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This week, Noble picked up more work for a pair of CJ70 jackups in the North Sea and for a semisubmersible in Colombia. Meanwhile, Valaris took delivery of two newbuild 7th generation drillships, which will be stacked in Las Palmas until they secure contracts.

In case you missed it, you can access our previous Rig Market Roundup here.


bp has exercised an option to add one well to the work scope of the ultra-harsh environment jackup rig Noble Innovator in the UK sector of the North Sea. The estimated duration of the contract extension is 90 days, which means that the CJ70 unit is now expected to be contracted into December 2024. In addition, the parties have agreed to amend and expand the option structure included in the contract, so that it now contains options to extend the contract by up to six additional wells at pre-agreed dayrates. The Noble Innovator is currently operating for bp in the UK North Sea under a contract awarded in December 2022. The work started at the beginning of June 2023, following the rig’s special periodic survey (SPS) in Aberdeen.

Harbour Energy has exercised an option to add up to three months of well intervention services to the firm contract of the 492-ft ultra-harsh environment jackup rig Noble Intrepid at the Judy field in the UK sector of the North Sea. Harbour Energy awarded a 10-month contract to the CJ70 unit in early August 2023. The contract included options to add up to five months of accommodation and well intervention services. Specifically, one three-month option for well intervention services at $120,000 was included and two one-month options for accommodation services at a dayrate of $95,000. This latest addition to the rig’s backlog means that the Noble Intrepid is now expected to be contracted with Harbour into December 2024. Options to add up to two months of accommodation services remain on the contract. The Noble Intrepid started mobilising for the Harbour Energy contract earlier in December.

Tower Resources has executed a contract with Borr Drilling for the 400-ft jackup Norve to drill the NJOM-3 well in the Thali licence offshore Cameroon. Norve is currently under contract to BW Energy offshore Gabon. BW Energy recently exercised options for the unit which could keep it working until June 2024. Tower Resources expects the rig to be available in Cameroon between April and August 2024, following the completion of its work with BW Energy. Subject to rig availability, Tower Resources anticipates that the NJOM-3 well will be spudded in Q2 or Q3 of 2024, with the expected date range for the rig’s availability narrowed as it draws nearer. The contract is also subject to conditions precedent concerning the final documentation of the company’s Thali licence extension and the prepayment of a portion of the expected rig hire. Tower Resources stated: “Other terms of the contract are confidential, but the company can confirm that the contracted dayrate for the rig is in line with the company’s latest cost projections.” Tower Resources is now working to finalise documentation of the Thali licence extensions with Cameroon’s Ministry of Mines, Industry, and Technological Development. Tower Resources Chairman and CEO Jeremy Asher stated that the company will also “move our farm-out discussions with multiple parties towards a conclusion, we hope during the first quarter of 2024. As we have explained in the past, our plan is to fund the well primarily with asset-level financing, and we still believe that is realistic.” Tower Resources intends to raise gross proceeds of around GBP 600,000 through subscriptions for approximately 3,000,000,000 ordinary shares.

TotalEnergies has exercised its first option for the Northern Ocean-owned 10,000-ft semisubmersible Deepsea Mira, extending the rig’s contract for work offshore West Africa by 180 days into the fourth quarter of 2024. Northern Ocean stated that the exercised option provides between $68 million and $75 million of additional revenue backlog, excluding bonuses, reimbursables or other undeclared options. Under the contract for the rig fixed in late December 2022, TotalEnergies has a further 90-day option for Deepsea Mira available. Deepsea Mira, which is managed by Odfjell Drilling, began work for TotalEnergies offshore Namibia in June 2023. While TotalEnergies has used the rig in Namibia since then, the original contract is for multiple countries. TotalEnergies has interests in multiple countries in Africa, including South Africa, Angola and Nigeria. The 7,500-ft Deepsea Bollsta, another semisubmersible owned by Northern Ocean, has been working for Shell offshore Namibia. Deepsea Bollsta is scheduled to finish work with Shell in June 2024 after the company elected not to exercise options.

