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2. Towards A Sustainable Electricity Sector for Israel


This chapter discusses electricity-related policies for Israel to accelerate climate mitigation and deliver on broader well-being goals. The chapter first compares natural gas with renewable energy sources. It concludes that a larger focus on renewables avoids the risk of jeopardising deep decarbonisation in the long term while contributing to broader well-being goals, including better public health, jobs and economic development. Second, the chapter sets out a number of policies and recommendations to accelerate renewables uptake: pricing carbon and other externalities; supporting utility-scale renewables and distributed generation; enhancing power system flexibility to integrate renewables; improving energy efficiency.

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In Brief
Key findings and recommendations for Israel’s electricity sector

Prioritise renewable energy over fossil fuel generation

  • Natural gas can reduce GHG emissions in the near term, but risks jeopardising deep decarbonisation and broader well-being goals in the long term. Natural gas power plants are cleaner than coal, but have a number of other issues, including the emission of GHGs (including fugitive emissions), NOx and other air pollutants along the gas supply chain.

  • Electricity from solar photovoltaic (PV) on a Levelised Cost of Electricity (LCOE) basis is cheaper than that from gas and delivers multiple other benefits, including improvements in public health, rural development, creation of high-tech jobs and export opportunities related to smart grid technologies.

  • Natural gas resources can be used in some industrial sectors or for export to countries with fewer renewable resources.

Align the energy tax system with the social costs and address energy poverty

  • Price fossil fuels according to the external costs, including greenhouse gases and air pollution

  • Measure and monitor fugitive emissions in the gas supply chain to allow these to be priced.

  • Adjust the (residential) electricity price to reflect all costs (social costs of generation and network costs) to improve incentives for energy efficiency and rooftop solar PV deployment.

  • Address the impacts of energy price reform on energy-poor households and energy-intensive firms, for example through targeted income transfers or dedicated programmes to deploy rooftop solar PV (e.g. on social housing units) and enhance energy efficiency.

Scale-up renewable electricity deployment

  • Support distributed solar PV cost-effectively (e.g. through tenders and incentives for self-consumption of solar generation).

  • Remove administrative barriers (e.g. streamlining the permit procedure) and integrate other well-being objectives (e.g. development of industrial clusters) into competitive tenders for utility-scale solar PV.

  • Foster integrated long-term planning of the power system to identify appropriate sites for solar PV and investment needs in the transmission network.

Improve power system flexibility to support grid integration of renewables

  • Create electricity markets to improve operational efficiency and to enable business models for providing power system flexibility (storage and demand response).

  • Reinitiate voluntary dynamic or time-of-use pricing in the residential sector to tap the potential of demand response, e.g. from air conditioners, refrigerators or heat pumps.

  • Modulate remuneration of solar PV to incentivise renewable energy developers to provide electricity at times when it is most valuable, e.g. by investing in on-site storage.

Improve energy efficiency

  • Promote electrification and map electrification pathways to estimate power infrastructure needs (generation as well as network assets).

  • Implement and strengthen minimum energy performance standards, energy labels and market-based instruments, including obligations for the Israel Electric Corporation (IEC).

  • Strengthen energy efficiency policies targeted to energy-poor households (e.g. to replace old and inefficient appliances).

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2.1. Introduction

The electricity sector is the largest source of greenhouse gas (GHG) emissions in Israel, accounting for almost 50% of total GHG emissions in 2016 (OECD, 2019[1]). Between 2010 and 2016, GHG emissions from electricity generation declined by 3.5%, as a result of the ongoing fuel switch from coal to natural gas. Yet, in 2017, Israel’s electricity-related carbon intensity amounted to 560g/kWh (EcoTraders, 2019[2]), one of the highest values among OECD countries (IEA, 2018[3]).

In the near term, natural gas will continue to play an important role in phasing out coal, reducing GHG emissions while bringing important immediate benefits in terms of improved public health through lower levels of air pollution, notably sulphur oxides (SOx) and particulate matter (PM) (IPCC, 2014[4]). However, predominantly relying on natural gas for the longer-term, in the absence of options for capturing and storing or using carbon dioxide (CO2) emissions, will jeopardise deep decarbonisation in line with international commitments. Natural gas power plants, even when equipped with carbon capture, utilisation and storage (CCUS), will still emit some GHG emissions, including fugitive emissions from the gas supply chain (IPCC, 2014[4]). Gas power plants are a major contributor to nitrous oxides (NOx) emissions with adverse health and biodiversity effects (OECD, 2018[5]), while gas extraction is responsible for a number of substances that are known to be carcinogenic (IEA, 2016[6]). Electricity from gas is already more expensive than that from utility-scale solar photovoltaic (PV) (Ministry of Energy, 2019[7]) and the cost difference is expected to widen, posing long-term economic risks to investments in gas. All this calls for a greater focus on renewables, notably solar energy.

The objective of this chapter is twofold. First, it takes a holistic view of Israel’s electricity sector, drawing on the OECD’s well-being framework applied to climate mitigation (OECD, 2019[8]). Looking at the sector in a holistic way reveals many synergies and trade-offs between transitioning to a low-carbon electricity sector and broader societal goals, including improved public health through lower levels of air pollution, the creation of jobs and the development of economically less developed areas. Exploiting these synergies can importantly accelerate climate action in Israel’s electricity sector.

Second, this chapter provides concrete good-practice policy examples that Israel can draw on in its planning for the next 5 to 10 years to enable a transition towards a sustainable electricity sector with high shares of solar energy. Besides discussing the effectiveness of the policies proposed, the chapter provides, where applicable, evidence of their effect on broader well-being dimensions, including health, affordability and equity. This chapter discusses three building blocks for decarbonising the electricity sector: i) pricing carbon and other externalities; ii) supporting solar PV (both utility-scale and distributed) and facilitating integration; iii) improving energy efficiency.

There are three major challenges for Israel in decarbonising the electricity sector while delivering other well-being benefits. First, despite improvements in energy efficiency, electricity demand is expected to grow by 2.1% per year to 2030 (Electricity Authority, 2018[9]). Growth in electricity demand is primarily due to population growth, increased electrification of end-uses (e.g. electric vehicles in transport) and further need for desalination from increased water stress linked to climate change (Electricity Authority, 2018[9]). Electrifying end-uses increases energy efficiency and is a major strategy to decarbonise some end-uses that are hard to abate otherwise (IEA, 2018[10]). Second, due to its geopolitical situation, Israel is an energy island without electricity interconnection to neighbouring countries. Third, despite having excellent solar resources, land availability next to major consumption centres is a barrier to scaling up low-cost utility-scale solar PV (Vardimon, 2011[11]).

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2.2. State of play and Israel’s electricity sector through a well-being lens

Using electricity is fundamental for well-being as it supports a wide range of basic services as well as economic infrastructure and activities. Electricity consumption has been rising at an annual rate of 2.5% from 54.6 terawatt hours (TWh) in 2000 to 69.6 TWh in 2018 (Electricity Authority, 2018[9]). In 2016, the residential sector accounted for 29%, the commercial and public sector for 28%, the industry sector for 25%, water desalination for 5% and other uses for the remainder (Ministry of Environmental Protection, 2018[12]). Israel aims to reduce electricity consumption by 17% by 2030, relative to Business as Usual (BAU), amounting to an absolute target of 80 TWh in 2030 (EcoTraders, 2019[2]).

Electricity generation, however, is not only the major contributor to GHG emissions, it also accounted for 85% and 58% of SOx and NOx emissions respectively in 2016 (OECD, 2018[13]) with serious impacts on public health and ecosystems. The power sector is the main source of some important air pollutants, accounting, e.g. for 34% and 40% of PM2.5 and PM10 emissions in the Haifa region (Ministry of Environmental Protection, 2019[14]). Air pollution is associated with adverse health effects, causing almost 2,500 premature deaths per year in Israel (Ministry of Health, 2017[15]). Vulnerable population groups, including children, pregnant women and the elderly are affected most, even at low concentrations. Pollution is also detrimental to Israeli students' performance and subsequent labour market outcomes (Lavy, Ebenstein and Roth, 2014[16]), reducing labour productivity (e.g. due to increased sickness absences) and lowering economic output (Dechezleprêtre, Rivers and Stadler, 2019[17]).

