Hungary 2022 Energy Policy Review

Posted on February 21, 2023 by Now.Solar

The International Energy Agency (IEA) has conducted in-depth peer reviews of its member countries’ energy policies since 1976. This process supports energy policy development and encourages the exchange of and learning from international best practices. By seeing what has worked – or not – in the “real world”, these reviews help to identify policies that deliver concrete results. Since the last IEA review of Hungary in 2017, the country has increased its climate ambition by legislating a carbon neutrality goal for 2050 and adopted a long-term vision informed by the National Clean Development Strategy, which offers a scenario approach for energy policy decision-making. Several other IEA member countries are looking at it to inform their own efforts towards carbon neutrality. In the near term, Hungary needs to prioritise efforts to reduce its high reliance on Russia for gas, oil and nuclear fuel. Concrete actions are needed to diversify energy sources and expand policies that lower fossil fuel consumption, increase energy savings and promote investments in clean energy technologies and in human resources to deliver a just and inclusive transition.

Since the last IEA review, Hungary increased its climate ambitions by legislating a carbon neutrality goal for 2050, adopting a long-term strategy, advancing the phase-out of coal by 2025, promoting a remarkable growth in the deployment of solar PV and upgrading its existing nuclear reactors. The major priorities for Hungary’s climate and energy policies relate to energy security, reducing fossil fuel use and keeping energy prices affordable. This new review presents a range of recommendations to the government of Hungary to help address its key energy policy challenges, notably the low levels of energy efficiency progress (buildings, transport), high vulnerability and reliance on Russia for gas, oil and nuclear fuel, regulated energy prices which may act as a barrier to clean energy investments, as well as the need for increased resources to deliver the transition.

Supply and demand Fossil fuels accounted for 68% of Hungary’s TES in 2020, of which 33% was natural gas, 27% oil and 7% coal. The main non-fossil energy source is nuclear (16% of TES), followed by bioenergy and waste (10%); electricity imports (4%); and other renewables (2%), including hydro, wind, geothermal and solar.

In 2020, Hungary produced 41% of its TES domestically, which indicates a high dependency on energy imports due mainly to the limited fossil fuel resources (Figure 2.2). Oil and natural gas together covered two-thirds of total final consumption (TFC), while the share of electricity in TFC was the third-lowest among IEA countries (17%) and below the IEA average of 23%. In terms of sectors in TFC, buildings accounted for 40% of TFC, followed by industry (38%) and transport (22%).

In 2020, Hungary produced 41% of its TES domestically, which indicates a high dependency on energy imports due mainly to the limited fossil fuel resources (Figure 2.2). Oil and natural gas together covered two-thirds of total final consumption (TFC), while the share of electricity in TFC was the third-lowest among IEA countries (17%) and below the IEA average of 23%. In terms of sectors in TFC, buildings accounted for 40% of TFC, followed by industry (38%) and transport (22%).

Emissions trends Between 2000 and 2019, Hungary’s total GHG emissions excluding land use, land-use change and forestry (LULUCF) declined by 14%, from 74.9 Mt CO2-eq to 64.4 Mt CO2-eq. GHG emissions saw a rebound from the lowest point of 58 Mt CO2-eq in 2013 and a stabilisation since 2017 (Figure 3.1). In 2019, the energy sector accounted for 72% of total GHG emissions. Overall, emissions removals from LULUCF increased fivefold between 2000 and 2019, from 1 Mt CO2-eq to 5.5 Mt CO2-eq, thanks to the growing stock in forests and other wood lands and a slow rate of land use, which would have converted agricultural, forest and other semi-natural land into urban and other artificial surfaces (UNECE and FAO, 2021; EEA, 2021a).

Consumption and energy-saving trends According to IEA data, in 2020, Hungary’s TFC was 20 Mtoe. Energy demand in Hungary slightly decreased from 2011 to 2013, rebounded until 2017, then plateaued from 2017 to 2020 at 20 Mtoe. Hungary has largely decoupled economic growth and energy consumption. Between 2010 and 2019, GDP increased by 30% while TFC rose only by 6%. Consequently, the TFC/GDP ratio, which measures the energy intensity of the economy, decreased by 19% in the same decade. Buildings account for the largest proportion of TFC. Building’s energy consumption has decreased gradually since 2005 to cover 40% of TFC in 2019. The industry and transport sectors have steadily increased their energy consumption in recent years. In 2020 they accounted for 38% and 22% of TFC, respectively.

Renewable energy trends According to IEA data, the share of renewables in total final energy consumption (TFEC) was 14.8% in 2020 (Figure 5.1). The share of renewables has overall increased since 2009 thanks to the rising use of biomass, peaking in 2013 (17% of TFEC). Thereafter, the share of renewables decreased until 2018, as the use of bioenergy in heating declined. Since 2018, the growth of solar PV is driving the share of renewables up again. Direct use of solid biomass accounts for most of renewables in Hungary’s TFEC (59%), followed by direct use of liquid biofuels (11%), solar (10%), electricity generation from bioenergy (8%), geothermal (5%), heat generation from bioenergy (3%), wind (2%) and hydro (1%).

Hungary exceeded its overall renewable energy target for 2020, as defined by Eurostat definitions. 6 In 2020, its shares of renewables accounted for 13.9% in gross final energy consumption, 11.9% in electricity, 11.6% in transport, and 17.7% in heating and cooling, which was slightly below the target (Figure 5.2 and Table 5.1).

In 2020, the HEA carried out an investigation of the level of competition in the electricit wholesale market in Hungary (HEA, 2020). The investigation found that although greater competition from imports has reduced the concentration of the Hungarian wholesale electricity market in the last decade, the wholesale sector can be still considered to be a “concentrated market”, and that MVM’s influence is very considerable. As a result, the HEA concluded that MVM subsidiary, Energiakereskedelmi Zrt, should sell an average of 400 MWh/h of electricity annually at a public auction or in stock exchange trading. However, no legal obligation was imposed on MVM to do so. Driven by increasing gas prices across Europe, Hungary’s wholesale electricity prices in Q3 2021 rose to 113 EUR/MWh, from 67 EUR/MWh in Q2 2021 and 40 EUR/MWh in Q3 2020, according to EU data. Neighbouring countries in the EU market have followed similar patterns (Figure 7.6).

Retail electricity market In the retail market, E.ON is the market leader, with a 55-58% market share, MVM has a share estimated at 22-24% while other independent traders hold an 18-20% share. In the Universal Service Scheme market segment, MVM is the market leader, jointly with E.ON. E.ON and MVM are also the owners of Hungary’s distribution networks. E.ON’s market share in the retail sector will likely decrease in the near future following the planned sale of one of its subsidiaries, E.ON Energiakereskedelmi, to the Spanish company Audax Renovables; this sale was approved in 2020.

