The Top 5 Oil Exploration Prospects of 2025
The global oil industry saw approximately 120 oil and gas discoveries in 2024, the overwhelming majority of which were small incremental reserve additions. This stands in contrast with the previous years when the 2022 discovery of Venus in Namibia, followed by the 2023 Mopane find in the same country, instilled hope in the global upstream community that multi-billion-barrel discoveries are still possible. Last year, it was only Kuwait’s al-Nokhatha that fit that description, and it could very well happen that the largest 2025 find would once again take place in Kuwait’s offshore. Now let’s look at the hottest exploration prospects of this year, potentially opening previously untapped frontier areas or simply adding a new twist to already producing basins. Jazza (Kuwait) Kuwait’s exploration efforts have been on fire lately. As of this writing, Kuwait does not operate any offshore fields in its territorial waters and has a 50% stake in the Khafji field located in the Neutral Zone. That said, the past two years have seen a string of offshore drilling successes from Kuwait, first with the play-opening discovery of al-Nokhatha (believed to contain some 2 billion barrels of oil) that was subsequently backed up by the al-Julaia find (reserves assessed around 0.8 billion barrels). With Kuwait’s national oil company KOC already dreaming big about bringing the Middle Eastern nation’s production capacity to 4 million b/d, an almost 1.5 million b/d increase compared to current OPEC+-capped output figures, the Jazza prospect could become the crown jewel of recent exploration efforts. The Jazza-1 wildcat is spudded to the southwest of al-Nokhatha, in relative proximity to the disputed Durra gas field, suggesting that a dry well would be very unlikely. Korikori (Suriname) US oil major Chevron will be looking forward to a series of high-impact decisions this year. The Chevron-Exxon arbitration regarding Hess’ Guyanese assets will foreshadow its expansion into South America’s new frontiers, whilst its Korikori-1 exploration well could boost that portfolio with a new entry point, Suriname. Suriname’s shallow water remains a terra incognita for oil drillers as the first reflex of oil companies was to appraise the blocks immediately bordering Guyana’s Stabroek license. Following a set of discoveries and even a final investment decision on the 200,000 b/d Gran Morgu project (combining the Sapakara and Krabdagu finds), the time has come for oil firms to look towards shallow water plays. Chevron is set to drill Korikori in Q4 2025, suggesting we will only hear about its commercial qualities by early next year. Elektra (Cyprus) Chevron’s much-awaited approval for the $4 billion Aphrodite gas field in offshore Cyprus happens at the right time for other drillers in the Eastern Mediterranean. Suddenly, the option of exporting natural gas to Egypt is a workable scenario that avoids the pitfalls of building costly floating liquefaction terminals. Against this background, ExxonMobil is preparing to drill its Elektra exploration well, potentially the biggest natural gas find of this year with the US major setting estimated pre-drill volumes at 1.7-1.8 bboe. Electra is in the immediate vicinity of Egypt’s Zohr, meaning ample hydrocarbon plays are almost guaranteed, even if their subsequent recoverability might be limited by water influx and reservoir pressure issues. The increasing sophistication of subsea infrastructure would also allow ExxonMobil to tie in any potential Elektra gas production into the existing evacuation system. The Valaris DS-9 drillship started drilling in late January, with results expected towards the end of Q1 2025. Area C (Libya) Exploration efforts in Libya have been wrapped in a mystery over the past decade, with European majors Repsol, Eni and TotalEnergies making a gradual comeback to the North African country last year. Whilst most of those upstream activities were taking place in well-established basins such as the coastal Ghadames or Murzuq further inland, Eni is poised to test Libya’s deepwater offshore, for the first time ever. Together with project partner BP, the Matsola-1 well (to be drilled in Q4 2025) could confirm that the onshore Sirte Basin extends into the seas as well. The Libyan Civil War derailed many highly promising offshore projects, including Hess Corp’s 2009 Arous