Brancheanalyserrapport-PDF 版本-三制革商报告 (2023)

IEA PVPS：2022 年全球太阳能光伏市场简报（英文版）(23 sider).pdf

fc Snapshot of Global PV Markets 2022 Report IEA-PVPS T1-42:2022 Task 1 Strategic PV Analysis and Outreach PVPS Task 1 Strategic PV Analysis and Outreach 2020 Snapshot of Global PV Markets What is IEA PVPS TCP?The International Energy Agency(IEA),founded in 1974,is an autonomous body within the framework of the Organization for Economic Cooperation and Development(OECD).The Technology Collaboration Programme(TCP)was created with a belief that the future of energy security and sustainability starts with global collaboration.The programme is made up of 6000 experts across government,academia,and industry dedicated to advancing common research and the application of specific energy technologies.The IEA Photovoltaic Power Systems Programme(IEA PVPS)is one of the TCPs within the IEA and was established in 1993.The mission of the programme is to“enhance the international collaborative efforts which facilitate the role of photovoltaic solar energy as a cornerstone in the transition to sustainable energy systems.”In order to achieve this,the Programmes participants have undertaken a variety of joint research projects in PV power systems applications.The overall programme is headed by an Executive Committee,comprised of one delegate from each country or organisation member,which designates distinct Tasks,that may be research projects or activity areas.The IEA PVPS participating countries are Australia,Austria,Belgium,Canada,Chile,China,Denmark,Finland,France,Germany,Israel,Italy,Japan,Korea,Malaysia,Mexico,Morocco,the Netherlands,Norway,Portugal,South Africa,Spain,Sweden,Switzerland,Thailand,Turkey,and the United States of America.The European Commission,Solar Power Europe,the Smart Electric Power Alliance(SEPA),the Solar Energy Industries Association and the Copper Alliance are sponsor members.Visit us at:www.iea-pvps.org What is IEA PVPS Task 1?The objective of Task 1 of the IEA Photovoltaic Power Systems Programme is promoting and facilitating the exchange and dissemination of information on the technical,economic,environmental and social aspects of PV power systems.Task 1 activities support the broader PVPS objectives:to contribute to cost reduction of PV power applications,to increase awareness of the potential and value of PV power systems,to foster the removal of both technical and non-technical barriers and to enhance technology co-operation.Authors Data:IEA PVPS Reporting Countries,Becquerel Institute(BE).For the non-IEA PVPS countries:Izumi Kaizuka(RTS Corporation),Arnulf Jger-Waldau(EU-JRC),Jose Donoso(UNEF).Analysis:Gatan Masson,Elina Bosch(Becquerel Institute).Editor:Gatan Masson,IEA PVPS Task 1 Operating Agent.Design:IEA PVPS DISCLAIMER The IEA PVPS TCP is organised under the auspices of the International Energy Agency(IEA)but is functionally and legally autonomous.Views,findings and publications of the IEA PVPS TCP do not necessarily represent the views or policies of the IEA Secretariat or its individual member countries Data for non-IEA PVPS countries are provided by official contacts or experts in the relevant countries.Data are valid at the date of publication and should be considered as estimates in several countries due to the publication date.COVER PICTURE Expo 2020 Dubai,Solar Flowers.ISBN 978-3-907281-31-4:2022 Snapshot of Global PV Markets INTERNATIONAL ENERGY AGENCY PHOTOVOLTAIC POWER SYSTEMS PROGRAMME IEA PVPS Task 1 Strategic PV Analysis and Outreach Report IEA-PVPS T1-42:2022 April 2022 ISBN 978-3-907281-31-4 Task 1 Strategic PV Analysis and Outreach 2021 Snapshot of Global PV Markets 5 TABLE OF CONTENTS Table of Contents.5 Executive summary.6 1 Snapshot of the Global PV Market in 2021.9 2 The Top 10 Markets in 2021.11 3 AC or DC Numbers.13 4 market Segmentation.14 5 Cumulative Installed Capacity in the World.15 6 Electricity Production from PV.18 7 Policy&Markets Trends.19 7.1 Competitive Tenders&Merchant PV.19 7.2 Prosumers Policies.19 7.3 Local manufacturing policies.20 8 PV in the Broader Energy Transition.21 8.1 PV and Other Renewable Energy Evolutions.21 8.2 Impact of PV Development on CO2 Emissions.22 8.3 PV Fostering Development of a Cleaner Energy System.22 Task 1 Strategic PV Analysis and Outreach 2021 Snapshot of Global PV Markets 6 EXECUTIVE SUMMARY Despite a second year of COVID-19 pandemic,preliminary reported market data shows that the global PV market again grew significantly in 2021.At least 175 GW of PV systems have been installed and commissioned in the world last year which means that the total cumulative installed capacity for PV at the end of 2021 reached at least 942 GW.While these data will have to be confirmed in the coming months,some important trends can already be extracted:The Chinese PV market grew again in 2021,despite shortages observed in the value chain during the year and was the largest market in terms of annual installed capacity.In 2021,54,9 GW of PV were installed,compared to 48,2 GW in 2020 and 30,1 GW in 2019.China remains the leader in terms of cumulative capacity with 308,5 GW installed,almost one third of the global PV installed capacity.In addition to China,the rest of the global PV market grew significantly from 97 GW in 2020,to at least 120 GW in 2021,a 24%increase year on year.o The US market saw its market increasing to 26,9 GW which allowed it to overtake the European Union that was ranked second last year.Utility-scale installations accounted for about 75%of the new additions.o The European Union lost its position as the second global PV market and ranked third in 2021 by installing close to 26,8 GW.Outside of the EU,the rest of Europe added around 3 GW.The largest European market in 2021 was again Germany(5,3 GW),followed by Spain(4,9 GW),France(3,4 GW)the Netherlands(3,3 GW),Poland(3,3 GW),Greece(1,2 GW),Italy(944 MW)and Belgium(850 MW).o India and Japan rank third and fourth with respectively an estimated 13 GW and 6,5 GW annual installed capacity.o Some growing key markets contributed significantly to new additions in 2021,Brazil(5,5 GW,fifth),Australia(4,6 GW,eighth),Korea(4,2 GW,ninth),Mexico(1,8 GW).Preliminary numbers show that Taiwan,Pakistan each have installed close to 2 GW.o Among the top 10 countries,there are now five Asia-Pacific countries(Australia,China,India,Japan,Korea),three European countries(Germany,Spain and France)and two countries in the Americas(Brazil and the USA).The level to enter the top 10 global markets in 2021 was around 3,0 GW;a stable level compared to 2020 and twice the level needed in 2019.The top 10 countries represented around 74%of the global annual PV market,a slight decrease compared to 2020.Task 1 Strategic PV Analysis and Outreach 2021 Snapshot of Global PV Markets 7 Australia,Spain,Greece,Honduras,the Netherlands,Chile and Germany now have enough PV capacity to theoretically1 produce more than 10%of their annual electricity demand with PV.PV covers around 5%of the global electricity demand.The contribution of PV to decarbonizing the energy mix is progressing,with PV saving as much as 1 100 million tons of CO2eq.However,much remains to be done to fully decarbonize and PV deployment should increase by at least one order of magnitude to cope with the targets defined during the COP21 in Paris,France.1 Based on end-of year PV installed capacitys theoretical production Task 1 Strategic PV Analysis and Outreach 2021 Snapshot of Global PV Markets 8 Task 1 Strategic PV Analysis and Outreach 2021 Snapshot of Global PV Markets 9 1 SNAPSHOT OF THE GLOBAL PV MARKET IN 2021 IEA PVPS has distinguished itself throughout the years by producing unbiased reports on the development of PV all over the world,based on information from official government bodies and reliable industry sources.This 10th edition of the“Snapshot of Global PV Markets”aims at providing preliminary information on how the PV market developed in 2021.The 27th edition of the PVPS complete“Trends in Photovoltaic Applications”report will be published in Q4 2022.At least 175 GWdc of PV systems have been commissioned in the world last year of which the IEA PVPS countries represented 132 GWdc.The IEA PVPS countries represented 767 GW of cumulative PV at the end of 2021,which is at least 81%of the global PV capacity.Next to the members of the IEA PVPS programme,the other major markets in the world represent at least 175 GW cumulative installed capacity at the end of 2021.At present,it appears that around 922 GW represents the minimum installed by the end of 2021,with a firm level of certainty in the IEA PVPS countries and the other major markets.Remaining markets account for an estimated additional 20 GW that could bring the total cumulative installed capacity to around 942 GWdc.The installations in third countries without a robust reporting system are growing significantly,leading to increased uncertainties on the total installed capacity.In 2021,at least 20 countries installed more than 1 GW.Fifteen countries now have more than 10 GW of total cumulative capacity,five have more than 40 GW.China alone represented 308,5 GW followed by the European Union(as EU27),which used to lead the rankings for years,but ranks second since 2015(178,7 GW),the USA ranks third(123 GW)and Japan fourth(78,2 GW).IEA-PVPS numbers comprise the entire EU,not only the PVPS-member states which are part of the programme directly.Source:IEA PVPS 0000111268173130384050771031041111451750204060801001201401601802002000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021GWpFIGURE 1:EVOLUTION OF ANNUAL PV INSTALLATIONSNon IEA PVPS CountriesIEA PVPS CountriesJapanUSAEuropean UnionChina Task 1 Strategic PV Analysis and Outreach 2021 Snapshot of Global PV Markets 10 Evolution of regional PV markets The majority of the growth of the PV market in 2021 came from China,the US,Europe,India and emerging countries.Other markets saw some additions,too.Figure 2 below illustrates the changing dynamics of the global PV market,and the huge influence of the Chinese PV market.However,the positive dynamics of the other countries show a constant progress in the last years,despite some localized negative effects,which have been limited in 2021 compared to 2020.Source:IEA PVPS Impact of international trade disruptions Identifying the impact of the pandemic on the PV market in 2021 is a difficult exercise.While the market continued its development,one might consider that it could have grown even more without the impact on international trade and in some cases on local PV manufacturing.However,the impacts seen in China in 2021 were not directly correlated to the pandemic itself and reflect more the growing part of PV in the economy,especially regarding raw material consumption.In 2021,polysilicon and glass,but also aluminium,saw prices surges,which impacted the end-user price of PV modules.This led to contract cancellations and price increases for developers,and with a possible slowed down market development in many locations as a result.The additional shipping costs incurred in 2021 due to the pandemic also contributed to PV components price increases and possibly terminate some very competitive business models.At the same time,the increases in costs of energy,and specifically electricity prices,have enhanced the PV competitiveness in numerous countries.It is difficult to distinguish if this acceleration effect is stronger or weaker than the braking effect of higher PV hardware prices.Overall,we can consider that the COVID-19 pandemic did not significantly impact market development in 2021.The national market regressions or stagnations discussed above can be linked to regulatory burdens.But in a nutshell,most key markets progressed.The resiliency of the PV market despite the major economic and logistic disruptions is remarkable and shows the potential of the technology to limit the economic downturn and social damage brought by the COVID-19 pandemic.This shows that national green recovery plans and better regulations could propel the PV industry far beyond the current installation trends(which is needed to achieve the Paris Climate Agreement).Task 1 Strategic PV Analysis and Outreach 2021 Snapshot of Global PV Markets 11 2 THE TOP 10 MARKETS IN 2021 The Chinese market grew again with 54,9 GW installed in 2021.This represented 31%of the global market.Behind China,the USA ranked second with around 26,9 GW of annual installations in 2021.The European Union followed with an increased market of 26,8 GW,followed by India where an estimated 13 GW were installed.Japan closes the top five with an estimated 6,5 GW.Behind these countries,some changes were quite visible:Brazil installed 5,5 GW,sementing its title as the most dynamic market in Latin America.Korea(stable)and Australia(growing)respectively installed 4,2 GW and 4,6 GW.Looking a bit more in depth at European Union countries,Germany experienced another growth year,with about 5,3 GW of additional capacities installed,Spain installed 4,9 GW,setting a new annual solar PV installed capacity record while France saw its market more than triple with 3,4 GW installed.Notable growth was also observed in Portugal(572 MW compared to 151 MW in 2020),in Austria(720 MW compared to 340 MW in 2020)and to a lesser extent in Italy(944 MW compared to 785 MW 2020).The Netherlands continued to massively install PV,with 3,3 GW after 3 GW in the previous year and Poland continues its GW-scale expansion.Greece restarted PV installations after years of pause and in general,the European market benefited from a,overall growth.As in 2020,top 10 markets for PV in 2021 have installed at least 3 GW of PV systems,compared to 1,5 GW in 2018.Several countries which in previous years installed significant capacities have left the top 10 for annual installed capacities,such as Vietnam.These countries still experienced significant market developments,however,not enough to stay in the top 10.The top 10 of total cumulative installed capacities shows more inertia due to past levels of installations:Italy and the UK have left the top countries in terms of annual installations several years back.If Italys past developments still allow it to stay in the top 10 for cumulative installed capacity,the UK exited the top 10 for cumulative installed capacity this year and was replaced by Spain.As mentioned in the next section,capacities for a few countries that report PV installations in AC power,have been converted into DC power to ease comparison.This can lead to discrepancies with official PV data in several countries such as Japan or India.Source:IEA PVPS*The European Union grouped 27 European countries in 2021,out of which Germany,Spain,France,the Netherlands and Italy also appear in the Top 10,either for the installed capacity Task 1 Strategic PV Analysis and Outreach 2021 Snapshot of Global PV Markets 12 or the annual installations.The EU is a member of IEA-PVPS through its Joint Research Centre(EU-JRC).Task 1 Strategic PV Analysis and Outreach 2021 Snapshot of Global PV Markets 13 3 AC OR DC NUMBERS IEA PVPS counts all PV installations,both grid-connected and off-grid,when numbers are reported.By convention,the numbers reported refer to the nominal power of PV systems installed.These are expressed in W(or Wp).Some countries are reporting the power output of the PV inverter(the device converting DC power from the PV system into AC electricity compatible with standard electricity networks)or the grid connection power level.The difference between the standard DC power(in Wp)and the AC power can range from as little as 5%(conversion losses,inverter set at the DC level)to as much as 60%.For instance,some grid regulations limit output to as low as 70%of the peak power from the residential PV systems installed in the last years.Most utility-scale plants built in 2021 have an AC-DC ratio between 1,1 and 1,6.For some countries,numbers indicated in this report have been transformed to DC numbers to maintain the coherency of the overall report.In general,IEA PVPS recommends registering PV systems with both the DC power and the AC value.DC power gives a precise idea of the installed capacity,regardless of the grid connection(if any)and allows a reliable calculation of the energy production.On the other hand,AC power allows grid operators to better understand the maximum power output of the PV fleet.However,the AC value must be defined precisely since the AC output of many inverters can exceed the nominal value during small periods of time.On the other side,AC limits on the grid connection side do not always reflect the nominal capacity of PV plants.More information about recommendations to properly register PV plants can be found in the following report:IEA PVPS Report:Data Model and Data Acquisition for PV Registration Schemes and Grid Connection Best Practice and Recommendations Download the report:https:/iea-pvps.org/or scan the QR code Task 1 Strategic PV Analysis and Outreach 2021 Snapshot of Global PV Markets 14 4 MARKET SEGMENTATION Preliminary data show that the utility-scale PV market increased in absolute numbers compared to 2020.This trend was observed in many countries,due to the easiness to develop utility-scale PV compared to the difficulties or setting-up sound regulations for distributed PV under self-consumption and even more in energy communities.The rooftop market grew in 2021 in absolute terms,due growth in China,Australia,Germany,and the United States.Important growth of the distributed market was also observed in Spain( 100%compared to 2020).However,the relative shares of rooftop PV and utility-scale PV remained similar in 2021 compared to previous year.Source:IEA PVPS,Becquerel Institute The market has also started to diversify in terms of type of applications,with floating PV adding to utility-scale and BIPV starting to complement BAPV in the built environment.Other emerging segments such as agricultural PV are hardly visible yet but are attracting a growing interest and progressing fast.From a technology point of view,some evolutions have been notable,such as the start of bifacial PV development.PV integrated in vehicles,or VIPV/VAPV,is showing the potential for further diversification of PV components,but its current market level remains too low to be considered in this publication.02040608010012014016018020020112012201320142015201620172018201920202021GWpFIGURE 3:SEGMENTATION OF PV INSTALLATION 2011-2021ROOFTOPUTILITY SCALE Task 1 Strategic PV Analysis and Outreach 2021 Snapshot of Global PV Markets 15 5 CUMULATIVE INSTALLED CAPACITY IN THE WORLD As illustrated in Figure 4,the total cumulative installed capacity at the end of 2021 globally amounted to at least 942 GW.China continues to lead with a cumulative capacity of 308,5 GW,followed by the European Union(178,7 GW),the USA(122,9 GW),Japan(78,2 GW)and India(60,4 GW).In 2021,Australia reached 25,4 GW cumulative installations and Korea 21,5 GW.In the European Union,Germany leads with 59,2 GW,followed by Italy(22,6 GW),Spain(18,5 GW),France(14,3 GW)and the Netherlands(13,2 GW).Source:IEA PVPS Decommissioning,Repowering and Recycling So far,numbers published by IEA PVPS consider the annual installations and total installed capacities based on official data in reporting countries.Several countries already incorporate decommissioning of PV plants in their total capacity numbers by reducing the total cumulative number.However,it is believed that many countries do not track decommissioning properly,and even more problematic,repowering.It is assumed that real decommissioning is relatively unusual given the age of the oldest installations,since the real market started around 2005.Replacement of components,and in particular,PV modules and inverters are part of the usual maintenance and operation business,but in general it does not impact the total capacity.Recycling numbers can provide a glimpse of what is happening in this field.However,recycling schemes are not yet common,and the availability of data must be improved.In the coming years,IEA PVPS will follow the dynamic evolution of decommissioning,repowering and recycling closely,with the expected impact on the installed capacity,market projections for repowering and the decline in PV performances due to ageing PV systems.4681422397010013717722830440751162276794201002003004005006007008009001.0002005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021GWpFIGURE 4:GLOBAL EVOLUTION OF CUMULATIVE PV INSTALLATIONS Non IEA PVPS CountriesIEA PVPS Countries Task 1 Strategic PV Analysis and Outreach 2021 Snapshot of Global PV Markets 16 Evolution of Regional PV Installations While Europe played a key pioneering role in the early developments of PV,Asias share started to grow rapidly in 2012 and it has not stopped since then(see Figure 5).Driven by China,India,Japan,Korea and more recently Vietnam,Asia represented around 57%of the total cumulative installed capacity in 2021-a similar share compared to previous year.In the other continents and regions,PV installations were distributed similarly to previous year.Europe represented 21%of the global cumulative PV market(out of which the European Union accounted for 92%)despite the renewed and significant growth for the fourth year in a row.The Americas represented 16%,thanks to the USA and some Latin American countries such as Brazil,while the remaining 6me from the MEA region and the rest of the world(unidentified installations).Source:IEA PVPS Asia continues to dominate the global PV market,with China as a global leader.Some already established major Asian markets,such as China,India Japan,Korea,Taiwan or Malaysia,experienced a growth in 2021.The development in other markets,such as Thailand,Singapore,Indonesia and the Philippines has been slow or intermittent over the years.Vietnam now ranks amongst the top markets for the third year in a row,but it is unsure whether such an installation level will be sustained,as the significant decline in 2021 illustrates.Asian markets represented around 52%of the annual global PV market in 2021,a slight decrease compared to the level in 2020,but in line with previous years.In the Americas,the market increased,mainly through the US market which experienced accelerated growth(26,9 GW)in 2021.Brazil is the second market with around 5,5 GW installed in 2021,followed by Mexico which installed around 1,8 GW,Chile with 1,3 GW and Argentina installed around 200 MW,a level comparable to 2020.The market in Canada grew 01002003004005006007008009001.0002001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021GWpFIGURE 5:EVOLUTION OF REGIONAL PV INSTALLATIONSEuropeAsia PacificAfrica&Middle EastRoWThe Americas Task 1 Strategic PV Analysis and Outreach 2021 Snapshot of Global PV Markets 17 at around 400 MW installed capacity in 2021.The Americas represented around 21%of the annual global PV market in 2021.In the European Union,Germany took the lead with 5,3 GW,a significant increase for the fourth year in a row.Spain took the second place with 4,9 GW,an important growth compared to 2020.France took the third place thanks to 3,4 GW installed which represented around a threefold increase compared to previous year.The Netherlands ranked fourth with 3,3 GW installed,a comparable level to 2020.They are followed Poland with 3,3 GW and Greece(1200 MW).A few countries were just below the GW mark such as Italy(944 MW),Belgium(850 MW)and Hungary(800 MW).The ranking continued with Austria(720 MW),Portugal(572 MW),Sweden(500 MW),Denmark(312 MW)and Czech Republic(68 MW).Outside of the EU,Norway installed 45 MW in 2021.Other countries in Europe,experienced interesting developments in 2021:one can cite Switzerland(616 MW).It is also worth mentioning Ukraine which saw significant amounts of PV installed in the last years.Europe represented slightly more than 17%of the annual global PV market in 2021.In the Middle East and Africa,Israel installed an additional 935 MW,a significant increase compared to the previous year.In the United Arab Emirates,very few projects came online despite the tenders in the previous years but prospects for growth are positive.Turkey installed again around 1 GW-a stable market level compared to 2020.Africa and the Middle East represented around 3%of global PV installations in 2021 with off-grid installations growing rapidly and rooftop PV outside of any regulatory scheme are progressing in many countries rapidly.Task 1 Strategic PV Analysis and Outreach 2021 Snapshot of Global PV Markets 18 6 ELECTRICITY PRODUCTION FROM PV PV electricity production is easy to measure for an individual power plant but much more complicated to compile for an entire country.First,solar irradiation can vary depending on the local climate and the weather can show some significant differences from one year to another.Furthermore,a system installed in December,will have produced only a small fraction of its regular annual electricity output;systems installed on buildings may not be at optimum orientation or may have partial shading during the day.For these reasons,the electricity production from PV per country,as shown in Figure 6,estimates what the PV production could be based on the cumulative PV capacity at the end of 2021,close to optimum siting,orientation and long-term average weather conditions.Figure 6 shows how PV theoretically contributes to meet the electricity demand in key countries(IEA PVPS and others),based on the PV capacity installed by the end of 2021.Since these numbers are estimates based on the total cumulative capacity at the end of the year,they can slightly differ from official PV production numbers in some countries.These numbers should be considered as indicative,they provide a reliable estimation of the production in different countries and allow comparison between countries but do not replace official data.In several countries,the PV contribution to the electricity demand has passed the 10%mark with Australia in first place with 15,5%.Spain is second with an estimated 14,2%and Greece third with a theoretical penetration level of 13,6%.In total,PV contribution amounts to close to 5%of the electricity demand in the world.0,0%0,1%0,3%0,8%1,0%2,4%2,8%3,6%3,7%3,8%4,0%4,0%4,0%4,4%4,5%4,6%4,8%5,0%5,0%5,2%5,2%5,6%5,7%6,2%7,2%7,7%8,2%8,9%9,3%9,4,9,9,8,9,6,2,5%0%5 %SlovakiaNorwayFinlandCanadaSwedenMalaysiaThailandFranceCzech RepublicRomaniaUSAMoroccoSouth AfricaAustriaUKKoreaChinaWorldDenmarkMexicoBulgariaSwitzerlandPortugalTurkeyEUBelgiumIndiaIsraelItalyJapanGermanyChileNetherlandsHondurasGreeceSpainAustraliaFIGURE 6:THEORETICAL PV PENETRATION 2021 Task 1 Strategic PV Analysis and Outreach 2021 Snapshot of Global PV Markets 19 7 POLICY&MARKETS TRENDS 7.1 Competitive Tenders&Merchant PV Tenders have driven PV development in the last years and continued to be granted in several places in the world with extremely competitive prices,well below 20 USD/MWh in the sunniest places.Winning bids down to almost 10 USD/MWh have been reported in the Middle East,while some tenders with prices below 14 USD/MWh have been recorded in Europe(but these can be questioned).The decreasing price trend halted in 2021 due to module prices hikes,and most believe that prices will hardly continue to go down in the coming years,at least until the raw material crisis can be solved.In some countries,cost-based tenders evolve towards multiple-factors tenders.Environmental or industrial constraints are introduced to give an advantage to local companies or to favour a better environmental footprint of the products.Merchant PV,with PV electricity sold on electricity markets or through PPAs has been seen in an increasing number of countries in 2021(e.g.100%of the ground-mounted installed capacity in 2021 in Spain(3,5 GW)was developed through PPAs),with perspectives for further development in the coming years,especially if higher market prices for electricity remain,which would change completely the competitiveness question.Therefore,in addition to tenders,utility-scale PV starts to develop outside of the framed tenders and similar policies,thereby bringing cheap electricity to the world.7.2 Prosumers Policies The idea that PV producers could be considered as“prosumers”both producers and consumers of energy is evolving rapidly and policies are being adapted accordingly in several countries.The first set of policies used to develop the market of small-scale PV installations on buildings were called“net-metering”policies and were adopted in a large number of countries,however,with different definitions.The genuine“net-metering”which offers credits for PV electricity injected into the grid,have previously supported market development in Belgium,Canada,Denmark,the Netherlands,Portugal,Korea and the USA,but such policies are increasingly replaced by self-consumption policies favouring real-time consumption of PV electricity,often completed with a feed-in tariff(or feed-in premium added on top of the spot price)for the excess PV electricity fed into the grid.This is for example the case in Spain.As a result,self-consumption is becoming a major driver of distributed PV installations.The use of self-consumption in collective buildings is not yet widespread but exists in the Netherlands,Spain,Austria,Sweden,France,Switzerland,Germany or Italy to mention a few.Decentralized or distributed self-consumption is starting to develop with the idea to disconnect production and consumption of PV electricity.This would allow one or several PV producers(even utility-scale plants)to feed one or more consumers at a reasonable distance so that the use of the public grid is minimized.Such disconnection between production and consumption would help to alleviate the constraint of the local self-consumption ratio and allow for a better use of available space on roofs or land.France,the Netherlands and Australia allow it under different forms,mostly for small-scale installations.Task 1 Strategic PV Analysis and Outreach 2021 Snapshot of Global PV Markets 20 In many countries,such policies encounter a fierce resistance from many distribution system operators who fear for their future financing.With a growing share of distributed generation and self-consumption,the question of grid finance is a key issue to address,together with other new uses of distribution grids to charge EV or for heating through heat-pumps.In the Clean energy for all Europeans package,the European Union introduced the concept of Renewable Energy Communities(REC)and of Citizen Energy Communities(CEC).REC should allow citizens to sell renewable energy production to their neighbours,while some crucial components are the definition of the perimeter and the tariffication for grid use.Those key components are defined in the national implementation in the member states.This concept of energy communities is likely to expand existing PV market segments and to allow cost reductions for consumers not able to invest in a solar installation themselves.7.3 Local manufacturing policies 2021 has seen numerous initiatives favouring local manufacturing at various steps of the PV value chain.The increasing importance of PV in the energy sector,and its expected growth are pushing numerous governments to support local manufacturing through policies,subsidies and regulations.While trade conflicts have diminished in intensity in the last years,the willingness to support local production has increased with initiatives in Europe,the USA,India,Morocco or Saudi Arabia.This reflects the growing perception of the importance that PV could take in the coming years and the willingness to secure strategic production in some countries.This trend is increasing globally,often without a clear understanding of the industry dynamics and the complexities of PV manufacturing,which will lead to less real projects than what some governments would like to see.In addition to this,the growing share of PV in the production of some components,like glass sheets for instance,starts to represent a growing share of the total production,with local and global impacts in case of shortage as seen in China in 2021.In that respect,local manufacturing will imply the access to global value chains and the role of already existing global actors shouldnt be neglected.Task 1 Strategic PV Analysis and Outreach 2021 Snapshot of Global PV Markets 21 8 PV IN THE BROADER ENERGY TRANSITION 8.1 PV and Other Renewable Energy Evolutions PV will play a key role in the energy transition.This trend is already visible when looking at the evolution of the renewable energy technologies as shown in Figure 7.In the last 15 years,PV technology has shown an ever-increasing market growth thanks to technology and price development.In the last three decades,PV has gone from being a niche technology,mostly used for electricity production either in space or in remote places,to a mainstream energy source.Sources:compilation of IEA PVPS,BNEF,GWEC,IRENA and estimations for 2021 In 2021,solar PV stood for approximately 40%of the total renewable electricity production from new production assets.The difference with the figure above is due to the different capacity factors of renewable technologies.Whereas biomass installations can virtually produce all day and all year-round,wind and solar installations outputs strongly depend on the available resources that can vary locally.Sources:IEA PVPS,BNEF,GWEC and estimations for 2021 050100150200250300350201020112012201320142015201620172018201920202021GWpFIGURE 7:EVOLUTION OF RENEWABLE ENERGY ANNUAL INSTALLATIONSWindSolarHydroOther renewables(non hydro)FIGURE 8:ELECTRICITY PRODUCTION OF THE RENEWABLE ENERGY CAPACITY INSTALLED IN 2021Wind offshoreWind onshoreSolar PVHydro Task 1 Strategic PV Analysis and Outreach 2021 Snapshot of Global PV Markets 22 8.2 Impact of PV Development on CO2 Emissions Global energy related CO2eq emissions have been around 33 Gt in 2021.2 This represented a 7%year on year growth mainly due to economic rebound after the historic decrease in the previous year.Indeed,the energy related CO2eq emissions decrease in 2020 was mainly to be incurred to the COVID-19 pandemic which severely impacted the global energy demand,both in transport as in the industry.The total emissions of the electricity and heat sector have reached close to 14,6 Gt of CO2eq in 2021,almost 1 000 MT of CO2eq more than the previous year.3 The role played by PV in the reduction of the CO2 emissions from electricity is continuously increasing.Based on the total electricity generated by the cumulative PV capacity installed globally at the end of 2021,around 1 100 Mt of annual CO2 emissions were avoided.This amount is calculated based on the emissions that would have been generated from the same amount of electricity produced by the different grid mixes in all countries,and taking into consideration life cycle emissions of PV systems.This represents around 7,5%of the total electricity and heat sector emissions and 3%of all energy emissions.8.3 PV Fostering Development of a Cleaner Energy System In addition to directly fighting rising CO2 emissions by offering an alternative to fossil-based electricity production,the deployment of PV technology can also work as a catalyst for other technologies with a potential to tackle climate change.Indeed,PV is now the most competitive electricity source in some market segments.The availability of this cheap electricity is starting to allow the breakthrough of“green”synthetic fuels.Given the need for seasonal storage,one key technology for the energy transition,is probably green hydrogen production.After years of research and pilot projects,the first commercial green hydrogen plants are being built all over the world.While green hydrogen can be the final product and be used in the industry instead of hydrogen produced from fossil fuels,it can also 2 IEA,Global Energy Review,CO2 Emissions(https:/www.iea.org/reports/global-energy-review-2021/co2-emissions)3 IEA,Global Energy Review:CO2 Emissions in 2021,March 2022(https:/www.iea.org/reports/global-energy-review-co2-emissions-in-2021-2)Task 1 Strategic PV Analysis and Outreach 2021 Snapshot of Global PV Markets 23 produce other fuels,which prove to be transportable in an easier way:ammonia,methanol,toluene or similar.Another example of synergies between PV and other sectors are electric vehicles(EV).The electrification of transport is accelerating in many countries;and almost all of which are active in the IEA PVPS Technology Collaboration Programme.The link between PV development and EVs is not straightforwardly understood yet,but it is simply becoming a reality with the growth of self-consumption policies.Charging EVs during peak load hours implies to rethink power generation,while concepts such as virtual self-consumption could rapidly provide a framework for rapid PV development.The accelerated development of the EV market could be compared to the development of the PV market.With close to 7 million EVs sold in 2021 alone,with an increase of more than 100%compared to 2020,the penetration of EVs is likely to breakthrough more quickly than PV did initially.Source:IEA PVPS&EV Volumes 0123456702040608010012014016018020020082009201020112012201320142015201620172018201920202021EV sales(millions)PV installation(GW)FIGURE 9:EVOLUTION OF EV AND PV ANNUAL GROWTH PV installation(GW)EV sales(millions)Task 1 Strategic PV Analysis and Outreach 2021 Snapshot of Global PV Markets 24

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NationalGridESO：2022-23电力市场冬季展望报告（英文版）（25页）.pdf

Winter Outlook Report6 October 2022Helping to inform the electricity industry and prepare for the winter aheadSince last winter the world has fundamentally changed with the invasion of Ukraine by Russia.With this backdrop the ESO presents the Winter Outlook.Building on the Early View of Winter,this document presents a more detailed view focusing on the upcoming winter in Great Britain.This Winter Outlook covers the period from 31 October 2022 to 31 March 2023.The data freeze date for this outlook was 22 September 2022.This Winter Outlook is developed in the context of unprecedented turmoil and volatility in energy markets in Europe and beyond and,as we stated earlier in the year,shortfalls of gas in continental Europe could have a range of knock-on impacts in Britain.Therefore,in this Winter Outlook in addition to our Base Case,we also set out scenarios to illustrate the implications should some of those risks to security of energy supplies materialise.Our central view remains,as set out in the Base Case,that there will be adequate margins(3.7GW/6.3%)through the winter to ensure Great Britain remains within the reliability standard1,although we expect there to be days where we will need to utilise many of the tools in our operational toolkit,including use of system notices2.Given the scale of uncertainty and risks associated with the current geopolitical situation we have developed a range of new tools,including:Publishing an early view of winter to help the market understand risks contracting to retain approximately 2GW of coal fired generation that would otherwise have closed and introducing an innovative Demand Flexibility Service to incentivise customers to reduce consumption at periods when margins are tight.Notwithstanding the mitigation measures noted above,it is highly likely that the wholesale price of energy(both gas and electricity)will remain very high throughout the winter outlook period3.While our Base Case assumes that capacity across all providers(generation,storage,interconnection etc.)is available in line with commitments secured under the Capacity Market,we have also modelled a scenario whereby the energy crisis in Europe results in electricity not being available to import into Great Britain from continental Europe.This could be due to a combination of factors,including a shortage of gas in Europe(which in turn limits power generation in Europe)and/or generation unavailability(e.g.,due to a high level of outages across the French nuclear fleet).We have also considered the scenario where there is a shortfall of gas available in Great Britain.Executive summary2 2Fintan SlyeDirector,Electricity System Operator1 The reliability standard is 3 hours Loss of Load Expectation(LOLE).Modelling shows the Base Case LOLE to be 0.2 hrs,well within the standard.2 These would include Electricity Margin Notices(EMNs),Capacity Market Notices(CMNs)etc.3 This will also lead to higher balancing costs as the costs of each required action are linked to the wholesale price of electricity as bid into the Balancing Mechanism or offered for trades on interconnectors.Executive summary3 3Our first illustrative scenario examines what would happen if there were no electricity imports from continental Europe4.In this scenario we would deploy our mitigation strategies dispatching the retained coal units and our Demand Flexibility Service.By securing 4GW5through these actions,we would maintain adequate margins and mitigate impacts on customers.Our Demand Flexibility Service is new and innovative,and we have worked with suppliers,aggregators,industry,Ofgem and BEIS on the design to ensure it is ready for the winter and capable of delivering the required level of participation and response(2 GW ).It will launch on 1 November,and we are encouraging suppliers and aggregators to work with their customers to ensure the highest levels of engagement and participation.We see particular potential from commercial organisations who can shift their load from peak hours and have had positive feedback from British companies on this.Without the Demand Flexibility Service,we would expect to see a reduction in margins.In this scenario on days when it was cold(therefore likely high demand),with low levels of wind(reduced available generation),there is the potential to need to interrupt supply to some customers for limited periods of time in a managed and controlled manner.However,we expect the mitigations outlined above to be effective.A second,more extreme scenario,looks at a hypothetical escalation of the energy crisis in Europe such that there is insufficient gas supply available in Great Britain(in addition to no electricity available to import from continental Europe as per above scenario).In the unlikely event that escalation of the situation in Europe means that insufficient gas supply were to be available in Great Britain this would further erode electricity supply margins6potentially leading to interruptions to customers for periods.All possible mitigating strategies,including our new measures,would be deployed to minimise the disruption.Overall,this is likely to be a challenging winter for energy supply throughout Europe.We have taken extensive measures to try to mitigate the impacts for British consumers and expect that,under our base case,margins will be adequate.Nevertheless,there remain scenarios,driven principally by factors outside of Great Britain which could impact upon British electricity supplies.Plans are in place to ensure the impact is minimised and the overall security and integrity of Britains energy systems are protected.This document only covers the electricity outlook for the winter ahead;the Gas Winter Outlook can be found here.For more information,you can email us at 4 The scenario assumes no electricity imports available from France,Netherlands and Belgium;1.2 GW imports from Norway;0.4 GW exports to Northern Ireland&Ireland.5 We expect the additional coal units to provide 2 GW and therefore the Demand Flexibility Service would need to provide 2 GW.6 Due to the curtailment of gas supplies to gas fired power stations in GB for example CCGTs etc.Executive summary3Base case5Winter scenarios 8Scenario 19Scenario 210Demand 11Supply 12Europe and interconnected markets14Market prices 18Appendices 19Glossary214 4Executive summary2Base case5Winter scenarios 8Scenario 19Scenario 210Demand 11Supply 12Europe and interconnected markets14Market prices 18Appendices 19Glossary21ContentsThe de-rated margin of 3.7GW(6.3%)is similar to both our Early View of Winter and margins that we have had in recent years.The Base Case loss of load expectation(LOLE)is around 0.2 hours/year,which is within Reliability Standard of three hours per year set by Government.Our base case assumes electricity imports from Europe are available at times when we need them to meet demand,delivering in line with their Capacity Market agreements,and that there is no disruption to gas supplies.Our base case does not assume any material reduction of consumer demand due to high energy prices.It does not include any of our mitigation measures such as coal contracts or the Demand Flexibility Service as we would not expect to deploy them here.The chart in Figure 2 shows the de-rated margins included in previous Winter Outlook Reports and highlights how this years de-rated margin is similar to those in some recent winters(e.g.2015/16,2016/17 and 2021/22).If there are some tight periods this winter,we may need to use our standard operational tools such as issuing Electricity Margin Notices(EMNs).Capacity Market Notices(CMNs)may also be issued.We expect there to be sufficient available supply to respond to these signals to meet demand.System margins are expected to be adequate in our Base Case.Notwithstanding this we expect there may be days when we need to use our operational tools.Figure 1.Supply margin in relation to generation capacity and demand5 5Base Case/System marginsFigure 2.Historic de-rated margin forecasts made ahead of each winter in the Winter Outlook Report(i.e.not out-turns)11 Includes additional reserves(Supplemental Balancing Reserve and Demand Side Balancing Reserve SBR and DSBR)of 2.4 GW and 3.5 GW procured in 2015/16 and 2016/17 respectively.How our assessments are developedAs we get closer to winter,we move from an assessment that considers the winter as a whole,to one where we consider much greater temporal granularity on a week-by-week and day-by-day basis.This is our operational modelling.It includes actual plant outages,current weather patterns and price differentials that drive interconnector flows.It is based on transmission demand and generation,and therefore represents the perspective from our control room based on what the market is currently intending to provide(i.e.before use of our operational tools).Our operational modelling helps to identify when tight periods are most likely to occur,and to indicate when we may need to use our operational tools to manage margins.These periods do not necessarily occur at times of peak demand.This view will change throughout winter,based on weather and changes to plant outages.Our Base Case operational view assumes imports from Continental Europe in line with Capacity Market agreements.It also assumes 750MW exports to Ireland,which is based on long-term historic flows.However,we have observed that the flows on Irish interconnectors have become much more variable in recent years(see page 17)and could reverse direction in the event of tight periods in Great Britain,responding to market signals.Our Base Case operational view does not include potential market responses to higher demand or tighter conditions,such as power stations increasing their output levels for short periods.Nor does it include our mitigation measures for winter(i.e.the contingency coal contracts or the Demand Flexibility Service).During periods of low operational surplus,generators may be incentivised to reschedule planned outages by Capacity Market obligations or through revenue opportunity from higher market prices.ACS demand has historically always occurred between the first week in December and the first week in February,but never during the Christmas fortnight or on a weekend.This winter we expectnormalised weather corrected transmission system demand to be met in the Base Case before using any operational toolsAverage Cold Spell(ACS)transmission demand to be met under our base case with utilisation of our operational tools(e.g.system notices)normalised peak transmission demand to occur in mid December or early January,based on our latest forecaststhe minimum operational surplus is currently projected to be lowest in mid-December when these forecasts are combined with current generator submissions.Our base case operational view shows sufficient operational surplus for each week of winter.Figure 3.Day-by-day view of operational surplus for winter 2022/23(based on market data submissions from 22 September)6 6Base Case/Operational SurplusWe expect to have sufficient operational surplus throughout winter in our Base Case,even when we consider the expected natural variation of demand,wind and outages.This winter we expectto have sufficient operational surplus throughout winter when routine tools such as margin notices are used tight margins to be likely throughout December to mid-January(excluding the Christmas period).Base Case/Credible rangeFigure 4.Range of outcomes for the daily operational surplus in our Base Case under different supply and demand conditions7 7Did you know?Figure 3 shows a particular view of generation and demand from which you can extract a single view of operational surplus.However,a single view is not appropriate in assessing the potential risk due to natural variation in demand,wind,outages etc.The analysis behind Figure 4 considers a situation under typical conditions,using average weather conditions for demand,average availability for conventional generation and average wind conditions when margin is tight.To explore the variation around this central view,we simulate many possible scenarios for weather,demand,conventional generation availability,wind generation output and interconnector availability and,for each of these scenarios,we calculate the daily surplus time series across the entire winter for that scenario.We do not include any actions that could be taken by the ESO.Figure 4 shows the forecast of daily surplus under our Base Case,with the shaded region representing the credible region within which the surplus can fluctuate.It is important to note that,although on any given day the fluctuation can reach the lower bound(or dip below it),it is not credible that surplus will remain at the lower bound level for the entirety of the winter.We look at a day-by-day analysis,finding the daily credible range of values for the surplus.By credible we mean a 90%confidence bound for the day-by-day fluctuations in surplus between 5%and 95%The modelling here considers the natural variation of forced outages.Planned outages are assumed to be in line with those declared through REMIT at the time of the data freeze for this report.This modelling also assumes that,for continental interconnectors,market forces will allow flow into GB of whatever interconnector capacity is available after unplanned outages.Winter scenarios Scenario 1:Reduced electricity imports from EuropeDue to risks created by the invasion of Ukraine by Russia,we have modelled a scenario where the energy crisis in Europe results in electricity not being available to import into Great Britain from continental Europe at times when we need it.This could be due to a combination of factors,including a shortage of gas in Europe(which in turn may limit power generation in Europe)and/or generation availability(e.g.due to a high level of outages across the French nuclear fleet).This scenario assumes no electricity imports from France,Belgium and the Netherlands for the whole winter.We continue to assume 1.2GW imports from Norway,with a total of 0.4GW sustained exports to Northern Ireland and Ireland.In this scenario we would need to deploy our mitigation strategies,and so we assume the additional coal units(around 2GW)are available to dispatch by the ESO and the Demand Flexibility Service is deployed(delivering around 2GW).In addition to our Base Case,we have set out two scenarios to illustrate the risks and uncertainties for winter.These scenarios are not forecasts and they do not indicate an expectation or likelihood of these situations materialising.8 8Scenario 2:Reduced electricity imports from Europe combined with insufficient available gas supply in Great BritainWe have also considered a situation where there is a shortfall of gas supply available in Great Britain.In addition to the assumptions of Scenario 1,we have chosen to model a two-week period in January in which around 10GW CCGTs are unavailable due to a gas shortage.We continue to assume the additional coal units(around 2GW)are available to dispatch by the ESO and the Demand Flexibility Service is deployed(delivering around 2GW).We have modelled this scenario to illustrate the impact on the electricity system if there is insufficient gas supply available in GB.For further details on the Gas Winter Outlook,please refer National Grid Gas Transmissions 2022/23 Winter Outlook Report.In this scenario we assume that we have no electricity interconnector imports from France,Belgium and the Netherlands(these are assumed to provide a de-rated capacity of 3.9GW in the Base Case).It is assumed that we import 1.2GW from Norway and export 0.4GW to Northern Ireland and Ireland.In this situation we would deploy both the contingency coal contracts(around 2GW)and the Demand Flexibility Service(assumed around 2GW).This would result in a de-rated margin of 3.3GW(5.7%)with an LOLE of 0.5 hours/year,broadly similar to our Base Case.Without sufficient take-up of the Demand Flexibility Service,we would still expect margins1to be within the Reliability Standard of three hours LOLE per year.In this case,there may be days when it was cold(therefore likely high demand),with low levels of wind(reduced available generation),where there is the potential to need to interrupt supply to some customers for limited periods of time in a managed and controlled manner.However,our expectation is that our mitigation measures will be effective.Credible range for surplusFigure 6 shows the variation in operational surplus for Scenario 1.It uses the same approach as outlined on page 8 to reflect the natural variation of demand,wind and outages,for the assumptions set out for this scenario.It assumes contingency coal contracts and the Demand Flexibility Service are deployed.The tightest periods are from late November to January,where the daily margin often drops below zero.This does not mean that there will be interruption to supply.It means that it is more likely we will need to use our operational tools at these times(e.g.system notices).In deploying both the contingency coal contracts and the Demand Flexibility Service,we would expect to mitigate the risk of supply disruption to customers.We expect to use coal contracts and our Demand Flexibility Service to maintain adequate margins if imports from Europe are not available when we need.Figure 5.Supply margin in relation to generation capacity and demand for Scenario 19 9Scenario 1/Reduced electricity imports from EuropeFigure 6.Range of outcomes for the daily operational surplus in Scenario 1 under different supply and demand conditions1Assuming 0GW from the Demand Flexibility Service results in a de-rated margin of 2GW/3.3%with an LOLE of 2.4 hours/year.The shift in margin is less than the 2GW from DFS due to the way wind(which is variable)is represented as a single number through its Equivalent Firm Capacity(EFC)in the margin.The EFC value changes with system tightness even though we model its full variability in the LOLE calculation in the same way.In this scenario we assume the same assumptions as Scenario 1,but with an additional 10GW CCGTs unavailable for a two-week period in January1.These assumptions have been chosen to illustrate the potential impact on the electricity system if there was insufficient gas supply in Great Britain.As this scenario only considers a specific,limited time period within the winter,we can only consider it using the modelling for our operational view.We are unable to provide a de-rated margin or LOLE value for this scenario.Credible range for surplusFigure 7 shows the variation in operational surplus for Scenario 2.Coal contingency contracts(around 2GW)and the Demand Flexibility Service(around 2GW)are both assumed to be deployed.The impact of this is evident from the large negative surplus on the chart.The magnitude of this surplus is such that we would not expect there to be a sufficient response from the rest of the market to prevent interruptions to consumer supplies.Should this scenario happen,it may be necessary to initiate the planned,controlled and temporary rota load shedding scheme under the Electricity Supply Emergency Code(ESEC).In the unlikely event we were in this situation,it would mean that some customers could be without power for pre-defined periods during a day generally this is assumed to be for 3 hour blocks.This would be necessary to ensure the overall security and integrity of the electricity system across Great Britain.All possible mitigating strategies would be deployed to minimise the disruption.The extent of rota load shedding would depend on the number of CCGTs that are unavailable and the duration for which there is insufficient gas to meet power station demand.If there is insufficient gas in GB for power generation combined with reduced electricity imports from Europe then this could erode security of supply margins.1010Scenario 2/Reduced electricity imports from Europe combined with insufficient gas supply in Great Britain Figure 7.Range of outcomes for the daily operational surplus in Scenario 2 under different supply and demand conditions1We have arbitrarily assumed 9 23 January 2023Demand/Normal peak demandThis winter we expectweather corrected peak transmission system demand(TSD)to be 45.3GW,based on assumptions in Table 1.minimum demand under normal weather conditions to be 20.7GW(assuming no interconnector exports overnight).triad avoidance of up to 0.8GWWeather corrected peak demand for winter 2022/23 is expected to be lower than the previous winter,but higher than winter 2020/21 which was affected by COVID-19 restrictions.Weather corrected minimum demand is expected to be greater than last winter.Transmission connected power station demand600MWBase case interconnector exports to Ireland(at time of peak)750MWEmbedded wind capacity6.5GWEmbedded solar capacity13.1GWPumped storage(at time of peak)0GWDid you know?The ESO is currently consulting with the energy industry on proposals for a new Demand Flexibility Service to run between November 2022 and March 2023.This service will incentivise consumers and businesses to reduce or reschedule their electricity use away from peak times.The service will be offered by suppliers and aggregators to their customers.This could reduce peak demand below levels shown in the forecast in Figure 8 by up to around 2GW.Figure 8.Historical and forecast normalised weekly peak winter demand11 Data is adjusted for interconnector export,historical data is weather corrected,forecast uses normal weather.1111Table 1.Assumptions for weather corrected peak TSD demandSupply/OverviewAdditional coal fired generationAt the request of the Department for Business,Energy and Industrial Strategy the ESO has signed three contracts with EDF,DRAX and Uniper to provide additional coal generation this winter.Note,Figure 9 excludes this additional coal capacity.These contracts will enable the ESO to directly instruct units at West Burton A,Ratcliffe and Drax to provide around 2GW additional de-rated capacity to support the system this winter if required.These contracts are only intended to be used after all other commercial options.This could be in response to a generation shortfall over an extended period of time or a short-term margin issue.This winter we expectlower available generator capacity than last year,driven by reductions in nuclear and coal capacity available over the wintergenerator reliability to be broadly in line with recent winters(Table 2)remaining coal-fired generation to potentially run more frequently due to high gas prices(but for overall levels of coal generation to remain low due to continued reductions in capacity levels)We currently expect sufficient levels of generation and interconnector imports to meet demand throughout the winter under our base case.Breakdown ratesThe assumed breakdown rates are based on historic data to reflect how generators performed against their planned availability during peak demand periods over the last three winters(see Table 2).For nuclear and biomass,the three-year rolling average has increased when last winter was accounted for.For wind generation,we assume an Equivalent Firm Capacity(EFC)of 16%.Table 2.Breakdown rates by fuel type(based on a 3-year rolling average)1212Assumed Breakdown RatePower Station Fuel Type21/2222/23Coal11GT6%6%Nuclear9%OCGT5%7%Biomass5%6%Hydro9%8%Wind(EFC)17%Pumped storage3%3%Supply/Daily viewDid you know?Figure 9 shows a daily view of generation based on generator submissions of availability which is different to our calculation of de-rated margin for the winter on page 5.Our generation forecasts are based on published availability data broken down to a half-hourly profile,to which we apply a breakdown rate for each fuel type,to account for unexpected generator breakdowns,restrictions or losses close to real-time.We currently expect sufficient levels of generation and interconnector imports to meet demand throughout the winter under our base case.1313Figure 9.Daily generation availability by fuel type(based on market submissions and including breakdown rates)Europe and interconnected markets/OverviewDid you know?Figure 10 shows last years average interconnector flows at peak times,and during periods when operational surplus was below 2GW.These,alongside the expected prices(see page 16)are used to help inform our expectations for interconnector flows this year.The new NSL interconnector was operating at restricted capacity for part of last winter,but is now running at full capacity and is expected to import to GB especially at times of tight margins.Since last winter the ElecLink interconnector between GB and France has also come into service.This winter we expectforward prices,including peak prices,in GB to be below some of those in continental Europe across parts of the winter periodincreased exports to Continental Europe across much of the winter period driven by price differentials outside of times of system stressnet imports from Norway across the NSL interconnector across the winter period,particularly at peakimports into GB at peak times of tight margins or stress on the GB system.We dont expect interconnectors to be exporting to Europe if this would mean we were unable to meet GB demandMoyle and EWIC typically export from GB to Northern Ireland and Ireland during peak times,although at substantially less than maximum capacity due to high demand on the GB system.When operational surplus is particularly tight,exports to Northern Ireland and Ireland are expected to reduce to zero,and could even provide imports to GB.We expect more exports across the interconnectors to continental Europe from GB than in past winters.Figure 10.Historical flows on the interconnectors for winter 2021/221414Winter 2021/22Winter 2021/22Europe and interconnected markets/Peak flows analysis1.Physical capabilitiesInterconnector capability will be affected by the outages set out in the table below.The ongoing IFA outage is a result of a fire last autumn that led to reduced capacity,it is expected to come back to full capacity by mid-December.Since last winter the ElecLink interconnector between GB and France has also come into service.Our assumptions around peak flow of electricity on the interconnectors depend on a number of factors.InterconnectorMaximum capacityPlanned outagesAvailable capacity during outageIFA2GW21/10/21 30/10/221GW31/10/22 15/12/221.5GWIFA21GWn/aBritNed1GWn/aNemo Link1GWn/aEWIC500MWn/aMoyle500MWn/aNSL1.4GWn/aElecLink1GWn/a2.Capacity MarketInterconnectors have secured agreements in the Capacity Market(CM)in the T-31auction for 2022/23 as set out in Figure 11 below.While we expect increased exports this winter to continental Europe,at times of tight margins or stress in GB(e.g.,when a Capacity Market Notice was issued)we would expect to see flows into GB.Our Base Case assumes interconnectors deliver in line with their CM obligations.We have also assessed the risks and uncertainties of reduced imports from Continental Europe through our first scenario.Figure 11.Capacity Market agreements for interconnectors in Delivery Year 2022/231515Table 3.Planned interconnector outages at time of analysis1 Due to the suspension of the Capacity Market,a T-3 auction was run for delivery in 2022/23 rather than a T-4 auctionEurope and interconnected markets/Peak flows analysis3.European forward pricesElectricity flows through the interconnectors are primarily driven by the price differentials between the markets.Quarter ahead forward prices for baseload electricity during winter 2022/23 in GB are below those in the French and Dutch,but above those in the Belgian markets(see Figure 12).We therefore expect exports across the interconnectors to France and the Netherlands at times across the winter.Figure 13 shows forward prices for peakload electricity during winter 2022/23,in which GB prices are ahead of those in the Dutch market but significantly below prices in France.This indicates we may see exports to France at peak times over the winter.However,should GB experience some tight/stress periods,we would expect GB prices to escalate and interconnectors to import in line with Capacity Market obligations.We dont expect interconnectors to export to Europe if this would mean we were unable to meet GB demand;they would import or float in this situation.4.Network access constraintsTransmission outages in the regions with interconnectors could cause power flow constraints resulting in disruption to interconnector flows,particularly in the South East.This has already been challenging to manage over the summer.5.Nuclear availability in FranceFigure 14 shows French nuclear outages for the winter ahead against historical outages.While outages are high at the beginning of the winter period they are expected to drop to around 5GW(around 8%of capacity2)by January 2023.We expect these outage levels,combined with high French market prices,to lead to exports to France across much of the winter.Figure 14.The impact on French nuclear capacity from planned outages in 2022/23 and actual outages in recent years3Figure 12.Winter 2022/23 electricity baseload Figure 13.Winter 2022/23 electricity peak forward prices116161Figure 12 uses data from Bloomberg.Peak forward prices were only given for GB and France in Bloomberg,therefore Figure 13 uses data taken from Argus,which includes prices for the Netherlands.Lower liquidity means no peakload forward prices were available for Belgium.2Total French nuclear capacity is 61.4GW this winter.3 https:/www.edf.fr/en/the-edf-group/who-we-are/activities/optimisation-and-trading/list-of-outages-and-messages/list-of-outagesOverview of European interconnectorsBased on forward prices for the 2022/23 winter products,we expect imports into GB at peak times from Norway,the Netherlands and Belgium under normal network operating conditions.We may see greater levels of export to France at peak times than in previous years.Despite day ahead baseload prices in France exceeding GB prices on a number of occasions last winter we saw only limited exports to France at peak last winter,as shown in Figure 15.Europe and interconnected markets/Historic flowsOverview of Irish interconnectorsDuring peak times through winter 2022/23,we expect a similar proportion of exports to imports across the Moyle and EWIC interconnectors to Ireland.This may,however,be reversed during periods of high wind and system stress.Figure 16 shows examples of where market conditions and weather variance affected flows last winter.Last winter we saw imports at peak times throughout the winter,despite day ahead baseload prices in France sometimes exceeding those in GBFigure 16.Daily peak time flows across the Irish interconnectors in winter 2020/21(positive MW values mean imports into GB)17171Figure 15 peak forward prices were not provided for weekend days so interpolation was used to predict these values.Flows are out-turn values.Figure 15.Daily peak time flows across the continental interconnectors in winter 2021/22(positive MW values mean imports into GB)1Market prices/Winter viewDid you know?Traditionally power plants have bid into the Balancing Mechanism at prices which largely reflected the marginal cost of running the plant over that period.Capital and operational costs are generally recouped over a longer period through forward markets and/or long-term contracts.Last winter saw significantly increased prices over the year before and this winter has much higher market prices still,with baseload prices several times higher than last winter,although having dropped by a third from a peak of over 800/MWh at the end of August.We commissioned an independent review of the balancing market and have provided the report to Ofgem.This is available here.We are also enhancing our market monitoring activities this Winter.This winter we expectforward prices in GB to be higher than last year across the winter period(Figure 17).This is due to external pressures,particularly very high gas prices.days with tight margins to see spikes in the balancing mechanism.During periods of tight system margins,energy prices increase to reflect the scarcity of the resource,particularly when margin notices are issued.Forward wholesale electricity prices are significantly higher than last year.In addition,tight margin days are likely to see significant price spikes in the Balancing Mechanism.Figure 17 Historically traded quarter-ahead GB winter ahead forward electricity baseload prices for Winter 2020/21,Winter 2021/22 and Winter 2022/23 taken from Argus118181 The numbers shown in Figure 17 are historical traded prices not forecasts.Trading does not take place on weekends or bank holidays so these values have been interpolated.Appendix/Margin noticesElectricity Margin Notices(EMNs)are one of our operational tools to manage margins.They are based on operational margins which are calculated from transmission system demand and transmission system capacity.Capacity Market Notices(CMNs)are issued automatically.They act as a notice for providers with Capacity Market agreements to deliver in line with their CM obligations for the indicated settlement period(s).If the CMN remains in place,the providers who do not deliver in line with their obligations may be subject to penalties in accordance with the CM Rules.They are issued automatically and are not considered as one of our operational tools.They are based on Capacity Market margins which are calculated from whole system demand and whole system capacity(including Distributed Energy Resources(DER).While having similar intentions in stimulating a market response for tight periods,EMNs and CMNs should be considered as being part of two separate processes:the operational processes used by our control room to operate the system in real-time,and the CM penalty process.They serve different purposes,and are not part of the same sequential process.The ESO is working with Ofgem to improve the communication of system notices.This is an ongoing process and more detail will be published in due course.Electricity Margin Notices(EMNs)and Capacity Market Notices(CMNs)are used to highlight to market participants when margins are looking tight ahead of real-time.They are intended to stimulate a market response through,for example,additional generation being made available.They dont indicate that demand will not be met.1919There are a number of significant differences between the operational System Warning messages(such as EMNs)and Capacity Market Notices:1.Trigger-Capacity Market Notices are issued based on an automated system margin calculation using data provided by market participants,whereas System Warnings are manually issued by the ESO control room using engineering judgement based on experience and knowledge of managing the electricity transmission system.2.Threshold-Capacity Market Notices are triggered where the buffer between available generation and the total of forecast demand and Operating Margin falls below a threshold.The threshold is taken from the Capacity Market Rules.System Warnings are triggered by varying volumes,for example an EMN may be issued where ESO expects to utilise a certain amount of its Operating Margin.3.Constraints-The Capacity Market Notice calculation does not take account of any transmission system constraints that may be preventing capacity from accessing the network.System Warnings however do take such constraints into account.4.Lead time-Capacity Market Notices are initially issued four hours ahead of when the challenge is foreseen.System Warnings can be issued at any time but we would generally expect to issue a first EMN at the day ahead stage.For more information about margins and margin noticeshttps:/surplus analysisHow the operational surplus is calculated and usedFor the operational surplus analysis,we plan based on the operational data submitted to us.We are not just looking at the capacity provided via the Capacity Market(a market tool that helps to set us up for winter),but also at the supply that is forecast to be available on a day-by-day basis.To do this we need to consider a more granular view of the winter.We consider a daily view as we get closer to real-time and start assessing the daily views in August ahead of the Winter Outlook Report publication in October.The Winter Outlook Report includes a daily view of margins for the winter,as well as information on the effects of variability and the likelihood of tight operational margins.The operational data includes information relating to planned plant outages,the impact of weather(e.g.on wind and demand)and flows on interconnectors.As generators can also have unplanned outages,we also apply breakdown rates based on averages of the last 3 winters.In addition,we study the effects of variability of all relevant factors,particularly weather,renewable resource and unplanned outages.The operational data may be different from the assumptions based on historic data/long-term averages used for the winter view of margin.The operational surplus also considers grid constraints and largest loss requirements.In the central daily view we use a low wind scenario,so the grid constraints play only a small part in the calculation.When we consider the credible range of values,grid constraints become more significant.The operational surplus helps us to identify when we might have tight periods.However,the operational data provided to us changes throughout the winter.There may be some tight periods that are apparent a week in advance;others may not become apparent until much closer to real-time(e.g.day ahead or on the day itself).These assessments of security of supply are used to support decisions taken in operational timescales(e.g.whether to issue an EMN).Our operational surplus analysis represents the markets current intentions(i.e.based on market submissions before we take actions).This analysis is based on market submissions as of 22ndSeptember.It is a dynamic view that changes throughout winter and,as such,we will be providing regular updates at the ESO Operational Transparency Forum.It provides insight on the periods when we may need to send market signals/use tools to ensure there is enough generation on the system to meet demand and contingency requirements.The periods of tightest margins do not necessarily occur at times of peak demand but rather when supply is lowest relative to demand.2020Glossary2121Average Cold Spell(ACS)ACS methodology takes into consideration peoples changing behaviour due to the variability in weather(e.g.more heating demand when it is colder)and the variability in weather dependent distributed generation(e.g.wind generation).These two elements combine have a significant effect on peak electricity demand.Balancing MechanismThe Balancing Mechanism is a tool which we use to balance electricity supply and demand.It allows participants to set prices for which they will increase or decrease their output if requested by the ESO.All large generators must participate in the BM,whereas it is optional for smaller generators.Balancing Mechanism Unit(BMU)A unit which participates in the Balancing Mechanism.Baseload electricityA market product for a volume of energy across the whole day(the full 24hrs)or a running pattern of being on all the time for power sources that are inflexible and operate continuously,like nuclear.Breakdown rates A calculated value to account for unexpected generator unit breakdowns,restrictions or losses close to real time.Forecast breakdown rates are applied to the operational data provided to the ESO by generators.Rates are based on how generators performed on average by fuel type during peak demand periods(7am to 7pm)over the last three winters.BritNedBritNed Development Limited is a joint venture between Dutch TenneT and British National Grid that operates the electricity link between Great Britain and the Netherlands.It is a bi-directional interconnector with a capacity of 1,000MW.You can find out more at.Capacity Market(CM)The Capacity Market is designed to ensure security of electricity supply.It provides a payment for reliable sources of capacity,alongside their electricity revenues,ensuring they deliver energy when needed.Capacity Market Notice(CMN)Based on Capacity Market margins which are calculated from whole system demand and whole system capacity.For more information about margins and margin notices see:https:/Combined Cycle Gas Turbine(CCGT)A power station that uses the combustion of natural gas or liquid fuel to drive a gas turbine generator to produce electricity.The exhaust gas from this process is used to produce steam in a heat recovery boiler.This steam then drives a turbine generator to produce more electricity.Contingency coal contractsAt the request of the Department for Business,Energy and Industrial Strategy the ESO has signed three contracts with EDF,DRAX and Uniper to provide additional coal generation this winter.More details can be found here:https:/flexibility serviceThe ESO is currently consulting with the energy industry on proposals for a new Demand Flexibility Service to run between November 2022 and March 2023.This service will incentivise consumers and businesses to reduce or reschedule their electricity use away from peak times.The service will be offered by suppliers and aggregators to their customers.More details can be found here:https:/suppressionThe difference between our pre-Covid forecast demand levels and the actual demand seen on the system.We have not included any Covid-related demand suppression this winter.Glossary2222De-rated margin for electricityThe sum of de-rated supply sources considered as being available during the time of peak demand plus support from interconnection,minus the expected demand at that time and basic reserve requirement.This can be presented as either an absolute GW value or a percentage of demand(demand plus reserve).The formula was revised in winter 2017/18 to include distribution system demand,and in winter 18/19 to better account for interconnection.See our previous publications for further details(https:/Energy Resources(DER)Resources connected to the distribution network which can generate or offtake electricity.East West Interconnector(EWIC)A 500MW interconnector that links the electricity transmission systems of Ireland and Great Britain.You can find out more at 1000MW interconnector that links the electricity transmission systems of France and Great Britain.You can find out more at https:/www.eleclink.co.uk/.Embedded generationPower generating stations/units that are not directly connected to the National Grid electricity transmission network and for which we do not have metering data/information.They have the effect of reducing the electricity demand on the transmission system.Electricity Margin Notice(EMN)Based on operational margins which are calculated from transmission system demand and transmission system capacity.For more information about margins and margin notices see:https:/Firm Capacity(EFC)An assessment of the entire wind fleets contribution to capacity adequacy.It represents how much of 100 per cent available conventional plant could theoretically replace the entire wind fleet and leave security of supply unchanged.Float/FloatingWhen an interconnector is neither importing nor exporting electricity.Forward pricesThe predetermined delivery price for a commodity,such as electricity or gas,as decided by the buyer and the seller of the forward contract,to be paid at a predetermined date in the future.Grid CodeThe Grid Code details the technical requirements for connecting to and using the National Electricity Transmission System(NETS).GW Gigawatt(GW)A measure of power.1GW=1,000,000,000 watts.InterconnectorElectricity interconnectors are transmission assets that connect the GB market toContinental Europe and Ireland.They allow suppliers to trade electricity between thesemarkets.Interconnexion FranceAngleterre(IFA)A 2,000MW link between the French and British transmission systems.Ownership is shared between National Grid and Rseau de Transport dElectricit(RTE).See more at https:/FranceAngleterre 2(IFA2)A 1,000MW link between the French and British transmission systems commissioned in 2020.Ownership is shared between National Grid and Rseau de Transport dElectricit(RTE).See more at https:/factors The amount of electricity generated by a plant or technology type across the year,expressed as a percentage of maximum possible generation.These are calculated by dividing the total electricity output across the year by the maximum possible generation for each plant or technology type.Loss of Load Expectation(LOLE)LOLE is the expected number of hours when demand is higher than available generation during the year before any mitigating/emergency actions are taken but after all system warnings and System Operator(SO)balancing contracts have been exhausted.It is important to note when interpreting this metric that a certain level of loss of load is not equivalent to the same amount of blackouts;in most cases,loss of load would be managed by actions without significant impacts on consumers.The Reliability Standard set by the Government is an LOLE of 3 hours/yearMinimum demandThe lowest demand on the transmission system.This typically occurs overnight.MoyleA 500MW bi-directional interconnector between Northern Ireland and Scotland.You can find out more at www.mutual-.MW Megawatt(MW)A measure of power.1MW=1,000,000 watts.Nemo Link A 1GW HVDC sub-sea link between GB and Belgium.See more at https:/www.nemolink.co.uk/.North Sea Link(NSL)A 1.4GW HVDC sub-sea link from Norway to GB commissioned this October.See more at https:/transmission demandThe demand seen on the transmission system,forecast using long-term trends and calculated with the effects of the weather and the day of the week removed as appropriate.This takes into account the power used by generating stations when producing electricity(the station load)and interconnector exports.Normalised peak transmission demandThe peak demand seen on the transmission system,forecast using long-term trendsand calculated with the effects of the weather and the day of the week removed asappropriate.This takes into account the power used by generating stations whenproducing electricity(the station load)and interconnector exports.Operational surplusThe difference between the level of demand(plus the reserve requirement)andgeneration expected to be available,modelled on a week-by-week or day-by-day basis.It includes both notified planned outages and assumed breakdown rates for each powerstation type.OutageThe annual planned maintenance period,which requires a complete shutdown,duringwhich essential maintenance is carried out.Peakload electricityA market product for a volume of energy for delivery between 7am and 7pm onweekdays.Pumped storageA system in which electricity is generated during periods of high demand by the use of water that has been pumped into a reservoir at a higher altitude during periods of low demand.Reactive powerThe movement of energy across a network which is measured in MVAr.Different types of network assets and generators can generate or absorb reactive power.The flows of reactive power on a system affect voltage levels.REMITREMIT data is information provided by market participants to comply with Article 4 of Regulation on Wholesale Energy Market Integrity and Transparency(REMIT)Regulation(EU)1227/2011.GlossaryGlossary2424RenewablesElectricity generation from renewable resources,which are naturally replenished,such as sunlight or wind.Reserve requirementTo manage system frequency,and to respond to sudden changes in demand and supply,the ESO maintains positive and negative reserve to increase or decrease supply and demand.This provides head room(positive reserve)and foot room(negative reserve)across all assets synchronised to the system.Rota load sheddingScheduled disconnection and reconnection of electricity supplies in an electricity supply emergency,as set out in the governments Electricity Supply Emergency Code(ESEC).Seasonal normal weatherThe average set of conditions we could reasonably expect to occur.We use industry agreed seasonal normal weather conditions.These reflect recent changes in climate conditions,rather than being a simple average of historic weather.Short Term Operating Reserve(STOR)At certain times of the day,we may need access to sources of extra power to help manage actual demand on the system being greater than forecast or unforeseen generation unavailability.STOR provides this reserve.System Operator Transmission Code(STC)The System Operator Transmission Owner Code defines the relationship between the Transmission Owners(TOs)and the ESO.Technical capabilityThe capacity of connected plant expected to be generating in the market,based on the Capacity Market auctions and another sources of market intelligence,but not taking any account of potential breakdown or outage.Transmission System Demand(TSD)Demand that the ESO sees at grid supply points,which are the connections to the distribution networks.Triad avoidance When demand side customers reduce the amount of energy they draw from the transmission network,either by switching to distributed generation sources,using on-site generation or reducing their energy consumption.This is sometimes referred to as customer demand management but we refer here to customer behaviour that occurs close to anticipated Triad periods,usually to reduce exposure to peak time charges.TriadsThe three half-hourly settlement periods with the highest electricity transmission system demand.Triads can occur in any half-hour on any day between November and February.They must be separated from each other by at least ten days.Typically,they take place on weekdays around 4.30 to 6pm.Underlying demandDemand varies from day to day,depending on the weather and the day of week.Underlying demand is a measure of how much demand there is once the effects of the weather,the day of the week and distributed generation have been removed.VoltageUnlike system frequency,voltage varies across different locations on the network,depending on supply and demand for electricity,and the amount of reactive power in that area.Broadly,when electricity demand falls,reactive power increases and this increases the likelihood of a high voltage occurrence.Weather corrected demand The demand expected or out-turned with the impact of the weather removed.A 30-year average of each relevant weather variable is constructed for each week of the year.This is then applied to linear regression models to calculate what the demand would have been with this standardised weather.Western High Voltage(HVDC)Link(WLHVDC)The Western Link uses DC technology to reinforce the UK transmission system and move electricity across the country in very large volumes between Hunterston in Scotland and Deeside in North Wales.Winter period The winter period is defined as 1 October to 31 March.2525Join our mailing list to receive email updates on our Future of Energy us with your views on the Winter Outlook Report at:and we will get in touch.You can write to us at:Energy InsightsElectricity System OperatorFaraday HouseWarwick Technology ParkGallows HillWarwickCV34 6DAElectricity System Operator legal noticePursuant to its electricity transmission licence,National Grid Electricity System Operator Limited is the system operator of the national electricity transmission system.For the purpose of this outlook document,the terms“we”,“our”,“us”etc.are used to refer to the licensed entity,National Grid Electricity System Operator Limited.National Grid Electricity System Operator Limited has prepared this outlook document pursuant to its electricity transmission licence in good faith,and has endeavoured to prepare this outlook document in a manner which is,as far as reasonably possible,objective,using information collected and compiled from users of the electricity transmission system together with its own forecasts of the future development of those systems.While National Grid Electricity System Operator Limited has not sought to mislead any person as to the contents of this outlook document and whilst such content represent its best view as at the time of publication,readers of this document should not place any reliance on the contents of this outlook document.The contents of this outlook document must be considered as illustrative only and no warranty can be or is made as to the accuracy and completeness of such contents,nor shall anything within this outlook document constitute an offer capable of acceptance or form the basis of any contract.Other than in the event of fraudulent misstatement or fraudulent misrepresentation,National Grid Electricity System Operator Limited does not accept any responsibility for any use which is made of the information contained within this outlook document.

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NationalGridESO：2022 年电力市场回顾报告（英文版）（26 页）.pdf

Winter Review and ConsultationJune 2022Helping to inform the electricity industry,reflect on last winter and prepare for the winter ahead.SectionPageWelcome2Key Messages3Margins4-10Triad Avoidance11Electricity Supply12Europe and Interconnected Markets13-15Operational View16-17Consultation questions18-19Appendix20-22Glossary23-25Welcome ContentsWelcome to our 2022 Winter Review and Consultation Report.This annual document provides a review of how what we said in the 2021/22 Winter Outlook Report compared to what actually happened.This document includes a review of all the standard analysis from the 2021/22 Winter Outlook Report in relation to elements such as demand levels,performance of generators and any operability challenges faced.This year we will be publishing an early view of Winter 2022/23 in July 2022 to give earlier information to the industry in light of the recent very high energy prices.This means that the consultation questions in this document are less specific to the coming winter and more about this document and the Electricity Outlooks process in general.However,feedback on our potential plans and on preparations for the upcoming winter remains extremely important and so we will make sure any comments and information received via this document are passed to the relevant teams within the ESO.If you would like to share your views,or if you have any general queries or comments,please dont hesitate to email us at,join us for a discussion at our Operational Transparency Forum(OTF)or get in touch via social media.This document covers Winter 2021/22 from the electricity perspective.National Grid Gas Transmission(NGGT)publish a similar document from the gas perspective,the Gas 2022 Winter Review and Consultation Report,which can be found here.We continue to engage with NGGT on approach and consistency.2Key Messages/Winter Review 2021-22123MarginsMarginsPricesPricesAs margins over winter 2021/22 were less tight than the previous winter,no Electricity Margin Notices(EMNs)were issued.The Winter Outlook Reporthighlighted a potential need for EMNs but none were issued.High wholesale electricity prices meant that the cost of individual ESO actions was higher than in previous years although overall volumes of actions were lower.This was largely due to the unexpected and significant rise in gas prices which translated into higher balancing costs overall and therefore increased costs for consumers.System conditionsSystem conditionsConditions over Winter 2021/22 were close to average with no prolonged cold spells coincident with low wind output.Interconnectors imported when needed,and availability of thermal generation was in line with forecasts.3Review/MarginsOperational surplus:a look back at our Winter Outlook Report forecastsThe 2021/22 Winter Outlook Report contained a day-by-day view of operational margin(also referred to as surplus)and this is shown in Figure 1.The green bars represent the transmission system demand forecast(under average weather conditions,with average embedded wind generation).Demand is then combined with the expected reserve requirement(in orange).The red dotted line represents where demand and reserve could be,should average cold temperature conditions be experienced thereby raising demand levels.This is referred to as ACS(Average Cold Spell)conditions.Finally,the light and dark blue and purple lines represent the forecast of generation supply when combined with low,medium and high imports from interconnectors.Note that generation supply is made up of Balancing Mechanism generation availability submissions(de-rated using historic data to take account of breakdowns)plus an assumption of expected wind generation.Other forms of distribution connected generation are excluded as quoted demands are at transmission level.This day-by-day chart showed that normalised peak transmission demand was expected in mid-December.The minimum operational surplus under average weather conditions was projected to be lowest throughout December to mid-January(excluding the Christmas period).Figure 1.Day-by-day forecast view of operational surplus for winter 2021/22(Figure 1 from Winter Outlook Report 2021/22)3035404550556001 Nov 2108 Nov 2115 Nov 2122 Nov 2129 Nov 2106 Dec 2113 Dec 2120 Dec 2127 Dec 2103 Jan 2210 Jan 2217 Jan 2224 Jan 2231 Jan 2207 Feb 2214 Feb 2221 Feb 2228 Feb 2207 Mar 2214 Mar 2221 Mar 22GWDateReserve requirementMax normal demand forecast(inc.Ireland export and no triad avoidance)ACS forecast demand inc.reserve requirement and exports to IrelandAssumed generation with low imports from EuropeAssumed generation with medium imports from EuropeAssumed generation with high imports from Europe4How did the winter compare to the forecast in the Winter Outlook Report?Figure 2 overlays the forecast from the Winter Outlook Report with the actual outturns from the winter for both demand and plant availability and is designed to be comparable with Figure 1 on the previous page.Demandgreen and orange bars respectively show the forecast daily normal demand and reserve requirements as in the Winter Outlook Report(exact same values)solid black line indicates daily outturn total of“demand plus reserve”.dotted red line represents the forecast Average Cold Spell(ACS)peak demand at transmission level as in the Winter Outlook Report(exact same values).The actual winter peak demand was close to the forecast peak,and well below the ACS peak.Supplydotted purple line shows the daily expected plant availability under the base case interconnector scenario from the Winter Outlook Report(exact same values).solid yellow line shows the actual daily plant availability,including wind output and interconnector flows.Tight margin days,occur when the solid black outturn demand is close to the solid yellow outturn supply.The graph in Figure 2 clearly demonstrates the variability inbothdemandandgenerationbutalsoshowshealthymargins for the majority of the winter.Figure 2.Day-by-day view of actual operational surplus for winter 2021/2253035404550556001 Nov 2108 Nov 2115 Nov 2122 Nov 2129 Nov 2106 Dec 2113 Dec 2120 Dec 2127 Dec 2103 Jan 2210 Jan 2217 Jan 2224 Jan 2231 Jan 2207 Feb 2214 Feb 2221 Feb 2228 Feb 2207 Mar 2214 Mar 2221 Mar 22GWDateReserve requirementMax normal demand forecast(inc.Ireland export and no triad avoidance)ACS forecast demand inc.reserve requirement and exports to IrelandAssumed generation with medium imports from EuropeActual Available GenerationActual Demand&ReserveReview/MarginsHow did the winter compare to the forecast in the Winter Outlook Report?Figure 3 overlays the forecast range for operational surplus from the Winter Outlook Report with the actual outturns from the winter for operational surplus.In the Winter Outlook Report we published a central view for operational surplus(dashed green line)which assumed typical conditions and medium imports.To explore the sensitivities around this central view,we simulated many possible scenarios for weather,demand,conventional generation availability,wind generation output and interconnector availability and,for each of these scenarios,we calculated the daily surplus time series across the entire winter for that scenario.This did not include any ESO actions.Our credible range was defined as the 90%confidence bound for the day-by-day fluctuations in surplus(red dashed area on chart).Figure 3 overlays this forecast range with the outturn of operational surplus for winter 21/22(solid purple line).From this you can see that the actual surplus varies across the winter,but stays within this range for the vast majority of the time.There were just 15 days when the surplus was outside this range,these were the days with the tightest margins.Figure 3.Day-by-day view of actual operational surplus for winter 2021/22 against the forecast surplus and credible range sensitivity from the Winter Outlook Report-50510152025303501 Nov 2111 Nov 2121 Nov 2101 Dec 2111 Dec 2121 Dec 2131 Dec 2110 Jan 2220 Jan 2230 Jan 2209 Feb 2219 Feb 2201 Mar 2211 Mar 2221 Mar 22GWDateForecast surplus-90%confidence boundSurplus under average conditions with medium importsIndicative outturn surplus6Review/MarginsReview/MarginsHow did the winter compare to the forecast in the Winter Outlook Report?Overall,winter 21/22 was windier than the previous winter,and temperatures were close to the seasonal average,meaning margins were not unduly tight.What we said in the Winter Outlook ReportWhat actually happenedWhy was there a difference?Average Cold Spell(ACS)transmission demand to be met on all days under the high and medium import interconnector scenarios.ACS demand(calculated proxy rather than metered figure)would not have been met in all weeks but there was sufficient generation and interconnector imports to meet demand throughout the winter period.The Winter Outlook Report considers what would happen under different average conditions whilst the outturn fluctuates around the average level.Had cold spells fallen on different days the ESO would have called upon the market to deliver a response through its range of routine tools(parison has to be hypothetical).To have sufficient operational surplus throughout winter when routine tools such asmargin notices are used.We expect to issue a broadly similar number of EMNs as last year(EMNs in winter2020/21=6).Operational surplus was sufficient throughout the winter and we issued just two CMNs and no EMNs.Surplus was within our credible range of outcomes throughout the majority of the winter.The Winter Outlook Report considered the possibility of system conditions being outside of the typical range.Temperatures outturned close to the seasonal normal average,interconnector availability and flow patterns over tight periods were as expected and wind output levels were generally high.Table 1 below shows the days when Electricity Margin Notices(EMNs)and Capacity Market Notices(CMNs)were issued over the winter period.There were no EMNs issued in winter 2021/22(compared to 6 issued in winter 2020/21),and there were only 2 CMNs(winter 2020/21:2 CMNs).Across the last two winters,three CMNs have been issued when margins were relatively healthy,including both CMNs last winter.Under a specific set of circumstances,CMN margin is calculated to be too pessimistic.The ESO are implementing a fix to this ahead of next winter and we will continue to monitor margins and aim to investigate and engage promptly with industry in the event that any further spurious CMNs are issued.DateEMNCMN3 DecemberNoYes24 JanuaryNoYesTable 1.Days of EMNs and CMNs over Winter 2021/227Figure 4.Wind output against equivalent firm capacityFor wind generation,we consider a shortfall to be the gap between actual wind generation on a given day and the level assumed in the Winter Outlook Report which is based on a statistical consideration of the contribution of wind to capacity adequacy(i.e.not its average annual load factor).Figure 4 shows this Equivalent Firm Capacity(EFC)for wind assumed and what was actually available throughout the winter at peak.Wind generation output was high throughout most of the winter.On many of the days with tighter margins,wind generation output compensated for any shortfall in other forms of generation.Wind generation output8Other generation shortfallFor Continental interconnectors,we treat shortfall as the gap between actual availability and our high import scenario in the Winter Outlook Report.For all other generators,it is the difference from the de-rated daily expectations of the Winter Outlook Report and the actual available generation on the day.The main drivers for lower margins came from nuclear and CCGT plant being less available than had been notified at the time of the Winter Outlook Report.Nuclear generation availability was lower than forecast through most of the winter.There was also reduced interconnector availability at times across the whole winter due to unplanned outages but,despite this,imports were still typically available when needed at peak.More detail on other generator shortfall is available in the data workbook which can be downloaded here.Review/Margins02468101214Wind output(GW)Wind equivalent firm capacity output forecastActual wind output at peakFigure 5 shows the difference or shortfall between generation availability notified when the Winter Outlook Report was published,and the prevailing view of availability at real time.There are a number of different reasons for the lower than anticipated availability of generators and no common theme.This chart excludes wind and solar generation assets.There is no impact of a large shortfall between expectations and outturns when demands are lower,typically at weekends and over Christmas.When forecasting interconnector flows in the Winter Outlook Report over the peak period of the day,we expect imports from the continent to GB and exports from GB to Ireland.We model both a high import case based on outage plans and price spreads and a more conservative base case which includes some unavailability as well as lower levels of import.There were planned outages affecting IFA and NSL interconnectors ahead of the winter and,beyond this,there were a high number of unplanned interconnector outages over the winter,details of which are explored later in the report.Despite this,winter interconnector availability was consistently higher than the base case and typically in line with the high case(see Figure 6).Generation and interconnector background to marginsFigure 5.Shortfall between generation availability notified in the Winter Outlook Report and actual generator availability(excluding wind and solar)Figure 6.Interconnector scenarios in the Winter Outlook Report and actual availability during peak times*Outage continues beyond the winter period37394143454749515355Availability(GW)Actual generator availabilityWinter Outlook forecast availability9012345601/11/2115/11/2129/11/2113/12/2127/12/2110/01/2224/01/2207/02/2221/02/22IC Availability(GW)ActualHighBaseReview/MarginsPeak actual weather-corrected Transmission System Demand(TSD)was in line with the forecast from the Winter Outlook Report.The highest normalised demand was expected(from the Winter Outlook Report)in the week commencing 13th December,the actual peak demand occurred in the week commencing 6th December(see Figure 6).Otherwise demand tracked broadly in line with our forecast.2021/22 Winter Outlook Reportforecast peak(normal weather used)(GW)Actual 2021/22 peak(weather-corrected)(GW)Actual 2021/22 peak(not weather-corrected)(GW)46.846.747.1Figure 7.Peak Transmission System Demand(TSD)forecast and outturn for winter 2020/21(weather-corrected)CMN dateDay of weekActual Peak TSD on days with a CMN(GW)3 Dec 2021Friday44.2 GW24 Jan 2022Monday45.0 GWTable 3.Actual peak Transmission System Demand on days with CMNs(not weather-corrected)*For the purpose of the Outlook and Review Reports,TSD includes national demand,600MW of station load and 750MW export on interconnectors(over the peak only).On both occasions when CMNs were issued,actual TSD(as opposed to weather-corrected as in the forecast)was lower than the actual winter peak TSD(47.1 GW)in Table 5.In general,times when margins are tight do not necessarily occur on the days with the highest demand but on the days with the biggest shortfall of generation.Transmission demandFigure 8.Daily actual and weather-corrected peak demands including triad avoidance10012343035404550Triad avoidance estimate(GW)Demand(GW)Triad avoidanceWeather-corrected transmission system demandActual transmission system demandReview/Margins36384042444648Demand(GW)Week beginningNormal forecastNormal outturnTable 2.Peak transmission system demands for winter 2021/22Triad avoidance occurs when industrial and commercial users alter their pattern of energy use during peak periods to avoid transmission charges.The three half-hourly periods with the highest demand over the winter,separated by 10 calendar days,are known as Triads.Triad avoidance levels were lower again than the previous year(maximum estimated avoidance level stands at 1.3 GW),down from 1.7 GW the year before.As shown in Figure 9,one Triad corresponds to much lower temperature than the seasonal normal temperature for that date,while the others occurred under seasonal normal conditions in January.What we said in the Winter Outlook ReportWhat triad avoidance occurred(estimation)Why was there a difference?Maximum forecast Triad avoidance:1.2 GWThe values corresponding to the three triad dates(operational view)were 0 GW,0 GW and 0.4 GW(see Table 9).Maximum estimated triad avoidance was broadly in line with our forecast ahead of the winter at 1.3 GW compared to a forecast of 1.2 GW.This maximum response was not seen on any of the actual triad days however.Response rates close to the forecast did occur through late November,and through much of January,around the times of the triads,but not during the triad days themselves.*The triad avoidance estimate is not based on demand reduction data provided to us by suppliers,customers or aggregators.DateTimeHalf hour endingNational Demand(MW)Estimated*triad avoidance(HH corresponding with the peak)(MW)29/11/21173045679005/01/22180044245020/01/22173044977400Figure 9.Daily actual temperature for winter 2021/2022 and seasonal normal temperature alongside the date of the three triads(three vertical black lines)Table 4.Details of Triads for winter 2021/2211024681012141618TriadActual Temperature at 17:00GMT(C)Seasonal normal temperature(30 yrs average of observed temp)at 17:00GMT(C)Review/Triad avoidance*Clean spark spread:The revenue that a gas-fired generation plant receives from selling electricity once fuel and carbon costs have been accounted for.Clean dark spread:The revenue that a coal-fired generation plant receives from selling electricity once fuel and carbon costs have been accounted for.What we said in the Winter Outlook ReportWhat actually happenedWhy was there a difference?Clean spark spreads vs.clean dark spreads*Remaining coal-fired generation to potentially run more frequently due to price effects(but for overall levels of coal generation to remain low due to continued reductions in capacity levels).Coal provided the same proportion of generation as the previous winter,and overall levels remained low,while gas generation output was lower than in winter 2020/21.Wind generation was higher than expected displacing some gas generation,and gas prices were also high.Breakdown rates(this term covers all aspects of plant reliability,including restrictions and unplanned generator breakdowns).Generator reliability to be broadly in line with recent winters although coal,CCGT and biomass plant had a slight increase in expected breakdown rate compared to the previous winter.Breakdown rates(where by breakdown we mean outages that were not notified in advance of the outage,and do not include planned unavailability)on average across the winter as a whole were largely in line with expectations(see Table 5)with most generators within a small range of between 1 and 3%.However,the breakdown rate for nuclear was much higher than forecast,at 20%.OCGT breakdown rate was also significantly higher at 11%compared to a forecast of 5%.Unexpected outages were higher for OCGTs and nuclear generation,nevertheless the percentage energy provided by nuclear generation across the winter was the same year on year.Figure 10.Percentage of energy provided by each fuel type over Winter 2020/21 and Winter 2021/22(transmission connected)Fuel TypeForecastActualCoal11%8GT6%5%Nuclear9 %OCGT5%Pumped Storage3%2%Biomass5%8%Hydro9%6%Table 5.Breakdown rates by fuel type for winter forecast and actual winter.0%5 %05E%Percentage Energy Provided(%)Fuel Type2020/212021/2212Review/Electricity supply-250-200-150-100-50050100150200250-2500-2000-1500-1000-5000500100015002000250001/11/2101/12/2101/01/2201/02/2201/03/22GB france price differential(/MWh)Net IC flows(MW)Net flows over French IcsGB-France price differentialWhat we said in the Winter Outlook ReportWhat actually happenedWhy was there a difference?Overview of continental European interconnectors(BritNed,IFA,IFA2,NEMO Link,NSL)Imports into GB at peak times via the IFA,IFA2,BritNed and Nemo Link interconnectors,although occasionally not at full import and subject to weather variations.During times of tight margins,such as a typical period when an EMN could be issued,imports continue into GB but at closer to full import.There were more periods of export to continental Europe at peak times than usual,along with a much higher level variation in import at peak.Most exports that were seen at peak were over interconnectors to France.This was driven by unplanned outages and relatively higher prices in European markets.We dont have historic flows for NSL as it only recently began commercial operation but we expect imports to GB,especially at times of tight margins,based on price spreads.NSL began running on 01/10/21.As part of its trial phase it spent a lot of time running at partial capacity,with a capacity of 700 MW through most of the winter.As seen in Figure 12,NSL flowed into GB as expected.N/AFigure 11.IFA,IFA2,BritNed,Nemo Link and NSL flow at peak timesFigure 12.Interconnector flows at peak between France and GB combined with the GB France price differential(positive values signify imports into GB and GB prices ahead of French prices)-2-10123456GWNSLIFA2NemoBritnedIFA13There was greater variation in interconnector imports at peak than in previous winters,but flows still followed price spreads across the winter,with imports into GB at peak seen throughout the vast majority of the winter.Continental EuropeReview/Europe and interconnected marketsWhat we said in the Winter Outlook ReportWhat actually happenedWhy was there a difference?Physical capabilities Interconnector capability will be affected by the following outages:IFA:4 Oct-23 Oct(0 MW),24 Oct-27 Mar(1000 MW)NSL:1 Oct-31 Oct(700MW)There were a high number of changes in interconnector availability status through the winter across a range of interconnectors.Unplanned outages impacted interconnector availability.European forward pricesForward prices,including peak prices,in GB to be ahead of those in continental Europe for the majority of the winter periodPrices in continental European markets were closer to GB prices than usual,and exceeded them more often(see Figure 11).While we still saw a net flow of electricity from the continent to GB as expected the majority of the time,there were more occasions than usual when this wasnt the case as prices in France were higher than in GB on a number of occasions.Prices were higher than usual in both GB and European markets reducing the differential that is usually seen.Figure 13.GB and European day-ahead baseload prices across winter 2021/22The Data Workbook contains further detail on:Interconnector outages;specific interconnector behaviour;andBreakdown rates050100150200250300350400450500Baseload price(/MWh)GB BaseloadNetherlands BaseloadBelgian BaseloadFrench BaseloadNorwegian Baseload14Review/Europe and interconnected marketsWhat we said in the Winter Outlook ReportWhat actually happenedWhy was there a difference?Overview of Irish interconnectors(Moyle and EWIC)Moyle and EWIC to typically export from GB to Northern Ireland and Ireland during peak times,although at substantially less than maximum capacity due to high demand on the GB system.During a typical EMN period,exports to Northern Ireland and Ireland are expectedto reduce to zero.Both Moyle and EWIC exported electricity to Northern Ireland at peak times for the majority of the winter(see Figure 14).N/AFigure 14.Moyle and EWIC flows at peak times(positive MW values mean flows into GB)-1000-800-600-400-20002004006008001000MWMoyleEWIC15Flows across the EWIC and Moyle interconnectors to Ireland and Northern Ireland were broadly as expected.Irish interconnectorsReview/Europe and interconnected marketsWe took action across the five core areas to ensure operational security over the winter period.ThermalThe TO experienced delays to the scheme to connect a major windfarm at Tealing substation.This resulted in greater levels of constraints across the B4 boundary.Additional outages and delays were experienced/required for bird nest removal which exacerbated the situation and the restrictions ran beyond autumn and into the winter months.A proposed scheme to allow maximum use of the Western Link HVDC could not be accelerated in to 2022 as planned,impacting the B6 boundary between Scotland and England following the decommissioning of Hunterston in January 2021.NSL interconnector completed commissioning and,as noted in the Winter Outlook Report,it did contribute to volumes required to be bid off above the B7 boundary.It can also restrict the B6 boundary when NSL is at full export.However,as expected we did not have to take additional actions to manage operability issues relating to the import into ScotlandThe significant rise in gas prices had the consequence of increasing the net exposure cost of all thermally driven outage combinations,as replacement energy prices rose to extraordinary levels.StabilityAs part of Stability Pathfinder Phase 1,three further units went live over the winter providing additional inertia and fault infeed to the network,thereby reducing the reliance on buying on thermal plants during periods of high renewable generation.The remaining units are expected to go-live by this year providing additional support for winter 2022/23.FrequencyFrom November 2021 to March 2022 there were no frequency events causing a deviation greater than 0.5 Hz.Our Dynamic Containment High service was in operation last winter for the first time and this was the first winter whereby Short Term Operating Reserve was procured through a day ahead auction mechanism.More details can be found on the following page.RestorationOur Restoration capability was maintained over the Winter period as per our requirement.VoltageControl of high voltages proved challenging though manageable through the Christmas and New Year period.High availability of synchronous generation meant that lack of available generation was not the main challenge.Variable system conditions were seen through the period,with swings from high wind and high flows to low wind with low flows requiring frequent reassessment within day to optimise the requirement for voltage control.Actions to synchronise generation to manage the system reactive power balance and voltages were required,depending on the forecast system demand and other conditions.Some operational actions were also required.16Review/Operational view transmission system ServicesDynamic Containment(DC)is designed to operate post-fault,i.e.for deployment after a significant frequency deviation in order to meet our most immediate need for faster-acting frequency response.Dynamic Containment Low(DCL)was launched in October 2020 with Dynamic Containment High launched in October 2021.We launched Dynamic Containment High as a new tool in our tool-kit to help manage largest loss risks.exporting interconnectors or demand loss risks.We also improved our procurement of DC,making our procurement more granular which enabled consumer savings.The move to EFA block procurement meant that,instead of procuring volume to cover the maximum DC requirement over a 24-hour window,the ESO was able to signal the value of DC across a day,as system conditions such as demand,inertia and largest loss risks change.Last winter we saw providers exiting DC during tight periods impacting volume across the day.More granular procurement enables providers to choose which market they participate in and which EFA block they were available for which helped to minimise the impact of such market behaviourThe record-high wholesale prices since the start of September 2021 led to increased volatility in the participation of Dynamic Containment,with some providers choosing to participate in the wholesale market during lucrative periods.However,despite the impact of the wholesale energy price on participation,the implementation of EFA block procurement still resulted in a saving of around 18.7m during the period compared to the counterfactual scenario if the procurement granularity and costs had remained unchanged.The Winter 2021/22 season,was also the first in which Short Term Operating Reserve(STOR)was procured at the day-ahead level.We experienced some similar challenges with market providers leaving the market on tight days but reviewed our buy order methodology in response to this and were able to mitigate this.These changes brought with it significant challenges in no small part due to the unprecedented wholesale market dynamics which permeated all Ancillary Services markets.Notwithstanding this,the ESO were able to deliver significant savings through the implementation of the procurement strategy for STOR versus the costs that would have been incurred in the absence of the service.The primary challenge arising during the Winter 2021/22 season was reserve volume shortfalls:where less volume was secured via the day-ahead auction process than was required.Occurrences of reserve shortfalls were most prevalent on days characterised by significant electricity system tightness,i.e.low margin.More specifically,the associated effect of system tightness on prices in the Balancing Mechanism and wholesale market saw a marked fall in the number of providers tendering for day-ahead STOR contracts.This,in turn,resulted in fewer MWs of firm reserve capacity than required being procured ahead of delivery.To address this,the ESO implemented changes in the pricing methodology for Short Term Operating Reserve during the Winter 2021/22 season to ensure that the service was providing sufficient commercial incentive for providers,even on days where the electricity system was forecast to be tight.As a result of the amendments,and the inherent benefit of Day-Ahead procurement versus real-time,the ESO were able to delivery cost savings of over 90mn between 1st October 2021 and 31st March 2022,against the alternative cost of the STOR service,(i.e.the cost of securing the full daily requirements via the Balancing Mechanism in real time).17Review/Operational view transmission system This years consultation closes on 30 July 2022.Please refer to the next slide for questions.You can send us your views via email:The ENCC Operational Transparency Forum will also provides an opportunity for you to share your views on the winter ahead and ask us questions.Please register here.Consultation/IntroductionThe purpose of this annual consultation is to gather feedback on our Outlook documents and gather stakeholder insight each year to inform our analysis for the upcoming Winter Outlook Report,to be published in October 2022.Your views on the market and related issues are always important to provide a comprehensive picture of the challenges and opportunities of the forthcoming winter.It also allows us to test how useful the suite of Outlook documents are and to identify areas for improvement with our engagement.The ESO has committed to providing an early view of winter 2022/23 in July 2022 to give earlier information to the industry in light of the recent very high energy prices.As this early view of winter 2022/23 will include a consultation aspect,the consultation questions in this document are less specific to winter 2022/23 and more about this document and the Electricity Outlooks process in general.However,feedback on our potential plans and on preparations for the upcoming winter remains extremely important and so we will make sure any comments and information received via this document are passed to the relevant teams within the ESO.18Consultation/QuestionsWinter Review and Consultation1.What do you use the Winter Review and Consultation Report for?What information in the report is most useful to you for this?2.Is there anything else that could be included in the Winter Review and Consultation Report?3.How do you think the Winter Review and Consultation Report could be improved more generally to increase benefit for consumers?4.Do you have any other feedback on this report or the other Outlook documents?Winter Outlook5.Is there anything you are particularly interested in seeing as part of our early winter view in July?6.Is there anything different you would like to see in the Winter Outlook Report,to be published in October 2022?7.Do you have any general queries or concerns in relation to winter 2022/23?19Appendix Contains extra information on demand definitions and margin notifications20The market or the ESO may take actions to increase exports across the interconnectors or increasing pumping at pumped storage stations to increase the amount of demand on the transmission system if required.Demand Definitions21Margins on the electricity system can vary throughout the winter.Thiswilldependonactualweatherpatternsandoutagestakenbygenerators.The Winter Outlook Report also considers how marginscould change on a week-by-week basis throughout winter for thetransmission system only.There are two views of margins which the ESO works with.CapacityMarket Margins are based on whole system demand and wholesystem capacity(including Distributed Energy Resources(DER).As the majority of the DER are not visible to the ESO,OperationalMargins are based on transmission system demand and transmissionsystem capacity.The EMN process is based around the OperationalMargins and the CMN process is based around the Capacity MarketMargins.The EMN and CMN processes both rely on the visible generation asthat is the data provided to the ESO.The Winter Outlook Reportprovides both margin views;the overall Capacity Market Margin forthe winter as a whole and the weekly Operational Margin.Find out more on the differences between Electricity Margin Notices(EMNs)and Capacity Market Notices(CMNs)here.Did you know?/Capacity Market Notices and Electricity Margin NoticesThere are a number of significant differences between the operational System Warning messages(such as EMN)and Capacity Market Notices:1.Trigger-Capacity Market Notices are issued based on an automated system margincalculation using data provided by market participants,whereas System Warnings aremanually issued by the National Grid ESO control room using engineering judgement basedon experience and knowledge of managing the electricity transmission system.2.Threshold-Capacity Market Notices are triggered where the volume of available generationabove the sum of forecast demand and Operating Margin,is less than 500MW.The 500MWthreshold is taken from the Capacity Market Rules.System Warnings are triggered by varyingvolumes,for example a EMN may be issued where National Grid ESO expects to utilise500MW of its Operating Margin.There is therefore a 1,000MW variance between these twodiscrete alerts.3.Constraints-The Capacity Market Notice calculation does not take account of anytransmission system constraints that may be preventing capacity from accessing the network.System Warnings however do take such constraints into account.4.Lead time-Capacity Market Notices are initially issued four hours ahead of when thechallenge is foreseen,whereas System Warnings can be issued at any time but we wouldexpect to issue a first EMN at the day ahead stage.22GlossaryActive Notification System(ANS)A system for sharing short notifications with the industry via text message or email.Breakdown ratesA calculated value to account for unexpected generator unit breakdowns,restrictions or losses.Forecast breakdown rates are applied to the operational data provided to the ESO by generators.They account for restrictions and unplanned generator breakdowns or losses close to real time.Rates are based on how generators performed on average by fuel type during peak demand periods(7am to 7pm)over the last 3 winters.BritNedBritNed Development Limited is a joint venture between Dutch TenneT and British National Grid that operates the electricity interconnector between Great Britain and the Netherlands.BritNed is a bi-directional interconnector with a capacity of 1,000MW.You can find out more at.Capacity Market(CM)The Capacity Market is designed to ensure security of electricity supply.This is achieved by providing a payment for reliable sources of capacity,alongside their electricity revenues,ensuring they deliver energy when needed.Carbon intensityA way of examining how much carbon dioxide is emitted in different processes.It is usually expressed as the amount of carbon dioxide emitted per kilometre travelled,per unit of heat created or per kilowatt hour of electricity produced.Clean dark spreadThe revenue that a coal fired generation plant receives from selling electricity once fuel and carbon costs have been accounted for.Clean spark spreadThe revenue that a gas fired generation plant receives from selling electricity once fuel and carbon costs have been accounted for.CMP264/265Changes to the Charging and Use of System Code(CUSC).These changes were phased in from1 April 2018 and reduce the value of avoided network charges over triad periods.CO2 equivalent/kWhThe units gCO2eq/kWh are grams of carbon dioxide equivalent per kilowatt-hour of electricity generated.Carbon dioxide is the most significant greenhouse gas(GHG).GHGs other than carbon dioxide,such as methane,are quantified as equivalent amounts of carbon dioxide.This is done by calculating their global warming potential relative to carbon dioxide over a specified timescale,usually 100 years.Combined cycle gas turbine(CCGT)A power station that uses the combustion of natural gas or liquid fuel to drive a gas turbine generator to produce electricity.The exhaust gas from this process is used to produce steam in a heat recovery boiler.This steam then drives a turbine generator to produce more electricity.Distribution connectedAny generation or storage that is connected directly to the local distribution network,as opposed to the transmission network.It includes combined heat and power schemes of any scale,wind generation and battery units.Generation that is connected to the distribution system is not usually directly visible to National Grid ESO as the system operator and acts to reduce demand on the transmission system.East West Interconnector(EWIC)A 500MW interconnector that links the electricity transmission systems of Ireland and Great Britain.You can find out more at Forward Agreement(EFA)EFA blocks are a product used to trade electricity on the wholesale market.There are 6 EFA blocks in a baseload day.EFA5(15:00 19:00)contains the Darkness Peak in winter.European Union Emissions Trading System(EU ETS)An EU-wide system for trading greenhouse gas emission allowances.The scheme covers more than 11,000 power stations and industrial plants in 31 countries.FloatingWhen an interconnector is neither importing nor exporting electricity.23FootroomWhen a generator can reduce its output without going below minimum output levels.Forward pricesThe predetermined delivery price for an underlying commodity,such as electricity or gas,as decided by the buyer and the seller of the forward contract,to be paid at a predetermined date in the future.Gigawatt(GW)a measure of power.1 GW=1,000,000,000 watts.Interconnexion FranceAngleterre(IFA)A 2,000 MW link interconnector between the French and British transmission systems.Ownership is shared between National Grid and Rseau de Transport dElectricit(RTE).Interconnexion FranceAngleterre 2(IFA 2)A 1000 MW link between the French and British transmission systems(commissioned early 2021).Ownership is shared between National Grid and Rseau de Transport dElectricit(RTE).InertiaSystem inertia is how resilient a system is to frequency change.System inertia will depend on what types of generation are connected to the system.Typically,generators with large moving parts have high inertia because their moving parts continue to move even after they are switched off or turned down.In contrast,some types of generation that have no moving parts,such as solar panels,are classed as low inertia generationInflexible generationTypes of generation that require long notice periods to change their output,do not participate in the Balancing Mechanism or may find it expensive to change their output due to commercial arrangements or technical reasons.Examples of inflexible generation include nuclear,combined heat and power(CHP)stations,and some hydro generators and wind farms.Interconnector Electricity interconnectors are transmission assets that connect the GB market to other marketsincluding Continental Europe and Ireland.They allow suppliers to trade electricity between thesemarkets.Load FactorsAn indication of how much a generation plant or technology type has output across the year,expressed as a percentage of maximum possible generation.These are calculated by dividing thetotal electricity output across the year by the maximum possible generation for each plant ortechnology type.Margins Notice IssuedWhen forecast demand for the day ahead exceeds a pre-defined forecast of supply.MoyleA 500 MW interconnector between Northern Ireland and Scotland.You can find out more atwww.mutual-.National electricity transmission system(NETS)High voltage electricity is transported on the transmission system from where it is produced towhere it is needed throughout the country.The system is made up of high voltage electricity wiresthat extend across Britain and nearby offshore waters.It is owned and maintained by regionaltransmission companies,while the system as a whole is operated by a single Electricity SystemOperator(ESO).Nemo LinkA 1000MW interconnector between GB and Belgium.Ownership is shared between National Gridand Elia.Positive and negative reserveTo manage system frequency and to respond to sudden changes in demand and supply,the ESOmaintains positive and negative reserve which is the capability to increase or decrease supplyand demand.Pumped storageA system in which electricity is generated during periods of high demand by the use of water that has been pumped into a reservoir at a higher altitude during periods of low demand.Glossary24Rate of Change of Frequency(RoCoF)How quickly system frequency changes on the electricity network.Usually measured in Hertz per second.Some generators have a protection system that will disconnect them from the network if the Rate of Change of Frequency goes above a certain threshold.Reserve requirementTo manage system frequency,and to respond to sudden changes in demand and supply,the ESO maintains positive and negative reserve to increase or decrease supply and demand.This provides head room(positive reserve)and foot room(negative reserve)across all assets synchronised to the system.Seasonal normal weatherThe average set of conditions we could reasonably expect to occur.We use industry agreed seasonal normal weather conditions.These reflect recent changes in climate conditions,rather than being a simple average of historic weather.Short Term Operating Reserve(STOR)At certain times of the day,we may need access to sources of extra power to help manage actual demand on the system being greater than forecast or unforeseen generation unavailability.STOR provides this reserve.Stability Pathfinder(Phase 1)A process to identify the most cost-effective way to address stability issues in the electricity system.Phase 1 was looking to increase inertia and resulted in 12 contracts being awarded to 5 providers.Transmission System Demand(TSD)Demand that the ESO sees at grid supply points,which are the connections to the distribution networks.Triad avoidance When demand side customers reduce the amount of energy they draw from the transmission network,either by switching to distribution generation sources,using on-site generation or reducing their energy consumption.This is sometimes referred to as customer demand management but,in this section,we are considering customer behaviour that occurs close to anticipated Triad periods,usually to reduce exposure to peak time charges.TriadsThe three half-hourly settlement periods with the highest electricity transmission system demand.Triads can occur in any half-hour on any day between November and February.They must be separated from each other by at least ten days.Typically,they take place on weekdays around 4.30 to 6pm.VoltageUnlike system frequency,voltage varies across different locations on the network,depending on supply and demand for electricity,and the amount of reactive power in that area.Broadly,when electricity demand falls,reactive power increases and this increases the likelihood of a high voltage occurrence.Weather-corrected demand The demand expected or outturned with the impact of the weather removed.A 30-year average of each relevant weather variable is constructed for each week of the year.This is then applied to linear regression models to calculate what the demand would have been with this standardisedweather.Western High Voltage(HVDC)Link(WLHVDC)The Western Link uses DC technology to reinforce the UK transmission system and move electricity across the country in very large volumes between Hunterston in Scotland and Deeside in North Wales.Winter period The winter period is defined as 1 October to 31 March.Glossary25Join our mailing list to receive email updates on our Future of Energy us with your views on the Winter Review Report at:and we will get in touch.You can write to us at:Energy Insights and Analysis,Electricity System Operator Faraday HouseWarwick Technology Park Gallows Hill WarwickCV34 6DAElectricity System Operator legal notice Pursuant to its electricity transmission licence,National Grid Electricity System Operator Limited is the system operator of the national electricity transmission system.For the purpose of this outlook document,the terms“we”,“our”,“us”etc.are used to refer to the licensed entity,National Grid Electricity System Operator Limited.National Grid Electricity System Operator Limited has prepared this outlook document pursuant to its electricity transmission licence in good faith and has endeavoured to prepare this outlook document in a manner which is,as far as reasonably possible,objective,using information collected and compiled from users of the electricity transmission system together with its own forecasts of the future development of those systems.While National Grid Electricity System Operator Limited has not sought to mislead any person as to the contents of this outlook document and whilst such content represent its best view as at the time of publication,readers of this document should not place any reliance on the contents of this outlook document.The contents of this outlook document must be considered as illustrative only and no warranty can be or is made as to the accuracy and completeness of such contents,nor shall anything within this outlook document constitute an offer capable of acceptance or form the basis of any contract.Other than in the event of fraudulent misstatement or fraudulent misrepresentation,National Grid Electricity System Operator Limited does not accept any responsibility for any use which is made of the information contained within this outlook document.The Winter Review&Consultation Report is part of a suite of documents prepared by the Electricity System Operator on the future of energy.They inform the energy debate and are shaped by feedback from the wider industry.Visit our websitefor more information.26

