# Joint Appendix — Environmental Defense v. Duke Energy Corporation > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/brief%3Amicro_IA40385016_0237%3A09 ## Record - **Collection:** Supreme Court brief - **Document type:** Joint Appendix - **Published:** January 1, 2007 - **Citation:** 549 U.S. 561 ## Text 42 | _FILE COPY No. 05-848 jn The OFFICE OF THE CLERK | Supreme Court of the Gnited States Supreme Court, US FILED | ENVIRONMENTAL DEFENSE, et ai., Petitioners, v. DUKE ENERGY CORPORATION, et ai., Respondents. SJ On Writ Of Certiorari To The United States Court Of Appeals For The Fourth Circuit ¢ JOINT APPENDIX VOLUME I, Pages 1 to 265 + SEAN H. DONAHUE CARTER G. PHILLIPS Counsel of Record Counsel of Record 2000 L St., NW MarK D. Hopson Suite 808 KATHRYN B. THOMSON Washington, DC 20036 STEVEN M. NICKELSBURG (202) 466-2234 SIDLEY AUSTIN LLP (202) 315-3582 Fax 1501 K St., NW Washington, DC 20005 (202) 736-8000 (202) 736-8711 Fax iH) nsel for Respondent RECEIVE D uke Energy Corporation Counsel for Petitioners JUL 25 2005 PAUL D. CLEMENT olicitor General OFFICE OF THE CLEP: Counsel of Record | St JPR, a Ecc UIT, U. SD partment of Justice Washington, DC 20530 (202) 514-2217 (202) 514-8844 Fax Counsel for Respondent The United States [Additional Counsel Listed On Inside Cover] as Petition For Certiorari Filed December 28, 2005 Certiorari Granted May 15, 2006 oe COCKLE LAW BRIEF PRINTING CO (800) 225-6964 OR CALL COLLECT (402) 342-2831 BEST AVAILABLE COPY C ‘ounsel For Petitioners: JE: FFREY M: GL EASON. > J.: BLANDING HOLMAN; IV: C Al EB JAFFE | "LAW Coste R Counsel: for Respondent ‘} . “Duke Kriergy Corporation: Hexky N --Nickes: +% F. Ww ILLIAM- Bow: Nett elt 4. “MAKRANIB. TA XBER™ 200 W. Franklin, Suite 330 HUNTON ‘& Wi. L. iaMs S LLP Chapel Hill, NC 27516. (434) 967-1450 VICKIE PATTON ENVIRONMENTAL DEF ENSE, 2334 North Broadway Boulder; CO 80304 » (303) 447-7215 ge, Dav 1p T. GOLDBERG - 99 Hudson St1., 8th Floor | New York, XY 10013 - - (212) 334-8813 . 1900 K Street; »NW.- Washington;: ‘DC. 20006 (202) 955- 1500 » of THOMAS Co’ rTINGHAM, IL Nasu E. Lone, Ill ‘HUNTON & WILLIAMS ELP 101 South Tryon’Strect, * * Suite 3500". °. +: _Charlotte, NC 28280. (704) 378-4700 - MARC E. MAN! LY” "Executive Vice President “and Chief Legal Officer’ * CATHARINE S..STEMPIEN ; 3 Associate General’ Counsel Garry S. RICE ° Associate General Counsel ‘DUKE ENERGY CORPORATION ‘Legal:Department 526 South Church Sireet ; ‘-ECO3T° Charlotte; NC 28242 (704) 382-8111 ‘Dean’ M. Moésser’ : DUKE: ENERGY CORPORATION 5400 Westheimer. Court -Houston,.TX 77056 » (713) 627-5298 BEST AVAILABLE COPY i TABLE OF CONTENTS Page VOLUME I! District Court Docket Entries .....-------serensrr 1 Court of Appeals Docket PEntries.....-.s-0-csecnsnenereneserensnersneere® 9 Order Granting Intervention (Sept. 6, 2001) (CR (District Court Docket Number] 25) ...-----rrrrrrrn 10 Exhibits in Support of Duke’s Motion for Summary Judgment (Jan. 31, 2003) (CR 129) Letter from Administrator Lee M. Thomas to Congressman J ohn D. Dingell (May 9, 1986) (DX [Defendant's Exhibit Number] 9).-.------sr-rrn 11 Expert Report of Walter C. Barber (August 15, 2002) (pp. 5-10) (DX Se nlecscenensenainnecanenesnnenemer en 16 Memorandum from Edward E. Reich, et al., EPA to Allyn M. Davis, et al., EPA Region VI (April 21, 1983) (DX 16)..-.--sserrerseeseerensrsererernsnnnrnene TT 23 Letter from Edward E. Reich, Director, Division of Stationary Source Enforcement, EPA, to Amas- jit S. Gill, General Electric — Gas Turbine Divi- sion (June 24, 1981) (DIK 28) ..--0v--nseenseneennensennsensenssenrenns 27 Letter from Edward E. Reich, EPA, to Charles Whitmore, EPA Region VII (Jan. 22, 1981) (DX Letter from Administrator Lee M. Thomas to John W. Boston, Vice President, WEPCO. (Oct. 14, 1988) (DX DOD cexseccocccsenenvsvscsonsscssoonens svensesensensnseneess 38 Memorandum from David Kee, EPA, to Gerald A. Emison, EPA (Mar. 25, 1988) (DX 31).....---cereerereerenerere® 49 Deposition of Walter Stevenson (Sept. 10, 2002) (pp. 1, 42-45) 0 ene een occmmmemmmmmsnenets 52 TABLE OF CONTENTS - Continued Letter from William G. Rosenberg, Assistant Administrator for Air and Radiation, to John Boston, President, WEPCO. (June 8, 1990) (DX FD scocecsenssevensnentnnimesensiichsnniionnpacitedninnbiiveimuiinniidibimeinet EPA Office of Air Quality Planning and Stan- dards, Proceedings of Acid Rain Conference, April 8-9, 1990 (Aug. 1980) (DX 36) ............cccceesecceeeeeeeneees Acid Rain and Nonattainment Issues, Hearing Before the Senate Subcommittee on Environ- mental Protection of the Committee on Environ- ment and Public Works, 100th Congress (statement of Administrator Lee Thomas) (Apr. BR, BRIG Ge Be Pecccccnepeeresensscnssresevesecesecceutecsvetsenases Expert Report of Kenneth Schweers (Aug. 15, BE GEE Die cccscccciscscrinasivevtensnennicncsnvasnepnsstormesnesuness 1989 EPA Base Case Forecasts, prepared for EPA by ICF Resources, Inc. (May 1989) (DX 40)............. Letter from Kenneth A. Schweers, ICF, to Robert A. Beck, Edison Electric Institute (July 26, 1989) Ge Ge Pecsccsversccepnisnicesessninintesnatorinnasantntinisemipetenctiinonee Electricity Supply: Older Power Plants’ Impact on Reliability and Air Quality, GAO Report to the Chairman, House Subcommittee on Oversight and Investigations, Committee on Energy and Commerce (Sept. 1990) (DX 42) .......... ccc ccecceceeeeee eens Deposition of Steven Tiber (May 15, 2002) (pp. 1, PEED Ge GR ce cescsvececcccceserenceresecennsenssennpeusepessessceenss Page ee rr 7 ill TABLE OF CONTENTS - Continued Letter from William G. Rosenberg, EPA to Congressman John D. Dingell (June 19, 1991) Billi iciiivissaseneisnsecectvetaiisioinnienmniaéemdbutaiansntsnidireiedutabutasetninins Declaration of Kris W. Knudsen (Jan. 30, 2003) i a i a a Deposition of Ranajit Sahu (Nov. 25, 2002) (DX SE csicliahhesicesctalsechaiiididaateidipecihneniehipiaiiichtinabaduicesiainladiaienuidintedsneteds Deposition of David A. Lloyd under Fed. R. Civ. P. 30(b)(6) (Oct. 4, 2001) (DX 72)... cceecececteeeeeeeeeeeeeeeens Memorandum from Jack R. Farmer, EPA (May I Ei ealeiciecetneercicnibtibcipieptnesiiianemadiaeaiintaniabdennitidn Letter from Ronald V. Shearin, Duke Power Co., to Robert F. Helms, NCDNR (Aug. 17, 1983) (DX RRR Ee aaa ee ws EE ELS Ree nO NS See Ree OT Letter from Ronald V. Shearin, Duke Power Co., to Roger E. Davis, SCDHEC (Aug. 17, 1983) (DX SEES Ao RS TE Sr. ar ower SOUR az aem sn ee Ue SeenON Letter from William W. Culler, SCDHEC, to Ronald V. Shearin, Duke Power Co. (Aug. 23, SERRE SES Aare anes ena wee ane ene Te Letter from Robert V. Helms, NCDNR, to Ronald V. Shearin, Duke Power Co (Sept. 15, 1983) (DX ETA IE I ae eee cr ee a nee ee Letter from B. Keith Sipe to Ray M. Davis (Apr. ee NET Gee icicniniecsinsnnintccnionstenatsitipemimeiatniieseiee Certified Inspection Reports, Air Quality Action Request, Duke Power Co., Buck Steam Station Ici I i i i iain iv TABLE OF CONTENTS - Continued Page ; Exhibits in Support of United States’ Motion for Partial Summary Judgment (Jan. 31, 2003) (CR 133) 1 Direct Testimony of William S. Lee, Chairman of the Board and CEO, Duke Power Co., Before South Carolina Public Service Commission (July 30, 1985) (USX [United States’ Summary Judg- ; ment Exhibit Number] 13)............cccssessssssssssrssesseseoees 198 Redirect Testimony of William S. Lee, Chairman of the Board and CEO, Duke Power Co., Before ; North Carolina Utilities Commission (July 16, Se IIE: THEI cccccntacecscsiscdsintincatantinimmiteniiiagiteausiainasiitiaies 205 Duke Power Co., Proposed Order Granting Rate Increase, Before the North Carolina Utilities Commission (Aug. 27, 1985) (USX 19).................eeeeeee 211 Direct Testimony of William S. Lee, Chairman of the Board and CEO, Duke Power Co., Before North Carolina Utilities Commission (Sept. 3, SOBE) CIEE BE) accceccecccrssscsescseinnsatinnotssdotovcssetsenseagnsienses 223 Memorandum to File re: Fossil Units — Extended Cold Shutdown (Feb. 1, 1985) (USX 22) .........:..:cccseee 227 Plant Modernization Project, Project Review (April 24, 1989) (USX 28)................-ccrsssssosssssesseseeseees 229 Memorandum of William O. Parker re: Plant Modernization Program Strategy Statement GR. SER, Be Cae MD crnccetctecevintsntnctisciadaintadsninaianl 232 Direct Testimony of William S. Lee, Chairman of the Board and CEO, Duke Power Co., Before North Carolina Utilities Commission (April 12, I GRE GD diicdencddinicnseninaieintiannnnsetiduiduditeiaiiieaiuiata 233 Project Outage Table (USX 40) .0...... eee eeeeeeeeeeee 236 TABLE OF CONTENTS -— Continued Duke Training and Reference Guide, Fossil Environmental Compliance, Volume 2 - Air Quality (Sept/Oct. 1991) (USX 57) .........cccccccccecseeeeees Memorandum of Don Clay, Acting Assistant Administrator, EPA, to David Kee, Director of Air and Radiation Division, EPA Region V (Sept. 9, RETEST VOLUME II Letter from Henry Nickel, Hunton & Williams, to Polly Gault, U.S. Dept. of Energy (June 5, 1989) NE EE ee Memorandum from J.O. Fayssoux to W.O. Parker, Jr. re: EEI Prime Movers —- WEPCo. (Feb. 5 TE STINET Memorandum re: NSPS/PSD Implications of Plant Modifications (USX 93A) ..............cccccceseseeeeeeeees Letter from Don R. Clay, Acting Administrator for Air and Radiation, EPA, to John W. Boston oe rerrnriniichneeeenngtnanttenadeemnanenn Letter from Francis X. Lyons, Regional Adminis- trator, EPA Region V, to Henry Nickel, Counsel for Detroit Edison Co. (May 23, 2000) (USX 101)....... In re Monroe Electric Generating Plant Proposed Operating Permit, Petition No. 6-99-2 (EPA 1999) EE TABLE OF CONTENTS -— C-mtinued Page Exhibits in Support of United States’ Response to Duke’s Motion for Summary Judgment (Mar. 31, 2003) (CR 152) Deposition of Laura Butler (Dec. 10, 2002) (USX Siri nccsliietncecseaneneneiasininditriadiitieipctindiiiesittiiatieaatiaaniatasstenaaaslicceatinateds 311 Deposition of Michael Parkin (Dec. 10, 2002) ey Seer ne nee eRe 314 Deposition of Michael Landis (Dec. 11, 2002) TE Uae csiieseincapiisitieasiteiashctineiatinenaeindadianpaninniataptiaabitienbaaranaintieaads 338 Deposition of Thomas McManus (Dec. 11, 2002) PS Sei ciciccicliininrectetencithtriaenbidiestaientatieniadnenanicisinmtineastnsiistteiaiis 353 Memo re: Key Regulations and Issues Impacting Alternative Fuels, Fuel Additives, and Facility Modifications (Feb. 13, 1995) (USX 146) .................... 366 Duke Energy 1995 Training Materials (USX 147) .....371 Memo from Bobby McManus re: MSS 3&4 Mill Replacement and PSD/NSPS Meeting (May 23, IE Tt ichsiedibeeiinticcinntttniteanegeidinsneineptiiniamteininsitniin 372 Duke Internal Emails (Nov. 1990) (USX 149)............. 375 Deposition of William T. Horton (Dec. 4, 2002) SPRITES Ut iictnctciactnedbtuniniianinsemetseiitinsnetaiatiiteatitmimatasds 385 Expert Report, Ranajit Sahu (Aug. 1, 2002) (USX ore ccerenanhtecesliealstniniahtieaiseinintiaabanestaaiacitintaainiaalnian testa intataaasiiiaeaaa 388 Statement of Henry V. Nickel, EPA Docket No. A- RIT Tartttt cinsihiccepesncetritnsinateiahasitsiaibiaiiilahiniiiaiiidinateaenais 453 vii TABLE OF CONTENTS - Continued Supplemental Exhibits in Support of Duke’s Motion for Summary Judgment (March 31, 2003) (CR 158) Energy Resource Consultants, Inc., Report to the Public Staff, North Carolina Public Utilities Commission - The Duke Power Company’s Plant Modernization Program and Catawba Unit 2 (Volume II: Analysis of Life Extension) (DX 114) (pp. internal cover page, II-1-4, []-2-21) ..................... 460 Memorandum from Edward E. Reich, Director, Stationary Source Compliance Division, EPA Office of Air Quality Planning and Standards, to Harley Laing, EPA Region I re: Bridgeport Har- bor Coal Conversion (July 28, 1983) (DX 129)............ 464 Deposition of Ranajit Sahu (Nov. 26, 2002) (DX Be cescasstncntnesnnessusrtgnasssnncenmanciermmenemmeneenetiommenttaness 473 Memorandum from Edward A. Reich, Director, DSSE, to Thomas W. Devine, Chief, Air Branch, EPA Region I (Feb. 13, 1978) (DX 143)...............000-+++ 477 Deposition of John Hewson, pp. 1, 64-65, 69-70 ee Fe ncertctcerreepaiernesinnmmpeinenctieamenanmmnemenios 484 Memorandum from Gerald A. Emison, EPA, to William G. Rosenberg, EPA (May 25, 1990) (DX 189)..... 489 Exhibits in Support of United States’ Response to Duke’s Proposed Supplemental Memorandum in Support of Its Motion for Reconsideration (Oct. 8, 2003) (CR 240) Analysis of Potential Cost, Environmental and Energy Implications of EPA’s Recent WEPCO and Greenwood Decisions, prepared by ICF Re- sources for UARG (Jan. 1990) (Exhibit 1) .................. 492 TABLE OF CONTENTS - Continued Page Order (Feb. 23, 2004) (CR 294) .0............:ccssssceesseseeeeeenees 499 Stipulations (April 13, 2004) (CR 311)............ccceeeeeeeeees 503 The following opinions, judgments, and orders have been omitted in printing this Joint Appendix because they appear on the following pages in the appendix to the petition for certiorari: United States District Court for the Middle District of North Carolina: Memorandum Opinion (August 26, SID vacsemmepnesnsssteuscetnssmeneainaniimenecsmenmn Pet. App. 22a-84a Order and Judgment (August 26, PIED cosssnansenntacmscnsmensamircenpenseemibecnenss Pet. App. 85a-86a Order and Final Judgment (April 14, FEED scvreninndacsaccnpssnnsistapincennegtstnieniottnbouses Pet. App. 87a-95a United States Court of Appeals for the Fourth Circuit: Order Requesting Supplemental! Briefing yg 8 ee Pet. App. 21a Opinion (June 15, 2005)......................... Pet. App. la-19a Order Denying Petitions for Rehearing and Rehearing En Panc (Aug. 30, 2005)..... Pet. App. 20a Date Filed 12/22/00 3/12/01 5/8/01 9/6/01 1 RELEVANT DOCKET ENTRIES U.S. District Court Middle District of North Carolina (Durham) CIVIL DOCKET FOR CASE USA v. Duke Energy Corp. Docket Entry # 1 3 5 24 #: 00-CV-1262 Description Complaint filed. (Entry date: 12/28/00) Answer to Complaint and Counterclaim by Duke Energy Corp. (Attorneys DANIEL W. FOUTS, T. THOMAS COTTINGHAM IID) against USA; Answer due on 4/1/2001 for USA (Entered: 03/13/2001) Motion by Environmental Def., NC Sierra Club, NC Public Interest to Intervene as Plaintiffs (Entered: 05/09/2001) MEMORANDUM OPINION on appli- cants’ motion to intervene; applicants have a statutory right to intervene and their motion to intervene will be granted pursuant to Rule 24(aX1) of the Fed.R.Civ.P.; applicants’ participation in the litigation will be coordinated with that of the Plaintiff United States to ensure the efficient adjudication of this case; an order in accordance with this memorandum opinion shall be entered contemporaneously herewith (signed by JUDGE FRANK W. BULLOCK JR.) (EOD Date 9/6/01). 