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Last Updated: June 26, 2020
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Overview 

  • Nigeria is the largest oil producer in Africa. It holds the largest natural gas reserves on the continent and was the world’s fifth–largest exporter of liquefied natural gas (LNG) in 2018.[1] Although Nigeria is the leading crude oil producer in Africa, production is affected by sporadic supply disruptions.
  • Nigeria’s crude oil and natural gas resources are the mainstay of the country’s economy. Because Nigeria heavily depends on oil revenue, its economy is noticeably affected by crude oil price changes. The International Monetary Fund (IMF) projects that Nigeria’s crude oil and natural gas exports earned $55 billion in 2018, which is $23 billion higher than in 2016.[2] The growth in export revenue, which can be partly attributed to the rebound in crude oil prices, has helped improve Nigeria’s fiscal position. However, Nigeria’s fiscal deficit remained flat at 4% of its gross domestic product (GDP) because of a significant increase in capital expenditures and lower–than–expected non–oil revenue collection, in spite of improvements to the country’s tax administration. The Nigerian government still heavily relies on crude oil and natural gas revenue; its non–oil revenue comprises only 3.4% of GDP, one of the lowest in the world.[3]


Sector organization

Recent updates

  • In September 2018, President Muhammadu Buhari vetoed the Petroleum Industry Governance Bill (PIGB) that was passed by the legislature in March 2018, which delayed efforts to liberalize the oil and natural gas sector and restructure the Nigerian National Petroleum Corporation (NNPC). The PIGB is one of four separate bills that were taken from the previous version, the Petroleum Industry Bill (PIB). Latest reports indicate that the National Assembly is drafting a new version of the PIB and is hoping to pass the bill by the end of 2020, although when or if this action will occur is unclear.[4]
  • The Nigerian government passed the Finance Act 2020 in January 2020. This act amends a number of tax laws and is aimed at improving tax participation and collection and modernizing the tax system. Provisions in the bill, such as the Petroleum Profits Tax (which repeals a tax exemption for dividends paid from after–tax profits), a value–added tax (which increases from 5% to 7.5%), and the Companies Income Tax (which requires Nigerian companies to deduct and withhold tax on payments to any foreign company that provides them with technical or professional services), are likely to affect oil and natural gas companies and increase their overall cost of doing business in the country.[5]
  • The Finance 2020 Act follows a November 2019 amendment to the 1999 Deep Offshore and Inland Basin Production Sharing Contracts Act, which changed royalty rates for deepwater (specifically greater than 200 meters in water depth) and inland basin contracts (which comprise onshore basins aside from the Niger Delta) to 10% and 7.5%, respectively. The amendment also introduces an additional royalty tax rate that ranges from 0% to 10% based on the price of crude oil. Given that international oil companies (IOCs) primarily operate in the deepwater fields in Nigeria, this amendment is likely to increase government’s share of revenue generated from these fields and to lead investors to re–evaluate their investment plans for currently producing fields as well as new–source development.[6]


