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Editorial Board of Africa Oil+Gas Report

NNPC’s widely distributed press release about a loan it secured from AFREXIM bank, ostensibly for the purpose of supporting the Naira, is taken from a playbook that has served it well in the last eight years. The basic contents of that playbook are for NNPC to position itself as the be all and end all of the solution to Nigeria’s enduring fiscal and economic challenges.

These two lines in the release simply play to the gallery for President Bola Tinubu: “The partnership with AFREXIM Bank is projected to play a crucial role in bolstering the nation’s financial stability”.

And: “This combined action signifies a crucial stride in ensuring the equilibrium of Nigeria’s currency, the Naira”.

The announcement came at a time of precipitous drop of the naira against the American dollar, which also coincided with the news that crude oil output had plunged Month-on Month by 13% from 1.25Million Barrels Per Day in June to 1.1Million Barrels of Oil Per Day(BOPD) in July 2023, according to data published by the Nigerian Upstream Petroleum Regulatory Commission (NUPRC).

NNPC is not the finance ministry that should be assigning itself the mandate of supporting the naira.

NNPC should ordinarily be ashamed and concerned that the drop in crude oil output, which will help worsen the value of the naira, is largely of its own doing.

The state-owned company should be focusing single-mindedly on improving its technical efficiency so it can deliver more of the crude oil-locked behind pipes as a result of its suboptimal operational procedures- into terminals.

NNPC has over 55% equity in the largest producing oil and gas fields in Nigeria. While the general perception is that NNPC is mainly a joint venture partner in producing assets that it doesn’t operate, the reality is that NNPC has 100% in several producing assets, most of them underperforming because of the company’s poor technical delivery.

If we ignore NNPC’s JV equity in 57 blocks operated by Chevron, ENI (Agip), ExxonMobil, Shell,TOTAL, AITEO, Amni, Elcrest, FHN, First E&P, Seplat, Heirs, NDWestern, Shoreline, WAEP, and others, what about the low hanging fruits in NNPC’s own 100% held and operated assets?

Some examples: NNPC operates the Okono/Okpoho fields in Oil Mining Lease (OML) 119 offshore Niger Delta, free of any encumbrances of pipeline evacuation. The low output of ~10,000BOPD, at which the company has been stuck for over the last five years is not due to geology, but facility constraints. NNPC insiders know they can produce 30,000BOPD readily. But it won’t happen.

NNPC was gifted the OML 98 in 2019, after that asset was revoked from Pan Ocean Corporation, but it hasn’t been able to revamp the acreage and grow production from at most 4,000Barrels of Oil Per Day.

There was so much bluster from the NNPC Towers when the company took charge of what were Addax operated OMLs 123/124 and 126/137 in January 2023. NNPC has since superintended the fall in production from these assets. To go by data from the NUPRC, the Antan Terminal received 15,568BOPD in January 2023. As of July 2023, that volume had dwindled to 10, 650BOPD. The Okwori terminal, which took in 951BOPD in January 2023, received 248BOPD in July 2023. These are shallow water assets without any issue of pipeline attacks.

Out of the three 100% -held NNPC acreages for which the company has signed Finance and Technical Service Agreements (FTSA) with partners, only the development on the OML 13 agreement, signed with the Indian Independent SEEPCO, is close to first oil. NNPC could beat its chest about topping up the country’s crude export volume with around 30,000Barrels of Oil Per Day in the next few months with this project, but the company can do much better.

There are two other FTSAs, one of which is for an asset (OML11) with far larger producible fields than OML 13 has, but that development is struggling as we write.

ANY LISTED COMPANY IN THE WORLD, WHICH CONSTRUCTS a gas pipeline for 11 years without the certainty of completion will be punished by the market. NNPC has been looping the 439 kilometre Escravos-Lagos Pipeline System (ELPS) since 2012. It has been constructing the 127kilometre OBOBOB (OB3) since 2012. The costs of these grid length, transmission lines, would have ballooned from the original invoice in 2012 but they don’t show up in the section allotted to the Nigerian Gas Company in NNPC’s widely celebrated Annual Reports. And, what’s even more crucial; these are transportation facilities that were meant to improve the distribution of natural gas to power plants and industrial clusters in the country. It is for the lack of completion of OBOBOB that Seplat operated ANOH project has been held up for at least 12 months. It is for the limitation of the ELPS that Chevron is never sure whether it can pump more than 300Million standard cubic feet a day (300MMscf/d) even when it has the capacity to deliver more than 400MMsf/d.

NNPC has behaved like a chokehold on the Nigerian economy.

With this score card you have to wonder how the company’s top brass are able to stand and deliver keynote addresses with themes like Defining the Roadmap for the Future of Nigeria’s Upstream Sector, at conferences.

Without a solid set of achievements in getting crude oil and gas out of the subsurface by its own competence, the recourse is grandstanding, like the press release on the AFREXIM bank loan, and barefaced lies about what the company is doing with or without its partners.

Of course, they lie. Bala Wunti, the flamboyant, admittedly personable NNPC Ltd’s Chief Upstream Investment Officer, told a conference in Abuja in mid-July 2023 that he was looking forward to Final Investment Decision on ExxonMobil’s (deepwater) Owowo field and Chevron operated Agbami Gas project in the next two years. It was so untrue. The man lied in the presence of the world. Owowo is in Pre-Feed stage and is unlikely to take FID in that time frame. Neither is Agbami Gas. More explanation about why these projects are held up, is here.