Source:IEA

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Global Hydrogen Review2022

Posted on February 20, 2023 by Now.Solar

Hydrogen demand is growing, with positive signals in key applications Hydrogen demand reached 94 million tonnes (Mt) in 2021, recovering to above pre-pandemic levels (91 Mt in 2019), and containing energy equal to about 2.5% of global final energy consumption. Most of the increase came from traditional uses in refining and industry, though demand for new applications grew to about 40 thousand tonnes (up 60% from 2020, albeit from a low base). Some key new applications for hydrogen are showing signs of progress. Announcements for new steel projects are growing fast just one year after the start-up of the first demonstration project for using pure hydrogen in direct reduction of iron. The first fleet of hydrogen fuel cell trains started operating in Germany. There are also more than 100 pilot and demonstration projects for using hydrogen and its derivatives in shipping, and major companies are already signing strategic partnerships to secure the supply of these fuels. In the power sector, the use of hydrogen and ammonia is attracting more attention; announced projects stack up to almost 3.5 GW of potential capacity by 2030.

Global hydrogen demand reached more than 94 million tonnes (Mt) in 20215, a 5% increase from the previous year and compared to 91 Mt in 2019 (pre-pandemic level). Most of the increase was for the use of hydrogen in traditional applications, particularly in chemicals, with nearly 3 Mt increase, and in refining with about 2 Mt increase from 2020. These sub-sectors, particularly refining, were strongly affected by the Covid-19 pandemic. Activity that was restrained due to the lockdowns and the general economic slowdown started to recover in 2021, as reflected in increased hydrogen demand. Most of the hydrogen supplied was produced from fossil fuels with no benefit for climate change.

Several projects have been announced or are under development that could represent around 3 500 MW of hydrogen- and ammonia-fired power plant capacity worldwide by 2030.28 Around 85% of these projects focus on the use of hydrogen in combined-cycle or open-cycle gas turbines. The use of hydrogen in fuel cells and the co-firing of ammonia in coal-fired power plants each account for around 10% and 6%, respectively, of the capacity of the project pipeline by 2030. Most of the gas turbine projects initially start with a hydrogen co-firing share in the range of 5-10% in energy terms (15-30% volumetric), but plan to move to higher shares and in some cases even 100% hydrogen firing in the longer term.

Current status of hydrogen production Demand for hydrogen is met almost entirely by hydrogen production from unabated fossil fuels. In 2021, total global production was 94 million tonnes of hydrogen (Mt H2) with associated emissions of more than 900 Mt CO2.30 Natural gas without CCUS31 is the main route and accounted for 62% of hydrogen production in 2021. Hydrogen is also produced as a by-product of naphtha reforming at refineries (18%) and then used for other refinery processes (e.g. hydrocracking, desulphurisation). Hydrogen production from coal accounted for 19% of total production in 2021, mainly based in China. Limited amounts of oil (less than 1%) were also used to produce hydrogen.

A hydrogen cluster, also called hub or valley57, is defined as a network of hydrogen producers (sometimes including renewable electricity production), potential users and infrastructure connecting the two. Clusters are expected to form in and around first-mover hydrogen supply and demand areas. These include industrial clusters, ports, cities and other locations that are already embracing pilot projects and commercial hydrogen developments. Hydrogen clusters will catalyse larger infrastructure development and will facilitate large-scale hydrogen trade when linked to ports. While it is desirable, to produce low-emission hydrogen at the beginning, though not strictly necessary, public support may be conditional on hydrogen being produced by low-emission technologies or below specified life cycle emissions values.

Beyond individual national efforts, international co-operation is paramount to align objectives, increase market size and promote knowledge-sharing and the development of best practices. International co-operation related to hydrogen remained strong over the last year and is expected to accelerate as a consequence of the Russian invasion of Ukraine and growing concerns about energy security. Since September 2021, fifteen new bilateral international agreements between governments have been signed – most focus on the development of international hydrogen trade. Governments, particularly in Europe, are looking at opportunities to accelerate the commercial availability of hydrogen technologies and the development of international trade to reduce dependency on fossil fuels as fast as possible. Moreover, European institutions are actively signing international agreements with non-European governments seeking to facilitate investment and accelerate development of international supply chains. Examples include the case of the European Investment Bank with Mauritania to scale up investment in wind, solar and green hydrogen and the European Bank for Reconstruction and Development with Egypt to assess the potential to develop low-emission hydrogen supply chains in Egypt.

Global hydrogen demand in 2021 was 94 Mt.78 Almost all of it is concentrated in refining and industrial applications, with very little demand in other sectors (around 40 kilotonnes [kt], practically all in road transport). More than 80% of hydrogen is produced from fossil fuels, with the remainder largely from refineries where hydrogen is produced as a by-product of processes that use fossil fuels as inputs. The production of renewables-based hydrogen is very low, accounting for around 0.1% of total production. Almost all dedicated hydrogen production, excluding by-product hydrogen, occurs onsite at the same industrial facility or refinery that consume the hydrogen. Only a small fraction (7%) is produced in external facilities and delivered as merchant hydrogen. Most of the merchant hydrogen is consumed in refineries that require a more flexible operation to respond to variable demand for oil products.

Source:IEA

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The Futureof Heat Pumps

Posted on February 20, 2023 by Now.Solar

Today, many of the ways we heat buildings around the world – such as homes, offices, schools and factories – still rely largely on fossil fuels, particularly natural gas. It haslong been clear that this leads to large amounts of greenhouse gas emissions – and the current global energy crisis is a sharp reminder of the urgency of moving to more affordable, reliable and cleaner ways of heating buildings. In this context, heat pumps, which can efficiently provide heating to buildings and industry, are the key technology to make heating more secure and sustainable. They are quickly becoming more cost competitive, drawing interest from a growing number of governments, businesses and consumers across the globe. Until now, though, there has not been a comprehensive global study of the state of play of heat pumps – and their future role in our energy systems. This World Energy Outlook special report aims to fill that gap. Our in‐depth analysis finds that policy plans announced so far by governments globally point to a large expansion of the use of heat pumps, which will have a clear impact on the use of gas, oil and coal for heating. Heat pumps have the potential to reduce global carbon dioxide emissions by at least 500 million tonnes in 2030. For Europe, they are a vital tool to cut reliance on Russian gas,since they can lower Europe’slargestsource of gas demand – heating in buildings – by at least 21 billion cubic metres in 2030.

Introduction This chapter assesses the outlook for heat pump installations and their impact on the energy mix for heating in buildings and industry, drawing on the projections of the system‐wide energy scenarios depicted in the latest edition of the World Energy Outlook (WEO), released in October 2022 (IEA, 2022a). Emphasis is given here to the Announced Pledges Scenario (APS), which assumes that governments around the world meet all announced energy‐ and climate‐related commitments in full and on time. This is contrasted throughout the report with the Stated Policies Scenario (STEPS), which describes how the global energy system would evolve under the policies already in place today, provided they are backed by concrete implementation plans. These comparisons are intended to highlight where additional efforts are required to accelerate heat pump deployment. In some cases, the APS projections are also compared with the Net Zero Emissions by 2050 (NZE) Scenario, which represents a pathway to reduce energy emissionsto zero on a net basis by 2050 in order to stabilise global average temperatures at 1.5 °C above pre‐industrial levels. More detail about the scenarios and the projections can be found in WEO 2022. A heat pump uses technology similar to that found in a refrigerator or an air conditioner. It extracts heat1 from a source, such as the surrounding air, geothermal energy stored in the ground, or nearby sources of water or waste heat from a factory. It then amplifies and transfers the heat to where it is needed (Figure 1.1). Because most of the heat is transferred rather than generated, heat pumps are far more efficient than conventional heating technologies such as boilers or electric heaters and can be cheaper to run. The output of energy in the form of heat is normally several times greater than that required to power the heat pump, normally in the form of electricity. For example, the coefficient of performance (COP) for a typical household heat pump is around four, i.e. the energy output is four times greater than the electrical energy used to run it. This makes current models 3‐5 times more energy efficient than gas boilers. Heat pumps can be combined with other heating systems, commonly gas, in hybrid configurations.