Petroleum and other liquids

Exploration and production

  • According to the Oil & Gas Journal, Nigeria had an estimated 37.0 billion barrels of proved crude oil reserves by the end of 2019–the second–largest amount in Africa after Libya.[7] The majority of reserves are along the country’s Niger River Delta and offshore in the Bight of Benin, the Gulf of Guinea, and the Bight of Bonny.
  • As a member of the Organization of the Petroleum Exporting Countries (OPEC), Nigeria renewed its commitment to reduce crude oil production in April 2020, capping its production at 1.41 million barrels per day (b/d).[8] The agreement takes effect on May 1, 2020, and ends on April 30, 2022.[9] However, Nigeria’s compliance with the OPEC+ agreement has been intermittent; the country has at times produced more than the agreed-upon quota in the past. In addition, Nigeria has designated some of its crude oil streams as lease condensate, which is not subject to the OPEC+ agreement production cuts, which allows Nigeria to circumvent its obligation to reduce production.
  • In 2019, Nigeria produced about 2.0 million b/d of petroleum and other liquids, of which 1.65 million b/d was crude oil. The remainder is composed of natural gas plant liquids, other liquids, and refinery processing gains[10] (Figure 1).
  • The deepwater Egina project was the latest significant field to come online in Nigeria. The Egina field came online in January 2019 and reached its peak production plateau of 200,000 b/d at the end of 2019. The Nigerian minister of petroleum, Emmanuel Kachikwu, has labeled Egina crude oil as a condensate, in spite of its API gravity and sulfur content being specified at 27° and 0.17%, respectively, a crude oil assay that would place it in the medium, sweet categories.[11]
  • Smaller fields, such as the offshore Gbetiokun field and the onshore Qua Ibo field in the eastern part of the Niger Delta, have provided marginal increases to Nigeria’s crude oil production in the past year.[12] These projects have helped to partially offset production declines at Nigeria’s older, more mature fields. Other planned deepwater projects have been repeatedly delayed because of regulatory uncertainty surrounding the PIB. In addition, the recent deepwater royalty tax increase may further inhibit investor interest in exploration and development of new offshore fields.
  • Exploration activities have largely focused in deepwater and ultra-deepwater offshore fields, partially as a result of security concerns onshore, and many IOCs have divested their onshore assets. The NNPC plans to launch a new crude oil licensing round in mid–2020, although the licensing round will likely be postponed until after the PIB legislation issue is resolved later this year. Whether or not there will be sufficient investor interest if the PIB does not pass is unclear, given the recent amendments to the royalty tax structure for deepwater production.[13]


Refining and refined oil products

  • Nigeria relies on imports of petroleum products to meet domestic demand, importing about 442,000 b/d of petroleum products in 2018.[14]
  • The country has three major crude oil refineries (Port Harcourt I and II, Warri, and Kaduna) and has a total crude oil distillation capacity of 423,750 b/d, according to the Oil & Gas Journal.[15] All three refineries are run by the state–owned national oil company (NOC), NNPC. These refineries persistently operate at far lower than full capacity because of operational failures, fires, and sabotage, mainly on the crude oil pipelines feeding the refineries. NNPC has begun rehabilitation work at its refineries, and the NNPC’s latest reports indicate that the refineries have been shuttered. The rehabilitation work is expected to be completed by 2022, although how much throughput the refineries will have after rehabilitation is unclear. NNPC stated in April 2020 that it will no longer run the refineries after rehabilitation and is reportedly seeking a private sector company to manage operations at the refineries.[16]
  • A small, privately owned refinery located in Ogbele, Ahoada, in the Rivers state expanded its refining capacity to 6,000 b/d in January 2020. The expansions completed at the refinery will allow it to produce and market other fuels such as heavy residual fuel oil, marine diesel, and kerosene. Previously, diesel was the only petroleum product the refinery could produce. The refinery is owned by Niger Delta Petroleum Resources (NPDR), a subsidiary of Niger Delta Exploration and Production; NPDR plans to further increase the refinery’s capacity to 11,000 b/d in the future, although they have not released any concrete dates.[17]
  • Nigeria has a gas–to–liquids (GTL) plant at Escravos with a nameplate capacity of 33,000 b/d that started production in mid–2014, about a decade behind schedule. The Escravos GTL plant is operated by Chevron (75%) in partnership with NNPC (25%). The Escravos GTL plant can convert about 475 million cubic feet per day (MMcf/d) of natural gas into diesel, liquefied petroleum gas (LPG), and naphtha products, primarily for export.[18]
  • The Dangote Group, a Nigerian conglomerate, is constructing an integrated refining and petrochemical complex in the Lekki Free Trade Zone east of Lagos, Nigeria’s most populous city. The Dangote Group expects the refinery to come online by 2021, although the refinery is not likely to be completed on time.[19] According to the Oil & Gas Journal, the refining and petrochemical complex will have a 650,000 b/d crude oil distillation unit (making it the world’s largest single–train refinery), a 3.6 million ton per year polypropylene plant, a 3.0 million ton per year urea plant, and natural gas processing installations to feed in natural gas.[20] Once completed, it will be the largest refinery in Africa and is expected to significantly affect domestic and regional crude oil and petroleum products markets.


