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The Facts, The Figures: Why NNPC’s Divestment is the Place to Go

By the Editorial Board of Africa Oil+Gas Report

For close to 50 years, the company formerly known as Nigeria National Petroleum Corporation (NNPC) has functioned essentially in two key areas of the petroleum industry.

The first is upstream crude oil and natural gas operations.

The second comprises services, midstream, and downstream activity.

A close examination of the performance of this state-owned entity, in these sectors, in those decades, provides us a handy guide to determine the merit of the recent calls for its outright privatization.

In the 49 years since Nigeria inaugurated the Joint Venture scheme between NNPC and multinational companies, six (6) international majors, have effectively produced all of Nigeria’s crude oil and gas output.

These multinationals have been self-regulating, with high standards of efficiency, governance, and application of technology, that, in spite of NNPC, they planned and executed programmes for national production, which grew to a peak of 2.531Barrels per day (crude oil and condensate) in 2010, according to the BP Review of Statistics, an industry bible of production data. It was easy for NNPC, the 57% (average) equity holder of the JVs, to take credit for these numbers.

Now the multinationals have, since 2012, been steadily implementing a withdrawal and are being replaced by Nigerian independents who do not have the same standards, efficiency, governance, and application of technology.

In the same hydrocarbon patch in which these six multinationals could collectively produce 2.5Million Barrels per day, there are now over 30 producing companies, “superintended” by NNPC, collectively struggling to deliver 1.3Million Barrels per day (crude oil and condensates), with heavy sweating. It’s not a challenge of geology, we aver, but above-surface issues.

Throughout what is now known as the golden era of Nigerian crude production, NNPC’s main contribution has been the long, dispiriting stretch of contracting cycles and delayed cash call payments.

Now the NNPC has grown larger in terms of asset footprint, with more acreages handed to them in those last 10 years; the same decade in which the multinationals have retreated and Nigerian production has shriveled.

Eighty-eight percent (88%) of the fiscal contribution of oil and gas to the Nigerian treasury comes from rent: taxes and royalties and only 12% come from revenues accruing to NNPC from its equity in the Joint Ventures as well as share in Petroleum Sharing Contracts. NNPC’s whopping 57% of the main oil and gas producing projects translates to only 12% of the total contributions of oil and gas to the treasury. What this means in simple terms is this. If we assume that Nigeria is producing 2.5 Million barrels per day today, then NNPC’s entitlement will be 1.425Million barrels per day. This volume is what is the Federation volume. It is the one whose proceeds are always consistently underperforming. It is the one that Ahmed El Rufai, governor of the Nigerian northwestern state of Kaduna, alleges, never reaches the Federation account. It is this NNPC equity entitlement, that we aver, contributes just 12% of the total contributions of oil and gas to the treasury, at the best of times.

The bulk of contribution to the National Treasury from oil and gas comes from the petroleum profit tax (now hydrocarbon tax) and royalties that are paid by Shell, Chevron, TOTAL, ExxonMobil, ENI, Seplat, NDEP, NDWestern, AITEO, Newcross, Amni, Elcrest, First Hydrocarbon Nigeria, Midwestern, Lekoil, First E&P, Conoil, Green Energy, Energia, Waltersmith, Platform, Britannia U, Savannah Energy, Sahara Energy, Oando, Shoreline, Neconde, Heirs Holdings, Oriental Resources, Eroton, NNPC itself and several others.

And there is another point we have to make here. It is its “senior” position in the JVs and its management of the PSCs that has provided NNPC the opportunity to wreak so much havoc (Poor cash call remittances, long contracting cycles, bullying service companies into partnerships with NNPC owned service companies and then insisting the contracts for oilfield service be awarded to those partnerships).

If NNPC was holding a zero percent interest in these JVs, the national purse will feel a more positive impact.

This is why the Africa Oil+Gas Report has always made the argument for the reduction of NNPC equity in the JVs.

The clearest example of the need for NNPC to be less than a 50% shareholder in Nigeria’s oil and gas projects is the Nigeria Liquefied Natural Gas (NLNG) Ltd. Its an incorporated joint venture of NNPC with three European majors (UK’s Shell, France’s TOTAL and Italy’s ENI) in which NNPC has 49% equity. That less than 50% NNPC equity allows these companies a breather to run one of the most profitable hydrocarbon operations (no cash call (payables) issues, no approval challenges for projects, no bullying), with billions of dollars guaranteed as dividends meant for the National Treasury.