22人看过 2022-11-08 26面 5星

落基山研究所 (RMI)：全球能源转型指南 - 电力市场结构（英文版）（82 页）.pdf

Αποποίηση ευθύνης Η Snow Lake έχει επί του παρόντος μια θετική θέση στις μετοχές της Luckin Coffee Inc. (OTC LKNCY). Η Snow Lake μπορεί να κερδίσει εάν η τιμή διαπραγμάτευσης της Luckin Coffee Inc. αυξηθεί και θα μπορούσε να χάσει χρήματα εάν η τιμή διαπραγμάτευσης της Luckin Coffee Inc. Το fall Snow Lake μπορεί να αλλάξει τις απόψεις του ή τις επενδυτικές του θέσεις στην Luckin Coffee Inc. ανά πάσα στιγμή, για οποιοδήποτε λόγο ή για κανένα λόγο. Η Snow Lake μπορεί να αγοράσει, να πουλήσει, να αντισταθμίσει ή να αλλάξει με άλλο τρόπο τη μορφή ή την ουσία της επένδυσής της στην Luckin Coffee Inc. Η Snow Lake αποποιείται κάθε υποχρέωσης να ειδοποιεί την αγορά για τέτοιες αλλαγές. Οι πληροφορίες, οι αναλύσεις και οι απόψεις που εκφράζονται σε αυτήν την παρουσίαση (η "Παρουσίαση") βασίζονται, μεταξύ άλλων, σε δημόσια διαθέσιμες πληροφορίες σχετικά με τη LuckinCoffee Inc., έρευνα τρίτων από πλευράς αγοράς ή πώλησης, τη δική μας δέουσα επιμέλεια και συμπεράσματα και συμπεράσματα μέσα από την ανάλυσή μας. Η Snow Lake δεν εγγυάται με κανέναν τρόπο ότι θα παρέχει όλες τις πληροφορίες που μπορεί να είναι διαθέσιμες. Η Snow Lake αναγνωρίζει ότι ενδέχεται να υπάρχουν μη δημόσιες πληροφορίες στην Luckin Coffee Inc. ή άλλους που μπορεί να διευθύνουν την Luckin Coffee Inc. ή άλλους να διαφωνούν με τις αναλύσεις, τα συμπεράσματα και τις απόψεις των Snow Lakes. Η παρουσίαση μπορεί να περιλαμβάνει μελλοντικές δηλώσεις, εκτιμήσεις, προβλέψεις και προετοιμασμένες δηλώσεις σχετικά με, μεταξύ άλλων, ορισμένα νομικά και κανονιστικά θέματα που η Luckin Coffee Inc. πρόσωπα και τον πιθανό αντίκτυπο αυτών των θεμάτων στις μελλοντικές επιχειρηματικές της δραστηριότητες, την οικονομική κατάσταση και τα αποτελέσματα των εργασιών της, καθώς και γενικότερα τα αναμενόμενα αποτελέσματα των εργασιών της Luckin Coffee Inc., την πρόσβαση στις κεφαλαιαγορές, τις συνθήκες της αγοράς, τα περιουσιακά στοιχεία και τις υποχρεώσεις, καθώς και όπως αυτά της Luckin Coffee Inc. Τέτοιες δηλώσεις, εκτιμήσεις, προβλέψεις και απόψεις μπορεί να αποδειχθούν ουσιωδώς ανακριβείς και υπόκεινται εγγενώς σε σημαντικούς κινδύνους και αβεβαιότητες πέρα ​​από τον έλεγχο της SnowLakes. Παρόλο που η Snow Lake πιστεύει ότι η παρουσίαση είναι ουσιαστικά ακριβής από κάθε υλική άποψη και δεν παραλείπει σχετικά γεγονότα που είναι απαραίτητα για να είναι παραπλανητικές οι δηλώσεις σε αυτήν, η Snow Lake δεν παρέχει καμία δήλωση ή εγγύηση, ρητή ή σιωπηρή, ως προς την ακρίβεια ή την πληρότητα οποιουδήποτε Η υποβολή ή οποιαδήποτε άλλη γραπτή ή προφορική επικοινωνία που κάνετε σχετικά με την Luckin Coffee Inc. και τη Snow Lake αποποιείται ρητά κάθε ευθύνη σε σχέση με την Υποβολή ή τέτοιες ανακοινώσεις (ή τυχόν ανακρίβειες ή παραλείψεις σε αυτήν). Συνεπώς, οι μέτοχοι και άλλοι θα πρέπει να διεξάγουν τις δικές τους ανεξάρτητες έρευνες και αναθεωρήσεις της παρουσίασης και η LuckinCoffee Inc. και άλλες αναφερόμενες εταιρείες. Η Snow Lake συνιστά σε όλους τους επενδυτές να κάνουν τη δική τους δέουσα επιμέλεια πριν αγοράσουν ή πουλήσουν τίτλους. Η παρουσίαση δεν είναι επενδυτική συμβουλή ή σύσταση ή παρότρυνση για αγορά ή πώληση τίτλων. όπως αναφέρεται, η παρουσίαση αναφέρεται ως την ημερομηνία του παρόντος και η Snow Lake δεν αναλαμβάνει καμία υποχρέωση να διορθώσει, να ενημερώσει ή να αναθεωρήσει την παρουσίαση ή να παράσχει πρόσθετο υλικό. Ούτε η Snow Lake δεσμεύεται να λάβει ή να απέχει από οποιαδήποτε ενέργεια σε σχέση με την Luckin Coffee Inc. ή οποιαδήποτε άλλη επιχείρηση. Όπως χρησιμοποιείται στο παρόν, εκτός εάν το πλαίσιο απαιτεί διαφορετικά, η Snow Lake περιλαμβάνει τις θυγατρικές της και τους αντίστοιχους συνεργάτες, διευθυντές, στελέχη και υπαλλήλους τους.排行榜 (直辷市 ， 省会 城市)

30人参加 2022-11-08 54面 5星

Dealroom：2022年中东欧初创企业展（英文版）（66页）.pdf

CEE PolandCzech RepublicSlovakiaHungarySloveniaCroatiaEstoniaLatviaLithuaniaMacedoniaSerbiaMontenegroRomaniaBulgariaBosnia and HerzegovinaAlbaniaMoldovaGeorgiaUkraine?Greece?Belarus?Moldova?Armenia?Third Edition,November 2022Central and Eastern European startups 2022Page/2 FOREWORD BYIts been a turbulent year for everyone,but nobody has been closer to the epicentre than the Ukraine,and more broadly Central and Eastern Europe.Reading the data,it strikes me just how deeply rooted resilience is within our regional DNA.Harnessing this resilience is proving vital to the growth of our technology ecosystem.Despite enormous challenges,technology companies are continuing on a mission of improving the lives of millions.Since its inception is 2006,Atomico has stood firm on an idea that great founders and companies can come from anywhere.Whats becoming obvious,and is starting to be seen through the data,is that CEE has emerged not only as a cradle to great human minds helping others in building products,but also a birthplace of the most innovative and efficient companies.And that those firms are increasingly maintaining a strong presence in the region.Its never been more important to combine ambition with a sustainable approach to growth,so its no surprise that CEEs approach to company building works.But what excites me is the future potential,as operators in those early success stories re-emerge as founders of the great companies of tomorrow.Its important to share these voices and inspire people to build bolder,faster,and better.We couldnt be more excited to take these findings to the world.Sasha VidiborskiyPosition and roleAt AtomicoSasha Vidiborskiy Partner at Atomico“Its been a turbulent year for everyone,but nobody has been closer to the epicentre than the Ukraine,and more broadly Central and Eastern Europe.Reading the data,it strikes me just how deeply rooted resilience is within our regional DNA.Harnessing this resilience is proving vital to the growth of our technology ecosystem.Despite enormous challenges,technology companies are continuing on a mission of improving the lives of millions.Since its inception is 2006,Atomico has stood firm on an idea that great founders and companies can come from anywhere.Whats becoming obvious,and is starting to be seen through the data,is that CEE has emerged not only as a cradle to great human minds helping others in building products,but also a birthplace of the most innovative and efficient companies.And that those firms are increasingly maintaining a strong presence in the region.Its never been more important to combine ambition with a sustainable approach to growth,so its no surprise that CEEs approach to company building works.But what excites me is the future potential,as operators in those early success stories re-emerge as founders of the great companies of tomorrow.Its important to share these voices and inspire people to build bolder,faster,and better.We couldnt be more excited to take these findings to the world.Sasha VidiborskiyPartnerat Atomico“Its been a turbulent year for everyone,but nobody has been closer to the epicentre than Ukraine,and more broadly Central and Eastern Europe.Reading the data,it strikes me just how deeply rooted resilience is within our regional DNA.Harnessing this resilience is proving vital to the growth of our technology ecosystem.Despite enormous challenges,technology companies are continuing on a mission of improving the lives of millions.Since its inception is 2006,Atomico has stood firm on an idea that great founders and companies can come from anywhere.Whats becoming obvious,and is starting to be seen through the data,is that CEE has emerged not only as a cradle to great human minds helping others in building products,but also a birthplace of the most innovativeand efficient companies.And that those firms are increasingly maintaining a strong presence in the region.Its never been more important to combine ambition with a sustainable approach to growth,so its no surprise that CEEs approach to company building works.But what excites me is the future potential,as operators in those early success stories re-emerge as founders of the great companies of tomorrow.Its important to share these voices and inspire people to build bolder,faster,and better.We couldnt be more excited to take these findings to the world.Page/3 Source:Key takeaways.CEE has shown resilience through uncertain market conditions.CEE has diversified investment into promising new sectors.CEE startups are ranked among the highest in Europe for jobs created per Euro of venture capital invested.The experience in scaling efficiently can be an advantage in aiming to minimize the effects of a market downturn.Combined venture capital investment in CEE has doubled since 2020.The region is on track to break its yearly venture capital investment record and raise 6.2B.CEE has made a name for itself as a pioneering region for Enterprise Software and Gaming companies.As the startup ecosystem matures,CEE is now home to promising startups in many other segments including disruptive technologies such as Web3 and Crypto.2017202020212022YTD5.3B Combined venture capital investment into CEE2.1x40302010CEEDACHEuropeExcl CEENordicsJobs created by M raised in venture capitalCEE is among the most efficient creators of value in Europe.Dealroom.co Top 5 Industries by venture capital investment,Q1-Q3 2022Transportation1.6B|32%FoodFintechEnterprise SoftwareSecurityValue Invested%of Total VC Funding880M|18v4M|1537M|732M|7%6.1B2.5B Page/4 FOREWORD BYJoanna NagadowskaVC and Startups Partnershipsat GoogleYou have in your hands the third edition of the Central Eastern Europe(CEE)Report.In last years report,we saw how the region positioned itself as a solid startup hub,attracting the attention of many local and international investors.This year saw the ecosystem mature and expand its reach by developing and investing in disruptive technologies such as gaming,Web3,and crypto.However,the progress made by CEE founders and investors has been disrupted and challenged by the geopolitical fallout of the invasion of Ukraine.The CEE is a patchwork region of 20 countries that speak different languages,each with unique political landscapes and complex histories.Each of these countries is also bound together by shared experiences of threats to their livelihoods and their collective fight to gain independence.Weve held our breaths watching our Ukrainian neighbors face the same decade-spanning threat once again.The latest edition of the CEE report will shed light on how the tech ecosystem has maintained hopeful resilience during these turbulent times,the investors that did not lose their confidence in the region,the regions strong culture of creating value internally rather than relying on external resources,and the determined CEE founders who stayed focused on innovating their businesses and keeping their employees safe.Having worked alongside CEE founders for the last 10 years,Im humbled by their courage and determination to build global solutions in spite of the dangers they face.This report is a thank you to all the brave CEE founders from our region who do not give up,who believe in their dreams,and are fighting to make them happen.“Joanna NagadowskaVC and Startups Partnershipsat Google for StartupsPage/5 Central and Eastern European startups 2022Ecosystem Overview-Value CreationPulse check of CEE amid uncertain times.Current&future successes.Rising Stars.CEE startups&investment in context.Resilience.Bootstrapping.Funding.Value creation for entrepreneurs,investors&society.2.VC activity&exits in CEEThe whole picture.Early stage to megarounds.Tallinn to Sofia,via Berlin&San Francisco.3.Deep dives:Enterprise software,Gaming,Web3 With the support of 4.1.Spotlight on UkraineWith the support of 5.Co-authors:Sasha Vidiborskiy Partner at AtomicoJoanna NagadowskaVC Partnerships at Google for StartupsMaciej GnutekGeneral Partner at Credo VenturesJakub KrikavaInvestment Analyst at Credo VenturesLouis Geoffroy-TerrynGovernment Research Lead at DealroomChristopher DbereinerEcosystem Analyst at DealroomLiselore HavermansHead of Research at DealroomSkirmantas JanukasCo-Founder&CEO at DappRadarAndrew WrobelFounding Partner at Emerging EuropeTable of contentsSasha Vidiborskiy Partner at AtomicoJoanna NagadowskaVC Partnerships at Google for StartupsMaciej GnutekGeneral Partner at Credo VenturesJakub KrikavaInvestment Analyst at Credo VenturesChristopher DbereinerEcosystem Analyst at DealroomLiselore HavermansHead of Research at DealroomSkirmantas JanukasCo-Founder&CEO at DappRadarAndrew WrobelFounding Partner at Emerging EuropeMatj MicekAssociate at Credo VenturesAudrius JanuliusIndustry Managerat Google BalticsMartin SvobodaIndustry Manager at Google CzechiaWith contributions from:Martin,Audtrius,Jakub,Matej,Christopher,Andrew,SkirmantasMartin SvobodaIndustry Manager at Google CzechiaAudrius JanulisIndustry Managerat Google BalticsMatj MicekAssociate at Credo VenturesJakub KrikavaInvestment Analyst at Credo VenturesChristopher DbereinerEcosystem Analyst at DealroomMaciej wikiewicz CEOat PFR VenturesSkirmantas JanukasCo-Founder&CEO at DappRadarMaciej GnutekGeneral Partner at Credo VenturesMaciej GnutekGeneral Partner at Credo VenturesLouis Geoffroy-TerrynGovernment Research Lead at DealroomAndrew WrobelFounding Partner at Emerging EuropePage/6 Source:Dealroom.co.Combined enterprise value by region refers to the sum of the latest disclosed or estimated public and private valuations of companies Headquartered or founded in respective regions.Double counting may occur on a marginal scale.China is excluded from global average in 2022 in order to provide a more accurate picture of the global trend.CEE NORDICS EUROPE AVERAGE 4.0 x3.6x3.1xCEE is one of the fastest growing regions in Europe by enterprise value.GLOBAL AVERAGE EXCL.CHINA3.3x$22.8T2022$6.9T2017$3.4T2022$1.1T2017$190B2022$47B2017$468B2022$129B2017Enterprise value of startups founded since 1990,founded and/or HQed in selected regions.Last Updated:20/10/2022Page/7 Source:Dealroom.co.VC activityInvestment volume(year-to-date)CEE is one of the fastest growing regions for VC funding in Europe,growing 7.6x since 2017.Growthin VC activity,2017-2022(year-to-date)CEENordicsEurope(excl CEE)DACH7.6x3.8x3.8x2.9xEurope(excl CEE)DACH regionNordicsCEE84.9B14.7B9.0B5.3BLast Updated:24/10/20221.Ecosystem Overview-Value CreationPage/9 Source:Combined enterprise value of CEE startups has quadrupled in the last five years,now totalling 190B.Current HQ in CEEDealroom.co.As part of the CEE ecosystem,Dealroom includes both(1)organizations with current headquarters located in CEE and(2)those founded in CEE that relocated beyond CEE as part of the CEE ecosystem.Combined enterprise value of the CEE tech ecosystem view online200B150B50B100B250BCEE founded,relocated190B 47B 4.0 x23B 94B 201720182019202020212022 YTDLast Updated:20/10/2022Last Updated:20/10/2022Page/10 Source:Among CEE countries,Croatia,Lithuania&Ukraine have grown fastest since 2017 in combined enterprise value.Ecosystem value,five-year growth(2017-2022)Dealroom.co.Combined enterprise value of companies based in,or founded in,selected countries in Central Eastern Europe in 2017 and 2022.20172022 YTDValue growth#2 Croatia#4 Bulgaria#6 Hungary#5 Romania#1 Lithuania#3 Ukraine0.6B0.3B2.5B0.6B1.2B1.4B20172022 YTDValue growth#8 PolandRest of CEEBelarus#7 Czechia#9 Estonia4.7B4.8B7.6B8.1B10.0B23.3B36.3B20.4B7.8B30.2B36.8B6.9B11.4B11.8B2.6B7.7B16.6x15.7x8.0 x6.8x9.3x5.4x3.0 x2.6x3.2x3.1x4.4xLast Updated:20/10/2022Page/11 Source:“Were preparing for different scenarios to both be ready to accelerate and deal with potential global slowdown.We used to have a pure growth mindset,now its changed to cost-efficient growth.”Adam GrniakChief Revenue Officer at BooksyWe did not make significant adjustments to the current state of affairs.If the rate of change of company operations due to growth is massively larger than the rate of change of macro;if you have great margins,great NDR,low burn and are operating world-wide,the macro doesnt matter that much.Juraj Masar Co-founder&CEO at BetterstackWeve focused our efforts on the critical path across the board,and put more emphasis on efficiency of the business over short-to-mid-term,setting the right foundation to optimize for the long run when the uncertainty level curtails.“Josip CesicCTO&Co-founder at Gideon Brothers“Weve focused our efforts on the critical path across the board,and put more emphasis on efficiency of the business over short-to-mid-term,setting the right foundation to optimize for the long run when the uncertainty level curtails.Josip CesicCTO&Co-founder at Gideon“Although in the short-term there are valid reasons to be cautiously conservative,in the long-term we are optimistic and confident.Currently,were being more margin and profit driven in our approach,while at the same time increasing our innovation efforts.This is the time to build with the emphasis on innovation.Anton GauffinCo-CEO&Executive Director at Huuuge Games“The mindset of growing at all costs has changed,and companies have become more conservative when it comes to financial planning.For businesses operating in the CEE region,strong capitalizing combined with a diverse and global client portfolio are an advantage in the current macroeconomic environment.Kaarel KotkasCEO and Founder at VeriffRead the full interview“We did not make significant adjustments to the current state of affairs.If the rate of change of company operations due to growth is massively larger than the rate of change of macro;if you have great margins,great NDR,low burn and are operating world-wide,the macro doesnt matter that much.”Juraj Masar Co-founder&CEO at BetterstackRead the full interviewRead the full interviewRead the full interviewStartups in CEE are bracing for uncertain times.Page/12 Source:2021 and 2022 have been the strongest years for unicorn creation in CEE,with the number of unicorns more than doubling since December 2020.Cumulative number of CEE Unicorns view online20152016201720182019202020212022204044 3621171511968 new Unicorns in CEE,year-to-date view onlineAirSlateFounded:UkraineIndustry:SaaS/LegalRimac AutomobiliFounded:CroatiaIndustry:TransportationNord SecurityFounded:LithuaniaIndustry:SecurityGliaFounded:EstoniaIndustry:MarketingPayhawkFounded:BulgariaIndustry:FintechProductboardFounded:CzechiaIndustry:Enterprise SoftwareVeriffFounded:EstoniaIndustry:FintechLast Updated:25/10/2022Unstoppable DomainsFounded:UkraineIndustry:Hosting/Web3Page/13 Source:Dealroom.co Sofia BULGARIARiga LATVIAUnicorns are being created across the region,even outside of major metropolitan areas.Startups-turned-Unicorns in the past 18 months.New CEE unicorn cities in 2022.New unicorns in existing CEE unicorn cities.Existing CEE unicorn cities.CEE countries with 1 unicorn.CEE countries with no unicorn.Last Updated:20/10/2022NEW UNICORN CITY(2022)NEW UNICORN CITY(2022)Page/14 Source:Emerging hubs are becoming more relevant in the region.Historically small countries have experienced fast growth in CEE and increasingly become key players for development in the region.Dealroom.co.Startups verified by Dealroom and currently based or founded in each country are counted.Selected startups shown for each country.CroatiaVilnius LithuaniaN.of Startups:1.1k Enterprise Value:10BVC Activity 2022:245MVC Activity Growth:8.6xLjubljanaSloveniaN.of Startups:600 Enterprise Value:2.1BVC Activity 2022:71MVC Activity Growth:8.6xBosnia&HerzegovinaN.of Startups:70 RigaLatviaN.of Startups:600 Enterprise Value:2.6BVC Activity 2022:48MVC Activity Growth:2.0 xSofiaBulgariaN.of Startups:800 Enterprise Value:4.8BVC Activity 2022:181MVC Activity Growth:22.3xBelgradeSerbiaN.of Startups:400 Enterprise Value:1.1BVC Activity 2022:44MVC Activity Growth:16.9xRiga LATVIANr.of Startups:600 Enterprise Value:2.6BVC Activity 2022:48MVC Activity Growth:2.0 xVilnius LITHUANIANr.of Startups:1.1k Enterprise Value:10BVC Activity 2022:245MVC Activity Growth:8.6xSofia BULGARIANr.of Startups:800 Enterprise Value:4.8BVC Activity 2022:181MVC Activity Growth:22.3xBosnia&HerzegovinaNr.of Startups:70 Belgrade SERBIANr.of Startups:400 Enterprise Value:1.1BVC Activity 2022:44MVC Activity Growth:16.9xLjubljana SLOVENIANr.of Startups:600 Enterprise Value:2.1BVC Activity 2022:71MVC Activity Growth:8.6xEmerging hubs are becoming more relevant in the region.Last Updated:20/10/2022Page/15 Source:ExitedPrivate 1B Future unicorns200M-1BEstoniaPolandRomaniaHungaryCzechiaUkraineBulgariaLatviaLithuaniaBelarusCroatiaRest of CEECEE is home to many of Europes most renowned unicorns and tech success stories.Dealroom.co.Green outlines represent startups which have transitioned forward between categories since 2021.Grey outlines represent closed startups.EstoniaPolandRomaniaHungaryCzechiaUkraineBulgariaLatviaLithuaniaBelarusCroatiaRest of CEEThis list features startups across all industry verticals.Web3 and Gaming companies are the focus of the industry deep dives in chapter 4,further down the report.Page/16 Source:Dealroom.co.Startups in Gaming and Web 3.0 segments have been excluded from this list and highlighted in distinct parts of the report.The region has a strong pipeline of rising stars ready to write its future.Suggested query for rising stars.Rising stars gives idea of growth,so taking highest dealroom signal with highest employee growth should a)let local players agree(high employee growth)and b)give us high chances of hitting startups that will raise more(dealroom signal).From a quick view,doesnt seem to have excluded many famous players from the list.Rising Stars200MEstoniaPolandRomaniaHungaryCzechiaUkraineBulgariaLatviaLithuaniaBelarusCroatiaRest of CEECases to review:-Serbia:https:/app.dealroom.co/companies/clockify(suggested by Mladen,no known funding)-Zizooboats(Berlin based,suggested by Mladen)This list features startups across all industry verticals.Web3 and Gaming companies are the focus of the industry deep dives in chapter 4,further down the report.Page/17 Source:Western Europe384B1.2T201720223.1xNordics Dealroom.co.All startups are verified on the Dealroom platform.NordicsCEE Founded Enterprise Value:1BCEE-founded,relocated5 Year Funding:0.3BUnited KingdomCEE Founded Enterprise Value:17BCEE-founded,relocated5 Year Funding:1.7BWest CoastCEE Founded Enterprise Value:15BCEE-founded,relocated5 Year Funding:2.5BEast CoastCEE Founded Enterprise Value:15BCEE-founded,relocated 5 Year Funding:2.5BGermanyCEE Founded Enterprise Value:0.5BCEE-founded,relocated 5 Year Funding:0.1BThe NetherlandsCEE Founded Enterprise Value:0.3BCEE-founded,relocated 5 Year Funding:0.2B200 CEE-born,relocated funded startups17%of CEE startups with 1M in funding have moved abroad.Top destinations include the US West and East coasts,and London.Last Updated:20/10/2022Page/18 Source:Although many successful CEE startups move their HQ abroad,they tend to keep a strong presence in the region.Dealroom.co.Analysis based on most valuable companies which relocated HQ outside of CEE.Scaling is accelerating in CEE.Younger star first-generation unicorns,younger startups took almost a third of the time to hit billion dollar status.Share of the workforce based in Central Eastern Europe.25P0%Selected CEE-born startups which relocated their registered address abroad.Page/19 Source:Dealroom.co Distribution of combined enterprise value,Oct/2022for CEE startups by place of incorporation Startups relocate as they scale.CEE startups are far more likely to do so than European average,although the picture differs by country.CEE-basedCEE born,relocated54sed in CEE46%Relocated from CEE Enterprise value of CEE startupsby place of incorporation89sed in EuropeBelarus0.3B Ukraine22.4B 0.9B BulgariaSlovenia1.4B 0.7B Hungary21.6B 13.2B LatviaEstoniaSlovakiaCroatiaSerbia30.7B Czechia3.2B 27.0B Lithuania76hdcE40%8%7%Share of ecosystem value startups abroad.CEE born,HQ in CEECEE born,HQ relocatedEnterprise value of European startups by place of incorporationEurope-born,Europe basedEurope born,HQ relocatedHQ in CEE54%HQ Relocated outside of CEE46%HQ in Europe89%Poland20.6B 3.9B 1.2B 4.9B 2.7B 1.7B 1.0B 14.7B 13.2B 0.5B 0.7B 13.2B 1.6B 3.1B 13.2B 0.3B 0.8B 0.8B 9.2B 34.3B 2.5B 99%Last Updated:20/10/2022Romania35%8.5B 2.9B HQ Relocated outside of Europe11E startups are growing at home and abroad,although the picture is vastly different across the region.2.CEE startups&investment in context.Page/21 Source:Last Updated:17/10/2022“Were doing what always needs to be done in times of uncertainty:be smart about what you invest in and realize that innovation is essential,even more than usual.Especially during difficult times,there are opportunities that can boost your growth and redefine how you operate.Micha BorkowskiCo-Founder and CEO at Brainly“We did not make significant adjustments to the current state of affairs.If the rate of change of company operations due to growth is massively larger than the rate of change of macro;if you have great margins,great NDR,low burn and are operating world-wide,the macro doesnt matter that much.Juraj Masar Co-founder&CEO at BetterstackWeve focused our efforts on the critical path across the board,and put more emphasis on efficiency of the business over short-to-mid-term,setting the right foundation to optimize for the long run when the uncertainty level curtails.“Josip CesicCTO&Co-founder at Gideon Brothers“Behind every successful company is a happy workforce,which is why we focus more on operational efficiency and employee health.We show resilience and kindness,and inspire our team to work together towards our goals that way we can move forward,not backward.Petr AntropovCRO and Co-founder at Lokalise“Although in the short-term there are valid reasons to be cautiously conservative,in the long-term we are optimistic and confident.Currently,were being more margin and profit driven in our approach,while at the same time increasing our innovation efforts.This is the time to build with the emphasis on innovation.Anton GauffinCo-CEO&Executive Director at Huuuge Games“Although in the short-term there are valid reasons to be cautiously conservative,in the long-term we are optimistic and confident.Currently,were being more margin and profit driven in our approach,while at the same time increasing our innovation efforts.This is the time to build with the emphasis on innovation.Anton GauffinCo-CEO&Executive Director at Huuuge GamesRead the full interview“E-learning adoption was already experiencing hyper growth and global lockdowns have accelerated it.The number of people using the Preply app has grown 4x over the last 2 years,and in many regions overall users have almost doubled year on year.The online language learning market is set to reach$47B by 2025 and Preply is well-positioned to take advantage of this opportunity.”Kirill Bigai&Dmytro Voloshyn Co-founders at PreplyRead the full interviewRead the full interviewRead the full interviewResilience is deeply rooted in CEEs entrepreneurial mentality.Page/22 Source:Dealroom.co.Bootstrapped is defined as not receiving publicly-disclosed external funding.Grants are not included in funding.CEEWith an active domestic early-stage investment industry,CEE startups get VC backing at the same rate as all of Europe,with 23%of startups venture backed.Active startups funding status,2022 Bootstrapped startupsVC-backed startups3.6k VC-backed startups239.1k VC-backed startups23.7k Bootstrapped startups770.9k Bootstrapped startups77%EuropePage/23 Source:Dealroom.co12 months18 months24 months30 months36 monthsRest of Europe ConversionCEE Conversion9%Conversion to Series A by time elapsed since Seed roundSeed is the 1st round between$1-4M;Series A is the 1st round between$4-15MWhen they are backed,CEE startups successfully graduate from Seed to Series A at a similar pace and rate compared to the rest of Europe.16!%)0!%8&%Page/24 Source:Bootstrapping plays a prominent role in CEEs late-stage successes:almost a quarter of unicorns born in CEE are not VC-backed.Bootstrapped unicorns view onlineCEE22%7%EuropeAverageWestern Europe5alroom.co.*Edge cases excluded from the bootstrapping analysis.2021&2022 have been the strongest years for unicorn creation in CEE,with the number of unicorns more than doubling since 2020.*VC-backed(30)Bootstrapped(10)2022 UnicornsAlmost bootstrapped(5)*Page/25 Source:VC activity in CEE has already surpassed every year prior to 2021.At the current rate,2022 is on track to match the levels of last year as well.Dealroom.co.Annualized VC funding value based on performance up to October/2022.8B6B2B4B201720182019202020212022Combined venture capital investment into CEE view onlineInvestment into startups founded in CEE with current HQ abroad Investment into startups with HQ in CEE Annualized 6.2B*6.1B2.5B 1.3B 5.3B 3.6B 2.1xLast Updated:20/10/2022Update design.Page/26 Source:Lithuania236MIn CEE-Estonia,Czechia and Croatia have received the most VC funding in 2022 so far.VC funding value by country,year-to-date 2022Dealroom.co Countries with 500M VC funding in 2022Estonia1.4B CzechiaCroatiaPolandRomaniaBulgariaUkraineHungarySlovakiaLatviaSloveniaSerbiaNorth MacedoniaBelarusMoldovaAlbaniaKosovoMontenegroBosnia&Herzegovina1.1B865M550M304M245M246M132M117M50M71M44M10M5M5M5M5M5M hoxton;khosla;accel;nortzone;EUR 22m|(e)Symmetrical.ai;EUR 18m;Partech,GFC,Target Global/all from 2022Page/36 Source:2022 is set to match the record breaking 2021 volume of early-stage VC funding in Central and Eastern Europe.Early-stage venture capital investment into CEE founded companies view onlineDealroom.co.*Especially at early stages,there is systemic underreporting in the last 12 months.Early stage rounds considered those under 40M.Early-stage VC funding rounds in 2022 view online1.0B2.0BSilent EightFounded:PolandEurora SolutionsFounded:EstoniaKenticoFounded:Czech RepublicTenderlyFounded:SerbiaElrondFounded:RomaniaLast Updated:26/10/2022Update design.40MSeries B40MSeries A40MEarly VC40MSeries B40MEarly VC3CommasFounded:Estonia40MSeries B1.8B2.2B2010201120122013201420152016201720182019202020212022(year-to-date)Page/37 Source:Seed investments are crucial for the Polish ecosystem,as we need to sow first,to be able to harvest.For years,our young entrepreneurs were lacking capital.Since its inception,PFR Ventures mission has been not to just boost funding,but also to change the mindset.Since 2019,we have been experiencing a major mindset change among young people.They know that they can rely on dozens of early-stage VC teams constantly looking for new start-ups.Its no longer a fools dream to raise a pre-seed round for just an idea in a PowerPoint deck.Joanna NagadowskaVC and Startups Partnershipsat GoogleIm very happy to see that 9 out of 20 the rising startups were backed by our portfolio funds.Its an indication that our work begins to bear fruit.I believe that whole CEE region will remain attractive to international investors in the time of uncertainty and the rising stars will soon raise their own megarounds.Our recent investments in international funds like Northzone,WSC,DN Capital,and Lakestar will probably make it even easier.“Maciej wikiewicz CEOat PFR Ventures100 Polish startups which raised early stage rounds in 2022 view onlinepoland.dealroom.coPoland Startup EcosystemDiscover the Polish startup ecosystemPage/38 Source:Dealroom.co.*There may occur overlap between industries.*Bolt has been excluded from Food industry.*Percentage and value of funding based on averages from 2015-2021.Transportation,Fintech&Enterprise Software lead VC investments into CEE.Top 5 Industries in CEE by VC funding Q1-Q3 2022 view onlineTransportation1.6B|32%FoodFintechEnterprise SoftwareSecurityValue Invested%of Total VC Funding880M|18v4M|1537M|732M|7%Last Updated:14/10/2022Biggest Industries 2015-2021 by VC fundingEnterprise Software1.3B33%Fintech440M11%Transportation400M10%Food360M9%Marketing240M6%Biggest Industries 2015-2021 by VC funding averageEnterprise SoftwareFoodFintechTransportationMarketing1.3B|33D0M|110M|1060M|9$0M|6%Value Invested%of Total VC Funding*Page/39 Source:The record in VC funding raised has already been broken.New funds are born and old funds are raising new funding.Dealroom.co.*2022YTD based on H1 performance.Venture capital funds are investment funds that manage the money of investors who seek private equity stakes in startup and small-to medium-sized enterprises with strong growth potentialNew VC funds raised by CEE-based investors view onlineNumber of CEE-based funds announced view online200M400M600M800M201720182019202020212022 YTD102030201720182019202020212022 YTDLast Updated:20/10/2022Domestic investors are raising growing amounts of fresh capital,ready to be deployed in the region.923M 550M350M360M820M2031Page/40 Source:Credo Stage IV75MPrague CZECHIACEE-based 50M funds announced this year.Inovo Ventures Fund III100M*Warsaw POLANDEleven Ventures Fund III60MSofia BULGARIADealroom.co.*reported values as of 10.2022.Debt Fund I55MZagreb CROATIACatalyst Romania Fund II50MBucharest ROMANIASuperangel Fund II50MTallinn ESTONIA19 New funds announced across CEE,year-to-date.990 foreign investors with investments in CEEMarket One Capital Fund II 80M*Warsaw POLANDContrarian Ventures Fund II100MVilnius LITHUANIATrind VC Fund II55MTallinn ESTONIAAt a glanceSPOTLIGHT ON UKRAINEBlue&Yellow Heritage 30M*HCGF IV 125MEIC Ukraine program20MSCV Technology Fund III70M*Belgrade SERBIAPage/41 Source:Dealroom.co.*Last 12 months are systematically under reported and may cause lag in values.Confidential exits do not contribute to complete values.Exits are at one of their highest points in CEEs history,but it remains unclear how amounts will be affected by this years market downturn.Number of exits in CEE view onlineH12017H12018H12019H12020H12021H1202210050838074693434449111011888*Last Updated:20/10/2022Exit amounts in CEE view onlineH12017H12018H12019H12020H12021H1202240B30B20B10B630M*37.2B42.3B14.8B496M5.3B822M5.4B4.5B2.7B1.9BH1 2022 88%of exits have undisclosed values year-to-date.Skirmantas JanukasCo-Founder&CEO at DappRadar4.Deep dives:Enterprise software,Gaming,Web3 With the support ofMariusz Gasiewski CEE Mobile Gaming Lead at GoogleMaciej GnutekGeneral Partner at Credo VenturesWeb3GamingEnterprise softwareHas contributed onPage/43 Source:Dealroom.co.*There may occur overlap between industries.eCommerce contains Fashion,Home Living&Wellness segments.More on industry definitions can be found here.CEE Enterprise Software startups have a combined valuation exceeding all of their Fintech,Transportation and eCommerce counterparts combined.Top 5 Industries in CEE by combined enterprise value,October 2022Enterprise Software80BeCommerceFintechTransportationSecurity30B19B19B15BLast Updated:14/10/2022In CEE Enterprise Software is worth more than Fintech,Transportation&Fashion combined.Dealroom.co.*There may occur overlap between industries.Top 5 Industries in CEE by combined enterprise value,Q3 2022Enterprise Software80B FintechTransportationFashionSecurity30B 19B 17B 15B Page/44 Source:The funding landscape in CEE looks different compared to European average,with Enterprise Software taking up a significantly larger chunk of VC activity in the region.Dealroom.co.*Startups may belong to up to two industries.Overlaps and double counting is reduced organically but may occur at scale.10 0%Enterprise softwareTransportationFintechSecurityHealthEnergy38%5%4%3#%8%9%5%of B2B VC funding by sector(2016-Q3/2022)Rest of Europe CEELast Updated:20/10/2022Page/45 Source:CEE is home to some of the most promising Enterprise Software startups.Dealroom.co Legal&AccountingData ManagementDevelopment ToolsOtherSecurityTeam ProductivityMarketing&SalesLast Updated:20/10/2022Enterprise Software in CEE is primarily centered around 7 main categories.Top Rounds 2022Rising Stars-Identified with Page/46 Source:Source:Dealroom.co Funding into CEE Enterprise Software startups is down on a record-breaking 2021,but is still 2.5x compared to 5 years ago.Select CEE-founded Enterprise Software Funding Rounds of 2022CEE Enterprise Software VC Funding view onlineMANTACentral hub for data flows.Round:35M Series BH12017H12021H120221.0B500M662M919M264M2.5x1.5B1.1BH22021SyneriseAI behavioural data processing.Round:23M Series BMemsourceAutomating content translation.Round:15M Growth Equity VCDRUIDIntelligent chat bot.Round:14.2M Series APage/47 Source:CEEs Software Development legacy is feeding a new generation of startups,as tech talents increasingly become founders.%of EV in Product Led StartupsQuote-transformation in CEE to product focused80%of Enterprise Value in CEEis in Product Led StartupsLast Updated:13/10/2022UkrainePoland,Hungary,Czechia&SlovakiaCEE-based outsourcing companies&software development studiosSelected startups(co-)founded by former employees of 20 Software Development studios,IT outsourcing companies and R&D offices of large European IT consultancies in CEE.BalkansBalticsRest of EuropeNorth AmericaSelected CEE outsourcing companies&software development studiosBalkansPoland,Hungary,Czechia&SlovakiaRest of EuropeBalticsUkraineNorth AmericaPage/48 Source:100u%PEs Enterprise Software expertise is increasingly supporting innovation in other segments.Dealroom.co.*There may occur overlap between industries.DraftLast Updated:27/10/2022Update design.Share of VC funding in CEE by industry 20172022(Q1-Q3)10E%5%Croatia Greece Romania Bulgaria Serbia Slovenia North Macedonia56#sign update.Semiconductors Health Gaming Marketing Travel Energy Security Food Enterprise Software Fintech Transportation Enterprise softwareEnterprise software matures and gains in various industries.CybersecurityTransportation,Mobility&LogisticsFintech36%of CEE VC funding16%of CEE VC fundingEnterprise softwareCybersecurityTransportation,Mobility&LogisticsFintechEnterprise softwareTransportation,Mobility&LogisticsFintechEnterprise softwareCybersecurityPage/49 Source:Source:Dealroom.co VC funding has grown 5.6x since 2021 for CEE-based Crypto and Web3 startups.Selected Crypto&Web 3.0 CEE VC Funding Rounds,2022CEE-based Crypto/Web 3.0 Startups-VC Funding view onlineH12017H12021H12022 H22021100M50M119M101M3M39xNOW100M50M150M119M101M3M5.6xReady Player MeFounded:EstoniaRound:56M Series BBITLEVEXFounded:EstoniaRound:50M Early VCTenderlyFounded:SerbiaRound:40M Series B21MTatumFounded:CzechiaRound:41M Early VCElrondFounded:RomaniaRound:40M Early VCNFTPortFounded:EstoniaRound:24.9M Series AAleph ZeroFounded:PolandRound:14.8M SeedPage/50 Source:Web3 startups to watch out for in Central Eastern Europe.Dealroom.co Selected CEE Web 3.0 startups,using TenderlyEthereum developer platform for innovative blockchain products.RMRKNFT exchange platform.StrigaCrypto and Banking APIs.Single.EarthBuilds tools to mitigate climate change and biodiversity loss.TatumSolution to build test and run blockchains.Change InvestCrypto exchange platform.DappRadarDecentralized crypto app store.Coinrule Automated crypto trading platform.RevutoSubscription management with crypto micro-lending and borrowing.Somnium SpaceSocial&open world VR platform.SerbiaEstoniaCzechiaLithuaniaCroatiaCroatiaEstoniaEstoniaRomaniaCzech RepublicFiat Republice-money solution&APIPolandTop CEE Web3 startups to watch out for view onlineLast Updated:20/10/2022Update screenshotUpdate designTenderlyFounded:SerbiaRound:405 Series BFiat republicFounded:PolandE-money solution&API.TenderlyFounded:SerbiaEthereum developer platform for innovative blockchain products.StrigaFounded:EstoniaCrypto and Banking APIs.3CommasFounded:EstoniaCrypto trading platform.RevutoFounded:CroatiaSubscription management with crypto micro-lending and borrowing.DappRadarFounded:LithuaniaDecentralized crypto app store.Aurora LabsFounded:UkraineSolution to operate apps on Ethereum-based platform.Single.EarthFounded:EstoniaBuilds tools to mitigate climate change and biodiversity loss.Change InvestFounded:EstoniaCrypto exchange platform.RMRKFounded:CroatiaNFT exchange platform.Somnium SpaceFounded:CzechiaSocial&open world VR platform.CoinruleFounded:RomaniaAutomated crypto trading platformRampFounded:PolandBanking APIs to connect crypto with fiat.NexoFounded:BulgariaCrypto-backed loans.NFTPortFounded:EstoniaNFT infrastructure&API tool for developers.WertFounded:EstoniaCrypto currency provider.TenderlyFounded:SerbiaEthereum developer platform for innovative blockchain products.StrigaFounded:EstoniaCrypto and Banking APIs3CommasFounded:EstoniaCrypto trading platform.DappRadarFounded:LithuaniaDecentralized crypto app store.RevutoFounded:CroatiaSubscription management with crypto micro-lending and borrowing.Aurora LabsFounded:UkraineSolution to operate apps on Ethereum-based platform.RMRKFounded:CroatiaNFT exchange platform.Single.EarthFounded:EstoniaBuilds tools to mitigate climate change and biodiversity loss.Change InvestFounded:EstoniaCrypto exchange platform.RampFounded:PolandBanking APIs to connect crypto with fiat.CoinruleFounded:RomaniaAutomated crypto trading platformSomnium SpaceFounded:CzechiaSocial&open world VR platform.WertFounded:EstoniaCrypto currency provider.NFTPortFounded:EstoniaNFT infrastructure&API tool for developers.NexoFounded:BulgariaCrypto-backed loans.Page/51 Source:Estonia,Slovenia&Serbia concentrate over 70%of combined value of Web3 startups in CEE.Top 5 Web 3.0 hubs in CEE by Enterprise Value view onlineDealroom.co.Combined enterprise value of 585 startups identified on the basis of their product and location of their main center of business.Countries 100M in combined crypto enterprise valueEstonia1.3B Czech RepublicCroatiaPolandRomaniaLithuaniaBulgariaUkraineHungarySlovakiaLatviaSloveniaSerbiaNorth MacedoniaBelarusMoldovaAlbaniaKosovoMontenegroBosnia&Herzegovina883M772M490M285M245M181M169M132M117M48M71M44M10M5M5M5M5M5M5MLast Updated:17/10/2022Countries with less than Open access to the Ukrainian Startup EcosystemJoobleSupported byTR DATA,ALTY,RENTPage/58 Source:Ukrainian startups are showing incredible resilience in spite of the war and recession,with enterprise value growing 3.3x since 2020.Dealroom.co Last Updated:17/10/2022SPOTLIGHT ON UKRAINETotal combined enterprise value of Ukrainian Startups view onlineTotal combined enterprise value of CEE view online201720182019202020212022201720182019202020212022102030190B242B148B93B65B49B250B200B150B100B50B23.3B27.1B7.0B3.3x6.4B4.5B2.9B1.3xPage/59 Source:This can take a toll on startup teams.“At the moment Russia invaded,one third of the team was in Kyiv,roughly 150 people.Other than the co-founders,none of the leadership team are Ukrainian and they really did their best to manage the business and evacuation process.We organized a team of 10 people working 24/7 to make sure every single Prepler in UA had everything they needed during those weeks,from transportation to accommodation in the west of Ukraine or outside.We also provided financial,and mental health support.”Startups have had to cope with uncertain times.“We extended deadlines for projects we planned to launch in 2022,but we havent abandoned them.After all,the team lost the ability to work effectively for a few months,and its impossible to work on the same level of productivity when constantly thinking and living through whats happening to our people and our country(Ukraine).”SPOTLIGHT ON UKRAINERead the full interviewOleksandr KosovanFounder and CEOof MacPawKirill Bigai&Dmytro VoloshynCo-foundersat PreplyRead the full interviewPage/60 Source:Western Europe384B1.2T201720223.1xNordics Dealroom.co.All startups are verified on the Dealroom platform.Last Updated:20/10/2022startups with UA roots abroad slide-WIPForeign startups&tech companies actively recruiting in Ukraine this year:https:/app.dealroom.co/lists/31980?showGrid=false&showTransactions=false&sort=-startup_ranking_ratingForeign startups with ties to Ukraine:https:/app.dealroom.co/lists/31921?showGrid=false&showTransactions=false&sort=-startup_ranking_rating-Companies founded in Ukraine with current HQ abroad-Companies(co-)founded by alumni of Ukrainian universities-Companies founded by Ukraine-based founding teamsUkraine is home to 285 000 IT professionals(1),over 2,000 startups and hundreds of service providers and software development studios.The Ukrainian startup ecosystem has shown incredible resilience and continues to provide livelihoods to Ukrainians at home and abroad,as well as innovations to the world.(1)Source:IT Ukraine Association.(2)Source:ukraine.dealroom.co.500 foreign startupswith recent job openings in UkraineUkraine is home to a dense startup&tech ecosystem:there are 1.5k active startups based in the country(2).Another 600 startups were founded in Ukraine,or by Ukraine-based founding teams and/or by alumnus of Ukrainian universities.SPOTLIGHT ON UKRAINEUkraines tech ecosystem is more than the sum of its startups.SPOTLIGHT ON UKRAINEForeign startups with ties to Ukraine.View onlineCompanies founded in Ukraine with current HQ abroadCompanies(co-)founded by alumni of Ukrainian universitiesCompanies founded by Ukraine-based founding teamsForeign startups&tech companies actively recruiting in Ukraine this year.View online600 startups abroadwith strong ties to Ukraine1.5K Ukrainian startupsmain center of businessin UkrainePage/61 Source:Magdalena PrzelaskowskaSenior Startup Partner Managerat Google for StartupsWhen the war started we opened our Campus doors to founders who arrived in Warsaw.The one strong feedback we got was that on top of the fund they need visibility to show the world that Ukraine is still standing.This strong resilience shows in the numbers that we can see throughout this report.We received 1,670 applications and we did 300 interviews for the fund.From that experience I can share that many startups from that region build sophisticated tech products,have strong teams with tech talent and are bootstrapped with most reaching break-even.All this with limited access to capital,so founders try to minimize costs where possible.In the report we can see that Ukraine is number 1 country when it comes to jobs creation per$M raised.In the challenging times that are ahead of us,this cash-conservative mindset of Ukrainian founders gives them a natural advantage and will help them survive with hopes to grow further and rebuild their countrys economy after the war.talent and are bootstrapped with most reaching break-even.All this with limited access to capital,so founders try to minimize costs where possible.In the report we can see that Ukraine is number 1 country when it comes to jobs creation per$M raised.In the challenging times that are ahead of us,this mindset of Ukrainian founders gives them a natural advantage and will help them survive with hopes to grow further and rebuild their countrys economy after the war.When the war started,we opened our Google for Startups Campus doors to Ukrainian founders who arrived in Warsaw.The one strong feedback we got was that,on top of funds,they need visibility to show the world that Ukraine is still standing.This strong resilience shows in the numbers that we can see throughout this report.For the Ukraine Support Fund,we have interviewed hundreds of Ukrainian founders.From that experience I can share that many startups from that region build sophisticated techproducts,have strong teams with tech To help Ukrainian entrepreneurs maintain and grow their businesses,strengthen their community and build a foundation for post-war economic recovery,Google announced in March a$5 million Google for Startups Ukraine Support Fund.Selected Ukraine-based startups will receive up to$100,000 in non-dilutive funding as well as ongoing Google mentorship,product support,and Cloud credits.So far 33 startups were selected,with more to be announced before the end of year.Ukraine Support FundSPOTLIGHT ON UKRAINE|“bootstrapped with most reaching break-even.All this with limited access to capital,so founders try to minimize costs where possible.In the report we can see that Ukraine is number 1 country when it comes to jobs creation per$M raised.In the challenging times that are ahead of us,this cash-conservative mindset of Ukrainian founders gives them a natural advantage and will help them survive with hopes to grow further and rebuild their countrys economy after the war.When the war started we opened our Campus doors to founders who arrived in Warsaw.The one strong feedback we got was that on top of the fund they need visibility to show the world that Ukraine is still standing.This strong resilience shows in the numbers that we can see throughout this report.We received 1,670 applications and we did 300 interviews for the fund.From that experience I can share that many startups from that region build sophisticated tech products,have strong teams with tech talent and are6.Methodology&AcknowledgementsPage/63 Source:A few words on our methodology.Homegrown and relocation What is a startup?Companies designed to grow fast.Generally,such companies are VC-investable businesses.Sometimes they can become very big(e.g.$1B valuation).When startups are successful,they develop into scaleups(50 people),grownups(500 people)and result in big companies.Only companies founded since 1990 are included in this report.What is a unicorn?Unicorns are(former)startups that reached US$1B valuation or exit at one point in time.What is a startup?Geographic scopeIn this report,the countries considered as part of CEE include:Estonia,Lithuania,Latvia,Poland,Czech Republic,Hungary,Slovakia,Croatia,Romania,Serbia,Bulgaria,Montenegro,Slovenia,North Macedonia,Bosnia and Herzegovina,Albania,Kosovo,Moldova,Ukraine,Belarus.While many startups founded in CEE relocate beyond the borders of CEE,most maintain business-critical ties to their homelands.In order to take this reality into account,this report includes both CEE-based startups,which maintain their main center of business(HQ)in their country of origin,and CEE-born startups,relocated outside of CEE as they grew.Startups founded by alumni of CEE Universities,and/or nationals of CEE countries whilst abroad,as well as startup funded by CEE investors abroad,are not included in the main section of this report.CEE startups on DealroomWhat is a Unicorn?Underlying DataDealrooms proprietary database and software aggregate data from multiple sources:harvesting public information,user-submitted data verified by Dealroom,data engineering.All data is verified and curated with an extensive manual process.The data on which this report builds is available via app.dealroom.co.For more info please visit dealroom.co or contact supportdealroom.co.Venture Capital,InvestorsDomestic investors refer to each respective SEE countries.Europe investors include all SEE and CEE investments except those from the companys founding or HQ location.Europe includes the entire European continent,the UK and Russia,but excludes Turkey.Investment are referred to by their round labels such as Seed,Series A,B,C,late stage,and growth equity.VC investments exclude debt,non-equity funding,lending capital and grants.CEE PolandCzech RepublicSlovakiaHungarySloveniaCroatiaEstoniaLatviaLithuaniaMacedoniaSerbiaMontenegroRomaniaBulgariaBosnia and HerzegovinaAlbaniaMoldovaGeorgiaUkraine?Greece?Belarus?Moldova?Armenia?Previous editions of the report.Page/64 1st Edition 20192nd Edition(2021)3rd Edition(2022)2nd Edition 20213rd Edition 2022Page/65 Source:Global startup&venture capital intelligence platformDealroom.co is the foremost data provider on startup,early-stage and growth company ecosystems in Europe and around the globe.Founded in Amsterdam in 2013,we now work with many of the worlds most prominent investors,entrepreneurs and government organizations to provide transparency,analysis and insights on venture capital activity.Pending content(partner)Credo Ventures is a venture capital company focused on early stage investments in Central Europe.Our mission is to identify and back the most interesting early stage companies in the region,support them in their growth plans in global markets and help to achieve their objectives.Built by founders for founders,every single aspect of our firm,every part of our culture and every decision we take is designed with the sole ambition of helping our partners succeed.Because its through these pioneers that change happens.Rewiring our world to be a fundamentally better place.One entrepreneur at a time.At their best,startups solve complex problems.When they succeed,they move us all forward.Thats why Google for Startups brings the best of Googles products,connections,and best practices to level the playing field for startup founders and communities,and enable startups to build something better.We partner with outstanding technology founders from CEE to help them realize their global ambitions.We partner with Europes most ambitious tech founders.Googles initiative to help startups thrive across every corner of the world.

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IEA PVPS：2021年泰国太阳能光伏应用研究报告（英文版）（27页）.pdf

National Survey Report of PV Power Applications in THAILAND 2021 PVPS Task 1 Strategic PV Analysis and Outreach Task 1 National Survey Report of PV Power Applications in COUNTRY What is IEA PVPS TCP?The International Energy Agency(IEA),founded in 1974,is an autonomous body within the framework of the Organization for Economic Cooperation and Development(OECD).The Technology Collaboration Programme(TCP)was created with a belief that the future of energy security and sustainability starts with global collaboration.The programme is made up of 6.000 experts across government,academia,and industry dedicated to advancing common research and the application of specific energy technologies.The IEA Photovoltaic Power Systems Programme(IEA PVPS)is one of the TCPs within the IEA and was established in 1993.The mission of the programme is to“enhance the international collaborative efforts which facilitate the role of photovoltaic solar energy as a cornerstone in the transition to sustainable energy systems.”In order to achieve this,the Programmes participants have undertaken a variety of joint research projects in PV power systems applications.The overall programme is headed by an Executive Committee,comprised of one delegate from each country or organisation member,which designates distinct Tasks,that may be research projects or activity areas.The IEA PVPS participating countries are Australia,Austria,Belgium,Canada,Chile,China,Denmark,Finland,France,Germany,Israel,Italy,Japan,Korea,Malaysia,Mexico,Morocco,the Netherlands,Norway,Portugal,South Africa,Spain,Sweden,Switzerland,Thailand,Turkey,and the United States of America.The European Commission,Solar Power Europe,the Smart Electric Power Alliance(SEPA),the Solar Energy Industries Association and the Cop-per Alliance are also members.Visit us at:www.iea-pvps.org What is IEA PVPS Task 1?The objective of Task 1 of the IEA Photovoltaic Power Systems Programme is to promote and facilitate the exchange and dissemination of information on the technical,economic,environmental and social aspects of PV power systems.Task 1 activities support the broader PVPS objectives:to contribute to cost reduction of PV power applications,to increase awareness of the potential and value of PV power systems,to foster the removal of both technical and non-technical barriers and to enhance technology co-operation.An important deliverable of Task 1 is the annual“Trends in photovoltaic applications”report.In parallel,National Survey Reports are produced annually by each Task 1 participant.This document is the country National Survey Report for the year 2020.Information from this document will be used as input to the annual Trends in photovoltaic applications report.Authors Main Content:Department of Alternative Energy Development and Efficiency,Ministry of Energy Data:Department of Alternative Energy Development and Efficiency,Office of Energy Regulatory Commission,Metropolitan Energy Authority,Provincial Energy Authority,Electricity Generating Authority of Thailand,King Mongkuts University of Technology Thonburi Analysis:Department of Alternative Energy Development and Efficiency,King Mongkuts University of Technology Thonburi DISCLAIMER The IEA PVPS TCP is organised under the auspices of the International Energy Agency(IEA)but is functionally and legally autonomous.Views,findings and publications of the IEA PVPS TCP do not necessarily represent the views or policies of the IEA Secretariat or its individual member countries COVER PICTURE The 45 MW(AC)world-largest Floating PVs(FPVs)System integrated with hydropower at Sirindhorn dam at Ubonratchathani province of Thailand in near-complete phase as part of the 2,725 MW(AC)plan of FPVs installation of Thailand by 2037.Task 1 National Survey Report of PV Power Applications in COUNTRY 2 TABLE OF CONTENTS Acknowledgements.4 1 Installation Data.5 Applications for Photovoltaics.5 Total photovoltaic power installed.5 Key enablers of PV development.8 2 Competitiveness of pv electricity.9 Module prices.9 System prices.9 Financial Parameters and specific financing programs.10 Specific investments programs.11 Additional Country information.11 3 Policy Framework.14 National targets for PV.14 Direct support policies for PV installations.15 Self-consumption measures.15 Collective self-consumption,community solar and similar measures.16 Tenders,auctions&similar schemes.16 Other utility-scale measures including floating and agricultural PV.17 Social Policies.17 Retroactive measures applied to PV.17 Indirect policy issues.17 Financing and cost of support measures.18 4 Industry.19 Production of feedstocks,ingots and wafers(crystalline silicon industry).19 Production of photovoltaic cells and modules(including TF and CPV).19 Manufacturers and suppliers of other components.20 5 Pv In The Economy.21 Labour places.21 Business value.21 6 Interest From Electricity Stakeholders.23 Task 1 National Survey Report of PV Power Applications in COUNTRY 3 Structure of the electricity system.23 Interest from electricity utility businesses.24 7 Highlights and Prospects.25 Highlights.25 Prospects.25 Task 1 National Survey Report of PV Power Applications in COUNTRY 4 ACKNOWLEDGEMENTS This paper received valuable contributions from several organization including the Department of Alternative Energy Development and Efficiency(DEDE),King Mongkuts University of Technology Thonburi(KMUTT),Electricity Generating Authority of Thailand(EGAT),Office of Energy Regulatory Commission(OERC),Metropolitan Energy Authority(MEA)and Provincial Energy Authority(PEA).Task 1 National Survey Report of PV Power Applications in COUNTRY 5 1 INSTALLATION DATA The PV power systems market is defined as the market of all nationally installed(terrestrial)PV applications with a PV capacity of 40 W or more.A PV system consists of modules,inverters,batteries and all installation and control components for modules,inverters and batteries.Other applications such as small mobile devices are not considered in this report.For the purposes of this report,PV installations are included in the 2020 statistics if the PV modules were installed and connected to the grid between 1 January and 31 December 2020,although commissioning may have taken place at a later date.Applications for Photovoltaics In 2020 the development of PV systems for electricity generation in Thailand continued to grow in decentralized sector,where the BAPV in industrial and commercial showed the most prominent growth in PV installation.In terms of national target,by 2037,Thailand aimed to commission new power plant capacity at 56 431 MW in which 18 696 MW of this would come from renewable electricity power plant.In addition,the target of new solar PV power plant capacity target in 2037 was set at 8 740 MW,plus additional 550 MW capacity target of solar PV hybrid with other renewable energy source according to community power plant project.Moreover,Thailand also established 2 725 MW solar PV floating target hybrid with large hydropower dams by 2037.Thailand cumulative PV installed capacity was at 3 939,8 MWp,consisting of 3 933,7 MW of grid-connected PV systems and 6,1 MWp of off-grid PV systems.Most of the total installed capacity was ground-mounted PV systems.In 2020,Thailand annual grid-connected systems installation was 143,64 MWp.Data showed that rooftop PV systems for the commercial was dominated the sector with 127,25 MW of installation.In addition,there was 12,69 MW of floating PV systems and 3,7 MW of ground mounted systems installed in 2020.When incorporating 80 kW off-grid installation in 2020,total annual PV installation of Thailand stood at 143,72 MW.The constructions for floating PVs system with the installation capacity of 58,8 MWp(45 MWAC)hybridized with regular hydropower generation at Sirindhorn Dam,Ubonratchathani province had been completed and the system came online since November 2021.Total photovoltaic power installed Data collection for the PV installed capacity of Thailand in this report used the secondary data from the Office of Energy Regulatory Commission(OERC)which were collected from the Electricity Generating Authority of Thailand(EGAT),Provincial Electricity Authority(PEA)and Metropolitan Electricity Authority(MEA).Centralized:any PV installation which only injects electricity and is not associated with a consumer(no self-consumption).In Thailand,these are mostly ground-mounted PV systems with the power purchasing agreement(PPA)in utility applications.Decentralized:any PV installation which is embedded into a customers premises.In Thailand,these are comprised of rooftop PV systems,ground-mounted PV systems and floating PV systems.The implementation can be done in both self-consumption with the ability to sell the excess electricity back to the grid,and with the private power purchase agreement(private-PPA)aspects.Task 1 National Survey Report of PV Power Applications in COUNTRY 6 Table 1:Annual PV power installed during calendar year 2020 Installed PV capacity in 2020 MW AC or DC Decentralized 139,94 DC Centralized 3,7-Off-grid 80 kW DC Total 143,72 DC Table 2:PV power installed during calendar year 2020 Installed PV capacity MW Installed PV capacity MW AC or DC Grid-connected BAPV Residential 127,25 2,22 DC Commercial 125,03 DC Industrial BIPV Residential-Commercial-Industrial-Utility-scale Ground-mounted 16,39 3,7 DC Floating 12,69 DC Agricultural-Off-grid Residential 80 kW n/a DC Other 15 kW DC Hybrid systems 65 kW DC Total 143,72 DC Task 1 National Survey Report of PV Power Applications in COUNTRY 7 Table 3:Data collection process If data are reported in AC,please mention a conversion coefficient to estimate DC installations.-Is the collection process done by an official body or a private company/Association?The data is collected by official bodies primarily from(1)Office of Energy Regulatory Commission(OERC)and(2)Department of Alternative Energy Development and Efficiency(DEDE)Ministry of Energy.Link to official statistics(if this exists)www.erc.or.th,and www.dede.go.th Table 4:The cumulative installed PV power in 4 sub-markets Year Off-grid MW(including large hybrids)Grid-connected distributed MW(BAPV,BIPV)Grid-connected centralized MW(Ground,floating,agricultural)Total MW 2002 2,57-2,57 2003 3,13-3,13 2004 9,07-9,07 2005 22,11-22,11 2006 28,66-0,1 28,72 2007 28,90-1,6 30,53 2008 29,33-2,0 31,28 2009 29,49-5,4 34,84 2010 29,65-21,0 50,66 2011 29,58-174,0 203,62 2012 30,19-406,5 436,64 2013 29,73-954,8 984,5 2014 29,15-1 342,2 1 371,39 2015 29,64 130 1 952,0 2 111,61 2016 33,8 135,63 2 861,1 3 030,48 2017 34,14 365,17 2 915,0 3 314,27 2018 30,14 599,43 3 060,2 3 689,8 2019 5,8*717,32 3 072,8 3 795,87 2020 6,11*857,26 3 076,5 3 939,82 Remark:*Excluding 24,38 MWp of Solar Home System project implemented since 2005.Task 1 National Survey Report of PV Power Applications in COUNTRY 8 Table 5:Other PV market information 2020 Number of PV systems in operation in your country(a split per market segment is interesting)n/a Decommissioned PV systems during the year MW n/a Repowered PV systems during the year MW n/a Table 6 is the information about broader national energy market from 2017 to 2020 as follows.Table 6:PV power and the broader national energy market 2020 2019 2018 2017 Total power generation capacities MW 45 480 45 297 43 374 42 443 Total renewable power generation capacities(including hydropower)MW 12 004,62 11 852,04 11 368,94 n/a Total electricity demand GWh 187 046 192 960 187 832 185 124 New power generation capacities installed MW 183 1 923 941 877 New renewable power generation capacities(including hydropower)MW 152,58 483,1 n/a n/a Estimated total PV electricity production(including self-consumed PV electricity)in GWh 5 867,18 5 652,81 5 494,85 4 935,61 Total PV electricity production as a%of total electricity consumption 3,13%2,93%2,93%2,67%Average yield of PV installations(in kWh/kWp)1 489,2 1 489,2 1 489,2 1 489,2 Key enablers of PV development-Task 1 National Survey Report of PV Power Applications in COUNTRY 9 2 COMPETITIVENESS OF PV ELECTRICITY Module prices The module prices were collected in the local market that the lowest price and highest price of standard module crystalline silicon were 0,24 0,33 and 0,40 0,58 USD/Wp,respectively.The lowest price for large scale order was ground mounted PV power plant and the highest price for small scale order was rooftop PV systems.However,most of PV module in local market was imported while PV module of local manufactured has higher price.The exchange rate as of 22th Nov 2021 was 1 USD=32,68 THB.Table 7:Typical module prices USD/Wp)Year Lowest price of a standard module crystalline silicon Highest price of a standard module crystalline silicon Typical price of a standard module crystalline silicon 2020 0,29 0,49 0,31 System prices Table 8 show typical systems prices of residential,commercial,and industrial BAPV as well as small ground mounted PV system in Thailand.The range of systems price of residential was 1,07 1,38 USD/W.While the commercial,and industrial BAPV system prices were 0,77 0,92 USD/W.For small ground mounted PV system price was 0,61-0,77 USD/W.The price for large ground mounted PV system was not available due to no installation in 2020.The data was provided by local manufacturers who offered PV system installation services.The exchange rate as of 22th Nov 2021 was 1 USD=32,68 THB.Table 8:Turnkey PV system prices of different typical PV systems Category/Size Typical applications and brief details Current prices USD/W Residential BAPV 5-10 kW Grid-connected,roof-mounted,distributed PV systems installed on the roof to produce electricity to grid-connected households.1,23 Small commercial BAPV 10-100 kW Grid-connected,roof-mounted,distributed PV systems installed mostly on small size commercial building or industry plants rooftop.0,84 Large commercial BAPV 100-250 kW Grid-connected,roof-mounted,distributed PV systems installed mostly on larger size commercial building or industry plants rooftop.Task 1 National Survey Report of PV Power Applications in COUNTRY 10 Industrial BAPV 250 kW Grid-connected,roof-mounted,distributed PV systems installed mostly on larger size commercial building or industry plants rooftop.Small centralized PV 1-20 MW Grid-connected,ground-mounted,centralized PV systems that work as central power station.This included SPP(Small Power Producers,10-90 MW)and VSPP(Very Small Power Producer,1-10 MW)utility.0,69 Large centralized PV 20 MW Grid-connected,ground-mounted,centralized PV systems that work as central power station.This included SPP and IPPs(Independent Power Producers,90 MW)utility.However,there was no large-scale PV utility installation in 2020 in Thailand as the government tended to promote more on decentralized PV systems.N/A Table 9:National trends in system prices for different applications Year Residential BAPV Grid-connected,roof-mounted,distributed PV system 5-10 kW USD/W Small commercial BAPV Grid-connected,roof-mounted,distributed PV systems 10-100 kW USD/W Large commercial BAPV Grid-connected,roof-mounted,distributed PV systems 100-250 kW USD/W Centralized PV Grid-connected,ground-mounted,centralized PV systems 10-50 MW USD/W 2020 1,23 0,84 No installation Financial Parameters and specific financing programs The energy conservation with PV rooftop systems was very popular in the commercial and industrial company.Commercial bank had the promotion of green energy and for SMEs(Small and Medium Enterprises).In general,the rate of loans was 3-5%per year.Table 10:PV financing information in 2020 Different market segments Loan rate%Average rate of loans residential installations 3 5%Average rate of loans commercial installations Average cost of capital industrial and ground-mounted installations Task 1 National Survey Report of PV Power Applications in COUNTRY 11 Specific investments programs In 2020 the decentralized rooftop PV systems installation were carried out by private sectors under various business models,and utilities,i.e.the Provincial Electricity Authority(PEA)and the Metropolitan Electricity Authority MEA.This resulted in more installation of PV rooftop systems in commercial,and industrial sectors of Thailand in 2020.The implementation of this scheme was aimed for both self-consumptions and with PPA/private PPA aspects.Since 2019,Thailand has launched the promotion of solar rooftop systems installation for Thai People Incentive Program for residential household for self-consumption purpose with the measure to sell the excessed electricity back to the grid.These projects were conducted by PEA and MEA.Commercial and industrial PV systems were carried out by private sectors that could be via renting and leasing PV systems.The power purchasing contract was developed and signed between the land/building owner and the systems owner/investors.Additional Country information Table 11 shows the retail electricity prices for household,commercial and industrial company.The exchange rate as of 22th Nov 2021 was 1 USD=32,68 THB.Table 11:Country information Retail electricity prices for a household USD/W Note:Time of Use Rate for a household,voltage level 1 refers to 12 kV for MEA and 150 kWh/month:Energy charge:0,099 0,13 USD/kWh,(progressive rate)Monthly service fee:1,16 USD/month Time of Use rate for a household:Voltage Level 1:Energy charge:0,08(Off Peak)0,18(On Peak)USD/kWh,Monthly service fee:1,16 USD/month Voltage Level 2:Energy charge:0,079(Off Peak)0,16(On Peak)USD/kWh,Monthly service fee:9,5 USD/month Retail electricity prices for a commercial company USD/W Small General Service:(A maximum of 15-minute integrated demand of less than 30 Normal Rate of Small General Service:Voltage Level 1:Energy charge:0,099-0,13 USD/kWh,(progressive rate)Monthly service fee:1,40 USD/month Voltage Level 2:Energy charge:0,12 USD/kWh,Task 1 National Survey Report of PV Power Applications in COUNTRY 12 kW through a single Watt-hour meter)Voltage Level:1 refer to 12 kV for MEA and 22 kV for PEA.2 refer to 12-24 kV for MEA and 22-33 kV for PEA.Medium General Service:(A maximum of 15-minute integrated demand from 30 to 999 kW and the energy consumption for three consecutive months through a single Watt-hour meter are not exceeding 250,000 kWh per month)Voltage Level:1 refer to 12 kV for MEA and 69 kV for both MEA and PEA.Monthly service fee:9,50 USD/month Time of Use Tariff of Small General Service:Voltage Level 1:Energy charge:0,08(Off Peak)0,18(On Peak)USD/kWh,Monthly service fee:1,40 USD/month Voltage Level 2:Energy charge:0,079(Off Peak)0,16(On Peak)USD/kWh,Monthly service fee:9,50 USD/month Normal Rate of Medium General Service:Voltage Level 1:Demand charge:6,74 USD/kWh,Energy charge:0,097 USD/kWh,Voltage Level 2:Demand charge:5,97 USD/kWh,Energy charge:0,096 USD/kWh,Voltage Level 3:Demand charge:5,35 USD/kWh,Energy charge:30,095 USD/kWh,*Monthly service fee of all voltage level:9,50 USD/month Time of Use Tariff of Medium General Service:Voltage Level 1:Demand charge:6,39(On Peak)USD/kWh,Energy charge:0,08(Off Peak)0,13(On Peak)USD/kWh,Voltage Level 2:Demand charge:4,05(On Peak)USD/kWh,Energy charge:0,079(Off Peak)0,13(On Peak)USD/kWh,Voltage Level 3:Demand charge 2,26(On Peak)USD/kWh,Energy charge:0,079(Off Peak)0,12(On Peak)USD/kWh,*Monthly service fee of all voltage level:9,50 USD/month Retail electricity prices for an industrial company USD/W(A maximum of 15-minute integrated demand exceeds 1 000 kW,or the energy consumption for three consecutive months through Time of Day Tariff:TOD Voltage Level 1:Demand charge:2,08(Partial Peak)10,12(On Peak)USD/kWh,Energy charge:0,097 USD/kWh,Voltage Level 2:Demand charge:1,79(Partial Peak)8,67(On Peak)USD/kWh,Energy charge:3,1471 USD/kWh,Task 1 National Survey Report of PV Power Applications in COUNTRY 13 a single Watt-hour meter exceeds 250 000 kWh per month)Voltage Level:1 refer to 12 kV for MEA and 69 kV for both MEA and PEA.Voltage Level 3:Demand charge:0,91(Partial Peak)6,83(On Peak)USD/kWh,Energy charge:0,095 USD/kWh,*Monthly service fee of all voltage level:9,50 USD/month Time of Use Tariff:TOU Voltage Level 1:Demand charge:6,39 USD/kWh,Energy charge:0,08(Off Peak)4.3297(On Peak)USD/kWh,Voltage Level 2:Demand charge:4,05 USD/kWh,Energy charge:0,079(Off Peak)0,13(On Peak)USD/kWh,Voltage Level 3:Demand charge:2,26 USD/kWh,Energy charge:0,079(Off Peak)0,12(On Peak)USD/kWh,*Monthly service fee of all voltage level:9,50 USD/month Liberalization of the electricity sector Large scale of electricity generation is monopoly by the utility,but nowadays the electricity generation by distributed generation such as solar rooftop system has the liberty.They need to register with official of Energy Regulatory Commission(OERC)to obtain the production licensing and the distribution licensing for prosumer that own the PV systems capacity is larger than 1 000 kVA.So,the PV system capacity is less than 1 000 kVA,the production licensing is excepted but they should notify to OERC.Task 1 National Survey Report of PV Power Applications in COUNTRY 14 3 POLICY FRAMEWORK This chapter describes the support policies aiming directly or indirectly to drive the development of PV.Direct support policies have a direct influence on PV development by incentivizing or simplifying or defining adequate policies.Indirect support policies change the regulatory environment in a way that can push PV development.Table 12:Summary of PV support measures Category Residential Commercial Industrial Centralized Measures in 2020 On-going New On-going New On-going New Feed-in tariffs Yes Yes Yes Yes Yes-Feed-in premium(above market price)Yes-Yes-Capital subsidies-Green certificates-Renewable portfolio standards with/without PV requirements-Income tax credits-Self-consumption Yes Yes Yes Yes-Net-metering-Net-billing Yes Yes Yes-Collective self-consumption and delocalized net-metering-Sustainable building requirements-BIPV incentives-Other-National targets for PV According to Thailand Power Development Plan 2018-2037(Revision 1)and Alternative Energy Development Plan 2018,Thailand aims to achieve new PV install capacity of 9 290 MWp(new PV 8 740 MWp and new PV hybrid 550 MWp)as well as the 2 725 MW(AC)of floating PV systems by 2037.This will contribute to around half of all electricity produced from renewable energy sources at 2037.When incorporating the project that already got the PPA of 2 849 MWp today,the total install capacity of PV system at 2037 is expected to achieve 12 139 MWp.Task 1 National Survey Report of PV Power Applications in COUNTRY 15 Direct support policies for PV installations 3.2.1 The Energy Plans of Thailand There are two main plans involved in managing the direction of energy and renewable energy in Thailand:Power Development Plan 2018-2037(PDP 2018)revision 1 and the Alternative Energy Development Plan 2018-2037(AEDP 2018).The PDP2018 has set the target of new power plant capacity at 56 431 MW by 2037,with the target of new renewable energy plant construction at 18 696 MW(which will account for around 34,23%of total electricity demand of Thailand in 2037).Of this target,PV sector will dominate the majority of renewable electricity at 9 290 MWp(8 740 MWp new PV systems and 550 MWp new PV hybrid systems),which is accounted for around half of total renewable energy capacity at the end of the plan,as well as the 2 725 MW(AC)target of installing floating PV systems over 9 major dams of Thailand.3.2.2 The Solar for Thai People Incentive Program The Solar for Thai People Incentive Program continues the supporting scheme from previous years where residential electricity users(single home,non-collective)can apply for the program to install PV systems on their rooftop area and be able to serve the role of electricity producers(thus,as prosumers).The program started since 2019 with the primary objective of utilizing electricity produced from PV system for self-consumption,while the excessed electricity from own use can be sold back to the grid at the FiT rate of 2,20 THB/kWh(equivalent to around 0,067 USD/kWh).The target of this program is 50 MWp PV installation per year and will receive the FiT for 10 years.However,the reception of this program is yet to be widely accepted as less than 5 MWp had been achieved since the first phase of this program in 2019.In 2020,the National Energy Policy Council(NEPC)resolution had approved the extension of implementation of this program to be used in academic institutes,hospitals,and agricultural water pumping systems in 2021.This pilot program will focus on the self-consumption of such utilization,with the FiT of selling the excess electricity to the grid of 0,03 USD/kWh(1 THB/kWh).The target of this program was also set at 50 MWp of PV install capacity(20 MWp for hospital,20 MWp for academic institutes,and 10 MWp for agricultural pumping),for the system size of more than 10 kWp but less than 200 kWp with 10 years FiT contract.Self-consumption measures Table 13:Summary of self-consumption regulations for small private PV systems in 2020 PV self-consumption 1 Right to self-consume Yes 2 Revenues from self-consumed PV Saving on electricity bill(net billing scheme)3 Charges to finance Transmission,Distribution grids&Renewable Levies none Excess PV electricity 4 Revenues from excess PV electricity injected into the grid Solar for Thai People Incentive Program FiT of 0,067 USD/kWh for Task 1 National Survey Report of PV Power Applications in COUNTRY 16(Household)FiT of 0,03 USD/kWh for hospital,academic institutes,and agricultural water pumping.(pilot)5 Maximum timeframe for compensation of fluxes N/A 6 Geographical compensation(virtual self-consumption or metering)N/A Other characteristics 7 Regulatory scheme duration N/A 8 Third party ownership accepted No 9 Grid codes and/or additional taxes/fees impacting the revenues of the prosumer Grid code of allowing less than 15%electricity from RE for local transformer capacity in that area 10 Regulations on enablers of self-consumption(storage,DSM)None 11 PV system size limitations Solar for Thai People Incentive Program Household:Less than 10 kWp/household Hospital,academic institutes,and agricultural water pump:more than 10 kWp but less than 200 kWp 12 Electricity system limitations N/A 13 Additional features-Collective self-consumption,community solar and similar measures None Tenders,auctions&similar schemes None Task 1 National Survey Report of PV Power Applications in COUNTRY 17 Other utility-scale measures including floating and agricultural PV Thailand PDP 2018(revision 1)had set the target of 2 725 MWAC floating PVs(FPVs)by 2037 that will be functionally integrated with 9 hydropower dams of Electricity Generating Authority of Thailand(EGAT).In 2020,the construction of the 45 MWAC(58.8 MWp)FPVs system integrated with EGAT Sirindhorn dam hydropower was completed and the system went online in November 2021.This project exploited double-glasses PV technology to maximize the efficiency and performance on water as well as incorporates the energy management system(EMS)that will integrally function with traditional hydropower system to ensure improved capacity,stability and security of electricity production.EGAT will increase the proportion of renewable energy of the country by developing 16 FPVs-Hydro Solar Hybrid Projects within the area of 9 EGAT dams with the total capacity of 2 725 MW(AC)at the end of the plan in 2037.Moreover,IRPC an industry player in Thailand petrochemical business also installed the 12,5 MW floating PV system in 2020,with its prominent application of IRPC-invented HDPE plastic buoys that offered strength against impacts and corrosion,UV-resistant,and environmental-friendly(food-graded materials test passed by US FDA).This is currently the largest floating PVs systems in south-east Asia.Thailand also applied solar pumping for agricultural purposes for quite a long time but only in small scale through various support projects and Royal Initiatives.Social Policies None Retroactive measures applied to PV None Indirect policy issues 3.9.1 Rural electrification measures Thailand has 99,8%electricity access but there are some parts of the region that are difficult in connecting to the grid,such as in high mountain or country border.Thailand had implemented a number of solar PV off-grid projects in the Royal Initiatives area,local community learning center,remote school,local hospitals,protected forest area,and border school to enable the access to electricity where grid access was not applicable.The total combined power production from solar PV off-grid from the Ministry of Energy during 1993 to 2020 was reported around 3 974 kW.Task 1 National Survey Report of PV Power Applications in COUNTRY 18 3.9.2 Support for electricity storage and demand response measures none 3.9.3 Other support measures None Financing and cost of support measures The Board of Investment(BOI)ongoing campaign on investment promotion measures to increase production efficiency had extended from 2017 to 2020.This measure allowed the Industry and SMEs to install solar rooftop on their area to save cost on their electricity bills.The benefits from this measure included a)tax exemption for imported machineries(10%import tax and 7%VAT)and b)3 years income tax exemption with the amount equal to 50%of investment costs.Task 1 National Survey Report of PV Power Applications in COUNTRY 19 4 INDUSTRY Production of feedstocks,ingots and wafers(crystalline silicon industry)PV manufacture in Thailand had no production of feedstocks,ingots,and wafers.The wafers were imported for cell production while the cells were also imported to fabricate the modules.Production of photovoltaic cells and modules(including TF and CPV)Module manufacturing was defined as an industry where the processes of the production of PV modules(the encapsulation)are done.A company may also be involved in the production of ingots,wafers,or the processing of cells,in addition to fabricating the modules with frames,junction boxes etc.The manufacturing of modules may only be counted to a country if the encapsulation takes place in that country.There were total 15 PV module manufactures in 2020 in Thailand,which were responsible for cell and module production and module fabrication.By estimates,total module production was 3 938 MW,and maximum production capacity was 7 078 MW/yr.There were 7 of 15 manufactures are foreign investors and their main PV module productions were subjected for export.Note that cell production information was not available for Thailand,while most of module production information was achievable due to market competition.Total PV cell and module manufactures,together with production capacity information,were summarized in Table 14.Table 14:PV cell and module production and production capacity information for 2020 Cell/Module manufacturer(or total national production)Technology(sc-Si,mc-Si,a-Si,CdTe,CIGS)Total Production MW Maximum production capacity MW/yr Cell Module Cell Module Wafer-based PV manufactures Canadian Solar Manufacturing(Thailand)Co.,Ltd sc-Si,mc-Si n/a 2 000 n/a 3 600 Gintech(Thailand)Co.,Ltd.sc-Si,mc-Si n/a 1 600 n/a n/a Jetion Solar(Thailand)Co.,Ltd.sc-Si,mc-Si n/a 200 n/a 200 Solartron Public Co.,Ltd.sc-Si,mc-Si n/a 100 n/a 700 Talesun Technology(Thailand)Co.,Ltd.sc-Si,mc-Si n/a n/a n/a 1 500 Task 1 National Survey Report of PV Power Applications in COUNTRY 20 Trina Solar Science&Technology(Thailand)Co.,Ltd.sc-Si,mc-Si n/a n/a n/a n/a Yingli Green Energy Holding Co.,Ltd.sc-Si,mc-Si n/a n/a n/a 500 Ekarat Solar Co.,Ltd.mc-Si n/a 9 n/a 15 Full Solar Co.,Ltd.sc-Si,mc-Si n/a 10 n/a 50 G.K.Assembly Co.,Ltd.mc-Si n/a n/a n/a n/a Irradiance Solar Co.,Ltd.mc-Si n/a 1,5 n/a 3 Pornjaroen Tempered Safety Glass Co.,Ltd.sc-Si,mc-Si n/a 2,5 n/a 2,5 Schetten Solar(Thailand)Co.,Ltd.sc-Si,mc-Si n/a 10 n/a 500 Solar Power Technology Co.,Ltd.sc-Si,mc-Si n/a 5 n/a 7,5 Total n/a 3 938 n/a 7 078 Manufacturers and suppliers of other components There were 6 local inverter manufacturers in Thailand,which were P.Y.Enginerring Co.,Ltd.,Chuphotic Co.,Ltd.,Daddee Power Group Co.,Ltd.,Delta Electronics(Thailand)Public Co.,599Ltd.,Leonics Co.,Ltd.and Thai Tabuchi Electric Co.,Ltd.When taking price consideration into the account,most PV inverters were found to be imported due to lower cost.However,in the case that the higher cost inverters were chosen,the customer tended to expect superior after-sale service qualities instead.For battery energy storage,there were 3 manufacturers in Thailand,which were Amita Technology(Thailand)Co.,Ltd.(ATT)cooperate with Energy Absolute Public Co.Ltd.(EA),Global Power Synergy Public Company Limited(GPSC)and Rojana Industrial Park Public Co.,Ltd.cooperate with EVLOMO(US)Co.,Ltd.The market of PV supporting structures is related to the steel manufacturing industry that has no upstream manufacturers.Most of them started at the electric arc furnace(EAF)in order to produce the steel.Steel and iron manufactures represented two main industries in Thailand.As a result,the supporting structures supply of PV system is mainly depended on the steel market.Task 1 National Survey Report of PV Power Applications in COUNTRY 21 5 PV IN THE ECONOMY This chapter aims to provide information on the benefits of PV for the economy.Labour places Table 15 shows the estimated labour places that are related to PV activity by categories.Research and development group(not including companies)had about 14 agency and average of 20 labour places each,totalling 280 labour places.The second category was consisted of 24 companies including PV module manufacturers and balance-of-systems components(inverters and energy storage batteries)that the approximate of labour places is about 300 per company,totalling 7 200 labour places.The next category was consisted of around 100 distributors of PV production and installation company that was receiving public interests especially the rooftop PV systems installation program,had about 50 labour places per company,totalling 5 000 available labour places in the market.Moreover,the PV system operation and maintenance in the PV power plants had about 6 000 labour places in total.Then the total of estimated PV-related labour places in 2020 was estimated to create around 18 480 jobs.Table 15:Estimated PV-related full-time labour places in 2020 Market category Number of full-time labour places Research and development(not including companies)280 Manufacturing of products throughout the PV value chain from feedstock to systems,including company R&D 7 200 Distributors of PV products and installations 5 000 PV power plant operation and maintenance 6 000 Total 18 480 Business value Table 16 shows estimation of PV business values in 2020,which was around 92 978,9 million THB(2 845,13 million USD),consisting of off-grid,grid-connected distributed and grid-connected centralized systems.The exchange rate as of 22th Nov 2021 was 1 USD=32,68 THB Table 16:Rough estimation of the value of the PV business in 2020(VAT is excluded)Sub-market Capacity installed MW Average price USD/W Value USD Sub-market MUSD Off-grid 6,1 0,918 5 599 755,202 5,6 Task 1 National Survey Report of PV Power Applications in COUNTRY 22 Grid-connected distributed 857,26 27,5 721 378 518,972 721,379 Grid-connected centralized 3 076,5 0,688 2 118 153 304,773 2 118,153 Value of PV business in 2020 2 845,13 Task 1 National Survey Report of PV Power Applications in COUNTRY 23 6 INTEREST FROM ELECTRICITY STAKEHOLDERS Structure of the electricity system Electricity utilities in Thailand are consisted of the electricity production and electricity distribution sectors.The electricity production sector consists of the Electricity Generating Authority of Thailand(EGAT),the independent power producers(IPP),the small power producers(SPP),and some imported electricity from neighbour countries.These,included SPP from PV power plants(installed capacity of 10-90 MWp),were regulated by EGAT as well as the electricity transmission systems and infrastructures.Moreover,some direct customers are also be able to sell the electricity back to EGAT.The distribution sector has two involved distribution utilities that are a)Metropolitan Electricity Authority(MEA)and b)Provincial Energy Authority(PEA).MEA is responsible for 3 province areas-Bangkok and two other adjacent provinces(Nonthaburi and Samut Prakan)-while PEA is responsible for the rest of the country.In addition,the very small power producers(VSPP),the electricity producers in distributed renewable energy production,in which smaller scale of PV(installed capacity of 1-10 MWp)installation including solar rooftop PV from either household,commercial,or industrial sources were regulated by MEA and PEA.Moreover,the national energy policy of Thailand is integrally conducted by the National Energy Policy Committee(NEPC),Energy Policy and Planning Office(EPPO)and Office of Energy Regulatory Commission(OERC).In 2020 the transition of electricity industry was occurring and seemed to be on the onset for the preparation of regulation amendments for prosumer aspect.The private sector tends to exhibit the trend to own both PV systems for self-consumption and be able to own distribution system to response to the liberty of rooftop PV system under national energy reform policy.As a result,in the next few years,the new regulations for wheeling charge will be introduced.Regarding installing PV rooftop systems in Thailand,those that install PV capacity of more than 1 000 kVA needed to be applied for the licensing of electricity generation from OERC,either for self-consumption or selling electricity back to the grid.However,those that install PV capacity below 1 000 kVA needed to notify OERC for exemption of licensing of electricity generation.Ground-mounted PV and floating PV were needed to apply for licensing of electricity generation for all capacity.Utility trading in Thailand is currently adopting Enhanced Single Buyer(ESB)scheme,by which EGAT acts as both power producer and electricity purchaser from large scale power producers(Independent Power Producers(IPP)and SPP)while MEA and PEA act as both power distributors for their responsible regions,and power purchaser for VSPP.In order to support effective power transition of the country towards digitalized economy and decentralized power systems,attempts had been made to amend regulatory and legislation obstacles,as well as grid code adjustment to transform from ESB model into wholesale power market in the future.This would lead to the liberalization of prosumer concept that allow easier trading of electricity between private sectors or between households,as well as the grid access of third-party players(Third Party Access,TPA),with the specified wheeling charges,to support the forthcoming of prosumers in Thailand PV market.Task 1 National Survey Report of PV Power Applications in COUNTRY 24 Interest from electricity utility businesses In 2020,apart from the Solar for Thai People Incentive Program that offered possibility of households to receive 2,20 THB/kWh FiT incentives for excessed electricity from installed PV rooftop systems operated under regulation of OERC,PEA and MEA,PEA also supported the installation of rooftop PV systems for social community centers under the“60 Years,60 Cooperations,60 Giveaways,for never-ending lightings”campaign.This campaign offered free investments from provided investors for those who are direct PEA customers who had more than 1 million THB electricity bills(collective bills applicable,no overdue bills required)with more than 10 000 m2 roof area to install around 1 MW rooftop PV systems.Moreover,the campaign also supported the installation of PV rooftops for social and community centers,such as academic institutes,religious places/temples,hospitals,or those that contributed the good deeds for local communities.As Thailand is approaching the concrete expansion of electric vehicles(EVs),the development of electricity demand management system of the country was under development in 2020,where utility players were also key parts of this measures.Task 1 National Survey Report of PV Power Applications in COUNTRY 25 7 HIGHLIGHTS AND PROSPECTS Highlights To summarize PV market in Thailand in 2020,Thailand continued to support the installation of PV in various markets,especially those in decentralized or distributed systems,in order to fulfil the PDP2018 rev.1 target of installing new 9 290 MWp of PV system by 2037.The Solar for Thai People Incentive Program started since 2019,with the prospect to use electricity for self-consumption while the excess electricity can be sold back to the utility grid,also received increase FiT rate from 1,68 THB/kWh($0,0514 USD/kWh)to the new rate of 2,20 THB/kWh($0,0673 USD/kWh)to attract more installation from residential sectors.This program will also be extended to be implemented in academic institutes,hospitals,and agricultural water pumping systems in 2021,with the FiT rate of 1 THB/kWh($0,0305 USD/kWh).In the meantime,the installation of rooftop PV systems in private sectors,such as in commercial buildings and industrial plants,were also developed under various business models by both state-enterprise utility and private investors.This was primarily to reduce the expenses of electricity bills.Apart from EGAT target of installing 2 725 MW floating PV systems,other players were also interested in developing and implementing floating PVs in their premises to save cost from electricity consumption.Finally,PV manufacturers in Thailand had seen increased production capacity from foreign investors due to the global market growth,while local manufacturers confronted with high competition with the imported PV module and system equipment.Prospects Solar PV in Thailand will continue to be an important player in energy market as Thailand had set the ambitious target of installing around half of its renewable electricity from PV systems by 2037.With the suitable driving forces from policy implementation and private sector growth,the growth of PV market in the future is expected to be substantial.With the ongoing trend of self-consuming electricity produced from PV systems installed on the rooftop of the premises,implementing energy storage system is now one of Thailand interests to achieve more reliable source of renewable electricity and match with consumption patterns of electricity users.Currently,Thailand is also conducting studies on PV module recycling as well as the establishment of pilot PV module recycle plant in order to promote more sustainable use of PV modules,as well as to explore their second life potential.As per COP26,Thailand will introduce and adopt the carbon neutrality policy in order to achieve carbon zero by 2050 and will be zero emission by 2065,in the light that more PV systems will become a prominent player in this goal.Task 1 National Survey Report of PV Power Applications in COUNTRY 1