9/6/01 9/6/01 10/9/01 12/18/02 12/18/02 1/31/03 25 26 35 94 95 128 —_ - 2 ORDER, for the reasons set forth in the memorandum opinion filed contempo- raneously herewith, that Applicants Environmental Defense, North Caro- lina Sierra Club, and North Carolina Lobby/Education Funds motion to untervene [Doc. #5] is GRANTED (signed by JUDGE FRANK W. BULLOCK JR.) (EOD Date 9/6/01). Complaint in Intervention (Entered: 09/06/2001) ANSWER to Plaintiffs-Intervenors’ Complaint by DUKE ENERGY CORP. (Entered: 10/11/2001) MEMORANDUM OPINION re: the United States’ motion for leave to amend the complaint; an order in accordance with this memorandum opinion shall be entered contempora- neously herewith (signed by JUDGE FRANK W. BULLOCK JR.) (EOD Date 12/18/02). ORDER, for the reasons set forth in the memorandum opinion filed contemporaneously herewith, that the motion [Doc. #72] of the United States for leave to file an amended complaint is DENIED * * * (signed by JUDGE FRANK W. BULLOCK JR.) (EOD Date 12/18/02). MOTION for Summary Judgment on all of Plaintiff’s and Intervenors’ claims that Duke violated the New Source Review provision of the Clean 1/31/03 1/31/03 1/31/03 1/31/03 129 130 131 132 152 3 Air Act and related States Implemen- tation Plan provision of North and South Carolina by defendant DUKE ENERGY CORP. (Entered: 02/03/2003) Brief, with Appendices in Five (5) Volumes ... by Duke Energy Corp. in Support of [128-1] Motion for Sum- mary Judgment *** (Entered: 02/03/2003) MOTION for Partial Summary Judg- ment on Defendant’s Defenses of “Fair Notice” and JOINDER IN MOTION for Partial Summary Judgment by the United States on the applicable legal test for “routine maintenance”; on Defendant’s defenses on “routine maintenance”, emissions calculations and defendant’s “statute of limitations” defenses by intervenor-plaintiffs NC PUBLIC INTEREST, NC SIERRA CLUB, and ENVIRONMENTAL DEF. (Entered: 02/03/2003) Brief, with Exhibits 1-21, by NC Public Interest, NC Sierra Club, Environmental Def. in Support of [130- 1] Motion * * * (Entered: 02/03/2003) MOTION for Partial Summary Judgment on the applicable legal test for “routine maintenance,” Defen- dant’s defenses of “fair notice” and “routine maintenance”, calculation of emissions, and defendant’s “statute of limitations” defenses by plaintiff USA (Entered: 02/03/2003) RESPONSE by USA to [128-1] motion for Summary Judgment on all of 3/31/03 3/31/03 3/31/03 4/25/03 158 159 160 174 4 Plaintiff’s and Intervenors’ claims that Duke violated the New Source Review provision of the Clean Air Act and related States Implementation Plan provision of North and South Carolina by DUKE ENERGY CORP. (Entered: 04/01/2003) RESPONSE BRIEF IN OPPOSI- TION, with Supplemental Appendix of Exhibits in four (4) Volumes, by DUKE ENERGY CORP. to [132-1] motion for Partial Summary Judg- ment * * * (Entered: 04/01/2003) BRIEF IN RESPONSE with Exhibits by ENVIRONMENTAL DEF, NC SIERRA CLUB, NC PUBLIC INTER- EST to [128-1] motion for Summary Judgment * * * (Entered: 04/01/2003) RESPONSE BRIEF IN OPPOSITION by DUKE ENERGY CORP. to [130-1] motion for Partial Summary Judgment on Defendant's Defenses of “Fair Notice” by Plaintiff-Intervenors, ENVI- RONMENTAL DEF, NC SIERRA CLUB, NC PUBLIC INTEREST (Entered: 05/12/2003) AMENDED RESPONSE BRIEF IN OPPOSITION, with attachments, by DUKE ENERGY CORP. to Plaintiff's [132-1] motion for Partial Summary Judgment on the applicable legal test for “routine maintenance,” Defendant’s defenses of “fair notice” and “routine maintenance”, calculation of emissions, and defendant’s “statute of limitations” defenses (Entered: 04/28/2003) 4/30/03 4/30/03 4/30/03 4/30/03 4/30/03 7/18/03 8/13/03 185 186 187 188 189 231 5 REPLY by DUKE ENERGY CORP to Plaintiff-Intervenors’ response to [128-1] motion for Summary Judg- ment * * * (Entered: 05/01/2003) REPLY by DUKE ENERGY CORP to Plaintiff, USA’s response to [128-1] motion for Summary Judgment * * * (Entered: 05/01/2003) SECOND SUPPLEMENTAL APPEN- DIX OF EXHIBITS in one (1) volume by DUKE ENERGY CORP. in sup- port of (128-1) motion for Summary Judgment * * * (Entered: 05/01/2003) REPLY, with Exhibits 1 & 2, by Plaintiff-Intervenors’ NC PUBLIC INTEREST, NC SIERRA CLUB, ENVIRONMENTAL DEF. in support of [130-1] Motion Summary Judg- ment on Fair Notice (Entered: 05/01/2003) REPLY, with Appendix A and sup- porting Exhibits 156-165, by USA to response to [132-1] motion for Partial Summary Judgment * * * (Entered: 05/01/2003) Motion hearing held re: [132-1] motion for Partial Summary Judg- ment * * * , {130-1} motion for Partial Summary Judgment *** , [128-1] motion for Summary Judgment * * * held before USDJ Frank W. Bullock, dr. * * * (Entered: 07/21/2003) TRANSCRIPT of ORAL ARGU- MENTS ON MOTIONS FOR SUM- MARY JUDGMENT filed, held before 8/26/03 8/26/03 234 235 6 JUDGE FRANiw W. BULLOCK, JR. * * * (Entered: 08/14/2003) MEMORANDUM OPINION that, for the reasons set out, the court will grant in part and deny in part the EPAs motion for partial summary judgment in which Intervenor-Plaintiffs join; * * * (signed by JUDGE FRANK W. BULLOCK JR.) (Entered: 08/26/2003) ORDER AND JUDGMENT, for the reasons set forth in the memorandum opinion filed contemporaneously herewith, that Duke Energy’s motion for summary judgment [Doc. #128] is DENIED; further ORDERED that the United States’ motion for rartial summary judgment [Doc. #132] on the applicable legal tests for “routine maintenance” and calculation of emissions, and on Duke Energy's defenses of “fair notice” and “routine maintenance”, in which Intervenor- Plaintiffs join (Doc. #130], is DE- NIED; further ORDERED AND ADJUDGED that the United States’ motion for partial summary judg- ment (Doc. #132] on Duke Energy’s defense that the statute of limita- tions bars the United States’ claims arising from activities occurring prior to December 22, 1995, in which Intervenor-Plaintiffs join [Doc. #130}, is GRANTED; further ORDERED that Intervenor-Plaintiffs’ motion for partial summary judgment ([Doc. #130] on Duke Energy's defense of “fair notice” is DENIED; further 12/23/03 12/29/03 2/23/04 268 270 294 7 ORDERED that Duke Energy’s motion for partial judgment on the pleadings [Doc. #37] is DENIED. Remaining for trial are the issues of whether Duke Energy’s projects were routine maintenance, repair, and replacement as defined relative to the industrial category and whether Duke Energy’s projects caused an increase in annual net emissions, assuming constant hours and condi- tions of operation (signed by JUDGE FRANK W. BULLOCK JR.) (Entered: 08/26/2003) MOTION by USA for Reconsideration of [235-1] judgment and [234-1] order or, in the alternative, to certify orders for interlocutory appeal and for stay pending appeal. (Entered: 12/29/2003) Response by NC Public Interest, NC Sierra Club, Environmental Def., to the [268-1] USA’s Motion for Recon- sideration * * * (Entered: 12/30/2003) ORDER denying [268-1] motion for Reconsideration of [235-1] judgment and [234-1] order or, in the alterna- tive, to certify orders for interlocutory appeal and for stay pending appeal. The court will direct the Clerk to schedule this case for trial during the July term and provide proper notice to the parties; signed by JUDGE FRANK W. BULLOCK JR. (WJ. Wil- son) (Entered: 02/23/2004) ~z oe e- . : > 2 “« 4/13/04 4/14/04 6/10/04 6/10/04 311 313 314 315 8 STIPULATIONS by all parties in support of Joint Motion for entry of final Judgment, to stay consideration of Rule 72(a) Objections, and to stay enforcement of discovery Order (Entered: 04/13/2004) OKDER AND FINAL JUDGMENT signed by JUDGE FRANK W. BUL- LOCK JR., that Summary Judgment is granted in favor of Defendant Duke Energy on Plaintiff’s and Plaintiff-Intervenors’ PSD claims in this action. * * * (Entered: 04/15/2004) NOTICE OF APPEAL to USCA 4th Circuit by NC PUBLIC INTEREST, NC SIERRA CLUB and ENVIRON- MENTAL DEFENSE of [313-1] Final Order and Judgment (Entered: 06/14/2004) NOTICE OF APPEAL to USCA 4th Circuit by USA of [313-1] Final Order and Judgment (Entered: 06/14/2004) ee a 9 US Court of Appeals for the Fourth Circuit GENERAL DOCKET FOR CASE United States, et al v. Duke Energy Corp. No. 04-1763 Date Description 6/24/04 Civil Case Docketed. 2/3/05 Oral argument heard. Panel: Honorable J.M. Luttig, Honorable Diana G. Motz, Honorable Samuel G. Wilson. [04-1763] (su) 5/2/05 Court Order to file Supplemental Briefs. 6/15/05 Judgment Order filed. Decision: AFFIRMED. 8/1/05 Petition Filed by Appellant Environmental Defense, NC Sierra Club, Appellant NC Public Interest for rehearing/ rehearing en banc 8/1/05 Petition filed by Appellant USA for rehear- ing * * * and rehearing en banc. 8/30/05 Court Order filed Denying all Motions for Rehearing; Motions for Rehearing En Banc 9/7/05 Mandate Issued. 10 | IN THE UNITED STATES DISTRICT COURT FOR THE MIDDLE DISTRICT OF NORTH CAROLINA UNITED STATES OF AMERICA, Plaintiff, CIVIL NO. 1:000V1262 Vv. DUKE ENERGY CORPORATION, Defendant. me ee ee ee ee eee ee” ORDER (Filed Sep. 6, 2001) BULLOCK, District Judge For the reasons set forth in the memorandum opinion filed contemporaneously herewith, IT IS ORDERED that Applicants Environmental Defense, North Carolina Sierra Club, and North Carolina Public Interest Research Group Citizen Lobby/Education Fund’s motion to intervene [Doc. #5] is GRANTED. September 6, 2001 /s/ United States District Judge IN THE UNITED STATES DISTRICT COURT FOR THE MIDDLE DISTRICT OF NORTH CAROLINA UNITED STATES ) OF AMERICA, ne ) Plaintiff, ) CIVIL NO. 1:00CV1262 . ) ) ) ) ) DUKE ENERGY CORPORATION, Defendant. EXHIBITS IN SUPPORT OF DUKE’S MOTION FOR SUMMARY JUDGMENT (Filed Jan. 31, 2003) * * x 11 EXHIBIT 9 [LOGO] UNITED STATES ENVIRONMENTAL PROTECTION AGENCY WASHINGTON, D.C. 20460 MAY 9 1986 THE ADMINISTRATOR Honorable John D. Dingell Chairman Committee on Energy and Commerce House of Representive Washington, D.C. 20515 Dear Mr. Chairman: | On April 14, 1986 you requested that I respond to a number of questions regarding H.R. 4567, the “Acid Deposition Control Act of 1986.” Given the seriousness of both the proposal and its potential consequences over the next 20 years, I believe deliberate and thorough considera- tion should be given to your questions and to the impact of this proposed legislation. We also wish to be timely and helpful with respect to the Committee’s rapid deliberations on H.R. 4567. Therefore, the enclosure provides prelimi- nary answers to questions 1 through 7, 9, 11 through 23, and 25. We may wish to provide revised answers to these a,’ questions after more careful review and analysis. Any i. revised answers and answers to the remaining questions y will be provided as soon as possible. x } a I should point out that these answers have not yet * been reviewed by all Interested Agencies of the Admini- % ‘stration and, therefore, can be said to reflect only EPA’s assessment. 12 Sincerely, /s/ Lee M. Thomas Lee M. Thomas 76. Acid Deposition Control Act of 1986 (Part 1): Hearing on H.R. 4567 Before the Subcomm. on Health and the Env’t of the House Comm. on Energy and Commerce, 99th Cong., 439, 446-449 (1986) (material submitted for the record by Environmental Protection Agency, responses to questions submitted by April 14, 1986, letter from John D. Dingell). Hearings Volume XVIII — 4/29/86. Question 2.a. According to a March 3, 1986 letter from the Environ- mental Protection Agency (EPA) to the National Coal Association (NCA), EPA and NCA apparently have differ- ences about forecasts of SO, emissions form coal-fired power plants. Please provide a table showing the EPA and NCA projections and the assumptions adopted by both. Please explain how the assumptions may differ and the significance of the of the differences. Please indicate to what extent, if any, the recent reduction in the price of all and other market forces may affect these predictions. We are providing a copy of this enclosure to the Department of Energy (DOE) to comment on the forecasts. Please discuss the implications of these differences to the potential cost and emission reductions achieved by this bill. Response: Attachment 2A is an excerpt from a recent report by ICF, Inc. which summarizes the differences between EPA and NCA projections of future SO, emissions. yt eh me oe ae \ +45 adied ; ee “—~- F, 3 “*-. ~~. 3 & ° ay Y as * fy : a “de mS ee 8 13 We have not yet performed an analysis using current low oil prices. The environmental implications of lower oil prices are not obvious because oil would displace lower- emitting gas as well as higher-emitting coal. Lower oil prices also could stimulate increased economic activity, resulting in higher overall electricity growth, and perhaps even increased coal use and emissions. If one assumes that oil (and possibly gas) prices will remain very low for a prolonged period of years, this could affect both emissions and cost results we have estimated for H.R. 4567. It is possible that oil and gas could replace some coal burning in the base case projection. This would reduce base emissions and emission rates, thus requiring smaller reductions, at lower cost, to meet the required targets. Switching to oil and gas is also possibie as a compliance strategy. With very low fuel prices, this could reduce compliance costs somewhat. On the other hand, lower fuel prices could stimulate higher electricity demands and higher base case emis- sions. In this case, the implementation of H.R. 4567 might require larger reductions and higher costs than we have projected. Also, total emissions after implementation of the reductions would be higher because the emissions rate ' requirements would be applied to higher total fuel use. Evaluating the net effect of all if these possible re- .', $ponses would require a complex analysis. We have asked ICF to conduct more detailed analysis of this issue which 44» ‘will be incorporated into their final report. “i = Gare 14 Question 2.b. [You referenced a March 3 letter from EPA to National Coal Association and then asked us the following ques- tions.] What actions has EPA taken or can it take to prevent such shifts to higher sulfur coal? Please explain the term “sulfur premiums,” the range of amounts of such premi- ums, and their impact. Can we expect such premiums under this legislation if a utility opts to shift to low sulfur coal or some mixture of such coal? Please discuss the difficulty caused by these shifts in determining compliance with the emission caps in the bill. Response: There is nothing that EPA can do to prevent a power- plant which had previously been emitting at a level well below its SIP limit from increasing its emissions, as long as it remains below its legally sanctioned ceiling. Under current law, a state would have to justify any SIP changes on an ambient basis. However, under a congressionally mandated acid rain control program, states could tighten SIP limits to prevent emissions creep. “Sulfur premiums” are the price differentials between high and low sulfur coal. They are related to the cost differences between mining and transporting low vs. high sulfur coal, as well as the higher demand for low sulfur coal created by environmental regulations. Sulfur premi- ums