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Kazakhstan, an oil producer since 1911, has the second-largest oil reserves and the second-largest oil production among the former Soviet republics after Russia.

Kazakhstan is a major oil producer. The country’s estimated total petroleum and other liquids production was 1.698 million barrels per day (b/d) in 2016. The key to its continued growth in liquids production from this level is the development of its giant Tengiz, Karachaganak, and Kashagan fields. Development of additional export capacity will also be necessary for production growth.

Although Kazakhstan became an oil producer in 1911, its production did not increase to a meaningful level until the 1960s and 1970s, when production plateaued at nearly 500,000 b/d, a pre-Soviet independence record production level. Since the mid-1990s, and with the help of major international oil companies, Kazakhstan's production first exceeded 1 million b/d in 2003.

Oil field development in Kazakhstan reached two milestones in 2016. In October 2016, the giant Kashagan field resumed production after years of delays. Kashagan is expected to produce 370,000 b/d of liquids at full capacity. Additionally, in July 2016, The Tengizchevroil consortium decided to proceed with expansion plans that should increase liquids production at the Tengiz project by about 260,000 b/d beginning in 2022.

Kazakhstan is landlocked and is far from international oil markets. The lack of access to the open ocean makes the country dependent mainly on pipelines to transport its hydrocarbons to world markets. Kazakhstan is also a transit country for oil and natural gas pipeline exports to China.

Kazakhstan consumed 2.66 quadrillion British thermal units (Btu) of energy in 2014, with coal accounting for the largest share of energy consumed (63%), followed by petroleum and natural gas (18% and 16%, respectively) (Figure 2).

Kazakhstan is a Caspian Sea littoral state. The legal status of the Caspian area remains unresolved, mainly driven by a lack of agreement on whether the Caspian is a sea or a lake. Until all states agree on a definition, the legal status of the area will remain unresolved.

uploads1494583497760-energy_consumption.pngOil field development in Kazakhstan reached two milestones in 2016. In October 2016, Kashagan field resumed production after years of delays. In July 2016, the Tengizchevroil consortium made a final investment decision on a project to increase liquids production by about 260,000 b/d.

According to the Oil & Gas Journal (OGJ), Kazakhstan had proved crude oil reserves of 30 billion barrels as of January 2017–the second–largest endowment in Eurasia after Russia, and the twelfth largest in the world, just behind the United States.1 Kazakhstan's current oil production (Figure 3) has been dominated by two giant onshore fields in the northwest of the country: Tengiz and Karachaganak, which together produced about half of Kazakhstan’s total petroleum liquids output in 2016. The offshore Kashagan field, in Kazakhstan’s part of the Caspian Sea, started production in October 2016. At full capacity, Kashagan will join Tengiz and Karachaganak as the three largest producing fields in Kazakhstan. Additionally, in July 2016, The Tengizchevroil consortium decided to proceed with expansion plans that should increase liquids production at the Tengiz project by about 260,000 b/d beginning in 2022.

Kazakhstan's petroleum and other liquids production and consumption

Sector organization

The Ministry of Energy oversees the oil and natural gas industry in Kazakhstan. In August 2014, Kazakhstan’s president, Nursultan Nazarbayev, announced an extensive government reorganization with the intention of creating a more compact and effective government. The number of ministries in the government was reduced from 17 to 12, and the Ministry of Energy was created to absorb the functions of the Ministry of Oil and Gas and parts of the functions of the Ministry for Industry and New Technologies and the Ministry for Environment and Water Resources.2

The national oil and natural gas company, KazMunaiGaz (KMG), represents the state's interests in Kazakhstan's oil and gas industry. KMG was created in 2002 and holds equity interests in Karachaganak (10%), Kashagan (16.88%), and Tengiz (20%), as well as interests ranging between 33% and 100% in many other production projects.3

Kazakhstan's Law on Subsoil and Subsoil Use (Subsoil Use Law) governs investments in the oil and natural gas industries. The Subsoil Use Law has been amended several times, most notably in 2005, 2007, 2010, and 2014. Among other provisions, the Subsoil Use Law along with the December 2009 Local Content Law established strict local content requirements for oil and gas contracts. The Subsoil Use Law also established the government’s right to preempt any sale of oil and gas assets. In 2013 Kazakhstan preempted ConocoPhillips sale of its 8.4% stake in the Kashagan project to India’s ONGC.

