The Economics of

Oﬀshore Wind-Based

Hydrogen Production

in Saudi Arabia

Ahmed A. Albalawi, Shahid Hasan, and

Amro M. Elshurafa

Discussion Paper

December 2024 I Doi: 10.30573/KS--2024-DP68

About KAPSARC

KAPSARC is an advisory think tank within global energy

economics and sustainability providing advisory services to

entities and authorities in the Saudi energy sector to advance

Saudi Arabia’s energy sector and inform global policies through

evidence-based advice and applied research.

This publication is also available in Arabic.

Legal Notice

Center (“KAPSARC”). This Document (and any information, data

or materials contained therein) (the “Document”) shall not be

used without the proper attribution to KAPSARC. The Document

shall not be reproduced, in whole or in part, without the

written permission of KAPSARC. KAPSARC makes no warranty,

representation or undertaking whether expressed or implied,

nor does it assume any legal liability, whether direct or indirect,

or responsibility for the accuracy, completeness, or usefulness

of any information that is contained in the Document. Nothing in

the Document constitutes or shall be implied to constitute advice,

recommendation or option. The views and opinions expressed in

this publication are those of the authors and do not necessarily

reﬂect the ocial views or position of KAPSARC.

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

Key Points

Oshore hydrogen production from oshore wind energy is gaining global

attention as an appealing solution for scaling up green hydrogen production.

The technoeconomic feasibility of integrating oshore wind into hydrogen

production has been explored in various regions, but no comprehensive

study exists concerning Saudi Arabia’s oshore wind potential. This work

aims to assess the cost-eectiveness of producing hydrogen onshore versus

oshore from wind power in the Red Sea. Via the use of a deterministic cost

model, this study evaluates the levelized cost of hydrogen (LCOH) for both

conﬁgurations. The results show that oshore wind farm costs and ﬂoating

foundations are the major drivers of capital expenditure (CAPEX). While

onshore electrolysis remains slightly less expensive than oshore electrolysis,

both conﬁgurations require substantial cost reductions to compete with

alternative onshore renewable energy sources.

• The LCOH of oshore hydrogen production

from ﬂoating oshore wind ranges from $6.47 to

$8.01/kg, reﬂecting the current high cost of

such technology.

• Signiﬁcant cost reductions in the main components of

the system can reduce the cost range down to $4.57 to

$6.07/kg.

• The development of Saudi Arabia’s oshore wind-to-

hydrogen sector will likely be a medium- to long-term

target, requiring further cost reductions in oshore

wind technology.

• Future innovations in decentralized hydrogen

production can create new opportunities for cost

reduction and scalability in the sector.

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

1. Introduction

The global push toward decarbonization and sustainable energy systems is

driving innovation in how and where we produce and utilize clean energy.

Hydrogen, a zero-emission fuel, is at the center of these innovations

and can be utilized across various hard-to-electrify industries. Hydrogen

production is categorized on the basis of the energy source used, with

greater attention being paid to renewable energy-based hydrogen, known as

“green hydrogen.” This situation has driven research, for example, into how

to integrate oshore wind energy into hydrogen production to leverage the

vast potential of oshore wind for producing green hydrogen. Oshore wind

is particularly appealing because of its high-capacity factors and consistent

speeds, oering a reliable and large-scale energy source for hydrogen

production, especially in areas with limited land availability. Globally, this

concept is gaining traction as countries seek to align their energy strategies

with decarbonization goals and establish themselves as leaders in the

emerging hydrogen economy.

Countries that have established oshore wind industries

are naturally proactive in exploring the promise of this

combination. The North Sea, in particular, is seeing a

collaborative approach to the development of these

two technologies and linking them to energy hubs in

countries such as Germany, Scotland, England, Denmark,

and Norway (Farahmand, Günther, and Kristiansen

2024). Energy hubs, which allow for the coordinated

management and optimization of dierent energy carriers

within a single integrated infrastructure, including local

renewable energy for green hydrogen production, have

become increasingly relevant in the context of oshore

wind. These hubs can eectively integrate wind power

generation into hydrogen production, energy storage,

and potentially other renewable sources, such as wave or

solar energy. By enabling the direct conversion of wind

energy into hydrogen at sea, these hubs can facilitate

more cost-eective oshore hydrogen production than

can the alternative of building high-voltage direct current

(HVDC) networks for onshore hydrogen production,

particularly in remote locations (Glaum, Neumann, and

Brown 2024).

The growth of oshore wind has been driven by

supportive policies, such as the European Union’s

(EU’s) Oshore Renewable Energy Strategy, which

aims to expand capacity to 60 gigawatts (GW) by 2030

and 300 GW by 2050 (European Commission 2020).

Owing to its high-capacity factors and potential for

large-scale deployment, oshore wind is ideally suited

to meet the growing demand for green hydrogen. The

ongoing advancements in ﬂoating wind technology

further expand the geographical scope of oshore wind,

enabling its deployment in deeper waters, where ﬁxed-

bottom turbines are not feasible. This situation opens

new opportunities for countries with large amounts

of oshore wind resources in deeper waters. Floating

oshore wind farms (FOWFs), though currently more

expensive than ﬁxed turbines, oer greater wind resource

potential and are the focus of ongoing research to

reduce costs (Kang, Gbadago, and Hwang 2024). There

are positive interactions between ﬁxed and ﬂoating

oshore wind technologies, such as knowledge sharing

and collaboration. But negative interactions, such as

competition for resources, resistance from established

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

turbine manufacturers, and challenges in infrastructure

and labor availability, have also been found (Havinga, van

der Loos, and Steen 2024).

In the UK’s latest Contracts-for-Dierence (CfD) Allocation

Round 6 (AR6), the strike price for oshore wind is set at

£58.87/MWh (approximately $78/MWh), whereas ﬂoating

oshore wind secures a higher strike price of £139.93/

MWh (approximately $186/MWh) owing to the newer and

less mature technology of the latter (DESNZ 2024). For

the global oshore wind sector, auction design elements

such as revenue stabilization mechanisms and strategic

bidding behavior have successfully reduced costs and

accelerated deployment. Jansen et al.’s (2022) review of

historical auction bids reveals a trend of decreasing bid

prices over time, driven by technological advancements,

economies of scale, and increased competition. However,

the analysis also emphasizes the challenges posed by

strategic bidding and the risk of underbidding in highly

competitive markets. In electricity markets, integrating

hydrogen in oshore wind farms adds ﬂexibility, reducing

electricity imbalances and regulation costs because

of the diculty in accurately forecasting the amount of

wind generation (Calado et al. 2024). Hydrogen oers

signiﬁcant opportunities for long- and short-term energy

storage, enabling the integration of intermittent renewable

energy sources into the grid without disrupting the market

(Hill et al. 2024). However, while electrolyzers have the

potential to provide ﬂexibility services, their primary

economic driver is solely hydrogen production (Lüth et al.

2024).

Yet, the integration of oshore wind and hydrogen

production is not without its challenges. Although

technical, environmental, and operational challenges

exist, we focus primarily on economic challenges in this

paper. The high costs associated with oshore wind

infrastructure, electrolysis technology, and hydrogen

transportation remain key barriers. These costs need

to be carefully evaluated through technoeconomic

assessment (TEA) to determine the viability of such

projects. TEA provides a framework for assessing the

economic and technical feasibility of integrating oshore

wind into hydrogen production, considering factors such

as capital and operational costs, potential revenue, and

the impact of scale. This analysis is crucial for identifying

the most cost-eective strategies, for guiding investments

in this emerging sector and for determining the level

of incentive support required to reduce hydrogen

production costs.

This study aims to clarify the costs associated with

oshore wind-to-hydrogen pathways, speciﬁcally in the

context of Saudi Arabia. The economic analysis in this

work compares the costs and eciencies of producing

hydrogen onshore via transmitted electrical power from

oshore wind turbines with the alternative approach

of producing hydrogen oshore and transporting it via

pipelines. This study provides valuable insights into the

technoeconomic aspects of oshore wind-to-hydrogen

integration in the Red Sea region, highlighting the

challenges of this technology, as Saudi Arabia aims to

become a global leader in green hydrogen production.

This work identiﬁes the unique cost drivers for both

onshore and oshore conﬁgurations and emphasizes

the need for signiﬁcant cost reductions to make these

pathways competitive with alternative green hydrogen

production methods. The various modes of hydrogen

production with oshore wind power examined in this

study are brieﬂy described below.

The integration of oshore wind energy into hydrogen

production can be achieved through the following two

potential conﬁgurations, each with a distinct technological

setup and infrastructure requirements: producing

renewable energy oshore, converting it to hydrogen

oshore, and then transporting hydrogen to shore, or

producing renewable energy oshore, transmitting it to

shore, and producing hydrogen onshore.

A. Centralized

Onshore Electrolysis

(Undersea Power

Cables for Onshore

Electrolysis)

In this mode, the electricity generated by oshore

wind farms is transported to onshore facilities, where

hydrogen production takes place through electrolysis.

This conﬁguration typically involves the use of either high-

voltage alternative current (HVAC) or HVDC undersea

cables, depending on distance required. The onshore

electrolysis production provides easier access to the

desalinated water supply needed for the electrolysis

process, as well as proximity to existing industrial and

transport networks.

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

B. Centralized

Oshore Electrolysis

(Hydrogen

Transported by Pipe

or Ship)

In this conﬁguration, electrolysis occurs on a central

oshore platform, where wind power is used to produce

hydrogen via seawater. Platforms can accommodate

systems ranging from 100 megawatts (MW) to 700 MWs

(Venugopalan, Garcia Navarro, and Buijs 2024). The

hydrogen produced is transported to shore via pipelines

Substation Electrolyzers

Land

Hydrogen

network

Sea

Inner-array

cables

Hydrogen pipeline

Figure 1. Hydrogen integration with oshore wind farms.

Substation Substation Electrolyzers

Land

Hydrogen

Sea

Inner-array

cables

Undersea HVAC cables

(b) Centralized oshore electrolysis.

Source: Authors.

(a) Centralized onshore electrolysis.

or specialized hydrogen carriers (ships). It is also possible

for large-scale electrolysis to take place on artiﬁcial

islands, accommodating multiple GW-scale hydrogen

production units. These islands have the potential for both

horizontal and vertical expansion to accommodate future

increases in hydrogen demand.

In oshore hydrogen production, it is crucial to treat water

properly because electrolyzers require very pure water to

operate eciently. Seawater, which contains high levels of

salt and other impurities, cannot be used directly. Therefore,

seawater must undergo a puriﬁcation/desalination process.

The puriﬁcation process is crucial for preventing damage

to equipment and maintaining eciency during hydrogen

production. Without this step, impurities in seawater can

corrode the system or clog the components, resulting

in expensive maintenance and reduced performance

(Venugopalan, Garcia Navarro, and Buijs 2024).

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

Transporting oshore-produced hydrogen to shore can

be accomplished via pipelines, most likely through newly

built pipeline infrastructure; ship transport in various forms

(compressed gas, liquid hydrogen, or hydrogen carriers

such as ammonia) from centralized oshore electrolyzers;

or the ﬂoating production, storage and ooading (FPSO1)

concept. Each method comes with its own set of cost,

infrastructure, and eciency considerations.

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

2. Status of Oﬀshore

Hydrogen from Wind

Power and Literature

Review

2.1 Sample Global Projects

Oshore wind energy integration into hydrogen production is increasingly

becoming a key strategic focus for many countries as part of their broader

energy transition goals. Several countries are developing strategies to

leverage oshore wind resources for large-scale hydrogen production.

These strategies are often aligned with national decarbonization targets,

energy security goals, and ambitions to become leaders in the emerging

global hydrogen economy.

Germany is planning to integrate oshore wind power

into hydrogen production as part of its National

Hydrogen Strategy. The country aims to use its

extensive oshore wind resources in the North and

Baltic Seas to advance green hydrogen production.

Germany is working on several pilot projects in the

North Sea, including the AquaVentus initiative, which

aims to produce 1 million tonnes (Mt) of green hydrogen

from approximately 10 GW oshore wind power by

2035 (AquaVentus 2024). This initiative includes several

projects, such as the AquaSector project, which plans

to install a 300-MW electrolyzer capacity as a proof

of concept. The AquaPrimus pilot project will focus

on testing the integration of a 15-MW hydrogen wind

turbine. Additionally, the AquaDuctus project will

transport green hydrogen from oshore production sites

to the mainland through a hydrogen pipeline. Helgoland,

a small island in the North Sea, is set to become an

energy hub within the AquaVentus initiative, serving as

a central point for hydrogen production, storage, and

distribution (RWE 2024).

