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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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Saudi Aramco Moves Into Russia’s Backyard

International expansions for Saudi Aramco – the largest oil company in the world – are not uncommon. But up to this point, those expansions have followed a certain logic: to create entrenched demand for Saudi crude in the world’s largest consuming markets. But Saudi champion’s latest expansion move defies, or perhaps, changes that logic, as Aramco returns to Europe. And not just any part of Europe, but Eastern Europe – an area of the world dominated by Russia – as Saudi Aramco acquires downstream assets from Poland’s PKN Orlen and signs quite a significant crude supply deal. How is this important? Let us examine.

First, the deal itself and its history. As part of the current Polish government’s plan to strengthen its national ‘crown jewels’ in line with its more nationalistic stance, state energy firm PKN Orlen announced plans to purchase its fellow Polish rival (and also state-owned) Grupa Lotos. The outright purchase fell afoul of EU anti-competition rules, which meant that PKN Orlen had to divest some Lotos assets in order to win approval of the deal. Some of the Lotos assets – including 417 fuel stations – are being sold to Hungary’s MOL, which will also sign a long-term fuel supply agreement with PKN Orlen for the newly-acquired sites, while PKN Orlen will gain fuel retail assets in Hungary and Slovakia as part of the deal. But, more interestingly, PKN Orlen has chosen to sell a 30% stake in the Lotos Gdansk refinery in Poland (with a crude processing capacity of 210,000 bd) to Saudi Aramco, alongside a stake in a fuel logistic subsidiary and jet fuel joint venture supply arrangement between Lotos and BP. In return, PKN Orlen will also sign a long-term contract to purchase between 200,000-337,000 b/d of crude from Aramco, which is an addition to the current contract for 100,000 b/d of Saudi crude that already exists. At a maximum, that figure will cover more than half of Poland’s crude oil requirements, but PKN Orlen has also said that it plans to direct some of that new supply to several of its other refineries elsewhere in Lithuania and the Czech Republic.

For Saudi Aramco, this is very interesting. While Aramco has always been a presence in Europe as a major crude supplier, its expansion plans over the past decade have been focused elsewhere. In the US, where it acquired full ownership of the Motiva joint venture from Shell in 2017. In doing so, it acquired control of Port Arthur, the largest refinery in North America, and has been on a petrochemicals-focused expansion since. In Asia, where Aramco has been busy creating significant nodes for its crude – in China, in India and in Malaysia (to serve the Southeast Asia and facilitate trade). And at home, where the focus has on expanding refining and petrochemical capacity, and strengthen its natural gas position. So this expansion in Europe – a mature market with a low ceiling for growth, even in Eastern Europe, is interesting. Why Poland, and not East or southern Africa? The answer seems fairly obvious: Russia.

The current era of relatively peaceful cooperation between Saudi Arabia and Russia in the oil sphere is recent. Very recent. It was not too long ago that Saudi Arabia and Russia were locked in a crude price war, which had devastating consequences, and ultimately led to the détente through OPEC+ that presaged an unprecedented supply control deal. That was through necessity, as the world faced the far ranging impact of the Covid-19 pandemic. But remove that lens of cooperation, and Saudi Arabia and Russia are actual rivals. With the current supply easing strategy through OPEC+ gradually coming to an end, this could remove the need for the that club (by say 2H 2022). And with Russia not being part of OPEC itself – where Saudi Arabia is the kingpin – cooperation is no longer necessary once the world returns to normality.

So the Polish deal is canny. In a statement, Aramco stated that ‘the investments will widen (our) presence in the European downstream sector and further expand (our) crude imports into Poland, which aligns with PKN Orlen’s strategy of diversifying its energy supplies’. Which hints at the other geopolitical aspect in play. Europe’s major reliance on Russia for its crude and natural gas has been a minefield – see the recent price chaos in the European natural gas markets – and countries that were formally under the Soviet sphere of influence have been trying to wean themselves off reliance from a politically unpredictable neighbour. Poland’s current disillusion with EU membership (at least from the ruling party) are well-documented, but its entanglement with Russia is existential. The Cold War is not more than 30 years gone.

For Saudi Aramco, the move aligns with its desire to optimise export sales from its Red Sea-facing terminals Yanbu, Jeddah, Shuqaiq and Rabigh, which have closer access to Europe through the Suez Canal. It is for the same reason that Aramco’s trading subsidiary ATC recently signed a deal with German refiner/trader Klesch Group for a 3-year supply of 110,000 b/d crude. It would seem that Saudi Arabia is anticipating an eventual end to the OPEC+ era of cooperative and a return to rivalry. And in a rivalry, that means having to make power moves. The PKN Orlen deal is a power move, since it brings Aramco squarely in Russia’s backyard, directly displacing Russian market share. Not just in Poland, but in other markets as well. And with a geopolitical situation that is fragile – see the recent tensions about Russian military build-up at the Ukrainian borders – that plays into Aramco’s hands. European sales make up only a fraction of the daily flotilla of Saudi crude to enters international markets, but even though European consumption is in structural decline, there are still volumes required.

How will Russia react? Politically, it is on the backfoot, but its entrenched positions in Europe allows it to hold plenty of sway. European reservations about the Putin administration and climate change goals do not detract from commercial reality that Europe needs energy now. The debate of the Nord Stream 2 pipeline is proof of that. Russian crude freed up from being directed to Eastern Europe means a surplus to sell elsewhere. Which means that Russia will be looking at deals with other countries and refiners, possibly in markets with Aramco is dominant. That level of tension won’t be seen for a while – these deals takes months and years to complete – but we can certainly expect that agitation to be reflected in upcoming OPEC+ discussions. The club recently endorsed another expected 400,000 b/d of supply easing for January. Reading the tea leaves – of which the PKN Orlen is one – makes it sound like there will not be much more cooperation beyond April, once the supply deal is anticipated to end.

End of Article

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Market Outlook:

-       Crude price trading range: Brent – US$86-88/b, WTI – US$84-86/b

-       Crude oil benchmarks globally continue their gain streak for a fifth week, as the market bounces back from the lows seen in early December as the threat of the Omicron virus variant fades and signs point to tightening balances on strong consumption

-       This could set the stage for US$100/b oil by midyear – as predicted by several key analysts – as consumption rebounds ahead of summer travel and OPEC+ remains locked into its gradual consumption easing schedule 

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