Ask the Scholar

Document scope · 1 page

doc

Scholar

Ask about this object, its catalog metadata, its source description, or the page inventory. For page-specific OCR and visual context, open one of the page chats.

Scholar Source Context

Document identity

localId

158698252

label

Clean Coal [1]

core

doc

dtoType

document

citationUrl

https://catalog.archives.gov/id/158698252

pageCount

Source metadata

158698252

sourceUrl

https://catalog.archives.gov/id/158698252

contentType

document

title

Clean Coal [1]

citationUrl

https://catalog.archives.gov/id/158698252

collections

Records of the White House Task Force on Climate Change

General Files

iiifBase

https://s3.amazonaws.com/NARAprodstorage/lz/presidential-libraries/clinton/foia/2017/2017-1094-F/42-t-146925349-20171094F-003-014-2019.pdf

thumbnailUrl

https://s3.amazonaws.com/NARAprodstorage/lz/presidential-libraries/clinton/foia/2017/2017-1094-F/42-t-146925349-20171094F-003-014-2019.pdf

largeImageUrl

https://s3.amazonaws.com/NARAprodstorage/lz/presidential-libraries/clinton/foia/2017/2017-1094-F/42-t-146925349-20171094F-003-014-2019.pdf

imageCount

hasImages

yes

source

import

hasTranscription

Source extras

url

https://catalog.archives.gov/id/158698252

naId

158698252

levelOfDescription

fileUnit

otherTitles

42-t-146925349-20171094F-003-014-2019

recordType

description

ocrSource

nara-archive

Single page context

seq

pageIndex

type

document

url

https://s3.amazonaws.com/NARAprodstorage/lz/presidential-libraries/clinton/foia/2017/2017-1094-F/42-t-146925349-20171094F-003-014-2019.pdf

