 Compliance Time ............................................................................................................... . 38

I.D Alleged Negative Non-Air Qua lity Environmental Impacts Are Mischaracterized and Unsuppo rted in the Record .......................................... 39

I.D.1 Alleged Impacts Are Not Supported in the Record ................................................... 39

I.D.2 Potential Non-Air Quality Environmental Impacts of SCR Compared to SNCR and Rotamix ............................................................................................................ 4 1

I.D.3 Impacts of Ammonia Slip on Salability of Fly Ash Are Mischaracterized .............. 44

I.D.4 Visible Plume Impacts Ar e Mischaracterized ............................................................... 44

I.D.5 Transportation Risk Can Be Av oided ............................................................................ 47

I.E EPA’s Proposed Higher Controlled Emission Rate for Unit 3 Compared to Units 1 and 2 for ROFA with Rotamix Is Not Justified ............................... 48

II. NDEP’s BART Determinations Do Not Follow the Methodology Assumed by the EPA ............................................................................................ 50

II.A NDEP Did Not Follow 40 CFR 51.308(e) .......................................................... 50

II.B NDEP Did Not Follow EPA’ s BART Guidelines ............................................... 51

II.B.1 Averaging Time Is Incorrect ............................................................................................. 52

II.B.2 Design Parameters Are Missing....................................................................................... 52

II.B.3 Equipment List Is Missing .................................................................................................. 53

II.B.4 Documentation for Cost Es timates Is Missing ............................................................. 54

II.B.5 Other Missing Documents, Modelin g Files, and Information ................................... 55

II.B.6 Costing Methodology Is Incons istent With BART Guidelines ................................. 56

II.C NDEP’s Analysis Did Not Follow EP A’s Air Pollution Control Cost Manual .................................................................................................................. 56iii Tables

Table 1: Baseline years, baseline (pre-BART) NO x emission rates, and NOx control efficiency for control scenarios evaluated by NDEP for Reid Gardner

Table 2: Achievable controlled NOx emission rates at Reid Gardner based on NDEP baseline and SCR with 90% control efficiency Table 3: Design criteria for Seminole Units 1 and 2 Table 4: Trimble County acceptance test results Table 5: Desert Rock NOx permit limits (lb/MMBtu) Table 6: Average cost-effectiveness fo r control option 5: LNB/OFA + SCR

Figures

Figure 1: NDEP’s least-cost envelope for Reid Gardner Unit 3 Figure 2: EPA BART Guidelines example fo r least-cost envelope determination of dominant/inferior controls Figure 3: Reid Gardner Units 1-3 historic a nnual average NOx emission rates and proposed NOx BART limits

Attachments

Attach. 1: NOx design efficiencies of retrofit SCRs in the CAMD database and the ICAC White Paper Attach. 2: Information compile d from EPA’s CAMD database Attach. 3: Compilation of SCR control efficiency data from vendor experience lists, technical papers, and McIlvaine databases Attach. 4a, 4b, 4c: Reverse engineered cost analys es from 10/09 CH2MHill BART Analyses for Units 1, 2, 3, respectively Attach. 5a, 5b, 5c: Spreadsheets to support revised cost analyses for Units 1, 2, 3, respectively

Exhibits

Ex. 1: Environmental Protection Agency, 40 CFR Part 52, [EPA-R06-OAR-2010-0846; FRL-], Approval and Promulgation of Implementation Plans; New Mexico; Federal Implementation Plan for Interstate Transport of Pollution A ffecting Visibility and Best Available Retrofit Technology Determination, signed by L.P. Jack son, dated August 4, and supporting Technical Support Document Ex. 2: California Air Resources Board, Compliance Assistance Technical Manual Series: Stationary Source Air Pollution Control Devices and Tec hniques, Section 310: Selective Non-Catalytic Reduction Control Theory and Designiv Ex. 3: Haldor Topsoe, Experience List, October 2009 Ex. 4: Hitachi, NOx Removal Coal Plant Supply List, October 23, 2002 Ex. 5: Argillon Experience List U.S. Coal Plant Ex. 6: CERAM Reference List, August 2006 Ex. 7: Hitachi, SCR System and NOx Catalyst Experience, Coal, February 2010
Ex. 8: Kurtides, T., Lessons Learned from SC R Reactor Retrofit, COAL-GEN, Columbus, OH, August 6-8, 2003, Sargent and Lundy Ex. 9: Rutherford, S., Coal-Fired SCR Applicatio ns in the US – Challenges and Strategies for Successful Operation and Emission Compliance, Cormetech Inc., VGB Workshop “Flue Gas Cleaning 2007,” Vienna, Austria, May 22–23, 2007 Ex. 10: Karina Rigby and others, SCR: The Most Effective Technology for NOx Reduction in Large Combustion Plants Ex. 11: H. Jensen-Holm, N.-Y. Topsøe, J.J. Cui, Im plementation of SCR DeNOx Technology on CoalFired Boilers in P.R. China, Haldor Topsoe, August 2006 Ex. 12: James E. Staudt and Clayton Erickson. Sele ctive Catalytic Reduction System Performance and Reliability Review, Andover Technology Partners Ex. 13: McIlvaine, Utility E-Alert #798, November 3, 2006 Ex. 14: Srivastava et al., Nitrogen Oxides Emission Control Options for Coal-Fired Electric Utility Boilers, J. Air & Waste Manage. Asso c., Vol 55, pp. 1367-1388, Table 4 Ex. 15: M. J. Oliva and S.R. Khan, Performance Anal ysis of SCR Installations on Coal-Fired Boilers, Pittsburgh Coal Conference, September 2005 Ex. 16: Callie A. Videtich, Director Air Program, EP A Region 8, Letter to Paul Tourangeau, Director, Colorado Department of Public Health an d the Environment, Re: Regional Haze State Implementation Plan, October 26, 2010 Ex. 17: Clay Erickson, Robert Lisauskas, an d Anthony Licata, What’s New in SCRs, DOE’s Environmental Control Conference, May 16, 2006 Ex. 18: B. Butler and R.P. Gaikwad, Operating Expe rience of SCRs at Texas Genco’s Coal and Gas Fired Power Plants, Mega Symposium 2004 Ex. 19: W.J. Gretta, D. Harajda, A.C. Favale, and T. J. Wess, The SCR Retrofit Design for the Seminole Generating Station Ex. 20: Email from Andrew Gray to Petra Pless, Re: NDEP Spreadsheets, August 20, 2011, and Excel spreadsheet ‘Copy Acid Rain Annual Data BART NVE (4).xls’ provided via email by Adele Malone, NDEP, to Andrew Gray, Gray Sky Solutions, on August 11, 2011 Ex. 21: R. Peltier, Top Plants: Seminole Generating Station, Palatka, Florida, Power, October 1, 2009 Ex. 22: K. Bresnahan, C. Erickson, M. Phillipo, S. Dean, and B. Rogan, Design, Installation and Startup Experience on a High Removal Efficiency SCR Sy stem at Morgantown Generating Station Units 1&2, Mega 2008 Ex. 23: E. Saunders, S. Straight, E. Pear, C. Er ickson, H. Culberson, and M. Kelly, SCR System Performance at LG&E’s Trimble County Generati ng Station, EPRI Workshop on Selective Catalytic Reduction, Atlanta, GA, October 22-23, 2002 Ex. 24: J. Cooper, W.J. Gretta, A.C. Favale, and H. N. Franklin, First Application of Babcock-Hitachi K.K. Low SO2 to SO3 Oxidation Catalyst at the IPL Petersburg Generation Station, ICAC Clean Air Technologies and Strategies, March 2005v Ex. 25: C. Erickson, S. Straight, and L. Hutcheso n, Coal-Fired SCR Operating Experience with High Removal Efficiency and Low-NOx Firing Systems, 2003
Ex. 26: T.R. Ake, C.A. Erickson, and L. K. Hutcheson, Increasing SCR NOx removal from 85% to 93% at the Duke Power Cliffside Steam Station, Ap ril 2006 ASME Power Division Special Section, ENERGY-TECH.com Ex. 27: S. Zwayyed, T. Pearson, and T. Reynolds, Low Maintenance SCR at the South Carolina Electric and Gas Cope Generating Station Unit 1, PowerGen 2009 Ex. 28: Institute of Clean Air Companies, White Pa per, Selective Catalytic Reduction (SCR) Control of NOx Emissions from Fossil Fuel-Fired El ectric Power Plants, May 2009, EPA-R09-OAR2009-0598-0032 Ex. 29: Texas Register, v. 26, no. 2, January 12, 2001, p. 557 Ex. 30: B. Butler and R.P. Gaikwad, Operating Expe rience of SCRs at Texas Genco’s Coal and Gas Fired Plants, Mega Symposium, 2004 Ex. 31: Texas Register, v. 26, no. 41, October 12, 2001, pp. 8159-8163 Ex. 32: U.S. Environmental Protection Agency, Region 9, PSD Permit Issued Pursuant to Requirement at 40 CFR 52.21, PSD Permit Number AZP 04-01, Desert Rock Energy Company, July 31, 2008 Ex. 33: U.S. Environmental Protection Agency, Regi on 9, EPA Responses to Public Comments on the Proposed Prevention of Significant Deterioratio n Permit for the Desert Rock Energy Facility, July 31, 2008
Ex. 34: Notes from October 16, 2007 U.S Environme ntal Protection Agency/Sithe Conference Call, Desert Rock Docket ID EPA-R09-OAR-2007-1110-0091 Ex. 35: Georgia Department of Natural Resources, Air Quality Permit, Plant Washington, Permit No. 4911-303-0051P-010-0, April 8, 2010 Ex. 36: Power4Georgians, LLC, Prevention of Sign ificant Deterioration Air Permit Application, November 26, 2008, Supplemental Data, Exhi bit A: Emission Calculations, Table A-2
Ex. 37: Illinois EPA, Construction Permit – PSD A pproval, NSPS Emission Units, Dallman Unit 4, August 10, 2006 Ex. 38: Kansas Department of Health and Environ ment, Air Emission Source Construction Permit, Holcomb Station, December 16, 2010 Ex. 39: Wyoming Department of Environmental Quality, Black Hills Corporation, Wygen 3, Permit No. CT-4517, February 5, 2007 Ex. 40: Wyoming Department of Environmental Qu ality, Basin Electric Power Corp., Dry Fork Station, Permit No. CT-4631, October 15, 2007 Ex. 41: Texas Department of Environmental Qualit y, Spruce Special Conditions, Permit Nos. 70492 and PSD-TX-1037, June 28, 2005 Ex. 42: Georgia Department of Natural Resource s, Air Quality Permit No. 4911-099-0030-P-01-0, Longleaf Energy Associates, LLC, May 14, 2007
Ex. 43: State of Nevada, Bureau of Pollution Cont rol, Class I Air Quality Operating Permit, General Requirements, No. AP4911-1349, issued to Newm ont Nevada Energy Investment, LLC, May 5, 2005 Ex. 44: Public Service Company of New Mexico, San Ju an Generating Station, Best Available Retrofit Technology Analysis, prepared by Black & Veatch, June 6, 2007vi Ex. 45: Golder Associates, Inc., Air Construction Permit Application and Prevention of Significant Deterioration Analysis for FPL Glades Power Park, Glades County, Florida, Prepared for Florida Power & Light, December 2006, Table 2-1 Ex. 46: Florida Power & Light Glades Resp onse to EPA Comments, March 26, 2007 Ex. 47: Matt Haber, Best Available Control Technologi es for the Baldwin Genera ting Station, Baldwin, Illinois, Prepared for the United States in connection with: United States v. Illinois Power Company and Dynergy Midwest Generation, Inc ., Civil Action No. 99-833-MJR, in the U.S. District Court for the Southern District of Illinois Ex. 48: BART Cost-effectiveness Summary Ex. 49: New Mexico Environment Department Ai r Quality Bureau, BART Determination, Public Service Company of New Mexico, San Juan Generating Station, Units 1-4, June 21, 2010 Ex. 50: Letter from Andrew M. Gaydosh, Assistant Regional Administrator, EPA Region 8, to Terry O’Clair, Director, Division of Air Quality, North Dakota Department of Health, Re: EPA’s Comments on the North Dakota Departme nt of Health’s April 2010 Draft BACT Determination for NOx for the Milton R. Young Station, May 10, 2010

Ex. 51 – Ex 86: BACT Cost-effectiveness Documents Ex 87: U.S. Environmental Protection Agency, EPA Air Pollution Control Cost Manual, Report EPA/452/B-02-001, 6th Ed., January 2002 Ex. 88: Four Corners Technical Support Document , Excel spreadsheet entitled “Four Corners SCR Cost Analysis 8-26-10,” from the Four Corners docket #EPA-R09-OAR-2010-0683 Ex. 89: S.D. Unwin R.W. Johnson, S.W. Rudy, J.E. Delargey, and W. Rogers, Selective Catalytic Reduction (SCR) System Design and Operations : Quantitative Risk Analysis of Options, Presented at CCPS 17th Annual International Co nference: Risk, Reliab ility, and Security Ex. 90: Thomas O’Brien, Email to Phil Hayes, EPSR, Dan Yagodinski, WPSC, Gary van Helvoirt, Greg Etvedt, WPSC, September 28, 2004, Re: 040928 SCR & SO 2 Permitting Issues (revised) 32.0440 Ex. 91: Sargent & Lundy, Salt Rive r Project, Najavo Generating St ation – Units 1, 2, 3, SCR and Baghouse Capital Cost Estimate Report, August 17, 2010, Appendix A Ex. 92: U.S. Office of Management and Budget, Circular A-4, September 2003
Ex. 93: IEA Clean Coal Centre, Selective No n-Catalytic Reduction (SNCR) for NOx Control Ex. 94: Nalco Mobotec, Multi-pollutant Emission Reduction Technology for Small Utility Boilers, Presented to Lake Michigan Air Directors Consortium, Innovative Industrial Source Control and Measurement Technologies Workshop, March 24, 2010 Ex. 95: McIlvaine Utility Environmental Upgr ade Tracking System, Reid Gardner Unit 4 Ex. 96: Pfafflin J.R., Ziegler E.N. (eds.), Encycloped ia of Environmental Science and Engineering, Vol. 2, CRC Press, 2006
Ex. 97: Black & Veatch, Platte River Power Au thority, Rawhide Energy Station, Rawhide NOx Reduction Study
Ex. 98: IEA Clean Coal Centre, Selective Non- Catalytic Reduction (SNCR) For NOx Control Ex. 99: U.S. Environmental Protection Agency, Identifi cation of (and Responses to) Potential Effects of SCR and Wet Scrubbers on Submicron Particulat e Emissions and Plume Characteristics, EPA600/R-04-107, August 2004 Ex. 100: Nalco Mobotec, ROTAMIX® Systemvii Ex. 101: Nalco Mobotec, NOx Control Ex. 102: E.E. Haddad, J.S. Crilley, and B.S. Higgi ns, Mobotec USA Inc., The Viability and Economics of Adding a ROFA®/Rotamix® MobotecSystem to a Selective Catalytic Reduction (SCR) Installation, NETL/DOE 2003 Conference on SC R and SNCR for NOx Reduction, Pittsburgh, PA October 29-30, 2003 Ex. 103: MobotecUSA, ROFA and ROTAMIX Installation, Cape Fear 6 of Progress Energy Ex. 104: G. Moberg, J.O. Blid, S. Wallin, T. Fa reid, and J. Ralston, Combined DeNOx/DeSOx and Additional NOx Reduction by Cleaning Flue Gas Condensate From Ammonia, PowerGen International, November 30–December 2, New Orleans 1999 Ex. 105: U.S. Environmental Protection Agency, Air Pollution Control Technology Fact Sheet, Name of Technology: Selective Non-Catalyti c Reduction (SNCR), EPA-452/F-03-031 Ex. 106: U.S. Environmental Protection Agency, Air Pollution Control Technology Fact Sheet, Name of Technology: Selective Catalytic Reduction (SCR), EPA-452/F-03-032
Ex. 107: L.F. Drbal, P.G. Boston, K.L. Westra , Black & Veatch, Power Plant Engineering, Black & Veatch, Springer, 1996 Ex. 108: California Air Resources Board, Compliance Assistance Technical Manual Series: Stationary Source Air Pollution Control Devices and Te chniques, Section 309: Selective Catalytic Reduction Control Theory and Design Ex. 109: B. Adams and C. Senior, Curbing the Blue Plume: SO 3 Formation and Mitigation, May 15, 2006
Ex. 110: Chemithon, Enviro Safe De nox®, SafeDeNOx® Urea to Ammonia Ex. 111: CERAM, Project: IPALCO Harding St Unit 7, July 7, 2003 Ex. 112: K.K. Humphreys and P. Wellman, Basic Co st Engineering, 3rd Ed., Marcel Dekker, Inc., 1996
Ex. 113: Lamar Larrimore, Effects of Ammonia fr om Post-combustion NOx Control on Ash Handling and Use, Effects on Utilization Applications , Fuel Chemistry Division Preprints 2002, 47(2), 832
Ex. 114: Lewandowski, Boilers, Emission Controls and the CCPs They Generate, presented at the American Coal Ash Association Educational Program for Managers of Coal Combustion Products (CCP), Morgantown, WV, June 5-9, 2000 Ex. 115: ROFA and ROATMIX Installation, Cape Fear 6 of Progress Energy Ex. 116: ICAC, Typical Installation Timelines for NOx Emissions Control Technologies on Industrial Sources, December 4, 2006.

### Comments

The federal Clean Air Act’s Regional H aze Rule requires assessment of older emission sources that are causing or contribu ting to visibility impairment in National Parks and Wilderness Areas (“Class I areas”) an d installation of Best Available Retrofit Technology (“BART”) on BART-eligible sources. 1 On November 2009, the Nevada Division of Environmental Protection (“NDEP”) adopted and transmitted the Nevada Regional Haze State Implementation Plan 2 (“Nevada RH SIP”), which implements the requirements of the Regional Haze Rule, to EPA Region 9. 3 On June 22, 2011, the U.S. Environmental Protection Agency (“EPA”) proposed to approve and promulgate a revision to the Nevada State Implementation Plan (“SIP”) to implement the regional haze program under the federal Clean Air Ac t for the first planning period through July 31, 2018 (“proposed rule”). 4

This comment letter addresses substantive flaws in EPA’s analysis of Nevada’s RH SIP and discusses how the proposed SIP revi sion fails to satisfy the requirements of the Regional Haze Rule under the federal Cl ean Air Act. Our comments focus mainly on the BART determinations for Nevada En ergy’s Reid Gardner generating station but also address general flaws applicable to other BART-eligible sources in Nevada.



### I. EPA’s NOx BART Determinations for Reid Gardner Are Fundamentally Flawed

Nevada Energy’s Reid Gardner generating station, located in Moapa, NV, is a primarily coal-fired steam-electric generating plant with four operating units. Units 1, 2, and 3, built in 1965, 1968, and 1976, respectively , are subject to BART requirements for reducing regional haze. Each of these units produces about 100 MW with wall-fired steam boilers manufactured by Foster Wheel er that drive turbine-generators firing primarily pulverized western bituminous co al. All three units are currently equipped with low NOx burners (“LNB”) and overfire air (“OFA”) systems for control of NOx; mechanical collectors and recently installed baghouses for particulate control; and wet scrubbers that use soda ash for sulfur dioxide (“SO 2 ”) removal. 5,6

1 40 CFR 51 (64 FR 35174-35774).

