Toluene-MCH As a Two-Way Carrier for Hydrogen Transmission and Storage

Toluene-MCH as a Two-Way Carrier for Hydrogen Transmission and Storage

D.D. Papadias and R.K. Ahluwalia

U.S. DOE Hydrogen and Fuel Cells Program 2020 Annual Merit Review and Peer Evaluation Meeting Washington, D.C. 30 May 2020

Project ID: H2058

This presentation does not contain any proprietary, confidential, or otherwise restricted information. Overview Timeline Barriers ▪ Project start date: Oct 2020 ▪ H2 Storage Barriers Addressed: ▪ Project end date: Sep 2020 – B: System Cost % Complete: 100 – C: Efficiency – K: Life-Cycle Assessments

Budget Partners/Interactions Industry & research collaborations ▪ FY20 Total Funding: $100 K ▪ Chiyoda Corporation ▪ FY20 DOE Funding: $50 K

2 Relevance

[1] [2] Chlor-Alkali NGL Cracking - Objectives ▪ Investigate the performance, regulated/unregulated greenhouse gas (GHG) emissions and cost advantages of using a two-way toluene- Solar[3] Wind[4] methylcyclohexane (MCH) carrier for hydrogen transmission and storage

▪MPDevelopBP andH2 Capacity analyze specificProduction hydrogenDecomposition supply, oC oC wt% g/L P, bar T, oC P, bar T, oC DH Transmission by Rail[5-6] transmission and demand scenarios that are kJ/mol-H2 Ammoniaparticularly favorable for toluene-MCH carrier -78 -33.4 17.6 121 150 375 20 800 30.6 Haber-Bosch Process High-Temperature Cracking

Rail infrastructureRail Fe Based Catalyst Ni Catalyst Transmission by Ship[7-8] MethanolMP BP H2 Capacity Production Decomposition -98oC 64.7oC 18.75wt% 149g/L P,51 bar T,250 oC P, 3bar T,290 oC 16.6DH

Cu/ZnO/Al2O3 Catalyst Steam ReformingkJ/mol-H2 AmmoniaMCH

at aJetty at -127-78 -33.4101 17.66.1 12147 15010 375240 202 800350 30.668.3

Shipunloading cargo Haber-BoschNon-PGM Catalyst Process High-TemperaturePt/Al2O3 Catalyst Cracking Fe Based Catalyst Ni Catalyst Methanol -98 64.7 18.75 149 51 250 3 290 16.6 3 Cu/ZnO/Al2O3 Catalyst Steam Reforming MCH -127 101 6.1 47 10 240 2 350 68.3

Non-PGM Catalyst Pt/Al2O3 Catalyst Approach

- Tasks and Approach

▪ Develop models for cost and performance of toluene hydrogenation and

dehydrogenation plants of 50-650 TPD (Metric Tons Per Day H2 equivalent).

▪ H2 supply scenarios: S1 – byproduct H2 from chlor-alkali plants, S2 – byproduct H2 from NGL steam cracking, S3 and S4 – renewable H2 from solar and wind, respectively

▪ Develop models and/or use existing tools1 and models for cost and performance of

H2 demand scenarios (D1 - FC LDV, D2 – FC HDV, D3 – Power GTCC) ▪ Develop models for transmission, infrastructure and storage of MCH and toluene by rail or by ships (product tankers)

▪ For each case study, determine the performance (energy consumption, MJ/kg-H2), levelized cost ($/kg-H2), and greenhouse gas emissions (kg-CO2/kg-H2) ▪ All pathway costs evaluated by H2A2 guidelines and based on 2016 $-year basis

1Tools and methods: Matlab, GC-Tool, H2A, HDSAM, HDRSAM, SAM, Cost models (Internal Developed/Aspen/Literature) 2https://www.hydrogen.energy.gov/h2a_analysis.html 4 1 (S1) - Utilization of by-Product H2 from Chlor-Alkali plants ▪ An estimated 0.4 million metric tons of hydrogen is produced annually by the chlor-alkali Approach industry in the U.S. ▪ Approximately 80% of the United States chlor-alkali capacity is in the Gulf region

▪ About 35% of by-product hydrogen is known to enter the merchant gas market. H2 is combusted for steam generation or vented (~10-15%)

