Germany’s core hydrogen network and regulatory framework explained

Germany’s national hydrogen network is progressing rapidly, with the final hydrogen core network (HCN) proposal approved by the German regulator, the Bundesnetzagentur (BNetzA), on October 22, 2024. This proposal is a collaborative effort by natural gas transmission system operators (TSOs) united under FNB Gas, the German association of supra-regional gas transmission operators.

The HCN is the first step in establishing a nationwide hydrogen infrastructure in Germany. It will span 9,040km, connecting key domestic hydrogen production and offtake clusters with relevant import and storage facilities across the country. The network is projected to be operational by 2032. Approximately 56% of the hydrogen network will consist of converted natural gas pipelines, which will help reduce costs, while the remaining 44% will be newly constructed infrastructure.

The German HCN comprises a series of interconnected projects of several TSOs working on different segments of the trajectory that will eventually be linked together. Some of these projects have been designated as Important Projects of Common European Interest (IPCEI), allowing the German government to provide more state aid than typically permitted under internal competition rules.

Projects can also obtain Project of Common Interest (PCI) status, which identifies key cross-border infrastructure projects that connect the energy systems of EU countries. Projects of Mutual Interest (PMI) involve collaboration between an EU member state and non-EU countries. These projects must contribute to the EU’s decarbonization objectives, integrate renewable energy into the grid, and transmit renewable generation to major consumption centers and storage sites.

Germany’s geographic location in Europe, combined with its anticipated high demand for hydrogen, necessitate collaboration between TSOs in Germany and those in neighboring countries to facilitate hydrogen imports. Authorities estimate that 50% to 70% of Germany’s hydrogen demand will be met by imports in the long term, amounting to approximately 45 to 90 terawatt hour s per year by 2030.

Constructing new pipelines is 5.5 times more expensive than converting existing natural gas pipelines into hydrogen pipelines. The plans for the HCN are estimated to cost EUR 18.9bn by 2032. Most of these costs are attributed to newly built pipelines, even though they make up only 44% of the network.

The EUR 18.9bn required for the HCN should be financed through private funding. One of the main risks for investors is the significant uncertainty surrounding the development of the hydrogen market. To mitigate part of this risk, the German federal government has pledged EUR 3bn in financial support, which was approved by the European Commission. This state aid consists of financial guarantees for the TSOs that will build the HCN, reducing the risk of these projects and enabling them to secure better funding terms.

Germany is finalizing a new regulatory framework to govern the hydrogen TSOs, crucial for balancing costs and revenues during the network’s ramp-up phase. Regulatory frameworks are extremely complex, but simply put, they determine how and what the TSOs may earn in the coming years, as they are natural monopolists in their regions. In the EU, each member state has its own regulatory framework for TSOs. Generally, these frameworks cap the TSOs’ revenues but often incorporate some form of competitive incentive.

One of the challenges with the HCN is that it needs to be built for a mature market that has yet to develop. This means that in the early years the network will be significantly over-dimensioned because there will be very few customers and low volumes of hydrogen being transported, while the costs for building the HCN are very high. These high costs cannot be passed on to off-takers through high tariffs during the early years. For instance, if only one customer were to emerge in the first year, they would have to bear the full annual costs of the network, which would deter any customer from being the first to step in. Therefore, the regulator, BNetzA, will set a lower tariff that does not reflect the actual costs. This means that TSOs will charge this tariff to their customers. As TSOs will not be able to cover their costs with these lower tariffs, they require some form of financial compensation during the ramp-up phase.

The regulatory framework addresses this issue by calculating an average annual network cost over a transitional period, known as the payback period, which runs from 2025 to 2055. During this period, the BNetzA has modeled a certain development in the volumes of hydrogen that need to be transported. This model uses announced hydrogen production, consumption, storage, and import projects as input. Additionally, two other instruments are introduced: a uniform ramp-up tariff and an amortization account.

Uniform ramp-up tariff

The uniform ramp-up tariff is a standardized fee applied to all entry and exit points throughout Germany. It is called a “postage stamp” fee because it does not differentiate based on entry or exit location or physical distance. During the entire transitional period from 2025 to 2055, TSOs will charge this uniform ramp-up tariff to all their customers. The tariff will be indexed annually according to the overall consumer price index.

By paying the ramp-up tariff, the customer books a non-interruptible annual capacity of the pipeline at an entry point and an exit point. This capacity is measured in EUR per kWh per hour per annum (EUR/kWh/h/a). This means that for every hour of the day, the TSO allocates a specific pipeline capacity, measured in kWh, to the customer for the entire year, regardless of whether they use it or not.

Amortization account

Given that in the early years only a small number of customers will use the hydrogen network and pay the ramp-up tariff, the revenues will not cover the annual costs of the TSOs. To address this shortfall, each TSO will receive funds from an amortization account to compensate for the difference between their ramp-up revenues and actual costs on an annual basis.

As the hydrogen market matures, more customers will start using the network and paying the ramp-up tariff, leading to growing annual revenues for the TSOs. Eventually, these annual revenues will surpass the annual costs of the network. At that point, the TSOs must use the annual surplus revenues to repay the amortization account, which provided them with the compensation in the early years.

