Assessment of High Temperature Gas-Cooled Reactor (HTGR) Capital and Operating Costs

Transcription

1 Document ID: TEV-96 Revision ID: 0/09/202 Technical Evaluation Study Project No Assessment of High Temperature Gas-Cooled Reactor (HTGR) Capital and Operating Costs

2 0/09/202

3 TEV-96 0/09/202 Page: 2 of 45 REVISION LOG Rev. Date Affected Pages Revision Description 0 04/29/20 All Newly issued document. 0/09/202 4, 38, 39 Fixed a small error in the calculation of NEI costs.

4 TEV-96 0/09/202 Page: 3 of 45 EXECUTIVE SUMMARY This technical evaluation (TEV) has been prepared as part of a study for the Next Generation Nuclear Plant (NGNP) Project to address estimating the capital, operating, and decommissioning costs of a high-temperature gas-cooled reactor (HTGR). These results are preliminary and should be refined as the design of the HTGR progresses, if the design of the HTGR is changed significantly, or if additional refinements of the costs become available. The results of this evaluation will be used to update the HTGR capital and operating costs used in previous and future TEVs and economic models developed for the NGNP process heat applications study. The capital, operating, and decommissioning costs are based on the HTGR design presented in the NGNP Pre-Conceptual Design Report (INL 2007a). Capital costs include the preconstruction costs, direct costs, indirect costs, and project contingency. Operating costs include operating and maintenance (O&M) costs and fuel costs. In addition to estimating the capital, operating, and decommissioning costs for a reactor outlet temperature (ROT) of 950C, costs for ROTs of 750C, 800C, 850C, and 900C were also evaluated. HTGR costs were also developed with and without power cycles; the power cycles evaluated included both Brayton and Rankine cycles. Finally, the estimates were generated for single and four-pack reactor configurations for both 350 MWt and 600 MWt power levels, for the NGNP (demonstration), first of a kind, and nth of a kind (NOAK) project phases. Table ES- presents the projected capital, operating, and decommissioning costs of an HTGR with a Rankine cycle for the NGNP and NOAK project phases at a ROT of 850 C. The results include costs for the 350 MWt and 600 MWt power levels for single and four-pack rector configurations (the NGNP phase includes only a single reactor option). The O&M costs presented are based on staffing estimates from the reactor design suppliers; currently there are differences in the projected staffing between designers and the INL estimate, in part because required staffing levels have not yet been established. The capital costs are graphically presented in Figure ES- and on a dollar-per-kwt basis in Figure ES-2. The cost model is capable of adjusting capital, operating, and decommissioning costs based on the desired reactor configuration to provide input to multiple process modeling scenarios. The level of project definition for this study was determined to be an AACE International Class 4 estimate, which has a probable error of -30% and +50%.

5 TEV-96 0/09/202 Page: 4 of 45 Table ES-. Cost Summary for NGNP & NOAK HTGR with a Rankine power cycle, 850 C ROT (2009 basis). Reactor Phase NGNP NOAK Reactor Size 600 MWt 350 MWt 600 MWt 350 MWt Number of Modules 4 4 Capital Costs ($0 6 ) Preconstruction Costs Direct Costs Indirect Costs Contingency Overnight Cost ($0 6 ) Lower Bound Upper Bound Overnight Cost ($/kwt) Lower Bound Upper Bound Yearly O&M Costs ($0 6 ) Yearly O&M Costs ($/MWt-hr) Yearly Fuel Costs ($0 6 ) Yearly Fuel Costs ($/MWt-hr) Decommissioning Costs ($0 6 ) Figure ES-. Capital Cost Summary for NGNP and NOAK HTGR with a Rankine power cycle, 850 C ROT ($ basis).

6 TEV-96 0/09/202 Page: 5 of 45 Figure ES-2. Capital Cost Summary for NGNP and NOAK HTGR with a Rankine power cycle, 850 C ROT ($/kwt 2009 basis).