The preemption did not affect Conoco’s proceeds from the sale, but rather than going to ONGC, the stake was purchased by KMG before being resold to China’s CNPC.4

The government announced the re-introduction of oil export duties in August 2010, increasing the duty in subsequent years as oil prices climbed, and reducing the oil duty several times since 2014 when oil prices declined sharply. Export duties were first introduced in 2008 and then were suspended in January 2009. Export duties affect all oil exporters operating in Kazakhstan, with the exceptions of those that include a tax stabilization clause in their contracts.

Production

In the 1970s, several large discoveries were made in presalt reservoirs, including Karachaganak and Tengiz. However, the development of these fields was not possible at the time because of the technical challenges of developing the deep, high-pressure reservoirs. Since international oil companies began to participate in Kazakhstan's petroleum sector and as presalt deposits became technically and commercially viable, these fields have become the foundation of the country's petroleum liquids production.

Although Kazakhstan is the second-largest liquid fuels producer among Former Soviet Union republics, its future as a producer of petroleum liquids depends on the development and expansion of its three largest projects: Karachaganak, Kashagan, and Tengiz (Table 1).5Kazakhstan’s two largest projects, Tengiz and Karachaganak, accounted for 50% (Tengiz 35%, Karachaganak 15%) of the country's production in 2016, according to data published by Energy Intelligence.6 When production at Kashagan (which started in October 2016) reaches full capacity, the combined output of all three projects is likely to account for at least 60% of Kazakhstan’s total production.

In July 2016, the Tengiz partners made a final investment decision to proceed with the Future Growth Project. This expansion project is expected to be completed by 2022, bringing about 260,000 b/d of additional liquids production from Tengiz. An expansion project has also been proposed for the Karachaganak field, but it is at a less-advanced stage of planning.

The Kashagan field, the largest known oil field outside the Middle East and the fifth largest in the world in terms of reserves, is located off the northern shore of the Caspian Sea near the city of Atyrau, Kazakhstan. Kashagan's recoverable reserves are estimated at 7 to 13 billion barrels of crude oil. On September 11, 2013, production from the super-giant field commenced, eight years after the originally scheduled startup date. In October 2013, just a few weeks after production began, production had to be halted because of leaks in the pipeline that transports natural gas from the field to shore. Production restarted in October 2016, and by January 2017, the field was producing more than 100,000 b/d of liquids. Full capacity for the first phase of development is production of 370,000 b/d.

Many of the repeated delays at Kashagan were the result of the field's adverse operating environment and complexity, resulting in significant cost overruns. The Kashagan reservoir is located more than 13,000 feet below the seabed and is under very high pressure (770 pounds per square inch). The reservoir contains high levels of hydrogen sulfide. Hydrogen sulfide is both highly toxic and highly corrosive and has been blamed for the pipeline leaks. In addition, conventional drilling and production technologies such as fixed or floating platforms cannot be used because of the shallow water and cold climate. Instead, offshore facilities are installed on artificial islands (drilling and hub islands) that house drilling and processing equipment. The processing facilities separate recovered liquids from the gas, reinject a portion of the gas, and send the liquids and the remainder of the gas to shore for further processing. Before production could restart, the pipelines connecting the field with the onshore processing facilities had to be replaced using higher-grade materials that are more resistant to corrosion.

Table 1. Kazakhstan's major oil and gas fieldsField nameCompaniesStart yearLiquids productionNatural gas productionTengiz (& Korolev)Chevron, ExxonMobil, KazMunaiGaz, LukArco (Lukoil and BP)1991570,000 thousand bbl/d total liquids production in 2016
Expansion project to add 260,000 b/d of crude production beginning in 2022274 Bcf drymarketed gas production in 2013KarachaganakBG, Eni, Chevron, Lukoil, KazMunaiGaz1984206,000 b/d total liquids production in 2016
An expansion project is under consideration, but potential production volumes are uncertainAbout 300 Bcf wet marketed gas production in 2016KashaganKazMunaiGaz, Eni, ExxonMobil, Shell, Total, China National Petroleum Corporation, Inpex2016370,000 b/d liquids processing capacity with current developmentOver 100 Bcf gas production capacitySource: U.S. Energy Information Administration based on data from TengizChevroil, Chevron, Karachaganak Petroleum Operating (KPO), and Eni

