Wintershall Dea exits Brage oil field

Wintershall Dea is divesting its ownership of the Brage field and transferring the operatorship to the mid-late life specialist operator OKEA. In the next chapter of Wintershall Dea’s story in Norway the company will build on its strength as one of the largest subsea operators on the shelf.


"Norway is and remains an important core region for Wintershall Dea's production in our global portfolio," said Dawn Summers, Chief Operating Officer at Wintershall Dea. "With the sale of our interests in Brage and Ivar Aasen, we are further strengthening our focus in Norway on gas production. Here we already have a strong position in the country, and our major projects Dvalin and Njord, that are planned to come on stream by the end of 2022, will add further gas volumes that secure energy supply in Europe”, Summers added.

As part of the agreement, OKEA purchases Wintershall Dea’s 35.2% share in the Brage field and 6.46% share in the Ivar Aasen field, as well as 6% of the Nova development for €108 million (NOK 1.1 billion). In addition, payments linked to the fulfilment of certain conditions are part of the transaction.



FOCUS ON FURTHER GAS VOLUMES


“We remain one of the biggest producers in Norway, and one of the largest exporters of gas, while also robustly shaping our business for the opportunities we see coming on the shelf,” said Managing Director at Wintershall Dea Norge, Michael Zechner. “Through this agreement, we have not only realised value for our assets and exited the operatorship of Brage in favour of a company which specialises in mid-late life fields, we have also gained a valuable partner in our operated Nova license”, Zechner underlined. In Norway, Wintershall Dea will put an even stronger focus on exploration, development, and production in core areas, to continuously develop a low-carbon asset portfolio and position the company within carbon management and hydrogen.

Wintershall Dea's total production in Norway was 159,000 barrels of oil equivalent per day in 2021, more than half of which was natural gas. Volumes from upcoming projects Nova, Njord and Dvalin will add around 70,000 to 80,000 boe/d. Production from Brage and Ivar Aasen totalled around 6,000 boe per day.



STRENGTHENING EFFICIENT AND LOW-CARBON SUBSEA PRODUCTION


Wintershall Dea is moving forward on the Norwegian Continental Shelf as a leading subsea operator with a focus on gas and carbon management projects. The company is committed to having net zero upstream activities by 20301 by increasingly focusing on assets with a low carbon footprint and strict emissions management. The gas-weighted company is already the third largest subsea operator by number of fields in Norway and is now also pursuing carbon management opportunities on the shelf.

Subject to customary approval by authorities the deal is expected to be completed in Q4 2022. The transaction will then be effective retroactively from 1.1.2022.



FIELD SHARES AFTER COMPLETED TRANSACTION:


Brage fieldLocated in the northern part of the North Sea, 123 kilometres west of Bergen, with a water depth of 140 metres.
Discovered in 1980 and production start in 1993.
The field has been developed with an integrated production, drilling and accommodation facility with a steel jacket.
The oil is transported by pipeline to the Oseberg field and further through the Oseberg Transport System (OTS) pipeline to the Sture terminal. A gas pipeline is tied-back to Statpipe.
OKEA will take over Wintershall Dea Norge AS’s entire share (35.2%) as well as the operatorship, with other partners comprising of Lime Petroleum AS (33.84%), DNO Norge AS (14.26%), Vår Energi ASA (12.26%) and M Vest Energy AS (4.44%).



Ivar Aasen fieldLocated at a water depth of 110 metres in the northern part of the North Sea, 30 kilometres south of Grane and Balder.
Discovered in 2008, and the plan for development and operation (PDO) was approved in 2013. Production started in 2016.
The development includes a production, drilling and housing facility (PDQ) with a steel substructure and a separate jack-up rig for drilling and completion. Ivar Aasen is powered by electricity from Edvard Grieg and will be supplied with power from shore as part of the joint development of Utsira High expected to commence in late 2022.
Aker BP is the operator (34.79%), with other partners comprising Equinor Energy AS (41.47%), Spirit Energy Norway AS (12.32%), Lundin Energy Norway AS (1.39%), M Vest Energy AS (0.80%) and after the transaction has been completed OKEA will own 9.23%.



Nova fieldLocated in the northern part of the North Sea, 45 kilometres west of Florø and 17 kilometres southwest of the Gjøa field with a water depth of 370 metres.
Nova was discovered in 2012, and the plan for development and operation (PDO) was approved in 2018. The development consists of two four-slot subsea templates tied back to the Gjøa host platform wherefrom Nova will be provided with green power from shore. The subsea installation scope was finalised in 2021.
The field is under development, and production is planned in the second half of 2022.
The well stream will be routed to the Gjøa platform for processing and export. The oil will be transported further through the Troll Oil Pipeline II to the Mongstad terminal, and the gas will be exported via the Far North Liquids and Associated Gas System (FLAGS) pipeline to St Fergus in the UK.
After the transaction has been completed Wintershall Dea Norge AS as the operator will own 39%, with other partners comprising OKEA (6%), Sval Energi AS (25%), Spirit Energy Norway (20%) and ONE-Dyas Norge AS (10%).

