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On 29 November 2018, Discover Exploration Ltd announced that it has signed a binding agreement with Bahari Resources Ltd to acquire its entire issued share capital. Bahara Resources holds a 40% interest in the Blocks 35, 36 and 37 licence. At the same time, Discover Exploration and Tullow Oil announced a deal whereas Discover Exploration agreed to farm-out 35% interest of its initial 60% interest in the licence to Tullow Oil. Following the governmental approval of both deals, Tullow will operate the licence with a 35% interest and Discover Resources will hold the remaining 65% (25% through its local subdisiary Discover Exploration Comoros B.V. and 40% through Bahari Resources Ltd. The 17,853 sq km acreage is located in the Outer Rovuma Fan, in water depth between 2,500 and 3,000 m about 100 km to the east of the Mozambique large gas discoveries. The licence is in its second exploration period that is valid until April 2021. Commitments calls for the acquisition of some 2D or 3D seismic data as well as for the drilling of an exploration well. Earlier in 2018, Discover Exploration released its plans to drill the first exploration well in 2019/2020. The well will test two large stratigraphic prospects that are partially overlapping. The mid-Eocene prospect has a Pmean prospective reso5rce of 5.8 Bbbl (for the oil case) or 3.7 Bboe (for the gas case). The Cenomanian prospect has a Pmean prospective resource of 3.5 Bbbl (oil) or 2.5 Bboe (gas). Background Information The companies were awarded the licence in March 2014. In May 2014 the companies started the acquisition of a 2,330 km 2D infill seismic survey being part of the GX Technology (ION Geoventures) East Africa SPAN programme. The survey was completed in early August 2014. The seismic survey fulfilled the commitments for the initial period that ended in March 2018. The data were reported of excellent quality, and initial interpretation suggested an extension of the Mozambican reservoir play beneath the Comoro acreage. Vast areal extend of Paleocene fan has been interpreted over Blocks 35, 36 and 37, with possible source rock in the oil window. The previous 2D seismic survey in the area was shot in 1H 2011, also part of the East Africa SPAN programme. Commitment for the second exploration phase (2018 to 2021) is to acquire either 2D or 3D seismic data. Commitment for the last and third exploration phase is to drill one exploration well. The Comoros’ acreage is a frontier area. The main potential for O&G business appears to be the eastern extension of the Rovuma Delta where deepwater fan stratigraphic plays are expected to be found. Faulting along the ridge separating the Comoros from East Africa Continent is also known to have created large anticlinal structures

Comoro Islands Discover Exploration Ltd announced that it has signed a binding agreement with Bahari Resources Ltd to acquire its entire issued share capital. Bahara Resources holds a 40% interest in the Blocks 35, 36 and 37 licence. At the same time, Discover Exploration and Tullow Oil announced a deal whereas Discover Exploration agreed to farm-out 35% interest of its initial 60% interest in the licence to Tullow Oil.

On 20 November 2019, the Federal Agency for Subsoil Use held an auction for the Rozovskiy block in Saratov Oblast (Volga-Ural Province). The highest bid of RUB 5.289 million (USD 0.08 million) was offered by company Nizhniy Novgorod Neft. The winner of the auction will obtain a 25-year E&P license. The Rozovskiy block covers 49.9 sq km in the Volga-Urals Basin. The block partially encompasses the Rozovskaya structure. Hydrocarbon resources (category D1) of the block are estimated at 2.9 MMbbl of oil, 10.3 Bcf of gas and 0.4 MMbbl of condensate. The starting price amounted to RUB 1.29 million (USD 0.02 million).

Nizhniy Novgorod Neft won Rozovskiy block in Saratov Oblast.

Local press reports suggest Tamarind has bought a 55% stake in the Galoc field from partner BCP. News is not confirmed and details n/a. Galoc lies off NW Palawan in SC 14C-1 and is run by Galoc Prod. Co. in which BCP has a stake. Field ownership is otherwise complex.

Local press reports suggest Tamarind has bought a 55% stake in the Galoc field from partner BCP. News is not confirmed and details n/a. Galoc lies off NW Palawan in SC 14C-1 and is run by Galoc Prod. Co. in which BCP has a stake. Field ownership is otherwise complex.

Eneco (formerly Ramba Energy) intends to sell its 100% interest in the West Jambi KSO, 1,100 sq km in South Sumatra. Regional targets Talang Akar, Gumai, Air Benakat + Batu Raja fm’s, several leads identified.

Eneco (formerly Ramba Energy) intends to sell its 100% interest in the West Jambi KSO, 1,100 sq km in South Sumatra. Regional targets Talang Akar, Gumai, Air Benakat + Batu Raja fm’s, several leads identified.

Aker BP spudded an exploration well on the Vagar prospect in PL 762 on 19 July 2019 using the “Deepsea Stavanger” S/S. 6608/6-1 targeted a karstified and dolomitised Permian carbonate play with Top Reservoir expected at 2,533 m. The well is located approximately 65 km northeast of Norne and was to be tested in the event of a discovery. Potential reserves, quoted by Aker BP, were 62-130 MMboe. The company believed that the well had a moderate chance of success and, if successful, it would have been a play-opener. TD was reached at 2,754 m. On 11 August 2019 the well was abandoned and results are expected shortly. PL 762 was awarded in APA 2013 and it covers part of the Traena Sub-basin and the Nordland Ridge to the northeast of Urd and Norne. It contains the 1983 dry hole 6609/7-1 drilled by Phillips. This well’s objective was the Upper Paleozoic but the Cretaceous Lange Formation sat directly upon the Zechstein Group, which in turn rested on metamorphic Basement. No sands were present in the Paleozoic and there were only traces of migrated hydrocarbons identified in cuttings from the Cretaceous section. Aker BP ASA (20%) operates PL 762 with Equinor Energy AS (60%) and Petoro AS (20%) as partners.

6608/06-01 (Vagar) exploration (Aker BP 20% op. Equinor 60%, Petoro 20%) in PL 762, P&A with results awaited, targeted a karstified and dolomitised Permian carbonate play

Hibiscus Petroleum has completed its acquisition of 50% participating interest in the 2011 North Sabah Enhanced Oil Recovery Production Sharing Contract (PSC) and the joint operating agreement (JOA) in relation to the PSC.  Following the US$25million acquisition, Hibiscus' unit SEA HIbiscus assumed the role of operator of the North Sabah PSC. The other holders of the PSC are Petronas and Petronas Carigali, while the JOA now stands between SEA Hibiscus and Petronas Carigali.  According to Hibiscus, the North Sabah PSC includes 20 offshore platforms across four producing fields located in the South China Sea, off the west coast of Sabah, and the Labuan Crude Oil Terminal located in the Labuan. 'The North Sabah PSC constitutes our second producing asset, providing the Company with another revenue stream after the Anasuria Cluster. It is an exciting time for Hibiscus Petroleum as we expand and strengthen our technical and operating capabilities, profitability and balance sheet. 'This is an example of Hibiscus Petroleum’s strategy to grow shareholder value by focusing our activities on assets where we believe we can offer a unique value proposition to enhance production from mature assets in regions of our geographic focus,' said Hibiscus Petroleum chairman Zainul Rahim. Hibiscus said the North Sabah PSC will significantly boost the group's production and proven and probable reserves. Location of North Sabah PSCSee related article: Hibiscus buys Shell's interest in four fields offshore Sabah (Oct 2016) Original article linkSource: The Star Online

Hibiscus Petroleum has completed its acquisition of 50% participating interest in the 2011 North Sabah Enhanced Oil Recovery Production Sharing Contract (PSC) and the joint operating agreement (JOA) in relation to the PSC.

Corallian is looking to dilute its 100% in P2493 / blocks 217/12-20, 218/11 + 16 containing the seismically-defined Eocene Sandvoe prospect:

Corallian is looking to dilute its 100% in P2493 / blocks 217/12-20, 218/11 + 16 containing the seismically-defined Eocene Sandvoe prospect:

In late-February 2018, local reports indicated that the government of Santa Cruz Province has awarded 35-year unconventional exploitation concessions to Cia General de Combustibles (CGC) for two of its producing blocks, namely the El Cerrito and Campo Indio Este. The company plans to invest USD 200 million in developing the tight gas reservoir of Tertiary-age Magallanes Formation with 34 wells planned. In addition, CGC will also carry out an exploration program that includes the acquisition of 2,000 sq km of 3D seismic and the drilling of ten new exploration wells.   The El Cerrito and Campo Indio Este blocks are originally part of CGC’s Santa Cruz I concession in onshore Austral Basin covering 42 sq km and 33 sq km of areas, respectively. In November 2017, the Argentinean Government expanded the subsidies in its “Gas Plan” to also cover unconventional gas production from the Austral Basin.

CGC was awarded Campo Indio Este-El Cerrito block.

Following amendments to the list of the areas for offering in the country’s next tender call (Round 2), initially scheduled for 2017, the Department of Geology and Geological Concessions approved the final list of eight areas for offering in a bid round that may now open in 2018. The acreage inventory includes the following blocks: Bochnia (234 sq km), Damnica (1,038 sq km), Debrzno-Czluchow (1,159 sq km), Koszalin-Polanow (1,111 sq km), Sucha Beskidzka-Wisniowa (983 sq km), Szamotuly-Poznan Polnoc (1,138 sq km), Zlotow-Zabartowo (1,070 sq km) and Zarnowiec (1,121 sq km). Seven blocks have mainly conventional exploration targets, while one holds the conventional and unconventional resource potential. Also, on 29 June 2017, the authorities have selected 17 blocks for a subsequent tender (Round 3): Blazowa (270 sq km), Braniewo-Milakovo (788 sq km), Bytow (784 sq km), Chelmno (248 sq km), Chodziez (1,172 sq km), Konin (1,034 sq km), Krolowka (201 sq km), Leszno (1,008 sq km), Orle (423 sq km), Pila (949 sq km), Proszowice W (1,104 sq km), Rudnik-Lipiny (480 sq km), Ryki (1,048 sq km), Sierpowo (669 sq km), Wejherowo (710 sq km), Wetlina (221 sq km) and Zabowo (1,000 sq km). Most blocks display conventional exploration targets. The timing of the round is undecided.

The Department of Geology and Geological Concessions approved the final list of eight areas for offering in a bid round that may now open in 2018. The acreage inventory includes the following blocks: Bochnia (234 sq km), Damnica (1,038 sq km), Debrzno-Czluchow (1,159 sq km), Koszalin-Polanow (1,111 sq km), Sucha Beskidzka-Wisniowa (983 sq km), Szamotuly-Poznan Polnoc (1,138 sq km), Zlotow-Zabartowo (1,070 sq km) and Zarnowiec (1,121 sq km). Seven blocks have mainly conventional exploration targets, while one holds the conventional and unconventional resource potential.

Petrobras has published the teaser promoting the sale of all its equity (100%) in the Merluza + Lagosta fields, shallow waters of the Santos Basin. Merluza comprises the PMLZ-1 platform in WD 135m handling gas + cond since 1993, and hosting Lagosta gas + cond since 2009. Avg production 3,600 boe/d.

Petrobras has published the teaser promoting the sale of all its equity (100%) in the Merluza + Lagosta fields, shallow waters of the Santos Basin. Merluza comprises the PMLZ-1 platform in WD 135m handling gas + cond since 1993, and hosting Lagosta gas + cond since 2009. Avg production 3,600 boe/d.

Location W. of Doina gasfield in XV-Midia West block, WD 75m, ops terminated and GSP Saturn JU released and available. Next well planned Mia-1 in same block, scheduled 2019 using GSP Uranus. BSOG (op), partners Petro Ventures + Gas Plus.

Iulia 1 (BSOG (op), partners Petro Ventures + Gas Plus), W. of Doina gasfield in XV-Midia West block, ops terminated, results n/a. WD=75m

On 31 July 2020 Equinor agreed to sell 40.8125% of its interest and transfer operatorship of licences P234 (block 3/28a), P493 (block 3/28b), P920 (3/27b) and P977 (blocks 9/2a and 9/3a) to EnQuest. A sale and purchase agreement has been signed between the two companies for the licences that host the Bressay heavy oil field. The sale is for an initial consideration of GBP 2.2 million (as a carry against 50% of Equinor's net share of costs) and a further consideration of GBP 11.48 (USD 15 million) will be payable when the Bressay field development plan is approved. The deal is estimated to complete in Q4 2020. Located northeast of Kraken field, the Bressay field was discovered in 1976 with heavy oil and a small gas cap in the Upper Paleocene Teal Sands. The heavy oil has an average API of 12° and a viscosity of 550 cP. An environmental statement was submitted for the field in June 2013 which described the development via 70 development wells, with operations commencing in 2016, first oil in 2018 and peak production was anticipated to take place between 2022 and 2025. However, by November 2013 the development was stated to be delayed and in August 2016 the concept selection was deferred because of market conditions and the need to simplify the development concept. A number of development scenarios are still under consideration, one involves a tie back to Kraken field. Interest in the licences P234, P493, P920 and P977 is held by EnQuest Heather Ltd (40.8125% + operator), Equinor (UK) Ltd (40.8125%) and Chrysaor Ltd (18.375%).

(East Shetland Platform) EnQuest has agreed to acquire 40.8125% and operatorship from Equinor in Bressay heavy oil field licences P234 (3/28a), P493 (3/28b), P920 (3/27b) and P977 (9/2a & 9/3a). Current field partners Equinor UK Ltd (81.625% + Op) and Chrysaor Ltd (18.375%). After completion, new field partners will be EnQuest (40.8125%, op.), Equinor UK Ltd (40.8125%) and Chrysaor Ltd (18.375%).

BHP is reportedly looking to offload its interests in Algeria. It is involved with Eni in the ROD cluster, Berkine Basin, namely : Rhourde Ouled Djemma (ROD) / 402A, Rhourde El Rouni Nord (RERN) / 401A, Rhourde El Attar (RAR) / 402A, Bir Sif Fatima (BSF) / 402, Sif Fatima Nord-Est (SFNE) / 402 and Rhourde Debdeba (TAGI) / 402A, all of which run to 2036. Eni (op), partners BHP (17.65%) + Sonatrach.

BHP is reportedly looking to offload its interests in Algeria. It is involved with Eni in the ROD cluster, Berkine Basin, namely : Rhourde Ouled Djemma (ROD) / 402A, Rhourde El Rouni Nord (RERN) / 401A, Rhourde El Attar (RAR) / 402A, Bir Sif Fatima (BSF) / 402, Sif Fatima Nord-Est (SFNE) / 402 and Rhourde Debdeba (TAGI) / 402A, all of which run to 2036. Eni (op), partners BHP (17.65%) + Sonatrach.

Selva prospect in Podere Gallina block near Bologna, Po Valley, TMD 1,330m, logs suggest a gas-bearing reservoir intersected, 53m gross pay below 1,245m (vertical), well to be tested rigless in January. Main target Pliocene Porto Garibaldi fm, Drillmec HH220 rig. United O+G partly funding the well in exchange for a 20% stake in the 506-sq km permit, partner otherwise Prospex O+G.

