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PGS Completes $450Million Refinancing, Says Seismic Market Is in Strong Recovery

Norwegian marine geophysical company, PGS ASA, has successfully placed a new $450Million senior secured bond with 4-year.

The proceeds from the Bonds will together with cash held on balance sheet be used to repay $600Million of the Company’s Term Loan B (the “TLB”) maturing in March 2024 at par value. The Transaction is expected to be completed around March 31, 2023.

“The offshore seismic market is in strong recovery as multiple years of underinvestment in oil and gas exploration and development, combined with a materially changed energy security situation, drive a strong increase of E&P spending”, the company says in a release.

“The Transaction materially improves the Company’s debt maturity profile while still allowing PGS flexibility to pursue its deleveraging strategy without incurring excessive costs.

  • After the Transaction, $138Million of the TLB maturing in March 2024 will remain outstanding and be repaid at par value from cash flow and liquidity sources
  • The $50Million super senior loan maturing in March 2024 remains in place. The loan may be extended by one year at the Company’s discretion or alternatively be replaced by a revolving credit and guarantee facility of up to $75Mllion
  • The Bonds are callable after two years with a customary declining call premium profile

PGS made a repayment of $83Million on its export credit financing (ECF) loans in early February 2023. The remaining balance of the ECF loans is $180Million gross (~$140Million net, if considering ~$40Million of restricted cash for debt service on the ECF loans).

The Bonds will carry a fixed interest of 13.5%. The total interest costs for the Company will be reduced following the Transaction as the Company will have significantly less debt. In addition, the interest on the remaining portion of the TLB is expected to be reduced by approximately 1% as a result of improved credit ratings and lower leverage. The Company remains committed to continue reducing its debt and thereby further reduce interest cost.

PGS insists it retains a strong liquidity reserve after the debt repayments.

DNB Markets, a part of DNB Bank ASA and Pareto Securities AS acted as joint bookrunners (the “Joint Bookrunners”) for the issuance of the Bonds. Advokatfirmaet BAHR AS is acting as Norwegian counsel to the Company and Wikborg Rein Advokatfirma AS is acting as Norwegian counsel to the Joint Bookrunners and Nordic Trustee.

PGS ASA and its subsidiaries provides a broad range of seismic and reservoir services, including data acquisition, imaging, interpretation, and field evaluation to the oil and gas industry, as well as to the broader and emerging new energy industries, including carbon storage and offshore wind.

Seplat Sues ABC Orjiako in Court For “Impersonation, Grave Act of Deceit”, Demands ₦5Billion

Seplat Energy has commenced legal proceedings against its former chairman Ambrosie Bryant Chukwueloa (ABC) Orjiako, and his consulting company Amaze Limited, demanding the sum of five billion naira (₦5 Billion) as damages.

Seplat is levelling allegations of a host of corporate governance infractions against Mr. Orjiako a co-founder of the company, who retired from the board in May 2022. The proceedings centre around the manner of execution of his consultancy contract with the company, awarded in mid-2022, for services that would assist Seplat Energy Plc with specific and essential external stakeholder engagements he was involved in, which continued beyond the date he stepped down.  At the heart of that contract is to engage with agencies of the state to deliver on the closure of the company’s acquisition of the entire shares of Mobil Producing Nigeria Unlimited, which has been held up for over a year.

That contract was suspended before this court challenge.

Part of Seplat’s claim in the writ of summons is that Orjiako unilaterally issued a letter purporting to be from the company, with the company’s letterhead-without Seplat’s approval-to the President of Nigeria and Honourable Minister of Petroleum, “an act of deceit and false representation especially as it is intended to bind Seplat in a transaction worth over $300Million”. Seplat alleges that, in the said letter, Orjiako describes himself as Pioneer Chairman, a position unknown to the relevant law on corporate matters, especially as the letter sought to create the false impression that he had the authority of Seplat to bind the company in an offer of rights worth over $300Million.

The timing of the writ of summons, filed at the Federal High Court in Abuja, capital of Nigeria, on March 21, 2023, is telling, coming less than two weeks after a Federal High Court in Lagos issued an interim order restricting Roger Brown, the Chief Executive of Seplat , from everyday running and management of the company, based on a motion by some stakeholders on notice for interlocutory injunction.

The court action against Mr. Brown, instituted within 48 hours of his deportation for “charges of racism, favouring of foreign workers, and discriminating against Nigerian employees”, was clearly suggestive of a high stake wangling between some very interested persons and the Seplat’s board and top management.

In the statement it issued after Roger Brown’s deportation, the Board of Directors had pointedly noted that the allegations against Brown, a British national, are “a spurious and vindictive reaction to the enforcement of corporate governance standards in the company.”

The question had always been: whose interests could Roger Brown and the multinational board of directors of Seplat have hurt so badly that they don’t mind wrestling the company to the mud? Whose sense of justice has been affronted? Whose sense of entitlement has been so bruised, or whose sense of outrage has been stoked by Brown & Company in a way that ‘the victim’ feels justified in throwing everything into the fight?

Seplat’s top six shareholders are Maurel & Prom (20.7%); Petrolin (14.5%) Platform Group (11.5%), Sustainable Capital (SA) 9.5% and Shebah Group (8.5%). Nigerian institutional investors (Pension funds and insurance companies) hold about 15%.

Mr. Orjiako’s interests in Seplat are held through Shebah Group, of which he is founder. The group has a representation on the board, as does Platform Group and M&P, all three of which are Seplat’s co-founders. Petrolin and Sustainable Capital (SA) decline to have seats on the board.

In its writ of summons, Seplat is asking the court to declare that Orjiako and Amaze Limited (his consultancy company) acted in contravention of the Companies and Allied Matters Act (CAMA) and the operations and regulations of Seplat when they unilaterally issued a letter dated December 22, 2022 purporting same to be from Seplat to the President of Nigeria and the Honourable Minister of State for Petroleum Resources, without the approval of Seplat or its Board of Directors.

Exxon Gets Better Fiscal Terms for Angola’s New Deepwater Blocks

Angola’s National Agency for Petroleum, Gas and Biofuels (ANPG) has announced an improvement of the fiscal terms of Blocks 30, 44 and 45 in the Namibe Basin, “within the scope of the Contracts for Services with Risk (CSR) and Extension of the Initial Phases of Exploration for the referred Blocks”,

These improved fiscal terms are expressed in a Memorandum of Understanding jointly signed in Luanda by the country’s General Tax Authority (AGT), ExxonMobil and (the state hydrocarbon firm) Sonangol.

In the context of the agreement, ANPG expects some $15Billion to be invested “in case of commercial success, with the State expected to raise between $20Billion and $40Billion for conservative oil prices of between 50 and 60 dollars a barrel”.

At the signing ceremony March 14, 2023, Paulino Jerónimo, Chairman of the Board of Directors of ANPG, emphasized the benefits in mitigating the decline in production, replacing reserves and creating jobs: “The Memorandum of Understanding, which is the result of the negotiated terms, provides considerable benefits for all parties involved. I highlight the estimated investments of $200Million dollars for studies and the drilling of the research well, until 2024. And the estimated revenue for the Angolan State from the development of a single large commercial discovery, which can vary from $20 Billion to $40Billion, if we consider a conservative analysis price between 50 and 60 Dollars/barrel”

Melissa Bond, Exxon Mobil’s General Manager in Angola, said the MoU reinforces the company’s commitment to the exploration sector in the country, namely in southern zone of Namibe, as the exploration of Blocks 30, 44 and 45 in the Namibe Basin opens a new door for the consolidation of the operator’s activity in the country”.

