To: Laurent Charles THERY- senior VP International Development/GRT GAZ – France From: Ciprian – Octavian ALIC – dipl. Eng. / Visiting Professor /… [303828]

STRICTLY CONFIDENTIAL

To: [anonimizat]/[anonimizat]: Ciprian – [anonimizat]. Eng. / Visiting Professor / [anonimizat] – ENERGY MARKET /Bucharest / ROMANIA

Re: Hydrogen – The blue future begins today! Report on the sector / Production, transport, storage, projects, financing investments

Date: 12.08.2019

[anonimizat], projects in energy field focused on Hydrogen; production, storage and hydrogen as a fuel, [anonimizat].

Furthermore, the Report present case studies and international scientific approach on hydrogen sector.

[anonimizat].

[anonimizat] a deep analysis of various studies on Hydrogen elaborated in the last years corelated with updates / actual information on the subject by the most important European and international experts and scientists.

Important Note! This Report is not public!

[anonimizat], the result of the research work and represents the author's own evaluation in the line established by the beneficiary. Some bibliographic documents have a [anonimizat]. The report is a working document only to facilitate decision making regarding the approaches of the projects in the use of hydrogen as a clean energy source for today and tomorrow.

HYDROGEN

The blue future begins today!

[anonimizat], storage, projects, financing investments

August 2019

CONTENTS

Chapter I. ABSTRACT

Generalities

Production

Connection to the natural gas network

Mechanisms and tools to finance Hydrogen projects

Chapter II. SECTOR ANALYSIS. SAFETY AND SECURITY. CASE STUDIES. AMERICAN SCIENTISTS APPROACH

II.1. [anonimizat] a fuel, comparison, advantages

II.2. CASE STUDIES

a) Hydrogen in the gas network; preamble, opportunities,

b) Challenges,

c) [anonimizat].3. USA scientist’s overview: [anonimizat]-to-Gas (P2G) / Electrolysis

Hydrogen interconnection/standards

Hydrogen fuel cells and fuel cell vehicles

The Future of Technology

Macro Challenges (High Level)

Hydrogen pipeline systems; [anonimizat]’ opinion

Similarities and differences between the two pipeline networks

Hydrogen pipeline systems; common facility characteristics; transmission pipelines; design parameters; materials for pipelines

Compressor stations

Metering stations

City gate stations

Valves

Pig launching and receiving facilities

SCADA centers

Telecommunications towers

Access roads

Chapter III. CEF TRANSPORT BLENDING FACILITY. GRANTS. CEF PROJECTS EXAMPLES

III.1. Blending Facility; application process and role of the Implementing Partners

III.2.1. Eligibility of costs

III.2.2. A CEF indicated business plan

III.3. [anonimizat] – EXAMPLES

Hydrogen as an alternative fuel

Models for Economic Hydrogen Refueling Infrastructure

TSO 2020: Electric “Transmission and Storage Options” along TEN-E and TEN-T corridors for 2020

Zero Emission Valley

Chapter IV. OVERVIEW ON SPECIFIC LEGISLATION FRAMEWORK AND EU’s COHESION POLICY

IV.1. 2030 Energy Strategy; targets and policies for 2030

IV.2. Directive 2014/94/EU on the deployment of alternative fuels infrastructure

IV.3. COMMISSION STAFF WORKING DOCUMENT-February 2019

IV.3.1. Brief on Romania

IV.4. Cohesion policy of the European Union 2021-2027

IV.5. International Energy Agency vision

Chapter V. CONCLUSIONS AND RECOMMENDATIONS

APPENDIX 1 – USA: Hydrogen – fuel for vehicles – about hydrogen stations

APPENDIX 2 – Thermodynamic analysis of hydrogen pipeline transportation – selected aspects

APPENDIX 3 – Estimation Costs – hydrogen pipeline and Case City demand

APPENDIX 4 – Poland: Waste hydrogen pipelines monitoring in modern power plant

APPENDIX 5 – Research on Hydrogen from coal

APPENDIX 6 – Canada: The 100 MW euro-Quebec hydro-hydrogen pilot project

APPENDIX 7 – USA: Nebraska Monolith Project – a plasma-based process for cracking hydrocarbons for the co-synthesis of carbon black hydrogen

APPENDIX 8 – Holland: the hydrogen project HyStock – 1 MW power-to-gas installation in the Netherlands

APPENDIX 9 – Project-Hypothetical Plant in Singapore / The Profitability Estimation of a 100 MW Power-to-Gas Plant – case study

APPENDIX 10 – Method for Producing Hydrogen from Hydrocarbon Liquid Using Microwave In-liquid Plasma

APPENDIX 11 – Horizon 2020: The ODYSSEE-MURE project

Chapter I. ABSTRACT

Generalities; Production; Connection to the natural gas network; Mechanisms and tools to finance Hydrogen projects

The ABSTRACT of the Report presents a description of the main principles of the efficient use of hydrogen as a source of energy and the result of research & projects development in hydrogen business. The ABSTRACT reviews also Mechanisms and tools to finance Hydrogen projects.

Hydrogen is the most present element in the Universe, and, at the same time, it is the element having the biggest energy per mass unit. A fuel cell converts hydrogen, or hydrogen-containing fuels, directly into electrical energy plus heat through the electrochemical reaction of hydrogen and oxygen into water.

Hydrogen can be blended in the natural gas infrastructure up to a certain percentage without major problems – between 5-20% by volume, as demonstrated by the research project NaturalHy – co-financed by European Commission.

A European-wide understanding on the acceptable hydrogen content in natural gas is needed as a basis for a future gas quality harmonization.

Currently the injection limits range from 0.1% vol in Great Britain, to 2% vol in Denmark, to 6% vol in France, to 10% vol in Germany (2% vol in case that there is a CNG station downstream).

Although in theory the two (hydrogen and natural gas) can be mixed in any proportion, when blending hydrogen with natural gas, the differences in their properties should be considered.

The ASSET study "Sectoral integration – long-term perspective in the EU energy system" estimated that, in a basic decarbonization scenario (assuming that the climate and energy targets for 2030 as proposed by the European Commission in the Winter Package are met), important amounts of energy and industrial process emissions would still exist in 2050.

In order to achieve deep decarbonization by 2050 in line with a 1.5°C target as per the Paris Agreement, would require stronger sectoral measures and higher levels of sectoral integration. In this context, hydrogen could play a key role.

A balanced scenario was designed considering a mix of hydrogen up to 15% in the gas distribution grids, together with amounts of bio-methane and clean methane.

For example, numerous studies revealed that several steels and alloys pipeline materials are prone to hydrogen embrittlement. The impact of hydrogen natural gas mixtures on the operation of the network is also being considered. In longer term the existence and operation of pure hydrogen infrastructure can be also envisaged.

ș Hydrogen produced from renewables

Hydrogen – in particular through electrolysis – details follows in the chapters below- represents a great potential in this context: excess energy is stored in gas, then injected into the existing grid and distributed to end users at different locations.

Thanks to its various applications, hydrogen can enable sectorial integration:

already used in fuel cells electric vehicles

good potential in the railway system and in the maritime sector.

It could enable the integration between the energy and the industrial sectors, namely for those sectors which have a large hydrogen demand (e.g. fertilizers industry, refineries and steel production).

Another product of P2G is methane (obtained by coupling hydrogen and carbon dioxide), which has similar properties to natural gas (NG) and is called synthetic natural gas (SNG). This way, P2G can reduce the dependence of certain countries on imported NG.

ș Hydrogen and the natural gas network

The scientific and technical community has become increasingly aware that the injection of hydrogen from renewable sources into the natural gas network would effectively allow transport and storage infrastructure to indirectly contribute to the storage and achievement of the electricity decarbonization targets.

There are two semi-distinct topics of approach:

(1) hydrogen injection at the transmission and distribution level (for energy storage and sustainability);

(2) methanisation and injection of synthetic methane gas into the transmission / distribution network.

Gas networks are traditionally managed to ensure the safety, technical integrity of the system and gas quality parameters for natural gas.

Hydrogen as an energy carrier that can be stored and used to reduce carbon dioxide emissions is not yet fully accepted at the network level and there are very different limits for the percentage of hydrogen accepted in national gas grids, there is a lack of a coherent or coherent policy and regulatory framework to allow for the injection of hydrogen into the grid.

ș Mechanisms and tools to finance Hydrogen projects

There are many ways of funding Hydrogen projects including research& innovation field. The most well-known today’s mechanism for financing energy and transport businesses is Connecting Europe Facility (CEF) – programing period 2014-2020.

(1) THE CONNECTING EUROPE FACILITY (CEF) is a key European Union funding instrument to promote growth, jobs and competitiveness through targeted infrastructure investment at European level.

It supports the development of high performing, sustainable and efficiently interconnected trans-European networks in the fields of transport, energy and digital services. CEF investments fill the missing links in Europe's energy, transport and digital backbone.

The Connecting Europe Facility (CEF) for Transport is the funding instrument to realize European transport infrastructure policy. It aims at supporting investments in building new transport infrastructure in Europe or rehabilitating and upgrading the existing one. TEN-T policy objectives foresee:

completion by 2030 of the Core Network, structured around nine multimodal Core Network Corridors.

completion by 2050 of the Comprehensive Network in order to facilitate accessibility to all European regions

CEF Transport focuses on cross-border projects and projects aiming at removing bottlenecks or bridging missing links in various sections of the Core Network and on the Comprehensive Network (link), as well as for horizontal priorities such as traffic management systems.  CEF Transport also supports innovation in the transport system in order to improve the use of infrastructure, reduce the environmental impact of transport, enhance energy efficiency and increase safety. The total budget for CEF Transport is €24.05 billion for the period 2014-2020. INEA is responsible for implementing €22.4 billion of the CEF Transport budget in the forms of grants during the same period.

(2) EUROPEAN FUND FOR STRATEGIC INVESTMENTS (EFSI) – 2014-2020.

EFSI is an initiative launched jointly by the EIB Group – the European Investment Bank and European Investment Fund – and the European Commission to help overcome the current investment gap in the EU.

EFSI is one of the three pillars of the Investment Plan for Europe that aims to revive investment in strategic projects around the continent to ensure that money reaches the real economy.

With EFSI support, the EIB Group is providing funding for economically viable projects, especially for projects with a higher risk profile than usually taken on by the Bank.

EFSI is focusing on sectors of key importance for the European economy, including:

Strategic infrastructure including digital, transport and energy

Education, research, development and innovation

Renewable energy and resource efficiency

Support for small and mid-sized businesses

Looking forward: 2021-2027

Building on the success of the EFSI while taking into account the European Court of Auditors (ECA) recommendations for improvements, the InvestEU Programme will be set up under the new MFF. It will consolidate under one roof the EU financial instruments and EFSI and all the related advisory facilities. It will make EU funding and advice for investment projects simpler, more efficient and more flexible, promoting a coherent approach to financing EU policy objectives. A €11.5 billion Union guarantee will be allocated to the Sustainable Infrastructure Window (SIW), one of InvestEU‘s four policy priorities, expected to mobilize €185 billion. DG MOVE and DG ENER will co-chair the Sustainable Infrastructure Window.

(3) INVEST EU – post 2021

The Invest EU Programme will bring together under one roof the multitude of EU financial instruments currently available to support investment in the EU, making EU funding for investment projects in Europe simpler, more efficient and more flexible.

The Invest EU Programme consists of 3 pillars:

Invest EU Fund

Invest EU Advisory Hub

Invest EU Portal

It will further boost job creation and support investment and innovation in the EU.

Invest EU will run between 2021 and 2027 and it builds on the success of the Juncker Plan's European Fund for Strategic Investments (EFSI) by providing an EU budget guarantee to support investment and access to finance in the EU.

Invest EU aims to trigger €650 billion in additional investment.

The Invest EU Fund will support four policy areas:

sustainable infrastructure;

research, innovation and digitization;

small and medium-sized businesses;

social investment and skills.

Invest EU will also be flexible: it will have the ability to react to market changes and policy priorities that change over time.

(4) STRUCTURAL & INVESTMENT FUNDS & National / MEMBER STATES FINANCING PROGRAMS

Every European Union region may benefit from the European Regional Development Fund (ERDF) and European Social Fund (ESF).

However, only the less developed regions may receive support from the third instrument Cohesion Fund.

Five main Funds work together to support economic development across all EU countries, in line with the objectives of the Europe 2020 strategy:

European Regional Development Fund (ERDF)

European Social Fund (ESF)

Cohesion Fund (CF)

European Agricultural Fund for Rural Development (EAFRD)

European Maritime and Fisheries Fund (EMFF)

(5) OTHER APPROPIATE FINANCE INSTRUMENTS & LOAN TYPES

Business Loans ș International Commercial ș International Business ș Corporate Loans ș Commercial Land Development ș Stock Loans ș Lines Of Credit ș Hard Money ș Fixed Rates ș Construction Loans ș Acquisition & Development ș Equity Financing ș Remodel-Renovation ș Joint Ventures ș Green Energy Loans ș Foreign Nationals Cross Collateral ș Distressed Borrowers ș Bridge Loans ș Corporate Trusts and Partnerships ș Blanket Loans ș Equipment & Machinery ș SBLC's (Standby Letter of Credit)

Chapter II. Sector analysis. Safety and security

Case studies. American scientists’ approach

ș II.1. About hydrogen; safety and security of using as a fuel

For over 40 years, industry has used hydrogen in vast quantities as an industrial chemical and fuel for space exploration. During that time, industry has developed an infrastructure to produce, store, transport and utilize hydrogen safely.

Hydrogen is no more or less dangerous than other flammable fuels, including gasoline and natural gas!

In fact, some of hydrogen’s differences actually provide safety benefits compared to gasoline or other fuels. However, all flammable fuels must be handled responsibly.

Like gasoline and natural gas, hydrogen is flammable and can behave dangerously under specific conditions.

Hydrogen can be handled safely when simple guidelines are observed and the user has an understanding of its behavior.

Most notable differences compared to gasoline/other fuels

Hydrogen is lighter than air and diffuses rapidly

Hydrogen has a rapid diffusivity, 3.8 times faster than natural gas, which means that
when released, it dilutes quickly into a non-flammable concentration.
Hydrogen rises 2 times faster than helium and 6 times faster than natural gas at a speed of almost 45 mph (20m/s).

Therefore, unless a roof, a poorly ventilated room or some other structure contains the rising gas, the laws of physics prevent hydrogen from lingering near a leak (or near people using hydrogen-fueled equipment).