By-product hydrogen capacity, 1010 TPD

Chlor-Alkali hydrogen capacity in LA and TX

LA 243 TX

1Lee, D.Y. and Elgowainy, A., Dai Q. Life Cycle Greenhouse Gas Emissions of By-Product Hydrogen 5 from Chlor Alkali Plants. ANL/ESD-17/27 1 (S1) - Utilization of by-Product H2 from Chlor-Alkali Plants ▪ About two-thirds (68%) of total electricity consumed by the U.S. chlor-alkali industry is Approach from the bulk electricity market (or the grid); ▪ The remainder (32%) is sourced from on-site power generation. Most of the CHP units are in the Gulf Coast region, which all are topping cycle systems ▪ Steam is needed in the chlor-alkali production e.g. for salt preparation and concentration of caustic soda. NaOH after-treatment process accounts for the largest heat requirement (95%) ▪ By-product hydrogen can be exported or used for steam/electricity production ▪ Hydrogen used for hydrogenation needs to be substituted by NG to meet heat demand

Grid: U.S. Mix Grid: U.S. Mix (10.4 MJe/kg-Cl ) (10.6 MJe/kg-Cl2) Heat Demand Electricity Demand 2 Heat Demand Electricity Demand 2.8% 92%

Brine NaCl(aq) Cl2 Cl2 Brine NaCl(aq) Cl2 Cl2 Electrolysis After-treatment Electrolysis After-treatment Preparation NaOH NaOH Preparation NaOH NaOH

0.028 kg-H2/kg-Cl2 95% H2

Cooling and Cooling and Compression Purification Purification (1.3-10 bar)

H2: 3.34 MJth/kg-Cl2 5.25 Boiler MCH Boiler 0.8 MJ /kg-Cl Hydrogenation MJth/kg-Cl2 (η=80%) th 2 (η=80%) 0.46 kg-MCH/kg-Cl2 System Boundary System Boundary NG: 3.22 MJth/kg-Cl2 NG: 5.59 MJth/kg-Cl2

Case: By-product H2 is used for energy production Substitution: By-product H2 is used for hydrogenation

1Lee, D.Y. and Elgowainy, A., Dai Q. Life Cycle Greenhouse Gas Emissions of By-Product Hydrogen 6 from Chlor Alkali Plants. ANL/ESD-17/27 1,2 (S2) - Utilization of by-Product H2 - NGL Steam Cracking Plants ▪ An estimated 1.8 million metric tons per year (5,000 tpd) of by-product hydrogen is produced annually from NGL steam crackers in the U.S. ▪ Steam crackers in Texas and Louisiana makes up ~88% of the total by-product hydrogen

▪ As of 2017, ethane makes up 67% of the steam cracker feedstock in the U.S. (H2/C2H4=7.6 wt.%)

Ethylene production. Metric tons/year

Lake Charles, 350 Point Comfort, LA, 1,200,000 TX, 800,000 300

, tpd , 250 2 Plants constructed 2016-2017 200 based on ethane as feedstock. Baytown, TX, 150 Source. University of Oxford Cedar 1,500,000 productH 100 Bayou, TX, - 1,500,000 By 50 West Virginia, 0 Freeport, TX, Monaca, PA, 272,158 1,250,000 1,500,000 Point Baytown, West Monaca, PA Freeport, Cedar Lake Comfort, TX TX Virginia TX Bayou, TX Charles, LA

By-product hydrogen by steam crackers in the U.S. 1 Steam crackers based on natural gas liquids (NGLs)1,2

Heat Demand: 17.7 GJ/Tonne-C2H4

NG NGL Fractionator Ethylene,

4 Propylene, H

2 other C

- Ethane/Popane/Butane Fractionation

Steam 5.26 GJ/Tonne 5.26 Compression Steam 1.1-10 bar Cracker

H2: 8.88 GJth/Tonne-C2H4 PSA (80% Recovery) CH4: 3.52 GJth/Tonne-C2H4 H2 export (MCH)