Israel has been increasingly switching power supply from coal to gas and this trend is expected to continue. In 2018, coal accounted for 30% of total power generation, half the share of 2010 (Electricity Authority, 2018[9]). The share of natural gas has increased from 39% in 2010 to 66% in 2018, primarily driven by the availability of domestic natural gas discovered off the coast of Israel. Since 2016, the Ministry of Energy implemented an environmental load order, meaning that coal plants are mandated to operate at the minimum load possible and are increasingly used as back-up to maintain reliability and provide flexibility (EcoTraders, 2019[2]). The Minister of Energy announced his intention to phase out coal completely by 2025, but a final government decision is still pending (EcoTraders, 2019[2]). Israel joined the Power Past Coal Alliance end of 2018 (Ministry of Energy, 2018[18]). In December 2019, the Energy Minister Yuval Steinitz announced that the coal phase out could be as early as 2025.

The switch from coal to gas has reduced CO2 emissions somewhat and air pollutants substantially while contributing to energy security. According to OECD data, between 2010 and 2016, electricity related CO2 emissions have decreased from 42.3 MtCO2e to 40.2 MtCO2e whereas NOx and SOx emissions attributable to the electricity sector decreased by 38 and 33% respectively (OECD, 2019[1]).1 The transition from coal to gas also reduced the SOx and PM2.5 concentrations in major population centres, including Haifa, Tel Aviv and Ashdod with statistically significant reductions in cardiovascular events (-13.3%) and in total mortality (-19%) (Ministry of Health, 2017[15]).

Royalties from gas extraction has increased government revenues and may feed into a sovereign wealth fund to share the wealth with future generations. Royalty revenue amounted to NIS 542 million in 2013, but is expected to rise to NIS 2.1 billion by 2020 (Ministry of Energy, 2017[19]), accounting for around 0.5% of Israel’s central government budget in 2020.2 In addition to royalty income, Israel is planning to set up a sovereign wealth fund, fed by a special levy of 20 – 50% on gas extractors’ profits over normal returns on investment (OECD, 2018[20]). By 2040, this fund could accumulate up to USD 40 billion, representing more than 10% of Israel’s current GDP. (OECD, 2018[20]). This fund could be set up in a similar way as Norway’s Government Pension Fund Global (Box 2.1).

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Box 2.1. Investment Strategy, governance and ethical standards of Norway’s Government Pension Fund Global

Norway’s Government Pension Fund Global, previously the Petroleum Fund of Norway, was established in 1990 to sustain the wealth from Norway’s oil revenue for future generations. As of 2019, the fund manages more than USD 1 trillion, making it one of the largest funds in the world (Norges Bank, 2019[21]). The fund invests in international financial markets, including bonds, real estate and private equity with stakes in more than 9,000 companies across 73 countries.

The Ministry of Finance has tasked Norway’s central bank, Norges Bank, with the management of the fund based on the Government Pension Fund Act, enacted by the Norwegian Parliament. The Ministry has the overall responsibility of the Fund and provides clear guidelines for the management, including guidelines for the observation and exclusion of companies that violate specific ethical standards. Based on the guidelines the Council of Ethics, appointed by the Ministry, proposes a list of firms to be excluded from investment. As of November 2019, the list included 154 companies that had been excluded for reasons such as violations of human rights, corruption as well as production of tobacco, weapons and coal or coal-based energy. As of 2014, the guidelines explicitly stipulate to exclude all companies whose revenue from thermal coal exceeds 30% (Ministry of Finance, 2014[22]). In addition, the updated 2019 guidelines force the fund to divest from companies that produce more than 20 million tonnes of coal annually and recommend the exclusion of companies involved in oil and gas exploration (Ministry of Finance, 2019[23]).

Source: Authors based on (Norges Bank, 2019[21])

Natural gas power plants have improved the environmental performance of Israel’s electricity sector, but relying on large contribution of natural gas to electricity generation in the longer-term and in the absence of CCUS or similar technologies will jeopardise the achievement of deep decarbonisation in line with Israel’s international commitments under the Paris Agreement. Assuming a share of natural gas of 70% and renewables of 30%, annual carbon emissions could still be as high as 37.2 Mt CO2 in 2050, similar to electricity-related carbon emissions in 2018.3 In addition, relying on natural gas is detrimental for achieving broader well-being objectives for the following reasons:

  1. 1. The extraction and combustion of natural gas still emits large amounts of GHG emissions, albeit half the amount of coal on average (IPCC, 2014[4]). Lifecycle GHG emissions of gas power plants are around half of coal power plants, ranging from 410 to 650gCO2e/kWh (IPCC, 2014[4]).4 Fugitive emissions through leaks in the extraction, transmission and distribution of natural gas can cause the GHG emission intensity of gas to be even higher than that of coal if leakage rates exceed 3% (OECD, 2017[24]). In addition, methane emissions also contribute to the production of tropospheric ozone, which has detrimental impacts on both human health and ecosystems (Shindell et al., 2012[25]). Measuring, monitoring and minimising fugitive emissions in the gas supply chain is therefore a key priority. Even equipping natural gas power plants with CCUS would not entirely exclude CO2 emissions, but could reduce them by approximately 88% (Ministry of Environmental Protection, 2018[26]), still requiring carbon removal technologies to achieve net-zero emissions. CCUS with current technologies would raise estimated capital costs for natural gas-fired plants by between 55 – 100%, translating into a 26 – 40% increase of levelised cost of electricity (LCOE) - the unit costs of electricity over the lifetime of the plant (IPCC, 2014[4]). This estimate does not include transport and storage, which would add USD 10/tCO2 on average (IPCC, 2014[4]). Increasingly blending natural gas with green hydrogen – hydrogen produced with electrolysers, using renewable electricity – may be a lower cost strategy to reduce GHG intensity of the electricity sector. For example, a 5% blend of green hydrogen would reduce CO2 emissions from gas combustion by 2% (IEA, 2019[27]).5 It would also improve system flexibility through providing a long-term storage option for a dispatchable fuel (IEA, 2019[28]). As the typical lifetime of gas power plants is 36 years (IPCC, 2014[29]), equipping new gas power plants with turbines that accommodate high shares of hydrogen would reduce the risk of stranded assets.

  2. 2. While gas power plants emit hardly any direct SOx and PM, they are still significant contributors to NOx emissions, albeit to a lesser extent than coal (IEA, 2016[6]). Gas power plants account for 20% of global power-related NOx emissions (IEA, 2016[6]). NOx emissions contribute to the acidification of fresh water and soils as well as to the eutrophication of water, all of which threaten biodiversity (OECD, 2018[5]). NOx emissions have direct negative impacts on public health and are responsible for the creation of summer smog, aggravating the negative health impacts (IPCC, 2014[29]). In addition, gas extraction is a major contributor to air pollutants known or suspected to be carcinogenic. However, the implementation of abatement measures for existing gas extraction and stricter environmental planning and permitting for gas extraction coming online can reduce the negative effects of gas operation on air quality (Ministry of Environmental Protection, 2019[30]).

  3. 3. The LCOE of natural gas is higher than that of solar PV, even at current fuel tax levels that do not include the full social costs (Gallo and Porath, 2017[31]). The latest clearing prices of Israel’s utility-scale solar auctions (USD 55/MWh) is lower than the generation costs of fossil fuels (80 USD/MWh) (EcoTraders, 2019[2]).6 The cost of solar PV has fallen sharply over the last years and this trend is expected to continue with expected cost reductions between 15 – 35% in the next 5 years (IEA, 2019[32]). The cost for distributed solar PV (USD 150/MWh), however, is still above that of fossil fuels (Ministry of Energy, 2019).

The long-term risks related to natural gas call for a greater focus on renewable energy sources in the generation of electricity.  

