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NUPRC Calls for Inputs for the Next Phase of Regulations Development

PARTNER CONTENT

The Nigerian Upstream Petroleum Regulatory Commission(NUPRC) has given notice of stakeholder consultation regarding the third phase of regulations development in line with section 216 of the Petroleum Industry Act (PIA) 2021.

The commission invites inputs from Lessees, Licensees, Permit holders, Host Communities, and other stakeholders of the Nigerian Upstream Petroleum sector, between now and January 9, 2023.

1. The matters to which this stakeholders inputs and consultations relate are as follows:

i. Upstream Petroleum Measurement Regulations

ii. Advance Cargo Declaration Regulations

iii. Significant Discovery Regulations

iv. Gas Flare Penalty (Amendment) Regulations

v. Domestic Crude Oil Supply Obligation Regulations

vi. Nigerian Upstream Measurement Regulations

2. Stakeholders are kindly enjoined to follow the link below to download and

review the proposed regulations; https://www.n u p r c.gov. ng/regulation- development-pio-2021/.

3. Accordingly, submissions of inputs to the regulations are hereby requested as part of the process of stakeholder consultation prior to finalization of the regulations, to give meaning to the intent of the PIA 2021

4. All submissions must be made using the format accessible through this link https://WWW.nuprc.gov.nq/wpcontent /uploads/2022/NUPRCRequlation-Comments-Sheet- xlsl.

They must be received at the email address below NO LATER THAN 21 DAYS FROM DECEMBER 19 2022, which means January 9, 2023 (as his publication was put on NUPRC website on December 19 2022).

5. Kindly forward your submissions to the Head Compliance and Enforcement Unit of NUPRC, Kingston Ezeugo Chikwendu on regcon@nuprc.gov.ng, GSM 08077724442 for further necessary action.

Signed:

Engr. Gbenga Komolafe FNSE Commission Chief Executive


Angola’s Hydrocarbon Output Slumps for the Third Consecutive Month

By Angolan National Petroleum and Gas (ANPG) Agency

Translated directly from Portuguese

Angola produced 32,590,947 barrels of crude in October 2022, corresponding to a daily average of 1,051,321 barrels of oil (BOPD) against a forecast of 1,123,215BOPD.

It was 3% less than the 1,091,371BOPD produced in September 2022, which was 7% less than the 1,174410BOPD produced in August 2022, which itself was less than the July 2022 output of 1,177,153BOPD.

Associated gas produced (outside the Cabinda Association) during October 2022 was 69.140Billion cubic feet (bcf), a 10% drop from the 76.6Bcf of gas output in September 2022, which on its own was a 14% slide from the 89.5Bcf produced in August 2022. Naturally the volume of gas made available to the Angola LNG plant in Soyo, dropped 17% to 498MMscf/d from 599MMscf/d in September 2022, which itself was an 18% plunge from 730MMscf/d in August 2022.

1,096MMscf/d was injected, and 300MMscf/d utilized for power generation at oil facilities and the remainder used in oil operations and disposal.

The ALNG Factory produced 2,614,487barrels of oil equivalent (BOE), or 84,338BOEPD in October 2022, with LNG production of 68,188BOEPD, 6 898BOEPD of Propane, 5,311BOEPD of Butane and 3,942BOEPD Condensates.

Associated gas production of the Cabinda Association was 700MMscf/d in October 2022, from which 349,578barrels of LPG (averaging 11,277Barrels Per Day) was extracted and divided into daily production of propane of 6,387barrels and butane of 4,674barrels.

The total production of crude oil, condensate and LPG was 32,940,525BOE, or average of 1,062,598BOEPD; the operational efficiency of the facilities was 89.18% against a forecast of 91.18%.

Angola’s crude oil exports for October 2022 were 33,619,013barrels (or 1,084,484BOPD) against 996,774BOPD predictted. The ANPG lifted around 7,252,023 barrels (22% of total withdrawals), Sonangol P&P lifted 4,859,517barrels (14% of total withdrawals) and the Sonangol EP lifted 1,759,442barrels (5% of total withdrawals).