7 TEV-96 0/09/202 Page: 6 of 45 CONTENTS EXECUTIVE SUMMARY...3 ACRONYMS AND NOMENCLATURE...7. INTRODUCTION CAPITAL COST MODELING OVERVIEW Preconstruction Costs Direct Costs Indirect Costs Project Contingency Total Capital Investment Correlation Development for Direct Capital Costs Correlations for the HTGR Cost, Less Power Cycle Correlations for the Brayton Cycle Cost Correlations for the Rankine Cycle Cost Capital Cost Results Comparisons ESTIMATION OF O&M Costs Fuel Costs DECOMMISSIONING COSTS FUTURE WORK AND RECOMMENDATIONS REFERENCES APPENDIXES...44 Appendix A... A-45

8 TEV-96 0/09/202 Page: 7 of 45 ACRONYMS AND NOMENCLATURE AACE BLS BOE BWR CEPCI COLA DOE DP ESP FCL FOAK GA GIF HP HTGR I&C IHX INL INPO ISI LLW LWR NDE NEI NGNP NOAK NRC O&M PWR R&D Association for the Advancement of Cost Engineering Bureau of Labor Statistics balance of equipment boiling water reactor chemical engineering plant cost index combined operating license application Department of Energy duplicate position early site permit fuel cycle length first of a kind General Atomics GEN-IV International Forum health physics high temperature gas-cooled reactor instrumentation and control intermediate heat exchanger Idaho National Laboratory Institute of Nuclear Power Operations in-service inspection low level waste light water reactor non-destructive exams Nuclear Energy Institute Next Generation Nuclear Plant nth of a kind Nuclear Regulatory Commission operations and maintenance pressurized water reactor research & development

9 TEV-96 0/09/202 Page: 8 of 45 RO ROT SC SCM STA SWU TCI TEV reactor operator reactor outlet temperature subcontract supply chain management shift technical advisors separative work unit total capital investment technical evaluation

10 TEV-96 0/09/202 Page: 9 of 45. INTRODUCTION This technical evaluation (TEV) has been prepared as part of a study for the Next Generation Nuclear Plant (NGNP) Project to address estimating the capital, operating, and decommissioning costs of a high-temperature gas-cooled reactor (HTGR). The NGNP Project is being conducted under U.S. Department of Energy (DOE) direction to meet a national strategic need identified in the 2005 Energy Policy Act to promote reliance on safe, clean, economic nuclear energy and to establish a greenhouse-gas-free technology for the production of hydrogen. The NGNP represents an integration of high-temperature reactor technology with advanced hydrogen, electricity, and process heat production capabilities, thereby meeting the mission need identified by DOE. The strategic goal of the NGNP Project is to broaden the environmental and economic benefits of nuclear energy in the U.S. economy by demonstrating its applicability to market sectors not being served by light water reactors. The HTGR produces high-temperature helium that can be used to produce electricity and/or process heat for export in the form of steam or high-temperature helium. This TEV presents the methodology and results of a cost model which was developed to estimate the capital, operating, and decommissioning costs of an HTGR. These costs are based, in general, on the HTGR design presented in the NGNP Pre-Conceptual Design Report (INL 2007a). Although initial HTGR implementations may target a reactor outlet temperature (ROT) of approximately 750 C, temperatures of up to 950 C are anticipated for later designs. Therefore, the cost model was developed to be capable of estimating costs for the ROT range of 750 C to 950 C, in 50 C increments. HTGR costs were also developed with and without power cycles; the power cycles evaluated included both Brayton and Rankine cycles. Correlations are developed for the power cycles, such that combined heat and power facility costs can be evaluated. Finally, the estimates were generated for single and four-pack reactor configurations for both 350 MWt and 600 MWt power levels, for the NGNP, first of a kind (FOAK), and nth of a kind (NOAK) project phases. A four-pack reactor plant includes four reactor vessels with shared control facilities. The NGNP plant is the initial demonstration of the current HTGR design funded through a public-private-partnership cost-share, a FOAK plant is the first privately funded commercial installation of the HTGR technology, while the NOAK plant is a mature privately funded commercial installation of the HTGR technology. The intended application of the cost model is to develop capital and operating costs for a wide variety of HTGR deployment options, such that the economic impact of HTGR integration into electricity, heat, and/or commercial chemical production can be assessed for business development, project screening, and economic feasibility. As the HTGR is still in the early stages of project development, the cost model has an expected accuracy of -30% to +50%. This TEV assumes familiarity with the NGNP Pre-Conceptual Design Report; hence, detailed descriptions of the HTGR design are not presented here. The cost model used for this analysis has been developed in Microsoft Excel (Excel 2007). This study makes