vary greatly. They depend upon such factors as plant location, competition among coal suppliers, access to transportation facilities, and the stringency of environ- mente! requirements. Because coal markets are currently depressed, current premiums range from $0-5 per ton. 15 Under our base case forecast, by the year 2000 when coal market conditions have significantly improved, premiurns of $4-15 are created. According to our analysis of the default emission cap in the HR 4567, in the year 2000 sulfur premiums would be somewhat higher than in the base case, ranging from $5-25. Any legislation which precipitates large amounts of coal switching will create sulfur premiums. The creation of such premiums complicates the achievement of emission caps for two reasons. First of all, incentives are created for uncontrolled plants to use cheaper, higher sulfur coals. Secondly, all other things being equal, lower prices of high sulfur coal relative to low sulfur coal will encourage the utilization of high-emitting plants relative to low-emitting plants. In developing plans to implement a control pro- gram, States will have to be careful that they take into account the changes in coal quality and utilization that would occur, to ensure that they will actually meet re- quirements of the program. st > 16 EXPERT REPORT OF WALTER C. BARBER DUKE ENERGY CORPORATION AUGUST 15, 2002 /s/ Walter C Barber Walter C. Barber III. Conclusions and Opinions. My job duties as Director of OAQPS required me to be fully aware of the statutory provisions and Congressional intent that both authorized and guided my office’s activi- ties. My understanding of the relevant statutory provisions derived from many sources, including my participation in discussions within USEPA and my personal review of the statute and accompanying legislative materials. My understanding of the topics under OAQPS’s responsibility reflects the nature and type of understanding common among policy-level agency personnel who had senior responsibility for developing regulations authorized by USEPA’s operating statutes. The ensuing discussion regarding the CAA, therefore, provides context to this report and my opinions regarding the development of the NSR programs and the manner in which USEPA is now interpreting these programs. In 1970, Congress enacted the CAA to establish nationwide air quality standards to protect public health ‘and welfare. These national ambient air quality standards specify the maximum permissible concentration of certain air pollutants in ambient air required to protect the public health with an adequate margin of safety. Congress directed the States to prepare implementation plans to control emissions of these pollutants to ensure attainment 17 dards and the state implementation Plans designed to achieve those Standards are two of the cornerstones of air pollution contro] in the United States. sources. In 1977, Congress amended the CAA to expand the NSPS Program and to add specific PSD and NNSR programs. The PSD Provisions of the CAA responded to F 5 5; 5 a n ° : d a ° . = E =a > d @ g S E a. ° =) = 'd6, not: apply to existing sources, unless an existing source isichanged to such an extent that it is “modified” within the m aning of such provisions. cot 18 During the development and promulgation of the NSR programs, OAQPS was keenly aware of the Congressional distinction between new and existing sources. As Director of the office, I ensured that OAQPS developed regulations designed to carry out Congress’ determination both that new sources should be required to install stringent, technology- based air pollution controls and that, unless an existing source was “modified,” existing sources should not be required to install or be retrofitted with such air pollution controls. Consistent with the statutory principles and Congressional intent, OAQPS developed regulations providing that those existing sources would be addressed, if needed, through a state’s regulation of existing sources under its state implementation plan. As applied to the electrical utility industry, OAQPS developed regulations primarily addressing new sources. Existing sources (the vast majority of which at that time were coal-fired steam generating facilities) were required to be retrofitted with enhanced air pollution control devices only when those sources were changed to such an extent as to render them “modified,” which was something that was expected to occur only rarely. Three of the critical bases for this mindset are as follows. First, as I have discussed above, OAQPS understood that Congress did not intend to develop regulations that would provide for extensive retrofitting of existing sources. Second, OAQPS believed that, in general, requiring existing electric gener- ating power plants to be retrofitted with new control technologies would not be cost-effective. Finally, in devel- oping regulations, OAQPS was always mindful of the country’s increasing demand for energy, its vulnerability to foreign sources of energy, and the increasing role coal car = imported oil. : * Existing gas turbines, which do not have built-in dual-fuel =. capability, must install new combustion hardware so that Be they ‘can burn natural gas instead of middle distillates. t. The concern arises whether such a conversion would be fe calssified a “modification” or “major modification” and, therefore, subject the gas turbine to the New Source Performance Standards (NSPS) or a Prevention of Signifi- Eant Deterioration (PSD) review. eS ES | et AOI ie Ree 30 MODIFIED The definition of modification is provided in 40 CFR 60 as: 60.14 (a) “Except as provided under paragraphs (e) and (f) of this section, any physical or operational change to any existing facility which results in an increase in the emission rate to the atmosphere of any pollutant to which a standard applies shall be considered a modifica- tion within the meaning of Section III of the Act...” 60.2 “‘Standard’ means a standard of performance proposed or promulgated under this part.” NEW SOURCE PERFORMANCE STANDARDS (NSPS) Hydrocarbons, carbon monoxide and particulates are specifically excluded from the NSPS promulgated on Sept. 10, 1979. Justification for the exclusion was provided in the Oct. 3, 1977 Federal Register on page 53783. “HC and CO emissions from stationary gas tur- bines operating at peak load are relatively low because the higher the percentage of peak load at which a turbine operates, the more efficient the combustion of the fuel. Gas turbines normally operate at 80 to 100 percent of peak load with HC emissions averaging less than 50 ppm and CO emissions averaging less than 500 ppm at 15 percent oxygen. HC and CO emissions from sta- tionary gas turbines, therefore, were not selected for control by standards of performance.” “Particulate emissions from stationary gas tur- bines depend on the ash content of the fuel and 31 are minimal. Consequently, particulate emis- sions from stationary gas turbines were not se- lected for control by standards of performance.” Since there is no standard for CO, unburned hydrocarbons and particulates under NSPS for stationary gas turbines, NSPS would not apply even if there was an increase in the emission rate of these three pollutants. As shown in the attached four tables, NO, and SO, decrease, and CO, unburned hydrocarbons and particulates remain un- changed or decrease. PREVENTION OF SIGNIFICANT DETERIORATION (PSD) ~ PSD review would apply if the emissions increase by amounts greater than de minimis levels. De minimis levels, shown on page 52709 in the August 7, 1980 Federal Register, are: Equivalent lbs/hour : Tons/Year (8760 hours/year) Carbon Monoxide 100 22.83 Nitrogen Oxides 40 9.13 Sulfur Ofoxide 40 9.13 Particulates 25 5.70 ** Volatile Organic * :.. Compounds 40 9.13 For those machines which are not restricted to a specific number of hours of operation per year by an enforceable ‘ ‘permit condition, allowable emissions would be the hourly -emission rate multiplied by 8760 hours per year. Then, for | ‘PSD review purposes, net emissions increases should be = ‘evaluated against these allowable emissions to see if de " ‘thinimis levels are exceeded. at sh — 32 PG7101E FUEL -— NATURAL GAS | DISTILLATE LOAD - BASE PEAK | BASE PEAK Output, kW 74,400 80,500 | 72,900 78,800 Heat Rate (LHV), Btw/kWH /10,690 10,640 | 10,790 10,750 Fuel Consump. (LHV) 10° Btu/hr 795.3 856.5 | 786.6 417.1 _|NOx as NO2, lbs/hr 450 535 790 §=«©970 *SOx as SO2, Ibs/hr 0 0 254 275 Particulates, Ibs/hr } 36 the 1978 PSD regulations, as stayed, and certain other conditions are met. (See 40 CFR 52.21 (i)(4V)). If the grandfather exemption does not apply the addition of the ethanol plant should be considered a modification to an existing major stationary source. In order to determine if the modification is major and subject to preconstruction PSD review, it is first necessary to determine if there will be a significant net emissions increase from the modification itself. EPA is interpreting the term “net emissions increase” as any significant increase in actual emissions from a physical change or change in the method of operation at a stationary source and any other creditable contemporaneous increases or decreases in actual emissions. A conforming amendment to this effect will be published in the Federal Register. In this case there is an expected increase at the ethanol plant of approximately 15 TPY of TSP, 11 TPY of SO, and less than 40 TPY VOC. All of these emission rates are de minimus, (See 40 CFR 52.21(b)(23)) and therefore this modification would not be subject to PSD review. Regard- less of whether or not this is determined to be a modifica- tion any increase in emission will consume increment provided the baseline has been triggered. It is also important to note that, in the absence of any SIP or permit limitations, neither the increase in emis- sions from the switch to burn coal exclusively nor the increase in hours of operation at the power plant would be 4 considered a modification (See 40 CFR 52. 21(bX2KitiXe) _ and (f)). : This determination has been made with the concur-.# rence of the Office of Air Quality Planning and Standards’§ and the Office of General Counsel. If you have any questions ne TLL, 37 regarding this memo, please contact Janet Littlejohn of my staff at 755-2564. /s/ Edward E. Reich Edward E. Reich cc: Peter Wyckoff, OGC Mike Trutna, OAQPS Darry! Tyler, OAQPS 38 EXHIBIT 29 [LOGO] UNITED STATES ENVIRONMENTAL PROTECTION AGENCY WASHINGTON, D.C. 20450 Oct. 14, 1988 THE ADMINISTRATOR Mr. John W. Boston Vice President Wisconsin Electric Power Company Post Office Box 2046 Milwaukee, Wisconsin 52301 Dear Mr. Boston: As you requested in our meeting on September 15, 1988, I have made fina] determinations regarding the applicability of the Clean Air Act’s New Source Perform- ance Standards (NSPS) and Prevention of Significant Deterioration (PSD) requirements to the proposed life extension project at the Port Washington steam electric generating station, which is owned and operated by Wisconsin Electric Power Company (WEPCO). For the reasons discussed below, I have determined that, as proposed, the renovations at Port Washington are subject to both PSD and NSPS requirements. However, EPA remains willing to work with you regarding methods of compliance. As we have discussed, one alternative would be to reconfigure the project such that no emissions increases would occur. My staff is ready to meet with you to discuss these matters at any time. 39 I. BACKGROUND On September 12, 1988, David Kee, Director Air and Radiation Division, EPA Region V, wrote you regarding PSD and NSPS coverage of the Port Washington renova- tions. Enclosed with that letter was a memorandum dated September 9, 1988 from Don R. Clay, Acting Assistant Administrator, addressing the background of the Port Washington project, and analyzing at some length the relevant interpretative issues. For purposes of brevity, I will not repeat that material here, but rather incorporate it by reference. The September documents concluded that the life extension project, as proposed, likely would be subject to PSD and NSPS requirements. However, EPA also stated that final applicability determinations could not be pro- vided at that time in the absence of certain factual infor- mation. In our subsequent meeting you requested that EPA furnish final determinations, and agreed to provide the necessary additional information. You also asked EPA to reconsider certain of the conclusions in Don Clay’s memorandum. These matters are discussed below. Il. FINAL DETERMINATIONS Your staff has responded to our requests for addi- tional information, and I want to thank you for WEPCO’s continued cooperation in doing so. Based on this, and the other information in EPA's files, I now make the following final determinations: (1) The life extension project, as proposed, will render WEPCO’s Port Washington plant subject to the PSD requirements of Part C of the Clean Air Act as a - Pa > aay 40 major modification within the meaning of the Act and the EPA regulations at 40 C.F.R. § 52.21. (2) The proposed life extension project will render each of the five steam generating units at the Port Wash- ington plant subject to the NSPS requirements of section 111 of the Clean Air Act as modification within the mean- ing of the Act and the EPA regulations at 40 C.F.R. Part 60. In reconsidering the memorandum and letter of September 9 and 12, I have taken a careful look at the issues you raised in our meeting: whether the renovations are routine; whether EPA has treated similar projects in a different fashion; and whether there would be an emis- sions increase due to a physical or operational change. However, I find no reason to depart from the reasoning of the September documents. Accordingly, I conclude that WEPCO’s life extension project, if carried out as proposed, will involve a substantial and non-routine renewal of the Port Washington facilities that will significantly increase both hourly maximum and annual emissions of air pollut- ants. Specifically, regarding the nature of the proposed work at Port Washington, I find that these renovations constitute physical changes for PSD purposes within the meaning of 40 C.F.R. § 52.21(b)(2)(i), and physical and operational changes for NSPS purposes within the mean- ing of 40 C.F.R. §60.14(a). I find further that these changes do not come within the PSD and NSPS exclusions for routine maintenance, repair, and replacement, nor the exclusions for increases in production rate or hours of “% operation. (See 40 C.F.R. §§ 52.21(bX2)(iii) and 60.14(e)). 