1Lee, D.Y. and Elgowainy, A. International journal of hydrogen energy 43 (2018) 20143-20160 7 2The Lindgren Group, LLC, Production of Ethylene from Natural Gas, April 22, 2013 1 S3 and S4 - Cost of Electricity by Wind and Solar 18 State TX (SW) CA (SE) Resource Wind Wind 16 Wind Solar Turbine General Electric 3.6sl General Electric 3.6sl 14 Accomplishment Rated Capacity (kW) 3,600 3,600 12 Hub Height (m) 80 80 10 CAPEX ($/kW) 1,695 1,695 8 CA OPEX ($/MWh) 18.1 18.1 TX CA/TX Analysis Period (years) 25 25 6 IRR (%) 10 10 4 Capacity Factor (%) 38.1 32.2

Cost of Electricity, cents/kWh Electricity, of Cost 2 CAPEX (cents/kWh) 4.98 5.89 OPEX (cents/kWh) 1.53 1.81 0 Total LCOE (cents/kWh) 6.51 7.71 0 10 20 30 40 50 Capacity Factor, % State TX (SW) CA (SE) Resource Solar (PV) Solar (PV) Projected Electricity Costs Array Type 1 Axis Tracking 1 Axis Tracking Direct normal (kWh/m2/day) 5.23 5.23 ▪ Wind offers higher annual capacity factor Inverter Efficiency (%) 96 96 than solar. Wind capacity : TX 38.1% vs CAPEX ($/kW) 1,040 1,040 32.2% in CA OPEX ($/MWh) 4.8 4.8 ▪ Solar capacity factor near similar in TX Analysis Period (years) 25 25 and CA ~21% IRR (%) 10 10 Capacity Factor (%) 21.1 21.4 ▪ Cost of solar cheaper than wind in all CAPEX (cents/kWh) 5.51 5.44 cases: CAPEX and OPEX of solar less OPEX (cents/kWh) 0.49 0.48 than wind Total LCOE (cents/kWh) 6.00 5.92

1Wind and solar techno-economics based on System Advisor Model (SAM). www.nrel.gov 8 Utilization by Wind – Example Profiles in TX1 40 60 Approach 35 SEP FEB 50 30 25 40 Average yearly power 20 30

15 MW Power, 20 10 10 Monthly Averege, GWh Averege, Monthly 5 0 0 0 4 8 12 16 20 24 Time of Day Average Month 100 90 Renewable Power Intermittency 80 ▪ Yearly, monthly and even hourly average 70 Average yearly power values are not very useful metrics for 60 analysis. 50 ▪ Actual hourly profiles (e.g. wind) show 40 sharp variability with 0-100% rated MW Power, 30 capacity and idling at hours. 20 ▪ Using load following, the cost of hydrogen 10 by electrolysis capital alone, will increase 0 by 2-2.5 $/kg (at 38%-32% capacity factor) 0 20 40 60 80 100 120 Hourly Profile Since JAN 1 1Example 100 MW name-plate capacity 9 Capacity Factor = Annual energy produced/annual nameplate energy capacity Utilization by Wind – Example Scenario Options

100 100 To Grid: All Excess Back to grid To Grid: 90 90 Excess

Accomplishment at Peak 80 80 Demand From grid 70 70 60 60 To Grid: None Plant 50 usage Daily production need 50

Renewable Electricity, % Electricity, Renewable 40

40 30 % Plant, for Power Peak Usable

30 20 10 20 30 40 Capacity Factor, % Renewable Power Intermittency 0.2 ▪ Utilize a fraction of the rated power of the To Grid - All Excess plant for hydrogen production 0.175

▪ Excess electricity is sold back to the grid To Grid - Excess at Peak 0.15 (all excess, or excess during peak demand Demand hours 8 am – 8 pm) 0.125 To Grid - None ▪ At times when wind power is less than utilized for hydrogen production; import 0.1

electricity from the grid $/kWh Electricity, of Cost

Cost of Electricity, cents/kWh Electricity, of Cost 0.075 ▪ Cost of grid power: 5.74 ¢/kWh, price of electricity sold: 2.5 ¢/kWh 0.05 ▪ Renewable power: Offset import to export 10 20 30 40

Capacity Factor, % 10 Grid power assumes fossil based power and should not be confused with actual GHG emissions Capital Cost of Toluene Hydrogenation Plant

▪ Reactor operated at 240°C and 10 atm for nearly complete conversion. Conversion is kinetically limited. No side-reactions are considered.

