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In late March 2019, Apex International Energy abandoned the West Badr El Din West C-1 (WBED-C1) (Hg 028-1) exploration well in the West Badr El Din exploration block, Abu Gharadiq basin as a dry hole after reaching a TD of 2,774 m in the Kharita Member. The well was spudded on 23 February 2019 with the “ECDC-2” land rig. It had a planned TD of 2,783 m and the Turonian Abu Roash C Member as primary objective and the Albian-Cenomanian Kharita Member as the secondary Objective. Apex International Energy operates the block with a 100% interest. Background Information On 27 August 2017, Egypt Oil Ministry announced that Apex International Energy was awarded the West Badre El Din (Block 8) and Southeast Meleiha (Block 9) blocks in the Western Desert as part of the Egyptian General Petroleum Company (EGPC) 2016 Bid Round. The company is committed to invest USD 27. 4 million for the acquisition of a 3D seismic survey and the drilling of six exploration wells during the first exploration phase. The signing bonuses amounted to USD 5.2 million.

Apex International Energy abandoned the West Badr El Din West C-1 (WBED-C1) (Hg 028-1) exploration well in the West Badr El Din exploration block, Abu Gharadiq basin as a dry hole after reaching a TD of 2,774 m in the Kharita Member.

Crown Point Energy reported on 4 December 2019, that it plugged and abandoned the Sur Rio Malargue x-1002(d), in the 1,041 sq km Cerro de los Leones license, northern Neuquen Basin. The drilling rig was the SAI-318. The well was spud on 10 November to test the Tertiary-Upper Cretaceous Sandstone on an extension of the structural crest. It reached 1,183m TD on 18 November and was abandoned after well log analysis confirmed no hydrocarbons present in the well.Crown Point Energy reported on 4 June 2019 that it was planning to spud two exploration wells in this exploration permit in the Mendoza province. These wells were planned for Q3 2019 at a cost of US$ 3.7 million. Crown Point acquired 214 sq km of 3D seismic to determine drilling locations in the northern portion of the block. The first NFW spud in the area, Sur Rio Malargue x-1001(d) was logged recently and shown to be a potential discovery. The company requested a four month extension for the exploration permit in this block to 23 February 2020 to complete the drilling and evaluation of that well.

Argentina, Cerro de los Leones

Accumulate (88 Energy sub) has agreed to acquire a 69.1% interest in 23 Great Bear Petroleum leases on the North Slope adjacent to its Icewine project for USD 206,388 cash. The company also obtained an oil & gas lease with the Arctic Slope Regional Corporation (ASRC) on 5 blocks west of the Icewine project on the Central North Slope.

Accumulate (88 Energy sub) has agreed to acquire a 69.1% interest in 23 Great Bear Petroleum leases on the North Slope adjacent to its Icewine project for USD 206,388 cash. The company also obtained an oil & gas lease with the Arctic Slope Regional Corporation (ASRC) on 5 blocks west of the Icewine project on the Central North Slope.

On 6 March 2018, DEA Deutsche Erdoel AG was granted an official award by the CNH for the CNH-A4.Ogarrio/2018 contract from the CNH-A4-Ogarrio/2017 farm-out bid round for the 156.27 sq km Ogarrio block in the onshore Sureste Basin.  DEA Deutsche Erdoel has a 50% working interest in the contract and is the operator and PEMEX has a 50% non-operated working interest. The contract is a license contract with a 25 year development phase and two possible five year extension periods.  The minimum work program has been set at 5,620 work units equivalent to USD 6.09 million at an oil price of between USD 60 to USD 65/bbl.  PEMEX has its 50% working interest carried up to USD 190 million of expenditures.  The JOA for the Ogarrio license contract has DEA Deutsche paying PEMEX a fee of USD 190 million for previous work conducted in the block.   

Dea will take a 50%+op. share in the CNH-A4-Ogarrio/2017 block (Ogarrio oilfield),

In November 2018 NIS reported that appraisal well Cestereg 1X situated in the Srednji Banat licence was successfully completed during Q3 2018. The drilling operations were concluded in June 2018 and the well was put on testing. The Cestereg discovery is situated about 1 km east of the Banatski Dvor gas field and 12 km north-northeast of the city of Zrenjanin. NIS drilled the Cestereg 2 gas discovery to a total depth of 1,350 m in October 1998. The objective was in Pontian sandstones. A 27-sq km 3D seismic survey was conducted over the area between October and December 1998 to define the extent of the discovery. On 18 June 1998 NIS spudded the Cestereg 4 appraisal well which was abandoned as a dry hole at some 1,000 m on 7 July 2000. The planned total depth was 1,387 m. Sidetrack Cestereg 4/1 was kicked off from Cestereg 4 on 10 July 2000 and it was also abandoned as a dry hole on 25 July 2000 at a total depth of 1,436 m. Between May and July 2000 NIS drilled the Cestereg 3 appraisal well to a total depth of 1,363 m. The well was completed with gas. Interest in the licence is held solely by NIS which is majority owned by Gazprom Neft (56.15%), the oil arm of Russia’s state-owned natural gas monopoly Gazprom.

Serbia (Banat Sub-basin (Pannonian B.)) Cestereg 2

1989 (non-commercial) discovery in block XX Kultak-Kamashi, Amu-Darya Basin, early April re-entry, work-over + 30m horiz deviation sidetrack, tested 6,9 MMcfg/d, to be stimulated. Izgancha-4 likewise tested gas + condensate in March. Field reserves now est. 171.3 Bcf, while appraisal drilling is also underway.

Re-entry + successful: Izgancha-2 expl 1989 (non-commercial) discovery in block XX Kultak-Kamashi, Amu-Darya Basin, early April re-entry, work-over + 30m horiz deviation sidetrack, tested 6,9 MMcfg/d, to be stimulated. Izgancha-4 likewise tested gas + condensate in March. Field reserves now est. 171.3 Bcf, while appraisal drilling is also underway.

In late April 2018, it was reported that Lebanon’s Minister of Energy & Water has requested that the Lebanese Petroleum Administration (LPA) commence preparations for a potential second offshore licensing round. The Council of Ministers subsequently approved the recommendations of the LPA on 17 May 2018. This second offshore licensing round is expected to be launched by the end of 2018 and will extend over a twelve month period. A pre-qualification round will be held in the first quarter of 2019 with submission of bids expected in May to October 2019. Lebanon’s First Offshore Licensing Round closed on 12 October 2017. A consortium of Total S.A., Eni International BV and JSC Novatek were awarded two blocks, Block 4 and 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. The 10 designated offshore Lebanese blocks cover the entire offshore area with areas ranging from approximately 1,260 sq km to 2,380 sq km.   Tentative Second Licensing Round Timeline     Dates Official Launching of Licensing Round and Announcement of Open Blocks Late 2018 Submission of Prequalification Applications Jan 2019  -  End April 2019 Declaration of Prequalification Results May 2019 Submission of Bids May 2019  -  End Oct 2019 Evaluation of Bids and CoM approval Nov 2019 Signature of EPAs Dec 2019   Meeting the LPA     Event Location Dates ONS Stavanger – Norway 27-31 Aug 2018 Gastech Barcelona – Spain 17-20 Sept 2018 Adipec Abu Dhabi – UAE 12-15 Nov 2018 Petex London – UK 27-29 Nov 2018

Lebanon Lebanon preparing for second offshore licensing round

Mari has picked-up Tullow’s 30% in the Kalchas 2969-7 EL,  2,061 sq km in the Sulaiman Fold Belt, effective 7 Jun ‘18. Partnership therefore becomes OGDC (op), Mari 50:50.

Pakistan, Kalchas 2969-7 EL

Concho Resources has completed its USD 9.5-billion, all-stock acquisition of RSP Permian, becoming the largest shale producer in the Permian Basin.

Concho Resources has completed its USD 9.5-billion, all-stock acquisition of RSP Permian, becoming the largest shale producer in the Permian Basin.

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%).

Rey Resources Ltd and Doriemus Plc entered into a farm-in agreement in March 2019, which will see Doriemus acquire interest in licence L 15, located in the Canning Basin.  Doriemus initiated the farm-in agreement on 5 March 2019. Doriemus is to acquire 50% interest in L 15 under the farm-in agreement. To acquire 50% interest, and operatorship, in L 15 Doriemus must fund up to AUD 1 million in development costs associated with bringing the Kora West field back into production over the first 12 months. Doriemus reported that funds were already available prior to completion of due diligence. Doriemus reported on 15 February 2019 that the interest sale of Horse Hill Developments, UK, has also provided strength to its balance sheet as the West Australian farm-ins progress. Additional spend could also be raised from a combination of cash reserves and production revenue from its 20% interest in the Lidsey oil field, located in the Wessex Basin, UK. L 15 is 100% owned by Gulliver Productions Pty Ltd, a wholly owned subsidiary of Rey Resources, and covers an area of 165 sq km over the Kora West field. The field was discovered in 1984 and produced around 20,000 bbl oil between 1989 and 1992. With 2P recoverable reserves of nearly 400,000 bbl, Doriemus plans to bring the Kora West field back into production by around May 2019. Doriemus reported on 15 February 2019 that it had completed its due diligence relating to the acquisition of interest in Rey Resources’ L 15 (West Kora) licence. The company planned to seek finalisation of the previously reported farm-in agreement and joint operating agreement.  Doriemus first announced on that it had entered into a farm-in deal with Rey Resources 31 December 2018, for two Canning Basin permits, exploration permit EP 487 (Derby Block) and production licence L 15 (West Kora). The companies signed two independent binding letters of intent for Doriemus to acquire 50% interest and operatorship in both assets. In Ep 487, the farm-in agreement was terminated in August 2019, after Doriemus failed to meet required funding conditions for the farm-in. L 15 was awarded on 1 April 2010. Should the farm-in be completed, interests will become: Doriemus Plc (50% + operator) and Gulliver Productions Pty Ltd (50%). Until this time, Gulliver Productions remains as operator with 100% interest. Doriemus currently holds minority, non-operated interest in three licences in onshore United Kingdom. Upon completion of the deal with Rey will see Doriemus enter Australia for the first time.

PL 216 (Dalwogan), 230 sq km in the Taroom Trough, Bowen-Surat Basin, was awarded for CBM ops on 23 Jul ’19 for 30 years

On 25 September 2019, the Federal Agency for Subsoil Use held an auction for three blocks in Khanty-Mansiysk (Yugra) Autonomous Okrug (Western Siberia). Surgutneftegaz emerged as the winner for all blocks. The company will obtain 25-year E&P licenses. The Vayskiy 1 block covers 422 sq km in the Ural-Frolov Province and encompasses seven prospects with combined oil resources estimated at 19 MMbbl. Seismic coverage amounts to 415 km. No exploratory wells have been drilled in the block. Resources (categories D1+D2) of the block are estimated at 25 MMbbl of oil. The starting price amounted to RUB 36.925 million (USD 0.57 million). Surgutneftegaz offered RUB 40.618 million (USD 0.63 million). The Vayskiy 2 block covers 326 sq km in the Ural-Frolov Province and encompasses a prospect with oil resources estimated at 3 MMbbl. Seismic coverage amounts to 360 km. One exploratory well has been drilled in the block. Resources (categories D1+D2) of the block are estimated at 19 MMbbl of oil. The starting price amounted to RUB 12.704 million (USD 0.2 million). Surgutneftegaz offered RUB 13.974 million (USD 0.22 million). The Vayskiy 4 block covers 572 sq km in the Ural-Frolov Province and encompasses six prospects with combined oil resources estimated at 12 MMbbl. Seismic coverage amounts to 400 km. No exploratory wells have been drilled in the block. Resources (categories D1+D2) of the block are estimated at 36 MMbbl of oil. The starting price amounted to RUB 33.029 million (USD 0.51 million). Surgutneftegaz offered RUB 36.332 million (USD 0.56 million).

Surgutneftegaz won 3 blocks in the Khanty-Mansiysk AO: Vayskiy 1, 2, 4.

Mozambique has defined a preliminary set of 9 blocks in the Zambezi Delta to be offered in its next (6th) licensing round, consultations with suitors planned to determine the final acreage on offer + data packages. The round is scheduled for 1H '20, preliminary preparations by 20 Feb, govt approvals yet required.

Mozambique has defined a preliminary set of 9 blocks in the Zambezi Delta to be offered in its next (6th) licensing round, consultations with suitors planned to determine the final acreage on offer + data packages. The round is scheduled for 1H '20, preliminary preparations by 20 Feb, govt approvals yet required

The state company Onhym has published a list of 36 open blocks located in various geological domains including explored areas with proven hydrocarbon potential and prospective areas still under-explored: Basin Names Block Name Onshore/Offshore Terrains Block Sq km Onshore Sq km Shelf Sq km DW Sq km Max WD (m) Aaiun-Tarfaya Basin Anzarane Offshore Onshore/Offshore DW~Shelf 100,927 929 28,241 71,757 3,500 Rharb-Prerif Basin Asilah Onshore Land 2,281 2,281       Tindouf Basin Assa Onshore Land 54,994 54,994       Rharb-Prerif Basin Boufakrane Onshore Land 10,225 10,225       Aaiun-Tarfaya Basin Boujdour Deep Offshore Offshore DW 17,766     17,766 3,000 Aaiun-Tarfaya Basin Boujdour Offshore I Offshore DW~Shelf 13,040   9,266 3,775 980 Aaiun-Tarfaya Basin Boujdour Offshore II Offshore Shelf 19,299   19,299   400 Aaiun-Tarfaya Basin Boujdour Onshore East Onshore Land 19,726 19,726       Aaiun-Tarfaya Basin Boujdour Onshore Ouest Onshore Land 14,862 14,862       Aaiun-Tarfaya Basin Dakhla-Lagwira Onshore Land 38,541 38,541       Rharb-Prerif Basin Gharb Offshore Nord Offshore DW~Shelf 9,397   1,983 7,414 2,200 Essaouira Basin Haouz Onshore Land 9,558 9,558       High Plateau Hassi Berkane Onshore Land 5,124 5,124       Aaiun-Tarfaya Basin Ifni Deep Offshore Offshore DW 11,229     11,229 1,300 Rharb-Prerif Basin Lixus Offshore Offshore DW~Shelf 2,309   1,748 562 600 Rharb-Prerif Basin Loukos Offshore Offshore DW~Shelf 1,873   1,582 291 1,100 Rharb-Prerif Basin Maamora Est Onshore Land 769 769       Tafelney Plateau Mazagan Offshore Offshore DW 8,742     8,742   Alboran Sea Basin Mediterranee II Offshore DW~Shelf 6,248   505 5,743 1,100 Alboran Sea Basin Mediterranee III Offshore DW~Shelf 10,622   1,588 9,034 1,000 Souss Trough Mir Left Offshore I Offshore DW~Shelf 1,537   1,345 192   Souss Trough Mir Left Offshore II Offshore DW~Shelf 1,738   1,622 116   Anti-Atlas Ouarzazate Onshore Land 4,442 4,442       Rharb-Prerif Basin Ouezzane (I+II+III) Onshore Land 4,110 4,110       Rharb-Prerif Basin Rharb Occidental Onshore Land 1,367 1,367       Rharb-Prerif Basin Rharb Oriental Onshore Land 1,801 1,801       Doukkala Basin Safi Offshore Nord Offshore DW~Shelf 6,206   4,737 1,469 500 Essaouira Basin Safi Offshore Sud Offshore DW~Shelf 5,936   4,537 1,399 1,000 Aaiun-Tarfaya Basin Sakia El Hamra Onshore Land 12,891 12,891       Souss Trough Souss Onshore Land 6,257 6,257       Tadla Basin Tadla I Onshore Land 18,821 18,821       Rharb-Prerif Basin Taounate Onshore Land 8,141 8,141       Tafelney Plateau Tarhazoute Offshore DW 7,771     7,771 2,500 Tafelney Plateau Ultra-Deep Rabat Offshore V Offshore DW 11,136     11,136 4,000   Interested parties may contact: Onhym, 34 Avenue Al Fadila, 10050 Rabat - Morocco - Tel 00 212 537 23 8000 - Fax: 00 212 537 28 16 34 & 00 212 537 28 16 26 - email: [email protected]

The state company Onhym has published a list of 36 open blocks located in various geological domains including explored areas with proven hydrocarbon potential and prospective areas still under-explored

An auction is planned before end 2018 for the Obskoy Yuzhnyy block, 321 sq km in the Ob Estuary of the Kara Sea. Obskoy Yuzhnyy is defined as a site of federal significance, which may imply the auction could be limited to participants where the state has a controlling stake (Gazprom, Rosneft or Zarubezhneft). Starting price USD 2.17 MM.