al Bahar gas discovery that was poised to become a frontier-opening gas project. Eni’s drilling is in the immediate vicinity of Hess’ discovery and could well kickstart further appraisal works in the Gulf of Sirte. Libya’s offshore projects have been immune to the country’s notorious power struggles (it’s quite difficult to blockade an offshore platform), with the two main producing fields – Bouri and al-Jurf – remaining operational all throughout the bloody 2011-2020 period. DWOB (South Africa) TotalEnergies’ Venus discovery became the largest oil and gas discovery of 2022 and kickstarted a Namibian oil rush in 2023-2024 as everyone wanted to make sure they don’t miss out on the latest exploration frontier. Despite Shell writing down some Namibian discoveries as sub-commercial, the drilling frenzy in Namibian waters is far from over. The same TotalEnergies is now aiming to develop South Africa’s Deep Water Orange Basin (DWOB) block that abuts its Namibian projects across the Orange Basin, hoping that the prolific oil resources of Venus extend southwards. DWOB is relatively far away from the shore, some 200 km or 125 miles, in water depths that mostly range between 1,500 m and 3,000 m. Namibia’s offshore discoveries contained a lot of natural gas – one of the main reasons why Venus will not see commissioning until at least 2029 is the difficulty of marketing the gas – and DWOB would most probably have the same problem. That said, some estimates put the total recoverable resource at 1 boe, which would be a welcome boost to Total’s African portfolio. With the spudding expected to start only in late 2025, we would not see the results of DWOB drilling before 2026. THE ONES THAT DIDN’T MAKE IT Whilst Jazza or Korikori could still become the largest oil discovery of 2025, several hydrocarbon prospects are already out of the game, either hitting sub-commercial volumes of oil or not finding any resource at all. A lot of
Shell forecasts global LNG demand to increase by 60% by 2040
Global demand for liquefied natural gas (LNG) is projected to rise by approximately 60% by 2040, primarily fuelled by economic expansion in Asia, according to Shell’s LNG Outlook 2025 report. The report highlights the increasing demand for natural gas as the world transitions to cleaner energy sources. The impact of AI and efforts to reduce emissions in heavy industries and transportation will also contribute to the demand, the report stated. Industry forecasts predict LNG demand will reach between 630 million tonnes per annum (mtpa) and 718mtpa by 2040. This projection surpasses last year’s forecast, which estimated global LNG demand in 2040 to be between 625mtpa and 685mtpa. Shell senior vice-president for LNG marketing and trading Tom Summers said: “Upgraded forecasts show that the world will need more gas for power generation, heating and cooling, industry and transport to meet development and decarbonisation goals. “LNG will continue to be a fuel of choice because it is a reliable, flexible and adaptable way to meet growing global energy demand.” China, the leading LNG importer, and India are expanding LNG import capacity and related infrastructure to accommodate the growing demand, Shell noted. LNG demand in Asia grew in the first half of 2024, as China capitalised on lower prices, importing 79 million tonnes (mt) during the year. India also bought record amounts to meet higher power demand caused by hotter weather in early summer, with its imports rising by 20% to 27mt compared with 2023. Shell has indicated that, in response to the increasing demand, particularly in Asia, more than 170mt of additional LNG supply is projected to be available by 2030.
India looking at increasing ethanol blending with petrol to over 20%: Hardeep Singh Puri
India is looking at increasing its target to blend ethanol with petrol to more than 20% and has formed a committee under the NITI Aayog to look into it, Petroleum and Natural Gas Minister Hardeep S. Puri said on Wednesday (February 26, 2025). Addressing the Advantage Assam 2.0 business summit, he said 19.6% blending has already been achieved. “We will be looking at more than 20% blending of biofuel. Already a NITI Aayog group has been set up and they are looking into it,” he said. Mr. Puri said that all the fossil fuel production companies will achieve net zero by 2045, even though India has developmental challenges.