Petrobras and Equinor start production on IOR project at Roncador, Brazil

Petrobras, the operator, and Equinor successfully started production from the first two wells of the increased oil recovery (IOR) project at Roncador.
 

This represents an important milestone in the development of the field, increasing recovery rates, adding valuable production and demonstrating the potential to leverage new technology.
 

The two wells are the first of a series of IOR wells to reach production. Start-up is almost five months ahead of schedule and at half of the planned cost. The wells add a combined ~20,000 barrels of oil equivalent per day to Roncador, bringing daily production to approximately 150,000 barrels and reducing the carbon intensity (emissions per barrel produced) of the field.


Through this first IOR project, the partnership will drill 18 wells, which are expected to provide additional recoverable resources of 160 million barrels. Improvements in well design and the partners’ combined technological experience are the main drivers behind the 50% cost reduction across the first six wells, including the two in production.


Roncador is Brazil’s fifth largest producing asset and has been in production since 1999. Petrobras is the operator of the field (75% equity) with Equinor (25% equity) entering the project in 2018 as a strategic partner.


“This milestone demonstrates the partnership’s ability to increase production and value through technology. We will continue combining our capabilities to improve recovery from Roncador and extract further value from the field. Petrobras will leverage its experience as one of the largest deep-water operators and pre-salt developers in the world and Equinor will draw on its technology, expertise and decades of experience in IOR on the Norwegian Continental Shelf,” says Veronica Coelho, Equinor country manager for Brazil.



In addition to the planned 18 IOR wells, the partnership believes it can improve recovery further and aims to increase recoverable resources by a total of 1 billion barrels of oil equivalent. The field has more than 10 billion barrels of oil equivalent in place, under a license lasting until 2052. The strategic alliance agreement also includes an energy efficiency and CO2 emissions reduction program for Roncador.

 

MOL divests Upstream assets in the UK

 MOL today signed an agreement with Waldorf Production Limited (“Waldorf”) covering the sale of its entire Upstream portfolio in the United Kingdom.

The divested offshore assets include MOL’s 20% stake in the Catcher field, a 50% stake in Scolty & Crathes and a 21.8% stake in Scott as well as stakes in a number of other licences. MOL’s UK working interest production peaked above 18 mboepd in 2019 and has been falling in the last two years, accordingly Q4 2021 production was marginally above 12 mboepd. MOL’s corresponding proved and probable reserves (SPE 2P) amounted to 14.9 MMboe at the end of 2021.

Waldorf offered a base cash consideration of USD 305mn, which is subject to customary purchase price adjustments and is based on an economic effective date of January 1, 2021. In addition, the agreement contains an earn-out scheme mainly dependent on oil prices during 2022-2025.

As a result of the transaction, Waldorf will retain all future field abandonment liabilities such that on completion MOL will derecognise provisions of around USD 350mn. Furthermore, MOL’s average lifting cost will improve following completion of the transaction, as the production costs of the UK assets exceed the average lifting costs of the rest of MOL’s E&P portfolio.

The closing of the transaction is subject to obtaining necessary approvals and is expected to take place in the second half of 2022.

List of divested assets:  

• Greater Catcher Area 20.00%
  Scott 21.83%
  Telford 1.59%
  Rochelle 20.71%
  Scolty & Crathes 50.00%
  Broom 29.00%
  Cladhan 33.50%*
  Brent Pipeline System 1.77%
  Sullom Voe Terminal 0.72%

TotalEnergies sells minority interests in West of Shetland fields

TotalEnergies has signed an agreement to sell to Kistos Energy Limited a 20% interest in the Greater Laggan Area fields and in the Shetland Gas Plant in the UK, as well as interests in several nearby exploration licenses.

The transaction price includes a firm consideration of 125 M$, as well as two contingent payments, the first one up to 40 M$ depending on the gas price in 2022, and the second one in the event of development of a discovery on an exploration license.

The transaction is subject to the approval of the UK authorities.

The Greater Laggan Area comprises the Laggan, Tormore, Glenlivet, Edradour and Glendronach fields, located around 140 kilometers west of the Shetland Islands, at water depths of 300 to 600 meters. Development of the fields was launched in 2010 and production start-up was achieved in 2016. Production from the 20% interest sold to Kistos Energy Limited was about 8,000 barrels of oil equivalent per day in 2021.

Following completion of the transaction, TotalEnergies E&P UK Limited will hold a 40% operated interest in the Laggan, Tormore, Glenlivet, Edradour and Glendronach fields, including infield facilities and the onshore Shetland Gas Plant, alongside partners Kistos Energy Limited (20%), Ineos E&P UK Limited (20%) and RockRose UKCS15 Limited (20%).

TotalEnergies withdraws from Myanmar

Following the coup of 1st February 2021 in Myanmar, TotalEnergies has firmly condemned on several occasions the abuses and human rights violations taking place there. Since then, our Company's decisions have been guided by clear principles: to halt all our ongoing projects, but to continue to produce gas from the Yadana field, which is essential for supplying electricity to the local Burmese and Thai population, to protect our employees from the risk of criminal prosecution or forced labour, and, insofar as is materially and legally possible, to limit the financial flows received by the national oil company MOGE.

