The official history of the Iraq’s oil began when a well at Baba Gurgur just north of Kirkuk was struck in the early hours of 14 October 1927 by the Turkish Petroleum Company (TPC) however the early negotiations for an oil concession was started with Ottoman Sultan from the late 19th century.
Indeed, the significant proved reserves of crude oil during the steps of new government installation in the Iraq was enough appealing for giant oil companies to own the shares of TPC. In 1928 the composition of TPC was rearranged through a formal agreement and TPC shareholders were formed by Anglo – Persian Company(the forerunner of the British Petroleum), Royal Dutch-Shell, Compagnie Française des Pétroles (which was named later the Total) and NEDC, an American consortium included Standard Oil of New Jersey (The prior name of Exxon which merged to Mobil and formed Exxon Mobil Company in 1999), Standard Oil Company of New York, Gulf Oil, the Pan-American Petroleum and Transport Company, Atlantic Richfield Co and an Turkish American businessman Calouste Gulbenkian.
Meanwhile by the new structure of TPC shareholders, it was renamed the Iraq Petroleum Company (IPC) and its operational territory was expanded to all the Red Line (except of Kuwait), though by establishing the Bahrain National Petroleum Company and later, the ARAMCO (Saudi Arabia) followed by last two U.S companies’ exit from the NEDC in 1948, the IPC was limited to the Iraq country and left the Iraq after nationalizing the country’s oil industry in 1972.
Of course the bp’s roll in IPC’s achievements was significantly different than another shareholders, not only because of Great Britain Government’s supports, but also by its great perseverance from 1928 until 1972 when Iraq’s oil industry was nationalized completely, the historical character of bp in the Iraqi minds.
bp’s comeback to the Iraq’s oil
Regarding to the high dependence of Iraq’s economy and its public budget on the oil’s income which is on the top of world countries’ level, the Iraqi government in the new era (after 2003) made plans to increase the oil production which was followed by inviting the IOCs’ return to the Iraq’s oil industry, after 40 years of divorce.
While the Iraq’s statement in 2007 declared sharp raises in its proven oil reserves up to 115 billion barrels, 26 international oil companies returned to the Iraq’s oil industry, including the Exxon Mobil, Royal Dutch-Shell, Total and bp, the main shareholders of the IPC. Of course some another famous companies expressed their intend and won some projects, such as Chinese National Petroleum Company (CNPC), Malaysian Petronas, GAZPROM, Turkiye Petroleum Anonim Ortakligi (TPAO), Lukoil or Dragon oil.
Whereas the several International Oil Companies participated in the Iraq’s oil projects and development plans but the bp’s comeback was significantly different, especially when the bp’s strong involvement in the giant Rumaila field enhanced its production rapidly while the most of IOCs stay in studying phases yet.
Afterwards, the bp expressed it’s interest in developing the Kirkuk’s oilfields, where was the first entrance of bp to the Iraq’s oil industry. The negotiations with the Ministry of Oil of Iraq resulted in an agreement in 2013 which was a basis for making common operational team in February 2014 but bp’s operations in Kirkuk was stopped until the October 2017 when the Kirkuk was handed over to the Iraqi federal government.
The preliminary Kirkuk’s production target of 750,000 bpd which it’s not only seemed far to be quickly achieved, but also it’s predictable to be increased up to 1,500,000 bpd until 2021.
Meanwhile, if the bp could has the chance to participate in the development of the big Majnoon oilfield, its historical synergy in the Iraq’s oil industry could be revived again. While the bp would be involved in the fields containing 40% of Iraqi Federal reserves, it will influence on producing more than half of Iraqi federal’s oil production.
Despite the bp’s concern for strong participation in the Iraq’s oil industry, the most of IPC shareholders pulled out or limited their activities in the Iraq’s projects such as ExxonMobile which sold the most of its share in the big field of West Qurna#1 or Royal Dutch-shell which left the critical field of Majnoon. Meanwhile, the Total’s participation in the Iraq’s oil industry limited to the Halfaya field by just 18.75%. In the same approach, some another international oil companies limited their actives or shares in the Iraq’s oil projects, such as the Petronas who left the Majnoon recently or Sonangol which is going to resume it’s operation in Qayara and Najma fields that were stopped from 2015.