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IEA PVPS：2021 年瑞典太阳能装置调查（英文版）（86 页）.pdf

g National Survey Report of PV Power Applications in Sweden 2021 Task 1 Strategic PV Analysis and Outreach Task 1 National Survey Report of PV Power Applications in Sweden What is IEA PVPS TCP?The International Energy Agency(IEA),founded in 1974,is an autonomous body within the framework of the Organization for Economic Cooperation and Development(OECD).The Technology Collaboration Programme(TCP)was created with a belief that the future of energy security and sustainability starts with global collaboration.The programme is made up of 6.000 experts across government,academia,and industry dedicated to advancing common research and the application of specific energy technologies.The IEA Photovoltaic Power Systems Programme(IEA PVPS)is one of the TCPs within the IEA and was established in 1993.The mission of the programme is to“enhance the international collaborative efforts which facilitate the role of photovoltaic solar energy as a cornerstone in the transition to sustainable energy systems.”In order to achieve this,the Programmes participants have undertaken a variety of joint research projects in PV power systems applications.The overall programme is headed by an Executive Committee,comprised of one delegate from each country or organisation member,which designates distinct Tasks,that may be research projects or activity areas.The IEA PVPS participating countries are Australia,Austria,Canada,Chile,China,Denmark,Finland,France,Germany,Israel,Italy,Japan,Korea,Malaysia,Mexico,Morocco,the Netherlands,Norway,Portugal,South Africa,Spain,Sweden,Switzerland,Thailand,Turkey,and the United States of America.The European Commission,SolarPower Europe,the Smart Electric Power Alliance(SEPA)and the Solar Energy Industries Association and the Solar Energy Research Institute of Singapore are also members.Visit us at:www.iea-pvps.org What is IEA PVPS Task 1?The objective of Task 1 of the IEA Photovoltaic Power Systems Programme is to promote and facilitate the exchange and dissemination of information on the technical,economic,environmental and social aspects of PV power systems.Task 1 activities support the broader PVPS objectives:to contribute to cost reduction of PV power applications,to increase awareness of the potential and value of PV power systems,to foster the removal of both technical and non-technical barriers and to enhance technology co-operation.An important deliverable of Task 1 is the annual“Trends in photovoltaic applications”report.In parallel,National Survey Reports are produced annually by each Task 1 participant.This document is the country National Survey Report for the year 2021.Information from this document will be used as input to the annual Trends in photovoltaic applications report.Authors Main Content:Johan Lindahl and Amelia Oller Westerberg Data:The Swedish Energy Agency,Becquerel Sweden,Swedenergy,Svenska Kraftnt Analysis:Johan Lindahl,Jeffrey Berard,and Amelia Oller Westerberg DISCLAIMER The IEA PVPS TCP is organised under the auspices of the International Energy Agency(IEA)but is functionally and legally autonomous.Views,findings and publications of the IEA PVPS TCP do not necessarily represent the views or policies of the IEA Secretariat or its individual member countries COVER PICTURE Building integrated PV roof(3 MWDC/3 MWAC)in Knivsta,Sweden,manufactured by Midsummer AB.Foto:Johan Lindahl Task 1 National Survey Report of PV Power Applications in Sweden 2 TABLE OF CONTENTS 1 Installation Data.4 Applications for Photovoltaics.4 Annual installed PV capacity.4 Total installed PV capacity.7 PV market segments.10 The geographical distribution of PV in Sweden.12 Key enablers of PV development.14 PV in the broader Swedish power system.15 2 Competitiveness of PV electricity.17 Module prices.17 System prices.18 Financial parameters and specific financing programs.26 Specific investments programs.27 Additional Country information.28 Electricity prices.29 Global solar radiation.33 Production costs of PV electricity.34 3 Policy Framework.36 National targets for PV.37 Direct support policies for PV installations.37 Self-consumption measures.45 Collective self-consumption,community solar and similar measures.51 Tenders,auctions&similar schemes.51 Utility-scale measures including floating and agricultural PV.52 Social Policies.52 Retrospective measures applied to PV.52 Indirect policy issues.52 Financing and cost of support measures.54 4 Industry.55 Production of feedstocks,ingots and wafers.56 Production of photovoltaic cells and modules.56 Task 1 National Survey Report of PV Power Applications in Sweden 3 Manufacturers and suppliers of other components.58 R&D companies and companies with R&D divisions in Sweden.62 Installers,retailers and wholesalers of PV systems.64 Consultancy firms.67 5 Highlights of R&D.68 PV research groups.68 Public budgets for PV research.70 6 PV in the Economy.71 Labour places.71 Business value.73 7 Interest From Electricity Stakeholders.73 Structure of the electricity system.73 Interest from electricity utility businesses.74 Interest from municipalities and local governments.74 8 Highlights and Prospects.76 Highlights.76 Prospects.76 9 APPENDIX I-Data sources and their limitations.78 10 References.81 Task 1 National Survey Report of PV Power Applications in Sweden 4 1 INSTALLATION DATA The PV power systems market is defined as the market of all nationally installed(terrestrial)PV applications with a PV capacity of 40 W or more.A PV system consists of modules,inverters,batteries and all installation and control components for modules,inverters,and batteries.Other applications such as small mobile devices are not considered in this report.For the purposes of this report,PV installations are included in the 2021 statistics if the PV modules were installed and connected to the grid between 1 January and 31 December 2021,although commissioning may have taken place at a later date.Applications for Photovoltaics The installation of grid connected PV systems in Sweden can be said to have taken off in 2006,when about 300 kW was installed that year.Before that only a few grid-connected systems were installed each year.Until 2006,the Swedish PV market almost exclusively consisted of a small but stable off-grid market where the majority constituted of systems for holiday cottages,marine applications and caravans.This domestic off-grid market has been quite stable throughout the years.But since 2007 more grid-connected capacity than off-grid capacity has been installed annually.The grid-connected market is almost exclusively made up by distributed roof-mounted systems installed by individual homeowners,companies,municipalities,farmers,etc.Already from the start,the Swedish distributed market has been driven by the self-consumption business model,as there has never existed a feed-in-tariff in Sweden.Capital subsidies in combination with a feed-in premium scheme,that add value for the excess electricity,has until now been crucial for this business model to work in Sweden.However,as of 2022 no subsidies exist except for the private domestic PV market segment.About 52%of the installed grid-connected PV power are residential systems,33%are installed on commercial buildings,4%on public buildings and 3%on industrial buildings and sites.So far only 8%of the grid-connected market are ground-mounted centralized PV parks,and by international standards the parks are relatively small in size.But the interest and activity in this market segment has increased a lot in 2021 and the number and sizes of centralized PV parks are expected to increase in the coming years.Annual installed PV capacity The installation rate of PV continues to increase at a high speed in Sweden.A total of 499.7 MW was installed in 2021,out of which 497.8 MW was grid-connected,as shown in Figure 1 and Table 2.This means that the annual Swedish PV market grew with 25%compared to the 400.1 MW that was installed in 2020.Of the grid-connected PV capacity installed in 2021,52.3 MW is estimated to be centralized PV parks and 445.5 MW distributed PV systems for primary self-consumption.By that,the annual market of centralized PV in Sweden grew with about 14%and the distributed annual market by 26%as compared with 2020,when approximately 46.0 MW of centralized and 352.5 MW of distributed PV was installed.Sweden has a stable off-grid PV market.In 20172019,about two MW per year of off-grid applications were sold.In 2020 the annual off-grid market decreased slightly to 1.6 MW but grew again in 2021 to 1.9 MW.Task 1 National Survey Report of PV Power Applications in Sweden 5 Figure 1:Annual installed PV capacity in Sweden Table 1:Annual PV power installed during calendar year 2021.Installed PV capacity in 2021 MW AC or DC PV capacity Off-grid 1.891 DC Decentralized 445.51 AC Centralized 52.26 AC Total 499.66 AC Table 2:PV power installed during calendar year 2021.Installed PV capacity MW Installed PV capacity MW AC or DC Grid-connected BAPV Residential 445.51 266.82 AC Commercial 132.56 AC Public 18.83 AC Industrial 27.30 AC BIPV Unknown(Included in BAPV)Utility-scale Ground-mounted 52.26 52.26 AC Floating 0 AC Agricultural 0 AC Off-grid Residential 1.61 0.93 DC Commercial 0.14 DC Mobile applications 0.82 DC Total 499.66 AC Task 1 National Survey Report of PV Power Applications in Sweden 6 Table 3:Data collection process Is the data reported in AC or DC?The reported data is in AC Is the collection process done by an official body or a private company/Association?Public body,the Swedish Energy Agency(grid connected data)Company,Becquerel Sweden(off-grid data)Link to official statistics http:/www.energimyndigheten.se/statistik/den-officiella-statistiken/statistikprodukter/natanslutna-solcellsanlaggningar/The different data sources used for this report are all described and discussed in APPENDIX I-Data sources and their limitations Task 1 National Survey Report of PV Power Applications in Sweden 7 Total installed PV capacity The total grid-connected capacity at the end of 2021 was 1 587.2 MW,according to the grid operators.Out of this capacity,about 133.8 MW is estimated to be centralized PV and 1 453.3 MW to be distributed.In addition,a total of 21.8 MW of off-grid PV applications have been sold in Sweden since 1993,wherein 18.9 MW is estimated to still be in operation.By adding the off-grid and the grid-connected PV capacities together,a total of 1 606.1 MW of electricity producing PV power by the end of 2021 is estimated to up and running,illustrated in Figure 2 and summarized in Table 4.The total installed PV capacity grew by 45%in 2021,which is in line with the development over the five previous years,where the total market grew by 57%(2020)66%(2019),59%(2018),47%(2017)and 49%(2016).The strong overall growth in the last decade started with the introduction of the direct capital subsidy system(see section 3.2.1)in 2006,and has since then been fuelled by the declining system prices(see section 2.2),high popularity among the public(see section 1.6.2),a growing interest from utilities(see 7.1)and an ongoing reformation work from the Government to simplify the rules for micro-producers(see section 3.3).In total there were 92 359 grid-connected PV systems in Sweden by the end of 2021.The number of off-grid systems is unknown.A majority of the grid-connected PV systems,80 207,are small systems below 20 kW.12 093 are in between 20 kW 1000 kW and 59 systems are above 1 MW according to the official statistics(summarized in Table 5).However,the official statistics count everything behind one single connection point to the grid as one system.Several of the centralized PV parks built in Sweden have several connection points to the low voltage distribution grid.These PV parks are divided into several systems in the statistics,and often in sizes below 1 MW.So,the actual number of PV systems above 1 MW in Sweden is larger than 59 systems the way most people would see it.With regards to the number of installed PV systems in Sweden,statistics are available for grid-connected system for the years 2016 to 2021.The number of systems at the end of each year,and the corresponding average system size is presented in Table 6.As can be seen at the end of 2021,Sweden had 92 359 grid-connected PV system,and the corresponding average system size was about 17.2 kW.That is a relatively small system size,which clearly illustrates that the Swedish PV market mainly consist of small distributed PV systems.Figure 2:Total installed PV capacity in Sweden.Task 1 National Survey Report of PV Power Applications in Sweden 8 Table 4:The cumulative installed PV power in 3 sub-markets.Year Off-grid MW Grid-connected distributed MW Grid-connected centralized MW Total MW 1992 0.80 0.01 0.00 0.81 1993 1.03 0.02 0.00 1.05 1994 1.31 0.02 0.00 1.33 1995 1.59 0.03 0.00 1.62 1996 1.82 0.03 0.00 1.85 1997 2.03 0.09 0.00 2.12 1998 2.26 0.11 0.00 2.37 1999 2.46 0.12 0.00 2.58 2000 2.68 0.12 0.00 2.80 2001 2.88 0.15 0.00 3.03 2002 3.14 0.16 0.00 3.30 2003 3.39 0.19 0.00 3.58 2004 3.67 0.19 0.00 3.86 2005 3.98 0.25 0.00 4.23 2006 4.30 0.56 0.00 4.86 2007 4.57 1.68 0.00 6.25 2008 4.83 3.08 0.00 7.91 2009 4.97 3.54 0.06 8.57 2010 5.34 5.12 0.25 10.71 2011 5.78 8.47 0.28 14.53 2012 6.38 14.92 0.89 22.19 2013 7.31 32.14 1.37 40.82 2014 8.20 63.81 2.95 74.95 2015 9.16 109.19 4.30 122.64 2016 10.43 165.17 7.12 182.73 2017 12.27 244.18 11.64 268.10 2018 14.09 390.15 20.09 425.14 2019 15.82 655.86 35.07 706.75 2020 17.20 1 007.82 81.58 1 106.60 2021 18.89 1 453.33 133.84 1 606.06 Task 1 National Survey Report of PV Power Applications in Sweden 9 Table 5:Other PV market information.2021 Number of PV systems in operation in Sweden Grid connected PV Under 20 kW 80 207 20 kW 1000 kW 12 093 Above 1000 kW 59 Total 92 359 Off-grid PV Unknown Decommissioned PV systems during the year MW 221 kW of off-grid system is estimated to have been decommissioned Repowered PV systems during the year MW Unknown Table 6:Number and average sizes of grid connected PV systems in Sweden at the end of each year.2016 2017 2018 2019 2020 2021 Number of systems 10 006 15 298 25 486 43 944 65 819 92 359 Average size per system for the total number of systems at the end of each year kW 14.0 15.1 16.1 15.9 16.6 17.2 Average size per system for the annual market kW 17.3 17.3 17.6 15.7 17.7 18.7 Task 1 National Survey Report of PV Power Applications in Sweden 10 PV market segments The official statistics of the grid operators,collected by the Swedish Energy Agency,only include segmentation in PV system sizes(power)in the ranges 020 kW,201000 kW and 1000 kW.The total installations at the end of 2021,according to this source,are summarized in Table 7.Table 7:Total installations of grid connected PV capacity and number of systems at the end of 2021,according to the grid operators1.020 kW 201000 kW 1000 kW Total grid-connected PV capacity according to the grid operators collected by the Swedish Energy Agency MW 789.55 675.28 122.38 Total number of grid-connected PV systems according to the grid operators collected by the Swedish Energy Agency#80 207 12 093 59 However,for market segmentation there is another data source.In the database of the Swedish direct capital subsidy(see section 3.2.1)all PV systems that have been granted support from the start of the subsidy programme in 2009 until now are recorded.By cross-referencing between this database and Swedens national business directory,a business sector can be assigned to each system owner.By doing this,the database can be divided into centralized,industry,commercial or residential systems(see section 9.1.4).By dividing the annual installed PV capacity for each market segment by the total installed PV capacity the different market segments share of the annual installations can be estimated.The historic development of these shares is presented in Figure 3.Figure 3:Various market segments share of the annual installed PV capacity in Sweden.Based on statistics from the capital subsidy database.Task 1 National Survey Report of PV Power Applications in Sweden 11 Clearly,the biggest market segments in Sweden have been residential domestic single-family houses and commercial facilities.A slight variation over the years can be seen,but these two segments have always been the biggest.The reason for that is that the self-consumption business model is easy to implement for these types of buildings.The low shares of the other market segments,such as centralized PV parks,industry and residential multi-family houses can all be explained by the historic policy structure in Sweden.The reason for the underdeveloped Swedish market of centralized PV parks,as compared to in many other countries,is that the current support schemes has not been enough do drive PV park development in Sweden until 2020 basically.The two support schemes that has been available has been the renewable electricity certificate system(see section 3.2.3)and a maximum 1.2 million SEK per system from the direct capital subsidy programme(see section 3.2.1).However,this is a market sector that is expected to grow in the coming years.At the end of 2020 there was 38 commissioned PV parks in Sweden that with a capacity of above 0.5 MW known to the authors.Besides those mentioned,the authors are aware of additional plans for several larger PV parks.It appears this sector is on the brink of managing without any subsidies,with the help of innovative business models such as PPA-contracts and PV cooperative models.The increase of the industry segment in 2021 can partly be explained by the increase of the energy tax threshold from 255 kW to 500 kW that took place the July 1st,2021(see section 3.3.2),which made it economical more feasible to install larger systems.In addition,a few ground-mounted PV parks,built next industry facilities,was commissioned in 2021.These are counted as industry systems and not centralized PV parks(even if they are ground-mounted parks)as the electricity is generated in primary for self-consumption on the site.The general obstacle for residential multi-family houses is the current tax laws,which makes it complicated to self-consume PV electricity in the apartments of a multi-family house.The most common situation is that the apartments have their own meter and contract with the grid operators and the whole multi-family house has one separate meter and contract for the electricity consumed in common areas of the house,e.g.elevators,laundry room,lighting.With this arrangement it is only possible to use the produced PV electricity(from a PV system on the building)for the electricity consumption of the common areas.If the owner of the multi-family house wants to sell the PV electricity to the apartments,the owner becomes a retailer of the electricity and must follow the regulations which come along with that role including the Swedish energy tax that is applied to the electricity(even if it has not left the building).Hence,it is difficult to reach a high degree of self-consumption in multi-family houses arranged this way.The value of the excess electricity exported to the grid drops if the fuse exceeds 100 amperes(see section 3.2.4),thus it becomes hard to achieve a decent profitability for such installations.However,it is possible to self-consume the PV electricity in the apartments without taxes if the whole multi-family building,including the apartments,share one single meter and contract with the grid operator.This arrangement requires that the electricity consumption in the apartments is included in the general rent of the apartments.And then it is up to the owner of the multi-family house to decide if the residents in the apartments should pay a fixed price for the electricity regardless of their consumption or handle the metering of the electricity consumption themselves and vary the level of the monthly rent for the residents depending on their electricity consumption.The latter solution becomes more and more common in Sweden,but the general complexity to move to this arrangement is one reason for the low installation numbers for multi-family houses.Several proactive housing and property companies have however experienced added values after investments in PV,such as sustainability,fair cost,and induced innovativeness 2.These experiences are likely to spread over time to other actors and motivate them to overcome the perceived legislative barriers.Task 1 National Survey Report of PV Power Applications in Sweden 12 The geographical distribution of PV in Sweden The data from the grid operators statistics about the installed PV power in Sweden has a geographical resolution down to municipality-level.This data has been used to illustrate the geographical distribution of PV in Sweden in Figure 4 and Figure 5 for most of the municipalities in Sweden.However,some municipalities are marked as blank by the public Swedish Energy Agency due to confidentiality reasons.For these municipalities,data from the green electricity certificate system(see section 3.2.3)has been used to complement the grid operators data in creating Figure 4 and Figure 5.In 2019 these municipalities were Ale,Arjeplog,Arvidsjaur,Borgholm,Haparanda,Hultsfred,Norberg,Skellefte,Sorsele,Storuman,Surahammar,ml and verkalix.In 2021,no confidentiality hindered the reporting of installed PV power in any municipalities.Figure 4 and Figure 5 clearly show that the expansion of PV takes place at different speeds in Swedens municipalities.When it comes to most installed PV capacity,Gothenburg,followed by Uppsala and Linkping were in the top at the end of 2021 with 58.4,41.7 and 40.7 MW,respectively.Gothenburg,that overtook the lead from Linkping in 2018,is much helped by the three PV parks of 5.5,5.5 and 3.7 MWp,respectively,that have been commissioned in the municipality the recent years.Taking the lead from last years leader Strngns,Skurup was the top municipality in 2021 with regards to installed PV capacity per capita.Skurup is a rather small municipality with 16 322 inhabitants,which with 19.5 MW installed PV capacity results in the top score of 1189.5 W/capita.Swedens largest PV park(18 MW)was installed in Skurup by E.ON in 2021,and even though it was officially commissioned in 2022,it was probably connected and registered already in the end of 2021 3.Second on the list is Sjbo with 992.0 W/capita,holding its position from 2020.It is no coincidence that Sjbo is also in the forefront.In Sjbo,Swedens at the time largest PV park,“Sparbanken Sknes Solcellspark”was commissioned in 2019,with 5.8 MWp installed.This PV Park was extended to 18 MW in 2020,giving it the top ranking again in 2021.Borgholm is the municipality with third most PV capacity installed per capita,with 581.0 W/capita.The Swedish electricity market is from the first of November 2011 divided into four bidding areas by decision of the Swedish National Grid(Svenska Kraftnt),marked as SE1,SE2,SE3 and SE4 in Figure 4 and Figure 5.The reason is that northern Sweden has an excess of electricity production,since that is where a lot of the wind power and a majority of the hydropower is situated,while the demand is larger than the production in southern Sweden.This has resulted in transmission bottlenecks,and the borders between the bidding areas have been drawn where there are congestions in the national grid.The idea of the four bidding areas is to make it clear where the national grid needs to be expanded and where an increased electricity production is required to better meet the consumption.From this perspective,it is positive that a majority of the PV capacity is being installed in southern Sweden and mainly in the densely populated municipalities,as shows.The value of the PV electricity is also higher in SE4 and SE3,as the average market value between 2014 and 2021(see section 2.6 for further explanation and discussion)of PV in these bidding areas was 382.9 and 352.9 SEK/MWh respectively,as compared to 318.5 and 319.5 in SE2 and SE1 respectively.Task 1 National Survey Report of PV Power Applications in Sweden 13 Figure 5:Total power of the PV systems per capita in each of Swedens municipalities.For some municipalities data from the green electricity system has been used instead of grid operators data due to confidentiality reasons Figure 4:Total power of the PV systems in each of Swedens municipalities.For some municipalities data from the green electricity system has been used instead of grid operators data due to confidentiality reasons.Task 1 National Survey Report of PV Power Applications in Sweden 14 Key enablers of PV development 1.6.1 Other technologies For the last six years,the survey sent to the installation companies included questions about grid connected battery capacity that had been installed.According to the installations companies a total battery capacity of 21.5 MWh was installed in 2021,an increase of 74%compared to the 12.4 MWh installed in 2020,as Table 8 illustrates.The general global trend of decreasing battery prices 4,signals that a growing battery market in Sweden is expected.In 2018,a clear shift can be seen in Table 8,as compared to previous years,where the battery market for private households became larger than the market for commercial systems.This development can be explained by the introduction of the capital subsidy programme for storage(see section 3.9.3),which influences the storage market.The reader should be aware that this battery capacity is not the total annual installed grid connected battery capacity in Sweden.It is only the battery capacity that PV installation companies have installed in connection to distributed PV systems.The battery capacity of the electrical cars in Sweden was 7377 MWh in the end of 2021 5.If one adds the total battery capacity of stationary grid connected batteries connected to PV systems installed between 2016 and 2021 the total battery capacity at the end of 2020 became 7 425 MWh.Table 8:Annual installed grid connected stationary battery capacity installed by PV installation companies.Year Private system Commercial system Total 2016 177 kWh 1 365 kWh 1 542 kWh 2017 1 138 kWh 1 288 kWh 2 426 kWh 2018 2 414 kWh 1 520 kWh 3 934 kWh 2019 3 506 kWh 2 956 kWh 6 462 kWh 2020 8 879 kWh 3 498 kWh 12 378 kWh 2021 16 086 kWh 5 413 kWh 21 499 kWh 1.6.2 The public opinion about PV The general opinion about PV in Sweden is very positive among the public.In an annual survey 6,sent out by the SOM-institute,randomly selected respondents have answered the question“How much should Sweden invest in the following energy sources during the next 5-10 years?”.The result is presented in Figure 6,indicating a strong majority of 80%of the respondents want more investments in PV in Sweden,which makes the PV technology by far the most popular electricity production technology in that aspect.Figure 6:The public opinion in Sweden about different electricity production technologies in 2020.Task 1 National Survey Report of PV Power Applications in Sweden 15 PV in the broader Swedish power system The Swedish power system has been divided into four bidding areas(SE1SE4)since November 1st,2011,by decision of the Swedish National Grid(Svenska Kraftnt).The reason is that northern Sweden has a surplus of electricity production compared to the demand,while there is a higher demand than production in southern Sweden.This has resulted in transmission capacity problems and the borders between the bidding areas have been drawn where there are congestions in the national grid.The idea of the four bidding areas is to make it clear where in Sweden the national grid needs to be expanded and where in the country increased electricity production is required to better meet consumption,and thus reduce the need to transport electricity long distances.The geographical borders of the areas are marked in Figure 4 and Figure 5.The major changes in the Swedish power production the last years have been the expansion of wind power,the decommission of two nuclear power reactors and the closure of the last coal power plant.The nuclear reactors Ringhals 2(905 MW)was taken out of service on the morning of 30 December 2019 and Ringhals 1(881 MW)in the evening on 31 December 2020.The last coal power plant,Vrtaverket,was shut down in 2020.Another recent change in the system is that the yearly average allocated transmission capacity between SE2 and SE3,respectively SE3 and SE4,by the Swedish transmission system operator(TSO),has decreased in recent years.For the whole year of 2020 the average transmission capacity between SE2 and SE3 was 6,132 MW,which is approximately 1 200 MW less than the boundarys maximum capacity of 7 300 MW,and the lowest value of the last 8 years.About the same reduction is observed between SE3 and SE4.On average,the price area border had a transmission capacity of 4 198 MW in 2020,which can be compared with the maximum capacity of 5 400 MW.The allocation of transmission capacity is made hour by hour.The explanation for the decreasing average allocated transmission capacity in recent years given by the Swedish TSO is interruptions on cables due to maintenance work and changed energy flows in the electricity grid 7.Lastly,the off shore transmission capacity from the Nordic region to the continental Europe and Baltic countries are steadily increasing as several transmission cables has been built in last decades,such as the Baltic Cable(Germany to SE4,600 MW,in operation 1994),the Swe-Pol Link(SE4 to Poland,600 MW,2000),Nordbalt(SE4 to Lithuania,700 MW,2016),Nordlink(Norway to Germany,1400 MW,2021)and the North Sea Link(Norway to UK,1 400 MW,2021).This enables“import”of the higher spot prices of the different European price areas to the Nordic region 891011,which can increase the internal congestion in Sweden 8.The higher electricity prices will benefit both variable renewable technologies,such as wind power and PV and reservoir hydropower through a transfer of wealth from thermal power technologies on the European continent,which will receive reduced revenues with increasing interconnection levels 11.The consequences of offshore transmission capacity extensions can lead to higher prices in the Swedish price areas SE3 and SE4,which will be beneficial for PV as most of the PV capacity in Sweden are being installed in these two price areas,see section 1.4.In Figure 7,the Swedish electricity production in 2021 is presented.The electricity production data used in Figure 7 and Figure 8,along with Table 9,were retrieved from Svenska Kraftnt 12,but with complementary data from SCB 13 with regards to the fuels used in the Swedish CHP power plants.The total power generation in Sweden was 165.8 TWh in 2021,while the electricity consumption was 139.8 TWh.In total,Sweden imported 8.3 TWh and exported 33.9 TWh.As can be seen in Figure 8,the Swedish electricity has historically been produced by technologies that have a low CO2-footprint.This along with the low electricity prices(see section 2.6)counts as the two main reasons why the Swedish PV deployment started late compared to other European markets and still is rather small.Task 1 National Survey Report of PV Power Applications in Sweden 16 Table 9.PV power and the broader national energy market.Data Year Total power generation capacities MW 43 669 2021 Total renewable power generation capacities(including hydropower)MW 33 699 2021 Total electricity demand TWh 139.8 2021 New power generation capacities installed GW 2 614 2021 New renewable power generation capacities(including hydropower)GW 2 530 2021 Estimated total PV electricity production(including self-consumed PV electricity)in GWh 1118 2021 Total PV electricity production as a%of total electricity consumption 1 21 Average yield of PV installations kWh/kWp 950 2021 Figure 7.Total electricity production in Sweden in 2021.Figure 8.Total annual electricity production in Sweden between 1990 to 2021.Task 1 National Survey Report of PV Power Applications in Sweden 17 2 COMPETITIVENESS OF PV ELECTRICITY Module prices Module prices in Sweden are heavily dependent on the international module market.Sweden saw a very rapid decline in price for PV modules between 2008 and 2013 due to a growing domestic market,which allowed retailers to import larger quantities.Between 2013 and 2016,the price decline in Sweden was more moderate.The main reasons for the stabilization of the module prices under this time period was the import duties on Chinese PV modules and cells that were introduced in 2013 by the European Commission 14.In these measures,a minimum import price(MIP)was introduced,which means that no silicon modules could be imported to the European Union at a price lower than 0.56/Wp,which corresponded to about 5.2 SEK/Wp.After the termination of the duties many Swedish retailers lowered their module prices towards the Swedish installation companies with 20-30%.That resulted in a price drop of the average typical module price to the end consumer by 14%in 2018,which continued with a price decline of 4%in 2019 and 7%n 2020(see Table 10).In 2021,however,the price survey shows an increase in price for the first time since the data collection started.A slight increase in prices for 2021 has been documented in several sources,amongst them IEA PVPS Task 1 global Trends report 15 and international spot market prices 16.This increase is assigned to conjunctural effects of the COVID-19 pandemic,which resulted in disrupted value chains,higher polysilicon prices and shipment costs globally.This development also affected Sweden.In addition to the collected sales statistics,which should be read as the module price to the end customer,the result of an Swedish study showed that the internal module cost from the perspective of the installer was 3.1 SEK/Wp for 10 kWp residential systems in 2020 17.The result of study is further discussed in section 2.2.3.Table 10:The historical development of typical module prices.The prices are reported by Swedish installers and retailers.The prices are the prices to the end costumer,not the import price for the retailers.Year Lowest price of a standard module crystalline silicon SEK/Wp Highest price of a standard module crystalline silicon SEK/Wp Typical price of a standard module crystalline silicon SEK/Wp 2004-70 2005-70 2006-65 2007-63 2008-61 2009-50 2010 20 68 27 2011 12 50 19 2012 9.5 40 14 2013 6.0 16 8.9 2014 6.0 12 8.2 2015 5.1 10 7.6 2016 4.5 9.3 7.1 2017 4.0 6.6 5.3 2018 3.2 6.6 4.5 2019 2.9 5.4 4.3 2020 2.5 6.6 4.0 2021 3.5 7.0 4.6 Task 1 National Survey Report of PV Power Applications in Sweden 18 System prices Sweden has experienced a large decrease in PV system prices since 2010,especially before 2013,as Figure 7 shows.The major reason for the decline in system prices in Sweden is that the prices of modules and the balance of system(BoS)equipment has dropped in the international market.Another reason is that the Swedish market is growing,providing the installation firms a steadier flow of orders and an opportunity to streamline the installation process,thus reducing both labour and cost margins.A historic trend of decreasing yearly full-time labour positions per installed MW is illustrated in Table 33.The decreasing trend in labour places per MW is probably one of the reasons for the declining PV prices in Sweden since companies are becoming bigger and more effective in their marketing and installation processes.This can be applied to all years except the 2021 development that can be explained by major events following the COVID-19 pandemic and the subsequent supply constraints,see sections 2.2.4 and 6.1.The maturing of the Swedish PV market and the increasing competition is a factor likely pushing down the prices of Swedish PV systems.Table 32 further corroborates this,as in 2010 the authors of the Swedish NSRs were aware of 111 active companies that sold and/or installed modules or PV systems in Sweden.In the end of 2021,the corresponding figure had gone up to 308.2.2.1 Estimated PV system prices by the sales statistics The price information from the sales surveys is presented in Figure 7 and Table 11.The methodology for collecting the price statistic is explained in section 9.1.5 and the price development is discussed in section 2.2.4 below.Compared to previous years of collecting sales statistics,the installation and sales companies have reported difficulty to generalise prices on a yearly basis.The reason for this is that the last year have demonstrated an increased hardware price volatility,which translates to the end customer system prices.Figure 7:Historic development of the weighted average typical prices for turnkey photovoltaic systems(excluding VAT),reported by Swedish installation companies.Task 1 National Survey Report of PV Power Applications in Sweden 19 Table 11:National trends in system prices for different applications.Year Residential BAPV Grid-connected,roof-mounted,distributed PV system 5 kW SEK/Wp Small commercial BAPV Grid-connected,roof-mounted,distributed PV systems 15 kW SEK/Wp Large commercial BAPV Grid-connected,roof-mounted,distributed PV systems 100 SEK/Wp Small centralized PV Grid-connected,ground-mounted,centralized PV systems 0.5 MW SEK/Wp 2007 2008 96.00 67.00 2009 76.00 47.00 2010 63.33 45.89 40.79 2011 32.07 28.77 24.44 2012 21.43 20.29 16.13 2013 16.68 15.09 13.62 12.73 2014 15.28 13.81 12.63 11.77 2015 15.13 13.20 11.82 10.69 2016 15.07 12.48 11.56 9.03 2017 14.81 12.22 10.70 9.30 2018 14.76 12.09 10.31 8.18 2019 14.40 11.74 10.28 7.50 2020 13.27 10.50 8.92 6.50 2021 14.91 12.21 10.34 7.60 2.2.2 PV system prices recorded in the direct capital subsidy programme The other source for system price statistics is the database of the Swedish direct capital subsidy,in depth described in section 9.1.4.As explained in 3.2.1 and 9.1.4,the number of systems in the data base is lower this year compared to previous years.This is because investment support was closed for new applications in 2020.The decrease is evident in Table 12 and 13,as they also list how many systems that the presented average prices have been derived from,for the reader to get a sense of relevance of the average price presented.Concretely,it means that the number of systems on which the price information is based has dropped and thus also the statistical certainty.When it comes to the prices of turn-key grid connected roof-mounted PV systems there is of course a wide range,even for systems with similar size and type of owner.The range depends on many factors,such as type of building,type of roof,type of module and BoS,etc.Furthermore,it is not possible to derive if the PV systems are building applied(BAPV)or building integrated(BIPV),or if the owner has carried out some of the installation work by him/herself.These factors result in several recorded PV system prices(especially in the segment of small residential single-family systems)that are unusually high 44 SEK/Wp or low 250 kW Grid-connected,roof-mounted,distributed PV systems installed to produce electricity to grid-connected industrial buildings,warehouses,etc.611 Small centralized PV 1-20 MW Grid-connected,ground-mounted,centralized PV systems that work as central power stations.The electricity generated in this type of facility is not tied to a specific customer and the purpose is to produce electricity for sale.58 Large centralized PV 20 MW Grid-connected,ground-mounted,centralized PV systems that work as central power station.The electricity generated in this type of facility is not tied to a specific customer and the purpose is to produce electricity for sale.not applicable Financial parameters and specific financing programs The interest rate(reporntan)of the central bank of Sweden(Riksbanken)was to 0.00%during the entire 2021 19.Changes in interest rate by the central bank have a direct impact on the market rates,which therefore have been quite low in 2021.The cost of capital for a PV system was consequently low in 2021.In Table 16 the average nominal mortgage rate in 2021 has been used for residential installations.For commercial installations in Sweden a realistic nominal loan rate has been reported to be the STIBOR rate plus 450 dps.A study deriving the levelized cost of electricity(LCOE)of Swedish centralized PV parks 20 present average weighted average cost of capital(WACC)for industrial and ground-mounted installations,which have been used in Table 16.However,the reader should not that the interest rates since 2021 in general have increased,and higher values are reasonable to assume for 2022 and onwards.Task 1 National Survey Report of PV Power Applications in Sweden 27 Table 16:PV financing information in 2021.Different market segments Loan rate%Average rate of loans residential installations 21 1.5%Average rate of loans commercial installations 22 4.5%Average nominal cost of capital industrial and ground-mounted installations 3.4%Several commercial Banks have started to offer specific solar loans directed to private individuals with single family houses.To the knowledge of the authors,the first loan specifically directed to PV installations in Sweden was launched by Sparbanken Syd in 2019,from which private PV system buyers at the time of writing can loan 250 000 SEK at a variable interest rate of 2.90%and a repayment period of up to 10 years 23.Other examples are the offers of Swedbank and SEB,who both present solar loans for up to 350 000 SEK at a variable interest rate of 2.15%and a repayment period of up to 10 years 2425.A third example is Vattenfall,that in collaboration with Handelsbanken,offer a solar loan at an interest rate of 1.9&.Specific investments programs Already in 2009,the first PV cooperative,Solel i Sala&Heby ekonomisk frening,started in Sweden.This PV cooperative has a FiT agreement with the local utility company Sala-Heby Energi,that buys the electricity from the cooperatives PV systems.Since the start in 2009 the cooperative has now built six systems with a total capacity of 599 kWp.Other examples of similar PV cooperatives that has built co-owned PV systems are Solel i Bergslagen ekonomisk frening,with three systems totalling 156 kWp,and Zolcell 1:1 ekonomisk frening,with 2 systems totalling 27 kWp.The PV cooperative business model have in later years been adapted by utility companies that have built large PV parks or systems.Any private person or company can buy a share in such a cooperative and the shares represent a certain yearly production or renumeration,which the cooperatibe organization deduct from the share owners electricity bill or pay in real money.One example of this business model is the 1 MWp park with solar tracking outside of Vsters,which the utility company Mlarenergi and the installation company Kraftpojkarna manage together.Another example is the cooperative Trneby driftfrening Ek.Frening,initiated by Kalmar Enerig,that installed a crowdfunded 600 kWp system on the roof of a local farm called Nbble Grd.Following the positive response of Nbble Grd,Kalmar Energi is now stepwise building a PV park close to the Kalmar Airport on the behalf of the coopertive.This park is built in stages of 750 kWp each.The first one was finalized in the end of September 2017,the second in June 2018 and the third in May 2019.In 2017,resundskraft initiated the cooperative Solar Park Ek.Frening,which in two phases have built a PV park with a total capacity if 530 kWp on a former landfill close to Helsingborg.A fourth PV park cooperative is Karlskrona Solpark drift Ek.Frening,initiated by the utility Affrsverken.Their first stage of 0.6 MW of their crowd funded PV park was finalized in April 2019,the second stage of another 0.6 MW was complete in October 2019.The utility Jmtkraft has also created a cooperative,stersunds Solpark Drift Ek.Frening,which owns a 3 MW PV park outside of stersund which was commenced in late 2019.In addition,the local utilities Trans Energi and C4 Energi have initiated similar cooperatives,Bredstorp Sol Ek.Frening and Solpunkten Kristianstad Ek.Frening,respectively.These two cooperatives are as of 2021 running PV parks at the size of 1.2 MW and 4 MW outside of Trans and Kristianstad,respectively.In 2014 there was no company offering PV leasing contracts.However,in 2015,the company Eneo Solutions AB started to offer solar leasing contracts to owners of commercial and public buildings.In 2016 two utility companies,Ume Energi and ETC El started to offer solar leasing contracts to private homeowners.Task 1 National Survey Report of PV Power Applications in Sweden 28 Table 17:Summary of existing investment schemes.Investment Schemes Introduced in Sweden Third party ownership(no investment)Yes Renting Yes Leasing Yes Financing through utilities Yes Investment in PV plants against free electricity Yes Crowd funding(investment in PV plants)Yes Community solar Yes International organization financing No Additional Country information Sweden is a country in northern Europe.With a land area of 407 284 km 27,Sweden is the fifth largest country in Europe.In January 2017 Sweden passed ten million inhabitants for the first time in history 28.With a population of 10 452 326 people at the end of 2021,the population density of Sweden is therefore low with about 25.7 inhabitants per km,but with a much higher density in the southern part of the country 29.About 88%of the population live in urban areas 30.Table 18:Country information.Retail Electricity Prices for a household(range)1.54.8 SEK/kWh(including grid charges and taxes)Retail Electricity Prices for a commercial company(range)0.92.17 SEK/kWh(including grid charges and taxes)Retail Electricity Prices for an industrial company(range)0.81.1 SEK/kWh(including grid charges and taxes)Liberalization of the electricity sector Sweden currently has one of the most liberalized and top ranked electricity systems in the world 31,due to its(1)high operational reliability-the delivery security was 99.987%in 2020 32,(2)high electrification level 100%of total population have access to electricity 33,and(3)low greenhouse gas emissions emissions from fossil fuels associated with the domestic electricity production,in 2021 was 1.4 TWh,which corresponds to 0.9%of the total Swedish electricity production of 165.8 TWh 34.Task 1 National Survey Report of PV Power Applications in Sweden 29 Electricity prices In Sweden,the physical electricity trading takes place on the Nordic electricity retailing market,Nord Pool Spot market.Historically,electricity prices in Sweden have primarily been dependent on the rainfall and snow melting,the availability of the nuclear reactors and the outside temperature.In recent years,a lot of wind power has been built,which affect the spot prices,and more transmission connections to surrounding countries have come online.2021 was a year with record-high electricity prices in Sweden.The annual average was the highest recorded and even the average price per week,day and hour were on peak levels.The main reason was the high natural gas prices in Europe,and coupled with a substantial deficit in the hydrological balance,it negatively affected the usual Nordic resilience to high electricity prices from central Europe.Since the Swedish electricity mix is characterized by a large share of hydropower while having problems with power congestions,large variations between the bidding areas appear 35.Opposite to 2021,Sweden experienced low electricity prices in 2020,with a 73crease from 2019.The national yearly average electricity price was 0.63 SEK/kWh on the Swedish electricity market in 2021,which is a 554%increase compared to the 2020 average of 0.11 SEK/kWh.In 2021,the spot prices were quite volatile over the year,with remarkably high prices,as Figure 12 and 15 illustrates.The yearly average ended up at 0.432 in SE1,0.433 in SE2,0.672 in SE3 and 0.819 in SE4.Up until 2020,there was only a very small price difference between the areas,which have probably not influenced the distribution of PV systems over the country to the same extent as solar radiation(see section 2.7)and the population distribution does(see section 1.3).However,if the price difference between the different price areas will be in the same order of magnitude as in 2020 and 2021 in the future,this could affect the distribution of PV in Sweden.Looking back at the last seven years,the spot prices have varied substantially in Sweden,as Figure 13 and Table 19 illustrates,which makes it harder to predict the renumeration of centralized PV parks.One method of determining the actual value of power from a certain electricity generation technology on a shifting spot market is to calculate the market value over a certain period 36373811.The market value of an electricity generation technology over a time period represents the relationship between the average spot price of the electricity produced by a power source and its production share on the market.Furthermore,by comparing the market value a technology with the time-weighted average wholesale electricity price of the same market and time period a“value factor”,VF(or sometimes referred to as“capture rate”),can be determined.Figure 12:Daily average day-ahead spot prices in area 1(Lule)and area 4(Malm)in 2021.Task 1 National Survey Report of PV Power Applications in Sweden 30 A value factor above one is a result of a positive correlation between the production profile of an electricity generating technology(or an individual power plant)and the price fluctuations on the spot market.It can therefore be seen as an indication that the power system would benefit from more production with a similar production profile.As can be derived from Table 19,the market value of PV electricity in Sweden has on average been 7.7 SEK/MWh higher and 2.2 SEK/MWh lower than the average spot prices in Sweden during 2014 to 2021 in SE1 and SE4,respectively.The highest market value was achieved in 2021,which was also the year with highest electricity prices in this period in Sweden.From Table 19,one can also see that the market value of PV electricity is higher in the two southern price areas(SE3 and SE4)than in the two northern ones(SE1 and SE2).This is fortunate,as the average global radiation is higher in the southern part of Sweden.Analysing the value factor of PV,Table 19 show that the value factor has varied over the years.In 2015 and 2019 it was below 1.0,while it was higher than 1.0 in 2014,2016,2017 and 2018.In 2020,the value factor was above 1.0 in SE3 and SE4,but below in SE1 and SE2,while 2021,the opposite occurred with value factor was above 1.0 in SE1 and SE2,but below 1.0 in SE3 and SE4.If one compares the value factor of PV with the value factor of the other power sources in Table 19,one can see that hydro power,PV and CHP in general has value factors above 1.0,while nuclear are very close to 1.0 and wind power consistently have value factors below 1.0.A simplified conclusion is that the price indicates that the Swedish electricity system would benefit if production with the production profiles similar to either hydro power,PV or CHP would be added.However,this does not by default correlate with profitability for these power sources.Figure 13:Weekly average day-ahead spot prices in area 1(Lule)and area 4(Malm)in 20142021.Task 1 National Survey Report of PV Power Applications in Sweden 31 Table 19.The market value,in SEK/MWh,and corresponding value factor for the major electricity generation technologies in Sweden from 2014 to 2021 in each of the price areas.Nuclear power only appears in SE3 since all active reactors during this time period is located in that region.Task 1 National Survey Report of PV Power Applications in Sweden 32 As the electricity mix in Sweden changes,(more wind and PV are expected to be built while two nuclear reactors at Ringhals 1 and Ringhals 2 was decommissioned as of 30 of December 2019 and 31st of December 2020)the value factor of the different power sources will change.E.g.in a recent study it was simulated that the value factor of PV will go from in general being above 1.0 to in general be below 1.0 if PV reaches above 5%of the total power production in the electricity mix 39.Household electricity costs consist of several components.The base is the Nord Pool Spot price of electricity.On top of that,energy tax,the cost of green electricity certificates,the variable grid charge,the fixed grid charge,VAT and sometimes an electricity surcharge and a fixed trading fee are added.Figure 14 illustrates the evolution of the average electricity price for the average end consumer over the years 34.In Figure 15,the variable part of the electricity price,which is what can be saved if the micro-producer replaces purchased electricity with self-generated PV electricity,is illustrated.Furthermore,the value of the excess electricity is shown for two base cases with the Nord Pool spot price as a base compensation offered by electricity trading utility companies(see section 7.1),energy compensation from the grid owner(see section 3.3.6),the tax credit system(see section 3.2.4)and with and without the green electricity certificate,since few PV owners are using the green electricity certificate system(see section 3.2.3).It is worth noting that some utility companies offer higher compensations than the Nord Pool spot price,so with all current possible revenue streams,both the self-consumed electricity and the excess electricity would have been higher than in the figure.Figure 14:Evolution of the average electricity price(in January)for private end consumer with a single-family house with electric heating.Task 1 National Survey Report of PV Power Applications in Sweden 33 Global solar radiation The total amount of solar radiation that hits a horizontal surface is called the global radiation.The global solar radiation thus consists of the direct radiation from the sun and the diffuse radiation from the rest of the sky and the ground.The solar radiation therefore depends on the weather,on the position on the globe and the season of the year.The distribution of annual average global radiation over Sweden is presented in Figure 16 40.Figure 15:The lowest available electricity price for a typical house with district heating in Stockholm with an annual electricity consumption of about 10 000 kWh/year,a 16-ampere fuse and Vattenfall as the grid owner in July 2021.Furthermore,the compensation for the excess electricity,with and without the extra remuneration from green electricity certificates.Figure 16:Average global solar radiation in Sweden in one year.Task 1 National Survey Report of PV Power Applications in Sweden 34 In the long-term variation of global radiation in Sweden a slight upward trend has been noted and the average solar radiation has increased by about 8%from the mid-1980s until 20052006,from about 900 kWh/m2 in 1985 to the current level of the recent years,which has varied between 9001 000 kWh/m.Recent years have seen some further increase.A similar trend is seen in large parts of Europe.In 2021 annual average accumulated global radiation reached 976.6 kWh/m 40.This is quite a normal value and is well below the historic record of 1050.6 kWh/m2 in 2018,as illustrated in Figure 17,when long periods of anticyclone weather(where barometric pressure is high)over Scandinavia gave very sunny weather during May and July.Production costs of PV electricity Levelized cost of electricity,LCOE,is a transparent measure of generating costs of different power plants and a widely used tool for comparing the costs of different power generating technologies.The definition of the LCOE can be expressed as the real fixed price of electricity that would exactly cover the sum of costs in terms of present value.To simplify,two assumptions are usually used.Firstly,that the real interest rate,r,used for discounting costs and revenues is constant during the lifetime of the power plant.Secondly,that the real electricity tariff is assumed not to change during the lifetime of the power plant and that all the produced electricity is sold at this tariff.With this as a starting point,along with some simplifications and additions based on characteristics of the PV technology,the following equation can be used to calculate the LCOE of PV electricity:=? ?&? &?(1)?(1 ?)? ?(1 ?)? ?(1 ?)? (1 ?)?(1)?(1 ?)?where t is the year number ranging from 0 to N,N the operational lifetime of the PV park,CAPEX0 the total capital expenditure of the system in year 0 expressed in SEK,O&Mf the fixed operation and maintenance cost in year t expressed in SEK,O&Mv the variable operation and maintenance cost per produced unit of energy in year t expressed in SEK/MWh,Yo the initial annual electricity production(yield)in the year when operation start expressed in MWh,Dg an annual degradation factor expressed in%,ReInv1 the first major reinvestment needed to reach expected lifetime in year x1 expressed in SEK,ReInv2 the second major reinvestment needed to reach expected lifetime in year x2 expressed in SEK,ResC and the residual cost of the system at the end of the lifetime expressed in SEK and WACCr the real weighted average cost of capital per annum in%.Figure 17:The annual average accumulated global solar radiation in Sweden between 1984 and 2021.Task 1 National Survey Report of PV Power Applications in Sweden 35 The LCOE of PV electricity very much depend on the size of the PV system and the type of actor owning the system,as the CAPEX and WACC parameters are the two most influential ones for the result.The typical LCOE of two type of PV systems in 2020 in Sweden,namely centralized ground mounted PV parks and decentralized roof mounted PV system for residential villa system of about 10 kWp,have been thoughtfully investigated in 41.In this report the interested can find information and discussions about the different parameters needed to calculate the LCOE and the end result.In this report the derived LCOE parameters and final LCOE of 41 is summarized in Table 20.Table 20:Average values for the parameters need to calculate LCOE and the final LCOE value for a 10 kWp residential system and a 5 MWp centralized PV park in Sweden 41.Parameter 10 kWp residential 5 MWp centralized Lifetime,N Years 30 33 Initial annual yield,Y kWh/kWp/a 849 969 System degradation rate,Dg%0.2 0.2 CAPEX SEK/kWp 16 496 7 232 Yearly fixed operation and maintenance,O&Mfix SEK/kWp/a 64 87 Variable operation and maintenance,O&Mvar SEK/kWh-0.04-0.02 Major reinvestment needed to reach expected lifetime in at t=x,ReInv SEK/kWp 2 300 582 Years after operation start when major reinvestment is needed,x Years 15 16.7 Residual cost of the system at the end of the lifetime SEK/kWp 0 19 Nominal weighted average cost of capital per annum,WACCnom%2 3.4 Real weighted average cost of capital per annum,WACCreal%0 1.4 Levelized cost of electricity 0.79 SEK/kWh 0.43 SEK/kWh As can be seen in Table 20 the average LCOE of a 10 kWp villa system was derived to be 0.79 SEK/kWh.This is with no subsidies whatsoever.If the direct capital subsidy is used,which gave a 20%rebate on the CAPEX in 2020,the LCOE becomes 0.6 SEK/kWh.These 0.6 SEK/kWh in production cost can be compared with the revenues of the self-consumed electricity and excess electricity in Figure 15 for assessments of profitability of small residential systems in Sweden in 2020.The LCOE of PV parks was concluded to be 0.43 SEK/kWh on average.Comparing this production cost with the market value of PV the last six years in Table 19,it can be concluded that profitability for a merchant business model would only be reached with spot prices at levels seen in 2018.Hence,for the 2020 market of centralized PV parks in Sweden it was still important that additional value to PV electricity is added through business models such as PPAs or cooperative owned PV parks.Task 1 National Survey Report of PV Power Applications in Sweden 36 3 POLICY FRAMEWORK This chapter describes the support policies aiming directly or indirectly to drive the development of PV.Direct support policies have a direct influence on PV development by incentivizing,simplifying or defining adequate policies.Indirect support policies change the regulatory environment in a way that can push PV development.Table 21:Summary of PV support measures.Category Residential Commercial Industrial Centralized Measures in 2020 On-going New On-going New On-going New Feed-in tariffs-Feed-in premium(above market price)Yes-(Yes)1-Capital subsidies Yes2-Yes2-Yes2-Green certificates Yes-Yes-Yes-Renewable portfolio standards with/without PV requirements-Income tax credits Yes3-(Yes)3-Self-consumption Yes-Yes-Net-metering-Net-billing-Collective self-consumption and virtual net-metering Yes-Commercial bank activities e.g.green mortgages promoting PV Yes Yes-Activities of electricity utility businesses Yes-Yes-Yes-Sustainable building requirements Yes-Yes-BIPV incentives-Guarantees of origin Yes-Yes-Yes-1 Only small commercial system can benefit from the tax credit system.2 Eligible for residential projects completed before June 30th,2021,and non-residential projects completed no later than September 30th,2021.3 Feed in premium is compensated as income tax credits.It is the same system.Task 1 National Survey Report of PV Power Applications in Sweden 37 National targets for PV There is no official target for future PV installation in Sweden.However,there exist a political agreement that sets a goal that Sweden will have a 100%renewable electricity system by 2040,while still planning to be a net exporter of power.The agreement is not a political stop date for nuclear,but to reach the goal,this implies phasing out the Swedish nuclear reactors that are coming of age and continuously pushing for new renewable energy production.Many of the introduced legislation changes in the coming years are expected to spring from this political agreement,and the Swedish PV market will most likely benefit from it.Direct support policies for PV installations 3.2.1 Direct capital subsidy for PV installations The direct capital subsidy was active between 2009 and 2021 in its latest form.Prior to that,there was a support for energy efficiency in public premises,where PV was included as eligible investments that could be applied for.In the beginning of 2009,there was a gap with no direct support for grid-connected PV and the installation rate went down in 2009,as can be seen in Table 4.However,a new subsidy program was introduced in mid-2009,now open for all actors 42.As presented in Table 22,it has since then been modified several times and the support level has been decreased as the market grew and prices fell.The program was extended several times and more money was allocated over time,as Figure 18 shows.Table 22:Summary of changes in the direct capital subsidy ordinance,support level and duration 43.Ordinance Start date Maximum coverage of the installation costs Initial stop date 2005:205 Energieffektivisering i offentliga lokaler 2005-04-14 70 08-12-31 2009:689 Std till solceller 2009-07-01 55%for large companies 60%all others 2011-12-31 2011:1027 ndring av 2009:689 2011-01-01 45 12-12-31 2012:971 ndring av 2009:689 2013-02-01 35 16-12-31 2014:1582 ndring av 2009:689 2015-01-01 30%companies 20%all other 2016-12-31 2016:900 ndring av 2009:689 2016-10-13 30%companies 20%all other 2019-12-31 2017:1300 ndring av 2009:689 2018-01-01 30 20-12-31 2019:192 ndring av 2009:689 2019-05-08 20 20-12-31 2020:489 ndring av 2009:689 2020-06-30 20 21-06-30 2020:1263 ndring av 2009:689 2021-01-15 10%companies 2021-09-30 Task 1 National Survey Report of PV Power Applications in Sweden 38 Since its introduction,the interest in the capital subsidy program has always been greater than the budget allocated.When the support was introduced the 1st of July 2009,there had been a gap since the 31st of December 2008 when support for public premises was ended,and many actors were prepared to invest.The 50 million SEK that were allocated for 2009 were therefore all applied for already in day 3 43.Ever since then,the amount of money applied for each year has been much higher than the allocated budget.Therefore,a long queue to get the subsidy has arisen as applications do not fall out of the line at the end of a year.When the situation was at its peak in 2016,average waiting time was on average 722 days,i.e.almost 2 years 43.The effect of the previous long waiting times led to that the program not solely stimulated,but also constituted an upper cap of the Swedish PV market.Until 2011 the new version of the subsidy covered 60%(55%for large companies)of the installation costs of PV systems,including both material and labour costs.For 2012 this was lowered to 45%to follow the decreasing system prices in Sweden and was lowered further in 2013 to 35%.From 2015 the level was decreased to maximum 30%for companies and 20%for other stakeholders.From January 1st,2018,the Swedish government increased the subsidy level for“others”to 30%so that all actors had the same level.From the 8th of May 2019 the level has been decreased to 20%for all following the decline of PV prices and increase in electricity prices for end consumers.In the last version of the statute,active in 2020,funds could only be applied for if the system costs were less than 37 000 SEK excluding VAT/kWp.Solar power/heat hybrid systems could cost up to 90 000 SEK plus VAT/kWp.If the total system costs exceed 1.2 million SEK,capital support was only granted for the part of the system cost that was less than this value.The 1.2 million SEK cap effectively lowered the subsidy level available for big PV systems.For example,if a large,centralized PV park of 10 MW at a cost of 70 million SEK received the 1.2 million SEK subsidy,it would only cover 1.7%of the total system cost.Figure 18:The annual budget of the direct capital subsidy program.Task 1 National Survey Report of PV Power Applications in Sweden 39 Table 23:Summary of the Swedish direct capital subsidy program 434445.Maximum coverage of the installation costs Upper support limit per PV system MSEK Maximum system cost per W SEK/W Budget MSEK Granted funds1 MSEK Disbursed funds MSEK Yearly PV capacity with support from the direct capital subsidy2 MWp Yearly total installed grid connected PV capacity MWp Total 2006 2008 70%Only for public building 5.0-138 138 138 2.96 2.83 2009 55%Companies 60%Others 2.0 75 212 28.43 0.05 0.20 0.52 2010 74.12 33.23 2.08 1.77 2011 70.93 81.02 3.12 3.45 2012 45%1.5 40 57.5 57.70 78.35 6.28 7,18 2013 35%1.3 37 210 108.61 73.16 11.54 1.95 2014 58.85 75.60 21.94 34 2015 30%Companies 20%Other 1.2 90 71.62 78.17 29.50 47.07 2016 316 213.39 138.79 50.93 57.27 2017 585.6 307.58 235.71 76.81 83.61 2018 3085 959.02 601.56 164.92 155.16 2019 2036 579.19 676.53 283.26 279.89 2020 2035 993.15 840.12 303.52 398.45 2021 20%3 520 128.04 633.13 159.78 497.77 Total-5485.10 3 788.63 3 545.40 1116.84 1587.17 1Extract from Boverkets database 2022-08.The granted resources are expected payments which may change if the circumstances change in individual cases.2The numbers are probably higher for several of the later years,as there is a large delay in the system due to the long queues.The numbers are retroactively updated in these publications.3No new applications are accepted in 2021.Since the start of the first program in 2006 until the end in 2021,3788.63 million SEK had been granted and 3 545.40 million SEK had been disbursed 45.This capital has supported a total installation of 1116.84 MWp so far.This means that the average subsidy for all PV systems since 2006 to 2021 has been 3.2 SEK/Wp,down from 8.9 SEK/Wp in 2016,5.3 SEK/Wp in 2017,4.6 SEK/Wp in 2018,3.7 SEK/Wp I 2019 and 3.3 SEK/Wp in 2020.Task 1 National Survey Report of PV Power Applications in Sweden 40 Listed in Table 23 is the annual installed PV capacity that has received support from the direct capital subsidy as compared to the statistics of yearly installed grid connect PV capacities.The statistic from direct capital subsidy program correlates well with the yearly installation statistics,except for 2009 and 2020.For 2009 it can be explained with a backlog of installations from the older direct capital subsidy program.The difference in the statistics for 2018 onwards can probably be related to the switch from sales statistics to collecting the statistics from the grid owner.A general explanation for the higher number of annual installed capacities compared to yearly PV capacity with support from the direct capital subsidy is that it was common to complete the installation of the PV system without first being granted the direct capital subsidy.This can be seen in the database of the program where there are several systems that have a registered system completion date that is earlier than the granted support date.The explanation for the incoherence of 2020 between the supported capacity and the total installed capacity is that the Swedish Government announced to close the capital subsidy system for new applications by July 7th,2020 in June of 2020 46.For private persons,this marked the end of a more than 10-year long support program for PV.Instead,the capital subsidy was replaced by a green tax deduction(see section 3.2.4).At the same time,they communicated that the completion period would be prolonged until the June 30th,2021,instead of the 31st of December 2020 47.This was a measure to meet the need for possible project time extensions due to the COVID-19 pandemic.For municipalities and companies,a total of SEK 260 million was set aside in the budget for the capital subsidy program in 2021,eligible for projects completed no later than September 30th,2021.The support level was 10%for these projects.After recognizing that 9 000 private individuals in the queue for approval of already installed projects would suffer from the sudden termination,SEK 260 million was added in the spring budget for projects eligible for support according to the abovementioned criteria 48.Adding to the applications from companies and municipalities,the applications from private individuals that meet the criteria above could not start to be processed earlier than 1 December 2021.The evaluation process is expected to continue well into 2022,explaining the apparent lag in disbursements.3.2.2 Direct capital subsidy program for renewable energy production in the agriculture industry In 2015 the Swedish Board of Agriculture(Jordbruksverket)introduced a direct capital subsidy for production of renewable energy.The subsidy can be applied for if a company has a business in agriculture,gardening or herding.The subsidy is given to support production of renewable energy for both self-consumption in agricultural activities and for sale.This may be in the form of biomass,wind,hydropower,geothermal or PV 49.The subsidy is granted for the purchase of materials,services of consultants to plan and carry out the investment,but not salary to employees or work done by the applicant.The level of the direct capital subsidy is 40%of the total expenses.The total project cost must exceed 100 000 SEK for the subsidy program to apply.The maximum amount of aid a company can receive is decided by the respective County Administration(Lnsstyrelse)or by the Sami Parliament(Sametinget)49.The support level of this direct capital subsidy is higher than in the previously active national direct capital subsidy program for PV installation.This can be motivated by the fact that many agricultural companies pay a lower level of the Swedish energy tax(see section 3.3.1),which makes the value of self-consumed electricity lower than for regular electricity consumers and therefore a PV system or any other renewable system is less profitable.A higher subsidy level increases the profitability of PV installations on barns and other agriculture buildings,which is a market segment with large potential 50.Until the end of 2021,the program has granted and disbursed support to 193 PV projects with a total capacity of 8 785 kW for a total amount of 33 542 362 SEK,in accordance with Table 24.On December 22,2020,the government decided on a proposal to alter the Swedish rural development program for 2014-2022 and submitted it to the European Commission.The reason for the decision was that the original rural development program for 2014-2020 was extended and new funds were added for 2021-2022.The European Commission subsequently approved on the proposed program changes 22 April 2021,marking the date of closing for new applications in the direct Task 1 National Survey Report of PV Power Applications in Sweden 41 capital subsidy program for renewable energy production,as it was not included in the prolonged plan.There are no plans to re-open the subsidy program,but support could possibly be applied for through a capital subsidy program for investments in agriculture,horticulture,and reindeer farming,as it includes support for energy efficiency measures.Table 24:Summary of the PV projects in the direct capital subsidy program for renewable production in the agriculture industry.The column Year Number of financed PV projects Disbursed funds SEK Installed PV capacity kWp Average cost per kWp 2016 5 1 026 096 203 13.6 2017 25 2 865 775 632 13.2 2018 31 5 180 719 1 109 12.3 2019 39 7 159 718 1 740 11.9 2020 61 12 930 949 3 193 11.7 2021 32 4 379 105 1 907 11.7 Total 193 33 542 362 8 785 12.1 3.2.3 The renewable electricity certificate system The basic principle of the renewable electricity certificate system is that producers of renewable electricity receive one certificate from the Government for each MWh produced.Meanwhile,certain electricity stakeholders are obliged to purchase certificates representing a specific share of the electricity they sell or use,the so-called quota obligation.The sale of certificates gives producers an extra income in addition to the revenues from electricity sales.Ultimately it is the electricity consumers that pay for the expansion of renewable electricity production as the cost of the certificates is a part of the end consumers electricity price.The energy sources that are entitled to receive certificates are wind power,some small hydro,some biofuels,solar,geothermal,wave and peat in power generation,and each production facility can receive renewable electricity certificates for a maximum of 15 years and limited to the end of year 2045.The quota-bound stakeholders are:electricity suppliers;electricity consumers who use electricity that they themselves produced if the amount used is more than 60 MWh per year and it has been produced in a plant with an installed capacity of more than 50 kWp;electricity consumers that have used electricity that they have imported or purchased on the Nordic power exchange;producers who produce electricity to a grid which is used without support of grid concession(ntkoncession),provided the electricity used amounts to more than 60 MWh per year and if the electricity is commercially supplied to consumers who use the electricity on the same grid;and electricity-intensive industries that have been registered by the Swedish Energy Agency(Energimyndigheten).The system was introduced in Sweden in 2003 to increase the use of renewable electricity.The goal of the certificate system at that time was to increase the annual electricity production from renewable energy sources by 17 TWh in 2016 compared to the levels of 2002.In 2012 Sweden and Norway joined forces and formed a joint certificate market.The objective then was that the electricity certificate system would increase the production of electricity from renewable sources by 26.4 TWh between 2012 and 2020 in Sweden and Norway combined.In the common market there is the opportunity to deal with both Swedish and Norwegian certificates to meet quotas 51.In March 2015,the Swedish and Norwegian governments made a new agreement that raised the common goal of 2 TWh to 28.4 TWh until 2020.This increase will only be funded by Swedish consumers 52.Furthermore,in the wake of the broad political agreement on the future Swedish electricity system(see section 3.1)it was decided in 2017 that the electricity certificate system will be extended to 2030 with another 18 TWh of renewable electricity.The prolongation involves a linear escalation of the 18 TWh with 2 TWh per year from 2022 to 2030.However,primarily due to the rapid deployment of wind power,the goal was reached already in March Task 1 National Survey Report of PV Power Applications in Sweden 42 2021 5354.To avoid prices of the certificates to drop down to zero due to over-establishment of renewable energy sources,which would be detrimental to early investors,a new change in the system was decided on by the Swedish government on November 11th,2020.The amendment stated that no power production constructed after 2021 would be eligible for certificates,and that the termination of the certificate system would be advanced to 2035 rather than the previous 2045 end date 55.In 2021,the average price for a certificate decreased drastically to 18.9 SEK/MWh from the average price of 69.6 SEK/MWh in 2020,120.7 SEK/MWh in 2019 56,and the quota obligation was decreased to 25.5%from the 26.3%that was set for 2020,which was in turn decreased from 30.5%in 2019 57.The established trend in the level of the quota duties is summarized in Figure 19 and the price trend in Figure 20.Figure 20:The price development of the renewable electricity certificates 56.Figure 21:The allocation of renewable electricity certificates to different technologies 56 Figure 19:The quota levels in the renewable electricity certificate system 52.Task 1 National Survey Report of PV Power Applications in Sweden 43 Until 2005 there were no PV systems in the electricity certificate system 58.However,as Table 25 show,the number of approved PV installations increased over the years and a majority of the approved plants in the certificate system are now PV systems.However,these systems only make up for a very small part of the total installed power and produced certificates.As can be seen in Figure 21,most of the certificates has gone to wind and biomass power,which produce more in the winter months.Following the amendment stating that no power production constructed after 2021 would be eligible for certificates,the Swedish Parliament agreed that owners of a certificate trading account will be charged an annual administrative fee of 200 SEK,starting July 1st,2021 59.This meant that for owners of smaller PV system,many of the villa system owners,it would no longer be profitable to be part of the renewable electricity certificate system.To avoid the account fee,PV system owners needed to close their electricity certificate account before May 31st,2021,and by doing that,the facilities approval for electricity certificates is revoked.This explains the drastic decrease in systems approved for electricity certificates in the end of 2021 and the decreased number of issued certificates to PV,in Table 25:Statistics about PV in the electricity certificate system The fact that only larger PV systems are still profiting from the electricity certificate system is clearly demonstrated in table 25,as the average system size more than doubled when 67%of the PV systems withdrew their participation in the program.255 206 certificates were issued to PV in 2021 50.This is only about 18%of the theoretical production of 1 586 MW 900 kWh/kW 1427.4 GWh from all grid-connected PV systems in Sweden.The reader should note that the calculation above is very simplified,especially since the whole cumulative grid-connected PV power at the end of 2021 was not up and running throughout the whole year.334.0 MW of PV power was accepted in the certificate system at the end of 2021 58,making it 21%of the total installed PV grid connected capacity.The steep decrease in Figure 22a and 25b can be explained by the low certificate price and the expiration of the program combined with the introduction of an administrative yearly fee for all PV system owners taking part in the system.Figure 23:Renewable electricity certificates issued to PV produced electricity 56.Figure 22:(a)Percentage of the installed PV power in Sweden that is approved for renewable electricity certificates.(b)Allocated certificates to PV electricity divided by the theoretical yearly PV production 56.Task 1 National Survey Report of PV Power Applications in Sweden 44 Table 25:Statistics about PV in the electricity certificate system 5658.To summarize,the renewable electricity certificate system in the present shape is being used by larger PV systems and parks but does not provide a significant support to increase smaller PV installations in Sweden in general.Number of approved PV systems in the certificate system at the end of each year Total approved solar power in the certificate system at the end of each year Average size of PV systems in the certificate system at the end of each year Number of issued certificates from solar cells per year Number of produced certificates eligible in kWh per installed power and year 2006 3 103 kW 34.3 kW 20 MWh 194 kWh/kW 2007 6 184 kW 30.6 kW 19 MWh 103 kWh/kW 2008 16 508 kW 31.7 kW 129 MWh 254 kWh/kW 2009 27 1 059 kW 39.2 kW 212 MWh 200 kWh/kW 2010 62 3 227 kW 52.1 kW 278 MWh 86 kWh/kW 2011 138 4 196 kW 30.4 kW 556 MWh 133 kWh/kW 2012 395 8 104 kW 20.5 kW 1 029 MWh 127 kWh/kW 2013 972 18 419 kW 19.0 kW 3 705 MWh 201 kWh/kW 2014 1 866 36 437 kW 19.5 kW 10 771 MWh 296 kWh/kW 2015 3 270 63 934 kW 19.6 kW 24 544 MWh 384 kWh/kW 2016 5 107 104 070 kW 20.4 kW 45 535 MWh 438 kWh/kW 2017 7 428 159 050 kW 21.4 kW 74 148 MWh 466 kWh/kW 2018 11 282 250 912 kW 22.2 kW 120 919 MWh 482 kWh/kW 2019 16 683 380 227 kW 22.8 kW 181 908 MWh 478 kWh/kW 2020 19 903 492 759 kW 24.8 kW 290 152 MWh 589 kWh/kW 2021 6 615 333 954 kW 50.5 kW 255 206 MWh 764 kWh/kW Task 1 National Survey Report of PV Power Applications in Sweden 45 3.2.4 Tax reduction for green technology As mentioned in paragraph 3.2.1 on the expiration of the direct capital subsidy for PV installations for private individuals in July 2020,the possibility of receiving compensation for residential PV installation will remain.A tax reduction program for green technology gained legal effect January 1st 2021 and replaced three existing support systems,namely the direct capital subsidy for PV installations(2009:689)42 for private persons,the subsidy for storage of self-produced electricity(2016:899)60 and the subsidy for private installations of charging points for electric vehicles(2017:1318)61.It is often referred to as the green deduction.Unlike the direct capital subsidy for PV installations,this is a support system that is managed and administered by the system suppliers and ultimately by the Swedish Tax Agency(Skatteverket).It is designed much like the ROT tax deduction,see 3.9.6.This means that instead of the system owner applying for the economic support and handling the process,the tax deduction reduce the price for the house owner already on the invoice,and the system suppliers will report the deducted amounts to the tax authorities 17.This system provides a percentual tax deduction for the hardware and installations costs of the three energy efficiency measures for private house owners.PV installations are offered a 15duction,while batteries and charging points for electric vehicles get a 50%tax deduction.This deduction can be made by private persons and can be used once per year and person.There is a maximum annual accepted amount of 50,000 SEK.In the case of all three measures being installed at once,which has both cost and installation benefits,there is a possibility that the maximum amount will be reached.Since PV have the lowest deduction level,the ROT-tax deduction might be applied to the PV installation while the charging point and the battery installation is included in the green deduction.To facilitate the administration for both companies and the Swedish Tax Agency,a level of 97 percent of the total investment cost has been approved as deductible costs for the green deduction 62.This means that the direct capital subsidy for private individuals of 20 percent of the total cost was replaced by a support of 15%of 97%total system cost,which equals 14.55%percent,by 2021.The advantage of the tax reduction for green technology,as compared to the former direct capital subsidy,is that there is no limiting budget,and thus no queue in this system as everyone who meets the requirements can take advantage of the tax deduction directly at the investment time.3.2.5 BIPV development measures There were no specific BIPV measures in Sweden in 2021.Self-consumption measures Self-consumption of PV electricity is allowed in Sweden and is the main business model that is driving the market.Several utilities offer various agreements for the excess electricity of a micro-producer.Since the spring of 2014 an ongoing debate about what tax rules that apply to micro-producers has been conducted,and consequently several changes in the different tax laws have occurred since then.Listed in this section are some specific tax laws that affect self-consumption and micro-producers.Task 1 National Survey Report of PV Power Applications in Sweden 46 Table 26:Summary of self-consumption regulations for small private PV systems in 2021.PV self-consumption 1 Right to self-consume Yes 2 Revenues from self-consumed PV Savings on the electricity bill 3 Charges to finance Transmission,Distribution grids&Renewable Levies None Excess PV electricity 4 Revenues from excess PV electricity injected into the grid Various offers from utilities 0.6 SEK/kWh Feed in compensation from the grid owner 5 Maximum timeframe for compensation of fluxes One year 6 Geographical compensation(virtual self-consumption or metering)On site only Other characteristics 7 Regulatory scheme duration Subject to annual revision 8 Third party ownership accepted Yes 9 Grid codes and/or additional taxes/fees impacting the revenues of the prosumer Grid codes requirements 10 Regulations on enablers of self-consumption(storage,DSM)Tax reduction for green technology 11 PV system size limitations 1.Below 43.5 kWp and 63 A,and net-consumer on yearly basis,for free feed-in subscription towards the grid owner.2.Below 100 A and maximum 30 MWh/year for the tax credit.3.Below 500 kWp for no energy tax on self-consumed electricity.12 Electricity system limitations None 13 Additional features Feed in compensation from the grid owner 3.3.1 General taxes on electricity In Sweden,taxes and fees are charged at both the production of electricity and at the consumption of electricity.Taxes that are associated with the production of electricity are property taxes(see section 0),taxes on fuels and taxes on emissions to the atmosphere.The taxes associated with electricity consumption are mainly the energy tax on electricity and the value added tax(VAT).The manufacturing and agriculture industry paid 0.006 SEK/kWh in energy tax in 2020.The Energy tax rate has been increased in steps for residential customers the last couple of years after the Swedish Energy Commission(see section 3.1)decided to remove the specific tax on nuclear and finance that with a higher energy tax 63.The Task 1 National Survey Report of PV Power Applications in Sweden 47 latest increase occurred the first of January 2021 when the energy tax was increased from 0.353 SEK/kWh(excluding VAT)to 0.356 SEK/kWh.The exception is some municipalities in northern Sweden where the energy tax now is 0.260 SEK/kWh(excluding VAT)64.Additionally,a VAT of 25%is applied on top of the energy tax.Altogether,roughly 40%of the total consumer electricity price(including grid fees)was taxes,VAT and certificates in 2021,see Figure 14.3.3.2 Energy tax on self-consumption There has been an ongoing modernization of the Swedish tax rules when it comes to taxation on self-consumed electricity.The current rules,which were implemented July 1st 2021,can be can be summarized as 65:A solar electricity producer that owns one or more PV systems whose total power amounts to less than 500 kWp does not have to pay any energy tax for the self-consumed electricity consumed within the same premises as where the PV systems is installed.A solar producer that owns several PV systems,which total power amounts to 500 kWp or more,but where all the individual PV systems are smaller than 500 kWp,pays an energy tax of 0.005 SEK/kWh on the self-consumed electricity used within the same premises as where the PV systems is installed.A solar producer that owns a PV system larger than 500 kWp pays the normal energy tax of 0.356 SEK/kWh on the self-consumed electricity used within the same premises as where the PV systems is installed,but 0.005 SEK/kWh in energy tax for the self-consumed electricity from the other systems if they are less than 500 kWp.The current legislation has the effect that few PV systems over 500 kWp are built for self-consumption in Sweden.The full energy tax on self-consumed electricity limits the profitability for those systems.This leads to that the technical potential of PV systems on large industrial properties currently is unexploited.When it comes to systems smaller than 500 kWp the main economic obstacle for real estate owners that plan to build several small PV systems has been removed with this legislation.However,the administrative burden of measuring and reporting the self-consumed electricity if the total power limit of 500 kWp is exceeded remains.However,it is only since July 1st,2021,that the limit has been 500 kWp.Before that,PV system owners had to pay energy tax on self-consumed electricity produced by systems larger than 255 kWp.The former limit actively hindered the market development in the industrial and large commercial segments.The limit-increase was welcomed by the Swedish industry,even though many advocates for the limit be completely abolished,amongst them the Swedish solar trade association 66.Another positive prospect in this matter is that the government has declared their purpose to remove the 0.006 SEK/kWh energy tax for real estate owners that own several small systems,and thereby remove the administrative barrier,by sending in a state aid notification to the EU Commission 67.3.3.3 Deduction of the VAT for the PV system Sweden has a non-deductible VAT for permanent residences 68.However,homeowners associations or property owners are granted the right of deduction for VAT for a roof-mounted PV systems as long as the acquisition is attributable to the associations or companys VAT liable sales of surplus electricity.This position,published in November 2020 by the Swedish Tax Agency,replaced the former position from 1 March 2018 69,as it was legally tried in case 6174-18 of the Swedish Supreme Administrative Court 70.Before that,only if all generated electricity was delivered to an electricity supplier,and the PV system was therefore exclusively used in economic activity,deduction of the VAT for the PV system was allowed.Worth noting is that it was crucial for the case that a roof mounted PV system is not a part of the permanent residence.Consequently,this does not necessary apply to building-integrated PV.To summarize,a homeowners association or property owner may deduct VAT on the investment,operation and preparation of a PV system corresponding to the proportion of electricity that will be sold to the electricity grid 71.Task 1 National Survey Report of PV Power Applications in Sweden 48 3.3.4 VAT on the revenues of the excess electricity A PV system owner that sells the excess electricity will receive compensation from the electricity trading utility company and from the grid owner(see section 0).If the total annual renumeration from the property(including other revenue streams than selling excess electricity)exceeds 30 000 SEK,excluding VAT,the house owner needs to register for VAT and handle the VAT streams between the utilities that buy the excess electricity and the tax agency(see Figure 24).If the total annual sales do not exceed 30 000 SEK the PV system owner are exempted from VAT 72.At a reimbursement from a utility company of 0.5 SEK/kWh,60 000 kWh can be sold per year before reaching the limit.At a self-consumption rate of 50%it corresponds to a PV system of a size of about 120 kWp.Hence,as a general rule of thumb,the 30 000 SEK limit corresponds to PV systems of 100200 kWp,which would be an exceptionally large PV system size for a regular homeowner.The limit of 30 000 SEK was implemented the 1st of January 2017 and is an improvement for the Swedish PV market.In 2016,a private homeowner needed to go through the administration of registering for VAT and reporting the VAT to the Government.The new set of rules makes it much easier for a household to invest in PV in Sweden.Furthermore,it has also reduced the administration for the tax agency as it doesnt need to handle the registration of thousands of private PV owners.As the Government is not losing any tax income,as illustrated in Figure 24,it is a win-win situation for all parties as compared to before the 1st of January 2017.3.3.5 Tax credit for micro-producers of renewable electricity The 1st of January 2015,an amendment to the Income Tax Act was introduced 73.The tax credit is 0.60 SEK/kWh for renewable electricity fed into the grid.The right to receive the tax credit applies to both physical and legal persons.To be entitled to receive the tax credit the PV system owner must:feed in the excess electricity to the grid at the same connection point as where the electricity is received,not have a fuse that exceed 100 amperes at the connection point,notify the grid owner that renewable electricity is produced at the connection point.The basis for the tax reduction is the number of kWh that are fed into the grid at the connection point within a calendar year.However,the maximum number of kWh for which a system owner can receive the tax credit may not exceed the number of kWh bought within the same year.In addition,one is only obliged to a maximum of 30 000 kWh per year.The grid owner will file the measurement on how much electricity that has been fed into and out of the connection point in one year and the data will be sent to the Swedish Tax Agency(Skatteverket).The tax reduction will then be included in the income tax return information,which should be submitted to the Swedish Tax Agency in May the following year.The tax credit of 0.60 SEK/kWh is received on top of other compensations for the excess electricity,such as compensation offered by electricity retailer utility companies(see section 7.1),the grid benefit compensation(see Figure 24:Illustration of the revenue and VAT streams for the excess electricity for a private PV owner before and after the 1st of January 2017.Task 1 National Survey Report of PV Power Applications in Sweden 49 section 3.3.6)and revenues for selling renewable electricity certificates and guarantees of origins(see section 3.2.3 and 3.3.6).The tax credit system can be seen as a feed-in premium for the excess electricity.However,unlike the case in other European countries,the Swedish tax credit system does not offer a guaranteed revenue over a specific period.This means that the extra income that a micro-producer receives from the tax credit system when feeding electricity to the grid can be withdrawn,increased,or decreased by a political decision.According to the Swedish Tax Agency 76 370 micro-producers of renewable electricity received a total 385 556 429 SEK for excess electricity fed into the grid in 2021.This amount is based on 385 556 MWh of excess electricity fed into the low voltage grid by micro producers,reported by the grid operators to the Swedish Tax Agency.The average production fed into the grid per micro-producer with a capacity of less 100 amperes was thereby 5 049 kWh in 2021,as summarized in Table 27.Table 27:Statistics about tax credit for micro-producers of renewable electricity.Year Number of micro-producers Paid funds each year SEK The basis(excess electricity)of the tax reduction kWh Average electricity fed into the grid per micro-producer kWh/micro-producer 2015 5 391 11 421 003 19 035 005 3 531 2016 8 161 19 545 400 32 575 667 3 992 2017 12 138 30 068 341 50 113 902 4 129 2018 20 350 57 098 546 95 164 243 4 676 2019 40 442 102 164 634 170 274 390 4 210 2020 56 188 183 883 925 306 473 209 5 454 2021 76 370 231 333 857 385 556 429 5 049 Total-635 515 706 1 059 192 845-These numbers contain,not only PV,but all small-scale renewable production.Historically,the share of technologies of systems with a production capacity below 69 kW(which corresponds to the 100-ampere limit of the tax reduction)in the green electricity certificate system has been studied to get an estimation of the share of PV in the tax reduction.This methodology generated a rough estimation since both the total produced electricity in a year and the self-consumption ratio differ between the different renewable energy technologies and between all the individual production facilities.However,as explained in section 3.2.3,few incentives remain for residential PV system owners to be registered for green certificates in 2021,which eliminates the possibility for that estimation.Both in 2020 and 2019,98%of the capacity of systems below 69 kW were PV in the green electricity certificate system,and the corresponding number for 2018 was 96%.There is therefore reason to believe that the share of PV would have been around that level also in 2021,if were not for the changes in the system.A level of 98%PV among the micro-produced electricity would result in 622 805 392 SEK has been paid to PV system owners through the tax credit for micro-production system until the end of 2021.3.3.6 Grid benefit compensation A micro-producer is entitled to reimbursement from the grid owner for the electricity that is fed into the grid.The compensation shall correspond to the value of the energy loss reduction in the grid that the excess electricity necessitates 74.The compensation varies between different grid owners and grid areas and is typically between 0.02 and 0.10 SEK/kWh.Task 1 National Survey Report of PV Power Applications in Sweden 50 3.3.7 Guarantees of origin Guarantees of origin(GOs),were introduced in Sweden on December 1st in 2010,and are electronic documents that guarantee the origin of the electricity.Electricity producers receive a guarantee from the Government for each MWh of electricity.The electricity producer can then sell GOs on an open market.The buyer is usually a utility company who wants to sell that specific type of electricity.Utilities buy guarantees of origin corresponding to the amount of electricity they would like to sell.GOs are issued for all types of power generation and applying for guarantees of origin is still voluntary.When the electricity supplier has bought the GOs and sold electricity to a customer,the GOs are nullified.The nullification ensures that the amount of electricity sold from a specific source is equivalent to the amount of electricity produced from that source.Table 28:Statistics about solar guarantees of origin 56.Year Solar GOs issued in Sweden Solar GOs transferred within Sweden Solar GOs imported to Sweden Solar GOs exported from Sweden Solar GOs nullified in Sweden Solar GOs that expired in Sweden 2011 194 96-0 0 2012 378 173-104 90 2013 2 337 1 373-324 294 2014 7 846 4 563-1 510 972 2015 18 953 11 301-5 314 2 830 2016 36 702 22 183-11 966 9 454 2017 58 806 65 936 1 481 437 69 279 96 442 16 146 2018 111 143 1 306 626 568 832 1 467 852 317 189 29 499 2019 166 670 894 568 1 527 014 526 292 976 716 51 935 2020 272 646 943 181 1 383 593 373 746 927 148 68 924 2021 316 475 518 255 969 157 201 969 952 894 111 143 A utility company that wants to sell,for example,electricity from PV can do so in two ways.Either by nullify gua

