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- 1. DIPLOMADO EN PRODUCCIÓN Y USOS DEL HIDRÓGENO Modulo 13 : Consideraciones económicas en la implementación Carlos Andrés Vasco Correa Economista, Docente-Investigador en Microeconomía Aplicada, economía ambiental y de la energía Departamento de Economía Universidad de Antioquia Julio 8 de 2021 carlos.vasco@udea.edu.co Clasificación A1 MinCiencias
- 2. 2 Contenido Carlos Andrés Vasco Correa DIPLOMADO: Producción y Usos del Hidrógeno Modulo 13: Consideraciones económicas en la implementación 1 2 3 4 Metodología de Costos Nivelados Competitividad del Hidrógeno Modelación Determinística y Estocástica Aplicaciones prácticas
- 3. 3 LCOE - Costos Nivelados Carlos Andrés Vasco Correa DIPLOMADO: Producción y Usos del Hidrógeno Modulo 13: Consideraciones económicas en la implementación Life Cycle Costing (LCC) LCC is an important method to evaluate the total cost of a product or a system over its given lifetime • Define the cost elements; • Define the cost structure; • Establish cost estimating relationships; • Establish the method of LCC formulation. Levelized Cost of Hydrogen (LCOH) In is the initial investment cost for year n, Mn is the maintenance cost in year n, Fn is the fuel cost in year n, En is the energy generation in year n, i is the discount rate and N is the lifetime. The LCOE method is a valuable tool when comparing different case studies and is not limited to renewable energy sources but has been used widely to assess the cost of hydrogen. Viktorsson, L., Heinonen, J., Skulason, J., & Unnthorsson, R. (2017). A Step towards the Hydrogen Economy—A Life Cycle Cost Analysis of A Hydrogen Refueling Station. Energies, 10(6), 763. https://doi.org/10.3390/en10060763
- 4. 4 LCOE - Costos Nivelados Carlos Andrés Vasco Correa DIPLOMADO: Producción y Usos del Hidrógeno Modulo 13: Consideraciones económicas en la implementación Life Cycle Costing (LCC) for Hydrogen where Cinv is the investment cost, Cwe is the Water Electrolyzer cost, Cc is the compressor cost, Cs is the storage unit cost, Cd is the dispenser cost and Cmisc is miscellaneous costs or all other costs that were connected to the station (certification and the preparation costs). where i is the nominal discount rate and n is the economic lifetime of the station. The annualized, a, investment costs are therefore Viktorsson, L., Heinonen, J., Skulason, J., & Unnthorsson, R. (2017). A Step towards the Hydrogen Economy—A Life Cycle Cost Analysis of A Hydrogen Refueling Station. Energies, 10(6), 763. https://doi.org/10.3390/en10060763 Capital Recovery Factor (CRF)
- 5. 5 LCOE - Costos Nivelados Carlos Andrés Vasco Correa DIPLOMADO: Producción y Usos del Hidrógeno Modulo 13: Consideraciones económicas en la implementación Life Cycle Costing (LCC) for Hydrogen The operational and maintenance (O&M) costs were divided between fixed and variable expenses. The annual fixed O&M is denoted by: where Cmc is the maintenance cost for the compressor, Ccont is the service contract cost and Crep,a is the annualized replacement cost. Similarly, the variable O&M is presented by where Ce is the annual electricity cost and Cw is the annual water cost Viktorsson, L., Heinonen, J., Skulason, J., & Unnthorsson, R. (2017). A Step towards the Hydrogen Economy—A Life Cycle Cost Analysis of A Hydrogen Refueling Station. Energies, 10(6), 763. https://doi.org/10.3390/en10060763
- 6. 6 LCOE - Costos Nivelados Carlos Andrés Vasco Correa DIPLOMADO: Producción y Usos del Hidrógeno Modulo 13: Consideraciones económicas en la implementación Life Cycle Costing (LCC) for Hydrogen The annualized LCC can therefore be expressed by After the annualized LCC have been calculated the LCOH can be assessed by dividing the annualized LCC noted as CLCC,a by the amount of produced hydrogen (kg H2) noted as EH2,a LCOH (USD/ Kg H2) = Viktorsson, L., Heinonen, J., Skulason, J., & Unnthorsson, R. (2017). A Step towards the Hydrogen Economy—A Life Cycle Cost Analysis of A Hydrogen Refueling Station. Energies, 10(6), 763. https://doi.org/10.3390/en10060763
- 7. 7 LCOE - Costos Nivelados Carlos Andrés Vasco Correa DIPLOMADO: Producción y Usos del Hidrógeno Modulo 13: Consideraciones económicas en la implementación Fuente: Tecnologías del Hidrógeno y Perspectivas para Chile 2019 - 4e Chile
- 8. 8 Competitividad del Hidrógeno Carlos Andrés Vasco Correa DIPLOMADO: Producción y Usos del Hidrógeno Modulo 13: Consideraciones económicas en la implementación Hydrogen Council (2021) “The Path to Hydrogen Competitiveness: A Cost Perspective” hydrogencouncil.com.