GHL Moves Rig on to the Oyo Field, Targets “The Big Ewo”

By Macson Obojemuinmoin, in Lagos

General Hydrocarbons Limited has moved the platform rig Blackford Dolphin to a location in deepwater Nigeria for a multi-well campaign on the Oyo oil field and adjoining prospects.

It will start operations by the second week of April 2023.

The company is particularly excited about the potential of a deep prospect in the vicinity of the Oyo North West Structure. The prospect, a robust, four-way closure hemmed in by a roll over fault, is called ‘Ewo Deep’. Top officials at GHL describe it as “The Big Ewo”.

An analogue of the Big Ewo, in another part of OML 120

Although GHL wants to establish revenue inflow by re-entering and hooking up some of the producer wells that have been shut in for the past five years, there is also the proposition that “access to development funding will be enhanced if Ewo proves to be what it seems”, company sources say.

The Oyo field and associated prospects are located in Oil Mining leases (OML) 120 & 121. The field was producing before the acreages were revoked from Erin Energy, its previous operator.

GHC also wants to drill new prospects that had been identified and listed in the prospect inventory. Company sources insist that the available seismic and petrophysical data have been extensively reviewed and the locations high graded. “Schlumberger has worked on the studies, Baker Hughes has taken a comprehensive look and (the Nigerian subsurface consultant) D’Harmattan has been part of these studies”, GHL sources, who want to remain unnamed, tell Africa Oil+Gas Report. “GCA (Gaffney Cline & Associates, a firm of ‘Competent Persons’) has evaluated what Schlumberger and others have done”.

Africa Oil+Gas Report’s skepticism is borne out of the fact of the chequered history of OMLs 120 and 121.  Production from the Oyo field, the only producing property in the acreages, fell rapidly almost as soon as first oil gushed out in December 2009, crashing from 22,500Barrels Per Day (BOPD) to 4,000BOPD in the space of 10 months. By November 2014, the six well field was delivering less than 1,000BOPD.  Two wells drilled in 2015: Oyo- 7 and Oyo -8, took the field to over 10,000BOPD, but Erin Energy was severely indebted at the time and was so burdened by litigations and other woes it keeled over into bankruptcy. The Nigerian state moved in to revoke the assets in 2019. The company lost its Ghanaian asset the same way two years after. It is noteworthy that Oyo -7 and Oyo-8 are two of the locations that GHL

Oyo Field Performance Profile

proposes to re-enter in the course of the campaign. No one says that there is any new seismic acquisition or processing. The lingering question is: If the ‘Big Ewo’ was sitting there all along, how come no one ever drilled it, in all the 30 years since the acreages were first awarded?

The planned drilling and re-entry in Oyo field &Co would be GHL’s first field operations since its incorporation in 2007. The company, owned by Nigerian investors, was discretionally awarded the OMLs 120 and 121 in 2020, several months after the revocation from the previous asset holder. It was one of the last discretionary awards of acreages under the laws that governed the country’s petroleum industry at the time. In the Petroleum Industry Act (PIA), which is the new overarching legislation of the industry, no company will access an acreage outside of the process of a bid round.


Uganda’s Petroleum Authority Joins the DANR Hub

The Petroleum Authority of Uganda (PAU) has joined the Data as a National Resource (DANR) hub.

The PAU, which monitors and regulates the exploration, development, and production, the refining, gas conversion, transportation, and storage of petroleum in Uganda, joins the Petroleum Agency of South Africa, SKK Migas, the North Sea Transition Authority, and the National Offshore Petroleum Titles Administrator as early adopters and supporters of the DANR initiative.

Powered by the PPDM Association, DANR was launched last year to support established and emerging economies in leveraging successes and experiences from other areas. DANR aims to bring together regulators, National Oil Companies (NOC), National Data Repositories, and technology and service providers to collaborate, share experiences, and access training and resources.

“The PAU, which has been a member of the PPDM Association since 2019 is proud be part of the DANR Hub and congratulates the PPDM for this new initiative. The Authority set up a state-of-the-art ICT data centre in 2021. This data centre is part of the National Petroleum Data Repository infrastructure, which will include a Real-Time Monitoring Centre (RTMC), a disaster recovery facility, and a seismic data transcription facility among others. We, therefore, look forward to benefiting from the various DANR resources and events to improve how we manage our data at the PAU,’’ said Ernest Rubondo, the Executive Director of the PAU.

“It’s a great pleasure to welcome the Petroleum Authority of Uganda to the DANR community. Our community is dedicated to providing practical support for managing data as a national strategic resource through information sharing, research, training and networking. We hope that as the DANR community grows we will realise even more benefits to the PAU,” said Trudy Curtis, CEO of the PPDM Association, the organization heading DANR.

DANR is accessed through subscription, at minimal cost. Sponsorship is invited from service providers, and a range of sponsorship opportunities are available. For more information visit

Chevron Starts Production of a Marginal Oil Field in Angola

Chevron has commenced production on the Lifua field, located in Angola’s offshore Block 0, at a water depth of 70 meters. The development of the field is phased, with the Lifua-A fixed metallic platform, model (STS), recently installed, representing the first of three phases (A, B and C), for the Lifua project.

“The Lifua-A platform is interconnected with the existing facilities in the Takula Area and is expected to produce a total of 6,500 barrels of oil per day from the Vermelha and Likouala reservoirs”, according to ANPG, Angola’s petroleum regulatory agency.

“The equipment was 100% manufactured in Angola, applying low-cost concepts and technologies with a short manufacturing time”, ANPG explains in a release.

“The development strategy for this oil field is to apply innovative solutions, using existing facilities and services to reduce development and operating costs, in order to increase the economy of small discoveries of petroleum found in the current Development Areas”, the regulator says.

Chevron, through its Angolan subsidiary CABGOC, is the operator of Block 0 with 39.2%. Partners include Sonangol EP (41% interest), TOTALEnergies (10% interest) and ENI (9.8%).

NDEP Leads the AOGR Top Ten

Nigerian Indies: The Talented Tenth Annual 2022


Africa’s growth as an industrial marketplace is going to be determined by its exceptional companies

By the Editorial Board of the Africa Oil+Gas Report…


It has been a bruising 24-month period for most Nigerian owned Exploration and Production companies, the object of The Talented Tenth, our annual ranking.

2020 was the year of the epidemic, which impacted every sector of the global economy and from which the hydrocarbon industry recovered in 2021. But 2021-2022 proved to be a season of crude evacuation disruptions in Africa’s largest economy. The 539,000Barrels per day (BPD) drop in the country’s output (from 1.676MillionBPD of crude oil and condensate in January 2022 to 1.137 MMBPD in September 2022), is largely related to the turmoil in the scores of hydrocarbon assets that these companies manage across the length and breadth of Nigeria’s Niger Delta basin.

No one is spared. The best corporate governance, the most carefully wrought environmental and community engagement ethics, could only go some distance in mitigating the Nigerian challenge.

Four grid length crude evacuation pipelines lay mostly prostate in the three months between August and October 2022, imperiling the possibility of exporting over 400,000BOPD of crude. The NPDC operated TransForcados pipeline in the western Niger Delta had, at the time, less than 80% uptime in the year. The ENI operated Beniboye to Brass pipeline has performed even worse. Shell’s Trans Niger Pipeline (TNP) has been out of work since March 2022 and the AITEO managed Nembe Creek Trunk Line (NCTL) hardly functions. So that export operations in six Nigerian owned E&P companies, with oil producing fields onshore eastern Nigeria, were effectively shut down from February to August 2022.

Five Nigerian owned companies, with oil producing fields onshore western Nigeria had essentially zero hydrocarbon output in September 2022.

Luckier are five Nigerian owned companies, whose main producing assets are in shallow water. They have had, unlike their peers, uninterrupted access to production.