2 Nevada Division of Environmental Protection, Ne vada Regional Haze State Implementation Plan, October 2009, EPA-R09-OAR-2011-0130-0003 (hereinafter “Nevada RH SIP”).

3 76 FR 36451.

4 76 FR 36450-36468.

5 76 FR 36463.

6 CH2MHill, BART Analysis for Reid Gardner Station Un it 1, 2, and 3, Prepared for NV Energy, Revised Report, October 2008, EPA-R09-OAR-2011-0130-0007 (hereinafter “10/08 CH2MHill BART Analyses”), pp. ES-3 and 2-1, respectively.2 The initial BART analyses for Reid Gardner Units 1-3 were prepared for Nevada Energy by the consulting company CH2M Hill in October 2008. CH2MHill concluded that BART for NOx for Reid Gardner was sati sfied by LNB with OFA designed to meet a NOx emission limit of 0.39 lb/MMBtu at Un its 1 and 2 and 0.46 lb/MMBtu at Unit 3. 7 NDEP adopted the company’s cost analysis as presented in the 10/08 CH2MHill BART Analyses but used different baseline years for uncontrolled NOx emission rates based on the acid rain database maintained by EPA’s Clean Air Markets Division (“CAMD”). 8 Table 1 summarizes the baseline (pre-BART) NOx emission rates for Reid Gardner and control scenarios evaluated by NDEP for its BART determinations.

Table 1: Baseline years, baseline (pre-BART) NOx emission rates, and NOx control efficiency for control scen arios evaluated by NDEP for Reid Gardner

Unit 1 Unit 2 Unit 3
Baseline years a 2002/2003 2002/2003 2001/2002
Baseline (pre-BART) NOx emission rate (lb/MMBtu) b 0.461 0.462 0.447 NOx control efficiency (%) c
(1) LNB/OFA 21.3 23.7 6.5
(2) LNB/OFA and SNCR 40.9 42.7 29.9
(3) ROFA with Rotamix 57.7 59.0 38.3
(4) LNB/OFA with SCR 81.6 82.2 78.2
(5) ROFA with SCR 81.6 82.2 78.2

a 10/22/09 10/22/09 NDEP BART Review, p. 6: two consecutiv e years from 2001 through 2007 with highest NOx emission

rates b Average of EPA’s CAMD data NOx emission rates for two baseline years c 10/22/09 NDEP BART Review, Table 1, pp. 5-6
NDEP determined that BART is rotating opposed overfire air (“ROFA”) with Rotamix and emission limits of 0.20 pounds per million British thermal units (“lb/MMBtu”) for Units 1 and 2 and 0.28 lb/MMBtu for Unit 3 based on a 12-month rolling average. 9 The EPA is proposing to approve these BART determinations. 10 This does not satisfy BART for the subject units at Reid Gardner for the reasons discussed in detail below. Instead, BART for these un its should be the use of low NOx burners

7 10/08 CH2MHill BART Analyses, pp. ES-3 and 2-1, respectively.

8 Nevada Division of Environmental Protection, BART Determination Review of NV Energy’s Reid Gardner Generating Station Units 1, 2, and 3, Re vised October 22, 2009, EPA-R09-OAR-2011-0130-0003, (hereinafter “10/22/09 NDEP BART Review”), p. 6.

9 Ibid ., Table 1.

10 76 FR 36463.3 (“LNB”) with overfire air (“OFA”) and a se lective catalytic reduction (“SCR”) system designed to reduce NOx emissions to 0.05 lb/MMBtu on a 30-day rolling average based on a boiler operating day and an ammonia slip 11 of 2 parts per million (“ppm”) 12 . The basis of this conclusion is set out below.

Best Available Retrofit Technology or BA RT is “an emission limitation based on the degree of reduction achievable through the application of the best system of continuous emission reduction...” 13 BART is determined on a case-by-case basis following a five-step process laid out in the BART Guidelines, as follows:

STEP 1 – Identify all available retrofit control technologies STEP 2 – Eliminate techni cally infeasible options STEP 3 – Evaluate control effectivene ss of remaining control technologies, STEP 4 – Evaluate impacts and document the results, and STEP 5 – Evaluate visibility impacts. 14

The BART analyses conducted by CH2M Hill and NDEP contain a number of fatal flaws in implementing Steps 3 and 4 of this process.

I.A NDEP’s NOx BART Determination for Reid Gardner Failed to Evaluate the Most Stringent NOx Em ission Control Level for SCR
Many of the NOx control options that wer e evaluated are capable of performing at a wide range of levels. A selective cata lytic reduction (“SCR”) system, for example, can remove 90% or more of the NOx emissions. 15 A selective non-catalytic reduction system (“SNCR”) typically removes 30% to 60% of the NOx, depending upon the specifics of the boiler. 16 The EPA’s BART Guidelines, which EPA claims NDEP followed 17 , notes: “It is important, however, that in analyzing the technology you take

11 Unreacted ammonia from an SCR or SNCR emitted from the stack is commonly called ammonia slip.

12 See, for example, Environmental Protection Agency, 40 CFR Part 52, [EPA-R06-OAR-2010-0846; FRL- ], Approval and Promulgation of Im plementation Plans; New Mexico; Federal Implementation Plan for Interstate Transport of Pollution Affecting Visi bility and Best Available Retrofit Technology Determination, signed by L.P. Jackson, dated Au gust 4, 2011 (hereinafter “New Mexico FIP”) and supporting Technical Support Document, (Exhibit 1).

13 40 CFR 51.301.

14 70 FR 39164.

15 California Air Resources Board, Compliance Assistan ce Technical Manual Series: Stationary Source Air Pollution Control Devices and Techniques, Section 310: Selective Non-Catalytic Reduction Control Theory and Design; http://www.arb.ca.gov/cap/manuals /cntrldev/sncr_etc/310sncr.htm , accessed August 19, 2011 (Exhibit 2).

16 Ibid

.

17 76 FR 36462, see also Comment II.B.4 into account the most stringent emission control level that the technology is capable of achieving.” Elsewhere, the BA RT Guidelines note: “While you must consider the most stringent level as one of the control options, you may consider less stringent levels of control as additional options.” 18 This was not done. As demonstrated below, the BART analysis was not based on the most stringent level of control that could be reasonably achieved by either the selected BART te chnology, ROFA/Rotamix, or the technology that should have been selected, SCR with LNB/OFA.

NDEP (and CH2MHill) considered two control scenarios with SCR systems: ROFA with SCR (option 4) and LNB/OFA wi th SCR (option 5). NDEP reported the combined control efficiency for these two sce narios as 81.6% for Unit 1, 82.2% for Unit 2, and 78.2%, for Unit 3. 19 However, a portion of this redu ction is due to the ROFA in option 4 and to the LNB/OFA in option 5. Th e NDEP does not disclose the portion of this reduction due to ROFA, but does disclose it for the LNB/OFA. 20 Using NDEP’s information, the cost analyses for LNB/OFA with SCR at Units 1 to 3 assume that the SCR system would remove only 77% of the NOx at the inlet to the SCR. 21

As BART is “an emission limitation based on the degree of reduction achievable through the application of the best system of continuous emission reduction...,” it is essential to consider “the most stringent em ission control level” in evaluating control effectiveness. The NDEP BART determination did not even identify, let alone consider, the most stringent emission control level th at SCR systems are capable of achieving. When the most stringent emissi on control level is not cons idered, the BART Guidelines require “a showing of differences between the source and other sources that have achieved more stringent emissions limits...” 22 The record in this case contains no showing of differences between Reid Gardne r Units 1, 2, and 3 and many other similar sources that have been permitted and are cu rrently operating with SCRs designed to remove 90% or more of the units’ NOx emissi ons with outlet NOx levels as low as or lower than 0.05 lb/MMBtu based on a 30-day rolling average.

18 70 FR 39166, emphasis added.

19 10/22/09 NDEP BART Review, Table 1, pp. 3 and 5-6; see also 10/09 CH2MHill BART Analyses, Table 3-2, p. 3-8, respectively.

20 10/22/09 NDEP BART Review, p. 3 and Table 1.

21 Based on 10/22/09 NDEP BART Review, Table 1, the assumed SCR removal efficiency based on the controlled NOx emission rates (in lb/MMBtu) for Unit 1: (1-0.085/0.364) = 0.766; Unit 2: (1-0.083/0.355) = 0.766; Unit 3: (1-0.098/0.421) = 0.767.

22 70 FR 39166.5 I.A.1 SCR Can Meet an Emission Limit of 0.05 lb/MMBtu NOx and ≥ 90% Control Efficiency

The control efficiencies assumed for SCR options at Reid Gardner Units 1-3 (81.6%, 82.2%, 78.2%, respectively) are considerab ly lower than typically guaranteed by vendors for coal-fired boilers. CH2MHill’s reports claim that the design control efficiencies were based on vendor -obtained performance quotations. 23 These vendorobtained performance quotations or the request for proposal that they are based on are not provided anywhere in the record. Do th e control efficiencies that were costed, for example, represent the best level of reduction that can be achieved, or are they just the levels requested by CH2MHill? The record is silent on this key issue. Neither EPA nor NDEP questioned these unusually low control e fficiencies but instead took them at face value.

An SCR system by itself ( i.e. , without LNB /OFA or ROFA) is routinely designed to achieve 90% NOx reduction. There is nothing unusual about Reid Gardner that would preclude the installation and operatio n of a 90% efficient SCR. The NOx emission rates that could be achieved at Reid Gard ner using a 90% efficient SCR are summarized in Table 2.

Table 2: Achievable controlled NOx emission rates at Reid Gardner based on NDEP baseline and SCR with 90% control efficiency

Unit Baseline
years a NDEP baseline emission rates b Controlled NOx emission rates c (lb/MMBtu) (lb/MMBtu)

1 2002/2003 0.461 0.04605

2 2002/2003 0.462 0.04615

3 2001/2002 0.447 0.04465
a 10/22/09 10/22/09 NDEP BART Review, p. 6: two consecutive years from 2001 through 2007 with highest NOx emission rates
b Average of EPA’s CAMD data NOx emission rates for two baseline years c (NDEP baseline emission rates) × (1-0.90)

It is reasonable to assume a NOx emi ssion limit of 0.05 lb/MMBtu and 90% NOx control by SCR for Reid Gardner, given the impressive and growing track record of successful SCR installations documented belo w, over 300 in operation in the United States alone, and the low sulfur content of the coal fired at Reid Gardner (0.29%-0.57%). These SCRs have been installed on electric generating units ranging in size from 40 MW to over 1600 MW. The San Juan units are 100 MW each. The Reid Gardner units could be controlled by three 100-MW SCR systems, or the three units ducted together and

23 10/08 CH2MHill BART Analyses, p. 3-7, respectively.6 served by a single 300-MW system. The Energy Information Agency database, Form EIA-860, indicates that 353 EGUs are retrofit with SCR and that of these, 37 are 100 MW or smaller and 146 are 300 MW or smaller.

The EPA must demonstrate why SCR at Reid Gardner cannot achieve 90% NOx control when SCR retrofits on older boilers are doing much better today. The docket contains no site-specific or technical fa ctors that would preclude the successful installation and operation of a 90 % efficient SCR at Reid Gardner.

a) General SCR Design Experience
It is widely recognized today that all major SCR catalyst vendors 24 can easily guarantee at least 90% efficiency for SCRs burning coals with a wide range of properties, from low sulfur, highly alkaline ash, high moisture Powder River Basin (“PRB”) subbituminous coal to high sulfur, high ash, high moisture lignites to high sulfur, high ash, bituminous coal an d coal waste. Vendor experience lists 25 indicate that SCRs are routinely designed for 90% NOx control, depending on purchaser specifications. The NOx design efficiencies of retrofit SCRs in the CAMD database and the ICAC White Paper were compiled from publicly available sources and are summarized in Attachment 2. This summary shows that SCR NOx control efficiencies were available for 242 out of 372 coal-fired boile rs equipped with SCR units. Of these, 188 or 78% were designed for 90% or greater NOx control efficiency on a wide range of coals.

Most of these SCRs are required un der various trading programs that cap regional or utility-wide emissions, allowing the operator to evaluate market conditions to determine whether to operate existing co ntrols, install more controls, or purchase allowances generated by other plants. This a llows significant flexibility in operation of any given SCR. Thus, most of the SCR-con trolled units do not operate at design efficiencies all of the time as they do not have unit-specific NOx permit limits.

Reflecting on this experience in 2003, S argent and Lundy, an engineering firm that designs SCRs, stated:

“[A]ll Sargent & Lundy-designed SCR reacto rs at coal-fired units, which have been placed into service, have achieved their gu aranteed NOx reduction efficiencies within the specified ammonia slip limits. The mini mum design NOx reduction efficiency was

24 These include Haldor Topsoe (Exhibit 3), Hitachi (Exhibit 4), Johnson-Matthey/Argillon (Exhibit 5), CERAM (Exhibit 6), etc.

25 See
, e.g. , Haldor Topsoe, SCR Experience List, October 2009 (Exhibit 3), Hitachi, NOx Removal Coal Plant Supply List, October 17, 2006 (Exhibit 4); Argi llon Experience List U.S. Coal Plants (Exhibit 5); Hitachi, SCR System and NOx Catalyst Experience, Coal, February 2010 (Exhibit 7).7 85% and the maximum reduction efficiency wa s in excess of 90%. Design ammonia slip levels ranged between 2 ppm and 3 ppm at th e end of catalyst life. Although no SCR installations have yet operated for the guarantee d catalyst life duration, it is anticipated that the NOx reduction and ammonia slip pe rformance guarantees will continue to be met over that period. Operational installati ons include pulverized coal units burning PRB coal, Illinois low- to high-sulfur coal , and eastern low to high-sulfur coal; one cyclone unit burning PRB coal; and two cycl one units burning Illinois low-sulfur coal. SCR reactor designs have included 2+1 and 3+ 1 catalyst level insta llation sequences and have used plate, honeycomb, and corrugated type catalysts. Design of SCR reactors for removal efficiencies greater than 90% at ammonia slip levels less than 2 ppm to 3 ppm has been demonstrated and should be cons idered as a feasible design criterion.” 26

Cormetech, an SCR catalyst vendor noted the following in a 2007 paper:

“It is common for units to be designed for NOx removal efficiencies of 90%, and operate at efficiencies that are greater than the design value. As catalyst performance guarantees are defined to be those associated with the en d of a specified lifetime, SCR catalyst that is early in its functional life has considerably higher capability. As an example, catalyst that is designed to achieve 90% NOx removal and 2 ppm ammonia slip after a lifetime of 24,000 operating hours will operate with virtua lly no ammonia slip at the beginning of its life.” 27

Siemens AG, another catalyst supplier notes:

“Selective Catalytic Reduction (SCR) is curren tly the most widely applied state of the art technology for controlling NOx emissions from coal fired power plants... across Germany, many other parts of Europe, in Japa n, as well as in the US. This technology has been proven to be reliabl e over almost two decades of use under the most extreme conditions. SCR can reduce NOx emissions up to >93% in many cases...” 28

26 Kurtides, T., Sargent and Lundy, Lessons Learne d from SCR Reactor Retrofit, COAL-GEN, Columbus, OH, August 6-8, 2003; http://www.adeq.state.ar.us/f tproot/pub/commission/p/Closed%20Permit%20Dockets%202006-2010/08-007-P%20AEP%20Service%20Corp%20&%20SwepcoHempstead%20Co%20Hunting%20Club/2008-12- 03_Ex._7_SCR_Lessons_Learned_from_SCR_Reactor_Retrofit_Coal-G.pdf , accessed August 18, 2011 (Exhibit 8).

27 Rutherford, S., Coal-Fired SCR Applications in the US – Challenges and Strategies for Successful Operation and Emission Compliance, Cormetech Inc., VGB Workshop “F lue Gas Cleaning 2007,” Vienna, Austria, May 22–23, 2007; http://www.cormetech.com/brochure s/2007_VGB_Confe rence_Paper.pdf
, accessed August 18, 2011 (Exhibit 9).

28 Karina Rigby and others, SCR: The Most Effectiv e Technology for NOx Reduction in Large Combustion Plants; http://legsys.infomil.nl/legsys /noxconf/uk/pdf/combust/rigby.pdf , accessed August 18, 2011 (Exhibit 10).8 Hitachi’s NOx Removal Coal Plant Supply Li st also includes many retrofit SCRs on similar existing units that burn similar an d more difficult fuels that were designed to achieve 90% NOx reduction. 29

In a paper discussing developments in China, Haldor Topsoe, a SCR catalyst vendor, stated that “[T]he Taishan Thermal Power Plant is a 5 × 600 MWe coal-fired power plant firing domestic coals. Unit 5 includes an SCR system, scheduled for startup in 2006. Haldor Topsøe A/S is the supplier of the catalyst and critical components and has performed the system design including physical flow model tests. The DeNOx unit is guaranteed to have a NOx conversion at 94% with only 3 ppm ammonia slip.” 30

b) General Operating Experience in U.S.
Continuous emission monitoring data su bmitted by utilities to EPA’s CAMD and analyzed by others indicate that “90% remova l efficiency is currently being achieved by a significant portion of the coal-fired SCR fleet.” 31 More than 30 units have achieved greater than 90% NOx reduction. 32 NOx removal of 90% was achieved on 10,000 MW of coal-fired generation in 2004. The McIlvaine Re ports, a source of control technology information for BACT determination, report ed that three of Haldor Topsoe’s SCR installations averaged over 95% NOx reduction during the 2005 ozone season. 33

Similarly, the U.S. EPA analyzed CAMD NOx data for 22 existing units that are achieving limits below 0.07 lb/MMBtu on a 30- day rolling average. Eight of these units were operating at or above 90% removal effi ciency and not one was operating at less than 86%. 34 Moreover, these data were collected from 2003, before the NOx SIP Call 35

29 Hitachi, NOx Removal Coal Plant Supply List, October 17, 2006 (Exhibit 4).

30 H. Jensen-Holm, N.-Y. Topsøe, J.J. Cui, Implementation of SCR DeNOx Technology on Coal-Fired Boilers in P.R. China, Haldor Topsoe, August 2006; http://www.topsoe.com/business_ areas/air_pollution_control/~/m edia/PDF%20files/Scr_denox/Imp lementation%20of%20SCR%20techology%20on%20Coal%20Fired%20Boilers%20%20China%20Power%20 2006.ashx , accessed August 19, 2011 (Exhibit 11).

31 James E. Staudt and Clayton Erickson. Selective Catalytic Reduction System Performance and Reliability Review, Andover Technology Partners, p. 15; http://www.gaepd.org/air/airpermit/downloads/pe rmits/psd/dockets/longle af/appealdocs/exhibits /excluded/Petitioners/P-006-1.pdf , accessed August 18, 2011 (Exhibit 12).

32 Ibid , p. 1.

33 McIlvaine, Utility E-Alert #798, November 3, 2006 (Exhibit 13).

34 Srivastava et al., Nitrogen Oxides Emission Control Options for Coal-Fired Electric Utility Boilers, J. Air & Waste Manage. Assoc., Vol 55, pp. 1367-1388, Table 4; http://www.netl.doe.gov/technologies/coalpow er/ewr/pubs/NOx%20control%20Lani%20AWMA%20 0905.pdf (Exhibit 14).

