Abstract
The energy transition both in MENA countries and at the international level entails massive consequences for the region. The chapter presents different factors determining the future geopolitical role for MENA oil and gas exporters as well as MENA hydrocarbon-poor countries. By doing so, the chapter identifies the possible strategies, competitive advantages and constraints that will define the future geopolitical relevance both in the hydrocarbon sector (for hydrocarbon-exporters) and in the clean energy sector (for all MENA countries).
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Keywords
This chapter addresses the geopolitical consequences of the energy transformation in MENA countries. The global decarbonization entails both opportunities and challenges for all MENA countries. Their future geopolitical relevance will depend on how fast they manage to exploit their competitive advantages both in the hydrocarbon sector (for hydrocarbon-exporters) and in the clean energy sector (for all MENA countries).
For hydrocarbon exporters, the future geopolitical relevance will depend firstly on the type of energy source that they export the most (either oil or gas) as a faster decline for global oil demand than global gas demand is generally forecast in deep decarbonization scenarios. Notwithstanding the differences, all hydrocarbon countries will need to enhance the diversification of their export portfolio in order to balance declining demand in key regions. In general, those hydrocarbon exporters (North African countries) that rely heavily on certain world’s regions that have more ambitious and tighter climate policy (e.g. Europe) may in the long run face more challenges than those (Gulf countries) which export most of their volumes to rising energy markets (e.g. Asia). Additionally, geopolitical relevance for gas exporters will be determined also by the transportation mode: those countries which rely more on pipeline (Algeria, Libya) will face more challenges compared to those who export most of their gas via LNG, such as Qatar. The latter will be better positioned to respond to the variation and shifts of global demand. In short, energy demand will become a key component of the future energy geopolitics as exporters will compete for smaller markets. Furthermore, some of the MENA hydrocarbon exporters (Saudi Arabia, the UAE, Qatar) could remain geopolitically relevant in a low carbon future given their low-production costs and low carbon intensity of their production compared to other MENA and global producers. In order to remain competitive and geopolitical relevant, MENA hydrocarbon exporters will need to enhance the resilience of their industry to better face tighter demand and climate policies.
All MENA countries could gain new geopolitical relevance by exploiting their great renewables potential. Key domestic factors determining the future geopolitical role of all MENA countries include population growth, financial capabilities, governance stability. These will define the ability to implement the required reforms as well as adapt and adjust the domestic dimension to the upcoming low-carbon future. Those with small population, high domestic financial reserves and stable governance will be better positioned to achieve their renewable targets, implement domestic reforms to transform the industry and the country in line with a decarbonized global energy landscape.
A key sector where all these countries have a potential is the export of clean energy both in the form of electricity and hydrogen. North African countries could eventually benefit from higher renewable installation, land availability and geographical proximity to export clean energy to Europe even though they would need to speed up renewable deployment for domestic and international purposes as well as enhance cross-border interconnections. Hydrogen fits well in the existing hydrocarbon industry and responses to the need to find new income sources. Numerous countries in the region have expressed their commitment to become major producers and exporters. Preferences on the ‘color’ of hydrogen vary among MENA countries. Maghreb producers have the advantage compared to other MENA countries to be able to export hydrogen to Europe cheaply through adapted but existing gas pipelines. Those countries which are considering to develop long-distance maritime hydrogen trade may face technical and economic challenges. Some countries may prefer to use domestically produced clean hydrogen in order to decarbonize their industry sector, often a key pillar of the industrialization of these countries, and then export final or semifinal decarbonized products.
The global energy transition is set to entail major geopolitical transformations that will impact the countries of the MENA region, given the current pivotal role of these countries in global energy geopolitics. Commonly, yet erroneously, the energy transition is seen as the end of the petrostates. Indeed, some petrostates are expected to remain relevant in the energy system as hydrocarbons will still play a significant role also in a future net-zero energy system. Moreover, MENA countries, thanks to their low production costs, have a competitive advantage. Energy markets have always been characterized by volatility and shocks. Strong price volatility may result in the fortune or crisis of hydrocarbon producing countries, enhancing or weakening their role in the geopolitical landscape. In fact, the energy transition entails opportunities for MENA countries, because they are all endowed with renewable energy sources, notably solar and wind. Therefore, both hydrocarbon-rich and hydrocarbon-poor countries may find solutions to remain or become relevant in the upcoming geopolitical map.
This chapter seeks to address these issues by explaining the impact of the changing global energy process on the MENA region, and then identifying which factors, both at the international and domestic level, could contribute to the repositioning of MENA countries in the evolving energy landscape. Finally, the chapter will try to outline further geo-economic implications for the region in light of the energy transition.
1 Geopolitical Impacts of the Changing Global Energy Landscape on the MENA Region
As illustrated in the previous chapter, the MENA region is a cornerstone of the current global energy system. Oil has shaped the domestic socioeconomic model, contributing to form the existing ruling élites, and positioning the MENA region at the center of the architecture of energy geopolitics. However, all of this could fade away—or at least be drastically weakened—as the global energy transition unfolds.
The clean energy transition, along with technological developments, is expected to challenge the socio-economic and geopolitical foundations of the region in general, and of its oil and gas producing countries in particular. This could cause major geopolitical risks as oil and gas producers could start a fierce competition war, while lower oil revenues could trigger domestic social instability. At the same time, however, both hydrocarbon producers and importers of the MENA region may benefit from the energy transition thanks to their important renewable energy potential (mainly solar, but in some countries also wind), positioning themselves as clean energy exporters.
In 2019, the International Renewable Energy Agency (IRENA) launched the report ‘A New World. The Geopolitics of the Energy Transformation’ (2019), assessing the geopolitical consequences of the energy transition. This report takes into consideration its potential effects on oil producing countries, among which MENA oil and gas producers are particularly important.
In the last five years, several scholars have increasingly focused their studies on the evolution of low-carbon energy geopolitics (O’Sullivan et al. 2017; Scholten 2018; Hafner and Tagliapietra 2020), which may produce multiple and relevant consequences in the power relations among and between energy producers and consumers, affecting the geopolitical importance of MENA oil producers. MENA producing countries have historically enjoyed an important geopolitical influence because they supply a large portion of the fossil fuels needed to run the world’s economy. However, they are likely to see a decline in their global influence due to the expected reduction in global oil demand, unless they can adapt and adjust their economy to the new energy era.
Oil and gas producers in the region must face a challenge that has two dimensions: domestic and international. A decline in global oil and gas demand would entail less revenues for producing countries. This would deeply challenge the socio-economic roots of these countries, considering their profound dependence on the oil and gas rents (the so-called ‘Rentier state’ model) see Chap. 2, Sect. 2.1. Moreover, the clean energy transition might push producers towards a fierce competition for global market share, exacerbating geopolitical risks both regionally and globally.
The evolution of oil, domestic stability and prosperity, as well as international influence, are deeply interlinked in the MENA region. Any geopolitical consideration of a more carbon-constrained world must therefore take into consideration the domestic aspects.
In 2020, MENA oil and gas producers experienced a situation that can be described as a preview of what the future might look like for them beyond 2030 and towards 2050, as global decarbonization takes more and more ground. The COVID-19 pandemic resulted in an unprecedented crash in global oil demand. Lockdown policies across the globe forced the shutdown of business, manufacturing, travel, entertainment, logistics and retail destroying the ability to consume oil, causing the strongest contraction in the oil industry’s history (−20 mb/d in April 2020).
At the same time, oil prices collapsed due to a lethal combination of falling demand and OPEC+ coordination failure. Brent price dropped from $63.5 in January to $18.3 in April 2020. The benchmark price for US crude oil, the West Texas Intermediate (WTI), was even briefly negative in April 2020 for the first time in history due to the lack of available storage capacity in Cushing, Oklahoma, where the WTI trading hub is located. The combination of falling demand and oil prices generated a perfect storm for MENA oil and gas producing countries that led to significant macroeconomic imbalances.
All the countries of the region saw negative growth in 2020 (IEA 2020a). This weakness was manifested in both oil and non-oil sectors. Indeed, most of the oil and gas exporters had diversified their economies in sectors deeply affected by the COVID-19 outbreak, such as tourism, real estate and aviation. MENA oil and gas producers had to turn to public expenditure cuts and increase fiscal adjustments. Saudi Arabia decided to triple its VAT from 5 to 15% in July 2020, while suspending its cost of living allowance to shore up state finances. The allowance of 1000 riyals ($267) to state employees was introduced in 2018 to help offset increased financial burdens (BBC 2020).
After decades of (largely unfounded) concerns about supply disruptions and resource scarcity, COVID-19 exacerbated a trend started almost a decade before: abundance of energy. Underpinned by high oil prices, the 2000s have witnessed an expansion of oil production in different geographical areas, including US shale oil in the 2010s. A confirmation of the energy abundance dynamic is the relatively small oil price impact of major incidents to oil infrastructure and tensions between critical suppliers, such as the attacks to Saudi oil facilities, tanker seizures since 2020, and the increasing use of international sanctions against major oil and gas producers such as Venezuela and Iran. All these (geo)political episodes did not reignite fears over potential supply disruptions, while it is reasonable to say that the same events would have produced more long-lasting and serious oil price shocks only a decade ago.
Energy abundance has triggered the decline of energy prices, which were expected to enter into a “lower for longer” period—albeit with some volatility. So, the expansion of the supply side and lower oil prices are two of the main characteristics of the energy abundance period that started in 2014. Nonetheless, in 2021/22 the world has experienced a spike of energy prices caused by the sudden and strong restart of energy demand after months of lockdowns, massive public expenditure, limited spare capacity and geopolitical tensions. Although high energy prices may remain for quite a while, the current energy price spike highlights the increasing role of price volatility as a feature of the transitional process. Low energy prices may be the end outcome, while growing price volatility may be the transitional effect of a world that is steadily undergoing a fundamental overhaul.
Throughout the last two decades, the world’s energy markets have witnessed an expansionary trend, with an increasing global output. Simultaneously, OPEC countries have seen their market share decline (Fig. 6.1).
Source Authors’ elaboration on BP (2022)
World’s oil output (million tonnes, left axis) and OPEC, US and Russian share (%, right axis), 2000–2021.
COVID-19 has exacerbated some factors, shifting the attention from the supply to the demand side. Until 2020 the abundance of energy was related to the supply side; 2020 (and COVID-19) produced an energy abundance, which was mainly driven by demand constraints—a plausible scenario also for the decades ahead in a global deep decarbonization pathway.
As in other phases of high oil prices (e.g. 1980s), in the 2000s non-OPEC production grew extensively while demand growth was more moderate. Such an expansion was mainly driven by high prices (above $100 per barrel over the period 2011–2014) (Fig. 6.2). High prices were motivated by low spare capacities, thus the risk of potential supply disruptions, mostly due to geopolitical reasons.
Source Authors’ elaboration on BP (2022)
World oil output 1965–2021, mb/d (right axis) and Mt (left axis).
Around 2010, the global energy markets were shaken by a major energy revolution pushed by small independent companies that tapped US oil and gas unconventional reserves through ‘hydraulic fracking’. The so-called ‘Frackers’ allowed the US to increase domestic output and reduce its import dependence towards unstable regions like the Middle East and North Africa.
Sustained by favorable economic, financial and technological conditions, the ‘Frackers’ allowed the US to abandon fears of energy scarcity, which had driven American energy policy and diplomacy for decades. The US’ historical need to secure stable and ever-growing oil supplies had underpinned the traditional security architecture of the MENA region, influencing alliances and hostility.
The expansion of domestic oil and gas output (and the consequent ability to export) prompted lengthy discussions about the potential consequences on US-MENA relations and the region’s loss of strategic relevance for US policymakers. The Trump Administration extensively invoked the achievement of ‘energy dominance’ and ‘energy independence’. Thanks to the growing domestic output, Trump decided to pursue a more assertive foreign policy regarding energy and security issues, expanding financial sanctions (against Venezuela and Russia) and imposing higher pressure on other suppliers (Iran). This strategy has partially faded with the election of Joe Biden as President in 2021. Nonetheless, the new American energy status has enabled Washington to take a stand vis-à-vis Russia. Moreover, the Biden Administration has extensively affirmed its commitment to lead the energy transition.
The American oil and gas production may ultimately cause a reduction of US engagement in the MENA region, especially at a time of escalating power rivalry with China. Even though the US will increasingly focus on its broader competition with China and other world regions, the US will not completely withdraw from the MENA region or lose its interest in energy issues. O’Sullivan (2017a, b) affirmed that the US has three constant objectives that are easier to achieve thanks to the new energy abundance, i.e.: (1) ensuring that global energy markets—particularly the oil market—are well supplied; (2) encouraging allies to diversify their own sources of energy; and (3) using its power as the largest global oil consumer to penalize countries, or to compel them to change policies (O’Sullivan 2017a, b). As we shall see below, the US energy status is still far from the self-proclaimed ‘energy independence’. Even though the US has reduced energy imports, the US oil and gas producers are exposed to price volatility. Thus, the MENA region is still strategically important for Washington and the US and its energy sector is still deeply affected by the developments of the global energy markets.
However, the growing role of the US in the global oil market has also impacted the long-lasting relation with Saudi Arabia. In 2014, Saudi Arabia increased its oil output in order to drive out of the market its higher-cost competitors, notably the US shale producers, which were constantly increasing output at prices above 100 $/b. This strategy caused a major drop in oil prices (Fig. 6.3), and MENA oil and gas producers started to take into consideration diversification strategies in order to reduce their vulnerability to oil price volatility. Oil prices were then stabilized thanks to the shared and coordinated effort of OPEC and non-OPEC countries (led by Russia) in 2016, which contributed to enlarging the governance of global oil markets.
From a demand perspective, fossil fuels have witnessed some downturns. The 2008 financial crisis caused a temporary decline of oil demand, especially in developed countries. Nonetheless, the demand of fossil fuels (especially oil) has increasingly been under pressure. The 2015 Paris Agreement represents a watershed episode for future fossil fuels demand. The COP21 marked climate change as one of the top priorities for the world’s governments. National governments and international institutions have expressed their political commitment to decarbonize the world’s economy in order to reduce global temperature and tackle the negative effects of climate change. Ever since, the global momentum for a global and deep decarbonization has increased.