Oil exports

Kazakhstan is an exporter of light, sweet crude oil. In 2016, Kazakhstan exported about 1.3 million b/d of crude oil and condensate, according to EIA estimates based on data from Global Trade Tracker and Lloyd's List Intelligence (APEX) (Figure 4).7 Most of Kazakhstan’s crude exports travel around or across the Caspian Sea to European markets. An additional 5% of Kazakhstan’s crude oil exports flowed east via a pipeline to China. A significant portion of Kazakhstan’s exports transit Italy and the Netherlands, making it difficult to determine where this crude oil ends up because Kazakhstan reports these volumes as having been delivered to the transit countries.

Export routes

Kazakhstan's pipeline system is operated by the state-run KazTransOil, a subsidiary of KazMunaiGas, which runs approximately 3,400 miles of pipelines. Because of Kazakhstan’s landlocked location and the continued use of Soviet-era infrastructure, much of Kazakhstan’s oil and gas export infrastructure is integrated with major Caspian oil and natural gas export routes that interlink the region. Since independence, Kazakhstan has successfully expanded and diversified its export capabilities. Major crude oil export pipelines include the Caspian Pipeline Consortium pipeline to the Black Sea port of Novorossiysk, the Kazakhstan-China pipeline, and the Uzen-Atyrau-Samara pipeline to Russia (Figure 5).

Kazakhstan also exports crude oil via the Caspian Sea and via rail. Oil is loaded onto tankers or barges at Kazakhstan’s port of Aktau or the smaller Atyrau port and then shipped across the Caspian Sea, where it is loaded onto the Baku-Tbilisi-Ceyhan pipeline or the Northern Route pipeline (Baku-Novorossiysk) for onward transport, mainly to Europe. Additionally, Kazakhstan has an extensive rail network, which it uses to transport liquid fuels both for domestic consumption and for exports. Continued expansion and diversification of Kazakhstan’s petroleum liquids transport capacity, particularly export capacity, is key to its future ability to increase production.

Another potential export route for Caspian crude oil is via swaps with Iran. For years, Kazakhstan and other Central Asian countries delivered their crude oil to Iran’s Caspian Sea port of Neka. From there the crude oil was delivered to refineries in Tehran and Tabriz, with the refined products distributed and consumed in northern Iran. In exchange, Iran exported equal volumes of crude out of its Persian Gulf ports on behalf of Kazakhstan. Swap volumes have varied over the years, with little to no crude swapped since 2011. Sanctions against Iran reportedly complicated swap arrangements, especially the marketing of the crude oil exported in the Persian Gulf, which had been done by the Iranians. Also complicating the swap arrangements was Iran’s desire to raise the fee it charged Kazakhstan for each barrel of crude swapped. Since at least late 2013, Iran and Kazakhstan have been discussing resumption of the swap arrangement and have periodically announced their intentions to resume swaps, but no swaps had occurred as of the end of 2016.

Kazakhstan's crude exports by destination, 2016

Figure 5. Kazakhstan map of major crude oil pipelines

Map of major Caspian oil and natural gas export routes

Oil grades

Kazakhstan’s main export oil grade is the CPC Blend. CPC Blend is a very light (45.3° API), sweet crude (0.56% sulfur)8 that is valued for its high yield of gasoline and light distillates. Production from the Tengiz field accounts for about 60% of the CPC blend. Other components include production from Karachaganak, Kashagan, and Kumkol fields, some Russian grades such as Siberian Light, along with a variety of other Russian and Kazakh grades.

Smaller volumes of many of the components of CPC Blend are also marketed separately as distinct crude oil grades. However, with the recent expansion of the CPC pipeline, the volumes of crude oil marketed separately have declined.

