# The impact of temporal hydrogen regulation on hydrogen exporters and their
domestic energy transition

Leon Schumm  Hazem Abdel-Khalek  Tom Brown  Falko Ueckerdt  Michael Sterner
Maximilian Parzen  Davide Fioriti  Research Center on Energy Transmission and
Storage (FENES), Faculty of Electrical and Information Technology, University
of Applied Sciences (OTH) Regensburg, Seybothstr. 2, 93053 Regensburg, Germany
Department of Digital Transformation in Energy Systems, Institute of Energy
Technology, Technische Universität Berlin, Fakultät III, Einsteinufer 25 (TA
8), 10587 Berlin, Germany  Fraunhofer Research Institution for Energy
Infrastructures and Geothermal Systems IEG, Gulbener Straße 23, 03046 Cottbus,
Germany  Albert-Ludwigs Universität Freiburg, Faculty of Environment and
Natural Resources, Tennenbacher Str. 4, 79106 Freiburg im Breisgau, Germany
Potsdam Institute for Climate Impact Research, Telegrafenberg, 14473 Potsdam,
Germany  University of Edinburgh, Institute for Energy Systems, EH9 3DW
Edinburgh, United Kingdom  University of Pisa, Department of Energy Systems,
Territory and Construction Engineering, Largo Lucio Lazzarino, 56122 Pisa,
Italy  Lead contact

###### Abstract

As global demand for green hydrogen rises, potential hydrogen exporters move
into the spotlight. However, the large-scale installation of on-grid hydrogen
electrolysis for export can have profound impacts on domestic energy prices
and energy-related emissions. Our investigation explores the interplay of
hydrogen exports, domestic energy transition and temporal hydrogen regulation,
employing a sector-coupled energy model in Morocco. We find substantial co-
benefits of domestic climate change mitigation and hydrogen exports, whereby
exports can reduce domestic electricity prices while mitigation reduces
hydrogen export prices. However, increasing hydrogen exports quickly in a
system that is still dominated by fossil fuels can substantially raise
domestic electricity prices, if green hydrogen production is not regulated.
Surprisingly, temporal matching of hydrogen production lowers domestic
electricity cost by up to 31% while the effect on exporters is minimal. This
policy instrument can steer the welfare (re-)distribution between hydrogen
exporting firms, hydrogen importers, and domestic electricity consumers and
hereby increases acceptance among actors.

###### keywords:

Energy Transition, Hydrogen regulation, Hydrogen export, Climate-neutral,
Domestic prices, Hydrogen prices, Power-to-X

††journal: Nature Communications

Summary

## Introduction

The global energy environment is experiencing fundamental upheaval, driven by
the need to reduce greenhouse gas emissions and transition to a low-carbon
future. In this context, hydrogen has emerged as a viable clean energy carrier
capable of addressing the issues of decarbonizing numerous sectors such as
industry, transport, heating and power generation. A growing number of
countries are investigating green hydrogen production and use as a crucial
component of their strategy to cut greenhouse gas emissions and meet ambitious
climate targets. Simultaneously, several countries are positioning themselves
as potential exporters of hydrogen and Power-to-X products, discovering an
opportunity to leverage their renewable energy resources and technological
advances. These countries are expected to play a substantial role in the
global energy market by supplying clean hydrogen and therefore contributing to
global decarbonization efforts. However, pursuing both (on-grid) hydrogen
exports and national energy transition raises questions on welfare
redistribution, prices and co-benefits that require in-depth analysis,
additionally shining a light on the role of temporal hydrogen regulation.

Morocco serves as a blueprint for investigating these dependencies. Morocco,
which has vast solar and wind resources 1, 2, 3, has proposed ambitious
renewable energy adoption objectives, displaying a commitment to lowering its
own greenhouse gas emissions 4. At the same time, the country is strategically
positioned to deploy its renewable energy potentials to export green hydrogen,
opening the door to substantial economic opportunities and local value chains
5. Furthermore, the country is a net importer of energy 6, and green hydrogen
could help reduce its dependency on energy imports. The proximity to Europe,
which is expected to be a major hydrogen importer, makes Morocco an attractive
potential exporter.

These conditions are the motivation of several studies 7, 8, 9, 10, 11, 12,
13, 14 examining the potential of hydrogen in Africa and synergies with
European demand. A more detailed study of Morocco has been undertaken by
Boulakhbar et al.15 examining challenges in integrating Renewable Energies,
Khouya et al.16 determining the Levelized Cost of Hydrogen based on
concentrated solar power and wind farms, and Touili et al.2 investigating the
potential of hydrogen from solar energy. Hampp et al.17 investigates various
PtX products and their transportation to Europe, and Eichhammer et al. 18
highlights diverse opportunities and challenges related to exporting hydrogen
and Power-to-X products from Morocco. While several studies 17, 8, 7 have
examined the potential of hydrogen as a low-carbon energy carrier and others
have explored various countries’ climate targets and aspirations 15, a
substantial research gap remains regarding the integrated investigation of
both perspectives.

Apart from hydrogen exports and domestic climate change mitigation, temporal
hydrogen regulation plays a decisive role in prices for domestic consumers and
hydrogen exporters. Temporal hydrogen regulation defines the rules for green
hydrogen production when there is no direct connection between the
electrolyser and green electricity production. Temporal matching in selected
European countries is investigated in Zeyen et al.19, whereas Ruhnau et al.20
points out benefits of relaxing simultaneity requirements of renewable
electricity (RE) supply and hydrogen generation. The effect of regulatory
options on social welfare and carbon emissions is assessed in Brauer et al.21.
The interplay of additionality criteria and time matching requirements is
investigated in Giovanniello et al.22, highlighting how additionality drices
the emissions impact of temporal hydrogen regulation. While Zeyen et al.19
contextualizes the role of temporal hydrogen regulation with decarbonization
scenarios of Germany and Netherlands, none of the mentioned studies fully
integrates domestic climate change mitigation and temporal hydrogen regulation
scenarios. Furthermore, none of these studies looked into exports in depth.

Numerous studies focus exclusively on either hydrogen exports, domestic
climate mitigation or temporal hydrogen regulation, without discussing the
complex relationship between these three dimensions. These studies miss
interactions between on-grid hydrogen electrolysis and the domestic
electricity system, fail to uncover potential synergies and conflicts for both
hydrogen exporters as well as domestic electricity consumers with respect to
different temporal hydrogen regulation regimes.

The novelty of our study is the development of a sector-coupled energy model
for the target region, the inclusion of modelling the temporal hydrogen
regulation, and the evaluation of the synergies among hydrogen exports,
domestic energy transition and hydrogen regulation. Additionally, we present a
broad scenario vector, sweeping along these three dimensions:

  1. 1.

Domestic climate change mitigation: The domestic climate change mitigation
varies between 0–100% based on Morocco’s current emissions of 72 MtCO2e,

  2. 2.

