In April 2026, the World Bank repeated a familiar prescription, one of many that have never guided any developing nation toward genuine success. The pattern is predictable: a prescription, followed by confusion, and ultimately chaos. This time, it urged Nigeria to reopen petrol imports to moderate inflation. The argument was wrapped in technocratic language, but the message was unmistakable. Nigeria is being asked to return to the very trap that weakened its economy for decades. This recommendation is not reform; it is regression. It is unacceptable and should not even be entertained by the country.
Nigeria must be especially cautious about the World Bank’s longstanding neoliberal globalization doctrines, which dominated the 1980s through the early 2000s. These principles have now been significantly disrupted by a rising wave of economic nationalism, epitomised by President Trump’s aggressive tariff regimes. It is telling that the World Bank would never offer this kind of advice to China, Brazil, Indonesia, or the United States.
Nigeria heeded the World Bank’s calls for FX liberalization and the removal of fuel subsidies, yet the consequences have been severe: rising poverty, social strain, and economic hardship, largely because the country lacks strong domestic production capacity. Nigerians supported those reforms because they seemed rational and necessary. Against this backdrop, it is baffling that the World Bank now recommends reopening Nigeria’s petroleum products market to foreign dumping. The contradiction is as striking as it is unacceptable.
Nigeria’s history with fuel importation is a history of dysfunction. It produced chronic scarcity, inflated costs, a corrupt subsidy regime, and persistent foreign exchange crises. Every litre of gasoline imported drained the nation’s reserves. Every spike in global crude prices delivered immediate economic pain. Import dependence was never a temporary inconvenience; it was a structural failure. I have analyzed, reviewed, and criticized these systemic flaws extensively in several of my previous writings. Through my experience in the oil and gas sector, I witnessed this rot from the front row, and I repeatedly advocated and pushed for reforms even when such efforts seemed futile.
Today, however, Nigeria stands at the brink of a different future. The Dangote Petroleum Refinery has already begun reshaping the country’s energy landscape. Since fuel imports were curtailed, the refinery has become the primary source of petrol in Nigeria, significantly increasing domestic supply and expanding exports across Africa. This capacity is measurable and undeniable. The refinery confirmed producing 50Million litres of PMS in January 2026. The product is also of higher quality than what was previously imported.
Allowing widespread fuel imports to return at this moment would not increase competition. It would destabilise a sector that is only now beginning to find its footing. The Dangote Refinery has stabilised domestic petroleum prices at levels significantly below those prevailing in neighbouring, import-dependent African countries. The assertion that reopening imports will automatically lead to lower prices is factually untenable and unsupported by recent evidence.
Import dependence drains scarce foreign exchange, weakens the naira, and exposes the entire economy to global volatility. Nigeria has already been warned that rising global crude prices, intensified by geopolitical tensions, could add roughly 3.1 percentage points to national inflation. The Dangote Refinery has helped stabilise the naira, with the exchange rate strengthening from over NGN 1,600 per US dollar to below NGN 1,400. Reopening fuel imports would exert renewed pressure on the currency, triggering depreciation and leading to cost‑push inflation.
The World Bank’s recommendation focuses narrowly on theoretical competition while ignoring the consequences of undermining a strategic national industrial asset just as its benefits are beginning to materialise. The Dangote Refinery is not merely a fuel supplier; it is the anchor of a broader industrial resurgence. Aliko Dangote built Africa’s largest cement company. He built the continent’s largest fertilizer plant. He has established manufacturing footprints far beyond Nigeria, including significant operations in Ethiopia, where Dangote Cement stands as one of the largest producers and employers. These enterprises transformed entire value chains, reduced imports, strengthened domestic supply, and created industries that now serve multiple regional markets.
Nigeria’s own experience in cement is deeply instructive. Dangote Cement eliminated Nigeria’s dependence on imported cement by building robust local capacity. Beyond Nigeria, the company replicated this achievement in countries such as Ethiopia, Zambia, and Senegal. The same transformation is underway in the fertilizer sector, where Nigeria is emerging as a continental hub through the Dangote Fertilizer Plant. If Nigeria reopens fuel imports now, it will effectively sabotage its opportunity to replicate this success in the petroleum sector.
It is particularly ironic that the author of the World Bank report is from Ethiopia, a country where the Dangote Group is currently conducting surveys to identify a suitable site for a petroleum products tank farm and pipeline infrastructure to support Ethiopian energy security. The World Bank, by contrast, has not undertaken any comparable project to strengthen Africa’s energy capacity in more than four decades. It is therefore unsurprising that the institution’s influence continues to diminish across developing nations. If the World Bank had been asked to recommend investment in the Dangote Refinery during its inception, it is highly likely it would have declined. One must hope that this recommendation is not part of a coordinated effort, aided by local collaborators, to push Nigeria backward, as occurred with the collapse of the textile, automobile, and agricultural industries.
The refinery is already exporting to Ghana, Togo, Cameroon, Tanzania, and other markets, and several African governments, including South Africa, are pursuing long‑term supply contracts. This is not dominance; it is integration. It represents a gravitational pull toward Nigerian industrial capacity. There is no scenario in which Nigeria enhances its economic sovereignty by sidelining its own refiners in favour of foreign suppliers.
The argument that fuel imports will reduce inflation is shallow. It presupposes that cheaper fuel is available, that imported fuel is of comparable quality, and that the long‑term costs of sustaining import dependency are justified by short‑term relief. Fuel imports not only transmit global shocks directly into the domestic economy, but they also place permanent pressure on foreign exchange reserves and weaken the naira. Even the World Bank’s own report acknowledged that recent price spikes were driven by global tensions, not domestic constraints. Reopening imports would simply import these shocks wholesale.
Dan Kunle is Nigeria’s most subscribed Energy Analyst
The global energy map is being redrawn, and Africa is back at the centre of it.
Since the Russia-Ukraine War, Europe has been searching for alternatives to Russian energy. That search has sharpened into urgency in recent weeks, as escalating tensions between the United States and Iran disrupt global oil flows and rattle one of the world’s most critical supply corridors.
Energy security, once assumed, is now being actively rebuilt.
African producers, from Mozambique to Senegal to Nigeria, have become newly strategic. Cargoes are being redirected. Contracts accelerated. Supply chains quietly reconfigured.
But beneath this renewed engagement sits a contradiction that is becoming harder to ignore.
The same global actors seeking long-term energy supply from Africa, including the United States and European partners, are also advancing climate financing frameworks and policy signals that constrain new fossil fuel development across African economies.
“When energy systems are stressed, priorities reveal themselves quickly. Europe is securing supply. Markets are reallocating toward stability. Capital is flowing to where rules hold.
Africa is participating in this system, but not fully on terms that support its own internal resilience.”
Africa, in effect, is being positioned as a supplier of hydrocarbons to the world, but not necessarily as a beneficiary of them at home.
That tension is no longer theoretical. It is showing up in real time.
Consider Nigeria.
In recent weeks, as global oil markets tightened following disruptions linked to the U.S.–Iran conflict, Europe has increased its pull on alternative fuel sources, including refined products from West Africa. Nigerian-linked jet fuel cargoes have moved into international markets where pricing is clearer, contracts are enforceable and payment is predictable.
At the same moment, inside Nigeria, airlines are confronting a different reality: the prospect of grounding planes for lack of affordable fuel.
Jet fuel prices have surged to levels operators describe as unsustainable. Carriers are cutting routes, consolidating schedules and modeling shutdown scenarios. In a country where aviation is not optional but connective infrastructure, the consequences are immediate. Flights do not just move passengers. They sustain commerce, coordination and continuity across distance.
The contradiction is difficult to miss: a country exporting fuel into a functioning global market while its own airlines prepare for disruption.
This is not simply a failure of local coordination, though domestic constraints are real. It is also a function of how global energy markets behave under pressure.
When supply shocks hit, commodities and capital move toward certainty. Buyers with stronger currencies, clearer pricing frameworks and enforceable contracts secure supply first. Producers, rationally, follow those signals.
Markets do not prioritize geography. They prioritize predictability.
The current crisis has only accelerated this logic.
European governments, facing immediate political and economic risk, are acting decisively to secure supply. For them, Nigeria represents resilience in a tightening market.
For Nigeria, the same dynamic translates into internal scarcity at precisely the moment stability is most needed.
Overlay this with the broader climate policy environment, and the imbalance becomes structural.
African countries are being encouraged, and in many cases financially steered, to limit long-term investment in fossil fuel infrastructure. U.S. and European-backed financing frameworks increasingly favour low-carbon projects, while support for hydrocarbons becomes more conditional or constrained.
Yet global demand for those same resources has not diminished. In moments of crisis, it intensifies.
The result is a system that pulls African energy outward while limiting its role inward.
That raises questions current policy frameworks tend to sidestep.
Can countries build reliable domestic energy systems if the most bankable uses of their resources are external? Can energy security be achieved locally when global demand consistently outcompetes domestic need? And can a transition be considered equitable if it stabilizes some regions while exposing others to deeper volatility?
These are not abstract concerns. They are visible now in flight schedules, fuel invoices and operational decisions being made in real time.
They are also not arguments against climate ambition. They are arguments about alignment.
In many African economies, hydrocarbons remain part of the infrastructure required to power industry, sustain transport systems and support economic expansion. Removing them from the development equation without viable, scaled alternatives does not accelerate transition. It redistributes risk.
The past few weeks have made one thing clear.
When energy systems are stressed, priorities reveal themselves quickly. Europe is securing supply. Markets are reallocating toward stability. Capital is flowing to where rules hold.
Africa is participating in this system, but not fully on terms that support its own internal resilience.
If that misalignment persists, it will do more than shape outcomes in moments of crisis. It will define the architecture of the global energy transition itself.
Because an energy system that exports stability and imports scarcity is not a transition.
It is a transfer of risk.
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Sola Adebawo is an institutional strategy and public affairs leader with deep experience at the intersection of energy, governance, policy, and strategic communication. His writing explores reform, political economy, leadership, culture, and the relationship between institutions and public life. He is an author, scholar, and ordained minister.