Petrobras has awarded Noble Corporation a contract for the 10,000-ft semisubmersible Noble Discoverer to drill offshore Colombia. The contract is expected to start in Q2 2024 and has a firm duration of 300 days with an option to extend by 390 days. Petrobras is understood to be using the Noble Discoverer for appraisal drilling on the Tayrona Block, following up the 2022 Uchuva-1 natural gas discovery. Noble Discoverer is currently operating offshore Colombia for Ecopetrol, drilling the Orca Norte-1 well. The rig began work with Ecopetrol in November 2023 and is expected to continue this work into January 2024.

Drilling Activity and Discoveries

Mubadala Energy has made a major gas discovery in South Andaman, about 100 kilometres offshore North Sumatra, Indonesia. Mubadala Energy said that with potential for over 6-TCF of gas-in-place and for multi-TCF expansion within the broader structure, this is “one of the most significant Southeast Asia discoveries for many years.” The discovery is Mubadala Energy’s second consecutive successful well in the Andaman area. Mubadala Energy is the operator of the South Andaman Gross Split PSC, and this is the first deep water well operated by the company, drilled to a depth of 13805 ft in ~3960 ft of water. The well encountered an extensive gas column with a thickness of over 230 metres in an Oligocene sandstone reservoir. A complete data acquisition, including wireline, coring, sampling, and production test (DST) were conducted. The well successfully flowed over 30mmscf/d of excellent gas quality, Mubadala Energy said. Harbour Energy, which owns a 20% stake in the South Andaman licence, said that Layaran-1 was the first of a four-well exploration campaign targeting the same Oligocene play as the successful Timpan-1 well drilled on Andaman II (Harbour operator, 40 percent) in 2022. Harbour Energy said that the rig—Seadrill’s 10,000-ft West Capella drillship—would next move to drill the Harbour-operated Halwa and Gayo wells on Andaman II.

Valeura Energy has completed an infill drilling campaign at its Nong Yao offshore oil field, in the Gulf of Thailand and has moved the drilling rig to the Wassana field. Using Borr Drilling’s 350-ft jackup Mist, Valeura drilled four wells at the Nong Yao A wellhead processing platform, including three production-oriented development wells and one appraisal well. The development wells have encountered targets in line with pre-drill expectations and have been brought online as producers. The appraisal well was designed to delineate the extent of certain reservoir intervals in the field that are currently not producing. Valeura said that results from the appraisal well had exceeded expectations, with the well confirming approximately 50’ of new net oil pay over several intervals. The company anticipates this will give rise to between two and four additional development targets, which will form the basis of a future infill drilling campaign. The jackup rig has now been mobilised to the Wassana field, where it is currently on location and being positioned to start drilling a programme of three production-oriented development wells. After this, the rig will return to Nong Yao in Q1 2024 to begin the development drilling at Nong Yao C accumulation. The rig has a firm contract with Valeura until September 2024, with an extension option that could, if exercised keep the rig busy until the end of 2025.


Woodside has submitted an environment plan (EP) for the drilling and subsea installation as part of the Julimar development Phase 3, offshore Western Australia. Woodside proposes to develop the Julimar Development Project Phase 3 (JDP3) wells and subsea infrastructure, which will connect to the existing Julimar Field Production System. This will involve the drilling of up to four wells in the Julimar field and one well in the Penfolds prospect, located in WA-49-L. The plan also includes subsea installation, pre-commissioning, and cold commissioning activities up to the point of introduction of hydrocarbons. Wells will be drilled by either a moored semi-submersible MODU or a hybrid MODU with both moorings and dynamically positioned (DP) systems. The hybrid MODU may operate on DP some or all of the time, as required. Drilling is anticipated to take 60 days per well and could occur any time of year, according to the Australian offshore energy regulator NOPSEMA, which is currently assessing Woodside’s EP. The water depth in the area ranges between 120 and 300 metres. If required, Woodside may intervene or workover any of the JDP3 development wells drilled under the EP, and the JULA or Brunello Manifold production wells. Other contingent activities that Woodside may need to perform during drilling include well abandonment, re-spud, side-track, well suspension, leaving wellhead assembly in-situ, sediment mobilisation and relocation, venting, well test/unload, and emergency disconnect. According to Woodside’s EP, the Petroleum Activities Programme (PAP) is currently anticipated to start from Q3 2024, with drilling and completions activities taking approximately 60 days per well, including mobilisation, demobilisation, and contingency activities. Subsea installation activities are planned to start in Q1 2025 and are likely to take 60 days, with production targeted for the second half of 2025. The wells may be developed as a single campaign or a second, shorter campaign may be required in 2026, with production for those second campaign wells expected to start in 2026 or 2027. If required, contingent well intervention activities are expected to take approximately 30 days.