Simply stated, to become a fire hazard, hydrogen must first be confined – but as the lightest element in the universe, confining hydrogen is very difficult. Industry takes these properties into account when designing structures where hydrogen will be used.

The designs help hydrogen escape up and away from the user in case of an unexpected release.

Hydrogen is odorless, colorless and tasteless

In this respect most human senses won’t help to detect a leak. However, given hydrogen’s tendency to rise quickly, a hydrogen leak indoors would briefly collect on the
ceiling and eventually move towards the corners and away from where
any nose might detect it. For that and other reasons, industry often uses hydrogen sensors to help detect hydrogen leaks and has maintained a high safety record using them for decades.

By comparison, natural gas is also odorless, colorless and tasteless, but industry adds a sulfur-containing odorant, called mercaptan, to make it detectable by people.

Currently, all known odorants contaminate fuel cells (a popular application for hydrogen).

Researchers are investigating other methods that might be used for hydrogen detection: tracers, new odorant technology, advanced sensors and others.

Hydrogen flames have low radiant heat

Hydrogen combustion primarily produces heat and water. Due to the absence of carbon and the presence of heat absorbing water vapor created when hydrogen
burns, a hydrogen fire has significantly less radiant heat compared to a
hydrocarbon fire. Since the flame emits low levels of heat near the flame (the
flame itself is just as hot), the risk of secondary fires is lower. This fact has a significant impact for the public and rescue workers.

Hydrogen Combustion

Like any flammable fuel, hydrogen can combust. But hydrogen’s buoyancy, diffusivity and small molecular size make it difficult to contain and create a combustible situation.

In order for a hydrogen fire to occur, an adequate concentration of hydrogen, the presence of an ignition source and the right amount of oxidizer (like oxygen) must be present at the same time. Hydrogen has a wide flammability range (4-74% in air) and the energy required to ignite hydrogen (0.02mJ) can be very low.

However, at low concentrations (below 10%) the energy required to ignite hydrogen is high–similar to the energy required to ignite natural gas and gasoline in their respective flammability ranges—making hydrogen realistically more difficult to ignite near the lower flammability limit. On the other hand, if conditions exist where the hydrogen concentration increased toward the stoichiometric (most easily ignited) mixture of 29% hydrogen (in air), the ignition energy drops to about one fifteenth of that required to ignite natural gas (or one tenth for gasoline).

See Figure below for more fuel comparisons.

Explosion

An explosion cannot occur in a tank or any contained location that contains only hydrogen.

An oxidizer, such as oxygen must be present in a concentration of at least 10% pure oxygen or 41% air. Hydrogen can be explosive at concentrations of 18.3- 59% and although the range is wide, it is important to remember that gasoline can present a more dangerous potential than hydrogen since the potential for explosion occurs with gasoline at much lower concentrations, 1.1- 3.3%. Furthermore, there is very little likelihood that hydrogen will explode in open air, due to its tendency to rise quickly. This is the opposite of what we find for heavier gases such as propane or gasoline fumes, which hover near the ground, creating a greater danger for explosion.

Asphyxiation

With the exception of oxygen, any gas can cause asphyxiation. In most scenarios, hydrogen’s buoyancy and diffusivity make hydrogen unlikely to be confined where asphyxiation might occur.

Toxicity/poison

Hydrogen is non-toxic and non-poisonous. It will not contaminate methods that might be used for hydrogen detection: tracers, new odorant technology, advanced sensors and others.

Conclusions: Industry has developed new safety designs and equipment because hydrogen’s properties and behavior are different than the fuels we use now. Hydrogen will make us re-think operating practices already in place for gaseous and liquid fuels. Education of those differences is the key enabler to making hydrogen a consumer-handled fuel that we use safely and responsibly.

ș II.2. CASE STUDIES

Hydrogen in the gas network

Preamble. Renewable energy sources (RES) would have to move into the center stage of the energy mix in order to achieve long term de-carbonization by 2050.

In electricity generation the share of RES will be as high as 80 to 100% in certain regions. RES electricity could therefore become a main vector for decarbonizing the economy.

For this to happen we need to ensure that adequate systems of security and flexibility are in place to integrate it in the future energy system in an optimal way.

From the perspective of integration of higher shares of RES electricity, the opportunity offered by Power to Heat (P2H) and by Power to Gas (P2G) appears to be essential. The P2G technology was pioneered in Japan producing hydrogen from seawater electrolysis, and then developed in Denmark and Netherlands and more recently in Germany, France, USA and Canada.

Hydrogen produced from renewables (in particular through electrolysis) represents a great potential in this context:

excess energy is stored in gas, then injected into the existing grid and distributed to end users at different locations.

Thanks to its various applications, hydrogen can enable sectorial integration: it is already used in fuel cells electric vehicles, and has a good potential in the railway system and in the maritime sector. It could enable the integration between the energy and the industrial sectors, namely for those sectors which have a large hydrogen demand – e.g. fertilizers industry, refineries and steel production.

Another product of P2G is methane (obtained by coupling hydrogen and carbon dioxide), which has similar properties to natural gas (NG) and is called synthetic natural gas (SNG). This way, P2G can reduce the dependence of certain countries on imported NG.

Opportunities. As a stable chemical, hydrogen can be stored for long time without degradation under pressure. Hydrogen is miscible with other gases and can be injected into the existing NG grid. In theory, hydrogen and NG can be mixed in any proportion, but the resulting blend should be compatible with existing NG transmission and distribution infrastructure, as well as end-use equipment specifics.

Chemical storage can provide storage services over various timeframes (up to days and weeks), depending on the specific application.

Hydrogen could be stored at a low cost for example in salt caverns in very large amounts.

The potential is significant, as the underground storage sites for methane (NG) in Europe (EU-28) have a capacity of approximately 1200 TWh (see the Figure below), while the annual electricity generation from all sources in 2014 was around 3000 TWh. The addition of hydrogen into NG is the only energy storage concept that addresses energy storage in a range >100 GWh . Subsequently, hydrogen can be used in transport, in carbon intensive industries, or converted back to electricity (by 2030 it is estimated to be the most cost-effective power-to-power storage option for time frames of seasonal storage, over 2000 hours).

Storage capacity in European Union: electric vehicles vs gas infrastructure (source Energinet). The gas storage capacity is 60 times the capacity that could be provided by batteries for electric vehicles.

The gas industry is also becoming increasingly interested in contributing to the decarbonization effort and in developing plans compatible with sustainable energy transitions. Integrating renewable gases, either biomethane or green hydrogen or SNG would represent a sustainable pathway and a new business model.

From the point of view of RES electricity integration, the blending of green hydrogen into the gas infrastructure would offer significant benefits. Electricity grids represent a potential source of revenues via the provision of balancing services through electrolysis.

The gas infrastructure can help store and transport higher amounts of energy for the same capital costs as the electricity networks. The ratio is in the range of 15 more energy capacity via the gas infrastructure then via high voltage lines.

While there are more elements to take into account in deciding the most effective way to transport the energy, this still points to an untapped potential so far.

Challenges

Hydrogen can be blended in the natural gas infrastructure up to a certain percentage without major problems (between 5-20% by volume, as demonstrated by the EC research project NaturalHy).

A European-wide understanding on the acceptable hydrogen content in natural gas is needed as a basis for a future gas quality harmonization.

Currently the injection limits range from 0.1%vol in Great Britain, to 2% vol in Denmark, to: 6%vol in France, to 10%vol in Germany (2%vol in case that there is a CNG station downstream). Although in theory the two can be mixed in any proportion, when blending hydrogen with NG, the differences in their properties should be considered.

Cable versus Pipeline cost (source prof. Ad Van Wijk, Delft University of Technology)

The ratio can vary widely depending on the application and it would also identify how much hydrogen must be produce to satisfy the energy storage need.

The hydrogen tolerance of infrastructure components, end-user appliances and the effect on the system as a whole (e.g. effects on capacity) needs to be agreed upon, and is currently in the focus of CEN/CENELEC standardization objectives.

For example, numerous studies revealed that several steels and alloys pipeline materials are prone to hydrogen embrittlement. The impact of hydrogen natural gas mixtures on the operation of the network is also being considered. In longer term the existence and operation of pure hydrogen infrastructure can be also envisaged.

The business model of hydrogen infrastructure is similar to the business model of gas distribution. Unsupported private investment is rather unlikely to be able to develop the network at a full scale. This is due to the uncertainty regarding the size and the pace of development of the hydrogen market, which requires large-scale distribution to develop.

The ASSET study "Sectoral integration – long-term perspective in the EU energy system" estimated that, in a basic decarbonization scenario (assuming that the climate and energy targets for 2030 as proposed by the EC in the Winter Package are met), important amounts of energy and industrial process emissions would still exist in 2050. In order to achieve deep decarbonization by 2050 in line with a 1.5°C target as per the Paris agreement, would require stronger sectoral measures and higher levels of sectoral integration. In this context, hydrogen could play a key role. A balanced scenario was designed considering a mix of hydrogen up to 15% in the gas distribution grids, together with amounts of bio-methane and clean methane.

European research

Several initiatives are ongoing in Europe in order to prepare the natural gas networks for hydrogen injection, for example the HYREADY project led by DNV GL, the H21 Leeds City Gate and the HyDeploy projects in UK.

In the Netherlands, Akzo Nobel (paints and chemicals maker) and Gasunie (gas network operator) plan to build Europe’s largest green hydrogen production plant, consisting of a 20-megawatt (MW) water electrolysis unit that would produce around 3,000 tons of green hydrogen each year.

This hydrogen can either be used by Akzo’s specialty chemicals division or be sold to third parties, such as public transport companies using hydrogen buses.

GASUNIE is also planning to convert a gas transport pipeline to transport hydrogen for industrial use between Dow Benelux and Yara.

ș II.3. USA scientist’s overview: Market Potential – Pipeline Hydrogen

Market potential

Today, the industry sector represents over 99% of the entire hydrogen market.

Major consumers of hydrogen are petroleum refining (47%) and fertilizer production (45%).

The US alone produces 10 million metric tons of hydrogen each year, and steam methane reformation accounts for 95% of that production. (Fraile,2015).

In the future, hydrogen could play a significant role in connecting different layers of infrastructure in a low-carbon energy system.

The market potential of hydrogen as a fuel is closely linked to the advancement of hydrogen fuel cells and electrolyzers with large opportunities for it to be used on a large scale in renewable electricity integration, power-to-gas, and eventually for mobility.

Global demand is expected to grow from 43 Mtons in 2010 to 53 Mtons by 2030 with Europe representing 16% of the hydrogen global market. (Fraile,2015)

Comparison of the energy system today and in the future

(International Energy Agency, 2015)

The Hydrogen Council estimates that by 2030, 230-250 TWh of surplus solar and wind energy will be converted to hydrogen (Hydrogen Council, 2017).

As much as 1/5th of total energy consumed by 2050 can be from hydrogen (Mehta, 2018). Countries have made commitments to advance and promote hydrogen as a fuel.

Following the tsunami and nuclear disaster, Japan announced that the 2020 Tokyo Olympics will showcase thousands of hydrogen fuel cell vehicles. (Mehta, 2018)

A Toyota plant that is manufacturing fuel cell stacks already. Japan will import hydrogen, with Australia being a front-runner, using plentiful coal supply to make hydrogen and capturing the resulting carbon dioxide emissions.

In Europe, transportation demand for hydrogen is expected to be concentrated in light-duty vehicles, mainly in Germany and the UK.

Estimated hydrogen injection based on 1% and 2% blending

(International Energy Agency, 2015)

The demand by market segment will be dependent on the strength of the regulatory framework and market incentives. It is also dependent on the ability to produce hydrogen cost effectively.

POWER-TO-GAS (P2G)

Electrolysis

Power-to-gas (P2G) is an umbrella term for technologies that convert electrical energy into gas fuel, most commonly hydrogen gas (Wikiwand Power-to-Gas, 2018).

P2G is important to PG&E for 2 major reasons:

If the electrical energy converted to gas is renewably generated (say from wind or solar), then the gas generated is also renewable in nature, potentially reducing the GHG intensity of gas generated by PG&E. PG&E is also uniquely optimized to explore these technologies because it is an integrated gas and electric utility.

It can maximize the benefits of P2G not just for gas, but also to the electric grid, particularly the added-value of the gas system as high capacity storage for an electric generation portfolio increasingly dominated by renewable energy.

While there are several mechanisms for generating power to gas, the most common and mature technology for Hydrogen generation is Electrolysis

Path of Electrolysis (SoCalGas, 2018)

Electrolysis uses an electric current to split water into hydrogen gas and breathable oxygen. This reaction takes place in an electrolyzer.

Most electrolyzers consist of two electrodes or plates that are placed in water, and a DC electric current is connected to both sides.

Hydrogen appears at the cathode (where the electrons enter the water) and oxygen forms at the anode. The efficiency of this process can be increased by adding an electrolyte (like salt) to the water or through the use of electro-catalysts. (Wikiwand Electrolysis of Water, 2018)

There are three main types of electrolyzers as shown below:

Safe and efficient distribution to consumers

The use of hydrogen gas as a renewable and practical energy carrier partly depends on whether it can be distributed safely and efficiently to consumers.

The existing natural gas piping infrastructure could provide that means if it is compatible. However, a network designed for natural gas can’t be used for pure hydrogen without major modifications to network components or the way it is operated and maintained.

The existing natural gas transmission, distribution and end use systems could be used for mixtures of natural gas and hydrogen given appropriate adaptations.

The key concern with hydrogen injection into a utility natural gas pipeline system is safety, especially in regards to the integrity management of the pipeline infrastructure. While the performance of the gas in end-use appliances is of significant concern.

The physical and chemical properties of hydrogen differ from natural gas, so adding a certain percentage of hydrogen may impact combustion properties, diffusion into pipeline materials, carbon steel oxidation, and how the gas mixture behaves in air.

In order to achieve a reasonable expectation of safety, many steps must be taken by the natural gas utility to inspect and fortify the system to match the needs of hydrogen injection

Hydrogen interconnection/standards

According to the International Energy Agency (IEA), blending hydrogen in the natural gas pipeline system necessitates, “upper blending limits of around 20% to 30%, depending on the pipeline pressure and regional specification of steel quality.”

This is primarily due to Hydrogen’s ability to embrittle steel, or more precisely, accelerate crack growth particularly in steel welds. (International Energy Agency, 2015). Additionally, since Hydrogen has a much lower energy density than Natural Gas, more volume of hydrogen is needed to generate the same amount of energy as natural gas.

