Unlocking investment for deepwater projects
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Not long ago, West Africa was at the top of the list for international E&P companies looking for high impact growth. "Here be giants," they surmised.
Angola and Nigeria production peaked at 3.8 million b/d of oil as recently as 2010 – as big as the North Sea and equivalent to more than 40% of OPEC production outside the Middle East. The potential in deeper waters up and down the continental margin was only just beginning to be tested. There were high hopes of a mirror image of the giant reservoirs in Brazil on the west side of the Atlantic that would propel the region into a new golden era of growth.
The oil price collapse put paid to most of these hopes. Capital investment in the region has fallen 60% from US$50 billion in 2014 to just US$20 billion per annum – worse than the global average of 40%.
High costs, a history of tortuous project execution, red tape, and in some cases, exorbitant government takes, have proved a near-fatal combination.
IOCs went cold, most choosing to spend their limited capital where the risk/reward ratio was better.
The final investment decision (FID) on Total’s Zinia-2 project in Angola on May 25th is a sign that the industry there at least is starting to move out of the trough. Adam Pollard, Senior Analyst, Sub-Sahara Africa Upstream, reckons this streamlined, fast-tracked incremental oil development may be emblematic of a new investment phase in Angola.
Zinia-2 holds just 80 million bbls, will be tied-back to an existing FPSO extending the life of the infrastructure, and production will start inside two years. The economics are attractive – our model indicates a 25% a post-tax IRR at Brent US$65/bbl.
A critical factor behind this FID has been fiscal flexibility. Projects with low IRRs can qualify for marginal field terms. Angola’s new government, elected last year, raised the threshold from below 10% to below 15% on May 18, 2018, for fields of up to 300 million bbls.
We think there are at least a dozen Zinia 2-like potential incremental developments holding a combined 1.4bn bbls that may meet this definition.
The uptick in investment in the next few years won’t take Angola back to its glory years, but it could breathe life into a flagging industry and stabilise the declining production profile. The new legislation, forged through consultation with the IOCs, also aims to stimulate investment in exploration and gas, and to streamline the regulatory process.
Other nations would do well to take note. Yet Andon Blake, Petroleum Economist, notes that the tendency has been to do the opposite and crank up fiscal take. Investment in Nigeria is at a low ebb, with operators rattled by the general uncertainty of the Petroleum Industry Fiscal Bill and specific proposals from the Ministry that would increase royalty for new large deepwater projects from 8% to 28%. Senegal, an emergent province, is reviewing its terms after giant oil and gas discoveries.
There’s a lot at stake. Sub-Saharan Africa has at least 23 bn bbls of oil and 54 Tcf of gas yet-to- find, some 15% of the world’s YTF outside the US Lower 48.
Around half of these future reserves are in Angola and Nigeria. The region should be a magnet for IOCs and internationalising NOCs alike. But development economics are still challenging three years on from the downturn.
Senegal’s SNE and Zinia-2 aside, breakevens for pre-FID projects in our database average US$58/bbl, NPV15 – uncompetitive with the best conventional alternatives in Brazil, Guyana, Mexico and the Gulf of Mexico. Higher costs, long lead times and high tax rates take their toll.
Decline rates in West Africa are accelerating after three years of low investment. Production has fallen by 12% to 4.3 million b/d already this decade and will drop another 1.0 million b/d by 2026 on our forecasts.
The industry has its motivation to sustain and grow its assets, and getting costs down is its preoccupation. But governments are competing for investment. As Angola has recognised, they themselves hold a key to making sure capital flows their way.