Apart from JVs and Production Sharing Agreements in oil and gas production, the NNPC has an extensive network of subsidiaries, some of them service companies, some of them midstream companies, some are in transportation and some are in marketing.

The NNPC runs refineries. It has depots and pipelines for petroleum product storage and distribution.

It has a seismic acquisition and seismic data processing subsidiary chrsitened Integrated Data Services Limited (IDSL); it has an engineering company named NETCO. It has a crude oil marketing division for marketing the Federation crude.

The refineries have not performed above 25% of their capacity since 1997, which is 25 years ago. NNPC’s bungling of its mandate to refine-the Nigerian- crude is one of the most brazen acts of de-industrialisation of the Nigerian economy by any state-owned enterprise.

NNPC, the one-time corporation, now a Limited Liability Company, had three petrochemical plants, each in Warri, Port Harcourt, and Kaduna. The one in Port Harcourt was built as a stand-alone from the refinery. The Warri and Kaduna Petrochemical plants are located inside the refineries.

Nigeria took the bold step to privatize the Port Harcourt Petrochemical plant, named Eleme Petrochemicals. It has been so successful that the 10% equity of it that is owned by the Rivers State Government is probably the state’s largest investment.

The petrochemical plants that remain in NNPC’s control are shabby; they have not sold a bag of petrochemicals for 30 years.

Let us go to crude oil marketing.

Every large oil producer, even lowly Angola, sells its crude oil directly on its own through its state hydrocarbon company.

NNPC is the only such state company that does not market its crude.  It has to allocate to companies who line up every year waiting for an arbitrage opportunity. Nigeria is the only place where you have to allocate crude oil to middlemen to sell.

Even Duke Oil, the NNPC’s crude marketing subsidiary, doesn’t sell directly. It markets through other entities.

The data acquisition and processing company, IDSL and the engineering firm, NETCO, each forms partnership with the competition. By using the weight of the NNPC, they get the contracts that oil companies would have awarded directly to their competition and hand over the work to the competition to do. IDSL, on its own, does not process a single kilometre of seismic data.

NPDC has been delinquent in paying taxes and royalties on most of the assets in which it is 55% or 60% joint venture partner to private producing companies. Most of these assets were assigned to them by NNPC: NNPC novated its equity in several joint ventures to NPDC, but the latter has never paid the equivalent market price for those assets.

NNPC’s Petroleum distribution is probably the most inefficient of all its operations. The petroleum product pipeline system is supposed to ensure the minimal presence of tankers on Nigerian roads. The failure of that system is the reason for some of the most fatal traffic accidents across the breadth of the country.

If NNPC is scrapped today, what will the Federation account lose?

But that’s already a stretch of the argument.

This editorial is part of the Public Service contribution of the Africa Oil+Gas Report.


Saipem Wins Drilling Contracts in Angola, Cote D’Ivoire

Italian contractor Saipem has been awarded two Ultra Deep-Water contracts offshore West Africa for drilling operations with the sixth-generation Drillship Saipem 12000.

The first contract was awarded by ENI for drilling operations offshore Cote d’Ivoire, expected to start in the fourth quarter of 2022 and extend the current activities of the rig in the area of about six months.

The second contract was awarded by Azule Energy for drilling, completion, and testing of development and exploration wells offshore Angola in Block 15/06 operated by ENI Angola S.p.A. The contract will have the duration necessary to drill and complete 12 firm wells (estimated lasting 26 months) and include the possibility of extension for an optional term”, Saipem explains. The project is scheduled to start in 2023 in continuity with the previous works of the rig in West Africa.


Zimbabwe Wildcat: Working Petroleum System Doesn’t Mean a Discovery

By John Mokwena, in Johannesburg

Australian minnow Invictus Energy has reported “fluorescence and elevated gas shows of up to 65 times above background levels” in the Upper Angwa sequence, a primary target in the Mukuyu-1 well in Zimbabwe’s Cabora Bassa Basin.

The company also reports “elevated gas shows and resistivity in shallower Pebbly Arkose formation” and has so declared that there’s a “working conventional hydrocarbon system” in the frontier Cabora Bassa Basin.