At 20% volumetric blend share, flow rate needs to be increased by around 15% to provide the same energy to the customer.”

Maximum allowable operating pressure standards (MAOP), Hydrogen’s tendency to embrittle and accelerate crack growth in steel welds, and hydrogen’s performance at the point of customer demand combine to throttle the potential upper limits of hydrogen blending without significant infrastructure adjustments. (International Energy Agency, 2015).

Limitations on the blend share of hydrogen by application – the most important applications to the blend share are gas
turbines, compressing stations and CNG tanks

According to a GTI study, “Blending Hydrogen into Natural Gas Pipeline Networks: A Review of Key Issues,” a quantitative risk assessment indicated blending of hydrogen up to 20% in distribution mains and services was not significant.

That same study indicated that up to 50% blended hydrogen would have a moderate risk increase on average, but that in some discrete areas, the risk could be quite severe, and anything above that level becomes prohibitive with distribution mains and services designed for natural gas. (Melaina, 2013).

Hydrogen fuel cells and fuel cell vehicles

Hydrogen Fuel Cells are designed to produce electricity from Hydrogen, and are most commonly used for transportation.

Principle of fuel cells

Hydrogen Fuel Cell Vehicle

Below is a graphic from the US National Renewable Energy Laboratory (NREL) on the hydrogen supply chain and various potential uses for hydrogen in the modern energy economy:

Potential uses for hydrogen in the modern energy economy

The future of technology

Successful technologies or processes will address the following:

● Get around the inefficiency of generating or converting electricity to hydrogen, or hy-drogen to methane or vice-versa

● Provide infrastructure for natural gas pipelines that is also resistant to H2 embrittle-ment

● Monitor, measure, or offer integrity management tools for Hydrogen, specifically

● Develop products that fill out the downstream market demand for hydrogen in a safe and flexible way (i.e. appliances that can handle hydrogen as well as gas, H2 fuel cell cars)

● Identify a cheaper method or a new method of separating methane and hydrogen from the blended pipeline gas

Macro Challenges (High Level)

Hydrogen is a brave new world. While it offers a great deal of promise, it also comes with a great deal of risk, associated with the lack of knowledge and experience around hydrogen injection into natural gas pipelines. Much of the “facts” used to justify arguments for or against hydrogen in utility pipelines are based primarily on theoretical assumptions, because very few projects of this type operate worldwide, and nearly all are extremely recent demonstration projects.

However, here are some of the Key challenges that utilities can widely anticipate needing to address before establishing injection projects for hydrogen.

6 KEY CHALLENGES

• Hydrogen Embrittlement and Corrosion – Hydrogen has an active electron, and can easily migrate into the crystal structure of most metals. Therefore, steel pipes – particularly the steel welds – used for transmission pipeline infrastructure can suffer from embrittlement and cracking after continuous exposure to hydrogen. Any pipe transporting hydrogen (or any metal exposed to it) must be resistant to corrosion or cracking.

• Needed Monitoring and Measurement Tools for Hydrogen

Most hydrogen is transported today in dedicated Hydrogen pipelines, and natural gas pipelines have not needed to be retrofitted to accommodate the needs of hydrogen. Using utility pipeline systems implies the need for certain types of safety features that either do not exist or are as yet undeveloped. There is need for a hydrogen odorant (none exist at present).

Utilities need leak detection and monitoring devices that are either specifically designed for hydrogen or can detect both hydrogen and methane.

• Efficiency of Hydrogen Generation or Separation

While Hydrogen is theoretically an excellent form of renewable energy storage, physical and chemical realities mean that any P2G option is extremely inefficient. The conversion of electricity to gas is itself an entropic process.

While 70% efficiency for electrolysis is comparable to the round-trip efficiency of lithium-ion batteries, hydrogen can only be used when burned, or when methanated into natural gas, both of which further degrade the efficiency of hydrogen use.

Specifically: Generating Hydrogen from renewable energy through electrolysis is 70% efficient. Converting it to methane reduces the efficiency even further to around 54%. If burned, the energy generated could be even 50% less than that (25% of the original electricity). If used in a fuel cell it could have a slightly better efficiency of 60%, for about 30% of the total electricity. (International Energy Agency, 2015)

Questions to the scientists and experts (Wikiwand Power-to-Gas, 2018):

– Are there alternative methods that offer better efficiencies?

– Is there a clever way to produce and use hydrogen that allows us to circumvent these rules?

• Current Appliances were Designed for Methane, not Hydrogen

End-use appliances for residential customers (and to an extent, commercial customers) were designed around the chemical properties of methane, not hydrogen. How will hydrogen blending impact the safe use or lifecycle of appliances?

• Hydrogen Market Development Path is Risky

Hydrogen has a great deal of potential, but much of it rests on infrastructure development that does not yet exist – hydrogen-tolerant pipeline networks, hydrogen refueling infrastructure, hydrogen generation facilities, etc. Taking fuel cell EVs as an example, it is estimated that it could cost $900-$1,900 of investment per FCEV to develop necessary support structures until 2050 (Starling, 2015).

This challenge falls into the chicken-and-egg paradigm, where few wishes to make these sizeable investments in infrastructure required to support the market without seeing growth, and in turn, the market does not grow without the supporting infrastructure.

Being the first to make these investments is a significant risk, without sure uptake of demand for hydrogen products after that investment has been made.

Few companies have the capacity to make this kind of high volume, expensive, up-front, high risk investments.

Instead, coalitions such as the Hydrogen Council have been forming around Hydrogen suppliers to reduce the risk of going-it-alone, but they have yet to see significant pro-gress at this time.

• Much is still unknown

While Hydrogen is generated in significant amounts in the USA, there are a vanishingly small number of projects that have injected hydrogen into the gas pipeline system throughout the world (only 1 so far in the United States), and all those have come in the last few years.

Few demonstration projects are running in Europe such as P2G Ibbenbüren and WindGas Falkenhagen in Germany, HyDeploy in the UK and Juniper in France. (Navas, 2017).

There is a striking need to develop engineering, safety, and gas quality standards around Hydrogen that simply do not exist yet.

Hydrogen pipeline systems; USA state of play- American experts’ opinion

The use of hydrogen in the energy sector of the United States is projected to increase
significantly in the future. Current uses are predominantly in the petroleum refining sector, with hydrogen also being used in the manufacture of chemicals and other specialized products.

Growth in hydrogen consumption is likely to appear in the refining sector, where greater quantities of hydrogen will be required as the quality of the raw crude decreases, and in the mining and processing of tar sands and other energy resources that are not currently used at a significant level.

Furthermore, the use of hydrogen as a transportation fuel has been proposed both by automobile manufacturers and the federal government.

Assuming that the use of hydrogen will significantly increase in the future, there would be a corresponding need to transport this material.

A variety of production technologies are available for making hydrogen, and there are equally varied raw materials.

Potential raw materials include natural gas, coal, nuclear fuel, and renewables such as solar, wind, or wave energy. As these raw materials are not uniformly distributed throughout the United States, it would be necessary to transport either the raw materials or the hydrogen long distances to the appropriate markets.

While hydrogen may be transported in a number of possible forms,
pipelines currently appear to be the most economical means of moving it in large quantities over great distances.

One means of controlling hydrogen pipeline costs is to use common rights-of way (ROWs) whenever feasible.

Many of the features of hydrogen pipelines are similar to those of natural gas
pipelines. Furthermore, as hydrogen pipeline networks expand, many of the same construction and operating features of natural gas networks would be replicated.

As a result, the description of hydrogen pipelines will be very similar to that of natural gas pipelines.

Similarities and differences between the two pipeline networks

Location of production centers

Hydrogen production units need to have ready access to natural gas. Production centers could possibly change to lie along coastlines, rivers, lakes, or rail lines, should nuclear power or coal become a significant energy source for hydrogen production processes.

Should electrolysis become a dominant process for hydrogen production, water availability would be an additional factor in the location of production facilities.

Once produced, hydrogen must be transported to markets. A key obstacle to making hydrogen fuel widely available is the scale of expansion needed to serve additional markets.

Developing a hydrogen transmission and distribution infrastructure would be one of the challenges to be faced if the decision is to move toward a hydrogen economy. Initial uses of hydrogen are likely to involve a variety of transmission and distribution methods.

Transmission and distribution methods

Smaller users would probably use truck transport, with the hydrogen being in either the liquid or gaseous form. Larger users, however, would likely consider using pipelines. This option would require specially constructed pipelines and the associated infrastructure.

Historical data, evolution, analysis and estimates in USA and Europe

Pipeline transmission of hydrogen dates back to late 1930s. These pipelines have generally operated at less than 1,000 pounds per square inch (psi), with a good safety record.
Estimates of the existing hydrogen transmission system in the United States range from about 450 to 800 miles.

Estimates for Europe range from about 700 to 1,100 miles (Mohipour et al.
2004; Amos 1998).

These seemingly large ranges result from using differing criteria in determining pipeline distances.

For example, some analysts consider only pipelines above a certain diameter as transmission lines. Others count only those pipelines that transport hydrogen from a producer to a customer (e.g., those pipelines designed for in-plant transport of hydrogen for use as feedstock or fuel are not counted).

Operational status and hydrogen purity levels are also factors in defining these ranges. Hydrogen pipelines in the United States are predominantly along the Gulf Coast and connect major hydrogen producers with well-established, long-term customers. These hydrogen transmission systems pall by comparison with the 180,000-mile natural gas transmission pipeline.

Since 1939, Germany has had a 130-mile pipeline carrying 20,000 lb/hour of hydrogen in a 10-inch pipe at 290 psi gauge (psig).

The longest hydrogen pipeline in Europe is owned by Air Liquide and extends 250 miles from Northern France to Belgium.

In theory, a blend of up to 20% hydrogen in natural gas can be transported without
modifying natural gas pipelines (Oney et al. 1994).

Modifying the same pipelines to carry pure hydrogen, however, requires addressing a number of issues, including the potential for embrittlement of some steels and sealing difficulties at fittings that are tight enough to prevent natural gas from escaping, but possibly not hydrogen. Regardless of these materials issues, construction of new pipelines to carry hydrogen could benefit from joint use of existing ROWs for natural gas distribution.

Hydrogen pipeline systems

Common facility characteristics

Hydrogen pipeline systems are fundamentally the same as natural gas systems, in that they involve similar components such as transmission pipelines, compressor stati-ons, and city gates.

Transmission pipelines

Design requirements for hydrogen pipelines are still evolving. Most hydrogen pipelines are designed to transport hydrogen only short distances, from the production facility to the end user. Many such applications typically represent only a few hundred feet of pipeline and operate with maximum pressures of considerably less than the 1,000-psi absolute (psia) or more that would likely be required for long-distance pipeline transmission of hydrogen. The safety record for these pipelines is considered to be very good.

The definition of required safety margins, codes, and standards for application to large-scale hydrogen transport remains a work in progress.

Design parameters

However, based on the design parameters of some hydrogen pipelines and on expe-rience with natural gas pipelines, it is reasonable to suggest some design parame-ters that could very well be applicable to the flow rates, distances, and pressures asso-ciated with long-distance transmission of hydrogen via pipeline.

At a given pressure, the energy density of hydrogen is approximately one-third that of natural gas.

Anyway, for the same pipe diameter and pressure, hydrogen flows approximately three times as fast as natural gas. As a result, if hydrogen compressors could be operated to meet similar pressure requirements as natural gas compressors, it could be expected that hydrogen pipe diameters would approach those for natural gas transmission pipelines. As noted in the discussion of natural gas pipelines, pipe diameters of up to 48 inches are seen.

Actual hydrogen pipeline diameters would of course depend on hydrogen demand, the pressures achievable, and codes and standards that are yet to be developed.

Experts suggests that existing natural gas pipelines could be converted to hydrogen use. However, in addition to the issue of compressor power noted above, there are questions as to whether fittings, gaskets, and other materials designed for natural gas pipelines could withstand hydrogen diffusion.

Materials for pipelines

Historically, carbon steel or stainless steel has been used to transport hydrogen. Gray, ductile, or cast iron and nickel steels have been used but are not considered suitable for high pressure hydrogen transmission (Mohipour et al. 2004).

Austenitic stainless steels, aluminum (including alloys), copper (including alloys), and titanium (including alloys) are generally applicable for most hydrogen service applications.

High-strength steels (above 100 ksi) are more susceptible to hydrogen embrittlement, so the use of thicker, low-strength steels is sometimes recommended for hydrogen pipelines. Polymer/fiberglass-reinforced pipes have been used in specific applications such as for in-plant piping at moderate temperatures.

As is the case with natural gas pipelines, welding is the preferred joint technology for hydrogen pipelines.

Questions to be resolved before hydrogen pipelines can be economically built is that of potential hydrogen embrittlement, which tends to occur with higher strength steels.

Additional questions such as loss of material strength, fracture toughness, enhanced fatigue crack growth rates, low cycle fatigue, subcritical and sustained load cracking, susceptibility to stress corrosion cracking, and hydrogen-induced cracking in welds and joints must also be answered before there can be a large-scale application of hydrogen pipelines.

Although design requirements for hydrogen pipelines have yet to be established, some reasonable assumptions can be made. These assumptions are based on operating experience with both natural gas and hydrogen and on the expectations for large-scale hydrogen delivery. For example, it can be reasonably assumed that hydrogen pipelines will be constructed of carbon or stainless-steel Schedule 40 welded pipe.

Consistent with official requirements and conventional practice, the top of the pipe will be at least 30 inches below ground, and the pipe will sit on a 4- to 12-inch crushed rock or soft clay base. Again, consistent with conventional practice, it can be assumed that the pipe would be precoated on its exterior with a fusion-bond epoxy or a polyethylene sleeve to inhibit corrosion.

As with natural gas pipelines, it is likely that standards promulgated by the American Petroleum Institute would be used in the construction and operation of hydrogen pipelines.

Compressor stations

As noted above, the volumetric energy density of hydrogen gas is only about one-third that of natural gas at the same pressure.

Because compressors operate on the basis of volume rather than energy content, considerably higher compression horsepower would be required to move comparable amounts of energy as compared to the power requirements for a natural gas system.

Hydrogen is difficult to compress, as it consists of very small molecules, so positive displacement compressors are typically used.

Materials

Hydrogen compressors are expensive due to the required materials, the physical size needed to supply the needed compression power, and the redundancy needed to provide reliability. Hydrogen compressors must have tight tolerances and/or special seals to reach the pressures required for high-volume transmission.

