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TOTALEnergies Is the Largest Hydrocarbon Producer in Nigeria

TOTALEnergies averaged a net output of 273,220Barrels of Oil Equivalent Per Day (273,220BOEPD) in Nigeria in 2020.

The figure was over 50,000BOEPD higher than the output reported by Shell, which came a distant second, at 223,000BOEPD. 

Chevron and…..Click here to read full article

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

By Fred Akanni, in Warri

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

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

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

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

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

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

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

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

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

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

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

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

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

For Nigerian Indies, “Diversification of Portfolio is Key to Staying Alive”

Eberechukwu Oji, CEO of NDWestern, argues that diversification of portfolios is the key for E&P operating companies to weather the storms of boom-and-bust cycles of crude oil prices and, in the peculiar case of Nigeria, perennial outage of crude evacuation pipelines.

“I have been in the industry for almost three decades”, Oji told Africa Oil+Gas Report in a chat in the course of the magazine’s “Interview the CEO” series. “During this time, I have experienced the peaks and troughs of oil price crash and outage of backbone facilities. Some of the lessons learned from these experiences are that

(1) Diversification of portfolio is key to staying alive. Indigenous companies must take local refining and mid-stream business very seriously to be better able to handle these major shocks

(2) Reduction of reliance on 3rd party services such as pipelines and infrastructure.

(3) Self-developed evacuation of produced crude, the so-called alternative evacuation options is also becoming a necessity to reduce deferments from uncontrolled incessant outages”.

The company actually looks towards being fully integrated.

NDWestern’s joint venture with state owned NPDC (NPDC/NDWestern JV) is the largest indigenous producer and supplier of natural gas into the domestic market.

Its gross output of 310Million standard cubic feet per day (310MMscf/d) on average in 2020 betters the nearest local competitor by around 25%. The Joint Venture supplies the 1,000MW Transcorp Power Plant at Ughelli, the 1,320MW (capacity) Egbin Power Plant in Lagos, Olorunsogo Plant in Ogun State in Nigeria’s southwest, as well as other offtakers through transport lines operated by the Nigerian Gas Transportation Company. The company envisages production of over 400MMscf/d “if the off-takers will perform”.

In its TALENTED TENTH annual, published late in December 2020, Africa Oil+Gas Report reported that NDWestern had completed Front End Engineering Design (FEED) on a 10,000BPD refinery on the Oil Mining Lease (OML) 34 and hopes to convince NPDC to jointly take a Final Investment Decision by second quarter 2021NDWestern’s 2020 revenue, up to October 2020, was running north of $200Million, with 33% operating profit. Gas offtake has been higher than forecast and the company has been pleasantly surprised that crude oil prices were doing better, as of end of 3Q 2020, than had been predicted earlier in the year, when the contagion forced down prices to sub $10 levels.




How OPEC+ Cuts Have Sliced Deep into Nigerian Crude Output

By Bunmi Christiana Aduloju


The COVID-19 pandemic roiled global markets for most of 2020, and kept down demand for crude oil in the earlier part of the year, nudging the price per barrel of the commodity to as low as $-37.63 on April 20th, 2020, (West Texas Intermediate, an international oil benchmark), for the first time in history.  


As the demand collapse held up, the Organisation of Petroleum Exporting Countries (OPEC) and its allies, OPEC+, an intergovernmental cartel, reached an agreement on the 9th of April, 2020, to reduce their crude oil production output in order to rebalance the international oil market. This was the beginning of a journey to periodic cuts of crude oil by member states of OPEC and its allies. 

On the 12th of April, 2020, they finalised the agreement and decided to reduce oil output to 9.7Million barrels per day(9.7MMBOPD) from May 1, 2020 to June 30, 2020. From July 1, 2020 to December 31, 2020, 7.7MMBOPD and a 5.8MMBOPD cut in output from January 1, 2021 to April 30, 2022. The reference point for the calculation of the cut down was the oil production for October 2018.

OPEC is on familiar grounds whenever it takes a decision to modify crude oil production output. According to a Reuters report, the cartel has changed production output 34 times – often exempting some of its member countries from these cuts – from 1998 to 2018. 

But this particular cut which started in May 2020 was referred to as the “single largest output cut in history.” With this cut, the oil production in OPEC member countries sank to the lowest in almost 20 years, in the first month of the curtailment. 

Prior to this agreement, there had been a price war between Russia and Saudi Arabia which instigated a major oil price crashing the global market. Nigeria, Africa’s giant, being a member country of OPEC, joined in the production cuts.


In fulfilment of the OPEC+ decision, Nigeria agreed to cut its production to 1.412MMBOPD for May to June 2020, 1.495MMBOPD for July to December 2020 and 1.579MMBOPD for January 2021 to April 2022, based on the reference production of October 2018 of 1.829MMBOPD. These production cuts exclude condensate production which is exempt from OPEC’s output cuts.

These periodical cuts have proven to be an effective mechanism for cushioning the oil glut that pervaded the international oil market in the early months of 2020.

Oil prices skyrocketed with the OPEC cuts. Brent crude oil futures, an international oil benchmark, jumped from as low as $26 on April 20th, 2020 to as high as $71.49 on June 7, 2021 and WTI price, from as low as $-37.63 on the 20th of April, 2020 to as high as $69.23 on June 7, 2021. 

Oil prices may have increased with the OPEC+ cuts, which is an advantage for oil revenue generation in terms of FX, but “the rising oil prices could also be a curse for Nigeria as it has to pay more because of an operating cost of about $40,” notes Bamidele Samuel, a senior research analyst with one of the big four accounting firms in Lagos.

Compliance or Non-compliance 

Nigeria started on a discordant note, in the first month of the curtailment, by complying only partially with its agreed portion of the cut. The country overproduced crude oil in May 2020, with about 1.61MMBOPD, accounting for about 52% compliance. 

However, Nigeria promised to make up for the non-compliance by the end of June 2020 or no later than mid-July 2020. 

As OPEC+ alliance extended the 9.7Million barrels oil production cut – which was supposed to end in June 2020 – into July 2020 to further rebalance the oil market, again, Nigeria overproduced oil at 1. 49MMBOPD, against its promised 1.41MMBOPD production for July, according to OPEC monthly oil market report.

In the following months until the end of the year, OPEC recorded that Nigeria was mostly compliant with its designated quota of crude oil production.

