swot-pestel study of constraints to decarbonization of the
TRANSCRIPT
SWOT-PESTEL Study of
Constraints to Decarbonization of
the Natural Gas System in the EU:
Techno-economic analysis of hydrogen
production in Portugal
Rohan Adithya Vasudevan
Master of Science Thesis
TRITA-ITM-EX 2021:69
KTH School of Industrial Engineering and Management
Division of Energy Systems, Department of Energy Technology
SE-100 44 STOCKHOLM
Master of Science Thesis EGI TRITA-ITM-EX
2021:69
SWOT-PESTEL Study of Constraints to
Decarbonization of the Natural Gas
System in the EU:
Techno-economic analysis of hydrogen
production in Portugal
ROHAN ADITHYA VASUDEVAN
Approved
26 March 2021
Examiner
Dilip Khatiwada
Supervisor
Dilip Khatiwada (KTH)
Bruno Henrique Santos
(REN Portgas)
Commissioner
Bruno Henrique Santos (REN
Portgas)
Contact person
Dilip Khatiwada
Abstract
The exigent need to address climate change and its adverse effects is felt all around the world.
As pioneers in tackling carbon emissions, the European Union continue to be head and
shoulders above other continents by implementing policies and keeping a tab on its carbon
dependence and emissions. However, being one of the largest importers of Natural Gas in
the world, the EU remains dependent on a fossil fuel to meet its demands.
The aim of the research is to investigate the barriers and constraints in the EU policies and
framework that affects the natural gas decarbonization and to investigate the levelized cost
of hydrogen production (LCOH) that would be used to decarbonize the natural gas sector.
Thus a comprehensive study, based on existing academic and scientific literature, EU
policies, framework and regulations pertinent to Natural gas and a techno economic analysis
of possible substitution of natural gas with Hydrogen, is performed. The motivation behind
choosing hydrogen is based on various research studies that indicate the importance and
ability to replace to natural gas. In addition, Portugal provides a great environment for cheap
green hydrogen production and thus chosen as the main region of evaluation.
The study evaluates the current framework based on a SWOT ((Strength, Weakness, and
Opportunities & Weakness) analysis, which includes a PESTEL (Political, Economic,
Social, Technological, Environmental & Legal) macroeconomic factor assessment and an
expert elicitation. The levelized cost of hydrogen is calculated for blue (SMR - Steam
Methane Reforming with natural gas as the feedstock) and green hydrogen (Electrolyzer with
electricity from grid, solar and wind sources). The costs were specific to Portuguese
conditions and for the years 2020, 2030 and 2050 based on availability of data and the
alignment with the National Energy and Climate Plan (NECP) and the climate action
framework 2050. The sizes of Electrolyzers are based on the current Market capacities while
SMR is capped at 300MW. The thesis only considers production of hydrogen. Transmission,
distribution and storage of hydrogen are beyond the scope of the analysis.
Results show that the barriers are mainly related to costs competitiveness, amendments in
rules/regulations, provisions of incentives, and constraints in the creation of market demand
for low carbon gases. Ensuring energy security and supply while being economically feasible
demands immediate amendments to the regulations and policies such as incentivizing supply,
creating a demand for low carbon gases and taxation on carbon.
Considering the LCOH, the cheapest production costs continue to be dominated by blue
hydrogen (1.33 € per kg of H2) in comparison to green hydrogen (4.27 and 3.68 € per kg of
H2) from grid electricity and solar power respectively. The sensitivity analysis shows the
importance of investments costs and the efficiency in case of electrolyzers and the carbon
tax in the case of SMR. With improvements in electrolyzer technologies and increased
carbon tax, the uptake of green hydrogen would be easier, ensuring a fair yet competitive gas
market.
Keywords: Decarbonization, Natural Gas System, SWOT (Strength, Weakness, and Opportunities & Weakness), PESTEL (Political, Economic, Social, Technological, Environmental & Legal), Green Hydrogen, Blue Hydrogen, Methane Reforming, Electrolysis, LCOH (Levelized Cost of Hydrogen)
Sammanfattning
Det starka behovet av att ta itu med klimatförändringarna och deras negativa effekter är omfattande
världen över. Den europeiska unionen utgör en pionjär när det gäller att såväl hantera sina
koldioxidberoende och utsläpp som att implementera reglerande miljöpolitik, och framstår därmed
som överlägsen andra stater och organisationer i detta hänseende. Unionen är emellertid fortfarande
mycket beroende av fossilt bränsle för att uppfylla sina energibehov, och kvarstår därför som en av
världens största importörer av naturgas.
Syftet med denna forskningsavhandling är att undersöka befintliga hinder och restriktioner i EU: s
politiska ramverk som medför konsekvenser avkolningen av naturgas, samt att undersöka de
utjämnande kostnaderna för väteproduktion (LCOH) som kan användas för att avkolna
naturgassektorn. Därmed utförs en omfattande studie baserad på befintlig akademisk och
vetenskaplig litteratur, EU: s politiska ramverk och stadgar som är relevanta för naturgasindustrin.
Dessutom genomförs en teknisk-ekonomisk analys av eventuella ersättningar av naturgas med väte.
Valet av väte som forskningsobjekt motiveras olika forskningsstudier som indikerar vikten och
förmågan att ersätta till naturgas. Till sist berör studien Portugal. som tillhandahåller en lämplig miljö
för billig och grön vätgasproduktion. Av denna anledning är Portugal utvalt som den viktigaste
utvärderingsregionen.
Studien utvärderar det nuvarande ramverket baserat på en SWOT-analys ((Strength, Weakness, and
Opportunities & Weakness), som inkluderar en PESTEL (Political, Economical, Social,
Technological, Environmental och Legal) makroekonomisk faktoranalys och elicitering. Den
utjömnade vätekostnaden beräknades i blått (SMR - Ångmetanreformering med naturgas som råvara)
och grönt väte (elektrolyser med el från elnät, sol och vindkällor). Kostnaderna var specifika för de
portugisiska förhållandena under åren 2020, 2030 och 2050 baserat på tillgänglighet av data samt
anpassningen till den nationella energi- och klimatplanen (NECP) och klimatåtgärdsramen 2050.
Storleken på elektrolyserar baseras på den nuvarande marknadskapaciteten medan SMR är begränsad
till 300 MW. Avhandlingen tar endast hänsyn till produktionen av vätgas. Transmission, distribution
och lagring av väte ligger utanför analysens räckvidd.
Resultaten visar att hindren är främst relaterade till kostnadskonkurrens, förändringar i stadgar och
bestämmelser, incitament och begränsningar i formerandet av efterfrågan på koldioxidsnåla gaser på
marknaden. Att säkerställa energiförsörjning och tillgång på ett ekonomiskt hållbart sätt kräver
omedelbara ändringar av reglerna och politiken, såsom att stimulera utbudet, att skapa en efterfrågan
på koldioxidsnåla gaser och genom att beskatta kol.
När det gäller LCOH dominerar blåväte beträffande produktionskostnaderna (1,33 € per kg H2)
jämfört med grönt väte (4,27 respektive 3,68 € per kg H2) från elnät respektive solenergi.
Osäkerhetsanalysen visar vikten av investeringskostnader och effektiviteten vid elektrolysörer och
koldioxidskatten för SMR. Med förbättringar av elektrolys-tekniken och ökad koldioxidskatt skulle
upptagningen av grön vätgas vara enklare och säkerställa en rättvis men konkurrenskraftig
gasmarknad.
Nyckelord: Avkolningen, Naturgas systemet, SWOT (Strength, Weakness, and Opportunities & Weakness), PESTEL (Political, Economic, Social, Technological, Environmental & Legal), Grönt väte, Blå väte, Metanreformering, Elektrolys
Preface
This thesis work was developed at the REN Portgas in Portugal. I would like to extend
my sincere appreciation to Bruno Henrique Santos for hosting me at the company.
REN Portgás Distribuição is a natural gas distributing Public Service Company. Its
activities are central to the northern coastal region of Portugal and focuses on the gas
distribution network development and operation. It covers 29 districts with network
currently at 4797 kms and 350 000 corresponding supply points. Portgas leads the
country in terms of investments in the national natural gas system, representing more
than half of the investments in the distribution level. A strong innovation and
sustainability goal is the focus area for the company. It believes that innovation is the
key driver in developing the business, and publically commits to be environmental
responsibility.
Acknowledgements
शुक्लाम्बरधरं विषंु् शवशिरं्ण चतुरुु्जम् ।
प्रसन्निदनं ध्यायेत् सिुविघ्नोपशान्तये ॥१।।
I would like to begin by thanking the almighty, my family and friends for all the amazing
support during all my studies, particularly during the last few months. I would especially like
to thank my parents and my sister, Mrinalini for always pushing me to strive for more and
giving me all the help I needed to succeed. Their perpetual love and guidance has made me
the person I am today and without them, nothing would have been possible.
I express my sincere gratitude to Bruno Henrique Santos, my supervisor for the opportunity
to do my thesis with REN Portgas. I could not have hoped for a more caring and attentive
guide during the whole period. Thank you for all the suggestions, wisdom and expertise that
were pivotal in shaping the outcome of the thesis and making my stay in Porto memorable.
Thank you to my supervisor and examiner at KTH, Asst. Professor Dilip Khatiwada for the
valuable insights during this thesis study. A special thanks to all the experts for their inputs
and contribution to this study. Thank you for your time and indispensable contributions.
To Dinesh, Raghav, Srinath and Padmaja, cheers for always being there for me during this
time, including the period of difficulties. You all have always helped me to move forward
and push me to give my best. Being away from home was not easy and the pandemic made
it worse but your help made it possible to successfully complete the thesis.
In general, appreciations to all the people that helped and supported me through this journey.
Rohan Adithya Vasudevan
Table of Contents
ABSTRACT 3
SAMMANFATTNING 4
PREFACE 5
ACKNOWLEDGEMENTS 6
TABLE OF CONTENTS 7
LIST OF FIGURES 10
LIST OF TABLES 11
LIST OF ABBREVIATIONS 12
LIST OF UNITS 12
1. INTRODUCTION 13
1.1 Background 13
1.2 Objective & Scope of Study 17
1.3 Structure of the report 19
2. NATURAL GAS: WORLD DATA, DECARBONIZATION PATHWAY AND
HYDROGEN IN PORTUGAL 20
2.1 World vs Europe Outlook 20 2.1.1 Natural gas WORLD data: Production, Imports & Demand 21
a. Natural Gas Production 21 b. Natural Gas Imports 22 c. Natural Gas Demand 23
2.1.2 Natural gas EUROPE data: Production, Imports & Demand 23
2.2 Need for Decarbonization? 24
2.3 Means to Decarbonize Natural Gas 25 Hydrogen 26 Bio methane and Synthetic methane 26
2.4 Hydrogen in EU 27 2.4.1 Hydrogen Production 28
2.4.2 Hydrogen Demand 29
2.5 Hydrogen Production Technologies 29
2.6 Hydrogen Strategy in Portugal 30
3. REVIEW OF POLICIES/PLANS AND LITERATURE ON NATURAL GAS
DECARBONIZATION AND HYDROGEN IN THE EU 33
3.1 Existing Literature: Natural Gas Decarbonization 33
3.2 Current EU policies & Regulatory Framework 34 3.2.1 Policies 34
a. 2030 Climate and Energy Framework 35 b. Renewable Energy Directive (RED II) 35 c. European Climate Law 35 d. European Green Deal 36 e. 2050 long-term strategy: Clean Planet for all 36 f. Energy Taxation Directive: Revised 36
3.2.2 Regulations 37 Third Energy Directive: Third Gas Directive 37
a. Independent regulators & the Gas Regulation 37 b. Regulation on Market Integrity and Transparency (REMIT) 37 c. Agency for Cooperation of Energy Regulators (ACER) 37 d. Unbundling 38 e. Projects of Common Interest (PCIs) & Third Party Access 38
The TEN-E Regulation 38 3.2.3 Preliminary Conclusions of the Author 38
3.3 Hydrogen Production Methods: A review 39
4. METHODS AND MATERIALS 43
4.1 Study Area 43
4.2 Research Design 43 4.2.1 SWOT Analysis 44 4.2.2 PESTEL Analysis 45 4.2.3 Expert Elicitation 46
4.3 Levelized Cost of Hydrogen Production (LCOH) for Different Production Systems (SMR+
CCS and Electrolysis) 47
4.4 Definitions, Assumptions and Calculation 50 4.4.1 Costs 50 4.4.2 Assumptions and Data Sources 52 4.4.3 Calculation of Costs 54
5. RESULTS 57
5.1 Constraints to Decarbonization 57 5.1.1 Compilation of the Barriers 57
Barriers related to political aspects of Policies and Regulations 57 Barriers related to Economic aspects of Policies and Regulations 60 Barriers related to Social aspects of Policies and Regulations 61 Barriers related to Technological aspects of Policies and Regulations 63
5.1.2 SWOT Analysis 65 5.1.3 Uncertainty analysis of Survey Results 67
5.2 Hydrogen Production: Costs and Sensitivity Analysis 70 5.2.1 Steam Methane Reforming (With and Without CCUS) 70 5.2.2 Hydrogen Production from Electrolyzers (PEM, ALK & SOEC) 73
Polymer Electrolyte Membrane (PEM) Electrolyzer 73 5.2.3 Sensitivity Analysis 75
5.3 Emissions from Hydrogen production 76
6. DISCUSSIONS 78
6.1 Research Questions and Methodology Discussion 78
6.2 Survey and SWOT-PESTEL results 78
6.3 Hydrogen Production costs 79
7. RECOMMENDATIONS AND CONCLUSIONS 83
7.1 Recommendations 83
7.2 Conclusions 86
7.3 Future Scope 87
8. REFERENCES 88
9. APPENDIX 96
List of Figures
Figure 1 EU demand for gaseous fuels, in 2015 14
Figure 2 Pathways to decarbonize current gas demand 15
Figure 3 Total energy supply (TES) by source, Portugal 1990-2019 16
Figure 4 CO2 emissions from the combustion of natural gas 21
Figure 5 World natural gas production (volume) by region from 1973 until 2019 22
Figure 6 Natural Gas: National Consumption in 2019 (Bcm) 22
Figure 7 Correlation between GHG emission reduction and expected gas demand until 2050 24
Figure 8 Correlation between GHG emission reduction until 2050 and type of gas 25
Figure 9 Climate Change mitigation performances of fossil and renewables based gas production
segregation of gas types 26
Figure 10 Hydrogen generation capacity by technology 29
Figure 11 Potential pathways for producing hydrogen and by products 30
Figure 12 Hydrogen generation and infrastructure in Portugal by 2030 (Predicted) 31
Figure 13 Portuguese National Hydrogen Strategy 32
Figure 14 EU policy timeline 34
Figure 15 Hydrogen production via SMR with CO2 capture (CCS) 39
Figure 16 Working of an Electrolyzer 41
Figure 17 Boundaries of the Thesis 43
Figure 18 SWOT Analysis 44
Figure 19 PESTLE Analysis 45
Figure 20 Systematic methodology of the survey 46
Figure 21 Schematic overview of production methods 47
Figure 22 Hydrogen Production Costs – Methodology 48
Figure 23 Political Barriers 58
Figure 24 Economic Barriers 60
Figure 25 Social Barriers 62
Figure 26 Technological, Technical & Operational Barriers 64
Figure 27 SWOT ANALYSIS 65
Figure 28 SWOT ANALYSIS SUMMARY 66
Figure 29 Uncertainty: Social Barriers 68
Figure 30 Uncertainty: Social Barriers 69
Figure 31 Uncertainty: Technological & Technical Barriers 69
Figure 32 LCOH: SMR: Split up of costs 71
Figure 33 LCOH: SMR: Comparison with and without Carbon taxes 72
Figure 34 LCOH: PEM: Split up of costs in 2020 73
Figure 35 LCOH: PEM: Price range 74
Figure 36 Sensitivity Analysis:SMR, PEM-GRID, PEM-WIND & PEM-SOLAR 75
Figure 37 CO2 Emissions from Hydrogen Production (kg CO2/kg H2) 76
Figure 38 Levelized Cost of Hydrogen from Clean Hydrogen Report 80
Figure 39 GHG emissions of Hydrogen production 81
Figure 40 Summary of estimates from the literature of LCOE and CO2 emissions of Hydrogen
Production methods 82
Figure 41 Areas of Action 83
Figure 42 LCOH: ALK: Split up of costs 98
Figure 43 LCOH: ALK: Price Range 99
Figure 44 LCOH: SOEC: Split up of costs 100
Figure 45 LCOH: SOEC: Price Range 101
Figure 46 Sensitivity Analysis:Alkaline Water Electrolysis and Solid Oxide electrolyzer Cell 102
List of Tables
Table 1 Alternatives to Natural Gas 26
Table 2 Investment Costs and Efficiency of Hydrogen Production Technologies [37] 51
Table 3 Fuel and Water price 52
Table 4 Electrolyzer Lifetime [37] 53
Table 5 Parameters and formula used 54
Table 6 Steam Methane Reforming: Calculated Costs 55
Table 7 Expert´s opinion: Political and Regulatory Barriers 59
Table 8 Expert´s opinion: Economic Barriers 61
Table 9 Expert´s opinion: Social Barriers 62
Table 10 Expert´s opinion: Technological & Technical Barriers 64
Table 11 Statistical Treatment of the Survey replies 67
Table 12 LCOH SMR: Split up of Costs 70
Table 13 CO2 Emitted and Captured per year [64] 71
Table 14 LCOH: SMR: Comparison with and without Carbon taxes 72
Table 15 LCOH: PEM: Split up of costs 73
Table 16 LCOH: PEM: 2020 vs 2030 74
Table 17 Summary of LCOH from Electrolyzers 79
Table 18 Statistical Treatment of the Survey replies: 1.Economic Barriers 2.Social &
3.Technological and Technical Barriers 96
Table 19 LCOH: ALK: Split up of costs 98
Table 20 LCOH: ALK: 2020 vs 2030 vs 2050 98
Table 21 LCOH: SOEC: Split up of costs 100
Table 22 LCOH: SOEC: 2020 vs 2030 vs 2050 100
List of Abbreviations
ALK: Alkaline Water Electrolyzer
CCS/CCUS: Carbon Capture & Storage/ Carbon Capture Utilization & Storage
EU: European Union
FCH JU: Fuel Cells and Hydrogen Joint Undertaking
GHG: Green House Gases
LCOH: Levelized Cost of Hydrogen
MDEA: Methyldiethanolamine
MEA: Methylenedianiline
NECP: National Energy and Climate Plans
PEM: Polymer Electrolyte Membrane Electrolyzer
PESTEL: Political, Economic, Social, Technological, Environmental & Legal
REN: Rede Electrica Nacional
SMR: Steam Methane Reforming
SOEC: Solid Oxide Electrolyzer Cell
SWOT: Strengths, Weakness, Opportunities and Threats
YOY: Year on Year
List of Units
EUR Euro
gCO2 gram Carbon dioxide
GW Giga Watt
GWh Gigawatt-hour
kJ kilo Joule
ktoe kiloton of oil equivalent
kWh kilowatt-hour
m3 meter cube
mol moles
Mt Megaton/ Billion kilograms
MW Mega Watt
Nm3 Nominal cubic meters
Tcm Trillion cubic meters
tCO2 ton carbon dioxide
TWh Terawatt-hour
1. Introduction
1.1 Background
Decarbonizing the natural gas industry
The European commission’s long-term objective of achieving carbon neutrality by the year
2050 [1] and its synergy with Paris Agreement [2] calls for decarbonization of its energy
markets. The commitment beckons for an equivocal response to ensure a sustainable mix in
the energy sector. The international scenario points to a growing trend towards electrification
of the economy, and energy matrix resulting from a blend of renewable sources (solar, wind,
water and biofuels). Therefore, the objectives and the profound decarbonization trends looks
to guarantee carbon neutrality of national emissions, ensuring the safety of supply and the
financial sustainability of the energy system.