TAPI Pipeline to Remain Failure Without India and Pakistan’s Participation
During a cabinet meeting on February 7, President of Turkmenistan Serdar Berdimuhamedov urged Turkmen officials to accelerate the construction of the $10 billion Turkmenistan-Afghanistan-Pakistan-India (TAPI) gas pipeline. While highlighting Turkmenistan’s energy policy for 2025, Berdimuhamedov stressed the need to modernize the energy sector on a priority basis to enhance the country’s oil and gas production capacity. When emphasizing reliable gas supplies to domestic and international markets, he urged for fast-track construction of the much-delayed TAPI pipeline (Afghanistan International, February 8; News Central Asia, February 10). The TAPI pipeline is a strategic energy transportation project, opening the Galkynysh gas field in Turkmenistan to the energy-starved markets of India and Pakistan (see EDM, June 6, 2023; News AZ, September 12, 2024). The TAPI pipeline is projected to transport 33 billion cubic meters (BCM) of natural gas each year from Turkmenistan’s gas field to the Indian city of Fazilka near the Pakistan border via Afghanistan and Pakistan through the construction of an approximately 1,800-kilometer (1,120-mile) long pipeline (Business Turkmenistan, August 23, 2022; Interfax, January 14). The preliminary cost of the pipeline is estimated at $10 billion (Interfax, January 14). The project was launched in 2018, but the construction work could not proceed due to security concerns in Afghanistan (Pakistan Today, January 18, 2022). The state-owned Turkmengaz, a Turkmen energy company, has already completed a 214-kilometer (133-mile) section of the pipeline in Turkmenistan. In the TAPI project, Turkmengaz holds an 85 percent stake (Interfax, January 14). Afghanistan, India, and Pakistan hold the remaining stakes with 5 percent of shares each (News AZ, September 12, 2024). In September 2024, Ashgabat and Kabul officially resumed work on the Afghanistan section of the TAPI gas pipeline project (Turkmen Portal, September 11, 2024). India has already raised concerns about this pipeline project on different grounds. In 2018, India objected to the price of natural gas and sought renegotiation (Economic Times India Times, August 22, 2018). India contended that the 2013 gas sale purchase agreement benchmarked the price of exported Turkmen gas at 55 percent of the prevailing crude oil price (Economic Times India Times, August 22, 2018). Moreover, transit fees and transportation charges would further increase the price of gas imported to India through the TAPI pipeline to over $10.5 per British thermal unit (mmBtu), which at the time was more than double the average rate of natural gas prices in India (Economic Times India Times, August 22, 2018). India also expressed dissatisfaction with the logistical and security challenges the project could face in constructing the pipeline through volatile areas in Afghanistan and Pakistan (South Asian Voices, November 6, 2024). New Delhi is also worried about becoming dependent on its arch-rival Pakistan for its gas supply. India considers that the pipeline would grant Pakistan leverage in the case of a future bilateral conflict, allowing Pakistan to potentially halt India’s gas supply (Economic Times India Times, September 17, 2024). New Delhi has not completely withdrawn from the project but has not firmly committed to joining it. India’s concerns make its participation in the TAPI pipeline uncertain, and due to this response, Pakistan is also losing interest in the project. Officials in Islamabad consider the TAPI pipeline project unsustainable for Pakistan without India’s participation. Pakistan would have to pay a transit fee of $500 million annually, not including a gas price of $7.5 per MMBtu (The News, November 6, 2024). The project would only be economical for Pakistan if India committed to paying a transit fee of $700–800 million per year to Pakistan. With India’s participation, Pakistan could save $200–300 million per year just in transit fees. India’s withdrawal from the project and Pakistan’s subsequent departure would mean an end to this pipeline, meaning Turkmenistan’s ambition and 30-year-long plans to export its gas to India and Pakistan’s major energy-starved markets would fail.
Oil India Limited CMD highlights bamboo-based 2G ethanol plant
At the Advantage Assam 2.0 Summit on Tuesday, Dr Ranjit Rath, Chairman & Managing Director (CMD) of Oil India Limited (OIL), underscored the company’s pioneering efforts in the energy sector, particularly the establishment of a bamboo feedstock-based second-generation (2G) ethanol plant at Numaligarh Refinery Limited(NRL). This initiative, he emphasized, aligns with Prime Minister Narendra Modi’s vision for import substitution and self-reliance in energy production. He stated, “This is one of the path-breaking initiatives under which we are doing this. If you recall, the Prime Minister’s clarion call for import substitution, and so bamboo feedstock-based 2G ethanol plant; this will be one of its kind in the whole world. And given that we have a lot of bamboo as a grass.”