All articles in the Gas Monetization Section:

The Angola LNG Limited (ALNG) plant, located in the municipality of Soyo, Zaire province, in conjunction with the maintenance campaigns of the Sanha Complex and the Sanha FPSO, in Area B of the Cabinda offshore, will carry out a Scheduled General Shutdown, within the scope of its periodic extended maintenance plan (TAR).

The shutdown is expected to last 32 days, starting Wednesday, July 8, 2026.

“The intervention is part of regular maintenance and facility integrity practices, aiming to ensure the safe continuity of ALNG’s operations, preserving equipment reliability and raising the performance and efficiency levels of the LNG plant”, the National Agency for Petroleum, Gas and Biofuels (ANPG) says in a release.

“During this period, the ALNG plant will experience a complete suspension of liquefied natural gas and related derivative production, which will reduce monthly production and loading by approximately 80%. Resumption will occur in a phased and safe manner after the completion of the works.

“The impact on oil production resulting from the shutdown of the Sanha Complex and Sanha FPSO is estimated at 48,996Barrels of Oil Per Day (BOPD).

“Regarding ALNG’s contractual commitments in the international market, ALNG has been working to find appropriate solutions to ensure the timely fulfillment of its contractual obligations and, consequently, the collection of revenue for the Angolan State”, the regulator explains.

“The National Concessionaire will continue to work to ensure that activities are carried out with technical rigour and in strict compliance with safety, health, environmental and operational integrity standards”.

Global demand for liquefied natural gas (LNG) is expected to increase to nearly 700Million tonnes a year (700MMTPA) by 2050, an increase of around 65% from 2025 levels, according to Shell’s LNG Outlook 2026.

These numbers are based on expectations that “countries continue to prioritise flexible and reliable energy security offered by gas and LNG”, the outlook, in its 10^th year, notes.

A total of 422Million tonnes of LNG were traded in 2025 and this was expected to increase significantly in 2026. However, severe disruption to shipping through the Strait of Hormuz has shut in around one fifth of the world’s monthly LNG supply since the conflict started, pushing up prices on the spot market and adversely affecting some countries in Asia.

“With long-term supply agreements accounting for around two thirds of total LNG trade, the average price that buyers paid for LNG in May was around $11-12 per MMBtu, compared to $7-11 in January before the conflict began”.

“The ramp up of new liquefaction facilities in North America, improved performance at existing plants and slower Asian imports of LNG have partially offset the impact of reduced supply from the Middle East”, the outlook explains. As a result, total LNG trade in 2026 could be similar to last year if shipping through the Strait of Hormuz returns to normal this summer, before returning to growth in 2027.

“The conflict created a system-wide shock with disruption cascading across all segments of the economy, but the LNG industry has proved resilient and able to adapt to changing market conditions,” said Cederic Cremers, President of Integrated Gas at Shell. “While more investment in both supply and demand infrastructure is needed, the long-term outlook remains strong and LNG will continue to be a stabilising force in the global energy system.”

ABOUT 180MILLION TONNES OF ANNUAL NEW SUPPLY is forecast in the outlook to enter the market by 2030, improving the availability and affordability of gas and opening up demand in new markets.

However, the ability to benefit from new supply will depend on the availability of infrastructure in importing countries, including regasification capacity and pipeline connectivity, especially in South and Southeast Asia.

Forecasts show that those regions will account for around 40% of global LNG imports by 2050 to meet rapidly growing demand for energy with lower emissions than coal. In more mature Asian markets such as Japan, data centres are emerging as a new source of power demand.

The report declares that emerging segments of demand are also growing rapidly. “According to forecasts, LNG bunkering will grow seven-fold to 27Million tonnes by 2035, more than the amount of LNG imported by India in 2025.

“LNG will continue to have a vital role to deliver energy security to Europe, to balance intermittent renewables as domestic gas production declines”, the report contends. “To meet the growing demand, significant additional investment will be needed in new LNG liquefaction plants through the 2030s and 2040s, with around 200Mllion tonnes a year of new supply needed, in addition to projects already under construction”.

A more resilient market-Although spot prices of LNG in Asia increased to more than $20 per Million British thermal units (MMBtu) at the peak of the Middle East crisis, they remained significantly lower than in 2022 when gas supplies were disrupted following the Russian invasion of Ukraine, reflecting the greater resilience of the LNG market now.

