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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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Your Weekly Update: 13 - 17 May 2019

Market Watch

Headline crude prices for the week beginning 13 May 2019 – Brent: US$70/b; WTI: US$61/b

  • Crude oil prices are holding their ground, despite the markets showing nervousness over the escalating trade dispute between the USA and China, as well as brewing tensions in the Middle East over the Iranian situation
  • China retaliated against President Trump’s decision to raise tariffs from 10% to 25% on US$200 billion worth of Chinese imports by raising its own tariffs; crucially, China has also slapped taxes on US LNG imports at a time when American export LNG projects banking on Chinese demand are coming online
  • In the Middle East, Saudi Arabia reported that two of its oil tankers were attacked in the Persian Gulf, with the ‘sabotage attack’ near the UAE speculated to be related to Iran; with the US increasing its military presence in the area, the risk of military action has escalated
  • The non-extension of US waiver on Iranian crude is biting hard on Iran, with its leaders calling it ‘unprecedented pressure’, setting the stage for a contentious OPEC meeting in Vienna
  • In a move that is sure to be opposed by Iran, Saudi Arabia has said it is willing to meet ‘all orders’ from former Iranian buyers through June at least; Saudi Aramco is also responding to requests by Asian buyers to provide extra oil
  • The see-saw trend in US drilling activity continues; after a huge gain two weeks ago, the active US rig count declined for a second consecutive rig, with the loss of two oil rigs bringing the total site count to 988, below the equivalent number of 1,045 last year
  • There is considerably more upside to crude prices at the moment, with jitters over the health of the global economy and a delicate situation in the Middle East likely to keep Brent higher at US$71-73/b and WTI at US$62-64/b


Headlines of the week

Upstream

  • Occidental Petroleum and Warren Buffet have triumphed, as Chevron bowed out of a bidding war for Anadarko Petroleum; Occidental will now acquire Anadarko for US$57 billion, up significantly from Chevron’s US$33 billion bid
  • The deal means that Occidental’s agreement to sell Anadarko’s African assets to Total for US$8.8 billion will also go through, covering the Hassi Berkine, Ourhoud and El Merk fields in Algeria, the Jubilee and TEN fields in Ghana, the Area 1 LNG project in Mozambiuqe and E&P licences in South Africa
  • BP has sanctioned the Thunder Horse South Expansion Phase 2 deepwater project in the US Gulf of Mexico, which is expected to add 50,000 boe/d of production at the Thunder Horse platform beginning 2021
  • Africa is proving to be very fruitful for Eni, as it announced a new gas and condensate discovery offshore Ghana; the CTP-Block 4 in the Akoma prospect is estimated to hold some 550-650 bcf of gas and 18-20 mmbl of condensate
  • In an atypical development, South Africa has signed a deal for the B2 oil block in South Sudan, as part of efforts to boost output there to 350,000 b/d
  • Shell expects to drill its first deepwater well in Mexico by December 2019 after walking away with nine Mexican deepwater blocks last year

Midstream & Downstream

  • China’s domestic crude imports surged to a record 10.64 mmb/d in April, as refiners stocked up on an Iranian crude bonanza due to uncertainty over US policy, which has been confirmed as crude waivers were not renewed
  • Having had to close the Druzhba pipeline and Ust-Luga port for contaminated crude, Russia says it will fully restore compliant crude by end May shipments, including cargoes to Poland and the Czech Republic
  • Mexico’s attempt to open up its refining sector has seemingly failed, with Pemex taking over the new 340 kb/d refinery as private players balked at the US$8 billion price tag and 3-year construction deadline
  • Ahead of India’s move to Euro VI fuels in April 2020, CPCL is partially shutting down its 210 kb/d Manali refinery for a desulfurisation revamp
  • China’s Hengli Petrochemical is reportedly now stocking up on Saudi Arabian crude imports as it prepares to ramp up production at its new 400 kb/d Dalian refinery alongside its 175 kb/d site in Brunei
  • South Korea’s Lotte Chemical Corp expects its ethane cracker in Louisiana to start up by end May, adding 1 mtpa of ethylene capacity to its portfolio
  • Due to water shortage, India’s MRPL will be operating its 300 kb/d refinery in Katipalla at 50% as drought causes a severe water shortage in the area