- 9. 9 Carlos Andrés Vasco Correa DIPLOMADO: Producción y Usos del Hidrógeno Modulo 13: Consideraciones económicas en la implementación Competitividad del Hidrógeno Hydrogen Council (2021) “The Path to Hydrogen Competitiveness: A Cost Perspective” hydrogencouncil.com.
- 10. 10 Carlos Andrés Vasco Correa DIPLOMADO: Producción y Usos del Hidrógeno Modulo 13: Consideraciones económicas en la implementación Competitividad del Hidrógeno Hydrogen Council (2021) “The Path to Hydrogen Competitiveness: A Cost Perspective” hydrogencouncil.com.
- 11. 11 Competitividad del Hidrógeno Hydrogen Council (2021) “The Path to Hydrogen Competitiveness: A Cost Perspective” hydrogencouncil.com.
- 12. 12 Carlos Andrés Vasco Correa DIPLOMADO: Producción y Usos del Hidrógeno Modulo 13: Consideraciones económicas en la implementación Competitividad del Hidrógeno Hydrogen Council (2021) “The Path to Hydrogen Competitiveness: A Cost Perspective” hydrogencouncil.com.
- 13. 13 Carlos Andrés Vasco Correa DIPLOMADO: Producción y Usos del Hidrógeno Modulo 13: Consideraciones económicas en la implementación Competitividad del Hidrógeno IRENA (2020), Green Hydrogen Cost Reduction: Scaling up Electrolysers to Meet the 1.5⁰C Climate Goal, International Renewable Energy Agency, Abu Dhabi.
- 14. 14 Carlos Andrés Vasco Correa DIPLOMADO: Producción y Usos del Hidrógeno Modulo 13: Consideraciones económicas en la implementación Competitividad del Hidrógeno Nguyen, T., Abdin, Z., Holm, T., & Mérida, W. (2019). Grid-connected hydrogen production via large-scale water electrolysis. Energy Conversion and Management, 200, 112108. https://doi.org/10.1016/j.enconman.2019.112108 Grid-connected hydrogen production via large-scale water electrolysis
- 15. 15 Carlos Andrés Vasco Correa DIPLOMADO: Producción y Usos del Hidrógeno Modulo 13: Consideraciones económicas en la implementación Competitividad del Hidrógeno Nguyen, T., Abdin, Z., Holm, T., & Mérida, W. (2019). Grid- connected hydrogen production via large-scale water electrolysis. Energy Conversion and Management, 200, 112108. https://doi.org/10.1016/j.enconman.2019.112108 CANADA: Grid-connected hydrogen production via large-scale water electrolysis
- 16. 16 Carlos Andrés Vasco Correa DIPLOMADO: Producción y Usos del Hidrógeno Modulo 13: Consideraciones económicas en la implementación Competitividad del Hidrógeno Hydrogen Council (2021) “The Path to Hydrogen Competitiveness: A Cost Perspective” hydrogencouncil.com.
- 17. 17 Carlos Andrés Vasco Correa DIPLOMADO: Producción y Usos del Hidrógeno Modulo 13: Consideraciones económicas en la implementación Competitividad del Hidrógeno Hydrogen Council (2021) “The Path to Hydrogen Competitiveness: A Cost Perspective” hydrogencouncil.com.