The efficiency of a heat pump depends critically on the source of the heat. In winter, the ground and external watersources typically remain warmer than the ambient air,so ground‐ source and water‐source heat pumps consume less electricity than air‐source ones, yielding a higher COP. This is particularly the case in cold climates where defrosting the outside components of air‐source heat pumps can consume additional energy. However, ground‐ source heat pumps are more expensive to install, as they require an underground heat exchanger – a deep vertical borehole or a large network of pipes buried at least one metre below the surface of the ground. Connecting a water‐source heat pump to a nearby river, groundwater or wastewater can also be costly.

Heating needs Heating currently represents a sizeable share of global energy consumption and a major source of CO2 emissions. Global energy demand for space and water heating amounted to 62 exajoules (EJ) in 2021, accounting for around half of energy consumption in buildings and directly emitting 2.5 gigatonnes (Gt) of CO2 – roughly 80% of direct buildings emissions. This moves up to 4 Gt of CO2 when considering indirect emissions from electricity and district heating.

The level of energy demand varies substantially by household within and across countries and regions, mainly according to climate, household size, living space, the degree to which buildings are well‐insulated, and the type and quality of heating equipment (Figure 1.2). Around 70% of total heating needs are for space heating and the rest for hot water. The energy mix for heating also varies. Natural gas is the leading form of energy for heating in buildings, meeting 42% of heating energy demand globally. One sixth of global natural gas demand is for heating in buildings—in the European Union this number moves up to one third. Oil follows next with 15%, then electricity at 15%, and district heating – concentrated in China, Northern and Eastern Europe, and Central Asia – at 11%. The direct use of biomass and coal make up the difference. The fuel mix for heating differs substantially across major heating regions, though gas dominates everywhere except East Asia.

Industrial heat pumps There is considerable potential for electric heat pumps to provide process heat for industry. Because of the complexity of industrial processes, heat pumps generally need to be tailored to specific applications. In contrast to those used in buildings, industrial heat pumps typically rely on higher input temperatures, asthe required output temperatures are also significantly higher. Today, industrial heat pumps are mainly used for low‐temperature processes below 100 °C, notably in the paper, food and chemicals industries (Table 1.2). However, output temperatures of up to 150 °C can already be achieved if waste heat of about 100 °C is available as input. For temperatures between 150 °C and 200 °C, heat pumps need special refrigerants and compressors, for which technologies are still in an early prototype stage.

Industrial heat pumps can be very efficient, with a COP of more than three, when the temperature lift, i.e. the difference between the input and output temperatures, is in the 30‐50 °C range. For higher temperature lifts, the COP is generally lower, though a heat pump can be configured in a way that limits the loss of efficiency, such as by incorporating intermediate heat exchangers or cascaded cycles(whereby the pump operates astwo single‐ stage cycles coupled together by a cascade heat exchanger). However, the costs of such heat pump systems are usually significantly higher.

With today’s F‐gas refrigerants and full leakage, heat pumps still reduce greenhouse gas emissions by at least 20% compared with a high‐efficiency gas boiler, even when running on emissions‐intensive electricity. In regions accounting for 70% of world energy consumption, the emissions savings are above 45% and reach 80% in countries with cleaner electricity mixes. These values can be improved by 10 percentage points, respectively, with alternative refrigerants. The large variation is mainly due to differences in the emissions intensity of electricity generation rather than refrigerant choice. Figure 2.7 illustrates emissions savings in four countries based on their climate conditions and emissions intensity of electricity production.

If F‐gas refrigerants continue to be used in the same way, by 2030 in the NZE Scenario, the global heat pump stock will bank nearly 740 Mt CO2 equivalent of greenhouse gas emissions – about twice the total annual greenhouse gas emissions of Australia. Even if today’s best practices in maintenance and recycling were applied worldwide, only one‐third of these emissions would be prevented, making it harder to limit the global temperature rise to 1.5 °C.

The running costs of a heat pump are also affected by how well it is operated and maintained. It is essential that the owner of a heat pump isinformed about correct handling and the need for thorough maintenance by qualified technicians so that they operate efficiently and at optimal cost throughout their lifetime. Air‐source heat pumps can become clogged with dirt over time, leading to increased electricity consumption and premature wearing of the unit, as well as noisier operation. Refrigerants also tend to leak out over time, which reduces efficiency, as well as contributing to climate change . Refrigerant leakage warning systems are currently commercially available for large heat pumps; a roll‐out to residential systems could help users identify the reason for loss in performance and avoid the emission of refrigerant gas.

Non‐cost hurdles to consumer adoption In addition to cost, there are a range of other hurdles to the adoption by consumers of heat pumps, notably restrictions relating to heat pump installation, a lack of information about the benefits of heat pumps, and split incentives between building owners and tenants. While these barriers are less concrete in nature than costs, they contribute significantly to the reticence of many consumers to opt for a heat pump over other heating systems. A failure to take action to address them could deter large numbers of consumers and hold back deployment of the technology. Many countries have developed programmes to address some of the barriers. Further efforts are needed to strengthen them and apply them more widely.

The REPowerEU targets for heat pumps, reflected in the APS, call for an increase in the number of trained heat pump installers from around 40 000 in 2019 to 110 000 by 2030. Certification is mandatory across all EU countries for heat pump installations that require refrigerant handling by the installer, which is the case for most systems, except self‐ contained systems like a monobloc. With increasing restrictions on F‐Gas refrigerant usage in line with the Kigali Amendment, the required certification may pass from handling of F‐Gases to handling of flammable material. However, for the majority of installations, requirements for training and certification of installers vary between countries, despite the requirement for mutually recognised certification under the Renewable Energy Directive. Given the enormous differences in the maturity of the heat pump market across countries, collaboration between them on heat pump installer training and transfer of best‐practice know‐how could help ensure efficient and high‐ quality installations and achieve the REPowerEU targets.

Source:IEA


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Tracking PublicInvestment in EnergyTechnology Research –A Roadmap

Posted on February 17, 2023 by Now.Solar

Tracking public energy research development and demonstration Reducing global CO2 emissions to net zero by 2050 is consistent with efforts to limit the long‐term increase in average global temperatures to 1.5 C. This calls for nothing less than a complete transformation of how we produce, transport and consume energy. Without a major acceleration in clean energy innovation, reaching net zero emissions by 2050 will not be achievable. Estimations show that technologies that are available on the market today could provide nearly all of the emissions reductions required by 2030 to put the world on track for net zero emissions by 2050. However, reaching this target will require the widespread use after 2030 of technologies that are still at the research, development and demonstration (RD&D) stage today. This need is even bigger in sectors such as heavy industry and long‐distance transport. Major innovation efforts are vital so that the technologies necessary for net‐zero emissions can reach markets as soon as possible.