The SEN-1 area in the German North Sea is set to be the

ﬁrst region tendered speciﬁcally for oshore hydrogen

production. Within this area, 300 MW of electrolyzers will

be installed to produce green hydrogen, which will then

be transported to shore through the AquaDuctus pipeline.

In its Baltic Sea areas, Rostock’s port infrastructure

will be upgraded to support hydrogen storage and

distribution. The HyTech Hafen Rostock Project will utilize

oshore wind power to produce green hydrogen. This

hydrogen will be used in various applications, including

port operations, industrial processes, and transportation

(Rostock 2024).

The Netherlands is investing heavily in oshore wind

energy with hydrogen as part of its strategy to transition

to a low-carbon economy. The country aims to have

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

11.5 GW of oshore wind capacity by 2030, with plans

for further expansion in the future. A signiﬁcant portion

of this capacity will be used for hydrogen production.

The NortH2 project aims to develop 4 GW of electrolysis

capacity by 2030, powered by oshore wind farms, with

plans to expand to 10 GW by 2040. Initially, electrolyzers

will be placed onshore at the Eemshaven port, with future

targets to produce hydrogen at sea once the technology

matures (NortH2 2024). The Netherlands was the ﬁrst

country to pilot oshore green hydrogen production

through the PosHYdon project, which integrated the

following three energy systems in the Dutch North Sea:

oshore wind, oshore gas, and oshore hydrogen.

Green hydrogen is mixed with gas and transported via an

existing gas pipeline to the coast (PosHYdon 2024).

Near the port of Rotterdam, the Holland Hydrogen I

project aims to connect 200-MW electrolyzers with

oshore wind to serve the industrial areas in the port

(Shell 2022). Another key project for large-scale oshore

wind development is underway north of the Wadden

Islands in the North Sea, with a 500-MW electrolysis

capacity expected to be operational by 2031. The project

will source energy from approximately 4 GW of oshore

wind power and use an existing natural gas pipeline for

hydrogen transport (Enerdata 2024).

The UK is actively pursuing several oshore wind-to-

hydrogen projects as part of its broader strategy to

achieve net-zero carbon emissions by 2050. These

projects are designed to leverage the UK’s substantial

oshore wind resources to produce green hydrogen. This

hydrogen can be used to decarbonize various sectors,

including industry, transportation, and heating. On its

east coast, the UK has ﬁve hydrogen production hubs,

with a targeted hydrogen capacity of 11.6 GW by 2037, of

which 5.2 GW are projected to be green hydrogen. This

approach aims to leverage the region’s concentrated

industrial energy demand, signiﬁcant gas storage and

oshore wind power (East Coast Hydrogen 2023). The

Barrow Green Hydrogen Hub is a planned project in

Cumbria that seeks to produce green hydrogen from

35-MW electrolyzers using solar power and oshore

wind power from the Irish Sea. The hydrogen produced

will be used to decarbonize local industries (Barrow

Green Hydrogen 2024). The Deepwater Oshore Local

Production of Hydrogen (Dolphyn) project focuses on

developing technology that allows hydrogen production

from seawater to take place directly on ﬂoating oshore

wind platforms. This technology is in the trial phase, with a

target to commercialize it before 2030 (Dolphyn Hydrogen

2024). The Dolphyn project in the UK has reported that

decentralized hydrogen production via ﬂoating oshore

wind and PEMEL systems are the most cost-eective

approaches, with a levelized cost of hydrogen (LCOH) of

approximately £2/kg at 100 km oshore (Kang, Gbadago,

and Hwang 2024).

ScotWind is a major oshore wind leasing round

managed by Crown Estate Scotland, which has opened

up vast areas of Scotland’s seabed for oshore wind

development. Some of these projects are exploring

the integration of hydrogen production. A study

by the Net Zero Technology Centre (NZTC) on the

Hydrogen Backbone Link has highlighted potential

complementarities between the ScotWind leasing sites

and a potential hydrogen pipeline from Scotland to

Europe to utilize approximately 10 GW of wind power

(NZTC 2023).

Denmark, known for its leadership in wind energy, is now

focusing on green hydrogen as a key part of its energy

transition strategy. The country is working on ambitious

projects to produce green hydrogen from oshore wind.

One of these projects is the Energy Island North Sea,

which aims to create the world’s ﬁrst artiﬁcial energy

island. The island will serve as a hub for oshore wind

farms and green hydrogen production, connecting up to

10 GW of oshore wind capacity. The generated power

can either feed into the grid or be used for hydrogen or

other power-to-X products (DEA 2024).

Similarly, on its Baltic Sea coast, the Bornholm Energy

Island project aims to connect up to 3 GW of oshore

wind capacity to the energy island. The project plans to

produce green hydrogen for domestic use and export.

The H2RES Project aims to establish a small-scale

electrolysis facility powered by oshore wind turbines.

The 2-MW demonstration project will use two 3.6-

MW oshore wind turbines to power green hydrogen

production (Ørsted 2021).

Sweden is planning to build the Neptunus Energy Hub

in the southern Baltic Sea. This energy hub is set to

feature up to 3.1 GW of oshore wind capacity, and a

portion of this electricity will be used to produce up to

370 kilotons (kt) of green hydrogen per year through

oshore electrolyzers.

Additionally, the Polargrund Energy Hub, situated in

the northern Gulf of Bothnia, aims to have a capacity of

3-GW oshore wind and will include electrolyzers that

can produce up to 200 kt of green hydrogen per year.

These projects are important parts of Sweden’s strategy

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

to expand its renewable energy infrastructure and reduce

carbon emissions, with operations expected to begin by

the early 2030s (Enerdata 2024). In Vietnam, the use of

2 GW of oshore wind for hydrogen production by 2035

has been proposed. This proposal is part of the country’s

broader energy transition strategy, which includes

signiﬁcant oshore wind development and the integration

of green hydrogen production to support its 2050 net-

zero emission target (Enerdata 2024).

2.2 Literature

Review of Oshore

Wind and Hydrogen

Production

Recent studies have focused on evaluating the

technoeconomic feasibility of integrating oshore wind

energy with hydrogen production to increase energy

sustainability and reduce curtailment issues. Oshore

wind farms face signiﬁcant challenges related to high

installation costs and grid connection diculties,

particularly due to the higher capacitance in underwater

AC cables. While HVDC systems can mitigate energy

loss, they have higher installation costs than do other

systems. This situation has prompted the exploration of

innovative alternatives, such as producing hydrogen at

sea and transporting it to land without direct electricity

grid connections (Calado et al. 2024; Kang, Gbadago,

and Hwang 2024). In fact, some studies have reported

that oshore hydrogen production is more cost-eective

than is the construction of HVDC networks for onshore

hydrogen production, especially in remote locations and

for large capacities (Glaum, Neumann, and Brown 2024;

Ibrahim et al. 2022; Wang et al. 2024). Conversely, wind

farms located close to shore are likely connected to

onshore facilities via power cables (Lüth et al. 2023).

Compared with underwater electrical cables, the

transportation of energy via underwater hydrogen

pipelines is an appealing option because of lower energy

losses, lower costs, and improved scalability (Calado

et al. 2024). This approach allows oshore wind farms

to bypass grid connections entirely, increasing their

feasibility and eciency when combined with onsite

hydrogen production in areas with high wind power

density (Bonacina, Bordbar Gaskare, and Valenti 2022;

Giampieri, Ling-Chin, and Roskilly 2024).

Promising developments in the oshore wind-to-hydrogen

sector involve the use of ammonia as a renewable

hydrogen carrier for long-distance interoceanic transport.

Studies have suggested that the transportation costs of

ammonia are lower than are the expenses associated with

hydrogen conversion, storage, and reconversion. While

liquid hydrogen is also considered promising because

of its lower cost and greater ﬂexibility in delivery, it faces

signiﬁcant energy loss during storage and transport (Díaz-

Motta, Díaz-González, and Villa-Arrieta 2023; Bonacina,

Bordbar Gaskare, and Valenti 2022). Ammonia, with its

relatively high volumetric energy density and existing

global infrastructure for storage and transport, is gaining

attention as a critical component in the emerging hydrogen

and green hydrogen economy (Díaz-Motta, Díaz-González,

and Villa-Arriet 2023; Perez-Vigueras et al. 2023).

Proton exchange membrane (PEM) electrolyzers are well

suited for oshore wind integration because of their high

eciency, rapid response to variable loads, and ability

to adapt to the intermittency of wind power. Compared

with other electrolysis technologies, the superior

performance of PEM electrolyzers makes them ideal for

oshore hydrogen production (Farahmand, Günther, and

Kristiansen 2024; Guven 2024; Akdağ 2023; Luo et al.

2022). To produce hydrogen at sea, electrolyzers require

high-purity water, which is typically obtained through

reverse osmosis or other water treatment processes to

ensure the necessary quality (Komorowska, Benalcazar,

and Kamiński 2023). Desalination coupled with

seawater electrolysis is feasible but requires signiﬁcant

technological advancements (Ramakrishnan et al. 2024).

The integration of hydrogen production into oshore

wind shows promise, but several challenges need to

be addressed. Farahmand, Günther, and Kristiansen

(2024); Komorowska, Benalcazar, and Kamiński (2023)

have highlighted the need for substantial investments in

infrastructure, such as pipelines and storage facilities, to

manage the produced hydrogen. Additionally, the above

authors have noted that regulatory frameworks and

market mechanisms need to evolve to support the large-

scale deployment of these systems. Distributed hydrogen

production, which eliminates the need for centralized

onshore facilities, has been demonstrated to be more

cost-eective than other types of hydrogen production,

especially in marine environments (Kang, Gbadago, and

Hwang 2024).

In recent studies, Bonacina, Bordbar Gaskare, and Valenti

(2022) and Díaz-Motta, Díaz-González, and Villa-Arriet

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

(2023) have investigated the environmental sustainability

of producing hydrogen via oshore wind. Both studies

have concluded that oshore wind-powered hydrogen

production has a lower environmental impact than

conventional hydrogen production. Despite its signiﬁcant

potential and low environmental impact, the oshore wind

sector faces high installation costs and the challenges of

operating under harsh environmental conditions (Rezaei,

Akimov, and Gray 2024). Some research on electrolysis

has emphasized the use of surplus renewable energy.

This approach increases production costs because both

hydrogen and electricity need to be exported. Recent

studies have suggested that relying solely on excess wind

energy is not economically viable. Instead, dedicated

oshore wind farms for hydrogen production should be

prioritized (Hill et al. 2024; Bonacina, Bordbar Gaskare,

and Valenti 2022).

The uncertainty in cost assumptions presents a signiﬁcant

challenge for oshore wind-hydrogen systems. The LCOH

is highly sensitive to the electricity costs associated

with oshore wind farms (Bødal et al. 2024). Existing

technoeconomic studies have often lacked clarity

in terms of hydrogen production costs. Additionally,

electrolyzer eciency is sensitive to ﬂuctuations

in input power, necessitating dynamic models to

accurately estimate hydrogen production costs (Rezaei,

Akimov, and Gray 2024; Hill et al. 2024). This ambiguity

emphasizes the need for more detailed and transparent

analyses to assess the ﬁnancial feasibility of oshore

wind-hydrogen systems.

2.3 LCOH from

Oshore Wind

The TEA of hydrogen production from oshore wind

energy is an important area of focus in current research.

A consistent theme across several studies is the

evaluation of the LCOH under dierent scenarios and

timelines. Studies such as that of Groenemans et al.

(2022) have demonstrated that directly coupling PEM

electrolysis (PEMEL) systems with oshore wind turbines

can potentially lower the LCOH to $2.09/kg via pipelines,

compared with $3.86/kg from traditional electrolysis using

transmitted electricity, assuming an accelerated price

reduction in the main components. Similarly, Giampieri,

Ling-Chin, and Roskilly (2024) have conducted a detailed

case study on the UK, using simulation models to analyze

the costs and technical requirements of hydrogen

production, storage, and transportation in various oshore

wind-to-hydrogen scenarios, revealing that compressed

hydrogen, which is produced oshore and transported

via pipelines, is the most cost-eective scenario,

potentially lowering the LCOH from 6.6 $/kg at present to

approximately $2.9/kg by 2050.

