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In Search of the (Last) Silver Lining

By Gerard Kreeft

Rystad Energy has recently published two findings which cannot be reassuring to the oil and gas sector: firstly, it estimates that global total recoverable oil reserves have fallen approximately 10% in 2021- 1,725Billion barrels in 2021 compared to 1,903Billion in 2020. 

Secondly, Rystad estimates that the downturn, combined with the COVID-19 pandemic has cost the sector some $285Billionin upstream investments for 2020 and 2021. Pre-pandemic spending in 2019 was approximately $530Billion. In 2020 spending was reduced to  $382Billion and in 2021 is expected to be $390Billion.

Andrew Latham, Vice President Energy Research, Wood Mackenzie, has offered deepwater players a somewhat more cautious, but reassuring message. In a July study entitled ‘Deepwater’s Growing EUR Advantage’, Latham explainshow deepwater upstream growth is expected to rise from 10Million Barrels Oil Equivalent Per Day (MMMBOEPD) in 2021 (6% global supply) to over 17MMMBOEPD by2030(10%).

He states that almost half of oil and gas reserves being sanctioned for development over the next 5 years will come from the deepwater. Why? According to Woodmac, the outperformance is based on reservoir fundamentals. Deepwater reservoirs will produce substantially more oil and gas than shallow or onshore reservoirs. EUR(Estimated Ultimate Recovery) in deepwater averages 12MMBOEPD for oil wells and 43MMBOEPD for gas wells. Future deepwater oil fields will enjoy twice the average EUR of fields already onstream. Reflecting the industry’s recent successes in Guyana and Brazil’s Santos.  

Oil Wells

Brazil with 36Billion barrels of oil reserves has an average EUR of 14MMBOEPD per well. Brazil’s early deepwater developments took place in the post-salt plays of Campos Basin where heavier crudes and drilling technologies of the 1980s limited average EUR to 8MMBOEPD per well. Recent investments in pre-salt in the Santos Basin is 27MMBOEPDper well. 

Angola has 11Billion barrels of oil reserves, 1000 wells, and an average of 10MMBOEPD.

Nigeria has 7Billion barrels of oil reserves and an average EUR of 16MMBOEPD.

Guyana has 6Billion barrels of reserves and an average EUR of 24MMBOEPD.

Gas Wells

Gas basins are approximately half the size of oil basins. Woodmac anticipates the development of approximately 1000 deepwater gas wells, of which 700(64%) have already been developed. The average EUR is 43MMBOEPD. Mozambique’s Rovuma will have an average EUR of 93MMBOEPD.

Up to 2009, the average EUR was 31MMBOEPD. Now the average has jumped to 90MMBOEPD based on gas discoveries in the eastern Mediterranean, Mozambique, and Mauritania, and Senegal.

The Players & Assets


EUR averages could also dramatically rise because of possible merger talks between BP and ENI regarding their Angolan assets Will this model become the standard for other African countries?

An Algerian variant is perhaps already in the making. Reuters reported that a potential deal would allow ENI to acquire BP’s 45.89% stake in the Amenas natural gas plant and a 33% stake in the Salah gas plant. ENI expects to transform Algeria into a hub with the acquisition of BP’s assets.

Egypt could prove to be more challenging for both companies to find a lasting solution either to work together or a possible takeover of assets. BP currently produces, with its partners, close to 60% of Egypt’s gas production through the joint ventures the Pharaonic Petroleum Company (PhPC) and Petrobel (IEOC JV) in the East Nile Delta as well as through BP’s operated West Nile Delta fields. 

Nonetheless, ENI claims to be Egypt’s largest oil and producer, and its huge Zohr gas field is viewed as an example of the company’s extensive assets in the country. Most recently ENI together with EEHC (Egyptian Electricity Holding Company) and EGAS (Egyptian Natural Gas Holding Company) has signed an agreement to assess the technical and commercial feasibility of producing hydrogen.

Talk of potentially moving in the direction of hydrogen development could well trigger further cooperation between BP and ENI.


EUR averages have certainly caught the eye of TOTALEnergies who, with its deepwater track record in Angola Block 17, will certainly play a key role in developing new deepwater projects.