11 TEV-96 0/09/202 Page: 0 of 45 extensive use of this model; this TEV assumes familiarity with Excel. A detailed explanation of the software capabilities is beyond the scope of this study. This TEV first presents the approach for generating the HTGR capital costs as a function of the reactor parameters described above. Next the approach for generating the operating costs is presented, followed by the approach for estimating decommissioning costs. Finally, results of the cost models are presented and discussed. These results are preliminary and should be refined as the design of the HTGR progresses, if the design of the HTGR is changed significantly, or if additional refinements of the costs become available. The results of this evaluation will be used to update the HTGR capital and operating costs used in previous and future TEVs and economic models developed for the NGNP process heat applications study. 2. CAPITAL COST MODELING OVERVIEW The capital costs for the HTGR were assessed using a top-down evaluation; including factored cost estimates for major equipment items and ratio factors based on industry experience and/or program guidance for balance of equipment costs, indirect costs, and project contingency. The costs were evaluated in detail for the following cases : Project phases: NGNP FOAK NOAK ROTs of 750C to 950C, in 50C increments Single and four-pack reactor modules, NGNP phase includes a single reactor only Power levels: 350 MWt 600 MWt Power cycle configurations: No power cycle, i.e. heat only Brayton cycle Rankine cycle The detailed cost assessments were used to develop correlations that can be used to estimate the costs for other operating conditions and configurations, e.g., more than four modules in a plant and ROTs other than 750 C to 950 C, in 50 C increments.

12 TEV-96 0/09/202 Page: of 45 The total capital investment (TCI), based on preconstruction, direct, and indirect costs are included in the capital cost estimate for the HTGR. The Association for the Advancement of Cost Engineering (AACE) International recognizes five classes of estimates. The level of project definition for this study was determined to be an AACE International Class 4 estimate, which has a probable error of -30% and +50%. A Class 4 estimate is associated with a feasibility study or top-down cost estimate and has one to fifteen percent of full project definition (AACE 2005). 2. Preconstruction Costs Preconstruction costs include the followings costs: Land and land rights Licensing and application Costs for land and land rights were based on the acreage required for a single reactor or for a four-pack of reactors. It was assumed that a single HTGR requires 50 acres of land, while a four-pack requires 00 acres. This data was approximated based on information provided by General Atomics (GA). A rule of thumb cost of $00,000 per acre was assumed (Wallace 20). Licensing and application costs were developed based on input from NGNP regulatory affairs for the various reactor phases; the costs are presented in Table. Licensing cost development associated with the single module NGNP HTGR are as described in the NGNP Program Planning Bases for the Schedule and Cost Estimates (INL 200). Table. Licensing cost summary ($ basis). Reactor Phase NGNP FOAK NOAK Task Number of Modules 4 4 Pre-Application ESP 2 and COLA 3 Preparation ESP and COLA Review by NRC Support of Construction & Initial Operation State and Local Permitting Total Early site permit (ESP). 3 Combine operating license application (COLA).

13 TEV-96 0/09/202 Page: 2 of 45 Design certification costs are included in the licensing costs for the NGNP plant. It is assumed that design certification costs would only be incurred for the initial plant and would cover all downstream builds. Costs for land and land rights and licensing and application are summed to determine the total preconstruction costs, summarized in Table 2. Table 2. Total preconstruction cost summary ($ basis). Reactor Phase NGNP FOAK NOAK Task Number of Modules 4 4 Land and Land Rights Licensing and Application Costs Total Direct Costs Direct costs for the reactor plant are associated with the cost of materials and installation for the equipment items that make up the reactor plant. Given the nascent stage of the HTGR design, previous reactor cost estimates provided by the reactor design suppliers were assessed to determine the reactor plant equipment items that make up the majority of the direct costs. Based on this analysis, the following equipment items make up approximately 80% of the installed equipment costs: Reactor building Reactor vessel Reactor initial core Reactor metallic internals Reactor graphite internals Reactor cavity cooling system Core refueling equipment Heat rejection system Intermediate heat exchanger (IHX) Power generation equipment Rankine cycle Brayton cycle, includes power conversion vessel The direct costs of the above items were estimated by Dominion for the INL through a separate subcontract. Costs were estimated for the prismatic block