Russia, not found

ANPG, Chevron and Sonangol signed a cooperation agreement for the study and evaluation of the yet-unassigned Block 33, which covers 4,936 sq km in the Congo Fan in WDs of 1,500 – 2,500m. ExxonMobil drilled a small oil discovery (Calulu 1) in 2003. Chevron signed a similar agreement for Block 34 in June.

ANPG, Chevron and Sonangol signed a cooperation agreement for the study and evaluation of the yet-unassigned Block 33, which covers 4,936 sq km in the Congo Fan in WDs of 1,500 – 2,500m. ExxonMobil drilled a small oil discovery (Calulu 1) in 2003. Chevron signed a similar agreement for Block 34 in June.

KG-ONN-2004/1 block, KG swampy onshore, ops terminated (assumed P&A) at TD 3,840m (Basement) after encountering gas shows presumably in the target Eocene-Miocene and/or Cretaceous-Jurassic, Essar rig 3. Oil India (op), partner GeoGlobal Resources.

India (Krishna-Godavari B.) ? op. by OIL INDIA (90.0%, GEOGLOB BB 10.0%) in KG-ONN-2004/1 block

Cairn's exchange of a non-operating 50% stake with Shell in so far wholly-owned P2379 (Diadem prospect) in return for 50% in Shell’s P2380 (Jaws prospect) was completed on 23 Jun '20, having been agreed in March. Partnership becomes 50:50 in both:

United Kingdom (Central Graben Province), Cairn confirmed in its full year announcement in March 2020 that it had agreed an asset exchange agreement with Shell involving two licences P2379 (blocks 22/11b, 22/12b, 22/16b and 22/17c) and P2380 (block 22/12d).

Laizhou Bay, S. Bohai Basin, WD ca. 19m, reserves confirmed at 730 MMbo recoverable. The Kenli 6-1-3 discovery, TD 1,596m, established a 20m total pay in the Neogene, tested 1,178 bo/d in March (DEA 16 Mar '20).

Kenli 6-1 (CNOOC 100%), Laizhou Bay, Bozhong block , S. Bohai Basin, reserves confirmed at 730 MMbo recoverable. The Kenli 6-1-3 discovery, TD 1596m, WD 19m, established a 20m total pay in the Neogene, tested 1,178 bo/d in March.

On 14 November 2017, Qatar Petroleum (QP) entered into an agreement to acquire a 30% participating interest in Eni SpA's exploration and production sharing agreement (EPSA) for the 90,760 sq km Block 52 (Juzor Al Hallaniyyat) offshore Sultanate of Oman. Eni initially signed an agreement to operate the block (through its subsidiary Eni Oman B.V.) with an 85% interest, Oman Oil Company Exploration and Production LLC (OOCEP) (a subsidiary of Oman Oil Company S.A.O.C. (OOC)) holding the remaining 15%. QP subsequently signed a secondary agreement to acquire the 30% interest in Block 52 from Eni, subject to the consent of the competent authorities of the Sultanate of Oman. Background information The signing ceremonies were held in Muscat on 14 November 2017. They were attended by Oman Minister of Oil and Gas Mohammed bin Hamad Al Rumhi, OOC CEO Isam Al Zadjali, Eni CEO Claudio Descalzi, and QP President and CEO Saad Sherida Al Kaabi. Commenting on the occasion, Mr Al-Kaabi stated: “I would like to thank the Sultanate of Oman, the Ministry of Oil and Gas of the Sultanate of Oman and Oman Oil Company for their trust and support. We are proud to have this opportunity to participate in the exploration and development of the oil and gas resources in the Sultanate of Oman. This agreement represents a stepping-stone towards further mutually rewarding opportunities, where we hope that our cooperation will bring benefits to all involved especially to the Omani oil and gas sector and the people of Oman”. He added: “We are very pleased to enter into this agreement with our valued partner Eni, with whom we enjoy a close business relationship, which we aspire to strengthen further. I would like to thank the executives of Eni, Oman Oil and Qatar Petroleum and their respective teams who contributed to this important milestone,” Mr. Al-Kaabi concluded. Block 52, which is largely underexplored, is located in water depths ranging from 10 meters to over 2,000 meters. The Contractor parties will soon embark upon executing an exploration program involving the acquisition and processing of 3D seismic, which will be followed by exploration drilling. Eni is the designated Operator of the block, through its subsidiary Eni Oman B.V.​ Circle Oil Plc (Circle) was the previous operator and 100% interest holder in what was a 61,440 sq km Block 52 offshore concession. It had originally signed a nine year EPSA with MOG in September 2005, but following a contract extension, it felt compelled to announce its intention to relinquish the acreage on 1 June 2015 after failing to attract partners to share the risk of an exploration drilling campaign. Circle had shot and processed an initial 5,026 km marine 2D commitment survey by 1Q 2011. In November 2014 it reported that the results of a new nearshore 2D seismic survey acquired during 1H 2014 had confirmed the presence of shallow water prospects and that it had added a fourth prospect to its Block 52 portfolio.   Block 52 is located off the southeast coast of Oman and remains underexplored. It currently encompasses acreage formerly assigned to the 18,973 sq km Sawqirah Bay Offshore Block 23 and 3,396 sq km Sawqirah Coast Offshore Block 24. Both blocks had been open for some years, but were withdrawn when the Oman Government signed a six-year agreement with Spectrum Energy and Information Technology Limited to 'acquire, improve and market' offshore geophysical data to the east and southeast of the country from Ras Al Hadd in the Dhofar Governate down to the Yemen border on 28 April 2003. The Spectrum project with the MOG was terminated during 2H 2004, after the company had reprocessed 6,440 km of existing 2D data, much of which had been acquired by previous operators of the shallow water Sawqirah Bay acreage. Previous interest holders to parts of the acreage currently encompassed by the sizable block include Amoco, and Petroleum Development Oman LLC. Once the revised EPSA is formally approved, the co-venture group will consist of Eni (operator, 55%), QP (30%) and OOCEP (15%).

Qatar Petroleum (QP) has acquired a 30% interest in block 52 (Juzor Al Hallaniyyat), a 90760km² largely-unexplored unit, WD=10-2000m, from Eni (55%, Oman Oil 15%).

Commitment well in E. part of PEP 50119, Great South Basin, WD 1,335m, seismically-defined prospect, P&A dry at TMD 2,980m, COSL Prospector SS. OMV (op), partners Beach + Mitsui.

Tawhaki 1 explo. (OMV 52,93% op. Beach 30%, Mitsui 17,07%) in PEP 50119 block, reached a TD=2980m but no hc were present in the late Cretaceous sandstone target reservoirs. P&A dry. WD about 1200m

Roch had successful results trying to boost production on the Moy Aike license, Austral Basin, by re-entering and testing oil and gas in April 2018 on the Moy Aike x-5 exploration well. 126 bo/d and 1.41 MMcfg/d was the test rate from the Springhill Formation. The well is located in the center of the block and was spud in 2005 by YPF. Roch operates the Moi Aike Block with 30% and Phoenix holds 70% WI.

Roch had successful results trying to boost production on the Moy Aike license, Austral Basin, by re-entering and testing oil and gas in April 2018 on the Moy Aike x-5 exploration well. 126 bo/d and 1.41 MMcfg/d was the test rate from the Springhill Formation. The well is located in the center of the block and was spud in 2005 by YPF. Roch operates the Moi Aike Block with 30% and Phoenix holds 70% WI.

Ref. DEA 20 Dec ’17, GeoPark has signed for the full rights from Pluspetrol in the Aguada Baguales (CNQ-12M, 178 sq km), El Porvenir (CNQ-15M, 283 sq km) and Puesto Touquet (CNQ-27M, 140 sq km) blocks in the Neuquén Basin, for USD 52 MM.

Ref. DEA 20 Dec ’17, GeoPark has signed for the full rights from Pluspetrol in the Aguada Baguales (CNQ-12M, 178 sq km), El Porvenir (CNQ-15M, 283 sq km) and Puesto Touquet (CNQ-27M, 140 sq km) blocks in the Neuquén Basin, for USD 52 MM.

On 13 February 2020, Neptune Energy signed a concession agreement with the Egyptian Ministry of Petroleum and Natural Resources to operate the North West El Amal offshore block in the Gulf of Suez Basin. This block which covers 367 sq km is located in the central part of the Gulf of Suez, approximately 40 km south of Ras Gharib and 100 km north of Hurghada. According to the initial commitments stated in the award procedure, the agreement should include a minimum expenditure of USD 34.5 million for exploration operations and a signature bonus (undisclosed amount) for the drilling of 3 exploration wells. During the first exploration phase of three years, starting in 2020, the company is planning to acquire 100 sq km of 3D seismic data and to drill one well. Neptune Energy is a JV between China Investment Corporation (49%), Carlyle International Energy Partners (30.6%) and CVC Capital Partners (20.4%). North West El Amal is the company's sole block in Egypt.

Neptune Energy Group Ltd signed E&P operation agreement for North West El Amal offshore block, Gulf of Suez Basin

Partners Idemitsu (17.416%) and JX Nippon (15.168%) have exited P324 Galley Field block 15/23a with operator Repsol Sinopec now having 100% equity, effective 12 March 2018. Block 15/23a (65 sq km) covers the Galley Field, which was discovered by 15/23- 1Z (1974), and produced 62.1 MMbo and 88.5 Bcfg from Late Jurassic reservoir between March 1998 and September 2012, via subsea tieback to the Tartan Field A platform 25km NW. P324 was awarded on 10 June 1981 in the 4th Seaward Licensing Round. Other blocks in P324 are 13/22a, 14/20b (Highlander & Claymore) and 15/16b & c (part of Titan). Repsol Sinopec Resources UK Ltd is now 100% operator of P324 - 15/23a.

Idemitsu (17,4%) and JX Nippon (15,2%) have exited P324 (Galley Field). Operator Repsol Sinopec (->100%).

LINN Energy has signed a definitive agreement to sell its interest in conventional properties located in west Texas to an undisclosed buyer for a contract price of $119.5 million, subject to closing adjustments. The properties to be sold consist of approx. 28,000 net acres in west Texas with 2017 net production of approx. 6,300 BOE/d, proved developed reserves of ~14.4 MMBOE and proved developed PV-10 of approx. $106 million. Annualized field level cash flow on these properties is approx. $32 million. Estimated annual general and administrative expense for these properties is approx. $3 million, which is not included in the field level cash flow estimates provided. The sale is expected to close in the first quarter of 2018 with an effective date of January 1, 2018. This transaction is subject to satisfactory completion of title and environmental due diligence, as well as the satisfaction of closing conditions. RBC Richardson Barr and Jefferies LLC acted as co-financial advisors and Kirkland & Ellis LLP as legal counsel during the transaction. Original article link Source: LINN Energy

Linn Energy will sell its conventional west Texas properties (28 000 net acres with a net production of 6300 boe/d.) to an undisclosed buyer for US$119,5 MM.

On 14 October 2019, the Federal Agency for Subsoil Use held an auction for three blocks in Krasnoyarsk Kray (Eastern Siberia). The winning bids were submitted by Irkutsk Oil Company (INK) and Krasnoyarsk Oil & Gaz Company (KNK). The winners of the auction will obtain 27-year E&P licenses including a 7-year exploratory stage. Details of the offer are as follows: The Belyakskiy block covers 1,323 sq km in the Baykit Basin and encompasses several leads. One well has been drilled in the block. Reservoirs of the Riphean-Vendian section are the main exploratory target. Hydrocarbon resources (category D1) of the block are estimated at 40 MMbbl of oil and 579 Bcf of gas. The starting price amounted to RUB 13.5 million (USD 0.2 million). INK offered RUB 14.85 million (USD 0.23 million). The Teryanskiy block covers 3,700 sq km in the Baykit Basin. No wells have been drilled in the block. Reservoirs of the Riphean-Vendian section are the main exploratory target. Hydrocarbon resources (category D1) of the block are estimated at 44 MMbbl of oil and 2,308 Bcf of gas. The starting price amounted to RUB 15.5 million (USD 0.23 million). KNK offered RUB 17.05 million (USD 0.27 million). The Yelomovskiy block covers 2,892 sq km in the Baykit Basin. No wells have been drilled in the block. Reservoirs of the Riphean-Vendian section are the main exploratory target. Hydrocarbon resources (categories D1+D2) of the block are estimated at 26 MMbbl of oil and 3,415 Bcf of gas. The starting price amounted to RUB 18.1 million (USD 0.27 million). KNK offered RUB 19.91 million (USD 0.31 million).

Russia, not found

On 4 December 2017 Egdon Resources plc announced that it has acquired a 100% interest in licence P2304 (block 41/24) from Arenite Petroleum Limited and Europa Oil and Gas Limited. The block is located directly below Egdon’s P1929 licence which contains the 1966 Resolution gas discovery. Egdon has mapped this discovery extending south into licence P2304. The deal is subject to approval from the OGA. Licence P2304 was awarded to Europa and Arenite under the ‘Promote’ scheme in the 28th Offshore Licensing Round. Additional discoveries exist in the acreage acquired such as the 41/24a-1 Maxwell discovery and another discovery on the eastern fringe of the block made by well 41/25a-1. Egdon believe there is potential below the discoveries which are predominately Zechstein, Hauptdolomit Formation reservoirs, in the Carboniferous. Following the completion of the deal interest in the licence will be held by Egdon Resources U.K. Limited.

United Kingdom (Anglo-Dutch B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: Europa op. by COP (20.0%, EXXONMOBIL 50.0%, STATOIL 30.0%) to be check.

Dommo Energia has been called upon to relinquish its 40% interest in BS-004 to partners Enauta and Barra Energia who now each hold 50% in the contract area which comprises the Atlanta + Oliva leases. Background from GEPS.

Dommo Energia tranfered its 40% interest in BS-004, which comprises the Atlanta + Oliva leases, to partners Enauta (->50%) and Barra Energia (50%).

