ELK HILLS POWER v. BOARD OF EQUALIZATION (Mihara and Miller, JJ., justices pro tempore; Baxter and Werdegar, JJ., not participating)

Appellant’s Request for Judicial Notice

Cal.July 25, 2012

SUPREME COURT FILED No. $194121 JUL 25 2012 IN THE Frank A. McGuire Clerk SUPREME COURT OF CALIFORNIA Deputy ELK HILLS POWER, LLC, Plaintiff and Appellant, Vv. CALIFORNIA STATE BOARD OF EQUALIZATION AND COUNTY OF KERN, Defendants and Respondents. After A Decision By The Court of Appeal Fourth Appellate District, Division One, Case No. D056943, San Diego Superior Court Case No. 37-2008-00097074-CU-MC-CTL APPELLANT’S MOTION REQUESTING JUDICIAL NOTICE LAW OFFICE OF PETER MICHAELS GIBSON DUNN & CRUTCHER Peter W. Michaels (93212) Julian W. Poon (219843) 6114 La Salle Avenue, #445 Blaine H. Evanson (254338) Oakland, California 94611 333 South Grand Avenue Telephone: (510) 547-0255 Los Angeles, California 90071 Telephone:(213) 229-7000 MOONEY, WRIGHT & MOORE, PLLC Paul J. Mooney (pro hac vice) Arizona State Bar No. 006708 1201 South Alma School Rd., Ste. 16000 Mesa, AZ 85210 Telephone: (480) 615-7500 Attorneysfor Plaintiffand Appellant Elk Hills Power, LLC No. 8194121 IN THE SUPREME COURT OF CALIFORNIA ELK HILLS POWER, LLC, Plaintiff and Appellant, Vv. CALIFORNIA STATE BOARD OF EQUALIZATION AND COUNTYOF KERN, Defendants and Respondents. After A Decision By The Court of Appeal Fourth Appellate District, Division One, Case No. D056943, San Diego Superior Court Case No. 37-2008-00097074-CU-MC-CTL APPELLANT’S MOTION REQUESTING JUDICIAL NOTICE LAW OFFICE OF PETER MICHAELS GIBSON DUNN & CRUTCHER Peter W. Michaels (93212) Julian W. Poon (219843) 6114 La Salle Avenue, #445 Blaine H. Evanson (254338) Oakland, California 94611 333 South Grand Avenue Telephone: (510) 547-0255 Los Angeles, California 90071 Telephone: (213) 229-7000 MOONEY, WRIGHT & MOORE, PLLC Paul J. Mooney (pro hac vice) Arizona State Bar No. 006708 1201 South Alma School Rd., Ste. 16000 Mesa, AZ 85210 Telephone: (480) 615-7500 Attorneysfor Plaintiffand Appellant Elk Hills Power, LLC MOTION REQUESTING JUDICIAL NOTICE Pursuant to Rules 8.520(g) and 8.252 of the California Rules of Court, and Sections 452 and 459 of the Evidence Code, Appellant Elk Hills Power, LLC (“EHP”) respectfully requests that the Court take judicial notice of the following nine (9) documents listed below, which are included as exhibits to the attached Declaration of Paul J. Mooney. 1. California Energy Commission Decision Application for Certification Elk Hills Power Project, Docket No. 99-AFC-1, (December, 2000), at pp.120-36. 2. United States Energy Information Administration — International Energy Outlook 2011 (September 19, 2011). 3. United States Energy Information Administration — Natural Gas 1998: Issues and Trends, Chapter 2, Natural Gas and the Environment. 4. United States Energy Information Administration - Annual Energy Outlook 2012 with Projections to 2035, pp.86-88. 5. San Joaquin Valley Air Pollution Control District Authority to Construct, Permit No. S-3523-1-2 (March 30, 2000). 6. San Joaquin Valley Air Pollution Control District Authority to Construct, Permit No. S-3523-2-2 (March 30, 2000). 7. California Energy Commission Order Approving Project Modification (March 19, 2003). 8. California Energy Commission Request to Amend the Elk Hills PowerProject (99-AFC-1C) to Allow PM10 ERC Tendering and Commissioning Emissions Increase Staff Analysis (February 28, 2003). 9. California Energy Commission Proceeding’s Main Pagefor the Elk Hills Power Plant Project. 1 The documents that are the subject of this Motion are offered in support of EHP’s Consolidated Answer to Amicus Curiae Briefs In Support of Respondents, which is filed simultaneously herewith. These documents were not presentedto thetrial court nor to the Court of Appeal, and they do not relate to proceedings occurring after the judgment in the above- captioned matter. True and correct copies of each documentare attached to the Declaration of Paul J. Mooney. This Motion is made on the basis that Exhibits 1-9 are relevant to EHP’s Consolidated Answer to Amicus Curiae Briefs Filed In Support of Respondents by the following entities: California State Association of Counties and California Assessors’ Association, John R. Noguez, Los Angeles County Assessor, Natural Resources Defense Council, The Sierra Club, Middle Class Taxpayers Association of San Diego, and Climate Protection Campaign. These Amici have raised arguments that go beyond the scope of the record in this case, including arguments based on appraisal theory and environmental policy. EHP’s response to these arguments requires reference to records of administrative agencies, including the United States Energy Information Administration, the California Energy Commission and the San Joaquin Valley Air Pollution Control District. The documents contained in Exhibits 1-9 are responsive to the arguments made by these Amici. Evidence Code Section 452(c) permits courts to take judicial notice of “[o]fficial acts of the legislative, executive, and judicial departments of the United States and of any state of the United States.” (Evid. Code § 452(c).) Official acts have been interpreted to include “records, reports and orders of administrative agencies.” (Ordlock v. Franchise Tax Bd. (2006) 38 Cal.4th 897, 912 n.8 [quoting Rodas v. Spiegel (2001) 87 Cal.App.4th 513, 518].) Evidence Code 452(h) permits courts to take judicial notice of “(f]acts and propositions that are not reasonably subject to dispute and are capable of immediate and accurate determination by resort to sources of reasonably indisputable accuracy.” (Evid. Code § 452(h).) Exhibits 1 and 7-9 are official records of the California Energy Commission. Exhibits 2-4 are reports of the United States Energy Information Administration. Exhibits 5-6 are official records of the San Joaquin Valley Air Pollution Control District. Exhibits 1-9 all set forth facts and propositions that are not reasonably subject to dispute and are capable of immediate and accurate determination by resort to sources of reasonably indisputable accuracy, i.e. the federal or State administrative agencies themselves. For these reasons, EHP respectfully requests that the Court take judicial notice of Exhibits 1-9. A proposed form oforderis attached. RESPECTFULLY SUBMITTEDthis 24" day of July, 2012. LAW OFFICE of PETER MICHAELS and GIBSON, DUNN & CRUTCHER, LLP and MOONEY, WRIGHT & MOORE, PLLC jh aul J. Mooney (Pro npn Attorneysfor Plaintiff/App4llant EHP DECLARATION OF PAUL J. MOONEY I, Paul J. Mooney, declare as follows: 1) I am an attorney duly licensed to practice in the State of Arizona and admitted pro hac vice for purposes of this matter. I am a partner in the law firm of Mooney, Wright & Moore, PLLC, co-counsel of record for Appellant Elk Hills Power, LLC (“EHP”). I submit this Declaration in support of EHP’s Motion Requesting Judicial Notice, which accompanies this Declaration. I have personal knowledge of the matters set forth herein, except for those matters which are based upon information and belief, in which case I believe those matters to be true. 2) Attached hereto, incorporated herein by reference, and marked as Exhibit 1 is a true and correct copy of the California Energy Commission Decision Application for Certification Elk Hills Power Project, Docket No. 99-AFC-1, (December, 2000), pp. 120-136. I downloaded a copy of this document on July 19, 2012, from the following website: http://www.energy.ca.gov/sitingcases/elkhills/documents/2000-12- 22DECISION.PDF. 3) Attached hereto, incorporated herein by reference, and marked as Exhibit 2 is a true and correct copy of the United States Energy Information Administration — International Energy Outlook 2011 (September 19, 2011). I downloaded a copy of this document on July 9, 2012, from the following website: http://www.cia.gov/forecasts/ieo/electricity.cfm. 4) Attached hereto, incorporated herein by reference, and marked as 1 ) 6) 7) 8) Exhibit 3 is a true and correct copy of the United States Energy Information Administration — Natural Gas 1998: Issues and Trends, Chapter 2, Natural Gas and the Environment. I downloaded a copy of this document on July 19, 2012, from the following website: http://www.eia.gov/oil_gas/natural_gas/analysis_publications/natura 1gas1998issues_and_trends/it98 html. Attached hereto, incorporated herein by reference, and marked as Exhibit 4 is a true and correct copy of the United States Energy Information Administration - Annual Energy Outlook 2012 with Projections to 2035, pp.86-88. I downloaded a copy of this document on July 19, 2012, from the following website: http://www.eia.gov/forecasts/aeo/pdf/03 83(2012).pdf. Attached hereto, incorporated herein by reference, and marked as Exhibit 5 is a true and correct copy of the San Joaquin Valley Air Pollution Control District Authority to Construct, Permit No. S- 3523-1-2 (March 30, 2000). I obtained a copy of this document from the San Joaquin Valley Air Pollution Control District on July 17, 2012, in response to a Public Records Request. Attached hereto, incorporated herein by reference, and marked as Exhibit 6 is a true and correct copy of the San Joaquin Valley Air Pollution Control District Authority to Construct, Permit No. S- 3523-2-2 (March 30, 2000). I obtained a copy of this document from the San Joaquin Valley Air Pollution Control District on July 17, 2012, in response to a Public Records Request. Attached hereto, incorporated herein by reference, and marked as Exhibit 7 is a true and correct copy of the California Energy 2 Commission Order Approving Project Modification (March 19, 2003). I downloaded a copy of this document on July 9, 2012, from the following website: http://www.energy.ca.gov/sitingcases/elkhills/compliance/2003-04- 03ORDER_APP.PDF. 9) Attached hereto, incorporated herein by reference, and marked as Exhibit 8 is a true and correct copy of the California Energy Commission Request to Amend the Elk Hills Power Project (99- AFC-1C) to Allow PM10 ERC Tendering and Commissioning Emissions Increase Staff Analysis (February 28, 2003). I downloaded a copy of this document on July 9, 2012, from the following website: http://www.energy.ca.gov/sitingcases/elkhills/compliance/2003-02- 28PUB_REVIEW_EMISN.PDF. 10)Attached hereto, incorporated herein by reference, and marked as Exhibit 9 is a true and correct copy of the California Energy Commission Proceeding’s Main Page the Elk Hills Power Plant Project. I downloaded a copy of this document on July 19, 2012, from the following website: http://www.energy.ca.gov/sitingcases/elkhills/. 11)I declare under penalty of perjury under the laws of the State of Arizona that the foregoingis true and correct. Executed this 24" day of July, 2012ini)icopa County, Arizona. By:AeVM Paul J. oney Din Attorneyfor Appellant Elk Gills Power, LLC 3 No. $194121 IN THE SUPREME COURT OF CALIFORNIA ELK HILLS POWER, LLC, Plaintiff and Appellant, Vv. CALIFORNIA STATE BOARD OF EQUALIZATION AND COUNTYOF KERN, Defendants and Respondents. After A Decision By The Court of Appeal Fourth Appellate District, Division One, Case No. D056943, San Diego Superior Court Case No. 37-2008-00097074-CU-MC-CTL [PROPOSED] ORDER Appellant Elk Hills Power, LLC (“EHP”) filed a Motion Requesting Judicial Notice. Pursuant to Evidence Code Sections 452 and 459, the Court hereby grants EHP’s Motion and judicially notices the following documents: 1. California Energy Commission Decision Application for Certification Elk Hills Power Project, Docket No. 99-AFC-1, (December, 2000), at pp.120-36. 2. United States Energy Information Administration — International Energy Outlook 2011 (September 19, 2011). 1 3. United States Energy Information Administration — Natural Gas 1998: Issues and Trends, Chapter 2, Natural Gas and the Environment 4. United States Energy Information Administration — Annual Energy Outlook 2012 with Projections to 2035, pp.86-88. 5. San Joaquin Valley Air Pollution Control District Authority to Construct, Permit No. S-3523-1-2 (March 30, 2000). 6. San Joaquin Valley Air Pollution Control District Authority to Construct, Permit No. S-3523-2-2 (March 30, 2000). 7. California Energy Commission Order Approving Project Modification (March 19, 2003). 8. California Energy Commission Request to Amendthe Elk Hills Power Project (99-AFC-1C) to Allow PM10 ERC Tendering and Commissioning Emissions Increase Staff Analysis (February 28, 2003). 9. California Energy Commission Proceeding’s Main Pagefor the Elk Hills PowerPlant Project. IT IS SO ORDERED. Dated: Presiding Justice CERTIFICATE OF SERVICE BY MAIL Elk Hills Power, LLC v. California State Board of Equalization,et al. Court of Appeal No. D056943 Superior Court Case No. 37-2008-00097074-CU-MC-CTL 1. At the time of service I wasat least 18 years of age and nota party to this legal action. 2. My business address is 1201 S. Alma School Rd., Ste. 16000, Mesa, AZ 85210. 3. On July 24, 2012, I enclosed copiesof: Appellant’s Motion Requesting Judicial Notice in envelopes and deposited the sealed envelopes with the U.S. Postal Service, with the postage full prepaid. 4. The envelopes were addressed as follows: Tim Nader, Esq. Deputy Attorney General 110 West A Street, Suite 1100 San Diego, CA 92101 Attorneysfor Defendant and Respondent, California State Board ofEqualization (619) 645-2210 Jerri S. Bradley, Esq. Deputy County Counsel County of Kern 1115 Truxtun Ave., 4" Floor Bakersfield, CA 93301 Attorneyfor Defendant and Respondent, Kern County (661) 868-3819 Kurt R. Wiese Barbara Baird South Coast Air Quality ManagementDistrict 21865 Copley Drive Diamond Bar, CA 91765 Attorneysfor Amicus Curiae South Coast Air Quality Management District Mardiros H. Dakessian Margaret M. Grignon Mike Shaikh Reed Smith LLP 355 South Grand Avenue, Suite 2900 Los Angeles, CA 90071-1514 Attorneysfor Amicus Curiae Institute for Professionals in Taxation John R. Messenger Reed Smith LLP 101 SecondStreet, Suite 1800 San Francisco, CA 94105 Attorneysfor Amicus Curiae Institute for Professionals in Taxation Peter H. Weiner Gordon E.Hart Sean D. Unger Jill E.C. Yung Paul Hastings, LLP 55 Second Street, 24" Floor San Francisco, CA 94105 Attorneysfor Amicus Curiae Independent Energy Producers Association NancyIredaleJeffrey G. VargaPaul Hastings, LLP515 South FlowerStreet, 25" FloorLos Angeles, CA 90071Attorneysfor Amicus Curiae Independent EnergyProducers Association Douglas Mo Prentiss Willson, Jr. Sutherland, Asbill & Brennan LLP 500 Capitol Mall, 19" Floor Sacramento, CA 95814 Attorneysfor Amicus Curiae Broadband Tax Institute Eric S. Tresh Sutherland, Asbill & Brennan LLP 999 Peachtree NE, Suite 2300 Atlanta, Georgia 30309 Attorneysfor Amicus Curiae Broadband Tax Institute Richard N. Wiley 775 E. Blithedale Ave., Ste. 369 Mill Valley, CA 94941 Attorneyfor Amicus Curiae Wirelessco., L.P. Richard R. Patch Jeffrey Sinsheimer Charmaine G. Yu Coblenz, Patch, Duffy & Bass LLP One Ferry Building, Suite 200 San Francisco, CA 94111-4213 Attorneysfor Amicus Curiae California Cable and Telecommunications Association Cris K. O’Neall Cahill, Davis & O’Neall, LLP 550 S. Hope Street, Suite 1650 Los Angeles, California 90071 Attorneysfor Amici Curiae California Taxpayers Association, California Manufacturers & Technology Association and Silicon Valley Leadership Group Wm.Gregory TurnerCouncil On State Taxation1415 L Street, Suite 1200Sacramento, CA 95814Attorneyfor Amicus Curiae Council on StateTaxation Steve Mitra County of Santa Clara 70 West HeddingSt., 9" Floor, East Wing San Jose, CA 95110 Attorneyfor Amici Curiae California State Association ofCounties and California Assessors’ Association Edward G. Summers San Diego Middle Class Taxpayers Association 3737 Camino Del Rio South, Suite 203 San Diego, CA 92108-4007 Attorneyfor Amicus Curiae San Diego Middle Class Taxpayers Association Michael Wall Alex Jackson Natural Resources Defense Council 111 Sutter St., 20" FI. San Francisco, CA 94110 Attorneysfor Amicus Curiae Natural Resources Defense Council John F. Krattli Albert Ramseyer Los Angeles County Assessor 500 West Temple Street, Room 648 Los Angeles, CA 90012-2713 Attorneysfor Amicus Curiae John R. Noguez, Los Angeles County Assessor John Stump Sierra Club 85 Second St., 2™ Floor San Francisco, CA 94105 Attorneyfor Amicus Curiae Sierra Club Ann HancockClimate Protection CampaignP.O. Box 3785Santa Rosa, CA 95402 5. I am a resident of or employed in the county where the mailing occurred. The document was mailed from Mesa, Arizona. I declare under penalty of perjury that the foregoingis true and correct. Date: July 24, 2012 Kim Simonis ony, MNCMLa_ Printed Name Signature COMMISSION DECISION APPLICATION FOR CERTIFICATION ELK HILLS POWER PROJECT Docket No. 99-AFC-1 DECEMBER 2000 CALIFORNIA ENERGY COMMISSION Gray Davis, Governor P 800-00-013 CALIFORNIA ENERGY COMMISSION Committee Hearing Office WiillidteeBe, Chairman Stanley Valkosky, Chief Hearing Offi Robert A. Laurie, Commissioner Major Williams, Jr., Hearing Michal C. Moore, Commissioner RoberPernel Commissioner Arthur H. RosenfeftdmmbbsDoner STATE OF CALIFORNIA Energy Resources Conservation and Development Commission In the Matterof: Docket No. 99-AFC-1) ) Application for Certification ) COMMISSION ADOPTION ORDER for the Elk Hills Cogeneration ) PowerProject ) _) This Commission Order adopts the Commission Decision on the Elk Hills Cogeneration PowerProject. It incorporates the Presiding Member s Proposed Decision (PMPD)in the above-captioned matter and the Committee Errata (__Date__) thereto. The Commission Decision is based upon the evidentiary record of these proceedings (Docket No. 99-AFC-1) and considers the comments received at the ----------------------- business meeting. The text of the attached Commission Decision contains a summary of the proceedings, the evidence presented, and the rationale for the findings reached and Conditions imposed. This ORDER adopts by reference the text, Conditions of Certification, Compliance Verifications, and Appendices contained in the Commission Decision. It also adopts specific requirements contained in the PMPD which ensure that the proposed facility will be designed, sited, and operated in a mannerto protect environmental quality, to assure public health and safety, and to operate in a safe and reliable manner. FINDINGS The Commission hereby adopts the following findings in addition to those contained in the accompanying text: 1. The Elk Hills Power Project is a merchant power plant whosecapital costs will not be borne by the State s electricity ratepayers. 2. The Conditions of Certification contained in the accompanying text, if implemented by the Applicant, ensure that the project will be designed, sited, and operated in conformity with applicable local, regional, state, and federal laws, ordinances, regulations, and standards, including applicable public health and safety standards, and air and water quality standards. Implementation of the Conditions of Certification contained in the accompanying text will ensure protection of environmental quality and assure reasonably safe and reliable operation of the facility. The Conditions of Certification also assure that the project will neither result in, nor contribute substantially to, any significant direct, indirect, or cumulative adverse environmental impacts. Existing governmental land use restrictions are sufficient to adequately control population density in the area surrounding the facility and may be reasonably expected to ensure public health and safety. The evidence of record establishes that no feasible alternatives to the project, as described during these proceedings, exist. The evidence of the record does not establish the existence of any environmentally superioralternative site. The PMPDcontains measures to ensure that the planned, temporary, or unexpected closure of the project will occur in conformance with applicable laws, ordinances, regulations, and standards. The proceedingsleading to this Decision have been conducted in conformity with the applicable provisions of Commission regulations governing the consideration of an Application for Certification and thereby meet the requirements of Public Resources Code, sections 21000 et. seq., and 25500 et. seq.. ORDER Therefore, the Commission ORDERSthefollowing: 1. The Application for Certification of the Elk Hills Power Project as described in this Decision is hereby approved and a certificate to construct and operate the project is hereby granted. The approval of the Application for Certification is subject to the timely performance of the Conditions of Certification and Compliance Verifications enumerated in the accompanying text and Appendices. The Conditions and Compliance Verifications are integrated with this Decision and are not severable therefrom. While Applicant may delegate the performance of a Condition or Verification, the duty to ensure adequate performance of a Condition or Verification may not be delegated. 3. For purposes of reconsideration pursuant to Public Resources Code section 25530, this Decision is deemed adopted whenfiled with the Commission s Docket Unit. 4. For purposes ofjudicial review pursuant to Public Resources Code section 25531, this Decisionis final thirty (30) days afterits filing in the absenceofthefiling of a petition for reconsideration or, if a petition for reconsideration is filed within thirty (80) days, upon the adoption andfiling of an Order upon reconsideration with the Commission s Docket Unit. 5. The Commission hereby adopts the Conditions of Certification, Compliance Verifications, and associated dispute resolution procedures as part of this Decision in order to implement the compliance monitoring program required by Public Resources Code section 25532. All conditions in this Decision take effect immediately upon adoption and apply to all construction and site preparation activities including, but not limited to, ground disturbance,site preparation, and permanent structure construction. 6. The Executive Director of the Commission shall transmit a copy of this Decision and appropriate accompanying documents as provided by Public Resources Code section 25537 and California Code of Regulations, title 20, section 1768. Dated: ENERGY RESOURCES CONSERVATION AND DEVELOPMENT COMMISSION WILLIAM J. KEESE ROBERTA. LAURIE Chairman Commissioner MICHAL C. MOORE ROBERT PERNELL Commissioner Commissioner ARTHUR H. ROSENFELD Commissioner TABLE OF CONTENTS PAGE INTRODUCTION iveecccccevccccecccccencsvcnccecccececeesesssnsscsevsvnvessaceeseeeseeerterverersnees1 A. SUMMARY ec eccccaceccccccccccecceencucevccnaccedcuccccccccccceccetteceecenaacuueesess1 B. SITE CERTIFICATION PROCESS livceecccceccccccecccceccesscecesecssseeeuns7 Cc. PROCEDURAL HISTORY ciccscccsscscccceccecceccsetescusevensvccesceeceecees10 IPROJECT PURPOSE AND DESCRIPTION Liieecssccsccececccececceceveceacscces13 SUMMARY AND DISCUSSION OF THE EVIDENCE ....ceccscsecuesseceueceecessenserserenenees 13 FINDINGS AND CONCLUSIONS......cccssecescensveusesrsucusenevsneeeeeescseceeeeacesens 17 TINEED CONFORMANCE oo. icacccccccccceeccccececrccevccvecscrcnesecssceteeteveceseces 18 TIIPROJECT ALTERNATIVES —...ieescccccccccccccevccccccevvccctevecnccaceseceeterseeeees20 SUMMARY AND DISCUSSION OF THE EVIDENCE.eccscsencacececscscueuneavacseercenees 20 FINDINGS AND CONCLUSIONS........ccsssccecceccceecescusercursasecaueteusanseaseunens 23 TV. COMPLIANCE AND CLOSURE ——ooieceeecececccsscevevccccaccvcceccsetececeseeenencnes25 SUMMARYAND DISCUSSION OF THE EVIDENCE. .occcccesescerscaeecaceoversursessenarseseues 25 FINDINGS AND CONCLUSIONS......cccccescosccescesseescuecauecorsenereansenstensenanas 26 COMPLIANCE PLAN. ...cceccescsssccseceseossnceucascasacauecueeseusaueeeustansneuetanenenees 27 V. ENGINEERING ASSESSMENT oie i ecccccccccevevcccceevccccvenveccvecccescceeeceeecs41 A. FACILITY DESIGN .oeleec lec l ccc ccccccceccceecccecevvvereenennevacecccseceseeeeess41 SUMMARYAND DISCUSSION OF THE EVIDENCE. .ccececceeecsccsacenernsescnssensessraseccass 41 FINDINGS AND CONCLUSIONS .......ccccsceeccerccencaeccecscuseusversenssenantensensees 45 CONDITIONS OF CERTIFICATION ....ccccsccavcevccesececuscuasececeuseessuenseonseneees 46 B POWER PLANT RELIABILITY —o..eeiccescccccscccececceccccccescececesensnces68 SUMMARYAND DISCUSSION OF THE EVIDENCE, ...cscccescceccsueesscnsecsacsanecsssensenens 68 FINDINGS AND CONCLUSIONS.....cccccceceeececcsecuccuceueceecauareuseeannenseneren 71 on POWER PLANT EFFICIENCY ooeeiciccccccceceecucvccececevececececccseetense72 SUMMARYAND DISCUSSION OF THE EVIDENCE.....cccccesceeseccoeecrecsreenecossreceseees 72 FINDINGS AND CONCLUSIONS.....c.ccseeveecceccessccnccesenceennseuneerssonerenceasens 74 D. TRANSMISSION SYSTEM ENGINEERING oiivveccceccccececeesecseces76 SUMMARY AND DISCUSSION OF THE EVIDENCE... .ceccseceecceeceeseceneenausseenseenssceres 77 FINDINGS AND CONCLUSIONS............ccecesccnsescececcseuscuseeneransneussaasauerss 81 CONDITIONS OF CERTIFICATION ...cccccceeccesceceseceuccesecacsveccensenentescnessenss 82 E. TRANSMISSION LINE SAFETY AND NUISANCE ——oceeeececcccscnseee85 SUMMARYAND DISCUSSION OF THE EVIDENCE... .cccsecsceccesseecesececsuerensesneccears 85 FINDINGS AND CONCLUSIONS......cccccecesceeccecescuccseneceacseecseersnstesnensenss 88 CONDITIONS OF CERTIFICATION .ccccccccssscsscceaseccucsesssecssesennucesstensensenens 88 TABLE OF CONTENTS, (Cont.) PAGE VI. PUBLIC HEALTH AND SAFETY ..cccccccccccceccceeeeeeeeeesteecueeeneeeeeceeeeceees92 BIR QUALITY loiceccccccccecccc cere eee eceececeeeeesceeeeeseeeseeeeseesaneeeeeranes92 SUMMARYOF THE EVIDENCE ....sssesccsseccecsscssceseccessesteccaseeecuacecsecaaeetensenenenses 94 FINDINGS AND CONCLUSIONS......0ccceseeseneeseeneeteaeneneesceneuseensneeseensnees 120 CONDITIONS OF CERTIFICATION ...ccccecccsssecesesecsnnenstecseeanessenseeesentenes 122 PUBLIC HEALTH ooececcccccceeeseceeeeeee cect eeeeeeeeeeeeeneeeeesseeeeteeneeeees137 SUMMARY AND DISCUSSION OF THE EVIDENCE... .ccscssseeceserecsesensseeseeceeneneeeaes 137 FINDINGS AND CONCLUSIONS.......:ccsssecesscesseecteneceeesessenseseenseenesenaees 142 HAZARDOUS MATERIALS MANAGEMENT o..eeeeceeeseceeeeeeeeees144 SUMMARYAND DISCUSSION OF THE EVIDENCE.......:ssccccesecececscesecnsseeeneesees 144 FINDINGS AND CONCLUSIONS.......:0ccsecececcecessessecaseraeseateceescentonesane 147 CONDITIONS OF CERTIFICATION.......0s:ccceencccsenecnccatecescarecnecaseeseeaser 148 WORKER SAFETY AND FIRE PROTECTION ciccccccssececeeseeeess152 SUMMARY OF THE EVIDENCE...ssssesscssccecenencerecstencesstecacaereuaeanestessecarsceseceees 152 FINDINGS AND CONCLUSIONS.......c.ccsccconensssesetesserecnsenetsanecseesseeenes 161 CONDITIONS OF CERTIFICATION.......22c:ccereccsnsccenceneoataneeeenecsserseseaeet 162 VII. ENVIRONMENTAL ASSESSMENT isscccevaceccccceececeecseeeesceseeeeegeeesans166 BIOLOGICAL RESOURCES oiececcecececeececcceceeeeetecesceenneeseseeeres166 SUMMARYAND DISCUSSION OF THE EVIDENCE. ..sccssecescsscnsseecssessesnessentesaeneas 166 FINDINGS AND CONCLUSION .......cccssesccsseceecescceccuserenerseusetsceasesnentenas 178 CONDITIONS OF CERTIFICATION..........cccececcceseccecusescascesrscesscuescnersees 179 CULTURAL RESOURCES cecccccccesscncectceeeeeteseceessseteseeessseeeseees185 SUMMARY AND DISCUSSION OF THE EVIDENCE... ..sssscceceneeesercuceescseesucareseeaee 186 FINDINGS AND CONCLUSIONS......cccsececnsecnsscuvsnenensecustecseeusensesssessecss 195 CONDITIONS OF CERTIFICATION .....scccssstcoectsassenseeereanceensentsntenasasenens 195 GEOLOGY AND PALEONTOLOGY ——eeeccccesessvetesceetesteneveeesseees212 SUMMARYAND DISCUSSION OF THE EVIDENCE.....cccececseccsseeeaneersusnsceneeeenesess 212 FINDINGS AND CONCLUSIONS....sccceeccsssetensceceensenseecuseeuseneensessrenseeass 214 CONDITIONS OF CERTIFICATION ...-2sccesesccecesesesceneecseeneaneeeceeenseseeraeens 215 SOIL AND WATER RESOURCES —cececcsesseceesececcseecuseeseeteeeecess222 SUMMARYAND DISCUSSION OF THE EVIDENCE... .scsescesersessccarecnsaseeusseseusuenss 222 FINDINGS AND CONCLUSIONS......ccsccseestenectscseeretensesssaeteensateensneesers 256 CONDITIONS OF CERTIFICATION ....cscsceesecccctssetecesecenteceetentaasscusensceees 257 WASTE MANAGEMENT —cvecccecccsevnvcceveeecesetecsecseevssensescesneseuaes259 SUMMARYAND DISCUSSION OF THE EVIDENCE.....ecccsssscserencesecssersesrecueneeneas 259 FINDINGS AND CONCLUSIONS......csscssseereneeeesssseesscantecenteteeneesesseneeees 267 CONDITIONS OF CERTIFICATION.....:ccssecucecsecsseceuseuseeecenrensesrenesassaeas 268 TABLE OF CONTENTS, (Cont.) PAGE VIIILOCAL IMPACT ASSESSMENT =o. eee cece ccc ccececeecseeesterseuseseccseeseuenes270 A, LAND USE ciccscccccecccceecrvcrccesecncveneccuseetcceeeceseceesuugeuceaareesacees270 SUMMARY AND DISCUSSION OF THE EVIDENCE... ..cccsescsscecsssseusnsseusnuseeneecuuaes 270 FINDINGS AND CONCLUSIONS....cccccecceceersenesesesonsccteussessersereuvauseuseuts 276 CONDITIONS OF CERTIFICATION .....scccessccoussssesscccusnenseueeecersencecsarares 276 B. NOISE ciicccecccscccccccevccccesceeeceseeeeeeveteesueeccsseeeeeeeeesceverensueusees278 SUMMARYAND DISCUSSION OF THE EVIDENCE... .0.sescescessesneseneseesaeneeaeresaees 278 FINDINGS AND CONCLUSIONS.....cccsessecseseuscevsessusnvsnesnevaavaveeeaueaesanes 282 CONDITIONS OF CERTIFICATION ..sseeccscccccsccccsspevevuvessnuseusssesuseeseussesss 283 on SOCTOECONOMICS eeeeeccccccccccccvcvcvcccseeessssssesscessesceeceeneuveees287 SUMMARY AND DISCUSSION OF THE EVIDENCE.......sscssesneecsesnecseneeerenensenensees 287 FINDINGS AND CONCLUSIONS........:ccccceeceeecsccnscesensenerecceuesrarsuserersass 291 CONDITIONS OF CERTIFICATION ....scscesscscssvsussscnsuececuscersesenerausuneusenes 293 D. TRAFFIC AND TRANSPORTATION —ocicececccccccccccececceuvecesvecseees294 SUMMARY AND DISCUSSION OF THE EVIDENCE... cccssssesssesscneeaessaseauseceeeeeanens 294 FINDINGS AND CONCLUSIONS.....csssscsseuseseecsesecucencesessnssnccusseueuvanssens 304 CONDITIONS OF CERTIFICATION....:-scececcoceecerevcncursouseneconcanersursnereasas 305 BE. VISUAL RESOURCES Livecesccccaccccceeccececceceececesecsveceuseseeeseeeees309 SUMMARY AND DISCUSSION OF THE EVIDENCE... cccscssurcavessuuseuecuntuctacsucensueens 309 FINDINGS AND CONCLUSIONS.......ccccscsusesnressunceusssecsecsrsucuesessnseseenes 318 CONDITIONS OF CERTIFICATION .......cceccoscccnsuneussuencuecsroueasnenevansenenans 319 APPENDIX A: LAws 1 CRDINANCES 1 REGULATIONS AND STANDARDS APPENDIX B: EXHIBIT LIST APPENDIX C: PROOF OF SERVICE LIST APPENDIX D: GLOSSARY OF TERMS AND A CRONYMS APPENDIX E: STATE WATER RESOURCES C ONTROL BOARD — WATER Q UALITY ContRoL Ponicy (SWRCB 75-58) APPENDIX F: WATER C opE (1-4) Staff also points out that Midway-Sunset s AFC was not deemed data adequate until March 8, 2000, when many evidentiary hearings in Elk Hills had already concluded. (Staff Reply Brief on PhaseIII issues, p. 2.) Staff has requested that Midway-Sunset submit a cumulative analysis that includes Midway-Sunset, La Paloma, Sunrise, and Elk Hills. (Ex. 19D, Part Ill, p. 24.) We are thus persuaded to defer to Staffs original judgment not to request the analysis from Elk Hills in the first instance. We therefore reject CURE s contention that the cumulative impact analysis is flawed. The existing cumulative analysis considersall projects within a sufficient distance for impact assessment purposes. Similarly, CURE s contention that meteorological data relied on by Applicant and Staff was flawed is without merit. Applicant points out that the reliance on old data was corrected. (Applicant s Reply Brief on PhaseIll issues, p. 1.) The new data confirmed the previous finding that the project would not cause anyair quality standard violations and would comply with all applicable air quality LORS. (Ibid.) FINDINGS AND CONCLUSIONS Based upon the weight of the evidence of record, we find and conclude as follows: 1. The Elk Hills Power Project is located in the San Joaquin Valley Air Basin, within the jurisdiction of the San Joaquin Valley Unified Air Pollution Control District (SJVAPCD). 2. The project area is in unclassified/attainment status for applicable federal CO and NO»air quality standards, in attainment for the state s CO, NOz, SOz2, SOz, and lead standards, and in attainment for federal SO2 standard. It is designated as non-attainment for both state and federal ozone and PM, standards. 3. Construction and operation of the Elk Hills Power Project will result in emission ofcriteria air pollutants. 120 10. 11. 12. 13. 14. Operation of the project will result in emissions of NOx, SOQ2z, PMi1o, and VOC, which would, if not mitigated, contribute to violations of air quality standards. The Elk Hills Power Project will use Best Available Control Technology (BACT) as determined by the San Joaquin Valley Unified Air Pollution Control District to control emissions of NOx, CO, SO2z, PMio, and VOC. To minimize NO,, CO and VOC emissions during the combustion process, the CTG will be equipped with the latest dry low-NO, combustor design; the HRSG will employ SCR to reduce NOx emissions, and an oxidizing catalyst to reduce CO and VOC emissions. SJVAPCDreleased its Final Determination of Compliance (FDOC)for the Elk Hills project on March 30, 2000. The conditions contained in the FDOCare incorporated into the Conditions of Certification below. A representative of the SJVUAPCDhascertified that complete emissions offsets for the project have beenidentified and obtained by the Applicant. BACTfor the project s NO, emissions is 2.5 ppm @ 15% O2 averaged over one hour, to obtain which Applicant will install DLN-SCR rather than SCONOx. SCONOxfor the proposed project is approximately three times the cost per turbine as compared to SCR-oxidation catalyst. Applicant has obtained, by direct transfers or legally enforceable option contracts, Emission Reduction Credits (ERCs) sufficient to fully offset the project s increased emissions of NOx, SOz, VOC, and PMio, due to project operation, on an annual and a daily basis. To offset PMio emissions during construction, Applicant shall install oxidizing sootfilters on large construction equipment underthe conditions set forth below in Condition AQ-C2. The Elk Hills Power Project, with the implementation of the measures contained in the Conditions of Certification below,will not, either alone or in combination with other identified projects in the area, cause or contribute to any new or existing violations of applicable ambient air quality standards. With the implementation of the Conditions of Certification specified below, the Elk Hills PowerProject will be constructed and operated in compliance with all applicable laws, ordinances, regulations, and standardsidentified in the pertinent portion of Appendix A of this Decision. 121 We therefore conclude that with the implementation of the Conditions of Certification below, the Elk Hills Power Project will not create any significant direct, indirect, or cumulative adverse air quality impacts; and will conform withall applicable LORSrelating to air quality as set forth in the pertinent portions of Appendix A of this Decision. CONDITIONS OF CERTIFICATION AQ-C1 Prior to breaking ground at the project site, the project owner shall prepare a Construction Fugitive Dust Mitigation Plan (CFDMP), which specifically: e identifies fugitive dust mitigation measures that will be employed for the construction of the Elk Hills Power Project and related facilities; and e identifies measuresto limit fugitive dust emissions from construction of the project site and linear facilities. Measures that should be addressed include the following: the identification of the employee parking area(s) and surface of the parking area(s); the frequency of watering of unpaved roads and disturbed areas; the application of chemical dust suppressants; the use of gravelin high traffic areas; the use of paved access aprons; the use of posted speedlimit signs; the use of wheel washing areas prior to large trucks leaving the project site; and, e the methods that will be used to clean tracked-out mud and dirt from the project site onto public roads. Verification: At least sixty (60) days prior to breaking groundat the projectsite, the project owner shall provide the CPM with a copy of the Construction Fugitive Dust Mitigation Plan for approval. AQ-C2 The project ownershall do all of the following: 1. Ensure that all heavy earthmoving equipment has been properly maintained, including, but notlimited to: e bulldozers, backhoes, compactors, cranes dumptrucks loaders, motor graders 122 e trenchers, and e other heavy duty construction related trucks. 2. Engines shall be: (a) tuned to the engine manufacturer s specifications; (b) provided with ignition retard equipment wherefeasible, to provide additional NOx emission reductions during construction. Feasibility shall be determined by an independentCalifornia Licensed Mechanical Engineerunderthe identical circumstances presented below. 3. Install oxidizing sootfilters on all suitable construction equipment used either on the power plant construction site or on associated linear construction sites. Suitability is to be determined by an independent California Licensed Mechanical Engineer who will stamp and submit for approval an initial and all subsequent Suitability Reports as necessary containing at a minimum the following: 4. File an Initial Suitability Report. The initial suitability report shall be submitted to the CPM for approval sixty (60) days prior to breaking ground onthe project site. It shall contain: e A list of all fuel burning, construction related equipment used; e a determination of the suitability of each piece of equipment to work appropriately with an oxidizing sootfilter; e if a piece of equipment is determined to be suitable, a statement by the independent California Licensed Mechanical Engineer that the oxidizing sootfilter has been installed and is functioning properly; and e if a piece of equipment is determined to be unsuitable, an explanation by the independent California Licensed Mechanical Engineeras to the cause of this determination. 