mediaId

7914a49ed3580223

ocrText

FOIA Number: 2017-1094-F FOIA MARKER This is not a textual record. This is used as an administrative marker by the William J. Clinton Presidential Library Staff. Collection/Record Group: Clinton Presidential Records Subgroup/Office of Origin: WH Task Force on Climate Change Series/Staff Member: Roger Ballentine; Paul Bledsoe; Julie Anderson Subseries: OA/ID Number: 41302 FolderID: Folder Title: Clean Coal [1] Stack: Row: Section: Shelf: Position: S 100 3 10 3 COAL UTILIZATION ESEARCH COUNCIL Chairman February 12, 1999 James Markowsky. PhD Executive 1100 Prever nl Power Generation American Electric Power Treasurer Marshall Mazer Julie Anderson (i) Wilcons Director of Congressional Relations Executive Director White House Climate Change Task Force Pxin Yanggala 734 Jackson Place, NW Washington, D.C. 20503 Dear Julie: Thank you for taking the time to meet with CURC representatives on Wednesday. The members of CURC have invested a great deal of time and effort to define ways that government and industry might work together to insure the development of technologies that will dramatically improve the conversion or combustion of coal to useful energy. We appreciate your interest with our current and future plans to ensure that coal remains a viable energy resource in the marketplace and, we would welcome any further input or advice you might have regarding our initiatives to insure that coal remains a viable energy resource in the U.S. and abroad. Thank you again for taking the time to meet with us. We look forward to continuing dialogue with your offices about these matters. Sincerely, B Ben Yamagata Executive Director watter 1050 Thomas Jefferson St., NW John - Suite 700 Washington, DC 20007 314-342-7560 (202) 298-1850 (202) 338-2416 FAX [email protected] Clean Coal Technology Budget and Tax Incentives Meeting February 10, 1999 SC-4 The Capitol 2:00 - 3:30 p.m. I. Welcome & Introductions Franz Wuerfmannsdobler Office of Senator Byrd II. FY 2000 R&D budget & incentives package for coal Todd Stern - White House & Bob Kripowicz - DOE III. Energy challenges & fuel diversity Charles Goodman Southern Company IV. CURC's R&D Roadmap Ben Yamagata -- Industry reaction to DOE's initiatives CURC V. Incentives for early commercial application of CCT John Wootten -- CCT tax incentives Peabody Group -- Revenue requirements -- International options -- Carbon sequestration potential VI. Q & A / Discussion Franz Wuerfmannsdobler Office of Senator Byrd VII. Future activities All 15-Year Levelized Cost of Electricity for Coal Fired V. Gas Fired Power Technologies 45 2nd Gen Adv Coal 800 - 1,000 $/kWh 7,500 Btu/kWh 15-yr Levelized COE, mills/kWh (constant '97$) 40 3rd Gen Adv Coal 1st Gen Adv Coal 800 $/kW 35 900 - 1,300 $/kW 7,000 Btu/kWh 8,200 - 9,300 Btu/kWh 30 CC "F" 400-500 $/kW 7,000 Btu/kWh CC "H" 25 350-500 $/kW Adv GT Cycles 6,500 Btu/kWh 275 - 425 $/kW 6,500 Btu/kWh 20 1995 2000 2005 2010 2015 2020 2025 Year of Plant Start-Up © 1998 Coal Utilization Research Council February 25, 1998 30-Year Levelized Cost of Electricity for Coal Fired VS. Gas Fired Power Technologies 45 1st Gen Adv Coal 900 - 1,300 $/kW 30-yr Levelized COE, mills/kWh (constant '97$) 40 8,200 - 9,300 Btu/kWh 2nd Gen Adv Coal 800 - 1,000 $/kWh 7,500 Btu/kWh 35 Adv GT Cycles 275 - 425 $/kW 6,500 Btu/kWh 30 CC "F" 25 400-500 $/kW CC "H" 7,000 Btu/kWh 350-500 $/kW Adv Coal 6,500 Btu/kWh 800 $/kW 7,000 Btu/kWh 20 1995 2000 2005 2010 2015 2020 2025 Year of Plant Start-Up © 1998 Coal Utilization Research Council February 25, 1998 Performance Targets for Coal Generation Performance Target Today 2010 2020 900 - 1300 800 800 Capital Cost, $/kW 50 - 60 Efficiency, %HHV 40 45 SO2, removal % 95 97 99 0.1 - 0.3 Nox Ibs/mmbtu 0.08 0.05 HAPs (hazardous air pollutants) define goals meet goals meet goals Waste Utilization, % 100 50 . 75 15 - 30 Significant Deminimis Overall Emissions Reductions from Emissions Today's Technology © 1998 Coal Utilization Research Council Coal Fired Power Plant Technologies Today 2010 2020 HIPPS LEBS PCF Adv. APC Hybrid PFB APFB IGFC IGCC AGCC Coproduction Coproduction Coproduction Carbon Sequestration Carbon Sequestration Carbon Sequestration PCF - Pulverized Coal Fired Plant APFB - Advanced Pressurized Fluid Bed HIPPS - High Performance Power System PFB - Pressurized Fluid Bed AGCC - Advanced Gasification LEBS - Low Emission Boiler System IGCC - Integrated Gasification Combined APC - Advanced Pulverized Coal Fired Combined Cycle Cycle ICFC - Integrated Gasification Combined Plant Cycle © 1998 Coal Utilization Research Council Coal Fired Power Plants / Enabling Technologies Today 2010 2020 APCF PCF LEBS Coal Emissions Biomass HIPPS Prep Control USC UUSC PFB APFB HGCU ATS Hybrid IGCC AGCC IGFC Adv. Air Separ. Coproduction Coproduction Coproduction Carbon Sequestration Carbon Sequestration Carbon Sequestration Enabling technologies to build industry core competencies include materials and lifing; sensors and controls; computational fluid dynamics; coal characterization; and coal preparation. February 25, 1998 © 1998 Coal Utilization Research Council Efficiency Goals for Coal Fired Plants Year 2010 Goal Year 2020 Goal LEBS APCF HIPPS APFB AGCC Hybrid (70+) IGFC 40 45 50 55 60 Efficiency, %HHV © 1998 Coal Utilization Research Council February 25, 1998 AGCC Performance Targets Performance Target Today 2010 2020 1200-1300 Capital Cost, $/kW 800 800 57* Efficiency, %HHV 40 45 99 SO2 removal, % 97 99 (cold) (hot) (hot) NOx lbs/mmbtu 0.06 0.06 0.05 HAPs define goals meet goals meet goals 75 100 Waste Utilization, % 30 Equivalent Availability, % 90 90 90 *GCC/PFB Hybrid © 1998 Coal Utilization Research Council February 25, 1998 AGCC Technology Trajectories Technology Need Today 2010 2020 hot -- 1000 °F hot -1500°F Gas Cleanup cold 8,000-20,000 hrs 20,000 hours by 2005 "F" ATS -- 2750 °F Advanced Combustion 2350°F plus combustor Turbine development CT cycles Ultrasupercritical Steam Cycle Subcritical Subcritical Steam Air or O2 Air or O2 Oxidant O2 with advanced with advanced air separation air separation hot SO2 removal cold with external hot desulfurization Waste Utilization, % 15 - 30 50 - 75 100 February 25, 1998 © 1998 Coal Utilization Research Council APFBC Performance Targets Performance Target Today 2010 2020 900 Capital Cost, $/kW -1100 800 800 57* Efficiency, % HHV 45 40 99 SO2 removal, % 97 95 0.1 0.08 NOx, lbs/mmbtu 0.05 Equivalent Availability, % 90 90 90 * GCC/PFB Hybrid February 25, 1998 © 1998 Coal Utilization Research Council APFBC Technology Trajectories Technology Need Today 2010 2020 1600° F oxidizing 1700°F oxidizing HTHP Filters Cyclones conditions conditions ATS-- 2750 F "F"- 2350 °F Advanced Combustion Turbine advanced rugged combustor CT cycles 2400psi/1050°F 3500psi/1050°F 5000psi/1300°F Steam Cycle single reheat single reheat double reheat flue gas flue gas Sulfur removal dolomite polishing polishing HAPs define goals meet goals meet goals (trace) Waste Utilization, % 15 - 30 50 - 75 100 © 1998 Coal Utilization Research Council February 25, 1998 IGFC Performance Targets Performance Target Today 2010 2020 Capital Cost, $/kW n/a n/a 800+ Efficiency, %HHV n/a n/a 70+ SO2 removal, % n/a n/a 99+ NOx, lbs/mmbtu n/a n/a < 0.05 HAPs n/a n/a meet goals Waste Utilization, % n/a n/a 100 Equivalent Availability % n/a n/a 90 © 1998 Coal Utilization Research Council February 25, 1998 IGFC Technology Trajectories Technology Need Today 2010 2020 natural gas coal gas large coal gas Fuel Utilization fuel cells fuel cells fuel cells 250kw to 1MW 2 to 50MW 200-400MW Plant Scale-Up demos demos commercial plants as required to see GCC see GCC Hot Gas Clean-Up maintain fuel cell life as required to SO2 removal see GCC see GCC maintain fuel cell life CT/Fuel Cell Integration n/a integration of gasifier Integration hot-gas clean-up, and fuel cell © 1998 Coal Utilization Research Council February 25, 1998 HIPPS Performance Targets Performance Target Today 2010 2020 Capital Cost, $/kW n/a 800 800 Efficiency, %HHV n/a 47 55 SO2 removal, % n/a 99 99 NOx, lbs/mmbtu n/a 0.06 0.05 HAPs n/a meet goals meet goals Waste Utilization, % n/a some 100 Equivalent Availability, % n/a 90 90 © 1998 Coal Utilization Research Council February 25, 1998 HIPPS Technology Trajectories Technology Need Today 2010 2020 High Temperature / n/a 1100°F 1800°F High Pressure Filter reducing reducing n/a 1800°F Heat Exchanger 2750°F (Alloy) (ceramic) 4000psi/ 5000psi/ Steam Cycle n/a 1200°F 1300°F double reheat double reheat cycle design, cycle design, Steam Turbine n/a aerodynamics, aerodynamics, materials materials Humid air turbine Gas Turbine n/a Humid air turbine 2750° Particulate n/a to be defined to be defined © 1998 Coal Utilization Research Council February 25, 1998 Advanced PC Performance Targets Performance Target Today 2010 2020 1100 Capital Cost, $/kW 800 800 47-51 Efficiency, % HHV 45 41 SO2 removal, % 98 99 97 0.1 NOx, lbs/mmbtu 0.08 0.05 HAPs define goals mercury control meet goals Waste Utilization, % 15 - 30 50 - 75 100 Equivalent Availability, % 90 90 90 © 1998 Coal Utilization Research Council February 25, 1998 Advanced PC Technology Trajectories Technology Need Today 2010 2020 3500 psi/1050 °F 4000 psi/1200 °F 5000 psi/1300 °F Steam Double reheat Double reheat Double reheat Cycle Conditions Boiler and Steam ferritics, ferritics, austenitics, new Ni-based Cycle Materials austenitics Ni-based alloys alloys plant cycle new aerodynamics, Steam Turbine n/a integration, cycle integration, materials materials integrated with integrated with SO2 removal n/a HAPS & particulate HAPS & particulate control control NOx control burners, Adv. burners, Adv. burners, SCR SCR SCR 1998 Coal Utilization Research Council February 25, 1998 © Crosscutting Enabling Technology Technology 2010 2020 High Temperature/ High Pressure Filters AGCC 1000°F reducing 1500°F reducing APFB 1600°F reducing 1700°F reducing HIPPS 1100°F reducing 1500°F reducing IGFC n/a 1000°F reducing Combustion Turbine AGCC 2750°F - ATS Advanced Cycle APFB 2750°F - ATS Advanced Cycle HIPPS n/a 2750°F Steam Cycle Materials APFB n/a New Alloys, 1300°F APC Ferritics, new alloys New Alloys, 1300°F HIPPS n/a New Alloys, 1300°F HAPS Address issues as characterized by Address 2000 for all technologies © 1998 Coal Utilization Research Council February 25, 1998 Crosscutting Enabling Technology Technology 2010 2020 Hot Sulfur Cleanup AGCC External Hot Desulfurization External Hot Desulfurization APFB n/a Polishing IGFC n/a External Hot Desulfurization Polishing NOx Removal AGCC n/a n/a APFB n/a n/a IGFC n/a n/a HIPPS Advanced Cost Efficient NOx Advanced Cost Efficient NOx Removal Removal Air Seperation AGCC Advanced Air Seperation Advanced Air Seperation APFB Advanced Air Seperation Advanced Air Seperation IGFC Advanced Air Seperation Advanced Air Seperation HIPPS n/a n/a © 1998 Coal Utilization Research Council February 25, 1998 Assumptions Used to Determine COE in Comparison Charts Region SE SE SE SE SE SE SE SE Technology Adv PFBC Adv IGCC IGCC "F" IGCC "H" IGCHAT CC "F" CC "H" Adv CHAT Plant Size, MW 680 460 570 450 450 225 400 400 Capacity Factor, % 85 85 85 85 85 85 85 85 Fuel Coal Coal Coal Coal Coal Gas Gas Gas Fuel Cost in yr 2000, $MMBtu 1.29 1.29 1.29 1.29 1.29 2.24 2.24 2.24 Fuel Real Esc. Rate, %/yr -0.07 -0.07 -0.07 -0.07 -0.07 1 1 1 Total Plant Cost, $/kW 800 800 1310 1150 810 400 350 270 Fixed O&M, $/kW-yr 26.9 35.4 43.8 38.4 35.4 13.3 10.3 10.3 Var. O&M, mills/kWh 2 1.5 1.3 1.3 1.5 3.1 2.2 2.2 Heat Rate, Btu/kWh HHV 7240 7000 8200 7500 7000 7000 6500 6500 Note: Total Plant Costs are typical values. They vary depending on plant size and design, plant location, etc. Fuel Costs are based on EIA's 1997 AEO Projections (National Average) © 1998 coal Utilization Research Council February 25, 1998 Fuel Price Projections Based on AEO '97 3.5 Natural Gas (real escalation rate = 1.0%/yr) 3 Fuel Price, $/MMBtu (1997$) 2.5 2 1.5 1 Coal (real escalation rate = 0.7%/yr) 0.5 O 1995 2000 2005 2010 2015 2020 2025 2030 2035 2040 Year Natural Gas Coal © 1998 Coal Utilization Research Council February 25, 1998 Glossary of Acronyms ATS Advanced (gas) turbine system AGCC Advanced gasification combined cycle APCF Advanced pulverized Coal fired plant APFB Advanced pressurized fluid bed CC Combined cycle HAPs Hazardous air pollutants HIPPS High performance power system HGCU Hot gas cleanup HHV Higher heating value IGCC Integrated gasification combined cycle IGFC Integrated gasification fuel cell LEBS Low emission boiler system PCF Pulverized coal fired plant PFB Pressurized fluid bed USC Ultra supercritical UUSC Ultra, ultra supercritical © 1998 Coal Utilization Research Council February 25, 1998 OF THE TREASURY THE 1789 DEPARTMENT OF THE TREASURY OFFICE OF TAX ANALYSIS 1500 PENNSYLVANIA AVENUE, NW WASHINGTON, DC 20220 Number of pages to follow: 2 Date: September 18, 1998 To: Julie Anderson Fax: 395-2342 From: Len Burman Tel: (202) 622-0120 Comments: I've attached talking points on the clean coal technology proposal. The proposal raises serious concerns: 1. As currently crafted it can increase emissions in the US depending on the plants that are replaced; 2. For overseas investments, the incentives may be ineffective or overly generous, depending upon how they are structured; 3. The incentives are overly generous in relation to operating costs, the value of output or the potential environmental benefits. If we pursue a proposal fashioned after this one, it would be preferable to reduce the incentives provided and restrict them to domestic CCT investments that replace conventional coal plants. NOTE: THIS MESSAGE IS INTENDED ONLY FOR THE USE OF THE INDIVIDUAL OR ENTITY TO WHOM IT IS ADDRESSED AND MAY CONT INFORMATION THAT IS PRIVILEGED, CONFIDENTIAL AND/OR RICTED AS TO OR EXEMPT FROM DISCLOSURE UNDER APPLICABLE LAWS. IF the recipient of this massage is not the addresses (i.e., the intended recipient, you are hereby notified that you should not read this document and that any dissemination, distribution, or copying of this communication except Insofar as necessary to deliver this document to the intended recipient, is strictly prohibited. If you have received this communication in error, please notify the sender immediately by telephone, and you will be provided further instruction about the return or destruction of the this document. Thank you. UNCLASSIFIED Tax Incentives for Clean Coal Technologies (Document dated May 1998) The proposal would provide the following incentives for investments in qualifying clean coal technology (CCT) installed in the US or abroad: A 20% investment tax credit for CCT which begins operation between 2000 and 2012; A production tax credit for output from the qualifying CCT based on the design heat rate for the first ten years of operation; A risk pool established by the Federal government that would be available to the owners of qualifying CCT during its first 3 years of operation to offset costs for modifications resulting from the technology's failure to achieve its design performance, up to 5% of the cost of the project. The proposal raises serious concerns: As currently crafted, it may increase carbon emissions. If the plants are built domestically, the environmental benefits will depend upon which other plants are being replaced. The document acknowledges that new capacity installed in the near term in the US will most likely be gas fired. To the extent that qualifying coal plants displace gas or renewable energy plants that have lower carbon emissions per kilowatt-hour of electricity generated, carbon emissions would increase rather than decrease. The document does not provide specific suggestions on how the incentives would work for overseas investments in CCT plants. Depending upon how the incentives are structured they may be ineffective or overly generous. - The proposed tax incentives may not be effective for investments overseas that are usually undertaken through controlled foreign subsidiaries of US parent corporations because foreign subsidiaries of US parent corporations generally do not pay US tax and would not be eligible for the proposed tax incentives. Allowing the US parent company to claim the tax incentives against its US tax on foreign income may be ineffective because many US parent corporations do not pay US tax on the foreign income of their subsidiaries. (Domestic tax is deferred until the income is remitted to the US parent company, and can be offset by foreign taxes paid.) Allowing the tax credits to be claimed against the parent's domestic tax liability would be too generous and a major change in US tax policy, because the tax subsidy would be provided for income that may be exempt from US tax. The proposed tax credits are very large in relation either to expected operating costs or the value of output from the facilities receiving the subsidy. The production tax credit alone (0.55 to 1.3 cents per kilowatt-hour for plants placed in service before 2009) largely offsets or exceeds the expected plant operating costs of under 0.7 cents per kilowatt-hour. The production credit is about 20 to 40 percent of the projected price of power in most US areas (about 3 cents per kilowatt-hour at the generating plant). The 20 percent investment tax credit and risk pooling add a further level of subsidy that is difficult to justify. The proposed subsidies are disproportionate to the potential environmental benefits of CCT technology. When both operating and capital subsidies are considered, the proposed subsidies are comparable to those being provided to renewable technologies that have no greenhouse gas emissions. Since the proposed CCT plants would have emissions significantly higher than those of a combined-cycle gas-fired plant that are available today, the proposed subsidies are difficult to justify. September 18, 1998 02/09/99 17:29 FAX 003 FEB-09-99 12:01 From: T-533 P.03/03 Job-028 DISCUSSION: This proposal is intended to provide a technology- and fuel-neutral incentive to modernize the nation's fleet of electricity generators. Due to the legacy of monopoly regulation, electricity generating units are among the oldest capital stock of any industrial sector in the United States, with about half of the generating capacity being more than 30 years old. This older capacity tends to be less efficient and much more heavily polluting than modern generating units. The performance-based investment tax credit proposed here would reduce the up front capital costs needed to replace this aging equipment with modern technology. The minimum performance improvements specified above can be achieved with either coal or gas technology. Consider replacing an older. less efficient unit with a heat rate of 11,000 Btu/kWh. The 25% and 50% improvement requirements would mean that the replacement units would have to achieve a heat rate of 8,250 Btu/kWh for the 10% credit, and 5,500 Btu/kWh for the 20% credit. DOE's performance goals for both advanced pressurized fluidized bed (PFBC) and integrated gasification combined cycle (IGCC) technology is a generation efficiency of at least 50%, or a heat rate of less than 6,825 Btu/kWh, substantially better than needed to qualify for the 10% credit. DOE's performance goal for its Vision 21 plant (which is an advanced IGCC plant using an oxygen-blown gasifier) is 65% efficiency. or a heat rate of 5.250. low enough to qualify for the 20% credit. Use of combined heat and power technology would make either of these performance goals substantially easier to meet. The requirement that the units being replaced had to operate with a 50% capacity factor during the previous 5 year period is intended to ensure that the tax credit gets the greatest possible bang-for-the-buck by excluding simple-cycle combustion turbine peaking units (which are likely to be replaced by combined cycle units in any case) and units that have effectively been removed from service without being formally retired. The treatment of combined heat and power (CHP or cogeneration) plants is intended to provide a level playing field for this high efficiency technology. If it were not for the use of this technology, fuel would have to be consumed in separate boilers to produce steam for use in, for example, an industrial process or district heating system. The CHP plant receives credit for this avoided fuel consumption, based on the assumption that the separate boiler would have an efficiency of approximately 80% (hence the factor of 1.2). 02/09/99 17:28 FAX 002 FEB-09-99 12:01 From: T-533 P.02/03 Job-028 TITLE V. FOSSIL FUEL EFFICIENCY IMPROVEMENTS 10% investment tax credit for repowering or replacing existing fossil fuel generating units with technology that results in at least a 25% reduction in fossil fuel heat input per kilowatt-hour of net electricity generation. 