Petroleum and other liquids

According to the latest estimates by Global Trade Tracker, Nigeria exported about 2.08 million b/d of crude oil and condensate in 2019. India was the largest importer of Nigeria’s crude oil and condensate, purchasing about 420,000 b/d in 2019. Spain and the Netherlands were the next largest importers of Nigeria’s crude oil and condensate, each importing about 238,000 and 208,000 b/d in 2019, respectively. The United States was the fourth–largest importing country of Nigeria’s crude oil and condensate in 2019. Europe continued to be the largest importer by region, importing nearly 1 million b/d[21] (Figure 2).


Natural gasExploration and production


  • Nigeria had an estimated 200.4 trillion cubic feet (Tcf) of proved natural gas reserves by the end of 2019, according to the Oil & Gas Journal. Nigeria has the largest natural gas reserves in Africa.[22]
  • According to the latest estimates by EIA, Nigeria produced 1.6 Tcf of dry natural gas (or marketed natural gas production) in 2019.[23] Nigeria’s natural gas industry is also affected by the same security and regulatory issues that affect the crude oil industry.
  • A significant amount of Nigeria’s gross natural gas production is either re–injected or flared. Some of Nigeria’s oil fields lack the infrastructure to capture the natural gas produced with oil, known as associated gas. According to the most recent data by the World Bank’s Global Gas Flaring Reduction Partnership (GGFR), Nigeria flared about 261 billion cubic feet (Bcf) of natural gas in 2018, making Nigeria the seventh–largest natural gas flaring country in terms of annual natural gas flaring volume.[24]
  • In December 2019, Nigeria LNG (NLNG) reached financial close, or its final investment decision, to add a seventh train to its existing facility, adding about 365 Bcf, thus increasing the total capacity of the facility to 1.4 Tcf. The expansion project was initially proposed in 2005 but encountered numerous delays. NLNG expects the project to be completed by 2024, and it will be operated by Shell (25.6%), and the other shareholders are NNPC (49%), Total (15%), and Eni (10.4%)[25] (Figure 3).


Natural gas exports
  • Nigeria exports natural gas primarily as LNG. Both infrastructure and demand constraints are challenges to exporting primarily by pipeline to neighboring countries. Nigeria began exporting LNG in 1999 when the first two trains at the Bonny Island facility were completed.[26]
  • According to the latest estimates in BP’s 2019 Statistical Review of World Energy, Nigeria exported about 982 Bcf of LNG in 2018, ranking Nigeria as the world’s fifth–largest LNG exporter, behind Qatar, Australia, Malaysia, and the United States. Nigeria’s LNG exports accounted for about 6.5% of LNG traded globally. Spain was the largest importer of Nigeria’s LNG in 2018, importing about 146 Bcf of Nigeria’s LNG, followed by India (143 Bcf), and France (126 Bcf)[27] (Figure 4).


Energy consumption
  • According to EIA’s latest estimates, total primary energy consumption in Nigeria was about 1.5 quadrillion British thermal units in 2017. Most primary energy consumption in the country was derived from natural gas, petroleum, and other liquids (97%). Traditional biomass and waste (typically consisting of wood, charcoal, manure, and crop residues used for power generation), coal, and renewables accounted for only a marginal amount of consumption (3%) in 2017.[28]


Electricity
  • Nigeria’s generation capacity was 12,664 megawatts (MW) in 2017, of which 10,522 MW (83%) was from fossil fuels; 2,110 MW (17%) was from hydroelectricity; and 32 MW (1%) was from solar, wind, and biomass and waste. Net electricity generation was far lower than capacity and was 30.6 billion kilowatthours (3,495 MW) in 2017, or about 28% of total capacity.[29]
  • Although Nigeria is the continent’s largest economy, only 60% of the population had access to electricity in 2018, according to the latest estimates by the International Energy Agency. Most of Nigeria’s fossil fuel–derived electricity generation is from natural gas, and crude oil is mainly used for backup power generation. Nigeria’s power sector suffers from poor maintenance of electricity facilities, natural gas supply shortages, and an inadequate transmission and distribution network.[30]