Accomplishment ▪ Allowing for 0.5 atm pressure drop, 98.5% of MCH condenses at 9.5 atm and 45°C

▪ Excess H2 and MCH vapor recycled (H2/Toluene ratio = 4/1) ▪ Toluene makeup = 0.22% (due to dehydrogenation losses)

9% Hydrogenation Compression 12% Compression 3% Cooling Recycle H2/MCH Storage 2 54% Storage 22%

Storage 1 Misc Toluene Makeup MCH Tank Toluene Tank Heat

Rejection C7H14(l)

H 7

H2 C

Plant

°C

) l

( 5

240 240

C From DehydrogenationFrom

220 °C 4

)

(

°C

7 C Heat H2/TOL = 3 Rejection 180 H2 200 °C (High Grade) H2

Cooling Hydrogenation System Boundary T = 250 C

H2 H2 (1.1 atm)

Lindfors, L.P. et. al. (1993). Kinetics of Toluene Hydrogenation on Ni/Al2O3 Catalyst. Chem. Eng. Sci., 48, 3813 11 Capital Cost of Methylcyclohexane Dehydrogenation Plant ▪ Reactor operated at 350°C and 2 atm. Conversion is 98% with 99.9% toluene selectivity. No side-reactions considered.

Accomplishment ▪ Allowing for 0.5 atm pressure, 80% of toluene condenses at 1.5 atm and 40°C, remaining during the compression cycle (4 stages) and chiller

▪ H2 separation by PSA at 20 atm, 90% recovery (ISO/SAE H2 quality)

H Purification & Condensation 2 H2 Losses ISO/SAE Standard Compression PSA 20 atm Tailgas (1.3 atm) ▪Toluene+MCH: 0.84%

4 stages/Intercooled

atm .

8 ▪Hydrogen: 10%

40 °C .

)

(

Chiller

TOL

8 / H ▪Heat: 0.36 kWh /kWh -H

7 th th 2

C atm

MCH To Storage /

5 5 To Burner

. H 1 Dehydrogenation Compression Area 400 Feedstock/Utilities Storage 1 Area 300 Storage 2 Separation Storage ▪NG: 0.22 kWhth/KWhth-H2 MCH Tank Toluene Tank Misc 40 °C ▪Electricity: 0.04 kWhe/KWth-H2 MCH (~100%)

TOL (~100%)

°C 70 70 Area 102 6%

) 6%

)

(

°C

7 C

250 250 T=350 C C

Area 101 42% 350 °C 30% + 3H2 High grade

waste heat atm 2 2 T=300 C 16% NG 0.12 mol/s 255 °C 200 256 kWth Area Dehydrogenation Compression PSA Tailgas Dehydrogenation System Boundary Separation Storage Misc

Okada, Y. et. al. (2006). Development of Dehydrogenation Catalyst for Hydrogen Generation in Organic Chemical Hydride 6%Method. 12 Int. J. Hydrogen Energy, 31, 1348. 6%

42% 30%

16% (T1) - Transmission by Rail Scenario: Hydrogen by-product from chlor-alkali and steam cracker plants

▪ Hydrogenation of toluene: 50, 130, 260 and 650 TPD Accomplishment ▪ Location: Hydrogenation in Gulf of Mexico. ~80% H2 capacity (5,200 TPD) ▪ Transmission: Unit train or ships to dehydrogenation facility in northern California

▪ Distribution: H2 distribution to LDV market by GH2 trucks to a mid-size city (3 M)

MCH Production10 MCH Storage9 H 2 MCH

Toluene Storage9 Fresh Toluene Utilities MCH Toluene

5 100 km Toluene Distribution14 Liquid MCH/Toluene Carrier

9 Toluene

11 9 MCH GH Terminal13 H Purification PSA12 MCH Decomposition MCH Storage 2 2 MCH Toluene H2 NG

H2 + Toluene, MCH Utilities

Byproduct H2 from Gulf Coast H Demand FC Vehicle Chlor Alkali Steam Cracker Train Frequency Storage 2 Railcars (TPD) Market (%) (%) (%) (days) (days) $0.04/Ton-mile1 50 4 6.6 1.1 7 9 76 Fuel: 380 Ton-mile/gal 130 10 17.2 3.0 4 6 112 260 20 34.3 5.9 2 4 112 650 49 85.8 14.8 1 3 140