20% investment tax credit for repowering or replacing existing fossil fuel generating units with technology that results in at least a 50% reduction in fossil fuel heat input per kilowatt-hour of net electricity generation. Eligible units. To qualify for the credit, the unit(s) being repowered or replaced must have operated with an average capacity factor of at least 50% during the five year period prior to enactment. The investment tax credit can only be taken on that portion of the investment attributable to providing generating capacity not greater than the generating capacity of the unit(s) being repowered or replaced. Repowering means permanent modification of the generating unit so as to reduce the design average net heat rate by at least 25%. Replacement means permanent retirement of the existing generating unit and replacement of that amount of generating capacity with a new unit that has a design average net heat rate at least 25% lower than the retired unit. Treatment of combined heat and power plants (CHP or cogeneration). In the case of plants that produce both steam and electricity for sale, the net heat rate of electricity generation shall be calculated by subtracting 1.2 times the Btu content of the steam sold from the total Btus of heatiinput to the combined heat and power plant. OF THE THE TREASINY 1789 DEPARTMENT OF THE TREASURY OFFICE OF TAX ANALYSIS 1500 PENNSYLVANIA AVENUE, NW WASHINGTON, DC 20220 Number of pages to follow: 2 Date: September 18, 1998 To: Julie Anderson Fax: 395-2342 From: Len Burman Tel: (202) 622-0120 Comments: I've attached talking points on the clean coal technology proposal. The proposal raises serious concerns: 1. As currently crafted it can increase emissions in the US depending on the plants that are replaced; 2. For overseas investments, the incentives may be ineffective or overly generous, depending upon how they are structured; 3. The incentives are overly generous in relation to operating costs, the value of output or the potential environmental benefits. If we pursue a proposal fashioned after this one, it would be preferable to reduce the incentives provided and restrict them to domestic CCT investments that replace conventional coal plants. NOTE: THIS MESSAGE IS INTENDED ONLY FOR THE USE OF THE INDIVIDUAL OR ENTITY TO WHOM IT IS ADDRESSED AND MAY CONTAIN INFORMATION THAT IS PRIVILEGED CONFIDENTIAL AND/OR RICTED AS TO OREXEMPT FROM DISCLOSURE UNDER APPLICABLE LAWS. If the recipient of the message is not the addresses (i.e., the intended recipient, you are hereby notified that you should not read this document and that any dissemination, distribution, or copying of this communication except insofar as necessary to deliver this document to the intended recipient, is strictly prohibited. If you have received this communication in error, please notify the sender immediately by telephone, and you will be provided further instruction about the return or destruction of the this document. Thank you. UNCLASSIFIED Tax Incentives for Clean Coal Technologies (Document dated May 1998) The proposal would provide the following incentives for investments in qualifying clean coal technology (CCT) installed in the US or abroad: A 20% investment tax credit for CCT which begins operation between 2000 and 2012; A production tax credit for output from the qualifying CCT based on the design heat rate for the first ten years of operation; A risk pool established by the Federal government that would be available to the owners of qualifying CCT during its first 3 years of operation to offset costs for modifications resulting from the technology's failure to achieve its design performance, up to 5% of the cost of the project. The proposal raises serious concerns: As currently crafted, it may increase carbon emissions. If the plants are built domestically, the environmental benefits will depend upon which other plants are being replaced. The document acknowledges that new capacity installed in the near term in the US will most likely be gas fired. To the extent that qualifying coal plants displace gas or renewable energy plants that have lower carbon emissions per kilowatt-hour of electricity generated, carbon emissions would increase rather than decrease. The document does not provide specific suggestions on how the incentives would work for overseas investments in CCT plants. Depending upon how the incentives are structured they may be ineffective or overly generous. The proposed tax incentives may not be effective for investments overseas that are usually undertaken through controlled foreign subsidiaries of US parent corporations because foreign subsidiaries of US parent corporations generally do not pay US tax and would not be eligible for the proposed tax incentives. Allowing the US parent company to claim the tax incentives against its US tax on foreign income may be ineffective because many US parent corporations do not pay US tax on the foreign income of their subsidiaries. (Domestic tax is deferred until the income is remitted to the US parent company, and can be offset by foreign taxes paid.) Allowing the tax credits to be claimed against the parent's domestic tax liability would be too generous and a major change in US tax policy, because the tax subsidy would be provided for income that may be exempt from US tax. The proposed tax credits are very large in relation either to expected operating costs or the value of output from the facilities receiving the subsidy. - The production tax credit alone (0.55 to 1.3 cents per kilowatt-hour for plants placed in service before 2009) largely offsets or exceeds the expected plant operating costs of under 0.7 cents per kilowatt-hour. The production credit is about 20 to 40 percent of the projected price of power in most US areas (about 3 cents per kilowatt-hour at the generating plant). - The 20 percent investment tax credit and risk pooling add a further level of subsidy that is difficult to justify. The proposed subsidies are disproportionate to the potential environmental benefits of CCT technology. - When both operating and capital subsidies are considered, the proposed subsidies are comparable to those being provided to renewable technologies that have no greenhouse gas emissions. Since the proposed CCT plants would have emissions significantly higher than those of a combined-cycle gas-fired plant that are available today, the proposed subsidies are difficult to justify. September 18, 1998 1AA PULICY 12:49 0202 6220605 OF THE TREASURY THE 1789 DEPARTMENT OF THE TREASURY OFFICE OF TAX ANALYSIS 1500 PENNSYLVANIA AVENUE, NW WASHINGTON, DC 20220 Number of pages to follow: 2 Date: September 18, 1998 To: Julie Anderson Fax: 395-2342 From: Len Burman Tel: (202) 622-0120 Comments: I've attached talking points on the clean coal technology proposal. The proposal raises serious concerns: 1. As currently crafted it can increase emissions in the US depending on the plants that are replaced; 2. For overseas investments, the incentives may be ineffective or overly generous, depending upon how they are structured; 3. The incentives are overly generous in relation to operating costs, the value of output or the potential environmental benefits. If we pursue a proposal fashioned after this one, it would be preferable to reduce the incentives provided and restrict them to domestic CCT investments that replace conventional coal plants. NOTE: THIS MESSAGE IS INTENDED ONLY FOR THE USE OF THE INDIVIDUAL OR ENTITY TO WHOM IT IS ADDRESSED AND MAY CONT AIN INFORMATION THAT IS PRIVILEGED CONFIDENT TAL AND/OR IRICTED AS TO OR EXEMPT FROM DISCLOSURE UNDER APPLICABLE LAWS. If the recipient of this message is not the addresses (i.e., the intended recipient, you are hereby notified that you should not read this document and that any dissemination, distribution, or copying of this communication except Insofar as necessary to deliver this document to the intended recipient, is strictly prohibited. If you have received this communication in error, please notify the sender immediately by telephone, and you will be provided further instruction about the return or destruction of the this document. Thank you. UNCLASSIFIED PHOTOCOPY PRESERVATION TAX POLICY 09/18/98 12:49 202 6220605 Tax Incentives for Clean Coal Technologies (Document dated May 1998) The proposal would provide the following incentives for investments in qualifying clean coal technology (CCT) installed in the US or abroad: A 20% investment tax credit for CCT which begins operation between 2000 and 2012; A production tax credit for output from the qualifying CCT based on the design heat rate for the first ten years of operation; A risk pool established by the Federal government that would be available to the owners of qualifying CCT during its first 3 years of operation to offset costs for modifications resulting from the technology's failure to achieve its design performance, up to 5% of the cost of the project. The proposal raises serious concerns: As currently crafted, it may increase carbon emissions. If the plants are built domestically, the environmental benefits will depend upon which other plants are being replaced. The document acknowledges that new capacity installed in the near term in the US will most likely be gas fired. To the extent that qualifying coal plants displace gas or renewable energy plants that have lower carbon emissions per kilowatt-hour of electricity generated, carbon emissions would increase rather than decrease. The document does not provide specific suggestions on how the incentives would work for overseas investments in CCT plants. Depending upon how the incentives are structured they may be ineffective or overly generous. The proposed tax incentives may not be effective for investments overseas that are usually undertaken through controlled foreign subsidiaries of US parent corporations because foreign subsidiaries of US parent corporations generally do not pay US tax and would not be eligible for the proposed tax incentives. Allowing the US parent company to claim the tax incentives against its US tax on foreign income may be ineffective because many US parent corporations do not pay US tax on the foreign income of their subsidiaries. (Domestic tax is deferred until the income is remitted to the US parent company, and can be offset by foreign taxes paid.) Allowing the tax credits to be claimed against the parent's domestic tax liability would be too generous and a major change in US tax policy, because the tax subsidy would be provided for income that may be exempt from US tax. The proposed tax credits are very large in relation either to expected operating costs or the value of output from the facilities receiving the subsidy. TAX POLICY 09/18/98 12:50 202 6220605 The production tax credit alone (0.55 to 1.3 cents per kilowatt-hour for plants placed in service before 2009) largely offsets or exceeds the expected plant operating costs of under 0.7 cents per kilowatt-hour. The production credit is about 20 to 40 percent of the projected price of power in most US areas (about 3 cents per kilowatt-hour at the generating plant). The 20 percent investment tax credit and risk pooling add a further level of subsidy that is difficult to justify. The proposed subsidies are disproportionate to the potential environmental benefits of CCT technology. - When both operating and capital subsidies are considered, the proposed subsidies are comparable to those being provided to renewable technologies that have no greenhouse gas emissions. Since the proposed CCT plants would have emissions significantly higher than those of a combined-cycle gas-fired plant that are available today, the proposed subsidies are difficult to justify. September 18, 1998 From: Dirk Forrister on 01/21/99 09:25:00 AM Record Type: Record To: Julie M. Anderson/WHCCTF/EOF CC: Subject: Forwarded by Dirk Forrister/WHCCTF/EOP on 01/21/99 09:26 AM From: Dirk Forrister on 01/20/99 05:32:21 PM Record Type: Record To: Todd Stern/WHO/EOP, Roger S. Ballentine/WHO/EOP, David B Sandalow/CEQ/EOP CC: Subject: COALMTG.MEM Please find a short background paper for the meeting with Senator Byrd's staff tomorrow. This updated version incorporates the topics we covered in the 1:00 prep session. Here's a short-short version of our key messages to use as you prepare your own cheat-sheet. Economic Analysis: While we recognize that the nation's climate response will have some effects on coal, our analysis shows that an economically efficient policy framework will minimize those impacts. Coal will continue to play an important role in America's energy mix for many years to come. Technology Initiatives: Our portfolio of climate programs includes continued work on advanced coal R&D, sequestration and efficiency in mining. Our tax incentives will be changing modestly -- but still hold some potential for coal-based strategies to play a role through combined heat and power as well as improved biomass cofiring provisions. Credit for Early Action: The President expressed interest in the State of the Union. We're committed to work with you to get a bill done. Surface Mining: We see a valuable role emerging for our mined land reclamation programs -- they are focusing more on ways of including reforestation strategies to play a larger role. While not by any means the total solution, his program has the advantage of putting dollars and jobs into coal mining communities. New Issues: We Know We Can Do Even Better: We know your interest in the tax incentive proposal by the Coal Utilization Research Council -- and we are continuing to examine it. We are also working with the steel and coke industries on their interest in tax incentives for advanced coking technologies. We have concerns with both proposals -- and we have funding constraints that kept us from adding new initiatives on the tax side. That said, we will continue to work with them should the funding prospects change later in the year. International: We know y our interest in China, and we are developing some alternatives to prompt more clean coal technology partnerships there. We are also hearing soundings from Sen. Hagel that he may be planning a legislative effort this year -- and we hope that we can work closely with you if anything materializes on that front. Clean Coal Technology Incentives and R&D Program for Early Commercial Applications of Clean Coal Technology Winter 1999 COAL UTILIZATION RESEARCH COUNCIL Clean Coal Technologies Technology Promise Climate Change Initiative Proposed by the Administration - Immediate actions to stimulate the use of technologies that minimize costs to reduce greenhouse gas emissions - R&D and tax incentives aimed at deployment of energy efficient, carbon-reduction technologies - Electricity generating sector research program for innovative coal combustion approaches that offer the possibility of much lower carbon emissions Clean Coal Technologies (CCTs) can be further developed and deployed to cause or induce real increases in efficiency and decreases in carbon emissions from domestic and international electricity generation COAL UTILIZATION RESEARCH COUNCIL 2 Performance Targets for Coal Generation Performance Target Today 2010 2020 900 Capital Cost, $/kW -1300 800 800 50 - 60 Efficiency, %HHV 45 40 99 SO2, removal % 97 95 Nox lbs/mmbtu 0.1 - 0.3 0.08 0.05 HAPs (hazardous air pollutants) define goals meet goals meet goals Waste Utilization, % 15 - 30 50 - 75 100 © 1998 Coal Utilization Research Council February 25, 1998 Coal Fired Power Plant Technologies Today 2010 2020 HIPPS LEBS PCF APC PFB APFB Adv. Hybrid IGCC AGCC IGFC Coproduction Coproduction Coproduction Carbon Sequestration Carbon Sequestration Carbon Sequestration © 1998 Coal Utilization Research Council February 25, 1998 Coal Fired Power Plants / Enabling Technologies Today 2010 2020 APCF PCF LEBS Coal Emissions Biomass Prep Control HIPPS USC UUSC PFB APFB HGCU ATS Hybrid IGCC AGCC IGFC Adv. Air Separ. Coproduction Coproduction Coproduction Carbon Sequestration Carbon Sequestration Carbon Sequestration Enabling technologies to build industry core competencies include materials and lifing; sensors and controls; computational fluid dynamics; coal characterization; and coal preparation. © 1998 Coal Utilization Research Council February 25, 1998 Efficiency Goals for Coal Fired Plants Year 2010 Goal Year 2020 Goal LEBS APCF HIPPS APFB AGCC Hybrid (70+) IGFC 40 45 50 55 60 Efficiency, %HHV © 1998 Coal Utilization Research Council February 25, 1998 15-Year Levelized Cost of Electricity for Coal Fired V. Gas Fired Power Technologies 45 2nd Gen Adv Coal 800 + 1,000 $/kWh 7,500 Btu/kWh 15-yr Levelized COE, mills/kWh (constant '97$) 40 3rd Gen Adv Coal 1st Gen Adv Coal 800 $/kW 35 900 - 1,300 $/kW 7,000 Btu/kWh 8,200 - 9,300 Btu/kWh 30 CC "F" 400-500 $/kW 7,000 Btu/kWh CC "H" 25 350-500 $/kW Adv GT Cycles 6,500 Btu/kWh 275 - 425 $/kW 6,500 Btu/kWh 20 1995 2000 2005 2010 2015 2020 2025 Year of Plant Start-Up February 25, 1998 © 1998 Coal Utilization Research Council Clean Coal Technologies Environmental Impacts Environmental benefits: - 10 million metric ton reduction in domestic carbon emissions from the incentives - 294 million metric ton reduction in international carbon emissions from deployment of CCTs worldwide - 25% of the reduction required under a Kyoto type agreement COAL UTILIZATION RESEARCH COUNCIL 17 Clean Coal Technologies Incentive and R&D Program Objectives Fuel Diversity - coal largest source of electricity generation U.S. - 57% World - 38% - coal is projected to remain the largest source of electricity EIA AEO98 - 51% in 2020 even with a 400% increase in natural gas OECD/IEA - 43% of the world's electricity in 2020 Technology Promise - further R&D and deployment of early commercial applications will result in increased generating efficiency and lower carbon emissions Sustainable Economy - coal must remain a viable, readily available, competitive source of fuel for electricity generation, transportation fuels and chemical feed stocks to promote economic growth, price stability and energy security COAL UTILIZATION RESEARCH COUNCIL 8 Clean Coal Technologies Carbon Emission Reduction Potential 35 33 30 27 27 26 40 Year Carbon Emissions, Million Tonnes 25 21 21 20 17 Current 15 13 2010 2020 10 5 0 Conv Adv PC IGCC PFBC IGCF NGCC PC COAL UTILIZATION RESEARCH COUNCIL 9 Clean Coal Technologies Background CCT program will be successfully completed with demonstrated "first-of-a-kind" technologies to increase efficiency and reduce pollutants full commercial penetration requires 2-3 early commercial applications of these promising technologies developers unable to accept technical and financial risk of a "not yet fully commercial" application - lack of need for new base load capacity - utility deregulation - become more risk adverse - competition from natural gas Developing countries require large amounts of new capacity - much of it coal fired, but CCTs will not be utilized COAL UTILIZATION RESEARCH COUNCIL 10 Clean Coal Technologies Projected World Coal Consumption 100 90 80 Coal Consumption, Quadrillion Btu 70 60 1995 50 2010 40 2020 30 20 10 0 N. Am W Eur FSU/EE Ind Asia Asia Source: EIA International Energy Outlook, 1998, April 1998 COAL UTILIZATION RESEARCH COUNCIL 11 Clean Coal Technologies Key Issues Coal will continue to be used domestically and internationally Carbon emissions will continue to rise Conventional coal combustion is 37% efficient CCTs offer the promise of efficiencies exceeding 50% Full commercial deployment of CCTs can cause or induce real reductions in carbon emissions Full commercial deployment of CCTs will require incentives for a limited number of early commercial applications Achievement of the CCTs full efficiency gain and emission reduction potential will require a continued R&D effort to support the early commercial applications COAL UTILIZATION RESEARCH COUNCIL 12 Clean Coal Technologies Benefits of Incentives for Early Commercial Applications Accelerate commercial availability of CCTs as an option for achieving economic and environmental goals Cause or induce real carbon emission reductions domestically and internationally Keep US CCTs in forefront and globally competitive Create jobs and favorable economic contributions to the U.S. economy COAL UTILIZATION RESEARCH COUNCIL 13 Clean Coal Technologies Criteria for Incentives Tax incentives preferred over direct subsidies Address technical and economic risks of early commercial applications of CCTs Program should focus on coal fired CCTs, but be robust enough to address co-firing with renewables Apply only to those technologies that measurably increase thermal efficiency and reduce carbon emissions Target both domestic and international early commercial applications Address the higher capital and operating costs and the increased potential, inherent with new technology, for modifications to achieve design specifications COAL UTILIZATION RESEARCH COUNCIL 14 Clean Coal Technologies Proposed Incentives Investment tax credit - 20% of the project owner or parent company equity investment Production tax credit - variable incentive based on the production rate and efficiency of the technology over the first 10 years of operation Operation Design Incentive for Incentive for beginning Average Heat First 5 years of Second 5 during or Rate Btu/kWh Operation, years of before (HHV) cents/kWh Operation, Generated cents/kWh Generated 8400 or less 1.30 1.10 2004 8401-8550 1.00 0.85 8551-8750 0.90 0.70 7770 or less 1.00 0.80 2008 7771-8125 0.80 0.65 8126-8350 0.70 0.55 7720 or less 0.85 0.70 2012 7721-7380 0.70 0.45 COAL UTILIZATION RESEARCH COUNCIL 15 Clean Coal Technologies Proposed Incentives (Continued) Risk pool - 5% of the installed cost available from the Federal Gov't to cover repairs or modifications required to achieve design performance level during start-up and the initial 3 year operating period Qualification and selection criteria - limited capacity - 6000MW - limited period for installation - 2004 to 2012 - every increasing efficiency threshold to qualify (39% to 46%), higher in later years - selection based on maximum efficiency and lowest cost to government COAL UTILIZATION RESEARCH COUNCIL 16 Clean Coal Technologies Environmental Impacts Environmental benefits: - 10 million metric ton reduction in domestic carbon emissions from the incentives - 294 million metric ton reduction in international carbon emissions from deployment of CCTs worldwide - 25% of the reduction required under a Kyoto type agreement COAL UTILIZATION RESEARCH COUNCIL 17 Clean Coal Technologies Environmental Impacts World Carbon Emissions in 2010 & 2020 12000 10000 8000 5159 4894 Million Tonnes 5159 6000 4000 2000 0 BAU KYOTO CCT BAU KYOTO CCT Dev 2010 UnDev 2010 Dev 2020 UnDev 2020 COAL UTILIZATION RESEARCH COUNCIL 18 Clean Coal Technologies Revenue Impacts Revenue impacts over 23 year period (1999 -2021) Incentive 1999-2003 2004-2008 2009-2013 1999-2021 (Million 1998 $ NPV) Investment Tax Credit $90 $73 $41 $203 Production Tax Credit $0 $377 $439 $1,023 Risk Pool $0 $135 $117 $276 Total $90 $585 $597 $1,502 COAL UTILIZATION RESEARCH COUNCIL 19 Clean Coal Technology Incentives and R&D Program for Early Commercial Applications of Clean Coal Technology Winter 1999 COAL UTILIZATION RESEARCH COUNCIL Clean Coal Technologies Technology Promise Climate Change Technology Initiative proposed in Administration's FY 2000 budget - designed to promote energy efficiency, develop low carbon energy sources and reduce greenhouse gas emissions - $1.4 billion R&D spending on energy efficiency and renewable energy technologies - $0.4 billion for tax credits to stimulate adoption of energy efficient