This is the context in which this fifth edition of the Talented Tenth, is determined.


Nigeria is the main playground of Africa’s homegrown independents.

Nowhere else on the continent provides the ready breeding ground for this unique species of Exploration and production companies.

But what do we mean by the term Independent?

When a non-state-owned E&P company, holding one or several oil and gas permits, and exploring and or producing them, is not large enough to be considered a Major, producing, in excess of 1Million Barrels of Oil and Gas Equivalent per day, then it is an independent. The world has only six majors: ExxonMobil, Shell, Chevron, BP, TOTAL and, to a lesser extent, ENI. All other E&P companies, the largest of them being ConocoPhillips, are ranked as Independents.

Over 25 private Nigerian owned, indigenous independents produce oil and gas from the bowels of their hydrocarbon rich country. In February 2022, their total, operated crude oil output capacity averaged slightly less than three hundred thousand barrels of oil per day (300,000BOPD). That’s a significant contribution from the private sector in any petrostate in the world.

Some of these companies are leading the charge on in-country beneficiation of hydrocarbon resources. Some are keen champions of the industrial society. Yet many-and justifiably so-are just about the extraction: “to win and carry away”.

At the Africa Oil+Gas Report, we understand that a continuous evaluation of the context of growth and challenges of the Nigerian independent provides a clear line of sight to opportunities for investment in Africa’s hydrocarbon properties.


THE TALENTED TENTH ANNUAL, of which this article is the fifth edition, is an intelligible ranking of the top 10 progressive, indigenous Nigerian E&P Independents.

This is where we publish, in few hundred words, efforts of those Nigerian indies, who show the most willingness and ability to grow; who are keen on operatorship and not content to be mere partners. Those firms whose choice of projects help catalyse the industrial economy and who exhibit old fashioned aggressiveness that is not contaminated by the rentier instinct.

While corporate governance shines bright on our radar, we take more than a cursory look at the debt profile. We have a soft spot for companies who are angling to diversify into midstream, even downstream segments, to help tackle the country’s industrial challenges. We are, of course, passionate about healthy focus on community development.

We acknowledge that a company’s emphasis on everything but profit will not guarantee its survival.

We are reviewing, in this fifth outing, an earlier declaration that this list will exclude companies who become operators by default. Operatorship of E&P assets is a long work in progress and as more enterprises learn to manage and optimise output of oil and gas fields, the quality of the management is as important as the process through which they become managers.


No 1- NDEP

Niger Delta Exploration and Production (NDEP) retained the lead, for the second consecutive time, among the top ten progressive, indigenous Nigerian E&P Independents.

The company reported 26,000Barrels of oil Equivalent Per Day (26,000BOEPD) net in 2021. This is constituted of 11,000BOPD and 82Million standard cubic feet of gas per day from both its 100% owned Ogbele field in eastern Nigeria and the 18.75% owned Oil Mining Lease (OML) 34 in the west of the country.

The OML 34 investment provided a firm mooring for First E&P, as it strived to develop the Anyala (OML83) and Madu (OML85) fields.

The cash register has also been ringing. Revenues increased by 41% from $91.3Million in 2020 to $128.7Million in 2021 and Profit after Tax leaped by 68% from $43.3Million in 2020 to $73.1Million in 2021.

It’s always time for work. NDEP had moved a rig to site on the Ogbele field, its flagship asset, as of the time of writing this report. It’s the second campaign in two years. The current programme is to drill four wells, one of them a gas probe and the other three intended “to arrest decline and reset our production capability higher than what it currently is”, the company’s management says.

NDEP has been producing crude oil from the Ogbele field for 17 years, exploiting what was called a marginal field whose recoverable reserves was estimated at 5Million Barrels at the time it was acquired.

The visioning process to diversify into several aspects of the hydrocarbon value chain is trending among Nigerian E&P companies, but NDEP has been an integrated energy player for the last 10 years and remains the most diversified among Nigeria’s independents. It has always produced crude oil,; it runs a sizeable gas processing plant (100MMscf/d) through which it has eliminated routine gas flaring since 2012, and has expanded its refinery from a 1,000BPD topping plant it installed in 2011 to three modular trains with optimum input capacity of 11,000BOPD to deliver Diesel, Marine Diesel, DPK, Naphtha and High Pour Fuel Oil. NDEP’s wish to introduce Premium Motor Spirit (Gasoline) has been so far discouraged by the government’s insistence on controlling the price of this particular product.

Ogbele field’s crude oil output capacity growth of 2018 to 2021 (6,500BOPD to 9,000BOPD to 12,000BOPD) has been curbed by the acute challenges of evacuation in 2022 (although that story is still evolving). And it is not always a given that every barrel of crude stranded for export can be refined.

NDEP has been working on the alternative to barge its crude in the last nine months.

Still, the integrated scope of NDEP oilfield practice calls for an evaluation outside conventional upstream product output analysis.

The volume of refinery products sold to the market has doubled from 37Million litres in 2020 to 74Million Litres in 2021, the annual report says. “Between the end of 2021 and the end of third quarter 2022, we have produced 110Million Litres”, declares Gbite Falade, NDEP’s Chief Executive Officer. ”Now we are on course to reach 150Million Litres by the end of 2022”.

Behind those numbers are significant logistical issues. A case in point is the commercialisation of Naptha, which was originally intended as a feedstock for gasoline. As gasoline production is a non-issue for now, the produced Naptha has always been spiked into the crude stream and exported. But the five-month long outage of the TransNiger Pipeline in 2022 meant that there was no market for the Naptha as it is not in demand in Nigeria. “We had to work with regulators and standards agencies, for the licencing for storage and export of Naptha, satisfying very stringent requirements”, Falade explains. In the event the company has one petroleum product, outside of raw crude and gas, that is a foreign exchange income earner.

NDEP’s refining growth is set against the background of the unproven nature of the crude oil refining landscape.

Unlike upstream work, which teems with activity and skills that can be hired round the corner, the refining landscape lacks a robust technical workforce.

State owned NNPC, with combined nameplate capacity of 445,000BPSD, has been the only warehouse of refining skills in the country, but it has been chronically inefficient and hasn’t produced anywhere close to 15% of its capacity in 15 years. “Local support from a technical and operational point of view is lacking”, Falade says. Which is why the company has always had to bring in Original Equipment Manufacturers (OEM) personnel to ‘put out fires’, in a manner of speaking. The company has been investing in upskilling and ensuring that OEM personnel adequately pass on the skills.

Other challenges have tested the capacity to deliver. Falade recalls the vigorous work of lowering the pour point of the High Pour Fuel Oil, one of the refinery’s top revenue earners. “At atmospheric pressure, the product was congealing, such that offtake was complicated”, he explains. He is happy to conclude that the resolution of every one of these complications has aided the improvement of the refining ecosystem. “There’s a curve we are passing which anyone who comes after us would not need to navigate”.

Since 2011, NDEP has operated a 100Million standard cubic feet per day (100MMscf/d) gas processing plant from which it pipes 35MMscf/d to the NLNG system at Bonny. But crude oil evacuation issues have forced the company into a force majeure mode with the NLNG as the bulk of the supply to NLNG is associated gas.

Those hitches haven’t killed the vision “to position Ogbele as an emerging gas processing hub, in the Eastern Niger Delta region”.

The company started acquiring additional capacity build-up for the gas processing plant in 2019. Early in 2020, it took a Final Investment Decision (FID) to increase the processing capacity to 400MMscf/d. “Investments in this project will continue, with completion projected before the end of Q4 2024”, NDEP explains in a report.

The project is being held up by delays in securing the assets to provide the feedstock.

