ExxonMobil said that the acquisition included 1.2 million acres in the North Marakia Offshore block, located approximately five miles offshore Egypt’s northern coast in the Herodotus basin. The remaining 543,000 acres is in the North East El Amriya Offshore block in the Nile Delta.
Mike Cousins, senior vice president of exploration and new ventures at ExxonMobil, said: “These awards strengthen our exploration portfolio in the Eastern Mediterranean. We look forward to working with the government and deploying our proven expertise and advanced technology.”
According to the company, ExxonMobil will operate both blocks and hold a 100 percent interest. Operations, including the acquisition of seismic data, are scheduled to begin in 2020.
Hesham Elamroussy, chairman and managing director of ExxonMobil Egypt, added: “ExxonMobil has been a partner in Egypt’s growth for more than 115 years, and these awards reaffirm our commitment to pursuing high-quality opportunities in the country.”
The awards add upstream interests to ExxonMobil’s long-standing downstream presence in Egypt, where it has been a fuel, lubricants, and specialties marketer since 1902.
New Zealand: OMV to sell Maari oil field to Jadestone for $50M
Austria’s OMV will sell its 69% interest in the Maari Field offshore New Zealand to Jadestone Energy for $50 million, to focus on gas production in the country.
Floating Production, Storage and Offloading Raroa / Image by OMV
The Maari Project is a mid-life producing asset located in permit PMP 38160, in the offshore Taranaki Basin, in 100 meters water depth, approximately 80 kilometers southwest of New Zealand’s North Island.
The project includes the Maari and Manaia oil fields, produced via a self-elevated jack-up wellhead platform, FPSO Raroa, owned by the joint venture partners (being Horizon Oil Limited (26%) and Cue Taranaki Pty Ltd (5%)) and the associated decommissioning liability with respect to all facilities, which is shared by the partners in accordance with their respective working interests.
The effective date of the transaction between OMV and Jadestone is January 1, 2019, and the closing of the transaction is subject to Joint Venture and New Zealand Government approvals. The average production of the divested assets in 2018, net to OMV, was around 5 thousand barrels of oil equivalent.
Jadestone, an independent oil company focused on the Asia Pacific, said it would fund the acquisition from its cash resources.
Johann Pleininger, OMV Board Member Upstream and Deputy Chairman of the Executive Board: “The divestment of the Maari Field further optimizes our portfolio and will shift us in New Zealand to a gas-only producer. This underlines OMV’s strategy to produce significantly more natural gas than oil to reduce the carbon intensity of the product portfolio in the future.”
Jadestone said the transaction represented exceptional value to Jadestone shareholders, as it would increase the company’s net production by approximately 30%, and 2P reserves by 33%, and would pay back in less than 12 months from anticipated transaction closing.
Paul Blakeley, Jadestone President, and CEO said he was delighted to establish a new operating presence in New Zealand and to begin building relationships with local regulators, communities, staff, and other stakeholders.
He said: “Adding the Maari Project to our growing portfolio of high-value assets in the Asia Pacific region demonstrates our ability to bolt on new assets and provides more than a decade of additional free cashflow, even in the 2P reserves only scenario, as supported by our external reserves audit.”
“The Maari project adds both significant additional opportunity as well as diversity to our operations. New Zealand is a natural strategic fit for Jadestone, where we see many shared values with regards to sustainable energy investment, through maximizing recovery of existing resources and world-class expectations for health, safety, and environmental stewardship.”
“The Maari Project has achieved very modest recovery factors to date, relative to the substantial estimated original oil in place, making this an ideal platform to showcase our differentiated technical capabilities.”
He said Jadestone’s focus was also on extending the life of existing infrastructure that may otherwise not realize its full potential, “thereby continuing to generate income, growth, and ongoing employment for local communities and the New Zealand economy.”
On the OMV side, the company said it would continue to operate the Māui and Pohokura gas fields – which together produced 37 kboe/d year to date (net to OMV) and contain about a third of New Zealand’s gas reserves.
OMV is investing a further USD 300 mn on a range of projects to extend the lives of the Māui and Pohokura gas fields over the next two years and to maintain New Zealand’s gas supply, the company added.