Natural gas is a fossil fuel, considered as the cleanest burning fossil fuel with the highest
hydrogen to carbon ratio [3]. It is seen as a quick fix for the road to neutrality as it ensures
flexibility and security needed in the energy sector, replacing coal and thus lowering
emissions. This is considering the energy demand and the electricity production from
renewables that depends on the seasonal variations and peak loads [3]. Natural gas provides
an alternative to the expensive 100% electrification pathway, thereby enabling ease of
decarbonization by fulfilling the energy demands that are not covered completely by
electricity.
Natural gas represented a quarter of energy supply (close to 16000 thousand Terajoules) and
22% of final energy use in the EU (including the United Kingdom) in 2018 [3]. With 2.2
million kilometers of gas pipelines, the current gas infrastructure in Europe helps in a wide
scale deployment and storage of hydrogen and other decarbonized renewable gas [4]. A
steady increase in the installed natural gas capacity thanks to the lower capital costs, flexibility
and higher efficiencies, the interrelations between molecules (gas) and electrons (electricity)
is also on the rise. Enabling the substantial investment made in energy transport and
distribution infrastructures provides the quality of service to the consumers in this gradually
complex market.
The future of the European energy system however will require more of renewable electricity
and the scale-up of renewable and decarbonized gases than existing and proposed levels. The
demand for gaseous fuels in the various scenarios can be seen in Figure 1. The existing
decarbonizing strategies and methodologies suggest a low carbon gas uptake, namely
hydrogen and bio methane. As seen in Figure 1, hydrogen plays an important role in all the
scenarios and while the pathways as shown in Figure 2 are the possible alternatives for natural
gas as an energy carrier; the main link was identified by many studies as Hydrogen [6]. The
leftmost bar represents the current methane demand projected at 525 Bcm (billion cubic
meters annual) and the following bars denote the avenues, gas demand, and the method to
produce hydrogen.
Figure 1 EU demand for gaseous fuels, in 2015, forecast for 2030, baseline for 2050 and different
decarbonization scenarios for 2050 developed for the EU 2050 strategy, [5]
Hydrogen is considered as the pivotal facilitator of quick and viable decarbonization
alternative to replace natural gas. The hydrogen pathway can be predominantly used in the
heat, transport and the power sectors while the benefits also include reduction in nuclear
power for electricity and heavy investments in the electricity grid [7]. Being versatile, it could
be produced from a range of fuels including natural gas via Steam Methane Reforming
(known as blue hydrogen) and renewable electricity via Electrolyzers (known as green
hydrogen). It can be transported in the existing gas pipelines or even as liquid [8]. Although
hydrogen has different chemical properties when compared to natural gas, addition of
compressors and refurbishing pipelines, hydrogen can be distributed through the prevalent
natural gas network. The current hydrogen infrastructure and grid connectivity is detailed in
Chapter 2.
The uses of hydrogen are multifold across many sectors and can be used in a versatile manner
as an energy vector to store renewable electricity or for space heating. The supply of
hydrogen is a topic under research that looks at a variety of issues including the injection,
safety, end user acceptance and the costs [9]. The conversion of hydrogen and its various
other uses are further discussed in Chapter 2.
It is often dubbed as the fight of the decarbonization pathways where hydrogen was the
preferred option for the gas system while electricity generation from renewables were the
desired option for the electricity sector. However, in order to enable a fast yet cost effective
decarbonization, Electricity and hydrogen interlinking in an effort to use green molecules
(H2) and green electrons (e- from renewables) to achieve the desired targets of the 2030
Climate and Energy Framework (Refer to Chapter 3) [6].
Figure 2 Pathways to decarbonize current gas demand [6] NOTE: Size of bars are just for the sake of visualization
The major roadblock for hydrogen and other low carbon gases such as synthetic methane
and bio methane would obviously be the economic aspect, as the competitiveness, supply
and demand from them are yet to reach that of natural gas [6]. In addition, there are also the
compatibility issues such as injection of gases in the grid and blending hydrogen into existing
gas network.
A market reform backed with regulations and policies will deliver an accelerated and effective
decarbonization pathway of the gas sector in Europe. Several studies show that a
restructuring based on hydrogen will in turn aid in the gas infrastructure’s transformation,
creating a more integrated European energy system [7]. Production and supply of hydrogen
that is economically competitive compared to natural gas is thus essential. As a dedicated
Member state, Portugal and its hydrogen strategy appears to be a viable area of introspection
to evaluate green hydrogen production costs as it aims to be the principle supplier of cheap
green hydrogen in EU. This calls for realizing a case study in Portugal considering the
hydrogen production in the state. The following sub topic covers this in elaboration.
Development of a case study in Portugal: Future principle green
Hydrogen producer in EU
Portugal, the westernmost nation state of Europe is a world leader in promoting and
implementing integrated renewable electricity production from wind and solar power as
clearly seen in Figure 3. It has a solid renewable energy target of 80% by 2030 and plans for
carbon neutrality by 2050 [10]. The energy transition in Portugal, like the majority of
European countries, will undoubtedly go through the electricity and power sector, based on
reliable electrification and decarbonization of the economy. Portugal has enormous potential
for the development of a heavily decarbonized electric power sector, either through the
availability of renewable endogenous resources such as water, wind, sun, biomass and
geothermal energy, or because it has a reliable and safe electrical system capable of handling
the variability [11].
Figure 3 Total energy supply (TES) by source, Portugal 1990-2019, [11]
The program of the Roadmap for Carbon Neutrality 2050 [12] and the National Energy and
Climate Plan (NECP) 2030 [13] designed by the Portuguese government, are in response to
the Paris Agreement signed by the Government. An initiative of the Ministry of the
Environment and Climate Action, they represent the national goal of achieving sharp
reductions of harmful emissions and guarantee energy sustainability of future generations.
The main goal is to enable the rational use of resources and technologies that allow the
transition to a low carbon economy, enhancing endogenous resources in a cost-effective
logic of the national energy system, in its different vectors, where hydrogen can play a
significant role, up to 50% according to FCH JU [14].
In the Portuguese National Electric System (PNES), public policies were oriented towards
the decarbonization of energy production, favoring renewable sources, reducing or
eliminating fossil production. However, in the Portuguese Natural Gas System (PNGS) the
challenge lies in need to decarbonize the primary energy source, ensuring the proper
compatibility of transport and distribution assets, as well as the synchronization of consumer
equipment. In this context, hydrogen appears as a renewable energy source capable of
guaranteeing not only the transformation of the PNGS but also the integration with the
PNES, ensuring the conversion of excess electrical energy into storable energy in the
networks. The use of existing grid and the pathways are discussed in detail in Chapter 2.
Portugal aspires to be the supplier of the cheapest green hydrogen in Europe backed by the
NECP, which states the country’s commitment towards creating a market for renewable
gases. Backed by its abundant and cheap renewable energy in the form of solar energy, the
NECP also desires to develop policies that enables Portugal to be in a favorable position. An
incentivized pathway is to bring greater dependency on Hydrogen and Portugal expects to
have 7% of the renewable fuels of transport sector to be green hydrogen. This is nearly 756
GWh by 2030 [15].
Policies and regulatory measures in the industry will guarantee a solid market for renewable
hydrogen, not just as a replacement of natural gas but also in the fertilizer and ammonia
industries and transport sector. Chapter 2 has a dedicated section that describes Portugal’s
hydrogen usage plans.
A well-devised framework for the hydrogen pathway should address the value chain in
entirety, encompassing generation, transmission, distribution and storage as well as the end
users. REN is public service Company that controls the transportation and storage value
chain of natural gas in Portugal. REN Portgas is a subsidiary of REN, and is involved with
the distribution of natural gas. Portgas in particular is the only Portuguese company to be
admitted to join the second round of the European Clean Hydrogen Alliance [16]. Thus, it
plays an important role in the implementation and the realization of the country’s NECPs
using its existing infrastructure and strategies to decarbonize gas and digitize its assets using
smart metering. The thesis therefore is performed at REN Portgas and provides the perfect
environment for research and development.
1.2 Objective & Scope of Study
The current state may not enable a full realization of the potential of decarbonizing the gas
sector and requires swift developments and policy frameworks that accelerate the transition.
It is questionable as to why there are no obligations on the industry itself to facilitate the
shift. This raises the important question:
1. What are barriers that the current policies and regulations pose to decarbonization
of natural gas?
The pathways for decarbonization and replacing natural gas with Hydrogen, as introduced
in the previous section, could play a pivotal role. Thus, Hydrogen will be the explored
pathway. Portugal as the country could create a great environment for cheap green hydrogen
production. The end user costs of hydrogen can be split into production, transmission,
distribution, and storage and dispensing. Studies suggest that production costs contributes
40-60% of the entire hydrogen systems costs, including grid infrastructure [7]. Therefore,
this thesis only considers the production costs of hydrogen production. In this context, to
fulfil the hydrogen injection, there are financial, operational, technological and regulatory
challenges that gives rise to the following questions, which the market has to gradually answer
and address.
2. What are the costs involved in hydrogen production using renewable energy sources
given Portugal’s ambitious plans (Refer chapter 2)?
The costs associated are calculated for the scenarios of electrolyzers connected to the grid,
solar electricity and wind electricity. Specifically the years 2020, 2030 and 2050 are taken into
account due to its alignments with policies such as the NECP 2030 and the Road to neutrality
2050. The production costs does not necessarily take the role of carbon taxation into
consideration and thus
3. How does implementing a carbon tax affect the LOCH of blue hydrogen, the
hydrogen obtained from methane reforming?
The predictions of possible pathways in Portugal do not cover the questions mentioned but
the solutions may have profound impact on the policy and regulatory framework of Portugal
in the near future.
While a plethora of discussion exists elaborating the need to ditch fossil fuel dependency,
there is a dearth of debates on the barriers of existing reforms and cost associated with
desired pathways in Portugal. Thus, the thesis includes an examination of regulations and
policies, a techno economic assessment of hydrogen production in Portugal and a sensitivity
analysis. The objectives are:
To perform a qualitative study on the barriers to decarbonization of gas sector
based on the prevailing policies and regulations using SWOT-PESTEL approach.
To perform a techno-economic analysis of hydrogen production from different
technologies, viz. Steam Methane Reforming, SMR (with and without Carbon
Capture Utilization and Storage, CCUS) and electrolysis (grid vs renewables) in
Portugal.
To help formulate strategies and recommendations for Portuguese policymakers
and natural gas industry stakeholders for better future policies and regulatory
reforms.
This study could provide a deeper understanding on the conditions/strategies, and benefits
of decarbonizing the natural gas sector and facilitating the proper compatibility of hydrogen
in the gas network. Such information could help local & national governments, and key
stakeholders alike, to be equipped with the investment needs and helping industries to plan
for the impending future of carbon neutrality. As a whole, these assessments can support
Portugal in determining or adapting their hydrogen policies and targets for 2030 and beyond
and how to support hydrogen deployment with the right set of policy measures.
1.3 Structure of the report
This introductory chapter provides a background of the study and thesis objective.
Chapter 2 talks about natural gas and its world outlook. It addresses the need for
decarbonization and introduces different methods of decarbonizing the system. Then the
importance of hydrogen in a long-term decarbonization strategy is introduced. It covers the
current hydrogen outlook in EU and its member states, which also introduces the case study
in Portugal and its hydrogen plans. This chapter will further provide methods in use for
hydrogen production, and narrowing the research of the cost evaluation for hydrogen
production in Portugal to two methods: Steam Methane Reforming with/without Carbon
Capture and Storage (SMR+ CCS) and Electrolysis.
Chapter 3 covers the literatures reviewed pertaining to decarbonization and hydrogen
production technologies. The chapter further provides an analysis of the various existing
policies & regulations on natural gas and its markets in EU. Chapter 4 defines the
methodology used in the study. Here the boundaries and limitations are reasoned. The
methods are defined and the steps, assumptions and calculation of the LCOH are discussed.
Chapter 5 is results, and it provides the findings of the research, namely, constraints to
decarbonization, the SWOT-PESTEL analysis and finally the results of economic and
sensitivity analysis of hydrogen production costs. The chapter presents the results of the
emissions from the production. The subsequent chapter 6 is dedicated for discussions,
compares the research questions, the methodology, and presented results to the literatures
and reports related to this topic.
Chapter 7 presents the conclusions and recommendations of the thesis. It also insights into
to possible future outlook of the thesis.
2. Natural gas: World Data, Decarbonization Pathway
and Hydrogen in Portugal
In this chapter, natural gas is discussed in depth with insights into the current world outlook,
the supply demand and imports in Europe and the need for decarbonization. The pathways
to decarbonization are also discussed to emphasize the importance of hydrogen production
and the motive for the case study in Portugal.
2.1 World vs Europe Outlook
Natural gas is one of the leading fossil fuels, globally growing in demand every year and
currently accounting for 23% of primary energy demand and one fourth of the electricity
generation across the world [17]. It is regarded as the cleanest fossil fuel when burnt and is
superior to other fossil fuels in terms of the environmental benefits that encompasses GHG
emissions and air quality due to a more complete burning of the fuel.
It is also reckoned as an optimal agent to enhance the security of electricity supply procured
by renewable production due to its flexibility and storability [17]. Responsive to the seasonal
outages and the ever-growing short-term demand and fluctuations, the natural gas sector is
pivotal to enable any transition in the near future. It is a potential supplement to electricity
from renewable energy, in the sense that it covers for the intermittency associated with wind
and solar energy. The major role natural gas would play is to be the provider of a low cost,
low carbon (in comparison to coal) electricity as a backup instead of being the round-the-
clock main supplier. This makes natural gas as a great facilitator of energy transition.
A globalized market powered by the rising supplies of Liquefied natural gas (LNG) and the
availability of shale gas has visibly increased the gas trade all over the world, thus creating
novel dimensions of interconnected gas markets, supply security of natural gas and the
interdependency across regions [17].
Natural gas is mainly composed of the smallest hydrocarbon component (CH4) consisting of
one carbon atom and four hydrogen atoms. It, like other fossil-based fuels, is an energy
source buried deep down the earth’s crust, predominately trapped between overlaying rock
layers [17]. Natural gas found in large creaks, known as Conventional Natural Gas while
the gas occurring in smaller pores of shale and sedimentary rocks, commonly known as Shale
Gas or Unconventional Natural Gas. The gas that is found along with oil wells are known
as associated natural gas while the type found along with coal beds is referred to as Coalbed
Methane [17].
Naturally occurring gas contains amounts of other gases like CO2, H2S, Nitrogen or helium
and other Natural Gas Liquids (NGLs) in varying percentages. Being a fossil fuel, natural gas
is a non-renewable and contributes to the global CO2 emissions (Figure 4) [17].
Figure 4 CO2 emissions from the combustion of natural gas [18]
Natural gas had a 4.6% increase in consumption in the year 2018, which amounted to nearly
50% of the increase in energy demand [17]. The growth of natural gas has been prominent
and majorly converged in just three areas as following. The Middle East, where gas is a
blessing in disguise to diversify the heavy economic dependence on oil; The United States,
backed by the abundant shale reserves and China, where exigent measures where needed to
curb the coal reliant power industry to improve the poor air quality. Surge in investments in
the new Liquefied Natural Gas (LNG) pipelines and supply and low import prices promote
LNG as the torchbearer for a broad-based growth in future. Natural gas continues to
outperform coal or oil in scenarios developed by the IEA but the gas industry as a whole,
confronts many challenges including environmental ones [17].
2.1.1 Natural gas WORLD data: Production, Imports & Demand
a. Natural Gas Production
The global production of natural gas has been progressively rising since the 2007-08 financial
crisis, with a 2.7% growth rate Y.O.Y. But 2019 saw the highest increase in the production,
crossing the 4 Tcm, a total of 4088 Billion cubic meters (Bcm) and a rise of 3.3%, 0.6% more
than the previous average as seen in figure 5. Geographically, the increase in production was
propelled by North America, with an increase of 78.4 Bcm, more than 50% of 131.5 Bcm.
The OECD Asia Oceania also played a significant role, with 25 Bcm increase [17].
0
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Figure 5 World natural gas production (volume) by region from 1973 until 2019 [19]
b. Natural Gas Imports
Like the production, the imports also saw an increase, hitting 1.2 Tcm in 2019. This also saw
an augmentation to the ratio of gas imported/ traded to that of produced to 30.2%,
previously at 29.8% as of 2018. The trend is majorly due to the amplified LNG trade and
imports amounting to 65.6 Bcm in the world. LNG volumes accounted for more than 38%
in 2019, a 4% increase in comparison to 2018 levels of 34.3%. Like its neighbors, China
cemented it place as a pivotal player in the dynamics of the LNG market in the world. With
an increase of 11.8 Bcm compared to 2018, China saw the largest increase in imports of
LNG for the second consecutive year. UK closely followed China with 11.3 Bcm in 2019
[17].