35 In October 1998, EPA finalized the “Finding of Significant Contribution and Rulemaking for Certain States in the Ozone Transport Assessment Group Region for Purposes of Reducing Regional Transport of9 and other regulatory programs for NOX were in place. Because compliance with the NOx SIP Call was generally not required until May of 2005, performance has improved since then compared to 2003. 36 A recent reanalysis of CAMD data by EPA indicates “many boilers retrofitted with SCR are achieving an emission rate of 0.03-0.06 lb/MMBtu.” 37

SCR system designers have analyzed EP A CAMD CEMS data to determine the NOx levels that are currently being achieved by over 100 SCR-equipped coal-fired boilers. This analysis identified 25 unit s that are achieving NOx emissions less than 0.05 lb/MMBtu on an hourly average basis. 38 Others have reported similar results. 39 A few examples of retrofit units designed for 90% NOx control are discussed below.

c) Specific SCR Design with NOx Control Efficiency of ≥ 90% and Operating Experience
This section reviews the design basis of several coal-fired boiler retrofit units. The subject Reid Gardner BART units could be designed to meet the same design basis as the units discussed below, i.e.
, ≥ 90% NOx control with low SO 2 to SO 3 conversion and low ammonia slip. While these and other SCRs are routinely designed to achieve 90% NOx control, they may not be not operated to meet these design targets as they operate under cap and trade programs that do not apply to specific units. This discrepancy between design and operation is discussed in the next section and does not affect the NOx BART determination.

Vendor acceptance tests indicate th at units designed to achieve 90%+ NOx reduction are able to meet and often exceed the design levels. When the need arises, the SCRs are able to perform as designed. This has been demonstrated in many cases. The

Ozone,”commonly called the “NOx SIP Call.” The NOx SIP Call was designed to mitigate significant transport of NOx, one of the precursors of ozone; see U.S. Environmental Protection Agency, The NOx SIP Call; http://www.epa.gov/airmarkets/p rogsregs/nox/noxsipcall.html , accessed August 18, 2011.

36 M.J. Oliva and S.R. Khan, Performance Analysis of SCR Installations on Coal-Fired Boilers, Pittsburgh Coal Conference, September 2005, p. 3; http://www.gaepd.org/air/airpermit/downloads/pe rmits/psd/dockets/longle af/appealdocs/exhibits /excluded/Petitioners/P-013.pdf , accessed August 18, 2011 (Exhibit 15).

37 Callie A. Videtich, Director Air Program, EPA Region 8, Letter to Paul Tourangeau, Director, Colorado Department of Public Health and the Environment, Re: Regional Haze State Implementation Plan, October 26, 2010, p. 3 (Exhibit 16).

38 Clay Erickson, Robert Lisauskas, and Anthony Licata, What’s New in SCRs, DOE’s Environmental Control Conference, May 16, 2006, p. 28; http://www.netl.doe.gov/publications/p roceedings/06/ecc/pdfs/Licata.pdf , accessed August 18, 2011 (Exhibit 17).

39 M.J. Oliva and S.R. Kahn, Performance Analysis of SCR Installations on Coal-Fired Boilers, Presented at the Pittsburgh Coal Conference, September 2005 (Exhibit 15).10 W.A. Parish Electric Generating Station unit s, for example, operate under the HoustonGalveston-Brazoria ozone nonatt ainment area regulations. ( See Comment I.A.1.e). Parish Unit 8, which typically operates at about 0.044 lb/MMBtu, was run for extended periods at 0.03 lb/MMBtu and then at 0.03 5 lb/MMBtu (August through November 2006) to demonstrate its capability to do so. 40

i. Seminole Units 1 & 2

The Seminole Generating Station consists of two 650 MW units firing eastern bituminous coal. 41 The Seminole SCR systems were designed for 90% NOx reduction and low SO 2 conversion (<0.5%). The inlet NOx (0.413 lb/MMBtu) and controlled with LNB and OFA (uncontrolled NOx emissi ons Unit 1: 0.461 lb/MMBtu, Unit 2: 0.462 lb/MMBtu, Unit 3: 0.447 lb/MMBtu). 42 The design basis for the Seminole SCRs is given in Table 3. The required outlet NOx of 0.04 lb/MMBtu represents the end-of-life performance after catalyst deactivation has taken place. 43

Table 3: Design criteria for Seminole Units 1 and a

a from W.J. Gretta, D. Harajda, A.C. Favale, and T.J. Wess, The SCR Retrofit Design for the Seminole Generating Station; http://www.hitachipowersystems.us/support ingdocs/forbus/hpsa/technical_papers/ SCR_Retrofit_Seminole_Generating_Station.pdf , accessed August 18, 2011, attached as Exhibit 19
Performance testing indicated the in stalled SCR systems significantly outperformed their NOx removal guaran tees of 90.3%, from 0.413 lb/MMBtu to

40 B. Butler and R.P. Gaikwad, Operating Experience of SCRs at Texas Genco’s Coal and Gas Fired Power Plants, Mega Symposium 2004 (Exhibit 19).

41 W.J. Gretta, D. Harajda, A.C. Favale, and T.J. Wess, The SCR Retrofit Design for the Seminole Generating Station; http://www.hitachipowersystems. us/supportingdocs/forbus/hpsa/t echnical_papers/SCR_Retrofit_Se minole_Generating_Station.pdf , accessed August 18, 2011 (Exhibit 19).

42 Email from Andrew Gray to Petra Pless, Re: NDEP Spreadsheets, August 20, 2011, and Excel spreadsheet ‘Copy Acid Rain Annual Data BART NVE (4).xls’ provided via email by Adele Malone, NDEP, to Andrew Gray, Gray Sky Solutions, on August 11, 2011 (Exhibit 20).

43 W.J. Gretta et al. (Exhibit 19).11 0.04 lb/MMBtu. Ammonia slip, guaranteed at 2 ppm, was measured at 0.2 ppm. The SO 2 oxidation was guaranteed at 0.5% and meas ured at less than 0.1% across the entire SCR system. The system pressure drop was less than 5 inches of water, well under the guaranteed value. 44

ii. Morgantown Generating Station Units 1 & 2

The Morgantown 642 MW boilers burn high sulfur (3%) eastern bituminous coal. An SCR was installed in 2007/2008, designed to remove 92.5% from an inlet NOx of 0.6 lb/MMBtu at maximum load to an outlet of 0.045 lb/MMBtu and an SO 2 oxidation rate of 0.5% and 2 ppm ammonia slip. The SCR consists of two four-layer reactors per unit, with three initially installed layers an d one future layer of catalyst. The acceptance test demonstrated 92.65% to 94.6% NOx removal to outlets of 0.032 lb/MMBtu at maximum load and 90% to 91.3% at minimum load to NOx outlets of 0.043 to 0.054 lb/MMBtu. 45

iii. Louisville Gas & Electric (E.ON) Program Alliance

Louisville Gas & Electric (“LGE,” now E.ON) retained Babcock Power and Duke Fluor Daniel to engineer, procure, and cons truct six SCRs within the LG&E system. The first was Trimble County Generating Statio n Unit 1 (tangentially fired 547 MW), followed by similar projects at Mill Creek Generating Station Unit 3 (opposed wall fired 410 MW); Mill Creek Generating Station 4 (opposed wall fired 520 MW); Ghent Generating Station Units 3 and 4 (opposed wall fired 520 MW); and Ghent Generating Station Unit 1 (tangentially fired 520 MW). Each SCR system was designed to reduce baseline NOx emissions by 90%. These systems included a variety of boilers, operating conditions, space restrictions, low and high dust loadings, low and high sulfur coals, various coal blends, and inlet NOx ranging from 0.34 to 0.45 lb/MMBtu. The acceptance tests indicate that all systems met or exceeded design requirements. 46

Detailed results have been published for one of the units, Trimble County Generating Station Unit 1, which fires high sulfur (~4%) eastern bituminous coal. The

44 R. Peltier, Top Plants: Seminole Generating Station, Palatka, Florida, Power, October 1, 2009; http://www.powermag.com/coal/Top-Plants -Seminole-Generating -Station-PalatkaFlorida_2181_p4.html , accessed August 18, 2011 (Exhibit 21).

45 K. Bresnahan, C. Erickson, M. Phillipo, S. Dean, and B. Rogan, Design, Installation and Startup Experience on a High Removal Efficiency SCR System at Morgantown Generating Station Units 1&2, Mega 2008; http://secure.awma.org/presentations /Mega08/presentations/5-Erickson.pdf , accessed August 18, 2011 (Exhibit 22).

46 E. Saunders, S. Straight, E. Pear, C. Erickson, H. Culberson, and M. Kelly, SCR System Performance at LG&E’s Trimble County Generating Station, EPRI Workshop on Selective Catalytic Reduction, Atlanta, GA, October 22-23, 2002; www.babcockpower.com/pdf/t-177.pdf , accessed August 18, 2011 (Exhibit 23).12 SCR was designed to reduce NOx from 0.32 lb/MMBtu by 90% to 0.032 lb/MMBtu with 2 ppm ammonia slip and an SO 2 to SO 3 conversion of 1.5%. These units were designed and installed before low SO 2 conversion catalyst had been developed. 47 Trimble was a difficult retrofit application with spac e restrictions and a high sulfur fuel. 48 The acceptance testing, which occurred in Se ptember 2002, yielded the results summarized in Table 4.

Table 4: Trimble County acceptance test results a

a C. Erickson, S. Straight, and L. Hutcheson, Coal-Fir ed SCR Operating Experience with High Removal Efficiency

and Low-NOx Firing Systems, 2003; http://www.babcockpower.com/pdf/t-188.pdf , accessed August 18, 2011, attached as Exhibit 25
This work concluded: “Based on Riley Power Inc. analysis and industry experience... mixing systems with <3% standard deviation can obtain ultra high NOx removal efficiencies of >93% wi th the correct catalyst volume.” 49

iv. Cliffside Unit 5

An 85% efficient SCR was originally installed on Duke Energy’s 590 MW Cliffside Steam Station Unit 5 in May 2002. The unit burns 1.5% Central Appalachian bituminous coal. This unit was upgraded in 2003 to meet the NOx SIP Call limit during the ozone season. The demonstration test in dicate: “[T]he SCR system for the Unit 5 boiler at the Cliffside steam station operated at 93% NOx removal with the ammonia to NOx ratio variation within 5% for each reacto r. While the SCR is not currently operated at this high NOx removal rate, the test results showed that the SCR is able to operate at

47 J. Cooper, W.J. Gretta, A.C. Favale, and H.N. Fran klin, First Application of Babcock-Hitachi K.K. Low SO 2 to SO 3 Oxidation Catalyst at the IPL Petersburg Gene ration Station, ICAC Clean Air Technologies and Strategies, March 2005; http://www.hitachipowersystems. us/supportingdocs/forbus/hpsa /technical_papers/ICAC2005.pdf
, accessed August 18, 2011 (Exhibit 24).

48 E. Saunders et al. (Exhibit 23).

49 C. Erickson et al. (Exhibit 25).13 high NOx removal without added risk to the catalyst or causing excessive ammonia slip.” 50

v. Cope Generating Station

The SCE&G 400 MW Cope Generating Stat ion burns bituminous coal. The SCR was designed to reduce the NOx from an outlet of 0.32 lb/MMBtu to 0.032 lb/MMBtu based on 90% NOx reduction. The guaranteed SO 2 oxidation was 1% at 688 F. The performance tests demonstrated NOx re moval at 91.6% with an average SO 2 /SO 3 oxidation rate of 0.3%. 51

d) SCR Experience with Boiler Retr ofits in the United States
The Institute of Clean Air Companies (“ICAC”) May 2009 White Paper on SCR 52 compiled information showing that over 300 SCR systems have been installed on coal fired-boilers in the U.S. 53 to meet various regulatory programs. 54 Most of the SCRs on coal-fired boilers are designed for about 90% NOx removal. 55 About a third or 118 of these SCRs serve units 300 MW and lower in ou tput. Ten SCR system included in this summary operate on boilers that are 100 MW or under. ( See Attachment 2.) The size of the boiler does not affect the performance of SCR.

These SCRs are individually lis ted in the ICAC White Paper. 56 Over 95% of these listed SCRs were installed on existing facilitie s as retrofit applications, indicating that that 90% or greater NOx removal is routine for retrofit units such as Reid Gardner. This is supported by information compiled from EPA’s CAMD, which reports the year each boiler was installed and its controls. This analysis, attached as Attachment 2 57 , shows that almost all of the existing SCRs, 94% of those included in the CAMD database, were installed on units that were built before th e first SCR was installed in the U.S. in 1994.

50 T.R. Ake, C.A. Erickson, and L. K. Hutcheson, Increasing SCR NOx removal from 85% to 93% at theDuke Power Cliffside Steam Station, April 2006 ASME Power Division Special Section, ENERGYTECH.com, www.babcockpower.com/pdf/rpi-13.pdf , accessed August 19, 2011 (Exhibit 26).

51 S. Zwayyed, T. Pearson, and T. Reynolds, Low Main tenance SCR at the South Ca rolina Electric and Gas Cope Generating Station Unit 1, PowerGen 2009 (Exhibit 27).

52 Institute of Clean Air Companies, White Paper, Selective Catalytic Reduction (SCR) Control of NOx Emissions from Fossil Fuel-Fired Electric Power Plants, May 2009, EPA-R09-OAR-2009-0598-0032, (hereinafter “ICAC 2009 White Paper on SCR”) (Exhibit 28).

53 Ibid ., p. 7.

54 Ibid ., pp. 4-5.

55 Ibid ., pp. 7 and 12.

56 Ibid ., pp. 23-29.

57 Information compiled from EPA’s CAMD database, which reports the year each boiler was installed and its controls.14 And of these, the majority (84%) are installe d on pre-New Source Performance Standard (“NSPS”) units that were built prior to 1978. A further compilation of SCR control efficiency data from vendor experience lis ts, technical papers, and McIlvaine databases (Attachment 3) shows that SCR design NOx co ntrol efficiency has increased over time, from around 50% on the first units in the 1990s to 90%+ on SCRs designed from 2000 onward. Thus, the existing installed SCR base is retrofit SCRs. The majority of these retrofitted units operate under various tradin g programs without permit limits and they are not obligated to meet any specific NOx emission limit

Further, the ICAC report notes that SCRs are being designed to achieve NOx emission rates of 0.04 lb/MMBtu 58 , substantially lower than the 0.083–0.098 lb/MMBtu established by NDEP as controlled emissi on levels for Reid Gardner Units 1-3. 59 In most instances, a retrofit SCR can achieve the sa me NOx reduction efficiency as an SCR on a new facility. The catalyst and the rest of the SCR system starts out new in both cases and treats the exhaust gas from the same coal . The only retrofit exception would be the lack of adequate space to optimize ductwo rk layout to achieve adequate mixing of ammonia with the flue gas. CH2MHill’s BA RT Analyses for Reid Gardner Units 1-3 indicate no such limitation and this issue ha s not been raised in the docket. Even if it existed, it could be addressed by locati ng the SCR at the tail end of the plant.

e) Existing SIP BART Emission Limits
EPA’s BART Guidelines require permi tting agencies to “consider recent regulatory decisions... when identifying an emissions performance level” that can be achieved by available pollution-reduction methods. 60

The Texas Commission concluded in 2001 that a NOx emission limit of 0.03 lb/MMBtu was “technically feasible in the commission’s analysis, based on the literature and discussion with SCR vendors. REI [Reliant Energy Inc., now NRG, owner of the Texas Parish units] has awarded a contract for construction of SCRs on its four coal-fired boilers with an emission sp ecification of 0.03 lb NOx/MMBtu, which supports the commission’s view that the tec hnology has the capacity to achieve this level.” 61 The Commission then established emission limits of 0.033 lb/MMBtu for the Dallas/Fort Worth nonattainment area and 0.040 lb/MMBtu for the Houston/Galveston nonattainment area for coal-fired boilers. 62

58 Ibid. , p. 7.

59 10/22/09 NDEP BART Review, pp. 5-6.

60 70 FR 39166 (July 6, 2005).

61 Texas Register, v. 26, no. 2, January 12, 2001, p. 557 (Exhibit 29). See also: B. Butler and R.P. Gaikwad, Operating Experience of SCRs at Texas Genco’s Coal and Gas Fired Plants, Mega Symposium, 2004 (Exhibit 30).

62 Texas Register, v. 26, no. 41, October 12, 2001, pp. 8159-8163, (Exhibit 31).15 These limits were subsequently modified and incorporated into the Texas SIPunder a cap and trade program. The current ozone SIP for the Houston-GalvestonBrazoria area specifies NOx emission limit s for wall-fired units of 0.05 lb/MMBtu and for tangential-fired boilers of 0.045 lb/MMBt u, based on daily and 30-day averaging periods. 63 The Texas SIP limit for wall-fired boilers, expressed as both a daily and 30-day average, is lower than the BART lim it we recommend for each of the three wallfired Reid Gardner units (0.05 lb/MMBtu). Th e docket contains no discussion of the Texas SIP limits or any evidence that the wall-fired limit of 0.05 lb/MMBtu based on a 30-day rolling average could not be achieved at Reid Gardner.
f) Existing Permit Limits
Permits have been issued to several facilities burning a wide range of coals, including the same coal burned by Reid Gardner. These permits, discussed below, require the use of combustion controls an d SCR to meet much lower NOx limits. These permits, considered within the framework of constraints unique to Reid Gardner, should establish BART.

Most of these permits have been issued for new units while Reid Gardner is an existing facility that would require retrofit of combustion controls and SCR. While inadequate space can elevate the cost, space constraints can generally be addressed by applying good SCR design practices, includ ing locating the SCR at the tail end of the exhaust system. There is no evidence of space constraints at Reid Gardner.

These permits should serve as a guide in setting BART emission limits for the Reid Gardner units. The BART Guidelines no te: “... if there is a permit requiring the application of a certain technology or emission limit to be achieved for such technology, this usually is sufficient justification for yo u to assume the technical feasibility of that technology or emissions limit.” 64 There are many such permits that are not discussed in the Reid Gardner docket.

i. Desert Rock Energy Center In July 2008, EPA Region 9 issued a PSD permit to Desert Rock Energy Center 65 for two 750 MW boilers. This permit sets em ission goals based on SCR design. These goals are evaluated during a 5-year “NOx Opt imization Period” negotiated with the Permittee. A 5-year optimization period was ch osen to encompass a complete catalyst

63 30 TAC Rule 117.1210(a)(1)(B).

64 70 FR 39165 (July 6, 2005).

65 U.S. Environmental Protection Agency, Region 9, PSD Permit Issued Purs uant to Requirement at 40 CFR 52.21, PSD Permit Number AZP 04-01, Desert Rock Energy Company, July 31, 2008 (Exhibit 32).16 lifecycle plus additional time to compile and analyze operating data. An optimization period approach was selected to address un certainty in performance of SCR with the coal to be fired at Desert Rock (Navajo Mine ) due to its elevated ash and nitrogen levels compared to the then-best performing Parish units, which burn PRB coal. 66 A 5-year optimization period is, however, excessive. An y uncertainty in SCR performance can be resolved in much less time. Any limit within 5 years of rule promulgation would be acceptable for BART.