Apart from the Ogbele field and the OML 34, which it doesn’t manage, NDEP operates the Omerelu marginal field, still undeveloped. Offshore, it manages the Oil Prospecting Lease (OPL) 227, an exploration acreage. NDEP extended its upstream operational footprint in 2019 by drilling an appraisal well in OPL 227, with disappointing results. It deployed a rig on the Omerelu structure and encountered gas in the sidetrack hole, as prognosed.

NDEP is more a Pan African hydrocarbon upstream player than any of its peers. It is in a joint venture with NilePet, the South Sudanese state hydrocarbon company. It won a lease in the Ugandan 2015/2016 bid round but dropped the asset as a result of governance concerns. It has since ceased conversation with the Mozambican government, for a licencing award for onshore natural gas development.

NDEP is a nimble enterprise that started life as Midas Drilling Fund in 1992 with the idea of having more than a handful of shareholders pooling resources, a contrarian thinking to the concept that created most Nigerian independents. The company holds a regular, annual, well attended General Meetings, and publishes an annual report, going back to 2013, on its website. It has a non-executive chairman and the board, filled with representatives from as far afield as Petrolin, the Geneva headquartered international petroleum group. None of the company’s founders is a member of the current board.

NDEP is proud of its partnership deal with the host communities around the Ogbele field which involves a clause that allocates 5% of the annual profit to the communities. It is one of the most generous partnerships that any Nigerian independent has initiated with its neighbouring constituents.

NDEP is a smart, highly technically resourced company that is continually looking forward.


NDEP CEO Gbite Falade: “The resolution of every one of these complications has aided the improvement of the refining ecosystem. There’s a curve we are passing which anyone who comes after us would not need to navigate”.

Seplat Energy’s net production of 43,337Barrels of Oil Equivalent Per Day (BOEPD) year to date (by end September 2022) is the largest of any Nigerian founded, non-state-owned operator. The split is almost equal parts for gas and oil, and while it is the lowest since 2018, despite the inclusion of the volumes from Eland Oil & Gas, which the company acquired in 2019, the figures run in inverse proportion to the scale of the ambition.

Seplat dreams big and it is always on an acquisition mode. But its story of transaction hitches and project delays in the last two years reminds us of a 1980s quote in the Nigerian daily, The Punch by the columnist Tunji Lardner: “Nigeria, desperately wants to be great…but some Nigerians won’t let her”.

Seplat’s revenue leapt by 38% from $530.5Million in 2020 to $733Million in 2021. Gross profit was even higher; a 129% hop from $124.6Million in 2020 to $285.2Million in 2021. The 2020 loss before tax of $80.2Million was turned into a profit before tax of $177.3Million in 2021.  But Seplat’s 2021 annual report doesn’t indicate Profit After Tax, which is curious.

Seplat could have grown larger in asset holding since the last ranking but for the intervention of the state hydrocarbon company, NNPC, which held up its bid to conclude the purchase of the entire share capital of the Nigerian unit of Exxon Mobil Corporation – Mobil Producing Nigeria Unlimited (MPNU) for a consideration of $1.28Billion. The asset is the entire offshore shallow water business of ExxonMobil in Nigeria, producing 95,000BOEPD in 2020 (92% liquids). Based on 2020 pro forma working interest volumes for Seplat and MPNU, “the transaction would deliver 186% increase in production from 51,000BOEPD (capacity) to 146,000BOEPD; 170% increase in 2P liquids reserves, from 241Million barrels ( MMbbls) to 650MMbbls; 14% increase in 2P gas reserves from 1.501Triillion cubic feet (Tcf) to 1.712Tcf, plus significant undeveloped gas potential of 2.910Tcf (JV: 7.275Tscf); and 89% increase in total 2P reserves from 499 MMboe to 945 MMBOE.”

A Period of Waiting…

As it waits out NNPC’s stalling of the ExxonMobil purchase, Seplat’s portfolio comprises eight oil blocks- direct interests in seven blocks in the Niger Delta area, four of which (OMLs 4, 38, 41 & 53) SEPLAT operates, and one further (OML 55) revenue interest.

Seplat has had to wait in other areas. The company is involved in the Assa North-Ohaji South project (ANOH), aimed at monetising 4.3 Trillion cubic feet (Tcf) of and 215Million barrels (MMbbls) of condensate, one of the largest greenfield gas condensate development projects under construction in Nigeria. ANOH will develop Ohaji South gas and condensate field located within the license the Seplat operated block OML 53 and the Assa North field in Shell operated license block OML 21. The Seplat promoted part of the project will develop 50% of the reserves, while Shell will develop the other 50%. The two fields are together expected to produce 600Million standard cubic feet per day (Mscfd) of lean gas. Seplat expects to produce 300MMscf/d, 22,000Barrels Per Day of condensate and 38,000 Tonnes of Liquefied Petroleum Gas (LPG). This Seplat part of ANOH project will cost $650Million. The updates

are cheery: ▪ Mechanical completion expected in H2 2022 ▪ all fabricated equipment now in Nigeria with over 90% delivered to the project site ▪ All static process equipment foundations and most rotating equipment foundations completed. ▪ Overall completion for foundations at circa 90% ▪ Installation phase underway. – Installation of pipe racks, inlet manifolds, compressors, gas turbine generators, E-House in progress.

ANOH is held up and cannot be commissioned in 2022 largely because the evacuation pipeline for the gas is not in place. Gas is meant to be pumped into the grid length Obrikom-Obiafu -Oben (OB3) pipeline through a 23 kilometre Spur line, en route to the market, but neither the OB3 pipeline, nor the Spur line from the field to the OB3, are completed. NNPC has been constructing OB3 for over 15 years. It is also constructing the spur line.

Leader in domestic gas market

Seplat Energy is a key player in the domestic gas market (a high mark in the ranking criteria). It’s gas output has turned back up, cruising to 260MMscf/d in 2022 after dropping from 291MMscf/d in 2019 to 220MMscf/d in 2020,

….and contributor to local crude refining: Seplat commits to the Ibigwe Refinery by supplying, uninterrupted, 2,000BOPD to the refinery in the last one year. (Seplat’s contribution of feedstock to the refinery is higher than the owner, Waltersmith’s own contribution (See below).

Seplat is on the brink of a huge transformation:  Takeover of 95,000BPD MPNU, and commissioning of a 300MMscf/d plant, will be significant achievements. But even if you insist that these two have remained: “to be delivered”, what about the completion of the Amukpe-Escravos Pipeline which has provided the company an alternative evacuation route, to the TranForcados Pipeline, for 35,000BPD of crude oil?

Seplat, like NDEP, is a transparently governed E&P independent.

In 2020, it welcomed a new Chief Executive Officer, taking over from a man who co-founded the company in 2009. Between 2021 and 2022, it saw off, from its board, the two founders of the company. Basil Omiyi, the company’s new chairman, was the first Nigerian to be appointed CEO of Shell E&P in Nigeria. this kind of open court running of one of the largest enterprises in the land, counts for a lot. As we have indicated here before, whereas The Talented Tenth Annual has to rely on its own intelligence gathering skills for accessing the production figures and operational challenges of most Nigerian independents, this dual listed company (London Stock Exchange, Nigerian Stock Exchange) has its data laid out bare in public, even when the details are not entirely-in the slang of the social media-likeable.

SEPLAT started business as a Special Purpose Vehicle for the acquisition of Shell/TOTAL/ENI’s 45% in OMLs 4, 38 and 41 and rapidly grew production from 20,000BOEPD (gas + liquids) in 2010 to 51,183BOEPD in six acreages including Oil Prospecting Lease (OPL 283) and OMLs 40, 53 in 2020. These figures are net to SEPLAT.