The rise of Namibia as one of the world’s most closely watched oil and gas frontiers did not happen by accident. Long before the wave of supermajors and billion-dollar discoveries, a small group of local pioneers were working to position the country as a serious player in global energy markets. Among them, Knowledge Katti stands out for both the scale of his ambition and the lasting imprint of his work.
Today, Katti serves as Chairman and CEO of Custos Energy and as a Director at Sintana Energy – roles that place him at the centre of Namibia’s ongoing exploration and investment story, including some of the country’s most significant recent offshore developments.
Ownership Before Access
Katti’s journey into energy was not conventional. He began his career at PwC (formerly Coopers & Lybrand), where he audited some of Namibia’s largest companies including Rössing Uranium. It was here that he developed a critical understanding of ownership structures – and a growing concern. Namibia’s resources were generating significant value, but that value was largely accruing to foreign shareholders rather than Namibians themselves.
That realization became a defining driver. From early on, Katti focused not simply on participation in the sector, but on ownership – arguing that Namibians needed equity stakes in their natural resources if the country was to fully benefit from its wealth.
Katti’s early efforts to enter the resources sector were met with resistance. At the time, local players were often told they needed foreign partners before they could secure licenses. Meanwhile, junior companies from markets like Canada and Australia were acquiring licenses first and raising capital afterward. Katti challenged this model, advocating for a system that would allow Namibians to lead projects from inception.
“Katti took a step few had attempted before: accessing international capital markets. By listing his company on the Toronto Stock Exchange through a reverse listing that became UNX Energy, he helped establish one of the first Namibian-led, internationally listed oil and gas companies.”
A turning point came in the mid-2000s, when he shifted focus offshore. Drawing on extensive research into the Kudu Gas Field and the broader Orange Basin, Katti presented a development vision to Namibia’s Ministry of Industries, Mines and Energy and NAMCOR. His efforts resulted in the award of an offshore license adjacent to the Kudu field – an important breakthrough for indigenous participation in the upstream sector.
To finance this vision, Katti took a step few had attempted before: accessing international capital markets. By listing his company on the Toronto Stock Exchange through a reverse listing that became UNX Energy, he helped establish one of the first Namibian-led, internationally listed oil and gas companies. While early drilling campaigns did not deliver commercial success, the experience laid critical groundwork for future development.
Equally significant was Katti’s role in shaping Namibia’s approach to resource governance. He was an early and vocal advocate for ensuring that the state – through NAMCOR – held meaningful equity stakes in oil and gas projects. This approach helped secure a substantial national position in the Kudu Gas Field and set a precedent for embedding national participation into the structure of future deals.
As the scale of offshore opportunity became clearer, Katti adapted his strategy. Rather than pursuing development alone, he focused on bringing in global partners with the technical and financial capacity to unlock Namibia’s deepwater resources. Through sustained engagement and dealmaking, he played a catalytic role in attracting companies such as Shell, TOTALEnergies, ExxonMobil, Chevron and Galp into Namibia’s offshore basin.
Beyond transactions and policy, Katti has also invested in Namibia’s human capital. Over the years, he has supported the education of more than 120 Namibian students, reflecting a long-standing belief that the country’s energy future must be built on local expertise as much as natural resources.
Today, as Namibia enters a new phase of development – marked by large-scale discoveries and growing investor interest – the foundations laid over the past two decades are becoming increasingly visible. The country’s emphasis on local participation, its ability to attract global partners and its expanding talent base all reflect a broader vision that has been years in the making.
Katti’s contribution lies not only in individual deals or discoveries, but in helping to shape the framework through which Namibia’s energy sector operates. In doing so, he has played a central role in ensuring that the country is not just a destination for investment, but an active participant in its own energy future.
In January 2026, Tony Attah, CEO of Renaissance Africa Energy, made a bold claim: Artificial Intelligence could revive 300 abandoned wells in the Niger Delta. While some may see this as purely optimistic, industry insiders know it is a grounded reality provided Nigeria changes how it handles data.
The truth is that the Niger Delta has not “run out” of oil; it is suffering from a visibility crisis. The three points below outline a strategic response on how Nigeria can turn abandoned steel into flowing gold through a digital-first approach.
Ranking the ‘Quick Wins’ from Legacy Reserve Books
The fastest route to production is not drilling new wells; it is ranking the ones Nigeria already has. Companies like Shell possess massive reserve books containing decades of data on assets that were decommissioned not because they were empty, but because they were considered uneconomic under 20th-century cost structures.
The Strategy here is to implement AI-Driven Ranking: Instead of manual reviews, AI can ingest entire reserve books and rank wells using a multi-constraint model:
Proximity to Flow Stations: Can the well be tied back within 30 days?
Well Integrity: Does the casing still hold?
Recovery per Unit Cost ($/bbl): Which wells offer the highest margin under the current $65/bbl reality?etc.
The result is a “Top 40” list of wells that can be reopened with a simple intervention (workover), rather than a $20Million drilling campaign.
“For this “magic” to become reality, data cannot remain scattered in dusty basements. Success depends on a high-value National Data Repository (NDR). While the NUPRC has already centralized massive reserve books and established the Integrated Data Mining and Analytics Centre (IDMAC), the challenge remains the sheer volume and usability of information.”
Finding “Hidden” Oil Behind Casing
Many wells in the Niger Delta were produced from a single primary reservoir, often leaving marginal zones behind pipe or bypassed entirely. Traditionally, identifying these required expensive new logging runs.
The strategy here are
Automated Log Reinterpretation AI algorithms can process legacy well logs at a scale humans cannot, identifying patterns in resistivity and porosity data that were previously overlooked. AI can pinpoint zones behind casing.
Zero-Drill Reserves By utilizing existing boreholes, operators can perforate a new section of pipe to access unproduced reserves. This turns a “dead” asset into a producer at a fraction of the cost.
High-Resolution Four Dimensional(4D) Seismic & AI Inversion
The ultimate tool for a mature basin is 4D (time-lapse) seismic. Comparing seismic surveys taken years apart, operators can see exactly how oil has moved, and where it has remained trapped.
The Nigerian Upstream Petroleum Regulatory Commission (NUPRC) is already encouraging the use of 3D and 4D seismic. The real breakthrough happens when AI takes over the complex task of inversion converting seismic soundwaves into accurate reservoir maps.
The strategy here are
Identify ‘Sweet Zones’ In mature basins, oil often becomes trapped in pockets or unswept zones. AI compares 4D seismic surveys to determine precisely where hydrocarbons remain.
Precision Infill Drilling Instead of “hitting and hoping,” operators can deploy AI-guided sidetracks to drain trapped reservoirs with surgical accuracy.
For this “magic” to become reality, data cannot remain scattered in dusty basements. Success depends on a high-value National Data Repository (NDR). While the NUPRC has already centralized massive reserve books and established the Integrated Data Mining and Analytics Centre (IDMAC), the challenge remains the sheer volume and usability of information.
The industry does not need more human reviewers; it needs a Predictive Ranking Engine, an AI layer integrated directly into the NDR to automate filtering across thousands of shut-in wells.
The success of the North Sea Transition Authority (NSTA) and the Norwegian Petroleum Directorate (NPD) shows that data becomes a national asset when it is machine-readable. Nigeria has already built the library; now it needs to hire the “AI Librarian.”
To fully support the 300-well revival, the next phase of the NDR must:
Adopt OSDU Standards: Ensure all data (logs, seismic, reports) follow the Open Subsurface Data Universe framework so AI tools can ingest it without extensive cleaning.
Democratize Insights: Provide AI ready data packages to all players, including indigenous operators enabling them to innovate as quickly as the global majors.
Create a Living Digital Twin: As wells are revived, data must flow back into the NDR in real time, creating a self-improving loop of national energy intelligence.
The bottom line is that Tony Attah is right: AI can revive those 300 wells, but AI is only the engine; data is the fuel. If Nigeria builds a world-class Data Repository, it will not just revive wells, it will revive an entire economy.
Funke Taylor is an energy industry strategist and consultant operating at the intersection of infrastructure, capital, and digital transformation. With a foundation in engineering and EPC project environments, she brings field insight into the boardroom, advising executives on data-driven, future-ready upstream strategy.
She is the Host of the Energy Web Conference, convening professionals across oil, gas, power, AI, and policy to accelerate digital innovation in energy worldwide. Her work transforms legacy assets into global digital opportunity. She can be reached at funke@theenergyaxis.com
The Nigerian National Petroleum Corporation Limited, NNPC, has been given a new Board to steer it towards national economic and energy policy. It has also come a new management team, with Engineer Bayo Ojulari as Group CEO, to recharge business performance and operational execution.
This leadership reset comes at a pivotal moment for Nigeria’s state oil company, the arrowhead of Nigeria’s position as the top oil producer in Africa, and the 12th largest resource-owning national oil company in the world by oil reserves size, and among the top 10 by gas reserves. Tectonic shifts have taken place in the operating landscape, meaning strategic outcomes must be earned, rather than flow from the status quo. The corporation has become a commercial entity, resulting from the overarching four-year-old Petroleum Industry Act. The joint venture operated fields have changed hands from international majors to emergent indigenous operators. Gasoline import subsidy has been removed, and refining is now predominantly local. Meanwhile global oil and gas prices are still sluggish, and recent tariff wars pile pressure on demand, costs, and margins. There is also the persisting push for energy transition, and the reality of OPEC quotas.
It has been widely acknowledged that the new leadership brings private-sector expertise to NNPC, and a represents a renewed focus on efficiency, transparency, and energy transition. This article provides an overview of NNPC’s corporate performance, strategic direction, and challenges under the new management leadership as of July 2025, with comparisons to leading African and emerging-market peers, while highlighting early wins which need to be sustained and scaled.
Leadership Transition and Strategic Vision
The appointment of Mr. Ojulari, an industry veteran formerly Managing Director of Shell Nigeria Exploration and Production Company (SNEPCo), in April 2025, has received much acclaim by industry stakeholders, who expect a sharper commercial focus and accelerated reforms, given his pedigree.