Refining

Kazakhstan had three major crude oil refineries with crude oil distillation capacity of 340,000 b/d as of January 1, 2017, according to OGJ.9 The three major oil refineries in Kazakhstan are: Pavlodar, Atyrau, and Shymkent. The Pavlodar refinery is in north-central Kazakhstan and is supplied mainly by a crude oil pipeline from western Siberia, because Russian supplies are well-placed geographically to serve that refinery. The Atyrau refinery uses only domestic crude oil from northwest Kazakhstan, and the Shymkent refinery currently uses crude from the oil fields at Kumkol and the nearby area in central Kazakhstan. There is also a smaller refinery at Aktau that processes heavy crude oil produced at a nearby field to make bitumen for road construction.10

The three main refineries meet approximately 70% of Kazakhstan’s gasoline and diesel demand, with most of the remaining demand met by imports from Russia. Upgrading projects were underway in early 2017 at all three refineries and are expected to be completed in late 2017 or early 2018. The upgrades will allow the three plants to produce fewer heavy products and more high-quality transportation fuels. With these upgrades, Kazakhstan aims to meet all domestic demand for gasoline and diesel production by 2019.11

Natural gas

Kazakhstan’s largest petroleum liquids fields also contain substantial volumes of natural gas, much of which is reinjected into oil wells to improve oil recovery rates.

OGJ estimated Kazakhstan’s proven natural gas reserves at 85 trillion cubic feet (Tcf) as of January 1, 2017.12 Most of Kazakhstan’s natural gas reserves are in crude oil or condensate-rich fields. The two largest petroleum liquids fields, Karachaganak and Tengiz, are also the two largest natural gas fields.

Production

Over the past decade, annual gross natural gas production almost doubled, from 0.8 Tcf in 2005 to 1.5 Tcf in 2015. Much of Kazakhstan’s gross natural gas production is reinjected (more than 30% in 2015) to increase oil production. Much of the natural gas produced at Tengiz and Kashagan is high in sulfur, and therefore requires special handling and is more costly to process.

In 2016, the Karachaganak and Tengiz fields combined accounted for about 70% of Kazakhstan’s natural gas production.13 The Tengiz project includes a natural gas processing plant, which according to Chevron produced 274 billion cubic feet (Bcf) of dry marketed natural gas in 2016 that was sold to local consumers.14 The Karachaganak project has insufficient gas processing capacity. Most of the raw marketed production from the Karachaganak field must be exported to Russia to be processed at a gas processing plant in Orenberg.

Production restarted at the Kashagan field in October 2016. When the project reaches full capacity, it is expected to produce about 100 Bcf of natural gas per year for domestic consumption, with additional produced gas reinjected into the reservoir to boost liquids recovery.

Consumption, imports, and exports

Kazakhstan has two major export pipelines for natural gas (Figure 6). The Central Asia Centre pipeline (CAC), which traverses the western edge of Kazakhstan on its way to Russia and points further west, and the Turkmenistan-China pipeline, which traverses the southern edge of the country on its way to China. Both pipelines are part of the regional Caspian export infrastructure and mainly carry natural gas exports from Turkmenistan, along with smaller but still significant volumes of exports from Kazakhstan and Uzbekistan. The CAC pipeline also serves local natural gas demand in western Kazakhstan, including northwestern Kazakhstan where most of the country’s production is located.

A third major international pipeline, the Bukhara-Tashkent-Bishkek-Almaty pipeline, serves local demand in southern Kazakhstan. Two of Kazakhstan’s three underground natural gas storage facilities are located along this pipeline.

Natural gas production in Kazakhstan is concentrated in the northwest and, until recently, has not been connected to population centers in the south, north, center, and east. Prior to 2016, consumers in southern Kazakhstan were supplied with imported natural gas from Turkmenistan or Uzbekistan. However, in November 2015, KazTransGas, the state-owned natural gas pipeline operator, completed the final link in the new Beinu-Bozoi-Shymkent pipeline. This pipeline has allowed Kazakhstan to gasify communities along the route of the pipeline that previously had no access to gas. It has also connected the natural gas fields and infrastructure in the northwest of the country to the population centers in the south of the country, replacing imported natural gas in those markets with domestically produced gas. Completing this link has also connected Kazakshtan’s producing regions with the natural gas pipeline to China, allowing production from northwestern Kazakhstan to be exported to China. Kazakhstan has also discussed the possibility of using this infrastructure to transit Russian natural gas to China.