The Desert Rock permit requires the Permittee to design the SCR system to achieve a NOx limit of 0.035 lb/MMBtu on a 365-day rolling average basis. Prior to construction, the Permittee must submit desi gn specifications as proof that the SCR systems are designed to achieve this limit. The Permittee is also required to submit a catalyst management plan, which lays out th e measures that will be taken to maintain the system and optimize its performance. The NOx permit limits are as follows:

Table 5: Desert Rock NOx permit limits (lb/MMBtu)

NOx Limit Optimization Period Final Limit 24-h r 0.060 0.060 30-day 0.05 365-day 0.05 0.035 a U.S. Environmental Protection Agency, Region 9, EPA Responses to

Public Comments on the Proposed Prevention of Significant Deterioration Permit for the Desert Rock Energy Facility, July 31, 2008 (Exhibit 33)
During the Desert Rock optimizatio n period, the NOx emission limits are: 0.05 lb/MMBtu (365-day rolling average) an d 0.060 lb/MMBtu (24-hour block average). Following the optimization period, the emission limits are 0.035 lb/MMBtu 67 (365-day rolling average), 0.05 lb/MMBtu (30-day ro lling average), and 0.06 lb/MMBtu (24-hr block average) unless a demonstration is ma de, and EPA approves, that an adjustment is required.

The Desert Rock Permit does not contain a backstop on the adju stment, either up or down and thus is not consistent with BA RT. The BART process requires the best limit

66 U.S. Environmental Protection Agency, Region 9, EPA Responses to Public Comments on the Proposed Prevention of Significant Deterioration Permit fo r the Desert Rock Energy Facility, July 31, 2008 (Exhibit 33).

67 We believe the limit of 0.0385 lb/MMBtu in Condition IX.E.4 should have been 0.035 lb/MMBtu, as Condition IX.E.2.a requires the SCR to be designed to achieve 0.035 lb/MMBtu and supporting notes in the Desert Rock docket identify 0.035 lb/MMBtu as the limit that was discussed. See Notes from October 16, 2007 U.S Environmental Protecti on Agency/Sithe Conference Call, Desert Rock Docket ID EPA-R09- OAR-2007-1110-0091 (Exhibit 34).17 that is feasible to be set. We recommend a similar approach, but with a firm BART backstop and a shorter optimization period. Our proposed BART limits do not allow backsliding below 0.05 lb/MMBtu.

ii. Plant Washington

In April 2010, the Georgia Department of Natural Resources issued a permit to Plant Washington for one 850 MW boiler that will burn PRB coal or up to a 50/50 blend of eastern bituminous coal (Illinois #6) and sub-bituminous coal. 68 The 50/50 blend will contain up to 2.23% sulfur and 7.6% ash. The I llinois #6 coal it will burn will contain up to 11.6% ash and 3.93% sulfur. 69 The NOx emission limits are: 0.050 lb/MMBtu based on a 30-day rolling average and 0.030 lb/MMBtu based on a 12-month rolling average while firing sub-bituminous coal or a computed weighted average on a 12-month rolling basis based on the heat rate weight am ount of each, assuming the bituminous coal contributes 0.044 lb/MMBtu to the weigh ted average. The annual average becomes effective 6 months after initial startup of the coal boiler, allowing a 6-month optimization period.

iii. Other Permits

Permits with low NOx emission limits fo r facilities operating SCR and burning a wide range of coals include:

 0.05 lb/MMBtu (30-day rolling average), Dallman Unit 4, IL (8/06) 70

 0.05 lb/MMBtu (30-day rolling average) , Sunflower Holcomb, KS (12/10) 71

 0.05 lb/MMBtu (12-month rolling average), Wygen 3, WY (2/5/07) 72

 0.05 lb/MMBtu (12-month rolling average), Dry Fork, WY (10/15/07) 73

68 Georgia Department of Natural Re sources, Air Quality Permit, Plan t Washington, Permit No. 4911-303- 0051P-010-0, April 8, 2010; http://airpermit.dnr.state.ga.us/gaa irpermits/PermitPDF.aspx?id=PDF-PI17924 , accessed August 22, 2011 (Exhibit 35).

69 Power4Georgians, LLC, Prevention of Significant Deterioration Air Permit Application, Plant Washington, November 26, 2008, Supplemental Data, Exhibit A: Emission Calculations, Table A-2 (Exhibit 36).

70 Illinois EPA, Construction Permit – PSD Approval, NSPS Emission Units, Dallman Unit 4, August 10, 2006, p. 4-13. (Exhibit 37). Limit exclud es startups, shutdowns, and malfunctions.

71 Kansas Department of Health and Environment, Air Emission Source Construction Permit, Holcomb Station, December 16, 2010, p. 7; http://www.kdheks.gov/bar/s unflower/Final_Permit.pdf , accessed on August 21, 2011 (Exhibit 38). Limit expressed as boiler day average and excludes startups and shutdowns, setting separate limits for them.

72 Wyoming Department of Environmental Quality, Bl ack Hills Corporation, Wygen 3, Permit No. CT4517, February 5, 2007 (Exhibit 39).18  0.05 lb/MMBtu (12-month rolling av erage), Spruce, TX (6/28/05) 74

 0.05 lb/MMBtu (annual average), Longleaf, GA (5/14/07) 75

 0.067 lb/MMBtu (24-hour average), Newmont, NV (5/5/05) 76
Dallman, which burns a high ash, high sulfur Illinois coal and Wygen 3 and Newmont, which burn PRB coals, are in operation.
g) Other Considerations for Establishing SCR Limits
The record for the proposed action does not contain any indication that permits issued to other facilities, regulatory determinations, consent decrees, or other information were taken into consideration to establish the proposed BART limits. We conclude that – by virtue of its failure to address these lower achievable NOx emissions – EPA has not established BART for Reid Gardner. As the following comments show, NOx emission limits have been establishe d for similar facilities in permits and regulatory decisions that are much more aggr essive than or equivalent to those that we propose as BART for Reid Gardner.

i. San Juan Generating Station

The San Juan Generating Station (“SJGS ”), operated by the Public Service Company of New Mexico (“PSC NM”), consists of four boilers. Unit 1 is a 360-MW wall-fired boiler; Unit 2 is a 350-MW wall-fired boiler; and Units 3 and 4 are 544-MW opposed wall-fired boilers. The San Juan boilers were previously retrofitted with new low NOx burners, overfire air, and neural networks under a prior Consent Decree and thus have lower NOx outlet emissions of 0.30 lb/MMBtu 77 than the Reid Gardner boilers. 78

73 Wyoming Department of Environmen tal Quality, Basin Electric Power Corp., Dry Fork Station, Permit No. CT-4631, October 15, 2007 (Exhibit 40).

74 Texas Department of Environmental Quality, Spru ce Special Conditions, Permit Nos. 70492 and PSDTX-1037, June 28, 2005 (Exhibit 41).

75 Georgia Department of Natural Resources, Air Quality Permit No. 4911-099-0030-P-01-0, Longleaf Energy Associates, LLC, May 14, 2007 (Exhibit 42).

76 State of Nevada, Bureau of Pollution Control, Class I Air Quality Operating Permit, General Requirements, No. AP4911-1349, issued to Newm ont Nevada Energy Investment, LLC, May 5, 2005 (Exhibit 43).

77 Public Service Company of New Mexico, San Juan Generating Station, Best Available Retrofit Technology Analysis, prepared by Black & Veatch, June 6, 2007 (Exhibit 44).

78 NDEP baseline: 0.447-0.462 lb/MMBtu, see Tables 2 and 3.19 On January 5, 2011, EPA Region 6 proposed a NOx BART determination for these units under a Federal Implementation Plan (“FIP”) for New Mexico. The EPA proposed to require SJGS to meet an emi ssion limit of 0.05 lb/MMBtu individually at each unit, for a 30-day rolling average, based on a calendar day. This NOx limit is achievable by installing and operating SCR. Be cause the visibility analysis relied in part on assumptions as to the amount of ammoni a that would slip out of the SCR and the amount of SO 2 that the SCR catalyst would convert to sulfuric acid, the EPA also proposed a limit on ammonia slip of 2 ppm and on sulfuric acid of 0.000106 lb/MMBtu, based on an SCR catalyst SO 2 to SO 3 conversion of 0.5%. 79 These limits are consistent with those that we propose for Reid Gard ner. On August 4, 2011, the EPA adopted the Final SIP for New Mexico which establis hes a NOx BART limit of 0.05 lb/MMBtu based on a 30-day rolling average boiler operating day and requires that the NOx control device be designed to meet an ammonia s lip limit of no greater than 2.0 ppm. The New Mexico FIP establishes a sulfuric acid mist emission limit of 0.00026 lb/MMBtu and a five-year compliance period. 80

ii. Glades Power Park

In addition, Florida Power and Light (“ FP&L”) filed an application in March 2007 for the Glades facility, two 980-MW boilers firing similar bituminous coal (0.5-1.3% sulfur; 6-15% ash) with up to 20% coke. The proposed NO X BACT limit was 0.05 lb/MMBtu based on a 24-hour rolling average. 81 This facility was rejected by the Florida Public Service Commission based on need, but nevertheless, demonstrates that FP&L considered this limit to be achievable. This FP&L limit is more stringent than the 0.05 lb/MMBtu limit based on a 30-day rolling average we propose because to meet it, the 30-day average must be lower than the 24-hour limit.

iii. Baldwin Station

The Baldwin Station in Illinois, consisti ng of three 585-MW coal-fired units, was subject to an NSR enforcement action. 82 Matt Haber, EPA Region 9’s BACT expert and current Deputy Director of the Air Division, f iled an expert report with the court in the Baldwin case. His report included historic BACT analyses for the Baldwin units. 83

79 76 FR 503, 505, 507 (January 5, 2011).

80 See, New Mexico FIP (Exhibit 1).

81 Golder Associates, Inc., Air Construction Perm it Application and Prevention of Significant Deterioration Analysis for FPL Glades Power Park, Glades County, Florida, Prepared for Florida Power & Light, December 2006, Table 2-1 (Exhibit 45); Florida Power & Light Glades Response to EPA Comments, March 26, 2007, p. 2 (Exhibit 46).

82 United States v. Illinois Power Co., 245 F. Supp. 2d 951 (S.D. Ill. 2003).

83 Matt Haber, Best Available Control Technologies for the Baldwin Generating Station, Baldwin, Illinois, Prepared for the United States in connection with: United States v. Illinois Power Company and Dynergy20 (A BACT determination is similar to a BART determination.) Mr. Haber’s report included a BACT determination for Baldwin Unit 3, a tangentially fired unit burning PRB coal. He concluded that BACT fo r NOx for Baldwin Unit 3 as of 2002 was 0.015 lb/MMBtu for a new unit and 0.020 lb/MMBtu for a retrofit unit, based on a 3-hour average, achieved using low-NOx burners, SCR, and a combustion optimization system. This limit could be adjusted as high as 0.04 lb/MMBtu if a lower limit was demonstrated to be unachievable. This is co nsistent with conclusions in the notice for the Texas SIP and a subsequent permit issued by Region 9 for Desert Rock and is much more aggressive than our proposed BART limits for Reid Gardner.

I.A.2 Cost-Effectiveness at Other Facilities Must Be Considered

The BART Guidelines indicate that “in cases where recent retrofits have costeffectiveness values that are within what has been considered a reasonable range, but your analysis concludes that costs for the source being analyzed are not considered reasonable (A reasonable range would be a ran ge that is consistent with the range of cost effectiveness values used in other simil ar permit decisions over a period of time.) ... you should provide documentation of any unusual circumstances that exit for the source that would lead to cost-effective ness estimates that would exceed those for recent retrofits.” 84 This is the situation here. NDEP has eliminated SCR options based on costs that have been found to be cost-effect ive in many other similar permit decisions without documenting any unusual circumstan ces. The conclusion is based on an erroneous interpretation of incremental cost-e ffectiveness. The control costs found to be cost-effective in other similar decisions are summarized below.

The State of New Mexico concluded that SCR designed to achieve a NOx emission rate of 0.03 to 0.07 lb/MMBtu was co st-effective for the San Juan Generating Station. The average cost-effe ctiveness was $5,946/ton to $7,398/ton. 85 The corresponding incremental cost-effectivenes s values relative to ROFA/Rotamix, the same combination proposed as BART fo r Reid Gardner, ranges from $7,339/ton to $7,765/ton. 86 EPA Region 6 agreed with New Mexico and required SCR designed to meet a NOx limit 0.05 lb/MMBtu based on a 30-day rolling boiler operating day

Midwest Generation, Inc., Civil Action No. 99-833-MJR, in the U.S. District Court for the Southern District of Illinois, pp. 2, 48-52 (Exhibit 47).

84 70 FR 39168.

85 New Mexico Environment Department Air Qualit y Bureau, BART Determination, Public Service Company of New Mexico, San Juan Generating Station, Units 1-4, June 21, 2010, Table 10 and p. 33; available at http://www.nmenv.state.nm.us/aqb/reghaz/doc uments/AppxA_NM_SJGS_ NOxBARTDetermination _06212010.pdf , accessed August 21, 2011 (Exhibit 49).

86 Ibid

.21 average. The final cost effectiveness values for the San Juan units, after correcting the company’s inflated cost analyses, ranged from $1,757/ton to $2,219/ton. 87 Similarly, Region 9 itself has proposed SCR as BART for Four Corners designed to meet a NOx emission rate of 0.11 lb/MMBtu at $2,515/ton to $3,163/ton, 88 after adjusting the company’s inflated costs, which ranged from $4,343/ton to $5,484/ton. 89 In fact, BART determinations have been found cost effect ive at values ranging up to $15,920/ton, as summarized in Exhibit 48.

Cost-effectiveness values calculated to establish BACT under the New Source Review (“NSR”) program, which uses identical cost metrics, guidance, and relies on the same underlying Cost Manual, have a long history of establishing SCR as satisfying BACT at cost-effectiveness values ran ging from $2,000/ton to over $10,000/ton. ( See comments filed by EPA in the Milton R. Young case 90 and supporting documentation for these determinations included in Exhibits 51 to 86.)

I.B The Reid Gardner NOx Cost Analys is Is Fundamentally Flawed
The initial cost analyses for Reid G ardner Units 1-3 were prepared for Nevada Energy by the consulting company CH2M Hill in October 2008 (“the Company Cost Analyses”). They are found in Appendix A to the 10/08 CH2MHill BART Analyses, respectively. The NDEP adopted this cost an alysis wholesale, reporting unaltered costs from it in its October 22, 2009 review of the company’s BART Analyses. 91 The capital cost, first year O&M costs, first year debt serv ice and total annual cost exactly match the costs reported in the 10/08 CH2MHill BART Analyses, Appendix A. Thus, NDEP’s BART determination, and EPA’s proposal to approve it, are based on the October 2008 CH2MHill cost analysis. The cost analysis is important because NDEP rejected the most effective NOx control options, using SCR, ba sed on cost. We found no evidence in the record that any party critically reviewed th e company’s cost analysis. The company cost analyses are unsupported and deviate in si gnificant ways from the methodology used in regulatory cost analyses.

87 New Mexico FIP (Exhibit 1).

88 75 FR 64,227

89 74 FR 44,318, Table 3.

90 Letter from Andrew M. Gaydosh, Assistant Regional Administrator, EPA Region 8, to Terry O’Clair, Director, Division of Air Qualit y, North Dakota Department of Health, Re: EPA’s Comments on the North Dakota Department of Health’s April 2010 Dr aft BACT Determination for NOx for the Milton R. Young Station, May 10, 2010 (Exhibit 50).

91 Compare 10/08 CH2MHill BART Analyses, Appx. A, Tables ‘Input Calculations’, and 10/22/09 NDEP BART Review, Table 1.22 While NDEP relies on the company’s total annual cost, it deviates in calculating cost-effectiveness metrics expressed in do llars per ton and in evaluating their significance. First, NDEP changed the NOx ba seline that it uses to calculate costeffectiveness values in dollars per ton wi thout making adjustments to the company’s annual cost. This invalidates the cost effe ctiveness analysis. Second, the NDEP adopted a novel “clear break” theory to reject the top NOx control technologies using SCR based on a misinterpretation of EPA’s BART Guid elines regarding average and incremental cost-effectiveness. The following sections cr itique the company’s cost analysis, discuss the impact of the mismatch between the base line and the cost analysis, and explain why the cost rejection method is invalid. In su m, NDEP and EPA inappropriately rejected the best system of continuous NOx reductio n, SCR, based on an unsupported cost analysis, sole reliance on incremental co st analysis and a misinterpretation of incremental cost-effectiveness. We revised the cost analysis and conclude that BART for NOx at Reid Gardner Units 1-3 is LNB/OFA and SCR designed to meet a NOx emission limit of 0.05 lb/MMBtu based on a 30-day rolling average based on a boiler operating day.

I.B.1 The Costs to Install SCR on R eid Gardner Are Overestimated
The original company cost analysis wa s relied on by both NDEP and EPA in making their BART determination. NDEP re lied on costs prepared by CH2MHill for NV Energy contained in the 10/08 CH2MHill BART Analysis, Appendix A. In addition, in response to comments, NDEP prepared an al ternative cost-effectiveness analysis to demonstrate that its conclusions as to the co st-effectiveness of SCR would not change if assumed costs were lower. 92 Both of these cost analyses overestimate costs and contain
many errors.
The company cost analyses included in Appendix A to the 10/08 CH2MHill BART Analyses consist of a series of spre adsheets provided in PDF format. The inputs and calculations used to generate the variou s cost estimates in these spreadsheets are unsupported in the record that was availabl e for review. We requested copies of these spreadsheets so that we could review the form ulas and underlying assumptions used to make the cost calculations. 93 The spreadsheet provided by NDEP did not contain the underlying assumptions and calculations but only “NDEP’s Economic Analysis Summary.” 94 The original analyses were likely prepared in Excel spreadsheets, which allow the inputs and formula used in the calcul ations to be inspected. It is standard practice to produce the original spreadsh eets so the basis of calculations can be examined.

92 Nevada RH SIP, Appendix D, pp. D-65 - D-68.

93 Email from to Andrew Gray, Gray Sky Solutions, to Adele Malone, NDEP, Exhibit 20.

94 Excel spreadsheet ‘Copy Acid Rain Annual Data BA RT NVE (4).xls’ provided by NDEP (Exhibit 20).23 Thus, we reverse-engineered the spread sheets and converted them into Excel spreadsheets that show the embedded formul as and assumptions for just the LNB/OFA with SCR scenario (option 4). We selected this scenario to analyze as it is the best system of continuous reduction for NOx emissions fr om the three Reid Gardner units and thus satisfies BART. We first replicated the re sults in the 10/09 CH2MHill BART Analyses, Appendix A. Our calculations match the CH2M Hill calculations within a few percent. Differences are due to rounding. Our spread sheets are included in Attachments 4a, 4b and 4c.

We next evaluated the assumptions used in this company cost analysis. Our comments are discussed below. Based on th is review, we revised the company cost analyses to correct the errors and omission s that we found. The revised cost analyses are attached as Attachments 5a, 5b, and 5c. Ou r revisions significantly reduced the cost of using SCR in the usual configuration, wi th LNB plus OFA, as summarized below in Table 6. The cost-effectiveness values in this table are based on the original baseline NOx emissions assumed in the company analysis, not the revised baseline NOx emission, subsequently adopted by NDEP. If NDEP’s approach of simply modifying the baseline emissions without making concomit ant changes in the costs were used, the revised cost number would be even sma ller as NDEP increased the NOx baseline, which increases NOx reductions and hence reduces cost-effectiveness.