In his first address as Group CEO, Ojulari stated: “NNPC must deliver value for all Nigerians by operating transparently, efficiently, and with a clear focus on the future of energy.”
Based on Bayo’s public statements, the new management team’s early priorities include:
Driving operational efficiency through digital transformation and cost management.
Accelerating gas development for domestic industrialization and export growth.
Strengthening governance and transparency, with a commitment to timely publication of audited accounts and preparation for NNPC’s planned IPO.
Building partnerships and fostering innovation to attract investment and deploy new technologies.
NNPC’s Role in Nigeria’s Economic and Energy Agenda
NNPC remains central to Nigeria’s ambitions for economic diversification, energy security, and emissions reduction. The following are currently some of the officially declared national energy policy objectives related to NNPC’s role as a now commerialised national oil company.
– Increase oil production toward OPEC quota of 1.8Million barrels per day (MMBOPD).
– Expand domestic gas utilization for power and industry.
– Reduce fiscal reliance on crude exports by growing non-oil revenue.
– Advance energy transition with gas and renewables, targeting net-zero by 2060.
Revenue and profit have continued to grow, with H1 2025 maintaining the positive trend. Oil production has stabilized, though still below pre-2020 highs due to security and infrastructure challenges. Gas output is rising, reflecting Ojulari’s focus on gas-led growth. Overall half year performance trend is healthy, credit to new management priorities, and need to be sustained against financial, operational and quota constraints.
Given its relatively low production base, NNPC’s revenue is appreciable in absolute figures. Yet, given the volume of reserves available to be produced, compared to peers, the leadership of NNPC has its work well cut out. Early efforts at transparent and timely reporting of financial and operating results will serve the corporation’s strategies very well.
NNPC’s oil P/R ratio (1.65%) is moderate, reflecting large reserves but relatively low production rates compared to Petrobras and Sonatrach. The gas P/R ratio (0.85%) is low, highlighting significant untapped potential and room for accelerated gas development. Petrobras’s higher ratios indicate more aggressive resource monetization, while Sonatrach leads Africa in active reserve utilization. NNPC’s cautious pace provides a cushion for future growth but also underscores the need to boost efficiency, especially in gas, as Nigeria seeks to industrialize and expand exports. Moreover, consideration must go to global decarbonization risk to eventual hydrocarbon reserves development.
– NNPC’s governance reforms have accelerated, with a partial IPO still planned for 2028.
– Audited financials are now published annually and independently verified, a significant improvement from earlier years.
Strategic Initiatives and Recent Developments
– Gas Expansion: The AKK pipeline is 80% complete as of July 2025, with first deliveries expected by year-end. LNG exports are up 8% year-on-year.
– Refining: The Dangote Refinery, with NNPC as a 7% stakeholder, began commercial operations in March 2024, reducing Nigeria’s fuel import bill by $2.5Billion in the first half of 2025.
– Regional Integration: NNPC is negotiating new gas supply deals with Ghana and Benin, aiming to become a regional gas hub.
Challenges and Constraints Remain
As the new management cranks up the NNPC machine, the old challenges and legendary issue remain and will be compounded by a giddy energy market and complicated fiscal situation. Below are some of the moving parts the new captains much keep in focus and as they progress demonstrate success on.
Security and Oil Theft:
Pipeline vandalism and theft remain issues, though incidents have dropped by 30% since 2023. Losses still average 120,000BOPD.
Regulatory Uncertainty:
The Petroleum Industry Act has improved the investment climate, but delays in downstream deregulation and gas pricing reforms persist.
Capital Access:
The planned IPO is closely watched. Success will depend on continued governance improvements and investor confidence in oil and gas.
Global Energy Transition:
NNPC faces pressure to decarbonize, with international lenders tightening criteria for oil and gas financing.
Opportunities and Strategic Levers
Gas Industrialization:
Nigeria’s gas reserves exceed 206rillion cubic feet. A successful gas push could transform the power sector and create new export opportunities.
Petrochemicals and Value Addition:
NNPC’s new partnerships in fertilizer and methanol production are starting to support non-oil export growth.
Capital Market Access:
A successful NNPC initial public offer could unlock new funding and drive further governance improvements, as seen with Petrobras. As IPO’s go though, especially when there are competing investment options, success will require deftly calibrated implementation, robust investor targeting and solid fundamentals, as investors will be voting as much for potential as for capacity. And there are reputational risks to overcome.
Regional Energy Leadership:
Nigeria is well placed to become West Africa’s main supplier of gas and refined products, leveraging new infrastructure. As regional market beckons, new refining capacity sufficient for export and a renewed focus on tangible commercialization of gas will deliver on the opportunity.
Major Global Energy Events and Issues
Several major global and national energy events, issues, and deadlines in 2025 and 2026 are poised to test, and if successful, demonstrate NNPC’s new strategic direction under Bayo Ojulari’s leadership. These milestones reflect both the company’s internal reforms and its response to broader shifts in the energy landscape.
– COP30 (November 2025, Brazil)
The UN Climate Change Conference will spotlight global commitments to decarbonization and energy transition. NNPC’s participation and potential announcements on gas and renewables will signal its alignment with climate goals and international expectations.
– OPEC+ Production Policy Reviews (Quarterly, 2025‚ 2026)
OPEC+ meetings will shape oil production quotas and market stability. NNPC’s ability to meet or exceed Nigeria’s quota consistently will reflect operational improvements and its role in global supply dynamics. These metrics will be factored in as OPEC considers Nigeria’s push for quota increase. Conversely, managing the quota ceiling without losing production will require NNPC working with regulators and partners to stimulate local refining and absorb production volumes, and to diversify export revenues from products not constrained by the quota, such as condensate.
– Global LNG Market Expansion (2025‚ 2026)
As new LNG projects come online worldwide, NNPC’s progress with Nigeria LNG expansion and new gas export deals will demonstrate its competitiveness in the evolving gas market.
– International Oil Company (IOC) Divestments in Africa
Ongoing IOC asset sales in Nigeria and elsewhere present opportunities for NNPC to acquire assets, form new partnerships, or increase domestic participation‚ showcasing a more assertive commercial strategy.
Key National Energy Events, Issues, and Deadlines
– AKK Gas Pipeline Commissioning (Expected Q4 2025)
The completion and commissioning of the Ajaokuta-Kaduna-Kano (AKK) gas pipeline will be a landmark for Nigeria’s gas industrialization agenda and a core test of NNPC’s project delivery under Ojulari.
– Dangote Refinery Full Ramp-Up (2025‚ 2026)
Achieving full operational capacity at the Dangote Refinery (where NNPC holds a 7% stake) will significantly reduce Nigeria’s fuel imports and demonstrate NNPC’s commitment to domestic value addition.
– NNPC Partial IPO (Planned 2026)
Preparations for NNPC’s partial listing on the Nigerian Stock Exchange and possibly international markets will test its governance reforms, transparency, and investor appeal‚ key markers of its new commercial orientation.
– Petroleum Industry Act (PIA) Implementation Deadlines
Full compliance with PIA provisions‚ especially around host community development, fiscal terms, and deregulation‚ will be closely watched by investors and the public as indicators of regulatory discipline and reform momentum.
– Gas Pricing and Market Reforms (Ongoing, 2025-2026)
Progress on domestic gas pricing reforms and market liberalization will be crucial for unlocking investment and expanding gas-based industries, aligning with Ojulari’s gas-led growth strategy.
– Renewable Energy Project Announcements
New solar, wind, or hybrid energy projects launched or commissioned by NNPC will highlight its diversification efforts and response to global energy transition pressures.
New Tax Regime
A portfolio of four wide-ranging federal tax laws was recently signed and will take effect from January 1, 2026. Major components of the new tax regime will impact NNPC as a corporate taxpayer, a major employer of taxpayers, and a contracted partner to large operators, and suppliers. In addition, its operations are linked to revenue collecting entities such as the regulators, fiscal roles are being redefined. NNPC’s response to the new tax and non-tax revenue regime will be visibly central to successful implementation and the prospect of achieving the intended economic goals. Besides, the corporation’s fiscal behavior, already watched as a commercial entity, will be further scrutinized in the run-up to an IPO.
These events and issues will test and define NNPC’s evolving strategy‚ demonstrate transparency, commercial discipline, gas-led growth, and alignment with energy transition‚ under its new leadership.
NNPC’s new management, under the direction of a reconstituted Board, has a pivotal window for to rest NNPC Limited. As CEO, Engineer Ojulari’s private-sector experience and declared reform agenda are already driving operational improvements and greater transparency. NNPC’s production-to-reserves ratios reveal both a solid resource base and the need for more aggressive production, especially in gas, to fully realize Nigeria’s energy ambitions. While challenges remain‚ particularly around security, regulation, and the global energy transition‚ NNPC under the new management appears more transparent, increasingly competitive, and strategically aligned with the country’s goals.
The wide scope of the prevailing issues will test the new management’s ability to inspire its workforce, attract investors, constructively build trust with a broad spectrum of stakeholders and to connect purposefully with national aspirations in an era of intensified scrutiny. The company’s outlook is more optimistic than it has been in years, with the new leadership well curated and poised, offering a prospect of a true regional leader in integrated energy.
Note: Data for this article were synthesized from sources including NNPC reports and statements, NUPRC regulatory reports, OPEC reports, World Bank assessments, International Energy Agency reports, industry analytical platforms such as SBM Intelligence and Africa Oil+Gas Report, government policy statements, NOC websites, news reports, etc.
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Dr. Arinze is an energy policy and investment thought leader, consultant, and author.
North African nations have seen recent progress in the field of renewable energy, especially in green hydrogen.
Hydrogen has many uses across varied industries, from petroleum refining and food processing to fertilizer and steel production. While the aerospace industry has used hydrogen as a rocket fuel since the dawn of the space age, there is plenty of room for the growth of hydrogen-powered cars, or fuel cell electric vehicles (FCEVs), in the automotive world. Though its implementation in electricity generation is minimal at present, hydrogen may see more widespread use as a supplementary or alternative fuel source in the future at standalone facilities and power plants currently running on natural gas.