“With long-term supply agreements accounting for around two thirds of total LNG trade, the average price that buyers paid for LNG in May was around $11-12 per MMBtu, compared to $7-11 in January before the conflict began”.

Egypt is expecting an extra 200Million standard cubic feet of gas per day (MMscf/d) via pipeline from Israel by the end of June 2026.

The new 46 kilometre Ashdod-Ashkelon pipeline, operated by Israel Natural Gas Lines (INGL), is an additional stretch of transportation facility from offshore Israel, to ease bottlenecks in that country’s southern gas pipeline network and increase the capacity of the offshore East Mediterranean Gas (EMG) pipeline from around 650MMscf/d to 850MMscf/d.

Still another 400MMscf/d is supplied through the more circuitous Arab Gas Pipeline (AGP) that is also used to supply Jordan with around 300MMscf/d. The AGP route is also being expanded. Completion of compressors at Rehab in northern Jordan in the second half of 2026 will increase AGP flows by around 400MMscf/d.

All of these mean that overall Israeli-Egypt export through both the EMG and the AGP systems should reach as high as 1.3Billion cubic feet per day (1.3Bscf/d), in  time for the peak gas demand season.

ExxonMobil is looking to exploit a significant volume of gas when it develops its Owowo and Bosi fields, whose sanctions are both a heavy work in progress.

“Part of Owowo’s delivery is a gas pipeline”, says Jagir Baxi, Lead Country Manager of ExxonMobil Nigeria and its affiliates. “If we are successful to FID (Final Investment Decision), it will be gas to shore. But Bosi in its complexity is another step forward from where Owowo is”.

He said the company would “like to be able to get to 100Million cubic feet of gas per day also from Owowo.

“So there is gas there. It has more gas compared to Usan or Erha, so it is valuable that we try and monetize it together with doing the oil development”.

Baxi said the Bosi accumulation is a much more oil and gas development than Owowo, although it is farther down the years from development than Owowo. “It means that the nature of the investment infrastructure is fundamentally different and more involved. Bosi will need a pathway for gas handling from day one”.

Baxi was fielding questions by three journalists from as many publications in his office, located in Ikoyi, on the edge of the Lagos Lagoon.

ExxonMobil’s plan for Usan field redevelopment has been widely published in the media. Baxi has also been quoted as describing the Owowo project as the tip of the company’s ‘growth spear’. The discovery of the Owowo field, in 600 metres of water, was announced in October 2016. A development drilling campaign, planned to commence by January 2020, was kicked further down the road when the Nigerian government passed a new law: the Deep Offshore and Inland Basin Production Sharing Contract (PSC) Amendment Act (November 2019), which the project’s partners deemed to have weakened the project’s commerciality. Now, 10 years after the announcement of its discovery Owowo is  very close to happening…

Excerpts from the interview by AKPELU PAUL KELECHI 

One of the most consequential things about the proposed Owowo field development is that it doesn’t come with a new Floating Production Storage & Offloading (FPSO) facility?

The lead concept is a tie-in and it’s because it is within the technical boundary of being able to do a tie-back. It’s a step out, but it’s within a global experience envelope. Usan is available, it has capacity. It is largely the kind of FPSO that Owowo needs to develop.

Conceptually, a new FPSO at Owowo would come with more capital expenditure CAPEX. And more CAPEX means the investor group will seek to recover their capital through the production of Owowo, which would mean fewer barrels for the state, either in revenues or taxes or profit sharing to government. So when we look at Owowo, we also use this phrase “competitive deepwater oil for development,” meaning it achieves a capital basis that is the most optimal, which is a tie-back. An investment that is higher CAPEX for whatever reason, in a production sharing contract environment, the investors will recover that because the capital must get recovered. That’s not necessarily good; a lower CAPEX equals more of the production barrels available to share. Investors will share some of that, but so will many others. So I don’t want to be lazy about our capital investments. It has to be the right capital efficient development for Owowo. Usan provides that opportunity and the partners in Owowo are the same partners in Usan, so there is a natural environment to capitalize on what’s available at Usan.  

Jagir Baxi: “We want to mature Bosi in this 5-year horizon. I cannot tell you today where that notable FID might occur, but we will invest to mature it as fast as we can”

If it is this easy to take advantage of the Usan infrastructure, why is it taking so long?