Italy (Northwest Peri-Apenninic Foredeep Province) ? op. by PVE (63.0%, UNITED O 20.0%, PROSPEX OG 17.0%) in Podere Gallina block

African Petroleum, an independent oil and gas exploration company with licence interests in four countries offshore West Africa, has announced that its wholly owned subsidiaries European Hydrocarbon and African Petroleum Sierra Leone have signed agreements with the  Petroleum Directorate Sierra Leone to enter into the Second Extension Periods of the SL-03 and SL-4A-10 licences respectively and to modify the work programmes for both licences during these periods.   The Second Extension Period will expire on 23 April 2019 for the SL-03 licence and on 17 September 2019 for the SL-4A-10 licence should the Subsidiary Companies commit, prior to 1 November 2018, to drilling one exploration well in each licence area during the remaining term of the respective licence.  During the next 12 months, the Subsidiary Companies will be utilising State owned well and seismic data, together with existing seismic data, to further derisk the licences prior to deciding to commit to the drilling of an exploration well on each licence (which must be drilled prior to expiry of the respective Second Extension Period, if the Subsidiary Companies commit to drilling).   In accordance with the requirements of the petroleum licence agreements, African Petroleum has relinquished 50% of the SL-03 licence area, reducing the licence area from 1,930km2 to 962km2, and 50% of the SL-4A-10 licence area, reducing the licence area from 1,995km2 to 995km2.   Simultaneously with the approval of the entry into the next licence periods, the Petroleum Directorate Sierra Leone agreed to modify the work programmes and minimum expenditure requirements of the two licences, and to defer the social obligations of the two licences contingent on the drilling of an exploration well on each licence ('Licence Amendments').   The entry into the next licence periods and the Licence Amendments were ratified by the Parliament of Republic of Sierra Leone on the 4 December 2017.   The Subsidiary Companies have been working with ERC Equipoise to re-assess the prospective oil resources on the SL-03 and SL-4A-10 licences through the inclusion of two new material prospects: Leo and Vega.  It is expected that the revised prospective resources for the SL-03 and SL-4A-10 licences will be published shortly.   The ultra-deep water (3,000 – 3,600 metres) setting of these licences has received limited industry interest during the low oil price environment in the last few years.  However, the Subsidiary Companies have recently experienced increased industry interest in this acreage due to technology improvements and cost reductions in ultra-deep water drilling together with the materiality of the prospects identified by the Subsidiary Companies on the SL-03 and SL-4A-10 licences.SL-03 and SL-4A-10 (Source: African Petroleum) Jens Pace, African Petroleum’s CEO, comments: 'We would like to thank the Petroleum Directorate and the Parliament of the Republic of Sierra Leone for supporting and ratifying our entry into the Second Extension Periods with amended commitments. Our relationship with the Petroleum Directorate has been very important over what has been a challenging couple of years for offshore oil and gas development.  We believe negotiations were helped by the fact that we have been active in the country since 2010 and have invested in excess of US$39 million in the two licences to date.  Based on recent discussions we have held with industry players, we are aware of an increased appetite for material ultra-deep offshore opportunities, driven by the advancements in drilling technology and the decrease in operating costs. The additional flexibility afforded by the amended commitments will help us to introduce new parties to the project.'  Original article link Source: African Petroleum

Sierra Leone, not found

On 17 December 2019, the Federal Agency for Subsoil Use held an auction for five blocks in Bashkortostan Republic (Volga-Ural Province). Local companies MNK Ishimbayneftegaz and Bars emerged as the winners of the contest. The winners will obtain 25-year E&P licenses. The Ashinskiy block covers 31 sq km. Hydrocarbon resources (category D1) of the block are estimated at 2 MMbbl of oil. The starting price amounted to RUB 0.355 million (USD 5,550). MNK Ishimbayneftegaz offered RUB 0.462 million (USD 7,450) The Kazayakskiy block covers 22 sq km and encompasses the Amirovskaya prospect with oil resources estimated at 5 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 2 MMbbl of oil. The starting price amounted to RUB 10.537 million (USD 0.17 million). MNK Ishimbayneftegaz offered RUB 13.698 million (USD 0.22 million). The Mayskiy block covers 22 sq km. Hydrocarbon resources (category D1) of the block are estimated at 2 MMbbl of oil. The starting price amounted to RUB 0.429 million (USD 6,900). MNK Ishimbayneftegaz offered RUB 0.558 million (USD 0.009 million). The Podolskiy block covers 20 sq km and encompasses the Boguslavskaya prospect with oil resources estimated at 2 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 1 MMbbl of oil. The starting price amounted to RUB 3.39 million (USD 0.05 million). MNK Ishimbayneftegaz offered RUB 4.407 million (USD 0.07 million). The Pervomayskiy block covers 82 sq km and encompasses the Alinskaya and Alinskaya Severnaya prospects with combined oil resources estimated at 3 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 9 MMbbl of oil. The starting price amounts to RUB 6.674 million (USD 0.11 million). Bars offered RUB 8.676 million (USD 0.14 million).

MNK Ishimbayneftegaz won Ashinskiy (31km²), Kazayakskiy (22km²), Mayskiy (22km²), Podolskiy (20km²) blocks. Bars won Pervomayskiy (82km²) block.

In mid-June 2018 Black Sea Oil & Gas (BSOG) completed drilling operations in the Iulia exploration well in the XV-Midia West block. The well was drilled on the Iulia prospect targeting the Upper Pontian. It was spudded using the GSP “Saturn” J/U in early May 2018. No further details were disclosed. The block includes the Ana and Doina fields. The Ana (previously named Doina Sister) and Doina fields are located about 105 km from the coast. The Doina field was discovered in 1995 while the Ana field was discovered in 2007. Both are located along the same fault trend with the same reservoir horizon in the Dacian to Recent Series (Dacian to Holocene) below 766 m. Interest in the XV-Midia West block is divided between Black Sea Oil & Gas SRL (65% + operator), Petro Ventures Europe BV (20%) and Gas Plus International BV (15%).

Iulia 1 (BSOG 65% op, Petro Ventures + Gas Plus), W. of Doina gasfield in XV-Midia West block, ops terminated, results n/a. WD=75m

The Alaska Department of Natural Resources (DNR) announced on 10 April 2020 that it is offering State lands for competitive oil and gas leasing in the Alaska Peninsula Areawide 2020 (APA 20202) and the Cook Inlet Areawide 2020W (Cia 2020W) Lease Sales. The deadline to submit bids online through EnergyNet is 11 June 2020 at 4:00 p.m. ADT. The results will be available to the public online at http://dog.dnr.alaska.gov on 17 June 2020 at 9:00 a.m. ADT. The APA 2020 lease sale includes approximately 5 million ac (20, 234 sq km) of state-owned land in 1,004 tracts, ranging in size from 1,280 - 5,760 ac (5 - 23 sq km). The sale area encompasses onshore and offshore acreage that stretches from the Nushagak Peninsula in the north, down the north side of the Alaska Peninsula to just north of Cold Bay. Portions of these tracts are located within the Bristol Bay Borough, the Lake and Peninsula Borough, the Aleutians East Borough, and the Dillingham Census Area. There is a required minimum bid of USD 5 per acre with a royalty rate of 12.5% and a primary lease term of 10 years. Annual rental rates start at USD 1 per acre in Year 1, escalate by USD 0.5 per acre every year, topping out at USD 3 per acre in Years 5 – 10. The CIA 2020W lease sale includes approximately 3.3 million ac (13,355 sq km) of state-owned land in 833 tracts, ranging in size from 640 - 5,760 ac (3 - 23 sq km). The sale area encompasses onshore and offshore acreage that extends from Wasilla in the north to Anchor Point in the southeast, then along Alaska’s Submerged Lands Act boundary in Cook Inlet to the Iniskin Peninsula. Portions of these tracts are located within the Kenai Peninsula Borough, the Matanuska – Susitna Borough, and the Municipality of Anchorage. There is a required minimum bid of USD 5 per acre with a royalty rate of 12.5% and a primary lease term of 8 years. Annual rental rates start at USD 5 per acre in Years 1 - 4, and escalate to USD 10 per acre in Years 5 - 8.

T DNR announces Spring 2020 Alaska Peninsula and Cook Inlet sales

Azimuth Group subsidiary Azinor Catalyst has agreed to farm out 12.5% from its 25% stake in P1763 to Faroe Petroleum on 14 August 2018. The deal is subject to regulatory and partner consent. Faroe's 12.5% in P1763 equates to 25% of the Agar/Plantain well planned for August 2018 where operator Apache (50%) is not participating, and partners will be Azinor (25% + Op), Faroe Petroleum (25%) and Cairn Energy (50%). Cairn farmed in for 25% of P1763 (50% of Agar/Plantain) effective from 9 August 2018. The planned well has a PTD of 1,625m to appraise the Agar discovery near the centre of the licence, then sidetrack to the SE to explore the Plantain prospect. It is targeting combined P50 estimated recoverable resources of 60 MMboe. Success case cost is US$15 million, and the appraisal leg has 58% CoS. Apache opted out of the Agar appraisal after reviewing results from its Titan NFW 9/14b-16, drilled 8km to the S on P1985, which was P&A in December 2017. Agar was discovered by 9/14a-15A (2014, MPX), which encountered a 10m oil column within the Eocene Frigg Formation sandstone. P1763 covers 89 sq km on Northern North Sea blocks 9/9d and 9/14a, adjacent to the S of Bruce Field and 3km E of Beryl Field. It was awarded in the 26th Offshore Round on 10 January 2011, with obligations to reprocess 425 sq km of 3D seismic to PSTM, and a drill or drop option to the shallower of 4,500m or 10m below the logged gas/water contact. Azimuth farmed in for 33% WI in January 2016, increasing its share to 50% in May 2016 with the exit of JX Nippon and Dyas. Licence partners are Apache Beryl I Ltd (50% + Op), Azimuth Group via Azinor Catalyst Ltd (25%) and Cairn Energy subsidiary Nautical Petroleum Ltd (25%).

Azimuth Group (-> 25%, Apache 50% op.) subsidiary Azinor Catalyst has completed the farm out of 25% stake in P1763 to Cairn Energy.

Messoyakhskoye Vostochnoye field area, Yamal-Nenets AO, W. Siberia, spudded May ‘17, TD 3,190m (L. Cretaceous), tested up to 11.1 MMcfg/d + 698 bc/d on 14mm choke in reservoir BU21/0 between 2,904-2,909m and likewise from the upper part of BU21/0 between 2,893-2,903m. Meanwhile in July Messoyakhskaya Zapadnaya-203 (spudded Apr ’17) TD’d at 2,600m (M. Jurassic), tested 3.3 MMcfg/d + 15 bc/d, followed by Messoyakhskaya Vostochnaya-309, spudded Jun ’17, PTD 3,200m, currently suspended.  

Russia (West Siberian B.) Messoyakhskaya Vostochnaya 309 op. by MESSOYA (100.0%) in Messoyakhskoye Vost. block

North Umbaraka block, W. Desert, compl. gas at TD 4,380m in mid-Jul ’18, EDC rig 49. Targets Lower Safa + Masajid.

Umbaraka N.-3 (NUMB-3) (Ja 18-2) appr North Umbaraka block, W. Desert, compl. gas at TD 4,380m in mid-Jul ’18, EDC rig 49. Targets Lower Safa + Masajid.

On 5 March 2020, PEMEX abandoned dry the Ku 201EXP directional new-pool-wildcat (NPW) in the AE-0013-2M-Pilar de Akal-Kayab-04 (AE-0161-Chalabil) entitlement block during end-January 2020. The NPW was spudded on 14 October 2019, with a proposed total depth (PTD) of 4,790 m measured depth m (MD) and 4,750 m true vertical depth (TVD). The NFW targeted the Upper Jurassic from 4,340 m to 4,790 m. The well was drilled by the “Indepedencia I” J/U in a water depth of 37 m, in the northwestern area of the block approximately 6 km west of the Ku Field. It has estimated unrisked prospective resources of 45 MMboe. PEMEX estimated the drilling cost at 1USD to 20 MXN to be USD 38.97 million and the completion cost to be USD 13.31 million. On 6 August 2019, the CNH granted approval to a PEMEX request for a modification of the exploration plan for the AE-0013-2M-Pilar de Akal-Kayab-04 entitlement block that involves the addition of an incremental well scenario which is the Ku 201EXP. On 24 July 2019, the CNH approved a PEMEX request for a drilling permit for the Ku 201EXP NPW. The AE-0013-2M-Pilar de Akal-Kayab-04 entitlement block was granted to PEMEX by SENER on 27 August 2014 and extended for two years on 27 August 2017 but was relinquished on 27 August 2019. It was superseded by the 730.16 sq km AE-0161-Chalabil entitlement block on 28 August 2019.

Mexico (Sureste B.), Ku-201EXP npw, operated by PEMEX (100%), NW part of AE-0013-2M-Pilar de Akal-Kayab-04 (AE-0161-Chalabil) block, offshore, WD 37m, P&A dry as of Jan '20, Indepedencia I JU. PTMD was 4,790m (4,750m TVD), target U. Jurassic.

N. part of field in PL 093, Trondelag Platform, WD 243m, PTD 1,733m, reservoir section drilled in the target Rogn fm, log data from the well confirms the presence of an oil column here but that this area is already sufficiently drained and does not warrant a new producer. Well to P&A, Deepsea Nordkapp SS back to Skumnisse (batch-drilling). Okea (op), partners Petoro + Neptune.

Norway, PL 093

On 18 February 2019, the Federal Agency for Subsoil Use added the Yambotysskiy block in Nenets Autonomous Okrug (Timan-Pechora Basin) to a list of assets planned for auctions in 2019. It is understood that the block will be offered in the third quarter of 2019. Yambotysskiy covers 1,212 sq km and encompasses the Kushvozhskiy and Nyadeytynskiy prospects with combined oil resources estimated at 9 MMbbl. Oil resources of the block are estimated at 137 MMbbl.

On 18 February 2019, the Federal Agency for Subsoil Use added the Yambotysskiy block in Nenets Autonomous Okrug (Timan-Pechora Basin) to a list of assets planned for auctions in 2019. It is understood that the block will be offered in the third quarter of 2019. Yambotysskiy covers 1,212 sq km and encompasses the Kushvozhskiy and Nyadeytynskiy prospects with combined oil resources estimated at 9 MMbbl. Oil resources of the block are estimated at 137 MMbbl.

In early February 2020, Chevron USA acquired 25% WI from BP Exploration & Production in Green Canyon Block GC 865 (G35010). In mid-October 2019, BP acquired 75% WI interest from Talos Energy in GC 865, is sited 2km south-west from the Puma oilfield. The original Puma discovery well, G16808 1 BP2, was drilled in GC 823 in 2003 and encountered 152m of net oil pay in Miocene sandstones. Following completion of the Chevron/BP transaction, equity in GC 865 is now shared between BP Exploration & Production (50% WI + Op), Chevron USA (25%) and Talos Resources (25%).

Chevron USA acquired 25% WI from BP Exploration & Production in Green Canyon Block GC 865 (G35010).

Rex subsidiary Lime Petroleum has agreed to sell its 20% interest in PL 762,  772 sq km in the Norwegian Sea, to a yet-unnamed 3rd party, effective date 1 Jan ‘18. The sale is pending regulatory approval. Lime intends to focus on assets located on or close to the Utsira High, where drilling of a horiz appraisal to the Rolvsnes discovery is planned late March 2018. PL 762 has been so far held by Aker BP (op), partners Fortis Petr. + Lime.

Rex subsidiary Lime Petroleum has agreed to sell its 20% interest in PL 762, 772 sq km in the Norwegian Sea, to a yet-unnamed 3rd party, effective date 1 Jan ‘18. The sale is pending regulatory approval. Lime intends to focus on assets located on or close to the Utsira High, where drilling of a horiz appraisal to the Rolvsnes discovery is planned late March 2018. PL 762 has been so far held by Aker BP (op), partners Fortis Petr. + Lime.

Block 15-1/05, Cuu Long Basin, P&A results n/a on 25 Apr ’19, PV Drilling I JU. Target Late Oligocene Tra Tan ‘G’. Murphy (op), partners PVEP + SK Inno.

15-1/05-LDT 1X (Lac Da Trang-1X) (Murphy 40% op), PVEP 35%, SK Inno. 25%) in Block 15-1/05, P&A results n/a on 25 Apr ’19, target Late Oligocene Tra Tan ‘G’.

The deadlines for Argentina’s 1st offshore round, launched in Nov ’18 for 38 blocks (DEA 8 Nov ’18), have been set back a month. Bid envelopes will now be opened on 16 April, preliminary awards on 16 May, and permits issued on 1 Aug ‘19. Official awards a fortnight from there. Contact: Rodrigo Garcia Berro at RGarciaBerro@minem.gob.ar or +54-911-6648-9244.

