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Constraints to Decarbonization of
the Natural Gas System in the EU:
Techno-economic analysis of hydrogen
production in Portugal
SE-100 44 STOCKHOLM
Master of Science Thesis EGI TRITA-ITM-EX
2021:69
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 विष्ुं शवशिर्णं चतुर्ुजम् ।
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
2.4 Hydrogen in EU 27
2.4.1 Hydrogen Production 28
2.4.2 Hydrogen Demand 29
4.3 Levelized Cost of Hydrogen Production (LCOH) for Different Production Systems (SMR+
CCS and Electrolysis) 47
5. RESULTS 57
6. DISCUSSIONS 78
7.1 Recommendations 83
7.2 Conclusions 86
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]
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].
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. 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:
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.
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].
CO2 emissions from fuel combustion - Gas
Million tonnes of CO2
7500
7000
6500
6000
5500
Million tonnes of CO2
5000
4500
4000
3500
3000
2500
2000
1500
1000
500
0
Year
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].
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].
Figure 5 World natural gas production (volume) by region from 1973 until 2019 [19]
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].
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.
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.
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, 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].
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”
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].
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.
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.
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.
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.
3.2.1 Policies
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%
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]
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]
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.
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:
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 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]
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.
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].
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:
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
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
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:
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].
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):
Source of Production
H2
Power/Fuel Method
GRID
Connected
1. PEM
Electricity
2. ALK
from Wind
3. SOEC
Electricity Hydrogen
from Solar
1. SMR
Natural Gas 2. SMR with
CCS
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.
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.
∑𝑁
𝑛=1(𝐼𝑛 + 𝐹𝑛 + 𝑉𝑛 ) ∗ (1 + 𝑖)
−𝑛
𝐿𝐶𝑂𝐸 = (1)
∑𝑁
𝑛=1 𝐸𝑛 ∗ (1 + 𝑖)
−𝑛
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
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:
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 𝐸𝐻2 𝑎 (kg/year):
𝐶𝑎
𝐿𝐶𝑂𝐻 = (6)
𝐸𝐻2 𝑎
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]
Cost of Value
Natural gas 0.0263 €/kWh
Grid 0.074 €/kWh
Electricity Wind 0.09 €/kWh
Solar 0.02 €/kWh
Water 1.8818 €/m³
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]
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]
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
365*24*Capacity Factor
year
Number of replacements Lifetime /Years before Replacements
Electricity Consumption per
Hydrogen Produced per year (kWh) /efficiency
year
Water Consumption per year Water Consumption (Volumetric)*Full Load Hours
Hydrogen Produced per year
Hydrogen Produced per year (kg) * LHV
(kWh)
Hydrogen Produced per
Hydrogen Produced per year (Nm³) * Density
year(kg)
Hydrogen Produced per year
Hydrogen Production capacity*Full Load Hours
(Nm³)
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
Invest Costs*REPEX Percentage
(Euro)
Annualized REPEX (Euro) REPEX per Replacement* CRF
Annual Electricity Costs (Euro) Electricity Consumption per year *Electricity Price
Annual Natural Gas Costs
Natural Gas Consumption per year *Gas Price
(Euro)
Annual Water Costs (Euro) Water Consumption per year *Water Price
Annualized CAPEX+ Fixed OPEX+ Annualized REPEX +
Total Costs
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
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.
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 The political focus on maximizing the shift of as many economical sectors as
Respondent 1 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 "Lack of predictable/stable regulatory framework
Respondent 2
Anonymous Conflicting policy objectives
Respondent 3
Anonymous Lack of adequate pricing scheme for CO2-emissions"
Respondent 4
Anonymous I think the major threat is the Electrification lobby
Respondent 5
Anonymous Natural gas taxation and incentives, policy towards electrification and current
Respondent 6 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 Policies are needed to drive the demand and supply of renewable and low-
Respondent 7 carbon gases (see our Gas for Climate reports), and to enable infrastructure
(e.g. anticipatory investments) and markets for those.
Anonymous The major influence of the Oil industry and the hypocrisy of the politicians
Respondent 8 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 The major threats are the following. This does not mean that policymakers are
Respondent 9 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
Name Comments
Anonymous In most cases, the technology is at an emerging stage and therefore lacks
Respondent 1 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 Cost gap between natural gas and renewable or low-carbon gases is still
Respondent 2 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 Cost of production and delay when compared to Electricity.