The country recorded the lowest production output for 2020 at 1.42MMBOPD in December, which was the lowest production level since August 2016, according to OPEC’s report. This was largely due to disruption in production at ten terminals including Yoho, Agbami, Pennington, Qua Iboe and Erha terminals.


On one hand, Nigeria promised to make up for the OPEC cuts loopholes with condensates, which is not part of the OPEC+ curtailment. Timipre Sylva Minister of State, Petroleum, reiterated that through the respective periods of the OPEC+ cuts, Nigeria would add “condensate production of between 360-460 KBOPD.” 

In November 2020, Nigeria urged OPEC to reconsider the oil production cuts designated to Nigeria due to the confusion over the categorisation of Agbami field as condensate or as crude oil. 

However, OPEC declined Nigeria’s request with a comment that the production cuts was in the best interest of the international oil market.

With these cuts and other production challenges, Nigeria’s overall oil and condensate production slumped drastically in 2020 to around 1.66MMBOPD in 2020 from 2.04MMBOPD in 2019, according to an S&P Platts analysis, a UK-based market intelligence firm. This was its lowest annual output figure since 2016 when militancy in the Niger Delta pushed output to as low as 1.60MMBOPD.

According to data obtained from the NNPC Annual Statistics Bulletin, total crude oil and condensate production for the year 2019 was 735,244,080 barrels of oil and the daily average production was 2.01MMBOPD. In 2020, however, Nigeria produced 643,938,257 barrels of oil and condensate, the lowest ever produced since 1990, when the production figure was 630,245,500 barrels of oil and condensates. 

In January 2020, Nigeria produced 64,260,394 barrels of oil and condensate, representing an average daily production of 2.07Million barrels, the highest in the year and in December 2020, it produced 44,018,411 barrels of crude oil and condensate, with an average daily production of 1.42Million barrels, accounting for the lowest. 

Mr. Bamidele Samuel regards the operating cost to the upstream sector – which is around $40 – as a major shortfall for oil exploration and production in Nigeria. 


In December 2020, the OPEC+ alliance agreed to increase production by 500,000BOPD, from January 2021. This brought the total production cut for OPEC+ in January to 7.2MMBOPD. This production cut decreased gradually to 7.13MMBOPD in February and 7.05MMBOPD in March 2021 through April 2021. Saudi Arabia, OPEC kingpin, stepped in with a voluntary cut of 1MMBOPD from February 2021 till April 2021.

On April 1, 2020, OPEC+ alliance decided to ease cuts to 5.8mb/d spanning from May 2021 till July 2021.

Some analysts believe that the OPEC+ cuts would continue to go down the slope until April 2022 as the world recovers from coronavirus and the oil glut that accompanied it. 

According to OPEC monthly crude oil production data obtained from its secondary sources, in 2021, Nigeria’s crude oil production figures stood at 1.34MMBOPD in January, 1.49MMBOPD in February, 1.48MMBOPD in March 2021 and 1.56MMBOPD in April 2021. 

“The fact that Nigeria cannot do as much as an average capacity of 1.9MMBOPD is a challenge, especially with oil prices trading above $70 per barrels,” Bamidele Samuel argues.

“If we are producing more, that is more revenue for the government to stimulate the economy on the part of recovery,” he added. 

Russia and Saudi Arabia keep disagreeing on the change in production output. While Russia has been pushing for increase in OPEC+ production output, Saudi Arabia has been more conservative, contending that another wave of coronavirus in India and other parts of Asia, is capable of assaulting demand for crude oil.

This story was produced under the NAREP Media Oil and Gas 2021 Fellowship of the Premium Times Centre for Investigative Journalism.

Tullow Oil Shifts Focus from Exploration to Production

Tullow Oil will now focus on producing all the oil it has discovered, as well as invest spare cash in hub size, near-term crude oil discoveries, rather than foraging for new oil anywhere.

The Irish company no longer wants to be seen as a leading wildcatter in Africa’s frontier, a description that it wore like a badge up until a few years ago.

“We have shifted our focus away from exploration and development and long-cycle capital commitments to a production focused company with a robust, cash generative business plan”, Rahul Dhir, the Chief Executive Officer, says in a pre-Annual General Meeting statement. 

The company’s cash cow remains the assets in Ghana. From January 2021, Tullow is implementing a 10-year business plan “which focuses over 90% of our capital investment in our high margin production assets in West Africa”, Dhir says. 

For ‘West Africa’, read ‘Ghana’, as Tullow has sold its stakes in Equatorial Guinea and most of Gabon.

The London listed junior started a multi-year drilling campaign in Ghana, planning to drill four wells in total in 2021, consisting of two production and one water injection well on its flagship Jubilee field and one gas injector well on the relatively less prolific TEN field. 

“We have successfully drilled the first Jubilee production well and the Jubilee water injector well, and the reservoirs encountered are in line with expectations. The rig will now carry out the completion of these two wells with tie-in and start-up of both wells expected in the third quarter of 2021”.

The business plan, Mr. Dhir says, “will generate material cashflow to self-fund high return, fast payback investment opportunities and reduce debt – even at low oil prices”. 

Dhir’s plan proposes: 

• Reducing our cost base: we are delivering cost savings across the business including annual G&A cash savings of $125Million. We are becoming a performance focused organisation where every barrel matters and every dollar counts.

• Improving operational performance: our ongoing operational turnaround is delivering more reliable and consistent operating performance with 98% average uptime year-to-date at Jubilee and TEN and better utilisation of our existing infrastructure.

• Rigorous capital allocation: we are focusing on high return and fast payback investments in our production assets and have significantly reduced capital allocation to long-cycle projects.

• Reducing our debt: We have sold our interests in Uganda, Equatorial Guinea and the Dussafu Marin permit in Gabon, raising over $700 million in proceeds. This asset sale programme puts us well on the way to realizing c.$1Billion over two years through assets sales and cost reductions.

• Simplifying our capital structure: we recently completed a comprehensive debt refinancing which gives us the financial stability to deliver our business plan.

• Strong ESG focus: we announced in March that we aim to become Net Zero (Scope 1 & 2) by 2030 as part of our commitment to sustainability. In addition, we maintain our commitment to social investment and developing local content.

Group production to the end of May 2021 averaged c.62,000 Barrels of Oil Per Day(BOPD), which, Dhir says, is in line with expectations. 