Plans for gasifying other parts of the country and connecting them to the existing infrastructure in the West and South are more uncertain. The vast distances and relatively low population density in the north, center, and east make the economics challenging for any potential gas pipeline projects to serve those regions. Kazakhstan contracted to import 5,000 metric tons of liquefied natural gas (LNG) in 2017 (about 0.2 Bcf of gaseous natural gas) from Russia by road to Astana, Kazakhstan’s capital, and other cities in the north of the country. Kazakhstan’s coal basins, which lie in the north and center of the country, could also be a source of natural gas supplies for areas of the country that are far from existing natural gas production and infrastructure. Kazakhstan has been exploring the potential to produce and market methane from coal mines and coal beds.

Figure 6. Kazakhstan map of major natural gas pipelines

Figure 6. Kazakhstan map of major natural gas pipelines

Coal

In 2014, coal accounted for 56% of Kazakhstan’s total energy consumption.

With 28,225 million short tons (MMst) of total recoverable coal reserves as of 2014, Kazakhstan is in the top ten countries in the world in terms of coal reserves, coal production, and coal exports. It is also in the top fifteen countries in the world in terms of coal consumption. Despite being among the top coal countries, Kazakhstan is a relatively small contributor to global coal volumes. The top four countries globally account for disproportionate shares of total global coal reserves, production, consumption, and exports (between 65% and 75% combined), while Kazakhstan accounts for between 1% and 4%.

About a quarter of Kazakhstan’s coal production is exported, with most going to Russia. Virtually all of Kazakhstan’s coal production and exports consist of steam coal, which is suitable for burning in electric power plants or in other applications to generate steam and heat. Kazakhstan also produces smaller quantities of metallurgical coal that are consumed domestically. Kazakhstan is rich in a variety of minerals, with mineral and coal deposits concentrated in the north and center of the country. Coal is a major energy source for the mining and smelting industries and for the electricity sector in Kazakhstan.

Electricity

Most of Kazakhstan's power generation comes from coal-fired power plants, concentrated in the north of the country near the coal-producing regions.

Kazakhstan's total installed generating capacity was 22.1 gigawatts (GW) as of 2017.15Kazakhstan's total generation in 2016 was 94.1 billion kilowatthours (BkWh) of electricity—of which 87% came from fossil fuel-fired plants, 12% came from hydropower plants, and less than 1% came from solar and wind installations.16

Kazakhstan's only nuclear power plant, a BN-350 nuclear reactor at Aktau, was shut down in 1999. Kazakhstan has some of the largest uranium deposits in the world and is the world's largest uranium producer.17 Although plans have long existed to build additional nuclear power plants, there has been little progress on constructing these units.

Kazakhstan's national grid is operated by the Kazakhstan's Electricity Grid Operating Company, a state-owned company, which is responsible for electric transmission and network management. A number of medium and small regional electricity companies handle distribution, some of which are privately owned. The electricity transmission and distribution sectors are considered to be natural monopolies and are regulated by the government. However, wholesale generation of power is considered to be a competitive market with most generation assets owned by private enterprises.


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Myanmar’s Coup and Repercussions to Its Oil Industry

It was a good run while it lasted. Almost exactly a decade ago, the military junta in Myanmar was dissolved, following civilian elections. The country’s figurehead, Aung San Suu Kyi, was released from house arrest to lead, following in the footsteps of her father. Although her reputation has since been tarnished with the Rohingya crisis, she remains beloved by most of her countrymen, and her installation as Myanmar’s de facto leader lead to a golden economic age. Sanctions were eased, trade links were restored, and investment flowed in, not least in the energy sector. Yet the military still remained a powerful force, lurking in the background. In early February, they bared their fangs. Following an election in November 2020 in which Aung San Suu Kyi’s National League for Democracy (NLD) won an outright majority in both houses of Parliament. A coup d’etat was instigated, with the Tatmadaw – the Burmese military – decrying fraud in the election. Key politicians were arrested, and rule returned to the military.

For many Burmese, this was a return to a dark past that many thought was firmly behind them. Widespread protests erupted, quickly turning violent. The Tatmadaw still has an iron grip, but it has created some bizarre situations – ordinary Burmese citizens calling on Facebook and foreign governments to impose sanctions on their country, while the Myanmar ambassador to the United Nations was fired for making an anti-army speech at the UN General Assembly.