Rig Activity/Well Count: In October 2022, TEN (10) drilling units were in operation, five (5) of which were drillships, namely West Gemini, Sonangol Libongos, Valaris DS-09, Sonangol Quenguela and Transocean Skyros and one (1) semi-submersible rig Scarabeo 9. There was one ground probe FALCON HP-1000, one (1) Tender SKD Jaya, one (1) Tension Leg Platform TLP-A; one (1) Jack Up Shelf Drilling Tenacious Probe. These 10 units carried out work in twenty (20) wells, including four (4) intervention operations, fiftteen (14) drilling/completion operations and one (1) evaluation, making a total of 8,754 metres of drilling.

Completed in the month: Four (4) development wells (producers), one (1) injector development well, and two (2) interventions in producing wells.

Originally published in the October 2022 edition of the Africa Oil+Gas Report.


Sirius, with Funds in Hand, Takes Over Management of Abura Field Redevelopment

Sirius has now fulfilled all conditions needed to access the funding facility for the planned redevelopment of the Abura field in Oil Mining Lease (OML) 65, and will assume key senior management positions within CMESOMS Petroleum Development Company (COPDC) Limited, the organization which “owns” the project.

Sirius holds 30% in COPDC, who in turn has a Finance and Technical Sales Agreement (FTSA) with NNPC Ltd, the licenceholder of OML 65. But Sirius is the one bringing the finances, as well as technical and managerial expertise, to the project.

With these credentials, Sirius takes fuller control of OML 65 redevelopment, with its executives assuming the positions of Managing Director, Finance Director, Executive Director, and Vice-Chairman of COPDC “and will immediately begin to accumulate cash flow entitlements related to the assumption of operational responsibility for existing production at the Abura field”.

Following the approvals previously secured from NNPC regarding the commencement of Phase 1 of the OML65 Approved Work Programme (AWP), Sirius can now start drawing down funds under the senior loan facility of up to $200Million, executed with (the commodity trader) Trafigura, to finance the well drilling, re-entry and completion in OML 65, notably the Abura field, to boost production by as high as 11,000Barrels of Oil Per Day, to reach, around 16,000BOPD.

The project has come a long way, even though it is yet to take off.

The context: In 2019, COPDC, the Nigerian E&P company founded by Hosa Okunbor, who was very well connected to President Muhammadu Buhari, secured an FTSA with the Nigerian Petroleum Development Company (NPDC), an NNPC subsidiary which holds the right to OML 65, located onshore mid-western Nigeria, in the Niger Delta basin.  COPDC had never operated an E&P asset before it was granted the FTSA, a deal it clinched largely as a result of political connections of its principal.

Sirius Petroleum, as of then, was desperate to get in on the action on any bankable hydrocarbon project. The OML 65 revamp, as it were, has provided it the first real opportunity for relevance.

Phase 1 of the AWP will be undertaken in conjunction with Baker Hughes under a Master Services Agreement (“MSA”) which has been executed with Sirius, and will involve the drilling of up to nine wells on the Abura field, intended to produce the remaining 2P reserves of 16.2 MMbbl1.


Uganda to Re- Nationalise Its Electricity Industry

The Ugandan government wants to “minimize expensive private capital” in the electricity sector by bringing it under direct state management and control.

The country’s public officials are disappointed with the execution of the 20-year concessions granted to two companies for generation and distribution and have decided not to renew them.

Eskom’s generation licenses- to run two hydropower stations- will expire in March 2023 and will not be renewed.

Umeme Limited (UMEME.UG)’s monopoly rights to distribute power in Uganda, will not be renewed when it expires in 2025.

In their place the Uganda National Electricity Company Limited (UNECL), a state-run company which is currently under formation, will manage the generation, transmission and distribution segments of the electricity sector. UNECL, will likely be structured as a Public Private Partnership (PPP) with the state firm as a majority shareholder, according to a statement by the energy, ministry said.

The government hopes, by taking electricity supply back from the private sector, it could enormously reduce costs to consumers.

President Yoweri Museveni has repeatedly complained that expensive private capital was responsible for high electricity tariffs in Uganda, which makes it unaffordable for consumers.


Afentra’s Angola Acquisition: So Far, Still Far

By Sully Manupe, in Windhoek

Afentra has made significant progress trying to win upstream assets in Angola. But the company admits that none of the two deals leading to ownership is likely to be consummated by December 31, 2022.