The IEA collects annual energy RD&D data using a standardised questionnaire that classifies energy technologies into four levels of detail within seven high-level categories: energy efficiency, fossil fuels, renewable energy, nuclear, hydrogen and fuel cells, other power and storage technologies, and cross-cutting. Based on this data collection, the IEA releases its dataset of public investment in energy RD&D online. For example, the latest data show that the global investment of IEA members in 2021 was almost USD 23 billion. Since 2021, the dataset also includes data shared by Brazil, the first non-member country of the IEA to contribute to the database.

The IEA dataset is made possible through the significant efforts of governments to compile energy RD&D data. While each government has historically designed its most appropriate approach to collecting and sharing national energy RD&D data, the IEA has seen the value in exchanging knowledge across country experts. To accurately track all flows of funds, a number of common steps must be followed regardless of the national context.

As described in this document, the different methodologies followed by countries to compile energy RD&D statistics are grouped into six phases and 11 steps. These six phases are: purpose and objectives; institutional arrangement; collection, classification and validation; data management and technology; data dissemination; and continuous improvement. These phases can be followed in sequence for countries near the beginning of their journeys towards energy RD&D data collection but also independently for countries that are redesigning specific areas of the process. While the phases described in this report follow an order, they can be considered in parallel depending on the context of each country.

As mentioned earlier, the IEA describes here possible options for countries to follow during the design of their energy RD&D data collection systems. Each country’s situation is different, and governments should see this report as a toolbox to adapt to their individual situations. This roadmap is an initial step that aims to be the basis for further exchanges between countries, and the IEA is happy to provide further support to any country that wants to improve or set up its data collection system.

Funding institutions and major programmes The main sources of funding for energy RD&D are the federal ministries and the Climate and Energy Fund. These funds are mainly transferred to the research institutions through the national funding agencies. In 2021, almost three-quarters of this expenditure was provided by governmental authorities (federal and regional funding organisations). The remaining part came from (publicly funded) research institutions and universities provided with equity capital.

Austria’s national funding agencies assign a significant share of financial resources provided by federal budgets to energy RD&D. In 2021, EUR 163 million was contracted via these institutions. Collection, classification and validation process Every year, aligned with the IEA deadlines, MITECO asks the Ministry of Science and Innovation to send the IEA questionnaire to the two funding agencies: AEI and CDTI. This process is done exclusively to report to the IEA. There are other RD&D data collection processes in parallel, but none of them is exclusive to the energy field. There are internal discussions to harmonise this process with the general RD&D data collection process.

Source:IEA

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Gas MarketReport, Q4-2022including Global Gas Security Review 2022

Posted on February 17, 2023 by Now.Solar

As the summer ends in the northern hemisphere on new highs for natural gas prices and volatility, and markets brace themselves for a winter of unprecedented uncertainty of supply due to Russia’s behaviour, security of energy supply has become a priority issue for consumers and policy makers across major consuming markets. A complete shutdown of Russian pipeline flows to the European Union cannot be ruled out. The sharp decline in Russian gas flows to Europe and a tight power market drove European gas prices – and indirectly Asian spot LNG prices – to record highs in the third quarter of 2022. Meanwhile, prices in the United States reached their highest summer levels since 2008. This has come with extremely high price volatility, which further increases financial pressure on market participants and the risk of defaults, limiting the number of active market participants and resulting in further volatility.

Russia’s invasion of Ukraine triggered deep concern over gas supply security in the European market and ripple effects in the global LNG market. Russia’s strategic behaviour of using natural gas as a political weapon has become increasingly obvious since September 2021. Despite available production and transport capacity, Russia has reduced its gas supplies to the European Union by close to 50% y-o-y since the start of 2022. In the current context, the complete shutdown of Russian pipeline gas supplies to the European Union cannot be excluded ahead of the 2022/23 heating season – when the European gas market is at its most vulnerable. Almost half of natural gas is consumed in the residential and commercial sectors for space heating purposes during this period, with demand strongly linked to the variation in temperatures. The following section provides an overview of the European Union’s preparedness for the 2022/23 winter and a resilience analysis in the case of a complete cut-off in Russian pipeline gas supply starting from 1 November 2022.

Our analysis indicates that maintaining adequate storage levels until the end of the heating season – at 33% of their working storage capacity as a minimum – will be crucial for a safe and secure winter. Higher storage levels would also moderate injection needs during the 2023 summer, potentially reducing some of the market tensions. Storage levels below this threshold might not be sufficient to tackle a cold spell occurring at the end of the heating season, similar to the one Europe faced in March 2018. Storage fill levels will largely depend on the evolution of demand factors as well as primary gas supply, particularly LNG inflow into Europe. The rapid build-up of regasification capacity creates the possibility of additional imports, but does not guarantee an increase in LNG supply. Increased natural gas demand due to a colder winter, stronger recovery in economic activity in Northeast Asia and unplanned outages could, separately or collectively, weigh on Europe’s winter LNG supply and lead to a more rapid depletion of underground gas storage.

The share of destination-fixed contracts has increased sharply since 2020 Flexible contracts accounted for almost 80% of the average contracted volumes in 2018-2019, driven by new FIDs in the United States. Most of these were on FOB (free on board) transport terms, which provides the greatest flexibility to portfolio players to leverage their trading capabilities. The share of destination-flexible contracts dropped to 35% in 2020 and 11% in 2021. This trend of returning to destination-fixed terms results from a declining share of flexible supply sources in contracting activity (mainly in the United States) and a corresponding rise in available supply from Eurasia and the Middle East, with a preference for fixed-destination sales contracts. The share of destination-flexible volumes among the portfolio players’ newly signed contracts in 2020 was 11%, the lowest level since 2015. China was the single largest signatory of fixed-destination contracts in 2021 with a share of almost two-thirds of the total volume.

Dry gas production in the United States is estimated to have increased by close to 4% y-o-y in the first eight months of 2022 to reach a record average of 98 bcf/d in July-August and above 99 bcf/d in the first half of September. This growth was principally driven by higher associated gas production in the oil-driven Permian Basin and higher output from the gas-driven Haynesville play. Production growth from the major Appalachian Basin appeared more limited. Natural gas output in Pennsylvania, the country’s second largest gas-producing state after Texas, posted y-o-y declines in both Q1 and Q2 2022 (down 0.6% and 0.9% respectively). These results, published by the state’s Independent Fiscal Office, were interpreted as resulting from lower drilling activity in 2020 and 2021, and from the impact of transport infrastructure bottlenecks.

In the European Union gas storage sites stood 25% (or 8.5 bcm) below their five-year average at the beginning of April, which marks the end of the European heating season. The strong inflow of LNG together with lower consumption enabled a strong storage build-up in Q2 and Q3. Storage injections were 18% above their five-year average and totalled over 60 bcm during the gas summer. Despite lower Russian flows, storage injections were 15% above their five-year average in Q3. Consequently, the European Union completely eradicated its storage deficit, inventory levels standing 2.5% (or 2.5 bcm) above their five-year average at the end of Q3. Inventory levels reached close to 90% of their working storage capacity at the end of September, surpassing the EU target of storage sites reaching at least 80% capacity by 1 November and in line with the recommendations of the IEA’s 10-Point Plan to Reduce the European Union’s Reliance on Russian Natural Gas. In Ukraine gas storage levels remain low, standing at just 30% of their working storage capacity as at the end of Q3 according to data from Gas Infrastructure Europe. In Russia storage sites were over 90% full at the end of August and may have reached full capacity by the end of Q3.