In the face of the crash in crude oil output and steep drop in the Naira’s value, NNPC’s position ought to be, how can we find a way to add 300,000BOPD to production volumes within the next six months? That should be its valid concern, not financial engineering announcements.

This is a public service opinion/analysis by the Editorial Board of Africa Oil+Gas Report.

Italian major ENI has awarded a contract for the conversion of Scarabeo 5 semisubmersible drilling unit into a separation and boosting plant (Floating Production Unit – FPU) for a gas project in Congo Brazzaville.

The contract is worth more than $100Million.

The FPU is a semisubmersible production platform that receives the production fluids from wellheads riser platforms, separate the gas from liquids and boosts the gas in order to feed the nearby Floating LNG (FLNG) unit.

It is the second time in one week that Saipem is announcing the award of a contact of significant value to it by ENI, a company in which it holds significant ownership, for a project in Africa.

On August 9, 2023, Saipem announced a $1Billion contract for a Libyan gas utilisation project awarded to it by ENI. In that statement, Saipem admitted that the Libyan contract was a “related party transaction”, pursuant to Article 6 of the Consob Regulation on related party transactions, since ENI S.p.A. jointly controls both Saipem and Mellitah Oil & Gas B.V (the Joint Venture which owns the project).

ENI owns 30% of Saipem. Indeed, until 2016, it owned 42.5% of Saipem. This means that ENI is one major oil company operating in Africa which thrives on awarding key contracts to a service provider which is almost its own subsidiary.

The Congo contract, subsequent to an agreement signed early this year for the execution of preliminary engineering and procurement activities, entails the Engineering, Procurement, Construction, Transportation and Commissioning of the FPU, to be installed offshore the coast of the Republic of Congo, located northwest of the Djeno Terminal, in a depth of about 35 metres. The commissioning offshore works and the start-up of the FPU are scheduled by the fourth quarter of 2025.

This contract awarded to Saipem is part of Eni’s Congo LNG Project, the country’s first natural gas liquefaction project that is expected to reach an overall liquefied natural gas (LNG) production capacity of 3 million tons per year (approximately 4.5 billion cubic meters/year) from 2025.

Italian explorer ENI says it has formalised with its Libyan counterpart NOC the revocation of force majeure status on exploration areas A and B (onshore), and C (offshore), where the company is the operator with a 42.5% stake, along with BP, 42.5%, and the Libyan Investment Authority with 15%.

“Force Majeure, declared in 2014, was revoked following the completion by ENI of a Security Risk Assessment to assess the security conditions in the areas where the exploration programme will be carried out; this study yielded positive results”, ENI says in a release.

ENI, as operator of the blocks, will now be able to resume the contract activities in exploration basins, some of which are located close to Wafa’s gas facilities.

With an 80% share of national production (1.6Billion standard cubic feet per day (1.6 Bscf/d in 2022)), ENI is Libya’s leading gas producer and domestic market supplier.

ENI has operated in Libya for 64 years and currently has a large portfolio of assets under exploration, production and development.

Production activities are operated through the joint venture company Mellitah Oil and Gas BV (ENI 50%, NOC 50%). Equity production was 165,000 barrels of oil equivalent per day in 2022.

The Senegalese government had banked on commissioning the country’s first commercial scale oilfield development by Christmas of 2023.

The operator, Australian based Woodside Energy, had repeated assurances of this timeline for the past three years.

Even when BP and Kosmos Energy announced the postponement of first cargo from the Greater Tortue Ahmeyim (GTA) liquefied natural gas project — which the country shares with Mauritania —  from 2023 to 2024, Woodside kept insisting that the first development phase of the Sangomar oilfield development was on course.

Now the company is saying that first oil is now delayed to as late as mid-2024, with project costs for the development going up by as high as 13%.

Woodside, on July 18, 2023 said it had carried out a cost and schedule review of the Sangomar field development’s first phase “following the identification of remedial work required on the floating production storage and offloading facility”, which highlighted higher project costs.

This remedial work, which the company did not anticipate, is responsible for pushing the timeline father down some three to five months away. Meg O’Neill, Woodside’s chief executive officer (CEO), said the project team’s highest priority remains “the safe completion of all activities.”

The company, she said, has “taken the prudent decision to have the remedial work conducted while the FPSO remains at the shipyard in Singapore.”

The total project cost has now moved up by around 7% to 13%, to between $4.9Billion and $5.2Billion, an increase from the $4.6Billion that was previously estimated.

The FPSO was delivered to Keppel Offshore & Marine in Singapore in November 2022.

Once the FPSO associated problems are resolved, Ms. O’Neil assures, “the project can achieve production start-up in line with the adjusted schedule, and ramp-up operations as planned”.

Petrofac, the UK headquartered energy industry service provider, has been awarded a facilities management contract by CNR International offshore Cote D’Ivoire, West Africa.

“The initial three-year, multi-million-dollar contract will see Petrofac’s Asset Solutions business providing integrated services for the Espoir Ivoirien Floating Production Storage and Offloading (FPSO) vessel”, the company says in a release.

“Around 110 personnel currently supporting the FPSO, including those onshore and on the vessel, will transition to Petrofac from BW Offshore following the recent sale of the vessel to CNRI. The transition of people and operatorship is expected to complete before the end of July 2023”.

Petrofac says the contract builds upon its existing strong relationship with CNRI in the UK Continental Shelf (UKCS), which has centred around the provision of operations and maintenance services.

“The contract will be managed from Petrofac’s technical hub in Aberdeen, using decades of experience in the mature and highly regulated UKCS market”.