The sale and purchase agreement with Sonangol Pesquisa e Producao S.A. (Sonangol) to purchase non-operating interests in offshore Block 3/05 (20%) and Block 23 (40%), is subject to a number of conditions precedent (the ‘CPs’), including the receipt of governmental approvals and the extension of the Block 3/05 Production Sharing Agreement until at least December 31, 2040. The Company remains in discussion with all relevant parties in this regard, as the Block 3/05 contractor group continues to progress conversations with the  ANPG, the country’s oil and gas regulatory body, Afentra notes in a release. “Nevertheless, the PSA extension is now unlikely to be finalised before December 31, 2022 and the Company, together with Sonangol, are working on extending the long stop date for the Sonangol Acquisition in order to facilitate satisfaction of the remaining CPs to enable completion in Q1 2023”.

Afentra also signed an SPA with INA – Industrija Nafte d.d. (‘INA’) to purchase a 4% interest in Block 3/05 and an up to 5.33% interest in Block 3/05A offshore Angola (the ‘INA Acquisition’). ”The transaction is now with the Ministry awaiting Governmental approval, and formal completion is anticipated to occur in early 2023”. In this particular case, “given the progress made to date, there is not considered to be any requirement to extend the long-stop date pursuant to the INA Acquisition at this time, as set out in the Company’s admission document”.

Afentra says that Block 3/05 “production for the first nine months of 2022 has been stable and in-line with expectation at 19,160Barrels of Oil Per Day (BOPD) gross. This is equivalent to ~4,600BOPD net to Afentra upon completion of the Sonangol and INA Acquisitions”. in due course.


Savannah Terminates SPA With PETRONAS in Chad, Cameroon

British producer Savannah Energy and Malaysian state-owned PETRONAS have mutually agreed to terminate the Sales and Purchase Agreement (SPA) for the latter’s Chad and Cameroon portfolios.

“Completion of the proposed acquisition remained subject to satisfaction of certain conditions precedent which has not yet been satisfied”, Savannah says in a statement, “and Savannah and PETRONAS have, therefore, mutually agreed to terminate the SPA with immediate effect”.

The agreement was initially announced exactly a year ago to the date of termination (December 13, 2021). Savannah signed an SPA with PETRONAS at the same time it did with ExxonMobil. The ExxonMobil sale has been concluded, but the PETRONAS transaction failed.

If both had been concluded, Savannah would be holding a 75% controlling interest in the Doba Oil Project and an effective c. 70% indirect controlling interest in the Chad-Cameroon export transportation system.

Instead, Savannah now owns a 40% interest in the Doba Oil Project (comprising interests in seven producing fields) with a combined gross 2P Reserve base of 142.3Million barrels (MMbbls) as of October 1, 2022 and expected 2022 gross production of 28, 000Barrels of Oil Per Day (BOPD) and an effective c. 40% indirect interest in the Chad-Cameroon export transportation system comprising a 1,081 km pipeline and the Kome Kribi 1 floating storage and offloading facility, offshore Cameroon.

The remaining 25% interest in the Doba Oil Project is held by the national oil company of Chad, SHT Petroleum Chad Company Limited (“SHT”). The remaining 30% interest in the Chad-Cameroon export transportation system is held indirectly by affiliates of SHT together with the Republic of Chad and the national oil company of Cameroon, Société Nationale Des Hydrocarbures. For reference, in 2020 the Doba Oil Project produced an average gross 33,700BOPD and the Chad-Cameroon pipeline transported a gross 129,200BOPD.


Tullow Chases the Same Fortune as ENI; Takes More Position in Cote D’Ivoire

By Marcus Michelangelo, in Accra

Tullow Oil has signed Production Sharing Contract for new offshore exploration licence in Côte d’Ivoire in order to chase leads in the country’s segment of the Tano Basin.

Tullow will operate the CI-803 licence with 90% equity, the remaining 10% is held by PetroCi. CI-803 covers an area of 1,345 square kilometres and is adjacent to licence CI-524 which is also held by Tullow (90%, operator) and PetroCi (10%).

Tullow produces hydrocarbon in the Ghana segment of the basin, but its forays in Cote D’Ivoire have not delivered commercial results.