Kang, Gbadago, and Hwang (2024) have examined

the feasibility of hydrogen production by FOWFs o

the Korean Peninsula highlighting that liquid hydrogen

production becomes more cost-eective at scales up

to 250 MW, with the LCOH holding at approximately

11 $/kg. The above study has suggested that speciﬁc

regional conditions and synergies can further enhance

the economic viability of oshore wind-to-hydrogen

systems. Bonacina, Bordbar Gaskare, and Valenti (2022)

have explored the viability of creating oshore liqueﬁed

hydrogen production plants powered by wind energy

for the purpose of refueling ships, aiming to reduce

carbon emissions in the naval sector. The above study

employs an analytical model combined with an economic

prefeasibility analysis and uses MATLAB simulations to

assess the performance and economic metrics of dierent

plant conﬁgurations, with a focus on the optimal sizing

of wind farms and hydrogen production capacity. The

above study has revealed that the LCOH can be below

$4.37/kg for a wide range of plant capacities, suggesting

that oshore liqueﬁed hydrogen production plants are

economically feasible.

Rezaei, Akimov, and Gray (2024) have modeled the cost

and eciency of hydrogen production from oshore wind

power in Australia via a dynamic system that accounts for

real-world factors such as economies of scale, learning

by doing, and the variable nature of wind power input.

The study has revealed that the LCOH can be reduced to

approximately $2.6/kg in the “fast progress” scenario by

2040, given a rapid scale-up and lower ﬁnancial costs.

The study assumes that PEM technology will continue

to dominate hydrogen production from oshore wind.

Moreover, Cheng and Hughes (2023) have explored

the role of oshore wind in Australia’s renewable

hydrogen production via a least-cost optimization model

to simulate energy ﬂows and optimize the capacities

of oshore wind, solar photovoltaics (PV), battery

storage, and electrolyzers. The study has revealed that

a hybrid renewable energy system can reduce hydrogen

production costs to $2.96-$3.71/kg by 2030.

Hill et al. (2024) have developed a technoeconomic model

that incorporates Monte Carlo simulations to account

for uncertainties to determine the cost competitiveness

of hydrogen produced from oshore wind power and

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

compared dierent electrolysis technologies. The

results indicate that hydrogen produced through alkaline

electrolysis (AEL) is the most cost-eective type of

hydrogen, with an LCOH of €7.66/kg in the base case,

which is potentially lower under optimized scenarios. In

contrast to other studies that prefer PEMEL over AEL, the

above paper argues that the modular nature of operating

98 AEL stacks allows the system to adapt to intermittent

generation. The weighted average cost of capital (WACC)

has a strong inﬂuence on the LCOH in all the scenarios.

Rogeau et al. (2023) have conducted a resource

assessment across Europe, employing a detailed cost

modeling approach combined with geospatial analysis.

The study estimates that more than 1000 terawatt hours

(TWh) of green hydrogen could be produced at a price

below $3.3/kg by 2030, making it competitive with gray

hydrogen. The above study has highlighted the potential

of decentralized oshore electrolysis conﬁgurations

in maximizing the use of Europe’s extensive oshore

wind resources.

Lucas et al. (2022) have analyzed the feasibility of

producing hydrogen via electricity generated from the

WindFloat Atlantic oshore wind farm in Portugal. The

study considers PEM electrolyzer systems and evaluates

the costs and beneﬁts of hydrogen production under

dierent electricity price conditions. Hydrogen production

from oshore wind energy can become proﬁtable at

$4.40/kg LCOH with larger wind farm capacities and

when hydrogen is produced during periods of low

electricity prices. Calado et al. (2024) have assessed

the technoeconomic viability of hydrogen production

associated with oshore wind farms, taking the Iberian

Peninsula as a case study. The study involves the

modeling and simulation of the following two hydrogen

production systems: one with an oshore electrolyzer

and another with an onshore electrolyzer. The onshore

electrolyzer system is more economically viable than

is the oshore system, mainly because of its ability to

purchase electricity from the grid, resulting in a lower

LCOH. The LCOH for the onshore system decreases

signiﬁcantly from 2020 to 2030 and then to 2050 as

follows: €5.84/kg ($6.15/kg), €3.42/kg ($3.60/kg), and

€2.57/kg ($2.71/kg). In the oshore electrolyzer case, the

LCOH is €8.98/kg ($9.47/kg), €4.37/kg ($4.61/kg), and

€2.68/kg ($2.83/kg).

Guven’s (2024) study employs life cycle assessment

(LCA) via GREET to assess the environmental impact and

economic feasibility of producing green hydrogen via

oshore wind power. The paper concludes that while

oshore wind-driven green hydrogen production has

signiﬁcant environmental beneﬁts, achieving economic

viability requires targeted incentives. The LCOH is

estimated at $4.36/kg under the base scenario, which is

not proﬁtable under the current corporate tax rate. Akdağ

(2023) has focused on the operation of green hydrogen

production via oshore wind in Turkey, highlighting the

importance of infrastructure investments and supportive

policies. The study estimates that the cost per kg of

hydrogen could drop from €6.26/kg ($6.60/kg) in 2023

to €1.13/kg ($1.19/kg) by 2050. The analysis also shows

that despite initial high costs, green hydrogen can

become a viable alternative for fueling stations and the

transportation sector with proper policy support and

technological advancements.

Farahmand, Günther, and Kristiansen (2024) have

explored the potential beneﬁt of hydrogen in terms of

the oshore wind utilization rate in the North Sea. The

study uses a deterministic optimization model (PowerGIM)

to assess the optimal transmission expansion plan and

generation expansion plan for the North Sea Oshore

Grid, including the integration of a PEM electrolyzer for

hydrogen production. Their study ﬁnds that coupling

hydrogen with oshore wind can reduce wind curtailment

and drive the LCOH to €1.4/kg ($1.47/kg) by 2040

when electrolyzer demand is optimized in a market

context. Komorowska, Benalcazar, and Kamiński (2023)

have focused on assessing the competitiveness and

uncertainty of oshore wind-to-hydrogen production

systems in Poland and used a Monte-Carlo-based

framework to analyze location-based variability and

long-term planning uncertainties. By analyzing 23

planned oshore wind farm locations in Poland, the

LCOH for oshore wind-to-hydrogen is estimated to be

between €3.60 ($3.79/kg) and €3.71/kg ($3.90/kg) in

2030 and between €2.05 ($2.16/kg) and €2.15/kg ($2.26/

kg) in 2050. The study ﬁnds that electricity prices and

electrolyzer utilization rates are the main cost drivers of

the LCOH.

Díaz-Motta, Díaz-González, and Villa-Arriet (2023)

have evaluated the long-term sustainability and

competitiveness of producing renewable ammonia

via oshore wind energy, focusing on the production

process, technological advancements, and potential cost

reductions in the coming decades. The analysis ﬁnds

that the high production costs of oshore wind-powered

ammonia (ranging from $600 to $1,500/t NH₃) currently

pose a barrier to its deployment.

The LCOH is highly sensitive to several region-speciﬁc

factors, such as natural resources, the cost of electricity,

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

infrastructure, and technological advancements. For

Saudi Arabia, understanding the real economics of

producing hydrogen from oshore wind is essential

for assessing the feasibility of this option as a viable

green hydrogen source. Moreover, benchmarking its

competitiveness against international ﬁgures is important

given Saudi Arabia’s ambition to become a leader in the

energy transition.

As summarized in Table 1, no previous technoeconomic

study has speciﬁcally assessed the integration of oshore

wind into hydrogen production in Saudi Arabia. This

study aims to ﬁll this gap by developing a transparent

deterministic cost model for the LCOH, focused on the

natural resources of Saudi Arabia. Through a detailed

case study of a selected wind farm location in the Red

Sea, this research will evaluate the cost-eectiveness

and eciency of onshore versus oshore hydrogen

electrolysis. By identifying speciﬁc cost drivers, this study

will inform policymakers and industry stakeholders in

focusing on targeted innovations, realistic timelines, and

research and development (R&D) investments that have

the greatest potential to lower costs.

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

Table 1. Comparison of oshore wind-based hydrogen production studies.

Reference Location Objective Methodology Components

assessed

Results

Farahmand,

Günther, and

Kristiansen

(2024)

North Sea,

Europe

This paper assesses

the business case for

integrating oshore wind

with green hydrogen

production in the North

Sea while considering the

future development of an

integrated oshore grid.

This study uses a deterministic

optimization model (PowerGIM)

to optimize the North Sea

oshore grid’s expansion plans,

integrating a PEM electrolyzer

for hydrogen production. The

analysis is based on the TYNDP

2020 Global Ambition scenario

for 2040.

Fixed wind turbines,

PEM electrolyzers,

the direct coupling

of wind and

electrolysis, and the

hydrogen pipeline.

Combining a 5-GW PEM

electrolyzer with oshore

wind farms reduces wind

curtailment and boosts

electricity market revenue.

This study suggests that the

LCOH could drop to €1.4/

kg H2, with power costs as

the main factor. Sensitivity

analysis shows the LCOH

ranging between €1.2 and

€1.6/kg of hydrogen in

2030 based on electrolyzer

CAPEX, lifetime, and

eciency variations.

Calado et al.

(2024)

Iberian

Peninsula

This study assesses the

feasibility and economic

potential of integrating

hydrogen production with

oshore wind farms in the

Iberian Peninsula.

This study involves the modeling

and simulation of the following

two hydrogen production

systems: one with an oshore

electrolyzer and another with

an onshore electrolyzer. An

hourly optimization algorithm

and neural network forecasts are

used to assess day-ahead power

production and electricity prices.

Floating wind

turbines, HVAC

cables, oshore

central platform,

PEM electrolyzer,

desalination unit,

compressor,

hydrogen pipeline,

hydrogen storage,

fuel cell, and

transmission cables.

The onshore electrolyzer

system is more economically

viable than is the oshore

system due to its ability to

purchase electricity from

the grid, resulting in a lower

LCOH. The LCOH for the

onshore system decreases

signiﬁcantly from 2020 to

2030 and then to 2050:

€5.84/kg, €3.42/kg, and

€2.57/kg. While the oshore

electrolyzer case LCOH is

€8.98/kg, €4.37/kg, and

€2.68/kg.

(Continued)

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

Reference Location Objective Methodology Components

assessed

Results

Bonacina,

Bordbar

Gaskare,

and Valenti

(2022)

Mediterranean

Sea, Italy

To explore the viability of

creating oshore liqueﬁed

hydrogen production

plants powered by wind

energy for the purpose

of refueling ships, this

work aims to reduce

carbon emissions in the

naval sector.

This study employs an analytical

model combined with an

economic prefeasibility analysis.

MATLAB simulations are used

to assess the performance

and economic metrics of

dierent plant conﬁgurations,

focusing on the optimal sizing

of wind farms and hydrogen

production capacities.

Fixed wind

turbines, ﬂoating

wind turbines,

desalination unit,

electrolyzer,

liquiﬁcation plant,

hydrogen storage,

and ship transport.

The study ﬁnds that the

LCOH can be below €4/

kg for a wide range of plant

capacities, and the optimal

electrolyzer capacity is

between 80% and 90%

of the wind farm capacity.

The payback time can be

reduced to below 11 years

if the wind farm capacity is

more than 150 MW.

Díaz- Motta,

Díaz-

González,

and Villa-

Arrieta

(2023)

– To evaluate the long-

term sustainability and

competitiveness of

producing renewable

ammonia using oshore

wind energy, this study

focuses on the production

process, technological

advancements, and

potential cost reductions

in the coming decades.

This study conducts a literature

review and quantitative analysis,

comparing the production costs,

energy consumption, eciency,

and CO₂ emissions of oshore

wind-powered ammonia with

fossil-based (steam methane

reforming) and low-emission

ammonia (SMR-carbon capture

and storage).

Fixed wind

turbines, ﬂoating

wind turbines,

desalination unit,

electrolyzer, air

separation unit, and

ammonia synthesis.

The analysis ﬁnds that the

high production costs of

oshore wind-powered

ammonia (ranging from

$600 to $1,500/t NH₃)

currently pose a barrier to

its deployment. However,

improvements in solid

oxide electrolysis (SOEL)

technology and reductions

in CAPEX could make it

competitive in the future.

Komorowska,

Benalcazar,

and Kamiński

(2023)

Baltic Sea,

Poland

This work aims to evaluate

the competitiveness

of green hydrogen

production from oshore

wind farms in Poland by

analyzing the LCOH and

exploring uncertainties

in the planning and

development of

these systems.

The study uses a Monte-Carlo-

based framework to assess

the LCOH for oshore wind-to-

hydrogen systems, considering

23 planned oshore wind farm

locations in the Baltic Sea. The

analysis includes a comparison

with onshore wind-to-hydrogen

systems for 2030 and 2050.