The company hasn’t declared a commercial discovery, as these mudlog interpretations are not ever any geoscientist’s basis for calling a discovery.

Invictus is going ahead to drill to a planned total depth of 3,500 metres Measured Depth.

The Mukuyu-1 well is being drilled in Invictus Energy’s 80% owned SG 4571 license.

Scott Macmillan, the company’s Managing Director, says that while “the presence of elevated mud gas readings, fluorescence in the cuttings, elevated LWD resistivity and increasing background gas with depth is a positive sign as we progress through the Upper Angwa Alternations Member”, the company still has several hundred metres of drilling “through our primary targets with additional potential, which will be followed by a comprehensive wireline logging programme to evaluate results, with the aim of confirming the presence of moveable hydrocarbons in multiple zones.”

So far, the 8½” hole section of the well has been drilled to a depth of 3,086 metres Measured Depth. Elevated mud gas peaks (up to 65 times above the background gas baseline) have been observed while drilling through a depth of 3,070 mMD with marked increases from C1 to C5 compounds (methane, ethane, propane, butanes, and pentanes).


Humphrey Onyeukwu becomes Group Head, Legal at Oilserv

Oilserv Limited, the Nigerian provider of EPCIC services, has appointed Humphrey Onyeukwu as the Group Head, of its Legal department.

Onyeukwu was, until the end of September 2022, the Head, Legal & Commercial at Transcorp Plc. with oversight responsibility for driving the growth of the energy business and other targeted asset acquisitions.

He helped shape Transcorp’s engagements in the acquisition of the Afam Power Plants (with 966MW of installed capacity) and shell Nigeria’s divested interests in Oil Mining Lease (OML)17, and also was instrumental to Transcorp’s recent foray into renewable power generation.

A law graduate of the University of Nigeria, Nsukka and alumnus of the University of Dundee, Scotland, where he obtained an LL.M degree in Petroleum Taxation and Finance, Onyeukwu is the founder of The Lagos Oil Club, an association of senior Oil and Gas Professionals in Nigeria with interest in networking and advancing advocacy of petroleum and other energy resources related issues.

Humphrey Onyeukwu is joining Oilserv, at the time the company is evolving into an integrated energy group to accelerate energy transition across Africa. The Oilserv group comprises Oilserv EPCIC, Frazimex Engineering, FrazOil E & P, FrazPower, and EnviFraz.

Oilserv has been a key player in Nigeria’s gas revolution, through such projects as the OB3 and AKK gas pipelines. The 612km AKK gas pipeline, which traverses across Kogi, Niger, Kaduna, and Kano States, is estimated at a $2.6bn construction cost and on completion, the country is expected to have over 8 billion standard cubic feet of gas injected into the domestic pipeline.


GEIL Looks Towards Installing Own, Expanded Evacuation Terminal

With gross output expected to reach over 10,000 Barrels of Oil Per Day (BOPD) on hook up of the second of its two well campaign, the Nigerian independent Green Energy International (GEIL) is considering the limitations of its current evacuation infrastructure.

The company’s production leaped from 4,651BOPD in June 2022, through 5,199BOPD in July 2022 to 7,596BOPD in August 2022, largely on account of the tie in of one of the two wells. The output performance has been beyond the company’s expectations.

Five years after first oil from Otakikpo field onshore eastern Nigeria, the operator envisages the possibility of an output higher than 20,000BOPD from what was initially identified as a “marginal field”. The company currently pumps its crude volumes into Amni International’s Ima Floating Storage and Offloading (FSO) Terminal. But until August 2022, output had been less than 6,500BOPD.