In 2021, however, the Italian explorer ENI reported the discovery of a massive tank of oil and gas in their first wildcat in Côte d’Ivoire. Baleine-1X was drilled in 1,200metre water to a TD of 3445metres, targeting Cretaceous sands in the Tano,which is a Transform Margin.  The company currently carries a figure as high as 2Billion BOE as ultimate recoverable reserves in the Baleine Structure.

Tullow’s managers, clearly sat up and took notice. Houston based Vanco (now defunct) had held the acreage in 2007 and just fell short of drilling this major prospect, supported by amplitude and a large ‘gas cloud’, according to a report by GeoExpro. In 2013 and 2014Lukoil drilled the Capitaine EastIndependence and Orca fields nearby, finding sub-commercial volumes of oil in Upper Cretaceous sands, GeoExpro explains

Tullow’s management is convinced it can deploy the geoscientific skill sets that helped ENI to nail the Baleine mega structure. “Significant prospectivity has been identified within the proven Cretaceous turbidite plays, similar to the plays which are producing in the adjacent TEN and Jubilee Fields. The work programme for the initial two and a half years includes reprocessing of existing 3D seismic data, along with prospect evaluation. In CI-524, a number of drill candidates are being matured while preparations continue for an exploration well to be drilled during 2024”.


Smarting from a Stalemate in Nigeria, ExxonMobil Exits Chad and Looks to Wind Up in Eq. Guinea

By Macson Obojemuinmoin, in Kribi

The US major remains fully engaged in Angola but is unsure of investment decisions in Mozambique

It is official. ExxonMobil is done with Chad; one of the four sub-Saharan African countries in which it has operated upstream hydrocarbon assets for the last 30 years.

The company has finalized the sale of its entire upstream and midstream asset portfolio in Chad and Cameroon, including operatorship of the upstream assets (through the sale of Esso Exploration and Production Chad Inc., its subsidiary, and the former operator) for $407Million. Savannah Energy, the buyer, now owns a 40% interest in the Doba Oil Project (comprisinginterests in seven producing fields) with a combined gross 2P Reserve base of 142.3Million barrels (MMbbls) as at October 1, 2022 and expected 2022 gross production of 28, 000Barrels of Oil Per Day and an effective c. 40% indirect interest in the Chad-Cameroon export transportation system comprising a 1,081 km pipeline and the Kome Kribi 1 floating storage and offloading facility, offshore Cameroon.

ExxonMobil didn’t own any upstream asset in Chad. Themajor’s involvement with the country was in the form of the Chad-Cameroon pipeline and the production terminal off the coast of Kribi.

WITH CHAD GONE, ExxonMobil still has shallow water assets for sale in Nigeria and Equatorial Guinea. The former is held up in regulatory challenges. The latter is struggling for the right buyers.

The Nigerian sale in which ExxonMobil is disposing off Mobil Producing Nigeria Unlimited (MPNU), a wholly owned subsidiary, was blocked by the state hydrocarbon company NNPC, with which ExxonMobil has been in arbitration.

ExxonMobil’s Angolan and Mozambican assets are in deepwater. The company has shown no indication, in public, of willingness to divest these. In November 2022, ExxonMobil reported a discovery in Block 15, its sole asset in Angola. The Bavuca South-1 well is part of the Angola Block 15 redevelopment project, aimed at producing approximately 40,000 barrels of oil per day to help offset natural production declines. It is also staying on in deepwater Nigeria, where it has only recently renewed its licences.

The supermajor’s entry into Mozambique is far more recent and whereas there has been significant front end-loading work on a 15Million Tonne Per Annum Liquefied Natural Gas (LNG) project it is leading, the ferocious armed insurgency happening close to the site of the project in Cabo Delgado Province in the north of Mozambique, is holding up Final Investment Decision.


Canada Balances International Scales at Calgary’s Global Energy Show

By Tako Koning

Houston, Texas is the energy capital of the world.

The city of Calgary in Canada’s western province of Alberta is, however, the energy capital of Canada.  With a population of approximately 1.5Million people, Calgary hosts annually the Global Energy Show, North America’s leading, fully integrated energy event which will be held again June 13 – 15, 2023.