The next months when the Iraqi government would make decision about the service companies in the Manoomn oilfield, the perspective of bp in Iraq’s oil industry could be clarified whether it will comeback to the historical rail or continuously run in the limited situation.
Thinking about energy and water together can help ensure that “no one is left behind”
The theme of this year’s World Water Day is “leave no one behind”, a salient theme for the IEA because of the importance our work places on achieving affordable and clean energy for all (SDG 7), but also because energy acts as an enabler of other SDGs, including access to clean water and sanitation for all (SDG 6).
Last year the World Energy Outlook integrated a water dimension into the IEA’s Sustainable Development Scenario (SDS) to better understand how much energy it might take to achieve SDG 6 and what role the energy sector could play.
This analysis found that while energy is essential to solving the world’s water problems, the amount of energy required to attain SDG 6 hardly moves the dial in terms of global consumption. Ensuring that 2.1 billion people have access to clean drinking water, 4.5 billion have safely managed sanitation, collecting and treating more wastewater and using water more efficiently adds less than 1% to global energy demand in the SDS in 2030.
It also found that it is much better to tackle these problems in tandem rather than in parallel as there are significant synergies between SDG 6 and SDG 7, which if tapped could accelerate progress on both goals.
For example, almost two-thirds of those who lack access to clean drinking water in rural areas also lack access to electricity. This opens up a range of potential opportunities to coordinate solutions and make progress on multiple SDGs at once.
This is because many of the technologies and solutions being deployed to provide electricity can also be used to provide access to water. Decentralised solar PV water pumps can replace more expensive diesel pumps or hand-pumps and mini-grids can power filtration technologies, such as reverse osmosis systems, to produce clean drinking water. While there are many solutions that do not require energy, its use can help increase the reliability and the amount of clean water available at a given point in time.
That said, providing access to clean water is just a start. Ensuring it is reliable, affordable and able to scale up to meet continued demand from rising standards of living and population growth is another challenge. So is moving beyond just a household level of access towards delivering access for productive uses, such as agriculture. In each case, the energy load is likely to grow.
As such, meeting these challenges and approaching water and electricity access in an integrated way may shift the emphasis away from off-grid solutions towards mini-grid or grid-connected solutions, especially where water services can provide an “anchor load” for power generation and assist with balancing and storage.
There is also another side to the story: waste can generate energy. Anaerobic digesters can be used to produce biogas from waste, which can then be used by households to displace the use of wood and charcoal. With proper planning and support, such solutions deployed in rural areas can ensure the safe collection, disposal and treatment of waste and contribute to the achievement of clean cooking for all, one of the targets of SDG 7. This has the potential to provide upwards of 180 million households with clean cooking fuel while also reducing indoor air pollution. We will be looking in detail at the potential for biogas in WEO 2019.
Beyond these synergies, it’s important to also highlight how achieving SDG 6 requires improving the way we manage and use water to ensure it is available when needed. While the energy sector’s share of total global water use today is relatively low – accounting for roughly 10% of total global withdrawals and 3% of consumption – there is room to further reduce demand. Water withdrawals for the energy sector in the SDS decline by 20% by 2030 from today’s levels thanks to a combination of energy efficiency, a move away from coal-fired power generation and greater deployment of solar PV and wind.
Getting the water and energy communities to coordinate efforts and financing has the potential to unlock significant progress on some of the most deep-rooted issues of our day: providing electricity, clean cooking, clean drinking water and sanitation to the billions of people who lack these today. This will require thinking and working together, innovative business models and cross-sectoral planning and regulation. There are no simple solutions, but exploiting these synergies can make a big difference for those currently left behind.
Are aviation biofuels ready for take off?
Air travel is booming, with the number of air passengers set to double over the next twenty years. Aviation demand is particularly evident in in the Asia Pacific region, where growing economic wealth is opening new travel opportunities.
Aviation accounts for around 15% of global oil demand growth up to 2030 in the IEA’s New Policies Scenario, a similar amount to the growth from passenger vehicles. Such a rise means that aviation will account for 3.5% of global energy related CO2 emissions by 2030, up from just over 2.5% today, despite ongoing improvements in aviation efficiency.