“This figure reflects the completion of the sale of our Equatorial Guinea interests on March 31, 2021, with no production from these assets recorded past the first quarter. On June 9, 2021, we announced the sale completion of the Dussafu Marin permit in Gabon and we will adjust our full year guidance to reflect both these divestments in our upcoming Trading Statement on 14 July 2021.

“In Ghana, our operational improvement plan is delivering results with 98% average uptime year-to-date across both the Jubilee and TEN FPSOs. As we have previously stated, reliable gas offtake and water injection are an important part of our strategy to optimise reservoir performance and address production decline”. 

PACEGATE Commissions Drilling Fluids Manufacturing Plant

By Foluso Ogunsan

PACEGATE Energy & Resources Limited (PEARL) has launched a drilling fluids manufacturing plant in Nigeria and by extension West Africa.

The company will formulate specialised drilling fluids at this ultramodern plant located in Ilupeju, an industrial estate located in the north of Lagos, Nigeria’s commercial city.

PEARL says that the oil field chemicals to be produced fall into three categories including:

  • Corrosion Inhibitors, Biocides, Oxygen and H2S Scavengers, Scale/Salt Inhibitors and Desolvers for Asset Protection and Integrity.
  • Demulsifiers, Defoamers, Flocculant and Water Clarifier or Deoiler for Phase Treatment and Separation.
  • Depressants/Removers, Gas Hydrate Inhibitors and Well Stimulation fluids for Flow Assurance and Well Stimulation Chemicals.

Other products include Glycols, Solvents Amines, Alcohol, Industrial Chemicals, Cleaner and degreasers for the refining and transportation industry.

“We are specialised in things that will enhance stability of drilling activity”, the company says. The chemical plant has a production capacity of 12,900 Metric Tonnes per annum.

The idea to venture into manufacturing of drilling chemicals for the upstream hydrocarbon industry, has so impressed the Nigerian Content Development Monitoring Board (NCDMB), that the agency awarded PEARL the “Nigerian Equipment Certificate”, guaranteeing PEARL the first right of refusal to the chemicals produced and coming out of the facility by hydrocarbon producing companies and their service-related affiliates.

PEARL was established in 2020 as an indigenous local content company seeking to provide indigenous oilfield solution via chemistry to the oil and gas drilling, refining and transportation sectors of the economy.  It exclusively represents Canadian Energy Services, its technical partners, in Africa through the ADIPRO.

Manoj Kirpalani, a second generation Indian-Nigerian who is PEARL’s Chairman, traces the history of its existence from 1979 when it was formed by his father as an importer of finished goods to an in-country manufacturer of specialised production chemicals that it is today.

Niyi Adebayo, Nigeria’s Minister of Investments and Trade who formally commissioned the plant, described it as “first local content chemicals manufacturing plant in Nigeria”.

The Ilupeju facility includes a steel drum manufacturing plant, a chemicals manufacturing plant and a laboratory and has a branch in Port-Harcourt, in eastern Nigeria. PEARL also has plans to open up another arm at the Lekki free Trade Zone, a growing industrial suburb in the east of Lagos in the coming years, targeting exports.

“As long as crude oil is still being extracted here, production chemicals are our primary focus. Our secondary focus is gas treatment chemicals as gas grows here”, says Umesh Amarani, PEARL’s Managing Director.

Ghana’s Operators Are Mostly Not Performing the Terms of Petroleum Agreements

…Contractors hold on to acreages for five-six years without visible work programme

Despite the relative success of Ghana’s E&P industry, with three sizeable oilfield developments in full production 10 years after the country’s first commercial discovery, and two gas processing plants delivering over 200MMscf/d, most of the petroleum contracts signed with government are chronically underperforming.

Only seven of the 18 petroleum agreements signed between Ghana and several oil companies, in the last 18 years have performed up to par, a new report has shown.

Almost all of the contracts were negotiated and ratified under PNDC Law 84, with the exception of Springfield West Cape Three Points (Block 2), ENI Ghana Exploration and Production Limited (BLOCK 4) and SWAOCO Onshore/Offshore Keta Delta Block, which were ratified in 2016. Most of the least performing contracts were signed between 2013 and 2016, according to the Ghana Petroleum Industry Report 2019, published by C-BOD and released in Accra in early March 2021.

Lacklustre operators include Erin Energy, Sahara Energy, Medea Development, Britannia U, UB Resources, Eco Atlantic, and GNPC Operating Services Company Limited (GOSCO), none of which is likely to conduct seismic acquisition, or drill any well, as indicated in their contract obligation, even by 2021.

Erin Energy is the 60% operator of Expanded Shallow Water Tano Block, with an agreement dating back to January 2015; Sahara Energy operates the Shallow Water Cape Three Points Block with 85% interest, with an agreement dated July 2014; Eco Atlantic is operator of Deepwater Cape Three Points with 50.42% interest and A-Z Petroleum (27.88%) and Petrogulf (4.35%) as partners. Its contract date is March 2015; Brittania-U, (the 76% operator of South West Saltpond Block), has an agreement dated July 2014; UB Resources operates the Offshore Cape Three Points South Block, with Royalgate GH Limited, Houston Drilling Management as its contracting parties. The effective date is July 2014.

Amni International has also not performed optimally with the Central Tano Block (effective date March 2014), in which it holds 90% interest, but if it does get to drill a well on the acreage in 3Q 2021, as it promises, it will escape being lumped in the class of lacklustre operators.

One stellar performer in the last three years has been Aker Energy, who acquired the interests of Hess in the Deep Water Tano Cape Three Points block, proceeded to complete appraisal studies and drilled three more wells, bringing to seven (7) successful exploration wells and eight (8) appraisal wells on the block. Aker submitted a Plan of Development (PoD) for the field to the government in March 2019. The pandemic has, however muted the roar.

The Springfield (Block 2) contract has also performed; the operator, an indigenous Ghanaian independent drilled an expensive deepwater well in 2019, three years after it signed a contract. So has the ENI Ghana (Block 4), which completed its drilling towards the end of the initial exploratory phase and made a discovery of gas and condensate. “The contractor will undertake further drilling in 2021 before appraisal programme is submitted to the Commission”, the report says.