BP revealed as buyer of KrisEnergy’s stake in block offshore Indonesia
Oil and gas company KrisEnergy has signed an agreement with BP for the sale of its participating interest in the Andaman II PSC located in the Malacca Strait, offshore Indonesia.
In late October KrisEnergy said it had accepted a binding letter of offer by an unnamed ‘major international oil and gas company’ for the disposal of its 30% non-operated working interest in the Andaman II production sharing contract.
KrisEnergy announced on Tuesday that it had entered into a conditional sale and purchase agreement with BP for the disposal, subject to obtaining all necessary approvals including from the Government of Indonesia for the assignment of the working interest.
The disposal comes after taking into consideration the future exploration cost and risks associated with deepwater activities, the company explained.
The company said that the board believed it was more prudent to allocate KrisEnergy’s limited capital to funding near-term development.
However, there is no certainty or assurance as at the date of this announcement that the disposal will be completed.
The Andaman II PSC is an exploration block over the North Sumatra Basin covering an area of 7,400 sq. km. The disposal is in line with the group’s risk mitigation, intention to reduce future exposure to exploration capital expenditure and strategy to focus its limited financial resources on optimizing operations at its existing producing assets in Bangladesh and the Gulf of Thailand and progressing the development of the Apsara oil field in Cambodia block A.
Premier Oil is the operator of the Andaman II PSC with a 40% interest and Mubadala Petroleum has a 30% interest.
It is also worth mentioning that Mubadala last July signed an agreement with Premier Oil to farm out a 20 percent participating interest in each of the Andaman I and South Andaman Gross Split Production Sharing Contracts. Mubadala Petroleum is the operator of both the Andaman I and adjacent South Andaman PSCs.
Petrobras poised to become world’s largest oil producer by 2030, Rystad says
Brazil’s Petrobras is on track to become the world’s largest oil producer among publicly listed companies by 2030, based on Rystad Energy’s latest data and forecasts.
However, national oil company Petrobras could not have asked for a better outcome, Rystad said on Tuesday.
Namely, the world’s fastest-growing oil producer gained nearly full control of more than eight billion barrels of oil in the Buzios field, where a sixth floater is being planned. To develop these and other resources off the coast of the South American country, Brazil is set for a whopping $70 billion offshore capital investment spree between 2020 and 2025, solely on field development. This program will have a monumental effect on Petrobras, Rystad said.
“Petrobras can, in a matter of years, become the world’s largest oil producer among publicly listed companies. The significance is huge and symbolic,” commented Aditya Ravi, vice president of Rystad Energy’s upstream team, specialized in E&P activities in Latin America.
“We predict that Petrobras alone can boost its production numbers by more than 1.3 million barrels per day over the next decade.”
During the course of 2019, Petrobras has evolved from fifth place to become the third-largest oil producer, reaching output of around 2.2 million bpd in the third quarter. As it stands, Rosneft and PetroChina top the list over the world’s largest public E&P companies.
Based on Rystad Energy’s latest forecasts, Petrobras could be poised to overtake PetroChina over the next few months, and potentially dethrone the ruling Russian producer Rosneft over the next decade, thanks in no small part to its latest acquisitions.
Brazil’s production could be pushed from 2.8 million bpd in 2019 average to over 5.5 million bpd thanks to Petrobras’ potential peak output of almost 3.8 million bpd by 2030.
Brazilian officials recently indicated the country wishes to join OPEC, the oil cartel dominated by Saudi Arabia and 13 other oil-producing countries. Brazil’s current output would make it OPEC’s third-largest producer, behind Saudi Arabia and Iraq.
“Joining OPEC could cause a major disruption for Brazil, bringing the country into the spotlight with the potential risk of having its wings clipped by the cartel just as production takes off,” Ravi cautioned.
This potential shift in ranking has been spurred on in the aftermath of the three Brazilian licensing rounds organized over the past five weeks by the National Petroleum Agency (ANP), in which 45 blocks were on offer. With only one-third of the blocks receiving bids, the rounds raised concerns that Brazil lacks the luster that in the past ensured active and competitive bid rounds.
In the wake of these rounds, the Brazilian Energy Minister remarked that the current legal and tendering structure could warrant a re-think, including a look at Petrobras’ pre-emptive rights on oil blocks. Others have voiced dismay over the steep signature bonuses.