Hydrogen production primarily uses electrolysis, a process in which an electric current passes through water to separate hydrogen from oxygen. Currently, about 95% of the electricity for global hydrogen production comes from natural gas and coal-fired power plants. By contrast, green hydrogen production utilizes electricity from renewable sources such as solar and wind instead. If the majority of hydrogen production facilities switched to renewable energy, the International Energy Agency (IEA) estimates this could reduce CO2 emissions by approximately 830Million tonnes annually.
As the world struggles with the urgent need to transition from fossil fuels to more sustainable energy sources, green hydrogen offers an avenue where production can continue with the same capacity but without harmful by-products, particularly in regions rich in renewable energy potential like North Africa. This region, characterized by vast, consistently sun-drenched deserts and strong winds, could potentially lead the way in developing a global green hydrogen economy. However, this transition is not without its complexities and challenges.
The Promise
North Africa offers several compelling advantages, marking it as a prospective green hydrogen mega-producer.
North Africa already has the requisite abundant natural resources and developing infrastructure to support a massive expansion in green hydrogen production. The region boasts some of the highest solar irradiation levels globally, making it an ideal location for solar-powered hydrogen production. Countries like Morocco and Egypt have already initiated projects like the Noor Ouarzazate Solar Thermal Complex and the Benban Solar Complex, respectively, which could serve as the backbone for the industry. Additionally, the wind potential along the coasts of Algeria and Mauritania provides another renewable energy source for industrial-scale electrolysis.
For national economies critically dependent on oil and gas, green hydrogen offers a path to greater diversification. The transition would not only lessen the negative impacts of oil’s inherent price fluctuations but also foster new industries. Green hydrogen production could lead to development in related sectors such as hydrogen fuel cells, ammonia production for fertilizers, and even green steel (steel produced using hydrogen as a reducing agent eliminating coal and CO2 emissions from the process) creating new jobs and stimulating economic growth.
A ramp-up in green hydrogen production would also have more than just local benefits as the endeavor aligns with global climate goals as well. By focusing on green hydrogen, North African countries could position themselves as leaders in the worldwide decarbonization effort while opening up new export markets. The export of green hydrogen to Europe, which has set ambitious climate targets, could become a lucrative trade, further enhancing North Africa’s geopolitical stature in the energy sector.
With the right infrastructure in place, like the kind proposed for the SoutH2 corridor linking North Africa, Italy, Austria, and Germany, producers could transport green hydrogen via pipelines or as easily shippable derivatives like ammonia or liquid organic hydrogen carriers (LOHCs), which would be particularly appealing to European markets seeking to decarbonize.
The Challenges
A realistic assessment of the path to a green hydrogen economy in North Africa reveals it is not without its fair share of challenges.
Hydrogen production through electrolysis requires significant amounts of water, which is already scarce in many parts of North Africa. This fact essentially mandates solutions like seawater desalination or wastewater recycling, both of which add to the energy and financial burdens of any green hydrogen initiative.
The lack of existing infrastructure for hydrogen production, storage, and distribution is also a major hurdle. North Africa will need new pipelines, storage facilities, and ports capable of handling hydrogen and its derivatives, and the construction associated with these features will require substantial investment. Moreover, while adapting existing gas infrastructure to facilitate hydrogen transportation is a feasible venture, it presents additional technical and safety challenges due to hydrogen’s volatile properties.
Another impediment to green hydrogen’s expansion is its overall economic viability. Currently, green hydrogen production costs remain higher than those of fossil fuels or even those of blue hydrogen (hydrogen produced using natural gas with carbon capture). Achieving economies of scale and technological advancements in electrolyzers could reduce costs, but until then, green hydrogen will struggle to compete without subsidies or carbon pricing mechanisms.
Nations engaged in green hydrogen production will also have to create and clearly define their associated policies and regulations. This nascent stage of the technology’s development calls for robust policy frameworks if producers are to attract investment, ensure safety, and integrate hydrogen into their existing energy systems. North African nations need to develop clear strategies, not only for hydrogen production but also for how it fits into their broader energy policies. This includes regulatory support for renewable energy projects, hydrogen certification, and cross-border trade agreements.
The capital-intensive nature of green hydrogen projects means funding is another critical barrier. While there are signs of interest from international investors, the risk perception in some North African markets could deter the necessary influx of capital. It might be necessary to seek international cooperation on innovative financing models such as green bonds which are issued by public or private institutions for the purpose of funding projects intended to mitigate climate change.
Lastly, skill development and technology transfer present other hurdles. Building a green hydrogen industry requires a skilled workforce that counts engineers, technicians, laborers, and policymakers as members. Considering that nations who want to participate in the green hydrogen economy will have to develop local expertise, there is a built-in need for investment in education and training. And while technology transfer from countries leading in hydrogen technology would be beneficial, it comes with its own set of potential limitations regarding intellectual property and capacity expansion.
Moving Forward
Despite these challenges, leveraging North Africa’s green hydrogen potential is a worthy pursuit and will require a multi-faceted approach:
Regional collaboration. Initiatives like the African Green Hydrogen Alliance are steps in the right direction, promoting shared knowledge, infrastructure, and investment.
Technological innovation. Conducting research into more efficient electrolyzers, better hydrogen storage solutions, and the use of non-fresh water sources for electrolysis could mitigate some of the current limitations.
International partnerships. The EU’s goal of importing 10 million tonnes of green hydrogen by 2030, as stipulated by the REPowerEU Plan, presents an immediate market opportunity. Collaborations across Europe for diversified investment, technology sharing, and market access can accelerate development.
Policy leadership. Governments must lead with policies and offerings that not only incentivize green hydrogen but also ensure sustainability. These would include clear and detailed roadmaps to success, unwavering support for initial projects, and incentives like the simplified administrative procedures and tax breaks l the Egyptian government established when it granted 42,000 square kilometers of land to the New and Renewable Energy Authority (NREA) for green hydrogen production.
Environmental considerations. It is crucial to ensure that green hydrogen projects do not lead to unintended environmental degradation, especially concerning water use. Operators must integrate and adhere to environmentally friendly practices from the outset.
The development of green hydrogen in North Africa holds transformative potential, offering a route to clean energy production that could redefine the region’s economic landscape.
However, to realize this potential, North Africa will have to overcome significant hurdles through strategic planning, international cooperation, and a commitment to sustainability. If North Africa navigates these challenges with foresight and innovation, the region could meet its own energy needs via greener alternatives while playing a pivotal role in the global energy transition and setting a precedent for other regions to follow.
NJ Ayuk is Executive Chairman, African Energy Chamber
Reviewing the majors for 2025 brings with it a plurality of scenarios.
Trump’s entry to the White House has more than a passing interest to both Chevron and ExxonMobil. Both companies will be lobbying Trump to ensure that US-Russian relationships are improved. Why?
When the Soviet Union broke up in the early 90s and Kazakhstan emerged as a new oil province, both Chevron and ExxonMobil, seen as ambassadors of US goodwill, gained access to the country’s black gold. Chevron’s prize was operatorship of Tengiz (50%) and ExxonMobil gained a 25% share. Chevron also has an 18% share in the large Karachaganak Gas Field. ExxonMobil has a 16.81% share of the troubled Kashagan Project.
Shell’s attention will no doubt be focused on its important LNG sector which can anticipate the necessary headwinds. While the courts in the Netherlands has given the UK major a pass on its Carbon Dioxide (CO2) reduction appeal, no doubt a new narrative must be developed if new energy is to develop a societal consensus.
Equinor …willing to fight the good fight is too small to be a force for good and must re-invent its development scenarios.
ENI, small and contrarian, has found through strategic alliances and pragmatic solutions that it has become a respected player in Africa.
TOTALEnergies, both in terms of leading the pack with its innovative approach for the energy transition and its deepwater exploration, is a player to watch.
BP continues to flounder: a company in search of its soul.
In the period 2021-2024 the Dow Jones Industrials gained 38%: from 31,098 in January 2021 to 42,992 December 2024. The oil majors have displayed a variety of results:
ExxonMobil +130%
Chevron +58%
Shell +55%
Eni +23%
Equinor +22%
BP +21%
TOTALEnergies +20%
Table 1: Oil majors stock prices 2021-2024 (NYSE)
Year
BP
Shell
ENI
TOTAL
Energies
Chevron
ExxonMobil
Equinor
2021
$24
$40
$22
$46
$91
$46
$18
2024
$29
$62
$27
$55
$144
$106
$22
BP: A Takeover prey?
BP’s share price in the period January 2021- December 2024 has remained tepid: from $24 to $38. The company’s checkered history continues to haunt its assets:
BP’s Deepwater Horizon oil spill of 2010 in the Gulf of Mexico has cost the company $65Billion;
The company’s withdrawal from Russia in February 2022, because of the Ukraine conflict, meant the loss of 50% of its global reserves; and
In September 2023, the abrupt resignation of CEO Bernard Looney after he admitted that he had not been “fully transparent” about historical relationships with colleagues.
BP is promising to spend up to $65Billion on renewables between 2023-2030, amounting to half of its investments by 2030. Yet the company has written off $540Million of its offshore wind assets in New York.
Will BP be able to meet its renewable energy goal given the long-term slump of renewables and BP’s lingering share price?
What BP was Promising Originally?
An underlying EBIDA (earnings before interest, depreciation, and amortization) of between 5–6% per year through to 2025 with returns in the range of 12–14% in 2025.
From 2025 onwards, when its low-carbon projects would start to kick in, an expected growth of between 12–14% to be maintained.
More recently BP has announced that in 2025 its oil and gas production to be around 2.6Million b/d of oil equivalent. The capex for oil and gas is $8.5Billion. The company has a renewable pipeline of some 47GW.
BP’s faltering vision, its downward share price and its low valuation—some $84Billion–makes the company a vulnerable takeover prey.
The chief obsession of Wael Sewan, Shell CEO since 2023, is to drive up the company’s stock price. His hydrocarbon narrative is mimicking that of Chevron and ExxonMobil.
Shell’s total capex for the period 2023-2025 is between $22-$25Billion per year, of which 80% is earmarked for hydrocarbons. Not unlike Chevron and ExxonMobil.