1 www.stb.gov: sample of carload waybills for all U.S. rail traffic submitted by 13 1 Short ton (ton) = 0.907 Metric ton (Tonne) those rail carriers terminating 4,500 or more revenue carloads annually. (T2) – Transmission by Product Tanker

Approach Tanker Specifications 50 TPD 130 TPD 260 TPD 650 TPD Tanker Size (DWT) 35,000 92,615 92,615 115,000 ECA Number of Ships per Route 1 1 2 4 Tanker MCH Capacity (Tonnes) 24,400 63,355 63,355 79,194 Tanker H Capacity (Tonnes) 1,500 3,900 3,900 4,875 ECA 2 Tanker Length (m) 183 239 239 248 Tanker Width (m) 30 38 38 42 Tanker draught (m) 9 13 13 14 Storage (Days) 32 32 17 10 Tanker size limited by LR2 size, not Neopanamax canal dimensions Panamax locks: Length of up to 294 m (965´), beam of up to 32.31 m (106´), draught of up to 12.04 m (39.5´). Neopanamax locks: Length of up to 427 m (1,401´), beam of up to 52 m (170´), draught of up to 18.3 m (60´). MCH/Toluene tanker limited in capacity to 115 kDWT based on largest LR2 product tanker ▪ Round-trip time: 30 days (15 knots at sail; 8 h to pass Panama Canal, 20 h to un- load and load shipment) ▪ From 2020, IMO regulations will cut sulfur dioxide emissions by 86%, reducing worldwide sulfur content in fuel from 3.5% (IFO) to 0.5% (MGO). ▪ Ships that operate in Emissions Control Areas (ECA) must limit sulfur content in fuel to <0.1% as in low-sulfur marine gas oil (LSMGO). ▪ Tanker will spend 27% of it’s time in ECA zones (sail & at berth) ▪ Panama canal fees varies on ship length, width and laden conditions

14 Tanker (T2) Transmission Cost Relative to Rail (T1)

2.5 2.5 Infrastructure Infrastructure Tanker - CAPEX ▪ Economy of scale favors

Rail - Fuel 2

H H - Tanker - Fuel Tanker - O&M - 2.0 Rail - Other 2.0 35 large tankers (single ship 1.64 1.60 (kDWT) per route) 1.58 1.53 92.6 1.5 1.5 1.42 92.6 115 (kDWT) (kDWT) (kDWT) ▪ Tankers more favorable for 0.35 0.97 transmission than rail >50 0.97 0.97 1.05 0.92 1.0 1.0 0.81 TPD 0.43 0.24 0.70 0.24 ▪ GHG Emissions lowest for 0.24 0.22 0.5 0.5 0.32 0.24 Rail Transmission Cost, $/kg Cost, Transmission Rail 0.50 0.21 Tanker>50 TPD demand 0.50 0.50 $/kg Costs, Transmissio Tanker 0.22 0.50 0.22 0.31 0.20 0.17 0.22 0.11 0.0 0.11 0.06 0.05 0.0 0.07 50 TPD 130 TPD 260 TPD 650 TPD 50 TPD 130 TPD 260 TPD 650 TPD

3.5 Service Life, yr [30 25 18] -1.5% +2.8%

2 3

H 3.06 - 2.94 2.5

CAPEX [-20% 0 +20%] -7.2% +7.2% CO2/kg - 2 +18.2% 1.5 1.72 Fuel Cost, $/T [380 650 1000] -14.3% 1.52 1 +25.7%

IRR [8% 10% 20%] -4.3% kg Emissions, GHG 0.5

0 0.5 0.6 0.7 0.8 0.9 Rail Ship Ship Ship Tanker specific costs 92,600 DWT Transmission Cost, $/kg-H2 (35 kDWT) (92.6 kDWT) (115 kDWT)

15 Pathway Costs and Green-House Gas Emissions Electricity Source (%) U.S. Mix TRE (TX) Mix CA Mix 160 Residual oil 0.5% 0.1% 0.0% 141.03 Natural gas 29.8% 45.5% 41.3% 140

Coal 32.7% 28.9% 6.3% /MJ Nuclear power 20.6% 11.5% 9.7% 2 120

Biomass 0.1% 0.0% 0.5%

CO - Renewable 16.3% 14.0% 42.2% 100 89.29

Electricity Source (g-GHG/kWh) U.S. Mix CA Mix 80 69.81 TRE (TX) Mix 64.03 Residual oil 4.06 1.06 0.24 60 Natural gas 126.53 193.54 175.63 Coal 325.56 287.72 62.89 GREET2019 40 Nuclear power 0.00 0.00 0.00