41 Regarding the emissions changes from the life exten- sion project, based upon the emissions data and certain factual assertions submitted by WEPCO, I find that the Port Washington renovations will result in a significant net increase in emissions of several pollutants for PSD purposes within the meaning of 40 C.F.R. § 52.21(b)(2)(i), (b)(3), and (b)(21). I find further that the renovations will result in an increase in the emission rate of several pollut- : ants at each of units 1-5 for NSPS purposes within the ; meaning of 40 C.F.R. § 60.14(a) and (b). Enclosures A and B detail the emissions changes d underlying these findings for PSD and NSPS purposes. As a indicated above, EPA’s calculations and determinations 2 are based on data supplied by WEPCO. We will use the é* data in Enclosures A and B in the event you would like to work with us to establish an acceptable arrangement for satisfying PSD and NSPS requirements through the © addition or enhancement of pollution control equipment, "3 physical capacity restrictions, or, in the case of PSD, >’ federally enforceable limitations on potential emissions. i, . ° ill. DISCUSSION to maximum “achievable’ capacity in determining the _ emissions changes at each of these units. Thus, for exam- ple, in the case of unit 5, the current capacity must be regarded as zero. fue * IV. CONCLUSION é¢.°«- In adopting the PSD and NSPS programs, Congress ' :imtended to address the type of long-term capital invest- oe ments in pollution-emitting facilities at issue in the Port f Washington life extension project. Thus, as proposed, f. these renovations would be subject to the requirements of ‘,, both. programs. However, as indicated above, my staff : remains ready to work closely with WEPCO to discuss - “specific pollution control equipment and permitting 46 Again, thank you for your cooperation is this matter. Sincerely, /s/ Lee M. Thomas Lee M. Thomas Enclosures cc: Senator Robert W. Kasten, Jr. Representative F. James Sensenbrenner, Jr. Don Clay, EPA (ANR-445) David Kee, Air & Radiation Div., Region V Enclosure A PSD Applicability Port Washington Power Plant Renovation Project (all emissions calculations are in tons per year) Actual Potential Net Subject Emissions Emissions EmissionsPSD to, PSD Pollutant Baseline (1) (2) Increase Level Review Total suspended particulate 170 283 (3) 108 25 yes Sulfur dioxide 24,234 52,621(3) 28,385 40 yes Nitrogen oxides 2,991 8,201 5,210 40 yes Carbon monoxide 144 397 253 100 yes ~ Hydrocarbon 17 47 30 46 no Beryllium 0.0016 0.005 0.0034 0.0004yes Fluorides 38 98 60 3 yes 47 NOTE: PSD applicability for the other PSD regulated pollutants listed at 40 CFR Section 52.21(b)(23)ji) and (ii) has not been determined at this time. 1) Average emissions for two-year period defined by calendar years 1983 and 1984. 2) As calculated by WEPCO based on 1992 coal type, actual emissions after ESP, and an annual capacity utilization factor of 90%. 3) An EPA estimate of potential emissions, based on existing federally enforceable limits (i.e., applicable SIP), may be higher. The indicated PSD applicability determination would, however, not change. se Oe & i? Enclosure B é NSPS Applicability | y Port Washington Power Plant Renovation Project is FULL LOAD EMISSIONS AT CURRENT ct CAPACITY (BEFORE RENOVATION) a UNIT-1 UNIT-2 UNIT-3 UNIT-4 UNIT-5 ¢:. SO,(LBS/HR) 1417 1828 2043 1580 ~ -0- >. PM(LBS/HR) 15 16 12 12 -0- .NOx(LBS/HR) 480 352 289 221 -0. FULL LOAD EMISSIONS AT FUTURE CAPACITY (AFTER RENOVATION) UNIT-1 UNIT-2 UNIT-3 UNIT-4 UNIT-5 2 SO,’ (LBS/HR) 2046 2037 2088 2269 2695 17 15 316 369 % | ‘ : eS ee 65 regulations, used this period to establish the baseline. The period used was also within the contemporaneous period specified in 40 CFR 52.21(b\(3)(ii). It should be empha- sized that, in the WEPCO case, the parties and the court agreed that 1983-84 (prior to discovery of steam drum cracks) should be the basel'ne years (slip op. at 26); these years had an average 29 percent utilization rate. We continue to believe this is the appropriate baseline period for the Port Washington renovation. B. Calculating Post-Change Emissions Under PSD. The court concluded that “EPA’s reliance on an assumed continuous operation as a basis for finding an emissions increase is not properly supported” (slip op. at 30). Although the court held that EPA cannot, in this case, wholly disregard past operating conditions at the plant, it also held that EPA could not reasonably rely on the company’s own unenforceable projection of operating conditions (slip op at 29). The court remanded the question of PSD applicability to EPA for further proceedings not inconsistent with its decision. Before the court remanded EPA’s determination, it attempted to ascertain whether, in fact, the proposed project would be a major modification even using the assumptions least likely to result in an emissions increase. The court felt (and we agree) that such a “best” case scenario for WEPCO would assume that the “present hours and conditions” would not change at all following the renovations (despite, of course, WEPCO’s own esti- mates of at least tripling of utilization over current levels) (slip op. at 31, n. 14). The court, however, lacked the data to make this calculation, as it could not determine whether yoo arated te ce ‘3 Nis 75 Enclosure A Revised PSO Applicability Determination Port Washington Power Plant Renovation of Units 1-5 (all emissions calculations are in tons per year) Actual Estimated Emissions Future Actual Pollutant Baseline (1) Emissions (2) Particulate 328 323 matter (4) (5) Sulfur dioxide (4) 24,236 15,919 Nitrogen oxides (5) 2,592 3,405 Carbon monoxide 144 217 Hydrocarbon 17 25 PSD Subject Net Significance to PSD Emissions Change Level Review (3) -5 25 no -8,317 40 no 813 40 yes 73 100 no 9 40 no Other Regulated Pollutants: Due to insufficient source- specific information regarding emission factors, PSD applicability for PM-10, lead and noncriteria pollutants listed at 40 CFR Section 52.21 (b)(23)(i) and (ii) cannot be determined at this time. 1) Average actual emissions for 2-year period defined by calendar years 1983 and 1984. ee ne ee 76 2) Calculated by EPA based on the following information submitted by WEPCO. a. The average historic firing rate (approxi- mately 17x10° per year) for the 2-year period defined by calendar years 1978 and 1979. b. The emissions estimates for the renovated units based on future coal characteristics (e.g., sulfur and heat content) and actual emissions after pollution controls for par- ticulate. c. Sulfur dioxide controls applied to units 5 at 75 percent sulfur dioxide removal to comply with NSPS Subpart No. Sulfur dioxide re- moval of 22 and 13 percent at units 1 and 4, respectively, to exclude these units from NSPS requirements for greater control of sulfur dioxide. 3) If new data indicate that annual, historic-firing rates at the Port Washington facility exceeded historic 1978 and 1979 levels, the indicated applicability determination could change. 4) The calculation of estimated, future, actual emissions for this pollutant is based on WEPCO’s projection of annual technology performance levels and/or fuel sulfur content for post-renovation operations. Consequently, EPA’s PSD applicability determination is valid only to the extent that the specific particulate and sulfur dioxide emissions factors used for units I-5 to calculate future emissions (based on particulate and 50, control technology performance levels and fuel sulfur and heat content) are made federally enforceable. Otherwise, the calculation of estimated, future, actual emissions for this pollutant will 77 be revised by EPA, based on existing federally-enforceable limits (i.e., applicable SIP, NSPS). The use of current, federally-enforceable emissions factors would result in higher, projected, future emissions and, consequently, could affect the indicated PSD applicability finding. 5) Baseline emissions (actual emissions for 2-year period defined by calendar years 1983 and 1984) have been revised based on additional information submitted by WEPCO. Enclosure B Revised PSD Applicability Determination Port Washington Power Plant Renovation of Units 1-4 (all emissions calculations are in tons per year) Actual Estimated Emissions Future Actual Pollutant Baseline (1) Emissions (2) Particulate 328 339 matter (4) (5) Sulfur dioxide (4) 24,236 18,505 Nitrogen oxides (5) 2,592 3,396 Carbon monoxide 144 217 Hydrocarbon 17 25 PSD Subject Net Significance to PSD Emissions Change Level Review (3) 11 25 no -5,731 40 no 804 40 yes ' 3 : ‘ 3 : | f AED ee yer Ss TOs wre © Or pena Phe § 6 a eat ay Ee RC ET i cc ; 78 73 100 no 4 9 40 no | Other Regulated Pollutants: Due to insufficient source g specific information regarding emission factors, PSD 4 applicability for PM-10, lead and noncriteria pollutants a listed at 40 CFR Section 52.21 (b)(23)(i) and (ii) cannot be . 1) Average actual emissions for 2-year period defined by ty determined at this time. Z | calendar years 1983 and 1984. | 2) Calculated by EPA based on the following information submitted by WEPCO: a. The average, historic-firing rate (approxi- mately 17 x 10° per year) for the 2-year pe- riod defined by calendar years 1978 and 1979. b. The emissions estimates for the renovated units based on future coal characterization (e.g., sulfur and heat content) and actual rf emissions after pollution controls for par- *, ticulate. c. Unit 5 inoperative. Sulfur dioxide removal of 22 and 13 percent at units 1 and 4, respec- tively, to exclude these units from NSPS re- quirements for greater control of sulfur dioxide. % 3) If new data indicate that annual, historic-firing rates at the Port Washington facility exceeded historic 1978 and 1979 levels, the indicated applicability determination could change. 79 4) The calculation of estimated, future, actual emissions for this pollutant is based on WEPCO’s projection of control technology performance levels and/or fuel sulfur content for port renovation operations. Consequently, EPA's PSD applicability determination is valid only to the extent that the specific particulate and sulfur dioxide emission factors used for units 1-4 to calculate future emissions (based on particulate and SO, control technology performance levels and fuel sulfur and heat content) are made federally-enforceable. Otherwise, the calculation of estimated, future, actual emissions for this pollutant will be revised by EPA, based on existing federally-enforceable limits (i.e., applicable SIP, NSPS). The use of current, federally-enforceable emissions factors would result in higher, projected, future emissions and, consequently, could affect the indicated PSD applicability finding. 5) Baseline emissions (actual emissions for 2-year period defined by calendar years 1983 and 1984) have been revised based on additional information submitted by WEPCO. 80 IN THE UNITED STATES COURT OF APPEALS 2 ; EXHIBIT 35 FOR THE SEVENTH CIRCUIT Nos. 88-3264 89-1339 WISCONSIN ELECTRIC POWER COMPANY, Petitioner, Vv. WILLIAM K. REILLY, Administrator United States Environmental Protection Agency, et al., Respondents. ON PETITIONS TO REVIEW FINAL ACTION OF THE UNITED STATES ENVIRONMENTAL PROTECTION AGENCY AFFIDAVIT IN SUPPORT OF RESPONDENTS’ MOTION FOR EXTENSION OF TIME AFFIDAVIT OF GREGORY B. FOOTE 1. My name is Gregory B. Foote. I am a staff attor- ney in the Office of General Counsel at the U.S. Environ- mental Protection Agency (“EPA”) in Washington, D.C. I have held this position since 1985. In this capacity I have primary responsibility within the Office of General Counsel 81 for advising and representing EPA in matters involving the prevention of significant deterioration (“PED”) provi- sions of the Clean Air Act, 42 U.S.C. §7470-7479. 2. This affidavit is filed in support of Respondents’ Motion For Extension of Time. 3. Iam assigned prin.ary responsibility in the above captioned case. 4. EPA and the United States Department of Justice presently intend to file a Petition for Rehearing in connec- tion with the decision issued by this Court on January 19, 1990. 5. The matter under review is so complex that an adequate brief in support of the Petition for Rehearing cannot reasonably be prepared during the fourteen-day period allowed under Circuit Rule 40(d) for the following reasons: (a) The Court’s decision of January 19, 1990 largely upheld EPA’s applicability determinations ruling that an extensive renovation project at the Port Washington power plant owned and operated by petitioner Wisconsin Electric Co. (““WEPCO”) would be subject to new source require- ments under the Clean Air Act, 42 U.S.C. § 7401, et seq. However, the court vacated EPA’s determination that the calculation of future increases in “actual emissions” for purposes of determining applicability of the PSD provi- sions of the Act should be made using the “potential to emit” concept in 40 C.F.R. § 52.21(b)(21\iv). Slip op. at 28- 31. The Court also rejected WEPCO’s proffered view that emissions increases following the renovations should be calculated based on the company’s own unenforceable estimates of emissions. Jd. at 29. The Court remanded the 6 a Ss bee ee 82 PSD applicability determination to EPA for further pro- ceedings not inconsistent with its opinion. Jd. at 33. The Court further appeared to suggest that EPA could, on remand, calculate future emissions based on “whether the renovated plant would cause a significant net emissions increase if it were operated under present hours and conditions.” Jd. at 31 n. 14. (b) EPA has tentatively concluded that the analysis employed by the court in deciding to vacate EPA’s PSD applicability determination is faulty, and for this reason, EPA presently intends to file a petition for rehearing in which it will ask the Court to reinstate EPA’s applicability determination. In addition, EPA presently expects that its petition for rehearing will, in the alternative, seek clarifi- cation of the Court’s January 19 decision. However, as explained in paragraph (c) below, EPA at present is unclear as to the meaning or impact of the Court’s deci- sion. (c) EPA staff are actively engaged in reviewing the Court’s decision, including the suggestion on page 31 n. 14 for EPA action on remand. At this juncture, it appears that the Court’s suggestion may not comport with any known method of calculating emissions increases under EPA’s regulations. Consequently, EPA has not yet come to any conclusion as to the meaning or impact of the Court’s decision on either the WEPCO project or the many other similarly situated sources which may be affected by that decision. I anticipate that several days of review and analysis will be necessary before EPA staff are able to present to EPA management their views as to the mean- ing and impact of this decision on the exceedingly complex PSD program. Only at that point will EPA be in a position to determine whether further clarification of the Court’s 83 decision is appropriate and, if so, what clarifying order would be sought. . Pursuant to 28 U.S.C. 1746, I declare under penalty of pe perjury that the foregoing is true and