The long-term risks related to natural gas call for a greater focus on renewable energy sources in the generation of electricity. Israel could use its natural gas resources in some industrial sectors that are hard to decarbonise otherwise or for export to other countries with fewer renewable resources. Exports to Egypt and Jordan are expected to start in 2020 and there are also longer-term plans to export gas to Europe via the EastMed pipeline. However, exporting gas requires substantial investments in gas transport infrastructure, amounting to as much as EUR 6 billion for the EastMed pipeline project (Eastmed, 2017[33]) and gas demand in Europe is expected to decline (IEA, 2019[27]). Similarly, liquefied natural gas terminals enabling exports to growing Asian economies face key uncertainties as gas exports to those countries may not be cost-competitive (IEA, 2019[27]). The investment risks would be further exacerbated as and when gas-importing countries increased their own climate ambition, e.g. through higher taxes on gas. If Israel’s gas extraction and transport costs were too high to be internationally competitive, some reserves might not be economic to extract.

The transition to an electricity sector with higher shares of renewables likely will result in a modest increase in employment in the sector, but power plants relying on fossil fuels are expected to experience employment losses (OECD, 2017[34]). In 2018, almost 17,000 people or 0.5% of Israel’s total workforce were directly employed in the electricity sector (OECD, 2019[35]). The Israel Electric Corporation (IEC) – the state-owned electricity supplier and owner of the transmission and distribution network - alone employed 11,139 persons, but this number is expected to decline to 9,300 by 2026 in accordance with the latest electricity sector reform that foresees privatisation and prevents the IEC from investing in new capacities (Electricity Authority, 2018[9]).

At the same time, renewables, notably solar PV, can create new jobs and business opportunities, including for small and medium enterprises, while boosting productivity through innovation (OECD, 2012[36]). For example, a 50 megawatt (MW) solar plant can create between 60 and 80 permanent full-time jobs (IRENA, 2018[37]), notably in Israel’s rural areas that are economically less developed. For example, renewables expansion in the Negev desert could significantly spur economic development and diversify the local economy while reducing unemployment and poverty, notably for the Bedouin minority (Potter et al., 2012[38]).7 Rooftop solar is even more labour intensive and creates higher shares of high-skilled jobs (IEA and CEEW, 2019[39]). Integrating solar PV into the grid also requires smart technologies that enable new business models and can provide highly skilled IT jobs as well as export opportunities.

In 2018, renewables accounted for approximately 4% of total electricity generation with solar power accounting for the biggest share (3.6%) (EcoTraders, 2019[2]). This share is low compared to other OECD countries (Figure 2.1). Israel aims to achieve a renewable share of at least 10% by 2020, 13% by 2025 and 17% by 2030 (Ministry of Environmental Protection, 2018[12]). In 2018, total renewables capacity amounted to 1,450 MW with solar PV accounting for 1,358 MW, most of which was distributed solar (Electricity Authority, 2018[9]). To achieve the stated 2030 target of 17% generation from renewables, the expected installed capacity of renewables would have to increase to 8,600 MW, with 7,500 MW from solar PV. The Ministry of Energy’s 2030 Targets for the Energy Sector will review the 2030 goals in the coming years and has already announced a preliminary decision to raise the target to 25% to 30% (EcoTraders, 2019[2]). Based on the stated target (17%), extrapolating the speed of renewable energy deployment between 2020 and 2030 would result in a renewables share of 31% by 2050. Conversely, reaching a renewables share of 70% by 2050 would require raising the 2030 target to 30%. A 30% target by 2030 would translate into a renewable capacity of more than 15,200 MW in 2030. This would require annual capacity additions of around 1,140 MW after 2020, which is actually lower than the expected capacity addition in the year 2020.8

Israel has excellent solar resources, but limited resources for other renewables. Israel is currently re-assessing the technical long-term potential of renewables (EcoTraders, 2019[2]). Past assessments revealed that Israel has no potential for hydro or geothermal power (Solomon, Bogdanov and Breyer, 2018[40]) and only limited potential for wind and biomass (Ministry of National Infrastructures, 2010[41]). However, Israel’s annual solar radiation is between 1,900 and 2,200 kWh/m2 (Vardimon, 2011[11]), up to 50% higher than in Greece where solar radiation ranges between 1,450 and 1,800kWh/m2 (Fantidis et al., 2012[42]). The maximum total ground area available for solar PV is reported to be 6% of the total land area, equivalent to 1,324 km2 (Solomon, Bogdanov and Breyer, 2018[40]). If this area was entirely devoted to utility-scale solar PV, this could generate, with current technologies, at least 280 TWh electricity, more than four times the electricity consumption in 2018 and more than three times the expected consumption in 2030.

Israel is currently focusing on distributed solar PV to achieve its renewable energy targets as transmission grid constraints have slowed down deployment of utility-scale solar (Gallo and Porath, 2017[31]). An early study estimated the nation-wide technical potential for rooftop solar PV (based on 75 km2 available rooftop area) to be 15.9 TWh, almost one quarter of Israel’s electricity consumption in 2018 (Vardimon, 2011[11]).9 A more recent study from 2020 conducted by the Ministry of Environmental Protection and EcoTraders estimated the potential of solar PV in urban built areas in 2030 to be 38 TWh with more than a third from rooftop solar PV, 7% from building-applied PV on facades, and the remainder from utilising water reservoirs as well as additional built-areas, including highways and parking lots.

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Table 2.1. Estimates of the technical solar PV potential in Israel


Type of area


280 TWh

Land area

(Solomon, Bogdanov and Breyer, 2018[40])

38 TWh

Urban built area

Ministry of Environmental Protection and EcoTraders (2020)

15.9 TWh

Rooftop area

(Vardimon, 2011[11])

Source: (Solomon, Bogdanov and Breyer, 2018[40]); (Vardimon, 2011[11]); Ministry of Environmental Protection and EcoTraders (2020).

Realising the full potential of distributed PV is key as distributed solar PV has a number of advantages. Relative to utility-scale PV located far away from consumption centres, a power system with high shares of distributed PV would reduce losses due to electricity transmission and voltage conversion. Distributed PV, though more expensive on an LCOE basis, would not require investments in transmission capacity and would also increase the resilience of the power system while reducing the risks of wild fires, which are frequently caused by electric faults in the transmission system in dry regions, as in California (RFF, 2019[43]).

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Figure 2.1. Renewables and solar share of electricity generation across OECD countries in 2018
Figure 2.1. Renewables and solar share of electricity generation across OECD countries in 2018

Source: (IEA, 2019[44]).


Deployment of solar PV faces challenges and barriers related to the intermittency of generation and land availability, but these challenges can be addressed:

  1. 1. Solar PV is a variable renewable energy (VRE) source that generates energy only during the day. With rising shares of solar PV, the need for power system flexibility – flexible power plants, storage and demand response - increase to ensure that supply meets demand at every hour of the day (IEA, 2019[27]). The existing stock of gas power plants is well suited for integrating solar PV due to their ability to quickly ramp generation up and down. Additional flexibility needs can be delivered by pumped hydro storage and battery storage with battery costs expected to decline rapidly (IEA, 2019[27]). Demand response (DR), e.g. shifting load from peak demand hours to hours of the day where solar power is abundant, can provide flexibility at a low cost. Developing smart technologies to manage flexible loads could also strengthen Israel’s technological leadership and create new high-skill jobs.

  2. 2. The sparsely populated Negev desert seems suitable for utility-scale solar PV deployment, but other competing users exist. The Negev covers more than 55% of Israel’s land area equivalent to 13,000km2. However, much land is currently occupied by other uses: Israeli military (55%), nature reserves and national parks (90% of the Negev desert is classified as preserved land) as well as agriculture (8%) (Fischhendler, Nathan and Boymel, 2015[45]). Reassessing land uses in the Negev is key for further deployment of utility-scale solar PV. This becomes even more important in view of rising electricity demand due to electrification and – potentially – to the use of electrolysers to produce hydrogen. Yet, deploying utility-scale solar PV along with transmission lines would most likely affect sensitive ecosystems, calling for a robust full environmental assessment of all generating technologies along their lifecycle. Accounting for the most relevant external costs and benefits of generating technologies implies that Israel should seek to limit its need for additional large-scale generating capacity to the extent possible. There should therefore be a stronger focus on energy efficiency, on smart grid and storage solutions (including through sector-coupling) as well as on realising the potential of distributed solar in built-areas, water reservoirs and brownfield sites (e.g. decommissioned industrial areas). Solar PV on water reservoirs would in addition save up to 80% of evaporating water (Taboada et al., 2017[46]) and reduce algae growth while improving the solar panels’ power conversion efficiency due to lower ambient air temperatures underneath the panels (Spencer et al., 2018[47]).