Biomass 0.00 0.00 0.00 emissions,g GHG 20

Renewable 0.00 0.00 0.00 Electricity Electricity Mix Production Total (g/kWh) 480.16 507.71 251.32 0 Total (g/MJ) 133.38 141.03 69.81 Natural ElectricityElectricity Diesel Gas (TX) (CA) Chlor-Alkali Allocation Emissions and Energy Chlor-Alkali Cl2 NaOH H2 Co-products (kg/kg H2) 35.09 39.65 1 ▪ Emissions and energy use include well to Market Values ($/kg) 0.26 0.44 1 Mass share 46.33% 52.35% 1.32% point of use metrics according to latest Market value share 32.62% 63.74% 3.65% GREET model 2019

Ethane Crackers - Allocation ▪ Electricity emissions used for TRE region Products Formula kg/kg-H2 Mass Share (TX) and CA with a mix of energy sources Ethylene (C2H4) 13.158 83.20% Propylene (C3H6) 0.25 1.58% ▪ H by-product emissions will be compared on

Allocation 2 Methane (CH4) 0.895 5.66% Butadiene (C4H6) 0.368 2.33% substitution (NG consumption) as well as on Butene (C4H8) 0.039 0.25% mass-allocation basis (CO2 emissions split Benzene (C6H6) 0.092 0.58% Toluene (C7H8) 0.013 0.08% on all co-products) Hydrogen (H2) 1 6.32% ▪ For brevity, costs are compared for a large Total 15.815 100.00% demand case (650 TPD). All cost break- downs are available in separate spreadsheet. 16 Cost, Up-stream Energy Use and Emissions: Summary Dehydrogenation cost by Bio-Methane (BM) (not shown) S=Substitution, A=Mass-Allocation, increases by $0.18/kg 7.99 NG=Natural Gas, BM=Biomethane $8.0 18 0.66 NG (Feedstock) Hydrogen Production 7.09 16 Transmission by NG (Fuel)

$7.0 Hydrogenation 2 LR2 Product Tanker Accomplishment 0.66 H Electricity Transmission 1.60 - 14

$6.0 0.70 /kg Dehydrogenation 2 0.30 0.30 11.84

CO 12

- 10.81 $5.0 0.54 10 1.52 $4.0 -57% 8 1.80 -71% -68% $3.0 2.78 1.66 5.43 5.43 6 5.05 -82% 0.66 1.88 11.3 $2.0 1.52 3.39 3.83 0.66 4 1.60 5.84 1.52 2.17 Total GHG Emissions, kg Emissions, GHG Total 1.80 1.52 $1.0 0.70 2 0.65 Hydrogen Pathways Cost, $/kg Cost, Pathways Hydrogen 1.52 0.30 0.30 1.66 1.80 1.66 $0.0 0.22 0.22 0 0.65 S₁/T₁ (NG) S₁/T₂ (NG) S₃/S₄/T₁ (NG) S₃/S₄/T₂ (NG) SMR S₁ (S + NG) S₁ (A + NG) S₁ (A + BM) S₃/S₄ (NG) S₃/S₄ (BM) (Reference)

2.00 ▪ By-product H2 incurs the lowest cost among

2 1.80 NG Electricity Fuel H the pathways analyzed. Using ships as - transmission mode, the cost could 1.60 1.50 potentially be below $2/kg1 1.40 0.03 1.20 ▪ By-product H2 could reduce GHG by 57- 1.00 71% relative to SMR if emissions are mass- 0.80 1.47 0.76 allocated to all co-products and if bio- 0.60

methane is available for dehydrogenation. 0.40 0.29 0.27 Upstream Energy Use, MJ/MJ Use, Energy Upstream 0.76 0.08 0.20 0.14 ▪ Producing renewable H2 in TX for 0.07 dehydrogenation in CA will be at best cost 0.00 0.22 competitive ($7.26/kg in CA) but incur higher emissions.