correct to the best of my knowledge and belief. Executed this 26th day of January 1990 at Washing- ton, D.C. /s/ Gregory B. Foote Gregory B. Foote -—- —— oe CAE aes ee ere ne Senator BURDICK. Well, I understand you, Mr. Tho- mas, but pardon me if I say it looks like we're retreating a bit if we’re not going to be as firm as we have been in the past. Mr. THOMAS. Retreating from what, Senator? Senator BURDICK. Well, the requirement for scrubbers, for example. Mr. THOMAS. But the requirement for scrubbers has always been on new sources. Senator MITCHELL. Thank you, Senator Burdick. Senator Chafee? Senator CHAFEE. Thank you, Mr. Chairman. Briefly — and I just want to get this quickly from you because I want to move on to something else — the problem we've got is that the new source performance standards obviously impose stiff requirements on new, sources, so therefore what’s happening in our country is that we’re not having new sources, that they are keeping the old plants going because there is less expense in so doing. Many of us feel that we ought to be in a situation where we should be requiring the new source performance standards on the older plants because the theory was that the older plants eventually would expire, and then you would get new and more efficient plants — efficient as regards the release of pollutants. That’s not happening. What are you suggesting we ought to do? Why shouldn’t we impose these new source performance stan- dards on the old plants? Mr. THOMAS. Well, first, Senator, I don’t think you should impose them on the old plants because I don’t think there’s a scientific rationale for requiring that kind of emission reduction that you’d get from a new source performance standard, either as far as total loadings is concerned, as it relates to environmental damage, or the kind of specific definition that you would give to one location receiving damage from a particular plant. I don’t think that there’s a rationale for suggesting that you've got to have those new source standards on those old plants today or next year. The problem you've got is as you stated. This country has decided not to go forward with the nuclear option, —_s—“— 95 which was one we were pursuing aggressively a number of years ago. A lot of the new sources, as far as utilities were concerned, were nuclear at that point in time. We also, now, are looking at how we can go forward and extend the life of our existing sources. We have found through technology development a number of ways to do that cost-effectively, repowering ways, retrofitting ways to extend those lifetimes. So in fact, we have to deal with, is that going to be an environmental issue for us or a public health issue? I don’t think it’s going to be a public health issue; there’s debate on that. I don’t think it’s going to be an environmental issue; there’s debate on that. I may change my mind on that, but today I don’t think you've got the basis to go in and suggest that all of those old sources should put on very stringent contro] requirements that we impose on the new source performance standards. Senator CHAFEE. Well, Mr. Thomas, what’s the prob- 7 lem here? Is it your belief that the current emissions in 4 the United States are not causing enough damage to cause : you to enact stronger restrictions than currently exist? I mean, no one knows more about the damage that has taken place in Europe. You've seen it. You've seen the lakes in Sweden. You’ve seen the forests in Switzerland and West Germany, and, in your mind, you just are not con- vinced that that damage is taking place in the United States. Is that the problem? Mr. THOMAS. That damage, connected with the emis- sions levels that we’ve got in the United States? That's correct. 96 EXHIBIT 38 EXPERT REPORT OF KENNETH SCHWEERS DUKE ENERGY CORPORATION AUGUST 15, 2002 /s/ Kenneth A. Schweers Kenneth Schweers I. INTRODUCTION I am Kenneth Schweers, and I have just recently resigned as Chief Operating Officer of Development Alternatives, Inc. I have been asked by Duke Energy Corporation to provide an expert report in connection with this litigation. This report describes the assumptions made by the United States Environmental Protection Agency (“EPA”) in the studies I did for the consulting firm ICF Incorporated on behalf of EPA evaluating the economic impact of environmental legislation and regulations, including EPA’s New Source Performance Standards (“NSPS”), Prevention of Significant Deterioration (“PSD”) and Non-Attainment New Source Review (“NNSR”) regulations. I will refer to these regulations collectively as the “New Source Review” or “NSR” regulations or pro- grams. In my opinion, from the mid-1970s through the 1980s, EPA believed the ¢ the focus of the NSR programs was to regulate emissions from new plants, not existing plants; e the NSR requirements would not be triggered by existing coal-fired plants that operated at their original capacity and took actions necessary to maintain that capacity; and a ee 97 * significant emissions reductions from existing coal-fired power plants would not be achieved through the application of the NSR programs and that new and additional legislative and regu- latory programs were necessary to achieve reduc- tions from existing plants, such as the “Acid Rain” regulations adopted in the Clean Air Act Amendments of 1990. ‘. II. Summary of Qualifications and Preparation of gE this Report I am an industrial and nuclear engineer and economic analyst by training. I received a Bachelor of Science in Industrial Engineering from Stanford University (1969). After graduation, I worked as a project manager for the U.S. Navy, where I assisted in directing the work of contractors in the design of reactor cores for submarines and heavy reactor equipment * * * The ICF studies used the aforementioned computer model that simulated the dynamics of the electric utility sector and the coal industry to estimate the economic and environmental impact of various legislative and regulatory proposals. The studies evaluated the economic impact by: (1) establishing a “base case” that assumed the pre- existing regulatory requirements with no new environ- mental requirements; (2) identifying the additional envi- ronmental requirements imposed by the legislative or regulatory proposals being evaluated; and (3) forecasting the incremental impact on the utility and energy produc- ing sectors by adding the proposed environmental re- ’ quirements to the pre-existing regulatory regime. The 98 assumptions used in the base case and the proposed requirements were either provided or approved by EPA. NSPS Studies In 1977 and 1978, ICF conducted economic impact studies under contract to EPA evaluating amendments to the NSPS regulations to implement the Clean Air Act Amendments of 1977. These studies, which I conducted, were designed to assist EPA in its review of proposed additions to the then existing NSPS regulations and to support its final rulemaking amending the NSPS. The base cases for these studies incorporated various understandings and assumptions about how coal-fired plants were operating and being regulated. These under- standings were either communicated by EPA to ICF, or suggested by ICF and approved by EPA. For the base case, EPA understood and assumed that existing plants were complying or would comply with then current Federal regulations (e.g., NSPS) and the State Implementation Plans (SIPs). We then modeled the potential impact of various alternative amended NSPS, each of which in- cluded its own set of understandings and assumptions that were approved by EPA. Both the base cases and the proposed alternatives shared a common understanding and assumption adopted by EPA: that existing coal-fired power plants would continue to operate at original capac- ity without being required to retrofit scrubbers.’ EPA ’ By “original capacity,” I mean the design net dependable capacity that is available to the electrical power grid. This accounts for the energy needs of the plant itself to operate, and is differerit from what is often referred to as nameplate or gross capacity. 99 ‘ recognized that existing coal-fired power plants would be required to meet only the emission limits that had been established in the SIPs for existing plants. The ICF analysis included estimates of operation & maintenance (O&M) costs. EPA did not direct ICF to assume that these O&M expenditures that allowed the plants to operate at their original capacity would trigger NSR requirements and the attendant cost of retrofitting pollution control equipment. Had EPA instructed ICF to assume that O&M expenditures would trigger NSR, ICF , would have included such costs in the model’s assump- tions. For example, when modeling the costs of complying with SIPs, ICF evaluated the costs associated with SIP compliance options such as switching to low-sulfur coal or installing scrubbers. For purposes of the NSPS studies, EPA never asked ICF, however, to calculate what would have been the additional cost under NSR of retrofitting scrubbers to existing plants that operated within original capacity and were already in compliance with the SIPs. : The NSPS studies focused on the costs associated with *- designing and operating new facilities under a variety of | regulatory scenarios. The impact of regulatory proposals on new plants could be accurately evaluated by relying on accepted engineering assumptions. The NSPS studies did not evaluate the costs of regulatory proposals on existing ‘ plants, which is a substantially different exercise that has ¢ to'take into account a number of factors reflecting the range of financial, physical, technical and geographical constraints on existing plants. It was in the context of the 2 acid rain initiative that EPA asked ICF to conduct eco- “nomic evaluations of significant legislative or regulatory _ : options for reducing emissions from existing plants. i +. 8 ne Ws o-- ~~ i Acid Rain Studies After EPA promulgated the NSPS and PSD regula- tions in 1979-1980, ICF conducted a number of studies for FPA in the 1980s addressing the issue of acid rain. “Acid rain” is acidic precipitation resulting from accumulated atmospheric loadings of SO, and NOx. The ICF acid rain studies supported the efforts of various governmental agencies, including EPA, to evaluate regulatory and legislative proposals to reduce total SO, and NOx emis- sions, primarily from existing coal-fired power plants. While at ICF, I conducted or oversaw the conduct of these studies. The “base cases” for these acid rain studies projected emissions based on the understanding that the then current environmental regulatory regime remained unchanged. EPA believed that SO, and NOx emissions from existing coal-fired power plants would be relatively constant under existing law. This assumption was based on plants operating at their original capacity at their allowable emissions level. EPA did not request ICF to study, whether under existing law, SO, emissions from + existing coal-fired plants would decrease because of the application of NSR and the attendant retrofitting of — pollution control equipment. EPA also did not direct ICF to ** assume that variations in actual operating or emissions . levels, such as periodic decreases associated with mainte-. + nance followed by increases back to original capacity; would trigger NSR. In other words, EPA believed that: existing coal-fired power plants would continue to operate: without triggering NSR. : a 2" The focus of the acid rain proposals we evaluated on’ behalf of EPA and other government agencies was reducing es 4" 101 the SO, and NOx emissions from existing sources. EPA believed that new regulations and the legislative programs would be needed to achieve these reductions and that significant SO, and NOx reductions would not be achieved by retrofitting scrubbers or other pollution control equip- ment on existing plants through the application of NSR. EPA believed that SO, and NOx emissions at existing plants would remain relatively constant absent a change in environmental legislation or regulation. The emission- reduction options ICF evaluated in various acid rain studies conducted for EPA in the 1980s included, among numerous others: ° a30% reduction of SO, and NOx emissions; a 2.0 lb./mmbtu SO, limit; a tax on utility emissions of $0.15 per pound of SO, emitted; the Waxman-Sikorski bill (H.R. 3400), which pro- posed a 9.5 million ton SO, reduction for existing utility plants; the Acid Deposition Control Act of 1986 (HR. 4567) which would require a 2.0 lb. SO/mmbtu limit, to be followed by a 1.2 limit; and an option EPA considered to require existing plants to meet NSPS when they reached 30 years of service. 