Seplat has been more aggressive with the drill bit since 2021, fulfilling its 2020 promise to “return to a level of drilling and development activity not seen since 2015”. The Sibiri -1 well, drilled in OML 40, was the only exploratory probe in the Niger Delta in 2021.

Despite the daunting Nigerian risk, SEPLAT looks sure to prevail and grow in the next five years, with its corporate governance structure, its constant watching its pocket with ratio of spending and debt to production revenue and its ability to manage its relationship with all the state hydrocarbon companies it works with, including the NPDC (with which it has a Joint Venture operations in OMLs 4, 38 & 41, the Nigerian Gas Transmission Company (with which it has formed an Incorporated Joint Venture midstream gas company) and NAPIMS, the investment arm of NNPC which runs the JV relationship in OML 53.

No 3- NDWestern

NDWestern Ltd has a large, vivid dream: to acquire the entire shares of Shell Petroleum Development Company (SPDC) Nigeria, operator of the Shell/TOTAL/AGIP/NNPC Joint Venture. That joint venture manages 19 Oil Mining Leases, all located on the shelf (onshore and shallow water), and the cost of acquisition could be up to $3Billion. For a company described by its own CEO, Eberechukwu Oji, as understated, the statement that NDWestern will make if it takes over Shell in Nigeria, would be thunderous. NDWestern is on the final lap of the competition for that acquisition, racing with two other companies who could clinch the prize.

But the proposed takeover of Shell has not reached the stage that could pull it in the scope of this article, unlike the Seplat deal with ExxonMobil. What is compelling about NDwestern is that for the last seven years, it has been the largest, non-state-owned indigenous producer and supplier of natural gas into the domestic market.

That is enough to be among the top three in the Talented Tenth ranking. The building of an industrial state matters. Gas in the domestic economy is a key plank.

The company co-operates the Oil Mining Lease (OML) 34 with the NPDC, the upstream jewel of the NNPC group. NDWestern has no publicly available annual report like NDEP or Seplat Energy, but field data available to Africa Oil+Gas indicates a gross output of 14,000Barrels of oil and condensate per day and 323Million standard cubic feet per day of gas in the first nine months of 2022. The gas is sold to the country’s largest electricity plants in Ughelli, Egbin, and Olorunsogo. Off takers also include Dangote Industries (for the fertiliser plant) and N-Gas, the NNPC-Shell-Chevron owned company that delivers gas to Benin, Togo and Ghana through the West African Pipeline.

NDWestern wants to do more: to build a 10,000BPSD capacity crude oil refinery and facilitate an industrial park in OML 34, supplying gas and petroleum products and power to companies which locate their activity in the Utorogu Industrial Park, to be cited in the vicinity of the gas processing plant. “We share a lot of benefits in co-locating”, Oji tells Africa Oil+Gas Report. “We are working on an export route. There is a rail line if you need to transport the products from the industrial park inland. There is a case to be made to extend a very short portion of the rail line to Warri wharf so that the export-oriented manufacturing firms in the park would have the option of a rail line to take their products straight to the port and then straight for export. But before that infrastructure is built, with the road, a very short road trip, you can get to Warri wharf and then you can export your product”.

NDWestern benefits from the technical strength of NDEP, the top performer in the Talented Tenth ranking. The 11-year-old company is majorly owned by NDEP (42%), Petrolin (40%), First E&P (10%) and Waltersmith Petroman (8%). It was formed as a Special Purpose Vehicle for the acquisition of the 45% stake owned by Shell/TOTAL/ENI in OMl 34, the gas and condensate rich asset in the Western Niger Delta. This company is a joint operator, with state firm NPDC, of OML 34.


Headwinds: NDWestern has been unable take a Final Investment Decision on the 10,000BPD refinery. “We have been on a bit of a lengthy commercial negotiation with our JV Partner, NNPC on the split of investment and responsibilities for the modular Refinery (led by ND Western) and the Condensate Refinery (led by NNPC), 10,000bbls per day each”, Oji explains. “Once the discussions are concluded, we will make a joint public announcement”.

NDWestern does not see the delay in the go-ahead on the refineries as stalling the Industrial park project. “The Park has many segments including the Gas Based Industries sector, the Eco Park, the Agro Park which are making progress at their different pace”, Oji explains. “Our particular model recognizes that industrialization does take time and we are here for the long haul”.

NDWestern is also not worried that the Nigerian government has dusted off the plan for the Ogidigben Park (which has similar aspirations to Utorogu Industrial Park and is not a far distance away). “If you think about it, the Niger Delta needs as many of these Parks as we can get to speed up industrialization of the region. We must domesticate jobs in the Niger Delta to combat the attractiveness of criminality and crude theft in particular. I see an opportunity to supply gas to Ogidigben Park due to their proximity to Utorogu Plant”.

If there’s any surefooted Nigerian company which has a solid future, at least in the near term, NDWestern is one.


Platform Petroleum, also a marginal field producer, makes the Talented Tenth for the second time in its five editions.

Thirteen years after the company commenced production of condensate, exported as crude oil, from the Egbaoma field, in Oil Mining Lease (OML) 38 in the north west of the Niger Delta basin, it started, in 2020, to supply lean natural gas to the Nigerian domestic gas market, through the Nigerian Gas Company (NGC) operated Oben-Obiafu-Obrikom (OB3) pipeline. With a 10 year Gas Sales Agreement with the NGC, committing 10 – 30Million standard cubic feet of gas per day supply to the OB3, Platform becomes a local natural gas supplier of some reckoning, the only indigenous marginal field operator with that level of commitment of gas into the “national gas grid”. It’s a steep reversal from the situation in 2014 when, after installing a 30MMscf/d gas processing plant, the company faced commissioning hitches and had to bring in partners (Gas Train Limited/Capital Alliance Partners) to take financial and operational stake in the plant.

With a 10 year Gas Sales Agreement with the NGC, committing 10 – 30Million standard cubic feet of gas per day supply to the OB3, Platform becomes a local natural gas supplier of some reckoning, the only indigenous marginal field operator with that level of commitment of gas into the “national gas grid”.

Platform has repurchased the 30MMscf/d LPG/NGL Plant from Gas Train Limited/Capital Alliance Partners. With the completion of this transaction, Platform now operates a full-cycle gas/condensate business, producing and selling about 3kbd of oil/condensate, 50 MT per day of LPG Propane and 25MMscf/d of lean gas. The second set of compressors were commissioned at the end of June 2022, six months after schedule, but they achieved a key milestone in the annals of hydrocarbon production from small fields in Niigeria’s Niger Delta: gas flaring at the Egbaoma Field has been completely eliminated, the company says.

What qualifies Platform for the Talented Tenth, is that willingness for portfolio diversification, beyond a mere producer and exporter of liquid hydrocarbons in the first place.

Like other ambitious marginal field operators, Platform has been scouting around for opportunities for development assets that lie within a 25km radius of its facilities and has initiated discussions with Newcross (OML 152) and Seplat (OML 38) for this purpose.

It also participated in the 2020/2022 Marginal Fields bid round, where it was awarded a 28% stake in its bottom ranked field for a signature bonus that was higher than its bid for the entire field. It turned down the offer and went into the secondary market to farm into the stakes of two sets of winners – one who won a 40% stake in the Benin Estuary Field and two others who won the Kuri field. Platform paid their signature bonuses and will fund their respective share of development costs for an agreed commercial construct.