Along with political decisions, technological developments have enabled governments and citizens to increase energy efficiency and allowed renewable energy sources to penetrate energy mixes. The strong development and prospects of electric vehicles (EVs), combined with regulatory bans on internal combustion engines (ICEs), may hinder future oil demand. Road transport accounted for more than 40% of global oil demand in 2019. The transport sector’s growth has been responsible for over half of the total oil demand growth since 2000. The growing deployment of EVs, along with hydrogen and natural gas vehicles, will erode almost 15 mb/d of oil demand growth by 2040, according to BNEF (2020).
Source Authors’ elaboration on BP (2022)
Brent price ($/barrel, $ money of the day) and main (geo)political events, 2000–2021.
Energy geopolitics will further mutate, as the global energy transition gains pace. MENA oil and gas producing countries will feel geopolitical shifts, both in terms of domestic stability and international influence. Therefore, this chapter will evaluate the geopolitical implications of the consequences caused by the transition, taking into account also the domestic sphere.
The general context is thus characterized by increasing political support for decarbonization policies combined with technological progress aimed at increasing the penetration of technological solutions that reduce reliance on hydrocarbons. Despite this general context, it is important to stress again that the MENA countries are far from being a homogenous group, and that the impacts of the global energy transition may be very different depending on the country. Such differences are due to: the country being a hydrocarbon exporter or importer, if the country is a hydrocarbon exporter, whether its primary focus is on oil or gas; the country’s export portfolio composition and its diversification, its economic diversification, and domestic characteristics (financial, political and institutional capacity to adapt to profound transformations).
2 Key Factors Determining the Future Geopolitical Role of MENA Oil and Gas Exporters
Today, MENA oil and gas producers need to take into consideration some international factors in order to design proper strategies to maintain their geopolitical influence and role. As discussed in the following pages, these international factors are: (i) the different trajectories of oil and gas demand as decarbonization policies are gaining momentum worldwide; (ii) the different pace of the energy transition across the world’s regions; (iii) the crucial need for diversification of export portfolios; (iv) the higher competition experienced by producers in a constrained demand world; (v) the advantages of some producers (low-production costs and carbon intensity) compared to their competitors.
MENA producers are set to remain among the last producers in a decarbonized world thanks to their vast resources, low production costs and new competitive advantages. At the same time, MENA countries (including non-hydrocarbon producers) might try to exploit their renewable potential to contribute to the common effort against climate change and to position themselves as important clean energy players. That is not, however, an easy task. Nonetheless, the global energy transition will further stress the strong tie between oil revenues and socioeconomic and political stability. The ability to collect and allocate oil revenues remains crucial as oil revenues may fade away in the longer run, while at the same time moving away from the rentier economy may prove socially difficult.
The following sections (from 6.2.1 to 6.2.5) are focused on the key factors that will affect oil and gas producing countries, while non-hydrocarbon producers in the MENA region are driven by different factors. They are not pushed by the need to protect their hydrocarbon industry and increase its resilience ahead of lower oil demand, but they need to find alternatives to produce wealth for their growing population as explained in the section (domestic factors).
2.1 Oil and Gas: Different Scenarios, but with Some Common Long-Term Challenges
In a decarbonized world, fossil fuel demand will decline significantly. However, future fossil fuel demand may witness differences across the world’s regions due to climate policies as well as economic and demographic trends. Oil and gas demand are likely to have different trajectories in the future. Oil demand is expected to increasingly lose relevance as a result of growing decarbonization policies and technological developments in oil demand-driving sectors such as transport (i.e. electric vehicles), while natural gas will play a bridging role in the global energy mix for decades to come—often labelled as “transition fuel”. Natural gas will, however, face higher political scrutiny due to methane emissions and it will need to be decarbonized in the longer run.
Thus, a first consideration is the different outlook that oil and gas producers may have. Oil producers may encounter challenges and a loss of geopolitical influence earlier than gas producers. In the last years, attention has moved from the concept of ‘peak oil supply’ to ‘peak oil demand’. Peak oil demand consists of a decline of global oil demand in the relatively near term, caused by the climate policies (i.e. improvements in energy efficiency, greenhouse gas emissions limits) and the development of technological solutions (i.e. expansion of EVs). Estimates and forecasts diverge on when this might occur. A range from the mid-2020s to the 2040s or beyond is identified by different sources.
Section 2.6.3 in Chap. 2 outlines the evolution of future oil demand according to the International Energy Agency’s scenarios. Global oil demand, which had reached its record level of 97.6 mb/d in 2019 before falling to 88.5 mb/d in 2020 during the shutdowns of the first Corona year, is expected to reach by 2050 a level of 45 mb/d (−54% compared to 2019) in the “Sustainable Development Scenario” (SDS) and even down to 21 mb/d (−78.5%, or compared to 2019) in the “Net Zero Emissions Scenario by 2050” NZE (Fig. 2.7, see Chap. 2, Sect. 2.6.3). In SDS, Middle EastFootnote 1 oil production is expected to fall from some 30 mb/d in 2019 to some 18 mb/d by 2050, a reduction of 40%. At the same time, the global market share of MENA oil will increase from some 31% of today to 38% by 2050. Despite the expected peak of oil demand, global oil demand increased in 2021 (94 mb/d) underpinned by economic recovery and massive public investment plans. Apparently, oil demand has not reached its peak yet. Nonetheless, governments have committed to their climate ambitions. Moreover, technological developments, coupled with high fossil fuel prices, may incentivize consumers to shift towards more clean energy solutions in several sectors, such as transport.
Natural gas demand has a different, yet challenging, future (Figs. 2.8 and 2.9 see Chap. 2, Sect. 2.6.3). The IEA foresees that in decarbonization scenarios global natural gas demand remains roughly stable at around 3860 bcm (the 2020 level) up to 2030. After 2030, the global demand for natural gas (in particular for unabated natural gas) should decline rapidly. By 2050, natural gas demand is expected to reach around 2367 bcm (−39% compared to 2020) in the SDS and 1686 bcm (−56% compared to 2020) in the NZE. In NZE, natural gas demand falls largely in all regions, except those that are currently heavily reliant on coal, where natural gas largely displaces coal. In NZE, in 2050, about half the global gas will be produced in the Middle East and Russia. According to this deep decarbonization scenario, the Middle East production of natural gas would fall from around 650 bcm in 2019 to some 400 bcm in 2050, representing a quarter of the global natural gas supply (another quarter is expected to be supplied by Russia and the US, respectively—the balance by Africa and the rest of the world). Therefore, even though overall production in the Middle East would decline, its market share on a worldwide scale would increase from 14% of today to 24% by 2050. Still according to NZE, interregional trade of natural gas will fall to less than 300 bcm, around 40% of the current level.
In short, over the next decades, global oil and gas demand will need to fall in line with global climate targets. Compared to oil, the fall in gas demand will be less rapid and less dramatic. Due to the important reserves and low production costs of the MENA region, the market share of this area is expected to increase, even though their absolute exports will nevertheless fall importantly. The different pace of declining demand for oil and gas poses a different urgency to MENA oil and gas producers in the short term, while in the longer run they face the same challenges to preserve their geopolitical position in the global energy map.
As the following section illustrates, today’s energy transition is mainly a policy-driven process, meaning that its speed across the world may vary significantly.
2.2 Energy Transition: Not with the Same Pace Across the Globe
Being a policy-driven process, clean energy transition will happen at different speeds across the world, and this will be a further factor in determining MENA geopolitical shifts. Moreover, it will determine divergent trends of fossil fuels demand in different geographical areas. For instance, Europe’s oil and liquids demand is expected to decrease from the current 13.3 million tons of oil equivalent (Mtoe) to 8.6 Mtoe in 2040, according to the International Energy Agency (IEA)’s Stated Policies Scenario. By contrast, Asia–Pacific countries’ oil and liquids demand is set to increase from the current 32.5 to 37.9 Mtoe in 2040 (IEA 2020b).
The pandemic has further exacerbated such divergent trends among different regions—especially between OECD and non-OECD. The focus of most governments in the post-pandemic period will be on restoring economies and stimulating employment. This focus might push global oil demand. However, a growing number of the world’s economies (mainly advanced economies) have decided to use their recovery strategies and funds with a strong emphasis on supporting green investment. This will exacerbate the divergent trends in energy (and particularly oil) demand between OECD and non-OECD countries (OPEC 2020). The 2022 Ukraine war will also strengthen Europe’s transition to green energies over the medium to long term as outlined by the REPowerEU plan.
These elements highlight an important feature of future energy geopolitics: the increasing dominance of energy demand. Particularly in an energy abundance period (oversupplied energy markets and constrained demand), energy demand will become more relevant in the geopolitical equation.
Following the recent IPCC reports of 2018 (Global Warming of 1.5 °C), 2021 (Climate Change 2021: The Physical Science Basis) and 2022 (Climate Change 2022: Impacts, Adaptation, and Vulnerability) calling for limiting global temperatures to 1.5 °C, a growing number of countries have announced their pledge to become carbon–neutral by mid-century (Fig. 6.4).
Source Authors’ elaboration on Rystad Energy (2020)
Number of countries to announce net zero targets, count, split by year of announcement.
Many governments took advantage of the recovery plans to implement strong climate agendas and to prepare their economies for a decarbonized world. For example, the EU announced its ambition to become the first carbon–neutral continent. Climate policies and the European Green Deal are key pillars of its €750 billion recovery plan. In September 2020, China’s President Xi Jinping announced that China will reach carbon-neutrality by 2060. And with the election of Joe Biden as President of the United States, the US rejoined the global climate arena aiming at reaffirming itself as an important player in the fight against climate change and the energy transition. In 2021, Russia joined the carbon neutrality club, with President Putin’s announcement that Russia will reach carbon neutrality by 2060 at the latest.
Those MENA producers that are more dependent on the energy markets that have higher decarbonization commitments, such as the European Union, will be more exposed to economic and geopolitical loss unless they adapt to the new context. The producers, such as the North African ones, which are unable to diversify their export portfolio, may suffer the most and more rapidly from the energy transition of their key markets. By contrast, those MENA oil and gas producers that export to growing energy markets, like Asian countries, should be able to preserve their geopolitical influence. For such reasons, the export portfolio composition and its diversification are increasingly crucial in the new energy transition.
2.3 Export Portfolio Composition and Its Diversification
It will be of paramount relevance for oil and gas producers to ensure a proper and diversified export portfolio that will help them to navigate in the future geopolitical waters of the energy transition, and it will be crucial for MENA oil and gas producers to secure and create demand for their exports.
The main battleground will be Asia and its fast-growing energy markets. By contrast, Europe is expected to reduce its fossil fuels import dependence, especially in the long-term, as a consequence of strong climate policies (i.e. the European Green Deal). Therefore, those oil and gas exporters that are (and continue to be) heavily dependent on the European markets will see a reduction of geopolitical influence, alongside falling revenues.
Among oil exporters, the Gulf countries are already selling most of their products to the Asian markets. By contrast, the North African countries, such as Algeria and Libya, export most of their oil to Europe and North America. This divergence is clear in the following table that shows the different export outlets for key oil exporters and the relevance of the Asian markets in their export portfolio. Kuwait and the Emirates export about 84% of their oil to the Asian markets, while the percentage declines significantly for North African countries (26%) (Fig. 6.5).
Source Authors’ elaboration on BP data
Main oil exporters and their export outlets, 2019. Note Figures above the bars are the total export volumes in million tonnes in 2019.
A defining factor for successful diversification strategies also regards the type of fossil fuel and transportation mode in the case of gas. Indeed, while oil (and LNG) can easily follow demand changes, piped gas does not provide the same degree of flexibility, as it cannot shift according to demand dynamics. An example of challenge represented by demand changes is Algeria, once an important gas player in the European gas markets. The vast majority of its gas exports flows to Europe via pipeline: in 2019 85% of Algeria’s total gas exports went to Europe, 62% of which via pipeline (BP 2020b), mainly to Italy and Spain (Fig. 6.6). To reduce its overdependence on European markets, Algeria could increase its LNG exports to its total capacity of 25.3 Mtpa, and thus diversify its gas export markets. Following Russia’s invasion of Ukraine in 2022, the European Union wants to wean itself off Russian gas. This provides a new momentum for North African countries as they benefit from geographical proximity and existing political and energy relations with European countries.
Source Authors’ elaboration on BP data
Main MENA gas exporters’ gas exports composition (LNG vs. pipeline), (left), and the LNG share of total gas exports (right) in 2019, bcm.
Indeed, LNG provides more flexibility to gas exporters, which are better positioned to respond to the geographical shifts of energy demand, ensuring market shares in growing gas markets in particular in Asia. However, Algeria’s LNG exports are highly dependent on European markets (92% of Algeria’s total LNG exports in 2019) (Fig. 6.7). LNG exporters in the MENA region are divided between those located West of Suez (North African exporters) and East of Suez (Gulf exporters). This geographical factor will define competitiveness in the European or Asian markets, as passing through Suez entails higher costs (besides longer distances). Thus contributing to increasing costs. In fact, the competitive advantage of LNG exporters in the European or Asian markets will depend on whether they are located West or East of Suez.
Source Authors’ elaboration on BP data
Main LNG exporters and their export outlets, 2019. Note Figures on the top of the bars represent the total LNG export volumes in 2019.
Qatar inevitably holds a leading position within this group of countries, being the top LNG exporter. Indeed, in 2019 Qatar exported 107.1 bcm of LNG, which represents 83% of its total gas exports. Of this volume, 67% was directed to Asia Pacific countries (BP 2020b). Moreover, Qatar has developed a well-diversified export portfolio, with several LNG importing countries (both in Europe and in Asia), as Fig. 6.8 shows.
Source Authors’ elaboration on BP (2020b)
Qatar LNG exports by country, 2019, (bcm).
In fact, the Asian markets are expected to lead natural gas demand growth, with China and India as the two major gas importers in the coming decades. Furthermore, increasing global gas volumes are expected to be transported via LNG, while pipeline volumes (especially in Europe) are expected to decline, also in line with the effort of European countries to reduce their dependence on Russian gas due to Russia’s war in Ukraine. LNG trade is thus expected to expand significantly at a global level in the next decades, and global LNG trade will expand from just over 50% of the traded volumes of today to 60–70% in 2050, depending on the scenario (IEA 2021). DNV GL forecasts that the seaborne trade of natural gas (LNG and liquefied petroleum gas combined) will increase fourfold from 415 Mt per year in 2018 to 1680 Mt per year in 2050 (DNV GL 2020). Bloomberg NEF et al. (2020) estimates that China will meet 54% of its demand through gas imports in 2040, while India’s import share will rise from 48% in 2018 to 58% by 2040.