This is the lowest cost reflected by hydrogen substituted by NG for 17

heat demand, and not assigning a “market” value for H2 (D1) - GH2 Terminal and Distribution Costs 2.0 LDV GH2 Refueling Infrastructure 1.8 CAPEX Fuel O&M California City Case Size Population (Million) 3 3 3 3

2 Station Utilization (%) 80 80 80 80

H 1.6 - Accomplishment Station Dispensing Capacity (kg/day) 400 600 800 1000 1.4 1.23 H2 Demand (TPD) 50 130 260 650 1.2 H2 LDV Market Penetration (%) 4 10 19 49 0.29 0.97 H2 LDV Fleet 87,700 219,000 416,000 1,075,000 1.0 0.85 0.12 0.77 # of H2 Stations in City 168 280 400 822 0.8 0.29 Distance Between Stations (km) 3.36 2.6 2.18 1.52 0.29 0.6 0.12 0.29 H2 Stations displacing Gas Stations (%) 11 18 26 53 0.12 # of TrucksRequired Per Day 32 80 151 388 0.4 0.82 0.12 # 540 bar Trailers 187 310 441 907 Distribution Cost, $/kg Cost, Distribution 0.56 0.2 0.44 0.36 Tube trailers/H2 Daily demand (#/TPD) 3.7 2.4 1.7 1.4 0.0 Cost of Electricity - CA ($/kWh) 0.125 0.125 0.125 0.125 50 TPD 130 TPD 260 TPD 650 TPD GH2 Terminal Cost: $1.14/kg-H2 Distribution costs are affected by the station capacity (dispensing rate) 13% CAPEX - Compressor Distribution (400 vs 1000 kg/day) 21% ▪ Lower cost as number of tube trailers are CAPEX - Storage reduced per daily demand Electricity 30% - Gaseous H2 terminal ▪ Cost not affected by market penetration O&M 36% rate. Buffer storage accounts for 36% of the cost (required to fill 540 bar/1,040 kg-

H2 within 10 hours) 18 (D1) - GH2 Total Dispensing Costs and Emissions 5.0 8.0 CAPEX - Compressor CAPEX - Storage Gaseous H₂ Terminal CAPEX - Dispenser CAPEX - Refrigeration

2 7.0 Distribution H

CAPEX - Rest Electricity - Dispensing

Accomplishment 4.0 2 O&M

H 6.0

- 5.44 3.03 4.96 3.0 2.83 5.0 4.62 2.62 4.21 0.92 2.30 0.83 4.0 3.03 0.73 2.83 0.23 0.62 2.62 2.0 0.23 0.23 3.0 2.30 0.37 0.28 $/kg DispensingCost,

0.20 0.23 2 0.30 0.29 0.29 0.16

Dispensing Cost, $/kg DispensingCost, 0.23 0.20 0.20 0.20 2.0 1.0 0.16 1.23 0.97 0.31 0.31 0.85 0.77 0.31 0.31 Total GH Total 1.0 0.69 0.68 0.66 0.58 1.18 1.16 1.15 1.14 0.0 0.0 50 TPD 130 TPD 260 TPD 650 TPD 50 TPD 130 TPD 260 TPD 650 TPD

GHG Emissions: 2.56 kg-CO /kg-H Total Dispensing Cost (400 vs 1000 kg/day) 2 2 ▪ Cost reduction by $1.23/kg as station capacity increases due to lower transmission and dispensing costs 31% GH₂ Terminal

Distribution - Emissions 50% ▪ A total of 2.56 kg-CO /kg-H for GH 2 2 2 Dispensing refueling pathway. GH2 terminal account for 19% 50% of GHG emissions.

19 Summary and Conclusions

The performance, regulated/unregulated greenhouse gas (GHG) emissions and cost advantages of using a two-way toluene-methylcyclohexane (MCH) carrier for hydrogen transmission and end use was analyzed for different scenarios

▪ By-product H2 incurs the lowest cost among the pathways analyzed. Using ships as transmission mode, the cost, reflected by NG substitution only, could potentially be

below $2/kg ($1.88/kg S1/T2)

▪ By-product H2 pathway could reduce GHG by ~58% relative to H2 produced by SMR if emissions are mass-allocated to all co-products (5.05 kg-CO2/kg-H2 vs 11.84 kg-CO2/kg-H2). Potentially, GHG emissions could be reduced by a total of 71% with biogas available for dehydrogenation

▪ Producing renewable H2 for hydrogenation in TX and dehydrogenation in CA could be cost competitive with renewable H2 locally produced in CA ($7.09/kg vs $7.26/kg in CA). GHG emissions due to transmission and dehydrogenation will increase by

3.83 kg-CO2/kg-H2 ▪ Transmission of MCH/Toluene by large product tankers (115,000 DWT) is 50% less expensive than transmission by rail ($0.7/kg vs $1.53/kg). Emissions utilizing ships for transmission are reduced by half relative to rail.