The deadlines for Argentina’s 1st offshore round, launched in Nov ’18 for 38 blocks (DEA 8 Nov ’18), have been set back a month. Bid envelopes will now be opened on 16 April, preliminary awards on 16 May,

Fudong 1 flow tested approximately 38 bo/d between 2,340.1-2,342.6m from the Taizhou Formation on 19 April 2020. The success of Fudong 1 confirms the hydrocarbon potential of a new pool reservoir in the eastern region of the Qintong Sag. Fudong 1 was spudded in July 2019 to drill to a PTD of 2,150m and was suspended for testing in August 2019. Fudong 1 is in the Sinopec operated Qintong Sag Block in the South Yellow Sea Basin and is geographically located within Jiangsu Province, Yancheng City, Dongtai City, Tongcheng Village.

China (South Yellow Sea B.) ? op. by SINOPEC (100%) in Qintong block, flow tested approximately 38 bo/d between 2,340.1-2,342.6m from the Taizhou Formation

On 3 December 2019 Equinor spudded exploration well 15/3-12 S on the Sigrun East prospect. The well location is approximately 4 km southeast of Sigrun discovery well 15/3-4. 15/3-12 S was drilled jointly between PL 025 and PL 187 using the “West Phoenix” S/S. The objective was the Middle Jurassic Hugin Formation and there was a secondary target in the Upper Jurassic Draupne Formation. TD has been reached at 3,810 m and on 21 January 2020 sidetrack 15/3-12 A was kicked-off. This well has a planned TD of 4,044 m (3,868 m TVD) and is being drilled because the main wellbore was not sited in an optimal position to test the Draupne target. Equinor had drilled the 12-1/4" hole to section TD at 3,593 m (3,427 m TVD) and had started logging, but then ran into issues which led to a technical sidetrack (T2) being kicked-off in early February 2020. By 19 February 2020 it had reached TD at 4,037 m and was plugging back. The Sigrun discovery was made by Elf Petroleum in 1982. 25/3-4 proved oil and gas at four levels in the Hugin and Sleipner formations with different pressure regimes. A test in the Hugin Formation flowed at a rate of 3,868 bo/d plus 8.65 MMcfg/d through a 40/64” choke. A downdip appraisal well was drilled in 1983 / 1984 which established an OWC at 4,023 m. The Hugin Formation was absent and the Sleipner Formation consisted of thin sandstones with a net pay of less than 7 m. In 2018 Equinor drilled appraisal well 15/3-11 which confirmed a 35 m oil column (15 m of sandstone) in the Hugin Formation with no OWC. As a result of this well, Equinor increased the estimated recoverable reserves range from 2-9 MMboe to 7-13 MMboe and a development using the Gudrun facilities is being considered. Equinor Energy AS operates PL 025 with a 36% interest. It is partnered by Neptune Energy Norge AS (25%), OMV (Norge) AS (24%) and Repsol Norge AS (15%).

15/03-12 S (Sigrun East) (Equin 36% op. Neptune 25%, OMV 24%, Repsol 15%) in PL 025 block The objective was the Middle Jurassic Hugin Fm and there was a secondary target in the Upper Jurassic Draupne Fm. TD=3810 m. Abandoning, w.o. details.

Turkiye Petrolleri A.O. (TPAO) spudded the Gumusyaka 1 new field wildcat (NFW) shallow water offshore well in the G20-A exploration licence (Thrace Basin) in the Sea of Marmara during August 2019 using the GSP Saturn jack-up rig. The drilling activity is subsequently understood to have been completed during early February 2020 and the well was suspended. The G20-A licence, covering an area of 585 sq km, is believed to have been awarded to TPAO in early 2019.

Gümüsyaka 1 (TPAO 100%) in G20 explo block. P&A, Results are not yet available, targeted the Degirmenköy member of the Eocene Sogucak Fm.

On 30 January 2018 the Danish Energy Agency reported that A.P. Moller – Maersk A/S has transferred its 31.2% interest in the Contiguous Area and in the SW Area licences to Maersk Olie og Gas effective from 7 December 2017. The Contiguous Area and SW Area licences are situated in the western part of the country’s offshore area, close to the border with Germany. The Contiguous Area licence contains 11 blocks while the SW Area licence five blocks. A total of 19 fields a situated within the area covered by the licences: especially Dan (oil & gas), Halfdan (oil, gas & condensate), Tyra (gas, condensate & oil), Gorm (oil) and Skjold (oil). In December 2017 the Danish Underground Consortium (DUC) has approved an investment of approximately DKK 21 billion (USD 3.37 billion) for the full redevelopment of the Tyra field. It will be shut-in for redevelopment in November 2019 with production expected to recommence in July 2022. A full redevelopment will involve a restoration of the current infrastructure including the gas processing hub and five surrounding satellite fields. The licences are operated by the Dansk Undergrunds Consortium (DUC). This is a joint venture between Maersk Olie og Gas A/S (31.2% + operator on behalf of the consortium), Shell Olie og Gasudvinding Danmark BV (36.8%), Danish North Sea Fund (20%) and Chevron Denmark Inc (12%).

A.P. Moller – Maersk A/S has transferred its 31.2% interest in the Contiguous Area and in the SW Area licences to Maersk Olie og Gas

The Division of Oil and Gas of the Alaska Department of Natural Resources on 13 March 2020 issued a call for proposals for the 2020 Exploration Licensing Program. The program supplements the state's oil and gas leasing program and encourages exploration outside the known hydrocarbon provinces in the Alaska Peninsula, Cook Inlet, Beaufort Sea, North Slope and North Slope Foothills areas. Proposals can be submitted during the month of April each year and application forms can be found at http://dog.dnr.alaska.gov/Documents/Programs/Exploration_License_Application.pdf. The license grants the exclusive right to explore an area between 10,000 – 500,000 ac (40 -2,023 sq km) for up to 10 years. The licensee must commit direct expenditures for exploration. The licensee pays a one-time USD 1 per acre licensing fee with no annual rental payments and must provide all geological and geophysical data acquired to the State.

United States, not found

Abu Dhabi National Oil Company (ADNOC) announced on 26 February 2018 that it has signed an agreement awarding a 10% interest in Abu Dhabi's new Lower Zakum Concession to INPEX Corp. Under the agreement, INPEX has paid a participation fee of US$ 600 million to join ADNOC subsidiary ADNOC Offshore (60%, op) and an ONGC-led Indian consortium (10%), as well as other yet-to-be determined international partners in the concession. INPEX's stake will be held and managed by its wholly-owned subsidiary JODCO Lower Zakum Ltd. ANDOC stated that it is in the process of finalising the potential partners for the remaining 20% interest. The 40-year concession has an effective date of 9 March 2018.<P />Lower Zakum is one of three new separate concession areas which will replace the current offshore concession operated by the Abu Dhabi Marine Operating Co (ADMA-OPCO). The ADMA offshore concession will expire on 8 March 2018, after ADNOC chose not to extend it. The move follows the company's decision to expand its strategic partnership model, as well as the active management of its portfolio of assets. The company stated that the new approach, which builds on its flexible and enhanced operating model as well as its 2030 growth strategy, will enable it to gain greater market access, broaden the partner base, expand technical expertise and maximize value<P />ADMA-OPCO, a JV comprising ADNOC (60%), BP (14.67%), Total (13.33%) and INPEX Corp (12%), was established in 1977 to operate the ADMA concession, which among others includes the Lower Zakum, Umm Shaif, Umm Lulu, Satah Al Razboot and Nasr fields. The current production of the Lower Zakum Field stands at around 400,000 bo/d, with the aim of reaching a production plateau of 450,000 bo/d by 2025. The field was discovered in 1963 and began production in 1967. As ADNOC looks to boost the country's oil production capacity to 3.5 MMbo/d in 2018, the development of its offshore fields is of strategic importance. The ADMA concession area, which produces around 700,000 bo/d, is planned to have a production capacity of about 1.0 MMbo/d by 2021.

Abu Dhabi Inpex has won a 10% stake in the Lower Zakum concession.

As of October 2018, Rhino Oil and Gas (Rhino) is understood to have been awarded a Technical Cooperation Permit (Rhino Deepwater TCP). The 8,446 sq km permit covers acreage atop the Orange Sub-basin. The acreage is located adjacent to the west of Total’s Outeniqua South Area, water depts range between 3,000 m and 4,000 m deep. Silver Wave previously held a TCP over the area.   Rhino is understood to be the sole participant

Rhino Oil and Gas (Rhino) is understood to have been awarded a Technical Cooperation Permit (Rhino Deepwater TCP). The 8,446 sq km permit covers acreage atop the Orange Sub-basin

In mid-March 2018 the bid round for the Omurtag exploration block was still not launched. This offer has been repeatedly postponed since 2013. The Omurtag block encompasses 2,834 sq km and is situated in eastern Bulgaria, between the 1-16 Gradishte and Provadia permits. Potential finds are expected in Valanginian limestones, which are producing in Bulgaria's oldest field Tyulenovo-Shabla, situated onshore on the Black Sea coast. Particularly attractive objectives seem to be Eocene limestones and sandstones with other possible targets in Middle Jurassic and Triassic sandstones and Middle Triassic limestones/dolomites.    

In mid-March 2018 the bid round for the Omurtag exploration block was still not launched. This offer has been repeatedly postponed since 2013.

PB-1 wellpad in Mahato PSC, Central Sumatra, committed well believed compl. oil in Jan '20. For the record PB-1 was completed in January after DST'ing 500 bo/d, no water. Target assumed L. Miocene Bekasap sst. Texcal (op), partners Bow Egy, Cue Egy + Central Sumatra Egy.

PB-2 appr of PB-1 (Texcal 51% op. Bow Egy 25%, Cue 12,5%, Centr.Sumatra Egy 11,5%) in Mahato PSC, oil discovered. The operator conducted one open hole test and one DST, with the DST flowing approximately 500 bo/d and no water cut.

Huizhou 26-6-4 (HZ 26-6-4) was suspended (results TBC) on or around 15 April 2020 after having been spudded on or around 29 February 2020, using the “Haiyangshiyou 943” jack-up. The oil and gas exploration well was likely targeting the Zhujiang and Enping formations. Huizhou 26-6-4 is in the CNOOC operated Huizhou 26-1 Field Block in the offshore Pearl River Mouth Basin and is approximately 2km SE of Huizhou 26-6-1. <P />

Not Found

Regal has an MoU for the acquisition of Ukrnaftinvest, holder of the Belolisky + Alibeysk-Trapivska licences in the Odessa area, SW coastal Ukraine. The acreage is prospective for o&g and up to 3 wells may be drilled subject to conclusion of a deal.

Regal has an MoU for the acquisition of Ukrnaftinvest, holder of the Belolisky + Alibeysk-Trapivska licences in the Odessa area, SW coastal Ukraine. The acreage is prospective for o&g and up to 3 wells may be drilled subject to conclusion of a deal.

On 29 June 2020, Lukoil, Gazprom Neft and Tatneft announced the completion of a deal regarding setting up JV New Oil Production Technologies LLC (NOPT) aimed at exploration and production of hard-to-recover hydrocarbons in Orenburg Oblast (Volga-Ural Province). Each company holds a one-third interest in the JV. During the initial stage, the venture will operate two licenses in the region. The Savitskiy block (ORB03334NR) covers 900 sq km and encompasses several prospects and leads. The license was originally awarded to Gazprom Neft and it was transferred to Gazprom Neft's subsidiary Savitskoye in early 2020 as the preparation for the reported deal. It is understood that Gazprom Neft already drilled one exploratory well with horizontal completion and recorded a 880 sq km 3D seismic survey. Five more wells have been planned. The Zhuravlevskiy block (ORB16634NR) covers 123 sq km and encompasses the suspended Zhuravlevskoye field with remaining in-place reserves estimated 18 MMbbl of oil. The license, awarded to Lukoil-subsidiary RITEK, was transferred to its subsidiary Zhuravlevskiy in March 2020. The JV plans to record 118 sq km of 3D seismic data and to drill one exploratory well for conventional resources and one well for unconventional resources during 2020-2023.

Lukoil, Gazprom Neft and Tatneft have formed New Oil Production Technologies LLC (each holding one third) to explore and produce conventional and unconventional hydrocarbons in the Savitskiy and Zhuravlyovskiy licences (Orenburg region).

Petroandina has acquired a yet-undisclosed interest from Tullow in the latter’s so far wholly-owned block 62,  4,061 sq km in deepwaters of the Guyana Basin:

Petroandina has acquired a yet-undisclosed interest from Tullow in the latter’s so far wholly-owned block 62, 4,061 sq km in deepwaters of the Guyana Basin

On 8 June 2019, it was announced that Turkiye Petrolleri A.O. (TPAO) has been awarded the L43-A3,A4 onshore exploration licence in the Zagros Province towards southeast of the country on 28 May 2019. The licence covers around 304 sq km area and it has been granted for a five-year term with an expiry date of 27 May 2024. TPAO is 100% owner and operator of the licence. TPAO had filed the application for L43-A3,A4 exploration licence on 26 October 2018.

TPAO has been awarded the L43-A3,A4 onshore exploration licence in the Zagros Province towards southeast of the country

As of 27 February 2016, Anadarko Canada has withdrawn from two offshore exploration licenses and sold its interest to BP Canada for an undisclosed amount. The blocks, EL 1125 and EL 1126 are both located in the East Orphan and Flemish Pass basins respectively. The effective date of the interest change is 15 January 2018. No reason was given for the sell since Anadarko continues to hold interest in four additional blocks in the region. Anadarko acquired the interest through the acquisition of Shell Canada’s working interest in the same blocks, Shell in turn had acquired the working interest through its acquisition of BG. EL 1125 and EL 1126 were both officially awarded on 15 January 2012 from the NL11-02 Call for Bids held in 2011. EL 1125 consisted of 2,470.16 sq km at the time of award but has been reduced by half to 1,230.95 sq km through an extension of Period I for one year by placing a CAD 1,000,000 drilling deposit. Working interest partners in EL 1125 are now Statoil Canada (operator) 40%, Chevron Canada 40% and BP Canada 10%. The exploration license was awarded for a work commitment bid of CAD 202,171,394. EL 1126 consist of 1,867.80 sq km and was awarded for a work commitment bit of CAD 145,603.270 million. The contract entered Period II based on the drilling of one exploration well. Working interest holders are the same as EL 1125 at Statoil Canada (operator) 40%, Chevron Canada 40% and BP Canada 10%.

BP (->20%) acquired 10% WI from Anadarko (-> 0%, Statoil 40% op, Chevron 40%) in 2 Grand Banks exploration licences: EL 1125 and EL 1126.

OKEA has agreed a deal with Equinor to acquire its 40% interest plus operatorship in PL 195 and PL 195 B, subject to government approval. The licences contain the 1988 Aurora gas discovery made by 35/8-3 which OKEA is intending to develop as a tie-back to the nearby Gjoa field without drilling an appraisal well. Estimated recoverable reserves for Aurora are 12-28 MMboe. The deal was announced on 15 July 2020. 35/8-3 encountered a gas column of 70 m (32 m of net pay) in the Upper Jurassic Heather Formation. Average porosity was 16% and average water saturation was 22%. The GWC was not penetrated. The underlying Middle Jurassic Brent Group was the main target for the well but was water-wet. Upon completion of the deal, interest in PL 195 and PL 195 B will be divided between OKEA ASA (40% + operator), Petoro AS (35%) and Wintershall Dea Norge AS (25%).

Norway (Viking Graben Province), OKEA has agreed a deal with Equinor to acquire its 40% interest plus operatorship in PL 195 and PL 195 B, subject to government approval. PL 195 operated by EQUINOR (40%), PETORO (35%), BASF (17%), L1 EN (8%).

The country’s Petroleum Minister recently stated that the environmental audit for South Sudan’s long-awaited first bid round has begun and the offer is on track to launch in March. Some 13 blocks are expected to be on offer. Background from GEPS.

he country’s Petroleum Minister recently stated that the environmental audit for South Sudan’s long-awaited first bid round has begun and the offer is on track to launch in March. Some 13 blocks are expected to be on offer.