102 Beginning in 1985, EPA believed that existing plants would operate for 60 years. EPA also understood that utilities would have to repair or replace components as required to continue to operate to this longer lifetime. ICF recognized that these costs occurred throughout the life of the plant and that it was not possible to establish precisely when these replacements or repairs had occurred (or would occur). For modeling and study reporting purposes, however, we assumed that these repairs or replacements would occur at 30 years of the plant’s useful operating life and would be referred to as “refurbishment.” This mid-life refurbishment was part of the maintenance that the ICF studies assumed would occur at existing coal-fired power plants to allow them to continue to operate at their orizi- nal capacity and close to their design efficiency. The 1985 and subsequent studies ICF conducted on behalf of EPA all assumed, as EPA directed, that the O&M necessary to keep the plants operating, including the refurbishment at the 30-year mark, would not trigger NSR or scrubber retrofits for those existing plants. I do not recall any discussion that I had with EPA about the assumptions in these models in which the Agency stated that mid-life refurbishments would trigger NSR and require the existing plants to retrofit scrubbers. Had it been EPA’s view that the NSR programs, beginning in 1979-1980, would have achieved significant SO, reduc- tions, [CF would have reflected that belief in the acid rain studies we conducted on EPA’s behalf. EPA’s understand- ing that NSR would not significantly reduce SO, emissions from existing coal-fired plants was further reflected in one of the regulatory proposals EPA asked ICF to evaluate. ., EPA was considering the automatic imposition of NSPS requirements on existing coal-fired power plants when 4 103 they reached the 30-year mark as an alternative regula- tory approach to address acid rain. This EPA proposal demonstrates EPA’s belief that existing plants would not be subject to widespread retrofitting of scrubbers absent a change in the law. Most of the acid rain proposals we evaluated for EPA included the option for large-scale retrofitting of scrubbers at existing plants. ICF did not include the retrofitting analyses in the base case because EPA did not view the widespread installation of scrubbers on existing plants to be required under the existing CAA regulatory regime. To project the costs of retrofitting, we had to better under- stand the specific characteristics of the various types of existing plants. This is because, unlike projecting scrubber costs for new “greenfleld” plants which can be estimated rather accurately in a generic manner based on engineer- ing estimates, retrofit costs are dependent on a number of historical and site-specific factors. These factors include the type, location and capacity of the plant, the design of the plant (e.g., types of coal likely to be burned and whether the plant had physical space for scrubbers), and how the plant was intended to be used in the power grid. ICF did not include this type of site-specific analysis, which is neces- sary to understand retrofitting costs, in its studies for the NSPS rulemakings in 1978-1979, since those rule-makings focused on regulatory proposals applicable to new plants. ae a “oe in a Pa — ; Our studies projected that a regulatory program that . forced the retrofitting of scrubbers at existing power |. plants would be very expensive. For example, the study * that evaluated the option considered by EPA to impose _NSPS on coal-fired plants when they reached 30 years in age projected that by 1995, utilities would incur an incre- mental annual cost of $3.9 billion in 1985 dollars (this es 104 would be $6.6 billion in 2002 dollars). By the year 2010 the incremental annual cost of retrofitting would increase to $9.4 billion in 1985 dollars (this would be $15.8 billion in 2002 dollars). This incremental annual cost of retrofitting scrubbers included the annual capital charge for the costs for additional equipment (e.g., the scrubbers themselves) installation, incremental increases in O&M costs and any additional fuel costs resulting from the use of additional pollution control equipment. EPA’s option to impose NSPS on coal-fired plants when they reached 30 years in age would have required the utility industry to invest by 1995 about $29.8 billion in 1985 dollars (it would be $50 billion in 2002 dollars). Overall, if EPA’s proposal to impose NSPS on coal- fired plants at the 30-year point in their life had been adopted, the utility industry would have been required to invest approximately $69.5 billion between 1990 and 2010 in 1985 dollars (this would be approximately $117 billion in 2002 dollars). Further, these studies noted that there were other uncertainties and constraints associated with retrofitting that would have likely increased the projected costs above those reported in the ICF study. Though our model attempted to take site-specific constraints associ- ated with plant design or location into account, it was able to do so only in the most general way. * * * te 105 a % EXHIBIT 40 7 1989 EPA BASE CASE FORECASTS } | Prepared For | The U.S. Environmental Protection Agency By ICF Resources Incorporated May 1989 TABLE OF CONTENTS INTRODUCTION - stonsaniaieibiidliasdshidiaiddiadidpiaiaiiadeapabaindtampinnteteiniin 1 FORECASTS FROM 1989 EPA BASE CASES: HIGH AND LOW EMISSIONS CASES. .................... 4 SREY GPU; GI NITND cwnecosuscecceevesvevesoncenesesoooessesesee 4 TE UE: SERIES coveccesestonsceenersecsoceosorensieesensen 8 ~ Utility. Co, REESE Sea een een 9 «, Utility Generating SII sienicdeshiinniduapeumteesinemieuin 9 f- GOREN COUUNIURGEGE BAGGED ..ccccoccccscevccscccescecseccccsevess 9 Utility Fuel Consumption ...................cccceseeeeneeeenes 11 “Coal Production. .............:ccsceeseeeseeeensees scamaataaniienth 13 *- COMPARISON WITH 1987 EPA BASE CASE........... 16 3 ; SEs senmmere 22 EAR GD GPR vvessavessoncsseeconsetetecveveseevenseunsesees 22 I esissiibiescnbuneeeenedl 23 4 =f Electricity Demand Growth..............ccccccsseseeeeeseees 25 _ * "Repowering latina 25 “New Unplanned Coal Capacity...............ccccsseeeeeeens 27 ie Renewable and Non-Traditional Capacity and IESE Tee aD eae enero eas 27 SEO A ITS 28 : pe: owsrplant a aad intemmmsininesinnael 28 Coal Mining Productivity ................:cccsccceeeeseeeesees 28 106 Emissions Rates and Limits....................ccceeeeeeeess 29 PT PII ctcisicintaieiiiinincidnintnininiaaae 29 Nuclear Capacity and Capacity Factors ................ 30 AppendixA Forecasts From 1989 EPA Base: High Case Appendix B__‘ Forecasts From 1989 EPA Base: Low Case Appendix C Base Case Assumptions INTRODUCTION This report presents new EPA Base Reference Case forecasts through 2010 of future trends in utility air emissions, utility capacity and generation levels; utility fuel consumption, and regional coal production. These trends were recently re-examined in order to provide up- to-date bases from which economic and emissions impacts under alternative environmental control proposals can be assessed. Two Base Reference Case scenarios (referred to as the High and Low Emissions Cases) were analyzed to present a reasonable possible range of electric utility air emissions over the next two decades. This report is organized into three sections with three appendices. The first section presents the forecasted trends from the two new EPA Base Cases, as well as a brief analysis of the factors underlying these trends. The second section presents these forecasts in comparison to the previous (1987) EPA Base Case forecasts. The final section presents some of the key assumptions and uncer- tainties that underlie these forecasts. Appendices A and B present forecasts from the High and Low Emissions Cases, respectively, while Appendix C presents a detailed list of the 1989 EPA Base Case assumptions. — ‘o 2+ > ° — — i lng ? — _ ee eee 3 wh. + _ | . 7, 2 , 107 In the High Emissions Case utility sulfur dioxide (SO,) and nitrogen oxide (NO_) emissions are forecasted to rise moderately from recent historical levels in the near- term with continued growth in the long-term. In the Low Emissions Case, emissions remain flat in the near term, grow slightly through 2000, but decline thereafter. Gas- fired capacity options (e.g., combined cycles and turbines) are expected to be chosen for most new, currently un- planned capacity requirements through 2000 in both cases, while a significant amount of new coal capacity is forecasted to come on-line after 2000. National utility gas consumption in the High Emissions Case is expected to rise only moderately from current levels while gas loses market share to oil in many existing utility steam plant markets. In contrast, in the Low Emissions Case, gas gains considerable market share from oil in the near-term. National coal production levels are \orecasted to increase steadily, with most regions experiencing some growth from 1985 levels in both cases. Many important assumptions underlie these forecasts. Several of these assumptions have been substantially revised since the 1987 EPA Base Case analysis (which was based on assumptions developed in late 1986), reflecting important changes in the energy markets. Some key assumptions were varied between the two reference cases to reveal the sensitivity of the emissions and fuel use forecasts to these factors. The most important of these assumptions are presented in the table on the following page. In general, the assumptions used in the Low Case contribute to lower forecasted emissions growth than in the High Case. In particular: 108 ¢ Lower electricity demand results in lower coal powerplant utilization. ¢ Shorter fossil steam powerplant lifetimes result in earlier retirements of higher- emitting existing coal units, which are 1989 EPA Base: Reference Case Assumption High Low Crude Oil Prices 1995 18.00 25.00 (1988$/bbl) 2000 22.00 29.00 2005 25.00 2010 29.50 Electricity 1988-2000 2.8 Demand Growth 2001-2010 2.3 (% per year) Steam Powerplant Coal/Oil/Gas> 50Mw 65 Lifetimes (years) Coal/Oil/Gas> 50Mw 45 Nuclear 35 Cogeneration 1995 175 (billions of 2000 208 kilowatt hours) 2005 255 2010 313 New Non-Fossil Capacity 2005 0 (gigawatts) 2010 0 Repowered Coal 2000 Capacity* (gigawatts) 2005 6 2010 10 PS tee. Apr * dk PARE ot eee VER eke od Xs. 109 New Unplanned 2000 2005 Coal Powerplants Allowed By * Includes 50% increase in capacity due to repowering. generally replaced by new lower-emitting gas or scrubbed coal capacity. ¢ More repowering with clean coal technolo- gies reduces SO, and NO, emissions rates at repowered plants. * More non-fossil capacity and cogeneration reduces the amount of higher-emitting coal- fired capacity operated and built. A more detailed discussion of the assumptions, cave- ats, and uncertainties pertaining to this 1989 EPA Base Case analysis is presented in the final section of this report. - *x * KEY ASSUMPTIONS A number of assumptions have important effects on projections of future levels of utility emissions, utility is , generation and capacity, utility fuel consumption, and coal production. A short list of some of the key assumptions used in the two reference cases is shown on page 2, while a detailed list of the assumptions is presented in Appendix ; .C.:Several of the more important assumptions incorpo- rated in this Base Case analysis, and their effects on the forecasts presented herein, are discussed below. ey 110 Oil and Gas Prices Oil and gas prices have a very important effect on the amount of turbine/combined cycle versus coal capacity built. In turn, relative oil and gas prices affect the amount of gas versus oil consumption at existing oil/gas steam powerplants. Accordingly, the level of oil and gas prices have important effects on utility SO, emissions. World oil prices are very uncertain because the world oil market is fundamentally unstable: the lowest cost producer (Saudi Arabia) is also the marginal producer (largely for political reasons). Therefore, it is difficult to define within a narrow range the full spectrum of potential future oil prices. However, future oil prices would be expected to range from levels near recent depressed levels of $17/bbl (reflecting continued market weakness) to moderately higher real prices as the current excess pro- duction capacity situation abates. There is also uncertainty with respect to delivered natural gas prices. Recent ICF gas market assessments suggest that the current gas supply “bubble” will dissipate by around 1990. This is expected to lead to relatively significant increases in prices in the near term such that wellhead prices would be expected to be no lower than $2.60 per million Btu even assuming low oil prices. In the long-term, recent ICF analyses conducted for DOE suggest that gas resources available for production in North America (both in Canada and in the U.S.) are more plenti- ful than previously thought, and that advances in explora- tion and extraction techniques will expand the supply of low- to medium-cost gas reserves. Accordingly, wellhead prices increase more slowly in response to greater supplies in the $3 to $4 wellhead gas price range. However, the 111 trends in gas prices are strongly linked to future oil prices (since gas and oil are substitutes in many applications), and hence are also very uncertain. Alternative oil and gas prices in the High and Low Cases were assumed to reflect these uncertainties. ICF’s projections of oil and gas prices are based on a previous integrative assessment of demand and supply conducted for the DOE which suggested an amount of supply that would be available at given price levels. The specific price projections used in this base case analysis were not devel- oped using a detailed supply/demand model, such an effort would be outside of the intended scope of this proj »ct. In the High Case, lower oil prices were assumed over time, remaining at about $18/bbl through 1995, increasing moderately to reach $22/bb by 2000 and $29.50/bbl by 2010. Accordingly, delivered natural gas prices to utilities (on an average annual, interruptible basis), in New Eng- land rise from roughly $2.50/mmBtu recently to $4.10/mmBtu in 2000 and $4.95/mmBtu by 2010. As a result, gas prices are generally higher than most grades of residual oil in this case, thereby leading to relatively more oil consumption. In contrast, in the Low Case, world oil prices are forecasted to increase more rapidly over time, reaching $29/bbl by 2000 and $34/bbl by 2010. Although delivered gas prices are forecasted to be higher than in the High Case ($4.40/mmBtu in New England by 2000, and $5.15/mmBtu by 2010), gas prices are typically lower than competing residual oil prices, so that relatively more gas consumption results in this case. See Appendix C for average annual interruptible prices for gas delivered to utilities in the High and Low Cases as compared to re- gional residual oil prices. 112 Because of seasonal fluctuations in the demand for gas from residential and commercial customers, there tends to be relatively high delivered gas prices to utilities in the winter (about 10-20 percent above the annual average price in recent years) and lower delivered gas prices in the summer (about 10-20 percent below the annual average price). Electric utility consumption of gas is assumed to vary seasonally. In the High Case, with relatively low oil prices, gas was generally forecasted only to be consumed by electric utilities in the summer months in the Eastern states. In the Low Case, with relatively low gas prices as compared with oil, gas was generally fore- casted to be consumed by utilities during all seasons except the winter months in the Eastern states. In the West South Central region, gas was forecasted always to be competitive with oil in both the Low and High Cases, with electric utilities consuming all natural gas at oil/gas steam plants in Texas and Louisiana in all years. In California, due to stringent environmental regulations, only gas was assumed to be consumed at oil/gas steam plants. Scrubber Costs Lower scrubber costs were assumed in the new EPA Base Case analysis than were used in the 1987 EPA Base Case, reflecting technology improvements in the pollution control industry. These costs are roughly comparable to the lower industry scrubber costs used in a number of EPA acid rain coutrol analyses conducted recently by ICF.’ The * See, for instance, Analysis of the Mitchell Compromise Acid Rain Proposal, September 1988. +" nthe + ay + ’ on 8 9” 113 new scrubber cost assumptions were based on EPRI/ Stearns-Rogers cost assumptions as interpreted by RCG/ Hagler, Bailly, Inc. (Several key assumptions were made: (1) a contingency factor of 15 percent was used, (2) one spare module was assumed, and (3) scrubbers were as- sumed to be designed with no reheat in contrast to as- sumptions in the 1987 EPA Base Case.) The cost assumptions for a new NSPS-Da powerplant resulting from this assessment are presented in Table 4. The net effect of these assessments was that wet scrub- bing was assumed to be employed at all unplanned new powerplants, because wet scrubbing cost estimates were lower than dry scrubbing costs estimates. Accordingly, the cost differences in scrubbing high and low sulfur coals were smaller than were assumed in the 1987 EPA Base Case. Furthermore, scrubbed units are forecasted to be higher utilities’ dispatch order than in the 1987 EPA Base Case because of lower variable O&M costs associated with scrub- bing, thereby increasing forecasted utilization levels some- what. These effects led to stronger growth in high sulfur coal production than was forecasted in the 1987 EPA Base Case. Sulfur Level Lbs. 5U /mmbBtu: Very Low Sulfur Less than 0.80 Low Sulfur 0.80-1.08 Low-Medium Sulfur 1.09-1.66 Medium Sulfur 1.67-2.50 High-Medium Sulfur 2.51-3.33 High Sulfur 3.54-5.00 Very High Sulfur More than 5.00 Capital Costs (early ’86 $/kw) Fixed O&M Costs (early ’86 Vkw-yr) Variable O&M Costs (early ’86 mills/kwh) Energy Penalty (%) Capacity Penalty (%) Reliability Penalty (%) Annual Emissions Rate (ibs. SO/mmBtu) UTILITY POWERPLANTS MEETING . — te NSPS SUBPART DA REGULATIONS Sulfur Level Very Low High Low Low Medium Medium Medium High 108.00 110.00 110.00 124.00 133.00 145.00 492 498 500 545 574 611 0.25 0.32 0.46 0.69 0.92 1.36 2.50 2.50 2.50 2.50 2.50 2.50 2.10 2.20 2.10 2.10 2.10 2.10 2.70 2.70 2.70 * 2.70 2.70 2.70 0.22 0.29 0.48 0.48 0.48 0.60 115 Electricity Demand Growth Electricity demand growth is forecasted to be much lower (1.7 percent per year from 1987 to 2010) in the Low z. Case than in the High Case (2.6 percent per year from t 1987 to 2010). This has readily apparent ramifications 3 upon the amount of utility generation required to meet e electricity demands, the majority of which is provided by fossil fuels. Thus, higher electricity demand growth ultimately translates to higher utility emissions. The national average growth rate assumptions incor- porated in these reference cases were implemented at EPA's direction. Differential growth rates by region were based on recent NERC projections of future electricity growth in each NERC reliability council region, and then adjusted by RCG/Hagler, Bailly, Inc. to achieve the target national sales growth rate assumed by EPA. In the High Case, however, somewhat different near-term growth assumptions (i.e., through 1995) were used in the East North Central and the West South Central regions. In this case, higher near-term growth was assumed in the East North Central (2.9% per year from 1987 to 1995 instead of 2.5% per year) reflecting a continuation of recent historical growth trends (about 3.3% per year from 1986 to 1988) and consistent with strong economic growth and low oil prices assumed in this case. In contrast, low near-term growth was assumed in the West South Central (1.9% per yeer from 1987 to 1995 instead of 2.9% per year) reflecting -+ a continuation of recent historical trends (only 2% per year _ from 1985 to 1988) and consistent with low oil prices and, - & Since ICF forecasts of future regional electricity eis demand growth were previously the underlying source for 116 the EPA demand forecasts, regional sales growth patterns in the 1989 EPA Base Case analysis are different than those used in the 1987 EPA Base Case. Repowering In contrast to the 1987 EPA Base Case, EPA assumed for this Base Case analysis that utilities would undertake a small to significant amount of repowering at certain existing coal-fired units. Repowering (using a “generic clean coal” technology) was assumed at EPA's direction to have much greater market penetration in the Low Case than in the High Case. Repowering candidates were assumed to include only those unscrubbed SIP coalunits greater than 75 megawatts and less than 400 megawatts, since current evidence suggests that repowering technolo- gies may be uneconomic or technically infeasible at very small or very large units. Units were assumed to become part of the candidate pool upon reaching 35 years of age beginning in 2000 (with only units built before 1950 assumed to be too old to repower). In the Low Case, it was assumed a total of one third of all such candidates would repower by 2010 with lower percentages (5 percent by 2000 and 20 percent by 2005) assumed in earlier years. In the High Case, much lower market penetration was assumed with only 10 percent of candidate units repowering by 2010 (5 percent by 2005 and no repowering in 2000). In the assumed first year of repowering in both the High and Low Cases, units between 75 and 150 Mw and built before 1960 were generally selected for repowering. In later years, units up to 400 Mw and those built in the late 1960s and early 1970s were assumed to be selected for 117 repowering. Smaller units were assumed to be selected first because utilities would wish to develop their design and construction expertise in simpler, less expensive settings. Older units were selected first because they are generally smaller and because many utilities would tend to repower units as they reached the end of their useful lives (assuming no major refurbishment). Repowered units were selected regionally so as to roughly reflect the pro- portional distribution of available candidate capacity. (A list of selected repowered capacity by CEUM regions is included in Appendix C.) Future utility regional capacity requirements (as forecast in the two reference cases) were taken into account in selecting the repowered units. Capacity was only selected to the extent new capacity was needed in the region to meet reserve margin requirements. Note that capacity affected by these repowering assumptions are in addition to those units which have already repowered (e.g., TVA’s Shawnee 10, NSP’s Black Dog 4, MDU’s Heskett 2, Colorado-Ute’s Nucla 4) or have firm plans to repower (AEP’s Tidd and Sporn projects, SPS’s Nichols 3). Together, these units total roughly 1 gigawatt of capacity, in contrast to about 38 gigawatts of repowered capacity that results by 2010 from the repower- ing assumptions of the Low Case.’ The assumed cost and performance characteristics of the repowering technology are discussed below, and are generally representative of a fluidized bed combustion (FBC) technology. * In addition, other projects (using other emissions control tech- nologies which do not increase capacity) that were approved for funding .. , in DOE’s Clean Coal Technoiogy development program (through Round II) were also included in this Base Case analysis. 118 ¢ Capacity at those units that were selected for repowering was assumed to increase by 50 percent upon repowering. DOE assumes that atmospheric FBC (AFBC) repowering would lead to a 15 percent increase in capac- ity, pressurized FBC (PFBC) repowering would lead to a 30-50 percent capacity in- crease, and integrated gasifier combined cy- cle (IGCC) repowering would lead to a 150 percent increase in capacity.‘ The 50 percent capacity increase assumption was thus chosen as a reasonable average capacity gain for re- powering projects to reflect a “representative” repowering technology, weighted heavily to- wards FBC technology for a typical installa- tion (given the current relatively advanced state of FBC development, demonstration, a economic refinement). This 50 percent aver- age capacity gain assumption is in agree- ment with EPRI’s current assumptions. ¢ A heat rate of 9500 Btu/kwh was assumed for all repowering projects. This is in rough accord with EPRI TAG estimates for the candidate repowering technologies (9000 Btu/kwh for PFBC and IGCC, 10000 Btu/kwh for AFBC).° ¢ O&M cost estimates for the generic repower- ing projects were also derived using EPRI TAG. information (see PFBC combined cycles). Assuming the use of a 4% sulfur bituminous * America’s Clean Coal Commitment. U.S. Department of Energy, Office of Fossil Energy, February 1987. * TAG - Technical Assessment Guide, Volume 1: Electricity Supply - 1986. Electric Power Research Institute (EPRI p. 4463-SR), December 1986. ° 119 coal, fixed O&M costs were assumed to be $38.60/kw-ye, while variable O&M costs were assumed to equal 5.5 mills/kwh (costs in early 1986 $). ¢ A minimum capacity, (turndown) of 50 per- cent was assumed for repowered units also in line with EPRI’s assessment of PFBC technology. ¢ Additionally, it was further assumed that repowering would not affect a unit’s avail- ability (forced and scheduled outage rates were assumed not to improve). * Emissions rates were assumed to meet cur- rent NSPS requirements for SO, and TSP. NO, rates from repowered projects were as- sumed to equal 0.3 lbs. NO, per million Btu. Note that the assumed level of repowering can signifi- cantly affect new utility capacity needs/decisions, regional coal production, and the level of SO, emissions (since repowered units have much lower SO, emissions rates). New Unplanned Coal Capacity No new unplanned coal capacity was assumed to be ~.. built until 2000 (High Case) or 2005 (Low Case) to reflect the difficulties and long lead times in planning/siting/ building new coal plants. This assumption influences coal versus gas capacity and consumption levels, as well as coal production levels and SO, emissions forecasts. u ; 120 Renewable and Non-Traditional Capacity and Generation In the High Case, a small amount of planned renew- able and non-traditional capacity was assumed to be added by 20 (about 5 gigawatts, with most being added in California). After 2000, in the High Case, no additional non-fossil capacity was assumed to be added. In contrast, in the Low Case, a significant quantity of new currently unplanned renewable and non-traditional capacity was assumed to be added by utilities after 2000. This was assumed to include such possibilities as advanced nuclear, wind, solar, and geothermal technologies. The amount of such capacity was assumed to be sufficient to meet ap- proximately one-quarter of all assumed incremental electricity demand growth after 2000. The effects of this assumption are to reduce new fossil capacity require- ments, lower fossil fuel consumption, and decrease utility SO, and NO, emissions. Cogeneration The effects of the assumed higher cogeneration fore- casts in the Low Case are similar to the effects of in- creased renewable and non-traditional capacity. The cogeneration assumptions used in the Low Case were developed by RCG/Hagler, Bailly, Inc. The High Case cogeneration assumptions were developed by ICF from recent assessments conducted in preparing the FERC Base Case.* Although the High Case cogeneration forecasts * Draft Environmental Impact Statement: Regulations Governing Independent Power Producers (RM88-4-000) and Regulatwons Governing Bidding Programs (RM88-5-000), Federal Energy Regulatory Commission, (Continued on following page) a” ek ee ee 7 ton 3s & aie: al ET TT TET ES 121 are lower than those used in the Low Case, both sets, of assumptions result in more cogeneration than assumed in the 1987 EPA Base Case. This results in less utility generation and, hence, lower emissions. Powerplant Lifetimes Powerplant lifetime assumptions also have significant effects upon forecasted SO, emissions. Shorter assumed fossil powerplant lifetimes serve to lower SO, emissions forecasts, since older high-emitting units would retire sooner (and be replaced by lower-emitting new capacity). Further, regional coal production patterns are potentially affected, since retiring low- or medium-sulfur coal units might be replaced by new scrubbed coal capacity using high sulfur coals. In contrast, longer assumed nuclear lifetimes would lower SO, emissions by delaying the need for fossil-fired replacement capacity. The range of assumptions for large fossil plants (65 years assumed in the High Case, 55 years assumed in the Low Case) was specified by EPA. EPA in the past has used a 60 year lifetime assumption. Note that smaller units (under 50 megawatts) are assumed to retire sooner (after 45 years) to reflect generally unfavorable econoinies of scale in refurbishing low capacity units. The range of assumptions for nuclear plants (35 years in the High Case and 40 years in the Low Case) was also specified by EPA. Nuclear plants are granted a 40-year operating license upon issuance of their construction permit (for plants built prior to 1982) or upon issuance of their operating license ie Offices of the General Counsel, Office of Economic Policy, Office of » Electric Power Regulation, June 1988. 122 (for plants built in 1982 or after). Thus, most pre-1982 plants would only have lifetimes of about 35 years or less from date of initial operation (because of the lag between licensing, construction, and final operation). However, the NRC has recently changed the terms in two cases such that the duration of the permit is from the date of initial operation, which would result, in an effective 40-year lifetime. Accordingly, the range of nuclear plant commer- cial lifetimes is most probably bounded by a low of 35 years and a high of 40 years. Coal Mining Productivity Coal mining productivity assumptions were revised for this Base Case analysis to reflect recent continued high productivity growth in the coal mining industry. For instance, gross labor productivity increased by about 7 percent per year between 1982 and 1987 at underground mining operations. While ICF views these high rates of productivity growth as a short-term phenomenon, the high rates of growth in the past few years (and expected in the near future) were newly incorporated into this Base Case analysis, and have important implications on coal prices: real coal prices (and sulfur premia) are lower in these reference cases than in the 1987 EPA Base Case. The net effect of higher assumed mining productivity is thus to make coal more economically attractive (by reducing the future trends in real coal prices) in new capacity decisions. Emissions Rates and Limits A recent review of SO, emissions rates at selected powerplant units around the country revealed that some units (including many unscrubbed NSPS Subpart D units 123 in the West) have historically emitted, and will likely continue to emit, at rates well below their required limits. Generally, this is because these units have access to ample supplies of inexpensive local coals, or have committed to contract purchases of coals, which have sulfur contents well below SIP or NSPS requirements, or have found that the variability of sulfur in coals requires a lower long-term average sulfur content. For the new Base Case analysis, these units were assumed to emit at rates in line with current coal deliveries As a result of (1) the recent enactment, revisions to, or implementation of acid rain programs in certain states (Minnesota, Wisconsin, Massachusetts, New Hampshire, and New York), and (2) latest revisions in SIP limits due to stack height or local