Figure 6 Natural Gas: National Consumption in 2019 (Bcm) [20]
c. Natural Gas Demand
From Figure 6, in 2019, the natural gas, just like the production and import, saw a rise in the
demand end of business. 57.9 Bcm (1.5%) was added to the 2018 levels, pushing the total to
3.98 Tcm. OECD countries in Europe and America were predominantly responsible for the
increase with contributions of 13.9 Bcm and 22.3 Bcm respectively. Although Korea (-3.0
Bcm), Japan (-5.6 Bcm) and Turkey (-4.7 Bcm) experienced a fall in the demand, USA with
22.3 Bcm, Germany and Australia reset the offset of demand decrease. The Middle East
represented by Iran, Iraq Bahrain and Kuwait contributed to +11.7 Bcm from the Non-
OECD countries in the region. China, however was the major driver of the demand from
Non-OECD countries and overall, contributing to 24.1 Bcm [17]. The demand is mainly for
the industrial use (37%), followed by residential heating at 30%. Natural gas has also uses in
the transport and the commercial and public services sectors.
2.1.2 Natural gas EUROPE data: Production, Imports & Demand
The EU Economy is dependent on Natural gas, amounting to 24% (525 Bcm) of the energy
supply and 22% of final energy use in EU and the United Kingdom in 2018. Power
generation has also seen a gradual increase in the share of natural gas, 22% in 2019,
successfully and gradually supplanting coal. Sector wise, natural gas accounts for 31% of
commercial energy needs, 36% for residential, 32% for industrial use, 23% of the final energy
consumption and an additional non- energy use of 15% [21]. The average stated above varies
drastically among the different countries and reasonably so. For example, the Netherlands
leads EU in terms of the largest natural gas share by volume in the primary energy supply
with 42%, and natural gas represents 71% of the residential heating and 44% of commercial
space heating. With over 115 million customers, the European natural gas sector needs a
decarbonization strategy backed with strong regulations [22].
The natural gas demand in the EU however is principally met by imports, close to 400 billion
cubic meters (83%) of imported natural gas by volume [23]. An extensive and integrated
trans-European transmission and distribution pipeline network caters to over 115 million
consumers, industries, commercial entities and residential customers alike. The transmission
lines of about 200,000 kms, owned by 47 TSOs across the EU, carries high-pressure natural
gas connecting the various industries, power plants, storage facilities and the distribution
networks. The DSOs and their strong 2 million km distribution lines supply low and medium
pressure gas [22].
The market structure is a bit complicated and is quite diverse across the member states. While
energy content based trading of gas is common, the quality is varied between countries and
in some cases within parts of a country. The network operators oversee the differences in
gas qualities and the regulators set the national level gas quality.
Commercially, wholesale markets are connect importers of natural gas and LNG to large
scale users with a middleman in the form of traders and the retail markets supplies (utilities)
to smaller users.
2.2 Need for Decarbonization?
Decarbonization of the natural gas sector is inevitable and there is an exigent need to address
the growing carbon-intensive sector. Existing decarbonization policies and regulations like
that of RED II [24] and the EU ETS [25] continue to monitor and guide the sector to reduce
the carbon footprint. Setting carbon prices, national targets and support for the uptake of
renewable gases (hydrogen, primarily green, bio methane etc.) ensures a smooth transition.
A regulated market further guarantees positive competition and a levelized field for all
players. However, the present frameworks cannot render the gas sector decarbonization by
2050 as forecasted by many including Alex Barnes in their Energy Insight 71 for The Oxford
Institute for Energy Studies [26].
The EU plans to completely overhaul its economy to be carbon neutral by 2050. The
European Green deal, released in the end of 2019, details a large-scale plan in order to
accelerate the pathway towards decarbonized economy. This calls for a step-up in
investments in greener alternatives. Low carbon intensive energy vectors and carrier,
renewable energy should take over while simultaneously phasing out fossil fuels. It will also
depend largely on sector integration, mainly electricity and gas. A decarbonized Europe relies
heavily on a low cost interplay between renewable electricity production and pan sector
supply. To this end, conversion of green electrons to molecules takes precedence. On a
contradictory note, the same climate policies that have ensured a spike in greener electricity
production has failed to cater to the gas sector.
Figure 7 Correlation between GHG emission reduction and expected gas demand until 2050 [27]
As seen in the previous section, there has been a significant dependence on Natural gas in
the EU. The flipside of the increased consumption is that companies and governments alike
continue to invest in improving the infrastructure, thus creating a loop of dependency on
fossil fuels. With the continued increase in gas consumption, inevitable emissions currently
present in gas extraction stage and transportation stage of the value chain pose a threat to
decarbonization. The increase in investments, combined with the need to achieve Carbon
neutrality, leaves the sector bound to a substantial number of stranded assets. What follows
is a reiteration among different stakeholders placing blame on the other unless there is a
defined strategy by the EU that addresses the issues at hand.
The figure 7 shows the predicted trend lines of natural gas demand for different scenarios of
CO2 emission reduction. In order to reduce the CO2 emissions up to 80%, 43% of the gas
demand should be constant while having a 29% moderate decrease. Clearly, a decrease in the
natural gas demand would reduce the amount of CO2 emissions. Figure 8 on the other hand
predicts the type of gases in the mix by 2050. It is evident that hydrogen (40% of total
volume), synthetic methane and biomethane are key to reduce the emissions to below 95%.
Figure 8 Correlation between GHG emission reduction until 2050 and type of gas [27]
In the subsequent section, the means to achieve carbon neutrality in the natural gas sector
are examined. Additionally, hydrogen pathway is inspected.
2.3 Means to Decarbonize Natural Gas
The current trends of natural gas in Europe, as discussed in the previous sections, shows that
gas consumption is dominated by natural gas (Fossil). However, if EU is to be the first
climate neutral continent as targeted, it would mean that this dependence is gradually but
inevitably reduced. It would also imply that gas would then not only constitute of methane,
but a mix of hydrogen and other low carbon gases as indicated in Figure 9.
High GHG Low GHG GHG Neutral
Fossil gas
Natural gas from conventional and unconventional sources
Hydrogen from Natural gas coupled with CCS
Hydrogen from natural gas with 100% carbon capture
Fossil gas from coal or petroleum coke gasification
Synthetic methane from grid connected electricity
Synthetic Methane from grid electricity coupled with CO2 capture
Renewable gas Biomethane from crops
Hydrogen or synthetic methane from low GHG electricity production
Hydrogen or synthetic methane from renewable electricity
Biomethane from crops with low methane leak
Biomethane from wastes and avoided methane
Figure 9 Climate Change mitigation performances of fossil and renewables based gas production segregation of gas types [28]
Various studies have indicated the means to decarbonize gas. The following are the most
quoted and suggested ways:
Hydrogen
Hydrogen is produced from water electrolysis or using methane reforming. It could ideally
be used as a substitute for natural gas. Various studies in Europe have explored the pathway
with hydrogen as an energy carrier and its potential to replace natural gas. EU commission’s
report on the impact of hydrogen and bio methane on the infrastructure [29]. Poyry, now
AFRY, explored hydrogen use in their reports on “Fully decarbonizing Europe’s energy
system by 2050” and “Hydrogen from natural gas – the key to deep decarbonization” [30]
[7]. Navigant, a consultancy, and Gas for climate also evaluated hydrogen as the successor
of natural gas [31] [32].
Bio methane and Synthetic methane
Bio methane and synthetic methane, when blended with natural gas have shown to reduce
CO2 emissions by up to 95% [33]. These gases are low carbon gases and have very little
carbon footprint. Biogas, produced from the gasification of organic wastes [28], can be easily
injected into the existing grid. Power to gas to produce synthetic methane from excess
renewable power is also a viable option [33]. As of 2018, biogas installations was at 18202,
producing 63511 GWh of biogas in Europe [34].
Table 1 Alternatives to Natural Gas
Method Pros Cons
Hydrogen:
Water
Electrolysis
Renewable electricity usage
Excess renewable output can be stored in Hydrogen as a form of Energy Vector
Highly dependent on electricity
Policy and investment barriers
Seasonality of RE
Can utilize existing grid as well as newly planned RE projects
Cost of production and competitively vs Natural gas
Steam
Methane
Reforming
Production from SMR can be easily achieved with CCUS
Natural gas is utilized as the feedstock
Nascent technology in terms of carbon capture and storage
Highly reliant on CCUS to be deemed as blue hydrogen
Bio methane
and synthetic
methane
Produced from wastes and byproducts can be used as fertilizers
Small scale implementation is already in place
Easier process
Efficiency
Potential and scalability will depend on agricultural wastes
CO2 is a byproduct
Impurities will bear additional costs
From table 1, it is clear that Hydrogen pathway is easily compatible with the electricity sector,
acting as an energy vector, storing excess renewable electricity as hydrogen and converting
H2 into electricity during higher demands. It can also be produced without any emissions
(green hydrogen). Using these as the main advantages of the selected pathway, the thesis
proceeds to analyze the current state of hydrogen in Europe and the reason for a study
specific to Portugal in the following sub chapters.
2.4 Hydrogen in EU
The European Commission took to its hydrogen strategy for a climate-neutral Europe. The
Strategy lays out a detailed plan to enable scaling up of Hydrogen to satisfy the demand for
a climate neutral ecosystem. Covering the whole hydrogen value chain, the strategy looks to
put together the different players in the industrial, infrastructure and market aspects coupled
with research, development and innovation globally. The strategy also highlights clean
hydrogen and its value chain as one of the essential areas to unlock investment to foster
sustainable growth and jobs. Objectively, the strategy aims to have at least 6 GW of
renewable hydrogen electrolyzers by 2024 and at least 40 GW of renewable hydrogen
electrolyzers by 2030 [35].
The Vice President of European Green Deal, Mr. Frans Timmermans said
“Driving hydrogen development past the tipping point needs critical mass in
investment, an enabling regulatory framework, new lead markets, sustained research
and innovation into breakthrough technologies and for bringing new solutions to the
market, a large-scale infrastructure network that only the EU and the single market
can offer, and cooperation with our third country partners”
As reported by the Smart Energy International Issue 4-2020 [36]
The role of hydrogen in the EU’s energy and greenhouse gas (GHG) emission reduction
efforts will rapidly increase. Currently at 339 TWh of hydrogen per year (2019), the
expectation is a significant increase in the use of hydrogen – between 667 – 4000 TWh in
2050. In order to have a positive impact in the transition, hydrogen must be sustainable
across the value chain and other factors like costs, and the impact it has on jobs etc. [35].
2.4.1 Hydrogen Production
Production by Type
In total, 457 hydrogen production sites are said to be in operation in Europe at the end of
2018. Facilities are further divided into three main types: captive production (64%), merchant
production (15%) and by-product of other processes (21%). The total production capacity
was close to 11.5 million tonnes per year as of 2018. Pure hydrogen production capacity is
9.9 Mt per year of which the majority is produced on site, amounting to at least 2/3 of the
total capacity. The utilization was 84% in the year 2019. The other major producer are the
merchant plants, estimated to be 184 in number across Europe. Merchant Hydrogen plants
often provide to either a single large consumer or small/ medium plants that caters to retail
customers. While the first type can be comparable in scale to the largest captive hydrogen
production facilities, the installations intended with the hydrogen market in mind are an order
of magnitude smaller in terms of their maximum capacity [35].
Hydrogen from other processes, usually as a by-product is produced at 133 different plants.
Total by-product hydrogen production capacity has been estimated at 2.36 Mt per year
(around 20% of total production capacity) of which the coke oven gas (COG) represents the
highest share. Though the purity is not 100% (~60%), COG produces about 1.6Mt per year.
Production by Technology
Steam Methane Reforming (SMR) or Auto thermal reforming (ATR) is by far the most
common method used for hydrogen production. SMR and ATR are broadly utilized for all
applications, be it oil refining, smelling salts amalgamation or some other mass hydrogen
creation. Albeit natural gas is the most well-known feed for hydrogen production, SMR can
also be utilized with different feeds, including fluid hydrocarbons like Naphtha or Liquefied
Petroleum Gas (LPG) [35].
As of now, 95% of EU hydrogen production is done via steam methane reforming (SMR)
and to a lower extent auto thermal reforming (ATR), both highly carbon-intensive processes
and thus commonly called the blue hydrogen [37]. The production capacity by technology
can be seen in figure 10. However, both the reforming methods can be coupled with CCUS
to capture the CO2 for later use, and thus reducing its footprint. The hydrogen thus produced
is name the blue hydrogen. 228 hydrogen production plants were using a fossil-based
feedstock and thus unsustainable. Five percent is produced through chlor-alkali process,
which falls under the category of Chemical industry by product [35].
Polymer electrolyzer membrane (PEM), Alkaline Water electrolysis (ALK) & Solid Oxide
(SOEC) are the main methods in green hydrogen production aka renewable hydrogen. There
are a significant number of electrolyzers installed in Europe. Conventionally, electrolyzer
technology have been given precedence whenever the volumetric demand for hydrogen is
sufficient to commission a separate onsite unit instead of relying on outside supply [35].
Figure 10 Hydrogen generation capacity by technology [35]
2.4.2 Hydrogen Demand
Total demand for hydrogen in the EU in the year 2018 was 327 TWh. Refineries and the
ammonia industries were the main consumers and amounted to 4/5 of the total demand,
equivalent to 6.5 Mt of 8.3Mt in total (45% and 34% respectively). Methanol production
contributed to 12% of the demand. The current supply and demand is based on years of
using Hydrogen as a feedstock for ammonia (34%), methanol (5%) and other refineries
(40%) rather than as an energy carrier or for energy use (1%) [35]. Thus, most of the
production is dedicated to the refinery and ammonia production industry and do not
necessarily produce hydrogen from low carbon fuels.
2.5 Hydrogen Production Technologies
Hydrogen is predominantly produced from fossil fuels (Natural Gas, Coal), biomass, or from
water and sometimes a combination of either [8]. The potential pathways to produce are
described in the figure 11. This figure also shows the ammonia production from hydrogen,
which constituted to 35% of hydrogen demand in the EU. As seen before, the largest share
of current production is by methane and hydrocarbon reforming (90%). The current state of
clean hydrogen production, i.e. low carbon or renewable hydrogen (Green hydrogen) is less
than 1% in terms of production capacity [35]. The downsides include upcoming end uses of
hydrogen that include zero “Well to Wheel” emission mobility.
However, as per the EU Hydrogen Strategy, renewable hydrogen production have been set
an ambitious target of reaching almost 10 million tonnes (equal to the current production
capacities) by 2030 [1]. This clearly indicates the imminent need to implement technologies
that produce renewable and low carbon hydrogen.
Since Hydrogen production in EU is dominated by SMR [8], the thesis chooses to underline
its focus on the LCOH from SMR. It is often labelled as blue hydrogen and can be coupled
with Carbon Capture and Storage to reduce its CO2 emissions. In order to take into account
Green Hydrogen production, electrolyzers are taken into consideration. The next chapter
will detail about the working of the selected production technologies along with its types.
Figure 11 Potential pathways for producing hydrogen and by products [8]
Although the production is mainly attributed to Germany (2.5Mt) and Netherlands (1.5Mt)
in terms of production capacity [35], the hydrogen production strategy in Portugal has the
potential to enable cheap yet green hydrogen [13]. This could be seen as an interesting area
of deliberation as to how the production cost could vary based on the electricity, natural gas
and carbon prices in Portugal for the years 2020, 2030 and 2050. Thus, a case study in
Portugal is used to evaluate the production costs of hydrogen in the Member State.
2.6 Hydrogen Strategy in Portugal
Portugal in its NECP (PNES in Portuguese) has defined a definite strategy for hydrogen in
its economy [13]. It is deemed as an important factor in its decarbonization strategy. In
addition to the ongoing projects in the transport and production of Hydrogen, It also has
various projects that are set to decarbonize its heat and electricity sectors [38]. Albeit having
low percentage of hydrogen and low carbon gases in its current mix, the country endeavors
to maximize use of Hydrogen, especially green hydrogen. The EU, as part of the EU
Hydrogen Strategy has already allocated 40 million Euros to the projects in Portugal [15].
The following are the sectors forecasted to use green hydrogen under its strategy:
a. Power to Gas (P2G): H2 to be injected in to the existing natural gas grid
b. Power to Mobility (P2M): As a fuel in the transport sector
c. Power to power (P2P): Surplus Renewable Electricity stored as Hydrogen
d. Power to Industry (P2I): Replacement of Natural Gas as Industrial fuel
e. Power to Synfuel (P2Fuel): Synthetic Gas from Hydrogen and captured
CO2
Figure 12 Hydrogen generation and infrastructure in Portugal by 2030 (Predicted) [15]
The renewable hydrogen generation and the required infrastructure includes an electrolysis
range of 0.3 to 2.3 GW and a renewable electricity generation from solar PV of the range of
0.8-19.8 TWh per year as seen in figure 12 [15] . Portugal intends to set up an anchor
production plant in Sines, scaling up to 1GW Electrolyzer (not clear about the electrolyzer
technology) capacity by 2030 [15]. The plant would be powered primarily by Solar but also
considers Wind power. This is the reason why the production costs analysed in this
thesis considers electricity from grid as well as Solar and Wind powered electricity.
With expected consumption in 2030 in the range of 756 GWh, Portugal has also planned to
invest heavily in R&D. The barriers however will be addressed by introducing specifications
and regulations that mandate uptake of hydrogen.
The NECP has the following goals for 2020 (figure 13):
i. 15% of H2 in the natural gas grid
ii. Ample fueling station for H2 Powered vehicles
iii. Limiting import of Natural Gas
iv. 7 Billion+ euros investments in Hydrogen Projects
v. 5% share in the energy, transport and final consumption
Figure 13 Portuguese National Hydrogen Strategy [39]
3. Review of policies/plans and literature on Natural
Gas decarbonization and Hydrogen in the EU
This chapter consists of the literature that were reviewed during the thesis. The chapter also
links the current data, trends and decarbonization pathways to the methodology opted that
discussed in the subsequent chapter. It also includes a brief description of the EU policies
and regulations relating to natural gas and decarbonization.
3.1 Existing Literature: Natural Gas Decarbonization
Jacquelyn Pless [40] studied the pathways to decarbonization using Natural Gas and
Renewable Energy while Consonni [41] had talked about the co-production of de-carbonized
hydrogen and electricity from natural gas. Abánades, in his paper discusses how gas
decarbonization would serve as a tool to control the CO2 emissions in the EU [42]. Jack et
al, [43] talks about the roadmap toward a rapid decarbonization. Horschig [44] went on
further and carried out a dynamic market simulation for bio methane in the Natural Gas
pipeline. Gil et al, compared Electricity and Natural Gas Interdependency using two methods
by while the use of renewable methane was technologically evaluated by Billig et al., in the
European perspective [45].