technologies in building, industrial processes, vehicles, and power generation FY 2000 budget proposes $321 million in bilateral and multilateral environmental assistance to address climate change issues in developing countries Clean Coal Technologies (CCTs) can be further developed and deployed to cause or induce real increases in efficiency and decreases in carbon emissions from domestic and international electricity generation 2 Clean Coal Technologies Incentive and R&D Program Objectives Fuel Diversity - coal largest source of electricity generation U.S. - 57% World - 38% - coal is projected to remain the largest source of electricity EIA AEO98 - 51% in 2020 even with a 400% increase in natural gas OECD/IEA - 43% of the world's electricity in 2020 Technology Promise - further R&D and deployment of early commercial applications will result in increased generating efficiency and lower carbon emissions Sustainable Economy - coal must remain a viable, readily available, competitive source of fuel for electricity generation, transportation fuels and chemical feed stocks to promote economic growth, price stability and energy security 3 Clean Coal Technologies Carbon Emission Reduction Potential 35 33 30 27 27 26 40 Year Carbon Emissions, Million Tonnes 25 21 21 20 17 Current 15 13 2010 2020 10 5 0 Conv Adv PC IGCC PFBC IGCF NGCC PC 4 Clean Coal Technologies Background CCT program will be successfully completed with demonstrated "first-of-a-kind" technologies to increase efficiency and reduce pollutants full commercial penetration requires 2-3 early commercial applications of these promising technologies developers unable to accept technical and financial risk of a "not yet fully commercial" application - lack of need for new base load capacity - utility deregulation - become more risk adverse - competition from natural gas Developing countries require large amounts of new capacity - much of it coal fired, but CCTs will not be utilized 5 Clean Coal Technologies Projected World Coal Consumption 100 90 80 Coal Consumption, Quadrillion Btu 70 60 1995 50 2010 40 2020 30 20 10 0 N. Am W Eur FSU/EE Japan & Asia Australia Source: EIA International Energy Outlook, 1998, April 1998 6 Clean Coal Technologies Key Issues Coal will continue to be used domestically and internationally Carbon emissions will continue to rise Conventional coal combustion is 37% efficient CCTs offer the promise of efficiencies exceeding 50% Full commercial deployment of CCTs can cause or induce real reductions in carbon emissions Full commercial deployment of CCTs will require incentives for a limited number of early commercial applications Achievement of the CCTs full efficiency gain and emission reduction potential will require a continued R&D effort to support the early commercial applications 7 Clean Coal Technologies Criteria for Incentives Tax incentives preferred over direct subsidies Address technical and economic risks of early commercial applications of CCTs Program should focus on coal fired CCTs, but be robust enough to address co-firing with renewables Apply only to those technologies that measurably increase thermal efficiency and reduce carbon emissions Place priority on early commercial applications in the US, but allow for international applications, if domestic opportunities fail to materialize Address the higher capital and operating costs and the increased potential, inherent with new technology, for modifications to achieve design specifications 8 Clean Coal Technologies Proposed Incentives Investment tax credit - 10% of the project owner or parent company investment Production tax credit - variable incentive based on the production rate and efficiency of the technology over the first 10 years of operation Operation Design Incentive for Incentive for beginning Average Heat First 5 years of Second 5 during or Rate Btu/kWh Operation, years of before (HHV) cents/kWh Operation, Generated cents/kWh Generated 8400 or less 1.30 1.15 2004 8401-8550 1.00 0.80 8551-8750 0.75 0.60 7770 or less 1.35 1.10 2008 7771-8125 1.15 0.90 8126-8350 0.90 0.80 7380 or less 1.55 1.35 2012 7381-7720 1.35 1.15 9 Clean Coal Technologies Proposed Incentives (Continued) Risk pool - 5% of the installed cost available from the Federal Gov't to cover repairs or modifications required to achieve design performance level during start-up and the initial 3 year operating period Qualification and selection criteria - limited capacity - 6000MW 2000 MU undepred could be biomass - limited period for installation - 2004 to 2012 - every increasing efficiency threshold to qualify (39% to 46%), higher in later years - selection based on maximum efficiency and lowest cost to government 10 Clean Coal Technologies Environmental Impacts Example of worldwide commercial applications: - 10% of coal combustion by 2010 - 50% of new coal combustion between 2010 and 2015 - 75% of new coal combustion between 2015 and 2020 Potential environmental benefits: - 10 million metric ton reduction in domestic carbon emissions from the incentives program - 294 million metric ton reduction in worldwide carbon emissions per year by 2020 from deployment of CCTs worldwide - 25% of the developed country reduction required under a Kyoto type agreement 11 Clean Coal Technologies Environmental Impacts World Carbon Emissions in 2010 & 2020 12000 10,448 10,154 9,268 10000 8000 5159 4894 Million Tonnes 5159 3592 3514 6000 3592 4000 2000 0 BAU KYOTO CCT BAU KYOTO CCT Dev 2010 UnDev 2010 Dev 2020 UnDev 2020 12 Clean Coal Technologies Revenue Impacts Revenue impacts over 22 year period (2000 -2021) Incentive 2000- 2005- 2010- 2000- 2004 2009 2014 2021 (Million 1998 $ NPV) Investment Tax Credit $180 $145 $81 $406 Production Tax Credit $59 $383 $485 $1,214 Risk Pool $34 $136 $107 $276 Total $273 $664 $673 $1,896 13 Winter 1999 INCENTIVES FOR THE EARLY COMMERCIAL APPLICATIONS OF CLEAN COAL TECHNOLOGY The Challenge - Ensure that the U.S. energy supply is based on a diverse mix of fuels, incorporates the benefits promised by new technology, guarantees a sustainable economy, and meets all environmental goals. The Solution - Clean Coal Technology (CCT) is critical to the U.S. effort to meet this challenge. FUEL DIVERSITY CCT can avoid a dependence on a limited number of fuel sources for U.S. power production and will assure the reduction of carbon emissions without economic penalty. TECHNOLOGY PROMISE CCT can dramatically increase efficiency and significantly reduce emissions from coal combustion. SUSTAINABLE ECONOMY CCT can preserve and promote economic growth, energy price stability and national energy security by allowing coal to remain a readily available and competitive source of clean fuel for electric generation, transportation fuels and chemical feed stocks. Today, a number of emerging clean coal technologies (CCTs) stand ready to be further developed and deployed to bring about real increases in the conversion efficiency of coal to electricity and real decreases in carbon emissions from power generation domestically and internationally. However, full commercial penetration for these technologies first requires building and operating experience from several early commercial applications for each major technology category. It is in the best interests of the United States to drive development of these early commercial applications as soon as possible, both at home and overseas. This will: accelerate the availability of commercially mature CCTs to enable the United States to meet future economic and environmental goals; result in real reductions of greenhouse gases wherever these early commercial applications occur; keep U.S. industry in the forefront of the world market place for CCTs; and create jobs and favorable economic contributions to the U.S. economy. The Action Required - Development of these early commercial CCT applications will require a new program of limited financial incentives and continued R&D funding to overcome the associated technological and economic risks. The proposed program would be limited in scope (6000MW) and timing (installations placed in service between 2004 and 2012) and the technologies would be required to meet ever-increasing performance levels to qualify. U.S. tax code should be amended to provide for the following incentives: (1) an Investment Tax Credit equal to 20% of the project owner's equity investment, (2) a Production Tax Credit for each kilowatt hour generated over the first 10 years of operation and based on the technologies design net heat rate, and (3) a Risk Pool to offset costs, if any, for modifications resulting from the technology's failure to achieve its design performance during start-up and initial operation, limited to 5% of the total installed cost of the project. COAL UTILIZATION RESEARCH COUNCIL Revision 4 11/16/98 Incentives and Research & Development for Early Commercial Applications of Clean Coal Technology November 1998 COM UTILIZATION RESEARCH COUNCIL Revision 4 11/16/98 Incentives and Research & Development for Early Commercial Applications of Clean Coal Technology November 1998 COM ! R Clinton Presidential Records Digital Records Marker This is not a presidential record. This is used as an administrative marker by the William J. Clinton Presidential Library Staff. This marker identifies the place of a tabbed divider. Given our digitization capabilities, we are sometimes unable to adequately scan such dividers. The title from the original document is indicated below. PROPOSAL Divider Title: Rev 4 11/16/98 Page 2 INCENTIVES FOR EARLY COMMERCIAL APPLICATIONS OF CLEAN COAL TECHNOLOGIES (1) Investment Tax Credit The U.S. owner(s) or U.S. parent company(s) of the owner(s) of a Qualifying Clean Coal Technology, which is installed in the U.S. or abroad between 2000 and 2012, shall be entitled to a tax credit equal to 20% of the project owner's equity investment. (2) Production Tax Credit The U.S. owner(s) or U.S. parent company(s) of the owner(s) of a Qualifying Clean Coal Technology, which is installed in the U.S. or abroad and begins operation between 2000 and 2012, shall receive a production tax credit for each kilowatt hour generated over the first 10 years of operation and based on the technologies design net heat rate as indicated in the table below: Operation Design Average Incentive for Incentive for beginning Net Heat Rate, First 5 years of Second 5 Years of during or Btu/kWh (HHV)* Operation, Operation, before cents/kWh cents/kWh Generated Generated 8400 or less 1.30 1.10 2004 8401-8550 1.00 0.85 8551-8750 0.90 0.70 7770 or less 1.00 0.80 2008 7771-8125 0.80 0.65 8126-8350 0.70 0.55 7720 or less 0.85 0.70 2012 7721-7380 0.70 0.45 *Note: Increased efficiency is equivalent to a lower net heat rate. (3) Risk Pool The federal government shall establish a financial Risk Pool that would be available to the U.S. owner(s) of a Qualifying Clean Coal Technology, installed in the U.S. or abroad, during its first 3 years of operation to offset costs, if any, for modifications resulting from the technology's failure to achieve its design performance during start-up and initial operation. The total amount of recoverable costs shall be limited to 5% of the total installed cost of the project. COAL UTILIZATION RESEARCH COUNCIL Rev 4 11/16/98 Page 3 (4) Definitions: (a) Conventional Technology - (i) coal-fired combustion technology with a design average net heat rate of not less than 9,300 Btu/kWh (HHV) and a carbon equivalents emission rate of not more than 0.53 pounds of carbon per kilowatt hour; or (ii) natural gas- fired combustion technology with a design average net heat rate of not less than 7,500 Btu/kWh (HHV) and a carbon equivalents emission rate of not more than 0.24 lbs. of carbon per kilowatt hour. (b) Clean Coal Technology (CCT's) - advanced technology that utilizes coal to produce 50% or more of its thermal output as electricity including advanced pulverized coal or atmospheric fluidized bed combustion, pressurized fluidized bed combustion, integrated gasification combined cycle, and any other advanced combustion technology that exceeds the performance of the conventional technology specified above. (c) Qualifying Clean Coal Technology - (i) applications totaling 1,000 MW of advanced pulverized coal or atmospheric fluidized bed combustion technology installed as a new, retrofit, or repowering applications and operated between 2000 and 2010 that have a design average net heat rate of not more than 8,750 Btu/kWh; (ii) applications totaling 1,500 MW of pressurized fluidized bed combustion technology installed as a new, retrofit, or repowering applications and operated between 2000 and 2012 that have a design average net heat rate of not more than 8,400 Btu/kWh; (iii) applications totaling 1,500 MW of integrated gasification combined cycle technology installed as a new, retrofit, or repowering applications and operated between 2000 and 2012 that have a design average net heat rate of not more than 8,550 Btu/kWh; and (iv) applications totaling 2000 MW or equivalent of technology for the production of electricity installed as a new, retrofit, or repowering application and operated between 2000 and 2012 that have a carbon emission rate that is no more than 85% of conventional technology. Clean coal technology projects receiving or scheduled to receive funding under the Department of Energy's Clean Coal Technology Program, shall not be eligible to be a Qualifying Clean Coal Technology as defined above. (d) Design Average Net Heat Rate - shall be based on the design average annual heat input and the design average annual net electrical generating capacity of the Qualifying Clean Coal Technology at standard conditions. Co-generation of steam shall not be considered in determining a technology's Design Average Net Heat Rate. (e) Project Selection Criteria - shall be established by the Department of Energy as part of a competitive solicitation for selecting Qualifying Clean Coal Technologies and the primary selection criteria shall be minimum design average net heat rate, maximum design average thermal efficiency and lowest cost to the government. DOE may establish other supplemental selection criteria as appropriate. COAL UTILIZATION RESEARCH COUNCIL Clinton Presidential Records Digital Records Marker This is not a presidential record. This is used as an administrative marker by the William J. Clinton Presidential Library Staff. This marker identifies the place of a tabbed divider. Given our digitization capabilities, we are sometimes unable to adequately scan such dividers. The title from the original document is indicated below. INCENTIVES AND R & D Divider Title: Rev 4 11/16/98 Page 4 Incentives and R&D Program for the Early Commercial Applications of Clean Coal Technology In October of 1997, President Clinton proposed a three-stage approach for the U.S. to address climate change. The first stage consists of immediate actions to stimulate development and use of technologies that can minimize the cost of meeting U.S. goals for reducing greenhouse gas emissions. Among the actions were proposals for funding R&D as well as tax incentives aimed at deployment of energy efficient, renewable energy and carbon-reduction technologies. For the electricity-generating sector, the proposals called for DOE to initiate a research program on innovative new approaches to coal combustion that offer the possibility of much lower carbon emissions than existing technologies. While an increased emphasis on researching new technologies is needed, there are a number of emerging clean coal technologies (CCT's) that could be further developed and deployed to cause or induce real increases in the conversion efficiency of coal to electricity, which would in turn cause or induce real decreases in carbon emissions from power generation domestically and internationally through the use of U.S. technologies. The following discussion addresses the objectives, background and financial incentives for a program of incentives and research and development for the early commercial applications of Clean Coal Technologies. Objectives of the Incentives and R&D Program for the Early Commercial Applications of Clean Coal Technology: Fuel Diversity - Coal combustion is currently the largest source of energy for electricity production in the U.S. (55%) as well as the rest of the world (38%) and is projected to remain so for the foreseeable future. Development and deployment of highly efficient clean coal technologies will allow for the reduction of carbon emissions and avoid a dependence on a limited number of fuel sources for U.S. power production. According to the EIA's latest Annual Energy Outlook1, coal is projected to generate 57% of the electricity consumed in 1998, and is to produce 52% and 51% respectively in 2010 and 2020. Coal remains the major U.S. source of electricity, even after over a 400% increase in electricity produced from natural gas between 1998 and 2020. The International Energy Agency of the OECD has projected that coal will provide 43% of the world's electricity in 2020². Development and deployment of these technologies globally will allow for the double opportunities of exporting U.S. technologies and reducing carbon emissions from developing countries. I Energy Information Administration, Annual Energy Outlook 1998, Washington DC, November 1997. 2 International Energy Agency, World Energy Prospects To 2020, Paris, March 1998. COAL UTILIZATION RESEARCH COUNCIL Rev 4 11/16/98 Page 5 Technology Promise - The clean coal technology program has allowed for the demonstration of a number of first-of-a-kind technologies that can increase efficiency and reduce carbon emissions from coal combustion. With further R&D and deployment, these technologies can be optimized for increased efficiency and lower carbon emissions and their technical and economic viability can be validated to ensure their commercial feasibility to enter the market place in the intermediate term (2010). Sustainable Economy - Coal must remain a viable, readily available, and competitive source of fuel for electric power generation and become a significant source of transportation fuels and chemical feed stocks in order to preserve and promote economic growth, energy price stability and national energy security. Background for the Clean Coal Technology Program It is in the U.S. national interest to retain coal as a viable fuel source in order to preserve fuel flexibility and to assure energy security for the country. In the past, coal related R&D and technology demonstration efforts have shown that coal can be burned in a manner that is consistent with the country's economic and environmental goals. The current Clean Coal Technology Program has demonstrated a number of excellent options to increase efficiency and reduce emissions. However, full commercial penetration of these technologies will require building and operating experience from the next 2-3 early commercial applications for each major technology category, e.g. APCS, PFBC, IGCC, etc. In order to install these early commercial applications, the designer, manufacturer, financier and owner must be willing to accept the technological and economic risk associated with the not yet fully commercial technology. With impending deregulation, electricity producers in the U.S. are not able to assume this risk in comparison to installing conventional technologies. After deregulation, 2005 and beyond, the developers of new electric generating plants will typically be more risk adverse. Furthermore, the U.S. currently has ample generating capacity through 2005 and little if any base-load capacity will be constructed. New capacity, which may be installed, will most probably be natural gas-fired because of its lower equipment cost and projected lower cost of gas over the near term. In contrast to the U.S., developing countries will be installing large amounts of new generating capacity and much of it will be coal-fired. Therefore it is in the best interests of the U.S. to promote the installation of these early commercial applications as soon as possible, including consideration of encouraging U.S. companies and U.S. clean coal technology to be installed overseas. This will: COAL UTILIZATION RESEARCH COUNCIL Rev 4 11/16/98 Page 6 accelerate the availability of commercially mature CCT's so that the option is available to the U.S. to meet its future economic and environmental goals; result in real reductions of greenhouse gases wherever these early commercial applications occur; keep U.S. industry in the forefront of CCT development and competitive in the world market place; and create jobs and favorable economic contributions to the U.S. economy. Promotion of the installation of these early commercial applications of the CCT's will require continued R&D funding and new financial incentives to overcome the associated technological and economic risks. Criteria for Financial Incentives for the Early Commercial Applications of Clean Coal Technology: Tax Incentives are preferred over direct subsidies. Incentives are to address technical and commercial risk associated with the development and deployment of a new technology. Program should be robust enough to encompass all fuels, but have a primary emphasis on coal. Program should have a limited timeframe of 2000 to 2012 to address only the early commercial applications of new technologies. Incentives would apply only to those technologies that measurably increase thermal efficiency or reduce carbon emissions in comparison to conventional technologies. Incentives should first target domestic markets for deployment of the early commercial applications, but the incentives should be applicable to international applications of qualifying U.S. technologies by U.S. companies if domestic markets fail to offer sufficient opportunities for timely commercialization. Proposed Financial Incentives for the Early Commercial Applications of Clean Coal Technology: The following incentives represent the minimum set of financial mechanisms that will overcome the higher capital cost and greater operating risk associated with early commercial applications of CCT's. Exclusion of any one of the incentives will cause the CCT to become uneconomical or too great a