Following the Demerara Bid Round, which ended on 31 May 2023, TotalEnergies, Shell, and Petronas have signed production sharing contracts (PSCs) with state oil company Staatsolie for blocks offshore Suriname. TotalEnergies, in partnership with QatarEnergy and Petronas, has signed a PSC for Block 64. The supermajor will operate the block, holding a 40% stake, while QatarEnergy and Petronas will each have a 30% interest. TotalEnergies has other interests in Suriname, including operations in Block 58, where five discoveries have been made and the company is currently engaged in development studies with its partner APA Corp. TotalEnergies is also the operator of blocks 6 and 8 offshore Suriname with a 40% interest, in collaboration with QatarEnergy with a 20% interest and Staatsolie subsidiary Paradise Oil Company with a 40% interest. Shell subsidiary BG International made a joint bid for Block 65 with QatarEnergy. Shell will act as operator of Block 65 with a 60% interest while QatarEnergy holds the remaining 40% interest. Petronas made a solo bid and has signed a PSC for Block 63. The exploration period for the blocks consists of three phases and will last seven years. An exploration well will be drilled in Block 64 and Block 65 in the first phase of this period, which will last three years. In Block 63 the first exploration well follows in the second phase of the exploration period. In the event of an oil or gas discovery that is declared commercial, Staatsolie has the right to participate in all three blocks for a maximum of 20% from the development period.

Shell and its partner Deltic Energy have made a positive well investment decision for the drilling of the Pensacola appraisal well. The partnership also remains on track to drill the Selene exploration well in the UK North Sea in 2024. The Pensacola discovery is located in Licence P2252 and the Selene prospect is situated in the Southern North Sea Licence P2347. Both licences are operated by Shell, with Deltic Energy participating as a partner. The rig tendering process is ongoing. The JV has now finalised the positive well investment decision on Licence P2252 and approved the 2024 work programme and budget that allows for drilling the Pensacola appraisal well in late 2024. Meanwhile, the geotechnical site investigation works on the preferred surface location of the Selene exploration well has been successfully completed and the vessel has been demobilised from site. The results of this work will be incorporated into the operational drilling plan. The well remains on track to be drilled in Q3 of 2024.

Australian offshore energy regulator NOPSEMA has accepted Santos’ environment plan (EP) for development drilling at the Barossa field. The field is located in Commonwealth waters approximately 285 kilometres offshore, north-north west from Darwin, Australia. The petroleum activities are part of the Barossa gas and condensate development, comprising a floating production, storage and offloading (FPSO) facility, subsea production wells, supporting subsea infrastructure, and a gas export pipeline. Santos’ previous EP was set aside after a legal challenge from Tiwi Islanders, which led to Santos having to file a revised plan. The approved EP provides for drilling and completing up to eight production wells using a semisubmersible drilling rig. More specifically, six subsea production wells are planned to be drilled and completed around the future locations of three subsea production manifolds, with two wellheads adjacent to each manifold. If required, up to two contingency production wells could be drilled and completed (eight wells in total) due to gas deliverability issues from a well. Water depths in the area range from 204 metres to 376 metres. The planned duration for drilling and completion of each well is estimated to be approximately 90 days of continuous well operations (24 hours per day, seven days per week) and the total duration for the planned 6-well campaign is estimated to be approximately 2 years, subject to the availability of vessels and the functional supply chain. This activity duration includes positioning (towing) and anchoring of the MODU, drilling, completion, and well flowback activities. According to information on NOPSEMA’s website, the development drilling is expected to start in 2023, and the first gas production is targeted for the first half of 2025.