R The French major has two key assets in South Africa in which EUR will certainly play a key role:   Brulpadda Deepwater Project drilled to a final dep of more than 3,600 metres, and Luiperd, the second discovery in the Paddavissie Fairway in the southwest corner of the block.

In Africa, TOTALEnergies is the undisputed energy champion helping to leapfrog exploration and development hurdles ensuring that oil and gas projects are implemented, on time, and under budget.

Conclusions 1. EUR in Africa is not for the faint-of-heart, but a domain already long carved out by TOTALEnergies and ENI, Africa’s two dominant deepwater players. 2. A key theme in pursuing EUR goals for TOTALEnergies is not whether the oil and gas reserves are ‘probable’, reflecting any notion that the SPE Petroleum  Classification is still in place. No the key driver for TOTALEnergies is simply the economics of deciding whether EUR projects are up to investment grade and can compete with green projects.3. Any notion that the oil majors will use their EUR profits generated in Africa to create green projects in Africa is pure sentimentality. As Africa Oil+Gas Report has reported in the past, the oil majors have used profits generated in Africa to help finance their global green energy projects elsewhere around the globe.4. If EUR projects are to be developed, they must be fast-tracked, otherwise, there is little chance they will see first oil. Take the Lake Albert development project, recently signed in the spring of 2021, which encompasses the Tilenga and Kingfisher upstream oil projects in Uganda and the construction of the East African Crude Oil Pipeline (EACOP) in Uganda and Tanzania. To reach a signing ceremony for the project has taken some 15 years. In the present low-carbon environment, the dithering of long-drawn-out development plans, will for whatever reason, not be tolerated.  5. No doubt the BP-ENI joint venture in Angola will ensure that this model will be duplicated or expanded throughout the continent. Certainly, it will shore up deepwater exploration and development plans. 6. Participation of new entrants- independents seeking new opportunities or savy investors-will likely also be part of the mix.7. Perhaps EUR could become the driving force to enable the deepwater market to become an even more lucrative niche market. Perhaps not entirely in vogue given the low-carbon surroundings.8. Yet the final warning comes from Institute for Energy Economics and Financial Analysis (IEEFA)’s July report: In financial year (FY) 2020, the clean energy sector received record investment commitments totaling $501Billion – 9% more than the previous year. The renewable energy segment led with $303Billion in 2020, which is 60% of total investment committed into the overall low carbon energy transition sector.9. EUR-driven projects will have to compete with renewables investments.

Gerard Kreeft, BA (Calvin University, Grand Rapids, USA) and MA (Carleton University, Ottawa, Canada), Energy Transition Adviser, was the founder and owner of EnergyWise.  He has managed and implemented energy conferences, seminars, and university master classes in Alaska, Angola, Brazil, Canada, India, Libya, Kazakhstan, Russia, and throughout Europe.  Kreeft has Dutch and Canadian citizenship and resides in the Netherlands.  He writes on a regular basis for Africa Oil + Gas Report and contributes to the Institute of Energy Economics and Financial Analysis(IEEFA).

BOAZ rebrands to deliver apex of service and technology-enabled solutions for the energy industry


Boaz Integrated Energy (BOAZ) (

has rebranded and unveiled its new logo to re-position to offer cutting-edge services in the oil and gas industry.

“The Company has completed its rebranding program in response to the new opportunities for technology-enabled solutions in the energy sector”, said Adeola Adebari, the Chief Executive Officer for BOAZ.

“Our visual identity is an essential part of the BOAZ Brand. Each element in the new logo was carefully crafted to symbolize the company’s dynamism and forward-thinking positioning within the Oil and Gas Servicing Industry, and the energy space at large. Indeed, this is a major milestone for us as a company”.

BOAZ provides revolutionary solutions to production and reservoir management challenges for the oil and gas industry, in partnership with such technology companies as Roke, Blue Spark, Jorin, and Data Science Nigeria.

The new brand captures the company’s readiness to support the industry’s renewed focus on maximizing ultimate hydrocarbon recovery, using cost-effective solutions, leveraging digital technologies, transitioning to renewable energies as well as maximizing returns on investments through safe, quality and sustainable solutions.

