The African Energy Chamber (AEC), representing industry stakeholders, welcomed the development, emphasizing the importance of stronger intergovernmental and institutional linkages. Increased coordination between Petrosen and NNPC is expected to facilitate knowledge transfer, enhance institutional frameworks and accelerate project execution across upstream, refining and gas commercialization segments. Senegal Nigeria energy ties also aligns with ongoing efforts to operationalize the Africa Energy Bank, with Senegal already contributing capital and positioning itself within the financing structure for future energy projects.

“This is exactly the kind of collaboration Africa needs. When countries like Senegal and Nigeria work together – sharing knowledge, building infrastructure, strengthening NOCs and improving policies – we create an environment where investment can thrive and where Africa can take control of its energy future. Strong partnerships between African nations will be the foundation of energy security, industrialization and economic growth across the continent,” states NJ Ayuk, Executive Chairman, AEC.

Momentum around Senegal Nigeria energy ties comes as both countries scale their oil and gas ambitions. Senegal continues to build on recent production milestones, including operations at the Sangomar oilfield and the Greater Tortue Ahmeyim (GTA) LNG project. Output at Sangomar has stabilized at approximately 100,000 bpd, while GTA has recorded 24 LNG cargo exports between February 2025 and February 2026, alongside 1.6 million barrels of condensate marketed internationally. The country is also advancing the Yakaar-Teranga offshore project and pursuing a $100 million onshore exploration campaign aimed at unlocking new reserves through seismic acquisition and exploratory drilling.

Nigeria, Africa’s largest oil producer, is simultaneously targeting production levels of around 2 million bpd while expanding its refining and gas sectors. A 2025 licensing round offering 50 frontier and one deepwater block is expected to attract $10 billion in investment, complemented by renewed engagement with international oil companies including Chevron, ExxonMobil and Shell. The NNPC is targeting $30 billion in upstream investments by 2030.

On the downstream side, plans are underway to expand the Dangote Refinery’s capacity to 1.4 million bpd, while recent gas flare commercialization initiatives are set to unlock $2 billion in investments. The growing alignment between Senegal and Nigeria reflects a wider continental shift toward cooperative frameworks aimed at strengthening energy security, infrastructure development and long-term market integration.

The primary mechanism by which carbon pricing influences the market is through the “merit order” of power plants. In a traditional competitive market, plants are dispatched based on their short-run marginal costs. Historically, coal and gas were at the front of the queue due to their low fuel costs. However, carbon pricing power generation economics flips this logic. By adding a cost per ton of CO2 emitted, carbon pricing makes high-carbon fuels like coal significantly more expensive to run than lower-carbon natural gas, and both become less competitive compared to zero-marginal-cost renewables. This “fuel switching” is the most immediate impact of carbon pricing, driving a rapid reduction in emissions as the most polluting plants are pushed out of the market by cleaner alternatives. This is not just a temporary shift but a permanent reconfiguration of the electricity supply.

Shifting Investment Strategies and Capital Allocation

Beyond daily operations, the long-term impact of carbon pricing power generation economics is most visible in the realm of low carbon investment. For institutional investors and utilities, the “carbon price signal” is the most critical variable in their long-term financial models. A high and stable carbon price reduces the uncertainty associated with clean energy projects, making them more attractive to capital markets. Conversely, it increases the risk profile of fossil fuel projects, which may face rising costs or even stranded asset status over their 30-year operational life. This shift in capital allocation is the engine of the energy transition policy, as it ensures that the billions of dollars required for new infrastructure are directed toward sustainable technologies rather than legacy systems.

Furthermore, carbon pricing provides a direct financial incentive for the deployment of carbon capture and storage (CCS) and hydrogen technologies. When the cost of emitting a ton of CO2 exceeds the cost of capturing and storing it, CCS becomes an economically rational choice for thermal power operators. This threshold is a key milestone in carbon pricing power generation economics, as it marks the point where “abated” fossil fuels can compete on a level playing field with renewables. The revenue generated from carbon markets is also being increasingly “recycled” by governments to fund research and development in these emerging sectors, creating a virtuous cycle where the polluter pays for the innovation that will ultimately replace them. This is the essence of a well-functioning energy transition policy.

