Abstract
This chapter presents the present energy, economic and political landscape of the MENA region, country by country. While fossil fuels have been at the center of this landscape in the MENA region, each MENA country has gone through a transformation of its energy system. Understanding this historical evolution is instrumental to better understand the starting point for future national energy transformations. While fossil fuels play a key role in all national energy sectors, countries vary regarding energy endowment, population size and economics. The chapter highlights the clear regional cleavage between hydrocarbon-exporting and hydrocarbon-importing countries and its consequences on national energy sector evolutions.
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Keywords
This Chapter presents the present energy, economics and politics landscape of the MENA region country by country. Fossil fuels fuels have been at the center of this landscape in the MENA region. Each MENA country has gone through a transformation of their energy systems. Understanding this historical evolution is instrumental to better understand the starting point for future national energy transformations (Chap. 4 ). While fossil fuels play a key role in all national energy sectors, countries vary regarding energy endowment, population size and economics. A clear regional cleavage can be identified between hydrocarbon-exporting and hydrocarbon-importing countries.
The Arabian-Persian Gulf (GCC countries plus Iran) is home of the largest hydrocarbon-producing countries embodying the most prominent example of rentier state. Given high hydrocarbon resources, limited population, they have generally benefit economically from the hydrocarbon industry with high wealth level per capita. Saudi Arabia and the UAE have become major oil producers and exporters. Nonetheless, they all have a very strongly increasing domestic hydrocarbon consumption which could in the future undermine their main income source. Gulf countries are also endowed by large gas reserves but so far only Qatar has been able to become a global powerhouse of gas (LNG) trade, while other countries with large gas reserves (e.g. Iran and Saudi Arabia) have not managed to gain an international or regional gas trade role. Saudi Arabia consumes its entire gas production domestically, while Iran has seen its ability to attract LNG technology hindered by international sanctions. Natural gas has, over the years, gained relevance in the domestic energy mix of Gulf countries in the attempt to decarbonize the power sector and free additional oil export volumes. Since all of them have a strongly rising energy consumption and are among the highest energy consumers per capita in the world, they have started to undertake some energy subsidy reforms albeit at different pace and intensity.
The Mashreq cluster (Egypt, Iraq, Israel, Jordan, Lebanon, Palestine and Syria) is home of both hydrocarbon-rich and hydrocarbon-poor countries. Some of them have experienced multiple transformation in terms of energy conditions with countries shifting from being net-importers to net-exporters. Egypt for instance, which is an old oil province, has since mid-1990s strongly expanded the role of gas. However, in the aftermath of the Arab Spring it became a net gas importer in the 2010s. Later, in 2018, thanks to the discovery of the Zohr offshore gas field, Egypt returned to be a net gas exporter. Another major transformation occurred in Israel, which has managed to reduce its dependence on coal (traditionally used for energy security reasons) and increase the role of gas in the energy sector thanks to the discovery of offshore gas fields. While sharing several characteristics, Lebanon and Jordan have undertaken different energy pathways with Jordan undergoing through a transformation of its energy sector while Lebanon remaining very much reliant on oil imports. The most striking difference between the two countries comes from the role of natural gas, which is absent in Lebanon’s energy system. Different sociopolitical and economic features in these two countries have heavily influenced their ability to reform and transform the energy sector, with Lebanon experiencing a dramatic economic (and political) crisis. Lastly, the cluster is home of two countries (Iraq and Syria) whose energy sectors have been heavily affected by the long-lasting security and governance issues. Iraq holds large hydrocarbon reserves but its ability of monetizing them (and create socioeconomic development for its citizens) has been impacted by numerous international and regional events.
Within the Maghreb cluster (Algeria, Morocco, Tunisia), Algeria and Libya stand out in terms of hydrocarbon reserves. Algeria is particularly important for Europe’s gas security as it is linked with it through three pipelines (two to Spain and one to Italy). Nonetheless, Algeria represents also the perfect example of rentier state—with high dependence on oil rents extremely visible during the periods of low oil prices. Libya has important oil reserves and a gas pipeline to Italy, but the country has long suffered international sanctions and over the last decade a civil war, deeply affecting oil and gas production and exports.
1 The Arabian-Persian Gulf
The Arabian-Persian Gulf cluster is composed of GCC countries plus Iran. These countries represent the most prominent example of rentier states. They share numerous similarities in political and socio-economic terms and a common evolving context, mostly due to the changing role of oil in the global energy system (Table 3.1).
Countries in this cluster greatly vary in population size, ranging from just over 1 million people (Bahrain) to nearly 35 million (Saudi Arabia). The population comprises both nationals as well as expats, which can make up to roughly 80% of the total population in countries such as Qatar and the UAE. Countries with limited oil and/or gas endowments (i.e. Bahrain and Oman) have lower GDP and GDP per capita levels, with the exception of Iran, which for a few decades was under international sanctions that limited its economic growth and well-being. Regarding energy, electricity consumption depends on population size, the amount of energy subsidies and on consumers’ lifestyle, as some countries may consume above their needs.
A key common characteristic of these countries is the abundance of hydrocarbon resources, which puts them on the global energy, economic and geopolitical map. With the exception of Algeria, Iraq and Libya, all the main oil producers and the largest oil reserve holders in the MENA region are located in this cluster, with Saudi Arabia and Iran playing the predominant roles, closely followed by Kuwait, as summarized in Table 3.2.
This cluster’s wealth, however, is not limited to oil. The Gulf countries are also endowed with natural gas reserves, which are expected to play a key role (at least as a transition fuel) in the energy transition process. Iran and Qatar are the largest gas reserve holders worldwide after Russia. In terms of global production share, the role of Gulf gas producers has been mostly downsized following the surge in US shale gas production. Nevertheless, as of 2019, Iran, Qatar and Saudi Arabia are the third, fifth and eighth largest gas producers in the world (BP 2020). Table 3.2 illustrates the great potential of gas in the region in terms of reserves, production and consumption, although in some countries of the area its full exploitation is hindered by a number of barriers.
Over the last decades, Gulf countries have seen a growing domestic energy demand, which affects the stability of their macroeconomic structure based on oil, the product that these countries export and that provides their revenues. Gulf countries have a significantly higher oil consumption per capita rate compared with other (developed and developing) countries. In 2019, the per capita consumption in Gulf countries, except for Iran, was two times the per capita level of the US and four times the level of European countries (see Fig. 2.6 in Chap. 2).
Despite the high gas potential, only few countries in this cluster export relevant gas volumes. Figure 3.1 shows the different evolution of their gas balance. Traditionally, some countries have faced high domestic consumption (i.e. Saudi Arabia and Kuwait), which has absorbed their entire gas production. Kuwait has recently had to rely on some gas import volumes from Iran to meet its domestic demand. Iran, though having the second largest gas reserves in the world after Russia, has traditionally been either a very minor net gas exporter or sometimes even a net gas importer. In fact, the country exports gas to Turkey and Iraq, and at the same time imports gas from Turkmenistan. Only recently, gas exports have increased to a record level of above 20 bcm/y, which is very little for a country with such important gas reserves and gas production levels. The reason is that most of Iran’s gas production is consumed domestically (including the amount reinjected into aging oil fields to boost their output). Obviously, the geopolitical barriers (i.e. sanctions) did not help Iran to become a major gas exporter. Indeed, the country had important LNG export projects that had to be abandoned due to the sanctions. Thanks to Abu Dhabi’s gas production, the UAE has been a net exporter, although it has recently become a net importer, through the Dolphin pipeline, mainly due to the rising demand and lack of reserves in Dubai and in some of the other minor emirates. Although Bahrain and Oman import gas from Saudi Arabia and Qatar, Oman is a net gas exporter, exporting LNG to Asia. Graph 3.s does not include Qatar given the great difference in terms of scale of gas exports. Indeed, it is the largest gas exporting country in the region, reaching a level of 122 bcm of total gas exports in 2019 (both by LNG and pipeline).
Source Authors’ elaboration on BP
Gas balance* of selected Gulf countries, 2000–2019, bcm. *: Production minus consumption. Exports (+) Imports (−).
Historically, GCC countries, with the exception of Qatar, have made no particular investments in gas exploration and development. This trend is now changing with the National Oil Companies, especially in Saudi Arabia, the UAE and Kuwait, which are planning to invest also in upstream gas projects. The push towards gas investment is dictated by numerous reasons. Firstly, gas can substitute oil in domestic consumption, enhancing oil volumes available for export. Secondly, gas itself may become a precious source of revenues, as global oil demand is expected to peak in the coming decade. Lastly, the decision to invest in gas is vital for these countries, mostly reliant on oil revenues, in order to remain at the forefront of the global energy system in the medium-term, gas being a key component of the global energy transition for European and Asian countries alike.
Key chokepoints, however, are located in this region (Map 3.1), such as the Hormuz Strait, where 21 million barrels of oil pass through every day, corresponding to nearly one-third of the total sea-traded oil. After passing through the Hormuz Strait, the oil export volumes must pass through other major chokepoints: the Bab el-Mandab and the Suez Canal before reaching Europe, and the Malacca Strait before arriving to Asia. Map 3.1 highlights the two main oil chokepoints of the Gulf region (Hormuz and Bab el-Mandab). In 2018, 27 million barrels of oil passed through these two chokepoints every day.
Source Authors’ elaboration on CIA
Oil chokepoints in the Middle East.
Gulf countries have enjoyed massive oil revenues thanks to their vast hydrocarbon resources and relatively small population. Thanks to the distribution of their conspicuous hydrocarbon rent, these countries have been able to put in place solid social contracts.
As already mentioned in Chap. 1 (Sect. 1.3), oil plays a pivotal role in the governance and politics of these countries, even though it is important to understand that this is true only for the most recent part of their history. Krane (2019a) highlights how before oil the main feature of the Arabian Peninsula was isolation. The ascent of Islam in the V century AD, and centuries later (XX century AD) the advent of oil, have put the Arabian Peninsula in the world’s political map. Before the rise of the present monarchies in the XX century, people in this area were organized under a system of tribal rule. As Britain expanded its interests in the Gulf, it became mandatory to overcome the ill-defined tribal rule as a way to protect British interests in the region. Britain thus created clear political institutions, providing political and financial backing to sheikhs who were in favor of and followed the terms of the Queen’s treaties (Krane 2019a). This allowed the creation of the hereditary sheikhly rule. The Gulf sheikhs extended control over their territories and a consequence was the settlement and loyalty of nomadic tribes. After the end of British control, the monarchies developed strong governing institutions and remained politically stable throughout the following decades, albeit with some differences, as described here below.
Oil has contributed to the integration of this area with the rest of the world, prompting significant socioeconomic development. Benefiting from their vast hydrocarbon resources and small populations, Gulf countries have experienced a generally high wealth level per capita, with a GDP per capita (PPP) ranging between $12,389.2 (Iran) and $90,043.8 (Qatar).
Gulf countries have in general experienced a high degree of political stability over the last decades. In the aftermath of the Arab Spring, GCC countries in the MENA region were the least affected by revolts and social unrest. The only exception was Bahrain, the worst-off among GCC countries, which holds the smallest hydrocarbon reserves and oil revenues to redistribute to the population, which is starkly divided between a ruling Sunni minority and a vast Shiite majority (Map 3.2). Saudi Arabia and Oman also experienced some protests in 2011, but to a lesser extent.
Source CASSINI
Religious distribution and energy resources and infrastructure in the Middle East.
A major driver of the revolts in the region is the unequal redistribution of the oil rent and benefits among the population, as we will analyze in the specific case of Saudi Arabia. Following these protests, governments in most GCC countries sharply increased their direct cash transfers and public sector wages to nationals.
Iran has also experienced numerous protests during the last decade, especially since the 2009 presidential elections. Overall, Iran is a different type of rentier state compared to most GCC countries, mainly due to its large population. Afflicted by international sanctions, Iran has made considerable investments in non-oil related industries, especially manufacturing, in order to satisfy its citizens’ requests for a better standard of living. Over the years, the private sector has significantly developed and it has become a lifeline for the country amid sanctions. For instance, in 2019–2020, the exports of the private manufacturing sector (roughly $41.3 million) exceeded oil exports.
All in all, a small or unequal redistribution of oil revenues is one of the main drivers of social instability, threatening the political power in place. Thus, the need of these countries to gradually change in order to keep their political status quo is enhanced by volatile and low oil prices, coupled with the (likely) decreasing role of oil in the global energy system in the future.
1.1 Saudi Arabia
Oil might stand as a synonym for Saudi Arabia. The Kingdom of Saudi Arabia holds 17% of the world’s proven petroleum reserves and is the world’s largest oil exporter. The hydrocarbon sector plays a paramount role in the Saudi economy, accounting for 70% of the Kingdom’s exports and 50% of its GDP (OPEC 2019a). Figure 3.2 presents the historical oil production and demand evolution of Saudi Arabia. Between 1980 and 2015, oil demand grew by an average of 6%/y.
Source Authors’ elaboration on ENERDATA
Saudi Arabia’s oil production, consumption 1980–2019, Mt (left), mb/d (right).
In the early 1980s, Saudi oil production declined significantly as Saudi Arabia played the role of swing producer trying to keep up its oil prices, and deciding to leave the administered pricing system in 1985 (Chap. 5, Sect. 5.1.1). However, in the second half of the 1980s, Saudi Arabia’s oil production swung progressively back to around 8 mb/d, a level it kept throughout the 1990s. These 15 years were years of low oil prices which therefore pushed up world demand. Indeed, during the 2000 and 2010 decades, when global oil demand increased strongly in particular due to China’s strong economic growth rates, Saudi Arabia further increased its oil production, which amounted roughly to 10–11 mb/d during the 2010 decade. Over the same period, crude oil production increased by 18%. This higher production level was needed to satisfy both the increasing domestic and international demands. The difference between production and domestic consumption is what Saudi Arabia can export. With exports of around 7 mb/d, Saudi Arabia is by far the largest oil exporter in the world.
At the same time, Saudi Arabia is one of the largest gas producers worldwide (113.6 bcm in 2019). However, the entire gas production is used to satisfy the country’s internal demand, leaving no room for gas exports.
The Saudi National Oil Company, Saudi ARAMCO, owns and operates Ghawar, the largest conventional oil field worldwide (discovered in 1948, it accounts for roughly a third of the cumulative oil production of Saudi Arabia as of 2018), with 48 billion barrels in reserves and a daily production of nearly 4 million barrels, as well as Safaniya, the largest offshore oil field in the world, with 37 billion barrels in reserves and a daily production of up to 1.3 million barrels.
Besides its vast oil resources, Saudi Arabia can also benefit from low production costs. It is often affirmed that Saudi Arabia has the lowest oil production costs in the world, with some estimates below $3 per barrel (Al Jazeera 2020a). That figure may be true for old oil fields, which however face declining production levels. New oil fields will inevitably be developed at higher production costs, albeit remaining competitive compared to other global oil producing areas. Saudi Aramco declared an average upstream cost per barrel of $7 per boe (Saudi Aramco 2021). In any case, Saudi Arabia is traditionally considered the world’s oil supplier of last resort due to its vast and cheap reserves, meaning that it is potentially able to produce and supply oil as long as anyone is willing to buy it.
Hydrocarbons play a pervasive role not only in Saudi GDP and export revenues, but also in its energy mix. As in other MENA countries, the availability of vast and cheap fossil fuel resources has shaped the Saudi energy mix. In the total primary energy supply (TPES) (213.6 Mtoe in 2018) the share of oil amounts to 63% while the share of gas represents 37% (IEA 2018a), while other sources, namely solar and biomass, play a very marginal role (Fig. 3.3).
Source Authors’ elaboration on ENERDATA
Total primary energy production of Saudi Arabia, 1990–2019 Mtoe.
A relevant development in the Saudi energy sector is the evolution of the power sector, which has evolved over the past decade both in terms of growth and fuel mix (Fig. 3.4). Power generation has increased by an annual average of 6.4% since 2005. However, between 2000 and 2015, power generation has grown by 7% per year (which means doubling every ten years!), while since 2015 it has drastically slowed down (1% per year) due to the economic crunch following the fall in international oil prices. In terms of fuel mix, the Kingdom decided to strongly expand its natural gas production and installation of gas-fired generation since 2016. Back then, oil-based liquid fuel covered more than half of the power generation feedstock needs. In 2019, Saudi Arabia had a total capacity of 86 GW, which is almost entirely thermal (53% oil and 46% gas). Saudi electricity generation (357.4 TWh in 2019) was dominated by gas (206 TWh, equivalent to 58% of the total) and oil (147 TWh, i.e. 42% of total), while renewable energy sources still play a very modest role (less than 1%) (BP 2020).
Source Authors’ elaboration on BP
Saudi Arabia’s electricity generation by source, 1985–2019, (TWh).
Prior to the 1980s, Saudi Arabia had only a limited interest in gas production, resulting in a high flaring rate of its associated gas from crude oil production. This approach drastically changed as the government invested massively in gas infrastructure to utilize its gas output. In the past two decades, gas output has risen significantly from 47.3 bcm in 2000 to 113.9 bcm in 2019 (BP 2020). Natural gas is expected to play an even more important role in Saudi electricity generation as the deployment of renewable energy sources (RES) in the Kingdom faces several limits and barriers despite their great potential (Chap. 4, Sect. 4.2.1).
A peculiarity of Saudi electricity is the large use of crude oil for power generation. Indeed, Saudi Arabia is the biggest user of crude oil for power generation worldwide. Burning unprocessed oil results in significant economic loss since crude oil could be refined into much higher value oil products with a very high valorization on international markets, while for power generation the much lower value of the fuel oil component would be largely sufficient. Over the last years the usage of unprocessed crude oil for power generation has, however, strongly declined and at the same time a strong shift to natural gas has been implemented. But still in 2019, out of 2.6 mb/d of oil used for power generation, Saudi still burned 0.43 mb/d (16.5%) of unprocessed oil. In 2015, its average use of crude oil in power generation peaked at 0.9 mb/d (i.e. 26% of the 3.4 mb/d of the oil used for power generation that year) (Al Ghamdi 2020).
Like other Gulf countries, Saudi Arabia consumes a significant amount of oil (40.4 barrel per capita per year), which leads to a lower economic gain and a higher environmental footprint (Fig. 2.6 in Chap. 2).
Since its growing domestic energy demand may erode its profitable export volumes, Saudi Arabia has also considered developing and harnessing its solar and wind potential to satisfy its domestic needs. Saudi Arabia holds a great potential in renewable energy sources, especially solar, which is however still largely untapped. In 2019, renewable energy sources accounted only for 0.3% of the Saudi energy mix. Saudi Arabia has set several targets throughout the years. In 2013, the King Abdullah City for Atomic and Renewable Energy (K.A. CARE) announced ambitious plans to develop solar power, reaching 41 GW, 17.6 GW of nuclear power thanks to 16 nuclear power plants, and 9 GW of wind power by 2032 (Krane 2019b). During the second half of the 2010 decade, however, these plans were cut down due to low oil prices and political commitment. Saudi Arabia now plans only two nuclear power plants of 1.4 GW each. The renewables target has been reduced to a modest 3.45 GW of renewables capacity by 2020 and 9.5 GW by 2023. In 2020, Saudi Arabia has a total installed renewable capacity of 413 MW. Despite the challenges, natural gas and RES can play a more important role in the foreseeable future, allowing Saudi Arabia to free additional oil volumes for export from the domestic market, resulting in higher revenues.
Most of Saudi oil flows through the Hormuz Strait heading to Asia (69% of its total oil exports in 2019). In 2019, Saudi Arabia exported 415.8 Mt of crude and oil products and its main markets were China (86.8 Mt, i.e. 21% of total exports), Japan (53.9 Mt, 13%) and India (50.7 Mt, 12%), while it exported 56.4 Mt (14% of total exports) to Europe. Due to political hostility, Saudi Arabia fears the closure of the Hormuz Strait by its regional nemesis, Iran. For this reason, Saudi Arabia has tried to enhance alternative export options, in particular through its East–West pipeline. This pipeline has a total capacity of 5 mb/d and brings Saudi oil from the Eastern province to the Red Sea Yanbu port. Yet, Saudi still depends largely on the Hormuz Strait for most of its oil exports, leaving political and security risks as Chap. 5 Sect. 5.1.3 will analyze.
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Saudi energy companies
The Saudi energy market is largely dominated by state-owned companies. Saudi Electrical Company (SEC) is the vertically integrated power utility which holds the Kingdom’s monopoly of power supply. According to the Electricity Law of 2005 (issued by Royal Decree N. M/56), the Saudi electricity market aims at introducing competition. Unbundling is currently taking place, which should establish one transmission company, one distribution company and four generation companies, all regulated with a SEC holding company (Li et al. 2017).
Concerning oil and gas, Saudi ARAMCO is the well-known National Oil Company of the Kingdom. Its presence in the oil and gas sector dates back in time. Saudi Arabia was completely overlooked by British regional and oil interests, leaving the door open to a new company, Standard Oil of California, known as SOCAL (now Chevron). In 1933, SOCAL signed a 60-year concession agreement with the new Saudi king, Ibn Saud, who was eager to receive money in exchange of concessions. A subsidiary company, called California Arabian Standard Oil Company (CASOC), was created to manage the agreement. SOCAL initially did not have any major discovery success; thus, it decided to share the risks with one of the major American oil companies, Texaco. In 1944, the company changed its name to Arabian American Oil Company (ARAMCO). However, the two companies decided to include other companies in the development of the concession agreement and secure capital. The Saudi king insisted that Aramco remained 100% American. Thus, they identified Standard Oil of New Jersey (then Exxon) and Socony Vacuum (then Mobil) as the two new partners. SOCAL and Texaco held 30% each of Aramco, while Standard Oil of New Jersey purchased 30% and Socony Vacuum 10% of the company. In 1948, the first well was drilled in the supergiant Ghawar field, which is considered the biggest oil field in the world. Several decades and stages of development were required to realize the extent of this reserve, which is really a network of five fields. Already in the 1950s, ARAMCO was able to produce 500,000 barrels per day also thanks to an increasing oil demand. A couple of decades later, in 1973, Saudi Arabia bought 25% interest in ARAMCO, which increased to 60% the following year. Finally, in 1980, the Saudi government acquired full ownership of ARAMCO and in 1988 the name was changed to “Saudi ARAMCO”. This company was a precursor of the “Saudization policies” carried out in the 2010s by the Kingdom. In fact, by 1989, all senior executives and 73% of the workforce were Saudi nationals (ARAMCO Museum, Dhahran), but at the same time the Government was clever enough to persuade a large number of American and international expats to keep on working at Saudi Aramco—of all NOCs, Saudi Aramco is often referred to as the best. Since the early 1990s, Saudi ARAMCO has formed joint ventures in Asia, Europe and North America, and in 1993 a Royal Decree merged Saudi Arabia Marketing and Refining Company with Saudi ARAMCO, integrating the Kingdom’s petroleum activities. In the 2000s, it considerably increased its gas activities, thanks to, for instance, the Hawiyah Gas Plant which began production, boosting Saudi’s gas supplies by more than 30%. Today, Saudi ARAMCO is regarded as one of the world’s most profitable companies, generating $88.2 billion in net income in 2019, a 22% decrease compared to the previous year (Gambrella 2020). In 2018, it decided to disclose for the first time the accounts in preparation for the IPO of 1.5% of the company, which took place in December 2019. It was traded only on the Saudi stock exchange, Tadawul. In December 2019, the IPO raised a record $25.6 billion, by selling 3 billion shares at SAR32 ($8.53) per share (Gross 2019). In January, an additional 450 million shares were sold, increasing the size of the IPO to $29.4 billion (Reuters 2020). The goal of the IPO is to raise capital vital for the diversification strategies enacted by Saudi Arabia, since the current socio-economic system may not be sustainable in the long run.
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The unsustainability of the rentier state: an economic and energy perspective
Saudi Arabia experiences all the pains and gains of the classic rentier state. The Saudi debt (as a percentage of GDP) changes in relation with the fluctuations of oil prices. In 2014, when oil prices were rather stable and over $100 per barrel, the country’s debt reached its lowest level (1.5% of the GDP). Since the fall of oil prices in 2014, Saudi Arabia has seen its debt expanding. This condition reached a new peak with the unprecedented crisis in 2020 caused by the Covid-19 pandemic. In that year, oil prices plummeted below $20 per barrel, reaching an 18-year low for Brent crude. To tackle oil prices volatility, Saudi Arabia used its large foreign reserves to preserve the social welfare for its citizens. In March 2020, oil prices fell at the fastest rate in the last 20 years with a monthly drop of nearly $27 billion, reaching the lowest point in the last 19 years (Barbuscia and Rashad 2020).
In 2020, Saudi Arabia started also a price war with Russia following the fallout in the OPEC + meeting in March 2020. The Kingdom showed its unique capacity to increase oil production on very short notice, as it promised to reach 12.3 million barrels per day in April 2020, thus increasing its ability to export greater oil volumes. This ability, however, may be hindered over time due to the steep rise in domestic energy demand. Indeed, the internal electricity demand grew at a rate of 5% per year between 2010 and 2018 and it is expected to increase by 8–10% yearly to 2032 (Khan and Salam 2018), due to an annual population growth of 2.62% (2010–2018), an annual average GDP growth of 3.81% (2010–2018) (The World Bank 2020a, 2020b) and the expected localization of numerous industries in the country. All these factors contribute to a growing water demand, which relies for 60% on energy-intensive desalination plants, increasing the electricity demand even further (IRENA 2019). Overall, Saudi Arabia is the 13th largest energy consumer in the world, ahead of countries with considerably larger populations and economies (i.e. Canada, Germany). Other key factors also contribute to the Kingdom’s high energy consumption.
Saudi Arabia’s harsh environment (temperatures reaching 50 °C in summer, resulting in high consumption of air conditioning) and water scarcity also partly explain the elevated use of electricity. Another important factor regards the generous energy subsidies in place in the country, which hinder energy efficient measures. These subsidies also represent a fiscal burden for the government, since they amounted to $80 billion (11% of the country’s GDP) in 2012. Thus, Saudi Arabia planned and started to implement their gradual reduction. While the, energy subsidy reform is not yet complete at the time of writing, already in 2018 total energy subsidies had been partly decreased and amounted to less than 6% of Saudi GDP. Indeed, since 2015, Saudi Arabia has significantly increased tariffs for all fossil fuels. Energy-intensive industries, the most developed in the country, were the most affected since they felt threatened in terms of competitiveness. Also, in 2015, households were impacted by a substantial increase in energy tariffs, especially in terms of transport fuel and electricity prices. Though low consuming households (< 4000 kWh) were exempt from the price increase, middle (4000–6000 kWh) and high (> 6000 kWh) consuming households saw a price increase of $0.05/kWh and $0.08/kWh, respectively (APICORP 2018). However, these new retail prices still do not cover production costs, since the Kingdom also raised the prices of the fuels employed for generating electricity. Despite the unpopularity of the subsidy reforms, which led to an inflation spike, the government explicitly set the goal of zero electricity subsidies by 2025. Table 3.3 summarizes the main drivers leading to an astonishingly high and rising energy demand.