Table 6: Average cost-effectiveness for control option 5: LNB/OFA + SCR ($/ton NOx)

Unit NDEP a Revised b

1 3,583 2,179 2 3,334 2,040 3 4,159 2,519

a See Exhibit 4a, 4b, and 4c, respectively. These differ slightly from those reported in the 10/09 CH2MHill BART Analyses, Appendix A due to rounding (3578, 3332, 4155)
b See Exhibit 5a, 5b, and 5c, respectively

As discussed in Comment I.A.2, both th e original and revised average costeffectiveness values are within what has b een considered a reasonable range in other similar permit decisions.24 a) Multiple Unit Discounts
The vendor costs relied on by NV En ergy were estimated on a per-generating unit-basis and are identical for all three units. 95 There is no evidence that multiple unit discounts were factored into the cost analys is. Considerable savings could be achieved in capital costs and labor by designing and constructing all three units in one fell swoop or constructing a single SCR syst em to serve the three units.

There are many economies involved in de signing, procuring, and installing all three units from the same vendor. Only one system must be designed, which could be replicated for the other two units, reduci ng engineering and shop setup time. Thus, vendors typically offer discounts for awards of multiples of the same system.

Capital and labor costs also could be reduced by combining processing units, e.g. , a single ammonia delivery and injection syst em and single balance of plant facilities. Installing three separate SCR units essentia lly triples the balance of plant labor and increases capital costs. Common facilities should have been designed and costed.

We cannot precisely estimate the reduct ion in cost from taking into account multiple units because NV Energy did no t supply the underlying vendor quotes. However, based on our experience, vendors would offer at least a 5% discount on equipment cost for multiple identical units. The revised cost analyses in Attachments 5a, 5b, and 5c assume a 5% re duction in the vendor quoted costs.

b) AFUDC
The CH2MHill cost estimates upon wh ich NDEP relied include a charge for interest during construction, estimated as 16% of “Major Materials Design and Supply Construction.” This charge, generally called “allowance for funds during construction” or AFUDC, is disallowed in EPA’s Cost Manual for SCRs. 96 NDEP ultimately relied on the Cost Manual as NDEP adopted the Company’s analysis wholesale and the Company’s analysis claims to have followed it. 97 EPA’s position on AFUDC was

95 Compare 10/09 CH2MHill BART Analyses, Appx. A, Tables ‘Economic Analysis Summary’ and ‘Input Calculations,’ respectively.

96 U.S. Environmental Protection Agency, EPA Air Pollution Control Cost Manual, Report EPA/452/B02-001, 6th Ed., January 2002, http://www.epa.gov/oaqps001/lead/pdfs/2002_01_cost_control_%20manual.pdf , accessed August 19, 2011 (Exhibit 87) (hereinafter “Cost Manual”), pdf p. 486, Table 2.5, E (Allowance for Funds during Construction) = 0. The EPA Air Pollution Control Cost Manual is the current name for what was previously known as the OAQPS Control Cost Manu al, the name for the Cost Manual in previous (pre-2002) editions of the Cost Manual.

97 10/08 CH2MHill BART Analyses, p. 3-3, respectively.25 recently upheld in the final FIP for San Juan. 98 Thus, we set AFUDC equal to zero in our revised cost analyses.

AFUDC is an accounting method. Asse ts under construction do not provide service to current customers and thus associ ated interest and allowed return on equity are not charged to current customers. Instea d, AFUDC capitalizes these costs and adds them to the rate base so that they can be recovered from future customers when the assets are used. Thus, these charges represent future cash income to the utility. In other words, AFUDC is the accumulated cost of carrying capital and holding it waiting to spend, so money can be made in the future, by selling electricity. Future income should not be charged against the cost of a SCR in a BART cost-effectiveness analysis. These costs are not part of the constant-dollar approach found in the EPA Control Cost Manual and should not be included in BART cost-effectiveness analyses.

c) Owner’s Cost
The NV Energy cost analyses include ow ner’s costs as a separate capital cost, estimated as 5% of “Major Materials Design and Supply Construction.” These are presumably costs incurred by the owner in managing and implementing a capital project. While owners do incur some cost s, owners generally do not manage and implement capital projects, but rather reta in engineering firms, called the owner’s engineer, to perform these functions or more commonly, hire an engineering, procurement, and construction (“EPC”) contractor to perform the project for a fixed cost. Owner’s costs are not separately included in BART cost-effectiveness analyses and have been more than double-counted here. In its May 10, 2010 formal comments to the North Dakota Department of Health, for example, EPA rejected the inclusion of “owner’s costs” in cost analyses for Milton R. Young. 99 It has also rejected these costs for Four Corners, 100 and San Juan 101 generating stations. Thus, we set owner’s cost equal to zero in our revised cost analyses.

98 New Mexico FIP (Exhibit 1), p. 37 (“Future income should not be charged against the cost of a SCR in a BART cost-effectiveness analysis. These costs are not part of the constant dollar approach found in the Cost Manual and should not be included in BART cost-effectiveness analyses.”).

99 Letter from Andrew M. Gaydosh, Assistant Regional Administrator, EPA Region 8, to Terry O’Clair, Director, Division of Air Qualit y, North Dakota Department of Health, Re: EPA’s Comments on the North Dakota Department of Health’s April 2010 Draft BACT Determination for NOx for the Milton R. Young Station, May 10, 2010 (Exhibit 50).

100 See Four Corners Technical Support Document, Exce l spreadsheet entitled “Four Corners SCR Cost Analysis 8-26-10,” from the Four Corners docket #EPA-R09-OAR-2010-0683 (Exhibit 88), Row 52.

101 New Mexico FIP (Exhibit 1), p. 9 (“As explained more fully in our Complete Response to Comments for NM Regional Haze/Visibility Transport FIP document, we also agree with the USFS that owner's costs are not an appropriate cost item to include in a BART co st estimate, as owners are not included in the Cost Manual.”)26 d) Contingency and Surcharge
The NV Energy cost analyses include a contingency estimated as 15% of the “Major Materials Design and Supply Cons truction” and a “surcharge” estimated as 16% of the “Major Materials Design and Su pply Construction.” The record does not explain what is included in the surcharge or what the contingency covers. No basis is provided for these cost adders.

A contingency factor in a regulatory cost-effectiveness analysis “should be reserved (and applied to) only those it ems that could incur a reasonable but unanticipated increase but are not directly related to the demolition, fabrication, and installation of the system.” 102 An example would be a hundred-year flood that postpones delivery of materials, but their time ly arrival at the job site is not a problem unique to the retrofit. The standard contin gency factor used in a cost-effectiveness analysis, when it is included, is 3% of purchased equipment cost. 103 Thus, we revised the contingency in our cost analysis to us e 3% of “Major Materials Design and Supply Construction.”

e) Capital Recovery
The NV Energy cost analyses annualized total capital cost using a first year debt service calculation. This calculation is equiva lent to the capital recovery method used in regulatory cost analyses. 104 However, the variables used to annualize capital costs are not consistent with those used in regulatory analyses.

A capital recovery factor (“CRF”) is used to convert a present value into a stream of equal annual payments over a given time at a given interest rate. Under EPA’s Control Cost Manual methodology, total capi tal costs are annualized by calculating an annual payment sufficient to finance the invest ment over its entire life. This payment is calculated by multiplying the total capital investment by a capital recovery factor calculated from a formula based on interest rate and equipment lifetime. The CRF is given by:

CRF = [ i(1+i) n ]/[(1+i) n -1 ]

where “i” is the interest rate and “n” is the life of the pollution control equipment. In essence, annualization establishes an annual payment sufficient to finance the capital

102 Cost Manual, Chapter 2, Cost Estimation: Concepts and Methodology, Sec. 2.5.4, p. 2-30, pdf 44.

103 See , for example, Cost Manual, Section 5.2, Post-Combustion Controls, Chapter 1: Wet Scrubbers for Acid Gas, Table 1.3 and Section 6, Chapter 1: Baghouses and Filters, Table 1.9.

104 Cost Manual, pdf 35, Equations 2.7 and 2.8.27 investment for its entire life. 105 This payment is equivalent mathematically to the first year debt service used in the NV Energy co st analyses. The longer the equipment life and the lower the interest rate, the lower th e annualized capital costs and the lower the cost effectiveness in $/ton of pollutant reduced.

NV Energy calculated capital recovery costs assuming an interest rate of 8.55% and an SCR lifetime of 20 years. This is in consistent with the Cost Manual, which requires that the CRF be based on an intere st rate of 7% and the actual lifetime of the control equipment. 106

i. SCR Lifetime

The lifetime used to calculate the capital recovery factor is the actual (or anticipated) service life of the equipment. In BART analyses, the lifetime of a retrofit SCR is generally set equal to the re maining useful life of the facility. 107 The record is silent on the remaining useful life of the Reid Gardner units. The company analysis assumed a lifetime for SCR of 20 years. Ho wever, this is nothing in the record supporting this lifetime.

The lifetime is important because the shorter th e lifetime, the higher the capital recovery factor and the higher the annual capital cost used to determine cost-effectiveness. The lifetime of an SCR, which is a metal frame packed with catalyst modules, is generally equal to the lifetime of the boiler, which might easily be well over 80 years. Units 1, 2, and 3 were built in 1965, 1968, and 1976. 108 Absent an enforceable condition requiring shutdown by a date certain, these units could run more than 20+ additional years if they continue to be maintained and upgraded.

Many utilities routinely specify 30+ year lif etimes in requests for proposal and to evaluate proposals for retrofit SCRs. A stud y of the economic risks from SCR operation at the Detroit Edison Monroe power plant, fo r example, used 30 years as the anticipated lifetime. 109 An analysis prepared by Black & Veatch for another facility assumed a

105 Cost Manual, p. 2-21, pdf 35.

106 While 20 years is used as the equipment life for SC R in an example calculation in the Cost Manual, it should be noted that this is merely an assumption for purposes of presenting an example of cost estimation for SCR installation and operation in the Cost Manual. See Cost Manual, pdf 492.

107 New Mexico FIP (Exhibit 1), p . 31 (“The lifetime of a retrofit SCR is generally set equal to the remaining useful life of the facility...We conclude there is nothing in the record to support a 20 year lifetime for the SCR and believe a 30 year lifetime is justified.”).

108 70 FR 36459, Table 6.

109 S.D. Unwin R.W. Johnson, S.W. Rudy, J.E. Delargey, and W. Rogers, Selective Catalytic Reduction (SCR) System Design and Operations: Quantitative Risk Analysis of Options, Presented at CCPS 17th28 40-year SCR lifetime. 110 Sargent & Lundy assumed a design life of 30 years 111 for the Navajo Generating Station which burns a sim ilar western bituminous coal. These units were built between 1974 and 1976 and are 36 to 38 years old, similar in age to the Reid Gardner units.

When the lifetime of a control affect s the BART determination, as here, a federally-enforceable restriction is required to prevent further operation after a certain date. 112 The proposed SIP does not contain a firm shutdown date. Thus, unless the final SIP is revised to require a shutdown date co nsistent with an assumed 20-year lifetime, cost effectiveness should be determined based on an SCR lifetime of no less than 30 years.

ii. Interest Rate

The CH2MHill cost analyses upon which NDEP relied assumed an interest rate of 8.55%. 113 No support is provided for this interest rate. It has long been standard practice to use an interest rate of 7% in regu latory cost effectiveness analyses, as this is the social cost of borrowing specified for governmental analyses. 114 The interest rate used to calculate the capital recovery factor fo r cost analyses is the “social” interest rate established by the Office of Management and Budget (“OMB”) for comparison of public policy issues. 115 The latest real interest rate for co st-effectiveness analyses published by OMB is 2.8%. 116 The EPA calculated the CRF using bo th 3% and 7% interest rates in determining cost-effectiveness for the Regula tory Impact Analysis for the Final Clean Air Visibility rule and the Guidelines for BART Determinations under the Regional

Annual International Conference: Risk, Reliability, and Security, p. 3; available at: http://www.unwinco.com/files%5CSCR-Ris k-Paper,CCPS-RRS2002.pdf (Exhibit 89)

110 Thomas O’Brien, Email to Phil Hayes, EPSR, Dan Yagodinski, WPSC, Gary van Helvoirt, Greg Etvedt, WPSC, September 28, 2004, Re: 040928 SCR & SO 2 Permitting Issues (revised) 32.0440 (Exhibit 90), p. WPS-011905.

111 Sargent & Lundy, Salt River Project, Najavo Gene rating Station – Units 1, 2, 3, SCR and Baghouse Capital Cost Estimate Report, August 17, 2010, Appendix A (Exhibit 91), Section 1.7, p. 6; available at http://en3pro.com/2011/01/ 30/cost_estimate_report/ , accessed August 21, 2011.

112 70 FR 39169 (July 6, 2005). Where the date that a facility permanently stops operation affects the BART determination, “this date should be assured by a federally- or State-enforceable restriction preventing further operation.”

113 10/08 CH2MHill BART Analyses for Units 1-3, A ppx. A, Table ‘Input Calculations,’ respectively.

114 Cost Manual, pdf 27; and U.S. Office of Management and Budget, Circular A-4, September 2003; http://www.whitehouse.gov /omb/circula rs_a004_a-4/#d , accessed August 22, 2011 (Exhibit 92).

115 Cost Manual, pdf 26; and U.S. Office of Management and Budget, Circular A-4, September 2003; http://www.whitehouse.gov /omb/circula rs_a004_a-4/#d , accessed August 22, 2011 (Exhibit 92).

116 Ibid

.29 Haze regulations. 117 Thus, we calculated the CRF using a 7% interest rate, which yields an upper bound favorable to NV Energy.
f) Reagent Costs
Ammonia is used to control NOx in four of the five NOx control options evaluated by NDEP, including for SNCR, ROFA with Rotamix, and the two SCR options. The cost of ammonia is a significan t fraction of the operating and maintenance (O&M) costs for all four of these options. Fo r example, for Unit 1, the cost of ammonia comprises 41% of the total first year O&M co sts for option 2 (LNB/OFA with SNCR); 35% for option 3 (ROFA with Rotamix); 30% for Option 4 (LNB/OFA with SCR); and 24% for option 5 (ROFA with SCR). 118 The amount of ammonia required by each of these control options varies accord ing to the molar ratio of NOx to NH 3 , the design ammonia slip, and the assumed control efficiency.

All of the cost analyses incorrectly assume the same stoichiometric molar ratio of NOx to NH 3 for all three control options and ignore the ammonia slip, even though it is well known that much more ammonia (3 to 4 ti mes) is required to remove a molecule of NOx using SNCR and Rotamix than using SCR. 119 SCRs are typically designed with an ammonia slip of 2 ppm and SNCR systems, including Rotamix ( see Comment I.D.2), with an ammonia slip of 5 ppm, or over two times more ammonia wastage. These erroneous ammonia calculations result in considerably higher ammonia costs for SCR than for SNCR and Rotamix, unfairly skewing the cost analysis in favor of the less efficient SNCR technologies.

I.B.2 NDEP Improperly Modified the Baseline
The cost analysis discussed above start ed with baseline NOx emissions for the year 2004 and control efficiencies based on vendor quotes. Equipment sizing and annual operating expenses were estimated assuming NOx reduction from this original baseline. NDEP changed the baseline years and hence the baseline NOx emissions. However, NDEP did not modify the control e fficiencies or the co st analysis. The new baseline emissions are generally higher than the company’s original baseline. Thus, there is a mismatch between costs and emi ssion reductions. This makes meaningful comment on NDEP’s analysis difficult. The proposed approval should be stayed and EPA should request that NDEP co rrect this fundamental error.

117 See Four Corners Technical Support Document, Exce l spreadsheet entitled “Four Corners SCR Cost Analysis 8-26-10” from the Four Corners Docket #EPA-R09-OAR-2010-0683 (Exhibit 93).

118 10/08 CH2MHill BART Analyses, Appx. A, respectively.

119 IEA Clean Coal Centre, Selective Non-Cata lytic Reduction (SNCR) for NOx Control; http://www.ieacoal.org.uk/site/2010/database-section/ccts/select ive-non-catalytic-reduction-sncr-for-nox-control (Exhibit 94.)30 I.B.3 NDEP’s Cost Rejection Methodology Is Invalid

NDEP evaluated two SCR control options: (1) ROFA with SCR and (2) LNB/OFA with SCR. 120 NDEP estimated the average cost effectiveness to control NOx at Reid Gardner using these two options as ranging from $2,386 to $3,045 per ton of NOx removed. These values are overestima ted, but nevertheless, are cost-effective.

Selective catalytic reduction has been required to satisfy BART requirements at similar sources. Costs for SCR within this range are routinely considered to be costeffective in other BART determinations. However, here, NDEP eliminated these SCR options as not cost-effective, based on an er roneous interpretation of incremental cost that is inconsistent with both the definiti on of BART and the BART Guidelines that NDEP purports to follow. The BART Guide lines explain that two measures of cost should be considered, average cost-effecti veness and incremental cost-effectiveness. NDEP calculated both. 121 However, in rejecting the SCR options, NDEP relied solely on a misinterpretation of incremental cost-eff ectiveness. The BART Guidelines explain: “You should consider the incremental cost effectiveness in combination with the average cost effectiveness when considerin g whether to eliminate a control option.” 122

However, NDEP ignores average cost-effectiveness of the SCR options and the fact that it is well within the range routin ely found to be cost-effective for similar controls in other BART determinations. ( See Comment I.A.2.) Instead, it goes off on a tangent that is not cited to any source, as discussed below. The NDEP offers no explanation of how it considered average cost effectiveness in its de cision to reject SCR based on cost.

The NDEP first plotted the annual cost of each option as calculated by the company against the tons removed by that option, based on NDEP’s revised baseline. 123 Figure 1 for Unit 3 is attached below.

120 10/22/09 NDEP BART Review, Table 1.

121 Ibid

.

122 70 FR 39167.

123 Spreadsheet ‘Copy of Acid Rain Data Annual Data BART NVE (4).xls’ provided via email by Adele Malone, NDEP, to Andrew Gray, Gray Sky Solutions, on August 11, 2011 (Exhibit 20) and 10/22/09 NDEP BART Review, Figure 1.31 Figure 1: NDEP’s least-cost envelope for Reid Gardner Unit 3 (10/22/09 NDEP BART Review, Figure 1, p. 8; copied without changes from spre adsheet ‘Copy Acid Rain Annual Data BART NVE (4).xls’ provided by NDEP (Exhibit 20); the pink square above “LNB w/OFA & SCR” represents “ROFA with SCR”) Plots of annual cost versus correspon ding emission reductions are generally consistent with the BART Gu idelines, when the correct data are used. However, here, the plots are meaningless as they mism atch costs and reductions, as discussed previously. Further, the NDEP did not follow the incremental cost-effectiveness analysis laid out in EPA’s BART Guidelines.

The BART Guidelines explain in the section “How do I calculate baseline emissions:”

In calculating incremental costs, you: (1) Array the control options in ascend ing order of annualized total costs, (2) Develop a graph of the most reasonable smooth curve of the control options, as shown in Figure 2. This is to show the ‘‘least-cost envelope’’ discussed above; and (3) Calculate the incremental cost effectiveness for each dominant option, which is the difference in total annual costs between that option and the next most stringent option, divided by the difference in emissions, after controls have been applied, between those two control options. For example, usin g Figure 2, you would calculate incremental32 cost effectiveness for the difference between options B and D, options D and F, options F and G, and options G and H. 124
The BART Guidelines provid e the following example:

Eight technically feasible control options for analysis are listed. These are represented as A through H in Figure 2. The dominant set of control options, B, D, F, G, and H, represent the least-cost envelope, as we depi ct by the cost curve connecting them. Points A, C and E are inferior options, and you shou ld not use them in calculating incremental cost effectiveness. Points A, C and E repres ent inferior controls because B will buy more emissions reductions for less money than A; and similarly, D and F will buy more reductions for less money than C and E, respectively.“ 125
The BART Guidelines provide the following example graph to visualize step (2):

Figure 2: EPA BART Guidelines example for least-cost envelope determination of dominant/inferior controls (70 FR 39168)

124 70 FR 39168.