I don’t want to leave you with the impression that this is that easy. It is at the very edge of global experience for deep water development.  So it is challenging in that sense and it’s challenging in terms of going from the idea of Owowo to Usan and then to translate that to an engineered solution that we can bank. We, meaning all of us, the investor group, the government, and the stakeholders can bank for what is hopefully more than two decades. 

The journey of Owowo to the point where FID is the visible announcement, goes back at least two years. We have been on the journey to utilize the data of Owowo exploration and appraisal with reprocessing of that data and seismic with the most modern capability that exists in industry today. We did that through 2021 and 2022. 

It underpinned the field development plan (FDP) update that we submitted to Nigerian Upstream Regulatory Commission (NUPRC) and that they approved. From there, we have been working and inspired by this administration’s enabling announcements through 2024. I’m referring specifically to Presidential Executive Directives 40, 41, 42, on national content and contract. 

The journey since the FDP for Owowo was approved, has been to take each one of those directives, translate them to project specific outcomes. So for example, national content directive translates to an Owowo specific national content strategy. The directive on contracting and efficient cycle time of contract translates to an Owowo contracting strategy. And the incentive structure translates to an Owowo incentive analysis. That’s been the journey of our work since our divestment concluded.

So it’s 15 or 16 months. That’s the kind of time horizon it’s taking.

15 or 16 months since our divestment because we have been public about the fact that we needed the shallow water and deep water separation to occur so that we could bring our best attention to the deep water and we have. Think about Owowo at the $7 to $8Billion range plus. I come back to Usan at $1Billion, Bonga North at $5Billion. We’re now in the $8Billion plus range as a measure of the complexity of step up. But in order to make an announcement that we can all stand behind, the maturity of all the thinking that has to occur is in flight. 

We hope to be able to point to the formative announcements of formative agreements like long lead procurement, like establishing shore based capability to support that project. These will be the visible early signals before FID. just like we did with Usan. So there’s a lot that occurs today that are within the stakeholder groups enabling the presidential inspiration. Each of those will reach a milestone that will underpin more visible commitments. That’s the journey we’re on. So when we make an FID announcement, we do it with the partners clearly aligned with us, the stakeholders clearly aligned. It’s a signal to go.

We’re not interested in making an announcement that looks like we want to go. We want certainty, we’ll work for certainty, and we’ll commit to what we say we will do as operator and we’ll do it with them. That’s the reputation we want to continue with. 

 One of the directives that were issued in 2024 was the incentive structure. And it has enabled Owowo to be more globally competitive. But ExxonMobil is not looking for hand-outs. What we want is to be able to bring our best which is highly competitive cost and schedule because that will create more value of the resource for more stakeholders, not just for the investor group.

The incentives that the president has codified, and is continuing to support, brings another level of improved ability to invest. It takes all three of those and I’m not interested in taking advantage of just one. I want to bring our best as an investor by capitalizing on contracting and national content along with incentives. We want to do our best on capital to project to cost efficiency. Then we will all win. 

“The incentive structure accounts for gas explicitly today, that hasn’t been the case before.
The nature of Owowo and Bosi requires top-tier global contracting partners. Those partners are more interested to return and invest in Nigeria today.”

What’s the current cost of production per barrel for these three assets? What’s the global benchmark? 

There’s no single number that I can point you to. Life cycle matters in these deepwater developments. Early in the life of the developments, cost of production is naturally low but the investors have put large capital up front. As assets age, technology becomes obsolete, a greater amount of maintenance of floating structures, subsea structures have to happen, cost tends to go through waves. Bonga and Erha are now in the window where the industry asks the question, how do I extend the life of this FPSO for another cycle? 20 to 25 years, I want another cycle. So there’s another wave of investment and cost will come with that. What I can say is that Nigeria’s deep water operations that we participate in are able to be competitive. There is an inherent extra cost burden in Nigeria, to be transparent. It does exist. It’s also one of the reasons why one of the presidential orders was incentivizing cost performance in order to achieve greater return for the industry. That signals an intent to help pull cost down.

In terms of Nigeria being a developing country environment in which large capital investments have to occur, the fact that there is a cost delta to other climates, other environments, is not itself an issue. I don’t want you to leave with a view that I see that as an issue. It’s not.

Bringing the very best of global capability that ExxonMobil can bring is also about bringing our best capability to bring costs down.

