Nigerian Lawmakers Vote to Increase Deepwater Royalties

Oil & Gas
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Tuesday, November 05, 2019   /12:42PM  / By Wood Mackenzie / Header Image Credit: Wood Mackenzie 


Executive Summary


On 29 October, Nigeria's National Assembly voted through the first ever change to royalty within the Deep Offshore and Inland Basin PSC Act. The whole process took just 26 days, taking the industry by surprise. The key points of the amendment bill are:


  • It removes the current water depth-based royalty and replaces it with a uniform 10% royalty for all deepwater PSCs.

  • It introduces a price-based royalty which will add 0% to 10% depending on oil price. At our long-term price assumption of $65/bbl, this would be an extra 4%.

  • Deepwater fields currently pay between 0% and 8% royalty, but they could expect to pay 14% once the Bill is enacted.


  • The terms can be reviewed every eight years.


The change applies to all deepwater PSCs, regardless of vintage. Wood Mackenzie estimates it will result in a loss of value of $2.7 billion over the remaining life of the assets, a value reduction of 18%.


The toughening of royalty is, relatively speaking, not as bad as investors feared. The average remaining government share increases by 5%. Production will continue and most pre-FID deepwater projects could still make money at a long-term oil price of $65/bbl, even with a 15% discount rate. So what's the problem?


Deepwater investors the world over need to ensure their projects can withstand low oil prices of $50-55/bbl, given recent price fluctuations and long-term forecasts of declining oil demand. This means delivering low breakevens, and here, Nigeria already struggles to be globally competitive.


By increasing royalty, deepwater projects in Nigeria will move further up the breakeven curve, considerably increasing the risk of being stranded. Although in the short term, the change will deliver the intended increase in revenues for Nigeria, in the long-term it won't if investors allocate capital to better projects elsewhere.


Finally, royalty is only one piece of the fiscal framework. Deepwater investors know that when their contracts expire over the next five years or so, they will likely face more fiscal changes in return for a 20-year renewal. Do they have the appetite for another long slog?


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Surprisingly rapid legislative passage

On 8 October, President Buhari delivered his 2020 budget to the National Assembly, in which he said:


We need to quickly review the fiscal terms for deep offshore oil fields to reflect the current realities and for more revenue to accrue to the government.


The Executive tabled such a bill in 2018 to increase royalties, which Wood Mackenzie analysed in our last fiscal reform update.

This bill ran out of time, however, Buhari went on to say:


I will be re-forwarding the Bill to this Assembly very shortly and therefore urge you to pass it. We estimate that this effort can generate at least $500 million additional revenue for the Federal Government in 2020 and over $1 billion from 2021.


A week later, the Senate duly passed a bill to amend the Deep Offshore and Inland Basin PSC Act (DOIBPSC). Senate Bill 21 (SB 21) was tabled on 3 October (first reading) and passed its second reading on 8 October. In the space of just one week, it passed committee stage (where a public hearing is held) and was passed on 15 October. However, the initial version of bill that passed contained completely different royalties to the clean copy approved by the Senate president. That said, it proceeded to concurrence in the House of Representatives and was passed within hours on 29 October.


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SB 21 was sponsored by the opposition PDP but sailed through the National Assembly despite President Buhari's APC controlling both upper and lower houses - an indication of the universal support increasing deepwater royalties has across the political divide. The APC's own proposed amendment to the DOIBPSC Act - House Bill 89 (HB 89) - was tabled in July but hadn't progressed beyond first reading. That bill resurrected the Executive's 2018 bill that would keep the current royalties but also apply a windfall royalty of 50% to deepwater PSCs when the oil price exceeds $20/bbl (1993 terms).


At concurrence on 29 October, HB 89 was presented initially to the House, then discarded in favour of SB 21. This removed the risk that it could be harmonised with SB 21 to impose much tougher royalties. SB 21 will now progress to the President for his assent.


Senate Bill 21

This amendment bill removes the current royalty and introduces a new 10% rate for oil and condensates for all deep offshore fields (>200 metres). At present, deepwater PSC royalty is based on a sliding scale of water depth, but fields in over 1,000 metres (including Agbami, Akpo and Egina) currently pay nothing, while Bonga, Erha and Usan pay 2% to 8%.