Source:IEA

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Clean EnergyTransitions in theGreater Horn of Africa

Posted on February 16, 2023 by Now.Solar

The future of Africa’s energy sector is important globally. The International Energy Agency (IEA) is actively supporting evidence-based energy policy making in African countries with the aim of achieving affordable and clean energy, in line with United Nations Sustainable Development Goal (SDG) 7. This includes ensuring universal access for all, promoting increased energy security and affordability, and accelerating the development of clean energy systems across Africa, through a sustainable and accelerated regional energy system transformation.

Over the 2010s, the region has experienced major developments that are shaking up the energy sector, as oil and gas reserves have been discovered. Additionally, there have been significant efforts to improve substantially electricity access using on- and off-grid connections and systems. Yet, about 50% of the population still lives without electricity and 85% without clean cooking solutions.

Despite a recent increase in power generation capacity, which almost doubled between 2010 and 2020, and improved communication infrastructure, the region lags other developing regions in terms of adequacy and quality of its infrastructure. Regional key infrastructure systems (transport, energy, water and energy) rank low on the Africa infrastructure development index of the African Development Bank when compared with other regions of the continent. This exacerbates the effects of isolation and impedes trade and investment.

In the Africa Case, demand for energy in the buildings sector decreases by one-quarter by 2030, while demand for bioenergy decreases by one-third because of better access to clean cooking solutions and increased electrification. Similar to under STEPS, the energy consumption of the transport and industry sectors doubles under the Africa Case compared to today’s levels. The demand for transportation services is higher in the Africa Case than in STEPS, but energy consumption is lower. This underscores the consistent emphasis of the Africa Case on efficiency, as evidenced by policies limiting import of inefficient vehicles, such as higher excise taxes on used cars or enforcement of a maximum age limit for used car imports. Electricity use into the transport sector will be developed, representing 5% of the total final consumption, with the remainder being fossil fuels. The total final energy consumption of the industry sector will be mainly supported by increased use of modern bioenergy, electricity and fossil fuels.

Similar variations are observed in the greater Horn region. In 2019, 73% of Ethiopian women over the age of 15 years were employed, compared to 22% of Somali and 29% of Sudanese women. Kenya, South Sudan and Uganda have an almost equal gender balance in economy‐wide employment and a high women participation rate in manufacturing. Ethiopia rates best in the energy-related sector, and women represent almost two-thirds of employment in utilities.

High rates of participation should not conceal that women are more likely than men to work in the informal sector, thereby working in jobs that are usually less stable and with lower wages. This is due to women’s limited access to education, heir household and childcare responsibilities, and their concerns about safety, especially when commuting to work. When attempting to enter the workforce, including in the energy sector, women need to overcome many barriers such as gender stereotyping and bias, and lack of training, mentorship and networking. Although women are increasingly obtaining diplomas in fields related to science, technology, engineering and mathematics, their employment in the electricity sector has barely risen. Women with such qualifications and technical training therefore often end up working in unrelated fields, thus underutilising their skills.

Electricity access is improving, but keeping up with population growth is challenging About 40% of the sub-Saharan Africa population lives in the greater Horn of Africa. In 2020, half of them, or 150 million people, are without access to electricity14. Rates of access to electricity in the greater Horn have improved considerably since 2000. Then, one in ten people had access to electricity, whereas today, it is one in two, which is comparable to the sub-Saharan Africa average (excluding South Africa). An additional 90 million people have gained access to electricity between 2010 and 2020. This progress has mainly been driven by the two economic powerhouses in the region: Ethiopia and Kenya. Both these countries have made spectacular progress, raising the electrification rate by over 6 percentage points every year, and representing 80% of people gaining access during the same period.

Progress is insufficient as the number of people without access keeps increasing In the greater Horn region, nearly 250 million people rely on traditional cooking solutions, such as the use of wood and charcoal as cooking fuels. Access to clean cooking lags far behind access to electricity throughout the region. The share of the population with access to clean cooking systems has steadily increased from about 10% in 2010 to 15% in 2020. However, the number of people relying on traditional cooking solutions grew by 20% or about 50 million people during the same period due to population growth outpacing access gains. While no country experienced a reduction in the total number of people without access, around 1 million people shifted to modern fuel each year. In addition, six out of the eight countries managed to improve their overall access rate.

There are noticeable disparities among countries in the region. Sudan and Kenya in particular both increased their access rates by 20 and 10 percentage points, respectively, between 2010 and 2020. These two countries track above the sub-Saharan Africa average with 55% and 17% access rates, respectively, for clean cooking. All other countries of the region are trailing far behind with access rates of less than 10%. Uganda, a country with a population size comparable to that of Sudan has an access rate of less than 1%. Ethiopia has one of the largest populations without access, at above 110 million people, while Kenya and Uganda together account for 90 million people without access.

Urban access to clean cooking grew faster than rural access over the last two decades, outpacing the urbanisation rate from 2012 onwards. Improved biomass cookstoves are supporting the expansion of access in rural areas where distribution infrastructure for LPG does not yet exist.

In both scenarios, the relative use of oil in generation of power in the region decreases threefold by 2030. It is surpassed as the second most important energy source for power generation, and replaced by geothermal power in STEPS and by geothermal and solar in the Africa Case. The share of geothermal power is above 15% in STEPS and close to 20% in the Africa Case in the overall electricity generation mix. STEPS considers introducing coal based on the existing pipeline of projects in Kenya and Sudan, but with a share of less than 1%, whereas it is fully phased out in the Africa Case by 2030.

Installed capacity in the region grows about threefold in STEPS and fourfold in the Africa Case by 2030, while doubling across Africa as a whole. The greater Horn’s abundant hydroelectric potential makes it attractive for large-scale, uninterrupted, long-term, low-carbon electricity generation. Hydropower remains the most important source of renewable power generation, with additions of installed capacity of close to 17 GW in STEPS and 25 GW in the Africa Case.

This increase in debt has left six countries in the region either at high risk or in debt distress as of April 2022.24 High commodity prices, adding to the supply chain shortages already present at the end of 2021, are driving surging inflation and higher costs of living. Major economies have responded by increasing their interest rates. Countries with high levels of debt are therefore now facing a combination of rising debt service costs, worsened by a strengthening US dollar (which most public debt is denominated in), and surging bond yields.

This worsening macroeconomic environment reduces governments’ abilities to invest in their energy sector, and also reduces the appeal to private sector investors. High levels of country risk in the greater Horn already limit the involvement of private sector investors, who will be further concerned about the possibility of rising food and fuel prices triggering short-term social unrest in countries with ongoing conflicts or a recent history of instability.