Platform has even bigger plans. It tried to participate in a Financial &Technical Service Agreement in OML 30, citing NNPC’s decision to buy out Shoreline Natural Resources’ 45% stake on account of the shoddy pace of development of the asset. Platform was working with NNPC’s selected FTSA contractor. The plan was to use her reach “to fully set up the structure and engage all the required resources to deliver a reliable, competent independent operator”, company sources tell Africa Oil+Gas Report. Platform planned to contribute some take-off funds and earn a tiny equity stake on the operating entity, but the deal fell apart.

Platform is also currently involved in the bid to purchase TOTALEnergies’ 10% equity in the 19 OMLs in the SPDC/TOTAL/Agip/NNPC JV. Indeed, the company, in a consortium with Pillar, is in the semi final lap of the race.

The overall intention is to move Platform’s working Interest daily production North of 10,000 boe per day in the next three years

Platform has been in continuous, uninterrupted output (except for the standard outage by vandals and militants) all these years. It has produced, on operated gross basis, an average of 3,000BPD for 2021. The company is the first of the 31 indigenous E&P independents, awarded 24 marginal fields by the Nigerian government in 2004, to reach first oil. It commenced production in September 2007, after 34 months of taking over what was then named Umutu/Asuokpu field (later renamed Egbaoma field). Platform reached this point with the help of Newcross, another Nigerian E&P firm, which provided some financing and took 40% stake in a Joint Venture. The partners constructed and commissioned a 48km crude export pipeline, from their field, eastwards to ENI’s export facility in Kwale. The pipeline to Kwale now serves other companies who operate marginal fields in the vicinity, called the cluster, including Pillar Oil (which produces the Umuseti field), Energia (which produces the Ebendo field) and Midwestern Oil&Gas (which produces the Umusadege field).

Platform is neither as diversified as NDEP (No 1 on this list), nor has it the scope of a SEPLAT (No 2), but it can take a large credit for the creation of SEPLAT in 2009. It was Platform’s search to grow beyond being a mere one marginal field producer that led it to request Shell to divest OML 38 to it. At the time Shell decided to respond, there was also a request by Shebah Exploration, another local producer, on the table. The two companies formed SEPLAT from their names and Platform today, still holds as much as 7.5% of SEPLAT’s entire equity.

Platform remains an independent company outside the arrangement and still has ambition to grow.


Waltersmith Petroman has maintained a presence on the top five positions on the Talented Tenth without the benefit of ownership of something that most of its peers have in relative abundance: Reserves. The company operates the Ibigwe field in OML 16 onshore eastern Nigeria. Its main claim to the ranking is that it advances the industrial economy on the back of a small hydrocarbon resource.

Apart from the Ibigwe field, which can produce at most 4,000BOPD today, Waltersmith has a 3.6% equity in OML 34, which translated to 576BPD and 11MMscf/d (or 2,376BOEPD) in 2021.

Yet the company has relentlessly pursued the idea of a phased refinery complex; a gas processing plant and gas fired power plant as centrepieces of an industrial park to service factories, and provide support to industries and other enterprises in a space spanning over 65 Hectares. When it commissioned the project’s first phase: a 5,000BOPD modular refinery in November 2020, it was clear that it was on course of delivering the hub it promised. That commissioning event doubled as groundbreaking ceremony for the next two phases, (a 25,000BPD Condensate Refinery and a 20,000BOPD Oil Refinery) leading to a 50,000BOPD refinery complex producing, by the company’s own estimates about 2.7BIllion litres of products per annum by 2024.

Will it deliver?

Waltersmith finalised a three well drilling campaign between 2021/2022 that assured it had the capacity to produce 3,500BOPD from the Ibigwe field, but as it is, only 30% of the crude output from the field can meet refinery spec. This indicates poor scoping in the design of the refinery. As the outage on the (evacuation facility) Trans Niger Pipeline was still 100%, alternative evaluation options for export are under discussion for most of the produced crude in Ibigwe. Most wells are shut in.

It’s not entirely negative. Seplat supplies 2,000BOPD to the Ibigwe refinery from its Ohaji field. Waltersmith supplies 1,000BOPD. With these two streams, the 5,000BOPD refinery is up and running every day.

Long before the commissioning of the facility, it had been clear that the reserves at Ibigwe were too low for the scale of Waltersmith’s ambition (The challenge of low reserves has been further exacerbated by the poor quality the off spec). The company started reaching out to other stakeholders to win oil and gas assets in the vicinity. “We are engaging the Presidency, Ministry of Petroleum Resources and NNPC to resolve the feedstock issue, including condensate in OML 53 on a wholistic basis”, the company said in a published brief in 2020.    “All our current partners and more (read Nigeria Content Development Monitoring Board NCDMB and Africa Investment Corporation AFC) are lined up for participation in the next phase”, which is the 25,000BPD Condensate refinery.

But the proposed expansion was being challenged by NNPC’s insistence that the condensate from the SEPLAT operated ANOH development in OML 53 was rightfully its own to offtake and it was going ahead with another partner to build a similar plant on the ANOH field.

Waltersmith has now won NNPC over. And it has won two other assets along the way.

The commissioning dates for the refinery’’s second and third phases may have shifted, but the project is on course.

  1. Waltersmith has won the right to use the condensate produced in the NNPC/Seplat ANOH field development project as feedstock for (what is now) a 20,000BSD condensate refinery, now planned to commence production by 2026; the second phase of its three phase refinery project
  2. Waltersmith was also awarded the Assa marginal field, located less than 20kilometres from the Ibigwe field, through a Presidential discretionary allocation by President Muhammadu Buhari  in April 2021. The company has paid the signature bonus, paid the Farmout bonus, concluded the agreements and commenced the process of asset takeover of Assa field
  3. Waltersmith is also finalizing a financial and technical service agreement (FTSA) with Shell Nigeria for the Egbema West and Ogada fields in Oil Mining Lease (OML) 20,

This is access to three upstream hydrocarbon assets all located in the 30kilometre radius of the Ibigwe Field, which Waltersmith has operated since 2004.

“We believe that by positioning ourselves and being supportive of domestic refining, we would be in a more advantageous position when we discuss with government about some of these assets and that has also turned out positively”, says Chikezie Nwosu, Waltersmith’s Chief Executive Officer.  “We have both a technical and financial sales agreement that was approved by the Group Managing Director (GMD) NNPC to take over the operations of the OML 20 assets. That’s the Ebema-Egbema West and Ogada. We are still waiting for some peace to reign in that area before we progress”.

So, how did Waltersmith convince NNPC to ditch the other partner with whom it had planned to build a condensate refinery on the ANOH project? The conversation had dragged over three to four years. Nwosu would not provide a very detailed response other than that, on the basis of cost, quality, and economics, the Waltersmith refinery won over the competition. “I know but the difference between us and any other companies is that we are tenacious; so even when it looked as if it wasn’t happening, we completed our FEED, did EPC Contracting, everything that was needed and then kept it aside and said let’s watch”, he said. “We’re now in a position where we’re about to conclude certain agreements between ourselves and other parties so that we can get condensate from the plants to do the refinery. Once those are concluded, we will start building the refinery”.

Created in 1996, Waltersmith was awarded the Ibigwe field (then located in OML 16 but now OPL 2004) in 2003 through the marginal field licensing round. It has had three field development phases, involving six successful wells, since it took up the licence. It started production in 2008, ramping up from an initial 500BOPD to the current optimum output of 7,00BOPD over a period of ten years. It also has 8% equity of NDWestern, which itself has 45% of OML 34. In 2016, Waltersmith won the Turaco acreage in Uganda, after a keenly contested bid round, but dropped the asset because of “unfavourable terms”.