- 18. 18 Carlos Andrés Vasco Correa DIPLOMADO: Producción y Usos del Hidrógeno Modulo 13: Consideraciones económicas en la implementación Competitividad del Hidrógeno
- 19. 19 Carlos Andrés Vasco Correa DIPLOMADO: Producción y Usos del Hidrógeno Modulo 13: Consideraciones económicas en la implementación Competitividad del Hidrógeno
- 20. 20 Carlos Andrés Vasco Correa DIPLOMADO: Producción y Usos del Hidrógeno Modulo 13: Consideraciones económicas en la implementación Competitividad: Ruta Colombia Fuente: Procolombia (2021)
- 21. 21 Carlos Andrés Vasco Correa DIPLOMADO: Producción y Usos del Hidrógeno Modulo 13: Consideraciones económicas en la implementación Competitividad: Ruta Colombia
- 22. 22 Carlos Andrés Vasco Correa DIPLOMADO: Producción y Usos del Hidrógeno Modulo 13: Consideraciones económicas en la implementación Competitividad: Ruta Colombia
- 23. 23 Modelación Determinística y Estocástica Platon, V., & Constantinescu, A. (2014). Monte Carlo Method in Risk Analysis for Investment Projects. Procedia Economics and Finance, 15, 393–400. https://doi.org/10.1016/s2212-5671(14)00463-8
- 24. 24 Modelación Determinística y Estocástica
- 26. 26 Modelación Estocástica Simulaciones Montecarlo Simulaciones en HOMER Pro US DOE – National Renewable Energy Lab
Notas del editor
- LCC is an important method to evaluate the total cost of a product or a system over its given lifetime [31,32]. By applying LCC into the early life cycle stage, changes are easier in terms of minimizing the LCC. There is no global approach that fits all situations and as the literature reveals the LCC discourse has been a long journey. Many methods have been proposed and are rather general in approach [31–33]. Although the methods are different, many of the main steps are similar to some of the first methods such as the steps in the method by Harvey [33]: Although LCC has been accepted as a methodology it is still being criticized. The main disadvantages of the LCC method come from the fact that it includes a future estimation and can lead to uncertain results. Despite the flaws of the LCC method it still provides a somewhat holistic universal method to evaluate and compare different investment opportunities. Hydrogen output is usually measured in terms of energy and therefore, similarly to electrical calculations, the cost can be presented in terms of cost per unit energy or mass of hydrogen
- Renewable hydrogen production costs continue to fall more swiftly than previously expected. Compared with the Hydrogen Council Study 2020 report, “Path to hydrogen competitiveness: a cost perspective”, this year’s update resulted in even more aggressive cost-down expectations for renewable hydrogen production. Three factors are driving this acceleration. First, capex requirements are dropping. We expect a significant electrolyzer capex decline by 2030 – to about USD 200-250/kW at the system-level (including electrolyzer stack, voltage supply and rectifier, drying/purification and compression to 30 bar). That is 30-50% lower than we anticipated last year, due to accelerated cost roadmaps and a faster scale-up of electrolyzer supply chains. For example, several electrolyzer manufacturers have announced near-term capacity scale-ups for a combined total of over approximately 3 GW per year. Second, the levelized cost of energy (LCOE) is declining. Ongoing reductions in renewables cost to levels as much as 15% lower than previously expected result from the deployment of at-scale renewables, especially in regions with high solar irradiation (where renewables auctions continue to break record lows). The strongest reductions are expected in locations with optimal resources, including Spain, Chile, and the Middle East. Third, utilization levels continue to increase. Large-scale, integrated renewable hydrogen projects are achieving higher electrolyzer utilization levels. This performance is driven largely by the centralization of production, a better mix of renewables (e.g., onshore wind and solar PV) and integrated design optimization (e.g., oversizing renewables capacity versus electrolyzer capacity for optimized utilization)
- We find that hydrogen can unlock approximately 8 per cent of global energy demand with a hydrogen production cost of USD 2.50 per kg, while a cost of USD 1.80 per kg would unlock as much as roughly 15 per cent of global energy demand by 2030. This does not imply that hydrogen will satisfy all of this energy demand by 2030, but it does showcase that hydrogen will have a significant role to play as a clean energy vector in the future energy mix. As mentioned in our prior report, we expect hydrogen may fulfil about 18 per cent of final energy demand by 2050.