Petrobras has issued a second re-bid to contract a jackup drilling rig to run P&A operations and assist with the decomissioning of fixed platforms at several mature development fields in Brazil. The rig is set to operate in shallow waters in the Ceara, Potiguar, and Sergipe-Alagoas basins off northeast Brazil. Petrobras has kept the terms and conditions of this new tender very similar to the past ones, looking for one independent-leg cantilever jackup rig, with water depth capacity from 12 to 50 metres (39 to 164 ft). The operator is offering a 1,460-day contract with a 150-day option, totaling 1,610 days, and mobilisation of 210 days. Bids are due 2 January 2024.

The government of Sierra Leone has awarded six offshore blocks to F.A. Oil Limited, following the conclusion of the country’s fifth licensing round in late September 2023 and negotiations for a petroleum license agreement. F.A. Oil has been awarded Blocks 53, 54, 55, 71, 72 and 73. The chairman and CEO of F.A. Oil is Apostle Folorunso Alakija, a Nigerian businessperson who is also the vice chairman of Nigerian oil exploration and production company Famfa Oil Limited. Famfa Oil is a partner in the Chevron-operated Agbami field offshore Nigeria.

The US Bureau of Ocean Energy Management (BOEM) held Gulf of Mexico Oil and Gas Lease Sale 261 on 20 December 2023, generating $382,168,507 in high bids for 311 tracts covering 1.7 million acres in federal waters of the Gulf of Mexico. A total of 26 companies participated in the lease sale, submitting 352 bids totaling $441,896,332. Lease Sale 261 offered 13,482 unleased blocks on 72.7 million acres in the Western, Central and Eastern Planning Areas of the US GOM. Shell submitted 65 high bids in the lease sale; this was the largest number of total high bids and came in at $69,039,820. Other companies involved included Anadarko with 49 high bids, Repsol with 45, Chevron with 28, BP with 24, Red Willow Offshore with 22, Hess with 20, Woodside Energy with 18, Houston Energy with 17 and Equinor with 13. Occidental subsidiary Anadarko submitted the highest bid on a block with a $25,500,085 bid on Mississippi Canyon Block 389. The block also received the greatest number of bids, with five bids submitted.

Mobilisation/Rig Moves

Following the completion of operations in the North Sea, Stena Drilling’s 5,000-ft semisub Stena Spey has arrived in Invergordon, Scotland, where it’s going to be warm stacked. The semisub had been working on the K2 exploration well for Ithaca Energy from June until late October 2023, discovering hydrocarbons in the reservoir in the Forties member sandstones, with 45 feet of net thickness. However, after losing anchors during Storm Babet in late October, the rig moved to CCB yard in Ågotnes, Norway. After about a month there, the rig returned to K2 location in late November. The rig has now demobilised to Invergordon, where it’s being warm stacked as it has no further commitments.

Constellation 12,000-ft drillship Brava Star has begun a new three-year contract with Petrobras offshore Brazil. The rig’s new contract was fixed in late 2022 and will keep it working into December 2026. A mutually agreed option to extend the rig’s contract by a further three years is also available. The drillship’s previous contract with Petrobras offshore Brazil ran from March 2021 to September 2023.

Borr Drilling’s Idun, a Keppel FELS Super B Bigfoot Class jackup, has arrived at Crystal Offshore Singapore yard to undergo activation works ahead of a new contract. Upon the contract preparations being completed, the 350-ft jackup will mobilise for its two-year contract with PTTEP in Thailand. This is expected to keep it busy until January 2026, with options to extend. The rig’s previous contract with Petronas in Malaysia ended in late 2023.