This expansion underscores the need for the aviation industry to tackle its carbon emissions. For now, liquid hydrocarbon fuels like jet fuel remain the only means of powering commercial air travel. Therefore, along with a sustained improvement in energy efficiency, Sustainable Aviation Fuel (SAF) such as aviation biofuels are key to reducing aviation’s carbon emissions.
The International Civil Aviation Organization (ICAO), which governs international aviation, has committed to reducing carbon emissions by 50% from their 2005 level by 2050. Blending lower carbon SAF with fossil jet fuel will be essential to meeting this goal. This is reflected in the IEA’s Sustainable Development Scenario (SDS), which anticipates biofuels reaching around 10% of aviation fuel demand by 2030, and close to 20% by 2040.
The aviation industry demonstrates a strong commitment to sustainable aviation fuel use
The first flight using blended biofuel took place in 2008. Since then, more than 150,000 flights have used biofuels. Only five airports have regular biofuel distribution today (Bergen, Brisbane, Los Angeles, Oslo and Stockholm), with others offering occasional supply. But the centralised nature of aviation fuelling, where less than 5% of all airports handle 90% of international flights, means SAF availability at a small number of airports could cover a large share of demand.
Another indication of aviation’s commitment to growing SAF use is the agreement of long-term offtake agreements between airlines and biofuel producers. These now cumulatively cover around 6 billion litres of fuel. Meeting this demand will require further production facilities, and some airlines have directly invested in aviation biofuel refinery projects.
Still, aviation biofuel production of about 15 million litres in 2018 accounted for less than 0.1% of total aviation fuel consumption. This means that significantly faster market development is needed to deliver the levels of SAF production required by the aviation industry and keep on track with the requirements of the SDS.
Technology development is essential to increase aviation biofuel availability
Currently, five aviation biofuel production pathways are approved for blending with fossil jet kerosene. However, only one – hydroprocessed esters and fatty acids synthetic paraffinic kerosene (HEFA-SPK) fuel – is currently technically mature and commercialised. Therefore, HEFA‑SPK is anticipated to be the principal aviation biofuel used over the short to medium term.
Meeting 2% of annual jet fuel demand from international aviation with SAF could deliver the necessary cost reduction for a self-sustaining aviation biofuel market thereafter. Meeting such a level of demand requires increased HEFA-SPK production capacity. If met entirely by new facilities, approximately 20 refineries would be required. This could entail investment in the region of $10 billion. Although significant, this is relatively small compared to fossil fuel refinery investment of $60 billion in 2017 alone.
Ongoing research and development is needed to support the commercialisation of novel advanced aviation biofuels which can unlock the potential to use agricultural residues and municipal solid wastes. These feedstocks are more abundant and generally cost less than the waste oils and animal fats commonly used by HEFA-SPK, and can therefore facilitate greater SAF production. Furthermore, synthetic fuels produced from renewable electricity, CO2 and water via Power-to-Liquid processes may offer an alternative fuel source for aviation in the long term.
Improved aviation biofuel cost competitiveness with fossil jet kerosene is also needed
SAF are currently more expensive than jet fuel, and this cost premium is a key barrier to their wider use. Fuel cost is the single largest overhead expense for airlines, accounting for 22% of direct costs on average, and covering a significant cost premium to utilise aviation biofuels is challenging.
The competitiveness of SAF depends on its production cost relative to that of fossil jet kerosene (which varies with crude oil price). For all biofuels obtaining an economic feedstock supply is fundamental to achieve competitiveness, as feedstocks are the major determinant of production costs. For HEFA-SPK economies of scale could be realised by refineries designed for continuous production.
In the long term, airlines may include SAF consumption cost premiums within ticket costs. At current prices and today’s fleet average energy efficiency, the additional cost per passenger for a 15% blend of HEFA may not be high in comparison with other elements that influence ticket prices, such as seating class, the time of ticket purchase and taxation. However, due to the competiveness of the aviation industry customer price sensitivity is a core consideration for airlines.
Policy measures are crucial to stimulate sustainable aviation fuel demand
Impressive progress has been made in the utilisation of SAF since the first biofuel flight ten years ago. However, to fulfil aviation biofuels’ potential to reduce the climate impact of growing air transport demand, further technological development and improved economics are needed.
There is a key role for policy frameworks at this crucial early phase of SAF industry development. Without a supportive policy landscape, the aviation industry is unlikely to scale up biofuel consumption to levels where costs fall and SAF become self-sustaining.