Yet what distinguishes Shell is its strong LNG arm, truly global. In short, Shell is really a natural gas company.
A fundamental concern for Shell should be the global outlook for LNG. Shell’s LNG Outlook 2024 forecasts that China will grow its LNG requirements more than 50% by 2040: rising to 23Trillion cubic feet (Tcf) in 2040 from 14Tcf in 2023.
Yet Shell’s optimism may be premature.
The Institute for Energy Economic and Financial Analysis (IEEFA)’sGlobal LNG Outlook 2023-2027casts a far more somber analysis for future LNG developments, in particular for China: rising domestic gas production, pipeline gas imports, and renewable power capacity could limit the potential for rapid LNG demand growth over the medium term.
Where did it go wrong?
A long-term LNG slow down for China is only a part of the puzzle. According to IEEFA the global demand for LNG is slowing:
Europe, while maintaining a high degree of LNG import, is also increasing energy efficiency measures and wind and solar projects have become commonplace.
Japan and Korea, historically dependable LNG importers, are increasingly turning to nuclear, and renewables; and
South Asia, including India, Pakistan, and Bangladesh slashed purchases by 16% in 2022 and suppliers often defaulted on contracts to obtain higher prices elsewhere.
“After several years of weak supply growth, IEEFA anticipates that the global LNG market will see a tidal wave of new projects come online starting in mid-2025. The wave will likely crest in 2026, with the addition of 64Million metric tons of annual liquefaction capacity—the most in the history of the global LNG industry. The supply additions will boost global liquefaction capacity by roughly 13% in a single year. Liquefaction projects targeting in-service after 2026 may be entering a much smaller demand pool than bullish market forecasts anticipate. As new supply floods the market, today’s tight markets may give way to a supply glut, with lower-than-anticipated prices, smaller netbacks, tighter margins, and lower profits for LNG exporters.”
The turning point will be 2025.
“IEEFA anticipates that roughly 17Million Tonnes Per Annum (MMTPA) of liquefaction projects are likely to come online around the world in 2025—more than in 2023 and 2024 combined. New capacity additions will crest in 2026, with an estimated 64MMTPA of capacity coming online in a single year, and continue into 2027, when 37MMTPA of new capacity is expected to begin operating”.
How will a floundering LNG market affect Shell’s dominant LNG position? Does Shell continue to have the agility to re-calibrate its strategy?
Redefining the Common Good
Up to 10-15 years ago, what Shell stated as a company policy in the Netherlands was largely interpreted as the ‘Common Good’. What was good for Shell was also deemed good for the country as a whole.
For example, up to 2018, the Inspector-General of the Dutch State Supervision of Mines, the highest regulatory authority for the oil and gas industry in the Netherlands, was always headed up by an ex-Shell nominee.
Yet Shell’s recent win in its landmark case overturning an earlier ruling requiring it to cut its carbon emissions by 45% have seen Shell do an abrupt about-turn: in essence arguing that cutting carbon emissions was a “private matter” and had little to do with the “Common Good”.
The Court of Appeal in the Netherland’s capital city of The Hague, said it could not establish that Shell had a “social standard of care” to reduce its emissions by 45% or any other amount, even though it agreed the company had an obligation to citizens to limit emissions.
If people considered progress was too slow towards cutting emissions, then, according to Shell, they should lobby governments to change policies and bring about a green transition.
Shell’s insistence that the courts have no jurisdiction in the Shell boardroom could in the longer-term backfire. Perhaps time to go back to Jean-Jacques Rousseau.
For Rousseau, writing in the mid-18th century, the notion of the Common Good, achieved through the active and voluntary commitment of citizens, was to be distinguished from the pursuit of an individual’s private will.
As Rousseau explains, the general will is the will of the sovereign, or all the people together, that aims at the Common Good—what is best for the state as a whole.
The heart of the matter for Shell is that the company has continued to argue that this is a private( company) matter, not one involving the the Common Good.
Yet the 2016 Paris Climate Agreement, which was signed by 195 countries, agreed to try and prevent an average global temperature rise of under the 20C and hopefully 1.50C, is the clearest example of a Common Good.
What the court and Shell are arguing is that the Common Good must be redefined: a court follows precedent and does not establish it. In other words, the current design of the energy transition must have a more encompassing architecture if a new consensus is to be arrived at.
The Joker in the Deck
ENI, the Italian-based oil and gas giant, is often overlooked in any discussions involving the other oil majors-BP, Chevron, Equinor ExxonMobil, Shell, and TOTALEnergies. Yet ENI could be the Joker in the deck providing surprises to an unwitting public and be an upstart which deserves the needed attention.
ENI’s strong presence in North Africa—Algeria, Egypt, and Libya—could in the coming months become one of Europe’s substitute providers of natural gas. This region currently produces 648,000barrels of oil equivalent per day (BOEPD). The company operates in the frontier areas seldom mentioned in the daily news media.
For starters the company produces 1.7mboed(million barrels of oil equivalent per day), has a balance sheet which has an economic leverage of 20%, and has, according to its website, an Internal Rate of Return(IRR) of 34%, the highest of all its peers for the 2012-2021. Also, its RRR(Reserve Replacement Ratio) of 110% for the period 2012-2021 is the highest compared to its industry peers.
ENI further states that 90% of exploration capex is spent on near fields and proven basins. Some $11Billion in the last 10 years has been spent on its dual exploration model—near fields and proven basins. The company states that it only requires three years—from first discovery of oil to market—twice as fast as the industry average.
A key ENI strategy is developing a series of joint-ventures to ensure that ENI can achieve maximum leverage for its current oil and gas assets and at the same pursuing new strategies as part of its energy transition plan. Some examples:
Vår Energi, Norway was formed in 2018 following the merger of Eni Norge AS and Point Resources AS owned by Hitec Vision, a private Norwegian investment fund. The company’s primary focus is oil and gas developments on the Norwegian Continental Shelf. ENI controls 69.6% of the shares, and HitecVision 30.4%. Vår Energi has production in 36 fields and produces 247,000 boepd.
Ithaca Energy in the UK (ENI 37.17%) has become the largest O&G operator in the UKCS by resources.
Azule Energy, Angola, a 50-50 joint venture between ENI and BP formed in 2022 to include both companies’upstream assets, LNG and solar business. Azule Energy is now Angola’s largest independent equity producer of oil and gas, holding 2Billion barrels equivalent of net resources and growing to about 250,000BOEPD of equity oil and gas production over the next five years.
Azule Energy in 2024 completed a farm-in of Block 2914A located in Namibia’s Orange Basin, giving the company a 42.5% share.
Plenitude, ENI’s new company, launched in June 2022 is an integrated business combining the generation of electricity from renewables, the sale of electricity, gas and energy services to households and businesses, and a European network of charging points for electric vehicles.
Enilive is ENI’s mobility transformation company. Founded with the goal of offering integrated services and products that are progressively decarbonized by 2050, Enilive is the tangible result of Eni’s ten-year commitment to sustainability-driven mobility transformation.
TOTALEnergies’ energy production in the period 2020 -2030 “will grow by one third, roughly from 3MMBOEPD to 4MMBOEPD, half from LNG, half from electricity, mainly from renewables”, according to Patrick Pouyanné, the company’s Chairman and CEO.
This was the first time that a major operator has wittingly or unwittingly translated its renewables to BOE(barrels of oil equivalent). The golden rule was that RRR(Reserve Replacement Ratio) was always used to assess a company’s hydrocarbon reserves. This author has for some time argued that oil companies also include other fuels in their reserve count—be that wind or solar– to create a basket of energy reserves. Thus, increasing reserve count and buttressing up fossil reserves and adding value to hydrocarbon assets.
By taking renewables on board has enabled the company to leapfrog the competition. Getting a head start with renewables and continuing to manage its deepwater projects. The company has confirmed that it is on track to deliver 100GW of renewables by 2030.
The company’s twin pillars—Oil and Gas and Integrated Power—have a capex of between $16-18Billion for 2025 of which $5 billion will be spent on low-carbon energy.
TOTALEnergies’s goal for its Integrated Power division is to have a ROACE(Return on Average Capital Employed) of 12%; in 2023 it was 10%.
Yet ROACE averages for the oil and gas industry are virtually double that of new energy: in 2022 TOTALEnergies’ROACE stood at 28.2%, and in 2023 Equinor’s ROACE stood at 24.9%.
In terms of deepwater TOTALEnergies will be focused on its Venus prospect in Namibia: in its Venus 2913 B development is taking place and the company is engaged in a further exploration programme.
Fly in the Ointment: ENI’s Coral Sul Project in Mozambique
A fly in the ointment could well be ENI’s LNG projects. The first LNG shipment of Eni’s Coral Sul FLNG shipment took place in November 2022. ENI’s second LNG project—Coral Norte–is expected to receive FID shortly.
Meanwhile Africa’s two most highly touted LNG projects—Rovuma and Mozambique LNG—have continued to be on security hold.
TOTALEnergies has made no final FID decision on its Mozambique LNG project, which is expected to cost $20 billion and produce up to 43 million tons per annum remains. Will it ever be developed?
Chevron: Stay vigilant
Aside from its newly acquired asset in Guyana two-thirds of Chevron’s total production of 3 million barrels of oil will in 2025 come from just two projects: Tengiz in Kazakhstan and the Permian Basin in the United States each yielding 1Million barrels of oil equivalent per day.
Today the company has a net value of over $283Billion, seen its stock price rise to $144 by December 2024, up from $91 in January 2021.
The company will devote $14.5-$15.5Billion of capital spending for consolidated subsidiaries. The company has indicated that $13 billion is devoted to domestic upstream operations.
Outside the USA, Chevron will spend between $1.7 -$2Billion to further develop its Tengiz asset in Kazakhstan, and other assets elsewhere. This is not promising for Africa, where Chevron has major operations stretched across the continent including major projects in Nigeria, Angola, Equatorial Guinea, and Egypt.
Tengiz Project
Tengiz production is currently producing 560,000 BOPD and is being expanded by some 260,000BOPD. Total costing is estimated at $45Billion.