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2.3. Policies for a sustainable electricity sector

The previous section has argued that the shift from coal to natural gas has important benefits in terms of reducing both GHG and air pollution in the near term, but that a predominant focus on natural gas will constrain the ambition of future GHG emission reduction targets and broader well-being goals in the long-term. Instead, more emphasis should be given to renewables, notably solar PV. This section discusses three building blocks for decarbonising the electricity sector. First, section 2.3.1 presents pricing instruments to address externalities as well as how these instruments need to be designed to avoid a too high burden on lower-income groups. Second, this part discusses support measures for both utility-scale (Section 2.3.2) and distributed solar PV (Section 2.3.3) as well as solutions to better integrate solar PV through enabling policies, including electricity market regulation (Section 2.3.4). Third, Section 2.3.5 provides insights on policies promoting energy efficiency.

2.3.1. Pricing carbon and other externalities correctly and removing subsidies

Pricing carbon and other externalities (notably air pollution) according to its social costs, aligns the incentives of emitters with those of society and reduces emissions in a cost-effective way. The High-Level Commission on Carbon Prices suggests that the carbon price should be in the range of USD 40 – 80 per tonne of CO2e by 2020 and USD 50 – 100 by 2030 to hold global warming under 2°C relative to pre-industrial levels, provided complementary policies addressing other market failures are in place (High-Level Commission on Carbon Prices, 2017[48]). More recently, the International Monetary Fund (IMF) estimated that a carbon price of USD 75 per tonne of CO2e by 2030 is needed to be compatible with the goals of the Paris Agreement (IMF, 2019[49]). Incorporating the external costs from air pollutants (e.g. SOx, NOx, PM, O3 emissions) would further increase these figures. For example, Israel’s Ministry of Environmental Protection calculates the electricity-related external costs of SOx and NOx emissions at NIS 46,260​​ and 26,791 (USD 12,588 and 7,290) per tonne, respectively (Ministry of Environmental Protection, 2019[50]). Pricing fugitive emissions from gas extraction provides strong incentives for gas operators to reduce emission leaks in the gas supply chain. Fugitive emissions from gas extraction are priced, among others, in the Californian emissions trading scheme based on the global warming potential (ICAP, 2018[51]).

Only 1% of Israel’s electricity-related carbon emissions are priced above EUR 5, one of the lowest shares across OECD countries (Figure 2.2).10 Israel uses excise taxes on coal at NIS 46.09 per ton and on natural gas at NIS 17.36 per ton, translating into implicit carbon rates of EUR 4.54 and EUR 1.91 per ton CO2 respectively (OECD, 2019[52]). Recent developments suggest that the gap between the effective carbon rates of Israel and other OECD countries is widening (OECD, 2018[53]). For example, due to the rise of the permit price in the European Union emissions trading scheme increased from EUR 5 in 2017 to EUR 25 in 2019. Natural gas received public support of approximately NIS 500 million, equivalent to 0.04% of GDP in 2017 (OECD, 2018[53]). The major part of this producer support reflects a long-term gas agreement at guaranteed prices between the IEC and the investor consortium of the Tamar gas field (OECD, 2018[53]).

Introducing a carbon tax or gradually raising excise taxes on natural gas and coal would improve the incentives of independent power producers (IPPs) to invest in renewables. Cost-reflective prices for natural gas would increase the cost of the government to procure investments in new gas capacity. This, in turn, would decrease the relative costs of renewables vis-à-vis gas power plants, enhancing the competitiveness of renewables. In addition, higher taxes on natural gas would preserve the tax base since electricity generation is increasingly shifting towards gas with the announced coal phase out.

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Figure 2.2. Share of electricity-related CO2 emissions priced above EUR 5 in 2015
Figure 2.2. Share of electricity-related CO2 emissions priced above EUR 5 in 2015

Note: Includes emissions from biomass firing. 99% of Israel’s electricity-related CO2 emissions are priced below EUR 5.

Source: Authors, based on (OECD, 2018[54]).


Retail electricity prices would likely need to increase to reflect rising carbon costs of the IEC and IPPs. Electricity retail prices need to reflect the full cost of electricity, including the social cost of generation and the electricity system costs (storage, transmission and distribution network) (IEA, 2016[55]). Higher retail prices encourage private investments in energy efficient equipment, including air conditioners, refrigerators and electric heat pumps (Section 2.3.5). Higher prices also improve the payback time for investments in energy efficient buildings to reduce the heating and cooling needs in the first place (Chapter 3) while ensuring sufficient investments in distribution and transmission networks by the IEC. Finally, cost-reflective prices also provide more incentives to drive private investments into distributed solar PV (Section 2.3.3).

Residential electricity prices in Israel, administratively set by the Electricity Authority, have slightly increased from 0.462 NIS/kWh in 2015 to 0.472 NIS/kWh in 2018. They are, however, still below the levels of 2006 in real terms (0.502 NIS/kWh) (Electricity Authority, 2018[9]). Israel has one of the lowest residential retail rates among OECD countries, 40% lower than the EU average (EcoTraders, 2019[2]). Despite the low price levels, electricity price hikes can create affordability problems for low-income households. At current prices, the poorest 10% of the income distribution spend already 9% of the available income on electricity, gas and fuels compared to 3.4% for the 5th decile (EcoTraders, 2019[2]). Increasing electricity prices can also challenge the competitiveness of firms in the industry sector. However, complementary policies can alleviate some of the negative impacts for households and firms and can avoid carbon leakage.11

Addressing the problem of residential electricity affordability and energy poverty in general requires a two-step approach, identifying vulnerable population groups in the first step and using targeted policy support for these groups in a second. The low-income high-cost share (LIHCS) indicator is suitable for identifying vulnerable household groups and is used in a number of countries, including the UK (BEIS, 2019[56]). Countries are using different thresholds for the definition of low-income and high-cost share, depending on the country-specific circumstances, but commonly applied thresholds include an expenditure share of energy of more than 10% while being below the relative poverty line (i.e. 60% of median income) after expenditure on energy (Flues and van Dender, 2017[57]). LIHCS is one of the most selective indicator on affordability risks as it combines two criteria, identifying households in the low-income group that spend a high share of their income on energy products. However, LIHCS’ data requirements are relatively high, preventing the calculation of this indicator for Israel with publicly available data.

In a second step, targeted support, including targeted deployment of distributed solar PV, targeted income transfers or dedicated programmes to enhance energy efficiency (Section 2.3.5) help reduce energy poverty. Deploying distributed solar PV on social housing units or in disadvantaged communities reduces the energy bill of low-income households while spurring renewable expansion. For example, California provides upfront financial incentives of USD 3,000 per kW for the installation of rooftop solar PV under the Disadvantaged Communities Single-family Solar Homes programme (CPUC, 2019[58]). Eligible customers must live in a disadvantaged community12 and must be below a certain income threshold. Targeted transfers help low-income households to cope with energy poverty without distorting the price incentives for saving energy (as would be the case for preferential electricity tariffs). For example, in 2016 France switched from social energy tariffs to providing energy cheques to help households pay their energy bills (OECD, 2016[59]). Depending on the households’ income and the characteristics of the dwelling, eligible households receive a cheque of up to EUR 277 per year (EUR 150 on average) to pay utility bills, in 90% of the cases electricity bills. In 2019, 5.8 million households were eligible for this programme (Ministry for the Ecological and Inclusive Transition, 2019[60]).

Addressing the burden of higher electricity prices for electricity-intensive industries also entails a two-step approach to reduce negative impacts on competitiveness and avoid carbon leakage. Up to today, the economics literature has not found negative effects of carbon prices on industrial firms’ competitiveness, measured by revenue, jobs, profits or net imports (Ellis, Nachtigall and Venmans, 2019[61]). Yet, this finding is in part due to low carbon price levels levied on industrial installations either because of tax exemptions or allocation of free allowances. Rapidly rising electricity prices as a result of cost-pass through of carbon costs can have negative short-term adjustment effects, notably for electricity-intensive firms. These firms may receive support depending on their electricity and trade intensity. Support could be either in form of direct transfers or targeted support for energy efficiency improvements, allowing these firms to better cope with higher electricity prices while enhancing their competitiveness in the future.