Local press reported in June 2020 that Eni would be looking at divesting its 40% non-operating stake in the C.C 6.EO exploitation concession covering the Vega oil field in the Sicily channel. The information was confirmed by the CEO of Energean – the company in the process of acquiring Edison E&P, the operator of the field - in an interview to an Italian energy media published on 14 July 2020. Edison and Eni have been trying to progress with the "Vega B" development project since 2012. It aims at unlocking 30.9 MMbbl of recoverable reserves trapped in the Vega B structure. It includes the installation of the “Vega B” new well-head platform located in 130 m of water approximately 6 km west-northwest of the existing “Vega A” platform, the drilling of 12 single-completion directional wells, the laying of two subsea pipelines linking the two platforms and the upgrade of the “Vega A” platform. To date, only four wells have received the approval from the environmental authorities, while the environmental impact assessment (EIA) for the eight remaining wells was rejected in mid-2019. Located 20 km off the southeastern coast of Sicily between Marina di Ravenna and Pozzallo, the Vega field was discovered by Seagull Exploration Italy in March 1981 and put on-stream in 1987. The production was suspended between 2007 and late-2009 to allow the construction and installation of a new Floating Storage and Offloading system (FSO "Leonis") tied into the platform via three underwater pipelines. As of 31 December 2019, it has produced 66.3 MMbbl of oil (15-16° API) and 3.6 Bcfg from one reservoir located below 2,422 m in the Siracusa Formation (Hettangian-Pliensbachian). 2P reserves at production start-up were estimated at 95 MMbbl of oil. According to the latest available figures, the field was producing at an average rate of 2,137 bo/d in March 2020. Originally covering 91 sq km off Ragusa, the C.C 6.EO concession was awarded to a group led by Montedison on 28 December 1982 for a 30-year period. The concession area was increased to 185 sq km in April 1984 and renewed for 10 years in 2012. In May 2020 Edison applied for a reduction of the surface to 93.83 sq km. Edison E&P SpA operates the concession with a 60% interest and Eni SpA is a partner with a 40% interest.

Italy (Pelagian B.), Eni could be looking into selling its 40% stake in the C.C 6.EO exploitation lease containing the Edison-operated Vega oilfield in the Sicily channel. C.C 6.EO operated by EDISON (60%), ENI SPA (40%).

Kanuku offshore block, WD 68m, TD 3,290m, ab. 4m net oil pay (27 API) in U. Cretaceous sst, suggesting an extension of the Cretaceous oil play from the Stabroek licence southwards into Kanuku, well to P&A, Valaris EXL II JU. Repsol (op), partners Tullow + Total.

Carapa-1 nfw Kanuku offshore block, WD 68m, TD 3,290m, ab. 4m net oil pay (27 API) in U. Cretaceous sst, suggesting an extension of the Cretaceous oil play from the Stabroek licence southwards into Kanuku, well to P&A, Valaris EXL II JU. Repsol (op), partners Tullow + Total.

JAPEX completed the well drilling in early July 2019 without result reported. JAPEX reported on 16 April 2019 that the company started the exploratory drilling at offshore Hidaka area of Hokkaido on April 13 2019, it is taken as part of the offshore exploration project commissioned by the Agency for Natural Resources and Energy of the Ministry of Economy, Trade and Industry (ANRE). “Ensco 8504” S/S is used for the drilling operation. The location of the well is approximately 50 kilometers offshore of Hidaka area of Hokkaido with a water depth of 1,070 m, which has been selected based on geophysical survey results obtained through a seismic vessel “SHIGEN” owned by ANRE. This exploratory well, with a PTD of 2,000 m below seabed, is aiming to evaluate the presence of oil and natural gas resources in the area. The well has been decided upon completion of the preparation works including a preliminary seabed survey at the location conducted in October 2018. The operation of exploratory drilling is expected to be carried out until late July, and the data obtained through the operations will be later utilized for analysis and evaluation purposes.    Most of Japan’s oil and gas fields are located along the western coastline, about 15 fields are on production in Japan. Major operators are INPEX and Japex. Japan’s major upstream oil and natural gas focus has been involved in locating new domestic reserves in the Niigata, Akita, Yamagata, and Hokkaido regions of Japan, targeting areas near existing oil and natural gas fields. In 2017 Japex announced that it decided to commence oil development of a shallow reservoir named the Takinoue Formation of the Yufutsu Oil and Gas Field in Tomakomai city of Hokkaido aiming commercial production of crude oil. The Takinoue Formation is a discovered but undeveloped reservoir which is shallower than the current oil and gas producing reservoir of the Field. Background Information In 2013, Japex tested oil and gas in Akebono SK-2D-1H, which flowed 1,300 bo/d and 159 Mscfg/d gas at an interval from 1,738 to 1,958m in the Takinoue formation, in the north of Yufutsu field in Hokkaido. Akebono SK-2D-1H, an appraisal well, was drilled in the Yukutsu field. The well was spudded on 22 February 2013 and reached a TD of 2,050m with objective in shallow reservoir in the Takinoue formation. After this shallow reservoir discovery Japex continued evaluation of the oil reserves in the entire shallow reservoir and property analysis of produced oil, and study of appropriate development plan and feasibility of the development. As a result, the company decided to commence development, since it is expected that crude oil reservoir spread out widely in the Takinoue Formation while the quality of oil is heavy. Japex will manage to secure the economic efficiency by reduction of development cost such as modification of existing wells and diversion of idle production facilities of the Yufutsu Oil and Gas Field. Japex commenced development from July 2017, proceeding modification of the existing wells to the production wells and conducting installation work of additional well-head facilities and heavy oil processing facilities in order. Commencement of oil production is anticipated in the second half of 2019 and initial production rate is expected 200 kiloliters per day. Japex also continue the reserves study for the shallow oil reservoir, and pursue the possibility of additional development. Japex has production operations in Hokkaido centered on the Yufutsu oil and gas field, which was discovered in 1989 when Minami Yufutsu SK-1 tested oil and gas. In 1992 Japex drilled Numanohata SK-1D and Akebono SK-1 to assess this discovery and both wells achieved oil and gas flow. With success of those three wells the Yufutsu field is confirmed and the field has been on production since 1996.

JAPEX completed the well drilling (as part of the offshore exploration project commissioned by the Agency for Natural Resources and Energy of the Ministry of Economy, Trade and Industry (ANRE) in early July 2019 without result reported. The location of the well is approximately 50km offshore of Hidaka area of Hokkaido with a WD=1070 m with PTD= 2000 m below seabed, is aiming to evaluate the presence of oil and natural gas resources in the area.

On 1 October 2018, Petrosen published a call for expressions of interest for the Senegal Offshore Sud and the Senegal Offshore Sud Profond blocks in a local newspaper. Interested parties should submit their expressions of interest to the Ministry of Petroleum and Energy no later than the 31 October 2018 16:00 hrs GMT. The offers should be addressed to: Ministère du Pétrole et des Energies Mr. Thierno Seydou LY Conseiller Technique n°1 en charge des projets pétroliers et gaziers 18, Boulevard de la République Immeuble Bourgi, 7e étage Dakar, Sénégal   Direct phone : +221 33 889 27 91 E-mail : [email protected]   Petrosen will organize a data room for the interested companies.   Senegal Offshore Sud Profond (SOSP) Cairn Energy’s discoveries in 2014 have proven hydrocarbon resources in the shelf edge play and the slope channel/fan play. This has de-risked prospects in the Senegal Offshore Sud Profond which is located around 90 km south of the discoveries, along the same shelf edge. The block covers 7,920 sq km Arbitration proceedings are currently under way on the SOSP block between former operator African Petroleum and the Senegal authorities. Senegal Offshore Sud In mid-2014, former operator Elenilto planned to acquire a 1,400 sq km 3D seismic survey over the Senegal Offshore Sud permit. The survey was to cover shallow-water salt dome leads and deep-water shelf edge prospects. The block covers 6,774 sq km to the east of the Senegal Offshore Sud Profond permit. An oil resource assessment (based on 2D seismic and wells) estimates a STOIIP exceeding 1.5 Bbo potential for the permit. Of the eights wells included in the perimeter, none has resulted in a discovery.

Senegal, Senegal Offshore Sud Profond

Commitment well in block 40/02, shallow waters astride the Khorat Swell and Malay Basin, P&A results n/a around 20 May ’18, PV Drilling II JU. Targets assumed U. Oligocene – M. Miocene J, K + L sst. Idemitsu (op), partner Sumitomo.

40/02-CS-1X Idemitsu (op), partner Sumitomo in block 40/02, shallow waters astride the Khorat Swell and Malay Basin, P&A results n/a, argets assumed U. Oligocene – M. Miocene J, K + L sst.

HitecVision-owned Sval Energi has transferred operating responsibility and 30% from its 70% stake in PL1057 to partner Lundin Petroleum (now 60% operator), effective 30 June 2020. This follows Sval's entry into the licence via acquisition of Capricorn Norge from Cairn Energy in February 2020. PL1057 covers 3,721 sq km of Norwegian Sea blocks 6302/2 & 3, 6303/1-3, 6402/11 & 12 and 6403/10-12. The licence was awarded on 14 February 2020 in APA 2020 with an obligation to acquire new 3D seismic and a three year drill decision. TGS commenced acquisition of its 2020 Atlantic Margin Survey programme (AM20) on 25 May 2020, which includes acreage licensed under PL1057 (NPD Survey code TGS20001). The acreage contains dry NFW 6403/10-1 (2002, Statoil, 3,398m) and encountered the targeted Cretaceous Nise Formation, but reservoir was poor. PL1057 partners are now Lundin Energy Norway AS (60% + Op) and Sval Energi AS (40%).

Norway (More B.) PL 1057 op. by SVAL EN (70%), LUNDIN EN (30%). HitecVision-owned Sval Energi has transferred operating responsibility and 30% from its 70% stake in PL1057 to partner Lundin Petroleum (now 60% operator), effective 30 June 2020. This follows Sval's entry into the licence via acquisition of Capricorn Norge from Cairn Energy in February 2020. PL1057 covers 3,721 sq km of Norwegian Sea blocks 6302/2 & 3, 6303/1-3, 6402/11 & 12 and 6403/10-12.

Serica Energy is looking for partners to help fund the drilling of an exploration well in Frontier Exploration Licence (FEL) 1/09 or FEL 4/13 (previously OP 11/01). The Muckish prospect lies within a tilted fault block in FEL 1/09 and is analogous to the Dooish discovery, which lies 30 km to the south. FEL 4/13 contains two large pre-Cretaceous prospects, Aghla More and Aghla Beg. The company has interpreted the presence of turbidite fans in FEL 4/13. The largest fan forms the Derryveagh prospect and is draped over the top of the Aghla More prospect. Technical work carried out by Serica in 2018 investigated the similarities in geology of the prospects in FEL 4/13 compared to the Muckish prospect through seismic attribute analysis. The results of this work were inconclusive due to seismic noise and volcanic interreference. Following the results of this study, in April 2019 Serica announced that an exploration well which would penetrate Derryveagh and Aghla More is the highest ranked opportunity and the company is seeking a farm-in partner to join in drilling. The Muckish prospect has an aerial closure of 31 sq km and vertical closure of 600 m. The prospect is interpreted to have a Permian to Middle Jurassic reservoir. Serica estimate P50 most likely recoverable resources of 1,285 Bcf and 85 MMbbl of condensate. Two further prospects, Muckish East and Mackoght, have also been identified in FEL 1/09 and are follow-up prospects in the event of success at Muckish. Aghla More is defined as a tilted fault block. Aghla Beg is a fractured basement play, with a seismic character analogous to the Lancaster and Clair fields, West-of-Shetlands, UK. Serica estimates P50 prospective resources for these stacked prospects in FEL 4/13 to be in the region of 4 Tcf and 250 MMbbl of condensate. Interest in licences FEL 1/09 and FEL 4/13 is held solely by Serica Energy (UK) Ltd. For further information regarding the Farm-out opportunity please contact: Clara Altobell, International Asset Manager Tel – 0044 (0) 207 487 7300 Email: [email protected]

Ireland, not found

Bids are invited as of today for the Open Acreage Licensing Programme (OALP-IV) offer,  7 blocks totalling 18,500 sq km available in 3 basins. Full details of OALP-IV, including blocks locations and bid procedure, will be available from the DGH website (http://online.dghindia.org/oalp) as of today, bid deadline 31 Oct ‘19. Despite an invitation for EoI’s, the govt has provided no clue on any interest level.

Bids are invited as of today for the Open Acreage Licensing Programme (OALP-IV) offer, 7 blocks totalling 18,500 sq km available in 3 basins. Full details of OALP-IV, including blocks locations and bid procedure, will be available from the DGH website (http://online.dghindia.org/oalp) as of today, bid deadline 31 Oct ‘19. Despite an invitation for EoI’s, the govt has provided no clue on any interest level.

On 13 November 2017 Hague and London Oil (HALO) reported that the takeover of non-operated offshore licences from Tullow was completed. Consequently HALO is a producer of more than 2,500 boe/d, having 2P reserves in excess of 12 MMboe and more than 19 MMboe in contingent resource The table below shows Tullow’s assets and its participation interest: Asset Operator Tullow’s participation E10 ENGIE 30% E11 ENGIE 30% E14 ENGIE 30% E15c ENGIE 25% E15a Wintershall 4.69% E15b Wintershall 21.12% E18a Wintershall 17.6% F13a Wintershall 4.69% J9 NAM 9.95% K8 NAM 9.95% K11 NAM 9.95% K7 NAM 9.95% K14 NAM 9.95% K15 NAM 9.95% L13 NAM 9.95%   HALO was formed in 2012 and combined with Wessex Oil in 2014. The company’s portfolio is so far comprised of assets in the United Kingdom, Western Sahara, French Guyana and the Scattered Islands.  

Netherlands, J9

On 17 May 2018, the Federal Agency for Subsoil Use held an auction for three blocks in Orenburg Oblast (Volga-Ural Province). The winning bids were submitted by Preobrazhenskneft, Sakmaraneft and Alfa-StroyTrans. Winners of the auction will obtain 25-year E&P licenses. Details of the offer are as follows: The Malokinelskiy block covers 329 sq km in the Buzuluk Depression and encompasses the Chesnokovskoye oil discovery with 3P reserves estimated at 0.4 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 37 MMbbl of oil and 51 Bcf of gas. The starting price amounted to RUB 28.2 million (USD 0.45 million). Preobrazhenskneft offered RUB 403.26 million (USD 6.5 million). The Klyuchevskoy block covers 169 sq km in the Buzuluk Depression and encompasses the Tikhonovskiy Zapadnyy and Tikhonovskiy prospects with combine oil resources estimated at 4 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 20 MMbbl of oil and 27 Bcf of gas. The starting price amounted to RUB 8 million (USD 0.13 million). Sakmaraneft offered RUB 8.8 million (USD 0.14 million). The Iskrovskiy block covers 318 sq km in the Buzuluk Depression. Hydrocarbon resources (category D1) of the block are estimated at 18 MMbbl of oil and 24 Bcf of gas. The starting price amounted to RUB 2.5 million (USD 0.04 million). Alfa-StroyTrans offered RUB 156.75 million (USD 2.5 million).

Federal Agency for Subsoil Use held an auction for three blocks in Orenburg Oblast (Volga-Ural Province). The winning bids were submitted by Preobrazhenskneft, Sakmaraneft and Alfa-StroyTrans.

Add. DEA 24 Apr ’18: Six blocks are on offer in Gambia’s current round: 4 offshore (A1, A3, A4, A6) and 2 onshore (Upper River and Lower River). 11 companies have pre-qualified to participate in the offer, paving the way for an invitation by the ministry for a selected company to negotiate a petroleum licence. Contacts: [email protected] (tel +220 745 33 13 / 996 33 13), or [email protected] (tel +220 997 77 02 / 986 77 01). Of note, an arbitration process is under way on A1 + A4 between African Petroleum (former optr) and the authorities.