Expiry date for the Tengiz concession is 2033. What will happen then? Tengiz was for most of its duration Chevron’s crown jewel, providing cash to developing assets elsewhere including Africa. Given Chevron’s current strategy it can only hope that Tengiz can continue to squeeze out more oil.
Caspian Pipeline Consortium(CPC)
A potentially troubling problem is the Caspian Pipeline Consortium(CPC) which transports Caspian oil from Tengiz field to Novorossiysk-2 Marine Terminal, an export terminal at the Russian Black Sea port of Novorossiysk. The CPC pipeline handles almost all of Kazakhstan’s oil exports. In 2021 the pipeline exported up to 1.3 million bpd(barrels per day). On July 6, 2022 a Russian court ordered a 30-day suspension of the pipeline because of an oil spill. The CPC appealed the ruling and the suspension was lifted on 11 July of the following week, and the CPC was instead fined 200,000 rubles ($3,300).
The incident demonstrates the vulnerability of Tengiz and future production. No doubt this is not the last such incident which involves Russian and Kazakhstan goodwill to ensure that Chevron’s Tengiz Project does not falter. Having to dependent on Russian-Kazakhstan goodwill to guarantee Tengiz production has put Chevron’s lack of diversity of oil supply in a very bad light.
Permian Basin
A final sour note for Chevron could be its Permian Basin assets. What assurances do we have that Chevron’s Permian Basin adventure will fare better than that of past shale operators?
In a 2021 March report IEEFA found the 30 producers generated $1.8 billion in free cash flows in 2020 after slashing capital spending by $20Billion from the previous year.
Since 2010, the 30 companies examined by IEEFA had reported negative free cash flows totaling $158Billion. “The positive free cash flows pale in comparison to the industry’s accumulated debt loads.” The 30 shale producers owe almost $90Billion in long-term debt, and the reductions in capital expenditures are unlikely to ensure that the industry grows.
ExxonMobil: Don’t count your chickens…
ExxonMobil’s vital signs are the following: between January 2021 and December 2024 the stock price at the NYSE has risen from $46 to $106. The company has a capex of between $27-29Billion in 2025 and a market capitalization of $487Billion.
Good News & Bad News from Guyana
ExxonMobil continues to publish for the world its good news from its offshore Stabroek Block in Guyana: by 2027 a target of 1.7MMBPD will be pumped, budgeted at a cost of $45Billion. Total recoverable reserves are estimated at 11Billion barrels.
Not mentioned is the price tag.
Guyana will carry a minimum $20Billion outstanding balance owed to its oil producer partners at the end of 2024, in the opinion IEEFA. This amount must be paid, along with other contractually obligated development costs, before the country can fully enjoy any long-term benefits that might materialize.
This is a discussion which must be had in the coming months.
LNG—A Mixed Blessing
Rovuma LNG was supposed to become ExxonMobil’s futuristic model LNG project. ExxonMobil has recently issued various tenders to move its Rovuma project ahead. Instead, in a matter of months events have overtaken ExxonMobil’s best laid plans.
IEEFA’s recent warning of a global LNG oversupply in the coming five years is not good news! Will Rovuma make it to the starting gate?
Then there is the matter of Eni’s Coral Sul Project in Mozambique.
ENI’s Coral Sul FLNG project’s inauguration deserves special attention. The first LNG shipment of Eni’s Coral Sul FLNG shipment took place in November 2022.
While Africa’s two most highly touted LNG projects—Rovuma and Mozambique LNG– continued to be on security hold, Eni achieved pole position with its Coral Sul FLNG project. A FID(Final Investment Decision) is expected to be made on ENI’s second Coral Sul Project in Mozambique in early 2025.
On May 31, 2023 Equinor announced that it would delay by at least three years its Bay du Nord project in the deepwater Flemish Pass basin 500 km off the coast of Newfoundland, Canada. Why? Because the project would cost an estimated $12Billion. Only $12Billion you might think. Is that a reason for not developing this project at a time when oil and gas companies are showing record earnings? According to Equinor technical and financial challenges are the main reasons for the delay.
Yet Equinor’s reasoning is not directly related to the Bay du Nord capital costs. By 2030 the company is pledged to spending half of its capex on renewable energy. In 2024 its capital budget was $13Billion. On this basis Equinor’s capital budget for future oil and gas projects is rather restrained.
Yet the company has revealed how it will be implementing its strategy:
In October 2024 Equinor announced that it had taken a 10% stake in Ørsted.
Equinor UK and Shell UK have combined their UK offshore oil and gas assets to form a new joint JV.
Will more strategic alliances be announced?
Pillar Number One
Equinor’s concern is whether the company’s twin pillars–natural gas and offshore wind — have the financial depth and ability to achieve maximum leverage for both pillars?
Equinor’s offshore wind portfolio is pledged to grow to 12–16 GW of installed capacity by 2030. Equinor has chosen a series of joint ventures to develop its offshore wind portfolio. The first, Dogger Bank, heralded to become the world’s largest offshore wind farm, is being developed together with SSE Renewables based in the UK. Located in the North Sea, the project will produce some 3.6 GW of energy, enough to power 6 million households.
Originally Equinor and BP were partners in the Empire Wind and Beacon Wind assets off the USA’s east coast. Under a swap agreement Equinor has taken over full ownership of the Empire Wind lease and projects and BP will take full ownership of the Beacon Wind lease and projects. The two projects will generate 4.4 GW of energy.
Equinor’s rivals have the size and economies of scale to be very competitive:
ENGIE based in France: In 2021 the company spent more than $11 billion on investments across a broad swath of sectors, including solar, wind (on and offshore), hydro plants, biogas, and developing gas and power lines, and will have 50 GW of global renewable installed capacity by 2025.
Enel based in Italy: The company’s strategic plan outlines total investments of $231Billion and tripling renewable capacity to 154 GW by 2030.
Ørsted based in Denmark: By 2030 the company will have an installed capacity of 50 GW of renewable power.
Iberdrola based in Spain: From 2020–2025, the company will be spending $165Billion on renewable energy and has a pending target of 95 GW of installed wind capacity.
RWE based in Germany: By 2030 RWE will have 50 GW of installed wind and solar capacity.
Vattenfall based in Sweden: In the Nordic countries, Vattenfall has low emissions, with practically 100% of the electricity produced based on renewable hydro power and low-emitting nuclear energy.
Pillar Number Two
Oil is the main money earner for Equinor but it’s providing of natural gas to Europe which has caught the public fancy.
According to the Norwegian Petroleum Association (see below), Norway produced in 2020, 22% of Europe’s natural gas demands. Additionally, 2/3’s of Norway’s total gas resources is still to be produced. No doubt in the short-term natural gas exports from Norway to Europe will be substantially raised.
Choosing a Future Home
The company’s net income in 2023 was $11.9Billion, basically the lion’s share from natural gas while its renewables business division(read offshore wind) Equinor’s renewables business has reported a net operating loss of $166Million for the third quarter of 2024, compared with a loss of $412Million in the same period in 2023.
No doubt Equinor’s natural gas will continue to flourish in the short-term. The key question is what will happen to the offshore wind division? In this context do not expect that the Bay du Nord project will be developed in Canada any time soon.
Some Final Thoughts
The Higher Court’s decision in the Netherlands ruled that it could not establish that Shell had a “social standard of care” to reduce its emissions by 45% or any other amount. Yet the court agreed the company had an obligation to citizens to limit emissions.
A court follows precedent and does not establish it. In other words, the current design of the energy transition must have a more encompassing architecture if a new consensus is to be arrived at.
An important item to address is the high ROACE rate which the oil companies see necessary to maintain their operations and investments: an ROACE above 20% is more or less the norm; double that of the new energy companies who aim to achieve an ROACE of 10%-12%.
Maintaining a 20% ROACE is necessary if an oil company is to continue its generous dividends.
If an energy transition CO2 surcharge were introduced would an oil company’s ROACE look so positive?
New energy companies will be seeking more specialized services and government incentivized programs to ensure their growth both in terms of their share price and dividends.
Finally, anticipate that the oil companies and new energy will continue to spin off, merge or form joint ventures to maintain economies of scale and further profitability.
Gerard Kreeft, BA (Calvin University, Grand Rapids, USA) and MA (Carleton University, Ottawa, Canada), Energy Transition Adviser, was 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 Energy Economics and Financial Analysis(IEEFA). His book The 10 commandments of the Energy Transition is now on sale at Bookstorehttps://books.friesenpress.com/store/title/119734000211674846/Gerard-Kreeft-The-10-Commandments-of-the-Energy-Transition.
To prevent catastrophic climate change, environmental organizations, financial organizations, and governments across Europe and North America have insisted that developing nations, including those in Africa, must immediately transition from fossil fuel production and usage to renewable energy sources like solar, wind, and hydrogen.
The majority of those making these demands are based in industrialized nations that were built on fossil fuels — oil and gas fueled their economic engines — yet they are unwilling to allow less developed nations to use fossil fuels to the same end. Even more troubling, the countries these groups are taking aim at have a wealth of natural resources under their feet, resources that can be monetized and used to build a better future.
We have explained, over and over, why African countries, businesses, and communities still need support from international oil companies (IOCs), foreign governments, and investment institutions for oil and gas projects. IOCs, for example, play an important role in knowledge sharing and helping Africans build valuable job skills. What’s more, foreign oil and gas investments create opportunities for revenue that can be used to build and improve energy infrastructure — for both fossil fuels and renewables. And, by supporting natural gas projects, investors create a path for gas-to-power projects that help minimize the continent’s widespread energy poverty.
In July 2021, when it became apparent that reasoning was not yielding results, the African Energy Chamber employed the same tactics the international community used against our members. We called for boycotts against financial institutions that discriminated against the African oil and gas industry.
But the calls to stop financing African oil and gas have only grown louder and more insistent.
In the course of the 2021 United Nations Climate Change Conference (COP26) in Glasgow, more than 20 countries and financial institutions pledged to stop public financing for overseas fossil fuel projects. Europe then decided that gas was clean for Europe so it will be financed but for Africa, gas is dirty and will receive no funding. The United Kingdom and the European Union have also reportedly joined in the chorus of voices demanding a ban against developed nations providing subsidies for fossil fuels.