In 2019, the company was awarded an 80% stake and operatorship in Block EG-23 in Equatorial Guinea’s Niger Delta basin. Its partners include Hawtai Energy (HK) Limited and GEPetrol (the National Oil Company of Equatorial Guinea), with whom a draft PSC has been successfully negotiated and awaiting execution with the Ministry of Mines and Hydrocarbons who doubles as the Concessionaire and the government of Equatorial Guinea. Block EG-23 has a total area of 592 square kilometers and located offshore in water depths of 50-100 metres. Waltersmith is still waiting to get the PSC signed for this lease.

Waltersmith is not an open company with a large pool of shareholders and an independent board like SEPLAT and NDEP. But in 2019, the company’s Executive Chairman ceded the Chief Executive position to Chikezie Nwosu, a technically honed, experienced industry hand who has worked at top levels at Shell and Addax.  The company also revamped its management and brought in a broad range of technical and managerial skills from key E&P companies in the industry. If there’s anything, Waltersmith gets the messaging right. And we are willing to believe it. The Talented Tenth gets the sense that, the large, ever attendant Nigerian risk notwithstanding, this company will continue taking a several steps forward, to enable Nigeria’s industrialisation, in the short to medium term.


In OMLs 83& 85, which it operates, First E&P has averaged a net output 16,844BOPD (or gross production of 42, 109BOPD) year to date at the end of September 2022. That’s quite some volume for a Nigerian operator in the torrid business weather of 2021 to 2022. But the asset is in shallow water.

With the company’s 4.5% equity in OML 34 factored in, First E&P nets 19,896BOEPD, of which 14.53MMscf/d, (or 2,422BOEPD) is gas.

First E&P came to public consciousness in 2012, when it took a $67Million loan to acquire 10% stake in NDWestern, as the latter purchased 45% of OML 34 from Shell, TOTAL and ENI (Agip). That 10% of NDWestern is what becomes 4.5% of OML 34.

A full year later, First E&P convinced Chevron to sell its 40% stake in OMLs 83 and 85 for an amount slightly less than $70Million. First E&P was also Involved in Dangote subsidiary WAEP’s purchase of OMLs 71 and 72 from Shell/TOTAL/ENI for about $300Million.

The OML 34 investment provided a firm mooring for First E&P, as it strived to develop the Anyala (OML83) and Madu (OML85) fields. It took Anyala field to first oil, in October 2020, six years after it finalized the purchase of the assets from Chevron and it has been producing a gross average of around 40,000BOPD since January 2022. First E&P is the sixth Nigerian indigenous operator of an offshore acreage but only the third, after Conoil and Brittania U, who didn’t become an operator by default.  Anyala field is usually named as part of Anyala Madu fields (OMLs 83 & 85), as if they are twin fields, or straddle fields. But they are not. They are two different accumulations.

. As we went to press with this issue, First E&P had moved the rig Mentor, a jack o up owned and managed by Shelf Drilling to commence drilling of its first development well in the Madu field.

But OMLs 83& 85 lie in one of the most gas prone areas of the Niger Delta basin. So, what does First E&P want to do with its gas? What are its plans to contribute to the industrial state?

“First E&P has been sequestering the gas produced in association with oil in Anyala. It is using reservoirs in the Madu field as storage, as it invests in a large-scale gas processing facility and embarks on offtake negotiations”, company sources tell Africa Oil+Gas Report.

First E&P does not have a firmed-up offtake agreement, for the gas being produced in association with the crude oil it is producing, but company insiders talk of he lans for large gas processing plants..

One of the earlier gas monetization plans considered wasthat Madu and Anyala fields will supply a fifth of the 600MMscf/d targeted for the first phase of the East West Offshore Gas Gathering System promoted by Dangote Industries. The second of the plan is to pipe the gas to some yet-to be firmly defined gas commercialisation project hosted in OML 86. The Dangote gas gathering project is, for now, farfetched. It’s unlikely to be delivered. As for OML 86, Chevron has sold the asset, so it is not going to proceed with a gas infrastructure. Africa Oil+Gas Report believes that the associated gas accompanying the crude out of the subsurface is significant.


Conoil Producing, the country’s first real Nigerian independent operator of E&P assets, has been around for 30 years.

It has delivered on the original promise of ‘The Indigenous Thrust” of the Nigerian Military Government, which, in 1991, granted petroleum prospecting licences to “Nigerian Businesses who had performed well in other areas of endeavour”.

Conoil has maintained around 20,000BOPD output (net and gross) in the last t one year.

The challenges to maintain output at 20, 000BOPD and even double it, as is the plan, have far less to do with the subsurface than above ground issues and largely centre around leadership. Conoil has been haemorrhaging smart technical talent in the last five years, without durable replacement.

The company has seen off two managing directors since December 2015.

Conoil operates Oil Mining Leases (OMLs) 103, 59, 150 and 153. Five years ago, the company signalled aggressive drilling and comprehensive exploitation of these assets and targeted 40,000BOPD by 2019, at the latest.  But that enthusiasm has waned. Outside of the operated acreages, Conoil is not exploring the full benefits of the partnership it has with TOTAL, to allow the French major to operate the gas reserves in OML 136 and Oil in OML 257.

29 years since it made its first oil discovery and 31 years since it was first awarded an exploratory tract, Conoil has prevailed. But it doesn’t have a technical or managerial succession planning scenario, which is a disadvantage. It will likely be around in the next five years, most likely in its current form, but a higher production than 20,000BOPD should not be a struggle for a company that has been around for this long, with all the advantage of longevity and a wide pool of acreages to choose from. Conoil’s main risk to being an exceptional performer in the Nigerian environment is its own self.

No 8-10?

Editor’s note: This is work in progress.

This ranking was originally published five months ago; in the October 2022 edition of the Africa Oil+Gas Report monthly, delivered to paying subscribers.

“Oil Companies are Not Here to Prove Ownership”


By Jide Ajide, John Ashima & Oluwole Agunbiade

It was as if Chevron envisaged trouble.

In July 1993, it hired Chima Nwogu, who was working then with the Rivers State Ministry of Lands and Housing. He started his career with the company as a land representative with the Department of Law and Land.

Two years after Nwogu joined the American major, the land division was merged with the Public Affairs Department. “When I was hired with my colleagues, that was the first time professionals with estate valuation background were coming into the system…and Niger Delta was then relatively safe for everyone”, he recalls. “I could go from one community to another, enter the creeks on a boat and assess whatever is on the land as a land officer without any problem. So, we could work together without any problem. But soon after, there was this scramble by the various communities to be part of what was going on. If they were not part of it, they will press their claims to belong until they get some part of the goodies. So, you would see where communities held out as if they did not know their history, as if they had forgotten who owned the land among them.”

Nwogu cites some examples of where two or more ethnic groups claimed ownership of same land. “In Dibi, we were running the flow lines for the Dibi oilfield initially. When we acquired the first one, we dealt with a group of people, the Itsekiris. They had documents. There were six Itsekiri communities in different areas of Dibi. Then, when we were dredging, we saw a lot of Ijaws who came around, I met them…because they were the ones fishing there (and claimed fishing rights). But when we came to acquire the land and do the necessary survey, they were not there. And as the project went on, more communities started springing up and we found it so difficult to manage. It got to a point that we could not do any project without settling 10, 20, 50 communities. Everybody wants you to negotiate with them as a community.

“Anyway, what we are looking for is the social license to operate (in peace). Achieving this involves a lot of ingenuity and skills. The perfect setting is to be in place where government has tangible presence, be it local or state (government). However, in this case, there was no government presence anywhere. You could move across fifty communities, and you would find no police station anywhere. Even, at some point, some Itsekiri people started questioning the overlordship of the Olu of Warri on land matters. They would say his (Olu’s) lordship does not cover land. It is because land is life; it is tied to people’s existence and heritage. So, people were ready to fight for it to any length.