14 TEV-96 0/09/202 Page: 3 of 45 reactor, the pebble bed reactor costs will be included in the future revisions of the TEV. Dominion estimated the direct component costs based on information provided in the GA Pre-Conceptual Design Report (GA 2007) and cost data in the public domain for the GA gas turbine-modular helium reactor. For each ROT (750 C to 950 C, in 50 C increments), the most probable material is selected for each component, choosing from SA-508, 2¼Cr-Mo, and Incoloy 800H, based on the expected component temperature, taking into account allowances for creep-fatigue and corrosion. Certain components, such as the Rankine power cycle, did not include options for material selection as the increase in ROT would have no impact on the material choice. The resulting component costs were adjusted based on the cost ratios for the raw materials as well as a ratio for ease of component fabrication, which is applied to the labor portion of the cost for the component for each material option. The breakdown between material, forming and fabrication, final fabrication, transportation, etc. is based on Dominion s extensive experience with LWR capital costs. Exponential scaling factors, based on LWR and other industrial experience, are used to adjust the capital costs for changes in the component sizes associated with slight capacity adjustments for changes in ROT and the overall thermal and/or power rating. A scaling factor was also used to adjust the costs from single to multiple module units, based on industrial LWR experience. Finally, factors were included to adjust the costs for the NGNP and FOAK project phases, based on data provided by the GEN-IV International Forum (GIF) (2007). Appendix A presents more detailed information on the methodology and approach Dominion used to estimate the direct costs for the specified reactor equipment items. Cost indices were used to adjust equipment prices provided in the Dominion assessment from 2007 dollars to 2009 dollars using the Chemical Engineering Plant Cost Index (CEPCI) shown in Table 3. Table 3. CEPCI data. Year CEPCI To account for the balance of equipment (BOE) costs not included in the Dominion direct cost estimate, the total cost of the items above were multiplied by a factor of.25. This factor was based upon the assessment of the previous cost estimates provided by the reactor design suppliers, in which the remaining equipment items contribute 20% of the installed equipment costs, as described previously.

15 TEV-96 0/09/202 Page: 4 of 45 The costs provided by Dominion, the associated balance of equipment costs, and the resulting total direct costs are summarized in Table 4 for the NGNP plant at all ROTs and power levels, Table 5 for a single and four-pack FOAK plant at all ROTs and power levels, and Table 6 for a single and four-pack NOAK plant at all ROTs and power levels. Table 4. Direct costs NGNP HTGR ($ basis). Power Modules Level Equipment Item ROT Reactor Building Reactor Vessel Reactor Initial Core Reactor Metallic Internals Reactor Graphite Internals Reactor Cavity Cooling System Core Refueling Equipment Heat Rejection System IHX Brayton Power Conversion Vessel Power Generation Brayton Cycle Power Generation Rankine Cycle BOE No Power Cycle BOE Brayton Power Cycle BOE Rankine Power Cycle Total No Power Cycle Total Brayton Power Cycle Total Rankine Power Cycle Reactor Building Reactor Vessel Reactor Initial Core Reactor Metallic Internals Reactor Graphite Internals Reactor Cavity Cooling System Core Refueling Equipment Heat Rejection System IHX Brayton Power Conversion Vessel Power Generation Brayton Cycle Power Generation Rankine Cycle BOE No Power Cycle BOE Brayton Power Cycle BOE Rankine Power Cycle Total No Power Cycle Total Brayton Power Cycle Total Rankine Power Cycle MWt 350 MWt

16 TEV-96 0/09/202 Page: 5 of 45 Table 5. Direct costs FOAK HTGR ($ basis). Power Modules 4 Level Equipment Item ROT Reactor Building Reactor Vessel Reactor Initial Core Reactor Metallic Internals Reactor Graphite Internals Reactor Cavity Cooling System Core Refueling Equipment Heat Rejection System IHX Brayton Power Conversion Vessel Power Generation Brayton Cycle Power Generation Rankine Cycle BOE No Power Cycle BOE Brayton Power Cycle BOE Rankine Power Cycle Total No Power Cycle Total Brayton Power Cycle Total Rankine Power Cycle MWt 350 MWt Reactor Building Reactor Vessel Reactor Initial Core Reactor Metallic Internals Reactor Graphite Internals Reactor Cavity Cooling System Core Refueling Equipment Heat Rejection System IHX Brayton Power Conversion Vessel Power Generation Brayton Cycle Power Generation Rankine Cycle BOE No Power Cycle BOE Brayton Power Cycle BOE Rankine Power Cycle Total No Power Cycle Total Brayton Power Cycle Total Rankine Power Cycle