Other expectations for the 2024 edition of the conference include calls for member states to formally commit to triple their renewable energy capacity and double their energy efficiency across the board by 2030.
The thread tying all these pledges together, with respect to our work at the African Energy Chamber, is that none of them bode very well for any future success stories from the African energy economy.
For those of us who care about Africa’s oil and gas industry, it’s time to face facts: We need to find a way to save it ourselves. The African Energy Chamber is calling upon African states and the private sector to fund the African Energy Bank, an institution which is focused on funding African energy projects. The African Petroleum Producers Organization (APPO) and the African Export-Import Bank (Afreximbank) have paved the way. The idea is to create funding sources for all types of African energy — from oil and gas exploration to solar and hydrogen operations — so that projects will not be dependent on foreign support.
We can do this, and we must. Too much is at stake. We can’t afford not to capitalize on recent discoveries such as the light oil found offshore Angola, the oil in Namibia’s Orange Basin, the shale gas in South Africa’s Karoo Basin, or the oil and natural gas off the coast of Côte d’Ivoire. Those are only a few of the important discoveries that occurred recently, and each represents critical opportunities for everyday Africans.
You may be wondering if African energy banks are a realistic goal. How can a continent that is struggling to bring many of its people out of poverty raise capital for energy projects? I believe it can be done. To begin with, African governments can set aside a percentage of their oil and gas revenues for new project funding. In its report, Africa Energy Outlook 2021, Rystad Energy projected that African governments’ earnings from royalties, profit oil, and other taxes in 2021 would reach USD 100 billion. Even 1% of that amount would produce USD 1 billion dollars.
We can also raise capital by investing African pension funds in African energy projects. According to Cape Town-based investment firm, RisCura, local pension funds collectively manage around USD 450 billion of assets in sub-Saharan Africa, and they are actively looking for new places to invest. Why not encourage them to add oil, gas, and renewables projects to their list? Investing pensions in the energy sector is hardly a new practice. Some of America’s largest pension funds are invested in fossil fuel producers, and an increasing amount of pension funds around the globe are investing in green energy projects.
Our options for raising capital don’t end there. We should also seek the support of wealthy Africans who want to invest in a better African future. As of December 2023, total private wealth in Africa totaled approximately USD 2.3 trillion. That’s not even including the African diaspora.
In May 2022, Afreximbank signed an agreement with APPO on the joint establishment of a special multi-lateral financial institution (MFI) – the African Energy Bank – to provide support for the shift away from fossil fuels. The agreement calls for APPO’s member states to provide equity for the new institution and serve as its founding members, with Afreximbank acting as co-investor and providing organizational support.
The new bank will be able to reach more countries than either APPO or Afreximbank could do on their own, as their rosters are not identical: APPO has 15 member states, while Afreximbank has 51 and there is a significant amount of overlap, as Algeria and Libya are the only APPO members that are not also Afreximbank members. But the point remains that if the two institutions join forces, their combined efforts will go further.
Professor Benedict Oramah, the President of Afreximbank, explained it as follows in May 2022: “For us at Afreximbank, supporting the emergence of [the Africa Energy Bank] will enable a more efficient and predictable capital allocation between fossil fuels and renewables. It will also free human and other resources at Afreximbank that will make it possible to support its member countries more effectively in the transition to cleaner fuels.”
Not only do we have pathways for raising capital, we also have an example of the kind of banks Africa needs to finance its own energy projects, one that goes back decades. I’m talking about Afreximbank. In 1993, African governments worked with public and private investors to create a bank that would finance, promote, and expand intra- and inter-African trade. They succeeded. In 2020, Afreximbank received the Africa-America Institute’s (AAI’s) Institutional Institution of Excellence Award for its commitment to the creation and implementation of the African Continental Free Trade Agreement and its ongoing dedication to investing in education. AAI noted that between 2015 and 2019 alone, Afrieximbank disbursed more than $30 billion in support of African trade, including more than $15 billion for the financing and promotion of intra-Africa trade.
I say, let’s build on Afreximbank’s model. And not only that, let’s cultivate a pool of investors who recognize and appreciate the importance of oil and gas to Africa. Capital from foreign countries and companies will always be welcome — as long as it isn’t predicated on phasing out fossil fuels on their timeline. If they’re pushing a rush to renewables, they’re not going to be part of our solution.
With the support of one or more African energy banks, local oil and gas companies will have the financing necessary to acquire assets. They’ll have the financing to build crude and gas pipelines across Africa and to facilitate the use of natural gas (including LNG) to power Africa, minimizing energy poverty and driving industrialization.
And African states and entrepreneurs will be able to finance the development of renewable energy operations, particularly blue, green, and grey hydrogen operations that create additional opportunities for Africans. Africa already has emerging green hydrogen operations in Mali, Namibia, Niger, and South Africa, and with the proper funding, could become a major green hydrogen exporter.
The AEC will support the energy bank initiative and work to bring potential participants together. Creating our own institutions to finance energy projects will send a clear signal to the marketplace that Africans are seeking to become leaders in scaling up private capital. It will show that we are advancing natural gas development and infrastructure while supporting low-carbon investments.
With the financing in place, not only will African companies be able to produce oil and gas, but they will also support local community development, develop green energy markets, and create jobs.
For many African countries, the oil and gas industry represents our best shot at giving millions of Africans the kind of jobs, living standards, and stability that developed countries have enjoyed for well over a century. We must hold fast to these goals and do what it takes to achieve them.
To quote Joel Barker in The Business of Paradigms: “It’s so easy to say no to a new idea. Afterall new ideas cause change, they disrupt the status quo. They take people out of their comfort zones and create uncertainty.. plus it is less work to do things the way we have always done it…. less work, maybe. Costly, definitely”
New Ideas are resisted from greasy rig floors in the Niger Delta Swamps to cushy conference rooms in regulator’s offices in Abuja; each with very prohibitive cost of inaction.
Yet it’s business as usual in Nigeria’s oil industry, despite the current economic realities providing impetus for a radical transformation of its cost base. Pulling the ailing economy from the brink calls for a radical improvement in efficiency within its mainstay industry. Dwindling daily production and significantly reduced foreign exchange earnings, and foreign reserves, establishes the urgency to drive down unit cost per barrel of oil produced.
Simply stated, Today’s ‘Good’ is tomorrow’s ‘Not good enough’ and what sets us apart today will be the baseline tomorrow. The future belongs to those who act with urgency and foresight.
A huge, yet untapped opportunity
Successful upstream operations are underpinned by the ability to balance the trio of cost-schedule- production and maximize NPV i.e. produce the most barrels in the quickest manner possible at the cheapest mean cost across a portfolio of assets.
Incremental improvement in well delivery (drilling & completion) efficiency in the US had characterized the shale oil boom which effectively began in 2007. Efficiency gains cut well costs by a third and reduced cost per barrel by 75% in the decade between 2007 and 2017. In effect, America became an oil and gas power house within this period, doubled US Shale production and tripled total daily oil output.
In Nigeria, the oil and gas industry is the largest revenue contributor to the Nigerian economy, but production has declined by 40% from 2010 to date. Declining oil production presents major revenue challenges and precipitates chronic macroeconomic crisis in the short to medium term.
“Reducing unit production costs by driving down well delivery costs presents an untapped opportunity to increase government earnings & reduce its fiscal deficit “
Being the most complex, costly and highly specialized upstream development activity which easily accounts for up to 60% of oilfield development CAPEX,
Drilling presents a unique opportunity to reduce the cost of oil production.
For this reason, in the early eighties, Drilling Engineers and other personnel operating in the UK North Sea recognized the need to learn from each other and compare performances across each others’ drilling operations. This led to the formation of the drilling performance review (DPR) in 1989, a drilling benchmarking club. Majority of International operators who are value driven continue to subscribe to the DPR till this day for the inherent benefit to their global operations and enterprise financial performance.
In general, up to 60% of drilling time goes to Non-productive time (NPT) and inefficiencies which is known in drilling parlance as invisible lost time (ILT). The cost of ILTs, being an invisible factor, to the Nigerian oil industry is in the order of billions of dollars overspent annually.
Improving drilling performance therefore is an enabler to reducing cost of oil production. Lower drilling costs stimulates more drilling activities which in turn increases production and reduces unit production costs.
You can’t improve what you don’t measure
Drilling performance in Nigeria is laden with tremendous inefficiencies. An indicative benchmark of an average Nigerian, and similar North American well reveals significant underperformance in the Nigerian well as measured by days to drill a 10,000 feet well. A 10,000 feet well routinely delivered in 10 days in the US / Canada could take as long as 85 days in Nigeria. This disparity is surmised to be causative of the consistently high well delivery cost in Nigeria. Disproportionately long well durations delays time to market (deferred production), reduces project NPV – costly wells reduces the number of profitable opportunities which in turn reduces rig activities and associated demand for services.
By top down estimates, the industry spends circa $11.4Billion to produce 1.25Million barrels daily and approximately $6Billion in drilling wells. A 30% performance gap between the authorized expenditure (budget) and actual costs as gleaned from an analysis of Nigerian wells represents a $1.8Billion a year opportunity.
The relentless pursuit of excellence in well delivery begins with establishing key indicators which must be tracked with rigour and provides indication of drilling performance and efficiency trends.
An excellent drilling efficiency metric commonly tracked is the spend ($) per reservoir foot of hole. Looking at this metric in US land operations from 2006 to date shows the cost of a foot of exposed reservoir falling by 75% in over a decade when considering what was paid to the contract driller. Similarly, the directional driller cost per exposed reservoir foot fell from $45 to $35, a decrease of 25%.
In addition to the reduced cost per barrel, other implications of drilling efficiency gains break down as follows:
The price of contracting a rig in 2006 is now the price of four rigs in 2023 i.e four rigs can be operating today for what it cost 16 years ago.
Four rigs drilling means 300 oilfield workers employed (instead of 75 on one rig). This is direct labour. We know how many mouths get fed when 300 workers are employed instead of 75.