Erdgas, in their report, insisted on the importance of hydrogen from natural gas and that it
holds the key to deepen decarbonization. Jose Hernandez researched on the policy and
regulatory challenges in natural gas infrastructure and supply in the energy transition in
Sweden [46] while Martin Lambert studied the narrative of the hydrogen and decarbonization
of gas being a boon [47].
Alex Barnes explored whether the current EU regulatory framework would enable the gas
industry decarbonization [26]. Foreest, on the other hand, discussed the need for a strategy
to have a low carbon natural gas in the UK and The Netherlands [48]. Stern argues that the
stakeholder in the European gas industry ought to demonstrate that they are pivotal in
achieving the targets set by the EU. Stern also asserts the need for a decline in the gas demand
in Europe in the 30s to meet the COP21 targets [49]. In a report by the Energy and
Environmental Economics, Inc., they understand the need to improve combustion process
efficiency while developing decarbonized alternatives to existing natural gas. They also assert
that existing policies still cater to complete electrification than decarbonizing gas.
Eurogas report on the role of gas in ensuring a carbon neutral EU also calls for the necessity
to ramp up relevant policies and changes to the regulations [50]. Several individual
organizations such as Climate Action Tracker researched and developed reports on the
continued dependence on gas and the risks it possesses [51]
Gotz et al, in their paper discusses the technological and economic standpoint of having a
system with renewable power to gas. Comparing the methanation technologies with that of
electrolysis, they concluded process costs curtail hydrogen production and thus need reforms
in policies to enable easier and economical ways to produce hydrogen. The paper states that
P2G can effectively contribute to minimizing the expansion and thus the costs of the
electricity grid. Germany is forefront in empowering P2G pilot plants that produce H2 to be
used as an energy vector [52]. However, the dearth of mass produced Hydrogen due to the
costs as mentioned by Gotz, various plants remain stagnant and thus become heavily reliant
on system configuration and existing infrastructure [53].
While the existing literatures provide information about the need for decarbonization and to
some extent conclude about the barriers to gas sector decarbonization, they have not dwelled
into dividing the internal and external factors. Moreover, the macroeconomic aspects are not
reviewed as well. Thus, this thesis will mainly focus on categorizing the barriers and perform
a SWOT analysis based on macroeconomic factors. The following section describes the
policies relating to Natural gas in the EU. Giving a brief description, it can been seen that
most policies align with Europe’s commitment towards a carbon neutral future.
3.2 Current EU policies & Regulatory Framework
The EU Commission followed their A Clean Planet for All [54] that laid out pathways by
which the EU could reduce emissions, with the European Green deal proposal [55]. The
present policies are consistent with the EU´s long-standing objective of reducing greenhouse
gases emissions (GHG). Added to the existing policies the new deal brings to the table a
bigger confrontation because of the challenges of decarbonising certain sectors of the
economy. The EU has a wide range of policies and regulations that address the GHG
emissions and the impacts of Hydrogen and low carbon gases like bio methane. While Third
Gas Directive governs Natural gas in the EU, regulations in EU do not explicitly addresses
the role of infrastructure in the treatment of gas. Moreover, a hydrogen exclusive regulatory
framework does not exist. The following sections below briefs about the current EU
decarbonization plans that cater to Hydrogen and Low carbon gases.
3.2.1 Policies
Figure 14 EU policy timeline [35]
The following section covers in detail about the policies and regulations that has references
to natural gas and low carbon gases in the EU. The timeline of these polices is as shown in
figure 14.
a. 2030 Climate and Energy Framework
The latest of the various plans ahead for the EU, this proposition has further increased the
GHG emission targets for 2030. It also addresses the actions needed among the sectors and
will further the process of detailing pertinent legislations. It also includes Pan EU targets and
objectives of policies in the period (2021-2030) [56]
Relevance to Gas sector:
1. Minimum 40% (1990 levels) decrease in GHG emissions by 2030
2. Share of renewable energy - >=32%
b. Renewable Energy Directive (RED II)
The revised version of the original RED came into force in 2018. The updated version sets
out modified targets for energy production from renewable energy and covers green
Hydrogen production. The most prominent feature is that the Member States can work in
collaboration with other MSs and third party countries as a part of joint ventures. [57]
Relevance to Gas sector:
1. Renewable Energy usage increase in the heating and cooling sectors: EU-wide target
of 1.3% YoY from 2020 to 2030
2. Recycled carbon gases and non-bio fuel included in the 14% EU-wide target for
renewable energy in the transport sector by 2030
3. A well operating gas network that has provisions for gases from renewable sources
4. Hydrogen and all renewable gases will have guarantees of origin
5. Transport fuels will have a share of biofuels and biogas (3.5%) in 2030
6. Sustainability and greenhouse gas emissions savings criteria
7. Bio methane is included in the definition of biogas as ‘gaseous fuels produced from
biomass’
c. European Climate Law
The law wants to achieve net zero GHGs for all the EU countries as a singular unit, ensuring
that all the further EU policies will inevitably promote this goal and is inclusive to all the
citizens and the sectors. The talking points include protection of environment, green
technology investments and reduced emissions [58].
Relevance to Gas sector:
1. New EU target for 2030 of reducing greenhouse gas emissions by at least 55%
compared to levels in 1990
2. Pan EU adoption of 2030-2050 trajectory for GHG emission reductions 3. Track progress of measures and assessments every 5 years
d. European Green Deal
With goals of becoming the first continent to be climate neutral, The Union came up with
the European Green Deal. The deal lays out an action plan for boosted efficiency, cleaner
fuels, implementing circular economy, cutting out pollution and restoring the serene
biodiversity. The European climate Law is a part of the green deal and is an instrument to a
commitment to a legal obligation. [55]
Relevance to Gas sector:
1. Phasing out coal and decarbonizing gas to facilitate renewable power generation
2. Gas sector Decarbonization by means of support mechanisms, development of low
carbon gases.
3. Competitive gas market for hydrogen and decarbonized gases
4. Reduction in methane emissions related to energy.
5. Energy security and affordability: Neutrality in technology across EU
6. EU Industrial strategy: Energy intensive industries to go through a “green
transformation”
e. 2050 long-term strategy: Clean Planet for all
The main vision of the EU commission with the 2050 strategy was to cover the important
sectors and investigating different transition pathways. The national strategies include
development of GHG emission strategies for 2050. [54]
Relevance to Gas sector:
1. Strategy to maximize energy efficiency
2. Deployment of renewables, clean electricity to decarbonize Europe’s energy supply
3. Hydrogen and Power to X (P2X)
4. Mobility: Hydrogen based and LNG with higher blends of Bio methane
5. Circular Economy: Carbon Capture and Storage converted as raw material for other
industries
6. Trans European Smart energy network 7. Bio economy and Carbon sinks: Uptake for biomass and biogas
f. Energy Taxation Directive: Revised
A steady increase in renewable energy production lead to a revision of the Energy Directive
and Regulation (2009) and included a cap on the subsidies for power plants producing from
fossil fuels. This was in place previously as a capacity mechanism to cope up with the
intermittency of renewable electricity generation and ensure enough capacity to meet the
demands [59].
Relevance to Gas sector:
1. Alignment of taxation on energy products with the climate policies and energy
policies in EU
2. Tax reductions and exemption: rationalized and an updated tax rate aligning with EU
2030 targets
3.2.2 Regulations
The regulations in the EU control natural gas. The Third Gas Directive largely governs
natural gas while Energy Union overlooks the overall policy pertaining to it. A competitive
market and decades of liberalisation has helped in nurturing natural gas in the EU. With a
successful single market and an ensured security of supply, there is a definite stability among
investments and regulations. Scattered third party access and unbundling ease a flexible
market.
Third Energy Directive: Third Gas Directive
Entering into action in 2009, the package works towards resolving the existing infrastructural
problems and better functioning of the energy market in EU. The following are the main
aspects with respect to Gas.
a. Independent regulators & the Gas Regulation
The vital role of independent regulators include instilling the rules and promoting a healthy
and competitive energy market. Important requirements for national regulators are:
The government or the industry will not have any say over the regulators. They will
function as an independent entity with the government supporting with resources
alone.
Companies are obliged to follow rules imposed by the regulators and will face
penalization failing to do so.
Network operators should report directly to the regulators
Cooperation among national regulators to improve cross border interactions
b. Regulation on Market Integrity and Transparency (REMIT)
The REMIT defines an outline to identify manipulation of market and punishing offenders.
The participants are mandated to report their trading to ACER [60].
c. Agency for Cooperation of Energy Regulators (ACER)
The European Union Agency for the Cooperation of Energy Regulators (ACER) was a part
of the legislation of Third Energy Package. It is a decentralized agency purposed with
achieving energy system transition and benefit from market integration across Europe. It
also attempts to deliver low carbon gases at low costs. By offering more choices and a
competitive market, the agency ensures security of energy supply. ACER also oversees
transparency and limits abusers, thus guaranteeing reasonable energy prices. [61]
d. Unbundling
Unbundling means no one can have control over the entire value chain. This implies that
companies involved in production can have no say over the TSOs or DSOs and vice versa
applies. The reason behind unbundling is to prevent unfair advantage to a single entity, which
may prevent competitor’s access to network. Unbundling imposes itself in one of three ways
depending upon the Member country:
Independent System Operators: Formally owned by producers, the system now
will act independently on all fronts- Operation, Maintenance, Grid Investments
etc.
Ownership Unbundling: No producers can hold major shares in TSOs
Independent TSOs: Ownership may be under energy company but must be
through a subsidiary and decisions should be independent of the parent company
e. Projects of Common Interest (PCIs) & Third Party Access
Projects of Common Interests are major cross border infrastructure projects that connect
gas and electricity systems in EU. National TSOs ensures safe and secure supply of energy
through pipelines across Member states. In order to guarantee ideal management, the
operators, controlled by European Network for Transmission System Operators for Gas
(ENTSO-G), across borders come together. The ENTSO-G are responsible for developing
codes and rules for the flow of gas. They are also in charge of the investments and the
monitoring developments.
Third Party Access is applicable to TSOs and storage operators. The third directive Article
13 states, “All transmission, storage and LNG system operators must “operate, maintain and develop
under economic conditions secure, reliable and efficient” facilities; and “refrain from discriminating between
system users or classes of system users, particularly in favour of its related undertakings”.
The TEN-E Regulation
The TEN-E Regulation enabled cross-border energy flow and planning of infrastructure.
Through PCIs, stakeholders and Member States came together to strengthen energy
networks and connect isolated regions. It also aids in reinforcing prevalent interconnections
and promote integration renewable energy. The Commission has however looked to revise
the TEN E regulation to be able to fit in the European Green Deal. Under the revised
version, PCI status is to be voided for natural gas and oil pipelines to promote low carbon
gases and decrease dependence on fossil fuels. [62]
3.2.3 Preliminary Conclusions of the Author
The current policies and regulations have extensively worked in establishing a medium to
reduce GHGs in EU but do not have particular decarbonization strategy for Gas. In order
to achieve its targets, all energy related emissions must be slashed, especially in the heat,
electricity, industry and transport sector. The core idea should be to reduce the dependence
on fossil fuels, more importantly gas. The key areas of action and the main barriers will be
identified in the coming chapters.
Policy makers should focus on these constraints when developing a framework for gas sector
decarbonization. Determining the tradeoffs and the importance of proper regulations will
shape the future of gas in Europe.
3.3 Hydrogen Production Methods: A review
As deliberated in the previous chapter, the chosen hydrogen production technologies are
Steam Methane reforming and Electrolysis of water. This section aims to give a concise
information on the topic along with existing literature on production cost estimation.
Steam Methane Reforming
Hydrogen is produced on a large scale via natural gas reforming. Methane reacts with steam
as shown in the reactions below, to produce a hydrogen-rich syngas. The schematic
representation of the process is a shown in the Figure 15. The long chain hydrocarbons are
broken down with the mixture of the feedstock and steam, (known as preforming), resulting
in methane and syngas. The methane obtained is further decomposed to obtain Hydrogen
and Carbon Monoxide. The process needs external heat and thus is endothermic (ΔHr= 206
kJ/mol). The heat is usually a furnace which can be an arc furnace powered by renewable
electricity, thus reducing the carbon footprint. Carbon monoxide is further reacted with
water to have higher yields of Hydrogen and carbon dioxide [63].
CH4 + H2O → 3H2 + CO
CO + H2O → CO2 + H2
Figure 15 Hydrogen production via SMR with CO2 capture (CCS) [63]
The carbon dioxide by product can be successfully captured and stored for future use and is
known to have profound effect in reducing the carbon impact of reforming process.
Hydrogen production by SMR are either centralized and distributed to in gaseous or liquid
form or be decentralized, where it is stored in the same location as production.
The IEA GHG report on Hydrogen Production [64] details about possible Carbon capture
locations in the SMR plant and the following are used in this thesis as well:
a. Shifted Syngas
b. Pressure Swing Adsorption Tail gas
c. SMR flue gas with MDEA or MEA
Methyldiethanolamine (MDEA) and Methylenedianiline (MEA) are compounds commonly
used in amine gas treating, a process commonly used in sweeting of natural gas to remove
hydrogen sulfide (H2S) and carbon dioxide (CO2) [64]. The CO2 capture using CCS in SMR
is an established technology and can often be found in many commercial scale SMR plants
[64]. Thus, it is a very good technology to rely on for at least the next ten years and be used
as a bridge until green hydrogen can take over.
Simpson, was one of the first to evaluate SMR based on waste, efficiencies and a specific
emphasis on flow of energy [65]. Various authors including Barelli, Antzara, Izquierdo etc.
discussed SMR in detail and its effectiveness [66] [67] [68]. Boyano performed an
exergoenvironmental analysis of SMR [69]. The results of this study show that the steam
reformer has the highest environmental impact potential among the techniques discussed.
Gangadharan et al, has furthered the research and included dry reforming to further reduce
the carbon footprint, enabling decarbonization of the gas industry [70]. SMR combined with
carbon capture was a topic of interest since the turn of the century. John C. Molburg and
Richard D. Doctor investigated the deployment of CO2 capture technologies, a researched
that included production of electricity and merchant hydrogen [71]. Rhodes et al, carried out
an economic analysis of the integration of biomass IGCC with CCS [72]. Various others have
also carried out research on hydrogen production via SMR and have gone to extent of having
a techno-economic analysis ( [73] [74] [75] [76] [77] [78] [79]).
Water Electrolysis
Much similar to SMR, Hydrogen production from water electrolysis has been the subject of
research for years. It is a promising alternative for SMR, being a renewable energy powered
Hydrogen production. It is the process of splitting water molecules in to Hydrogen and
Oxygen using high volt electricity. The setup is known as an electrolyzer and can have a small
range enough to produce on small scale to centralized production capacities that are linked
with renewable electricity production.
Figure 16 Working of an Electrolyzer [80]
Like the fuel cell, the electrolyzer is made up of cathode and anode with an electrolyte in
between [80]. The following are the most used electrolyzers:
a. Polymer Electrolyte Membrane (PEM): The electrolyte is basically a
special plastic membrane. The reaction occurs at the anode to produce
Oxygen and H+ ions. Flowing through the membrane, the protons reach the
cathode to combine with electrons to form H2 gas.
Anode: 2H2O → O2 + 4H+ + 4e-
Cathode: 4H+ + 4e- → 2H2
b. Alkaline Water Electrolyzers (ALK): Transporting the OH- ions through
the electrolyte, which is either Sodium Hydroxide or Potassium Hydroxide.
This also produces hydrogen at the Cathode.
c. Solid Oxide Electrolyzer Cell (SOEC): This uses a ceramic material as the
electrolyte and thus the name. It operates a little different manner compared
to the previous two. Water at cathode forms hydrogen combining with
electrons from the external circuit, obtained from the anode upon reaction
of O-2 to form Oxygen gas.
SOEC need higher temperature of the range 700-800°C whereas the PEM and ALK can
operate under 150°C. However this also an advantage for SOEC as the heat ensures
effectiveness in Hydrogen production and thus reducing electricity consumption [80].
Research continues to push the efficiencies of the electrolyzer while the following literatures
have covered the different electrolyzers in detail. Muller-Langer co-authored a techno
economic study of hydrogen production for the hydrogen economy [81]. In their paper, they
conclude water electrolysis costs primary and exponentially vary based on electricity price
and efficiency. Lemus updated on the existing studies and performed a parity analysis of cost
from renewable and conventional technologies [82]. Acar, Fino, Dincer Nikolaidis, and
Dagdougui have also researched comparative studies of hydrogen production methods [83]
[84] [85] [86] [87] . Pertaining to individual technology study, Shiva Kumar et al, reviewed
hydrogen production by PEM [88]. Li et al. and Lee et al have done potential and sensitivity
analysis, particular to Japan and Korea, respectively, while Pilar wrote specifically on offshore
facilities for hydrogen production [89] et [90]. Shaner et al and Sadegi et al covered solar
specific production [91] [92].
Relating to lifecycle assessment, Vitorsson et al and Khzouz et al are one of the recent
authors [93] [94] . The thesis will base its model and its calculations based on their
studies. Christensen broadened the research scope to cover EU and USA as well [95].
Nonetheless, the extent and the cost of hydrogen production from different methods in
Portugal is yet to be analyzed scientifically and thus the reason for this study. Assumptions
and data are taken from the rich literatures and data from IEA and EU commission. The
ensuing chapter on methodology clearly explains the steps involved in the thesis, the sources
of information, assumptions and the calculations.
4. Methods and Materials
4.1 Study Area
The thesis will be limited to EU policies & regulations, and aims to provide the results based
on them. The idea is to evaluate how the EU policies affect the strategy in Europe and a
special case study in Portugal. The hydrogen production costs are to be estimated in the
context of Portuguese energy sector. The technologies evaluated are SMR and electrolyzers
and their Well to Tank/Plant emissions are taken into consideration. This means the
emissions from the production due to natural gas or production of electricity is considered
for the sake of simplicity. A simple flowchart of the thesis is as follows
Figure 17 Boundaries of the Thesis
Figure 17 presents a methodological approach used in this study. Primarily a review of
literature is done followed by a close inspection of the policies and regulations. The barriers
identified in the process were then included in the survey sent out for expert validation.
Based on the response, a SWOT-PESTEL analysis is employed. Simultaneously, the case
study of hydrogen production in Portugal is performed, limiting to only costs from
production and technologically limited to SMR and Electrolyzers. The following subsections
will detail about the methodological steps involved.