According to PetroChina News report on 22 August 2018, PetroChina – Jilin achieved gas flow from a tight gas appraisal well, Deshen 80, in the Southeast Uplift of Songliao Basin. The well tested 3.85 MMcf/d possibly from the Lower Cretaceous following fracking work in July 2018. The well was drilled in the Baojia sub-sag of the Dehui Sag in Songliao Basin. The Dehui Sag covers an area about 4,000 sq km in the southern part of the Songliao Basin. Exploration in the Dehui Sag began in the 1970s. Several conventional fields have been discovered, such as the Nong’an, Xiaohelong, Wanjinta and Buhai fields. The sag was estimated to hold about 1.5 Bbbl of oil and 6 Tcf of gas resource potential. Background information In 2014, Deshen 17 tight gas block was discovered with reservoir of volcanic rocks in the Yingcheng Formation. The reservoir has average porosity less than 8% and average permeability less than 0.05 mD. The discovery was put on development in 2015, a development well, Deshen 17-1, was reported to test gas in 2016. In 2012, PetroChina - Jilin tested gas in Deshen 11 and Deshen 12 in the Dehui sag. Deshen 11 was drilled in the Huajia Structure Belt of the Dehui Sag. The well tested 1.87 MMcf/d (53 MMcm/d) of gas from sandstone reservoirs in the Huoshiling Formation. As of 2018, a total of 12 appraisal wells have been completed in the Deshen 11 tight gas block. In 1999, CNPC - Jilin drilled Deshen 4 in the Dehui Sag with gas shows encountered. Deshen 2 and Deshen 5 were drilled at the same year without results reported.

PetroChina – Jilin achieved gas flow from a tight gas appraisal well, Deshen 80, in the Southeast Uplift of Songliao Basin. The well tested 3.85 MMcf/d possibly from the Lower Cretaceous following fracking work in July 2018. The well was drilled in the Baojia sub-sag of the Dehui Sag in Songliao Basin.

EIV-1 Suceava block, East European Platform Margin in NE Romania, TD ca. 600m, 8m gas pay in 9m reservoir in the target Salmatian, tested ab. 1.17 MMcfg/d on 8mm choke from between 513.3-514.8m and 516.3-517.3m for 11 hours, now suspended as a potential producer via the Bilca facilities, expected on stream in 2Q ‘18. Weatherford 865 rig. Raffles (op) 50%, partner Prospex O+G.

Romania (East European Platform Margin) Bainet 1 op. by RAFFLES EN (50.0%, PROSPEX OG 50.0%) in E IV-01 Suceava block

Eni’s CEO Claudio Descalzi and Sonangol’s Chairman of the Board of Directors Carlos Saturnino signed today an agreement that assigns operatorship of Cabinda North block to Eni, as well as 48% the block’s rights. The signing took place in Luanda at the presence of the President of the Republic of Angola João Gonçalves Lourenço and the Prime Minister of Italy Paolo Gentiloni. Cabinda North, of which Eni previously controlled 15%, is an onshore block located in a little explored oil basin in the north of the country, where Eni will be able to leverage the mining knowledge acquired in activities in a neighboring area in the Republic of Congo. In case of significant discoveries, production will be facilitated by existing infrastructure. In addition, the two companies signed a Memorandum of Understanding to define joint projects throughout the whole value chain of the energy sector. The MoU provides for the assessment of associated and non-associated gas resources in Angola’s offshore, to be traded on both domestic and international markets, and the optimization of exploration activities and identification of new opportunities for joint exploration. Also, it provides for the study of optimization measures in the refining and trading sector in Angola, and the evaluation of opportunities in the sector of renewable energy and, in particular, in photovoltaic. These agreements expand the scope of Eni's activities in Angola and strengthen its presence in the country, while consolidating the strategic alliance with Sonangol. Eni has been present in Angola since 1980 through its subsidiary Eni Angola. Equity production amounts to 155,000 barrels of oil equivalent per day. Original article link Source: Eni

Angola, not found

Abu Dhabi’s 1st round has resulted in the award, to Eni (op, 70%) + PTTEP (30%), of offshore blocks 1 & 2 totalling ab. 8,000 sq km off NW Abu Dhabi (in brighter orange below). Both companies will share the rights during the explo phase, with Adnoc retaining the option to a 60% stake in a production phase. The Concession Agreement was signed with ADNOC on 12 January, contract duration 9 years explo, total 35 years (devt + prod). No news is yet available regarding the other 4 (onshore) blocks on offer in the round. (Map courtesy ADNOC).

SPC and ADNOC awarded a consortium of Eni (70%) and PTTEP (30%) exploration rights to Offshore Block 1 and Offshore Block 2 as offered in the Abu Dhabi Licensing Block Bid 2018.

Horizon Petroleum has agreed a Letter of Intent with an unnamed private European company for 50% WI in the 32/2009/p Bielsko-Biala concession. In return the farmee will fund 100% of the capital expenditures required to bring the Lachowice gas field online. This includes all costs related to drilling, completing and testing the first well and surface production equipment. Costs are expected to total approximately C$10.5 million (approximately US$8 million), however following first production future expenditures and profits will be shared equally. The first well is expected Q1 2019 with production in Q4 2019, initially estimated at 3 MMcfg/d. The Joint Venture (JV) is dependent on confirmation of the farmee's financial capacity, regulatory approvals and formal documentation, and completion of Horizon's pending acquisition of the concession from San Leon. Horizon entered an agreement with San Leon for 100% interest in five concessions in a two-part deal announced on 19 September 2017. Horizon will first acquire 100% of 32/2009/p Bielsko-Biala, as well as 69/2009/p Cieszyn, for US$ 1 million cash and C$1 million (US$ 815,000) worth of Horizon shares, and a 6% retained net profit interest (NPI) in the concessions. The acquisition is expected to close Q3 2018 following Horizon's plans to raise up to C$ 5 million (US$ 3.8 million) in a private placement of up to 100 million common shares of Horizon at a price of C$0.05 per share. The private placement is expected to be used to complete the acquisition as well as fund development of the assets and for general corporate expenses. 32/2009/p Bielsko-Biala (800 sq km) is located in the Slaskie Region of Southern Poland, within the North Carpathian Basin, and was awarded in May 2009. The Lachowice gas field was discovered on the concession by Lachowice 1 (1984, PGNiG, 4,525m) which encountered gas in compartmentalised Devonian carbonates. Subject to approval of the asset sale to Horizon Petroleum, San Leon subsidiary Energia Karpaty Zachodnie Sp zoo Spkom operates the licence with 100% equity.

Horizon has signed a LoI with an undisclosed European co. to farm out a 50% non-operated stake in the 32/2009/p Bielsko-Biala contract, 805km² in the S. Poland. This contains the undeveloped Lachowice gasfield for which updated plans are now to bring it to production.

In March 2020 Spark Exploration was still seeking potential partners to prove the extension of the Rona Ridge Basement play in licence P2407 (blocks 205/14a and 205/19). The acreage contains high quality Basement and conventional prospectivity on trend with Hurricane’s Basement Play and BP’s Clair field. The Bader prospect is located on the Rona Ridge within a mega-closure including the Lancaster and Halifax discoveries. The company previously derived two prospective resource scenarios relating Bader to the Halifax discovery. Scenario A had a 21% geological chance of success and classed the prospect as an independent accumulation from Halifax where the OWC could be different due to faulting. Scenario B classed the Bader prospect as a continuation of Halifax with the same OWC. The largest estimated resources were interpreted from scenario B and in Spark's latest presentation (March 2020) only scenario B was detailed. The mean STOIIP was estimated at 4,256 MMbbl with 956 MMbbl mean recoverable prospective resources (22.5% recovery factor). Spark has a fully funded two-year work programme with commitments of 3D PSDM reprocessing, G&G studies and a drill or drop decision in September 2020. The Bader prospect is defined on high quality 3D seismic data with similar basement fault networks to Lancaster and Halifax. Image logs in the south west area of the Halifax discovery display numerous open fractures which could extend into Bader. Spark interpret that no significant displacement of the Basement is observed across the ‘West Fault Zone’ which borders its acreage to Halifax, therefore it’s unlikely a lateral seal is present between Halifax and Bader. The crest of the structure is 800 m TVD and the Kimmeridge Clay acts as the source rock to Bader. Licence P2407 was awarded on 1 October 2018 in the 30th Seaward Licensing Round. Shell drilled the only exploration well in the acreage to date. Exploration well 205/14-1 was drilled in August 1990 to a depth of 9,170 feet. The well was drilled to test a Lower Palaeocene objective on the downthrown side of a major Tertiary fault but was plugged and abandoned as a dry hole. Interest in P2407 is held solely by Spark Exploration UK Ltd (100% + operator).

(Faroes-Shetland Trough) P2407 op. by SPARK (100%), In March 2020 Spark Exploration was still seeking potential partners to prove the extension of the Rona Ridge Basement play in licence P2407 (blocks 205/14a and 205/19). The acreage contains high quality Basement and conventional prospectivity on trend with Hurricane’s Basement Play and BP’s Clair field.

A1 prospect, Tendrara-Lakbir block in E. Morocco, P&A’ing dry at TMD 2,925m, main target TAGI gas, Saipem Nat. 110 IE rig off to drill planned TE-10, then 11. Sound (op), partners Moroccan O&G Investment Fund + Onhym.

Tendrara 009 (A1 prospect) (Sound op, Moroccan O&G Investment Fund, Onhym) in Tendrara-Lakbir block in E. Morocco, P&A’ing dry at TMD=2 925m, main target TAGI gas.

The Ministry of Energy and Petroleum is offering 29 open blocks on an open-door policy. The open blocks were:  Basin Names Block Name Block Sqkm Chad Basin~Termit Trough - Chad Basin Aborak 24,760 Chad Basin~Grein-Kafra Trough~Tenere Rift - Chad Basin Achegour 17,012 Iullemmeden Basin~Tahoua Depression (Iullemmeden Basin) Ader 31,174 Chad Basin~Bilma Trough - Chad Basin~Djado Basin Araga 28,196 Iullemmeden Basin~Mantass Depression (Iullemmeden Basin) Azawak 29,085 Chad Basin~Iullemmeden Basin Damagaram 29,680 Chad Basin~Termit Trough - Chad Basin Dibella 1 20,418 Djado Basin~Chad Basin Dissilak 19,924 Djado Basin Djado 1 14,121 Djado Basin Djado 2 12,694 Djado Basin Djado 3 11,288 Djado Basin Djado 4 11,981 Chad Basin~Tenere Rift - Chad Basin~Grein-Kafra Trough Grein 16,010 Chad Basin Homodji 33,118 Tamesna-Talak Depression (Iullemmeden Basin) ~Iullemmeden Basin Irhazer 25,758 Djado Basin~Chad Basin Karama 30,347 Chad Basin~Termit Trough - Chad Basin Manga 1 12,258 Chad Basin~Termit Trough - Chad Basin~Ngel Edji Trough - Chad Basin Manga 2 11,712 Chad Basin~Djado Basin~Grein-Kafra Trough~Hoggar Massif Seguedine 22,570 Iullemmeden Basin~Tahoua Depression (Iullemmeden Basin) Tadarast 39,972 Chad Basin~Hoggar Massif Tafassasset 21,965 Iullemmeden Basin~Tamesna-Talak Depression (Iullemmeden Basin)~Tahoua Depression (Iullemmeden Basin)~Air Massif Talak 30,120 Iullemmeden Basin~Tamesna-Talak Depression (Iullemmeden Basin) Tamesna 25,711 Tahoua Depression (Iullemmeden Basin)~Iullemmeden Basin~Nigerian Shield Tarka 43,342 Djado Basin Tchigai 21,160 Iullemmeden Basin~Chad Basin~Nigerian Shield Tegama 32,193 Chad Basin~Termit Trough - Chad Basin~Tefidet Rift - Chad Basin~Tenere Rift - Chad Basin Tenere Ouest 22,367 Iullemmeden Basin~Mantass Depression (Iullemmeden Basin)~Voltaian Basin Tounfalis 37,741 Mantass Depression (Iullemmeden Basin)~Iullemmeden Basin Yaris 30,807 Source, IHS Markit 2018

The Ministry of Energy and Petroleum is offering 29 open blocks on an open-door policy.

EnQuest has agreed to acquire 40.8125% and operatorship from Equinor in Bressay heavy oil field licences P234 (3/28a), P493 (3/28b), P920 (3/27b) and P977 (9/2a & 9/3a), as released on 31 July 2020. Initial consideration is GB£ 2.2 million (US$ 2.86 million), to be payed as 50% of Equinor’s net share of costs from deal completion (expected Q4 2020) with a contingent consideration of US$ 15 million following Field Development Plan (FDP) government approval for Bressay. The contingent payment increases to US$ 30 million if EnQuest sole risks Equinor in the submission of the FDP. The development concept selection was deferred in 2016 due to challenging market conditions and the need to simplify the development concept. Extensions to licence expiry dates and commitments are condition precedents to completion. A development concept being considered is a tie back to Kraken heavy oil field (EnQuest Op, 12km NE). EnQuest will become operator on P&A of discovery well 3/28-1 (1976, Chevron, 1,527m, Tertiary reservoir). The field was later successfully appraised. Estimated gross STOIIP is 600-1,050 MMbo and 100-300 MMbo estimated gross recoverable. 50km S is the Equinor operated Mariner Field. Chrysaor entered the licence when it acquired a package of assets from Shell in 2017. Current field partners Equinor UK Ltd (81.625% + Op) and Chrysaor Ltd (18.375%).

(East Shetland Platform) EnQuest has agreed to acquire 40.8125% and operatorship from Equinor in Bressay heavy oil field licences P234 (3/28a), P493 (3/28b), P920 (3/27b) and P977 (9/2a & 9/3a). Current field partners Equinor UK Ltd (81.625% + Op) and Chrysaor Ltd (18.375%). After completion, new field partners will be EnQuest (40.8125%, op.), Equinor UK Ltd (40.8125%) and Chrysaor Ltd (18.375%).

Pertamina EP has likely completed wildcat Kusuma Arum 1, in the Sumbagsel 2 PPC, located in the South Sumatra Basin, in late July 2020, with result unreported. Located near the Batanghari village, in the Ogan Komering Ulu Regency, the well was spudded around late November 2019, and had a planned total depth of around 2,300 m. The well was initially expected to be completed in three months. The operator has estimated a pre-drill volume of around 60 Bcfg from this well. Typical exploration target in the block is the Talang Akar Formation, from which several fields in the area have been producing. The last exploration drilling in the block was deeper pool wildcat Belimbing Deep 1 (gas shows), completed in February 2019. Located in the Belimbing Jaya village, Muara Enim Regency, the well was spudded around early November 2018, using PDSI’s Rig no.42 N-1500-E. Belimbing Deep 1 was likely targeting the pre-Tertiary Basement. The Talang Akar Formation, which is the producing reservoir in the Belimbing field, could have been a secondary objective for the well. Prior to wildcat Belimbing Deep 1, the operator completed Sekarwangi 1 in late October 2018. The well may have encountered gas, however the three DST tests performed at depths of 3,218 m to 3,228m, 3,074 m to 3,080 m and 2,071 m to 2,074 m have likely shown intermittent flow. Spudded in May 2018, Sekarwangi 1 was drilled using PDSI-operated Rig no.42 N-1500-E. The well is located within the vicinity of Darmo village, in the Muara Enim Regency. Pertamina holds 100% operatorship of the block. Background Information Pertamina spudded wildcat Sakura 1 in September 2017. The well with a PTD of 3,800 m, was targeting the deeper sandstones of the Upper Eocene-Lower Oligocene Lahat Formation, and secondarily the Upper Oligocene Talang Akar Formation. It is understood that the well encountered only minor gas indications. In November 2017, the company likely completed a 2D seismic survey over the Selingsing area. As of June 2017, approximately 85% of the planned 608 km had been acquired. The survey was conducted by PT Elnusa. Acquisition commenced in January 2017. Over 50% of the acquisition had been completed as of February 2017. The seismic campaign was initially expected to last for approximately four months. A socialization event to inform the local community about the planned survey was held on 6 October 2016. The survey covered areas in the vicinity of the Talang Akar-Pendopo field, within the Talang Ubi sub-district of South Sumatra Province. Preparations for the survey were ongoing in 2H 2015. In late 2014, Elnusa issued a pre-qualification tender for a subcontract related to the acquisition. Initial socialization activities with the locals were likewise conducted in late November 2014.