17 TEV-96 0/09/202 Page: 6 of 45 Table 6. Direct costs NOAK HTGR ($ basis). Power Modules 4 Level Equipment Item ROT Reactor Building Reactor Vessel Reactor Initial Core Reactor Metallic Internals Reactor Graphite Internals Reactor Cavity Cooling System Core Refueling Equipment Heat Rejection System IHX Brayton Power Conversion Vessel Power Generation Brayton Cycle Power Generation Rankine Cycle BOE No Power Cycle BOE Brayton Power Cycle BOE Rankine Power Cycle Total No Power Cycle Total Brayton Power Cycle Total Rankine Power Cycle MWt 350 MWt Reactor Building Reactor Vessel Reactor Initial Core Reactor Metallic Internals Reactor Graphite Internals Reactor Cavity Cooling System Core Refueling Equipment Heat Rejection System IHX Brayton Power Conversion Vessel Power Generation Brayton Cycle Power Generation Rankine Cycle BOE No Power Cycle BOE Brayton Power Cycle BOE Rankine Power Cycle Total No Power Cycle Total Brayton Power Cycle Total Rankine Power Cycle

18 TEV-96 0/09/202 Page: 7 of Indirect Costs The capital required for construction overhead and other costs not included in the direct costs are included in the indirect costs. Again, given the nascent stage of the HTGR design, it was necessary to estimate the indirect costs as a percentage of the direct costs based on previous reactor design supplier estimates and historical indirect costs for light water reactors (LWRs). Indirect costs included in the analysis are: Construction services including but not limited to costs for construction management, procurement, scheduling, cost control, site safety, and quality inspections Home office and engineering services - including but not limited to costs for estimating, scheduling, project expediting, project general management, design allowance, and project fees Field office and engineering services including but not limited to costs for the field office, field engineering, field drafting, field procurement, and field administrative and general expenses Owner s costs including but not limited to project fees, taxes, and insurance; spare parts and other capital expenses; staff training and startup costs; and administrative and general expenses Design costs Table 7 provides a list of HTGR (based on information provided by the reactor design suppliers) and historical LWR values for indirect costs. These values were averaged to determine the appropriate factors to use in the HTGR capital cost assessment for the indirect costs. These percentages were used for the NGNP plant, FOAK plant, and the NOAK plant. Table 7. Indirect cost summary (% of total direct cost). Const. Services Home Office & Eng. Field Office & Eng. Reference Services Services Owner s Costs Total GA 907 (GA 2007) % 4.7% 0.4% 8.8% 44.2% DOE/NE-0009 (DOE 980) 5 6% 9% 6% 0% 5% DOE/NE-0095 (DOE 988) 6 24% 25% 3% 6% 77% Average 20% 6% 0% 2% 57% 4 Based on data from cost estimate from GA for the NGNP Pre-Conceptual Design Report 5 Based on historical LWR costs up to Based on historical LWR costs including reactors constructed after Three Mile Island

19 TEV-96 0/09/202 Page: 8 of 45 Table 8 provides additional estimates for the total indirect cost as percentage of the direct costs. The values were not used in the average for this estimate as the breakdown for the indirect costs did not match the level of detail desired for this analysis. However, these references provide validation for the calculated average indirect cost. Table 8. Total indirect cost validation. Total % WSRC-MS (DOE 2006) 55% IAEA Bulletin Vol. 20, No. (IAEA 978) 52% The following design costs were also added to the indirect costs outlined above: Table 9. Design costs ($ basis). Item Phase NGNP FOAK & NOAK Conceptual Design Preliminary Design Final Design R&D Costs Total, The NGNP design costs are referenced from the design costs presented in the NGNP Program Planning Bases for the Schedule and Cost Estimates (INL 200). Final design costs for the FOAK and NOAK plants are based on information provided by reactor design suppliers and have been adjusted for recent project development and assumed design maturation. 2.4 Project Contingency A project contingency of 20% was selected for the HTGR capital cost analysis for all project phases (INL 2007a). 2.5 Total Capital Investment The TCI was calculated by summing the preconstruction costs, direct costs, indirect costs, and project contingency described in the previous sections. These costs are outlined in Table 0 for the NGNP plant at all ROTs and power levels, Table for the FOAK single and four-pack plants at all ROTs and power levels, and Table 2 for the NOAK single and four-pack plants at all ROTs and power levels. In addition to the TCI the costs on a dollar-per-kwt basis are also presented. 7 Research and development (R&D), includes INL s R&D costs.