Fixed wind turbines,

PEM electrolyzer,

transmission cables,

and water prices.

The LCOH for oshore

wind-to-hydrogen in Poland

is estimated to be between

€3.60 and €3.71/kg in 2030

and between €2.05 and

€2.15/kg in 2050. This study

ﬁnds that electricity prices

and electrolyzer utilization

rates are the main cost

drivers for the LCOH.

(Continued)

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

Reference Location Objective Methodology Components

assessed

Results

Lucas et al.

(2022)

Atlantic

Ocean,

Portugal

This study aims to

assess the feasibility

and economic viability

of producing hydrogen

from oshore wind

energy, speciﬁcally using

the WindFloat Atlantic

oshore wind farm as a

case study. This study

also evaluates dierent

scenarios for hydrogen

production and potential

proﬁts from oxygen sales.

The study adopts a

technoeconomic analysis,

considering the following two

scenarios: one with the current

25.2-MW capacity of the

WindFloat Atlantic wind farm and

another with a future expanded

capacity of 150 MW. The study

considers PEM electrolyzer

systems and evaluates the

costs and beneﬁts of hydrogen

production under dierent

electricity price conditions.

Floating wind

turbines, PEM

electrolyzer,

water treatment,

compressor,

hydrogen storage,

HVAC cables,

and substation.

The study ﬁnds that

hydrogen production is more

economically viable in the

long-term scenario with a

150-MW wind farm capacity

than in the other scenario.

The lowest hydrogen

production costs are

achieved when hydrogen is

produced during both night

and afternoon periods, with

the potential for proﬁtable

operations depending on

electricity prices and the

inclusion of oxygen sales.

Guven (2024) Aegean Sea,

Turkey

This work assesses the

environmental impact

and economic feasibility

of producing green

hydrogen using oshore

wind power, with a

focus on minimizing

greenhouse gas emissions

and optimizing the

cost-eectiveness of

the technology.

This study employs LCA using

GREET 2023 and life cycle

cost analysis (LCCA) under

various economic scenarios,

including STEPS, APS, and NZE,

to evaluate the environmental

and ﬁnancial performance of

the green hydrogen production

system. Global climate models

(GCMs) are used to predict wind

speeds for system sizing.

Fixed wind turbines,

PEM electrolyzer,

hydrogen storage,

transmission cables,

and substation.

The global warming potential

(GWP) of the system is

0.7 kgCO2-eq./kgH2 for a

20-year horizon and 0.753

kgCO2-eq./kgH2 for a 100-

year horizon. The LCOH is

estimated at $4.36/kgH2

under the base scenario.

This study ﬁnds that the

system is not proﬁtable

under the current corporate

tax rate without incentives,

with internal rates of return

(IRRs) below the expected

cost of equity.

(Continued)

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

Reference Location Objective Methodology Components

assessed

Results

Hill et al.

(2024)

Oshore, UK This study aims to

determine the cost

competitiveness of

hydrogen produced from

oshore wind power,

comparing dierent

electrolysis technologies

(alkaline and PEM) and

considering the impact of

integrating grid electricity

and salt-cavern storage

for hydrogen production.

This study aims to inform

strategies for lowering the

LCOH to compete with

conventional hydrogen

production methods.

The study develops a

technoeconomic model,

incorporating Monte Carlo

simulations to account for

uncertainties, and evaluates the

following three scenarios: AEL,

PEMEL, and a grid electricity-

backed AEL system. The model

considers CAPEX, OPEX, and

hydrogen production eciency

under each scenario, alongside

sensitivity analyses to identify

key cost drivers.

Fixed wind turbines,

substations,

PEM and AEL

electrolyzers,

desalination unit,

compressor,

hydrogen pipe,

hydrogen storage,

oshore central

platform, and

transmission cables.

The results indicate that the

AEL-driven cost of hydrogen

production (€8.38/kgH2) is

only three times that of SMR

+ CCS-generated hydrogen.

PEMEL-driven hydrogen

production has a higher

cost (€10.49/kgH2). This

study identiﬁes the WACC,

wind farm CAPEX, and

electrolyzer eciency as the

most signiﬁcant cost drivers.

Akdağ (2023) Aegean Sea,

Turkey

This study presents a

comprehensive model

for the installation and

operation of a green

hydrogen production

facility powered by

oshore wind and to

evaluate its economic

viability, particularly in

the context of supplying

hydrogen fuel stations

in Turkey. This study

also aims to identify

the challenges and

potential solutions for

the widespread adoption

of green hydrogen

technology in the

transportation sector.

The study uses a

technoeconomic analysis

approach, incorporating data

on wind potential, desalination,

and electrolysis technology.

This work includes a case

study for the Edirne-Enez

location in Turkey, where the

oshore wind potential and

water availability are analyzed

to determine the feasibility of

setting up a green hydrogen

production facility. The analysis

also covers the cost of hydrogen

production and the associated

infrastructure, including storage

and transportation to hydrogen

fuel stations.

Fixed wind turbines,

PEM electrolyzer,

hydrogen

storage, and truck

hydrogen transport.

The results indicate that

the cost of producing green

hydrogen through oshore

wind could decrease

signiﬁcantly by 2050, making

it competitive with other

forms of hydrogen. This

study estimates that the cost

per kilogram of hydrogen

could drop from €6.26/kg in

2023 to €1.13/kg by 2050.

The analysis also shows

that despite initial high

costs, green hydrogen can

become a viable alternative

for fueling stations and the

transportation sector with

proper policy support and

technological advancements.

(Continued)

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

Reference Location Objective Methodology Components

assessed

Results

Cheng and

Hughes

(2023)

Oshore,

Australia

This work investigates the

role of oshore wind in a

hybrid renewable energy

system for hydrogen

production in Australia,

particularly focusing on

cost optimization and the

integration of oshore

wind into other renewable

energy sources like

solar PV.

The study uses a least-cost

optimization model to simulate

energy ﬂows and optimize the

capacities of oshore wind,

solar PV, battery storage, and

electrolyzers over a 10-year

period. The model evaluates

dierent scenarios, including

varying levels of solar PV

contribution and cost reductions.

Fixed wind turbines,

solar PV, pumped

hydrostorage,

battery storage,

PEM electrolyzer,

and HVDC cables.

This study ﬁnds that oshore

wind plays a signiﬁcant role

in hydrogen production,

especially in regions with

strong wind resources.

The cost of hydrogen can

be competitive with solar

PV-dominated systems under

certain conditions. However,

achieving a low-cost

hydrogen production system

requires further reductions

in the costs of oshore wind

and electrolyzers.

Giampieri,

Ling-Chin,

and Roskilly

(2024)

North Sea, UK This study analyzes the

economic feasibility of

dierent oshore wind-

to-hydrogen production

scenarios in the UK,

focusing on the LCOH for

compressed, liqueﬁed,

and chemically bonded

hydrogen, and to provide

insights into the most

cost-eective strategies

for future projects.

This study employs a TEA

approach, using simulation

models to analyze the costs

and technical requirements

of hydrogen production,

storage, and transportation

scenarios. Data for capital and

operating costs are collected,

and scenarios are developed

to estimate the LCOH under

various conditions.

Fixed wind turbines,

substations, PEM

electrolyzer,

desalination unit,

liquiﬁcation unit,

ammonia synthesis,

compressor,

hydrogen pipe,

hydrogen storage,

liquid ship tanker,

and HVDC cables.

This study ﬁnds that

compressed hydrogen

produced oshore and

transported via pipeline

is the most cost-eective

scenario for projects starting

in 2025, with the LCOH

potentially reaching £2/

kg of hydrogen or lower

by 2050. The economic

feasibility of each scenario

varies signiﬁcantly based

on storage periods and

distances to shore.

(Continued)

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

Reference Location Objective Methodology Components

assessed

Results

Rogeau et al.

(2023)

Oshore,

Europe

This work aims to develop

a uniﬁed cost model that

incorporates various

conﬁgurations (onshore,

centralized oshore, and

decentralized oshore

electrolysis) and to

perform a resource

assessment at the

European scale. This study

aims to identify the most

economically attractive

sites for hydrogen

production from oshore

wind by 2050.

This study employs a detailed

cost modeling approach

combined with geospatial

analysis to assess the LCOH

across dierent sites in Europe.

The analysis includes onshore

and oshore electrolysis

conﬁgurations and considers

future projections of turbine and

electrolyzer costs.

Fixed wind turbines,

PEM electrolyzer,

desalination

unit, oshore

central platform,

turbine integrated

electrolysis,

hydrogen pipe,

HVDC cables,

and substations.

This study ﬁnds that the

LCOH could fall from €4.50-

€7.50/kg in 2020 to €1.50-

€3.00/kg in 2020 to 1.5–3.0

€/kg by 2050 as costs

decrease. More than 1,000

TWh of green hydrogen

could be produced at a price

below €3.0/kg by 2030,

making it competitive with

gray hydrogen. Oshore

electrolysis becomes

increasingly relevant closer

to shore over time.

Rezaei,

Akimov, and

Gray (2024)

Oshore,

Australia

This study models the

cost and eciency of

hydrogen production from

oshore wind power using

a dynamic system that

accounts for real-world

factors such as economies

of scale, learning by doing,

and the variable nature

of wind power input. This

study aims to determine

the LCOH under

dierent scenarios.

This study uses a detailed

technoeconomic model

that incorporates dynamic

electrolyzer eciency, air

density-adjusted wind speeds,

and plant-level losses to simulate

hydrogen production. The model

is applied to various oshore

wind sites in Australia to assess

the feasibility of achieving a

competitive LCOH by 2040.

Fixed wind

turbines, PEM

electrolyzer, central

oshore platform,

compressor, and

hydrogen storage.

This study ﬁnds that the

LCOH can be reduced to

below AU$3/kg (US$2/

kg) in the “fast progress”

scenario by 2040, given a

rapid scale-up and lower

ﬁnancial costs. Dynamic

eciency and well-planned

energy management

strategies are crucial in

achieving cost-competitive

hydrogen production.

(Continued)

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

Reference Location Objective Methodology Components

assessed

Results

Kang,

Gbadago,

and Hwang

(2024)

Oshore,

Republic of

Korea

This work aims to

determine the LCOH for

both gaseous and liquid

hydrogen produced using

ﬂoating oshore wind

turbines and to assess

the economic viability of

dierent transportation

methods for hydrogen

in Korea.

The study uses Aspen Plus

and Custom Modeler to

model PEMEL and hydrogen

liquefaction processes,

includes a sensitivity analysis

of transportation methods and

costs, and considers real-

time wind data for modeling

power generation.

Floating wind

turbines, PEM

electrolyzer,

water treatment,

compressor,

hydrogen pipe,

liquiﬁcation

unit, and truck

H2 transport.

This study ﬁnds that liquid

hydrogen is more cost-

eective at scales up to 250

MW, with an LCOH of $11.04/

kg H2. However, gaseous

hydrogen becomes less

expensive as production

scales exceed 500 MW due

to its greater sensitivity to

production volume.

Groenemans

et al. (2022)

Atlantic

Ocean, U.S.

This study evaluates the

economic viability and

eciency of producing

hydrogen directly at

oshore wind sites using

PEMEL, comparing it

to traditional methods

where electricity is

transmitted to shore for

hydrogen production.

This study uses a TEA approach,

modeling the hydrogen

production process using

real wind data and comparing

costs across methods. The

assumptions include a 14-MW GE

turbine and a pipeline length of

60 km.

Fixed wind turbines,

transmission

cables, and

PEM electrolyzer.

The results show that the

LCOH from direct oshore

wind electrolysis could

be as low as $2.09/kg H2,

compared to $3.86/kg H2

from traditional electrolysis

using transmitted electricity.

This work Red Sea,

Saudi Arabia

This work aims to evaluate

the LCOH of green

hydrogen production from

oshore wind in Saudi

Arabia, with a focus on

assessing the feasibility

of this option as a viable

green hydrogen source.

This study uses a deterministic

technoeconomic assessment

of green hydrogen production

from oshore wind in Saudi

Arabia, comparing centralized

onshore and oshore

electrolysis approaches. This

study analyzes the LCOH for

both scenarios, identiﬁes the

key cost drivers, and assesses

the competitiveness of each

approach for large-scale

hydrogen production.

Floating wind

turbines,

substations, PEM

electrolyzer,

desalination unit,

compressor,

hydrogen pipe,

oshore central

platform, and

HVAC cables.