Clean Power Competitiveness and Market Maturity

The evolution of carbon pricing power generation economics is also driving a surge in clean power competitiveness. In many regions, wind and solar are already the cheapest form of new electricity generation even without accounting for carbon. When the carbon price is added to the competition, the gap widens further, making it nearly impossible for new coal or unabated gas plants to compete on a merchant basis. This market maturity is a testament to the power of price signals to drive technological innovation and scale. As the cost of renewables continues to fall and the cost of carbon continues to rise, the economic case for the “all-electric” and “all-green” grid becomes increasingly overwhelming, reshaping the very foundations of the utility business model.

However, the impact of carbon pricing is not uniform across the globe. The fragmentation of carbon markets where some regions have high prices and others have none introduces the risk of “carbon leakage,” where energy-intensive industries move to jurisdictions with weaker regulations. To combat this, the introduction of carbon border adjustment mechanisms (CBAM) is becoming a vital component of carbon pricing power generation economics. By placing a carbon-related tariff on imported electricity and goods, these policies ensure that local generators are not penalized for their decarbonisation efforts. This creates a more level playing field and encourages a global convergence toward high carbon prices, ensuring that clean power competitiveness is protected in an increasingly globalized energy market.

The Role of Emissions Trading Systems (ETS)

An emissions trading system (ETS) offers a more flexible and market-driven approach to carbon pricing than a flat tax. By setting a “cap” on the total allowable emissions and allowing firms to trade allowances, the ETS ensures that emissions reductions occur where they are cheapest to achieve. In the context of carbon pricing power generation economics, the ETS provides a clear “glide path” for the decarbonisation of the grid. As the number of available allowances is reduced over time, the price naturally rises, providing an ever-stronger incentive for utilities to invest in low-carbon alternatives. The liquidity and transparency of these carbon markets are essential for allowing energy companies to hedge their carbon risk, much as they do with fuel or electricity prices.

The long-term success of an ETS depends on its ability to provide a predictable price floor and ceiling. Sudden price crashes can undermine the incentive for low carbon investment, while excessive volatility can make it difficult for utilities to plan their long-term fleet evolution. Many modern carbon markets now include “Market Stability Reserves” to manage supply and demand, ensuring that the price remains within a range that supports the goals of the energy transition policy. This sophisticated market management is a hallmark of the modern approach to power sector economics, where the goal is to use the power of the market to achieve a social and environmental objective the stabilization of the global climate.

As we look toward the 2030s and beyond, carbon pricing will remain the primary steering mechanism for the global energy system. It is the bridge between the physical reality of climate change and the financial reality of the boardroom. By masterfully managing the carbon pricing power generation economics, we can ensure that the transition to a low-carbon world is not only environmentally necessary but also economically efficient. The era of “unpriced” carbon is over, and the era of the clean, carbon-accountable grid has begun. This shift is not just an added cost; it is a fundamental revaluation of energy that prioritizes the health of the planet alongside the stability of the economy. The long-term impact of carbon pricing is nothing less than the total reinvention of how we value, produce, and consume power in a sustainable world.

Under the contract, Mitsubishi Power will supply its advanced M701JAC gas turbines to the Facility E project. These turbines are designed to be hydrogen-ready and are recognized for their operational efficiency, reliability, and flexibility. The technology will form the backbone of the power generation system for the Facility E IWPP, which combines electricity generation with large-scale desalination capacity.

The Facility E IWPP is located in the Ras Abu Fontas area, around 25 kilometers south of Doha. Once operational, the plant will add a combined 2.4 GW of power to Qatar’s electricity system, accounting for approximately 20% of the country’s national grid capacity. In parallel, the facility will deliver 495,000 tons of desalinated water per day, supporting Qatar’s growing demand for both power and water. The project aligns with Qatar’s National Vision 2030 and its broader decarbonization strategy, which focuses on reducing carbon emissions while expanding the use of cleaner energy technologies.