Given the investment chronology, your “tip of the spear” should be the ongoing Usan development, not Owowo which is farther down the line

We use this phrase for Owowo because it is a true green field development. We use the concept of tip of the spear because there are more developments that are following it. Our own next operated opportunity is Bosi. Then we are heavily invested and supportive of our partner development in Bonga or Bonga Southwest because we have a 20% share in Bonga and that’s of interest for us. In a sequence of the spear piercing the next horizon of deep water development, we see Owowo as the one we can bring. We see Bosi as the second one that we can bring, and we want to support the success of Bonga Southwest.

So Bosi is a higher priority for you than Bonga Southwest?  

No, it’s better to look at it in terms of technical maturity and readiness.  Owowo and Bonga Southwest are more similar in readiness terms. Bosi is less ready in terms of its overall technical maturity. The reason for that is important to understand.

Unlike Bonga and Owowo, Bosi is a much more oil and gas development, not a primarily oil development. It means that the nature of the investment infrastructure is fundamentally different and more involved. Today Erha doesn’t have and doesn’t need a pathway for gas handling. But Bosi will, from day one.  

Owowo scope will bring gas outlet for Owowo and Usan. So part of Owowo’s delivery is a gas pipeline. If we are successful to FID, it will be gas to shore. But Bosi in its complexity is now from where Owowo is another step forward.

It is really bigger than Owowo, multiple times bigger in terms of the span of that reservoir resource. In the geology, there are more geological areas for Bosi than Owowo. And its proximity to Erha…

When you say there are more geological reservoirs… 

Yes there are more reservoirs where the oil and gas is accumulated, there are more reservoirs. But in terms of a net basis, Bosi is bigger. Bosi is bigger than Owowo, but it has more gas than it has oil.

But you’ve never done any gas project in the country at all

Not in the deep water. We have in our shallow water days.

But even that was a struggle. You really haven’t been keen on the gas business in Nigeria.

No, and the conditions have always been more challenging. And in the deep water, it is challenging.

Is that going to slow down Bosi? Is that why Bosi has been on the back burner for 25 years?

It has struggled from a number of areas. Gas and gas development value chain is one of those. But we can see a path that’s a bit more clear today. The incentive structure accounts for gas explicitly today, that hasn’t been the case before.

The nature of Owowo and Bosi requires top-tier global contracting partners. Those partners are more interested to return and invest in Nigeria today. ExxonMobil will not be able to make Bosi a reality without that added capacity.

And then the ability to utilize the contracting and national content directives today is more enabling than it’s been historically. So we can see a clear path for Bosi. The technical maturity is not as ready as Bonga Southwest or Owowo, so it naturally will come behind. But it needs more work on the gas side than the other two have needed so far. There’s a journey of development for Bosi that is going to take the kind of time horizon we’ve talked about here.

Does this means that Bosi is not going to happen for another 7 or 8 years?

No, we are motivated to make it happen sooner than that. But in terms of major announcements, there is a journey still to go. The same journey we’ve talked about on the others, we still have to walk that journey together with our partners. So your questions started with tip of the spear. This is what I would like you to take away: there are three large important developments that we are a part of to which we are leading.

And we want to create the space and certainty that contracting can lift all three. National content can lift all three. The incentive structures can lift all three. Bosi has a specific need which is how do we maximally develop the gas at a scale that is not being done in deep water yet in Nigeria?  

An artist’s rendering of the two Esso Nigeria’s FPSOs

What’s ExxonMobil’s  five-year outlook in Nigeria?. Both Usan and Erha are roughly doing around 102,000 barrels now. And with this Usan infill, that will roughly go to 130,000. Are you seeing a possibility of 250,000 in the next 5 years? If indeed Owowo takes FID this year, which is unlikely… 

You’re absolutely right about the numbers. The Usan and Erha operations today accumulate a little over 100,000 barrels.

We also want to support about the same amount that Bonga is producing because that’s important for us as a shareholder and for the country. Usan’s infill programme should unlock, we expect somewhere up to 40,000 barrels. That is almost a doubling of flowing capacity in Usan. 

And for the Erha infill programme, we estimate somewhere around 20,000 barrels with what we can see today. We hope to be able to grow that. And then for Owowo, our view is that it can produce over 100,000 barrels at peak. So to your question about can we see a future of 250,000 or 200,000 barrels per day at peak? Yes, it is definitely a possibility as we put these investment pieces together. 

I mentioned that the Owowo project comes with an expectation of a gas pipeline that can unlock gas from Owowo and Usan to shore. So 250,000 barrels liquids, we’d like to be able to get to 100Million cubic feet of gas per day also from Owowo underpinned by Owowo. So the horizon has that kind of possibility.  