At elevated pressure and temperature, hydrogen can permeate carbon steel, resulting in decarburization.

Conventional mild steel has been used as pipeline material in Germany and France since 1938, and alloy steels with chromium and molybdenum have been suggested as compressor materials.

Multistage reciprocating machines to produce pressures of 700 to 1,000 psig are considered state-of-the-art, and additional research and development activities are under way in both the private and public sectors. These units have high maintenance costs due to wearing components such as valves, rider bands, and piston rings (Drnevich 2003).

These compressors are typically nonlubricated (oil-free) so as to reduce the poten-tial for oil contamination of the hydrogen (Mintz et al. 2002).

Current reciprocating compressors are costly, are subject to excessive wear, have poor reliability, and often use lubricants that can contaminate the hydrogen.

Research is currently under way to minimize moving parts and to address wear through new designs (centrifugal, linear, guided rotor, and electrochemical) and improved compressor materials. In selecting equipment for pipelines, it should be noted that centrifugal compressors create more operating problems than reciprocating compressors.

Considering the relative lightness of hydrogen, its recompression ratio is four times lower than for natural gas for a given rotor speed (Bossel 2003). This necessitates a greater number of stages.

Because of its low specific gravity, hydrogen tends to return to the compressor inlet of centrifugal compressors, thereby limiting their efficiency.

Three to five stages of compression are required to deliver hydrogen at pipeline pressures because water-cooled positive-displacement compressors can achieve a pressure ratio of only about 3 per stage.

Compressor stations are powered by compressors that are each rated at several thousand horsepower.

Most compressor stations are fully automated. The compressors are typically housed in a metal building with pipe appurtenances and other critical elements above ground.

If the hydrogen pipeline shared a common corridor with a natural gas pipeline or an electricity transmission line, it would be comparatively easy to bleed some natural gas or electricity to energize the hydrogen compressor. Alternatively, a quantity of hydrogen could be fed to the compressor for the same purpose.

The spacing between hydrogen compressors along a pipeline would be determined by operational and economic factors.

It is likely that the spacing between hydrogen compressors would be equal to or greater than the 60 to 160 km common for natural gas transmission pipelines (NGTP).

Costs

Hydrogen compressors have both high capital investment costs and high operating costs. It is generally assumed that this equipment would have to be subjected to a significant (i.e., costly) overhaul every few years.

Hydrogen compressors are the subject of several research and development programs – supported by European Union and private sector- with the expectation that more definitive information on their cost and performance characteristics can be developed.

Metering stations

Although details of hydrogen transmission pipelines have yet to be developed, it is likely that metering stations would be placed along the pipelines. In a manner similar to that for natural gas pipelines, these metering stations would allow pipeline companies to monitor and manage the hydrogen in their pipes.

Essentially, these metering stations measure the flow rate and pressure of the hy-drogen along the pipeline, thus allowing pipeline companies to track it as it flows along the pipeline.

(l) City gate stations

The potential uses for large quantities of hydrogen are as a feedstock or fuel for industrial facilities or as a transportation fuel. In either case, it is likely that hydrogen pressure would have to be reduced from transmission pipeline levels to distribution system levels.

In a manner similar to that for natural gas systems, pressure regulators would likely be used to control the hydrogen flow rate through the station and to maintain the desi-red pressure in the distribution system.

Should it be decided to add any additives to the hydrogen as it enters a distribution system, such as the odorant added to natural gas, it is likely that this would be done at the city gate stations.

(m) Valves

Interstate pipelines include a great number of valves along their entire length. These valves work like gateways; they are usually open and allow hydrogen to flow freely, but they could be used to stop the flow along a certain section of pipe. Due to the small molecular size of hydrogen, considerable research and development has been directed toward the development of effective valves.

This component of a hydrogen pipeline network is likely to be considerably more expensive than the corresponding valves in natural gas pipelines due to tighter tolerances and possibly more costly materials of construction.

(n) PIG launching/Receiving facilities

As with natural gas pipelines, hydrogen pipelines are likely to have pig launching and receiving equipment to allow the pipeline to accommodate a high-resolution internal inspection tool.

“Pigs” are devices that are placed inside a pipe to clean the inside of the pipeline and/or to monitor its condition.

Launchers and receivers are facilities that enable pigs to be inserted into or removed from the pipeline.

(o) SCADA CENTERS

Hydrogen pipeline networks can be expected to have supervisory control and data acquisition (SCADA) systems that are similar to those for natural gas pipeline networks.

The basic objective of such a system is to monitor conditions (e.g., flow rate, pressure, temperature, and valve positions) throughout the pipeline network and make any necessary changes in these conditions.

(p) TELECOMMUNICATIONS TOWERS

In all SCADA systems, the master terminal unit (MTU) and remote terminal units (RTUs) communicate through a defined network of some type, requiring telecommunications towers. Hydrogen pipeline network SCADA systems would have similar requirements.

(r) ACCESS ROADS

Hydrogen pipelines would require access roads for construction, operations, and
maintenance activities. These roads would be constructed and maintained in exactly the same manner as for natural gas pipelines. If the hydrogen pipeline shares a ROW with a natural gas pipeline and/or an electricity transmission line, the access roads would be shared

Chapter III. CEF TRANSPORT BLENDING FACILITY.

GRANTS. ELIGIBILITY. CEF PROJECTS EXAMPLES

III.1. Blending Facility

The CEF Transport Blending Facility is an innovative approach to promote the substantial participation of private sector investors and financial institutions in projects contributing to the environmental sustainability and efficiency of the transport sector in Europe.

The CEF Transport Blending Facility will support two areas which deliver on the Commission's agenda for a clean and digital transport system:

Deployment of the European Railway Traffic Management System (ERTMS)

Deployment of Alternative Fuels

It is implemented via a cooperation framework between the European Commission and Implementing Partners to support Blending Operations, i.e. investments combining the use of grants and/or financial instruments from the EU budget and financing from the Implementing Partners (via a loan, debt, equity or any other repayable form of support).

In the context of the CEF Transport Blending Facility, the European Investment Bank (EIB) will be the first Implementing Partner upon the signature of an operational agreement with the EC. Other entities, such as national promotional banks, may be entrusted in the future. The European Commission is currently negotiating agreements to define the respective involvement of other potential Implementing Partners.

With a budget of €198 million, the grant component of the Blending Operations under the CEF Transport Blending Facility is managed by the Innovation and Networks Executive Agency (INEA). Promoters can only apply for the CEF TBF grants with the support of the EIB or other implementing partners. Implementing Partners will screen potential operations for their eligibility for a CEF TBF grant.

They will share the pipeline of potentially eligible operations with the EC. Later, the Implementing Partner will facilitate the CEF TBF Application File.

A dedicated rolling call for proposals was published in July 2019 with quarterly cut-off dates until March 2021, unless the budget is exhausted earlier.

Call opening: autumn 2019

Grant Application form submitted by the Applicant, together with Application files submitted by the Implementing Partners will be evaluated by the European Commission after each cut-off date.

Application process and role of the Implementing Partners

Project promoters must engage first with an Implementing Partner, which performs an initial screening of each project to be potentially supported by financing from the Implementing Partner and, additionally, a grant component (CEF TBF Blending Operation), in order to be included in the CEF TBF Project Pipeline.

As a second step, the Implementing Partner engages with the project promoter to conduct the necessary appraisal in order to obtain the approval of the Implementing Partner’s governing bodies for the project, included in the CEF TBF Pipeline.

The relevant results of this appraisal are summarized in the Project Report and Eligibility Check List, which will become part of the Application File. The promoter will prepare a Grant Application form, which will also become part of the Application File.

The Application File may only be submitted in the context of the approval of the financing of the Implementing Partners governing bodies. The complete Application File (consisting of the Eligibility Check List, Project Report and the Grant Application form) will then be evaluated by the European Commission in order to decide on the award of the grant.

The Commission, the EIB and other Implementing Partners will collaborate closely to allow for a first submission of grant applications towards year-end 2019.

Project promoters can already now approach the EIB to discuss possibilities of EIB financing.

The complete Application File to the grant component can only be submitted however, after the related financing has been approved by the EIB’s relevant governing bodies.

In this context project promoters may receive advice through the European Investment Advisory Hub.

III.2. CONNECTING EUROPE FACILITY (CEF) – ELIGIBILITY OF COSTS. BUSINESS PLAN FOR A PROJECT – example

III.2.1. ELIGIBILITY OF COSTS

Regarding the eligibility of costs in the projects co-financed by the European Commission through INEA I will refer only to some Eligible Costs and Ineligible Costs.

The information is compliant with Guidelines (by EU Commission’s INEA) on the Eligibility of Costs under the Connecting Europe Facility – December 2018

ELIGIBILITY of COSTS is established by GENERAL REQUIREMENTS which defines 'eligible costs' in Article II.19.1 as costs actually incurred which meet all of the criteria indicated. Those criteria are cumulative: if a cost does not comply with all of them, such cost is ineligible.

As well ELIGIBILITY of COSTS is also discussed in the chapter SPECIFIC CATEGORIES of COSTS. This section discusses certain categories of costs, such as

Personnel Costs, travel, etc

As for INELIGIBLE COSTS, they are multiple and great care must be taken because they value the beneficiary's contribution from their own sources. I mention some ineligible costs below:

Return on capital and dividends paid by a beneficiary

Debt and debt service charges

Provisions for losses or debts

Interest owed

Doubtful debts

Exchange losses

Costs of transfers from the Agency charged by the bank of a beneficiary

Contributions in kind from third parties

Short comments on other INELIGIBLE COSTS as well:

Costs declared by the beneficiary in the framework of another action receiving a grant financed from the Union budget (including grants awarded by a Member State and financed from the Union budget and grants awarded by other bodies than the Commission for the purpose of implementing the Union budget).

Excessive or reckless expenditure

In practice, when assessing expenditure from this perspective, it can evaluate by: – benchmarking the price paid with that of the market for similar services/goods/works, or for internal costs by compared those incurred in the past for similar items/events; – considering the link with and the necessity to the action.

Deductible VAT. Deductible VAT is neutral to the beneficiary as it can be recovered by deducting this cost from the beneficiary's VAT liabilities.

Costs of land and building acquisition (including expropriation costs). However, for Cohesion envelope, costs of purchase15 of land (developed or not) may be eligible, up to 10 % of the total eligible costs of the action (15% for derelict sites and sites formerly in industrial use, which comprise buildings)16. (m) Indirect costs – for CEF Transport and CEF Energy.

III.2.2. A CEF indicated BUSINESS PLAN comprise inter alia:

Introduction

Project description

Objectives considered in project implementation

SWOT Analysis

Market survey

Evidence on TSO Consultations and Results of the Consultations

Investment and operational costs

Identification of the financing options

The financing structures

Equity (internal financing sources)

Debt (external financing sources)

The financial discount rates

Depreciation, residual value

Revenues

Results of the financial analysis based on the Business Plan

Financial performance indicators

Financial sustainability

Economic analysis – assumptions and results

And ANEXES and Tables

III.3. PROJECTS CO-FINANCED BY CEF – EXAMPLES

Hydrogen as an alternative fuel

Coordinator: Akuo Energy SAS (France)

Status: Ongoing

Transport corridor: Atlantic, Mediterranean, North Sea – Mediterranean

Transport mode: Road Last modified: August 2019

Subject: The Action aims to support zero-emission mobility through hydrogen technology for actors of the last mile logistics, namely the final segment of goods transportation. The Action will deploy 33 hydrogen charging stations and 400 Fuel Cell Electric Vehicles in France along three Core Network Corridors: Atlantic, Mediterranean and North Sea-Mediterranean and four urban nodes of the Core Network: Paris, Lyon, Marseille and Bordeaux.

The Action is aligned with France's "Mobilité Hydrogene France" hydrogen deployment roadmap, which aims to deploy 600 hydrogen refueling stations in the country by 2030. The Action will support the take up of hydrogen as an alternative fuel.

Models for Economic Hydrogen Refueling Infrastructure

Coordinator: Element Energy Ltd (United Kingdom) http://www.element-energy.co.uk/

Status: Ongoing

Transport corridor: North Sea – Baltic, North Sea – Mediterranean, Rhine – Alpine, Scandinavian – Mediterranean

Transport mode: Road Last modified:  August 2019

Subject: The Action aims to demonstrate a new demand-led commercial model for the deployment of hydrogen refueling stations, by carrying out a test of economies and practicalities of operating large hydrogen refueling stations.

The Action consists of a study with a real-life trial of large hydrogen stations in 7 different locations in Germany (Hürth, Wermelskirchen-Koln, Wuppertal, Italy (Bruneck/Brunico), the Netherlands (Oude Tongue – South Rotterdam) and the UK(London and Birmingham) along the North-Sea Mediterranean, North Sea Baltic, Rhine- Alpine and Scandinavian-Mediterranean Corridors.

A minimum of 10 operating hydrogen buses per station will operate on a daily basis. Buses will be co-funded by the Fuel Cell and Hydrogen Joint Undertaking under the JIVE project (735582 — JIVE — H2020-JTI-FCH-2016). Despite the focus is on the bus, during the Action stations will be progressively capable of refueling other kinds of vehicle

The Action includes the deployment of the stations, the operation of buses and stations, studies on the operations and on the bankability of the stations to boast the deployment and dissemination of Action results.

TSO 2020: Electric “Transmission and Storage Options” along TEN-E and TEN-T corridors for 2020

Coordinator: N.V. Nederlandse Gasunie (Netherlands); http://www.gasunie.nl

Status: Ongoing Energy corridor: Northern Seas offshore grid

Energy sector: Electricity Project of Common Interest:1.5

Transport corridor: North Sea – Baltic, Rhine – Alpine

Additional information:

– European Commission – Transport: http://ec.europa.eu/transport

– European Commission – Energy http://ec.europa.eu/energy/infrastructure/index_en.htm

– Innovation and Networks Executive Agency (INEA)
http://ec.europa.eu/inea

– European Network of Transmission System Operators for Electricity (ENTSO-E) www.entsoe.eu

Last modified: August 2019

Subject: The Action contributes to the implementation of the TEN-E Project of Common Interest (PCI) 1.5 Interconnection between Endrup (DK) and Eemshaven (NL) (known as COBRA cable) and of the TEN-T core networks on the North Sea-Baltic and Rhine-Alpine corridors.

The main objective of the Action is, first, to demonstrate the technical and commercial viability of power to hydrogen solutions in the context of the Groningen region (NL), and second, to assess the replicability of the solutions to other regions. These solutions are to simultaneously balance the intermittent power input from the COBRA cable and to develop the use of hydrogen for transport applications along the TEN-T corridors.