This study aims to provide

a transparent deterministic

cost model for the LCOH

from ﬂoating oshore wind

power in the context of

Saudi Arabia.

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

3. Technoeconomic

Assessment of

Hydrogen Production

from Oﬀshore Wind

in Saudi Arabia

In this study, the following two cases will be compared: onshore electrolysis

and centralized oshore electrolysis. Decentralized hydrogen production

will be discussed qualitatively. The analysis will begin with the selection of a

suitable oshore wind farm location. Locating oshore wind farms is based

on a prior study, and turbines will be located 35-km oshore at water depths

of approximately 720 m, opposite Duba port in the Red Sea. The wind farm’s

capacity will be set to 1,000 MW, chosen to represent a GW-scale project, which

is reasonable for oshore wind development and provides a reference point

for scaling costs up or down for various project sizes. The capital expenditure

(CAPEX) estimates will be derived from BVG Associates’ guidelines for FOWF

costs (BVGA 2023). While the cost estimates and projections from BVGA will

provide a valuable reference for understanding the potential cost structure

of ﬂoating oshore wind, these ﬁgures are based primarily on conditions and

markets in Europe, where ﬂoating wind technology and supply chains are

more mature. In the context of Saudi Arabia, unique local factors, such as site-

speciﬁc conditions, infrastructure readiness, and supply chain maturity, may lead

to cost variances. Nonetheless, BVGA’s guidelines will oer a solid foundation

for the technical assumption and provide insights into how costs may evolve

as the industry matures globally, which can inform preliminary assessments for

Saudi oshore wind projects. CAPEX encompasses development and project

management, wind turbines, the balance of plants, and installation costs.

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

Aqaba

Tabouk

Al-Tubayq

Natural Reserve

St. Catherine’s

Reserve

Duba Port

Potential Suitable

Locations for FOWFs

Protected Areas

Saudi Admin Boundary

Esri, FAO, NOAA, USGS, Esri, HERE,

Garmin, FAO, NOAA, USGS, Esri, USGS

0 25 50 100 150

The Red Sea

Sea Port

Yanbu Commercial Port

Yanbu

King Fahd Industrial

Port in Yanbu

SAUDI

ARABIA

Al Madinah

3862 km2

4593 km2

Hijaz Mountains

IRAN

Tabuk

South Sinai

Figure 2. Potential areas for ﬂoating oshore wind project development.

Source: Albalawi et al. 2024.

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

3.1 Hydrogen

Production from

Onshore Electrolysis

In the case of transmitting generated electricity to

shore, HVAC transmission is assumed because of the

relatively short distance involved. Oshore and onshore

substations are employed to optimize power conversion

and ensure ecient transmission. Our model shows

that the CAPEX of the wind farm, including the export

cables for the onshore electrolysis case, is $4,993/

kW. Additionally, the operation and maintenance (O&M)

costs are assumed to be 2% of the total CAPEX per year.

Decommission costs are estimated at 4% of CAPEX

(BVGA 2023).

To estimate the wind farm’s annual energy production, we

start by calculating the capacity factor (CF). This is done

via a methodology similar to that outlined in Chandler and

Whitlock (2005), which involves analyzing hourly wind

speed data against the turbine power curve. Wind speed

data are obtained from NASA’s power tool for the period

from 2021 to 2023. We choose a three-year average to

account for annual and seasonal variations in wind speed.

The wind speed data are then adjusted to a hub height of

136 m, which corresponds to the NREL annual technology

baseline turbine used in our analysis (NREL 2021). Wind

speed is adjusted via Gipe’s power law, and a surface

roughness exponent of 0.1 is used for open water (Gipe

1999). Next, we employ the speciﬁed power curve of the

15-MW NREL model turbine to correlate the adjusted wind

speeds with the estimated power output.

Rated power (MW)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25

Wind speed (m/s)

Source: NREL 2021.

Figure 3. NREL ATB reference 15-MW turbine power curve.

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

The CF is then calculated by dividing the total annual estimated power output by the theoretical maximum energy that can

be produced, which is the product of the turbine’s rated capacity and the total number of hours in a year:

  

  

Our analysis yields a CF of 38.51%. Table 1 outlines the speciﬁc characteristics of the wind farm.

Using the above inputs, we calculate the levelized cost of electricity (LCOE) for the wind farm over the project life cycle

using a discount rate (r) of 5% as follows:

 

    

󰇛  󰇜



󰇛  󰇜

Equation 1

The resulting LCOE for the 1,000-MW oshore wind farm is calculated to be approximately 1$124.19/MWh, including the

export cables used to transmit the power to shore.

To estimate the LCOH, the characteristics of the PEM electrolyzers are assumed, as shown in Table 2.

Table 2. Characteristics of the oshore wind farm.

Characteristics Value Reference

Site latitude 27.49 Selected site

Site longitude 35.05 Selected site

Distance from shore (km) 35 Selected site

Water depth (m) 720 Selected site

Wind farm capacity (MW) 1000 Assumed

Turbine rated power (MW) 15 NREL 2021

Turbine rotor diameter (m) 240 NREL 2021

Inter-array cable length (m) 100,500 Hill et al. 2024

Annual average wind speed at hub height (m/s) 7.04 NASA 2024

CF (%) 38.51 Model result

Discount rate (%) 5 Assumed

CAPEX ($/kW) 4,993.39 Total CAPEX

Development and project management ($/kW) 191.45 BVGA 2023

Wind turbine ($/kW) 1,755.4 BVGA 2023; DNV 2023

Balance of plant ($/kW) 2,884.29 BVGA 2023; DNV 2023

OPEX (% of CAPEX) 2 BVGA 2023; DNV 2023

Project life (years) 30 NREL 2021

Decommissioning (% of CAPEX) 4BVGA 2023

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

The LCOH is a key metric used to determine the cost-eectiveness of hydrogen production over the lifetime of a

project and is calculated via the following formula:

 

    

󰇛  󰇜



󰇛  󰇜

Equation 2

Table 3. Characteristics of the PEM onshore electrolyzers.

Characteristics Value Reference

Capacity of stack (MW) 20 Alhadhrami et al. 2024

Number of electrolyzer stacks 27 Model result

CAPEX ($/kW) 1450 Alhadhrami et al. 2024

OPEX (% of CAPEX) 2.5 Alhadhrami et al. 2024

Water consumption (L/kg) 9Alhadhrami et al. 2024

Eciency (%) 80 Alhadhrami et al. 2024

Energy input for 1 kg of hydrogen produced (kWh/kg) 50 Model result

Discount rate (%) 5 Assumed

Here, CAPEX includes the initial investment in wind

turbines, electrolysis systems, desalination units,

platforms, and pipelines (as applicable). Operational

expenditure (OPEX) covers ongoing maintenance,

operational costs, energy input for electrolysis, and any

other recurring expenses.

After performing the cost analysis over the expected

project lifetime, the LCOH is found to be $6.47/kg,

reﬂecting the weak cost-eectiveness of producing

hydrogen via oshore wind under the given assumption.

To put this ﬁnding into perspective, a previous KAPSARC

analysis showed that the LCOH using solar PV power is

approximately $3/kg (Alhadhrami et al. 2024). Clearly,

a signiﬁcant reduction in the cost of FOWF technology

is needed before it can be competitive with onshore

renewable energy.

Onshore electrolysis using oshore wind energy

beneﬁts from established onshore infrastructure and

reduces the need for complex oshore platforms and

equipment, making its O&M easier. However, despite

these advantages, the LCOH for onshore electrolysis

using FOWFs is notably greater than is that for onshore

electrolysis using solar PV. Currently, the LCOH for

oshore ﬂoating-wind-based hydrogen production

is signiﬁcantly higher than is that of solar PV-based

systems in Saudi Arabia. This signiﬁcant cost disparity

presents a challenge for the economic competitiveness

of hydrogen production from oshore wind in the

current market.

3.2 Hydrogen

Production from

Central Oshore

Electrolysis

Central oshore hydrogen production presents a

compelling approach to harnessing oshore wind energy

by centralizing the electrolysis process on an oshore

platform. For oshore hydrogen production, the wind

farm CAPEX is adjusted to exclude the costs of export

cables and substations, as no electrical energy needs

to be transmitted onshore. The 30 wind turbines are

connected via inner-array cables to an oshore platform

where the electrolyzers are centrally located. Additional

costs in this setup include the oshore platform,

desalination unit, compressors, and gas pipeline used to

transport the generated hydrogen to shore. The cost of

a new dedicated hydrogen pipeline, which factors in the

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

pipeline and compressor, is approximately $3.11 million/

km (Kotek, Takácsné Tóth, and Selei 2023).

The desalination system is sized to be 80% of the

electrolyzer capacity to account for a buer in the

desalination system capacity (Rogeau et al. 2023). The

cost of the desalination system is estimated via CAPEX

to be approximately $0.022/kg of hydrogen produced

(Singlitico, Østergaard, and Chatzivasileiadis 2021;

Donkers 2020). This simpliﬁed assumption allows for

direct cost estimation on the basis of hydrogen output.

The cost of ﬂoating oshore platforms for centralized

hydrogen production in waters deeper than 150 m,

where ﬂoating foundations are needed, is not explicitly

provided in the available data. However, this cost is

generally recognized as being high due to engineering

complexities and installation challenges at such

depths (Rogeau et al. 2023; Singlitico, Østergaard,

and Chatzivasileiadis 2021). Floating platforms, while

oering ﬂexibility in deep waters, are associated with

higher maintenance costs and risks due to factors such

as movement from wind and waves and vulnerability to

external damage (Gerrits 2017).

The CAPEX assumptions for these balance-of-plant

components are detailed in Table 3. The resulting

LCOH is calculated to be $8.01/kg, which is higher

than that in the case where the electrolyzers are

placed onshore.

Figure 4. CAPEX shares of the main components for the two scenarios.

Wind turbines Project ﬁnance Desalination unit Oshore central platform

PEM electrolyzers Pipeline and compressorWind farm BOS

100

Oshore electrolysis

Percentage

Onshore electrolysis

Source: Authors.

Table 4. Costs of the oshore hydrogen balance-of-system (BOS) components.

Characteristics Value Reference

Desalination CAPEX ($/kg hydrogen) 0.022 Singlitico et al. 2021; Donkers 2020; Hill et al. 2024;

Scottish Government 2020

Pipeline and compressor CAPEX ($/m) 3,110 Kotek et al. 2023; Hill et al. 2024; Scottish

Government 2020

Oshore platform CAPEX ($/MW) 1,668,300 Hill et al. 2024; Scottish Government 2020

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

The high LCOH for the onshore electrolysis case stems

primarily from the higher CAPEX associated with FOWFs

than with other types of wind farms. The installation

and maintenance costs of oshore turbines, the need

for high-voltage transmission infrastructure to bring

electricity onshore, and the inherent logistical challenges

of operating in harsh marine environments increase the

overall cost of hydrogen production.

For onshore electrolysis using oshore wind to become

economically competitive with solar PV, substantial

reductions in the cost of FOWFs are necessary. Advances

in technology, economies of scale, and improved

deployment techniques are essential to reduce the

costs of ﬂoating wind turbines and reduce the LCOH

for hydrogen production. As ﬂoating wind technology

matures, the potential for cost reductions can make

oshore wind a more attractive option for hydrogen

production in the future. The case for oshore wind in

hydrogen production may also become stronger as

land availability constraints for solar PV become stricter,

especially in densely populated regions or areas with

limited suitable land for solar development.

The CAPEX share of wind farm BOS decreases to $4,245/

kW for the oshore electrolysis case, as no electrical

transmission to shore is needed. Although the share of

PEM electrolyzers is slightly lower than that of onshore

electrolyzers, the overall cost increases because of the

additional expenses associated with oshore installation

and infrastructure. However, the costs related to the

central oshore platform, which hosts the electrolyzers,

are signiﬁcant. This platform introduces substantial

cost uncertainty, and its high CAPEX share complicates

accurate project feasibility assessments. Furthermore, this

uncertainty makes it challenging to estimate the potential

large-scale beneﬁts of oshore hydrogen production.

Theoretically, aggregating power outputs from several

wind farms and transporting the energy to shore as

hydrogen via a single pipeline appears advantageous.

In contrast, the electrical transmission of wind power to

shore requires each project to incur the same high costs

for substations and transmission lines. While the concept

of aggregating multiple wind farms seems promising,

current ﬁgures do not clearly indicate at what scale this

approach becomes economically favorable, further

complicating the assessment of its long-term feasibility.