Hydrogen export: The hydrogen export volume varies from 1–120 TWh, in
accordance with Morocco’s hydrogen export ambitions of 114.7 TWh/a and

  3. 3.

Temporal hydrogen regulation: The temporal matching (of additional renewable
electricity and the electrolyser electricity demand) varies between: no
regulation, annual, monthly and hourly matching.

This three-dimensional scenario space results in 264 model runs (excluding
sensitivity analysis) to grasp the full extent of the interaction between
various parameters. A 3-hourly resolution is chosen to capture energy system
dynamics (e.g. RE generation profiles, energy storage operation) with its
diurnal and seasonal variations in energy supply and demand. A similar study
23 finds minor underestimation of short-term battery storage and onshore wind
and minor overestimation of solar photovoltaics (PV) and hydrogen storage
compared to an hourly resolution, overall justifying the reduction of the
model size. A spatial resolution of 14 nodes represents the geographical
heterogeneity of RE resources, demand centers and energy networks.
Furthermore, the spatial resolution provides insights into land use conflicts
and competing RE resources as well as a spatial differentiation of export
ports. Since the 14 nodes align with the Global Administrative Areas level 1
regions, policy advisement can be tailored to specific regions considering
domestic needs and constraints.

To investigate interactions between hydrogen exports, domestic climate change
mitigation and temporal hydrogen regulation, this research paper presents a
fully sector-coupled capacity expansion and dispatch model of Morocco, which
includes both gas pipelines and electricity networks. By examining various
hydrogen export volumes, climate targets and temporal matchings, we evaluate
the potential impact of hydrogen exports on domestic electricity consumers
and, vice versa, interactions of domestic climate change mitigation on
hydrogen exporters. Shortcomings of studies on highly renewable energy systems
in Africa as low temporal and spatial resolutions as well as the lack of
sector-coupled energy models as pointed out in Oyewo et al.24 are tackled in
this study. The analysis of Morocco’s energy system contributes to the
expanding research that aims to inform policymaking and decision-making
regarding sustainable energy transitions. This study provides valuable
insights into the pathways unlocking synergies and reducing conflicts between
hydrogen exports and national energy transition, enabling Morocco and other
potential exporting regions to follow a harmonious and sustainable trajectory
while facing similar energy system planning challenges.

Chapter Introduction presents Morocco’s hydrogen strategy and climate targets
and outlines potential conflicts and synergies between these two goals.
Introducing the results along these three dimensions step-by-step, Results
evaluates synergies and conflicts based on prices and total cost for domestic
electricity consumers and hydrogen exporters, with emphazised consideration of
temporal hydrogen regulation. These results are contextualized along policy
recommendations in the Discussion. Methods presents the applied sector-coupled
energy model and scenario dimensions required to expose the export-mitigation-
regulation nexus.

### Hydrogen export strategy and climate targets

Morocco has implemented various strategies and policies to reach its climate
targets and promote hydrogen exports. These include programs on the expansion
of RE, the development of hydrogen for domestic demands and exports as well as
climate targets 25, 4.

Figure 1 shows the hydrogen strategy of Morocco, including national and export
demands. By 2030, the total hydrogen demand adds up to 13.9 TWh/a and ramps up
to 67.9 TWh/a in 2040 and 153.9 TWh/a in 2050, clearly listing higher demands
for export than for domestic use. The hydrogen generation is backed by 5.2 GW
of RE in 2030, 23 GW in 2040, and 57.4 GW in 2050 in the export sector. To
cover the national demand of hydrogen, a Renewable Energy deployment of 1.6 GW
in 2030, 7.0 GW in 2040 and 10.3 GW in 2050 is planned in Morocco’s Hydrogen
Strategy25.

In addition to the hydrogen strategy, Morocco has obliged to climate targets.
Figure 2 displays the historical emissions and targets of Morocco. According
to the self-defined national climate pledges under the Paris Agreement
(NDC’s), Morocco aims to limit historically rising greenhouse gas emissions to
75 MtCO2e (conditional) respectively 115 MtCO2e (unconditional) excluding
LULUCF by 2030 4. As stated by the Climate Action Tracker4, Morocco has not
yet submitted a net-zero target.

Both the hydrogen export strategy and climate targets imply a substantial
expansion of RE capacities. Furthermore, both strategies require an energy
infrastructure development of e.g. electricity grid, hydrogen pipelines,
$\mathrm{CO_{2}}$ network, ports and a considerable scale-up of electrolysers.
Limited resources (e.g. land availability, renewable potentials, workforce,
capital) require careful planning to minimize conflicts and maximize possible
synergies.

Figure 1: Hydrogen Strategy of Morocco 25. The export volume rises up to 115
TWh/a in 2050, the national demand up to 40 TWh/a in 2050. Figure 2: Morocco’s
historical CO2 and greenhouse gas emissions (GHG). While emissions are rising,
emission targets are in the range between 75 MtCO2e (conditional) and 115
MtCO2e (unconditional).

## Results

(a) Fixed (1 TWh) export and 0–100% domestic climate change mitigation

(b) Fixed (0%) domestic climate change mitigation and 1–120 TWh/a export

Figure 3: Electricity supply and demand at fixed export levels and increasing
domestic climate change mitigation (3(a)) and vice versa (3(b)). Increasing
domestic climate change mitigation first phases out carbon-intensive coal
generation in favor of CCGT, at medium to high domestic climate change
mitigation the electricity system is fully renewable supported by flexibility
through Vehicle-to-Grid (V2G) and sector coupling. Increasing electricity
demands include Battery Electric Vehicles (BEV) and hydrogen generation for
other sectors. At increasing hydrogen exports the additional electricity
required for hydrogen electrolysis is covered by onshore wind and solar PV, as
imposed by the temporal hydrogen regulation.

### Domestic climate change mitigation increases the domestic electricity
demand

First of all, we investigate the supply and demand of Morocco’s electricity
system depending on domestic climate change mitigation (dimension 1). Figure
3(a) depicts the supply and demand of the electricity system at increasing
climate mitigation ambitions from 0% to 100%. At low climate ambitions, the
electricity demand is mainly covered by coal power, existing (brownfield)
capacities of onshore wind, hydro, and combined-cycle gas turbines (CCGT) play
only a minor role. At increasing domestic climate change mitigation, coal
power is phased out in favour of solar PV, furthermore a fuel switch from coal
to gas (CCGT) is observable at increasing emission reductions. At medium
climate mitigation ambitions, the dipatchable power in the electricity system
is provided by CCGT. Further increasing the climate ambitions, wind onshore
and especially solar PV penetrate and dominate the electricity system
complemented by dispatchable power from Vehicle-to-Grid providing an almost
fully renewable electricity sector at 100% emission reduction.