“If we do 10,000 Barrels of Oil Per Day (BOPD) now and we want to go to 25,000BOPD, we are going to have a challenge with our evacuation”, says Anthony Adegbulugbe, GEIL’s Chief Executive Officer (CEO). Our present evacuation option will not work. If you want to take off on that scale and you are still depending on a third-party terminal, is that reasonable? Due to no fault of yours, if they close down for just one day, please multiply 25,000 by $50 and you will understand the amount of money that is on the table. We have not closed out any options and we might still build our own terminal. We might still talk with the likes of Notore and so forth. But definitely by the time we are going to 10,000 barrels, we have 140,000 barrels storage onsite now and that is 14 days. If we are now going to 10,000 would 14 days storage be reasonable? If there is some problem on the other side and you keep on producing, in just 14 days you won’t have any storage capacity and those are some of the issues that we are looking at. Every option is on the table and we are still looking for ways to debottleneck our processing facility and a lot of interesting things are going on. Again, this goes back our original philosophy of taking things step by step.


bp Commences Oil Output From Angola’s Platina: Planned Peak is 30KBPD

bp Angola’s Platina project in Block 18 has started production. The project was brought online both ahead of schedule and under the contractor group’s initial budget. Angola’s National Agency for Petroleum, Gas, and Biofuels (ANPG) considers the project a significant reinforcement of Angola’s oil production capacity.

Platina is a subsea tie-back development to the existing Greater Plutonio floating production, storage, and offloading (FPSO) vessel on Block 18.  It will access an estimated 44 million barrels of oil reserves and, at peak, is expected to add 30 thousand barrels of oil per day to Block 18 production. The project was delivered 44 days ahead of schedule and 25% below the original budget. Its development increased expected recoverable resilient reserves by 10%. The development of resilient hydrocarbon resources focused on maximizing value from existing positions and on high-quality fast-payback new projects is central to bp’s strategy.

Belarmino Chitangueleca, Acting Chief Executive Officer of ANPG highlighted the importance of Platina’s first oil in Block 18 and its contribution to oil production levels in Angola: “With this and other projects, we are gradually meeting the objectives of preventing production decline and increasing production levels with the ongoing bidding of projects.”

Platina, the development of which was approved in December 2018, is the first new development on Block 18 since Greater Plutonio started up in 2007. It is bp’s first newly operated development in Angola since the start of production from the PSVM development in Block 31 in 2012.

Platina is the seventh new project to start production for bp worldwide in 2021. It follows new projects in Egypt, India, Trinidad, two in the US Gulf of Mexico, and an earlier project on Block 17 offshore Angola.

bp Angola is the operator and has a 46% stake in Block 18, Sinopec has a 37.72% stake and Sonangol P&P 16.28%.​


NETCO, IDSL Record Large Losses of Revenue, Says NNPC Annual Report

NNPC’s upstream technical service subsidiaries NETCO and IDSL, were badly bruised by the challenges in the oil and gas industry in 2020, recording large losses of revenue but eventually clawing victory from the jaws of defeat.

The two companies managed to each turn a profit despite their large year on year declines in revenue. NETCO made…

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Nigeria’s President Signs the Petroleum Industry Bill Into Law

President Muhammadu Buhari has signed the Petroleum Industry Bill 2021 into law.

“Working from home in five days quarantine as required by the Presidential Steering Committee on COVID-19 after returning from London on Friday August 13, the President assented to the Bill Monday August 16, 2021, in his determination to fulfill his constitutional duty”, according to a press statement issued by the Nigerian state house and signed by Femi Adesina, special adviser to the President (Media and Publicity).

“The ceremonial part of the new legislation will be done on Wednesday”, August 18, 2021, “after the days of mandatory isolation would have been fulfilled”, the statement adds.

“The Petroleum Industry Act provides legal, governance, regulatory and fiscal framework for the Nigerian petroleum industry, the development of host communities, and related matters.

“The Senate had passed the Bill on July 15, 2021, while the House of Representatives did same on July 16, thus ending a long wait since early 2000s, and notching another high for the Buhari administration”.

 


Advance Military Teams from SADC Arrive Mozambique

Advance teams from the Southern African Development Community (SADC) have arrived in Mozambique to support the battle against the Islamist terrorist groups, known locally as “Al-Shabaab”.

Colonel Omar Saranga, the Ministry’s spokesperson dismissed the news that the regional bloc’s full Standby Force, was already in the country.

The advance teams, he explained, are in Maputo and in Palma (a town in the province of Cabo Delgado), to prepare the deployment of the main force.

