The upcoming licensing round will promote new acreage. (Image source: Adobe Stock)

Equatorial Guinea is preparing to open doors to investors in home and abroad as it is working on launching a new licensing round this year, with a special focus on upstream

According to the Equatorial Guinea's Minister of Mines and Hydrocarbons, Antonio Oburu Ondo, the Ministry is particularly enthusiastic about the country's offshore acreage, which they are looking to develop in collaboration with Cameroon. These include the Yoyo and Yolanda fields, the Etinde gas field and the Camen and Diega fields, which lies in the maritime borders of these two countries. 

The upcoming licensing round will promote new acreage, including Block H and Block 02, previously operated by Atlas Oranto Petroleum and PanAtlantic Energy (Vanco Energy). 

Last time the country had held a licensing round was in 2019, when 27 blocks were offered. It saw participation from 53 companies, with 17 bids submitted. 

Equatorial Guinea continues to deliver attractive exploration opportunities, with elements of an active petroleum system found in the Upper Albian region of one of the wells from Block S a couple of months back. In Block G, Trident Energy remains ahead of schedule following a production optimisation programme on Okume and Ceiba infill wells, boosting yield by more than 5,000 barrels of oil per day. 

International energy services providers are increasingly operating in the region, with Petrofac being one of the latest examples. GEPetrol signed a US$350mn technical services contract with the company in April last year to develop the Zafiro field in Block B, which is known to be the country's largest. The five-year contract includes support services for onshore bases, a floating production storage and offloading (FPSO) vessel and platform for the operator. It will encompass a holistic asset solution, including operations, maintenance, asset integrity, integrity management, marine services, well engineering, project delivery and supply chain services. 

GEPetrol has a multi-phase development plan with the Zafiro field, with Phase 1 to reconnect selected wells that were previously produced via tiebacks to the Zafiro Producer floating production unit. Phase 2 is supposed to run in parallel, with production and cost optimisation drives, followed by a full-scale redevelopment of the field as part of Phase 3. 

Petrocfac is also providing a master service agreement for Marathon Oil to support key onshore and offshore assets, including five offshore steel jacket facilities in the Alba Field and the Alba Gas Plant onshore. The Alba field is part of Equatorial Guinea's Gas Mega Hub project, in which Chevron is a key player. Processing gas from Alba will mark the second phase of the project, while Phase III will involve gas integration from the Aseng field. 

Chevron's presence in the Equatorial Guinea also includes production sharing contracts (PSCs) in Blocks EG-06 and EG-11, which are an extension of its existing interests in the Alen, Aseng and Yolanda fields.

Vaalco Energy, on the other hand, is focusing on exploration and production from Block P, working on a plan of development following the finalisation of a PSC for the asset in August.

68% of methane emissions stem from upstream facilities. (Image source: Adobe Stock)

The energy sector presents the largest and most cost-effective opportunity for methane emissions reduction, with 68% of methane emissions stemming from upstream facilities, according to Momentick’s 2024 Methane Emissions Report

Momentick, a leading emissions intelligence company, which leverages the power of hyper and multispectral satellites to monitor GHG emissions on a planetary scale, detected emissions at 17% of the sites analysed, measuring a staggering 899 million tons of CO2-equivalent emissions, with 10% of assets accounting for 50% of the emissions detected. The highest concentration of methane leaks was detected in Asia, Africa, and North America, while Europe recorded the fewest leaks.

Methane is a colourless, odourless gas, which requires highly sensitive instruments for detection. Methane leaks can manifest as both diffuse, small emissions and large, concentrated bursts, complicating the consistent identification of leaks. Environmental factors, such as wind, temperature, and terrain, further hinder accurate detection and measurement, as methane plumes disperse quickly, making it difficult to trace emissions back to their sources.

Unlike CO2, methane emission reductions have an almost immediate effect on slowing global warming as methane has a relatively short atmospheric lifespan compared to CO2. By urgently tackling methane emissions, the rate of warming could be slowed by as much as 30% before mid-century, according to Momentick.