Subsidising the consumption of SAF envisaged in the SDS scenario in 2025, around 5% of total aviation jet fuel demand, would require about $6.5 billion of subsidy (based on closing a cost premium of USD 0.35 litre between HEFA-SPK and fossil jet kerosene at USD 70/bbl oil prices). This is far below the support for renewable power generation in 2017, which reached $143 billion.
Other policy measures that could support SAF market development include:
- Financial de-risking measures for refinery project investments (e.g. grants, loan guarantees).
- Measures to provide guaranteed SAF offtake, e.g. mandates, targets and public procurement.
- Other mechanisms that close the cost gap between SAFs and fossil jet fuel e.g. carbon pricing.
Countries have more control over policy support for domestic than international aviation, and the introduction of national policy mechanisms to facilitate SAF consumption is gathering pace. The United States, the European Union, the Netherlands, the United Kingdom and Norway have all recently established policy mechanisms which will support the use of aviation biofuels. To gain the confidence of policy makers and the general public, such support will need to be linked to robust fuel sustainability criteria.
The Carbon Offsetting and Reduction Scheme for International Aviation (CORSIA), scheduled to be introduced in 2021, will be the principal mechanism to meet the ICAO’s long-term decarbonisation targets. SAF consumption and the purchase of carbon offsets are the two principal means to achieve CORSIA compliance, with the relative attractiveness of these to the aviation industry dependent on their cost per tonne of CO2 emissions mitigated.
A long-term view of natural gas security in the European Union
The security of European natural gas supplies has rarely been far off the political agenda. New gas pipeline and LNG projects command high levels of attention, particularly in the context of the European Union’s growing need for imports: its own production is declining; around 100 billion cubic metres (bcm) of long-term contracts expire by 2025; and there is some upside for gas consumption – at least in the near term – as coal and nuclear plants are retired. We estimate that the EU will have to to seek additional imports by 2025 to cover up to one-third of its anticipated consumption.
At the moment, Russia is sending record volumes to Europe while LNG utilisation rates remain relatively low. Limits to European production capacity and import infrastructure (with over half of pipelines operating at monthly peaks above 80%) may contribute to market tightness over the coming years, particularly if Asia continues to absorb the ramp up in global LNG liquefaction capacity.
Over the long-term, our projections in the latest World Energy Outlook suggest that Russia is well placed to remain the primary source of gas into Europe. LNG imports are projected to grow, as new suppliers – notably the United States – increase their presence on international markets and more European countries build LNG regasification capacity. However, Russia is still projected to account for around one-third of the EU’s supply requirements through to 2040.
But import dependence is only one part of the gas security equation. Less attention is being paid to three issues that may, in the long run, have an even greater impact on gas security in the European Union: how easily gas can flow within the European Union itself; how patterns of demand might change in the future; and what role gas infrastructure might play in a decarbonising European energy system.
A liberalised internal gas market
Whether or not gas can flow easily across borders within the European Union is a key focus of the EU’s Energy Union Strategy. On this score, our analysis suggests that the internal market is already functioning reasonably well: around 75% of gas in the European Union is consumed within a competitive liquid market, one in which gas can be flexibly redirected across borders to areas experiencing spikes in demand or shortages in supply. Bidirectional capacity has been instrumental in this regard.
That said, there are a few areas where markets and physical interconnections need further development. For example, roughly 80 billion cubic metres (bcm), or 40%, of the EU’s LNG regasification capacity cannot be accessed by neighbouring states, and some countries in central and southeast Europe still have limited access to alternative sources of supply.
On the whole, our projections suggest that targeted implementation of the European Union’s Projects of Common Interest (PCI) and full transposition of internal gas market directives can remove remaining bottlenecks to the completion of a fully-integrated internal gas market, thereby enhancing the security and diversity of gas supply. With LNG import capacity and pipeline projects like the Southern Gas Corridor increasing Europe’s supply options, the gas market in an ‘Energy Union’ case can build up its resilience to supply shocks while enabling short-term price signals, rather than fixed delivery commitments, to determine optimal imports and intra-EU gas flows.