This project represents the first deployment of Mitsubishi Power’s M701JAC gas turbine technology in Qatar. The turbines’ ability to co-fire hydrogen and operate flexibly is expected to play a key role in enhancing grid stability and supporting the country’s transition toward lower-carbon power generation.

Khalid Salem, President of Middle East & North Africa, Mitsubishi Power said: “Qatar has long been a key partner for Mitsubishi Power, and we are honored to play a pivotal role in supporting the country’s ambitious energy goals. As one of the world’s leading LNG hubs, Qatar’s continued growth and economic development are intrinsically tied to its energy infrastructure. The Facility E IWPP project is a significant step in addressing Qatar’s rising energy demand while ensuring the stability and resilience of its power grid. Mitsubishi Power’s hydrogen-ready M701JAC gas turbines will provide Qatar with highly efficient, reliable, and flexible power generation solutions that synchronize with renewable energy sources. This partnership reflects our long-term commitment to the country and its energy transition, reinforcing our shared vision for a low-carbon, sustainable future. We are proud to contribute to Qatar’s National Vision 2030, further strengthening our legacy of delivering cutting-edge technologies to meet the dynamic energy needs of the region.”

H.E. Eng. Abdulla Bin Ali Al-Theyab, President of Qatar General Electricity and Water Corporation (KAHRAMAA), said: “KAHRAMAA, through the adoption of the Facility E project utilizing hydrogen-ready M701JAC gas turbines supplied by Mitsubishi Power to the project company, represents a pivotal step in ensuring grid stability, which helps strengthen the State of Qatar’s electricity energy security, underpins the nation’s commitment to delivering sustainable and reliable electricity energy to its citizens, residents, and industrial sectors, meets future electricity needs, and maintains high levels of reliability and performance required by the State, in line with Qatar National Vision 2030”.

Beyond equipment supply, Mitsubishi Power has also entered into a long-term service agreement with Ras Abu Fontas Power Company. The agreement covers parts, repairs, and related services to support high availability and sustained performance throughout the project’s operational life.

The Facility E IWPP is expected to begin operations in 2028, reinforcing Qatar’s energy security and contributing to the country’s long-term sustainability and growth objectives.

Honeywell’s liquefaction technology, modularized heat exchangers and pretreatment solutions will enable the production of 9.5 million tonnes per annum of LNG, supporting global energy demand

Honeywell today announced an agreement with Technip Energies, an engineering, procurement and construction contractor, to provide integrated liquefied natural gas (LNG) pretreatment and liquefaction solutions for Commonwealth LNG’s planned export facility in Cameron Parish, Louisiana. Honeywell’s modular technology will enable Commonwealth LNG to expedite project timelines, simplify execution, mitigate construction risks and enhance production efficiency to meet increasing energy demand.

Commonwealth LNG, part of the Caturus platform, will use Honeywell’s single‑mixed refrigerant liquefaction process technology and six modularized coil wound heat exchangers (CWHEs) to produce a projected 9.5 million tonnes per annum of LNG. Honeywell’s CWHEs provide the highest throughput of natural gas within a compact footprint, maximizing processing capabilities with a space-saving design, while enhancing safety and operational reliability.

Additionally, Honeywell UOP SeparSIV® pretreatment technology will be used to remove water and heavy hydrocarbons to meet the required LNG specifications. The technology can be used with varying feed compositions and can save operators up to 50% of lifecycle cost versus traditional removal processes.

“Honeywell’s end-to-end LNG solutions and modular delivery model options can help customers reduce construction timelines, increase speed to market and ultimately enhance the return on their investment,” said John Palamara, vice president and general manager of Honeywell’s LNG business. “The combination of our innovative technologies with our deep industry expertise can help to optimize every phase of the LNG process, supporting global energy security needs.”