20 TEV-96 0/09/202 Page: 9 of 45 Table 0. TCI NGNP HTGR ($ basis). Power Modules Level Item ROT Preconstruction Costs Direct Costs No Power Cycle Direct Costs Brayton Cycle Direct Costs Rankine Cycle Indirect Costs No Power Cycle Indirect Costs Brayton Cycle Indirect Costs Rankine Cycle Contingency No Power Cycle Contingency Brayton Cycle Contingency Rankine Cycle TCI No Power Cycle $/kwt TCI Brayton Power Cycle $/kwt TCI Rankine Power Cycle $/kwt MWt 350 MWt Preconstruction Costs Direct Costs No Power Cycle Direct Costs Brayton Cycle Direct Costs Rankine Cycle Indirect Costs No Power Cycle Indirect Costs Brayton Cycle Indirect Costs Rankine Cycle Contingency No Power Cycle Contingency Brayton Cycle Contingency Rankine Cycle TCI No Power Cycle $/kwt TCI Brayton Power Cycle $/kwt TCI Rankine Power Cycle $/kwt

21 TEV-96 0/09/202 Page: 20 of 45 Table. TCI FOAK HTGR ($ basis). Power Modules 4 Level Item ROT Preconstruction Costs Direct Costs No Power Cycle Direct Costs Brayton Cycle Direct Costs Rankine Cycle Indirect Costs No Power Cycle Indirect Costs Brayton Cycle Indirect Costs Rankine Cycle Contingency No Power Cycle Contingency Brayton Cycle Contingency Rankine Cycle TCI No Power Cycle $/kwt TCI Brayton Power Cycle $/kwt TCI Rankine Power Cycle $/kwt MWt 350 MWt Preconstruction Costs Direct Costs No Power Cycle Direct Costs Brayton Cycle Direct Costs Rankine Cycle Indirect Costs No Power Cycle Indirect Costs Brayton Cycle Indirect Costs Rankine Cycle Contingency No Power Cycle Contingency Brayton Cycle Contingency Rankine Cycle TCI No Power Cycle $/kwt TCI Brayton Power Cycle $/kwt TCI Rankine Power Cycle $/kwt

22 TEV-96 0/09/202 Page: 2 of 45 Table 2. TCI NOAK HTGR ($ basis). Power Modules 4 Level Item ROT Preconstruction Costs Direct Costs No Power Cycle Direct Costs Brayton Cycle Direct Costs Rankine Cycle Indirect Costs No Power Cycle Indirect Costs Brayton Cycle Indirect Costs Rankine Cycle Contingency No Power Cycle Contingency Brayton Cycle Contingency Rankine Cycle TCI No Power Cycle $/kwt TCI Brayton Power Cycle $/kwt TCI Rankine Power Cycle $/kwt MWt 350 MWt Preconstruction Costs Direct Costs No Power Cycle Direct Costs Brayton Cycle Direct Costs Rankine Cycle Indirect Costs No Power Cycle Indirect Costs Brayton Cycle Indirect Costs Rankine Cycle Contingency No Power Cycle Contingency Brayton Cycle Contingency Rankine Cycle TCI No Power Cycle $/kwt TCI Brayton Power Cycle $/kwt TCI Rankine Power Cycle $/kwt