5. File a Subsequent Suitability Reports as follows: e If a piece of construction related equipment is subsequently determined to be unsuitable for an oxidizing sootfilter after such installation has occurred, the filter may be removed immediately. e In that event, notification must be sent to the CPM for approval containing an explanation for the changein suitability within ten (10) days. 123 e Changesin suitability are restricted to three explanations, which mustbe identified in any subsequent suitability report, as shown below: e The oxidizing sootfilter is reducing normal availability of the construction equipment due to increased downtime, and/or poweroutput due to increased backpressure by 20% or more. e The oxidizing sootfilter is causing or reasonably expected to causesignificant damageto the construction equipment engine. e The oxidizing sootfilter is causing or reasonably expected to causea significant risk to nearby workersor the public. Verification: The project owner shall submit to the CPM, via the Monthly Compliance Report, documentation, which demonstrates that the contractor s heavy earthmoving equipment is properly maintained and the engines are tuned to the manufacturer s specifications. The project ownershall maintain all records on the site for six monthsfollowing the start of commercial operation. The project ownerwill submit to the CPM for approval, the initial suitability report stamped by an independentCalifornia Licensed Mechanical Engineer, sixty (60) days prior to breaking ground on the project site. The project ownerwill submit to the CPM for approval, subsequentsuitability reports as required, stamped by an independent California Licensed Mechanical Engineer no later than ten (10) working day following a changein the suitability status of any construction equipment. Conditions of Certification AQ-1 through AQ-44 apply to the following equipment: SJVUAPCDPermit No. S-3523-1-0- GE FRAME 7 MODEL PG7241FA NATURAL GAS FIRED COMBINED CYCLE GAS TURBINE ENGINE/ELECTRICAL GENERATOR #1 WITH DRY LOW NOX COMBUSTORS, SELECTIVE CATALYTIC REDUCTION, OXIDIATION CATALYST, AND STEAM TURBINE S-3532-2 (503 MW TOTAL NOMINAL RATING), SJVUAPCDPermit No. S-3523-2-0- GE FRAME 7 MODEL PG7241FA NATURAL GAS FIRED COMBINED CYCLE GAS’ TURBINE ENGINE/ELECTRICAL GENERATOR #1 WITH DRY LOW NOX COMBUSTORS, SELECTIVE CATALYTIC REDUCTION, OXIDIATION CATALYST, AND STEAM TURBINE S-3532-2 (503 MW TOTAL NOMINAL RATING), AQ-1 No air contaminant shall be released into the atmosphere, which causes a public nuisance.[District Rule 4102] Verification: The project owner shall make the site available for inspection by representatives of the District, California Air Resources Board (CARB) and the Commission. 124 AQ-2 The project owner shall submit selective catalytic reduction, oxidation catalyst, and continuous emission monitor design details to the District at least 30 daysprior to the construction of permanent foundations.[District Rule 2201] Verification: The project owner shall provide copies of the drawings of the catalyst system chosen and the continuous emission monitor design detail to the CPM and the District at least thirty (30) days prior to the construction of permanent foundations. AQ-3 Combustion turbine generator (CTG) and electric generator lube oil vents shall be equipped with mist eliminators to maintain visible emissions from lubeoil vents shall no greater than 5% opacity, except for three minutes in any hour. [District Rule 2201] Verification: The project owner shall make the site available for inspection by representatives of the District, CARB and the Commission. AQ-4 The CTG shall be equipped with continuously recording fuel gas flowmeter. [District Rule 2201] Verification: The information above shall be included in the quarterly reports of Condition AQ-35. AQ-5 CTG exhaust shall be equipped with continuously recording emissions monitor for NOx (before and after the SCR unit), CO, and O2 dedicated to this unit. Continuous emission monitors shall meet the requirements of 40 CFR parts 60 and 75 and shall be capable of monitoring emissions during startups and shutdownsas well as normaloperating conditions. If relative accuracy of CEM(s) cannot be certified during startup conditions, CEM results during startup and shutdown events shall be replaced with startup emission rates obtained during source testing to determine compliance with emission limits in Conditions AQ-13, 16, 17 and 18. [District Rule 2201] Verification: The project owner shall make the site available for inspection by representatives of the District, CARB and the Commission. AQ-6 Ammonia injection grid shall be equipped with operational ammonia flowmeterandinjection pressure indicator. [District Rule 2201] Verification: The project owner shall make the site available for inspection by representatives of the District, CARB and the Commission. AQ-7 Exhaust stack shall be equipped with permanent provisions to allow collection of stack gas samples consistent with EPA test methods.[District Rule 1081] Verification: The project owner shall make the site available for inspection by representatives of the District, CARB and the Commission. 125 AQ-8 Heat recovery steam generator design shall provide space for additional selective catalytic reduction catalyst and oxidizing catalyst if required to meet NOx and CO emissionlimits. [District Rule 2201] Verification: Please refer to Condition AQ-2. AQ-9 The project owner shall monitor and record exhaust gas temperature at the selective catalytic reduction and oxidation catalyst inlets. [District Rule 2201] Verification: The project owner shall record the exhaust gas and selective catalytic reduction temperaturesin the daily logs. AQ-10 CTG shall be fired on natural gas, consisting primarily of methane and ethane, with a sulfur content no greater than 0.75 grains of sulfur compounds (as S) per 100 dry-scf of natural gas. [District Rule 2201] Verification: The project owner shall provide records of compliance as part of the quarterly reports of Condition AQ-35. AQ-11 Startup is defined as the period beginning with initial turbine firing until the unit meets the lb/hr and ppmv emissionlimits in Condition AQ-15. Shutdown is defined as the period beginning with initiation of turbine shutdown sequence and ending with cessation of firing of the gas turbine engine. Startup and shutdown duration shall not exceed the following: e two hoursfor a regular startup, e four hours for an extendedstartup, e and one hourfor a shutdown, per occurrence. [District Rule 2201 and 4001] Verification: The project ownershall provide records of compliance as part of the quarterly reports of Condition AQ-35. AQ-12 Ammonia shall be injected when the SCR catalyst temperature exceeds 500 degrees F. The project owner shall monitor and record catalyst temperature during periods of startup. [District Rules 2201] Verification: The project owner shall provide records of compliance as part of the quarterly reports of Condition AQ-35. AQ-13 During startup or shutdown of any gas turbine engine(s), combined emissions from both gas turbine engines (s-3523-1-0 and —2-0) heat recovery steam generator exhausts shall not exceed any of the following limits in any one hour: e NOx(asNO2) 76 Ibs e CO 38 Ibs 126 Verification: The project owner shall provide records of compliance as part of the quarterly reports of Condition AQ-35. AQ-14 By two hoursafterinitial turbine firing, CTG exhaust emissions shall not exceed any of the following: NO, (as NOz) 12.2 ppmv @ 15% O* and CO 25 ppmv @ 15% O°. [District Rule 4703] Verification: The project ownershall provide records of compliance as part of the quarterly reports of Condition AQ-35. AQ-15 Emission rates from each CTG, except during startup or shutdown, shall not exceed anyof the following emissionlimits: PMio 18 Ibs/hr SO2 3.6 Ibs/hr NOz 15.8 lbs/hr and 2.5 ppmvd @ 15% O° averaged over1-hr VOC 4.0 Ibs/hr and 2.0 ppmvd @ 15% O* averaged over3-hr CO 12.5 Ibs/hr and 4 ppmvd @ 15% O° averaged over3-hr Ammonia 10 ppmvd @ 15% O? averaged over 24-hr [District Rule 2201, 4001 and 4703] Verification: The project owner shall provide records of compliance as part of the quarterly reports of Condition AQ-35. AQ-16 Emission rates from each CTG, on days whena startup or shutdown occurs, shall not exceed anyof the following: PMio 432 \bs/day SO2 86.4 lbs/day NOz 418.5 lbs/day VOC 96.0 Ibs/day CO 326.7 Ibs/day [District Rule 2201] Verification: The project owner shall provide records of compliance as part of the quarterly reports of Condition AQ-35. AQ-17 Emission rates from both CTGs (S-3523-1 and -2), on days when a startup or shutdown occursfor either or both turbines, shall not exceed anyof the following: PMio 864.0 Ib/day SOz2 172.8 Ib/day NOz 817.8 Ib/day VOC 192.0 Ib/day CO 640.4 Ib/day. [District Rule 2201] The project owner shall provide records of compliance as part of the quarterly reports of Condition AQ-35. AQ-18 Annual emissions from both CTGs calculated on a twelve (12) consecutive month rolling basis shall not exceed any of the following: PM10 - 127 315,360 Ib/year, SO, (as SOz2) - 57,468 Ib/year, NO, (as NO2) - 285,042 Ib/year, VOC- 64,478 Ib/year, and CO - 223,040 Ib/year. [District Rule 2201] Verification: The project owner shall provide records of compliance as part of the quarterly reports of Condition AQ-35. AQ-19 Each one-hour period in a one-hour rolling average will commence on the hour. Each one-hourperiod in a three-hour rolling average will commence on the hour. The three-hour average will be compiled from the three most recent one-hour periods. Each one-hour period in a twenty-four-hour average for ammoniaslip will commence on the hour. The twenty-four-hour average will be calculated starting and ending at twelve-midnight. [District Rule 2201] Verification: The project owner shall provide records of compliance as part of the quarterly reports of Condition AQ-35. AQ-20 Daily emissions will be compiled for a twenty-four hour period starting and ending at twelve-midnight. Each calendar month in twelve-consecutive- month rolling emissions will commence at the beginning of the first day of the month. The twelve-consecutive-month rolling emissions total to determine compliance with annual emissions will be compiled from the twelve (12) most recent calendar months. [District Rule 2201] Verification: The project ownershall provide records of compliance as part of the quarterly reports of Condition AQ-35. AQ-21 Prior to or upon startup of S-3523-1-0, -2-0, & 3-0, emission offsets shall be surrendered for all calendar quarters in the following amounts, at the offset ratio specified in Rule 2201 (6/15/95 version) Table 1, PMio - Q1: 78,596 Ib, Q2: 79,470 lb, Q3: 80,343 Ib, and Q4: 80,343 Ib; SOx (as SOz) - Q1: 14,170 Ib, Q2: 14,328 Ib , Q3: 14,485 Ib, and Q4: 14,485 lb; NOx (as NOz) - Q1: 65,353 Ib, Q2: 66,079 Ib, Q3: 66,805 Ib, and Q4: 66,805 ib; and VOC - Q1: 10,967 Ib, Q2: 11,089 Ib, Q3: 11,211 Ib, and Q4: 11,211 Ib. [District Rule 2201] Verification: The owner/operator shall submit copies of ERC surrendered to the SJVUAPCDin the totals shown to the CPM prior to or uponstartup of the CTGs or cooling tower. AQ-22 NO, and VOC emission reductions that occurred from April through November may be used to offset increases in NO, and VOC respectively during any period of the year. [District Rule 2201] Verification: The project owner shall provide records of compliance as part of the quarterly reports of Condition AQ-21. AQ-23 NO, ERCs may be used to offset PMi9 emission increases at a ratio of 2.42 Ib NOx: 1 Ib PM10 for reductions occurring within fifteen (15) miles of this 128 facility, and at 2.72 Ib NOx: 1 Ib PM1o for reductions occurring greater than fifteen (15) miles from this facility. [District Rule 2201] Verification: The project owner shall provide records of the ERCs as part of Condition AQ-21. AQ-24 At least thirty (30) days prior to the construction of permanent foundations, the project ownershall provide the District with: e written documentation that all necessary offsets have been acquired or that e binding contracts to secure such offsets have been entered into. [District Rule 2201] Verification: The project owner shall provide ERC records as part of Condition AQ-21. AQ-25 Compliance with ammoniaslip limit shall be demonstrated by using the following calculation procedure: ammonia slip ppmv @ 15% O2 = ((a- (bxc/1,000,000)) x 1,000,000 / b) x d, where a = ammonia injection rate(Ib/hr)/17(Ib/Ib. mol), b = dry exhaust gas flow rate (Ib/hr)/(29(Ib/Ib. mol), c = change in measured NO, concentration ppmv at 15% O2 across catalyst, and d = correction factor. The correction factor shall be derived annually during compliance testing by comparing the measured and calculated ammoniaslip. Alternatively, the project owner may utilize a continuous in-stack ammonia monitor, acceptable to the Disirict, to monitor compliance. At least 60 days prior to using a NH3 CEM, the project owner must submit a monitoring plan for District review and approval[District Rule 4102] Verification: The project owner shall provide records of compliance as part of _ the quarterly reports of Condition AQ-35. AQ-26 Compliance with the short term emission limits (lb/hr and ppmv @ 15% O2) shall be demonstrated within 60 daysofinitial operation of each gas turbine engine and annually thereafter. On site sampling of exhaust gassesat full load conditions by a qualified independent sourcetest firm, in full view of District witnesses, as follows: NOx: ppmvd @ 15% O2 andIb/hr; CO: ppmvd @ 15% Oz andIb/hr; VOC: ppmvd @ 15% Oz and lb/hr; PM4o: lb/hr; and ammonia: ppmvd @ 15% Oz. Sample collection to demonstrate compliance with ammonia emission limit shall be based on three consecutive test runs of thirty minutes each. [District Rule 1081] 129 Verification: The project owner shall provide records of compliance as part of Condition AQ-29. AQ-27 Compliance with the startup NO,, CO, and VOC mass emission limits shall be demonstrated for one of the CTGs (S-3523-1, or -2) upon initial operation and at least every seven years thereafter by District witnessed in situ sampling of exhaust gases by a qualified independent sourcetest firm. [District Rule 1081] Verification: The project owner shall provide records of compliance as part of Condition AQ-29. AQ-28 Compliance with natural gas sulfur content limit shall be demonstrated within sixty (60) days of operation of each gas turbine engine and periodically as required by 40 CFR 60 Subpart GG and 40 CFR75.[District Rules 1081, 2540, and 4001] Verification: The project ownershall provide records of compliance as part of the quarterly reports of Condition AQ-35. AQ-29 The District must be notified thirty (30) days prior to any compliance source test, and a source test plan must be submitted for approvalfifteen (15) days prior to testing. Official test results and field data collected by sourcetests required by conditions on this permit shall be submitted to the District within sixty (60) days of testing. [District Rule 1081] Verification: The project owner shall notify the CPM and the District thirty (30) days prior to any compliance source test. The project owner shall provide a sourcetest plan to the CPM and District for the CPM andDistrict approvalfifteen (15) days prior to testing. The results and field data collected by the source tests shall be submitted to the CPM and theDistrict within 60 days of testing. AQ-30 Sourcetest plansforinitial and seven-year sourcetests shall include: e amethod for measuring the VOC/CO surrogate relationship that will be used to demonstrate compliance with VOC lb/hr, Ib/day; and e lb/twelve month rolling emissionlimits. [District Rule 2201] Verification: The project owner shall provide a source test plan to the CPM and District for the CPM and District approvalfifteen (15) days prior to testing. The results and field data collected by the source tests shall be submitted to the CPM and the District within sixty (60) days of testing. AQ-31 The following test methods shall be used: e PMio: EPA method 5 (front half and back half), e NO,: EPA Method 7E or 20, e CO: EPA method 10 or 10B, O02: EPA Method 3, 3A, or 20, 130 e VOC: EPA method 18 or 25, ® ammonia: BAAQMDST-1B8, and e fuel gas sulfur content: ASTM D3246. EPA approved alternative test methods as approved bythe District may also be used to address the source testing requirements of this permit. [District Rules 1081, 4001, and 4703] Verification: The project owner shall provide records of compliance as part of Condition AQ-29. AQ-32 The project ownershall notify District of the: e date ofinitiation of construction no later than 30 days after such date; date of anticipated startup not more than 60 days nor less than 30 daysprior to such date; and e date of actual startup within fifteen (15) days after such date. [District Rule 4001] Verification: Within thirty (30) days after such event, the project owner shall notify the CPM and theDistrict of the date of initiation of construction. Not more than sixty (60) days orless than thirty (30) days prior to such event, the CPM andtheDistrict shall be notified of the date of anticipated startup. The CPM andthe District shall be notified within fifteen (15) days after actual startup . AQ-33 The project owner shall maintain hourly records of NOx, CO, and ammonia emission concentrations (ppmv @ 15% Oz), and hourly, daily, and twelve month rolling average records of NOx and CO emissions. Compliance with the hourly, daily, and twelve-monthrolling average VOC emissionlimits shall be demonstrated by the CO CEM data and the VOC/COrelationship determined by annual CO and VOCsourcetests. [District Rule 2201] Verification: The project owner shall provide records of compliance as part of the quarterly reports of Condition AQ-35. AQ-34 The project owner shall maintain records of SO, Ib/hr, Ib/day, and lb/twelve month rolling average emission. SO, emissions shall be based onfuel use records, natural gas sulfur content, and mass balancecalculations. [District Rule 2201] Verification: The project owner shall provide records of compliance as part of the quarterly reports of Condition AQ-35. AQ-35 The project owner shail maintain the following records for the CTG: occurrence, duration, and type of any startup, shutdown, or malfunction; emission measurements; total daily and annual hours of operation; and hourly quantity of fuel used. [District Rules 2201 & 4703] 131 Verification: The project owner shall compile required data and submit the information to the CPM in quarterly reports submitted no later than thirty (30) days after the end of each calendar quarter. AQ-36 The project owner shall maintain the following records for the continuous emissions monitoring system (CEMS): performance testing, evaluations, calibrations, checks, maintenance, adjustments, and any period of non-operation of any continuous emissions monitor. [District Rules 2201 & 4703] Verification: The project owner shall provide records of compliance as part of the quarterly reports of Condition AQ-35. AQ-37 All records required to be maintained by this permit shall be maintained for a period of five (5) years and shall be made readily available for District inspection upon request. [District Rule 2201] Verification: The project owner shall make records available for inspection by representatives of the District, CARB and the Commission upon request. AQ-38 Results of continuous emissions monitoring shall be reduced according to the procedure established in 40 CFR, Part 51, Appendix P, and paragraphs 5.0 through 5.3. 3, or by other methods deemed equivalent by mutual agreement with the District, the ARB, and the EPA.[District Rule 1080] Verification: The project owner shall compile the required data in the formats discussed above and submit the results as part of the quarterly reports specified in Condition AQ-35. AQ-39 Not later than one (1) hour after its detection, the project owner shall notify the District of any breakdown condition, unless the owner or operator demonstrates to the Districts satisfaction that the longer reporting period was necessary.[District Rule 1100] Verification: The project owner shall comply with the notification requirements of the District and submit written copies of these notification reports to the CPM as part of the quarterly reports of Condition AQ-35. AQ-40 TheDistrict shall be notified in writing within ten (10) days following the correction of any breakdown condition. The breakdownnotification shall include a description of the equipment malfunction or failure, the date and cause of the initial failure, the estimated emissions in excess of those allowed, and the methodsutilized to restore normal operations. [District Rule 1100] Verification: The project owner shall comply with the notification requirements of the District and submit written copies of these notification reports to the CPM as part of the quarterly reports of Condition AQ-35. 132 AQ-41 Audits of continuous emission monitors shall be conducted quarterly, except during quarters in which relative accuracy and total accuracy testing is performed, in accordance with EPA guidelines. The District shall be notified prior to completion of the audits. Audit reports shall be submitted along with quarterly compliance reports to the District. [District Rule 1080] Verification: The project owner shall submit the continuous emission monitor audit results with the quarterly reports required of Condition AQ-43. AQ-42 The project owner shall comply with the applicable requirements for quality assurance testing and maintenance of the continuous emission monitor equipmentin accordance with the procedures and guidance specified in 40 CFR Part 60, Appendix F. [District Rule 1080] Verification: The project owner shall submit the continuous emission monitor results with the quarterly reports of Condition AQ-43. AQ-43 Within thirty (30) days of the end of the quarter, for each calendar quarter, the project ownershall submit a written report to the APCO that includes: e time intervals, e data and magnitude of excess emissions, e nature and cause of excess(if known), e corrective actions taken and preventive measures adopted. Averaging period used for data reporting shall correspond to the averaging period for each respective emission standard; applicable time and date of each period during which the CEM wasinoperative (except for zero and span checks) and the nature of system repairs and adjustments; and a negative declaration when no excess emissions occurred. [District Rule 1080] Verification: The project owner shall compile the required data and submit the quarterly reports to the CPM and the APCOwithin thirty (30) days of the end of the quarter. AQ-44 The project ownershall submit an application to comply with Rule 2540- Acid Rain Program twenty four (24) months before the unit commences operation. [District Rule 2540] Verification: The project ownershall file their application with the District at least twenty four (24) months prior to the commencementof operation of any of the combustion turbine generators. Conditions of Certification AQ-45 through AQ-52 apply to the following equipment: FORCED DRAFT COOLING TOWERWITH 6 CELLS AND HIGH EFFICIENCY DRIFT ELIMINATOR S-3523-3-0: 133 AQ-45_ Noair contaminant shall be released into the atmosphere which causes a public nuisance.[District Rule 4102] Verification: The project owner shall make the site available for inspection by representatives of the District, CARB and the Commission. AQ-46 At least thirty (30) days prior to commencement of construction, the project ownershall submit to the District: e drift eliminator design details; and e vendor specific emission justification for the correction factor to be used to correlate blowdown TDSto drift TDS and the amountof drift that stays suspended in the atmosphere utilizing the equation in Condition AQ-51. [District Rule 2201] Verification: Thirty (30) days prior to commencement of construction of the cooling towers, the project ownershail submit the information required above to the District and the CPM. AQ-47 The project ownershall submit to the District cooling tower design details (including the cooling tower type and materials of construction) at least thirty (30) days prior to commencement of construction, and, at least ninety (90) days before the toweris to be operated. [District Rule 7012] Verification: Thirty (30) days prior to commencement of construction of the cooling towers, the project owner shall submit the information required aboveto the District and the CPM. AQ-48 No hexavalent chromium containing compounds shall be added to cooling towercirculating water. [District Rule 7012] Verification: The project owner shall make the site available for inspection by representatives of the District, CARB and the Commission. AQ-49_ Drift eliminator drift rate shall not exceed 0.0006%. [District Rule 2201] Verification: The project owner shall submit documentation from the selected cooling tower vendorthat verifies the drift efficiency to the CPM thirty (30) days prior to commencementof construction of the cooling towers. AQ-50 PM, emission rate shall not exceed 9.3 Ib/day. [District Rule 2201] Verification: Please refer to Condition AQ-51. AQ-51 Compliance with the PMio daily emission limit shall demonstrated as follows: PMy9 Ib/day = circulating water recirculation rate * total dissolved solids concentration in the blowdown water * design drift rate * correction factor. [District Rule 2201} Verification: The project owner shall compile the required daily PMi9 emissions data and maintain the data for a period of five (5) years. The project ownershall 134 make the site available for inspection by representatives of the District, CARB and the Commission. AQ-52 Compliance with PM19 emission limit shall be determined bycirculating water sample analysis by independent laboratory within 90 daysofinitial operation and weekly thereafter. [District Rule 1081] Verification: The project owner shall compile the required daily PM10 emissions data and maintain the data for a period of five (5) years. The project owner shall makethe site available for inspection by representatives of the District, CARB and the Commission. Conditions of Certification AQ-53 through AQ-62 apply to the following equipment: SAMPLE EQUIPMENT DESCRIPTION: 125 HP PERKINS/DETROIT DIESEL MODEL PDFP-06YR DIESEL-FIRED IC ENGINE DRIVING EMERGENCYFIRE WATER PUMPS-3523-4-0: AQ-53 Noair contaminant shall be released into the atmosphere which causes a public nuisance. [District Rule 4102] Verification: The project owner shall make the site available for inspection by representatives of the District, CARB and the Commission. AQ-54 Noair contaminant shall be discharged into the atmosphere for a period or periods aggregating more than three minutes in any one hour whichis as dark as, or darker than, Ringelmann 1 or 20% opacity. [District Rule 4101] Verification: The project owner shall make the site available for inspection by representatives of the District, CARB and the Commission. AQ-55 The engine shall be equipped with a turbocharger and intercooler/aftercooler. [District Rule 2201] Verification: The project owner shall make the site available for inspection by representatives of the District, CARB and the Commission. AQ-56 The engine shall be equipped with an operational non-resettable hour meter. [District Rule 2201] Verification: The project owner shall make the site available for inspection by representatives of the District, CARB and the Commission. AQ-57 The engine shall be equipped with a positive crankcase ventilation (PCV) system or a crankcase emissions control device of at least 90% control efficiency unless UL certification would be voided. [District Rule 2201] 135 Verification: The project owner shall make the site available for inspection by representatives of the District, CARB and the Commission. AQ-58 NO, emissions shall not exceed 7.2 g/hp-hr. [District Rule 2201]. Verification: The project owner shall make the site available for inspection by representatives of the District, CARB and the Commission. AQ-59 The sulfur content of the diesel fuel used shall not exceed 0.05% by weight. [District Rule 2201] Verification: Please refer to Condition AQ-62. AQ-60 Particulate matter emissions shall not exceed 0.1 grains/dscf in concentration. [District Rule 4201] Verification: The project owner shall make the site available for inspection by representatives of the District, CARB and the Commission. AQ-61 The engine shall be operated only for maintenance, testing, and required regulatory purposes, and during emergencysituations. Operation of the engine for maintenance,testing, and required regulatory purposesshall not exceed 200 hours peryear. [District Rules 2201 and 4701] Verification: The project owner shall compile records of hours of operation of any of the IC engines and include those records as part of the quarterly reports submitted to the CPM under Condition AQ-35. AQ-62 The project owner shall maintain records of hours of non-emergency operation and of the sulfur content of the diesel fuel used. Such records shall be made available for District inspection upon request for a period offive (5) years. [District Rules 2201 and 4701] Verification: The project ownershall compile records of hours of operation of the IC engines and of the diesel fuel purchased that includes the sulfur content, and maintain the data for a period of five years. The project owner shall makethesite available for inspection by representatives of the District, CARB and the Commission. 136 U.S. Energy Information Administration (EIA) Page | of 22 ia) US. Energy Information Administration International Energy Outlook 2011 Release Date: September 19, 2011 | Report Number: DOE/EIA-0484(2011) Electricity Overview Figure 72. Growth in world electricity generation and total delivered energy consumption, 1990-2035 ndies, Pe90= 1) 4 History 2008 Projechons 3 Phat elocincity generabor Total delrered energy consumphan Oe ; ‘ ¢ r 1980 2000 2008 2075 2025 2035 t figure data In the /EO2011 Reference case, electricity supplies an increasing share of the world's total energy demand, andelectricity use grows morerapidly than consumption ofliquid fuels, natural gas, or coal in all end-use sectors except transportation. From 1990 to 2008, growthin net electricity generation outpaced the growth in delivered energy consumption (3.0 percent per year and 1.8 percent per year, respectively). World demandforelectricity increases by 2.3 percent per year from 2008 to 2035 and continues to outpace growth in total energy use throughout the projection period (Figure 72). World net electricity generation increases by 84 percent in the Reference case, from 19.1 trillion kilowatthours in 2008 to 25.5 trillion kilowatthours in 2020 and 35.2 trillion kilowatthours in 2035 (Table 11). Although the 2008-2009 global economic recession slowed the rate of growth in electricity use in 2008 and resulted in negligible changein electricity use in 2009, worldwide electricity demand increased by an estimated 5.4 percent in 2010, with non-OECDelectricity demand alone increasing by an estimated 9.5 percent. In general, projected growth in OECD countries, whereelectricity markets are well established and consumption patterns are mature, is slower than in non-OECD countries, where a large amount of demand goes unmetat present. The electrification of historically off-grid areas plays a strong role in projected growth trends. The International Energy Agencyestimates that 21 percent of the world's population did not have accessto electricity in 2009—a total of about 1.4 billion people [207]. Regionally, sub-Saharan Africa is worst off: more than 69 percentof the population currently remains without accessto power. With strong economic growth and targeted government programs, however,electrification can occur quickly.In http://www.eia.gov/forecasts/ieo/electricity.cfm 7/9/2012 U.S. Energy Information Administration (EIA) Page 2 of 22 Vietnam, for example, the government's ruralelectrification program increased access to powerfrom 51 percentof rural households in 1996 to 95 percent at the end of 2008 [208]. Figure 73. OECD and non-OECD net electricity figure data generation, 1990-2035 ; fErilllon Kilowattheurs} Non-OECDnations consumed 47 percentof the ; Project world’s total electricity supply in 2008, and their share 25 Histony 2008 reckons of world consumption is poised to increase overthe projection period. In 2035, non-OECDnations account 20 wo for 60 percent of world electricity use, while the OECD share declines to 40 percent (Figure 73). Total net electricity generation in non-OECD countries . increases by an average of 3.3 percent per yearin the 10 Reference case, led by annual increases averaging — an 4.0 percent in non-OECDAsia (including China and India) from 2008 to 2035 (Figure 74). In contrast, total a a oe a net generation in the OECD nations grows by an averageof only 1.2 percent per year from 2008 to NebCD 15 Os t t ’ 2035. 1950 2000 2008 2045 2025 2035 Figure 74. Non-OECD netelectricity generation by region, 1990-2035 flallcen hilesvatthioias | 40 History _ 2008 Projections Chie & 8 ipecdin ered Catia ae Middle East andAfrica ae Europe and Eurasia | aa aad Seu ones 0G £ v ¥ ¥ F 1990 2000 2006 20158 2025 2035 figure data The outlook for total electricity generation is largely the same as projected in last year’s report. However, the projected mix of generation byfuel in the /EO2011 Reference case has changed. Thelargest difference betweenthe two outlooksis for natural-gas-fired generation—whichis 22 percent higherin this year's outlook in 2035. The more optimistic outlook for generation from natural gas-fired powerplants is a result of a reassessmentof available gas supplies. This year's [EO includes an upward revision in potential gas supplies, largely becauseof increases in unconventional supplies of natural gas in the United States and otherparts of the world. The increasein the natural gas share of generation to a large extent displaces coal-fired generation, which is 14 percent lower than in last year’s report. In addition, projected nuclear power generation is 9 percent higher, and generation from renewable sourcesis 3 percent higher in 2035 than projected in 1EO2010. The nuclear projection does notreflect consideration of policy responses to Japan's Fukushima Daiichi nuclear disaster, which are likely to reduce projected nuclear generation from both existing and new plants. Liquids-fired generation, in contrast, is 3 percent lowerin this year’s projection. http://www.eia.gov/forecasts/ieo/electricity.cfm 7/9/2012 U.S. Energy Information Administration (EIA) Page 3 of 22 The /EO2011 projections do not incorporate assumptionsrelated to limiting or reducing greenhouse gas emissions, such as caps on carbon dioxide emissions levels or taxes on carbon dioxide emissions. However, the Reference case does incorporate current national energy policies, such as the European Union's "20-20-20"plan and its memberstates’ nuclear policies; China's wind capacity targets; and India's National Solar Mission.”