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The unsustainability of the rentier state: a socio-political perspective
Oil is predominant also in the socio-political sphere. A high and fairly equal redistribution of oil revenues within the framework of a rentier economy is key to social stability. Indeed, Steffen Hertog argues that regions with a more coherent regional identity, such as the central ones, receive the highest contributions thanks to their ability to organize around such identity (Haykel et al. 2015). The South, which is very similar to the center, but has developed a less cohesive identity, suffers the most. Concerning the Eastern Province, Hertog states that this region has enjoyed fewer contributions since it was not able to draw on regional identities, but rather on town-based ones (Haykel et al. 2015). Therefore, it was not the Eastern Province that was specifically discriminated against for religious/sectarian divide (inhabited predominantly by Shi’a), since there are other regions in the Kingdom, inhabited by Sunni Saudi nationals, that also suffer from unequal redistribution of resources (Haykel et al. 2015). The town-based identity argument is in line with Alamer research (Al Rasheed 2018), which focuses on the reasons why this region has seen the largest number of protests against the political regime in place, going beyond the dichotomy of the Sunni-Shi’a divide. He argues that the presence of strong town-based identities, dating back before the establishment of the Saudi state, paved the way to the formation of a homogenous and well-organized group, such as in Qassim, which experienced the highest number of protests. The strengthening of the town-based identity in Qassim was facilitated by its location: it is close enough to oil fields so that its inhabitants go to work and come back every day, but far enough so that migrants, as well as Saudis coming from other towns or regions, do not move here, preferring to reside closer to the oil fields.
Building on this argument, political mobilization and oil prices are positively correlated in the Kingdom. In fact, the Gregory Gause III shows that political mobilization occurs mostly during periods of high prices, since in times of low oil prices the government increases the level of subsidies and of general redistribution to the population (Haykel et al. 2015). The author concludes that Saudi Arabia presents a “rentier exceptionalism” because mobilization does not happen when oil prices drop, as is usually the case (Haykel et al. 2015). This policy also contributes to the unsustainability of the rentier economy in the Kingdom, arising especially from the volatility of oil prices due to the oil dependence of the Saudi economy. Until King Salman and his son, the current Crown Prince Mohammed bin Salman, came to power in 2015, periods with very low oil prices were coped with by spending and borrowing. Recently, various methods, such as selling a $17.5 billion bond in 2016, were employed, but new strategies, such as Vision 2030 and the National Transformation Program (NTP), have also envisaged a decrease of subsidies and the introduction of VAT (Al Rasheed 2018).
As the world is expected to decarbonize and consume less oil, Saudi Arabia may experience lower income from oil rents. Therefore, its “rentier exceptionalism” may need to change. A small taste of potential future challenges occurred in 2020, when the Kingdom suffered from low oil prices caused by the effects of the Covid-19 pandemic. In May 2020 the Saudi government decided to raise the VAT from 5 to 15% starting from July and to cut the cost-of-living allowances for public employees by SAR 1000 ($267), in response to record low oil prices and the effects of the corona virus lockdown (Bostock 2020). New austerity measures mean lower revenues for citizens, which could further stress the weaknesses of the current social contract.
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The example of ARAMCO adaptation to the changing Saudi context
Saudi ARAMCO, the national oil company, has significantly contributed to Saudi Arabia’s economic and social development, and it has ensured stability through the social contract by becoming one of the main actors in the global energy system. It may be described as the “economic star” of Saudi Arabia. Recently, ARAMCO had to outline new strategies in order to adapt to and enhance its resilience in response to the changing energy context.
The following section analyzes the new strategies of ARAMCO in order to remain at the forefront of the global energy system and to strengthen the economic sustainability of the Saudi energy sector in the mid-long term.
ARAMCO horizontal diversification strategy for a flexible adaptation
Regarding horizontal diversification, namely diversification strategies within the energy sector, ARAMCO has made strong investments in activities with a forecasted high growth in the coming years, such as gas and petrochemicals/refineries both in Saudi Arabia and abroad. As a matter of fact, OECD countries are forecasted to externalize petrochemical activities in order to be in line with their decarbonization policies and targets. However, worldwide petrochemical demand is expected to increase in the coming decades and to account for more than a third of oil demand growth in 2030 and roughly 50% in 2050, according to the 2018 IEA report on the future of petrochemicals (IEA 2018b). Thus, ARAMCO is also making large investments in refining activities: in 2019, it set a goal to increase its refining capacity from 4.9 billion barrels per day to 10 billion barrels per day by 2030 (Dipaola 2019). By predominantly investing in Asia, the Kingdom manages to adapt these refineries to the quality of Saudi crude, managing to maintain and enhance its market share. A primary example includes ARAMCO’s acquisition of 20% of stakes of the Indian Reliance Industries’ refining and petrochemical business, which amounts to one of the largest foreign investments in India (Mukherjee and Ulmer 2019). Moreover, this strategy has had an important development also at home. In March 2019, Saudi Aramco announced the acquisition of a 70% stake in the country’s petrochemicals giant, SABIC, from the Saudi sovereign wealth fund (SWF), Public Investment Fund (PIF). The deal is of considerable relevance and scale: the purchase price amounted to $69.1 billion and SABIC is the fourth largest chemical company for sales. It usually employs natural gas to produce its chemicals, while Aramco employs liquids derived from crude oil (Seznec 2020). With this merge, ARAMCO is striving to expand also in the chemical downstream activities, coupled with the natural gas and general downstream (refineries etc.) sector to become a world player in numerous fields. Moreover, by focusing on non-combustion activities of oil and gas, ARAMCO is able to reduce its vulnerability with respect to decarbonization policies as well as to financially contribute to the economic and social diversification strategy through the PIF.
Regarding energy-related fields, ARAMCO, through its subsidiary Saudi Aramco Energy Ventures (SAEV) is aiming to invest in R&D regarding hydrogen fuels, higher efficiency for internal combustion engines, limiting carbon emissions and CCS technology for cleaner mobility in Saudi Arabia. SAEV is expected to launch a $500 million fund for renewable projects and energy efficiency (Pyper 2020). Moreover, SAEV is exploiting venture capital to help minimize CO2 impact in the oil and gas sector, which is one of the main strategies of ARAMCO nowadays. For instance, by also investing in Zouk, a European equity fund for clean-tech startups, ARAMCO is acquiring expertise in related fields, which might generate an increasingly added value in the coming decades (Pyper 2020).
ARAMCO contributes to the diversification of the Saudi energy mix
ARAMCO is also striving to expand its trade and activities in the gas sector. ARAMCO has always been the only gas provider for domestic consumption in Saudi Arabia, in particular for water desalination and high energy-intensive industries (steel, aluminum etc.). As aforementioned, despite being the 8th largest gas market worldwide, high domestic internal gas consumption hinders gas exports. Therefore, Saudi Arabia has recently embarked on new large development projects in order to have a global outreach also in the gas market, such as Hasbah, Hawiyah and Marjan. Moreover, the Kingdom is also developing megaprojects in new areas, including the Jafurah shale development, which is expected to come online in roughly 2025 (IEA 2020). In May 2019, ARAMCO signed with the US company Sempra Energy a 20-year contract stipulating that it would buy 5 million tons of LNG per year. Moreover, it has also acquired a 20% equity in an LNG facility, currently under construction in Port Arthur, Texas (Bussewitz 2019). Nevertheless, due to the consequences of Covid-19, ARAMCO is reviewing its LNG investment plan in Texas. The stand-by of numerous new projects is in line with ARAMCO’s current strategy to cut investments in new projects, while keeping investing in its assets and focusing on upstream oil and gas projects. Indeed, investments were downgraded from a $40 billion target to $25 billion, with possible further decreases (Ratcliffe et al. 2020). Similarly, Saudi Arabia put on hold its plans to enhance its refinery capacities and petrochemical activities worldwide. For instance, in August 2020 ARAMCO suspended a $10 billion petrochemical project in China while in July 2021, it appeared to have put on hold the expansion of its petrochemical activities in Port Arthur, Texas (Faucon and Said 2021).
Saudi ARAMCO has increasingly looked into opportunities in the LNG sector, especially in the Asian markets. However, Saudi Arabia ought to deal with challenging conditions both at the domestic and international level. Domestically, the development of new gas fields comes with higher costs. Moreover, Saudi Arabia has prioritized the use of gas domestically in order to free additional oil export volumes. Internationally, Saudi Arabia would be a late comer, while other LNG exporting countries have better economic conditions to consolidate their power.
To conclude, economic diversification has become a priority for the Kingdom to ensure its socio-political and economic sustainability. In 2016, it published “Vision 2030”, a document comprising targets and objectives in numerous fields to reduce reliance upon oil for revenues, envisaging, for instance, quite ambitious targets for renewable energy capacity. Saudi ARAMCO is already adapting to the new global context in order to try to remain at the front of tomorrow’s global energy system.
1.2 UAE and Qatar
Qatar and the UAE share numerous characteristics in various fields. Both countries extend over relatively small territories, (Qatar area: 11,437 km2 and UAE area: 83,600km2), they are aviation (Qatar Airways, Emirates in Dubai and Etihad in Abu Dhabi are some of the most renowned airlines worldwide) and events hubs (Expo 2020 in the UAE and 2022 World Cup in Qatar). Also, in the demographic sphere, non-nationals make up the great majority of the population, representing 87% of the total population in both countries (Gulf Labour Markets and Migration 2019). Similarly, in the energy sector, both the UAE and Qatar are heavily reliant on gas, which represents 88% and 94% of total primary energy supply (91.4 Mtoe for UAE and 50.6 Mtoe for Qatar) and 98% and 100% of power generation, respectively (138.4 TWh for UAE and 49.8 TWh for Qatar) in 2019 (WEO 2021; IEA 2018c, d).
Before diving into the similarities and differences between Qatar and the UAE, it must be remembered that although the UAE is taken as a whole, it consists of a federation of seven semiautonomous sheikhdoms (or emirates): Abu Dhabi, Dubai, Sharjah, Ajman, Umm al-Quwain, Ras al-Khaimah, and Fujairah. The federation was initially formed in 1971 when the emirates became independent from the British empire, and achieved the present formation in 1972 following Ras al-Khaimah’s reluctant join. Within the federation, Abu Dhabi and Dubai are by far the most important emirates. However, these two emirates present major differences in their economy and political power. While Abu Dhabi is rich in oil and gas (holding 93% of the UAE’s oil and gas), Dubai is a post-oil economy. Abu Dhabi is the political and petroleum powerhouse of the UAE. Abu Dhabi and Dubai are the most influent emirates in the federation, holding key cabinet posts and economic relevance (Abu Dhabi with its oil and gas reserves, Dubai with trade and real estate). Power and authority in the UAE are shared between the federal and emirate levels and apportioned among the seven emirates based largely on population size. While nineteen issues (including foreign affairs, defense, finances, education, and health) are under federal government responsibility, the constitution allows each emirate to exercise sovereignty over issues not under federal jurisdiction. In this way, Abu Dhabi managed to retain control over its own oil and gas reserves (Ulrichsen 2020). For such reasons, in several occasions the two emirates had disagreements. They underwent several crises due to a rift over the degree of federal power and oversight; with Dubai in favor of a looser arrangement, whereas Abu Dhabi for a closer integration (Idem). Especially in the 2000s, Dubai’s policy was strongly characterized by unilateralism, with decisions taken with little coordination with the federal government. The result was a less coherent UAE foreign policy.
The following section will analyze firstly the major differences between Qatar and the UAE in the energy sphere, such as energy security and diversification of energy sources, and then the main characteristics these two countries share in the energy sector.
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Differences in the energy sector: energy security and diversification of energy sources
Stark differences between Qatar and the UAE arise when analyzing more in depth the recent energy policies and the “sources” of natural gas, a key element of the energy mix of both countries. These two countries differ in energy security and in diversification of sources for their energy mix and power generation.
The UAE: energy security as a major driver for diversification of energy sources
The UAE holds significant oil and gas reserves (97.8 thousand million barrels and 5.9 tcm in 2019), which are almost entirely located in Abu Dhabi, and it is a major oil and gas producing country. It is member of the Organization of the Petroleum Exporting Countries (OPEC) and the Gas Exporting Countries Forum (GECF). The UAE mainly produces crude oil (around 3.1 mb/d) and a lower share of non-crude oil liquids (about 0.9 mb/d) (Fig. 3.5).
Source Authors’ elaboration on ENERDATA Global Energy & CO2 DATA
UAE’s oil production and consumption, 1980–2019, Mt (left), mb/d (right).
With a relatively small population (9.7 million people in 2019), the UAE is also a major oil-exporting country. Within the OPEC, the UAE is the third-largest oil producer behind Saudi Arabia and Iraq. It is committed to monetizing its vast resources, fueling growing tensions with the OPEC leader, Saudi Arabia. The UAE indeed announced its plans to increase its crude oil production capacity to 5 mb/d in 2030. In 2019, it exported 2.8 mb/d of crude oil, most of which went to Asia (93% of total exports) and primarily to Japan (30% of total exports).
The UAE’s total primary energy supply amounted to 91.4 Mtoe in 2019, with natural gas (71% of total TPES) gaining increasing relevance and replacing oil, especially in the last years (27%) (Fig. 3.6). Nonetheless, over the past years, the UAE has also increasingly used coal in its energy mix with a 2% share. At the same time the UAE has increased its effort in renewable energy sources, but with modest results.
Source Authors’ elaboration on ENERDATA
UAE’s TPES 1990–2019 Mtoe.
Its domestic electricity consumption has increased constantly over the last three decades from 14.3 TWh in 1990 to 125.7 TWh in 2019 (+7.8% on average annual growth rate). The power sector is nearly totally reliant on natural gas. That is why the UAE is striving to enhance its energy security. The UAE has increased its gas production from around 20.1 bcm in 1990 to 67 bcm in 2019. However, it has also experienced a growing gas consumption that forced the country to increasingly rely on LNG imports as well as gas pipeline imports to meet its domestic needs. The UAE became a net importer of natural gas in 2008 as UAE consumption exceeded production. However, Fig. 3.7 also shows the double nature of the UAE gas patterns. On the one hand, the UAE has exported constant gas volumes via LNG mainly to Asia, thanks to Abu Dhabi’s gas production and liquefaction plant. On the other hand, growing gas consumption has contributed to higher gas imports both from Qatar via pipeline and, since 2014, LNG using Dubai’s Floating Storage and Regasification Unit (FSRU) as well as a second FSRU-based import terminal in Abu Dhabi since September 2016.
Source Authors’ elaboration on ENERDATA
UAE’s natural gas production, consumption, imports and exports 1990–2019 (bcm).
The main route of gas supply to the UAE is through the Dolphin pipeline (Map 3.3), which connects Qatar with the UAE and Oman, providing one-third of the UAE gas supply. In 2010, Qatar and Dubai signed a contract whereby Qatar would sell gas via Dolphin pipeline at $2/MBtu until 2032. However, taking into account the geopolitical tensions between Qatar and the UAE, culminated in June 2017 with the embargo on Qatar by the Quartet (Bahrain, Egypt, Saudi Arabia and the UAE), it is unlikely that Qatar will renew the contract with the same favorable terms and prices. Also, given the high growth of electricity and water demand in the UAE, it might be quite challenging for this country to secure increasingly higher quantities of gas, given the current political stalemate with Qatar.
Source Authors’ elaboration
Dolphin gas pipeline connecting Qatar to the UAE and Oman.
The Dolphin pipeline currently satisfies more than one-fourth of the UAE’s gas supply. Had the UAE chosen to increase its LNG from other countries, it would have had to pay on average 3 times more, assuming 2017 gas prices. As a matter of fact, by importing gas through the Dolphin pipeline, the UAE is able to guarantee affordable prices, even if the electricity subsidies are decreased, as planned in Vision 2021. In short, the Dolphin pipeline has been a key factor for the Emirates’ security of gas supply, especially when taking into account IEA’s definition of security of supply as “uninterrupted availability of energy sources at an affordable price” (IEA 2019). Nonetheless, the UAE has increased its LNG imports especially in the aftermath of the crisis within the GCC. Such an increase was driven by the need to improve its security of supply.
Meanwhile, the UAE, through the national oil company Abu Dhabi National Oil Company (ADNOC) and joint ventures, has carried out major exploration activities for gas fields. Natural gas is expected to reach the target of 38% of the energy mix by 2050. However, Emirati gas production used to be rather low, and the newly discovered gas fields are usually rich in sulphur content so that the total costs for gas production and treatment for sulphur are expected to be quite high, standing at around $8/MBtu (IRENA and MASDAR Institute 2015). Nevertheless, in February 2020, ADNOC announced the discovery of 2.2 tcm of gas in Jebel Ali, on the border between the emirates of Dubai and Abu Dhabi, representing the largest gas discovery worldwide since 2005 (Meliksetian 2020). This gas field is shallower than most other gas fields in the UAE, leading to possible lower production costs, even though it is sour. Also, ADNOC, with Wintershall and ENI, is developing the Ghasha ultra-sour gas concession, which is expected to come in operation in 2025 (Saadi 2020).
In order to enhance its energy self-sufficiency, the UAE is striving to diversify its energy mix and power generation sources. To date, the UAE is the country in the cluster with the highest share of renewable sources (excluding hydro) in the energy mix for electricity generation, amounting to 0.4% of total electricity (IEA 2018c). In 2017, the UAE published the so-called “Energy Strategy 2050” with the aim of increasing the percentage of clean energy (intended as renewables plus nuclear) in the energy mix from 25 to 50% by 2050 (UAE Ministry of Energy and Industry 2017). In order to meet this objective, the UAE has made considerable investments in renewable mega-projects, such as the Mohammed bin Rashid Al Maktoum Solar Park, which is expected to become the world’s largest independent power producer in terms of capacity (5 GW by 2030) with a conspicuous investment of AED 50 billion ($13.61 billion). The first two phases of the project have been carried out in 2013 and in 2017, and they started operating with a capacity of 13 MW and 200 MW, respectively. In full operation, the Al Maktoum Solar Park is expected to meet 25% of the UAE’s internal demand for electricity from clean sources. Also, in 2013, the Emirate of Abu Dhabi, put into operation the largest concentrated solar power (CSP) plant in the world (at that time) named Shams 1, which provides electricity to roughly 20,000 households thanks to a capacity of 100 MW. It was developed and financed by Shams Power Company, a joint venture between the Emirati Masdar (60%) and a consortium composed of Total (20%) and Abengoa Solar (20%) (Masdar 2017).
Moreover, the UAE has not limited its diversification efforts to only solar and wind, but it has also launched the first nuclear energy program in the GCC, becoming the main frontrunner of the diversification of energy sources in the GCC. The UAE has begun the construction of a four-nuclear reactor power plant (5.6 GW), jointly developed by Emirates Nuclear Energy Corporation (ENEC) and Korea Electric Power Corporation (KEPCO). The plant entered commercial operation in 2021. Ahead of the COP26, the UAE reiterated its ambition to achieve leadership in the clean energy sources, announcing its ambition to achieve net-zero emissions by 2050.
Overall, in the medium-long term, the UAE energy security landscape is drastically improving, thanks to the newly discovered gas fields, the full operation of the Barakah nuclear power plant and of solar power mega-projects. Nevertheless, in today’s context, the country is still reliant on imports, the majority of which come from Qatar, which is not considered a closed ally anymore. Thus, from the energy security point of view, the UAE is committed to bringing online the new gas, renewable and nuclear projects as soon as possible, especially before the termination of the Dolphin pipeline contract in 2032.
Qatar: the global LNG powerhouse
Qatar stands out among the GCC countries, as it holds a special place in the global gas market rather than in the oil market. The small emirate has focused on LNG exports rather than oil, benefiting from its vast reserves based on the giant field, North Dome—shared with Iran. These reserves and strategy allow Qatar to be the world leading player in the LNG industry. In fact, it holds the third largest gas reserves after Russia and Iran and it has very low production costs.
In 2019, Qatar holds 24.7 tcm of natural gas reserves, accounting for around 12.4% of the world’s total gas reserves. The turning point for Qatar’s gas production was 1996 (Fig. 3.8). Until then, its entire gas production was consumed domestically. After that year, Qatar’s growing gas production has aimed at exporting LNG. Indeed, the country entered the LNG sector in 1996 when it launched its first LNG train. Since then (4.3 bcm per year), Qatar’s LNG capacity has expanded rapidly, reaching a production capacity of 101 bcm per year in 2009–2010.
Source Authors’ elaboration on ENERDATA
Qatar’s gas production and consumption, 1980–2019, bcm.
Qatar has been able to expand its LNG industry thanks to the vital contribution of the IOCs (ExxonMobil, Total, Japanese Marubeni and Mitsui as well as Shell) in terms of both technology and expertise. Growing production volumes combined with a small population has allowed Qatar to consolidate its status as the world’s top LNG producer and exporter. In 2019, Qatar accounted for 22% of the world total LNG production—the highest global share by a single country (GIIGNL 2020). The bulk of Qatar’s exports are via LNG—with a smaller share via pipeline to UAE and Oman. In 2019, it exported 107.1 bcm via LNG and the main destinations are located in Asia (67% of total exports) and Europe (30% of the total) (BP 2020). The largest buyers are China, India, Japan and South Korea. Meanwhile, Qatar has also exported its gas through the Dolphin pipeline to UAE and Oman.
Prior to 2017, there were two main companies, Qatargas and RasGas, operating in the LNG sector. The state-owned Qatar Petroleum had a majority stake in Qatargas and in other international companies, such as Total and Mitsui &Co, and owned small stockholdings, while RasGas consisted of a 70/30 joint venture between Qatar Petroleum and Exxon Mobil, respectively. At the end of 2016, the chief executive of Qatar Petroleum announced the merger of the two companies into one company, named Qatargas. This merge established the largest LNG producing company in the world, which also produces helium and other derivatives, with a capacity of 77 million tons (Qatargas n.d.). This choice was predominantly dictated by the desire to take advantage of the economies of scale and to better coordinate and counteract the increasing competition from other LNG exporting countries. In fact, in order to remain a leader in the LNG market share, Qatar has to increase its investments in this sector to counteract fierce competition, especially from Australia, Russia and the United States (Fig. 3.9). Therefore, in April 2019, Qatar Petroleum invited bids from three joint ventures to develop a massive expansion project for the North Field, which is planned to be completed by 2024.
Source Authors’ elaboration on BP (2020)
LNG export volume by world’s largest LNG exporting country, 2000–2019, bcm.
This move marked a sharp change in Qatar’s approach to its LNG industry and natural gas resources management. In 2005, it established a self-imposed moratorium on the development of the North Dome in order to preserve its resources for future generations, and to understand the effect of the field’s rising output on the reservoir. In 2017, Qatar decided to lift the moratorium in response to the growing international competition in the LNG industry. Qatar expects to boost output in the North Dome in order to increase LNG production by 64%, from 77 million tonnes per annum (Mtpa) in 2019 to 126 Mtpa in 2027.
Qatar’s LNG exports increased significantly between 1997 and 2011, when they stabilized at slightly above 100 bcm (77 Mt). Until 2010, Qatar’s LNG exports were divided almost equally between Europe and Asia; however, in 2019, the largest share (67%) flew to the energy-hungry Asian markets, with the main markets being South Korea, India and Japan.
Qatar feels pressure also in terms of pricing mechanisms. The US LNG has contributed to foster spot and gas prices. However, Qatar has been one of the strongest supporters—along with Algeria—of long-term contracts based on oil indexation. Oil indexed long-term contracts still represented around 60% of the exports in 2019. It considers them a more predictable and reliable mechanism for those involved in the industry. However, the US LNG has substantially changed the global LNG market, fostering the use of spot prices. Despite buyers’ growing renegotiation calls, Qatar has remained extensively committed to oil indexation.
Along with the expanded production of natural gas since 2000, Qatar has also managed to increase its production of liquids, such as condensate LPG and NGLs, which are a significant and valuable byproduct of natural gas. Around 50% of the oil production in Qatar is related to NGL production (Fig. 3.10). However, total oil production (crude oil plus natural gas liquids) underwent an up and down during the last two decades. Until 2013 it increased, reaching 80 Mt in 2013. Since then, total oil output declined to 71 Mt in 2019, and 60% of Qatari oil production is exported.
Source Authors’ elaboration on ENERDATA Global Energy & CO2 DATA
Qatar’s production of crude oil and natural gas liquids 2000–2019 (Mt).
Qatar produces less oil than its regional peers, especially Saudi Arabia and the UAE, but it is by far the largest MENA gas (mainly LNG) exporter. In December 2018, Doha announced its decision to exit from OPEC. The move could have a political motivation as Qatar intends to distance itself from Saudi Arabia, the de facto leader of OPEC, especially following the 2017 blockade on Qatar. With only 600,000 barrels per day of crude oil output in 2017, Qatar accounted for less than 2% of OPEC’s crude oil output. In recent years, small producers held little power in the cartel. This decision will be analyzed in more depth in Chap. 5 (Sect. 5.1.2), but the move was driven by political considerations and it was also based on the strong belief that natural gas will have a rosier future than oil and coal in light of the global energy transition.
Given its vast gas reserves, Qatar’s total primary energy supply relies significantly on natural gas (Fig. 3.11), in particular following the massive investment in gas production in the 2000s, which has also allowed Doha to become the world’s top LNG exporter. The country’s TPES is therefore heavily reliant on natural gas (around 88% of TPES in 2019), with the rest being oil. Qatar’s TPES is thus not very diversified, relying exclusively on gas and oil. Like other MENA countries, it has increased significantly from 6,558 Mtoe in 1990 to 43,408 Mtoe in 2019, i.e. an average annual growth rate of 6.7%. The strong growth is also due to its important industrial sector (in particular its LNG, refining, petrochemical, desalination, and gas-to-liquids complexes) which are very energy-intensive.
Source Authors’ elaboration on ENERDATA
Qatar’s TPES, 1990–2019, Mtoe.
Natural gas also dominates Qatar’s electricity capacity, which is nearly 100% gas-based. The country’s total installed power capacity stands at 14.5 GW, after having been increased by 2.5 GW in 2019 with the commissioning of the Umm Al Houl gas power plant. Electricity production (49 TWh) is all gas-based and has increased by 9.7% per year between 2005 and 2018.
Overall, Qatar has so far had no incentive to diversify its energy mix and power generation sources, since it is endowed with natural gas, which is used to satisfy its domestic energy demand and water desalination plants. Renewables thus play a very minor role in Qatar’s energy policy. The only targets set in the renewable energy field (the Qatar National Development Strategy 2018–2022) envisaged the commissioning of 200 MW of renewable energy by the end of 2022. This target has already been outpaced thanks to the commissioning of a 350 MW solar PV plant in 2021. This capacity will be increased to 500 MW at an indefinite and future point in time (The State of Qatar 2018). Nevertheless, in 2021, Qatar Petroleum set a 4 GW renewable target by 2030 in its Sustainability Strategy (Ingram 2021). A detailed analysis on this subject will be conducted in Chap. 4, which is devoted to renewable targets and their possible attainment. However, Qatar’s lower economic and strategic need to develop renewable energy, with respect to the UAE, is further demonstrated by the lack of specific renewable targets for the energy sector in Qatar’s National Vision 2030 (General Secretariat of Development Planning 2008).