4.2 Research Design
This section of the study focuses on the constraints involving the decarbonization of the
natural gas system. It comprises of a review of Policies, NECPs, regulations and other
relevant national documents, in order to identify main references to Natural gas, low carbon
gases and hydrogen, production and role of gas in the system and end use applications. The
main sources of data and information are Hydrogen Europe, FCH JU, the European Union
and the national regulatory sites as discussed previously in section 3.2. While the intention is
to provide accurate summary of existing planned developments, regulations and policies, it
is likely that the overview may not include publically unavailable documents.
The research is an explanatory study that seeks to explain how policies and regulatory
framework particular to the natural gas sector will affect the impending decarbonization of
the sector by comparing the immediate impacts of the legislatures in different locations
mentioned above. The hypothesis is that the frameworks are a hindrance for the inclusion
of renewable methane and hydrogen in the natural gas mix. This involves a combined SWOT
and PESTEL analysis. The reason for choosing this method is that it is an exploratory and
descriptive study predominantly used to predict cause and effect.
4.2.1 SWOT Analysis
SWOT identifies the strengths, weaknesses, opportunities and threats of an existing or
upcoming strategy/policy or regulations. It differentiates the internal parameters i.e.,
Strengths and Weakness that the policy/strategy has by itself and the external parameters
that may affect the working of strategy, i.e., Threats and Opportunities [96].
Strengths: This internal factor describes the points or areas where the object in
question excels. For example, TESLA offers a zero tail pipe emissions vehicle but
what separates it from others is that it offers supercharging and range.
Weaknesses: These internal factors prohibit the full utilization of potential. They
are areas where the policy or regulation needs to improve to remain effective.
Opportunities: They are external factors referring to those that will boost the
effectiveness if given proper attention to.
Threats: They refer to factors that have the capacity to derail the intended action.
A typical SWOT analysis is presented as a square, divided in to four equal quadrants, each
representing one of the factors. This arrangement helps easier visualization and it looks like
in figure below
Figure 18 SWOT Analysis [96]
However, like every pathway, questions loom over the method on its merits and demerits.
The advantages include the ease of use of the method and the simplicity of results. The
shortcomings, however, also refers to its simplicity and the fact that the results are subjective.
[97] The SWOT analysis also includes TWOS mapping which maps the strengths and
weakness to the opportunities and threats and formulates the following strategies:
S-O strategy to use strength to take advantage of opportunities
S-T strategy to use strengths to tackle the external threats
W-O strategy to overcome the internal weakness to maximize opportunities &
W-T strategy to format a plan to make the weakness more resistant to the threats
4.2.2 PESTEL Analysis
PESTEL or PESTLE analysis is a tool predominantly used to monitor and evaluate the
macro economic factors that may influence the performance of a policy, a regulation or an
organization. The PESTEL framework is an analysis merging six macro-economic factors,
namely:
Political Factors: Policies, Regulations, Tariffs, Bureaucracy etc.
Economic Factors: Investment Costs, Depreciation Factors, Inflation etc.
Social Factors: Cultural perceptions, Acceptance, Awareness etc.
Technological Factors: R&D, International cooperation
Environmental Factors: Impact on environment, Climatic conditions
Legal Factors: Industry Regulations, IPR etc.
Figure 19 PESTLE Analysis [98]
The advantages include anticipation of future opportunities and threats and develops an
external and strategic thinking while the demerits are over simplification of data and
unproven assumptions [99].
The following authors have previously relied on the above said methods. Fozer, Fertel,
Zalengera Srdjevic and Kamran are few authors to use PESTEL method to evaluate the
impacts of renewable energy, biofuel industry and similar topics of relevance to this study
[100] [101] [102] [103] & [104].
A SWOT-PEST analysis helps in differentiating the internal and external agents of the
constraints. The reason for combining SWOT and PEST analysis is to complement the
controllable internal factors from SWOT and the external predefined factors from PEST
This method has profound usage in environmental policy analysis like in the works of
Nikolaou, Igliński, Yuan and more recently AnnaKowalska-Pyzalska [105], [106], [107],
[108].
4.2.3 Expert Elicitation
To understand the constraints from an expert point of view, the study employs a survey. An
expert elicitation is a scientific consensus method that collects an educated guess although
the demerits include uncertainty that arise from qualitative vocabulary. This methodology
has been adapted previously in studies that require an evaluation of data when it is limited
and subjective. For instance, James et al used expert elicitation to evaluate a tool formulated
for regression in ecology [109]. Similarly, Knol et al assessed environmental health impacts
using the same method as they dealt with uncertainties [110]. Particular to energy and
renewables, several authors have used this methodology whenever there was ambiguities
[111] [112] & [113].
Figure 20 Systematic methodology of the survey
The systematic methodology used in expert elicitation can be seen in figure 20. Upon
identification of the barriers, the next step was to compile the survey and identify the experts.
The survey used is both subjective and numeric, where the respondents answers a wide range
of question, half of which expects a qualitative response and the other half requests a scaling
of 1-5. The survey was sent out to experts in the field of decarbonization including
researchers, industrial experts from TSOs and DSOs, consultants who have worked on
studies based on decarbonization and members of Hydrogen council etc. They are also asked
to rate the importance of stakeholders, governmental action, researchers and individual
citizen in decarbonization of the natural gas sector. The full questionnaire is available in the
link below. 1
1 https://forms.office.com/r/XGzgAjDXtq
4.3 Levelized Cost of Hydrogen Production (LCOH) for
Different Production Systems (SMR+ CCS and Electrolysis)
The purpose of this analysis is to calculate the levelized costs of blue hydrogen and green
hydrogen, both unsubsidized. The study evaluates the costs for the years 2020, 2030 and
2050, based on data availability.
The methods of production taken into consideration are (figure 21):
Steam Methane Reforming (with and without CCUS)
Water Electrolysis (Grid vs Wind vs Solar)
a. Polymer Electrolyte Membrane (PEM)
b. Alkaline Water Electrolysis (ALK)
c. Solid Oxide Electrolyzer Cell (SOEC)
Figure 21 Schematic overview of production methods
The calculation of unit hydrogen production cost includes capital costs and operating costs
associated with SMR+ CCS and Electrolysis of water based on grid connectivity and 100%
RES production. Capital costs takes account of H2 production equipment, storage,
compressor, dispenser, construction, and supplement, operating costs consist of labor,
maintenance, other operating cost, while the variable costs include fuel and feed stock costs.
In addition, sensitivity analysis using a statistical approach can provide a parameter for
economic evaluations and enumerate risks of underdeveloped and nascent technologies. This
study uses, among various available methods, a simple analysis with method to consider
unpredictable factors such as the fuel costs, capacity factor in case of renewables etc. Unlike
the typical uncertainty analysis, which applies randomly assigned parameters, the study
applies select individual parameters to understand the uncertainties.
Source of Power/Fuel
Production Method
H2
Hydrogen
1. PEM
2. ALK
3. SOEC
GRID Connected
Electricity from Wind
Electricity from Solar
1. SMR
2. SMR with CCS
Natural Gas
Figure 22 Hydrogen Production Costs – Methodology
Figure 22 represents the proposed methodology involved in this cost model structure and
strategy for hydrogen cost analysis. The framework includes sensitivity analysis of feedstock
price and capacity of hydrogen production among other parameters. Both technical and
economical parameters are included.
Levelized Cost of Hydrogen (LCOH)
The formula used for the LCOH is adapted from the Levelized cost of energy (LCOE)
method, which has profound usage in the energy sector, renewable in particular. It is the
ratio of lifetime costs to lifetime energy generation, annualized with the help of discount rate
based on capital investments. According to IRENA [114],
𝐿𝐶𝑂𝐸 =
∑ (𝐼𝑛 + 𝐹𝑛 + 𝑉𝑛) ∗ (1 + 𝑖)−𝑛𝑁𝑛=1
∑ 𝐸𝑛 ∗ (1 + 𝑖)−𝑛𝑁𝑛=1
(1)
Where: 𝐼𝑛 is the investment cost in the year n, 𝐹𝑛 is the fixed OPEX in the year n, 𝑉𝑛 is the
variable OPEX for the year n, 𝐸𝑛 is the produced energy in the year n, 𝑁 the lifetime and 𝑖
is the discount rate. Refer to table 5 for equations related to𝐹𝑛, 𝐸𝑛 & 𝑉𝑛.
This method of cost evaluation adapted from Vicktorson´s paper [93] while the LCOE from
IRENA; however it can further extended to hydrogen as well. Hydrogen output measured
in terms of energy or kilograms produced is equitable to the cost and presented in terms of
cost per unit mass of hydrogen.
The following equations govern the annualized CAPEX, OEPX and variable costs
𝐼𝑎,𝑛 = 𝐼𝑛 ∗ 𝐶𝑅𝐹 = (𝐶𝑒 + 𝐶𝑑 + 𝐶𝑐 + 𝐶𝑚𝑖𝑠𝑐 + ⋯ ) ∗ 𝐶𝑅𝐹 (2)
Where Ce is the electrolyzer CAPEX; Cd is the dispenser CAPEX; Cc is the compressor
CAPEX and CRF is the Capital Recovery Factor and is equal to
𝐶𝑅𝐹 =
𝑖(1 + 𝑖)𝑛
(1 + 𝑖)𝑛 − 1 (3)
The Fixed OPEX is calculated as a percentage of the total CAPEX and will be assumed
based on production method. The Variable OPEX, which includes the fuel and water costs,
is given by:
𝑉𝑎 = 𝐶𝑒 + 𝐶𝑤 + 𝐶𝑛 (4)
Here 𝐶𝑒 , 𝐶𝑤 & 𝐶𝑛 are the electricity costs, water costs and natural gas costs. The equation
below denotes the calculation of total annual costs:
𝐶𝑎 = 𝐼𝑎,𝑛 + 𝐹𝑎,𝑛 + 𝑉𝑎,𝑛 (5)
Where Ca, , Ia,n, Fa,n & Va,n are the total annual costs, annualized investment costs, annual fixed
OPEX and the Variable costs in Euros/year. The annual hydrogen is estimated in kWh/year
or kg/year and is calculated as given in Table 5. The LCOH is assessed by dividing the annual
costs by the annual hydrogen production 𝐸𝐻2𝑎 (kg/year):
𝐿𝐶𝑂𝐻 =
𝐶𝑎
𝐸𝐻2𝑎 (6)
4.4 Definitions, Assumptions and Calculation
The objective of this section is to brief about the costs, the assumptions involved and the
data sources used for calculating the LCOH from the different said methods of hydrogen
production.
4.4.1 Costs
1. CAPEX or Investment Costs
Capital Expense or Investment cost in this study will look to include all the cost involved
and is inclusive of the electrolyzer costs, dispenser costs, and compressor costs or
combined as “Production Unit CAPEX”, integration cost and the balance of costs as
reported by the European Commission. The cost components for SMR include that of
direct materials, construction and EPC services. The components of the Carbon capture
and storage costs include just the costs of the CCS installation in existing plants. It should
also be noted that the efficiency data is represented in Lower Heating Value, as it is
conventional and used for comparison of fuels.
The table below is used as the main data source assumed in this study. The table consists
of the following: Technologies of hydrogen production, namely Alkaline Water
Electrolyzer (ALK), Polymer Electrolyte Membrane (PEM), Solid Oxide Electrolyzer
(SOEC) and Steam Methane Reforming (SMR) with and without Carbon Capture and
Storage (CCS). In the case of SMR with CCS, the following cases were analyzed:
a) SMR WITH CCS: syngas MDEA
b) SMR WITH CCS: syngas MDEA 2
c) SMR WITH CCS: PSA tail gas MDEA
d) SMR WITH CCS: flue gas MEA
Where, MDEA is Methyldiethanolamine, MEA is Methylenedianiline and PSA is
Pressure Swing Adsorption.
The year column in Table 2 represents the data from various sources for the same
particular year. For example, refereeing to the table, in the year 2020 for ALK, the data
from IEA indicates that the minimum investment cost would be 0.628 Million € per MW
of H2. The efficiency ranges between 0.52 for PEM in 2020 to 0.9 for SOEC in 2050.
Here the minimum and maximum costs indicate the overall minimum/ maximum
investment costs for the technology in the year as indicated. The increase in efficiency
and decrease in investments cost would directly affect the LCOH, which is discussed in
the results section in detail.
Table 2 Investment Costs and Efficiency of Hydrogen Production Technologies [37]
Technology Year Min Investment cost (million EUR/MWH2)
Max Investment cost (million EUR/MWH2)
Min Efficiency (LHV of Hydrogen)
Max Efficiency (LHV of Hydrogen)
Sources as indicated in EU commission report
Green - Alkaline
electrolyzer (ALK)
2020 0.628 1.955 0.63 0.7 (IEA, 2019)
2020 0.444 0.947 0.63 0.68 (H21 NoE, 2018)
2020 1.395 1.395 0.51 0.51 (IRENA, 2018)
2020 1.158 2.837 0.49 0.69 (Schmidt, 2017)
2030 0.496 1.151 0.65 0.71 (IEA, 2019)
2030 0.361 0.74 0.68 0.69 (Hydrogen Europe, 2020)
2030 0.7 0.7 0.65 0.65 (IRENA, 2018)
2030 0.736 1.531 0.52 0.73 (Schmidt, 2017)
2050 0.22 0.88 0.7 0.8 (IEA, 2019)
2050 0.289 0.289 0.69 0.69 (Hydrogen Europe, 2020)
Green - Polymer
Electrolyte Membrane electrolyzer
(PEM)
2020 1.613 2.828 0.56 0.6 (IEA, 2019)
2020 1.997 1.997 0.57 0.57 (IRENA, 2018)
2020 1.474 3.402 0.55 0.63 (JRC, 2019)
2020 1.266 3.596 0.52 0.63 (Schmidt, 2017)
2030 0.841 2.095 0.63 0.68 (IEA, 2019)
2030 1.037 1.037 0.64 0.64 (IRENA, 2018)
2030 0.998 2.457 0.59 0.68 (JRC, 2019)
2030 0.772 2.739 0.52 0.69 (Schmidt, 2017)
Green - Solid Oxide
Electrolyzer (SOEC)
2020 3.041 6.658 0.74 0.81 (IEA, 2019)
2020 1.066 1.066 0.76 0.76 (JRC, 2019)
2020 2.132 3.664 0.8 0.8 (Schmidt, 2017)
2030 0.838 3.199 0.77 0.84 (IEA, 2019)
2030 0.582 0.582 0.8 0.8 (JRC, 2019)
2030 0.799 3.331 0.8 0.8 (Schmidt, 2017)
2050 0.489 1.143 0.77 0.9 (IEA, 2019)
2050 0.388 0.388 0.8 0.8 (JRC, 2019)
CCS for existing SMR
plant 2020 0.701 0.701 N/A N/A
(Jakobsen & Åtland, 2016)
Blue - New Steam
Methane Reforming
(SMR) plant & CCS
2020 1.65 1.65 N/A N/A (Jakobsen & Åtland, 2016)
2020 0.963 0.963 N/A N/A (ASSET, 2018)
2020 1.594 1.594 0.69 0.69 (IEA, 2019)
2020 0.792 1.408 N/A N/A (IEA, 2019)
2030 0.909 0.909 N/A N/A (ASSET, 2018)
2030 1.29 1.29 0.69 0.69 (IEA, 2019)
2050 0.856 0.856 N/A N/A (ASSET, 2018)
2. Fixed OPEX
The Fixed OPEX involves the costs of Labor, Maintenance, Plant operation and other
related costs such as administration costs and in some cases chemical & catalysts cost,
replacement costs etc. Following Adam Christensen’s work [95], Fixed OPEX per year
is assumed 1.5% of the overall CAPEX of the project for Electrolyzers and 3.5% for
SMR. Similarly, Catalyst & Chemicals cost is assumed as .2% of the CAPEX.
Replacement costs are more expensive and taken as 20% of the CAPEX and then
annualized as in equation 2.
3. Variable OPEX:
Variable OPEX consists of the fuel (Natural Gas and electricity) costs (Taxes Omitted),
feedstock costs, and water costs as in table 3. The values are for Portugal and based on
data from Portugal Database and Eurostat [115]. The sources of electricity are the current
grid of Portugal and also electricity from Solar PV farms and Wind farms.
Table 3 Fuel and Water price
Cost of Value
Natural gas 0.0263 €/kWh
Electricity
Grid 0.074 €/kWh
Wind 0.09 €/kWh
Solar 0.02 €/kWh
Water 1.8818 €/m³
4.4.2 Assumptions and Data Sources
The following were assumptions based on literatures, reports from established organizations,
data from government of Portugal and the EU, manufacturers of electrolyzers and other
pertaining documents from the web.
1. Capacity of the Hydrogen Production:
The capacity of each method was decided based on the biggest single electrolyzers
available in the market. For SMR, it was adapted from the IEA GHG study on
emissions from SMR. The following are the capacity in MW and their sources:
i) PEM: 3 MW H2 Out at Lower Heating Value (LHV) [116]
ii) ALK: 13 MW H2 Out at Lower Heating Value (LHV) [116]
iii) SOEC: 2.5 MW H2 Out at Lower Heating Value (LHV) [117]
iv) SMR: 300 MW H2 Out at Lower Heating Value (LHV) [64]
2. Discount Rate: 6% [93]
3. Lifetime of the plant:
i) For Electrolyzers: 20 years [93]
ii) For SMR: 25 years [64]
4. Capacity Factor:
i) Electrolyzer:
(1) GRID: 80% Lower limit, Assumed [93]
(2) WIND: 30% Upper Limit, Assumed [37]
(3) SOLAR: 20% Upper Limit, Assumed [37]
ii) SMR: 95 % [64]
5. Fixed OPEX:
i) For Electrolyzers: 1.5% of CAPEX [93]
ii) For SMR: 3% of CAPEX [64]
6. Replacement and Chemical Costs: Annualized REPEX
i) For Electrolyzers: 20% of CAPEX per replacement [95]
ii) For SMR: 3% of CAPEX [64]
7. Electrolyzer Lifetime:
Electrolyzer lifetime is the lifetime until which the stack of electrolyzers will run (in
hours). The reason of inclusion is because it has been often estimated that the stack
cost constitutes up to 20% of the initial CAPEX [95]. The idea behind calculating
the number of replacements is evaluating the number of years before replacement to
the lifetime of the plant. The years before replacement is obtained by equating the
lifetime, from Table 4 to the total number of running hours per year as an integer.