In such a challenging context, both oil and gas producers will look to preserve and expand their competitive advantages as they will need to compete for a smaller market.
2.4 Competition Will Remain and Increase in a Constrained Demand World
Although energy demand will dominate the next phase of energy geopolitics, supply issues will not disappear. Oil and gas producers will still compete for markets and this competition could even increase. A peak of oil demand will result in harsher and more intense competition, and tighter revenues for MENA oil and gas producers. It is reasonable to believe that not all oil and gas producers will pursue the same supply strategy, as each producer will also make specific social and economic considerations related to its domestic sphere.
Indeed, the transition raises an existential dilemma of maximizing production and weakening higher-cost competitors, or coordinating production cuts to increase oil prices—vital for governments’ revenues and their domestic stability. This is of paramount importance, as the future strategy will change global oil markets and the geopolitical relevance of MENA oil and gas producers.
Over the past few decades, high-cost producers have coexisted and competed alongside low-cost producers in the oil market. Due to the perceived scarcity fears, the laws of competitive markets have not been applied to the oil markets. High-cost producers have been able to operate without being driven out of the market; on the contrary, they have gained ground, as happened with the US. This is because low-cost producers, such as MENA countries, have effectively rationed their supplies of oil. They have preserved their resources for the future (since they are the government’s main revenue source) rather than using their competitive advantage to maximize their market share (Dale and Fattouh 2018). A consequence of this policy is that the proved reserve to production ratio (R/P) extends to several decades, beyond all peak oil demand forecasts (Fig. 6.9). This could undermine the ability of MENA countries to monetize their large reserve base, which is vital for the functioning of their economies.
Source Authors’ elaboration on BP (2020b)
R/P ratio in selected MENA oil producing countries, 2019 (years).
To avoid major losses, MENA oil exporting countries could also pursue oil output strategies to boost their revenues. Such an approach does not come without important consequences and trade-offs, and thus requires to be carefully considered. A high volume or market share strategy could result in a fall in oil revenues as the higher revenue due to higher volumes may not compensate for the loss in revenues due to the lower oil prices. Such a risk is both related to the short term (as low oil prices may not result in the immediate shut-in of production in high-cost producers) and to the long-term (as revenues might not increase if other producers turn out to be more resilient to a low oil price environment—while in a high price environment, which implies a supply shortage, any supply maximization possibility will be pursued by all players). On the other hand, in a low price environment, MENA oil producers could cut output to support prices and increase their revenues even though this strategy comes with great uncertainty. It may result in loss of market share and may not lead to large increases in revenues if the cuts are replaced by increases in output from non-participating producers (Fattouh and Poudineh 2020) and/or a faster demand destruction.
2020 and COVID-19, characterized by a strong reduction of demand and thus prices, exacerbated the dilemma of low-cost producers. A maximization of production strategy would put into question established assumptions on saving reserves for future production and avoid stranded assets. However, greater competition among suppliers could undermine coordinated actions (i.e. agreements within OPEC), which are a key tool to oil price stability. The years 2021 and 2022 present a completely different situation in terms of energy prices due to an unbalanced supply–demand equilibrium and a geopolitical price premium due to additional risks. Nonetheless, high energy prices may induce some producing countries to ramp up their production, especially those that rely heavily on hydrocarbons to maximize their revenues. As a result, political coordination among producers may become increasingly difficult in a scenario characterized by tighter demand.
Throughout the period of low prices (2014–2020), producers managed to work together to stabilize oil prices. A crucial contribution was the expansion of oil governance with the formation of OPEC+ in 2016. Its relevance became even clearer in March 2020 when the agreement collapsed due to differences between the two kingmakers (Riyadh and Moscow). The disagreements regarded the best political response to the sudden halt of the world’s oil demand due to lockdowns. Saudi Arabia waged a full price war, slashing their official selling prices (FT 2020) and announced plans to increase production to 10 mb/d or more since April 1st, 2020 (the day after the expiration of the OPEC+ agreement). Traditionally, Saudi Arabia is able to increase its supply at short notice and is willing to shift policy if there is no agreement on collective cuts and/or lack of compliance to enforce discipline in the absence of a formal enforcement mechanism (Fattouh 2021).
Moreover, the 2020 oil price war between Saudi Arabia and Russia also had another target: the US shale producers. Thanks to high oil prices, technological developments and financial advantages, the US has become one of the world’s largest oil producers, gaining increasingly large market shares at the expense of the OPEC+ countries.
To end the economic bleeding, Russia and Saudi Arabia put aside their disagreements within weeks and OPEC+ agreed on a historic cut of 9.7 mb/d. On this occasion, the US played a pivotal role in the agreement, demanding a more collaborative approach to its long-lasting Gulf ally. The American involvement highlights the dual role of the US in the global oil markets and governance: on the one side, the US acts as a producer and calls for a higher oil price in a low-price environment, whereas in a high-price environment, it acts as a consumer calling for a lower oil price (Fattouh 2021).
OPEC+ managed to preserve its cohesion throughout the increase of oil prices in 2021/22 despite the growing political pressure of Western importing countries (US, UK and the EU). It was possible because its coordination is in the national interests of the producing countries. Nonetheless, some OPEC countries have announced their intention to pursue the maximization of their capacity, thus weakening the coordinated policy, because it is in the interest of some of the countries to remain relevant players (albeit potential lower oil demand). This is the case of cyclical tensions between the UAE (OPEC’s third-largest oil producer) and Saudi Arabia. Indeed, the UAE announced an ambitious plan to increase its oil capacity from about 4 to 5 mb/d by 2030. Moreover, in late 2020, ADNOC announced a $122 billion investment plan for 2021–2025 (corresponding to an annual investment of $24.4 billion), suggesting that the UAE have abandoned their more cautious approach to the oil sector. To put its scale into context, the 2020 ADNOC’s investment plans are broadly in line with those of Saudi Aramco. Indeed, Saudi Aramco slashed 2020’s planned CAPEX by nearly 30% to $25–30 billion.
These expansion plans reveal that MENA oil producing countries are eager to benefit from their vast competitive advantages compared to other producing countries. For example, the UAE has a strong ambition on energy: it has announced a 5 mb/d target by 2030, setting its target of gas self-sufficiency by that time, tripling its petrochemicals capacity and boosting its refining capacity by 60%. These plans are underpinned by vast and existing fields and major additional discoveries such as those announced by Abu Dhabi’s Supreme Council in November 2020, of an additional 2 billion barrels of conventional to 107 billion barrels oil reserves and a more notable discovery of 22 billion barrels of unconventional oil resources (Mills 2020b). This confirms the ability of ADNOC to increase its capacity with existing fields.
Despite the great unity throughout the Covid crisis and the following oil price spike, the growing prioritization of national interests, the potentially looming peak of oil demand and higher volatility may induce producers to increase their production and undermine coordinated policy. The pursuit of national interests may induce a change in oil policy and intensify disagreements within the OPEC and OPEC+ framework. Nonetheless, it seems that only few countries (Saudi Arabia, UAE and Kuwait) hold enough spare capacity to increase their production and gain higher market shares. Another source of potential tension within the OPEC+ framework may be the fact that Russia may be forced to increase its oil imports toward Asia, the main market for the Gulf countries, especially in China, due to the increasing pressure of Western sanctions in the wake of the Ukrainian war. This may put under scrutiny the Saudi-Russian pact and the broader OPEC+ framework.
All of this poses further pressure on the traditional alignment among Gulf OPEC producers, and challenges OPEC agreements particularly since the month-by-month revision of output limits is a source of potential tension every month. Although all oil producers agree on the necessity to cooperate in order to correct market and price volatility (given their negative effects on government revenues), they generally disagree over which producer should shoulder the burden of the cut. As the global clean energy transition unfolds, these disagreements might intensify, particularly if we consider the larger number of producers involved in the latest coordinated decisions (OPEC, non-OPEC, including also to some extent the US), the size of the needed cut, the diverse nature of the players and their different interests.
Indeed, other OPEC countries have repeatedly announced expansion plans. An example is Iraq that declared a capacity of not less than 7 mb/d by 2027 (Mills 2020b). However, such a target might seem unrealistic in the foreseeable future due to Iraq’s specific characteristics, such as poor fiscal terms for IOCs, a lack of infrastructure and the inability of the Baghdad government to carry its share of costs.
In the gas sector, Qatar mostly competes with extra-regional producers, notably Australia, the US and Russia. Due to major changes in the LNG market and higher competition from other LNG producers, in 2017 Qatar ended its self-imposed moratorium of 77 Mtpa in place since 2005. The capacity expansion will be divided into 2 phases. Phase 1 encompasses four trains with a capacity of 32 Mtpa, which should become online by 2025 raising Qatar’s overall liquefaction capacity to 110 Mtpa. Phase 2 would produce an additional capacity of 16 Mtpa over the next two years. Such an expansion faces some challenges. Qatar will have to find markets for 32 Mtpa in new volumes by 2025 along with around 20 Mtpa in contracts expiring in that time (Cahill and Tsafos 2020). Qatar will evaluate whether to postpone the Phase 2 expansion according to market conditions. Qatar Petroleum (QP) also holds a 70% equity stake in Golden Pass LNG in the US, which has a capacity of 15.6 Mtpa. Its first train is expected to be on stream in 2024. QP decided to enter the US LNG market in the aftermath of the GCC embargo against Doha in the attempt to enhance its ties with Washington. Moreover, in the last years QP has expanded its international presence by acquiring upstream and downstream assets in the US, Brazil, Angola, Cote d’Ivoire, Guyana, Kenya, Morocco, Mozambique, Oman and South Africa.
In the upcoming competition, Qatar believes it is in the best position to defend and gain market shares, although it may suffer some losses on the price side. To gain market, QP may partially rethink its price strategy. Qatar has been one of the strongest supporters of oil-indexation and long-term contracts in Asia. Some contract negotiations suggest that at least in the short term QP will make concessions on prices to lock up long-term contracts. As a defense mechanism, Qatar expanded booking capacity at existing European import terminals—in particularly at the Zeebrugge terminal in Belgium and the Montoir-de-Bretagne terminal in France (Cahill and Tsafos 2020). Europe still represents the destination of last resort for LNG. Since Asian countries will play a crucial role in the expansion of LNG demand in the foreseeable future, QP could decide to solidify its ties with Asian importing states through concessions to Asian energy companies in its LNG expansion, as did Abu Dhabi with its offshore and onshore blocks.
In order to face the effects of the global energy transition and the potential oil demand peak, MENA oil and gas producers may pursue a strategy aimed at diversifying export portfolio (new and old markets), while generating more value from their existing production as highlighted by Mills (2020a).
However, MENA oil and gas producers are looking for value generation mostly outside the upstream sector. Investment in the oil upstream generally faces challenges caused by either domestic political or security problems, especially in some North African countries. Libya’s upstream situation is highly influenced by security concerns and the evolution of the conflict. Algeria is facing a long-term decline of its oil and gas output unless major new discoveries or investment in EOR are made.
MENA oil and gas producers are increasingly moving toward the downstream sector like refining, petrochemicals, tankers, storage, trading and fuel retail in order to increase the value of, and securing market for, their products. Petrochemicals are seen as one of the most promising areas in the MENA energy landscape. The petrochemical sector is seen by international agencies as a key driver of future oil demand. According to APICORP Gas and Petrochemicals Outlook 2020–2024, planned petrochemical projects are expected to rise by $4 billion from the previous estimate to achieve $95 billion over the period 2020–2024 (APICORP 2020).
Middle Eastern countries have increasingly focused on integrating their large-scale refineries with petrochemical facilities in response to the changing global oil consumption habits. The Middle East—along with Asia—accounted for two-thirds of the global refining investment over the period 2015–2020 and for more than 80% of the refining capacity currently under construction.
Given such investments, by 2030 the Middle East and Asia will emerge as the largest global refining centers, overtaking more traditional ones. Moreover, COVID-19 and the following financial constraints are expected to accelerate the restructuring of the global refining industry in these two regions which have different but competitive advantages: the Middle East has the advantage of cheaper feedstocks, while Asia enjoys the vicinity to still-growing demand centers. As a result, the role of NOCs in global refining is likely to strengthen (IEA 2020c). Despite the great ambition, the road to the petrochemicals boom might face financial constraints, geopolitical threats and competition among producers. Among MENA countries, Egypt, Iran and Saudi Arabia are the top three countries in the region in terms of committed petrochemicals investments (Saadi 2020).
Mills (2020a) points out that the Gulf has developed a large basic chemical industry, mostly based on previously flared gas, and using methane and ethane as feedstocks to yield fertilizers, methanol, polyethylene and polypropylene. Currently, new petrochemical strategies focus on mega-scale integrated refining and petrochemical complexes. Such strategies are an important element for supporting local industries and diversification.
For example, Abu Dhabi’s ADNOC has decided a $45 billion plan to boost its refining capacity by 60% and more than triple its petrochemicals capacity by 2025—starting from a total refining capacity of 1.3 mb/d in 2019 (BP 2021). A number of the planned petrochemicals projects would use natural gas feedstock. In line with this plan, ADNOC is aggressively expanding the Ruwais downstream hub. ADNOC formed with ADQ the Ta’ziz JV to develop the Ruwais hub. In November 2020, the joint venture outlined plans for the $5 billion first phase of the Ruwais Derivatives Park that will be built near the existing downstream hub. This first investment is a key element of ADNOC’s $45 billion program to turn Ruwais into the world’s largest integrated refining and petrochemicals complex.
Qatar has also invested in the petrochemicals sector, with the contribution of international partnerships with IOCs (Cahill and Tsafors 2020). For example, in June 2019 Qatar Petroleum signed an agreement with Chevron Phillips Chemical to build one of the world’s largest ethane crackers in Qatar. The new petrochemical plant will be built in Ras Laffan Industrial City and will come online by 2025. The plant will include an ethane cracker with an annual ethylene capacity of about 1.9 Mt, increasing Qatar’s polyethylene output capacity by 82% (Reuters 2019). The QP-Chevron partnership did not end with this project, reaching an agreement shortly after on an $8 billion petrochemicals complex in the US: the US Gulf Coast II Petrochemical Project (Al Jazeera 2019).