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Energy subsidy reforms: some similarities
Qatar and the UAE have carried out thorough energy subsidy reforms, motivated by the fast-growing electricity demand, which has grown by 8% per year between 2006 and 2016, one of the highest rates in the world. In recent years it was slightly below 6%, but it is still very high. Both countries share the need to curb electricity, fossil fuel and domestic water demand due to numerous common peculiarities. In fact, they experience not only high energy consumption growth rates, but also robust population growth, especially of non-nationals, due to the labor-intensive structure of the countries’ labor markets and their migration policies. Moreover, the localization of industries within the countries, a key policy for economic diversification from hydrocarbon revenues and export, boosts domestic electricity demand. Decreasing water demand is also crucial since both Qatar and the UAE rely for more than 90% of their household and industry water consumption on energy-intensive seawater desalination plants (IRENA 2019). The roll out of water and energy subsidy reforms played a crucial role in the steep decrease in electricity and water consumption in Qatar and the UAE.
Qatar implemented electricity subsidy reforms between 2015 and 2017, increasing its electricity prices from 2.16 US cent per kWh to 2.43 US cent per kWh only for expats (Krane and Monaldi 2017). Indeed, Qatar is the last GCC country to provide free electricity and water to its nationals (Hussein and Lambert 2020). Regarding energy sources, natural gas subsidies fell from $950 million in 2015 to $493.1 million in 2017 (Krane and Monaldi 2017). Overall, Qatar substantially reformed total energy subsidies, including oil and gas, aiming at decreasing government expense from $3 billion in 2015 to $1.5 billion in 2017, representing 0.9% of the country’s GDP, significantly lower than most other GCC countries (Kahramaa 2016). The majority of these reforms resulted in a significant growth in electricity and water tariffs for non-nationals, leading to a remarkable gap in prices paid by residents and nationals. The success of the energy subsidy reform was strengthened by the implementation of the National Programme for Conservation and Energy Efficiency, the so-called Tarsheed program. Under this scheme, the government set the goal to reduce electricity and water consumption per capita by 8% and 20% between 2011 and 2016, respectively. Already in 2016, the country managed to successfully curb electricity consumption per capita by 18% and water consumption per capita by 20%, especially thanks to the wide utilization of smart meters (Oxford Business Group 2019).
Similarly, also the UAE, depending on the emirate, has adopted some of the most successful energy subsidy reforms in the region. Fuel prices are traditionally set at the federal level, but in 2015 they were reformed throughout the country. Fuel prices are not yet deregulated, but they are set by a commission each month, based on international prices. The fuel prices reform was carried out timely in 2015–2016 when oil prices were already low, thus without triggering social discontent or instability. The Dubai Emirate was the forerunner for reforming electricity and water tariffs in 2011, resulting in a 15–20% growth in electricity and tariff prices for non-nationals, industries and government. Nationals witnessed very modest tariff increases and only when their consumption exceeded a cap. Overall, they paid electricity and water 3–4 times less than non-nationals. In 2015, also the Emirate of Abu Dhabi started implementing electricity and water tariff reforms, raising the electricity prices for expats by 40% on average and by 120% for high-consumption households, while nationals were not affected (Krane and Monaldi 2017). Similarly, water tariffs for non-nationals increased by 170% reaching peaks of 374% for particularly high consumption levels. In this case, an increase in tariff was also introduced for nationals, which, however, was roughly three times lower than the tariff paid by expats. Since then, no significant changes have occurred to the 2015 energy subsidies reform in the UAE (Al-Saidi 2020).
In conclusion, although the UAE and Qatar are often considered very similar, they score very differently in terms of energy security and type of source endowment. Thus, these two countries are not only taking diverging paths in the geopolitical landscape of the region, but also their current energy sectors, future energy targets and objectives vary greatly. Indeed, by relying on gas rent, Qatar is less pressed to quickly diversify, as gas is likely to play a key role in the future global energy system for some time. Nevertheless, both Qatar and the UAE are striving to carry out efficient and effective energy subsidy reforms and economic diversification, each country at its own pace, depending on their economic needs and on their natural resource endowment.
1.3 Other GCC Countries: Bahrain, Kuwait and Oman
Bahrain and Oman share multiple characteristics both in economic and energy terms, while Kuwait differs substantially from the other two countries. At the same time, Kuwait and Oman play similar roles in the region’s geopolitics since they both strive to be perceived as neutral and independent. Thus, grouping Bahrain, Kuwait and Oman together enables a deeper understanding from a multidisciplinary perspective, as these countries share common characteristics as well as striking differences. For example, Kuwait has been one of the richest countries in the MENA region with a GDP per capitaFootnote 1 of $27,156 in 2019, while Bahrain and Oman have a lower rate, that is $21,199 and $14,516, respectively.
This section will firstly provide an overview of energy peculiarities in Bahrain, Kuwait and Oman, highlighting similarities. It will then assess the role of natural resource abundance and rentier economy in shaping current economic trends and challenges for the three countries, also considering their geopolitical stance. Lastly, it will discuss the roll-out of energy subsidy reforms, common to all these countries, in order to offset high domestic energy consumption levels.
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Key energy sector peculiarities
The striking difference among these three Gulf countries is that Kuwait is a hydrocarbon-rich country. And it is responsible for a significant production, Bahrain and Oman own more limited hydrocarbon reserves and their production levels are significantly lower than those of Kuwait (Table 3.4).
Kuwait stands out in terms of oil production, and despite its relatively small geographic size, it ranks seventh worldwide for oil reserves (101.5 thousand million barrels), with oil production slightly above 3 million barrels per day and oil exports above 2 million barrels per day in 2019. On the contrary, Oman’s oil reserves amount to 5.4 thousand million barrels (ranking 21st in the world). Its oil production is slightly below 1 million barrels per day, 87% of which is exported. The oil reserves of Bahrain amount to 189 million barrels (ranking 67th worldwide) and its oil production is unable to satisfy internal consumption, obliging the country to import 93% of its domestic oil consumption (BP 2020).
Gas reserves in Kuwait are also quite large, ranking 20th worldwide. However, Kuwait produces natural gas below its capacity so that it imports almost 20% of its total natural gas demand. Oman ranks 28th in terms of gas reserves worldwide, managing to export 21% of its total natural gas production while Bahrain has more limited gas reserves. In fact, it ranks 52nd in the world, with its natural gas production satisfying its internal consumption (BP 2020). Kuwait’s inability to meet its gas demand with its domestic production explains why power generation is mostly provided by oil, which accounts for 57% of total electricity generation and the remainder is provided by natural gas (IEA 2018e).
Kuwait’s total oil reserves include roughly half of the 5 billion barrels of the Neutral Area shared with Saudi Arabia. The bulk of Kuwait reserves are located in the Burgan area, which is considered to be the second largest oil field in the world after Ghawar in Saudi Arabia. Kuwait’s oil production was severely affected by the war with Iraq in the early 1990s. However, Kuwait managed to rapidly resume, and even expand, its pre-war oil production level. In the past two decades, Kuwait’s oil production has surged and then declined driven by OPEC quotas (Fig. 3.12). Between 2000 and 2013, Kuwait increased its oil production by around 50% when it peaked at 158 Mt (3.1 mb/d). The production remained stable until 2016, declined by 7.5% in 2017 and remained stable at around 145 Mt (2.9 mb/d) due to OPEC’s production curbs. Most of Kuwait’s oil production is exported to the Asia–Pacific region (85%).
Source Authors’ elaboration on ENERDATA
Kuwait’s oil production and consumption, 2000–2019, Mt (left) mb/d (right).
Kuwait’s gas reserves are also quite large. Since 2010, Kuwait managed to rapidly increase its gas production (by around 6%/y), reaching 18.4 bcm in 2019 (BP 2020). This volume meets almost 80% of Kuwait’s gas consumption (23.5 bcm). For this reason, Kuwait decided to import LNG through a FSRUFootnote 2 commissioned in 2009 with a capacity of 7.8 bcm/year. In 2019, Kuwait imported 5.2 bcm of LNG. The country is committed to increasing LNG imports with different agreementsFootnote 3 in order to secure future gas supplies. In addition, Kuwait is also considering importing pipeline gas from Iran and Iraq to help meet rising demand from power plants and industry.
The country’s total primary energy supply is strongly reliant on fossil fuels. Compared to Oman and Bahrain, oil is far more important in Kuwait’s TPES, accounting for almost 50% (Fig. 3.13). However, natural gas has increasingly gained ground in the energy mix. Fossil fuels dominate also Kuwait’s total power capacity (19.8 GW in 2019), with natural gas accounting for 11.4 GW and oil for 8.3 GW. Total power capacity has been expanded by more than 25% since 2014. That has gone hand in hand with the expansion of power production, which has increased on average by 3%/year since 2010, reaching 75 TWh in 2019. Natural gas has increasingly gained relevance in the power mix by replacing oil; it increased its share from 40% (22.6 TWh) in 2010 to 61.5% (46.2 TWh) in 2019. The rest is being supplied almost entirely by oil (Fig. 3.14). The power sector is almost totally responsible for total gas consumption since the mid-2000s as Kuwait strives to keep more profitable oil for exports. Total energy consumption increased rapidly between 2000 and 2008 (5.4% per year on average). Since 2014, it has been fluctuating around 36 Mtoe.
Source Authors’ elaboration on ENERDATA
Total primary energy supply in Kuwait, 1990–2019, Mtoe.
Source Authors’ elaboration on ENERDATA
Electricity production in Kuwait, 1990–2019, TWh.
Bahrain and Oman have more limited hydrocarbon reserves, in particular Bahrain is the country with the smallest reserves of the three. Since 2013, Bahrain’s oil production has remained stable, reaching 10 Mt in 2019 (Fig. 3.15). The lion share of its production (around 75%) comes from the Abu Safah offshore field, where Saudi Aramco is the main producer. Currently, Saudi Aramco produces around 300,000 b/d from this field, half of which is owned by Bahrain. The Awali oil field, owned entirely by Tatweer Petroleum,Footnote 4 is Bahrain’s other historical oil reserve. However, this field has experienced a steady decline due to a steep drop in drilled wells and facility shutdowns. In 2018, a new tight oil field in the Khalij Al-Bahrain Absin was discovered. The oil field holds great potential since it is estimated to be the largest oil reserve ever discovered in the country. It could hold at least 80 billion barrels of tight oil and 282–565 mcm of deep gas.
Source Authors’ elaboration on ENERDATA
Bahrain’s oil production and consumption, 1990–2019, Mt (left), mb/d (right).
Bahrain also produces natural gas, although at a modest level (around 15–17 bcm), which accounts for the majority of the national TPES (Fig. 3.16). Therefore, after several delays, in 2020 Bahrain commissioned an LNG import terminal with a capacity of 8.2 bcm/year. Power generation (34.7 TWh in 2019) relies entirely on natural gas (Fig. 3.17). Bahrain’s power sector is among the most privatized sectors in the region since 2004. The total capacity stood at 8.8 GW, 4 GW of which is owned by auto-producers, mainly in the aluminum sector.
Source Authors’ elaboration on ENERDATA
Total primary energy supply in Bahrain, 1990–2019, Mtoe.
Source Authors’ elaboration on ENERDATA
Electricity production in Bahrain, 1990–2019, TWh.
Oman stands in between Kuwait and Bahrain in terms of oil and gas production. Oman has produced stably around 48 Mt/y since 2015. However, the country’s oil production experienced a phase of strong decline between 2001 and 2007 (from a peak of 50 Mt in 2001 to 38 Mt) and then a rapid increase between 2009 and 2015 (Fig. 3.18). 90% of Oman’s oil production is exported and around 80% of it went to China in 2019. The upstream sector is dominated by Petroleum Development Oman (PDO),Footnote 5 which accounts for about 60% of total oil production and holds more than 90% of Oman’s oil reserves.
Source Authors’ elaboration on ENERDATA
Oman’s oil production and consumption 1980–2019, Mt (left) mb/d (right).
Source Authors’ elaboration on ENERDATA
Oman’s gas production and consumption 1990–2019, bcm.
Concerning natural gas, Oman has expanded its efforts to increase gas production in order to free oil volume for exports. Natural gas production in Oman has increased four-fold from the level of 2000, reaching 41 bcm in 2019 (Fig. 3.19). Since 2010, gas output has increased by 3%/year. Oman owns Block 61, which is the largest tight gas reserve in the Middle East. The gas fields, Ghazeer and Khazzan, will be responsible for a combined production of 31 bcm. The Khazzan gas field is already producing 15.5 bcm/year, while the Ghazeer gas field started its production in 2020 (15.5 bcm/year of gas and over 65,000 b/d of condensates). Natural gas exports started much later than oil exports, with the Oman LNG company established in 1994. Oman has one LNG liquefaction plant for exports in Qalhat near Sur, composed of 3 units, with a capacity of 10.4 Mt/year. In 2000, Oman commissioned two gas liquefaction trains, with a third added in 2006. Oman has exported growing LNG volumes, while at the same time it imports Qatari gas through the Dolphin pipeline (Fig. 3.20). LNG has become a major income source for Oman, while reducing its dependence on oil.
Source Authors’ elaboration on ENERDATA
Oman’s gas exports and imports, 1990–2019, bcm.
In 2019, Oman’s TPES was 25.5 Mtoe, with natural gas accounting for almost 90%. In terms of TPES, natural gas has become more and more relevant after 2005 in line with Oman’s strategy to diversify its economy away from oil (Fig. 3.21). Moreover, the domestic use of gas changed considerably over the period 2000–2011. During that time, the industry’s gas use increased from 27% in 2000 to 58%, while the electricity sector’s share remained constant at around 19% (IRENA 2014). Moreover, gas use at oil fields, flared gas and other uses accounted for 22% of the total gas use in 2011, significantly less than the 54% share in 2000s.
Source Authors’ elaboration on ENERDATA
Total primary energy supply in Oman, 1990–2019, Mtoe.
Natural gas plays a dominant role in Oman’s electricity production. Oman has a total power capacity of 14 GW (96% gas and the rest oil). In 2019, Oman’s electricity production reached 38.1 TWh, 94% of which from gas and the rest from oil (Fig. 3.22). Power generation from natural gas grew at a remarkable average annual growth rate of 9.9% from 2000 and 2010 and at 6.7% over the period 2010–2019.
Source Authors’ elaboration on ENERDATA
Electricity production in Oman, 1990–2019, TWh.
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Unsustainability of the rentier economy: socio-economic consequences
Kuwait
The energy sector is the pillar of the Kuwaiti economy since it accounts for more than 90% of government revenues and total exports, and 50% of the country’s GDP, stimulating the consolidation of a rentier economy and the social contract. However, despite having the second lowest fiscal breakeven price in the GCC region ($61 per barrel) and a positive budget balance (a surplus of roughly 6% in 2019), Kuwait’s socio-economic model has become quite unsustainable in the medium term (Statista 2020). Given the predominance of the public sector, key feature of the social contract, 54% of the government’s budget for the fiscal year 2018–2019 was utilized to pay the wages of Kuwaiti nationals. The private sector is scarcely present as the government implements 90% of all development projects, which hinders human capital development and the shift towards a knowledge-based economy (Olver-Ellis 2019). Apart from very high expenditures, the Kuwaiti economy has been stagnating for nearly a decade. This means that it is falling behind, with respect to other GCC economies, in key economic indicators, such as regulatory environment and economic competitiveness, partly due to tensions in its parliamentary politics. Nowadays, Kuwait is striving to horizontally diversify its production and exports from hydrocarbons, shifting towards an integrated energy sector, by diversifying downstream activities, boosting refining capacities and realizing the full potential of natural gas fields (Oxford Business Group 2018). Kuwait, through its national oil company, Kuwait Oil Company, has therefore attracted numerous foreign oil companies, namely Shell, and mostly employed Service Agreements as fiscal arrangements.
Overall, in theoretical terms, Kuwait is one of the best placed countries in the GCC to diversify its revenues, export and energy mix from oil, thanks to a relatively small population (4 million people, contrary to Saudi Arabia), a large oil production and reserves base (contrary to Bahrain and Oman) and an ideal geographical position to develop both wind and solar energy. However, economic diversification and the introduction of renewable energy sources (0.11% of total electricity generation in 2018) (IEA 2018e) have not yet taken place mostly due to political stalemate, a low level of private sector involvement and low synergies among the numerous authorities involved (Butler 2019).
Bahrain and Oman
In Oman and Bahrain too the social contract is built upon the oil rent, which has shaped their socio-economic model, despite the lower abundance of their natural resources. Little diversification from oil revenues, volatile and low oil prices and social unrest in the broader MENA region (e.g. the 2011 Arab Spring) may in part destabilize these countries with lower natural resources. Both countries suffer from budget pressure, with increasing deficits, leading to higher debts to GDP (Bahrain debt amounts to 105% of its GDP and Oman to 60.1% in 2019) (Trading Economics 2019a, b), high fiscal breakeven oil prices ($96 per barrel for Bahrain and $87 per barrel for Oman in 2020) and an increasing unemployment rate, especially among the young people (IMF 2020). Worse financial and economic conditions have already led to some protests and social unrest since the demands of the population (i.e. high level of subsidies, a well-paid job in the public sector etc.) may not always be met. Austerity measures were discussed, and suggested by the IMF, but rarely implemented fearing further social dissatisfaction and unrest, especially in Bahrain, which has witnessed the highest level of social unrest among Gulf countries during the Arab Spring. Social unrest has been generated by a polarized population between Sunni and Shiites, with the Sunni minority holding the power, as well as economic dissatisfaction.
In order to deal with their poor economic outlook, both countries may need to request external economic aid. Nevertheless, both countries may privilege financial aid from neighboring countries rather than international financial institutions such as the IMF, which are often conditioned on the implementation of specific and possibly unpopular policies. However, access to external aid is different for Bahrain and Oman, depending on regional alliances. Bahrain is under the geopolitical influence of Saudi Arabia and the UAE so that these countries, along with Kuwait, may resort to Manama for financial assistance, as in 2018 with a $10 billion stimulus package (Thafer 2020). On the contrary, Oman has always strived to adopt a neutral and balanced stance regarding the region’s geopolitics. The new Sultan Haitham bin Tariq has expressed his willingness to follow the steps of his predecessor, Sultan Qaboos bin Said, and remain the neutral arbiter in the region. Thus, for Oman, accepting financial assistance from the UAE and Saudi Arabia may result in losing its geopolitical independence. Relying on Qatar might also lead to regional turbulence, since the Quartet (Saudi Arabia, the UAE, Egypt and Bahrain), which established an embargo over Qatar, may be angered by this request. Oman may request financial stimulus from Kuwait since the latter has always adopted a neutral stance, this would ensure that Oman’s neutrality and independence are not threatened. At the same time, as mentioned before, Kuwait’s economy is not thriving, especially following the Covid-19 crisis, and it may thus prefer to direct its finances internally rather than to Oman. Overall, while Bahrain may rely on its major allies and protectors to receive financial stimulus, Oman may find itself in a harder position, while trying to conjugate its neutral geopolitical stance with financial assistance. Oman is also likely to find it challenging to seek credit, given its high public debt to GDP ratio (above 80% in 2020) and strained capital reserves (The World Bank 2020c). Moreover, contrary to other GCC countries, net foreign assets are some of the lowest in the region and sovereign wealth fund assets are valued approximately at 50% of the country’s GDP (Ismail and Narayanan 2020).
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A common path: energy subsidy reforms
Kuwait, Oman and Bahrain have considerably high energy and electricity consumption per capita rates. Of the three, Bahrain has the highest per capita energy consumption (9.7 toe in 2019), which is also three times the Middle East average and five times the global average. Kuwait’s energy consumption per capita rate (around 8.5 toe since 2011) represents the world’s sixth highest in 2019. Oman has a lower rate (5.1 toe in 2019) even though it is three times higher than the global average, due to its energy-intensive industrial production. Similarly, Bahrain’s electricity consumption per capita rate (21 MWh) is higher than that of Kuwait and Oman due to the aluminum sector, which is five times the Middle East average and seven times the global average. Kuwait has a rate of 12–13 MWh/capita since 2008, representing the world’s seventh highest in 2019, while Oman’s per capita electricity consumption reached 6.7 MWh in 2019.
Kuwait, Oman and Bahrain revised their energy pricing policy in consideration of their high energy and electricity consumption per capita rates, while in all three countries the path to reform of the energy subsidies is hindered by economic constraints and sociopolitical issues.
Kuwait
In Kuwait energy subsidies made up 16% of the government’s budget in 2018, a burden for public finances (Moerenhout 2018). Nevertheless, Kuwait was the last GCC country to introduce energy subsidy reforms, because of the robustness of its budget compared to other countries, its rather small population size, and the political struggle between the National Assembly, the legislative authority, and the government. Until 2016, electricity prices were one-twentieth of production costs and water was basically free, making the country the sixth highest energy consumer in the world (World Bank 2017a). However, low oil prices in 2016 led the National Assembly to propose and approve an increase in electricity tariffs for expatriates and for commercial use. Moreover, Kuwait was the last country to reform gasoline prices, which were the lowest worldwide: in 2016, the government, circumventing the National Assembly, raised gasoline prices by 41–83%, depending on octane levels (Shehabi 2017). A political confrontation between the government and the National Assembly took place, with the latter challenging the energy price reform in court. One year later, the Appeals Court ratified the energy reform carried out by the government. Overall, prices for some petroleum products were raised in Kuwait, for instance, gasoline increased from 0.24$/liter in 2015 to 0.34 $/liter in 2018, while prices for other products did not change in this time span (i.e. diesel) (Shehabi 2019).
Bahrain and Oman
In Bahrain and Oman the path to energy subsidy reform was rather similar in terms of time and content: both countries decided to raise natural gas prices in 2015 by 11% and 100%, respectively, and to reform diesel and petrol prices in 2016. In the same year, Bahrain increased diesel prices by 14% and petrol prices by 60%, while Oman increased diesel by 10% and petrol by 33% (Lahn 2016). Moreover, both countries are setting energy prices per unit by consumption slab, which might allow cross-subsidization, namely high-consuming customers are discouraged from excessive consumption by paying above the cost, subsidizing for low-consuming customers, who are usually the least well-off. Nevertheless, there are differences in the subsidy reforms of Oman and Bahrain: first, while Oman does not have differentiated prices for expats and nationals, in Bahrain prices were increased for both categories, although nationals are still benefiting from lower prices. Another striking divergence regards Oman’s gradual increase of energy prices, which are linked to the international market—a strategy similar to the one adopted in the UAE and Qatar—while Bahrain applied “ad hoc” price adjustments more than once, in line with the policy of Saudi Arabia and, partly, Kuwait (Moerenhout 2020). Therefore, ever since 2016, Oman has increased its energy prices by employing a pricing formula that links Omani prices to international and UAE ones. For instance, in 2016, diesel price with the first adjustment amounted to 0.42 USD/l, while in 2018 it was equal to 0.65 USD/l. To curb opposition to its energy price reforms, Oman first unsuccessfully attempted to put caps for regular gasoline. Then, in 2018, Oman introduced the “National Subsidy Scheme” aimed at ensuring regular gasoline to low-income households at a subsidized price of 0.47 USD/l (in 2018 regular gasoline amounted to 0.59 USD/l with projected yearly increases) (Moerenhout 2020). In Bahrain, since 2016, energy prices were increased in 2018, in particular gasoline 95 went from 0.42 USD/l in 2016 (which was already 58% higher than in 2015) to 0.53 USD/l in 2018, while diesel from 0.32 USD/l in 2016 (which was already 19% higher than in 2015) to 0.42 USD/l in 2018 (Moerenhout 2020).
To conclude, the rentier economy and the social contract have become economically unsustainable for all three countries. Nevertheless, while Bahrain and Oman are already experiencing economic difficulties, for Kuwait economic diversification has become a priority to build an economically sustainable future and to dynamize the economy by involving also the private sector.
1.4 Iran
Iran is a major oil and gas producing country with vast oil and gas resources (155.6 thousand million barrels and 32 tcm in 2019). Iran’s heavy reliance on oil and gas derives from its conspicuous hydrocarbon reserves: it ranks fourth in the world in terms of oil reserves, representing 9% of total proven oil reserves. It also holds the second largest gas reserves worldwide, preceded by Russia, accounting for 16.1% of total proven gas reserves (BP 2020). Iran shares with Qatar the largest non-associated gas field in terms of reserves worldwide, named South Pars for the Iranian side and North Dome for the Qatari side, as detailed in Map 3.4 (NS Energy n.d.). Discovered in 1990, South Pars accounts for around 40% of proven Iranian gas reserves. It has a 24-phase development plan with 18 phases already operational and it is managed by a subsidiary of the National Iranian Oil Company (NIOC), the Pars Oil & Gas Company (POGC).
Source EIA
Division of North Dome/ South Pars gas field between Qatar and Iran.
Despite its great gas and oil potential, several cycles of international sanctions and the limitations on exporting these natural resources have greatly affected the development of the country’s oil and gas sector, in terms of production and foreign investments. Iran remains nonetheless the second largest economy in the MENA region, after Saudi Arabia, and a slowdown of GDP growth has not directly affected the unemployment rate, which, on the contrary fell from 13% in 2011 to 11% in 2016, which is consistently lower than in numerous other MENA countries (The World Bank 2020d).
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Iranian hydrocarbon sector: a turbulent history
Iran’s oil and gas history is a turbulent one, limited by both external and internal forces. The history of its hydrocarbon sector dates back over a century and represents the starting point of oil discoveries in the MENA region. In fact, oil in the Middle East was first discovered in today’s Iran in 1908 by the British geologist G.B Reynolds and the following year a subsidiary of the British oil company Burmah Oil was established: the Anglo-Persian Oil Company (APOC). Oil production started in 1913 and its increasing importance was dictated by the willingness of the British navy to shift its fuel source from coal to oil. Already at that time, APOC was widely unpopular in Iran, since the host country was only receiving 16% of net profits (Kent 2015). After World War II, in line with other MENA countries, resource nationalism was on the rise in Iran with a specific animosity towards the British presence, embodied by the Anglo-Iranian Oil Company (AIOC), APOC’s new name following 1935. Although the concession agreement was revised to include more favorable clauses for the country, resource nationalism gained consensus under the leadership of Iranian Prime Minister Mossadegh. In 1951, the Iranian Parliament decided to nationalize AIOC leading to the so-called Abadan Crisis. The UK responded strongly, putting pressure on other countries to boycott Iranian oil, leading to a substantial contraction of revenues for the Iranian government. In 1953, a US-backed coup overthrew Mossadegh and secured the power of the pro-Western Shah, Mohammed Reza Pahlavi. The AIOC changed its name to National Iranian Oil Company (NIOC) and Iranian oil was exported once again. Throughout the following two decades, the Iranian oil and gas sector witnessed a period of prosperity: in 1976 peak production reached 6.6 million barrels per day and in 1978 Iran became the second largest OPEC producer.