“This significant capital investment in the Commonwealth LNG platform is a key milestone, along with the financing process, which is well underway, and illustrates our level of commitment to developing this global-scale LNG project,” said Caturus Chief Executive Officer David Lawler. “The Commonwealth project is a crucial component of Caturus’ wellhead-to-water strategy, and this is another important step toward building the nation’s leading independent integrated natural gas company.”

Honeywell is a global leader in LNG process technology and automation, including pretreatment and liquefaction technologies along with cutting-edge automation and software technologies to help optimize the overall LNG process scheme. The company is responsible for liquefying about two-thirds of the world’s LNG and provides integrated pretreatment for about 40% of global LNG capacity. Honeywell provides customers with various options for modular LNG technology solutions that can be built off-site and shipped to export facilities, helping reduce risk and expedite construction timelines to enable LNG facilities to enter operation quicker than those built with traditional construction methods.

The unit, having a capacity of 622.6 megawatts, is the first half of a 1.25-gigawatt facility that is designed to strengthen the electricity generation capacity of the company.

The new natural gas-fired power plant makes use of a gas turbine combined-cycle system, which in a way enhances the energy efficiency through recovering exhaust heat in order to power a secondary steam turbine. The second unit, having equal capacity, is set to come online in May 2026. Once both these units are functional, the domestic thermal generation capacity of Osaka Gas is going to increase to 3.2 gigawatts, which is up from almost 2 gigawatts.

The launch comes in the middle of a growing demand in terms of electricity that’s especially driven by the expansion of data centres that are needed to support the growth of artificial intelligence. The option of natural gas goes on to sync along with a strategy so as to meet the evolving grid requirements while at the same time making sure of energy dependence.

The latest Strategic Energy Plan by Japan, which was approved in February 2025, happens to identify natural gas as being a practical energy source in order to support the energy transition of the country. It is regarded to be a stable pillar of the energy mix that goes even beyond the target of carbon neutrality, which has been set for 2050.

With regard to this, Japan has gone on to conduct auctions in the past two years in order to allocate the new gas-fired capacity as a replacement for the erstwhile coal plants. An overall 7 gigawatts of capacity has been awarded during this period, as per the data from the Organization for Cross-regional Coordination of Transmission Operators, Japan – OCCTO.

The OCCTO forecasts a consistent growth in liquefied natural gas – LNG-fired capacity, having installed capacity anticipated to touch 85.75 gigawatts by 2034, which is up from 79.98 gigawatts in 2024. This growth reflects a strategy of energy diversification within the context of industrial as well as digital shifts.

Due to the Himeji plant, Osaka Gas has indeed strengthened its role within thermal power generation while at the same time responding to the structural changes in the electricity market of Japan.

The transaction, which according to Harbour is going to be funded from the present liquidity, is anticipated to be immediately materially accretive in order to free cash flow and at the same time also elevate the resilience along with the longevity of its UK business. Completion is all set for Q2 of 2026, subject to the regulatory approvals as well as the settlement of creditor claims.

As Harbour Energy strikes $170mn deal, the acquisition of Waldorf is bound to add almost 20,000 barrels of oil equivalent per day of oil-weighted production and also around 35 million barrels of oil equivalent of 2P reserves. It also raises the operated interest of Harbour in the Catcher field to 90%, which is up from 50%, a move that, as per the company, is going to improve the financial balance of the joint venture.

Besides, Harbour will also gain a new production foothold within the Northern North Sea by way of a 29.5% non-operated interest within the Kraken oil field, hence widening its geographic exposure across the basin.

Apart from the headline production and reserves, Harbour is also targeting significant operational along with financial synergies. The integration of the non-operated portfolio of Waldorf into Harbour’s UK organization is anticipated to unlock the efficiencies, while the deal structure enables Harbour to make utmost use of its investment-grade balance sheet to release a forecasted $350 million of cash, which is at present posted as security for decommissioning liabilities of Waldorf.

The acquisition also goes on to bring another UK ring fence tax loss, which could as well further elevate the cash flow profile of Harbour over time.