The path forward for Myanmar from this point is unclear. The Tatmadaw has declared a state of emergency lasting up to a year, promising new elections by the end of 2021. There is little doubt that the NLD will win yet another supermajority in the election, IF they are fair and free. But that is a big if. Meanwhile, the coup threatens to return Myanmar to the pariah state that it was pre-2010. And threatens to abort all the grand economic progress made since.

In the decade since military rule was abolished, development in Myanmar has been rapid. In the capital city Yangon, glittering new malls have been developed. The Ministry of Energy in 2009 was housed in a crumbling former high school; today, it occupies a sprawling complex in the new administrative capital of Naypyidaw. While not exactly up to the level of the Department of Energy in Washington DC, it is certainly no longer than ministry that was once reputed to take up to three years to process exploration licences for offshore oil and gas blocks.

And it is that very future that is now at stake. Energy has been a great focus for investment in Myanmar, drawn by the rich offshore deposits in the Andaman Sea and the country’s location as a possible pipeline route between the Middle East and inland China. Estimates suggest that – based on pre-coup trends – Myanmar was likely to attract over US$1.1 billion in upstream investment in 2023, more than four times projected for 2021 and almost 20 times higher than 2011. The funds would not only be directed at maintaining production at the current Yadana, Yetagun, Zawtika and Shwe gas fields – where offshore production is mainly exported to Thailand, but also upcoming megaprojects such as Woodside and Total’s A-6 deepwater natural gas and PTTEP’s Aung Sinka Block M3 developments.

The coup now presents foreign investors in Myanmar’s upstream energy sector with a conundrum and reputational risk. Stay, and risk being seen as abetting an undemocratic government? Or leave, and risk being flushing away years of hard work? The home governments of foreign investors such as Total, Chevron, PTTEP, Woodside, Petronas, ONGC, Nippon Oil, Kogas, POSCO, Sumitomo, Mitsui and others have already condemned the coup. For now these companies are hoping that foreign pressure will resolve the situation in a short enough timeframe to allow business to resume. Australia’s Woodside Petroleum has already called the coup a ‘transitionary issue’ claiming that it will not affect its exploration plans, while other operators such as Total and Petronas have focused on the safety of their employees as they ‘monitor the evolving situation’.

But the longer the coup lasts without a resolution satisfactory to the international community and the longer the protests last (and the more deaths that result from that), the more untenable the position of the foreign upstream players will be. Asian investors, especially the Chinese, mainly through CNPC/PetroChina, and the Thais, through PTTEP - will be relatively insulated, but American and European majors face bigger risks. This could jeopardise key projects such as the Myanmar-to-China crude oil and natural gas pipeline project (a 771km connection to Yunnan), two LNG-to-power projects (Thaketa and Thilawa, meant to deal with the country’s chronic blackouts) and the massive Block A-6 gas development in the Shwe Yee Htun field by Woodside which just kicked off a fourth drilling campaign in December.

It is a big unknown. The Tatmadaw has proven to be impervious to foreign criticism in the past, ignoring even the most stringent sanctions thrown their way. In fact, it was a huge surprise that the army even relinquished power back in 2010. But the situation has changed. The Myanmar population is now more connected and more aware, while the army has profited off the opening of the economy. The economic consequences of returning to its darker days might be enough to trigger a resolution. But that’s not a guarantee. What is certain is that the coup will have a lasting effect on energy investment and plans in Myanmar. How long and how deep is a question that only the Tatmadaw can answer. 

Market Outlook:

  • Crude price trading range: Brent – US$63-65/b, WTI – US$60-63/b
  • The slow-but-sure recovery in Texan energy infrastructure following the big freeze has caused crude oil benchmarks to retreat somewhat, with all eyes now focusing on OPEC+ as it meets to decide its supply quotas for April and beyond
  • Some form of supply easing is expected, given that the market is showing signs of tight supply, but OPEC+ is still split on how aggressive it can be; Saudi Arabia is advocating caution while most others, led by Russia, favour a bolder easing given current prices
  • While OPEC+ supply will be keenly watched as an indicator of future crude trends, supply elsewhere is picking up, with the Baker Hughes survey of active oil and gas rigs in the USA crossing the 400-site level for the first time in over a year, with gains mainly from onshore shale drillers tempted back after being wiped up last year