Revenues from carbon pricing can be used for targeted support, alleviating the regressive distributional effects of carbon pricing while strengthening citizen support (Marten and van Dender, 2019[62]). Research in European economies suggests that it may be sufficient to use one third of the revenues from higher energy taxation for transfers to low-income households to improve energy affordability of these households (Flues and van Dender, 2017[57]). Using carbon tax revenues to improve environmental outcomes and reduce poverty also strengthens citizens’ support (Kallbekken and Aasen, 2010[63]; Baranzini and Carattini, 2017[64]; Kallbekken, Kroll and Cherry, 2011[65]).

2.3.2. Accelerate utility-scale solar PV deployment and removing barriers

Utility-scale solar PV is already cheaper than natural gas, but long-term support remains important to reduce financing costs. Providing revenue certainty for private investors reduces risks of solar PV projects and helps channel private capital into renewables. Competitive auctions are more cost-effective than administratively set Feed-In-Tariffs (FIT) (IEA, 2018[66]). In 2017, the Electricity Authority switched its major support scheme from FiTs to competitive tenders (Gallo and Porath, 2017[31]). The Electricity Authority held the first solar PV auction in 2017, tendering a total capacity of 234 MW from 12 selected project developers at a price of NIS 199/MWh (USD 55/MWh) (IEA, 2019[67]).

Support mechanisms can be designed to account for various well-being dimensions, including jobs and the development of local industrial clusters. For example, South Africa’s Renewable Energy Independent Power Procurement Program (REIPPP) assigned 70% of the auction score on the bid price whereas the remaining 30% are allocated based on socio-economic dimensions including job creation, black ownership and enterprise development (Ettmayr and Lloyd, 2017[68]). Between 2011 and 2015, the REIPPP is estimated to have created more than 100.000 direct full-time jobs (Eberhard and Naude, 2017[69]). As another example, the Contract for Differences programme in the UK requires projects larger than 300MW to submit a ‘supply chain plan’ (Fitch-Roy and Woodman, 2016[70]). This is to encourage the effective development of renewable energy supply chains, notably to enhance competition, support the development of local industrial clusters and to promote innovation and skills, all of which trigger further cost decreases in the long-term (BEIS, 2018[71]).

Remuneration of renewable projects must strike a balance between channelling private investments into sustainable infrastructure and risk-taking of private actors. As technologies become more mature and the share of renewables increases, support schemes need to be adjusted to hand over more risk to private actors. Notably, this includes increasingly exposing renewables to market risk in form of wholesale market remuneration to incentivise system-friendly behaviour, i.e. providing electricity at hours of the day when it is most beneficial for the power system. This requires a wholesale market that Israel does not yet have (Section 2.3.4).

Until recently, infrastructure development has not yet fully taken into account the potential for renewable generation away from the consumption centres, likely leading to bottlenecks in the transmission grid (Gallo and Porath, 2017[31]). Most of the available land is located far away from the main consumption centres, notably in the Negev desert. In 2018, the Ministry of Energy and the Electricity Authority approved a five year development plan that includes significant investment in the transmission grid and will expand the transmission network from 5.587 km in 2018 to 6.389 km in 2022 (Electricity Authority, 2018[9]). Investments in 2018 were NIS 0.9 billion, almost double the amount of the average in the last 10 years (Electricity Authority, 2018[9]). Tenders for transmission capacity have been found to be cost-effective for realising transmission projects (IEA, 2016[55]). Integrated long-term planning, including mapping of the geographical distribution of renewable energy resources and establishing project pipelines of bankable PV projects, improves the co-ordination between land-use planning and deployment of utility-scale solar PV while reducing the investment risk of project developers (OECD, 2015[72]). Long-term scenarios help evaluate the investment needs in network infrastructure. For example, ENTSO-E, the European transmission network operator, explores a range of long-term scenarios until 2050 (ENTSO-E and ENTSO-G, 2018[73]) and provides open access to all relevant electricity data through its Transparency Platform (Hirth, Mühlenpfordt and Bulkeley, 2018[74]).

Removing administrative barriers for project developers of solar PV (e.g. the lack of land allocation procedure, delays in obtaining installation permits) can also substantially lower the costs. One-stop shops, i.e. offices in charge of issuing all necessary permits, are effective in streamlining permit and licensing procedures (OECD, 2017[34]). Completing general environmental impact assessments before the competitive tender reduces the uncertainty of project developers, leaving only the project-specific risk related to environmental impact assessment to the bidder (OECD, 2017[34]). Israel has tendered pre-approved sites for solar PV deployment (Ministry of Environmental Protection, 2015[75]). Legal time limits for permit approval speeds up construction (Koźluk, 2014[76]) and helps address conflict of interest between project developers and the IEC that is responsible for issuing the installation permits. In addition, legal time limits for connecting generators to the distribution and transmission network would further strengthen the position of IPPs.

Market concentration of state-owned enterprises has been found to discourage investment in renewables (Prag, Röttgers and Scherrer, 2018[77]). The state-owned IEC is the dominant generator of electricity, accounting for 79% of installed capacity and 69% of generation in 2018 (Electricity Authority, 2018[9]). The major electricity sector reform, enacted in 2018, foresees to reduce IEC’s share on installed capacity to 45% by 2025 through privatisation, requiring the IEC to sell half of its gas-fired power stations, equivalent to 4,500 MW (EcoTraders, 2019[2]). At the same time, the reform prevents the IEC from investing in new capacity further adding to a more competitive electricity sector. The electricity sector reform also transfers the operation of the electricity system from the IEC to an independent, but state-owned body (EcoTraders, 2019[2]). The system operator is responsible, among others, for the dispatch of power stations as well as long-term planning and forecasts of electricity demand. It will be important for the system manager to be fully independent of the incumbent to prevent discrimination against market entrants (Fuentes, 2009[78]).

2.3.3. Supporting distributed energy resources

Distributed generation, notably distributed solar PV, plays an increasingly important role in Israel’s electricity system, overcoming bottlenecks in the transmission lines and preventing costly expansion of the transmission network. Investment costs of distributed solar PV has globally declined by 60-80% since 2010 and are expected to decline by a further 15-35% until 2024, making this technology cost-competitive in an increasing number of countries (IEA, 2019[32]). Even though the costs of utility-scale solar PV are between 10-50% lower than distributed solar PV, there is an economic argument for distributed generation due to its proximity to the consumption centres (IEA, 2019[32]). Generating electricity onsite or next to consumption centres reduces the investment need in transmission grid extension and distribution grid reinforcement with lower impacts on biodiversity and ecosystems.

In most countries, distributed solar PV’s LCOE, ranging between USD 83 and USD 195/MWh, is well-below the variable part of the retail tariff, rendering distributed PV deployment profitable (IEA, 2019[32]). However, in Israel, the economic attractiveness of rooftop solar PV in the absence of policy support is not given under current electricity prices. The LCOE of rooftop solar in Israel, currently around USD 150/MWh (Ministry of Energy, 2019[7]), is higher than the electricity retail price at USD 120/MWh. A carbon price of USD 50/tCO2 would equalise Israel’s electricity retail price with the cost of rooftop solar PV, creating strong economic incentives for distributed PV deployment. This number is based on the assumption of full cost pass-through of carbon costs to electricity consumers, using Israel’s carbon intensity of the electricity mix in 2018.

A carbon price of USD 50/tCO2 would equalise Israel’s electricity retail price with the cost of rooftop solar PV, creating strong economic incentives for distributed PV deployment.  