The demand for titanium is expected to rise significantly, especially for clean energy technologies such as geothermal. Around 16 GW of geothermal capacities are located in geo-hotspots such as Iceland, Indonesia, the Philippines, Turkey and the United States, as well as Kenya. This technology, providing a low-carbon baseload, is set to increase significantly at the global level and in the greater Horn region. In IEA climate-driven scenarios, mineral demand from geothermal technologies grows more than seven times over the coming two decades, and geothermal power becomes a major source of demand for nickel, chromium, molybdenum and titanium. This could offer further opportunities for Kenya. It is a country with a well-established geothermal industry and ambitious plans to develop it, where annual production of titanium has reached 250-350 kt in recent years.

Eritrea Data for Eritrea are available starting in 1992. Prior to 1992, data are included in Ethiopia. At the time of preparation of the 2022 edition of the World Energy Statistics and Balances, no official data were available from Eritrea from 2019 to 2020 Official data were also not available for most products and flows for 2018. As a consequence, the statistics and balances for 2018 to 2019 have been mostly estimated based on data from the United Nations Statistical Division (UNSD). Data for 2020 have been estimated based on population growth for biomass and household consumption, and GDP growth for other products. In the 2022 edition of the World Energy Statistics and Balances, most products and flows were revised from 2011 to 2017 based on new data provided by the Ministry of Energy and Mines.

Source:IEA

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World EnergyOutlook2022

Posted on February 16, 2023 by Now.Solar

Today, the world is in the midst of the first truly global energy crisis, with impacts that will be felt for years to come. Russia’s unprovoked invasion of Ukraine in February has had far‐ reaching impacts on the global energy system, disrupting supply and demand patterns and fracturing long‐standing trading relationships. The crisis is affecting all countries, but at the International Energy Agency (IEA), we are particularly concerned about the effect it is having on the people who can least afford it. One of the striking findings in this year’s World Energy Outlook (WEO) is that the combination of the Covid pandemic and the current energy crisis means that 70 million people who recently gained access to electricity will likely lose the ability to afford that access – and 100 million people may no longer be able to cook with clean fuels, returning to unhealthy and unsafe means of cooking. That is a global tragedy. And it is not only an energy crisis with which wevare dealing: many countries also face a food security crisis and increasingly visible impacts ofvclimate change.

Moreover, there isscant evidence to support the notion that netzero emissions pledges have stifled traditional investmentsin supply, asthese pledges are not yet correlated with changes in fossil fuel spending. Most net zero emissions pledges are recent, and many have yet to be translated into specific plans and policy measures. Our analysis of fossil fuel investment in countries with netzero emissions pledges(68 countries plusthe European Union)showsthat they are at a similar level to where they were in 2016, and that changes in investment levels in those countries in recent years are not noticeably different from those that have taken place in countries without net zero emissions pledges (Figure 1.3).

Outlook for energy markets and security Today’s high energy prices and gloomy economic outlook lead to lower energy demand growth in the STEPS and APS, both in the near term and out to 2030, than in the WEO‐2021 (IEA, 2021a). Faced with market uncertainty and high prices, consumers are forgoing purchases and industry is scaling back production. Despite a strong economic rebound from the pandemic in 2021, the assumed rate of average annual GDP growth for the rest of the decade has been revised down slightly to 3.3% (see Chapter 2). Energy demand rises more slowly in both the STEPS and APS as a result, and the mixture of fuels used to meet this demand growth changes substantially from previous projections (Figure 1.8).

Background to the global energy crisis The historic plunge in global energy consumption in the early months of the Covid‐19 crisis in 2020 drove the prices of many fossil fuels to their lowest levels in decades. However, the price rebounds since mid‐2021 have been brutally quick (Figure 2.1). Oil prices that briefly moved into negative territory in 2020 have been back around or above USD 100/barrel. Coal prices have reached record levels. Spot natural gas prices in Europe have regularly been above USD 50 per million British thermal units (MBtu), more than double the crude oil price on an energy‐equivalent basis. Tight gas and coal markets have fed through into exceptionally high electricity prices in many markets. The global energy crisis has hurt households, industries and entire economies around the world, with the poorest and most vulnerable suffering particular hardship.

Thanks to electrification, improvements in energy efficiency and behavioural changes total energy supply declines by 10% between 2021 and 2030 even as the global economy grows by nearly a third. The annual rate of energy intensity improvement nearly triples as it rises to more than 4% per year. Unabated sources of supply decline by nearly a third, with unabated coal falling by nearly one‐half and unabated natural gas by more than one‐quarter by 2030. This contrasts with the NZE Scenario in the World Energy Outlook 2021 (WEO‐2021), in which natural gas held on to a largershare of the global energy mix for a little longer: the change reflects heightened energy security concerns around natural gas precipitated by Russia’s invasion of Ukraine. Oil also declines by around one‐ fifth to 2030 as a result of energy efficiency gains, behavioural change and increasing electrification in transport.

The global average CO₂ intensity of electricity generation declines in all scenarios from its level of 459 grammes of carbon dioxide per kilowatt‐hour (g CO2 /kWh) in 2021, falling by 2030 to 330 g CO2/kWh in the STEPS, 280 g CO2/kWh in the APS and 165 g CO2/kWh in the NZE Scenario. By 2050, the average intensity of electricity generation ranges from 160 g CO2/kWh in STEPS to slightly below zero in the NZE Scenario. However, countries start from different places in 2021 and their pathways vary. In general, the rapid growth of power systems in emerging market and developing economies and higher use of unabated coal result in an average CO2 intensity of electricity generation that is 70% higherthan the average in advanced economies (Figure 6.14). In advanced economies, while stated policies lead to significant reductionsin annual emissions, announced pledges lead to faster reductions, with the United States and the European Union reaching net zero emissions electricity by 2040, and Japan and Korea by 2050. A number of emerging market and developing economies have also pledged to reach net zero emissions, and this leads in the APS to deep reductions in the CO2 intensity of electricity by 2050 in Africa, China, India, Middle East and Southeast Asia.

The future uptake of low‐emissions hydrogen‐based liquid fuels depends crucially on finding ways to reduce production costs. Cheaper renewable energy and carbon capture, utilisation and storage (CCUS) will make a big difference, but dedicated projects are also needed to improve low‐emissions hydrogen and ammonia production technologies and to reduce efficiency losses across the value chain. There has been recent progress on this front. The largest power generation company in Japan, JERA, issued a tender in 2022 for up to 0.5 Mt of low‐emissions ammonia (around 5 thousand barrels of oil equivalent per day [kboe/d]) to replace 20% of the coal at a large power plant unit from 2027. Maersk, a leading shipping company, has commissioned 19 methanol‐fuelled container ships and it is studying how to ensure that the methanol they use is produced from sustainable biomass. In Germany, a 350 tonne per year plant for the production of synthetic kerosene opened in 2022 next to an existing synthetic methane plant and a source of CO2 from biogas upgrading.

In the APS, global coal trade falls by 25% to 2030 and by 60% to 2050. There is 470 Mtce of coal imported in 2050, mainly by countries with large distances between domestic production and consumption hubs and where differences in coal quality require domestic production to be supplemented with imports. Imports of coking coal in India increase by 40% to 2030 as it expands steel production. Indonesian exports drop by 30% to 2030 as the market for steam coal shrinks. Australia fares better, with coal exports falling by less than 20% to 2030, although its exports fall by about 50% between 2030 and 2050 as the use of clean energy technologies increases.