(South Sumatra B.) Kusuma Arum 1 nfw, in the Sumbagsel 2 PPC, operated by PERTAMINA (100%), was completed, results n/a.

On 27 September 2018, BASF and LetterOne signed a definitive transaction agreement to merge their respective oil and gas businesses (Wintershall and DEA) in a joint venture, which will operate under the name Wintershall DEA. This follows BASF and LetterOne signing a Letter of Intent to merge their respective oil and gas businesses in December 2017. The oil and gas business of BASF is bundled in the Wintershall Group, consisting of Wintershall Holding GmbH and its subsidiaries, including the gas transportation business. The oil and gas business of LetterOne comprises DEA Deutsche Erdol AG and its subsidiaries. Closing of the transaction is expected in the first half of 2019.Wintershall DEA will be formed by LetterOne contributing all its shares in DEA Deutsche Erdol AG into Wintershall against issuance of new shares to LetterOne. Based on the valuation of the exploration and production businesses, BASF will initially hold 67% and LetterOne will hold 33% in Wintershall DEA. In this shareholding ratio, Wintershall's gas transportation business is not accounted for. As of closing, Wintershall DEA will issue a mandatory convertible bond to BASF reflecting the value of Wintershall's gas transportation business. No later than 36 months after closing, this bond will be converted into new shares in Wintershall DEA, resulting in a higher shareholding ratio in Wintershall DEA for BASF to 72.7%. In 2017, production volumes of Wintershall and DEA on a pro-forma basis amounted to 210 MMboe or some 575,000 boe/d (77% Wintershall).In March 2015, DEA, formerly part of RWE AG, was acquired by LetterOne. DEA has interest in production facilities and concessions in Germany, Norway, Denmark, Egypt, Algeria and Mexico. Subsequent to this purchase, LetterOne, through a forced sale instigated by the UK government, sold the UK assets held in DEA to INEOS.BASF's oil and gas activities are held in the Wintershall Group. Wintershall focuses on exploration and production in oil and gas-rich regions in Europe, North Africa, Russia, South America and the Middle East. Through a swap arrangement consummated in September 2015, Gazprom acquired a 50% interest in the activities of the Wintershall Noordzee BV subsidiary, which is active in exploration and production in the southern North Sea (Netherlands, UK and Denmark).<P /><P />

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CalEnergy has acquired Zennor's 11% stake in P1242 on 21 Jul '20. The 53-sq km licence covers blocks 47/5b + 48/1a and contains the Platypus gas field, PDO for which is awaiting approval. Dana Petr (op), partners CalEnergy + Parkmead.

(Anglo-Dutch B.) CalEnergy acquired 11% from Zennor in the P1242 block op. by KNOC (59%)

Metgasco Pty Ltd completed a farm-out agreement with Vintage Energy Pty Ltd, in which Vintage acquired 50% interest in exploration permit ATP 2021-P, located in the Cooper-Eromanga Basin, in December 2019. Vintage funded part of the Vali 1 exploration well under the initial farm-in terms. The farm-in agreement was entered in to in July 2019, after a Heads of Agreement (HoA) was executed on 22 May 2019. In late August 2019 Metgasco reported that it had entered a second farm-in agreement, to farm-down a further 25% in the permit to Bridgeport Energy Ltd. This was completed as of February 2020. Bridgeport also funded part of the permit’s upcoming work programme to earn interest. The permit, which is located in the Cooper-Eromanga basins, was awarded to Metgasco on 29 May 2018 and the company had been seeking a farm-in partner since acquiring the permit ahead of further exploration operations. The farm-in agreement with Vintage Energy was subject to regular required approvals, such as ministerial approval and licence registration. As per the HOA, Vintage contributed 65% of costs associated with drilling a first exploration well (up to AUD 5.3 million) and to also cover 65% of past exploration costs already incurred by Metgasco (AUD 527,800). The initial work programme over the permit focused on better identifying the leads, completing regional geological evaluation and refining play types. To further define existing shallow oil targets, Vintage will also fund up to AUD 70,000 relating to reprocessing of 2D and 3D seismic data. The well drilled under the farm-in agreements was the Vali 1 well, drilled in late 2019. The exploration well encountered 35 m net gas pay in the primary Patchawarra Formation, plus additional gas recovery and oil shows the deeper Triassic and Jurassic secondary targets. Vintage reported that the results are on the high side of pre-drill estimates. In addition, potential gas pay was interpreted in the secondary Toolachee target and the Triassic Nappamerri Group, in which, gas was recovered. Oil shows in the Jurassic Westbourne and Birkhead formations were also reported by Vintage. ATP 2021-P is mainly prospective for Permian gas and Jurassic oil accumulations. The Odin Prospect is another identified prospect, comprising an anticlinal structure on the western boundary of the permit with an independent closure at a depth of around 2,300 m. The Strathmount 1 exploration well, which was drilled in 1987, lies within the extent of the prospect. The well encountered 21 m of reservoir sands and 13.7 m of interpreted gas pay. Gas flow testing indicated returned gas to surface but at rates were too small to measure. On the 2016 Snowball 3D seismic data, Metgasco reports that the well appears to have intersected the sands outside of the Toolachee and lower Patchawarra level. Odin has been assigned P50 recoverable resources of 8.7 Bcf. ATP 2021-P, which covers an area 371 sq km, is currently 100% owned and operated by Metgasco. With both farm-in agreements now complete, participants are: Vintage Energy Ltd (50% + operator) Metgasco Pty Ltd (25%) and Bridgeport Energy Ltd (25%).

Metgasco Pty Ltd, Vintage Energy Pty Ltd ATP 2021 permit, Cooper-Eromanga basin - Farm-in complete

Eni Timor Leste SpA, a wholly owned subsidiary of Eni SpA, is offering interested companies the opportunity to farm into or possibly acquire Production Sharing Contract S06-04 also known as Block E, located in the Bonaparte Basin. Participating interest of up to 35% was thought to have been initially available, with negotiable terms. In May 2020, it was reported in the media that Eni could be looking to exit its Australian production and exploration position, which could also include its Timor Leste assets. Eni has reported that the permit contains the Samara Prospect, with potential mean estimates for oil in place of 319 MMbbl of oil. The prospect reservoir targets are within the Plover and Nome formation sandstones. There are additional oil prospects outlined by Eni, including Estado Lauana, Paramin, Deleco and Atara, which range in size from between 111 to 393 MMbbl of oil in place. There have been no wells yet drilled within the permit area. However, Eni conducted a 3D seismic survey in 2007, which covered a number of permits including S06-04. A total of 8,400 sq km of data was acquired. The permit was awarded in November 2006 and was scheduled to expire in 2014. As of August 2020, it is under a renewal consideration by Autoridade Nacional do Petróleo e Minerais (ANPM). In 2009 Eni and Joint Venture Partners Kogas and Galp Exploration & Production, relinquished around 25% of the permitted area, reducing the total area to 2,310 sq km, with S06-04 (E) covering around 1,810 sq km. The permit was the only valid licence in East Timor for a period of time, before an additional PSC (TL-SO-15-01) was awarded in December 2015. S06-04, which covers an area of 2,310 sq km, was awarded on 3 November 2006. Participants in the permit are Eni Timor Leste SpA (80% interest and operatorship) Korea Gas Corp (KOGAS) (10% interest) and Galp Energia Espana SA (10% interest). Companies interested in pursuing this opportunity should contact: Satyavan Reymond, Exploration Manager Email: satyavan.reymond@eniaustralia.com.au

(Bonaparte B.) Block E in Production Sharing Contract S06-04, operated by ENI (80%) and partners Galp (10%) + Kogas (10%), Eni is offering interested companies the opportunity to farm into or possibly acquire the block.

ConocoPhillips is said to be planning a sale of its remaining UK North Sea assets, up to USD 3 bn could be netted. The move would be the result of COP receiving an unsolicited offer, which did not meet the company’s expectations for value.

ConocoPhillips is said to be planning a sale of its remaining UK North Sea assets, up to USD 3 bn could be netted. The move would be the result of COP receiving an unsolicited offer, which did not meet the company’s expectations for value.

PPL 6, Cooper Eromanga, P&A'd earlier this week, Ensign rig 967. Santos (op), partner Beach.

Gidgealpa S.-1 nfw PPL 6, Cooper Eromanga, P&A'd earlier this week, Ensign rig 967. Santos (op), partner Beach.

In January 2019, Oil Search Ltd agreed to pay USD 8-million to acquire a 50% working interest in 195,200 acres (789 sq km) on the North Slope from Armstrong subsidiary Lagniappe Alaska. The leases were acquired by Lagniappe in November 2016 from the NS2018W oil & gas lease sale. Lagniappe was founded by Armstrong Energy LLC owner Bill Armstrong for the sole purpose of participating anonymously in the 2018 lease sale. Oil Search had agreed to establishing an Area of Mutual Interest with Armstrong when it entered the state through the acquisition of the Pikka acreage located to the west. The AMI granted Oil Search an option to acquire a 50% working interest in acreage acquired by Armstrong. In November 2018, Lagniappe Alaska LLC submitted high bids on 120 tracts and was preliminarily awarded the rights to the leases by the Alaska Division of Natural Resources (ADNR) at the North Slope Areawide Oil & Gas Lease Sale (NS2018W), held on 15 November 2018. The Lafayette, Louisiana-based company dominated this year’s auction, bidding a total of USD 14,143,315.20 for the 120 tracts that cover 195,200 acres (789.94 sq km) for an average bid per acre of USD 72.45. Lagniappe Alaska’s acreage position forms a contiguous block starting about 5 km (8 km) south of the Savant Alaska-operated Badami Unit and a little west of the Arctic National Wildlife Refuge. Lagniappe Alaska was by far the most active bidder of this sale that saw 147 bids on 133 tracts spanning 223,680 acres (905 sq km). The sum of the high bids accepted by the ADNR came to USD 27,313,721.60. Lagniappe Alaska Acreage Position     Bidder Block ADL Bonus Bid (USD) Acres Sq Km Partner(s) Lagniappe Alaska LLC 50% NS0498A 393750 $53,726.40 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0498B 393751 $53,726.40 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0498C 393752 $53,438.40 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0498D 393753 $53,438.40 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0502A 393754 $53,467.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0502B 393755 $53,467.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0502C 393756 $53,380.80 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0502D 393757 $53,380.80 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0503A 393758 $53,467.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0503B 393759 $53,467.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0503C 393760 $53,380.80 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0503D 393761 $53,380.80 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0506A 393762 $39,038.40 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0506B 393763 $39,038.40 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0506C 393764 $38,923.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0506D 393765 $38,923.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0507A 393766 $39,038.40 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0507B 393767 $39,038.40 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0507C 393768 $38,923.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0507D 393769 $38,923.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0510A 393770 $39,124.80 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0510B 393771 $39,124.80 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0510C 393772 $38,952.00 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0510D 393773 $38,952.00 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0511A 393774 $39,124.80 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0511B 393775 $39,124.80 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0511C 393776 $38,952.00 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0511D 393777 $38,952.00 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0515A 393778 $39,038.40 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0515B 393779 $39,038.40 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0515C 393780 $38,923.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0515D 393781 $38,923.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0582A 393784 $64,958.40 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0582B 393785 $64,958.40 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0582C 393786 $64,958.40 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0582D 393787 $64,958.40 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0583A 393788 $56,260.80 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0583B 393789 $56,260.80 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0583C 393790 $56,260.80 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0583D 393791 $56,260.80 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0585A 393792 $53,524.80 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0585B 393793 $53,524.80 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0585C 393794 $53,524.80 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0585D 393795 $53,524.80 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0586A 393796 $128,318.40 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0586B 393797 $128,318.40 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0586C 393798 $128,318.40 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0586D 393799 $128,318.40 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0587A 393800 $79,387.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0587B 393801 $79,387.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0587C 393802 $79,387.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0587D 393803 $79,387.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0588A 393804 $53,611.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0588B 393805 $53,611.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0588C 393806 $53,611.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0588D 393807 $53,611.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0589A 393808 $53,380.80 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0589B 393809 $53,380.80 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0589C 393810 $53,380.80 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0589D 393811 $53,380.80 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0590A 393812 $73,627.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0590B 393813 $73,627.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0590C 393814 $73,627.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0590D 393815 $73,627.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0591A 393816 $128,404.80 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0591B 393817 $128,404.80 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0591C 393818 $128,404.80 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0591D 393819 $128,404.80 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0592A 393820 $53,582.40 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0592B 393821 $53,582.40 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0592C 393822 $53,582.40 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0592D 393823 $53,582.40 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0593A 393824 $53,467.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0593B 393825 $53,467.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0593C 393826 $53,467.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0593D 393827 $53,467.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0594A 393828 $87,940.80 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0594B 393829 $87,940.80 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0594C 393830 $87,940.80 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0594D 393831 $87,940.80 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0595A 393832 $73,483.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0595B 393833 $73,483.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0595C 393834 $73,483.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0595D 393835 $73,483.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0596A 393836 $53,380.80 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0596B 393837 $53,380.80 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0596C 393838 $53,380.80 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0596D 393839 $53,380.80 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0597A 393840 $53,352.00 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0597B 393841 $53,352.00 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0597C 393842 $53,352.00 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0597D 393843 $53,352.00 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0599A 393844 $67,838.40 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0599B 393845 $67,838.40 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0599C 393846 $67,838.40 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0599D 393847 $67,838.40 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0600A 393848 $53,323.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0600B 393849 $53,323.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0600C 393850 $53,323.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0600D 393851 $53,323.20 1,440.00 5.82 Oil Search 50% Lagniappe Alaska LLC 50% NS0700 393852 $156,697.60 2,560.00 10.35 Oil Search 50% Lagniappe Alaska LLC 50% NS0701 393853 $515,251.20 2,560.00 10.35 Oil Search 50% Lagniappe Alaska LLC 50% NS0702 393854 $515,251.20 2,560.00 10.35 Oil Search 50% Lagniappe Alaska LLC 50% NS0703 393855 $397,235.20 2,560.00 10.35 Oil Search 50% Lagniappe Alaska LLC 50% NS0704 393856 $515,097.60 2,560.00 10.35 Oil Search 50% Lagniappe Alaska LLC 50% NS0705 393857 $515,097.60 2,560.00 10.35 Oil Search 50% Lagniappe Alaska LLC 50% NS0708 393858 $381,721.60 2,560.00 10.35 Oil Search 50% Lagniappe Alaska LLC 50% NS0709 393859 $381,721.60 2,560.00 10.35 Oil Search 50% Lagniappe Alaska LLC 50% NS0710 393860 $514,969.60 2,560.00 10.35 Oil Search 50% Lagniappe Alaska LLC 50% NS0711 393861 $514,969.60 2,560.00 10.35 Oil Search 50% Lagniappe Alaska LLC 50% NS0712 393862 $515,097.60 2,560.00 10.35 Oil Search 50% Lagniappe Alaska LLC 50% NS0713 393863 $514,969.60 2,560.00 10.35 Oil Search 50% Lagniappe Alaska LLC 50% NS0714 393864 $514,969.60 2,560.00 10.35 Oil Search 50% Lagniappe Alaska LLC 50% NS0715 393865 $515,097.60 2,560.00 10.35 Oil Search 50% Lagniappe Alaska LLC 50% NS0719 393866 $181,836.80 2,560.00 10.35 Oil Search 50% Lagniappe Alaska LLC 50% NS0720 393867 $258,739.20 2,560.00 10.35 Oil Search 50% Lagniappe Alaska LLC 50% NS0721 393868 $310,425.60 2,560.00 10.35 Oil Search 50% Lagniappe Alaska LLC 50% NS0722 393869 $181,836.80 2,560.00 10.35 Oil Search 50% Lagniappe Alaska LLC 50% NS0723 393870 $258,739.20 2,560.00 10.35 Oil Search 50% Lagniappe Alaska LLC 50% NS0724 393871 $310,425.60 2,560.00 10.35 Oil Search 50% Source: IHS Markit $14,143,315.20 195,200.00 789 © 2019 IHS Markit

Oil Search has exercised a right to acquire a 50% operating interest in 120 leases totalling 878km² in the eastern Alaska North Slope. These leases were run by Lagniappe Alaska LLC, an Armstrong subsidiary.