The managing director of the UK business unit of Harbour, Scott Barr, remarked that the transaction does build on actions that are already taken in order to sustain the position of the company in the basin and that too in the middle of the ongoing fiscal year along with regulatory pressures. He underscored the stabilization of the Catcher partnership and the immediate cash flow advantages, along with the improvements to the long-term sustainability of the UK operations of Harbour, which also includes employment along with energy security.

This deal comes as the UK North Sea goes on to face quite a few mounting challenges, which include higher taxes and regulatory uncertainty as well as decommissioning obligations, which are rising. In such an environment, asset sales out of administration as well as increased consolidation among the established operators have gone on to become more common, especially where stronger balance sheets can go on to absorb late-life assets along with associated liabilities.

For Harbour Energy, this acquisition reinforces its strategy of going ahead and selectively investing in high-quality, cash-generative North Sea assets while at the same time seeking scale and, with it, the operational control in a basin that looks mature.

The Nigerian Gas Flare Commercialisation Programme – NGFCP marks quite a prominent step towards ending flaring as well as monetizing wasted gas, the officials from NGFCP confirmed on December 12, 2025.

Gas flaring apparently is the controlled burning of natural gas, which gets released at the time of oil extraction.

The gas flaring projects could very well capture between 250 and 300 million standard cubic feet per day – mmscfd of gas, which is currently flared, and slash around 6 million tonnes of CO₂ per year, and also unlock almost 3 gigawatts of power generation potential, showed an NGFCP document.

Nigeria anticipates the initiative to attract around $2 billion in terms of investment and also come up with over 100,000 jobs. It could also go on to produce 170,000 metric tons of LPG per year, hence offering clean cooking access across 1.4 million households.

The permits of the gas flaring projects go on to follow a competitive bid round, which went on to award 49 flare sites to 42 bidders post the programme got restructured after COVID-19 as well as the Petroleum Industry Act.

The head of the Nigerian Upstream Petroleum Regulatory Commission, Gbenga Komolafe, attended and also presented the certificates to all 28 companies.

As per the NGFCP official, the NGFCP is indeed a pillar in their quest to eradicate routine flaring, decrease emissions, and also elevate the global credibility of Nigeria when it comes to its energy transition commitments.

Notably, the programme sync well with the Energy Transition Plan of Nigeria and also looks to turn flare gas from being an environmental liability to an economic asset.

The 28 companies that have gone on to ink key agreements pertaining to milestone development and connection, as well as gas sales agreements, and now qualify for the permits so as to access flare gas.

Producers are also going to benefit from the decreased liabilities, enhanced ESG performance, and also alignment with the decarbonization agenda of the government.

Development partners, which are the likes of KPMG, Power Africa, the Global Gas Flaring Reduction initiative by the World Bank, and USAID, as well as financiers, have all supported the programme with technical along with commercial frameworks.

According to the official, while the permits indeed go on to mark a milestone, engineering, construction, and financing have to begin in earnest.

The official further said that the real work begins now, as this programme is going to create economic and industrial as well as environmental value while at the same time also strengthening the energy transition of Nigeria.

The nation has recently gone on to issue a tender for a company so as to supply a floating storage as well as a regasification unit, which will be moored at the Nador West Med port that is about to start operating in 2026. It’s also looking to go ahead and pick firms in order to build and finance as well as operate new pipelines that are connecting the port to prominent industrial areas.

By being a $1 billion LNG hub, Morocco looks forward to becoming a player in LNG imports, with the government planning to spend almost $3.5 billion in order to boost gas consumption to 12 billion cubic meters by the decade from the present from 1.2 billion cubic meters. The new projects are going to help counter the loss of Algerian supplies in 2021 after a diplomatic dispute, whereas gas is an important bridge fuel for the manufacturing industries that go on to export goods to Europe.