Saranga confirmed that General Xolani Mankayi, head of South Africa’s 43 Brigade, the rapid intervention unit of the South African National Defence Force (SANDF), will command the SADC Full Standby Force. Mankayi is already in Mozambique, “and he has been received by the Defence Minister and by the Chief of Staff of the Mozambican Armed Forces. He has received a briefing on the situation”, Saranga said. Last August, the energy press speculated that General Manyi had instructed the 43 Brigade to begin an intensive training programme for possible action in Cabo Delgado if President Cyril Ramaphosa decides to intervene. “Questions of command have been outlined in the combined planning”, Saranga offered. “Right now, what is important to say is not who will command or cease to command. The troops will be led by their respective commands, but the chief coordinator is the Republic of Mozambique”.

Islamic insurgents have killed hundreds of people and turned thousands to refugees in towns and villages located in the province and close to the Afungi Peninsula, where the TOTALEnergies operated 13 Million Metric Tonnes Per Annum Liquefied Natural Gas project is sited.

In late March 2021, just when TOTALEnergies’ workers returned to site in Afungi to continue construction, Islamic insurgents made their most sweeping attack on the neighboring Palma town.

TOTALEnergies pulled out its workers after that attack and Mozambique has since been looking for a way to permanently root out renewed attacks. Part of the effort was to call on member countries of the Southern African Development Commission (SADC) to provide military assistance.

Saranga waved aside questions regarding combat operations of Rwandan troops who arrived in the week of July 12, 2021. The questions referenced report by the independent newssheet “Carta de Mocambique, that soldiers of the Rwanda Defence Force (RDF) left their base on the Afungi Peninsula to patrol a forested area close to the town of Palma. They reportedly found a terrorist group in the Quionga administrative post, retreating towards the Tanzanian border, engaged them and killed 30 terrorists. Saranga said that questions about Rwandan forces “are operational question and I can’t answer it. It’s the force commander who can answer. The enemy may be watching our actions to see what direction we are going to take”. But he volunteered that the SADC member states who will take part in the Standby Force are South Africa, Tanzania, Angola, and Botswana, “and we are confident that, during the operations, more countries may express an interest in supporting Mozambique”.

“The SADC heads of state summit, held in Maputo on 23 June, approved a mandate for the deployment of the Standby Force”, Col. Saranga told reporters. “The objective was to support the national efforts to fight against terrorism in Cabo Delgado. Following up this mandate, in late June there was a joint planning conference, and this event outlined the next steps that should be taken to deploy the force”.

“What is happening right now is the implementation of this plan”, he continued. “The mandate envisaged that the deployment of the force should happen as from 15 July. So from 15 July to now, activities have been undertaken in order to receive this force, which is rather substantial. Steps are being taken so that it can be received and carry out its work. That means there are advance teams that are working with our troops on the ground to receive the force.


PIB: 3% of Nigeria’s Oil Industry OPEX, around $500Million, is Adequate for Hostcom Development, Say Oil Industry Leaders

By Fred Akanni, in Warri

Nigerian oil Industry leaders are reacting to agitations that 3% of Operating Expenses (OPEX) of companies licenced to operate on any hydrocarbon acreage be paid into a Host Community Trust Fund for the communities around the subject acreage, as mandated in the current draft of the Petroleum Industry Bill, is too low.

“I believe there is too much uninformed noise”, says Joseph Nwakwue, retired ExxonMobil Petroleum Engineer, former President of the Society of Petroleum Engineers (SPE), and former special assistant to the Minister of State for Petroleum Resources. “This provision is to provide direct benefits to the host community. It needs to be at a level that does not significantly increase the unit OPEX. We had estimated the impact on cost of operations and hence profitability of the upstream. I really believe 2.5% would work”.

The Petroleum Industry Bill (PIB) is close to final passage at both the House of Representatives and the Senate. But whereas the Senate has passed “the conference committee report in which 3% of companies OPEX in the last calendar year is retained for Host Community Trust Fund”, the House of Representatives stepped down the bill after an hour long, rowdy closed-door session assessing the committee report, as lawmakers from Bayelsa, Delta, and Rivers States, the country’s largest hydrocarbon producers, opposed what they consider a low contribution into Host Community Development.

Elected legislators representing the Niger Delta region at the House of Representatives, are championing 5% of the total operating expenses (OPEX) over 3%. The Niger Delta hosts over 99.9% of all hydrocarbon currently produced. The Dahomey basin, located in the country’s southwest, produces less than 1% of the nation’s output. No other sedimentary basin has contributed to the national production since first oil in 1958.