Many people are not aware that Canada ranks as the world’s fourth largest oil producer at 4.2Million barrels of oil per day.Only the USA, Russia and Saudi Arabia produce more oil than Canada. This country is also the world’s sixth largest producer of natural gas.

In terms of area, Canada is the second largest country in the world, after Russia, and with its vast sedimentary basins Canada remains much under explored for oil and gas.

This country is also much undeveloped for renewable energy including geothermal, wind, solar, hydro and nuclear energy and increasingly hydrogen. On February 24, 2022 Russia invaded Ukraine leading to serious concerns about global shortages of oil and gas.  Canada has caught the world’s attention due to this country’s ability to provide large volumes of secure, stable and safe supplies of energy for domestic and overseas consumers.

The world’s largest oil and gas event is the annual Offshore Technology Conference (OTC) in Houston but the OTC is primarily focused on offshore oil and gas technology.  In comparison, Calgary’s Global Energy Show is focused on both onshore and offshore oil and gas. As well, it is highly focused on the technology, economics, financing and geopolitics of the energy transition.

The Global Energy Show believes that no single source of energy can meet the ever-increasing global energy demand. This conference is where Canada demonstrates its vision and leadership by bringing key people together to meet global challenges with real-world solutions.  The conference addressesenergy sustainability strategies, how oil and gas is still vital to a functioning economy and uncovering how hydrogen has the potential to power our everyday lives.  The Global Energy Show states that “our major international conference will investigate new avenues for renewable energy and how cleantech investments and innovations are at the forefront of decarbonization”.

The Top 3 Strategic Conference Panels focus on the following:

1. Balancing the International Scales: Are Unsettling Geopolitical Situations Threatening the Energy Transition?

2. Nuclear, The Myth, The Legend

3. The Great Carbon Capture Debate -A Real Solution or Another Way to Extend the Use of Fossil Fuels?

The following will be participating in this globally-focused conference: (1.) Government entities (2.) Service & supply companies (3.) Gas & LNG companies (4.) Integrated energy companies (5.) Transmission & distribution (6.) Refineries and maintenance (7.) Clean technology companies (8.) Power generation and utilities (9.) Technology providers (10.) Legal & industry analysts (11.) National & international oil companies (12.) Financers & investors.

This event includes a comprehensive exhibition floor with over 600 exhibitors across five exhibition halls and a large outdoor zone where heavy oil and gas equipment will be available for visiting, inspecting and purchasing.  The total floor space is over one million square feet.

The 2023 Global Energy Conference anticipates the following:

30,000+ attendees
1,000 Delegates from 50 countries
600+ Exhibiting companies
300+ Presenting speakers
15 National Oil Companies (NOCs)
30 International Oil Companies (IOCs)
The importance of Calgary in the world of energy is also highlighted that the 24th World Petroleum Congress (WPC) will be held in this city September 17 – 21, 2023. The 16th World Petroleum Congress was also held in Calgary twenty-two years ago in 2000. However, the World Petroleum Congress is more useful for high-level government officials including provincial and national energy regulators, ministers of petroleum and energy, and executives of major international and national oil companies.  In contrast, the Global Energy Show is much more focused on grass-roots energy development at all levels, from small to large scale.

The author of this article for the Africa Oil + Gas Report has attended the Global Energy Show for many years.  He believes that this event is an excellent venue for networking and learning.  Furthermore, it provides an opportunity for international and local companies to promote and sell their products.  An example of the opportunities provided by the Global Energy Show is that at last year’s event a pavilion was made available for Nigeria-based oil companies and service providers to meet Canadian and international counterparts and also to meet with the many Nigerian Canadians living in Calgary.

Tako Koning is a senior geologist and energy consultant based in Calgary. He is Netherlands-born but Canada-raised.  He has a B.Sc. in Geology from the University of Alberta and a B.A. in Economics from the University of Calgary.  He worked for thirty years for Texaco in Canada, Indonesia, Nigeria and Angola.  He also consulted in Angola for Tullow Oil and Gaffney, Cline & Associates.   For the past twenty-one years he has been on the International Advisory Board of Africa Oil + Gas Report since it was founded by Toyin Akinosho in 2001.


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.

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