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IEA PVPS：2021年澳大利亚太阳能光伏应用研究报告（英文版）（46页）.pdf

National Survey Report of PV Power Applications in AUSTRALIA 2021 PVPS Task 1 Strategic PV Analysis and Outreach Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY What is IEA PVPS TCP?The International Energy Agency(IEA),founded in 1974,is an autonomous body within the framework of the Organization for Economic Cooperation and Development(OECD).The IEA carries out a comprehensive programme of energy cooperation among its 30 member countries and with the participation of the European Commission.The IEA Photovoltaic Power Systems Programme(IEA PVPS)is one of the collaborative research and development agreements(technology collaboration programmes)within the IEA and was established in 1993.The mission of the programme is to“enhance the international collaborative efforts which facilitate the role of photovoltaic solar energy as a cornerstone in the transition to sustainable energy systems.”In order to achieve this,the Programmes participants have undertaken a variety of joint research projects in PV power systems applications.The overall programme is headed by an Executive Committee,comprised of one delegate from each country or organisation member,which designates distinct Tasks,that may be research projects or activity areas.This report has been prepared under Task 1,which deals with market and industry analysis,strategic research and facilitates the exchange and dissemination of information arising from the overall IEA PVPS Programme.The IEA PVPS participating countries are Australia,Austria,Belgium,Canada,Chile,China,Denmark,Finland,France,Germany,Israel,Italy,Japan,Korea,Malaysia,Mexico,Morocco,the Netherlands,Norway,Portugal,South Africa,Spain,Sweden,Switzerland,Thailand,Turkey,and the United States of America.The European Commission,Solar Power Europe,the Smart Electric Power Alliance(SEPA),the Solar Energy Industries Association and the Copper Alliance are also members.Visit us at:www.iea-pvps.org What is IEA PVPS Task 1?The objective of Task 1 of the IEA Photovoltaic Power Systems Programme is to promote and facilitate the exchange and dissemination of information on the technical,economic,environmental and social aspects of PV power systems.Task 1 activities support the broader PVPS objectives:to contribute to cost reduction of PV power applications,to increase awareness of the potential and value of PV power systems,to foster the removal of both technical and non-technical barriers and to enhance technology co-operation.An important deliverable of Task 1 is the annual“Trends in photovoltaic applications”report.In parallel,National Survey Reports are produced annually by each Task 1 participant.This document is the country National Survey Report for the year 2018.Information from this document will be used as input to the annual Trends in photovoltaic applications report.Authors Main Content:RJ Egan,L Koschier Data:N Haghdadi,M Deghani,R Passey,A Bruce,Australian PV Institute(APVI)Analysis:RJ Egan,O Ashby Editing:O Ashby DISCLAIMER The IEA PVPS TCP is organised under the auspices of the International Energy Agency(IEA)but is functionally and legally autonomous.Views,findings and publications of the IEA PVPS TCP do not necessarily represent the views or policies of the IEA Secretariat or its individual member countries This Project received funding from the Australian Renewable Energy Agency(ARENA).The views expressed herein are not necessarily the views of the Australian Government,and the Australian Government does not accept responsibility for any information or advice contained herein.COVER PICTURE 35 MW Brigalow solar farm in Queensland.Image provided by Ideematec,Sentient Impact Group and GLSG Solar Australia.COPYRIGHT This report is copyright of the Australian PV Institute.The information contained therein may freely be used but all such use should cite the source as“2021 PV in Australia Report,APVI”.Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 2 TABLE OF CONTENTS Acknowledgements.4 EXECUTIVE SUMMARY.5 1 Installation Data.9 Applications for photovoltaics.9 Total photovoltaic power installed.9 Key enablers of PV development.13 2 Competitiveness of pv electricity.14 Module prices.14 System prices.15 Cost breakdown of PV installations.17 Additional country information.18 3 Policy Framework.19 National targets for PV.20 Direct support policies for PV installations.20 Self-consumption measures.26 Tenders,auctions&similar schemes.28 Other utility-scale measures including floating and agricultural PV.28 Retroactive measures applied to PV.29 Indirect policy issues.29 Financing and cost of support measures.31 4 Industry.32 Production of feedstocks,ingots and wafers(crystalline silicon industry).32 Production of photovoltaic cells and modules(including TF and CPV).32 Manufacturers and suppliers of other components.33 5 Pv In the Economy.36 Labour places.37 Research Development and Innovation.37 Business value.37 6 Interest From Electricity Stakeholders.38 Structure of the electricity system.38 Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 3 Interest from electricity utility businesses.39 Interest from municipalities and local governments.40 States and Territories.41 7 Highlights and Prospects.42 Highlights.42 Prospects.42 Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 4 ACKNOWLEDGEMENTS COPYRIGHT:This report is copyright of the Australian PV Institute.The information contained therein may freely be used but all such use should cite the source as“PV in Australia Report 2021,APVI,July 2022”.This report is prepared by the Australian PV Institute(APVI)in its role representing Australia on the International Energy Agency(IEA)in the IEA PV Power Systems(PVPS)Technical Collaboration Platform.The APVI is supported in this by ARENA and by its members who are active in the IEA PVPS program of work.The Institute receives funding from the Australian Renewable Energy Agency(ARENA:www.arena.gov.au)to assist with the costs of IEA PVPS Programme membership,Task activities and preparation of this report.The IEA programme is headed by an Executive Committee composed of representatives from each participating country or organisation.The Australian Executive Committee member is Renate Egan(ACAP)and the alternate member is Olivia Coldrey(Sustainable Energy for All).Australian participation in the IEA PVPS tasks is managed by the APVI.The management of individual tasks(research projects/activity areas)is the responsibility of Operating Agents,with participating countries providing Task Leaders and Experts.In Australia,tasks are represented by Australian Experts including;Task 1 Communications,Strategy and Outreach.Expert is Linda Koschier Task 12 Sustainability.Co-Operating Agent is Jose Bilbao(UNSW),Expert is Rong Deng(UNSW)Task 13 Performance and Reliability.Expert is David Parveliet(Murdoch)Task 14 High Penetration PV.Expert is Iain Macgill(UNSW)Task 15 Building Integrated PV.Expert is Rebecca Yang(RMIT)Task 16 Solar Resource for High Penetration and Large Scale Applications.Expert is John Boland(UniSA)Task 17 PV and Transport.Experts are Julie Macdonald(ITPower)and N Ekins-Daukes(UNSW)Information about the active and completed tasks can be found on the IEA-PVPS website.www.iea-pvps.org THE AUSTRALIAN PV INSTITUTE(APVI)The objective of the APVI is to support the increased development and use of PV via research,analysis and information.The APVI provides;up to date information and analysis of PV developments in Australia and around the world,as well as issues arising,a network of PV industry,government and researchers who undertake local and international PV projects,with associated shared knowledge and understanding;Australian input to PV guidelines and standards development;and management of Australian participation in the IEA SHC and PVPS Programme.More information on the APVI can be found:www.apvi.org.au Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 5 EXECUTIVE SUMMARY The Australian market for grid-connected photovoltaics(PV)continued to grow through 2021,in both centralised(utility scale)and decentralised(rooftop)installs,with a new benchmark of 4.9 GW of new solar registered.Additional annual rooftop installs on residential,commercial and industrial roofs exceeded 3 GW,with 1.7 GW on residential roofs and 1.3 GW on commercial and industrial roofs,shown in Figure 1.New centralised,utility scale solar connections remain stable at around 1.7 GW annual installs,off a high of 2.4 GW in 2019.The total installed capacity at the end of 2021 reached 26 GW,meaning Australia has a remarkable,and world leading installation rate of over 1 kW of solar per person,ahead of the Netherlands and Germany who both have less than 800 W per person.With continued growth in 2022,Australia looks set to maintain this lead.Figure 1.Annual PV installations by sector By the end of 2021,the average penetration of solar on free-standing homes was 33%,and the average installation size exceeded 8.8 kW.In the ten years,since 2011,the installation rate has grown nearly five-fold,from just under 1 GW/year to 4.9 GW/year in 2021.In 2011,Australia had no centralised plant greater than 1 GW,and in just ten years,by the end of 2021,Australia had close to 9 GW of utility scale solar connected.Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 6 Historical trends in total installed capacity are shown in Figure 2,where a few highlights can be seen:With 16.5 GW on rooftops,Australia has seen a greater than ten-fold increase over ten years,from a total installed capacity of 1.3 GW in 2011.The total installed capacity across all sectors has more than doubled to 26 GW in three years from 11.5 GW in 2018.More solar was installed in the single year 2021(4.9 GW)than the sum of all total installed to the end of 2014(4.1 GW)Figure 2.Cumulative Installs in Australia by Grid-Connection The Australian market is very different to most world markets as it has been dominated by rooftop PV.The demand for rooftop solar PV has kept Australia in the top ten markets for photovoltaics by annual installs and total installed capacity for over ten years,a remarkable outcome for a country of only 26 million people.At the end of 2021,Australia saw:The total number of rooftop installations exceed 3 million.This means over 33%of free-standing households across the nation are now powered with a PV system.In the states of Queensland and South Australia,achieve an average of close to 40%of free-standing homes being powered by solar.A significant number of localities now have densities of rooftop solar over 50%.Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 7 The percentage of residential rooftop dwellings is shown by state in Figure 3.Highlighting an average penetration in the states of Queensland and South Australia in excess of 40%,with populations of 5.2 million and 1.8 million respectively.Figure 3.Percentage of residential dwellings with a PV system by state/territory In 2021,the average size of rooftop installation(100 kW)was 8.8 kW,up from 8.0 kW in 2020.The average PV system size continues to grow steadily as the size of residential systems increases,and as a growing number of businesses purchase PV.Technology and manufacturing improvements led to a steep drop in prices between 2007 and 2013.Prices then continued to drop,but less dramatically.In 2021,however,compounding factors of supply chain challenges associated with COVID-19 and growing demand has led to the first significant price increase in years.The evidence is that the situation will not improve over 2022.Despite this,demand remained high over 2021.In contrast to other areas of global leadership,very little building-integrated PV(BIPV)was added in 2021,and no new Floatovoltaics have been recorded beyond the single 100 kW installation in 2017.In late 2021,Australia moved from a 30-minute settlement period in energy market transactions to a 5-minute settlement period,providing better returns for battery investment.We also recently saw the first wholesale demand response mechanism on the national electricity market(NEM).Australias long-standing off-grid market continues to be important,particularly in residential applications where PV continues to displace diesel in hybrid power systems and in industrial and agricultural applications including power systems for telecommunications,signalling,water pumping and lighting.In Western Australia(WA),microgrids and stand-alone power systems(SAPS)are being tested for wider implementation to better serve remote communities by taking advantage of new renewable energy technologies.These systems make use of PV technology along with energy storage to provide reliable renewable power generation to isolated and fringe-of-grid communities,particularly those in areas prone to extreme weather events.Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 8 Significant markets also exist for fuel saving and peak load reduction on diesel grid systems in communities,mine sites and tourist locations.There is also a reasonably significant market for recreational PV applications for caravans,boats and off-road vehicles.Looking to the future,Australias rooftop market is expected to remain strong through to 2030,with increasing interest due to price pressures related to supply of coal and gas emerging in 2022.For large scale solar,there is a firm pipeline of projects,supported by state-based initiatives,with all Australian states now having zero-carbon targets by 2050 and plans for Renewable Energy Zones,designed to coordinate transmission,generation,firming and storage projects to deliver efficient,timely and coordinated investment in renewable energy.A change of government in Australia in mid-2022 has resulted in an acceleration in commitments to net-zero emissions that is expected to result in increased investor confidence and growth in the solar PV sector.Some large prospective projects,in support of energy exports,green-hydrogen and green-minerals processing could result in a significant boost,with each of the prospective projects positioned to add 4 GW per year in demand if actioned.Figure 4.35 MW Brigalow solar farm in Queensland.Image provided by Ideematec,Sentient Impact Group and GLSG Solar Australia.Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 9 1 INSTALLATION DATA The PV power systems market is defined as the market of all nationally installed(terrestrial)PV applications with a PV capacity of 40W or more.A PV system consists of modules,inverters,batteries and all installation and control components for modules,inverters and batteries.Other applications such as small mobile devices are not considered in this report.For the purposes of this report,PV installations are included in these statistics if the PV modules were installed and connected to the grid between 1 January and 31 December 2021 although commissioning may have taken place at a later date.Applications for photovoltaics Unlike other markets,Australian solar installations are dominated by rooftop demand,supported by a government mechanism that delivers an upfront capital cost reduction.Over 30%of Australian free-standing homes are now powered by solar,and over 12.5%of electricity demand,nationally,is met by solar energy.The commercial and industrial rooftop market has shown consistent growth.Due to this continuing demand for rooftop solar,Australia has remained in the top ten markets world-wide for photovoltaics by annual installs and total installed capacity for over ten years,a remarkable outcome for a country of only 26 million people.The utility scale solar market grew with the benefit of incentives until 2020.With the removal of these incentives,the utility scale market initially contracted but has started to recover.In Australia,there are only small activities that target BIPV,floating PV,AgriPV and VIPV,and they typically only operate at research or demonstration scale.Total photovoltaic power installed PV connected to the grid in Australia has benefitted from incentives and support from national government through a Renewable Energy Target(RET).The RET is delivered through the Small-scale Renewable Energy Scheme(SRES)for systems up to 100 kW and will continue to 2030.The Large-Scale Renewable Energy Target(LRET)for systems over 100 kW was met in 2020.Data is collected by the Federal Governments Clean Energy Regulator.Small-scale systems create trading certificates(STCs)which are redeemable as an upfront capital subsidy.Large systems produce generation certificates(LGCs)are redeemable annually based on energy generated.These incentives come with a reporting obligation and are categorised into small(100 kW).Within these categories residential solar is typically considered 0-10 kW while commercial and industrial installations are rated at 10-100 kW.Above 100 kW there is a mix of commercial,industrial,and ground mount up to 5 MW;installations above 5 MW are usually ground mounted.The Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 10 STC system will run to 2030,with an annual reduction in the support provided.The LGC system is closed,with certificates to continue to be redeemed and traded for some time.Table 1:Annual PV power installed during calendar year 2021 Installed PV capacity in 2021 MW AC or DC Decentralized 3201 DC Centralized 1713 DC Off-grid 30 DC Total 4944 DC Table 2:PV power installed during calendar year 2021 Installed PV capacity MW Installed PV capacity MW AC or DC Grid-connected BAPV Residential 3201 1737 DC Commercial 1355 DC Industrial 109 DC BIPV Residential Commercial Industrial Utility-scale Ground-mounted 1713 1713 DC Floating Agricultural Off-grid Residential 29.6 24.2 DC Other Hybrid systems Total 4943.6 DC Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 11 Table 3:Data collection process If data are reported in AC,please mention a conversion coefficient to estimate DC installations.Utility-scale capacity is often reported in AC terms,and occasionally in DC terms.Where the DC capacity is unknown,we have assumed a 1.27x DC:AC ratio based on an average from those plants that report the ratio.The average is available for more than 50%of new plant.Is the collection process done by an official body or a private company/Association?PV data for the tables above are derived from an official process from the Renewable Energy Certificate(REC)Registry of the Australian Governments Clean Energy Regulator.The data is cleaned and published by the APVI.www.apvi.org.au Link to official statistics(if this exists)Large Scale:http:/www.cleanenergyregulator.gov.au/RET/About-the-Renewable-Energy-Target/Large-scale-Renewable-Energy-Target-market-data/large-scale-renewable-energy-target-supply-data Small Scale:http:/www.cleanenergyregulator.gov.au/DocumentAssets/Pages/Postcode-data-for-small-scale-installations-SGU-Solar.aspx Figure 5.Rooftop mounted PV system,5.4 kW capacity installed on a new house in suburban Australia.Credit:Tindo Solar.Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 12 Table 4:The cumulative installed PV power in 4 sub-markets Year Off-grid MW(Including large hybrids)Grid-connected distributed MW(BAPV,BIPV)Grid-connected centralized MW(Ground,floating,agricultural,etc)Total MW 1992 7.3 0 0 7.3 1993 8.9 0 0 8.9 1994 10.7 0 0 10.7 1995 12.7 0 0 12.7 1996 15.6 0.1 0 15.7 1997 18.3 0.2 0.2 18.7 1998 21.2 0.9 0.5 22.6 1999 23.3 1.5 0.5 25.3 2000 26.3 2.4 0.5 29.2 2001 30.2 2.8 0.5 33.5 2002 35.2 3.4 0.5 39.1 2003 40.3 4.6 0.7 45.6 2004 46.2 5.4 0.7 52.3 2005 53 6.9 0.8 60.7 2006 60.5 9 0.8 70.3 2007 66.4 15 1 82.4 2008 73.3 29.9 1.3 105 2009 83.9 101 2.5 187 2010 87.8 479 3.8 571 2011 101 1268 7.4 1376 2012 118 2276 21.5 2416 2013 132 3070 24 3226 2014 148 3875 68.5 4092 2015 173 4580 356 5109 2016 210 5329 446 5985 2017 247 6145 740 7132 2018 284 8030 3272 11 586 2019 303 10 395 5701 16 399 2020 330 13 476 7285 21 091 2021 360 16 677 8998 26 035*small changes to historical values reflect changes in the source data.Installs can be reported as much as a year later.Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 13 Table 5:Other PV market information 2021 Number of PV systems in operation in your country Residential 3 066 748 2 798 782 Commercial 266 299 Industrial 1531 Utility-scale 136 Off-grid na Decommissioned PV systems during the year MW Residential 1 1 Commercial Industrial Utility-scale Off-grid Repowered PV systems during the year MW Residential 0 Commercial Industrial Utility-scale Off-grid Table 6:PV power and the broader national energy market 2020 2021 Total electricity demand TWh 265.2 267.4 Estimated total PV electricity production(including self-consumption)GWh 29.5 36 Key enablers of PV development Table 7:Information on key enablers.Comment Annual Value Total Value Source Decentralized storage systems Registered grid connected batteries.12 977 sites NA Clean energy regulator data.The industry thinks its nearly three times larger than the recorded value Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 14 2 COMPETITIVENESS OF PV ELECTRICITY Module prices Module price trends(excluding sales tax)by year shown in Table 8.All prices listed are in AUD/W.Module prices are average prices inferred from system prices.The minimum price quoted achieved in 2021 was from imported panels.Module prices have increased due to supply chain challenges and increased shipping costs.Table 8:Typical module prices Year Lowest price of a standard module crystalline silicon$/W Highest price of a standard module crystalline silicon$/W Typical price of a standard module crystalline silicon$/W 2005 8 2006 7.5 8.5 2007 7 8 2008 5 8 2009 3 6 2010 2 3.2 2011 1.2 2.1 2012 0.9 1.5 2013 0.5 0.75 2014 0.62 0.8 2015 0.62 0.8 2016 0.57 0.78 2017 0.53 1.35 0.67 2018 0.35 1.15 0.55 2019 0.35 1.15 0.52 2020 0.3 1.15 0.47 2021 0.3 1.15 0.55 Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 15 System prices The figures reported in the table below are an average price for a rooftop installation of 7 kW excluding subsidies which reduce the system cost by a further 40-50c/W,depending on insolation,averaged here at 0.45c/W Residential and commercial prices are based on a dataset provided by PV lead generator Solar Choice.Small-scale systems are eligible for an up-front subsidy that is excluded in the table below.Prices quoted are also exclusive of sales tax(GST).Pricing is all inclusive for rooftop solar costs including installation,connection and registration.The utility-scale solar market grew rapidly between 2014 and 2020 with a steep decline in pricing.LGC system sizes average prices are not published as they are site dependent and commercial in confidence.The prices for systems connected in 2021 were negotiated some years ago.Table 9:Turnkey PV system prices of different typical PV systems Category/Size Typical applications and brief details Current prices AUD/W Residential BAPV 5-10 kW Grid-connected,roof-mounted,distributed PV systems installed to produce electricity to grid-connected households.Typically roof-mounted systems on villas and single-family homes.1.55 Small commercial BAPV 10-100 kW Grid-connected,roof-mounted,distributed PV systems installed to produce electricity to grid-connected commercial buildings,such as public buildings,multi-family houses,agriculture barns,grocery stores etc.1.60 Large commercial BAPV 100-250 kW Grid-connected,roof-mounted,distributed PV systems installed to produce electricity to grid-connected large commercial buildings,such as public buildings,multi-family houses,agriculture barns,grocery stores etc.1.60 Industrial BAPV 250 kW Grid-connected,roof-mounted,distributed PV systems installed to produce electricity to grid-connected industrial buildings,warehouses,etc.1.50 Small centralized PV 1-20 MW Grid-connected,ground-mounted,centralized PV systems that work as central power station.The electricity generated in this type of facility is not tied to a specific customer and the purpose is to produce electricity for sale.N/A Large centralized PV 20 MW Grid-connected,ground-mounted,centralized PV systems that work as central power station.The electricity generated in this type of facility is not tied to a specific customer and the purpose is to produce electricity for sale.N/A Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 16 Table 10:National trends in system prices for different applications Year Residential BAPV Grid-connected,roof-mounted,distributed PV system 5-10 kW AUD/kW Small commercial BAPV Grid-connected,roof-mounted,distributed PV systems 10-100 kW AUD/kW Large commercial BAPV Grid-connected,roof-mounted,distributed PV systems 100-250 kW AUD/kW Small Centralized PV Grid-connected,roof-mounted,centralized PV systems 10-20 MW AUD/kW 2005 12 2006 12.5 2007 12 2008 12 2009 9 2010 6 2011 3.9 2012 3 2013 3.1 2014 2.77 2.68 2.7 2015 2.45 2.07 2.18 2016 2.42 2.08 2.76 2017 2.22 2.01 2.24 2018 1.72 1.77 1.77 1.85 2019 1.6 1.58 1.44 na 2020 1.52 1.58 1.44 na 2021 1.55 1.60 1.60 na Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 17 Cost breakdown of PV installations The cost breakdown of a typical 5-10 kW roof-mounted,grid-connected,distributed PV system on a residential single-family house and a typical 10 MW Grid-connected,ground-mounted,centralized PV systems at the end of 2021 is presented in Table 11.The cost structure presented is from the customers point of view i.e.it does not reflect the installer companies overall costs and revenues.The“average”category in Table 11 and Table 12 represents the average cost for each cost category and is the average of the typical cost structure.The average cost is taking the whole system into account and summarizes the average end price to the customer.The“low”and“high”categories are the lowest and highest cost that have been reported within each segment.These costs are individual figures,i.e.summarizing these costs do not give an accurate system price.Table 11:Cost breakdown for a grid-connected roof-mounted,distributed residential PV system of 5-10 kW Cost category Average AUD/W Low AUD/W High AUD/W Hardware Module 0.55 0.3 NA Inverter 0.2 Mounting material 0.22 Other electronics(cables,etc.)Subtotal Hardware 0.97 Soft costs Planning 0.59 Installation work Shipping and travel expenses to customer Permits and commissioning(i.e.,cost for electrician,etc.)Project margin Subtotal Soft costs 0.59 Total(excluding VAT)1.56 Average VAT Total(including VAT)1.56 Total(excluding VAT)Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 18 Additional country information With over 26 GW of solar and a population of 26 million,Australia now leads the world in installed solar per capita,with 3 million rooftop solar installations and 1 kW of solar per person.Germany and the Netherlands follow with less than 800W of installed solar per person.With the current high energy prices and continued support for small-scale installations through the Small-scale Technology Certificates,we expect the small-scale market to remain strong into the future.The Australian electricity market is described in more detail in Section 6.Table 14:Country information Retail electricity prices for a household AUD/kWh 0.2-0.42 Retail electricity prices for a commercial company AUD/kWh 0.23 0.42 Retail electricity prices for an industrial company AUD/kWh 0.20 0.30 Population mid 2022 26 094 037 Country size km2 7.69 million Average PV yield in kWh/kW 1400 PV yield value information This value is a generalised average as conditions vary significantly across Australia.Figure 6:Rooftop solar panels on a rural property.Credit:APVI.Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 19 3 POLICY FRAMEWORK This chapter describes the support policies aiming directly or indirectly to drive the development of PV.Direct support policies have a direct influence on PV development by incentivising,simplifying or defining adequate policies.Indirect support policies change the regulatory environment in a way that can push PV development.Table 15:Summary of PV support measures Category Residential Commercial Industrial Centralized Measures in 2021 On-going New On-going New On-going New Feed-in tariffs Yes-Yes-Feed-in premium(above market price)-Capital subsidies Yes-Yes-Green certificates-Yes-Yes-Renewable portfolio standards with/without PV requirements-Income tax credits-Self-consumption Yes-Yes-Net-metering-Net-billing-Collective self-consumption and virtual net-metering-Commercial bank activities e.g.,green mortgages promoting PV Yes-Yes-Activities of electricity utility businesses Yes-Yes-Sustainable building requirements-Yes-BIPV incentives-Other(specify)-Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 20 National targets for PV The Renewable Energy Target(RET)is designed to reduce emissions of greenhouse gases in the electricity sector and encourage the additional generation of electricity from sustainable and renewable sources.The RET is made up of two parts the Large-scale Renewable Energy Target(LRET),of 33,000 GWh(that was met before 2020),and the Small-scale Renewable Energy Scheme(SRES),with no set target.Details are provided below.Direct support policies for PV installations 3.2.1 The Renewable Energy Target The Renewable Energy Target works by allowing both large-scale power stations and the owners of small-scale systems to create large-scale generation certificates and small-scale technology certificates for every megawatt hour of power they generate.Certificates are then purchased by electricity retailers(who supply electricity to householders and businesses)and submitted to the Clean Energy Regulator to meet the retailers legal obligations under the Renewable Energy Target.This creates a market which provides financial incentives to both large-scale renewable energy power stations and the owners of small-scale renewable energy systems.The RET is funded by a cross-subsidy,leveraged upon all electricity consumption except for certain classes of industrial electricity consumers.Small-scale Renewable Energy Scheme(SRES)The SRES covers small generation units(small-scale solar photovoltaic,small wind turbines and micro hydroelectric systems)and solar water heaters,which can create small-scale technology certificates(STCs).There is no cap on the number of STCs that can be created,however the scheme has a completion date of 2030.Prior to 2015,up-front deeming arrangements meant that PV systems up to 100 kWp could claim 15 years worth of STCs up front.Since 2015,PV installations receive one year less deeming each year,diminishing in line with the RET completion date of 2030.Small-scale technology certificates can be created following the installation of an eligible system and are calculated based on the amount of electricity a system produces or replaces(that is,electricity from non-renewable sources).Generally,householders who purchase these systems assign the right to create their certificates to an agent in return for a lower purchase price.The level of this benefit differs across the country depending on the level of solar energy.The Clean Energy Regulator(CER)manages transfer of STCs through a voluntary clearing house and liable entities are required to surrender STCs to the CER four times a year.The dollar value of these STCs is discounted from the upfront cost of the installation.With support from the SRES,and the declining cost of PV systems,both the volume of new small-scale installs and the average system size has grown year on year.Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 21 Large-scale Renewable Energy Target(LRET)The LRET,covering large-scale renewable energy projects like wind farms,commercial-scale solar and bioenergy includes legislated annual targets had an initial target of 41 000 GWh,that was reduced in 2015 to 33 000 GWhr,which was then achieved in late 2019,ahead of the 2020 target date.Liable entities meet their obligations by acquiring and surrendering Large-scale Generation Certificates(LGCs),with 1 LGC created for each MWh of renewable electricity 3.2.2 National government agencies The Australian Renewable Energy Agency(ARENA),Clean Energy Finance Corporation(CEFC),and Clean Energy Innovation Fund(CEIF)continued to operate throughout 2021 to support the deployment of renewable and clean energy technologies,with a strong focus on solar PV.3.2.2.1 The Australian Renewable Energy Agency(ARENA)The Australian Renewable Energy Agency(ARENA)is an Australian Government statutory agency,established in 2012 by the Australian Renewable Energy Agency Act 2011(ARENA Act).ARENA supports the global transition to net zero emissions by accelerating the pace of pre-commercial innovation,to the benefit of Australian consumers,businesses and workers.ARENA supports renewable energy technologies to become commercially viable by investing in innovation and knowledge.We invest throughout the innovation chain,balancing investment in emerging commercial technologies with earlier-stage research,development and demonstrations to address long-term needs.ARENA has been directly responsible for many renewable energy success stories including:World-leading solar photovoltaic(PV)research,principally through ongoing funding of the Australian Centre for Advanced Photovoltaics(ACAP),including,in 2021,the delivery of the first pieces of equipment supported by a$19 million Infrastructure Project Funding Round for research infrastructure to maintain Australias world class solar PV research program.Support for innovation,trials and pilots in demand response,virtual power plants and energy engagement to help pave the way for a better understanding of consumer behaviour and identify opportunities to reduce consumer costs Co-investment in large-scale solar and batteries to de-risk large projects,to enhance the reliability of supply and to provide support for power system security as Australia transitions to a low emissions energy future.Source:https:/www.transparency.gov.au/annual-reports/australian-renewable-energy-agency/reporting-year/2020-21 Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 22 3.2.2.2 Clean Energy Finance Corporation(CEFC)The Clean Energy Finance Corporation(CEFC)is a Commonwealth Government initiative with a clear mission to accelerate investment in Australias transition to net zero emissions.The CEFC invests to lead the market,operating with commercial rigour to address some of Australias toughest emissions challenges.With the increase in experience and competitive pricing for utility scale solar,CEFC investment is shifting away from solar to enabling technology,including increased transmission,2021 project commitments related to solar photovoltaics include participation in a joint venture to accelerate the delivery of Gippslands Perry Bridge and Fulham solar farms,where grazing and solar will co-exist;3.2.2.3 Clean Energy Innovation Fund(CEIF)The Clean Energy Innovation Fund is an AUD 200 million program supporting the growth of innovative clean energy technologies and businesses,including Australias first Clean Energy Seed Fund.3.2.2.4 Australian Energy Market Operator(AEMO)AEMO develops and maintains an Integrated System Plan(ISP);a whole-of-system plan that provides an integrated roadmap for the efficient development of the National Electricity Market(NEM)over the next 20 years and beyond.The 2020 release reports an expectation that distributed energy will provide as much as 22 per cent of total underlying annual energy consumption by 2040,with more than 26 gigawatts of additional renewable energy required to replace coal-fired generation and a further 6-19 gigawatts of new dispatchable resources required in the form of utility scale pumped hydro,fast response gas-fired generation,battery storage,demand response and virtual power plants.An updated Integrated System Plan was released on June 30 2022.More detail can be found at https:/.au/en/energy-systems/major-publications/integrated-system-plan-isp 3.2.2.5 Technology Investment Roadmap developed by the Commonwealth Department of Industry,Science,Energy and Resources(DISER).The Technology Investment Roadmap is a strategy to accelerate development and commercialisation of low emissions technologies.These include energy storage to assist cost effective,reliable low emission electricity,hydrogen,carbon capture and storage,soil carbon sequestration,biofuels,resources,and energy exports to reduce emissions while strengthening our economy.Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 23 3.2.3 Solar for communities No ongoing programs exist in this area.The Federal Government Community Energy Efficiency and Solar Grants program closed in 2021.Examples of local initiatives include the Majura Community Solar Farm in the ACT,established by SolarShare,the Majura Community Solar Farm is part of the ACT governments Community Solar initiative whereby electricity is sold under a Feed in Tariff contract.SolarShare will be able to sell the energy into the energy network and receive 19.56c for each kWh of electricity generated.https:/.au/solar-farm-project/greenfield-project Figure 7:Majura Community Solar Farm.Credit:ITP Renewables.Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 24 3.2.4 State based incentives including feed in tariffs Complementing the established RET,state-based incentives have helped support PV markets through feed-in-tariffs,cash incentives and reverse auctions.Source:https:/www.energy.gov.au/rebates 3.2.4.1 Direct Subsidies Most state governments are now offering some type of incentive for solar plus battery installations or to add a battery to an existing solar system:The NSW Government is offering up to 3,000 free 3 kW solar installations for low-income households.The ACT Government offers an AUD 2,500 incentive for low-income households to invest in rooftop solar PV panels.The Victorian Government Solar Homes provides eligible Victorian households with a rebate of up to 50%of the purchase cost to install solar PV panels.The rebate is up to$1,850,currently about half the value of an average 4 kW solar PV system.The Victorian Government Small Business Rebate offers a rebate of 50%,up to AUD 3,500 to reduce the upfront cost of installing a solar PV system on a business,and access to interest free loans.3.2.4.2 Feed-in Tariff Each of the State and Territory jurisdictions have run their own feed-in tariff(FiT)schemes.All now closed to new entrants but many are still operating.Most PV systems now receive feed-in tariffs with a value that is ostensibly based on the wholesale electricity price but is often more because of customer acquisition value;in some states a minimum value is stipulated by the government but in other states the value is left to electricity retailers to decide.In Victoria,the value of avoided greenhouse gas emissions is included in the mandatory minimum feed-in tariff.Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 25 Table 16:Australian State and Territory feed-in tariffs in 2021 State Start Date Size Limits Rate AUDc/kWh Scheme end Type Eligibility Victoria Premium FiT(closed 1 Jan 2012)1 Nov 2009 5 kW 60 2024 Net Residential,community,small business Comments Customers lose their FiT if they change their system size or move house.South Australia Groups 1,2&3(closed 30 Sept 2011)1 July 2008 10 kVA 1 30 kVA 3 44 30 June 2028 Net A facility that consumes less than 160 MWh/yr Comments Groups 1,2&3 differ according to the amount of electricity the FiT applies to and when the system was logged with the network operator.ACT Gross FiT(closed 31 May 2011)1 March 2009 30 kW 50,05(10 kW),40,04(10-30 kW),after 1 July 2010 45,7(30 kW)20 years after connection Gross Residential,business Gross FiT(closed 13 July 2011)1 April 2011 30-200 kW 34,27 20 years after connection Gross Residential,business Comments Although the Gross FiT(30 kW)was closed on 31 May 2011,30 kW systems were made eligible for the Gross FiT(30-200 kW)from 12 July 2011 to 13 July 2011 to allow these systems to access the cap originally set aside for systems 30 kW to 200 kW.Queensland Solar Bonus Scheme(closed 10 July 2012)1 July 2008 10 kVA 1 30 kVA 3 44 1 July 2028 Net Consumers with less than 100 MWh/yr Comments Customers lose their SBS FiT if they change their system size or move house.Western Australia Residential FiT scheme(closed 1 Aug 2011)1 July 2010 5 kW(city)10 kW 1 30 kW 3(country)40 to 30 June 2011 20 from 1 July 2011 10 years after installation Net Residential RE Buyback Scheme 2005 Up to 5 kW dropped to 7.135 from 9.5 on 1 Sept.2014 Open ended Net Residential,Commercial(Horizon Power)Comments The amount of the REBS FiT depends on the local cost of generation,the retail tariff and whether residential or commercial Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 26 3.2.5 Local government incentives In 2021,local governments continue to play a part in supporting the deployment of solar power systems.Local governments installed PV on their own premises,offered Environmental Upgrade Agreements,supported community bulk-buy initiatives,and have financially supported the Australian PV Institutes SunSPoT that allows households and businesses to obtain a better understanding of the financial outcomes of installing solar in their roof.3.2.6 BIPV development measures Australia has no specific Building Integrated PV(BIPV)development measures.Australia maintains a Nationwide House Energy Rating Scheme(NatHERS)that measures the energy efficiency of residential buildings.There is also the National Australian Built Environment Rating System(NABERS),that measures the energy efficiency,water usage,waste management and indoor environmental quality of buildings,tenancies and homes and their impact on the environment.Solar PV can be used to help meet both these schemes.Self-consumption measures Table 17:Summary of self-consumption regulations for small private PV systems in 2021 PV self-consumption 1 Right to self-consume Yes.2 Revenues from self-consumed PV Savings on the electricity bill.3 Charges to finance Transmission,Distribution grids&Renewable Levies Charged to consumers,incorporated in the retail tariff in c/kWh.Excess PV electricity 4 Revenues from excess PV electricity injected into the grid Different types of Feed-in Tariffs.5 Maximum timeframe for compensation of fluxes In 2021,the market operator changed the settlement period from the former current 30-minute wholesale electricity spot market settlement period to five-minutes,providing a better price signal for investment in faster response technologies,such as batteries and gas peaking generators 6 Geographical perimeter(use of the public or private grid)Feed-in-tariff payments only,no use of grid possible for trading 7 Number of participants(individual or collective self-consumption)No collective self-consumption,distribution costs apply to all excess PV electricity Other characteristics 8 Regulatory scheme duration Premium FiTs differ between jurisdictions,and standard FiTs are revised annually.Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 27 9 Third party ownership accepted Yes(for ex-solar leasing).10 Grid codes and/or additional taxes/fees impacting the revenues of the prosumer No.11 Regulations on enablers of self-consumption(storage,DSM)None.12 PV system size limitations Some regional limits on system size to connect.Some regional limits requiring self-consumption only.13 Electricity system limitations None(except additional grid codes).14 Additional features None.3.3.1 Change to 5 minute settlement The introduction of 5-minute settlement to the Australian Energy Market in 2021 has led to some significant changes in bidding practices for generators and batteries in the energy market,with some of the big-battery projects benefiting from arbitrage opportunities.In contrast to bidding under the 30-minute period,the market is not seeing a rush to negative price-bidding after a price spike by generators to secure offtake,which was a perverse outcome of the 30-minute settlement scheme.The change was agreed to in 2017,giving generators sufficient notice to plan.More detail can be found here:https:/.au/initiatives/major-programs/nem-five-minute-settlement-program-and-global-settlement 3.3.2 Collective self-consumption Current network pricing regulations in Australia stipulate that full network charges must be paid even for locally transmitted electricity,which acts as a barrier to collective self-consumption or virtual net-metering(which are therefore only practical within embedded networks).Microgrids that include PV operate across the country,particularly in new housing developments and in power supplies for remote communities.Community solar investment occurs at relatively low levels in Australia.Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 28 Tenders,auctions&similar schemes 3.4.1 Solar tenders Solar tenders come from a mix of state governments,local governments,electricity retailers,and the Australian Renewable Energy Agency(ARENA).Each has its own process with varying funding mechanisms,the most common being PPAs for energy generation or Renewable Energy Certificates(or both).In addition to state government tenders,corporations are running tenders for supply of electricity,known as Corporate PPAs.Other utility-scale measures including floating and agricultural PV 3.5.1 Floating solar After the construction of one floating solar plant in 2017,there were no new connections in 2021.There are no agriculture-specific large-scale solar plants.Two GW-scale solar projects are under development:3.5.2 Ultra-large-scale solar The Australian-ASEAN Power Link in the Northern Territory,is projected to be the worlds largest solar farm and battery storage facility with 20 GW of solar,42 GWhr of battery storage and 4,200 km of under-sea cable delivering power into Southeast Asia.The Asian Renewable Energy Hub in Western Australia,which will see 26 GW of wind and solar proposed to provide energy to large energy users in the Pilbara region,including new and expanded mines and downstream mineral processing.The bulk of the energy will be used for large scale production of green hydrogen products for both domestic and export markets.3.5.3 Social policies In 2021,several measures for solar for low-income households were maintained by State Governments:The NSW Government is offering the Solar for Low Income Households program to 3,000 selected households,with the government installing a 3 kW rooftop solar for free in exchange for no longer receiving the Low-Income Household Rebate for electricity bills for ten years.The Victorian government offers the Solar for Rentals program for landlords up to a maximum of AUD 1,850 as well as an interest free loan up to the value of the rebate which must be paid back over 4 years.The AUD 1,850 rebate is also available for community housing.The ACT Government provides the Solar for Low Income Households Program where eligible participants can access a subsidy of up to 50%of the total cost of a solar system.Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 29 Retroactive measures applied to PV No retrospective measures that impact the profitability of existing PV plants,either positively or negatively have been implemented.Indirect policy issues 3.7.1 Rural electrification measures Some examples of rural electrification measures are:The Commonwealth government is providing up to AUD 50.4 million from 2019/20 to 2023/24 to support feasibility studies looking at microgrid technologies to replace,upgrade or supplement existing electricity supply arrangements in off-grid and fringe-of-grid communities located in regional and remote areas.The Western Australian government has developed the Distributed Energy Resources(DER)Roadmap which includes a strong focus on microgrids in rural areas.They have also announced regulatory changes that allow the state government owned network operator,Western Power,to excise customers from fringe-of-grid areas and develop solar powered microgrids to improve power quality.As part of the AUD 3.6 million Decarbonising Remote Communities program,four Indigenous communities in Queenslands far north Doomadgee,Mapoon,Pormpuraaw and the Northern Peninsula Area are receiving over 1 MW solar PV installed to reduce the use of diesel power.3.7.2 Support for electricity storage and demand response measures There are numerous trials of virtual power plants,demand response and battery integration.Some offer discounts on hardware,others premium payments for demand response.There are currently about 20 commercially available VPP products,testing different business models.There is around 300 MW of household VPP aggregated under all the schemes and around 350 MW in commercial and industrial VPP arrangements.source:https:/ieefa.org/wp-content/uploads/2022/03/What-Is-the-State-of-Virtual-Power-Plants-in-Australia_March-2022_2.pdf Victoria,the ACT,and South Australia all have solar rebates for batteries.NSW Govt offers interest free loans to support household batteries.3.7.3 Support for electric vehicles and vehicle-integrated photovoltaics(VIPV)In 2021,there was no national program to develop the electric vehicle market.Government support for electric vehicles(EVs)has instead been led by state governments.State Governments offer a rebate of up to$3,000 as well as waiving Stamp Duty on Electric Vehicles.They are also supporting the roll out of charging stations.Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 30 One state(Victoria)introduced an EV specific tax.It charges electric vehicle owners 2.5 cents per kilometre to partially account for the declining fuel excise paid by those filling up with petrol or diesel.For a car travelling 15,000km annually,that means$375 in a road user charges source:https:/.au/car-motoring/info/electric-car-incentives#:text=NSW EV incentives,can be up to $3,000.3.7.4 Curtailment policies The Australian Energy Market Operator(AEMO)poses strict rules that limit total large-scale solar(and wind)output to protect what it calls system strength.Curtailment happens when combined output reaches a pre-defined level and happens regularly in South Australia,where there is a rapidly growing large-scale solar capacity now standing at 110 MW and more than 1,800 MW of wind capacity.Output of solar farms is also discounted using a Marginal Loss Factor(MLF).The MLF is a calculation used to estimate how much a plants output reaches a destination and reflects distance to load.An MLF of 0.9,for instance,suggests losses of 10 per cent,so a solar plant will be credited for just 90 MWh out of every 100 MWh registered at the meter at the plant.MLFs are revised and set annually and lead to increased risk in establishing business models around return on investment in large-scale solar.3.7.5 Other support measures 3.7.5.1 State-Based Emission Reduction Targets State and territory governments are driving the Australian energy markets progress in emissions reductions.All states and territories except Western Australia now have strong renewable energy targets or net zero emissions targets in place.Both the ACT and Tasmania are now powered by 100%renewables,and in addition now Tasmania plans to decarbonise their whole electricity and energy system with a 200%renewables target.The state initiatives contrast with the position that the Australian Commonwealth Government held in 2021,where they preferred a technology led initiative and developed a Roadmap for low emissions technologies,with the then Prime Ministers stated goal to“reach net-zero emissions as soon as possible,and preferably by 2050”.The state-based targets that are in place are broadly consistent with the level of renewable energy needed across Australia by 2030 to contribute to keeping global temperature rise below two degrees Celsius(2C).Australia has seen a change of government in mid-2022,which has already resulted in some significant changes including a commit to cut emissions by 43%by 2030.3.7.5.2 Renewable Energy Zones(REZs)State based Renewable Energy Zones(REZs)aim to motivate regional investment in generation from wind and solar,storage(e.g.,batteries),and in high-voltage poles and wires.Queensland has announced plans for three REZs with 60 GW of projects proposed from the market.Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 31 NSW has announced plans for a targeted AUD 32 billion investment in five REZs,calling for 12 GW of renewable energy to be built and an additional 2 GW for storage,with bipartisan support.Victoria has announced an AUD 1.6 billion plan for clean energy including the biggest battery in the southern hemisphere.Financing and cost of support measures The cost of the SRES and LRET schemes and most feed in tariffs are passed through to energy consumers as a levy on their bills.Financing for large scale projects from government funds in 2021 was by way of recuperable grants or equity.Figure 8.Limondale Solar Farm in NSW 349 MW installation.Image provided by RWE Renewables Australia and Ideematec.Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 32 4 INDUSTRY Production of feedstocks,ingots and wafers(crystalline silicon industry)Australia has no solar feedstock,ingot or wafer production.Production of photovoltaic cells and modules(including TF and CPV)Module manufacturing is defined as the industry where the process of the production of PV modules(the encapsulation)is done.A company may also be involved in the production of ingots,wafers or the processing of cells,in addition to fabricating the modules with frames,junction boxes,etc.The manufacturing of modules may only be counted to a country if the encapsulation takes place in that country.For many years,Tindo Solar has been the sole manufacturer of solar panels in Australia.Tindo imports cells to produce poly and PERC-mono panels,doing module assembly and testing in Australia.Tindos business model is to both sell panels wholesale and retail PV systems through parent company Cool or Cosy.In early 2021,Tindo secured funds to expand manufacturing capacity to 150 MW/yr,expected to be finished in 2022.Total PV cell and module manufacture together with production capacity information is summarised in Table 19 below.Table 19:PV cell and module production and production capacity information for 2021 Cell/Module manufacturer(or total national production)Technology(sc-Si,mc-Si,a-Si,CdTe,CIGS)Total Production MW Maximum production capacity MW/yr Cell Module Cell Module Wafer-based PV manufactures Tindo Solar 30 60 Totals 0 30 0 60 Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 33 Manufacturers and suppliers of other components Balance of system component manufacture and supply is an important part of the PV system value chain.4.3.1 PV inverters(for grid-connection and stand-alone systems)Australian companies Latronics and Selectronics design and manufacture inverters for use in both grid and off-grid applications.Magellan Power is an Australian based manufacturer of power electronics including PV inverters designed for both residential and commercial applications.Redback Technologies is an Australian intelligent hybrid PV-storage inverter manufacturer.MIL Systems is an Australian power system engineering company that produces a residential grid-connected inverter.4.3.2 Storage batteries Australian company RedFlow manufactures Zinc Bromine flow batteries.Its ZBM product delivers up to 3 kW of continuous power(5 kW peak)and up to 8 kWh of energy.RedFlow has launched a product to serve the residential market.There are large numbers of foreign manufactured battery companies supplying to the Australian market,some of whom are setting up local manufacturing.4.3.3 Battery charge controllers and DC switchgear A range of specialised fuses,switches and charge controllers are made locally.Here are a few examples of charge controllers&switchgear implementations in Australia:Magellan Power have a range of battery,control and switching technologies.Solari Energy Solagrid Energy Storage System(ESS)a stand-alone energy storage system suitable for any sized solar energy installation.They also produce Solagrid audible alarm safety device in case of faults.Wattwatchers have developed low-cost,ultra-compact,multi-circuit meters with built in wireless communications.Solar Analytics provide a home energy monitoring solution with a focus on solar,with over 35,000 sales.CatchPower,SwitchdIn,Greensync,Reposit and Evergen are developing internet-of-energy solutions including to optimise solar and battery interactions with the grid.Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 34 4.3.4 Supporting structures With most solar going in on rooftops,there is some local industry including-IXL who manufacture a range of mounting and tracking systems to suit local conditions.-Capral Aluminium makes extruded aluminium for Clenergy mounting systems here in Australia.See https:/company Schletter are also making roof top mounting systems For large scale solar,5B is a Sydney based renewable energy technology business that has created a completely prefabricated and rapidly deployable ground mount solar array solution-enabling faster,lower cost and more flexible solar projects.Figure 9.2.2 MW Large Scale PV array Port Bonython roll out of 5B Maverick Technology.Image courtesy of 5B Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 35 4.3.5 BIPV Tractile Solar manufactures composite roof tiles that combine PV cells with Thermal Hot Water.and was showcased in the Desert Rose House,that took second place in 2018 Solar Decathlon,Middle East.Bristile roofing(part of the Brickworks group of companies)make a PV integrated rooftile.See https:/.au/solar/Melbourne-based architectural firm Kennon has announced the nations first building to harness solar power via its facade is under construction.The revolutionary design conceived by Kennon in 2019 will be brought to life by a private developer,with the eight-storey office building to be located at 550 Spencer Street,West Melbourne.With 1182 individual solar panels to be located on the facade,the building will produce more energy than it consumes,revolutionising sustainability outcomes for the future of architectural design.Construction is expected to be completed in mid-2023,with the developer seeking a long-term tenant motivated to uphold the buildings sustainability values.Figure 10.Schematic of planned BIPV on a commercial building at 550 Spencer St,Melbourne Credit:CUUB/Kennon architecture firm Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 36 5 PV IN THE ECONOMY This chapter aims to provide information on the benefits of PV for the economy.The Australian solar supply chain is typically structured as follows:Wholesalers(Distributors)import from overseas manufacturers and sell to PV Retailers.PV retailers buy products from wholesalers,or direct from the manufacturer,and arrange for installation.PV retailers often outsource installation to contract installers,though its not uncommon for them to employ in-house accredited installers.The retailer is responsible for collecting the paperwork from the installer that is needed for STC creation.Installers collect equipment from retailers(or from wholesalers bonded warehouses)and transport it to site for installation.The installer is responsible for physical installation and commissioning of the system,as well as signing off on critical paperwork for electrical connection and STCs.Installation teams must include at least one accredited installer(electrician),with accreditation by the Clean Energy Council(CEC).The CEC-accredited installer signing off on the job is liable to ensure both the system design and installation meet Australian Standards and CEC guidelines.Some PV installers are also micro-retailers.Figure 11.Rooftop Installation PV in progress.Credit:Tindo Solar.Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 37 Labour places Through 2021 there were an estimated 25,370 full-time equivalent(FTE)labour places in the PV industry.Indirect employment would include jobs related within consultancies,industry associations,government and electricity utilities and would potentially double these numbers.Research and development are well supported in Australia,with close to 250 employed in solar energy research and over 300 students in higher education research in solar energy.The significant R&D budget is supported principally by the national funded Australian Renewable Energy Agency with funding to the end of 2030.Table 20:Estimated PV-related full-time labour places in 2021 Market category Number of full-time labour places Research and development(not including companies)250 Manufacturing of products throughout the PV value chain from feedstock to systems,including company R&D 120 Distributors of PV products and installations 25,000 System and installation companies Operation and maintenance companies Electricity utility businesses and government Total 25 370 Research development and innovation Solar PV R&D is primarily funded by the Australian Renewable Energy Agency,with an annual research budget,averaged around 19 MAUD/yr over four years.Business value Table 21:Rough estimation of the value of the PV business in 2021(VAT is excluded)Sub-market Capacity installed MW Average price AUD/W Value AUD Sub-market AUD Off-grid Grid-connected distributed 3,056 1.6 4,930,000,000 4,930,000,000 Grid-connected centralized 1,422 1.5 2,275,000,000 2,275,000,000 Value of PV business in 2021 7,205,000,000 Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 38 6 INTEREST FROM ELECTRICITY STAKEHOLDERS Structure of the electricity system In most areas of the country on main grids the electricity system is split into generation,transmission,distribution,and retail sectors,where smaller grids are(typically)vertically integrated.There is a mix of public and private ownership across all jurisdictions and sectors.The National Electricity Market(NEM)spans Australias eastern and south-eastern coasts and comprises five interconnected states that also act as price regions:Queensland,New South Wales(including the Australian Capital Territory),South Australia,Victoria,and Tasmania.There are over 400 registered participants in the NEM,both State government owned and private,including market generators,transmission network service providers,distribution network service providers,and market customers.The NEM is a wholesale commodity exchange for electricity across the five interconnected states.The market works as a“pool”,or spot market,where power supply and demand is matched in real time through a centrally coordinated dispatch process.Generators offer to supply the market with specified amounts of electricity at specified prices for set time periods and can re-submit the offered amounts at any time.From all the bids offered,the Australian Energy Market Operator(AEMO)decides which generators will be deployed to produce electricity,with the cheapest generator put into operation first.A dispatch price is determined every five minutes,and six dispatch prices are averaged every half-hour to determine the“spot price”for each NEM region.AEMO uses the spot price as its basis for settling the financial transactions for all electricity traded in the NEM.Network,retail and environmental charges are added to the energy price in calculating retail tariffs and these are all charged to the customer by the retailer.Western Australia and the Northern Territory are not connected to the NEM.Western Australia operates two separate networks,the South West Interconnected System(SWIS)and the North West Interconnected System.A range of smaller grids also operate in remote areas of the states.The SWIS operates via a short-term energy market and a reserve capacity market.Capacity and energy are traded separately.The Northern Territory operates several grids both large and small to service population centres and regional townships.Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 39 Interest from electricity utility businesses The businesses that make up the electricity industry have collectively recognised the inevitability of solar power rolling out across Australia,and most have opted to play a constructive role.Solar is impacting the energy market operation both technically and financially.-Financially,solar is reducing the amount of energy transported and sold and reducing the wholesale electricity price during the daytime.-Technical issues most commonly relate to inverter response to system disturbance and impacts upon local voltages.Network operators have been given the ability to constrain the amount of PV that is connected to their networks and impose these constraints upon individual applicants,unless applicants use inverters with operation modes under the network operators influence.6.2.1 Electricity network operators Though the energy market operator has stopped electricity network operators from discriminating with solar-specific tariffs that would financially penalise solar households,most network operators still impose delays and conditions to network connection approval that increase the soft costs of solar deployment.Despite this,some network operators have spun-off solar retailing companies of their own and managed at arms length through ring-fencing provisions.Australian energy regulators,while becoming mindful of the need to change regulatory frameworks considering these developments,are currently themselves restricted by their own governance arrangements and reporting structures.Nevertheless,new regulatory frameworks are needed to cater for rapidly increasing distributed energy options.For instance,network businesses are currently prevented from implementing distributed energy options themselves,even if these may provide more cost-effective solutions than grid upgrades or extensions,while third party access to this market is not available.Regardless,momentum is swinging towards a more neutral playing field that balances the needs of both incumbents and the new entrant distributed energy market participants.The Energy Networks Association is actively considering a future with high-penetration PV,working with CSIRO to produce an Electricity Network Transformation Roadmap.6.2.2 Electricity generators and retailers Electricity generators and retailers are commonly the same company in many parts of Australia and are therefore collectively referred to as gentailers.Three large companies dominate the energy retail space in Australia,all offer feed-in-tariffs,have made some investment in large-scale solar and/or are currently participating in the rollout of solar farms by contracting PPAs from solar farms(in order to meet their Renewable Energy Target obligations).The three largest electricity retailers also have their own solar retailing divisions.Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 40 Several small retailers with a solar-energy focus have been established to address a market opportunity in the community demand for access to solar,the significant portion of Australian households with an investment in solar and increased electricity prices.Interest from municipalities and local governments There is high(and increasing)interest in PV implementation from local governments and community organisations around Australia.These groups are typically less well-resourced than utility or large government organisations and must operate within the electricity market described above.However,they are backed by a high level of community support for local generation and employment creation.Many local governments install PV on their own buildings,operate bulk-buy initiatives,and are beginning to set their own renewable energy goals and support community-owned solar installations.Specific examples of local government solar PV support initiatives include:City Power Partnerships,an initiative of the Climate Council that brings together over 150 local government organisations,over 500 cities and towns representing 60%of the population.The CPP has a commitment to clean energy,representing almost 60%of the Australian population.The Melbourne Renewable Energy Project(MREP)1 and 2:a consortium of local government,educational institutions,and private companies that successfully purchased 88h and 110h per year(respectively)of energy from new large-scale renewable energy facilities.Together,MREP 1 and 2 contributed to reducing the equivalent of 5%of Melbournes emissions.Solar My School,a Council-run program initially founded by three Sydney Councils,now involves over 160 schools across Sydney and regional NSW.This program aims to help schools install solar with support through the whole process.Other examples of broader programs used by,and in some cases established by,local governments include:Solar Bulk Buy Programs,which give households and businesses in these municipalities access to bulk purchase discount deals.Many local government bulk-buy programmes exist.Many local governments have initiated Environmental Upgrade Agreements to assist in reducing the carbon intensity of energy use.This can include solar PV and is implemented by lower than market fixed interest rate loans over a longer than usual loan term.Community Groups and Energy Foundations including the Australian Energy Foundation(formerly Moreland Energy Foundation)and the Yarra Energy Foundation.Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 41 States and territories In 2021,state governments continued to progress measures that would support the deployment of renewable energy,by identifying areas of opportunity,accelerating the development approval of some solar farms,tendering for renewable energy for their facilities,creating state-based targets for renewable energy uptake,and launching tenders for grid-scale batteries.Collectively Australian governments are investing over AUD 7 billion in clean energy stimulus measures,with the Tasmanian government leading progress having already achieved 100%renewables and South Australia following Figure 12.Residential solar.Credit:APVI.Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 42 7 HIGHLIGHTS AND PROSPECTS Highlights Despite the challenges faced through 2021 posed by the COVID-19 pandemic,this year was another strong one for solar installations across the Australian market.The year saw a total installed capacity of 4.9 GW taking the country to a total cumulative capacity of 26 GW,more than doubling the total capacity at the end of 2018.With a population of 26 million people,Australia now has a world-class 1 kW per capita of solar installed.The small-scale solar sector(100 kW)had another incredible year despite COVID-19 and supply chain challenges,with over 3 GW of installed capacity.State,local government and community initiatives have continued to drive this market through what was otherwise a challenging year.Australia continues to build on its high per-capita rooftop install rate with over 33%of free-standing households now generating power from their rooftop,and well over 50%in many urban areas.At the end of 2021 there were more than 3 million household solar installations across the country.Prospects Building off a strong base,and with a change in government in mid-2022 leading to stronger and more ambitious commitments to net-zero emissions,Australia is likely to see ongoing growth in the solar PV market.There are well established plans and commitments to invest in adapting the electricity system to meet increasing solar deployment at utility scale,through enhancing transmission,and to manage the significant decentralised generation investment.Continuing support from Small-scale Technology Certificates through to 2030 will provide ongoing momentum for rooftop solar,with strong growth expected in commercial and industrial markets.State-based government competition for investment in Renewable Energy Zones,including related infrastructure investments will drive large-scale investment in both solar and wind by reducing risk and increasing investor confidence.The Commonwealth Government funded Australian Renewable Energy Agency(ARENA)has a budget to end 2030 of 1.6 BAUDs to support Australia in the global transition to net zero emissions,by accelerating the pace of precommercial innovation,to the benefit of Australian consumers,businesses and workers.The energy market operator(AEMO)is designing for 100%renewable penetration across the market by 2025,with evidence already of feasibility,and challenges,when on occasions,the entire state of South Australia(SA)is entirely powered by solar and wind,supported by batteries.New infrastructure connecting SA-NSW and VIC-NSW grids are under development.Project EnergyConnect was approved for construction in mid-2021.Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 43 Network operators are looking at setting up autonomous micro and mini-grids and generator/retailers are investing in virtual power plants(VPPs).Storage capacity is set to increase with large-scale storage project approvals and the increasing competitiveness of small-scale,behind the meter storage options.Big vison projects are under development to support renewable energy exports including Sun Cables plans for 20 GW of solar in the Northern Territory delivering power by under-sea cable into Southeast Asia and the Asian Renewable Energy Hub with up to 26 GW of wind and solar to support hydrogen exports.The ongoing investment in renewables will present market and engineering challenges that will need to be met by policy and regulatory change including by a redesign of tariffs to incentivise use of low-cost,low-emissions power,by investments in storage and investments in transmission and distribution.New benchmarks continue to be set,with South Australia achieving 100%renewable energy over a 24-hour period in late September 2021.Fig 12:The state of South Australia is 100%renewables for a 24hour period for the first time on September 20 2021.Source:https:/opennem.org.au/Challenges include grid and connection constraints for utility scale solar and changing economics as Marginal Loss Factors(MLF)are adjusted to reflect co-incidence of supply and connection and distance to load.Technology is moving faster than policy and regulation and to maintain the rapid pace of renewable energy deployment,Australia needs to support national electricity market reforms and provide policy certainty to support the needed electricity infrastructure investments and additional electricity transmission,energy storage and demand response mechanisms.Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 44 END This report was prepared by the APVI with support from ARENA and APVI members www.apvi.org.au The views expressed herein are not necessarily the views of the Australian Government.The Australian Government does not accept responsibility for any information or advice contained within this document.Fig 13:Trundle Solar Farm 6.4 MW Solar Farm,where ITP Renewables provided due diligence for the financiers and commissioning for Enerparc Australia.Image courtesy of ITP Renewables.Task 1 National Survey Report of PV_Australia Power Applications in COUNTRY 1

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IEA PVPS：2021年法国太阳能光伏应用调查报告（英文版）（45面）.pdf