Renewable Energy Sources
  • Nigeria has set ambitious goals to increase renewable power generation capacity. The Nigerian government has approved the contract to develop the 3.01 GW Mambilla hydropower plant located in the Taraba state. The Exim Bank of China will provide 85% of the required financing to develop the project, and the contract to construct the facility was awarded in November 2017 to a consortium of three Chinese companies, including the Gezhouba Group.[31] Other significant hydropower projects that are currently in development or construction include the 700 MW Zungeru hydropower project and the 40 MW Kashimbila hydropower project, which are currently under construction, and the rehabilitation of the 578 MW Jebba hydropower project and the 548 MW Kainji hydropower project. These projects are reportedly due to come online in the next two to three years, but whether the completion dates will be postponed because of project delays is still unclear.[32]
  • Government support and investor interest in solar power projects have been growing in the past few years in Nigeria, partially as a way to mitigate natural gas supply shortages and to increase access to electricity in remote and rural areas. The Nigerian government, the Rural Electrification Agency, and the World Bank–funded Nigeria Electrification Project are jointly funding a $75 million grant to encourage off–grid solar investments to reduce kerosene and diesel use for lighting and backup power generation.[33] In July 2016, Nigeria signed power purchase agreements with 14 utility–scale solar photovoltaic facilities that have a total generation capacity of 1.1 GW, although none of these projects has yet reached financial close, and reportedly the independent power producers and the Nigerian government have a dispute regarding tariff pricing.[34]

renewable energy electricity energy consumption natural gas exports imports exploration production petroleum Nigeria refined oil products oil EIA
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U.S. natural gas exports to Mexico set to rise with completion of the Wahalajara system

Exports of natural gas to Mexico by pipeline are the largest component of U.S. natural gas trade, accounting for 40% of all U.S. gross natural gas exports in 2019. EIA expects these exports to increase with the completion of the southern-most segment of the Wahalajara system, the Villa de Reyes-Aguascalientes-Guadalajara (VAG) pipeline. VAG began operations in June 2020, connecting new demand markets in Mexico to U.S. natural gas pipeline exports.

The Wahalajara system is a group of new pipelines that connects the Waha hub in western Texas, a major supply hub for Permian Basin natural gas producers, to Guadalajara and other population centers in west-central Mexico. The Wahalajara system provides U.S. natural gas to meet growing demand from Mexico’s electric power and industrial sectors. With the 0.89 billion cubic feet per day (Bcf/d) VAG pipeline entering service, EIA expects utilization of the Wahalajara system to quickly ramp up, resulting in increased U.S. natural gas exports to Mexico out of western Texas and additional takeaway capacity out of the Permian Basin.

Since 2016, Mexico has been expanding its natural gas pipeline system, which has supported continual growth in U.S. natural gas exports. Most of this growth has been in U.S. natural gas exports from southern Texas after the existing U.S. pipeline infrastructure was expanded and the Los Ramones Phase II pipeline in central Mexico was completed.

Since the Sur de Texas-Tuxpan pipeline was completed in September 2019, U.S. natural gas exports to Mexico reached a record 5.5 Bcf/d in October 2019. U.S. natural gas exports from the border at Brownsville, Texas, to the southeastern state of Veracruz in Mexico averaged 0.6 Bcf/d during the last quarter of 2019, or about 20% of the pipeline’s capacity.

Overall, U.S. natural gas exports from this region have only increased by 0.2 Bcf/d from 2016 to 2019 because of delays in pipeline construction in Mexico. In particular, two regional pipelines were completed in 2017 but have not been used near their capacity:

  • The 1.1 Bcf/d Comanche Trail pipeline, which delivers natural gas to Mexico from San Elizaro, Texas
  • The 1.4 Bcf/d Trans-Pecos pipeline, which crosses the border at Presidio, Texas 

U.S. monthly natural gas exports to Mexico by region

Source: U.S. Energy Information Administration, Natural Gas Monthly

The Comanche Trail pipeline has been delivering an average of 0.1 Bcf/d of natural gas to Mexico since the San Isidro-Samalayuca pipeline entered service in June 2017. Pipeline operators do not expect flows to rise until the 0.47 Bcf/d Samalayuca-Sásabe pipeline is completed in either late 2020 or early 2021 in Mexico.