Sensitivity analysis is conducted on the LCOH model for

the oshore electrolysis case to determine the primary

cost drivers for each scenario. In this analysis, the input

parameters are adjusted to their respective limits for each

scenario, with only one parameter altered at a time from the

baseline scenario to observe its impact on the LCOH. The

reduction range of 30% is based on a study by Catapult

(2021), which reveals that FOWF costs could decrease by

30%-50% by 2030, driven primarily by scaling turbine sizes,

economies of scale, and technological advancements.

A similar cost reduction is projected for electrolyzers,

with Fraunhofer (2021) estimating an ~30% decline in

electrolyzer costs by 2030 due to advancements in stack

components and manufacturing processes. The outcomes

of the sensitivity analysis are presented in Table 5. An

additional sensitivity analysis combining cost reductions in

the three main components simultaneously is considered

for both the onshore and oshore electrolysis cases to

estimate an optimistic lower bound for the LCOH. The

resulting range is between $4.57 and $6.07/kg.

Table 5. Sensitivity results for the oshore electrolysis case.

Input variableInput variable Base scenarioBase scenario Sensitivity analysisSensitivity analysis New LCOH ($/kg)New LCOH ($/kg) Change %Change %

Baseline LCOHBaseline LCOH 8.018.01

Turbine foundationTurbine foundation FloatingFloating FixedFixed 6.526.52 −19−19

Wind farm CAPEXWind farm CAPEX Business as Business as

usual (BAU)usual (BAU)

30% reduction30% reduction 6.736.73 −16−16

Electrolyzer CAPEXElectrolyzer CAPEX BAUBAU 30% reduction30% reduction 7.67.6 −5−5

Central oshore platform CAPEXCentral oshore platform CAPEX BAUBAU 30% reduction30% reduction 7.677.67 −4−4

Wind farm, electrolyzer, and Wind farm, electrolyzer, and

central oshore platform CAPEXcentral oshore platform CAPEX

BAUBAU 30% reduction30% reduction 6.076.07 −24−24

Discount rateDiscount rate 5%5% 3%3% 6.966.96 −13−13

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

4. Discussion

Onshore electrolysis using oshore wind energy beneﬁts from established

onshore infrastructure and reduces the need for complex oshore platforms

and equipment, making O&M easier. However, despite these advantages,

the LCOH for onshore electrolysis using FOWFs is notably greater than is

that for onshore electrolysis using solar PV. Currently, on the basis of our

results, the LCOH for oshore ﬂoating-wind-based hydrogen production is

approximately three times greater than is that of solar PV-based systems

in Saudi Arabia. This signiﬁcant cost disparity presents a challenge for the

economic competitiveness of hydrogen production from oshore wind in

the current market. Nonetheless, ongoing advancements in technology,

supply chain maturity, and key component cost reductions are expected to

signiﬁcantly lower these costs in the near future. In regions with limited land

availability, these improvements could make oshore wind a viable alternative

for hydrogen production.

The high LCOH for oshore wind stems primarily from the

higher CAPEX associated with FOWFs. The installation

and maintenance costs of oshore turbines, the need

for high-voltage transmission infrastructure to bring

electricity onshore, and the inherent logistical challenges

of operating in harsh marine environments increase

the overall cost of hydrogen production. In comparison,

solar PV has signiﬁcantly lower CAPEX because of its

simpler installation processes, minimal maintenance

requirements, and the rapidly declining costs of solar

panels over the past decade.

For onshore electrolysis using oshore wind to become

economically competitive with solar PV, substantial

reductions in the cost of FOWFs are necessary. Advances

in technology, economies of scale, and improved

deployment techniques are essential to reduce the

costs of ﬂoating wind turbines and reduce the LCOH

for hydrogen production. As ﬂoating wind technology

matures, the potential for cost reductions could make

oshore wind a more attractive option for hydrogen

production in the future. As mentioned above, the

case for oshore wind in hydrogen production may

also become stronger as land availability constraints

for solar PV become stricter, especially in densely

populated regions or areas with limited suitable land for

solar development.

The central oshore hydrogen production model oers

scalability beneﬁts. In large-scale aggregated oshore

wind projects, such as those reaching 10 GW, each

project typically requires separate high-voltage cables

to transmit electricity onshore. In contrast, a single,

well-sized and strategically planned hydrogen pipeline

can carry the hydrogen output from multiple projects,

signiﬁcantly reducing overall infrastructure costs as the

project scale increases (Derelle 2023). This situation

reduces the operational complexity and capital costs

associated with the installation of multiple platforms. With

a central oshore platform, hydrogen production can

be eciently managed, with shared infrastructure such

as desalination, compression, and transport systems,

making it a promising solution for large-scale oshore

wind farms.

The results show that while central oshore hydrogen

production involves high CAPEX, especially for the

platform, the potential for cost reductions exists as

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

projects scale up. In this model, hydrogen is produced

oshore and transported to shore through pipelines,

which is the most commonly used method for shorter to

moderate distances, where large volumes of hydrogen

can be eciently carried to onshore storage or

distribution hubs. However, this approach is not the only

option available for hydrogen transport. Other options,

such as using ships to transport liqueﬁed hydrogen or

hydrogen carriers such as ammonia or liquid organic

hydrogen carriers (LOHCs), oer alternative pathways,

especially for projects located further from shore or

in deeper waters, where pipeline infrastructure may

become prohibitively expensive. Ship transport allows

for the ﬂexibility of scaling up transport as demand

grows without the need for ﬁxed infrastructure, and

the technology for liquefying hydrogen is continuously

improving. Although liquefaction requires signiﬁcant

energy input, advances in eciency may reduce these

costs in the future.

Moreover, hydrogen carriers such as ammonia or LOHCs

provide additional ﬂexibility. These carriers allow for

easier storage and transport over long distances, as

they are more stable and can be integrated into existing

global shipping networks. Ammonia, for example, can

be easily converted back to hydrogen or used directly

as a fuel, adding another layer of utility. Importantly,

the conversion of hydrogen into ammonia at oshore

facilities can be performed at a relatively low cost,

further increasing its feasibility for export. However,

these methods come with their own sets of technical and

economic challenges.

In our analysis, central oshore hydrogen production

and pipeline-based transport are selected because

of their lower energy consumption and feasibility for

hydrogen transport over moderate distances. While our

study focuses primarily on the domestic production of

hydrogen, its export potential should also be considered.

As Saudi Arabia aims to become a leader in the global

hydrogen market, a key question is whether producing

hydrogen onshore or oshore for export is more cost

eective. Although export-related costs are not central to

our analysis, future studies should explore the potential

of shared oshore infrastructure among countries, as

seen in the North Sea, to reduce costs and improve

competitiveness. Nonetheless, as the scale of oshore

hydrogen production grows and projects move further

from shore, alternative transport methods such as ships

or carriers may become more cost competitive, with

estimates for shipping hydrogen from Saudi to Northwest

Europe in the form of ammonia being approximately $1/

kg (Alhadhrami et al. 2024). The incorporation of these

options into the global landscape of the hydrogen

economy and potential exports across continents could

provide a more comprehensive view of the potential

beneﬁts of these options.

4.1 Hydrogen

Production from

Decentralized

Oshore Electrolysis

Decentralized hydrogen production (i.e., the deployment

of electrolysis systems at individual wind turbines)

oers a novel approach to leveraging oshore wind

energy. By placing electrolyzers directly at the source of

generation, this method bypasses the need for complex

and expensive electricity transmission infrastructure,

such as high-voltage cables, and allows hydrogen

to be produced and transported as a fuel directly

from the wind turbine. The promise of decentralized

hydrogen production lies in its potential to reduce grid

congestion, lower transmission losses, and provide a

ﬂexible solution for hydrogen storage and distribution.

However, despite these theoretical advantages, there

are signiﬁcant challenges that need to be addressed

before decentralized hydrogen production can be

widely adopted.

Conversely, one of the primary hurdles impeding

the development of decentralized oshore

electrolyzers is the lack of large-scale pilot projects

that demonstrate the technical and economic viability

of decentralized electrolysis. The concept remains

largely in the experimental phase, with only one

notable demonstration project underway in the UK

(Venugopalan, Garcia Navarro, and Buijs 2024).

Without comprehensive operational data, performing a

detailed quantitative analysis or accurately assessing

the LCOH for decentralized systems is dicult. This

uncertainty limits the ability to predict the scalability

of decentralized electrolysis and makes it challenging

to determine how it compares to centralized or

onshore alternatives in terms of cost eectiveness and

overall performance.

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

The technical complexity of integrating electrolyzers

into individual turbines introduces additional layers of

uncertainty. While decentralized electrolysis reduces the

need for oshore platforms and pipelines, it requires each

wind turbine to have its own electrolyzer, desalination

unit, and potentially compression and storage system.

This modular approach complicates maintenance and

operational logistics, as each unit needs to be monitored

and serviced separately. Moreover, placing desalination

units at every turbine to purify seawater for electrolysis

is both resource and energy intensive, further increasing

costs and operational challenges. It will take time for

pilot projects to demonstrate and evaluate whether such

systems can function eciently at scale.

From an economic standpoint, decentralized electrolysis

carries the risk of higher CAPEX due to the need for

individual components at each turbine. The lack of

economies of scale, which centralized systems can

exploit by aggregating resources and infrastructure,

also poses a barrier to reducing costs. Nevertheless,

the potential for decentralized electrolysis to unlock

hydrogen production in remote or deep-water oshore

wind farms, where traditional electrical grid connections

are not feasible, is an exciting opportunity. As FOWFs

become more viable, decentralized hydrogen production

could allow developers to build wind farms far from shore

without the need for expensive electrical infrastructure.

In these scenarios, producing hydrogen at the source

and transporting it via ships or pipelines could oer a

cost-eective solution, especially if future technological

developments reduce the costs of decentralized systems.

4.2 Challenges,

Risks, and Barriers

Ahead

While both onshore and oshore electrolysis present

unique advantages, it is essential to consider the

common barriers that can inﬂuence the feasibility of

both approaches.

1. Oshore hydrogen production involves considerable

CAPEX, posing signiﬁcant ﬁnancing challenges.

Oshore hydrogen production faces signiﬁcant

challenges, including high capital costs, economic

uncertainties, and technological integration issues.

Substantial upfront investments are required for

infrastructure, including the installation of wind turbines,

electrolysis systems, pipelines, and supporting facilities.

Furthermore, uncertainties surrounding the future

market price of hydrogen complicate the economic

viability of these ventures. The integration of oshore

wind technology with large-scale oshore hydrogen

production is still in its early stages of development.

2. Oshore production and technology integration

increase regulatory and permitting complexities.

The regulatory and permitting complexities of oshore

hydrogen production are major barriers. The regulatory

Platform integrated

Hydrogen production

Land

Hydrogen

network

Sea

Inner-array

pipeline

Hydrogen pipeline

Figure 5. Decentralized oshore electrolysis.

Source: Authors.

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

landscape for hydrogen is still emerging, and obtaining

permits for large-scale projects can be time consuming.

Streamlining regulatory processes and creating

standardized regulations for hydrogen production,

transport, and storage are essential for accelerating

project development. Furthermore, integration with

hydrogen transport and storage systems presents

signiﬁcant technical challenges, particularly with

respect to reliability, eciency, and safety.

3. Managing too many stages and steps presents

operational challenges.

Grid integration and infrastructure development pose

signiﬁcant challenges, including the development

and operation of hydrogen pipelines, storage

infrastructure, subsea piping systems, and intermediate

storage solutions for hydrogen. The installation and

maintenance of subsea pipelines present technical

challenges and operational risks, adding complexity to

infrastructure planning and development.

4. Oshore hydrogen production is hindered by

intermittent wind power.

Electrolyzers, which are used to produce hydrogen,

need to operate continuously to maximize eciency

and cost-eectiveness. However, the variability of

wind energy can lead to interruptions, necessitating

the use of backup systems or energy storage solutions

such as batteries, which would further increase costs.

Thus, it is essential to develop systems that can

manage this intermittent supply without compromising

hydrogen output to ensure the feasibility of oshore

hydrogen projects.

5. Safety and environmental issues will require

careful management.

Environmental concerns are crucial in hydrogen

production via electrolysis, which requires signiﬁcant

fresh water and energy-intensive desalination

processes, impacting marine life. The safety risks

associated with hydrogen storage and transport in

oshore environments require careful management.

It is crucial to establish technological standards and

ensure long-term operational stability for the success

of oshore hydrogen production.

