Exploration & Production

Onshore Middle East is the cheapest source of new production, with an average breakeven price of just US$27 per barrel. (Image source: Adobe Stock)

Onshore Middle East is the cheapest source of new oil production, as the cost of developing new upstream oil projects continues to rise, according to new research from Rystad Energy

According to Rystad Energy, the average breakeven cost of a non-OPEC oil project grew to US$47 per barrel of Brent crude, a 5% increase in the last year alone, thanks to inflationary pressure and supply chain issues. Offshore deepwater and tight oil projects remain the most economical new supply sources, with oil sands still the most expensive.

The report found that onshore Middle East is the cheapest source of new production, with an average breakeven price of just US$27 per barrel. This segment also boasts one of the most significant resource potentials. Offshore shelf is the next cheapest (US$37 per barrel), followed by offshore deepwater (US$43) and North American shale (US$45). Conversely, oil sands production breakevens average US$57 per barrel, but can go as high as around US$75.

Cost pressures

"Rising breakeven prices reflect the increasing cost pressures on the upstream industry. This challenges the economic feasibility of some new projects, but certain segments, including offshore and tight oil, continue to offer competitive costs, ensuring supply can still be brought online to meet future demand. Managing these cost increases will be critical to sustaining long-term production growth,” said Espen Erlingsen, head of Upstream Research at Rystad Energy.

As well as breakevens, average payback for new projects, internal rate of return (IRR) and carbon dioxide (CO2) intensity are vital metrics for evaluating new oil development economics. The tight oil sector’s payback time is just two years, assuming an average oil price of US$70 per barrel, illustrating how quickly operators are recovering their investments. Payback time is closer to 10 years or more for the other supply segments. Tight oil also leads the pack in terms of IRR, with an estimated IRR of around 35% in the same average oil price scenario. Conversely, oil sands, the most expensive supply source, has the lowest IRR of approximately 12%.

Over the last three years, the average CO2 intensity for tight oil has been 14 kilograms per barrel of oil equivalent (kg per boe), while deepwater has a slightly higher average CO2 intensity of 15 kg per boe. The oil sands sector again falls behind the other segments, with the highest future estimated emissions at around 70 kg per boe.

Onshore Block 2 is Petronas Abu Dhabi's third exploration concession. (Image source: Adobe Stock)

PETRONAS Abu Dhabi, subsidiary of Malaysia’s PETRONAS, has been granted a new oil and gas exploration concession in Onshore Block 2, by the Supreme Council for Financial and Economic Affairs (SCFEA)

Under the agreement, PETRONAS Abu Dhabi will hold 100% equity and become operator of the concession.

The Onshore Block 2, located within the Al Dhafra region of Abu Dhabi, covers an area of more than 7,300 sq. km and is PETRONAS Abu Dhabi’s third exploration concession, following the Unconventional Block 5 in 2024 and the Unconventional Block 1 in 2022. it is thought to have both conventional and unconventional potential. 

This concession award comes after the successful completion of Abu Dhabi’s first and second exploration concession bid rounds launched in 2018 and 2019, resulting in the award of 11 blocks to leading international partners in the energy sector.

“We are excited about this new venture and extend our deepest gratitude to SCFEA for their unwavering trust and collaboration. This endeavour broadens PETRONAS Upstream’s portfolio in Abu Dhabi, incorporating both unconventional and conventional resources, offering potential for exploration growth,” said PETRONAS executive vice president and chief executive officer of Upstream, Mohd Jukris Abdul Wahab.

Premium energy basins hold the potential for upstream players to decarbonise while continuing to meet oil and gas demand. (Image source: Rystad Energy)

Middle Eastern basins will play a pivotal role in meeting global energy demand while decarbonising, according to new research from Rystad Energy

Despite the accelerating energy transition, oil and gas will remain central to the global energy mix for the foreseeable future given the growth in energy demand. Rystad Energy estimates that by 2030, more than 75% of total demand will be met by fossil fuels, with emissions climbing as a result. This underscores the continuing importance of hydrocarbons, while also highlighting the need for oil and gas companies to build sustainable portfolios and reduce their Scope 1 and Scope 2 emissions to meet medium and long-term targets. As oil companies work to transform into integrated energy players and decarbonise their operations, it is crucial not only to achieve transition goals but also to minimise the carbon footprint of upstream activities, with the extraction of these resources accounting for more than 800mn tonnes of CO₂e every year.

