NAPENews Magazine June 2023 Edition

INDUSTRY NEWS
A REVIEW OF ACTIVITIES IN THE
NIGERIA OIL & GAS SPACE
COURTESY AFRICAN OIL + GAS REPORT
business with its biorefineries, which will be
replicated in a network incorporating other
African countries", the report highlights.
In the same month, ENI completed the
phase-out of palm oil as feedstock supply for
ENI's biorefineries, with it fully replaced by
sustainable raw materials from Africa. The
company also launched a study to assess
the economic feasibility of building and
operating a biorefinery at the Livorno hub
(also in Italy, several thousand kilometres
from Africa), with a design capacity of 500
kilotonnes/annum.
In November 2022, ENI signed several
agreements with the Government of
Rwanda "to promote high- quality seed
production suitable for agri-feedstock, for
the production of biofuel in ENI's
biorefinery".
ENI is in the process of searching for
biorefinery sites all over the world, anywhere
but Africa.
In December 2022, the company started a
collaboration with Euglena, a leading
Japanese biotechnology firm, and Petronas,
Malaysia state-owned oil company, to
evaluate the economic feasibility of building
and operating a biorefinery complex in the
S o u t h - E a s t e r n A s i a n c o u n t r y . A n
investment decision is expected to be
reached by 2023 with possible completion in
2025 and a targeted processing capacity of
up to 650 ktonnes/y of bio-feedstock. The
project will leverage Honeywell UOP's
EcofiningTM process technology, which
was jointly developed by ENI and Honeywell
UOP.
In December 2022, Versalis acquired from
DSM a technology to produce enzymes for
second-generation ethanol to be employed
at the Crescentino plant to integrate the
proprietary Proesa® technology to deliver
sustainable bioethanol and chemical
products from lignocellulosic biomass.
ENI keeps looking all over the world for
suitable sites for converting wastes it
collects from Africa, into high value
products. "As part of the development of the
biorefining business, ENI signed definitive
agreements with PBF to partner in a 50-50
joint venture, St. Bernard Renewables LLC
(SBR), for the biorefinery currently under
construction in Louisiana (US). The
biorefinery start-up is expected in the first
half of 2023, with a target processing
capacity of about 1.1 million tonnes/year of
raw materials to produce mainly HVO
Diesel”.
Seplat Acquires 95% of Abiala Marginal field-Elcrest
Seplat Acquires 95% of Abiala Marginal field-Elcrest (45% owned by Seplat Energy) and has entered into an agreement with Naphta
Global E&P Ltd for a 95% equity farm-in to the Abiala marginal field. Naphta will have a 5% carried interest. Elcrest will also assume the
role of Operator and Technical &Financial Partner in the Elcrest/Naphta Joint Venture. The partners executed Heads of Agreement
with a signature bonus of $12Million paid to NUPRC. The transaction represents a consolidation of the Company's strategic position on the
Oil Mining Lease (OML) 40 block. Naphta was awarded 100% equity in the Abiala marginal field carved out of OML 40 by the NUPRC in the
2020 marginal field bid round. The marginal field contains 2C gross oil resources of approximately 40 MMbbls, Seplat says in its annual
report. The company adds that the deal provides an early monetisation opportunity using existing OML 40 facilities, subject to agreement
with NEPL (NNPC E&P Limited, formerly NPDC), which operates the OML 40 Asset. In developing the field, Elcrest is targeting first oil by
the end of Q2 2023 and plans to focus on low-cost development with early monetisation opportunities that leverage existing contractual
positions to accelerate the field's development. Seplat Energy will also explore optimising its tax position to the extent possible under the
new PIA.
The Crucial Sections of the NUPRC's Newly Gazetted Domestic Gas Demand
Delivery Obligation Regulations-
The first and most important line in the newly gazetted regulations on domestic gas demand delivery, is that a Lessee shall provide -to the
NUPRC- information relating to its natural gas reserves and resources, as at December 31st of the preceding year. Then a lessee shall in
addition to reporting reserves, provide estimates of the rates at which the marketable natural gas shall be produced, either directly at the
measurement point or at any other marketable delivery point. A lessee shall, for gas destined for export and the domestic free market, use
such price as may be applicable at the end of the preceding year. A lessee shall report to the Commission volume of tiers 1, 2 and 3 gas that
are — (a) connected but not produced or delivered for lack of domestic gas demand or for any other reason stipulated in section 110(10) of
the Act ; and (b) not connected to gas infrastructure or connected to such gas infrastructure, but with insufficient spare capacity for the
delivery of the gas. The domestic gas demand requirement for gas under the proved developed non-producing and the proved
undeveloped, shall include gas that is not specifically destined or committed for any purpose at the time of reporting and the volume shall be
separately identified. Where the lessee reports low-Btu resources, it shall inform the Commission of the marketable gas price level at which
the resource is projected to be commercially viable. A lessee shall for reporting purposes of low-Btu resources, include proved reserves of
low-Btu gas. A lessee shall report to the Commission the — (a) low estimate marginal contingent resources where the lessee, or any party
constituting the lessee, is already providing such information in its annual report or any communication with its parent company,
shareholders, or other parties ; and (b) marketable gas price levels at which such resources are projected to be commercially viable. Proved
gas reserves in the deep offshore shall be included in the estimates for export, and where otherwise, be allocated to the free market and be
separately identified. (13) A lessee shall report proved developed producing reserves under the domestic gas demand regulation.
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