The Trans-Pecos pipeline, the U.S. segment of the Wahalajara system, did not transport significant volumes of natural gas until October 2018; it is currently only operating at 10% to 15% of its total capacity. Most of the demand centers are in southern Mexico, waiting to be connected to the VAG pipeline. Three of the project’s four pipelines in Mexico that are currently in-service include

  • Ojinga-El Encino: 1.4 Bcf/d, entered service in June 2017
  • El Encino-La Laguna: 1.5 Bcf/d, entered service in January 2018
  • La Laguna-Aguascalientes: 1.2 Bcf/d, entered service in December 2019

Before the economic impacts and uncertainty associated with COVID-19 mitigation efforts and declining crude oil prices, S&P Global Platts expected U.S. natural gas exports to Mexico to increase immediately by 0.3 Bcf/d to 0.4 Bcf/d on the Wahalajara system. However, given the decreased demand for natural gas in Mexico in response to the economic impact of COVID-19 mitigation efforts, growth is likely to be slower than expected. Beyond these volumes, additional export volumes will be limited by how quickly customers in Mexico can be connected to the pipeline system.

These connections include new natural gas-fired combined-cycle generators and the scheduled 2020 completion of the 0.89 Bcf/d Tula-Villa de Reyes pipeline, which will deliver natural gas to central Mexico. Deliveries from the Wahalajara network are likely to partially displace higher-cost liquefied natural gas (LNG) imports into Mexico’s Manzanillo terminal, which serves markets in Guadalajara and Mexico City.

As U.S. natural gas exports on the Wahalajara system rise and crude oil prices remain low, EIA expects the price at the Waha hub in the Permian Basin, which had been steeply discounted to the Henry Hub national benchmark, to continue to strengthen.

July, 07 2020
The Oil World’s Ongoing Impairments

Officially, we are past the half point of 2020 and with that the end of the second quarter. And what a quarter it has been. WTI prices plunged into negative territory (as low as -US$37/b) then recovered to US$40/b as OPEC+ moved from infighting to coordinating the largest crude production cut in history. In between, the Covid-19 pandemic wreaked havoc with the global economy, setting off a chain reaction within the oil world whose full impact is still unknown.

Opinions on a post-Covid oil world are divided. Some voices, the more optimistic ones, think that oil demand could recover to pre-Covid levels within a year or two. The more pessimistic ones think that this will never happen, that Covid-19 has hastened the trend away from fossil fuels to sustainable energy against the backdrop of climate change. Either way, this has thrown a spanner in the works of the giant, multi-billion oil and gas projects that were announced over the past two years as the energy world began to wake up from its post-2015 price crash investment hibernation. Those projects were made at a time when oil prices were at US$50-60/b. Since oil prices are now only at US$40/b, the current value and the future worth of these assets have now declined. Energy companies account for this by adjusting the value of their portfolios in accordance to the projected value of crude: an upward adjustment is known as a revaluation, and a negative one is known as an impairment.

This is a term that will crop up many times over 2020, as energy companies close their quarterly financial books and report their results to shareholders. The plunge in crude oil prices and the uncertain outlook for oil demand means that publicly-traded companies must account for this to their shareholders. Chevron was the first supermajor to book an impairment, in late 2019 when it took a US$10 billion hit to its oil and gas assets. It wasn’t the only one: firms all across the oil chain also reduced the value of their assets, from Repsol to Equinor.

Further impairments were made in April 2020 when the Q1 financial results were announced, mainly in response to the triggering of the OPEC+ price war (which saw crude prices halve from US$60/b to US$30/b) and the Covid-19 pandemic accelerating to a point where over half of the world’s population went into lockdown. But the major impact will come in Q2 2020, when the roil in the oil markets truly began to boil uncontrollably. BP has announced that it may take up to a US$17.5 billion impairment in its Q2 2020 financial results, while Shell has just admitted that it may have to shave US$22 billion from its asset value.