® Electricity supply by energy source The worldwide mix of primary fuels used to generate electricity has changed a great deal over the past four decades. Coal continues to be the fuel most widely used for electricity generation, although generation from nuclear powerincreased rapidly from the 1970s through the 1980s, and naturai-gas-fired generation grew rapidly in the 1980s and 1990s. The useofoil for electricity generation has been declining since the mid-1970s, whenoil prices rose sharply. The high fossil fuel prices recorded between 2003 and 2008, combined with concerns about the environmental consequencesof greenhouse gas emissions, have renewedinterest in the developmentof alternatives to fossil fuels— specifically, nuclear power and renewable energy sources.In the /EO2017 Reference case, long-term prospects continue to improve for generation from both nuclear and renewable energy sources—primarily supported by governmentincentives. Renewable energy sourcesare the fastest-growing sourcesofelectricity generation in the /EQ2017 Reference case, with annual increases averaging 3.1 percent per year from 2008 to 2035. Natural gas is the second fastest-growing generation source, increasing by 2.6 percent per year, followed by nuclear powerat 2.4 percent per year. Although coal-fired generation increases by an annual averageof only 1.9 percent over the projection period, it remains the largest source of generation through 2035. However, the outlook for coal, in particular, could be altered substantially by any future national policies or international agreements aimed at reducing orlimiting the growth of greenhouse gas emissions. Coal Figure 75. World net electricity generation by fuel, 2008-2035 tiiBion wicwatthours) 15 19 Liquids —- i C 2020 2008 2015 2025 2030 2035 figure data In the /EO02011 Reference case, coal continuesto fuel the largest share of worldwide electric power production by a wide margin (Figure 75). In 2008, coal-fired generation accounted for 40 percent of world electricity supply; in 2035,its share decreases to 37 percent, as renewables, natural gas, and nuclear powerall are expected to advancestrongly during the projection and displace the needfor coal-fired-generation in many parts of the world. World net coal-fired generation grows by 67 percent, from 7.7 trillion kilowatthours in 2008 to 12.9 trillion kilowatthours in 2035. The electric power sector offers some of the mostcost-effective opportunities for reducing carbon dioxide emissions in many countries. Coal is both the world’s most widely used source of energy for power generation and also the most carbon- intensive energy source.If a cost, either implicit or explicit, is applied to carbon dioxide emissions in the future, there are http://www.cia.gov/forecasts/ieo/electricity.cfm 7/9/2012 U.S. Energy Information Administration (EIA) Page 4 of 22 several alternative technologies with no emissionsorrelatively low levels of emissions that currently are commercially proven or under development and could be used to displace coal-fired generation. Natural gas Over the 2008 to 2035 projection period, natural-gas-fired electricity generation increases by 2.6 percent peryear. Generation from natural gas worldwide increases from 4.2 trillion kilowatthours in 2008 to 8.4 trillion kilowatthours in 2035, but the total amount ofelectricity generated from natural gas continues to be less than one-half the total for coal, even in 2035. Natural-gas-fired combined-cycle technology is an attractive choice for new powerplants becauseofits fuel efficiency, operatingflexibility (it can be brought online in minutes rather than the hoursit takes for coal-fired and some other generating capacity), relatively short planning and construction times, relatively low emissions, andrelatively low capital costs. Prospects for natural gas have improved substantially relative to last year's outlook, in large part becauseof the revised expectations for unconventional sourcesof natural gas, especially shale gas,” both within the United States and globally. The additional! resourceswill allow natural gas supplies outside North American to be used as LNGto supply markets that have few domestic resources. As a result, natural gas markets are expected to remain well supplied and pricesrelatively low in the mid-term, and many nations are expected to turn to natural gas, rather than more expensive or more carbon-intensive sourcesofelectricity, to supply their future power needs. Liquid fuels and other petroleum With world oil prices projected to return to relatively high levels, reaching $125 perbarrel (in real 2009 dollars) in 2035,liquid fuels are the only energy source for power generation that does not grow on a worldwide basis. Nations are expected to respond to higheroil prices by reducing oreliminating their use ofoil for generation—opting instead for more economical sourcesofelectricity, including natural gas and nuclear. Even in the resource-rich Middle East, there is an effort to reduce the use of petroleum liquids for generation in favor of natural gas and other resources,in order to maximize revenuesfrom oil exports. Worldwide, generation from liquid fuels decreases by 0.9 percent per year, from 1.0 trillion kilowatthours in 2008 to 0.8 trillion kilowatthours in 2035. Nuclear power Electricity generation from nuclear powerworldwide increasesfrom 2.6 trillion kilowatthours in 2008 to 4.9 trillion kilowatthours in 2035 in the /EO2071 Reference case, as concerns about energy security and greenhouse gas emissions support the development of new nuclear generating capacity. In addition, world average capacity utilization rates have continued to rise overtime, from about 65 percent in 1990 to about 80 percent today, with someincreasesstill anticipated in the future. Finally, most older plants now operating in OECD countries and in non-OECDEurasia probably will be granted extensionsto their operating licenses. While /EO20117 wasin preparation, a large earthquake and tsunamistruck the northeast coast of Japan, severely damaging nuclear powerplants at Fukushima Daiichi [209]. Although the full extent of the damage remains unclear, the event is almost certain to have a negative impact on Japan's nuclear powerindustry, at least in the short term, andit is also likely to reduce projected nuclear generation from both existing and newfacilities as governments formulate their policy responses to the disaster. The /EO02011 Reference case was notrevised to take the March 2011 natural disaster into account, but the uncertainty associated with nuclear powerprojections for Japan and for the rest of the world has increased. A numberof issues could slow the development of new nuclear powerplants. In many countries, concerns about plant safety, radioactive waste disposal, and nuclear materialproliferation could hinder plans for new installations. Moreover, the explosions at Japan's Fukushima Daiichi nuclear powerplant in the aftermath of the March 2011 earthquake and tsunami could have long-term implications for the future of world nuclear power developmentin general. Even China—wherelarge increases in nuclear capacity have been announced and are anticipated in the /EO20171 Reference case—hasindicated that it will halt approval processesforall new reactors until the country's nuclear regulator completes a "thorough safety review'— a processthat could last for as long as a year [210]. Germany, Switzerland, and Italy already have announcedplans to phase http://www.ela.gov/forecasts/ieo/electricity.cfm 7/9/2012 U.S. Energy Information Administration (EIA) Page 5 of 22 out or cancelall their existing and future reactors, indicating that some slowdownin the growth of nuclear power should be expected. High capital and maintenance costs may also keep some countries from expanding their nuclear power programs. Finally, a lack of trained labor resources, as well as limited global capacity for the manufacture of technological components, could keep national nuclear programs from advancing quickly. 1E02011 provides the status of international radioactive waste disposal programsin the box on page, which identifies the most common approachesto radioactive waste disposal and, where available, their costs and schedules. Storage and disposal costs remain an importantlife-cycle consideration in the decision to add nuclear generation capacity. Future IEOs will address supply chain uncertainties as well as uncertainties relatedto construction costs and uranium enrichment. Despite such uncertainties, the /EO2011 Reference case projects continued growth in world nuclear power generation. The projection for nuclear electricity generation in 2035 is 9 percent higher than the projection publishedin last year's IEO. Figure 76. Vvorld net electricity generation fram figure data nuclearpower by region, 2008-2035 nilion kilawattha ws) On a regional basis, the Reference case projects the strongest growth in nuclear powerfor the countries of non-OECDAsia (Figure 76), averaging 9.2 percent 5 per yearfrom 2008 to 2035, including increases of 10.3 percent per year in China and 10.8 percent per yearin India. China leadsthe field with nearly 44 AU Burne percent of the world’s active reactor projects under construction in 2011 and is expectedto install the ta d most nuclear capacity over the period, building 106 gigawatts of net generation capacity by 2035 [211]. Outside Asia, nuclear generation growsthe fastest in Obier Asia: . as Central and South America, whereit increases by an Urdted States average of 4.2 percent per year. Nuclear generation 0 >ong 2018 | 2020. 2025 2030 2035 ' worldwide increases by 2.4 percent per yearin the Reference case. To address the uncertainty inherent in projections of nuclear power growth overthe long term, a two-step approachis used to formulate the outlook for nuctear power.In the short term (through 2020), projections are based primarily on the current activities of the nuclear powerindustry and national governments. Becauseofthe long permitting and construction lead times associated with nuclear powerplants, there is general agreement amonganalysts on which nuclear projects are likely to become operational in the short term. After 2020, the projections are based on a combination of announcedplansor goals at the country and regional levels and consideration of other issues facing the developmentof nuclear power, including economics, geopolitical issues, technology advances, environmental policies, supply chain issues, and uranium availability. Hydroelectric, wind, geothermal, and other renewable generation Renewable energyis the fastest-growing source ofelectricity generation in the /EO2011 Reference case. Total generation from renewable resourcesincreasesby 3.1 percent annually, and the renewable share of world electricity generation grows from 19 percent in 2008 to 23 percent in 2035. More than 82 percentof the increaseis in hydroelectric power and wind power. The contribution of wind energy, in particular, has grown swiftly over the past decade,from 18 gigawatis of net installed capacity at the end of 2000 to 121 gigawatts at the end of 2008—atrend that continuesinto the future. Of the 4.6 trillion kilowatthours of new renewable generation added overthe projection period, 2.5 trillion kilowatthours (55 percent) is attributed to hydroelectric power and 1.3 trillion kilowatthours (27 percent) to wind (Table 13). Although renewable energy sources havepositive environmental and energy security attributes, most renewable technologies other than hydroelectricity are not able to compete economically with fossil fuels during the projection period http://www.eia.gov/forecasts/ieo/electricity.cfm 7/9/2012 U.S. Energy Information Administration (EIA) Page 6 of 22 exceptin a few regionsorin niche markets. Solar power,for instance, is currently a "niche" source of renewable energy, but it can be economical whereelectricity prices are especially high, where peak load pricing occurs, or where government incentives are available. Governmentpolicies or incentives often provide the primary economic motivation for construction of renewable generationfacilities. Wind and solar are intermittent technologies that can be used only when resourcesare available. Once windorsolarfacilities are built, however, their operating costs generally are much lowerthan the operating costs for fossil fuel-fired powerplants. However, high construction costs can makethetotal cost to build and operate renewable generators higher than thosefor conventional plants. The intermittence of wind and solar canfurther hinder the economic competitiveness of those resources, becausethey are not operator-controlled and are not necessarily available when they would be of greatest valueto the system. Although the technologies currently are not cost-effective, the use of energy storage (such as hydroelectric pumped storage, compressedair storage, and batteries) and the dispersal of wind and solar generating facilities over wide geographic areas could mitigate many of the problems associated with intermittency. Changesin the mix of renewable fuels usedforelectricity generation differ between the OECD and non-OECDregionsin the 1EO2011 Reference case. In the OECD nations, most of the hydroelectric resources that are both economical to develop and also meet environmental regulations already have been exploited. With the exceptions of Canada and Turkey,there are few large-scale hydroelectric projects plannedforthe future. As a result, most renewable energy growth in OECD countries comes from nonhydroelectric sources, especially wind and biomass. Many OECD countries, particularly those in Europe, have governmentpolicies, including feed-in tariffs (FiTs),°° tax incentives, and market share quotas, that encourage the construction of such renewableelectricity facilities. in non-OECDcountries, hydroelectric power is expected to be the predominant source of renewable electricity growth. Strong growth in hydroelectric generation, primarily from mid- to large-scale powerplants, is expected in China, India, Brazil, and a numberof nations in Southeast Asia, including Malaysia and Vietnam. Growth rates for wind-powered generation also are high in non-OECD countries. The most substantial additions to electricity supply generated from wind powerare expected for China. The /EO02017 projections for renewable energy sources include only marketed renewables. Non-marketed (noncommercial) biomassfrom plant and animal resources, while an important source of energy, particularly in the developing non-OECD economies,is not included in the projections, because comprehensive data on its use are not available. For the same reason, off-grid distributed renewables—renewable energy consumedatthesite of production, such as off-grid photovoltaic (PV) panels—are notincludedin the projections. Globalefforts to manage radioactive waste from nuclear powerplants Prospects for nuclear power generation have improved in recent years, as many nations have attempted to diversify the fuel mix for their power generation sectors away from fossil fuels while also addressing concerns about greenhouse gas emissions. Nuclear power generators do not emit the greenhouse gases produced byfossil fuel generators. However, they do produce radioactive waste that must be managed. In the /EO2011 Reference case,nuclearelectricity generation nearly doubles from 2008 to 2035. Such an increase would be accompaniedbysignificant increases in the accumulation of spent fuel rods and other nuclear waste in countries with nuclear powerplants. Managing nuclear waste is a long-term issue. Governments must protect the public and environment from exposure to highly radioactive materials for hundreds or thousandsof years into the future. And although there is general international agreement about how waste disposal should be approached, implementing managementplans has proven to be politically complicated. As a result, few of the countries that currently have nuclear generation programsin operation have solidified their long-term plans for managing nuclear waste. There are two forms of nuclear waste: spent nuclear fuel (SNF) and high-level radioactive waste (HLW), which results from the processing of SNFfor re-use in nuclear powerreactors. If SNF is not reprocessed, the normal management approachis http://www.eia.gov/forecasts/ieo/electricity.cfm 7/9/2012 U.S. Energy Information Administration (EIA) Page 7 of 22 long-term storage,either on site at nuclear powerstations or at centralized interim storage facilities followed by deep geological disposalin a repository. This approach to waste managementis knownasthe “direct disposal option." In the United States, SNF is stored at the country's 104 operating nuclear reactors. In Swedenit is stored at a single site, the Central Interim Storage Facility for Spent Nuclear Fue! at Oskarshamn.France reprocessesits spent nuclear fuel to recover plutonium and uranium for use in fabricating new mixed-oxide fuel for its nuclear powerplants, and it has successfully commercialized the process. Reprocessing greatly reduces the volumeof nuclear waste for which disposal is necessary, but some components of the HLW cannot be recycled and must bevitrified (solidified in a glass-like matrix), stored, and eventually placedin a repository. in selecting a nuclear waste management approach, several countries, including the United States, have optedfor direct disposal in order to reducethe risk of nuclear weaponsproliferation that is associated with the reprocessing option. The International Atomic Energy Agency's (IAEA) Joint Convention on the Safety of Spent Fuel Management and on the Safetyof Radioactive Waste Management, which entered into force on June 18, 2001, recognizesthat at the technicallevel disposalof nuclear waste in a deep geological repository ultimately represents the safest method of managing nuclear waste [212]. Manycountries are investigating geological disposal and are committed to the approachin principle, including the 13 countries that produce more than 80 percentof the world's nuclear power: Belgium, Canada, China, Finland, France, Germany, Japan, South Korea, Spain, Sweden, Switzerland, the United Kingdom, and the United States. Only a few countries provide reliable data on the costs of geological disposal. Their estimates generally are contained in national reports to the IAEA underthe provisions of the Joint Conventionor, alternatively, in published accounts oftotallife- cycle costs for their nuclear power systems. Disposal costs are affected by such factors as the type and quantity of waste that requires disposal, the design of the waste repository andits period of operation, and the country's waste management strategy (direct disposal or reprocessing). National cost estimates for the management of spent nuclear fuel vary widely: * inthe United States, a facility with storage capacity for 70,000 metric tons of heavy metal (MTHM)is estimated to cost $96.18 billion (2007 dollars) or about $707 per kilogram of heavy metal [213]. + In Japan a 29,647 MTHMstoragefacility is estimated to cost $25 billion (2007 dollars) or about $851 perkilogram of heavy metal [214]. * In Sweden a 9,741 MTHMstoragefacility is estimated to cost $3.4 billion (2007 dollars) or about $350 per kilogram of heavy metal [215]. Nuclear energy remains a key componentof the world's electric power mix in the /EO2011 Reference case. Countries with nuclear generation programs recognize the need for long-term planning for waste disposal, but the timing and costs of disposal are uncertain at best. Currently, no country has an operational disposalfacility. With the United States recently having terminatedits plan for disposal at Yucca Mountain in Nevada,the only countrieslikely to have operational deep geological repositories by 2025 are Finland, France, and Sweden. Others, including China and Spain, may not have established geological repositories until as late as 2050 (Table 12). Implementing timely nuclear waste managementstrategies will reduce uncertainties in the nuclear fuel cycle as well as the ultimate cost of disposal, but it remains to be seen how successful the international community will be in implementing such strategies. Regionalelectricity outlooks In the /EO2017 Reference case, the highest growth ratesforelectricity generation are in non-OECD nations, where strong economic growth and rising personal incomesdrive the growth in demandfor electric power. In OECD countries—where electric powerinfrastructures are relatively mature, national populations generally are expected to grow slowly or decline, and GDPgrowth is slower than in the developing nations—demandforelectricity grows much more slowly. Electricity generation http://www.eia.gov/forecasts/ieo/electricity.cfm 7/9/2012 U.S. Energy Information Administration (EIA) Page 8 of 22 in non-OECD nationsincreases by 3.3 percent per year in the Reference case, as compared with 1.2 percent per yearin CECDnations. OECDelectricity Americas The countries of the OECD Americas (the United States, Canada, Chile, and Mexico) currently account for the largest regional share of world electricity generation, with 26 percentofthe total in 2008. That share declines as non-OECDnations experience fast-paced growth in demand for electric power. In 2035, the nations of the OECD Americas together account for only 19 percent of the world's net electric power generation. figure data Figure 77. OECD Americas net electricity generation by region, 2008-2035anion Kinwatthouss} The United States is by far the largest consumerof electricity in the region (Figure 77). U.S. electricity a ‘ generation—including both generation by electric powerproducersandon-site generation—increases slowly, at an average annual rate of 0.8 percent from s 2008 to 2035. Canada, like the United States, has a matureelectricity market, and its generation increases 40 ted States by 1.4 percent per year over the sameperiod. Mexico/Chile's electricity generation grows at a faster rate—averaging 3.2 percent per year through 2035— reflecting the current less-developed state of their Mexicaithile electric powerinfrastructure (and thus the greater ada potential for expansion) relative to Canada and the United States. Ke 2008 : 2015 2020 2025 2030 2035 There are large differences in the mix of energy sources used to generateelectricity in the four countries that make up the OECD Americas, and those differences are likely to become more pronouncedin the future (Figure 78). In the United States, coal is the leading source of energy for power generation, accounting for 48 percent of the 2008total. In Canada, hydroelectricity provided 60 percent of the nation’s electricity generation in 2008. Mostof Mexico/Chile's electricity generation is currently fueled by petroleum-basedliquid fuels and natural gas, which together accounted for 66 percentof total generation in 2008. The predominantfuels for generation in the United States and Canada are expected to lose market share by 2035, although electricity generation continues to be added. Coal-fired generation declines to 43 percent of the U.S. total, and hydropowerfalls to 54 percent of Canada'stotal in 2035. In contrast, in Mexico/Chile, natural-gas-fired generation increases from 48 percentof the total in 2008 to 58 percentin 2035. figure data Generation from renewable energy sourcesin the United States increases in response to requirements in more than half of the 50 States for minimum renewable sharesofelectricity generation or capacity. Although renewable generation in 2035 in the /EO2011 Reference case is 17 percent lowerthanin last year’s outlook (due to a variety of factors, including lower electricity demand,a significant increasein the availability of shale gas, and revised technology and policy assumptions), the share of renewable-based generation is expected to grow from 9.7 percent in 2008 to 14.3 percent in 2035. The projection for electricity generation from other renewables sources also has dropped,as a result of lower expectations for biomass co- firing. U.S. Federal subsidies for renewable generation are assumed to expire as enacted. If those subsidies were extended, however, a larger increase in renewable generation would be expected. http://www.eia.gov/forecasts/ieo/electricity.cfm 7/9/2012 U.S. Energy Information Administration (EIA) Page 9 of 22 < . _ . Electricity generation from nuclear powerplants Figure 78. OECD Americas netelectricity generation . byfuel, 2008-2035 accounts for 16.9 percent of total U.S. generationin (perment of total) 2035 in the {£02011 Reference case. Title XVII of the U.S. Energy Policy Act of 2005 (EPACT2005, Public wn Law 109-58) authorized the U.S. Department of Energy to issue loan guaranteesfor innovative 96 technologies that “avoid, reduce, or sequester greenhouse gases.” In addition, subsequent legislative provisions in the Consolidated a Appropriation Act of 2008 (Public Law 110-161) allocated $18.5 billion in guarantees for nuclear power 25 plants [216]. That legislation supports a net increase of about 10 gigawatts of nuclear powercapacity, which growsfrom 101 gigawatts in 2008 to 114 DE mre ~ngom eee a gigawatts in 2035. The increase includes 3.8 2008 2035 2008 2035 2008 2035United States Canada MexivarGhile gigawatts of expanded capacity at existing plants and 6.3 gigawatts of new capacity. The /EO2017 Reference caseincludes completion of a second unit at the Watts Bar nuclear site in Tennessee, where construction was halted in 1988 when it was nearly 80 percent complete. Four new U.S. nuclear power plants are completed by 2035, all brought on before 2020 to take advantage of Federal financial incentives. One nuclear unit, Oyster Creek, is projected to be retired at the end of 2019, as announced by Exelon in December2010. All other existing nuclear units continue to operate through 2035 in the Reference case. In Canada, generation from natural gas increases by 3.8 percent per year from 2008 to 2035, nuclear by 2.2 percent per year, hydroelectricity by 0.9 percent per year, and wind by 9.9 percent per year. Oil-fired generation and coal-fired generation, on the other hand, decline by 1.0 percent per year and 0.6 percent per year, respectively. in Ontario—Canada's largest provincial electricity consumer—the governmentplansto close its four remaining coal-fired plants (Atikokan, Lambton, Nanticoke, and Thunder Bay) by December31, 2014, citing environmental and health concerns [217]. Units 1 and 2 of Lambton and units 3 and 4 of Nanticoke were decommissioned in 2010 [218]. The government plans to replace coal-fired generation with natural gas, nuclear, hydropower, and wind. It also plans to increase conservation measures. With the planned retirements in Ontario, Canada's coal-fired generation declines from about 104 billion kilowatthours in 2008 to 88billion kilowatthours in 2035. The renewable share of Canada's overall generation remains roughly constant throughout the projection. Hydroelectric power is, and is expected to remain, the primary sourceof electricity in Canada. From 60 percent of the country's total generation in 2008, hydropowerfalls to 54 percent in 2035. As one of the few OECDcountries with large untapped hydroelectric potential, Canada currently has several large- and small-scale hydroelectric facilities either planned or under construction. Hydro- Quebecis continuing the construction of a 768-megawatt facility near Eastmain and a smaller 150-megawatt facility at Sarcelle in QUA©@bec, both of which are expected to be fully commissioned by 2012 [219]. Other hydroelectric projects are underconstruction, including the 1,550-megawatt Romaine River project in Quebec and the 200-megawatt Wuskwatim project in Manitoba [220]. The /EO2077 Reference case does notanticipate that all planned projects will be constructed, but given Canada’s past experience with hydropower and the commitments for construction, new hydroelectric capacity accounts for 25,563 megawatts of additional renewable capacity added in Canada between 2008 and 2035. Wind-powered generation, in contrast, is the fastest-growing source of new energy in Canada,with its share of total generation increasing from less than 1 percent in 2008 to 5 percent in 2035. Canada hasplans to continue expandingits wind powercapacity, from 4.0 gigawattsofinstalled capacity at the end of 2010 [221] to nearly 16.6 gigawatts in 2035in the Reference case. Growth in wind capacity has been so rapid that Canada's federal wind incentive program, “ecoENERGYfor http://www.eia.gov/forecasts/ieo/electricity.cfm 7/9/2012 U.S. Energy Information Administration (EJA) Page 10 of 22 Renewable Power,” which targeted the deploymentof 4 gigawatts of renewable energy by 2011, allocated all ofits funding and metits target by the end of 2009 [222]. In addition to the incentive programs of Canada's federal government, several provincial governments haveinstituted their ownincentives to support the construction of new wind capacity. After the success ofits Renewable Energy Standard Offer Program, Ontario enacted a feed-in-tariff that pays all sizes of renewable energy generators between 10 cents and 80 cents (Canadian) per kilowatthour, depending on projecttype, for electricity delivered to the grid [223]. The two programs have helped support robust growth in wind installations over the past several years, and installed wind capacity in the province has risen from 0.6 megawatts in 1995 to 1,457 megawatts in February 2011 [224]. Continued support from Canada’s federal and provincial governments—along with the sustained higherfossil fuel prices in the /EO2017 Reference case—is expected to provide momentum for the projected increase in the country's use of wind powerfor electricity generation. The combinedelectricity generation of Mexico and Chile increases by an average of 3.2 percent annually from 2008 to 2035—more than double the rate for Canada and almost quadruple the rate for the United States. In Mexico, the government has recognized the need for the country’s electricity infrastructure to keep pace with the fast-paced growth anticipated for electricity demand. In July 2007, the governmentunveiled its 2007-2012 National Infrastructure Program, which included plansto invest $25.3 billion to improve and expandelectricity infrastructure [225]. As part of the program, the government has set a goal to increase installed generating capacity by 8.6 gigawatts from 2006 to.2012 [226]. Natural-gas-fired generation in Mexico and Chile more than doubles in the Reference case, from 147billion kilowatthours in 2008 to 418 billion kilowatthours in 2035. With Mexico's government expected to implements plans to reduce the country's use of diesel and fuel oil for power generation [227], the country's demand for natural gas strongly outpaces growth in electricity production, leaving it dependent on pipeline imports from the United States and LNG from other countries. Currently, Mexico has one LNG import terminal, Altamira, operating on the Gulf Coast and another, Costa Azul, on the Pacific Coast. A contract tenderfor a third terminal at Manzanillo, also on the Pacific Coast, was awarded in March 2008, and the project is scheduled for completion by 2011 [228]. Chile also has beentrying to increase natural gas use for electricity generation in orderto diversify its fuel mix. In 2008, nearly 40 percent of the country's total generation came from hydropower, which can be problematic during times of drought. An unusually hot and dry summerin Chile in 2010-2011 has resulted in the country's worst drought in several decades and threatens power shortages [229]. The governmenthasinstituted emergency measures to ensure power supplies, launching a nationwide energy conservation program andalso increasing imports of LNG throughits two regasification terminals. Although Chile can import natural gas from Argentina through existing pipelines, supplies have not always beenreliable. Beginning in 2004, Argentina beganto restrict its gas exports to Chile because it was unable to meetits own domestic supplies, leading Chile to develop its LNG import capacity [230]. Mostof the renewable generation in Chile and Mexico comes from hydroelectric dams. Hydroelectric resources provide about 85 percentof the region's current renewable generation mix, with another 9 percent coming from geothermal energy. There are plans to expand hydroelectric powerin both countries in the future. In the /EO2017 Reference case, hydfoelectric poweraccounts for almost 75 percent of Mexico/Chile's total net generation from renewable energy sources in 2035. In Mexico, there are two major hydroelectric projects underway: the 750-megawatt La Yescafacility, scheduled for completion by 2012, and the planned 900-megawatt La Parota project, which has been delayed and may not be completed until 2018 [231]. in addition to efforts to diversify its electricity fuel mix, Chile has a numberof new hydroelectric plants planned or under construction. In October 2010, the 150-megawatt La Higuera and 158-megawatt La Confluencia hydro projects on the Tinguiririca River were completed [232]. The two run-of-river projects were constructedin a joint venture by Australia’s Pacific Hydro and Norway's SN PowerInvest. Pacific Hydro also has plans to construct another 650 megawatts of hydroelectric capacity on Chile's Upper Cachapoal River. Construction on the first phase of the development beganin 2009. Thefirst hydro plant in the system, the 111-megawatt Chacayes powerplant, is scheduled for completion in October 2011. The entire http://www.eia.gov/forecasts/ieo/electricity.cfm 7/9/2012 U.S. Energy Information Administration (EIA) Page 11 of 22 development should be completed in 2019, when the 78-megawatt Las Maravillas project is scheduled to begin operation [233]. Thereis virtually no wind orsolar generation in Mexico at present, but the Mexican government's goalofinstalling 2.5 gigawatts of wind capacity on the TehuantepecIsthmus by 2012 has encouraged wind developmentin the short term [234]. The 161-megawatt Los Vergelesproject and the OaxacaIl, Ill, and IV projects—totaling more than 300 megawatts—are due for completion in 2011 and 2012,respectively. In Baja California even larger projects are under development, such as the 1,200-megawatt Sempra and the 400-megawatt Union Fenosaprojects [235]. Further, Mexico's goal of reducing national greenhouse gas emissionsto 50 percentof 2002 levels by 2050 is expected to spur wind andsolarinstallations in the future [236]. Chile expandedits total installed wind capacity to 167 megawatts in early 2011 and has granted environmental approvalto an additional 1,500 megawatts of windprojects [237]. Still, the penetration of wind and solar generating capacity in Chile remains modest throughoutthe projection, with their share of Mexico and Chile's combinedtotal electricity generation rising from less than 0.1 percent in 2008 to 3 percent in 2035. OECD Europe Electricity generation in the nations of OECD Europeincreases by an average of 1.2 percent per year in the /EO2071 Reference case,from 3.4 trillion kilowatthours in 2008 to 4.8 trillion kilowatthours in 2035. Because mostof the countriesin OECDEurope haverelatively stable populations and mature electricity markets, most of the region's growth in electricity demandis expected to come from those nations with more robust population growth (including Turkey, Ireland, and Spain) and from the newest OECD members(including the Czech Republic, Hungary, Poland, and Slovenia), whose projected economic growth rates exceed the OECDaverage.In addition, with environmental concerns remaining prominentin the region, there is a concerted effort in the industrial sector to switch from coal andliquid fuelsto electricity. Figure 7&. OECD Europe netelectricity generation figure data byfuel, 2008-2035 ; itwson iiowasthours) Renewable energy is OECD Europe's fastest-growing sourceofelectricity generation in the Reference case (Figure 79), increasing by 2.5 percent per year through 2035. The increase is almostentirely from wind and solar. OECD Europe's leading position worldwide in wind power capacity is maintained through 2035, with growth in generation from wind sources averaging 6.4 percent per year, even though the Reference case assumes no enactmentof 15 Klugman Ligueiis 1.0 additional!legislation to limit greenhouse gas emissions. Strong growth in offshore wind capacity is underway, with 883 megawatts addedto the grid in 2010, representing a 51-percent increase over the amount of capacity added in 2009 [238]. 2008 «2015 20202025 20302035 The United Kingdom is expected to spearhead the growth in OECD Europe's offshore wind capacity. Although there is debate within the country over the costs and benefits of offshore wind power, the 300-megawatt Thanet Wind Farm,the world’s largest, was completed in September 2010 [239]. Workis also continuing on other majorprojects, including the 1,000-megawatt LondonArray, for which thefirst foundation waslaid in March 2011 [240]. The growth of nonhydropower renewable energy sources in OECD Europe is encouraged by someof the world's most favorable renewable energy policies. The European Unionset a binding target to produce 21 percentof electricity generation http://www.eia.gov/forecasts/ieo/electricity.cfm 7/9/2012 U.S. Energy Information Administration (EIA) Page 12 of 22 from renewable sources by 2010 [241] andreaffirmed the goal of increasing renewable energy use with its December 2008 "climate and energy policy,” which mandatesthat 20 percentof total energy production must come from renewables by 2020 [242]. Approximately 18 percent of the European Union's electricity came from renewable sources in 2008. The /EO2011 Reference case does not anticipatethat all future renewable energy targets in the European Union will be met on time. Nevertheless, current laws are expected to lead to the construction of more renewable capacity than would have occurredin their absence.In addition, some individual countries provide economic incentives to promote the expansion of renewable electricity. For example, Germany, Spain, and Denmark—the leaders in OECD Europe'sinstalled wind capacity— have enacted feed-in tariffs that guarantee above-market rates for electricity generated from renewable sources and, typically, last for 20 years after a project's completion. As long as European governments support such price premiumsfor renewable electricity, robust growth in renewable generationis likely to continue. Exceptionally generous feed-in tariffs have been falling out of favor in recent years, however. Before September 2008, Spain's solar subsidy led to an overabundanceof solar PV projects. When the Spanish feed-in tariff was lowered after September 2008, a PV supply glut or "solar bubble” resulted, driving downtheprice of solar panels and lowering profits throughoutthe industry [243]. The Spanish governmentis nowset to reduceits tariffs by a further 45 percent for large ground -basedsites, in view of the country's large public deficit and the fear of creating another solar bubble [244]. Germany has taken a similar approach andwill cut its feed-in tariff for ground PV units by 15 percent, effective in the summerof 2011 [245]. Italy, with the third-largest installed PV capacity in OECD Europe,is also loweringits solar feed-in tariff in June 2011, after experiencing a financially unsustainable 128-percent increase in solar PV output between November 2009 and November2010 [246]. Natural gas is the second fastest-growing source of power generation after renewables in the outlook for OECD Europe, increasing at an average rate of 1.8 percent per year from 2008 to 2035. Growth is projected to be more robust than the 1.3- percent annualincreasein last year's outlook, as prospects for the development of unconventional sourcesof natural gas in the United States and otherparts of the world help to keep world markets well supplied and globalpricesrelatively low. As a result, natural gas is more competitive in European markets in the /EO2017 Reference casethan it was in /EO2070. Before the Fukushima disaster in Japan, prospects for nuclear power in OECD Europe had improved markedly in recent years, and many countries were reevaluating their programs to considerplantlife extensions or construction of new nuclear generating capacity.In the aftermath of Fukushima, it appears that many OECD nations are reconsidering their plans. Although thefull extent to which European governments might withdraw their support for nuclear poweris uncertain, some countries already have reversedtheir nuclear policies. For example, the German government has announced plansto close all nuclear reactors in the country by 2022 [247]; the Swiss Cabinet has decided to phase out nuclear power by 2034 [248]; and Italian voters, in a country-wide referendum, haverejected plans to build nuclear powerplants in Italy [249]. In addition, the European Commission has announcedthatit will conduct a program of stress tests on nuclear reactors operating in the European Union. (Turkey, in contrast, has announcedthatit will proceed with construction of the country's first nuclear power plant [250].) Still, environmental concerns and the importance of energy security provide support for future European nuclear generation. With no phaseout of nuclear poweranticipated in the IEQO2011 Reference case, nuclear capacity in OECD Europe increases by a net 19 gigawatts from 2008 to 2035. Coal accounted for 25 percent of OECD Europe's netelectricity generation in 2008, but concerns about the contribution of carbon dioxide emissions to climate change could reduce that sharein the future. In the /EO20171 Reference case, electricity from coal slowly loses its prominence in OECD Europe,declining by 0.5 percent per year from 2008 to 2035 and ultimately falling behind renewables, natural gas, and nuclear energy as a source ofelectricity. Coal consumptionin the electric power sector is not decreasing uniformly in all countries in OECD Europe, however. Spain's Coal Decree, which wentinto force in February 2011, subsidizes the use of domestic coal in Spanish powerplants. The policy is expected to result in more electricity generation from coal-fired plants at least through 2014, when the subsidy is scheduled to expire [251]. http://www.ela.gov/forecasts/ieo/electricity.cfm 7/9/2012 U.S. Energy Information Administration (EIA) Page 13 of 22 OECDAsia Total electricity generation in OECD Asia increases by an averageof 1.2 percent per yearin the Reference case, from 1.7 trillion kilowatthours in 2008 to 2.4 trillion kilowatthours in 2035. Japan accountedfor the largest share ofelectricity generation in the region in 2008 and continuesto do so throughoutthe projection period, despite having the slowest-growing electricity market in the region and the slowest among all OECD countries, averaging 0.8 percent per year, as compared with 1.3 percent per year for Australia/New Zealand and 2.0 percent per year for South Korea (Figure 80). Japan's electricity markets are well established, andits aging population andrelatively slow projected economic growth translate into slow growth in demandforelectric power. In contrast, Australia/New Zealand and South Korea are expected to see more robust economic growth and population growth, leading to more rapid growth in demand forelectricity. ; figure data Figure 80. OECD Asia net electricity generation by fuel, 2008-2035 {irilion kilowatihours} The fuel mix for ele ctricity generation varies widely among the three economies that make up the OECD Asia region. In Japan, natural gas, coal, and nuclear SE! santero, | power make upthe bulkof the current electric power Auswalia/NewZealand ° mix, with natural gas and nuclear accounting for about 51 percentof total generation and coal another 26 percent. The remaining portion is split between renewables and petroleum-basedliquid fuels. Japan's reliance on nuclear powerincreases over the projection period, from 24 percentof total generation in 2008 to 33 percent in 2035. The natural gas share of generation declines slightly over the sameperiod, from 27 percent to 26 percent, and coal's share declines to 18 percent, being displaced by nuclear and renewable energy sources. 