The article was initially published in the March 2021 edition of the Africa Oil+Gas Report

Funding of E&P Business in Nigeria; Strategies for Sustainability

By Tunde Afolabi

Twenty years ago, 90% or more of all the oil and gas licenses in Nigeria were held by the International Oil Companies (IOCs), most of them global oil majors in their own right. The rest were either unassigned or held by a sprinkle of Nigerian independents.

By 2020, about 75% of the oil and gas licenses in Nigeria were held by the IOCs while the rest were held by the Indies or unassigned. The independents came into being, largely in the 1990s, courtesy of some tenacious Nigerians with the undying support of the then minister of petroleum resources, Jubril Aminu, a Professor of medical sciences, when the concessionary block award was approved by the government of General Ibrahim Babangida.

Production capacity of the independents hovered around 2% of the nation’s total output, until the majors’ divestment exercises of between 2013 and 2016, in which several onshore assets with reserves ranging from 200Million barrels to 1.2Billion barrels were sold and purchased and a new class of independent producers emerged with some, with some having production capacity in excess of 70,000 barrels of oil per day. The determining factor of the health and well-being of the oil and gas industry is the price of crude oil.

Between 2002 and 2005, oil prices hovered between a low of $18 per barrel to a high of $40 per barrel. From 2005 to 2008, the price rose from $40 per barrel to $132 per barrel. This was followed by the 2008 crash when oil prices plunged by more than $90 per barrel to a low of $40 per barrel. The good days returned in 2009, ushering in a time of global economic recovery that lasted till 2014. During this period, oil enjoyed a robust average price of $100 per barrel. By May 2014, we experienced another crash when oil prices plunged to $50 per barrel and did not stop the free-fall until it reached $27 per barrel. Oil price started recovering in September 2015 and by 2018, had reached another milestone of $80 per barrel. Prices hovered between $80 per barrel and $60 per barrel until February, 2020 when oil took a nosedive to below $15 per barrel.

The capital spend of the oil industry is highly influenced by the robustness of oil prices. Between 2009 and 2015, when oil prices were averaging about $100 per barrel, the Nigerian oil industry was spending an average of $18Billion per annum. However, between 2016 and 2019 when the prices of oil fell to an average of $60 per barrel, capital spend during the same period fell to an average $7.5Billion per annum.

The number of exploration and appraisal wells was optimal in Nigeria between 2010 and 2019, closely mirroring the level of capital expenditure. In 2010, 2011, 2012 and especially 2013, the number of exploration and appraisal wells drilled globally were significantly higher than the previous years and the following years.

The proven crude oil reserves growth between 2010 and 2016 mirrors the price of oil during that period. The crash of 2015 significantly affected the reserves growth from 2017 and beyond.

The only aberration which I can find in the statistics of Nigerian Oil Industry activities is the decline of production from 2010 to 2016. One would have expected that as exploration and appraisal activities grew and crude oil reserves grew, so would the production activities, but that is not the case.

Fast forward to 2021: One thing is for certain, capital spend in 2020, 2021 will be significantly reduced, a situation which will impact spending on core  exploration activities.


By the fourth quarter of 2019, oil prices were getting restless and $60 barrel oil was looking unsustainable. 2020 started with some optimism that things might turn around, with $65 per barrel average price in January and February. In fact, at a point in January, we had a $70 per barrel oil.

Then came the surprise assault of COVID-19 and the whole world was caught flat-footed. By the end of that first quarter of 2020, oil prices had crashed to $18 per barrel. The world was awash with oil, as over $100Million barrels of homeless crude roamed the seas. Tankers on the world’s main water ways were being used for emergency storages because the storage terminals were filled to capacity.

The most readily impacted by this free fall in oil prices in the Nigerian oil and gas industry were:

1 The Federal Government of Nigeria through NNPC whose revenues fell by more than 70%.

2 The independent oil producers whose income comes from near-marginal field operations and who live from month-to-month and from hand-to-mouth and at the mercies of their bankers. Some were lucky to have hedged early but none was spared the agony of budget balancing. Oil men became finance strategists overnight, sourcing for funds.

Funding problems for E&P oil and gas companies have been around for a number of years, even before the pandemic induced destruction of demand for crude.

It is important to note here that facilities granted by banks to the marketers of petroleum products, such as diesel and gasoline marketers, are included in the count of what is given to the oil and gas sector and amount to 50% of the total financing granted to the oil and gas industry.

The major oil companies which operate in Nigeria are generally self-funding for their E&P activities. They spend shareholder equity funds on technical operations, while they borrow, from local banks, mostly naira for sundry services like staff salaries and emoluments and contractor naira portion of their invoices among other things. However, you will find out that the independents depend mostly on local bank financing and very little on shareholders equities. Therefore, the ones who feel the most impact of crude oil price collapse in their businesses are the independents. Between 2014 and 2019, when the industry suffered a major price collapse, even at $60 per barrel oil, credits from banks to the oil and gas industry dropped from the high of $12.5Billion in 2014 to a low of $9.5Billion in 2019, a whopping 24% fall in available credit.

One factor that has exacerbated the credit crunch for the independents from the local banks is the Central Bank of Nigeria (CBN)’s sectorial limitation; that is, how much of a bank’s portfolio can be allocated to a particular industry, which has been falling from a high of 28% in 2014 to a low of 22% in 2019. Meanwhile, the petroleum products market (downstream activity) and the IOC naira demand drastically reduced what eventually was available for field operations for Nigerian indigenous E&P companies. This has led to high financing cost.


Today, there are at least 13 Nigerian owned independent oil and gas companies with reserves of almost 4Billion barrels of oil and producing close to 500,000 barrels of oil per day. If these reserves are to be developed at an average cost of $5-$10 per barrel, the companies will require between $20- $40Billion. The top ten Nigerian banks all together give a total of about $5.5Billion in loans to the Nigerian oil and gas industry, including the marketers of petroleum products.

Meanwhile, more players are upcoming, as the marginal field bid round is finalized. These players will be added to the list of Nigerian independent producers who require funds to appraise, develop and produce their newly acquired assets.

There are numerous proposals on the way forward.

It is imperative for the Nigerian government to encourage licensing a purely oil and gas bank with significant subscription to the shares of the bank by the government. An oil and gas focused bank will understand the market fundamentals and the rudiments of running an oil and gas exploration and production company.