ambient air quality reviews (particu- larly in Indiana), several unit-specific, utility-specific, or statewide emissions limits were included for this new EPA Base Case analysis. These regulatory changes have occurred since the development of the 1987 Base Case in late 1986. No other changes in emissions limits were assumed by EPA. It was assumed by EPA that the recent WEPCo decision would not result in any significant number of powerplants having to comply with NSPS upon refurbishment. Financial Parameters Electric utility financial assumptions are presented below and were not varied under the two base cases. They differ slightly from the 1987 EPA Base Case with the real cost of capital somewhat higher but the real capital charge rate about the same. The major difference in the real cost of capital was the assumed cost of debt, preferred equity, 124 and common equity. These were raised to levels of 9.2 percent pre-tax cost of debt, 10 percent cost of preferred equity, and 13 percent cost of common equity (based on current nominal cost of debt and preferred equity for utilities) from previous assessments of 7.6, 7.9, and 12.8 percent respectively. Note that for future investments this cost of capital could be higher or lower although long term real cost of debt and equity have generally been much lower. EPRI assumes somewhat higher nominal cost of debt and equity which largely reflects a higher assumed inflation rate of 6 percent. Mixed Percent of Weighted Total Utility Pre-Tax After Average Capital Cost TaxCost Cost Debt 50% 9.2% 5.61% 4.60 Preferred Equity 15% 16.39% 10.0% 1.50 Common Equity 35% 21.31% 13.0% 4.55 10.65% Nominal Discount Rate 10.65% Real Discount Rate 5.38% Inflation Rate 5.0% Real Capital Charge Rates 30 Year Book Life: Coal/Nuclear/Scrubber/ Combined Cycle 9.4% 20 Year Book Life: Combustion Turbines 11.5% Nuclear Capacity and Capacity Factors Nuclear capacity was not assumed to vary between the two base cases. No new nuclear capacity beyond 27 2 BRS a. ees ie “er LO TK a” ee 2 Rey tee |, ASBOES TP phy 125 currently planned units was assumed to be built by 2010 in the High Case. In the Low Case, as part of increased non-fossil generation assumptions, it was implicitly assumed that new nuclear plants could potentially be built after 2000. In both cases, in the near term, several impor- tant assumptions were made regarding the completion of delayed units: Seabrook will be at full power by 1995, Shoreham will be cancelled and remain unused, and Rancho Seco will continue to operate for the duration of its life. In addition, Vogtle 2 (Georgia Power), Limerick 2 (Philadelphia Electric), Comanche Peak 1 and 2 (Texas Utilities), South Texas 1 and 2 (MAP), and all TVA units except Watts Bars 2 and Bellefonte are assumed to be on- line by 1995; Watts Bar 2 will be on-line by 2000, and Bellefonte will be cancelled. Average nuclear capacity factors have been increased in the near-term compared with the 1987 EPA Base Case (70 percent versus 67 percent in 1995). In the new refer- ence cases the capacity factor‘was also increased in 2000 (71 percent versus 67 percent in 2000). The higher capac- ity factors in 1995 and 2000 reflect better operational practices instituted in, recent years and a continuation of improvements experienced in the last several years (e.g., historical capacity factors in the U.S. have increased from recent low levels of 57 percent in 1986 to 65 percent in 1988). After 2000, as many units age, average capacity factors are assumed to decline to about 66 to 68 percent as unit reliability decreases. 126 EXHIBIT 41 ICF RESOURCES INCORPORATED Mr. Robert A. Beck July 26, 1989 Director Clean Air, Fossil Fuels and Natural Resources Edison Electric Institute 1111 19th Street, N.W. Washington, D.C. 20036 Dear Mr. Beck: In your letter of July 12, 1989, you raised a number of questions regarding the assumptions used in the 1989 Base Case analyses performed by ICF Resources for EPA. We are happy in this letter to respond to these questions. In addition, we have enclosed a copy of the report 1989 Base Case Forecasts for your use and review. The 1989 EPA Base Case analyses were conducted by ICF for EPA’s Office of Policy, Planning and Evaluation to reassess future utility air emission trends using up-to-date sets of assumptions. In the Base Case analyses, EPA had us examine two cases — a “High” case and “Low” case — so as to present a reasonable possible range of future utility emissions. To achieve this result, these cases incorporated different sets of assumptions that would respectively result in higher and lower utility SO, emissions trends. Fossil powerplant lifetime assumptions were among the important differences in assumptions between the two cases: 55 years was assumed for all large (i.e., larger than 50 megawatt) fossil steam generating units in the Low case, while 65 years was assumed for all large fossil steam units in the High case. The difference in assumptions &* owe a eke S Scene y, -«". 127 obviously has an important effect on utility emission trends, as demonstrated in the ICF analysis. Before 1984, EPA had assumed that all fossil-fueled powerplants had a physical, useful operating lifetime of 45 years for al of the analyses performed by ICF for EPA. This assumption was subsequently revised to 60 years for the 1984 Interim EPA Base Case and all following analyses as it became obvious that existing powerplants were being operated for periods longer than 45 years. For both of the cases evaluated for the 1989 EPA Base Case forecasts, it was assumed that all large oil- and coal- fired powerplant units at 30 years of age would engage in refurbishment activities sufficient to achieve the above- noted powerplant lifetime assumptions. Those units explicitly assumed to repower using a “generic clean coal” technology were not included as part of this universe of “life extended” powerplants. About 350 gigawatts of e capacity (about half of all fossil fuel-fired capacity ex- pected to online by 2010) will undertake life extension activities by 2010 under these specific assumptions. Consistent with previous ICF modeling efforts, it was assumed that net dependable capacity and reliability of existing powerplants would be maintained at design levels for their entire 55 to 65 year lifetime. However, unit heat rates were assumed to increase by 0.25% per year to reflect powerplant aging (i.e., to reflect progressive dete- rioration in potential power output, combined with a one- 3 time 5% decrease in heat rates assumed to occur at the i time of refurbishment (to reflect the restoration of the b. powerplant to something close to its original design operating efficiency as a result of refurbishment). These assumptions have been included in all of the EPA analyses 128 by ICF since the 1985 EPA Base Case assessments began in 1984. Two additional issues related to powerplant refur- bishment that were raised either directly or implicitly in your letter include the following: ¢ The powerplant lifetime/refurbishment assump- tions in the 1987 Interim EPA Base Case in- cluded an assumed average cost of $200 per kilowatt in early 1986 dollars for all refurbished units. No assumptions regarding the costs of re- furbishment were explicitly made in the more re- cent analyses, however, because the costs of life extension were assumed to be sufficiently low (at $200 per kilowatt in early 1986 dollars or less) that all units would be refurbished and their lives extended under all the environmental regu- latory scenarios evaluated. Since these refur- bishment costs will be incurred in all cases, they do not affect the analysis of different environ- mental regulator scenarios. ¢ As stated on page 29 of the enclosed report, “it was assumed by EPA that that recent WEPCo decision would not result in any significant num- ber of powerplants having to comply with NSPS upon refurbishment.” It was also assumed that refurbishment would not result in more stringent emission requirements under PSD. Thus, for purposes of the recent EPA forecasts, the act of refurbishment, (which, for the purposes of the EPA Base Case, means efficiency improvements and other maintenance designed to enable an additional 25-35 years of acceptable operation up to design capacity) was not assumed by EPA to require any refurbished plant to meet tighter new source emission controls. 129 We hope that this information is useful to you and ade- quately addresses your questions. Please call should you have any further questions. Sincerely, SIGNED BY K.A. SCHWEERS Kenneth A. Schweers, President ICF Resources Incorporated 130 EXHIBIT 42 United States General Accounting Office GAO Report to the Chairman, Sv’ ommittee on Oversight and Investi; ‘ions, Committee on Energy and Commerce, House of Representatives September ELECTRICITY 1990 SUPPLY Older Plants’ Impact on Reliability and Air Quality [SEAL] GAO/RCED 90-200 Chapter 3 Changing Air Quality Requirements Could Affect Life Extension Plans Fossil fuel power plants are significant sources of harmful pollutants, particularly sulfur dioxide and nitrogen oxides, and the plants exempted from the Clean Air Act produce a disproportionately large share of these pollutants. Recent legislative and regulatory developments could require significantly reduced emissions from these exempt plants and could cause electric utilities to alter some planned life extensions projects. Enactment of proposed acid rain control legislation probably would not preclude life extension, but this depends on the legislation’s final requirements. Offi- cials of DOE and utility organizations expressed concern, however, that exempt plants altered to extend their service life must meet the act’s emission standards if EPA decides, as it did for one plant in 1988, that the alteration would result in increased emissions. According to the officials, the additional costs of achieving the more stringent standards . . 3- i i €. “ 131 could discourage some life extension projects. However, such decision one plant in 1988, that the alteration would result in increased emissions. According to the officials, the additional costs of achieving the more stringent standards could discourage some life extension projects. However, such decisions could also reduce the nation’s total power plant emissions by eliminating an existing economic incen- tive to retain exempt plants. Plants Constructed Before August 1971 Produce the Most Pollutants When Congress enacted the Clean Air Amendments of 1970, it exempted power plants constructed prior to the publication of EPA’s regulations (August 17, 1971) from having to meet the legislated emission standards. The exempt plants produce a disproportionate share of utilities’ sulfur dioxide and nitrogen oxide emissions.’ Although these plants that were exempted from federal regulations are subject to state regulations, the states generally allow emissions at much higher levels than those specified in the Clean Air Act. Emissions of sulfur dioxide and nitrogen oxides have associated health and environmental consequences. Sulfur dioxide, a colorless gas with a pungent and irritating odor, can aggravate symptoms of heart and respiratory diseases. Nitrogen oxides, gaseous air pollutants, can also aggravate respiratory problems. Emissions of sulfur dioxide and nitrogen oxides, which have been linked to the formation of acid rain, also represent a threat to natural resources, ecosystems, materials, and visibility. * Burning fossil fuel also produces air pollutants such as particu- late matter and carbon dioxide, but because the current Clean Air Act debate relating to utilities focuses on acid rain controls, our analysis was limited to sulfur dioxide and nitrogen oxides. 132 According to EPA’s nationwide data for 1985,’ the last year for which complete data are available, plants’ built prior to August 1971 contribute the majority of fossil fuel plants’ emissions of sulfur dioxide and nitrogen oxides. In 1985 fossil fuel power plants emitted 16 million tons of sulfur dioxide; plants built prior to August 17, 1971, emitted 88 per cent of the total (see fig. 3.1). Of the nearly 7 million tons of nitrogen oxides emitted in 1985 by fossil fuel plants, approximately 79 percent was emitted by the exempt plants (see fig. 3.2). Figure 3.1: 1985 Sulfur Dioxide Emissions by Exempt and Nonexempt Fossil Fuel Power Plants Nonexempt Power Plants Exempt Power Plants Note: Total 1985 sulfur dioxide emissions from electric utility fossil steam power plants were 16,046,190 tons Source: Prepared by GAO from EPA data. * The data, from EPA’s Air and Energy Engineering Research Laboratory, are not measurements of actual pollutants released into the atmosphere, but EPA’s best estimates. * ~ * 133 Application of the Clean Air Act’s Current Emission Standards to Plants With an Extended Service Life Is Uncertain In developing regulations following the 1977 Clean Air Act amendments, EPA assumed that utilities would continue to replace most plants at the end of their traditional 30- to 40-year service life; consequently, the regulations do not explicitly address power plant life extension. In a 1988 case, the agency ruled that the Clean Air Act’s emission standards would apply to a previously exempt power plant if the utility would pursue its life extension project as proposed. This ruling has created concern among DOE and electric utility organization officials regarding the poten- tial costs, and therefore the economic viability of some life extension projects. Clean Air Act Regulations Do Not Explicitly Address Life Extension In enacting the Clean Air Act Amendments of 1977, Congress revised the New Source Performance Standards (NSPS) and established the Prevention of Significant Deterioration (PSD) program. The NSPS, established by Congress under Clean Air Amendments of 1970, regulate the emissions from new sources, including electric utility power plants. The standards were modified in 1977 to further restrict power plant emissions by requiring the use of emission control technology, typically flue gas desulfuriza- tion (FGD) equipment for reducing sulfur dioxide emissions, and other types of emission control equipment for reducing emissions of other regulated pollutants. The PSD program was established to preserve air quality in unpolluted areas 134 of the country by regulating power plants’ total annual emissions and, as the NSPS do, by requiring the use of the “best available” emission control equipment. EPA, in formulating the NSPS and the PSD program, included provisions regulating modifications of power plants, but because it did not anticipate life extension, it did not explicitly address life extension projects. While Congress exempted plants constructed prior to the enactment o [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/brief%3Amicro_IA40385016_0237%3A09. Public record. Not legal advice.