- Key drivers for continued cost reduction include the industrialisation of electrolyser manufacturing (-25 per cent), improvements in electrolyser efficiency and operations and maintenance (-10 per cent), and the use of low-cost renewable power (-20 per cent). The latter will be region specific and depend highly on access to renewable resources (sun and wind). Regarding capex, a 60 to 80 per cent reduction from larger-scale manufacturing is expected by 2030. Important drivers of this drop include the shift from a largely manual production process to greater use of automation and ‘roll-to-roll’ streamlined production processes. Supporting factors include further technological improvements (like optimisation of catalyst loading), and increased system sizes, with associated scaling benefits. Moving from the 1 to 2 MW systems typically deployed today to, for instance, 80 to 100 MW systems can significantly decrease the cost contribution from auxiliary systems. In total, these improvements should reduce the capex from today’s USD 2 per kg of hydrogen produced to USD 0.50 per kg by 2030. As mentioned in the previous chapter, this number might be conservative: the underlying learning rate is notably more conservative than in other ‘new’ technologies like solar photovoltaics (PV) and wind power. Thus, actual cost decline could happen even faster and accelerate the competitiveness of renewable hydrogen from electrolysis even more. Higher efficiency results from incremental improvements in technology. The industry could increase lower heating value efficiency from around 64 to 68 per cent today for PEM/alkaline technology to about 70 per cent in 2030. Higher efficiency enables a smaller system using less electricity to produce the same amount of hydrogen, which would account for an approximate USD 0.40 per kg of hydrogen cost improvement. Additional O&M cost improvements should contribute another USD 0.20 per kg in cost cuts. The lower cost of electricity from renewables will contribute the biggest share of reduction in operational cost. In the offshore wind example, a 40 per cent cost decline from approximately USD 70 to 40 per MWh could occur in 2030, accounting for lower costs of around USD 1.30 per kg. Variations in renewables resources make renewable hydrogen from electrolysis production highly region specific. For example, solar paired with wind power in Chile should reduce hydrogen production cost to as low as USD 1.40 in 2030. Exhibit 14 shows the resulting production cost under different LCOE, utilisation, and electrolyser capex assumptions. The assessment also shows that even for a conservative assumption – an electrolyser capex of USD 500 per kW – access to renewables at USD 20 per MWh enables production of renewable hydrogen at about USD 2 per kg.
- Figure ES1 shows how up to 85% of green hydrogen production costs can be reduced in the long term by a combination of cheaper electricity and electrolyser capex investment, in addition to increased efficiency and optimised operation of the electrolyser. Today’s cost and performance are not the same for all electrolyser technologies (see Table ES1). Alkaline and PEM electrolysers are the most advanced and already commercial, while each technology has its own competitive advantage. Alkaline electrolysers have the lowest installed cost, while PEM electrolysers have a much smaller footprint, combined with higher current density and output pressure. Meanwhile, solid oxide has the highest electrical efficiency. As the ell stack is only part of the electrolyser facility footprint, a reduced stack footprint of around 60% for PEM compared to alkaline translates into a 20%-24% reduction in the facility footprint, with an estimated footprint of 8 hectares (ha)- 3 ha for a 1 GW facility using PEM, compared to 10 ha-17 ha using alkaline (ISPT, 2020). Gaps in cost and performance are expected to narrow over time as innovation and mass deployment of different electrolysis technologies rive convergence towards similar costs. The wide range in system costs is expected to remain, however, as this is very much dependent on the scale, application and scope of delivery. For instance, a containerised system inside an xisting facility with existing power supply is significantly lower cost than a new building in a plot of land to be purchased, with complete water and electricity supply system to be included, high purity hydrogen for fuel cell applications and high output pressure. Normally, numbers for system costs include not only cell stack, but also balance of stacks, power rectifiers, the hydrogen purification system, water supply and purification, cooling and commissioning – yet xclude shipping, civil works and site preparations. Notably, the numbers for 2020 are cost estimates for a system ordered in 2020, representing the lowest value the price can be (on the limit of zero profit). As the market scales up apidly, in the initial phase, the investment in manufacturing facilities must be recovered, therefore the gap between cost and price is currently higher than in 10 or 20 years from now. As a reference, an estimated investment of EUR 45- 9 million is required for each GW of manufacturing capacity (Cihlar et al., 2020).
- Figure ES1 shows how up to 85% of green hydrogen production costs can be reduced in the long term by a combination of cheaper electricity and electrolyser capex investment, in addition to increased efficiency and optimised operation of the electrolyser. Today’s cost and performance are not the same for all electrolyser technologies (see Table ES1). Alkaline and PEM electrolysers are the most advanced and already commercial, while each technology has its own competitive advantage. Alkaline electrolysers have the lowest installed cost, while PEM electrolysers have a much smaller footprint, combined with higher current density and output pressure. Meanwhile, solid oxide has the highest electrical efficiency. As the ell stack is only part of the electrolyser facility footprint, a reduced stack footprint of around 60% for PEM compared to alkaline translates into a 20%-24% reduction in the facility footprint, with an estimated footprint of 8 hectares (ha)- 3 ha for a 1 GW facility using PEM, compared to 10 ha-17 ha using alkaline (ISPT, 2020). Gaps in cost and performance are expected to narrow over time as innovation and mass deployment of different electrolysis technologies rive convergence towards similar costs. The wide range in system costs is expected to remain, however, as this is very much dependent on the scale, application and scope of delivery. For instance, a containerised system inside an xisting facility with existing power supply is significantly lower cost than a new building in a plot of land to be purchased, with complete water and electricity supply system to be included, high purity hydrogen for fuel cell applications and high output pressure. Normally, numbers for system costs include not only cell stack, but also balance of stacks, power rectifiers, the hydrogen purification system, water supply and purification, cooling and commissioning – yet xclude shipping, civil works and site preparations. Notably, the numbers for 2020 are cost estimates for a system ordered in 2020, representing the lowest value the price can be (on the limit of zero profit). As the market scales up apidly, in the initial phase, the investment in manufacturing facilities must be recovered, therefore the gap between cost and price is currently higher than in 10 or 20 years from now. As a reference, an estimated investment of EUR 45- 9 million is required for each GW of manufacturing capacity (Cihlar et al., 2020).