Ml National Survey Report of PV Power Applications in France 2021 PV PS Task 1 Strategic PV Analysis and Outreach Task 1 What is IEA PVPS TCP?The International Energy Agency(IEA),founded in 1974,is an autonomous body within the framework of the Organization for Economic Cooperation and Development(OECD).The Technology Collaboration Programme(TCP)was created with a belief that the future of energy security and sustainability starts with global collaboration.The programme is made up of 6.000 experts across government,academia,and industry dedicated to advancing common research and the application of specific energy technologies.The IEA Photovoltaic Power Systems Programme(IEA PVPS)is one of the TCPs within the IEA and was established in 1993.The mission of the programme is to“enhance the international collaborative efforts which facilitate the role of photovoltaic solar energy as a cornerstone in the transition to sustainable energy systems.”In order to achieve this,the Programmes participants have undertaken a variety of joint research projects in PV power systems applications.The overall programme is headed by an Executive Committee,comprised of one delegate from each country or organisation member,which designates distinct Tasks,that may be research projects or activity areas.The IEA PVPS participating countries are Australia,Austria,Belgium,Canada,Chile,China,Denmark,Finland,France,Germany,Israel,Italy,Japan,Korea,Malaysia,Mexico,Morocco,the Netherlands,Norway,Portugal,South Africa,Spain,Sweden,Switzerland,Thailand,Turkey,and the United States of America.The European Commission,Solar Power Europe,the Smart Electric Power Alliance(SEPA),the Solar Energy Industries Association and the Cop-per Alliance are also members.Visit us at:www.iea-pvps.org What is IEA PVPS Task 1?The objective of Task 1 of the IEA Photovoltaic Power Systems Programme is to promote and facilitate the exchange and dissemination of information on the technical,economic,environmental and social aspects of PV power systems.Task 1 activities support the broader PVPS objectives:to contribute to cost reduction of PV power applications,to increase awareness of the potential and value of PV power systems,to foster the removal of both technical and non-technical barriers and to enhance technology co-operation.An important deliverable of Task 1 is the annual“Trends in photovoltaic applications”report.In parallel,National Survey Reports are produced annually by each Task 1 participant.This document is the country National Survey Report for the year 2021.Information from this document will be used as input to the annual Trends in photovoltaic applications report.Authors Main Content:Melodie DE LEPINE,Damien SALEL Data:ENEDIS,SDES,RTE Analysis:Melodie DE LEPINE,Damien SALEL DISCLAIMER The IEA PVPS TCP is organised under the auspices of the International Energy Agency(IEA)but is functionally and legally autonomous.Views,findings and publications of the IEA PVPS TCP do not necessarily represent the views or policies of the IEA Secretariat or its individual member countries COVER PICTURE 36 kW on a municipal building by community solar group EnerCOA at Villefranche de Rouergue credit:EnerCOA Task 1 2 TABLE OF CONTENTS Acknowledgements.4 REFERENCES.4 1 Installation Data.5 1.1 Applications for Photovoltaics.5 1.2 Total photovoltaic power installed.6 1.3 Key enablers of PV development.12 2 Competitiveness of PV electricity.13 2.1 Module prices.13 2.2 System prices.14 2.3 Cost breakdown of PV installations.17 2.4 Financial Parameters and specific financing programs.19 2.5 Specific investments programs.19 2.6 Additional Country information.22 3 Policy Framework.23 3.1 National targets for PV.24 3.2 Direct support policies for PV installations.24 3.3 Self-consumption measures.27 3.4 Collective self-consumption,community solar and similar measures.30 3.5 Tenders,auctions&similar schemes.31 3.6 Other utility-scale measures including floating and agricultural PV.34 3.7 Retroactive measures applied to PV.34 3.8 Indirect policy issues.34 3.9 Financing and cost of support measures.35 4 Industry.36 4.1 Production of feedstocks,ingots and wafers(crystalline silicon industry).36 4.2 Production of photovoltaic cells and modules(including TF and CPV).36 4.3 Manufacturers and suppliers of other components.39 5 PV in the Economy.40 5.1 Labour places.40 5.2 Business value.41 Task 1 3 6 Interest From Electricity Stakeholders.42 6.1 Structure of the electricity system.42 6.2 Interest from electricity utility businesses.42 6.3 Interest from municipalities and local governments.42 7 Highlights and Prospects.43 7.1 Highlights.43 7.2 Perspectives.43 Task 1 4 ACKNOWLEDGEMENTS This paper received valuable contributions from different sources mentioned in the references,and from Paul KAAIJK SRER ADEME Valbonne.REFERENCES The principal references are cited below;however,a number of additional sources,including web sites,private communications and diverse publications were also used.Tableau de bord photovoltaque,Sttinfo,n 436,February 2022(SDES Service de la donne et des tudes statistiques,Commissariat au Dveloppement Durable,the Ministry for the Ecological and Inclusive Transition);Registre national des installations de production et de stockage dlectricit(National Register of Generators and electricity storage systems);Bilans des Raccordements,Enedis Open Data(distribution grid manager for 95%of the nation);Bilan lectrique 2021(RTE Electricity Report 2021),RTE,February 2022(Transport grid manager);Baromtre annuel 2021,AVERE;Cots des nergies renouvelables et de rcupration en France Edition 2022 ADEME;Charges de service public de lnergie prvisionnelles au titre de lanne 2021,CRE;France Territoire Solaire Bilan T4 2021;Baromtre 2021 du crowdfunding EnR,Green Univers;“Baromtre des achats dnergie verte en France T4 2021 Capgemini invent;Le baromtre 2021 des nergies renouvelables lectriques en France,ObservER;Public reports on national Call for Tenders dedicated to solar energy,CRE(Rapport de synthse(version publique),Appel doffres portant sur la ralisation et lexploitation dinstallations de production dlectricit partir de techniques de conversion du rayonnement solaire,Commission de Rgulation de lEnergie)(several publications,2021 and 2022).Task 1 5 1 INSTALLATION DATA The PV power systems market is defined as the market of all nationally installed(terrestrial)PV applications with a PV capacity of 40 W or more.A PV system consists of modules,inverters,batteries and all installation and control components for modules,inverters and batteries.Other applications such as small mobile devices are not considered in this report.For the purposes of this report,PV installations are included in the 2021 statistics if the PV modules were installed and connected to the grid between 1 January and 31 December 2021,although commissioning may have taken place at a later date.Data collection includes information on storage capacity,and injection type is now collected by Enedis(total or partial self-consumption,full generation sales).Official statistics report the AC power of photovoltaic fields,despite eligibility for Feed-in Tariffs and Tender support mechanisms being indicated in by peak DC power thresholds.It may be useful for the reader to know that the average generation across France is 1 160 kWh/kW,but that systems installed in the southern half of mainland France and in overseas territories will generate more,up to 1 400 kWh/kW.For the purposes of this report,all AC data has been converted to DC power,with a standard ratio of 1.2(AC to DC)unless otherwise specified.In the particular segment of utility scale systems,some data is available on both DC and AC power and the reported DC power has been used.Little data is available on off-grid applications as there are few support mechanisms that allow observers to track installation volumes.1.1 Applications for Photovoltaics The principal applications for photovoltaics in France in 2021 are grid connected:Residential(house and multi-apartment)systems.These systems tend to range from one or two modules with self-consumption through to standard 3 kW,6 kW or 9 kW systems.Much of the current total capacity was installed during the 2009/2011”boom”and is building integrated however,since 2017,new capacity is only building applied PV;Commercial,agricultural or industrial systems on buildings(36 kW to 250 kW AC or around 300 kW DC).A small proportion(3%of total new capacity)are systems between 9 kW and 36 kW,generally on public buildings such as town halls,primary schools or technical services buildings;Industrial building mounted or parking canopy systems(250 kW to 10MW);Utility scale ground mounted systems(over 10 MW).Small but growing segments include agrivoltaics and floating PV.A small amount of off grid systems has been installed in overseas territories(Guiana,etc.)or in mainland mountainous areas.Self-consumption has now become the norm for residential systems,with 95%of newly commissioned systems(in cumulative power in the segment),compared to 70%in 2018 for this segment.There was strong growth across all segments,however large industrial and utility systems dominated once again,with 65%of installed power connected to the medium or high voltage grid,and residential systems accounting for less than 10%of installed volumes,despite a more Task 1 6 than doubling of quarterly volumes.Industrial and utility systems grew at a faster rate than other segments with installed capacity in these segments multiplied fourfold as compared to others where a doubling of capacity was witnessed.1.2 Total photovoltaic power installed With the combined increase in electricity consumption prices and costly grid connection costs for new distribution connection points,self-consumption models are growing across all segments.As such,the previous separation between centralised(no self-consumption)and decentralised(on buildings or with self-consumption)systems has become more difficult to define based only on systems power level.As such,the following segments,whilst informative,may be misleading as a growing capacity of self-consumption systems over 250 kVA are connected(50 MW reported in 2021,although current data collection practices are not adequate to quantify all systems with good accuracy).Centralized:any PV installation which only injects electricity and is not associated with a consumer(no self-consumption)over 250 kW.Decentralized:any PV installation which is embedded into a customers premises(either with or without self-consumption)under 250 kW.Cumulative PV installed capacity as of the end of 2021 reached 13 990 MW(AC Alternative Current)or roughly 16,5 GW DC.Data collection process Data supplied by all transmission and distribution grid managers is aggregated and published by the SDES:Service de la Donne et des Etudes Statistiques,Ministry for the Ecological and Inclusive Transition.Data is segmented by systems size(3 kW,9 kW,36 kW,100 kW,250 kW 2 475 8 915 Total 569 023 16450 Total Off-grid 30 Capacity of decommissioned PV systems during the year MW 0(estimated).Capacity of repowered PV systems during the year MW 0 to 10(estimated).Total capacity connected to the low voltage distribution grid MW 566 548 systems for 7 535 MW.Total capacity connected to the medium voltage distribution grid MW 2 386*systems for 7 700 MW DC(6 420 MW DC).Total capacity connected to the high voltage transmission grid MW 89 systems for 969 MW DC(807 MW AC).Unregistered capacity Analysis of the data from the 3 major sources(SDES,Enedis and the Register)indicates a missing capacity of approximately 500 MW AC in the Register,for systems connected to the medium and high voltage grid.As such,whilst total capacity would seem to be around 16,45 GW,the error margin is plus 0,5 GW/minus 1 GW.Sources:SDES,Registre national des installations de production et de stockage dlectricit(2021),Open data rseaux nergies(ODR)*Hespul extrapolations.Data has been converted from reported AC to DC power,with a standard ratio of 1,2(1,15 for systems over 250 kW),and rounded.Task 1 11 Table 6:PV power and the broader national energy market Data Year Total power generation capacities GW Total:139,07 GW of which Nuclear:61,37 GW;Fossil fuel:17,9 GW;RES:59,8 GW(see below)2021 Total renewable power generation capacities(including hydropower)GW PV*:13,1 GW;Hydro:25,7 GW;Wind:18,8 GW;Other RES:2,2 GW 2021 Total electricity demand TWh 468 TWh 2021 New power generation capacities installed GW Total:2,7 GW of which Gas: 0,496 GW;Coal:-1,16 GW;Diesel:0,0 GW;Nuclear:0 GW;PV and other RES:3,9 GW(see below)2021 New renewable power generation capacities(including hydropower)GW PV*: 2,69 GW;Wind: 1,19 GW;Hydro: 0,00 GW;Other RES: 0,06 GW 2021 Estimated total PV electricity production(including self-consumed PV electricity)in TWh PV:14,809 TWh 2021 Total PV electricity production as a%of total electricity consumption 3 21 Average PV yield in kWh/kW 1160 kWh/kW(30 with system losses(PV GIS)France mainland)Ranges from 900 kWh/kW to 1 550 kWh/kW(30 with system losses(PV GIS)continental France)2021 2021:RTE France Electricity Report 2021.*Data in this table is provided by RTE and provisional PV are AC power only.*Source:SDES,non-energy uses included.Task 1 12 1.3 Key enablers of PV development Table 7:Information on key enablers Description Annual Volume(Number of units)Total Volume Source Decentralized storage systems Systems connected to the low voltage distribution grid.Does not include data for overseas territories or systems connected to the medium voltage grid 6,66 MW for 830 systems on mainland 31,8 MW for 8 357 systems Enedis Open Data,EDF SEI Residential Heat Pumps Mono and multi-split reversible heat pumps 837 629 5 895 864 www.uniclima.fr Uniclima:Bilan 2021 et perspectives 2022 du gnie climatique Thermodynamic domestic water heater 150 615 868 386 Electric cars Cars&Lightweight utility vehicles 174 191 512 178 www.avere-france.org AVERE:Bilan 2021 Mobilit lctrique Hybrid rechargeable cars 141 787 274 096 Public charge points 20 931 53 667 www.avere-france.org AVERE:Bilan 2021 Infrastructures de recharge ouvertes au public Task 1 13 2 COMPETITIVENESS OF PV ELECTRICITY The past year was unprecedented for the competitiveness of photovoltaic electricity in France,as in much of Europe.Rising equipment costs due to follow on effects of COVID and economic growth(primary materials costs,supply chain disruptions,local and international growth markets)increased the cost of photovoltaic systems,with significant impacts on module and steel costs,amongst others.On the other hand,through 2021 market costs of electricity ballooned as gas prices rose on the back of strong economic growth and demand,leaving photovoltaic as an increasingly attractive source of electricity despite its concurrent,but lower,increased costs.Data on market prices is published irregularly,based on either surveys or,when published by the Energy Regulation Commission,data provided by tender candidates.2021 data are based on limited market surveys conducted for the purposes of this report,and due to the different factors disrupting the market,can only be used as a guide,with significant cost differences between early and late 2021,and even greater differences between prices quoted in 2021 for future systems,and prices paid in 2021 for systems reaching commissioning.Given the continued market tension in 2022,an indication of indicative costs can only be representative of a short time period,well under a year as such the level of uncertainty on the indicated costs is high.2.1 Module prices A 2019 study by the Energy Regulation Commission(CRE)provides the most recent large-scale survey of price breakdowns in France.The business plans in the CRE study include the module prices that the candidates expect to pay.The lead-time between project submission to the tender and module acquisition is generally between 16 and 18 months.Module costs reported below are average costs according to the expected commissioning year,and are differentiated according to the system size.This survey is still used as the basis for cost estimations and market reports by public and private organisations in France(including ADEME).Task 1 14 Table 8:Typical module prices(/Wp)for a number of years Year 2016 2017 2018 2019 Typical price of a standard module crystalline silicon 2020 Typical price of a standard module crystalline silicon 2021 Average module price(all technologies)for systems in Tenders 0,7/0,35-0,4*0,25 0,4 Average module price(all technologies)for systems in Building Applications PV Tenders Over 90%of modules in the survey were monocrystalline silicon 0,6 0,6 0,45 Average module price(all technologies)for systems in ground based PV Tenders 60%of modules in the survey were monocrystalline silicon,13%polycrystalline silicon and 27%thin film technologies 0,55 0,4 0,4 SOURCE:CRE“Cots et rentabilits du grand photovoltaque en mtropole continentale”,pvXchange and Hespul estimate.2021 data from Hespul limited market survey.2.2 System prices There is a wide range in turnkey prices,especially in the small to medium size segment.This range of prices is determined by the ease of installation(or the state of repair and complexity of the existing roof),the type of supporting structures needed,the complexity of the grid connection and the development time associated with these complexities.Through 2021,those companies working on residential and small scale systems generally maintained costs with small negative to small positive changes.Task 1 15 Table 9:Turnkey PV system prices of different typical PV systems Category/Size Typical applications and brief details Current prices/W Residential BAPV 250 kW Grid-connected,roof-mounted,distributed PV systems installed to produce electricity to grid-connected industrial buildings,warehouses,etc.Grid connection not included.0,8-1,1 Small centralized PV 1-10 MW Grid-connected,ground-mounted,centralized PV systems that work as central power station.The electricity generated in this type of facility is not tied to a specific customer and the purpose is to produce electricity for sale.With few exceptions,financed through competitive tender.0,5-0,9 Medium centralized PV 10-20 MW Grid-connected,ground-mounted,centralized PV systems that work as central power station.The electricity generated in this type of facility is not tied to a specific customer and the purpose is to produce electricity for sale.With few exceptions,financed through competitive tender.0,5-0,9 Parking canopies 5 to 10 MW Grid-connected,distributed PV systems installed over impermeable car parks to produce electricity to grid-connected industrial buildings,warehouses,etc.Financed through competitive tender.0,9 1,1 Floating centralised PV Financed through competitive tender.1 Task 1 16 SOURCE:FiT systems:estimation HESPUL from sources Hespul.Tenders source:CRE“Cots et rentabilits du grand photovoltaque en mtropole continentale”,Etude ADEME“Cots des nergies renouvelables et de rcupration en France”,HESPUL estimations.Table 10:National trends in system prices for different applications Year Residential BAPV Grid-connected,roof-mounted,distributed PV system 5-10 kW euro/W Small commercial BAPV Grid-connected,roof-mounted,distributed PV systems 10-100 kW euro/W Large commercial BAPV Grid-connected,roof-mounted,distributed PV systems 100-250 kW euro/W Centralized PV Grid-connected,ground-mounted,centralized PV systems 10-50 MW euro/W 2007 8,4 7,8 6,3 2008 8,2 7,6 6,2 2009 6,9 6,4 5,2 2010 5,9 5,5 4,5 2011 3,9 2,6 2 2012 3,7 2 1,6 2013 2,7 2 1,3 2014 2,6 2 1,3 2015 2,5 1,9 1,2 2016 2,41 1,58 1,1 2017 2,2 1,2 0,9-1,1 2018 2,2 1,2 0,7-0,9 2019 2 1,2 1,2 0,65 0,85 2020 1,9 1,1 0,9 0,65 0,85 2021 1,7 2,5 0,6 1,7 0,7 1,1 0,5 0,9 NOTE The table includes BIPV-IAB systems up to 3 kW until 2012,BIPV-IAB systems up to 9 kW from 2013 to 2016 and BAPV systems up to 9 kW since 2017.SOURCE:Previous IEA NSR-FR reports,limited market surveys by Hespul,VAT not included.*IAB:completely building integrated;*ISB:simplified building integration;BAPV building applied/roof top systems.Task 1 17 2.3 Cost breakdown of PV installations The Renewable Energy Trade Association(Syndicat des Energies Renouvelables,SER)study evaluating the contribution to renewable to the French economy,published in 2020,builds on the 2019 energy Regulation Commissions study on the cost of photovoltaics in France,with results as detailed below.This data is still used in national studies by private and public bodies as they are the most recent,comprehensive,publicly available studies.Limited market surveys have been used to evaluate the cost redistributions in the context of rising upstream costs as professionals responded to these events.Table 11:Cost breakdown for a grid-connected roof-mounted,distributed residential PV system of 5 to 10 kW Cost category Average/W Hardware Module 0,57 Inverter 0,27 Mounting material 0,32 Other electronics(cables,etc.),including installation 0,33 Subtotal Hardware 1,49 Soft costs Installation work(included in Other Hardware costs)Planning 0,1 Shipping and travel expenses to customer Customer acquisition Permits and commissioning(i.e.cost for electrician,etc.)Project margin Subtotal Soft costs 0,1 Grid connection 0 Total(excluding VAT)1,59 Average VAT 20%SOURCE:“valuation et analyse de la contribution des nergies renouvelables lconomie de la France et de ses territoires”SER/EY June 2021 market surveys(Hespul).For this segment,module and inverter prices are well above that of other segments;in France both distributors and installers add a margin to module costs.Task 1 18 Table 12:Cost breakdown for a grid-connected,ground-mounted,centralized PV systems of 10 MW Cost category Average/W Hardware Module 0,25 Inverter 0,06 Mounting material 0,16 Other electronics(cables,etc.),including installation 0,17 Subtotal Hardware 0,64 Soft costs Installation work(included in Other Hardware costs)Planning 0,13 Shipping and travel expenses to customer Customer acquisition Permits and commissioning(i.e.cost for electrician,etc.)Project margin Subtotal Soft costs 0,13 Grid connection 0,08 Total(excluding VAT)0,85 Average VAT 20%SOURCE:“valuation et analyse de la contribution des nergies renouvelables lconomie de la France et de ses territoires”SER/EY June 2021,Estimations by HESPUL Task 1 19 2.4 Financial Parameters and specific financing programs Table 13:PV financing information in 2021 Different market segments Loan rate%Average rate of loans residential installations 4%-7%over 12 years,slight reduction compared to 2020*Average rate of loans commercial installations From 1,1%to 1,5%for 12 to 18 years Average cost of capital industrial and ground-mounted installations 3%over 20 years*SOURCE:ADEME study“Cots des nergies renouvelables et de rcupration en France”2022,CRE“Cots et rentabilits du grand photovoltaque en mtropole continentale”,Statinfo Crdit la Conso and Crdit au SNF,Taux des crdits aux entreprises by Banque de France,estimation Hespul.*Rate of loans for residential applications are considered consumer credit which explains their relatively high level,well above home loans.*The ADEME study considers an average cost of capital for 2020 at 3,2%for 80bt financing,and 3,6%for 70bt financing,with a relative stability from 2019 to 2020;for the purposes of this report values from market surveys were included leading to slightly lower values.Interest rates for all sectors remained low and decreasing through 2021,albeit with slight rises in December for residentials.2.5 Specific investments programs Table 14:Summary of existing investment schemes Investment Schemes Introduced in France Third party ownership(no investment)Used for commercial and industrial systems(roof and land rental),but also to a lesser extent on new agricultural buildings.Renting A few small-scale operations in self-consumption models where building occupiers rent PV systems.This is a growth segment with high interest in 2021 as electricity prices rose.Leasing Leasing is a common financing instrument in France for commercial systems.“Sofergie”(Energy Financing Company)provide credit or leasing options for projects developed by municipalities,social housing organisations,commercial companies and agricultural companies.Financing through utilities Some electric utilities(more often their subsidiaries)develop and invest in PV systems,but they do not offer finance for third parties.Utilities can access all support mechanisms,including FiT and Tenders for systems that they develop or own.Task 1 20 Investment in PV plants against free electricity(See self-consumption).Crowd funding(investment in PV plants)Crowd-funding generally finances debt through crowd-funding platforms,however some platforms allow for equity financing.Changes to the bonus mechanisms in the new PPE2 Tenders have resulted in a significant shift from citizen investment and governance to debt crowdfunding.Community solar Yes International organization financing No The main financing organizations are commercial banks(both French and foreign),debt funds(French and foreign insurers)and institutional lenders(European and national).Cleantech investments in France grew again in 2021,and whilst the RES sector was overtaken by the circular economy sector,growth in the RES sector was spectacular with a doubling of investments to nearly 600 million(not including hydrogen).The largest operation in the RES sector was Neon,with 255 million euro raised with cleantech funds(for a total of 600 million in the operation)towards its investment 2021-2025 program.Portfolio financing Portfolio financing/refinancing and large or utility-scale projects can make use of the European Investment Bank(European long-term investment fundEIB)offers.The EIB supports a number of renewable energy source(RES)investments funds available for photovoltaics projects.The EIB approved a number of credit lines to local financing organisation within different mechanism including the Private Finance for Energy Efficiency(PF4EE)collateral agreement,the CALEF-PAN-EUROPEAN RENEWABLE ENERGY FL and SAAR LB CLIMATE ACTION MBIL II loans(respectively 200 million euros and 150 million euros for small to medium projects).Other major actors include La Banque des Territoires(Caisse des Dpts)and its subsidiary Bpifrance.Project financing Project financing,classically used for infrastructure projects,is based on project cash flows repaying project debt and equity.Project financing for privately owned projects is available through both commercial banks and bpifrance,a public investment bank.Public authorities can access financing from public long-term investors such as the Caisse des Dpts(Deposits and Consignments Fund).Project financing is also available through Sofergies-financial institutions that provide debt financing or leasing options for energy efficiency and renewable energy projects by Task 1 21 municipalities,social housing organisation,commercial companies and agricultural companies.Bpifrance has increased volumes available for project financing as part of its 2021-2024,building on its regional presence to identify local requirements.Community solar(citizen investment)Citizen investment is mobilised through specific citizen RES funds and crowdfunding platformsfinancing both equity and debt.The principal organisations active in channelling citizen investment are crowdfunding platforms(debt and equity investments)and Energie Partage.Energy Partage collected 2,2 million euros in 2021.30 new solar community projects for 22,6 MW were commissioned in 2021,bringing the total since inception up to 76 MW,representing 15 million euros in direct community investment for systems ranging from small 9 kW projects to multi-MW ground-based systems.Crowdfunding Crowdfunding projects once again increased in volume in 2021,with,for the first time,more crowdfunding equity than debt for renewable energy projects within the framework of the competitive Tenders.Financing of photovoltaics through crowdfunding:Roof-mounted systems:33 million euros raised for 258 MW across 151 projects;Ground-based systems:68 million euros raised for 1 344 MW across 151 projects;Floating systems:1 million euros raised for 30 MW across 3 projects.Residential project financing Residential systems are financed through different schemes:100%owner capital,home renovation loans or consumer credit loans.Task 1 22 2.6 Additional Country information Table 15:Country information Retail electricity prices for a household Time of use contracts available.Eurostat Band DC(2500 kWh consumption 5000 kWh)202,2/MWh all taxes and levies included.Retail electricity prices for a commercial company Time of use contracts available.Eurostat Band IB(20 MWh consumption 500 MWh):130/MWh excluding VAT and other recoverable taxes and levies:154/MWh all taxes and levies included.Eurostat Band IC(500 MWh consumption 2000 MWh):100/MWh excluding VAT and other recoverable taxes and levies:120,7/MWh all taxes and levies included.Retail electricity prices for an industrial company Time of use,demand response,peak shaving contracts available.Eurostat Band ID(2000 MWh consumption 20000 MWh):88,2/MWh excluding VAT and other recoverable taxes and levies;104,7/MWh all taxes and levies included.Liberalization of the electricity sector Frances electricity industry is highly concentrated but not vertically integrated in theory.However,in practice,EDF,(the state holds over 80%of EDF share capital)and its different wholly or partially owned subsidiary companies are the principal generator(over 80%of electricity production),transport grid manager(100%),distribution grid manager(over 95%of grid subscribers)and retailer(over 75%of retail customers).SOURCE:INSEE,CRE,Eurostat nrg_pc_204 and(nrg_pc_205)2021S2.Task 1 23 3 POLICY FRAMEWORK This chapter describes the support policies aiming directly or indirectly to drive the development of PV.Direct support policies have a direct influence on PV development by incentivizing or simplifying or defining adequate policies.Indirect support policies change the regulatory environment in a way that can push PV development.Table 16:Summary of PV support measures Category Residential Commercial Industrial Centralized Measures in 2021 On-going New On-going New On-going New Feed-in tariffs Yes Yes(changes to Feed in Tariff conditions)Yes,(competitive Tenders)Yes(Open access Feed in Tariffs up to 500 kW)-Feed-in premium(above market price)-Yes,(competitive Tenders)Yes,(competitive Tenders)Capital subsidies-Yes,some regions.Terminated in 2021-Green certificates-Renewable portfolio standards(RPS)-Income tax credits-Self-consumption Yes-Yes-Net-metering-Net-billing Yes Yes(Changes to Feed in Tariff conditions)Yes Yes(Feed in Tariffs up to 500 kW)-Task 1 24 Collective self-consumption and virtual net-metering Yes-Yes-Sustainable building requirements Yes-Yes Yes(changes to conditions for mandatory solar/living roofs,threshold lowered to 500 m2 and new types of buildings under obligation)-BIPV incentives-Yes(cumulative with Feed in Tariffs)-Yes(cumulative with Feed in Tariffs for up to 500 kW)-3.1 National targets for PV The framework for developing photovoltaics policies in France falls within the long term National Low Carbon Strategy(SNBC,2050 horizon)and the 10-year Energy Programme Decree(PPE).The current PPE,published in 2020,targets 3 GW to 5 GW a year new capacity,to reach 20 GW in 2023 and 35 GW to 44 GW in 2028.The PPE authorizes competitive tenders as the preferred mechanism to reach these goals if market forces are insufficient.The government has signalled a real desire to meet the PPE targets,publishing an Action Plan to accelerate the development of photovoltaics in November.This plan includes a possible feed in tariff for ground-based systems under 500 kW on wasteland,1 000 projects on public land and buildings,a reduction in upfront grid connection costs and simplifications to administrative procedures.The national environmental agency,ADEME,the national Transport network operator and an independent organisation ngaWatt all published possible future energy scenarios in 2050,and all scenarios had a common element of high photovoltaics volumes needed in France by 2050,with volume ranging from 90 GW to nearly 200 GW an indication of the accepted level of investment required from both the public and private sectors.3.2 Direct support policies for PV installations The measures summarized in table 16,and their effectiveness,are described below.Task 1 25 Support measures include,for individual self-consumed electricity from systems under 1 MW,exemption from the tax surcharges,local electricity and grid taxes and VAT(these taxes and levies normally represent approximately 30%of a consumers electricity bill).Property tax exemptions for agricultural and public-sector buildings equipped with photovoltaic systems are also in place,and thermal and environmental building regulations that should encourage the use of photovoltaics on new buildings.3.2.1 Open volume feed-in tariffs for BAPV Feed-in tariffs and net-billing tariffs are segmented according to system size and decrease each trimester,with the decrease pegged to grid connection requests for previous trimesters.For overseas regions,the tariffs are adapted to regional irradiation levels.Tables 17 and 18 detail 4th quarter 2021 tariff levels.A new framework from October 2021 for feed in tariffs for systems up to 500 kW(up from 100 kW)on buildings,greenhouses and parking canopies on mainland France includes differentiated tariffs depending on system size,and lump sums for smaller self-consumption systems(with net-billing)as well as specific building integrated products.Systems may now participate in collective self-consumption projects,and changes have improved access to tariffs for systems on publicly owned buildings.Mandatory 550 kg CO2/kW maximum carbon footprint for modules in systems between 100 kW and 500 kW.Table 17 Feed-in Tariff and Tender remuneration levels Mainland France Tariff category Power of PV installation Tariff Q4 2021*(EUR/MWh)Continental France building applied PV Ta(no self-consumption)3 kW 178,9 Ta(no self-consumption)3 kW to 9 kW 152,1 Tb(no self-consumption)9 kW to 36 kW 108,9 Tb(no self-consumption)36 kW to 100 kW 94,7 Tc(with or without self-consumption)100 kW to 500 kW 98,0*For projects that will be built in 2022 or first semester 2023.Task 1 26 Table 18:Feed-in Tariff and Tender remuneration levelsOverseas France Tariff category Power of PV installation Tariff Q4 2021(EUR/MWh)Tariff base 8,12 Sample system in Guadeloupe 2 kW 186,5 Sample system in Corsica 8 kW 146,3 Sample system in Runion 50 kW 130,0 Power factor 3 kW 3 kW to 9 kW 9 kW to 36 kW 36 kW to 100 kW 1,35 1,2 1,1 1 0=8,12 x 1,35 x location factor=8,12 x 1,2 x location factor=8,12 x 1,1 x location factor=8,12 x 1x location factor=0 Location factor Guadeloupe&Martinique Corsica Runion French Guiana Mayotte 17 15 16 18 19=8,12 x 17 x power factor=8,12 x 15 x power factor=8,12 x 16 x power factor=8,12 x 18 x power factor=8,12 x 19 x power factor Note:To calculate overseas tariffs,multiply the trimestral tariff base by the power factor and a location factorfor exact tariffs,refer to CRE publications.Note:there is also a time-based compensation for grid manager commanded disconnections.3.2.2 Feed-in tariffs and Feed-in premiums in competitive tenders Volume capped periodic competitive tenders for systems from 500 kW to 30 MW(no size limit for ground-based systems on waste land)are segmented according to size and application(building applications,ground based etc.).Eight competitive tenders were held in 2021 in mainland France,whilst the target volume was over 2,3 GW,only 2,02 GW of projects were awarded:656 MW for building applied,1,34 GW for ground-based systems,and 25 MW self-consumption systems.3.2.3 BIPV development measures The new feed in tariff framework published in October 2021 included an investment bonus for systems up to 500 kW using one of 4 approved,certified BIPV products.To be paid in 5 yearly instalments,the investment bonus is available for a maximum of 145 MW of projects over 2 years(30 MW in 2022,115 MW in 2023)on a first come first served basis.The bonus can by combined with the partial self-consumption bonus and feed in tariffs/net billing.Task 1 27 Table 19 Feed-in Tariff BIPV bonus Mainland France System size Bonus for grid connection request in the first period from 09/10/2021 au 08/10/2022,capped at 30 MW Bonus for grid connection request in the second period from 09/10/2022 au 08/10/2023,capped at 115 MW 100 kW 0,238 EUR per W installed 0,133 EUR per W installed 100 kW to 250 kW 0,235 EUR per W installed 0,128 EUR per W installed 250 kW to 500kW 0,233 EUR per W installed 0,125 EUR per W installed A number of indirect measures included reducing the threshold for mandatory solar or living roofs for commercial and industrial buildings or covered car parks to those occupying 500 m2 of ground surface(down from 1 000 m2)and including new types of buildings.Actual thermal regulations,and incentive high-performance building labels encourage photovoltaics and self-consumption as electricity consumed and exported from the building can be integrated in building performance calculations.In particular,the“Btiments Energie Positive et Rduction Carbone(E /C-)”label currently prefigures future building thermal regulation that will come into force in 2022.The future regulation includes a new set of criteria on energy and carbon,also applied to photovoltaics equipment.3.3 Self-consumption measures Table 20:Summary of self-consumption regulations for small private PV systems in 2021 PV self-consumption 1 Right to self-consume Individual self-consumption:the PV generator can be the consumer or a third-party owner.Participation in a collective self-consumption operation is limited to 3 use cases(see below):Virtual net-metering(virtual battery storage):the consumer must be the PV generator.2 Revenues from self-consumed PV Lump-sum for partial self-consumption systems in association with net-billing FiT.Winning candidates in the Self-Consumption Tender(systems from 500 kW to 10 MW)will receive a bonus on self-consumption at the tendered rate.Self-consumed electricity is not subject to tax for individual self-consumption.However,collective self-consumption is subject to tax.For individual self-consumption and in case of partial self-consumption,installed capacity is subject to capacity taxes,such as grid taxes.Task 1 28 3 Charges to finance Transmission,Distribution grids&Renewable Levies Systems with total self-consumption pay no connection or annual grid access costs.Systems in collective self-consumption systems pay grid connection costs and annual access fees.Excess PV electricity 4 Revenues from excess PV electricity injected into the grid Net-billing set by FiT(6,9,8 or 10 c/kWh depending on system size),or by Tender specifications(FiT or wholesale market premium)or by PPA(Power Purchase Agreement).This does not apply to collective self-consumption.5 Maximum timeframe for compensation of fluxes 30 minutes.6 Geographical compensation(virtual self-consumption or metering)Called“collective self-consumption”in France.Participation in a collective self-consumption operation is limited to 3 use cases:Default case:PV installations and consumers located in the same building.This opens the possibility for the participation of medium voltage connected PV installations;Extended case:PV installations and consumers connected to the low voltage grid within a distance of 2 km of each other;Exceptional case:PV installations and consumers within a distance of 20 km,where the low population and building density requires an exceptionally large perimeter;In all case,generators(s)and consumers(s)must be linked through a common legal entity.Compensation on a 30 minute time-step.Other characteristics 7 Regulatory scheme duration 20 years for surplus(net-billing)sold in FiT,10 years in Self-Consumption Tender.8 Third party ownership accepted Third party ownership is allowed.9 Grid codes and/or additional Grid connection fees for systems over 36 kVA.Task 1 29 taxes/fees impacting the revenues of the prosumer No grid access fees for total self-consumption systems.Reduced grid access fees for partial self-consumption systems(with net-billing).Energy taxes will apply in the case of collective self-consumption but not for individual self-consumption,even if the PV system is owned by a third-party.10 Regulations on enablers of self-consumption(storage,DSM)Electricity storage is considered as both a consumer and a generator when integrated into collective self-consumption.11 PV system size limitations Automatic grid connection limited to systems 36 kVA with no surplus injections and no grid feesother systems require approval.Systems size limited on buildings for access to net-billing(500 kW)and lump-sum(100 kW)within FiT framework.Systems must be between 500 kW to 10 MW to be eligible for the new 2021-2026 competitive tenders.In the case of“extended”collective self-consumption projects,the total PV volume is limited to 3 MW mainland and to 0,5 MW(power is expressed in peak DC power)in non-interconnected territories.12 Electricity system limitations Mainland,no limits.In overseas territories(ZNI),self-consumption systems must respect the same capacity and disconnect limits as feed-in systems(i.e.active capacity must not go over 30%(or as specified in the regional energy planning decree)of consumption(with the objective of raising this threshold to 45%by 2023),grid manager disconnects on a first installed-last disconnected priority order).13 Additional features Markets sales of surplus in the framework of Tenders require access to an Aggregator/Balancing Responsible Party.Collective self-consumption systems may now access FiT for excess production sales(changed in October 2021).Several virtual battery storage offers are available.Task 1 30 3.3.1 Net-billing feed-in tariff and lump sum for BAPV systems under 100 kW Table 21:Net billing Feed-in Tariffs for BAPV systems Tariff category Power of PV installation Net-billing tariff( lump sum)Q4 2021(EUR/MWh)Continental France building applied PV Pa(net-billing)3 kW 100( 0,38 EUR/W installed)Pa(net-billing)3 kW to 9 kW 100( 0,29 EUR/W installed)Pb(net-billing)9 kW to 36 kW 60( 0,16 EUR/W installed)Pb(net-billing)36 kW to 100 kW 60( 0,08 EUR/W installed)Tc(net-billing)100 kW to 500 kW 98(no lump sum)3.3.2 Net-billing with feed-in premium Winning candidates in the new 2021-2026 framework for Self-Consumption Tender(systems from 500 kW to 10 MW from November 2021,up from the 100 kW to 1 MW range in the previous tenders)receive a bonus on self-consumption at the tendered rate plus net-billing set by tender specifications(wholesale market premium).3.4 Collective self-consumption,community solar and similar measures 3.4.1 Collective self-consumption(PV systems for several apartments in the same building)The legal framework surrounding collective self-consumption in France is that of virtual self-consumption within a building,a 2 km,or exceptionally,a 20 km geographical perimeter.Where generators and consumers are in the same building,the PV installation can be connected to the medium voltage grid.In other cases,installations are connected to the low voltage grid and are limited to a total of 3 MW.Virtual metering is implemented by the grid manager and requires smart meters on all generation and consumption sites.Each operation must have a legal entity,whose primary role is to supply the grid manager with algorithms or rules defining the distribution of the PV power,and an updated list of registered members of the operation.By the end of 2021,with a total of 3,8 MW across 77 projects,849 consumers and 128 generators were involved.Economic models for self-consumption systems are uncertain,as the competitivity of the self-consumed electricity is very dependent on consumer electricity costs.In other words,grid parity is reached in certain sectors,and not in others.In October 2021 the new rules for access to feed in tariffs and net billing tariffs included changes that allow systems to access the feed in tariffs/net billing tariffs for excess production from collective self-consumption systems.However,in this case the system may not benefit Task 1 31 from any other form of public subsidy which were necessary to compensate the organisational and administrative over costs of collective self-consumption systems.3.4.2 Solar Community Solar communities(or citizen investment)continue to grow,with a specialised fund and regional and national networks supporting the inception and development of projects.The national government included the development of community solar as a priority in its renewable energy plan launching an awareness raising campaign including a dedicated section hosted on the Ministry for Ecological Transitions website,whilst it continues to maintain support,through ADEME,for the not-for-profit organisation Energie Partage that coordinates and disseminates information and tools.Work is on-going for the creation of the legal framework for citizen and renewable energy communities in France.3.5 Tenders,auctions&similar schemes Competitive tenders are the chosen tool for the French government to encourage the development of photovoltaic systems,although projects are increasingly developed outside of the framework in PPAs considering the ballooning market cost of electricity.The Minister of Ecological Transition establishes the Tender specifications,the CRE(Energy Regulator)manages the Tenders and transmits a list and analysis of the highest-ranking candidates to the Minister,who then determines and publishes the winning candidates.Since 2016,the winners of the calls for tenders are no longer supported by a feed-in-tariff but by a contract for difference mechanism(CfD).With the CfD,the generators of photovoltaic electricity sell their production on the market,and when the reference market costs are under the tendered costs,they receive additional remuneration from the state which compensates for the difference between the market price and the tendered cost.Conversely,when the reference market costs are above the tendered costs,operators are required to pay the difference back to the state.With the unprecedented rise in market costs in late 2021,the prices on the electricity market have become much higher than the tendered prices.As a result,whilst the generators concerned have seen their revenues increase from their sales on the market,a significant portion of this revenues is paid to the state under the CfD mechanism.Not only does the French state not subsidise these contracts for those months,but it also receives a portion of the revenues generated by photovoltaics.The CRE publishes a summary analysis after tenders are awarded,making available aggregated and comparative information on the provenance of materials,average bids,etc.A new Tenders framework was initially planned for 2020 but was pushed back to late 2021,with several tenders being held under the previous framework in 2021.By October and the publication of feed in tariffs for systems up to 500 kW,the new Tender framework(called PPE2)was ready for deployment,with a first round of tenders for building applied systems in October,self-consumption systems in November,and for ground-based systems in December.Tender selection criteria are on a lowest price basis for commercial and self-consumption systems,but price weighted with additional environmental or land use criteria(low module carbon footprints and degraded urbanised sites are benefited),or even innovation levels,for larger systems.The conditions for the PPE2 tenders were a continuation of the revised conditions for the last PPE1 Tenders.Task 1 32 The Energy Minister establishes the Tender specifications,the CRE(Energy Regulator)manages the tenders and transmits a list and analysis of the highest-ranking candidates to the Minister,who then determines and publishes the winning candidates.Remuneration(through Feed-in PPA,Feed-in premiums,bonuses etc.)is paid to operators by EDF(or,in certain areas,local public distribution grid managers,or other authorised organisations).The CRE publishes a summary analysis after tenders are awarded,making available aggregated and comparative information on the provenance of materials,average bids,etc.There were 8 national call for tenders in mainland France over 2021,including the innovation tender,and no tenders in the overseas territories.The 2021 mainland tenders were nearly all under-subscribed,with the exception of those for ground-based systems and the first building applied tender of the year,with a particularly low under 25%for the last self-consumption tender.Two factors contributed to this-the sharp rise in electricity prices,meaning no subsidy is needed in most cases,and a change in the specification requiring a unicity of the legal entities of the consumer and the generator,with significant impacts on the fiscalism of the self-consumed electricity when third party investors are involved.Table 22:Results for the last rounds of the 2017-2021 competitive tenders System type and size Building mounted systems,greenhouses and parking canopies Building mounted systems Ground-based systems and parking canopies Building mounted systems for self-consumption Individual system size limits 100 kW to 500 kW 500 kW to 8 MW Ground:500 kW to 30 MW Canopies:500 kW to 10 MW 100 kW to 1 MW Volume 1 175 MW in 11 calls of 75 MW to 150 MW 1 200 MW in 11 calls of 75 MW to 150 MW 5,78 GW in 9 calls of 330 MW to 850 MW 450 MW in 12 calls of 20 to 50 MW Remuneration type PPA*CfD*CfD*Self-consumption bonus on self-consumption CfD Number of Bids 12 and 13th calls:238 MW selected for 507 MW of bids 12 and 13th calls:188 MW selected for 260 MW of bids 10th call:637 MW selected for 1 014 MW of bids 10th call:17 MW selected for 25 MW of bids Average tendered price(or bonus for self-consumption)13th call:86,02 EUR/MWh 13th call:76,66 EUR/MWh 10th call:56,64 EUR/MWh 10th call:10,45 EUR/MWh*PPA=Power Purchase Agreement at tendered rate.Contract with an obligated purchaser,the PPA being guaranteed by the French government.*CfD=Contract for Difference=Market sales Additional Remuneration;Contract at tendered rate.Task 1 33 Table 23:PPE2(2021-2026)competitive tender volumes and results System type and size Building mounted systems,greenhouses and parking canopies Ground-based systems and parking canopies Building mounted systems for self-consumption Innovative solar systems Technology neutral Individual system size limits From 0,5 MW No upper limit 0,5 MW to 30 MW No upper limit on degraded sites 0,5 MW to 10 MW 100 kW 3 MW(Building mounted)500 kW 3 MW(Ground based)Volume 4,2 GW to 5,6 GW in 14 calls of 300 MW to 400 MW 9.25 GW in 10 calls of 925 MW 0,7 GW in 14 calls of 50 MW 0,4 GW in 5 calls of 80 MW(Building mounted)0,3 GW in 5 calls of 60 MW(Ground based)2,5 GW in 5 calls of 500 MW Number of Bids 1st call:157 MW selected for 268 MW of bids 1st call:705 MW selected for 845 MW of bids 1st call:7 MW selected for 11 MW of bids First results not available First results not available Average tendered price(or bonus for self-consumption)1st call:86,53 EUR/MWh 1st call:58,84 EUR/MWh 1st call:12,85 EUR/MWh-All systems are remunerated through CfD=Contract for difference=Market sales Additional Remuneration;Contract at tendered rate.Task 1 34 3.6 Other utility-scale measures including floating and agricultural PV These systems are financed through competitive tenders,generally in a specific call for innovative systems.The national Agency for Ecological Transition(ADEME)commissioned a study to define agrivoltaics(or agriphotovoltaics),with a wide participation across the industry and the agricultural sectors.Whilst the study and recommendation were completed in September 2021,it was not published until mid-2022 after extensive high-level discussion.Agrivoltaic and floating systems were developed and commissioned in 2021,financed through the Innovation competitive tenders.3.7 Retroactive measures applied to PV 3.7.1 Renegotiation of tariffs for systems above 250 kW with tariffs from 2006 and 2010 Following on from the 2020 announcement,contractual negotiations were held through 2021 to revise support levels,by negotiating,on an individual basis,the level of remuneration for systems over 250 kW.Benefitting from 2006 and 2010 feed in tariffs.Full data on the number of contracts re-negotiated has not yet been made public.3.8 Indirect policy issues 3.8.1 Rural electrification measures Rural electrification in France is primarily concentrated in overseas territories and isolated alpine areas.Overseas territories include remote or difficult to access zones with small villages with either no mini-grid or fossil fuel powered mini-grids,particularly in French Guiana and the island of Reunion.The national budget includes a line dedicated to off grid production in rural areas,with a 1 M budget in 2021,equivalent to the 2020 budget.In parallel,budgets are available for indirect measures such as electric vehicle charging points,partially financing grid connection in weak networks for renewable energies,storage and other innovations.3.8.2 Support for electricity storage and demand response measures There are no universal support mechanisms for electricity storage in France.However,public demand has seen a slow development in both the residential and commercial sectors,despite the low economic returns.Large scale storage In mainland France,by the end of 2021 about 115 storage facilities are connected to the medium-voltage grid with a capacity of 145 MW.60%of the cumulated installed capacity was commissioned in 2021.According to the National Registry for Generators and Storage,only three of these storage facilities are listed as being associated with photovoltaic systems connected to the medium voltage grid.Four projects for 23 MW total were commissioned in 2021 in overseas territories.Task 1 35 Individual/small scale storage Conditions are not favourable for the development of small-scale storage in France(no subsidies,previously relatively low electricity consumption costs and winter peak consumption profiles on mainland France).There were about 11 000 storage facilities in France(8 200 on the mainland)on residential or small-scale installations.After a peak of 2 500 new installations per year in 2018 and 2019,the rate of installation continued to decrease through 2020 and down to 830 on mainland France in 2021.Demand Response Measures Time-of-use electricity rates are offered to consumers in France,with a particular emphasis on displacing winter peak consumption to late night/early morning.France has very high winter evening peak demand,reflecting the high penetration of resistive electric heating.Demand response mechanisms(flexibility)include both reduction and increases in consumption to respond to specific conditions either through equipment shutdown or storage;given the habitual consumption profile and nuclear generation capacity in France,most is for reducing demand.Projects offering less than 1 MW of flexibility must be aggregated with other projects,but projects offering over 1 MW can be certified individually.In November 2020 the government announced the results of the competitive tenders for demand response measures to provide primary reserve production capacity for 2021.These Tenders are an explicit support measure for the development of demand response capacity.In 2021,there were 50 successful projects for 1,5 GW of capacity,doubling the 2020 volumes.3.9 Financing and cost of support measures Operator remuneration(through feed-in tariffs,Additional remuneration market premium,bonuses etc.)is paid to operators by a designated Co-contractor(EDF,other authorised organisations or,in certain areas,local public distribution grid managers).The Co-contractor is compensated for over-costs from a dedicated account in the national Budget(Energy Transition).This account is financed by a tax on petrol and its derivatives when used as an energy source for transport or heating.Over-costs are calculated based on a typical production curve weighting of monthly average day time spot prices on the national electricity market.The estimated total cost of compensation for 2021 for photovoltaic contracts(feed-in tariffs and premiums)for continental France is 2 706,2 M EUR(source annual finance law 2022,national government).Much of this cost finances contracts signed in 2009 and 2010.With the increase in market costs for electricity,over costs have reduced and led to twice-revised estimates for the 2021 cost of support measures.With market costs expected to remain high(roughly 4 times their 2019 level),the cost of support measures for new photovoltaics is increasingly marginal and recent and new contract for systems within competitive tenders may just reimburse a large part of previous costs over the coming years.Task 1 36 4 INDUSTRY 4.1 Production of feedstocks,ingots and wafers(crystalline silicon industry)Table 24:Silicon feedstock,ingot and wafer producers production information for 2021.Manufacturers Process&technology Estimated Total Production Photowatt EDF ENR PWT mc-Si wafers MW 75 MW Photowatt EDF ENR PWT is a vertically integrated manufacturer,manufacturing its own cells,wafers and modules.Its processes produce monocrystalline bricks(Crystal Advanced Process).Its subsidiary,Photowatt Crystal Advanced(in partnership with CSI and ECM Greentech),is specialised in low carbon production of advanced technology silicon ingots and wafers.The COVID crisis in 2020-2021 has impacted the strategic position of EDF with regards to Photowatt,and is likely to result in ownership or operational changes in 2022.Irysolar,part of the ECM Greentech group,focuses on supplying photovoltaic equipment manufacturing for the end-to-end value chain,from ingots to cells.4.2 Production of photovoltaic cells and modules(including TF and CPV)Module manufacturing is defined as the industry where the process of the production of PV modules(the encapsulation)is done.A company may also be involved in the production of ingots,wafers or the processing of cells,in addition to fabricating the modules with frames,junction boxes etc.The manufacturing of modules may only be counted to a country if the encapsulation takes place in that country.Task 1 37 Table 25:PV cell and module production and production capacity information for 2021 Cell/Module manufacturer Technology(sc-Si,mc-Si,a-Si,CdTe,CIGS)Production and/or capacity(MW/year)Cell Module Wafer-based PV manufactures EDF ENR PWT(Photowatt)sc-Si 2 2 Reden Solar sc-Si 90 Recom Sillia sc-Si 300 Stile sc-Si 15 Systovi sc-Si 80 Sunpower(Total)sc-Si 80 VMH Energies sc-Si 60 Voltec Solar sc-Si 200 Thin film manufacturers ARMOR OPV 40 40 Dracula Technologies OPV/Totals Approximately 850 MW Sources:Le photovoltaque:choix technologiques,enjeux matires et opportunits industrielles,French Ministry of Energy and Environment;interviews with manufacturers and Hespul treatment.The national industry is relatively small,with several manufacturers targeting specific niche markets,often related to building integration products(PV tiles,faade elements),PV/thermal hybrid modules(Dualsun,Systovi)or small-scale production runs and pre-industrial research(Photowatt,Irysolar).This industry operates with strong public R&D/industry links.In the past years,several manufacturers have increased their production capacity based on the favourable market visibility given by the national competitive tenders.However,this situation tends now to become less favourable as observed in the heavy decrease of French modules share in the results of 2019 and 2021 competitive tenders.Small-scale producers of modules dedicated to the national or western market:Recom Sillias Lannion site production has a 300 MW/year capacity;Sunpower(Total Group subsidiary)has two factories in France:Tenesol Technologies in Toulouse and SunPower Manufacturing de Vernejoul,Moselle,and manufactures modules from PV laminates.The modules use single-crystal silicon back-contact cells manufactured by overseas Sunpower factories,with industry high Task 1 38 performances of up to 24%.The two factories have a production capability around 40 MW each.The manufacturer announced at the end of 2021 the conversion of the Vernejoul line to the production of Maxeon air modules with the objective of producing 100 MW/year by 2023.The silicon modules should be much lighter than conventional modules,with the possibility of being glued directly to the waterproofing of roofs whose structure is too weak for conventional systems;Voltec Solar assembles modules on their Alsace site,its production capacity is 200 MW/year,with the objective of doubling this capacity and producing heterojunction modules.The company has launched the Belenos project with Systovi,which aims to reach a cumulative capacity of 1 GW/year for both manufacturers;Reden Solar manufactures modules,but also develops and operates photovoltaic power plants.Its semi-automated and automated production lines manufacture modules but also PV powered streetlamps,street furniture and solar thermal equipment;VMH Energies production site is located in Chtellerault near Poitiers.Its production capacity is 60 MW per year.Integrated cells and modules manufacturers:Photowatt/EDF ENR PWTs Bourgoin Jailleu site,has an R&D cells and modules production site with a capacity of 2 MW per year.Photowatt/EDF ENR PWT now concentrates on research and development to“foster the emergence of new technological solutions”and test them in pre-industrial conditions.Other markets:Photovoltaic tiled roofs,photovoltaic thin films and aero-voltaic modules:Systovi assembles monocrystalline modules.It mainly manufactures PV/thermal hybrid modules(hot air).Its manufacturing facilities are located at Carquefou,close to Nantes.The company,owned by the Cetih group,invested in a new production line with a capacity of 65 MW/year.It is also considering expansion to 200 MW/year with the possibility of using heterojunction technology.The company has launched the Belenos project with Voltec,which aims to reach a cumulative capacity of 1 GW/year for both manufacturers;STile develops a 15 MW pilot line where their proprietary“i-Cells”are assembled into modules since early 2017.The company develops a line of modules from 25 W to 200 W with customised formats for BIPV or off grid applications,such as integration into streetlights.They have a small range of standardised modules targeting high end building integration clients;ARMOR develops proprietary organic“ASCA”films,targeting the market for connected devices,wearable photovoltaics as well as building integration applications(semi-transparent glazing),with a manufacturing capacity of 1 million m2/year.The company invested 10 million euros a year in R&D and its production capacity;Dracula Technologies is a start-up developing printed organic photovoltaic cells(trademarked LAYER technology)aimed at the connected device market.Its pilot line was inaugurated in September 2019;Solems SA manufactures thin-film elements and modules up to 30 cm x 30 cm for connected devices and self-powered automates and building elements;SolarCloth develops flexible solar on different supports for integration onto canvas(tourism and agricultural uses)and vehicle roofs(with Renault Trucks).Task 1 39 Other operators such as Edilians,manufactures PV tiles(size 45 cm 31 cm and 136 cm 50 cm respectively),while DualSun develops and markets photovoltaic-thermal hybrid modules(PV-T).The Norwegian manufacturer REC was planning to build a heterojunction module factory in France with a capacity of 2 GW/year(in 2022)then 4 GW/year(in 2025).This production site,planned in Moselle,could produce the equivalent of Frances needs to meet the Energy Programme Decree,however the project seems to have stalled in 2021 without any official announcements.4.3 Manufacturers and suppliers of other components Balance of system component manufacture and supply is an important part of the PV system value chain.There are a number of French companies with an international presence providing a full range of electrical solutions for connection,conversion and management of photovoltaic systems.The France solar industry initiative is designed to showcase French know how across all solar technologies,and members are present from upstream(research and machine tools)all the way through the value chain from industry to support,installation and O&M.PV inverters(for grid-connection and stand-alone systems)Only a small handful of inverter manufacturers are French a large multinational with a complete offer(string and centralised inverters),and other manufacturers with a small range of products targeting specific markets with(off grid,on grid,storage).Storage batteries Market penetration remains very low for residential systems,although offers are present,and whilst national industry has international players(SAFT,EDF),deployment of large-scale storage is limited mostly to overseas territories,although some projects on the mainland are supplying flexibility measures.Supporting structures A number of local manufactures of supporting structures exist;products range from PV tiles(Edilians,SunStyle),roof integration supports(IRFTS,bought by Edilians in early 2022 and GSE),pergolas(Mitjavila,Adiwatt)and residential car ports(IRFTS,Adiwatt,Carport Solaire).Solar parking supports are designed and manufactured by a number of companies present,with a range of materials used(wood,steel,aluminium).Manufacturers of on-roof systems for industrial metallic roofs and bituminous or polymer roofs are also present,including Dome Solar,Solapro,Arcelor or Soprasolar.A number of manufacturers of solar support buildings(agricultural hangars,greenhouses)are also present(Mecosun)although rising and fluctuating steel costs have led to much uncertainty over 2021.With a unique lead on the international market,Ciel&Terre is a leading designer and manufacturer of floating photovoltaic supports and systems.Task 1 40 5 PV IN THE ECONOMY This chapter aims to provide information on the benefits of PV for the economy.5.1 Labour places Table 26:Estimated PV-related full-time labour places in 2021 Market category Number of full-time labour places Research and development(not including companies)500 Manufacturing of products throughout the PV value chain from feedstock to systems,including company R&D 700 Distributors of PV products and installations 5 100*Other 3 300*Total 9600 Sources:Etude ADEME“Marchs et emplois concourant la transition nergtique dans le secteur des nergies renouvelables et de rcupration”(2021),valuation et analyse de la contribution des EnR lconomie de la France et des territoires 2020,SER and Hespul estimates(*).While jobs related to the manufacture of photovoltaic equipment,R&D or the installation of photovoltaic systems are stagnating,those dedicated to project development,studies and operations are growing rapidly due to the almost threefold increase in installed capacity compared to previous years.The rapid growth of the sector,and the lack of qualified manpower,has led to tensions in recruitment.Conversely,material shortages at the end of the year led some companies to significantly reduce their activity,even putting some employees on reduced hours.The most recent Renewable Energy Market and Employment Study was published in 2021 and covers 2019 direct employment data.This data has been completed and updated based on market evolutions in 2021.Other studies indicate a total of 17 000 direct and indirect jobs without providing a breakdown between the different market segments.Task 1 41 5.2 Business value In 2021,the installed capacity has tripled compared to previous years.This boom in the French market is also reflected in the estimated value of the PV business,which has also increased almost threefold,with little change in the unit costs of the PV systems compared to previous years.Investments and turnover are studied by ADEME every two years in the study“Marchs et emplois lis lefficacit nergtique et aux nergies renouvelables“.The market value for 2021(below)has been estimated based on 2021 trending prices and extrapolated official 2021 grid connection volumes.Data accuracy may be compromised by the use of trends costs(these costs are from a reduced sample across France and may not accurately reflect real costs)and the volume estimate spread across segments for Industrial systems with power above 250 kW and ground-mounted systems.An EY study commissioned by the French Renewable Energy Trade Association estimates the added value of the sector at 1,4 billion euros in 2021,but does not give a breakdown of the wealth created by power segment.EYs estimate is the result of macro-economic modelling,based on an input-output table(IOT)considering imports and exports for each segment of the value chain.Their estimate is likely to be more accurate than the one presented below,however the one below remains relevant as a first approach and is sufficient to compare with other PVPS countries.The following table represents the value of investments in PV systems.Table 27:Rough estimation of the value of the PV business in 2021(VAT is excluded)Sub-market Capacity installed in 2021 MW Average price/W Estimated value M EUR Off-grid Residential 3 kW 85 2,4 200 Residential 9 kW 151 2,1 320 Commercial 100 kW 699 1,15 800 Commercial 250 kW 904 0,95 860 Grid-connected distributed 2 036 1,16 2 360 Grid-connected centralized 1 315 0,7 920 Estimated Value of PV investments in 2021 3 000 to 3 500*SOURCE:SDES,ObservER Baromtre lectrique 2021,France Terre Solaire Bilan 2021*estimate HESPUL,Etude ADEME“Marchs et emplois concourant la transition nergtique dans le secteur des nergies renouvelables et de rcupration”(2021),valuation et analyse de la contribution des EnR lconomie de la France et des territoires 2020 SER,Cots des nergies renouvelables et de rcupration 2019 ADEME.*A range is published due to the approximate nature of data.Task 1 42 6 INTEREST FROM ELECTRICITY STAKEHOLDERS 6.1 Structure of the electricity system With a highly concentrated electricity EDF,(the state holds over 80%of EDF share capital)and its different wholly or partially owned subsidiary companies are the principal generator,transport grid manager,distribution grid manager and retailer.In response to the open market European Directives,the different entities are legally separate,with grid management missions run as“delegated public services”.The EDF group has an extensive portfolio of nuclear and renewable energy sites.Secondary operators include the generator Engie(the state holds over 20%of the share capital)and municipal DSOs(they cover about 5%of the population).The National Energy Regulator,Commission de rgulation de lnergie(CRE)is an independent administrative authority and supervises market regulations,grid access conditions and manages competitive tender processes based on rules established by the government.They also judge grid access conflicts and are a mandatory consultative body for changes to the legislative and regulatory energy framework.6.2 Interest from electricity utility businesses In France the only private electricity utility is EDF(the state is the majority owner with over 80%of share capital),that covers 95%of the population-all other utilities are(generally very small)public entities a legacy of the post-war nationalisation of private electricity companies.EDF and its subsidiary companies are major players in photovoltaics,with branches dedicated to different market segments present in France and across the world.EDF Renouvelables(EDF Renewable for the international branch centralised photovoltaics),EDF Renouvelables Services(O&M services in Europe),EDF Energie Nouvelles Rparties(EDF ENR-residential and small commercial systems),Sunzil(operating in the Caribbean and other isolated/off grid areas)are all active in France.EDF Store&Forecast provides software solutions for piloting renewables and storage.EDF EN Photowatt is a photovoltaics manufacturer.EDF is also active in R&D activities through both EDF internal research departments,research partnerships with public research organisations and Photowatt.Through its different subsidiaries,EDF has a worldwide portfolio of 43,6 GW of solar projects in early and late stage development,compared to 8 GW in construction and 6 GW already installed(total or partial ownership)of which there is nearly 400 MW in France(proportional to ownership).ENGIE is a gas utility also present in the development and generation of electricity capacity-and has the biggest solar portfolio in France at around 1 GW(3 GW worldwide).6.3 Interest from municipalities and local governments Almost all local authorities have climate energy plans that are generally ambitious in terms of photovoltaic development.This is one of the reasons why municipalities and local governments continue to be active participants in the growth of photovoltaics in France,both investing in projects,experimenting innovative projects(particularly collective self-consumption),and facilitating citizen investment and grid integration.Many have created public-private development and investment companies to both facilitate project development without the constraints of public procurement,but also serve as a vehicle for their projects.Task 1 43 7 HIGHLIGHTS AND PROSPECTS 7.1 Highlights With the publication of future development scenarios,new frameworks for feed in tariffs,building integrated photovoltaics and competitive tenders,more new buildings falling under mandatory solar roofs requirements,new targets for solar on public buildings and an awareness raising campaign for community solar,and record new capacity,2021 was a busy year for solar in France.The national energy Programme Decree(PPE)for photovoltaics targets 20,6 GW of photovoltaics in 2023 and a 2028 target of 35,6 GW to 44,5 GW.Long term scenarios were established by both the national transport system owner(RTE)and environmental agency(ADEME),highlighting the need for at least 70 GW and up to 200 GW in 2050 if carbon neutrality is to be achieved by then.In 2021,national photovoltaic capacity grew by a nearly unprecedented 3,3 GW DC,(triple the 2020 volume,up from 1 GW),for a cumulative capacity of nearly 17 GW DC for grid connected installations.More than 2/3 of new capacity is industrial and utility scale systems.Approximately 10%of the new capacity is with some form of self-consumption and although self-consumption models remain marginal for industrial systems,over 90%of capacity for new residential and small(under 100 kW)commercial systems have self-consumption,generally associated with feed in tariffs for net billing.In France projects progress from gaining urban planning approval(permitting)to entering the grid connection queue to commissioning.Over 4 GW DC of new projects entered the grid connection queue in 2021,bringing the queue to around 10 GW DC of projects,including nearly 3 GW with DSO contracts.The new framework for feed in tariffs led to an explosion in the number of grid connection requests in the newly accessible 100 kW to 500 kW segment,with the previous quarterly volumes of between 30 MW and 80 MW ballooning to 700 MW in the 4th quarter,after the new framework came into effect.With longer lead times than smaller projects,and time to prepare,grid managers have been mostly able to treat the requests in a timely manner.7.2 Perspectives Worldwide tension in the solar supply markets will impact new capacity in 2022,with strong demand from the local market as electricity costs soar exacerbating long delivery times for inverters and continued rising module costs.Project developers have either put off projects as the new materials costs outstrip any possibility of a profit margin,or on the contrary sped up projects where possible to beat future rising costs,leaving the market hard to predict.The newly opened segment of systems 100 kW to 500 kW will likely drive the market in late 2022,with around 600 MW that should be ready for commissioning late 2022 or early 2023 if installers can access modules and inverters,but many industry actors consider that 2022 installed capacity is likely to fall far short of 2021s over 3 GW,because of rising costs and supply chain issues.Task 1 1

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国际能源署 (IEA)：2022 年世界能源展望报告（英文版）（524 页）.pdf

