D2a.3 – Electrolyzer business case in a standalone hydrogen area and the effect of adding firm/non-firm grid tariffs

With increasingly higher amounts of renewable, fluctuating power expected by 2040 and 2050, electricity grid congestion is a difficult challenge to be faced by the grid operators in The Netherlands, both at transmission and distribution levels. Current mechanisms to mitigate grid congestion, such as long-term grid reinforcement, can be very costly and/or unfeasible to match these targets, due to reasons such as land availability, specialized labour or raw material scarcity. Bilateral agreements for re-dispatching can also be expensive, and it may affect several parties within the value chain. The limitations in power availability due to current and future grid congestion are relevant when considering the business case of new assets that consume power, such as electrolyzers.

This study analyses the effect in the business case of an electrolyzer of contract-based strategies at the Distribution System Operator (DSO) level, when combining a multi-energy asset of power generation (solar) and consumption (electrolyzer) within the same asset owner. The case study chosen is inspired by the H2 Hollandia pilot in Drenthe, with 115 MW of solar power and a 5 MW electrolyzer. Following the spirit of the ATR85 proposal for transmission rights, a similar set of tariffs is set here: 15% power can be restricted at selected time slots, providing in exchange a reduction in the grid tariff (non-firm tariffs). It is investigated if this can positively affect the business case of the electrolyzer, using the Levelized Cost of Hydrogen (LCoH) as a metric. In addition, subcases restricting consumption and generation and an exploration of different relative sizes of the electrolyzer and the grid availability for a fixed solar park and firm/non-firm have been explored. These cases have been tested for two purchasing strategies of green power: purchasing from any source only when it is fully green (using grid price as a proxy to determine this at flexible pricing based on the market rate) or with a dedicated wind farm with a fixed Power Purchase Agreement (PPA) price. The explicit impact on the distribution grid in an area and at a particular substation has not been modelled in this study, and only qualitative insights in this aspect can be considered.

The results of the study indicate that, if the infrastructure and other conditions (e.g., off-taker agreements) are present, grid tariffs could be one of the relevant incentives (in combination with others) to bring hydrogen production to certain areas. The best result was achieved with the flexible pricing purchasing strategy, where a reduction of around 0.3 EUR/kg was achieved in the LCoH when using a non-firm grid tariff compared to a firm tariff. In this case, the grid tariff was reduced from around 150 EUR/MWh to around 70 EUR/MWh, for less than 1% of reduction of the utilization factor of the electrolyzer due to the restrictions in consumption.
However, this positive effect was not always observed. For the fixed PPA strategy, the LCoH remained approximately constant for firm and non-firm tariffs. This is due to the fact that the reduction in tariff and utilization factor of the electrolyzer had approximately the same positive and negative effects, respectively, with less OPEX but less hydrogen production. A modest decrease in the monthly LCoH profiles variability was achieved, resulting in a more stable overall LCoH along the year.
Introducing a second component of a grid tariff reduction, by reducing further the consumption tariff but restricting generation as well (suitable for assets with both generation and consumption), did not result in a positive impact in the LCoH compared to the other flexible tariffs for the conditions tested.

In a sizing optimization study of the electrolyzer capacity and the grid connection/PPA usage for a fixed solar park, flexible grid tariffs usually promoted solutions with more usage from the grid. In the case of a fixed PPA pricing scheme, a region with larger electrolyzer sizes (in the order of 20 MW, compared to the original 5 MW) were seen as the most cost-effective solutions regarding the LCoH.

This work highlights that non-firm tariffs could potentially present an opportunity to encourage the placement of electrolyzers in certain areas and/or to improve the business case of a system composed of renewable energy assets and an electrolyzer. However, their specific implementation may require significant tailoring to each asset/value chain. The willingness of flexible delivery of hydrogen from the side of the off-taker, purchasing agreement strategies, and also other elements out of scope of this study, such as energy storage solutions, are elements that may largely affect the impact of these tariffs. In addition, this study only included restrictions at random times within specific months and hours. In certain substations, patterns may be present that could allow for further benefits, synergizing the flexibility of the asset and the grid tariff contract conditions. These, and a more holistic analysis at qualitative/quantitative level of the costs associated with reducing congestion outside of the asset owner, such as at DSO and societal levels, could lead to other positive dimensions which were not part of the scope of this study.