At 70% and above, the electricity demand of eletrolysers increases
substantially to supply hydrogen allowing a switch from fossil oil products to
Fischer-Tropsch fuels in various sectors (s. Fig. S7). The Fischer-Tropsch
demand in the transport sector increases, even though the increasing Battery
Electric Vehicle (BEV) diffusion is counterbalancing the demand for oil
products (see Supplementary Information section Diffusion of Battery Electric
Vehicles). Both electrolysers and BEVs drive the electricity demand
substantially, up to two times of the domestic end-use electricity demand.
Additionally, the electricity demand for air heat pumps increases, supporting
the defossilisation in the heating sector and supplying heat for Direct Air
Capture required for synthetic fuels.

### Hydrogen exports require a multiple of the domestic electricity demand

Here, we analyse the hydrogen export ramp up (dimension 2). The electricity
supply at increasing hydrogen exports is displayed in Figure 3(b). The
deployment of hydrogen exports requires a scale up of onshore wind and solar
PV accordingly, as defined by the green hydrogen constraint outlined in Green
hydrogen policy. Without the temporal hydrogen regulation, the additional
electricity demand of hydrogen exports is covered by coal power plants and
CCGT (by increasing the capacity factor of existing brownfield coal and CCGT
capacities) and an expansion of open-cycle gas turbines (OCGT) installation
and supply as pointed out in Figure S8. In contrast to the exponential
increase of electricity demand observable at increasing climate mitigation
ambitions displayed in Figure 3(a), the electricity demand increases linearly
with the hydrogen export ambitions.

(a) Relative cost of electricity for domestic customers (normalized to 1 TWh/a
hydrogen export)

(b) Relative cost of hydrogen for exporters (normalized to 0% domestic climate
change mitigation)

Figure 4:  Cost for domestic electricity consumers (4(a)) and hydrogen
exporters (4(b)), normalized to costs at 1 TWh/a hydrogen export (4(a)) and to
0% CO2 reduction (4(b)) at each domestic climate change mitigation level.
Domestic electricity consumers profit from increasing hydrogen exports,
especially at low domestic climate change mitigation and high exports.
Hydrogen exporters profit from domestic climate change mitigation at medium
mitigation efforts. Both (4(a)) and (4(b)) include possible pathways of i)
quick exports and slow climate change mitigation, ii) balanced exports and
mitigation and iii) slow exports and quick climate change mitigation. Years
are illustrative.

### Domestic climate change mitigation and hydrogen export show co-benefits

In an integrated analysis of domestic climate change mitigation (dimension 1)
and hydrogen exports (dimension 2) is study outlines that both domestic
climate change mitigation and hydrogen exports profit from each other and show
co-benefits. In this Section, we i) show the effects of hydrogen exports on
domestic electricity prices, ii) the role of domestic climate change
mitigation on hydrogen export cost, and lastly iii) common co-benefits.

First, Figure 4(a) shows the cost for domestic electricity consumers subject
to mitigation and hydrogen export volumes. The costs are normalized to costs
at 1 TWh/a Hydrogen export at each domestic climate change mitigation level,
displaying relative changes for domestic electricity consumers induced by
hydrogen exports at a certain domestic climate change mitigation. Hydrogen
exports decrease the relative domestic electricity cost by up to 45%,
especially at mitigation below 40% and exports above 50 TWh. In these ranges,
the fossil dominated domestic electricity system profits from excess green
electricity originating from additional renewable energy capacities required
for hydrogen export. The more the domestic electricity system is decarbonized
(domestic climate change mitigation above 50–60%), the weaker is the decrease
of domestic electricity prices with hydrogen exports. The only increase of
cost induced by hydrogen exports is observable at a low climate change
mitigation of 10% and exports of 20 TWh.

Second, Figure 4(b) shows the cost of hydrogen exports subject to mitigation
and hydrogen export volumes. The costs are normalized to costs at 0% climate
change mitigation at each hydrogen export volume, displaying relative changes
for hydrogen exports from domestic climate change mitigation at a certain
hydrogen export volume. At hydrogen export volumes of 25–75 TWh, an increase
of domestic climate change mitigation up to 40–60% decreases the hydrogen
export prices up to -9%. The only price increase observable in the range of
our scenarios is observable at low export volumes below 20 TWh. Here, advances
in domestic climate change mitigation increase the hydrogen export cost by up
to 19% compared to no domestic climate change mitigation. This cost increase
results from lower electrolysis capacity factors compared to the 0% climate
change mitigation scenario, where we observe high electrolysis capacity
factors of above 80% (s. Fig. 17(a)). The triangle in the top left area shows
that cost for hydrogen exporters at certain export levels are independent of
domestic climate change mitigation, this is driven by temporal hydrogen
regulation further investigated in section Hydrogen regulation reduces
domestic electricity prices and emissions. Here, hydrogen export
infrastructure decouples from the domestic electricity system, the cost is
increasingly independent of domestic climate change mitigation. The hydrogen
exports are 2 times higher than the domestic electricity demand (s. Fig.
4(b)), dwarfing the importance of the domestic electricity system.

Third, we derive co-benefits for domestic climate change mitigation and
hydrogen exports. Within the area of 40-60% climate change mitigation and
50-100 TWh/a hydrogen exports, we see i) domestic electricity consumers profit
from hydrogen exports compared to very low (1 TWh) exports and ii) hydrogen
exporters decrease their cost compared to no (0%) domestic climate change
mitigation. Hence, both domestic climate change mitigation and hydrogen
exports show clear co-benefits at medium mitigation (40–60%) and moderate to
high hydrogen exports (25–120 TWh).

Apart from the cost of electricity for domestic customers and cost of hydrogen
for exporters, Figure 4 presents possible pathways of climate change
mitigation and export. We have derived three illustrative mitigation-export
pathways presenting various speeds of transformation:

  1. 1.

Quick exports and slow climate change mitigation,

  2. 2.

Balanced exports and climate change mitigation and

  3. 3.

Slow exports and quick climate change mitigation.

In the long run, domestic electricity consumers profit in all pathways from
hydrogen exports. A slight and short increase of domestic electricity prices
in the early transformation phase (2030) is compensated by later (2050) strong
(pathway 1) and medium (pathway 2) benefits for domestic electricity
customers, profiting from hydrogen exports. In pathway 3, the short-term price
increases are only marginal, but the long-term benefit from decreased is not
as strong as in the scenarios with quicker export scale-ups. Figure 4(b) shows
that hydrogen exporters have clear benefits in pathway 2, the cost of hydrogen
for exports decrease compared to no domestic climate change mitigation. By
ramping up hydrogen exports in an early stage of domestic climate change
mitigation, high relative cost of hydrogen can be avoided.

Figure 5: Price duration curve at 120 TWh/a export and 0% domestic climate
change mitigation. Stricter temporal hydrogen regulation pushes the price
duration curve towards the left, since additional renewable electricity
capacities phase out fossil generation with higher marginal costs than
renewables. Negative prices below -50 €/MWh are cut off.