It has more gas compared to Usan or Erha, so it is valuable that we try and monetize it together with doing the oil development. So we are incentivized with the partner group to bring gas from the hub of Erha and Owowo to shore. 

That’s the development path that gets us to 200K plus and some valuable amount of gas. In a five year horizon. Beyond that, we want to mature Bosi in this five-year horizon. I cannot tell you today where that notable FID might occur, but we will invest to mature it as fast as we can.

“In terms of Nigeria being a developing country environment in which large capital investments have to occur, the fact that there is a cost delta to other climates, other environments, is not itself an issue”

Can we have clarity on partner alignment on Bonga Southwest, because the narrative out there was that ExxonMobil was the stumbling block. That you have now aligned and we’re looking at Bonga Southwest taking FID in, say, August 2026?

Let me talk a little bit about Bonga Southwest because I appreciate the narrative that exists. Allow me to at least express our partner view on Bonga Southwest. There’s definitely a way one can describe it which is ExxonMobil is blocking.

I would say to you, blocking looks like this. That’s not our posture on Bonga. Our posture on Bonga Southwest has been to help and support the operator and the partners to do the necessary work to improve its readiness for FID. Part of what’s being needed is an enabling fiscal structure that now exists.

But also part of what’s being needed is the maturity of the resource understanding and the maturity of the project-specific application of national content and contracting strategy. So the perception is blocking, but I would offer to you that we have tried to express first of all what can make Bonga Southwest compete in our capital portfolio. That’s a partner view. But in doing that, it also makes the project more capitally competitive. So that when we do invest, we are not simply getting barrels recovering extra CAPEX, which otherwise would be shared across the shareholders. That important factor is often lost in the top line narrative that somehow our partners want. 

It’s an expression of what can make that investment capitally competitive and when it is capitally competitive, it’s also unlocking the best total value for shareholders. Otherwise, the CAPEX will be high, the schedule will be long, the investors will recover capital; we will recover our capital under a PSC contract. It’s just not fair to the nation that that’s what happens. 

So underlying this is an expression of hey, we should do the work and we should ask our stakeholders to do the work with us to make as big an investment as Bonga Southwest competitive at a global scale. In Nigeria, it may not be the most competitive, but that’s okay. But it needs to be competitive because otherwise the barrels will produce, the dollars will come and it will recover to the investors. It’s just not fair. 

So this is what’s underlying the stance of saying, “Hey, it’s not ready.” We’re not blocking it just because I took my toys and went home. We’re expressing a view that more needs to be done to make it ready. This administration, His Excellency the president and the honourable ministers and other stakeholders today allow for honest discussion like that to be tabled and we can move forward together. That’s the way I would describe it today. It is not just blocking for blocking sake but it is an expression of improving the project and in doing that for the investors, we will do that for everyone.

Nigeria’s state hydrocarbon firm NNPC Limited has reported successful completion of the River Niger Crossing of the 130-kilometre Obiafu-Obrikom-Oben (OB3) Gas Pipeline.

“It’s the crucial “milestone in the expansion of Nigeria’s national gas transmission network”, the company declares in a statement.

The project is being constructed by NNPC Gas Infrastructure Company (NGIC), a wholly owned subsidiary of NNPC Limited.  Construction has so far lasted over 13 years, with the River Niger Crossing taking over six years and becoming the chain that determines the rate of construction.

“The successful crossing unlocks the full potential of the OB3 Pipeline, a strategic infrastructure designed to transport up to 2Billion standard cubic feet of gas per day”, the statement notes. “Executed approximately two kilometres beneath the River Niger riverbed, the technically complex crossing was delivered by the NNPC project team working with PCE Nig. Limited, using advanced horizontal directional drilling (HDD) technology”.

With the crossing, the construction has between five and 10 kilometres pipe-work to reach mechanical completion, after which is the commissioning phase. The River Niger Crossing is an important chokehold, but its resolution does not finalise the OB3 construction.

“The OB3 Pipeline will serve as a backbone gas infrastructure linking the Eastern gas network to the Western network and extending connectivity to the Northern corridor through the AKK Pipeline. In the near term, the successful crossing is expected to unlock over 500Million standard cubic feet of incremental gas supply for the domestic market, supporting power generation, industrial growth, and gas supply to the West African market”, NNPC says.