125 Ibid.33 In other words, the lower curve determ ines the “dominant controls and the upper curve envelopes the “inferior cont rols.” The dominant controls buy more emission reductions for less money than the in ferior controls for roughly the same cost.

The plotted cost data for Reid Gardner (F igure 1) do not separate into inferior and dominate cost curves. (While Figure 1 show s Unit 3, this is true for Units 1 and 2 as well.) Rather, all of the cost data for the Reid Gardner units line up on a single cost curve. The only dominant and inferior points are the two SCR options and they separate along the annual cost axis only because the cost analysis is defective, i.e. , the same NOx emission reductions were assumed even though the ROFA with SCR option should theoretically be able to achieve a higher NOx control efficiency.

NDEP ignored the fact that there are no inferior and dominant cost curves and thus no least-cost envelope, instead noting that the two SCR options have much higher annual costs than the other options, as well as higher cost per ton and incremental costs but do not achieve proportional reductions in NOx, i.e. , costs are four times higher than the selected control while NOx reductions are not four times greater. Thus, NDEP proclaimed a “clear break” in the plotted points, justifying rejection of the SCR options. 126 However, this results in BART never being satisfied by the most expensive option, a result contrary to the definition of BART and the BART Guidelines.

There is no such “clear break” theory for determining the cost effectiveness of BART. The so-called “clear break” is due to the absence of control options that fall within the so-called gap between ROFA with Rotamix and the two SCR options. As an example, the “clear break” would still exist ev en if, for example, SNCR would cost only $1/ton, ROFA with Rotamix $3/ton and SCR $10/ton. The so-called “break” would still be clearly visible in a graph, yet eliminatin g SCR at those costs would be nonsensical. This problem arises because NDEP did not consider average and incremental cost effectiveness together.

126 See
, e.g. , Appendix D, p. D-59 (“NDEP consistently evaluated the cost and visibility data by looking at clear breaks in the cost effectiveness of the BART controls and resulting visibility improvement or emissions reductions.”); p. D-64 (“Capital cost increa ses by more than four times, cost per ton by more than twice, and incremental cost by more than seve n times, while emissions are reduced by 542 tpy or 41 percent for unit 1. The clear breaks in these fa ctors support NDEP’s BART determination.”); p. D-65 (“Nevada deems NDEP’s identification of BART as co nsistent with the breaks in cost effectiveness and visibility improvement/emissions reduction ( i.e. , cost benefits), as well as the Appendix Y guidance.”); p. D-70 (“NDEP has consistently evaluated the prop osed BART controls on a unit-by-unit basis by identifying the clear breaks in cost-benefit based on cost effectiveness and visibility improvement.”); p. D-76 (“NDEP has consistently determined BART th rough identification of clear breaks in the cost effectiveness measures identified in Appendix Y guidance and visibility improvement/emissions reductions at the affected Class I areas.”).34 NDEP’s “clear break” theory turns the co ncept of cost-effectiveness on its head. The BART Guidelines that NDEP claims to have followed lays out an example that epitomizes why NDEP’s approach is wrong. It notes: “

For example, large capital costs for a contro l option alone would not preclude selection of the control measure if large emission reduct ions are projected. In such a case, low or reasonable cost effectiveness numbers may validate the option as an appropriate BART alternative irrespective of the large capital costs.” 127

An SCR has a high capital cost compared to the other control options that were evaluated. However, SCR also results in a mu ch higher and very large reductions in NOx emissions that are not achievable by any of the other options. An SCR is routinely designed to reduce 90%+ of the NOx while RO FA with Rotamix, the BART option, tops out at about 80% under ideal conditions 128 and for Reid Gardner was assumed at 57.7%, 59.0%, and 38.3% for Units 1-3, respectively. 129

As explained in Comment I.A.2, the costs per ton of NOx removed estimated by NDEP for the SCR options are reasonable compared to other BART determinations. Cost-effectiveness is determined by comp aring annual cost per ton of pollutant removed for the source of interest to the range of cost-effectiveness values for other similar permit decisions. If a given cost-e ffectiveness value falls within the range of costs borne by others, it is per se cost-effective unless unusual circumstances exist at the

source. 130 No unusual circumstances are documented for Reid Gardner that would render SCR not cost-effective compared to the use of SCR at other similar facilities.

When there are no inferior controls, as he re, no controls can be eliminated out of hand, i.e. , there is no “clear break” that allows the SCR options to be rejected. Rather, the incremental cost must be consider ed for each dominant control option. 131 Incremental costs were reported by NDEP in the 10/22/09 NDEP BART Review, Table 1. The incremental costs for the LNB/OF A with SCR scenario (option 4) relative to the ROFA with Rotamix scenario range from $3,688 to $6,085 per incremental ton of NOx removed; the incremental costs for the ROFA with SCR scenario (option 5) relative

127 70 FR 39168.

128 Nalco Mobotec, Multi-pollutant Emission Reduction Technology for Small Utility Boilers, Presented to Lake Michigan Air Directors Cons ortium, Innovative Industrial Source Control and Measurement Technologies Workshop, March 24, 2010, pdf 17; http://www.ladco.org/about/general/Em issions_Meeting/Fe ssenden_032410.pdf , accessed August 21, 2011 (Exhibit 94).

129 10/09 CH2MHill BART Analyses, Appx. A, Table ‘Input Calculations,’ and NDEP Revised BART Determination Review, Table 1, pp. 5-6.

130 70 FR 39168.

131 70 FR 39168, Step (3).35 to the ROFA with Rotamix scenario range from $4,444 to $7,280 per incremental ton of NOx removed. 132

These costs are greatly overestimated for two reasons. First as explained in Comment I.B.1, they include costs that are not allowed in standard regulatory cost analyses and contain other errors. Second, ND EP’s incremental cost-effectiveness values are significantly overestimated because they are not based on the usual control efficiency readily achievable by SCR. The BA RT Guidelines that NDEP claims to have relied on states that “when you evaluate the average or incremental cost effectiveness of a control alternative, you should make reasonable and supportable assumptions regarding control efficiencies. An unrea listically low assessment of the emission reduction potential of a certain technology could result in inflat ed cost-effectiveness figures.” 133 This has happened here. The NDEP’s incremental costs assume the SCR removes only 78.2-82.2% of NOx. ( See Table 1.) As explained in Comment I.A.1, SCR systems are routinely design ed to achieve, and commonly do achieve, a NOx control efficiency of 90% or greater. We revised ou r cost-effectiveness analyses (provided in Attachments 5a, 5b, and 5c) assuming 90% co ntrol efficiency for the LNB with SCR scenario (option 4). This decreased increm ental cost-effectiveness to from $3,713 to $2,745/ton NOx removed (Unit 1), $3,552 to $2,656/ton NOx removed (Unit 2), and $2,554 to $1,971/ton NOx removed (Unit 3), which is well within the range routinely found to be cost-effective for av erage cost-effectiveness and thus per se cost-effective in an incremental analysis.

In spite of these overestimates, NDEP’s cost-effectiveness values are within the range reported as cost-effective for both average and incremental cost-effectiveness values. The New Mexico Environment Department, for example, concluded that SCR was cost-effective at similar units based on average cost-effectiveness of $5,946/ton to $7,398/ton and incremental cost-effectiveness, relative to ROFA/Rotamix, of $7,399/ton to $7,803/ton. 134 The EPA has confirmed New Mexico’s analysis and published a final implementation plan requiring SCR at the subject units. 135 Thus, absent any unusual circumstance, and none is documented in the record, the SCR options are per se costeffective on both an average and incremental cost basis.

132 10/22/09 NDEP BART Review, Table 1, pp. 5-6.

133 70 FR 39168.

134 New Mexico Environment Department, Air Qualit y Bureau, BART Determination, Public Service Company of New Mexico, San Juan Generating Station, Units 1-4, June 21, 2010, Table 10 and p. 33 (Exhibit 49); available at: http://www.nmenv.state.nm.us/aqb/reghaz/doc uments/AppxA_NM_SJGS_ NOxBARTDetermination _06212010.pdf , accessed August 21, 2011.

135 New Mexico FIP (Exhibit 1).36 I.C EPA Fails to Provide Enforceable Compliance Provisions

The last step of the BART determinat ion process is to establish enforceable emission limits and compliance dates. 136 EPA’s proposed approval of Nevada’s SIP claims the BART emission limits are enfo rceable through Nevada State regulation R190-08. 137 This regulation sets specific NOx emission limits for Reid Gardner at 0.20 lb/MMBtu for Units 1 and 2 and at 0.28 lb/MMBtu for Unit 3, based on a 12-month rolling average. 138 However, as explained below, these limits are not enforceable because the averaging time is too long. Furt her, the proposed BART emission limits for NOx, SO 2 , and PM10 are not enforceable because monitoring and recordkeeping are not required. (This comment applies also to T racy and Fort Churchill Generating Stations.)

I.C.1 Averaging Time

An emission limit consists of two parts: (1) the numerical limit itself and (2) the period over which the emissions are averag ed. The NOx BART emission limits for Reid Gardner in R190-08 are established as 12-mont h rolling averages. This is a very long averaging time and is inappropriate for BART.

Averaging time plays an important role in determining the stringency of a BART limit. For a given limit, the shorter the ave raging time, the more stringent the limit because less time is available to average out spikes that occur during the stated period.A 30-day average, for example, allows 720 hours (30 × 24 = 720) to average out a onehour spike while a 12-month rolling average allows well over 8,000 hours (30 × 24 × 12 = 8,640) to average out the same spike.

The BART guidelines require that emissi on limits for electric generating units, such as Reid Gardner, use an averaging ti me of 30-days, based on a boiler operating day. NDEP instead chose a 12-month rolling average based on NV Energy’s operating experience with ROFA/Rotamix 139 (the proposed BART technologies for Units 1-3) on Unit 4. According to NDEP, Nevada Energy “confronted serious operational problems, creating a high degree of variability in the operational characteristics of the unit.” 140

136 40 CFR 51, Appx. Y (70 FR 39172).

137 76 FR 36462.

138 Nevada R190-08, Sec. 4(c).), attached as Appx. A to Nevada RH SIP.

139 It is unclear from the record whether just ROFA or ROFA plus Rotamix is installed on Unit 4. NDEP’s response to comments mentions only “r otating opposed fire air” or ROFA. ( See Nevada RH SIP Appx. D, p. D-60.) A Mobotech experience list published in March 2010 also lists just ROFA. ( See Nalco Mobotec, March 24, 2010 (Exhibit 94), pdf 6. However, the McIlvaine Utility Environmental Upgrade Tracking System (Exhibit 95) reports Unit 4 is equipped with both ROFA and Rotamix, the BART controls recommended for Units 1-3.)

140 Nevada RH SIP, Appx. D, p. D-60.37 “Thus, “[i]n order to ensure that industry is not out of compliance because of such issues, Nevada has chosen th e 12-month rolling average.” 141

First, poor operating experience wi th ROFA (or ROFA/Rotamix at Unit 4 provides an insufficient technical basis fo r selecting this technology as BART at Units 1-3. It also attempts to sidestep EPA’s clear direction in its BART Guidelines. The relaxation of an emission limit to allow an inferior technology to be selected as BART fundamentally undermines the BA RT determination process.

BART is an emission limitation that “is based on the degree of reduction achievable through the application of the best system of continuous emission reduction for each pollutant which is emitted by an existing stationary facility.” (40 CFR §51.301.) If ROFA/Rotamix results in “serious” ope rational problems, as argued by NDEP in carving out an exception to the required av eraging time, then surely ROFA/Rotamix is not the best system of “continuous” emission reduction. As explained in Comment I.A.2, SCR has been demonstrated to continuously achieve much lower NOx emission limits on a 30-day rolling averag e basis than proposed here as BART. Alternatively, if ROFA/Rotamix is the best system of continuous emission reduction, then it does not qualify for an exception to the standard 30-day averaging period for electric generating units (“EGUs”).

Second, NDEP’s claim of “serious” operat ional problems with ROFA/Rotamix as its technical basis for disregarding BART’s 30-day averaging requirement is illogical. This is because Rule R190-08 itself allows the company to comply with the BART emission limits using alternative technologies, so long as the emission limits themselves
are met. 142 Thus, under Rule R190-08, ROFA/Rotamix does not have to be used. A more reliable technology capable of higher NOx em ission reductions, such as SCR, could have been and should have been chosen as BART.

Third, even if one assumes that only ROFA was installed on Unit 4, the averaging time exception still would not be warranted because the BART technology is ROFA plus Rotamix. The Rotamix componen t is a selective non-catalytic reduction control that is normally operated in conc ert with ROFA to even out the peaks and valleys this exception was meant to address. Thus, there is no justification for the averaging time exception.

In sum, the BART guidance in Appendix Y states that BART emission limits for EGUs “must” “specify a 30-day rolling ave rage and contain a definition of “boiler

141 Ibid

.

142 Nevada RH SIP, Appx. A, p. A-12.38 operating day.” Nevada’s BART emission lim its in Rule R190-08 that EPA is proposing to approve do not satisfy either prong of this requirement.

I.C.2 Monitoring and Recordkeeping
BART emission limits must be federally enforceable, which requires practical enforceability. The Clean Air Act requires emi ssions limits such as BART to be met on a continuous basis:

The terms ‘emission limitation’ and ‘emission standard’ mean a requirement established by the State or the Administrator which limits the quantity, rate, or concentration of emissions of air pollutants on a continuous ba sis, including any requirement relating to the operation or maintenance of a source to assure continuous emission reduction, and any design, equipment, work practice or op erational standard promulgated under this chapter.” 143

and elsewhere:

To complete the BART process, you must establish enforceable emission limits that reflect the BART requirements and require compli ance within a given period of time.” Emphasis added. 144

Practical enforceability means the source must be able to show continuous compliance with each limitation. This re quires monitoring, recordkeeping, and reporting. As explained by the BART Guide lines, “emissions limits must be enforceable as a practical matter (contain appropriate averaging times, compliance verification procedures and recordkeeping requirements).” 145 Nevada regulation R190-08 does not require any monitoring, recordkeeping or reporting. Thus, these limits are not enforceable and do not constitute BART.

I.C.3 Compliance Time

BART includes “A requirement that each source subject to BART be required to install and operate BART as expeditiously as practicable, but in no event later than 5 years after approval of the implementa tion plan revision.” 40 CFR 51.308(e)(iv). Regulation R190-08 requires that the BART co ntrols must be installed and operating: “(a) For NV Energy’s Fort Churchill, Trac y and Reid Gardner generating stations: (2) On or before January 1, 2015; or (2) Not later than 5 years after approval of Nevada’s

143 42 U.S.C. §7602(k).

144 40 CFR Part 51, App. Y, Section V.

145 70 FR 39172.39 state implementation plan fo r regional haze by the Un ited States Environmental Protection Agency Region 9, whichever occu rs first.” Assuming EPA approves the Nevada SIP by the end of the current year, this would allow four years to install the proposed ROFA/Rotamix controls. This is an excessive amount of time for the proposed BART technologies. The subject technologies require placement of air and ammonia injection boxes, ducting, supports, fans, tanks, and tie-ins to the existing boilers. These types of modifications can be executed, from contract signing to startup, in less than a year. 146

I.D Alleged Negative Non-Air Quality Environmental Impacts Are Mischaracterized and Unsupported in the Record
The EPA claims, based on NDEP’s analys is, that there are negative non-air quality environmental impacts associated with SCR and SNCR compared to the selected BART technology, ROFA with Rota mix, including the salability and ultimate disposal of fly ash due to higher ammonia le vels and the potential for creating a visible stack plume. Further, EPA claims that the tr ansportation of ammonia to Reid Gardner raises concerns due to the increased likelihood of an accidental release. 147 The EPA appears to imply that these concerns were co ntributing factors for NDEP’s decision for rejecting SCR and SNCR as BART for Reid Gardner.

I.D.1 Alleged Impacts Are Not Supported in the Record
In its analysis for the Nevada RH SIP, NDEP voiced its concerns regarding the potential negative non-air quality impacts associated with SCR and SNCR as follows:

SNCR and SCR installation could impact the salability and disposal of fly ash due to ammonia levels and could potentially create a visible st ack plume. Transport of ammonia to the site may be an issue in the event of an accidental release. 148

NDEP’s analysis did not contain any further discussion of these potential negative impacts. Instead, NDEP’s concerns appear to be derived from the following vague and unsupported statements found in Nevada Energy’s BART Analyses for Reid Gardner Units 1-3:

146 ROFA and ROATMIX Installation, Cape Fear 6 of Progress Energy, Available at: http://www.nalcomobotec.com.cn/projects/capefear6- sellsheet.pdf (Exhibit 115) and ICAC, Typical Installation Timelines for NOx Emissions Control Tec hnologies on Industrial Sources, December 4, 2006 (Exhibit 116).

147 76 FR 36463.

148 10/22/09 NDEP BART Review, p. 4, emphasis added.40 [For SNCR:] With low-reagent utilization, low temperatures, or inadequate mixing, ammonia slip occurs, allowing unreacted a mmonia to create problems downstream. The ammonia may render fly ash unsalable ... and/or create a visible stack plume.

... SNCR and SCR installation could impact the salability and disposal of fly ash due to ammonia levels and could potentially create a visible stack plume, which may negate other visibility improvements. Other envi ronmental impacts involve the storage of ammonia, especially if anhydrous ammonia is used, and the transportation of the ammonia to the power plant site. 149
Nowhere in the record (including EPA’s docket, NDEP’s RH SIP, and Nevada Energy’s BART Analyses) is th ere any further discussion of these potential negative non-air quality environmental impacts such as: experience with SNCR and SCR retrofits at similar facilities; a discussion of negati ve experiences with ammonia-contaminated fly ash at other facilities; potential for minimization of higher ammonia levels in fly ash; a discussion of the mechanisms and likelihood of a visible stack plume; quantification of potential economic impacts; an ammonia transportation risk analysis; a comparison between SCR and SNCR regarding these risks; etc. (Note also the use of the modal verbs

“ may ” and “ could ” in Nevada Energy’s statements co nnoting that occurrence of these undesirable phenomena is by no means a given. ) In other words, there is absolutely no support in the record for the NDEP’s and EPA’s statements and the insinuation that SCR and SNCR control options were eliminat ed as BART for NOx emissions from Reid Gardner, at least in part, due to these alle ged negative non-air quality environmental impacts.