23 TEV-96 0/09/202 Page: 22 of Correlation Development for Direct Capital Costs Correlations were developed for the HTGR and power cycle costs based on the ROT, thermal rating, power cycle rating, number of modules, and project phase. These correlations were developed in order to scale the costs for project variations not included in this study. For example, these correlations would be used to estimate the cost of six HTGR modules at an ROT of 775C for an NOAK HTGR plant. Separate correlations are developed for the HTGR cost without power cycles (i.e. for heat production only), the Brayton cycle cost, and the Rankine cycle cost. The correlations presented are base direct costs, less the adders, which can be added to the correlations to account for the balance of equipment costs, indirect costs, preconstruction costs, and project contingency Correlations for the HTGR Cost, Less Power Cycle The correlation for the HTGR cost as a function of ROT is best fit using a linear step function. The following equation set is used: The above correlation provides the base cost for an NOAK single 600 MWt HTGR as a function of the ROT. This base cost is then adjusted to account for the number of reactors using an exponential correlation:. A similar adjustment can be made for the reactor thermal rating: 600. Thus, the overall correlation for the NOAK HTGR cost is as follows:. 600 Finally, multipliers for the project phases were determined to adjust the cost for FOAK and NGNP project phases:

24 TEV-96 0/09/202 Page: 23 of 45 Table 3 presents a comparison of the correlation results and the data for the HTGR costs less the power cycles. The costs predicted by the correlations have a percent error of 0% to 4.3%, when compared to the actual cost data. Table 3. Correlation results and comparison for HTGR costs, less power cycles ($ basis). Power Project Modules 4 Level Phase Item ROT Value NOAK Model Prediction % Error Value FOAK Model Prediction % Error Value NGNP Model Prediction % Error Value NOAK Model Prediction % Error Value FOAK Model Prediction % Error Value NGNP Model Prediction % Error MWt 350 MWt

25 TEV-96 0/09/202 Page: 24 of 45 Figure presents the HTGR cost correlations for the NOAK project phase. Figure. NOAK HTGR cost correlations, less power cycles Correlations for the Brayton Cycle Cost The correlation for the Brayton cycle cost as a function of ROT is best fit using a linear step function. The following equation set is used: The above correlation provides the base cost for an NOAK single 28 MWe Brayton cycle, which includes both the power conversion vessel and the turbo-machinery. This base cost is then adjusted to account for the number of cycles using an exponential correlation:. A similar adjustment can be made for the power cycle size. Note that the base power cycle size at 750 C for a 600 MWt HTGR is used for this correlation: 28.

26 TEV-96 0/09/202 Page: 25 of 45 Thus, the overall correlation for the NOAK Brayton cycle cost is as follows:. 28. Finally, multipliers for the project phases were determined to adjust the cost for FOAK and NGNP project phases: Table 4 presents a comparison of the correlation results and the data for the Brayton cycle costs. The costs predicted by the correlations have a percent error of 0% to 7.5%, when compared to the actual cost data. Figure 2 presents the Brayton cycle cost correlation for the NOAK project phase. Figure 2. NOAK Brayton cycle cost correlations.

27 TEV-96 0/09/202 Page: 26 of 45 Table 4. Correlation results and comparison for Brayton cycle costs ($ basis). Power Project Modules 4 Level Phase Item ROT Value NOAK Model Prediction % Error MWt (28 MWe at 750 C) 350 MWt (64 MWe at 750 C) FOAK NGNP NOAK FOAK NGNP Value Model Prediction % Error Value Model Prediction % Error Value Model Prediction % Error Value Model Prediction % Error Value Model Prediction % Error

28 TEV-96 0/09/202 Page: 27 of Correlations for the Rankine Cycle Cost The correlation for the Rankine cycle cost as a function of ROT is best fit using a linear function; however, a step function is not required for the Rankine cycle cost as the fabrication materials are consistent for all ROTs. The following equation is used: The correlation for the ROT provides the base cost for an NOAK single 267 MWe Rankine cycle. This base cost is then adjusted to account for the number of cycles using an exponential correlation: A similar adjustment can be made for the power cycle size. Note that the base power cycle size at 750 C for a 600 MWt HTGR is used for this correlation:. 267 Thus, the overall correlation for the NOAK Rankine cycle cost is as follows:. 267 Finally, multipliers for the project phases were determined to adjust the cost for FOAK and NGNP project phases: Table 5 presents a comparison of the correlation results and the data for the Rankine cycle costs. The costs predicted by the correlations have a percent error of 0% to 0.8%, when compared to the actual cost data.

