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Vol 61 No 12

Published 11th June 2020

From great crash to weak bounce

The pandemic is forcing oil producers to find new ideas to attract investment and absorb the shocks. Some show promise. Others may have left it too late

Copyright © Africa Confidential 2020

The great hopes of strong growth for Africa's oil and gas producers this year, particularly in East and Southern Africa, have been crushed as companies scramble to cut planned investments across the continent to preserve cash-flow.

Multi-billion-dollar investment in new production has been delayed or deferred, and high-risk exploration wells have been shelved while many governments hold off from auctioning new exploration blocks until the market improves. The weak recovery of oil prices over the past month is not enough to change the big companies' calculations. 

For now, falls in production should be modest as Africa's OPEC members cut output to meet their new cartel quotas. But a protracted period of sub-$30 a barrel prices could force operators to shut in wells. Whether or not they do, production will fall more steeply in 2021 as the effects of the delays and production halts feed through.

Rystad, a Norwegian-based energy consultancy, has identified 13 major projects awaiting Final Investment Decisions (FID) that are now under threat (See diagram and map). That could cut oil production in Africa by 200,000 barrels a day over the next five years, and then perhaps falling further, by over a million a day, calculates Rystad.

Copyright © Africa Confidential 2020

Several African governments were adjusting investment terms in the wake of the changed landscape after the 2015 oil price shock. Then the pandemic landed a second, far worse blow to their prospects. Before that, 2020 was expected to kick-start a new wave of oil company spending, particularly in East Africa and on large-scale Liquefied Natural Gas (LNG) projects.

Africa would have accounted for more than a quarter of the new acreage on offer in licensing rounds this year, with at least a dozen countries from Senegal to Somalia expected to promote blocks onshore and off.

Just before the pandemic struck, oil majors were already reviewing their plans because of the depressive effect on prices of the dispute between Saudi Arabia and Russia (AC Vol 61 No 7, Protests on pause). What was seen as a short-term supply shock turned catastrophic when it segued into the black hole of the coronavirus crisis and demand crashed.

In times of low prices cash flow is the corporate priority. Over the past two months, international oil companies (IOCs) announced they were cutting capital spending on drilling wells and building new facilities by up to a third. Big greenfield projects yet to reach an FID but which were expected to start in the next two years are a target for cuts.

Last month, ExxonMobil said its $23 billion Rovuma LNG project offshore Mozambique, due to start this year, was being put off, with no indication of when it might be re-scheduled (AC Vol 57 No 21, Good gas and bad governance). Yet France's Total, which is due to sign a $15bn financing deal this month for its LNG project in Mozambique insists it will be exporting gas from there within four years.

As the biggest-ever energy project in Africa, Total's gas plant in Mozambique flies in the face of the industry trend. Finance was helped by US Export-Import Bank backing of just under $5bn for US companies for work; Japanese state backing produced another $3bn of guarantees. Washington and Tokyo both wanted to outmanoeuvre China's plans for the region.

In March, Aker Energy announced that its troubled Pecan project in Ghana – targeting 450-550 million barrels-of-oil-equivalent in the Deepwater Tano Cape Three Points block, outbound of the producing Jubilee and TEN fields – would be postponed 'indefinitely'.

Several other unsanctioned projects are likely to be deferred, according to Rystad Energy, because their breakeven prices are well above the current oil price. Among these are the Tullow-operated South Lokichar onshore development in northern Kenya, Shell's Bonga South West-Aparo project in Nigeria, ENI's Etan-Zabazaba field (also in Nigeria) and BP's Palas-Astraea-Juno development in Angola's Block 31.

Mothballing unsanctioned projects is fairly straightforward. Suspending projects already under development is far more complex given the array of contractual obligations, the stand-down costs, differing partner interests and implications for host country relationships.

For this reason, some projects may push ahead regardless of weak prices: Exxon indicated that while the Rovuma project would be delayed, the Coral floating LNG project operated by ENI (in which Exxon has an equity interest) was proceeding, albeit with some changes to the drilling schedule.