But those who routinely pay close attention to value creation in oil and gas activity, have a nuanced view.

“3% of OPEX, currently being paid to the Niger Delta Development Commission (NDDC) for the region’s development is estimated at about $500Million annually”, says Taiwo Oyedele, Fiscal Policy Partner and Africa Tax Leader at PwC, the global firm of consultants. “Unfortunately, this has not had any meaningful impact due to mismanagement. My view is that 3% of OPEX for host community development is a fair percentage given the need to make investment in the sector attractive and viable”, Oyedele explains. “I expect that the governance structure as proposed under the PIB will ensure that the funds deliver concrete results and if this is sustained, the amounts available will increase as more investments are attracted. It may also provide a compelling basis for NDDC to be scrapped and the contributions added to the Host Communities”.

The governance structure for Host Community Fund that Oyedele refers to in the PIB, is fairly rigorous. Unlike the payment to NDDC, the PIB mandates clear guidelines on governance of the funds, which, unlike NDDC, are to be locally applied, not granted “globally” to state governments. The draft of the PIB says that the Board of Trustees of Host Community Trust Fund, to be set up by the oil company/ies “shall in each year allocate from the host communities development trust fund, a sum equivalent -(a) 75% to the capital fund out of which the Board of Trustees shall make disbursements for projects in each of the host community as may be determined by the management committee, provided that any sums not utilised in a given financial year shall be rolled over and utilized in subsequent year; (b) 20% to the reserve fund, which sums shall be invested for the utilisation of the host community development trust whenever there is a cessation in the contribution payable by the oil ompany/ies; and (c) to an amount not exceeding 5% to be utilised solely for administrative cost of running the trust and special projects, which shall be entrusted by the Board of Trustee to the oil company/ies. The law also says that host community development plan shall -(a) specify the community development initiatives required to respond to the findings and strategy identified in the host community needs assessment; (b) determine and specify the projects to implement the specified initiatives; (c) provide a detailed timeline for projects; (d) determine and prepare the budget of the host community development plan; (e) set out the reasons and objectives of each project as supported by the host community needs assessments”.

Oyedele says: “I do not think the agitation (for 5% or even more of the OPEX) is warranted. More focus should be on the judicious utilisation of the 3% for Host Community in addition to 3% for NDDC and 13% Derivation for the oil producing states. All together these funds are capable of transforming the region and providing opportunities for the people”. 

Africa Oil+Gas Report asked five Chief Executives of indigenous companies, all of them demanding not to be named. Two did not respond. Two of them nodded in preference of 3% of OPEX for the Host Community Trust Fund. The third said he could live with 5%.

Still, there is one industry leader who supports even higher percentages of OPEX than the two bands that members of the National Assembly are bickering about.  “Beyond a 10% OPEX allocation, I would support a 10% equity participation in the lease”, argues Nedo Osanyande, a widely respected geoscientist, former General Manager of Sustainable Development and Community Relations at Shell Nigeria, and fellow of the prestigious Nigerian Association of Petroleum Explorationists (NAPE). “In the absence of equity participation, I’d support a 10% OPEX allocation”, he says. “Importantly, a sizeable part of this must be spent (at least initially) in community capacity development in managing this fund. Currently, the social organisation capacity is lacking. This is the reason the funds allocation so far – however inadequate –  has not been judiciously utilized”.

Mr. Osanyande says that “with the right social organization capacity, financial resources captured by elites, strong men, and the like would be reduced. Thus far, such capture results in the funds not being invested in the communities”. Arguing that everyone one gains if the communities are happy, he concludes that “hydrocarbon production could easily double, and OPEX costs halved if the hydrocarbon producing communities are happy”. 

But Mr. Osayande’s figures are not popular among his colleagues.

Says a consultant geoscientist who has worked on virtually every draft of the Petroleum Industry Bill since 2008: “Actually the 3, 5 or 10% would have been unnecessary if prior initiatives (13% Derivation, 3% NDDC, 8% Littoral State Allowance, Amnesty payments as well as Niger Delta Ministry mandates) have worked half as expected. They all have not worked because of implementation failures. Some of them are even now being copied as best practice in other countries where they are well implemented”.

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