On 9 July 2019, Perenco plc (Perenco) has been awarded by Gabonese authorities the Olowi permit. The signed agreement commits Perenco not only for the exploitation of oil but also for the implementation of an LNG project. The former operator, CNR decided to not renew the permit after the expiration of the license on 30 April 2019. The demobilisation of the FPSO “Knock Allan” located at the Olowi Marin field was effective on 31 January 2019. Perenco’s general manager in Gabon, Baptiste Breton, said that his company will develop the gas potential of the Olowi Marin field, liquefy it and export it. The field that holds 590 Bcf of gas in place, according to CNR, could have the potential to produce some 85,000 Mcf/d. We assumed that Perenco is operator of the licence with 100% interest. Background information The Olowi permit contains the Olowi Marin oil and gas field that was operated and produced by CNR for ten years. The Olowi field has been delineated by the drilling of 15 wells by initial operator Pioneer and is characterized by an oil rim of light crude (34° API) which is overlain by an extensive gas cap. Then the next operator CNR focused on the development of the oil rim and cumulative production reached about 8 MMbo since inception in April 2009.

Perenco (100%) has been awarded by Gabonese authorities the Olowi permit.

Vic/P70, deepwater Gippsland Basin, WD 2,300m, follow-up to 2018 Baldfish + Hairtail wells (P&A’d), ops terminated, Ocean Monarch SS released from site 29 Jan '20.

Sculpin 1 nfw. (ExxonMobil 100%) in Vic/P70, follow-up to 2018 Baldfish + Hairtail wells, ops terminated, Results are not available. WD=2300m.

Shell has transferred its 40% interest and operatorship in PL 793 to Equinor with effect from 28 September 2018 (reported by the NPD on 7 October 2018). The APA 2014 licence covers 227 sq km over parts of blocks 6407/7, 6407/8, 6407/10 and 6407/11 immediately southeast of Njord. A well was drilled on the Portrush prospect in 2015 but it was a dry hole. Two earlier wells which lie within the licence both encountered weak shows but are also classified as dry holes by the NPD. Portrush well 6407/10-5 proved a 330 m Upper Jurassic Rogn Formation section which contained 134 m of sands but no hydrocarbons. The prospect was mapped as an analogue of the nearby Pil and Bue discoveries (renamed Fenja). Interest in PL 793 is now divided between Equinor Energy AS (50% + operator), Faroe Petroleum Norge AS (20%), Petoro AS (20%) and Neptune Energy Norge AS (10%).

Shell has transferred its 40% interest and operatorship in PL 793 to Equinor (->50% op, Faroe Petr. 20%, Petoro 20%, Neptune Energy 10%).

Egyptian Natural Gas Holding Co. (EGAS) has awarded 5 of its of its 16 blocks proposed in its 2018 bid round, namely North Sidi Gaber (Block 4), North El Fanar (Block 6), East Damanhur (Block 10), West Sherbin (Block 11) and Northeast El Amereya (Block 3). Egyptian General Petroleum Corporation (EGPC) has awarded 7 of its of its 11 blocks proposed in its 2018 bid round, namely North Beni Suef (Block 5), West El Fayoum (Faiyum) (Block 7), South Abu Sennan (Block 10), Southeast Siwa (Block 11), Southeast Horus (Block 9), West Amer (Block 2) and Northwest El Amal (Block 4)

Egyptian Natural Gas Holding Co. (EGAS) has awarded 5 of its of its 16 blocks proposed in its 2018 bid round, namely North Sidi Gaber (Block 4), North El Fanar (Block 6), East Damanhur (Block 10), West Sherbin (Block 11) and Northeast El Amereya (Block 3). Egyptian General Petroleum Corporation (EGPC) has awarded 7 of its of its 11 blocks proposed in its 2018 bid round, namely North Beni Suef (Block 5), West El Fayoum (Faiyum) (Block 7), South Abu Sennan (Block 10), Southeast Siwa (Block 11), Southeast Horus (Block 9), West Amer (Block 2) and Northwest El Amal (Block 4)

Petrobras suspended with oil shows the 1-FAT-001D-BA (1-BRSA-1366D-BA) directional new-field wildcat (NFW) in the REC-T-080 block in the onshore Reconcavo Basin during late-January 2019.  Petrobras filed an oil show report for the well with the ANP on 22 January 2019. The well was spudded on 21 December 2018. The NFW had a proposed total depth (PTD) of 2,000 m measured depth (MD) and 1,507 m true vertical depth (TVD). The well was targeting the Early Cretaceous Candeias Formation. The NFW is located in the western central area of the block approximately 1.7 km south-west of the 2016 plugged and abandoned dry 1-GC-001D-BA (1-BRSA-1336D-BA). Petrobras has 100% working interest in the contract.    On 17 February 2016, Petrobras plugged and abandoned dry the 1-GC-001D-BA (1-BRSA-1336D-BA) directional new-field wildcat (NFW) in the REC-T-080 block.  The operator filed no show reports for the well through early March 2016.  It reached a final total depth (TD) of 3,121 m on 8 February 2016.  The NFW was spudded on 24 December 2015.  It had a proposed total depth (PTD) of 3,455 m measured depth (MD) and 3,280 m true vertical depth (TVD). The Early Cretaceous Agua Grande Formation was the primary objective.  The NFW is located in the north central area of the REC-T-080 about 1.85 km west of the Fazenda Imbe field limits.  Petrobras has 100% working interest in the contract that was awarded in the ANP Round 12 on 15 May 2014.

Brazil (Central Reconcavo Sub-basin (Reconcavo B.)) Agua Grande

JKX Oil & Gas is believed to be in the final stages of divesting 6 devt and prod areas in E. Hungary, namely: Emod V (100 sq km), Hajdunanas IV (28 sq km), Hajdunanas V (7 sq km), Jaszkiser II (6 sq km), Pely I (18 sq km) and Tiszavasvari IV (46 sq km). More from GEPS.

JKX Oil & Gas is believed to be in the final stages of divesting 6 devt and prod areas in E. Hungary, namely: Emod V (100 sq km), Hajdunanas IV (28 sq km), Hajdunanas V (7 sq km), Jaszkiser II (6 sq km), Pely I (18 sq km) and Tiszavasvari IV (46 sq km).

Cue Energy Resources Ltd has announced that it is looking to farm-down interest in its interest in exploration permit WA-359-P, located in an under explored region of the northern Exmouth Plateau, North Carnarvon Basin. The company is offering 20% interest in the permit in return for participation and part-funding of a drilling programme to target the Ironbark Prospect. In mid-2017 Cue reported that it was in discussion with several parties that are evaluating the farm-in opportunity. Cue had held 100% interest in the permit.  However, in a deal announced on 29 November 2017, Cue has agreed to farm-out 21% interest in WA-359-P to Beach Energy in return for a one-off payment to Cue of AUD 900,000, for past costs, and future payments equating up to 4% of Cue’s cost for the drilling of the Ironbark 1 exploration well.  In additional to this, BP has an option to acquire a 42.5% interest in WA-359-P as part of its farm-in to WA-409-P. BP has the option, as part of a larger farm-in agreement, to acquire 42.5% interest in WA-359-P. The option was valid through until May 2017, but was initially extended to 25 October 2017 and then again to 25 April 2018. This was then further extended, in mid-April 2018, to October 2018 (pending a permit suspension). The permit was extended and suspended on 8 August 2018 for a period of 12 months, effective from the previous expiry schedule on 25 April 2018. The option to acquire interest in WA-359-P is supplementary to BP’s acquisition of interest in WA-409-P, also in the Carnarvon Basin and adjacent to WA-359-P. On 20 December 2016 Cue Energy announced that the transfer of 80% equity and operatorship of WA-409-P to BP Developments Australia had been approved by NOPTA. An agreement was first entered into by the two companies on 13 October 2016. WA-359-P, which covers an area of 649 sq km, was awarded on 1 February 2005. Cue is offering a farm-in opportunity to help fund the drilling of the Ironbark Prospect, scheduled for 2018/2019. If BP and Beach completed their respective farm-ins to the permit it will fund up to 54% of the drilling costs, with gross estimated dry-hold costs being AUD 30 – 50 million. The commitment to drill the well must be made prior to the commencement of the final term. Geotechnical studies are also planned to be undertaken as part of the ongoing work commitments. Gas prospect, Ironbark, is located in the Triassic intra-Mungaroo Formation sands, which has already been proven as a significant gas bearing reservoir in the Perseus and North Rankin fields located approximately 25 km to the south. An area of up to 400 sq km has been assigned to the prospect, spanning both permits, and is estimated to contain unrisked prospective gas resources in excess of 15 Tcf (based on a technical estimated by Cue). It has been reported that the well would have an expected total depth of around 3,500 m. The WA-359-P period three work commitment - drilling of one exploration well (Ironbark 1), has been suspended since 26 October 2015 and will remain so until 25 April 2018 after Cue received approval to further suspend the permit on 11 April 2016. Cue applied for the suspension to permit time to finalise the planning of drilling the Ironbark prospect and secure a farm in partner (in which BP will now assist). The Brigadier 1 well, completed in 1978, is the only well within WA-359-P. Shows were recorded within the base Cretaceous/Top North Rankin Formation around a depth of 2,810 m. The main oil prospect within WA-359-P, Sherlock (a combined structural and stratigraphic trap), is estimated to contain 300 MMb oil in place. Work was undertaken in 2014 to lower the geological risk of the prospect.  The primary target is expected below the base Cretaceous. The North Carnarvon Basin is one of the most prospective resource provinces within Australia with over 150 producing and developing fields. Reprocessing of existing multi-client 3D seismic data over the WA-359-P area was completed in November 2013 which has facilitated a geological and geophysical study conducted by Cue. The study is expected to firm up a drilling location, for which Cue seeks a joint venture partner with material interest available, capable of operating and funding the drilling phase of exploration within the permit.  A physical dataroom is opened for interested parties. WA-409-P was initially part of the farm-in in opportunity in conjunction with WA-359-P. Upon BP’s entry, it has agreed to fund Cue’s work programme costs, in WA-409-P, based on the remaining 20% equity interest over the next three years, will be fully funded by BP (estimated at AUD 400,000). The permit was under a 12 month work suspension prior to reaching its expiry date on 29 April 2016. Cue had lodged an application for renewal which was granted on 13 October 2016 for a five year period. One exploration well has been scheduled in term four, at a forecasted cost of AUD 50 million. WA-409-P, which now covers an area of 324 sq km, was awarded on 30 April 2008.  Cue acquired 100% interest after the withdrawal of joint venture partners Apache Energy and Moby Oil and Gas in February 2015. Apache had previously been granted two contract extensions/suspensions of the sixth year work programme, totaling 12 months. The extensions allow time to complete seismic reprocessing of existing Zeebries multi-client MC3D data (2011) and select potential well locations. This will now be conducted within the first three year term of the renewed work conditions. WA-359-P, which is located in water depths of 200 m to 500 m, was awarded on 24 January 2005.  Participants in the permit are: Cue Energy Resources (79% + operator) and Beach Energy Pty Ltd (21%).  A further 42.5% interest may be farmed out to BP. Companies interested in pursuing the farm-in opportunity should contact: Matthew Boyall, Commercial Manager Email: Matthew.Boyall@cuenrg.com.au Tel: +61 (0) 3 8610 4000

Cue Energy Resources Ltd has announced that it is looking to farm-down interest in its interest in exploration permit WA-359-P, located in an under explored region of the northern Exmouth Plateau, North Carnarvon Basin. The company is offering 20% interest in the permit in return for participation and part-funding of a drilling programme to target the Ironbark Prospect. In mid-2017 Cue reported that it was in discussion with several parties that are evaluating the farm-in opportunity.

On 4 November 2019, Hungarian Magyar Olaj- és Gázipari Nyrt. (MOL) announced it signed an agreement to acquire Chevron's 9.57% stake in the Azeri-Chirag-Guneshli field (ACG) and 8.9% stake in the Baku-Tbilisi-Ceyhan (BTC) pipeline. The transaction is valued at USD 1.57 billion (subject to adjustments at closing). After closing of the deal, MOL will be the third largest stake holder in ACG and BTC, after BP and SOCAR. In 2018, approximately 212 MMbbl (580,000 b/d) of oil were produced at ACG, which represents about 80% of Azerbaijan’s oil production. In December 2018, media reported Chevron’s and ExxonMobil’s intends to exit ACG. Background Information The ACG fields are located 60 kms east of the Absheron peninsula, in the Caspian Sea, on the regional Absheron-Pribalkhan zone of uplifts. This zone represents a string of structures running from the Absheron Peninsula to the Cheleken Peninsula in Western Turkmenistan. Initial 2P Reserves are estimated at 6.8 Bbbl of oil. On 31 October 2017, the Azeri Parliament ratified the new Azeri-Chirag-Guneshli (ACG) field PSA signed by partners on 14 September. SOCAR increased its take from 11.645% to 25%, while other participants decreased their stake. New ownership: BP-operator (30.37%), SOCAR (25%), Chevron (9.57%), INPEX (9.31%), Statoil (now Equinor) (7.27%), ExxonMobil (6.79%), TPAO (5.73%), ITOCHU (3.65%) and ONGC Videsh Limited (2.31%). In addition, Azerbaijan would receive 75% of production after cost recovery (currently 80%) and USD 3.6 billion in bonuses. Plans foresee investments in the amount of USD 40 billion during the next 32 years. The PSA is valid until 31 December 2049. The previous ownership in the PSA was: BP - operator (35.795%), SOCAR (11.645%), Chevron (11.27%), INPEX (10.96%), Statoil (now Equinor) (8.56%), ExxonMobil (8%), TPAO (6.75%), ITOCHU (4.3%), ONGC Videsh Limited (OVL) (2.72%). The contract was signed on 20 September 1994 for duration of 30 years. The BTC pipeline has a capacity of over 1 MMb/d for a total length of 1,768 km, crossing Azerbaijan (443 km), Georgia (249 km) and Turkey (1,076 km). BTC shareholders are BP (30.1%), SOCAR (25%), Chevron (8.9%), Statoil (now Equinor) (8.71%), TPAO (6.53%), ENI (5%), Total (5%), Itochu (3.4%), ExxonMobil (2.5%), Inpex (2.5%) and ONGC Videsh (2.36%).

Azerbaijan MOL (BP op 30.37%, Socar 25%, Inpex 9.31%, Equinor 7.27%, ExxonMobil 6.79%, TPAO 5.73%, Itochu 3.65% and OVL 2.31%) has agreed to acquire Chevron's 9,57% stake in the Azeri-Chirag-Guneshli (ACG) field, for US$ 1.57 billion (comprises an 8.9% stake in the Baku-Tbilisi-Ceyhan (BTC) pipeline).

Azinam has agreed in principle to become a 10% shareholder in OK Energy. A deal would result in Azinam holding 4.9% in the Shell-operated Northern Cape Ultra-Deep block (Orange Deepwater / ER 274), 37,254 sq km in the Orange Basin, partners Kosmos + OKE, and in the Equinor-run Algoa East block (ER 257), 6,654 sq km in the Algoa Basin, partners Total + OKE. It is recalled Azinam recently moved-into block 2B from Africa Energy (DEA 25 Feb).

Azinam reached an agreement to acquire a 49% interest in private OK Energy. The details of the transaction have not been disclosed. OK Energy holds a 10% stake in 2 offshore exploration rights

Genel's farm-out effort for the 5,122-sq km Sidi Moussa block (now Lagzira Offshore) has been once more set back, now to 3Q '20. The move is in aid of the appraisal / possible devt of the 2014 Sidi Moussa-1 oil discovery, Aaiun-Tarfaya Basin. Currently Genel (op), partner Onhym.