Table 4 Electrolyzer Lifetime [37]
Method Year Stack Lifetime (Hours)
Min Max
Alkaline (ALK)
2020 50000 90000
2030 72500 100000
2050 100000 150000
PEM
2020 30000 90000
2030 60000 90000
2050 100000 150000
Solid Oxide (SOEC)
2020 10000 30000
2030 40000 60000
2050 75000 100000
8. CO2 Emissions:
i) For Electrolyzers (Emissions from GRID) : 213 gCO2/kWh of electricity [38]
ii) For SMR (Process Emission): 890 gCO2/Nm3 H2 [118]
9. CO2 Emissions:
i) Portuguese Carbon Tax Rate: 23.77 €/tCO2 [119]
ii) Swedish Carbon Tax Rate: 108.910 €/tCO2 [119]
4.4.3 Calculation of Costs
This section is to give a brief idea behind the calculation of the levelized cost of hydrogen.
The table 5 describes the formula used apart from the ones mentioned in the previous
sections. Here i is the discount rate, n is the lifetime of the plant. CRF is first calculated using
the formula mentioned above. Then the investment cost is determined using the capacity
factor and the data from Table 2. It is then annualized using the formula in Equation 2 in
section 4.3. Similarly, OPEX and REPEX are calculated. The production related values are
then estimated based on the assumptions as stated.
Table 5 Parameters and formula used
Parameter Formula
Capital Recovery Factor (i(1 + i)^n)/(((1 + i)^n - 1))
Full Load Running Hours per year
365*24*Capacity Factor
Number of replacements Lifetime /Years before Replacements
Electricity Consumption per year
Hydrogen Produced per year (kWh) /efficiency
Water Consumption per year Water Consumption (Volumetric)*Full Load Hours
Hydrogen Produced per year (kWh)
Hydrogen Produced per year (kg) * LHV
Hydrogen Produced per year(kg)
Hydrogen Produced per year (Nm³) * Density
Hydrogen Produced per year (Nm³)
Hydrogen Production capacity*Full Load Hours
Investment Costs (Mil Euro) Investment cost (EUR/MW)*Capacity (MW H2)
Annualized CAPEX (Euro) Investment cost*CRF
Fixed OPEX (Euro) Invest Costs*OPEX Percentage
REPEX per Replacement (Euro)
Invest Costs*REPEX Percentage
Annualized REPEX (Euro) REPEX per Replacement* CRF
Annual Electricity Costs (Euro) Electricity Consumption per year *Electricity Price
Annual Natural Gas Costs (Euro)
Natural Gas Consumption per year *Gas Price
Annual Water Costs (Euro) Water Consumption per year *Water Price
Total Costs Annualized CAPEX+ Fixed OPEX+ Annualized REPEX + Electricity Cost + Water costs
LCOH Total Costs per year/Kilogram of Hydrogen produced per year
The number of replacements can be determined by equating the total running hours and the
lifetime of the electrolyzers. Other costs like the cost of electricity and water are then
evaluated using simple mathematical equation of the total consumption times the price of
fuel or water. Total costs is a summation of the CAPEX and OPEX (Fixed, REPEX and
Fuel Costs). The LCOH is then determined by dividing the total costs by the total hydrogen
produced in the year in kg. The CO2 emissions and the carbon tax are implied using the
Portuguese grid emissions in the case of electrolyzers and the generalized emissions from
SMR. The carbon tax is taken for Portugal obviously but also includes Sweden as they have
the highest tax on carbon in Europe as of 2020 [119].
The following table is the calculation for the Steam Methane Reforming plant. The sample
taken is for the costs of production from SMR. The capacity is taken as 300MW, adopted
from IEA GHG study [69]. This roughly translates to 100,000 Nm³/h of hydrogen. The
capacity factor is assumed 95% and the lifetime of the plant is 25 years. The capital recovery
factor is calculated using the formula in Equation 3. The discount rate is 6% (assumed based
on typical rates for energy EPC). The assumed values are later varied in the sensitivity analysis
along with the capacity factor, production capacity, Natural gas price and the investment
costs.
Table 6 Steam Methane Reforming: Calculated Costs
Basic Data Symbol Value Units
Capacity c 300.00 MW H2
Hydrogen Production capacity v 100,000.00 Nm³/h
Energy Content en 0.75 kWhH2/kWhn
Efficiency η 0.95 Electricity Production PE 11.00 MW
Electricity Consumption for plant operation CE 3.00 MW
Capacity Factor (based on feedstock availability) CF 0.95 Full Load Running Hours per year h 8,322.00 hours
Lower heating value l 33.33 kWh/kg H2
Density d 0.09 kg/Nm³
Discount Rates i 0.06 Lifetime n 25.00 years
CRF a 0.078226718 OPEX % (excluding Fuel costs) o 3.5% Chemical and Catalyst Costs c&c 0.2% Consumption and Production Values Symbol Value Units
Natural Gas Consumption per year N- 3,461,169,872.16 kWhn/year
Electricity Produced per year E+ 91,542,000.00 kWhe/year
Electricity Consumption per year E- 24,966,000.00 kWhe/year
Water Consumption per year W- 495,683.29 m³/year
Water Consumption (Volumetric) WV 0.01 m³/kg H2
Water Consumption (Weight) WK 6.70 kg/kg H2
Hydrogen Produced per year (kWh) EH2 2,466,083,533.91 kWhH2/year
Hydrogen Produced per year(kg) KH2 73,982,580.00 kg/year
Hydrogen Produced per year (Nm³) VH2 832,200,000.00 Nm³/year
Carbon Emissions per Nm³ H2 CO2 0.81 kg/Nm³
Economic boundary conditions Symbol Value Units
Natural gas Costs Nc 91,028,767.64 €/year
Electricity Revenue Er 6,774,108.00 €/year
Electricity Costs Ec 1,847,484.00 €/year
Water costs Wc 99,136.66 €/year
Natural Gas Price Pn 0.0263 €/kWh
Electricity Price Pe 0.074 €/kWh
Water Price Pw 0.20 €/m³
Annual Costs Symbol Value Units
Initial Investment cost min im 0.36 M€/MWH2
Initial Investment cost max i 0.74 M€/MWH2
Initial Investment cost min € Im 108.00 M€
Initial Investment cost max € I 222.00 M€
Annualized CAPEX min CAPm 8,448,485.57 €/year
Annualized CAPEX max CAP 17,366,331.44 €/year
Fixed OPEX min FOPm 3,780,000.00 €/year
Fixed OPEX max FOP 7,770,000.00 €/year
Fuel Costs FC 92,876,251.64 €/year
Water costs WC 99,136.66 €/year
Revenues R 6,774,108.00 €/year
Chemical and Catalyst Costs min C&Cm 216,000.00 €/year
Chemical and Catalyst Costs max C&C 444,000.00 €/year
Total Annual Costs min Tm 98,645,765.86 €/year
Total Annual Costs max T 111,781,611.74 €/year
The values obtained in the table is the base for the LCOH calculation. The minimum and
maximum value is due to the varying factor of the investment costs as seen in Table 2. The
reason is due to fluctuating factors of the capital costs such as the EPC services costs or the
material costs. Similarly, LCOH is calculated for every alternatives that has been described:
Steam Methane Reforming with CCS and its types (Refer chapter) and Electrolyzers (PEM,
ALK and SOEC). The following chapter elaborates the results.
5. Results
5.1 Constraints to Decarbonization
The barriers and restrictions identified from the policies, regulations and other literature
(refer to Section 3.1) are classified in four major criteria: Political Barriers, Economic Barriers,
Social Barriers and Technological Barriers (includes Technical & Operational). The survey
had 18 respondents in total. The following figures (23- 26) represent a web chart that reports
the average response to a barrier.
5.1.1 Compilation of the Barriers
Barriers related to political aspects of Policies and Regulations
A single European market based on interconnections between Member States creates an
unnecessary additional financial burden if such infrastructure is mandated. As of now, there
is no regulation or EU level funding for the same. In addition, the current EU framework is
highly detailed preventing Member States from developing approaches that suits their
economies best. The overall target plays an important role in country’s NECP. Regulatory
uncertainty delays investment and a lack of clarity will make stakeholders to hesitate in taking
decisions.
Over the years, regulators have discouraged long-term contracts to prevent market
foreclosure but for a developing market, it is way of risk sharing. Moreover, unbundling rules
limits possibility of vertical integration of the value chain, another necessity for risk
management in developing markets. Likewise, the current decarbonization framework does
not incentivize supply or create demand for low carbon gases. Most of the time, it is the case
of Chicken and Egg: Without demand, suppliers will hesitate and without ensured supply,
customers will not choose low carbon gases. The policies do not necessarily incentivize low
carbon gases in particular.
As far as the environmental point of view goes, emissions from Natural Gas are controlled
differently for industries (EU ETS) and residential/commercial setting (NECPs). A different
tool for same network will complicate decarbonization strategies. It is also noted that
electrification pathway is more attractive as it is simpler unlike gas decarbonization. As such,
the value chain remains the same for electrification while needs changes in case of gas.
The survey results is presented along with some insights shared by the experts. Majority
had prioritized the following policy and regulation related barriers as the major threats
to decarbonization, as seen in Figure 23:
1. Delays in investments due to lack of clarity in regulations
2. The case of Chicken and Egg: Demand Supply clashes
3. The lack of incentives in the current framework
The following figure represents the results from the survey as a radar chart while the table
consists of the individual opinion shared by the respondents.
Figure 23 Political Barriers
Table 7 Expert´s opinion: Political and Regulatory Barriers
Name Comments
Anonymous
Respondent 1
The political focus on maximizing the shift of as many economical sectors as
possible to electricity as the main decarbonization vector of energy end
consumption. The electricity sector itself is the obvious entrance door to
decarbonization efforts, but there must be a better understanding about the
role of gas in that process. Even as the EU gives a clear push towards the
introduction of green and blue hydrogen into the equation, additional
measures at fiscal level are required to encourage industry to adopt this
solution. We are also in the early stages of the discussion of how to adapt
existing regulation and which new regulatory measures are needed to
accommodate the introduction of renewable and decarbonized gases in the
energy mix.
Anonymous
Respondent 2
"Lack of predictable/stable regulatory framework
Anonymous
Respondent 3
Conflicting policy objectives
Anonymous
Respondent 4
Lack of adequate pricing scheme for CO2-emissions"
Anonymous
Respondent 5
I think the major threat is the Electrification lobby
Anonymous
Respondent 6
Natural gas taxation and incentives, policy towards electrification and current
incentives to upgrade appliances namely in domestic towards electrical
demand, absence or inadequacy of current regulatory framework for non
domestic users of natural gas.
Anonymous
Respondent 7
Policies are needed to drive the demand and supply of renewable and low-
carbon gases (see our Gas for Climate reports), and to enable infrastructure
(e.g. anticipatory investments) and markets for those.
Anonymous
Respondent 8
The major influence of the Oil industry and the hypocrisy of the politicians
that still give subventions to the carbon industry and do not have the courage
and money to give subventions to what matters. The unbalanced value of
taxes paid by the citizens against the taxes paid by the big fortunes and
companies is also in my opinion of the biggest barriers that don't enable to be
stronger in the adequate politics (not enough public money)
Anonymous
Respondent 9
The major threats are the following. This does not mean that policymakers are
not taking measures to address those: - A lack of policy signals providing
certainty to market and regulated actors to pursue decarbonization measures -
A risk of sustainability impacts not being adequately considered and the
regulatory framework allowing lock-in in fossil gas use for decades to come -
An uneven playing field for different technologies, gas types and end-uses,
with value chain (especially methane leakages) not being adequately
considered
Note that the number next to respondents are not necessarily in the order of responses and is not the same for the following
tables as well. Since the opinions were optional, the responses are not necessarily from the same set of respondents.
Although some opted to be named, for the sake of future where opinions are subject to change, the thesis would not want to
hold responsible for any such changes and thus prefer not to name any.
Barriers related to Economic aspects of Policies and Regulations
Primarily is the hurdle of the cost of production; Hydrogen production, especially Green
hydrogen is expensive and thus will not be preferred first option for customers.
Infrastructure development costs also plays an important role. The pipelines needs
refurbishing at the very least and need better compressors for hydrogen and other gases.
Often overlooked, are the cost of stranded assets. Assets of Producers of Natural gas, TSOs
and DSOs will have stranded costs if not properly decommissioned. In addition, cost of
Natural gas vs low carbon gas & Hydrogen is not competitive. This may be due to the lack
of enough tax on carbon and thus Natural Gas continues to be the preferred option. This is
not consistent with the REMIT regulations.
For the producers, TSOs and DSOs, lack of security for their investments prevails as high
risks for investments and longer ROI. This is also due to the barrier rom previous section as
integration of value chain provides risk sharing. There is also a lack of payment and
remuneration mechanisms. For the consumers, the end user costs is still a question mark.
The need for equipment change and modification to accommodate new gases are still by
large unknown and not regulated. Moreover, the lack of incentives for uptake is a major
roadblock. Similar to points above, there are no enticement for the uptake of low carbon
gases.
The results of the survey is as follows. The top three constraints (Figure 24) as identified by the respondents are:
1. The production cost of green hydrogen 2. Cost competitiveness and 3. The lack of enough taxation on carbon emissions
Figure 24 Economic Barriers
Table 8 Expert´s opinion: Economic Barriers
Name Comments
Anonymous
Respondent 1
In most cases, the technology is at an emerging stage and therefore lacks
scale. Both factors lead to high costs that act as an effective barrier to
both investors and end consumers. The industry needs to go all the way
up the learning curve and gain scale so that costs can be brought down.
In turn, adequate incentives are required to that end
Anonymous
Respondent 2
Cost gap between natural gas and renewable or low-carbon gases is still
very high => CO2 emission price is not high enough to bridge the gap.
Most renewable electricity sources have become less expensive than
renewable gases
Anonymous
Respondent 3
Cost of production and delay when compared to Electricity.
Anonymous
Respondent 4
Incentives on demand and also regulation framework for the initial
projects
Anonymous
Respondent 5
Cost of fossil gases are lower than that of decarbonized gases
Anonymous
Respondent 6
Costs of low carbon gases versus fossil natural gas limits demand for it
Anonymous
Respondent 7
Natural gas prices are much lower than that of biogas, and hydrogen is
far more expensive. - Tax regimes don't help by not fully incorporating
the external costs into the price; - Electricity prices are still to high to
facilitate cost-efficient production of hydrogen through electrolysis; -
Carbon price is currently still too low to incentivize industries to make
radical changes in their production processes
Anonymous
Respondent 8
The barrier is the time needed to transform the energy sector in a
relatively short space of time. Energy assets have a useful life of around
50 years and we want to completely transform the sector in 30, with the
overwhelming majority of the process in 10 years (including the
development of new technologies). I think there are no barriers, the
level of the challenge is that it is very big
Barriers related to Social aspects of Policies and Regulations
Society places an important role in shaping the future, being the last but the most pivotal
player in the value chain. Therefore, it is important to understand their concerns and queries.
To start with, there is a wide spread question about energy security. The reliability of existing
natural gas has to be disturbed and hydrogen production from renewables is intermittent.
Adding to it is the much higher energy bills due to lack of competitiveness among the various
gases, the public will have to bear to some extent higher bills. Lack of awareness would
cutback the ease of decarbonization. Safety concerns especially with hydrogen needs
addressing. Impact on jobs in the sector is also often quoted as the existing jobs are displaced
due to gradual decommissioning of natural gas
Albeit unrelated to any policy or regulation, cultural mind blocks would still prove to be a
tough obstacle. Finally, the disparity in wealth affects the mentality. Higher cost of bills would
mean an easier transition for wealthy individuals than people of lower income group.
Figure 25 Social Barriers
The societal limitation that were deemed important are mostly related to lack of awareness and the costs of energy bills with Table 9 consisting of the expert’s opinion.
Table 9 Expert´s opinion: Social Barriers
Name Comments
Anonymous
Respondent 1
Usually those related to economic and social welfare aspects. Increasing
energy efficiency and minimizing energy end consumption are usually
met with mistrust and perceived as affecting economic welfare.
Anonymous
Respondent 2
Sociological aspects are to my understanding less important barriers
than the economic (competitiveness- and technological aspects
Anonymous
Respondent 3
Hydrogen fear
Anonymous
Respondent 4
The efforts of reducing emissions is commonly associated with the
electricity production, although in Portugal between electricity and gas
demand, gas is the highest and people are not aware of this energy
distribution/relative importance.
Anonymous
Respondent 5
Citizens need to become familiar with the new gases, and need to know
what the transition means for their appliances, infrastructure etc.
Barriers related to Technological aspects of Policies and Regulations
These impediments often arise due to lack of or nascence of a particular technology. In the
case of Electrolyzers, the efficiency of hydrogen production have huge potentials to be
fulfilled but currently hamper green hydrogen. Technological improvements needed in
pipelines to accommodate hydrogen and Biomethane are not defined. Changes in calorific
values requires new grades of pipelines. Storage of hydrogen is still deemed dangerous, thus
requiring technological advancements. Regulations lack in this. Moreover, like in the previous
sections, end user appliances need to be compliant to new gases. No such regulation exists
that control the appliance end of value chain.
The blurred position of permitted concentration of hydrogen in the gas grid is an operational
barrier as the blending limits are yet to be regulated. Land Use Prohibitions limits zones for
Hydrogen production from Electrolyzers, although having no emissions, still can be done
only in permitted locations. Likewise, infrastructural modifications are unclear due to lack of
clear targets of hydrogen and other gases. TSOs and storage facilities and distribution needs
to revamp but do not want to under/over invest without proper communications. Managing
volatility in the gas composition and in particular variations of the calorific value of the gas
mix is necessary. More importantly, border crossing transmission lines faces conflicts with
the current regulations on gas quality are different for all Members States.
In the expert’s point of view, Technological barriers were more relevant and thus the
following were chosen (Figure 26) as the ones that need the most attention
1. Border Crossing Transmission lines: conflict with the current regulations
on gas quality are different for all Members States.
2. Storage of hydrogen is still a nascent technology
3. End user appliances need to be compliant to new gases. No such regulation
exists that control the appliance end of value chain
4. Unclear position of permitted concentration of hydrogen in the gas grid. As
an operational barrier, the blending limits are yet to be regulated.
Figure 26 Technological, Technical & Operational Barriers
Table 10 Expert´s opinion: Technological & Technical Barriers
Name Comments
Anonymous
Respondent 1
Green hydrogen should play a pivotal role and in order for this to happen
electrolyzers need to be further developed and improved (while also
gaining scale). In some cases, progressive blending with natural gas will be
an acceptable way towards decarbonization goals, but it can grid-lock the
gas sector at the upper limit of natural gas interoperability range.