(a) Electricity dispatch and demand

(b) Cost for domestic electricity consumers and hydrogen exporters

Figure 6: Electricity dispatch and demand (6(a)) and cost for consumers (6(b))
for various (hydrogen) temporal matching regimes in the 120 TWh/a export and
0% climate change mitigation scenario. Stricter temporal matching decreases
carbon-intensive electricity generation (coal & gas) for hydrogen generation
and even domestic electricity consumers (s. Fig. 6(a)). Cost for export
hydrogen generation increase to fulfill the temporal matching constraint,
whereas domestic electricity consumers profit from stricter hydrogen
regulation.

### Hydrogen regulation reduces domestic electricity prices and emissions

Hydrogen regulation has strong effects on electricity system dispatch (and
emissions), increasing the prices and cost for hydrogen exporters whilst
decreasing for domestic electricity consumers. This section shows the
mechanisms of temporal matching in the 120 TWh/a export and 0% domestic
climate change mitigation scenario.

As the temporal matching becomes stricter, additional renewable capacities and
complementing hydrogen storage are required to meet the electricity demand of
electrolysis on an annual, monthly and hourly basis, as shown in Figure S9.
These renewable capacities i.) push out high marginal cost fossil generation
(price spillover) and ii.) provide excess electricity to the domestic
electricity system (energy spillover). Both spillover effects are linked, the
energy spillover causes a merit order effect affecting the domestic
electricity prices.

The price spillover is observable in Figure 5 depicting the price duration
curve at 120 TWh/a export and 0% domestic climate change mitigation. The price
duration curve describes the sorted price of electricity (spatial mean) at
every hour of the year. Stricter hydrogen regulation pushes the price duration
curve towards the left, since additional renewable electricity capacities
phase out fossil generation with higher marginal costs than renewable
electricity.

The energy spillover is shown in Figure 6(a). In the no rule scenario, which
does not constrain the electricity input of hydrogen electrolysis, coal and
OCGT are running close to their (brownfield) capacity limits to supply
electricity. If annual matching is applied, the renewable electricity supply
to the electricity system equals the annual demand for electrolysis,
increasing the supply of solar PV by 20 TWh/a while decreasing the supply of
fossil electricity generation. Monthly matching increases this trend, while
hourly matching completely phases out OCGT and CCGT. Figure 6(a) highlights
the energy spillover effect: going beyond the electricity demand of hydrogen
electrolysis, renewable capacities installations necessary to meet the
temporal matching decarbonize the domestic electricity demand and decrease the
grid emissions. This effect is steered by the strictness of temporal matching,
hence stricter temporal matching rules enable a further decrease in emissions.
The slight increase in total dispatch for annual and monthly matching is
balanced by resistive heaters in the heating sector. In addition to the
synergies between hydrogen export and domestic climate change mitigation, the
energy spillover outlines a clear synergy between domestic climate change
mitigation and temporal hydrogen regulation.

The price spillover effects results in lower electricity prices for domestic
consumers. Taking the electricity demand into account, the decrease of prices
results in a decrease of electricity cost shown in Figure 6(b). Stricter
temporal hydrogen regulation decreases the domestic electricity cost from 2.7
B€ to 1.2 B€. In contrast, the hydrogen cost for exporters increases from 10.1
B€ to 10.6 B€, carrying the cost of the temporal matching constraint and hence
financing additional solar PV and hydrogen storage required to meet the
electrolysis electricity demand on a certain temporal basis.

The combined cost of domestic electricity and export hydrogen decreases with
stricter temporal hydrogen regulation, whereas the total system cost increase
as displayed in Figure S9. This seeming inconsistency is based on the fact,
that electricity consumers (domestic and hydrogen electrolyser input) pay less
contribution margin to the cost of capital of coal power plants, since they
get phased out with stricter temporal hydrogen regulation. On the other hand,
the cost of capital of existing coal power plants is not part of the
optimization-based total system cost, since they are a brownfield capacity and
not extended. In short, the reduction of utilisation of the brownfield coal
power assets decreases the cost for electricity consumers, whereas the
additional renewable capacities required to meet the temporal hydrogen
regulation drive the total system cost as shown in Figure S9.

To sum up, temporal hydrogen regulation is a policy instrument acting in a
twofold way. It steers the redistribution between hydrogen exports and
domestic electricity consumers (based on the price spillover effect),
decreasing the cost for domestic electricity consumers and increasing the cost
for hydrogen exporters. The energy spillover effect not only decarbonizes
hydrogen exports but decreases grid emissions for domestic electricity demand
as well. Both effects scale with stricter temporal matching.

### The effects of temporal hydrogen regulation are strongest in high export
and low climate change mitigation systems

Based on the effects of temporal hydrogen regulation in the scenario of 120
TWh/a export and 0% climate change mitigation presented in the previous
section, this section explores the temporal hydrogen regulation across the
pathway ii.) Balanced exports and mitigation by combining all three dimensions
of domestic climate change mitigation, hydrogen export and temporal hydrogen
regulation. Figure 7 shows the relative change of electricity and hydrogen
cost of the balanced exports and mitigation scenarios in dependence of
temporal matching. Across all displayed scenarios, temporal hydrogen
regulation hedges domestic electricity consumers against rising prices.
Depending on the domestic climate change mitigation and hydrogen export,
hourly matching decreases the cost of electricity for domestic consumers by up
to 31%.

The scenarios of the balanced exports and mitigation pathway in Figure 7 show
that in only three mitigation-export combinations the annual or monthly
matching decreases the cost for domestic electricity, whereas all other
combinations of the Balanced exports and mitigation pathway are only sensitive
to the strictest – hourly matching – hydrogen regulation.

In only two scenarios, hourly matching regulation increases the hydrogen cost
above 7% compared to no temporal hydrogen regulation. This is the case for 0%
climate change mitigation and 1 and 20 TWh/a export scenarios.

The effects of temporal hydrogen regulation on domestic electricity prices are
most dominant in high export and low climate change mitigation scenarios. In
these cases, the introduction of annual matching has already a striking
effect, because the price spillover observed in Figure 5 decreases (domestic)
electricity prices. The price spillover unfolds in fossil-dominated (hence low
domestic climate change mitigation) systems, combined with high hydrogen
exports providing a strong energy spillover effect. See also Figure 14(b) for
scenarios following the quick exports and slow climate change mitigation
pathway in which the effect of temporal hydrogen regulation is even stronger.

In contrast, in the slow exports and quick climate change mitigation scenarios
only the hourly matching has observable effects, since the electricity system
is already dominated by renewable electricity and only hourly matching phases
out the remaining fossil generation (s. Fig. 14(b)). The differentiation among
the domestic climate change mitigation leads to these staged effects of
temporal hydrogen regulation on domestic electricity cost.

Figure 7: Relative change of electricity and hydrogen cost and total system
cost depending on the temporal hydrogen regulation. Domestic electricity
consumers profit across all export and mitigation scenarios but most at high
export and low climate change mitigation. Hydrogen exporters experience higher
cost with stricter temporal hydrogen regulation. The temporal hydrogen
regulation regulates the welfare distribution between both groups.