With heavy toll on lives, livelihoods and property.

At least eight lives were lost, when in March 1997, fight broke out between the Iteskiris and Ijaws over the relocation of the Warri South-West Local Government Area from Ogbe-Ijoh (Ijaw land) to Ogidigben (Itsekiri land), according to a report by the AFP (news agency).

Some other reports said that “hundreds were killed.” Expectedly, multimillion dollar assets of oil companies were targeted and destroyed.

As Nwogu says, “the oil companies are not there to prove ownership to anybody. They are there to do business. Only those who can produce documents to prove ownership gets compensated. One good thing about the area is that there is virtually no land, dating from the 1920s or 1930s, that has not been litigated upon up to the Supreme Court. However, people seem to forget those things. Or those who did not win their cases tend to allege that the other people got the verdict through fraud.”

Things really fell apart when militants came into the scene and the community elders lost their authority and became afraid of interacting with the IOCs as the youth suspected them of undercutting the communities. According to Smart Amola, an Itsekiri leader from Deghele community in Warri South-West Local Government, politics and the influence of the nouveau riche have affected the integrity of the traditional political system in the oil producing communities. Amola, who is an ex-militant, notes that the traditional Council of Elders, the youth groups and other institutions have been subverted and weakened by the oil phenomenon.

Before oil exploration, boundaries in the Niger Delta were relatively fluid in most communities. The land was there for everyone to use for agriculture or for building (homes) without ethnic acrimony.

Boundary adjustments became imperative because of oil, in the view of Collins Oturubo, former Youth Secretary and later Chairman of his Ijaw community at Okerenkoko.  Every community, he explains, did everything to assert itself. If one community went to court and got a favourable judgment, the defeated community would go to another in pursuit of a favourite verdict. “The issue was how to share the benefits from oil. It was just like two brothers fighting over their father’s properties. Each one wants to take everything for himself alone. Each community wanted to be recognized. Each community wanted to see how it could defeat the other. They started piling up arms to confront each other” he stresses.

SOLA OMOLE JOINED CHEVRON AS ADVISOR, PUBLIC COMMUNICATIONS on 18 October 1985, when the company was still Gulf Oil Company of Nigeria (GOCON) Limited. At some point, he became General Manager, Government and Public Affairs. Omole provides first-hand information on land issues and also relationships between the company and its host communities. “Chevron had a very cordial relationship with the host communities in the beginning. The relationship prior to the mid-to-late 1990s consisted largely of payment for land acquired from communities. Gifts to them at that time were small, intangible year-end gifts as well as occasional oneoff assistance. The communities enjoyed some temporary or contract jobs which provided sustenance for them and their families. At the end of each year, the company, led by the managing director and accompanied by all management staff and their spouses, usually flew to Escravos for a date with the Ugborodo community. The date featured a football match between the community and the company as well as food and drink in abundance. It was an impressive social outing to bring down the curtain on the operating year.”

In the beginning, Omole recalls, Chevron “maintained fairly close relationship with Ugborodo in the West, Kula, Idama and Izombe in the East and it bought land on which its oil production and gathering facilities were built from these communities so they were considered primary communities to Gulf Oil.” Soon, things were no longer at ease between company and communities. “As time went on, however, this situation was challenged severely by other adjoining communities which felt that they also deserved attention from the company. Mere office locations attracted so-called community ownership and therefore patronage from the company. When I became manager of the Public Affairs Department, we were receiving letters in droves from communities requesting recognition and therefore relationship/resources from us and I insisted that all letters must receive a response from us to signify our intention to be respectful and polite.” And: do things professionally and legitimately.

Tony Emegere, a retired manager in Chevron, overseeing land and community affairs, says the company always did its homework well. “Normally when you go into land acquisition, you should be able to properly identify the community or communities within the area. Once you have the survey map, it is sent to us (land and estate professionals) and based on the map, we now determine where the land situates. All we need to do is to identify the community or communities within the area.” He admits that “the most difficult land to acquire is the one that falls between two ethnic groups. It could also fall between two communities that are in dispute over land. The land would be difficult to acquire, especially if it falls on lands between Itsekiri and Ijaw.”

Excerpted from No Good Deed Go Unpunished; the Contentious Search for Peace by Niger Delta Stakeholders, authored by Jide Ajide, John Ashima & Oluwole Agunbiade. Published in 2022 by Jijowo Publishers, Nigeria.

Tullow to Spend $300Million CAPEX in Ghana, Push Jubilee to 100KBD  in 2023

Tullow Oil has forecast a capital expenditure (CAPEX) of c.$400Million in three African countries 2023.

The highest spend will be in Ghana, the company’s crown jewel, expected to gulp 75% (about $300Million) of the CAPEX.

Gabon comes a distant second at, c.$40Million, followed by Côte d’Ivoire (c.$20Million) and Kenya (c.$10Million).

Less than 10% of the CAPEX (c.$30Million) is allotted to exploration and appraisal activities, in these countries and, perhaps, outside them.

Some of the CAPEX in Ghana will be used to complete the production facility for the Jubilee South East in the first half of 2023. “It will mark the end of the current major infrastructure spend on Jubilee”.

The UK minnow anticipates gross production from Jubilee expected to increase to over 100,000BOPD with four new wells at Jubilee South East and a further Jubilee producer onstream later in 2023.

Tullow is impressed with the outcome of the change of operations & maintenance (O&M) contractor o the Kwame Nkrumah FPSO on the Jubilee field; it says that  costs are “expected to be c.23% lower than in 2021”.

Our Latest Issue/The 16th Deepwater Africa Annual

Uganda’s Lake Albert basin wide development is the largest E&P project currently under construction in Africa. But onshore developments like this (it is expected to peak at 230,000Barrels of oil per day (BOPD)) are becoming outliers. The rule is that the large discoveries take place in deepwater.

After just one dry hole, the media have muted their once animated discussions about anticipated outcome of ReconAfrica’s exploration in the vast onshore Kavango basin in Namibia. And there was never major headline news tracking Invictus Energy’s wildcat drilling in landlocked Cahora Bass Basin in Zimbabwe.

On the contrary, discoveries in Namibian deep offshore and developments in South African deepwater, have remained on the front-page news.

And it seems to get better the more the water depth. TOTALEnergies is vigorously reconsidering a return to its 13Million Tonnes Per Day Liquefied Natural Gas project in Mozambique which, though located on land, is extracting and processing massive volumes of natural gas lying beneath 2,000 metres of water in the Indian Ocean.

Senegal should become an oil producer by the last quarter of 2023, when Woodside Energy and its partners complete the first phase of valourising the Sangmar field in water depths from 700 metres to 1,400metres.  The target is 100,000BOPD. Around the corner, straddling Mauritania and Senegal, the 2.5Million Metric Tonne Per Day Floating LNG project on the Grand Tortue Ahmeyim (GTA) field is located in 2,850metre water depth, representing Africa’s deepest offshore project to date.

This is the 16th edition of Africa Oil+Gas Report’s Deepwater Annual, in which we explore, as much as possible, the up-to-date market intelligence about the activities in the deep blue. Welcome to 2023.

Grab your copy here.

This journal is the primer of the hydrocarbon industry on the continent. It is the market leader in local contextualizing of global developments and policy issues and is the go-to medium for decision makers, whether they be international corporations or local entrepreneurs, technical enterprises or financing institutions. Published by the Festac News Press Limited since November 2001, AOGR is a paid subscription based monthly, e-copy publication delivered around the world. Its website remains  and the contact email address is  . Contact telephone numbers in our West African regional headquarters in Lagos are +2348130733523, +2347062420127, +234803652979, +2348023902519.

– Editor

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