Anonymous
Respondent 2
Technical potential to use existing natural gas infrastructure and equipment
for renewable/low-carbon gases Availability of specific hydrogen
appliances/equipment at competitive prices and with similar efficiency
levels as natural gas appliances/equipment
Anonymous
Respondent 3
Efficiency of Hydrogen production, distribution and billing to end
consumer
Anonymous
Respondent 4
Transmission and medium pressure asset compatibility (carbon steel
pipelines) and overall system operation.
Anonymous
Respondent 5
Scaling up of Electrolyzers, reducing cost of the gases, increasing renewable
energy production, CCS infrastructure and operation
Anonymous
Respondent 6
Electrolyzers need to be ramped up from 10 MW to GW scale, and made
much cheaper in the process. We have to accommodate much more wind
and solar than for electricity alone. Processes in industry (and dispatchable
power) need to be adapted for hydrogen use. Biomethane needs strong
development too: larger, more professional, lower cost, gasification next to
anaerobic digestion. Hybrid heat pumps need to be taken seriously as part
of a net-zero emission built environment.
Anonymous
Respondent 7
Adequate standards and rules to ensure interoperability between MSs,
compliance of end-use equipment and more flexible gas standards, which
allow for the injection of a variety of gas types, are central aspects for
fostering renewable/low-carbon gases. Some network operators are already
investing in hydrogen-ready networks. Lack of regulatory clarity in these
aspects is still a barrier. There is still uncertainty on the levels of
development of dedicated hydrogen networks, other renewable fuels of
non-biological origin for the different sectors -> but anyway regulation
should be technology neutral (but favoring renewable/low-carbon gases
and allowing for eventual incentives to renewable gases by Member States)
and thus can be improved to address this uncertainty.
5.1.2 SWOT Analysis
The SWOT analysis yielded some interesting results in the perspective of the macro
economic factors of PESTEL. The following figure 27, presents the results:
Figure 27 SWOT ANALYSIS
STRENGTHS: The strengths identified were the Environmental and
Technological aspects. This is true to the EU Commission’s target based on Climate
Action and the need to decarbonize its economy. The Technological aspects can also
be validated in that there has been significant strides in improving technology,
especially in electrolyzers and Carbon capture.
WEAKNESS: Economic, Legislative and Market aspects prove to be the weakness
and are the ones that needs to be exigently addressed.
OPPORTUNITIES: Although technological advances continue to push
innovation, this needs accelerations in order to achieve the targets. This applies to
Economic aspects, where implying taxes, proper funding and other such mechanisms
would bring about the competitiveness among gases.
THREATS: As indicated, the threats are from the Economic and the Market
aspects. Economically unviable production cost, investments costs and
competitiveness would prove to be a big barrier in implementing decarbonization of
the gas sector while the Market should be regulated to create demand and supply.
Figure 28 SWOT ANALYSIS SUMMARY
The strategies to map the strengths and weakness to opportunities and threats are discussed
in below:
(1) Strength-Opportunities Strategies: Strengths can take advantage of opportunities and
can further be bolstered to enable decarbonization. While opportunities are aplenty in
terms of technological advancements, the policies can be aligned to incentivize R&D in
low carbon gases
(2) Strength-Threats Strategies: Strong environmentally aligned policies to drive up the
prices of fossil fuels in order to reduce susceptibility to the threats. Technological
advances in the case of electrolyzers would also plummet the amount of fuel consumed
and the investment costs.
(3) Weakness-Opportunities Strategies: The identified opportunities in the economic and
the technological aspects opens up avenues to ensure the weakness in the market and the
legislative aspects. Bettering technologies and devising new framework would
automatically eliminate the threat of stakeholder hesitation and the market constraints
(4) Weakness-Threats Strategies: In order to protect the decarbonization from
internalities of the weakness and the externalities of the threats, a defensive plan must be
set up. As such, incentivizing low carbon gases and creating a demand using new
regulations could potentially make the framework more resilient to economic and market
weakness and threats
5.1.3 Uncertainty analysis of Survey Results
The participants are a refined group of experts in the field and 19 responses were obtained.
Primarily from different professional background, in the sense of being a researcher,
technical director of a TSO etc., they had varied opinions on the topic and each had their
own perception. As surveys are compilation of an educated guess, by different experts and
individual, it is important to identify the uncertainty that arises with it.
On a statistical note, the following tables and figures shows the standard deviation and the
variance of the responses for the various barriers. These represent the fact that although the
survey is a great method to validate a study, the differences of opinion among academicians
and expert exists. Table 11 below represents the Statistical treatment of the survey responses
of regulatory and policies related barriers, while figures 29-31 represents the data in a
graphical format. The rest of the tables for the other sub sections of the constraints can
found in the Appendix.
Table 11 Statistical Treatment of the Survey replies: Regulatory and Policies related Barriers
Barriers Median Mean Mode Std Deviation
Variance
A single European market based on interconnections between Member States could create an unnecessary additional financial burden if such infrastructure is mandated
2 2,111 2 0,963 0,928
Electrification Pathway is more attractive as it is simpler unlike gas decarbonization: Value chain remains the same for electrification while needs changes in case of gas
3 3,222 3 1,215 1,477
Emissions from Natural Gas: Different tool for same network will complicate decarbonization strategies (EU ETS, NECPs)
1 2,000 1 1,328 1,765
Regulators have discouraged long term contracts to prevent market foreclosure but for a developing market, it is way of risk sharing
2 2,444 2 0,856 0,732
Regulatory uncertainty delays investment. Lack of clarity will prevent stakeholders to hesitate
4 4,111 4 0,676 0,458
The case of Chicken and Egg: Without demand, suppliers will hesitate and without ensured supply, customers will not choose low carbon gases
3 3,167 3 1,150 1,324
The current decarbonization framework does not incentivize supply or create demand for low carbon gases
4 4,111 5 1,023 1,046
The current EU framework is highly detailed preventing Member States from developing approaches that suits their economies best
2 1,889 2 0,963 0,928
Unbundling rules limits possibility of Vertical integration of the value chain, another necessity for risk management in developing markets
2 1,944 1 0,998 0,997
Figure 29 Uncertainty: Social Barriers
Figure 30 Uncertainty: Social Barriers
Figure 31 Uncertainty: Technological & Technical Barriers
Though it is evident that the uncertainty is present, majority of the “Major barriers” that
were identified remain the same and thus is considered as sufficient. The validation of the
barriers using literatures and reports likewise is part of the survey. This is due to the reason
that either preponderance of participants were involved in or co-authored studies relating to
the barriers in Gas sector decarbonization.
5.2 Hydrogen Production: Costs and Sensitivity Analysis
5.2.1 Steam Methane Reforming (With and Without CCUS)
The calculations performed under the governing equations from the Methodology section
generated the following results. The production cost from Steam Methane Reforming
without CCUS is the cheapest at 1.33 €/kg of H2. The Investment cost was at 0.36 million
€/MW H2 (Table 2). The production rate and the capacity was taken to be 100,000 Nm³/h
and 300 MW H2 out at Lower heating Value. The Capacity factor was 95% while the discount
rate and the lifetime was taken to be 6% and 25 years respectively. Fixed OPEX and
Chemical & Catalysts cost was modelled as 3.5% and 0.2% of the CAPEX. The split up of
the costs are as in the Table below. It is evident from figure 32 that the fuel price makes up
most of the LCOH while the carbon tax does not affect when it is at 23.77 €/ton CO2.
Table 12 LCOH SMR: Split up of Costs
Annual Costs
SMR WITHOUT CCS
SMR WITH CCS: syngas MDEA
SMR WITH CCS: syngas MDEA 2
SMR WITH CCS: PSA tail gas MDEA
SMR WITH CCS: flue gas MEA
CAPEX 0,114 0,251 0,288 0,385 0,447
OPEX 0,054 0,119 0,136 0,182 0,211
Fuel Costs 1,257 1,714 1,761 1,657 1,77
Revenues -0,092 -0,056 -0,058 -0,067 -0,083
LCOH w/o tax 1,33 € 2,03 € 2,13 € 2,16 € 2,35 €
Carbon Tax 0,216 0,099 0,08 0,103 0,024
LCOH with tax 1,55 € 2,13 € 2,21 € 2,26 € 2,37 €
Figure 32 LCOH: SMR: Split up of costs
The implementation of a carbon tax on the CO2 emitted made the least cost competitive
SMR with flue gas MDEA more close to Steam Methane Reforming without carbon capture
and storage. The CO2 Emissions and the capture rates (Table 13) determined the price on
Carbon and the taxes were Portuguese and Swedish carbon tax rates.
Table 13 CO2 Emitted and Captured per year [64]
CO2
SMR WITHOUT CCS
SMR WITH CCS: syngas MDEA
SMR WITH CCS: syngas MDEA 2
SMR WITH CCS: PSA tail gas MDEA
SMR WITH CCS: flue gas MEA
CO2 emitted Mton/year
0,673 0,308 0,249 0,322 0,074
CO2 Captured Mton/year
- 0,365 0,424 0,351 0,599
Table 14 LCOH: SMR: Comparison with and without Carbon taxes
Carbon Tax
SMR
NO CCS Syngas MDEA
Syngas MDEA 2
PSA tail gas MDEA
Flue gas MEA
No Carbon Tax Min 1,33 € 2,03 € 2,13 € 2,16 € 2,35 €
Max 1,51 € 2,06 € 2,15 € 2,19 € 2,35 €
Portuguese Rate 23,77 €/ton CO2
Min 1,55 € 2,13 € 2,21 € 2,26 € 2,37 €
Max 1,73 € 2,16 € 2,23 € 2,30 € 2,37 €
Swedish Rate 108,91 €/ton CO2
Min 2,32 € 2,48 € 2,49 € 2,63 € 2,45 €
Max 2,50 € 2,51 € 2,52 € 2,67 € 2,45 €
The minimum LCOH (Refer to Table 14) without applying a carbon tax for Steam Methane
Reforming with carbon capture is 2.03 €/kg of H2 and the maximum is 2.35 €/kg of H2.
Upon introducing the current Portuguese Carbon Tax, the difference decreases but not up
to the anticipated amount. However, the Swedish rate of carbon tax has profound impact on
the LCOH, visually represented in figure 33. This proves the importance of a heavy carbon
taxation on CO2 emissions to not just increase the price of fossil-based generation but also
ensure competitiveness among low carbon gases.
Figure 33 LCOH: SMR: Comparison with and without Carbon taxes
5.2.2 Hydrogen Production from Electrolyzers (PEM, ALK & SOEC)
Polymer Electrolyte Membrane (PEM) Electrolyzer
Just like the SMR calculations, the PEM was also based on the methodology previously
explained. The capacity however was much smaller in comparison and it applies to other
electrolyzers as well. This is because the current installations are yet to be utilized for large-
scale hydrogen production. The capacity was 3 MW H2 out at Lower Heating Value, with a
hourly volumetric rate of 1200 Nm³/h [120]. The efficiencies and the investment costs are
derived from Table 2, while the discount rate and the lifetime was taken to be 6% and 20
years respectively. The capacity factor for Grid was assumed 80% and will be taken into
consideration when evaluating the sensitivity. Capacity factors for Wind and Solar are 30%
and 20% respectively as indicated in EU commission’s report on Hydrogen generation in
Europe [37].
Table 15 LCOH: PEM: Split up of costs
Annual Costs GRID WIND SOLAR
CAPEX 0,56 € 1,48 € 2,22 €
OPEX 0,10 € 0,25 € 0,38 €
Fuel Costs 4,04 € 4,92 € 1,64 €
Water costs 0,02 € 0,02 € 0,02 €
REPEX 0,22 € 0,00 € 0,00 €
LCOH 4,94 € 6,67 € 4,26 €
Similar to the SMR split up of costs, the PEM LCOH, represented in table 15 and figure 34,
follows the pattern where the fuel costs dictate the overall LCOH. This is evident from the
fact that the hydrogen production is directly proportional to the electricity consumed and
thus efficiency plays an important role in decreasing the costs. The following figures shows
how the minimum and maximum costs of production from PEM for the years 2020, 2030
and 2050.
Figure 34 LCOH: PEM: Split up of costs in 2020
0.56 €1.48 €
2.22 €0.10 €
0.25 €
0.38 €4.04 €
4.92 €
1.64 €
0.02 €
0.02 €
0.02 €
0.22 €
0 €
1 €
2 €
3 €
4 €
5 €
6 €
7 €
8 €
GRID WIND SOLAR
LC
OH
Eu
ro/k
g
LCOH: PEM: Split up of costs
CAPEX OPEX Fuel Costs Water costs REPEX
The minimum LCOH from PEM in the year 2020 was produced from Solar connected
electrolyzers and at 3.68 € per unit hydrogen, it was 200% more expensive than the H2
produced from SMR, as seen in the previous results. The scenario, however, changes quickly
when the 2030 investment cost and efficiencies are introduced. This makes the lowest LCOH
obtained as 1.95 € per unit hydrogen, as exhibited in Table 16, which is more cost competitive
and just 45% more expensive in comparison to the 2020 rates. Figure 35 shows the pictorial
decrease in the LCOH. Thus, the importance of technology is felt and justifies our choices of
technological barriers. The variance of LCOH with investments costs, efficiencies and other
parameters will be performed in the Sensitivity analysis.
Table 16 LCOH: PEM: 2020 vs 2030
Year Electricity
GRID WIND SOLAR
2020 Min 4,66 € 6,17 € 3,68 €
Max 6,82 € 9,72 € 7,84 €
2030 Min 4,08 € 5,09 € 1,95 €
Max 6,50 € 8,37 € 4,73 €
Figure 35 LCOH: PEM: Price range
The LCOH of Alkaline Water Electrolysis and Solid Oxide Electrolyzer Cell is given in the
Appendix. A comparison of the LCOH from different electrolyzer technologies in done in
section 6.3. The trend of Solar based production in Portugal for ALK and SOEC continues
to be cost competitive like in the case of PEM. The following section deals with the
sensitivity analysis for all the production methods.
5.2.3 Sensitivity Analysis
Sensitivity analysis is an important factor in understanding the influence of parameters on
the cost, while also validating the results and taking into considerations the errors in the input
parameters. For this study, the parameters considered and varied are as follows:
I. Capacity Factor of the plant (and of electricity in case of Wind and Solar)
II. Electricity/Natural Gas Price
III. Hydrogen Production capacity
IV. Efficiency
V. Discount Rate
VI. Investment Costs
The parameters are varied by ± 30% to have a deeper understanding of the associated errors
and possible increase/decrease in costs of fuel etc. The value is assumed as 30% as from the
data on investment costs and efficiency [37], it is clear that the percentage decrease/increase
is around 30%. The following figure 36 shows the sensitivity analysis for Steam Methane
Reforming without CCUS and PEM for the year 2020. The sensitivity for ALK and SOEC
is in the Appendix under Sensitivity Analysis.
Figure 36 Sensitivity Analysis: From Top right: SMR, PEM-GRID, PEM-WIND & PEM-SOLAR
For the different parameters, the variance of the LCOH is altered based on its direct/indirect
influence. For example, in the case of Steam Methane Reforming with CCUS, LCOH is
varied the most with the price of natural gas. A 30 increase in natural gas price results in
almost 30% increase in the LCOH, from 1.31€ to 1.72€. However, the other parameter were
not of much importance when it comes to SMR. This may be due to the fact that the
technology is already mature and the just needs to be taxed on Carbon emissions.
The scenario however is not the same for the nascent electrolyzer technology. It is evident
that electricity price and efficiency will play a major role in the LCOH. A 30% increase or
decrease in GRID Electricity prices has a ±1€ difference in the LCOH. The same is
applicable for Wind electricity price but the solar powered electrolyzers is not affected in the
same scale. This is especially true and a good sign for Portugal as the potential and the price
of Solar works in favor of its Hydrogen Strategy.
It is also an important inference to note that a reduction in investment costs in the case of
PEM-Solar has the highest impact, pushing down the LCOH to 3.5€ per unit hydrogen. The
results of this sensitivity analysis is in congruence with the results from earlier with the 2030
investment costs, where the LCOH was in the range of 2-4 €.
5.3 Emissions from Hydrogen production
The topic of the thesis is about decarbonization and thus for complete justification the
carbon emissions were also included. Many studies indicate the need for decarbonization and
estimate the amount of reduction in emissions from the different hydrogen production
methods. Having that in mind, the following are the results from the thesis and the estimated
CO2 emissions from the production of hydrogen from SMR and Electrolysis connected to
the grid. The reason for omitting the electrolysis from the RE sources is that the CO2
emissions from RE is considered negligible and thus assumed zero.
Figure 37 CO2 Emissions from Hydrogen Production (kg CO2/kg H2)
It is clear from figure 37 that the emission per kg of H2 is highest for the PEM and the lowest
for the SMR. This is quite the contrary to the definition of Green and Blue Hydrogen. As
such, SMR seems to be the most effective in terms of specific emissions given that the
electrolysis is performed by GRID connected electricity. The values are at 11.64 kg CO2/kg
H2 for PEM, 10.92 kg CO2/kg H2 for Alkaline water Electrolysis while SMR yield is at just 9
kg CO2/kg H2.
In the next chapter, the discussions of the results are presented. A deeper analysis of the
results, graphs and tables will enable better scrutiny of the work. The results will also be
validated using relevant existing reports and literatures. In addition, it also addresses the
research questions and the methodology results and finally summarized in the Conclusions
chapter.
6. Discussions
6.1 Research Questions and Methodology Discussion
The research questions framed in the beginning have been thoroughly examined using an
explanatory study that employed a SWOT analysis of the PESTEL macroeconomic factors.
The important question of the roadblocks to decarbonization in the current policies and
regulations has been addressed meticulously, using the reports and literatures mentioned
previously in Chapter 3. As a part of evaluation, the thesis also devoted a survey with the
sole purpose of collecting the precious inputs and validations from the experts of the field.
Production of hydrogen in Portugal was the next research question that was answered in this
thesis. The levelized cost of hydrogen was modeled based on the algorithm previously used
in studies and research papers. The thesis looks for the best alternative to replace natural gas
by weighing the levelized cost of hydrogen production. Since the model heavily depends on
investments costs and fuel price, the errors in assumptions have also been methodically
inspected using a sensitivity analysis. The quantitative approach provided results that will be
validated in the following subsections. Albeit a simple model, the results strengthen the
chosen methodology.