## Discussion

### Temporal hydrogen regulation and the speed of transformation

The transition towards climate neutrality of Morocco’s energy system and the
ramping up of exports up to 120 TWh/a are a matter of decade(s) and undergo a
certain pathway. Based on the co-benefits identified in Domestic climate
change mitigation and hydrogen export show co-benefits, steering the
transition by minimizing conflicts and amplifying co-benefits potentially
reduces both the price of electricity and price of hydrogen.

The broad scenario design of this study allows conclusions and recommendations
beyond the specific Morocco case. Various potential hydrogen exporting
countries with different prerequisite can be found in the integrated analysis
of benefits and burdens for domestic electricity consumers and hydrogen
exporters among the dimensions of domestic climate change mitigation, hydrogen
export and hydrogen regulation.

Based on the main findings of co-benefits and temporal hydrogen regulation, we
present three possible pathways of reaching the aims of hydrogen exports and
domestic climate change mitigation complemented with tailored temporal
hydrogen regulation recommendations:

  1. 1.

Quick exports and slow climate change mitigation: Reaching high export levels
before adequately mitigating domestic emissions leads to higher total
emissions, if no strict temporal hydrogen regulation is in place. Instead,
hourly matching reduces domestic electricity cost effectively and
redistributes welfare from exporters to domestic consumers. This regulation
plays a decisive role in this pathway, even annual or monthly matching
triggers the price spillover and energy spillover effects.

  2. 2.

Balanced exports and climate change mitigation: A medium (or balanced)
transition of both exports and mitigation offers benefits for both domestic
electricity consumers and hydrogen exporters. Domestic electricity consumers
experience a short phase of higher prices (10% climate change mitigation and
20 TWh/a export), but are then rewarded towards higher export levels given
strict hourly temporal hydrogen regulation.

  3. 3.

Slow exports and quick climate change mitigation: If the transition speed of
domestic climate change mitigation is quicker than the scale-up of hydrogen
exports, this imposes increasing cost for hydrogen exporters, while the effect
of exports on domestic electricity cost is marginal. The temporal hydrogen
regulation plays only a minor role in this pathway, since the electricity
system is already highly or fully renewable electricity based and neither
price spillover nor energy spillover are effective.

The three illustrative pathways offer certain room for manoeuvre in policy-
making for various countries and their export ambitions as well as speed of
domestic climate change mitigation. However, these pathways do not reflect
additional constraints as limited renewable energy ramp-up rates, the
availability of workforce, additional prerequisites such as an effective
carbon pricing system for carbon-based Power-to-X products and bureaucratic
hurdles among others. A holistic approach and well-balanced policies is
required to steer the energy transition and export ambitions.

### Balancing interests of exporters and domestic demand

The implications of hydrogen export on domestic electricity consumers are
reflected in various dimensions.

First, the price of electricity for domestic businesses and households need to
be considered to enable a fair discussion and balance of burdens and
opportunities. This study shows that the price of electricity highly depends
on hydrogen export volumes and temporal hydrogen regulation. The export of
hydrogen in combination with strict temporal hydrogen regulation provides the
opportunity of decreasing domestic electricity prices, providing opportunities
for domestic businesses and households.

Second, the substantial deployment of solar PV and onshore wind comes along
with a substantial land use. Several studies 26, 27 highlight the requirement
of local acceptance of renewable energies in Morocco. From a German/European
perspective, hydrogen imports are not necessarily the most economic option 28
but also provide a way out of having to deal with the domestic acceptance of
renewable energies. Shifting such issues of acceptance to Morocco by deploying
renewable energy and scaling up their hydrogen exports raises moral questions
and should be dealt with carefully.

Third, this study shows the benefits of integrating solar PV and onshore wind
into the main grid for both domestic electricity consumers and hydrogen
exporters. By integrating the best sites of solar PV and onshore wind,
domestic electricity consumers can access the cost-cutting potentials and
benefit from lower electricity prices as shown in our results. On the other
hand, off-grid hydrogen generation potentially reserves the promising
electricity potentials for hydrogen export only. Nonetheless, Tries et al.29
show the benefits of hydrogen islanding, offering cost savings for inverters
and benefits for power quality. Domestic consumers may profit from these
economic opportunities for hydrogen exporters indirectly through corresponding
policies.

Hydrogen export ambitions (fostered by e.g. the European Union) do not cause
disadvantages for the domestic population per se, a proactive transition
taking into account the interplay of domestic electricity prices unleashes
economic opportunities for both exporters and domestic population.

### Limitations

The sector-coupled energy model as well as the results underly certain
limitations. In this study, we leave the option open that the hydrogen for
export is further synthesized to hydrogen derivatives as ammonia, Fischer-
Tropsch products or sponge iron etc. We do not model the system operation of a
further synthesis of export products explicitly, unlike we do for the domestic
demands for hydrogen derivatives. Further synthesis of export products and
linked transportation modes are investigated in Hampp et al.17, Galimova et
al.30 and Verpoort et al.31 but not in the scope of this study.

A further synthesis will likely have effects on the system operation, since
the synthesis in combination with cheaper storage (e.g. oil storage is cheaper
than hydrogen storage 32) provides an additional flexibility to a certain
extent but is limited by the operation flexibility of Fischer-Tropsch or
Haber-Bosch processes.

The constant hydrogen export demand assumed in this study represents pipeline
operation or a further hydrogen synthesis. If the export hydrogen is not
further synthesized but exported as liquified hydrogen via shipping, there are
significant impacts on the energy system to expect. The demand pattern of ship
export (landing, loading, travel time) triggers spikes in hydrogen demand,
which would need to be buffered by large-scale hydrogen storage or by a
corresponding operation of hydrogen electrolysis.

Additionally, the transition of certain sectors is not subject to the
optimisation but exogenously defined. Such nodal shifts (e.g. in transport:
share of electric vehicles) provide system benefits (e.g. Vehicle-to-Grid) for
which an integrated optimisation favours e.g. higher shares of electric
vehicles. Recent approaches as Zeyen et al.33 improve such caveats by
incorporating endogenous learning, but research gaps on the endogenous demand
of the transport sector remain.

National climate ambitions and especially the scale-up of hydrogen export
require substantial amounts of raw materials (e.g. copper, cement) linked with
resource limitations as well as upstream greenhouse gas emissions. As pointed
out in Wang et al.34 in a global analysis, most raw material limitations
required for electricity generation do not exceed geological reserves.
However, material demands of e.g. electrolysers are not within the scope of
Wang et al.34.

The cost of water through desalination and transport has a single cost for the
whole country. However, the transportation costs highly depend on the terrain
as pointed out by Caldera et al.35, hence the water costs are higher in more
remote areas which is not taken into account in this study. In contrast, the
effect of a higher spatial resolution of water costs is assumed to be minor,
since the water desalination and transport costs do not contribute
substantially to the cost of hydrogen as emphasized in Hampp et al.17.