Iran’s hydrocarbon industry, however, has experienced some major turbulent times since 1979. Following the Iranian Revolution in 1979, the National Iranian Oil Company (NIOC) took absolute control over the oil and gas sector, cancelling all international oil agreements. This process took place at the same time as the emergence of national oil companies in the broader MENA region. The war with Iraq in the ‘80 s considerably hindered oil production so that it was only from the mid- ‘90 s that NIOC started investing in the hydrocarbon sector with projects either financed by NIOC or in joint ventures with international oil companies. Figure 3.23 depicts the country’s oil production and exports, highlighting the main sanctions introduced and changed.
Source Authors’ elaboration
Iran oil production and export (Mt) and key political events.
Sanctions on Iran have been recurrent in the last few decades, heavily affecting oil exports and production, as the table above highlights. The 1979 Iranian Revolution and the imposition of the first US sanctions on Iran in 1980 resulted in a drastic drop in oil production (from 263.7 Mt in 1978 to 74.4 Mt in 1980) and exports (from 193.6 Mt to 43.6 over the same period). The 8-year war with Iraq limited production levels and investments. Nonetheless, Iran showed significant resilience and managed to increase its oil output and export volumes, despite the 1984 listing of Iran as “State sponsor of terrorism” and the 1995 ban on American trade with and investments in Iran, targeting especially the energy sector. NIOC started investing again in hydrocarbon projects from the mid-1990s. In 2006, the new round of American and UN sanctions on Iran harmed oil exports, but it did not greatly impact production, since oil products were mostly employed to satisfy the growing internal demand for power generation.
In 2010, unilateral sanctions were imposed on Iran, which negatively decreased oil output (passing from 214 Mt in 2010 to 158.7 Mt in 2013) and exports (from 138.8 Mt to 73.3 Mt over the same period). This new round of sanctions targeted Iranian petroleum exports and imports, forbidding large investments in the hydrocarbon industries and cutting off sources for financial transactions with the EU and the US. In the last years, Iran has been able to increase its production and exports as the international community reached an agreement with Iran based on the Joint Comprehensive Plan of Action (JCPOA) related to its nuclear sector and to the possibility to remove several sanctions allowing foreign investments (see Chap. 5, Sect. 5.1.3).
Iran’s gas potential is constrained by several factors resulting in a diametrically opposite position compared to Qatar, even though the two countries share the South Pars/North Dome gas field. Indeed, the two countries are in stark contrast in the gas sector: Qatar is a leading gas exporter, while Iran is unable to export large quantities of gas due to a much larger domestic gas market (population of 89.3 million in Iran vs. 2.8 million in Qatar) combined with geopolitical and regulatory constraints. Indeed, Iran’s gas production is almost entirely consumed domestically (Fig. 3.24). Gas exports account for a small share of total production, characterizing Iran as an inward-looking gas power. Indeed, Iran is the world’s third largest producer of natural gas but its exports (only via pipeline) constitute only less than 2% of global gas trade in 2019. The country has been able to increase its production levels, which have been crucial to meet domestic power demand. The prioritization of gas for the domestic market was part of the strategy to free oil export volumes for additional revenues. Since Iran is striving to substitute oil with natural gas for power generation and natural gas consumption levels are astonishingly high (it is the fourth largest consumer of natural gas worldwide), the need to refrain internal demand has grown (EIA 2019).
Source Authors’ elaboration on ENERDATA
Iran’s gas production and consumption, 1980–2019, bcm.
Thus, while gas production has increased since the 1980s, the share of gas exported, mostly to Turkey and Iraq via pipeline, has remained steady. More recently, Iran has been able to increase its gas production and divert such additional volumes to export rather than to the domestic market. Nonetheless, one of the most important features of Iran’s gas industry is the limited role of gas exports compared to its reserves. In 2019, Iran exported 16.9 bcm of gas via pipeline out of a total production of 244.2 bcm, while the domestic market consumed 223.6 bcm (BP 2020). Turkey and Iraq are the main gas markets for Iran’s exports. A more modest share flows to CIS countries, namely Armenia and Azerbaijan (Fig. 3.25). At the same time, Iran also imports some gas volumes from Turkmenistan, and a smaller volume from Azerbaijan (Fig. 3.26). These two countries usually supply gas to Iran’s northern provinces and during the winter season. Since Iran has been concurrently exporting and importing natural gas, over the years it has sometimes been a minor net gas exporter, and sometimes a minor net gas importer, only recently has it established itself as a consequent gas exporter by reducing imports from Turkmenistan and increasing exports in particular to Iraq. With some 16 bcm of net exports in 2019, Iran remains a very modest gas exporter in particular considering its vast reserve base (the second largest in the World after Russia).
Source Authors’ elaboration on CEDIGAZ
Iran’s gas exports by country 2010–2019, bcm.
Source Authors’ elaboration on CEDIGAZ
Iran’s gas imports by country 2010–2019, bcm.
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JCPOA: changes in the hydrocarbon sector to attract foreign investments
Following prolonged and difficult negotiations, the international community marked a milestone with the signature of the Joint Comprehensive Plan of Action (JCPOA) between Iran and a group of countries, P5 + 1Footnote 6 together with the EU, in July 2015. The agreement entered into force in 2016. With this agreement, Iran saw a new window of opportunity to increase foreign investments, in particular in its hydrocarbon sector.
In order to attract foreign capital and expertise, Iran changed its petroleum fiscal regime, which historically represented one of the greatest constraints for the positive development of Iran’s hydrocarbon sector. The 1979 Islamic Constitution referred specifically to natural resources in some articles (Art. 44, 45 and 81), shaped by the desire to strictly control the terms of any agreement with foreign companies (Tagliapietra 2014). Legally, the Iranian government was the only authority that could deal with natural resources. Therefore, the NIOC took control of the Iranian petroleum industry and canceled Iran’s international oil agreements, holding complete ownership of the assets in line with the Iranian law. In the early 1990s, a new type of contract (called buyback contract) was developed in order to allow the so-much required foreign investments in the hydrocarbon sector in respect of the overall Constitution. A buyback contract is essentially a service contract under which a foreign company develops a hydrocarbon deposit and recovers its costs and a pre-negotiated remuneration fee from sales revenues, but has no share in the project’s profit. Moreover, the agreement's duration was limited to five to seven years so as to prevent any single firm from having too much power in Iran and fixed a relatively low rate of return (Brumberg and Ahmar 2007). Such conditions have inevitably discouraged IOCs to invest in the Iranian oil and gas industry.
Notwithstanding these disadvantages, this scheme remained in place for over 20 years until mid-2016, when Iran introduced a new legal framework: the Integrated (or Iran) Petroleum Contract (IPC). Through the IPC, Iran aimed to offer more attractive terms to IOCs. For example, the term of the contract is extended to a maximum of 20 years from the start of development. In the presence of enhanced oil recovery (EOR), the term can be extended up to another 5 years (Farimani et al. 2020). The IPC also modified some of the previous issues regarding remuneration. Under the buyback, the remuneration fee was paid as a percentage of total capital costs, while under the IPC the fee is based on production rate and set as a fee per barrel of oil or per cubic foot of gas. However, the IPC does not allow foreign ownership of reserves.
As international and domestic circumstances appeared to improve, Iran fixed more ambitious targets for its hydrocarbon sector: 6 mb/d of oil production and 1055 mcm per day (about 350 bcm) of gas production by 2020. A positive consequence was the signature of two contracts with IOCs, within the IPC framework, between 2016 and mid-2018: in July 2017 with the French IOC Total and the Chinese CNPC to develop phase 11 of the South Pars field, and in 2018 with the Russian Zarubezhneft for the development of the Abadan and West Paydar onshore fields, on the border with Iraq. Total and CNPC preferred to focus on the production of gas and condensate, which are considered less geopolitically sensitive than oil. This promising start, however, did not translate into concrete developments due to the resume of unilateral sanctions decided by the Trump administration which forced companies to leave the projects.
Regarding the gas sector, Iran has historically prioritized its residential, industry and power demand rather than exports. This strategy aimed at freeing oil volumes for export, the latter being more remunerative than gas and easier to transport. To maximize its oil production (and consequent revenues), Iran also utilized large quantities of gas for injection into its oil fields for enhanced oil recovery (EOR) activities, a particularly crucial process given that more than 80% of Iran’s active oil fields are depleting (losing around 8–12% of their production capacity per year) and that their recovery factor is 20% lower than the global average (35%) (Mordor Intelligence 2019). EOR techniques might thus contribute to increasing annual production volumes by around 7% per year. In a nutshell, Iran has struggled to find the perfect equilibrium between meeting its domestic demand, enhancing its more remunerative oil production and exporting some gas volumes. Moreover, Iran could not benefit from growing gas consumption in the Middle Eastern countries also due to its political isolation.
For these reasons, Iran’s gas exports have been relatively low despite its vast gas reserves. Nevertheless, Iran aimed at increasing its gas exports via pipeline (also because international sanctions prevented the development of LNG facilities). Traditionally, Iran exported to Turkey and at a smaller scale to Armenia and Azerbaijan. It started exporting gas to Turkey via the Tabriz-Ankara-Pipeline in the 1990s. Natural gas trade between these two countries was geopolitically relevant due to Turkey’s membership to NATO. However, the volume was not particularly relevant. In 2019, Iran exported 7.4 bcm to Turkey. The pipeline flows were also disrupted as a result of sabotage attacks by the Kurdistan Workers’ Party (PKK). In Turkey, Iranian gas exports face growing competition from LNG and from the Russian gas pipeline due to the recent opening of TurkStream. Iran exports also to Azerbaijan (since 2005) and Armenia (since 2009). In 2013 and 2015 Iran signed two supply agreements with Iraq. Moreover, in 2017, Iran started exporting gas via pipeline to Iraq to power electricity generation plants. Despite its great potential and its geographical location, Iran imported gas from Turkmenistan in order to meet its domestic consumption, especially for its northern areas. The two countries, however, have had several disagreements over the terms of the contract. Iran also explored other regional export projects (for example to Pakistan and India or to the Gulf countries). However, the likelihood of these projects coming online is not high due to geopolitical tensions in the region and beyond, which adversely affect Iranian investments in its promising oil and gas sector (Mordor Intelligence 2019).
The US unilateral decision to withdraw from the JCPOA at the end of 2018 inexorably affected the numerous targets and goals that Iran had set for its energy sector, especially in terms of exports and domestic and foreign investments in its upstream. China and Russia were the last ones to remain in Iran, operating as “contractors” to obfuscate their presence in order to avoid both American sanctions and the Iranian public’s backlash, since the contracts signed were not deemed to fully protect Iranian interests (Watkins 2020).
The withdrawal of the United States from the JCPOA and the reintroduction of numerous sanctions have inevitably undermined the country’s economy in the last few years. Indeed, a 37% decline in the gas sector was the main cause behind the 7.6% contraction of GDP between April and December 2019, since non-oil GDP growth registered a 0% change in this timeframe (The World Bank 2020e). Besides international financial sanctions, Iran was also one of the countries in the MENA region that was hit the hardest by the Covid-19 pandemic, in terms of number of infections and deaths, further affecting the country’s economy. Also, Iran’s foreign reserves fell to about $85 billion in 2020 (losing one-fifth of 2019 value) and are expected to fall to $69 billion in 2021 (Fathollah-Nejad 2020). Thus, unsurprisingly, the country is facing rampant inflation, which reached 34.4% in September 2020 from the previous year. Indeed, the riyal lost nearly 50% of its value against the dollar in 2020, hitting a low of 300,000 to $1 on October 1st, 2020 (Motamedi 2020).
Natural gas and oil inevitably play a major role in Iran’s total primary energy supply and power generation. In 2019, the total primary energy supply (271.5 Mtoe) in Iran is mostly composed of natural gas (56%), followed by oil (42%). Other sources, nuclear and renewables, account for 2% of TPES (Fig. 3.27). Natural gas has increased its relevance throughout the past 30 years in the TPES and electricity generation, replacing oil, thanks to the development of the South Pars field, which resulted in higher gas production despite the unfavorable international framework.
Source Authors’ elaboration on ENERDATA
Total primary energy supply of Iran 1990–2019 Mtoe.
Similarly, natural gas is predominant also in electricity generation by source, accounting for 84% of total electricity generation (314 TWh) (ENERDATA n.d.), as shown in Fig. 3.28. Natural gas has steadily gained relevance within Iranian electricity production, with the particular aim to free oil export volumes. Since 2013, Iran has benefited from the previous development of South Pars, which resulted in higher gas production. The additional gas caused the replacement of oil in the power sector. The other two main sources for power generation in Iran are hydro and nuclear.
Source Authors’ elaboration on ENERDATA
Electricity production of Iran 1990–2019 TWh.
The highly controversial nuclear energy represents a minority share in electricity generation (around 2%). Moreover, electricity final consumption has witnessed a strong growth of 6% per year on average between 1990 and 2020, increasing three times faster than the country’s population, thanks to economic growth, localization and development of industries, especially energy-intensive ones.
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Nuclear energy for power generation: a chess game
Nuclear power, a key energy source for electricity generation, has been at the center of international attention and a driving force to imposing sanctions. In the case of Iran, the highly debated stage of the nuclear fuel cycle regards fuel supply, with the Iranian government fearing disruption of the enriched uranium supply. Such a threat would depend on the political context, since there is a substantial global surplus of both uranium and enrichment capacity. Indeed, the price per separative work unit for uranium enrichment has dropped from ~$160 in 2010, to ~$40 in 2018. Contrary to the model adopted by the UAE, which relies on the diversification of fuel suppliers, Iran has been bound by its contract with Russia as the sole supplier of nuclear fuel for the entire life of the Bushehr’s nuclear power plant. The reliance on a single supplier makes Iran’s nuclear power program vulnerable to disruptions from Russia, which could have played a role in Iran’s insistence to carry out front-end activities within its borders. Indeed, Russia has already taken advantage of its role as a nuclear energy supplier as a political leverage. For instance, Russia has used its key position in Turkey’s Akkuyu nuclear power plant to further its agenda in Syria. After Turkey shot down a Russian fighter jet that had briefly violated Turkish airspace by flying over Syria for a mission, Russia suspended the plant’s construction and cancelled the training programs it had already signed with four Turkish universities (Reuters 2015a). After mending its relations with Turkey, Russia resumed the construction of Akkuyu.
Since Iran possesses some uranium deposits and has recently discovered new ones in its territories, having enrichment facilities would make the country less reliant on nuclear fuel imports and even self-sufficient (Reuters 2015b). At the same time, the international community saw this decision as a potential threat to regional and international stability (the most vociferous countries were Israel, the United States, the Kingdom of Saudi Arabia and the United Arab Emirates, which fear that these uranium enrichment facilities could also be used to build nuclear bombs). Iran thus became the target of international sanctions increasing the country’s vulnerability to fuel supply disruptions.Footnote 7 Enrichment facilities, in particular in the Natanz nuclear site, have thus been targeted and damaged in the first half of 2020, presumably by Israel (Bergman et al. 2020). Overall, localizing nuclear fuel supplies is more expensive for Iran, as it cannot benefit from economies of scale, and it also goes against Russia’s interests, since exports of nuclear fuel to Russian-built nuclear power plants are highly profitable (Obergfaell 2019).
Iran’s petrochemical industry, accounting for 3.6% of worldwide petrochemical output, is the country’s leading industrial sector, and according to Behzad Mohammadi, head of Iran’s National Petrochemicals Company (NPC), it is forecasted to increase and cover 6.2% of global petrochemical production by 2025, (Kerimkhanov 2019). Indeed, Iran is striving to reduce its dependence on crude oil exports, by turning its attention to and enhancing investments in the petrochemical sector, which represents its second largest export industry. In 2020–2021, three petrochemical projects - worth $1.6 billion - were inaugurated, in 2021 13 new petrochemical projects are expected to come onstream, and between 2022 and 2026 additional investments in petrochemical activities are projected to amount to $37 billion (MEMO 2020).
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Iranian energy subsidy reform: a “Basic income” model
Iran was forced to implement some major energy policies aimed at curbing fast-growing energy demand. In 2010, Iran carried out an innovative energy subsidy reform, which also represents one of the most comprehensive attempts of basic income, even though its characteristics partly diverge from the basic income model par excellence adopted in AlaskaFootnote 8 (Howard and Widerquist 2012). In 2011, Iran managed to halve its subsidy expenditures, which in 2010 where the highest in the world, amounting to 25% of Iranian GDP, without causing social unrest thanks to universal cash transfers. The government opened bank accounts for all families, regardless of individual characteristics (income, wealth, age etc.) and unconditionally distributed around $40–$45 per person per month (roughly 15% of the national income), following the rollout of subsidy reforms. This transfer program was financed by eliminating subsidies thus increasing prices for goods, without putting a burden on the country’s budget.
Regarding direct effects, the subsidy reform was deemed successful to reduce energy consumption: from 2010 to 2011 the demand of fuel oil, diesel, petrol, and kerosene decreased by 36.4%, 9.8%, 5.6% and 2.9%, respectively (Hassanzadeh 2012). Also electricity and natural gas demand for households contracted by 1.7% and 1.5%, respectively, even though total natural gas demand increased as it replaced oil products in electricity generation. Also, this program led to positive spillover effects since inequality and poverty indicators in 2011 significantly decreased with respect to 2010. In the first year, replacing subsidies with cash transfer directly benefited the local population, especially the least well-off (Deutschmann et al. 2014). However, while inflation was dramatically on the rise and even doubled by 2015, energy prices remained constant, reducing, in real terms, the positive effects of the subsidy reform in limiting energy consumption levels. In 2015 the Iranian government decided to increase gasoline and diesel prices by 20% to catch up with previous inflation, and to retain the impact of the subsidy reform (Krane and Monaldi 2017). Similarly, in December 2018, President Rouhani tried to increase fuel prices, but the move was blocked by the Parliament following social protests. In 2019, Iran managed to considerably increase pump prices by 50%, and the revenues were given to the worst-off households as cash handouts. This move was also partly triggered by inflation with the riyal value plummeting compared to the US dollar (France24 2019).
Iran’s hydrocarbon development and exports face several constraints, both domestically and internationally. The legal framework has historically undermined the partnership with foreign companies that Iran is in much need of to foster natural gas production. Indeed, gas production has been mostly used to satisfy domestic gas consumption, incentivized through energy subsidies and infrastructure development. The international environment further exacerbated challenges to positively develop the sector. Thus, Iran has faced some major economic hurdles over the last decades, now further aggravated by the COVID-19 pandemic. Despite all these challenges, Iran has been able to become particularly resilient to both internal and external difficulties.
2 Mashreq
Seven heterogeneous countries—Egypt, Jordan, Lebanon, Israel, Syria, Iraq and Palestine—compose the Mashreq cluster. Among these countries, there are some old oil provinces, such as Egypt, Syria and Iraq, while others have struggled to maintain a high degree of energy security due to the lack of adequate domestic hydrocarbon reserves, for example Israel, Jordan and Lebanon. They vary significantly in terms of socioeconomic indicators (Table 3.5).
Different population sizes and economic relevance represent the most striking differences. Within this cluster, Egypt is the most populated country, with 100 million citizens in 2019 (almost doubled compared to 1990), Iraq 39 million and Syria 17 million, while the other countries are home to about 4–10 million people. In its median scenario the UN projects that by 2050 Egypt will reach about 160 million (+60 million), Iraq 7 million (+32 million), while Syria will reach 33 million (+16 million) people. Of all MENA countries, these are the countries where the population is expected to grow the most.
World War I was a disruptive event for this region, drastically changing the power in place. In December 1914, the British proclaimed a protectorate over Egypt. With the end of World War I and the defeat of the Ottoman Empire, the UK and France drew the borders of the Levant region, based on the 1916 secret treaty of Sykes-Picot, resulting in the British Mandate for Palestine (currently south Iraq and Kuwait under direct control while Jordan, the Negev desert and north Iraq under British influence) and the French Mandate for Syria (Lebanon and south-East Turkey under direct control, Syria and Mosul under French influence), while the northern part of historic Palestine was designated an “international zone” (with the exceptions of Haifa and Acre/Acca controlled by the UK).
Today, Lebanon has a precarious sociopolitical equilibrium due to a fragmented political system with different posts traditionally attributed to a specific sect (i.e. the President is a Maronite Christian, the Prime Minister a Sunni and the speaker of Parliament a Shia), originated from the 1943 National Pact and not eliminated by the 1989 Taif Agreement. This sectarian political arrangement has paralyzed most of the reforms.
Jordan’s Hashemite dynasty originates from the appointment of Abdullah I King of Jordan by the British in 1921, while his brother Faisal was appointed King of Iraq. Both brothers were the sons of Sharif Hussein, who was the Sharif and Emir of Mecca after proclaiming the Great Arab Revolt against the Ottoman Empire and King of Hejaz (from 1916 to 2024). He was the 37th-generation direct descendant of Muhammad. He belonged to the Hashemite family. Nowadays, the Hashemite dynasty is still ruling Jordan with a parliamentary system of government, and plays a relevant role in the Muslim world.
In Iraq the Hashemite reign came to an end when Brigadier Abd al-Rarim Qasim and Colonel Abdul Salam Arif overthrew the Hashemite monarchy in 1958 and proclaimed Iraq a republic. In 1963 Qasim was assassinated when the Baath Party took power and retained it until the fall of Saddam Hussein in 2003. Saddam Hussein initiated the inconclusive and costly eight-year war against Iran (1980–1988) which devastated the Iraqi economy. He invaded Kuwait in 1990, starting the first Gulf War (1991). After the 2001 terrorist attacks on New York and Washington, linked to the group formed by multi-milionaire Saudi Osama bin Laden, American foreign policy began to call for the removal of the Baath government in Iraq. This finally led to the invasion of Iraq in 2003 by the United States and the United Kingdom (with military aid from other nations), followed by the fall of Saddam Hussein. The American occupation lasted from 2003 through 2011. The departure of US troops in 2011 triggered a renewed insurgency and a spillover of the Syrian civil war into Iraq. The Islamic State of Levant and Iraq seized large parts of Iraqi territory in 2013–14, but was finally defeated by the central Government in 2017. Regular protests over deteriorating economic conditions and state corruption continue, but the violence level is now (since 2018) the lowest of the last ten years.
Syria’s current borders were set by the League of Nations’ French Mandate, following the dismantling of the Ottoman Empire after World War I. The country has always been characterized by multiple and different ethnic groups. The French mandate ended in 1946, leaving the power to the Sunnis. However, the birth of the Baath party in Syria in 1947 provided the ideal platform and political vehicle to organize and unify the country, also for minorities like Alawites. Given its campaign of secularism, along with socialism and Arab nationalism, the Baath party met a strong opposition from the Sunni group. In 1963, the Baath party reached power through a military coup led by President Amin al-Hafiz. In 1970, then-air force commander and Defense Minister Gen. Hafez al Assad ended Syria’s string of coups and counter-coups through a bloodless military coup. After Hafez’s death in 2000, his younger son, Bashar al Assad, assumed the presidency. Initially, it was Hafez’s eldest son, Bassel, who was groomed for power. However, Bassel’s death in a car accident in 1994 thrust Bashar to the fore. Since 2011, the country has been lacerated by a civil war, further exacerbated by external interferences. Syria has been a traditional ally of Russia.
Israel was part of the British Mandate of Palestine from 1922 until the years following the end of WWII. In 1948, Israel proclaimed its independence triggering the fierce military response of five Arab nations (i.e. Egypt, Jordan, Iraq, Syria and Lebanon). A ceasefire agreement was reached in 1949, but since then several conflicts have erupted between Israel and its neighboring countries. Israel is a parliamentary democracy, with the parliament known as the Knesset. Between 2009 and 2021, Israel witnessed a continuity in terms of political leadership, with the 12-year long run of Netanyahu as Prime Minister. However, between 2020 and 2021, Israel held four elections, which ultimately ended with a new government led by the new Prime Minister Bennet. Regarding Palestine, the Palestinian Authority was established in 1994 and Mahmoud Abbas became PA’s President in the 2005 elections. He still holds this post today, and was also appointed PLO leader following Arafat’s death in 2004. In 2006, Hamas won the Palestinian Legislative Council elections, winning the majority of seats. One year later, Abbas dissolved the Hamas-led government, declared a state of emergency and since then Gaza is controlled by Hamas.
Egypt has been another crucial player in the region. Egypt has been ruled for several decades by long-lasting rulers until the Arab Spring in 2011. In 1922, Egypt gained its independence from the UK when Faud I become King. Indeed, Egypt was a British protectorate from 1914 to 1922. The British influence remained significant in the country until the 1950s, and formally ended with the Suez Canal crisis. In the 1950s, Gamal Abdel Nasser surged to power until his death in 1970. Initially, he developed good relations with the US as a potential driver for economy growth and development. Due to political disagreements, however, Egypt started to reorient its relations towards the Soviet Union, which became its major supplier of military equipment and its financial supporter for the construction of the Aswan High Dam. This alignment was reverted by President Anwar al-Sadat, who decided to reopen Egypt’s relations with the West and to start a de-escalation process with Israel (culminating with the 1979 peace treaty). Anwar al-Sadat was killed in 1981, and he was succeeded by then-vice-president Hosni Mubarak, who ruled Egypt for 30 years until 2011. In 2011, social unrest led to the overthrowing of President Mubarak. The consequent elections resulted in the advent of the Muslim Brotherhood with President Mohamed Morsi. However, General Abdel Fattah Al-Sisi has emerged as leading political figure vis-à-vis Morsi and during the previous 2013–2014 government, becoming President in June 2014.
In this cluster, the strategic relevance of Iraq, Egypt, Israel, and more recently Syria, goes way beyond the MENA region, where these countries are among the main players in different sectors. From an economic perspective, Israel is considered a developed country with a service-based economy particularly focused on the technological sector. Among the Eastern Mediterranean countries, Israel has the highest GDP per capita, more similar to the ones of Western European countries. At the same time, Egypt has the highest GDP rate, albeit with a lower GDP per capita PPP rate compared to Israel. Egypt’s economy is based on three main pillars: tourism, the hydrocarbon industry, and the Suez Canal. Jordan has historically been dependent on the international dimension (foreign loans, international aid, and remittances from expatriate workers), while the Lebanese economy has suffered from high debt and structural weakness in particular since late 2019.
Alliances have been forged, wars have broken out, shaky or robust peace treaties have been signed: these are some of the elements that characterize the East Mediterranean cluster. More recently, a common denominator strengthens the ties, as well as the rivalries, of these countries: the discovery of commercial offshore oil and especially gas fields over the last decade. The recent discoveries caused the advent of new hydrocarbon producing countries and allowed some other countries to increase their production. However, the Eastern Mediterranean is not a new oil and gas region, even though the East Mediterranean countries have limited oil reserves, with the exception of Iraq and Egypt and, to a lesser extent, Syria (Table 3.6).
