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Significant potential from untapped discovered
resources
The Niger Delta Basin constitutes one of the world's largest
Tertiary deltas and most prolific hydrocarbon systems.
Notwithstanding the mature status of the Basin, it continues to be
highly prospective, boasting a technical exploration success rate
of 56%, and an estimated 118 billion barrels oil equivalent (Bboe)
of total discovered resource.
With a daily crude production rate of around 2 million barrels
the Niger Delta Basin is by far the largest oil producing basin in
Africa. Discovered remaining resources are estimated at 66 Bboe, of
which 51% is gas; 26 Bboe remains untapped in unsanctioned assets,
and discoveries risk being stranded if they are far removed from
infrastructure in the more technically challenging deepwater
terrain.
Over 85% of the Niger Delta Basin underlies the coastal plain,
the continental shelf, and slope of central and eastern Nigeria.
Also included in the basin is a small coastal area and part of the
shelf of western Cameroon (where it is called the Rio del Rey
Basin), much of the offshore territorial waters of Equatorial
Guinea west of Bioko Island (part of the Cameroon Volcanic Trend),
and an area of deepwater slope that lies within the territorial
waters of São Tomé and Príncipe. However, Nigeria dominates the
area both in terms of current production (93% of current basin
output) and resources (94% of recoverable resources). Nigeria's
E&P outlook will therefore determine the trajectory for the
wider basin.
Figure 1: Niger Delta Basin Total Recoverable
Resource
The Nigerian National Assembly (NASS) signed the Petroleum
Industry Act (PIA) into law on the 16 August 2021, after almost two
decades of negotiations. The PIA's passage demonstrates political
consensus that oil and gas legal reform can no longer be put off
after several failed attempts dating back to the late 2000s.
Figure 2: Overview of Nigeria's oil and gas sector reform
plan
Will 2022 ignite new project sanctions or will investors
take a "wait and see" approach?
The PIA provides the clarity that license holders have been
yearning for to make empowered decisions on stalled E&P
investments in Nigeria. However pro-investment elements of the PIA
may be offset by investor-negative changes that may increase legal
risks, operating costs and administrative complexity.
The extent of the backlog of projects awaiting sanction
potentially magnifies the impact of the PIA. The window of
opportunity to monetize the Basin's resource potential now appears
to be shrinking amid accelerated global international oil company
(GIOC) disengagement, corporate capital discipline, portfolio
consolidation and new climate policies related to the Energy
Transition.
Several mid-term projects may remain uncertain, but it is
possible that during the next three years the number of projects
undergoing sanction could exceed twenty. Growth in the domestic gas
market will be an enabler for project sanctioning; whilst
established exporters will benefit from existing offshore
infrastructure.
New project sanctioning could increase primary gas production by
20% and boost oil output to over 2.3 million barrels per day during
the second half of this decade. In the coming months, companies
will assess whether the updated framework is sufficient to support
the investment required to improve the outlook for the Nigeria's
dominant portion of the Niger Delta Basin.
Regional gas balances are shifting
Natural gas production in the Niger Delta Basin is currently
around 6 Bcf/d. Flaring has decreased from over 60% of produced gas
volumes prior to 2000 to around 10% or less of total gas output in
recent years, while gas reinjection has increased from around 10%
of produced volumes at the turn of the century to over 25% of total
gas production this past decade. The basin is slowly transitioning
to gas, but stalled investment has delayed the establishment of
infrastructure to create new markets.
One of the aims of Nigeria's PIA is to further encourage the
monetization of gas. New regulations and terms to support the
midstream and downstream segments of the gas value chain include
domestic gas delivery obligations and a midstream gas
infrastructure fund which will be financed by a new 0.5% levy on
gas and refined product purchases by wholesale customers. The
royalty base for natural gas and natural gas liquids has been set
at a rate of 5% of the chargeable volume; 2.5% if produced and
utilized in country. The domestic gas sales price will be increased
by $0.05/MMBtu per year from a January 2021 fixed price of
$3.2/MMBtu to reach $4/MMBtu by 2037.
Figure 3: Niger Delta Basin: Historic liquids and gas
production and outlook
The gap between the volume of gas on offer and available
infrastructure to transport and process will present a challenge to
the commerciality of new gas developments; a further concern is the
financial capability of domestic and regional end-users to honour
contractual commitments.
Current strategic Nigerian gas infrastructure projects include
the Obiafu-Obrikom-Oben (OB3) pipeline (nearing completion) and the
Ajaokuta-Kaduna-Kano (AKK) pipeline (2023 planned completion),
which will connect gas production in the southern and south-eastern
regions to population centers in the southwest (Lagos), central
(Abuja) and northern (Kano) regions of Nigeria. An East West
Offshore Gas Gathering System (EWOGGS) is also being developed as
part of the Dangote Group's project which will support new
petrochemical facilities near to Lagos in the southwest.
During the second half of 2021 Algeria's Energy Minister
affirmed the country's commitment to the Trans-Saharan gas pipeline
project to export Nigerian gas to Europe through Algerian
infrastructure; meanwhile the Nigeria-Morocco gas pipeline project
secured feasibility design and engineering study (FEED) funding
approval by the Islamic Development Bank. Should they eventually
come to fruition, these large but highly challenging projects could
help unlock Nigeria's substantial gas resources and create
advantaged northwest African markets.
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May 18
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