World EnergyOutlook 2022The IEA examines the full spectrum of energy issues including oil,gas and coal supply and demand,renewable energy technologies,electricity markets,energy efficiency,access to energy,demand side management and much more.Through its work,the IEA advocates policies that will enhance the reliability,affordability and sustainability of energy in its 31 member countries,11 association countries and beyond.Please note that this publication is subject to specific restrictions that limit its use and distribution.The terms and conditions are available online at www.iea.org/t&c/This publication and any map included herein are without prejudice to the status of or sovereignty over any territory,to the delimitation of international frontiers and boundaries and to the name of any territory,city or area.Source:IEA.International Energy Agency Website:www.iea.orgIEA member countries:Australia Austria Belgium CanadaCzech Republic Denmark Estonia Finland France Germany Greece Hungary Ireland ItalyJapanKorea Lithuania Luxembourg Mexico Netherlands New Zealand Norway Poland Portugal Slovak Republic Spain Sweden Switzerland Republic of TrkiyeUnited Kingdom United StatesThe European Commission also participates in the work of the IEAIEA association countries:INTERNATIONAL ENERGYAGENCYArgentinaBrazilChinaEgyptIndiaIndonesiaMoroccoSingaporeSouth AfricaThailandUkraineIEA.CC BY 4.0.Foreword 3 ForewordToday,theworldisinthemidstofthefirsttrulyglobalenergycrisis,withimpactsthatwillbefeltforyearstocome.RussiasunprovokedinvasionofUkraineinFebruaryhashadfarreachingimpactsontheglobalenergysystem,disruptingsupplyanddemandpatternsandfracturinglongstandingtradingrelationships.Thecrisisisaffectingallcountries,butattheInternationalEnergyAgency(IEA),weareparticularlyconcernedabouttheeffectitishavingonthepeoplewhocanleastaffordit.OneofthestrikingfindingsinthisyearsWorldEnergyOutlook(WEO)isthatthecombinationoftheCovidpandemicandthecurrentenergycrisismeansthat70millionpeoplewhorecentlygainedaccesstoelectricitywilllikelylosetheabilitytoaffordthataccessand100millionpeoplemaynolongerbeabletocookwithcleanfuels,returningtounhealthyandunsafemeansofcooking.Thatisaglobaltragedy.Anditisnotonlyanenergycrisiswithwhichwearedealing:manycountriesalsofaceafoodsecuritycrisisandincreasinglyvisibleimpactsofclimatechange.Astheworldfacesthisunprecedentedenergyshockandtheotheroverlappingcrises,weneedtobeclearonhowwegothereandwhereweneedtogo.TheanalysisinthisOutlookisparticularlyimportanttoshedlightonthesequestionsandtodispelsomeofthemistakenandmisleadingideasthathavearisenaboutthisenergycrisis.Forexample,thereisamistakenideathatthisissomehowacleanenergycrisis.Thatissimplynottrue.Theworldisstrugglingwithtoolittlecleanenergy,nottoomuch.Fastercleanenergy transitions would have helped to moderate the impact of this crisis,and theyrepresentthebestwayoutofit.Whenpeoplemisleadinglyblameclimateandcleanenergyfortodayscrisis,whattheyaredoingwhethertheymeantoornotisshiftingattentionawayfromtherealcause:RussiasinvasionofUkraine.Anothermistakenideaisthattodayscrisisisahugesetbackforeffortstotackleclimatechange.TheanalysisinthisOutlookshowsthat,infact,thiscanbeahistoricturningpointtowardsacleanerandmoresecureenergysystemthankstotheunprecedentedresponsefromgovernmentsaroundtheworld,includingtheInflationReductionActintheUnitedStates,the Fit for 55 package and REPowerEU in the European Union,Japans GreenTransformation(GX)programme,Koreas aim to increase the share of nuclear andrenewablesinitsenergymix,andambitiouscleanenergytargetsinChinaandIndia.Atthesametime,Iamworriedthattodaysmajorglobalenergyandclimatechallengesincreasetheriskofgeopoliticalfracturesandnewinternationaldividinglinesespeciallybetweenadvancedeconomiesandmanyemerginganddevelopingeconomies.Unityandsolidarityneedtobethehallmarksofourresponsetotodayscrisis.ThatisthecaseforEuropeduringwhatpromisetobetoughwintersnotonlythisyearbutalsonext.Anditistrueglobally.ThisWEOunderscoresthatsuccessfulenergytransitionsmustbefairandinclusive,offeringahelpinghandtothoseinneedandensuringthebenefitsofthenewenergyeconomyaresharedwidely.Evenascountriesstruggletomanagethebrutalshocksfromthecrisis,theIEA.CC BY 4.0.4 International Energy Agency|World Energy Outlook 2022 lastthingweshoulddoisturninwardsandawayfromsupportingeachother.Instead,weneedtoworktogethertobuildtrust.TheIEAiscommittedtocontinuingtoplayacentralroleinthisbyhelpinggovernmentstodefinetheactionsthatareneededtoenabletheworldtoconfrontoursharedenergyandclimatechallengestogether.Inthis,weareguidedbytheIEAsworldclassenergymodellingandanalysisunderpinnedbyunparalleleddatathatisexemplifiedbytheWorldEnergyOutlook.Forthis,IwouldliketowarmlythanktheexcellentIEAteamthathasworkedskilfullyandtirelesslyundertheoutstandingleadershipofmycolleaguesLauraCozziandTimGouldto produce another essential and timely Outlook that I hope will help decisionmakersgloballytonavigatethecurrentcrisisandmovetheworldtowardsamoresecureandsustainablefuture.DrFatihBirolExecutiveDirectorInternationalEnergyAgencyIEA.CC BY 4.0.Acknowledgements 5AcknowledgementsThisstudywaspreparedbytheWorldEnergyOutlook(WEO)teamintheDirectorateofSustainability,TechnologyandOutlooks(STO)incooperationwithotherdirectoratesandofficesoftheInternationalEnergyAgency(IEA).ThestudywasdesignedanddirectedbyLauraCozzi,ChiefEnergyModellerandHeadofDivisionforEnergyDemandOutlook,andTimGould,ChiefEnergyEconomistandHeadofDivisionforEnergySupplyandInvestmentOutlooks.ThemodellingandanalyticalteamsforthisWEO2022wereledbyStphanieBouckaert(demand),JonathanCoppel(investment and finance),ChristopheMcGlade(supply),ThomasSpencer(climate and environment),BrentWanner(power)and DanielWetzel(sustainabletransitions).KeycontributionsfromacrosstheWEOteamwerefrom:OskarasAlauskas(transport),LucilaArboleyaSarazola(investment and finance),YasmineArsalane(leadoneconomicoutlook,power),BlandineBarreau(recoveryplan),SimonBennett(colead on hydrogen,energy technologies),CharlneBisch(datamanagement),JustinaBodlkov(employment),OliviaChen(employment),YunyouChen(power),DanielCrow(leadonbehaviour,airpollution),DavideDAmbrosio(leadondatascience,power),AmritaDasgupta(criticalminerals),TanguyDeBienassis(investmentandfinance),TomsdeOliveiraBredariol(leadoncoal,methane),MichaelDrtil(powerandelectricity networks),DarlainEdeme(Africa),MusaErdogan(fossil fuel subsidies,datamanagement),EricFabozzi(power and electricity networks),VctorGarcaTapia(datascience,buildings),PabloGonzlez(investmentandfinance),TimothyGoodson(leadonbuildings),EmmaGordon(investmentand finance),JrmeHilaire(leadonoilandgassupply modelling),PaulHugues(lead on industry),JacobHyppoliteII(energy access),BrunoIdini(transport),GeorgeKamiya(energy technologies,digitalisation),HyejiKim(transport),TaeYoonKim(leadonenergysecurityandcriticalminerals),MartinKueppers(industry),TobiasLechtenbohmer(industry),LauraMaiolo(oil and gas supply),OrlaMcAlinden(behaviour),YannickMonschauer(affordability),ToruMuta(leadonfossilfuel subsidies),PaweOlejarnik(supply modelling),DianaPerezSanchez(industry),ApostolosPetropoulos(leadontransport),MariachiaraPolisena(power),RyszardPospiech(leadoncoalsupplymodelling,datamanagement),ArthurRog(buildings),MaxSchoenfisch(power),RebeccaSchulz(oil and gas supply),LeonieStaas(buildings,behaviour),GianlucaTonolo(leadonenergyaccess),WonjikYang(datavisualisation)andPeterZeniewski(lead on gas).Other contributions were from NiccolHurst andCarloStarace.MarinaDosSantosandEleniTsoukalaprovidedessentialsupport.EdmundHoskercarriededitorialresponsibility.DebraJustuswasthecopyeditor.Colleagues from the Energy Technology Policy(ETP)Division led by Head of DivisionTimurGlcoleadonmodellingandanalysis,withoverallguidancefromAraceli Fernandez Pales and Uwe Remme.Peter Levi,Tiffany Vass,Alexandre Gouy,Leonardo Collina and Faidon Papadimoulis contributed to the analysis on industry.IEA.CC BY 4.0.6 International Energy Agency|World Energy Outlook 2022JacobTeter,LeonardoPaoli,ElizabethConnellyandEktaBibracontributedtotheanalysisontransport.ChiaraDelmastroandMartinHusekcontributedtotheanalysisonbuildings.StavroulaEvangelopoulou,FrancescoPavan,AmaliaPizarroandAmarBhardwajcontributedto the analysis on hydrogen.Praveen Bains contributed to the analysis on biofuels.MathildeHuismanscontributedtodatascience.OtherkeycontributorsfromacrosstheIEAwere:AliAlSaffar,HeymiBahar,ChiaraDAdamo,CarlosFernndezAlvarez,DavidFischer,InhoiHeo,JinsunLim,LucaLoRe,RebeccaMcKimm,JeremyMoorhouse,KristinePetrosyan,GabrielSaiveandTalyaVatman.Valuable comments and feedback were provided by other senior management andnumerousothercolleagueswithintheIEA.Inparticular,MaryWarlick,KeisukeSadamori,NickJohnstone,AmosBromhead,TorilBosoni,JoelCouse,PaoloFrankl,BrianMotherway,Aad Van Bohemen,Rebecca Gaghen,An Fengquan,Sara Moarif,Hiro Sakaguchi andJacobMessing.ThanksgototheIEAsCommunicationsandDigitalOfficefortheirhelpinproducingthereportandwebsitematerials,particularlytoJadMouawad,FabienBarau,CurtisBrainard,AdrienChorlet,JonCuster,ClaireDehouck,AstridDumond,TanyaDyhin,MerveErdem,Grace Gordon,Barbara Moure,Jethro Mullen,Isabelle NonainSemelin,Julie Puech,ClaraVallois,GregoryViscusiandThereseWalsh.IvoLetraandBenMcCullochprovidedessentialsupporttotheproductionprocess.IEAsOfficeoftheLegalCounsel,OfficeofManagementandAdministrationandEnergyDataCentreprovidedassistancethroughoutthepreparationofthereport.Valuableinputtotheanalysiswasprovidedby:DavidWilkinson(independentconsultant).Valuableinputtothemodellingonairpollutionandassociatedhealthimpactswasprovidedby Peter Rafaj,Gregor Kiesewetter,Wolfgang Schpp,Chris Heyes,Pallav Purohit,LauraWarnecke,AdrianaGomezSanabriaandZbigniewKlimont(InternationalInstituteforAppliedSystemsAnalysis).Valuableinputtothemodellingandanalysisofgreenhousegasemissions from land use and bioenergy production was provided by Nicklas Forsell,AndreyLessaDerciAugustynczik,PekkaLauri,MykolaGusti,ZuelcladyAraujoGutierrezandPetrHavlk(InternationalInstituteforAppliedSystemsAnalysis).Theworkcouldnothavebeenachievedwithoutthesupportandcooperationprovidedbymany government bodies,organisations and companies worldwide,notably:Enel;Eni;EuropeanUnion(GlobalPublicGoodsandChallengesProgramme);HitachiEnergy;Iberdrola;JupiterIntelligence;MinistryofEconomy,TradeandIndustry,Japan;MinistryofEconomicAffairsandClimatePolicy,theNetherlands;TheResearchInstituteofInnovativeTechnologyfortheEarth,Japan;Shell;SwissFederalOfficeofEnergy;andToshiba.TheIEACleanEnergyTransitionsProgramme(CETP),particularlythroughthecontributionsoftheAgenceFranaisedeDveloppement,Italy,Japan,theNetherlands,SwedenandtheUnitedKingdomsupportedthisanalysis.ThanksalsogototheIEAEnergyBusinessCouncil,IEACoalIndustryAdvisoryBoard,IEAEnergyEfficiencyIndustryAdvisoryBoardandtheIEARenewableIndustryAdvisoryBoard.IEA.CC BY 4.0.Acknowledgements 7PeerreviewersManyseniorgovernmentofficialsandinternationalexpertsprovidedinputandreviewedpreliminarydraftsofthereport.Theircommentsandsuggestionswereofgreatvalue.Theyinclude:KeigoAkimotoResearchInstituteofInnovativeTechnologyfortheEarth,JapanVenkatachalamAnbumozhiEconomicResearchInstituteforASEANandEastAsia(ERIA)DougArentNationalRenewableEnergyLaboratory(NREL),UnitedStatesNeilAtkinsonIndependentconsultantAndreyAugustynszikInternationalInstituteforAppliedSystemsAnalysis(IIASA)PeterBachDanishEnergyAgencyShanBaoguoStateGridEnergyResearchInstitute,ChinaManuelBaritaudEuropeanInvestmentBankPaulBaruyaWorldCoalAssociationTomBastinUKDepartmentforBusiness,EnergyandIndustrialStrategy(BEIS)HarmeetBawaHitachiEnergyLeeBeckCleanAirTaskForceChristianBessonIndependentconsultantSamaBilbaoyLeonWorldNuclearAssociationJorgeBlazquezBPJasonBordoffColumbiaUniversity,UnitedStatesMickBuffierGlencoreNickButlerKingsCollegeLondonBenCahillCenterforStrategicandInternationalStudies(CSIS),UnitedStatesDianeCameronNuclearEnergyAgencyKimballChenGlobalLPGPartnershipDrewClarkeAustralianEnergyMarketOperatorRebeccaCollyerEuropeanClimateFoundationRussellConklinUSDepartmentofEnergyAnneSophieCorbeauColumbiaUniversityIanCronshawIndependentconsultantHelenCurrieConocoPhillipsFrancoisDassaEDFRalfDickelOxfordInstituteforEnergyStudies,UnitedKingdomGilesDicksonWindEuropeZuzanaDobrotkovaWorldBankLynetteDrayUniversityCollegeLondonCodyFinkeBrimstoneEnergyNikkiFisherThungelaIEA.CC BY 4.0.8 International Energy Agency|World Energy Outlook 2022 JustinFloodDeltaElectricityNicklasForsellIIASADavidFritschUSEnergyInformationAdministrationHiroyukiFukuiToyotaMikeFulwoodNexantDavidG.HawkinsNaturalResourcesDefenseCouncil(NRDC)DolfGielenInternationalRenewableEnergyAgency(IRENA)AndriiGritsevskyiInternationalAtomicEnergyAgency(IAEA)MichaelHackethalMinistryforEconomicAffairsandIndustry,GermanyYuyaHasegawaMinistryofEconomy,TradeandIndustry,JapanSaraHastingsSimonUniversityofCalgaryColinHendersonCleanCoalCentreJamesHendersonOxfordInstituteforEnergyStudies,UnitedKingdomMasazumiHironoTokyoGasTakashiHongoMitsuiGlobalStrategicStudiesInstitute,JapanJanHeinJesseJOSCOEnergyFinanceandStrategyConsultancySohbetKarbuzMediterraneanObservatoryforEnergyRafaelKaweckiSiemensEnergyMichaelKellyWorldLPGAssociationNobuyukiKikuchiMinistryofForeignAffairs,JapanKenKoyamaInstituteofEnergyEconomics,JapanJimKraneBakerInstituteforPublicPolicyAtsuhitoKurozumiKyotoUniversityofForeignStudies,JapanSarahLadislawRockyMountainInstituteFranciscoLaveronIberdrolaJoyceLeeGlobalWindEnergyCouncilLeeLevkowitzBHPLiJiangtaoStateGridEnergyResearchInstitute,ChinaLiuXiaoliEnergyResearchInstitute,NationalDevelopmentandReformCommission,ChinaPierreLaurentLucilleEngieMalteMeinshausenUniversityofMelbourne,AustraliaAntonioMerinoGarciaRepsolMichelleMichotFossBakerInstituteforPublicPolicyCristobalMillerDepartmentofNaturalResources,CanadaVincentMinierSchneiderElectricTatianaMitrovaSIPACenteronGlobalEnergyPolicySimoneMoriENELPeterMorrisMineralsCouncilofAustraliaSteveNadelAmericanCouncilforanEnergyEfficientEconomy,UnitedStatesIEA.CC BY 4.0.Acknowledgements 9 JanPetterNoreNoradAndiNoviantoCoordinatingMinistryforEconomicAffairs,IndonesiaStefanNowakTechnologyCollaborationProgrammeonPhotovoltaicPowerThomasNowakEuropeanHeatPumpAssociationKentaroOePermanentDelegationofJapantotheOECDPakYongdukKoreaEnergyEconomicsInstituteIgnacioPerezArriagaComillasPontificalUniversitysInstituteforResearchinTechnology,SpainStephaniePfeiferInstitutionalInvestorsGrouponClimateChangeCdricPhilibertFrenchInstituteofInternationalRelations,CentreforEnergy&ClimateElbietaPiskorzMinistryofClimateandEnvironment,PolandVickiPollardDGforClimateAction,EuropeanCommissionAndrewPurvisWorldSteelJasonRandallDepartmentofNaturalResources,CanadaSethRobertsSaudiAramcoTonyRookeGlasgowFinancialAllianceforNetZeroAprilRossExxonMobilYaminaSahebOpenEXP,IPCCauthorJuanBautistaSnchezPeuelaLejarragaPermanentRepresentationofSpaintotheEuropeanUnionHansWilhelmSchifferWorldEnergyCouncilSandroSchmidtPolarGeologyFederalInstituteforGeosciencesandNaturalResources,GermanyRobertSchwiersChevronAdnanShihabEldinIndependentexpertJesseScottDeutschesInstitutfrWirtschaftsforschung(GermanInstituteforEconomicResearch)SimonaSerafiniENIMariaSiciliaEnagsPaulSimonsYaleUniversityJimSkeaImperialCollegeLondon,IPCCCoChairWorkingGroupIIIAshleySteelFoodandAgricultureOrganizationoftheUnitedNationsJonathanSternOxfordInstituteforEnergyStudies,UnitedKingdomWimThomasIndependentconsultantNikosTsafosGeneralSecretariatofthePrimeMinisteroftheHellenicRepublicJamesTurnureUSEnergyInformationAdministrationFridtjofFossumUnanderAkerHorizonsNoVanHulstInternationalPartnershipforHydrogenandFuelCellsintheEconomyDavidVictorUniversityofCalifornia,SanDiego,UnitedStatesIEA.CC BY 4.0.10 International Energy Agency|World Energy Outlook 2022 AndrewWalkerCheniereEnergyPeterWoodShellChristianZinglersenEuropeanUnionAgencyfortheCooperationofEnergyRegulatorsTheworkreflectstheviewsoftheInternationalEnergyAgencySecretariat,butdoesnotnecessarilyreflectthoseofindividualIEAmembercountriesorofanyparticularfunder,supporterorcollaborator.NoneoftheIEAoranyfunder,supporterorcollaboratorthatcontributed to this work makes any representation or warranty,express or implied,inrespectoftheworkscontents(includingitscompletenessoraccuracy)andshallnotberesponsibleforanyuseof,orrelianceon,thework.Thisdocumentandanymapincludedhereinarewithoutprejudicetothestatusoforsovereigntyoveranyterritory,tothedelimitationofinternationalfrontiersandboundariesandtothenameofanyterritory,cityorarea.Commentsandquestionsarewelcomeandshouldbeaddressedto:LauraCozziandTimGouldDirectorateofSustainability,TechnologyandOutlooksInternationalEnergyAgency9,ruedelaFdration75739ParisCedex15FranceEmail:weoiea.orgMoreinformationabouttheWorldEnergyOutlookisavailableatwww.iea.org/weo.IEA.CC BY 4.0.TABLE OF CONTENTSTABLE OF CONTENTSIEA.CC BY 4.0.PART A:OVERVIEW AND CONTEXT Overview and key findingsSetting the scenePART B:ROADMAP TO NET ZERO EMISSIONSAn updated roadmap to Net Zero Emissions by 2050PART C:KEY ENERGY TRENDS Energy security in energy transitionsOutlook for energy demandOutlook for electricityOutlook for liquid fuelsOutlook for gaseous fuelsOutlook for solid fuels2983121181233277325365409ANNEXES429IEA.CC BY 4.0.14 World Energy Outlook 2022 Foreword3Acknowledgements5Executivesummary19PartA:Overviewandcontext27Overviewandkeyfindings291.1 Introduction321.2 Causesofthecrisisandimmediateconsequences331.2.1Causesofthecrisis331.2.2Immediateconsequences361.3 Outlookforenergymarketsandsecurity421.3.1Trendsandvulnerabilitiesacrosstheenergymix441.3.2Isamessytransitionunavoidable?581.4 Outlookforenergytransitions631.4.1Selectedcountryandregionaltrends661.4.2Keepingthedoorto1.5Copen72Settingthescene832.1 Introduction862.2 Backgroundtotheglobalenergycrisis872.2.1Initialsignsofstrain872.2.2RussiasinvasionofUkraine882.2.3Economicconsequences922.3 Wheredowegofromhere?972.3.1Investmentandtraderesponses972.3.2Policyresponses1022.3.3WorldEnergyOutlook2022scenarios1052.4 Inputstothescenarios1072.4.1Economicandpopulationassumptions1072.4.2Energy,mineralandcarbonprices1102.4.3Technologycosts115PartB:Roadtonetzeroemissions119AnupdatedroadmaptoNetZeroEmissionsby2050121Introduction124123IEA.CC BY 4.0.Table of Contents 15 NetZeroEmissionsScenario1253.1Emissionsandtemperaturetrends1253.2Energytrends1283.3Fuelsupply1333.4Electricitygeneration1363.5Industry1413.6Transport1463.7Buildings150Keythemes1553.8Avoidinggrowthinenergydemand1553.9Whatarethepublicandprivateinvestmentsneededto2030?1633.10Canwerampuplowemissionstechnologiesfastenough?1663.11Energyemployment:anopportunityandabottleneckintheNZEScenario175PartC:Keyenergytrends179Energysecurityinenergytransitions181Introduction184Tenessentialsforsecureenergytransitions1864.1Synchronisescalinguparangeofcleanenergytechnologieswithscalingbackoffossilfuels1864.2Tacklethedemandsideandprioritiseenergyefficiency1914.3Reversetheslideintoenergypovertyandgivepoorcommunitiesaliftintothenewenergyeconomy1954.4Collaboratetobringdownthecostofcapitalinemergingmarketanddevelopingeconomies2004.5Managetheretirementandreuseofexistinginfrastructurecarefully,someofitwillbeessentialforasecurejourneytonetzeroemissions2044.6Tacklethespecificrisksfacingproducereconomies2094.7Investinflexibilityanewwatchwordforelectricitysecurity2144.8Ensurediverseandresilientcleanenergysupplychains2174.9Fostertheclimateresilienceofenergyinfrastructure2234.10Providestrategicdirectionandaddressmarketfailures,butdonotdismantlemarkets228Conclusion2324IEA.CC BY 4.0.16 World Energy Outlook 2022 Outlookforenergydemand233Introduction236Scenarios2365.1Overview2365.2Energydemand2415.3Emissions2495.4Airpollution2555.5Investment257Keythemes2595.6Energyaccess2595.7Efficientcoolingforawarmingworld2665.8Bringingforwardthepeakinoiluseforroadtransport272Outlookforelectricity277Introduction280Scenarios2816.1Overview2816.2Electricitydemand2836.3Electricitysupply2906.4COemissionsfromelectricitygeneration3036.5Investment305Keythemes3076.6Powersystemflexibilityiskeytoelectricitysecurity3076.7Electricitynetworksarethebackboneofcleanpowersystems3126.8Criticalmineralsunderpinfuturecleanelectricitysystems318Outlookforliquidfuels325Introduction328Scenarios3297.1Overview3297.2Oildemandbyregionandsector3317.3Oilsupply3367.4Oiltrade3417.5Oilinvestment3427.6Liquidbiofuels3437.7Lowemissionshydrogenbasedliquidfuels345567IEA.CC BY 4.0.Table of Contents 17 Keythemes3477.8Oiluseinplastics3477.9Arenewconventionaloilprojectsananswertotodaysenergycrisis?3527.10Refining:immediateandlongertermchallenges357Outlookforgaseousfuels365Introduction368Scenarios3698.1Overview3698.2Gasdemand3728.3Gassupply3778.4Gastrade3818.5Investment383Keythemes3868.6OutlookfornaturalgasintheEuropeanUnionafterRussiasinvasionofUkraine3868.7Scalinguphydrogen3958.8IsnaturalgasstillatransitionfuelinemergingmarketanddevelopingeconomiesinAsia?402Outlookforsolidfuels409Introduction411Scenarios4129.1Overview4129.2Coaldemand4149.3Coalsupply4189.4Coaltrade4219.5Coalinvestment4229.6Solidbioenergy423Annexes429AnnexA.Tablesforscenarioprojections431AnnexB.Designofthescenarios463AnnexC.Definitions485AnnexD.References505AnnexE.InputstotheGlobalEnergyandClimateModel51789IEA.CC BY 4.0.Executive Summary 19 ExecutiveSummaryRussiasinvasionofUkrainehassparkedaglobalenergycrisisTheworldisinthemidstofitsfirstglobalenergycrisisashockofunprecedentedbreadthandcomplexity.PressuresinmarketspredatedRussiasinvasionofUkraine,butRussiasactionshaveturnedarapideconomicrecoveryfromthepandemicwhichstrainedallmannerofglobalsupplychains,includingenergyintofullblownenergyturmoil.Russiahasbeenbyfartheworldslargestexporteroffossilfuels,butitscurtailmentsofnaturalgassupplytoEuropeandEuropeansanctionsonimportsofoilandcoalfromRussiaareseveringoneofthemainarteriesofglobalenergytrade.Allfuelsareaffected,butgasmarketsaretheepicentreasRussiaseeksleveragebyexposingconsumerstohigherenergybillsandsupplyshortages.Pricesforspotpurchasesofnaturalgashavereachedlevelsneverseenbefore,regularlyexceedingtheequivalentofUSD250forabarrelofoil.Coalpriceshavealsohitrecordlevels,whileoilrosewellaboveUSD100perbarrelinmid2022beforefallingback.Highgasandcoalpricesaccountfor90%oftheupwardpressureonelectricitycostsaroundtheworld.TooffsetshortfallsinRussiangassupply,Europeissettoimportanextra50billioncubicmetres(bcm)ofliquefiednaturalgas(LNG)in2022comparedwiththepreviousyear.ThishasbeeneasedbylowerdemandfromChina,wheregasusewasheldbackbylockdownsandsubduedeconomicgrowth,buthigherEuropeanLNGdemandhasdivertedgasawayfromotherimportersinAsia.Thecrisishasstokedinflationarypressuresandcreatedaloomingriskofrecession,aswellasahugeUSD2trillionwindfallforfossilfuelproducersabovetheir2021netincome.Higherenergypricesarealsoincreasingfoodinsecurityinmanydevelopingeconomies,withtheheaviestburdenfallingonpoorerhouseholdswherealargershareofincomeisspentonenergyandfood.Some75millionpeoplewhorecentlygainedaccesstoelectricityarelikelytolosetheabilitytopayforit,meaningthatforthefirsttimesincewestartedtrackingit,thetotalnumberofpeopleworldwidewithoutelectricityaccesshasstartedtorise.Andalmost100millionpeoplemaybepushedbackintorelianceonfirewoodforcookinginsteadofcleaner,healthiersolutions.Facedwithenergyshortfallsandhighprices,governmentshavesofarcommittedwelloverUSD500billion,mainlyinadvancedeconomies,toshieldconsumersfromtheimmediateimpacts.Theyhaverushedtotryandsecurealternativefuelsuppliesandensureadequategasstorage.Othershorttermactionshaveincludedincreasingoilandcoalfiredelectricitygeneration,extendingthelifetimesofsomenuclearpowerplants,andacceleratingtheflowofnewrenewablesprojects.Demandsidemeasureshavegenerallyreceivedlessattention,butgreaterefficiencyisanessentialpartoftheshortandlongertermresponse.Isthecrisisaboost,orasetback,forenergytransitions?Withenergymarketsremainingextremelyvulnerable,todaysenergyshockisareminderofthefragilityandunsustainabilityofourcurrentenergysystem.Akeyquestionforpolicymakers,and for this Outlook,is whether the crisis will be a setback for clean energytransitionsorwillcatalysefasteraction.ClimatepoliciesandnetzerocommitmentswereIEA.CC BY 4.0.20 International Energy Agency|World Energy Outlook 2022 blamedinsomequartersforcontributingtotherunupinenergyprices,butthereisscantevidenceforthis.Inthemostaffectedregions,highersharesofrenewableswerecorrelatedwithlowerelectricityprices,andmoreefficienthomesandelectrifiedheathaveprovidedanimportantbufferforsomebutfarfromenoughconsumers.Timesofcrisisputthespotlightongovernments,andonhowtheyreact.Alongsideshorttermmeasures,manygovernmentsarenowtakinglongertermsteps:someseekingtoincreaseordiversifyoilandgassupply;manylookingtoacceleratestructuralchange.ThethreescenariosexploredinthisWorldEnergyOutlook(WEO)aredifferentiatedprimarilybytheassumptionsmadeongovernmentpolicies.TheStatedPoliciesScenario(STEPS)showsthetrajectoryimpliedbytodayspolicysettings.TheAnnouncedPledgesScenario(APS)assumesthatallaspirationaltargetsannouncedbygovernmentsaremetontimeandinfull,includingtheirlongtermnetzeroandenergyaccessgoals.TheNetZeroEmissionsby2050(NZE)Scenariomapsoutawaytoachievea1.5Cstabilisationintheriseinglobalaveragetemperatures,alongsideuniversalaccesstomodernenergyby2030.PolicyresponsesarefasttrackingtheemergenceofacleanenergyeconomyNewpoliciesinmajorenergymarketshelppropelannualcleanenergyinvestmenttomorethanUSD2trillionby2030intheSTEPS,ariseofmorethan50%fromtoday.Cleanenergybecomes a huge opportunity for growth and jobs,and amajor arena for internationaleconomiccompetition.By2030,thanksinlargeparttotheUSInflationReductionAct,annualsolar and wind capacity additions in the United States grow twoandahalftimes overtodayslevels,whileelectriccarsalesareseventimeslarger.NewtargetscontinuetospurthemassivebuildoutofcleanenergyinChina,meaningthatitscoalandoilconsumptionbothpeakbeforetheendofthisdecade.FasterdeploymentofrenewablesandefficiencyimprovementsintheEuropeanUnionbringdownEUnaturalgasandoildemandby20%thisdecade,andcoaldemandby50%,apushgivenadditionalurgencybytheneedtofindnewsources of economic and industrial advantage beyond Russian gas.Japans GreenTransformation(GX)programmeprovidesamajorfundingboostfortechnologiesincludingnuclear,lowemissionshydrogenandammonia,whileKoreaisalsolookingtoincreasetheshareofnuclearandrenewablesinitsenergymix.Indiamakesfurtherprogresstowardsitsdomesticrenewablecapacitytargetof500gigawatts(GW)in2030,andrenewablesmeetnearlytwothirdsofthecountrysrapidlyrisingdemandforelectricity.Asmarketsrebalance,renewables,supportedbynuclearpower,seesustainedgains;theupside for coal from todays crisis is temporary.The increase in renewable electricitygenerationissufficientlyfasttooutpacegrowthintotalelectricitygeneration,drivingdownthecontributionoffossilfuelsforpower.Thecrisisbrieflypushesuputilisationratesforexistingcoalfiredassets,butdoesnotbringhigherinvestmentinnewones.Strengthenedpolicies,a subdued economic outlook and high nearterm prices combine to moderateoverallenergydemandgrowth.IncreasescomeprimarilyfromIndia,SoutheastAsia,AfricaandtheMiddleEast.However,theriseinChinasenergyuse,whichhasbeensuchanimportantdriverforglobalenergytrendsoverthepasttwodecades,slowsandthenhaltsaltogetherbefore2030asChinashiftstoamoreservicesorientatedeconomy.IEA.CC BY 4.0.Executive Summary 21 Internationalenergytradeundergoesaprofoundreorientationinthe2020sascountriesadjusttotheruptureofRussiaEuropeflows,whichisassumedtobepermanent.NotallRussianflowsdisplacedfromEuropefindanewhomeinothermarkets,bringingdownRussianproductionandglobalsupply.Crudeoilandproductmarkets,especiallydiesel,faceaturbulentperiodasEUbansonRussianimportskickin.Naturalgastakeslongertoadjust.The upcoming northern hemisphere winter promises to be a perilous moment for gasmarketsandatestingtimeforEUsolidarityandthewinterof202324couldbeeventougher.MajornewadditionstoLNGsupplymainlyfromNorthAmerica,QatarandAfrica arrive only around the mid2020s.Competition for available cargoes is fierce in themeantimeasChineseimportdemandpicksupagain.TodaysstrongerpolicysettingsbringafossilfuelpeakintoviewForthefirsttime,aWEOscenariobasedonprevailingpolicysettingshasglobaldemandforeachofthefossilfuelsexhibitingapeakorplateau.IntheSTEPS,coalusefallsbackwithinthenextfewyears,naturalgasdemandreachesaplateaubytheendofthedecade,andrisingsalesofelectricvehicles(EVs)meanthatoildemandlevelsoffinthemid2030sbeforeebbingslightlytomidcentury.Totaldemandforfossilfuelsdeclinessteadilyfromthemid2020sbyaround2exajoulesperyearonaverageto2050,anannualreductionroughlyequivalenttothelifetimeoutputofalargeoilfield.GlobalfossilfuelusehasrisenalongsideGDPsincethestartoftheIndustrialRevolutioninthe18thcentury:puttingthisriseintoreversewhilecontinuingtoexpandtheglobaleconomywillbeapivotalmomentinenergyhistory.Theshareoffossilfuelsintheglobalenergymixhasbeenstubbornlyhigh,ataround80%,fordecades.By2030intheSTEPS,thissharefallsbelow75%,andtojustabove60%by2050.AhighpointforglobalenergyrelatedCO2emissionsisreachedintheSTEPSin2025,at37billiontonnes(Gt)peryear,andtheyfallbackto32Gtby2050.Thiswouldbeassociatedwithariseofaround2.5Cinglobalaveragetemperaturesby2100.Thisisabetteroutcomethanprojectedafewyearsago:renewedpolicymomentumandtechnologygainsmadesince2015haveshavedaround1Coffthelongtermtemperaturerise.However,areductionofonly13%inannualCO2emissionsto2050intheSTEPSisfarfromenoughtoavoidsevereimpactsfromachangingclimate.Fullachievementofallclimatepledgeswouldmovetheworldtowardssaferground,butthereisstillalargegapbetweentodaysambitionsanda1.5Cstabilisation.IntheAPS,aneartermpeakinannualemissionsisfollowedbyafasterdeclineto12Gtby2050.ThisisabiggerreductionthanintheWEO2021APS,reflectingtheadditionalpledgesthathavebeenmadeoverthepastyear,notablybyIndiaandIndonesia.Ifimplementedontimeandinfull,these additional national commitments as well as sectoral commitments for specificindustriesandcompanytargets(consideredforthefirsttimeinthisyearsAPS)keepthetemperatureriseintheAPSin2100ataround1.7C.However,itiseasiertomakepledgesthantoimplementthemand,eveniftheyareachieved,thereisstillconsiderablyfurthertogotoalignwiththeNZEScenario,whichachievesthe1.5Coutcomebyreducingannualemissionsto23Gtby2030andtonetzeroby2050.IEA.CC BY 4.0.22 International Energy Agency|World Energy Outlook 2022 Ledbycleanelectricity,somesectorsarepoisedforafastertransformationTheworldisinacriticaldecadefordeliveringamoresecure,sustainableandaffordableenergysystemthepotentialforfasterprogressisenormousifstrongactionistakenimmediately.Investmentsincleanelectricityandelectrification,alongwithexpandedandmodernisedgrids,offerclearandcosteffectiveopportunitiestocutemissionsmorerapidlywhilebringingelectricitycostsdownfromtheircurrenthighs.TodaysgrowthratesfordeploymentofsolarPV,wind,EVsandbatteries,ifmaintained,wouldleadtoamuchfastertransformationthanprojectedintheSTEPS,althoughthiswouldrequiresupportivepoliciesnotjustintheleadingmarketsforthesetechnologiesbutacrosstheworld.By2030,ifcountriesdeliverontheirclimatepledges,everysecondcarsoldintheEuropeanUnion,ChinaandtheUnitedStatesiselectric.Supplychainsforsomekeytechnologiesincludingbatteries,solarPVandelectrolysersareexpandingatratesthatsupporthigherglobalambition.IfallannouncedmanufacturingexpansionplansforsolarPVseethelightofday,manufacturingcapacitywouldexceedthedeploymentlevelsintheAPSin2030byaround75%andapproachthelevelsrequiredintheNZEScenario.Inthecaseofelectrolysersforhydrogenproduction,thepotentialexcesscapacityofallannouncedprojectsrelativetoAPSdeploymentin2030isaround50%.IntheEVsector,theexpansionofbatterymanufacturingcapacityreflectstheshiftunderwayintheautomotiveindustry,whichattimeshasmovedfasterthangovernmentsinsettingtargetsforelectrifiedmobility.Thesecleanenergysupplychainsareahugesourceofemploymentgrowth,with clean energy jobs already exceeding those in fossil fuels worldwide andprojectedtogrowfromaround33milliontodaytoalmost55millionin2030intheAPS.EfficiencyandcleanfuelsgetacompetitiveboostTodayshighenergypricesunderscorethebenefitsofgreaterenergyefficiencyandarepromptingbehaviouralandtechnologychangesinsomecountriestoreduceenergyuse.Efficiencymeasurescanhavedramaticeffectstodayslightbulbsareatleastfourtimesmoreefficientthanthoseonsaletwodecadesagobutmuchmoreremainstobedone.Demandforcoolingneedstobeaparticularlyfocusforpolicymakers,asitmakesthesecondlargestcontributiontotheoverallriseinglobalelectricitydemandoverthecomingdecades(afterEVs).Manyairconditionersusedtodayaresubjectonlytoweakefficiencystandardsandonefifthofelectricitydemandforcoolinginemerginganddevelopingeconomiesisnotcoveredbyanystandardsatall.IntheSTEPS,coolingdemandinemerginganddevelopingeconomiesrisesby2800terawatthoursto2050,whichistheequivalentofaddinganotherEuropeanUniontotodaysglobalelectricitydemand.ThisgrowthisreducedbyhalfintheAPSbecauseoftighterefficiencystandardsandbetterbuildingdesignandinsulationandbyhalfagainintheNZEScenario.Concernsaboutfuelprices,energysecurityandemissionsbolsteredbystrongerpolicysupportarebrighteningtheprospectsformanylowemissionsfuels.Investmentinlowemissionsgasesissettorisesharplyinthecomingyears.IntheAPS,globallowemissionshydrogenproductionrisesfromverylowlevelstodaytoreachover30milliontonnes(Mt)IEA.CC BY 4.0.Executive Summary 23 peryearin2030,equivalenttoover100bcmofnaturalgas(althoughnotalllowemissionshydrogenwouldreplacenaturalgas).Muchofthisisproducedclosetothepointofuse,butthereisgrowingmomentumbehindinternationaltradeinhydrogenandhydrogenbasedfuels.Projectsrepresentingapotential12Mtofexportcapacityareinvariousstagesofplanning,although these are more numerous and more advanced than correspondingprojectstounderpinimportinfrastructureanddemand.Carboncapture,utilisationandstorageprojectsarealsoadvancingmorerapidlythanbefore,spurredbygreaterpolicysupporttoaidindustrialdecarbonisation,toproduceloworloweremissionsfuels,andtoallowfordirectaircaptureprojectsthatremovecarbonfromtheatmosphere.ButrapidtransitionsultimatelydependoninvestmentAhugeincreaseinenergyinvestmentisessentialtoreducetherisksoffuturepricespikesandvolatility,andtogetontrackfornetzeroemissionsby2050.FromUSD1.3trilliontoday,cleanenergyinvestmentrisesaboveUSD2trillionby2030intheSTEPS,butitwouldhavetobeaboveUSD4trillionbythesamedateintheNZEScenario,highlightingtheneedtoattractnewinvestorstotheenergysector.Governmentsshouldtaketheleadandprovidestrongstrategicdirection,buttheinvestmentsrequiredarefarbeyondthereachesofpublicfinance.Itisvitaltoharnessthevastresourcesofmarketsandincentiviseprivateactorstoplaytheirpart.Today,foreveryUSD1spentgloballyonfossilfuels,USD1.5isspentoncleanenergytechnologies.By2030,intheNZEScenario,everyUSD1spentonfossilfuelsisoutmatchedbyUSD5oncleanenergysupplyandanotherUSD4onefficiencyandenduses.Shortfallsincleanenergyinvestmentarelargestinemerginganddevelopingeconomies,aworryingsignalgiventheirrapidprojectedgrowthindemandforenergyservices.IfChinaisexcluded,thentheamountbeinginvestedincleanenergyeachyearinemerginganddevelopingeconomieshasremainedflatsincetheParisAgreementwasconcludedin2015.ThecostofcapitalforasolarPVplantin2021inkeyemergingeconomieswasbetweentwoandthreetimeshigherthaninadvancedeconomiesandChina.Todaysrisingborrowingcostscouldexacerbatethefinancingchallengesfacingsuchprojects,despitetheirfavourableunderlyingcosts.Arenewedinternationaleffortisneededtostepupclimatefinanceandtackle the various economywide or projectspecific risks that deter investors.There isimmensevalueinbroadnationaltransitionstrategiessuchastheJustEnergyTransitionPartnershipswithIndonesia,SouthAfricaandothercountries,thatintegrateinternationalsupportandambitiousnationalpolicyactionswhilealsoprovidingsafeguardsforenergysecurityandthesocialconsequencesofchange.Thespeedatwhichinvestorsreacttobroadandcredibletransitionframeworksdependsinpracticeonahostofmoregranularissues.Supplychainsarefragile,andinfrastructureandskilledlabourarenotalwaysavailable.Permittingprovisionsanddeadlinesareoftencomplexandtimeconsuming.Clearproceduresforprojectapproval,supportedbyadequateadministrativecapacity,arevitaltoacceleratetheflowofviable,investableprojectsbothforcleanenergysupplyaswellasforefficiencyandelectrification.Ouranalysisfindsthatpermittingandconstructionofasingleoverheadelectricitytransmissionlinecantakeupto13years,withsomeofthelongestleadtimesinadvancedeconomies.DevelopingnewIEA.CC BY 4.0.24 International Energy Agency|World Energy Outlook 2022 depositsofcriticalmineralshashistoricallytakenover16yearsonaverage,with12yearsspentliningupallaspectsofpermittingandfinancingand45yearsforconstruction.Whatiftransitionsdontpickup?If clean energy investment does not accelerate as in the NZE Scenario then higherinvestmentinoilandgaswouldbeneededtoavoidfurtherfuelpricevolatility,butthiswouldalsomeanputtingthe1.5Cgoalinjeopardy.IntheSTEPS,anaverageofalmostUSD650billionperyearisspentonupstreamoilandnaturalgasinvestmentto2030,ariseofmorethan50%comparedwithrecentyears.Thisinvestmentcomeswithrisks,bothcommercialandenvironmental,andcannotbetakenforgranted.Despitehugewindfallsthisyear,someMiddleEastproducersaretheonlypartoftheupstreamindustryinvestingmoretodaythanpriortotheCovid19pandemic.Amidconcernsaboutcostinflation,capitaldisciplineratherthanproductiongrowthhasbecomethedefaultsettingfortheUSshaleindustry,meaningthatsomeofthewindhasgonefromthesailsofthemainsourceofrecentglobaloilandgasgrowth.ImmediateshortfallsinfossilfuelproductionfromRussiawillneedtobereplacedbyproductionelsewhereeveninaworldworkingtowardsnetzeroemissionsby2050.Themostsuitableneartermsubstitutesareprojectswithshortleadtimesthatbringoilandgastomarketquickly,aswellascapturingsomeofthe260bcmofgasthatiswastedeachyearthroughflaringandmethaneleakstotheatmosphere.Butlastingsolutionstotodayscrisislieinreducingfossilfueldemand.Manyfinancialorganisationshavesetgoalsandplanstoscaledowninvestmentinfossilfuels.Muchmoreemphasisisneededongoalsandplansforscalingupinvestmentincleanenergytransitions,andonwhatgovernmentscandotoincentivisethis.RussialosesoutinthereshufflingofinternationaltradeRussiasinvasionofUkraineispromptingawholesalereorientationofglobalenergytrade,leavingRussiawithamuchdiminishedposition.AllRussiastradetieswithEuropebasedonfossilfuelshadultimatelybeenundercutinourpreviousscenariosbyEuropesnetzeroambitions,butRussiasabilitytodeliveratrelativelylowcostmeantthatitlostgroundonlygradually.Nowtherupturehascomewithaspeedthatfewimaginedpossible.InthisOutlook,more Russian resources are drawn eastwards to Asian markets,but Russia isunsuccessfulinfindingmarketsforalloftheflowsthatpreviouslywenttoEurope.In2025,Russias oil production is 2million barrels a day lower than in the WEO2021 and gasproductionisdownby200bcm.Longertermprospectsareweakenedbyuncertaintiesoverdemand,aswellasrestrictedaccesstointernationalcapitalandtechnologiestodevelopmorechallengingfieldsandLNGprojects.Russianfossilfuelexportsneverreturninanyofourscenariostothelevelsseenin2021,anditsshareofinternationallytradedoilandgasfallsbyhalfby2030intheSTEPS.RussiasreorientationtoAsianmarketsisparticularlychallenginginthecaseofnaturalgas,asthemarketopportunityforlargescaleadditionaldeliveriestoChinaislimited.RussiaistargetingnewpipelinelinkstoChina,notablythelargecapacityPowerofSiberia2pipelineIEA.CC BY 4.0.Executive Summary 25 throughMongolia.However,ourdemandprojectionsforChinaraiseconsiderabledoubtsabouttheviabilityofanotherlargescalegaslinkwithRussia,oncetheexistingPowerofSiberialinerampsuptofullcapacity.IntheSTEPS,Chinasgasdemandgrowthslowsto2%peryearbetween2021and2030,comparedwithanaveragegrowthrateof12%peryearsince2010,reflectingapolicypreferenceforrenewablesandelectrificationovergasuseforpowerandheat.ChineseimportershavebeenactivelycontractingfornewlongtermLNGsupplies,andChinaalreadyhasadequatecontractedsupplytomeetprojecteddemandintheSTEPSuntilwellintothe2030s.Werethe2010sthe“goldenageofgas”?OneoftheeffectsofRussiasactionsisthattheeraofrapidgrowthinnaturalgasdemanddrawstoaclose.IntheSTEPS,thescenariothatseesthehighestgasconsumption,globaldemandrisesbylessthan5tween2021and2030andthenremainsflatataround4400bcmthroughto2050.Theoutlookforgasisdampenedbyhigherneartermprices;morerapiddeploymentofheatpumpsandotherefficiencymeasures;higherrenewablesdeploymentandafasteruptakeofotherflexibilityoptionsinthepowersector;and,insomecases,relianceoncoalforslightlylonger.TheInflationReductionActcutsprojectedUSnaturalgasdemandin2030intheSTEPSbymorethan40bcmcomparedwithlastyearsprojections,freeing up gas for export.Stronger climate policies accelerate Europesstructuralshiftawayfromgas.Newsupplybringspricesdownbythemid2020s,andLNGbecomesevenmoreimportanttooverallgassecurity.Butmomentumbehindnaturalgasgrowthindevelopingeconomieshasslowed,notablyinSouthandSoutheastAsia,puttingadentinthecredentialsofgasasatransitionfuel.Mostofthedownwardrevisiontogasdemandto2030inthisyearsSTEPSisduetoafasterswitchtocleanenergy,althougharoundonequarterisbecausegaslosesouttocoalandoil.Afocusonaffordable,securetransitionsbasedonresilientsupplychainsAnewenergysecurityparadigmisneededtomaintainreliabilityandaffordabilitywhilereducingemissions.ThisOutlookincludestenprinciplesthatcanhelpguidepolicymakersthroughtheperiodwhendecliningfossilfuelandexpandingcleanenergysystemscoexist.Duringenergytransitions,bothsystemsarerequiredtofunctionwellinordertodelivertheenergyservicesneededbyconsumers,evenastheirrespectivecontributionschangeovertime.Maintainingelectricitysecurityintomorrowspowersystemscallsfornewtools,moreflexibleapproachesandmechanismstoensureadequatecapacities.Powergeneratorswillneedtobemoreresponsive,consumerswillneedtobemoreconnectedandadaptable,andgridinfrastructurewillneedtobestrengthenedanddigitalised.Inclusive,peoplecentredapproachesareessentialtoallowvulnerablecommunitiestomanagetheupfrontcostsofcleaner technologies and ensure that the benefits of transitions are felt widely acrosssocieties.Evenastransitionsreducefossilfueluse,therearepartsofthefossilfuelsystemthatremaincriticaltoenergysecurity,suchasgasfiredpowerforpeakelectricityneeds,orrefineriestosupplyresidualusersoftransportfuels.Unplannedorprematureretirementofthisinfrastructurecouldhavenegativeconsequencesforenergysecurity.IEA.CC BY 4.0.26 International Energy Agency|World Energy Outlook 2022 Astheworldmovesonfromtodaysenergycrisis,itneedstoavoidnewvulnerabilitiesarisingfromhighandvolatilecriticalmineralpricesorhighlyconcentratedcleanenergysupplychains.Ifnotadequatelyaddressed,theseissuescoulddelayenergytransitionsormakethemmorecostly.Demandforcriticalmineralsforcleanenergytechnologiesissettorisesharply,morethandoublingfromtodayslevelby2030intheAPS.Copperseesthelargestincreaseintermsofabsolutevolumes,butothercriticalmineralsexperiencemuchfasterratesofdemandgrowth,notablysiliconandsilverforsolarPV,rareearthelementsforwind turbine motors and lithium for batteries.Continued technology innovation andrecyclingarevitaloptionstoeasestrainsoncriticalmineralsmarkets.HighrelianceonindividualcountriessuchasChinaforcriticalmineralsuppliesandformanycleantechnologysupplychainsisariskfortransitions,butsotooarediversificationoptionsthatcloseoffthebenefitsoftrade.TheenergycrisispromisestobeahistoricturningpointtowardsacleanerandmoresecureenergysystemEnergymarketsandpolicieshavechangedasaresultofRussiasinvasionofUkraine,notjustforthetimebeing,butfordecadestocome.Theenvironmentalcaseforcleanenergyneedednoreinforcement,buttheeconomicargumentsinfavourofcostcompetitiveandaffordablecleantechnologiesarenowstrongerandsotooistheenergysecuritycase.Thisalignmentofeconomic,climateandsecurityprioritieshasalreadystartedtomovethedialtowardsabetteroutcomefortheworldspeopleandfortheplanet.Muchmoreremainstobedone,andastheseeffortsgathermomentum,itisessentialtobringeveryoneonboard,especiallyatatimewhengeopoliticalfracturesonenergyandclimateareallthemorevisible.Thismeansredoublingeffortstoensurethatabroadcoalitionofcountrieshasastakeinthenewenergyeconomy.Thejourneytoamoresecureandsustainableenergysystemmaynotbeasmoothone.Buttodayscrisismakesitcrystalclearwhyweneedtopressahead.IEA.CC BY 4.0.PART A OVERVIEW AND CONTEXT OVERVIEW AND CONTEXT PartAoftheWorldEnergyOutlookprovidesthestartingpointforthisyearsenergyprojectionsandgivesanoverviewofsomeofthekeyfindings.Chapter1exploresthecausesoftodaysglobalenergycrisisand the consequences.Itprovides projections forenergymarketsandenergysecuritythroughthreescenariosandexamines what those outlooks imply for energyrelatedemissions and achievement of the worlds sustainabledevelopmentgoals.Chapter2examinesthevariousforcesthatareimpactingtheenergysectortodayandthepolicyresponses,andassessestheimplicationsforourOutlookin2022.Italsodetailsthebasisofeachofthethreemainscenariosandhowandwhytheydiffer.IEA.CC BY 4.0.Chapter 1|Overview and key findings 29 Chapter1Overview and key findings Global energy crisis:causes and implications TheglobalenergycrisissparkedbyRussiasinvasionofUkraineishavingfarreachingimplicationsforhouseholds,businessesandentireeconomies,promptingshorttermresponsesfromgovernmentsaswellasadeeperdebateaboutthewaystoreducetheriskoffuturedisruptionsandpromoteenergysecurity.Thisisaglobalcrisis,butEuropeisthemaintheatreinwhichitisplayingout,andnaturalgasiscentrestageespeciallyduringthecomingnorthernhemispherewinter.High energy prices are causing a huge transfer of wealth from consumers toproducers,backtothelevelsseenin2014foroil,butentirelyunprecedentedfornaturalgas.Highfuelpricesaccountfor90%oftheriseintheaveragecostsofelectricitygenerationworldwide,naturalgasaloneformorethan50%.Thecostsofrenewablesandcarbondioxidehaveplayedonlyamarginalrole,underscoringthatthisisacrisiswhereenergytransitionsarethesolution,ratherthantheproblem.Priceandeconomicpressuresmeanthatthenumberofpeoplewithoutaccesstomodernenergyisrisingforthefirsttimeinadecade.Around75millionpeoplewhorecentlygainedaccesstoelectricityarelikelytolosetheabilitytopayforit,and100millionpeoplemayreverttotheuseoftraditionalbiomassforcooking.Thereremainhugeuncertaintiesoverhowthisenergycrisiswillevolveandforhowlongfossilfuelpriceswillremainelevated,andtherisksoffurtherenergydisruptionandgeopoliticalfragmentationarehigh.Inallourscenarios,pricepressuresandadimneartermoutlookfortheglobaleconomyfeedthroughintolowerenergydemandthaninlastyearsOutlook.Thecrisisprovidesashorttermboosttodemandforoilandcoalasconsumersscrambleforalternativestohighpricedgas.Butthelastinggainsfromthecrisisaccrueto lowemissions sources,mainly renewables,but also nuclear in some cases,alongsidefasterprogresswithefficiencyandelectrification,e.g.electricvehicles.IntheStatedPoliciesScenario(STEPS),globalenergydemandgrowthofaround1%peryearto2030ismetinaggregatealmostentirelybyrenewables.Emergingmarketanddevelopingeconomies,suchasIndia,seeincreasesacrossabroaderrangeoffuelsandtechnologies,whiletheonlysourcestoshowgrowthinadvancedeconomiesto2030arelowemissions.Thecostadvantagesofmaturecleanenergytechnologiesandtheprospectsfornewones,suchaslowemissionshydrogen,areboostedbytheInflationReductionActintheUnitedStates,Europesincreasedpushforcleanenergy,andothermajornewpolicies.Theresultistoturbochargetheemergingglobalcleanenergyeconomy.TheSTEPSinthisOutlookisthefirstWorldEnergyOutlook(WEO)scenariobasedonprevailingpolicysettingsthatseesadefinitivepeakinglobaldemandforfossilfuels.S U M M A R Y IEA.CC BY 4.0.30 International Energy Agency|World Energy Outlook 2022 Coaldemandpeaksinthenextfewyears,naturalgasdemandreachesaplateaubytheendofthedecade,andoildemandreachesahighpointinthemid2030sbeforefallingslightly.From80%todayalevelthathasbeenconstantfordecadestheshareoffossilfuelsintheglobalenergymixfallstolessthan75%by2030andtojustabove60%bymidcentury.IntheAnnouncedPledgesScenario(APS),thedrivetomeetclimatepledgesinfullsendsdemandforallthefossilfuelsintodeclineby2030.WiththelossofitslargestexportmarketinEurope,Russiafacestheprospectofamuchdiminishedroleininternationalenergyaffairs.2021provestobeahighwatermarkforRussianexportflows.Itsshareofinternationallytradedgas,whichstoodat30%in2021,fallsto15%by2030intheSTEPSandto10%intheAPS.ImportersinChinahavebeenactivelycontractingforliquefiednaturalgas,andthereisnoroominChinasprojectedgasbalanceforanotherlargescalepipelinefromRussia.EnergyrelatedCO2emissionsreboundedto36.6Gtin2021,thelargesteverannualriseinemissions.IntheSTEPS,theyreachaplateauaround37Gtbeforefallingslowlyto32Gtin2050,atrajectorythatwouldleadtoa2.5Criseinglobalaveragetemperatures by 2100.This is around 1C lower than implied by the baselinetrajectorypriortotheParisAgreement,indicatingtheprogressthathasbeenmadesincethen.Butmuchmoreneedstobedone.IntheAPS,emissionspeakinthemid2020s and fall to 12Gt in 2050,resulting in a projected global mediantemperaturerisein2100of1.7C.IntheNetZeroEmissionsby2050(NZE)Scenario,CO2emissionsfallto23Gtin2030andtozeroin2050,atrajectoryconsistentwithlimitingthetemperatureincreasetolessthan1.5Cin2100.Plannedincreasesinglobalcleanenergymanufacturingcapacityprovidealeadingindicatorofthepotentialforrapidincreasesindeployment.Inthecaseofheatpumps,currentandplannedmanufacturingcapacityisbelowthedeploymentlevelsprojectedintheAPS.ButannouncedglobalmanufacturingcapacityforelectrolysersandsolarPVmodulesin2030issufficientnotonlytoreachAPSdeploymentlevelsbuttogobeyondthem.Onepointcommontoeachscenarioistherisingshareofelectricityinglobalfinalenergyconsumption.From20%today,thisincreasesineachscenario,reachingmorethan50%bymidcenturyintheNZEScenario.Thisisassociatedwithahugeoverallincreaseinglobalelectricitydemandwiththebulkofthisgrowthcomingfromemergingmarketanddevelopingeconomiesandtheneedforconstantvigilancefrompolicymakerstoarangeofriskstoelectricitysecurity,inparticulartheeverincreasingneedforflexibleoperationofpowersystems.Theworldhasnotbeeninvestingenoughinenergyinrecentyears,afactthatlefttheenergysystemmuchmorevulnerabletothesortofshocksseenin2022.Asmoothandsecureenergytransitionwillrequireamajoruptickincleanenergyinvestmentflows.GettingontrackfortheNZEScenariowillrequireatriplinginspendingoncleanenergyandinfrastructureto2030,alongsideashifttowardsmuchhigherinvestmentinemergingmarketanddevelopingeconomies.-0.8Dec 20Oct 20Feb 21Apr 21Jun 21Aug 21Oct 21Dec 21Apr 22Jun 22Aug 22Feb 22Gas importersGas exporters2022200620082010201220142016201820202 4002 0001 600Asian spot LNGEU imported coalGerman powerNorth Sea BrentEurope natural gas(TTF)OtherEurasiaAfricaMiddle EastEuropeOtherCentral andSouth AmericaAsia Pacific202120302040Emissions2050Median temperature rise in 210001234CNet Zero5336 Gt CO212.332Index(1 September 2020=100)Trillion USD-0.400.40.8Pre-ParisAgreementAPSNZESTEPSHuge transfers fromconsumers to producers:Oil has been expensive before,but there is no precedent for the import bills for natural gas in 2022.Policy and technology changes since the Paris Agreement in 2015 have reduced the projected temperature rise,but theres still a long way to go to cap global warming at 1.5 C.Emissions have tocome downA shock to the systemRussias invasion of Ukraine has led to a period of extraordinary turbulence in energy markets,especially for natural gas.32 International Energy Agency|World Energy Outlook 2022 1.1 IntroductionEachenergycrisishasechoesofthepast,andtheacutestrainsonmarketstodayaredrawingcomparisonwiththemostsevereenergydisruptionsinmodernenergyhistory,mostnotablytheoilshocksofthe1970s.Then,asnow,therewerestronggeopoliticaldriversfortheriseinprices,whichledtohighinflationandeconomicdamage.Then,asnow,thecrisesbroughttothesurfacesomeunderlyingfragilitiesanddependenciesintheenergysystem.Then,asnow,highpricescreatedstrongeconomicincentivestoact,andthoseincentiveswerereinforcedbyconsiderationsofeconomicandenergysecurity.Buttodaysglobalenergycrisisissignificantlybroaderandmorecomplexthanthosethatcamebefore.Theshocksinthe1970swereaboutoil,andthetaskfacingpolicymakerswasrelativelyclear(ifnotnecessarilysimpletoimplement):reducedependenceonoil,especiallyoilimports.Bycontrast,theenergycrisistodayhasmultipledimensions:naturalgas,butalsooil,coal,electricity,foodsecurityandclimate.Therefore,thesolutionsaresimilarlyallencompassing.Ultimatelywhatisrequiredisnotjusttodiversifyawayfromasingleenergycommodity,but to change the nature of the energy system itself,and to do so whilemaintainingtheaffordable,secureprovisionofenergyservices.ThisOutlookexploreshowthischangemightplayout,andwhatpitfallsandopportunitiesmaybeencounteredalongtheway.Eachscenarioisbasedonadifferentvisionofhowpolicymakersmightrespondtotodayscrisis.IntheStatedPoliciesScenario(STEPS),weexplorehowtheenergysystemevolvesifweretaincurrentpolicysettings.Theseincludethelatestpolicymeasuresadoptedbygovernmentsaroundtheworld,suchastheInflationReductionActintheUnitedStates,butdonotassumethataspirationaloreconomywidetargetsaremetunlesstheyarebackedupwithdetailonhowtheyaretobeachieved.IntheAnnouncedPledgesScenario(APS),governmentsgetthebenefitofthedoubt.Inthisscenario,theirtargetsareachievedontimeandinfull,whethertheyrelatetoclimatechange,energysystemsornationalpledgesinotherareassuchasenergyaccess.Trendsinthisscenariorevealtheextentoftheworldscollectiveambition,asitstandstoday,totackleclimate change and meet other sustainable development goals.Only in the Net ZeroEmissionsby2050(NZE)Scenario,doweworkbackfromspecificgoalsthemainoneinthiscasebeingtocapglobalwarmingto1.5Candshowhowtheycanbeachieved.Eachscenariomeetscurrentenergysecurityandclimatechallengesindifferentwaysandtodifferent extents,but the starting point for todays decision makers is fundamentallydifferentfromthatfacingtheircounterpartsinthe1970s.Theclimateandenvironmentalchallengesaremuchmoreacute,duetoahalfcenturyofrisingemissions.Butthecleantechnology choices available today are also much more mature and cost competitive,providing options for much more efficient energy use,cleaner energy production andgeneration,andnewkindsofstorage.Asaresult,manyofthecomponentpartsofanewtypeofenergysystemareclearlyvisible.Thequestionishoweffectivelyandquicklytheycanbedeployedalongsidetraditionaltechnologies,andtheninplaceofthem.IEA.CC BY 4.0.Chapter 1|Overview and key findings 33 11.2 Causesofthecrisisandimmediateconsequences1.2.1 CausesofthecrisisTheworldisfacingaglobalenergycrisisofunprecedenteddepthandcomplexity.Thisishavingfarreachingimplicationsformanyhouseholds,businessesandentireeconomies,promptingarangeofshorttermresponsesfromgovernmentsaswellasadeeperdebateaboutthewaystoavoidsuchdisruptionsinthefuture.PressuresonmarketspredatedtheRussianFederations(hereinafterRussia)invasionofUkraine,butitsactionshavetippedwhatwasastrongrecoveryfromthepandemicstrongenoughtostrainweakenedsupplychainsandproductioncapacityintofullblownturmoilinenergymarkets,causingseveredamagetotheglobaleconomy.Thisisaglobalcrisis,butEuropeisthemaintheatreinwhichitisplayingout,andnaturalgasiscentrestage.Russiaisseekingtogainpoliticalleveragebywithholdinggassuppliesandexposingconsumerstohigherenergybillsandsupplyshortagesoverthewinterheatingseason.AsofSeptember2022,RussiasgasdeliveriestotheEuropeanUnionaredownby80%comparedtowheretheyhavebeeninrecentyears.ThishasnaturallycreatedsignificantpressureonEuropeanandglobalgasbalances.Duetodemandforheating,Europeangasdemandisroughlytwiceashighduringthewintermonthsasduringthesummer,andismetbyacombinationofdomesticproduction(whichhasbeenindecline),importsbypipelineandliquefiednaturalgas(LNG),andwithdrawalsfromstorage(Figure1.1).Figure 1.1 European Union and United Kingdom winter natural gas supply and options to compensate for a cut in Russian pipeline gas IEA.CCBY4.0.Russian pipeline imports met 20%of gas demand in the European Union in winter 2021-22;managing without this gas requires alternative imports,use of storage and lower demand IEA.CC BY 4.0.34 International Energy Agency|World Energy Outlook 2022 EUgasstoragefacilitiesweremorethan90%fullinearlyOctober2022,aconsiderableachievementgiventhecutstoRussiansupplyoverthecourseoftheyear.IncombinationwithlowerdemandandcontinuedstronginflowsfromnonRussiansources,thisopensanarrowbutpotentiallysafepathwayforEuropethroughthenorthernhemispherewintermonths,albeitathighlyelevatedprices,onconditionthattheweatherdoesnotturntoocold.However,thebalancesfor20232024lookmorechallenging.TherearemanystrandstotheenergyrelationshipbetweenRussiaandEurope.Russiahasactedtoseverthegasrelationship.TheEuropeanUnionhashaltedcoalimportsfromRussia,meaningthatcoaldeliveriesfromEuropeslargestexternalsupplierfelltozeroasofAugust2022.Forthemoment,Russianoilproductionandexportsremainclosetoprewarlevels,despite some countries such as the United States and the United Kingdom imposingimmediaterestrictionsonoiltrade.Somereorientationoftradeflowshasalreadytakenplace,withlowerflowsofoilfromRussiatotheEuropeanUnionandNorthAmericaoffsetbyhigherexportstoothermarkets,notablyIndia,ChinaandTrkiye.Butthemajorchangeslieahead:Russiaexported2.6millionbarrelsperday(mb/d)ofoiltotheEuropeanUnioninSeptember2022,andmostoftheseexportswillcometoanendwhenanEUbanonseabornecrudeoilimportsfromRussiaentersintoforceinDecember2022andonabanonoilproductsfromRussia(whicharemainlymiddledistillates)takeseffectinFebruary2023.TheproximatecauseofthecrisiswasRussiasinvasionofUkraine,butpressureonmarketswasvisiblebeforeFebruary2022.Themainreasonwasthespeedoftheeconomicreboundfromthepandemicinducedslump in2020;thisstretched allmannerof supplychains,includingthoseinfuelsupply.Therewerealsoweatherrelatedfactors,ahigherincidenceofoutagestosupplyoftenrelatedtomaintenancepostponedfrom2020asaresultofthepandemicandwhattheIEAwascalling“artificialtightness”inmarkets.Innaturalgasmarkets,thisstemmedinlargepartfromGazpromssluggishnessinrefillingitsEuropeangasstorageinthethirdquarterof2021,whichinretrospecthastobeseeninthecontextofRussiasinvasionofUkrainesomemonthslaterandthepressuresubsequentlyappliedtoEuropebycuttingoffgassupplies.The key underlying imbalance,which had been some years in the making,relates toinvestment(Figure1.2).ThishasbeenarecurrentthemeinIEAanalysisintheWorldEnergyOutlookandWorldEnergyInvestmentseries.ForfiveyearsaftertheconclusionoftheParisAgreement,theamountofinvestmentgoingintoenergytransitionsremainedflatataroundUSD1trillionperyear.Sincecleanenergytechnologycostscontinuedtodeclineduringthisperiod,thiswasenoughtogenerateyearonyearincreasesindeployment.Butitremainedfarshortoftheamountsneededtosupportathoroughgoingtransformationoftheenergysystem.Onlyinthelasttwoyears,2021and2022,didcleanenergyspendingseeanotableuptick.Theothersideoftheinvestmentcoinisspendingonfossilfuels.Thisdroppedrapidlyafterthefalloftheoilpricein201415,reflectinglowerrevenuesandinvestorfrustrationatthepoorreturnsthatoilandgascompaniesweregenerating.Intheabsenceofamuchneededaccelerationtoenergytransitionstocurbfossilfueldemand,thedeclinesinoilandgasIEA.CC BY 4.0.Chapter 1|Overview and key findings 35 1investmentinthesecondhalfofthe2010spresentedarisktomarketbalancesinthe2020s.IntheWEO2016ExecutiveSummary,forexample,wesaidthat“ifnewprojectapprovalsremainlowforathirdyearinarowin2017,thenitbecomesincreasinglyunlikelythatdemand(asprojectedinourthenNewPoliciesScenario)andsupplycanbematchedintheearly2020swithoutthestartofanewboom/bustcyclefortheindustry”.Naturalgasmarketsalsofacedthe“riskofahardlanding”(IEA,2016).Figure 1.2 Historical energy investment and GDP trends IEA.CCBY4.0.Energy investment was subdued from 2015 to 2020;fossil fuel investment dropped after the 2014-2015 oil price fall and clean energy spending did not start to pick up until recently Acceleration in new approvals failed to materialise,however,at least in part becauseuncertaintyoverlongtermdemandledtheindustrytoshyawayfromlargecapitalintensiveprojects.Eventoday,despitehigherpricesandhugewindfallproductsfortheoilandgasindustryin2022,upstreamspendingistheonlysignificantsegmentoftheinvestmentpicturethatremainsbelowpreCovidlevels.TheotherunderlyingissuethathascontributedtothecrisisisEuropescontinuedhighlevelofrelianceonRussianenergy.In2021,oneoutoffiveunitsofprimaryenergyconsumedintheEuropeanUnioncamefromRussia.ThisrelianceonRussiahadlongbeenidentifiedasastrategic weakness,especially after the annexation of Crimea in 2014,and someinfrastructurewasbuilttodiversifysourcesofimports,butRussianflowsremainedhigh.Inthecaseofnaturalgas,RussiasshareofEuropeangasdemandactuallyrosefrom30%onaveragein200510toreach40%in201520.Climatepoliciesandnetzeroemissionscommitmentswereblamedinsomequartersforcontributingtotherunupinprices,butitisdifficulttoarguethattheyplayedarole.Morerapiddeploymentofcleanenergysourcesandtechnologiesinpracticewouldhavehelpedtoprotectconsumersandmitigatesomeoftheupwardpressureonfuelprices.Itwouldalso0.5%1.0%1.5%2.0 15201720192021CleanenergyFossilfuelsEnergyinvestmentGDPInvestmentasashareofGDP20%0 15201720192021AnnualchangeinGDPandinvestmentIEA.CC BY 4.0.36 International Energy Agency|World Energy Outlook 2022 havemitigatedthepostpandemicreboundinenergyrelatedcarbondioxide(CO2)emissionswhichreached36.6gigatonnes(Gt)in2021.Theannualincreaseof1.9Gtwasthelargestinhistory,offsettingthepreviousyearspandemicinduceddecline.Moreover,thereisscantevidencetosupportthenotionthatnetzeroemissionspledgeshavestifledtraditionalinvestmentsinsupply,asthesepledgesarenotyetcorrelatedwithchangesinfossilfuelspending.Mostnetzeroemissionspledgesarerecent,andmanyhaveyettobetranslatedintospecificplansandpolicymeasures.Ouranalysisoffossilfuelinvestmentincountrieswithnetzeroemissionspledges(68countriesplustheEuropeanUnion)showsthattheyareatasimilarleveltowheretheywerein2016,andthatchangesininvestmentlevelsinthosecountriesinrecentyearsarenotnoticeablydifferentfromthosethathavetakenplaceincountrieswithoutnetzeroemissionspledges(Figure1.3).Figure 1.3 Fossil fuel investment in countries with and without net zero emissions pledges,2015-22 IEA.CCBY4.0.There are,as yet,few signs that net zero emissions pledges are correlated with lower global spending on fossil fuels Notes:NZE=netzeroemissions.Investmentisbasedoncountrieswhereinvestmentoccursratherthanwhereitoriginates.StatusofNZEpledgesasof2022.1.2.2 ImmediateconsequencesThemostvisibleconsequenceofthecrisiswasanexplosioninenergyprices.WhileoilpricesaboveUSD100/barrelhavebeenseenbefore,thereisnoprecedentforthepricelevelsseenin2022fornaturalgas,withpricesatEuropesTitleTransferFacility(TTF)hubregularlyexceedingUSD50permillionBritishthermalunits(MBtu),theequivalentofmorethanUSD200/barrel.High fuel prices were the main reason for upward pressure on global2004006008001000120020152016201720182019202020212022WithNZEpledgesinlawWithNZEpledgesinpolicydocumentsWithoutaNZEpledgeBillionUSD(2021)IEA.CC BY 4.0.Chapter 1|Overview and key findings 37 1electricityprices,inourestimationaccountingfor90%oftheriseintheaveragecostsofelectricitygenerationworldwide(naturalgasaloneformorethan50%).Thecostsofcapitalrecoveryaddedonlyabout5%tothepricepressures,astheelectricitysectorcontinuestoshifttowardsrelativelycapitalintensivetechnologieslikesolarPVandwind.Theremaining5%increaseincostswasduetohighercostsformaintenanceandthoserelatedtoCO2pricesinseveralmarkets.Figure 1.4 Year-on-year increase in average power generation costs by selected country and region,2022 IEA.CCBY4.0.Increases in power generation costs were driven by higher fuel prices and have been particularly sharp in gas-importing countries and regions ThehighcostofnaturalgasfiredpowertypicallythemarginalsourceofgenerationwasthemainfactorbehindahugeriseinEUwholesaleelectricityprices,withtrendsalsoabettedbyhighercoal,oilandCO2prices,reducedavailabilityofnuclearpowerandapooryearforhydropower.WholesaleelectricitypricesintheEuropeanUniontripledinthefirsthalfof2022,wellabovethe40%increaseintheunderlyingaveragecostsofgeneration(Figure1.4).This divergence,which produced huge excess revenues for some market participants,sparked a vigorous debate over the EU electricity market design and whether gas andelectricitypricesshouldsomehowbedelinked.TherippleeffectsofhighernaturalgaspricesinEuropewerefeltaroundtheworld.OneofthemostimmediateconsequencesofRussiascurtailmentofgasdeliverieswasasharpincreaseinEuropeandemandforLNGimports:inthefirsteightmonthsof2022,netLNGimportsinEuroperosebytwothirds(by45billioncubicmetresbcm)comparedwiththesameperiodayearearlier.ItfellmainlyonAsiatobalancethemarket;AsianLNGdemandhasfallenyearonyearin2022forthefirsttimesince2015.Relativelyweakdemandinthe10 0P%MexicoChinaJapanKoreaIndiaEuropeanUnionIEA.CC BY 4.0.38 International Energy Agency|World Energy Outlook 2022 PeoplesRepublicofChina(hereinafterChina),duetoslowereconomicgrowthandCovidrelatedlockdowns,hasbeenafactorineasingmarketbalances(thesameistrueforoil),althoughthisraisesquestionsaboutwhatliesaheadwhendemandinChinastartstopickup.Elsewhere,highpricesandshortfallsinsupplyhaveledtosignificanthardshipfordevelopingcountriesthatrelyonLNG.Figure 1.5 Value of natural gas trade,2005-2022 IEA.CCBY4.0.There is no precedent for the huge increase in payments for traded gas in 2022 Oneeffectofthecurrenthighenergypricesisahugetransferofwealthfromconsumerstoproducers.Thesumsinvolvedarelargebutnotentirelyunprecedentedforoil,beingsimilartotheamountspaidduringtheearly2010s,andpriortothedeclineintheoilpriceinlate2014.Buttheyareextraordinaryfornaturalgas(Figure1.5).Naturalgasistypicallythejuniorpartnerintermsofrevenueforhydrocarbonexporters,withthevalueofinternationaltradeingasaveragingaround20%ofthetotalvalueoftradedoilandgasbetween2010and2021.Thispercentageisnowsettoincreaseto40%in2022.Theenergycrisisisfuellinginflationarypressures,increasingfoodinsecurityandsqueezinghouseholdbudgets,especiallyinpoorhouseholdswherearelativelyhighpercentageofincomeisspentonenergyandfood.TheeffectsofhighernaturalgasandelectricitypriceshavebeenfeltacutelyacrossmuchofEurope.Elsewhereintheworld,theconsequenceshavevariedaccordingtothetypeofeconomy,buttheyareclearlynegativeinoverallterms:theInternationalMonetaryFundcutitsexpectationsofglobalgrowthfor2022from4.9%inOctober2021to3.2%initsOctoberupdate(IMF,2022a).Overall,lowincomecountriesareparticularly exposed to higher food prices,to which higher energy and fertiliser costscontribute(Figure1.6).Thecrisishasalsobeenafurthersetbackforeffortstoimproveenergyaccess(Box1.1).0.80.400.40.82005201020152020MiddleEastEurasiaAfricaCentralandSouthAmericaAsiaPacificEuropeOtherTrillionUSD(2021)Importingregions2022ExportingregionsIEA.CC BY 4.0.Chapter 1|Overview and key findings 39 1Figure 1.6 Contributions of energy and food to inflation in selected countries,2022 IEA.CCBY4.0.Energy is behind many of the inflationary impacts of the crisis in Europe,but higher food prices to which energy contributes are the main driver in many low income countries Source:IEAanalysisbasedonIMF(2022b).Box 1.1 Getting energy access back on track Duetothecombinationofthepandemicandthecurrentenergycrisis,theIEAestimatesthat75millionpeoplethatrecentlygainedaccesstoelectricityarelikelytolosetheabilitytopayforit,andthat100millionpeoplethathavegainedaccesstocookingwithcleanfuelsmayforgoitoncostgrounds,returninginsteadtotheuseoftraditionalbiomass.Gettingtheworldontrackforuniversalaccesstoelectricityandcleancookingwillrequirededicatedadditionaleffortfromawiderangeofnationalandinternationalactors.Onlyhalfofthe113countrieswithoutuniversalaccesstoelectricityhavetargetstoincreaseaccess,andfewerthanhalfofthoseaimtoreachuniversalaccessby2030.Anevensmaller number,e.g.Cte dIvoire,Kenya,Senegal,Rwanda and Myanmar,havecomprehensivenationalelectrificationstrategiesinplace.TheachievementofnationaltargetsasmodelledintheAPSisthereforenotenoughtoachievefulluniversalaccesstoelectricityby2030(theaimofSustainableDevelopmentGoal7).TheNZEScenario,bycontrast,buildsinachievementofthe2030target(Figure1.7).ThegapbetweentheSustainableDevelopmentGoal7(SDG7)targetandcurrentpolicyambitionsisevenwiderinthecaseofcleancookingfuels.Some128countriescurrentlylackuniversalaccesstocleancooking,butonly39ofthemhavecleancookingtargets,andfewerthanhalfofthesearetargetinguniversalaccessby2030.ChinaandIndonesiaIEA.CC BY 4.0.40 International Energy Agency|World Energy Outlook 2022 areclosetobeingontracktoachievetheirtargetsbutinmanyothercountriesthereisaneedtoraisethecurrentlevelofambitionandtoimproveimplementation.Aswithaccesstoelectricity,universalaccesstocleancookingby2030isbuiltintotheNZEScenario.Figure 1.7 Number of people without access to electricity and clean cooking by scenario,2021 and 2030 IEA.CCBY4.0.Well-formulated national strategies and international support are vital to regain momentum on improving energy access after Covid-19 and todays high energy prices Notes:SubSaharanAfricaexcludesSouthAfrica.STEPS=StatedPoliciesScenario;APS=AnnouncedPledgesScenario;NZE=NetZeroEmissionsby2050Scenario.Shorttermpolicyresponsestothecrisishavebeenfocusedonaffordabilityandsecurityofsupply,withmitigatingmeasuresthatcanbeimplementedquicklyatapremium,evenwhentheyareexpensiveorcomeatthecostoftemporarilyhigheremissions.Oneresponsehasbeentoseektoprotectconsumersfromsomeoralloftheincreaseinprices,withmassiveinterventionsinparticulartoshieldvulnerableconsumers.SinceSeptember2021,theIEAhastrackedaroundUSD550billioningovernmentinterventions,mostlyinEurope,toshieldconsumersfromtheworsteffectsofthepricespikes,withalargeamountofadditionalsupportalsounderconsiderationinseveralcountries.Therehavebeenmeasurestoallowforhighercoalfiredgeneration,toextendthelifetimeofsomenuclearpowerplantsandtoaccelerate the flow of new renewable projects.Demandside measures have generallyreceivedlessattention,buttherehavebeeninitiativestoencourageandincentivisecutsinenergyuse:attheEuropeanUnionlevel,theseincludeavoluntary15%reductioninnaturalgasdemandaswellasamandatoryreductiontargetof5%ofelectricityuseinpeakhours(demand which is typically met by gasfired generation).There have also been variousinterventionstocaptherevenuespaidforcheapersourcesofgeneration,whichwould200400600800100020212030STEPS2030APS2030NZESubSaharanAfricaDevelopingAsiaRestofworldWithoutaccesstoelectricityMillionpeople500100015002000250020212030STEPS2030APS2030NZEMillionpeopleWithoutaccesstocleancookingIEA.CC BY 4.0.Chapter 1|Overview and key findings 41 1otherwise be making huge gains because of the pricesetting role of gasfired plants,alongsidetemporaryadditionaltaxesontheprofitsofoilandgascompanies,withtheproceedsusedtohelpeasethepressureonhouseholdandcompanyenergybills.Alongsidetheseshorttermmeasures,somegovernmentshavetakenstepsthatwillplayoutoverthelongerterm.Someoftheseseektoincreaseoilandgassupply,viaannouncementsof new incentives or licensing rounds,1 or through support for new infrastructure,inparticularnewLNGterminalsinEuropetofacilitatethesupplyofnonRussiangas.Butmostofthenewpolicyinitiativesaimtoacceleratethestructuraltransformationoftheenergysector.TheEuropeanUnionisraisingitsrenewablesand energyefficiencytargetsandputtingsignificantresourcesbehindachievingthem.TheadoptionoftheInflationReductionActintheUnitedStatesgivesaboosttoanarrayofcleanenergytechnologiesthroughtheprovisionofUSD370billionforenergysecurityandclimatechangeinvestments,withthepotentialtomobilisefarlargersumsfromtheprivatesector.TheJapanesegovernmentisseeking to restart and build more nuclear plants and expand other lowemissionstechnologieswithitsGreenTransformation(GX)plan.Chinacontinuestobreakrecordsforinvestmentsinrenewablesandtoaddhugenumbersofelectricvehicles(EVs)toitsstockeachyear.Indiahastakenakeysteptowardsestablishingacarbonmarketandboostingtheenergyefficiencyofbuildingsandappliances.Thereremainhugeuncertaintiesoverhowthisenergycrisiswillevolve.ThebiggestconcernisthewarinUkrainehowitwillprogress,whenandhowitmightend.Othersrelatetothepossibilityoffurtherescalationinprices,theseverityofthe202223winter,theextenttowhichRussianexportflowscanberedirectedtoothermarkets,andthewaythathighpricesinfluenceconsumerbehaviourorsocialattitudestowardscleanenergytransitions.Butthecurrentenergyshockhasalreadyhadaseismiceffect,providingavividreminderifonewasneededoftheimportanceofenergysecurityanddiversity.Insodoing,ithashighlightedthefragilityandunsustainabilityofmanyaspectsofourcurrentenergysystemandthewiderrisksthatthisposesforoureconomiesandwellbeing.Andithasplayedoutagainstabackdropofincreasinglyvisiblevulnerabilitiesandimpactsfromachangingclimate.Timesofcrisisputthespotlightongovernments,andthescenariosthatweincludeintheWorldEnergyOutlookaredifferentiatedprimarilybyhowpolicymakersrespond.1Thetypicalleadtimesforupstreamprojectsareconsiderable.Ouranalysisshowsthatforconventionalupstreamprojectsthathavestartedproductionsince2010,ittookonaveragearoundsixyearsfromtheawardofanexplorationlicencetodiscovery;nineyearsfromdiscoverytoprojectapproval;andjustoverfouryearsfromapprovaltofirstproduction.IEA.CC BY 4.0.42 International Energy Agency|World Energy Outlook 2022 1.3 OutlookforenergymarketsandsecurityTodayshighenergypricesandgloomyeconomicoutlookleadtolowerenergydemandgrowthintheSTEPSandAPS,bothintheneartermandoutto2030,thanintheWEO2021(IEA,2021a).Faced with market uncertainty and high prices,consumers are forgoingpurchasesandindustryisscalingbackproduction.Despiteastrongeconomicreboundfromthepandemicin2021,theassumedrateofaverageannualGDPgrowthfortherestofthedecadehasbeenreviseddownslightlyto3.3%(seeChapter2).EnergydemandrisesmoreslowlyinboththeSTEPSandAPSasaresult,andthemixtureoffuelsusedtomeetthisdemandgrowthchangessubstantiallyfrompreviousprojections(Figure1.8).Figure 1.8 Difference in total energy supply in the WEO-2022 STEPS relative to the WEO-2021 STEPS IEA.CCBY4.0.Gas demand is markedly lower than in last years STEPS while low-emissions sources led by renewables see even greater growth.The upside for coal proves short-lived.Notes:EJ=exajoule.PositivenumbersindicatetotalenergysupplyishigherintheSTEPSinthisOutlookthanintheWEO2021STEPS.Thetrendsto2030intheSTEPSareconsistentwithaworldthatisgrapplingwithahostofneartermvulnerabilities,concernedaboutthehighcostofimportedfuelsbutalsoaboutclimatechange,andawareoftheopportunitiesaffordedbycosteffectivecleanenergytechnologies.Naturalgaspricesremainatveryhighlevelsbyhistoricalstandardsuntilthemiddle of the decade,causing gas to lose ground as new natural gas power plantconstructionsslows,withcountriesoptingforothersourcestomaintainsystemadequacyandflexibilitywhileacceleratingrenewables.Tradeflowsundergoaprofoundreorientationasimportingregionstendtoprioritisedomesticresourceswherepossibleinanattempttoensurereliablesuppliesofenergyandlimitexposuretovolatileinternationalmarkets,andastheimplicationsofEuropesshiftawayfromRussianimportsreverberatearoundthesystem.Overall,energysecurityconcernsreinforcetheriseoflowemissionssourcesand151050510152021202220232024202520262027202820292030OilNaturalgasCoalRenewablesNuclearEJIEA.CC BY 4.0.Chapter 1|Overview and key findings 43 1efficiency:energydemandgrowthofalmost1%ayearto2030islargelymetbyrenewables.Forthefirsttime,theSTEPSinthisOutlookshowsanoticeablepeakinoverallfossilfuelconsumptionwithinthisdecade(Box1.2).However,whileshowingdistinctsignsofchange,thetrendsintheSTEPSdonotyetamounttoaparadigmshift.Box 1.2 Era of fossil fuel growth may soon be over TheStatedPoliciesScenariointhisOutlookisthefirstWEOscenariobasedonprevailingpolicysettingsthatseesglobaldemandforeachofthefossilfuelsexhibitapeakorplateau.Coaldemandpeakswithinthenextfewyears,naturalgasdemandreachesaplateaubytheendofthedecade,andoildemandreachesahighpointinthemid2030sbeforefalling.Theresultisthattotaldemandforfossilfuelsdeclinessteadilyfromthemid2020sbyaround2exajoules(EJ)(equivalentto1millionbarrelsofoilequivalentperdaymboe/d)everyyearonaverageto2050(Figure1.9).Figure 1.9 Fossil fuel demand in the STEPS,1990-2050 IEA.CCBY4.0.Total fossil fuel use sees a definitive peak for the first time in this years STEPS.The share of fossil fuels in the energy mix falls to around 60%in 2050,a clear break from past trends Note:EJ=exajoule;TES=totalenergysupply.ChangesinfossilfuelusehavebroadlyfollowedchangesinGDPfordecades,andglobalfossilfueldemandhasremainedataround80%oftotaldemandfordecades.The2022STEPSprojectionsarenowputtingtheworldonapathtowardsasignificantbreakwiththesetrendswithinafewyears.By2030,fossilfuelsaccountforlessthanthreequartersoftotalenergysupply,andby2050theirsharefallstojustabove60%.Thesetrendsareemblematic of a shift in the energy landscape since the Paris Agreement.In theWEO2015,forexample,thescenarioequivalenttotheSTEPS(thencalledtheNewPoliciesScenario)sawasteadyriseindemandforeachofthefossilfuelsto2040,andtotalfossilfuelusein2040wasprojectedtobenearly20%largerthanin2040inthis20002003004005001990200020102020203020402050OilCoalNaturalgasEJShareoffossilfuels inTES(rightaxis)IEA.CC BY 4.0.44 International Energy Agency|World Energy Outlook 2022 yearsSTEPSprojections(IEA,2015).Thebiggestsinglechangesincethenhasbeeninthepower sector:the STEPS in this Outlook sees a much higher level of renewablesdeploymentto2030andbeyondthanitspredecessorscenariodidin2015,andthiscomesattheexpenseofcoalandnaturalgas.TheAPSbuildsonthesetrends,butassumesthatgovernments,companiesandcitizenstakefurthermeasurestoensurethattheresponsetothesetrendsisconsistentwithlongtermclimategoals.ThesehavecollectivelybecomemoreambitioussincetheWEO2021asaresultofnewpledgesandtargetsannouncedsincethen,notablyinIndiaandIndonesia.IntheAPS,globalenergydemandissettoincreaseby0.2%peryearto2030,comparedwith0.8%peryearintheSTEPS,reflectingmoreactivemeasuresintheAPStocurbdemandthroughenergyefficiencygains.Thereisalsoamuchmoredramaticshiftinfavouroflowemissionssourcesofenergy.TheNZEScenariomapsoutacompleteandevenmorerapidtransformationwhichisconsistentwithapathtonetzeroCO2emissionsfromenergyandindustrialprocessesby2050.TherateatwhichtheenergyefficiencyofdifferenteconomiesimprovesisacrucialvariableinourOutlook.Between2017and2020,energyintensityhasimprovedonaverageby1.3%peryearconsiderablylowerthanthe2.1%seenbetween2011and2016andtherateofimprovementfurtherslowedto0.5%in2021.IntheSTEPS,energyintensityimprovesby2.4%peryearfrom2021to2030;asaresult,around44EJ(10%oftotalfinalconsumption)isavoidedby2030.However,thisstillleavesagreatdealofuntappedpotential:intheAPS,energyintensityimprovesby3%peryear,andevenmorerapidlyintheNZEScenario.1.3.1 TrendsandvulnerabilitiesacrosstheenergymixElectricityTherearemanyuncertaintiesinourOutlook,butonepointwhichiscommontoallthescenariosistherisingshareofelectricityinglobalfinalenergyconsumption.From20%today,thisincreasesto22%by2030intheSTEPS,and28%in2050.IntheAPS,thesharerisesto24%in2030and39%in2050.IntheNZEScenario,thesharerisesfurtherto28%by2030and52%by2050.Thisisassociatedwithahugeoverallincreaseinglobalelectricitydemandoverthecomingdecadesbymidcentury,electricitydemandis75%higherthantodayinthe STEPS,120%higher in APS and 150%in the NZE Scenario.Clean electricity andelectrificationareabsolutelycentraltotheshifttoanetzeroemissionssystem.Thebulkofthegrowthcomesfromemergingmarketanddevelopingeconomies,whereelectricitymeetsabroadrangeofresidential,commercialandindustrialneeds.Growingpopulations,higherincomesandrisingtemperaturesleadtorapidlyincreasingdemandforspacecooling,whichisoneofthebiggestcontributorstoelectricitydemandgrowth;anextra2800terawatthours(TWh)globallyforspacecoolingto2050inemergingmarketanddevelopingeconomiesintheSTEPSistheequivalentofaddinganotherEuropeanUniontocurrentglobalelectricitydemand.ComparingthisdemandforspacecoolingacrosstheIEA.CC BY 4.0.Chapter 1|Overview and key findings 45 1scenariosprovidesausefulillustrationofthevalueofstringentefficiencypolicies:intheAPS,efficiencygainscutthegrowthincoolingdemandbyalmosthalf;evenmorestringentstandardsforairconditionersintheNZEScenario,togetherwithbetterinsulationinhomes,cutthisbyhalfagain.Asmodernlivesandeconomiesbecomeincreasinglyreliantonelectricity,sothereliabilityand affordability of electricity supply take centre stage in any discussion about energysecurity,anddecarbonisationofelectricitysupplybecomescentralinplanningfornetzeroemissionsgoals.Around65%ofthecoalusedgloballyin2021and40%ofthenaturalgaswereforpowergeneration.Coaluseforelectricitygenerationisrisinginmanycountries,atleasttemporarily,inresponsetotheenergycrisis.Thesharesofcoalandnaturalgasinpowergenerationaresettodecreaseto2030ineachscenario,buttovaryingdegrees(Figure1.10).Theglobalaveragecarbonintensityofelectricitygenerationiscurrently460grammesofcarbondioxideperkilowatthour(gCO2/kWh),heavilyinfluencedbytheamountofcoalinthemix.Bymidcentury,unabatedcoalfallsto12%oftotalgenerationintheSTEPS,downfrom 36%today,helping to reduce the carbon intensity of electricity generation to160gCO2/kWh.Thispointisreached20yearsearlierintheNZEScenario,whichseescarbonintensitydipbelowzeroby2050asnegativeemissionsinthepowersectoroffsetresidualemissionsinindustryandtransport.Changingdemandpatternsandrisingsharesofsolarphotovoltaics(PV)andwindintheelectricitymixputapremiumonpowersystemflexibilityasacornerstoneofelectricitysecurity.Flexibilityneeds(measuredastheamounttherestofthesystemneedstoadjustonanhourlybasistoaccommodatedemandpatternsandthevariabilityofwindandsolaroutput)increaseinallscenarios;theydoubleintheAPSby2030,forexample,andthennearlydoubleagainby2050.Therearefourmainsourcesofflexibilityinpowersystems:generation plants,grids,demandside response and energy storage.For the moment,thermalpowerplantsperformmostoftheadjustmentstomatchenergydemandandsupply,butasotherformsofflexibilitydevelopandexpand,coalandthengasfiredplantsseetheirroleasasourceofflexibilityprogressivelydiminishandeventuallydisappear.Removingexistingsourcesofflexibilitybeforeothersarescaleduprepresentsamajorrisktoelectricitysecurity.Adequateinvestmenttoexpandandmodernisegridinfrastructureisacaseinpoint.OurprojectionsintheSTEPSseeannualinvestmentofUSD770billionininfrastructureandstorageto2050asgridsincreaseinlengthbyabout90%overtheperiod.Investmentingridsandstorageis30%higheronaverageintheAPS,atclosetoUSD1trillionperyear.However,thereareobstaclesthatneedtobeaddressed.Inpractice,thepermittingandconstructionofasinglehighpoweroverheadline(400kilovolts)cantakeasmuchas13years,dependingonthejurisdictionandlengthoftheline,withsomeofthelongestleadtimesfoundinadvancedeconomies.Transmissionbottlenecksarealreadycreatingnumerousinefficienciesandrisks.Forexample,authoritiesinVietNamannouncedinearly2022thattheywouldnotconnectanynewsolarPVorwindprojecttothegridfortherestoftheyear,whileinMongolia12%oftheelectricitygeneratedin2021couldnotbetransportedtoendusers.IEA.CC BY 4.0.46 International Energy Agency|World Energy Outlook 2022 Figure 1.10 Global energy supply and demand by sector,scenario and fuel IEA.CCBY4.0.Energy efficiency,electrification and expansion of low-emissions supply are the hallmarks of rapid transitions to 2030 1202403604806007202021STEPSAPSNZECoalOilNaturalgasTraditionaluseofbiomassNuclearModernbioenergyTotalenergysupply(EJ)2030501001502002503002021STEPSAPSNZE2021STEPSAPSNZE2021STEPSAPSNZE2021STEPSAPSNZEOtherrenewablesElectricityOtherElectricityandheat(EJ)2030Industry(EJ)Transport(EJ)Buildings(EJ)203020302030IEA.CC BY 4.0.Chapter 1|Overview and key findings 47 1CleanenergysupplyandcriticalmineralsCleanenergy,includingbothlowemissionselectricityandfuels,isthebiggrowthstoryofthisOutlook.Theextentofthatgrowthstillrestsinthehandsofpolicymakers,evenwhereasinthecaseofwindandsolartheyenjoylargecostadvantagesoverothertechnologies.Buttherearesignsthattheenergycrisisisgalvanisingincreasedpolicysupport,withtheInflationReductionActintheUnitedStatesbeingaparticularlystrikingexample.Lowemissionssourcesnowaccountforaround40%ofelectricitygeneration,with30%comingfromrenewablesandanother10%fromnuclear.DeploymentofsolarPVandwindpoweracceleratesinallscenarios,settingnewrecordseveryyearto2030:bymidcenturytheircombinedshareofthesetwotechnologiesintheelectricitymixreaches45%intheSTEPSand60%intheAPS.Withintenyears,ifcountriesaretakingthenecessaryactiontodeliverontheirclimatepledges,theworldwillbedeployingaround210gigawatts(GW)ofwindcapacityeachyearand370GWofsolar.Thebalanceofdeploymentvariesbyregionandcountry.IntheUnitedStatesandIndia,forexample,solarPVbecomestheleadingtechnology.Bycontrast,theEuropeanUnionmovestowardsanelectricitysystemdominatedbyonshoreandoffshorewind,withbothsourcescombinedaccountingformorethan40%oftotalgenerationin2050intheSTEPSandover50%intheAPSandNZEScenario.The huge rise in the share of solar PV and wind in total generation in all scenariosfundamentallyreshapesthepowersystemandsignificantlyincreasesthedemandforpowersystemflexibilitytomaintainelectricitysecurity.Thisputsapremiumondispatchablelowemissionstechnologies,suchashydropower,bioenergyandgeothermal.Italsoencouragesnewapproachessuchasthecofiringofammoniaincoalplantsandlowemissionshydrogeninnaturalgasplants,aswellassomeretrofitsofexistingpowerplantswithcarboncapture,utilisationandstorage(CCUS).RegionswithhighsharesofsolarPVrelativetowindtendtoseehigherrelativelevelsofbatterydeploymentthanregionsinwhichwindpredominates,suchasChinaortheEuropeanUnion,becausetheshortdurationstoragethatbatteriesprovideiswellsuitedtosmoothoutthedailycycleofsolarPVbasedelectricitygeneration.Regionswherewindistheleadingpowergenerationtechnologytendtorelyonawiderrangeofsourcesofflexibility.Investmentinnuclearpowerisalsocomingbackintofavourinsomecountries.Therehavebeen announcements of lifetime extensions for existing reactors,often as part of theresponsetothecurrentcrisis,aswellasannouncementsofnewconstruction,forexampleinJapanandFrance.Worldwide,thelargestnewbuildnuclearprogrammeisinChinaasitworkstowardsitsgoalofcarbonneutralityby2060.Thereisgrowinginterestinthepotentialfor small modular reactors to contribute to emissions reductions and power systemreliability.Theshareofnuclearinthegenerationmixremainsbroadlywhereitistodayaround10%inallscenarios.Criticalmineralsareafundamentalpartoftheenergyandelectricitysecuritylandscape.Demandforcriticalmineralsforcleanenergytechnologiesissettorisetwotofourfoldby2030(dependingonthescenario)asaresultoftheexpandingdeploymentofrenewables,IEA.CC BY 4.0.48 International Energy Agency|World Energy Outlook 2022 EVs,batterystorageandelectricitynetworks(Figure1.11).Copperuseseesthelargestincreaseintermsofabsolutevolumes,withcurrentdemandofaround6milliontonnes(Mt)peryearincreasingto11Mtby2030intheAPSand16MtintheNZEScenario,butothercriticalmineralsexperiencefasterratesofdemandgrowth,notablysilverandsiliconforsolarPV,rareearthelementsforwindturbinemotorsandlithiumforbatteries.Boththeextractionandprocessingofcriticalmineralsarehighlyconcentratedgeographically:unlesstheneedforstrongerresilienceanddiversityinsupplychainsisaddressed,thereisariskthattheincreasinguseandimportanceofcriticalmineralscouldbecomeabottleneckforcleanenergydeployment.Figure 1.11 Mineral requirements for clean energy technologies by scenario,2021 and 2030 IEA.CCBY4.0.Mineral requirements for clean energy technologies quadruple to 2030 in the NZE Scenario,with particularly high growth for materials for electric vehicles Notes:Mt=milliontonnes;EVs=electricvehicles.Includesmostofthemineralsusedinvariouscleanenergytechnologies,butdoesnotincludesteelandaluminium.SeeIEA(2021b)forafulllistofmineralsassessed.Recyclingisanimportantandforthemomentunderutilisedoptiontoreducecriticalminerals demand:95%of solar panel components by mass are recyclable,and thepercentageforwindturbinesissimilar.IntheNZEScenario,annualcapacityretirementsforsolarPVrisefrom3GWin2030to400GWin2050,andforwindturbinesfrom16GWto240GWoverthesameperiod.Furtherpolicyeffortsareneededtoboostrecyclingandensurethatthesolarpanelsandwindturbinesreachingtheendoftheirlifedonotendupinlandfills.OtheruntappedopportunitiesforreuseandrecyclingincludespentEVbatteries,whichcanretainlargeamountsofunusedenergythatnolongermeetthestandardsforuseinavehicle;spentEVbatteriestypicallymaintainabout80%oftheirtotalusablecapacity.102030402021STEPSAPSNZEHydrogenElectricityEVsandNuclearWindSolarPVBytechnologyMt2030storageandotherrenewables102030402021STEPSAPSNZEMtOtherCobaltManganeseLithiumGraphiteNickelCopper2030BymineralIEA.CC BY 4.0.Chapter 1|Overview and key findings 49 1Whilenotincreasingatthescaleoflowemissionselectricity,theprospectsforlowemissionsfuelsarebrightening,withbiogasesandlowemissionshydrogeninparticulargettingaboostfromthecurrentenergycrisis.IntheAPS,globallowemissionshydrogenproductionrisesfromverylowlevelstodaytoreach30milliontonnesofhydrogen(MtH2)peryearin2030.Thisisequivalentto100bcmofnaturalgas(althoughnotalllowemissionshydrogenwouldreplacenaturalgasuse).Moreambitiousproductiontargetsarealsobeingsetinmanycountries for biogases and biomethane.Efforts to promote the use of hydrogen areconcentratedinEuropeandtheUnitedStates,butothercountriesarealsoactiveinthisfield:Japan,forexample,aimsfora20%rateofcofiringimportedammoniaatitscoalfiredpowerplantsby2030,andthiswillrequire0.5MtH2peryear.Liquidfuelsarederivinglessbenefitfromcurrentmarketconditions:disruptiontofoodsupplychainsandhighfertiliserpricesmeanliquidbiofuelcostshaverisensharply.Toavoidconflictsbetweenfoodproductionandaffordability,thereisageneralshiftinplanningforenergytransitionsawayfromconventionalbioenergysourcestowardsadvancedbiofuels,andaparticularfocusontwoinputs:sustainablewastestreamsthatdonotrequirespecificlanduseanddedicatedshortrotationwoodycropsgrownoncropland,pasturelandandmarginallandsthatarenotsuitedtofoodcrops.IntheNZEScenario,thereisnoincreaseincroplanduseforbioenergyandnobioenergycropsaregrownonexistingforestedland.Liquidbiofuelsincreasefrom2.2millionbarrelsofoilequivalentperday(mboe/d)in2021to3.4mboe/dintheSTEPS,5.5mboe/dintheAPSand5.7mboe/dintheNZEScenarioin2030.AviationandshippingarethelargestcontributorstotheriseinliquidbiofueldemandintheAPSandNZEScenarioasroadtransportisincreasinglyelectrified.NaturalgasTheeraofrapidgrowthinnaturalgasseemstobedrawingtoaclose.IntheSTEPS,demandrisesbylessthan5tween2021and2030andthenremainsflatataround4400bcmthroughto2050.Thisisabout750bcmlowerin2050thaninthecorrespondingscenariointheWEO2021(Figure1.12).Higherneartermprices,morerapidelectrificationofheatdemand,fasteruptakeofotherflexibilityoptionsinthepowersectorandinsomecasesrelianceoncoalforslightlylongeralldampentheoutlookforgas.Newpolicyinitiativesalsoplayanimportantpart:forexample,thesupportprovidedforavarietyofcleanenergytechnologiesbytheUSInflationReductionActisakeyreasonwhynaturalgasdemandintheUnitedStatesisaround250bcmlowerbymidcentury,comparedwiththeSTEPSintheWEO2021.RussiasinvasionofUkraineanditscutsingassupplytotheEuropeanUnionalsoaccelerateEuropesstructuralshiftawayfromnaturalgas.InboththeSTEPSandAPS,naturalgaspricesinimportingcountriesinEuropeandAsiaremainhighoverthenextfewyearsasEuropesdrivetoreducerelianceonRussianimportskeepsglobalgasmarketstightduringarelativelybarrenperiodforlargenewgasexportprojects.Arebalancingcomeslaterinthe2020swhenslowerdemandgrowthcoincideswithnewsupplyprojectscomingonline.Butthiscrisishasundercutmomentumbehindnaturalgas expansion in some large potential markets in south and southeast Asia and put aIEA.CC BY 4.0.50 International Energy Agency|World Energy Outlook 2022 significantdentintheideaofgasasatransitionfuel.Globally,aroundonequarterofthedownwardrevisiontogasdemandto2030inthisyearsSTEPSisduetolessswitchingfromcoalandoiltonaturalgas,butmostofitreflectsacceleratedswitchingfromnaturalgastocleanenergy.IntheNZEScenario,naturalgasdemandfallsfurtherandfasterthanintheSTEPSandAPS,decliningto3300bcmin2030and1200bcmin2050.Around1900bcmequivalent of lowemissions gases hydrogen,biogases and synthetic methane areconsumedgloballyintheNZEScenarioin2050.Figure 1.12 Drivers of change in natural gas demand in the WEO-2022 STEPS relative to the WEO-2021 STEPS IEA.CCBY4.0.Natural gas demand in this years STEPS is around 750 bcm lower in 2050 than in the WEO-2021,driven mainly by switching from natural gas to renewables Note:bcm=billioncubicmetres.Inallourscenarios,theEuropeanUnioncompensatesforthelossofRussianimportswithanacceleratedtransitionawayfromnaturalgasthroughasurgeinrenewablecapacityadditionsandapushtoretrofitbuildingsandinstallheatpumps,alongsideanincreasedneartermcallonnonRussiansupply,notablyviaLNG.AdditionalannualcleanenergyinvestmentofsomeUSD65billionto2030intheAPSismorethanoffsetovertimebylowernaturalgasimportcosts.MeanwhiletherearenoeasydiversificationoptionsfortheRussiangastraditionallyexportedtoEurope.Thebroadergassecuritylandscapeisdefinedbythreekeyquestions.Firstconcernstheroleofgasintheelectricitymarket.Gasaccountedfor23%ofglobalelectricitygenerationin2021andthissharedeclinesinallscenarios,albeitnotasprecipitouslyasthatofcoal.Butdeclinesin the volume of gas consumed for power generation do not imply a commensuratereductioninthevalueofgastoelectricitysecurity:naturalgasfiredcapacityremainsacriticalsourceofpowersystemflexibilityinmanymarkets,especiallytocoverforseasonal800600400200203020402050bcmMoregastorenewablesswitchingLesscoalandoiltogasswitchingAvoideddemandIEA.CC BY 4.0.Chapter 1|Overview and key findings 51 1variationsindemand.Europesgasstoragecontinuestoplayavitalrole:theshareofgasstoredtototalgasdemandin2030intheAPSissimilartothesharein2021.Secondconcernsthelevelofinvestment.Gasinfrastructureinvestmentsarecapitalintensiveand typically pay back over decades;they are therefore vulnerable to uncertaintiesconcerninglongtermdemand.ThishasalreadybeenastumblingblockforgasdiversificationeffortsinEurope:mostpotentialsuppliersarelookingforlongtermcommitments,whichEuropeanbuyersareunwillingtoprovidebecausestrongneartermneedsareunlikelytobesustainedintothe2030s.AndasimilardilemmamaycometoAsia.ThecommercialcasefornewLNGinvestmentsintheAPSisundercutbyfallingimportdemandinemergingmarketanddevelopingeconomiesinAsiainthe2040sandbeyond.Shorteningeconomiclifetimestotenyearswouldreducetheriskofnewcapacityadditionsturningintostrandedassets,butitwouldalsoincreasethebreakevengaspriceneededtofullyrecoupinvestmentcostsbyaround20%onaverage.Ashifttolowemissionshydrogenandhydrogenbasedfuelscouldprovideapartialanswertothisdilemma,butisunlikelytoofferacompletesolution.Thethirdquestionconcernsflexibilityofdelivery.Around50%ofcurrentglobalLNGtrade,250bcm,isflexibleinthesenseofhavingitsenddestinationdeterminedcargobycargobyprice competition at a late stage:the rest is governed by fixed pointtopoint deliveryarrangements.Thecurrentenergycrisishasillustratedthisflexibilitywell,withhighpricesinEuropeincentivisingamajorinfluxofcargoestomeetthecontinentsshortfallingas,albeitattheexpenseofgasimporterselsewhere,notablyamongdevelopingcountriesinAsia.However,whileflexibilityonthesupplysideislikelytobeunderpinnedbyafurtherriseinLNGexportsfromtheUnitedStates(facilitatedbythereductionsindomesticdemandarisingfromtheInflationReductionAct),thereareopenquestionsaboutflexibilityonthedemandside.Thepowersectoristypicallyanimportantproviderofflexibility,asutilitiesoftenhavetheabilitytoswitchtootherfuelsifgasbecomestoocostly.Butthephaseoutofcoalwillreducethisflexibility:asaresult,gasdemandinEuropeinparticularislikelytobecomelessresponsivetoprice,anddemandsideflexibilityislikelytobecomeconcentratedinothermarkets,notablyinChina.OilOildemandpeaksineachscenariointhisOutlook.IntheSTEPS,demandreachesahighpointinthemid2030sat103mb/dandthendeclinesverygentlyto2050.GlobalgasolinedemandpeaksintheneartermandfallsasEVsdeploy.Demandinadvancedeconomiesdeclinesby3mb/dto2030,mainlybecauseofreductionsinroadtransport,butthisismorethanoffsetbyincreasesinemergingmarketanddevelopingeconomieswheredemandrisesby8mb/dthisdecade.Globally,themainsectorsseeinganincreaseintheuseofoilareaviationandshipping,petrochemicals(whereoilisusedasfeedstock),andheavytrucks,whereoilisusedasafuelandnotdisplacedbytheriseofEVsinthesamewayasinotherroadtransportmodes.Thesesectorsseeariseindemandofaround16mb/dbetween2021and2050,butfrom the mid2030s growth in these sectors is more than offset by declining oil useelsewhere,especiallyinpassengercars,buildingsandpowergeneration.IEA.CC BY 4.0.52 International Energy Agency|World Energy Outlook 2022 ThereisnoshortageofoilresourcesworldwidetocoverthislevelofdemandintheSTEPSto2050;akeyuncertaintyforoilsecurityrelatestotheadequacyofinvestment.TheimpactoftheCovid19pandemicandthelowlevelofinvestmentinrecentyearsmeantherearerelatively few new resources under development and a dwindling stock of discoveredresourcesinthenonOPECworldavailabletobedeveloped.Newoilresourcesdiscoveredin2021wereattheirlowestlevelsincethe1930s.Moreover,thereareconcernsinsomequarters in several nonOPEC countries about the commercial wisdom and socialacceptabilityofembarkingonsignificanthighupstreamcapitalexpenditure.TheSTEPSseesneartermincreasesinoutputintheUnitedStates,GuyanaandBrazil,amongothers,butrelianceonmajorresourceholdersintheMiddleEastgrowssteadily:theshareofOPECcountriesinglobaloilproductionrisesfrom35%in2021to36%in2030and43%in2050,implyinganincreasingdegreeofmarketpowerforthatgroupofproducers.Persistentunderproductioninrecentyearsamongthisgroup,relativetothetargetedlevels,maybeaharbingeroftherisksthatlieahead.TheoutlookforoilisverydifferentintheAPS,wherestrongerpolicyactionleadsglobaloildemandtopeakinthemid2020sbeforedroppingto93mb/din2030(similartothelevelofdemandin2019).Oildemandinadvancedeconomiesfallsby7.5mb/dbetween2021and2030andincreasesby4mb/dinemergingmarketanddevelopingeconomies.ItisdifferentagainintheNZEScenario,whereglobaloildemandneverrecoverstoits2019levelandfallsbynearly20mb/dbetween2021and2030,ledbyasharpdeclineinoiluseinpassengercars(Figure1.13).Figure 1.13 Energy use in transport by scenario,2000-2050 IEA.CCBY4.0.Transport has long been the bedrock of oil demand,but its role weakens in the APS and NZE Scenario as electricity displaces very large volumes of oil Note:mboe/d=millionbarrelsofoilequivalentperday.10203040506070200020102020203020402050OilproductsElectricityBiofuelsHydrogenHydrogenbasedfuelsNaturalgasSTEPSmboe/d2020203020402050APS2020203020402050NZEIEA.CC BY 4.0.Chapter 1|Overview and key findings 53 1ThesetwoscenarioseasetherisksonthesupplysidethatariseintheSTEPS,but,despitetodaysscrambleforoilproducts,theyimplyseverelongtermpressuresforrefiners.IntheAPS,morethanhalfofcurrentrefiningcapacityfacestheriskoflowerutilisationorclosureby2050,andtherearefewcapacityadditionsafterprojectscurrentlyunderconstructioncome online.Those refiners that survive,invest to reduce emissions from refiningoperations,notablyvialowemissionshydrogen,CCUSandefficiencyimprovements.Theyalsoviewintegrationwithpetrochemicaloperationsasamajorstrategicpriority,giventhattheuseofoilasapetrochemicalfeedstockisthemostdurableelementofdemand.Itwastheonlyuseofoilthatincreasedin2020amidthedisruptionoftheCovid19pandemic,anddemandremainsrelativelyrobusteveninveryrapidtransitions:intheNZEScenario,oiluseforpassengercarsfallsby98tweentodayand2050,butoiluseforpetrochemicalsfallsbyonly10%,despitepoliciestobanorreducesingleuseplastics,improverecyclingratesandpromotealternativefeedstocks.Thisisnottosaythatthesepolicieshavenoeffects:globalaveragerecyclingratesforplasticsincreasefromthecurrentlevelof17%to27%in2050intheSTEPS,50%intheAPS,and54%intheNZEScenario.2Manyrefinersarenowconsideringexpansionintoplasticsrecyclingasanotherwaytosecurenewrevenuestreams,alongsideareassuchasliquidbiofuelsandlowemissionshydrogen.CoalCoalconsumptionisprojectedtofallinallscenarios,decliningby10%to2030intheSTEPS,by20%intheAPSoverthesameperiod,andby45%intheNZEScenario.Inthenearterm,coaldemandincreasesastheenergycrisisleadstosomeswitchingawayfromnaturalgasbecauseofconcernsabouthighpricesandavailability.Asaresult,coaldemandintheSTEPSishigherin2030thaninthesamescenariointheWEO2021.Thisincreaseindemand,however,isrelativelyshortlived:intheSTEPS,coaldemandislowerin2030thanitistoday(althoughnotaslowasprojectedintheSTEPSintheWEO2021).Byandlarge,thecurrentcrisispushesuputilisationratesforexistingcoalfiredassets,butdoesnotbringhigherinvestmentinnewones.Thisamountofadditionalcapacity,however,doesprolongtheperioduntilglobalcoalfiredcapacitypeaks(2025intheSTEPS).Inadditiontoincreaseddemandinthepowersector,coalseesariseindemandinindustryinemergingmarketanddevelopingeconomies,whereitalreadyaccountsfor35%ofenergyusedbyindustry.Thesetrendsinpowerandindustrykeepcoaldemandaroundtodayselevated levels to the mid2020s,but structural decline sets in thereafter.Overall coalconsumptionshowsamoresustainedriseonlyinafewfastgrowingcountriesandregions,notablyIndiaandSoutheastAsia.InIndia,coaldemandintheSTEPSdoesnotpeakuntiltheearly2030s,whenthedeploymentofrenewablesinthepowersectorspeedsup;intheAPS,thispeakoccursinthelate2020s,andthesubsequentdeclineincoaldemandisconsiderablysteeper.2Globally,17%ofplasticwasteiscollectedforrecyclingtodayalthoughtherearelargedifferencesbetweenregions:forexample,25%iscollectedforrecyclinginEuropeandlessthan10%intheUnitedStates.Recyclingratesforplasticsaremuchlowerthanrecyclingratesforsteel(80%),aluminium(80%)andpaper(60%).IEA.CC BY 4.0.54 Internat

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国际能源署（IEA）：2023-2024年欧洲天然气平衡报告（英文版）（12面）.pdf

Never Too Early to Prepare for Next Winter:Europes Gas Balance for 2023-2024The IEA examines the full spectrum of energy issues including oil,gas and coal supply and demand,renewable energy technologies,electricity markets,energy efficiency,access to energy,demand side management and much more.Through its work,the IEA advocates policies that will enhance the reliability,affordability and sustainability of energy in its 31 member countries,11 association countries and beyond.This publication and any map included herein are without prejudice to the status of or sovereignty over any territory,to the delimitation of international frontiers and boundaries and to the name of any territory,city or area.Source:IEA.International Energy Agency Website:www.iea.orgIEA member countries:AustraliaAustriaBelgiumCanadaCzech RepublicDenmarkEstoniaFinlandFranceGermanyGreeceHungaryIrelandItalyJapanKoreaLithuaniaLuxembourgMexicoNetherlandsNew ZealandNorwayPolandPortugalSlovak RepublicSpainSwedenSwitzerlandRepublic of TrkiyeUnited KingdomUnited StatesThe European Commission also participates in the work of the IEAIEA association countries:ArgentinaBrazilChinaEgyptIndiaIndonesiaMoroccoSingaporeSouth AfricaThailandUkraineINTERNATIONAL ENERGYAGENCYNever Too Early to Prepare for Next Winter:Europes Gas Balance for 2023-2024 Page|3 IEA.CC BY 4.0.Summary Russias natural gas deliveries to the European Union by pipeline halved in the firstten months of 2022 compared with the same period in 2021,a drop of 60 billion cubicmetres(bcm).For the full year,Russias pipeline supplies are expected to decline by over55%,a drop of 80 bcm,putting unprecedented pressure on both European and global gasmarkets.EU gas storage sites are now 95%full putting them 5%,or 5 bcm,above their 5-yearaverage.The process of filling EU storages over the summer of 2022 benefitted from twofactors that might not be repeated in 2023:30 bcm of Russian gas supplied to the EUvia pipeline,and lower LNG imports by China due to its economic slowdown and Covid-induced lockdowns.The cushion provided by the current mild temperatures,lower gas prices and highstorage levels should not lead to overly optimistic predictions about the future.Thecombination of lower-than-normal gas demand in October and persistently strong LNGinflows has put strong downward pressure on day-ahead prices,which fell below USD10/MMBtu by the end of October against an all-time high of USD 100/MMBtu at the endof August.However,Europe is not out of the woods yet,and our analysis identifies somesignificant risks ahead in 2023 and 2024.Global LNG supply is expected to increase by only 20 bcm in 2023,much less thanthe likely additional reduction in Russian pipeline deliveries.Russian pipeline gasdeliveries to the EU in 2022 are set to reach around 60 bcm.But in 2023,they will in allprobability drop to less than half that amount and could cease completely.Chinas LNG imports could rebound next year to close to their 2021 levels aseconomic growth recovers after Covid-related lockdowns.This would capture over 85%of the expected increase in global LNG supply,much of which has in any case alreadybeen contracted to China,thereby limiting the amount of LNG cargoes available to theEuropean market in 2023.If Russian pipeline gas supplies to the EU cease completely and Chinese LNGimports recover to 2021 levels,Europe could face a supply-demand gap of 30 bcmduring the key summer period for refilling gas storage in 2023.This gap couldrepresent almost half the gas required to fill storage sites to 95pacity by the startof the 2023-24 heating season.More rapid deployment of energy efficiency measures,renewables and heat pumpsis needed to reduce the risk of a worsening energy and gas crisis.This will requireimmediate action from governments.A further push to accelerate structural changes andreduce gas consumption is essential not only for Europes clean energy transitions but alsofor its energy security and the wellbeing of its citizens and industries.The IEA will present a roadmap for securing Europes gas balance for next wintershowing what is needed to ensure storage sites are filled to 95pacity by the beginningof the 2023-24 heating season and to structurally reduce gas consumption during thewinter.Never Too Early to Prepare for Next Winter:Europes Gas Balance for 2023-2024 Page|4 IEA.CC BY 4.0.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 Russias steep cuts to natural gas deliveries Russias pipeline gas deliveries to the European Union halved in the first tenmonths of 2022 compared with last years levels.The decline in absolute termswas 60 bcm,the equivalent of over 10%of the global LNG trade.The steep declinein Russian gas supplies coincided with multi-year lows in European hydro andnuclear power output(down by 20%and 16%year-on-year,respectively),puttinghuge pressure on European gas markets.Gas prices on the Dutch Title Transfer Facility(TTF)a leading European gashub averaged over EUR 130/MWh(USD 40/MMBtu)year-to-date,almost eighttimes the 5-year average between 2016 and 2020.The all-time high pricesattracted record LNG inflows to the European Union and the United Kingdom,rising by 65%or over 50 bcm year-on-year in the first ten months of 2022.Gas demand in the European Union and the United Kingdom in the first 10 monthsof 2022 was down by an estimated 10%,or over 40 bcm,compared with the sameperiod a year earlier.This was mainly the result of lower consumption across theresidential,commercial and industrial sectors,but it also includes some efficiencygains and behavioural responses to higher prices.It also reflects demanddestruction,particularly in gas-intensive industries.Non-Russian pipeline supplies to Europe increased substantially.Pipelinedeliveries from Norway rose by 5%(5 bcm)and flows from Azerbaijan via theTrans Adriatic Pipeline surged by close to 50%(3 bcm)year-on-year in the firstten months of 2022.In both cases,export infrastructure is running close tonameplate capacity.Algeria increased its pipeline supplies to Europe by over 10%(or 3 bcm)on available export routes in the first ten months of the year,and hassome limited upsideNever Too Early to Prepare for Next Winter:Europes Gas Balance for 2023-2024 Page|5 IEA.CC BY 4.0.Year-on-year changes in global LNG exports and imports by key regions,January October 2022 IEA.CC BY 4.0.Strong European demand for LNG led to a reconfiguration of global LNG flows asincreases in LNG supply(23 bcm)were not sufficient to meet Europes rapidlyrising LNG imports.Higher LNG flows towards Europe were enabled in part byChinas LNG imports falling by 20%(or 19 bcm)year-to-date as it drasticallyreduced spot procurements.Europes thirst for LNG also disrupted gas andelectricity supply in more price-sensitive markets,including in South Asia.Mild weather,healthy storage levels and strong LNG supply have led to a significant fall in some natural gas price markers The combination of higher non-Russian gas imports and lower demand wasinstrumental for Europe to offset Russias gas supply cuts and enable a near-record build-up of storage levels.Storage injections were 22%,or 13 bcm,abovetheir 5-year average in 2022.At the beginning of November,EU storage sites wereclose to 95%full well above the European Unions 80%target and well-alignedwith the IEAs 10-Point Plan to Reduce the European Unions Reliance on RussianNatural Gas.Unseasonably mild weather in October reduced gas demand from distributionnetworks(concentrated in the commercial and residential sectors)by over 30%year-on-year and effectively delayed the start of the heating season in mostEuropean markets.This steep decline in demand coincided with a persistentlystrong influx of LNG cargoes,which have limited immediate flexibility to changedestination,as deliveries are typically scheduled several weeks in advance.Lower-than-expected demand,together with high LNG inflow and healthy storagelevels,pushed down European gas prices.Month-ahead prices on TTF fell to just01020304050Yoy change(bcm)EUOtherEuropeLower demand in AsiaLower demand in South AmericaDemand in other regionsLNG export growth from the USSupply growth from other regionsChinaNever Too Early to Prepare for Next Winter:Europes Gas Balance for 2023-2024 Page|6 IEA.CC BY 4.0.below EUR 100/MWh(USD 30/MMBtu)by the end of October.This was less than one-third of the all-time high at the end of August but still more than five times the 5-year average during the 2016-20 period.Day-ahead prices which are morereflective of short-term supply-demand factors fell below USD 10/MMBtu at theend of October,while next-hour prices dropped into negative territory for a shortperiod on 24 October amid infrastructure constraints in the TTF market zone.Day-ahead and month-ahead TTF prices(August October 2022)EU gas storage levels(1 November 2022)IEA.CC BY 4.0.The temporary comfort provided by todays market conditions should not lead to overly optimistic conclusions about the future:a cold spell could quickly change sentiment and Europes gas balance faces even tougher tests in 2023 While EU gas inventories are standing 5%,or 5 bcm,above their 5-year average,this additional storage cushion could be quickly erased:5 bcm is just two days ofEU gas demand during a cold spell.There is a wide range of possible outcomes for EU gas storage at the end of thiswinter heating season.Assuming no or very low Russian gas deliveries to theEuropean Union this winter,and average levels of LNG imports(around 13 bcmper month),then gas storage levels could be anywhere between 5%and 35%bythe end of the heating season,depending on demand trajectories over the comingmonths.Variable demand trajectories,which can be influenced by policies as well as pricesand weather,translate into a variety of future scenarios for gas injection needsduring the summer of 2023.These vary between 60 bcm and 90 bcm in order toreach 95%storage levels by the beginning of the 2023-24 heating season.05010015020025030035001-Aug-2209-Aug-2217-Aug-2225-Aug-2202-Sep-2210-Sep-2218-Sep-2226-Sep-2204-Oct-2212-Oct-2220-Oct-2228-Oct-22EUR/MWhTTF month-aheadTTF day-ahead020406080100201720182019202020212022bcmEU storage levels5-year averageNever Too Early to Prepare for Next Winter:Europes Gas Balance for 2023-2024 Page|7 IEA.CC BY 4.0.Considering current market trends,our assessment today is that the storageinjection 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 thisNovember-March period is 11low its 5-year average.A colder-than-averagewinter could deplete European storage levels faster,resulting in injection needs inthe range of 80-90 bcm.Potential EU and UK storage levels by end March 2023 Resulting injection needs in summer 2023 to reach 95%fill level IEA.CC BY 4.0.Note:assuming no Russian piped gas to the European Union from 1st of January and average(13 bcm/month)LNG imports into the European Union and the United Kingdom.Measures to limit short-term demand and storage depletion,alongside morestructural measures to bring down gas demand,are absolutely essential toposition Europe for next year.The drive to refill Europes gas storages for the2023-24 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 higherAlthough Russian gas deliveries to Europe were cut sharply during 2022,theywere close to normal levels for much of the first half of the year.Total pipelinesupply from Russia in 2022 is likely to amount to around 60 bcm.It is highlyunlikely that Russia will deliver another 60 bcm of piped gas in 2023.If supplyremains at current levels,then Russian pipeline supply would be around 25 bcmin 2023.It is also entirely possible that Russian deliveries could fall further orcease entirely.Non-Russian pipeline suppliers have limited upside potential,with both Azerbaijanand Norway supplying close to their nameplate capacity in 2022.In the case ofAlgeria,some limited upside is expected with the development of gas fields in theBerkine South basin.0 0mandreduction5y average9mandreductionno demandreductionFill levels02040608010013mandreduction2022 injections9mandreductionno demandreductionbcmInjection needs to 95%Never Too Early to Prepare for Next Winter:Europes Gas Balance for 2023-2024 Page|8 IEA.CC BY 4.0.Change in non-Russian pipeline gas deliveries to Europe IEA.CC BY 4.0.Global LNG supply is expected to increase by 20 bcm in 2023,supported mainlyby the ramp-up of the Calcasieu Pass LNG facility in the United States and theCoral South LNG facility in Mozambique,as well as the return of the Freeport LNGfacility in the United States.However,this increased LNG supply will not be notsufficient to offset the likely decline in Russias pipeline deliveries to the EuropeanUnion.Domestic gas production in the European Union is set to decline in 2023.In theNetherlands,production at the Groningen field was capped at 2.8 bcm for the2022-23 Gas Year1,down from 4.5 bcm in the 2021-22 Gas Year.Production fromsmall fields in the Netherlands also continues to decline.In Denmark,the restartof the Tyra field was postponed to the 2023-24 winter meaning that it will notcontribute to the refilling of gas storages during summer 2023.In the UnitedKingdom,gas production recovered strongly in 2022 and the potential for furthershort-term growth is limited.Even more significantly,Chinas LNG imports could rebound next year.Chinaslower LNG imports in the first ten months of 2022 were a key enabler of higherLNG availability to Europe.A return to stronger Chinese economic growth andsome easing of lockdowns could bring 2023 LNG imports back to their 2021 levels(108 bcm),which would capture over 85%of next years expected increase inglobal LNG supply and limit the amount of LNG available to the European market.China has pursued a strong LNG contracting strategy in recent years.As a result,Chinas reliance on destination-fixed LNG contracts is set to increase from 88 bcmper year in 2022 to 100 bcm per year in 2023.This effectively means that China1 A Gas Year starts on 1 October and ends on 30 September.-30%-20%-10%0 0%-30-20-10010203020192020202120222023Y-o-y change(%)Y-o-y change(bcm)NorwayNorth AfricaAzerbaijanY-o-y changeNever Too Early to Prepare for Next Winter:Europes Gas Balance for 2023-2024 Page|9 IEA.CC BY 4.0.will have the right-of-first-refusal on an additional 12 bcm of LNG well over half of the expected increase in global LNG supply in 2023.In mid-October,it was widely reported that Chinas National Development andReform Commission had asked state-owned gas importers to stop reselling LNGto buyers in Europe and Asia to ensure stable gas supply ahead of winter.Structure of Chinas LNG import contracts IEA.CC BY 4.0.EU gas exports to Ukraine are set to rise.Ukraine started the 2022-23 heatingseason with storage levels at just 14 bcm well below their historic average.Evenassuming a 25%reduction in the countrys winter gas consumption,storage sitesare expected to be severely depleted by the end of March 2023.Our analysisindicates that Ukraine would require at least 5 bcm of gas imports from theEuropean Union during the summer of 2023 to replenish its storage levels to 14bcm by the start of the 2023-24 heating season.Europe could face a 30 bcm shortfall in the gas it needs to fuel its economy and sufficiently refill storage sites during the summer of 2023,jeopardising its preparations for the winter of 2023-24 A full cessation of Russian pipeline gas supplies to the European Union combinedwith a return of Chinese LNG imports to their 2021 levels would lead to a shortfallof 30 bcm of gas in Europe during the summer of 2023,the period when gasstorage sites need to be refilled.This equates to almost half of the injections required to fill storage sites to 95%ofcapacity by the start of the 2023-24 heating season.This is based on the02040608010012020192020202120222023bcm/yDestination-fixedDestination-flexibleNever Too Early to Prepare for Next Winter:Europes Gas Balance for 2023-2024 Page|10 IEA.CC BY 4.0.assumption that natural gas demand in the European Union and the United Kingdom will decline by 11%compared to its 5-year average during the November 2022 March 2023 period and that Europes gas storage sites will be around 30%full at the end of this winter.Breakdown of the summer 2023 natural gas balance of the European Union and the United Kingdom in case of full cessation of Russian flows and limited LNG availability,April September 2023 IEA.CC BY 4.0.A recovery in European hydropower generation to its 5-year average and highernuclear power output in France(aligned with the mid-range of EDFs latestguidance)could reduce the shortfall to 22 bcm,but it would not eliminate it.This puts the spotlight back on natural gas demand.Shortfalls in available supplywould put immense pressure on prices again,but this could be relieved byaccelerated structural changes in European gas demand.An even faster deployment of renewables,heat pumps and energy efficiency measures can mitigate the risks of a worsening energy and gas crisis While healthy storage levels and unseasonably mild weather at the beginning ofthe 2022-23 winter season provide some temporary relief to gas and relatedenergy markets in Europe,our analysis indicates that supply-demandfundamentals are set to tighten in 2023.A more rapid deployment of renewables,heat pumps and energy efficiencymeasures can mitigate the risk of a worsening energy and gas crisis.However,this would require immediate action from governments.The IEA will present a roadmap for securing Europes gas balance for nextwinter showing what is needed to ensure storage sites are filled to 95pacity0255075100125150175200225DemandSupply-demandgapIncrementalLNGLNGAzerbaijanNorth AfricaDomesticproductionNorwaybcm2022 summer demandneedsInjectionExports to UkraineNever Too Early to Prepare for Next Winter:Europes Gas Balance for 2023-2024 Page|11 IEA.CC BY 4.0.by the beginning of the 2023-24 heating season and to structurally reduce gas consumption during the winter.Key measures include:Speeding up investments in energy efficiency improvements.Faster deployment of renewables.Accelerated installation of heat pumps.Identifying remaining fuel-switching options in industry and the power sector.Behavioural changes.A further push to accelerate structural changes and reduce gas consumption isessential not only for Europes clean energy transitions but also for its energysecurity and the wellbeing of its citizens and industries.The current market context requires greater attention to instruments andmeasures that could facilitate investment in methane abatement options.International Energy Agency(IEA).This work reflects the views of the IEA Secretariat but does not necessarily reflect those of the IEAs individual Member countries or of any particular funder or collaborator.The work does not constitute professional advice on any specific issue or situation.The IEA makes no representation or warranty,express or implied,in respect of the works contents(including its completeness or accuracy)and shall not be responsible for any use of,or reliance on,the work.Subject to the IEAs Notice for CC-licenced Content,this work is licenced under a Creative Commons Attribution 4.0 International Licence.This document and any map included herein are without prejudice to the status of or sovereignty over any territory,to the delimitation of international frontiers and boundaries and to the name of any territory,city or area.Unless otherwise indicated,all material presented in figures and tables is derived from IEA data and analysis.IEA Publications International Energy Agency Website:www.iea.org Contact information:www.iea.org/contact Typeset in France by IEA-November 2022Cover design:IEA