15 - aH] pec tyapapeeings rrceee wescceseccaccciem Meerbeinititir 19 G5 :. . E 6 A 2608 2015 2020 26025 2030 2035 On March 11, 2011, a devastating, magnitude 9.0 earthquake,followed by a tsunami, struck northeastern Japan, resulting in extensivelossoflife and triggering a nuclear disaster at the Fukushima Daiichi nuclear powerplants. At present, it is impossible to assess the ultimate impact on Japan's nuclear program, and /EO2011 makesno attemptto incorporate the ultimate effects of the earthquakein the Reference case. In the immediate aftermath of the earthquake, reactors at Japan's Fukushima Daini and Onagawa nuclear facilities were successfully shut down, and theywill not be returned to operation until they have undergonestringent safety reviews [252]. The six reactors at Fukushima Daiichi were damaged beyondrepair, removing of 4.7 gigawatts of generating capacity from the grid. Although power had beenrestored in mostof the affected areas by June 2011, the temporary and permanentlosses of nuclear powercapacity from Japan's electricity grid (in addition to a substantial amountof coal-fired capacity that also remains shut down)will makeit difficult for power generators to meet demand in the summer months of 2011 (June, July, and August), whenelectricity consumptiontypically is very high [253]. Currently, Japan is reconsidering its electricity supply policies. In May, Prime Minister Naoto Kan statedthat the plan to increase the nuclear powershare of the country’s electricity supply, from about 26 percent at present to 50 percent by 2030, "will have to be set aside” [254]. Instead, the governmentplans to pursue an aggressive expansion of renewable energy capacity, especially solar power. Japan generates only about 6 percent ofits primary energy from renewable energy sources (including hydroelectricity), but governmentpolicies and incentives to increase solar powerwill improve the growth of the energy sourcein the future. In the /EO02011 Referencecase, electricity generation from solar energy increases by 11.5 percentper year from 2008 to 2035, making solar power Japan'sfastest-growing source of renewable energy (althoughit starts from a negligible amountin 2008). In November 2009, the governmentinitiated a feed-in tariff incentive to favor the developmentof solar power [255]. Wind-powered generation in Japan also increases strongly in the Reference case, by an average of 8.1 percent per year. In the wake of the nuclear disaster,it is likely that additional governmentincentives for http://www.eia.gov/forecasts/ieo/electricity.cfm 7/9/2012 U.S. Energy Information Administration (EIA) Page 14 of 22 renewable energy sourceswill follow. Both solar and wind power, however, remain minor sources ofelectricity, supplying 3 percent and 2 percentof total generation in 2035, respectively, as compared with hydropower's 8-percent share ofthetotal. Australia and New Zealand, as a region, rely on coalfor about 66 percentofelectricity generation, based largely on Australia's rich coal resource base (9 percent of the world's total coal reserves). The remaining regional generationis supplied by natural gas and renewable energy sources—mostly hydropower, wind, and, in New Zealand, geothermal. Australia continues to make advancesin wind energy, with 1,712 megawatts of capacity installed at the end of 2009 anda further 588 megawatts under construction [256]. To help meetits 2025 goal of having 90 percent of electricity generation come from renewable sources, New Zealandis focusing on harnessing moreof its geothermal potential [257]. Construction of the 250-megawatt TauharaII project, currently underreview by the country's Environmental Protection Authority, would alone powerall the homesin the Wellington metro area [258]. The Australia/New Zealandregion uses negligible amounts of oil for electricity generation and no nuclear power, andthat is not expected to changeoverthe projection period. Natural-gas- fired generation is expected to grow strongly in the region, at 4.0 percent per year from 2008to 2035, reducing the coal share to 39 percentin 2035. In South Korea, coal and nuclear powercurrently provide 42 percent and 34 percentoftotal electricity generation, respectively. Natural-gas-fired generation grows quickly in the Reference case, but despite a near doubling of electricity generation from natural gas, its share of total generation increases only slightly, from 19 percent in 2008 to 21 percentin 2035. Coal and nuclear powercontinue to provide most of South Korea's electricity generation, with a combined 73 percent of total electricity generation in 2035. Non-OECDelectricity Non-OECD Europe and Eurasia Total electricity generation in non-OECD Europe and Eurasia grows at an averagerate of 1.4 percent per year in the 1EO2011 Reference case, from 1.6 trillion kilowatthours in 2008 to 2.3 trillion kilowatthours in 2035. Russia, with the largest economy in non-OECD Europe and Eurasia, accounted for about 60 percent of the region's total generation in 2008 andis expected to retain approximately that share throughoutthe period (Figure 81). Figure 81. Non-OECD Europe and Eurasia electricity figuredata generation by region, 2008-2035 Arilion Mlovestthours) Natural gas and nuclear power supply muchof the growthin electricity generation in the region. Although non-OECD Europe and Eurasia has nearly one-third of the world's total proved natural gas reserves, some countries (notably, Russia) plan to export natural gas instead of usingit to fuel electricity generation. As a result, the region's natural-gas-fired generation grows modestly in the outlook, at an averagerate of 0.7 percent from 2008 to 2035. a0 o5 Generation from nuclear powergrowsstrongly in the region, averaging 3.0 percent per year. Much of the increase is expected in Russia, which continues to shift generation from natural gas to nuclear, because natural gas exports are more profitable than the domestic use of natural gas for electricity generation. oe E.. ge st a Ly as BONG. 2015 2020 2025 20530 2035 http://www.eia.gov/forecasts/ieo/electricity.cfm 7/9/2012 U.S. Energy Information Administration (EIA) Page 15 of 22 In 2006, the Russian governmentreleased Resolution 605, which set a federal target program (FTP) for nuclear power development. Although the FTP was updated andscaled backin July 2009 as a result of the recession, 10 nuclear power reactorsstill are slated for completion by 2016, adding a potential 9 gigawatts of capacity. According to the Russianplan, another 44 reactors are to be constructed, increasing Russia's total nuclear generating capacity to 42 gigawatts by 2024. By 2030, the plan would bring the total to nearly 50 gigawatts and increase nuclear generation to 25 or 30 percentoftotal generation. In January 2010, the Russian government approved an FTPthat wouldshift the focus of the nuclear power industry to fast reactors with a closed fuel cycle. Life extensions have been completedfor roughly 30 percentof Russia's operating reactors, and the installed capacity of most reactors has been uprated [259]. In the /E02071 Reference case, Russia's existing 23 gigawatts of nuclear generating capacity is supplemented by a nettotal of 5 gigawatts in 2015 and another 23 gigawatts in 2035. Renewable generation in non-OECD Europe and Eurasia, almostentirely from hydropowerfacilities, increases by an average of 1.9 percent per year, largely as a result of repairs and expansionsat existing sites. The repairs include reconstruction of turbines in the 6.4-gigawatt Sayano-Shushenskaya hydroelectric plant, which was damaged in an August 2009 accident [260]. Four of the plant's 640-megawatt generators are currently operational, and full restoration of the dam is expected to be completed by 2014 [261]. Notable new projects include the 3-gigawatt Boguchanskaya Hydroelectric Power Station in Russia and the 3.6-gigawatt Rogun Dam in Tajikistan. Construction of the Boguchanskayastation began in 1980, and work wasstarted on Rogun in 1976. However, work on both projects ceased when the former Soviet Union experienced economicdifficulties in the 1980s. Despite the recent recession, construction continues on Boguchanskaya, whichis on track for completion by 2012 [262]. Although Tajikistan’s president announced in May 2008 that construction work on Rogun Dam had resumed, its prospects are less favorable [263]. Neighboring Uzbekistan strongly opposes the dam, fearing thatit will reduce the water supply that supports the Uzbek cotton industry [264]. Furthermore, only $200 million of the $4 billion needed to complete the hydroelectric plant has been raised so far, enough to support the construction workfor just 2 more years [265]. Otherthan increases in hydropower, only modest growth in renewable generation is projected for the nations of non-OECD Europe and Eurasia, given the region's accessto fossil fuel resources and lack of financing available for relatively expensive renewable projects.In the /EO2011 Reference case, nonhydropower renewable capacity in the region increases by only 5 gigawatts from 2008 to 2035. Although total growth in nonhydropowerrenewable generationis projected to be small, Romania is one nation in the region that is moving ahead with wind energy projects:its 348-megawatt Fantanele wind farm is on track to be completed in late 2010, and the nearby Cogealac wind farm (253 megawatts) is due for commissioning in 2011 [266]. Non-OECDAsia Non-OECD Asia—led by China and India—hasthe fastest projected growth rate for electric power generation worldwide, averaging 4.0 percent per year from 2008 to 2035 in the Reference case. Although the global economic recession had an impact on the region's short-term economic growth, the economies of non-OECDAsia haveled the recovery and are projected to expand strongly in the long term, with corresponding increases in demandforelectricity in both the building and industrial sectors. Total electricity generation in non-OECD Asia grows by 49 percent, from 5.0 trillion kilowatthours in 2008 to 14.3 trillion kilowatthours in 2035, with electricity demand increasing by 46 percent from 2015 to 2025 and by another 32 percent from 2025 to 2035.In 2035, net electricity generation in non-OECDAsia totals 14.3 trillion kilowatthoursin the Reference case. Non-OECDAsia is the world's fastest-growing regional market for electricity in /EO2077, accounting for 41 percent of world electricity generation in 2035. Coalis used to fuel more than two-thirds of electricity generation in non-OECDAsia (Figure 82), led by coal-fired generation in China and India. Both countries rely heavily on coal to produce electric power. In 2008, coal's share of generation was an estimated 80 percent in China and 68 percent in India. Underexisting policies, it is likely that coal will remain the predominant source of power generation in both countries. In the |EO2011 Reference case,coal's shareof electricity generation declines to 66 percent in China and 51 percentin India in 2035. http://www.eia.gov/forecasts/ieo/electricity.cfm 7/9/2012 USS. Energy Information Administration (EIA) Page 16 of 22 oo figure data Figure 82. Non-OECD Asia netelectricity generation by fuel, 2008-2035 . ow. . . tition Miowatthours} At present, China is installing approximately 900 megawatts of coal-fired capacity (equivalent to one 10 large coal-fired powerplant) per week. However,it also has beenretiring old, inefficient plants to help 8 Nuies ee slow the rate of increasein the nation's carbon Linuids intensity. From 2006 to 2010, China retired almost 71 6. gigawatts of coal-fired capacity, including 11 gigawatts in 2010, andit plansto retire an additional 8 gigawatts in 2011 [267]. Non-OECDAsia leadsthe worldin installing new nuclear capacity in the /E02011 Reference case, accounting for 54 percent of the net incrementin _ = nuclear capacity worldwide (or 144 gigawatts of the 2008 2015 a02G 2025 20300 2085 total 266-gigawatt increase). China, in particular, has ambitious plans for nuclear power, with more than 27 nuclear powerplants currently under construction and a total of 106 gigawatts of new capacity expected to be installed by 2035. Thereis significant uncertainty in the /EO2011 Reference case projections for China's nuclear capacity. Officially, China's nuclear capacity targets are 70 to 86 gigawatts by 2020 and 200 gigawatts by 2030—targets that the Chinese government has beenincreasing since 2008, whenthe target was 40 gigawatts by 2020 [268]. Factors that may cause China to undershootits official targets inciude limited global capacity of heavy forging facilities required for the manufacture of Generation Ill reactor components and potential difficulties in training the large numberof engineers and regulators needed to operate and monitorthe planned powerplants. On the other hand, an estimated 226 gigawatts of new capacity has advanced beyondthe pre-feasibility study phase,including reactors in at least 20 provincesthat are not approvedfor the national plan [269]. The impact of the March 2011 disaster at Japan's Fukushima Daishi nuclear powerplant may also have a negative impact on the pace of China's nuclear power program. In the aftermath of the disaster, China announced it would halt approval processesfor all new reactors until the country's nuclear regulator completes a “thorough safety review"—a processthat could last for as long as a year[270]. The /EO2011 Reference case assumesthat the global lack of heavy forgingfacilities and the long lead times neededto build or upgrade forging facilities, build new nuclear powerplants, and train new personnelwill cause China's nuclear power industry to grow moreslowly thanin official government predictions. Nonetheless, the 115 gigawatts of nuclear capacity projected for 2035 is a 53-percent increase overlast year's Reference case. In the /EO2011 Reference case, the nuclear share of China’stotal electricity generation increases from 2 percent in 2008 to 10 percentin 2035. India also has plans to boostits nuclear power generating capacity. From 4 gigawatts of installed nuclear power capacity in operation in 2011, India has set an ambitious goalof increasing its nuclear generating capacity to 20 gigawatts by 2020 and to as much as 63 gigawatts by 2032 [271]. Currently, five nuclear reactors are under construction, three of which are scheduled for completion by the end of 2011 [272]. The /EO2011 Reference case assumesa slowerincrease in nuclear capacity than anticipated by India’s government, to 16 gigawatts in 2020 and 28 gigawaitts in 2035. In addition to China and India, several other countries in non-OECDAsia are expected to begin or expand nuclear power programs.In the Reference case, new nuclear powercapacityis installed in Taiwan, Vietnam, Indonesia, and Pakistan by 2020. Concerns about security of energy supplies and greenhouse gas emissions lead manynationsin the region to diversify their fuel mix for power generation by adding a nuclear component. http://www.eia.gov/forecasts/ieo/electricity.cfm 7/9/2012 U.S. Energy Information Administration (EIA) Page 17 of 22 Electricity generation from renewable energy sources in non-OECDAsia growsat an average annualrate of 4.9 percent, increasing the renewable share ofthe region's total generation from 17 percent in 2008to 21 percent in 2035. Small-, mid-, and large-scale hydroelectric facilities all contribute to the projected growth. Several countries in non-OECDAsia have hydropowerfacilities either planned or underconstruction, including Vietnam, Malaysia, Pakistan, and Myanmar(the former Burma). Almost 50 hydropowerfacilities, with a combined 3,398 megawatts capacity, are under construction in Vietnam's Son La province,including the 2,400-megawatt Son La and 520-megawatt Houi Quangprojects, both of which are scheduled for completion before 2015 [273]. The remaining facilities are primarily micro- and mini-hydroelectric powerplants. Malaysia expects to complete its 2,400-megawatt Bakun Dam bythe end of 2011, although the project has experienced delays and setbacksin the past [274]. Pakistan and Myanmaralso have substantial hydropower developmentplans,but those plans have been discountedin the 1EO2011 Reference caseto reflect the two countries’ historicaldifficulties in acquiring foreign direct investment for infrastructure projects. Pakistan's electricity developmentplans have beenfurther hampered by floods that occurred in 2010; powerplants that had been in need of refurbishment are now severely damaged or destroyed [275]. Nearly 150 of the 200 small hydroelectric plants in the northern Khyber-Pakhtunkhwaprovince were destroyed bythe floods and may take years to rebuild [276]. India has plans to more than doubleits installed hydropower capacity by 2030.In its Eleventh and Twelfth Five-Year Plans, which span 2008 through 2017,India's Central Electricity Authority has identified nearly 41 gigawatts of hydroelectric capacity thatit intends to build. Nearly one-half of the planned capacity is to be built in the Uttarakhand region. However, environmental concerns recently led to the rejection of two proposed projectsin the region, totaling 860 megawatts, which underscores the uncertainty associated with estimating India's future hydroelectric development. Despite $150 million already invested in the 600-megawatt Loharinag Pala project, construction on the project has also been halted, and its future is uncertain [277]. Although the /EO2011 Reference case does not assumethatall the planned capacity will be completed, more than one-third of the announced projects are underconstruction already and are expected to be completed by 2020 [278]. Like India, China has manylarge-scale hydroelectric projects under construction. Thefinal generatorfor the 18.2-gigawatt Three Gorges Dam project went on line in October 2008, and the Three Gorges Project Development Corporation plans to increasethe project's total installed capacity further, to 22.4 gigawatts by 2012 [279]. In addition, work continues on the 12.6- gigawatt Xiluodu project on the Jinsha River, which is scheduled for completion in 2015 as part of a 14-facility hydropower developmentplan [280]. China also has the world’s second-tallest dam (at nearly 985 feet) currently under construction, as part of the 3.6-gigawatt Jinping | project on the Yalong River. The dam scheduled for completion in 2014 as part of a plan by the Ertan Hydropower Development Companyto construct 21 facilities with 29.2 gigawatts of hydroelectric capacity on the Yalong [281]. The Chinese governmenthasset a 300-gigawatt target for hydroelectric capacity in 2020.Including those mentioned above, the country has a sufficient number of projects under construction or in developmentto meetthe target. China's aggressive hydropowerdevelopmentplan is expected to increase hydroelectricity generation by 3.2 percent per year, more than doubling the country's total hydroelectricity generation by 2035. Although hydroelectric projects dominate the renewable energy mix in non-OECDAsia, generation from nonhydroelectric renewable energy sources, especially wind, also is expected to grow significantly. In the IEO2011 Referencecase,electricity generation from wind plants in China grows by 14.2 percentperyear, from 12 billion kilowatthours in 2008 to 447billion kilowatthours in 2035. In addition, governmentpolicies in China and India are encouraging the growthof solar generation. Underits "Golden Sun" program, announcedin July 2009,the Chinese Ministry of Finance plansto subsidize 50 percentof the construction costs for grid-connected solar plants [282]. India’s National Solar Mission, launched in November2009, aims to have 20 gigawatts ofinstalled solar capacity (both PV and solar thermal) by 2020, 100 gigawatts by 2030, and 200 gigawatts by 2050 [283]. India’s targets have been discounted in the /EO2017 Reference case becauseofthe substantial uncertainty about the future of government-provided financial incentives [284]. However,the policies do support robust http://www.eia.gov/forecasts/ieo/electricity.cfm 7/9/2012 U.S. Energy Information Administration (EIA) Page 18 of 22 growth ratesin solar generation for China andIndia, at 22 percent per year and 28 percentperyear, respectively, in the Reference case. Measuring the growth of China's wind capacity has proven difficult as the numberof wind farms rapidly expands. According to the Chinese Renewable Energy Industry Association (CREIA), the country had 41.8 gigawatts of installed wind capacity at the end of 2010 [285]. The National Energy Administration and the Chinese Electricity Council, however, report only 31 ‘A gigawatts of wind capacity connectedto the electricity grid at the end of 2010. The discrepancy betweenthe two figures is a result of the inability of some local grids to absorb wind-generatedelectricity, a lack of long-distance transmission lines [286], and policies (now superseded) that encouraged construction of wind capacity instead of generation of electricity. The /EO2011 Reference case assumesthat China had 31.1 gigawatts of wind capacity installed at the end of 2010. Although geothermalenergy is a small contributor to non-OECDAsia'stotal electricity generation, it plays an important role in the Philippines and Indonesia. With the second-largest amountofinstalled geothermal capacity in the world, the Philippines generated almost 16 percentofits total electricity from geothermal sourcesin 2010 [287]. Indonesia, with the world's third- largest installed geothermal capacity, plans to have 3.9 gigawatts of capacity installed by 2014 [288] and 9.5 gigawatts by 2025 [289]. However, those goals are discounted in the Reference casein view ofthe long lead times and high exploration costs associated with geothermal energy. Middle East Electricity generation in the Middle East region grows by 2.5 percentper yearin the Reference case,from 0.7 trillion kilowatthours in 2008 to 1.4 trillion kilowatthours in 2035. The region's young and rapidly growing population, along with a strong increasein national income,is expected to result in rapid growth in demandforelectric power. Iran, Saudi Arabia, and the United Arab Emirates (UAE) account for two-thirds of the region's demandforelectricity, and demand has increased sharply over the past several years in each of those countries. From 2000to 2008, Iran's net generation increased by an average of 7.5 percent per year, Saudi Arabia's by 6.2 percent per year, and the UAE's by 10.1 percentper year. The Middle East depends on natural gas and petroleum liquid fuels to generate mostofits electricity and is projected to continue that reliance through 2035, although liquids-fired generation declines over the projection period and thus loses market shareto natural-gas-fired generation (Figure 83). In 2008, natural gas supplied 59 percentofelectricity generationin the Middle East and liquid fuels 35 percent. In 2035, the natural gas share is projected to be 75 percent and theliquid fuels share 14 percent. There has been a concerted effort by many of the petroleum exportersin the region to develop their natural gas resourcesfor use in domestic power generation. Petroleum is a valuable export commodity for many nationsin the Middle East, and there is growing interest in the use of domestic natural gas for electricity generation in order to make more oil assets available for export. figure data Other energy sources make only minor contributions to electricity supply in the Middle East. Israelis the only country in the region that uses significant amounts of coal to generate electric power [290], and Iran and the UAEare the only ones projected to add nuclear capacity. Iran's 1,000-megawatt Bushehrreactor is scheduled to begin operating in 2011, althoughit has faced repeated delays, the latest being the detection of metalparticles in the nuclearfuel rods, with the result that the fuel had to be unloaded and tested for possible contamination [291]. In December 2009, the Emirates Nuclear Energy Corporation (ENEC)in the UAE selected a South Korean consortium to build four nuclear reactors, with construction planned to begin in 2012 [292]. ENECfiled construction license applicationsfor the first two units in December 2010, andit plansto haveall four units operational by 2020 [293]. In addition to Iran and the UAE, several other Middle Eastern nations have announcedintentions in recent years to pursue nuclear power programs.In 2010, the six-nation Gulf Cooperation Council*! entered into a contract with U.S.-based Lightbridge Corporation to assess regional cooperation in the development of nuclear powerand desalination programs [294]. Jordan also has announcedits intention to add nuclear capacity [295], and in 2010 Kuwait's National Nuclear Energy http://www.cia.gov/forecasts/ieo/electricity.cfm 7/9/2012 U.S. Energy Information Administration (EIA) Page 19 of 22 ei @3. Middle E t electricity tion Committee announced plansto build four reactors by igure 83, Middle East net electricity generation by ; . . fuel, 2008-2035 2022 [296]. Even given the considerable interest in irilion winveatthours) nuclear powerin the region, however, given the 1a economic andpolitical issues and long lead times usually associated with beginning a nuclear program, the only reactors projected to be built in the Middle East in the /EO2011 Reference casearein Iran and the UAE. Muchear Coal OB Liguigs— Several Middle Eastern countries recently have expressed someinterest in increasing coal-fired aad generation in response to concerns about diversifying the electricity fuel mix and meeting the region's fast- paced growthin electricity demand. For example, Oman announcedin 2008that it would construct the Persian Gulfsfirst coal-fired power plant at Duqm [297]. According to the plan, the 1-gigawatt plantwill be fully operational by 2016, powering a water desalinization facility [298]. The UAE, Saudi Arabia, 2005 2018 2020 2025 2030 2035 and Bahrain also have considered building coal-fired capacity [299]. Althoughthereis little economic incentive for countries in the Middle East to increase their use of renewable energy sources (the renewable share of the region's total electricity generation increases from only 1 percent in 2008 to 5 percentin 2035in the Reference case), there have been some recent developments in renewable energy usein the region. Iran, which generated 10 percentofits electricity from hydropowerin 2010, is adding approximately 4 gigawatts of new hydroelectric capacity, even after the droughts of 2007 and 2008 reduced available hydroelectric generation by nearly 75 percent [300]. Although development of Abu Dhabi's MasdarCity project has been slowed by the current global economic environment [301], the governmentstill plans to meetits 2020 goal of producing 7 percentof its energy from renewable sources. Solar poweris expected to meet the vast majority of that goal, including two 100-megawatt solar powerplants that Masdar Power plans to build [302]. Africa - figure data Figure 84. Net electricity generation in Africa by fuel, 2008-2035 a . itratian Klowerttho ors) Demandforelectricity in Africa grows at an average 06 annualrate of 3.0 percent in the /EO2017 Reference case. Fossil-fuel-fired generation supplied 81 percent of the region'stotal electricity in 2008, and reliance on fossil fuels is expected to continue through 2035. Coal -fired power plants, which were the region's largest sourceof electricity in 2008, accounting for 41 percent of total generation, provide a 33-percent sharein 2035; and natural-gas-fired generation expands strongly, from 29 percent of the total in 2008 to 45 percent in 2035 (Figure 84). Peep|gigi nncrrnannannang 04 Liquids O.2 At present, South Africa's two nuclear reactors are the only commercial reactors operating in the region, accounting for about 2 percentof Africa's total electricity generation. Although the construction of a 2008 2015 2020 2025 2030 2035 http://www.eia.gov/forecasts/ieo/electricity.cfm 7/9/2012 U.S. Energy Information Administration (EIA) Page 20 of 22 new Pebble Bed Modular Reactor in South Africa has been canceled, the South African government's Integrated Electricity ResourcePlancalls for another 9.6 gigawatts of nuclear capacity to be built by 2030 [303]. In addition, in May 2009, Egypt's government awarded a contract to Worley Parsonsfor the construction of a 1,200-megawatt nuclear powerplant. Although original plans were for oneunit, current plans call for four units, with thefirst plant to be operational in 2019 and the others by 2025 [304]. In the Reference case, 2.3 gigawatts of net nuclear capacity becomes operationalin Africa over the 2008-2035 period, although only South Africa is expected to complete construction of any reactors. The nuclear share of the region's total generation remains at 2 percent in 2035. Generation from hydropowerand other marketed renewable energy sources is expected to growrelatively slowly in Africa. Plansfor several hydroelectric projects in the region have been advancedrecently, and they mayhelp to boost supplies of marketed renewable energy in the mid-term. Several (although notall) of the announced projects are expected to be completed by 2035,allowing the region's consumption of marketed renewable energy to grow by 2.9 percent per year from 2008 to 2035. For example, Ethiopia finished workon two hydroelectric facilities in 2009: the 300-megawatt Takeze power station and the 420-megawatt Gilgel GibeII [305]. A third plant, the 460-megawatt Tana Beles, was completed in 2010 [306]. Central and South America Electricity generation in Central and South America increases by 2.4 percent per year in the /E02077 Reference case,from 1.0 trillion kiiowatthours in 2008to 1.9 trillion kilowatthours in 2035. The fuel mix for electricity generation in Central and South America is dominated by hydroelectric power, which accounted for nearly two-thirds of the region's total net electricity generation in 2008. Ofthe topfive electricity-generating countries in the region, three—Brazil, Venezuela, Paraguay— generate more than 70 percentoftheir total electricity from hydropower. _ . og . figure data Figure £5, Net alectricitygeneration in Brazil by fuel, 2008-2035 . | Aritior: Klawalthours} In Brazil, the region's largest economy, hydropower provided more than 80 percentofelectricity generation in 2008 (Figure 85). The country has been trying to diversify its electricity generation fuel mix away from hydroelectric power becauseofthe risk of powershortages during times of severe drought. In the Brazilian National Energy Plan for 2010-2019, the Liquidig——ny a4 governmentset a goal to build 63 gigawatts of installed capacity, with nonhydroelectric capacity making up the majority of additions [307]. To help a2 achieve that target, the government has announced plans to increase nuclear powercapacity, beginning with the completion of the long-idled 1.3-gigawatt Angra-3 project [308]. Construction resumed in June 2010, and Angra-3 is expected to be operational at the end of 2015 [309]. Brazil also has plansto construct four new 1-gigawatt nuclear plants beginning in 2015.In the /E02011 Reference case, the Angra-3 project is completed by 2015, and three more planned nuclear projects are completed by 2035. inns | 2008 2015 2020 2025 2020 2035 In the past, the Brazilian governmenthas tried (with relativelylittle success) to attract substantial investmentin natural-gas- fired powerplants.Its lack of success has beenattributed mainly to the higher costs of natural-gas-fired generationrelative to hydroelectric power, and to concerns about the security of natural gas supplies. Brazil has relied on imported Bolivian natural gas for muchofits supply, but concerns about the impactof Bolivia's nationalization of its energy sector on foreign investment in the country's natural gas production has led Brazil to look toward LNG imports for secure supplies. Brazil has invested strongly in its LNG infrastructure, and its third LNG regasification plant is scheduled for completion in 2013 [310]. http://www.eia.gov/forecasts/ieo/electricity.cfm 7/9/2012 U.S. Energy Information Administration (EIA) Page 21 of 22 With Brazil diversifying its natural gas supplies, substantially increasing domestic production, and resolving to reduce the hydroelectric share of generation, natural gas is projectedto beits fastest-growing sourceofelectricity, increasing by 8.7 percent per year on average from 2008 to 2035. Brazil still has plans to continue expandingits hydroelectric generation over the projection period, including the construction of two plants on the Rio Madeira in Rondonia—the 3.2-gigawatt Santo Antonio and the 3.3-gigawatt Jirau hydroelectric facilities. The two plants, with completion dates scheduled for 2012-2013, are expected to help Brazil meet electricity demand in the mid-term [311]. In the long term, electricity demand could be met in part by the proposed 11.2-gigawatt Belo Monte dam, which was given approvalfor construction in April 2010 [312]. Each of the three projects could, however, be subject to further delay as a result of legal challenges. Brazil is also interested in increasing the use of other, nonhydroelectric renewable resourcesin the future—notably, wind.In December2009, Brazil held its first supply tender exclusively for wind farms. At the event, 1.8 gigawatts of capacity were purchased, for development by mid-2012 [313]. The first signs of wind developmentare now taking place, with a purchase contract already signed for the 90-megawatt Brotas wind farm, which is scheduled for completion in 2011 [314]. In the 1EO2011 Reference case, wind power generation in Brazil grows by 10.8 percent per year, from 530 million kilowatthours in 2008 to 8,508 million kilowatthours in 2035. Despite that robust growth, however, wind remains a modest componentof Brazil's renewable energy mix in the Reference case, as compared with the projected growth in hydroelectric generation to 792 billion kilowatthours in 2035. figure data Figure 86. Other Central and South America net electricity generationbyfuel, 2008-2035 In the /EO2011 Reference case, natural-gas-fired generation and hydroelectric generation are expected to dominate the electric power sector in Central and South America (excluding Brazil), increasing from 73 percentoftotal electricity generation in 2008 to 79 percent in 2035 (Figure 86). However, some countries in the region have a more diversefuel mix. Argentina, for example, generated 6 percentofits electricity from its two nuclear powerplants in 2008. Although construction of a third reactor, Atucha 2, was suspendedin 1994, the 692-megawattfacility is scheduled to be completed by the end of 2011 [315]. 