### Conclusion

Our study shows the importance of integrated scenario analysis combining
hydrogen exports, domestic climate change mitigation and temporal hydrogen
regulation.

Both hydrogen exports and domestic climate change mitigation benefit from each
other mainly at emissions reduction of 40–60% compared to the baseline
scenario and moderate to high hydrogen exports (25–120 TWh/a). However, we
show that there are also risks with respect to rising domestic electricity
prices and find that hydrogen regulation via temporal matching is a decisive
instrument to protect domestic consumers. Hourly matching decreases the cost
for domestic electricity consumers (up to -31%) while the effect on hydrogen
exports is minimal. Temporal hydrogen regulation can effectively hedge
domestic electricity consumers against rising prices across mitigation and
export scenarios.

This study contributes to the investigation of implications and benefits of
hydrogen exports for domestic electricity consumers. Even though temporal
hydrogen regulation hedges domestic electricity consumers against rising
prices, further implications of hydrogen exporters on the domestic population
(land use, competing RE resources, environmental concerns of desalination) are
not within the scope of this study.

In summary, our study underscores that hydrogen export ambitions, as
encouraged by entities like the European Union, is in favor of domestic
electricity consumers at certain export quantities, if the appropriate
hydrogen regulation is in place. A proactive and comprehensive transition
strategy, considering the interplay between hydrogen exports and domestic
climate change mitigation, is key to unlocking economic opportunities for both
hydrogen exporters and the domestic population.

Apart from reducing greenhouse gas emissions, temporal hydrogen regulation is
a decisive policy instrument in steering the welfare (re-)distribution between
i) hydrogen exporting firms and hydrogen importing countries and ii) hydrogen
exporting firms and domestic electricity consumers. A fair balance can
increase acceptance across actors, is crucial for a sustainable energy
transition in Morocco and offers valuable insights for further countries
facing similar energy challenges globally.

## Methods

### Sector-coupled energy model

The sector-coupled energy model of Morocco is based on the global electricity
model PyPSA-Earth 36 and the sector-coupling extension 37 using linear
optimisation and overnight scenarios. This capacity extension model optimises
the generation, transmission and storage capacities of Morocco’s energy system
by minimising the the total annualised system costs constrained by e.g.
climate targets or green hydrogen policies.

#### Energy demand

To obtain the annual energy demand, we use the workflow presented by Abdel-
Khalek et al.37. In a first step, the annual energy demand is obtained from
the United Nations Statistics Database38. The latest available data is from
2020, since these energy balances are likely to show irregularities due to
COVID-19 implications, the base year in this study is 2019. Based on the
annual energy demand from 2019, the energy demand of 2035 is projected
according to efficiency gains and activity growth rates similar to Müller et
al.39. In a second step, the annual and national energy demand is distributed
according to the production sites of Morocco. In case of subsectors where no
spatially resolved production sites are available (e.g. paper industry), the
demand is distributed according to GDP. Third, the annual but locationally
resolved energy demand is converted to hourly demands. In this study, a
constant hourly demand of the industry and agriculture sector is assumed
whereas electricity, heating, transport are temporally resolved based on time
series derived from Brown et al.40. The resulting temporal and spatial energy
demands of the sectors:

  * 1.

Electricity,

  * 2.

Heating,

  * 3.

Industry,

  * 4.

Transport (incl. aviation and shipping) and

  * 5.

Agriculture

are integrated in the sector coupled energy model. The inland energy demand
per sector remains constant throughout the scenarios presented in the
Introduction, regardless of endogenous hydrogen export volumes or national
carbon emission reductions. However, to account for increasing shares of
battery electric vehicles (BEV) in the Moroccan energy system, the share of
BEV’s is linked to the emission reduction ambitions (s. Fig. S1) from 2%
(today’s levels) up to a share of 88% at 100% domestic climate change
mitigation in accordance with Rim et al.41.

#### Renewable Energy Sources

The sector-coupled energy model follows the data pipeline of 36 by
incorporating solar PV, onshore wind and hydro power using the open source
package Atlite 42. Atlite obtains technology-specific time series based on
weather data (ERA5 reanalysis data 43, SARAH-2 satellite data 44). In addition
to the time series, Atlite calculates land availabilities and linked
potentials using the Copernicus Global Land Service 45.

Figure 8: Current capacities of electricity generation and distribution,
obtained from 46 and visualization based on 47. Morocco’s electricity
generation portfolio is currently dominated by fossil generation (coal and
gas), includes some hydropower plants and increasing but still minor
capacities of onshore wind and solar PV. Boundaries depicted are based on the
Global Administrative Areas and are intended for illustrative purposes only,
not implying territorial claims.

#### Conventional electricity generation

The conventional electricity generators are obtained from the
powerplantmatching tool 48. Powerplantmatching uses various input sources as
OpenStreetMap2022, Global Energy Monitor, IRENA 49, 50, 51 to download, filter
and merge the datasets. In this study, powerplantmatching is applied to
Morocco delivering the conventional power plants.

#### Electricity networks and gas pipelines

The electricity network is based on the PyPSA-Earth workflow using
OpenStreetMap2022 data 50 as presented in Parzen et al.36. First, the data is
downloaded, filtered and cleaned. Second, a meshed network dataset including
transformers, substations, converters as well as HVAC and HVDC components is
build36. The brownfield gas pipeline infrastructure of Morocco is not
considered in this study. The Maghreb-Europe pipeline passing through Morocco
is the only pipeline in operation but currently subject to political disputes
52. Further proposed projects are excluded due to miniscule capacity compared
to Morocco’s energy system (Tendrara LNG Terminal, 100 million cubic meters
per year or uncertain commissioning dates (Nigeria-Morocco Pipeline, start
year 2046 53).

### Brownfield model and capacity expansion

Following the workflow of 36, Figure 8 shows the current capacities of
electricity generation and distribution of Morocco. Based on this brownfield
electricity system, the sector-coupled energy model allows the capacity
expansion of storage, (electricity networks), hydrogen pipelines, renewable
and conventional generators.

### Technology and cost assumptions

All technology and cost assumptions are based on the year 2030, taken from
github.com/pypsa/technologydata version 0.4.0. A discount rate of 13% is
applied.

### Water supply

Hydrogen production through electrolysis requires fresh water, alternatives as
the direct use of high saline water sources are still in the experimental
stages 54. The depletion of freshwater resources and it’s competition with
other water uses is a concern, especially in regions such as Morocco which is
ranked 27th among the world’s most water-stressed countries 55. Sea Water
Reverse Osmosis (SWRO) emerges as a feasible solution to address this issue.
In this model, the additional water cost of 0.80 €/${\mathrm{m}}^{3}\text{/}$
through desalination and transport is considered in line with the base
scenario for Morocco in 2030 in Caldera et al.56. These findings are
comparable to Kettani et al.57 and Caldera et al.35 stating the water costs of
1$/$m^{3}$ resp. 0.60 - 1.50 €/${\mathrm{m}}^{3}\text{/}$ for Morocco in 2030.
Given a water demand of 9 $m^{3}/kg_{hydrogen}$ 17, the additional costs for
electrolysers result in 0.216 $MWh/kg_{hydrogen}$ (LHV).