Other News

Baron Oil’s subsidiary SundaGas has entered into a memorandum of understanding with TIMOR GAP to transfer a 15% stake in the Chuditch PSC, offshore Timor-Leste, to TIMOR GAP. With this agreement, which is subject to certain conditions being met, TIMOR GAP’s interest in the project will increase to 40%, with SundaGas retaining the operatorship and holding a 60% working interest in the Chuditch PSC. Baron said that the transaction would have a value to Baron of approximately US$8.5 million in reimbursement for prior costs and in the offset of future spending. The operational plan remains to drill and flow test the Chuditch-2 appraisal well in late 2024, subject to rig and drilling services availability and the completion of drill financing, Baron Oil said. A location has been selected for the drilling of the Chuditch-2 appraisal well and significant progress has been made in preparation for the drilling campaign, the company said. The cost of the Chuditch-2 appraisal well is anticipated to be approximately US$32 million, including the costs of a full production flow test and mobilisation and demobilisation costs for the rig and equipment. The previously indicated drilling cost estimate of US$24 million was prepared in late 2021, prior to recent inflationary pressures and in a looser market for drilling services in the region. Earlier indications of costing also excluded mobilisation and certain other costs.

The Biden Administration has published the final 2024–2029 National Outer Continental Shelf Oil and Gas Leasing Programme with “the fewest oil and gas lease sales in history.” The Inflation Reduction Act prohibits the US Bureau of Ocean Energy Management (BOEM) from issuing a lease for offshore wind development unless the agency has offered at least 60 million acres for oil and gas leasing on the OCS in the previous year. The latest oil and gas lease sale programme schedules three oil and gas lease sales in the Gulf of Mexico Programme Area in 2025, 2027, and 2029. There are no planned oil and gas lease sales in the Atlantic, Pacific, and Alaskan waters These three lease sales are the minimum number that will enable the Interior Department’s offshore wind energy programme to continue issuing leases in a way that will ensure continued progress towards the administration’s goal of 30 gigawatts of offshore wind by 2030, the Department of Interior said Friday. According to the DoI, the areas considered for leasing and number of lease sales in the 2024-2029 Final Programme have been significantly narrowed from the previous Administration’s original proposal of 47 lease sales off all coastal areas in the United States.

Finder Energy’s licence P2610 contains the large Boaz gas condensate prospect, which is estimated to contain gross mean prospective resources of 748 Bcf of gas and 81 MMbbl of condensate. Finder Energy announced it had received a priority offer in the 33rd UK Offshore Licencing Round for the licence containing the Boaz prospect in early November 2023. Finder’s bid was made in 50/50 partnership with Equinor with Finder nominated as the Licence Administrator (Operator). The licence is located within the South Viking Graben in the Central North Sea adjacent to the UK/Norway Median line. It is close to host facilities operated by Equinor, including Gina Krog and Sleipner. Equinor is currently fast-tracking the development of the Eirin field, which will connect to Sleipner via Gina Krog, and is also seeking to extend the life of the Sleipner facilities by actively exploring and developing around this area. This forms part of the company’s motivation for participating in the joint bid for the licence. Finder is currently finalising the process with the regulator to accept the award of P2610 with an initial firm work programme comprising geotechnical studies in Phase A with a duration of 4 years prior to a drill or drop decision to enter Phase C for a further 2 years. The geotechnical studies in Phase A are designed to derisk the Boaz prospect, increase the COS and attract a farmin partner. Once the geotechnical studies are completed, Finder will update the prospective resource and geological risk.