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March, 03 2021
The Competition For The LNG Crown

The year 2020 was exceptional in many ways, to say the least. All of which, lockdowns and meltdowns, managed to overshadow a changing of the guard in the LNG world. After leapfrogging Indonesia as the world’s largest LNG producer in 2006, Qatar was surpassed by Australia in 2020 when the final figures for 2019 came in. That this happened was no surprise; it was always a foregone conclusion given Australia’s massive LNG projects developed over the last decade. Were it not for the severe delays in completion, Australia would have taken the crown much earlier; in fact, by capacity, Australia already sailed past Qatar in 2018.

But Australia should not rest on its laurels. The last of the LNG mega-projects in Western Australia, Shell’s giant floating Prelude and Inpex’s sprawling Ichthys onshore complex, have been completed. Additional phases will provide incremental new capacity, but no new mega-projects are on the horizon, for now. Meanwhile, after several years of carefully managing its vast capacity, Qatar is now embarking on its own LNG infrastructure investment spree that should see it reclaim its LNG exporter crown in 2030.

Key to this is the vast North Field, the single largest non-associated gas field in the world. Straddling the maritime border between tiny Qatar and its giant neighbour Iran to the north, Qatar Petroleum has taken the final investment decision to develop the North Field East Project (NFE) this month. With a total price tag of US$28.75 billion, development will kick off in 2021 and is expected to start production in late 2025. Completion of the NFE will raise Qatar’s LNG production capacity from a current 77 million tons per annum to 110 mmtpa. This is easily higher than Australia’s current installed capacity of 88 mmtpa, but the difficulty in anticipating future utilisation rates means that Qatar might not retake pole position immediately. But it certainly will by 2030, when the second phase of the project – the North Field South (NFS) – is slated to start production. This would raise Qatar’s installed capacity to 126 mmtpa, cementing its lead further still, with Qatar Petroleum also stating that it is ‘evaluating further LNG capacity expansions’ beyond that ceiling. If it does, then it should be more big leaps, since this tiny country tends to do things in giant steps, rather than small jumps.

Will there be enough buyers for LNG at the time, though? With all the conversation about sustainability and carbon neutrality, does natural gas still have a role to play? Predicting the future is always difficult, but the short answer, based on current trends, it is a simple yes. 

Supermajors such as Shell, BP and Total have set carbon neutral targets for their operations by 2050. Under the Paris Agreement, many countries are also aiming to reduce their carbon emissions significantly as well; even the USA, under the new Biden administration, has rejoined the accord. But carbon neutral does not mean zero carbon. It means that the net carbon emissions of a company or of a country is zero. Emissions from one part of the pie can be offset by other parts of the pie, with the challenge being to excise the most polluting portions to make the overall goal of balancing emissions around the target easier. That, in energy terms, means moving away from dirtier power sources such as coal and oil, towards renewables such as solar and wind, as well as offsets such as carbon capture technology or carbon trading/pricing. Natural gas and LNG sit right in the middle of that spectrum: cleaner than conventional coal and oil, but still ubiquitous enough to be commercially viable.

So even in a carbon neutral world, there is a role for LNG to play. And crucially, demand is expected to continue rising. If ‘peak oil’ is now expected to be somewhere in the 2020s, then ‘peak gas’ is much further, post-2040s. In 2010, only 23 countries had access to LNG import facilities, led by Japan. In 2019, 43 countries now import LNG and that number will continue to rise as increased supply liquidity, cheaper pricing and infrastructural improvements take place. China will overtake Japan as the world’s largest LNG importer soon, while India just installed another 5 mmtpa import terminal in Hazira. More densely populated countries are hopping on the LNG bandwagon soon, the Philippines (108 million people), Vietnam (96 million people), to ensure a growing demand base for the fuel. Qatar’s central position in the world, sitting just between Europe and Asia, is a perfect base to service this growing demand.