Respondent 3
Anonymous Incentives on demand and also regulation framework for the initial
Respondent 4 projects
Anonymous Cost of fossil gases are lower than that of decarbonized gases
Respondent 5
Anonymous Costs of low carbon gases versus fossil natural gas limits demand for it
Respondent 6
Anonymous Natural gas prices are much lower than that of biogas, and hydrogen is
Respondent 7 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 The barrier is the time needed to transform the energy sector in a
Respondent 8 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
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.
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 Usually those related to economic and social welfare aspects. Increasing
Respondent 1 energy efficiency and minimizing energy end consumption are usually
met with mistrust and perceived as affecting economic welfare.
Anonymous Sociological aspects are to my understanding less important barriers
Respondent 2 than the economic (competitiveness- and technological aspects
Anonymous Hydrogen fear
Respondent 3
Anonymous The efforts of reducing emissions is commonly associated with the
Respondent 4 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 Citizens need to become familiar with the new gases, and need to know
Respondent 5 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
Name Comments
Anonymous Green hydrogen should play a pivotal role and in order for this to happen
Respondent 1 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 Technical potential to use existing natural gas infrastructure and equipment
Respondent 2 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 Efficiency of Hydrogen production, distribution and billing to end
Respondent 3 consumer
Anonymous Transmission and medium pressure asset compatibility (carbon steel
Respondent 4 pipelines) and overall system operation.
Anonymous Scaling up of Electrolyzers, reducing cost of the gases, increasing renewable
Respondent 5 energy production, CCS infrastructure and operation
Anonymous Electrolyzers need to be ramped up from 10 MW to GW scale, and made
Respondent 6 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 Adequate standards and rules to ensure interoperability between MSs,
Respondent 7 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.
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.
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
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
SMR SMR
WITH WITH SMR SMR
SMR CCS: CCS: WITH CCS: WITH CCS:
WITHOUT syngas syngas PSA tail gas flue gas
Annual Costs CCS MDEA MDEA 2 MDEA 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]
SMR SMR
WITH WITH SMR
SMR SMR WITH CCS: CCS: PSA WITH
WITHOUT CCS: syngas syngas tail gas CCS: flue
CO2 CCS MDEA MDEA 2 MDEA gas MEA
CO2 emitted
0,673 0,308 0,249 0,322 0,074
Mton/year
CO2
Captured - 0,365 0,424 0,351 0,599
Mton/year
Table 14 LCOH: SMR: Comparison with and without Carbon taxes
SMR
NO CCS Syngas Syngas PSA tail Flue gas
Carbon Tax
MDEA MDEA gas MEA
2 MDEA
Min 1,33 € 2,03 € 2,13 € 2,16 € 2,35 €
No Carbon Tax
Max 1,51 € 2,06 € 2,15 € 2,19 € 2,35 €
Portuguese Min 1,55 € 2,13 € 2,21 € 2,26 € 2,37 €
Rate 23,77
Max 1,73 € 2,16 € 2,23 € 2,30 € 2,37 €
€/ton CO2
Swedish Rate Min 2,32 € 2,48 € 2,49 € 2,63 € 2,45 €
108,91 €/ton
Max 2,50 € 2,51 € 2,52 € 2,67 € 2,45 €
CO2
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.
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
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.
0.22 €
5€
0.02 €
4€ 4.92 € 0.02 €
1.64 €
3€
4.04 € 0.38 €
2€
0.25 €
1€ 2.22 €
0.10 € 1.48 €
0€ 0.56 €
GRID WIND SOLAR
Year Electricity
GRID WIND SOLAR
Min 4,66 € 6,17 € 3,68 €
2020
Max 6,82 € 9,72 € 7,84 €
Min 4,08 € 5,09 € 1,95 €
2030
Max 6,50 € 8,37 € 4,73 €
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 €.
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.
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.
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.
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9. Appendix
Table 18 Statistical Treatment of the Survey replies: 1.Economic Barriers 2.Social &
3.Technological and Technical Barriers
Year Electricity
GRID WIND SOLAR
Min 4,27 € 5,69 € 3,38 €
2020
Max 9,04 € 14,21 € 14,16 €
Min 4,16 € 5,54 € 2,16 €
2030
Max 7,15 € 10,78 € 6,29 €
Min 3,89 € 5,02 € 1,68 €
2050
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
Year Electricity
GRID WIND SOLAR
Min 4,55 € 6,06 € 4,07 €
2020
Max 11,35 € 17,10 € 18,42 €
Min 3,85 € 5,04 € 1,97 €
2030
Max 7,37 € 11,00 € 9,51 €
Min 3,39 € 4,42 € 1,59 €
2050
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)