NHI Economic Analysis of Candidate Nuclear Hydrogen Processes Daniel Allen Technology Insights, San Diego, California Paul Pickard Sandia National Laboratories, Albuquerque, New Mexico Mike Patterson Idaho National Laboratory, Idaho Falls, Idaho Carl Sink Office of Nuclear Energy, U.S. Department of Energy, Washington DC Fourth NEA Information Exchange Meeting on Nuclear Production of Hydrogen Oak Brook, Illinois April 16, 2009

Outline Methods Issues 2007 Results 2009 Results Conclusions

Methods

Nuclear Hydrogen Production Cost Framework Data Base and Calculation Model To assess the comparative costs of bulk hydrogen production processes to support NHI prioritization Consistent, Transparent To support tradeoff studies optimizing the design and the allocation of limited R&D resources. To understand relative cost and risk (uncertainty) drivers as guide to R&D resource allocation. To quantify impact of pertinent market issues and uncertainties as further guide to R&D.

Nuclear Hydrogen Production Cost Framework Approach Use DOE H2A based Groundrules and Economic Model (Discounted Cash Flow) Decouple H2 process from HTGR energy source Near-term focus on H2 process Follow-on to address reactor-specific optimization Develop and maintain consistent databases for NHI systems

Major Input Elements Process Plant Capital Costs - $ Direct Equipment Installation (Field Material & Labor) Indirect Replacement Capital Process Plant Operation & Maintenance Fixed - $/yr Staff Other Labor Costs Materials & Services for Maintenance & Repair Variable - $/kg H2 Thermal Power Consumption and Costs Electric Power Consumption and Costs Feedstock: Water; Chemicals; Catalyst Performance Efficiency Capacity Factor

Nuclear Hydrogen Production Cost Evaluation 2007 Study Interacted with Technology Developers: Sulfur-Iodine, High-Temperature Electrolysis and Hybrid Sulfur Estimates (Baseline Costs) from developers Contingency (20%) added to input total to represent Expected (Mean) cost Uncertainties (10%/90% Range Limits) estimated with developers Analysis with Nuclear Heat and Electricity Parametrically Nominally 60 $/MWe-h, 20 $/MWt-h HTSE Case Posted on DOE H2A Website

Nuclear Hydrogen Production Cost Evaluation 2009 Status Continuing Interaction with Technology Developers: Sulfur-Iodine, High-Temperature Electrolysis and Hybrid Sulfur Hydrogen Plant Alternatives Study (HPAS) by WEC/PBMR/Shaw Team (Shaw lead) for NGNP concluded in January Building data base from HPAS

Issues

Nuclear Hydrogen Production Cost Evaluation Issues/Concerns Variation in “Maturity” of Flowsheets Development and “Depth” of Cost Estimates among system components and between Technologies Validity of Scaling (e.g.- Process Temperature Effects)

2007 Results

Nuclear Hydrogen Production Cost Evaluation Nuclear Options - 2007 Modeling Nuclear Heat Source Electric Power Generation Hydrogen Production Process 2030 Sulfur-Iodine Thermo-chemical and HTGR Modular High-Temperature Gas-Cooled Rector (HTGR) none Sulfur-Iodine (S-I) Cycle– Reactive & Extractive HI High Temperature Electrolysis and HTGR Closed Cycle Gas Turbo-Compressor/ Generator High-Temperature Steam Electrolysis (HTSE) Hybrid Sulfur and HTGR Steam Turbine-Generator (T/G) Hybrid Sulfur Cycle

2007 Results - Hydrogen Price Earlier Published Estimates 2007 Analysis Sulfur-Iodine HI section: extractive distillation 1 - - 3.41 $/kg HI section: reactive distillation 2 1.95 $/kg 3 3.05 $/kg High-Temperature Electrolysis 1.92 $/kg 4 3.22 $/kg Hybrid Sulfur 1.60 $/kg 5 2.50 $/kg 6 2.94 $/kg 1 Present INERI baseline 2 Projected process improvement 3 GA/INL/TexasA&M NERI (GA-A25401, APR06) 4 GA/INL/TexasA&M NERI (GA-A25402, APR06), electrolyzers 500 $/kWe 5 SRNL (WSRC-TR-2004-00460, APR05), electrolyzers 2000 $/m2 6 Westinghouse/Shaw (HTR 2006, OCT06), electrolyzers 2650 $/m2

Cash Flow Example: 2007 S-I Case, Extractive Distillation for H2 levelized price 3.41 $/kg

Contributions to H2 Price Example: 2007 S-I Case, Extractive Distillation Total 3.41 $/kg

Major Parameters Varied 10% and 90% Probability Indicative Limits Capital Costs: Overall, of Major Sections, of Major Equipment Finance / Performance Variation After-Tax Real IRR - 8%, 10%, 15% (100% Equity) Capacity Factor - 85%, 90%, 95% Process Efficiency - ± 5% points With and without O2 sales credit With and without CO2 avoidance credit Power Input Thermal Power Cost - 18 $/MWt-h, 20 $/MWt-h, 25 $/MWt-h Electric Power Cost - 55 $/MWe-h, 60 $/MWe-h, 75 $/MWe-h Other Process Plant Materials and Services - ± 20% Other factors (staff, etc.) at 10% and 90% probability