The scope of the Action entails: electricity grid stability studies; the commissioning and testing of a power-to-hydrogen pilot and of a hydrogen storage and transport pilot; a Cost-Benefit Analysis of the power-to-hydrogen solution; an analysis to scale-up to mass application; communication and visibility activities; and the management of the Action.

Upon completion of the Action, the deployment of grid management solutions to facilitate the implementation of the COBRA cable is planned, together with establishing a hydrogen production and distribution network in Groningen and neighbouring regions connected to the TEN-T network.

Zero Emission Valley

Coordinator:

Conseil Régional Auvergne-Rhône-Alpes (France) https://www.auvergnerhonealpes.fr

Status: Ongoing

Transport corridor: Mediterranean, North Sea – Mediterranean, Other Sections on the Core Network

Transport mode: Road

Last modified: August 2019

Subject: The overall objective of this Action is to foster fuel cell electric vehicle use in France, significantly contributing to the European alternative fuels’ implementation strategy.

The Action will deploy a network of hydrogen refuelling stations (HRS) at regional level to reach a critical mass for the market uptake, laying foundations for future national and European hydrogen mobility.

The Action consists of deploying twenty HRS, out of which fourteen will be supplied by onsite electrolysers and one thousand fuel cell vehicles in the region Auvergne-Rhône-Alpes.

"Zero Emission Valley" is aligned with France’s "H2Mobilité" programme, the roadmap to a national roll-out for hydrogen, which aims to deploy 600 HRS in the country by 2030.

Chapter IV. OVERVIEW ON SPECIFIC LEGISLATION FRAMEWORK AND EU’s COHESION POLICY

IV.1. 2030 Energy Strategy

In October 2014 The European Council agreed on a new 2030 Framework for climate and energy, including EU-wide targets and policy objectives for the period between 2020 and 2030. These targets aim to help the EU achieve a more competitive, secure and sustainable energy system and to meet its long-term 2050 greenhouse gas reductions target. The figures for renewables and energy efficiency have subsequently been increased in the context of the Clean Energy for all Europeans package.

The objective of the strategy is to send a strong signal to the market, encouraging private investment in new pipelines, electricity networks, and low-carbon technology. The targets were based on a thorough economic analysis measuring how to achieve decarbonisation by 2050in a cost-effective way.

The cost of meeting the targets does not substantially differ from the price we need to pay anyway to replace our ageing energy system. The main financial effect of decarbonisation will be to shift our spending away from fuel sources and towards low-carbon technologies.

șTargets for 2030

a 40% cut in greenhouse gas emissions compared to 1990 levels

at least a 32% share of renewable energy consumption, with an upward revisions’ clause for 2023

indicative target for an improvement in energy efficiency at EU level of at least 32.5%, following on from the existing 20% target for 2020

support the completion of the internal energy market by achieving the existing electricity interconnection target of 10% by 2020, with a view to reaching 15% by 2030

ș Policies for 2030

To meet the targets, the European Commission has proposed:

A reformed EU emissions trading scheme (ETS)

New indicators for the competitiveness and security of the energy system, such as price differences with major trading partners, diversification of supply, and interconnection capacity between EU countries

First ideas on a new governance system based on national plans for competitive, secure, and sustainable energy. These plans will follow a common EU approach. They will ensure stronger investor certainty, greater transparency, enhanced policy coherence and improved coordination across the EU.

IV.2. Directive 2014/94/EU on the deployment of alternative fuels infrastructure

Directive 2014/94/EU requires Member States to notify to the European Commission National Policy Frameworks (NPFs) for the development of the market as regards alternative fuels in the transport sector and the deployment of the relevant infrastructure.

To implement Article 10.2 of Directive 2014/94/EU, the Commission carried out an assessment of the NPFs and their coherence at Union level, including an evaluation of the level of attainment of the national targets and objectives referred to in Article 3 (1) of the Directive.

The relevant Staff Working Document SWD/2017/0365 and the accompanying Member States fiches were adopted by the Commission as part of the Clean Mobility Package (Mobility package II).

ș Alternative fuels for sustainable mobility in Europe

Today, transport still relies on oil for 94% of its energy needs. Europe imports around 87% of its crude oil and oil products from abroad, with a crude oil import bill estimated at around €187 billion in 20155, and additional costs to the environment.

Research and technological development have led to successful demonstrations of alternative fuel solutions for all transport modes. Market take-up, however, requires additional policy action.

The Clean Power for Transport package aims to facilitate the development of a single market for alternative fuels for transport in Europe:

A Communication laying out a comprehensive European alternative fuel’s strategy [COM (2013)17], for the long-term substitution of oil as energy source in all modes of transport;

A proposal for a Directive on the deployment of alternative fuels recharging and refueling infrastructure [COM (2013)18];

An accompanying Impact Assessment [SWD (2013)5];

A Staff Working Document setting out the needs in terms of market conditions, regulations, codes and standards for a broad market uptake of LNG in the shipping sector [SWD (2013)4].

The final Directive, as adopted by the European Parliament and the Council on 29 September 2014 following the inter-institutional negotiations:

Requires Member States to develop national policy frameworks for the market development of alternative fuels and their infrastructure;

Foresees the use of common technical specifications for recharging and refueling stations;

Paves the way for setting up appropriate consumer information on alternative fuels, including a clear and sound price comparison methodology.

ș Special remarks

The required coverage and the timings by which this coverage must be put in place is as follows:

“alternative fuels” means fuels or power sources which serve, at least partly, as a substitute for fossil oil sources in the energy supply to transport and which have the potential to contribute to its decarbonisation and enhance the environmental performance of the transport sector, they include, inter alia:

(a) electricity

(b) hydrogen

(c) biofuels

(d) synthetic and paraffinic fuels

(e) natural gas, including biomethane, in gaseous form (compressed natural gas (“CNG”))

(f) liquefied petroleum gas (“LPG”)

Hydrogen refueling point 6. An infrastructure operator who operates hydrogen refueling points accessible to the public, shall ensure that connectors for motor vehicles for the refueling of gaseous hydrogen conform with:

(a) the ISO 17268 gaseous hydrogen motor vehicle refueling connection devices standard

(b) the ISO 14687 hydrogen purity standard

Article 5. Hydrogen supply for road transport

a) Member States which decide to include hydrogen refueling points accessible to the public in their national policy frameworks shall ensure that, by 31 December 2025, an appropriate number of such points are available, to ensure the circulation of hydrogen-powered motor vehicles, including fuel cell vehicles, within networks determined by those Member States, including, where appropriate, cross-border links.

b) Member States shall ensure that hydrogen refueling points accessible to the public deployed or renewed as from 18 November 2017 comply with the technical specifications set out in point 2 of Annex II.

c) The Commission shall be empowered to adopt delegated acts in accordance with Article 8 to update the references to the standards referred to in the technical specifications set out in point 2 of Annex II where those standards are replaced by new versions thereof adopted by the relevant standardization organizations.

IV.3. COMMISSION STAFF WORKING DOCUMENT – February 2019

Report on the Assessment of the Member States National Policy Frameworks for the development of the market as regards alternative fuels in the transport sector and the deployment of the relevant infrastructure pursuant to Article 10 (2) of Directive 2014/94/EU

Relevant information for Netherland, Poland, Portugal, Slovakia, Romania

IV.3.1. Brief on Romania

The declared objectives of the Romanian NPF are reducing the impact of the transport sector on the environment, enhancing transport efficiency and fostering economic growth in the sector of alternative fuels. Romania reached already in 2015, its national target for 2020 of 24% of energy from renewable energy sources in the gross final consumption of energy and seeks to reach also the target of 10 %
renewable energy sources in the final energy consumption in transport in 2020.

However, Romania is lagging behind in terms of project implementation and development of the CNG and Hydrogen sectors.

The RO national targets and objectives regarding alternative fuels infrastructure

IV.4. Cohesion policy of the European Union 2021-2027

Within the next EU long-term budget for 2021-2027, the Commission proposes to modernize cohesion policy, the EU's main investment policy.

Five investment priorities:

Investments in regional development will focus mainly on objectives 1 and 2. These priorities will be allocated 65% – 85% of ERDF and Cohesion Fund resources, depending on the relative prosperity of the Member States.

ș A smarter Europe, through innovation, digitization, economic transformation and supporting small and medium-sized enterprises

ș A greener Europe without carbon emissions, implementation of the Paris Agreement and investments in energy transition, energy from renewable sources and combating climate change

ș A connected Europe, with strategic transport and digital networks

ș A more social Europe, to realize the European pillar of social rights and to support the quality of jobs, education, skills, social inclusion and equal access to the health system.

ș A Europe closer to its citizens, by supporting locally driven development strategies and sustainable urban development in the EU.

Cohesion policy continues investments in all regions, based on 3 categories (less developed, in transition, more developed). The method of allocating funds is still largely based on GDP per capita. New criteria are introduced (youth unemployment, low level of education, climate change and the reception and integration of migrants), to better reflect the reality on the ground. The outermost regions will continue to receive special support from the EU. Cohesion policy continues to support locally led development strategies and to empower local authorities to manage funds. The urban dimension of cohesion policy also increases, by allocating 6% of the ERDF to sustainable urban development and through a new network collaboration and capacity building program dedicated to urban authorities, under the name European Urban Initiative.

IV. 5. International Energy Agency vision

The Future of Hydrogen. Report prepared by the IEA for the G20, Japan- July 2019

Hydrogen trade in Europe in the 2030 timeframe

Extensive opportunities are open for hydrogen trade between countries in Europe. The gas grid is the most likely vehicle for such trade, but dedicated cross-border pipelines or internal waterways could also be used. Trade in hydrogen as well as electricity could help smooth low carbon energy supplies between countries and help match low-cost supplies with demand, and imported hydrogen might be competitive with local production (Chapter 3).

This is especially true for electrolysis hydrogen from renewables:

– production in North Africa from dedicated renewable electricity might have import costs in the near future as low as USD 4.7/kgH2 for over 500 MtH2/yr,60 which compares favorably with USD 4.9/kgH2 from renewable electricity in much of Europe. Hydrogen from natural gas with CCUS could also be imported from the Middle East at competitive costs as low as USD 2/kgH2 as ammonia, or USD 2.6/kgH2 if cracked to pure hydrogen.

If CO2 storage is equally accessible in Europe at similar costs, however, it is likely to be more cost-effective to import the gas and produce hydrogen in Europe. Natural gas can be imported with local conversion to hydrogen with CCUS at a cost of around USD 2.3/kgH2.

Energy trade with these regions is a pillar of European neighborhood policy, and is expected to remain so. To support this policy objective the European Union supports energy infrastructure investments in Africa and the Middle East. These regions are included in the scope of the European Neighborhood Instrument, which has a budget of over EUR 15 billion for 2014 to 2020.

The Africa–EU Energy Partnership’s energy security objectives include doubling electricity interconnections and African gas exports to EU by 2020 compared to 2010. The European Union already imports around 12–14% of its gas demand from North Africa (mainly Algeria), although it is not yet clear whether these pipelines could be repurposed cost-effectively to carry hydrogen at shares above a few per cent.

Near-term policy priorities

Targets and long-term policy signals.

Alignment of countries’ national hydrogen strategies and roadmaps via bilateral and multilateral partnerships would help the management of risks at both ends of the value chain.

Demand creation.

Imported hydrogen can be used in many sectors, but end users will only switch to hydrogen, or hydrogen-based products, if it is cost-effective to do so. Governments could help make hydrogen cost-effective in target sectors by using portfolio standards, mandates, performance standards, tax exemptions and CO2 pricing.

Exporting countries could stimulate early exports by providing time-limited support to buyers. Infrastructure costs might be minimised by tendering programmes with international support. Reaching sufficient demand to justify investment in import and export terminals, and hydrogen supplies, might similarly be best achieved through international co-operation.

Investment risk mitigation.

The first commercial-scale hydrogen export and import infrastructure projects will represent sizeable investments and may benefit from being structured as public–private partnerships with some direct public investment and multi-stage competitions to award contracts. In some cases, risks might best be managed by taking a modular approach and starting with funding smaller projects that reassure financers, although this might well not be effective for infrastructure such as tankers and storage facilities. Subsequent projects should benefit significantly from the exchange of learning and knowledge from the first projects, insofar as these need not be commercially confidential. It would be very helpful for risk management to have early clarity from governments on the question of tariffs, and to have clear permitting processes in place for hydrogen imports, especially for large, capital-intensive infrastructure projects in first-of-a-kind industries.

R&D, strategic demonstration projects and knowledge sharing.

Uncertainty remains about the most effective type of carrier for shipping hydrogen, with much scope for thorough investigation of the options and improvement of efficiency and capital costs. Liquefaction efficiency, boil-off management, scalability and the efficiency of the cooling cycle require improvement. Strategic demonstration projects could target the scale-up of liquefaction and regasification facilities for hydrogen directly or in the form of ammonia.

Harmonizing standards, removing barriers.

International standardization will be crucial in this value chain, including for “guarantees of origin”, 61 hydrogen purity, the design of liquefaction/conversion and regasification/reconversion facilities, and for equipment specifications. Some IMO regulations may need to be revised and new ones established.

Chapter V. CONCLUSIONS AND RECOMMENDATIONS

Further to GRTgaz request, this REPORT intends to contribute to the development of the concept of Hydrogen businesses, projects in energy field focused on Hydrogen; production, storage and hydrogen as a fuel, containing important remarks on the transportation of hydrogen – by dedicate pipelines and by the Gas Transmission Systems.

Furthermore, the Report present case studies and international scientific approach on hydrogen sector.

This Report present also an overview of the essentials of the financing support for the sector coming from European Union, financial instruments and the European money dedicated to some of the Member States by specific national programs with specific examples of projects already financed or in on going procedure.

This work is an original concept, comprise and is the result of a deep analysis of various studies on Hydrogen elaborated in the last years corelated with updates / actual information on the subject by the most important European and international experts and scientists.

Important Note! This Report is not public!

The report is the result of the analysis of dozens of studies, reports and published documents, the result of the research work and represents the author's own evaluation in the line established by the beneficiary. Some bibliographic documents have a closed circuit – dedicated only to research work. The report is a working document only to facilitate decision making regarding the approaches of the projects in the use of hydrogen as a clean energy source for today and tomorrow.