Natural Gas/LNG

  • Partners in the US$30 billion Rovuma LNG project in Mozambique now expect to sanction FID by July, even after a recent devastating cyclone
  • Also in Mozambioque, Anadarko is set to announce FID on its Mozambique LNG project on June 18, calling it a ‘historic day’
  • After talks of a joint LNG export complex to develop gas resources in Tanzania, Shell and Equinor now appear to be planning separate projects
  • Gazprom has abandoned plans to build an LNG plant in West Siberia to compete with Novatek, focusing instead on an LNG complex is Ust-Luga
  • First LNG has begun to flow at Sempra Energy’s 13.5 mtpa Cameron LNG project in Louisiana, with exports expected to begin by Q319
May, 17 2019
Shell Eclipses ExxonMobil Once Again

The world’s largest oil & gas companies have generally reported a mixed set of results in Q1 2019. Industry turmoil over new US sanctions on Venezuela, production woes in Canada and the ebb-and-flow between OPEC+’s supply deal and rising American production have created a shaky environment at the start of the year, with more ongoing as the oil world grapples with the removal of waivers on Iranian crude and Iran’s retaliation.

The results were particularly disappointing for ExxonMobil and Chevron, the two US supermajors. Both firms cited weak downstream performance as a drag on their financial performance, with ExxonMobil posting its first loss in its refining business since 2009. Chevron, too, reported a 65% drop in the refining and chemicals profit. Weak refining margins, particularly on gasoline, were blamed for the underperformance, exacerbating a set of weaker upstream numbers impaired by lower crude pricing even though production climbed. ExxonMobil was hit particularly hard, as its net profit fell below Chevron’s for the first time in nine years. Both supermajors did highlight growing output in the American Permian Basin as a future highlight, with ExxonMobil saying it was on track to produce 1 million barrels per day in the Permian by 2024. The Permian is also the focus of Chevron, which agreed to a US$33 billion takeover of Anadarko Petroleum (and its Permian Basin assets), only for the deal to be derailed by a rival bid from Occidental Petroleum with the backing of billionaire investor guru Warren Buffet. Chevron has now decided to opt out of the deal – a development that would put paid to Chevron’s ambitions to match or exceed ExxonMobil in shale.

Performance was better across the pond. Much better, in fact, for Royal Dutch Shell, which provided a positive end to a variable earnings season. Net profit for the Anglo-Dutch firm may have been down 2% y-o-y to US$5.3 billion, but that was still well ahead of even the highest analyst estimates of US$4.52 billion. Weaker refining margins and lower crude prices were cited as a slight drag on performance, but Shell’s acquisition of BG Group is paying dividends as strong natural gas performance contributed to the strong profits. Unlike ExxonMobil and Chevron, Shell has only dipped its toes in the Permian, preferring to maintain a strong global portfolio mixed between oil, gas and shale assets.

For the other European supermajors, BP and Total largely matched earning estimates. BP’s net profits of US$2.36 billion hit the target of analyst estimates. The addition of BHP Group’s US shale oil assets contributed to increased performance, while BP’s downstream performance was surprisingly resilient as its in-house supply and trading arm showed a strong performance – a business division that ExxonMobil lacks. France’s Total also hit the mark of expectations, with US$2.8 billion in net profit as lower crude prices offset the group’s record oil and gas output. Total’s upstream performance has been particularly notable – with start-ups in Angola, Brazil, the UK and Norway – with growth expected at 9% for the year.

All in all, the volatile environment over the first quarter of 2019 has seen some shift among the supermajors. Shell has eclipsed ExxonMobil once again – in both revenue and earnings – while Chevron’s failed bid for Anadarko won’t vault it up the rankings. Almost ten years after the Deepwater Horizon oil spill, BP is now reclaiming its place after being overtaken by Total over the past few years. With Q219 looking to be quite volatile as well, brace yourselves for an interesting earnings season.