This has roots not just in the depressed demand for energy due to Covid-19, but also the ongoing conversation on climate change. Almost all supermajors have announced intentions to become carbon neutral by the 2050 timeframe. That may be good news for the planet, but it is bad news for the companies’ portfolio. Put simply, it means that some of the assets that they have invested billions in are now not only worth a lot less (due to Covid-19) but they may in fact be worth nothing at all, because climate change considerations mean that they will never be exploited. Challenging projects such as Total’s deepwater Brulpadda discovery in turbulent South African waters or Pertamina/ExxonMobil/Total/PTTEP’s beleaguered and complicated East Natuna sour gas asset in Indonesia may never be commercialised, either because of uneconomic prices or because they run counter to the goal of becoming carbon neutral. The Financial Times estimates that the amount of unviable or stranded hydrocarbon assets could reach as much as US$900 billion; that figure is pre-Covid, and could now become even higher.

There is one supermajor bucking the trend though. The biggest supermajor of all, in fact. Unlike its peers, ExxonMobil has not yet succumbed to impairments. If fact, it has not announced any negative revaluations at all over the past decade, even during the 2015 oil price crash. ExxonMobil claims that this is because it books the value of new assets ‘very conservatively’ and does not ‘adjust values to short-term price trends’, but critics say that it has an ongoing history of vastly overestimating its assets’ value. Along with Chevron, ExxonMobil does not disclose price assumptions in its financials. But unlike Chevron, ExxonMobil has not yielded to climate change through an official emissions target or asset revaluations.

On paper, that will make ExxonMobil look better than its supermajor brothers. But behind the scenes, this reluctance to admit that the future is less rosy than expected could be trouble waiting to be unleashed. Impairments are a necessary reality check: an admission by a company that things have changed and it is starting to adapt. Most have accepted that reality. ExxonMobil seems to be resisting. But even it is not immune. In pre-Q2 2020 results guidance that was just announced, ExxonMobil admitted that it expects to take a hit of some US$3.1 billion and slump to a second straight quarterly loss. In terms of Covid-19 impairments, that’s small. But it is, at least, a start.

Market Outlook:

  • Crude price trading range: Brent – US$40-44/b, WTI – US$38-42/b
  • A swathe of positive economic data is supporting oil prices within its current range, with US light crude settling above US$40/b for the first time in four months
  • The relaxation of Covid-19 restrictions has led to improvements in most economic indicators, but the risk of the situation reversing is also higher, given the accelerating cases being reported in part of the USA, South America and India
  • On the supply side, OPEC+ is making adherence a priority, with lagging members now bucking up and swing producer Saudi Arabia also keeping its promises by throttling crude exports in June to some 5.7 mmb/d

End of Article

In this time of COVID-19, we have had to relook at the way we approach workplace learning. We understand that businesses can’t afford to push the pause button on capability building, as employee safety comes in first and mistakes can be very costly. That’s why we have put together a series of Virtual Instructor Led Training or VILT to ensure that there is no disruption to your workplace learning and progression.

Find courses available for Virtual Instructor Led Training through latest video conferencing technology.


July, 04 2020
Changing Investment Winds In The Middle East

The sale of a mere 5% stake in the oil world’s crown jewel, Saudi Aramco had captured the attention of the entire investment community last year. Pushing through after years of debate and delays, the sale on the Tadawul stock exchange valued Aramco at a whopping initial US$1.6 trillion. Investors were mainly connected Saudi individuals and wealthy families, with international buy-in limited as a planned parallel listing on the London or New York Stock Exchange fell through. Still, the deal was enough to unleash several thousand pages of speculation and opinion over potential liberalisation of the oil and gas complex in the Middle East, especially the upcoming post-oil and carbon-neutral environment.

Aramco may have captured all the main headlines, especially with its huge acquisition of fellow Saudi jewel SABIC but the true entity pushing the boundaries of privatisation and deregulation in the Middle East is elsewhere. Specifically, just east of Saudi Arabia, in Abu Dhabi – the largest and most influential of the seven emirates that make up the UAE.