6. International oshore wind and hydrogen projects

will require eective cooperation.

Finally, regional cooperation is challenging for

international oshore wind and hydrogen projects

because of diering regulations and national interests.

Eective cooperation is vital to optimize resource use

and develop cross-border hydrogen infrastructure,

thus requiring careful negotiation and collaboration.

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

5. Conclusions and

Ways Forward

Despite the challenges, oshore wind-to-hydrogen systems oer an

opportunity for decarbonization and energy security, particularly in sectors

that are hard to electrify, such as heavy industry, aviation, and shipping.

Hydrogen produced from renewable oshore wind energy provides a

zero-emission alternative to fossil fuels, positioning it as a key solution in

the transition to cleaner energy. The development of the oshore wind-to-

hydrogen industry also presents sizable potential for economic growth and

job creation. As the industry expands, opportunities will emerge across the

entire value chain, from the manufacturing of wind turbines and electrolyzers

to the construction, operation, and maintenance of both oshore wind farms

and hydrogen production facilities. This growth can drive local economies,

particularly in coastal regions where oshore wind farms are located, creating

long-term, high-skilled jobs in the renewable energy and hydrogen sectors.

Governments can leverage this opportunity to stimulate industrial growth and

strengthen domestic supply chains, fostering a robust green economy.

Additionally, countries that develop strong oshore

wind-to-hydrogen industries have substantial export

potential. As the global demand for green hydrogen

continues to rise, nations with abundant oshore wind

resources can position themselves as key exporters.

International collaboration in terms of infrastructure,

technology development, and regulatory frameworks will

be essential in accelerating this growth and opening new

markets. Collaborative eorts will enhance technological

advancements and standardization, driving down costs

and increasing eciency for global hydrogen markets,

further boosting the competitiveness of oshore wind-

to-hydrogen systems.

However, from the Saudi perspective, the economics

of oshore wind-to-hydrogen production, particularly

in the Red Sea, where much of the resource potential

lies in deeper areas suitable for FOWFs, make it less

competitive for green hydrogen production. Compared

with similar projects in Europe, this technology does not

provide a competitive advantage in exporting green

hydrogen, which has greater potential for FOWFs and is

further developed in terms of technological deployment

and cost eciency. Moreover, in terms of oshore wind

hydrogen production, Saudi Arabia will struggle to

compete with domestic onshore hydrogen production

from solar PV, which beneﬁts from the country’s vast solar

resources and much lower production costs.

As a result, the development of Saudi Arabia’s oshore

wind-to-hydrogen sector will likely be a medium- to long-

term target, driven by the need for further cost reductions

in oshore wind technology. In addition, incentives for

green hydrogen will be essential for making oshore wind

hydrogen production ﬁnancially viable. While the current

focus may remain on leveraging Saudi Arabia’s more

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

cost-eective solar and onshore wind resources, oshore

wind could play a more prominent role in the future as the

technology matures.

One of the primary economic advantages of oshore

hydrogen production is that transporting hydrogen is

less expensive than is transmitting electricity over long

distances. Hydrogen produced from several oshore

wind farms can be transported via a single pipeline,

dramatically reducing material requirements, installation

costs, and the space needed on the seabed. Oshore

electrolysis becomes particularly attractive for projects

located far from shore, where the cost of hydrogen

pipelines is considerably lower than is that of installing

electrical cables. For large-scale projects, a hydrogen

pipeline can cost up to three times less than can an

electrical cable to transmit the same amount of energy,

providing a strong case for further investment in oshore

electrolysis infrastructure.

To ensure the successful development of oshore wind-

to-hydrogen systems, developing a hydrogen strategy

that integrates oshore wind deployment is crucial. Such

a strategy will oer a clear direction to businesses and

industries, thus supporting investment decisions and

providing a long-term roadmap. Additionally, this strategy

will involve linking the siting of oshore wind farms with

the proximity of hydrogen end-use sectors or industrial

bases. Oshore wind locations should be strategically

chosen to minimize the cost and complexity of hydrogen

transport and ensure ecient delivery to demand centers

or export facilities. Setting capacity targets will help

establish a pipeline of projects, giving stakeholders

visibility into future opportunities, whereas cost targets

will encourage innovation and cost reduction across

the supply chain. A well-structured strategy can align

oshore wind capacity with hydrogen production goals,

supporting the growth of both domestic and international

hydrogen markets.

Investment in R&D will be vital in advancing those key

technologies required for the oshore hydrogen economy.

Funding for R&D is necessary to accelerate progress

in areas such as advanced electrolyzers, more ecient

hydrogen storage solutions, and cost-eective pipeline

infrastructure. Identifying and supporting demonstrator

projects, particularly those targeting the ﬁrst GW of

hydrogen production capacity, will be critical in kick starting

the supply chain and attracting investment. Additionally,

encouraging diverse business models will foster innovation

and competition, thus driving down costs and improving

the scalability of oshore hydrogen production.

Finally, international collaboration will play a crucial role

in advancing oshore hydrogen systems, especially

in regions with shared sea boundaries that oer

opportunities for cross-border projects. Collaboration

on technology sharing, regulatory harmonization, and

infrastructure development can help reduce costs

and improve the eciency of hydrogen production and

transport. Aligning regulatory standards across borders

will further streamline the development of transnational

hydrogen pipelines and facilitate the movement of green

hydrogen among nations.

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

Endnote

1 The FPSO concept involves generating hydrogen on the same ﬂoating platform as the wind turbine and storing it onboard. The

stored hydrogen can then be ooaded for transport by ships, oering greater ﬂexibility compared to pipeline-based systems,

especially in deep-water locations.

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

References

Akdağ, Ozan. 2023. “The Operation and Applicability

to Hydrogen Fuel Technology of Green Hydrogen

Production by Water Electrolysis Using Oshore Wind

Power.” Journal of Cleaner Production 425: 138863.

https://doi.org/10.1016/j.jclepro.2023.138863.

Albalawi, Ahmed A., Nora Nezamuddin, Frank A. Felder,

Abdelrahman Muhsen, and Amro M. Elshurafa. 2024.

“Assessment of the Potential of Floating Oshore Wind

Turbines in the Red Sea.” Riyadh: King Abdullah Petroleum

Studies and Research Center (KAPSARC). https://www.

kapsarc.org/research/publications/assessment-of-the-

potential-of-ﬂoating-oshore-wind-turbines-in-the-red-sea.

Alhadhrami, Khalid, Ahmed Albalawi, Shahid Hasan, and

Amro M. Elshurafa. 2024. “Modeling Green Hydrogen

Production Using Power-to-X: Saudi and German

Contexts.” International Journal of Hydrogen Energy 64:

1040–1051. https://doi.org/10.1016/j.ijhydene.2024.03.161.

AquaVentus. 2024. “AquaVentus.” https://aquaventus.

org/en.

Barrow Green Hydrogen. 2024. “Producing 100% Green

Hydrogen.” https://www.barrowgreenhydrogen.co.uk/

theproject.

Bødal, Espen Flo, Sigmund Eggen Holm, Avinash

Subramanian, Goran Durakovic, Dimitri Pinel, Lars

Hellemo, Miguel Muñoz Ortiz, Brage Rugstad Knudsen,

and Julian Straus. 2024. “Hydrogen for Harvesting

the Potential of Oshore Wind: A North Sea Case

Study.” Applied Energy 357. https://doi.org/10.1016/j.

apenergy.2023.122484.

Bonacina, Camilla Nicol, Nima Bordbar Gaskare, and

Gianluca Valenti. 2022. “Assessment of Oshore

Liquid Hydrogen Production from Wind Power for

Ship Refueling.” International Journal of Hydrogen

Energy 47 (2): 1279–1291. https://doi.org/10.1016/j.

ijhydene.2021.10.043.

BVG Associated (BVGA). 2023. “Guide to a Floating

Oshore Wind Farm.” BVG Associates Limited. Published

on behalf of the Oshore Renewable Energy Catapult,

The Crown Estate, and Crown Estate Scotland, 16 October.

https://bvgassociates.com/comprehensive-guide-to-a-

ﬂoating-oshore-wind-farm-launched-to-support-industry-

learning.

Calado, Goncalo, Rui Castro, A. J. Pires, and Miguel

J. Marques. 2024. “Assessment of Hydrogen-Based

Solutions Associated to Oshore Wind Farms: The Case

of the Iberian Peninsula.” Renewable and Sustainable

Energy Reviews 192 (March): 114268. https://doi.org/

10.1016/j.rser.2023.114268.

Catapult. 2021. The Floating Oshore Wind: Cost

Reduction Pathways to Subsidy Free. Oshore Renewable

Energy (ORE) Catapult. https://cms.ore.catapult.org.uk/

wp-content/uploads/2021/01/FOW-Cost-Reduction-

Pathways-to-Subsidy-Free-report-.pdf.

Chandler, William S., Charles H. Whitlock. 2005.

“Determining Wind Resources as a Function of Surface

Roughness and Height from NASA Global Assimilation

Analysis.” Proceedings of the International Solar Energy

Society 2005 Solar World Congress, Orlando, Florida,

August 6–12.

Cheng, Cheng, and Llewelyn Hughes. 2023. “The Role

for Oshore Wind Power in Renewable Hydrogen

Production in Australia.” Journal of Cleaner Production

391 (March 10): 136223. https://doi.org/10.1016/j.jclepro.

2023.136223.

Danish Energy Agency (DEA). 2024. “Energy Island

in the North Sea.” Danish Energy Agency. https://

ens.dk/en/our-responsibilities/oshore-wind-power/

energy-island-north-sea.

Department for Energy Security and Net Zero

(DESNZ). 2024. “Contracts for Dierence

Allocation Round 6 Results.” Gov.UK, September

3. https://www.gov.uk/government/publications/

contracts-for-dierence-cfd-allocation-round-6-results.

Derelle, Shane, Heernan Manon. 2023. “An Overview of

the UK Hydrogen Market.” Bringa. https://www.youtube.

com/watch?v=EpK2-8DKIQ8.

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

Det Norske Veritas (DNV). 2023. Cost and Performance

Data for Oshore Hydrogen Production. DNV Denmark

A/S (2900 Hellerup, Denmark). https://ens.dk/sites/ens.

dk/ﬁles/Energioer/cost_performance_data_oshore_

hydrogen_production.pdf.

Díaz-Motta, Armando, Francisco Díaz-González, and

Manuel Villa-Arrieta. 2023. “Energy Sustainability

Assessment of Oshore Wind-Powered Ammonia.”

Journal of Cleaner Production 420 (September 25):

138419. https://doi.org/10.1016/j.jclepro.2023.138419.

Dolphyn Hydrogen. 2024. “Our Hydrogen Production

Trials.” https://www.dolphynhydrogen.com/production-

trials.

Donkers, Koen. 2020. “Hydrogen Production on

Oshore Platforms: A Techno-Economic Analysis.”

Master’s thesis, Master Energy Science, Utrecht

University. https://studenttheses.uu.nl/bitstream/

handle/20.500.12932/37491/Thesis%20research%20

Koen%20Donkers%20-%20%20Final%20version.pdf?

sequence=1.

East Coast Hydrogen. 2023. East Coast Hydrogen

Delivery Plan. https://www.eastcoasthydrogen.co.uk/

east-coast-hydrogen-delivery-plan.

Enerdata. 2024. “Enerdata Key Energy Intelligence.”

https://www.enerdata.net/publications/reports-

presentations/world-energy-trends.html.

European Commission. 2020. “An EU Strategy to Harness

the Potential of Oshore Renewable Energy for a Climate

Neutral Future.” https://eur-lex.europa.eu/legal-content/

EN/TXT/?uri=COM:2020:741:FIN&qid=1605792629666.

Farahmand, Hossein, Sander Holt Günther, and Martin

Kristiansen. 2024. “Evaluating the Oshore Wind Business

Case and Green Hydrogen Production: A Case Study

of a Future North Sea Oshore Grid.” Electric Power

Systems Research 234 (September): 110814. https://doi.

org/10.1016/j.epsr.2024.110814.

Fraunhofer. 2021. Cost Forecast For Low-Temperature

Electrolysis – Technology Driven Bottom-Up Prognosis

For Pem And Alkaline Water Electrolysis Systems.

Fraunhofer Institute for Solar Energy Systems ISE,

Heidenhofstraße 279110 Freiburg, Germany. https://www.

ise.fraunhofer.de/en/publications/studies/catf.html.