0.5 0.3 DP rene OF Many countries in Central and South America are continuing their attempts to increase the role of natural gasin the electricity mix to prevent blackouts, zooa | 2015 2020 | 2025 2030 caused by a combination of surging electricity demand and droughts that decrease generation from hydroelectric sources. Argentina, which experienced repeated power outages from December20 through 31 in the summerof 2010, continues to increase LNG imports. The Argentine government has announcedplansto build an import terminal outside BuenosAires by 2012 and has signed a dealto import up to 706 million cubic feet of LNG from Qatar through another new terminal in Rio Negro province [316]. Venezuela has also committed to increasing its use of natural gas for electricity generation to both reduce the nation's heavy reliance on hydroelectricity and to meetfast-paced growth in electricity demand. At present, hydroelectricity accounts for around 63 percent of Venezuela's total installed generating capacity. In 2010, an extremely hot and dry summer reduced available hydroelectric generation so much that the country wasforced to ration electricity [317]. The rationing program was suspendedon July 30, 2010 asrainfall returned reservoir levels at the Guri hydroelectric plant approached more normal levels. However, despite the government's aggressive investment in powersectorinfrastructure improvements overthe past twoyears,electricity demand has continued to outpace the growth in generating capacity [318]. Venezuela once again began to experience widespread power http://www.eia.gov/forecasts/ieo/electricity.cfm 7/9/2012 U.S. Energy Information Administration (EIA) Page 22 of 22 outages beginning in March 2011 and in June the government announcedit would reinstate electricity rationing in an attempt to reduceelectricity demandin addition to continuing to invest in generating capacity increases. http://www.eia.gov/forecasts/ieo/electricity.cfm 7/9/2012 DOE/EIA-0560(98) Natural Gas 1998 Issues and Trends April 1999 Energy Information Administration Office of Oil and Gas U.S. Department of Energy Washington, DC 20585 This publication is on the Webat: http:/Awww.eia.doe.gov/oil_gas/natural_gas/analysis_publications/ naturalgas_1998issues_and_trends/it98.html This report was prepared by the Energy Information Administration, the independentstatistical and analytical agency within the Department of Energy. The information contained herein should not be construed as advocating or reflecting any policy position of the Dep artmentof Energy or any other organization. Preface Natural Gas 1998: Issues and Trends provides a summary of the latest data and information relating to the U.S. natural gas industry, including prices, production, transmission, consumption, and the financial and environmental aspects of the industry. The report consists of seven chapters and five appendices. Chapter | presents a summary of various data trends and key issues in today’s natural gas industry and examines someofthe emerging trends. Chapters 2 through 7 focus on specific areas or segments of the industry, highlighting someofthe issues associated with the impact of natural gas operations on the environment. Unless otherwise stated, historical data on natural gas production, consumption, and price through 1997 are from the Energy Information Administration (EIA) publication, Natural Gas Annual 1997, DOE/EIA-0131(97) (Washington, DC, November 1998). Similar annual data for 1998 and monthly data for 1997 and 1998 are from EIA, Natural Gas Monthly (NGM), DOE/EIA-0130 (99/02) (Washington, DC, February 1999). Natural Gas 1998: Issues and Trends was prepared by the Energy Information Administration, Office of Oil and Gas, Kenneth A. Vagts, Director (202/586-6401). General information concerning this report may be obtained from Joan E. Heinkel, Director of the Natural Gas Division (202/586-4680). Questions on specific sections of the report may be addressedto the following analysts: @ Chapter 1. “Overview,” James Tobin (202/586-4835). @ Chapter2. “Natural Gas and the Environment,” Robert F, King (202/586-4787). e Chapter 3. “Future Supply Potential of Natural Gas Hydrates,” David F. Morehouse (202/586-4853). @ Chapter 4. “Offshore Development and Production,” William A. Trapmann (202/586-6408). @ Chapter 5. “Natural Gas Pipeline Network: Changing and Growing,” James Tobin (202/586-4835). e Chapter 6. “Contracting Shifts in the Pipeline Transportation Market,” Barbara Mariner-Volpe (202/586-5878). @ Chapter 7. “Mergers and Other Corporate Combinationsin the Natural Gas Industry,” William A. Trapmann (202/586-6408). The overall scope and content of the report was supervised by James Tobin. Significant analytical contributions were made by the following individuals: Mary E. Carlson—Chapters | and 6 Michael J. Elias—-Chapter 1 William R. Keene—Chapter 7 James P. O’Sullivan—Chapter 6 Philip Shambaugh—Chapters 2 and 6 Michael J. Tita—Chapters I and 6 James Thompson—Chapter | James Todaro—Chapters 1 and 2 Lillian (Willie) Young—Chapter1. Editorial support was provided by Willie Young. Desktop publishing support was provided by Margareta Bennett. Energy Information Administration Natural Gas 1998: Issues and Trends iti Contents Page Executive Summary ..........00. 00.cneen nn nen tenet terete es Xi 1. Overview 2.0...eeeee ee ete een enn ene 1 Wellhead and Spot Market Prices... 0... eeettt e tenes 5 Natural Gas Futures Market 2.0.0.0... 0eee nee ene ae 7 Natural Gas Production ......0.0 0...e eneee renee ee ees 9 Reserves and Resources «0... 0.0 e tn een nett eee 11 Foreign Trade—Canada 2.0.0...eeeteen t tte e eee 13 Foreign Trade—Mexico .1...n nen een een ene 15 Foreign Trade—Liquefied Natural Gas 2...eeent teens 17 Interstate Pipeline Capacity 0.0.0...eeenett teens 19 Potential Interstate Pipeline Capacity . 2.0...eeeneeet 21 Storage Operations 2.2...ennent nent nents 23 Storage Development .......02.eeenn eet nee eee 25 Capacity Release 2.0...n een en eee nes 27 End-Use Consumption and Price 2.0... 1...ee e eens 29 Industrial Gas Consumption ........0. 000000eeeteens 31 Electricity Generation 2.0.6.e enn ete nents 33 Retail Unbundling ... 2.1...o ennnee tenets 35 New Technology and the Environment ... 0.2...eteee eee nee 37 Kyoto Protocol 2.0... enneee nee eens 39 2. Natural Gas and the Environment ..........0 0.00.ceeeeene tees 49 Air Pollutants and Greenhouse Gases .. 0.2.0.0... c ett eee 50 Effect of Greater Use ofNatural Gas2...eeeeee eee teens 57 Environmental Impacts of Gas Production and Delivery ... 22.6cteeee 61 Outlook ete ee eee een rn teen ee 71 3. Future Supply Potential of Natural Gas Hydrates . 2.2...teetees 73 How To Produce? .... 2.2.0.0eeeeene eee 74 Safety and Environmental Concerns 2.1.2...eeeee eee tenets 81 The Global Carbon Cycle Role of Natural Gas Hydrates .. 2...2.2eeeee 82 Natural Gas Hydrate Research 2.0...eeeet tenes 84 Outlook .....EEneee eee teens 90 4. Offshore Development and Production ............ 2...eeeeee nes 91 Production from the Gulf of Mexico .. 0.2...e eee ees 92 Economics of Offshore Investments 2.0.0...0 ereeet ete e eens 100 Environmental Aspects of Offshore Operations ... 6.0.2... eee 104 Outlook 2...neeeeene eee eee eee 107 5, Natural GasPipeline Network: Changing and Growing ...................0 000. c eee eee eee 109 Changesin Production and Market Links ........... 00.000.eee 111 Interregional Growth .. 0.1.0.ee ene nee 112 Regional Trends ......0.0...n ers 115 Cost of Pipeline Development ..........0.... 000 ecc eeee 121 Outlook 2.0.2... nneeeee eee 127 Energy Information Administration Natural Gas 1998: Issues and Trends Vv 6. Contracting Shifts in the Pipeline Transportation Market .............. 0.0000 - eee eee ees 129 Background ... 0.0...EneeEee tenes 130 Trends in Contracting Practices... 2.0...tneeeee 132 Capacity Release Market 0.0.0...ee eee eee 141 Outlook ooneen ee enn en een ene eens 142 7. Mergers and Other Corporate Combinations in the Natural Gas Industry .............---......5--- 147 OVEIVIEW0 eeen ne eee en nen en eee renee ene 148 Why Energy Companies Combine .. 10.0... ns 151 Regulatory Concerns «0.6...eeeen ener e eens 160 Implications for the Market and for Consumers .. 0.6... eee eeee 165 Outlook2.Eeneeenn n eee nee ee 166 Appendix A. Mapsof Gulf of Mexico OCS Planning Areas... 6...eeeeetees 171 B. Offshore Oil and Gas Recovery Technology ........ 0... c ceeeeeens 175 C. Economic Analysis of a Representative Deep-Water Gas Production Project .............2. 2000. eee ee 181 D. Data Sources and Methodology for Contracting and Capacity Turnback Analysis .................-5-- 191 E. Recent Corporate Combinations in the Natural Gas Industry... 0.26...eeeeee 231 Energy Information Administration vi Natural Gas 1998: Issues and Trends Tables 1. U.S. Carbon Dioxide Emissions from Energy and Industry, 1990-1997 2.0...eee 56 2. Poundsof Air Pollutants Produced per Billion Btu of Energy .... 0...0ceee 58 3. Forecasts of Natural Gas Consumption as a Vehicle Fuel 0.0... 0.oeeeeee 60 4. Typical Annual Air Pollutant Emissions from Exploration, Development, and Production Activities Offshore California 2... 0...n eet teen ene eee 65 5. U.S. Methane Emissions by Source, 1989-1996 22...eeetenes 67 6. U.S. Carbon Dioxide Inherent in Domestic Natural Gas Production, 1990-1997 ................ 2004. 68 7. The Earth’s Organic Carbon Endowment by Location (Reservoir) 0.6... 6.eeeeee 78 8. Estimates of Methane in Natural Gas Hydrate Deposits .. 2.2...L eee es 78 9. Offshore Oil and Gas Volumes Exempt from Royalty Charges Under the Outer Continental ShelfDeep Water Royalty ReliefAct... 6.000eeeens 97 10. Major Environmental Actions Affecting Federal Offshore Gas Recovery ........... 0.20.0 e eee eee 106 11. Summary Profile of Completed and Proposed Natural Gas Pipeline Projects, 1996-2000 .............. 110 12. Interregional Pipeline Capacity, Average Daily Flows, and Usage Rates, 1990 and 1997............... 113 13. Principal Interstate Natural Gas Pipeline Companies Operating in the United States, 1997 .............. 116 14. Characteristics of Firm Transportation Capacity Under Contract at the Beginning of Each Quarter, April 1, 1996 —July 1, 1998 0... nteeee 133 15. Regional Capacity Under Long-Term Firm Contracts, April 1, 1996 — March 31,1998 ................ 139 16. Actions Upon Contract Expiration for Sample of the Largest Expired Long-Term Contracts in Each Region, April 1, 1996 — March 31, 1998 2.0... etenes 141 17. Regional Estimated Turmback of Firm Transportation Capacity, 1998-2025, for Contracts Reported on July 1, 1998 2.0...eeecents 145 18. Agency Review of Corporate Combinations ..... 0... 0.eceeeeee ens 162 Figures ! Figures 1 through 19 (Chapter 1) are composed of multiple illustrations. Below each figure title for Chapter 1, there is _ a list of subtitles describing each illustration. The subtitles are listed in the order in which the illustrations appearin the - | figure, from left to right moving down the page. The remaining figures (20 through 57) are single illustrations with no - subtitles. 1. Natural Gas Consumption Is Expected To Increase About 50 Percent by 2020 ...........0......0005. 2 - Annual Natural Gas Consumption by All Consumers and by Electric Generation , 1950-1997 and Projected 1998-2020 and Range of Additional Consumption Owing to {mpacts of Kyoto Protocol 2. Price Variation Is a Significant Characteristic of the Market ...... 0.0.0 cece eee eee 4 - Monthly Natural Gas Wellhead Prices, 1994-1998 - Monthly Refiner Acquisition Costs and Gas Wellhead Prices, 1996-1998 - Daily Natural Gas Spot Prices at Regional Hubs, 1994-1998 Futures Trading Is a Key Componentof Efficiently Functioning Natural Gas Markets ................. 6 - Daily Settlement Price and Monthly Annualized Volatility Index for NYMEX Henry Hub Near-Month Futures Contract, January 1995 — December 1998 - Annual Volatility Indices of Futures Contracts for Various Energy Sources, 1991-1997 - Share of Reportable Open Interest in NYMEX Henry Hub Futures Contracts, by Trader Type, January 1991 — August 1998. Annual Natural Gas ProductionIs at Its Highest Level Since 1981, 19.0 Trillion Cubic Feet in 1998 ...... 8 - Daily Rates of Dry Natural Gas Production by Month, 1994-1998 - Indices of Natural Gas Well Completions and Wellhead Prices by Month, 1994-1998 - Average NumberofRotary Rigs for Natural Gas and Oil by Month, 1994-1998 Energy information Administration Natural Gas 1998: Issues and Trends vil 10. 11. 12. 13. 14. 15. 16. viii U.S. Proved Reserves Totaled 167.2 Trillion Cubic Feet at Year-End 1997 ..... 0.0... cece ce eee 10 - U.S. Dry Natural Gas Proved Reserves by Area, 1997 - Percent of U.S. Gas Production Replaced by Reserve Additions, 1991-1997 - Natural Gas Discoveries per Exploratory Gas Well, 1977-1997 U.S. Gas Trade with Canada Reflects Growing Competition 2... 0.0.0... c eee eens 12 - U.S. Imports of Canadian Natural Gas, 1980-1998 - U.S. Average Wellhead Price, Average Price for Gas Imports from Canada, and Average ImportPrice UnderShort- and Long-Term Authorizations, 1990-1997 - U.S. Imports of Canadian Natural Gas, by Region, 1990-1997 U.S. Gas Trade with Mexico Is Expected To Grow as the Industry Expands on Both Sides of the Border ... 14 - U.S. Average Wellhead Price and Average Price for U.S./Mexico Natural Gas Imports and Exports, January 1996 — September 1998 - U.S. Natural Gas Exports to Mexico by Border Point, 1988-1997 Liquefied Natural Gas (LNG) Provides the United States with Access to Global Markets .............-. 16 - U.S. LNG Imports by Country Source and U.S. LNG Exports, 1988-1997 - LNG Import Price in Massachusetts and Natural Gas Citygate Price in Massachusetts, 1990-1997 - LNG Import Price in Louisiana and Natural Gas Wellhead and Citygate Prices in Louisiana, 1990-1997 More Than 80 Natural Gas Pipeline Projects Were Completed Between January 1997 and December 1998 . 18 - Locations and Volumesof Regional Natural Gas Pipeline Capacity Additions, 1997-1998 - Interregional Interstate Natural Gas Pipeline Capacity Summary, 1998 The Interstate Natural Gas Pipeline Network Is Expected To Grow Significantly Through 2000 .......... 20 - Annual Interstate Natural Gas Pipeline Expansion Expenditures, 1996-2000 - Net Regional Natural Gas Pipeline Import/Export Capacity, 1998 and Projected Through 2000 - Regional Proposed Additions to Interstate Natural Gas Pipeline Capacity, 1999 and 2000 Underground Storage Operations Are Crucial to Meeting Seasonal Customer Demands ................. 22 - Working Gas Inventory Levels and Seasonally Adjusted Expected Range, and Average Wellhead Natural Gas Prices, by Month for Heating Seasons (November-March) 1995-96 Through 1997-98. - Cycling Rates of Salt Cavern Storage Facilities, Heating Seasons 1990-91 Through 1997-98 -U.S. Underground Natural Gas Storage Capacity and Deliverability as of November 1998, by Region and TypeofFacility Interest in Storage Development Has Slowed But 50 Projects Are Planned Between 1999 and 2003 ....... 24 - Locations and Types of Storage Development Projects Planned Between 1999 and 2003, as of December 1998 - Cumulative Levels and Percentages of Projected Additions to Working Gas Capacity and Deliverability Between 1999 and 2003, by Type of Storage Facility - Projected Additions to Storage Deliverability Between 1999 and 2003, by Region The Capacity Release Market Appears To Be a Reliable Source for Transportation Capacity............. 26 -Characteristics of Released Capacity, Heating Seasons 1993-94 Through 1997-98 -Characteristics of Released Capacity, Nonheating Seasons 1994-1997 -Average Prices for Released Capacity per Contract and on a Contracted Basis, July 1994 — March 1998 -Capacity Held by Replacement Shippers, November 1993 — March 1998 End-Use Consumption in 1998 Fell 4 Percent from Its Record High in 1997 ......................0-.. 28 - Annual Percent Changes in End-Use Natural Gas Consumption by Sector, 1995-1998 - Natural Gas Prices and Annual Price Changes, 1995-1997 - Residential Consumption and Expenditures for Natural Gas During the Heating Season, 1992-93 Through 1997-98 - Number ofNew Single-Family Houses by Type of Heating Fuel, 1992-1997 Industrial Natural Gas Consumption Was8.5 Trillion Cubic Feet in 1998, 4 Percent Below the 1996 Peak... 30 - Industrial Natural Gas Consumption by Region, 1995-1997 - Indices of Industrial Natural Gas Consumption and Manufacturing Production by Month, January 1988 — February 1999 - Nonutility Generator Consumption of Natural Gas and Share of Total Industrial Consumption, 1992-1997 - Industrial and Manufacturing Natural Gas Consumption and Average Prices, 1994 The Use of Natural Gas To Generate Electricity Is Expected To Grow ............ 0.000020 eee eee eeee 32 - Electric Utility Net Generation by Census Region by Type of Fuel, 1997 - Projected Cumulative Retirements and Additions of Generator Nameplate Capacity by Type of Fuel, 1998-2007 - Projected Natural Gas Consumption by End-Use Sector, 1997-2020 Energy Information Administration Natural Gas 1998: Issues and Trends 17. 18. 19. 20. 21. 22. 23. 24. 25. 26. 27. 28. 29. 30. 31. 32. 33. 34. 35. 36. 37. 38. 39. 40. 41. 42. 43. 44. 4S. 46, 47. 48, 49. 50. 51. Eighteen States and the District of Columbia Have Some Form of Residential Choice Program .......... 34 - Status of Natural Gas Retail Unbundling Initiatives by State, 1998 - Regional Summary of Residential Natural Gas Customers Affected by Unbundling Programs, 1997 - Numberof Residential Customers and NumberEligible to Purchase Offsystem Gas, by Region Natural Gas Industry Partners with EPA To Reduce Methane Emissions to the Atmosphere ............ 36 - Methane Emission Reduction Goals of Climate Change Action Plan, 1993~2000, and Reductions Obtained by Natural Gas Star Partners, 1993-1997 - Methane Emission Reductions in the Transmission and Distribution Sector and the Production Sector, 1993-1997 - Shares of Emission Reductions by Best ManagementPractices in the Transmission and Distribution Sector - Shares of Emission Reductions by Best ManagementPractices in the Production Sector Kyoto Implementation Could Have Far-Reaching Impacts on Gas Use and Prices ................000. 38 - Natural Gas Consumption and Potential Range of Additional Demand by Electricity Generators and Others as a Result of Kyoto Protocol, 1995-2020 - Natural Gas Wellhead Prices, 1970-1996 and Projected 1997-2020 Under Two Kyoto Scenarios - Share of Electricity Generation by Fuel Under Two Kyoto Scenarios, 1996, 2005, 2010, and 2020 - Share of Natural Gas Consumption by End-Use Sector Under Two Kyoto Scenarios, 1996, 2005, 2010, and 2020 U.S. Criteria Pollutants and Their Major Sources, 1996...eee ee eee 51 U.S. Anthropogenic Greenhouse Gases and Their Sources, 1997 1.0... 0. Leeeee eee 51 Air Pollutant Emissions by Fuel Type ........... 00.0202ceceeee 53 Carbon Dioxide Emission Share by Country, 1995 22.0.0...eecetet e nee 56 Environmental Impacts of Natural Gas Production, Transmission, and Distribution .................. 62 Gas Hydrate Occurrence Zone and Stability Zone ...... 2.2...eeeeee 77 Locations of Known and Expected Concentrated Methane Hydrate Deposits ................. 00.005. 77 USGSAssessment of Gas Hydrate Plays and Provinces, 1995 1... 0.eeeeee 79 U.S. East Coast Locations of Marine Slides and Natural Gas Hydrate Deposits .................2200. 83 The Department of Energy Proposed Technology Roadmap ........... 0.222.000 cece eee 87 Total Gas Production from Federal Waters of the Gulf of Mexico, 1970-1997 .......0............... 94 Monthly Offshore Drilling Rigs, 1992-1998 ....0...eens 95 Gulf of Mexico Bidding Trends, 1988-1997 .. 0.0...e e ene 97 Projected Gas Production for the Federal Gulf of Mexico ........... 2.02... c ece eee 99 U.S. Onshore and Offshore Finding Costs for Major Energy Companies, 1981-1997 ................. 101 Cycle Time for Deep-Water Projects ..... 0... 0. 0c ceeencee eee e eee eene 104 Major Additions to U.S. Interstate Natural Gas Pipeline Capacity, 1991-2000 ......................-. 110 Major Natural Gas Transportation Corridors in the United States and Canada, 1997 .................. 114 Region-to-Region Natural Gas Pipeline Capacity, 1997 and Proposed by 2000 ..................-4-- 114 Percent of Total Energy Fueled by Natural Gas in the United States .........0.0.. 0.000.002 ce eee eee 117 Average Annual Rate of Change in Natural Gas Use by Sector, 1990-1997 ©...eee ee 120 Proportion of Costs by Category for Completed Natural Gas Pipeline Projects, 1991-1997 ............. 123 Average Costs for New Capacity on Completed and Proposed Natural Gas Pipeline Projects, 1996-2000 20.e e eee nee tn ee nett tet eee nes 123 Total Firm Transportation Capacity Under Contract at the Beginning of Each Quarter, April 1, 1996 —July 11,1998 20...ceeence teen eens 133 Interstate Natural Gas Pipeline Capacity and Average Utilization, 1997 ... 0.0.0.0... cece eee 134 Share of Total Firm Capacity Held on January 1, 1998, and July 1, 1998, by Type of Shipper........... 134 Firm Capacity Under Expired and New Contracts During July 1, 1997 — July 1, 1998, by Shipper and Contract Length .. 0...cencetenn eee een teen tenes 136 Average Contract Length for Contracts with Terms of 3 Years or More, by Year of Contract Start, 1994-1998 ceeent ee tenn ee eee tnt ne ee 138 Daily Contracted and Released Firm Transportation Capacity, April 1, 1996 — March 31,1998 ......... 142 Firm Transportation Capacity by Year of Contract Expiration, 1998-2025, as Reported on July 1,1998 .. 143 Estimated Amounts Turned Back and Retained of Firm Transportation Capacity Under Contract as Of July 11,1998 2...ceeeee(eeeeee tees 143 Regional Exposure to Firm Capacity Contract Expirations, 1998-2025, as Reported on July 1,1998 ..... 144 Energy Information Administration Natural Gas 1998: Issues and Trends ix 52. 53. 54. 55. 56. 37. Value of Corporate Combinations Has Increased .. 2.0...ecetter eens 150 Value of Mergers and Acquisitions Involving Natural Gas Pipeline Companies ...........-..-----+5. 152 Corporate Combinations: Timeline 21...6...n ts 153 Top 20 Natural Gas Marketers: Growth in Volume Outpaces Growth in Share ...............0000006- 154 Mergers Continue To Grow in Value, Accounting for the Largest Share of Energy Combinations ........ 159 Corporate Combinations Reviewed by the FTC and DOJ .... 0...eeeeee 163 Energy Information Administration Natural Gas 1998: Issues and Trends 2. Natural Gas and the Environment Currently, natural gas represents 24 percent of the energy consumedin the United States. The EnergyInformation Administration (EIA) Annual Energy Outlook 1999 projects thatthis figure will increase to about 28 percent by 2020 under the reference case as consumption of natural gas is projected to increase to 32.3trillion cubic feet. In addition, a recent EIA Service Report, Impacts of the Kyoto Protocol on U.S. Energy Markets and Economic Activity, indicates that the use of natural gas could be even 6 to 10 percent higherin 2020 if the United States adopts the Kyoto Protocol’s requirement to reduce carbon emissions by 7 percentfrom their 1990levels by the 2008-2012 time period, without other changesin laws, regulations, and policies. These increases are expected because emissions of greenhouse gases are muchlowerwith the consumption of natural gas relative to otherfossil fuel consumption. For instance: e Natural gas, when burned, emits lower quantities of greenhouse gases andcriteria pollutants per unit of energy produced than do other fossil fuels. This occurs in part because natural gas is more easily fully combusted, and in part.because natural gas contains fewer impurities than. any otherfossil fuel. For example, U.S. coal contains 1.6 percent sulfur (a consumption-weighted national average) by weight. The oil burned atelectric utility power plants ranges from 0.5 to 1.4 percent sulfur. Diesel fuel has less than 0.05 percent, while the current national average for motor gasoline is 0.034 percent sulfur. Comparatively, natural gas at the burner tip has less than 0.0005 percent sulfur compounds. @ The amount of carbon dioxide produced for an equivalent amount of heat production varies substantially amongthefossil fuels, with natural gas producing the least. On a carbon-equivalent basis, energy-related carbon dioxide emissions accounted for 83.8 percent of U.S. anthropogenic greenhouse gas emissionsin 1997. For the majorfossil fuels, the amounts of carbon dioxide produced for each billion Btu of heat energy extracted are: 208,000 poundsfor coal, 164,000 pounds for petroleum products, and 117,000 poundsfor natural gas. Other aspects of the development and use of natural gas need to be considered as well in looking at the environmental consequencesrelated to natural gas. For example: ® The major constituent of natural gas, methane, also directly contributes to the greenhouse effect through venting or leaking of natural gas into the atmosphere. This is because methaneis 21 times as effective in trapping heat as is carbon dioxide. Although methane emissions amountto only 0.5 percentof U.S. emissions of carbon dioxide, they accountfor about 10 percent of the greenhouseeffect of U.S. emissions. e A majortransportation-related environmental advantage of natural gasis thatit is not a sourceof toxic spills. But, because there are about 300,000 miles of high-pressure transmission pipelines in the United States and its offshore areas, there are corollary impacts. For instance, the construction right-of-way on land commonly requires a width of 75 to 100 feet along the length of the pipeline; this is the area disturbed by trenching, soil storage, pipe storage, vehicle movement, etc. This area represents between 9.1 and 12.1 acres per mile of pipe whichis, or has been, subject to intrusion. Natural gas is seen by manyas an importantfuelin initiatives to address environmental concerns. Although natural gasis the mostbenignofthe fossil fuels in terms of air pollution, it is less so than nonfossil-based energy sources such as renewables or nuclear power. However, because ofits lower costs, greater resources, and existing infrastructure, natural gas is projected to increase its share of energy consumption relative to all other fuels, fossil and nonfossil, under current laws and regulations. The vast majority of U.S. energy use comes from the global warming and certain public health risks. To address combustion of fossil hydrocarbon fuels. This unavoidably these health and environmental concerns, the United States results in a degreeof air, land, and water pollution, and the has many laws and regulationsin place that are designed to production of greenhouse gases that might contribute to control and/or reduce pollution. In the United States, Energy Information Administration Natural Gas 1998: Issues and Trends 49 natural gas use is projected to increase nearly 50 percent by 2020.' This is because North American natural gas resources are considered both plentiful and secure, are expected to be competitively priced, and their increased use can beeffective in reducing the emission ofpollutants. While the use of natural gas does have environmental consequences,it is attractive becauseit is relatively clean- burning. This chapter discusses many environmental aspects related to the use of natural gas, including the environmental impactof natural gasrelative to otherfossil fuels and someofthe potential applications for increased use ofnatural gas. Onthe other hand, the venting or leaking of natural gas into the atmosphere can have a significant effect with respect to greenhouse gases because methane, the principal component of natural gas, is much more effective in trapping these gases than carbon dioxide. The exploration, production, and transmission of natural gas, as well, can have adverse effects on the environment. This chapter addresses the level and extent of some of these impacts on the environment. Air Pollutants and Greenhouse Gases The Earth’s atmosphereis a mixture primarily of the gases nitrogen and oxygen,totaling 99 percent; nearly | percent water; and very small amounts of other gases and substances, some of which are chemically reactive. With the exception of oxygen, nitrogen, water, and the inert gases, all constituents of air may be a source of concern owing either to their potential health effects on humans, animals, and plants, or to their influence on the climate. As mandated by The Clean Air Act (CAA), which waslast amended in 1990, the Environmental Protection Agency (EPA)regulates “criteria pollutants” that are considered harmful to the environment and public health: @ Gases. The gaseous criteria pollutants are carbon monoxide, nitrogen oxides, volatile organic compounds,’ and sulfur dioxide (Figure 20). These are reactive gases that in the presence of sunlight contribute to the formation of ground levei ozone, smog, and acid rain. ‘Energy Information Administration, Annual Energy Outlook 1999, DOE/EIA-0383(99) (Washington, DC, December 1998). *Note that methane, the principal ingredient in natural gas, is not classed as a volatile organic compound becauseit is not as chemically reactive as the other hydrocarbons,althoughit is a greenhousegas. e Particulates. The nongaseous criteria pollutant particulate matter consists of metals and substances suchas pollen, dust, yeast, mold, very tiny organisms such as mites and aerosolized liquids, and larger particles such as soot from woodfires or diesel fuel ignition. e Air Toxics. The CAAidentifies 188 substancesas air toxics or hazardousair pollutants, with lead being the only one that is currently classified as a criteria pollutant and thus regulated. Air toxic pollutants are more acute biological hazards than most particulate or criteria pollutants but are much smaller in volume. Procedures are now underway to regulate other air toxics under the CAA. The greenhouse gases are water vapor, carbon dioxide, methane, nitrous oxide, and a host of engineered chemicals, such as chlorofluorocarbons (Figure 21). These gases regulate the Earth’s temperature. When the natural balance of the atmosphereis disturbed, particularly by an increase or decrease in the greenhouse gases, the Earth’s climate could be affected. The combustion of fossil fuels produces 84 percent of U.S. anthropogenic (created by humans) greenhouse emissions.” When wood buming is included, these fuels produce 95 percent of the nitrogen oxides, 94 percent of the carbon monoxide, and 93 percent of the sulfur dioxide criteria pollutants (Figure 20). Most of these emissions are released into the atmosphere as a result of fossil fuel use in industrial boilers and power plants and in motor vehicles. Emissions from Burning Natural Gas Natural gas is less chemically complex than other fuels, has fewer impurities, and its combustion accordingly results in less pollution. Natural gas consists primarily of methane (see box, p. 52). In the simplest case, complete combustive reaction of a molecule of pure methane (which comprises one carbon atom and four hydrogen atoms) with two molecules of pure oxygen produces a molecule of carbon dioxide gas, two molecules of water in vapor form, and heat." In practice, however,the combustion process is never *Energy Information Administration, Emissions ofGreenhouse Gases in the United States 1997, DOE/EIA-0573(97) (Washington, DC, October 1998). “As described by CH,+20, ~ CO,+2H,O + heat. EnergyInformation Administration 50 Natural Gas 1998: Issues and Trends Figure 20. U.S. Criteria Pollutants and Their Major Sources, 1996 Pollutants Sources of (Million Tons) Sources of Nitrogen Oxides Carbon Monoxide oil (Engines and Vehicles) - ou bon M id58% Car *leo) e (Engines and 88.8 Vehicles) - 81% Coal- 27% Cae 40k. I Wood - 13% Other-5% Other-6% Particulate Matter” Sources of (PM 10) Sources of Volatile Organic 31.3 Sulfur Diaxide Compounds Nitrogen Oxides (NOx) 23.4 oll -50% Sulfur Dioxide soe (302) Coal- 74% Volatile Organic Compounds (VOC) 19.1 Solvents - 33% ee Lead _=3.9 Oil - 16% Other-9% pas SM Woad 8% Other-7% - 8% *Wood and otherfuels account for only 9 percent of particulate matter. **Ojil accounts for 25 percentof tead and other fuels 2 percent. Source: Energy Information Administration, Office of Oil and Gas, derived from: Environmental Protection Agency, National Air Pollutant Emission Trends 1990-1996, Appendix A (December 1997). Figure 21. U.S. Anthropogenic Greenhouse Gasesand Their Sources, 1997 Greenhouse Gases (Weighted by Greenhouse Potential) Sources of Carbon Dioxide Sources of Methane eeeon) Oil- 42% 83.8% Landfill - 35% Coal-35% Animats - 28% atural Gas” : _ Production and Oth er-1% “Distribution -.21% oo, Methane 5,422 MillionCoalMining -11% (CH,) Metric TonsOther-5% eee 9.3% TotalN,O - 4.8%29.1 Million CFO -2.1% Metric Tons Total N,O = Nitrous oxide. CFC = Chlorofluorocarbon. Source: Energy Information Administration, Emissions of Greenhouse Gasesin the United States 1997 (October 1998). Energy Information Administration Natural Gas 1998: Issues and Trends 531 Sources and Chemical Composition of Natural Gas Naturalgasis obtained principally from conventional crude oil and nonassociated gas reservoirs, and secondarily from coal beds,tight sandstones, and Devonian shales. Someis also produced from minor sources such aslandfills. in the future, it may also be obtained from natural gas hydrate deposits located beneath the sea floor in deep water on the continental shelves or associated with thick subsurface permafrost zonesin the Arctic. Natural gas is a mixture of low molecular-weight aliphatic (straight chain) hydrocarbon compoundsthat are gases at surface pressure and temperature conditions. At the pressure and temperature conditions of the source reservoir, it may occur as free gas (bubbles) or be dissolvedin either crudeoil or brine. While the primary constituent of natural gas is methane (CH,), it may contain smaller amounts of other hydrocarbons, such as ethane (C,H,) and various isomers of propane (C,H,), butane (G H,), and the pentanes {C,H ), as well as trace amounts of heavier hydrocarbons. Nonhydrocarbon gases,such as carbon dioxide (CO.), helium (He), hydrogensulfide (H,S), nitrogen (N,), and water vapor (H,O), may also be presentin any proportion to the total hydrocarbon content. Pipeline-quality natural gas contains at least 80 percent methane and has a minimum heat contentof 870 Btu per standard cubicfoot. Mostpipeline natural gas significantly exceeds both minimum specifications. Since natural gas has by far the lowest energy density of the common hydrocarbonfuels, by volume (not weight) much more of it must be used to provide a given amountof energy. Natural gas is also muchless physically dense, weighing about half as much (55 percent) as the same volumeofdry air at the same pressure.It is consequently buoyantin air, in which it is also combustible at concentrations ranging from 5 percent to 15 percent by volume. that perfect as it takes place in air rather than in pure oxygen,resulting in somepollutants.* The reaction products include particulate carbon, carbon monoxide, and nitrogen oxides, in addition to carbon dioxide, water vapor, and heat. Carbon monoxide, the nitrogen oxides, and particulate carbon are criteria pollutants (regulated emissions). The proportions of the reaction products are determined by the efficiency of combustion. For instance, when the air supply to a gas burner is not adequate, the produced levels of carbon monoxide and other pollutants are greater. This situation is, of course, similar to that of all other fossil hydrocarbon fuels—insufficient oxygen supply to the bumer will inevitably result in incomplete combustion and the consequent production of carbon monoxide and other pollutants. Since natural gas is never pure methane andairis not just oxygen and nitrogen, small amounts of additional pollutants are also generated during combustion of natural *Since the process takesplace in air rather than pure oxygen,the practical result is more like: CH, +0,+N, + C+CO+CO,+N,O +NO+ NO, + H,O + CH, (unbumed) + heat (exact proportions depend on the prevailing combustion conditions). gas. For example,all fossil fuels contain sulfur; its removal from both oil and gas is a major part of the processing of these fuels prior to distribution. However,notall sulfur is removed during processing. When the fuel is bummed, several oxides of sulfur are produced, consisting primarily of sulfur dioxide, some other sulfur-bearing acids, and traces ofmany other sulfur compounds depending on what other trace compoundsare present in the fuel. Additionally, since natural gas is both colorless and odorless, sulfur- bearing odorants® are intentionally added to the gas stream by gasdistributors so that residential consumers can smell a leak. Besides sulfur, natural gas can include other trace impurities and contaminants.’ Yet the emittable pollutants resulting from combustion of natural gas are far fewer in volume and numberthan those from the combustion of any other fossil fuel (Figure 22). This occurs in part because natural gas is more easily fully combusted, and in part because natural gas has fewer impurities than other hydrocarbon fuels. For example, the amountof sulfur in natural gas is much less than that of ‘These odorants are compoundssuch as dimethyl]sulfide, tertiary butyl mercaptan,tetrahydrothiophene, and methy! mercaptan. 