Policy support would remain the key stimulant for distributed solar PV uptake even if retail prices fully reflected the social cost of electricity generation (IEA, 2019[32]). Israel uses a diverse set of policies to scale up distributed solar PV deployment. Israel’s government increased investment incentives by granting small renewable energy installations exemptions from municipal tax, value-added tax, income tax, and betterment levies while streamlining the permit process. All of these measures have contributed to growth of distributed solar PV deployment (EcoTraders, 2019[2]). In addition, the Minister of Energy authorised a 1,600 MW framework for rooftop solar PV in 2018, valid for the next 3 years. The new framework stipulates competitive tenders for commercial rooftop solar, allowing the successful bidder to sell electricity at the winning bid to the grid under a long-term power purchase agreement. In addition, Israel switched from its net-metering scheme to administratively set FiTs for residential solar PV (IEA PVPS, 2018[79]). Households can apply for a 25-year FiT of 0.48 NIS (0.137 USD)/kWh while lower rates apply for larger project sizes (0.45 ILS or 0.129 USD/kWh for projects between 15kW and 100kW) (IEA PVPS, 2018[79]).13 Too high levels of FiTs risk overcompensating generators, increasing the cost burden of the IEC as electricity buyer.

Real-time self-consumption models provide better incentives than time-invariant FiTs (IEA, 2019[32]). In real-time self-consumption models, the excess electricity generation is sold to the grid at the current electricity market price, in some cases adjusted by some other factors reflecting the benefits of self-consumption. Self-consumption can lead to a reduction of grid costs as grid reinforcement and extension can be deferred, notably when distributed solar PV can lower peak power loads (IEA, 2019[32]). Selling electricity at real-time prices (or at time-varying prices that reflect system value) provides incentives to maximise the market value of electricity generation, e.g. by investing in distributed storage (Section 2.3.4). Real-time self-consumption models already dominate in the commercial PV segment and are employed in the residential PV segment by an increasing number of countries, including Denmark, Germany and Australia (IEA, 2019[32]).

An increasing share of self-consumption, however, can raise concerns on the cost recovery of distribution network costs, requiring adjustment of the retail tariff (IEA, 2019[32]). In Israel, as in most countries, grid costs are recovered from the variable part of the electricity price (EcoTraders, 2019[2]). Lower grid consumption of PV-owners has two implications: First, it challenges the financial viability of the IEC because the (fixed) network costs need to be allocated over a lower number of kWh consumed. Second, ensuring cost recovery may force the Electricity Authority to approve higher tariffs, which poses questions on the fairness of allocating costs between PV-owners and non-owners. PV-owners are still using grid services when consumption exceeds generation, but do not pay the fair share when grid costs are entirely recovered from the variable part of the retail tariff (IEA, 2019[32]). As the share of distributed generation and self-consumption increases, grid costs might be increasingly recovered through the fixed part of a two-part tariff to mitigate this problem (IEA, 2016[55]). However, increasing the fixed part of the electricity tariff would be regressive and would imply that the share of the tariffs’ variable part decreases. This reduces the economic incentives for energy efficiency and deploying distributed PV for self-consumption. The Electricity Authority, thus, needs to strike a balance between the two opposing effects as well as between the different stakeholders, including the IEC, IPPs, PV-owners and non-owners (IEA, 2019[32]).

The Israeli government can leverage the dynamics of sub-national governments, including cities and municipalities. Many cities have ambitious (100%) RE targets in the power sector (REN21, 2019[80]). In Israel, the southern city of Eilat aims to be energy independent by 2023 (Haaretz, 2018[81]). Sub-national governments can successfully activate the civil society, strengthening support for more rapid deployment of distributed solar PV or enact special regulations tailored to the preferences of citizens. For example, California and the German city Tübingen require rooftop solar deployment on new buildings. Mandatory deployment of rooftop solar, on a national or sub-national level, would increase deployment in Israel substantially as 1.5 mill houses are yet to be built until 2040 (Chapter 3). In fact, developers of new buildings need to choose whether they want to install solar water heaters or solar PV on their roofs. Currently, the Ministry of Energy is conducting a cost-benefit analysis of mandatory rooftop solar for new buildings (Ministry of Energy, 2019[7]). In addition, new PV technologies (e.g. building-integrated solar PV) would change building design even more drastically by replacing traditional building materials through PV materials.

2.3.4. Increasing the flexibility of the power system to integrate VREs

Integrating VREs into the grid by providing flexibility to ensure that supply meets demand at every hour of the day is not yet critical, but will become increasingly important as renewable penetration grows. In 2018, Israel’s share of VREs in the electricity generation mix was 3%, putting Israel in the first or second category of the IEA’s six phase framework, which categorises countries according to their flexibility needs (IEA, 2016[55]). In these stages, the penetration of VREs has no immediate impact on power system operations, requiring, if at all, only minor operational changes. However, some policy action needs to take place to address specific challenges (Table 2.2). It is important to keep in mind that the share of VREs on total electricity generation reflects the national average; some regions may already have higher shares, and thus facing different challenges.

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Table 2.2. Policy action for system integration of VREs in early stages

Possible challenge


Can the grid accommodate VRE at the identified site?

Solve local grid issues and/or introduce flexibility provisions into the interconnection agreement

Is the grid connection code appropriate?

Develop or upgrade codes with stakeholders

Is VRE reflected in system operations?

Ensure transparency and controllability of power plants Install VRE forecast system

Is VRE being deployed in a system-friendly way?

Manage VRE deployment locations

Source: (IEA, 2019[32]).

With higher penetration of solar PV in the generation mix, flexibility needs are increasing (IEA, 2019[27]). High penetration of solar PV substantially challenges the functioning of the electricity system, leading to the so-called Duck Curve, which is exemplified on the net load of California (Figure 2.3). This curve shows the (expected) net load, i.e. total electricity demand minus the generation of VREs, on January 11 for the years 2012 to 2020, identifying four different ramp periods:

  • 4am – 8am (duck’s tail): people get up and start their daily routine, need for conventional power

  • 8am – 4pm (duck’s belly): the sun starts shining, solar power replaces conventional power

  • 4pm – 7pm (duck’s neck): sun sets, solar generation ends, people come home and start their evening routine, need for steep ramp up

  • 7pm – 4am (duck’s other parts): no sun, demand is approaching night level

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Figure 2.3. Duck Curve and ramping requirements
Figure 2.3. Duck Curve and ramping requirements

Note: Net load throughout the day on January 11 between 2012 and 2020. ‘Stop’ and ‘start’ refer to dispatchable power plants.

Source: (CAISO, 2016[82]).

There are three major challenges associated with the duck curve. First, the duck’s belly entails a risk of over-generation where solar PV supply exceeds total demand, potentially necessitating curtailment of renewable electricity. Second, the steep ramp starting at 4pm where conventional power plants need to be brought online rapidly to avoid load curtailment and ensure grid reliability. Third, the demand peak around 7pm currently still needs to be satisfied with conventional power plants (after the sun has set).

A set of strategies and technologies can tackle the various challenges of the duck curve and provide power system flexibility, including storage (e.g. pumped hydro and battery), demand response (DR), and flexible power plants (IEA, 2019[83]). The Ministry of Energy set a quota of 800 MW to procure pumped storage, out of which 640 MW are expected to be built in the coming years (EcoTraders, 2019[2]). Battery storage is expected to be the fastest growing source of global flexibility provision over the next 20 years (IEA, 2019[27]). Batteries can be installed almost everywhere while the modularity allows for scaling according to the flexibility needs. The costs of battery storage declined by 45% between 2012 and 2018 and this trend is expected to continue, making them increasingly competitive with other sources of flexibility (IEA, 2019[27]). Energy arbitrage - buying electricity when solar PV is abundant and prices are low and selling electricity at peak prices - would reduce procurement costs and increase the market value of solar PV, but this requires the existence of an electricity market (see below).

Battery storage coupled with solar PV can also reduce the investments in peaking plants based on natural gas. For example, the Florida Power and Light Energy Storage Centre comprises a 409 MW battery that will be fed by electricity from utility-scale solar PV during the day and will deliver electricity during the evening peak demand. After coming online in 2021, the battery is expected is expected to replace two natural gas power plants. Besides the savings in investments costs associated with the replacement of the two natural gas peaking plants, the battery is also expected to save USD 100 million to customers in fuel costs and 1 million ton CO2 emissions (IRENA, 2020[84]).