Mexican conglomerate Grupo Carso’s subsidiary Zamajal S.A. de C.V. has made an agreement with PetroBal to acquire 100% of its subsidiary PetroBral Operaciones Upstream, which has a 50% interest in the Ichalkil- Pokoch oil fields, located in Area Contractual 4 off the coast of Campeche, Mexico. The closing of the transaction is subject to certain conditions, including authorization from Mexican regulatory authorities. A consortium of Fieldwood Energy and Delta 1 was awarded the shallow water area in January 2016. Lukoil acquired Fieldwood Energy’s 50% operating interest in early 2022. Area 4 consists of two blocks containing the Ichalkil and Pokoch oil fields in around 98 to 148 ft (30 to 45 m). In late September 2023, Grupo Carso subsidiary Zamajal acquired 49.9% of the Talos Energy company Talos Energy Mexico, which has a 17.4% interest in the Zama field offshore Mexico. Pemex is the operator of Zama with a 50.4% interest, while Wintershall Dea has a 19.8% interest and Harbour Energy has a 12.4% interest.

Shell announced the Final Investment Decision (FID) for the deep-water Sparta Development project in the US Gulf of Mexico. The project will be Shell’s 15th deep-water host in the Gulf of Mexico and the first development to produce from reservoirs with pressures up to 20,000 pounds per square inch. The Sparta project will span four Outer Continental Shelf (OCS) blocks in the Garden Banks area in the US Gulf of Mexico (US GoM) and will feature a semisubmersible production host in water depth of 4,700-ft (1,400m) with initially eight oil and gas producing well. Estimated recoverable resource volume is 244 million boe. Production is scheduled to begin in 2028. Sparta is expected to reach 90,000 boe per day at peak production and has an estimated recoverable resource volume of 244 million boe. TotalEnergies withdrew from the project (then called North Platte) in February 2022, while partner Equinor (49% WI) noted its intention to move forward with the project. The 12,000-ft ultra-deepwater drillship Valaris DS-11 was initially awarded a 3.5-year contract for the North Platte field development, contingent that FID was passed. The drillship was to undergo significant upgrades, including the installation of 20,000psi well control equipment. However, Equinor later terminated the contract. In June 2022, Shell acquired 51% participating interest and operatorship of the North Platte project and renamed it Sparta.

Longboat Energy has completed the acquisition of Topaz Number One, increasing its operating stake in the Production Sharing Contract over Block 2A offshore Sarawak, Malaysia, to 52.5%. Block 2A is located offshore Sarawak, north-west of the prolific Central Luconia hydrocarbon province, covering around 12,000 km2 in water depths between 100 – 1,400 metres (328 – 4593 ft). The block contains the “giant” Kertang prospect, which is understood to hold significant volume potential, representing “multiple trillions of cubic feet (TCF) of gas in stacked reservoirs.” According to Longboat, having a 52.5% operating stake should simplify the process towards a positive well decision and the potential introduction of an additional funding partner before drilling. In February 2023, Longboat announced it had been awarded its initial 36.75% operating interest in Block 2A alongside partners Petronas Carigali (40%), Petroleum Sarawak Exploration & Production Sdn. Bhd. (7.5%) and Topaz Number One Limited (15.75%). As part of the transaction for the Topaz acquisition, announced Thursday, the initial consideration is to be satisfied through an issue of new ordinary shares of 10 pence each in Longboat, equivalent to $100,000 based on the average closing price of such ordinary shares in the preceding ten days, representing 441,470 ordinary shares. There are two further contingent payments to be made: firstly an amount of $125,000 payable in cash or through a further issue of ordinary shares of an equivalent value, upon an exploration well being committed on Block 2A or a farm-out; and a further contingent amount of up to $3,000,000 payable in cash or through a further issue of ordinary shares of an equivalent value, upon a discovery being made on Block 2A, depending on the resource size and the growth in the price of the ordinary shares measured over a two-year period.