Gerrits, Stefan. 2017. “Feasibility Study of the Hub and

Spoke Concept in the North Sea Developing a Site

Selection Model to Determine the Optimal Location.”

Master thesis. Department of Hydraulic Engineering,

Delft University of Technology. https://repository.

tudelft.nl/record/uuid:9de1680b-7c16-4c93-bf3e-2af5e19

8eee0.

Giampieri, Alessandro, Janie Ling-Chin, and Anthony

Paul Roskilly. 2024. “Techno-Economic Assessment

of Oshore Wind-to-Hydrogen Scenarios: A UK Case

Study.” International Journal of Hydrogen Energy 52

(Part B, January 2): 589–617. https://doi.org/10.1016/j.

ijhydene.2023.01.346.

Gipe, Paul. 1999. Wind Energy Basics. Chelsea

Green Publishing.

Glaum, Philipp, Fabian Neumann, and Tom Brown.

2024. “Oshore Power and Hydrogen Networks for

Europe’s North Sea.” Applied Energy 369 (September 1):

123530. https://doi.org/10.1016/j.apenergy.2024.

123530.

Groenemans, Hugo, Genevieve Saur, Cortney

Mittelsteadt, Judith Lattimer, and Hui Xu. 2022.

“Techno-Economic Analysis of Oshore Wind PEM

Water Electrolysis for H2 Production.” Current

Opinion in Chemical Engineering 37 (September):

100828. https://doi.org/10.1016/j.coche.2022.

100828.

Guven, Denizhan. 2024. “Oshore Wind-Driven Green

Hydrogen: Bridging Environmental Sustainability and

Economic Viability.” International Journal of Hydrogen

Energy 72 (June 27): 661–676. https://doi.org/10.1016/j.

ijhydene.2024.05.335.

Havinga, Hylke C., H. Z. Adriaan van der Loos, and

Markus Steen. 2024. “Collaboration or Competition?

Interactions between Floating and Fixed-Bottom

Oshore Wind in Norway.” Environmental Innovation and

Societal Transitions 52 (September): 100872. https://doi.

org/10.1016/j.eist.2024.100872.

Hill, Samuel James Peter, Olusola Bamisile, Luke Hatton,

Iain Staell, and Malte Jansen. 2024. “The Cost of Clean

Hydrogen from Oshore Wind and Electrolysis.” Journal

of Cleaner Production 445 (March 15): 141162. https://doi.

org/10.1016/j.jclepro.2024.141162.

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

Ibrahim, Omar S., Alessandro Singlitico, Roberts Proskovics,

Shane McDonagh, Cian Desmond, and Jerry D. Murphy.

2022. “Dedicated Large-Scale Floating Oshore Wind

to Hydrogen: Assessing Design Variables in Proposed

Typologies.” Renewable and Sustainable Energy Reviews

160 (May): 112310. https://doi.org/10.1016/j.rser.2022.112310.

Jansen, Malte, Philipp Beiter, Iegor Riepin, Felix Müsgens,

Victor Juarez Guajardo-Fajardo, Iain Staell, Bernard

Bulder, and Lena Kitzing. 2022. “Policy Choices and

Outcomes for Oshore Wind Auctions Globally.” Energy

Policy 167 (August): 113000. https://doi.org/10.1016/j.

enpol.2022.113000.

Kang, Taehyung, Dela Quarme Gbadago, and Sungwon

Hwang. 2024. “Techno-Economic Analysis and

Comparison of Hydrogen Supply Using Oshore Wind

Power Sources on the Coast of the Korean Peninsula.”

International Journal of Hydrogen Energy 71 (June 19):

1201–1213. https://doi.org/10.1016/j.ijhydene.2024.05.188.

Komorowska, Aleksandra, Pablo Benalcazar, and Jacek

Kamiński. 2023. “Evaluating the Competitiveness and

Uncertainty of Oshore Wind-to-Hydrogen Production: A

Case Study of Poland.” International Journal of Hydrogen

Energy 48 (Issue 39, May 5): 14577–14590. https://doi.

org/10.1016/j.ijhydene.2023.01.015.

Kotek, Peter, Borbála Takácsné Tóth, and Adrienn Selei.

2023. “Designing a Future-Proof Gas and Hydrogen

Infrastructure for Europe – A Modelling-Based Approach.”

Energy Policy 180 (September): 113641. https://doi.

org/10.1016/j.enpol.2023.113641.

Lucas, Tiago R., Ana F. Ferreira, R. B. Santos Pereira,

and Marco Alves. 2022. “Hydrogen Production from

the WindFloat Atlantic Oshore Wind Farm: A Techno-

Economic Analysis.” Applied Energy 310 (March 15):

118481. https://doi.org/10.1016/j.apenergy.2021.118481.

Luo, Zhibin, Xiaobo Wang, Heng Wen, and Aiguo Pei.

2022. “Hydrogen Production from Oshore Wind Power

in South China.” International Journal of Hydrogen

Energy 47 (Issue 58, July 8): 24558–24568. https://doi.

org/10.1016/j.ijhydene.2022.03.162.

Lüth, Alexandra, Paul E. Seifert, Ruud Egging-Bratseth,

and Jens Weibezahn. 2023. “How to Connect Energy

Islands: Trade-Os Between Hydrogen and Electricity

Infrastructure.” Applied Energy 341 (July 1): 121045. https://

doi.org/10.1016/j.apenergy.2023.121045.

Lüth, Alexandra, Yannick Werner, Ruud Egging-Bratseth,

and Jalal Kazempour. 2024. “Electrolysis as a Flexibility

Resource on Energy Islands: The Case of the North

Sea.” Energy Policy 185 (February): 113921. https://doi.

org/10.1016/j.enpol.2023.113921.

NASA. 2024. “NASA Prediction of Worldwide Energy

Resources (POWER).” https://power.larc.nasa.gov.

National Renewable Energy Laboratory (NREL). 2021.

“NREL Annual Technology Baseline: Oshore Wind.”

National Renewable Energy Laboratory. https://atb.nrel.

gov/electricity/2021/oshore_wind.

NortH2. 2024. “NortH2 Project.” https://www.north2.eu.

National Renewable Energy Laboratory (NREL). 2021.

“NREL Annual Technology Baseline: Oshore Wind.”

https://atb.nrel.gov/electricity/2021/oshore_wind.

Net Zero Technology Centre (NZTC). 2023.

“Hydrogen Backbone Link: Connecting Scotland and

Europe.” Aberdeen, Scotland: Net Zero Technology

Centre. https://www.netzerotc.com/reports/

hydrogen-backbone-link-report.

Ørsted. 2021. “Ørsted Breaks Ground on First Renewable

Hydrogen Project.” https://orsted.com/en/media/

news/2021/05/953942245693267.

Pérez-Vigueras, Malinalli, Rogelio Sotelo-Boyá, Rosa de

Guadalupe González-Huerta, and Francisco Bañuelos-

Ruedas. 2023. “Feasibility Analysis of Green Hydrogen

Production from Oceanic Energy.” Heliyon 9 (9): e20046.

https://doi.org/10.1016/j.heliyon.2023.e20046.

PosHYdon. 2024. “PosHYdon Project.” https://poshydon.

com/en/home-en/process.

Ramakrishnan, Shanmugam, Mostafa Delpisheh,

Caillean Convery, Daniel Niblett, Mohanraj Vinothkannan,

and Mohamed Mamlouk. 2024. “Oshore Green

Hydrogen Production from Wind Energy: Critical

Review and Perspective.” Renewable and Sustainable

Energy Reviews 195. https://doi.org/10.1016/j.rser.2024.

114320.

Rezaei, Mostafa, Alexandr Akimov, and Evan Mac A.

Gray. 2024. “Techno-Economics of Oshore Wind-Based

Dynamic Hydrogen Production.” Applied Energy 374.

https://doi.org/10.1016/j.apenergy.2024.124030.

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

Rogeau, Antoine, Julien Vieubled, Matthieu de Coatpont,

Pedro Aonso Nobrega, Guillaume Erbs, and Robin

Girard. 2023. “Techno-Economic Evaluation and Resource

Assessment of Hydrogen Production through Oshore

Wind Farms: A European Perspective.” Renewable and

Sustainable Energy Reviews 187. https://doi.org/10.1016/j.

rser.2023.113699.

Rostock EnergyPort Coorperation. 2024. “HyTechHafen

Rostock – Green Hydrogen for Energy Transition.” https://

energyport-rostock.de/en/.

RWE. 2024. “Hydrogen Production in the North

Sea: AquaVentus.” RWE. https://www.rwe.com/en/

research-and-development/hydrogen-projects/

aquaventus.

Scottish Government. 2020. Scottish Oshore Wind to

Green Hydrogen Opportunity Assessment. The Scottish

Government, St Andrew’s House, Edinburgh EH1 3DG.

https://www.gov.scot/publications/scottish-oshore-wind-

green-hydrogen-opportunity-assessment.

Shell. 2022. “Shell to Start Building Europe’s Largest

Renewable Hydrogen Plant.” https://www.shell.com/news-

and-insights/newsroom/news-and-media-releases/2022/

shell-to-start-building-europes-largest-renewable-

hydrogen-plant.html.

Singlitico, Alessandro, Jacob Østergaard, and Spyros

Chatzivasileiadis. 2021. “Onshore, Oshore or In-Turbine

Electrolysis? Techno-Economic Overview of Alternative

Integration Designs for Green Hydrogen Production into

Oshore Wind Power Hubs.” Renewable and Sustainable

Energy Transition 1: 100005. https://doi.org/10.1016/j.

rset.2021.100005.

Venugopalan, Suriya, Julio Garcia Navarro, and Lennert

Buijs. 2024. State of Art in Oshore Hydrogen Production.

Utrecht: TKI Oshore Energy. https://energycentral.

com/system/ﬁles/ece/nodes/688785/state_of_art_in_

oshore_hydrogen_production.pdf.

Wang, Zhiwen, Hu Wang, Tonio Sant, Zecheng Zhao,

Rupp Carriveau, David S. K. Ting, Peng Li, Tielei Zhang,

and Wei Xiong. 2024. “Subsea Energy Storage as an

Enabler for Floating Oshore Wind–Hydrogen Production:

Review and Perspective.” International Journal of

Hydrogen Energy 71: 1266–1282. https://doi.org/10.1016/j.

ijhydene.2024.05.329.

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

Notes

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

Notes

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

Notes

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

Ahmed Albalawi

Ahmed is a Research Fellow in the Utilities & Renewables Program at KAPSARC. He is an

Electrical Engineer and holds an M.Sc. degree in renewable energy systems from Loughborough

University. Prior to joining KAPSARC, he worked as an R&D engineer at Saudi Electricity

Company for over ﬁve years, heading the research on renewables and energy storage. Ahmed’s

current research focuses on emerging technologies, critical minerals, and power system

modeling to help shape the future of the energy mix and the technologies that can contribute to

achieving the KSA’s green targets.

Shahid Hasan

Shahid is a Principal Fellow at KAPSARC. His current research focuses on electricity sector

transitions and hydrogen economics, as well as policy and regulatory issues in the Middle

East and globally. He also studies the development of regional electricity markets in the Gulf

Cooperation Council (GCC) and Middle East and North Africa regions. He previously consulted

extensively on policy, regulatory and market design for governments, electricity regulators,

public utilities and the electricity industries in India and Southeast Asia.

Amro M Elshurafa

Amro is the Executive Director of the Utilities & Renewables Department and possesses 20+

years of experience garnered on three continents. His research interests lie in renewable energy

policy, electricity market design and regulation, and power systems modeling. He has led and

executed several national modeling initiatives at distributed and utility scales. Some aspects

of his research have been adopted by BP in their seminal annual statistical review. He is listed

among the top 2% of scientists globally as per Stanford, and he is a board member of the Saudi

Water and Electricity Regulatory Authority. Credited with 50+ papers and patents, he holds a

Ph.D. in Engineering and an MBA in Finance.

About the Authors

The Economics of Oshore Wind-Based Hydrogen Production in Saudi Arabia

About the Project

This paper is part of the project “Innovations in electricity markets, network

regulations, low-carbon investments and technologies” under KAPSARC’s

Energy Transitions and Electric Power Program. This project aims to

provide insights into the transformation of the Saudi electricity sector. This

transformation is characterized by a willingness to increase the share of

renewables and replace liquid fuels with natural gas. This transformation

must also ensure ﬁscal balance, expand electricity exports, produce green

hydrogen and diversify the Saudi economy through localization. This project

provides insights into this transition by discussing and learning from electricity

markets worldwide.