Despite some political and economic challenges, East Mediterranean countries have managed to cooperate in the energy sector, establishing some energy trade schemes. In 2001 Egypt and Jordan agreed to build the Arab Gas Pipeline (AGP) to connect the two countries, including Lebanon and Syria. The pipeline became one of the most significant pipelines in the MENA region, as numerous other countries in the cluster planned to join (Map 3.5). A few years later, Israel, Iraq and Turkey expressed their willingness to participate in the project. While Israel was mostly excluded from the Pan Arab Electricity Project, an offshore gas pipeline was built to connect it with Egypt.
Source Authors’ elaboration
Arab gas pipeline.
In 2004, the four countries involved—Syria, Lebanon, Egypt and Jordan—decided to connect their gas grid with the Iraqi one to allow Iraq to export gas to Europe. Further connections were also evaluated. In theory, based on a 2006 MoU, the AGP was supposed to be connected to Turkey, with the Nabucco pipeline, for the export of gas from this cluster to the European countries. However, the pipeline between Syria and Turkey was not built, as it faces huge political and security challenges, given the current civil war in Syria and the two parties supporting opposing sides in the conflict.
Political instability has also damaged the pipeline. Indeed, the Arab Gas Pipeline was sabotaged numerous times, predominantly in Syria, in the Sinai Peninsula and in the adjacent pipeline connecting Egypt with Israel, thus highlighting low reliability and resilience, and preventing security of gas supply. For instance, numerous attacks against this pipeline were carried out in southern Syria, which led to nation-wide blackouts. This is one of the main reasons why importing countries—Israel (since 2013), Jordan (since 2015)—have turned their attention to LNG by renting FSRUs.
Other energy infrastructures have been built throughout the years and have also been damaged causing in most cases the termination of energy exchanges. Iraq has been exporting oil to Turkey through the Kirkuk-Ceyhan Oil Pipeline connecting Kirkuk in Iraq to Ceyhan in Turkey. However, this pipeline has been severely damaged by ISIS causing its closure in 2014. Another pipeline was the Trans-Arabian pipeline, which connects Saudi Arabia to Lebanon via Jordan and Syria. It operated from 1950 to 1982. In 1970, an incident in Syria prevented the export of 500,000 barrels per day of Saudi oil to the Mediterranean intensifying the pressure on oil transportation.
Over the last decade, the East Mediterranean region has drawn the interest of multiple players prompted by recent offshore hydrocarbon discoveries. The presence of hydrocarbon fields in the region was already signaled in 1999 with the discovery of the Marine gas field located 30 km from Gaza shores. Gas production from the Marine gas field never took place due to Israel’s harsh opposition, even though the Palestinian Authority had signed a concession agreement with the British Gas Group, Consolidated Contractors and Palestinian Investment Fund (PIF) (Alhelou 2020). A decade later, between 2009 and 2011, major offshore gas fields were discovered in Cyprus (Aphrodite field) and Israel (Tamar and Leviathan field). While the Tamar gas field entered the production phase as early as 2013, gas from the Leviathan field started flowing only in 2019. In 2015, the Italian energy company ENI discovered Zohr, the largest gas field in the Mediterranean Sea, in the Egyptian EEZ. ENI has a 50% stake and is responsible for the operations, while the other stakeholders are Rosneft (30%), BP (10%) and Mubadala Petroleum (10%) (Alhelou 2020). Gas production started less than two years later, with the main aim of satisfying the high domestic demand. These successful discoveries, along with numerous smaller ones, prompted also Lebanon to sign the Exploration and Production Agreement with the consortium ENI (40%), Total (40%) and Novatek (20%) to explore and develop the offshore blocks 4 and 9, located in the Lebanese EEZ (block 9 is in a disputed area with Israel).
The East Med region, however, is theatre of numerous tensions, which also reflect in the energy sector, through the disputes over the EEZ between countries in the cluster (Lebanon-Israel), and among external actors in the broader area (Turkey-Cyprus) (Map 3.6). Detailed cases and examples will be provided in Chap. 5 (see Sect. 5.2.2) with a geopolitical analysis of these tensions (i.e. between Cyprus and Turkey).
Gas fields and Exclusive Economic Zones in the Eastern Mediterranean
Notwithstanding the general geopolitical tensions in the region, gas exchanges can help promote energy security for importing countries (i.e. Jordan, Lebanon) and increase the economic benefits for gas exporting countries (i.e. Egypt, Israel). East Med countries have been trading natural gas throughout the past decades. Among East Med countries, Egypt has been a major gas exporter since the early 2000s. However, Egypt’s fortune quickly declined in the 2010s due to the structural challenges of its gas industry and political instability, making the country a gas importer (Fig. 3.29). Since 2018, Egypt managed to reverse its status. By contrast, Israel has turned to gas imports even though it has started to export some of its offshore gas. Iraq has started to import gas since 2016—especially from Iran—albeit the country ranks as one of the world’s largest flaring countries.
Source Authors’ elaboration on BP
Gas balance* of selected East Med countries, 2000–2019, bcm. *Production minus consumption. Exports (+) Imports (−).
2.1 Jordan and Lebanon
Jordan and Lebanon share numerous characteristics in economic, societal and cultural terms as well as in terms of hydrocarbon endowment, which is very limited in both countries. Despite these similarities, their energy and electricity sectors present some major differences. The trend of Jordan’s total primary energy supply by source has been more volatile than that of Lebanon, with the share of oil and natural gas changing abruptly from year to year. The most striking difference between Jordan and Lebanon is the role of natural gas.
Until the 2000s, Jordan’s TPES has been heavily reliant on imported oil. However, Jordan underwent a transformation of its TPES and electricity production in the early 2000s, with the advent of natural gas imported from Egypt that progressively replaced oil. However, the region’s growing instability, caused by the 2011 Arab Spring, disrupted also the regional gas markets. Egypt fell into political turmoil, its gas production decreased, and its gas exports to Jordan stopped.
By contrast, Lebanon has relied on natural gas (Egyptian gas transiting Jordan and Syria) only for a very short period (2009–2010) and in very modest volumes before Egypt cut off its exports due to the Arab Spring. The lack of steady supplies resulted in a very limited role of natural gas in Lebanon. The country has no proven natural gas reserves and very few options to import gas from neighboring countries. Moreover, in the 1980s and 1990s low oil prices reduced the incentive to switch from the use of fuel oil in the power sector. As oil prices increased in the 2000s, Lebanon began to reconsider its energy supply options. In 2009, natural gas entered Lebanon’s energy mix for the first time thanks to the Arab Gas Pipeline (AGP). Lebanon received 200 million cubic meters of Egyptian gas. Natural gas, however, had a short life in Lebanon’s energy mix. Gas supplies were subject to several and frequent disruptions due to numerous factors, notably delays in payments and later a series of explosions targeting the AGP. In such a challenging context, Egypt stopped gas supplies to Lebanon at the end of 2010 (Fattouh and El-Katiri 2015). The country’s TPES has thus been heavily dependent on oil imports (Fig. 3.31).
In the year 2014 the two countries had a comparable TPES (Fig. 3.30 and 3.32) and electricity mix (Fig. 3.31 and 3.33), when Jordan witnessed a peak of oil utilization and a low in natural gas. Due to the sudden reduction of Egypt’s gas supply, Jordan had to return to massive oil imports. The result was that in 2014 the total primary energy sources for both Jordan (8.2 Mtoe) and Lebanon (7.6 Mtoe) were largely dependent on oil (imports) (above 90%) with little diversification from other sources. The same result was visible in their overreliance on oil in electricity generation, which accounted for 92.5% and 99% of total electricity generation, respectively (18.2 TWh for Jordan and 17.9 TWh for Lebanon) (IEA n.d.). In those years, the two countries’ energy and economic sectors were thus highly exposed to the fluctuation of oil prices in the international market, further increasing the debt of the countries’ public utilities.
Jordan’s TPES 1990–2019 Mtoe. Source Authors’ elaboration on ENERDATA
Source Authors’ elaboration on ENERDATA
Jordan’s electricity generation 1990–2019 TWh.
Source Authors’ elaboration on ENERDATA
Lebanon’s TPES 1990–2019 Mtoe.
Source Authors’ elaboration on ENERDATA
Lebanon’s electricity generation 1990–2019 TWh.
However, in 2015, Jordan restarted to increase the share of natural gas in its energy mix and electricity generation (thanks in particular to LNG imports as well as pipeline gas imports from Israel – see below), while Lebanon’s share of gas remained roughly the same. By 2017, natural gas in Jordan accounted for 37.9% (3.51 Mtoe) of the total primary energy source and 79.96% (2.8 TWh) of electricity generation (IEA 2018g), thus resulting in the second rapid adoption of gas for electricity generation, and the symmetric decrease in the share of oil.
Between 2000 and 2019 both countries witness an astonishingly high growth in electricity consumption rates: 5.8% per year for Jordan and 3.4% per year for Lebanon. In Lebanon, power production at peak periods (e.g. 2050 MW in 2018) does not satisfy the domestic power demand in peak times (e.g. 3500 MW in 2018) so that power blackouts occur daily ranging from 3 to 4 h in well-off areas to 12 h per day in worse-off places. With the current dramatic economic crisis, power cuts have become longer on average in all cities and neighborhoods. Thus, consumers have to rely also on highly polluting private diesel generators, buying electricity at high prices to satisfy their electricity needs. For both countries, high domestic demand for electricity is mostly due to population growth, enhanced by the large influx of Syrian refugees during the war in Syria: as of November 2021, Lebanon received about 844 thousand registered refugees and Jordan 672 thousand, while hundreds of thousands more are unregistered (UNHCR 2020). This represents around 12% of the population in Lebanon and 6.5% of the population in Jordan which had to be absorbed in a short time frame. The inefficiencies of the countries’ electricity sectors, also resulting in high electricity demand, are increased by old and inefficient power plants, high transmission line losses, non-authorized illegal cables that take unpaid-for electricity to entire areas, and the generalized inability of the power utility to fully collect payments. Indeed, Lebanon’s public utility Electricité du Liban (EDL) collects payment for just 50% of the electricity it produces. Due to the resulting unreliability of the country’s electricity supply, many people who can afford it use their own diesel-based power generation sets.
Both Lebanon, with EDL, and Jordan, with National Electric Power Company (NEPCO), have a legacy of indebted public utilities. Due to the absence of resource endowments, both countries are large importers of hydrocarbons to satisfy their domestic energy demand. Thus, high reliance on oil, with consistently high oil prices in the late 2000s and first half of 2010s, coupled with the aforementioned energy system’s inefficiencies led to an astonishingly high debt of the countries’ public utilities. For instance, EDL benefits from net governmental transfers amounting to $1–1.5 billion per year, which correspond to 25% of the country’s public deficit for the year 2018. The accumulated cost for Lebanon to subsidize EDL amounts to 40% of the country’s public debt since 1992. Similarly, NEPCO’s debt amounts to $7 billion, corresponding to 18% of the total Jordanian debt, especially due to the substantial operating losses that the utility incurred between 2011 and 2014, when oil prices were above $100 per barrel (Fairbanks 2019).
The year 2015 was a turning point for Jordan, a radical year of change in terms of energy policy. That year, it became clear that NEPCO losses were unsustainable in the medium term, thus the country decided to diversify its energy sources especially for power generation. This decision marked the rise of gas and renewable sources. Regarding gas, Jordan had imported gas from Egypt through the Arab Gas Pipeline from 2003 to 2014, when several accidents on the Egyptian section of the pipeline and gas supply constraints in Egypt disrupted imports. After the Arab Spring, imports dropped sharply, with a volume ten times lower in 2014 than in 2010. In 2015, imports have restarted following the opening of an LNG regasification terminal. By 2019, imports had again reached the 2010 levels (3 bcm), but from different sources. LNG is the main source of this gas, with the US and Russia being the main suppliers. Since 2015, Jordan has Golar Eskimo, a Floating Storage and Regasification Unit (FSRU), off the Red Sea port of Aqaba. The unit has a total capacity of 5.1 bcm/year. Moreover, Jordan envisaged gas imports from Israel’s offshore gas fields. In 2017, it started importing small amounts of gas (2 bcm over 15 years) from Israel’s offshore Tamar gas field, while in 2019, a 15.5 km-long gas pipeline connecting Leviathan to Jordan was laid near the southern end of the Dead Sea. Noble Energy and its Leviathan partners supply 45 bcm over 15 years (equal to 3 bcm/year). As a result, in only two years, gas experienced a remarkable come-back in the power mix (increasing from 7% in 2014 to 84% in 2016). Thanks to the increasing tariffs (elimination of subsidies) and the low oil (and thus gas) prices, NEPCO managed to register for the first time in decades a net profit in that period.
Since 2015, the country introduced conspicuous renewable energy capacities, primarily solar PV and wind, enabling the renewable share to increase from zero to almost 7% of the country’s electricity generation, (IEA 2018g). Some important renewable projects came online, such as the wind plant in Al-Tafileh (117 MW) in 2015 and the solar plant in Ma’an (200 MW) in 2016. By 2020, Jordan had a capacity of installed solar PV amounting to 1 GW, close to the 1.2 GW target by 2025. Similarly, the country’s wind capacity is estimated at 500 MW in 2020, close to the 800 MW target by 2025.
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Energy sector today: two diverging paths
A question may arise: “Why hasn’t Lebanon followed the example of Jordan, in terms of a rapid adoption of gas and renewable energy sources?”. Indeed, since 2015, the energy sectors of the two countries have again experienced two diverging paths. Numerous reasons may explain this difference. Jordan, for instance, does not hold gas reserves, while Lebanon has hoped for many years to exploit its East Med gas potential. Moreover, Lebanon’s political and prolonged stalemate dramatically hinders changes to its energy sector or the adoption of energy subsidy reforms.
Natural resource endowment
A stark difference between the two countries regards their abundance of natural resources. Jordan is poor in conventional hydrocarbon resources while rich in oil shaleFootnote 9 reserves (the world’s fifth largest), which cover around 60% of the country (Ababsa 2013), and uranium reserves, estimated at 59,500 tU (World Nuclear Association 2019). To date, these reserves have not been fully exploited and have not contributed to the country’s energy mix. Negligible gas reserves and high domestic gas demand oblige the country to import 95% of its gas consumption.
Similarly, Lebanon is not a hydrocarbon resource-rich country. However, thanks to the recent discoveries in neighboring EEZs, in 2017 Lebanon awarded the first license for offshore oil and gas exploration and production to a consortium composed of Eni, Total and Novatek. In February 2020, the consortium announced the start of drilling activities for the exploration phase in blocks 4 and 9 (Asharq Al-Awsat 2020). Nevertheless, in April 2020, Total announced that while traces of gas were found in block 4, no reservoir was discovered. Lebanon also approved a second licensing round for offshore energy development with Russian companies, Malaysian Petronas and BP expressing interest in this latest bidding. Overall, while Jordan might be tempted to start developing oil shale, its investments in infrastructure for importing gas are not likely to be lost. On the contrary, investments in infrastructure to import gas (i.e. FSRU) in Lebanon seem to be in stalemate, since they are conditional on possible discoveries of commercially viable offshore gas fields.
Energy subsidy reforms
Both Jordan and Lebanon have been witnessing high domestic electricity demand, but their approach to energy subsidy reforms has been quite different. Lebanon, due to its internal political struggles, maintains energy subsidies, which in turn keep energy consumption rates high. As an example, in June 2019, the constitutional court halted a subsidy reform that the government had managed to agree on and approve. Nevertheless, a reform of the subsidy scheme was carried out by the Central Bank in the summer of 2021 when it decided to end subsidies for petroleum products, which had cost the country $3 billion per year. This is a noteworthy amount especially in the context of a significant drop of foreign exchange reserves, which went from $40 billion in 2016 to $15 billion in March 2021. The subsidy reform resulted in an increase of the gasoline price by 35% and of the diesel price by 38% in June 2021. It should here be pointed out that while energy subsidies are distortive and should be reformed and eliminated, they should be coupled with other accompanying measures that ensure safety nets to low-income families. Thus, the energy subsidy reform in the case of Lebanon was not beneficial or advantageous at all, given the dire economic conditions of the population, and the lack of accompanying policies to absorb the strong price increases for the poorest parts of the population. As detailed here below in “Lebanon’s free fall” section, the country is sinking, with more than half of the population below the poverty line and with the current crisis being labeled by the World Bank as one of the worst 3 economic crises in the last 150 years worldwide.
Jordan’s electricity sector situation remains very similar to Lebanon’s, though it has been a front-runner in petroleum subsidy reforms in the MENA region. Indeed, Jordan has not yet carried out an electricity reform, even though the disruption of gas supplies from Egypt led to a significant increase in the production costs of electricity, which were borne by NEPCO and not passed onto final consumers (Atamanov et al. 2015). Thus, similarly to Lebanon, NEPCO started running a deficit every year since it did not increase the electricity price for consumers. However, Jordan has made a step further in petroleum subsidy reforms. Due to fiscal pressures, Jordan rolled out a subsidy reform of petroleum products between 2008 and 2010, by setting prices at the international level with a consequent subsidy decrease (from 2.5% of GDP in 2007 to 0.3% in 2010). However, in 2010, oil prices increased to above $90 per barrel so that the government was obliged to phase out the reform. Already in 2012, petroleum subsidies amounted to 2.8% of GDP, or 9% of the government’s budget, leading to an unsustainable fiscal burden. Thus, in the same year, Jordan drastically cut subsidies on petroleum and implemented a large-scale cash transfer to all those earning less than JD 10,000 (equivalent to 7100 USD) a year, roughly corresponding to the income of two-thirds of the total population. This program is therefore similar to the Iranian subsidy reform, which however, provided cash transfer to all Iranians, regardless of their income or wealth.
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Case study: Lebanon’s freefall
Reforms in the Lebanese energy sector have become even more unlikely and challenging with the country’s dire economic crisis. Social unrest in Lebanon began on October, 17th, 2019, when the government suggested the implementation of a tax on calls via social media, in particular WhatsApp, which was seen as a tipping point after years of governmental mismanagement. Demonstrators, regardless of social class and religious affiliation, started to peacefully block roads demanding an end to sectarian politics, corruption and the introduction of fair taxes and a system to hold the corrupt accountable. At the end of October, the then Prime Minister Saad Hariri resigned. However, in November, banks started to impose limitations on the amounts withdrawn in dollars, and later banks and ATMs were shut down. It should be noted that in Lebanon there was a fixed exchange rate of $1 corresponding to 1500 Lebanese Lira, and the two currencies were used interchangeably in any daily life activity. The availability of dollars in the system was based on high interest rates paid to wealthy investors, however, over time, the gap between the dollars needed to repay investors and the real amount of money available in the banks widened. With the political crisis, Lebanese citizens rushed to withdraw dollars from their bank accounts while investments diminished due to the country’s political instability and difficulty in repaying interest rates. Thus, a shortage of dollars occurred, drastically diminishing the availability of imported goods, on which Lebanon is highly dependent. The economic crisis escalated in March 2020 with the country defaulting on debt payments—$1.2 billion in Eurobonds—for the first time and the slowdown of economic activities due to the Covid-19 lockdown. As a result of all the aforementioned concomitant effects, in July 2021, the Lebanese Lira lost 90% of its value since October 2019, leading to skyrocketing food prices as Fig. 3.34 depicts (food inflation reached 400% in December 2020 with respect to the previous year), shortage of imported goods, including oil, which is necessary to run the power plants resulting in a so-called “fuel crisis”. Figure 3.33 depicts the catastrophic consumer prices trend between July 2019 and November 2020. Indeed, the low levels reached by foreign exchange reserves resulted in worrying shortages of medicines and oil. Oil products make up 98% of the country’s electricity mix, and they are also used to run the private generators (diesel). Indeed, in August 2021, the Lebanese Minister of Electricity stated that the country needs 3 GW of power, but it is only able to produce 750 MW due to fuel shortages, resulting in only 1–2 h of electricity per day. Given the high scarcity of public electricity, also private generators are unable to satisfy the power demand. Due to the shortage, the skyrocketing prices of generator and diesel made them inaccessible for the majority of the population. Consequently, businesses had to reduce the number of opening hours, including bakeries, and hospitals which were on the verge of closing down some of their departments. Long queues at petrol stations have become the norm. Another dramatic effect of the fuel crisis hitting Lebanon regards the public water system which was also “on the verge of collapse” according to UNICEF in July 2021. The UN Agency has estimated that 71% of the population is at risk of losing access to water, as the majority of water pumping is forecasted to stop operating in the following months due to shortage of fuel, funding and chemicals (i.e. chlorine).
Source Authors’ elaboration on Central Administration of Statistics (Lebanon)
Lebanese consumer prices trend (changes in %) between July 2019 and November 2020.
In 2021 this dire economic situation has led about 50% of the population under the poverty line and 75% in need of aid and assistance, far beyond the percentage of the previous year, when mostly refugees (Syrian and Palestinian) relied on aid (Qiblawi 2020). Indeed, Lebanon is the country with the highest per capita concentration of refugees in the world, where only Syrian refugees constitute 30% of the total population (European Civil Protection and Humanitarian Aid Operations 2020).
Amid this socio-economic crisis, the Lebanese population also had to endure the blast at Beirut Port on August 4th, 2020, due to the explosion of 2750 tons of ammonium nitrate, which tragically killed 218 people and wounded thousands, causing significant infrastructure and economic damages.
Regardless of the highly unstable situation, the different political parties in Lebanon have been unable to agree on the formation of a government and on highly needed economic reforms. Indeed, Prime Minister Hassan Diab, who was leading a caretaker government, resigned in the wake of the Beirut explosion and was substituted by Saad Hariri, the prior Prime Minister between 2009 and 2011 and between 2016 and 2020. Nevertheless, in July 2021, Hariri also resigned and multibillionaire Najib Mikati (who had already been Prime Minister in 2005 and between 2011 and 2014) was appointed as new Prime Minister with the goal of forming a government, which is a priority to secure international support. By the fall of 2021 (the time we finished writing this book), the government had not yet reached an agreement on reforms aimed at reducing corruption, carrying out fiscal policy reforms and increasing the efficiency and effectiveness of public services, which are conditional on receiving a $10 billion loan from the IMF.
Similarly, Lebanon did not manage to agree on reforms in order to access a $11 billion package of loans and grants available since 2018 and decided at the so called Paris Conference, made up of 50 countries and international organizations. (Irish and Pennetier 2018). Carrying out fiscal reforms was deemed necessary by investors and donors, as Lebanon has a staggering and highly unsustainable projected public debt of 161.8% of GDP in 2020. Even potential oil and gas discoveries would not solve Lebanon’s structural problems. Overall, energy security has become paramount with the dollar shortage, which has forced the country to drastically reduce fossil fuel imports for electricity generation. Thus, despite the current crisis, the country, investors and donors, in addition to tackling economic and governance reforms, should focus on a green recovery by investing in sustainable technologies including renewable energy.
In conclusion, the starting points of the energy sectors of Lebanon and Jordan were very similar. Nevertheless, Jordan managed to partly solve some issues with a combination of favorable factors, while changes to the Lebanese energy sector were hindered by broader socio-economic, domestic, political and geopolitical forces. For all these diverging issues, Lebanon adopted a “wait-and-see” approach, which is also fueled by the hope of possible gas fields discoveries, which may dramatically change Lebanon’s energy system landscape and spillover in broader economic and political spheres, but which may also never happen. In the meantime the country is struggling against a deep socio-economic and energy crisis.
2.2 Egypt
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Opposing forces in Egypt’s energy sector between 2010 and 2016: decreasing production and increasing consumption
Egypt is a large, old oil province, as oil had already been discovered in 1886, and in 1907 the Egyptian Oil Trust Ltd was established with the aim of developing, drilling and producing oil. Most of its crude oil production is traditionally located in the Western Desert and Gulf of Suez. Other important producing areas are the Eastern Desert, Sinai, Mediterranean Sea, Nile Delta, and Upper Egypt. In the last decades, Egypt has changed its energy status from being an important net oil exporter up to the mid-2000s to a brief net oil importer, and in the 2010s again a net oil exporter, although to a lesser extent (Fig. 3.35). The declining ability to export was the result of rising domestic consumption combined with declining production. Egypt is facing a steadily declining production rate from its legacy onshore fields. Since 2014, oil production has declined by 11%. At the same time, Egypt’s oil consumption has significantly increased throughout the last decades and up to the mid-2000s when the government introduced measures to curb oil demand by substituting it with gas. Over the last decades, the increasing demand was driven by a larger population and economic development, while the drop in supply was due to a combination of difficulty in finding new reserves to substitute depleting fields, and a consequent drop in new investments in the oil sector. Besides being a traditional oil province, Egypt also plays a vital role in global and regional oil infrastructure thanks to the Suez Canal and the SUMED oil pipeline (from the Red Sea to the Mediterranean Sea).
Source Author’s elaboration on ENERDATA
Egypt’s oil production and consumption 1980–2019, Mt (left) mb/d (right).
There is an interesting story on Egypt’s natural gas. Until the late 1980s, natural gas in Egypt was considered a by-product of oil production. Natural gas has become a linchpin of Egypt’s energy policy only since the mid-1990s, when this country’s oil production began to decline. Egypt changed its regulatory framework providing better economic conditions for the discovery and development of its gas resources. These changes made possible substantive discoveries throughout the 1990s, with reserves increasing from 364 bcm in 1990 to 2127 bcm in 2010 (BP 2020), as shown in Fig. 3.36. Egypt decided to incentivize its gas production in order to meet growing power consumption caused by population growth, limited hydro generation capacity and a switch from oil to gas.
Source Authors’ elaboration on BP (2020)
Egypt’s proven natural gas reserves 1980–2019, Trillion cubic meters.
In 2009, Egypt’s gas production reached its then peak, amounting to 60.3 bcm, while domestic consumption was 40.9 bcm (BP 2020), leaving 19.4 bcm for export. However, Egypt could not maintain these production levels and the context drastically changed in the subsequent years. New contracts were halted in 2012–2013 and the government chose to curb the amount of natural gas for industries rather than residential areas to avoid social discontent, especially following the Arab Spring protests (Meighan 2016). Political disorders following the 2011 Arab Spring contributed to the inability of Egyptian authorities to continue exploration activities. Thus, the country’s gas production decreased by 31% between 2012 and 2016 (Fig. 3.37).
Source Authors’ elaboration on ENERDATA
Egypt’s gas production and consumption, 1980–2019, bcm.