Gambia, not found

Black Swan is looking to dilute its 100% in WA-503-P,  81 sq km in the offshore Barrow Basin (N. Carnarvon), 40-50% available. Drilling is tentatively planned by 2022. Contact: Conrad Todd, [email protected].

Black Swan is looking to dilute its 100% in WA-503-P, 81 sq km in the offshore Barrow Basin (N. Carnarvon), 40-50% available. Drilling is tentatively planned by 2022. Contact: Conrad Todd, [email protected].

Zarubezhneft is planning to acquire a 30% stake from PetroVietnam in block 09-2/09, 1,020 sq km in shallow waters of the Cuu Long Basin. The partners-to-be intend to develop the Kinh Ngu Trang (KNT) and Kinh Ngu Trang Nam (KTN) small oilfields therein.

Zarubezhneft is planning to acquire a 30% stake from PetroVietnam in 09-2/09 block (1020km²) in shallow waters.

SGH Energy Pty Ltd seeks a farm-in partner for exploration permit WA-377-P, located in the Caswell Sub-basin, Browse Basin. The permit, which is operated by SGH with 100% interest, contains the Echuca Shoals gas discovery plus additional prospects. Equity in the permit is on offer in return for contributing towards drilling a commitment exploration well to a total well depth of ~4,000m TVDSS, in water depths of around 200 m. The first well is required by 22 September 2018. Following a 12 month suspension and extension to allow for 3D seismic reprocessing, the permit is currently in permit year three of a five year term.  It is understood that the seismic reprocessing has further derisked the Schrodinger prospect through enhanced resolution, improved fault definition and reduced noise. Schrodinger is a stratigraphic trap targeting the Tithonian sands which were proven to contain gas by the Echuca Shoals-1 well drilled in 1983.  Schrodinger is estimated to contain 1.8 Tcf of gas in place. The permit also contains the Cooper Prospect which is estimated to contain 3 Tcf gas in place. Background SGH was granted a commitments change and validity extension on 13 December 2016 and again on 7 December 2017, which delays the commitment to drill an exploration well until 22 September 2018. The latest suspension facilitates SGH time to extend the work programme to include petrophysical studies and 100 sq km of seismic reprocessing and interpretation before moving towards drilling. The scheduled exploration well, which is forecasted to cost around AUD 20 million, could further appraise the Echuca Shoals gas field which was discovered in 1984, or target one of the two prospects identified. In December 2015, SGH reported that it was finalising drilling targets in preparation for drilling the first exploration well. On 28 January 2010 the Western Australian Government approved the transfer of 34% interest from Shell Development (Australia) Pty Ltd to Nexus Energy, as it had opted to withdraw from the permit, leaving Nexus with 100% interest. Nexus announced that the potential gas in place at the Echuca Shoals field within the permit is approximately 2 Tcf, with studies indicating the presence of a potential further 2 Tcf of gas in place. 3D seismic was acquired over the north east of the permit. One exploration well is known to have been drilled over the permit since it was awarded in March 2006. Fossetmaker 1, drilled in August 2007, was P&A after it encountered gas shows. Nexus Energy first offered equity in the permit in 2010 and the company has since been taken over by SGH on 31 December 2014. WA-377-P covers an area of 334 sq km and is 100% owned by SGH Energy WA377P Pty Ltd (a Seven Group Holdings subsidiary company).

SGH Energy Pty Ltd seeks a farm-in partner for exploration permit WA-377-P, located in the Caswell Sub-basin, Browse Basin. The permit, which is operated by SGH with 100% interest, contains the Echuca Shoals gas discovery plus additional prospects.

17 May 2019, KazMunayGaz (KMG) and BP signed a Memorandum of Understanding under which the companies agreed to review the available technical data and existing assets of KMG and third parties. The companies also intend to consider further co-operation. BP currently has no E&P assets in Kazakhstan.

BP and KazMunayGaz (KMG) signed a MOU under which the companies agreed to review the available technical data and existing assets of KMG and third parties. The companies also intend to consider further co-operation. BP currently has no E&P assets in Kazakhstan.

On 5 September 2018 Sapura Energy Bhd reported that it has signed a farm-in agreement with Finder Exploration Pty Ltd to enter four exploration permits. By farming in to the offshore permits, via its subsidiary company Sapura Upstream Sdn Bhd, Sapura will be entering Australian exploration for the first time. Sapura has agreed to acquire 70% interest and assume operatorship in Bonaparte Basin permit AC/P61 and three North Carnarvon Basin permits: EP 483, TP/25 and WA-412-P. Finder, which holds 100% interest, will retain 30% interest after the deal completes. The company had been looking for a farm-in partner for some time along with eight other Australian exploration licences. The deal remains subject to standard regulatory approvals. AC/P61 - Sapura reports that the newly formed joint venture will look to acquire seismic data within the permit area in 2019 to mature possible drilling targets. Both Upper Jurassic and Upper Cretaceous fan sandstones have been proven within the Vulcan Sub-basin and the permit is surrounded by the Oliver, Tenacious and Audacious oil discoveries. In May 2017 Finder outlined that the Gem Prospect had been identified for potential drilling, with a possible 130 MMb oil in place.  A development option for Gem, and possible discoveries from surrounding prospects, has been formulated for commercialisation. AC/P61, which covers an area of 335 sq km, was awarded on 22 June 2016. EP 483 & TP/25 - Finder has considered the permits as one with the split representing a transition from coastal, state waters of Western Australia (within 3 nm of land) to territorial waters (within 12 nm of land/islands - the Serrurier and Bessieres islands). Finder has delayed exploration to gain a financial partner and exploration wells are now due by 2019/2020. Finder has highlighted the Eagle Prospect for potential drilling, which lies in the centre of TP/25. The prospect is located in shallow water within the Mungaroo Formation at around 2,500 m below surface. Interpretation of the Numbat 3D seismic reveals a trap size of around 33 sq km within which, Finder reports the potential for mean gas-in-place of 2 Tcf. EP 483 and TP/25 cover a combined area of 1,076 sq km and were awarded in 2013. WA-412-P - The permit contains the Kanga prospect, which has highside potential of 220 MMb oil in place, within a structure at around 3,170 m depth.  Targeted reservoirs would be in the mid to late Jurassic, sealed by the Muderong Shale or Forestier Claystone.  Finder reports Kanga as a “drill ready prospect”.  Oil shows were encountered in the Lacerta 1 well, which is located to the south and was drilled in 1998. The Ironbark Prospect (high impact well) lies 20 km to the north of WA-412-P which is estimated to contain 15 Tcf (2C) in the Mungaroo Formation and is scheduled to be drilled by June 2020. WA-412-P, which covers an area of 387 sq km, was awarded on 13 June 2008.

Finder Exploration announces a farmout with Sapura Upstream of a portfolio of Australian offshore exploration permits comprising EP 483 & TP/25, WA-412-P and AC/P 61. Sapura Upstream will acquire a 70% interest in, and operatorship of, each of the permits. Finder will retain a 30% non-operating interest.

Kosmos Energy has announced today that it has completed drilling the Requin Tigre-1 exploration well located in Senegal’s Saint Louis Offshore Profond block. Location of Requin Tigre-1 (Source: Kosmos Energy)Requin Tigre-1 was drilled to a total depth of 5,200 meters and was designed to evaluate Cenomanian and Albian reservoirs in a structural-stratigraphic trap, charged from an underlying Neocomian-Valanginian source kitchen. The prospect was fully tested but did not encounter hydrocarbons. Post-well analysis is currently ongoing to determine the reasons it was unsuccessful. The exploration insights from the well, together with our existing knowledge will provide competitive advantage, and meaningfully advance our working understanding of the deepwater Cretaceous petroleum systems offshore Mauritania and Senegal where we believe there is substantial remaining prospectivity in the Company’s large acreage position. Andrew G. Inglis, chairman and chief executive officer, said: 'With each exploration well drilled, we deepen our understanding of this newly emerging basin, further refining our geologic model and geophysical tools. Requin Tigre was the last well in our second phase of exploration of the deepwater Cretaceous petroleum systems offshore Mauritania and Senegal targeting large basin floor fan structures. We have delivered one success (Yakaar) in four wells in this second phase program, following three successes in three wells (Tortue, Marsouin, Teranga) in the first phase program targeting inboard structures on the slope. Overall we have discovered gross resource of 40 trillion cubic feet, at a net cost of $0.20 per barrel of oil equivalent benefiting from the partner carry, and have created the potential for two world scale LNG hubs. We will rigorously evaluate our large inventory of prospects across Mauritania and Senegal ahead of the next phase of exploration offshore the two countries.' Kosmos was fully carried on the cost of the Requin Tigre well. The drillship will proceed as planned to test two oil prospects offshore Suriname commencing in early second quarter 2018. Kosmos holds an effective 30% participating interest in the Saint Louis Offshore Profond license. BP holds a 60% participating interest. The national oil company Société des Pétroles du Sénégal (Petrosen) holds 10%. Original article link Source: Kosmos Energy

Senegal, not found

On 24 February 2020, Canadian-junior Sunset Pacific Petroleum Ltd cancelled a previously announced letter of agreement with Bahraini-based investment firm Mazaya Energy Corporation. The agreement had only been signed on 19 February 2020. It would have seen a multi-phased investment in Sunset of up to US$ 10 million. The company has been seeking funding ever since 2016, when it announced that it had been awarded a PSC for the 3,772 sq km Ben Khedechef block, located in the Ghadames Basin. The award has remained under dispute ever since, with the Tunisian authorities denying any such agreement had been reached and Sunset subsequently stating that a contract is yet to be signed. Despite this, the company has continued to seek funds, with a US$ 5 million farm-out agreement for 16.7% equity (50% WI) reportedly agreed with an un-named party in April 2017. The deal has not closed. The under-explored block lies adjacent to the Algerian border. The acreage was formerly licensed to OMV as the El Hamra permit, with OMV relinquishing the block in April 2013. An application for the block was initially submitted by Sunset in July 2014, with the company reporting equity splits in the block as: Sunset (33.4% +Op), the CARTE Group (33.3%) and IMI-EAG Group (33.3%). The partners are two Tunisian-based investment firms. Sunset's only other assets are minor royalty interests in two oil & gas projects in NE British Columbia, with total proved plus probable reserves as of December 2015 standing at 0.743 MMcfg and 3.5 Mbbl of NGLs.

Canadian-junior Sunset Pacific Petroleum Ltd cancelled a previously announced letter of agreement with Bahraini-based investment firm Mazaya Energy Corporation. The agreement had only been signed on 19 February 2020.

G-1 field ML, Krishna-Godavari offshore, WD 188m, TD 3,780m, ops terminated (susp) late Dec ’18, Essar Wildcat SS.

G-1-NW AA appr (Ravva Sub-basin (Krishna-Godavari B.)) G-1, field ML, Krishna-Godavari offshore, WD 188m, TD 3,780m, ops terminated (susp) late Dec ’18

In November 2017, local reports indicated that the government of La Pampa Province has officially awarded two 25 year concessions for its producing blocks, namely the Jaguel de los Machos and 25 de Mayo-Medanito SE blocks, to Petroquimica Comodoro Rivadavia (PCR). The two adjacent blocks are situated in the Northeast Platform of Neuquen Basin, with the Jaguel de los Machos covering 319.92 sq km and the 25 de Mayo-Medanito SE covering 307.85 sq km of onshore lands. According to reports, PCR paid a total of USD 31 million bonus to the provincial government for both concessions, or specifically USD 11 million for Jaguel de los Machos and USD 20 million for 25 de Mayo-Medanito SE. The company holds 80% operatorship in both areas, while provincial company Pampetrol holds the remaining 20%. Planned long-term investment for the blocks was said to be approximately USD three billion during the 25 years of the concessions’ validity. PCR originally only applied for the Jaguel de los Machos block, which the company was already operating since late-2015 under a service contract for provincial company Pampetrol, and received a preliminary award for the concession in early-October 2017. Preliminary award for the 25 de Mayo-Medanito SE block was initially given to a consortium formed by Oilstone and energy infrastructure company Ribeiro SRL which reportedly submitted offers for both areas. However, it was said that the latter award was rescinded when the consortium failed to deposit the bonus that was previously agreed on during the bidding process.

Argentina (Neuquen B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: Jaguel de los Machos op. by PETROQUIM (100.0%) to be check.

Tullow has sold Cairn a 30% interest in its 7 recently-awarded coastal onshore blocks CI-518, 519, 301, 302, 520, 521 + 522 (from W to E), subject to govt approval. Tullow will retain 60% in all blocks and Petroci 10%.

Tullow farmed down 30% interest in all seven onshore permits (from west to east) CI-518, CI-519, CI-301, CI-302, CI-520, CI-521 and CI-522 to Cairn Energy.

Occidental Oil and Gas Corp (Oxy) is understood to have farmed in as operator with 48% in Ecopetrol's Llanos Basin Block LLA-52, industry sources said in November 2018. The farm in occurred in Q3. The block is adjacent to their Occidental de Colombia JV (OxyCol - Oxy 75%, Repsol 25%) northern Llanos basin portfolio, Rondon, Cosecha and Chipiron (Cravo Norte ADY). OxyCol is currently progressing with a five-well exploration programme across their northern Llanos acreage, which kicked off with the Pulpo-1 NFW in September 2018. The well was later P&A. The programme includes the (P&A) Chipiron Far North-1, the Cosecha-C-01 NFW, and the Finn-1. This latter well is expected to spud before the end of 2018. It is thought that Oxy can apply lessons learned from the nearby OxyCol blocks near the Venezuelan border. The LLA-52 Block includes the Rio Ele-1 NFW, which found oil shows in 1981, and the dry Chambery-1, which was drilled in 1995. The new block ownership is as thus: Oxy, 48% WI, with Ecopetrol holding the remaining 52%. Oxy also acquired the neighbouring LLA-39 during Q3 2018 (see related article).

Colombia (Llanos B.) Oxy is understood to have farmed in as operator with 48% in Ecopetrol's (->52%) Block LLA 52.

On 1 December 2017, Shell Offshore was formally awarded Mississippi Canyon Block MC 302 (lease G36129), situated in the Louisiana Coastal Basin. MC 302 was originally offered as part of Western Gulf of Mexico Lease Sale 249, which was held on 16 August 2017. The lease is expected to expire on 30 November 2024. Following formal award, Shell Offshore is now the operator and sole interest-holder (100% WI + Op) in MC 302.

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Ophir has agreed to farmout a 40% stake in EG-24 to Kosmos Energy in exchange for a carry on the cost of a block-wide 3D seismic survey. Kosmos will partially carry Ophir for the cost of a well if the partners subsequently elect to drill in phase 2, and Kosmos will also pay its pro-rata share of past costs. GEPetrol otherwise has a 20% carried interest in EG-24, which covers 3,543 sq km in deepwaters of the Rio Muni. Seismic is due to begin today using the Polar Marquis SV.