However, the challenge of brine disposal presents environmental concerns due
to treatment chemicals and high salinity as discussed by 58, 59, 60 that
require a careful site selection of desalination plants. A minimum distance of
four kilometers from marine protected areas is recommended in 58.

### Green hydrogen policy

A key constraint on the model is that the hydrogen exported from Morocco
requires to meet sustainability criteria (”green” hydrogen). A variety of
studies looks into various dimensions (temporal, geographical, electricity
origin) of green hydrogen and their trade-offs 21, 61, 19. Envisioning
hydrogen offtakers from the European Union, the green hydrogen constraint
applied in this study aligns with the _Delegated regulation on Union
methodology for RFNBOs_ of the European Commission 62 defining green hydrogen
based on the following criteria:

  1. 1.

Additionality: The electricity demand of electrolysers must be provided by
additional RE power generation (less than 3 years before the installation of
electrolysers, from 1.1.2028 onwards),

  2. 2.

Temporal correlation: Hourly matching (from 1.1.2030 onwards, until 31.12.2029
monthly) and

  3. 3.

Geographical correlation

which are required for Power Purchase Agreements (PPA) with RE-installation.
Apart from the PPAs, the delegated act also considers the possibility of:

  * 1.

direct connection of RE and electrolysers,

  * 2.

high share of RE in power mix ($>$ 90%) or the

  * 3.

avoidance of RE curtailment

to qualify as ”green” hydrogen. These further options are not considered here,
since a system-integrated electrolysis in a power system of a (current) share
of RE below 90% is the scope of this study. The sole focus on RE curtailment
and hence low total hydrogen volumes is not applicable due to expected
hydrogen exports of up to multiple times of Morocco’s domestic electricity
demand. The green hydrogen definition of the European Commission prior to
1.1.2028 is not applied in this study, since relevant volumes of hydrogen
export are expected to materialize from 2028 onwards and is excluded by the
scope of this study presented in the Introduction).

### Hydrogen export

The amount of hydrogen to be exported or further synthesized for export is
implemented as an exogenous parameter in the range of 0-120 TWh/a, with
sensitivity analysis up to 200 TWh/a presented in the Supplementary
Information section High export scenarios. The system boundary is the country
border of Morocco, hence transport options (as shipping or pipeline) are not
considered in detail. The profile for hydrogen (or derivatives) export assumed
in this study is constant. This represents the operation of pipeline exports
as well as the operation of a further hydrogen synthesis with limited
flexibility. The export of hydrogen is allowed via a range of ports in
Morocco.

The energy system model allows an endogenous spatial export decision, meaning
that the total demand (and export profiles) are exogenous, but the model
chooses the cost-optimal export location(s). At each port, the model has the
option to build a hydrogen underground or steel tank depending on domestic
geological conditions.

## Data availability

A dataset of the model results is available on Zenodo under a CC-BY-4.0
license. Technology data was taken from the technology-data repository
(v0.4.0).

## Code availability

The code to reproduce the experiments is available on GitHub. We also refer to
the documentations of PyPSA and PyPSA-Earth, and the code of PyPSA-Earth-Sec.

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## Acknowledgements

We are grateful for helpful comments by Alexander Meisinger and Anton
Achhammer.

We gratefully acknowledge funding from the H2Global meets Africa project
(03SF0703A) and the HYPAT project (03SF0620A) by the German Federal Ministry
of Education and Research.

## Author Contributions

L.S.: Conceptualization, Data curation, Formal Analysis, Funding acquisition,
Investigation, Methodology, Project administration, Software, Validation,
Visualization, Writing - original draft, Writing - review & editing; H.A-K.:
Data curation, Methodology, Project administration, Software, Validation,
Writing - review & editing; T.B.: Conceptualization, Formal Analysis,
Methodology, Supervision, Writing - review & editing; F.U.: Conceptualization,
Formal Analysis, Supervision, Visualization, Writing - review & editing; M.S.:
Funding acquisition, Project administration, Resources, Supervision, Writing -
review & editing; M.P.: Methodology, Software, Writing - review & editing;
D.F.: Conceptualization, Formal Analysis, Methodology, Software, Writing -
review & editing.

## Declaration of Interests

The authors declare no competing interests.

## Materials & Correspondence

Requests for further information, resources and materials should be directed
to and will be fulfilled by the lead contact, Leon Schumm (leon1.schumm@oth-
regensburg.de).

## Supplementary Information

##  S1 Energy demand

###  S1.1 Diffusion of Battery Electric Vehicles

Figure S1 shows the diffusion of battery electric vehicles depending on the
domestic climate change mitigation, displaying electric vehicle stock in
Morocco. The share rises from 2% (today’s levels) up to a share of 88% at 100%
domestic climate change mitigation.

Figure S1: Market diffusion of Battery Electricity Vehicles in Morocco,
synthesized based on an s-curve with a growth rate $k=0.2$ and inflection
point $x_{0}=2040$.

##  S2 Electricity supply

The electricity supply with hourly temporal matching is displayed in Figure
S2, along with the generation capacities in Figure S3 and capacity factors in
Figure S4.

###  S2.1 Electricity supply

Figure S2: Electricity supply

###  S2.2 Electricity capacities

Figure S3: Electricity capacities

###  S2.3 Electricity capacity factors

Figure S4: Electricity capacity factors

Figure S5: Capacity factors of renewable sources, graph style adapted from
Neumann et al. 23

###  S2.4 Electrolyser and Fischer-Tropsch capacity

(a) Electrolysis optimal capacity

(b) Fischer-Tropsch optimal capacity

Figure S6: Electrolysis and Fischer-Tropsch capacities

##  S3 Energy balances

###  S3.1 Oil balance

Figure S7 shows the oil balance at 1 TWh/a export at increasing domestic
climate change mitigation.

Figure S7: Oil balance at 1 TWh/a export at increasing domestic climate change
mitigation. The exogenously defined oil demand for land transport
substantially decreases due to electrification, whereas oil demands for
industrial naphta, aviation, agriculture are constant. The demand is met by
fossil oil up to 80% climate change mitigation, then gradually replaced by
Fischer-Tropsch fuels.

##  S4 Temporal hydrogen regulation

###  S4.1 Hourly matching prevents additional emissions induced by hydrogen
exports

Figure S8 displays the electricity balance ramp up from 1–120 TWh/a at 0%
domestic climate change mitigation with (8(a)) and without (8(b)) temporal
hydrogen regulation.

