Hydrogen price

For the economic evaluation, this price is compared with the costs of cheaper hydrogen production options, like natural gas reforming. With an operating time of 6750 h and a natural gas price of 2.35 ct/kWh, hydrogen costs are at 5.3 ct/kWh. This is much lower than the surplus wind pathway, if an electricity price of 4 ct/kWh is assumed. Further calculations have been performed, to show at what natural gas price natural gas reforming would reach hydrogen costs from surplus wind electricity the hydrogen price of surplus wind electricity is only reached at a natural gas price of 5.5 ct/kWh. If a carbon tax of 20/t is introduced, the necessary natural gas price is 5 ct/kWh (compare Fig. 16.10). 

Final hydrogen selling price was calculated using the capital and operating cost results from the hydrogen alternatives study and the H2A analysis tool. The cost data was subsequently entered into the NHI analysis framework database, and further calculations have been done using the data from the Shaw base cases. Results of those calculated hydrogen prices are reported below. 

Figure 1 Varying hydrogen price for cost model variations...

The formal approach taken to evaluate nuclear hydrogen technologies provides useful results for comparison of the various technologies. The range of relative variation in product hydrogen price in the evaluations is the result of several factors. One of the most significant is the uncertainty of new technology performance in flow sheets and simulation models that drive the process efficiency. These... 

These conclusions justify continuing the periodic evaluation of the candidate process hydrogen prices and maintenance of the NHI framework with a database of cost input factors as the technologies and designs mature. 

Basic investment and operating cost information was obtained from information in our files plus some input from Reference (1) adjusted to mid-1979 dollars. Natural gas is the assumed feedstock at a base cost of 2.00/106 Btu. Based on the guidelines, the capital cost of a 100 million SCF/day plant is 66.3 million, and the hydrogen price is 1.61/103 CF or 4.76/106 Btu. 

Basic information on facilities investment, residual oil, utilities, and operating labor for a 100 million SCF/day plant was taken from Reference (1). Capital cost for a 100 million SCF/day hydrogen plant is 178 million. With residual oil feedstock at 15/barrel, hydrogen price is 2.69/103 SCF. 

Basic information on facilities investment, coal, utilities, and operating labor for the 100 million SCF/day base case was obtained from Reference (JO and adjusted to a mid-1979 basis. Based upon the economic evaluation guidelines for 100 million SCF/day hydrogen production with Wyoming coal at 20/ton ( 1.17/106 Btu), the total capital required is 298.8 X 106 and the hydrogen price is 3.66/103 SCF, or 11.20/106 Btu. For Illinois coal at 20/ton, total capital required is 270.1 X 106 and hydrogen price is 3.19/103 SCF, or 9.76/106 Btu. 

Basic investment and operating cost information were scaled down to 100 million SCF/day from a larger IGT design (2). The total capital cost, according to the guidelines set in Table 1, is 237 million. At the base coal cost of 17.7/ton ( 1.00/106 Btu), hydrogen price is 2.56/103 CF, or 7.84/106 Btu. 

Sensitivity Analysis. The sensitivity of hydrogen price to the following variables was calculated raw materials cost, plant capital cost, stream factor, plant size, and by-product credits. 

Raw Materials Cost We assumed two or more raw material costs and then calculated the hydrogen price using the following procedure for each raw material cost ... 

Investment Changes We assumed two facilities investment costs, one 20% above and the other 20% below the base case, and calculated the hydrogen price using the same procedure as for the base case. 

Stream Factor Changes We assumed that for stream factors of 30%, 50%, and 70%, the raw materials requirement would be reduced proportionately, but capital-related costs do not change from the base case. We calculated the hydrogen price the same way as in the base case. 

The raw materials, utilities, and by-products were changed directly by the ratio of plant capacity. The hydrogen price was calculated using the same procedure as in the base case. Variations between the 0.6 and 0.7 power factor have only a small effect on hydrogen price. The assumption of many modules for electrolysis suggests a higher exponent. 

Figure 6 shows the sensitivity of hydrogen price to feedstock price, all plotted on the same scale. It should be noted that the "feedstock for electrolysis is electric power, not primary fuel, so that capital costs and inefficiencies associated with power generation are included in the raw material cost. The circles on this figure represent the base case for our calculations and reflect approximately realistic values for raw material costs for large-scale plants in 1979. 

Figure 7 shows the sensitivity of hydrogen price to variations in plant cost, and also exhibits the considerable differences in plant cost assumed for the base case — believed to be reasonable... 

It can be seen from Figure 6 that by far, the least expensive is hydrogen by steam reforming. This results from the low plant cost for this system, which is only a fraction of that for other processes. Even though the cost of the natural-gas feed, on an energy basis, is about twice that of coal, hydrogen price is about half that from the Koppers-Totzek and Steam-Iron Processes, if by-product power from the latter is sold at 2d/kWhr. At 4c/kWhr, the price drops to less than that for partial oxidation (Figure 11). 

Figure 7. Effect of facilities investment on hydrogen price for 100 X 106 scfd of hydrogen by various processes...

Figure 9. Effect of plant capacity on hydrogen price hy various processes...

The coal-to-hydrogen opportunity is real, and coal-derived hydrogen prices probably will not be subject to the market fluctuations that characterize natural gas prices. Coal-to-hydrogen production is already competitive elsewhere in the world, although economic considerations will dictate... 

The aim of using off-peak electricity is to reduce the electricity cost and to make the power plant investment more effective. However, in the case of off-peak electricity, the hydrogen production plant has a disadvantage of low availability. In the CRIEPI study, the hydrogen price at hydrogen stations for fuel-cell vehicles was assessed with a simple model. The model can take the plant size, plant availability and cost of electricity into account. 

The results showed that hydrogen prices at hydrogen stations, produced at both on-site and offsite production plants, were approximately 64 cn/Nm . In the case of off-peak electricity, the hydrogen price, produced at off-site production plants, can be decreased. On the other hand, it is difficult to decrease the hydrogen price, produced at on-site production plants, because of low availability. 

For the forecourt case, electricity represents 58% of the cost of the hydrogen, and the capital costs represent only 32%. For the small forecourt case, the electricity contribution drops to 35% while the capital costs become the major cost factor at 55%. In the neighborhood case, the capital costs increase to 73%, but electricity costs are significant at 17%. This analysis demonstrates that for all systems, the electricity price is a contributor to the hydrogen price, but for small-sized electrolyzers, capital costs are more significant. 

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