Genel's farm-out effort for the 5,122-sq km Sidi Moussa block (now Lagzira Offshore) has been once more set back, now to 3Q '20. The move is in aid of the appraisal / possible devt of the 2014 Sidi Moussa-1 oil discovery, Aaiun-Tarfaya Basin. Currently Genel (op), partner Onhym.

West Esh El Mellaha (WEEM) devt lease, S. onshore Gulf of Suez Basin, drilled 1-late Mar ’19, P&A at TD 2,879m (basement), Shams-2 rig. Target Nukhul, Matulla + Nubia fm’s. Eshpetco = Lukoil – EGPC JV.

Egypt, Esh El Mellaha

On 10 July 2019 Total announced that it has signed an agreement to divest a number of non-core UK assets to Petrogas NEO UK Ltd. The acquiring company is the exploration and production segment of the Oman based conglomerate MB Holding. Petrogas has partnered with private equity investor HitecVision for the deal. The overall consideration for the deal amounts to USD 635 million and the deal has an effective date of 1 January 2019. Completion of the deal is subject to regulatory approval and is expected to close in December 2019. A number of the assets involved in the acquisition were acquired by Total through the USD 7.45 billion acquisition of Maersk made in March 2018. Total stated the acquisition is in-line with its portfolio management strategy, aiming to lower its break-even point through optimizing capital allocation and divesting in high technical cost assets. Total’s primary objective is to maintain the organic break-even before dividend below USD 30/b.   Petrogas stated that through the acquisition it is taking on expected average 2019 production of 25,000 boe/d, putting it among the top 20 producers. Through the deal Petrogas will take over 110 employees and contractors through picking up operatorship of assets (Quad 15 and Flyndre) and a fully owned FPSO. Petrogas along with HitecVision plan to become a full-cycle North Sea operator focusing on combining value creation in the North Sea with high environmental, social and Governance standards. The Total acquisition is the first step in the implementation of this strategy and will provide further expansion through organic and in-organic activities which include growing the operatorship position further. Petrogas believes that the assets acquired provide a number of organic growth opportunities including infill drilling and development discoveries close to infrastructure. Assets acquired by Petrogas Field Interest sold Operator Dumbarton 100% TOTAL Balloch 100% Lochranza 100% Drumtochty 100% Flyndre 65.94% Affleck 66.67% Cawdor 60.60% Golden Eagle 31.56% CNOOC Scott 5.16% Telford 2.36%

United Kingdom, Golden Eagle

The Government of Guinea has divided the country’s offshore area into several blocks. Direct negotiations with the government are possible. The licensing authority is the Ministry of Mines and Geology. Interested parties should contact the Office National des Pétroles (ONAP) Director General: Famourou Kouruma Tel: +224 622 376 262   Director of Exploration and Production: Mohamed Bangoura Tel: +224 655 454 941 Email: drmobangoura@gmail.com   The available open blocks as of June 2020 are listed in the table below. Twenty-seven blocks are available. There was no change in the list compared to the previous one. Total open acreage amounts to 82,020 sq km, of which 69,441 is offshore and 12,579 is onshore.   Open blocks       Block Name Area (sq km) Situation Block Basin Block 1 5,667 onshore Bove Basin Block 2 6,911 onshore Bove Basin Block A1 2,158 offshore Senegal (M.S.G.B.C.) Basin Block A2 2,423 offshore Senegal (M.S.G.B.C.) Basin Block A3 2,853 offshore Senegal (M.S.G.B.C.) Basin Block A5 1,668 offshore Senegal (M.S.G.B.C.) Basin Block B1 2,357 offshore Senegal (M.S.G.B.C.) Basin Block B2 2,544 offshore Senegal (M.S.G.B.C.) Basin Block B3 2,997 offshore Senegal (M.S.G.B.C.) Basin Block B4 5,612 offshore Senegal (M.S.G.B.C.) Basin Block B5 2,740 offshore Sierra Leone Deep Sea Basin Block C1 2,366 offshore Senegal (M.S.G.B.C.) Basin Block C3 1,989 offshore Senegal (M.S.G.B.C.) Basin Block C4 5,429 offshore Senegal (M.S.G.B.C.) Basin Block C5 1,647 offshore Sierra Leone Deep Sea Basin Block D1 2,402 offshore Senegal (M.S.G.B.C.) Basin Block D2 2,537 offshore Senegal (M.S.G.B.C.) Basin Block D3 4,172 offshore Senegal (M.S.G.B.C.) Basin Block D4 4,607 offshore Sierra Leone Sub-basin (Sra Leone-Liberia Basin) Block E1 2,402 offshore Senegal (M.S.G.B.C.) Basin Block E2 2,558 offshore Senegal (M.S.G.B.C.) Basin Block E3 3,299 offshore Sierra Leone Sub-basin (Sra Leone-Liberia Basin) Block E4 481 offshore Sierra Leone Sub-basin (Sra Leone-Liberia Basin) Block F1 2,360 offshore Senegal (M.S.G.B.C.) Basin Block F2 2,490 offshore Sierra Leone Sub-basin (Sra Leone-Liberia Basin) Block F3 2,802 offshore Sierra Leone Sub-basin (Sra Leone-Liberia Basin) Block G1 2,546 offshore Sierra Leone Sub-basin (Sra Leone-Liberia Basin)

Guinea, not found

Following tests for gas in two potential reservoir formations, OMV plugged and suspended its XN 3 NFW in Q3 2017. The well is the company's first on the East Abu Dhabi Exploration Area and was spudded on 1 December 2016. It reached a TD of 4,880m in the Jurassic in March.<P />OMV signed an upstream exploration agreement with Abu Dhabi National Oil Co (ADNOC) on 24 June 2013 to jointly explore the underexplored eastern onshore region of the UAE's largest emirate. A comprehensive 2D and 3D seismic programme was conducted over the acreage between June 2014 - February 2015, with the 3D survey covering about 3,000 sq km of desert environment. It is understood that OMV has committed to drilling two wells. OMV East Abu Dhabi Exploration GmbH holds a 60% interest and is partnered by ADNOC (40%).

Not Found

On 27 January 2020, Sharjah National Oil Corporation (SNOC) confirmed that the Mahani 1 wildcat had tested gas and condensate within its 264 sq km onshore Block B concession. The well had been spudded with a Cretaceous, Thamama Formation primary objective during late December 2018. It was subsequently drilled to TD at 4,449m (14,597ft) during 4Q 2019, following which it tested gas at rates "up to" the equivalent of 50 million cubic feet a day (MMcf/d) along with associated condensate from Thamama carbonates. Eni SpA had confirmed its acquisition of a 50% stake in the concession on 13 January 2019 (post-spud). SNOC on behalf of the Petroleum Council of the Emirate of Sharjah (SPC) launched the Sharjah 2018 License Round for three onshore blocks (A, B and C) in June 2018 for which bids had been due for submission on 9 December 2018. The company previously reported that it had completed a new 483 sq km 3D onshore survey during February 2017, however it transpires that up to 851 sq km of “new” onshore 3D and 200 sq km of 2013 vintage 3D data had been made available. Of note is that SNOC’s initial interpretation of the newly acquired seismic had led it to believe that “most” historical wells were either drilled off structure or had failed to reach Thamama Group carbonate objectives. The three onshore bid blocks offered by SNOC covered an area of 1,885 sq km. They included developed hydrocarbon discoveries, along with a range of undrilled leads, prospects and untested plays. A WesternGeco land crew had initiated SNOC’s latest seismic survey in late October 2016. It was intended to support the forthcoming exploration drilling campaign, which is being devised to help meet those growing energy requirements through the discovery of additional domestic resources. Seismic data processing was completed during 1H 2017 in Schlumberger’s Abu Dhabi processing center using reverse time migration to image the complex geology. During February 2014 a decree signed by His Highness Dr Shaikh Sultan Bin Mohammad Al Qasimi, Supreme Council Member and Ruler of Sharjah was promulgated formally merging the Sharjah Liquefaction Gas Company (Shalco) and Sharjah Oil Company (SOC) into a new entity to be known as the Sharjah National Oil Corporation (SNOC). The SNOC is owned by the government, but it operates autonomously on a commercial basis and is headquartered in Sharjah City. The Sharjah Petroleum Council was created in 1999 as a result of a decree issued by Shaikh Sultan bin Muhammad Al Qasimi. The council was charged with oversight of the petroleum sector within the emirate, including upstream and downstream planning policy, legislation and investment. The council replaced the existing Department of Petroleum and Minerals which had been undertaking these roles since 1972. The chairman of the Department of Petroleum and Minerals, Shaikh Ahmad bin Sultan Al Qasimi was appointed chair of the new council.

Mahani 1 (State SNOC 50% op, Eni 50%) in Area B Concession, onshore, TD=4 449m, gas discovery in Thamama limestone, tested up to 50 MMcf/d lean gas + associated condensate, appraisal drilling planned. The new phase of exploration in the area, which has already been explored in the past, is targeting complex subthrust Jurassic and Cretaceous plays of the Arabian carbonate platform in the inner thrust zone of the Oman Fold belt and requires accurate and sophisticated seismic imaging.

Equinor spudded exploration well 35/10-6 on its Gabriel oil prospect in PL 827 S on 29 April 2020 using the “West Hercules” S/S. Both Equinor and the NPD had initially reported that the Gabriel well was 35/10-5, but the NPD has now re-classified that as a shallow gas well and no longer includes it in its list of exploration wells. PL 827 S, which covers a 52 sq km area over the northeastern part of block 35/10, lies immediately north of the company’s recent (late 2018) minor Gnomoria discovery and applies above Top Cretaceous. 35/10-6 was drilled to TD at 1,938 m in the Upper Paleocene Lista Formation. The Paleocene Balder Formation did not contain any sandstone but in the Paleocene Sele Formation there was 40 m of good quality sandstone. However, no hydrocarbons were present and the well was abandoned as a dry hole on 12 May 2020. Gabriel had potential, pre-drill, recoverable volumes of 5-34 MMboe according to partner DNO. The APA 2015 licence was originally awarded to a group consisting of Tullow, Statoil (Equinor) and Shell. Tullow (the original operator) withdrew in March 2017 and then in November 2018 Shell transferred its interest to DNO. In February 2020 DNO increased its equity by acquiring a further 19% from Equinor. Equinor’s Gnomoria well 35/10-4 A confirmed a section of poor reservoir quality sandstone in the Jurassic Heather Formation totalling 122 m. Oil was proven but no OWC was encountered. Estimated recoverable resources are 1.25 – 7.5 MMbo. PL 827 S is operated by Equinor Energy AS (51%). Equinor is partnered by DNO Norge AS (49%).

Equinor Energy AS PL 827 S - 35/10-6 (Gabriel) exploration - Abandoned, dry hole

As of late 2018, local sources indicated that technical operator Noble Energy Inc (Noble) was in the process of transferring its interest in the C-37 (Yoyo) permit, offshore Douala Basin, to an undisclosed company. The permit comprises a large gas and condensate deepwater discovery, namely Yoyo-Yolanda, which straddles the offshore border with Equatorial Guinea. Atlas Petroleum and Noble agreed in mid-2017 to jointly develop the asset as a unitized gas field. However, as of early 2019, the unitization agreement for the joint exploitation has still not been signed. Another ongoing issue for the development of this joint project is the setting of the reserves split between both countries. Geologically, the Cameroons part of the field (northeast) is situated on the updip sector, where larger reserves are believed to be concentrated. The reserves split will of course determine the interest split and ultimately the oil revenues attributed to each country. Both accumulations were discovered by technical operator Noble Energy in late 2007.

Cameroon Noble was in the process of transferring its interest in the C-37 (Yoyo) offshore permit, to an undisclosed company.

GK-OSN-2009/2, SW of GKS092NAA 1 field in Kutch shallow waters, TD 3,280, believed P&A dry early Oct ’18, Jindal Supreme JU.

GKS092NCA A Gin K-OSN-2009/2, SW of GKS092NAA 1 field in Kutch shallow waters, TD 3,280, believed P&A dry early Oct ’18, Jindal Supreme JU.

Subject to government approval, DNO and Wellesley with withdraw from PL 990, leaving operator Equinor with a 100% interest. A drilling decision has been made on the licence, with Equinor wishing to proceed but DNO and Wellesley declining. Drilling will take place at the Kvernbit / Mimung North prospects once Equinor has found a new partner for PL 990. The company is also looking at further prospectivity within the licence. PL 990 lies in the North Viking Graben between Vega and Visund and immediately north and east of Afrodite. It covers a 362 sq km area over parts of blocks 34/9, 35/7 and 35/10 and was awarded in APA 2018. Afrodite well 34/12-1 was drilled on a Jurassic horst structure by Eni in 2007 / 2008. It confirmed 52 m of net pay (gas condensate) in the Middle Jurassic Brent Group with no GWC. However, reservoir properties were poor, with an average of 13% porosity and less than 0.1 mD of permeability. Gas flowed at a maximum rate of 10 MMcf/d through a 40/64" choke and the total amount of condensate recovered at surface was 148 barrels. Following completion of the withdrawals, interest in PL 990 will be held solely by Equinor Energy AS.

DNO and Wellesley with withdraw from PL 990, leaving operator Equinor with a 100% interest.

EnQuest intends to execute its option to acquire BP's retained 75% interest in Magnus, and thus become sole Magnus licensee. EnQuest announced on 7 September 2018 that it is planning a rights issue to raise approximately GBPS 107 million (US$ 138 million) to cover US$ 100 million cash fee for BP's 75% stake and drilling two infill development wells at Magnus. The option is valid until 15 January 2019 and also includes 9.1% of Sullom Voe oil terminal (SVT), 27% in Northern Leg Gas Pipeline (NLGP) and 11.5% of Ninian Pipeline System (NPS). Total deal consideration is US$ 300 million base consideration potentially rising to US$ 1 billion depending on asset performance. Apart from the US$ 100 million cash portion at deal completion, the balance will be settled via a 37.5% asset cash flow interest, retained by BP up to the aforementioned US$ 1 billion maximum consideration. BP sold 25% operator share in Magnus oil field to EnQuest on 1 December 2017, backdated to the start of 2017. This is part of a larger deal, first announced on 24 January 2017, that gave EnQuest 3% of SVT, 9% of NLGP and 3.8% of NPS, for a total consideration of US$ 85 million, to be paid via cash flows from the assets. BP will remain liable for the existing wells, but EnQuest will pay 7.5% of BP's share of decommissioning costs, up to the amount of EnQuest's net receipts from the assets. EnQuest also has an option to manage Thistle and Deveron decommissioning, in exchange for US$ 50 million from BP. Magnus field is located in Northern North Sea part blocks 211/7a and 211/12a, with gross reserves of 63.4 MMboe and production of 16,600 boe/d. Current P193 - 211/7a & 211/12a and Magnus Field partners are EnQuest Heather Ltd (25% + Op) and BP Exploration Operating Company Ltd (75%).

United Kingdom, P193

Murphy has finally secured rights to block 15-2/17, 2,669 sq km in the Cuu Long Basin, having applied 2 years ago. It is partnered by PetroVietnam 35% and SK Innovation 25%. Murphy is planning to test the similar play concept tested by Lac Da Vang (LDV) in neighbouring block 15-1/05, i.e. the pre-tertiary fractured basement. Location map below from GEPS:

Murphy has finally secured rights to block 15-2/17, 2,669 sq km in the Cuu Long Basin, having applied 2 years ago. It is partnered by PetroVietnam 35% and SK Innovation 25%. Murphy is planning to test the similar play concept tested by Lac Da Vang (LDV) in neighbouring block 15-1/05, i.e. the pre-tertiary fractured basement.