The author: Ciprian Octavian ALIC

APPENDIX 1

USA: Hydrogen – fuel for vehicles – about hydrogen stations

Industrial gas merchants in North America produce more than 15 million kilograms of hydrogen a day, mostly for oil refineries and manufacturing, and deliver it by pipeline, truck, rail, and barge. Hydrogen can also be produced from a variety of renewable sources.

Hydrogen stations have a choice of having hydrogen delivered as a liquid, delivered as a gas, or making hydrogen on site.

Hydrogen stations are designed to be self-service and operate similarly to fueling with compressed natural gas.

Stations for cars are designed for consumer retail sales (accept credit cards, adhere to state standards for measurement and fuel quality).

Stations for heavy-duty vehicles and material handling equipment may use a PIN or key to identify the person fueling.

When a vehicle operator activates the dispenser, hydrogen flows from the storage tanks to the dispenser and through the nozzle into the vehicle in a closed system. Initial safety checks ensure the integrity of the system before fueling starts.

During the fill, the dispenser is designed to pause periodically for several seconds to conduct additional integrity checks, according to code and/or fuel protocol, and then resume filling.

Most vehicles have a standardized communication system that sends parameters from the vehicle’s fuel storage system to the dispenser, which are used to calculate the pressure to stop the fill at a “full” tank. A car can fill up in less than five minutes.

Hydrogen stations are in operation and under construction for light-duty vehicles (passenger vehicles), heavy-duty vehicles (trucks and buses), and material handling equipment. Stations dispense hydrogen as a compressed gas at pressures of 10,000 psi (H70) for light-duty vehicles and 5,000 psi (H35) for all other vehicles.

Stations examples

All stations generally have the same equipment, but station employs different designs depending on how the hydrogen is produced, delivered, stored and dispensed.

See some explanation and pictures below….

(1) Stations for light-duty vehicles are mostly retail stations—open 24/7, have unattended fueling, accept common credit/debit payment methods, and are conveniently located primarily at existing gas stations. Fuel cell cars fill their tanks in under five minutes

(2) Transit buses and trucks typically use private fleet or truck-stop-like stations and fill their large tanks in about 10 minutes. It is unlikely that heavy-duty vehicles will use passenger vehicle stations.

(3) Stations for material handling equipment often have the storage and compression outside, but the dispenser inside the warehouse or factory. Operators self-fuel the vehicles in about three minutes using H35 hydrogen.

At hydrogen stations with liquid storage, a tanker truck pumps hydrogen into an above-ground tank where it’s held at a cryogenic temperature. Liquid hydrogen is vaporized, compressed, and stored in above-ground cylinders for dispensing. As customers fuel their vehicles, the gaseous hydrogen cylinders are refilled. Liquid storage generally requires more space than gaseous storage.

Hydrogen can be delivered as a gas at pressures up to 7,200 psi. Cylinders are mounted into a trailer and the truck driver “refills” the storage by swapping a trailer of full cylinders for a trailer of almost-empty cylinders inside a walled storage area.

.

Stations can also make hydrogen onsite by electrolysis of water and reforming natural gas or biomethane. At some locations, a station could use hydrogen from an existing pipeline. All three methods result in gaseous hydrogen that must be compressed and stored, and all require more equipment and space than either option for delivered hydrogen. One of the advantages to renewable hydrogen is the future opportunity to sell Low Carbon Fuel Standard credits.

Safety

Hydrogen is a non-toxic, environmentally benign natural element has been safely used in manufacturing for more than 90 years. It is a very small, diffusive molecule that is 14 times lighter than air. Like all fuels, hydrogen is flammable and safety systems at the station and in the vehicle are designed for hydrogen’s properties.

Hydrogen stations have standardized safety systems that include grounding, breakaway hoses, and fire sensors that are common for all fueling stations, plus sensors that measure pressure, temperature, and leakage of gaseous hydrogen. Stations are designed to safely vent hydrogen in case of an extreme emergency, such as a gasoline fire that increases the temperature of the stored hydrogen. Although the illustration shows a passenger vehicle, stations for heavy-duty and material handling vehicles use the same safety standards and systems.

i

APPENDIX 2

THERMODYNAMIC ANALYSIS OF HYDROGEN PIPELINE TRANSPORTATION –SELECTED ASPECTS

Today, hydrogen is considered by industry as a fuel of the future, which may successfully replace conventional, non-renewable fuels.

Because of this fact hydrogen is perceived as an efficient source of environmental-friendly energy.

Presenting the idea of using the hydrogen as a substitute of hydrocarbons is a forward thinking, because there are no large-scale hydrogen production methods, which would be effective, economically justified and less time consuming to produce amounts required by industry.

Actually, the hydrogen is obtained from thermo-chemical processes, which main source of power is a combustion of coal, natural gas or oil. Unfortunately, the resources of hydrocarbons are limited, this is why the industry should focus on diversified types of fuels.

The way of obtaining the hydrogen is not the only one issue that should be faced by industry, because there is a necessity of development effective methods of its transportation and storage. This type of fuel can be stored as a gas under the pressure or a liquid (hydrides, carbonaceous materials) which is not a leading issue, because those methods are used today and all action needed to be taken is to adapt them to store bigger amounts of hydrogen. A not effective truck transportation is more problematic issue, because can provide a limited fuel volume on a relative short distance.

This is the main reason why the industry should focus on a hydrogen pipeline transportation. For transportation of hydrogen the special dedicated pipeline network can be developed.

Furthermore, using the natural gas pipelines for hydrogen transport should be considered as a component of natural gas. Industry practice shows that effective pipeline transport of hydrogen is possible also as a natural gas mixture component. Natural gas pipelines are long distance pipelines with high maximum operating pressure. The most important advantage of pipeline networks is their availability.

Nowadays this type of transport is expensive and used for a short distance only. Despite this fact some countries are considering a conversion of their natural gas pipelines for hydrogen transportation.

Using existing infrastructure, the transportation of hydrogen would be definitely cheaper than building special dedicated pipelines.

However, there are some disadvantages of using natural gas pipelines. Hydrogen has a higher ability to penetrate through construction materials of gas pipelines than natural gas. Moreover, hydrogen is highly corrosive. This fact requires that additional material research for pipeline steel should be performed. Those issues would require some special improvements that will protect pipelines from negative influence of hydrogen.

The flow of the pure hydrogen and bi-component mixtures of methane and hydrogen was analyzed especially for a pressure drops during the transportation in the pipeline. Increasing interest in hydrogen as a new medium of storage an excess energy is the main issue why pipeline transportation (for long distances in short time) becomes a challenge for scientists and engineers.

Energy transportation

Another issue of hydrogen pipeline transportation is energy transport. It has low
molar mass and consequently low density. Due to these two facts higher amount of energy is required for its compression process.

On the other hand, low pressure drops allow to minimize the number of compression stations used for hydrogen transport. Hydrogen, as additive in natural gas, has positive impact on pipeline transportation of natural gas which can be transported for longer distances. The important issue for hydrogen pipeline transportation is its energy value. Combustion heat of hydrogen per mass unit is much higher (141.9 MJ/kg) than methane (54 MJ/kg). Because of lower density hydrogen has lower heat of combustion (12.67 MJ/mn3) per volume unit in normal conditions than methane (38.55 MJ/mn3).

Conclusions

Transportation of hydrogen by pipelines is possible. It can be efficient and economically justified because of short time of transmission and large amounts that can be transported. Technical issues and assumptions were confirmed by calculations were made using developed algorithm. Pipeline inlet pressure (5 MPa) for hydrogen would require a lot of energy for compression process. According to calculation results and because of low pressure drop inlet pressure for pure hydrogen can be decreased to 2–3 MPa for presented case. Energy efficiency of hydrogen transportation is another important issue. Considering only parameters of hydrogen pipeline transportation it is obtained an incomplete picture of the energy transportation.

Hydrogen has low heating value and heat of combustion per volume unit; therefore, its transportation is less energy efficient than transmission methane or natural gas.

APPENDIX 3

Estimation Costs – Hydrogen Pipeline and Case City demand

The development of a hydrogen infrastructure is the subject of increasing research
interest. Many researchers are working toward estimating the cost of such an
infrastructure. Pipeline delivery of hydrogen is being considered but the expected costs are not well understood, as few pipelines exist today.

The question to which we want to give an appropriate answer is about the difference that hydrogen would make in the construction costs of natural gas, oil, and petroleum product transmission pipelines.

Pipeline planners are hesitant to give a generalized estimation for pipeline construction cost because it is very dependent on the location.

A pipeline through a rural area without special environmental concerns can cost five times less than a pipeline of the same length and diameter through a dense urban area.

Hydrogen pipelines add an extra level of complexity due to a relative lack of experience in installing hydrogen pipelines.

Construction costs – analyses the four categories

Materials costs account for approximately 26% of the total construction costs on average.

Labor- 45%,

Right of way up 22%,

Miscellaneous costs 7%

Materials. This is a simple analysis, looking at the dependence of each category on the length and diameter of the pipeline. First up is the materials cost. the materials cost is linearly dependent on length. The 36-inch diameter pipelines are used here as representative of the general trends because the most data exist for it.

The labor cost consistently averages between 40 and 50% while rest vary greatly
depending on diameter.

Miscellaneous costs are all costs not included in labor, material, or right of way. They generally include surveying, engineering, supervision, contingencies, allowances, overhead, and filing fees.

New Materials for Hydrogen Pipelines; Researchers and experts Objectives are to:

Investigate the use of fiber-reinforced polymer (FRP) pipeline technology for transmission and distribution of hydrogen, to achieve reduced installation costs, improved reliability and safer operation of hydrogen pipelines.

Develop polymeric nanocomposite with dramatically reduced hydrogen permeance for use as the barrier/ liner in non-metallic hydrogen pipelines.

Gas pipelines are at present the lowest cost option for transmitting large quantities of hydrogen. However, the existing hydrogen pipeline technology cannot be extrapolated to achieve the cost and performance goals required for successful implementation of this distribution network.

Fiber-reinforced polymer (FRP) pipelines are emerging as a feasible alternative to steel pipelines with regard to performance and cost.

Case City demand

Today, spoolable composite piping is readily available in sizes up to four-inch ID, with pressure ratings to 3,000 PSI for the four-inch pipe. Larger composite pipes are contemplated and are therefore considered in this analysis. It is assumed that
hydrogen enters a 200-mile long pipeline at 1,000 PSI pressure and the allowable pressure drop is 300 PSI. As estimated above, time-averaged demand is assumed to be 0.5 kg H2 per day per capita. However, as with electricity, the demand is not constant in time, so an assumption that peak demand is 1.5 times average demand was made.

Case 1

For a city population of 100,000, peak demand would be approximately 3,000 kg H2/h.
Five parallel spoolable, 4-inch diameter pipes or a single 8-inch diameter pipe will serve this city’s demand.

Case 2

For a city population of 1,000,000, peak demand will be approximately 30,000 kg H2/h. In this case, 50 parallel 4-inch diameter pipes, 9 parallel
8-inch diameter pipes, 3 parallel 12-inch diameter pipes, or a single 18-inch diameter pipe would be required.

Case 3

For a metropolitan area with a population of 10,000,000, peak demand will be about 300,000 kg H2/h. Such a large population likely will have to be served by multiple hydrogen generating stations, so it is likely that such a large population would be served by several pipelines similar to Case 2. If it is served by a single pipeline, that line would consist of 500 parallel 4-inch diameter pipes, or 90 parallel 8-inch diameter pipes, 30 parallel 12-inch diameter pipes, or a single 44-inch diameter pipe.

APPENDIX 4

Poland: WASTE HYDROGEN PIPELINES MONITORING IN MODERN POWER PLANT

Project co-financed by European Regional Development Fund (Poland) – The Innovative Economy Operational Program 2007-2013, Action No 1.4.

● Generalities

The importance of hydrogen as an energy carrier is growing. A term of hydrogen economy is even used to highlight the growing, and in the future, the dominant role of this fuel, in opposition to commonly used hydrocarbons. Hydrogen production in 2004 was about 50 million tons, which is equivalent to approximately 170 million tons of oil. Moreover, every year there is an increase of production at the level of about 10%.

The present trends show that in the future an innovative power engineering will be based on local energy sources (also small ones), which will be stored in the form of hydrogen.

● Waste hydrogen

Hydrogen is also a by-product – also called waste hydrogen – of many industrial processes like production of chlorine and caustic soda. Some of this hydrogen is reused in the production process, however significant amount that is wasted can be used as a fuel for transportation equipment and in stationary applications.

In Europe about 23bn m3 per year of by-product hydrogen is produced every year (mainly in chemical plants) and between 2 and 10 billion m3 is wasted. This amount of hydrogen would be enough to power up more than 1 million vehicles with hydrogen power cells or to produce heat and electrical power for industrial purposes

Hydrogen, which is being valuable fuel, shown at the same time many features that affect the safety of its use.

This is a consequence of such facts as:

colorless, odorless and tasteless
highly reactive with oxygen and other oxidizing agents; the ratio of hydrogen in the air, at which ignition occurs is in the wide range from 4% to 75.0%
highly explosive gas; explosion in the air can occur when the hydrogen content in the range of 18.3% to 59% by volume
a low ignition energy (0.02 mJ); it means that the mixture of hydrogen can be ignited in air by using an energy of 1/10 comparing to the fuel ignition

Many production processes in chemical industry generates hydrogen as a by-product.

Part of this is reused in the other production process, however significant amount that is wasted can be used for energy production in stationary application.

The goal of the project was development of the technology for safe exploitation of by-product hydrogen in chosen chemical plant.

During the pilot project a small power plant with electrical capacity of 1 MW was designed and constructed. Two energetic technologies were applied.

First use hydrogen and hydrocarbons as a fuel for combustion generators (leading technology), and the second one use purified hydrogen for fuel cells (complementary technology).

A big attention was put on safety aspects and structural health monitoring of the most critical elements. An innovative technology based on distributed optical fiber-based sensors for hydrogen pipeline integrity and leakage detection was applied. A temperature distribution along each of four supply gas pipelines (one with pure hydrogen to the fuel cell and three others with waste hydrogen to power generators) is permanently monitored.

The project “The use of waste hydrogen for energy purposes” is realized in Azoty Group company in Kędzierzyn-Koźle, which is one of their largest chemical plant in Poland.

The pilot project was started in 2013. The main goal was to develop a technology for exploitation of by-product hydrogen for energy production. Two methods using by-hydrogen as a fuel were implemented.