The trend in prices will be very dependent on new production development especially in the deep-water. If the past is the key to the future, let us consider events in the oil price recovery from the 2001 price dip, before the climb to $50 a barrel in 2005, which is a period of 4 years. Recovery to high prices might take longer or never as the industry competes with the challenges of low carbon emissions demand for climate change mitigation.

In conclusion, Nigeria independent oil and gas producers currently account for 25% of production of the total national output. We have not disappointed the government in domesticating the skillset of oil and gas exploration development and production. It will be a shame if we do not do all in our power to assure the survival of the independents.

There are several other mitigating options that may be considered. Most of them will require that extant laws are changed but for ones that do not require much of interference from legal constitutional challenges, I believe this proposal that has

been seriously considered about the creation of an oil and gas bank should be put into serious consideration.

It is imperative for government to encourage the licencing of an Oil &Gas Bank. An oil and gas focused bank will understand the market fundamentals and the rudiments of running an E&P business.

Abridged version of the Keynote address delivered by Tunde Afolabi, Chairman, Amni International Petroleum Development Company, at the 45th anniversary lecture of the Nigerian Association of Petroleum Explorationists, NAPE. Mr. Afolabi a tiled Nigerian traditional chief, is a former president and Fellow of NAPE, with a distinguished oil and gas industry career spanning 47 years. The speech was transcribed to text by Bunmi Aduloju, reporter and researcher with Africa Oil+Gas Report.



Nigerian Indies: The Talented Tenth Annual

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


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


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 an 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, 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 2018, their total, operated crude oil output averaged slightly less than four hundred thousand barrels of oil per day (400,000BOPD). 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.

Excited by its success at achieving first oil, First E&P Presents a model of its FPSO to DPR

THE TALENTED TENTH ANNUAL, of which this article is the fourth edition, is our rough but 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 issues light up 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.

This list, which we will continue to update and publish yearly, is unlikely to ever include companies who become operators by default.

Disclaimer: This is not a stamp of approval for any investment decision. It is an analytical piece by a set of journalists focused on ways and means of operations of upstream E&P companies in Africa.


No. 1 -NDEP

For the first time in the short history of The Talented Tenth, SEPLAT Petroleum is not occupying the top position.

The lead, this year, is taken by Niger Delta Exploration and Production (NDEP), which had competed fiercely against SEPLAT for the three consecutive years that the latter had been crowned winner.

NDEP remains the most integrated energy player among Nigeria’s independents; crude oil output, gas processing plant and a refinery designed to produce, among other products, gasoline.

The Ogbele refinery comprises three modular trains that can process 11,000BOPD at optimum to output Diesel, Marine Diesel, DPK, Naphtha and High Pour Fuel Oil. NDEP envisages that when all the trains are running optimally, by the end of the second quarter 2021 at the latest, the Train 3 will fully convert all Naphtha to Premium Motor Spirit (Gasoline) at an average daily output of some 600,000 Litres.

NDEP has been producing crude oil from Ogbele field for 15 years, exploiting a marginal field whose recoverable reserves was estimated at 5Million Barrels at the time it was acquired.  In two of the four ranking years of The Talented Tenth, NDEP has bolstered output of its primary product. Between 2018 and 2019, it grew production from 6,500BOPD to 9,000BOPD. Between then and 2020, it pushed upwards to 12,000BOPD, but OPEC+ curtailment compelled the output to be capped at 9,000BOPD for the October-December 2020 Quarter.

Since 2011, the company 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. A Nigerian offtaker purchases another 1MMscf/d for onward sale to industrial outlets. 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. “After extensive internal and external economic, financial and technical re-evaluations, the aim was to position Ogbele as an emerging gas processing hub, in the Eastern Niger Delta region”.

The refinery project initially came on stream in 2012 as a 1,000BOPD capacity topping plant, producing 85,860 litres of diesel every day from 540BOPD of crude. In late 2019, a second 5,000BOPD train was added.  With another 5,000BOPD train completed in October 2020, the three train 11,000BOPD refinery is fully functional.

Apart from the Ogbele marginal field, the company operates two other upstream assets: the Omerelu marginal field onshore, still undeveloped and the Oil Prospecting Lease (OPL) 227, an exploration acreage, offshore. NDEP drilled an appraisal well in OPL 227 in 2019 by drilling, with disappointing results. It deployed a rig on the Omerelu structure and encountered gas in the sidetrack hole, as prognosed.  In the meantime, NDEP achieves its full crude output capacity when the Trans Niger Pipeline, the evacuation facility, is not shut in due to vandalism, which is the most significant challenge.

NDEP has 42% (majority) stake in NDWestern, the entity that holds 45% in OML 34, which averaged gross production of 20,000BOPD of crude and 300MMscf/d of gas in October 2020.

NDEP is keen on winning the credentials of a Pan African hydrocarbon upstream player. 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 is in an ongoing conversation with the Mozambican government, for a licencing award for onshore natural gas development.

NDEP is a nimble enterprise that was founded in the late 1990s with the idea of having more than a handful of shareholders pooling resources, a contrarian thinking to the concept that created most Nigerian independents, so it holds a regular, annual, well attended General Meetings, although it has remained shy of listing on the local stock exchange, let alone any international bourse.

One chink in NDEP’s governance armour had been the leadership succession. For most of 2019, the company was certain of the handover of the Chief Executive position from Layiwola Fatona, who has run the company from the beginning, in 1996, to Toba Akinmoladun, an ex-Shell General Manager. It didn’t work out. In February 2021, two full months outside the scope of this report, the company took on board Gbite Falade, as Mr. Fatona’s successor. Any commentary on the success or otherwise of this succession will have to wait for the 2021 edition of The Talented Tenth Annual.

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.


SEPLAT has grown larger in asset holding since the last ranking. With the acquisition of AIM listed Eland Oil and Gas in December 2019, the company now holds participating interests in OML 40 and Ubima marginal field.

Its portfolio now 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 Petroleum remains the most transparently governed E&P independent operating in the country.

In 2020, it welcomed a new Chief Executive Officer, taking over from a man who co-founded the company 11 years ago. The British accountant Roger Brown’s taking of the reins of SEPLAT from the Nigerian geologist and entrepreneur, Austin Avuru, is a textbook story and stuff of legend. Brown is an employee of the company; he wasn’t coming from “corporate headquarters abroad” to take charge. In a fragile petrostate where opacity is the norm, 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.