No one in Brazil is keen on OPEC diet, Rystad says
At an October forum in Saudi Arabia, Brazil’s president Jair Bolsonaro suggested that he would like to see Brazil join OPEC. If such a marriage were to come to fruition, OPEC would be the clear winner and Brazil the loser by a long shot, energy intelligence group Rystad Energy said.
Brazil has experienced a tremendous spurt in crude oil production, propelled by the development of its pre-salt resources.
However, taking Brazil’s oil production to its current level certainly didn’t come cheap. Petrobras has paid over 78% of Brazil’s $396 billion bill for exploration (excluding dry well costs), development and operations from 2010 to 2018. This, in 2014, made Petrobras the world’s most indebted listed E&P company. Petrobras would be counting on the revenues from its growing production to help scale its debt mountain.
According to Rystad, OPEC-mandated production cuts at its projects would threaten Petrobras’ attempts to reduce gearing. Petrobras doesn’t need OPEC — it needs to reduce its still substantial debt.
The established players with activities in Brazil don’t need OPEC — they seek returns on already considerable investments incurred, Rystad said. The new entrants nibbling at Petrobras’ divestment clusters don’t need OPEC — they want to stabilize and even grow production at their acquisitions.
The oilfield service industry doesn’t need OPEC — it would rather have increased production levels to ensure more business.
Brazil has been invited to join OPEC previously also; then the government stated that under Brazilian law it can’t interfere with production operations. So even the Brazilian government doesn’t really need OPEC. No one in Brazil appears keen on the OPEC diet, Rystad concluded.
Karoon to give up its exploration permit in Great Australian Bight
Australia-based Karoon Gas has decided to ditch its exploration permit located in the Great Australian Bight area offshore Australia thus joining oil majors Chevron and BP who had previously abandoned their Bight permits.
During the company’s general meeting on Friday, Karoon Chairman Bruce Phillips said the company had “listened to our broader stakeholder groups and have initiated actions to relinquish EPP46 in the Great Australian Bight.”
Karoon was awarded the exploration permit EPP46 in October 2016. The permit covers 17,793 square kilometers of Australia’s most active and prospective frontier oil exploration province, the Ceduna Sub‐Basin, in the Great Australian Bight (GAB), offshore South Australia.
Karoon’s initial three‐year firm commitment consisted of acquiring an extensive 2D seismic survey over the permit area, a targeted 3D seismic survey, and geotechnical studies.
At the time of the license award, Karoon said it would be monitoring the progress of then-current committed drilling programs and make an assessment of the environmental risks following those campaigns prior to committing to any exploration drilling.
Phillips also said that Karoon had relinquished WA-314-P in Australia after failing to attract a suitable farminee.
Oil majors back out
Oil companies’ attempts to drill in the Great Australian Bight area have been under scrutiny in the last couple of years. Environmental groups like Greenpeace and political party Australian Greens have hampered oil companies’ plans for the Bight, claiming that drilling in the area containing a marine park would threaten marine life, fisheries, and eco-tourism operators.
Back in October 2016, BP gave up on its drilling program in the Bight, citing a new upstream strategy with a focus on opportunities likely to create value in the near to medium term as the reason behind its abandonment.
A year later, in October 2017, Chevron also ditched its Great Australian Bight exploration program due to its inability “to compete in the current low oil price environment.” Chevron denied that its decision had anything to do with the government policy, regulatory, community or environmental concerns, pointing out that it was a commercial decision.
In more recent news, Norwegian giant Equinor has been working to obtain approval for its environment plan for the planned Stromlo well in the Great Australian Bight, which was submitted in April 2019.
Equinor’s planned well is located in the Ceduna sub-basin, off southern Australia. The well is located approximately 400 km southwest of Ceduna and 476 km west of Port Lincoln and in a water depth of approximately 2240 meters.
Australian regulator NOPSEMA earlier in November requested from Equinor to modify and resubmit its GAB plan. Equinor got a deadline of 21 days to provide NOPSEMA with further information about matters relating to consultation, source control, oil spill risk and matters protected under Part 3 of the Environment Protection and Biodiversity Conservation Act 1999.
According to Equinor’s plan, the petroleum activity will occur anytime between October and May during the three years validity period from 2020 to 2022.