'Trace impurities can include radon, benzene, toluene, ethylbenzene, xylene, and organometallic compounds such as methyl mercury. Thelist of combustion byproducts can include fine particulate matter, polycyclic aromatic hydrocarbons, and volatile organic compounds including formaldehyde. Energy Information Administration 52 Natural Gas 1998: Issues and Trends Figure 22. Air Pollutant Emissions by Fuel Type 250,000 — 3,000 - 2,500 + 200,000 + 7 > - To © 2 2,000 - Cc| c& = w 4 OS a =o uO 22 150,000 ~ 8 > 7 os oo = 2 ue : a8 Siu so 1 2s 4 nD To 5G 100,000 + | es | 50,000 — - 0 —_ CO, NOx = N n N an o ° og So a 6 So of E n e r g y C o n s u m e d Po un ds p e r Bi ll io n B t u 3 oO SO2 Particulates co HC a Natural Gas i oi CO, = Carbon dioxide. No, = Nitrogen oxides. SO, = Sulfur dioxide. CO = Carbon monoxide. HC = Hydrocarbon. Note: Graphs should not be directly compared becausevertical scalesdiffer. Source: Energy Information Administration (EIA) Office of Oil and Gas. Carbon Monoxide:derived from EIA, Emissions of Greenhouse Gases in the United States 1997, Table B1, p. 106. Other Pollutants: derived from Environmental Protection Agency, Compilation ofAir Pollutant Emission Factors, Vol. 1 (1998). Based on conversion factors derived from EIA, Cost and Quality of Fuels for Electric Utility Plants (1996). coal or oil. U.S. coals contain an average of 1.6 percent sulfur by weight,® and the oil burned at electric utility powerplants ranges from 0.5 percentto 1.4 percent sulfur.’ Diesel fuel has less than 0.05 percent sulfur by weight (or 500 parts per million (ppm)) and the current national average for motor gasoline is 340 ppm sulfur (includes California where the regulated statewide average is 30 ppm).'° Comparatively, natural gas at the burnertip has less than 5 ppm of all sulfur compounds, typically 8U.S. coals bumed at Clean Air Act PhaseI electric powerplants contain an averageof0.3 percent sulfur for western coals and 2.5 percent for eastern coals, yielding a consumption-weighted national average of 1.6 percentsulfur by weight. Energy Information Administration, Electric Power Annual, 1996, Vol. 2, DOE/EIA-348(96) (Washington, DC, 1997), p. 41. "Gerald Karey, “EPA leaves sulfur verdict for another day,” Platts Oilgram News, 76/78 (April 24, 1998), p. 4. comprising about 1 ppm hydrogen sulfide and less than 2 ppm ofeach sulfur-bearing odorant.'' Toxic and Particulate Emissions The combustion ofnatural gas also produces significantly lower quantities of other undesirable compounds, "Washington Gas Light Company personnel stated that its system hydrogensulfide (H,S) levels are 1.8 parts per million (ppm) and the sulfur- bearing odorants are 2.0 ppm.Institute for Gas Technology tests of trace constituents in two intrastate pipeline samples and two Canadianinterstate samples supplied by the Pacific Gas and Electric Company had less than 5 ppm total H,S (usually between | and 1.5 ppm), Sulfur content by contract for pipeline-quality natural gas varies from 0.25 grains to 1.0 grain per 100 standard cubic feet (1.9 ppm to 7.6 ppm), in many cases 0.25 grains or 1.9 ppm. Dr. John M. Campbell, Chapter 7, “Product Specifications,” Gas Conditioning and Processing, Vol. 1 (Norman, OK,1979). Energy Information Administration Natural Gas 1998: Issues and Trends 53 particularly toxics, than those produced from combustion ofpetroleum products or coal. Toxic air pollutants are those compoundsthat are not specifically covered under other portions of the CAA (ie., the criteria pollutants and particulate matter) and are typically carcinogens, reproductive toxics, and mutagens. The United States emits 2.7 billion pounds of toxics into the atmosphere each year. Motor vehicles are the primary source, followed by residential wood combustion. Section 112 of the CAA of 1990lists 188 toxic compoundsor groupsas hazardousair pollutants (HAPs), including various compounds of mercury, arsenic, lead, nickel, and beryllium and also organic compounds, such as toluene, benzene, formaldehyde, chloroform, and phosgene, which are expected to be regulated soon. Presently, only lead is regulated. The toxic compound benzene can be a componentof both petroleum products and natural gas, but whereas it can comprise up to 1.5 percent by weight of motor gasoline, the levels in natural gas are considered insignificant and are not generally monitored by gas-processing plants and most pipeline companies.” As required by California Proposition 65, the Safe Drinking Water and Toxic Enforcement Act, gas pipeline companies that operate in California continuously monitor for toxic substances. These companies have found that the benzene and toluene content ofthe natural gas they carry varies by source and can range from less than 0.4 ppm to 6 ppm for interstate gas and up to 100 ppm forintrastate gas.'* Depending on the efficiency of the combustion, some will be oxidized to carbon dioxide and water, some will pass through unburned, and somewill be converted to other toxic compounds. Theparticulates produced by natural gas combustion are usually less than 1 micrometer (micron) in diameter and are composed of low molecular-weight hydrocarbonsthat are not fully combusted.'* Typically, combustion of the other fossil fuels produces greater volumes of larger and more complex particulates. In 1998, the Environmental Protection Agency set a new standard for very fine (less than 2.5 microns) particulates as an add-onto the existing regulation of suspended particulates that are 10 microns or “Based on communications with personnel at the Gas Processors Association and the Columbia Gas Pipeline Company. “Institute for Gas Technologytest of trace constituents in twointrastate pipeline samples and two Canadian interstate samples supplied by the Pacific Gas and Electric Company. “The aerosolized particulate matter resulting from combustionoffossil fuels is a mixture of solid particles and liquid droplets inclusive of soot, smoke, dust, ash, and condensing vapors. larger, set in 1987.'° Although powerplants and diesel- powered trucks and buses are major emitters of particulate matter, the bulk of 10-micron-plus particulate matter emissions is composed of “fugitive” dust from roadways (58 percent) and combined sources of agricultural operations and winderosion (30 percent).'° Acid Rain and Smog Formation Natural gas is not a significant contributor to acid rain formation. Acid rain is formed whensulfur dioxide and the nitrogen oxides chemically react with water vapor and oxidants in the presence of sunlight to produce various acidic compounds, such as sulfuric acid and nitric acid. Electric utility plants generate about 70 percent of SO, emissions and 30 percent ofNO, emissions in the United States; motor vehicles are the second largest source of both. Natural gas is responsible for only 3 percent of sulfur dioxide and 10 percent of nitrogen oxides (Figure 20). Precipitation in the form ofrain, snow,ice, and fog causes about half of these atmospheric acidsto fall to the ground as “acid rain,” while about half fall as dry particles and gases. Winds can blow the particles and compounds hundreds of miles from their source before they are deposited, and they and their sulfate and nitrate derivatives contribute to atmospheric haze prior to eventual deposition as acid rain. The dry particles that land on surfaces are also washedoffby rain, increasing the acidity of runoff. Natural gas use also is not much of a factor in smog formation. As opposed to petroleum products and coal, the combustion of natural gas results in relatively small production of smog-forming pollutants. The primary constituent of smog is ground-level ozone created by photochemical reactions in the near-surface atmosphere involving a combination of pollutants from many sources, including motor vehicle exhausts, volatile organic compounds such as paints and solvents, and smokestack emissions. The smog-forming pollutantsliterally cook in the air as they mix together and are acted on by heat and sunlight. The wind can blow smog-forming pollutants away ‘The larger particles are usually trapped in the upperrespiratory tract, whereas those smaller than 10 microns can penetrate further into the respiratory system. The most infamouscases of extreme particulate matter pollution, in Donora, Pennsylvania, and in London, England, during the 1930s-1950s, killed thousands of people, and recent studies have indicated that a relatively small rise in 2.5-micron particulates causes a 5-percentrise in infant mortality and greater risk of heart disease. Michael Day, “Taken to Heart,” New Scientist (May 9, 1998), p. 23. ‘SEnvironmental Protection Agency, National Air Pollution Trends Update, 1970-1997, EPA-454/E-98-007 (December 1998), Table A-5 “Particulate Matter (PM-10) Emissions.” Energy Information Administration 54 Natural Gas 1998: Issues and Trends from their sources while the reaction takes place, explaining why smog can be more severe miles away from the source of pollutants than at the sourceitself. Greenhouse Gasesand Climate Change The Earth’s surface temperature is maintained at a habitable level through the action of certain atmospheric gases known as “greenhouse gases”that help trap the Sun’s heatclose to the Earth’s surface. The main greenhouse gases are water vapor, carbon dioxide, methane,nitrous oxide, and several engineered chemicals, such as chlorofluorocarbons. Most greenhouse gases occur naturally, but concentrations of carbon dioxide and other greenhouse gases in the Earth’s atmosphere have been increasing since the Industrial Revolution with the increased combustion of fossil fuels and increased agricultural operations. Of late there has been concern that if this increase continues unabated, the ultimate result could be that more heat would be trapped, adversely affecting Earth’s climate. Consequently, governments worldwide are attempting to find some mechanisms for reducing emissions or increasing absorption of greenhousegases.’ On a carbon-equivalent basis, 99 percent of anthropogenically-sourced carbon dioxide emissions in the United States is due to the burning of fossil hydrocarbon fuels, with 22 percentofthis attributed to natural gas (Table 1). Carbon dioxide emissions accounted for 83.8 percent of U.S. greenhouse gas emissions in 1997, Between 1996 and 1997, total estimated U.S. carbon dioxide emissions increased by 1.5 percent (22.0 million metric tons) to about 1,501 million metric tons of carbon, representing an increase of about 145 million metric tons, or almost 10.7 percent overthe 1990 emission level. The increase between 1996 and 1997 wasthe sixth consecutive one. Increasing reliance on coal for electricity generation is one of the driving forces behind the growth in carbon emissions in 1996 and 1997. The major constituent ofnatural gas, methane, also directly contributes to the greenhouse effect. Its ability to trap heat in the atmosphereis estimated to be 21 times greater than "Tn December 1997, representatives from more than 160 countries met in Kyoto, Japan, to establish limits on greenhouse gas emissions for participating developed nations. The resulting Kyoto Protocol established annual emission targets for countries relative to their 1990 emissionlevels. The target for the United States is 7 percent below 1990levels. that of carbon dioxide, so although methane emissions amount to only 0.5 percent of U.S. emissions of carbon dioxide, they account for about 10 percent of the greenhouse effect of U.S. emissions. In 1997, methane emissions from waste management operations (primarily landfills), at 10.4 million metric tons, and from agricultural operations, at 8.6 million metric tons, substantially exceeded those from the oil and gas industries combined, estimated to be 6.2 million metric tons.’* Watervapor is the most common greenhouse gas, at about 1 percent of the atmosphere by weight, followed by carbon dioxide at 0.04 percent and then methane, nitrous oxide, and manmade compoundssuch as the chlorofluorocarbons (CFCs). Each gas has a different residence time in the atmosphere, from about a decade for carbon dioxide to 120 years for nitrous oxide and up to 50,000 years for some of the CFCs. Water vapor is omnipresent and continually cycles into and out of the atmosphere. In estimating the effect of these greenhouse gases on climate, both the global warming potential (heat-trapping effectiveness relative to carbon dioxide) and the quantity of gas must be considered for each of the greenhouse gases. Since human activity has minimal impact on the atmosphere’s water vapor content, unlike the other greenhouse gasesit is not addressedin the context of global warming prevention. Thecriteria pollutants specified in the CAA are reactive gasesthat, although they decay quickly,. nevertheless promote reactions in the atmosphere yielding the greenhouse gas ozone. These gases indirectly affect global climate because they produce undesirable lower atmosphere ozone, as opposedto the desirable high-altitude ozonethat shields Earth from most of the Sun’s ultraviolet radiation, Carbon dioxide, on the other hand, directly contributes to the greenhouse effect; it presently represents 61 percent of the worldwide global warming potential of the atmosphere’s greenhouse gases. The United States is the largest producer of carbon dioxide amongthe countries of the world, both per capita (5.4 tons in 1996) and absolutely (Figure 23).'" The amount of carbon dioxide produced for an equivalent amountofheat production substantially varies amongthe fossil fuels, with '*Energy Information Administration, Emissions of Greenhouse Gases in the United States 1997, DOE/EIA-0573(97) (Washington, DC, October 1998), pp. 27 and 29, U.S. Department of Energy, Oak Ridge National Laboratory, G. Marland and T. Broden,“Ranking of the World’s Countries by 1995 Total CO, Emissions from Fossil Fuel Burning, Cement Production, and Gas Flaring,”. Energy Information Administration Natural Gas 1998: Issues and Trends 55 Table 1. U.S. Carbon Dioxide Emissions from Energy and Industry, 1990-1997 (Million Metric Tons of Carbon) Fuel Type or Process 1990 1991 1992 1993 | 1994 1995 1996 P1997 Natural Gas Consumption ............00.. 02 cee eee 273.2 278.1 286.3 296.6 301.5 319.1 319.7 319.1 Gas Flaring ..........-... 20-00 - 2c 2.5 2.8 2.8 3.7 3.8 4.7 4.5 4.3 CO, in Natural Gas ....... 0.0... eee eee 3.6 3.7 3.9 4.1 4.3 4.2 4.5 4.6 Total oo... ccc eeeee 279.3 2846 293.0 3044 309.6 323.0 328.1 328.0 Other Energy Petroleum 1.0.2... 00.000 c eee eee eee eens 591.4 5769 587.6 588.8 601.3 597.4 6206 627.5 Coal 0.eeeee tees 481.5 475.7 478.1 4944 4956 500.2 5209 533.0 Geothermal .......... 0.00 e eee eter ee eee 0.1 0.1 0.1 0.1 * * * * Total ooo. c eceene eee 1,073.0 1,052.7 1,065.8 1,083.3 1,096.9 1,097.6 1,141.5 1,160.5 Other Sources Cement Production .............-200.0005- 8.9 8.7 8.8 9.3 9.8 9.9 9.9 10.1 Other industrial ......... 0.0.22 0 2 eee eee 8.0 8.0 8.0 8.0 8.1 8.9 9.1 9.2 Adjustments? ..........022200. cece eee eee -13.2 -13.2 -14.9 -11.3 -10.7 -11.2 -9.8 -7.1 Total oo... cece eeeee 3.7 3.5 1.9 6.0 7.2 7.6 9.2 12.2 Total from Energy and Industry ............ 1,355.9 1,340.8 1,360.6 1,393.6 1,413.8 1,428.1 1,478.8 1,500.8 Percent Natural Gas of Total ..............- 20.6 21.2 21.5 21.8 21.9 22.6 22.2 21.9 *Accounts fordifferent methodologies in calculating emissions for U.S. territories. *Less than 0.05 million metric tons. P = Preliminary data. Notes: Emission coefficients are annualized for coal, motor gasoline, liquefied petroleum gases,jet fuel, and crude oil. Includes emissions from bunkerfuels. Totals may not equal sum of components becauseof independent rounding. Source: Energy Information Administration, Emissions of Greenhouse Gasesin the United States 1997 (October 1998). Figure 23. Carbon Dioxide Emission Share by Country, 1995 China 14.1% United States 22.8% Russian Federation 8.0% Japan 5.0% India 4.0% Germany 3.7% United Kingdom 2.4% UA CanadaUkraine4.99 1.9% Restof World . 0 . 36.1% Total 1995 emissions = 6,173 million metric tons of carbon Note: Sum of percentages does not equal 100 because of independent rounding. Source: U.S. Department of Energy, Oak Ridge National Laboratory, G. Marland, T. Broden, “Ranking of the World’s Countries by 1995 Total CO2 Emissions from Fossil Fuel Burning, Cement Production, and Gas Flaring,” . Energy Information Administration 56 Natural Gas 1998: Issues and Trends natural gas producing the least. For the majorfossil fuels, the amounts of carbon dioxide produced for each billion Btu ofheat energy extracted are: 208,000 pounds for coal, 164,000 pounds for petroleum products, and 117,000 poundsfor natural gas (Table 2). Effect of Greater Use of Natural Gas Electric Power Generation Projections of increased use of natural gas center principally on the increased use of natural gas in electric generation. For example, the Annual Energy Outlook 1999 reference case projects natural gas consumption to rise by 10.3 trillion cubic feet (Tcf) from 1997 to 2020. Ofthis increase, 56 percent (5.8 Tcf) is expected to come as a result of increased use of natural gas for electricity generation. A recent Energy Information Administration (EIA) Service Report (prepared at the request of the House of Representatives Science Committee assuming no changes in domestic policy) analyzed the consequences of U.S. implementation of the Kyoto Protocol. In the carbon reduction cases cited in this report, Impacts of the Kyoto Protocol on U.S. Energy Markets and Economic Activity,”° power plant use of natural gas (excluding industrial cogeneration) could increase to between 8 and 12 Tcf in 2010 and 12 to 15 Tcf in 2020. This growth is expected to develop as many of the new generating units brought on line are gas-fired. Some repowering of existing units may be undertaken as well. Since electricity generation is the major source of U.S. sulfur dioxide (SO,) and carbon dioxide (CO,) emissions,”! as well as a major source of all other air pollutants excepting the chlorinated fluorocarbons, substitution of natural gas for other fossil fuels by utilities and nonutility *Energy Information Administration, Impacts ofthe Kyoto Protocol on US. Energy Markets and Economic Activity, SR/OLAF/98-03 (Washington, DC, October 1998), p. 76. This Service Report was requested by the U.S. House of Representatives Science Committee to provide information on the costs of the Kyoto Protocol without other changes in laws and regulations. The report relied on assumptions provided by the Committee. In 1996, electric utilities accounted for 12,604 thousand short tons of sulfur dioxide emissions out of a total of 19,113 thousand short tons (Environmental Protection Agency, National Air Pollutant Emission Trends, 1990-1996, EPA-454R-97-011 (December 1997), Table 2-1, p. 2-4); and for 532.4 million metric tons of carbon as carbon dioxide, exceeding the 482.9 and 473.1 million metric tons from the industrial and transportation sectors, respectively (Energy Information Administration, Emissions of Greenhouse Gases in the United States 1997, DOE/EIA-0573(97) (October 1998), Table 7, p. 21). generators would have a sizable impact on emission levels. However, if increased natural gas generation were to replace nuclear power or delay the commercialization of renewable-powered generation, this would represent a negative impact on emissionlevels. In 1997, there were 10,454 electric utility generating units in the United States, with a total net summer generation capacity of 712 gigawatts.” Of that capacity, 19 percent listed natural gas as the primary fuel and 27 percentlisted it as either the primary or secondary fuel. But natural gas was actually used to generate only 9.1 percent of the electricity generated by electric utilities in 1997, down 1.2 percent from the 1995 value of 10.3 percent and one of the lowest proportions in the past 10 years. Coal waslisted as the primary fuel source for almost 43 percent of the utility generating capacity and as a secondary source for only about 0.5 percent. But in 1997,it was the fuel used for 57.3 percent of net generation from electric utilities, up from 55.3 percent in 1995 and 56.3 percent in 1996. A utility typically has a base-load generating capacity that is essentially continuously on line and capable of satisfying most orall ofthe minimum service-area load. The base-load capacity is supplemented by intermediate-load generation and peak-load generation capacities, which are used to meet the seasonal and short-term fluctuating demands above base load; reserve or standby units are also maintained to handle outages or emergencies. The majority of non-nuclear base- load units are coal-fired, yet many utilities have gas turbines, which are primarily used as peak-load generators. Once the initial cost of a generating unit is paid for, fuel cost per unit ofenergy produced controls how electricity is generated. In 1997, the cost at steam-electric utility plants per million Btu for coal was less than half that for natural gas, $1.27 versus $2.76, and petroleum was even higherat $2.88.”> The per Btu natural gas cost to utilities increased by over one-third from 1995 to 1997, while the per Btu coal cost continued a 15-year decline, contributing to the decreased market share for natural gas. However, new technologies creating higher efficiency natural gas electric Excludes nonutility generators. Energy Information Administration, Inventory of Power Plants in the United States as of January 1, 1998, DOE/EIA-0095(98) (Washington, DC, December 1998). Nonutility generators totaled 78 gigawatts of capacity in 1997, with 42 percentutilizing natural gas. Energy Information Administration, Electric Power Annual 1997, Vol. II, DOE/EIA-348(97) (Washington, DC, July 1998), Table 54. Energy Information Administration, Electric Power Annual 1997, Vol. 1, DOE/EIA-348(97) (Washington DC, July 1998), Table 20, p. 37. Energy Information Administration Natural Gas 1998: Issues and Trends 57 Table 2. Poundsof Air Pollutants Produced perBillion Btu of Energy Pollutant Natural Gas Oil Coal Carbon Dioxide 117,000 164,000 208,000 Carbon Monoxide 33 208 Nitrogen Oxides 448 457 Sulfur Dioxide 0.6 1,122 2,591 Particulates 7.0 84 2,744 Formaldehyde 0.750 0.220 0.221 Mercury 0.000 0.007 0.016 Notes: No post combustion removal ofpollutants. Bituminous coal burned in a spreader stoker is compared with No. 6 fueloil burned in an oil-fired utility boiler and natural gas burned in uncontrolled residential gas burners. Conversionfactors are: bituminous coal at 12,027 Btu per pound and 1.64 percent sulfur content; and No. 6 fuel oil at 6.287 million Btu per barrel and 1.03 percent sulfur content—derived from Energy Information Administration, Cost and Quality of Fuels for Electric Utility Plants (1996). Source: Energy Information Administration (EIA), Office of Oil and Gas. Carbon Monoxide:derived from EIA, Emissions of Greenhouse Gases in the United States 1997, Table B1, p. 106. Other Pollutants: derived from Environmental Protection Agency, Compilation of Air Pollutant Emission Factors, Vol. 1 (1998). generators can overcome the current price differential betweenthe fuels. The new powerplants scheduled to come on line during the 10 years from 1998 through 2007 are 88 percent natural- gas-fired and only 5 percent coal-fired, but they will add only about 6 percent to total net generation capacity.” Thus, in order to make significant reductions in the volume of greenhouse gases and other pollutants produced by electricity generation, a significant amount of new unplanned gas-fired or renewable generation capacity would have to be built, or the existing generating equipment having natural gas as a fuel option would have to be utilized more and many of the existing coal plants would have to be repowered to burn gas. The utilities have many supply-side options at their disposal to reduce or offset carbon dioxide emissions from power generation. These options include repowering of coal-based plants with natural gas, building new gasplants, extension of the life of existing nuclear plants, implementation of renewable electricity technologies, and improvement of the efficiency of existing generation, transmission, and distribution systems. There are two principal conversion opportunities for utility power plants. The simplest and most capital-intensive approach is site repowering with an entirely new gas- turbine-based natural gas combined-cycle (NGCC)system. The more complex, less capital-intensive approach is steam “Energy Information Administration, /nventory ofPower Plants in the United States as ofJanuary 1, 1998, DOE/EIA-0095(98) (Washington, DC, December 1998), pp. 9 and 13. turbine repowering where a new gas turbine and a heat recovery steam generator are integrated with the existing steam turbine and auxiliary equipment. This option can have lowercapital costs if site redesign costs are low, but entails a higher operating cost becauseit is less efficient than total state-of-the-art repowering. As of January 1, 1998, there are 20 repowering projects planned in nine States that will primarily convert current oil-fired facilities to natural gas or co-firing capability; most of the projects are driven by economics with a secondary impetus as a response to the emission reduction requirements of the Clean Air Act Amendments of 1990 (see box, p. 59). Complete conversion may not be a practical goal for a number of plants without expansion ofthe transportation pipeline network. Mostofthe candidate plants are located in primary gas-consuming regions served by major trunk lines. It appears that converted plants may have sufficient access to firm transportation capacity on these systems during the heating and nonheating seasons, during which between 16 and 24 percent of average national system capability is available for firm transportation, respectively.” Theability of a plant to use firm transportation capacity for gas supply will depend on the location and specific load characteristics of the pipelines serving that plant. However, because of recent regulatory reforms, electric generation plants may no longer be required to use firm transportation to serve their supply needs. Under Federal Energy Information Administration, Deliverability on the Interstate Natural Gas Pipeline System, DOE/EIA-0618(98) (Washington, DC, May 1998), Table 14. Energy Information Administration 58 Natural Gas 1998: Issues and Trends DOE/EIA-O383¢(2012) | June 2012 Annual Energy Outlook 2012 with Projections to 2035 ne ¢ Information ; ‘ "alist hada | ela — US. Energy Administration Executive summary The projectionsin the U.S. Energy Information Administration's (EIA’s) Annual Energy Outlook 2012 (AEQ2012) focus on the factors that shape the U.S. energy system over the long term. Under the assumptionthat current laws and regulations remain unchanged throughoutthe projections, the AEO2012 Reference caseprovides the basis for examination and discussion of energy production, consumption, technology, and market trends andthe direction they may take in the future. It also servesas a starting point for analysis of potential changes in energy policies. But AEO2012is notlimited to the Reference case. It also includes 29 alternative cases (see Appendix £, Table E1), which explore important areasof uncertainty for markets, technologies, and policies in the U.S. energy economy. Many of the implications of the alternative cases are discussed in the “Issuesin focus” section of this report. Key results highlighted in AEO2012 include continued modest growth in demandfor energy over the next 25 years and increased domestic crudeoil and natural gas production, largely driven byrising production from tight oil and shale resources.As a result, U.S. reliance on imported oil is reduced; domestic production of natural gas exceeds consumption, allowing for net exports; a growing share of U.S. electric power generation is met with natural gas and renewables; and energy-related carbon dioxide emissions remain below their 2005level from 2010 to 2035, even in the absence of new Federal policies designed to mitigate greenhouse gas (GHG) emissions. The rate of growth in energy use slows over the projection period, relecting moderate population growth, an extended economic recovery, and increasing energyefficiency in end-use applications Overall U.S. energy consumption grows at an average annual rate of 0.3 percent from 2010 through 2035 in the AEO2012 Reference case. The U.S. does not return to the levels of energy demand growth experienced in the 20 years prior to the 2008- 2009 recession, because of more moderate projected economic growth and population growth, coupled with increasing levels of energy efficiency. For some end uses, current Federal and State energy requirements and incentives play a continuing role in requiring moreefficient technologies. Projected energy demandfor transportation grows at an annual rate of 0.1 percent from 2010 through 2035in the Reference case, and electricity demand grows by 0.7 percent per year, primarily as a result of rising energy consumption in the buildings sector. Energy consumption per capita declines by an average of 0.6 percent per year from 2010 to 2035 (Figure 1). The energy intensity of the U.S. economy, measured asprimary energyuse in British thermal units (Btu) per dollar of gross domestic product (GDP) in 2005dollars, declines by an average of 2.1 percent per year from 2010 to 2035. New Federal and State policies could lead to further reductions in energy consumption. The potential impact of technology change and the proposed vehicle fuel efficiency standards on energy consumption are discussed in “Issues in focus.” Domestic crude oil production increases Domestic crude oil production has increased over the past few years, reversing a decline that began in 1986. U.S. crude oil production increased from 5.0 million barrels per day in 2008 to 5.5 million barrels per day in 2010. Over the next 10 years, continued development oftight oil, in combination with the ongoing developmentof offshore resources in the Gulf of Mexico, pushes domestic crude oi! production higher. Because the technology advances that have providedfor recent increases in supply arestill in the early stages of development,future U.S. crude oil production could vary significantly, depending on the outcomesof key uncertainties related to well placement and recovery rates. Those uncertainties are highlighted in this Annual Energy Outlook's “Issues in focus” section, which includes an article examining impacts of uncertainty about current estimates of the crude oil and natural gas resources. The AEO2012 projections considering variations in these variables show total U.S. crude oil productionin 2035 ranging from 5.5 million barrels per dayto 7.8 million barrels per day, and projectionsfor U.S. tight oil production from eight selected plays in 2035 ranging from 0.7 million barrels per day to 2.8 million barrels per day (Figure 2). Figure 1. Energy use per capita and per dollar of Figure 2. U.S. production of tight oil in four cases, gross domestic product, 1980-2033 Gndex, 1980) 2000-2035 (million barrels per day} 1 History = 2010_—Projections,==) History 2010 Projections High TRR vo 1.0 : 2.5 Energy use percapita 0.8 son a fsa anaesa neinne 2.0 oe wn High EUR 0.4 1.0 Energy use per 2005 dollar of GDP 0.2 me 0.5 0 t T T 1 0 c T T T T T 1 1980 1995 2010 2020 2035 2000 2005 2010 2015 2020 2025 2030 2035 2 U.S, Energy Information Administration | Annual Energy Outlook 2012 With modest economic growth, increased efficiency, growing domestic production, and continued adaption of nonpetroleum liquids, net imports of petroleum and other liquids make up a smaller shareof total U.S. energy consumption U.S. dependence on imported petroleum and other liquids declines in the AEO2012 Reference case, primarily as a result of rising energy prices; growth in domestic crude oil production to more than 7 million barrels per day above 2010 levels in 2020; an increase of 1.2 million barrels per day crudeoil equivalent from 2010 to 2035in the use of biofuels, much of which is produced domestically; and slower growth of energy consumption in the transportation sector as a result of existing corporate average fuel economy standards. Proposed fuel economy standards covering vehicle model years (MY) 2017 through 2025 that are not included in the Reference case would further reduce projected needforliquid imports. Although U.S. consumption of petroleum and other liquid fuels continues to grow through 2035 in the Reference case, the reliance on imports of petroleum and other liquids as a share of total consumption declines. Total U.S. consumption of petroleum and other liquids, including both fossil fuels and biofuels, rises from 19.2 million barrels per day in 2010 to 19.9 million barrels per day in 2035 in the Reference case. The net import share of domestic consumption, which reached 60 percent in 2005 and 2006 before falling to 49 percent in 2010, continuesfalling in the Reference case to 36 percent in 2035 (Figure 3). Proposedlight-duty vehicles (LDV) fuel economystandards covering vehicle MY 2017 through 2025, which are not included in the Reference case, could further reduce demandfor petroleum and other liquids and the need for imports, and increased supplies from U.S. tight oil deposits could also significantly decrease the need for imports, as discussed in more detail in “Issues in focus.” Natural gas production increases throughoutthe projection period, allowing the United States to transition from a net importer to a net exporter of natural gas Muchof the growth in natural gas production in the AEO2072 Reference case results from the application of recent technological advances and continueddrilling in shale plays with high concentrations of natural gas liquids and crude oil, which have a higher value than dry natural gas in energy equivalent terms. Shale gas production increases in the Reference case from 5.0 trillion cubic feet per year in 2010 (23 percentoftotal U.S. dry gas production) to 13.6 trillion cubic feet per year in 2035 (49 percentof total U.S. dry gas production). As with tight oil, when looking forward to 2035, there are unresolved uncertainties surrounding the technological advances that have made shale gas productiona reality. The potential impact of those uncertainties results in a range of outcomesfor U.S. shale gas production from 9.7 to 20.5 trillion cubic feet per year when looking forward to 2035. As aresult of the projected growthin production, U.S. natural gas production exceeds consumptionearly in the next decadein the Reference case (Figure 4). The outlook reflects increased useof liquefied natural gas in markets outside North America, strong growth in domestic natural gas production, reduced pipeline imports and increased pipeline exports, and relatively low natural gas prices in the United States. Powergeneration from renewables and natural gas continues to increase In the Reference case, the natural gas share of electric power generation increases from 24 percent in 2010 to 28 percent in 2035, while the renewables share grows from 10 percent to 15 percent. In contrast, the share of generation fram coal-fired power plants declines. The historical reliance on coal-fired powerplants in the U.S. electric power sector has begun to wanein recent years. Figure 3. Total U.S. petroleum and other liquids Figure 4. Total U.S. natural gas production, production, consunmption, and net imports, 1970-2058 consuniplion, and net inporis, 900-2058 (million barrels per day) (trillion cubic feet) 95History, 2010 Projections 30 History -2010-——_—Projections 9Net imports, 2035 Net exports, 2035 i 20 aa _ 36% ’ pi ll Consumption ‘ 15 NL on Net imports, 2010 ve 11% Net imports, 2010 Net imports, 2005}: 49% | a — _ 1 Henry Hub spot market 60% 20 natural gas prices 10 1 : (2010 dollars per million Btu) ; ; ' Domestic production a Domestic production . ‘ 0 ' "1990 2010 2035 0 ! RY aeece ert ned 1970 1980 1990 2005 2010 2020 2035 1990 2000 2010 2020 2035 U.S. Energy Information Administration | Annual Energy Outlook 2012 3 Over the next 25 years, the share of electricity generation from coal falls to 38 percent, well below the 48-percent share seen as recently as 2008, due to slow growth in electricity demand, increased competition from natural gas and renewable generation, and the need to comply with new environmental regulations. Although the current trend toward increased use of natural gas and renewables appearsfairly robust, there is uncertainty about the factors influencing the fuel mix for electricity generation. AEO2012 includes several cases examining the impacts on coal-fired plant generation and retirements resulting from different pathsfor electricity demand growth, coal and natural gas prices, and compliance with upcoming environmental rules. While the Reference case projects 49 gigawatts of coal-fired generation retirements over the 2011 to 2035 period, nearly all of which occurs over the next 10 years, the range for cumulative retirements of coal-fired power plants over the projection period varies considerably across the alternative cases (Figure 5), from a low of 34 gigawatts (11 percentof the coal-fired generatorfleet) to a high of 70 gigawatts (22 percentof the fleet). The high end of the range is based on much lower natural gas prices than those assumed in the Reference case; the lower end of the range is based on stronger economic growth,leading to stronger growthin electricity demand and higher natura! gas prices. Other alternative cases, with varying assumptions about coal prices and the length of the period over which environmental compliance costs will be recovered, but no assumption of new policies to limit GHG emissions from existing plants,also yield cumulative retirements within a range of 34 to 70 gigawatts. Retirementsof coal-fired capacity exceed the high end of the range (70 gigawatts) whena significant GHG policy is assumed(for further description of the cases and results, see “Issues in