Equatorial Guinea, EG-24

Corallian Energy is looking for farm-in partners for three UK licences awarded in the 31st UK Licensing Round. In the Northern North Sea it is offering equity in licence P2464 (block 3/12b) which hosts the Unst gas prospect and in the Moray Firth it is offering interest in P2478 (blocks 17/5, 18/1 and 18/2) which houses the Dunrobin prospect and licence P2470 (blocks 11/23, 11/24c and 11/25b) which host a number of prospects including Dunbeath, Camster, Camster South and Whalingoe along with the Knockinnon discovery. Unst is an Eocene Frigg sandstone prospect which is seismically amplitude supported and is analogous to the Nuggets field. Unst is thought to hold 68 Bcf of gas. The Dunrobin prospect has a Beatrice Formation and Dunrobin Bay Group sandstone target. The prospect is estimated to hold 187 MMboe. Interest in P2478 is held by Corallian Energy Limited (45% + operator), Upland Resources (UK Onshore) Limited (40%) and Baron Oil Plc (15%). Interest in P2464 is held by solely by Corallian Energy Limited.

Corallian Energy is looking for farm-in partners for three UK licences awarded in the 31st UK Licensing Round. In the Northern North Sea it is offering equity in licence P2464 (block 3/12b) which hosts the Unst gas prospect and in the Moray

ENEVA SA suspended with gas shows the 1-ENV-BL69GA-MA (1-ENV-007A-MA) new-field wildcat (NFW) in the PN-T-069 block on 19 August 2019 at a reported final total depth (TD) of 727 m. The final TD was very shallow compared to its PTD. The ANP reported on 9 September 2019 that ENEVA filed a gas show report for the well. The NFW was spudded on 19 August 2019, assumed to be as a replacement wellbore for the junked and abandoned 1-ENV-BL69G-MA (1-ENV-007-MA) since both wells are reported to be at the same surface location. The NFW had a proposed total depth (PTD) of 2,442 m. The Devonian Cabecas Formation and the Mississippian Poti Formation were the primary targets. The NFW is located in the north-central area of the block approximately 9.8 km east south-east of the 1-ENV-BL69E-MA (1-ENV-004-MA) suspended with gas shows in June 2019. ENEVA SA has 100% working interest in the ANP Round 13, 3,066.97 sq km, PN-T-069 contract awarded on 23 December 2015.

ENEVA SA suspended with gas shows the 1-ENV-BL69GA-MA (1-ENV-007A-MA) new-field wildcat (NFW) in the PN-T-069 block on 19 August 2019 at a reported final total depth (TD) of 727 m.

In late August 2018, Apache was testing the Alam El Shawish South C1-3ST (SAES C1-3ST) (Hf032-7) exploration well in the South Alam El Shawish block, Western Desert. The original hole, SAES C1-3 was spudded on 10 July 2018 with “EDC- 47” land rig and drilled to a depth of 2,937 m before being sidetracked on 9 August 2018. SAES C1-3ST sidetrack was drilled to a TD of 3,962 m in the Paleozoic Shifah formation.    The well had a planned TD of 4,724 m and objectives in the Cenomanian Abu Roash G Member, the Aptian Alam El Bueib Member and the Jurassic Safa Member. Apache was awarded South Alam El Shawish block on 2 December 2016 as part of the EGPC 2016 bid round.

Apache was testing the Alam El Shawish South C1-3ST (SAES C1-3ST) (Hf032-7) exploration well in the South Alam El Shawish block, Western Desert. block

On 17 April 2018 it was announced that Eni and Sonatrach signed three agreements. The agreements were signed by Sonatrach CEO Abdelmoumen Ould Kaddour and Eni CEO Claudio Descalzi on the sidelines of an industry event in Oran. The first agreement is on the construction of a gas pipeline between the production facilities of Lajmat Bir Roud and Menzel Lejmat Est in the Berkine Basin. This should allow the local gas production to increase by 7 MM cm/d (247 MM cf/d). The second agreement is on synergy between the two companies. In the field of maintenance work and other activities, annual cost savings of USD 50 million are targeted. The third agreement is on the development of research and development notably in the field of renewable energies. Descalzi also mentioned that the Algerian offshore is very interesting. Eni does not have acreage there yet but the company is working towards it.

On 17 April 2018 it was announced that Eni and Sonatrach signed three agreements.

Dány block, Paleogene sub-basin ESE of Budapest, TD ca. 1,200m, tested in early 2020, w.o. results. Target Miocene.

Sülysáp Észak-Kelet (NE)-1 expl Dány block, Paleogene sub-basin ESE of Budapest, TD ca. 1,200m, tested in early 2020, w.o. results. Target Miocene.

Finder Exploration Pty Ltd is offering a farm-in opportunity in Exploration Permit AC/P61, located in the Vulcan Sub-basin, Bonaparte Basin. On 5 September 2018 Sapura Energy Bhd reported that it had signed a farm-in agreement with Finder to acquire 70% interest and operatorship in AC/P61, EP 483, TP/25 and WA-412-P. Finder will retain 30% working interest. Finder was awarded AC/P61 within the Territory of Ashmore and Cartier Islands in June 2016 after it was offered as AC15-1 in the 2015 Federal Offshore Acreage Release. Finder is also considering offering a potential farminee access to the remainder of its Australian portfolio. Finder first plans to undertake pre-stack depth migration seismic reprocessing, geological/geophysical studies and prospect de-risking studies during the first three-year term. The first exploration well is not scheduled until the sixth year term. The commitment to drill the well, which is forecasted to cost AUD 15 million, must be made before the start of the term on 23 June 2021. In May 2017 Finder outlined that the Gem Prospect had been identified for potential drilling, with a possible 130 MMb oil in place.  A development option for Gem, and possible discoveries from surrounding prospects, has been formulated for commercialisation. Both Upper Jurassic and Upper Cretaceous fan sandstones have been proven within the Vulcan Sub-basin and the permit is surrounded by the Oliver, Tenacious and Audacious oil discoveries. However, all five wells drilled within the permit boundary to date are dry (with the exception of minor oil/gas shows). The entire permit area is covered by the 1998 Onnia MC3D survey, acquired by PGS. At the time of acquisition the data was considered to be of excellent quality. Additional 3D seismic data covers the north-eastern area by the Schwarzer survey which was shot in 2007 over the Katandra and Audacious fields. AC/P61, which covers an area of 335 sq km, was awarded on 22 June 2016. Once the farm-down to Sapura is complete, Finder will hold 30% interest through its subsidiary company Finder No 1 Pty Ltd, and is actively seeking a farm-in partner. Companies interested in pursuing this opportunity should contact: Shane Westlake, CEO Finder Exploration Pty Ltd, 9 Richardson Street, West Perth, WA 6005. Tel: +61 8 9327 0128 Email: [email protected]

Finder Exploration Pty Ltd is offering a farm-in opportunity in Exploration Permit AC/P61, located in the Vulcan Sub-basin, Bonaparte Basin.

Al Wafa field area, Illizi Basin, drilled 25 Sep '19 – Jan '20, ops terminated at TD 2,664m. Mellitah = Eni – NOC JV

A-058-NC169A appr Al Wafa field area, Illizi Basin, drilled 25 Sep '19 – Jan '20, ops terminated at TD 2,664m. Mellitah = Eni – NOC JV

Subsequent to a portfolio review, Heritage Oil Ltd no longer sees Papua New Guinea as a core growth region. The company is looking to exit the country by divesting its entire PNG portfolio which includes exploration assets in the Western Forelands and the Southern Highlands (PPL 437 & PPL 486), and a gas field (Kuru, PRL 13). Heritage entered PNG in 2013 by acquiring operated interest in PPL 319 from Esrey Resources for around USD 4 million. The permit was later renewed in 2014 as PPL 486, which is still operated by Heritage. PPL 486 covers an area of 2,130 sq km in the Fly Platform, between the recently appraised, Oil Search operated, Barikewa gas field in the Papuan Fold Belt and the Total’s operated Elk-Antelope field in a carbonate platform, Fly Platform. The committed work programme was amended in October 2015 to move required 2D seismic acquisition from years 1&2, to years 3&4. However, after 11 lines were shot by Telemu (an Esrey subsidiary) in 2011, no known further ground works have taken place. The remaining programme includes three exploration wells by June 2020. Given the commitment from Heritage to exit the country, it is unlikely that the work programme will be altered again. Heritage reports two prospects and six leads within the permit area. The Tuyuwopi Prospect is considered ‘drill-ready’ by Heritage in a four-way dip closed drape structure which is thought to be on a direct migration pathway from a Jurassic source kitchen. Tuyowopi was the likely target for the first well to be funded by Heritage in the original farm-in agreement and site clearance work had commenced. It has the potential for gas within the Imburu, Iagifu and Koi Iange units, with Heritage reporting that it could contain 2P prospective recoverable resources of 600 Bcf in a gas case or 125 MMbo and 375 Bcfg in an oil and gas case. Both the Kutubu oil export pipeline and the PNG LNG natural gas pipeline run through the acreage which could aid in bringing resources to market in the case of a discovery with third-party pipeline access. Retention Lease PRL 13 is located directly east of PPL 486 and covers the Kuru gas discovery. Containing an estimated 30 – 50 Bcf gas, commercializing the field would benefit from aggregated resources of new finds. Discovered in 1956 after ground seepage was observed, Kuru 1 well blew out after penetrating around 12 m of the Puri Limestone. Kuru 2 was later drilled to test deeper targets including Miocene sandstones and the Darai Limestone. PRL 13 was set to expire on 15 June 2017. It is not thought that Esrey Resources applied for a licence renewal before exiting PNG. Pending confirmation, the licence could be inactive, meaning Kuru would no longer be under licence. Exploration licence PPL 437 is located immediately north of the Elevala and Ketu fields in Horizon’s operated PRL 21. It contains the drill ready Malisa Prospect, along with Ebony, Mango and Ketu North prospects. Partner and operator Kina Petroleum is also looking to farm-down interest in the licence which is currently under application for an extension. Malisa has the potential for gas within the Kimu and Elevala/Toro formations, with Heritage reporting that it could contain 2P prospective recoverable resources of 280 Bcf gas. The licence lies in close proximity to the Elevala, Ketu, Stanley, P’nyang and Juha discoveries, meaning opportunities for development could run through proposed Western LNG infrastructure or through third party access to the considered P’nyang to Kutubu pipeline. A total 170 km of 2D seismic was acquired over Malisa in 2014 during the Gosur Survey. Interpretation of this data was reported to be nearly complete in 2H 2017, along with integrated aerogravity data. Initial results showed significant prospectivity in the east of the permit. In addition, vintage seismic data was reprocessed within the licence and pending full interpretation. Under the work commitments, the option existed to either drill one well or complete an additional phase of seismic in place of the well, if the identification of a suitable drilling target had not been successful. Drilling targets could potentially be identified through interpretation of reprocessed vintage 2D seismic data. A seismic programme was expected in 2018 which did not materialize but could be included in the permit extension application programme. Heritage farmed into PPL 437 in 2013 with the condition that Kina would be free-carried through the first seismic programme. Additional interest could have been earned by Heritage (up to 50%) if the option to drill an exploration well was taken, in which Kina would also have been free carried. PPL 437, which covers an area of 1,537 sq km, was awarded on 19 February 2013. Heritage Oil is looking to divest its entire 42.5% interest. Operator Kina Petroleum is also looking to farm down its 57.5% interest. Companies interested in pursuing this opportunity should contact: Krey Stirland – Heritage Oil, Vice President Business Development Email: [email protected]

Heritage Oil Plc is looking to divest its entire PNG portfolio

Baojia sub-sag of the Dehui Sag, S. Songliao Basin, tight gas appraisal, fracked and tested 3.85 MMcf/d possibly from the L. Cretaceous.

Deshen-80 appr Baojia sub-sag of the Dehui Sag, S. Songliao Basin, tight gas appraisal, fracked and tested 3.85 MMcf/d possibly from the L. Cretaceous.

W&T Offshore has picked up ConocoPhillips' 75% + operatorship of the Magnolia field in Garden Banks blocks 783 + 784 for USD 20 MM plus assumption of abandonment costs. The deal is pending approvals and will be retro-effective 1 Oct '19.

W&T Offshore has picked up ConocoPhillips' 75% + op. of the Magnolia field in Garden Banks blocks 783 + 784 for USD 20 MM.

Premier Oil plans to acquire 25% in the Southern North Sea Tolmount Field and surrounding area from KNOC subsidiary Dana. Premier will pay US$ 191 million, plus up to US$ 55 million contingent consideration. This was announced on 7 January 2020 alongside another deal to acquire equity in Andrew Field area and Shearwater Field from BP. The two deals are to be funded via a US$ 500 million rights issue plus debt, however Premier's largest creditor, Analytical Research Capital Management (ARCM), has expressed opposition, citing a number of concerns including deal cost, decommissioning liabilities, and increased exposure to the UK gas market. Tolmount is estimated to contain 540 Bcfg P50 recoverable reserves in Permian Leman Formation sands. The development concept comprises four producing wells initially, and a standalone unmanned installation with a new gas export pipeline to shore, at a cost of US$ 550 million. Development drilling will commence in mid 2020, and first gas is expected by end 2020, with peak production anticipated to reach up to 300 MMcfg/d. A 500 sq km high resolution 3D seismic survey was acquired across the Greater Tolmount Area in March/April 2019 and the interpreted data will be used to optimise development drilling at Tolmount Main, refine the location of a potential Tolmount Far East exploration well (estimated 150 Bcfg unrisked resources), and identify further prospectivity in the area. The Greater Tolmount Area spans Southern North Sea licences P1330 - 42/28d and P2305 - 42/28c, and partners are Premier Oil E&P UK Ltd (50% + Op) and KNOC via Dana Petroleum E&P Ltd (50%).

Premier has agreed to acquire the Andrew Area and Shearwater assets from BP for US$625 MM as well as a 25% extra in the Tolmount Area from Dana for US$191 MM plus contingent payments of up to US$55 MM. Andrew involves 50%-100% interests in 5 fields + operatorship

Add. DEA 22 Sep ’17 (status) : AE-0019-Okom-02 block, offshore Sureste Basin, WD ~30m, P&A dry at TD 6,590m on 5 Nov ‘17, Fortius JU.

Mexico (Tampico-Misantla B.) ? op. by PEMEX (50.0%, RWE 50.0%) in 2 block

Schlumberger New Zealand Ltd as awarded petroleum prospecting permit PPP 60409, located in the Taranaki Basin, on 28 November 2017.  The permit has been awarded for a period of two years and will expire on 27 November 2019. Work commitments have been assigned to the permit’s validity and will see a minimum of 4,000 sq km of new 3D seismic acquired over the permit area. The permit is a prospecting licence and covers a number of existing exploration licences within the Taranaki Basin area, including several production licences over producing fields. PPP 60409, which covers an area of 18,722 sq km, was awarded on 28 November 2017.  Schlumberger New Zealand Ltd holds 100% interest and operatorship of the permit.