Two Equinor workers injured in serious incident in North Sea
Two Equinor employees were injured in a serious work-related incident on board the Heimdal platform in the North Sea on Thursday, November 28.
The Heimdal platform. (Photo: Equinor/IKM)
Equinor said on Friday that the incident had occurred as a result of an explosion of a portable gas container on board, and was reported in to Equinor’s emergency response centre at 1806 CET. There were 70 personnel on board the platform when the incident occurred.
The two injured employees were taken care of by health personnel on board Heimdal, and were transported further to Haukeland University Hospital and Stavanger University Hospital with a SAR helicopter and a Joint Rescue Coordination Centre helicopter.
Equinor is following up both those injured and their families. The Heimdal organization is also being taken care of, Equinor said.
On Thursday night extra personnel travelled out to the platform to follow up those who were on board.
Equinor also said that relevant authorities had been informed and updated, and the incident would be investigated further.
Heimdal is a gas field west of Sveio in Hordaland county, in the northern part of the North Sea, north of Johan Sverdrup and south of Oseberg, near the border with the UK shelf. The Heimdal Gas Centre, on Production Licence (PL) 036, is a hub for the processing and distribution of gas. It consists of an integrated steel platform, and a riser platform.
Current Heimdal partners are Equinor (29.4% – operator), Petoro (20%), Total E&P Norge (16.7%), Spirit Energy (28.8%) and LOTOS Exploration and Production (5%).
Santos eyes FPSO and wellhead platform development for Dorado
Australia’s Santos has revealed that its preferred concept for the Dorado field project, which is located offshore Australia, is an FPSO and wellhead platform development.
Dorado field illustration; Source: Santos
Dorado is located in WA-437-P in which Santos is the operator and holds an 80% interest and Carnarvon is its partner with the remaining 20% interest.
In its investor day presentation on Tuesday, Santos released initial ‘concept select’ information with respect to the proposed liquids development for the Dorado Project. The company’s preferred concept for the Dorado project is an FPSO and wellhead platform development. In the initial phase, Santos plans for oil and condensate development followed by future phase of gas export.
The Dorado oil, gas, and condensate field was discovered in 2018 and successfully appraised this calendar year.
In a separate statement on Tuesday, Carnarvon said that the project was currently in the late stages of the concept select phase for the liquids development, with a view to starting the Front End Engineering & Design (FEED) phase in early 2020.
During the FEED process, the final development and contracting strategy will be selected for key components of the development such as the number of wells and whether the Joint Venture leases or acquires an appropriate Floating Production Storage and Offtake (FPSO) vessel.
Carnarvon also said it had started early discussions with domestic and international banks who have indicated strong interest in financing the majority of its share of the development capital with senior debt. Oil traders have also indicated interest in providing structured finance as an additional source of funding to senior debt. Carnarvon will start a formal financing process once the development concept and contracting strategy has been finalized.
Managing Director, Adrian Cook, said: “The information released by the operator today demonstrates that the Dorado project has the potential for incredibly strong flow rates. Ultimately the initial flow rates will be dependent on the nature of the development. We look forward to finalizing the concept select in the coming months and announcing the beginning of the FEED work in the new year.”
The Norwegian Petroleum Directorate (NPD) has granted Equinor a drilling permit for a wildcat well located in the North Sea offshore Norway.
The West Hercules drilling rig. (Photo: Equinor/Ole Jørgen Bratland)
The well 30/6-31 S will be drilled from the West Hercules drilling rig after concluding the drilling of wildcat well 31/5-7 for Equinor in production license 001.
Equinor has already gained safety consent from the Petroleum Safety Authority (PSA) to use the West Hercules rig for this well, which has been given the prospect name of Helleneset. Drilling is scheduled to start in early 2020 and is estimated to last at least 31 days.
The drilling program for well 30/6-31 S relates to the drilling of a wildcat well in production license 053. Equinor is the operator with an ownership interest of 49.3 percent. Other licensees are Petoro (33.6 percent), Total E&P Norge (14.7 percent), and ConocoPhillips Scandinavia (2.4 percent).
The area in this license consists of block 30/6. The well will be drilled about 8 kilometers northeast of the Oseberg field center.
Production license 053 was awarded on April 6, 1979, in the 4th licensing round on the Norwegian shelf. This is the 31st exploration well to be drilled in the license.