United Oil and Gas Plc (United) has agreed an option to farm-in to block 49/29c (P2264) which contains the Acle prospect in the Southern North Sea. The company will acquire a total of 24% interest in the acreage from Swift Exploration Limited and Stelinmatvic Industries Ltd (12% from each) which currently hold 50% each in the acreage. In return for the interest United will pay 30% of the first exploration well on the prospect. The well has an estimated cost of USD 10 million. Execution of this option is dependent on further partners coming into the licence and a drilling commitment for the well. On 30 November 2018 Swift relinquished blocks 49/30b and 50/26a which are also part of P2264. Therefore, one block remains in the licence in which the Acle prospect sits. The Acle prospect is thought to hold gross recoverable resources of 50 Bcf to 160 Bcf and is located to the west of the Davy North gas field. Acle is thought to be a 2.5 sq km four-way dip closure with a further fault bounded upside. The reservoir is the Permian Rotliegendes formation as is common with most of the producing fields in the area. If an exploration campaign was successful then development could be via the Sean fields to the north of the prospect. Two wells have been drilled in the area which were both dry but these were believed to be off structure. Following the execution of the option along with other partners farming in to the acreage to drill a well, United Oil and Gas Plc will hold a 24% interest. Swift Exploration Limited and Stelinmatvic Industries Ltd interests would potentially change due to further farm-in partners.

United Oil and Gas Plc (United) has agreed an option to farm-in to block 49/29c (P2264) which contains the Acle prospect in the Southern North Sea. The company will acquire a total of 24% interest in the acreage from Swift Exploration Limited and Stelinmatvic Industries Ltd (12% from each) which currently hold 50% each in the acreage. In return for the interest United will pay 30% of the first exploration well on the prospect.

Talos Energy signed a deal to acquire Stone Energy, in late November 2017. The merger will result in the creation of a new offshore-focused exploration and production company, named Talos Energy Inc, which will be focused on E&P activity in the US Gulf of Mexico. The merger has been unanimously approved by the board of directors of the two companies. Each outstanding share of Stone common stock will be exchanged for one share of Talos common stock and the current Talos stakeholders will be issued an aggregate of ~34.2 million common shares. Talos will have an initial equity market capitalisation of ~US$ 1.9 billion and an enterprise value of ~US$ 2.5 billion. James M. Trimble, Stone's Interim Chief Executive Officer and President, said in a statement: "I want to thank our employees for their focus and dedication in positioning Stone for this important transaction. The team's management of Stone's assets and business in a safe and environmentally responsible manner will continue our success for the combined shareholder base. The combined company will be strategically positioned to drive meaningful production growth through complementary acreage positions. We look forward to this partnership with Tim and the Talos team." The transaction is anticipated to close in late Q1/early Q2 2018.

Not Found

Serica is to acquire further interests in the Bruce and Keith fields and associated infrastructure from BHP Billiton, namely 16% in Bruce and 31.83% in Keith. The deal will be retro-effective 1 Jan ‘18 subject to usual required approvals. This tags onto similar deals with BP + Total (completion pending) and will result in Serica holding resp. 94.25% and 91.67%. www.serica-energy.com.

United Kingdom, Keith

Lundin reported on 31 July 2018 that it has agreed a swap deal with DNO for a package of assets in the North and Barents seas. Lundin will acquire 15% interests in PL 921 and PL 924 and 10% interests in PL 926 and PL 929 from DNO in return for divesting 10% interests in PL 767, PL 825, PL 902 and PL 950 The deal is subject to government approval. PL 921 covers parts of blocks 32/4 and 32/7 and lies to the southeast of Troll. A commitment well is due to be drilled in this licence (probably in 2019) on the Gladsheim prospect. PL 924 is located northeast of Troll and covers parts of blocks 31/2, 31/3, 32/1 and 35/12. It contains dry hole 31/3-4 drilled by Tullow in 2013 / 2014 on the Mantra prospect. PL 926 covers parts of blocks 33/9, 33/12 and 34/10 between Statfjord and Gullfaks. Two wells (plus a sidetrack) lie within the licence – 33/9-18, 33/9-18 A (Statoil, dry holes, 1994 / 1995) and 34/10-39 S (Statoil, dry hole, 1995). PL 929 lies to the north of Gjoa and covers parts of blocks 35/6 and 36/4. PL 767 covers parts of blocks 7120/3, 7121/1, 7121/2 and 7121/4 and is located north of Snohvit North. A well is planned on the Setter / Pointer prospects in late 2018 / early 2019. PL 825 lies between Oseberg, Huldra and Veslefrikk and contains Norks Hydro’s 1982 / 1983 well 30/6-11 which had residual oil shows in the Middle Jurassic Brent Group, Lower Jurassic Cook Formation and the top part of the Lower Jurassic Statfjord Formation. A well was spudded on the Rungne prospect in October 2018. PL 902 covers parts of blocks 7120/1, 7120/2, 7120/3, 7120/4, 7120/5 and 7120/6 to the south of Alta and Gohta and contains Lundin’s Skalle gas discovery made by 7120/2-3 S in 2011 and the oil discovery made in 1989 by Shell’s 7120/1-2. PL 950 is located south of Snohvit and to the southwest of Alke North and South. It covers parts of blocks 7020/1, 7020/2 and 7120/11.

Norway (East Shetland B. (Viking Graben Province)) Gullfaks

Ancap has reportedly received a qualification request from Tullow on undisclosed acreage available in Uruguay's open door process. Kosmos has recently filed for blocks OFF 2 + 3 (DEA 15 Oct '19). is recalled Ancap's open-door process is biannual, with awards at the end of May and November every year. Contact: Santiago Ferro, Ancap, sferro@ancap.com.uy.

Ancap has reportedly received a qualification request from Tullow on undisclosed acreage available in Uruguay's open door process. Kosmos has recently submitted offers to state company ANCAP for two adjacent offshore blocks, OFF-2 and OFF-3, related to the ongoing Uruguay Open Round.

SK-320 off central Luconia, Sarawak, one of 2 wells planned with Buah Keras-1, P+A dry around 26 Jan ’18, Hakuryu 5 SS. Target Middle Miocene Cycle IV carbs. Mubadala (op), partners Petronas + Shell.

Malaysia (Central Luconia Province) Buah Keras 1 op. by MUBADALA I (55.0%, PETRONAS 25.0%, SHELL 20.0%) in SK-320 block

ExxonMobil has announced that its wholly owned affiliate, ExxonMobil Exploration and Production Mauritania Deepwater, has signed production sharing contracts with the government of Mauritania for three deepwater offshore blocks. 'These blocks further enhance ExxonMobil’s leading global deepwater acreage position,' said Steve Greenlee, president of ExxonMobil Exploration Company. 'We thank the government of Mauritania for the opportunity to evaluate the potential of this acreage using our expertise and advanced technology.' Blocks C22, C17 and C14 are located an average of 124 miles, or 200 kms, offshore Mauritania. Together they measure nearly 8.4 million acres in water depths ranging from 3,300 feet to 11,500 feet, or 1,000 meters to more than 3,500 meters. Following government approval of the contracts, ExxonMobil will begin exploration activities, including acquisition of seismic data and analysis. ExxonMobil will carry out the work program as operator with 90 percent interest. Societe Mauritanienne des Hydrocarbures et de Patrimoine Minier holds a 10 percent interest. Original article link Source: ExxonMobil

Mauritania, not found

Woodside is looking to reduce its 75% in the Scarborough gasfield in WA-01-R, North Carnarvon Basin, to ab. 40%. A data room opens this month although some discussions have already taken place. Likewise in the wholly-owned Pluto LNG Train 2 on the Burrup Peninsula, WA. BHP partners Scarborough with 25%.

Woodside is looking to reduce its 75% in the Scarborough gasfield in WA-01-R, North Carnarvon Basin, to ab. 40%. A data room opens this month although some discussions have already taken place. Likewise in the wholly-owned Pluto LNG Train 2 on the Burrup Peninsula, WA. BHP partners Scarborough with 25%.

As announced on 20 March 2018, Strata-X Energy Ltd (Strata-X) via its newly created subsidiary Jab Right Pty Ltd (Jab Right) was awarded two new prospecting licences. The new licences (PL016-2018 and PL017-2018) are understood to close to its existing prospecting licences (PL018-2018 and PL019-2018). PL016-2018 and PL017-2018 cover a combined area of 1,646 sq km within the Nana-Kalahari Basins. The licence schedule is as follows: Initial exploration period three years, two additional two-year renewal options are available (3+2+2). Strata-X operates the licences with a 100% interest via its local subsidiary.     

Botswana, not found

On 2 March 2020 Shearwater GeoServices confirmed the award by Total of a 3D seismic survey acquisition and Fast Track processing project using Shearwater's Reveal software in the 1-21 Han Asparuh licence. The acquisition commenced on approximately 10 March 2020 and it is expected to continue until mid-June 2020. On 8 April 2020 the 3D seismic acquisition was ongoing. The 3D seismic survey is being carried out by the "Oceanic Vega" vessel and it will cover an area of 5,500 sq km. Given the size of the survey, it will cover most of the licence east of the 2013 3D seismic survey. The drilling location of an exploration well will be defined after the seismic interpretation is complete. The well will be the fifth well on the licence and it is likely to be drilled in early 2021. The 1-21 Han Asparuh licence is set to expire in May 2020 but Total intend to extend the licence validity for an additional two years. Since 2016 Total drilled three exploration wells in the licence using the Noble Globetrotter II drillship: Polshkov 1, Rubin 1 and Melnik 1. Polshkov 1 was spudded in May 2016 targeting Lower Oligocene sandstones, Middle Eocene sandstones and Upper Jurassic to Lower Cretaceous carbonates. The well reached a total of 5,615 m and was plugged and abandoned as a discovery. Partner Repsol reported that the well encountered oil and gas in an Oligocene play. In January 2018 the company completed the drilling operations in the Rubin 1 exploration well. It was drilled in a water depth of about 1,500 m about 14 km northeast of the Polshkov 1 exploration well. It had a planned total depth of 5,500 m with several targets, but its main objective was the Polshkov High structure. The well encountered significant gas shows in the Middle Miocene. In December 2018 Total suspended its operations in the Melnik 1 exploration well. The well’s result was not communicated. It was spudded in a water depth of approximately 1,950 m. Melnik 1 had objectives in Eocene sandstones and Oligocene fans at a depth of approximately 5,500 m below sea level. Interest in the 14,220 sq km 1-21 Han Asparuh permit is held by Total E & P Bulgaria BV (40% + operator), OMV offshore Bulgaria GmbH (30%, operator until May 2014) and Repsol SA (30%).

Bulgaria, not found

AE-0024-2M-Okom-07, offshore Sureste Basin, 5km NNE of Wayil discovery, susp. results n/a late Nov ’18, Prospector II JU. PTD was 4,950m, target Cretaceous.

Yok 1EXP in AE-0024-2M-Okom-07, offshore Sureste Basin, 5km NNE of Wayil discovery, susp. results n/a late Nov ’18, target Cretaceous

ATP-1189-P, Cooper-Eromanga, drilled 10-19 Nov '19, TD 2,468m, suspended gas. Santos (op), partner Beach.

Leghorn 1 (Santos 60,66%, op, Beach 33,34%) in ATP 1189, gas discovery, having intersected gas in the target reservoir.

On 14 December 2017, it was announced that two bids submitted by a consortium of Total S.A., Eni International BV and JSC Novatek in Lebanon’s First Offshore Licensing Round had been approved by the cabinet. The consortium has been awarded Blocks 4 and 9. Exploratory drilling is expected to commence in early 2019. The initial exploration phase of the licences will last up to five years with a possible one year extension. The First Offshore Licensing Round closed on 12 October 2017. The Total consortium was the sole bidder, submitting two bids, one for Block 4 and one for Block 9. No other bids were made. The Lebanese Government was offering five offshore blocks (1,4,8,9 and 10) for exploration and production. Fifty-two international companies were pre-qualified to participate in the licensing round (46 pre-qualified at initial launch of the round in 2013 and an additional six companies pre-qualified at a second round in February/March 2017).  

Lebanon, Block 9

Aker BP has acquired a 10% stake in PL 1056, 4,549 sq km in the More Basin (blocks 6302/1 + 12, Tulipan discovery), in exchange for Shell getting 20% in PL 1005, 1,775 sq km over blocks 6404/9 + 12, 6405/4, 7 + 10 (Ellida discovery) in the deepwater Voring Basin. The deal is effective 30 Jun '20. PL 1005 partners now Aker BP (op), VÃ¥r + Shell and PL 1056 Shell (op), Petoro, DNO, Wintershall Dea + Aker BP.

Norway (More B.), PL 1056, Aker BP has acquired a 10% stake in PL 1056, 4,549 sq km in the More Basin (blocks 6302/1 + 12, Tulipan discovery), in exchange for Shell getting 20% in PL 1005, 1,775 sq km over blocks 6404/9 + 12, 6405/4, 7 + 10 (Ellida discovery) in the deepwater Voring Basin. The deal is effective 30 Jun '20. PL 1005 partners now Aker BP (op), VÃ¥r + Shell and PL 1056 Shell (op), Petoro, DNO, Wintershall Dea + Aker BP.

S. part of E X-30 Trident permit, Black Sea, WD 1,076m, TD reached, geologically successful however less so commercially, although a 46m gas-saturated intv was encountered in Miocene-Pliocene series. PTD was 3,250m, target gas in Tortonian-Messinian sands, Scarabeo 9 SS. Lukoil (op), partner Romgaz.

Romania (Black Sea B.) Trinity 1X op. by LUKOIL (88%), ROMGAZ (12%) in E X-30 Trident block, water depth 1076 m geologically successful however less so commercially, although a 46m gas-saturated intv was encountered in Miocene-Pliocene series. PTD was 3,250m, target gas in Tortonian-Messinian sands.

In late April 2020, press confirmed that Total and Tullow intend to reduce their interest in Block 10BB and Block 13T containing the Ngamia, Amosing and Twiga oil fields development project (Lokichar project) as well as in Block 10BA. According to Tullow, the partial farm-out by the latter and Total is progressing but with some delays induced by the COVID-19 crisis. Industry sources suggested that CNOOC would be interest in the Kenyan assets. The project is situated in the Lokichar Trough (EARS, East Branch). Considering the volatility in the oil market induced by the coronavirus disease 2019 (COVID-19) in March 2020, the Final Investment Decision (FID) for the Ngamia, Amosing and Twiga fields development project may be delayed to 2023. Before the crisis, the FID was expected in late 2020 with first oil production expected two to three years after. In February 2018 Tullow suggested to the Kenyan government to start the development phase with the Ngamia and Amosing fields. The Twiga field was added in February 2019 to the project. Tullow increased the oil production for the Early Oil Pilot Scheme (EOPS) from 600 b/d to 2,000 b/d in May 2019. In June 2019, several agreements around fiscal and commercial terms were signed between the joint-ventures partners and the government. In addition, FEED studies for the upstream and midstream project have been also completed. The development of the Foundation Stage will include the construction of a 60,000 to 80,000 b/d central processing facility (CPF) and the export pipeline to Lamu. In addition, 120 wells through 18 well pads for the Ngamia field will be involved and 70 wells through seven well pads for the Amosing field. The Foundation Stage is expected to produce about 38% of the 2C resources (210 MMbo out of 560 MMbo) with a plateau production between 60,000 and 80,000 b/d. The plateau production could be increase to 100,000 b/d with the development of the upside potential and the production of the remaining 2C resources. Pmean for the whole Lokichar Trough are estimated at 750 MMbbl. Tullow estimates total gross capex is expected to reach USD 2.9 billion (USD 1.8 billion for upstream and USD 1.1 billion for the pipeline). Interest in the licences is held by Tullow Kenya BV (50% + operator), Africa Oil BV (25%) and Total E&P Danmark A/S (25%).

Kenya, Block 10BA

Indonesia’s state oil company Pertamina has won a tender to operate Iran’s Mansouri field and it will sign a petroleum contract in early May, its upstream director told reporters on Wednesday.Pertamina will have an 80 percent participating interest in the field and the rest will go to its local partner, Pertamina director Syamsu Alam said, although he added that the company will look for other international partners to share operational risks.Pertamina wants to increase oil production in Mansouri to 250,000 barrels per day (bpd) from the current 60,000 bpd within 5 years, he added.Original article linkSource: Reuters

Iran, not found