New Zealand, PPP 60409

Cairn (through its subsidiary Capricorn) announced on 6 August 2019 that it has sold 10% of its interest in the Nova field to ONE-Dyas for the sum of USD 59.5 million. The field, currently under development with first oil due in September 2021, is covered by PL 378, PL 418 and PL 418 B. The deal will see ONE-Dyas take a 12% interest in PL 378 and 10% in both PL 418 and PL 418 B. Cairn states that it will use the proceeds of the sale to fund exploration and development activities across its group portfolio (Northwest Europe, West Africa and Latin America). The deal is subject to government approval and will be financially effective from 1 January 2019. Nova was previously called Skarfjell and was discovered in 2012 by 35/9-7. Its reservoir is the Upper Jurassic Heather Formation. The discovery was appraised over the following year and the PDO was submitted in May 2018 (and received approval four months later). Operator Wintershall intends to recover 77 MMboe from the field over an eight-year period using two 4-slot subsea templates (installed in May 2019) sited one kilometre apart (the northerly template will host three water injectors and the southerly one will have three producers). The templates will be tied back to Gjoa which lies approximately 16 km to the northeast. There is also provision for a third template with four more wells if needed. Gjoa will supply Nova with power (from shore), gas lift and water injection. Drilling of six wells will commence in H1 2020 and the installation of the other facilities will take place in 2019 / 2020. A new topsides module will be installed at Gjoa in May 2020 where processing will take place prior to export via the Troll oil pipeline to Mongstad. Maximum production is expected to be 50,000 boe/d and investment is estimated at NOK 9.9 billion (USD 1.23 billion). The field consists of three segments and the initial development relates solely to Nova Main, with the Southeast and East segments representing future upside potential. Upon completion of the deal, interest in PL 378 will be divided between Wintershall Dea through Wintershall Norge AS (75.76% + operator), Cairn through Capricorn Norge AS (12.12%) and ONE-Dyas Norge AS (12.12%) and interest in PL 418 and PL 418 B will be held by Wintershall Dea through Wintershall Norge AS (35% + operator) and DEA Norge AS (10%), Spirit Energy Norway AS (20%), Edison Norge AS (15%), Cairn through Capricorn Norge AS (10%) and ONE-Dyas Norge AS (10%)

Cairn announces the sale of a 10% interest in the Nova devt project to ONE-Dyas for US$ 59,5 MM. Cairn will retain a 10% stake in the project, Nova spans PL 4128 / 418B (Wintershall DEA (op), Spirit, Edison, Cairn, now ONE-Dyas) and PL 378 (Wintershall DEA (op), Cairn, now ONE-Dyas).

Rawson Oil & Gas Ltd announced on 16 November 2017 that it had executed its farm-in agreement for PEL 155 with Vintage Oil & Gas Ltd.  The agreement is seeing Vintage Oil and Gas earning a 25% interest in the licence, which is located in the onshore Otway Basin, for a payment of AUD 100,000. The execution of the agreement on 16 November has formalised the joint venture and has also initiated the ability of Vintage Oil and Gas to acquire an additional 25%.  The additional interest can be earned by assisting in funding an exploration well on a 50:50 basis with Rawson.  The joint venture has also applied for one of the new PACE grants from the South Australian government, which would see 50% of the wells cost covered under the PACE programme.  Successful applicants of PACE should be announced by end 2017. The companies aim to work towards drilling an exploration well in PEL 155, which would be planned to target a prospect in the northwest of the licence area.  The prospect is outlined by Rawson as a three-way dip closed, fault trapped reservoir within the Pretty Hills Formation.  The prospect has been defined by 3D seismic over the area and is thought to be analogous to the Katnook, Haselgrove and Ladbroke Grove gas/condensate fields, which are in close proximity and have all produced from Pretty Hill reservoirs. There are also additional leads within PEL 155 that could be targeted in future. PEL 155, which covers an area of 226 sq km, has been subject of a farm-in agreement between operator Rawson Oil & Gas and Vintage Oil & Gas. Vintage Oil & Gas has earned an initial 25%, with Rawson now holding 75%.  If Vintage proceeds with the full farm-in, participants in the licence will become Otway Energy Pty Ltd (50% + Operator) and Vintage Oil & Gas (50%).

Australia (Otway B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: PEL 155 op. by RAWSON O&G (100.0%) to be check.

It was reported in mid-October 2018 that Asset Energy Ltd, a wholly owned subsidiary of Advent Energy Ltd, had issued a notice to joint venture partner Bounty Oil and Gas it was exercising an option to acquire 100% interest in exploration permit PEP 11, located in the offshore Sydney Basin. Under the terms of the notice, Bounty is required to withdraw from the permit after Advent reported it is in default of payments for a number of outstanding costs.  Bounty holds a 15% interest in the permit, which will be assigned to Advent upon completion of the withdrawal of Bounty. The permit has been valid for a period of around 19 years, after being awarded in June 1999 to Flare Petroleum.  Bounty first acquired 50% interest in July 2001, before taking full interest and operatorship in December 2002.  Asset Energy farmed in in November 2006, before the current shareholding was entered, in January 2011. The permit is under a separate farm-out agreement, in which RL Energy has agreed to acquire up to 60% interest.  Under the terms of the farm-in agreement, RL Energy can earn an initial 5% interest by arranging environmental proposals for a new 3D seismic survey over the permit area.  RL Energy can then earn up to a further 55% by funding Advent Energy’s share of a 500 sq km 3D seismic survey, up to a capped amount of AUD 4 million.  The seismic acquisition is under the work programme for the permit and is scheduled between February 2020 and February 2021.  It was reported at the time that Bounty was requested to withdraw, that the farm-out to RL Energy was not affected. PEP 11 covers an area of 4,574 sq km.  Advent Energy Ltd is expected to hold 100% interest after it notified Bounty that default of payments would result in it exercising an option to take full interest.

Asset Energy has exercised its right to acquire full ownership of PEP 11 (4574km²). The company has therefore notified 15% partner Bounty O&G to completely withdraw from the JOA and the permit in lieu of default in payment of outstanding expenses.

Mubadala Petroleum has plugged and abandoned a newfield wildcat, Malika 1 in the B05/27 concession, located at Kra Sub-basin (Gulf of Thailand Basin), as a dry well on 21 December 2019. Spudded on 16 December 2019 at a water depth of approximately 45 m, the well was drilled to a total depth (TD) of 1,241 m using the “Valaris J/U-115". Malika 1 has likely targeted the Middle Miocene fluvial sandstones, analogue with Manora. Malika 1 is located approximately 8 km southwest of the producing Manora field in the G01/48 concession. The reason of well failure to find hydrocarbon is probably due to lack of charge and distribution of reservoirs. The previous exploratory well drilled within the concession was Ban Yen SW-1. No hydrocarbon encountered and the well was abandoned on 6 December 2015 at a TD of 2,834 m. Mubadala is the operator and sole interest holder in the B05/27 concession. The concession holds two oil producing fields, Jasmine and Ban Yen. These two fields produced at an average of 10,720 bo/d in 2019. More than 90% of the proved reserves for the concession have been produced since 2005, with estimated remaining reserves of around 5.7 MMbo. Background Information Pearl Oil (Thailand) Ltd (later acquired by Mubadala Petroleum) acquired 100% rights and operatorship over the B05/27 concession on 29 January 2004 from Harrods Energy Ltd. A total of eleven new-field wildcats were drilled since 1992, resulting in two discoveries. The Jasmine field was discovered by wildcat B05/27 3 (TD 1,762 m) in July 1999. The well was drilled on the shallow water "L" structure. The reservoir target was a Miocene deltaic sandstone unit. Sixteen appraisal wells have been drilled on the structure. The field was brought onstream in 2005 at an initial rate of 2,000 bo/d. The Ban Yen field was discovered in May 2006 by the Ban Yen 2A well which was drilled down to 2,292 m. The field was brought onstream in 2008 at an initial rate of 1,050 bo/d via a single well. A second well was subsequently brought onstream at an initial rate of 2,000 bo/d. Production from Jasmine and Ban Yen is via a subsea pipeline connected to the MV Jasmine Venture FPSO.

Malika 1 (Mubadala Petroleum) in the B05/27 concession located at Kra Sub-basin, P&A, dry.

PetroChina – Sichuan achieved an important exploration progress in the Sichuan Basin. Shuangtan 8, an exploration well, located in Shuangyushi prospect in Jiange area, tested gas in the Permian, the successful result further indicated gas exploration prospective potential in the northwest of the basin. The well was spudded in the second half of 2016. In 2014 PetroChina made Shuangtan 1 discovery in this area, the well tested 30 MMscfg/d from the Permian Qixia Formation and 44.7 MMcf/d of gas from Maokou formations. The well has a TD of 7,308 m. In 2016 PetroChina made a breakthrough in in Shuangtan 3 in this area, the well not only tested gas form the Permian Qixia Formation, but first time achieved  commercial gas flow from the Devonian Guanwushan Formation, from which tested 4 MMcf/d of gas. In September 2016, PetrroChina successfully completed an ultra-deep and ultra-pressure Shuangyu 001-1, to assess Shuangtan 1 discovery. The well reached a TD of 7,510 m. In October 2016 PetroChina spudded a record deep well around Shuangtan discovery area.  Shuangtan 7, an exploration well, has a PTD of 7,775 m. The well has objective in the Permian and Devonian formations. The well is still under drilling by end 2017.  

China (Sichuan B.) Shuangtan (Si) 3 op. by PETCHIN SC (100.0%) in Beichuan-Jiange block

Partner RCMA Australia had taken over operatorship of L14 (Jingemia field), 45 sq km in the Perth Basin, from Cyclone Energy. Partnership now RCMA (op, 60%, Cyclone (33.72%), Norwest Energy NL (6.28%).

Partner RCMA Australia had taken over operatorship of L14 (Jingemia field), 45 sq km in the Perth Basin, from Cyclone Energy. Partnership now RCMA (op, 60%, Cyclone (33.72%), Norwest Energy NL (6.28%).

ADL 392301, Alaska North Slope, susp 30 Jun ‘18, possible plans for horiz sidetrack with multi-stage frac. Results from the well to date ‘support the potential economic viability of the HRZ shale play’ despite a prod test which was not representative of the capability of the reservoir, hence a frac job.

Icewine-2 expl ADL 392301, Alaska North Slope, susp 30 Jun ‘18, possible plans for horiz sidetrack with multi-stage frac. Results from the well to date ‘support the potential economic viability of the HRZ shale play’ despite a prod test which was not representative of the capability of the reservoir, hence a frac job.

Effective 1 October 2017 Hilcorp Alaska LLC was officially awarded 14 tracts covering about 76,682 acres (310 sq km) off Alaska’s south-central coast from the Cook Inlet Lease Sale 244 held by the Bureau of Ocean Energy Management (BOEM) on 21 June 2017. The company placed high bids in the amount of USD 3,034,815 and was the sale’s lone bidder. Sale 244 was the thirteenth and final OCS lease sale held under the 2012-2017 Five-Year Program. It offered some 1.09 million acres (4,410 sq km) for leasing and consisted of 224 blocks that stretched roughly from Kalgin Island in the north to Augustine Island in the south. Each bid went through a 90-day evaluation process to ensure the public received fair market value before a lease was awarded. All materials and statistics for Lease Sale 244 are available at: http://www.boem.gov/ak244. Hilcorp Official Awards               Contract Company Name WI Bonus USD Acre Sqkm Lease Sale Award Date Basin   Y02434 Hilcorp Alaska 100 $62,208.00 5,184.26 20.98 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02435 Hilcorp Alaska 100 $37,416.00 3,118.47 12.62 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02436 Hilcorp Alaska 100 $68,376.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02437 Hilcorp Alaska 100 $142,500.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02438 Hilcorp Alaska 100 $111,606.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02439 Hilcorp Alaska 100 $313,500.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02440 Hilcorp Alaska 100 $474,582.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02441 Hilcorp Alaska 100 $203,319.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02442 Hilcorp Alaska 100 $111,606.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02443 Hilcorp Alaska 100 $256,500.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02444 Hilcorp Alaska 100 $474,582.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02445 Hilcorp Alaska 100 $474,582.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02446 Hilcorp Alaska 100 $152,019.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02447 Hilcorp Alaska 100 $152,019.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet    Totals     $3,034,815.00 76,681.62 310.32         Source: IHS Markit               © 2017 IHS  

United States, Y02440

During the first half of 2018, Salym Petroleum Development (SPD), a 50-50 joint venture of Shell and Gazprom Neft, completed testing of two new pool wildcats in the Verkhne-Salymskoye license in Khanty-Mansiysk (Yugra) Autonomous Okrug (Western Siberia). Verkhne-Salymskaya 65, spudded in early December 2017, reached its final TD of 3,300 m in early January 2018. Verkhne-Salymskaya 58, spudded in mid-February 2018, reached its final TD of 2,600 m in early March. In March, the company reported a new pool in the Cherkashinskaya Formation (Neocomian) after testing oil and water at rates of 598 b/d and 31 b/d, accordingly, from the interval 2,580-2,593 m (AS6) in Verkhne-Salymskaya 65. The same reservoir was perforated in Verkhne-Salymskaya 58. Oil at a rate of 1,151 b/d was obtained from the interval 2,267-2,278 m. Background Information SPD was created in 1996 to develop the Salym Group of fields in the southwestern part of the Middle Ob Province. The Salym Group comprises three fields: Salymskoye Zapadnoye, Verkhnesalymskoye and Vadelypskoye with 2P oil reserves of some 1.3 Bbbl.

Russia (West Siberian B.) ? op. by SALYM (100.0%) in Salymskoye Zap. block

Maybulak North discovery area in Zhilanshik Trough, N. South Turgay Basin, oil in fractured Triassic to possibly Lower Jurassic brecciated carbonate and siliceous rocks between 2,252-2,545m, tested 1,006 b/d unassisted on 9mm choke. So far Triassic reservoirs were unknown in the Turgay Basin. More details from GEPS.

Maybulak North (Crystal Management LLP 100%) in 3996R Crystal block, oil disc. in fractured Triassic to possibly Lower Jurassic brecciated carbonate and siliceous rocks between 2252-2545m, tested 1006 b/d unassisted [9mm choke]. So far Triassic reservoirs were unknown in this basin.

Merlon International has been pre-awarded the North Beni Suef block, following the announcement of the winners of the EGPC 2018 International Bid Round on 12 February 2019. The 5,060 sq km block is located in the Beni Suef Basin and lies immediately south of the company's El Fayoum concession. Work commitments in the initial exploration period include expenditure of US$ 36 million and 8 wells. A US$ 3.2 million signature bonus will be paid. Merlon is currently in the process of being acquired by SOCO International, in a US$ 136 million deal first announced on 20 September 2018. Upon PSC signature, the company will operate the concession with 100% equity.

Merlon International has been pre-awarded the North Beni Suef block, following the announcement of the winners of the EGPC 2018 International Bid Round on 12 February 2019. The 5,060 sq km block is located in the Beni Suef Basin and lies immediately south of the company's El Fayoum concession. Work commitments in the initial exploration period include expenditure of US$ 36 million and 8 wells. A US$ 3.2 million signature bonus will be paid. Merlon is currently in the process of being acquired by SOCO International, in a US$ 136 million deal first announced on 20 September 2018. Upon PSC signature, the company will operate the concession with 100% equity.

NE of Beshkent o/g/c field in block XX Kultak-Kamashi, Amu-Darya Basin, tested 6.85 MMcfg/d + ab. 150 bo/d presumably from Callovian-Oxfordian carbs, reserves estimated 137 Bcfg + 2.3 MMbo.

Beshkent Shimoliy 1 nfw. (Epsilon Development Company 100%) E of Beshkent o/g/c field in XX Kultak-Kamashi block, tested 6.85 MMcfg/d + ab. 150 bo/d presumably from Callovian-Oxfordian carbs, reserves estimated 137 Bcfg + 2.3 MMbo.Uzbekistan (Amu-Darya B.) ? op. by EPSILON D (100.0%) in XX Kultak-Kamashi block

Trident is reportedly looking to buy ExxonMobil’s 71% stake in the producing Zafiro field/complex off Bioko Island, a deal could fetch up to USD 1 bn. Word on the street is that Kosmos is also interested, or may share in the above deal if concluded.  Exxon retains rights to block EG-06 and EG-11 (80% ea.), and it is at present unclear if these will later also be offloaded.