On top of this, a price-based royalty will apply as follows:

<$20/bbl = 0%

>$20/bbl to $60/bbl = 2.5%

>$60/bbl to $100/bbl = 4.0%

>$100/bbl to $150/bbl = 8.0%

>$150/bbl = 10.0%


The bill doesn't stipulate whether the scale is progressive, hence we assume that a single flat rate is applied according to price. This means that if a barrel is sold next year for $65, as well as paying the new water depth-based royalty of 10%, deepwater

producers will also pay an additional 4% giving a total royalty of 14%. The other key amendment is to delete section 16 of the Act which states:


(1) The provisions of this Decree shall be subject to review to ensure that if the price of crude oil at any time exceeds $20per barrel, in real terms, the share of the Government of the Federation in the additional revenue shall be adjusted under the Production Sharing Contracts to such extent that the Production Sharing Contracts shall be economically beneficial to the Government of the Federation.


(2) Notwithstanding the provisions of subsection (1) of this section, the provisions of this Decree shall be liable to review after a period of 15 years from the date of commencement and every 5 years thereafter.


A new section is added which states:


The Minister shall cause the Corporation to call for a review of production sharing contracts every eight years.


This new amendment has no caveats in terms of prevailing oil price at the time. If effected this year, a review could be held in 2027. If Bonga SW Aparo came onstream in 2025, then its terms could be reviewed by NNPC near the point of peak production, and again in 2035. Even though previous openers in the law have never been used, it hardly needs stating that it would be very risky to sanction a multi-billion-dollar project if the terms could be toughened at its most cash-generative point.


What About Deepwater PSAs?

This change would apply to all deepwater PSCs regardless of vintage. There is a question of whether it will apply to deepwater PSAs, more properly known as indigenous sole risk contracts.


They were awarded in the early 1990s. Indigenous licence holders undertook exploration and development activities at their own risk, but they were permitted to farm-down up to 40% to foreign investors. Under the terms, foreign investors bore all costs of a development and the indigenous company received a share profit oil instead of NNPC (as per a typical PSC). For this

reason, the sole risk contract is also called a Production Sharing Agreement (PSA).


The most important deepwater PSAs cover 62% of Agbami (OML 127) and 50% of Akpo/Egina (OML 130). Because they are not PSCs, Wood Mackenzie has assumed they are not covered by the DOIBPSC Act as per our previous analysis in June.


Economic Impact


Impact by OML


Royalty is the first deduction from oil revenues and is payable from first oil. The front-loading of government share in favour of revenue rather than profit reduces investor returns which are largely driven by early year's cash flow when production peaks.


For the government, royalty ensures revenues from day one of production rather than waiting years for tax and profit oil to



Using Wood Mackenzie Valuations powered by our LENS Platform, we analysed the economic impact of SB 21. Applying the change across all deepwater PSCs with commercial assets, remaining value to investors reduces by $2.7 billion or 18% overall.


There is a strong correlation between the remaining pre-tax value per barrel and the scale of impact. This is highlighted by OML 130 which is generating significant cash flow after a sustained period of investment. Its reduction in value is only 11%. OML 118 on the other hand, despite producing over 150,000 b/d awaits major investment on Bonga SW, Bonga North and the Bonga Main extension; its value declines by as much as 20%. The average increase in remaining government share across the biggest producing PSCs is 5%.


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Impact on Pre-FID projects

Looking at some of Nigeria's Pre-FID projects, our analysis shows the impact on Bonga SW within the OML 118 1993 PSC contract area is even greater. It shows a 42% reduction in value and an increase in its breakeven from $45/bbl to $51/bbl. This of course is with the benefit of fiscal synergies, whereby capital costs and investment tax allowances can be deducted from PPT. The project will pay higher royalties from day one of production and so the impact is proportionally greater than the whole of OML 118.


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The potentially giant Owowo field's value reduces by 83%, because of also having to pay higher royalties from day one of production, and crucially, because it does not benefit from fiscal synergies. Its breakeven increases from $61/bbl to over $65/bbl.


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Contract Renewal Brings Additional Risks

This increase in deepwater royalty won't be the end of fiscal change. Royalty is just one piece of the fiscal framework. From 2024 onwards, all 1993 deepwater PSCs will begin to expire with Shell's OML 118 the first of them. It is expected that NNPC will renegotiate tougher PSC terms in exchange for a 20-year renewal.