Conclusion

Presented solution of SHM system for dangerous goods pipeline monitoring is a first example of implemented system in industry area in Poland. That project has a demonstrative character, so it was planned to realize a full-scale investigation in fields of waste hydrogen power generators and SHM systems for leakage detection. Preliminary tests with pipelines monitoring were done. It was shown that applied solution is able to detect potential failures in a short time (~40 seconds) and localize it with a sufficient accuracy (2 meters). In the next step it is planned to implement software with analysis module which will be able to online analyze measurement data in a reliable way and perform automatic detection of leaks.

APPENDIX 5

Research on Hydrogen from coal

Although coal may be viewed as a dirty fuel due to its high greenhouse emissions when combusted, a strong case can be made for coal to be a major world source of clean H2 energy.

Apart from the fact that resources of coal will outlast oil and natural gas by centuries, there is a shift towards developing environmentally benign coal technologies, which can lead to high energy conversion efficiencies and low air pollution emissions as compared to conventional coal fired power generation plant.

There are currently several world research and industrial development projects in the areas of Integrated Gasification Combined Cycles (IGCC) and IGFC-Integrated Gasification Fuel Cell systems.

In such systems, there is a need to integrate complex unit operations including gasifiers, gas separation and cleaning units, water gas shift reactors, turbines, heat exchangers, steam generators and fuel cells.

IGFC systems tested in the USA, Europe and Japan employing gasifiers (Texaco, Lurgi and Eagle) and fuel cells have resulted in energy conversions at efficiency of 47.5% (HHV) which is much higher than the 30–35% efficiency of conventional coal fired power generation.

Solid oxide fuel cells (SOFC) and molten carbonate fuel cells (MCFC) are the front runners in energy production from coal gases.

These fuel cells can operate at high temperatures and are robust to gas poisoning impurities. IGCC and IGFC technologies are expensive and currently economically uncompetitive as compared to established and mature power generation technology.

However, further efficiency and technology improvements coupled with world pressures on limitation of greenhouse gases and other gaseous pollutants could make IGCC/IGFC technically and economically viable for hydrogen production and utilization in clean and environmentally benign energy systems.

APPENDIX 6

Canada: The 100 MW euro-Quebec hydro-hydrogen pilot project-updates

The 100 MW pilot project is to demonstrate the provision of clean and renewable primary energy in the form of already available hydroelectricity from Québec, converted via electrolysis into hydrogen and shipped to Europe, where it is stored and used in different ways: electricity/heat cogeneration, vehicle and aviation propulsion, steel fabrication and hydrogen enrichment of natural gas for use in industry and households.

Three transport/storage modes are investigated: methylcyclohexane as energy carrier shipped in normal oil product carriers, ammonia shipped in special tankers and liquid hydrogen shipped in special LH2 ships and airplanes.

First evaluations indicate costs of the electrolytic hydrogen, produced with hydropower at 2 Can, cents kWh−1, stored in a European port of 69 Dpfg Nm−3 for the methylcyclohexane mode, 57 Dpfg Nm−3 for the ammonia mode, 30 Dpfg Nm−3 for the LH2 mode by ship transportation and 77/68 Dpfg Nm−3 by air transportation.

These averaged equivalent costs of 20 Dpfg kWh−1 (th) of clean, renewable and stored energy suggest competitivity within the not too distant future.

Phase II, the detailed system definition, indicates the costs of the electrolytic hydrogen produced with hydropower, which would be available at 2 cents kWh−1(cents of European Unit of Account, reference price for cost calculation) shipped to and stored in a European port, as 14.8 cents kWh−1 in the form of liquid hydrogen.

The present Phase III,0 is a hydrogen demonstration programme on the utilization of hydrogen in the fields of vehicle and aviation propulsion, steel fabrication and advanced techniques of liquid hydrogen storage. This phase also involves detailed studies of safety measures and codes, along with socio-economic studies on the comparison of hydrogen with conventional fuels.

APPENDIX 7

USA: NEBRASKA MONOLITH PROJECT

– a plasma-based process for cracking hydrocarbons for the co-synthesis of carbon black and hydrogen

Following an extensive and competitive evaluation process, Monolith chose to build its first commercial manufacturing facility in Hallam, Nebraska.

The Olive Creek Plant needed a location with stable and low-cost electricity, access to an abundant supply of natural gas, a strong rail network and a partner to use the plant’s hydrogen co-product. Few locations met these criteria, and only one offered an industrious and innovative workforce that aligned with Monolith’s pre-existing values: Nebraska.

Total investment

The total capital investment for phase one of Monolith’s Olive Creek Plant will be approximately $50 million. The phase two expansion of the Olive Creek Plant will be dependent upon customer demand for Monolith’s product, and will require hundreds of millions of dollars in investment.

Monolith currently has a team based in Lincoln, Nebraska, approximately 50 people to be a part of the Olive Creek Plant Phase One Operations Team (plant operators, maintenance service technicians, engineers, lab technicians, administrative staff and a plant manager).

Plant layout at site

The Olive Creek Plant will occupy approximately 10 acres of space during phase one, with phase two expanding to approximately 40 acres.

Generalities on the project

Two important result of carbon black production: carbon black and hydrogen

Carbon black is virtually pure elemental carbon produced by incomplete combustion or thermal decomposition of gaseous or liquid hydrocarbons under controlled conditions. Its physical appearance is that of a black, finely divided pellet or powder.

It is a common, essential product found in everyday products like tires, rubbers hoses, inks, and food related items, such as plastic utensils and travel coffee mugs.

Hydrogen is the co-product in the innovative process of carbon black production. It is non-toxic, non-poisonous and will not contaminate groundwater or contribute to atmospheric pollution. There are notable differences between hydrogen and natural gas or gasoline. Hydrogen is lighter than air and diffuses rapidly. It is odorless, colorless, and tasteless.

An understanding of hydrogen and its behavior allows the beneficiary to implement protocols and guidelines to handle it safely, which are factored into the necessary design.

Construction start: October 2016. Construction activities at site are currently underway.

Advantages for local people

This partnership with Nebraska Public Power District has the potential to create 600 new jobs and hundreds of millions of dollars in new capital investment in Nebraska. It also provides Nebraskans with the opportunity to produce clean and affordable energy, reducing pollution and making everyday items greener.

Initial production capacity: 2019

Full production capacity: 2020.

Next Generation Carbon Black Production

Conventional carbon black production uses crude oil or coal tar in its process.

Instead, Monolith developed and perfected process technology that converts pipeline-grade natural gas into carbon black and clean burning hydrogen.

Result: high-grade carbon black that is manufactured and produced in the U.S.

MINES ParisTech research and joint ventures with Monolith- more than 20 years of combined research and development on this process which initiated a carbon black revolution. See below a brief description on the cooperation with the French specialists.

– Monolith has partnered with Laurent Fulcheri’s group at the Centre for Processes, Renewable Energies and Energy Systems at Mines ParisTech PSL Research University, a leading university in France. Laurent FULCHERI has spent the past 20 years researching and developing a plasma-based process for cracking hydrocarbons for the co-synthesis of carbon black and hydrogen. Laurent FULCHERI and his team actively participate in the analysis and design of Monolith’s next-generation carbon black and hydrogen process technology.

Aker Solutions – Monolith has partnered with Aker Solutions (formerly Kvaerner), a global provider of products, systems and services to the oil and gas industry. From 1991 to 2003, Aker Solutions designed and built one pilot plant in Sweden and one industrial plant in Canada that electrically converted natural gas into carbon black and hydrogen. Monolith works closely with the original design team from those projects.

Cleaner Products

Monolith’s proprietary process is a low-emission, innovative technology that creates carbon black. Natural gas is used instead of crude oil as a feedstock, making the process more efficient and significantly more environmentally-friendly than alternative methods of production.

The only co-product in this revolutionary process is plentiful hydrogen. This valuable hydrogen gas can be used in a number of processes, but most importantly, in generating clean power. The use of hydrogen for clean power generation led to our first-of-its-kind partnership with the Nebraska Public Power District (NPPD), Nebraska’s largest provider of electricity.

Applications of carbon black

Tires and Industrial Rubber Products

Carbon black has a special interaction with rubber called reinforcement. When rubber and carbon black are intimately mixed together, carbon black enables rubber to become a high-performance tire through wet traction enhancement, reduction of wear by abrasion, stiffness improvement, and many other performance advantages. The combination of rubber and carbon black has been coined “the marriage of the century” by experts in the rubber and carbon black industries. Carbon black incorporated rubber makes great products, including rubber hoses, tires, door seals, roofing components and more.

Plastics

Carbon black in the plastics industry is first and foremost used as a pigment. However, carbon black enhanced plastics also provide improved UV resistance, increased strength, and a deep black pigment with tunable blue or brown undertones. Carbon black has the properties that make everyday plastics products useful, from electrical cables to trash bags to plastic forks.

High Performance Coatings & Adhesives

Carbon black enhances UV protection and durability for coatings used in the automotive marine and aerospace industries. These coatings and adhesives enable products to last longer, have greater reliability, and resist corrosion.

Toners and Printing Ink

Carbon black is an ideal black pigment-based particle for inkjet and toner applications. Carbon black provides a blacker lustrous color when compared to iron oxide-based black or dye-based black color. Additionally, the longevity of the deep black color generated by carbon black is superior to competitive products in the industry.

Batteries and Conductive Inks

In addition to the many attractive properties previously listed, carbon black conducts electricity. Carbon black is found in everyday batteries from Nickel Metal Hydride to Lead Acid to rechargeable Lithium Ion. Carbon black provides the appropriate amount of conductivity to the active component of these battery systems. Carbon black is found in many electronic battery-based devices, including those in mobile phones, everyday electronics and disposable Lithium Ion batteries. This same conductivity enables carbon black to be an essential part of conductive inks that can be used for consumer electronics, RFID tags and systems where transition metal based conductive inks cannot be used.

APPENDIX 8

Holland: the hydrogen project HyStock – 1 MW power-to-gas installation in the Netherlands

Co-finaced by European Union- CEF ENERGY / INEA

The first 1 MW power-to-gas installation is an important step in scaling up power-to-gas technology.

EnergyStock and Gasunie New Energy aim to convert sustainable electricity into hydrogen for transport and industry at the site of EnergyStock storage facility.

The EnergyStock facility is ideally situated for this project thanks to buffer capacity and connection with the main gas and electricity infrastructure.

This pilot project, called HyStock, is the first power-to-gas facility in the Netherlands with a capacity of 1 Megawatt.

The installation has started end of 2018 and construction has been finished in May 2019.

A 1 MW solar field consisting of approximately 12,500 solar panels to be installed at EnergyStock’s site of which approximately 4,500 panels will be dedicated to the HyStock project.

The other 8,000 panels will be used to improve the green credentials of the energy consumption of the actual gas storage facility.

The majority of the sustainable energy, e.g. 88%, will be delivered to the HyStock project via TenneT’s high-voltage electricity grid, enabling energy conversion between the high voltage electricity network and the gas transmission network.

The majority of the solar panels are placed on the inside of the earth embankments around the EnergyStock facility. In addition, the parking areas of the installation are covered by a solar roof.

One megawatt of the power generated will be converted into hydrogen.

For this purpose, three containers are placed within the gates of the installation: one will contain the electrolysis unit, the second the necessary electronics, and the third a compressor that fills the storage cylinders with hydrogen. The storage cylinders will be mobile and capable of being transported to end-users (e.g. transport and industry).

The hydrogen plant including external transformers, chillers and radiators

Hydrogen as energy carrier

Green power production is expected to take off over the coming years which will create huge fluctuations between supply and demand.

Storing sustainable electricity in large quantities is a challenge: an affordable battery that would be capable of doing this reliably on a large scale has yet to be invented.

The largest operational battery is 100 MWh whilst a hydrogen cavern could hold up to 240,000 MWh.

Therefore, hydrogen offers a good solution to store large quantities of renewable energy. Together with oxygen, hydrogen is the main component in water. You can separate these two components quite easily in a CO2 neutral way using sustainable electricity.

Gasunie New Energy and EnergyStock see the conversion of power-to-gas as a promising technology in which gas infrastructure can play an important role. In the future, hydrogen will be an important clean fuel in a sustainable energy supply. Hydrogen can be used for transport for instance, as well as for industrial applications and electricity supply.

HyStock pilot project aims to contribute to the further development of the market for green hydrogen.

North Netherlands can become a hydrogen economy

Possible hydrogen storage project developments over the next five years
North Netherlands is ideally located for the pilot project HyStock. The region offers the opportunity of future large-scale storage of hydrogen in salt caverns. Through HyStock, the Gasunie subsidiaries EnergyStock and Gasunie New Energy aim to contribute, together with market parties, to the further development of the hydrogen market and apply new technologies on a larger scale. The ambition of the North Netherlands region is to become a hydrogen economy.

There are wind parks at sea, solar panels on land, and the north of the Netherlands is connected to the electricity grid in Scandinavia and Germany via intercontinental cables.

Furthermore, hydrogen is already used by industries in the Delfzijl area. Power-to-gas can play an important part in the future in balancing the grid on a continuous basis. Energy Stock is capable of constructing large amounts of storage capacity and is strategically situated between the high-voltage electricity grid and the main gas transport grid. Energy Stock is highly experienced in storage operations and wishes to cooperate fully in this energy transition. Together with Gasunie New Energy, Energy Stock aims to ensure that all valuable sustainable energy can be fully utilized.

APPENDIX 9

Project-Hypothetical Plant in Singapore: The Profitability Estimation of a 100 MW Power-to-Gas Plant-Case study

Generalities

Power to Gas (PtG) is a grid -scale energy storage technology that converts electricity into the gas fuel as an energy carrier. Specifically, it utilizes surplus renewable electricity to generate hydrogen from electrolysis with Solid
Oxide Cell (SOC), and the hydrogen is then combined with CO2 through Sabatier process to form methane.

The methane can be transported within existing natural gas pipeline or city gas pipeline for civil and commercial usages. To increase the utilization rate of the plant, it is sensible to make use of the reverse function of SOC, which is a
Solid Oxide Fuel Cell (SOFC), to generate electricity when the grid is short of power.

The energy input of this process is methane, and it is called Gas-to-Power (GtP). The energy usages of the modern world are relying on the consumption of large amount of fossil fuel.

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Case study: Estimation of the investment and operational cost of building a 100 MW PtG plant.

The hypothetical plant was assumed to be constructed in Singapore. The country is planning to raise its solar power to 1GW in the coming decades. The estimation is based on parameters from similar technologies or reasonable assumptions.