The strong focus on a more integrated strategy in the region was highlighted when Saudi Aramco announced the acquisition of a 70% stake in Sabic in July 2020. That decision was a key element of its long-term downstream strategy to expand its refining and petrochemicals capacity as well as to generate more value from their existing production. In line with this strategy, the two companies planned to build a $20 billion integrated crude-to-chemicals project at Yanbu, located on Saudi Arabia’s west coast. Aramco and Sabic signed a preliminary agreement for the project in 2017. The plant would process 400,000 b/d of crude to produce some 9 Mtpa of chemicals and base oils (Argus Media 2020a). However, the project also represents a major setback in Saudi Aramco’s petrochemical ambition. Following the economic crisis in 2020, the two companies decided to reassess the project. As an alternative, the companies are considering the integration of Saudi Aramco’s existing refineries in Yanbu with a mixed feed steam cracker and downstream olefin derivative units. Moreover, Saudi Arabia invested heavily into the 400,000 b/d Jizan, or Jazan, refinery in the south of the country. The plant is linked to a petrochemical facility.
Egypt is focusing on two integrated projects. The $8.5 billion complex in Al Alamein, which includes a 2.5 Mt/year crude and condensate refinery, is expected to be completed by 2024. The project should meet local demand and could also export products. The other project is located in the Suez Canal Economic Zone. The $6.2 billion project is expected to produce up to 1.9 Mt/y of petrochemicals and up to 900,000 Mt/y of refined products. The project would import crude to be processed into petrochemical and refined products. These two projects are part of a $19 billion investment plan in 11 projects, highlighting Egypt’s ambitions to reduce its dependence on refined products imports by 2023. In 2019, Egypt imported nearly a third of its oil products consumption (30.2 Mt/y) at a cost of $6.8 billion (Saadi 2020).
MENA NOCs have also evaluated opportunities in the downstream sector abroad. The overseas investments allow NOCs to guarantee a stable channel for their crude, mostly in Asia (e.g. India and China). For example, Saudi Arabia and the UAE are increasingly looking for opportunities in India, which is expected to be a growing energy market with ambitious petrochemical plans for the medium and long-term. In 2018 Aramco and ADNOC agreed to 25% of India’s $70 billion 1.2 mn b/d refining and 18 Mtpa integrated petrochemicals JV project at Raigad. However, the project has suffered from serious delays. Costs have been soaring drastically and the planned completion was postponed, even before the COVID-19 outbreak, from 2023 to 2025. Aramco is also planning to invest $15 billion for 20% of the refining and petrochemicals business of India’s Reliance Industries, although with slow progress. The other major market is China, where Saudi Aramco has also tried to expand its downstream foothold with two preliminary agreements. It signed with Zheijan Petrochemical for 9% of the Zhoushan refining and petrochemicals complex south of Shanghai; and for 35% of Norinco’s complex at Panjin in the northeastern Lioning province. However, COVID-19 challenged also these projects. Saudi Aramco withdrew from the $10 billion project for the refining and petrochemicals complex in the northeastern Lioning province (ArgusMedia 2021). Nonetheless, the strategic goal is to create new business opportunities to ensure demand, and future projects may be signed depending on the evolution of oil prices and demand forecasts. Saudi Arabia and the UAE have key advantages over other current top suppliers, notably Iraq, which faces deep-rooted economic challenges that undermine its ability to carry out such strategy and investment.
The enhanced value generation involves also ‘in-country value (ICV) creation’, which is the attempt to improve the capacity of local firms or joint ventures to supply the domestic oil industry with equipment (Mills 2020a). One of its goals is to eventually produce internationally competitive oil services and engineering firms.
MENA oil and gas producers are looking at Norway as an example in ICV creation. Indeed, Norway was one of the first countries that devoted efforts to increasing value in its local supply chain. Seeing benefits from foreign investment in its resources, Norway set a series of policies to bolster ICV, such as requiring usage of local suppliers in procurement activities; mandating IOCs to enter into joint R&D agreements with Norwegian research institutes; and obligating IOCs to enter into training agreements in order to improve human capital and to recruit a specific share of Norwegian employees in projects.
ICV seeks to maximize the procurement of local goods and services as well as to improve the capacity and capability of MENA people and companies in order to secure sustainable commercial benefits for the regional countries. In doing so, MENA oil and gas producers could boost skills development and create high-skilled jobs for their citizens instead of hiring expatriates. Oman has implemented an important ICV strategy, while also ANDOC announced its effort to create ICV in the next years. Mills (2020a) warns of the collateral and negative effects of localization and protectionism that could result in higher production costs.
It is reasonable to believe that the oil and gas sector will remain dominant in the MENA countries’ economies in the years ahead. Renewables may replace hydrocarbon resources in the domestic energy mix, but not in the government budgets, because investment in renewables does not generate the high returns that the oil and gas industry does.
Fattouh and Poudineh (2020) claim that MENA oil and gas exporters could pursue a strategy that focuses on their competitive advantage and increases their resilience. This strategy is called conservative bet-hedging strategy, which in other words means that ‘a bird in the hand is worth two in the bush’. The core of this strategy is to enhance the competitiveness of the energy sector and increase its resilience against potential risks of disruption due to the energy transition.
The extraction and export of hydrocarbons is the core sector of these economies. It provides high return, but it faces high risk due to oil price volatility and potential change in demand patterns. MENA oil producers could thus adopt such a strategy to defend their economies from the risks of revenue disruptions. According to Fattouh and Poudineh (2020), MENA oil exporters could implement a set of key measures:
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Decarbonizing oil and gas production as it may become a new source of comparative advantage in a world of rising carbon prices and climate policies;
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Strengthening the sector’s cost efficiency to make it more competitive in a tough environment;
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Decarbonizing final petroleum products to ensure greater acceptance and demand for key products as the transition towards decarbonized sources of energy accelerates;
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Moving downward the value chain and producing decarbonized final products (e.g. steel and aluminum) through the use of clean hydrogen.
2.5 Low-Production Costs and Carbon Intensity Rate
The lowest-cost producers, the frontrunners of which are Saudi Arabia, the UAE, Kuwait and Iraq, will be able to keep selling their oil the longest. This position guarantees important competitive advantages to most MENA oil and gas producers vis-à-vis other global hydrocarbon producers. They have some of the lowest production costs and vast hydrocarbon reserves. Qatar has the world’s cheapest production cost in the LNG. The co-production of associated natural gas liquids (condensates and liquefied petroleum gas) made the North Field exploitation very lucrative. However, the Qatari LNG expansion would be the cheapest new LNG supply, even if the associated natural gas liquids may become less abundant in this development. However, MENA oil and gas producers must take into account their social costs. Due to their rentier state structure, their lowest production costs are markedly inferior to their socioeconomic costs. Their social costs are represented by the breakeven fiscal oil price (Fig. 2.1 in Chap. 2, Sect. 2.1), which suffers from price volatility.
Low-cost oil producers cannot sustainably seek to gain market shares by adopting a higher volume/lower price strategy if this strategy requires selling their products below their production plus social costs (Fattouh 2021). This would be the case, because pursuing such a strategy would induce a reaction from other OPEC producers, further depressing oil prices and harming macroeconomic and fiscal sustainability for MENA oil and gas producers. In such a scenario, there is no (or little) room for cooperation among producers. This is particularly true for those economies that lack an economic and fiscal diversification. The more MENA oil and gas producers are dependent on oil rents, the less a higher volume/lower price strategy would be bearable, especially in the short and medium term. In the longer run, a higher volume/lower price strategy could guarantee higher revenues for MENA oil and gas producers if higher-cost producers are driven out of the market. On the other hand, those MENA countries that fail to adapt and adjust their economies to a tighter revenues scenario, may face serious problems. They would ultimately be deeply affected both in terms of social and political stability as well as economic sustainability. The domestic instability could not only prevent these producers from maximizing their reserves, but also from potentially maintaining their oil capacity. In that case some major producers (namely Saudi Arabia) could decide to pursue a high-volume-market share strategy in the next decades (Fattouh 2021). In short, MENA oil and gas producers should first reduce their social costs of production, diminishing their dependence on hydrocarbon revenues, and then fully benefit from their lowest production costs without hindering their fiscal and macroeconomic outlooks.
Thus, low-production costs are only one part of the equation in evaluating the best strategy. Another crucial issue will be the carbon intensity of the oil and gas production. Even if MENA oil and gas producers manage to secure and defend their market share, and to maximize their product value, their products would still face climate issues. Production, transportation and use of oil and gas still produce carbon emissions. On this issue, some MENA oil and gas producers are well positioned, having the lowest production carbon intensity, which is set to become more relevant in a high-carbon prices scenario. At low levels of carbon prices, differences in carbon intensity have a relatively low impact on overall costs and competitiveness. Saudi Arabia and the UAE have one of the lowest carbon intensity rates in the world (as shown in Fig. 6.10). Saudi Arabia is committed to further improving this condition. Saudi Aramco announced that it aims to reduce its upstream carbon intensity by 15% by 2035 against a 2018 baseline (Aramco 2022). On the other hand, other MENA oil producers, such as Algeria and Iraq, have higher carbon intensity rates, which could harm their competitiveness in the future energy system.
The Saudi, Qatari and Emirati lower carbon intensity is due to a combination of the nature of their reserve base and their heavy investment in infrastructure and technology. For example, Saudi Arabia—via its NOC Aramco—is the most advanced in thinking about demand defense in terms of climate compatibility (Mills 2020b) through significant investment in R&D. Moreover, Saudi Arabia has very low gas flaring rates per barrel and low water volume per unit of oil produced. According to World Bank data, Saudi Arabia has one of the lowest gas flaring rates per barrel of oil produced thanks to the implementation of major projects to mitigate routine gas flaring across its oil and gas value chain. Gas flaring is one of the main causes of the high carbon intensity rate of crude production. This is why Algeria, Iraq and Iran are considered to have higher carbon intensity. However, the issue is far more serious in Iraq compared to Russia and the US in relative terms to total gas production (Fig. 6.11).
Source Authors’ elaboration on World Bank data
Gas flaring in 2019, (bcm).
Saudi Aramco prioritizes the reduction, reuse, recycle and removal of GHG emissions to harness its Circular Carbon Economy framework. Therefore, it announced that it aims to achieve emissions reduction and mitigation by 2035 through: renewable investment that will reduce 14 million metric tons of CO2e annually (MtCO2e/y); investing in CCUS for a reduction of 11 MtCO2e/y; improving energy efficiency to reduce 11 MtCO2e/y; reducing methane and flaring to cut 1 MtCO2e/y; and other offsets to mitigate 16 MtCO2e/y.
All these factors (low flaring, reducing methane leakage, improving energy efficiency of operations and inherent advantages such as prolific reservoirs and limited water cut) contribute to the greater competitive advantage of Saudi Arabia, Qatar and the UAE. The carbon intensity rate issue of oil and gas is expected to become a more decisive factor in a world of rising carbon prices and carbon border taxes, and is destined to become a key factor of the competitiveness of oil and gas producers.
A crucial issue is if the carbon intensity of different crudes and condensates can be reduced and at what cost. Electrification (via renewables) may offer some carbon intensity reduction to operational emissions at relatively little cost—especially in MENA countries. However, differences in carbon intensity may persist in the future. Similar issues also apply to natural gas supplies. In addition to the production side, carbon intensity also depends on the export mode (pipeline or LNG: the liquefaction process, for instance, has a very high self-consumption of 10–12%).
Concerning gas exporters, in November 2020 Qatar Petroleum signed a historic deal to supply Singapore’s Pavilion Energy with up to 1.8 Mt per year of LNG for 10 years from 2023. Besides marking the launch of QP’s new dedicated LNG trading arm (QP Trading), the deal is more meaningful because each delivered cargo will be accompanied by a statement of its GHG emissions measured from well to discharge port (MEES 2020a). Even if it is not a common, binding methodology, it represents a key opportunity for the world’s top LNG exporter to sell low-carbon LNG. QP aims at providing a reasonable methodology for its product, which could be a competitive advantage and a marketing tool within the energy transition.
IOCs have been setting several targets to reduce their carbon dioxide emissions pushed by governments, consumers and stakeholders. European companies, such as Total, BP, Eni, Shell and Equinor, have become leaders in this process, while US companies, like ExxonMobil and Chevron, have been more skeptical—even though higher investors’ pressure has recently led to some developments also in the US. Companies can target both emissions within their own boundaries (direct, Scope 1, and indirect, Scope 2) and those associated with the intended use of their products (Scope 3). Emissions are categorized as Scope 1, 2 and 3. Scope 1 covers “direct emissions” from sources owned or controlled by a company; Scope 2 covers emissions from the transformation of energy purchased by a company, such as electricity or heat; and Scope 3 consists of all other indirect GHG emissions as a result of a company’s activities from sources not owned or controlled by the company and the entire value chain. As public and political pressure grows, IOCs are increasingly considering to address also Scope 3. However, IOCs are only one factor in the fossil fuels industry; national oil companies produce 55% of the world’s oil and gas. Thus, NOCs are also expected to be under greater scrutiny in the foreseeable future.
To respond to such a scrutiny and strengthen their existing advantage, major Gulf NOCs (Saudi Aramco, ADNOC and QP) have launched large carbon capture and storage (CCS) facilities. CCS could contribute to injecting carbon dioxide from gas processing or industrial facilities into underground reservoirs for safe disposal or enhanced oil recovery (EOR). For example, Qatar Petroleum has set several targets to position itself as a leader in the decarbonization of the LNG value chain: reducing the emissions intensity of LNG facilities by 25%; installing Carbon Capture and Storage (CCS) facilities with a capacity of more than 7 Mtpa; eliminating routine flaring by 2030; setting a methane intensity target of 0.2% across all facilities by 2025. Moreover, it set a new target to reduce flare intensity across upstream facilities by more than 75% from the 2013 level (MEES 2021a). In line with these strategies, some MENA NOCs are also members or considering becoming members of international fora, such as the Oil and Gas Climate Initiative (OGCI), as is the case of Aramco, along with leading international oil companies such as Chevron, ExxonMobil, BP, Total, Shell, ENI, Equinor and Occidental.