Source:IEA

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Global Energy andClimate Model

Posted on February 15, 2023 by Now.Solar

Overview of model and scenarios Since 1993, the IEA has provided medium- to long-term energy projections using a continually-evolving set of detailed, world-leading modelling tools. First, the World Energy Model (WEM) – a large-scale simulation model designed to replicate how energy markets function – was developed. A decade later, the Energy Technology Perspectives (ETP) model – a technology-rich bottom-up model – was developed, for use in parallel to the WEM. In 2021, the IEA adopted for the first time a new hybrid modelling approach relying on the strengths of both models to develop the world’s first comprehensive study of how to transition to an energy system at net zero CO2 emissions by 2050. Since then, the IEA has worked to develop a new integrated modelling framework: IEA’s Global Energy and Climate (GEC) Model. As of 2022, this model is the principal tool used to generate detailed sector-by sector and region-by-region long-term scenarios across IEA’s publications.

GEC Model scenarios The IEA medium to long-term outlook publications – the World Energy Outlook (WEO) and the Energy Technology Perspectives (ETP) – use a scenario approach to examine future energy trends relying on the GEC Model. The GEC Model is used to explore various scenarios, each of which is built on a different set of underlying assumptions about how the energy system might respond to the current global energy crisis and evolve thereafter. By comparing them, the reader is able to assess what drives the various outcomes, and the opportunities and pitfalls that lie along the way. These scenarios are not predictions – GEC Model scenarios do not contain a single view about what the long-term future might hold. Instead, what the scenarios seek to do is to enable readers to compare different possible versions of the future and the levers and actions that produce them, with the aim of stimulating insights about the future of global energy.

The scenarios highlight the importance of government policies in determining the future of the global energy system: decisions made by governments are the main differentiating factor explaining the variations in outcomes across our scenarios. However, we also take into account other elements and influences, notably the economic and demographic context, technology costs and learning, energy prices and affordability, corporate sustainability commitments, and social and behavioural factors. However, while the evolving costs of known technologies are modelled in detail, we do not try and anticipate technology breakthroughs (e.g., nuclear fusion).

GEC Model overview Modelling methodology The GEC Model is a bottom-up partial-optimisation model covering energy demand, energy transformation and energy supply (Figure 1.1). The model uses a partial equilibrium approach, integrating price sensitivities. It shows the transformation of primary energy along energy supply chains to meet energy service demand, the final energy consumed by the end-user. The various supply, transformation and demand modules of the model are dynamically soft-linked: consumption of electricity, hydrogen and hydrogen-related fuels, biofuels, oil products, coal and natural gas in the end use sector model drives the transformation and supply modules, which in turn feed energy prices back to the demand module in an iterative process. In addition, energy system CO2, CH4 and N2O emissions are assessed. The model contains a number of additional analysis features evaluating further system implications such as investments, critical minerals, employment, temperature outcomes, land use, and air pollution (see more details below).

Material trade between model regions is not modelled endogenously in the technology model, but rather is reflected in the activity projections developed in the activity and stock models. Apart from specific instances where announced policies or projected energy price signals provide relevant evidence to the contrary, trade patterns in material production and consumption are projected to follow current trends. Global total material demand is thus allocated into regional production based on these current trends. The capacity model contains data on historic and planned plant capacity additions and retrofits by plant type. Using assumptions about investment cycles, it calculates plant refurbishments and retirements. The resulting remaining capacity informs the main technology model. The capacity model also provides projections on the average age of plants at a given time.

The main technology model of each sector consists of a detailed representation of process technologies required for relevant production routes. Energy use and technology portfolios for each country or region are characterised in the base year using relevant energy use and material production statistics. Throughout the modelling horizon, demand for materials (as dictated by the activity model outputs) is met by technologies and fuels, whose shares are informed by real-world technology progress and the previous ETP TIMES optimisation model. That model used a constrained optimisation framework, with the objective function set to make choices that minimise overall system cost (comprised of both energy costs and investments).

The transport module The transport module of the GEC Model consists of several sub-models covering road, aviation, rail and navigation transport modes (Figure 3.4). The GEC Model fully incorporates a detailed bottom-up approach for the transport sector in all GEC Model regions.

For each region, activity levels such as passenger-kilometres and tonne-kilometres are estimated econometrically for each mode of transport as a function of population, GDP and end-user price. Transport activity is linked to price through elasticity of fuel cost per kilometre, which is estimated for all modes except passenger buses and trains and inland navigation. This elasticity variable accounts for the “rebound” effect of increased car use that follows improved fuel efficiency. Energy intensity is projected by transport mode, taking into account changes in energy efficiency and fuel prices.

Hourly load curves for end-uses are informed by research and survey data where available. Detail on modelling of hourly heating, cooling and lighting electricity demand across the year is included, with deep learning algorithms used to predict space heating and cooling demand for both residential and services buildings based on temperature, building occupancy rates and historical demand. Lighting hourly electricity demand is projected based on building activity and occupation rates, daylight times and insolation levels. The aggregate electricity demand of each end-use or subsector is then matched to the total historical hourly load profile of a given country. 7 An example of the load aggregation is displayed in Figure 3.11.

The model subtracts from the demand in each segment any generation coming from plants that must run – such as some CHP plants and desalination plants – and also generation from renewables. For generation from variable renewables, the amount of generation in each demand segment is estimated based on the historical correlation between generation and demand. The remainder of the demand in each segment must be met by production from dispatchable plants. The model determines the mix of dispatchable generation by constructing a merit order of the plants installed – the cumulative installed generation capacity arranged in order of their variable generation costs – and finding the point in the merit order that corresponds to the level of demand in each segment (Figure 4.3). As a result, plants with low variable generation costs – such as nuclear and lignite-burning plants in the Figure 4.3 example – will tend to operate for a high number of hours each year because even baseload demand is higher than their position in the merit order. On the other hand, some plants with high variable costs, such as oil-fired plants, will operate only during the peak demand segment.

Calculation of the capacity credit and capacity factor of variable renewables Power generation from weather-dependent renewables such as wind and solar power varies over time and the characteristics of the power supply from variable renewables have to be taken into account for the decisions on dispatch and capacity additions of the remaining, mostly dispatchable power plants. The effect of all variable renewables (solar PV, solar CSP without storage and wind on- and offshore) is taken into account via the capacity credit and the capacity factor in each load segment.

Value-adjusted Levelized Cost of Electricity Major contributors to the Levelized Cost of Electricity (LCOE) include overnight capital costs; capacity factor that describes the average output over the year relative to the maximum rated capacity (typical values provided); the cost of fuel inputs; plus operation and maintenance. Economic lifetime assumptions are 25 years for solar PV, onshore and offshore wind. For all technologies, a standard weighted average cost of capital was assumed (7-8% based on the stage of economic development, in real terms). The value-adjusted LCOE (VALCOE) is a metric for competitiveness for power generation technologies, building on the capabilities of the GEC Model hourly power supply model. It is intended to complement the LCOE, which only captures relevant information on costs and does not reflect the differing value propositions of technologies. While LCOE has the advantage of compressing all the direct technology costs into a single metric which is easy to understand, it nevertheless has significant shortcomings: it lacks representation of value or indirect costs to the system and it is particularly poor for comparing technologies that operate differently (e.g. variable renewables and dispatchable technologies). VALCOE enables comparisons that take account of both cost and value to be made between variable renewables and dispatchable thermal technologies.