20 Picture Licenses/References

[1] Courtesy by Eric Burgers, from Flickr: https://www.flickr.com/photos/uw-eric/2890255375/in/photostream/ [2] https://commons.wikimedia.org/wiki/File:Cell_room_of_a_chlorine-caustic_soda_plant.JPG [3] https://commons.wikimedia.org/wiki/File:Solar_Panels_at_Topaz_Solar_5_(8159036498).jpg [4] Photo credit: USFWS/Joshua Winchell (https://www.flickr.com/photos/usfwshq/8426360101) [5] https://www.flickr.com/photos/royluck/21148125305 [6] https://pixabay.com/photos/cincinnati-train-yard-railway-1384325/ [7] https://pxhere.com/en/photo/1423603 [8] https://commons.wikimedia.org/wiki/File:Pauillac_tanker_unloading.jpg [9] Image by LEEROY Agency from Pixabaya [10] Image by Markus Naujoks from Pixabaya [11] Image by James Glen from Pixabaya [12] Image HDSAM Manual. www.energy.gov [13] Image courtesy Lincoln Composites. www.energy.gov

a Free for commercial use no attribution required. https://pixabay.com/service/license/ bhttps://creativecommons.org/licenses/by-nc-sa/2.0/ chttps://creativecommons.org/licenses/by/2.0/deed.en dhttps://creativecommons.org/licenses/by-sa/4.0/ eWikimedia Commons / CC BY-SA 3.0

21 Technical Backup Slides

22 H2 Production – PEM Electrolysis

We are using DOE H2A as the reference model for electrolysis cost1 ▪ Hydrogen production by PEM electrolysis, central case 50 TPD unit train according to DOE H2A current technology status. ▪ Uninstalled cost of $900/kW, stacks contribute 47% of cost. ▪ Cell voltage 1.75V, 70.3% voltage efficiency (as % of fuel LHV) ▪ Hydrogen drying losses: 3% of gross hydrogen

▪ Total system electrical usage: 54.3 kWhe /kg-H2 (stack contributes 93%) ▪ Unless specified, electricity cost is ¢5.74/kWh in TX and ¢12.5/kWh in CA (industrial cost, 2019 average, EIA.gov)

Rest of BOP Water & 10% Thermal System 10%

Stacks Gas 47% Management 12% Power Conditioning 21% Uninstalled cost break-down 1https://www.hydrogen.energy.gov/h2a_analysis.html

23 (T2) – Tanker Cost Factors (Fuel) We are using LSMGO as the reference fuel for maritime applications considered in this study. ▪ Small difference in price of MGO and LSMGO. As of end of 2019 cost of LSMGO is $650/Tonne (LHV = 42.8 MJ/kg, 900 m3/kg) ▪ Main fuel consumption occurs at sail. Engine operates at 85% of rated power for maximum fuel efficiency. ▪ Specific fuel consumption decreases with engine size (bigger engines operate at low RPM ~100 with efficiencies approaching 50%)

@85% rated power @85% rated power

2 4,600 Tonnes H Tonnes 4,600

24 (T2) – Tanker Cost Factors (Capex + Opex) Panama canal fees per roundtrip are based on laden conditions (MCH/Toluene) ▪ Canal fees decrease (on DWT basis) as ship increases in cargo capacity. ▪ Additional port fees included at $0.52/DWT-day. ▪ Capex of ship as function of size (DWT) based on statistical data around global shipyards. Additional cost of 20% will be included due to maritime commerce between U.S. ports1 ▪ Crew size complement: 2 Deck officers, 4 engineers, rest as deckhand

Crew: 26-28 2

Crew: 33 4,600 Tonnes H Tonnes 4,600

1The Jones Act requires goods shipped between U.S. ports to be transported on ships that are built, owned, and operated by United States citizens or permanent residents 25