The focus is given to the relationship between Levelized Cost of Electricity (LCOE) of the PtG plant with respect to several factors (such as plant cost of investment, capacitor factor).

Two cases are considered in the study:

The first case is PtG process and the second case is PtG + GtP processes. In the first case, methane is the final product of the renewable energy storage plant.

The first case is to validate the profitability of the carbon-free energy storage technic.

In the second case, the PtG is the electricity storage process, and the GtP is the electricity generation process. The net-product of the round-trip solution is electricity.

The purpose of the second case is to study the competitive of the PtG plant to the conventional natural gas power plant.

Illustration of Power-to-Gas system.

The PtG process makes use of surplus electricity in the grid or directly from the renewable power source to produce H2 and capture CO2, and further produce methane in the methanation reactor. Methane is injected into the local gas pipeline.
Water is a by-product of the methanation reactor and can be reused in the water electrolysis process. The reverse of this system is possible by
withdrawing pipeline methane as input and reforming to H2 and CO2. The H2 is consumed in the Fuel Cell to generate electricity. The CO2 is stored for PtG process. Water is reused in the methane reforming process.

Methodology

The PtG plant consists of two major parts:

the electrolyzer and the methanation reactor. The existing technologies were taken as references for the cost estimation of the plant.

A reasonable mass production cost of SOC and its auxiliary devices is within the
range of 1100 to 1800 USD/kW. The cost of methanation reactor and its auxiliary devices was estimated from the commercial Coal-to-SNG plant from literature. The unnecessary devices such as coal gasifier and sulfur removal device in a Coal-to-SNG plant were removed from the calculation. The unit cost was then scaled up by
the plant capacity (100 MW) to get the total cost of investment (TCI) of all the facilities in the PtG plant.

To simplify the calculation, the land lease cost, infrastructure and development cost, annual fixed operating cost and variable cost of the PtG plant were scaled-down from the reported 400MW NG power plant.

The capital cost is assumed to be discounted at a rate of 6% over 25 years. The energy input of energy storage process was taken from solar power.

The solar power was assumed to have much larger capacity than 100 MW so that the PtG facility was fully used. However, the solar power itself is limited to its local environmental and geographical factors, in Singapore, the average peak sunshine time of 4.55 hours was assumed, and the sunny days in a year was assumed to be 47.1%.

For the GtP process, the capacity factor was assumed as 58.5% of 24 hours.

The gas pipeline capacity was assumed to be large enough to store and retrieve sufficient CH4 during energy storage and electricity generation periods. Finally, the Levelized Cost of Electricity (LCOE) was calculated using the annualized cost of the
whole plant divided by the total energy produced of the year. All the algebra equations are solved and visualized in Matlab.

A summary of parameters is listed in table below.

Results and Discussion

Overall, the hypothetical 100 MW PtG plant was estimated to cost around 174 million USD (annualized to about 13.6 million USD/year).

As a comparison, a typical 100 MW NG power plant costs around 100 million USD. The fixed surplus solar power is around 58 GWh/year (stored in the form of methane HHV) in case-1, and the power generation is around 260.5 GWh/year in case-2.

The Figure below (next pages) for (a) shows the components of the P2G plant annual cost.

The major components are fuel cost (37%), SOC investment cost (29%), and fixed operating cost (12%). The remaining minor components are methanation investment cost (7%), land lease and others (7%), variable cost (5%), and solar power (2%), respectively.

The fuel cost may be reduced if the place is close to NG resource. In Singapore, the NG plant consumes Liquid Natural Gas (LNG) as fuel, which is about three times the price of pipeline NG. The SOC is in its emerging stage and has large space to reduce the cost.

The same Figure below (b) shows the comparison of CO2 emission of the PtG plant with other types of power plant. The CO2 emission of PtG + GtP process is around 160~218 kg/MWh. As a comparison, the median CO2 emission of coal-based power plant and NG power plant are 820 and 490 kg/MWh CO2, respectively.

The CO2 emission of PtG plant is significantly dropped compared with the NG power plant. The carbon footprint could be further reduced with a longer period of the renewable power supply.

The plot of PtG plant LCOE changes with descending SOC investment cost is shown in Figure(c).

The orange circle marker represents the case-1 (PtG process) and the blue plus marker represents the case-2 (PtG and GtP process).

The reference NG power plant LCOE (around 93 USD/MWh) is plotted in the green line, and the electricity retail price was plotted as the red line in the figure.

Result show that the PtG case is not profitable. The PtG + GtP case is profitable for all the given SOC TCI range. The LCOE of case-2 is even approaching to the NG power plant LCOE. The profitability divergence between the two cases indicates that the fully utilization of the facility is crucial to the profitability of the plant.

In the Figure (d) shows the LCOE changes of the PtG plant with increasing capacity factor of the GtP process. The PtG plant could be more competitive than NG power plant if the capacity factor can be raised to above 80%.

Although hard to achieve, multi-regional renewable power integration and smart grid management may help to reach this high utilization rate.

Even without a high capacity factor, the PtG plant can achieve substantial revenue margin in the local electricity market.

(a) The components of annualized investment and operational cost of PtG and GtP processes. Clockwise: Solar-power for PtG process (2%), Fuel-cost for GtP process (37%), Variable-cost (5%), Fixed-cost (12%), Land and others (7%), Methanation facility (7%), SOC facility (29%). (b) The lifecycle CO2 emission of the coal-based power plant, NG power plant, PtG plant, utility-scale solar power, and onshore wind power [9]. (c) The LCOE of case-1 (PtG only) and case-2 (PtG and GtP) compared with the LCOE changes of NG power plant with descending SOC investment cost. The capacity factor of both plants is fixed at 58.5%. (d) The LCOE changes of the case-2 (PtG and GtP) with the increase of GtP capacity factor. The NG power plant with a fixed capacity factor (58.5%) is plotted as a reference.

Conclusion

In this study, we estimated the profitability of a hypothetical 100 MW Power-to-Gas plant. The PtG plant serves as pure energy storage system may not profitable in case-1 due to the high cost of SOC and the conservative setting of the solar energy supply.

The plant with both PtG and GtP processes is profitable, and even beyond the NG power plant in certain situations.

Moreover, the CO2 emission of the PtG plant is significantly dropped compared with the state-of-the-art NG power plant.

The CO2 reduction is attributed to the PtG process, where surplus renewable energy and CO2 are stored in methane. With proper grid management, even with high SOC cost, the raise of the capacity factor will make the plant competitive to NG power plant.

The scale-up of the plant may further reduce the investment cost and make this technology promising. However, the PtG plant may still require the further development of SOC to have a lower TCI, say 900 USD/kW, to achieve higher revenue and shorter payback time.

The operation mode of PtG plant may differ from NG power plant. Hence the fixed operating cost and variable cost of the plant should be studied in detail in a separate work. Moreover, SOCs are normally constructed modularly rather than centralized, the land usage of PtG plant should be evaluated differently.

As a promising emerging power generation technology, the recycling costs of SOC is another important topic to be explored. All in all, the PtG plant with energy storage and power generation process may play a vital role in the era of renewable energy.

The combination of different types of energy storage system to tackle the short-term and long-term power fluctuation might be the key to the future of renewable energy.

APPENDIX 10

Method for Producing Hydrogen from a Hydrocarbon Liquid Using Microwave In-liquid Plasma

șThe in-liquid plasma method in brief

The method represents a using technology in which plasma of several thousand degrees Kelvin is generated within bubbles in a liquid. Two types of microwave in-liquid plasma apparatus are adopted for hydrogen production.

One is a conventional MW (microwave) oven, the other is a
microwave generator with a waveguide to apply the in-liquid plasma steam reforming method in n-dodecane.

The produced gas is 58%-90% hydrogen in these methods. The hydrogen production rate is improved by stabilization of the bubble growth. The gas production rate by plasma feeding steam in n-dodecane is 1.4 times higher than that without feeding steam.

In recent years, energy consumption driven by economic growth has increased dramatically, resulting in degradation to the environment. Therefore, sources of clean energy are becoming increasingly important, in order to protect the environment while maintaining an ample energy supply. Recycling of waste from organic and non-organic materials such as household garbage, waste oil, or plastics can protect the environment by reducing the amount of waste and mitigating the effects of greenhouse gasses.

Processing organic and non-organic materials to produce hydrogen gas is a challenging task and has been studied by several researchers.

The main reason that hydrogen used as fuel is water could be its source, and hydrogen has enormous potential energy per unit mass than any other fuel.

However, hydrogen is not a primary energy source like coal, oil and natural gas, which exist in nature. Rather, it is a secondary energy source that is obtained by processing a primary energy source. Accordingly, a relatively large amount of energy is needed to extract and capture hydrogen. Electrolysis of water is the dominant method for manufacturing clean hydrogen. However, since water is an extremely stable material, creating hydrogen from this material would be required tremendous amount of energy.

Steam reforming of natural gas is another method that has been commercially used for generating large amounts of hydrogen.

However, in the steam reforming method, carbon dioxide is released in the final stage of the reaction, so provisions for capturing and storing the CO2 are required.

One method for extracting and capturing hydrogen from waste materials that has been studied in recent years is the in-liquid plasma process.

This process can produce hydrogen gas and solidified carbon simultaneously without emitting CO2.

Description and principles

However, this method is only focus on hydrogen production, which is not as productive as other methods. Based on the previous study, a conventional MW (microwave) oven is used to irradiate at 2.45 GHz with the ability to circulate the liquid.

The power output of the conventional MW oven is 1,260 W with the magnetron using 750 W to generate plasma from the total power of MW oven.

The microwaves were irradiated and received at the tip of each antennas used to generate plasma inside the bubbles.

Six antennas were arranged on a copper plate and placed on a Teflon platform. The device could be applied as a method for continuous production. The configuration includes an effective bubble control plate which is selected based on gas production rate.

Additionally, in-liquid plasma steam reforming, which is plasma fed by steam created in hydrocarbon liquid. The power supplied into the vessel reactor for
each experiment was varied from 150 W to 330 W. The microwaves were irradiated through a waveguide in order to prevent loss of energy to the reactor vessel.

This method is investigated to accelerate the in-liquid plasma reaction. The chemical reactions of discharge in water are used for purification of polluted water. In general, the process of discharge in a liquid is a more complicated phenomenon than that in a gas, because discharges in a liquid are unstable and involve phase transitions.

When discharge occurs in a liquid, in most cases, bubbles appear.

There have been many reports which focused on bubbles in relation to the generation of
plasma in a liquid by a variety of methods.

The behavior of bubbles and plasma generated by high frequency waves and microwaves is observed using a high-speed camera.

Microwave plasma is generated when the electrode is heated to the saturation tempe-rature of n-dodecane.

The main reason for conducting this study is to compare the hydrogen gas production efficiency of the in-liquid plasma steam reforming method, when
using a MW oven and microwave generator with a waveguide as the power supply and n-dodecane as the source material. It is expected to offer the most efficient hydrogen production rate with a method that is both simple and environmentally friendly.

Conclusions

Plasma was generated within the bubble in-liquid. Two types of microwave in-liquid plasma apparatus are adopted for hydrogen production.

One is a conventional MW oven, the other is a microwave generator with a waveguide to apply the in-liquid plasma steam reforming method in n-dodecane.

A conventional MW oven is used to irradiate at 2.45 GHz within liquid.

The conventional MW oven has an output of 1,260 W with only 750 W being used by the magnetron to generate plasma.

Furthermore, in a separated system, 150-330 W of energy power was used by the steaming reforming method to generate plasma in the vessel reactor.

For the experimental results of the MW oven, the hydrogen proportion of the generated gas was affected by the graphite concentration.

Hydrogen was dominant in the gas produced, with the ratio around 58%-90% of the total gas. By using a bubble control plate, the gas production rate could be increased up to 1.3 times. The gas production rate using steam reforming could be increased up to 1.4 times over that without using steam reforming.

This indicates that, steam reforming method was effective in producing hydrogen gas since the rate of hydrogen gas production is higher than that of using a conventional MW oven

APPENDIX 11

Horizon 2020: The ODYSSEE-MURE project

The transport sector in the EU accounted for 33.2% of final energy consumption (353 Mtoe) ahead of the industrial or residential sectors.

This consumption is characterized by an almost exclusive dependence on oil products.

Road transport, in particular, accounts for 82.1% of the overall energy consumption of the
transport sector and oil products account for 94.6% of this. Road transport contributes to a large extent to the high energy dependence in the EU, at around 53.5% in 2014.

This dependence on petroleum generates a structural deficit which in 2012 amounted to a record figure of €337.9 billion, or almost 2.5% of the EU GDP, which negatively affects the competitiveness of the European economy.

This increases its vulnerability to the uncertainties associated with price fluctuations and geopolitical tensions linked to supply regions and to the financial markets. Another concern arises from the environmental effects caused by transport, among which are the GHG emissions – of which transport is responsible for 23.2% – and local air quality issues.

This shows the need to reinforce energy diversification in order to guarantee the security of energy supply and to reduce energy imports. The development of alternative fuels is one solution to this problem, while it contributes to mitigating the environmental impact of this sector.

According to estimates of the European Commission, the progressive use of alternative fuels in transport could lead to a potential accumulated saving of €9.3 billion in the EU energy bill by 2030.

However, the lack of a harmonized infrastructure at European level for the use of these fuels is a barrier to their development as well as a delay in achieving the expected environmental benefits. Thus, the EU adopted a strategy for clean transport – the Clean Power for Transport Package – which resulted in the
Directive for Alternative Fuels Infrastructure, 2014/94/EU (DAFI).

This fosters the use of alternative energies in transport by establishing a common framework for implementing the required infrastructure.

Synergy with other EU policies

This measure is complemented by other initiatives concerning energy and environmental policies which may affect the transport sector, such as;
• Directive 2008/50/EC on ambient air quality and cleaner air;

The regulations for the reduction of the CO2 emissions of new cars with restrictive targets for 2020 (95 g/km for private cars and 147 g/km for light commercial vehicles); and The 2020 climate & energy package, which establishes the 20-20-20 targets for 2020 which include a 20% reduction in the EU GHG emissions(from 1990 levels), a 20% share of renewables in the final energy consumption, and a 20% improvement in energy efficiency.

These objectives have been increased respectively to 40%, 27% and 27%2 for the year 2030.

This underlines the additional effort required to reduce emissions, in line with what was recently approved in the Paris Agreement.

The diffuse sources of emissions would need to be cut by 30% (compared with 2005 levels) with transport playing an important role.