There is competition, of course. Russia is increasingly moving to LNG as well, alongside its dominant position in piped natural gas. And there is the USA. By 2025, the USA should have 107 mmtpa of LNG capacity from currently sanctioned projects. That will be enough to make the USA the second-largest LNG exporter in the world, overtaking Australia. With a higher potential ceiling, the USA could also overtake Qatar eventually, since its capacity is driven by private enterprise rather than the controlled, centralised approach by Qatar Petroleum. The appearance of US LNG on the market has been a gamechanger; with lower costs, American LNG is highly competitive, having gone as far as Poland and China in a few short years. But while the average US LNG breakeven cost is estimated at around US$6.50-7.50/mmBtu, Qatar’s is even lower at US$4/mmBtu. Advantage: Qatar.

But there is still room for everyone in this growing LNG market. By 2030, global LNG demand is expected to grow to 580 million tons per annum, from a current 360 mmtpa. More LNG from Qatar is not just an opportunity, it is a necessity. Traditional LNG producers such as Malaysia and Indonesia are seeing waning volumes due to field maturity, but there is plenty of new capacity planned: in the USA, in Canada, in Egypt, in Israel, in Mozambique, and, of course, in Qatar. In that sense, it really doesn’t matter which country holds the crown of the world’s largest exporter, because LNG demand is a rising tide, and a rising tide lifts all 😊

Market Outlook:

  • Crude price trading range: Brent – US$64-66/b, WTI – US$60-63/b
  • Despite the thaw after Texas saw a devastating big freeze, the slow ramp-up in restoring US Gulf Coast oil production and refining has supported crude oil prices, with Brent moving above the US$65/b level and WTI now in the low US$60/b level
  • Some Wall Street analysts, including Goldman Sachs, are predicting that oil prices could climb above US$70/b level based on current fundamentals, as the short-term spike gives ways to accelerating consumption trends
  • However, much will depend on OPEC+’s approach to managing supply in Q2, with a meeting set for early March; Saudi Arabia is once again urging caution, but there are many other members of the club champing at the bit to increase output and capitalise on the rising price environment


March, 01 2021
EIA forecasts the U.S. will import more petroleum than it exports in 2021 and 2022

Throughout much of its history, the United States has imported more petroleum (which includes crude oil, refined petroleum products, and other liquids) than it has exported. That status changed in 2020. The U.S. Energy Information Administration’s (EIA) February 2021 Short-Term Energy Outlook (STEO) estimates that 2020 marked the first year that the United States exported more petroleum than it imported on an annual basis. However, largely because of declines in domestic crude oil production and corresponding increases in crude oil imports, EIA expects the United States to return to being a net petroleum importer on an annual basis in both 2021 and 2022.

EIA expects that increasing crude oil imports will drive the growth in net petroleum imports in 2021 and 2022 and more than offset changes in refined product net trade. EIA forecasts that net imports of crude oil will increase from its 2020 average of 2.7 million barrels per day (b/d) to 3.7 million b/d in 2021 and 4.4 million b/d in 2022.

Compared with crude oil trade, net exports of refined petroleum products did not change as much during 2020. On an annual average basis, U.S. net petroleum product exports—distillate fuel oil, hydrocarbon gas liquids, and motor gasoline, among others—averaged 3.2 million b/d in 2019 and 3.4 million b/d in 2020. EIA forecasts that net petroleum product exports will average 3.5 million b/d in 2021 and 3.9 million b/d in 2022 as global demand for petroleum products continues to increase from its recent low point in the first half of 2020.

U.S. quarterly crude oil production, net trade, and refinery runs

Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO), February 2021

EIA expects that the United States will import more crude oil to fill the widening gap between refinery inputs of crude oil and domestic crude oil production in 2021 and 2022. U.S. crude oil production declined by an estimated 0.9 million b/d (8%) to 11.3 million b/d in 2020 because of well curtailment and a drop in drilling activity related to low crude oil prices.

EIA expects the rising price of crude oil, which started in the fourth quarter of 2020, will contribute to more U.S. crude oil production later this year. EIA forecasts monthly domestic crude oil production will reach 11.3 million b/d by the end of 2021 and 11.9 million b/d by the end of 2022. These values are increases from the most recent monthly average of 11.1 million b/d in November 2020 (based on data in EIA’s Petroleum Supply Monthly) but still lower than the previous peak of 12.9 million b/d in November 2019.

February, 18 2021