risk for the owner to install the technology in comparison to conventional technology, which at the present time would most likely be natural gas combined cycle technology. COAL UTILIZATION RESEARCH COUNCIL Rev 4 11/16/98 Page 7 Proposed Incentives: Section 1 - Incentives (1) Investment Tax Credit - The U.S. owner(s) or U.S. parent company(s) of the owner(s) of a Qualifying Clean Coal Technology, which is installed in the U.S. or abroad between 2000 and 2012, shall be entitled to a tax credit equal to 20% of the project owner's equity investment. (2) Production Tax Credit - The U.S. owner(s) or U.S. parent company(s) of the owner(s) of a Qualifying Clean Coal Technology, which is installed in the U.S. or abroad and begins operation between 2000 and 2012, shall receive a production tax credit for each kilowatt hour generated over the first 10 years of operation and based on the technologies design net heat rate as indicated in the table below: Operation Design Average Incentive for Incentive for beginning Net Heat Rate, First 5 years of Second 5 Years of during or Btu/kWh (HHV)* Operation, Operation, before cents/kWh cents/kWh Generated Generated 8400 or less 1.30 1.10 2004 8401-8550 1.00 0.85 8551-8750 0.90 0.70 7770 or less 1.00 0.80 2008 7771-8125 0.80 0.65 8126-8350 0.70 0.55 7720 or less 0.85 0.70 2012 7721-7380 0.70 0.45 *Note: Increased efficiency is equivalent to a lower Net Heat Rate. (3) Risk Pool - The federal government would establish a Risk Pool that would be available to the owner(s) of a Qualifying Clean Coal Technology, which is installed in the U.S. or abroad, during its first 3 years of operation to offset costs, if any, for modifications resulting from the technology's failure to achieve its design performance during start-up and initial operation. The total amount of recoverable costs shall be limited to 5% of the total installed cost of the project. COAL UTILIZATION RESEARCH COUNCIL Rev 4 11/16/98 Page 8 Section 2 - Definitions: (a) Conventional Technology - (i) coal-fired combustion technology with a design average net heat rate of not less than 9,300 Btu/kWh (HHV) and a carbon equivalents emission rate of not more than 0.53 pounds of carbon per kilowatt hour; (ii) natural gas-fired combustion technology with a design average net heat rate of not less than 7,500 Btu/kWh (HHV) and a carbon equivalents emission rate of not more than 0.24 lbs. of carbon per kilowatt hour. (b) Clean Coal Technology (CCT's) - advanced technology that utilizes coal to produce 50% or more of its thermal output as electricity, including advanced pulverized coal or atmospheric fluidized bed combustion, pressurized fluidized bed combustion, integrated gasification combined cycle, and any other advanced combustion technology that exceeds the performance of the conventional technology specified above. (c) Qualifying Clean Coal Technology - (i) applications totaling 1,000 MW of advanced pulverized coal or atmospheric fluidized bed combustion technology installed as a new, retrofit, or repowering applications and operated between 2000 and 2010 that have a design average net heat rate of not more than 8,750 Btu/kWh; (ii) applications totaling 1,500 MW of pressurized fluidized bed combustion technology installed as a new, retrofit, or repowering applications and operated between 2000 and 2012 that have a design average net heat rate of not more than 8,400 Btu/kWh; (iii) applications totaling 1,500 MW of integrated gasification combined cycle technology installed as a new, retrofit, or repowering applications and operated between 2000 and 2012 that have a design average net heat rate of not more than 8,550 Btu/kWh; and (iv) applications totaling 2000 MW or equivalent of technology for the production of electricity installed as a new, retrofit, or repowering application and operated between 2000 and 2012 that have a carbon emission rate that is no more than 85% of conventional technology. Clean coal technology projects receiving or scheduled to receive funding under the Department of Energy's Clean Coal Technology Program, shall not be eligible to be a Qualifying Clean Coal Technology as defined above. (d) Design Average Net Heat Rate - shall be based on the design average annual heat input and the design average annual net electrical generating capacity of the Qualifying Clean Coal Technology at standard conditions. Co- generation of steam shall not be considered in determining a technology's Design Average Net Heat Rate. (e) Project Selection Criteria - shall be established by the Department of Energy as part of a competitive solicitation for selecting Qualifying Clean Coal Technologies and the primary selection criteria shall be minimum design average net heat rate, maximum design average thermal efficiency and lowest cost to the government. DOE may establish other supplemental selection criteria as appropriate. COAL UTILIZATION RESEARCH COUNCIL Rev 4 11/16/98 Page 9 Impact on U.S. Tax Revenue from the Incentives and R&D Program for the Early Commercial Applications of Clean Coal Technology: The cost of the tax incentives and Risk Pool appropriations requirements over the first 10 years of the program would be $675 million (1998$). The total cost of the program over its 22 years life would be $1,502 million. The EIA³ has estimated that between 1998 and 2020, 24,000 MW of coal-fired and 169,930 MW of natural gas-fired electric generating capacity will be installed in the U.S. Encouraging the early commercial application of CCT's with a combined generating capacity of 6,000 MW to be part of this new capacity could be accomplished through a combination of investment tax credits and production tax credits offered over a limited number of years. It is anticipated that the 6,000 MW of CCT's will be installed in steps with each subsequent installation achieving improved operating and financial performance. It takes approximately 3 years to build a commercial CCT project; therefore, it is unlikely that any Qualifying CCT's would be placed into service before 2004. Theses CCT's would need to be operated several years to validate their performance and provide a basis for further improvement of a technology's operating and financial characteristics. At the earliest, the next set of CCT's would be placed into service in 2008 with the third and final set of qualifying CCT's coming on line in 2012. The period during which a Qualifying CCT must be placed in service to receive the tax credits is 2000 to 2012. The investment tax credits would apply to the first 4 years of construction and the production tax credit would apply to the first 10 years of operation. The Risk Pool would apply to the first 3 years of operation of each Qualifying CCT. The total period during which Qualifying CCT's could be receiving tax credits would be from 2000 to 2021. The estimated impact on tax revenues of the credits and the appropriations requirements of the Risk Pool are shown in the following table: Financial Impact of Qualifying CCT's Tax Credits (million 1998 $ NPV) 1999-2003 2004-2008 2009-2013 1999-2021 Investment Tax Credit $90 $73 $41 $203 Production Tax Credit $0 $377 $439 $1,023 Risk Pool Appropriation $0 $135 $117 $276 Total $90 $585 $597 $1,502 The risk pool exposure to the federal government would be $276 million, which is 5% of the total installed cost of the CCT's. However, the actual exposure would be less 3 EIA, AEO1998 COAL UTILIZATION RESEARCH COUNCIL Rev 4 11/16/98 Page 10 because not all installations would be expected to experience problems severe enough during start-up and initial operation to require the use of all 5% of their installed cost. The proposal is not open-ended like many previous tax incentives for developing technologies. There is an upper limit on the amount of clean coal technology that could be constructed under these tax incentives. The limitation is included in paragraph (4) Definitions, in terms of megawatts of capacity. No more than 6,000 MW of CCT's could receive these tax incentives. The proposal includes scenarios, for analysis purposes, as to how many plants of different types might be constructed. However, the number may vary, but not the limitation of 6,000 MW of electricity generating capacity. An explanation of the assumptions and financial projections for the tax revenue impacts is contained in attachment A. Environmental Benefits of the Incentives and R&D Program for the Early Commercial Applications of Clean Coal Technology: A common trait among all of the CCT's is an increase in the thermal efficiency of converting fuel to electricity. Conventional technology being installed around the world today is approximately 37% efficient. It is anticipated that by 2010, advanced pulverized coal-fired systems, externally-fired heat exchanger power systems, advanced gasification combined cycle and advanced pressurized fluidized bed combustion will be able to achieve efficiencies of 45% to 47%. In addition, by 2020, hybrids of these same technologies with further improvements, combined with fuel cell technology are expected to achieve efficiencies of up to 60%. As a result of these efficiency increases, greenhouse gas emissions of carbon will decrease by an amount equal to the improvement in efficiency over conventional technology. Over its forty-year life a conventional 45OMW pulverized coal-fired electric generating unit would emit 32 million metric tons of carbon. By contrast, an advanced integrated gasification combined cycle (IGCC) unit would emit 29 million tonnes if installed today and would improve to between 26 million tonnes and 21 million tonnes if the advanced versions were available and installed in 2010 and 2020 respectively. This represents a potential reduction in carbon emissions of 35%. The DOE has estimated that the energy savings from increasing efficiency in U.S. coal-fired power plants to 50% would be the equivalent of: replacing 1.8 Billion light bulbs with energy saving types; or weatherizing 490 million homes - more than 5 times the number of U.S. homes. The attached graph and table present the estimates of life cycle emissions of greenhouse gases. COAL UTILIZATION RESEARCH COUNCIL Rev 4 11/16/98 Page 11 The 24,000 MW of conventional coal-fired capacity that EIA has projected to be installed between 1998-2012 would have an electricity production efficiency of approximately 37%. While the efficiencies of the 4,000 MW of electricity generating CCT's that are anticipated to be installed as a result of the tax incentives would range from 39 to 46%. The greater the efficiency, the lower the amount of emissions for the same amount of electricity produced. Installation of CCT's as opposed to conventional coal-fired technology would result in a reduction of carbon emissions of 1.2 million tonnes by 2008 and 10.7 million tonnes by 2021. If a sufficient number of early commercial applications of the electricity generating CCT's were to occur and the technologies reached the anticipated level of economic and technical performance, it is reasonable to assume that they would account for a significant portion of the replacement and new generating capacity that would be installed globally. The global impact of these installations would be to reduce carbon emissions by an amount proportional to their improvement in efficiency over conventional technology that would otherwise be installed. The EIA⁴ projects that total world carbon emissions were 5.8 billion metric tons in 1990 and will increase to 10.5 billion metric tons by 2020. If deployment of CCT's in the industrialized countries and the developing countries of Asia and Africa resulted in capacity additions equal to (1) 10% of the coal supplied energy utilized in 2010, (2) 50% of capacity additions between 2010 and 2015 and (3) 75% of the additions between 2015 and 2020, annual total world carbon emissions could be reduced by 294 million metric tons in 2020 with further decreases each year in which deployment increased. This is approximately a 3% reduction of world carbon emissions and is equivalent to 25% (294/1180) of the reduction required from developed countries in 2020 under provisions similar to those of the Kyoto Protocol. This reduction projection does not consider generating capacity that will be retired and replaced with advanced technologies, which would provide further reductions in carbon emissions. The attached graph and summary table provides an estimate of world carbon emissions on a regional basis for a business-as-usual case and a deployment of CCT's case. Research Vision for the Early Commercial Applications of Clean Coal Technology: The government and industry must work together to support an appropriate balance of short-term and long-term activities required to develop and commercialize technology which will permit the economic, efficient, and environmentally compatible use of coal. This can be accomplished through a sustained collaborative effort between private industry and government. Collaboration can best be achieved through communication, cooperation, and education in the design and execution of a targeted R&D program that focuses on 4 Energy Information Administration, International Energy Outlook 1998 With Projections through 2020, Washington DC, April 1998. COAL UTILIZATION RESEARCH COUNCIL Rev 4 11/16/98 Page 12 assisting the development and commercialization of coal utilization technologies. With limited financial resources, government and industry can leverage available funds through such a collaborative effort. U.S. based technological progress will be vital for satisfying domestic and global energy and environmental needs, while supporting domestic economic well being. The current portfolio of DOE Fossil Energy programs should continue to be funded with additional emphasis on those programs that will have the greatest impact on: efficiency, (e.g. ATS, HIPPS, Ultra-Supercritical Steam Cycle, IGCC and advanced PFBC); and component reliability of operation for such technologies as high temperature particulate filters, hot gas desulfurization, coal feed/ash withdrawal, syngas burners for advanced PFBC's and IGCC'S, and material technology. Budget Implications for the Incentives and R&D Program for the Early Commercial Applications of Clean Coal Technology: The potential timeframes in which the CCT's in the current DOE portfolio could be displayed are shown in attachment B. The specific schedules for accomplishing the development of each program element is primarily a function of budget resources. Presently, it is not possible to relate the DOE's budget to attachment B and make meaningful judgments as to how budget reallocations or additions would affect the availability of each CCT. The main emphasis here will be on efficiency, reliability and cost. The DOE should develop its budget for fossil R&D in terms of the elements and timeframes shown in attachment B so that a common baseline is established for the CCT program. DOE should recast and explain its current program/budget and schedule within the appropriate timeframes so that recommendations can be made for changes to the FY 2000 budget in the near term. COAL UTILIZATION RESEARCH COUNCIL Rev 4 11/16/98 Page 13 Life Cycle Carbon Emissions From Clean Coal Technologies 35 32.9 30 2010 2020 25.6 26.5 26.5 25 21.2 21.2 Carbon, Mil Tonnes 20 17.2 15 12.9 10 Not Availab 5 in 201 0 Conv PC HIPPS AGCC APFBC IGFC NGCC Technologies Commercially Available in 2010 and 2020 COAL UTILIZATION RESEARCH COUNCH Rev 4 11/16/98 Page 14 Life Cycle Carbon Emissions from Clean Coal Technologies Technology TODAY 2010 2020 Advanced Pulverized Coal-Fired Combustion Capacity, MW 450 450 Not Capacity Factor 85 85 Available Design Efficiency, % HHV 37 45 Design Heat Rate, Btu/kWh HHV 9300 7500 Carbon Emissions, Mil Tonnes/Year 0.82 0.66 Mil Tonnes/40 Yr Life 32.89 26.52 Difference from Today 6.37 High Performance Power Systems (Externally Fired Heat Exchanger) Capacity, MW 450 Not Capacity Factor 85 Available Design Efficiency, % HHV 47 Design Heat Rate, Btu/kWh HHV 7250 Carbon Emissions, Mil Tonnes/Year 0.64 Mil Tonnes/40 Yr Life 25.64 Difference from Today 7.25 Gasification Combined Cycle Advanced Hybrid Capacity, MW 450 450 450 Capacity Factor 85 85 85 Design Efficiency, % HHV 41 45 57 Design Heat Rate, Btu/kWh HHV 8200 7500 6000 Carbon Emissions, Mil Tonnes/Year 0.72 0.66 0.53 MII Tonnes/40 Yr Life 29.00 26.52 21.22 Difference from Today 6.37 11.67 Pressurized Fluidized Bed Combustion Advanced Hybrid Capacity, MW 450 450 450 Capacity Factor 85 85 85 Design Efficiency, % HHV 40 45 57 Design Heat Rate, Btu/kWh HHV 8500 7500 6000 Carbon Emissions, Mil Tonnes/Year 0.75 0.66 0.53 Mil Tonnes/40 Yr Life 30.06 26.52 21.22 Difference from Today 6.37 11.67 Integrated Gasification Fuel Cell Capacity, MW Not Not 450 Capacity Factor Available Available 85 Design Efficiency, % HHV 70 Design Heat Rate, Btu/kWh HHV 4875 Carbon Emissions, Mil Tonnes/Year 0.43 Mil Tonnes/40 Yr Life 17.24 Difference from Today 15.65 Natural Gas Fired Combine Cycle Capacity, MW 450 450 450 Capacity Factor 85 85 85 Design Efficiency, % HHV 49 52 52 Design Heat Rate, Btu/kWh HHV 7000 6500 6500 Carbon Emissions, Mil Tonnes/Year 0.35 0.32 0.32 Mil Tonnes/40 Yr Life 13.92 12.92 12.92 Difference from Today 19.96 19.96 COAL UTILIZATION RESEARCH COUNCIL Rev 4 11/16/98 Page 15 Impact of Advanced Clean Coal Technology on World Carbon Emissions 12,000 Adv CCT Developing Countries 10,448 10,154 Adv CCT Developed Countries 10,000 BAU Developing Countries 9,317 9,143 BAU Developed Countries 8,331 8,227 8,000 5,159 4,894 Carbon, Mil Tonnes 4.302 4,156 3,592 3,514 6,000 4,000 4,988 5,260 4,713 2,000 0 2010 2015 2020 COAL UTILIZATION RESEARCH COUNCIL Rev 4 11/16/98 Page 16 Impact of Advanced Clean Coal Technologies on World Carbon Emissions 2010 2015 2020 Developed Countries North America Business As Usual Carbon Emissions, Mil Tonnes 2,105 2,217 2,313 Coal Energy Supplied by Advanced Clean Coal 10% 11% 13% Carbon Emissions with Advanced CCT, Mil Tonnes 2,092 2,201 2,293 Carbon Reduction, Mil Tonnes/Year 13 16 20 Western Europe Business As Usual Carbon Emissions, Mil Tonnes 1,101 1,169 1,239 Coal Energy Supplied by Advanced Clean Coal 10% 10% 10% Carbon Emissions with Advanced CCT, Mil Tonnes 1,096 1,164 1,234 Carbon Reduction, Mil Tonnes/Year 5 5 5 Asia/Pacific Business As Usual Carbon Emissions, Mil Tonnes 461 485 514 Coal Energy Supplied by Advanced Clean Coal 10% 11% 12% Carbon Emissions with Advanced CCT, Mil Tonnes 459 482 511 Carbon Reduction, Mil Tonnes/Year 2 3 3 Eastern Europe/Former Soviet Union Business As Usual Carbon Emissions, Mil Tonnes 1,072 1,144 1,223 Coal Energy Supplied by Advanced Clean Coal 10% 8% 5% Carbon Emissions with Advanced CCT, Mil Tonnes 1,066 1,139 1,222 Carbon Reduction, Mil Tonnes/Year 6 5 1 Total Developed Countries Business As Usual Carbon Emissions, Mil Tonnes 4,739 5,015 5,289 Coal Energy Supplied by Advanced Clean Coal 10% 10% 10% Carbon Emissions with Advanced CCT, Mil Tonnes 4,713 4,988 5,260 Carbon Reduction, Mil Tonnes/Year 26 27 29 Developing Countries Asia/Pacific Business As Usual Carbon Emissions, Mil Tonnes 2,603 3,158 3,835 Coal Energy Supplied by Advanced Clean Coal 10% 17% 28% Carbon Emissions with Advanced CCT, Mil Tonnes 2,572 3,086 3,660 Carbon Reduction, Mil Tonnes/Year 31 72 175 Middle East Business As Usual Carbon Emissions, Mil Tonnes 322 363 409 Coal Energy Supplied by Advanced Clean Coal 0% 0% 0% Carbon Emissions with Advanced CCT, Mil Tonnes 315 344 388 Carbon Reduction, Mil Tonnes/Year 7 19 21 Africa Business As Usual Carbon Emissions, Mil Tonnes 276 306 341 Coal Energy Supplied by Advanced Clean Coal 10% 12% 17% Carbon Emissions with Advanced CCT, Mil Tonnes 245 274 302 Carbon Reduction, Mil Tonnes/Year 31 32 39 Central & South America Business As Usual Carbon Emissions, Mil Tonnes 391 475 574 Coal Energy Supplied by Advanced Clean Coal 0% 0% 0% Carbon Emissions with Advanced CCT, Mil Tonnes 382 452 545 Carbon Reduction, Mil Tonnes/Year 9 23 29 Total Developing Countries Business As Usual Carbon Emissions, Mil Tonnes 3,592 4,302 5,159 Coal Energy Supplied by Advanced Clean Coal 10% 17% 27% Carbon Emissions with Advanced CCT, Mil Tonnes 3,514 4,156 4,894 Carbon Reduction, Mil Tonnes/Year 78 146 265 Total World Business As Usual Carbon Emissions, Mil Tonnes 8,331 9,317 10,448 Coal Energy Supplied by Advanced Clean Coal 10% 14% 21% Carbon Emissions with Advanced CCT, Mil Tonnes 8,227 9,143 10,154 Carbon Reduction, Mil Tonnes/Year 104 174 294 COAL UTILIZATION RESEARCH COUNCIL Clinton Presidential Records Digital Records Marker This is not a presidential record. This is used as an administrative marker by the William J. Clinton Presidential Library Staff. This marker identifies the place of a tabbed divider. Given our digitization capabilities, we are sometimes unable to adequately scan such dividers. The title from the original document is indicated below. FINANCIAL ANALYSIS Divider Title: Rev 4 11/16/98 Page 17 Attachment A Financial Analysis of Tax Credits and Risk Pool Appropriation Requirements The financial analysis examines the level of tax credits that would be required to have a developer of electricity generating capacity to undertake an early commercial application of an emerging clean coal technology (CCT). The level of tax credits required is determined through a comparison of the revenue requirements for building and operating a CCT plant and a natural gas-fired combined cycle (NGCC) plant. The NGCC plant, in many applications in the US, represents the electricity generating technology that has the lowest capital costs and produces the lowest cost electricity. This comparison is intended to be a "first-look" at this question with only first order effects being modeled and the assumptions have not been refined beyond that point. The average price per MWh was calculated for the NGCC plant to produce an internal rate of return for the project cash flows, after taxes, which is equal to the weighted average cost of capital after taxes. The weighted average cost of capital reflects a 10% interest rate for debt, 25% owner's equity and a required rate of return on equity of 18%. The results of this calculation are shown for NGCC plants that begin operation in 2004, 2008 and 2012. The CCT's are