Despite the actions taken, TotalEnergies has not been able to meet the expectations of many stakeholders (shareholders, international and Burmese civil society organisations), who are calling to stop the revenues going to the Burmese state through the state-owned company MOGE from the Yadana field production. In fact, this is materially impossible for TotalEnergies, as most of the payments for the sale of the gas are made directly by the Thai company PTT, the buyer of the exported gas. TotalEnergies has also approached the French authorities to consider putting in place targeted sanctions that would confine all the financial flows of the various partners to escrow accounts without shutting down the gas production. TotalEnergies has not identified any means for doing so.

While our Company considers that its presence in a country allows it to promote its values, including outside its direct sphere of operations, the situation, in terms of human rights and more generally the rule of law, which have kept worsening in Myanmar since the coup of February 2021, has led us to reassess the situation and no longer allows TotalEnergies to make a sufficiently positive contribution in the country.

As a result, TotalEnergies has decided to initiate the contractual process of withdrawing from the Yadana field and from MGTC in Myanmar, both as operator and as shareholder, without any financial compensation for TotalEnergies. This withdrawal has been notified today to TotalEnergies' partners in Yadana and MGTC and will be effective at the latest at the expiry of the 6-month contractual period. The agreements also stipulate that, in the event of withdrawal, TotalEnergies' interests will be shared between the current partners, unless they object to such allocation, and that the role of operator will be taken over by one of the partners.

During this notice period, TotalEnergies will continue to act as a responsible operator in order to ensure the continuity of gas deliveries for the benefit of the population. TotalEnergies has indicated to its partners its willingness to ease the transition to the new operator and facilitate the transfer of staff who so wish.

***

About TotalEnergies in Myanmar

TotalEnergies has been a partner (31.24%) and operator of the Yadana gas field (Blocks M5 and M6) in Myanmar since 1992, alongside its partners Unocal-Chevron (28.26%), PTTEP (25.5%), a subsidiary of the Thai national energy company PTT, and the Burmese state-owned company MOGE (15%).

The Yadana field produces around 6 billion cubic meters per year of gas of which about 70% is exported to Thailand where it is sold to the national company PTT and 30% to the national company MOGE for domestic use. This gas helps to provide about half of the electricity in the Burmese capital Yangoon and supplies the western part of Thailand. Gas is exported to Thailand through a pipeline operated by MGTC that carries gas from the Yadana field to the Burmese-Thai border, over 400 kilometers. The shareholders of MGTC are the same as the partners in the Yadana field and in the same proportions.

TechnipFMC Awarded Integrated EPCI (iEPCI™) Contract by Equinor

TechnipFMC (NYSE: FTI) (PARIS: FTI) has been awarded an integrated Engineering, Procurement, Construction and Installation (iEPCI™) contract(1) for Equinor’s Smørbukk Nord development.

The contract covers a high-pressure, high-temperature subsea production system and associated equipment for a brownfield tieback in the Åsgard field in the Norwegian Continental Shelf, where TechnipFMC has a large installed base. The award follows front end engineering and design work on the project in 2021.

Jonathan Landes, President, Subsea at TechnipFMC, commented: “Our ability to deliver this optimized solution for Equinor is possible due to our close collaboration with the client, portfolio of subsea equipment, and integrated execution model. We’re delighted to be once again delivering an iEPCI™ project for Equinor.”
The installation campaign will use TechnipFMC’s battery hybrid vessel, which will reduce greenhouse gas emissions through reduced fuel consumption.

Eni awarded five Exploration Licenses in Egypt

Eni has been awarded five new exploration licenses by the Egyptian Ministry of Petroleum. The licenses, four of which as Operator, are in the Egyptian offshore and onshore, and follow the successful participation to the 2021 competitive “Egypt International Bid Round for Petroleum Exploration and Exploitation” which was previously announced by the Egyptian General Petroleum Corporation and the Egyptian Natural Gas Holding Company through the Egypt Exploration and Production Gateway.

The licenses are located in the Eastern Mediterranean Sea (Block “EGY-MED-E5” in partnership with BP 50%-50% and Block “EGY-MED-E6” IEOC 100%), in the Gulf of Suez (Block “EGY-GOS-13” IEOC 100%) and in the Western Desert (Blocks “Egy-WD- 7” in partnership with APEX 50%-50% and “EGY-WD-9” IEOC 100%) with a total acreage of about 8,410 sqkm. The licenses are placed within prolific basins with proved petroleum systems able to generate liquid and gaseous hydrocarbons and can also rely on nearby existing producing and processing facilities and on a demanding market that will allow a quick valorization of the potential exploration discoveries.

The bid results are aligned with Eni’s strategy to keep exploring and producing gas to sustain the Egyptian domestic market and contribute to LNG export, thanks to the recent restart of the Damietta LNG plant.

Eni has been present in Egypt since 1954 and is currently the country's main producer with equity hydrocarbon production of around 350,000 barrels of oil equivalent per day.