Equatorial Guinea, Block EG-06

On late June 2020, is assumed PEMEX reached the sidetrack proposed total depth (PTD) of 2,830 in the Chi 1EXPST New Pool Wildcat (NPW) located in the AE-0153-Uchukil entitlement, offshore Sureste Basin. As of 8 July 2020, no further information was released about this well. PEMEX holds 100% interest in this block. The sidetracked well had a proposed total depth (PTD) of 2,830 m measured depth (MD) and 2,000 m true vertical depth (TVD). The target was the Middle Pliocene at 2,058 m measured depth to evaluate prospective resources of 9 MMboe with 58% of Geological Chance of Success. The hydrocarbon expected was oil around 17° API. The "CME-1" jackup, which drilled the original vertical well, also drilled the sidetracked well section on water depth of 27 m. The estimated sidetrack section total cost was USD 5.4 million, which includes USD 4.5 million (13 days) for drilling and USD 0.9 million (6 days) for completion or abandon. On 28 August 2019, SENER officially granted the entitlement for this block AE-0150-Uchukil. On 02 October 2019 CNH approved its first exploration plan. On 20 February 2020, PEMEX was granted approval by the CNH to drill the Chi 1EXP new-field wildcat (NFW).  On 14 May 2020, PEMEX was granted approval by the CNH to sidetrack the Chi 1EXP new-field wildcat (NFW) at 750 m to complete the Middle Pliocene section evaluation because one of the most important Middle Pliocene interval is absent due to a normal fault.

Mexico (Sureste B.) Chi 1EXPST op. by PEMEX (100%) in AE-0153 block, WD = 27 m, is assumed PEMEX reached the sidetrack proposed total depth (PTD) of 2,830 m measured depth (MD).

Shatan 2 was drilled to a TD of 5,838m MD on 31 October 2019 and was suspended for further evaluation in mid-November 2019. The oil and gas exploration well was spudded in June 2019 to drill to an initial PTD of 5,500m but deepened to 5,900m and was targeting the Permian Upper Uhro Formation and Triassic Baikouquan Formation with the objective of further appraising and exploring the oil and gas discovery made by Shatan 1 by PetroChina in December 2018 in the Shamenzi Sag, Junggar Basin. Shatan 2 is in the PetroChina operated Shamenzi Block in the Junggar Basin.

Shatan (Ju) 1 nfw. (PetroChina – Xinjiang 100%) in Shamenzi Block, an important breakthrough, tested 119 bo/d and 0,22 MMcfg/d through a 6mm choke commercial oil flow from the Carboniferous Tailegula Fm. There are several oil fields found in this area, which has main reservoir in the Tertiary, Jurassic and Permian. A few wells penetrated Carboniferous reservoir, but no commercial oil has been achieved.

Wellesley has acquired a 30% interest in PL 829 and a 20% interest in PL 878 from Equinor. The deal was confirmed by the NPD on 5 December 2019 and is effective from 29 November 2019. PL 829 covers parts of blocks 6204/7, 6204/8, 6204/10 and 6204/11 and the decision to proceed with drilling a well was made in November 2019. PL 878 covers parts of blocks 30/2 and 30/3 and a well (30/2-5) will be drilled on the Atlantis prospect to the north of Huldra (the shallow gas pilot hole is expected in Q1 2020). Wellesley obtained its first 30% interest in PL 829 in 2016 by way of a deal with Point Resources. The licence contains two small gas discoveries made by 6204/11-1 (Statoil 1994) and 6204/10-2 R (Statoil 1997). Shell was a former partner in PL 878 and exited the licence in February 2019, leaving Equinor with 100% interest. The abandoned Huldra field lies in what is now PL 878. Huldra was discovered in 1982 by well 30/2-1 and it came onstream in November 2001. It is a rotated fault block structure with a Middle Jurassic Brent Group reservoir lying between 3,500-3,900 m. The reservoir was initially HPHT but compression was required to aid production from 2007. From the Huldra platform wet gas was transported to Heimdal for further processing and export and condensate was exported through Veslefrikk. Production ceased in 2014. Interest in PL 829 is now held by Equinor Energy AS (20% + operator), Wellesley Petroleum AS (60%) and Petoro AS (20%) and interest in PL 878 is divided between Equinor Energy AS (80% + operator) and Wellesley Petroleum AS (20%).

Wellesley has picked up 30% in PL 829 (part-blocks 6204/7, 8, 10 + 11) + 20% in PL 878 (part-blocks 30/2 + 3, Atlantis prospect) from Equinor. PL 829 now Equinor (op), Wellesley + Petoro

Further to DEA 20 Aug ’18 (discovery): Pangkah block off E. Java, TD 2,896m, mid-August oil find in the Tuban, Kujung + Ngimbang fm’s, DSTs proved find commercial (rates n/a), HYSY 937 JU.

Tambakboyo-2 (TKBY) Pangkah block off E. Java, TD 2,896m, mid-August oil find in the Tuban, Kujung + Ngimbang fm’s, DSTs proved find commercial (rates n/a),

On 22 March 2020, Egyptian government sources disclosed that Edison International SpA (Edison) abandoned its first deep-water exploration wildcat Ameeq 1 in the North Thekah offshore block (block 7), Levantine Basin. This failure comes a few weeks after Eni abandoned the Nigma 1 exploration well in the Northeast Hapy Offshore Block in the same basin. For the Egyptian state, these two successive setbacks represent a disappointment for the country in its efforts to convince the IOCs to start a new phase of exploration in its deep Mediterranean waters. Edison holds a 100% working interest in the North Thekah offshore block, which had been initially granted to Edison and Petroceltics in April 2013. Edison is a fully owned subsidiary of Edison SpA, a JV between Transalpina di Energia Srl (80.12%), EDF (19.35) and other partners (0.53%). Background information Edison started drilling operations of its first deep-water exploration Ameeq 1 in the North Thekah offshore block (block 7) on 18 January 2020. The company declared that the operation for which the semi-submersible rig Maersk Discoverer had been contracted, was estimated to take two months to reach the Ameeq prospect situated at a total depth of 5,200 m with 982 m of water depth. On 3 March 2020, Maersk Drilling announced a one-well contract for its rig in direct continuation of the current contract. This new contract, which was expected to commence in March 2020 had an estimated duration of 21 days for an approximate value of USD 3.8 million.

Ameeq 1 nfw. (Edison 100%) 1st of 3 commitment wells normally planned in DW North Thekah block, WD=982m in E. Mediterranean, reportedly dry, PTD was ca. 5,200m. This will no doubt be a major disappointment to Energean, in the process of taking over Edison, and to the govt who has been actively promoting DW acreage.

New W. extn of block 15/06, WNW of recent Afoxé discovery in WD 1,692m, drilled mid-Dec ’18 – Jan ’19, results yet n/a, Ocean Rig Poseidon DS. PTD was 3,540m. Eni (op), partners Sonangol P&P + Sonangol Sinopec Intl.

Angola (Congo Fan) ? op. by ENI SPA (36.84%, SONANGOL 36.84%, SSI15 26.32%) in Block 15/06

The Niger Republic Ministry of Oil is offering 36 open blocks on an open-door policy. The open blocks were: Niger Open Blocks Main Basin Name Block Name Block Sqkm Tahoua Depression Tarka 43,313 Iullemmeden Basin Dallol 41,579 Iullemmeden Basin Tadarast 39,972 Iullemmeden Basin Tounfalis 37,846 Chad Basin Homodji 33,123 Iullemmeden Basin Tegama 32,193 Iullemmeden Basin Ader 31,174 Iullemmeden Basin Yaris 30,696 Djado Basin Karama 30,357 Iullemmeden Basin Talak 30,120 Chad Basin Damagaram 29,680 Chad Basin) Dibella 2 29,634 Chad Basin Araga 28,196 Iullemmeden Basin Azawak 27,860 Iullemmeden Basin Irhazer 25,758 Iullemmeden Basin Tamesna 25,435 Chad Basin Aborak 24,760 Chad Basin Seguedine 22,570 Chad Basin Tenere Ouest 22,367 Chad Basin Tafassasset 21,815 Djado Basin Tchigai 21,166 Chad Basin Mandaram 21,005 Chad Basin Dibella 1 20,418 Djado Basin Dissilak 19,924 Chad Basin Achegour 17,012 Tenere Rift - Chad Basin Tenere Ouest 16,975 Chad Basin Grein 16,010 Chad Basin Bilma Est 14,276 Djado Basin Djado 1 13,974 Djado Basin Djado 2 12,520 Chad Basin Manga 1 12,274 Djado Basin Djado 4 11,982 Chad Basin Manga 2 11,712 Djado Basin Djado 3 11,240 Termit Trough - Chad Basin R5 2,710 Termit Trough - Chad Basin R6 2,375 Source: IHS Markit © 2019 IHS Markit   The Ministry of Energy and Petroleum updated its Petroleum Code in 2017 and offers a contractual relationship under PSCs. Exploration permits are granted for up to four years with the option to renovate twice up to a total of eight years. In the event of a discovery, two more years can be granted for further exploration. Following each renewal, half of the area must be relinquished. Production contracts are issued for an initial period of 25 years for oil and 30 years for gas development with a renewal period of 10 years. According to the Ministry in March 2019, the cost of exploration, development and productions is estimated at USD 18/bbl.

The Niger Republic Ministry of Oil is offering 36 open blocks on an open-door policy. The open blocks were: Niger Open Blocks Main Basin Name Block Name Block Sqkm Tahoua Depression Tarka 43,313 Iullemmeden Basin Dallol 41,579 Iullemmeden Basin Tadarast 39,972 Iullemmeden Basin Tounfalis 37,846 Chad Basin Homodji 33,123 Iullemmeden Basin Tegama 32,193 Iullemmeden Basin Ader 31,174 Iullemmeden Basin Yaris 30,696 Djado Basin Karama 30,357 Iullemmeden Basin Talak 30,120 Chad Basin Damagaram 29,680 Chad Basin) Dibella 2 29,634 Chad Basin Araga 28,196 Iullemmeden Basin Azawak 27,860 Iullemmeden Basin Irhazer 25,758 Iullemmeden Basin Tamesna 25,435 Chad Basin Aborak 24,760 Chad Basin Seguedine 22,570 Chad Basin Tenere Ouest 22,367 Chad Basin Tafassasset 21,815 Djado Basin Tchigai 21,166 Chad Basin Mandaram 21,005 Chad Basin Dibella 1 20,418 Djado Basin Dissilak 19,924 Chad Basin Achegour 17,012 Tenere Rift - Chad Basin Tenere Ouest 16,975 Chad Basin Grein 16,010 Chad Basin Bilma Est 14,276 Djado Basin Djado 1 13,974 Djado Basin Djado 2 12,520 Chad Basin Manga 1 12,274 Djado Basin Djado 4 11,982 Chad Basin Manga 2 11,712 Djado Basin Djado 3 11,240 Termit Trough - Chad Basin R5 2,710 Termit Trough - Chad Basin R6 2,375

In its Q2 2019 results announcement, operator VAALCO Energy Inc (Vaalco) reported that it was looking for a partner “on a promoted basis that will cover all or substantially all the costs to drill an exploratory well” in its Block P Development Area (PDA), shallow to deep waters of the Rio Muni Basin. Since November 2018, Vaalco expects to obtain the official approval from the Equatorial Guinea Ministry of Mines and Hydrocarbons (EG MMH) for acting as administrative operator of PDA. Prior to that, the company was only technical operator with 31% WI. It is understood that the new farminee will acquire the current GEPetrol’s 58.4% participating interest. The remaining partners are unchanged: Atlas Petroleum International Ltd with 5.6% and Crown Energy Ventures Corp with 5%. Upon EG MMH approving the new joint venture owner, Vaalco and its partners will have one year to drill an exploration well. In November 2018, the EG MMH also lifted the permit’s suspension, presumably in force since 2015, and extended the permit’s validity for two years until November 2020. Vaalco and its partners will now evaluate the timing and budgeting for development and exploration activities under a development and production area in the block, including the approval of a development and production plan. Background Information In early January 2015, Vaalco Energy’s partner Crown Energy informed that the authorities had given the approval to commence pre-front end engineering design (pre-FEED) studies for the development of the Venus field. Vaalco also informed that it was working together with GEPetrol in order to prepare a revised capital budget and work program for submittal to the Ministry of Mines Industry and Energy. Vaalco informed in September 2014 that it was aiming to drill two production wells and one water-injection well in the Venus field. Vaalco also plans to lease a FPSO. First oil extracted from the Upper Cretaceous sands was expected in 2017. Gross unrisked recoverable oil resources in the Venus field were estimated between 17 and 21 MMbo according to Vaalco Energy. Vaalco informed that there are a number of other potential prospects and leads within the acreage. The prospects include the Marte field and the SW Grande field with gross unrisked recoverable oil resources of 16-70 MMbbl and 10-180 MMbbl, respectively. Vaalco informed that two exploration wells are planned in the new prospects, but they will be only drilled after the development of the Venus field (2017). The Marte well will likely target Upper Cretaceous turbidites, whereas the SW Grande well will have Tertiary channels and Upper Cretaceous sands as targets.

Operator VAALCO Energy Inc (Vaalco) reported that it was looking for a partner “on a promoted basis that will cover all or substantially all the costs to drill an exploratory well” in its Block P Development Area (PDA), shallow to deep waters of the Rio Muni Basin

At crossroads of ADLs 391718, 391719, 319720 + 391721, E. of the Horseshoe 1/1A discovery in North Slope Basin, TD 2,073m reached 3 Mar ’19, pre-drill targets intersected, multiple potential pay zones identified, including in primary target zone (Nanushuk topsets), wireline logging to begin to confirm prospectivity ahead of possible testing. It is recalled weak to moderate oil shows within the Nanushuk and no oil shows from secondary Seabee target. Nordic-Calista Services rig 3. Accumulate (88 Energy) (op), partners Otto, Pantheon Res., Red Emperor.

Winx 1 (Pantheon Alaska Petroleum 89,2%, Borealis Alaska 10,8%), at crossroads of ADLs 391718, 391719, 319720 + 391721, 6,4 km E. of the Horseshoe 1/1A discovery, North Slope Basin, weak to moderate oil shows within the Nanushuk fm. and no oil shows from secondary Seabee target, testing of deeper objectives to follow.