currently in the early stage of commercialization and as a result have higher capital and operating costs and exhibit a higher level of risk associated with achieving its design performance. In order to encourage a developer to install a CCT, financial incentives must be offered to overcome the inherently higher financial and operating risk of an emerging technology. The financial incentives must be great enough for the CCT to compete with the lowest cost alternative energy source. In this analysis, that is assumed to be a NGCC plant. To determine the required level of financial incentives, the present value of the cash flows for each CCT assumed to be installed are calculated assuming that the average price of electricity is the same as for the NGCC plant. The cash flow from the CCT is increased by the application of an investment tax credit and a production tax credit until the internal rate of return of the cash flows is equivalent to the weighted average cost of capital after taxes. To determine the impact of the financial incentives on tax revenues, the analysis assumes that one each of three different CCT's would be installed in 2004. These would be one 500MW advanced pulverized coal-fired plant (AdvPCF2004), one 500MW pressurized fluidized bed plant (PFBC) and one 500MW integrated gasification combined cycle plant (IGCC). It takes approximately 3 years to build a CCT plant and that is why no plants begin operation before 2004. In order to benefit from the experience gained from the first units, the second set of the same technologies are COAL UTILIZATION RESEARCH COUNCIL Rev 4 11/16/98 Page 18 assumed to begin operation in 2008. The final 2 installations begin operation in 2012, but only a PFBC and an IGCC unit are assumed to be installed because AdvPCF is assumed to have reached its maximum level of performance with the 2008 installation. A third and equally necessary financial incentive (the "Risk Pool") is also calculated for each installation. The Risk Pool is to be established by appropriations from the U.S. government and authorized only if a qualifying CCT plant could not meet its design performance and had to be modified during the initial start-up or first 3 years of operation. The level of federal funding would be limited to 5% of the installed capital costs of the plant. The values of the tax incentives and risk pool are discounted to 1998 dollars at the current 30-year Treasury bill rate of 6%. COAL UTILIZATION RESEARCH COUNCIL Attachment A Financial Analysis of Tax Credits and Risk Pool Appropriation Requirements Tax Revenue, Appropriations and Environmental Impacts - Electricity Production 4/17/98 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2021 Tax Revenue Impacts, $x000 Installed Installed Capacity Cost Technology MW $/KW Adv PCF Investment Tax Credit 500 1,150 $37,335 Production Tax Credit $29,565 $29,565 $29,565 $29,565 $29,565 $22,995 $22,995 $22,995 $22,995 $22,995 Investment Tax Credit 500 1,095 $38,480 Production Tax Credit $22,995 $22,995 $22,995 $22,995 $22,995 $18,068 $18,068 PFBC Investment Tax Credit 500 1,250 $40,582 Production Tax Credit $32,850 $32,850 $32,850 $32,850 $32,850 $27,923 $27,923 $27,923 $27,923 $27,923 Investment Tax Credit 500 1,190 $41,818 Production Tax Credit $26,280 $26,280 $26,280 $26,280 $26,280 $21,353 $21,353 Investment Tax Credit 500 1,130 $42,983 Production Tax Credit $22,995 $22,995 $22,995 $14,783 IGCC Investment Tax Credit 500 1,300 $42,205 Production Tax Credit $42,705 $42,705 $42,705 $42,705 $42,705 $37,778 $37,778 $37,778 $37,778 $37,778 Investment Tax Credit 500 1,205 $42,345 Production Tax Credit $32,850 $32,850 $32,850 $32,850 $32,850 $26,280 $26,280 Investment Tax Credit 500 1,145 $43,554 Production Tax Credit $27,923 $27,923 $27,923 $22,995 Total Revenue Impact Investment Tax Credit 4,000 1,183 $120,122 $0 $0 $0 $122,644 $0 $0 $0 $86,537 Production Tax Credit $105,120 $105,120 $105,120 $105,120 $187,245 $170,820 $170,820 $170,820 $221,738 $205,313 $116,618 $37,778 Total $120,122 $105,120 $105,120 $105,120 $227,764 $187,245 $170,820 $170,820 $257,357 $221,738 $205,313 $116,618 $37,778 Total Revenue Impact (1998$, Discounted @ T-Bill rate of 6%) Investment Tax Credit $89,762 $0 $0 $0 $72,593 $0 $0 $0 $40,572 $0 $0 $0 $0 Production Tax Credit $0 $74,105 $69,911 $65,954 $62,220 $104,557 $89,986 $84,892 $80,087 $98,075 $85,670 $45,906 $9,890 Total $89,762 $74,105 $69,911 $65,954 $134,813 $104,557 $89,986 $84,892 $120,659 $98,075 $85,670 $45,906 $9,890 Total Revenue 1999-2003 (1998$) $89,762 Total Revenue 2004-2008 (1998$) $449,340 Total Revenue 1999-2021 (1998$) $1,225,919 Page A-1 incelec6 xls Attachment A Financial Analysis of Tax Credits and Risk Pool Appropriation Requirements Tax Revenue, Appropriations and Environmental Impacts - Electricity Production 4/17/98 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2021 Risk Pool Appropriations, $x000 Adv PCF $12,445 $12,445 $12,445 $12,827 $12,827 $12,827 PFBC $13,527 $13,527 $13,527 $13,939 $13,939 $13,939 $14,328 $14,328 $14,328 IGCC $14,068 $14,068 $14,068 $14,115 $14,115 $14,115 $14,518 $14,518 $14,518 Total $40,041 $40,041 $40,041 $40,881 $40,881 $40,881 $28,846 $28,846 $28,846 Total (1998$) $33,619 $33,619 $33,619 $34,325 $34,325 $34,325 $24,219 $24,219 $24,219 Total 1999-2003(1998$) $0 Total 2004-2008(1998$) $135,181 Total 1999-2021(1998$) $276,489 Carbon Equivalents Reductions (100 Year Warming Potential), Tonnes Heat Rate Thermal Technology Btu/kWh Efficiency Conventional PCF 9,300 37% Adv PCF 8,750 39% 46,506 46,506 46,506 46,506 46,506 46,506 46,506 46,506 46,506 46,506 46,506 46,506 8,315 41% 83,288 83,288 83,288 83,288 83,288 83,288 83,288 83,288 PFBC 8,550 40% 63,417 63,417 63,417 63,417 63,417 63,417 63,417 63,417 63,417 63,417 63,417 63,417 8,125 42% 99,353 99,353 99,353 99,353 99,353 99,353 99,353 99,353 7,720 44% 133,598 133,598 133,598 133,598 IGCC 6,400 41% 76,100 76,100 76,100 76,100 76,100 76,100 76,100 76,100 76,100 76,100 76,100 76,100 7,770 44% 129,371 129,371 129,371 129,371 129,371 129,371 129,371 129,371 7,380 46% 162,347 162,347 162,347 162,347 Total Reduction 186,023 186,023 186,023 186,023 498,034 498,034 498,034 498,034 793,980 793,980 793,980 793,980 1999-2003 0 2004-2008 1,242,126 $/Tonne 471 1999-2021 10,676,028 $/Tonne 141 Page A-2 incelec6.xls Attachment A NGCC 500 MW Plant (2004) 4/17/98 capacity 500 MW capital carrying charges 13.50% heat rate 7000 Btu/kWh depreciation Straight Line fuel cost $2.64 /mmBtu initial cost $525 /kW fuel escalation 3.0% % debt financing 75% inflation, O&M and capital 2.0% cost of debt 10% non-fuel variable O&M 1 $/MWh cost of equity 18% fixed O&M 9 $/kW-yr weighted ave cost of capital after ta 9.45% capacity factor 75% G&A 2% generation 3,285,000 MWh tax rate 34% book life 20 years construction expenditure cycle useful life 30 years year 1 30% loan term 20 years year 2 40% discount rate 6.0% year 3 30% Construction Period Investment 2001 2002 2003 2004 year 1998 -3 -2 -1 0 1 2 3 4 5 6 7 8 9 10 initial cost $262,500 $83,570 $113,655 $86,946 $340,886 Revenue electricity price, $/MWh $36.73 $41.36 $42.19 $43.04 $43.90 $44.77 $45.67 $46.58 $47.51 $48.46 $49.43 electricity revenue $135,881 $138,598 $141,370 $144,198 $147,081 $150,023 $153,024 $156,084 $159,206 $162,390 Expenses fuel expense $72,487 $74,662 $76,902 $79,209 $81,585 $84,032 $86,553 $89,150 $91,824 $94,579 non-fuel O&M $3,699 $3,773 $3,849 $3,926 $4,004 $4,084 $4,166 $4,249 $4,334 $4,421 fixed O&M $5,068 $5,169 $5,272 $5,378 $5,485 $5,595 $5,707 $5,821 $5,938 $6,056 total annual production expenses $81,254 $83,604 $86,023 $88,512 $91,075 $93,712 $96,427 $99,221 $102,097 $105,057 electricity production expense, $/MWh $24.73 $25.45 $26.19 $26.94 $27.72 $28.53 $29.35 $30.20 $31.08 $31.98 depreciation $17,044 $17,044 $17,044 $17,044 $17,044 $17,044 $17,044 $17,044 $17,044 $17,044 G&A $6,818 $6,818 $6,818 $6,818 $6,818 $6,818 $6,818 $6,818 $6,818 $6,818 total expenses $105,116 $107,466 $109,885 $112,374 $114,937 $117,574 $120,289 $123,083 $125,959 $128,919 Net Income Before Taxes $30,764 $31,132 $31,485 $31,823 $32,145 $32,449 $32,735 $33,001 $33,247 $33,471 cash flow, NIBT+depreciation ($340,886) $47,809 $48,176 $48,529 $48,867 $49,189 $49,493 $49,779 $50,046 $50,291 $50,515 taxes $10,460 $10,585 $10,705 $10,820 $10,929 $11,033 $11,130 $11,220 $11,304 $11,380 Net Income $20,304 $20,547 $20,780 $21,003 $21,216 $21,416 $21,605 $21,781 $21,943 $22,091 cash flow= NI + depreciation ($340,886) $37,349 $37,591 $37,825 $38,048 $38,260 $38,461 $38,649 $38,825 $38,987 $39,135 IRR after taxes 9.45% PV Investment ($308,751) PV NI + depreciation @ WACC $308,855 Page A-3 incelec6.xls Attachment A Advanced Pulverized Coal-Fired 500 MW Plant (2004) 4/17/98 capacity 500 MW capital carrying charges 13.50% Investment tax credit 20.0% of Owners equity heat rate 8750 Btu/kWh depreciation Straight Line Production tax credit fuel cost $1.20 /mmBtu initial cost $1,150 /kW 1st 5 years of operation $9.00 per megawatt hour fuel escalation 1.5% % debt financing 75% 2nd five years of operation $7.00 per megawatt hour inflation 2.0% cost of debt 10% Risk Pool 5.00% of capital investment, years 1-3 non-fuel variable O&M 3.25 $/MWh cost of equity 18% fixed O&M 16.5 $/kW-yr weighted ave cost of capital 9.45% capacity factor 75% G&A 2% generation 3,285,000 MWh tax rate 34% book life 20 years construction expenditure cycle useful life 30 years year 1 30% loan term 20 years year 2 40% T Bill rate 6.0% year 3 30% Construction Period Investment year 1998 -3 -2 -1 0 1 2 3 4 5 6 7 8 9 10 initial cost $575,000 $183,058 $248,959 $190,454 $746,702 Revenue electricity price, $/MWh $36.73 $41.36 $42.19 $43.04 $43.90 $44.77 $45.67 $46.58 $47.51 $48.46 $49.43 electricity revenue $135,881 $138,598 $141,370 $144,198 $147,081 $150,023 $153,024 $156,084 $159,206 $162,390 Expenses fuel expense $37,716 $38,281 $38,856 $39,438 $40,030 $40,630 $41,240 $41,858 $42,486 $43,124 non-fuel O&M $12,023 $12,264 $12,509 $12,759 $13,014 $13,275 $13,540 $13,811 $14,087 $14,369 fixed O&M $9,291 $9,477 $9,666 $9,860 $10,057 $10,258 $10,463 $10,672 $10,886 $11,103 total annual production expenses $59,030 $60,022 $61,031 $62,057 $63,101 $64,163 $65,243 $66,342 $67,459 $68,596 electricity production expense, $/MWh $17.97 $18.27 $18.58 $18.89 $19.21 $19.53 $19.86 $20.20 $20.54 $20.88 depreciation (investment -ITC)/20 $35,468 $35,468 $35,468 $35,468 $35,468 $35,468 $35,468 $35,468 $35,468 $35,468 G&A $14,934 $14,934 $14,934 $14,934 $14,934 $14,934 $14,934 $14,934 $14,934 $14,934 total expenses $109,432 $110,424 $111,433 $112,459 $113,503 $114,565 $115,645 $116,744 $117,862 $118,998 Net Income Before Taxes $26,449 $28,174 $29,937 $31,738 $33,578 $35,458 $37,378 $39,340 $41,344 $43,392 taxes $8,993 $9,579 $10,179 $10,791 $11,417 $12,056 $12,709 $13,376 $14,057 $14,753 Net Income $17,456 $18,595 $19,758 $20,947 $22,162 $23,402 $24,670 $25,964 $27,287 $28,638 Investment tax credit $37,335 Production tax credit $29,565 $29,565 $29,565 $29,565 $29,565 $22,995 $22,995 $22,995 $22,995 $22,995 cash flow= NI + depreciation ($709,367) $82,489 $83,628 $84,792 $85,981 $87,195 $81,866 $83,133 $84,428 $85,751 $87,102 IRR after Taxes 9.52% PV Investment ($642,495) PV NI + depreciation @ WACC $645,562 Risk pool appropriation $12,445 $12,445 $12,445 Page A-4 incelec6.xis Attachment A Pressurized Fluidized Bed Combustion 500 MW Plant (2004) 4/17/98 capacity 500 MW capital carrying charges 13.50% Investment tax credit 20.0% of Owners equity heat rate 8550 Btu/kWh depreciation Straight Line Production tax credit fuel cost $1.20 /mmBtu initial cost $1,250 /kW 1st 5 years of operation $10.00 per megawatt hour fuel escalation 1.5% % debt financing 75% 2nd five years of operation $8.50 per megawatt hour inflation 2.0% cost of debt 10% Risk Pool 5.0% of capital investment, years 1-3 non-fuel variable O&M 2.5 $/MWh cost of equity 18% fixed O&M 14 $/kW-yr weighted ave cost of capital 9% capacity factor 75% G&A 2% generation 3,285,000 MWh tax rate 34% book life 20 years construction expenditure cycle useful life 30 years year 1 30% loan term 20 years year 2 40% T Bill Rate 6.0% year 3 30% Construction Period Investment year 1998 -3 -2 -1 0 1 2 3 4 5 6 7 8 9 10 initial cost $625,000 $198,977 $270,608 $207,015 $811,633 Revenue electricity price, $/MWh $36.73 $41.36 $42.19 $43.04 $43.90 $44.77 $45.67 $46.58 $47.51 $48.46 $49.43 electricity revenue $135,881 $138,598 $141,370 $144,198 $147,081 $150,023 $153,024 $156,084 $159,206 $162,390 Expenses fuel expense $36,854 $37,406 $37,967 $38,537 $39,115 $39,702 $40,297 $40,902 $41,515 $42,138 non-fuel O&M $9,249 $9,434 $9,622 $9,815 $10,011 $10,211 $10,415 $10,624 $10,836 $11,053 fixed O&M $7,883 $8,041 $8,202 $8,366 $8,533 $8,704 $8,878 $9,055 $9,236 $9,421 total annual production expenses $53,985 $54,881 $55,791 $56,717 $57,659 $58,617 $59,590 $60,581 $61,588 $62,612 electricity production expense, $/MWh $16.43 $16.71 $16.98 $17.27 $17.55 $17.84 $18.14 $18.44 $18.75 $19.06 depreciation (investment -ITC)/20 $38,553 $38,553 $38,553 $38,553 $38,553 $38,553 $38,553 $38,553 $38,553 $38,553 G&A $16,233 $16,233 $16,233 $16,233 $16,233 $16,233 $16,233 $16,233 $16,233 $16,233 total expenses $108,770 $109,666 $110,576 $111,502 $112,444 $113,402 $114,376 $115,366 $116,373 $117,397 Net Income Before Taxes $27,110 $28,932 $30,794 $32,695 $34,637 $36,621 $38,648 $40,718 $42,833 $44,993 taxes $9,217 $9,837 $10,470 $11,116 $11,777 $12,451 $13,140 $13,844 $14,563 $15,298 Net Income $17,893 $19,095 $20,324 $21,579 $22,861 $24,170 $25,508 $26,874 $28,270 $29,695 Investment tax credit $40,582 Production tax credit $32,850 $32,850 $32,850 $32,850 $32,850 $27,923 $27,923 $27,923 $27,923 $27,923 cash flow= NI + depreciation ($771,051) $89,295 $90,498 $91,726 $92,981 $94,263 $90,645 $91,983 $93,349 $94,745 $96,170 IRR 9.48% PV Investment ($698,365) PV NI + depreciation @ WACC $699,872 Risk pool appropriation $13,527 $13,527 $13,527 Page A-5 incelec6.xls Attachment A Integrated Gasification Combined Cycle 500MW Plant (2004) 4/17/98 capacity 500 MW capital carrying charges 13.50% Investment tax credit 20.0% of Owners equity heat rate 8400 Btu/kWh depreciation Straight Line Production tax credit fuel cost $1.20 /mmBtu initial cost $1,300 /kW 1st 5 years of operation $13.00 per megawatt hour fuel escalation 1.5% % debt financing 75% 2nd five years of operation $11.50 per megawatt hour inflation 2.0% cost of debt 10% Risk Pool 5.0% of capital investment, years 1-3 non-fuel variable O&M 2.25 $/MWh cost of equity 18% fixed O&M 25 $/kW-yr weighted ave cost of capital 9% capacity factor 75% G&A 2% generation 3,285,000 MWh tax rate 34% book life 20 years construction expenditure cycle useful life 30 years year 1 30% loan term 20 years year 2 40% T Bill Rate 6.0% year 3 30% Construction Period Investment year 1998 -3 -2 -1 0 1 2 3 4 5 6 7 8 9 10 initial cost $650,000 $206,936 $281,432 $215,296 $844,098 Revenue electricity price, $/MWh $36.73 $41.36 $42.19 $43.04 $43.90 $44.77 $45.67 $46.58 $47.51 $48.46 $49.43 electricity revenue $135,881 $138,598 $141,370 $144,198 $147,081 $150,023 $153,024 $156,084 $159,206 $162,390 Expenses fuel expense $36,207 $36,750 $37,301 $37,861 $38,429 $39,005 $39,590 $40,184 $40,787 $41,399 non-fuel O&M $8,324 $8,490 $8,660 $8,833 $9,010 $9,190 $9,374 $9,561 $9,753 $9,948 fixed O&M $14,077 $14,359 $14,646 $14,939 $15,237 $15,542 $15,853 $16,170 $16,493 $16,823 total annual production expenses $58,608 $59,599 $60,607 $61,633 $62,676 $63,737 $64,817 $65,916 $67,033 $68,170 electricity production expense, $/MWh $17.84 $18.14 $18.45 $18.76 $19.08 $19.40 $19.73 $20.07 $20.41 $20.75 depreciation (investment -ITC)/20 $40,095 $40,095 $40,095 $40,095 $40,095 $40,095 $40,095 $40,095 $40,095 $40,095 G&A $16,882 $16,882 $16,882 $16,882 $16,882 $16,882 $16,882 $16,882 $16,882 $16,882 total expenses $115,584 $116,575 $117,584 $118,609 $119,653 $120,714 $121,794 $122,892 $124,010 $125,146 Net Income Before Taxes $20,296 $22,023 $23,786 $25,588 $27,429 $29,309 $31,230 $33,192 $35,196 $37,244 taxes $6,901 $7,488 $8,087 $8,700 $9,326 $9,965 $10,618 $11,285 $11,967 $12,663 Net Income after Taxes $13,395 $14,535 $15,699 $16,888 $18,103 $19,344 $20,612 $21,907 $23,229 $24,581 Investment tax credit $42,205 Production tax credit $42,705 $42,705 $42,705 $42,705 $42,705 $37,778 $37,778 $37,778 $37,778 $37,778 cash flow= NI + depreciation ($801,893) $96,195 $97,335 $98,499 $99,688 $100,903 $97,216 $98,484 $99,779 $101,102 $102,453 IRR 9.50% PV Investment ($726,299) PV NI + depreciation @ WACC $728,636 Risk pool appropriation $14,068 $14,068 $14,068 Page A-6 incelec6.xls NGCC 500 MW Plant (2008) 4/17/98 capacity 500 MW capital carrying charges 13.50% heat rate 6750 Btu/kWh depreciation Straight Line fuel cost $2.64 /mmBtu initial cost $525 /kW fuel escalation 3.0% % debt financing 75% inflation 2.0% cost of debt 10% non-fuel variable O&M 1 $/MWh cost of equity 18% fixed O&M 9 $/kW-yr weighted ave cost of capital 9% capacity factor 75% G&A 2% generation 3,285,000 MWh tax rate 34% book life 20 years construction expenditure cycle useful life 30 years year 1 30% loan term 20 years year 2 40% discount rate 6.0% year 3 30% Construction Period Investment year 1998 -3 -2 -1 0 1 2 3 4 5 6 7 8 9 10 initial cost $262,500 $90,459 $123,024 $94,114 $368,986 Revenue electricity price, $/MWh $36.78 $44.83 $45.73 $46.65 $47.58 $48.53 $49.50 $50.49 $51.50 $52.53 $53.58 revenue $147,282 $150,227 $153,232 $156,297 $159,422 $162,611 $165,863 $169,180 $172,564 $176,015 Expenses fuel expense $78,671 $81,031 $83,462 $85,966 $88,545 $91,201 $93,937 $96,756 $99,658 $102,648 non-fuel O&M $4,004 $4,084 $4,166 $4,249 $4,334 $4,421 $4,510 $4,600 $4,692 $4,786 fixed O&M $5,485 $5,595 $5,707 $5,821 $5,938 $6,056 $6,178 $6,301 $6,427 $6,556 total annual production expenses $88,161 $90,711 $93,335 $96,037 $98,817 $101,679 $104,625 $107,656 $110,777 $113,989 electricity production expense, $/MWh $26.84 $27.61 $28.41 $29.23 $30.08 $30.95 $31.85 $32.77 $33.72 $34.70 depreciation $18,449 $18,449 $18,449 $18,449 $18,449 $18,449 $18,449 $18,449 $18,449 $18,449 G&A $7,380 $7,380 $7,380 $7,380 $7,380 $7,380 $7,380 $7,380 $7,380 $7,380 total expenses $113,990 $116,540 $119,164 $121,866 $124,646 $127,508 $130,454 $133,485 $136,606 $139,818 Net Income Before Taxes $33,292 $33,687 $34,067 $34,431 $34,776 $35,103 $35,410 $35,695 $35,958 $36,197 taxes $11,319 $11,454 $11,583 $11,706 $11,824 $11,935 $12,039 $12,136 $12,226 $12,307 Net Income after Taxes $21,973 $22,234 $22,485 $22,724 $22,952 $23,168 $23,370 $23,559 $23,732 $23,890 cash flow= NI + depreciation ($368,986) $40,422 $40,683 $40,934 $41,174 $41,402 $41,617 $41,820 $42,008 $42,181 $42,339 IRR 9.45% PV Investment ($308,751) PV NI + depreciation @ WACC $308,720 Page A-7 incelec6.xls Attachment A Advanced Pulverized Coal-Fired 500 MW Plant (2008) 4/17/98 capacity 500 MW capital carrying charges 13.50% Investment tax credit 20.0% of Owners equity heat rate 8315 Btu/kWh depreciation Straight Line Production tax credit fuel cost $1.20 /mmBtu initial cost $1,095 /kW 1st 5 years of operation $7.00 per megawatt hour fuel escalation 1.5% % debt financing 75% 2nd five years of operation $5.50 per megawatt hour inflation 2.0% cost of debt 10% Risk Pool 5.0% of capital investment, years 1-3 non-fuel variable O&M 2.25 $/MWh cost of equity 18% fixed O&M 25 $/kW-yr weighted ave cost of capital 9% capacity factor 75% G&A 2% generation 3,285,000 MWh tax rate 34% book life 20 years construction expenditure cycle useful life 30 years year 1 30% loan term 20 years year 2 40% T Bill Rate 6.0% year 3 30% Construction Period Investment year 1998 -3 -2 -1 0 1 2 3 4 5 6 7 8 9 10 initial cost $547,500 $188,672 $256,593 $196,294 $769,599 Revenue electricity price, $/MWh $36.78 $44.83 $45.73 $46.65 $47.58 $48.53 $49.50 $50.49 $51.50 $52.53 $53.58 electricity revenue $147,282 $150,227 $153,232 $156,297 $159,422 $162,611 $165,863 $169,180 $172,564 $176,015 Expenses fuel expense $38,040 $38,610 $39,190 $39,777 $40,374 $40,980 $41,594 $42,218 $42,852 $43,494 non-fuel O&M $9,010 $9,190 $9,374 $9,561 $9,753 $9,948 $10,147 $10,350 $10,557 $10,768 fixed O&M $15,237 $15,542 $15,853 $16,170 $16,493 $16,823 $17,160 $17,503 $17,853 $18,210 total annual production expenses $62,287 $63,343 $64,417 $65,509 $66,620 $67,751 $68,901 $70,071 $71,261 $72,472 electricity production expense, $/MWh $18.96 $19.28 $19.61 $19.94 $20.28 $20.62 $20.97 $21.33 $21.69 $22.06 depreciation (investment -ITC)/20 $36,556 $36,556 $36,556 $36,556 $36,556 $36,556 $36,556 $36,556 $36,556 $36,556 G&A $15,392 $15,392 $15,392 $15,392 $15,392 $15,392 $15,392 $15,392 $15,392 $15,392 total expenses $114,235 $115,291 $116,364 $117,457 $118,568 $119,699 $120,849 $122,019 $123,209 $124,420 Net Income Before Taxes $33,047 $34,937 $36,867 $38,840 $40,854 $42,912 $45,014 $47,162 $49,355 $51,595 taxes $11,236 $11,878 $12,535 $13,205 $13,890 $14,590 $15,305 $16,035 $16,781 $17,542 Net Income after Taxes $21,811 $23,058 $24,332 $25,634 $26,964 $28,322 $29,709 $31,127 $32,574 $34,053 Investment tax credit $38,480 Production tax credit $22,995 $22,995 $22,995 $22,995 $22,995 $18,068 $18,068 $18,068 $18,068 $18,068 cash flow= NI + depreciation ($731,119) $81,362 $82,609 $83,883 $85,185 $86,515 $82,946 $84,333 $85,750 $87,198 $88,676 IRR 9.44% PV Investment ($611,767) PV NI + depreciation @ WACC $611,361 Risk pool appropriation $12,827 $12,827 $12,827 Page A-8 incelec6.xls Attachment A Pressurized Fluidized Bed Combustion 500 MW Plant (2008) 4/17/98 capacity 500 MW capital carrying charges 13.50% Investment tax credit 20.0% of Owners equity heat rate 8125 Btu/kWh depreciation Straight Line Production tax credit fuel cost $1.20 /mmBtu initial cost $1,190 /kW 1st 5 years of operation $8.00 per megawatt hour fuel escalation 1.5% % debt financing 75% 2nd five years of operation $6.50 per megawatt hour inflation 2.0% cost of debt 10% Risk Pool 5.0% of capital investment, years 1-3 non-fuel variable O&M 2.5 $/MWh cost of equity 18% fixed O&M 14 $/kW-yr weighted ave cost of capital 9% capacity factor 75% G&A 2% generation 3,285,000 MWh tax rate 34% book life 20 years construction expenditure cycle useful life 30 years year 1 30% loan term 20 years year 2 40% T Bill Rate 6.0% year 3 30% Construction Period Investment year 1998 -3 -2 -1 0 1 2 3 