Demand response (DR) has huge potential for low-cost flexibility provision (IEA, 2019[27]). DR can reduce the peak load (duck’s neck), typically by around 15%, by shifting load away from the peak towards hours of higher solar penetration (IEA, 2016[55]). Moreover, DR can also avoid curtailment of solar PV generation (filling the belly of the duck), reduce the steepness of the evening ramp and reduce carbon emissions by shifting load from relatively carbon-intense peak hours of the day to hours with high renewable shares (IEA, 2019[27]). The industry sector currently has the biggest potential to provide DR (IEA, 2016[55]). However, also electric appliances in the residential sector, including air conditioners, refrigerators and heat pumps, can shift their load through hours of the day without compromising the quality of their energy services. For these appliances, it is important to improve demand-response readiness, e.g. by introducing labels to inform customers about the capability of the appliances to be controllable by third parties, for example as done in Australia (IEA, 2018[85]). Korea’s energy labelling even requires air conditioners to be controllable in order to receive the highest energy rating (IEA, 2018[85]).

With higher penetration of electric vehicles (EVs), demand response becomes almost inevitable, as most consumers are expected to charge their EVs at home after returning from work (IEA, 2018[86]). This would further elevate the peak load, increasing the ramping requirements (transition between duck’s belly and duck’s neck) and putting considerable strain on the distribution network (IEA, 2019[27]). However, EVs can be also a source for providing (distributed) low-cost flexibility through vehicle to grid technologies, allowing EVs to be charged and discharged at times when it is most beneficial for the power system (IEA, 2019[27]). Currently, vehicle to grid is discussed in California to make the power system more resilient to outages (WRI, 2019[87]).

Tapping the potential of DR, EVs and storage requires having the right incentives and infrastructure in place. Time-of use prices provide important financial incentives for consumers to shift their load towards hours where electricity supply is abundant. In Israel, time-of-use rates are mandatory for large electricity consumers, but not yet for residential consumers (EcoTraders, 2019[2]). Residential time-of use prices were piloted some years ago on a voluntary basis, but the pilots have been stopped (EcoTraders, 2019[2]). Based on a case study on dynamic pricing in Chicago, participating households saved 1-2% of the electricity cost on average and reduced electricity-related GHG emissions by 4% (Allcott, 2011[88]). However, these numbers from early case studies are expected to increase as new information and communication technologies, including smart meters and smart appliances, become available, reducing the transaction costs for electricity consumers and strengthening the effectiveness of dynamic pricing (IEA, 2017[89]). Demand response aggregators, i.e. third-party entities, managing multiple residential loads, could further enhance DR uptake while offering well-paid IT jobs. Creating adequate electricity markets and ensuring market access for a broad range of actors, including aggregators, facilitates the effectiveness of DR. At the same time, cybersecurity risks and other consumer concerns need to be addressed adequately (IEA, 2019[27]).

Electricity generators, including solar PV, can also provide flexibility if the right incentives are in place. Remuneration of solar electricity can increasingly incorporate market exposure, shifting the support mechanism towards feed-in premiums (FiPs) instead of having a fixed FiT with the IEC as guaranteed buyer (IEA, 2019[83]). Fixed FiPs, as in Denmark, are paid on top of the electricity wholesale price, providing incentives for system-friendly behaviour, but also exposes project developers to the highest market risks (Diacore, 2014[90]). Alternatively, sliding FiPs, as those used in Germany and the Netherlands, guarantee a fixed remuneration,14 but let project developers benefit from electricity prices above the pre-determined remuneration. This incentivises system-friendly behaviour, e.g. by investing in on-site storage or adjusting the orientation of solar panels (Diacore, 2014[90]). Both FiPs and sliding FiPs, however, require a well-functioning electricity wholesale market.

In the absence of an electricity market, the auctioneer can announce, as in Mexico, a set of hourly adjustment factors that reflect the perceived and expected system value of the power system (IRENA, 2019[91]). In addition to a fixed remuneration determined by the auction bid, project developers receive the adjustment, providing incentives to align the generation profile with (expected) system needs while shielding developers from revenue risks. Determining the administratively set hourly adjustment factors is, however, complicated and requires vast amount of information on the generation costs of generators, which can be easier revealed through a market mechanism.

Electricity markets are key enabler for power system flexibility and support efficient co-ordination of a wide range of actors. Despite Israel’s major electricity sector reform from 2018, the electricity sector is expected to continue to operate under central planning and not as an electricity market at least in the short and medium term (EcoTraders, 2019[2]). Efficient co-ordination of multiple actors will become even more important as the number and diversity of market participants, including distributed generation and providers of demand response, aggregators and storage is expected to increase. A market aligns the incentives of renewable energy producers with those of the power system and enables business models to provide flexibility, including storage and demand response (IEA, 2016[55]). Other electricity market elements, including scarcity pricing, ancillary service markets and capacity mechanisms, further enhance investments in flexibility (IEA, 2019[27]). Electricity markets also provide incentives for efficient short-term operation as well as investment decisions, potentially leading to lower system costs and lower electricity prices. Temporally and spatially differentiated market prices reflect grid constraints and further enhance operational efficiency while providing incentives to invest in new capacity at places where it is most needed (IEA, 2016[55]). For example, increasing the spatial resolution of the electricity market by switching from zonal to nodal pricing resulted in more efficient system operation of gas power plants of around 2.1% (and lower fuel consumption by 2.5%) in California (Wolak, 2011[92]) as well as lower prices for consumers of around 2% in Texas (Zarnikau, Woo and Baldick, 2014[93]).

Electricity markets are a key enabler for power system flexibility and support efficient co-ordination of a wide range of actors.  

2.3.5. Energy efficiency and electrification of end-uses

Energy efficiency can cost-effectively reduce GHG emissions, deliver on a number of well-being goals, mitigate pressure on the power system and can ease the achievement of renewable energy and emission reduction targets, in particular by reducing investments in generating capacity. Yet, improving energy efficiency typically results in less than expected reductions in total electricity consumption and GHG emissions due to the rebound effect (Sorrell, Dimitropoulos and Sommerville, 2009[94]). For electricity, the rebound effect is estimated to be around 0.1, meaning that an initial 10kWh decrease of electricity consumption due to more efficient electric equipment would trigger a second-order increase of 1kWh due to consumer and market response, reducing the final saving to 9kWh (Gillingham, Rapson and Wagner, 2015[95]). The National Plan for Energy Efficiency-Electricity Consumption Reduction aims to reduce electricity consumption by 17% by 2030, relative to BAU consumption. The plan sets out key priorities for energy efficiency in the residential, commercial and industry sector and foresees most (47.2%) of the electricity reduction by 2020 to be achieved in the residential sector (Ministry of Energy, 2015[96]).

Electrification of end-uses (e.g. EVs in transport, heat pumps in buildings and electric motors in industry) is a key strategy to improve energy efficiency. For example, EVs are much more energy efficient than cars with internal combustion engines (IEA, 2018[86]). The Ministry of Energy is planning to ban the sales of new cars with internal combustion engines by 2030, which is expected to increase EV uptake (Chapter 4) and, thus, electricity consumption. Assuming the share of private electric vehicles, commercial vehicles and trucks to be 8%, 8% and 3% respectively by 2030 would increase electricity demand by 2.06TWh (EcoTraders, 2019[2]), equivalent to 2.6% of the targeted total electricity consumption in 2030. Higher EV shares would lead to higher electricity consumption. Yet, EVs can also be a major (low-cost) source of flexibility, improving the integration of renewables and the efficiency of the power system (Section 2.3.4). Mapping different EV pathways and electrification pathways is crucial to inform future power infrastructure needs (e.g. generation assets and networks) and to support long-term planning. Increasing electrification will also require distribution network upgrades. If upgrades are carried out, the network capacity may be expanded substantially as the cost of upgrading is relatively insensitive to the size of the capacity increase (Imperial College London and Vivid Economics, 2019[97]).