6.2 Survey and SWOT-PESTEL results
As a summary of the identified limitations, this subsection will compare and contrast the
results of this thesis with those of other relevant studies. Limitations due to the current
framework in terms of the political aspect is similar to the deductions of the report
commissioned by EU [121]. The report also categorized their results along the lines of
infrastructure planning, uneven field of play, immaturity of technology, interoperability risks
across the borders and among markets & the lack of focus on natural gas regulation. Alex
Barnes in their study discusses the key challenges in designing a decarbonization framework
[26]. The findings of this report include the emphasis on the need to prioritize the objective
of decarbonization and the lack of incentives for low carbon gases.
Lisa Fischer and Jonathan Gaventa classified what they concluded into four reasons to why
the current modus operandi is no longer apt. It includes compatibility issues, volume issues,
the economic factor and the fact that not all pathways to decarbonize gas are “Carbon
Neutral” per se [122]. Trinomics’s report on the role of gas infrastructure in 2050
decarbonization targets analyzed the readiness of the regulations [123]. While their study
mainly focused on the infrastructure aspect, this is not entirely considered in this thesis and
can be classed as a limitation. To sum up everything, the constraints identified by this thesis
has been well validated by firstly the participants of the survey and secondly, upon close
comparison with similar studies.
6.3 Hydrogen Production costs
As far as the production costs of Hydrogen is concerned, SMR continues to be the cheapest
in the technologies analyzed in 2020 while PEM and SOEC produced entirely from Solar
electricity is competitive in 2030 and 2050. While the Investments costs and efficiency
improvements are due for the electrolyzers, a carbon tax will need to be implemented to
have a levelized field of hydrogen production. Table 17 summarizes the costs from different
electrolyzer production methods
Table 17 Summary of LCOH from Electrolyzers
Year Technology Electricity
GRID WIND SOLAR
2020
PEM 4,66 € 6,17 € 3,68 €
ALK 4,27 € 5,69 € 3,38 €
SOEC 4,55 € 6,06 € 4,07 €
2030
PEM 4,08 € 5,09 € 1,95 €
ALK 4,16 € 5,54 € 2,16 €
SOEC 3,85 € 5,04 € 1,97 €
2050
PEM
ALK 3,89 € 5,02 € 1,68 €
SOEC 3,39 € 4,42 € 1,59 €
As seen from the results, it is clear that blue hydrogen is much cheaper than green hydrogen
currently. This is due to various factors including Technology Readiness level, cost of natural
gas and lack of carbon taxation. The current TRL values for different electrolyzers are SOEC
between 6-7 [124], while PEM is 4-6 and alkaline water is between 7-8 [125]. However, given
the TRL for electrolyzer is yet to reach its potential and rapid decreases in investment costs,
LCOE from renewable resources and increase in efficiency as forecasted before [37], the
cost gap between blue and green hydrogen would be more competitive. That said, without
furthering carbon tax, natural gas would still be much cheaper alternative compared to
Hydrogen and thus policies and reforms should be built around taxation on fossil energy
imports.
Figure 38 Levelized Cost of Hydrogen from Clean Hydrogen Report [35].
The above figure (figure 40) shows the estimates from the report on Clean Hydrogen by
Hydrogen Europe. It is clear that the results of this thesis are in congruence with that of the
report. With an estimated range of 2.9 – 3.5 € per kg of Hydrogen from Solar and 4.9 – 8.2
€ per kg of Hydrogen from Wind, the estimates are similar to the results of this thesis. The
resemblance can thus be used as a validation to our methods and the results as well.
Sensitivity analysis for the LCOH also authenticate the fact that the assumptions made in the
study were realistic. It should be noted that almost all of the assumptions have either been
tried or tested previously in the literatures from which it was derived. As such the only
Considering the emission results, it is in tandem with that of by Shell Hydrogen Study (figure
39) [126]. It also clearly shows that the electrolysis of water to produce hydrogen but
connected to the grid is not the best option given that the emissions are highest. Although
the units are different in the studies, it still displays the differences in CO2 emissions and thus
indicates the need for reduction of emissions from the electricity sector as well in order to
produce Hydrogen with the hassle of CO2 emissions.
Figure 39 GHG emissions of Hydrogen production [126]
In another study by Tong et al at the Carnegie Mellon University, in figure 40, also depicts
the CO2 emissions of different Hydrogen Production methods. The units of emissions are
given as kg CO2/kg H2 [127]. The results can be inferred as such that the SMR is even now
the more sustainable option and cost wise feasible.
Figure 40 Summary of estimates from the literature of LCOE and CO2 emissions of Hydrogen Production methods
The emissions for the different technologies have been evaluated from the production of
fuel to the production of the hydrogen. Regarding the downstream emissions, it is considered
as a limitation and out of scope of the thesis.
7. Recommendations and Conclusions
7.1 Recommendations
This chapter contains the recommendations proposed by the author that may help in
addressing the constraints seen in the previous chapters. The recommendations were
evaluated by the survey of experts as well. This will prove to be a stepping-stone in terms of
future policy and regulations.
Figure 41 Areas of Action
The areas that would ease the constraints on the sector’s decarbonization as seen in Figure
41 are:
1. Better regulatory and Policy framework
2. Better financial environment for new investments
3. Improvements in technology
4. Market incentives for stakeholders
The suggestion for a better regulatory and policy framework include new regulations for low
carbon gases and hydrogen that are different for the transition phase while understanding of
stakeholders’ motivations, creating a more robust regulatory framework that enables easier
uptake. It is also recommended that decarbonization should be viewed as the main objective,
rather than on the means to achieve it. Similarly, regulations should start incentivizing supply
and create demand for low carbon gases. In addition, There should be a need for
encouragement, development and refinement of technologies “learning by doing” for early
adopters and hence lower costs for later adopters. Finally, creating a level playing field
between different pathways, Electrification vs Gas Decarbonization is important.
It is evident that the LCOH of hydrogen, especially green hydrogen is economically
expensive (by at least one €/kg of hydrogen compared to blue) and thus not a viable pathway
yet. This proves to be a big area that needs to be addressed as soon as possible given the
need to curb CO2 emissions. Thus, the proposals for a better economic environment consist
of renewable gases (biomethane, hydrogen etc.) and an increase carbon tax on natural gas.
New unbundling rules will reduce risk on investments combined with improved EU level
funding for projects. By means of subsidies, industries and individual consumers alike will
stand to gain. Meanwhile, payment and remuneration mechanisms by means of cost
allocation and tariff arrangements will improve stakeholder participation. Power balancing
for the use of electrolyzers by exempting grid fee ensures competitive access to renewable
power and lastly, hydrogen quotas/targets for renewable and low carbon hydrogen on the
demand side will create the much needed market.
The technological, technical and operational barriers can be dealt with by the following
schemes. A safety (mandatory) and compliance requirements for grid connection and pan
EU gas safety and compliance requirements on the customer side. In addition, a harmonized
regulation for hydrogen admix is necessary. There is a need to distinguish and differentiate
the hydrogen production methods by incentivize production from environmentally friendly
methods. Guidelines for land use and zone prohibitions should be moderated for green
hydrogen productions and more importantly, a revision of TEN-E regulation to back the
growth and roll out of hydrogen networks is proposed.
As a policy implication of the study, it shows the areas and aspects in which the current
framework of policies and regulations are weak. It also helps in revealing the fault lines by
differentiating into individual aspects such as a political barrier or an economic barrier. This
may enable policymakers to target specific areas and design future policies that are more
effective. The study also considers the Sustainable Development Goals and as such are
aligned with the SDG 7, 11 and 13.2 This is because the policies and regulations studied are
interlinked with climate action, access to cheap and clean energy and having sustainable
communities and cities.
Since the recommendations solely represents the view of the thesis, they are cross verified
with those from published in reports by renowned entities such as European Network of
Transmission System Operators for Gas (ENTSOG), Agency for Cooperation of Energy
Regulators (ACER), and the Oxford Institute of Energy Studies (OIES). The ACER report
infers that the environmental effects of low carbon gases should be evaluated and defined
clearly. It also insists that the need for blending legislations and dynamic monitoring.
However, contrasting to this thesis, the ACER report suggests minimal participation of the
TSOs and the DSOs in competitive undertakings with the exception of having stringent rules
[128].
2 SDG: Sustainable Development Goals SDG 7: Affordable and Clean Energy, SDG 11: Sustainable Cities and Communities, SDG 13: Climate Action
ENTSOG presents its recommendations in seven sections. It also has a systematic approach
on the proposals, clearly defining the assumptions. They assume that the existing gas
infrastructure can bring about decarbonization. They also assume that the development in
individual member state will completely depend on the EU policy. Incidentally, this situation
was discussed under technical barriers in this thesis. Adhering to their assumptions, they
recommend a new market in the EU for the new gases, transportation standards; pan EU
Guarantees of Origins, importance of sector coupling, regulations on CO2 transportation and
a gas quality framework [129].
Given the nature of insights and recommendation, there are instances where they take the
polar opposite stand, as is the case with ENTSOG pushing for a TSO regulated Hydrogen
production but other stakeholders feel that it would be a bias towards the TSOs, as the
activities would bolster profits for the TSOs. Another area of concern is the fact that the EU
commission strongly prefers green hydrogen wile reports tend to favor a technology neutral
collective approach. While ACER not necessarily backs the TSO and are more concerned
about their position in production of hydrogen, ENTSOG endorses it.
It is clear that while the pathway for decarbonization uncertain, the journey towards a carbon
neutral economy has already been set in motion. Conflicts that needs addressing include a
new regulation and definition for the term gas and monitoring interesting especially with
stakeholders of sector coupling, and among the gas industry, the producers, TSOs and DSOs.
7.2 Conclusions
The thesis work has established that the policies and regulations currently in place in the EU
have barriers to decarbonizing the natural gas sector. While the barriers were mostly related
to economic constraints, the regulations and policies lack in political, social and technological
aspects as well. Consequently while evaluating the results of the survey; it is found that the
experts in the field validate the notion that the present framework in EU does not necessarily
facilitate the decarbonization. It can be concluded that although the policies and regulations
were formulated to reduce emissions and help transition to a carbon neutral future, the
emphasis is more on electrification pathway rather than a unified approach that includes
natural gas. The solutions and recommendations proposed include incentivizing and creating
a market for low carbon gases while simultaneously levying a heavy carbon tax on fossil fuels.
Regulations likewise should enable a level of vertical integration to ensure stakeholder
participation without hesitation.
However, the most important suggestion is that decarbonization should be the objective and
not the path to achieving it. It could be said that electrification seems to be easier pathway
given that the value chain remains same without the need for much modifications. Yet,
decarbonizing natural gas will not only make the process much cheaper but also provides the
means to counteract the intermittency of renewable electric generation. The future should
look towards an inclusive definition of “gas” covering not only methane but also other low
carbon alternatives and Hydrogen. Prioritizing conversion of green molecules to green
electrons and vice versa would guarantee a smoother transition.
In the case of pathways to decarbonize gas, hydrogen production in Portugal was examined
and the cost of production was determined for various technologies. It can be established
that the levelized cost of Hydrogen is far from being competitive, even in comparison to
blue hydrogen from SMR. The cost of investment for electrolyzer is still high and the
efficiency has scope for improvements. The technology readiness level for electrolyzers are
at 4-8 on average while for SMR is has been used all over the world and is established. This
difference is clearly visible in the overall LCOH. Upon exploring further, the study finds that
the costs are majorly dependent on the cost of electricity in case of electrolyzers and cost of
Natural gas for SMR.
The immediate inference is that a steep increase in the price of natural gas through import
tax and carbon tax, while decreasing the electricity prices through large-scale renewable
energy projects would create the much needed competitiveness among blue and green
hydrogen. It is evident in the case of SMR with and without CCS when the carbon tax is
introduced. Although the change is minimal for the Portuguese rates, the Swedish carbon
tax rate, the then highest in Europe, increases the LCOH to almost a euro per kg of hydrogen.
The thesis also dwells into the environmental impacts of producing hydrogen. It is was
surprising that the most polluting technology was in fact electrolyzer connected to the grid,
when considering the emissions of electricity generation as well. This is all the more a reason
to utilize the established and widely used reforming process as a bridge until the point when
green hydrogen produced from renewable energy can take over.
To sum up, the thesis has answered all of the intended research questions. As a conclusion
the following lines summarizes the final thoughts on the topic. Policy makers and regulators
should come together to create a special framework to enable decarbonization of the natural
gas in EU. It would heavily depend on future incentives, the penetration of renewables and
the inter link between gas and electricity sector. In comparison to the present day scenario,
green hydrogen production will play a significant role and the enablers include decrease in
investments cost and an increase in efficiency of the electrolyzers. Furthermore, the lesser
the emissions, more the LCOH and the vice versa is also found true. Whether or not
hydrogen production costs decrease, it is highly recommended to impose heavy taxation on
carbon emissions.
7.3 Future Scope
The scope of the current thesis was limited to the impact of policies and regulations and the
barriers that they pose to decarbonization of the natural gas industry. The cost analysis of
hydrogen production is used to show the vast inequalities present currently. This, thus, clearly
exhibits the needs to revamp and amend regulations, policies and mandates to push the low
carbon gases. However, the research does not stop here and can be further extended to
obtain a clearer picture. To this end, as a future scope the following areas could be addressed.
1. Bio Methane and Synthetic Methane Pathways.
2. The Impact on the players in the value chain of natural gas
3. Cost of Stranded assets
4. Production cost if subsidies are in place
5. Impact of Investments costs and efficient technologies on the costs
6. Emissions reductions due to injection of hydrogen and low carbon gases: TSO and
DSO emissions
7. Demand based analysis
Although a few of the topics have been adopted, they were not the main intention of this
thesis and thus the results may be need a deeper investigation.
8. References
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9. Appendix
Table 18 Statistical Treatment of the Survey replies: 1.Economic Barriers 2.Social & 3.Technological and Technical Barriers
Barriers Median Mean Mode Standard Deviation Variance
Cost of Production 5 4,333 5 1,113 1,238
Infrastructure development costs
4 3,867 4 0,834 0,695
Cost of Stranded assets 3 2,733 3 1,033 1,067
Cost competitiveness: Natural gas vs low carbon gas & Hydrogen
5 4,333 5 0,976 0,952
EU ETS: Not enough tax on carbon
4 4,267 5 0,799 0,638
End User costs: Need for equipment change and modification to accommodate new gases
3 3,133 3 0,743 0,552
Lack of Incentives for uptake 4 4,000 4 0,926 0,857
Lack of security for the Stakeholders: High risks for investments and longer ROI
4 3,533 4 0,990 0,981
Lack of Payment and remuneration mechanisms
4 3,933 4 0,884 0,781
Barriers Median Mean Mode Standard Deviation Variance
Higher Energy Bills 5 4,733 5 0,594 0,352
Questions about energy security 4 3,400 4 1,056 1,114
Safety Concerns (hydrogen) 4 4,200 4 0,862 0,743
User behavior / awareness 4 3,600 3 0,632 0,400
Availability and Reliability 3 3,333 4 1,113 1,238
Impact on Jobs in the Sector 2 2,133 1 1,125 1,267
Educational levels 3 3,133 3 0,834 0,695
Cultural blocks 2 2,533 2 1,060 1,124
Wealth disparity 2 2,600 2 1,121 1,257
Barriers Median Mean Mode Standard Deviation Variance
Efficiency of Hydrogen production methods: Electrolyzers, Steam methane reforming, Carbon capture and Storage
3 3,533 3 1,125 1,267
Technological improvements needed in Pipelines to accommodate hydrogen and Biomethane: Changes in calorific values
3 3,267 3 1,100 1,210
Storage of hydrogen is still deemed dangerous, thus
3 3,067 4 1,100 1,210
requiring technological advancements
End user appliances need to be compliant to new gases
4 3,667 4 0,724 0,524
Unclear position of permitted concentration of hydrogen in the gas grid
3 3,267 4 0,961 0,924
Land Use Prohibitions limits zones for Hydrogen production from Electrolyzers although having no emissions
3 2,667 3 0,976 0,952
Infrastructural modifications unclear due to lack of clear targets of hydrogen and other gases
4 3,667 3 0,900 0,810
Managing volatility in the gas composition and in particular variations of the calorific value of the gas mix
3 3,333 3 1,113 1,238
Border Crossing Transmission lines: conflict with the current regulations on gas quality are different for all Members States
4 3,600 4 1,242 1,543
Hydrogen Production Costs: Alkaline Water Electrolysis
Table 19 LCOH: ALK: Split up of costs
Annual Costs GRID WIND SOLAR
CAPEX 0,82 € 2,20 € 3,30 €
OPEX 0,14 € 0,38 € 0,57 €
Fuel Costs 3,79 € 4,62 € 1,54 €
Water costs 0,02 € 0,02 € 0,02 €
REPEX 0,33 € 0,00 € 0,00 €
LCOH 5,11 € 7,21 € 5,42 €
Figure 42 LCOH: ALK: Split up of costs
Table 20 LCOH: ALK: 2020 vs 2030 vs 2050
Year Electricity
GRID WIND SOLAR
2020 Min 4,27 € 5,69 € 3,38 €
Max 9,04 € 14,21 € 14,16 €
2030 Min 4,16 € 5,54 € 2,16 €
Max 7,15 € 10,78 € 6,29 €
2050 Min 3,89 € 5,02 € 1,68 €
Max 4,04 € 5,31 € 1,92 €
Figure 43 LCOH: ALK: Price Range
Hydrogen Production Costs: Solid Oxide Electrolyzer Cell
Table 21 LCOH: SOEC: Split up of costs
Annual Costs GRID WIND SOLAR
CAPEX 0,54 € 1,45 € 2,18 €
OPEX 0,09 € 0,25 € 0,37 €
Fuel Costs 3,08 € 3,75 € 1,25 €
Water costs 0,02 € 0,02 € 0,02 €
REPEX 0,65 € 0,58 € 0,44 €
LCOH 4,40 € 6,06 € 4,26 €
Figure 44 LCOH: SOEC: Split up of costs
Table 22 LCOH: SOEC: 2020 vs 2030 vs 2050
Year Electricity
GRID WIND SOLAR
2020 Min 4,55 € 6,06 € 4,07 €
Max 11,35 € 17,10 € 18,42 €
2030 Min 3,85 € 5,04 € 1,97 €
Max 7,37 € 11,00 € 9,51 €
2050 Min 3,39 € 4,42 € 1,59 €
Max 4,69 € 6,40 € 3,08 €
Figure 45 LCOH: SOEC: Price Range
Sensitivity Analysis
Figure 46 Sensitivity Analysis: Left Column: Alkaline Water Electrolysis (GRID, WIND, SOLAR); Solid Oxide electrolyzer Cell (GRID, WIND, SOLAR)