Example of Sensitivity to Uncertainty 2007 - HTSE Key cost factor: Electrolyzers 500 $/kWe Uncertainties (10% 90% probability estimates) From INL: 250 $/kWe to 800 $/kWe

Example of Uncertainty Results 2007 - HTSE Case “Tornado” Plot - Varying Economic and Operating Cost Drivers 55 60 75 $/MWe-h 8% 10% 15% 49% 44% 39% 27 $/tonne CO2 20 $/tonne 95% 85% 90% 100 200 160 18 25 $/MWt-h 20 80% 120% 30 40

Example of Uncertainty Results 2007 - HTSE Case “Tornado” Plot - Varying Plant Capital Cost Drivers 250 500 800 80% 100% 150% 20 yrs 10 yrs 5 yrs 70% 130% 70% 130% 70% 130% 70% 130%

2009 Results (Shaw Led Study)

Shaw 2009 Assessment Three Designs and Cost Data on the Same Basis Three process simulations by Shaw Mass and energy balances Flow diagrams Realistic pressure drops, energy recovery Three sets of PFDs and equipment sizing Non-developmental equipment and installation costs estimated by industry specialists Development item costs reviewed Sulfuric Acid Decomposition Reactor Solid Oxide Electrolysis Module SO2 Electrolysis Module O&M estimates on same basis for three designs

2009 Shaw Comparative Evaluation Base Case for Each Technology No reactor technologies No specific combinations Reactor thermal rating: 550 MWt System Energy Balance Excess heat used to generate electricity via a Rankine cycle, with variable efficiency based on available temperature Electricity deficit or surplus is balanced by the grid at a set price and charged with a carbon penalty Hydrogen output: 140 million SCFD (345 t/d, 4 kg/s) Lifetime: 30 years Plant baseline availability: 8200 hours per year average (94%) Operating temperatures Max Process side temperature: 870°C (Reactor Outlet = 950°C)

Nuclear Hydrogen Production Cost Evaluation Nuclear Options – 2009 Modeling Nuclear Heat Source Electric Power Generation Hydrogen Production Process 2030 Sulfur-Iodine Thermo-chemical and HTGR Modular High-Temperature Gas-Cooled Rector (HTGR) none Sulfur-Iodine (S-I) Cycle – Reactive HI High Temperature Electrolysis and HTGR Steam Turbine-Generator (T/G) High-Temperature Steam Electrolysis (HTSE) Hybrid Sulfur and HTGR Hybrid Sulfur Cycle

Shaw 2009 Assessment Issues Raised Results very sensitive to economic assumptions: cost of heat, electricity and electricity escalation Equipment costs at peak of commodity prices (summer 2008) Problems remain using new technology item “Target” costs Lack of usable performance lifetimes and output change rates Process flowsheet uncertainties (particularly S-I) give varying electric power consumption

Resolving Assessment Cost Factors Revise Energy Costs per 2007 study Nuclear heat from 30 to 20 $/MWt-h Electric power from 75 to 60 $/MWe-h escalation from 1%/yr to zero Use H2A default water costs Assume heat integration with steam cycle No thermal energy input Reduce Capital Cost for Conventional Equipment Costs were ~1.5 times higher in mid-2008 than before (2005-2007) or since Include O2 By-product Credit for HTSE

Revising Cost Factors Shaw base case results Shaw base case results with revised energy costs Lower capital costs O2 credit for HTSE

Resolving Assessment Cost Factors Additional Revisions Addresss S-I cost conservatism Account for less tanatlum pipe and vessel lining in HI section HTSE and HyS non-conservatism Increase equipment cost for electrolyzers

Revising Cost Factors Shaw base case results Shaw base case results with revised energy costs Lower capital costs O2 credit for HTSE Tantalum reduced for S-I and electrolyzer costs doubled for HTSE and HyS

Resolving Assessment Efficiency Factors S-I Use earlier GA flowsheet, particularly HI section thermodynamic factors Efficiency improvement from 25% to 42% HyS Lower cell voltage (525 vs. 600 mV) Reduced thermal demand in the acid concentration step Efficiency improvement from 35% to 38% HTSE Eliminate the air sweep subsystem Efficiency improvement from 33% to 37%

Revising Flowsheet Efficiency dotted extensions are to Shaw base case result

Conclusions

Conclusions from Evaluation Studies Within Hydrogen Production Technologies Cost drivers become apparent Comparisons Between Technologies Little distinction in required H2 price Adjusting capital cost, cases converge Considering variation in efficiencies, cases overlap Uncertain flowsheet efficiencies and simulation models Immature cost bases for technology items No bases for performance stability and lifetime H2 Price Compared to Alternatives Energy input costs significant Nuclear Heat Electric power, generated on site or imported Need to assure optimal conventional plant

End