The International Energy Agency (IEA) estimates that over 75% of the methane emissions in the oil and gas sector could be reduced today using existing technologies, while research conducted by JP Morgan has found that methane abatement is a cost-effective investment, revealing that up to 70% of the expenses associated with monitoring solutions can be offset by keeping methane in the pipe.

Addressing the issue of poor emissions data

The Momentick report notes that evolving regulations and financial incentives have highlighted the critical need to address the longstanding issue of poor emissions data, with accurate and reliable information needed for decision-makers to implement effective methane abatement strategies. The growing need for accurate and actionable emissions data is driving the expansion of space-based methane monitoring satellites, while advanced algorithmic software solutions are leveraging Earth observation satellites to enhance commercial applications and precise point-source methane detection. By analysing historical data captured by these satellites, researchers and decision-makers can track emission trends over time, gaining deeper insights for regulatory planning and climate action. Additionally, with cutting-edge developments in AI, satellite-based emissions data can now be processed in near real-time, delivering timely and actionable insights.

“2024 was an important year on the path to curbing methane emissions,” said Daniel Kashmir, CEO of Momentick in his Foreword to the report. “Governments committed billions to technological upgrades and research, while oil and gas operators accelerated progress towards their net-zero goals. Collaborating with a wide variety of stakeholders across the energy sector, our team at Momentick encountered a strong commitment to action and eagerness to implement our emissions intelligence technology over the last year.

“We envision satellite-based emissions monitoring becoming central to corporate sustainability strategies during the energy transition. The integration of GHG monitoring and MRV practices will become a standard component of operations across industries. Backed by evolving regulations and growing adoption, these technologies will make net-zero goals truly achievable.”

2025 brings an exciting programme of exploration activities for Impact. (Image source: Impact Oil & Gas)

Impact Oil & Gas Limited has completed drilling and DST operations at the Tamboti-1X exploration well and spudding of the Marula-1X exploration in Block 2913B (PEL 56), offshore Namibia 

Tamboti-1X was safely and successfully drilled to a total depth of 6450mMD on Block 2913B, approximately 12km northeast of the Mangetti-1X well and approximately 25km north-northwest of the Venus-2A well, using the Deepsea Mira semi-submersible drilling rig.

• Black oil was encountered within 85m of net reservoir of lower-quality Upper Cretaceous sandstones, belonging to the Mangetti fan system.

• A DST programme has now been concluded at the Tamboti-1X location, and results from the acquired log, core and DST data are currently under analysis.

The Deepsea Mira spud the Marula-1X exploration well within the southern part of Block 2913B. This well will target Albian-aged sandstones, within the Marula fan complex and has the potential to unlock further exploration targets across the south, which is an area lying at the heart of the prolific Kudu source-rock kitchen. At the end of 2025, the Deepsea Mira is expected to drill the Olympe prospect, targeting Albian sands within a structural closure on Block 2912.

The Joint Venture is continuing to progress the proposed development of the Venus Field, with development studies ongoing. Since the 2022 Venus-1X discovery well, three further wells have successfully penetrated the Venus Field, and four drill stem tests have been successfully carried out. The Venus Field is expected to be the first development in Block 2913B, producing 150kb/d of ~45° API oil, with the final investment decision expected by the first half of 2026

Siraj Ahmed, Chief Executive Officer of Impact commented, “2025 has commenced with an exciting programme of activities on Blocks 2912 and 2913B, with exploration continuing to prove up resources, whilst the Joint Venture rapidly advances towards the first development – the Venus Field – in our Namibia portfolio.

“With further analysis of the Tamboti-1X results underway, the outcome of this well, within the northern region of Block 2913B, highlights the potential of Namibia’s deep offshore play.