31人看过 2022-11-07 12面 5星

GIZ：无障碍运输 - 来自欧盟和德国的一般发展报告（英文版）（16 页）.pdf

Barrier-free Transport Overview of Developments in the European Union and Germany Implemented by Supported by based on a decision of the German Bundestag Imprint As a federally owned enterprise,GIZ supports the German Government in achieving its objectives in the field of international cooperation for sustainable development.Published by:Deutsche Gesellschaft fr Internationale Zusammenarbeit(GIZ)GmbH Registered offices Bonn and Eschborn,Germany Address:Tayuan Diplomatic Office Building 2-5 14 Liangmahe South Street,Chaoyang District 100600,Beijing,PR China T 86-(0)10-8527 5589 F 86-(0)10-8527 5591 E transition-chinagiz.de I www.mobility.transition-china.org Project:Sino-German Cooperation on Mobility and Fuels Strategy(MFS)as a Contribution to the Mobility and Transport Transition.Sino-German Cooperation on Low Carbon Transport(CLCT)CLCT Project is part of the International Climate Initiative(IKI).The Federal Ministry for the Environment,Nature Conservation and Nuclear Safety(BMU)supports this initiative on the basis of a decision adopted by the German Bundestag.Responsible Sebastian Ibold(GIZ),Alexander von Monschaw(GIZ)E transition-chinagiz.de I www.mobility.transition-china.org Author Mia Hallmanns,Eric Thomas Editor Carolin Bernhard(GIZ),Gregor Bauer(GIZ)Layout Xin Hu(GIZ),Qingmo Zhou(GIZ)Photo credits U(Cover page)URL links Responsibility for the content of external websites linked in this publication always lies with their respective publishers.GIZ expressly dissociates itself from such content.Beijing,2021 Contents Introduction 1 Definition of Barrier-free Transport 2 Status Quo of Barrier-free Transport Development in the European Union 3 Status Quo of Barrier-free Transport Development in Germany 3 Overview on Barrier-free Development Policies,Standards and Norms in Germany 5 Overview on Relevant Associations and Governmental Agencies in Germany 6 Financing of Barrier-free Transport Infrastructure in Germany 7 Best Practices in Germany by Transportation Mode 9 Conclusion 11 1 Introduction Globally,around one billion people experience some form of disability and one fifth of the global total have substantially limited ability to participate independently in society.1 Shifting the focus to Germany,there were approximately 7.9 million people as of late 2019 with severe disabilities,requiring extensive ongoing support in more than one major life activity.2 According to the German Federal Statistical Office,almost 60%of those people were aged 65 and above,while less than 10%were between the age of 25 and 44 or even younger than 25 years.3 Due to increased life expectancy and a prolonged participation in public life,the total resources to meet the populations needs are growing,for instance in the realm of technology,public infrastructure,and public service provision.Hereby various challenges arise.These challenges begin with the mere integration of people into public life by allowing them a high degree of 1 World Health Organization(2020):Disability and health.https:/www.who.int/en/news-room/fact-sheets/detail/disability-and-health.2 Federal Statistical Office(2020):Press re-lease:7.9 million severely disabled people liv-ing in Germany.https:/www.desta-tis.de/EN/Press/2020/06/PE20_230_227.html.self-determination.Enabling peoples individual mobility thus represents a critical driver for improving their quality of life.Indeed,commuting in daily life comes with a multitude of physical,digital or social barriers,irrespective of age or specific disabilities.From high curbs over high ticket prices to guidance systems in public spaces,these existing barriers complicate and impede peoples mobility and limit their choices for their means of transport.Barrier-free mobility is an important key for inclusive future urban development and sustainable societies.Urban transport systems need to become more inclusive and accessible.Mobility opportunities,meaning being able to freely choose ones means of transport,are a key element of the personal,social,and professional development of every individual,particularly for people with disabilities or mobility constraints.Many disabled persons without their own car rely on public transport.Accessible trains,subways,buses and 3 Federal Statistical Office(2020):Press re-lease:7.9 million severely disabled people liv-ing in Germany.https:/www.desta-tis.de/EN/Press/2020/06/PE20_230_227.html.2 coaches,as well as tramcars are essential for their participation in public life.The goal of achieving a barrier-free transport system is also formulated in the Agenda 2030.Under Sustainable Development Goal(SDG)11“Sustainable Cities and Communities”,a core target is to“provide access to safe,affordable,accessible and sustainable transport systems for all,improving road safety,notably by expanding public transport,with special attention to the needs of those in vulnerable situations,women,children,persons with disabilities and older persons.”The Agenda 2030 also acts as a guiding framework for the projects implemented by the Deutsche Gesellschaft fr internationale Zusammenarbeit(GIZ)GmbH.Definition of Barrier-free Transport A general European framework for a barrier-free society,in which every person has the equal right to participate,is set by the United Nations Convention on the Rights of Persons 4 PT Access(2008):Report on good Practice Examples of accessible Public Transport,6-7.https:/www.eltis.org/sites/default/files/PTac-cess_-_good_practice_2009_6.pdf.with Disabilities(UN Disability Rights Convention),adopted by the General Assembly in New York on December 13,2006.Germany was one of the first countries to sign the convention in 2007 and ratify it in 2009.Beyond this UN framework,there is however no coherent definition of“barrier-free”in Europe and every country sets its own standards in its transport infrastruc-ture.4 In Germany,barrier-free transport is defined in the Disability Discrimination Act(Behinder-tengleichstellungsgesetz;BGG),issued in 2002 by the German federal parliament.It emphasizes that“barrier-free are buildings,special facilities,means of transport,technical subjects,information systems,acoustic and visual sources of information and communication devices and other objects of everyday use accessible to people with reduced mobility,easily available,without undue restrictions and fundamentally without assistance”(4 BGG).5 Eliminating barriers for disabled people in the transport system,such as 5 Federal Ministry of Justice and Consumer Protection(2002):Disability Discrimination Act.https:/www.gesetze-im-inter-net.de/bgg/BJNR146800002.html.3 unsuitable stairs,differences in height between floors,barriers in interchanges,space between the platform and vehicle,low frequency of accessible public transport modes,lack in accessible information on local transport options or limited use of mobile apps in barrier-free trip planning,is thus highly important.Correspondingly,the main objectives of accessible public transport systems tie to increased comfort and safety of all citizens whilst enabling them to move independently from one place to another.6 Status Quo of Barrier-free Transport Development in the European Union Based on the UN Disability Rights Convention,the European Accessibility Act(EAA)is the foundation for EU member states legislation,a directive that aims to improve the functioning of the internal 6 Federal Ministry of Justice and Consumer Protection(2002):Disability Discrimination Act.https:/www.gesetze-im-inter-net.de/bgg/BJNR146800002.html.7 Acknowledgment:On European level,an“Act”by law has no binding force in European market for accessible products and services by removing barriers created by divergent rules in member states from 2025 onwards.7 Businesses get a common set of guiding rules applicable within the EU that facilitate cross-border trade for companies providing accessible products and services.For persons with disabilities,this means a greater range of accessible products and services,such as computers and operating systems,ATMs,ticketing and check-in machines,or services related to air,bus,rail,and waterborne passenger transport.Status Quo of Barrier-free Transport Development in Germany In Germany,barrier-free transport is a crucial quality factor in the realm of transport,especially public transport,and part of Germanys larger vision of making cities and rural areas more nation states.For the implementation,the act must be transferred into national law.There-fore,on the ground the object of interest is the law on the national level,thus,the PBefG in Germany,not the EAA on the European level.(See:Bundesfachstelle-Barrierefreit).4 sustainable and inclusive.8 In order to guarantee mobility opportunities especially for people with disabilities or mobility constraints,the transport sector was included in the Disability Discrimination Act(BGG).Important financial support to develop and implement barrier-free transport infrastructure is given by the federal government to federal states and local authorities.9 Currently,Germany still faces numerous challenges linked to inaccessible infrastructures,navigation systems and services.Considering infrastructural accessibility,different standards for platforms heights as stipulated by a German railway regulation in 1991 and the mismatch with different vehicle types still hinder level access at many train stations.Attempts to further standardise platform heights via the 2011“Concept for Platform Heights”10 have shown some 8 Federal Ministry of Transport and Digital In-frastructure(2019):Well-connected by public transport.https:/www.bmvi.de/Shared-Docs/EN/Dossier/OEPNV/significance-of-local-public-transport.html 9 Federal Ministry of Transport and Digital Infra-structure(2019):Well-connected by public transport.https:/www.bmvi.de/Shared-Docs/EN/Dossier/OEPNV/significance-of-local-public-transport.html 10 Kieffer,Eberhard,Jrgen Ernst and Christi-ane Jasper-Ottenhus.(2014).Das Bahnsteig-hhenkonzept der DB AG.https:/www.deut-towards more accessibility.Yet,according to data published in 2020 by the German Federal Ministry of Transport and Digital Infrastructure(BMVI),on average 1/6 of German train stations is currently still not barrier-free and lacks critical infrastructures such as elevators,escalators and ramps,with stark differences between accessibility levels in different regions.11 In terms of service affordability,the above average increase in ticket prices for public transport depicts another dimension of inaccessibility.The German Environment Agency(UBA)concluded that prices for public transport have risen twice as much as costs associated with owning a private car.12 These conditions severely affect people with disabilities,since many rely on public transportation due to disabilities hindering them from using private cars.Particularly on the“last-mile,”13 passengers oftentimes 219423424773/ETR-05_2014-Bahn-steighhenkonzept-data.pdf.11 Allianz Pro Schiene.(2020):Viele Bahnhfe machen es Rollstuhlfahrern schwer.https:/www.allianz-pro-schiene.de/presse/pressemitteilungen/viele-bahnhoefe-machen-es-rollstuhlfahrern-schwer/5.12 Federal Environment Agency 2020,15.13 The term“last mile”is commonly used in the realm of transport,where it describes the last stage of urban passenger travel or the last leg of supply chain delivery before the final desti-nation.See Business Insider(21 January 5 use private vehicles,but equally benefit from a diversified range of active,including shared vehicle modes,which are largely inaccessible to people with special mobility needs.The inaccessibility of public transport is furthermore particularly prevalent in rural areas,where less frequent public transport services often coincide with lower population densities,albeit higher shares of elderly and other people with mobility constraints,who critically rely on such public transport offers.Overview on Barrier-free Development Policies,Standards and Norms in Germany The Disability Discrimination Act(BGG),aimed at eliminating discrimination against people with disabilities in Germany,entered into force on May 1,2002.The transport sector is the main focus of the BGG(2021).https:/Federal Ministry of Transport and Digital In-frastructure(n.d.):Well-connected by public 8 of the BGG concerns barrier-free transport provisions),establishing equal opportunities and barrier-free access to transport.On the basis of the BGG,various other laws were adopted including the Municipal Transport Financing Act(GVFG),the Passenger Transportation Act(PBefG),the Railway Construction and Operating Regulations(EBO),the Air Traffic Act(LuftVG),and the Federal Highway Act(FStrG).14 By 2022,the Passenger Transportation Act(PBefG),for instance,will require barrier-free accessibility for all public transport.The goal is to make transport services accessible for all groups of society and especially consider people with special mobility needs.Various guidelines,standards,and norms are guiding and regulating the provision of barrier-free transport infrastructure development and services in Germany,including:Handbook Accessibility in Long Distance Bus Services,issued by the German Federal Ministry of Transport and Digital Infrastructure(BMVI).The transport.https:/www.bmvi.de/Shared-Docs/EN/Dossier/OEPNV/significance-of-local-public-transport.html.6 handbook provides an overview of the measures for long-distance bus services including e.g.the requirement that from January 2020 all public buses must be barrier-free and equipped with at least two seats for wheelchair users.In addition,the handbook offers further recommendations on how to make long-distance bus services more inclusive.Barrier-free Public Transport in Germany,issued by the BMVI and the Association of German Transport Companies(VCV).The document provides an overview on the efforts of German transport companies,public transport authorities,and policymakers to achieve accessibility in public transport,it identifies existing problems and presents adequate solutions and recommendations for vehicles,transport infrastructure,information,and service.Overview on Relevant Associations and Governmental Agencies in Germany In Germany,the discourse on barrier-free transport is facilitated by a variety of associations and agencies,for instance initiatives by federal ministries,online platforms for knowledge exchange by transport and construction companies,or larger research projects on the topic.Specific initiatives include:Barrier-free mobility With its contents,the online platform has the goal of expanding specialist knowledge about barrier-free planning and construction in public transport areas.The project is supported by various construction companies specialized in inclusive infrastructure,including manufacturers of tactile building bricks for pavements and platforms.It informs about relevant norms and standards as well as regulations on the construction of streets,street crossings,and bus and railway platforms.German Association for the Blind and Visually Handicapped(DBSV)The DBSV develops minimum standards for barrier-free access to the built environment and public transport and takes the special needs of blind and visually impaired people into consideration.In doing so,the expert committee draws on the experience of those affected and those providing professional services.In addition,it also includes results from practical studies in its work.The Association prepares statements,participates in standardization projects,and works 7 together with manufacturers and developers.Federal Office for Accessibility The Federal Office for Accessibility is part of the Initiative for Inclusive Social Space(Initiative Sozialraum Inklusiv)initiated by the German Federal Ministry of Labour and Social Affairs.Among others,it provides consultancy on the barrier-free design of services and infrastructures.Transport Innovation for disabled People needs Satisfaction(TRIPS)TRIPS is a consortium with the goal of making“public transport more accessible for persons with disabilities,elderly voyagers and really everyone”.Consortium partners include,among others,UITP or the German Aerospace Center(DLR).Mobile Inclusion Project TU Berlin The focus of the project is the economic aspect of barrier-free mobility by taking“mobility poverty”into consideration.While identifying urban districts with residents affected by transport disadvantage,its project maps can indicate potential or a need for transport planning interventions.Federal Association of Self-help for the Physically Disabled(BSK)The BSK is an association of citizens with physical disabilities committed to reducing barriers for disabled persons 15 Heavy Goods Vehicle(HGV)tolling was introduced to federal motorways in 2005 as a shift from using taxation revenue for fed-eral trunk road construction to using fees from road users,hence user financing.It has since been expanded and its specifications adjusted,for further details see Federal Ministry of Transport and and improve their integration into society.Federal Government Commissioner for the Interests of the Disabled This institution is responsible for the coordinating of efforts to implement standards and commitments made in the United Nations Convention on the Rights of Persons with Disabilities.These efforts include the cooperation with national and international associations in the civil society as well as the coordination of relevant activities such as the publication of studies and reports.Financing of Barrier-free Transport Infrastructure in Germany The funding of transport infrastructure in Germany comes from various sources:Tax revenue,accounting for about two thirds of the funding budget;revenue from the Heavy Goods Vehicle tolling scheme(user financing)15 which provides about one third;and additional funds from the European Union or through Public Private Partnerships.Digital Infrastructure(2018):The HGV tolling scheme.https:/www.bmvi.de/SharedDocs/EN/Articles/StV/Tolling-Scheme/hgv-tolling-scheme-2018.html.8 Figure based on“Sources of Transport Infrastructure Funding”BMVI.16 While experts still criticise severe underinvestment in public infrastructures,the total investment has continuously increased,amounting to 80 billion,equivalent to 2.4%of GDP in 2018.17 Amongst others,it is used to improve the quality of individual modes of transport federal railways,federal trunk roads,and waterways.The Federal Government also provides municipalities with funds to improve local transport conditions.The municipality can then decide how to use the funds.Additionally,Public Private Partnerships(PPP)are also a common 16 Federal Ministry of Transport and Digital In-frastructure(n.d.):Finance(Finanzierung)https:/www.bmvi.de/DE/Themen/Mobilitaet/In-frastrukturplanung-Investitionen/Finanzier-ung/finanzierung.html.17 Federal Ministry for Economic Affairs and Energy.(2020).ffentliche Infrastruktur in Deutschland:Probleme und Reformbedarf.https:/www.bmwi.de/Redaktion/DE/Publikatio-way of making funding of transport infrastructure more effective.18 To present one example of ongoing funding measures,the BMVI plans to upgrade over 3,000 train stations in the upcoming years investing 5 billion euro until 2026.The plan includes finances for the barrier-free redesign of 111 smaller stations(330 million;up to 1,000 passengers daily),50 medium-sized stations(330 million;1.000-4,000 passengers daily),50 large and medium-sized station buildings(142 million;up to 50,000 passengers daily)and includes the adaption of platform nen/Ministerium/Veroeffentlichung-Wissen-schaftlicher-Beirat/gutachten-oeffentliche-infra-struktur-in-deutschland.pdf?_blob=publica-tionFile&v=12.18 Federal Ministry of Transport and Digital In-frastructure(n.d.):Finance(Finanzierung)https:/www.bmvi.de/DE/Themen/Mobilitaet/In-frastrukturplanung-Investitionen/Finanzier-ung/finanzierung.html.User Financing(1/3 of the overall budget)Conventional funding:funds from the federal budget(2/3 of the overall budget)Transport infrastructure finance Additional Financing:Public Private Partnerships,EU Funding 9 height,ramps,elevators,guidance systems,signs,and information systems.The German state-owned bank KfW also offers programmes for cities,public transport operators and construction companies to finance barrier-free infrastructure.19 The funding programmes include a comprehensive scope of measures,such as for the barrier-free redesign of public buildings,traffic layouts and for public space in general.For the transport sector in particular,the programmes focus on subway,railway and tram stations,overpasses and underpasses,as well as on digital assistance systems.For the public realm in general,the programmes include the lowering of sidewalks,guidance systems for blind people,barrier-free public sanitary infrastructure and barrier-free playgrounds.20 Best Practices in Germany by Transportation Mode In public transport Specific laws,regulations and norms set the framework for the planning of public transport systems,and the design of stations and stops of trains,trams,buses,etc.aiming at providing equal and barrier-free transport offerings for people.As described above,a number of interest groups,research institutes,and both public and private stakeholders are engaged in related projects,from which several best practices can be highlighted:19 Requirements for the funding programs can be accessed via:KfW(2015):IKK und IKU Barrierefreie Stadt.https:/www.kfw.de/PDF/Download-Cen-ter/Frderprogramme-(In-landsfrderung)/PDF-Doku-mente/6000002503_M_233_234_An-lage_TMA.pdf.20 KfW(2021):IKK Barrierearme Stadt.https:/www.kfw.de/inlandsfoerde-rung/ffentliche-Einrichtungen/Kom-munen/Stadt-ohne-Barrieren/.10(Source:wheelmap.org)(Source:visitberlin.de)Digital barrier-free travel assistance tools:Smartphone apps that assist trip planning and barrier-free routing“Wheelmap”,an online,worldwide map for finding and marking wheelchair accessible places,developed by a German non-profit organisation.Anyone can find and add public places to the map and rate them according to a simple traffic light system.The“accessBerlin”App includes options for mobility restricted or blind/partially blind users around the city of Berlin.The app includes maps,bus routes,as well as pictures and descriptions of barrier-free attractions,culture highlights and accommodation,shopping and maps.Mobility Service Center of German Railways(Source:Berliner Behindertenzeitung)Option to book assistance at stations and find a journey companion for people with special mobility needs.From 2015 to 2020,the number of passengers with special mobility needs has almost doubled,leading to more than 875000 requests for service provision at the DB Mobility Service Centres.21(Source:German Railways website)DB Bahnhof live“App-App by German Railways allowing navigation on train stations and showing e.g.trains entrances for wheel-chair users-Showing elevators in stations(Source:kurier.de)Widespread use of buses with the ability to hydraulically lower themselves at the right(door)side to reduce the height difference between the platform and the bus floor-In long distance buses-Design manual,implementation guide and relevant norms etc.published by the BMVI in May 2017:Handbook on barrier free long distance bus traffic 11 Conclusion Germany has already set a strong legal ground for accessible public transport via various anti-discrimination acts,guidelines and infrastructure norms.Whilst current initiatives showcase the potential of grassroots organisations in further improving accessibility to existing transportation modes,and new legislation together with the respective public funding of barrier-free infrastructures confirm the increased awareness of the issue in German politics,there are however still major challenges ahead to ensure mobility for all,as it written down in the PBefG.A structural shift towards“disability mainstreaming”,meaning the design of barrier-free public(transport)infrastructures by default,must be critically underpinned by strengthened discourse on the sustainability of people-centred traffic systems.Indeed,urban and rural transport planning can both foster the overall mobility of people irrespective of demographic or disability,whilst reducing climate impacts via more environmentally-friendly transport modes such as taking shared vehicles or smoothly navigating through barrier-free infrastructures via bicycle or by foot.In this regard,international cooperation between Germany and other countries can open up new perspectives by offering a platform of exchange on common challenges,distinct policy approaches and innovative solutions for barrier-free mobility services.12 Sources Allianz Pro Schiene.(2020):Viele Bahnhfe machen es Rollstuhlfahrern schwer.https:/www.allianz-pro-schiene.de/presse/pressemitteilungen/viele-bahnhoefe-machen-es-rollstuhlfahrern-schwer/5.Auracher,Jelena and Gabriele Weigt(2019):iNUA Factsheet#6:Accessible Urban Mobility.https:/www.transformative-mobility.org/publications/inua-6-accessible-urban-mobility.European Commission(2019):Best practices guide on the carriage of persons with reduced mobility.https:/op.europa.eu/en/publication-detail/-/publication/bb3b7e92-df40-11e9-9c4e-01aa75ed71a1.European Commission(2020):How many people can you reach by public transport,bicycle or on foot in European cities?Measuring urban accessibility for low-carbon modes.https:/ec.europa.eu/re-gional_policy/en/information/publications/working-papers/2020/low-carbon-urban-accessibility.Federal Environment Agency.(2020).Transformation of Transportation:This is how we achieve a more socially just and environmentally compatible mobility.(Verkehrswende fr ALLE.So erreichen wir eine sozial gerechtere und umweltvertrgliche Mobilitt.)https:/www.umweltbundesamt.de/sites/default/fi-les/medien/376/publikationen/2020_pp_verkehrswende_fuer_alle_bf_02.pdf.Federal Ministry of Transport and Digital Infrastructure(n.d.):Accessibility-an important quality feature in public transport(Barrierefreiheit-wichtiges Qualittsmerkmal im ffentlichen Personenverkehr).https:/www.bmvi.de/SharedDocs/DE/Artikel/G/barrierefreiheit-im-oeffentlichen-personenverkehr.html.Federal Ministry of Justice and Consumer Protection(2002):Disability Discrimination Act.https:/www.gesetze-im-internet.de/bgg/BJNR146800002.html.Federal Ministry of Transport and Digital Infrastructure(n.d.):Finance(Finanzierung)https:/www.bmvi.de/DE/Themen/Mobilitaet/Infrastrukturplanung-Investitionen/Finanzierung/finanzier-ung.html.Federal Ministry of Transport and Digital Infrastructure(2019):Well-connected by public transport.https:/www.bmvi.de/SharedDocs/EN/Dossier/OEPNV/significance-of-local-public-transport.html.Federal Statistical Office(2020):Press release:7.9 million severely disabled people living in Germany.https:/www.destatis.de/EN/Press/2020/06/PE20_230_227.html.Kieffer,Eberhard,Jrgen Ernst and Christiane Jasper-Ottenhus(2014):Das Bahnsteighhenkonzept der DB AG.https:/Access(2008):Report on good Practice Examples of accessible Public Transport,6-7.https:/www.eltis.org/sites/default/files/PTaccess_-_good_practice_2009_6.pdf.World Health Organization(2020):Disability and health.https:/www.who.int/en/news-room/fact-sheets/detail/disability-and-health.Deutsche Gesellschaft fr Internationale Zusammenarbeit(GIZ)GmbH Sitz der Gesellschaft Bonn und Eschborn Friedrich-Ebert-Allee 32 36 53113 Bonn,Deutschland T 49 228 44 60-0 F 49 228 44 60-17 66 E infogiz.de I www.giz.de Dag-Hammarskjld-Weg 1-5 65760 Eschborn,Deutschland T 49 61 96 79-0 F 49 61 96 79-11 15

5 人看过 2022-11-07 16面 5星

国际能源署 (IEA)：2022 年全球能源和气候模型报告（英文版）（133 页）.pdf

DocumentationGlobal Energy and Climate Model DocumentationGlobal Energy and Climate Model The IEA examines the full spectrum of energy issues including oil,gas and coal supply and demand,renewable energy technologies,electricity markets,energy efficiency,access to energy,demand side management and much more.Through its work,the IEA advocates policies that will enhance the reliability,affordability and sustainability of energy in its 31 member countries,11 association countries and beyond.Please note that this publication is subject to specific restrictions that limit its use and distribution.The terms and conditions are available online at www.iea.org/t&c/This publication and any map included herein are without prejudice to the status of or sovereignty over any territory,to the delimitation of international frontiers and boundaries and to the name of any territory,city or area.Source:IEA.International Energy Agency Website:www.iea.orgIEA member countries:Australia Austria Belgium CanadaCzech Republic Denmark Estonia Finland France Germany Greece Hungary Ireland ItalyJapanKorea Lithuania Luxembourg Mexico Netherlands New Zealand Norway Poland Portugal Slovak Republic Spain Sweden Switzerland Republic of TrkiyeUnited Kingdom United StatesThe European Commission also participates in the work of the IEAIEA association countries:INTERNATIONAL ENERGYAGENCYArgentinaBrazilChinaEgyptIndiaIndonesiaMoroccoSingaporeSouth AfricaThailandUkraineIEA.CC BY 4.0.Table of Contents 1 Table of Contents 1 Overview of model and scenarios.5 1.1 GEC Model scenarios.6 1.2 Selected developments in 2022.10 1.3 GEC Model overview.12 2 Cross-cutting inputs and assumptions.17 2.1 Population assumptions.17 2.2 Macroeconomic assumptions.18 2.3 Prices.19 2.4 Policies.22 2.5 Techno-economic inputs.23 3 End-use sectors.25 3.1 Industry sector.25 3.2 Transport sector.30 3.3 Buildings sector.39 3.4 Hourly electricity demand and demand-side response.42 4 Electricity generation and heat production.45 4.1 Electricity generation.45 4.2 Value-adjusted Levelized Cost of Electricity.50 4.3 Electricity transmission and distribution networks.53 4.4 Hourly model.56 4.5 Mini-and off-grid power systems.57 4.6 Renewables and combined heat and power modules.57 4.7 Hydrogen and ammonia in electricity generation.59 4.8 Utility-scale battery storage.60 5 Other energy transformation.61 5.1 Oil refining and trade.61 5.2 Coal-to-liquids,Gas-to-liquids,Coal-to-gas.62 5.3 Hydrogen production and supply.62 5.4 Biofuel production.65 6 Energy supply.69 6.1 Oil.69 6.2 Natural gas.73 6.3 Coal.74 6.4 Bioenergy.75 2 International Energy Agency|Global Energy and Climate Model Documentation 7 Critical minerals.79 7.1 Demand.80 7.2 Supply requirements.80 8 Emissions.81 8.1 CO2 emissions.81 8.2 Non-CO2 greenhouse gases.81 8.3 Air pollution.82 8.4 Global temperature impacts.82 8.5 Oil and gas methane emissions model.82 9 Investment.89 9.1 Investment in fuel supply and the power sector.89 9.2 Demand-side investments.91 9.3 Financing for investments.92 9.4 Emissions performance of investments.93 10 Energy and CO2 decomposition.95 10.1 Methodology.96 11 Energy access.97 11.1 Defining modern energy access.97 11.2 Outlook for modern energy access.98 12 Employment.99 12.1 Definition and scope of employment.99 12.2 Estimating current employment.100 12.3 Outlook for employment.101 13 Assessing government spending on clean energy and energy affordability.103 13.1 Government spending policy identification and collection.103 13.2 Assessing the impact on overall clean energy investment.104 Annex A:Terminology.107 Definitions.107 Regional and country groupings.114 Acronyms.118 Annex B:References.121 Table of Contents 3 List of figures Figure 1.1 Global Energy and Climate Model Overview 13 Figure 2.1 Components of retail electricity end-use prices 21 Figure 3.1 General structure of demand modules 25 Figure 3.2 Major categories of technologies by end-use sub-sector in industry 26 Figure 3.3 Industry sector model internal module structure and key data flows 28 Figure 3.4 Structure of the transport sector 32 Figure 3.5 Illustration of scrappage curve and mileage decay by vehicle type 33 Figure 3.6 The role of passenger-LDV cost model 34 Figure 3.7 Illustration of an efficiency cost curve for road freight 35 Figure 3.8 Refuelling infrastructure cost curve(illustrative)36 Figure 3.9 Structure of the buildings sector 39 Figure 3.10 Major categories of technologies by end-use subsector in buildings 41 Figure 3.11 Illustrative load curves by sector for a weekday in February in the European Union compared to the observed load curve by ENTSO-E for 2014 43 Figure 4.1 Structure of the power generation module 45 Figure 4.2 Load duration curve showing the four demand segments 47 Figure 4.3 Example merit order and its intersection with demand in the power generation module 48 Figure 4.4 Example electricity demand and residual load 49 Figure 4.5 Exemplary electricity demand and residual load 50 Figure 4.6 Moving beyond the LCOE,to the value-adjusted LCOE 51 Figure 4.7 Electricity network expansion per unit of electricity demand growth by GDP per capita 54 Figure 5.1 Schematic of refining and international trade module 61 Figure 5.2 Schematic of merchant hydrogen supply module 63 Figure 6.1 Structure of the oil supply module 71 Figure 6.2 Evolution of production of currently producing conventional oil fields from a field-by-field database and from the GEC Model 73 Figure 6.3 Schematic of biomass supply potentials 75 Figure A.1 GEC Model regional groupings 115 List of tables Table 1.1 Definitions and objectives of the GEC Model 2022 scenarios 6 Table 2.1 Population assumptions by region 17 Table 2.2 Real GDP average growth assumptions by region and scenario 18 Table 2.3 Fossil fuel prices by scenario 19 Table 2.4 CO2 prices for electricity,industry and energy production in selected regions by scenario 20 Table 2.5 Capital costs for selected technologies by scenario 24 Table 6.1 Remaining technically recoverable fossil fuel resources,end-2021 74 Table 7.1 Critical minerals in scope 79 Table 8.1 Categories of emission sources and emissions intensities in the United States 83 Table 8.2 Scaling factors applied to the United States emission intensities 83 Table 8.3 Equipment-specific emissions sources used in the marginal abatement cost curves 84 Table 8.4 Abatement options for methane emissions from oil and gas operations 85 Table 9.1 Sub-sectors and assets included in fuel supply investment 90 Table 9.2 Sub-sectors and assets included in power sector investment 91 Table 9.3 Sub-sectors and assets included in end-use energy investment 92 4 International Energy Agency|Global Energy and Climate Model Documentation List of boxes Box 1.1 An integrated approach to energy and sustainable development in the Net Zero Emissions by 2050 Scenario 9 Box 4.1 Long-term potential of renewables 58 Box 6.1 GEC Model differences in methodology compared with the Medium-Term Oil Market Report 70 Box 6.2 Methodology to account for production decline in oil and gas fields 72 Section 1|Overview of model and scenarios 5 Section 1 1 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 worlds 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:IEAs 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 IEAs publications.The GEC Model brings together the modelling capabilities of the WEM and ETP models.The result is a large-scale bottom-up partial-optimisation modelling framework allowing for a unique set of analytical capacities in energy markets,technology trends,policy strategies and investments across the energy sector that would be critical to achieve climate goals.IEAs GEC Model covers 26 regions individually that can be aggregated to world-level results and all sectors across the energy system with dedicated bottom-up modelling for:Final energy demand,covering industry,transport,buildings,agriculture and other non-energy use.This is driven by detailed modelling of energy service and material demand.Energy transformation,including electricity generation and heat production,refineries,the production of biofuels,hydrogen and hydrogen-derived fuels and other energy-related processes,as well as related transmission and distribution systems,storage and trade.Energy supply,including fossil fuels exploration,extraction and trade,and availability of renewable energy resources.The GEC Model is a very data-intensive model covering the whole global energy system.Much of the data on energy supply,transformation and demand,as well as energy prices is obtained from the IEAs own databases of energy and economic statistics(http:/www.iea.org/statistics)and through collaboration with other institutions.It also draws data from a wide range of external sources which are indicated in the relevant sections of this document.The development of the GEC Model benefited from expert review within the IEA and beyond,and the IEA continues to work closely with colleagues in the international modelling community.The GEC Model is designed to analyse a diverse range of aspects of the energy system,including:Global and regional energy prospects:these include trends in demand,supply availability and constraints,international trade and energy balances by sector and by fuel in the projection horizon.Environmental impact of energy use:this includes CO2 emissions from fuel combustion,process emissions and from flaring,methane emissions from the oil and gas sector and coal mining,CH4 and N2O emissions from final energy demand and energy transformation local air pollutants,and temperature outcome.Effects of policy actions and technological changes:scenarios analyse the impact of a range of policy actions and technological developments on energy demand,supply,trade,investments and emissions.Investment in the energy sector:this includes investment requirements in the fuel supply chain to satisfy projected energy demand and demand-side investment requirements.Modern energy access assessments:these include trends in access to electricity and clean cooking facilities,and the additional energy demand,investments and CO2 emissions due to increased energy access.Energy employment:this includes the impact of the scenarios on employment in various energy sectors 6 International Energy Agency|Global Energy and Climate Model Documentation 1.1 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 WEO-2022 and ETP-2023 based on the integrated GEC modelling cycle explore three scenarios,all of which are fully updated to include the latest energy market and cost data.The Net Zero Emissions by 2050 Scenario(NZE Scenario)is normative,in that it is designed to achieve specific outcomes an emissions trajectory consistent with keeping the temperature rise in 2100 below 1.5 C(with a 50%probability),universal access to modern energy services and major improvements in air quality and shows a pathway to reach it.The Announced Pledges Scenario(APS),and the Stated Policies Scenario(STEPS)are exploratory,in that they define a set of starting conditions,such as policies and targets,and then see where they lead based on model representations of energy systems,including market dynamics and technological progress.The 2022 GEC modelling cycle does not include the Sustainable Development Scenario(SDS),which is another normative scenario used in previous editions to model a“well below 2 C”pathway as well as the achievement of other sustainable development goals.The APS outcomes are close,in some respects,to those in the SDS,in particular in terms of the temperature outcome.But they are the product of a different modelling approach and so as long as policy ambition does not fully capture all SDS outcomes,the APS falls short of achieving those.Table 1.1 Definitions and objectives of the GEC Model 2022 scenarios Net Zero Emissions by 2050 Scenario Announced Pledges Scenario Stated Policies Scenario Definitions A scenario which sets out a pathway for the global energy sector to achieve net zero CO2 emissions by 2050.It does not rely on emissions reductions from outside the energy sector to achieve its goals.Universal access to electricity and clean cooking are achieved by 2030.A scenario which assumes that all climate commitments made by governments around the world,including Nationally Determined Contributions(NDCs)and longer-term net zero targets,as well as targets for access to electricity and clean cooking,will be met in full and on time.A scenario which reflects current policy settings based on a sector-by-sector and country by country assessment of the specific policies that are in place,as well as those that have been announced by governments around the world.Objectives To show what is needed across the main sectors by various actors,and by when,for the world to achieve net zero energy related and industrial process CO2 emissions by 2050 while meeting other energy-related sustainable development goals such as universal energy access.To show how close do current pledges get the world towards the target of limiting global warming to 1.5 C,it highlights the“ambition gap”that needs to be closed to achieve the goals agreed at Paris in 2015.It also shows the gap between current targets and achieving universal energy access.To provide a benchmark to assess the potential achievements(and limitations)of recent developments in energy and climate policy.Section 1|Overview of model and scenarios 7 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).An inventory of the key policy assumptions available along with all the underlying data on population,economic growth,resources,technology costs and fossil fuel prices are available in the Macro Drivers and Techno-economic inputs pages.For the first time,the projections were generated by a unified model that integrates the strengths the previous World Energy Model(WEM)and the Energy Technology Perspectives(ETP)model.Combining the detailed features of the two previous models allows us to prepare a unique set of insights on energy markets,investment,technologies and the policies that would be needed for the clean energy transition.Net Zero Emissions by 2050 Scenario The Net Zero Emissions by 2050 Scenario(NZE)is a normative IEA scenario that shows a pathway for the global energy sector to achieve net zero CO2 emissions by 2050,with advanced economies reaching net zero emissions in advance of others.This scenario also meets key energy-related United Nations Sustainable Development Goals(SDGs),in particular by achieving universal energy access by 2030 and major improvements in air quality.It is consistent with limiting the global temperature rise to 1.5 C with no or limited temperature overshoot(with a 50%probability),in line with reductions assessed in the IPCC in its Sixth Assessment Report.There are many possible paths to achieve net zero CO2 emissions globally by 2050 and many uncertainties that could affect any of them;the NZE Scenario is therefore a path,not the path to net zero emissions.Much depends,for example,on the pace of innovation in new and emerging technologies,the extent to which citizens are able or willing to change behaviour,the availability of sustainable bioenergy and the extent and effectiveness of international collaboration.The Net Zero Emissions by 2050 Scenario is built on the following principles:The uptake of all the available technologies and emissions reduction options is dictated by costs,technology maturity,policy preferences,and market and country conditions.All countries co-operate towards achieving net zero emissions worldwide.This involves all countries participating in efforts to meet the net zero goal,working together in an effective and mutually beneficial way,and recognising the different stages of economic development of countries and regions,and the importance of ensuring a just transition.An orderly transition across the energy sector.This includes ensuring the security of fuel and electricity supplies at all times,minimising stranded assets where possible and aiming to avoid volatility in energy markets.In recent years,the energy sector was responsible for around three-quarters of global greenhouse gas(GHG)emissions.Achieving net zero energy-related and industrial process CO2 emissions by 2050 in the NZE Scenario does not rely on action in areas other than the energy sector,but limiting climate change does require such action.We therefore additionally examine the reductions in CO2 emissions from land use that would be commensurate with the transformation of the energy sector in the NZE Scenario,working in cooperation with the International Institute for Applied Systems Analysis(IIASA).8 International Energy Agency|Global Energy and Climate Model Documentation Announced Pledges Scenario The Announced Pledges Scenario introduced in 2021 aims to show to what extent the announced ambitions and targets,including the most recent ones,are on the path to deliver emissions reductions required to achieve net zero emissions by 2050.It includes all recent major national announcements as of September 2022 for 2030 targets and longer-term net zero and other pledges,regardless of whether these have been anchored in implementing legislation or in updated NDCs.In the APS,countries fully implement their national targets to 2030 and 2050,and the outlook for exporters of fossil fuels and low emissions fuels like hydrogen is shaped by what full implementation means for global demand.For the first time,the APS assumes this year that all country-level access to electricity and clean cooking targets are achieved on time and in full.The way these pledges are assumed to be implemented in the APS has important implications for the energy system.A net zero pledge for all GHG emissions does not necessarily mean that CO2 emissions from the energy sector need to reach net zero.For example,a countrys net zero plans may envisage some remaining energy-related emissions are offset by the absorption of emissions from forestry or land use.It is not possible to know exactly how net zero pledges will be implemented,but the design of the APS,particularly with respect to the details of the energy system pathway,has been informed by the pathways that a number of national bodies have developed to support net zero pledges.Policies in countries that have not yet made a net zero pledge are assumed to be the same as in the STEPS.Non-policy assumptions,including population and economic growth,are the same as in the STEPS.Stated Policies Scenario The STEPS provides a more conservative benchmark for the future,because it does not take it for granted that governments will reach all announced goals.Instead,it takes a more granular,sector-by-sector look at what has actually been put in place to reach these and other energy-related objectives,taking account not just of existing policies and measures but also of those that are under development.The STEPS explores where the energy system might go without a major additional steer from policy makers.As with the APS,it is not designed to achieve a particular outcome.The policies assessed in the Stated Policies Scenario cover a broad spectrum.These include Nationally Determined Contributions under the Paris Agreement,but much more besides.In practice,the bottom-up modelling effort in this scenario requires a lot of detail at the sectoral level,including pricing policies,efficiency standards and schemes,electrification programmes as well as specific infrastructure projects.The scenario takes into account the policies and implementing measures affecting energy markets that had been adopted as of end of September 2022,together with relevant policy proposals,even though specific measures needed to put them into effect have yet to be fully developed.The sorts of announcements made by governments include some far-reaching targets,including aspirations to achieve full energy access in a few years,to reform pricing regimes and,more recently,to reach net zero emissions in some countries and sectors.As with all the policies considered in the Stated Policies Scenario,these ambitions are not automatically incorporated into the scenario:full implementation cannot be taken for granted,so the prospects and timing for their realisation are based upon our assessment of countries relevant regulatory,market,infrastructure and financial circumstances.Where policies are time-limited,they are generally assumed to be replaced by measures of similar intensity,but we do not assume future strengthening or weakening of future policy action,except where there already is specific evidence to the contrary.Section 1|Overview of model and scenarios 9 The STEPS shows that in aggregate,current country commitments are enough to make a significant difference.However,there is still a large gap between the projections in the STEPS and a trajectory of the other two scenarios.Box 1.1 An integrated approach to energy and sustainable development in the Net Zero Emissions by 2050 Scenario The Net Zero Emissions by 2050 Scenario(NZE Scenario)integrates three key objectives of the UN 2030 Agenda for Sustainable Development:universal access to modern energy services by 2030(embodied in SDG 7),reducing health impacts of air pollution(SDG 3.9),and action to tackle climate change(SDG 13).As a first step,we use the GEC Model to assess how the energy sector would need to change to deliver universal access to modern energy services by 2030.To analyse electricity access,we combine cost-optimisation with new geospatial analysis that takes into account current and planned transmission lines,population density,resource availability and fuel costs.Second,we consider ambient and household air pollution and climate goals.The policies necessary to achieve the multiple SDGs covered in the NZE Scenario are often complementary.For example,energy efficiency and renewable energy significantly reduce local air pollution,particularly in cities,while access to clean cooking facilitated by liquefied petroleum gas also reduces household air pollution and overall greenhouse gas emissions by reducing methane emissions from incomplete combustion of biomass as well as by reducing deforestation.Trade-offs can also exist,for example between electric vehicles reducing local air pollution from traffic,but at the same time increasing overall CO2 emissions if there is not a parallel effort to decarbonise the power sector.Ultimately,the balance of potential synergies or trade-offs depends on the route chosen to achieve the energy transition,making an integrated,whole-system approach to scenario building essential.The emphasis of the NZE Scenario is on technologies with short project lead times in the power sector in particular,such as renewables,while the longer-term nature of climate change allows for other technology choices.Modern uses of biomass as a decarbonisation option is also less relevant in the NZE than in a single-objective climate scenario.This is because biomass is a combustible fuel,requiring post-combustion control to limit air pollutant emissions and depending on the region in question-making it more costly than alternatives.Since its launch in 2021,the NZE Scenario,also looks at the implications for the energy sector for achieving several of the targets under United Nations Sustainable Development Goal 6(clean water and sanitation for all)and what policymakers need to do to hit multiple goals with an integrated and coherent policy approach.In order to reflect in our modelling the announcements made by several countries to achieve carbon neutrality by 2050 and also allows us to model the potential for new technologies(such as hydrogen and renewable gases)to be deployed at scale,the time horizon of the model is 2050.The interpretation of the climate target embodied in the NZE Scenario also changes over time,as a consequence of both ongoing emissions of CO2 as well as developments in climate science(refer to the 8 Emissions section for more details).Despite the fundamental changes across all sectors the NZE scenario still ensures an orderly transition.This includes ensuring the security of fuel and electricity supplies at all times,minimising stranded assets where possible and aiming to avoid volatility in energy markets.10 International Energy Agency|Global Energy and Climate Model Documentation 1.2 Selected developments in 2022 In addition to the overall merge process of the previous WEM and ETP models and their data pipelines,sectoral and topic-specific developments this year,undertaken as part of the GEC Model development,include the following:Final energy consumption Behavioural analysis Several new specific behavioural changes have been modelled in detail,including measures to manage growth in aviation demand,such as frequent flyer levies,and the impact of measures to reduce the sales and use of SUVs.In addition,the modelling of the potential for ride-sharing to impact demand was covered in detail.The regional granularity of modelling has been improved to reflect differences in the potential scope,scale and speed of adoption of behavioural changes.Inputs into this modelling include the ability of existing infrastructure to support such changes and differences in geography,climate,urbanisation,social norms and cultural values.Buildings module The buildings module underwent significant updates for the 2022 modelling cycle,the module now fully combines the strengths of the pre-existing WEO and ETP modelling frameworks,allowing for more detailed representation of the stock of buildings and technologies.The new merged framework notably includes:A stock accounting model used to describe the evolution of buildings,tracking the vintage of each building,its energy service demand,energy performance,lifetime and whether the building has undergone a retrofit to improve its energy efficiency.Upon construction,buildings are classified into three categories:non-compliant to building energy codes,compliant to building energy codes and zero-carbon-ready building.Constructed buildings can then be retrofit to improve energy efficiency,and are categorised as:retrofit to compliant,or retrofit to zero-carbon-ready.Improved representation of the building stock allows for better representation of the impact of changes to building energy codes and other policy actions,the evolution of building floor area by vintage,the gains that can be achieved by retrofitting buildings,including the ability to target retrofits toward the least efficient buildings.Building upon local climate data,population density mapping and regional estimates of energy demand by end-use and sector provide a basis for distributing heating and cooling demand at the local level and assessing clean technology deployment strategies.For instance,the assessment of heat and cold demand densities at the city or district level is key to making sound judgement calls on the decarbonisation potential of district energy systems(together with other variables such as the share of variable renewables in the electricity mix and the availability of waste heat sources).Local climate and population data are also used to derive heat pump energy performance.Industry module The industry module went through a complete overhaul to take the best of both WEO and ETP frameworks.The new module enables a precise representation of heavy industries(chemicals,iron and steel and cement)and light industries(construction,food,machinery equipment,mining and quarrying,textile and leather,and wood and wood products),industrial capacity projections and related lock-in emissions analysis.The previous TIMES models for heavy industry are retained as satellite modules that can be used for exploratory analysis in order to inform the GEC module parameters,for example testing the impact of a particular shock,new technology or other important change in the system.Section 1|Overview of model and scenarios 11 Transport module The transport module integrated the framework of WEO and ETP modules,to allow for improved sectoral representation across all modes:road,aviation,navigation and rail.The integrated model utilises mainly Vensim,as well as dedicated modules developed in Java and R.For road,scrappage functions are extended across all vehicle types to improve sectoral representation,and dynamic scrappage function is implemented based on a correlation of average lifetime with economic growth.Mileage curves have been updated to take into account that old vehicles are driven less.Aviation modelling has integrated main features of the Aviation Integrated Modelling(AIM)tool developed by University College London(UCL)including:Operational and technical potential for energy intensity improvements based on iterative cost minimisation modelling across different airframe-propulsion systems and stock accounting.Electricity generation The structure of the grids component of the module has been significantly expanded to include increased detail on line and cable types.This includes by voltage level,overhead line or underground cable,and AC or DC lines and cables.In addition,cost inputs for both new and replacement lines have increased in granularity by line type as well as by region.Finally,the impacts of integrating high shares of renewables have been further developed in terms of transmission grid reinforcements and grid forming requirements.Energy supply Against the backdrop of an increasingly fragmented world,the oil and gas supply modules account this year for a wide range of financial risks(e.g.,geopolitics,rule of law,regulatory oversight).This improves the representation of decisions made by companies looking to invest in oil and natural gas fields in different countries.Other transformation Hydrogen module The temporal resolution of the hydrogen module has been enhanced by introducing sub-annual time slices to capture the variability in dedicated renewable electricity generation(solar PV,onshore wind,offshore wind)for the production of hydrogen and hydrogen-based fuels and to enable the modelling of hydrogen storage.A tool to analyse the regional hydrogen infrastructure needs and related investments for pipelines,ships,port terminals and storage has been developed.Biofuel production module The modelling of trade in liquid biofuels between the 26 GEC Model regions has been expanded by adding biojet kerosene to the already existing trade modelling for ethanol and biodiesel.Critical minerals The critical minerals module has been updated with a more granular technology representation(e.g.,battery chemistry,grid type and voltage levels,types of EV motors)and mineral intensity inputs,while also being fully linked to existing modules of the GEC model(transport,electricity generation and hydrogen transformation).12 International Energy Agency|Global Energy and Climate Model Documentation Energy access In previous years,energy access was assessed in two different scenarios:STEPS looking at the impacts of access policies(for electricity and clean cooking),and the achievement of SDG7(universal access to electricity and clean cooking).This edition of APS not only include all current announced energy and climate commitments but also electricity and clean cooking countries targets.The APS assumes that all these targets are implemented in full and on time.Employment Current employment now reflects the labour required for future projects in the pipeline.Value chain segments have been aligned with the International Standard Industrial Classification(revision 4).The model now incorporates parameters estimating labour productivity improvements.Global trade is reflected by a new calculation reflecting the regional distributions of manufacturing capacity for key clean energy technologies.The granularity for fossil fuel supply and power generation has been improved.Assessing government spending on clean energy and energy affordability The IEA has extended the scope of its government spending monitoring to cover both clean energy investment support and energy affordability for consumers in response to the energy crisis.Mobilisation effects on private investment have also been updated since last year.1.3 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).The main exogenous drivers of the scenarios are economic growth,demographics and technological developments.Energy service demand drivers,such as steel demand in industry or number of appliances within households,are estimated econometrically based on historical data and on the socioeconomic drivers.Interactions between energy service demand drivers are also accounted for,such as the influence of the number of vehicles sales on materials demand.This service demand is met by existing and new technologies.All sector modules(see subsequent sections for more details on these modules)base their projections on the existing stock of energy infrastructure(e.g.,the number of vehicles in transport,production capacity in industry,floor space area in buildings),through detailed stock-accounting frameworks.To assess how the service demand is met in the various scenarios,the model includes a wide range of fuels and technologies(existing and additions).This includes careful accounting of the current energy performance of different technologies and processes,and potential to improve efficiency.Section 1|Overview of model and scenarios 13 Figure 1.1 Global Energy and Climate Model Overview IEA.CC BY 4.0.The sectoral and cross-sectoral energy and emission balances are calculated based on the final energy end uses the service demand by determining first the final energy demand needed to serve it,then the required transformations to convert primary energy into the required fuels,and finally the primary energy needs.This is based on a partial equilibrium approach using for some elements a partial optimisation model,within which specific costs play an important role in determining the share of fuels and technologies to satisfy the energy service demand.In different parts of the model,Logit and Weibull functions are used to determine the share of 14 International Energy Agency|Global Energy and Climate Model Documentation technologies based upon their specific costs.This includes investment costs,operating and maintenance costs,fuel costs and in some cases costs for emitting CO2.In certain sectors,such as hydrogen production,specially designed and linked optimisation modules are used.While the model aims to identify an economical way for society to reach the desired scenario outcomes,the results do not necessarily reflect the least-cost way of doing so.This is because an unconstrained least-cost approach may fail to take account of all the issues that need to be considered in practice,such as market failures,political or individual preferences,feasible ramp-up rates,capital constraints and public acceptance.Instead,the analysis pursues a portfolio of fuels and technologies within a framework of cost minimisation,considering technical,economic and regulatory constraints.This approach,tailored to each sector and incorporating extensive expert consultation,enables the model to reflect as accurately as possible the realities of different sectors.It also offers a hedge against the real risks associated with the pathways:if one technology or fuel fails to fulfil its expected potential,it can more easily be compensated by another if its share in the overall energy mix is low.All fuels and technologies included in the model are either already commercially available or at a relatively advanced stage of development,so that they have at least reached a prototype size from which enough information about expected performance and costs at scale can be derived.Costs for new clean fuels and technologies are expected to fall over time and informed in many cases by learning curve approaches,helping to make a net zero future economically feasible.Besides this main feedback loop between supply and demand,there are also linkages between the transformation and supply modules.Further linkages between energy sectors are captured in the model,e.g.,material flows or biogenic or atmospheric CO2 via Direct Air Capture for synthetic fuel production.Primary energy needs and availability interact with the supply module.Complete energy balances are compiled at a regional level and the CO2 emissions of each region are then calculated using derived CO2 factors,taking into account reductions from CO2 removal technologies.The GEC Model is implemented in the simulation software Vensim(),but makes use of a wider range of software tools,including TIMES(https:/iea-etsap.org/index.php/etsap-tools/model-generators/times).Data inputs The GEC Model is a data-intensive model covering the whole global energy system.Much of the data to calibrate to historical energy supply,transformation and demand,as well as energy prices,is obtained from the IEAs own databases of energy and economic data.Additional data from a wide range of often sector-specific external sources is also used in particular to establish historic size and performance of energy-consuming stocks.The model is each year recalibrated to the latest available data.The formal base year is currently 2020,as this is the last year for which a complete picture of energy demand and production is in place.However,we have used more recent data wherever available,and we include 2021 and 2022 estimates for energy production and demand.Estimates are based on updates of the Global Energy Review reports which relies on a number of sources,including the latest monthly data submissions to the IEA Energy Data Centre,other statistical releases from national administrations,and recent market data from the IEA Market Report Series that cover coal,oil,natural gas,renewables and electricity.For a summary of selected key data inputs including macro drivers such as population,economic developments and prices as well as techno-economic inputs such as fossil fuel resources or technology costs please view the Global Energy and Climate Model key input dataset(https:/www.iea.org/data-and-statistics/data-product/global-energy-and-climate-model-2022-key-input-data).Section 1|Overview of model and scenarios 15 Regional coverage and time horizon The GEC Model covers the energy developments in the full global energy system up to 2050,with the capacity to extend beyond 2050 for some regions.Simulations are carried out on an annual basis.The current version of the model provides results for 26 regions of the globe,of which 12 are individual countries.Several supply components of the model have further regional disaggregation:the oil and gas supply model has 113 regions and the coal supply model 32 regions.Capabilities and features IEAs GEC Model offers unparalleled scope and detail on the energy system.Its raison dtre is evaluating energy supply and demand,as well as the environmental impacts of energy use and the impacts of policy and technology developments on the energy system.Through long-term scenario analysis,the model enables analysis of possible futures related to the following main areas:Global and regional energy trends:this includes assessment of energy demand,supply availability and constraints,international trade and energy balances by sector and by fuel.Environmental impact of energy use:CO2 emissions from fuel combustion are derived from the projections of energy consumption.CO2 process emissions are calculated based on the production of industrial materials and CH4 and N2O emissions are assessed for final energy demand as well as for energy transformation.Methane from oil and gas operations are assessed through bottom-up estimates and direct emissions measurements(see Methane Tracker).This allows to publish the CO2-equivalent emissions for the entire energy sector.Local air pollutants are also estimated linking the GEC Model with the GAINS model of the International Institute for Applied Systems Analysis(IIASA)and the temperature outcomes of modelled scenarios are assessed.Policy and technology developments:alternative scenarios analyse the impact of a range of policy actions and technological developments on energy demand,supply,trade,investments and emissions.Additionally,the GEC Model has multiple detailed features that either underlying or build from analysis of the broader energy trends.These include the following:Technologies:Detailed techno-economic characterisation of clean energy technologies under development(either at prototype or demonstration stage)including different applications in heavy industries,long distance transport and carbon dioxide removal technologies among more than 800 hundred technologies covered.People-centred:Detailed modelling of behavioural changes,energy sector employment and energy affordability among other implications for citizens.Critical minerals:Comprehensive analysis of projected demand and supply of critical minerals for the energy sectors transition.Infrastructure:Detailed modelling and analysis on enabling energy infrastructure development needs and strategies including:electricity systems,fossil fuels,hydrogen-related fuels distribution and CO2 transport options.Variable renewables potential:Detailed geospatial analysis of variable renewables potentials across the globe and modelling of their impact of exploiting those for hydrogen production.Modern energy access:Comprehensive modelling of the implications and opportunities to provide energy access to all communities.This includes access to electricity and clean cooking facilities,and an evaluation of additional energy demand,investments and related greenhouse gas emissions.16 International Energy Agency|Global Energy and Climate Model Documentation Material efficiency:Granular modelling of strategies along supply chains to make more efficient use of materials like steel,cement,aluminium,plastics and fertilisers,and their resulting impact on materials demand.Investments:Detailed modelling of overall energy sector and clean energy investments by sub-sector and technology areas,and comprehensive analysis on effective financing strategies.This includes investment requirements in fuel supply chains to satisfy projected energy demand and for demand-side technologies and measures(e.g.,energy efficiency,electrification).Government spending is also tracked.Decomposition:Detailed mathematical framework to analyse systematically the specific contribution of different strategies to emissions or energy savings between scenarios and over time.Connections with the international energy modelling community The development of the GEC Model benefits from expert review within the IEA and beyond and the IEA works closely with colleagues in the global modelling community.For example,the IEA participates in and regularly hosts the International Energy Workshop,and the analysis for the Net Zero Emissions by 2050 Scenario was informed by discussions with modelling teams from across the world,including from China,the United States,Japan,the United Kingdom,the European Union and the IPCC.The IEA also has a long-standing history of working with researchers and modellers around the world as part of its Technology Collaboration Programmes(TCP)network.The TCPs support the work of independent,international groups of experts that enable governments and industries from around the world to lead programmes and projects on a wide range of energy technologies and related issues.The Energy Technology Systems Analysis(ETSAP)TCP,established in 1977,is among the longest running TCPs.Its mission is to support policy makers in improving the evidence base underpinning energy and environmental policy decisions through energy systems modelling tools and capability through a unique network of nearly 200 energy modelling teams from approximately seventy countries.The ETSAP TCP develops,improves and makes available the TIMES energy systems modelling platform.IEAs GEC Model also interacts closely with other internationally recognised models:The IEA uses the Model for the Assessment of Greenhouse Gas Induced Climate Change(MAGICC),developed and maintained by ClimateResource and often used by IPCC for key publications,to inform its analysis on the impact of different greenhouse gases budgets on the average global temperature rise.IEA modelling results are coupled with the Greenhouse Gas Air Pollution Interactions and Synergies(GAINS)model developed and maintained by International Institute for Applied Systems Analysis(IIASA).This allows for detailed analysis on the impact on air pollution of different IEA scenarios.IEA results are coupled with the Global Biosphere Management Model(GLOBIOM)developed and maintained by IIASA to complement IEAs analysis on bioenergy supplies and effective use strategies.The Aviation Integrated Model(AIM)developed by University College London(UCL)forms the basis for our modelling of the aviation sector.IEA modelling results have been linked to the Global Integrated Monetary and Fiscal(GIMF)model of the International Monetary Fund(IMF)to assess the impacts of changes in investment and spending on global GDP.The Open Source Spatial Electrification Tool(OnSSET),a GIS-based optimisation tool developed out of a collaboration among several organisation,is used to inform the IEAs energy access modelling.Section 2|Cross-cutting inputs and assumptions 17 Section 2 2 Cross-cutting inputs and assumptions The Global Energy and Climate Model(GEC Model)uses macro drivers,techno-economic inputs and policies as input data to design and calculate the scenarios.Economic activity and population are the two fundamental drivers of demand for energy services in GEC Model scenarios.Unless otherwise specified,these are kept constant across all scenarios as a means of providing a starting point for the analysis and facilitating the interpretation of the results.Energy prices are another important input.The projections consider the average retail prices of each fuel used in final uses,power generation and other transformation sectors.These end-use prices are derived from projected international prices of fossil fuels and subsidy/tax levels and vary by country.2.1 Population assumptions Table 2.1 Population assumptions by region Compound average annual growth rate Population(million)Urbanisation(Share of population)2000-21 2021-30 2021-50 2021 2030 2050 2021 2030 2050 North America 0.9%0.6%0.5P2 532 580 82%United States 0.8%0.5%0.435 352 381 83ntral and South America 1.1%0.7%0.5R3 559 601 81%Brazil 1.0%0.5%0.2!4 224 229 87%Europe 0.3%0.0%-0.1p0 701 690 76x%European Union 0.2%-0.1%-0.2E1 448 429 75wrica 2.5%2.3%2.1%1 372 1 686 2 487 44HY%Middle East 2.1%1.5%1.1%2 289 348 73v%Eurasia 0.4%0.3%0.2#7 244 253 65gs%Russia-0.1%-0.2%-0.24 142 134 75w%Asia Pacific 1.0%0.6%0.4%4 250 4 496 4 734 50Ue%China 0.5%0.2%-0.1%1 423 1 443 1 383 63q%India 1.3%0.8%0.6%1 393 1 504 1 639 35S%Japan-0.1%-0.5%-0.65 120 105 92%Southeast Asia 1.2%0.8%0.6g4 726 792 51Vf%World 1.2%0.9%0.7%7 835 8 507 9 692 57h%Source:UN DESA(2018,2019);World Bank(2022a);IEA databases and analysis.Rates of population growth for each GEC Model region are based on the medium-fertility variant projections contained in the United Nations Population Division report(UN DESA,2019)1.In the 2022 GEC modelling cycle,population rises from 7.8 billion in 2021 to more than 9.6 billion in 2050.Population growth slows over the projection period,in line with past trends:from 1.2%per year in 2000-2021 to 0.9%in 2021-2030,due in large part to falling global fertility rates as average incomes rise.1 The World Population Prospects 2022 from UN DESA was published at a time when the modelling was already well advanced for this cycle.18 International Energy Agency|Global Energy and Climate Model Documentation More than half of the increase in the global population to 2050 is in Africa,underlining the importance of this continent to the achievement of the worlds sustainable development goals.India accounts for almost 15%of the growth and becomes the worlds most populous country in the near term as Chinas population growth stalls.Estimates of the rural/urban split for each GEC Model region have been taken from UN DESA(2018).This database provides the percentage of population residing in urban areas by country with annual granularity over the projection horizon.By combining this data with the UN population projections an estimate of the rural/urban split may be calculated.In 2021,about 57%of the world population is estimated to be living in urban areas.This is expected to rise to 68%by 2050.2.2 Macroeconomic assumptions Table 2.2 Real GDP average growth assumptions by region and scenario Compound average annual growth rate 2010-2021 2021-2030 2030-2050 2021-2050 North America 1.9%2.0%2.0%2.0%United States 2.0%2.0%2.0%2.0ntral and South America 0.9%2.4%2.4%2.4%Brazil 0.7%1.8%2.5%2.3%Europe 1.6%2.0%1.4%1.6%European Union 1.2%1.9%1.2%1.4rica 2.7%4.1%4.2%4.1%South Africa 1.1%1.6%2.8%2.4%Middle East 2.0%3.2%3.2%3.2%Eurasia 2.1%0.1%1.4%1.0%Russia 1.7%-1.1%0.7%0.1%Asia Pacific 4.9%4.7%3.1%3.6%China 6.8%4.7%2.8%3.4%India 5.5%7.2%4.4%5.2%Japan 0.5%0.9%0.6%0.7%Southeast Asia 4.1%5.0%3.3%3.8%World 2.9%3.3%2.6%2.8%Note:Calculated based on GDP expressed in year-2021 US dollars in purchasing power parity terms.Source:IEA analysis based on Oxford Economics(2022)and IMF(2022).Economic growth assumptions for the short to medium term are are broadly consistent with the latest assessments from the IMF and Oxford Economics.Over the long term,growth in each GEC Model region is assumed to converge to an annual long-term rate.This is dependent on demographic and productivity trends,macroeconomic conditions and the pace of technological change.In GEC Model 2022 scenarios,the growth trajectory remains positive,but much less so than a year ago when global aggregate demand was experiencing near record growth in response to the removal of pandemic lockdowns and restrictions being eased in many countries.The global economy is assumed to grow by 2.8%per year on average over the period to 2050,with large variations by country,by region and over time(Table 2.2).This growth is primarily driven by emerging market and developing economies.Over the near term,the growth trajectory includes the impact of Russias invasion of Ukraine and rising inflation.There are,however,downside Section 2|Cross-cutting inputs and assumptions 19 risks for the outlook to 2030 resulting from higher interest rates,a mood of insecurity holding back investment decisions and spending on household durables,and uncertainty as to whether macroeconomic authorities are able to contain inflation and avoid a price-wage spiral.The assumed rates of economic growth are held constant across the scenarios,which allows for a comparison of the effects of different energy and climate choices against a common backdrop.The way that economic growth plays through into energy demand depends heavily on the structure of any given economy,the exposure and resilience to shocks,the balance between different types of industry,services and agriculture,and on policies in areas such as pricing and energy efficiency.2.3 Prices International fossil fuel prices Table 2.3 Fossil fuel prices by scenario Net Zero Emissions by 2050 Announced Pledges Stated Policies Real terms(USD 2021)2010 2021 2030 2050 2030 2050 2030 2050 IEA crude oil(USD/barrel)96 69 35 24 64 60 82 95 Natural gas(USD/MBtu)United States 5.3 3.9 1.9 1.8 3.7 2.6 4.0 4.7 European Union 9.0 9.5 4.6 3.8 7.9 6.3 8.5 9.2 China 8.0 10.1 6.1 5.1 8.8 7.4 9.8 10.2 Japan 13.3 10.2 6.0 5.1 9.1 7.4 10.9 10.6 Steam coal(USD/tonne)United States 63 44 22 17 42 24 46 44 European Union 113 120 52 42 62 53 60 64 Japan 132 153 59 46 74 59 91 72 Coastal China 142 164 58 48 73 62 89 74 Notes:MBtu=million British thermal units.The IEA crude oil price is a weighted average import price among IEA member countries.Natural gas prices are weighted averages expressed on a gross calorific-value basis.The US natural gas price reflects the wholesale price prevailing on the domestic market.The European Union and China natural gas prices reflect a balance of pipeline and LNG imports,while the Japan gas price solely reflects LNG imports.The LNG prices used are those at the customs border,prior to regasification.Steam coal prices are weighted averages adjusted to 6 000 kilocalories per kilogramme.The US steam coal price reflects mine mouth prices plus transport and handling costs.Coastal China steam coal price reflects a balance of imports and domestic sales,while the European Union and Japanese steam coal prices are solely for imports.Source:IEA GEC Model 2022.International prices for coal,natural gas and oil in the GEC Model reflect the price levels that are needed to stimulate sufficient investment in supply to meet projected demand.They are one of the fundamental drivers for determining fossil fuel demand and supply projections in all sectors and are derived through iterative modelling.The supply modules calculate the production of coal,natural gas and oil that is stimulated under a given price trajectory,taking into account the costs of various supply options and the constraints on resources and production rates.If prices are too low to encourage sufficient production to cover global demand,the price level is increased and energy demand is recalculated.The new demand resulting from this iterative process is again fed back into the supply modules until a balance between demand and supply is reached for each projected year.20 International Energy Agency|Global Energy and Climate Model Documentation The price trajectories do not attempt to represent the fluctuations and price cycles that characterise commodity markets in practice.The potential for volatility is ever present,especially in systems that are undergoing a necessary and profound transformation.Fossil fuel price paths vary across the scenarios(Table 2.3).For example,in the Stated Policies Scenario,although policies are adopted to reduce the use of fossil fuels,demand is still high.That leads to higher prices than in the Announced Pledges Scenario and the Net Zero Emissions by 2050 Scenario,where the lower energy demand means that limitations on the production of various types of resources are less significant and there is less need to produce fossil fuels from resources higher up the supply cost curve.CO2 prices Table 2.4 CO2 prices for electricity,industry and energy production in selected regions by scenario USD(2021)per tonne of CO2 2030 2040 2050 Stated Policies Scenario Canada 54 62 77 Chile,Colombia 13 21 29 China 28 43 53 European Union 90 98 113 Korea 42 67 89 Announced Pledges Scenario Advanced economies with net zero emissions pledges1 135 175 200 Emerging market and developing economies with net zero emissions pledges 2 40 110 160 Other emerging market and developing economies-17 47 Net Zero Emissions by 2050 Scenario Advanced economies with net zero emissions pledges 140 205 250 Emerging market and developing economies with net zero emissions pledges 90 160 200 Other emerging market and developing economies 25 85 180 1 Includes all OECD countries except Mexico.2 Includes China,India,Indonesia,Brazil and South Africa.Note:The values are rounded.Source:IEA GEC Model 2022.CO2 price assumptions are one of the inputs into GEC Model as the pricing of CO2 emissions affects demand for energy by altering the relative costs of using different fuels.There were 68 direct carbon pricing instruments existing as of May 2022:32 emissions trading systems and 38 carbon taxes on fuels according to their related emissions when combusted,covering more than 40 countries.Many others have schemes under development or are considering to do so.The Stated Policies Scenario takes into consideration all existing or announced carbon pricing schemes,at national and sub-national level,covering electricity generation,industry,energy production sectors and end-use sectors,e.g.,aviation,road transport and buildings,where applicable.In the Announced Pledges Scenario,higher CO2 prices are introduced across all regions with net zero emissions pledges.In addition,several developing economies are assumed to put in place schemes to limit CO2 emissions.All regional markets have access to offsets,which is expected to lead to a convergence of prices.No explicit pricing is assumed in sub-Saharan Africa(excluding South Africa),the Caspian region and Other Asia regions.Instead,these regions rely on direct policy interventions to drive decarbonisation in the APS.In the Net Zero Emissions by 2050 Scenario,CO2 prices cover all regions and rise rapidly across all advanced economies as well as in emerging economies with net zero Section 2|Cross-cutting inputs and assumptions 21 emissions pledges,including China,India,Indonesia,Brazil and South Africa.CO2 prices are lower,but nevertheless,rising in other emerging economies such as North Africa,Middle East,Russia and Southeast Asia.CO2 prices are lower in all other emerging market and developing economies,as it is assumed they pursue more direct policies to adapt and transform their energy systems(Table 2.4).End-user prices Fuel end-use prices For each sector and GEC Model region,a representative price(usually a weighted average)is derived taking into account the product mix in final consumption and differences between countries.International price assumptions are then applied to derive average pre-tax prices for coal,oil,and gas over the projection period.Excise taxes,value added tax rates,subsidies and CO2 prices(where applicable)are taken into account in calculating average post-tax prices for all fuels.In all cases,the excise taxes and value added tax rates on fuels are assumed to remain unchanged over the projection period.We assume that energy-related consumption subsidies are gradually reduced over the projection period,though at varying rates across the GEC Model regions and the scenarios.In the Announced Pledges Scenario and the Net Zero Emissions by 2050 Scenario,the international oil price drops in comparison to the Stated Policies Scenario due to lower demand for oil products.In order to counteract a rebound effect in the transport sector from lower gasoline and diesel prices,an increase of fuel duty on top of CO2 price is applied whenever is necessary for ensuring that end-user prices are kept at least at the same level as in the Stated Policies Scenario.All prices are expressed in US dollars and assume no change in exchange rates.Electricity end-use prices The model calculates electricity end-use prices as a sum of the wholesale electricity price,system operation cost,transmission&distribution costs,supply costs,and taxes and subsidies(Figure 2.1).Figure 2.1 Components of retail electricity end-use prices IEA.CC BY 4.0.There is no single definition of wholesale electricity prices,but in the Global Energy and Climate Model the wholesale price refers to the average price paid to generators for their output.For each region,wholesale electricity price are derived under the assumption that all plants operating in a given year recover the full costs fixed costs as well as variable costs of electricity generation and storage.The key region-specific factors affecting wholesale prices are therefore:22 International Energy Agency|Global Energy and Climate Model Documentation The upfront capital investment and financing costs of electricity generation and storage plants;The operation and maintenance costs of electricity generation and storage plants;and The variable of coal,natural gas,oil and other fuels inputs and,if applicable,CO2 cost of generation plants output.System operation costs are taken from external studies and are increased in the presence of variable renewables in line with the results of these studies.Transmission and distribution tariffs are estimated based on a regulated rate of return on assets,asset depreciation and operating costs.Supply costs are estimated from historic data,and taxes and subsidies are also taken from the most recent historic data,with subsidy phase-out assumptions incorporated over the Outlook period in line with the relevant assumptions for each scenario.Subsidies to fossil fuels The IEA measures fossil fuel consumption subsidies2 using a price-gap approach.This compares final end-user prices with reference prices,which correspond to the full cost of supply,or,where appropriate,the international market price,adjusted for the costs of transportation and distribution.The estimates cover subsidies to fossil fuels consumed by end-users and subsidies to fossil-fuel inputs to electricity generation.The price-gap approach is designed to capture the net effect of all subsidies that reduce final prices below those that would prevail in a competitive market.However,estimates produced using the price-gap approach do not capture all types of interventions known to exist.They,therefore,tend to be understated as a basis for assessing the impact of subsidies on economic efficiency and trade.Despite these limitations,the price-gap approach is a valuable tool for estimating subsidies and for undertaking comparative analysis of subsidy levels across countries to support policy development(Koplow,2009).2.4 Policies In order to underpin scenario analysis of the GEC Model,an extensive effort is made to update and expand the list of energy and climate-related policies and measures that feed into our modelling.Assumptions about government policies are critical to this analysis and are the main reason for the differences in outcomes across the scenarios.Two notable IEA policy tracking efforts input into the scenarios:Policies and Measures database:The IEAs Policies and Measures Database provides access to information on past,existing or planned government policies and measures to reduce greenhouse gas emissions,improve energy efficiency and support the development and deployment of renewables and other clean energy technologies.This unique policy database brings together data from theIEAs Sustainable Recovery Tracker,IEA/IRENA Renewable Energy Policies and Measures Database,theIEA Energy Efficiency Database,theAddressing Climate Changedatabase,and the Building Energy Efficiency Policies(BEEP)database,along with information on CCUS and methane abatement policies.This policy information has been collected since 1999 from governments,partner organisations and IEA analysis.Governments have an opportunity to review the policy information periodically.SDG7 database:The International Energy Agency is at the forefront of global efforts to assess and analyse persistent energy access deficit,providing annual country-by-country data on access to electricity and clean cooking(SDG 7.1)and the main data source for tracking official progress towards SDG targets on renewables(SDG 7.2)and energy efficiency(SDG 7.3).The IEA is one of the appointed co-custodians for tracking global progress on SDG 7 alongside IRENA,UNSD,the World Bank,and WHO.2 https:/www.iea.org/topics/energy-subsidies Section 2|Cross-cutting inputs and assumptions 23 In total,new policies and measures globally have been considered during the model preparation,including recent announcements such as the Inflation Reduction Act(United States),Fit for 55(European Union),Climate Change Bill(Australia),and GX Green Transformation(Japan)as well as governmental spending as a reaction to the current energy crisis.The national net zero emissions pledges announced by India and Indonesia are also important changes compared to last year.A summary of some of the key policy targets and measures for different sectors by selected countries and regions can be found in the Annex B of WEO-2022.The considered policies are additive across scenarios:measures listed under the Announced Pledges Scenario(APS)supplement those in the Stated Policies Scenario(STEPS).In addition,separate policy assumptions are given for the Net Zero Emissions by 2050 Scenario(NZE)which provide indicative policymaking and decarbonising milestones that would steer global energy systems to these outcomes.The published tables begin with broad cross-cutting policy frameworks,followed by more detailed policies by sector:power,industry buildings,and transport.The tables list only the“new policies”enacted,implemented or revised since the last publication cycle 2021.Some regional policies have been included if they play a significant role in shaping energy at a global scale(e.g.regional carbon markets,standards in very large provinces or states).The tables do not include all policies and measures,rather they highlight the policies most shaping global energy demand today,while being derived from an exhaustive examination of announcements and plans in countries around the world.2.5 Techno-economic inputs Incorporation of a diverse range of technologies is a key feature of the GEC Model.Extensive research is undertaken to update the range of technologies in the model,as well as their techno-economic assumptions.The GEC Model includes the breadth of technologies that are available on the market today.Additionally,the model integrates innovative technologies and individual technology designs that are not yet available on the market at scale by characterising their maturity and expected time of market introduction.For each sector and technology area,new project announcements and important technological developments are tracked in databases that are regularly published.The modelled scenarios are informed by such detailed technology tracking process.For instance,the project planning financing status is an important consideration for whether projects are reflected in STEPS or rather in APS.For technology development progress and the time to bring new technologies to markets,the scenarios assume different pace of progress as the support and degree of international cooperation on clean energy innovation increases with the ambition in decarbonisation.The following databases are particularly relevant for the definition of the different scenarios:Clean innovative technologies tracking:Clean Technology Guide:interactive database that tracks the technology readiness level(TRL)of over 500 individual technology designs and components across the whole energy system that contribute to achieving the goal of net-zero emissions.The Guide is updated every year.Clean Energy Demonstration Projects Database:newly launched in 2022,that provides more detailed tracking of the location,status,capacity,timing and funding,of over 400 demonstration projects across the energy sector.Tracking Clean Energy Progress:annual tracking of developments for 55 components of the energy system that are critical for clean energy transitions and their progress towards short-term 2030 milestone along the trajectory of the Net Zero by 2050 Scenario.24 International Energy Agency|Global Energy and Climate Model Documentation Hydrogen Projects Database:covers all projects commissioned worldwide since 2000 to produce hydrogen for energy or climate-change-mitigation purposes.Global EV Outlook:annual publication that identifies and discusses recent policy and market developments in electric mobility across the globe.It is developed with the support of the members of the Clean Energy Ministerial Electric Vehicles Initiative(EVI).Technology costs are an important input to the model.All costs represent fully installed/delivered technologies,not solely the equipment cost,unless otherwise noted as for fuel cells.Installed/delivered costs include engineering,procurement and construction costs to install the equipment.Some illustrative examples include the following:Industry costs reflect average iron and steel production costs for a given technology and differentiate between conventional and innovative production routes.Electric Vehicle costs reflect production costs,not retail prices,to better reflect the cost declines in total cost of manufacturing,which move independently of final market prices for electric vehicles to customers.For the global average battery pack size,historical values in 2021 have been used.In hybrid cars,the future cost increase is driven by regional fuel economy and emissions standards.Electrolyser costs reflect a projected globally weighted average of installed electrolyser technologies(excluding China,where lower costs are assumed),including inverters.Fuel cell costs are based on stack manufacturing costs only,not installed/delivered costs.The costs provided are for automotive fuel cell stacks for light-duty vehicles.Utility-scale stationary battery costs reflect the average installed costs of all battery systems rated to provide maximum power output for a four-hour period.Table 2.5 Capital costs for selected technologies by scenario Stated Policies Announced Pledges Net Zero Emissions by 2050 2021 2030 2050 2030 2050 2030 2050 Primary steel production(USD/tpa)Conventional 640 650 660 650 670 650 680 Innovative n.a.1 400 1 050 1 330 980 1 020 910 Vehicles(USD/vehicle)Hybrid cars 16 122 14 686 14 861 14 528 14 718 14 460 14 638 Battery electric cars 21 322 15 772 14 185 15 265 13 618 14 783 13 251 Batteries and hydrogen Hydrogen electrolysers(USD/kW)1 505 575 445 390 265 315 230 Fuel cells(USD/kW)100 60 40 50 35 45 30 Utility-scale stationary batteries(USD/kWh)285 185 135 185 135 180 135 Notes:kW=kilowatt;tpa=tonne per annum;kWh=kilowatt-hour;n.a.=not applicable.All values are in USD(2021).Sources:IEA analysis;James et.al.(2018);Thompson,et al.(2018);Financial Times(2020);BNEF(2021);Cole et al.(2020);Tsiropoulos et al.(2018);Section 3|End-use sectors 25 Section 3 3 End-use sectors All 26 regions are modelled in considerable sectoral and end-use detail.Specifically:Industry is composed of five energy-intensive and eight non-energy-intensive sub-sectors;Buildings is separated into residential and services buildings,with eleven end-uses modelled separately;Transport is separated into nine modes with considerable detail for road transport;Agriculture modelling reflects the range of fuels and energy consuming applications in the sector.Total final energy demand is the sum of energy consumption in each final demand sector.In each sub-sector or end-use,at least seven types of energy are shown:coal,oil,gas,electricity,heat,hydrogen and renewables.The main oil products liquefied petroleum gas(LPG),naphtha,gasoline,kerosene,diesel,heavy fuel oil(HFO)and ethane are modelled separately for each final sectors.Demand-side drivers,such as steel production in industry or household size in dwellings,are estimated econometrically based on historical data and on socioeconomic drivers(GDP and population).All end-use sector modules base their projections on the existing stock of energy infrastructure.This includes the number of vehicles in transport,production capacity in industry,and floor space area in buildings.To take into account expected changes in structure,policy or technology,a wide range of technologies are integrated in the model that can satisfy each specific energy service.End-user fuel prices and technology costs play an important role in determining the distribution of technologies and fuels,although real-world non-cost influences also play a role.Respecting the efficiency level of all end-use technologies gives the final energy demand for each sector and sub-sector(Figure 3.1).Figure 3.1 General structure of demand modules IEA.CC BY 4.0.3.1 Industry sector The origins of the GEC industry sector model are the industry sector modules of the former WEM(simulation)and the ETP(TIMES optimisation)models,both now superseded by the GEC framework.The GEC industry sector model combines the strengths of each of these former models into a single simulation framework,with its constraints and input parameters informed by,among other things,periodic model runs of the former ETP TIMES optimisation framework.The result of these developments in 2022 is a technology-rich,optimisation-informed,simulation model,fully integrated into the broader GEC Model framework.The GEC industry model is implemented in Vensim,using the 26 GEC model regions(activity modelling is conducted at the country level),in annual time-steps.Industry model coverage and approach For the purposes of the GEC industry model,the industrial sector includes International Standard Industrial Classification(ISIC)Divisions 7,8,10-18,20-32 and 41-43,and Group 099,covering mining and quarrying DriversEconometric analysisEnergy service demand(demand for useful energy)Least-cost approachTechnology/fuel allocationEfficiency levelsFinal energy demand26 International Energy Agency|Global Energy and Climate Model Documentation(excluding mining and extraction of fuels),construction,and manufacturing.This coverage follows the structure of the IEA Energy Balances,covering all of the industry components of total final consumption.Chemical feedstock(a component of non-energy use)and blast furnace and coke oven energy use(both transformation and own use)are also included within the boundaries of industry.Aside from petrochemical feedstock,other non-energy use is not included in the GEC Models industry sector boundary,but rather is modelled as a separate category in the same framework.Figure 3.2 Major categories of technologies by end-use sub-sector in industry IEA.CC BY 4.0.The industry sector is modelled using a hybrid approach(Figure 3.2).Technology-rich simulation models,informed by periodic model runs of the former ETP TIMES optimisation framework,are used for five energy-intensive sub-sectors components thereof(iron and steel;primary chemicals within chemicals and petrochemicals;cement within non-metallic minerals;aluminium within non-ferrous metals;paper,pulp and CCUS options(cross-cutting)Technology-rich energy-intensive sub-sector modelsIron and steelChemicals and petrochemicalsNon-metallic mineralsNon-ferrous metalsPaper,pulp and printingCross-sectoral conversion device simulation modelMaterial and fuel preparation Coke ovens(coke dry quenching option)Sintering PelletisingIron production Blast furnaces(top gas recovery,top pressure recovery,hydrogen amplification,charcoal and hydrogen/biomass blending options)Smelt reduction Direct reduced iron(electrolysis option)Steel production Basic oxygen furnace Open hearth furnace Electric arc furnace Induction furnaceRaw material and fuel grindingBall millRoller press&ball millVertical millClinker production Dry kilns Wet kilns Vertical shaft kilns Electric kilnsFinished cement grinding Ball mill Roller press and ball mill Vertical millAlumina refining Bayer process Bayer-Sinter process Sinter processAluminium production Hall-Hroult smelting(inert anode option)Soderberg smelting Secondary furnaces(induction furnace and reverbatory furnace options)Finishing Cold rolling Extrusion Hot rolling Shape castingPulp production Conventional boilers(e.g.coal,oil,gas)Bark boiler Black liquor recovery Pulping Pulp bleaching Pulp dryingPaper production Conventional boilers(e.g.coal,oil,gas)Bark boiler Paper-making processesHigh value chemical production Steam cracking Electric seam cracking Bioethanol dehydration Naphtha catalytic cracking Propane dehydrogenation Methanol to olefins Methanol to aromaticsMethanol production Fossil fuel-based Biomass-based Electrolysis-basedAmmonia production Fossil fuel-based Biomass-based Electrolysis-based Pyrolysis-basedSectorsOther industry Transport equipment Machinery Mining and quarrying Food and tobacco Textile and leather Wood and wood products Construction Non-specified industryEquipment Cooling and refrigeration Boilers Heat pumps Solar/geothermal heating Resistance heating Electro-magnetic heating Motors Motor driven systemsGEC industry hybrid modelling approachMerchant hydrogen and synthetic hydrocarbon options(cross-cutting)Other non-metallic mineral production Fuel elasticity simulationOther non-ferrous metal production Fuel elasticity simulationOther chemical production Fuel elasticity simulationSemi-finishing and finishing processes Fuel elasticity simulationPrinting and finishing processes Fuel elasticity simulation Section 3|End-use sectors 27 printing).The remaining non-energy-intensive industry sub-sectors(construction,mining and quarrying,transport equipment,machinery,food and tobacco,wood and wood products,textile and leather and industry not-elsewhere specified)are modelled using a cross-cutting conversion device simulation approach.For the residual components of the five energy-intensive sub-sectors(chemicals besides primary chemicals,non-metallic minerals besides cement,non-ferrous metals besides aluminium,downstream finishing processes in the iron and steel and paper,pulp and print sectors),the same cross-cutting approach is applied as to the non-energy-intensive sub-sectors.The five energy-intensive sub-sector models characterise the energy performance of process technologies at the process unit level(e.g.coal blast furnace,naphtha steam cracker).The cross-cutting simulation model for the remaining industry sub-sectors characterises the stock of the main conversion devices(e.g.motors,heating equipment)used to provide various energy services required during the production of thousands of materials and products.See sections 3.1.3 and 3.1.4 for more information on the approaches taken for each of these main components of the GEC industry model.Energy-intensive sub-sectors For each of the five energy-intensity industry sub-sectors,the modelling framework consists of a series of interacting sub-modules and a core technology model(see Figure 3.3).The sub-modules consist of an activity model,a stock model and a capacity model.The activity drivers for each sub-sector of the GEC industry model are tonnages of material produced in a given scenario at a given point in time.Activity modelling is handled in a similar manner for all energy-intensive industry sub-sectors.Demand for materials is projected through interaction between an activity model and a stock model,together with modelling of material efficiency strategies.The activity model uses country-level historical data on material consumption to calculate demand per capita,then projects forward total demand using population projections and industry value-added projections.The industry value-added projections inform the rate of change in demand per capita.The results of the activity model on demand projections feed into the stock model,which uses bottom-up material demand inputs from the buildings,transport and supply modules and complementary assumptions about other end-product shares and lifetimes to calculate the implied build-up of material stocks.Stock saturation in the stock model in turn informs per capita material demand saturation in the activity model through a series of iterations.Material efficiency strategies across value chains also are modelled.This modelling work builds mainly on the literature and previous IEA publications relating to material efficiency(IEA 2019a).Strategies considered include:Design stage:light-weighting(produce the same product with a lower average mass per product),design for future material savings(modular design to enable reduce,design for recyclability)Construction and manufacturing:increased yields(reduce the losses in semi-manufacturing and manufacturing),reduced materials waste(more careful construction practices and material handling)Use:longer life times(refurbishing buildings for other uses,re-using components for particular products),more intensive use of products(for example car sharing or using a building for a higher share of the day),End-of-life:direct materials re-use(use of post-consumer materials without re-melting in the case of metals for the same or other applications),recycling(increased collection and improved sorting).Those strategies occurring in the other end-use sectors(e.g.building lifetime extension,vehicle light-weighting)are fed into the stock model via the bottom-up demand estimates,while material efficiency strategies within the industry boundary(e.g.manufacturing yield improvements,direct reuse and recycling)are modelled within the stock model.These strategies lead to reduced material demand,which is fed into the activity model via a material 28 International Energy Agency|Global Energy and Climate Model Documentation efficiency factor.The resulting activity projections from the activity model and scrap availability(including semi-manufacturing,manufacturing and post-consumer scrap)from the stock model feed into the main technology model.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.Figure 3.3 Industry sector model internal module structure and key data flows IEA.CC BY 4.0.Notes:Internal industry model flows:1)Historic production,population projection,industry value-added projection,2)End-use demand,product lifetimes,process yields,recycling and re-use rates,3)Energy and raw material intensities,energy prices,CAPEX and OPEX,lifetimes,technology deployment constraints,CO2 emissions reduction trajectory,4)Historic and planned capacity,lifetimes,refurbishments,5)Consumption projections,6)Material stocks saturation,material efficiency factors,7)Production projections,8)Scrap availability,9)Residual capacity.Model results:A)Material production,B)Material stocks saturation,C)Energy consumption,CO2 emissions,technology shares,investments,D)Capacity installed,added and retired.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).Changes in the technology and fuel mix,as well as efficiency improvements,are in part driven by a combination of exogenous assumptions on the penetration and energy performance of best available technologies,Input dataModel resultsActivity moduleCapacity moduleTechnology modelStock module5234D61789BCA Section 3|End-use sectors 29 constraints on the availability of raw materials(such as scrap availability according to the stock model outputs),technoeconomic characteristics of the available technologies and process routes,and assumed progress on demonstrating innovative technologies at commercial scale.The results are sensitive to assumptions about how quickly physical capital is turned over(including retirements of existing capacity according to the capacity model outputs)and about the relative costs of the various technology options and fuels.A given scenario can also be subject to a CO2 emission trajectory that the model must adhere to.Model outputs include energy consumption,fuel combustion and process CO2 emissions both emitted and captured,technology shares,raw materials and intermediate industrial materials flows and investment requirements.Some industrial sectors have the particularity to produce and use“on-site”hydrogen within the industrial facility as for specific ammonia,methanol or primary steel production processes.This hydrogen is not reported in the standard energy balance but it is reported as fossil fuel or electricity depending on whether it is produced via steam reforming or water electrolysis.Accounting of this hydrogen,necessary to build the global hydrogen accounting,is performed in a dedicated hydrogen module.Outputs of this module are hydrogen quantities produced onsite(low-emissions or not),electrolyser capacity and related-investments requirements,energy input and related CO2 emissions emitted as well as captured and stored.Non-energy intensive sub-sectors Activity modelling for the non-energy-intensive sub-sectors follows a different approach to the energy-intensive sectors.These sub-sectors produce a large range of final products without a clear common intermediate in many cases.This contrasts to the energy-intensive sub-sectors,which have a large range of final products but a clear common intermediate product for which production in physical terms can be clearly projected(e.g.crude steel in the iron and steel sector).As such,macro-economic indicators(e.g.industrial value-added)are used as the activity drivers for non-energy intensive sub-sectors,rather than physical production.Using historic relationships between macro-economic indicators and industrial energy demand,together with demand signals from the other end-use models(e.g.vehicle sales from the transport model for the transport equipment sector)and material efficiency considerations(based on the results of the energy-intensive sub-sector analyses)where relevant,projections of energy service demand are made across the following categories:Heat delivered at five temperature bands(0-60 C,60-100 C,100-200 C,200-400 C and above 400 C);Mechanical work to be delivered by electric motors;Other energy services in aggregate(cooling,lighting etc.).These energy service demands form the final activity drivers for the non-energy-intensive industry sub-sector models.A range of technologies are characterised for meeting each category of activity demand,including a range of different heating technologies using different fuels(fossil fuels,solar thermal,geothermal,electro-magnetic heating,electric resistance heating,heat pumps,hydrogen,bioenergy)and a range of motor options(differing efficiencies of the motor driven system,efficiencies of the motor itself,variable speed drive option).The shares of energy service demand met by each of these technologies are informed by their levelised cost(including the impact of any CO2 prices),constraints on fuel availability(e.g.,bioenergy resources),technology readiness(e.g.,electro-magnetic heating for large non-conductive media not commercially available today),limits on potential(e.g.,industrial heat pump penetration in medium and high temperature heat bands)and any CO2 emissions constraints of the scenario.The shares of fuels(and associated emissions)used to meet the remaining energy service demand of multifuel processes or processes that are not covered by the bottom-up technology modelling across the non-energy-intensive sectors(and residual portions of the energy-intensive sectors not covered in the energy-intensive sub-30 International Energy Agency|Global Energy and Climate Model Documentation sector models)is modelled by fuel using a Weibull function.This function is informed by previous years fuel share,the fuel price change(including the impact of any CO2 prices)and the price change in the previous year.Any CO2 constraints specified by the scenario are also respected.Industry sector investments The boundaries for investments reporting include capital expenditure(CAPEX),and engineering,procurement and construction costs.For carbon capture,utilisation and storage(CCUS)technologies,CO2 transport and storage costs are also included.For material efficiency,investments are based on data on CO2 abatement costs for material efficiency strategies,converted into costs for material savings.Fixed operating and maintenance expenditures(OPEX)are not included under reported investments,though they are considered in the context of the economic characterisation of technologies in the model.Energy system investments do not include core industrial equipment CAPEX,but do include the additional investment required to incrementally(e.g.,energy efficiency improvements through adoption of BAT)or substantially(e.g.electrolyser and carbon capture equipment)adjust the energy or emissions performance of a technology.Other investments in core industrial equipment are also accounted for,but not reported within the boundary of energy system investments.Input data Input data to the model comes from a wide variety of sources.Sources for historical production and consumption used in the activity modelling include the World Steel Association,the International Fertilizer Association,the United States Geological Survey,the International Aluminium Institute and a number of proprietary sources.Data on the energy intensities of processes come from a variety of industry sources(e.g.the Getting the Numbers Right publication overseen by the Global Concrete and Cement Association),academic literature and industry contacts.CAPEX and OPEX similarly come from a combination of industry and academic sources.Population,economic indicators(e.g.value added by industry),fuel costs i.e.end-use energy prices,and CO2 prices are provided by the main GEC Model(see Section 2).Other key inputs from the GEC modelling framework and associated work streams include the hydrogen and CCUS projects databases and the technology readiness assessments that form part of the Clean Technology Guide and Demonstration Projects Database.Techno-economic parameters are periodically reviewed,both as a component of aforementioned work streams,and during the course of preparing deep-dive analyses on specific sector or technology areas(e.g.the IEAs Iron and Steel Technology Roadmap,the Ammonia Technology Roadmap,The Future of Petrochemicals).3.2 Transport sector The GEC transport model combines strengths of both former World Energy Model(WEM)and Mobility Model(MoMo),and consists of dedicated sectoral model for road transport,aviation,maritime and rail.The Historical Database One key foundation for transport modelling work is the road transport database,a database that is updated annually based primarily on publicly available data on road vehicle sales,stocks,activity,and operations.The road database further benefits from data and analytical work for the Electric Vehicles Initiative1 and the Global Fuel Economy Initiative2.Similar historical databases form the basis for modelling rail,international maritime,and commercial passenger aviation.1 https:/www.iea.org/programmes/electric-vehicles-initiative 2 https:/www.iea.org/reports/global-fuel-economy-initiative-2021 Section 3|End-use sectors 31 Each region is characterised on the basis of information that includes,for each road transport mode,vehicle sales,mileage,and energy intensity by vintage,as well as the overall vehicle stock,load factors and fuel efficiency.The database allows linking historical data on several interconnected variables,trying to assure internal consistency across indicators,according to the ASIF framework,wherein Activity,Structure,and Intensity determine estimates of Fuel use):=()()=F total Fuel use A vehicle Activity(expressed in vkm)Fi fuel used by vehicles with a given set of characteristics(i)(e.g.segments by service,mode,vehicle and powertrain)Ai/A=Si sectoral Structure(same disaggregation level)Fi/Ai=Ii Energy Intensity,i.e.average fuel consumption per vkm(same disaggregation level)The parameters monitored include including sales/new registrations of vehicles,second hand imports,survival ages,stock,mileages,vehicle activity(vehicle-kilometres or vkm),loads/occupancy rates,passenger and freight activity(passenger-kilometres or pkm and tonne-kilometres or tkm),fuel economies and energy use(based on the IEA data on energy demand by country).The following parameters are collected and calibrated/validated against the road energy balances on an annual basis:Sales/new vehicle registration data are taken from publicly available data sources(e.g.ACEA,US Bureau of Transportation Statistics,and others).Fuel economy data for passenger light-duty vehicles are based on aggregated data from a proprietary database,plus conversions(based on an external research report)across regional vehicle test cycles to the World Light-Duty Test Cycle(WLTC),plus estimates for the gap between this test cycle and real-world specific fuel consumption(again,based on external research reports).Fuel economy data for buses,trucks,two/three-wheelers are taken from various academic,government and industry reports or technical calculations,over the course of nearly 20 years.Stocks are based on our estimates of how long different vehicle types are kept in the fleet(i.e.scrappage functions),and when reliable external estimates are available(as is the case,for instance,in the United States and Europe),these are calibrated to official data(e.g.ACEA,US Bureau of Transportation Statistics).In countries where academic or industry studies exist on the age distribution of the on-road fleet,scrappage functions are compared/calibrated with these.Occupancy(average people per vehicle)and Load Factors(average cargo weight per vehicle)are based on official statistics(e.g.,Eurostat),academic reports or surveys,or are developed by analogy/regression-based estimates when no data are available.Average Mileage(i.e.,annual kilometres driven)estimates are similarly taken from or compared/calibrated to official data and literature Scrappage and mileage are then adjusted,across all vehicle categories(e.g.,two/three-wheelers,cars,buses,light commercial vehicles,medium-and heavy-trucks)and across all fuel/powertrain types(e.g.gasoline,diesel,conventional hybrid,plug-in hybrid,battery and fuel-cell electric,etc.)to match the country-/regional time series of road gasoline,diesel,electricity,natural gas and LPG consumption as reported in the IEA energy balances.32 International Energy Agency|Global Energy and Climate Model Documentation 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.Figure 3.4 Structure of the transport sector IEA.CC BY 4.0.Note:Other includes pipeline and non-specified transport.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.Road transport Road transport energy demand is broken down among passenger light duty vehicles(PLDVs),light commercial vehicles(LCVs),buses,medium trucks,heavy trucks and two-and three-wheelers.The model allows fuel substitution and alternative powertrains across all sub-sectors of road transport.The gap between test and on-road fuel efficiency,i.e.,the difference between test cycle and real-life conditions,is also estimated and projected.As the largest share of energy demand in transport comes from oil use for road transport,the GEC Model contains technology-detailed sub-models of the total vehicle stock and the passenger car fleet.The stock projection model is based on an S-shaped Gompertz function,proposed in Dargay et al.(2006).This model gives the vehicle ownership based on income(derived from GDP assumptions)and 2 variables:the saturation level(assumed to be the maximum vehicle ownership of a country/region)and the speed at which the saturation level is reached.The equation used is:=Road transportRailNavigationOtherPassenger-kilometresTonne-kilometresActivity variablesPopulationGDPAviationSub-sectorsEnd-use energy pricesHistorical trends Section 3|End-use s