3 Key Domestic Factors Determining the Future Geopolitical Role of MENA Countries
The energy transition (and the consequent peak in oil demand) urges MENA countries to rethink their socioeconomic model, which depends heavily on oil rents. These rents are the core of the social contract across the region as shown in Chap. 2. Therefore, domestic factors—along with the international factors—will be a key part of the future transformation of these countries, and will determine their future geopolitical trajectory. While international factors are mainly related to oil and gas exporting countries, domestic factors are valid for all MENA countries—including hydrocarbon importing countries—as all of them could exploit their vast renewable energy potential.
Demography, financial reserves and strong governance are the main factors that will determine the ability to adapt and adjust the domestic sphere to the forthcoming transformation. Demographic growth is particularly relevant in the MENA region, where governments have created a socioeconomic and political model based on the allocation of resources. The growing population may hinder the ability of MENA governments to implement diversification, producing domestic and geopolitical risks.
3.1 Population Growth Outlook
Demography cannot be ignored in a geopolitical analysis, as it is a powerful element in the geopolitical destiny of a country. While it provides the necessary human capital to succeed and transform each country into a relevant geopolitical power, a growing and young population can also be a risk if not properly handled. This is especially true in many MENA hydrocarbon producing countries, given the peculiar relation between population, ruling class and oil rents, where the allocation of resources is a key pillar of domestic stability, but even more so in net-hydrocarbon importing countries that do not have oil rents, but still need to find employment for their people.
The MENA region has one of the world’s fastest growing populations in the world. In 2000, the region comprised 296 million inhabitants. Between 2000 and 2020, around 136 million people were added, almost the same figure (+125 million) is expected to be added in the next two decades (2020–2040). The region experienced an average population growth of around 2% per year over the last two decades, compared to the world’s annual average of 1.3% (UNICEF 2019). Currently, the rate in MENA countries is of about 1.7% per year and is expected to decline to about 1.3% around 2030, reaching about 0.8% per year by mid-century (Idem). Despite slowing growth rates, MENA’s population is expected to more than double in size during the first half of the XXI century, passing from around 296 million in 2000 to 650 million in 2060 according to the United Nations median population scenario (Fig. 6.12).
Source Authors’ elaboration on UN DESA data
Population growth in the largest populated countries and total MENA region (2000–2060), million.
As with other issues, the region is far from being a homogenous group also in terms of demographic trends. Albeit the general increasing trend, the rate at which the population grows varies considerably from one country to another. At the national level, all MENA countries—with the only exception of Lebanon—are expected to see increases in their total population in the coming decades. Figure 6.13 shows the net addition of total population for all MENA countries in the period 2020–2060 according to the United Nations median population scenario, and illustrates the astonishing growth in countries like Egypt, Iraq, Iran and Algeria. The largest population increase in absolute terms is expected to be seen in Egypt, with an additional 75 million by 2060 bringing the total to 177.5 million, followed by Iraq with an additional 40 million, bringing the total population to 80 million, and Algeria with an additional 21 million bringing the total to 65 million, over the same period. By contrast, according to the same source, Lebanon is expected see its population decrease by more than 200,000 people.
Source Authors’ elaboration on UN DESA data
Net addition of total population in the MENA countries 2020–2060, millions.
Demography is a particularly important feature of future geopolitical influence for MENA oil and gas producers. Should demographic growth offset economic growth, it could determine domestic unrest and socioeconomic instability, which may in turn pose a threat to critical operations in the domestic hydrocarbon industry. Population growth influences per capita income and patterns of employment. Two of the largest producers, Iraq and Saudi Arabia, are expected to see an important population growth, +20 million and +7.7 million by 2040, respectively. Consequently, they could see a decline in net income from oil rents, calculated on a per-capita basis. By contrast, for producers with relatively small populations (e.g. UAE, Qatar and Kuwait) this is less of a concern. On the other hand, hydrocarbon-poor countries are expected to face challenges too. Indeed, oil exporting countries may further reduce the distribution of oil rents in the region prioritizing the domestic dimension of the distribution, as occurred in the second oil cycle, undermining the region’s stability due to the widespread rentier mentality.
Given the high fertility rate, a large portion of the MENA population is extremely young (Fig. 6.14). In the years ahead, this proportion of population will need to find a job, thus stressing the MENA governments’ ability to create adequate and sufficient jobs for their citizens. The energy transition may represent a positive opportunity in this sense both for hydrocarbon-rich and -poor countries given their renewable potential.
Source Authors’ elaborations on UN DESA data
MENA population by selected age groups.
On this issue, population growth is expected to stress the weaknesses of the current socioeconomic model. A large number of young citizens will likely enter the domestic labor markets in the next decades, urging producers like Saudi Arabia and Iraq to diversify their economies and create new job opportunities. It has often been observed in the last decades that MENA producers have failed to foster private sector job creation for their young women and men, while significantly expanding public sector employment. If, on the other hand, these countries are able to diversify and create productive job opportunities, the increasingly larger workforce available (Fig. 6.14) should constitute a formidable driver for growth.
However, the lack of reforms could spark economic and political instability, resulting in a threat to the states. The 2011 Arab Spring embodies this fundamental challenge. Low living standards and lack of job opportunities were among the primary drivers of the uprisings that spread across the region in 2011. Long-lasting regimes were toppled, especially in North African countries, while others were torn apart by civil wars. In this general phenomenon demography played a significant role. Producers will thus need to diversify their economies, create job opportunities for their young populations and find new sources of revenues. Otherwise, they could see their geopolitical influence deeply affected by domestic instability.
3.2 Governing and Financing the Transformation
Given the urgency of reforms, another key factor in determining the future geoeconomic and geopolitical trajectories of MENA oil and gas producers, but also oil and gas importers, is the ability to govern the transformation. With some differences, MENA countries have launched diversification strategies, although the ability and strength to implement such strategies diverge significantly by country. Countries that are experiencing major domestic turmoil may not be able to pursue and implement the strategies required to position themselves in the forthcoming geopolitical map, and to adapt and adjust to the changing energy landscape.
Driven by their growing, young populations, governments will need to change their socioeconomic model and energy policies in order to navigate the new energy world. They will need the ability to govern and implement such transformations. Those countries that are experiencing major domestic turmoil may lag behind in the transition. For example, countries like Algeria, Libya, Iraq, Tunisia and Lebanon face significant domestic instability at different levels. These countries may be tempted to focus their energy policies on the maximization of their reserves, rather than addressing the reforms that will be needed to preserve geoeconomic and geopolitical influence.
Libya has been torn by the civil war since 2011. The inability to create a stable unity among different local groups undermines the possibility to implement some adjustments to the country’s hydrocarbon sector. Currently, local—along with external—players are more focused on gaining control over the country rather than on transforming the oil sector and the country’s economy. Moreover, hydrocarbon reserves are seen as a powerful political tool to gain political support and collect revenues, undermining political solutions.
In 2019–2020 Algeria has experienced unprecedented social unrest since the end of the civil war. The country has been a pillar of European energy security; however, its soaring domestic consumption is increasingly eroding gas export volumes, which are vital for the government’s coffers. Further potential social unrest may undermine the ability to implement key legal, fiscal and economic reforms undermines Algeria’s oil and gas industry.
Due to decades of political, economic and security shocks, Iraq is extremely fragile. It is one of the most oil-dependent countries in the world. According to the World Bank (2020), oil accounted for over 96% of exports, 92% of government budget revenues and 43% of GDP in 2019. Its energy and economic policies could be deeply affected by the continuous social unrest and negative economic outlook. Baghdad may focus on alleviating socioeconomic sufferings in the short-term without taking into consideration longer-term consequences.
Social and political instability are particularly common in hydrocarbon-poor countries, like Tunisia and Lebanon. Weak governance and inability to implement reforms may further undermine investment in the green transition exacerbating the fundamental weaknesses of their energy and economic systems (Fig. 6.15).
Source Authors’ elaboration on IRENA (2019)
The relative preparedness of MENA fossil fuel producing countries for the energy transition. Note The chart includes countries in which fossil fuel rents account for more than 5% of GDP. The GDP of Syria dates from 2010.
Another key factor is the ability of MENA countries (including oil and gas producers) to finance the transformation, while reducing the short-term negative economic effects of the clean energy transition. In this effort, countries with large foreign exchange reserves are better equipped to offset negative economic consequences in the short term, while financing economic transformation for the next generations (Fig. 6.16).
Source Authors’ elaboration on World Bank data
Total reserves* in selected MENA oil and gas producers, (current US$ billion). *gold is included. Note Total reserves comprise holdings of monetary gold, special drawing rights, reserves of IMF members held by the IMF, and holdings of foreign exchange under the control of monetary authorities.
MENA oil and gas producers have large foreign reserves, supported by other considerable assets that allow these countries to resist the economic crisis caused by decreasing oil prices and/or volumes. MENA oil and gas producers have withdrawn capital from their foreign reserves during previous oil price crises in order to alleviate the negative economic consequences and appease their citizens. Countries with low levels of reserves (and higher debt levels) are in a more vulnerable position to preserve their geopolitical role, potentially representing a greater geopolitical risk. Since renewables projects entail high CAPEX (yet low OPEX), importing countries with few financial reserves will need to rely more on external investors than exporting countries. To attract the required investments, importing countries will have to put in place favorable conditions and stable regulatory frameworks, removing market and infrastructure barriers.
Some countries have been able to build significant reserves during the past years, despite previous oil price shocks. Thanks to their larger reserves, the UAE, Qatar and Kuwait are in a better position to weather potential economic and fiscal crises due to the expected reduction of the world’s oil demand. Other countries have seen their reserves decline in the last years of low oil prices, notably Saudi Arabia and Algeria. Despite this common negative trend, the two countries have different outlooks. Algeria’s reserves have steadily declined since the 2014 oil price collapse due to poor economic management and failure to reform (EIU 2020), while Saudi Arabia still has a large amount of foreign exchange reserves, along with its sovereign wealth fund (SWF), to invest and offset negative economic downturns.
SWFs are another key element of a country’s ability to finance the transformation and to weather negative effects. During the previous high oil prices periods, the prevalent approach of these funds was to accumulate wealth with the specific goal to safeguard the economic future in these countries. They usually serve as long-term investment vehicles aiming to provide economic stability during commodities price volatility. The UAE, Kuwait, Qatar, and Saudi Arabia have among the largest SWFs in the region, as Fig. 6.17 shows. Recently, the SWF of UAE has surpassed Norway’s SWF, which is traditionally the world’s largest.
Source Authors’ elaboration on Bortolotti et al. (2020)
Sovereign Wealth Funds assets under management in the MENA region, (US$ billion).
Given their size, some of these funds can play a critical role in economic diversification efforts. MENA oil and gas producers may decide to use their accumulated wealth more actively to foster economic diversification, while investing on strategies to maintain their oil and gas sector competitive. However, SWFs in some countries are facing withdrawals or increased dividend distributions to fund their respective governments (Bortolotti et al. 2020). In consideration of the growing drawdowns in foreign exchange reserves and SWF assets, the IMF forecasts that financial wealth in the GCC could be depleted by 2035, with significant differences across the six nations (Bortolotti et al. 2020).
In conclusion, Qatar and the UAE are expected to be the best positioned countries given their larger financial buffers, while Algeria, Bahrain and Oman are in a weaker position (S&P Global Platts 2020a).
4 Energy Opportunities and Strategies for a Future Geopolitical Role of MENA Countries
4.1 Energy Transition in the Domestic Energy Sector: Natural Gas and RES
MENA oil and gas producers have announced major diversification strategies, aiming at adjusting and adapting their domestic energy markets, which are characterized by a soaring energy demand and a high dependence on fossil fuels.
The high dependence on fossil fuels of MENA oil exporters’ domestic energy markets poses an economic threat to their public finance. Growing domestic consumption erodes fossil fuels export volumes and hence the primary source of revenues. MENA oil exporters may therefore decide to invest in renewable energy capacity and free exports of hydrocarbons to address the government’s revenue maximization objective. The cases of Algeria and Saudi Arabia are quite illustrative, with a growing domestic energy consumption that has progressively reduced the availability of oil and gas exports directed to more lucrative markets. MENA oil importers may benefit from higher renewable capacity by reducing their import needs and consequently import expenditures. Thus, MENA countries have also developed ambitious plans to increase natural gas and renewables in the power generation mix, aiming also at reducing liquid burn in the power sector as is the case of Saudi Arabia.
In order to satisfy their growing domestic energy demand, MENA oil producers have considered the development of their domestic natural gas resources to increase the natural gas share in their energy mix. Traditionally, natural gas was considered a by-product of associated oil fields. With few exceptions (i.e. Algeria, Qatar and Egypt), MENA countries have not invested in non-associated natural gas fields, which are indeed relatively underdeveloped. The use of natural gas could allow MENA countries to develop a more diversified energy mix. Indeed, the use of associated gas in the power sector faces challenges especially under coordinated curbs on oil output, which consequently reduce gas output. Fattouh (2021) highlights the fact that the new increments of gas supplies in Saudi Arabia have reduced the volume and share of crude burn in power generation and moderated the sharp swings in crude burn. The development of non-associated gas fields is essential at a time of OPEC production cuts that reduce associated gas output. For example, Saudi Arabia brought online a major new non-associated gas processing plan (the Fadhili facility) which has helped offset the associated decline. Saudi Aramco has thus focused on developing shale gas and offshore non-associated gas reserves, allowing the Kingdom to meet its demand and increase the flexibility of its oil policy. This is evidence of the strong integration between Saudi oil and gas policies (Fattouh 2021).