- Figure ES1 shows how up to 85% of green hydrogen production costs can be reduced in the long term by a combination of cheaper electricity and electrolyser capex investment, in addition to increased efficiency and optimised operation of the electrolyser. Today’s cost and performance are not the same for all electrolyser technologies (see Table ES1). Alkaline and PEM electrolysers are the most advanced and already commercial, while each technology has its own competitive advantage. Alkaline electrolysers have the lowest installed cost, while PEM electrolysers have a much smaller footprint, combined with higher current density and output pressure. Meanwhile, solid oxide has the highest electrical efficiency. As the ell stack is only part of the electrolyser facility footprint, a reduced stack footprint of around 60% for PEM compared to alkaline translates into a 20%-24% reduction in the facility footprint, with an estimated footprint of 8 hectares (ha)- 3 ha for a 1 GW facility using PEM, compared to 10 ha-17 ha using alkaline (ISPT, 2020). Gaps in cost and performance are expected to narrow over time as innovation and mass deployment of different electrolysis technologies rive convergence towards similar costs. The wide range in system costs is expected to remain, however, as this is very much dependent on the scale, application and scope of delivery. For instance, a containerised system inside an xisting facility with existing power supply is significantly lower cost than a new building in a plot of land to be purchased, with complete water and electricity supply system to be included, high purity hydrogen for fuel cell applications and high output pressure. Normally, numbers for system costs include not only cell stack, but also balance of stacks, power rectifiers, the hydrogen purification system, water supply and purification, cooling and commissioning – yet xclude shipping, civil works and site preparations. Notably, the numbers for 2020 are cost estimates for a system ordered in 2020, representing the lowest value the price can be (on the limit of zero profit). As the market scales up apidly, in the initial phase, the investment in manufacturing facilities must be recovered, therefore the gap between cost and price is currently higher than in 10 or 20 years from now. As a reference, an estimated investment of EUR 45- 9 million is required for each GW of manufacturing capacity (Cihlar et al., 2020).
- Achieving this level of cost improvement depends on the scale-up of demand and the associated increase in utilisation of distribution infrastructure. For example, the main cost drivers in the trucking distribution pathway are as follows: Increase in trucking capacity. Costs for gaseous and liquid hydrogen trucking should decrease by USD 0.10 to 0.20 per kg for typical distances of 300 to 500 km, due mainly to improved utilisation and lower equipment costs with rising scale. Increasing scale and density of filling centres. Increasing utilisation and scaling up capacity of truck filling centers and liquefaction plants should reduce costs further by about USD 0.50 per kg for both liquid and gaseous trucking. A further cost decline is expected from the increasing density of filling centres: a reduction of trucking distance by 100 km on average will reduce trucking costs by another USD 0.10 per kg. Scaling up demand and HRS size. Hydrogen refuelling stations are currently the highest cost element in the cost at the pump, accounting for about 70 per cent of total distribution and retail costs. Today’s high cost primarily results from the low utilisation of even small stations due to the limited uptake of fuel cell vehicles. A cost decline of about 80 per cent is possible, from roughly USD 5 to 6 per kg in 2020 to about USD 1 to 1.50 per kg in 2030. The savings consist of higher utilisation (USD -2 per kg), increasing station size (USD -1 per kg) and industrialisation of equipment manufacturing (roughly USD -0.80 per kg).
- 05 de Mayo de 2021 El ministerio de Minas y Energía de Colombia anunció que para el primer semestre de este año el país ya contará con una hoja de ruta para la implementación del hidrógeno verde como fuente de energía, no solo para atender la demanda local, sino también para exportar. En línea con lo anterior, el Ministerio de Minas y Energía y ProColombia presentan el documento “Perspectivas del Hidrógeno en Colombia” que expone las ventajas y oportunidades de esta fuente de energía para la consolidación y desarrollo de la matriz energética nacional.