Four rigs working means higher rig count overall. Higher rig count means more services contracted e.g. wireline, mudlogging, casing and cementing crews etc. This means 4X the number of casing running crews, mudlogging crews, wireline crews etc needed (as well as the number of mouths each of them feed). Simply means higher activity and spend in the sector.
Four rigs working means more reservoir exposure, higher production, higher probability of new discoveries which increases reserves, and translates to higher revenues for the country in form of (a) increased government share of oil production and (b) increased taxes and royalties accruing to the state.
Where there is a will, there is a way
Investments in the Nigerian oil and gas sector declined by 70% between 2017 and 2021 closely correlating with the contracted output. Nigeria could only attract $3Billion in investments (approximately 5% of the total investment into the sector in Africa) in the five years between 2017 and 2022 despite having 38% of the continent’s total hydrocarbon reserves. As the government pushes for more transfer of resource ownership to locals via organized acreage farmouts and International Oil Company (IOC) divestments, the uncompetitiveness of Nigeria’s oil industry’s remains at its pinnacle.
For the sake of the industry some of us love for being the source of our livelihood, the hundreds of thousands of mouths it feeds directly and the hundreds of millions of Nigerians its long-term sustainability impacts, pulling the industry (and by extension the economy) back from the brink is not optional, but a matter of feral urgency and rest squarely with the industry regulatory agencies.
Tepid as the implementation has been, the Petroleum Industry Act emboldens the Nigerian Upstream Petroleum Regulatory Commission (NUPRC) to drive cost and capital efficiency in oil industry upstream operations. A total transmutation of the operating philosophy of the NUPRC from that of its predecessor agency- DPR (not the business as usual approach) will be required to unlock a $2Billion a year opportunity in these critical times as the oil industry continues hemorrhaging unabated.
Local operators and IOCs continue to battle a worsening capital drought and industry contraction. Stakeholders who will be convening in the nation’s capital on the 26th and 27th of June at the NUPRC organized industry consultative workshop will be seeking guidance from their host, curious to learn what fresh ideas will be unveiled that will provoke the cataclysmic effect to stem the existential crisis confronting the sector.
The current realities provides impetus to drive a deliberate drilling cost reduction. Effort should be made to reduce well delivery costs across all joint venture, sole risk and production sharing contract (PSC) operations for the lifeline it offers to an industry literally on life support.
Operators deserve insights and answers to these critical questions; which can be found in gigabytes of PDFs and thousands of hard copy folders sitting in dusty cabinets in NUPRC’s warehouses.
Who are the Best in Class Nigerian Operators across key performance metrics – (drilling efficiency (speed) and cost ($)) in each terrain?
What are the Performance Gaps between their own wells and the best in class wells?
What are the causative factors for the discrepancies in performance (gap) between their wells and the best in class wells?
What can they do to close the gaps and pull up their performance towards the best in class?
While they scratch their heads looking for answers, we recommend the regulator institute performance improvement programs that leverage the latest technologies and an abundance of human capital to drive the systematic optimization of drilling programs and commercial sustainability across the breadth of Nigerian drilling operations. This will serve as an economic stimulus by lowering all key metrics including unit operating as well as finding and development costs. It will improve the fiscal breakeven price of oil.
There is no standing still. We are either growing or dying and since we are not growing, as established by all indices, we challenge the custodians of this atrophying industry to lead, follow or get out of the way.
The author, who is also President & Co-Founder of Manup and a director at Vobiss Gridworx,has, in his 27 years of experience in the oil and gas industry, served as Country Manager, Nigeria at GE Oilfield Technology, Drilling Reliability Consultant at GE Energy Services, Drilling Performance Consultant / Coach at BP, Shell International, ConocoPhillips, Field Engineer / Field Applications Engineer Onshore and offshore drilling operations-related positions with Halliburton, Baker Hughes, Chevron. He contributes articles from time to time to Africa Oil+Gas Report
In 10 unbroken years of active participation in the Practical Nigerian Content (PNC) Forum, organised by the Nigerian Content Development and Monitoring Board (NCDMB), the leading lights of Nigeria’s oil and gas industry have signified that local content has something of a creedal force in their ranks. In-country value addition through enhanced local capacities and capabilities remains the unchanging focus – what they must pursue and actualise to enhance the country’s economic performance and development.
The apostolic zeal of the industry stakeholders, as they assemble in their hundreds from year to year to appraise the state of the industry and to determine what way(s) to maximise opportunities along lines spelt out in the Nigerian Oil and Gas Industry Content Development Act, 2010, is most remarkable. In the spirit of collaboration and stakeholder engagement, issues of topical importance are ever adopted as themes for presentation and deliberations in different editions of the Forum.
Innovations at NCDMB and results
NCDMB and stakeholders have been thus guided in subsequent actions by way of interventions, policies and compliance. The Board gets more and more innovative as challenges emerge through workshops and exhibitions. Concepts and undertakings such as Nigerian Oil and Gas Technology (NOGTECH) Hackathon, Nigerian Oil and Gas Opportunity Fair (NOGOF), Nigerian Oil and Gas Industry Content Joint Qualification System (NOGIC JQS), and research and development funding, were in response to felt need and have bolstered the sector.
“Key Highlights of this year’s PNC Forum from December 5-8, 2022
Harnessing Nigerian content opportunities for indigenous companies in Nigeria’s “Decade of Gas”
What opportunities have been revealed by the Seven Ministerial Regulations for increasing Nigerian content compliance?
Outlining Nigeria’s future energy mix and Nigerian content objectives over the next 30 years
What are the enablers required to bridge the capacity gap for improved local content implementation with a growing focus on gas?
How can indigenous companies attract required funding?
What efforts are in place to explore Nigerian content opportunities in AfCTA?”
Together, the industry regulator and the oil and gas companies – upstream, midstream and downstream – have moved mountains, radically altering the status and image of Nigeria as rent-seeker and placing her in a respectable position as resource-endowed and with appropriate technological capabilities to efficiently exploit and utilise hydrocarbons.
What difference NCDMB has made
In twelve (12) years of implementation of the NOGICD Act, 2010, Nigeria, through the Board’s well targeted strategic interventions, has developed the widest range of competencies and facilities for engineering, procurement, fabrication, and a lot else, and thus upped in-country value retention from less than five (5) per cent in 2010 to forty six (46) per cent in the first quarter of 2022. And seventy (70) per cent is in focus as we march towards the 2027 terminal date of the Board’s Nigerian Content 10-Year Strategic Road Map.
Today the world-class fabrication yards and pipe mills have turned Nigeria into a hub for related businesses in the Gulf of Guinea, just as the country’s service companies now operate as international servicing companies in different African countries. That’s the success story of the NCDMB made possible by far-sighted and resourceful leadership that carries all stakeholders along, unhesitatingly intervening in material terms to bolster operational capabilities of companies. This year’s edition of the PNC Forum, scheduled for December 5-8, 2022, is another platform with great possibilities for participants and the wider society.
What to expect from PNC 2022
Face to face with potential clients and investors, participants in PNC Forum 2022 in Uyo, Akwa Ibom State, will deliberate on the theme, “Deepening Nigerian Content Opportunities in the Decade of Gas.” Key topics, as highlighted at the PNC dedicated website are:
Harnessing Nigerian content opportunities for indigenous companies in Nigeria’s “Decade of Gas”
What opportunities have been revealed by the Seven Ministerial Regulations for increasing Nigerian content compliance
Outlining Nigeria’s future energy mix and Nigerian content objectives over the next 30 years
What are the enablers required to bridge the capacity gap for improved local content implementation with a growing focus on gas?
How can indigenous companies attract required funding?
What efforts are in place to explore Nigerian content opportunities in AfCTA?
Conclusion
In the broadest terms the PNC Forum is billed “to help shape the Nigerian Content Agenda for the next twelve months.” Industry regulator and all stakeholders would hopefully be on the same page all the way, directing energies and resources in a manner that would best promote corporate success as well as national development. But economic spin-offs never fail, particularly for a host city and state, in this case, Uyo and Akwa Ibom, whose hospitality industry is already bubbling in anticipation of several hundreds of guests in early December.
PNC Forum 2022 is the place to be for fresh ideas and strategies in the nation’s quest for economic development through effective and efficient management of her abundant hydrocarbon resources, especially gas as the transition fuel for Nigeria.
Esueme Dan Kikile ESQ, is the Manager, Corporate Communications, NCDMB
BP: A Takeover prey?
The chief obsession of Wael Sewan, Shell CEO since 2023, is to drive up the company’s stock price. His hydrocarbon narrative is mimicking that of Chevron and ExxonMobil.
The heart of the matter for Shell is that the company has continued to argue that this is a private( company) matter, not one involving the the Common Good.
The Joker in the Deck
ENI’s strong presence in North Africa—Algeria, Egypt, and Libya—could in the coming months become one of Europe’s substitute providers of natural gas. This region currently produces 648,000barrels of oil equivalent per day (BOEPD). The company operates in the frontier areas seldom mentioned in the daily news media.
TOTALEnergies’ energy production in the period 2020 -2030 “will grow by one third, roughly from 3MMBOEPD to 4MMBOEPD, half from LNG, half from electricity, mainly from renewables”, according to Patrick Pouyanné, the company’s Chairman and CEO.
Chevron: Stay vigilant
ExxonMobil: Don’t count your chickens…
On May 31, 2023 Equinor announced that it would delay by at least three years its Bay du Nord project in the deepwater Flemish Pass basin 500 km off the coast of Newfoundland, Canada. Why? Because the project would cost an estimated $12Billion. Only $12Billion you might think. Is that a reason for not developing this project at a time when oil and gas companies are showing record earnings? According to Equinor technical and financial challenges are the main reasons for the delay.
Yet Equinor’s reasoning is not directly related to the Bay du Nord capital costs. By 2030 the company is pledged to spending half of its capex on renewable energy. In 2024 its capital budget was $13Billion. On this basis Equinor’s capital budget for future oil and gas projects is rather restrained.
Choosing a Future Home