Some MENA countries have resorted to their domestic gas resources while others had to resort to gas imports. Some countries (i.e. Algeria, Qatar, Saudi Arabia, Iran and Egypt) have been able to exploit their resources with no gas imports (in the case of Algeria, Saudi Arabia and Qatar) or very limited ones (in the case of Iran). To meet their domestic consumption, other MENA countries need to rely on gas imports via both pipeline and LNG. It is the case of the UAE, which imports both pipelined gas via the Dolphin pipeline from Qatar and LNG through two FSRUs. The decision on the transportation mode depends on several factors, among which geopolitical and energy security concerns. Some MENA countries therefore decide to rely on LNG imports to meet their demand even though they have important gas producers nearby (i.e. Qatar and Iran for the Gulf countries and Algeria for North African countries). In 2009, Kuwait commenced the Mina Al Ahmadi FSRU, which was replaced in 2014 with the newly-built FSRU Golar Igloo that extended the nominal capacity to 5.8 Mtpa. In July 2021, Kuwait received its first LNG cargo at its new Al-Zour LNG import terminal. The Al-Zour plant will be the Middle East’s largest import terminal. The first phase of the project includes 11 Mtpa of regasification plant and four storage tanks of 225,000 m3 each, which could be doubled during the second phase allowing Kuwait to receive 22 Mtpa of LNG (Bloomberg 2020). In 2020, Kuwait signed a 15-year agreement with Sheel and Mitsui to secure a total of 8 bcm/y of LNG until 2035 and another set of contracts with QP and Qatargas running from 2022 to 2037 for 8 bcm/year. In January 2020, Bahrain completed the construction of its first LNG import terminal—the 6.1 Mtpa Hidd terminal—following some delays. Also, Saudi Arabia is evaluating importing LNG on its western coast. This decision came with Saudi Aramco’s international presence: in 2019 Saudi Aramco signed a preliminary agreement with Sempra which called for Aramco to take a 25% stake in the US Port Arthur LNG project and offtake 5 Mtpa of supply from the terminal. However, Saudi Aramco and Sempra mutually agreed to let their 2019 agreement expire in 2021. In North Africa, Morocco has evaluated increasing its gas share as a way to reduce its dependence on coal-fired power generation and on its neighboring country, Algeria. Morocco is thus considering importing LNG through an FSRU that would allow it to import 1.1 bcm by 2025, 1.7 bcm in 2030 and 3 bcm in 2040.
Natural gas will also represent a way of diversifying oil-based economies. Natural gas provides feedstock for value-added industries such as petrochemicals, monetizing gas reserves and extracting more value from their hydrocarbon resources. Some MENA countries have declared ambitious development plans for their natural gas reserves, in particularly unconventional and non-associated gas. The region holds important unconventional resources, for example in Algeria’s Ghadames and Timimoun basins and in Saudi Arabia’s Jafurah basin, the offshore Khalij al-Bahrain area, both onshore and offshore in the UAE (e.g. Jebel Ali find) as well as Oman.
Saudi Aramco has identified the expansion of its gas production as one of its main strategic goals. The country aims to double its gas production capacity in ten years to more than 200 bcm/year in 2025. The unconventional gas reserves are a pillar of this goal. Back in 2013 Saudi Aramco identified three major shale gas deposits: Turaif in the Northern Borders province, South Ghawar near the supergiant oilfield and the Jafurah Basin to the east of Gahwar. Turaif in the northwest region is the site of Saudi Arabia’s first ever unconventional gas production, having begun in 2018 at 55 mn cfd. A pillar of this goal is the development of the Jafurah Basin, among the largest shale gas resources in the world with 5664 bcm. Saudi Aramco envisaged a $110 billion investment plan for developing the field to reach a production of 63 mcm/d of gas (23 bcm/year) approximately 425 million cubic feet per day of ethane, and 550 thousand barrels per day (kb/d) of other natural gas liquids and condensates by 2036. Saudi Aramco is expecting to fund these expenses by selling stakes of the company. Its development will occur in stages. Jafurah will produce gas which will be primarily reserved for domestic use to meet future energy demand for power, water and petrochemical production. The Jurassic Tuwaiq Mountain formation is the primary target within Jafurah. Unconventional gas fields are major industrial projects. They could thus enable the growth of local small and medium enterprises, foster job creation and increase technical know-how, which would perfectly fit the goals of the Saudi Vision 2030.
Bahrain announced the discovery of the Khalij al-Bahrain tight oil reserves in 2019, with an estimated 80bn barrels of oil and 14 tcf gas in place. But the region’s leading unconventional player is Oman. BP brought the Ghazeer project online in October 2020. It is the second phase development of Block 61’s tight gas reserves, following the 2017 startup of 1 bcf/d Khazzan output. The Block 61 output should thus reach 1.5 Bcf/d. The Khazzan tight gas field is considered one of the largest unconventional gas developments outside North America. Initially, the gas from Khazzan was slated for domestic use to address the country’s gas deficit. However, the gas from Khazzan has been able to satisfy Oman’s domestic needs, leaving some available for export (Shabaneh and Al Suwailem 2020). Oman is also hoping to develop the Mabrouk North East field, which contains 4 tcf and was discovered in 2018. Domestic reforms and large unconventional reserves attracted international operators.
The UAE has decided to achieve gas self-sufficiency by 2030. The target is strongly motivated by the need to reduce its dependence on gas imports from Qatar via the Dolphin pipeline, as the contract expires by 2032. Energy security is still an important driver in this field. This is also the reason why LNG imports from Qatar to some Gulf countries appear to be challenged by political disagreements. The UAE is committed to reaching gas self-sufficiency through the development of several gas projects (unconventional, sour and offshore). Some of the key gas projects include the offshore Hail, Dalma, and Ghasha fields in the Ghasha concession and the Ruwais Diyab onshore project. In February 2020, ADNOC announced the discovery of a major gas field, the Jebel Ali, which comprises 80 tcf of gas.
Natural gas could play a greater role also in the Eastern Mediterranean, where countries are increasingly looking into natural gas for their domestic markets as well as export opportunities (see Chap. 5). Due to some economic and political challenges that prevent the region from becoming a gas export hub, the East Mediterranean producers could focus their efforts to find and create market share in the region as well as exporting LNG, which guarantees market flexibility. Natural gas could also enable some cooperation. Currently the three countries that are better positioned to become gas players in the area (Egypt, Israel and Cyprus) are expected to compete for the same regional markets. Due to market and size characteristics, this competition may hinder potential cooperation. Indeed, Jordan, Lebanon, Cyprus and Israel are small markets, while Egypt is largely self-sufficient, and Turkey and Syria are politically inaccessible to key regional gas producers—in particular Egypt and Israel. The better equipped are those producers that already have export infrastructure.
However, oil and gas producers in the region have traditionally been able to extract hydrocarbons at relatively cheap cost from onshore or shallow water offshore. Tapping their unconventional gas resources comes with some challenges, such as the vast amounts of water that are typically needed for fracking. To overcome this issue, Saudi Aramco is exploring using seawater for fracturing treatments. Moving to onshore or less easier reserves raises another key challenge for these projects, i.e. higher production costs compared to associated gas resources, which undermines a key driver for their development. Unconventional gas resources are often considered a vital feedstock for the petrochemicals sector, but higher costs would deprive Gulf countries of one of their most important advantages: cheap feedstock.
In the region, natural gas has experienced increasing competition from other generation options: RES, but lately also nuclear. Renewables could represent a competing alternative in the power sector mainly due to their declining costs and abundant potential in the region. Furthermore, they could fill the gap in those areas where gas delivery is uneconomical due to the lack of infrastructure. Meanwhile, some countries are evaluating other solutions, such as nuclear. This is the case of the UAE, which has inaugurated the first reactor of four at the Barakah nuclear plant—the Arab world’s first nuclear power plant—in August 2020. Once fully operational (expected around 2024), the Barakah plant will have a total capacity of 5.6 GW. For several years Saudi Arabia has declared its ambition to develop a nuclear sector. However, high upfront costs, technological challenges and geopolitical complications have halted Saudi and other regional countries’ ambitions. Nevertheless, there have been reports of some developments in the construction of a facility for the production of yellowcake from uranium ore mined in the Saudi northwestern region in collaboration with Chinese entities. This scenario, however, could attract further US criticism, as US-China competition is escalating.
Both exporting and importing countries in the MENA region have set numerous RES targets (see Chap. 4) in order to meet both internal and external pressures. The development of RES could also help MENA countries to maximize their revenues in the short term, freeing hydrocarbon export volumes for exporters, while reducing fossil fuels imports for importers and cutting the import bill. Despite the great potential, energy diversification towards renewable energy sources is not expected to contribute to the fiscal diversification in the long run, which is something much needed. The returns from investments in RES are not as high as those obtained from investments in the hydrocarbon sector.
MENA countries need to find solutions to remain geopolitically relevant, ensure future revenues, and reduce total emissions. Therefore, MENA oil and gas producers could decide to focus on decarbonizing products and replace oil exports with new, cleaner energy carriers, exploiting their strengths and competitive advantages (next section). This solution becomes feasible also for importers as they share similar renewable potential with exporting countries. To exploit this potential, the domestic factors analyzed in the previous pages become crucial.
4.2 Decarbonized Products: Electricity and Hydrogen
Even before considering the export of decarbonized products, MENA oil and gas producers have considered the possibility of using their high renewable energy potential, mostly solar, as an alternative tool to remain geopolitically influent in a low-carbon future. This option has also been taken into consideration by MENA hydrocarbon-poor countries as they could benefit both economically and geopolitically. MENA countries could decide to increase the role of RES domestically, and to export part of their clean electricity. This decision would allow them to position themselves in the new geopolitical map of the energy transition, and to collect alternative revenues.
The idea of producing clean energy in the MENA region and exporting it to the European markets goes back to the 2000s with the launch of several initiatives such as the Trans- Mediterranean Renewable Energy Cooperation (TREC) in 2003, the Desertec Foundation in 2009, and DII. This idea initially attracted a lot of interest in policymakers, industry and scholars. They stated that it could contribute to further integration between the two Mediterranean shores and the Middle East and Gulf countries. improving climate mitigation and enhancing energy security and economic prosperity. The idea was to seize the largely unused land of the MENA region and to exploit its favorable climatic conditions, making it an ideal location for renewable electricity production, and exporting part of this electricity to Europe. However, the ambition has so far failed to become reality. Indeed, the huge construction costs of such an electricity grid made electricity imports from North Africa uncompetitive, despite their lower production costs.
Currently, there is only one electricity interconnection between North and South Mediterranean countries, i.e. the two cables with a combined total transfer capacity of 1400 MW between Morocco and Spain. Until late 2018, subsea cables predominantly carried power from Spain to Morocco, but the direction has now reversed. Projects that will also connect Tunisia, Algeria, Libya and Egypt to the European grid have been under evaluation for many years. Their realization would enhance EU-MENA clean energy relations and ambitions. Moreover, as European countries are phasing out of coal, the EU may be interested in financing RES in those countries in order to prevent brown electricity imports and carbon leakage. In 2019, Egypt signed an agreement to create a 2 GW electricity interconnection (the 1.700 km long Euro-Africa interconnector) with Cyprus, Crete and mainland Greece (Tanchum 2020). The interconnection between Egypt and Cyprus should be commissioned in December 2022, while the Cyprus-Crete link will be operational in December 2023. In October 2021, the three countries signed a major agreement to link their electricity grids as a sign of the increasingly close and wide-ranging relations binding the three nations.
With an initial 1 GW subsea high-voltage direct current (HVDC) line, the EuroAfrica interconnector has a larger capacity compared to other EU-North African interconnectors. For example, in 2019, Tunisia and Italy signed an intergovernmental agreement for the development and joint construction of a 0.6 GW electricity interconnector (DW 2019). The ELMED interconnector was on the third list of EU Projects of Common Interest (PCI), which includes key infrastructure projects that can benefit from accelerated planning and permit granting.
As they increase the RES share in their domestic energy systems, MENA countries may need to increase the electricity trade among themselves. For example, Egypt could exploit its location and its ambitious RES plans. It already possesses interconnections with both Libya and Jordan (with a combined capacity of about 800 MW). Recently, it has worked with Saudi Arabia for the construction of a 3 GW electricity interconnection. The first 1.5 GW is expected to be operational in 2023 (Tanchum 2020).
Furthermore, Jordan is ready to connect its electricity grid to two of its neighbors (Saudi Arabia and Iraq) under separate deals. According to the MoU signed by the two countries, the integration with Saudi Arabia would allow both countries to supply each other as required through a 164 km electricity grid from North Western Saudi Arabia to East Amman (MEES 2020b). By contrast, the other deal aims to supply Jordan’s eastern neighbor. Iraq is looking to import up to 200 MW of electricity via the Jordan link, which would make Jordan a regional hub for energy exchange. Moreover, it would allow Saudi Arabia to increase its role in the weak Iraqi power sector, currently highly dependent on Iran.
Lately, MENA countries are considering another option to position themselves in the new energy geopolitical landscape: the production and export of hydrogen. In the last years, hydrogen has regained a strong political momentum, and a growing number of countries consider it a way to decarbonize hard-to-abate sectors. Many countries have announced, drafted or published national hydrogen strategies, and some European post-COVID recovery packages include support measures for clean hydrogen.
Given the great political support, hydrogen also revives the idea of connecting the MENA region to the global energy markets in the future clean energy system. MENA oil and gas producers could benefit from their renewable energy potential, vast hydrocarbon reserves as well as existing oil and gas infrastructure, allowing MENA countries to build a new geopolitical influence. Countries in the MENA area may decide to participate in the upcoming competition to become part of the global hydrogen supply side and major exporters, given their abundant renewable and CCS potential (Fig. 6.18). OPEC’s 2021 World Oil Outlook devotes considerable column inches to this fuel—much more than the 2020 edition did. The report assessed: “All six Gulf Cooperation Council (GCC) states have expressed interest in developing hydrogen production capacity. With their combination of low-cost gas resources and low-cost renewable energy, as well as other advantages, the Gulf states are strong candidates to emerge as major exporters of blue and green hydrogen. Saudi Aramco and ADNOC are making a push to do just that—positioning themselves to build upon their well-established and extensive energy ties with the Asia–Pacific region.” (OPEC 2021).
Source Noussan et al. (2021)
Comparison of selected countries based on green hydrogen domestic consumption and production potential.
Countries across the region have increasingly been working on their hydrogen ambitions, considering both blue and green hydrogen projects. Among them, four countries have announced major hydrogen plans. Three of them are oil exporters (Saudi Arabia, the UAE, and Oman) and one is a net importer (Morocco).