The repayment period will run until December 31, 2055. If the amortization account still has a negative balance on that date, the federal government will repay 76% of the outstanding negative balance, and the TSOs will cover the remaining 24%. If it becomes evident that the HCN will not reach a cost-covering level by 2055, the federal government can choose to terminate the amortization account from the end of 2038 onward. If this happens, the TSOs will incur a loss of 16%, increasing by 0.5 percentage points each year beyond 2038, up to 24% in 2055. If a TSO is unable to repay their share of the negative balance, they must transfer assets to the federal government at net residual value to cover the losses. The federal government guarantees that any outstanding balances on the amortization account will be settled by 2055. The TSOs have until 2057 to repay their share to the federal government.

The amortization account is a special purpose vehicle (SPV) owned and mandated by the participating HCN TSOs, who are its sole shareholders. It is financed with loans from the German development bank, the Kreditanstalt für Wiederaufbau. The expenses, including interest expenses and management fees related to the amortization account, will be charged annually to each TSO. As a borrower, the SPV is backed by a guarantee from the federal government.

The right level for the ramp-up tariff

The BNetzA will set the ramp-up tariff at a level they expect will balance the amortization account by 2055. When setting this tariff, the BNetzA must consider two conflicting priorities. On the one hand, a higher ramp-up tariff increases the likelihood and speed at which the amortization account will be balanced. On the other hand, a higher ramp-up tariff makes the HCN less attractive to potential customers, reducing the likelihood of balancing the amortization account by 2055.

An expert opinion by the Fraunhofer-Institute, prepared on behalf of the BnetzA, indicates that an average network tariff between EUR 15 per kWh/h/a to EUR 20 per kWh/h/a has a high probability of balancing the amortization account by 2055. The Fraunhofer-Institute considers this tariff “fundamentally marketable,” although it is three to four times higher than the current natural gas tariff.

The organization also assessed a highly adverse scenario where the hydrogen market develops much more slowly and faces other setbacks. In this scenario, the ramp-up tariff would need to increase to EUR 35 per kWh/h/a to balance the amortization account by 2055. The Fraunhofer-Institute considers this tariff “beyond the level that is marketable,” meaning it would be too expensive for customers, resulting in the failure of the financing model.

From this, it can be concluded that the BNetzA will set the ramp-up tariff somewhere between EUR 15 per kWh/h/a and EUR 35 per kWh/h/a. The ramp-up tariff will be reviewed every three years to ensure it remains appropriate. If analysis reveals that the probability of balancing the amortization account by 2055 deviates significantly, the tariff can be adjusted accordingly. The first review will be on January 1, 2028.

If, at some point during the transitional period, the BNetzA concludes that settling the amortization account by December 31, 2055, is not achievable, it will set the ramp-up fee at the lowest possible rate that still generates the highest possible total revenue.

If the amortization account is balanced around 2055, the BNetzA will switch to a normal standard cost-covering tariff, similar to what is used for natural gas TSOs.

Regulatory return on equity is set at 6.69%

Furthermore, since these operators are monopolists in their regions, the regulatory framework for hydrogen TSOs limits the returns that may be made on invested capital. Infrastructure projects like the HCN require large investments over a relatively condensed period, while assets such as pipelines, compressor stations, and control stations, are typically amortized over 30 to 55 years. For the HCN, most assets have a shortened useful life of 35 years.

In Germany, TSOs are allowed to have 40% of their capital in the form of equity. The BNetzA sets the return on equity (RoE) for this equity. In this regulatory period, starting January 1, 2025, TSOs may earn a pre-tax RoE of 6.69% for both converted and new hydrogen assets. The regulatory period lasts three years, with the first review scheduled for January 1, 2028.

The adequacy of a 6.69% pre-tax RoE for hydrogen TSOs remains uncertain, given the considerable utilization and regulatory risks involved. RaboResearch identifies significant utilization risk, which includes the possibility that the hydrogen economy may not develop as expected, and the risk that the customer numbers and bookings may fall short of projections. So far, we have witnessed numerous delays and even cancellations in hydrogen project developments, and we anticipate more in the future.

There is also a significant regulatory risk. The build-up of debt in the amortization account is likely to persist for an extended period, resulting in a shorter and increasingly backloaded time frame to settle the balance. If the hydrogen market rollout does not proceed as planned, TSOs may have to absorb up to 24% of the losses from the amortization account. This raises the question of whether a RoE of 6.69% will provide enough comfort to investors in such a case. Again, RaboResearch highlights the risk of further delays and cancellations of hydrogen projects. This situation suggests that TSOs may need to draw more funds from the amortization account, and for a longer period than initially expected, pushing the breakeven point further back in time and leaving less time to settle the balance.

Lastly, the pre-tax RoE for newly built assets for electricity TSOs is currently 6.74%, which is higher than the 6.69% for hydrogen TSOs under the new regulatory framework, even though the perceived risks for electricity TSOs are much lower. Additionally, the current natural gas pipelines, which will eventually be converted, have a RoE of 5.07%. After conversion, the RoE will increase to 6.69%. Although this represents a higher return, the associated risks are also significantly higher, as we previously explained.