4 5 6 7 8 9 10 initial cost $595,000 $205,040 $278,855 $213,324 $836,367 Revenue electricity price, $/MWh $36.78 $44.83 $45.73 $46.65 $47.58 $48.53 $49.50 $50.49 $51.50 $52.53 $53.58 electricity revenue $147,282 $150,227 $153,232 $156,297 $159,422 $162,611 $165,863 $169,180 $172,564 $176,015 Expenses fuel expense $37,171 $37,728 $38,294 $38,869 $39,452 $40,043 $40,644 $41,254 $41,872 $42,501 non-fuel O&M $10,011 $10,211 $10,415 $10,624 $10,836 $11,053 $11,274 $11,499 $11,729 $11,964 fixed O&M $8,533 $8,704 $8,878 $9,055 $9,236 $9,421 $9,609 $9,802 $9,998 $10,198 total annual production expenses $55,715 $56,643 $57,587 $58,548 $59,524 $60,517 $61,528 $62,555 $63,600 $64,662 electricity production expense, $/MWh $16.96 $17.24 $17.53 $17.82 $18.12 $18.42 $18.73 $19.04 $19.36 $19.68 depreciation (investment -ITC)/20 $39,727 $39,727 $39,727 $39,727 $39,727 $39,727 $39,727 $39,727 $39,727 $39,727 G&A $16,727 $16,727 $16,727 $16,727 $16,727 $16,727 $16,727 $16,727 $16,727 $16,727 total expenses $112,169 $113,098 $114,042 $115,002 $115,979 $116,972 $117,982 $119,010 $120,054 $121,117 Net Income Before Taxes $35,112 $37,129 $39,190 $41,294 $43,443 $45,639 $47,881 $50,171 $52,510 $54,898 taxes $11,938 $12,624 $13,325 $14,040 $14,771 $15,517 $16,279 $17,058 $17,853 $18,665 Net Income after Taxes $23,174 $24,505 $25,865 $27,254 $28,673 $30,122 $31,601 $33,113 $34,656 $36,233 Investment tax credit $41,818 Production tax credit $26,280 $26,280 $26,280 $26,280 $26,280 $21,353 $21,353 $21,353 $21,353 $21,353 cash flow= NI + depreciation ($794,549) $89,182 $90,513 $91,873 $93,262 $94,680 $91,202 $92,681 $94,193 $95,736 $97,313 IRR 9.49% PV Investment ($664,843) PV NI + depreciation @ WACC $666,772 Risk pool appropriation $13,939 $13,939 $13,939 Page A-9 incelec6 xls Attachment A Integrated Gasification Combined Cycle 500MW Plant (2008) capacity 500 MW capital carrying charges 13.50% Investment tax credit 20.0% of Owners equity heat rate 7770 Btu/kWh depreciation Straight Line Production tax credit fuel cost $1.20 /mmBtu initial cost $1,205 /kW 1st 5 years of operation $10.00 per megawatt hour fuel escalation 1.5% % debt financing 75% 2nd five years of operation $8.00 per megawatt hour inflation 2.0% cost of debt 10% Risk Pool 5.0% of capital investment, years 1-3 non-fuel variable O&M 2.25 $/MWh cost of equity 18% fixed O&M 25 $/kW-yr weighted ave cost of capital 9% capacity factor 75% G&A 2% generation 3,285,000 MWh tax rate 34% book life 20 years construction expenditure cycle useful life 30 years year 1 30% loan term 20 years year 2 40% T Bill Rate 6.0% year 3 30% Construction Period Investment year 1998 -3 -2 -1 0 1 2 3 4 5 6 7 8 9 10 initial cost $602,500 $207,625 $282,370 $216,013 $846,910 4/17/98 Revenue electricity price, $/MWh $36.78 $44.83 $45.73 $46.65 $47.58 $48.53 $49.50 $50.49 $51.50 $52.53 $53.58 electricity revenue $147,282 $150,227 $153,232 $156,297 $159,422 $162,611 $165,863 $169,180 $172,564 $176,015 Expenses fuel expense $35,547 $36,080 $36,621 $37,170 $37,728 $38,294 $38,868 $39,451 $40,043 $40,644 non-fuel O&M $9,010 $9,190 $9,374 $9,561 $9,753 $9,948 $10,147 $10,350 $10,557 $10,768 fixed O&M $15,237 $15,542 $15,853 $16,170 $16,493 $16,823 $17,160 $17,503 $17,853 $18,210 total annual production expenses $59,794 $60,812 $61,848 $62,902 $63,974 $65,065 $66,175 $67,304 $68,453 $69,621 electricity production expense, $/MWh $18.20 $18.51 $18.83 $19.15 $19.47 $19.81 $20.14 $20.49 $20.84 $21.19 depreciation (investment -ITC)/20 $40,228 $40,228 $40,228 $40,228 $40,228 $40,228 $40,228 $40,228 $40,228 $40,228 G&A $16,938 $16,938 $16,938 $16,938 $16,938 $16,938 $16,938 $16,938 $16,938 $16,938 total expenses $116,960 $117,978 $119,014 $120,068 $121,140 $122,231 $123,341 $124,470 $125,619 $126,788 Net Income Before Taxes $30,321 $32,249 $34,218 $36,228 $38,282 $40,380 $42,522 $44,710 $46,945 $49,227 taxes $10,309 $10,965 $11,634 $12,318 $13,016 $13,729 $14,458 $15,201 $15,961 $16,737 Net Income after Taxes $20,012 $21,284 $22,584 $23,911 $25,266 $26,651 $28,065 $29,509 $30,984 $32,490 Investment tax credit $42,345 Production tax credit $32,850 $32,850 $32,850 $32,850 $32,850 $26,280 $26,280 $26,280 $26,280 $26,280 cash flow= NI + depreciation ($804,564) $93,090 $94,362 $95,662 $96,989 $98,344 $93,159 $94,573 $96,017 $97,492 $98,998 IRR 9.49% PV Investment ($673,224) PV NI + depreciation @ WACC $675,060 Risk pool appropriation $14,115 $14,115 $14,115 Page A-10 incelec6.xls Attachment A NGCC 500 MW Plant (2012) 4/17/98 capacity 500 MW capital carrying charges 13.50% heat rate 6300 Btu/kWh depreciation Straight Line fuel cost $2.64 /mmBtu initial cost $525 /kW fuel escalation 3.0% % debt financing 75% inflation 2.0% cost of debt 10% non-fuel variable O&M 1 $/MWh cost of equity 18% fixed O&M 9 $/kW-yr weighted ave cost of capital 9% capacity factor 75% G&A 2% generation 3,285,000 MWh tax rate 34% book life 20 years construction expenditure cycle useful life 30 years year 1 30% loan term 20 years year 2 40% T Bill Rate 6.0% year 3 30% Construction Period Investment year 1998 -3 -2 -1 0 1 2 3 4 5 6 7 8 9 10 initial cost $262,500 $97,916 $133,165 $101,872 $399,402 Revenue electricity price, $/MWh $36.16 $47.71 $48.67 $49.64 $50.63 $51.65 $52.68 $53.73 $54.81 $55.90 $57.02 revenue $156,735 $159,870 $163,067 $166,329 $169,655 $173,048 $176,509 $180,039 $183,640 $187,313 Expenses fuel expense $82,642 $85,121 $87,675 $90,305 $93,014 $95,805 $98,679 $101,639 $104,688 $107,829 non-fuel O&M $4,334 $4,421 $4,510 $4,600 $4,692 $4,786 $4,881 $4,979 $5,079 $5,180 fixed O&M $5,938 $6,056 $6,178 $6,301 $6,427 $6,556 $6,687 $6,820 $6,957 $7,096 total annual production expenses $92,914 $95,599 $98,362 $101,206 $104,133 $107,146 $110,247 $113,439 $116,724 $120,105 electricity production expense, $/MWh $28.28 $29.10 $29.94 $30.81 $31.70 $32.62 $33.56 $34.53 $35.53 $36.56 depreciation $19,970 $19,970 $19,970 $19,970 $19,970 $19,970 $19,970 $19,970 $19,970 $19,970 G&A $7,988 $7,988 $7,988 $7,988 $7,988 $7,988 $7,988 $7,988 $7,988 $7,988 total expenses $120,872 $123,557 $126,320 $129,164 $132,091 $135,104 $138,205 $141,397 $144,682 $148,063 Net Income Before Taxes $35,863 $36,313 $36,747 $37,164 $37,564 $37,944 $38,304 $38,642 $38,958 $39,250 taxes $12,193 $12,346 $12,494 $12,636 $12,772 $12,901 $13,023 $13,138 $13,246 $13,345 Net Income after Taxes $23,669 $23,966 $24,253 $24,528 $24,792 $25,043 $25,281 $25,504 $25,712 $25,905 cash flow= NI + depreciation ($399,402) $43,640 $43,937 $44,223 $44,499 $44,762 $45,013 $45,251 $45,474 $45,682 $45,875 IRR 9.45% PV Investment ($308,751) PV NI + depreciation $308,794 Page A-11 incelec6 xis Attachment A Pressurized Fluidized Bed Combustion 500 MW Plant (2012) 4/17/98 capacity 500 MW capital carrying charges 13.50% Investment tax credit 20.0% of Owners equity heat rate 7720 Btu/kWh depreciation Straight Line Production tax credit fuel cost $1.20 /mmBtu initial cost $1,130 /kW 1st 5 years of operation $7.00 per megawatt hour fuel escalation 1.5% % debt financing 75% 2nd five years of operation $4.50 per megawatt hour inflation 2.0% cost of debt 10% Risk Pool 5.0% of capital investment, years 1-3 non-fuel variable O&M 2.5 $/MWh cost of equity 18% fixed O&M 14 $/kW-yr weighted ave cost of capital 9% capacity factor 75% G&A 2% generation 3,285,000 MWh tax rate 34% book life 20 years construction expenditure cycle useful life 30 years year 1 30% loan term 20 years year 2 40% T Bill Rate 6.0% year 3 30% Construction Period Investment year 1998 -3 -2 -1 0 1 2 3 4 5 6 7 8 9 10 initial cost $565,000 $210,752 $286,623 $219,266 $859,665 Revenue electricity price, $/MWh $36.16 $47.71 $48.67 $49.64 $50.63 $51.65 $52.68 $53.73 $54.81 $55.90 $57.02 electricity revenue $156,735 $159,870 $163,067 $166,329 $169,655 $173,048 $176,509 $180,039 $183,640 $187,313 Expenses fuel expense $37,485 $38,047 $38,618 $39,197 $39,785 $40,382 $40,988 $41,603 $42,227 $42,860 non-fuel O&M $10,836 $11,053 $11,274 $11,499 $11,729 $11,964 $12,203 $12,447 $12,696 $12,950 fixed O&M $9,236 $9,421 $9,609 $9,802 $9,998 $10,198 $10,402 $10,610 $10,822 $11,038 total annual production expenses $57,558 $58,521 $59,502 $60,499 $61,513 $62,544 $63,593 $64,660 $65,745 $66,849 electricity production expense, $/MWh $17.52 $17.81 $18.11 $18.42 $18.73 $19.04 $19.36 $19.68 $20.01 $20.35 depreciation (investment -ITC)/20 $40,834 $40,834 $40,834 $40,834 $40,834 $40,834 $40,834 $40,834 $40,834 $40,834 G&A $17,193 $17,193 $17,193 $17,193 $17,193 $17,193 $17,193 $17,193 $17,193 $17,193 total expenses $115,585 $116,549 $117,529 $118,526 $119,540 $120,571 $121,620 $122,687 $123,772 $124,876 Net Income Before Taxes $41,150 $43,321 $45,538 $47,803 $50,115 $52,477 $54,889 $57,352 $59,868 $62,437 taxes $13,991 $14,729 $15,483 $16,253 $17,039 $17,842 $18,662 $19,500 $20,355 $21,229 Net Income after Taxes $27,159 $28,592 $30,055 $31,550 $33,076 $34,635 $36,227 $37,852 $39,513 $41,208 Investment tax credit $42,983 Production tax credit $22,995 $22,995 $22,995 $22,995 $22,995 $14,783 $14,783 $14,783 $14,783 $14,783 cash flow= NI + depreciation ($816,682) $90,988 $92,421 $93,884 $95,379 $96,905 $90,251 $91,843 $93,469 $95,129 $96,825 IRR 9.50% PV Investment ($631,322) PV NI + depreciation @ WACC $633,718 Risk pool appropriation $14,328 $14,328 $14,328 Page A-12 incelec6 xls Attachment A Integrated Gasification Combined Cycle 500MW Plant (2012) 4/17/98 capacity 500 MW capital carrying charges 13.50% Investment tax credit 20.0% of Owners equity heat rate 7380 Btu/kWh depreciation Straight Line Production tax credit fuel cost $1.20 /mmBtu initial cost $1,145 /kW 1st 5 years of operation $8.50 per megawatt hour fuel escalation 1.5% % debt financing 75% 2nd five years of operation $7.00 per megawatt hour inflation 2.0% cost of debt 10% Risk Pool 5.0% of capital investment, years 1-3 non-fuel variable O&M 2.25 $/MWh cost of equity 18% fixed O&M 25 $/kW-yr weighted ave cost of capital 9% capacity factor 75% G&A 2% generation 3,285,000 MWh tax rate 34% book life 20 years construction expenditure cycle useful life 30 years year 1 30% loan term 20 years year 2 40% T Bill Rate 6.0% year 3 30% Construction Period Investment year 1998 -3 -2 -1 0 1 2 3 4 5 6 7 8 9 10 initial cost $572,500 $213,550 $290,427 $222,177 $871,077 Revenue electricity price, $/MWh $36.16 $47.71 $48.67 $49.64 $50.63 $51.65 $52.68 $53.73 $54.81 $55.90 $57.02 electricity revenue $156,735 $159,870 $163,067 $166,329 $169,655 $173,048 $176,509 $180,039 $183,640 $187,313 Expenses fuel expense $35,834 $36,372 $36,917 $37,471 $38,033 $38,604 $39,183 $39,770 $40,367 $40,972 non-fuel O&M $9,753 $9,948 $10,147 $10,350 $10,557 $10,768 $10,983 $11,203 $11,427 $11,655 fixed O&M $16,493 $16,823 $17,160 $17,503 $17,853 $18,210 $18,574 $18,946 $19,325 $19,711 total annual production expenses $62,080 $63,143 $64,224 $65,324 $66,443 $67,581 $68,740 $69,919 $71,118 $72,339 electricity production expense, $/MWh $18.90 $19.22 $19.55 $19.89 $20.23 $20.57 $20.93 $21.28 $21.65 $22.02 depreciation (investment -ITC)/20 $41,376 $41,376 $41,376 $41,376 $41,376 $41,376 $41,376 $41,376 $41,376 $41,376 G&A $17,422 $17,422 $17,422 $17,422 $17,422 $17,422 $17,422 $17,422 $17,422 $17,422 total expenses $120,878 $121,940 $123,021 $124,121 $125,240 $126,379 $127,538 $128,717 $129,916 $131,137 Net Income Before Taxes $35,857 $37,929 $40,046 $42,207 $44,415 $46,669 $48,971 $51,323 $53,724 $56,176 taxes $12,191 $12,896 $13,616 $14,350 $15,101 $15,868 $16,650 $17,450 $18,266 $19,100 Net Income after Taxes $23,666 $25,033 $26,430 $27,857 $29,314 $30,802 $32,321 $33,873 $35,458 $37,076 Investment tax credit $43,554 Production tax credit $27,923 $27,923 $27,923 $27,923 $27,923 $22,995 $22,995 $22,995 $22,995 $22,995 cash flow= NI + depreciation ($827,523) $92,964 $94,332 $95,729 $97,155 $98,612 $95,173 $96,692 $98,244 $99,829 $101,448 IRR 9.47% PV Investment ($639,702) PV NI + depreciation @ WACC $640,427 Risk pool appropriation $14,518 $14,518 $14,518 Page A-13 incelec6.xls Clinton Presidential Records Digital Records Marker This is not a presidential record. This is used as an administrative marker by the William J. Clinton Presidential Library Staff. This marker identifies the place of a tabbed divider. Given our digitization capabilities, we are sometimes unable to adequately scan such dividers. The title from the original document is indicated below. R & D ROAD MAPS Divider Title: Rev 4 11/16/98 Page 32 Attachment B Research and Development Road Maps for Clean Coal Technologies COAL UTILIZATION RESEARCH COUNCIL C:\DATA\WORD\CCT\inc_cct8.doc Performance Targets for Coal Generation Performance Target Today 2010 2020 900 Capital Cost, $/kW -1300 800 800 50 - 60 Efficiency, %HHV 45 40 99 SO2, removal % 97 95 Nox lbs/mmbtu 0.1 - 0.3 0.08 0.05 HAPs (hazardous air pollutants) define goals meet goals meet goals Waste Utilization, % 15 - 30 50 - 75 100 © 1998 Coal Utilization Research Council February 25, 1998 Coal Fired Power Plant Technologies Today 2010 2020 HIPPS LEBS PCF APC PFB APFB Adv. Hybrid IGCC AGCC IGFC Coproduction Coproduction Coproduction Carbon Sequestration Carbon Sequestration Carbon Sequestration © 1998 Coal Utilization Research Council February 25, 1998 Coal Fired Power Plants / Enabling Technologies Today 2010 2020 APCF PCF LEBS Coal Emissions Biomass Prep Control HIPPS USC UUSC PFB APFB HGCU ATS Hybrid IGCC AGCC IGFC Adv. Air Separ. Coproduction Coproduction Coproduction Carbon Sequestration Carbon Sequestration Carbon Sequestration Enabling technologies to build industry core competencies include materials and lifing; sensors and controls; computational fluid dynamics; coal characterization; and coal preparation. © 1998 Coal Utilization Research Council February 25, 1998 Efficiency Goals for Coal Fired Plants Year 2010 Goal Year 2020 Goal LEBS APCF HIPPS APFB AGCC Hybrid (70+) IGFC 40 45 50 55 60 Efficiency, %HHV © 1998 Coal Utilization Research Council February 25, 1998 15-Year Levelized Cost of Electricity for Coal Fired V. Gas Fired Power Technologies 45 2nd Gen Adv Coal 800 + 1,000 $/kWh 7,500 Btu/kWh 15-yr Levelized COE, mills/kWh (constant '97$) 40 3rd Gen Adv Coal 1st Gen Adv Coal 800 $/kW 35 900 - 1,300 $/kW 7,000 Btu/kWh 8,200 - 9,300 Btu/kWh 30 CC "F" 400-500 $/kW 7,000 Btu/kWh CC "H" 25 350-500 $/kW Adv GT Cycles 6,500 Btu/kWh 275 - - 425 $/kW 6,500 Btu/kWh 20 1995 2000 2005 2010 2015 2020 2025 Year of Plant Start-Up February 25, 1998 © 1998 Coal Utilization Research Council 30-Year Levelized Cost of Electricity for Coal Fired VS. Gas Fired Power Technologies 45 1st Gen Adv Coal 900 - 1,300 $/kW 30-yr Levelized COE, mills/kWh (constant '97$) 40 8,200 - 9,300 Btu/kWh 2nd Gen Adv Coal 800 - 1,000 $/kWh 7,500 Btu/kWh 35 Adv GT Cycles 275 - 425 $/kW 6,500 Btu/kWh 30 CC "F" 25 400-500 $/kW CC "H' 7,000 Btu/kWh 350-500 $/kW Adv Coal 6,500 Btu/kWh 800 $/kW 7,000 Btu/kWh 20 1995 2000 2005 2010 2015 2020 2025 Year of Plant Start-Up © 1998 Coal Utilization Research Council February 25, 1998 AGCC Performance Targets Performance Target Today 2010 2020 1200-1300 Capital Cost, $/kW 800 800 57* Efficiency, %HHV 40 45 99 SO2 removal, % 97 99 (cold) (hot) (hot) NOx lbs/mmbtu 0.06 0.06 0.05 HAPs define goals meet goals meet goals 75 100 Waste Utilization, % 30 Equivalent Availability, % 90 90 90 *GCC/PFB Hybrid © 1998 Coal Utilization Research Council February 25, 1998 AGCC Technology Trajectories Technology Need Today 2010 2020 hot -- 1000 °F hot -1500°F Gas Cleanup cold 8,000-20,000 hrs 20,000 hours by 2005 "F" ATS -- 2750 F Combustion Advanced 2350°F plus combustor Turbine development CT cycles Ultrasupercritical Steam Cycle Subcritical Subcritical Steam Air or O2 Air or O2 Oxidant O2 with advanced with advanced air separation air separation hot SO2 removal cold with external hot desulfurization Waste Utilization, % 15 - 30 50 - 75 100 © 1998 Coal Utilization Research Council February 25, 1998 APFBC Performance Targets Performance Target Today 2010 2020 900 Capital Cost, $/kW -1100 800 800 57* Efficiency, % HHV 45 40 99 SO2 removal, % 97 95 0.1 0.08 NOx, lbs/mmbtu 0.05 Equivalent Availability, % 90 90 90 * GCC/PFB Hybrid February 25, 1998 © 1998 Coal Utilization Research Council APFBC Technology Trajectories Technology Need Today 2010 2020 1600° F oxidizing 1700 F oxidizing HTHP Filters Cyclones conditions conditions ATS-- 2750 o F "F"- 2350 O F Advanced Combustion Turbine advanced rugged combustor CT cycles 2400psi/1050°F 3500psi/1050 °F 5000psi/1300 F Steam Cycle single reheat single reheat double reheat flue gas flue gas Sulfur removal dolomite polishing polishing define goals HAPs meet goals meet goals (trace) Waste Utilization, % 15 - 30 50 - 75 100 © 1998 Coal Utilization Research Council February 25, 1998 IGFC Performance Targets Performance Target Today 2010 2020 Capital Cost, $/kW n/a n/a 800+ Efficiency, %HHV n/a n/a 70+ SO2 removal, % n/a n/a 99+ NOx, Ibs/mmbtu n/a n/a < 0.05 HAPs n/a n/a meet goals Waste Utilization, % n/a n/a 100 Equivalent Availability % n/a n/a 90 © 1998 Coal Utilization Research Council February 25, 1998 IGFC Technology Trajectories Technology Need Today 2010 2020 natural gas coal gas large coal gas Fuel Utilization fuel cells fuel cells fuel cells 250kw to 1MW 2 to 50MW 200-400MW Plant Scale-Up demos demos commercial plants as required to see GCC see GCC Hot Gas Clean-Up maintain fuel cell life as required to SO2 removal see GCC see GCC maintain fuel cell life CT/Fuel Cell Integration n/a integration of gasifier Integration hot-gas clean-up, and fuel cell February 25, 1998 © 1998 Coal Utilization Research Council HIPPS Performance Targets Performance Target Today 2010 2020 Capital Cost, $/kW n/a 800 800 Efficiency, %HHV n/a 47 55 SO2 removal, % n/a 99 99 NOx, lbs/mmbtu n/a 0.06 0.05 HAPs n/a meet goals meet goals Waste Utilization, % n/a some 100 Equivalent Availability, % n/a 90 90 © 1998 Coal Utilization Research Council February 25, 1998 HIPPS Technology Trajectories Technology Need Today 2010 2020 High Temperature / n/a 1100°F 1800°F High Pressure Filter reducing reducing Heat Exchanger n/a 1800°F 2750°F (Alloy) (ceramic) 4000psi/ 5000psi/ Steam Cycle n/a 1200°F 1300°F double reheat double reheat cycle design, cycle design, Steam Turbine n/a aerodynamics, aerodynamics, materials materials Gas Turbine n/a Humid air turbine Humid air turbine 2750° Particulate n/a to be defined to be defined © 1998 Coal Utilization Research Council February 25, 1998 Advanced PC Performance Targets Performance Target Today 2010 2020 1100 Capital Cost, $/kW 800 800 47-51 Efficiency, % HHV 45 41 SO2 removal, % 98 97 99 NOx, lbs/mmbtu 0.1 0.08 0.05 HAPs define goals mercury control meet goals Waste Utilization, % 15 - 30 50 - 75 100 Equivalent Availability, % 90 90 90 © 1998 Coal Utilization Research Council February 25, 1998 Advanced PC Technology Trajectories Technology Need Today 2010 2020 3500 psi/1050°F Steam 4000 psi/1200 F 5000 psi/1300 °F Double reheat Double reheat Double reheat Cycle Conditions Boiler and Steam ferritics, ferritics, austenitics, new Ni-based Cycle Materials austenitics Ni-based alloys alloys plant cycle new aerodynamics, Steam Turbine n/a integration, cycle integration, materials materials integrated with integrated with SO2 removal n/a HAPS & particulate HAPS & particulate control control NOx control burners, Adv. burners, Adv. burners, SCR SCR SCR © 1998 Coal Utilization Research Council February 25, 1998 Crosscutting Enabling Technology Technology 2010 2020 High Temperature/ High Pressure Filters AGCC 1000°F reducing 1500°F reducing APFB 1600°F reducing 1700°F reducing HIPPS 1100°F reducing 1500°F reducing IGFC n/a 1000 °F reducing Combustion Turbine AGCC 2750°F - ATS Advanced Cycle APFB 2750°F --- ATS Advanced Cycle HIPPS n/a 2750°F Steam Cycle Materials APFB n/a New Alloys, 1300°F APC Ferritics, new alloys New Alloys, 1300°F HIPPS n/a New Alloys, 1300°F HAPS Address issues as characterized by Address 2000 for all technologies 1998 Coal Utilization Research Council February 25, 1998 Crosscutting Enabling Technology Technology 2010 2020 Hot Sulfur Cleanup AGCC External Hot Desulfurization External Hot Desulfurization APFB n/a Polishing IGFC n/a External Hot Desulfurization Polishing NOx Removal AGCC n/a n/a APFB n/a n/a IGFC n/a n/a HIPPS Advanced Cost Efficient NOx Advanced Cost Efficient NOx Removal Removal Air Seperation AGCC Advanced Air Seperation Advanced Air Seperation APFB Advanced Air Seperation Advanced Air Seperation IGFC Advanced Air Seperation Advanced Air Seperation HIPPS n/a n/a © 1998 Coal Utilization Research Council February 25, 1998 Assumptions Used to Determine COE in Comparison Charts Region SE SE SE SE SE SE SE SE Technology Adv PFBC Adv IGCC IGCC "F" IGCC "H" IGCHAT CC "F" CC "H" Adv CHAT Plant Size, MVV 680 460 570 450 450 225 400 400 Capacity Factor, % 85 85 85 85 85 85 85 85 Fuel Coal Coal Coal Coal Coal Gas Gas Gas Fuel Cost in yr 2000, $MMBtu 1.29 1.29 1.29 1.29 1.29 2.24 2.24 2.24 Fuel Real Esc. Rate, %/yr -0.07 -0.07 -0.07 -0.07 -0.07 1 1 1 Total Plant Cost, $/kW 800 800 1310 1150 810 400 350 270 Fixed O&M, $/kW-yr 26.9 35.4 43.8 38.4 35.4 13.3 10.3 10.3 Var. O&M, mills/kWh 2 1.5 1.3 1.3 1.5 3.1 2.2 2.2 Heat Rate, Btu/kWh HHV 7240 7000 8200 7500 7000 7000 6500 6500 Note: Total Plant Costs are typical values. They vary depending on plant size and design, plant location, etc. Fuel Costs are based on EIA's 1997 AEO Projections (National Average) 4 1998 Coal Utilization Research Council February 25, 1998 Fuel Price Projections Based on AEO '97 3.5 Natural Gas (real escalation rate = 1.0%/yr) 3 Fuel Price, $/MMBtu (1997$) 2.5 2 1.5 1 Coal (real escalation rate = 0.7%/yr) 0.5 0 1995 2000 2005 2010 2015 2020 2025 2030 2035 2040 Year Natural Gas Coal © 1998 Coal Utilization Research Council February 25, 1998 Glossary of Acronyms ATS Advanced (gas) turbine system AGCC Advanced gasification combined cycle APCF Advanced pulverized Coal fired plant APFB Advanced pressurized fluid bed CC Combined cycle HAPs Hazardous air pollutants HIPPS High performance power system HGCU Hot gas cleanup HHV Higher heating value IGCC Integrated gasification combined cycle IGFC Integrated gasification fuel cell LEBS Low emission boiler system PCF Pulverized coal fired plant PFB Pressurized fluid bed USC Ultra supercritical UUSC Ultra, ultra supercritical 1998 Coal Utilization Research Council February 25, 1998