2019 could be said to be the year of SEPLAT.

In March of that year, it took the Final Investment Decision (FID) to proceed with the Assa North-Ohaji South (ANOH) gas and condensate project at OML 53. In December it completed the acquisition of Eland Oil & Gas. The ANOH project entails the valourisation of 300MMscf/d of gas from those straddle fields (Assa North and Ohaji South) through a short pipeline into the Obiafu-Obrikom-Oben (OB3) pipeline, the grid length, east –west gas transmission line, which terminates at SEPLAT’s Oben facility, a hub “ideally located to aggregate and supply gas to Nigeria’s main demand centres on the Lagos and Abuja axes”. That FID, for a project of $700Million worth, affirmed the company’s leadership in the country’s domestic gas market.

But that was a year before the period covered in this report. Whilst work is going on in ANOH, there has been a drop in gas output in SEPLAT’s western Niger Delta assets. Gross supply from OMLs 4, 38 and 41, has dropped from 291MMscf/d in 2019, to less than 220MMscf/d for most of 2020.

Liquids production in the first nine months of 2020, leaped to 33,327BOPD, surpassing the company’s 2015 output (29,000BOPD), which is the record in the company’s 11-year history.  But this was on the back of the additional crude output contributed by Eland and incremental output from OML 53.

There was, fortunately, a decrease in losses arising from crude evacuation in the Transf Forcados Pipeline, but the alternative route is far from ready; the Amukpe-Escravos Pipeline is now expected operational in H2 2021.

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 50,000BOEPD in six acreages including Oil Prospecting Lease (OPL 283) and OMLs 52, 53 in 2018. These figures are net to SEPLAT.

In 2019, SEPLAT was not as aggressive at the drill bit as it could have been, but in 2020, its vow to “return to a level of drilling and development activity not seen since 2015”, was thwarted by the Pandemic.

Even the best run entities in Nigeria are affronted, when “Nigeria Happens”. As we went to press with this edition, the news broke that the building in which SEPLAT Corporate Headquarters is located, in Lagos, was sealed in connection with a court case by Access Bank, the country’s top lender, against Cardinal Drilling Services Limited, a third-party providing drilling services to SEPLAT. Cardinal Drilling has outstanding loan obligations to Access Bank. SEPLAT insists it is neither a shareholder in Cardinal Drilling, nor has outstanding loan obligations or guarantees to Access Bank and did not at any time make any commitments or guarantees in respect of Cardinal Drilling’s loan obligations to Access Bank. It argues that there is no merit or justification “for this action against it and has taken prompt legal action to vacate the court order pursuant to which the building was sealed”. But three weeks after that statement was issued, a high court order insisted that SEPLAT’s Corporate offices could still remain under lock and key if that was what Access Bank wished and that the case was only going to be heard in late January 2021. This is not good optics.

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 benefits from the technical strength of NDEP, the top performer in this year’s ranking. Founded in 2011, it 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.

In 2020, the NPDC/NDWestern JV swept past the SEPLAT/NDPC JV as the largest indigenous producer and supplier of natural gas into the domestic market. Its gross output of 310Million standard cubic feet per day (310MMscf/d) on average in that timeframe betters the nearest local competitor by around 25%. The Joint Venture supplies the 1,000MW Transcorp Power Plant at Ughelli, the 1,320MW (capacity) Egbin Power Plant in Lagos, Olorunsogo Plant in Ogun State in Nigeria’s southwest, as well as other offtakers through transport lines operated by the Nigerian Gas Transportation Company. The company envisages production of over 400MMscf/d “if the off-takers will perform”.

With a string of newly completed wells, the JV has also boosted liquid hydrocarbon production by 25%, consistently averaging in excess of 20,000BOPD in the last half year of 2020.

NDWestern has completed Front End Engineering Design (FEED) on a 10,000BPD refinery on OML 34 and hopes to convince NPDC to jointly take a Final Investment Decision by second quarter 2021. NDWestern’s 2020 revenue, up to October 2020, was running north of $200Million, with 33% operating profit. Gas offtake has been higher than forecast and the company has been pleasantly surprised that crude oil prices were doing better, as of end of 3Q 2020, than had been predicted earlier in the year, when the contagion forced down prices to sub $10 levels.

Like every E&P player, NDWestern is facing severe headwinds. The order from the Nigerian National Petroleum Corporation (NNPC), parent company of the NPDC, to slash Capital Expenses (CAPEX) by 30%, means that a number of growth projects will roll off to the back burner. Compounding this is the demand by the NPDC, to take over the role of Chief Operating Officer (COO) of the Asset Management Teams (AMTs) in some of the Nigerian independents it has Joint Venture with,including, of course, NPDC. The chronically inefficient NPDCIt is also asking to include a larger proportion of technical managers in the teams. The companies are pushing back.

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


Waltersmith Petroman’s main claim to the top four of The Talented Tenth for all our four annual rankings, is its advance the industrial economy on the back of a small hydrocarbon resource.

It neither has the breadth of an NDEP (No 1), nor the volume of a SEPLAT (No2). But it keeps on charging forward. Its yearning to contribute to the country’s industrial growth is a crucial marker point. Waltersmith is a marginal field producer who produces barely 7,000BOPD at the most but has, since 2017. 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 last November, it was clear to everyone that it was on course of delivering the hub it promised. That commissioning event doubled as groundbreaking ceremony for the next two phases, (a 25000BPD 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?

Actually, it had started to.

Three things have progressed since the late November launch: the Nigerian Content Development and Mentoring Board (NCDMB), which helped finance the 5,000BOPD, refinery, says it is ready to support the next phase. In late December, SEPLAT announced it had inked a crude purchasing agreement with Waltersmith to supply the refinery as much as 4,000BOPD of crude. The United Nations Industrial Development Organisation (UNIDO) and United Nations Economic Commission for Africa (UNECA) have signed a Technical support agreement with the company for the development of the Industrial Park. This entails preparation of project concept, feasibility studies, business plan, fund raising, promotion and attracting companies and overall implementation. Much work still has to be done.