focus”). Total energy-related emissions of carbon dioxide in the United Scates remain belowtheir 2005 level through 2035 Energy-related carbon dioxide (CO2) emissions grow slowly in the AEO2012 Reference case, due to a combination of modest economic growth, growing use of renewable technologies and fuels, efficiency improvements, slow growth in electricity demand, and increased use of natural gas, which is less carbon-intensive than other fossil fuels. In the Reference case, which assumes no explicit Federal! regulations to limit GHG emissions beyond vehicle GHG standards (although State programs and renewable portfolio standards are included), energy-related CO2 emissions grow byjust over 2 percent from 2010 to 2035,to a total of 5,758 million metric tons in 2035 (Figure 6). CO2 emissions in 2020 in the Reference case are more than 9 percent below the 2005level of 5,996 million metric tons, and they still are below the 2005level at the end of the projection period. Emissions per capita fall by an average of 1.0 percent per year from 2005 to 2035. Projections for COs emissions are sensitive to such economic and regulatory factors due to the pervasivenessof fossil fuel use in the economy. Theselinkages result in a range of potential GHG emissions scenarios. In the AEO2012 Low and High Economic Growth cases, projections for total primary energy consumption in 2035 are, respectively, 100.0 quadrillion Btu (6.4 percent below the Reference case) and 114.4 quadrillion Btu (7.0 percent above the Reference case), and projections for energy-related COemissions in 2035 are 5,356 million metric tons (7.0 percent below the Reference case) and 6,117 million metric tons (6.2 percent above the Reference case). Figure 5. Cumulative retirements of coal-fired Figure & U.S. eneray-related carbon dioxide generating capacity, 2001-2035 (gigawalts) emissions by sector and fuel, 2005 and 2035 (million metric tons) Reference : 4,000 _ __. ne 5,996 57 Reference 05 4770 vd ok gleum. High EUR 3,000 Total energy-related i aturalne ae gas | carbon dioxide emissions ‘' Coal Low EUR ricim 19002008 = 2oas, ectrity Low GasPrice 05 2,000 High Coal Cost Low Coal Cost 1,000 High Economic Growth Low Economic Growth : ' Residential Commercial Industrial Transportation Electric 0 25 50 75 power 4 U.S. Energy Information Administration | Annual Energy Outlook 2012 Electricity demand Heavy-duty vehicle energy demand continues to grow but slows from historical rates Figure 92, Heavy-duty vehicle energy consumption, 1998-2033 (quadrillicn Bty) 8 History 2010 Projections 6 _ te 4 2 0: T r T 1 1995 2005 2010 2015 2025 2035 Energy demand for HDVs—includingtractor trailers, vocational vehicles, heavy-duty pickups and vans, and buses—increases from 5.1 quadrillion Btu in 2010 to 6.2 quadrillion Btu in 2035,at an average annual growthrate of 0.8 percent, whichis the high- est among transportation modes. Still, the increase in energy demand for HDVsis lower than the 2-percent annual average from 1995 to 2010, as increases in VMTareoffset by improve- ments in fuel economyfollowing the recent introduction of new standards for HDVfuel efficiency and GHG emissions. The total numberof miles traveled annually by all HDVs grows by 48 percent from 2010 to 2035, from 234 billion miles to 345 billion miles, for an average annual increase of 1.6 percent. The rise in VMTis supported by rising economic output over the projection period and an increase in the numberof trucks on the road, from 8.9 million in 2010 to 12.5 million in 2035. Higher fuel economy for HDVspartially offsets the increase in their VMT,as average new vehicle fuel economyincreases from 6.6 mpg in 2010 to 8.2 mpg in 2035. The gain in fuel economy is primarily a consequence of the new GHG emissions andfuel efficiency standards enacted by EPA and NHTSAthat begin in MY 2014 and reach the moststringent levels in MY 2018 [728]. Fuel economy continues to improve moderately after 2018, as fuel-saving technologies continue to be adopted for economic reasons (Figure 92). Residential and commercial sectors dominate electricity demand growth Figure 93. U.S. electricity demand growth, 1930-2035 (percent, 3-vear moving average) 0 N Aheves moving average 6 Trendliné ON VN Yipee History 2010 Projections p h N O + -2 w 7 oe . r 1950 1970 1990 2010 2020 2035 Electricity demand (includingretail sales and direct use) growth has slowed in each decadesince the 1950s, from a 9.8-percent annual rate of growth from 1949 to 1959 to only 0.7 percent per year in the first decade of the 21st century. In the AEO2012 Reference case, electricity demand growth rebounds some- what from those low levels but remains relatively slow, as grow- ing demandfor electricity services is offset by efficiency gains from new appliance standards and investmentsin energy-effi- cient equipment (Figure 93). Electricity demand grows by 22 percent in the AEO2012 Reference case, from 3,877 billion kilowatthours in 2010 to 4,716 billion kilowatthours in 2035. Residential demand grows by 18 percent over the same period, to 1,718 billion kilowatt- hours in 2035, spurred by population growth,rising disposable income, and continued population shifts to warmer regions with greater cooling requirements. Commercial sector electric- ity demand increases by 28 percent, to 1,699 billion kilowatt- hours in 2035, led by demand in the service industries. In the industrial sector, electricity demand has been generally declin- ing since 2000, and it grows by only 2 percent from 2010 to 2035, slowed by increased competition from overseas manu- facturers and a shift of U.S. manufacturing toward consumer goods that require less energy to produce. Electricity demand in the transportation sector is small, but it is expected to more than triple from 7 billion kitowatthours in 2010 to 22 billion kilo- watthours in 2035 as sales of electric plug-in LDVs increase. Average annual electricity prices (in 2010 dollars) increase by 3 percent from 2010 to 2035 in the Reference case, generally falling through 2020 in response to lower fuel prices used to generate electricity. After 2020,rising fuel costs more than off- set lower costs for transmission and distribution. 86 U.S. Energy Information Administration | Annual Energy Outlook 2012 Coal-fired plants continue to be the largest source of U.S. electricity generation Figure 94. Electricity generation by fuel, 2010, 2020, and 2035 (oiion kilowatthours) 2,000 2010 2020 | 2035 4,500 | od | 1,000 ~~ 500 0 Coa Natural gas Nuclear Renewables Coal remains the dominantfuel for electricity generation in the AEO2012 Reference case (Figure 94), but its share declines sig- nificantly. in 2010, coal accounted for 45 percentof total U.S. generation; in 2020 and 2035its projected share of total gen- eration is 39 percent and 38 percent, respectively. Competition from natural gas and renewablesis a key factor in the decline. Overall, coal-fired generation in 2035 is 2 percent higher than in 2010 butstill 6 percent below the 2007 pre-recessionlevel. Generation from natural gas grows by 42 percent from 2010 to 2035, and its share of total generation increases from 24 per- cent in 2010 to 28 percent in 2035. The relatively low cost of natural gas makesthe dispatching of existing natural gas plants more competitive with coal plants and, in combination withrel- atively low capital costs, makes natural gas the primary choice to fuel new generation capacity. Generation from renewable sources grows by 77 percent in the Reference case, raising its share of total generation from 10 percent in 2010 to 15 percent in 2035. Most of the growthin renewable electricity generation comes from wind and biomass facilities, which benefit from State RPS requirements, Federal tax credits, and, in the case of biomass, the availability of low- cost feedstocks and the RFS. Generation from U.S. nuclear powerplants increases by 10 percent from 2010 to 2035,but the share of total generation declines from 20 percent in 2010 to 18 percent in 2035. Although new nuclear capacity is added by new reactors and uprates of olderones, total generation growsfaster and the nuclear sharefalls. Nuclear capac- ity grows from 101 gigawatts in 2010 to 111 gigawatts in 2035, with 7.3 gigawatts of additional uprates and 8.5 gigawatts of new capacity between 2010 and 2035. Someolder nuclear capacity is retired, which reduces overall! nuclear generation. Electricity generation Most new capacity additions use natural gas and renewables Figure 9S. Blectricity generation capacity additions by fuel type, including combined heat and power, 2011-2035 (gigawatts) Natural gas ; Renewables/other Nuclear Coal 30 20 - we . socseecteee 10 2026- 2030 2021- 2025 2016- 2020 2011- 2015 2031- 2035 Decisions to add capacity, and the choice of fuel for new capac- ity, depend on a numberof factors [129]. With growing elec- tricity demand and the retirement of 88 gigawatts of existing capacity, 235 gigawatts of new generating capacity Cincluding end-use combined heat and power) are projected to be added between 2011 and 2035 (Figure 95). Natural-gas-fired plants account for 60 percent of capacity additions between 2011 and 2035in the Reference case, com- pared with 29 percent for renewables, 7 percent for coal, and 4 percent for nuclear. Escalating construction costs have the largest impact on capital-intensive technologies, which include nuclear, coal, and renewables. However, Federal! tax incentives, State energy programs,and rising prices for fossil fuels increase the competitiveness of renewable and nuclear capacity. Current Federal and State environmental regulations also affect fossil fuel use, particularly coal. Uncertainty about future limits on GHG emissions and other possible environmental programs also reduces the competitiveness of coal-fired plants (reflected in AEQ2012 by adding 3 percentagepoints to the cost of capital for new coal-fired capacity). Uncertainty about demand growth and fuel prices also affects capacity planning. Total capacity additions from 2011 to 2035 range from 166 gigawatts in the Low Economic Growth case to 305 gigawatts in the High Economic Growth case. In the AEO2012 Low Tight Oil and Shale Gas Resource case, natural gas prices are higher than in the Reference case and new natu- ral gas fired capacity from 2011 to 2035 accounts for 102 giga- watts, which represents 47 percent of total additions. In the High Tight Oil and Shale Gas Resource case, delivered natural gas prices are lower than in the Reference case and natural gas- fired capacity additions by 2035 are 155 gigawatts, or 66 per- cent of total new capacity. U.S. Energy Information Administration | Annual Energy Outlook 2012 87 Electricity sales | Additions to powerplant capacity slow after 2012 but accelerate beyond 2020 Figure 96. Additionsto electricity generating capacity, {985-2035 (gigawatts) 2010History Projections 60 2 Other/renewables & @ Natural gas/oil : @ Nuclear 32 Hydropower Coal 40 moe 0) 1985 1995 2010 2025 2035 Typically, investments in electricity generation capacity have gone through “boom and bust”cycles. Periods of slower growth have been followed by strong growth in response to changing expectations for future electricity demand and fuel prices, as well as changesin the industry, such as restructuring (Figure 96). A construction boom in the early 2000s saw capacity additions averaging 35 gigawatts a year from 2000 to 2005, much higher than had been seen before. Since then, average annual builds have dropped to 17 gigawatts per year from 2006 to 2010. In the AEO2072 Reference case, capacity additions between 2011 and 2035 total 235 gigawatts, including new plants built not only in the power sector but also by end-use generators. Annual additions in 2011 and 2012 remain relatively high, aver- aging 24 gigawatts per year [730]. Of those early builds, about AO percent are renewable plants built to take advantage of Federal tax incentives and to meet State renewable standards. Annual builds drop significantly after 2012 and remain below 9 gigawatts per year until 2025. During that period, existing capacity is adequate to meet growth in demand in most regions, given the earlier construction boom and relatively slow growth in electricity demand after the economic recession. Between 2025 and 2035, average annual builds increase to 11 gigawatts per year, as excess capacity is depleted and the rate of total capacity growth is more consistent with electricity demand growth. More than 70 percent of the capacity additions from 2025 to 2035 are natural gasfired, given the higher construc- tion costs for other capacity types and uncertainty about the prospectsforfuture limits on GHG emissions. Growthin generating capacity parallels rising demandforelectricity Figure 97. Electricity sales and power sector generating capacity, 1949-2035 Undex, 1949 = 1.05 20 History _...2010Projections _ 45 Power sector generating capacity —— / Electricity sales 9) F T T + 1949 1965 1985 2010 2035 Over the long term, growth in electricity generating capac- ity parallels the growth in end-use demandfor electricity. However, unexpected shifts in demand or dramatic changes affecting capacity investment decisions can cause imbalances that can take years to work out. Figure 97 shows indexes summarizing relative changesin total generating capacity and electricity demand. During the 1950s and 1960s, the capacity and demand indexestracked closely. The energy crises of the 1970s and 1980s, together with other factors, slowed electricity demand growth, and capacity growth outpaced demand for more than 10 years thereafter, as planned units continued to come on line. Demand and capacity did not align again until the mid-1990s. Then,in the late 1990s, uncer- tainty about deregulation of the electricity industry caused a downturn in capacity expansion, and another period of imbal- ance followed, with growth in electricity demand exceeding capacity growth. In 2000, a boom in construction of new natural gas fired plants began, quickly bringing capacity back into balance with demandand,in fact, creating excess capacity. Construction of new intermittent wind capacity that sometimes needs backup capacity also began to grow after 2000. More recently, the 2008-2009 economic recession caused a significant drop in electricity demand, which has recovered only partially in the post-recession period. In combination with slow near-term growth in electricity demand, the slow economic recovery creates excess generating capacity in the AEO2012 Reference case. Capacity currently under construction is completed in the Reference case, but only a limited amountof additional capac- ity is built before 2025, while older capacity is retired. In 2025, capacity growth and demand growtharein balance again, and they grow at similar rates through 2035. 88 U.S. Energy information Administration | Annual Energy Outlook 2012 San Joaquin Valley Air Pollution Control District AUTHORITY TO CONSTRUCT PERMIT NO: $-3523-1-2 ISSUANCEDATE: 03/30/2000 LEGAL OWNER OR OPERATOR: ELK HILLS POWER LLC MAILING ADDRESS: PO BOX 460 4026 SKYLINE ROAD TUPMAN, CA 93276 LOCATION: NW CORNER OFELK HILLS RD & SKYLINE RD CA SECTION: NE35 TOWNSHIP: 30S RANGE:23E EQUIPMENT DESCRIPTION: MODIFICATION OF PREVIOUSLY AUTHORIZED GE FRAME 7 MODEL PG7241FA NATURAL GAS FIRED COMBINED CYCLE GAS TURBINE ENGINE/ELECTRICAL GENERATOR#1 WITH DRY LOW NOX COMBUSTORS,SELECTIVE CATALYTIC REDUCTION, OXIDATION CATALYST, AND STEAM TURBINE SHARED WITH S-3532-2 (503 MW TOTAL PLANT NOMINAL RATING): ALLOW REDUCTION OF PM10 EMISSION LIMITS AND PM10 OFFSET REQUIREMENTS BASED ONINITIAL SOURCE TEST RESULTS CONDITIONS 1. No air contaminantshall be released into the atmosphere which causes a public nuisance. [District Rule 4102] 2. Permittee shal! submit selective catalytic reduction, oxidation catalyst, and continuous emission monitor design details to the District at least 30 days prior to commencementof construction. [District Rule 2201] 3. Combustion turbine generator (CTG)and electrical generator lube oil vents shall be equipped with mist eliminators to maintain visible emissions from lube oil vents no greater than 5%opacity, exceptfor three minutes in any hour. {District Rule 2201] 4. CTGshall be equipped with continuously recording fuel gas flowmeter. [District Rule 2201] CTG exhaust shall be equipped with continuously recording emissions monitor (CEM) for NOx (before and after the SCR unit), CO, and O2 dedicated to this unit. Continuous emission monitors shall meet the requirements of 40 CFR Part 60 Appendices B & F, and 40 CFR Part 75, and shall be capable of monitoring emissions during startups and shutdownsas well as normaloperating conditions. If relative accuracy of CEM(s) cannotbecertified during startup conditions, CEM results during startup and shutdown eventsshall be replaced with startup emission rates obtained during source testing to determine compliance with emission limits in conditions 15, 18, 19, & 20. [District Rule 2201] CONDITIONS CONTINUE ON NEXT PAGE YOU MUST NOTIFY THE DISTRICT COMPLIANCE DIVISION AT (661) 326-6900 WHEN CONSTRUCTION IS COMPLETED AND PRIOR TO OPERATING THE EQUIPMENT OR MODIFICATIONS AUTHORIZED BY THIS AUTHORITY TO CONSTRUCT. This is NOT a PERMIT TO OPERATE. Approval or denial of a PERMIT TO OPERATEwill be madeafter an inspection to verify that the equipment has been constructed in accordance with the approved plans, specifications and conditions of this Authority to Construct, and to determineif the equipment can be operated in compliance with all Rules and Regulations of the San Joaquin Valley Unified Air Pollution Control District. Unless construction has commenced pursuant to Rule 2050,this Authority to Construct shall expire and application shall be cancelled two years from the date of issuance. The applicantis responsible for complying with all laws, ordinances and regulations of all other governmental agencies which maypertain to the above equipment. DAVID L, CROW, Executive Director / APCO Lf. SEYED SADREDIN, Director of Permit Services $-3S23-1-2 Owe 18 2007 4 4PM - TOMLNg <= Jot mspecion Requsred wath LOMLINS Southem Regional Office « 2700 M Street, Suite 275 « Bakersfield, CA 93301-2370 ¢ (661) 326-6900 « Fax (661) 326-6985 Conditions for S-3523-1-2 (continued) Page 2 of 4 6. 10. 1. 12. 13. 14, 15. 16. 17. 19, 20. 21. Thefacility shalf install and maintain equipment, facilities, and systems compatible with the District's CEM data polling software system and shall make CEM data available to the District's automatedpolling system on daily basis. [District Rule 1080] Uponnotice by the District that the facility's CEM system is not providing polling data, the facility may continue to operate without providing automated data for a maximum of 30 days per calendar year provided the CEM data is sent to the District by a District-approved alternative method. [District Rule 1080] Ammoniainjection grid shall be equipped with operational ammonia flowmeter and injection pressure indicator. [District Rule 2201] Exhauststack shall be equipped with permanent provisionsto allow collection of stack gas samples consistent with EPAtest methods. [District Rule 1081] Heat recovery steam generator design shall provide space for additional selective catalytic reduction catalyst and oxidation catalyst if required to meet NOx and CO emission limits. [District Rule 2201] Permittee shall monitor and record exhaust gas temperatureat selective catalytic reduction and oxidation catalyst inlets. [District Rule 2201] CTGshall be fired exclusively on natural gas, consisting primarily of methane and ethane, with a sulfur content no greater than 0.75 grainsof sulfur compounds(as S) per 100 dry scf of natural gas. [District Rule 2201] Startup is defined as the period beginning with turbineinitial firing until the unit meets the !b/hr and ppmv emission limits in condition 15. Shutdown is defined the period beginning with initiation of turbine shutdown sequence and ending with cessation of firing of the gas turbine engine. Startup and shutdown durations shall not exceed two hours for a regular startup, four hours for an extended startup, and one hour for a shutdown,per occurrence.[District Rule 2201 and 4001] Ammoniashall be injected when the selective catalytic reduction system catalyst temperature exceeds 500 degreesF. Permittee shall monitor and record catalyst temperature during periods ofstartup. [District Rule 2201] During startup or shutdownof any gas turbine engine(s), combined emissions from both gasturbine engines (S-3523-1 and -2) heat recovery steam generator exhausts shall not exceed anyof the following: NOx (as NO2) - 76 Ib and CO - 38 lb in any one hour. [CEQA] , By two hoursafter turbine initial firing, CTG exhaust emissionsshall not exceed any ofthe following: NOx (as NO2)- 12.2 ppmv @ [5% O2 and CO - 25 ppmv @ 15% O2.[District Rule 4703] Emission rates from each CTG,except during startup and/or shutdown, shall not exceed any of the following: PM10- 18.0 lb/hr, SOx (as SO2)- 3.6 lb/hr, NOx (as NO2)- 15.8 Ib/hr and 2.5 ppmvd @ 15% O2, VOC - 4.0 Ib/hr and 2.0 ppmvd @ 15% O02, CO - 32.5 lb/hr and 4 ppmvd @ 15% O2, ammonia - 10 ppmvd @15% O02. NOx (as NO2) emission limit is a one-hourrolling average. Ammonia emission limit is a twenty-four hourrolling average. Al] other emission limits are three-hour rolling averages. [District Rules 2201, 4001, and 4703] Emissionrates from each CTG, on days when a startup or shutdown occurs, shall not exceed any ofthe following: PM10 - 432.0 Ib/day, SOx (as SO2)- 86.4 Ib/day, NOx (as NO2)- 418.5 Ib/day, VOC - 96.0 Ib/day, and CO - 326.7 Ib/day. [District Rule 2201] Emission rates from both CTGs (S-3523-1 and -2), on days whena startup or shutdown occursfor either or both turbines, shall not exceed any ofthe following: PM10 - 864.0 Ib/day, SOx (as SO2) - 172.8 Ib/day, NOx (as NO2)- 817.8 Ib/day, VOC - 192.0 Ib/day, and CO - 640.4 Ib/day. [District Rule 2201] Annual emissions from both CTGscalculated on a twelve consecutive month rolling basis shall not exceed any ofthe following: PM10 - 315,360 Ib/year , SOx (as SO2) - 57,468 Ib/year, NOx (as NO2) - 285,042 Ib/year, VOC - 64,478 Ib/year, and CO - 223,040 Ib/year. [District Rule 2201] Each one-hourperiod in a one-hourrolling average will commence on the hour. Each one-hour period in a three-hour rolling average will commence on the hour. The three-hour average will be compiled from the three mostrecent one- hour periods. Each one-hourperiod in a twenty-four-hour average for ammoniaslip will commenceon the hour. The twenty-four-hour average will be calculated starting and endingat twelve-midnight. [District Rule 2201] CONDITIONS CONTINUE ONNEXT PAGE S3573- 1-2: Dec 18 2007 4 24PRt - TOMLINS Conditions for S-3523-1-2 (continued) Page 3 of 4 22. 23. 24. 25. 26. 27. 28. 29. 30. 31. 32. 33. 34. Daily emissionswill be compiled for a twenty-four period starting and ending at twelve-midnight. Each calendar - monthin a twelve-consecutive-month rolling emissions will commenceatthe beginning ofthe first day of the month. The twelve-consecutive-monthrolling emissionstotal to determine compliance with annual emissionswill be compiled from the twelve mostrecent calendar months. [District Rule 2201] Prior to commencementofoperation of the equipmentcovered by permit numbers S-3523-1, -2, & 3, emission offsets shall be tendered forall calendar quarters in the following amounts,at the offset ratio specified in Rule 2201 (6/15/95 version) Table 1, PM10 - Q1: 78,596 Ib, Q2: 79,470 Ib, Q3: 80,343 lb; and Q4: 80,343 Ib; SOx (as SO2) - Q1: 14,170 Ib, Q2: 14,328 Ib , Q3: 14,485 Ib, and Q4: 14,485 Ib; NOx (as NO2) - Q1: 65,353 Ib, Q2: 66,079 Ib, Q3: 66,805 Ib, and Q4: 66,805 Ib; and VOC - Q1: 10,967 Ib, Q2: 11,089 Ib, Q3: £1,211 Ib, and Q4: 11,211 Ib. [District Rule 2201] NOx and VOC emission reductions that occurred from Aprit through November maybeusedto offset increases in NOx and VOCrespectively during any periodofthe year. [District Rule 2201] NOx ERCs maybe usedto offset PM10 emission increases at a ratio of 2.42 Ib NOx: | Ib PM10 for reductions occurring within 15 miles ofthis facility, and at 2.72 Ib NOx : 1 Ib PM10for reductions occurring greater than 15 miles from this facility [District Rule 2201] At least 30 days prior to commencementofconstruction, the permittee shall provide the District with written documentationthat all necessary offsets have been acquired or that binding contracts to secure such offsets have been entered into. [District Rule 2201] Compliance with ammoniaslip limit shall be demonstrated by using the following calculation procedure: ammonia slip ppmv @ 15% O2 = ((a-(bx¢/1,000,000)) x 1,000,000 /b) x d, where a = ammoniainjection rate(Ib/hr)/1 7(ib/lb. moh), b = dry exhaustgas flow rate (Ib/hr)/(29(ib/Ib. mol), c = change in measured NOx concentration ppmvat 15% O2 across catalyst, and d = correction factor. The correction factor shall be derived annually during compliancetesting by comparing the measured and calculated ammoniaslip. Alternatively, permittee mayutilize a continuousin-stack ammonia monitor, acceptable to the District, to monitor compliance. At least 60 days prior to using a NH3 CEM,the permittee must submit a monitoring plan for District review and approval [District Rule 4102] Compliance with the short term emission limits (Ib/hr and ppmv @ 15% O02) shall be demonstrated within 60 days of initial operation of each gas turbine engine and annuaily thereafter by District witnessed in situ sampling of exhaust gasses by a qualified independent sourcetest firm at full load conditions as follows - NOx: ppmvd @ 15% O2 and ib/hr, CO: ppmvd @ 15% O2 and lb/hr, VOC: ppmvd @ 15% O2and Ib/hr, PM 10: lb/hr, and ammonia: ppmvd @ 15% O2, Sample collection to demonstrate compliance with ammonia emissionlimit shall be based on three consecutive test runs of thirty minutes each. [District Rule 1081] Compliance with the startup NOx, CO, and VOC mass emissionlimits shall be demonstrated for one of the CTGs (S- 3523-1, or -2) upon initial operation and at least every seven yearsthereafter by District witnessed in situ sampling of exhaust gases by a qualified independentsourcetest firm. [District Rule 1081] Compliance with natural gas sulfur contentlimit shall be demonstrated within 60 days of operation of each gas turbine engine and periodically as required by 40 CFR 60 Subpart GG and 40 CFR 75. {District Rules 1081, 2540, and 4001] TheDistrict must be notified 30 days prior to any compliance sourcetest, and a source test plan must be submitted for approval 15 daysprior to testing. Official test results and field data collected by sourcetests required by conditions on this permit shall be submitted to the District within 60 days oftesting. [District Rule 1081] Sourcetest plans for initial and seven-year sourcetests shall include a method for measuring the VOC/CO surrogate relationship that wilt be used to demonstrate compliance with VOCIb/hr, lb/day, and Ib/twelve month rolling emission limits. [District Rule 2201] The following test methods shall be used PM10: EPA method5 (front half and back half), NOx: EPA Method 7E or 20, CO: EPA method 10 or 10B, O02: EPA Method3, 3A, or 20, VOC: EPA method 18 or 25, ammonia: BAAQMD ST-1B, and fuel gas sulfur content: ASTM D3246. EPA approved alternative test methods as approved bythe District may also be used to addressthe source testing requirements ofthis permit. [District Rules 1081, 4001, and 4703} The permittee shall notify District of date ofinitiation of construction no later than 30 days after such date, date of anticipated startup not more than 60 days norless than 30 daysprior to such date, and date of actual startup within 15 daysafter such date. [District Rule 4001] CONDITIONS CONTINUE ON NEXT PAGE $-3523-1-2, Dec 18 2007 4 24PM - TOMUNS Conditions for S-3523-1-2 (continued) Page 4 of 4 35. 36. 37. 38. 39. 40. Al. 42. 43. 44. 45. 46. 47. The permittee shall maintain hourly records ofNOx, CO, and ammonia emission concentrations (ppmv @ 15% 02), and hourly, daily, and twelve month rolling average records ofNOx and CO emissions. Compliance with the hourly, daily, and twelve month rolling average VOC emission limits shall be demonstrated by the CO CEM data andthe VOC/COrelationship determined by annual CO and VOCsourcetests. [District Rule 2201] The permittee shall maintain records of SOx lb/hr, Ib/day, and Ib/twelve month rolling average emission. SOx emissions shall be based on fuel use records, natural gas sulfur content, and mass balance calculations. [District Rule 2201] Permittee shall maintain the following records for the CTG: occurrence, duration, and type of any startup, shutdown, or malfunction; emission measurements;total daily and annual hours of operation; and hourly quantity offuel used. (District Rules 2201 & 4703] Permittee shall maintain the following records for the continuous emissions monitoring system (CEMS): performance testing, evaluations, calibrations, checks, maintenance, adjustments, and any period of non-operation of any continuous emissions monitor. [District Rules 2201 & 4703] All records required to be maintainedby this permit shall be maintained for a periodoffive years and shall be made readily available for District inspection upon request. [District Rule 2201] Results of continuous emissions monitoring shall be reduced according to the procedureestablished in 40 CFR,Part 51, Appendix P, paragraphs5.0 through 5.3. 3, or by other methods deemed equivalent by mutual agreement with the District, the ARB, and the EPA.[District Rule 1080] Thepermittee shall notify the District of any breakdown condition as soon as reasonably possible, but nolater than one hourafter its detection, unless the owner or operator demonstrates to the Districts satisfaction that the longer reporting period wasnecessary. [District Rule 1100] The District shall be notified in writing within ten days followingthe correction of any breakdown condition. The breakdown notification shal] include a description of the equipment malfunction orfailure, the date and cause of the initial failure, the estimated emissions in excessof those allowed, and the methodsutilized to restore normal operations. [District Rule 1100] Audits of continuous emission monitors shall be conducted quarterly, except during quarters in whichrelative accuracy and total accuracy testing is performed,in accordance with EPA guidelines. The District shall be notified prior to completion of the audits. Audit reports shall be submitted along with quarterly compliancereports to the District. [District Rule 1080] The permittee shall comply with the applicable requirements for quality assurancetesting and maintenance ofthe continuous emission monitor equipment in accordance with the procedures and guidance specified in 40 CFR Part 60, Appendix F . [District Rule 1080] The permittee shall submit a written report to the APCO for each calendar quarter, within 30 daysof the end of the quarter, including: time intervals, data and magnitude of excess emissions, nature and cause of excess (if known), corrective actions taken and preventive measures adopted; averaging period used for data reporting shall correspond to the averaging period for each respective emission standard; applicable time and date of each period during which the CEM wasinoperative (except for zero and span checks) andthe nature of system repairs and adjustments; and a negative declaration when no excess emissions occurred . [District Rule 1080] Permittee shall submit an application to comply with Rule 2540 - Acid Rain Program 24 monthsbefore the unit commencesoperation. [District Rule 2540] Permittee may lower hourly, daily, and rolling twelve-month PM10 emissionlimits in Conditions 17, 18, 19, and 20, and thereby reduce PM10 offset requirements set forth in condition 23, based on actual PM10 emissions demonstrated during initial source tests. Revised emission limits shall be submitted to the District within 60 days after the last unit is initially source tested. The District will reflect revised limits in the Permit to Operate for the subject equipment. Any emission reduction credit (ERC)certificates, or portions thereof, that were tenderedto the District but are not needed to meet reduced PM10 offset requirements will be returned to the permittee at full value. The permittee shall indicate which ERCcertificates are to be retired. [District Rule 2201} $-1529-1-2° Dec 16 7002 4 2464s — TOMLINS. San Joaquin Valley Air Pollution Control District AUTHORITY TO CONSTRUCT PERMIT NO: S-3523-2-2 ISSUANCE DATE:03/30/2000 LEGAL OWNER OR OPERATOR: ELK HILLS POWER LLC MAILING ADDRESS: PO BOX 460 4026 SKYLINE ROAD TUPMAN, CA 93276 LOCATION: NW CORNEROF ELK HILLS RD & SKYLINE RD CA SECTION: NE35 TOWNSHIP: 30S RANGE:23E EQUIPMENT DESCRIPTION: MODIFICATION OF PREVIOUSLY AUTHORIZED GE FRAME 7 MODEL PG7241FA NATURAL GAS FIRED COMBINED CYCLE GAS TURBINE ENGINE/ELECTRICAL GENERATOR#2 WITH DRY LOW NOX COMBUSTORS,SELECTIVE CATALYTIC REDUCTION, OXIDATION CATALYST, AND STEAM TURBINE SHAREDWITH S-3532-1 (503 MW TOTAL PLANT NOMINAL RATING): ALLOW REDUCTION OF PM10 EMISSION LIMITS AND PM10 OFFSET REQUIREMENTS BASEDONINITIAL SOURCE TEST RESULTS CONDITIONS 1. Noair contaminantshall be released into the atmosphere which causes a public nuisance. [District Rule 4102) 2. Permittee shall submit selective catalytic reduction, oxidation catalyst, and continuous emission monitor design details to the District at least 30 days prior to commencementofconstruction. [District Rule 2201] 3. Combustion turbine generator (CTG)and electrical generator lube oil vents shall be equipped with mist eliminators to maintain visible emissions from lubeoil vents no greater than 5% opacity, except for three minutesin any hour. [District Rule 2201] 4. CTG shall be equipped with continuously recording fuel gas flowmeter. [District Rule 2201] CTG exhaust shall be equipped with continuously recording emissions monitor (CEM)for NOx (before and after the SCRunit), CO, and O2 dedicated to this unit, Continuous emission monitors shal} meet the requirements of 40 CFR Part 60 Appendices B & F, and 40 CFR Part 75, and shalt be capable of monitoring emissions during startups and shutdownsas well as normal operating conditions. If relative accuracy of CEM(s) cannotbecertified during startup conditions, CEM results during startup and shutdownevents shall be replaced with startup emission rates obtained during source testing to determine compliance with emission limits in conditions 15, 18 19, & 20. [District Rule 2201) CONDITIONS CONTINUE ON NEXT PAGE YOU MUST NOTIFY THE DISTRICT COMPLIANCE DIVISION AT (661) 326-6900 WHEN CONSTRUCTION IS COMPLETED AND PRIOR TO OPERATING THE EQUIPMENT OR MODIFICATIONS AUTHORIZED BY THIS AUTHORITY TO CONSTRUCT. This is NOT 2 PERMIT TO OPERATE. Approval or denial of a PERMIT TO OPERATEwill be madeafter an inspection to verify that the equipment has been constructed in accordance with the approved plans, specifications and conditions of this Authority to Construct, and to determineif the equipment can be operated in compliance with ail Rules and Regulations of the San Joaquin Valley Unified Air Pollution Control District. Unless construction has commenced pursuant to Rule 2050, this Authority to Construct shall expire and application shall be cancelled two years from the date of issuance. The applicantis responsible for complying with all laws, ordinances and regulations of all other governmental agencies which may pertain to the above equipment. DAVID L. CROW,Executive Director / APCO A | FLY SEYED SADREDIN,Director of Permit Services $-3523-2-2. Dec 18 2002 €24Pu:~ TOMUNS - Jord inspection Requred with TOMINS. Southern Regional Office *« 2700 M Street, Suite 275 ¢ Bakersfield, CA 93301-2370 (66%) 326-6900 » Fax (661) 326-6985 Conditions for S-3523-2-2 (continued) Page 3 of 4 22. 23. 24, 25. 26. 27. 28. 29. 30. 31.: 32. 33. 34. Daily emissions will be compiled for a twenty-four period starting and ending at twelve-midnight. Each calendar month in a twelve-consecutive-monthrolling emissions will commenceat the beginning ofthe first day of the month. The twelve-consecutive-month rolling emissionstotal to determine compliance with annual emissionswill be compiled from the twelve most recent calendar months.