In December 2019, Ecopetrol SA announced that Hocol Petroleum Ltd, their 100% owned subsidiary, and Lewis Energy Colombia are evaluating the Lewis Energy-operated Bullerengue SW-1 outpost well on contract block SSJN 1 in the Lower Magdalena Basin. The Bullerengue SW-1 outpost spudded in July 2019 and is located about 3 km southwest of the Bullerengue 1 gas/condensate discovery well. The well will likely have a proposed total depth of approximately 2,200 m (7,217 ft) and it is assumed to be targeting Miocene-Oligocene sandstones of the Cienaga de Oro Formation, the primary pay for the Bullerengue Field. The SSJN 1 contract covers 1,672.7 sq km and was awarded to Lewis Energy Colombia (100%) on 18 December 2008. Hocol Petroleum Ltd farmed in a 50% interest in the block from Lewis Energy on 24 December 2009, and Lewis Energy controls the remaining 50% interest. Background Information The Bullerengue gas/condensate field was discovered in October 2015 by Bullerengue 1 new-field wildcat (NFW). The NFW was drilled to a TD of 2,286 m (7,500 ft) where it tested 2.5 MMcfg/d and 50 barrels of condensate in an unreported reservoir - possibly within the Oligocene to Miocene Age Cienaga de Oro Formation or the Eocene Age La Risa Formation. Five other wells have been drilled in the structure: Bullerengue Sur 1 to 4 and Bullerengue SW 1. The Bullerengue Sur 1 exploratory well found 25 m (80 ft) of Eocene Age gas pay over several horizons, Ecopetrol SA announced on 27 December 2019. The field started production in October 2015.

ewis Energy Colombia evaluating the Bullerengue SW-1 outpost located in contract block SSJN 1

Shell spudded exploration well 6304/3-1 on the Coeus prospect in PL 832 on 7 July 2018. The well has an Upper Cretaceous Egga / Springar Formation target and the “Scarabeo 8” S/S was used for the work. By 6 August 2018 Shell was operating at TD – 3,642 m. Results are expected to be announced later this week. The Coeus prospect lies to the northwest of Shell’s Ormen Lange field where the company is studying different concepts for the utilisation of offshore compression at the field in the mid-2020's in order to increase gas production. In 2014 Shell reported that work on the project had been postponed as the potential concepts did not provide an economic return based on CAPEX and expected production volumes. Reservoir analysis at the time indicated that the timing for compression was not critical to ultimate recovery and therefore it was decided to re-evaluate at a later date. In 2018 gas production from Ormen Lange is due to increase as a result of land-based compression at the Nyhamna processing plant. The NPD granted approval in February 2017 for the installation of two new compressors at the plant as a first phase of production increases before any decision on the offshore compression is taken. PL 832 is operated by A/S Norske Shell holding a 45% interest. Shell is partnered by Petoro AS (20%), Spirit Energy Norge AS (20%) and DEA Norge AS (15%).

6304/03-01 (Coeus) (Shell (op), partners Petoro, Spirit Energy + DEA) in PL 832, NW of Ormen Lange field in Norwegian Sea, WD=1,235m, TD=3,642m reached, results later this week.

In July 2018, it was reported that INEOS left licences P1026, P1191 and P1272 which contain the Rosebank discovery. Suncor acquired its 10% interest increasing its interest to 40% in each licence. Further to this deal INEOS also left licence P1830 which contains the Blackrock prospect on 29 June 2018 with Suncor acquiring its entire 25% interest in the licence. It is understood that Chevron has extended its re-tender for the Rosebank field development drilling campaign. The plan is to drill 11 top holes commencing in 2020 until 2021 lasting approximately 120 days. The main drilling programme will commence in 2022 with the drilling of 17 subsea wells – nine producers and eight water injectors. The field will be developed via a Floating Production, Storage and Offloading unit. A Final Investment Decision for the project is planned for early 2019. Seismic interpretation is ongoing over the entire licence, the results of which will be used in final prospect definition. An exploration well is planned to drill Blackrock in 2019. Rosebank was discovered in August 2004 by well 213/27-1Z which encountered two reservoirs – Rosebank and Lochnagar - with a total net pay of 52 m. Rosebank has a Paleocene reservoir and Lochnagar has an Upper Jurassic reservoir. Appraisal well 205/1-1, drilled in 2007 on the Rosebank structure, tested 6,000 b/d of good quality oil with API values of 37°. The field is situated in water depths of approximately 1,100 m. Between April and August 2011 a 350 sq km High Density 3D OBN survey was performed over Rosebank with SeaBird’s “Munin Explorer”. This was the second phase of the Rosebank High Density 3D survey. The first stage was shot in 2010 and covered an area of 256 sq km. Front End Engineering Design studies commenced in 2012. In 2013 Chevron submitted and Environmental Statement for the project. The produced oil was to be shuttled by tanker, while gas will be exported via a newly installed pipeline. Back when the Environmental Statement was submitted it was thought that peak oil production was expected to reach 82,000 b/d with peak gas production, expected three years after the initial oil production, at 134 MMcf/d. The Blackrock prospect is situated between the Cambo and Rosebank fields and has a Colsay / Hildasay reservoir target. The licence, P1830, was awarded in the 26th Offshore Licensing Round. The planned 2019 exploration well, if successful, could add substantial resources to the planned area development. Interest in P1026, P1191 and P1272 is held by Chevron North Sea Limited (40% + operator), Suncor Energy (40%) and Siccar Point Energy (20%). Interest in P1830 is held by Siccar Point Energy (52.5% + operator), Suncor Energy (25%) and Shell UK Ltd (22.5%).

Ineos has withdrawn from P1026, P1191 + P1272 containing the Rosebank discovery, its 10% going to Suncor (->40%). Ineos also left P1830 (Blackrock prospect), Suncor also taking on its 25%.

PDL 9, Papuan Fold Belt / Highlands, TD 3,820m, Toro A sst test gauged 165 MMcfg/d on 52/64” choke, confirming the extn of the discovery, well P&A’ing as planned, High Arctic rig 104. Oil Search (op), partners ExxonMobil, Ampolex Kumul Petr., Nippon + Gas Res. Juha 1.

Muruk 2 appraisal well in PDL9 block, near the Muruk gas disc, (Oil Search 24,4% op. ExxonMobil 21,7%, Ampolex 21,7%, Kumul Petroleum 20,5%, Nippon PNG LNG 9,7%, Gas Resources Juha 2%) had flowed at a maximum rate of 16,5 MMscf/d on a 0.8-inch choke, confirmed the extension of the Muruk field after hitting gas-saturated Toro A sands in pressure communication with the Muruk-1 discovery.

News from October 2017 states that Polskie Gornictwo Naftowe i Gazownictwo (PGNiG) abandoned after tests new-field wildcat Godna Wieś 1K in the 35/2000/p Klaj–Krzeczow–Zabno–Letowice–Zaborow–Tarnow-Wierzchoslawice permit in southern Poland. The well, drilled to the final depth of 1,725m (TVD 1,548 m) in the Upper Jurassic series, failed to recover commercial quantities of hydrocarbons and was abandoned with gas shows (volumes undisclosed). PGNiG was the sole operator of the well. Godna Wieś 1K, spudded on 29 March 2017 using the IRI Cabot 750 drilling unit, is located in the Malopolskie political province, near the city of Tarnow. In a geological sense, the well is situated in the western sector of the Carpathian Foredeep. The well had a planned final depth of 1,725 m (TVD 1,550 m), targeting the autochthonous Miocene (Sarmatian, Badenian) clastic succession and upper Jurassic carbonates. By the end of March 2017, the well reached a depth of 54 m, progressing through undifferentiated Tertiary series. The well reached the final depth of 1,725 m (TVD 1,548 m) in the Upper Jurassic series on 28 April 2017. Godna Wieś 1K was plugged and abandoned on 7 May 2017.

Godna Wieś 1K op. by PGNiG (100%) in 35/2000/p Klaj–Krzeczow–Zabno–Letowice–Zaborow–Tarnow-Wierzchoslawice permit, failed to recover commercial quantities of hydrocarbons and was abandoned with gas shows (volumes undisclosed).

On 4 March 2020 Equinor completed a farm-in, into two UK licences – P2277 and P1891 taking a 50% interest from Total in both licences which contain the Finzean prospect. Total is planning to drill exploration well 12/30-2 on its Finzean prospect. The company is planning to use the Noble Sam Hartley rig for drilling operations. Finzean comprises of stacked turbidite sands from Lower Cretaceous to Upper Jurassic in age (Punt, Ettrick and Burns sands) and is thought to be large enough for a stand alone development with pre-drill resources estimated 290 MMboe. Finzean is located across licences P2277 and P1891 and is a pinch-out of two Lower Cretaceous turbidite Punt Sands (one locally and one regionally sourced) on the north-eastern flank of the West Bank High. The prospect is sealed by overlying Lower Cretaceous Valhall shales and laterally by faulting and stratigraphic pinch-out. There is underlying potential in the Jurassic (previously known as Ferrick and Ulysses) which comprise of pinch-outs of the Upper Jurassic Burns and Ettrick sandstones against the West Bank High. Ferrick and Ulysses are sealed by the surrounding Kimmeridge Clay and laterally by faulting and pinch-out. All reservoirs are sourced by the Kimmeridge Clay to the north of the West Halibut Basin. Interest in the licence is now held by Total E&P North Sea UK Limited (50% + operator) and Equinor UK limited (50%).

Equinor completed a farm-in, into two UK licences – P2277 and P1891 taking a 50% interest from Total in both licences which contain the Finzean prospect.

On 21 November 2018, the Council of Ministers met and agreed on the draft agreement to award the Marine XXI exploration licence to Societe Nationale des Petroles du Congo (SNPC). As is the norm SNPC was awarded the licence but only holds a 15 % interest, Kosmos Energy operates the area with an 85% stake. The 2,351 sq km area covers acreage atop the Congo Fan in water ranging in depths between 2,000 m and 3,300 m. the initial exploration period is six years, there are two potential three-year renewals (6+3+3).   To date two well have been drilled within the block: In 2009, Eni Congo SA drilled the Hivoua Marine 1 well. The well was drilled to a D of 4540 m (water depth 2,712 m). The primary Lower Miocene target was fond to be water bearing while the secondary target did found oil in the Middle Miocene sandy shales from 3,885m to 3,945m. In 2001, Agip Recherches Congo SA drilled the dry HITM-1 well, the well is understood to have been targeting the middle Miocene and reched a TD of 3,787 m (water depth 2412 m). Disputed area: It’s worth noting that the south western portion of the block includes a portion of the Angolan Block 46 (this area is disputed).

Kosmos (85% op, SNPC 15%) was awarded new PSCs for Marine XXI exploration licence. 2,351 sq km area covers acreage atop the Congo Fan in water ranging in depths between 2,000 m and 3,300 m.

Lundin has completed a licence swap with Edison whereby the former has taken 10% in PL 850 and the latter gained 10% in PL 952. The two licences lie adjacent to each other in the Barents Sea, and surround the Nucula oil and gas discovery (in separate PL 393). The NPD confirmed on 8 November 2018 that the deal was completed with effect from 31 October 2018. PL 952 contains well 7125/4-3 which was drilled by Statoil in 2014 when the area was held under PL 393 B. The well targeted the Ensis prospect. 35 m of poor quality sandstone was present in the Lower Cretaceous intra-Knurr Formation and 7125/4-3 was abandoned as a dry hole. According to partner Cairn, Ensis had potential recoverable reserves of 291 MMboe. The stratigraphic prospect stretched the length of the licence and had a 1 in 3 chance of success. Nucula was discovered in 2007 by Norsk Hydro’s 7125/4-1. Oil and gas was proven in the Triassic Realgrunnen Group and the Kobbe Formation with estimated reserves put at 210-420 MMboe. However, following an appraisal well in 2008, which proved just a small oil column in thin sands, reserves were downgraded to the lower part of the range. As of 31 December 2017 the NPD lists the find as ‘production is unlikely’ and does not give any associated volumes. Following completion of the deal, interest in PL 850 is divided between Edison Norge AS (30% + operator), KUFPEC Norway AS (20%), Lime Petroleum AS* (20%), PGNiG Upstream Norway AS (20%) and Lundin Norway AS (10%) and interest in PL 952 is held by Lundin Norway AS (50% + operator), Suncor Energy Norge AS (40%) and Edison Norge AS (10%). *Note: Lime is selling its 20% interest in PL 850 to an undisclosed third party (see separate article).

Lundin making a licence swap with Edison whereby the former will take 10% in PL 850 and the latter will gain 10% in PL 952.

In March 2019 Moesia was still looking for partners for additional funding of its planned operations in the 1-5 Devetaki, 1-7 Tarnak, 1-9 Miziya and 1-10 Botevo exploration permits in northwestern Bulgaria. In April 2018 industry sources reported that a company from the UK was interested in a partnership with Moesia but no more details were communicated. The company completed the reprocessing of more than 2,000 km of data across all four blocks. Moesia anticipates to re-appraise the Devetaki gas field which produced more than 15 Bcf of gas and condensate at economic rates but was not appraised or developed optimally. The Devetaki field is believed to contain significant incremental volumes and being located adjacent to existing infrastructure it offers near term production potential. Interest in the four permits are 100% held by Moesia Oil and Gas EOOD.

Moesia Oil and Gas (Bulgaria) EOOD 1-5 Devetaki, 1-7 Tarnak, 1-9 Miziya, 1-10 Botevo - Farm-in opportunity

On 18 October 2019, the Argentine government granted an exploration permit for MLO-118 block to a consortium of a partnership of ExxonMobil and Qatar Petroleum through the publication of Resolution 657/2019 in the nation’s official gazette following the preliminary award of the block in May 2019 as a result of the Argentina Round 1 offshore bid round. Work program in the first exploration period of four years consists of 2D seismic acquisition of 784.53 km and reprocessing of 1,968.21 km, 3D seismic acquisition of 1,763.82 sq km and reprocessing of 1,469.85 sq km, along with 2D gravimetry and magnetometry acquisition of 5,017.69 km, followed by a drilling commitment for one well in the second exploration period of another four years. An optional third exploration period of five years is possible, although accompanied by a 50% partial relinquishment. ExxonMobil operates the block with 70% interest while partner Qatar Petroleum holds the remaining 30%. MLO-118 covers 4,203 sq km of deepwater area (as designated by the Argentine Secretary of Energy) in Malvinas Basin with approximated water depth below 200 m. Exploration target for the blocks in the area is expected to be oil and gas in the Springhill Formation, which has not produced from any fields on the Malvinas Basin side in comparison to the adjacent Austral Basin side where several offshore gas fields are currently producing. ExxonMobil and Qatar Petroleum won the rights for MLO-118 after submitting a joint offer of USD 29.95 million in Round 1 of the country’s offshore bid round that ended on 16 April 2019. Along with MLO-118, the group also won the rights for MLO-113 and MLO-117 blocks with offers of 30.1 million and 34.475 million, respectively. The offshore blocks marked the second partnership between ExxonMobil and Qatar Petroleum in Argentina after Qatar Petroleum's purchase of 30% equity in ExxonMobil affiliates in mid-2018. Background Information The Argentine government published Resolution 276/2019 on 16 May 2019 to award 18 blocks in Austral, Malvinas, and Argentina Basin from its Round 1 of its offshore bid round with a total committed investment of USD 724 million. Granting of exploration permits from the round was originally expected to be published in early-August 2019 with signing of the permits to follow within 15 days.

On 18 October 2019, the Argentine government granted an exploration permit for MLO-118 block to a consortium of a partnership of ExxonMobil and Qatar Petroleum

Mumbai High NW ML, Bombay offshore, tested 824 bo/d + 94 Mcfg/d from the L-II fm in late 2019, Aban Ice DS.

WO-24-I npw, Mumbai High NW ML, Bombay offshore, tested 824 bo/d + 94 Mcfg/d from the L-II fm.

South Bassein ML, Bombay Basin, NNW of B-193 field, TD 2,300m, tested, ops terminated (assumed susp.) Dec ’17, Greatdrill Chitra JU off location 20 Dec.

B-193 I expl op by ONGC (100.0%) in South Bassein ML block (Bombay B.)TD 2,300m, tested, ops terminated