A non-binding Heads of Agreement was signed with Shell in February which provided a "clear commercial framework for a potential Bonga SW Aparo FID". That framework included a possible reduction in the cost recovery ceiling from 100% to 80%, and the removal of 50% investment tax allowances. Even the removal of fiscal consolidation within the contract was raised.


Higher royalty significantly alters this framework. FID on Bonga SW Aparo already looked unlikely this year, but now further negotiations will be needed if this project - and others - are to ever move forward. Fiscal uncertainty is set to continue for deepwater investors long after this change.


Nigeria's declining deepwater competitiveness


Fiscal competitiveness

We have compared government share for all global deepwater regimes. This uses the most recent terms that a new entrant investor would receive. In Nigeria this is the 2005 PSC terms.


The chart below shows that Nigeria currently ranks 36th out of 116 deepwater fiscal regimes in terms of highest government share. The SB 21 amendment pushes Nigeria up to 31st position - just outside the toughest quartile. SB 21 moderately increases state share from 68% to 71%, on the face of it not such a big change. It is worth noting that SB 21 is not the worst outcome for deepwater investors. House Bill 89 would have resulted in a government share of 77%.

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Cost competitiveness

But this analysis is only part of the story. It doesn't take account of Nigeria's deepwater costs relative to its competitors. As is well known, Nigeria suffers from very high costs in deepwater, and this has been a bugbear for the government for many years.


This is partly attributable to a lack focus on costs by deepwater operators during periods of high oil prices. Some operators have shown themselves to be better at lowering costs than others following the downturn.


However, it's is also true, and acknowledged by government, that local content has caused significant cost inflation. On Egina, local content accounted for inflation of well over 25%. Local content targets will get tougher, so this issue will not go away in the short term. Bonga SW Aparo has been challenged to meet a local content target of 34% by contract value, even though the country-wide average is 28%. Squaring the costs circle within the fiscal framework will now become even harder, contract renegotiation notwithstanding.


Wood Mackenzie's pre-FID project tracker provides breakevens for global pre-FID projects with reserves over 50 mmboe. The chart below highlights the challenges that Nigerian deepwater projects face. Their breakevens are among the highest in the world and typically higher than established competitors such as Brazil, Ghana and in some cases even Angola. This chart does not include the higher royalty of SB 21, but it doesn't need to - the implications of it are clear.

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Nigeria bucks the trend towards fiscal incentives in West Africa


The timing of this increase in government share from deepwater moves Nigeria out of line with a global industry which has worked hard to adapt to lower oil prices since 2014. Numerous mature countries in West Africa have recently implemented fiscal changes to attract investment. Fiscal flexibility and terms for gas (still missing from Nigerian PSCs) are prominent themes:


  • In 2018, Angola introduced marginal field terms for deepwater fields and offered gas terms for the first time, re-igniting deepwater interest from the majors


  • Gabon improved its Petroleum Code this year after its 2014 version turned-off investors, including flexible terms for marginal fields and gas terms


  • Congo-Brazzaville's 2016 terms allow royalty to be reduced and cost recovery ceilings to be increased for technically challenging projects with other terms open for negotiation


  • Cameroon's new law this year offers project incentives on a case-by-case basis as well as new gas terms


It will be argued that amending the DOIBPSC Act is something that past administrations should have done years ago (the latest claim on the IOCs for state revenues foregone due to failures to review terms as per section 16 (2) is reportedly, an eyewatering $62 billion). But the fact remains, it's a very different industry now compared to 2014, and the fiscal changes implemented by Nigeria's regional peers reflect that.



On the face of it, this change is relatively modest, a guaranteed 10% royalty and a small price-based royalty on top which responds to fluctuations in the oil market. Deepwater fields, which contribute a third of Nigeria's liquids production, will continue producing and most new projects could still make money at a discount rate of 15% and a long-term oil price of $65/bbl.


However, the question all investors will be asking is: why invest a dollar in Nigeria when that same dollar will deliver much greater returns elsewhere in our global portfolio? Breakeven prices have become critical to how industry measures investment attractiveness. And the process of ranking global portfolios has never been so rigorous and disciplined.


This royalty change may look reasonable from within Nigeria, but in the global competition for investment, it pushes Nigerianprojects another notch down the attractiveness ranking and possibly out of the money. It will increase government revenues in the near term, but it is hard to see major new deepwater projects progressing, particularly with the added uncertainties of

contract renewal and the challenging business environment. And that risks declining deepwater revenues in the long term.


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