However, this cannot be taken for granted. If spending on cross-border gas infrastructure were frozen and remaining contractual and regulatory congestion persists, then peak capacity utilisation rates would rise alongside the growth of European gas imports: around half of the EU’s import pipelines would run at maximum capacity in 2040 in this Counterfactual case, compared with less than a quarter in an Energy Union case.
Whether higher utilisation of the EU’s gas ‘hardware’ poses a security risk depends in large part on the strength of the ‘software’ of the internal market. The marketing of futures, swap deals and virtual reverse flows on hubs can allow gas to be bought and sold several times before being delivered to end-users. Along with more transparent rules for third party access to cross-border capacity, this might preclude some of the need for additional physical gas infrastructure and, in time, enable gas deliveries to be de-linked from specific suppliers or routes. Infrastructure investment decisions therefore require careful cost-benefit analysis, particularly as the debate about the pace of decarbonisation in Europe intensifies.
Security and demand
A second issue for long-term European gas security is the composition of demand. Winter gas consumption in the European Union (October-March) is almost double that of summer (April-September). The majority of this additional demand is required for heating buildings; this seasonal call is the primary determinant of gas infrastructure size and utilisation.
In the IEA’s New Policies Scenario, ambitious efficiency targets are projected to translate into a retrofit rate of 2% of the EU’s building stock each year, starting in 2021. Together with some electrification of heat demand, this would lead to a 25% drop in projected peak monthly gas demand in buildings by 2040.
This reduction in demand from the buildings sector more than offsets a 50% increase in peak gas demand for power generation, which is needed to support increasing amounts of electricity generated from variable sources, notably wind. Along with gradual declines in industrial demand, the net effect by 2040 is a reduction in monthly peak demand for gas by almost a third.
Such a trajectory for gas demand has significant commercial implications; reduced gas consumptions in buildings would lead to an import bill saving of almost €180 billion for the EU as a whole over the period 2017-2040. However, it also poses challenges for mid-stream players – e.g. grid and storage operators as well as for utilities:
For grid operators, structural declines in gas de21mand for heating means that the need for additional infrastructure is more uncertain, and what already exists may see falling utilisation (as discussed in WEO 2017). Capacity-based charges to end users typically contribute the most to cost recovery, and underpin the maintenance of the system. But, over time, higher operating costs for ageing infrastructure might need to be recovered from a diminishing customer base at the distribution level. This may further reinforce customer fuel switching over the long term.
For storage operators, the slow erosion of peak demand for heating implies an even more pronounced flattening of the spread between summer and winter gas prices, further challenging the economics of seasonal gas storage.
For utilities, with the anticipated declines in nuclear and the phasing out of coal-fired power plants in Europe, alongside the growth of variable renewable electricity, gas-fired power plants need to ramp up and down in short intervals in order to maintain power system stability. This flexible operation means a reduction in running hours but a continued need to pay for a similar amount of fuel delivery capacity (whether or not the gas itself comes from import pipelines or short-term storage sites).
A new set of questions for Europe’s gas infrastructure
The debate on Europe’s gas security has tended to concentrate on external aspects, mainly the sources and diversity of supply. But the focus may be shifting to internal questions over the role of gas infrastructure in a decarbonising European energy system, and the system value of gas delivery capacity.
A key dilemma is that, while Europe’s gas infrastructure might be needed less in aggregate, when it is needed during the winter months there is – for the moment – no obvious, cost-effective alternative to ensure that homes are kept warm and lights kept on. The amount of energy that gas delivers to the European energy system in winter is around double the current consumption of electricity.
Moreover, the importance of this function and the difficulty of maintaining it both increase as Europe proceeds with decarbonisation. As the European Union contemplates pathways to reach carbon neutrality in the Commission’s latest 2050 strategy, options to decarbonise the gas supply itself are gaining traction – notably with biomethane and hydrogen (we will be exploring these options in WEO 2019).
In order to stay relevant, natural gas infrastructure must evolve to fulfil additional functions beyond its traditional role of transporting fossil gas from the wellhead to the burner tip. Traditional concerns around security of supply of course remain relevant, but there are more things to value than volume. The security of the future gas system will increasingly depend on its versatility, flexibility, and the pricing of ‘externalities’ such as carbon emissions, air pollution or land use. Europe’s gas infrastructure is an undoubted asset. But, like many other pieces of energy infrastructure, it will need to adapt to the demands of sustainable development.
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