The Gulf countries have showed their interests on hydrogen—albeit some different intensity (Map 6.1). For example, Saudi Arabia has initiated major undertakings with no formal framework, while Oman is creating new structures and introducing various projects. The UAE has announced a policy framework and successfully realized its first ventures (Ansari 2022). On the other hand of the spectrum, Kuwait and Bahrain remain cautious, and Qatar prioritizes its LNG industry and blue hydrogen production abroad. There are some differences also regarding the hydrogen color: the UAE and Saudi Arabia are balancing between green and blue, while Oman is focusing on green and Qatar stays with blue.
Source Dawud Ansari (2022)
Gulf hydrogen projects.
In July 2020, Saudi Arabia revealed its green hydrogen ambition with the announcement of a joint-venture between Air Products, Saudi ACWA and Neom aimed at developing a $5 billion green hydrogen and green ammonia plant. It is expected to become the world’s largest project of green ammonia (producing 1.2 million tons per year) and green hydrogen (producing 650 tons/day, corresponding to 237,000 tons annually) (ACWA Power 2020). The project is expected to come online in 2025, and it will be supplied with energy through the integration of more than 4 GW of renewable power from solar and wind. The project is supported by the BMWi within the framework of the German National Hydrogen Strategy, a program to develop international energy cooperation. However, the project faces serious challenges from the announced renewable capacity to financial needs. In April 2021, ENEOS and Saudi Aramco signed an MoU to develop a blue hydrogen and blue ammonia supply chain connecting Japan and Saudi Arabia. Moreover, Saudi Altaaqa signed an MoU with AFC Energy to develop and use AFC Energy’s hydrogen fuel cell technology in Saudi Arabia and the Middle East (AFC Energy 2021).
The UAE has also started to evaluate potential hydrogen projects. At the beginning of 2021, three of Abu Dhabi’s biggest government-backed companies agreed to work together to position the UAE as an exporter of blue and green hydrogen. ADNOC, Mubadala and ADQ signed a MoU in January 2021 to establish the Abu Dhabi Hydrogen Alliance. The Alliance aims to develop a roadmap to accelerate the UAE’s adoption and use of green hydrogen domestically. Meanwhile, ANDOC will continue to develop blue hydrogen (Gulf Business 2021) using its gas and CCUS potential. Moreover, the state-owned Dubai Electricity and Water Authority (DEWA) is committed to developing a green hydrogen mobility project, which will benefit from the solar-driven electrolysis facility at the Mohammed bin Rashid Al Maktoum Solar Park. The solar park is expected to have an installed capacity of 5 GW by 2030 (Noussan et al. 2021). The UAE is confident that competitive prices from solar power generation will be an enabler to reduce green hydrogen prices (S&P Global Platts 2020b). On the other hand, Abu Dhabi, with its important hydrocarbon reserves, is more focused on blue rather than green hydrogen. This approach is mainly supported by the ADNOC CCUS capacity, a crucial element for the production of blue hydrogen. It currently stands at 800,000 t/y, captured from the Emirates Steel plant and injected into the Bab and Rumaitha fields. This figure is still modest, but ADNOC set the target of 5 million tons/year by 2030, which would allow ADNOC to produce blue hydrogen.
Oman is the third country in the Gulf that has been considering the potential use of hydrogen domestically. It announced the construction of a green hydrogen plant at the Duqm port. The hydrogen project is developed through a partnership between a Belgian consortium (DEME Concession and the Port of Antwerp) and Oman. The first phase is expected to have an electrolyser capacity between 250 and 500 MW. The facility will produce hydrogen for an export-focused refinery and a petrochemical facility which are being developed in that area. According to the partnership, the location in Duqm has some advantages, such as the availability of cheap renewable energy (solar and wind) as well as a large, accessible site (DEME 2020).
Saudi Arabia and the UAE in particular have the financial strength to boost hydrogen projects. These financial resources represent a competitive advantage if coupled with low-cost gas reserves and high levels of solar irradiation.
With large hydrocarbon and renewable potential, MENA countries could decide to produce and then export both blue and green hydrogen. However, despite the great solar and wind potential, the green hydrogen ambitions of MENA countries must address their high water scarcity rate, which will only worsen due to climate change in the next decades. Lack of water resources challenges the likelihood of becoming hydrogen champions. A potential solution would be developing hydrogen projects along with desalination plants, as Saudi does in Neom.
However, the expansion of desalination capacity for hydrogen production presents several challenges. First of all, desalination is an energy-intensive process. In fact, two-thirds of the water produced from seawater desalination in the region today is from fossil fuel-based thermal desalination (Walton 2019). The rest is produced from membrane-based desalination that relies heavily on electricity produced using natural gas. Desalination will thus increase energy demand and consumption, potentially eroding further oil and gas export volumes and government revenues. Secondly, because water is largely scarce in the MENA region, renewable hydrogen production would directly compete with other water-intense industries, such as agriculture (Pflugmann and De Blasio 2020). The low trade-off from funding such projects could determine a preference for blue hydrogen projects.
Moreover, MENA oil and gas producers will need to dramatically increase their renewable energy capacity, if they are committed to becoming major global green players. They will have to deploy a massive amount of renewables in order to both decarbonize their energy systems and export some clean energy volumes. However, these countries have been lagging behind their ambitious green targets in terms of installed renewable energy capacity.
Among the North African countries, Morocco is often seen as the potential future leading hydrogen producer and exporter. It does not hold significant hydrocarbon reserves, but it seeks to use its great solar and wind potential in order to develop green hydrogen. According to government estimates, it has a potential installed capacity of 20,000 GW of photovoltaic and 6500 MW of wind power, (Hydrogen Economist 2021). Moreover, Morocco set an ambitious renewable target of 52% of installed electricity capacity by 2030, which corresponds to around 11 GW of installed renewable power. Moroccan authorities have seen renewables and hydrogen as potential ways to decarbonize its energy mix, lessen its high import dependence and become an international clean energy player. The plan is to devote one-third of Morocco’s green hydrogen to the domestic market, while two-thirds to exports.
The region is expected to explore opportunities to enhance its geopolitical role in the upcoming energy landscape thanks to hydrogen. Some differences on potential export markets may appear between the two components of the area: North Africa and the Middle East. North Africa may be more interested in becoming a major clean hydrogen supplier to the European markets mainly because of their great energy potential and geographical vicinity. The Middle East, on the other side, may decide to export both green and blue hydrogen to Asia.
The EU has set ambitious decarbonization policies and key strategies, such as the EU Hydrogen Strategy, which also considers imports from southern Mediterranean countries. The EU Hydrogen Strategy envisages that 40 GW by 2030 would be imported from North African countries, especially Morocco.
Morocco—and other North African countries—could become key players in the export of green energies, exploiting their geographic position at the crossroads of Europe, the MENA region and Africa.
The EU Hydrogen Strategy explicitly stated that the EU’s top priority is green hydrogen; however, it accepts blue hydrogen in the short- and medium-term. North African countries could meet both these targets. The region has abundant renewable energy potential—notably solar and wind. In Morocco, Algeria and Egypt, certain land areas have wind speeds that are comparable to offshore conditions in the Mediterranean, Baltic Sea and some parts of the North Sea (Van Wijk and Wouters 2019). However, these countries could also take advantage of the existing gas infrastructure in order to export blue hydrogen in the short-term. Algeria and Libya could indeed benefit from their gas reserves and pipeline connections to Europe. Algeria sends its gas to Europe through its three pipelines: MedGaz to Spain, the Pedro Duran Farell pipeline via Morocco and the Enrico Mattei pipeline to Italy. Libya is connected to Italy through the Greenstream pipeline, while Algeria and Libya could use their existing gas infrastructure linked to Europe to supply hydrogen to the EU.
Algeria has started to reconsider hydrogen projects as Europe is committed to developing a hydrogen economy. It has more options to evaluate than Morocco and Tunisia, as it holds vast hydrocarbon resources and extensive experience with CO2 sequestration in geological structures, notably thanks to the In Salah project launched in 2004. The country, however, is not excluding the possibility to produce and export green hydrogen, but the success of green hydrogen production in Algeria crucially hinges on the significant expansion of its renewable energy production, which it so far lacks.
Algeria, however, is presently experiencing major domestic social unrest at different levels, and serious political and macroeconomic difficulties. Lack of strong governance and economic constraints hinder investment in hydrogen (and other diversification efforts). On the other hand, Libya is still suffering a civil war and lack of security on the ground. Until security is restored, a major transformation in Libya’s energy sector is unlikely to occur.
Morocco is deeply committed to devoting a large part of its green hydrogen to exports, using its section of the Maghreb-Europe gas pipeline. The long-term gas supply agreement is set to expire by November 2021, which may open new opportunities, as this pipeline could be converted and used for the export of green hydrogen blended with gas up to 15% (Dii Desert Energy 2020). Nonetheless, both Morocco and Tunisia, which could benefit from their vast renewable potential combined with their geographical proximity to Europe, do not own pipelines connected to Europe, and they would thus need to either build new pipelines or find an agreement with the owners.
Egypt has started to consider producing hydrogen thanks to its high renewable energy potential as well as natural gas reserves. Egypt’s Zaafarana region is comparable to Morocco’s Atlantic coast, with high and steady wind speeds. Additionally, Egypt could tap its offshore gas resources to produce also blue hydrogen. According to some studies, new hydrogen gas pipeline infrastructure could be built to transport hydrogen to Europe. The debate over the construction of the EastMed pipeline, which has gained relevance in the aftermath of the Russian war in Ukraine, could provide another potential avenue for hydrogen exports from the Eastern Mediterranean, as the gas pipeline is expected to be built hydrogen-ready.
By contrast, Gulf countries are currently considering the export of hydrogen to some Asian countries, given their geographical location and the growing economic and energy partnerships with Asia. However, Gulf countries face technological and economic challenges in hydrogen transportation, especially for the long-distance routes. Hydrogen transport in ships requires the highest possible energy density per unit of volume, to avoid excessive costs. Since hydrogen cannot be economically transported in ships in its gaseous form, other solutions are being considered. One viable option for exporting hydrogen is transporting it as ammonia over long-distance routes (Noussan et al. 2021). According to the IEA (2019), ammonia can be competitive if the end user can use it without the need for reconversion back to hydrogen. In that case, importing ammonia as electrolytic hydrogen from North Africa to Europe could be cheaper than producing it in Europe.
Some Asian countries are considering the import of ammonia. Japan, a leading hydrogen player, announced that ammonia will play an important role in Japan’s thermal power generation, as part of the Japanese efforts to reach carbon neutrality in 2050. In particular, Japan is committed to developing ammonia supply chains, and it is prioritizing the development of a supply chain for blue ammonia from natural gas rather than green ammonia (S&P Global Platts 2021). The Middle East is among the potential sources for Japan’s ammonia imports, and in September 2020 Saudi Arabia announced the world’s first shipment of 40 tonnes of blue ammonia to Japan. Despite the limited volume of the cargo, it shows that Saudi Arabia is increasingly considering opportunities in this direction.
However, global hydrogen trade will need to overcome serious logistic and economic challenges. The economics of intercontinental hydrogen ship transport will need to face lower volumetric energy densities in comparison with the current shipping of fossil fuels. Oil tankers, which are in some cases the largest ships in operation, can transport around 10.3 MWh of crude per each cubic meter of volume. LNG transport requires more space for the same energy content, since LNG has an energy density of 6.2 MWh per cubic meter. This figure is even worse for liquid hydrogen and ammonia, which have energy densities of 2.4 and 3.2 MWh per cubic meter respectively (Noussan et al. 2021). Moreover, liquid hydrogen will need to be kept at very low temperatures (i.e., around 20 K). This will require very high-quality insulation, and the energy losses during a long trip may be significant. Mitigation options are available, including the use of evaporated hydrogen to supply on-board power systems, and there is ongoing research on the possibility of applying them on large ships, although the evaporated hydrogen will need to be correctly removed to avoid safety issues.
In short, hydrogen is difficult and expensive to transport, and turning it into a more easily transportable non-carbon fuel entails further costs. Instead of focusing exclusively on hydrogen exports, MENA countries could develop clean hydrogen production in order to decarbonize their domestic heavy industries. It will always be more convenient to utilize renewable energy or blue/green hydrogen locally for the production of carbon-intensive intermediate or final products than to export hydrogen. In this way, MENA countries could overcome logistic and economic barriers and collect higher revenues, albeit lower compared to the oil and gas sector. Throughout the years, MENA countries have traditionally invested in carbon-intensive industries, such as steel, cement, aluminum and chemicals as well as fertilizers. The decision to decarbonize their domestic industrial output through hydrogen could protect a key economic/industrial pillar from potential and rising carbon prices at the borders of consuming countries. Moreover, it could become a competitive advantage vis-à-vis those industrial countries that do not hold hydrogen potential. MENA could also pursue an intermediate strategy, which consists in using hydrocarbons locally in energy-intensive transformations coupled with CCUS.
4.3 International Cooperation with Key Energy Geoeconomic Blocs
Both international and domestic factors will contribute to shaping the future role of MENA oil and gas producers within global energy geopolitics throughout the energy transition. Some consequences and anticipations of the future are already evident, and are expected to develop and grow during the next decades.
First, the energy transition may reaffirm the relevance of national oil companies (NOCs), especially those of the MENA oil and gas producers. NOCs currently hold most of the world’s oil and gas reserves (Figs. 6.19 and 6.20). Over the past years, international oil companies (IOCs) have been forced to restructure their business models, mainly due to the energy transition, climate targets, and political and investors pressure. IOCs have steadily reduced their investment plans and CAPEX due to low oil prices, which were further depressed in 2020 due to the Covid crisis. Oil and gas companies have cut their CAPEX by a combined 34% in 2020, slightly more than the initial 28% reduction following the price decline that started in 2014 (IEF and BCG 2020).
Moreover, Western IOCs are increasingly stating their commitment to the decarbonization effort. They are devoting growing funds to RES and low-carbon technologies. In 2020, eight energy companies have agreed to apply a common set of “energy transition principles” across their businesses, including a commitment to industry decarbonization. The eight companies comprise BP, Shell, Total, Eni, Equinor, Repsol, Galp and Occidental Petroleum (Argus Media 2020a, b). All these companies have announced major climate targets, albeit with some differences. BP, Shell, Total, Occidental, Equinor and Repsol have all committed to a net-zero emissions goal by 2050, while Eni has set a target of reducing net emissions by 80% over the same period. Galp aims at being carbon neutral in Europe by 2050 while intending to dedicate over 40% of its future investment to energy transition opportunities (Argus Media 2020b).