Israel uses a broad set of measures to improve energy efficiency. Many energy efficiency measures are related to the design and the insulation of buildings, which determine cooling and heating requirements of residential buildings, accounting for more than 50% in residential electricity consumption (BDO, 2017[98]). Chapter 3 will discuss these measures in detail. In addition, Israel also uses minimum energy performance standards (MEPS) for key equipment (see below), regulations on industry and large energy consumers that require periodical energy surveys and equipment efficiency tests, budgets and requirements for energy efficiency in the government sector as well as grants and loans (EcoTraders, 2019[2]). Israel has resumed the National Support Mechanism for Energy Efficiency and Emission Reduction with a renewed budget of NIS 300 million and will allocate NIS 500 million in loan guarantees over a ten-year period to leverage investment in the fields of energy efficiency. The government is currently discussing more stringent minimum performance standards for electric appliances as well as a set of market-based policy instruments, including a purchase mechanism for non-consumed megawatt and an energy efficiency certificates trade system (obligation) (EcoTraders, 2019[2]).

MEPS for key equipment and appliances, including air conditioners and refrigerators, are most effective for the diffusion of more energy efficient equipment (IEA, 2018[85]). Israel applies MEPS for a broad range of electric equipment, reducing electricity consumption and in turn saving money for private households and industry. MEPS can be complemented by labelling, which is a low-cost option to provide information and improve decisions of electricity customers (IEA, 2018[85]). Residential consumer savings on energy bills through MEPS and labels can be as high as EUR 490 a year on average as estimated for the European Union’s updated Ecodesign MEPS (European Parliament, 2019[99]).

Market-based instruments (MBi), such as energy efficiency obligations and auctions, offer efficiency gains more cost-effectively as they leave the decision on how to save energy to market actors, discovering the most cost-effective way to achieve a given target (OECD and IEA, 2017[100]). Obligations would require the utility to deliver a pre-specified amount of energy savings whereas auctions seek market actors to bid for energy savings. Several approaches for calculating the savings exist, but most existing MBi programs are using deemed savings, i.e. estimates based on previous efficiency measures using the same technology. MBi have proven to stimulate private investment (with a leverage factor up to 3), reduce electricity consumption cost-effectively, deter investments in generation capacity and avoid investment in network upgrades (as in New York) (OECD and IEA, 2017[100]).

The IEC as the monopolistic retailer and owner of the distribution and transmission network could leverage on these network savings, further improving cost-effectiveness and easing short-term congestion problems. Raising funds from an energy company rather than from the government budget is likely to deliver more stable outcomes due to the annual budget reviews in the political process (OECD and IEA, 2017[100]). In addition, the IEC as a state-owned enterprise may benefit from preferential financing conditions due to better credit ratings, allowing for further cost-reductions (Prag, Röttgers and Scherrer, 2018[77]). For example, the IEC could use on-bill financing, financing upfront energy efficiency improvements and allowing repayment to be made as part of the monthly electricity bill. The IEC could also co-finance the installation of modern and smart air conditioners in private dwellings and reserve the right to remotely control the equipment under pre-specified conditions to shift load. In addition to conserving energy, this can reduce peak demand and can further defer grid reinforcement. It would also create new business opportunities for the IEC, likely easing the transition towards a low-carbon electricity sector for its employees. The IEC may also go one step further and provide energy services through long-term agreements with customers that stipulate the delivery of a specific energy service (e.g. lighting or cooling) instead of delivering just electricity. Energy service companies, such as Proven Lightning in the UK, are currently focussing predominantly on commercial clients as the residential sector is too heterogeneous (IEA, 2018[85]).

Some energy efficiency programmes are specifically targeted to low-income or fuel-poor households. The UK ECO Scheme restricts the energy efficiency obligation entirely to households subject to fuel poverty (OECD and IEA, 2017[100]). The Brazilian obligation scheme has required utilities to allocate at least 60% of the investment to low-income communities or households since 2010. Most of the measures consisted in fully funded provision of energy efficient lightbulbs and refrigerators, reducing the electricity bill of low-income households (OECD and IEA, 2017[100]). Bulk procurement of equipment and appliances in competitive tenders as done under the Indian ‘Unnat Jyoti by Affordable LEDs for All’ (UJALA) programme can further reduce the costs. Combined with a public awareness campaign, India procured LEDs in large quantities and passed the reduced rates on to the customers. The scheme is responsible for annual energy savings of around 100 TWh and 790 Mt CO2 emissions while avoiding 20.000 MW of generation capacity (EESL, 2019[101]). India is currently exploring bulk procurement for highly energy efficient air conditioners.

Non-targeted energy efficiency investments can also be beneficial for low-income households even if they are not directly enrolled. This is because the social returns of energy efficiency improvements in terms of reduced system costs, including avoided distribution and transmission grid upgrades and avoided environmental costs, are returned to all customers, including low-income households, and can be larger than the direct costs associated with the investment (OECD and IEA, 2017[100]). Based on a study in Vermont, the social benefits of energy saving (USD 147/MWh) clearly outweighed the costs incurred by the obligation (USD 39/MWh) (OECD and IEA, 2017[100]). Part of the benefits (USD 47/MWh) was passed on to all participants, outweighing the initial increase in the electricity price, including for low-income households. Of course, this effect varies across programmes and crucially depends on whether and how the social benefits are returned to customers.


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← 1. Note that electricity-related GHG emissions spiked in 2012 at 48.9 Mt CO2e due to the anomalous disruption of the gas supply and the following higher generation through coal plants. Hence, the year 2012 does not represent an appropriate reference year to indicate emission trends.

← 2. The 2019 budget of Israel sees government expenses of NIS 480 bill.

← 3. This figure is based on the 2018 carbon intensity of natural gas (393g/kWh, (Electricity Authority, 2018[9])) and assumes electricity consumption growth to continue at a rate of 2.1% until 2050. Electricity-related CO2 emissions in 2018 were 37.8 Mt CO2 (EcoTraders, 2019[2]).

← 4. Lifecycle emissions from solar PV originate predominantly from the construction phase and range from 18 to 180gCO2e/kWh with a median of 50gCO2e/kWh (IPCC, 2014[4]). More recent studies suggest that this range has narrowed to 6 to 87gCO2e/kWh (Ludin et al., 2018[102]).

← 5. A hydrogen blend of 5% in the gas mix is currently the maximum threshold in some countries, including Germany (Schiebahn et al., 2015[103]). However, most technological studies suggest that this share could be increased to 15 – 20% (Quarton and Samsatli, 2018[104]). Beyond these shares, hydrogen would need to be transmitted through a dedicated network.

← 6. Note that these figures refer to the period before the COVID-19 crisis.

← 7. The unemployment and poverty rates in the Negev is higher than in the rest of Israel (Potter et al., 2012[38]). Levels of education are lower and the economic structure weaker, with manufacturing and agriculture accounting for 22% of total employment (Potter et al., 2012[38]). While the Negev has a diversity of skills in the labour force, albeit with a relatively low share of high-skilled labour suitable for renewable energy, there is a need for training to accommodate for growth in solar PV deployment (Potter et al., 2012[38]).

← 8. Annual required capacity addition post 2020 is based on expected renewable capacity of 3,800 MW in 2020. Expected capacity addition in 2020 is 1,367 MW (Electricity Authority, 2018[9]).

← 9. However, this number rather represents a lower bound as technological improvements in the panel efficiency are not taken into account and the available rooftop area was estimated conservatively and has since increased.

← 10. Note that this figure applies to the electricity sector only. This figure may contradict the fact that the share of Israel’s environmentally related tax revenues on total tax revenue or GDP are one of the highest across OECD countries (OECD, 2019[105]). However, the high share for Israel is primarily driven by the high tax rates and revenues in the transport sector (Section 4.3).

← 11. See the upcoming second part of the OECD report “Accelerating Climate Action: Refocusing Policies through a Well-being lens” for further discussion.

← 12. California defines disadvantaged communities as communities that are disproportionately burdened by and vulnerable to multiple sources of pollution (CPUC, 2019[58]).

← 13. Distributed solar PV for self-consumption outside the framework can sell the excess generation at NIS 0.16 (USD 0.045) kWh to the grid.

← 14. Typically, the premium is defined as difference between the winning bid and a reference electricity price, in most cases defined as the average electricity market value of solar plants in a given period.

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