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Paycor：2022年CFO人力资源团队建设指南（英文版）（32页）.pdf

CFOs Guide to Structuring an HR Team WITH LIMITED TIME,BUDGET AND RESOURCES center of excellenceby 2The North StarWherever you are on the path to building an HR team,its necessary to have a destination in mind.A framework for how youll structure and organize your team and what youll focus on.You may not be able to achieve the ideal overnight,or ever,but every team needs a north star to guide them.Based on 30 years of working with HR and business leaders,along with lots of interviews and research,we discovered that high-functioning HR teams invest in resources to support these 3 areas:Talent Management.8Benefi ts.15 HR Operations.24In the best of all possible worlds,if money and resources were no problem,what would your IDEAL HR team look like?2EXECUTIVE SUMMARY:The North Star3Keep Dreaming,Right?Lets Get RealWe cant answer the question“how many people do I need to create the ideal HR team?”that will depend on a variety of factors and decisions unique to you,especially as we face new challenges resulting from the pandemic.But,if youre like most organizations and cant wave a magic wand,let us suggest how to“hack”your way to an ideal state.EXECUTIVE SUMMARY4Building an HR TeamBUILDING AN HR TEAM5Who Leads the Charge?Developing an HR team begins and ends with the Director of HR.This person establishes a true partnership with executives,first by understanding goals and objectives at the highest level,and then by aligning HR to the overall mission.HR leaders must ensure the team is adequately prepared and supported,either through technology or staffor ideally bothto find the right people,develop them and create great places to work.Even if your HR department is a team of one,knowing where to invest time and most importantly resources will be valuable as you look to improve efficiencies.Changing DynamicThe COVID pandemic has changed what we look for in leadership.According to a Paycor survey,51%of respondents look for different qualities in their HR leader than they did before the crisis.As a result,HR leaders are adjusting how they lead,practicing flexibility,promoting collaboration and practicing empathy.HR Director6How to Make It HappenYour organization may not be able to hire an HR leader today or tomorrow,or you may be the person responsible for leading the charge;either way,its critical to align HRs unique capabilities with the companys objectives,goals,strategies and measures.If your company has aggressive plans to grow,HR should be focused on hiring strategies,including how to build and maintain a healthy pipeline of talent.But thats just the beginning.There are new FMLA regulations to think about and there are retention and engagement strategies as well.To make it happen,HR will need expertise in 3 key areas:talent management,benefits and HR operations.7Talent ManagementBenefitsHR Operations Talent Management Talent management is the single most important HR function for any organization,because the foundation for overall success depends on finding the best people and giving them everything they need to succeed and every reason to stay.Benefits The most successful HR teams use their overall benefits experience as a competitive advantage by offering plans that cater to the diverse needs of the entire workforce.Status quo benefits offerings wont cut it.And with mental health concerns on the rise,HR must consider additional resources that support employees wellbeing.HR Operations Most of HRs time,and its biggest challenges,come from managing people.The question is:is your time well spent?If youre drowning in manual work or stuck answering the same employee questions day after day,youand your companyare missing out on the significant upside of investing time and energy into building a great place to work where people show up,make a difference and win together.Critical Areas of Focus 8Talent ManagementIdeal StateBest case scenario,your organization can break down talent management into two focus areas:recruiting hiring and onboarding administration.The recruiting hiring function builds a candidate pipeline to attract better talent and focuses on hiring for open positions with the right candidates.The onboarding administration function provides the tools,resources and training to help new hires hit the ground running and solidify engagement while creating repeatable processes that ensure compliance.Talent ManagementRecruiting HiringOnboarding Administration9Recruiting Hiring:ResponsibilitiesA Well-Oiled MachineYour recruiting team is like a sales team.Recruiting should develop a talent pipeline by building a bench of candidates,regardless of openings,to ensure roles can be filled quickly.And just like a sales representative,recruiters should be measured on key performance indicators to support growth and respond to immediate business needs.Talent ManagementRecruiting HiringOnboarding Administration10INSIGHT:COST-PER-HIREIndustry benchmark is$4,129,yet more than 20%of organizations dont know their cost-per-hire.(SHRM)TIME-TO-FILLThe average is 42 days but varies across industries.(SHRM)CANDIDATE PIPELINECreate an effective pipeline by forecasting the number of candidates needed to hire each year,sourcing candidates,tracking referrals and reviewing conversion rates.SOURCE OF HIREEvaluating hiring sources and allotting budget spend is critical to developing an effective recruiting strategy.APPLICANTS PER HIREThis number will vary depending on employee size,role and brand,but its the first step to determining the ideal candidate pipeline size thats best for your organization.Here are just a few of the critical metrics you need HR to monitor to understand outages and ways to improve.Recruiting Hiring:Responsibilities Talent ManagementRecruiting HiringOnboarding Administration11How to Get There:Recruiting Hiring 12Where Does the Buck Stop?If you cant answer this question,youre headed for trouble.Many smaller organizations share the recruiting function across several people,with managers of other departments left to do much of the recruiting.HR can prevent a haphazard process by owning the recruiting function.With clear ownership,HR can assess the current state of recruiting,apply metrics to test and learn,align with the hiring manager and share results with leadership experienceso dont underestimate the importance of making it a priority from the start.How Technology Can Save Time&Money The right recruiting technology can vastly improve how you find talent AND relieve much of the administrative burden.Find technology that provides the data and reporting you need to identify top candidate sources and discover bottlenecks in the hiring process.Talent ManagementRecruiting HiringOnboarding AdministrationHow to Get There:Recruiting Hiring Recruiting:Optimize your remote recruiting process by focusing on key metrics,like time-to-fill,candidate pipeline and more.Stay in touch with candidates throughout the process with texting and capture manager feedback with interview scorecards.How Paycor Helps 13Ideal State:First Impressions Mean EverythingFilling out W-4s and reviewing policies are necessary components of any new hire process,but onboarding involves so much more than paperwork.Nearly 30%of new hires quit within the first 90 days because of a poor onboarding experienceso dont underestimate the importance of making it a priority from the start.Responsibilities:Who Leads the Way?HR and hiring managers should work together to define a consistent,repeatable onboarding process that prioritizes 4 things:1.Rules&regulations 2.Expectations 3.Culture 4.ConnectionNew Hire Retention RateIf new hires are looking for greener pastures within the first few weeks of employment,it could signal trouble with your onboarding program.Calculating new hire turnover at various increments(one week,one month,two months)can help provide insight into whats causing employees to leave.Are they not the right candidate?Or did a lack of training during onboarding contribute to a poor experience?KEY ONBOARDING METRIC Talent ManagementRecruiting HiringOnboarding AdministrationHow to Get There:Onboarding Administration 14Onboarding:If your workforce reports to different locations,its even more important to get onboarding right.Make the process more engaging and meaningful,eliminate hours of manual admin and view and sign documents electronically.How Paycor Helps The One Thing That Gets in the Way of OnboardingThe#1 onboarding mistake organizations make is that HR and frontline managers get bogged down with manual,administrative tasks which take their focus away from giving employees the training and introduction they need to be confident and productive.How Technology Can Save Time&Money Reduce hiring administration Mitigate compliance risk Tax credit integration Accelerate new hire productivity Increase retentionTalent ManagementRecruiting HiringOnboarding AdministrationHow to Get There:Onboarding Administration 15Benefits Administration Ideal StateBenefits administration is all about HR leveraging benefits as a competitive advantage to recruit,engage and retain top talent.But thats only part of the story.Labor costs are often a companys greatest expense.Managing these costs arent always seen as a primary function of HR,but we believe thats a missed opportunity.HR can offer a unique people-centric view of the business that can aid your efforts as a Finance leader to reduce costs and improve productivity.The benefits leader is responsible for the overall design,implementation,communication and administration of the organizations health and wellness programs.The key to a successful benefits program is removing the manual burden of tracking plans and conducting enrollment by hand so the benefits leader can create a benefits program that appeals to a diverse workforce and entices new talent.BenefitsBenefits AdministrationLabor Costs16INSIGHT:BENEFITS COST PER EMPLOYEEThe most successful HR teams are evaluating benefits packages to not only control costs but differentiate in the marketplace.PARTICIPATION RATEUnused benefits can be costly for employers,so finding which resources arent being utilized can impact the bottom line.BENEFITS SATISFACTIONSurveying employees is a great way to determine which benefits are most coveted.Here are just a few of the critical metrics your HR team should review to understand outages and ways to improve.Benefits:ResponsibilitiesBenefitsBenefits AdministrationLabor Costs17How to Get There:Benefits18BenefitsBenefits AdministrationLabor CostsBuried in Paperwork?If benefits administration relies on manual processes,HR will have little left to educate and guide employees through the fear and anxiety that comes with open enrollment.And adding more staff to manually fill out forms isnt the answer.How Technology Can Save Time&Money Streamline open enrollment Automate workflows Drive efficiency with carrier connections Talk to the Right BrokerBecause so much knowledge is needed to prescribe the right plans for both the organization and employees and resources are few,HR is at a crossroads.Thats why theyre turning to benefits brokers for help.The right technology and the right partner can be a game-changer for HR,simplifying everyday tasks.Leverage intuitive employee self-service Deliver real-time analytics How to Get There:BenefitsBenefits:The right solution will give you insights into your benefits spend and can even benchmark your data against the competition.How Paycor Helps 19Labor CostsThe Great DivideA recent Paycor survey found 40%of business leaders agreed that HR and Finance are working more closely together as a result of the pandemic.However,each discipline has a slightly different take on how effective this new degree of collaboration has been.Theres a disconnect,especially at the extremes,between these functions about how HRs contributions are perceived.HR leaders believe their programs and initiatives impact the bottom line,but Finance isnt as convinced.Paycors point of view on this age-old question is clear.HR is sitting on a goldmine of data that,properly leveraged,can have an enormously positive impact on the bottom line.So,Whats the Problem?HR teams still spend too much time on transactional HR functions,logging into multiple systems,toggling between spreadsheets.HR often doesnt have the tools they need to access,much less interpret,data.Your HCM platform has to make it easy to not only find the data but also separate the signal from the noise.BenefitsBenefits AdministrationLabor Costs20BenefitsBenefits AdministrationLabor CostsUnplanned Overtime Is a Big ProblemOne of the biggest challenges companies face is controlling labor costs.A quick way for HR to add value to the organization is to examine the impact labor expenses have on your business.Start with overtime.Its one of the main reasons labor expenses are off the charts.Then look at your scheduling process.By drilling down into key labor metrics across your business,HR can detect problem areas and optimize it to reduce unplanned expenses.70%Is a Big Number According to the Bureau of Labor,70%of businesses compensation costs are attributed to wages and salaries.If HR doesnt have meaningful,actionable data on your biggest expense,you cant impact your bottom line.21Here are just a few of the critical metrics your HR team should review to understand outages and ways to improve.INSIGHT:TOTAL LABOR COSTSEvaluating labor costs by location,month and annually can uncover problem areas.OVERTIME COSTSDrill down into overtime expenses by month,manager and department to find where hidden costs lie.Labor Costs:Responsibilities BenefitsBenefits AdministrationLabor Costs22How to Get There:Labor Costs23Avoid Blind SpotsHR technology,specifically time and attendance tracking,scheduling platforms and data analytics tools,can prove invaluable when evaluating and projecting out labor expenses.Not only can an accurate time solution alert you when employees approach overtime,but a scheduling tool allows HR to better organize and track schedules,resulting in more insight into hours worked.How Technology Can Save Time&Money Employee self-service Mobile punching Overtime insights Automated scheduling Proactive communication Detailed tracking and reporting How to Get There:Labor CostsBenefitsBenefits AdministrationLabor CostsTime&Attendance:Take control of labor costs by monitoring the hours your employees work.Scheduling:Organize your team and communicate critical scheduling information in real time.How Paycor Helps 24HR OperationsIdeal State:The Pulse of the HR DepartmentPeople are the heart of every organization,so creating a place where employees show up,make a difference and win together is an important responsibility of any HR team.But creating a culture that appeals to multiple generations doesnt happen overnight.HR must capture,analyze and share data across 4 key areas that influence every aspect of the business from recruiting and retaining talent to implementing new benefits and employee rewards.Performance Employee Experience Learning CompensationHR Operations25The Domino EffectGallups annual survey of engagement continually finds that only 1/3 of employees are engaged at work.Herein lies the problem:When employees are disengaged,they tend to disrupt morale.Thats why its critical that HR teams shape the employee experience by listening to,developing and supporting their people.51%of employees are not engaged and,even worse,16%are actively disengaged.(Gallup)HR Operations:ResponsibilitiesHR Operations26Here are just a few of the critical metrics your HR team should review to understand outages and ways to improve.INSIGHT:RETENTION RATEConduct exit interviews to understand whats causing employees to leave.TURNOVER RATEExamining turnover trends will allow HR to prevent problem areas from becoming larger issues.NET PROMOTER SCORELearning what makes promoters tick will enable you to build the right engagement strategies.HR Operations:Responsibilities HR Operations27How to Get There:HR Operations28The New Era of People Management Organizations have modernized their performance management process,replacing the dreaded annual review with more dynamic and engaging coaching sessions.Fast forward to today,and performance management is once again under the microscope as organizations are adopting a more agile approach to mitigate workforce disruptions and changing goals resulting from the pandemic.How Technology Can Save Time&Money Improve coaching conversations Empower employees to own personal development Provide career pathing Promote 360 performance feedbackHow to Get There:HR OperationsPerformance:Improve the quality of work by creating moments of genuine dialogue and coaching.Allow employees to feel heard and help them better understand what they need to do to succeed.How Paycor Helps HR Operations29Go Beyond the Average SurveyCompanies often use annual surveys to measure feedback,but because theyre conducted at such a large scale,they take a lot of time to prepare and analyze.HR teams are turning to pulse surveys which are conducted more regularly than traditional methods,but without losing any of the depth of insight.Natural Language Processing makes this possible by analyzing an entire batch of written responses instantly to discover pain points and identify areas of strength.How Technology Can Save Time&Money Drive business performance Support increased diversity Promote accountability Improve worker wellbeingPulse Surveys:Go beyond the average employee engagement survey by gathering and converting employee feedback into real insights so you can identify trends like turnover or low morale before they become problems.How Paycor Helps How to Get There:HR OperationsHR Operations30Help Employees DevelopNo Matter Where They AreAn essential part of HR operations is investing in resources to support employee development.Strong training and career development opportunities can raise profitability and dramatically increase retention rates.This is a big deal,especially when it can cost 6 to 9 months salary to identify,recruit and onboard new staff.How Technology Can Save Time&Money Make learning accessible for anyone Easily organize,manage and track training Build and deliver quality content quickly Reach employees anytime,anywhereLearning Management System:Deliver mobile-friendly learning with social capabilities on one platform.Easily create custom programs and offer workers self-paced options for maximum flexibility.How Paycor Helps How to Get There:HR OperationsHR Operations31Paint the Whole PictureEffective compensation management is one of the biggest drivers of engagement and retention.Yet,some confuse compensation with salary.While salary makes up a large part of total compensation,bonuses,health and life insurance,vacation,stock options,retirement savings plan contributions and pension plans complete the entire package.By providing a big picture of your companys contributions,employees can easily see how much youre investing in them.How Technology Can Save Time&Money Eliminate tedious admin work Mitigate compliance risk Ensure pay equity Retain talent and attract new candidatesCompensation Planning:Take the complexity out of planning and drive recruiting and retention by managing all aspects of compensation in one system.How Paycor Helps How to Get There:HR OperationsHR Operations32How Paycor HelpsVISIT PAYCOR.COM/HCM-SOFTWARECALL 844-981-0040 WORKFORCEMANAGEMENTEMPLOYEEEXPERIENCETALENTMANAGEMENTLeadersBENEFITSADMINISTRATIONONBOARDING HRPAYROLL ACA REPORTINGANALYTICS MOBILEHCMCorWorkforceManagementPAYCORTIMESCHEDULINGBenefits AdministrationTalentManagementEmployee EngagementRECRUITINGPERFORMANCECOMPENSATIONBENEFITS ADVISORLEARNING MANAGEMENTPAYCOR PULSEPaycor builds HR software for leaders.Our Human Capital Management(HCM)platform modernizes every aspect of people management,from the way you recruit,onboard and develop people,to the way you pay and retain them.But what really sets us apart is our focus on business leaders.For 30 years,weve been listening to and partnering with leaders,so we know what you need:HR technology that saves time,powerful analytics that provide actionable insights and a Personalized Support Model.Thats why more than 40,000 organizations nationwide trust Paycor to help them solve problems and achieve their goals.

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埃森哲：Cloud Continuum重塑高科技企业（英文版）（31页）.pdf

Transforming High Tech through the Cloud Continuum2Transforming High Tech through the Cloud ContinuumTable of ContentsDefining the future of cloud with High TechThe journey to Cloud as ContinuumFrom silos to Cloud ContinuumHigh Tech cloud obstaclesUnlocking Cloud Continuum benefits for High TechCloud Continuum best practicesDifferentiation leads to successShaping a future of growthHow to become a Continuum CompetitorThe many places Cloud Continuum can take youEstablish cloud practices to support and augment your technologiesAccelerate innovation to deliver exceptional experiencesThe cloud requires continuous commitmentConclusionAppendices345678910111216 20242829High Tech companies are facing a massive upheaval.The world has changed significantly in the past 24 months.Most enterprises are relying on High Tech organizations to enable a“new normal”of working and living.The High Tech industry has a unique relationship with the cloud.1 They are providers,consumers,and enablers,all in one.They make the products and tools that build the cloud,interconnect and define communication between clouds,integral to the transformative process of moving toward cloud.In the midst of their own cloud transformations,some High Tech companies have been providing top-tier clouds for years,while others are seeking to find cost savings or phase out aging hardware.Some High Tech companies are even ahead of the game.They are using cloud as a fundamental part of their own DNA,demonstrating excellence as they unleash innovation to define new experiences to sell and connect with their own clients.We call these companies Cloud Continuum Competitors.Defining the future of cloud with High TechHigh Tech organizations face a unique set of challenges and must reimagine their future with cloud3Transforming High Tech through the Cloud ContinuumFor more information about cloud transformation in High Tech,read our High Tech Industry Narrative.Transforming High Tech through the Cloud Continuum4The pandemic has accelerated change for all businesses,with timelines for migration being compressed from years to months.2 Accentures research predicts that over the next three to five years,two-thirds of workloads will shift to the cloud.3 This creates a whole new set of customer needs,with associated demand for products.With High Tech companies providing the tools and hardware for a large majority of that cloud,the likelihood for disruption(and opportunity)has never been higher.In its recent research,Accenture completed a global survey of top companies across many industries and evaluated their cloud maturity.Among the 4,000 respondents,193 were from the High Tech industry and almost all the organizations were present in the cloud.However,only a small subset were experiencing huge benefits from engaging fully with a new cloud operating model.These Continuum Competitors in High Tech are using cloud for more than compute,storage and networking.They are leveraging cloud to differentiate their business,by first using the cloud to bring innovation into their product development,and then in turn delivering those products via the cloud to their customers.They utilize the entire spectrum of cloud capabilities from public,private,edge,and everything in between.These organizations are reimagining their processes,from their product roadmaps and business models to their go-to-market strategies.They are positioning their organization for a stable and profitable future by:The journey to Cloud as a ContinuumCloud is not a single destination,but an ongoing journey to a new wave of operating modelsCloud Continuum Competitors embrace the cloud to grow their business as a tool,an ecosystem and an interface to new customers.Speeding up product developmentIncreasing agilityOptimizing manufacturingTransforming High Tech through the Cloud Continuum5CompliancePrivacyEfficiencyCLOUD CONTINUUMInnovationScaleElasticity LatencyExperiencePrivatePublicEdgeSDNCentralized&DistributedMultiHybridFrom silos to Cloud ContinuumOrganizations can realize more value from the cloud by using it as a continuum of seamlessnot siloedcapabilities for the ever-changing businessCompliancePrivacyLegacyLatencyUntetheredInnovationScaleElasticityDistributedComputingPrivate DataCenterPublicCloudCentralizedDistributed Manufacturing Supply chain Intellectual Property Personally identifiable information Highly confidential data ERPFromTo Non-core workload Elastic demand Innovation/toolsHigh Tech use casesTransforming High Tech through the Cloud Continuum6Migration to cloud can be difficult for any organization,but High Tech companies face a unique set of challenges.There are also varying levels of cloud maturity depending on geography.(see sidebar 1).Making operational changes to legacy methods and reworking product development processes to leverage cloud requires investment and change.This requires the right people with the right skills and tools.Security and compliance is also a primary concern for High Tech companies.Secure methods for storing and distributing data are vital to protect the most important assets,including intellectual property.While cloud security is improving,giving up data control gives rise to more private and hybrid solutions.Some companies still view cloud as a cheaper method of buying infrastructure,or simply a way to stop paying for a data center.This mindset restricts the long-term value proposition of embracing the cloud as a continuum.With the right strategy and commitment,cloud can unlock new market positions,differentiation,and agility.High Tech specific cloud challengesHigh Tech companies use private and hybrid clouds to a greater degree than firms in other industries.This makes infrastructure more challenging-from architecture to management-especially as companies continue to focus on governance,security,and regulatory compliance.Cloud Continuum companies are also in competition for scarce cloud skills.In order to grow quickly,they need to hire talent with the knowledge and skills to address these key concerns as referenced earlier.High Tech challenges vary by geographyHigh Tech cloud obstaclesHigh Tech organizations are facing challenges as they embrace the cloudNorth AmericaInfrastructure is a bottleneckSecurity and compliance risksLack of cloud skills within the organizationData sovereignty concerns/regulationsSecurity and compliance risksMisalignment between IT and businessGrowth Markets50FCE9B%Sidebar 1Transforming High Tech through the Cloud Continuum7Unlocking Cloud Continuum benefits for High TechHigh Tech Continuum Competitors use the cloud as the basis of their future operating models,reaching towards the future.Cloud unlocks new ways to interact with all parts of their business,and allows them to offer new products and services.High Tech Continuum Competitors are using cloud to differentiate.They are also creating and innovating the technology,software,and hardware that improves the cloud for their clients.Continuum Competitors are seeing between 1.2x(NA)and 2.7x(Europe)higher cost reduction than those just retaining their legacy hardware.Furthermore,Continuum Competitors are using the cloud for more than just savings,with 89%-90%of firms reporting that they use cloud to enhance collaboration among employees and make their work more interesting.They are also leveraging the cloud to:Drive innovation for their own operationsProvide a marketplace for their ongoing technology offersUndertake capital or operational improvementsCloud Continuum best practicesCloud Continuum Competitors view the cloud as a permanent commitment to reinventionCurrent state of practicesFigure XContinuum practicesDisconnected Agility:Some parts of business are agile,but others are a bottleneckWaterfall Goals:Waterfall approach to IT estate-big changes done infrequentlyCloud-last Apps:Cloud only when developing new apps,but core stays legacyMakeshift Talent Strategy:Tactical use of cloud in digital transformation,fills in gapsIT Conservation:Keeping-the-lights-on,no new casesScale Inflexibility:Perpetually underutilized or overwhelmed serversFeed-it-forward Agility:Speed time to future markets,again and againContinuous Goals:Alignment is continuous,not episodicCloud-first Apps:Clouds the developers defaultTalent Transformation:Compress transformation continuouslyIT Experimentation:Unremittingly upgrade experiencesScale Awareness:Predict the power requirements for new generation of Cloud-AI Services8Transforming High Tech through the Cloud ContinuumTransforming High Tech through the Cloud Continuum9Differentiation leads to successContinuum Competitors are forward thinking,looking not only at costs savings,but also ways they can truly differentiate themselves through the use of cloud9Companies focused solely on retaining their legacy infrastructure may miss savings and innovation opportunities.Because High Tech players are both builders and users of the cloud infrastructure/tools,their product roadmaps are uniquely impacted by the cloud.High Tech companies achieve cost saving by migrating to the cloud,however this is not their primary goal.Only 60%of High Tech companies report cost savings as a benefit of migrating to the cloud,compared to 80%of companies in other industries.Continuum competitors go beyond cost reduction.They use cloud to create differentiation-through public cloud partnership and/or private/hybrid cloud investment and expertise.Note:Data on this slide is from the global cross-industry research results,which include High Tech companies.High Tech Continuum Competitors use cutting edge tools,applications and processes that leverage massively available and scalable infrastructure.Some are developing applications in-house and running hybrid clouds but a growing number of customer clouds are built for single industries or applications.These clouds can offer unique opportunities to jumpstart business opportunities or reduce development costs.Retain LegacyNon virtualized,dedicated infrastructureNew tech adoption:0%Continuum Practices:0%Key benefit:Keep-the-lights-onNew tech adoption:40%Continuum Practices:38%Key benefit:Cost reductionNew tech adoption:72%Continuum Practices:77%Key benefits:Cost reduction,innovation,speed-to-market,cross sell&up-sell,diversification,compliance,simplification.Migrate OnlyFind lowest cost and/or best performance,public or privateCloud Continuum CompetitorsCloud in all forms:Public,Private,and Hybrid.Transforming High Tech through the Cloud Continuum10Shaping a future of growthStrategic leaders are discovering how to capitalize on the Cloud ContinuumWith High Tech at the forefront of the Cloud Continuum,the leaders are defining strategies that utilize cloud innovation to its fullest.The Cloud Continuum4 report lists four key approaches to the cloud that are common across Continuum Competitors.These approaches also apply to High Tech companies.They are defining strategy and innovation to unlock future opportunities and growth.These approaches are applicable to any High Tech company using the cloud,whether the firm is an early-adopter or just starting on their cloud journey.10Transforming High Tech through the Cloud Continuum11How to become a Continuum Competitor11Transforming High Tech through the Cloud Continuum01.03.02.Know where you want the Cloud Continuum to take youAccelerate innovation to deliver exceptional experiencesEstablish cloud practices to support and augment existing technologies04.Provide continuous strategic commitmentTransforming High Tech through the Cloud Continuum12The many places Cloud Continuum can take youDefine vision,vulnerabilities,shortcomings and capabilities.Plan for the future and follow through.01.12Transforming High Tech through the Cloud ContinuumTransforming High Tech through the Cloud Continuum13Capitalizing on the clouds full potentialYour Cloud Continuum strategy can help you realize your full business potentialTo achieve the full potential of your enterprise in the cloud,its important to develop a Continuum strategy involving three key facets:The Continuum is not just one technology,but manyeach with its own strengths and limits.The most successful cloud strategies utilize the full Cloud Continuum,including private,hybrid and public architectures.Continuum Competitors use these architectures to enable differentiation with analytics,high performance compute,artificial intelligence(AI)and machine learning(ML).01.Define a vision that clearly states the core values and future aspirationsIdentify competitive vulnerabilities and shortcomingsDevelop a clear classification of capabilities,anchored on where your organization is today versus its future aspirations,leveraging the full extent of the ContinuumEdge computing is also ripe for cloud and Continuum improvement.Private cloud architectures that work alongside public cloud are becoming increasingly popular.5G connectivity has massively expanded the possibilities for connecting devices anywhere.Simply understanding what capabilities are even available on the continuum can be hard,let alone understanding how to use them.It is important to first create a clear strategy and priorities before leaping head-first into adoption.This will keep an organization moving forward in the same direction.Continuum Competitors lead the pack not just in formulating ambitious visions,but also at realizing them.For example,in North America,Asia,and Latin America,High Tech Continuum Competitors aim for 1.4x more ambitious financial and operational goals(e.g.faster time to market,increased cross sell or up sell,and increased number of customers).Continuum Competitors are 3.3x more likely to have adopted AI-augmented knowledge work globally.13Transforming High Tech through the Cloud Continuum1401.Siemens makes the right connectionsSiemens AG,a 174-year-old company,rapidly pivoted to Industry 4.0 and became a highly advanced industrial manufacturer a few years ago,largely enabled by the Cloud Continuum.Siemens made the decision to help engineering and manufacturing companies use vast amounts of data from their factories,equipment,and production processes to operate more efficientlyall in alignment with the companys Industry 4.0 vision.To do so,it recognized those companies would need to embrace digital transformationdriven by automation,edge and cloud computing.It also understood those companies use a diverse landscape of different platforms,so offering cross-platform interoperability with innovation was important.Siemens chose to proceed with a multi-cloud,best-of-breed approach,working with multiple cloud providers to broaden the choice of platforms offered to companies,as well as investing in an advanced set of capabilities across those providers to continually optimize and improve manufacturing.14Cloud Continuum Competitors embrace the cloud to grow their business as a tool,an ecosystem and an interface to new customers.Transforming High Tech through the Cloud Continuum1501.1515In Depth:Siemens embraces smarter manufacturingSiemens Cloud Continuum journey has saved the company significant time and resources.In 2012,the company entered a strategic collaboration with Amazon Web Services in and followed up with a series of other investments,resulting in the development of MindSphere in 2017.MindSphere is a cloud-based operating system built on native AWS technologies.It can process data,in real-time,from thousands or even millions of devices and sensors in plants,systems,machinery,and products dispersed throughout production processes and supply chains.All this is possible due to an architecture where edge and cloud computing are working seamlessly to deliver the same business outcome.MindSphere was deployed that same year at Siemenss own factory in Monterrey,Mexico,which manufactures more than 28 million circuit breakers and switches every year for the US market.The factory had difficulty monitoring the overall efficiency of equipment,including unplanned downtimes and uneven quality of production.By connecting the factory to the cloud,workers were able to view problemssuch as a malfunctioning machinein real-time and make immediate improvements.By 2018,Siemens made MindSphere available on Microsoft Azure,which enabled a bigger base of customers to achieve quick time-to-value and scale across the enterprise.In 2019,Siemens announced a new cooperation with Google Cloud to optimize factory processes and improve productivity on the shop floor.By combining Google Clouds data cloud and AI/ML capabilities with Siemens Digital Industries Factory Automation portfolio,manufacturers were able to visually inspect products or predict wear-and-tear of machines on the assembly line.Another solution from its digital enterprise portfolio,Industrial Edge,allowed manufacturers to collect local data from IoT devices,which could then be preprocessed and sent to the cloud in small packages.Siemens Cloud Continuum saved both time and money,as central management of edge devices and apps reduced deployment and maintenance expenditures.Today,Siemens multi-cloud strategy allows it to offer a range of cloud-based solutions to customers in many other industries,including healthcare and infrastructure,to bring greater efficiency and cost savings from their machines and processes.Transforming High Tech through the Cloud Continuum16Establish cloud practices to support and augment your technologiesMigration alone is not sufficient.Companies must use cloud as a fundamental ingredient and pursue technology adoption.02.16Transforming High Tech through the Cloud ContinuumTransforming High Tech through the Cloud Continuum17Being agile helps to thrive and growIn a world where roughly one-third of workloads are in the cloud,a winning strategy hinges upon not just migrating to the cloud,but also continuously building upon the migration.For instance,its smart to build on cloud with edge,leverage Platform as a Service(PaaS)services to assemble and consume newer capabilities,and adopt and apply AI/ML technologies on your data and processes.Agility separates successful Continuum Competitors in this space and those who are still up-and-coming.Continuum Competitors are in a state of continuous innovation.They are adopting and integrating new technologies,without just chasing the next big thing.These competitors are able to evaluate and utilize new technologies faster,which means they reap the benefits fasterimproving their supply chain,bringing products to market faster and improving their customers experiences.However,innovation comes at a price.The key to success is combining adoption with practices that bring discipline and help companies achieve change outside of technology at the same rate.Successful Continuum Competitors follow at least four out of six best practices(referenced in Figure X).Companies that follow at least four out of the six best practices are able to adopt 30%more technologies.02.17Transforming High Tech through the Cloud Continuum1802.$8B communications hardware provider adopts Everything-as-a-ServiceA leading global provider of mission-critical communications hardware with$8 billion in annual revenue undertook their journey on the Cloud Continuum to better traverse and succeed at adopting an Everything-as-a-Service(XaaS)model.They had been experimenting with XaaS5 offerings,but were not achieving the desired scale.Their technology platforms in communications,software,video,and services make cities safer and help communities and businesses thrive,which has led to a new era in public safety and security.Public safety and commercial customers globally depend on their solutions to keep them connected,from every day to extreme moments.The client serves more than 100,000 customers in over 100 countries and has a rich heritage of innovation spanning 90 years.Accenture assisted this company with the planning and execution process.The first step was completing an as-is assessment and to-be design for capabilities,technology,and operating model.A series of workshops and interviews helped create a clear view of the pain points to be solved,and a concrete vision and strategy for their own future with cloud and XaaS.Below are some of the key deliverables.Co-created a two-year tactical roadmap of 70 initiatives to achieve target stateRe-prioritized IT initiatives to tie with business prioritiesDefined to-be decision authority and pilots to launch customer success and new NPI forumsCreated microsite to socialize project across organization18Transforming High Tech through the Cloud Continuum1902.Application innovation by global software providerA global provider for consumer and enterprise markets with 13 aging data centers is leveraging the Cloud Continuum to forge a path to consolidate cost savings,while leveraging the development and delivery agility of a cloud infrastructure.Accenture helped this company create a plan to reduce their data center footprint.We helped access,architect,and roadmap their journey to their future state environment.As part of the assessment,the team identified and analyzed a total of 1,000 applications.Accenture assisted with the cloud service provider selection and architecting the future state environments in the cloud,helping with the following actions:By leveraging a converged infrastructure private cloud tied to multiple public clouds,Accenture created a flexible infrastructure solution that enabled rapid development and delivery of software assets.Accenture is now contracted to migrate applications into one of their public cloud providers environment.In addition,the team is currently setting up a migration factory for 40,000 workloads into the cloud and is negotiating additional workloads into a second cloud provider.Dispositioned all identified applications into a proposed reference architecture(both public and private clouds)Completed future Infrastructure low level design Designed hybrid cloud security model for the future stateIdentified network requirements 19Transforming High Tech through the Cloud Continuum20Accelerate innovation to deliver exceptional experiencesSpread experiences across products,services,delivery,and the entire business.03.20Transforming High Tech through the Cloud ContinuumTransforming High Tech through the Cloud Continuum2103.Experience is everythingIts important to remember the cloud is an enabler and a stepping stone,not the end goal.Cloud and the Continuum enables High Tech companies to build better experiences that are human-centric,rethinking how they:To Continuum Competitors,experience-obsessed reimagination of their business is a competitive differentiator,which is enabled only by advancing on the Cloud Continuum.They also make their investments visible and accessible to both employees and customers.Deliver their products and servicesBuild an employee experienceEngage with customers through delivery modelsIn fact,these organizations go beyond the traditional notions of optimizing customer and employee touchpoints to innovate and deliver on exceptional experience.90%of High Tech Continuum Competitors in North America,and 100%in growth markets,use the cloud to enhance collaboration among employees and encourage ambitious projects that cut across business functions and geographies.They use the cloud to make work more interesting and data-driven by reducing manual tasks and maintenance work.They used cloud-based tools to make technology more approachable.Across the board,they natively provide employees with human-centric experiences that seamlessly flow across different applications.The result:human-centric experiences.21Transforming High Tech through the Cloud Continuum22Samsung elevates customer experiences03.Samsung NEXT Ventures,the investment arm of Samsung NEXTis an innovation group within Samsung dedicated to identifying new growth opportunities.They are leveraging the Cloud Continuum to provide an exceptional customer experience by getting close to where customers arewith edge computing.As such,it is developing innovative approaches to offset the lower compute power and lower data processing capabilities of edge devices.Samsung imagines a future in which every device in its vicinity draws on the resources of every other device around it to form a system stronger than the sum of its partsan ecosystem of connected doorbells,smart speakers,and TVs,all within the same neighborhood.The resulting mini cloudsformed of edge devices owned by multiple people or even companiescould combine the low-latency benefits of computing on the edge,with some of the brute computing power of the cloud,bringing together the best of both worlds.Meanwhile,at Samsung Research,experts are exploring AI to make customer interactions with devices and appliances hassle-free and natural.Its what the company calls“multimodal interactions,”where devices and appliances can offer multiple modes of interaction,including speech,sight,and touch.For a customer,this could mean giving sign-language directions to vacuum cleaners or voice commands to turn on or off air-conditioners.Today,AI systems use deep learning to achieve this type of elevated user experience.Mini clouds of edge devices combine the best of both worldsthe low latency benefits of computing on the edge,with the brute computing power of the cloud.22Transforming High Tech through the Cloud Continuum23Munters mixes it up with VRMunters is a great example of how an organization can use the Continuum to reimagine and reinvent the employee experience.Munters,a maker of energy-efficient air treatment and cooling systems for industrial and agricultural applications,found onsite client visits were difficult during the pandemic.Thus,they enabled engineers to use mixed reality,powered by Vuzix Smart Glasses,to collaborate remotely with clients via real-time video,images,gestures,real objects,and more.These glasses can be plugged into their enterprise resource planning(ERP)and asset management systems by technology partner IFS Cloud,powered by Azure.Today,this experience is used by more than 200 of Munters engineers worldwide.03.23Forced by the pandemic to provide customers unique experiences and serve them in newand virtualways,some companies compressed their digital transformation and leapfrogged to higher performance level.To learn more,read about the Leapfroggers here.Transforming High Tech through the Cloud Continuum24The cloud requires continuous commitmentCloud must be embraced as more than a cost-saving measure.Leaders must set objectives,build culture,and create awareness to make cloud effective.04.24Transforming High Tech through the Cloud ContinuumTransforming High Tech through the Cloud Continuum25You build a strategy,implement good cloud practices and build new experiences for your customers and employees.Its important to remember that a core requirement for success is to continually repeat the cycle:innovate,embrace and expand.However,an abundance of choice can also lead to paralysis when a company is faced with too many options and has to consider them for existing and future goals.Its therefore critical that leaders understand how to balance their own Continuum ambitions with strategic priorities that will keep the business focused.Specifically,leadership needs to balance the goals and strategy,and align them with business objectives.They must accept appropriate levels of risk and evangelize a culture of agility and growth.Between budgets,alignment between businesses and IT,incentives,risk and measuring success there are plenty of pitfalls.Leadership must become champions for their cloud strategy and advance initiatives with clarity and commitment.Organizations also must recognize the“all-hands”nature of the challengeand everyone across the organization needs to be aware of the clouds potential and best practices.Innovation can come from anywhere,and when more people with varying perspectives and skillsets are invited into the conversation,more possibilities abound.Leadership is responsible for not only setting ambitious yet attainable goals and touting an exciting vision,but also ensuring organization-wide education and evangelism.Leaders should intentionally go through the enterprise and ask,“What awareness are we building?”and“How well do employees at all levels understand the goals and the potential of the Cloud Continuum?”04.Build your own realityPut your customized business plan into action with the Cloud Continuum25Transforming High Tech through the Cloud Continuum2604.Customized NetApp cloud usage drove$1.5B in revenueNetApp as a business is moving to the cloud.Mark ChadwickVice President,Strategic Partners,Worldwide Partner Organization,NetAppNetApp embraced a top-down,strategy shift from traditional hardware to cloud-enabled sales.They invested in decoupling their hardware and software offerings to create offerings on the cloud.They partnered with previous competitors(CSPs)to expand customer base and market opportunities.They give customers the ability to use and consume NetApp customized for themNetApp set the strategy from leadership to adjust the business to accommodate the shift to cloud:activating the sales organization and adjusting compensation plans,etc.NetApp is a long-established hardware company.They embraced the change inherent in the cloud market and made moves to separate the OS from their hardware so that it could be offered to clients as an OS on top of a virtual machine(VM)accessed from a hyperscaler.The result is equivalent to a NetApp storage array running in a public cloud environment,making it easier and more economical to manage.NetApp embraced the growth of the CSPs,aggressively changing its business model to seize the market opportunity.“From a vendor perspective,weve been working very closely with the CSPs to transition some of the products in our portfolio to run in the cloud,”says Mark Chadwick,managing director,strategic partners at NetApp.“That introduces mobility,flexibility,scalability,and other benefits largely found through cloud deployments.”NetApp cloud developers arent just building these products for end-users.“Our engineering teams are actually leveraging the cloud for their development,”Chadwick says.“Its a way to both increase agility and demonstrate the effectiveness of the products to the customer base.”Its all part of the companys strategic shift to a more cloud-centric posture.“NetApp as a business is moving to the cloud,”Chadwick says.“Weve quit building data centers.Were doing more and more with the hyperscalers.So,for a lot of the offerings that NetApp actually builds,our own internal IT is the first customer.”26Transforming High Tech through the Cloud Continuum2704.Everything-as-a-Service business models expand customer reach and revenueA large multinational information technology company was experiencing significant competitive pressure and customer demands for a subscription-based option for many of their compute,storage,security,and networking offerings.Due to a series of targeted acquisitions,an opportunity for Everything-as-a-Service(EaaS)emerged,and they wanted to bundle many solutions into a single offer(hardware,software,services)and finance them.Accenture partnered with the company to conduct a Software-as-a-Service(SaaS)assessment and roadmap for their existing software business.This included evaluating operating capabilities and the current state of several business units and offerings against industry best practices.The teams focused on sales,customer success,finance,marketing,and organizational areas.Accenture also helped evaluate their business systems to provide actionable recommendations to change front and back office systems to conduct frictionless subscription and consumption transactions.Working with Accenture,the company was able to deliver on its commitment and successfully transition to an as-a-service(AaS)model that had a significant impact to their channel.This presented an opportunity to grow their services through its channel strategy.Since they were a hardware provider,special focus was given to protecting the existing business while growing a new(SaaS and Network-as-a-Service(NaaS)business.A commitment to embracing cloud as a new way of doing business(rather than a competitor to be avoided)has enabled the company to create new revenue,evolve business models and unlock better ways to serve customers.27Transforming High Tech through the Cloud Continuum2828Conclusion:The potential of becoming continuousBe ready for every opportunity that comes your way with the Cloud ContinuumAt the forefront of smart manufacturingBuilding supply chains that interconnect and respondProviding the largest private and hybrid cloud environmentsUtilizing cloud to solve their own industry challengesCreating cloud solutions for the other industriesHigh Tech Continuum Competitors are not only ahead of the pack,but they are also redefining what the cloud can be through innovative use cases.They are:Reframed as a strategic opportunity,the cloud equips High Tech companies to unlock new business initiatives and avoid being outpaced by the competition.Former hardware providers can switch to software-defined offerings,creating innovative solutions for their customers.Cloud creates a whole new set of customer needs,with associated demand for products.The use of cloud-centric tools and techniques streamlines development and supports innovation.From an operational standpoint,a strategic hybrid multi-cloud delivers the high-performance,resilient,elastic,and secure computing platform needed to support modern product development.Accenture can help your organization become a Cloud Continuum Competitor.Connect with us to learn how your company can accelerate reinvention.Transforming High Tech through the Cloud ContinuumTransforming High Tech through the Cloud Continuum29A spectrum of capabilities and services from public through edge and everything in betweenContinuum practicescloud is a permanent commitment to reinventionFeed-it-forward agility:Speed time to future markets,again and againContinuous goals:Alignment in continuous,not episodicCloud-first apps:Clouds the developers defaultTalent transformation:Compress transformation continuouslyIT experimentation:Unremittingly upgrade experiencesScale awareness:Predict the power requirements for new generation of cloud-AI servicesCloud SaaSCloud IaaSCloud PaasHybrid Cloud(mixed computing,storage,and services environment made up of on-premises infrastructure,private cloud services,and a public cloud)Serverless computingCloud-native applicationsContainersMicroservice architecturesMulti-cloudDeep learningPhysical robotsVision systemsNatural language systemsTiny MLFederated learningRPA(Robotic Process Automation)Cyber threat intelligence(CTI)/Active DefenseEndpoint detection and response:SIEM(security information and event management):Trust-based architecturesInternet of Things(IOT)Edge/fog computingData lakes(data repository)Streaming/real-time dataBig data analyticsCloud AI and automationSecurityInternet of thingsReal-time data capture and analysis25 technologiesenabled for the Cloud ContinuumSix practicesfor the continuumTransforming High Tech through the Cloud Continuum30Case Study ReferencesSiemens Siemens makes Industrial Data accessible and actionable.New services enabled by the Mendix low-code platform enable data-driven decision making in factories and across enterprise data source.Siemens and Microsoft partner to deliver secure,scalable and open Industrial IoT applications to support industrial organizations digital transformation.Siemens brings power of Mendix low-code enterprise application development platform to MindSphere,April 16,2019.A pilot version of the IoT operating system MindSphere from Siemens is now available on Microsoft Azure.Customers and partners of both companies can access MindSphere solutions via the cloud computing platform,May 19,2018.Industrial Edge:Exploit the full potential of your machine and plant data to increase your competitive edge and generate new business models.Siemens Mindsphere,Case Study,Amazon Web Services.Industrial Edge for machine-and plant builders:The easiest way to integrate information technology into machines.MindSphere is the cloud-based,open IoT operating system from Siemens that connects your products,plants,systems and machines,enabling you to harness the wealth of data generated by the Internet of Things(IoT)with advanced analytics.Industrial Edge is the SIEMENS platform to host applications from different vendors on a computing platform close to the shopfloor.Siemens Digital Industries Software and AWS have been working together since 2012.In 2017,AWS collaborated on the development and delivery of MindSpherev3.Siemens Smart Infrastructure Chooses AWS as its Preferred Cloud Provider for SAP Environments,December 3,2020.Siemens Advanta&Amazon Web Services:Bringing business into the cloud and your partners for industrial IoT solutions.Siemens:Scaling its global business through smarter recruiting with Cloud Talent Solution.Siemens Healthineers moves more computing to the cloud to support value-based care development,August 6,2018.Samsung Samsungs head researcher wants humanAI interactions to be a multisensory experience,December 09,2020.The future of AI is on the edge.Samsung Research,Artificial Intelligence:In the future,AI technology will become much more prevalent and we will interact with smart devices on a daily basis.Munters How COVID-19 spurred one manufacturer to roll out remote field service in days,April 20,2020.References1 High Tech Cloud Imperative,Accenture,20212 Make the leap,take the lead,Accenture,20213 4 Keys to Cloud Continuum Success,Accenture,20214 4 Keys to Cloud Continuum Success,Accenture,2021Transforming High Tech through the Cloud Continuum31AuthorsAbout AccentureAbout Accenture High TechAccenture is a global professional services company with leading capabilities in digital,cloud and security.Combining unmatched experience and specialized skills across more than 40 industries,we offer Strategy and Consulting,Technology and Operations services and Accenture Song all powered by the worlds largest network of Advanced Technology and Intelligent Operations centers.Our 710,000 people deliver on the promise of technology and human ingenuity every day,serving clients in more than 120 countries.We embrace the power of change to create value and shared success for our clients,people,shareholders,partners and communities.Visit us at.Jason MitchellManaging Director High Tech,Cloud,GlobalShaan MahbubaniSenior Manager Strategy&Consulting,High TechAustin HoltManager Technology Strategy&AdvisoryThe Accenture High Tech industry practice is committed to building compelling customer and partner experiences,reinventing core operations and scaling new business models through the power of digital transformation.Within the High Tech Industry,we work across the semiconductor,enterprise technology,consumer technology,communications technology and medical equipment sectors.With our deep expertise,we help organizations navigate through constant change and technology disruptions to drive long-term growth and expansion.Our teams have a strong track record in maximizing new market opportunities in areas such as cloud,IoT,5G,AI and emerging technologies.Visit us at document refers to marks owned by third parties.All such third-party marks are the property of their respective owners.No sponsorship,endorsement or approval of this content by the owners of such marks is intended,expressed or implied.This content is provided for general information purposes and is not intended to be used in place of consultation with our professional advisors.Copyright 2022 Accenture.All rights reserved.Accenture and its logo are trademarks of Accenture.

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Uber Freight：自动驾驶卡车技术的未来（英文版）(19 sider).pdf

1A road map for evolving freight transportation with autonomous trucksThe future of self-driving technology in trucking2The future of self-driving technology in truckingContentsTrucking is primed for self-driving technologyThe hub-to-hub modelWhat about trucking jobs?Autonomous trucking will expand incrementallyConclusionThe Uber Freight teamEndnotesAfter a decade of development,self-driving technology is starting to hit the roadsIn 2021,self-driving vehicles traveled approximately 4 million miles in California alone,doubling the previous years record.1 The trucking industry is well positioned to reap the benefits of this technology,which will be enjoyed by truck drivers,carriers,shippers,and road users.The first,and most important,benefit is better road safety.In 2019,more than 5,000 lives were lost in large truck crashes,including 892 truck occupants.2 About one-third of these accidents occurred on interstates,freeways,and expressways.Vehicle-and environment-related factors accounted for only 13%of these crashes.The remaining 87%were caused by drivers performance/non-performance(21%),decisions(38%),and recognition(28%).3While the safety benefits are likely to be welcomed by all,some state that the effects this technology will have on the trucking industry as a whole,and on truck drivers in particular,are less fully understood.At Uber Freight,we envision a bright future for the trucking industry,one where truck drivers and self-driving trucks connect long-haul and local-haul routes,thus complementing each other on capabilities and preferences.We think this model will support the growth in truck freight demand,create safer roads,provide better truck-driving jobs,and make goods more affordable and available for everyone.In this paper,we demonstrate why trucking is the faster route to commercialize and scale self-driving technology.We then lay out the hub-to-hub model,which will allow autonomous trucks(ATs)to operate alongside those driven by people.This model achieves synergies that benefit carriers,drivers,and autonomous vehicle(AV)developers.We show that autonomous trucking will not be a dispensable service that simply aims at reducing the cost of trucking.Instead,it will become an essential component of supply chains that helps satisfy the growing demand while offering drivers better working conditions.Finally,we outline our predictions for how this technology will unfold over the coming years.3613151718193Trucking is primed for self-driving technologyA trillion-dollar market4Surface freight transportation in the US is a$1.06 trillion market.5 Trucking constitutes the largest share of this market,as it moves about 64%of the total US freight(by tonnage)and approximately 80%of the total inland freight.6 In 2021,for-hire trucking carriers made$384 billion in total revenue.7 Private trucking fleets constitute an equally large market,which brings the total trucking market size close to$800 billion.Globally,the total addressable market(TAM)of freight($4 trillion)is comparable to that of ridesharing and delivery(more than$5 trillion each).8 Autonomous trucking solves bigger pain pointsDespite growing demand,the trucking industry continues to bleed skilled labor as experienced drivers retire or choose other careers.The American Trucking Associations(ATA)estimates that the US needs to fill one million jobs cumulatively between 2020 and 2030.9 Approximately 80%of these are due to retirements,early exits,and drivers pushed out of the industry.The remaining 20%are needed to support growth in freight demand.The trucking industry has also struggled with attracting younger drivers to the workforce.Figure 1 shows how the truck-driver population in the US has been aging with time.Lifestyle issues,notably time away from home,are among the primary factors behind this trend.Potential truckers have to wait until they are 21 to get their interstate CDL license,10 the hours are long and grueling,and trucking keeps drivers away from home for up to 200 nights a year.11Figure 1.Aging population of truck drivers12 On the other hand,other sectors,such as construction,manufacturing,and warehousing,can offer blue-collar jobs under more favorable conditions.Over the past decade,parcel delivery employment has doubled and warehousing employment has almost tripled.13 In previous years,market dynamics alone were not enough to bring drivers back.On the demand side,shippers still prefer trucking to rail and rail trucking,called intermodal,as trucking offers superior benefits in terms of speed and reach.On the supply side,new carriers face various constraints such as tightening regulations and high capital costs.In addition,small fleets pay 10%more than large fleets(per mile)to operate their trucks.14 This makes it difficult for them to sustain themselves,except in tight markets like the one we saw in 2021.15Driver shortage and retention were among the top 10 issues facing the trucking industry for 10 years in a row.16 These arent the only pain points,however.The industry grapples with driver compensation,safety,and facility-delay issues.Self-driving technology will improve drivers lifestyle and spare them hours spent away from home.It will also address most of the other issues shown in Table 1.0 0 to 24years25 to 34years35 to 44years45 to 54years55 to 64years65 yearsand over19942003201320214Table 1.Trucking industry pain points and how autonomous trucking can help mitigate themTrucking industry pain pointsRankHow autonomous trucking can helpDriver shortage1Provide additional capacity where its most needed and offer a better lifestyle to truck drivers.Driver retention2Driver compensation3Increase drivers rate per mile using the hub-to-hub model(see the next section).Lawsuit abuse reform4Reduce the number of trucking accidents,87%of which are caused by human error,17 and,therefore,improve safety and lower insurance costs.Compliance,safety,accountability6Insurance cost/availability9Limited truck parking5Reduce the need for truck parking,because ATs will be exempted from hours of service constraints.Detention/delay at customer facilities7Eliminate detentions and unnecessary delays with drop-and-hook operations,described in the next section.Transportation infrastructure/congestion/funding8Route and schedule ATs to operate during off-peak hours,thereby decongesting roads.Diesel technician shortage10Accelerate the adoption of electric trucks,due to the lower cost of waiting to recharge.Uber Freight has been leveraging technology to address some of these issues.For example,the Uber Freight app provides carriers of all sizes with easy and convenient access to freight,allowing them to operate profitably in the marketplace.In addition,Ubers facility ratings have been helping shippers to improve their facilities by reducing detentions,layovers,and unnecessary delays,and Uber Freight has also laid the groundwork for seamless trailer handoffs between autonomous trucks and human drivers with Powerloop,a drop-and-hook trailer solution.Finally,Uber Freights Carrier Wallet solution and Freight Plus program offer faster payments,fuel discounts,and rewards to carriers.Autonomous trucks present an opportunity that complements these efforts by giving drivers a better lifestyle and more profitable loads(see the“What about trucking jobs?”section).Enthusiastic early adoptersThe commercialization of autonomous vehicles at scale requires customers acceptance and trust in this technology.According to a 2022 survey18 of Uber Freight and Transplaces biggest shippers,Figure 2.Autonomous trucking survey results collected from a sample of Uber Freight/Transplace shippers2411722051015202530ExtremelylikelySomewhatlikelyNeither likelynor unlikelySomewhatunlikelyExtremelyunlikelyNumber of responsesHow likely are you to consider an autonomous freight solution in the future?5the majority of shippers indicated that they are either extremely likely(52%)or somewhat likely(24%)to consider an autonomous freight solution in the future.While this survey(see Figure 2)was based on a small sample,it clearly shows that shippers are more likely to adopt autonomous technology compared with the general population.The path of least resistanceSelf-driving development is an incremental endeavor.SAE International(formerly known as the Society of Automotive Engineers)and the National Highway Traffic Safety Administration(NHTSA)recognize 6 levels of automation.19 At Levels 0,1,and 2,the driver must be engaged at all times.The vehicle supports the driver with basic features,such as automatic steering,acceleration,deceleration/braking,and cruise control.Levels 3 and 4 include additional features that allow the vehicle to drive under certain conditions.However,at Level 3,the driver must be ready to take over when the feature requests.Finally,at Level 5,the vehicle can drive under all conditions without any assistance.Level 5 is the automation north star.However,it is unattainable within the coming years.Current self-driving developers are focusing on Level 4,where the vehicle can drive under most conditions along specific corridors.Remote operators will handle the remaining edge cases,where human intervention is needed.Think of all the complexities that a self-driving vehicle needs to handle on an urban trip.First,urban streets are far from uniform.Lanes vary by width,speed limit,and geometry.Some streets have side parking,shoulders,or sidewalks while others do not.Roundabouts and intersections are even more complex,whether they are controlled by traffic lights or stop signs.And while some turns are protected,others are not.Furthermore,urban streets can be jammed with pedestrians,bicyclists,and smaller delivery vehicles.Because of this complexity,highway driving is a more tractable and well-defined problem for AT developers.The US interstate highways are much more uniform because they are regulated and maintained by a single agency:the Federal Highway Administration(FHWA).The FHWA imposes uniform standards covering controlled access,minimum and maximum speed limits,and lane geometry.For example,most interstate highways have a posted speed limit of 65-70 mph.This makes long-distance trucking a feasible first step toward autonomy.But dont autonomous trucks still need to navigate complex urban streets for the first and last mile?6The hub-to-hub modelFor the foreseeable future,most ATs will operate under a hub-to-hub model.Human drivers will handle the trip ends,which involve complex urban streets and many manual operations at facilities,such as loading,unloading,gate entrance,and documentation.ATs will service the middle part of the trip(see Figure 3).Under this model,a driver picks up a preloaded trailer from the shippers facility and delivers it to a transfer hub located close to the highway.We refer to this as the first mile.The trailer then gets hooked to an AT,which drives on the highway to another transfer hub located near the receivers facility.This step is referred to as the middle mile.At the second transfer hub,another driver picks up the trailer and delivers it to its final destination.This is the last mile.Figure 3.The hub-to-hub modelDropping and hooking trailers,which we refer to as drop-and-hook,can minimize cost,boost efficiency,and improve the drivers experience.While it is not strictly required at shippers and receivers facilities,it will save drivers time by eliminating the need to wait for loading and unloading,and therefore reduce the cost of the first and last miles.However,drop-and-hook is required at transfer hubs in order to maximize the uptime of ATs and improve asset utilization.Eventually,ATs will be able to provide a depot-to-depot service,including the first and last miles.While some carriers and AT developers might adopt this model earlier along specific routes and with specific shippers,scaling it is expected to take several years.ATs will need to not only drive through complex urban environments but also handle manual operations at facilities that will require human intervention for the foreseeable future.The hub-to-hub model will bridge the gapsThe hub-to-hub model allows AT developers and carriers to launch commercial operations earlier,before transitioning to a depot-to-depot service.At the same time,it adds capacity where its needed mostin long-distance truckingand provides a better lifestyle to truck drivers.This model is a stepping stone toward full autonomy.It allows AT developers to start generating revenues in their early years of operation.This will provide them with a revenue stream that can sustain the development of self-driving technology instead of relying exclusively on external investment,in order to expand their capabilities beyond highway driving.This approach also cuts mapping costs by 2 orders of magnitude.Self-driving vehicles need high-definition maps in order to determine their exact location with respect to the surrounding environment and plan their next move accordingly.The mapping process is time-7consuming and costly.With the hub-to-hub model,self-driving providers will only need to map the highway segments on which they operate.According to FHWA,the total length of the US interstate highway system is 46,876 miles,20 which is only about 1.2%of the US public roads,but carries a quarter of vehicle-miles.21 In contrast,mapping urban streets is more complicated because they have more features,and a single large city like Los Angeles can have 6,500 street miles,22 almost 14%of the entire US interstate system.Figure 4.Employment growth in various trucking sectors23 Finally,drop-and-hook operations at transfer hubs and shippers facilities will save drivers time and boost the systems efficiency.By The advantages of the hub-to-hub model are not limited to self-driving developers;they help drivers as well.As shown in Figure 4,truck drivers are becoming more inclined toward localrather than long-distancefreight.This has been attributed to various factors,including the evolving preferences of younger drivers who like to stay closer to home.The hub-to-hub model will allow drivers to only serve short hauls and return to their homes and families every night.9000000 12 2014 2016 2018 2020 2022Long-distance TLLTLLocalSpecializedeliminating the need for appointment windows,carriers will be able to maximize the uptime of ATs,an expensive asset that should keep moving rather than waiting at facilities to load and unload.The hub-to-hub model requires a hybrid network of human drivers and self-driving trucks.It also requires seamless drop-and-hook operations,in addition to reliable technologies for tracking,dispatching,and planning.Uber Freights Powerloop program gives carriers access to a pool of trailers that allow the hub-to-hub model to operate smoothly and efficiently.Economics of the hub-to-hub modelAutonomous trucks will cut freight costs substantially in the long term.Currently,carriers spend about 34%-44%of their total operating costs on driver wages and benefits.24 Therefore,different studies have estimated the savings to be between 30%and 45%of total operating costs.25To achieve this,ATs need to drive on urban streets and handle a lot of edge cases.For the coming years,however,ATs will operate under the hub-to-hub model,which will transform the cost structure by reducing some costs and adding others,as shown in Figure 5.Under this model,we can divide the cost of a trip into 3 components:the first-and last-mile costs,which are handled by a human driver,and the middle-mile cost,which is driven autonomously.The middle-mile cost includes:Truck operating costs such as fuel,tractor and trailer depreciation,maintenance,permits,insurance,and tolls Transfer hub acquisition,lease,and operating costs Autonomous technology costs,such as sensors,mapping,remote assistance,data transfer,and storageTruck operating costsThe American Transportation Research Institute(ATRI)provided a breakdown of trucking costs for different fleet sizes in 2020.26 These costs vary significantly across carriers.Large fleets incur lower costs(per 8Figure 5.Total operating costs of trucking under the hub-to-hub model29 Figure 6.Per-mile operating costs of trucking for large fleets in 2020(ATRI)and 2022(Uber Freight calculations based on ATRI)30 General trucking costsAT-specifc costsTransfer hub real estate or leaseRemote assistance,data transfer,and storageAdditional trailers for drop-and-hookFirst-and last-mile driver costMap generation and updatingTechnology and self-driving kitFuel/energyInsuranceMaintenance and repairTractor and trailer purchase or leasePermits and licensesUnchanged costsHub-to-hub costsCosts reduced by ATAT technology costs$0.18$0.25$0.25$0.09$0.10$0.09$0.09$0.11$0.11$0.09$0.10$0.10$0.28$0.57$0.51$0.58$0.65$0.00$0.50$1.00$1.50$2.002020(ATRI)2022(Uber estimate)AT middle-mile costsDriver wages and benefitsFuelTires/tolls/permitsRepair and maintenanceTruck insurance premiumsTruck/trailer lease orpurchase paymentsHub-to-hub costsThese costs are associated with the leasing,acquisition,and operation of transfer hubs.They are generally low compared with other cost mile)than smaller ones across all cost components.In our analysis,we consider the operating costs of large fleets to estimate a lower bound of the total cost per mile.These costs are shown in Figure 6.The operating costs of trucking have increased substantially between 2020 and 2022.For example,the price of diesel has doubled,27 and the price of labor has increased by about 10%.Therefore,we need to apply relevant inflation factors to these costs to estimate their 2022 counterparts.Yet as the technology matures,ATs will decrease some of the truck operating costs,such as fuel and insurance,due to optimized driving patterns and fewer accidents.28 Therefore,we estimate the operating cost of an AT at about$1.06 per mile,which is about 72 cents per mile cheaper than a human-driven ponents.For example,if a transfer hub costs$5,000 per month and handles 20 loads per day,and if the average length of haul is 500 miles,the resulting cost will be less than 2 cents per mile.If workers are required at the transfer hubs(for maintenance,security,etc.),they might increase this cost substantially.For example,having 2 workers at each facility available for 24 hours a day will result in a daily cost of about$1,920.31 This is where the utilization of transfer hubs becomes essential.If each transfer hub processes 20 loads per day,the cost will be as high as 19 cents per mile.However,if each transfer hub processes 100 loads per day,then the labor cost will be lower than 4 cents per mile.However,AT carriers will need access to additional trailers for drop-and-hook operations at transfer hubs.Ideally,3 trailers per tractor will be available:at the origin,at the destination,and in transit.32 If 2 additional trailers per tractor are needed,the added cost(including maintenance,insurance,etc.)can be as high as 26 cents per mile.33 9LaneDallas to HoustonDallas to PhoenixLength(miles)2411,068Linehaul price(2021 average)$793$1,798Linehaul price(opposite direction)$761$3,061Local-haul price(Dallas)*$417$417Local-haul price(Houston/Phoenix)*$334$328Table 2.Characteristics of the lanes used in the hub-to-hub example*The local prices usually assume live loading and unloading.We applied a$76 reduction to these figures in our assumptions.The above conclusion holds for the majority of lanes on the Uber Freight network.We have calculated the autonomous middle-mile break-even rate per mile for Uber Freights top lanes,at which the combined cost of the first-,middle-,and last-mile segments is equal to the linehaul cost with a human driver.The results,shown in Figure 8,indicate that:The feasibility of the hub-to-hub model improves with longer hauls More than 80%of these lanes have a break-even price exceeding$1 per mile,and about 40%of them have a break-even price exceeding$2 per mileTherefore,the additional cost per mile associated with the 2 trailers and the 2 transfer hubs(on both ends)is about 30 cents per mile.Self-driving technology costsThese include sensors,mapping,data storage and transfer,and remote operations.These costs are difficult to quantify,because they depend on the technology maturity and will generally decrease with time.The sum of operating,hub-to-hub,and technology costs constitute the total cost per mile of the autonomous middle mile.First-and last-mile driver costsThese are the largest cost components of the hub-to-hub model and will be discussed in more detail in the following section.The hub-to-hub model will also be profitableThe major cost component associated with the hub-to-hub model relates to the first and last miles.How will this impact the profitability of ATs operating between transfer hubs?There are different ways in which we can procure and price first and last miles.For simplicity,we analyze 2 models:local-haul pricing and hourly driver pricing.Our analysis is based on the break-even points:At what price point will the combined cost of the first,last,and middle miles be equal to the cost of a human driver34 serving the entire haul?Local-haul pricingThe simplest approach is to treat the first and last miles as 2 separate local hauls.For example,a load going from Dallas to Phoenix will be divided into 3 hauls:a local haul in Dallas,an autonomous haul from Dallas to Phoenix,and a local haul in Phoenix.The total price is the sum of the 3 individual linehaul costs.We exclude the cost of fuel from our analysis because it is usually passed to the shippers in the form of a fuel surcharge.This approach favors long hauls.To illustrate this,we consider the following example with 2 lanes:Dallas to Houston and Dallas to Phoenix,which are 241 and 1,068 miles long,respectively.On both lanes,the combined price of the first and last miles was approximately$600 in 2021,35 assuming a$76 reduction in price due to drop-and-hook,based on the hourly earnings of local truck drivers in 2021.36 On the Dallas-Houston lane,this is almost equal to the total linehaul cost from Dallas to Houston.To achieve break-even,ATs need to have a cost of$0.70 per mile.On the other hand,the Phoenix-Dallas lane is more profitable for AT carriers.Because it is a longer haul,the combined price of the first and last miles is a smaller fraction of the total linehaul price as shown in Figure 7.Autonomous trucks can achieve break-even,even when their cost is as high as$2 per mile.10Figure 7.Cost of the first and last mile(in gray)and the AT break-even revenue(in green)using the hub-to-hub model.We assume a$76 reduction in the cost of local hauls because of time savings resulting from drop-and-hook operations.Figure 8.AT break-even rate per mile(excluding fuel)as a function of linehaul distance$0$500$1,000$1,500$2,000$2,500$3,000$3,500DAL-HOU(AT)DAL-HOU(humandriver)HOU-DAL(AT)HOU-DAL(humandriver)DAL-PHX(AT)DAL-PHX(humandriver)PHX-DAL(AT)PHX-DAL(humandriver)Price First mileAT break-even priceLast mileTotal linehaul priceBased on our analysis in the“Economics of the hub-to-hub model”section,a total middle-mile cost of$1-$2(excluding fuel)can be achieved as the technology matures.The truck operating costs and the hub-to-hub costs constitute about$0.86/mile.In order to achieve a middle-mile cost of$1/mile,the AT technology costs should be$0.14/mile.However,even if these costs are as high as$1.14/mile in the early years of operation,the total cost of the middle mile will be about$2/mile.Under this model,the high cost of the first and last mile is partly due to the added friction at facilities.For example,drivers might not show up on time(or at all)to pick up a scheduled load,either at the shippers facility or at a transfer hub.Since each load is divided into 3 separate segments(the first,middle,and last miles),the probability of such events occurring is magnified.Some of these costs are implicitly included in the first-and last-mile prices shown in Table 2,which uses data from various loads,including those with driver delays and no-shows.Hourly driver pricingIn the second approach,drivers who are paid hourly are hired at each transfer hub in order to handle first-/last-mile transportation.Preferably,these drivers can drop and hook trailers at both the shippers facilities and the transfer hubs rather than waiting to load and unload.With this approach,the combined cost of the first and last miles will be almost cut in half compared with local-haul pricing.To demonstrate this,we provide the following example,which is representative of typical hub-to-hub operations.We assume that each transfer hub is located about 25 miles from the shippers facility.Trucks can travel at a speed of 25 mph between the transfer hubs and the facilities.At these facilities,as well as at the transfer hubs,drivers are able to drop and hook trailers,and each drop-and-hook operation takes about 15 minutes.-$2-$1$0$1$2$3$402505007501,0001,2501,500Break-even cost per mile($/mi)Length of haul(miles)Break-even cost per mile$1/miFeasible at$1/miFeasible at$2/mi11In that example,about 5 hours are needed per load:4 hours of driving and one hour for all 4 drop-and-hook operations as shown in Figure 9.Using the average hourly earnings rate for local freight drivers37 and a 20%overhead cost,the total labor cost required at both ends is approximately$156.Labor cost is approximately 45%of the total operational cost of trucking.38 Therefore,the total cost of the first and last miles will be around$345 per load,approximately half the cost of 2 local hauls.The above analysis assumes that trucks are traveling empty to the source facility and from the destination facility.However,if enough loads are available in both directions,drivers can return with a backhaul.That way,the time required per load for the same example above can be cut to 3 hours.Figure 9.Example of a journey of a load and expected time at each stepUnfortunately,in the near term,not all facilities can support drop-and-hook.Instead,drivers might have to wait for live loading and unloading at these facilities.If we assume the average loading and unloading time to be 2 hours,the total time required per shipment will be about 8.5 hours.This translates to a total first-/last-mile cost of$455,still substantially cheaper than local-haul pricing.How much freight can be moved with the hub-to-hub model?In the previous section,we showed that the hub-to-hub model will be economically feasible on many lanes if AT developers can achieve a middle-mile cost between$1 and$2 per mile.In this section,we quantify the size of the opportunity associated with this model.Instead of limiting our analysis to a single number,we provide a range,which depends on the level of maturity of the technology.Combination trucks39 travel more than 177 billion miles annually in the US.40 These include both loaded and empty miles for long-distance and local freight.We estimate that long-distance freight accounts for 135 billion miles per year.These are mostly distributed along the US interstate corridors as shown in Figure 10.FACILITYFACILITYTRANSFER HUBTRANSFER HUBDriver heads to facility(1 hr)Hooks loaded trailer(15 min)Drives back from facility(1 hr)Drives to destination(1 hr)Drops trailer to AT(15 min)Driver picks trailer from AT(15 min)Autonomous truck handles middle mileDrops trailer at facility(15 min)Drives back to hub(1 hr)Figure 10.Mapping 2022 US truck shipments on the US interstate network using data from the Freight Analysis Framework41 54619237812The future of self-driving technology in truckingDue to technological limitations,early operations will focus on dry van trailers.In addition,these trailers are more convenient for drop-and-hook operations.Long-distance dry van freight amounts to 46 billion miles per year in the US.And using Uber Freights data,we find that 98%of these miles are driven on the highways,with a speed limit of 50 mph and above.Even if ATs were to operate on interstate highways only,they would still be able to capture a sizable fraction of miles traveled.This is because most of the lanes can be rerouted on the interstate system with a small increase in distance traveled.For example,54%of the lanes can be rerouted within 10%of the optimal distance,and 45n be rerouted with 5%.Route deviations will likely be tolerated by AT carriers,because ATs can achieve lower operating costs and be exempted from hours-of-service(HOS)limitations.Finally,by applying the above assumptions on the economic feasibility of different lanes(shown in Figure 8),we can quantify the total addressable market of ATs as shown in Figure 11.42 Figure 11.Total addressable market of autonomous trucking under the hub-to-hub model43 Combination trucks(tractor-trailer):177B-301B milesLong-distance freight:135B-230B milesDry van miles:46B-78B milesInterstate:25B-43B milesFeasible at CPM$1/mi:22B-37B milesFeasible at CPM$2/mi:11B-19B milesNon-interstate hwy:20B-34B milesFeasible at CPM$1/mi:17B-30B milesFeasible at CPM$2/mi:9B-15B milesSingle unit trucks:125B-213B miles13What about trucking jobs?There are more than 3.5 million truck drivers in the US.44 While many studies warn of automations dire effects on the labor force,they usually rely on unrealistic assumptions.The majority of these studies assume a rapid transition to autonomous vehicles,both in terms of technology development and market penetration.However,this is unlikely to occur given the high cost and technological challenges that will be overcome incrementally.In addition,the trucking industry is large and fragmented,which means that disruptions of this scale will need time to propagate.For example,even cheaper technologies,such as basic safety features,took years to scale.In the following sections,we discuss the positive effects self-driving technology will have on the trucking industry,and particularly on drivers.Autonomous trucks will fill gaps in the labor forceThe freight industry will continue to grow over the coming decades.According to the Freight Analysis Framework(FAF),trucks are expected to move 19 trillion tons of freight annually by 2050.This represents a compound annual growth rate of 1.5%per year.Similarly,trucking employment has been growing at a rate of 1.5%per year over the past decade.45 Assuming this growth persists,both trucking employment and trucking tonnage are expected to grow by more than 50%by 2050.While total trucking employment is expected to grow on par with the total trucking ton-miles,looking at the long-distance truckload sector paints a different picture.46 Over the past decade,employment in this sector has only grown by 0.95%annually.This means that at a similar rate,long-distance truckload employment in 2050 would be only 30ove its current level.This creates a mismatch between supply and demand.As shown in Figure 12,while long-distance truckload miles are expected to grow by 69%by 2050,employment in this sector will only grow by 30%.We estimate that at least 69,000 additional drivers will be needed to cover 7 billion dry van miles by 2035,and 180,000 drivers will be needed by 2050 to cover 18 billion miles.These figures are of the same order of magnitude as the total addressable market of the hub-to-hub model estimated in the“How much freight can be moved with the hub-to-hub model?”section.Figure 12.Expected growth in US dry van long-distance freight mileage and trucking employment50 using a similar growth rate as in the past decade 4546515971801020304050607080010020030040050060070080020172022(Forecast)2035(Forecast)2050(Forecast)Long-distance TL miles(billions)Long-distance TL employment(000s)Miles covered by available drivers(billions)AT opportunity(billions of miles)Projected driver shortage(000s)Long-distance TL employment(000s)This mismatch will be exacerbated by the looming cliff of hundreds of thousands of truck driver retirements over the next decade.This will have adverse effects on supply chains in the US and globally.For example,in 2021,long-distance truckload employment dropped 14Autonomous trucks will provide better jobs for truck driversNew technologies have not reduced overall employment in the past.However,they have changed the nature of these jobs and the tasks performed.For example,the introduction of automated teller machines(ATMs)has had positive effects on bank teller jobs.51 While the number of employees per branch dropped,efficiency gains caused the number of branches to increase.As a result,more tellers were needed to work in customer support.Self-driving technology will also transform the nature of trucking without necessarily reducing the overall employment in this sector.By tackling the long-haul middle mile,self-driving trucks will enable drivers to shift toward local hauls.This will boost demand for skilled drivers in the local freight sector,which is the most preferred among truckers as shown in Figure 4.It will also allow drivers to have a say in where and how they work and allow them to stay closer to their homes and families.On the other hand,drivers who prefer long-haul trucking will still be able to serve loads that cannot be addressed by ATs,due to technological limitations,regulatory constraints,or adverse weather.In addition,ATs will create new jobs.Since Level 5 automation is still years away,skilled drivers will provide remote assistance to handle AT disengagements and edge cases.Employees will also be hired to develop,maintain,and operate transfer hubs and self-driving trucks.Finally,ATs will accelerate the widespread adoption of drop-and-hook,which will spare drivers many unpleasant experiences,including waiting at facilities to load and unload,detentions,and layovers.Since the majority of company drivers are paid by the mile,52 they are not being paid while they rest or wait at facilities.Therefore,facilities do not have a strong incentive to improve service for drivers.Even drop-live loads will allow drivers to better plan their time;if an appointment is not ideal,they could run other loads instead of waiting at the facility to unload.by 5%,while freight demand has increased by only 2.4%compared with their pre-pandemic levels.47 This has led to the tightest truckload market in recent history.Dry van spot rates increased by more than 70%year-over-year in May 2021.The effects of a driver shortage will not be limited to the freight and logistics industry but can extend to the broader economy.In 2021,the“sustained breakdown of supply chains”was deemed by economists as one of the top factors contributing to long-term high inflation.48 Supply chain issues were also the leading constraints hindering manufacturing growth in 2021.49 These issues resulted in inventory shortages,order cuts,and higher prices.Finally,end consumers also felt these shortages,as retailers were struggling to fill their empty shelves throughout the year.Therefore,autonomous trucking will not simply replace trucking jobs but rather fill gaps in employment in order to keep our supply chains moving.15Autonomous trucking will expand incrementallyEarly expansion:navigating the maze of regulations and weatherA patchwork of state lawsThe US DOT has adopted a hands-off approach with respect to regulating autonomous vehicles.As a result,testing and deployment are regulated by a state-centric patchwork of laws.As of 2021,40 states in addition to Washington,DC,have either passed autonomous vehicle legislation or are operating under executive orders.53This fragmentation has led self-driving developers to favor some states over others for their testing and development efforts.As an example,state law in Texas allows an automated motor vehicle to operate regardless of whether a human operator is present in the vehicle,as long as certain requirements are met.Similarly,Arizona has adopted a permissive approach where automakers need only to notify the Arizona DOT before testing,as long as their vehicles comply with state and federal laws governing motor vehicles.Other states such as California adopted a more hands-on approach,by developing a comprehensive framework to regulate testing and operations.In 2016,Arizona,California,New Mexico,and Texas established the I-10 Corridor Coalition,54 to help provide a streamlined,end-to-end,and connected vehicle experience,and enable better freight and passenger movement along the corridor in a connected vehicle environment.WeatherA fully autonomous truck in the future would need to handle a wide range of weather conditions,ranging from light to heavy rain,to snow,fog,and freezing temperatures.However,in the short term,weather-related constraints will play a major role in shaping expansion strategies.Weather conditions vary widely by state,as shown in Figure 13.Deployment in many northern states is infeasible in the short term because of freezing temperatures and snow.Precipitation also renders southeastern states inconvenient.This leaves us with states in the West and Southwest that have consistently high temperatures and low precipitation,particularly Arizona,California,New Mexico,and Texas.Fortunately,these states happen to be the same regulation-friendly states working on the I-10 Corridor Coalition.Figure 13.Average temperature and precipitation in the US55 Over the coming years,autonomous trucking will expand gradually throughout the US interstate system.In the short term,weather,regulations,and autonomy capabilities will dictate the lanes on which ATs will operate.In the long term,commercial opportunities and technological developments will drive expansion strategies.Short-term opportunity:Show me the moneyIn the initial stages of commercial deployment,AT developers will need to prove that their technologies are safe,feasible,and capable of generating favorable unit economics.This stage might involve busy lanes with convenient weather and friendly regulations.The Dallas-Houston lane,on which Waymo and Aurora have both chosen to operate their pilots,checks all the boxes.In 2022,we estimate that this corridor will handle 0.36 billion to 0.66 billion miles of dry van freight.56 Other potential lanes include:The remaining legs of the Texas Triangle:DallasSan Antonio,and HoustonSan Antonio,which combined with the Dallas-Houston lane handle 1.13 billion to 2.06 billion miles of dry van freight Los AngelesPhoenix,with about 0.34 billion to 0.61 billion miles of dry van freight Los AngelesSan Francisco(regulation permitting),with about 0.66 billion to 1.20 billion miles of dry van freight16Figure 14.Mapping of Uber Freights loads in 2021(excluding Transplace)on the US interstate network:shipment movements span the entirety of the interstate network,with heavy presence in corridors that are strong candidates for early deploymentstrategy.For example,if a carrier were to expand AT operations to a new corridor,they would need to consider how much additional volume could be unlocked on the carriers extended network,how many empty miles their trucks would drive,and what the total return on investment of expanding on that particular corridor would be.In Table 3,we analyze some of the key routes that carry long-term potential for ATs,based on data from the Freight Analysis Framework that we loaded on the US interstate network.CorridorsOpportunitiesI-10/I-20 extending from Dallas to Los Angeles/Houston to Los Angeles through El Paso and Phoenix Check all the boxes for regulations,weather,and short-term and long-term opportunities A total addressable market of 160 billion ton-miles of freight as of 2022,which is more than 8%of the total US interstate ton-miles(based on our network model shown in Figure 10)I-5 starting with the LASan Francisco lane,and extending north toward Portland and Seattle in the future The busiest North-South corridor on the West Coast,and it connects to I-10 at Los Angeles Carries approximately 86 billion ton-miles annually,which is 4.5%of the total US interstate ton-milesI-40,connecting the 2 coasts through the south-central portion of the United States Falls on the optimal path connecting Los Angeles,the major import hub in the US,to key freight clusters such as Atlanta,Chicago,Indianapolis,Memphis,Nashville,and St.LouisI-35 and I-45 connecting the Texas Triangle to Oklahoma City Give access to the busy I-40 and I-44 corridors,connecting Los Angeles to the Midwest and NortheastI-95 extending from Mi-ami to the Northeast Serves the most populated cities along the East CoastI-75/I-65 extending from South Florida to Chicago Pass through major freight markets such as Atlanta,Nashville,Louisville,and IndianapolisTable 3.Freight corridors with the biggest long-term opportunities for commercial expansionTexas and California are Uber Freights earliest and most mature markets.In 2021,Uber Freight alone(excluding Transplace)had more than 17 million truck-miles traveled between Austin,Dallas,Houston,and San Antonio,and 41,000 loads going exclusively between these markets.In addition,Uber Freight had about 20 million truck-miles traversing the I-5 corridor between Fresno,Los Angeles,and San Francisco,and 45,000 loads between these markets.This gives Uber Freight a strategic advantage to be the platform of choice for early deployment and commercialization.Long-term opportunity:See the forest and the treesAs the technology matures and the costs decrease,self-driving developers and carriers will start shifting their focus toward long-term commercial opportunities.At this stage,long-haul lanes will be preferred,as discussed in“The hub-to-hub model will also be profitable.”At this stage,self-driving developers and carriers will need to consider how each lane fits into their network and long-term expansion 17ConclusionThe future of trucking will consist of a hybrid model whereby drivers and ATs share the roads and keep America moving.ATs will fill gaps in trucking supply and complement the role of truck drivers rather than competing with them.Uber Freight,being the preferred network for carriers in the US,is uniquely positioned to be also the preferred network for ATs.First,Uber Freight has developed key partnerships with leading technology players in the AT industry.In addition,we have developed all the necessary capabilities and tools to be the best AT network for both shippers and carriers.Uber Freight can introduce ATs as a new mode into a shippers network seamlessly and efficiently.Deep trust with shippers:With its acquisition of Transplace,Uber Freight is the trusted partner for shippers and their network of choice.We can partner with shippers to deploy ATs more strategically and help them achieve their profitability,sustainability,and network resiliency goals.Key,strategic partnerships with autonomous trucking technology developers:Uber Freight has executed a long-term,strategic partnership with Waymo to secure billions of autonomous miles to serve its customers on its network as well as a deep technical integration across platforms to further the mode of autonomous transportation for its shippers.Additionally,Uber Freight is currently running a multiphase pilot program with Aurora where Uber Freight is also learning how to integrate the Aurora Driver into its digital freight network.Richest freight data:Uber Freight has a rich database covering$17 billion of freight under management.This data can help Uber Freight and shippers deploy this technology in an optimized manner,by informing decisions on where,when,and how shippers can accommodate ATs in their networks.Largest carrier base:The hub-to-hub model requires both technology and skilled drivers to handle the first and last miles.Uber Freight,combined with Transplace,provides access to the largest carrier base in the US,with over 130,000 active carriers.Therefore,Uber Freight can seamlessly handle the entire journey of a load,from the first mile to the last mile.In addition,Uber Freights carriers will provide the required backup whenever an AT cannot service a load for any reason,including due to adverse weather conditions or unforeseen downtime.Drop-and-hook capability:Uber Freights drop trailer pool system,Powerloop,helps carriers and shippers of any size tap into the efficiencies of drop-and-hook loads.Powerloop is crucial for the hub-to-hub model,as it has the potential to reduce dwell time by 30%and keep ATs highly utilized.On the other hand,Uber Freight can help carriers of all types benefit from this technology.Largest demand base:Uber Freight provides carriers with access to$17 billion of freight under management.This covers the entire US interstate network as shown in Figure 14.The scale of Uber Freights network makes it a top choice for self-driving developers and carriers who want to expand their networks and grow their business successfully.The future of self-driving technology in truckingThe Uber Freight teamAuthorContributors Mazen DanafSenior Economist and Applied Scientist Mazens work focuses on analyzing the freight transportation landscape,and producing long-term forecasts based on supply and demand dynamics.He is also a research affiliate with the Intelligent Transportation Systems(ITS)Lab at MIT,where he completed his PhD in 2019.His research falls at the intersection of smart mobility,economic modeling,and machine learning.Laurent HautefeuilleHead of Business Development and Strategy&PlanningBar IfrachSenior Director,Head of Marketplace,Applied Science,and Data ScienceOlivia HuSenior Business Development ManagerMike PlaceProduct Manager Integration with autonomous trucking technology developers:In partnership with major AT players,carriers on the Uber Freight network will also have increased access to ATs,and higher efficiency through the seamless experience across one integrated platform between Uber Freight and its AT tech partners.Pioneering customers:Uber Freights large customer base includes shippers ranging from small and midsize businesses to large enterprises.Many of these customers are all early adopters of new technologies and supply chain innovations.Unmatched technology:Uber Freight has already been leveraging state-of-the-art technology to provide carriers with easy and convenient access to freight,support them financially,and improve their experiences at facilities.In the future,Uber Freight imagines a world where smart scheduling,combined with the efficiencies of transfer hubs,will enable short-haul drivers to move a higher volume of freight within their working hours than they can today.In addition,by providing the right load at the right time,and guaranteeing predictability and consistent demand,we can help AT carriers maximize their AT asset utilization and return on investment.At Uber Freight,we want to deploy data and algorithms to do the right thingby deploying autonomous trucks in a way that is beneficial to shippers,self-driving developers,carriers,and their truck drivers.181912021 Disengagement Reports,California Department of Motor Vehicles.2“2021 Pocket Guide to Large Truck and Bus Statistics,”Federal Motor Carrier Safety Administration(FMCSA),December 2021.According to FMCSA,“FARS and GES/CRSS define a large truck as a truck with a gross vehicle weight rating(GVWR)greater than 10,000 pounds.”This includes Classes 3 through 8.3“The Large Truck Crash Causation Study-Analysis Brief,”FMCSA,July 2007.4All monetary figures in this paper are in US dollars.5“Freight Forecast:US Rate and Volume Outlook,”ACT Research,June 2022.6“Freight Analysis Framework Version 5,”National Transportation Research Center,last modified April 26,2022.7These are the revenues subject to federal income tax by general and specialized freight carriers.8“Investor Day,”Uber,February 10,2022,slide 169.9“Driver Shortage Update 2021,”American Trucking Associations,October 25,2021.10“Owner-operator and professional employee driving facts,”OOIDA Research.11Employment Situation Summary,US Bureau of Labor Statistics:Couriers and Messengers(NAICS 492)and Warehousing and Storage(NAICS 493).12In 2021,FMCSA established the Safe Driver Apprenticeship Pilot Program(SDAP)to help people aged 18,19,and 20 check out interstate trucking careers.13“Analysis of truck driver age demographics across two decades,”American Transportation Research Institute(ATRI),December 2014;“Labor Force Statistics from the Current Population Survey,”Bureau of Labor Statistics,last modified January 20,2022.14“Critical issues in the trucking industry 2021,”ATRI,October 2021.ATRI defines small carriers as 100 or fewer power units,and large carriers as more than 100 power units.15“Trucking Market Update,”FTR State of Freight,March 7,2022.More than 165,000 new carriers emerged between June 2020 and February 2022.16“Critical issues in the trucking industry-2021,”ATRI,October 2021.17“The Large Truck Crash Causation Study,”FMCSA,July 2007.18“How do shippers feel about autonomous trucks?”Uber Freight,July 2022.19“SAE J3016 levels of driving automationTM,”SAE International,2021.20“Interstate Frequently Asked Questions,”FHWA,updated April 27,2021.21According to FHWA.In its S-1 filing,TuSimple indicated that it plans to map 250 miles per week.At this pace,the whole interstate system will be mapped in less than 4 years.TuSimple has so far mapped 11,200 miles but then decided to slow mapping,especially in areas where it does not operate.22“Los Angeles notorious traffic problem explained in graphics,”CNN,February 27,2018.23Truck transportation employment,production and nonsupervisory roles.US Bureau of Transportation Statistics.24“An Analysis of the Operational Costs of Trucking:2021 Update,”ATRI,November 2021.25“Distraction or disruption?Autonomous trucks gain ground in US logistics,”McKinsey&Company,December 10,2018.26“An Analysis of the Operational Costs of Trucking:2021 Update,”ATRI,November 2021.27“Gasoline and Diesel Fuel Update,”US Energy Information Administration.28We assume that ATs will reduce the insurance and fuel costs by 10%compared with human-driven trucks,based on the findings of a study by UCSD and TuSimple.29Self-driving might also reduce the capital costs and maintenance costs due to more efficient driving and better asset utilization.Note that AT carriers might not incur all of these costs.30“An Analysis of the Operational Costs of Trucking:2021 Update,”ATRI.AT middle-mile costs in this figure exclude the hub-to-hub and AT technology costs,which are discussed in the following section.31Using data from the Bureau of Labor Statistics:Average hourly earnings of production and nonsupervisory employees in warehousing and storage in 2021.32According to ATRI,US fleets have about 2.9 trailers for each tractor,which is about right for drop-and-hook if used properly.33Assuming an average trailer price of$45,000,and maintenance/insurance costs in line with the ATRI data relative to the capital cost.34We use the price paid to the carrier instead of the carriers operating cost in our analysis.35DAT RateView 2021 averages for dry van.36“Average hourly earnings of production and nonsupervisory employees,general freight trucking,local,seasonally adjusted,”US Bureau of Labor Statistics.37“Average hourly earnings of production and nonsupervisory employees,general freight trucking,local,seasonally adjusted,”US Bureau of Labor Statistics.38“An Analysis of the Operational Costs of Trucking:2021 Update,”ATRI,November 2021.39Combination trucks are those with a tractor and one or more trailers.40“US Vehicle-Miles,”Bureau of Transportation Statistics.41Note that this is slightly different from the figure published by FHWA:in order to quantify the addressable market for ATs under the hub-to-hub model,we assign all freight volumes to the interstate network only and exclude other highways and streets.42Our analysis does not account for weather and regulatory constraints,which may differ across AV developers and states and may reduce the addressable market further.43Total mileage for combination and single trucks:“US Vehicle-Miles,”Bureau of Transportation Statistics.Long-distance and dry van miles are estimated using FAF data.Interstate miles include all lanes that can be routed on the interstate system within 10%of the optimal distance.The ranges in each cell represent the current freight mileage and the projected mileage by 2050,assuming about 70%growth(FAF,Uber Freight analysis).44“Number of Truckers at All-Time High,”US Census,June 6,2019.45Truck transportation employment,production and nonsupervisory roles.US Bureau of Labor Statistics.46Total trucking employment is obtained from the NAICS 484 series.Long-distance truckload employment is a subset of total trucking employment,US Bureau of Labor Statistics(NAICS 484121).47According to total loadings above 100 miles from FTR Transportation Intelligence,Trucking Database.48“SIFMA Research:2021 End-Year US Economic Survey,”SIFMA Economic Advisory Roundtable,December 2021.49Institute for Supply Management,various reports.50This excludes company/dedicated fleet drivers;however,data from the commodity flow survey shows that these constitute a small fraction of long-haul trips.FAF5 and Uber Freight analysis.51“Learning by Doing:The Real Connection Between Innovation,Wages,and Wealth,”James Bessen,January 2015.52“Owner-operators/independent contractors in the supply chain,”ATRI,December 2021.53“Global Guide to Autonomous Vehicles 2021,”Dentons,January 28,2021.54“I-10 Corridor Coalition:A Connected Corridor of Opportunity,”Arizona Department of Transportation.55“New maps of annual average temperature and precipitation from the US Climate Normals,”Climate.gov.,October 11,2021.56The lower bound of the range assumes interstate only,while the upper bound assumes interstate and other highways.This includes all freight moving between Dallas and Houston,even if its origin and destination are not Dallas or Houston.Endnotes

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