As there isn’t a significant upside in the Ibigwe field resources itself, Waltersmith is eyeing oil and gas assets in the vicinity. “We are still 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 says in its brief.  “Thereafter we will take FID”, it explains.  “All our current partners and more (read NCDMB and Africa Investment Corporation AFC) are lined up for participation in the next phase”, which is the 25,000BPD Condensate refinery. This ambition to run an industrial park with a significant bolstering of  in-country beneficiation of Nigeria’s hydrocarbon resources is what makes Waltersmith one of our favourites. But it also has the potential to pull the company down. The second phase of the refinery project is challenged by NNPC’s insistence that the condensate from the SEPLAT operated OML 53’s ANOH development is rightfully its own to offtake and it is going ahead to build its own condensate refinery on ANOH field. It would seem like a joke, that NNPC says it actually wants to build a new refinery, but even if it eventually doesn’t, the publicity the state hydrocarbon company is making about it is enough to diminish the bankability of Waltersmith’s project. In any case, for as long as NNPC makes the claim it wants to build a condensate refinery on ANOH field, it is taking out the very feedstock that Waltersmith has banked its refinery project on. And what if Waltersmith doesn’t succeed in winning any asset in the marginal field bid round?

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 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.


Platform Petroleum, also a marginal field producer, makes the Talented Tenth for the first time in its four editions. 13 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 supplying 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 to take financial and operational stake in the plant. 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.

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 3,000BOPD for 2020. 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.

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


Eroton makes the Talented Tenth largely through the quality of its asset.

It is the 45% holder and operator of OML 18, onshore eastern Niger Delta, a property with, as of 2017, 2P reserves of 576Million barrels of crude and 3.2Trillion cubic feet of gas. Its average operated (gross) output is between 35,000BOPD and 45,000BOPD (before OPEC restrictions, which has now compelled it to produce 27,500BOPD).

It has industrial ambitions for its huge gas resources, though it produced less than 40MMscf/d, in spite of all those huge reserves, it is the sole supplier of natural gas to Notore, the fertiliser producer, its sister company, whose offtake is constrained by its ongoing Turn Around Maintenance.

Eroton has a proposal to develop up to 224Billion standard cubic feet of gas, for peak offtake of 260MMscf/d, according to the latest annual report by the Department of Petroleum Resources, Nigeria’s hydrocarbon regulatory agency. It says it expects to pool this volume from four fields: Alakiri (81MMsc/d), Cawthorne Channel (133MMscf/d), Akaso (41MMscf/d) and Opolo (5MMscf/d) in OML 18. It is the highest planned production of associated gas, in pre-development phase, by any company in the country. No further information about this project is located anywhere else.

As Eroton searches for offtakers for its putative gas projects, it is concerned about the 25-35% losses it incurs in crude evacuation, as a result of vandalism of the export pipeline: Nembe Creek Trunk Line (NCTL). Eroton is the promoter of the Alternative Crude Oil Evacuation System (ACOES) project, currently under construction by Energy Link Infrastructure (Malta) Ltd. (ELI), a third party in which Eroton is invested. ACOES is being built to provide a dedicated oil export route from OML 18, comprising a new pipeline and a floating storage and offloading vessel (FSO), ELI Akaso. The ACOES pipeline component is expected to have a throughput capability of 100,000BOPD, while the FSO has a storage capacity of 2Million bbls of oil. Once commissioned, ELI’s charges are expected to be comparable to current NCTL handling fees.

Eroton has the added advantage of a combined experience of its constituent founders. An outgrowth of Martwestern Energy, formed by Midwestern, operator of the 15,000BOPD Umusadege field and Mart Resources, the Canadian junior which has now been bought out by the former through the London listed San Leon, it also has Sahara Energy as a part owner. It proposes, next year, to continue the development drilling campaign it ended last April, with another three wells in the second half of 2021.


Neconde has shifted away from Pipeline evacuation

After a series of false starts, Neconde has become a valid member of Nigerian indigenous gas producers’ club. Two years after announcing, with fanfare, the revamp and commissioning of the Odidi Gas processing plant, in OML 42, which it jointly operates with NPDC, Neconde finally started reporting meaningful volumes of utilised gas, in third quarter 2020. In October 2020, utilised gas averaged 18MMscf/d, but that was a low and was largely due to crude output challenges brought about by community workers’ strike. At optimum, it has been delivering around 35MMscf/d in the last three months.

Field data received by Africa Oil+Gas Report between November 2018-when the gas plant was deemed commissioned -and July 2020, had indicated that most of the gas produced in OML 42 was simply flared. Utilised gas for the period averaged less than 2MMscf/d. It was thus noteworthy to start seeing utilised gas ticking upwards. What’s important to The Talented Tenth here is a Nigerian independent adding natural gas to the value stream.

Prior to this small achievement, Neconde Energy had largely been in the ranking due to its daring, alternative crude evacuation method. Since the third quarter of-2018, the NPDC/Neconde JV had opted out of exporting its crude through the Shell-led, Trans Forcados Pipeline System TFPS. It is the only one of the nine Nigerian independents impacted by the 16 month long shut in of the TFPS from 2016 to 2017, to have decided to permanently stay out of the uncertainty engendered by pumping crude through this influential facility. For that it has recorded a significant drop in redundancy and been rewarded with consistency of output at above 40,000BOPD for 80% of the period between July 2018 and October 2020. The company has more significant control than its peers, in delivering specific volumes from the well-head to the terminal. But how it has achieved this is also important. The NPDC/Neconde Joint Venture barges its crude through rivers to the Forcados terminal. To get export ready crude into the boats, it had to install a treatment facility. For the barging, the company has to pay cabotage fees, inland waterways number permit and DPR permit. Marine work is difficult because of the logistics and, as illegal bunkers can attack the barged crude on the way, the security cost is high. The Nigerian Navy escorts the barged crude with gunboats in front and back.

Neconde was formed by Nestoil, a leading local oilfield construction company and Yinka Folawiyo, holder of the OML 113 (containing the Aje field). From the outset, it has been the one of the most aggressive of the four Nigerian Independents who acquired Shell/TOTAL/ENI’s equity in four acreages in 2012. It was the most vocal in disputing the operatorship of the state firm NPDC, which has served largely in holding back production in these assets at a time of rising oil prices, a situation that has now, in retrospect, proved to be value destroying, as the loans raised for those acquisitions could no longer be rapidly paid back in the low-price era.

A corporate governance structure to enable sustainability of operations and regulatory compliance could help Neconde a great deal.