nara / coll_wjc-tfcc / doc

Clean Coal [1]

ID: 158698252
Type: document

Citation Image

Metadata

id	158698252
sourceUrl	https://catalog.archives.gov/id/158698252
contentType	document
collections	Records of the White House Task Force on Climate Change General Files
iiifBase	https://s3.amazonaws.com/NARAprodstorage/lz/presidential-libraries/clinton/foia/2017/2017-1094-F/42-t-146925349-20171094F-003-014-2019.pdf
thumbnailUrl	https://s3.amazonaws.com/NARAprodstorage/lz/presidential-libraries/clinton/foia/2017/2017-1094-F/42-t-146925349-20171094F-003-014-2019.pdf
largeImageUrl	https://s3.amazonaws.com/NARAprodstorage/lz/presidential-libraries/clinton/foia/2017/2017-1094-F/42-t-146925349-20171094F-003-014-2019.pdf
imageCount	1
hasImages	yes
source	import

Additional Source Fields

url	https://catalog.archives.gov/id/158698252
naId	158698252
levelOfDescription	fileUnit
otherTitles	42-t-146925349-20171094F-003-014-2019
recordType	description
ocrSource	nara-archive

Pages

Page 1 OCR

Survos folio item chat

Ask the Scholar

Scholar Source Context