Further, EPA cannot simply state that a potential for negative impacts exists in order to eliminate a control technology from consideration. If EPA indeed believed that these potential negative impacts were serious enough to affect the viability of SCR or SNCR systems as BART for Reid Gardner, it would have to provide a reasoned analysis with sufficient detail. This analysis woul d have to follow a similar approach as elimination of a control technology unde r the best available control technology (“BACT”) requirements under the federal Clea n Air Act, which EPA lays out as follows in its New Source Review Manual :

The applicant should identify any signif icant or unusual environmental impacts associated with a control alternative that hav e the potential to affect the selection or elimination of a control alternative. Some control technologies may have potentially significant secondary ( i.e. , collateral) environmental im pacts. Scrubber effluent, for example, may affect water quality and land use. Similarly, emissions of water vapor from technologies using cooling towers may affect local visibility. Other examples of secondary environmental impacts could incl ude hazardous waste discharges, such as spent catalysts or contaminated carbon. Generally, these types of environmental concerns

149 Nevada Energy, BART Analyses for Units 1-3, pp. 3-7 through 3-7, emphasis added.41 become important when sensitive site-specific rec eptors exist or when th e incremental emissions reduction potential of the top control is only marginally greater than the next most effective option. However, the fact that a control device creates liquid and solid waste that must be disposed of does not necessarily argue against sel ection of that technology as BACT, particularly if the control device has been applied to simil ar facilities elsewhere and the solid or liquid waste problem under review is similar to those other applications. On the other hand, where the applicant can show that unusual circumstances at the proposed facility create greater problems than experienced elsewhere, this ma y provide a basis for the elimination of that control alternative as BACT. 150

Here, the incremental emissions reduction potential of the top control options, i.e. , the two SCR technology combinations, is considerably greater than the next-most effective option, i.e. , ROFA with Rotamix, which was selected as BART. Specifically, according to NDEP, NOx control efficiencies for the SCR technologies range from 78.2% to 82.2% for the three units, whereas contro l efficiencies for RO FA with Rotamix are expected at only 38.3% to 59.0%. 151 Thus, the potential for negative environmental impacts alone would not be reason to e liminate the top control technologies.

I.D.2 Potential Non-Air Quality Environmental Impacts of SCR Compared to SNCR and Rotamix
Both SCR and SNCR are post-combustion add-on control technologies and are fundamentally similar in that they oxidize NOx entrained in the flue gas to form to molecular nitrogen (“N 2 ”) and water vapor (“H 2 O”) using ammonia (“NH 3 ”) or urea (“(NH 2 ) 2 CO”) as a reagent: in the SNCR process, ammonia is injected into the flue gas exiting the boiler whereas in th e SCR process, ammonia is injected into the hot side of the flue gas duct upstream of a catalyst.

Flue gas temperatures in the upper furnace through the convective pass may vary by ±150C (300oF); they depend on boththe boiler design and operating conditions and vary from one boiler to the next. 152 The effective temperature range for SNCR systems is 700 F-2000 F (for urea-based systems 1000 F-1900 F) is the optimum temperature range in the upper furnace regi on of the boiler, while SCR systems operate at about 700 F. 153,154 At lower temperatures the reaction kinetics are slow and ammonia

150 U.S. Environmental Protection Agency, New So urce Review Workshop Manual, Prevention of Significant Deterioration and Nonattainment Area Perm itting (hereinafter “NSR Manual”), Draft October 1990, p. B.47, emphasis added.

151 10/22/09 NDEP BART Review, Table 1, pp. 5-6.

152 Ibid

.

153 California Air Resources Board, Compliance Assistan ce Technical Manual Series: Stationary Source Air Pollution Control Devices and Techniques, Section 310: Selective Non-Catalytic Reduction Control Theory and Design; http://www.arb.ca.gov/cap/manuals /cntrldev/sncr_etc/310sncr.htm , accessed August 19, 2011 (Exhibit 2).42 passes unreacted through the boiler as the so-called ammonia slip. At higher temperatures the reagent oxidizes and addi tional NOx is generated. Because flue gas temperatures are generally set to meet st eam generation requirements, they are not always ideal for the SNCR process, which rely on appropriate injection temperatures, proper mixing of the reagent and flue gas, and prolonged retention time in place of the catalyst and are very sensitive to temperature changes. The California Air Resources Board (“CARB”) notes that “[v]ariations in the flue gas temperat ure make the design and operation of an SNCR system more di fficult...” and “... SNCR requires especially efficient temperature and NOx monitoring and diligent operator oversight.” 155

A recent study by Black & Veatch found that “SNCR processes typically require three to eight times the theoretical amount of reagent to achieve NOx reductions, as compared to SCR systems. The increased reagent consumption is due to reagent thermal decomposition, varying temperature, and the lack of a true steady-state controlled environment, which tends to incr ease ammonia slip emissions. Even with best efforts (multiple levels of injection, co nscientious operator attention, etc.), ammonia slip emissions from SNCR systems will be hi ghly variable during load changes. This can result in excess or inadequate reagent injection, the increased potential for exceeding allowable NOx emission limits, or in creased ammonia slip with associated air heater pluggage and fly ash contamination.” 156 Ammonia and urea-based SNCR processes require three or four times as much reagent as SCR systems to achieve similar NOx reductions. 157

Modern SNCR technologies typically have an ammonia slip of 5 to 10 parts per million (“ppm”). In contrast, SCR technologies nowadays are typically designed with a 2 ppm ammonia slip. 158 For example, the recently released FIP for New Mexico which

154 Pfafflin J.R., Ziegler E.N. (eds.), Encyclopedia of Environmental Science and Engineering, Vol. 2, CRC Press, 2006, p. 766 (Exhibit 96).

155 Ibid.

156 Black & Veatch, Platte River Power Authority, Rawhide Energy Station, Rawhide NOx Reduction Study, January 2009, Rev. 3; available at: http://www.cdphe.state.co.us/op/aqc c/meetingmaterials/1210/RegHazeReg3&7/PRPA/PRPS%20REB-EXHIBIT%20A.pdf (Exhibit 97).

157 IEA Clean Coal Centre, Selective Non-Catalytic Reduction (SNCR) For NOx Control; http://www.ieacoal.org.uk/site/2010/database-section/ccts/select ive-non-catalytic-reduction-sncr-for-nox-control (Exhibit 98.)

158 U.S. Environmental Protection Agency, Identificati on of (and Responses to) Potential Effects of SCR and Wet Scrubbers on Submicron Particulate Emissions and Plume Characteristics, EPA-600/R-04-107, August 2004; available at: http://www.epa.gov/nrmrl/pu bs/600r04107/ 600r04107.pdf , accessed August 21, 2011 (Exhibit 99).43 determines BART emission limits for the Sa n Juan Generating Station, requires design of the NOx control system with a 2 ppm ammonia slip. 159

The NOx control technology selected by EPA as BART for Reid Gardner, ROFA (rotating opposed fire air) with Rotamix, is a “third-generation” SNCR system developed by Nalco Mobotec (formerly MobotecUSA), which uses either ammonia or urea as a reagent. According to the manufacturer, the SNCR system uses boosted air to carry the reagent (ammonia or urea) deep in to the furnace cross flow. When combined with Nalco Mobotec’s ROFA system, the turbul ent air injection and mixing provided by Rotamix enables more effective mixing of ch emical reagents with combustion products in the furnace. Nalco Mobotec asserts that th ese improved mixing conditions lead to higher reagent utilization compared to conventional SNCR systems. 160 Nalco Mobotec typically designs its Rotamix systems for 5 ppm ammonia slip. 161 For Reid Gardner, the vendor guarantees a 5 ppm ammonia slip. 162 Experience shows that ROFA with Rotamix can achieve this design ammonia slip level. 163

Thus, SNCR, including ROFA with Rotami x technology, would result in more than twice as much ammonia slip emissions as SCR technologies. In other words, the selected BART control option, ROFA with Rota mix, will result in higher ammonia slip. Further, it will require the transport and us e of more ammonia. Thus, the potentially associated non-air quality environmental pr oblems of the selected BART technology would be greater than those associated withthe much more efficient and highly costeffective but unjustly reject ed SCR control options.

159 See Comment I.A.2 and New Mexico FIP (Exhibit 1), p. 111.

160 See : Nalco Mobotec, ROTAMIX® System; http://www.mobotecusa.com/mb/technology/rotamixsystem.htmhttp://www.mobotecusa.com /mb/technology/rotamix-system.htm accessed August 19, 2011 (Exhibit 100); and Nalco Mobotec, NOx Control; http://www.mobotecusa.com/mb/expertise/noxcontrol.htm , accessed August 19, 2011 (Exhibit 101).

161 For example: E.E. Haddad, J.S. Crilley, and B. S. Higgins, Mobotec USA Inc., The Viability and Economics of Adding a ROFA®/Rotamix® MobotecS ystem to a Selective Catalytic Reduction (SCR) Installation, NETL/DOE 2003 Conference on SCR an d SNCR for NOx Reduction, Pittsburgh, PA October 29-30, 2003; http://www.nalcomobotec.com.cn/white_p apers/MobotecSystem_ROFA-RotamixSCR.pdf , accessed August 19, 2011 (Exhibit 102).

162 10/08 CH2MHill BART Analyses, p. 3-6, respectively.

163 For example: M. Shilling, MobotecUSA, ROFA and ROTAMIX Installation, Cape Fear 6 of Progress Energy, p. 19, http://www.netl.doe.gov/publications /proceedings/02/ubc/Shilling.pdf , accessed August 19, 2011 (Exhibit 103); and G. Moberg, J.O. Blid, S. Wallin, T. Fareid, and J. Ralston, Combined DeNOx/DeSOx and Additional NOx Reduction by Cleaning Fl ue Gas Condensate From Ammonia, PowerGen International, November 30– December 2, New Orleans 1999; http://www.mobotec.com/eng/pdf/PowerGen99.pdf , accessed August 19, 2011 (Exhibit 104).44 I.D.3 Impacts of Ammonia Slip on Salability of Fly Ash Are Mischaracterized

Odor associated with ammonia slip can be a problem and the potential impacts associated with ammonia slip due to the operation of SCR and SNCR ammonia absorption into fly ash, which may affect disposal or reuse of the ash, are welldocumented. 164 However, the occurrence of these impa cts is highly site-specific and by no means occurs constantly or at all installations.

An informal phone survey of operatin g SCR and SNCR installations performed for Southern Company showed that “a majori ty of these plants sometimes experienced detectable ammonia odors; however, most were still able to utilize ash for beneficial purposes.” 165 Experience shows that an ammonia slip of 2 ppm maintains the usability/salability of fly ash. 166

As ammonia slip with SCR can be limit ed to 2 ppm, as discussed before, the salability of fly ash should not be impacted if a properly designed SCR system is used. However, the ammonia slip from a ROFA/Rotamix system cannot be similarly limited. Therefore, the SCR options eliminated by NDEP would have fewer negative impacts than the selected ROFA with Rotamix opti on, which would be designed with a 5 ppm ammonia slip.

I.D.4 Visible Plume Impacts Are Mischaracterized

EPA, based on NDEP’s Reid Gardner BART Determination Review, claims that SCR and SNCR increase the potential for creating a visible stack plume. (76 FR 36463.) EPA provides no further information on the origin of this potential visible stack plume. There are two reasons the operation of SCR an d/or SNCR could lead to a visible stack plume: increased ammonia slip and/or increased conversion of SO 2 to sulfur trioxide (“SO 3 ”).

164 See , for example, U.S. Environmental Protection Agen cy, Air Pollution Control Technology Fact Sheet, Name of Technology: Selective Non-Catalytic Reduction (SNCR), EPA-452/F-03-031, http://www.epa.gov/ttn/catc/dir1/fsncr.pdf (Exhibit 105); and U.S. Envi ronmental Protection Agency, Air Pollution Control Technology Fact Sheet, Name of Technology: Selective Catalytic Reduction (SCR), EPA-452/F-03-032; http://www.epa.gov/ttn/catc/dir1/fscr.pdf , accessed August 19, 2011 (Exhibit 106).

165 Lamar Larrimore, Effects of Ammonia from Post -combustion NOx Control on Ash Handling and Use, Effects on Utilization Applications, Fuel Chemistry Division Preprints 2002, 47(2), 832; available at: http://www.anl.gov/PCS/acsfuel/preprint%2 0archive/Files/47_2_B oston_10-0 2_0241.pdf (Exhibit 113).

166 Lewandowski, Boilers, Emission Controls and th e CCPs They Generate, presented at the American Coal Ash Association Educational Program for Managers of Coal Combustion Products (CCP), Morgantown, WV, June 5-9, 2000 (Exhibit 114), p. 12.45 a) Plume Formation due to Ammoni a Slip from SCR and SNCR
With SCR and SNCR systems, a detached plume may potentially be caused by condensation of ammonium chloride as the flue gas cools. The ammonia source is the ammonia slip from the post-combustion NOx control system and chlorides can come from either the fuel or the flue gas desulfurization (“FGD”) system for SO 2 control. 167 Although a threshold concentration has not b een established, literature indicates that plume formation should be considered if both ammonia and chlorides exceed 15 ppm. 168

In the U.S. permitted ammonia slip le vels from SCR and SNCR are typically between 2 to 10 ppm 169 and ammonia slip levels in practice can be controlled to considerably lower levels. Therefore, if the SCR or SNCR are operated at or below permitted levels, ammonia slip does not result in plume formation. Further, as discussed above, well-controlled SCR syst ems typically emit less ammonia than comparable SNCR control systems. Thus, the proposed BART option, ROFA with Rotamix, can be expected to have more of a potential plume formation problem than the rejected SCR control technology options.

b) Plume Formation due to SO 2 to SO 3 Conversion from SCR
The operation of an SCR can result in the so-called “blue plume” problem, which occurs because the SCR catalyst also in the flue gas to SO 3 while it converts NOx to elemental nitrogen. According to literature, the SO 3 created in the SCR is not effectively removed by wet scrubbers. 170 Water vapor and SO 3 then combine to sulfuric acid (“H 2 SO 4 ”), which is emitted from the stack as an aerosol known as sulfuric acid mist. The additional acid aerosol has a significan t impact upon stack opacity, creating a visible blue plume.

167 L.F. Drbal, P.G. Boston, K.L. Westra, Black & Veatch, Power Plant Engineering, Black & Veatch, Springer, 1996, 858 pp, p. 437 (Exhibit 107).

168 Ibid

.

169 California Air Resources Board, Compliance Assistan ce Technical Manual Series: Stationary Source Air Pollution Control Devices and Techniques, Section 309: Selective Catalytic Reduction Control Theory and Design; http://www.arb.ca.gov/cap/manuals /cntrldev/sncr_etc/309scr.htm , accessed August 19, 2011 (Exhibit 108); and California Air Resources Board, Compliance Assistan ce Technical Manual Series: Stationary Source Air Pollution Control Devices and Techniques, Section 310: Selective Non-Catalytic Reduction Control Theory and Design; http://www.arb.ca.gov/cap/manuals /cntrldev/sncr_etc/310sncr.htm , accessed August 19, 2011 (Exhibit 2).

170 U.S. Environmental Protection Agency, Identificati on of (and Responses to) Potential Effects of SCR and Wet Scrubbers on Submicron Particulate Emissions and Plume Characteristics, EPA-600/R-04-107, August 2004, (Exhibit 99).46 As SO 2 concentrations are directly related to coal sulfur content, the creation of a blue plume is correlated with coal sulfur co ntent. Thus, one solution to the blue plume problem is to use lower sulfur coals. Here, Reid Gardner uses western bituminous coal with a relatively low sulfur content of 0.29 to 0.57%. 171,172

Visible blue plume issues due to sulfuric acid emissions have not been reported for facilities firing Western bituminous coal s, such as Reid Gardner (maximum sulfur content 0.57%). For example, the EPA in thei r Federal Implementation Plan (“FIP”) for New Mexico rebutted comments regarding the potential for blue plume formation at the San Juan Generating Station (“SJGS”):

Visible plume issues have only been experienced at units that burn high sulfur coal, containing greater than 2+% sulfur and typically over 3% sulfur, e.g. , Gavin, Ghent. The coal burned at SJGS contains 0.77% sulfur, much lower than the amount of sulfur that has resulted in visible plume issues elsewher e and is considered to be low sulfur. No explanation is provided for why the comment er believes a plume may “materialize” on installing SCR. 173

Further, the presence of alkaline metals in coal counteracts SO 3 formation. Due largely to the abundance of alkaline metals in Western coals, SO 3 formation is dramatically lower than for low alkali, East ern bituminous coals. (In fact, for most western coals, SO 3 levels exiting the boiler are so low that SO 3 is commonly injected upstream of electrostatic precipitators to reduce ash resistivity to levels that all them to operate properly. 174 ) Conversion rates of SO 2 to SO 3 have been identified for four types of coal that correlate inversely with levels of alkaline metals: the estimated values range from 0.008 for Eastern bituminous coals, 0.001 for Western bituminous coals and lignite, and 0.0005 for Western subbituminous coals when burned in pulverized coal boilers. 175 Reid Gardner uses western bituminous coal; he nce, operation of an SCR would result in low SO 2 to SO 3 conversion.

Further, visible plume issues can be addres sed by specifying a properly designed SCR catalyst with a low conversion rate. Visible plume should not materialize. Conversion rates for SO 2 to SO 3 of as low as 0.1% per catalyst layer can be specified and conversion rates of <0.5% are commonly sp ecified, particularly in higher sulfur applications.

171 10/08 CH2MHill BART Analyses, Table 2-2, p. 2-3, respectively.

172 In the past, Reid Gardner also burned West Ridge coals, which the consultant CH2MHill did not consider typical. See 10/09 CH2MHill BART Analyses, Footnotes to Table 2-2, p. 2-3, respectively.

173 New Mexico FIP (Exhibit 1), p. 20.

174 U.S. Environmental Protection Agency, Identificati on of (and Responses to) Potential Effects of SCR and Wet Scrubbers on Submicron Particulate Emissions and Plume Characteristics, (Exhibit 99), p. 3.

175 Ibid

.47 If the SCR is properly designed to addre ss SJGS’s coal, a Low conversion catalysts capable of achieving an SO 2 conversion as low as 0.1% per layer of catalyst in the high dust, hot (>650 F) position and 0.5% across th e entire SCR reactor are common in higher sulfur and other applications. Even lower le vels can be achieved if the catalyst is regenerated. 176

Additionally, sorbent injection after the SCR can be used to address blue plume issues. Common sorbents used are hydrat ed lime, a magnesium-hydroxide slurry, sodium bisulfite, or Tron a (sodium sesquicarbonate). 177 These additives are commonly and successfully used by utilitie s firing higher sulfur coals. 178

Clearly, with a properly designed SCR an d firing western bituminous coal, blue plume formation is not an issue for Reid Gardner Units 1-3.

I.D.5 Transportation Risk Can Be Avoided
As discussed above, SNCR systems including the proposed BART option, ROFA with Rotamix, require three to four times mo re reagent than SCR. On site, the use of anhydrous ammonia for SNCR systems would require the same safety systems, storage tanks, and vaporizers as those required fo r SCR systems. Thus, any risks associated with transport of ammonia are greater fo r SNCR systems than for SCR systems.

As discussed before, both SCR and SNCR systems can be operated on anhydrous ammonia, aqueous ammonia, or urea as re agent. Anhydrous ammonia is toxic by inhalation and thus is regulated as a h azardous substance requiring a hazardous safety permit when transported in quan tities greater than 3,500 gallons. 179 Neither aqueous ammonia nor urea is classified as hazardous and their transportation does not require any special permits. To avoid the transpor tation risk associated with anhydrous ammonia, many coal-fired boilers with SCR and SNCR systems in the U.S. rely on aqueous ammonia or urea, options not consid ered by NDEP for Reid Gardner. Thus, the BART analysis is incomplete.

176 New Mexico FIP (Exhibit 1), p. 20.

177 B. Adams and C. Senior, Curbing the Blue Plume: SO 3 Formation and Mitigation, May 15, 2006; http://www.powermag.com/environmental/Cur bing-the-blue-plume-SO3-formation-andmitigation_564.html , accessed August 19, 2011 (Exhibit 109).

