Getting upstream oil and gas projects off the ground in sub-Saharan Africa was challenging before the Covid-19 pandemic. Now the operating environment is even tougher, as the industry contends with labour restrictions, disrupted supply chains and the long-term impact on revenues and investment of the collapse in global demand for energy products.
International oil companies that previously regarded the acquisition of new hydrocarbons reserves as a primary indicator of their corporate health are now touting the benefits of prudent investment in their existing oil and gas assets and diversification away from riskier upstream activities. That means all but the most attractive, low-cost African acreage will be a hard sell to international investors.
This is not good news for either Africa’s would-be entrants to the oil sector promoting frontier acreage, such as Somalia, or for established exporters seeking to shore up dwindling output – and revenues – from existing production through investment in more marginal fields and satellite developments.
The region’s largest oil exporters, Nigeria and Angola, fall into the latter category. Nigeria’s central bank reported in August that the value of the country’s crude oil exports fell to $9.48bn in the first quarter 2020, as the pandemic gathered momentum – a 20% drop compared with the previous quarter. The price of Nigeria’s Bonny light crude was over $65/barrel last December but below $15/barrel by April.
Fitch Ratings downgraded Angola to CCC in early September. It cited the fall in global oil prices, which it says has exacerbated key vulnerabilities in the Angolan economy, leading to lower external receipts and a sustained weakening of the country’s currency, the kwanza, which has resulted in increasing debt servicing costs and downward pressure on fiscal and external buffers.
Recovery in sight?
However, the picture is not one of unmitigated gloom for African upstream. If a resurgence of coronavirus infections can be averted, the worst impacts of the pandemic on the industry could be behind it.
Global oil prices have recovered from their lows, with Brent crude trading at almost $40 in early September, up from lows of $20 in mid-April, indicating demand recovery that could bolster investment.
It will still be a tough task. Most of the African oil and gas projects for which final investment decisions were originally planned for 2020 require an oil price of $40 and upwards – some much higher – just to break even.
Some areas of Africa have been less badly hit by Covid-19 than other parts of the world, allowing work to continue on hydrocarbons projects already in progress, albeit at a reduced pace. Nevertheless, the international nature of the oil industry, both in terms of personnel and equipment supply, has led to several projects being put on hold. Now, as international trade and travel resume, these projects can get back on track.
This is leading to more confident talk from upstream developers about getting projects operational as originally envisaged or with slight delays.
Prospects look good in Senegal
In one of the continent’s emerging upstream hotspots, Senegal, Woodside Energy says it still expects the first phase of its $4bn-plus Sangomar oil project to come on stream in 2023, as planned prior to the pandemic. The Australian company said in August it could achieve this because it had “taken early action to proactively manage the emerging impacts of Covid-19 on the supply chain and project schedule”. When operational, the project will use a floating production storage and offloading facility to produce 100,000 barrels per day (b/d) of oil and 130m cubic feet/day of gas.
However, all has not been running smoothly with the project. Australian junior partner FAR Ltd, which holds a 13.67% stake, had to give up on plans to raise more than $300m needed for its share of the work programme for the project when the oil price collapsed and has been looking to sell the stake. Another Sangomar partner, UK-based Cairn Energy, agreed to sell its 40% stake in the project to Russia’s Lukoil, only for Woodside to say in August it would use its pre-emption rights to block that deal and buy the stake itself.
Meanwhile, BP says first gas from its Greater Tortue/Ahmeyim floating LNG export project, on the Senegal-Mauritania maritime border, will be delayed by around a year to the first half of 2023, as the coronavirus outbreak prevented the company using this year’s weather window to build a breakwater for the scheme. The project is reportedly already 40% completed.
Mozambique gears up for gas
Across the continent in Mozambique, there is a mixed picture for two onshore mega-projects exploiting the country’s huge offshore gas reserves, mainly for exports to the energy demand centres of Asia.
The $20bn-plus Mozambique LNG project, led by France’s Total, has successfully secured up to $16bn of financing from a plethora of lending institutions, Bloomberg reported in July. This reflects the perceived importance of the project to energy security in countries such as Japan and India. The Japan Bank for International Cooperation signed a loan agreement which could cover $3bn of the total.
The future of ExxonMobil’s Rovuma LNG project, planned for the same location, is less certain. Unlike Total, Exxon has yet to make a final investment decision on its project and said in April that, as part of swingeing cutbacks in its global operations, it would delay doing so until after the end of 2020. The company said it was in talks with its Rovuma partners over cost-saving measures.
Both projects are under threat from an insurgency by a group with connections to Islamic State, which has carried out scores of attacks, largely in Cabo Delgado province where the facilities are being developed. Total recently signed a security pact with the Mozambique government to protect the area.
Projects in the balance
Other planned projects in sub-Saharan Africa that have yet to get under way are also in jeopardy. Progress to develop onshore oil export projects in both Kenya and Uganda have been chequered, and the Covid-19 pandemic has added another layer of uncertainty for developments whose economic viability remain questionable.
In Kenya, Tullow Oil, Total and Africa Oil issued a force majeure notice in May 2020, which said the partners could not meet their contractual engagements for the development of their project to export oil to the coast via pipeline from the remote Lake Turkana region, due to restrictions resulting from the pandemic.
That notice was withdrawn in August as conditions improved, but the project still faces a host of problems, including securing key water and land access and the need to finance and build export infrastructure – not least the 80,000-120,0000 b/d pipeline to Lamu port. Additionally, Tullow and Total have thus far failed to sell part of their stakes in the project, as they seek to spread the financial risk.
Elsewhere there has been progress. Uganda and Tanzania have signed a $3.5bn oil pipeline deal that advances Kampala’s long-delayed plans to develop its Lake Albert oil industry.
Total is also making progress in South Africa, where it is drilling near its gas discovery off the country’s southern coast in search of more reserves. Early estimates suggest Brulpadda could hold around 500m-600m barrels of oil equivalent. That would be more than enough for a commercial development and South Africa could provide a ready domestic market.
Ultimately, many African upstream producers remain dependent on a speedy resolution of the Covid-19 crisis in order to protect vulnerable projects and boost oil demand in the global economy, allowing them to forge ahead with progress at major fields.
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