Summary: Changes to fiscal terms and delays in licence renewals look likely to condemn Nigeria to declining production, following a path analogous to that of its regional challenger Angola.
About the publisher: Richard Norris is a leading business developer and advisor to energy investors, developers, bankers and the public sector.
A bit late for the Nigerian International Petroleum Summit #NIPS which closes today… some thoughts on future Nigerian oil production.
News on the oil price is currently dominated by demand being impacted by the Coronavirus and the supply-side playing catch-up, with OPEC+ making additional cuts to compensate the demand hit.
There is always noise about OPEC members respecting, or not, their quotas. At first glance, Angola has been a good student and has cut more production than required by its quota, Nigeria on the other hand has produced more. In Nigeria’s case the quota was recently increased as it was argued that the original number had not taken into account the imminent arrival of 200k bopd from the long-awaited Egina FPSO which came on-stream in early 2019. Consequently, the quota was increased, and yet despite this, Nigeria is still not managing to cut enough. In some ways this is not surprising as it is recovering market-share after the long export stoppages in 2016.
Angola and Nigeria used to compete for the title of biggest oil producer in Africa. Today, Angola is playing second fiddle with production having fallen from 1.8mmbbls/d to about 1.35 mmbbls/day – and that includes the recent addition of 235k bbls/d from Kaomba Sul in April 2019.
Angola’s production has been declining since mid-2016, when it started a precipitous drop. This is the result of production from the boom exploration years (1995-2005) coming off plateau and few new finds. New entrants have been squeezed between the requirement to have local partners and the unwillingness of institutional money to be associated with these local partners. They have simply gone elsewhere. The decline in production is a combination of geology and of capital flight with only the incumbent majors remaining. ESG with a focus on G has made Angola almost uninvestable. Changes are afoot, but for the moment serious capital is sitting on the side-lines waiting to see if the country will walk-the-walk after some good talk. The defenestration of the Dos Santos family is seen as a good start, but the continuing influence of a hard core of people who have equal links to the previous regime will be the crucial test as to whether Angola can come in from the cold.
In contrast, Nigeria is sitting pretty having recovered from the shut-ins of 2015-16 and the recent 1st oil of the huge Egina project. Sitting pretty? Well, only “sort of”.
As noted above, all the current concern seems to be focused on how Nigeria has not been abiding by its OPEC quotas – i.e., over producing. This situation is probably exacerbated by the rather random allocation of some production as “condensate” which is not subject to the quotas.
Whilst this “over production” seems to be a genuine issue presently, it is not going to last. Nigeria will soon be “over-conforming”, much as Angola, Equatorial Guinea and Algeria are already. Of course, these are not the result of voluntarily cutting back more than OPEC request, but instead result from collapsing production.
Nigeria announced in 2019 that it would be taking its production to north of 3 mmbbls/day “by 2023”. Some sources have that as a 4 mmbbls/day target.
Whilst I am not usually a betting man, I might be prepared to take a wager that this is not going to happen in the near future. In fact, I suggest that Nigeria will shortly be following Angola over the cliff.
The Importance of Deep-Water
Deepwater production, which makes up at least one third of Nigeria’s total comes from a handful of big fields with FPSOs. This is somewhat better balanced than Angola, where the rash of deep-water discoveries in 1995-2005 significantly outweighed the shallow-water and onshore production. Notwithstanding this, approximately 800k bopd (out of circa 1800k bopd) comes from the deep-water. Only Egina is a recent start-up (2018), with the next most recent being Usan (2012) and Akpo (2009). Given that typical deep-water fields are planned to be on plateau for 6-7 years, it is likely that all of Nigeria’s deep-water fields are in “managed” decline. The fact that globally the industry has focused on minimizing capex since the oil down-turn of 2014 to the present, will not have optimized those managed declines. Egina is unusual as the planned plateau is much shorter.
The Need for Investment
Nigeria clearly has the geology; not only does it have huge known reserves, but it also has significant exploration potential. The issue, much like Angola is going to be the ability to attract investment.
Unfortunately, in a time of low oil prices and declining production, the knee-jerk reaction will be to try and increase government revenues. In Nigeria’s case, this is hardly a “knee-jerk” as it is the outcome of a decades long process – usually referred to as the “PIB”. Notwithstanding the time frame, one of the great arguments for investing in Nigerian upstream has been the stability of the fiscal conditions over the years. This argument is now full of holes. Recently the existing PSCs have become subject to royalties, asset and corporate transactions attract a consent fee which has doubled, VAT is now applicable in the service sector (pushing up costs as there is no certainty around recovery of the VAT) and probably most problematic is the reluctance to discuss licence renewals. Whilst these are seen as negatives, there remains uncertainty on what else may come out of the woodwork. The uncertainty itself is also a cause for capital to pause
Regulatory uncertainty has resulted in fewer investments in new oil and natural gas projects, and no licensing round has occurred since 2007. The amount of money that Nigeria loses every year from not passing the PIB is estimated to be as high as $15 billion. (EIA)
On the point of licence renewals, Nigeria has an exemplary record of only removing licences at renewal date if the operating company has not met its minimum obligations, as would any sovereign state. The issue now is more about the timing. Onshore, payback on incremental field developments can be a few months, so worrying about a licence renewal in 3-5 years makes no sense. Offshore however, the enormous upfront costs mean that payback can be several years, so any uncertainty on licence renewal will discourage FID on any such investments.
Already in 2018 The Guardian (NG) reported
Already, the FID on the 225,000bpd Bonga Southwest-Aparo project; 120,000bpd Zabazaba-Etan project; 140,000bpd Bosi project; 110,000bpd Uge project and 100,000bpd Nsiko deepwater project has been delayed.
To-date, none of these projects has pulled the trigger on FID.
“To put our current reality into perspective, in 2018 while the Foreign Direct Investment to Africa rose 11% to $46 billion, the FDI to Nigeria shrunk 43% to $2 billion whilst Ghana received $3 billion (ref. world investment report 2019). This is in contrast to the vast hydrocarbon resource base Nigeria is blessed with (largest oil and gas reserves in Africa).” Mr. Victor Okoronkwo, GMD Aiteo : reported in energymixreport.com
OPEC will be pleased
So, at a time when global capital shuns the O&G sector in general, and is becoming increasingly risk-off, Nigeria is facing a production cliff-edge as deepwater starts to decline rapidly, only limited activity onshore and in shallow-water, barriers to M&A activity and barriers to new investments appearing. On top of this, existing projects which could add several hundred thousand barrels of oil per day are on hold whilst the licence renewal and “other fiscals” debates play out.
Given all this, I would expect Nigeria to join Angola in becoming one of OPEC’s better conforming producers, albeit due to an unintended decline in production
I personally don’t believe this will be long-term – not because the barriers to business are a good idea – but simply because I believe that the ability of the US shale to meet the future demand gap is limited, and that when the supply-demand gap starts to open, there will be a movement back into areas with good geology, even if the fiscal and administrative headwinds are significant.