“In the South, the joint venture has spud the Marula-1X well, our first well in the Marula fan complex, an area lying at the heart of the prolific Kudu source rock kitchen, which we hope will unlock further exploration targets.”

Block 2913B offshore Namibia

Petroleum Exploration Licence 56, Block 2913B, is located offshore southern Namibia and covers approximately 8,215km² in water depths up to 3,000m. Impact entered the licence as an Operator in 2014, and in 2017, Impact and NAMCOR were joined by TotalEnergies, bringing with it significant deep-water drilling expertise to the Joint Venture. In 2019 QatarEnergy joined the Joint Venture.

PEL 56 contains the Venus light oil field, discovered by the Venus-1X well drilled in 2022. The field has been appraised with the testing of the Venus-1X side-track well; Venus-1A; Venus-2A; and Mangetti-1X wells.

Impact (through its wholly owned subsidiary, Impact Oil and Gas Namibia (Pty) Ltd) holds a 9.5% interest in Block 2913B (PEL 56). PEL 56 is operated by TotalEnergies EP Namibia B.V, who holds a 50.5% interest; QatarEnergy holds a 30.0% interest and NAMCOR, the Namibian state oil company, holds a 10.0% interest.

Block 2912 offshore Namibia

Petroleum Exploration Licence 91, Block 2912, is located offshore southern Namibia, adjacent to, but outboard of, PEL 56 and covers approximately 7,884km² in water depths between 3,000 and 3,900m. Impact joined TotalEnergies and NAMCOR on the licence in 2019, as did QatarEnergy.

Impact Oil and Gas Namibia (Pty) Ltd) holds a 9.5% interest in this Block. PEL 91 is operated by TotalEnergies EP Namibia B.V, who holds a 47.2% interest, QatarEnergy holds a 28.3% interest and NAMCOR holds a 15.0% interest.

NAOC acquisition has been a key highlight for the company in 2024. (Image source: Adobe Stock)

The 2024 financial results for Oando Plc has primarily been driven by the Nigerian Agip Oil Company acquisition, recording a 45% revenue growth at N4.1 trillion from N2.9 trillion in 2023

Eni sold its Nigerian onshore wing NAOC ltd in July last year, in line with its 2023-2026 plan with a focus on upstream. 

“2024 was a year of transformation for Oando, the key highlight being our successful acquisition and subsequent integration of NAOC Ltd, which significantly enhanced our production capacity, attaining peak operated production of 103,206boepd and net entitlements of 45,000 boepd.

Despite a challenging operating environment, we achieved a 45% increase in revenue to ₦4.1 trillion, reflecting the strength of our business model, and a 9% rise in profit after tax to ₦65.5 billion, notwithstanding the costs associated with the onboarding of NAOC,” said Group Chief Executive, Oando PLC, Wale Tinubu.

Production in 2024 saw an increase to approximately 23,911 barrels of oil equivalent per day (boepd) from the 23,258 boepd achieved in 2023. 

There was a stark change in capital expenditures from US$52.3mn to US$18.1mn that included the development of oil and gas assets and exploration and evaluation activities.

Boosting production

Looking ahead to 2025, Tinubu said, “In 2025, our priority shall be to drive cost optimisation, operational efficiency, streamline processes, enhance procurement, and leverage technology to improve productivity across our operations. In parallel, we will intensify efforts to boost production through the dual approach of rig-less and workover initiatives while executing an aggressive drilling program across three rig lines.

Simultaneously, in collaboration with other stakeholders, we are proactively tackling above-ground security challenges by implementing a revamped security framework that integrates advanced surveillance technology and intelligence-driven initiatives to curb the perennial, unnecessary, and unjustifiable theft of oil to ensure the long-term integrity of our vast network.

As we look ahead to an exciting and successful 2025, we recognize that achieving our goals requires the unwavering support of our host communities and partners. Through extensive engagement, we will foster a collaborative ecosystem that not only secures our operations but also drives shared prosperity and sustainable development for all.”