Premium energy basins (PEB) – a term coined by Rystad Energy – are particularly valuable because they are rich in hydrocarbon reserves and offer the potential for integrating low-carbon energy sources. As such, they provide an ideal platform for addressing emission challenges by combining substantial hydrocarbon volumes with opportunities for incorporating low-carbon solutions to reduce overall emissions.

“A select few basins hold the potential for upstream players to decarbonise while continuing to meet oil and gas demand. However, the race to decarbonise hinges on three crucial factors: accelerating investment, overcoming geographical challenges and modifying existing infrastructure. These changes are essential for unlocking the full potential of these basins and for upstream players to achieve their decarbonisation targets,” said Palzor Shenga, vice president, Upstream Research at Rystad Energy.

The Central Arabian and Rub Al Khali basins stand out as carbon-efficient, resource-rich basins with significant potential, according to Rystad. These Middle Eastern basins are at the forefront of PEBs and play a pivotal role in global conventional discovered volumes, especially as global discoveries decline and exploration activity peaks. Separately, these basins also score highly in terms of renewable potential, with both offering more than 6.2 gigawatts (GW) combined of installed and upcoming solar capacity.

Since 2015, these basins have contributed approximately 40bn bbl of oil equivalent (boe) in newly discovered volumes, evenly divided between liquids and gas. Egypt’s Nile Delta, driven by Eni’s giant Zohr gas discovery in the Mediterranean Sea, ranks third with about 5bn boe discovered during this period, followed by the US Gulf Deepwater (3.7bn boe) and the Central Asian Amu-Darya (3.6bn boe) basins.

With a combined capital expenditure of US$638bn, the Rub Al Khali, US Gulf Deepwater and Central Arabian basins have seen the highest greenfield investments since 2000. Due to the vast volumes discovered, the unit cost of development in the two Middle Eastern basins has been under US$2 per boe. In contrast, the smaller average resource size in the exclusively offshore US Gulf Deepwater Basin has driven development costs to over US$9 per boe, with only the Viking Graben Basin (US$11 per boe) in Northwest Europe having a higher development cost. Significant investments have also been made in resource development in Brazil’s Santos Basin (US$153bn) and Australia’s North Carnarvon Basin (US$140bn).

Several PEBs offer significant potential for carbon storage, particularly in late-life or abandoned oil and gas fields, which are suitable for enhanced oil recovery or permanent storage. These basins are increasingly being utilised for carbon capture and storage due to their geological properties.

The bid round includes 10 offshore blocks. (Image source: Adobe Stock)

The Egyptian Natural Gas Holding Company (EGAS) has launched a new international 2024 bid round for the exploration and exploitation of natural gas and crude oil in 12 blocks in the Mediterranean and the Nile Delta

This includes 10 offshore blocks and two onshore blocks, according to the Production Sharing Agreements (PSA) model, through Egypt Upstream Gateway (EUG) at https://eug.petroleum.gov.eg. The closing date for submitting bids is 25 February 2025.

Promising basin

This bid round is part of the Ministry of Petroleum and Mineral Resources' efforts to attract new investments to Egypt, in line with its strategy to exploit promising opportunities in the field of gas and oil exploration, especially in the Mediterranean Sea, which holds significant potential as a promising basin for natural gas. A slew of recent discoveries, including the giant offshore Zohr gas field, containing an estimated 30 TCF, have highlighted Egypt's potential.

Eng. Karim Badawi, Minister of Petroleum and Mineral Resources, explained that the launch of this bid round for natural gas exploration supports Egypt's direction toward intensifying exploration activities in the Mediterranean, especially in light of the growing interest in achieving new discoveries and increasing natural gas production, which has become a crucial element in both the local and global energy mix.

The minister added that this is the eighth bid round of its kind to be launched using the latest digital tools through Egypt Upstream Gateway (EUG), which the ministry launched at the beginning of 2021. This provides seamless access to the essential and all updated technical data related to bid rounds, speeding up the process of evaluating investment opportunities and submitting bids.