To satisfy growing domestic demand, Egypt progressively stopped exports, ordered the diversion of gas to the domestic market and even started to rely on LNG imports. In 2015, Egypt acquired two Floating Storage Regasification Units (FSRU), started importing natural gas (amounting to 8% of total natural gas consumption) and received LNG from numerous international players (BP, Shell, Gazprom and PetroChina). However, higher domestic production came on line in 2015, in particular also thanks to the commissioning of the large offshore Zohr discovery, which allowed Egypt to progressively stop using its two FSRUs and cancelling the third planned FSRU (Fig. 3.38).
Source Authors’ elaboration on ENERDATA
Egypt’s natural gas imports and exports, 1990–2019, bcm.
By 2016, Egypt’s natural gas production reached a decade-low of 40.6 bcm, while becoming at the same time the largest natural gas and oil consumer in Africa, accounting for 37% and 22% of total consumption in 2016, respectively. Such high levels of hydrocarbon consumption are mostly due to an increasingly high domestic energy demand, which currently represents one of the main challenges for Egypt.
A wide range of factors contribute to the increasingly high energy consumption, ranging from population growth (an average of 1.9% per year between 2010 and 2020) (The World Bank 2019a), economic growth (an average of 3.78% per year between 2010 and 2020) (Trading Economics 2019c), increased industrial localization and production, especially of energy-intensive sectors, limited energy efficiency and high energy subsidies. Industry is Egypt’s major added value as a percentage of GDP, reaching a peak of almost 40% in 2014. In particular, Egypt has developed Africa’s largest refining sector, which is the second most energy-intensive industry after the chemical one. The key role of refineries in the country contributes to the high energy consumption in the industry sector, despite their current underproduction, due to aging and maintenance issues. Another key driver of high energy demand in the country regards low energy efficient levels. As a matter of fact, energy intensity in Egypt is the highest in the North African region, being twice as high as Morocco and four times higher than other industrialized countries. Industrial and residential appliances consume an average of 20% more electricity than the recommended international measures.
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Measures to satisfy high energy demand
The increase in energy consumption coupled with the decrease in gas production—from 60.3 bcm in 2009 to 40.3 bcm in 2016 (BP 2020)—led the Egyptian government to publish the “Integrated Sustainable Energy Strategy to 2035” in cooperation with the European Union in 2013. Within this framework, renewable energy sources were set to represent 20% of the electricity mix by 2022 and 42% by 2035. The following section will provide an overview of renewable energy development in Egypt, in terms of objectives, projects and possible scenarios regarding the attainment of the aforementioned targets.
Energy subsidy reform in an unstable economic context
Energy subsidies being a major driver of Egypt’s increasing energy demand, a reform was enacted in 2016 with the aim of eliminating them. It was carried out as part of broader economic and financial reforms in order to reduce the high fiscal deficit, which reached 12.5% of the GDP in the fiscal year 2015–2016. The exchange rate was overvalued, the current account deficit reached 6% of GDP in 2015–2016 and GDP growth, averaging 4.3%, grew less than in the period 2004–2010 (5.5%).
When the first reform to energy subsidies was introduced in 2014, the Egyptian economy was not thriving. At that time, the combined subsidies on electricity and fuel represented 6% of the GDP and 21.9% of total government expenditures. With the first wave of reform in 2014, diesel prices were increased by 64%, gasoline 80 prices by 78%, gasoline 92 prices by 40%, natural gas prices six-fold, while LPG prices remained subsidized, since the majority of LPG consumers were the worst-off. The Egyptian subsidy reform was timely, since it also took advantage of low international prices in 2014–2015. In 2016 and 2017, the Egyptian government decided to further cut down on energy subsidies, aiming at eliminating fuel subsidies by 2019 and halving electricity subsidies by 2020. Thus, LPG prices rapidly increased by 100%, gasoline 80 by 47% and gasoline 92 by 43%. In this second round of reforms, electricity prices were also raised by 40% (Breisinger et al. 2018). However, the devaluation of currency at the end of 2016 meant that fuel was still heavily subsidized. Overall, the government reduced spending in fuel subsidies by 46% in the fiscal year 2020–2021 compared to the previous year, while it increased electricity prices by 17–30% in July 2020. To mitigate the negative impact of energy price increase for the worse-off households, in 2018 Egypt rolled out a conditional cash transfer scheme and food subsidies for over 2 million families (Breisinger et al. 2019).
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Gas discoveries in Egypt: a relief for the country’s energy sector and beyond
Despite this grim framework, between 2011 and 2016 some of the major challenges faced by Egypt in the gas sector—satisfying the high and increasing energy demand and offsetting the decrease in hydrocarbon production—were partly solved with the recent discoveries of large and commercially viable offshore natural gas fields. These discoveries may also contribute to reviving industrial production, preventing potential social unrest, while reducing economic instability and the exacerbation of foreign exchange shortage.
Eni’s discovery of Zohr, the largest gas field ever discovered in the offshore Mediterranean Sea in 2015, represented a true blessing for Egypt. In 2020 the Zohr field contributed to 40% of Egypt’s total gas production, and it has reached an output of about 28 bcm, which represents the peak plateau production. Natural gas production from Zohr started flowing though offshore pipelines to Egypt at the end of 2017. Other smaller fields were discovered in the same years, among which the Atoll field (2015) in the East Nile Delta, with BP being responsible for all the field development and holding 100% equity in the discovery (Offshore technology n.d.). Thanks to recent discoveries and the quick ramp up of production, Egypt was able to halt all of its LNG imports through its two FSRUs (and to cancel the planned third FSRU).
In recent years, Egypt has re-emerged as an LNG exporter. In 2019, Egypt’s LNG exports amounted to 4.5 bcm, more than doubling its 2018 level, mostly thanks to the ramp up in gas production from the Zohr gas field. Egypt owns the only two LNG export terminals present in the East Mediterranean region: the Idku and Damietta plants. The two plants have a combined capacity of 19 bcm per year. However, for several years only the Shell-operated Idku was in operation and running at full capacity. Only in 2021, Eni, along with its Egyptian partners, managed to restart the Damietta plant, which had been idle since 2012. Egypt sells its LNG to a wide range of importing countries, both in Europe (France, Italy and Greece) and Asia (India, China, Singapore, Japan and Pakistan). Overall, total gas production reached 64.9 bcm in 2019 so that the country has the possibility to export around 6 bcm of natural gas, net of domestic gas demand.
Despite these major discoveries and developments, Egypt also started importing gas from Israel in January 2020: the paradox lies in the fact that a decade ago, until 2012, it was Israel that was importing gas from Egypt, satisfying 40% of its natural gas demand. The new deal signed to import gas may have been a way to settle the dispute with Israel, which accused Egypt of reneging contracts when the latter cut gas exports in 2012, following numerous attacks on the connecting subsea gas pipeline Arish-Ashkelon. Overall, the new gas deal with Israel, amounting to $19.5 billion for 85 bcm over a 15-year period, might also represent an opportunity for Egypt, since it ensures the country’s capacity and reliability as LNG exporter.
Along with natural gas, Egypt aims at harnessing its renewable potential. In 2016, Egypt released the 2035 Integrated Sustainable Energy Strategy setting a target of 20% of electricity production from renewables by 2022, and 42% by 2035. By that date, solar is expected to account for 25% of total power production, while wind and hydropower for 14% and 2%, respectively. The private sector is expected to play a key role in developing new capacities, as further detailed in Chap. 4 (see Sect. 4.3.2).
The long history as an oil province and the four-decade development of the gas sector contributed to the dominant role of hydrocarbons in Egypt’s TPES. In 2019, oil and gas represented together 91.9 Mtoe, or 96% of TPES. Egypt is thus still almost entirely reliant on oil and natural gas, with natural gas accounting for 62% of total TPES and oil for 34% (Fig. 3.39).
Source Authors’ elaboration on ENERDATA
Egypt’s TPES 1990–2019, Mtoe.
Natural gas plays a predominant role also in electricity generation (195.2 TWh in 2019), accounting for 79% of the total (ENERDATA n.d.) and growing strongly (Fig. 3.40). Natural gas increased its relevance as Egypt decided to install 3.6 GW of gas turbines in an emergency program for 2015. Indeed, the country has traditionally faced a context of chronic electricity shortages. Egypt used its domestic gas production to satisfy its growing power consumption. Also, hydro traditionally occupies a relevant position in the country’s electricity generation (7%), while solar and wind energy still represent a minority share in the electricity mix—1% and 2%, respectively. But wind and solar energy capacity are expected to steeply increase thanks to numerous new renewable projects coming online in the next few years.
Source Authors’ elaboration on ENERDATA
Electricity generation of Egypt 1990–2019, TWh.
Regardless of the huge difference in size, the current energy mix allows a comparison between Egypt and Jordan as they share some similarities regarding power generation by source. In both countries, natural gas represents about 80% of total power generation, followed by oil and then other sources. And in both countries the latest efforts have focused on developing renewable energy capacities. Nevertheless, a major difference arises: while Jordan imports more than 93% of oil and gas utilized for electricity generation, Egypt is a major oil and gas producer with large reserves. It is therefore midway between resource-rich countries in the GCC and Iran and resource-poor ones (e.g. Jordan and Lebanon).
In conclusion, Egypt may take advantage of the global energy transition, namely the increasingly important role of gas, by becoming a relevant player in gas production, thanks to large gas fields discoveries. In the short to medium term, gas—as the cleanest of all fossil fuels—has a certain potential also in transition scenarios in order to replace more polluting fuels. Also, the country may develop into a key transport hub for gas, thanks to its ability to export imported gas through its LNG terminals and its strategic regional location. The expected increase in LNG trade in the coming years also implies higher revenues from the tolls collected for the Suez Canal and its LNG terminals. In the longer term, Egypt could take advantage of its important solar and wind potential to export either renewable electricity (exporting solar electricity to Europe is an old Egyptian dream since the 1990s) or synthetic fuels, for instance in the form of green hydrogen or similar.
2.3 Israel and Palestine
Israel’s energy sector has recently witnessed a significant transformation fostered by the newly discovered offshore gas fields and by increasing investments in the renewable energy sector. Domestic natural gas and renewables have replaced coal and oil imports in the Israeli energy mix, enhancing its energy security. On the contrary, ensuring energy security of supply remains a priority for Palestine, which heavily relies on Israel, and often faces political and financial constraints to extend the grid and increase imports from Jordan and Egypt.
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Israel: Main trends, targets and discoveries: enhancing energy security
Israel has notoriously lacked its own oil and gas reserves, in particular compared to other MENA countries. The lack of hydrocarbon endowment, combined with being the only non-Arab country in the region, forced Israel to find energy solutions to preserve its energy security in an unfavorable political regional context due to political animosity with its Arab neighboring (and oil producing) countries. Coal imports have thus played a crucial role, since they come with a significant lower geopolitical risk compared to oil. However, since the 2000s, Israel has increasingly developed its gas industry following the offshore gas discoveries in the Eastern Mediterranean Sea (Fig. 3.41).
Source Authors’ elaboration on ENERDATA
Israel’s natural gas production and domestic consumption 2000–2019 bcm.
Israel’s energy mix has thus become more diversified thanks to the considerable gas discoveries which date back only a decade. In 2019, Israel’s TPES (24.1 Mtoe) was composed of 44% of oil, 33% of natural gas and 20% of coal and the rest of renewable energy sources.
Traditionally, Israel’s TPES was totally reliant on oil and coal imports. Similarly to Morocco, coal satisfies energy security concerns, given the peculiar geopolitical landscape. In the early 2000s, natural gas started to appear in the energy balance, and it progressively gained market share in the Israeli TPES (Fig. 3.42). The main source was Egypt. However, following the 2011 Arab Spring, Egypt halted gas exports to Israel, thus forcing Israel to briefly increase its oil imports once again. Then, starting already in 2013, while waiting to develop its own gas fields, Israel imported LNG thanks to a FSRU with a capacity of 3.5 Mt/y. With the commissioning of Leviathan, LNG imports decreased to 0.55 Mt/y in 2020.
Source Authors’ elaboration on ENERDATA
Israel’s TPES 1990–2019 Mtoe.
Natural gas has expanded its role in the generation of electricity (Fig. 3.43). Figure 3.42 illustrates the impact of the development and production of gas fields discovered at the end of the 2000s-beginning 2010s, leading to coal being partly replaced by natural gas. Since 2000, coal use for power generation in Israel decreased by 31%. In 2019, natural gas accounted for 66.2% of total electricity generation (68.74 TWh), coal for 30.6%, oil 0.5%, and solar PV and wind 2.8% (ENERDATA n.d.).
Source Authors’ elaboration on ENERDATA
Israel’s electricity generation 1990–2019 TWh.
Israel still lags behind other oil-importing countries (i.e. Jordan and Morocco) in the MENA region in terms of renewable energy sources for electricity generation. As aforementioned, between 2005 and 2015 Israel decreased its reliance on oil and especially coal, which represented the main energy source for electricity generation (Fig. 3.42), while natural gas consumption increased fourfold in the same time period. The change in the share of energy sources for electricity generation was vital for Israel, which attained a high level of energy security shifting away from its precarious position of net importer of coal, oil and natural gas (mainly from the neighboring Egypt).
This move was possible thanks to the discovery of numerous offshore gas fields over time, which also allowed the replacement of gas production from almost depleted gas fields with newly developed ones. Gas production, started in 2004, increased strongly from 2013, reaching 11 bcm in 2019. Israel has three operational offshore gas fields. The first commercially viable gas field Mari-B, which satisfied 40% of total gas demand, entered the depletion phase in 2012 and gas production was halted in 2013. The depletion of production from the Mari-B field combined with the cessation of Egypt’s gas imports contributed to the steep drop in the share of natural gas for electricity generation shown in the graph above. In the same year, the 280 bcm Tamar gas field replaced the Mari-B field by entering the gas production phase and satisfying more than 50% of Israel’s electricity needs and nearly 100% of the fuel needs for industry (EIA 2016). Nevertheless, the greatest discovery, the Leviathan gas field (605 bcm), was made in 2009 by Noble Energy, Ratio Oil Exploration and Derek drilling, and entered the production stage in December 2019 (Beckman 2020).
The management of these resources has generated strong political sentiments and arguments, resulting in the delay of key investment decisions (Hafner and Tagliapietra 2016). Having always been reliant on imported fuels, Israel looked at its offshore natural gas resources as a valuable tool to improve its energy autonomy in a region dominated by Arab producing countries. Therefore, Israel was immediately committed to using its natural gas to meet its domestic demand. This approach clashed inevitably with Noble Energy’s business ambitions to export gas in the global gas markets earning revenues. After long negotiations, Israel set limits on how much gas could be sold abroad, earmarking nearly 60% of reserves for domestic use. In the 2010s, Israel and Noble Energy looked into different export solutions to earn profits from offshore gas. LNG would be the most rational solution to gain market share in the profitable and growing Asian markets. However, the construction of a LNG liquefaction terminal on the Israeli coast was strongly contested, while the FLNG terminal was abandoned due to its high costs compared to the limited reserves volumes. Also connecting Israeli reserves with Cyprus’ ones and building an LNG export terminal in Cyprus was dismissed for security reasons. Lastly, Israel evaluated the possibility to build a pipeline to Israel’s mainland and then to Eliat in the Gulf of Aqaba on the Red Sea. This option would allow Israeli gas to bypass the Suez Canal on its way to Asia. However, the limited dimension of the Gulf of Aqaba did not allow LNG tankers to operate safely, hence inducing Israel to abandon the project. Exporting gas to Turkey was also not an option for geopolitical reasons.
In 2014, Israel and Jordan reached a deal for 2 bcm of gas over 15 years. In 2017, Israel has begun to export gas from the Tamar field to Jordan. Noble Energy has also signed a contract with Jordan for a 3 bcm gas supply. Moreover, at the end of 2019, Israel authorized natural gas exports from the Tamar and Leviathan fields to Egypt using the existing pipeline offshore Gaza, adapted with reverse flow. The $19.5 billion deal envisages the supply of 85 bcm of gas from Leviathan over 15 years.
In order to further enhance energy independence, in 2020 Israel announced it would scale up its renewable target in the energy mix for 2030 from 17 to 30%, with solar PV playing the primary role. Indeed, these targets seem highly ambitious, as of 2018 renewable energy sources represented 2.8% of electricity generation and 2.36% of TPES (IEA n.d.). Renewables are expected to replace, with natural gas, coal in electricity generation as Israel signed the Powering Past Coal Alliance in 2018 with the aim of phasing out coal by 2030. The large investments needed to attain the 2030 targets are expected to come mostly from the private sector with around $23 billion (Bellini 2020). The deployment of solar PV is now supported by a regulatory framework including net metering and feed-in-tariffs for rooftop solar PV and tenders for large-scale solar PV projects.
Overall, Israel’s energy sector is not yet competitive so that, in order to attract conspicuous private investments in the renewable field, reforms in this sector have to be carried out. Indeed, the Israel Electricity Corporation (IEC) dominates generation and distribution, even though in the last couple of years the share of independent generators has grown, reaching 35% of the market share in 2018. As generation from renewable energy sources is private, the share of independent generators is expected to further grow in the coming decade within the framework of 2030 renewable targets. IEC had established the National Coal Supply Corporation, which is responsible for coal imports. Regarding gas, the private sector is in charge of gas fields’ discoveries, development and production while gas transmission is in the hands of the government’s subsidiary Natural Gas Lines Company (INGL) (OECD 2019).
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Trends and key characteristics of the Palestinian energy sector: lack of energy security
Palestine is inexorably dependent on Israel for its energy sector—as in most other fields. Imports from Israel satisfy 99% of total electricity supply in the West Bank and 64% of total supply in Gaza. Overall, 87% of the electricity consumed is imported from Israel, 4% is imported from Egypt and Jordan and the remaining 9% is provided by the sole Gaza power plant (Dawabsheh 2019). In Palestine, power demand is higher than power supply, resulting in seasonal electricity blackouts in the West Bank, which are also due to an increasing number of unpaid bills. Daily blackouts are particularly severe in Gaza, lasting an average of 16–18 h per day. These blackouts particularly affect the most vulnerable part of the population, who is not able to afford a private diesel generator.
The West Bank and Gaza experience two different energy conditions. Overall, recent agreements have enhanced energy security for the West Bank, while Gaza remains excluded from any amelioration also in the energy sector. In May 2018, the Palestinian Electricity Transmission Co. Ltd. (PETL) reached a 15-year agreement with the state-owned utility Israel Electric Corporation (IEC) to gain the responsibility for electricity distribution in the West Bank. In order to increase energy security and diminish the nearly total dependence on Israel, the Palestinian Authority has negotiated with Jordan to increase the amount of imported electricity. Nevertheless, Israel has prevented the construction of power networks as well as the entry of material and development of solar PV in Area C, as will be discussed in Chap. 4 (see Sect. 4.3.3). These restrictions play a crucial role in preventing Palestine from developing an efficient, effective and sustainable energy sector, as Area C comprises 60% of the total territory of the West Bank and, according to the World Bank, it has the highest potential of solar power, corresponding to some 34.5 GW. Conversely, the potential of solar PV for Areas A and B combined amounts to only 103 MW (Hilal and Nassar 2018).
A very different framework regards Gaza’s energy sector. Gaza’s power supply (200–210 MW) does not satisfy the total demand, amounting to 450 MW per year. The main sources of power supply in Gaza are represented by electricity imported from Egypt (20–30 MW), Israel (120 MW) and by electricity produced locally with the Gaza Power Plant (GPP, 60–140 MW depending on degree of operation and damages). The GPP runs on diesel, but it operates only at half capacity due to prohibitive fuel costs for the Palestinian Authority. The mismatch between power demand and supply results in extenuating blackouts up to 18 h per day, which dramatically hinder the provision of key services such as healthcare.
The energy sector is inexorably linked with the political context, especially in the case of Palestine and Israel. An illustrative example regards Palestine’s inability to take advantage of its resources of the Meged oil and gas field and of the gas fields Marine 1 and Marine 2 offshore Gaza (Map 3.6). The former is situated in Area C of the West Bank. Divergent views on border agreements and local political developments have substantially hindered the positive development of these offshore resources.
In conclusion, the Israeli and Palestinian energy sectors are undeniably interconnected, or rather the latter has to depend on the former, so that an analysis focused on only one system would be incomplete. While Israel has attained a high level of energy security thanks to conspicuous quantities of gas discovered and its progressive inclusion of renewable energy sources in its electricity mix, Palestine’s energy security remains extremely low, being highly dependent on Israel. Solar PV represents a huge opportunity for a secure energy supply for Palestine especially in Area C, but this country may not be able to fully exploit this potential due to stringent political and economic constraints on the part of Israel.
2.4 Iraq and Syria
Iraq and Syria have a long hydrocarbon history, even though their reserves vary significantly. However, both countries have been struggling with major political instability since the 2000s. Syria has plugged into a civil—and proxy—war since 2011. Iraq has experienced three wars in the last 40 years (Iraq-Iran War in the 1980s, First Persian Gulf in the 1990s, and the US invasion in the early 2000s). Since the collapse of Saddam Hussein’s regime, the country has been suffering from major political and security instability.
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Iraq
Iraq is a key producing country, responsible for the production of 4.8 mb/d in 2019. It has the third largest conventional reserves in the world (145 thousand million barrels), with also conspicuous unconventional reserves. It is home to several super giant fields (with more than 5 billion barrels of reserves). Iraq also holds 3.5 tcm of gas reserves in 2019. However, approximately two-thirds of those reserves are associated with crude oil reserves, while one third are not. Figures 3.45 and 3.46 show the historical evolution of Iraq's TPES and power generation, which still rely heavily on oil.
The (geo)political events have deeply affected the country’s oil output. In the early 1980s, Iraq’s oil production fell drastically due to the 8-year war with Iran, but Iraq managed to progressively increase its production during the 1980s despite the conflict. In the 1990s, oil output suffered a heavier burden: the first Gulf War and the international sanctions pushed production down from 2 mb/d in 1990 to 0.35 mb/d in 1992. After 1996, Iraq was able to increase its domestic production again and was able to produce up to 2.6 Mt in 2001. The second Gulf War in the early 2000s, with the consequent collapse of Saddam Hussein’s regime and political instability, depressed once again oil production, but to a far lesser extent. Oil production has increased strongly since 2010 (2.5 mb/d), reaching 4.8 mb/d in 2019. The increase was driven by rising production in southern Iraq and in the Iraqi Kurdistan Region, offsetting the decline in the north. Iraq exports most of its oil (above 80% of the production) in 2019, Iraq exported 3.8 mb/d (Fig. 3.44).
Source Authors’ elaboration on ENERDATA
Iraq’s oil production and consumption 1980–2019, Mt (left), mb/d (right).
Conversely, its entire natural gas production (9.5 bcm in 2019) is used domestically. Gas production may be affected by OPEC’s production quotas as the majority of Iraq’s gas reserves is associated. Since 2015 the production has increased on average by 8% per year, as Iraq was able to boost its production within OPEC. However, Iraq is among the four largest gas flaring countries (with Russia, the US and Iran). This has significantly adverse environmental impacts, but it also creates a paradox since Iraq relies heavily on Iran both for electricity and natural gas imports. In 2019, Iraq received around 7 bcm of gas and 1.57 GW of electricity from Iran. Some estimated that Iran, directly and indirectly, met a whooping 28% of Iraq’s peak summer power supply. This dependence comes with great geopolitical competition, as the US seeks to reduce Iraq’s reliance on Iran imports.
Source Authors’ elaboration on ENERDATA
Iraq’s TPES 1990–2019, Mtoe.
Source Authors’ elaboration on ENERDATA
Iraq’s power generation, 1990–2019, TWh.
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Syria
By contrast, Syria’s oil and gas resources have hardly any impact on the world market. Syria’s oil production before the civil war began in 2011 was at 385,000 b/d, which was less than 0.5% of world supply. In 2019 Syria’s proven oil reserves were estimated at 2.5 billion barrels (BP 2020). Syria also holds 241 bcm of natural gas reserves, and in 2010 it produced 8.4 bcm of natural gas, most of which was used for electricity generation. Syria’s oil reserves are mainly localized in its two principal oil producing regions: the northeastern Hasakah Province and the Euphrates Valley. It is somewhat astonishing that Syria’s reserve figures are small compared to its neighbor to the East (Iraq).
The conflict has inevitably affected its limited oil production and upstream activities. Crude oil production dropped from an average of 385,000 b/d prior to the conflict to an average of 164,000 b/d in 2012 and to just 28,000 b/d in 2013 and further down to 9000 b/d in 2014. At the start of 2019, the regime declared that Syria was producing 24,000 b/d of crude oil (Butler 2019). The collapse of oil production forced Syria to increase its crude oil imports in order to keep its refineries running. In addition, it also needed imported products to meet domestic demand for gasoline, liquefied petroleum gas, and diesel. Syria began to rely on its partners for energy imports, especially Iran, in addition to buying volumes from the Kurdish-controlled fields in northeastern Syria. Syria looks with interest to natural gas, which is considered to be the only solution to its power generation woes. Also, Syrian offshore reserves in the Mediterranean Sea are very promising in terms of natural gas reserves. Some non-Western companies, notably Russian and Chinese, might be interested to invest and explore the area.
3 Maghreb
The Maghreb cluster comprises four countries—Algeria, Libya, Morocco and Tunisia—with very different features in the main socioeconomic indicators (table 3.7) as well as in the energy sector (table 3.8).
These four countries diverge also in socio-political terms, albeit they have some common heritage. Algeria, Morocco and Tunisia share a similar colonial history under French authority, while Libya was an Italian colony during part of the first half of the twentieth century (1912–1943) followed briefly (1943–51) by British and French rule before declaring independence in 1952 under King Idris I, Libya’s only monarch. He ruled the country until the 1969 coup by Muammar Ghaddafi. Thus Libya was under foreign rule for a shorter time compared to Algeria (1830–1962), Tunisia (1881–1956) or even Morocco (1907–1956) where the French introduced their own administrative system, which to a large extent survives until today. While Algeria was considered an integral part of the French state, Tunisia and Morocco were formally protectorates. The independence of Morocco and Tunisia was relatively bloodless, but the long eight-year very bloody independence war in Algeria (1954–1962) has left unhealed wounds between Algeria and France. Today, Morocco is the only monarchy in North Africa. Its King, Mohammed V, is directly descended from the Prophet Muhammad. As such, the King of Morocco and the Kind of Jordan, Abdullah II, are the only two rulers in all MENA countries to be considered direct descendants of the Prophet Muhammad, which gives them additional prestige in the Muslim world.
More recently, the Western Mediterranean countries experienced different sociopolitical developments. Tunisia was at the origin of the 2011 Arab Spring that spread across the region, while Algeria, which had its own bloody civil war in the 1990s, did not experience any major social unrest during the Arab Spring. In 2019, however, it witnessed the highest levels of social unrest since the 1990s, following the candidacy of Abdelaziz Bouteflika for the fifth presidential term. In Libya, the Arab Spring led to a bloody civil war including an international intervention which eventually led to the fall of Muammar Gaddafi in 2011, thus ending 42 years (since 1969) of Gaddafi leadership in Libya. The following political vacuum has caused a decade long civil war among different Libyan fractions, further exacerbated by international and external interferences (see Chap. 5 Sect. 5.3.2). Conversely, Morocco has been one of the relatively most stable countries in the MENA region, without the capacity of oil rent redistribution, which is typical of other countries in the region, to ensure socio-political stability.