The latest headline involving ADNOC, Abu Dhabi’s state oil firm, hasn’t really made the rounds beyond the industry’s eyes but it is crucial to understanding how the Middle East oil sector could adapt to the changing industry over the next few decades. Partnering with a consortium of six investors, ADNOC has sold a 49% stake in its ADNOC Gas Pipeline Assets subsidiary, retaining a 51% majority stake and control. The sale had been bandied around for over a year, seen as a sign of a gradual opening of a tightly controlled oil and gas region, and follows three other significant sales involving ADNOC. The first was in 2017, when ADNOC raised nearly a billion US dollars through an IPO of its fuels distribution unit on the Abu Dhabi Securities Exchange, offering up 10% of its shares. Then late 2019, ADNOC partnered with Italy’s Eni and Austria’s OMV to nearly double oil refining capacity in Abu Dhabi to 1.5 mmb/d – the largest foreign participation in the Middle East downstream industry since the Shell Pearl GTL project in Qatar and Total’s Jubail refining and petrochemicals push over a decade ago. Around the same time, ADNOC also pocketed US$4 billion from US investment giants BlackRock and KKR through the sale of a 40% stake in its ADNOC Oil Pipelines subsidiary. And now it is the turn of ADNOC’s gas pipelines.

The chronology and regional aspect of ADNOC’s moves is interesting. While Aramco looks local, Abu Dhabi went abroad. The refining expansion involved established oil market players, Eni and OMV – and parallels a gradual unbundling of Abu Dhabi’s upstream concessions, where stakes have been offered to Total, PetroChina, Eni, Cepsa and India’s ONGC over the past five years. But the choice of new investors are now not from the industry. After the deep-pocketed BlackRock and KKR, ADNOC has once against turned to institutional investors for its latest, and largest, sale, with the US$20.7 billion gas pipeline and infrastructure deal going to a consortium consisting of Global Infrastructure Partners (GIP), Brookfield Asset Management, Ontario Teacher’s Pension Plan Board, Singapore’s GIC sovereign wealth fund, NH Investment and Securities and Italy’s infrastructure operator SNAM. ADNOC called the deal a ‘landmark investment (that) signals continued strong interest in ADNOC’s low-risk, income-generating assets’. But it also illustrates two other points: institutional interest in strategic Middle East assets and the challenging environment within the industry because of Covid-19 that has led investment interest expanding to new capital that is currently reluctant to make risky bets in an unstable economic environment. So the choice of ADNOC’s safe assets and a captive domestic market is rather attractive.

ADNOC’s strategy differs from Aramco’s fundamentally. Where Aramco sold a stake of itself, ADNOC has parcelled out different parts of itself while keeping control of the main body intact. This is what Malaysia’s Petronas has done to a great degree of success, listing subsidiaries through IPOs and partnering with foreign investors on upstream/downstream projects, using the proceeds to finance a global expansion that now stretches across all continents. Replicating this strategy, as ADNOC looks to be doing, could pay dividends, particularly since ADNOC has a wider domestic base, as well as stronger export markets, than Petronas. Between Saudi Aramco and ADNOC, the OPEC duo seems to have kickstarted a liberalisation drive within the Middle East energy complex. Kuwait Petroleum and Bahrain’s BAPCO are already reported to be considering similar moves. Which model could this second wave follow: Aramco’s or ADNOC’s? Aramco’s is a shock-and-awe move, a potential wow factor at the size of any possible deal. But ADNOC’s more piecemeal approach could actually be far more stable and sustainable over time.

Market Outlook:

  • Crude price trading range: Brent – US$39-42/b, WTI – US$37-40/b
  • Signs that the oil demand recovery has been better-than-expected as economies re-open have been tempered by fears that a resurgence of Covid-19 infections is on the horizon
  • The US recorded its highest single-day case number this week, while Europe recorded its first increase in a month and cases in Latin America and India are accelerating, prompting fears that a second round of lockdowns was necessary
  • Economies will have more time to prepare for a second round of lockdowns, but the disruption will still snuff out any current nascent improvement in demand
  • This will weigh heavily on OPEC, as it now has to consider another extension beyond the end of July, although compliance has improved among the OPEC+ club as Iraq, Kazakhstan, Nigeria, Angola, Gabon and Brunei all submitted new output schedules

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End of Article

In this time of COVID-19, we have had to relook at the way we approach workplace learning. We understand that businesses can’t afford to push the pause button on capability building, as employee safety comes in first and mistakes can be very costly. That’s why we have put together a series of Virtual Instructor Led Training or VILT to ensure that there is no disruption to your workplace learning and progression.

Find courses available for Virtual Instructor Led Training through latest video conferencing technology.


June, 26 2020