Here is the new visual identity of the Company:





The rationale behind the new logo, according to the CEO, is in alignment with the strategic intent: “Our new logo consists of two main components: BOAZ typeface and Apex Wheel Icon. The Apex Wheel Icon is a stylized ‘A’ that points forward within a wheel or ‘O’. These two elements symbolize our drive to offer the apex of service and technology within the energy industry, in alignment with our  corporate strategic intent. It is important to note that the Apex points forward, indicating that we are disruptive, ready and willing to change the status quo and the way business is done within oil and gas servicing in Sub-Saharan Africa. This of course is complemented by the wheel or ‘O’ which is also all about moving forward”.

The oil and gas industry has undergone major changes in recent times, which have fundamentally changed the way things are done. As the industry heals from the debilitating dual impact of price wars and COVID-19 pandemic, business leaders have learnt to do things differently as evidenced by the increased adoption of green solutions and digital technology innovations. These changes require new thinking. BOAZ new brand speaks to this new thinking in that the Company is poised to deploy its revolutionary technologies in the industry.

Some of the flagship solutions of the Company include Quad Reservoir Saturation Logging Technology, Wireline Applied Stimulation (WASP) Techology, and Visual Process Analyser (ViPA) Technology. Their benefits are highlighted below:

Quad: For reservoir saturation measurement, fluid contacts, lithology, porosity, clay volume and relative bulk density.

WASP: For wellbore cleaning, removal of scales, fines and debris from screens, perforations, downhole subsurface safety valves, gas lift valves etc.

ViPA: For produced water management, production chemical optimization and surface production equipment optimization.

Plugged in always into forward thinking

At the heart of the rebranding programme is a renewal of the Company’s corporate vision and mission statements to emphasize its expanded focus on the energy industry.  The Company also renewed its Corporate Culture with a new corporate look for its website. (

BOAZ Culture (

Abimbola Onaolapo, one of the Company’s Directors, gave some insight into the new corporate culture: “Our strong corporate culture is based on our shared values, represented by our name BOAZ. We are BOAZ, we stand for:

 B:      Boldly rising to challenges through innovation, excellence and teamwork

O:      Obligation to exceed clients’ expectations, always.

A:      Acting with Integrity and Respect

Z:      Zero harm to people, assets and the environment

 This is what we represent.”

The new BOAZ brand signifies the Company’s commitment to remain innovative, nimble and agile in order to help its clients achieve ambitious goals and stay ahead of the curve in the next normal.

BOAZ…. creating value, unearthing possibilities.



PIB: Why the Frontier Exploration Fund Feels Like Slush Money

By Toyin Akinosho

The current version of the Petroleum Industry Bill is one of the most progressive pieces of legislation I have seen anywhere.

In the new law, the Nigerian state is willing to accept as low as 60% for both Hydrocarbon Tax and Companies Income Tax (CIT) combined (which collectively replace the Petroleum Profit Tax), for mining leases located onshore and shallow water. With these generous giveaways, the Bill’s drafters are hoping that companies can invest more on work programmes that reward the country with higher volumes of hydrocarbon output at lower cost of production, rather than surrendering to temptation to pad up OPEX and CAPEX in order to reduce their tax remittances.

A Midstream infrastructure Fund is set up to incentivize private investment in pipelines, gas processing plants and other such facility that help deliver processed hydrocarbon products to end users in the Nigerian market.

The Minister has a better handle of the petroleum industry than what he was allowed in the draft that emerged, after the long collective wait, last September, but as is the plan, he doesn’t have an undue control.

There is vigorous contestation of the percentage of Oil Companies’ Operating Expenses (OPEX), mandated by the new law for payment into the Host Community Trust Fund on any acreage under licence, but the deal in the PIB is a much more improved and structured community development intervention than the NDDC or the Derivation. The Host Community initiative in this law is more of a legal instrument than the Global Memorandum of Understanding, a participatory development planning process initiated by oil companies and which is, today, widely considered the most impactful process for delivering development. We have had a discussion of the value of the mandated size of OPEX, elsewhere on this site.

There are areas of the bill that I am not entirely comfortable with but I can let them all pass, except the Frontier Exploration Fund.

The provisions in the section for Frontier Exploration Fund leap at you like bad data does in a smooth creaming curve

The more we at Africa Oil+Gas Report examine the clause on the Frontier Exploration Fund in the current draft of the PIB, the less we are convinced that it is altruistically about exploration.