Algeria and Libya are fossil fuel endowed countries, representing the classic rentier state, while Tunisia transited from a minor hydrocarbon net exporter to a net importer (in fact, Tunisia is still a small oil exporter but a gas importer). Morocco has always been a hydrocarbon-poor country so that its energy strategies and development reflect the priority of ensuring security of supply. Although Morocco does not hold any significant hydrocarbon resources, the country is one of the world’s largest phosphates producer and exporter.
For a more detailed overview of the main energy indicators of the four countries constituting this cluster, see Table 3.8. It is interesting to notice that, although the two important hydrocarbon rich countries in this cluster, Libya and Algeria, have an overall similar level of hydrocarbon reserves, Libya’s reserves are constituted of two thirds oil and only one third gas, Algeria’s reserves on the contrary are constituted of two thirds natural gas and one third oil. So, even though both countries export both oil and gas, Libya is mainly an oil player, while Algeria is mainly a natural gas player as far as exports are concerned.
Nevertheless, countries in the Maghreb cluster share a key feature: their strategic location in the Sun Belt and their geographic vicinity to Europe, which have contributed to ensure revenues for Maghreb countries, and security of supply for Western Mediterranean European countries. Indeed, this proximity and strategic position between the two Mediterranean shores has led to the construction of several gas pipelines exporting gas to Europe (Maps 5.6 and 5.8).
Due to its proximity, Algeria is strategically more important to Europe than most other hydrocarbon endowed countries in the MENA region (Map 5.6 in Sect. 5.3.1). Algeria built the first international commercial LNG chain in 1964 (initially to the UK) before it became technically possible to build pipelines across the Mediterranean Sea. In 1983, the TransMed pipeline, later renamed Enrico Mattei,Footnote 10 became operational connecting Algeria to Italy via Tunisia. It was the first time that a 600-m-deep sea (between Tunisia and Sicily) had been crossed. In the following decades, Algeria was also connected to Spain in 1996 with the Gazoduc Maghreb-Europe (GME), later renamed Pedro Duran FarellFootnote 11 Pipeline, which passes through Morocco. As soon as the technological capabilities were reached to lay very deep-water pipelines (at 2000 m), the exporters and importers preferred to connect directly. This is the case of MEDGAS which connects directly Spain to Algeria, and it would have been the case with the GALSI Pipeline (Algeria Sardinia Italy Gas Pipeline), which would have connected Algeria directly to Italy via Sardinia. The construction of GALSI was never realized, however, because of gas pricing issues and low demand outlook in Italy and Europe after 2010, and the project was finally called off. Libya started to export its own gas to Italy in 2004 when the Greenstream pipeline came online. Thus, Algeria and, more recently and to a minor extent, Libya, managed to export considerable gas volumes (Fig. 3.47), becoming an important pillar of (mainly South) European gas supply strategy and security.
Source Authors’ elaboration on BP
Gas balance* of Maghreb countries, 2000–2019, bcm. *Production minus consumption. Exports (+) Imports (−).
Despite difficult political relations between Algeria and the two transit countries (Morocco and Tunisia), all countries involved in the gas trade managed to ensure their security of gas demand and supply. Several factors limited the bargaining power of the transit countries, avoiding the political risks and gas crises that had occurred in other contexts (e.g. Russia-Ukraine-Europe in the 2000s). After long negotiations, the importing countries (Italy and Spain) managed to create a scheme to reduce the interference of political issues in gas flow. While the gas lines in Tunisia and Morocco are owned by these respective countries, the operational rights of the pipelines belong to the importing countries. Transit countries can request to be paid either in cash or in kind (gas volume). In doing so, transit countries receive some 5–7% of transit gas (in cash or in kind) as royalty under an agreement with the importing country (Italy or Spain) rather than the producing country (Algeria) (see box on transit countries in Chap. 5). In short, Morocco and Tunisia take advantage of gas pipelines which connect Algeria to Spain and Italy, respectively, to ensure their security of gas supply, and at the same time they cannot cut off supplies since the operation of the pipelines is managed by the importing countries’ companies.
In order to satisfy its domestic gas demand, Tunisia relies on gas imported from Algeria via the Trans Mediterranean (Enrico Mattei) gas pipeline (52% of total gas consumption through commercial agreements and 13% through transit fee payments for the Trans Mediterranean pipeline in 2019) (Oxford Business Group 2019). The imports from the Trans Mediterranean gas pipeline are paramount for Tunisia, given its almost entire reliance on gas for electricity generation. Morocco benefits from the Gazoduc Maghreb-Europe (GME), from Algeria to Spain via the Kingdom, to import significant quantities of gas, and to satisfy 45% of the country’s gas consumption (500 cmc out of 1.1 bcm). It is well-worth to note that, similarly to Qatar and the UAE, energy needs are prioritized above and beyond (geo)political tensions also in the case between Morocco and Algeria, even though Spain and the European Union played a role in bringing the two countries to the table and to an agreement. Indeed, Morocco and Algeria are in a decades-long dispute regarding the Western Sahara, where Morocco claimed two-thirds of the territory, while Algeria supported Sahrawi Arab Democratic Republic (SADR) guerilla who were fighting for independence (Berkhahn and Kruse 2018). In 2021, the political disagreement between the two countries prevented renewing the transit contract, which expired in November 2021.
Overall, countries in the Maghreb cluster display a great potential not only for further regional energy integration, but they may also benefit from their strategic locations (windy, close to the Sun Belt and Europe) to integrate high capacities of renewable energy sources to enhance their energy security and their exports to Europe.
3.1 Algeria
Algeria is a major hydrocarbon rich country in Africa. The country is endowed with both oil and gas reserves, though gas reserves are more abundant than oil reserves. Algeria is indeed an important gas producing country, and natural gas plays a major strategic role for the country.
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A historical overview of the Algerian hydrocarbon sector
The history of the hydrocarbon sector in Algeria dates back to the 1950s when Algeria was still under French rule. 1956 was an important year in the Algerian hydrocarbon sector with the discovery of three of the largest oil and gas fields in the country: Edjeleh and the well-known Hassi Messaoud oil fields, as well as large volumes of gas at Hassi R’Mel, all of which were developed rapidly in the years to come. Oil production started in 1958 (Kamen-Kaye 1958). Algeria showed great potential for the exploration and development of the oil and gas sector, thus its hydrocarbon resources were first exploited by France—former colonial power until 1962—as well as by foreign investors, especially American oil companies. However, the American companies faced numerous limitations and their operations were confined to only few areas of the country. After Algeria’s independence in 1962, the National Oil Company (NOC) Sonatrach was established. Algeria’s energy sector is dominated by two public companies: Sonatrach in the hydrocarbon production and trade, and Sonelgaz in electricity production and distribution as well as in gas distribution. In the 1960s, Algeria became a major player on the world’s energy stage. In those years, Algeria commissioned the first LNG production and export facility worldwide in Arzew with exports beginning in 1964. In the late 1960s, as oil production grew, Algeria joined OPEC. Over the 2010s, oil and gas exports represented, on average, around 95% of total exports (94% in 2019), while oil and gas contributed, on average, to 20% of GDP, 40% of fiscal revenues (ENERDATA n.d.) and 60% of government revenue.
Given the abundance of oil and gas production, Algeria’s total primary energy supply is not well diversified: in 2019, oil accounts for 38% while gas for 61% of TPES (Fig. 3.48). TPES grew strongly over the last decades. During the 2010s, average TPES growth rate was 4.5%. From 2000 to 2015, a period of high oil prices, the average annual TPES growth rate was 7%, while during the second half of the decade after the fall in oil prices and the consequent economic crisis, the average growth rate fell to 3%.
Algeria’s TPES by source 1990–2019 Mtoe. Source Authors’ elaboration on ENERDATA
The power sector is almost entirely dominated by gas, with a 98.7% share of total electricity generation, while the remaining share was provided by diesel oil in remote villages of the South as well as some solar PV and hydro. Power generation has increased significantly between 2010 and 2015 (around 11% per year) (Fig. 3.49). Since 2015, it has slowed down, even though still witnessing high growth rates (4.5% per year). In 2019, power generation reached almost 90 TWh. To meet rising demand, power capacity has been expanded significantly: from 6.4 GW in 2000 to 12.5 GW in 2010 and to 22 GW in 2019. Since 2010, Algeria has installed additional 9.3 GW. Over the last two decades, Algeria has multiplied its installed capacity by 3.4.
Source Authors’ elaboration on ENERDATA
Algeria’s electricity generation by source 1990–2019 TWh.
Algeria is the third country in Africa in terms of proven oil reserves with 12.2 thousand million barrels in 2019 (preceded only by Libya and Nigeria). Together with Angola, it is the second largest oil producer in Africa, after Nigeria, with 1.5 million barrels per day. Algeria is also the top producer of natural gas liquid products in Africa (247 thousand barrels per day) (BP 2020). However, Algeria has to deal with a declining oil production. Since 2007, its production has decreased by 26% from almost 2 mb/d to almost 1.5 mb/d in 2019. Consequently, Algeria could not export the same share of its production, which dropped from 65% in 2007 to 41% in 2019. Meanwhile, oil consumption in the country has increased over the last two decades from 190 kb/d in 2000 to 454 kb/d in 2019, with a growth rate per annum over the last decade of 3.1% (BP 2020) (Fig. 3.50). Algeria is an OPEC member since 1969 (OPEC 2019b).
Source Authors’ elaboration on ENERDATA
Algeria’s oil production and consumption 2000–2019, Mt (left) mb/d (right).
The result of decreasing production and increasing demand was inevitably the reduction of Algeria’s oil exports, from 1.36 mb/d in 2000 to 1.03 mb/d in 2019. Moreover, Algeria has seen its oil exports to the US declining following the shale oil boom in North America. Like the US shale oil, Algerian oil is very light and has a low sulfur content; US refineries have thus increased the use of American oil at the expense of Algerian oil imports.
Algeria is also an important gas producing country. In 2019, Algeria holds the second largest proven gas reserves (4.3 tcm) in Africa, preceded only by Nigeria, and corresponding to 2.2% of the world’s total proven gas reserves. With an output of 87 bcm in 2019, Algeria is the first gas producer in Africa and the fourth in the MENA region (preceded by Iran, Qatar and Saudi Arabia) (BP 2020). However, the country faces growing domestic gas consumption (45.1 bcm in 2019), enabling the export of only about 52% of its total gas production. This ratio has declined over the years, in 2000 with a similar production level but a much lower domestic demand, it was 78%. Between 2000 and 2015, Algeria’s gas production declined steadily from around 90 bcm to around 80 bcm, but over the period 2013–2018, Algeria increased its natural gas production by around 4%/year reaching 93.8 bcm in 2018. Approximately 60% of the country’s gas production comes from the Hassi R’mel area. Algeria is also an important gas and LNG supplier for Europe through pipelines to Italy and Spain. Algeria exports most of its gas via pipeline to Spain (MedGaz and Maghreb pipeline) and Italy (TransMed pipeline) (Table 3.9). The two European countries receive around 60% of total Algerian gas exports (Fig. 3.51).
Source Authors’ elaboration on BP Statistical Review of Energy 2020
Algeria exports via pipeline (left) and LNG (right) by country in 2019, bcm.
In 2019, Algeria exported 26.7 bcm via pipeline and 16.6 bcm via LNG, (Fig. 2.6). Nevertheless, the 2019 export volumes mirror the declining use of Algerian gas pipelines in its two key markets, Spain and Italy. The trend has worsened in 2020, due to the collapse of gas demand in these countries following the outbreak of COVID-19 and soaring gas demand in Algeria.
Despite Algeria’s long history in the LNG industry (it became the first world producer of LNG in 1964), it has not fully exploited its potential. Algeria has four liquefaction plants with a total capacity of 25.3 Mt per annum (i.e. Arzew GL1Z with a capacity of 7.9 Mtpa, Arzew GL2Z with a capacity of 8.2 Mtpa, Azew GL3Z with a capacity of 4.7 MTpa and SKikda GL1K with a capacity of 4.5 Mtpa). However, the non-utilization rate of Algeria’s LNG export facilities is particularly significant (higher than 45% in 2019). This is caused by declining output from its largest gas field, Hassi R’Mel, and delayed new field development in the southwest region.
Between 2016 and 2020, Algeria has experienced higher competition in the European markets due to low gas prices, especially with the surge of the US LNG imports to Europe. In late 2020 and early 2021, Algeria managed to increase its market share in the European gas markets thanks to the steep increase of gas prices. At high gas prices, Algeria’s oil-price indexation provided a temporary buffer for European gas buyers.
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Prioritizing the gas sector: reasons, drivers and challenges behind this decision
The current picture of Algeria’s hydrocarbon sector is not particularly rosy despite its large potential. Sonatrach, which owns 75% of all fossil fuel projects and fields in the country, has prioritized the development of new gas projects rather than oil. Sonatrach focuses on enhancing the recovery rate of its largest oil field (Hassi Messaoud) rather than promoting the exploration and development of new oil projects.
The strategy to prioritize gas over oil is driven by a few intrinsic factors: Algeria’s fossil fuel endowments (Algeria’s proven gas reserves represent a much higher share than it’s proven oil reserves) and geographical characteristics (its vicinity to Europe made Algeria a key component of the European diversification strategy). Moreover, the decision is mainly motivated by the deterioration of the gas balance due to the combination of two simultaneous forces: the decrease in gas supply and the rapid increase in domestic gas demand.
On the supply side, natural gas output has undergone some ups and downs. Between 2005 and 2013, it declined by 11%. It then stagnated for two years and lastly increased by 14% by 2017. In 2018, gas production reached 93.8 bcm as a consequence of some previous investments. In fact, Algeria managed to add production from three main projects: in 2017 Touat (4.6 bcm/year) and North Reggane, composed of six gas fields (4.4 bcm/year), as well as in 2018 Timimoun (1.8 bcm/year). Many analysts believe that Algeria’s gas production will decline in the coming years due to multiple factors. However, disagreements over the timeframe arise. Indeed, thanks to recent investments, Algeria could see its gas production increase to around 110 bcmFootnote 12 or a bit less by 2025–2027 in order to allow exports not to decline but to last longer. Nonetheless, if no specific and additional measures are taken, the export potential may drop starting from around 2030 due to decreasing production and increasing demand. To maintain high gas export levels, Algeria will thus need to implement important strategies, such as developing its vast shale gas potential (above 20 tcm resource base), and curbing demand growth.
Algeria therefore faces several challenges, which could lead to a strong decline in gas production and export unless important strategies and measures are implemented during this decade. Firstly, Algeria’s gas fields are very mature, meaning depletion is growing. For example, the production of the largest gas field, Hassi R’ Mel, is already beyond the plateau stage. Secondly, Algeria has not managed to attract enough foreign investments in the upstream sector to explore and potentially develop new gas fields mainly due to legal constraints. That has also prevented the country from acquiring access to advanced technology to address production issues in the country’s mature fields. The legal constraints to foreign investments are set by the country’s hydrocarbon law, similar to the case of Iran, albeit with some differences. Throughout the decades, there have been some changes in the general hydrocarbon law, but for sure it has been one of the key drivers and constraints for Algeria’s hydrocarbon industry and production.
The 1986 Hydrocarbon Law (Law 86–14), amended in 1991 to open up the gas upstream sector, established favorable conditions for large hydrocarbon discoveries and the successful development of the Berkine hydrocarbon basin in the 1990s through the successful Production Sharing Contracts (PSC) system. In the 2000s, Algeria decided to revise its hydrocarbon law, introducing the 2005 Hydrocarbon Law, then amended in 2006 and 2013. These three laws (2005, 2006 and 2013) present a common feature and some differences on the engagement with IOCs. The common feature was the decision to abandon the PSC system, which however resulted in discouraging IOC investments in Algeria’s upstream. If the 2005 Hydrocarbon Law introduced some clauses that deterred foreign investments, including the prohibition of employing Production Sharing Contracts, the 2006 amendment was mainly responsible for discouraging foreign investments since it introduced the compulsory 51% participating share of Sonatrach in any hydrocarbon project: the so-called 51/49 rule. Under this law, only four international rounds were carried out over 15 years with limited success: for instance, in 2008, out of the 45 blocks offered, only 4 were awarded and this trend continued in the following years (King and Spalding 2020). Lastly, a slow and daunting bureaucratic system resulted in substantial delays in the permits for the exploration, development and implementation phases of hydrocarbon projects, hindering foreign investments. At the end of 2019, Algeria approved a new hydrocarbon law, which set more favorable terms for IOCs despite preserving some major obstacles (i.e. the 51/49 rule).
The challenges for the country’s oil and gas industry do not come only from the supply side, but also, and especially, from the demand side (Fig. 3.52). The country has witnessed a steep growth in domestic gas consumption, which has witnessed an average growth of 5.6% per year between 2008 and 2018 (BP 2020). On the other hand, Algeria’s gas production experienced a growth rate per annum of 1.3% over the same period.
Source Authors’ elaboration on BP (2020)
Algeria’s gas production and consumption, 1990–2019 (bcm).
High energy subsidies (oil, gas and electricity combined) are a leading driver of high consumption. Algeria is ranked third worldwide in terms of lowest gas prices, following Turkmenistan and Venezuela, with gas prices in the wholesale markets (roughly 0.5/MMBtu) lower than the cost of production (around 0.7/MMBtu) (Aissaoui 2016). In 2019, around 7.6% of Algeria’s GDP went into subsidies: oil was subsidized by $8.8 billion, gas by $2.3 billion and electricity by $2 billion. Political willingness seems to be lacking for a comprehensive reform and (gradual) reduction of energy subsidies. In order to offset this strong growth in domestic gas consumption, different ministries and Sonatrach have enacted energy efficient measures, especially for large energy-intensive industries. Sonatrach has also expressed its willingness to carry out energy audits to enhance the energy efficiency of its facilities. Nevertheless, without an overarching energy subsidy reform, energy efficient measures are deemed neither sufficient nor effective. High energy subsidies in Algeria not only entail lower gas export volumes, thus lower gas revenues and a higher current account deficit, but they also weigh importantly on the governmental budget (they account for 7.6% of total GDP in 2019).
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Strategies to offset the deterioration of Algeria’s gas balance
The latest wave of political instability and social unrest that started in 2019 has so far prevented the realization of a significant energy subsidy reform to limit and decrease gas consumption in Algeria. Indeed, Algeria has missed the opportunity to adopt a relevant energy subsidy reform when oil prices were over $100/b in the second half of the 2000s. Moreover, Algerian officials increased the public expenditure after the eruption of the Arab Spring across the region in 2011 to tackle social unrest. Lack of political will to reduce domestic consumption via economic and efficiency measures is one of the key bottlenecks for Algeria’s oil and gas sector. Additionally, governance issues are further hampering the development of the industry. Such challenges may be further enhanced due to political unrest and the transition. For example, the continuous changes in Sonatrach’s executive figures hindered a stable and long-term strategy, which is necessary to tackle the many challenges the hydrocarbon industry is facing in the country. In February 2020 Mr. Toufik Hakkar was appointed as Sonatrach’s fourth CEO in less than a year and eight in the past ten years. Notwithstanding this general context, the company has taken some steps to contrast the decline in gas production, while preserving export volumes, tackling different but interconnected spheres.
In order to boost hydrocarbon output, Algeria requires the essential contribution of IOCs both in terms of investments and technology; thus, a positive legal petroleum framework for foreign companies is crucial. In this sense, in November 2019 Algeria’s National Assembly approved a new hydrocarbon law and promulgated it the day before the presidential election in December 2019. The new law introduced some new positive details, without changing the famous term (51/49 rule) (Elliott 2019). It modified some fiscal terms in the effort to put Algeria more in line with its peers. For example, it reintroduced Production Sharing Agreements in parallel to Royalty/Tax Participation Agreements and Risk Service Agreements. Moreover, it abolished the VAT tax on professional activities within the oil and gas sector and on all imported materials and goods to carry out the hydrocarbon projects, in conjunction with the elimination of custom duties.
Another strategy is to boost Algeria’s shale gas potential (with more than 20 tcm estimated reserve base, i.e. about four to five times the proven conventional gas reserves), as a way to enhance gas production. Indeed, it is estimated that Algeria holds the third largest shale gas reserves in the world. However, the development of shale gas is hampered by the limited openness to international companies and the lack of water needed for hydro-fracking. Indeed, regions with the highest shale gas potential are the most water-stressed ones, leading to strong opposition to shale projects and popular unrest. The first shale gas drill carried out by Sonatrach in 2014 in the south-west region of Salah was met with mobilization of the local population mostly for concern over the already depleted water resources (Clemente 2019). These protests led to the termination of exploratory drills for shale gas so that it has not yet been possible to properly assess its potential and reserves.
Nevertheless, Algeria is attempting to sign joint ventures with foreign investors to explore and develop not only shale gas sites, but also underexplored areas in the south of the country and in the Mediterranean offshore, where to date only three drills have been carried out. The Italian company Eni has already signed an agreement for offshore development. Sonatrach hopes to attract foreign investors thanks to the new favorable conditions of the updated Hydrocarbon Law as well as Algeria’s export infrastructure potential, which is currently underutilized and in expansion. As a matter of fact, in 2019 Algeria shipped 16.6 bcm of LNG out of an export capacity of 34 bcm, and pipelines transported 26.7 bcm of gas out of an export capacity of 53.5 bcm.
In 2019, Sonatrach successfully managed to renew numerous long-term oil-indexed gas contracts that were going to expire for roughly another decade. Indeed, the Algerian NOC Sonatrach renewed agreements with Italian companies, mainly ENI, Enel and Edison for the supply via pipeline of 9 bcm, 3 bcm and 2 bcm, respectively, until 2027–2028. It also signed new deals with Botas (Turkey), Naturgy (Spain) and Galp (Portugal) (Elliott and Lalor 2019). However, the renewed contracts entailed lower volumes due to two main elements. First, Algeria insists on oil-indexed contracts. Indeed, in October 2020, following falling oil prices due to the Covid-19 pandemic, oil-indexed gas contracts became competitive with European gas hub prices. Also, during the 2021 gas price spikes, oil price indexation was very competitive. Second, Sonatrach is considering opportunities to bolster LNG sales to its European partners. However, Sonatrach must deal with a growing competition in the LNG market along with some structural challenges of its LNG industry.
Overall, despite these positive attempts to boost gas production and exports, Algeria has to face political unrest at all levels, from protests in the streets to the continuous management changes in the hydrocarbon sector (e.g. four chief executives changes in Sonatrach between April 2019 and February 2020). Thus, stabilizing Sonatrach’s production, management and image has become a priority for an economically sustainable energy sector and beyond.
3.2 Libya
Libya has the largest crude oil reserves and the fifth largest gas reserves in Africa, holding 6.3 Mt of oil reserves (2.8% of the world’s total proven reserves), and 1.4 tcm of gas reserves. Libya quickly became a major pillar of the oil (and later gas) security strategy of European countries. However, Libya’s oil and gas sector have experienced numerous ups and downs over the last decades. With the fall of its long-lasting ruler Qaddafi in 2011, the country fell into an escalation of violence and chaos, which have deeply affected oil and gas production and exports.
Its oil and gas industry began at the end of the 1950s, with the discovery of its first oil in 1959. Two years later, Libya began exporting oil, and in 1962 it became a member of OPEC. The country’s oil industry was born under the monarchy of Idris I, which set a positive and open environment to foreign investments for the industry. The first Libyan oil industry managed to attract foreign companies thanks to high competition through smaller concession areas than usually done in the other countries of the MENA region at the time (Fattouh 2008). Moreover, Libyan oil gained more strategic relevance at the end of the 1960s following several political events. The Suez Canal closure in 1967 due to the Six-Day War, in particular, considerably increased the value of Libya’s oil, since the country is located west of Suez and the main demand centers were in the Western world. Thus, Libya and its oil earned strategic relevance thanks to their proximity to European markets. In those years, Libya’s oil production grew rapidly, reaching a peak of around 3mb/d in 1970 (Fig. 3.53).
Source Authors’ elaboration on ENERDATA and BP
Libya’s oil production, 1965–2019, Mt (left) mb/d (right). Note Data of the period 1965–1970 are from BP, while 1970–2019 from ENERDATA.
With the advent of Colonel Muammar Qaddafi in 1969, Libyan energy resources became more and more essential for political power. Qaddafi used revenues derived from hydrocarbon resources to provide economic prosperity to the small population in Libya, which became a classic petro- and rentier state. In 2012, revenues from the sale of oil and gas accounted for 96% of government revenues, 98% of export revenues and 65% of GDP (EIA 2015). During Qaddafi’s regime, Libya amassed significant cash revenues and ran a debt-free economy for years; however, it was almost entirely dependent on the import of food, medicine and consumer goods.
The Libyan National Oil Corporation (NOC) was created in 1970. Meanwhile, the new Libyan regime initiated its campaign to strengthen its bargaining position vis-à-vis foreign companies. At the time, Libya was supplying 30% of Europe’s oil. The new political course on the oil industry undertaken by Qaddafi affected the balance of power between the governments of the producing countries and the oil companies (Yergin 2009).
In 1971–1973, shortly after Qaddafi’s rise to power, Libya decided to revise existing concessions in favor of 51% participation agreements with the state oil company NOC (Fattouh 2008). For those companies that rejected the new participation terms, on September 1, 1973 the government issued a decree nationalizing 51% of their concessions. However, in the early 1980s, the nationalization of oil assets led to a decrease of production to around 1 mb/d (from 3 mb/d in 1970). Oil production also suffered from growing international pressure in the 1980s and 1990s due to political confrontation between Libya and key Western countries, especially the US. This led to the UN and US enforcing sanctions against Qaddafi’s regime and Libya’s oil and gas industry, preventing its full development.
A reconciliation process between Libya and the Western countries began in the late 1990s. International sanctions were lifted in the early 2000s, rehabilitating Libya and its hydrocarbon sector, which underwent a positive development since the 2000s. Libya tried to attract new international investments and E&P activities by foreign companies to its oil and gas industry. The result was a moderate increase in Libya’s overall output and a relatively stable period for Libya’s oil sector. Most of Libya’s oil flows to Europe, with Italy as one of the main recipients.
Natural gas also witnessed a strong growth after the lifting of sanctions, with the domestic production increasing from an average of 6.0 bcm in 2000–2004 to 13.6 bcm in 2005–2010 (Fig. 3.54). This was possible thanks to the partnership between Italian ENI and NOC. The two companies own the Western Libya Gas Project and the associated 520 km GreenStream pipeline (8 bcm capacity) that transports Libyan gas from Mellitah to Italy.
Source Authors’ elaboration on ENERDATA
Libya’s natural gas production 1970–2019, bcm.