There will be some high-profile casualties, however. Having taken a conditional FID in December, the long-delayed Nigeria LNG Train 7 development looks set to be pushed back further, amid upstream deferments and financing challenges.

More dramatic still was BP's decision in early April to declare force majeure on Phase 1 of its Greater Tortue Ahmeyim (GTA) cross-border LNG project offshore Senegal and Mauritania (AC Vol 61 No 8, Ambition runs out of gas). BP took its FID in 2018 and spending was due to ramp up this year, with gas set to flow in 2022.

Golar LNG – which is supplying a vessel for GTA – said BP's decision had been based on its claim that it would 'not be ready to receive the floating LNG facility GIMI on the target connection date in 2022', adding that the project would be delayed by a year.

BP's announcement saw supplier Golar's stock price fall by more than 30% yet the delay to Tortue's ambitious offshore development may suit BP's joint venture partner, Kosmos Energy, due to spend $250m on Tortue in 2020, following the end of an arrangement for BP to cover Kosmos's costs.

This would have been a major commitment for Kosmos. Even before the oil price shock its management had been looking for alternative funding, including a possible farm-down of its equity or a new carry arrangement with BP. Force majeure will buy the company some time.

Senegal's second major development this year is at risk, due to the financial constraints of a junior partner. One of the world's largest oil finds of the last decade, the offshore Sangomar development received FID only in January with oil expected to flow from the 250bn barrel Phase 1 of the project in 2023.

However, Australian junior FAR, which discovered the field, has been unable to secure debt financing for its 15% interest. Now it is 'unlikely to be able to fund its future share', necessitating a farm-down or divestment of its equity interests. Operator Woodside and its joint venture partners put the project under review, scaling back planned capital spending to ease cash flow pressures.

Falling prices and disruptions will test the most resilient of companies in Africa and could change the competitive landscape. Weaker juniors with smaller portfolios may be forced to sell down their interests to manage their debt or relieve future financing pressures. In April, Tullow reached an agreement with Total to farm down all its interest in the 1.5bn-barrel Lake Albert fields and is looking for buyers for its equity in the South Lokichar project.

Although the smaller players will lose the most, tougher market conditions will also hit the majors. Balance sheets across the industry will be stretched. Only the most attractive wells will be drilled, appetite for costly and risky projects will fall. Among host countries there will be far greater competition for investment as pressures grow in response to climate change and energy transition plans.

At the turn of the year, Africa's three largest oil and gas producers – Angola, Nigeria and Algeria – had hoped to capitalise on the more buoyant industry mood. 

In Angola, the second half of 2019 saw more project approvals after the introduction of more flexible marginal field terms and a regulatory roadmap for the commercialisation of non-associated gas discoveries. Substantive reforms and a restructuring privatisation of state oil company Sonangol were under way. A plan to sell a third of Sonangol's in an Initial Public Offering in 2022 may go on ice.

The country's oil sector was on course for a revival, with at least ten exploration rigs due to start by the end of this year. But the price crash in March triggered a suspension of drilling by the biggest companies in the country – BP, ENI, Chevron, ExxonMobil, and Total, reported Reuters last month. Drilling ships heading for Angola have been diverted to other regions.

The changing of the guard in Algeria in December had also promised reformist momentum in the oil and gas sector, with the implementation of a new hydrocarbons code among the first legislative acts of President Abdelmajid Tebboune's government.

In Nigeria, Minister of State for Petroleum Resources Timipre Sylva is trying to rekindle hope in the long-delayed Petroleum Industry Bill (PIB) but the prospects of it passing this year are diminishing (AC Vol 59 No 16, Politics of patronage). The death of President Muhammadu Buhari's chief of staff Abba Kyari, the main driver of the reform, has lessened its chances.

Instead, Sylva is talking up the government's plans to hold a marginal field licensing round this year which could include as many as 56 swamp, shallow water and onshore fields in the Niger Delta. The last such round was 18 years ago.