In the draft of the bill that was sent to the National Assembly in late 2020, the oversight for Frontier Exploration, which has been in the orbit of NNPC for 33 years, was handed over to the regulator. In the wordings of that particular version: “Where data acquired and interpreted under a Petroleum Exploration Licence is, in the judgment of the Commission, requires testing and drilling of identifiable prospects and leads, and no commercial entity has publicly expressed an intention of testing or drilling such prospects, the Commission may engage the services of a competent person to drill or test such prospect and leads on a service fee basis”. That simply means that the regulator could put up a bid and any E&P company could contest for testing such a prospect for a fee. But how would the regulator find money to pay the fee? The answer is ‘The Frontier Exploration Fund’, the draft law said, which “shall be 10% of rents on petroleum prospecting licences and petroleum mining leases”.

This was already clearly provocative: to set aside 10% of rents on petroleum prospecting licences and petroleum mining leases for frontier exploration was already heavily contested.

So, it was more than rubbing salt into injury when, after all the public hearings, with heavy criticism about allotting high percentage of rents to a potentially unaccountable queue of drilling prospects, the draft that emerged, now calls for even more money being effectively taken out of the treasury, to fund frontier exploration. Over and above the 10% of rents on petroleum prospecting licences and petroleum mining leases, says the current draft of the bill, the Fund shall also swallow “30% of NNPC Limited’s profit oil and profit gas as in the production sharing, profit sharing and Risk service contracts”. NNPC Limited shall transfer the 30% of profit oil and profit gas to the frontier exploration fund escrow account dedicated for the development of frontier acreages only.

Governors, both Southern and Northern, missed the point that this 30% of PSC profit is a further robbery of the Federation account in favour of NNPC for a service that is already well catered for. Instead, they turned the discussion into a political, North/South affair, with the South accusing the North and the North defending what is actually a loss of revenue to them! It says a lot about how little those who queue up every month for Federal allocation understand how the money they are sharing is derived.

But perhaps the political class knows what most of us outside of their sphere don’t: this current draft is effectively having NNPC wresting control of the Frontier exploration initiatives from the regulator. Whereas in the earlier draft, the regulator could “engage the services of a competent person to drill or test such prospect and leads on a service fee basis”, thereby opening the space for understanding of the geological challenges, the latest draft restricts the studies to NNPC: “the Commission shall … request the services of NNPC Limited to drill or test such prospect and leads on a service fee basis to be charged to the Frontier Exploration Fund pursuant to this Act”.

That particular statement plays to the ideological mindset of the present administration at the centre; that ”the government will do things better than the private sector”(fund the country’s entire electricity bill, subsidise gasoline consumption and be the chronically inefficient nanny). Still, the self-evident truth is that when it comes to basic E&P operations, the NNPC has proven to be incapable of delivering. As have been convincingly argued elsewhere on this site, the least productive assets in the portfolio of NPDC, the NNPC’s E&P subsidiary, are those in which it is the sole stakeholder. This heightens my suspicion of this idea in the PIB, of cancelling the competition in favour of NNPC to probe prospective acreages.

I am not one of those who compare Frontier areas to sinkholes. No. I spent 20 years as an earth scientist with Chevron and went to several conferences at which many professional colleagues made presentations on the prospectivity of sedimentary basins in Ghana, Mozambique, Uganda and the like.  And yet it wasn’t until the last of my 20 years (2007)   that Kosmos reported the first sizeable commercial discovery of oil in Ghana. And the first of the reservoirs containing  100Trillion cubic feet (estimated recoverable reserves) offshore Mozambique), wasn’t discovered until three years later.

But it is to the marketing savvy of the hydrocarbon officials from these countries that we owe those discoveries, not the state’s readiness to throw money down the hole. They showed up gabfest after gabfest, making the case for investors to come.

It is neither fashionable, professional nor sensible for governments around the world to risk hard earned profits on exploration efforts, let alone frontier Basins!! The practice (and wisdom) is to create a system to make that happen by private funds. Nigeria did something like that in 1993 which led to Shell’s gas discovery in Kolmani-1 well in Bauchi area.

With the section on Frontier Exploration in the PIB the way it is, it is hard to assume that it is not a route for slush funds that can escape legislative scrutiny and financial regulatory oversight.


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

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