The Greenstream pipeline is the main avenue of Libya’s gas exports. Nonetheless, Libya has also been an LNG exporter. In 1971, it became the third country in the world (after Algeria in 1964 and the United States in 1969) to export LNG. The 3.2 Mtpa LNG plant, built in the late 1960s at Marsa al-Brega, is owned by NOC and operated by Sirte Oil Company (EIA 2015). From this terminal, Libya has exported its gas to Spain and other countries even on a spot basis. The sanctions prevented the Libyan government from properly renovating this facility, so its output has declined over time to about 15% of nameplate capacity. Finally, the civil war outbreak in 2011 severely damaged the infrastructure and halted LNG exports.
Indeed, the period of stability did not last more than a decade. The oil and gas industry began to face a period of great uncertainty and insecurity since the outbreak of the revolution in 2011. In February 2011, the ‘17th February Revolution’ began in Libya’s eastern region (Cyrenaica) and led to the overthrowing of Muammar Qaddafi on October 20th, 2011—after 42 years of power.
Notwithstanding the conflict, Libya’s oil and gas exports have shown a remarkable resilience. Despite widespread violence and fierce clashes around energy infrastructures, Libya managed to preserve its oil and gas exports to some extent. Natural gas has declined since 2015 to less than half Greenstream’s 11 bcm capacity. Oil exports have been affected by oil output and the conflicts over the control of oil fields and export terminals. The year 2019 was a relative success for the Libyan upstream sector with positive consequences for its exports. Indeed, in 2019 Libya managed to export 5.4 bcm to Italy, reaching a four-year high. The year 2020 witnessed an intensification of conflicts and the quest for the control of energy infrastructure. In January 2020, a blockade of export terminals in the Gulf of Sirte and the shut-in of the giant El Sharara and El Feel fields crashed Libya’s crude output and exports. Nonetheless, gas continued to flow to Italy, even though at limited capacity. In 2020, Italy still imported 4.2 bcm from Libya.
On the domestic side, fossil fuels dominate its total primary energy supply (TPES) and power generation. Oil represents 53.2% of TPES, while natural gas 43.5% (Fig. 3.55). Moreover, natural gas has increasingly replaced oil in power generation as domestic gas production was unleashed in the 2000s (Fig. 3.56). In 2019, 70% of power generation was based on natural gas and 29.8% on oil. Libya had managed to electrify its territory almost entirely decades ago. Power consumption grew at an average growth rate of 6.9% per year over the 2000–2010 period. Such growth was also caused by the high subsidization of energy prices, a key component of the social contract.
Source Authors’ elaboration on ENERDATA
Libya’s total primary energy supply 1990–2019, Mtoe.
Source Authors’ elaboration on ENERDATA
Libya’s power generation 1990–2019, TWh.
3.3 Tunisia and Morocco
Unlike other hydrocarbon-endowed countries of North Africa (Algeria, Libya and Egypt), Tunisia’s and Morocco’s oil reserves and production are quite negligible: 425 million oil barrels in reserves with an annual production of 42 thousand barrels per day for Tunisia in 2019 (BP 2021) and almost nil for Morocco. The same applies to natural gas reserves and production. Tunisian proven gas reserves are estimated at 64 bcm with an annual gas production of 2 bcm in 2019 (BP 2021), while Morocco is estimated to hold 1 bcm of natural gas reserves. Energy policies in Tunisia and Morocco have therefore traditionally prioritized energy security. However, the two countries have not followed the same path in terms of energy source diversification both in terms of TPES and electricity generation.
Morocco has preferred to import coal rather than depending on Algeria’s gas volumes due to high political disagreements with its neighbor. On the contrary, even though Tunisia does have an arm’s-length political relationship with its Algerian neighbor, political relations between these two countries are not as conflicting as those between Morocco and Algeria, where even the border is closed since 1994. This has allowed Tunisia to benefit from trade with Algeria, also thanks to imports of natural gas. Both countries have benefited over the years (Tunisia since 1983, Morocco since 1996) from the transit fees of Algerian gas exports to Italy (via the Transmed pipeline) and to Spain (via the GME pipeline). Nonetheless, no more gas is flowing through the GME across Morocco since November 2021 following political disagreements that prevented the extension of the transit deal.
The Tunisian energy and electricity sectors are not well diversified (Figs. 3.57 and 3.58), since they still mostly rely on an energy model set decades ago, when oil and gas were quite abundant in the country. In Tunisia the predominance of gas (mainly imported from Algeria) is particularly evident, gas being the almost exclusive source for electricity generation (about 96% of total electricity produced in 2019). Conversely, Morocco has the most diversified energy and electricity mixes not only of the West Med cluster, but of the whole MENA region (Figs. 3.59 and 3.60). Interestingly, Morocco still mostly relies on coal for power generation, while being the pacesetter for the adoption and development of renewable energy sources (more than 15% of the country’s electricity mix in 2019) in all the MENA region. The share of coal in Morocco’s power mix has increased since 2010, reaching 65%. As a direct result, coal replaced oil (the share of oil dropped from 24% in 2010 to 1% in 2019). Hydropower generation can vary widely from year to year because of climatic variations. For example, in 2010 it accounted for 15% compared to only 4% in 2019. Wind accounted for 11% of the power mix in 2019 and solar for around 4%.
Source Authors’ elaboration on ENERDATA
Tunisia’s TPES 1990–2019 Mtoe.
Source Authors’ elaboration on ENERDATA
Tunisia’s electricity generation 1990–2019 TWh.
Source Authors’ elaboration on ENERDATA
Morocco’s TPES 1990–2019 Mtoe.
Source Authors’ elaboration on ENERDATA
Morocco’s electricity generation 1990–2019 TWh.
Overall, despite environmental concerns on coal, Morocco may be deemed to have highly enhanced its energy security, while Tunisia may still fall behind since it almost entirely relies on imported gas for electricity generation.
This section will analyze the major characteristics between Morocco’s and Tunisia’s energy sectors and their main challenges related to security of supply. It will then discuss the main strategies put forward to enhance energy security, taking advantage of the countries’ intrinsic peculiarities (i.e. location).
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Features and challenges of the countries’ energy sectors
Tunisia
In the 1970s Tunisia started to substitute oil with gas for power generation, following the oil shocks and a simultaneous decline in oil production and growth in gas output and discoveries. Natural gas has gained a relevant role in the power sector under the supervision of the state-owned gas distribution and electricity utility Societé Tunisienne d’Electricité et du Gaz (STEG) which had the monopoly. Today, STEG is the main supplier of electricity, providing 84% of the country’s electricity production, and it has the monopoly of power distribution, while the rest is produced by Independent Power Producers (IPPs). STEG also has the monopoly of gas distribution, thus being the main player for the development of gas infrastructure. Due to its limited gas reserves and production (2 bcm in 2019), Tunisia relies heavily on Algerian imports (4.5 bcm, i.e. 70% of its domestic consumption). The increasing gas demand is largely due to its growing electricity consumption, which is driven by population and economic growth and low electricity prices mostly thanks to energy subsidies.
Tunisia pays only for importing gas above the share of transit gas it is entitled to, as per the royalty agreement with Italy. Above this threshold, importing gas puts pressure on STEG finances, and thus public finances. According to the National Institute for Statistics, Tunisia’s energy trade deficit accounted for around one-third of total trade deficit.
In order to prevent political risks and enhance security of supply for all the parts involved, Tunisia is entitled to receive some 6–7% of the transit gas either in kind (gas) or cash. Tunisia’s level of free gas thus depends on the amount of gas Italy imports from Algeria. In the second half of the 2010s, Italy bought fewer gas quantities from Algeria, thus Tunisia was obliged to increase its purchases of extra gas beyond transit agreements. For instance, Tunisia had to increase direct contractual quantities with Algeria by 9% in 2018 and 22% year-on-year in 2019 (Oxford Business Group 2019). Already in 2017, STEG’s financial situation had become so dire that its losses amounted to 42% of total revenues, weighing substantially on public finances. Indeed, the Tunisian Ministry of Finance covered STEG revenue gaps with direct subsidies, which make up 20% of total public spending, a higher percentage than programs related to health (The World Bank 2019b).
Economic difficulties and inefficiencies at STEG have resulted in overall lower investments in gas, which, in turn, entailed a higher unemployment rate as STEG is the leading employer in the country within the framework of the social contract. A major challenge to decrease expenses for STEG and, more broadly, for Tunisia’s energy sector, regards social distrust towards state institutions, especially in the aftermath of the Arab Spring. Accumulated unpaid bills have reached 28% of STEG’s annual revenues in 2018 and past attempts to reduce energy subsidies reforms, conditional on IMF loans, were met with social discontent and revolts (The World Bank 2019b). Energy subsidies represent quite a burden for the country, since they accounted for one-third of the fiscal deficit and 2.5% of GDP in 2018 (The World Bank 2019b). Despite the reluctance of policymakers to carry out energy subsidy reforms following the 2011 revolts, in January 2014 Tunisia managed to reduce electricity subsidies to low and medium-voltage consumers by 10% and by a further 10% in May 2014, and to eliminate energy subsidies to cement companies (Oxford Business Group 2016). In April 2020, Tunisia moved to phase out fuel subsidies (diesel and gasoline) taking advantage of very low oil prices, thus preventing the immediate increase of fuel prices (Cockayne and Calik 2020).
Morocco: striving for energy security
Morocco is a hydrocarbon resource-poor country and its territories are still largely unexplored. Thus, the North African kingdom has strived to attain higher levels of energy security thanks to coal imports and the exploitation of its hydroelectric potential on the Atlas Mountains. More recently, Morocco has expanded its security of supply by promoting a favorable regulatory environment for renewable energy sources. In 1996, Morocco has also started to import natural gas through the transit agreement between Spain and Algeria, benefiting from the same legal framework applied to the Italy-Tunisia-Algeria gas deal. However, this 25-year-old transit agreement expired on 31 October 2021 and was not renewed by Algeria for political reasons (Chap. 5, Sect. 5.3.1), resulting in zero gas volumes from Algeria. This forces Morocco to find alternatives for this gas, either by increasing coal imports, renewable development or LNG imports. Finally, Morocco has started to consider attracting investments for upstream activities in order to increase its own domestic hydrocarbon production.
These strategies have become paramount for the country’s energy security, especially following a steep surge in energy consumption levels (an annual average rate of 6.6% between 2002 and 2015), driven by population growth, economic development and increased electricity access rate. Morocco has also successfully attained nearly universal access to electricity, also in its rural areas which were only 18% in 1995 (Hafner et al. 2018). In fact, in 1995, Morocco launched an ambitious electrification program for its rural areas, the Rural Electrification Programme (PERG). The objective was to achieve 99% of electricity access in the rural areas in 2017. The target was reached in 2015.
Due to the lack of hydrocarbon endowments, Morocco must rely almost entirely on energy imports to satisfy the growth of its domestic energy consumption. Imports cover 100% of the country’s oil and coal consumption and 90% of its gas consumption (in 2019). In 2018, Morocco imported almost 92% of its energy, which accounted for 15.6% of the country’s total imports. Morocco has recently launched numerous renewable projects in line with its climate ambitions, the favorable wind and solar resources. The fast-pace development of renewable energy could also contribute to reducing government expenses on energy imports.
Coal represents the main base load fuel of the country, guaranteeing energy security. The most important coal power plant is located in Jorf Lasfar and is composed of four units with a capacity of 330 MW each. The first two units were commissioned in 1994, while the third in 2000 and the fourth in 2001. Morocco is expected to decommission these units in 2044 in line with its climate targets. However, Morocco commissioned a new coal power plant of 1.21 GW at Cap Ghir Safi in 2018, boosting the country’s coal-fired plant capacity to 4.3GW (MEES 2019). This is in stark contrast with Morocco’s “green ambition”, which resulted in a remarkable increase of renewable projects in the last five years.
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Strategies to enhance energy security and economic sustainability
Tunisia: hydrocarbon and renewable developments
Tunisia has witnessed a surge of its total primary energy supply. A major contributor is natural gas, although oil still plays an important role (Fig. 3.57). A relevant strategy put in place partly to enhance energy security and to increase the economic sustainability of Tunisia’s energy sector regarded the rapid increase of licenses issued by the government for new oil and gas exploration rounds. The 2011 Tunisian Revolution resulted in waning interest in the country’s oil and gas, mainly due to political instability. The 2014 Tunisian Constitution further limited attractiveness for foreign investors as its article 13 stipulates any new exploration awards to be approved by parliament. Political instability has also prevented Tunisia from reforming its legal regime, inducing some Western oil companies (i.e. Shell and Eni) to consider leaving the country’s upstream sector (Reuters 2021).
Despite these barriers, a major gas project, the Nawara gas field, started up in February 2020, and will produce 1 bcm, representing roughly 50% of the current total gas production. Nawara gas field production is expected to satisfy 17% of total domestic consumption and decrease energy deficit by 30%. This project is jointly operated, through a 50:50 concession, by the Austrian company OMV and Tunisia’s state-owned company responsible for hydrocarbon exploration and development, the Entreprise Tunisienne d’ Activités Pétrolières (ETAP) (The Arab Weekly 2019). However, the Nawara gas field illustrates the issues of Tunisia’s upstream sector and developments, namely underinvestment and instability. The gas project came online twelve years after its conception, but it has not been immune to further delays and challenges due to several shutdowns since its commission (OME 2021). A few offshore gas fields are also present in Tunisia, comprising the Hasdrubal and Miskar fields, which are 50 and 100% owned by Shell. However, in 2021, Shell seems to be trying to sell these two assets, along with an onshore oil field.
Most of the aforementioned challenges for Tunisia and its state-owned company STEG may be offset with the inclusion and enhancement of renewable energy sources for electricity generation, also thanks to the high potential of solar and wind energy, especially in the south (UNDP 2018). Renewable energy sources could help decrease the burden on public finance. The use of Independent Power Producers (IPPs) could play a crucial role in developing the country’s renewable potential avoiding upfront investments.
Also, since solar energy projects have the highest potential in the south, a significant uptake of solar projects by IPPs would contribute to meeting the demands of the Kamour movement in 2017, which reflects the state-of-art in the southern regions (Tataouine and Kerbili provinces): young, unemployed men asking to be employed in the oil and gas companies operating there. This movement showed a remarkable change in terms of social contract: residents were willing to work in the private sector, and thus requested to put quotas to hire a minimum number of Tunisians. Nevertheless, in June 2020, revolts in the Tataouine province erupted again with protesters demanding jobs in the oil and gas sector and infrastructure projects. Indeed, the government was perceived not to deliver on its promise, dating back to 2017, regarding the creation of job opportunities in southern Tunisia (Al Jazeera 2020b).
Given the numerous advantages from the development of renewables and the introduction of IPPs, Tunisia took some first steps to boost “green” electricity and to attract foreign investors. In 2012, under the Tunisia Solar Plan (TSP), the country announced the target of 30% of solar penetration by 2030. In 2015, the Parliament passed Law No. 12, which aimed at enhancing private investments for renewable development and liberalizing the market for the access, network and transport of electricity generated from renewables. Nevertheless, with this law, STEG remained the sole entity allowed to sell electricity to final consumers. Today renewable projects are thus mostly held by STEG, accounting for 91.5% of Tunisia’s installed capacity and 81% of electricity sold, while the remainder is provided by the Carthage Power Company, the country’s first IPP, with a 471 MW combined-cycle power plant commissioned in 2002. Overall, it would be extremely advantageous to also boost IPPs for renewable projects, as IPP would be an advantageous tool to exploit in order not to pay directly upfront. As of 2021, the only IPP in renewable projects regards the Sidi Mansour wind farm, which commenced construction in 2020. Numerous tenders were introduced in the last 4–5 years so that IPPs will follow suit in the next years. More in detail, in 2017 a tender process was launched with a capacity of 140 MW of wind and 70 MW for solar PV under the form of a PPA with STEG as the off taker (UNDP 2018). However, in 2018, STEG still operated all renewable projects, which amounted to a total capacity of 244 MW for wind, while no utility-scale solar PV was present in the country. A leap forward was taken in 2019 when Tunisia held a solar tender of 500 MW in an attempt to attract foreign investors in the country. In December 2019, the Tunisian Ministry of Mines and Energy announced the five winners of the tender: 300 MW of the project were attributed to the Norwegian developer Scatec Solar, which offered the lowest bid to build a 200 MW facility in the Tataouine governorate and sell electricity to STEG. The Norwegian utility was also awarded other projects of smaller capacities. Other two projects, each 100 MW, were won by the consortium led by ENGIE and the Moroccan NAREVA, and by the consortium led by the Chinese TBEA and the Emirati AMEA Power (Bellini 2019).
Challenges and opportunities arise from striving to enhance the presence of IPPs in renewable projects in the south for solar energy, and predominantly in the north (but also central and southern regions) for wind energy. Indeed, STEG has to expand and strengthen the north–south electricity interconnection, especially to allow solar development in the south. It may well be the case that lower power purchasing agreement (PPA) prices for ideally located RES projects, thanks to higher capacity factors, may offset grid expansion costs. Also, the availability of transmission infrastructure is critical to improve investor confidence in RES, as it provides an assurance that the newly developed capacity will be integrated into the system and dispatched in line with the contractual arrangements agreed with STEG. Lastly, Tunisia’s large potential for solar and wind energy also provides an important growth opportunity for the country. Indeed, the added RES capacity may also be used for electricity export purposes, especially once Tunisia is connected to the European electricity market through the planned Tunisia-Italy Power Interconnector.
Morocco: the “green” country of the MENA region?
In order to offset energy security challenges, trade deficits and increasing energy consumption in a hydrocarbon-resource poor framework, Morocco has become the country with the highest share of renewables in the energy and power mixes, mostly thanks to substantial investments and regulatory improvements in the renewable field.
Already in 2009, Morocco set out the National Energy Strategy, which set the targets of 42% of total installed power capacity from renewable sources (primarily solar, wind and hydropower resources) by 2020. In 2020, this share was 32% i.e. three quarters of the target. In 2015, during the 21st UNFCCC Conference of Parties (COP21) in Paris, the Kingdom announced its willingness to have 52% of the total installed power capacity coming from renewable sources by 2030 (20% solar, 20% wind and 12% hydro) (IEA 2019). In order to attain these ambitious objectives, the country has envisaged two programs for renewable development, one for solar and one for wind.
The Moroccan Agency for Sustainable Energy (MASEN) agency is responsible for the Moroccan Solar Plan and set the target of 2000 MW of solar capacity installed, both PV and CSP, by 2020 and 4800 MW by 2030. In reality, in 2020 the total solar capacity installed was 734 MW, i.e. about one third of the target.
Regarding the development of wind energy, the Moroccan Integrated Wind Program has been promoted, which aimed at reaching 2,000 MW of wind capacity installed by 2020 and 5000 MW by 2030. In 2020, the total wind capacity installed in the country represented 1410 MW, i.e. 70% of the target. Wind has a lot of potential in the country, demonstrated by the success of the 300 MW Tarfaya wind complex, the largest in Africa. This complex has been developed through a joint venture, similar to solar projects, between the French company ENGIE and the Moroccan NAREVA Holding company. Recently awarded wind projects, amounting to a total combined capacity of 850 MW, have been developed by a consortium of NAREVA Holding, ENGIE, ENEL Green Power and Siemens Wind Power, leading companies in this sector (Oxford Business Group 2020).
In order to accommodate large shares of renewable capacity, the Kingdom has changed the energy regulatory setting. Prior to 2012, Office National de l’ Electricité et de l’ Eau Potable (ONEE), the national utility in charge of electricity production, transmission grid and the majority of distribution, was the sole responsible for buying, selling, importing and exporting electricity. The national regulatory change Act No. 13-09 in 2012 opened up the market to the free exchange of electricity coming only from renewable energy sources. In other words, private green electricity developers were allowed to access the national grid, produce electricity from renewable sources, and buy it in the market. Thus, since Act No. 13-09, two parallel electricity markets coexist: the liberalization of the electricity market from renewable sources and the IPP scheme contract for the conventional electricity market. In 2016, an update of Act No. 13-09 was adopted, the Act No. 58-15, which further strengthened the liberalization of the electricity market from renewable energy sources. Indeed, the newly passed law envisages, among other provisions, the development of a low-voltage electricity market (i.e. rooftop solar PV) and the trade of surplus electricity from renewable sources to ONEE (up to 20% of the annual generation) (Khatib 2018).
Large-scale renewable projects, in line with most other countries in the MENA region, are usually envisaged in the framework of international tenders, with IPPs. Under this scheme, bidders sign power purchasing agreements (PPAs) with ONEE, which will buy electricity produced from the project for the following 20–30 years. These schemes have contributed to providing financial guarantees to investors, diminishing the cost of electricity produced (i.e. for NOOR III solar project) and introducing concentrated solar power plant (CSP) for peak load. Contrary to wind power and PV, the advantage of CSP, connected to melted salt storage, is that it produces heat which can be stored, making the plants dispatchable.
However, Morocco is currently characterized by a contradictory situation: on the one hand, great renewable potential and green ambitions, and on the other hand, the ‘brown’ reality of its energy mix, which still relies on coal imports to satisfy growing energy consumption that has been strongly increasing during the 2010 decade. A similar pathway can be traced in the United Arab Emirates, with Dubai commissioning a coal power plant and Abu Dhabi aspiring to become a leading renewable hub in the region. Overall, Morocco is simultaneously the “greenest” country in the MENA region, in terms of renewable uptake, and the “dirtiest” in terms of its reliance on coal. With the construction of new renewable and coal power plants, Morocco managed to enhance its power production (since 2010 by around 6% per year), almost halving its power imports, mostly from Spain, which still represent 8% of Moroccan electricity demand. Nevertheless, over the years, Morocco also put forward other strategies to strengthen its domestic power production and overall energy security.
Morocco: Complementing renewable energy sources with other strategies
Only recently, Morocco has also focused its attention on the exploration of hydrocarbon sources within its territory as a way to increase its security of supply. The upstream sector, which is under the Office Nationale des Hydrocarbures et des Mines (ONHYM), mostly benefits from international investments, with ONHYM contributing only 1.7% of total annual investments in 2018. Indeed, Morocco has managed to successfully attract foreign developers thanks to a favorable regulatory framework, which is set by changes to the country’s Hydrocarbon Law of 2000. Under the current regulatory framework, ONHYM can hold a maximum stake of 25% for upstream projects and the first 300–500 tons of oil and 300–500 mcm of gas produced are exempted from the payment of royalties. Other beneficial fiscal arrangements include a 10-year exemption from the corporate tax for foreign investors as well as an exemption from custom duties and other taxes related to imports of materials, equipment and services needed for hydrocarbon exploration and development (Oxford Business Group 2020).
Moreover, Morocco has also considered diversifying its gas import sources, given its strained political relations with Algeria. In November 2021, the Moroccan section of GME was closed at the end of the multiyear contract due to political clashes. LNG has become a topic of interest in Rabat. Already back in 2014, Morocco envisaged spending around $4.5 billion for the construction of a 5 bcm/year LNG terminal at Jorf Lasfar. However, this plan did not move forward as planned. In 2021, Morocco has started considering a more flexible and economic solution: a FSRU terminal. Morocco plans to start to import 1.1 bcm via LNG in 2025, going up to 1.7 bcm in 2030 and 3.1 bcm in 2040. LNG imports would supply mainly industry and power generation, and they would provide a direct alternative to Algeria’s gas (between 0.8 and 1 bcm). Moreover, Morocco is increasingly considering LNG imports in order to phase out of coal, in line with its climate targets and in response to the growing pressure on the most polluting fossil fuel source. Under these terms, LNG imports will be crucial to prevent further coal use as Morocco stopped receiving Algeria’s gas in November 2021.
In the long run, Morocco may well become a renewable power exporter. In 2019, Morocco and Spain signed a Memorandum of Understanding (MoU) for the construction of a third power interconnection, bringing the interconnection capacity from today’s 800 MW to 1,500 MW. The Spanish Electricity Grid Operator REE has strongly supported the construction of a third power line stating that it would boost green power in the Spanish grid, and it would contribute to reaching the goal of 100% renewable energy by 2050. Nevertheless, REE’s statement may be over-optimistic for two main reasons. First, despite electricity consumption growing at a slower pace in 2011–2020 (3.1% average annual growth rate per year) compared to the period 2000–2010 (4.5% average annual growth rate per year), it is still rising, possibly limiting the country’s export capacities in the years to come, especially in case hydrocarbon exploration and development remain unsuccessful. Second, as Morocco is the country most reliant on coal for power generation in the MENA region, electricity exports to Spain may not be that “green” and may therefore not contribute to reaching the Spanish decarbonization target by 2050.
All in all, despite similarities, Tunisia and Morocco display two different track records in the energy sector, which are highly influenced by the presence (or lack) of fossil fuel endowments. On the one hand, Morocco, being used to importing energy sources, has shown great adaptability and flexibility to ensure a secure and resilient energy mix (despite its dispute with Algeria), and it may well be on the right track to become a relevant power exporter. On the other hand, Tunisia has kept relying on gas, even though its domestic production cannot satisfy the country’s total demand. Thus, regulatory changes regarding the introduction of renewables took more time to take place and renewable capacities lag behind with respect to Morocco. Nevertheless, it may be concluded that Tunisia is following Morocco’s example to ensure a high degree of renewable energy development.
Notes
- 1.
At constant 2015 US$.
- 2.
The Mina Al-Ahmadi FSRU.
- 3.
In 2020, Kuwait signed a 15-year agreement with Shell and Mitsui for 8 bcm/year of LNG until 2035 and with Qatar Petroleum and Qatargas for 8 bcm/y from 2022 to 2037.
- 4.
Nagoholding owns 100% of Tatweer Petroleum since 2016 following the withdrawal of Occidental Petroleum and Mibadala Development Company.
- 5.
It is owned by Oman government (60%), Shell (34%), Total (4%) and Partex (2%).
- 6.
The term ‘P5 + 1’ refers to the five permanent members of the United Nations Security Council (the US, Russia, China, the United Kingdom and France) plus Germany.
- 7.
International sanctions hinder any trade exchange, including fuel imports/exports.
- 8.
Under the Alaska model, the state distributes the rent as cash payments rather than employment and free or subsidized goods and services.
- 9.
Oil shale is unlike shale oil in that oil shale is essentially rock that contains a compound called kerogen, which is used to make oil. It is also much more difficult to recover than shale oil.
- 10.
Founder of the Italian oil company, Eni.
- 11.
Former President of the Gas Natural Company, the Spanish gas company, now known as Naturgy.
- 12.
This figure was provided during a conversation between the authors and well-informed Algerian sources.
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Hafner, M., Raimondi, P.P., Bonometti, B. (2023). National Energy Sectors: Historical Evolution and Current Situation. In: The Energy Sector and Energy Geopolitics in the MENA Region at a Crossroad. Perspectives on Development in the Middle East and North Africa (MENA) Region. Springer, Cham. https://doi.org/10.1007/978-3-031-30705-8_3
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