178 U.S. Environmental Protection Agency, Identificati on of (and Responses to) Potential Effects of SCR and Wet Scrubbers on Submicron Particulate Emissions and Plume Characteristics, (Exhibit 99).

179 United States Department of Transportation, Frequently As ked Questions (FAQ) - Hazardous Matarials [sic]; http://www.fmcsa.dot.gov/safety-se curity/hazmat/hm-permitting.aspx#one , accessed August 21, 2011.48 Aqueous ammonia, while considerab ly less hazardous than anhydrous ammonia, is nonetheless classified as a toxic su bstance. A safe alternative is therefore to generate ammonia from urea on site. Urea is non-hazardous and can be transported to and stored safely on site. For example, Chemithon’s SafeDeNOx® process generates ammonia from urea for selective catalytic and non-catalytic reduction of NOx. 180

Thus, the risks associated with transpor tation of ammonia perceived by EPA and NDEP can be reduced or avoided altogether. Further, this risk exists for both BART and the rejected SCR technologies, but is more significant for the BART controls.

I.E EPA’s Proposed Higher Controlled Emission Rate for Unit 3 Compared to Units 1 and 2 for ROFA with Rotamix Is Not Justified
EPA, based on NDEP’s analysis, proposes a considerably higher NOx emission limit as BART for Unit 3 (0.28 lb/MMBt u) than for Units 1 and 2 (0.20 lb/MMBtu). 181 The EPA does not discuss why a higher NO x BART limit is proposed for the newer Unit 3 (1976) than for Units 1 and 2 (1965 and 1968, respectively) which are the same size (100 MW) and would be using on the same BART control technology, i.e. , ROFA with Rotamix.

The record fails provide vendor guarantees or any other documentation adequate to explain this issue. In comments on the Draft Nevada RH SIP, the National Park Service and the Fish and Wildlife Service (“NPS/FWS”) requested a justification for the higher NOx limit (and therefore lower control efficiencies) proposed for Unit 3 compared to those proposed for Units 1 and 2, especially in light of the fact EPA’s CAMD data show the lowest current (pre-BAR T) emission rate of the three units for Unit 3. 182 In response, NDEP explained that the emission limit for Unit 3 was based on control efficiency data presented by NV Energy taking into account the uncertainty in vendor emission guarantees and potential for variability. In addition, NDEP stated that the higher emission limits are further expl ained due to the use of different baseline emissions (in lb/MMBtu) as the starting poin t for calculation of emission limits as summarized in the Executive Summary of Nevada Energy’s BART Analysis for Unit 3. 183 We find that NDEP’s explanation is inadequate and does not address the issue. NDEP failed to provide any technical ju stification, why Unit 3 should have higher emissions than Units 1 and 2 after insta llation of the control technology when historically it did not.

180 Chemithon, Enviro Safe Denox® , SafeDeNOx® Urea to Ammonia; http://www.chemithon.com/Enviro_SafeDenox.html , accessed August 19, 2011 (Exhibit 110).

181 76 FR 36463.

182 Nevada RH SIP, Appx. C, pp. C-8 through C-9.

183 Ibid

.49 We have downloaded annual average NOx emission rates for Units 1-3 from EPA’s CAMD database for 2001 through 2010. Fi gure 3 shows these emission rates and compares them to the proposed NOx BART limits for ROFA with Rotamix.

Figure 3: Reid Gardner Units 1-3 historic a nnual average NOx emission rates and proposed NOx BART limits

(data from EPA’s CAMD database)

Figure 3 shows that since 2003, Unit 3 co nsistently emitted NOx at considerably lower emission rates than Unit s 2 and 3. Moreover, Unit 3 has consistently emitted at or below the proposed BART limit of 0.28 lb/MMBtu since 2007, before the 2008 CH2MHill BART analysis was finalized. By 2010, annual average NOx emission rates from Unit 3 decreased to 0.23 lb/MMBtu, 0.05 lb/MMBtu less than the proposed BART emission limit of 0.28 lb/MMBtu. Any NOx control technology installed at Reid Gardner, including the proposed BART contro l, ROFA with Rotamix, should further decrease these emissions. Thus, NDEP and EPA failed to provide an adequate justification that the proposed BART NOx emi ssion limits for Unit 3 should be higher than for Units 1 and 2.50 

### II. NDEP’s BART Determinations Do Not Follow the Methodology Assumed by the EPA

The EPA’s proposed approval of Nevada ’s Regional Haze SIP asserts that the BART determinations “were conducted in a manner consistent with the RHR BART requirements in 40 CFR 51.308(e), the EPA’s BA RT Guidelines, and EPA’s Air Pollution Control Cost Manual.” 184 We agree that the BART dete rminations must satisfy these requirements and follow these guidelines. We further agree that in some places, the NDEP asserts that it did follow these requ irements. However, we disagree that NDEP’s analysis satisfied any of these requirements or made any attempt to follow them. As discussed above, NDEP went far astray in it s efforts to eliminate SCR as BART. This section discusses some of the general flaw s in NDEP’s BART determinations, with emphasis on Reid Gardner, based on EPA’s claims that these requirements were followed.

II.A NDEP Did Not Follow 40 CFR 51.308(e)

The EPA’s proposed approval of Nevada ’s Regional Haze SIP asserts Nevada followed 40 CFR 51.308(e). 185 Our review of the record indicates that it did not follow this regulation in important respects . 40 CFR 51.308(e) requires that the BART determination “must be based on an analysis of the best system of continuous emission control technology available and associated emission reduction achievable for each BART-eligible source, taking into consid eration available technology, costs of compliance, energy and non-air quality en vironmental impacts of compliance, any pollution control equipment in use at the sour ce, the remaining useful life of the source, and the degree of improvement in visibili ty which may reasonably be anticipated.” 186

The chosen BART technology and emission limit for Reid Gardner are not based on an analysis of the best system of cont inuous emission control technology available and associated emission reduction. As discuss ed above, SCR’s are routinely designed to achieve 90%+ NOx control to an emission level of 0.05 lb/MMBtu based on a 30-day rolling average. NDEP’s analysis for SCR for Reid Gardner is based on an SCR designed to remove only 77% of the NOx existing the boiler to 0.085 lb/MMBtu 187 . Thus, NDEP failed entirely to analyze the best system of continuous emission reduction. Instead, it analyzed SCR, the best system, designed to operate far below its best performance level, overstated its costs, rejected it using an improper costing methodology, claimed non-air quality impacts that are actually worse fo r the BART technology, and substituted an

184 76 FR 36464.

185 76 FR 36464.

186 50 CFR 51.308(e)(ii)(A).

187 10/22/09 NDEP BART Review, Table 1, pp. 5-6.51 inferior technology that does not satisfy the “best system of continuous emission reduction.”

II.B NDEP Did Not Follow EPA’s BART Guidelines

Section 169A(b)(1) of the Clean Air Act requires EPA to issue regulations to provide guidelines to states on the implemen tation of the regional haze program. EPA promulgated the Guidelines for Best Available Retrofit Determinations on July 6, 2005. (70 FR 39104-39172.) The BART Guidelines la y out fundamental principles that are followed in preparing regulatory cost analyses that have been relied on for decades to estimate costs to comply with other variou s technology requirements of the Clean Air Act, including best available control tec hnology (“BACT”), lowest achievable emission rate (LAER), maximum achievable contro l technology (”MACT”) , and reasonably achievable control technology (”RACT”). NDEP refers to these Guidelines in numerous places. 188

EPA mandates use of the BART Guidelines in making BART determinations for power plants with a generating capaci ty of 750 Megawatts (“MW”) or greater. 189 With exception of the Mohave Generating Station, all power plants in Nevada subject to BART, i.e.
, Nevada Energy’s Tracy, Churchill, and Reid Gardner generating stations, have generating capacities less than the 750 MW threshold above which the use of EPA’s BART Guidelines for BART determinations becomes mandatory. 190 (The operating permit for the Mohave Generatin g Station was terminated and the facility permanently ceased operation on December 31, 2005. 191 ) NDEP has made clear that it is neither legally required to nor did it fo llow EPA’s BART Guidelines for its BART determinations for the other three facilities. 192 However, EPA relies on the assumption that it did in its proposed SIP approval. Our review of the record indicates that NDEP did not follow the BART Guidelines in impo rtant respects. Our review of the record also did not identify any reasoned al ternative approach to making a BART determination.

188 For example, 10/22/09 NDEP BART Review, p. 1 (“Explanation: BOLD text below identifies the Guidelines for BART Determinations under the Regional Haze Rule in Appendix Y of 40 CFR 51,” implying that NDEP’s review was conduc ted according to the BART Guidelines.)

189 70 FR 39108.

190 76 FR 36462-36463.

191 76 FR 36463.

192 Nevada RH SIP, Appx. C, p. C-3.52 II.B.1 Averaging Time Is Incorrect
NDEP selected a 12-month rolling average for monitoring emissions of nitrogen oxides (“NOx”) from Tracy, Fort Church ill and Reid Gardner generating stations instead of the 30-day rolling average sp ecified in EPA’s BART Guidelines. 193 NDEP in their response to comments on the draf t Nevada RH SIP expressly rejected recommendations by the Federal Land Ma nagers (“FLMs”) to specify a shorter averaging time of 30 days for monitoring of NOx emissions because Nevada’s BARTeligible power plants (with exception of the Mohave Generating Station) have generating capacities less than the 750 MW threshold and are thus not required to follow the guidelines. 194

Further, neither NDEP nor the EPA specify monitoring times, times of operation, fuel input, or other indices of operating conditions sufficient to show compliance or non-compliance or provide for adequate repo rting and recordkeeping so that air quality agency personnel can determine the compliance status of the source, as required by the EPA’s BART Guidelines to ensure that proposed BART emission limits are enforceable. 195

II.B.2 Design Parameters Are Missing
The Guidelines lay out the process for co nducting a BART cost analysis. The first major step in this process is to identify the design parameters for each emission control. 196 This is fundamental to any cost analysis for any purpose and is not specific to these Guidelines. ( See , for example, the EPA’s New Sour ce Review Manual at page B.32: “Before costs can be estimated, the control system design parameters must be specified.”) One cannot develop a meaningful cost analysis without specifying the relevant design parameters.

The docket in this case does not contai n the design parameters used to evaluate the BART controls. The 10/08 CH2MHill BART Analysis, Appendix A, includes certain “input calculations,” but these do not includ e the pollution control design parameters. For example, for SCR, the record does not disclose any of the key SCR design parameters, including the ammonia slip, the SO 2 to SO 3 conversion rate, the catalyst configuration ( e.g. , 3 catalyst layers + 1 spare or 3+1), the catalyst life, the catalyst volume, number of reactors, catalyst specific area, catalyst pitch, reactor and catalyst

193 76 FR 36462-36463; Nevada RH SIP, p. 5-12; 70 FR 39172.

194 Nevada RH SIP, Appx. C, p. C-3.

195 70 FR 39172; Nevada RH SIP, §5.5.

196 70 FR 39166.53 dimensions, and detailed coal quality information. ( See
, e.g. , a typical catalyst design for another facility shown in Exhibit 111. 197 )

This type of information is commonly provided when cost ing an SCR and is required here to assess the claimed capital cost of the SCR and to determine if it satisfies the “best system of continuous emission re duction.” The same is true for SNCR and ROFA Rotamix, which likewise are pres ented without the underlying design parameters, e.g. , ammonia slip, NOx to NH 3 molar ratio 198 , etc. Thus, it is not possible to determine if the proposed design of any of the NOx controls represent the “best system of continuous emission reduction.”

II.B.3 Equipment List Is Missing

Second, the BART Guidelines indicate that a cost analysis must include a list of equipment and associated costs. 199 This is also fundamental to cost analysis, regardless of the guidance that is followed. The NSR Manu al, for example, explains that the second step of a cost analysis is to “to list and co st each major piece of equipment within the battery limits.” 200 Standard cost estimating textbooks explain the importance of this key foundational step. 201

The cost analyses that EPA and NDEP re lied upon do not identify the equipment that it costed, instead reporting only lump sum estimates for each control from vendor quotes. These lump sums add up costs for in dividual pieces of equipment required to build the control systems. Th e underlying vendor quotes are not supplied, preventing any meaningful review or revision to accommoda te NDEP’s change in baseline. It is not possible to evaluate a lump sum cost with out the supporting vendor quote, which will typically identify and separately cost the co mponents. In addition, the cost analyses include certain “balance of plant” costs that are not broken out so their components can be individually assessed.

Applicants seeking to avoid the installati on of more effective, but more costly controls, such as SCR, frequently pad cost es timates with items that are not part of and are not required for the control. These incl ude costs for brand new electrical systems,

197 CERAM, Project: IPALCO Harding St Unit 7, July 7, 2003.

198 The 10/08 CH2MHill BART Analyses provide the stoichiometric ratio for NH 3 to NOx conversion (1.0) but fail to provide the ratio that is expected to be achieved for operating condit ions. These, as discussed in Comment I.B.1.f, are higher than 1.0 due to ammonia slip.

199 70 FR 39166.

200 NSR Manual, p. B.33.

201 K.K. Humphreys and P. Wellman, Basic Cost Engin eering, 3rd Ed., Marcel Dekker, Inc., 1996, Chapter 2, Table 2.3, and Chapter 3 (Exhibit 112).54 induced draft fans, stacks, conversion of the boiler from pressurized to balanced draft, SCR bypasses, and major modifications to ai r preheaters, among others. These types of costs are unwarranted for retrofit SCRs on un its burning low sulfur coal and only serve to artificially inflate costs. It is impossible to determine whether the capital costs for the SCR options at Reid Gardner, for example, in clude unnecessary costs as the components of the capital cost estimate are not specified, i.e. , they are presented as two lump sums: (1) major materials design and su pply and (2) balance of plant.

Similarly, applicants seeking to install a cheaper control can understate its cost to favor its selection by not including all of the components. The NDEP concluded that BART for NOx emissions at Reid Gardner is satisfied by ROFA with Rotamix. This combination includes several pieces of equipment. The ROFA requires a ROFA fan, ROFA boxes, ROFA dampers, and expansion joints. The Rotamix equipment includes a fan, reagent injection devices, tanks, pumps, and filters. There is no way to determine if the costs that NDEP relied on include all of the equipment necessary to operate the ROFA with Rotamix option.

The EPA explains in the BART Guidance (that it alleges NDEP followed): “The analysis should provide a clear summary lis t of equipment and the associated control costs. Inadequate documentation of th e equipment whose emissions are being controlled is a potential cause for confusion in comparison of costs of the same controls applied to similar sources.” 202 The costs used in the NDEP analysis are undocumented, preventing meaningful review.

II.B.4 Documentation for Cost Estimates Is Missing

Third, the BART Guidelines that EPA alleges NDEP followed recommends documenting assumptions regarding design parameters and equipment costs estimates, with either data supplied from an equipment vendor or citations to a referenced source, such as EPA’s Control Cost Manual (discuss ed below). The EPA explains: “You should include documentation for any additional information you used for the cost calculations, including any information supplied by vendors that affects your assumptions regarding purchased equipment costs, equipment life, replacement of major components, and any other elements of the calculation that differs from the Cost Control Manual.” 203

This standard practice is required for all regulatory cost analyses. 204 However, here, the cost analysis NDEP relied on an d EPA is proposing to adopt without any

202 70 FR 39166.

203 70 FR 39166, Footnote 15.

204 See
, e.g. , NSR Manual, p. B.33.55 independent analysis is wholly unsupport ed. NDEP, and consequently, EPA, took Nevada Energy’s assumptions for cost analys es for each control technology at face value. This includes NOx control efficiencies ; economic factors such as interest rates, discount rates, and plant economic life; insta lled capital costs; total fixed and variable operating and maintenance costs; reagent cost s; catalyst replacement costs; auxiliary power costs; etc. There is no support for any input into the analyses, including the calculations themselves that were used to arri ve at the cost effectiveness numbers. As explained elsewhere, we had to reverse-engi neer the cost spreadsheets as the record does not contain and NDEP did not su pply spreadsheets that disclosed these calculations.

Documented costs are particularly critical here as cost is the primary parameter that NDEP used to reject th e most effective NOx control technology, SCR. The record indicates that NDEP accepted the company’s cost estimate without critically reviewing it. In fact, critical review would not have been feasible as the costs are unsupported.

II.B.5 Other Missing Documents, Modeling Files, and Information
Documents, modeling files and informatio n missing from EPA’s docket for the proposed rule include:

 Appendix B (BART Protocol) to Nevada Energy’s BART Analyses for Reid Gardner Units 1-3. 205

 Input calculations to support NDEP’s economic analysis contained in the 10/22/09 NDEP BART Review. 206

 Support for NDEP’s baseline emission scenarios for NOx (using acid rain data) and PM10 (using annual emission s reported to NDEP) for calendar years 2001 through 2007 as described in 10/22/09 NDEP BART Review, p. 6. 207

 Vendor guarantees or quotes obtained for and relied upon for the 10/08 CH2MHill BART Analyses.

205 Andrew Gray, Gray Sky Solution s requested this document and re ceived it from Adele Malone, NDEP, via mail.

206 Adele Malone, NDEP, in an email to Andrew Gray , Gray Sky Solutions, August 9, 2011, declared “With respect to the input files for alternative NOx co ntrol scenarios, the NDEP doesn’t have these files. We haven’t requested additional files from NV Energy.” ( See Exhibit 20.)

207 Excel spreadsheet ‘Copy Acid Rain Annual Data BART NVE (4).xls’ provided via email by Adele Malone, NDEP, to Andrew Gray, Gray Sky Solutions, on August 11, 2011 (Exhibit 20).56  Report by Nevada Energy entitled “F ly Ash Conveyor System – Units 1, 2, and 3,” dated January 18, 2007, cited in 10/08 CH2MHill BART Analyses, Footnotes to Table 2-2, p. 2-3, respectively.

 Visibility modeling files.

 Appendices A through F to Letter from National Park Service (“NPS”) and U.S. Fish and Wildlife Service (“USFWS”) to NDEP. 208

II.B.6 Costing Methodology Is Inconsistent With BART Guidelines

The BART Guidelines set out an approach to determine the “cost effectiveness” of pollution controls. 209 Under these Guidelines, cost-effe ctiveness, measured in dollars per ton of pollutant removed, is calculated according to the EPA Air Pollution Control Cost Manual or “Cost Manual,” which EPA also alleges NDEP followed. 210 However, as explained elsewhere in these comments , NDEP did not follow the methodology recommended in the BART Guidelines and infact used a method to determine costeffectiveness that has never been approved for any regulatory cost analysis under the Clean Air Act and would always result in rejecting the “best system of continuous emission reduction.”

II.C NDEP’s Analysis Did Not Follow E PA’s Air Pollution Control Cost Manual
The EPA’s proposed approval of Nevada’s Regional Haze SIP asserts that NDEP followed EPA’s Air Pollution Control Cost Manual. 211 Our review of the record indicates that NDEP did not follow the Cost Manual. The NDEP cost analysis deviates in significant ways from the Cost Manu al, as documented in Comment I.B.

208 Letter from Chris Shaver, National Park Service, and Sandra Silva, U.S. Fish and Wildlife Service, to Michael Elges, Nevada Division of Environmental Protection, March 6, 2009, EPA-R09-OAR-2011-0130- 0041.

209 70 FR 39166 to 39172.

210 76 FR 36464.

211 76 FR 36464.