Sylva sees it as a way to raise state revenues, citing projected sale incomes of over $500m, a figure that few industry players find credible. Most of the local companies likely to bid are wrestling with pressures to cut output as revenues fall. And banks are reluctant to lend more to the over-stretched indigenous companies.

The federal government's inability to pass a reform bill that offers incentives and stability to upstream operators led to a decade of underinvestment. Nigeria has the worst record for bringing discovered resources onstream after Venezuela.

Under current market conditions, any reform measures are unlikely to revive IOCs' appetite for upstream investment after more than a decade of declining competitiveness.

Algeria's state oil company Sonatrach announced in April that it had signed four Memoranda of Understanding to facilitate upstream exploration under the new hydrocarbons code. But these MOUs are little more than expressions of intent and will not offset the production declines following swingeing cuts to Sonatrach's capital budget; it holds a 51% interest in most producing fields.

In Angola, Total, which produces about half the country's oil, has announced that three of the four developments approved in 2019 will be slowed due to low prices and high costs.

If oil prices stay depressed, Africa's mature producers will have to work much harder to bring in upstream investment, competing for increasingly scarce capital and to halt declining output.

Over the last two years, Angola, Algeria, Congo-Brazzaville and Gabon passed new hydrocarbons codes easing fiscal terms and improving competitiveness following the 2014-15 oil price crash.

However, in most cases, the reforms were plagued by political infighting and legislative inertia, and the resulting changes were late in the cycle, doing little to address investor concerns. Foreign companies see Algeria's 2020 code as a big improvement on its predecessor from a fiscal standpoint. But they don't like the requirement for Sonatrach to hold 51% in all new developments.

Regionally, African fiscal terms are still among the highest in the world; local content regulations are increasingly stringent and greater institutional complexity has slowed decision-making. 

Looking at the weakened financial position and higher risk aversion of IOCs, African governments may have to consider another round of liberalisation to win much new investment.

Any attempt to attract upstream investment will be shaped not only by the inter-agency wrangling and rent-seeking of the formal policy-making process, but also by the fallout of the public health emergency.

The UN Economic Commission for Africa (UNECA) estimates Africa will lose $100bn from oil revenues this year, with revenues in Nigeria and Angola falling by half (AC Vol 61 No 7, Third wave threatens the continent). For other producers – Algeria, Equatorial Guinea, Congo-Brazzaville and Gabon – the effect could be as severe.

Tighter public finances will complicate government attempts to buy off unrest with patronage. It may no longer be possible for Nigeria's government to pacify Niger Delta militants and resource nationalists at state level, threatening the 'pax Buhariana'.

Oil producers struggling to service dollar-denominated and oil-collateralised debts, most notably Angola, Congo-Brazzaville and Ghana, will have smaller budgets for public services and infrastructure projects that could help them politically. 

For countries planning oil and gas production, the effects of the slowdown should be attenuated. For Senegal and Mauritania, joint hosts of the now delayed GTA project, a year's delay is unlikely to unsettle the politics and economics. Discovered in 2016 and overseen by both governments, expectations around revenues and domestic opportunities have been modest so far.

In Mozambique, however, the delay to the Rovuma project and the potential scaling back of Mozambique and Coral projects, would be deeply problematic. The country's ability to service its gargantuan debts is dependent on the timing and value of LNG receipts.

With principal payments on the country's restructured Eurobonds falling due between 2028 and 2031, the current lack of clarity over the re-scheduling of Rovuma – which will account for around 50% of Mozambique's LNG exports – will worry the country's bondholders (AC Vol 61 No 9, How Frelimo lost a province). 

Although far from the onshore LNG facilities, the worsening insurgency in Cabo Delgado province has prompted oil companies to contribute funds to the security costs and use of foreign mercenary forces. But all those contributions will be taken out of Mozambique's future gas earnings. 

This is fuelling speculation that the project might be delayed still longer. In April, a research note from S&P Global Platts Analytics argued that Rovuma exports are now unlikely to start before 2030. Given Rovuma is one of the continent's flagship energy projects, that would send a chilling message to producers and governments alike.

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