The intention of some of the major Western IOCs is to become integrated “energy” companies, such as claimed by BP’s latest strategy (BP 2020c). Within the new strategy, the British company announced major targets that will reshape its business as it pivots from being an IOC to an integrated energy company. The focus will thus shift from producing resources to delivering solutions for customers. To do so, BP aims to increase its annual low-carbon investment to around $5 billion a year (a tenfold increase). BP also announced the target to develop around 50 GW of net renewable generating capacity and, at the same time, a 40% reduction of its oil and gas production by 2030 (BP 2020c). The different approach between IOCs and NOCs towards decarbonization is driven by differences in the ownership of the oil and gas reserves. Moreover, IOCs usually need to respond to their shareholders, while NOCs need to respond to state needs.
Source Authors’ elaboration on IEA
Share of oil reserves, production and upstream investment by company type, 2018.
Source Authors’ elaboration on IEA
Share of natural gas reserves, production and upstream investment by company type, 2018.
Moreover, fossil fuels investments are increasingly under pressure. In its Roadmap, the IEA stated that there is no need for investments in new fossil fuel supplies beyond projects already committed as of 2021. However, lower CAPEX levels may hinder oil and gas market stability causing underinvestment, and thus future higher prices, especially without significant measures related to energy efficiency and the demand side. These CAPEX levels appear insufficient to deliver the volumes of oil and gas needed to maintain market stability. A CAPEX reduction due to COVID-19, combined with lower investments in the oil and gas sector pushed by the IOCs’ decarbonization targets, may result in higher prices. Industry CAPEX in 2020 has fallen to levels last seen in 2004, when prices were similar to today’s. Back then, low CAPEX and prices contributed to the rising cycle of oil prices, as Asian economic growth boosted demand. While oil demand in the longer run is expected to fall in line with net-zero targets, in the short- and medium-term lower investment may result in high price volatility due to tightness on the supply side. Indeed, the industry requires significant investments to compensate for production declines. IEA warns that, in the absence of investments, the rate at which production from existing fields declines is roughly 8% per year (IEA 2020d), which is greater than any plausible fall in global demand.
As of today, both the IEA and OPEC believe that by 2022 another 27 million to 30 million barrels of oil equivalent per day of capacity will be needed to close the gap between projected production declines and demand. This figure soars to 68–70 million boe/d by 2030 (Energy Intelligence 2021). Investment in existing and some new fields would be crucial to meet demand in the next years. Weak upstream investment could lead to a supply crunch in the oil markets. As investment falls and markets become increasingly competitive, MENA oil and gas producers may benefit from their low-production costs.
Periods of higher prices will inevitably occur due to under-investment, offering temporary relief to MENA oil and gas producers. However, higher prices/revenues, although temporary, could tempt some oil and gas producers into maximizing their resources, thus missing the opportunity to diversify their economy.
Furthermore, Russia’s war in Ukraine, and the consequent political and social pressure, has led to the alienation of Russian hydrocarbon sectors for the IOCs and investors. Several IOCs have announced their intention to withdraw from Russia’s oil and gas industry and to sell their assets; particularly relevant is BP’s decision to sell its stake of Rosneft. While in the long-run such political pressure could somehow fade away, in the short and medium-term the MENA upstream could benefit from this situation attracting IOCs thanks to its low-production costs and well-developed history of engagement with IOCs.
MENA oil and gas producers and exporters need to adapt to the energy transition, seeking new business models while implementing fiscal and economic diversification in order to navigate in the future energy geopolitics. Each producer could pursue two strategies: defense of market share and maximization of reserves value. However, these two strategies may still face some challenges in a more decarbonized world. To secure future and further financial revenues, MENA oil and gas exporters may focus on their competitive advantage and increase the resilience of their oil and gas sector.
It may be expected that MENA oil and gas producers will face lower oil revenues in the longer-run (with possibly some temporary increases of oil prices from time to time) and intense competition in a demand-constrained world. This world will be a ‘buyers’ market’ compared to the previous ‘sellers’ market’, such as during the last oil price cycle in the period 2000–2014. A major trend will be an ever-growing broad consensus on climate policies and the clean energy transition. However, such a broad consensus may not be translated into a homogenous landscape. Instead, fragmentation and regionalization may be two features of the next global energy system, driven by growing competition among major economic blocs (i.e. USA, Europe, and China). Diverging policies and technological pathways may result in the rise of different market places across the world.
Major consequences will also occur in the geoeconomic sphere, with a growing role of Asian countries. Their influence has been increasing since the 2000s along with the broader realignment of the world’s economic centers of gravity. The growing energy demand in Asia has already induced MENA oil and gas producing countries to increasingly focus on these markets to secure export markets and revenues.
Asian countries already import significant hydrocarbon volumes from the MENA oil and gas producers. By 2019, Asian buyers accounted for more than 80% of crude oil and condensates that passed from Gulf ports through the Straits of Hormuz. China (19%), India (16%), Japan (15%), and South Korea (13%) were the largest receivers of Gulf crude exports. If we compare it with the US (6%), the relevance of Gulf-Asian energy relations becomes clear. The same picture is for LNG. In 2019, China, South Korea and Japan were the largest LNG importers. The Asian energy markets are set to become the main area for LNG demand driven by high economic and demographic growth. Regional NOCs have increasingly looked into opportunities to secure and expand their market share in the growing Asian energy markets, considering also the refining and petrochemicals projects. Energy is still a central pillar of the MENA-Asia relations. Any variation of the energy landscape will also reverberate in the broader relations.
Asia–Pacific countries are expected to have fast-growing domestic economies and energy demand, which may prompt further geoeconomic shifts. Fast-growing Asian economies already played an important role in the economic recoveries of Gulf States following the 2008 financial crisis and the 2014 oil price collapse. The MENA countries and Asian countries have expanded their relations to multiple sectors. In a post-COVID-19 world, Asian countries may increase their economic relevance for MENA countries, which could increasingly look to Asia–Pacific countries as vital economic partners in their diversification efforts. MENA countries (especially Gulf countries) are considering Asian countries as major partners in key sectors, such as digital and trade, as the flourishing economic relations between the UAE and China show. China has connected part of its regional presence and policies to its ambitious Belt and Road Initiative (BRI). The UAE is often considered a pivotal pillar of China’s MENA policy. An example is the announcement of a $10 billion investment in May 2019 in the Khalifa Industrial Zone Abu Dhabi (KIZAD) by East Hope Group, one of China’s largest companies (Fulton 2019). Moreover, since 2015, Abu Dhabi has used renewals at its most important onshore and offshore oil concessions to bring in a greater diversity of partners and far more Asian companies (Cahill and Tsafos 2020). The first step in UAE’s upstream sector occurred with the establishment of the Al-Yasat JV (ADNOC 60%, CNPC 40%) to explore for oil. Production from the field started in March 2018. In 2017, the Chinese presence picked up considerably when CNPC bought 8% in the Adnoc Onshore concession for $1.77 billion (OGJ 2017). The concession has total resources of 20–30 billion boe, and production capacity stands at 2 mn b/d. In July 2020, China’s CNOOC became the third Chinese firm in Abu Dhabi’s upstream sector, when ADNOC agreed to the transfer of rights in two key offshore concessions from CNPC to CNOOC (Khaleej Times 2020). The two concessions are Lower Zakum and Umm Shaif and Nasr. CNOOC bought 4% of CNPC’s former 10% stakes. The latest transfer of concession rights reinforces the strong and bilateral ties between the UAE and China.
With the expansion in scope of Gulf-Asia relations and growing economic interests, Asian players were encouraged to take on a more active security role (Lons et al. 2020). Japan attempted to mediate with Iran at the height of tensions in the Gulf in 2019. In February 2020, Japan dispatched a warship and patrol planes to gather intelligence and protect Japanese ships in the international waters of the Arabian Sea, Bab el-Mandeb Strait and Gulf of Oman. This area is not far from where two Japanese oil tankers were attacked in June 2019 (Lons et al. 2020). However, it seems improbable that Asian countries or others will increase their stake in the security sphere or pick sides in regional disputes to a degree close to that of the US. For example, most of the countries maintained a discreet security profile in the broader region, engaging in specific issues such as counter-piracy naval patrols. Their activities are mainly focused on areas outside the Gulf and do not come close to approximating the network of US bases and force deployments in the area. Indeed, the US is still the major security player in the MENA region, especially in the Gulf. However, the Gulf countries are increasingly evaluating alternative security solutions, underpinned by perceptions that the US are less interested in being involved in their regional affairs. The JCPOA, signed without the direct involvement of the Gulf countries, sparked security concerns in these capitals. But even the Trump Administration failed to provide visible responses to the attacks on Gulf’s energy infrastructure (tankers and Saudi facilities), fostering the reassessment of the nature of the US security guarantee that they had until then taken for granted (Coates Ulrichsen 2020a). The more assertive foreign policies of these countries (e.g. in Syria and Yemen) is the result of such perceptions.
The US, however, is still the main player in the security sphere, with the highest number of troops in the region. However, since 2008, the US is less eager to be involved in regional affairs. This has ignited a steady process in the region, inducing the Gulf countries to consider changes in their foreign policy in order to prepare themselves to a less direct American involvement in the area. A major development is the normalization of relations between some Sunni countries and Israel. In August 2020, the UAE, Bahrain and Israel signed the so-called Abraham Accords. Some Arab countries had already engaged in cooperation before the inception of formal relations. For example, trade between the UAE and Israel has multiplied in recent years via intermediary companies, and it is mainly focused on agricultural and medical technologies as well as security and communication systems (Coates Ulrichsen 2020b).
However, the accord formalizes bilateral cooperation, especially on intelligence and security, which has strengthened in recent years, and it appears to be specifically designed to counter the growing influence of their common enemy, Iran. The agreement may enlarge the regional security architecture aimed at obstructing Iran’s proxies in the region. For this reason, Saudi Arabia is also considering the normalization and formalization of its relations with Israel. However, its leadership in the Islam world, as Custodians of the Two Holy Mosques (of Islam), may be an obstacle. The UAE has been freer to express and pursue closer ties than Saudi Arabia (Coates Ulrichsen 2020b).
Two other events emphasize the recent developments and the growing convergence between Arab countries and Israel. In July 2020, Chevron bought Noble Energy, a key player in the East Med gas saga and Israeli offshore operations. This marked the historical entry of an American oil major, Chevron, in the Israeli gas sector. Historically, American majors saw Israel’s energy assets as a taboo, motivated by the need to avoid alienating the Gulf Arab countries that are significantly more important for oil and gas reserves. Secondly, the UAE is increasingly enhancing its role and support in the East Med gas saga with the clear intention to counter Turkish expansionism. In this effort, the UAE decided to join as an observer the Eastern Mediterranean Gas Forum (EMGF), an Egypt-led organization (Sabry 2020).
The energy sector is seen as a potential area of further cooperation and collaboration between Arab countries and Israel. In December 2020, a meeting between the energy ministers of Israel, the US, the UAE and Bahrain took place. Its goal was to establish a platform for a comprehensive dialogue on energy issues (Bassist 2020). The countries could exchange ideas for further cooperation and the creation of joint ventures in the energy sector (from natural gas to energy efficiency). This shows that energy cooperation between Israel and the UAE is not limited to fossil fuels. For example, the Masdar investment fund in Abu Dhabi announced the first major UAE investment in renewable energy in Israel in cooperation with EDF Renewables Israel (Zaken 2021).
At the beginning of 2021, another major development occurred in the region. Saudi Arabia and other GCC countries announced the end of their three-year blockade on Qatar, initially agreeing to reopen their land and maritime borders as well as their air space to Qatar on January 4, 2020. The next day, they pledged to restore relations with Qatar. This symbolic episode was mainly motivated by the Saudi need to improve its troubled relationship with its main ally, the United States. With the end of Trump’s presidency, Gulf countries may not have the same political support for their aggressive and assertive policy in the region. Despite the lower tension, serious differences between Riyadh and Washington remain, and they will continue to be a source of stress for the two countries. Moreover, even if it ended now, the blockade of Qatar will have long-term impacts that are not going to be resolved easily. Differences on regional issues were present before the 2017 blockade and they are set to remain in place after its end.
A de-escalation of tensions across the region can also be motivated by the countries’ need to attract foreign investments. Asia is not the only (geo)political center that may increase its influence in the region amid geopolitical shifts. As the Green Deal advances, Europe may increase its influence in the North African countries. Given the proximity of the two Mediterranean shores, the EU may look into opportunities to foster renewable energy investments in those countries, also aiming at importing some clean energy. As aforementioned, the EU is considering the possibility to import 40 GW of green hydrogen from North African countries. If the European institutions finance significant clean energy projects in the region, they would increase Europe’s geoeconomic influence and foster climate policies in those countries. With the election of President Biden, climate policies are back in the US agenda, and this could induce Washington to enhance and change its policies on several issues, affecting the current geopolitical equilibrium of the MENA region. To preserve its relevance in the area, it is crucial for the US and its energy companies to support climate, energy and technological solutions in the MENA region, finding cooperation opportunities with other countries. Otherwise, other players, notably China, will be ready to fill the vacuum. Moreover, the EU has decided to strengthen its cooperation in the energy sector also with the GCC in the wake of Russia’s war in Ukraine. In May 2022, the EC released a Joint Communication on a ‘Strategic Partnership with the Gulf’, envisaging areas of EU-GCC cooperation, among which energy plays a crucial role both in terms of energy security and decarbonization. The EU seeks to increase energy cooperation as the world’s energy flows are expected to change due to international sanctions on Russian fossil fuels. The GCC could benefit from the opportunity, and increase their share in the European energy markets. At the same time, the EU is committed to increasing cooperation also on the low-carbon alternatives, such as hydrogen, given the great ambitions of the GCC countries in the field.
Notes
- 1.
The IEA definition of Middle East excludes North Africa.
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Hafner, M., Raimondi, P.P., Bonometti, B. (2023). Geopolitics of the Energy Transformation in the MENA Region. 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_6
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