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

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

But its current average production of 20,000BOPD is, to put it mildly, punching below its weight.

And this is not about OPEC+ curtailment.

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. In 2015, 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.

27 years since it made its first oil discovery and 29 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 is not guaranteed, even in the best of local and international environments. The Company’s main risk to being an exceptional performer in the Nigerian environment is its own self.


First E&P commenced oil production from the Anyala West field in shallow offshore Oil Mining Leases (OMLs) 83 & 85 in October 2020. It is the fourth Nigerian indigenous operator of an offshore acreage but only the second, after Conoil, who didn’t become an operator by default.

It has taken two undeveloped discoveries to first oil, six years after it bought the assets from Chevron. Although First E&P had developed (and is still developing) these properties as part of a joint venture with NNPC, which is credited with supporting with prompt cash call payments, it has done so clearly in an adverse period of relatively lower crude oil prices.

The company started producing into the FPSO Abigail-Joseph from four producer wells and has added more wells (in 2021, which is outside the scope of this report).

First E&P had always come across, to the editorial board of the Africa Oil+Gas Report, as a candidate for inclusion in The Talented Tenth, but always looked over because it wasn’t an operating producer of hydrocarbon asset. It also wasn’t clear to the board what First E&P wanted to do with its gas assets.  The company 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. 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.

Pan African Ambition-

In 2019, First E&P, pulled ahead in Ghana’s first licencing round, winning Block GH_WB_02, or Block 2, one of the three blocks available for competitive bidding. The remaining two of the five blocks on offer were expressly for direct negotiations.  Ghana’s Ministry of Energy received 15 applications for Block 2, the highest number for any block. First E&P and its local content partner Elandel Energy (Ghana) Limited were invited for negotiations on the detailed terms of the Petroleum Agreement.

Gas Challenge

First E&P does not have a firmed-up offtake agreement, for the gas being produced in association with the crude oil from the Madu and Anyala fields.

One of the two gas monetization plans we know the company has considered is that 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 Chevron operated OML 86. The Dangote gas gathering project is, for now, farfetched. It’s unlikely to be delivered in the next five years. As for OML 86, Chevron is looking to sell 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.


Aiteo Exploration & Production makes the Number 10 on The Talented Tenth, for largely the same reason it showed up on the list in the last three years: the sheer size of its main hydrocarbon property, the OML 29 (Estimated 2P reserves: 2.2Billion BOE as of 2015), of which it holds 45%, purchased from Shell, TOTAL and ENI in 2015. We have no idea of the reserves estimate currently, but the company has averaged roughly 70,000BOPD from 2016 to 2019. The rapid increase in output, from the 35,000BOPD level when the purchase was completed, to 90,000BOPD reached by early 2017, has halted. Production averaged 70,000BOPD in 2018, and hovered between 65,000 and 85,000BOPD in 2019, with the key challenge being the vandalism of the 97 kilometre Nembe Creek Trunk Line, the crude evacuation facility which Aiteo operates. OPEC+ curtailment is a feature of the year 2020 and it has constrained production at lower than 50,000BOPD for most of the last five months.

Aiteo’s assets were part of Shell’s Eastern Gas Cluster, but the company, despite the huge resources, is not one of Nigeria’s top seven indigenous producers of natural gas.

Waltersmith’s 5,000BOPD First Phase Refinery

If there is any E&P firm that badly needs to increase hydrocarbon output after the pandemic, if only to assure its lenders, it is Aiteo. It has a $2Billion+ debt to restructure and can’t readily access fresh source of funding.

International lenders eye it warily, because of the aura around the company, which comes from its being founded and largely owned by a crude oil and petroleum products dealer who had close ties to the much-vilified former minister of Petroleum, Diezani Alison-Madueke.

Aiteo’s directors; in executive management or otherwise, are not published on its website. The founder’s name and career history are the only items on the site. This is a sort of hint at Maximum rulership.

The company’s charming, personable Managing Director, who is an experienced ex Shell manager, has been quoted in the media as saying that the NCTL pipeline “is a source of comfort to the company’s lenders”. That claim runs contrary to what Africa Oil+Gas Report has heard from some of the lenders, who would prefer not to be named. Their concern is that part of the lender-borrower consent was that Aiteo would ensure considerable uptime of the pipeline so that production would be assured, but the company has not delivered on that.

Just about every E&P company in the world is having a surreal time at the moment. And in Nigeria, the risks are higher than in many petroleum jurisdictions, but the question we ask is can Aiteo continue to deliver, in the way it is currently structured, in the next five years?

This report is a slightly edited version of what was originally published in the December 2020 edition of the monthly Africa Oil+Gas Report, which means that the magazine’s paying subscribers read it six months ago.

ENI and BP to Explore Combining Angolan Interests into New Joint Venture

BP and ENI have entered into a non-binding memorandum of understanding (MoU) to progress detailed discussions on combining their upstream portfolios in Angola, including all their oil, gas and LNG interests in the country.

The companies believe that combining their efforts in a new joint venture company would bring significant opportunities for them to jointly boost future developments and operations in Angola. In particular, it would be expected to generate significant synergies, create more efficient operations, and increase investment and growth in the basin. The new venture would reflect both companies’ commitment to continue developing the upstream sector potential of Angola.

The new company would be supported by Eni and bp, benefitting from the competencies and personnel of each, and would be expected to be self-funded. A business plan for the company would be agreed by bp and Eni to allow it to capture future opportunities in exploration, development and possibly portfolio growth, both in Angola and regionally.

HSE performance, project delivery and production efficiency will be priority areas for the management. The companies’ social investment commitments in the country will continue to be honoured.



BP and ENI have informed the Angolan Government of their intention. Any final transaction will be subject to relevant Governmental, regulatory, and partner approvals.

The companies have appointed advisors that will support the companies in raising finance for the new joint venture. 

ENI is operator of block 15/06, and exploration blocks Cabinda North, Cabinda Centro, 1/14 and soon 28 and is also operator of the New Gas Consortium (NGC). In addition, Eni has a stake in the non-operated blocks 0 (Cabinda), 3/05, 3 / 05A, 14, 14 K / A-IMI, 15 and in Angola LNG.

BP is operator of Blocks 18 and 31 offshore Angola, and has non-operated stakes in blocks 15, 17, 20, and soon 29. bp also has non-operated interests in the NGC and Angola LNG.

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