[District Rule 2201] Prior to commencementofoperation of the equipment covered by permit numbers S-3523-1, -2, & 3, emission offsets shall be tendered for all calendar quarters in the following amounts,at the offset ratio specified in Rule 2201 (6/15/95 version) Table 1, PM10 - Q1: 78,596 Ib, Q2: 79,470 Ib, Q3: 80,343 Ib, and Q4: 80,343 Ib; SOx (as SO2) - QI: 14,170 Ib, Q2: 14,328 Ib , Q3: 14,485 Ib, and Q4: 14,485 Ib; NOx (as NO2) - Q1: 65,353 Ib, Q2: 66,079 Ib, Q3: 66,805 lb, and Q4: 66,805 Ib; and VOC - Q1: 10,967 Ib, Q2: 11,089 Ib, Q3: 11,211 Ib, and Q4: 11,211 Ib. [District Rule 2201) NOx and VOC emission reductions that occurred from April through November maybe used to offset increases in NOx and VOCrespectively during any period ofthe year. [District Rule 2201] NOx ERCs maybe used to offset PM10 emission increasesat a ratio of 2.42 lb NOx: 1 1b PM10 for reductions occurring within 15 miles ofthis facility, and at 2.72 Ib NOx : 1 lb PM10 for reductions occurring greater than 15 miles from thisfacility [District Rule 2201} Atleast 30 days prior to commencementofconstruction, the permittee shall provide the District with written documentation that all necessary offsets have been acquired or that binding contracts to secure such offsets have been entered into. {District Rule 2201] Compliance with ammoniaslip limit shall be demonstrated by using the following calculation procedure: ammonia slip ppmv @ 15% O2 = ((a-(bxc/1,000,000)) x 1,000,000 / b) x d, where a = ammonia injection rate(Ib/hr)/17(ib/Ib. mol), b = dry exhaust gasflow rate (Ib/hr)/(29(Ib/Ib. mol), c = change in measured NOx concentration ppmv at 15% O2 across catalyst, and d = correction factor. The correction factor shall be derived annually during compliance testing by comparing the measured and calculated ammoniaslip. Alternatively, permittee may utilize a continuousin-stack ammonia monitor, acceptable to the District, to monitor compliance. At least 60 daysprior to using a NH3 CEM,the permittee must submit a monitoring plan for District review and approval[District Rule 4102} Compliance with the short term emission limits (lb/hr and ppmv @ 15% O2) shall be demonstrated within 60 days of initial operationof each gas turbine engine and annually thereafter by District witnessed in situ sampling of exhaust gasses by a qualified independentsourcetestfirm at full load conditions as follows - NOx: ppmvd @ 15% O02 and lb/hr, CO: ppmvd @ 15% O2 and Ib/hr, VOC: ppmvd @ 15% O2andIb/hr, PM10:Ib/hr, and ammonia: ppmvd @ 15% O2, Sample collection to demonstrate compliance with ammonia emission limit shall be based on three consecutivetest runsofthirty minutes each. [District Rule 1081] Compliance with the startup NOx, CO, and VOC massemissionlimits shall be demonstrated for one ofthe CTGs (S- 3523-1, or -2) upon initial operation and at least every seven years thereafter by District witnessed in situ sampling of exhaust gases by a qualified independent sourcetest firm. [District Rule 1081] Compliance with natural gas sulfur contentlimit shall be demonstrated within 60 days of operation of each gas turbine engine and periodically as required by 40 CFR 60 Subpart GG and 40 CFR 75. [District Rules 1081, 2540, and 4001} TheDistrict must be notified 30 days prior to any compliance sourcetest, and a source test plan must be submitted for approval 15 dayspriorto testing. Official test results and field data collected by source tests required by conditions on this permit shall be submitted to the District within 60 days oftesting. [District Rule 1081] Source test plans forinitial and seven-year sourcetests shall include a method for measuring the VOC/COsurrogate relationship that will be used to demonstrate compliance with VOC lb/hr, Ib/day, and !b/twelve monthrolling emission limits. (District Rute 2201] The following test methodsshall be used PM10: EPA method5 (front half and back half), NOx: EPA Method 7E or 20, CO: EPA method 10 or 10B, 02: EPA Method 3, 3A, or 20, VOC: EPA method 18 or 25, ammonia: BAAQMD ST-1B, and fuel gas sulfur content: ASTM D3246. EPA approved alternative test methods as approved bythe District may also be used to address the source testing requirements ofthis permit, [District Rules 1081, 4001, and 4703] Thepermittee shall notify District of date ofinitiation of construction nolater than 30 daysafter such date, date of anticipated startup not more than 60 daysnorless than 30 daysprior to such date, and date of actual startup within 15 days after such date. [District Rule 4001] CONDITIONS CONTINUE ON NEXT PAGE S38273-2-2: Dec 18 2002 4 247 ut TOMLINS Conditions for S-3523-2-2 (continued) _ Page 4 of 4 35. 36. 37. 38. 39. 40. 4]. 42. 43. 44, 45. 46. 47. The permittee shall maintain hourly records ofNOx, CO, and ammonia emission concentrations (ppmv @ 15% O2), and hourly, daily, and twelve monthrolling average records ofNOx and CO emissions. Compliance with the hourly, daily, and twelve monthrolling average VOC emission limits shall be demonstrated by the CO CEM data and the VOC/COrelationship determined by annual CO and VOCsourcetests. [District Rule 2201] The permittee shall maintain records of SOx !b/hr, Ib/day, and Ib/twelve monthrolling average emission. SOx emissions shall be based on fuel use records, natural gas sulfur content, and massbalance calculations. {District Rule 2201] Permittee shall maintain the following records for the CTG: occurrence, duration, and type of any startup, shutdown, or malfunction; emission measurements; total daily and annual hours of operation; and hourly quantity of fuel used. [District Rules 2201 & 4703] Permittee shall maintain the following records for the continuous emissions monitoring system (CEMS): performance testing, evaluations, calibrations, checks, maintenance, adjustments, and any period of non-operation of any continuous emissions monitor. [District Rules 2201 & 4703] All records required to be maintained bythis permit shall be maintained fora period of five years and shall be made readily available for District inspection upon request. [District Rule 2201] Results of continuous emissions monitoring shall be reduced according to the procedure established in 40 CFR, Part 51, Appendix P, paragraphs5.0 through 5.3. 3, or by other methods deemed equivalent by mutual agreement with the District, the ARB, and the EPA.[District Rule 1080] The permittee shall notify the District of any breakdown condition as soon as reasonably possible, but no later than one hour after its detection, unless the owner or operator demonstrates to the Districts satisfaction that the longer reporting period was necessary. [District Rule 1100] TheDistrict shall be notified in writing within ten days following the correction of any breakdown condition. The breakdown notification shall include a description of the equipment malfunction orfailure, the date and cause of the initial failure, the estimated emissions in excess ofthose allowed, and the methodsutilized to restore normal operations. [District Rule 1100] Audits of continuous emission monitors shall be conducted quarterly, except during quarters in which relative accuracy and total accuracy testing is performed, in accordance with EPA guidelines. The District shall be notified prior to completion of the audits. Audit reports shall be submitted along with quarterly compliancereports to the District. [District Rule 1080] The permittee shall comply with the applicable requirements for quality assurance testing and maintenanceof the continuous emission monitor equipment in accordance with the procedures and guidance specified in 40 CFR Part 60, Appendix F . [District Rule 1080] The permittee shall submit a written report to the APCOfor each calendar quarter, within 30 days of the end of the quarter, including: time intervals, data and magnitude ofexcess emissions, nature and cause ofexcess(if known), corrective actions taken and preventive measures adopted; averaging period used for data reporting shall correspond to the averaging period for each respective emission standard; applicable time and date of each period during which the CEM wasinoperative (except for zero and span checks) andthe nature of system repairs and adjustments; and a negative declaration when no excess emissions occurred . [District Rule 1080] Permittee shall submit an application to comply with Rule 2540 - Acid Rain Program 24 monthsbeforethe unit commencesoperation. [District Rule 2540] Permittee may lower hourly, daily, and rolling twelve-month PM10 emission limits in Conditions 17, 18, 19, and 20, and thereby reduce PM10 offset requirements set forth in condition 23, based on actual PM10 emissions demonstrated during initial source tests. Revised emission limits shall be submitted to the District within 60 daysafter the last unit is initially source tested. The District will reflect revised limits in the Permit to Operate for the subject equipment. Any emission reduction credit (ERC)certificates, or portions thereof, that were tendered to the District but are not needed to meet reduced PM10 offset requirements will be retumed to the permittee at full value. The permittee shall indicate which ERCcertificates are to be retired. [District Rule 2201] 5-3573-2-2: Dec 18 2002 4 24PM — TORUNS ‘ALIFORNIA ENERGY COMMISSION 16 NINTH STREET \CRAMENTO, CA 95814-5512 STATE OF CALIFORNIA State Energy Resources Conservation and Development Commission Docket No. 99-AFC-1C Order No. 03-0319-1(a) In the Matterof: Elk Hills Power Project Petition to Allow for Tendering of PMio ERCsand for a Temporary Increase in Commissioning Emissions COMMISSION ORDER APPROVING PROJECT MODIFICATION On December11, 2002, the California Energy Commission (Energy Commission) received a petition from Elk Hills Power, LLC to modify air quality Conditions of Certification to allow for tendering of PMjo emission reduction credits based on the outcomeofinitial source tests, and to allow for a temporary increase in commissioning emissions. At a regularly scheduled Business Meeting on March 19, 2003, the Energy Commission considered staff's analysis and approved revised and new air quality Conditions of Certification in accordance with Title 20, section 1769(a)(3) of the California Code of Regulations, allowing for the tendering of emission reduction credits and for a temporary increase in emissions during commissioning. COMMISSION FINDINGS Based onstaffs analysis, the Energy Commissionfindsthat: A. There will be no new oradditional unmitigated significant environmental impacts associated with the proposed change. B. The facility will remain in compliance with all applicable laws, ordinances, regulations, and standards, subject to the provisions of Public Resources code section 25525. C. The change will be beneficial to the project owner by allowing for flexibility to reduce the amount of emission reductions credits surrendered to the San JoaquinValley Air Pollution Control District, and by allowing for operational efficiency during the commissioning phase. D. There has been a substantial change since the Energy Commissioncertification based on the project owner’s re-evaluation of operational issues that were not available during the siting process. Mach19, 2003 Page 2 ORDER The California Energy Commission hereby approves the tendering of PMjo emission reduction credits based on the outcomeofinitial source tests, and approves a temporary increase in commissioning emissions. NEW ANDREVISIONS TO EXISTING CONDITIONS OF CERTIFICATION (Deleted text is shown in strikethrough, and new text is underlined). AQ-21 Prior to commencement of operation erapernstartup of S-3523-1-0, -2-0, & 3-0, emission offsets shall be tendered surrendered for all calendar quarters in the following amounts, at the offset ratio specified in Rule 2201 (6/15/95 version) Table 1, PM10 - Q1: 78,596 Ib, Q2: 79,470 Ib, Q3: 80,343 lb, and Q4: 80,343 lb; and surrendered for all calendar quarters in the following amounts, at the offset ratio specified in Rule 2201 (6/15/95 version) Table 1, SOx (as SO2) - QI: 14,170 lb, Q2: 14,328 lb , Q3: 14,485 lb, and Q4: 14,485 Ib; NOx (as NO2) - QI: 65,353 Ib, Q2: 66,079 lb, Q3: 66,805 Ib, and Q4: 66,805 lb; and VOC - Q1: 10,967 Ib, Q2: 11,089 Ib, Q3: 11,211 Ib, and Q4: 11,211 lb. [District Rule 2201] Verification: The owner/operator shall submit copies ofERCs tendered or surrendered to the SJVUAPCDinthe totals shown to the CPM prior to commencementof operation erapen-startup of the CTGsor cooling tower. AQ-63_ The project owner may lower hourly, daily, and rolling average twelve-month PM10 emission limits in Conditions AQ-15, AQ-16, AQ-17, and AQ-18, and thereby reduce PM10 offset requirements set forth in AQ-21, based on actual PM10 emissions demonstrated during initial source tests. Revised emission limits shall be submitted to the District within 60 days after the last unit is initially source tested. The District will reflect revised limits in the permit to operate for the subject equipment. Any emission reduction credit certificates, or portions thereof, that were tendered to the District but are not needed to meet reduced PM10 offset requirements will be returned to the project ownerat full value. The project owner shall indicate which emission reduction credit certificates are to be retired. Verification: The project ownershall notify the CPM and District of any proposed changesin PML10 emission limits and indicate which ERC certificates are to be retired within 60 days after the last unit is initially source tested. AQ-64 Relief granted by the San Joaquin Valley Air Pollution Control District Hearing Board on November 13, 2002 in Regular Variance Docket No. S-02-38R shall apply to Conditions of Certification AQ-5, AQ-13 through AQ-17, AQ-26, and AQ-27. The Project Ownershall comply with all requirements incorporated into the 19 conditions of this regular variance. Mach 19, 2003 Page 3 Verification: The project owner shall submit copies ofall notifications and_ reports required underthis regular variance to the CPM. The project ownershall notify the CPM within 5 days of any requested changesto this variance. AQ-65 During commissioning, emissions shall be limited to 400 lbs/hour ofNO, and 4,000 lbs/hour of CO. Verification: The project owner shall provide, within 24 hours of occurrence, notification to the CPM of any noncompliance with the commissioning startup/shutdown emission limits. IT IS SO ORDERED. STATE OF CALIFORNIA ENERGY RESOURCES CONSERVATION AND DEVELOPMENT COMMISSION DATE March 19, 2003 WILLIAM J. KEESE, Chairman Request to Amendthe Elk Hills Power Project (99-AFC-1C) to Allow PM.) ERC Tendering and Commissioning Emissions Increase Staff Analysis February 28, 2003 Amendment Request On December 10, 2002, Elk Hills Power, LLC (EHPor project owner) submitted to the Energy Commission a proposed amendmentto the Elk Hills Power Project (EHPP) (EHP 2002). The amendmentproposesto allow EHPto “tender” rather than “surrender” PM10 (particulate matter less than 10 microns in mean aerodynamic diameter) emission reduction credits (ERCs) to the San Joaquin Valley Air Pollution Control District (SJVAPCDorthe District). Excess ERCs would be returned to EHP if EHPis able to justify a lower permitted PM10 emission rate from the combustion turbine and heat recovery steam generator stack based on theinitial performance tests. On December 17, 2002, the SJVAPCDissued a revised approval to EHP’s Authority to Construct (ATC)reflecting the possible revision of PM10 emission rates and offset requirements. The amendmentrequest also includes a commissioning emissions variance, which was granted by the District on November 13, 2002 (District 2002). Background In February 1999, the project owner proposed to construct and operate a 500 megawatt (MW) combined cycle project in western Kern County, approximately 25 miles westof Bakersfield, California. The EHPP wascertified in December 2000 (CEC 2000a). The original project design included two natural gas fired 7F type combustion turbine generators (CTG), two heat recovery steam generators with ductfiring, a steam turbine generator, a six-cell cooling tower, and a diesel fired emergency engine. There have been no previous project amendments that have requested the modification of operational air quality requirements. The EHPPis expected to be online in June 2003. ERC Tendering PM10 ERCs have becomescarce in the SJVAPCD andas a result, have also escalated in price. Recent operating data from turbines similar to those being installed at EHPP have shownthat PM10 emission rates may be lower then originally assumed during the licensing process. Thus, the amount of ERCs actually necessary to mitigate project air emission impacts may be less than the amounts that were originally required, which were based on equipment vendor guarantees. The project owner would like to have the flexibility to lower their permitted PM10 emissions limits based on the results ofinitial source testing to determine actual facility PM10 emissions. This, in turn, would reduce the quantity of ERCs that would need to be surrendered to mitigate project air impacts. Excess ERCs would be returned to EHP. 1 of 8 Prior to changing any permit levels or associated ERC requirements, EHP would be required to submit a separate amendmentrequest to the Energy Commission and the District with the results ofinitial source testing and associated data regarding actual PM10 emission rates. Commissioning Variance Neither the original District Determination of Compliance, northe original Staff Assessment (CEC 2000b) evaluated commissioning emissions or provided Conditions of Certification to address emission requirements during commissioning. Emissions of nitrogen oxides (NOx), carbon monoxide (CO) and volatile organic compounds (VOC) are known to be elevated during commissioning, particularly in the early phases of commissioningpriorto the installation and operation of the pollution control equipment. The project ownerobtained a variance from the District and is requesting a similar amendmentof the Energy Commission decision in order to maintain project compliance with emission requirements during the commissioning period. Laws, Ordinances, Regulations and Standards (LORS) The California State Health and Safety Code, section 41700, requires that “no person shall discharge from any source whatsoever such quantities of air contaminants or other material which causeinjury, detriment, nuisance, or annoyance to any considerate numberof persons orto the public, or which endanger the comfort, repose, health, or safety of any such personsorthe public, or which cause,or have a natural tendency to cause, injury or damage to businessorproperty.” The project would continue to remain in compliance with all applicable LORS with the requested changes. Analysis ERC Tendering The concept of tendering would allow EHP to turn over PM10 ERCsto the District prior to the commencementoffacility operation, just as if the ERCs were to be surrendered. However, the District will not withdraw the ERCs from use until EHPP completes their initial source testing and determines if they can operate EHPP at a lower PM10 limit. EHP has acquired sufficient ERCs to offset maximum permitted plant emissions for VOC, SOx, NOx, and PM10 on a quarterly basis. The District has required EHP to surrender ERCcertificates for all calendar quarters at appropriate offset ratios prior to commencementof operation of the equipment covered by the District ATC. Once surrendered, these ERCs would be underthe control of the District. EHP’s ATC permit contains hourly, daily, and rolling twelve-month emissionlimits for PM10. There wasvery little operating experience with the GE7FA gasturbines in 1999 2of 8 when emission estimates and guarantees were used asthe basis for the project's permits. However, recent experience at other facilities has shown that measured PM10 rates may be substantially lower. The difference between any new PM10 limits that may be requested and changesto current permit limits would be basedsolely on actual measurements at EHPPduring initial source testing. There would be no physical modifications to the facility to achieve lowerlimits, nor any changesin operating conditions or assumptions. The request would be limited to PM10 emissions. If the initial source tests indicate that EHPP can operate at lower PM10 limits, then EHP would be allowed to submit an amendmentrequestto the District and the Energy Commissionat that time. If that request is approved, EHP would identify any tendered ERCcertificates that are surplus to the original PM10 offset requirements, and would request their return atfull value. EHPis proposing two modifications to the project's Conditions of Certification. Thefirst is a change to Condition AQ-21, which would be modified to require the tendering, rather than the surrendering of ERC certificates to the District, prior to the commencementof operation. The second modification is the addition of new Condition AQ-63. This sets forth the procedure by which EHP would lower hourly, daily, and annual PM10 emission limits and thereby reduce the PM10 offset requirements set forth in Condition AQ-21. The changes and additions to Conditions of Certification are presented below. On December 17, 2002, the SJVAPCDissued a revised approval to EHP’s ATC reflecting the revision of PM10 emission rates and offset requirements as described above. Commissioning Variance Emissions The requested commissioning emission limits are provided in Table 1, which shows the current hourly permit emissionslimits and the requested commissioning emissions limits. No revised emission limits for PM10, SO2, or ammonia emissions have been requested. Table 1 Original and Proposed EHPP Commissioning Emission Limits Turbine/HRSG Operating Turbine/HRSG Proposed Commissioning Pollutant Emission Limits Startup/Shutdown Emissions Emission Limits (Ibs/hour)* Limits (lbs/hour)? (Lbs/hour) NOx 15.8 76 400/185° co 12.5 38 4,000/75° VOC 4.0 -— 200/20 * a. From Condition of Certification AQ-15. b. From Condition of Certification AQ-13. c. Requested Phase i/PhaseII emissionlimits. Source: CEC 2000a, EHP 2002. 30f 8 As can be seen in Table 1, the potential maximum hourly commissioning emissions far exceed current hourly permit limits, thus necessitating this amendmentrequest. The requested commissioning emission limits are reasonable in comparison to the commissioning emissionlimits that have been allowed recently for otherlicensed projects. Additionally, these emission limits would only be effective during theinitial commissioning period. Phase |, referred to as the “Steam Blow/Boilout’ phase, would occuratthe start of initial commissioning. Phase Il, referred to as the “Testing and Tuning” phase, would occurlater during the initial commissioning period and would account for mostof the time duringinitial commissioning. Theinitial commission is stated to last up to 500 hours within a 120-day period for each turbine. The maximum initial commissioning emissions estimated by the project ownerare provided in Table 2. Table 2 Estimated Maximum Emissions During Commissioning (tons) Phase NO, co voc | Steam Blow/Boilout 18.3 11.2 1.0 ll Testing and Tuning 49.0 24.2 3.7 Total Commissioning 67.3 35.5 4.8 Source: (EHP 2002) It is possible that the actual emissions during commissioning will be substantially less than these conservative estimates. Impact Analysis The project ownerprovided a revised modeling analysis of the potential worst-case short-term NO2 and CO emission impacts. This modeling analysis did not use the normally accepted NOx-OLM (ozonelimiting method) modeling approach to determine worst-case 1-hour NO2 impacts. Therefore, staff also conducted a NOx-OLM screening analysis. The project owner's CO modeling procedures and results were acceptable to Energy Commissionstaff. Table 3 provides the results of the project owner’s and staffs modeling analyses. Table 3 Commissioning Emissions Short-Term Impact Modeling Results Pollutant Maximum Background Total (ug/m’) Limiting AAQS Impact (ug/m’) (ug/m*) (ug/m?) NO2 1-hour (EHP) 320° 97 417 470 1-hour (staff) 356° 97 453 470 CO 1-hour 4,418 2,941 7,359 23,000 8-hour 1,746 2,222 3,968 10,000 a. Assumes 75% NO, conversion to NO2. b. _NO,-OLM screening value using an initial 0.25 NO2/NO, ratio and a maximum 0.13 ppm ozone background. Source: (Head 2003) and staff's modeling analysis. 4of 8 This analysis shows that no exceedancesof the short-term NO2 or CO standards are expected to occur as a result of the commissioning activities. Staff reviewed the assumed exhaust conditions in the project owner's modeling files and found them to be reasonably consistent with the values used in other current siting cases. The stack velocity was somewhathigher than that used for other projects and the stack temperature was somewhatlower, which whentheir effects are combined they generally negate each otherin terms of over- or underestimating project impacts. Staff performed NOx-OLMscreening runs using the project owner assumed exhaust conditions (results shown in Table 3), and using the same stack conditions assumed for another recentsiting case, and determinedthat the difference was minor and that both modeling runs showed total impacts (project impact plus background) to be lowerthan the State 1-hour ambient air quality standards. Mitigation For projects now beinglicensed, staff is requiring that the commissioning emissions be included in the emissionstotals for the determination of offset requirements. This meansthat if a source has a quarterly emission limit to which they are applying emission offsets, the commissioning emissions would be assumed to be counted under that emissions limitation. However, this project was licensed prior to current staff proceduresfor counting commissioning emissions. The current quarterly emissionslimitations for theEHPP are approximately 35.6 tons for NOx, 8 tons for VOC, and 27.9 tons for CO. Equivalent 120-day emission totals would be approximately 47.4 tons for NOx, 10.7 tons of VOC and 37.2 tons of CO. Table 2 showsthat the estimated commissioning VOC and CO emissionsare less than the calculated quarterly limits extended to 120 days. The commissioning NOx emissions could cause an exceedanceof quarterly emissions. The District’s variance deals with this possibility by requiring NOx emission reduction credits (ERCs) in the amountof 20 percentof the excess determined to occur during the variance period be purchased and retired. The District's variance appears to use daily emission limits (condition 16f of the variance) as the basis for determining excess emissions. This approach is more conservative than using the quarterly emission limit approach, and may require the EHP to retire more NOx ERCsthanis required for projects now being licensed. No short-term NO2 impacts were found to occur from initial commissioning activities and any additional ERCs required for the project would result in a long-term netair quality improvementfor the air basin. Therefore, staff accepts the District's Variance as providing acceptable NO2 mitigation for the commissioning emissions. District's Variance The District approved a commissioning emissions variance on November 13, 2002. Staff has found a numberof potential issues regarding this variance. First, the District staff report, which was used as a basis for the excess emission value limits quoted in 5of 8 the variance, does not seem to properly quote the hourly emission limits for the project. Second, the variance exempts startup and shutdownsduring theinitial commissioning period from any andall emission limit requirements. Third, the variance does not allow excess PM10 emissions but does allow excess visible emissions. These issues will be discussed in order: 1. The staff report for the variance quoted non-startup hourly permitted emissionlimits for the two turbine/HRSGsto be 51 Ibs/hr for NOx, 38 Ibs/hr for CO and 5.2 !bs/hour for VOC. The current permit shows that the hourly permitted emissionlimits to be 31.6 lbs/hour for NOx, 25 lbs/hour for CO, and 8 lbs/hour for VOC. 2. The variance exempts startup and shutdownperiodsduring initial commissioning from any emissionlimitations. The variance indicates that no violations of State ambient air quality standardsare likely to occur. However, that cannot be confirmed without reasonable startup and shutdown emissionlimits. 3. The variance specifically notes that it allows only excess NOx, CO, VOC andvisible emissions. However, any visible emissions, unless from a visible NOx plume, are an indication of excess PM10 emissions. No provisions for excess PM10 emissions,in terms of lbs/hour, have been granted. Staff has soughtclarification of these issues with the District. Michael Carrera of the District indicated that they used the project owner's normal operating hourly emission estimates provided in the variance request without modification. The project owner has stated that these values were probably provided in error, but that they do notaffect the variance conditions. Mr. Carrera also indicated that the District's intent was to not provide specific startup/shutdown emission limits during the commissioning period. However, in orderto ensure that no ambient air quality standards are exceeded, staff recommendsthe addition of AQ-65, whichlimits the hourly NOx and CO emissions to 400 and 4,000 lbs/hour respectively (the maximum hourly emissions, regardless of operating mode, during commissioning). Mr. Carrera indicated that the visible emissions variance was meant to cover excess particulate emissions, although not formally stated, and that the excessvisible emissions were supposed to only occurearly in Phase | of the initial commissioning. Staff does not normally request additional PM10 mitigation for commissioning emissions, so staff will not require any additional mitigation for PM10, however,staff would like the opportunity to review the Visible Emissions Evaluation data gathered during the commissioning period. 6 of 8 Conclusions And Recommendations ERC Tendering Staff has analyzed the proposed changes to the EHPP Conditions of Certification and concludesthat there will be no new emissions and nopossibility of any significant air quality impacts associated with approving the request. Staff concludes that the proposed changesare based on new information that was not available during the original licensing proceedings. The proposed changesto the Conditions of Certification retain the intent of the original Commission Decision and Conditions of Certification. Therefore, staff recommendsapprovalof the changes which are included below. Commissioning Variance EHPPrequires higher emission limits during the initial commissioning period. EHP has already received a Variance from the District that covers commissioning emissions. Staff acknowledges the necessity for this amendment and accepts, with some minor changes, the Condition of Certification proposed by the project ownerto address this issue. Staff also recommendsan additional Condition of Certification to limit NOx and CO emissions during startup/shutdown events that occur during commissioning. Proposed New and Revisions to Existing Conditions of Certification Strikethrough indicates deleted text and underline indicates replacement or newtext. ERC Tendering AQ-21 Prior to commencement of operation startup of S-3523-1-0, -2-0, & 3-0, emission offsets shall be tendered surrendered for all calendar quarters in the following amounts, at the offset ratio specified in Rule 2201 (6/15/95 version) Table 1, PM10 - Q1: 78,596 Ib, Q2: 79,470 Ib, Q3: 80,343 Ib, and Q4: 80,343 Ib; and surrenderedforall calendar quarters in the following amounts, at the offset ratio specified in Rule 2201 (6/15/95 version) Table 1, SOx (as SO2) - Q1: 14,170 Ib, Q2: 14,328 Ib , Q3: 14,485 Ib, and Q4: 14,485 Ib; NOx (as NO2) - Q1: 65,353 Ib, Q2: 66,079 Ib, Q3: 66,805 Ib, and Q4: 66,805 Ib; and VOC - Q1: 10,967 Ib, Q2: 11,089 Ib, Q3: 11,211 Ib, and Q4: 11,217 Ib. [District Rule 2201] Verification: The owner/operator shall submit copies of ERCs tendered or surrendered to the SJVUAPCDin the totals shown to the CPM prior to commencementof operation erupen-statup of the CTGs or cooling tower. AQ-63 The project owner may lower hourly, daily, and rolling average twelve-month PM10 emission limits in Conditions AQ-15, AQ-16, AQ-17, and AQ-18, and thereby reduce PM10 offset requirements set forth in AQ-21, based on actual PM10 emissions demonstrated during initial source tests. Revised emission limits shall be submitted to the District within 60 days after the last unit is initially source tested. The District will 7of 8 reflect revised limits in the permit to operate for the subject equipment. Any emission reduction credit certificates. or portions thereof, that were tendered to the District but are not needed to meet reduced PM10 offset requirements will be returned to the project owneratfull value. The project owner shall indicate which emission reduction credit certificates are to be retired. Verification: The project ownershall notify the CPM and District of any proposed changes in PM10 emission limits and indicate which ERC certificates are to be retired within 60 daysafter the last unit is initially source tested. Commissioning Variance AQ-64 Relief granted by the San Joaquin Valley Air Pollution Control District Hearing Board on November 13, 2002 in Regular Variance Docket No. S-02-38R shall apply to Conditions of Certification AQ-5, AQ-13 through AQ-17, AQ-26, and AQ-27. The Project Ownershall comply with all requirements incorporated into the 19 conditions of this regular variance. Verification: The Project Owner shall submit copies of all notifications and reports required underthis regular variance to the CPM. The Project Ownershall notify the CPM within 5 days of any requested changesto this variance. AQ-65_ During commissioning, emissions shall be limited to 400 lbs/hour of NO, and 4,000 Ibs/hour of CO. Verification: The Proiect Owner shall provide, within 24 hours of occurrence, notification to the CPM of any noncompliance with the commissioning startup/shutdown emissionlimits. REFERENCES California Energy Commission (CEC). 2000a. Commission Decision — Elk Hills Power Project (99-AFC-1). December 2000. California Energy Commission (CEC). 2000b. Final Staff Assessment - Elk Hills Power Plant Project (99-AFC-1). April 2000. San Joaquin Valley Air Pollution Control District (District). 2002. Order Granting a Regular Variance. Docket No. S-02-38R. Granted on November 13, 2002. Elk Hills Power, LLC (EHP). 2002. Petition for Post Certification Amendment and Changes ~ Air Quality. Elk Hills Power Plant (Docket No. 99-AFC-1C), December 2002. Head. 2003. Commissioning Emissions Revised Modeling Files and Results Spreadsheet. Elk Hillis Power Plant (Docket No. 99-AFC-1C), received by e-mail from Sara Head of ENSR on February 6, 2003. 8 of 8 Elk Hills Power Plant Project Page | of 2 theCaliforni ENERGYCOMMISSION Elk Hills Power Plant Project Docket Number: 99-AFC-01 (Application For Certification) 98-SIT-6 (NOI Exemption Proceeding) 99-AFC-1C (Compliance Proceeding) Committee Overseeing This Case: Michal C. Moore, Commissioner Robert Pernell, Commissioner Presiding Member Associate Member Hearing Officer: Major Williams Key Dates * July 23, 2003 - Elk Hills Power Project declared asfully on line. * December6, 2000 - Energy Commission certifies the application and grants the license for the Elk Hills Power Project. - November20, 2000 - Revised Presiding Member's Proposed Decision (PMPD)issued. * August 25, 2000 - Presiding Member's Proposed Decision released. + April 28, 2000 - Staff issues Final Staff Assessment, Part 3 of 3. * February 18, 2000 - Staff issues Final Staff Assessment, Part 2 of 3. * January 6, 2000 - Staff issues Final Staff Assessment, Part 1 of 3. * November19, 1999 - Staff issues Preliminary Staff Assessment. * June 9, 1999 - Second Data Adequacy Determination at a Commission Business Meeting. * March 31, 1999 - Energy Commission deems AFC Data Inadequate. * February 24, 1999 - Elk Hills Power, LLC files Application For Certification (AFC) for the Elk Hills Power Project (EHPP). * January 6, 1999 - California Energy Commission grants Elk Hills Power, LLC an exemption from the requirementtofile a Notice of Intention (NOI) for construction of a powerplant in California. * October 14, 1998 - Elk Hills Power, LLC files a Request for Jurisdictional Determination requesting a exemption from the requirementto file a Notice of Intention (NOI) for construction of a powerplant in California. General Description of Project The project as proposed by Elk Hills Power, LLC is a nominal 500 megawatt, natural gas-fired, combined cycle facility. The powerplant would consist of two combustion turbine generators (CTGs), two heat recovery steam generators (HRSGs) and exhaust stacks, and one steam turbine.It is a joint venture between Sempra Energy Resources and Occidental Energy Venturesof Elk Hills. The Elk Hills Power Project (EHPP)will be located on 12 acres roughly in the center of the 74 square mile Elk Hills Oil and GasField operated by Occidental Energy Ventures of Elk Hills, Inc. (OEHI). The site is in western Kern County, California, approximately 25 miles west of Bakersfield, California. The project site is situated nearthe intersection of Elk Hills Road and Skyline Road. A proposed new 9-mile bundled 230 kilovolt (kV) double circuit overhead transmission line will be built to interconnect either to the east at a new substation near Tupman, California, or north to the Midway substation near Buttonwillow, California. Natural gas will be supplied by a proposed new 2,500 foot, 10-inch supply pipeline owned and operated by OEHI. http://www.energy.ca.gov/sitingcases/elkhills/ 7/19/2012 Elk Hills Power Plant Project Page 2 of 2 Process water would be groundwaterprovided by the West Kern WaterDistrict (WKWD) and conveyedto the project site by a proposed new 9.8-mile, 16-inch supply pipeline. This pipeline would originate east of the powerplantsite at WKWD's waterstorage site located southwestof the intersection of the California Aqueduct and State Highway 119. Wastewater would be disposed of in proposed new disposalwells located 4 miles south of the powerplant site and would be conveyed by a proposed new pipeline. Energy Commission Facility Certification Process The Energy Commissionis the lead agency underthe California Environmental Quality Act (CEQA) and hasa certified regulatory program under CEQA.Underits certified program, the Energy Commission is exemptfrom having to prepare an environmental impactreport. Its certified program, however, does require environmental analysis of the project, including an analysis of alternatives and mitigation measures to minimize any significant adverseeffect the project may have on the environment. For Questions About This Siting Case Contact: Mary Dyas Compliance Project Manager Siting, Transmission and Environmental Protection (STEP) Division California Energy Commission 1516 Ninth Street, MS-2000 Sacramento, CA 95814 Phone: 916-651-8891 Fax: 916-654-3882 E-mail: mdyas@energy.state.ca.us For Questions AboutParticipation in Siting Cases Contact: Public Adviser California Energy Commission 1516 Ninth Street, MS-12 Sacramento, CA 95814 Phone: 916-654-4489 Toll-Free in California: 1-800-822-6228 E-mail: PublicAdviser@energy.ca.gov News Media Please Contact: Media & Public Communications Office Phone: 916-654-4989 E-mail: mediaoffice@energy.ca.gov http://www.energy.ca.gov/sitingcases/elkhills/ 7/19/2012