Supermajor Financials: Q1 2019

  • ExxonMobil – Revenue (US$63.6 million, down 6.7% y-o-y), Net profit (US$2.35 billion, down 49.5% y-o-y)
  • Shell - Revenue (US$85.66 billion, down 5.9% y-o-y), Net profit (US$5.3 billion, down 2% y-o-y)
  • Chevron – Revenue (US$35.19 billion, down 5% y-o-y), Net profit (US$2.65 billion, down 27.2% y-o-y)
  • BP - Revenue (US$67.4 billion, down 2.51% y-o-y), Net profit (US$2.36 billion, down 9.2% y-o-y)
  • Total - Revenue (US$51.2billion, up 3.2% y-o-y), Net profit (US$2.8 billion, down 4.0% y-o-y)
May, 15 2019
EIA revises its crude oil price forecast upward as supply expectations change

monthly average Brent crude spot price

Source: U.S. Energy Information Administration, Short-Term Energy Outlook, January, April, and May 2019 editions

In its May 2019 edition of the Short-Term Energy Outlook (STEO), EIA revised its price forecast for Brent crude oil upward, reflecting price increases in recent months, more recent data, and changing expectations of global oil markets. Several supply constraints have caused oil markets to be generally tighter and oil prices to be higher so far in 2019 than previous STEOs expected.

Members of the Organization of the Petroleum Exporting Countries (OPEC) had agreed at a December 2018 meeting to cut crude oil production in the first six months of 2019; compliance with these cuts has been more effective than EIA initially expected. In the January STEO, OPEC’s crude oil and petroleum liquids production was expected to decline by 1.0 million b/d in 2019 compared with the 2018 level, but EIA now forecasts OPEC production to decline by 1.9 million b/d in the May STEO.

Within OPEC, EIA expects Iran’s liquid fuels production and exports to also decline. On April 22, 2019, the United States issued a statement indicating that it would not reissue waivers, which previously allowed eight countries to continue importing crude oil and condensate from Iran after their waivers expired on May 2. Although EIA’s previous forecasts had assumed that the United States would not reissue waivers, the increased certainty regarding waiver policy and enforcement led to lower forecasts of Iran’s crude oil production.

Venezuela—another OPEC member—has experienced declines in production and exports as a result of recurring power outages, political instability, and U.S. sanctions. In addition to supply constraints that have already materialized in 2019, political instability in Libya may further affect global supply. Any further escalation in conflict may damage crude oil infrastructure or result in a security environment where oil fields are shut in. Either situation could reduce global supply by more than EIA currently forecasts.

In the May STEO, total OPEC crude oil and other liquids supply was estimated at 37.3 million b/d in 2018, and EIA forecasts that it will average 35.4 million b/d in 2019. EIA assumes that the December 2018 agreement among OPEC members to limit production will expire following the June 2019 OPEC meeting.

annual changes in global liquids production

Source: U.S. Energy Information Administration, Short-Term Energy Outlook, January, April, and May 2019 editions

U.S. crude oil and other liquids production is sensitive to changes in crude oil prices, taking into account a lag of several months for drilling operations to adjust. As crude oil prices have increased in recent months, so too have EIA’s domestic liquid fuels production forecasts for the remaining months of 2019.

U.S. crude oil and other liquids production, which grew by 2.2 million b/d in 2018, is forecast in EIA’s May STEO to grow by 2.0 million b/d in 2019, an increase of 310,000 b/d more than anticipated in the January STEO. In 2019, EIA expects overall U.S. crude oil and liquids production to average 19.9 million b/d, with crude oil production alone forecast to average 12.4 million b/d.

Relative to these changes in forecasted supply, EIA’s changes in forecasted demand were relatively minor. EIA expects that global oil markets will be tightest in the second and third quarters of 2019, resulting in draws in global inventories. By the fourth quarter of 2019, EIA expects that inventories will build again, and Brent crude oil prices will fall slightly.

More information about changes in STEO expectations for crude oil prices, supply, demand, and inventories is available in This Week in Petroleum.

May, 15 2019