Valaris Limited has exercised its options and taken delivery of newbuild 12,0000-ft drillships Valaris DS-13 and Valaris DS-14 from Hanwha Ocean in South Korea for an aggregate purchase price of around $337 million. Valaris DS-13 and Valaris DS-14 will be mobilised from South Korea to Las Palmas in the Canary Islands, where they will be stacked until they secure contracts. Valaris stated that the purchase of the rigs is expected to increase its fourth quarter 2023 capital expenditures by around $355 million, representing the purchase price for the rigs and costs associated with preparing the rigs to mobilise from South Korea to Las Palmas. In addition, the company anticipates 2024 capital expenditures of around $35 million primarily related to mobilisation costs. Valaris DS-13 and Valaris DS-14 are 7th generation drillships of the DSME 12000 design and have maximum drilling depths of 40,000 ft. The rigs were originally ordered in 2012 and 2013 by Atwood Oceanics and had their deliveries postponed in late 2016. Atwood Oceanics was acquired by Ensco in 2017. Ensco merged with Rowan Companies in 2019 to form Valaris.

Harbour Energy has reached an agreement with BASF and LetterOne, the shareholders of Wintershall Dea, for the acquisition of substantially all of Wintershall Dea’s upstream assets for $11.2 billion. The target portfolio includes all of Wintershall Dea’s upstream assets in Norway, Germany, Denmark, Argentina, Mexico, Egypt, Libya, and Algeria as well as Wintershall Dea’s CO2 Capture and Storage (CCS) licences in Europe. Wintershall Dea’s Russian assets are excluded. The acquisition will add 1.1 bnboe of 2P reserves at c.$10/boe and more than 300 kboepd of production at c.$35,000/boepd. The acquisition is expected to transform Harbour into one of the world’s largest and most geographically diverse independent oil and gas companies, adding material gas-weighted portfolios in Norway and Argentina and complementary growth projects in Mexico. Post completion, Harbour will continue to be Chaired by R. Blair Thomas, with Linda Z. Cook and Alexander Krane remaining as Chief Executive Officer and Chief Financial Officer, respectively. All target portfolio employees will be transferred to Harbour on completion. In addition, Harbour intends to take on some employees from Wintershall Dea’s corporate headquarters. The acquisition constitutes a reverse takeover for the purposes of the Listing Rules for Harbour, with the intention that Harbour applies to retain its premium London listing on completion. The acquisition is subject to, amongst other things, regulatory, antitrust and foreign direct investment approvals, as well as Harbour shareholder approval. The completion is expected to occur in Q4 2024.

EnQuest has reached an agreement with Viaro Energy’s subsidiary, RockRose, to sell a 15% working interest in each of the Bressay field and the EnQuest Producer FPSO, both located in the UK North Sea. Bressay lies in the Northern North Sea and it is one of the largest undeveloped oil fields in the UKCS, with an estimated potential to extract around 200 million boe. Under the terms of the agreement, total consideration is £46 million (∼$58.4m) and will involve an initial payment by RockRose to EnQuest of £34.75 million, which will be used for general corporate purposes, with the remaining £11.25 million to be paid from future Bressay cash flows. The early production facility development under review has capital expenditure estimated at £600 million, with £90 million being RockRose’s net share. RockRose will pay its equity share of capital expenditure pursuant to an agreed schedule and approvals. Pending regulatory approval of the transaction, EnQuest will hold the remaining 85% stake in the field and is the operator. Viaro’s partnership with EnQuest provides support for the Bressay development and paves the way for a Field Development Plan (FDP) to be advanced in line with EnQuest’s ongoing plans. EnQuest continues to progress the development of the wider Kraken area, including a Bressay gas tie-back solution to reduce Kraken emissions, as well as an early production solution project at Bressay.

Karoon Energy has completed the acquisition of interests in the US Gulf of Mexico from LLOG. Karoon has acquired a 30% stake in the Who Dat and Dome Patrol oil and gas fields and associated infrastructure, an approximately 16% stake in the Abilene field and varying interests in adjacent exploration acreage. Karoon paid $684 million to LLOG (comprising the purchase price of $720 million less a $36 million deposit already paid). In addition, payments totaling $15 million were made in establishment and underwriting fees relating to the debt and equity processes. Karoon has received the economic benefit of the 30% interest in the acquired assets since 1 October 2023. Karoon said that the acquired producing assets, together with the appraisal and exploration opportunities, would help offset the natural decline from its Baúna Project in Brazil.

Image credit: Ecopetrol

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