The merchant hydrogen supply module uses a cost-optimisation modelling framework called TIMES, a
technology-rich modelling platform developed and further improved by the ETSAP Technology Collaboration Programme of the IEA. The hydrogen module depicts various technology options to produce hydrogen and hydrogen derived fuels (ammonia, synthetic liquid hydrocarbon fuels, synthetic methane) in terms of existing capacities, conversion efficiencies, fuel costs, operating and maintenance costs, CO2 emissions as well as CO2 capture rates for fossil fuel based technologies and capital costs for new capacity additions. Electrolyser capital costs represent a weighted average of likely deployment shares of different electrolyser technologies, which future cost reductions being derived by component-wise learning curves. Capital costs for all technologies also include all balance-of-plant and engineering, procurement and construction (EPC) costs, which can represent a high share of total installed costs.

Based on demands for merchant hydrogen and hydrogen-derived fuels from the end-use sectors, electricity and heat generation sector, refineries and biofuel production, the hydrogen supply module determines a least-cost technology mix to cover these demands. Besides these demands and the technical and economic characteristics of technologies, the module takes into account announced hydrogen production or trade projects (using for example the IEA’s Hydrogen Project Database) as well as policy constraints, such as CO2 prices or hydrogen deployment targets.

Source:IEA

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Never Too Early toPrepare for Next Winter:Europe’s Gas Balance for2023-2024

Posted on February 15, 2023 by Now.Solar

As winter approaches, a combination of favourable LNG market dynamics, robust pipeline deliveries from non-Russian suppliers, lower demand, and policy actions has given Europe a chance to sidestep some of the worst immediate impacts of Russia’s steep cuts to natural gas deliveries

Strong European demand for LNG led to a reconfiguration of global LNG flows as increases in LNG supply (23 bcm) were not sufficient to meet Europe’s rapidly rising LNG imports. Higher LNG flows towards Europe were enabled in part by China’s LNG imports falling by 20% (or 19 bcm) year-to-date as it drastically reduced spot procurements. Europe’s thirst for LNG also disrupted gas and electricity supply in more price-sensitive markets, including in South Asia.

Considering current market trends, our assessment today is that the storage injection needs of the European Union and the United Kingdom will be 68 bcm (including 1.68 bcm of injections to the Rough storage in the United Kingdom). This is based on the assumption that European gas demand during this November-March period is 11% below its 5-year average. A colder-than-average winter could deplete European storage levels faster, resulting in injection needs in the range of 80-90 bcm.

Measures to limit short-term demand and storage depletion, alongside more structural measures to bring down gas demand, are absolutely essential to position Europe for next year. The drive to refill Europe’s gas storages for the 2023-24 winter heating season has to begin now. Some of the factors that helped Europe in 2022 are unlikely to be as favourable in 2023: in particular, Russian deliveries are likely to be considerably lower and competition from China for available LNG cargoes considerably higher

Source:IEA

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Advancing DecarbonisationThrough Clean ElectricityProcurement

Posted on February 14, 2023 by Now.Solar

Executive summary An increasing number of companies are looking to ensure – and show – that they are trying to help mitigate climate change and contribute to clean energy ransitions. At the same time, more and more consumers want to choose products and services compatible with sustainable development. In this context, almost 1 000 companies across different activity sectors have pledged some form of emissions reduction or climate neutrality goals. To achieve these goals, many companies have started defining targets to reduce or eliminate emissions arising from their electricity consumption by procuring electricity from clean sources.

This report aims to support consumers of all sizes in choosing impactful ways to procure clean electricity. To this end, it provides guidance not only to companies but also to key stakeholder groups – policy makers, regulators, and system and network operators.

Corporates with more flexibility have potential for fast decarbonisation Companies and industries that rely on electricity for a major share of energy in their activities and who have flexible operations have high potentials for fast decarbonisation. For several key sectors – such as manufacturing of machinery and transport equipment, aluminium smelting, and commercial and service activities (notably information and communications technology [ICT]) – electricity already constitutes a major part of their direct energy use. Applying procurement strategies to leverage clean electricity generation can help these industries rapidly decarbonise a significant part of their emissions profile.

In turn, flexibility in production processes can facilitate matching demand with the availability of variable renewables, whether installed on-site or procured from the electrical grid. Common sources of demand flexibility within different company. 2010 to 27% in 2020. Greater efforts, on the part of corporates, to clearly demonstrate that procurement strategies contribute to new renewable electricity capacity is one of the reasons for this increase.

Many parameters influence the choice for one or another option, such as the size of the corporate, ease (or difficulty) of accounting, geographical availability, and availability of land (for BTM options). The corporate’s engagement towards proving actual decarbonisation impact also comes into play. These parameters are summarised in the table below and described more fully in the following sections.

On-site generation reduces grid electricity consumption with clear additionality Electricity generation on site is also referred to as “behind-the-meter” (BTM). This option requires sufficient resources (e.g. solar irradiance, wind speed or biomass) and space at the corporate’s facilities. Utility requirements such as the hosting capability must also be met. The installation can be owned by the corporate or leased, in which case the corporate rents its land to a clean electricity developer through a leasing agreement or an on-site PPA.

Procurement for smaller companies Enabling companies of all sizes to access clean electricity procurement options maximises the benefits of corporate procurement. In practice, despite the existence of several procurement options, not all are equally feasible for corporates of different sizes. Smaller companies can struggle with options, such as PPAs, that may be contractually complex and need high bankability.

Power sector modelling In order to provide in-depth analysis of the impacts of different corporate procurement goals, this report presents power sector modelling case studies for two countries – India and Indonesia. This analysis incorporates capacity expansion modelling based on corporate clean electricity procurement into the IEA’s India regional power system model and Indonesia regional power system model. India and Indonesia are selected to extend analysis of this topic to developing economies, relative to existing research examining markets in the United States and Europe. Several different scenarios are assessed, including the Announced Pledges Scenario (APS) for Indonesia and the Stated Policies Scenario (STEPS) and the Sustainable Development Scenario (SDS) for India. Comparisons are also made against a historical year (2020) and a highrenewables case for India.

Modelling analysis in this report assesses emissions impacts on a marginal basis for both load and generation, with a long-run perspective focusing on impacts in 2030 under specific scenarios. Procurement for all participating corporate load is assessed in aggregate (see Annex for detailed modelling methodology).

Modelling methodology To provide a deeper analysis of how corporate procurement could impact future power systems, the IEA has carried out two case studies on corporate-driven, cost-optimised capacity expansion, using our India Regional Power System Model and our Indonesia Regional Power System Model. The base scenarios analysed are the Stated Policies Scenario (STEPS) and Sustainable Development Scenario (SDS) for India and the Announced Pledges Scenario (APS) for Indonesia. Each case assumes that, in line with different clean electricity goals, corporates procure clean electricity generation amounting to 10% of commercial and industrial demand. This fixed share is used to illustrate the impacts of different clean electricity goals. In practice, some barriers to procurement exist in both countries.

Source:IEA

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