The Ministry of Energy Transition and Sustainable Development has forecasted that the FSRU would cost around $273 million, whereas the new pipelines will need investments of around $681 million. The pipelines are going to be connected to the Maghreb-Europe link, by way of which Morocco imports gas from Europe, since the projects are also going to form the backbone of a gas network that may as well, one day, carry green hydrogen across home as well as abroad.

The gas plans of the country involve spending $1.5 billion when it comes to infrastructure so as to become a player in LNG imports and replace dirtier feedstocks like fuel oil or even coal in the industrial sector, and also investing $2 billion in order to construct gas-fired plants, which would indeed triple the amount of power that gets generated through gas.

Morocco looks forward to decarbonizing its economy completely by 2050 by way of phasing out coal along the way through including expansion within solar and wind generation and also battery-storage facilities. Authorities anticipate almost $11 billion in investment so as to add 12.5 gigawatts of renewable capacity from 2025 to 2030, therefore representing almost 80% of all the new installed capacity within that period.

Gas is also going to play a limited role when it comes to replacing coal, with planned renewable expansion having a much larger percentage of new capacity, opines the Imal Initiative for Climate and Development’s director, Rachid Ennassiri.

Notably, when it comes to offers for the FSRU tender, they are going to be opened in early February 2026, and pre-qualified candidates for the new pipelines are going to get revealed around the same time.

The turbines deployed at Anji originate from a design developed by GE Vernova Inc., which formed a joint venture with state-owned Harbin Electric Corp. in 2019 to build the machines in China and supply up to a dozen units per year. The commissioning fits into China’s push to build more of its own turbine manufacturing, and the introduction of a domestic gas turbine comes at a moment when global suppliers are finding it hard to keep up with growing orders. Gas-fired power is taking on a bigger role for many industries, as tech companies look for steady electricity to run expanding data centers and as developing markets move away from coal toward cleaner-burning fuels.

China’s gas power capacity is projected to reach 150 gigawatts this year, and industry proposals are calling for an increase to 200 gigawatts by the end of the decade. According to Qi Qin, an analyst with the Centre for Research on Energy and Clean Air, gas-fired generation is playing a larger role in coastal regions where land limitations and grid congestion have slowed the expansion of onshore renewables. The commissioning of the Anji turbines, along with progress by other manufacturers, shows how adoption of the domestic gas turbine is becoming more widespread across the sector as companies such as Dongfang Electric Corp. and Shanghai Electric Group Co. advance their own programs.

The start-up of the Anji Power Plant demonstrates how China is positioning local turbine production as a central component of its power-sector planning. As demand for flexible, high-capacity gas generation continues to climb, the operational deployment of a domestic gas turbine and the development of new manufacturing partnerships signal a strengthening supply base for future power-generation projects.

It was in March 2025 that the government approved the project, underlining that at present 80% of the LNG supply of the country comes through two interconnectors from Britain. They said that any sort of an interruption is going to have an unimaginable impact on the electricity and heating across Ireland, both for homes as well as businesses. Gas at present offers almost 30% of the primary energy needs of Ireland and typically goes on to generate 40% of Ireland’s electricity. During the peak demand periods, gas can make up almost 80% of the electricity generation for the country.

Gas Networks Ireland has gone on to report that it has completed the search for the most apt location to place the first Strategic Gas Emergency Reserve of Ireland. Initially, 14 possible sites were considered. The engineers of the company undertook a detailed site evaluation in Cork Harbor as well as in the Shannon Estuary. All the sites were assessed for their technical, environmental, and planning as well as financial merits.

Cahiracon in County Clare, which is along the Shannon Estuary, was selected. The next step calls for more scoping as well as designs in order to refine the project as well as cost estimates.

The plan calls for having the FSRU at a deep-water jetty, which gets the support of an onshore facility. It will need a new connection to the national gas network. The FSRU is going to be owned as well as operated by Gas Networks Ireland for the state.

As per the company, there are over 50 operating floating storage as well as regasification units across the world at present. They believe it is going to offer critical support in order to ensure consistency in gas supply across Ireland. No timeline has been announced as to when the FSRU could get in place.