(a) Electricity balance with temporal hydrogen regulation

(b) Electricity balance without temporal hydrogen regulation

Figure S8: Electricity balance ramp up from 1–120 TWh/a at 0% domestic climate
change mitigation with (8(a)) and without (8(b)) temporal hydrogen regulation

###  S4.2 Effects of temporal matching in a high export and low climate change
mitigation scenario on total system costs

Figure S9: Total system costs at 120 TWh/a export and 0% domestic climate
change mitigation. Stricter temporal hydrogen regulation mainly increases the
total CAPEX of additional solar PV, electrolysis and hydrogen storage. In
return, the OPEX of fossil generation (mainly gas), decreases. The large share
of oil OPEX is independent of temporal hydrogen regulation, since these costs
are mainly linked to combustion engine cars with demands independent of
temporal hydrogen regulation.

##  S5 Hydrogen cost breakdown

The price of hydrogen depends on single cost components as well as the
temporal hydrogen regulation. Figure S10 displays the cost breakdown of
hydrogen whereas the combined cost in Figure 10(e) differs from the price of
hydrogen in Figure 10(f). This is due to the temporal hydrogen regulation, the
costs for the required installation of additional RE capacities are not
reflected in the cost breakdown but included in the price of hydrogen. This
effect is most striking in high export and low domestic climate change
mitigation scenarios. In constrast, if there is no temporal hydrogen
regulation applied, both hydrogen cost (s. Fig. 11(e)) and hydrogen price (s.
Fig. 11(f)) show similar trends across all domestic climate change mitigation
and export scenarios.

(a) CAPEX share of hydrogen costs

(b) Electrolysis capacity factor

(c) OPEX share of hydrogen costs

(d) Price of electricity (electrolysis demand weighted)

(e) Total hydrogen cost

(f) Hydrogen price

Figure S10: Cost components of hydrogen electrolysis and the respective main
influence factors on it with hourly temporal matching. The CAPEX (10(a))
depends on the electrolysis capacity factor (10(b)), whereas the OPEX (10(c))
is influenced by the price of electricity for electrolysis (10(d)). With
temporal hydrogen regulation, the cost of hydrogen (10(e)) is not reflected by
the price of hydrogen (10(f)), which includes the additional constraint of
hourly matching and hence the installation of RE and storage capacities.

(a) CAPEX share of hydrogen costs

(b) Electrolysis capacity factor

(c) OPEX share of hydrogen costs

(d) Price of electricity (electrolysis demand weighted)

(e) Total hydrogen cost

(f) Hydrogen price

Figure S11: Cost components of hydrogen electrolysis and the respective main
influence factors on it without temporal hydrogen regulation. The CAPEX
(11(a)) depends on the electrolysis capacity factor (11(b)), whereas the OPEX
(11(c)) is influenced by the price of electricity for electrolysis (11(d)).
With temporal hydrogen regulation, the cost of hydrogen (11(e)) is not
reflected by the price of hydrogen (11(f)), which includes the additional
constraint of hourly matching and hence the installation of RE and storage
capacities.

##  S6 High export scenarios

###  S6.1 Electricity supply and demand

(a) Fixed (1 TWh) export and 0–100% domestic climate change mitigation

(b) Fixed (0%) domestic climate change mitigation and 1–200 TWh/a export

Figure S12: Electricity supply and demand at fixed export levels and
increasing domestic climate change mitigation (12(a)) and vice versa (12(b)).
Increasing domestic climate change mitigation first phases out carbon-
intensive coal generation in favor of CCGT, at medium to high domestic climate
change mitigation the electricity system is fully renewable supported by
flexibility through Vehicle-to-Grid (V2G) and sector coupling. Increasing
electricity demands cover EVs and hydrogen generation for other sectors. At
increasing hydrogen exports the additional electricity required for hydrogen
electrolysis is covered by onshore wind and solar PV, as imposed by the
temporal hydrogen regulation.

###  S6.2 Relative cost of domestic electricity and hydrogen export

(a) Rel. cost of electricity for domestic customers (normalized to 1 TWh/a
hydrogen export)

(b) Rel. cost of hydrogen for exporters (normalized to 0% CO2 reduction)

Figure S13:  Rel. cost for domestic electricity consumers (13(a)) and hydrogen
exporters (13(b)), normalized to costs at 1 TWh/a hydrogen export (13(a)) and
to 0% CO2 reduction (13(b)) at each domestic climate change mitigation level.
Domestic electricity consumers profit from increasing hydrogen exports,
especially at low domestic climate change mitigation and high exports.
Hydrogen exporters profit from domestic climate change mitigation at medium
mitigation efforts. Both (13(a)) and (13(b)) include possible pathways of i)
quick exports and slow climate change mitigation, ii) balanced exports and
mitigation and iii) slow exports and quick climate change mitigation.

###  S6.3 Effect of temporal hydrogen regulation on electricity and hydrogen
costs in all scenarios

(a) All scenarios up to 120 TWh

(b) All scenarios up to 200 TWh

Figure S14: Supplement to Fig. 7. Relative change of electricity and hydrogen
cost and total system cost depending on the temporal hydrogen regulation.
Domestic electricity consumers profit across all export and mitigation
scenarios but most at high export and low climate change mitigation. Hydrogen
exporters experience higher cost with stricter temporal hydrogen regulation.
The temporal hydrogen regulation regulates the welfare distribution between
both groups.

##  S7 Carbon Management

Figure S15 shows the carbon management of scenarios with increasing emission
limit at 1 TWh/a export volume.

(a) Carbon dioxide emissions and capturing of non-electricity sectors

(b) Carbon dioxide balance of captured carbon dioxide

Figure S15: Carbon dioxide 15(a) emissions and capturing as well as 15(b)
management of captured carbon dioxide

##  S8 System operation

###  S8.1 Operation of electrolysers and Fischer-Tropsch in dependence of
domestic climate change mitigation

(a) 20% climate change mitigation

(b) 70% climate change mitigation

(c) 90% climate change mitigation

Figure S16: Operation of electrolysers/Fischer-Tropsch and prices of
electricity and hydrogen at 40 TWh/a export and 20%, 70% and 90% domestic
climate change mitigation. The electrolyser operation depends on the
electricity prices, strong diurnal electricity price patterns as in 16(b)
result in a corresponding electrolyser operation. Increased battery capacity
at 16(c) results in smoother electricity prices also increase the annual
capacity factor of the electrolyser. Note: electricity and hydrogen prices are
spatially averaged in non-weighted manner, graph style adapted from Neumann et
al. 23

###  S8.2 Capacity factors of electrolysis and Fischer-Tropsch

(a) Capacity factor of electrolysis

(b) Capacity factor of Fischer-Tropsch

Figure S17: Capacity factors of electrolysis and Fischer-Tropsch. The
electrolysis has a high capacity factor in low export and low domestic climate
change scenarios. The capacity factor for Fischer-Tropsch is close to 1 given
the limited flexibility of the process.