29 TEV-96 0/09/202 Page: 28 of 45 Table 5. Correlation results and comparison for Rankine cycle costs ($ basis). Power Project Modules 4 Level Phase Item ROT Value NOAK Model Prediction % Error MWt (267 MWe at 750 C) 350 MWt (56 MWe at 750 C) FOAK NGNP NOAK FOAK NGNP Value Model Prediction % Error Value Model Prediction % Error Value Model Prediction % Error Value Model Prediction % Error Value Model Prediction % Error

30 TEV-96 0/09/202 Page: 29 of 45 Figure 3 presents the Rankine cycle cost correlation for the NOAK project phase. Figure 3. NOAK Rankine cycle cost correlations. 2.7 Capital Cost Results Comparisons In order to assess the accuracy of the capital cost model, results from the INL cost model were compared to reactor design supplier cost estimates. In order to provide a direct comparison, the cost model design costs (for the NGNP project phase) and project contingencies were adjusted to match the estimates provided by the reactor design suppliers. This allows a more accurate comparison of the project costs, as the design costs and contingencies vary widely between the reactor design suppliers. Furthermore, reactor design supplier costs were adjusted to exclude costs for hydrogen production facilities. The projected model cost is compared to the reactor design supplier average costs, along with the associated cost accuracy range of -30% to +50% for an AACE International class four estimate. The specifics of the design supplier estimates are withheld, as certain aspects of the costs may be considered business sensitive. Figure 4 and Figure 5 present two separate comparisons for a reactor plant with a thermal rating of approximately 600 MWt and a ROT greater than 850 C from separate reactor design suppliers. Both comparisons include costs for NGNP and NOAK project phases. These comparisons demonstrate that the cost model is within the range of the costs projected by the reactor design suppliers.

31 TEV-96 0/09/202 Page: 30 of 45 Figure 4. HTGR Model Cost Comparison Prismatic Block Design, ~600 MWt ROT 850 C. Figure 5. HTGR Model Cost Comparison Prismatic Block Design 2, ~600 MWt ROT 850 C. Figure 6 and Figure 7 present two separate comparisons for a reactor plant with a thermal rating less than 350 MWt and a ROT less than 750 C from separate reactor design suppliers. Only one of the comparisons includes costs for NGNP and NOAK project phases. Again, these comparisons demonstrate that the cost model is within the range of the costs projected by the reactor design suppliers.

32 TEV-96 0/09/202 Page: 3 of 45 Figure 6. HTGR Model Cost Comparison Prismatic Block Design 3, 350 MWt ROT 750 C. Figure 7. HTGR Model Cost Comparison Pebble Bed Design, 350 MWt ROT 750 C. 3. ESTIMATION OF Operating costs were evaluated for the HTGR for the NGNP, FOAK, and NOAK plants, for single and multiple module scenarios. Operating costs are assumed to include operations and maintenance (O&M) costs and refueling costs.

33 TEV-96 0/09/202 Page: 32 of O&M Costs O&M costs were estimated based on methodology presented for a study of advanced reactor technologies, specifically the study of O&M staffing and costs conducted by Dominion with advice from Entergy (Dominion 2004). O&M costs are assumed to include the following items: Staffing requirements, including expenses for overtime, benefits and retirement, bonuses and incentives, and payroll taxes Nuclear Regulatory Commission (NRC) fees Institute of Nuclear Power Operations (INPO) fees Nuclear Energy Institute (NEI) fees Insurance and taxes Material supplies, services, and upgrades Outage costs Administration and general cost overhead Staffing requirements were estimated based on the staff positions outlined in the Dominion study with input from Entergy. Staffing was estimated for single modules as well as estimates for an additional unit for multiple module scenarios. It was assumed that staffing levels would be the same for both the 600 MWt and 350 MWt power levels. Staffing assumes five shifts, three shifts active per day, one shift inactive, and one shift in training. It is assumed that staffing levels are independent of ROT, heat or power production, power cycle type, as well as the reactor phase, i.e. staffing levels are the same for the NGNP, FOAK, and NOAK project phases. Table 6 presents the staffing levels for the HTGR modules. SC indicates a position that is subcontracted if required, DP indicates a position that is duplicated by another staff member. The lower levels of staffing assumed for the HTGR when compared to current LWR operations take into account advanced system automation, passive reactor safety systems, and reductions in security due to partially burying the core. Table 6. Staffing levels by title. Position Units Single Unit Additional Unit Management Supervisory Vice President 0 Director O&M 0 Director Site Safety 0 Non-Supervisory Executive Assistant 0 Human Resources Generalist 0