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Petroleum Development Oman LLC (PDO) completed drilling operations at the vertical exploration well, Zareef West 1, on 5 April 2020 after reaching a TD of 1,462 m. No result has been reported. The well was spudded on 22 March 2020 in the Block 6 onshore licence with L/R “1”. It is located in the South Oman Salt Sub-basin of the Oman Basin. The Zareef oil field was discovered in March 1985 and brought onstream in August 1986. The Oman government own a 60% stake in PDO, with the remaining equity held by Shell (34%), Total (4%) and Partex (2%). PDO is 100% rightholder of Block 6.

Oman (Oman B.) Zareef West 1 op. by GOVT OM (60%), SHELL (34%), TOTAL (4%), PTTEP (2%) in Block 06 ops terminated 5 Apr '20 at TD 1,462m, no results.

On 9 August 2019, the Federal Agency for Subsoil Use held an auction for four blocks in Samara Oblast (Volga-Ural Province). The combined offers exceeded the starting price by five times.The winners of the auction will obtain 25-year E&P licenses. Details of the offer are as follows: The Gostevskiy block covers 105.5 sq km in the Buzulukskaya Depression and encompasses the Gostevskiy prospect with oil resources estimated at 15 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 9 MMbbl of oil. The starting price amounted to RUB 21.8 million (USD 0.34 million). Lukoil-subsidiary Ritek offered RUB 407.66 million (USD 6.4 million). The Otradnenskiy block covers 96 sq km in the Buzulukskaya Depression and encompasses a prospect with oil resources estimated at 4 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 9 MMbbl of oil. The starting price amounted to RUB 3.4 million (USD 0.05 million). Tatneft-Samara offered RUB 56.1 million (USD 0.9 million). The Vinogradovskiy block covers 15.8 sq km in the Zhigulevsko-Pugachevskiy Dome and encompasses the Vinogradovskiy prospect with oil resources estimated at 1 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 1 MMbbl of oil. The starting price amounted to RUB 1.7 million (USD 0.03 million). Region-Neft offered RUB 44.88 million (USD 0.7 million). The Pavlovskiy block covers 114 sq km in the Buzulukskaya Depression and encompasses unlicensed parts of the Bogatyrevskoye, Subbotinskoye, Rechnoye and Polovetskoye fields with combined 3P reserves estimated at 7 MMbbl of oil. Hydrocarbon resources (category D1) of the block are estimated at 11 MMbbl of oil. The starting price amounted to RUB 138.3 million (USD 2.13 million). Rosneft-Samaraneftegaz offered RUB 331.92 million (USD 5.2 million).

Lukoil sub Ritek was awarded Gostevskiy block (106km²) in the Buzulukskaya Depression, Tatneft-Samara Otradnenskiy (96km²) and Pavlovskiy (114km²) blocks, in the same area, Rosneft-Samaraneftegaz Vinogradovskiy (16km²) block on the Zhigulevsko-Pugachevskiy Dome.

Apache's near field exploration well 9/14b-16 over the Titan prospect had been P&A by 2 January 2018. The well spudded on 5 November 2017 using the "WilPhoenix" semi sub in 121m WD, and PTD was 2,187m MD (2,164m TVD) targeting Tertiary injectites between the Horda and Heimdal formations similar to the Corona discoveries (14km SW), with Pmean prospective resources of 43MMboe, potentially rising to 119MMboe (P10 case). Titan is part of Apache's ongoing near field small discoveries campaign, and was drilled on part-block 9/14b, licensed under P1985 which also contains the abandoned Leadon oil field and lies adjacent to the E of Beryl Field. P1985 was awarded in the 27th Seaward Licensing Round on 1 January 2013 for four years initial term (later extended by one year), with firm commitments to shoot 105 sq km of 3D seismic ahead of a drill or drop to 4,267m to the Late Jurassic J60 horizon. Equity partners are Apache Beryl I Ltd (77.22% + Op) and Shell subsidiary Enterprise Oil Ltd (22.78%).

009/14b-16 (Titan) op. by Apache (77,22%, Enterprise 22,78%) in P1985, Beryl area, play similar to nearby Corona, target oil in Tertiary injectite. P&A with the results n/a.

Expression of interest for the 6th Open Acreage Licensing Programme (OALP-VI) round are invited between 1 Dec '19 - 31 Mar '20. Although the process is officially closed, there is no announcement on the number of EoI's received for OALP-V. OALP's are presently scheduled at a rate of 3/yr in an effort to promote 'ease of doing business” in India. Background from GEPS.

Expression of interest for the 6th Open Acreage Licensing Programme (OALP-VI) round are invited between 1 Dec '19 - 31 Mar '20. Although the process is officially closed, there is no announcement on the number of EoI's received for OALP-V. OALP's are presently scheduled at a rate of 3/yr in an effort to promote 'ease of doing business” in India.

ONGC Videsh, Bharat PetroResources, Indian Oil and Oil India have been awarded 3-year PSC rights to offshore block 32 offered in Israel’s 1st offshore round which closed on 16 Nov ’17 with 24 blocks on offer. Block 32,  357 sq km, lies between the Tamar and Dalit fields. Bids were also placed by Energean (see related entry). A further licensing round is expected to be launched in 2018.

Israel (Levantine B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: Tamar (I/12) op. by NOBLE (32.5%, ISRA PTS 28.75%, DELEK DRLG 22.0%, TAMAR 9.25%, DOR EN 4.0%, Harel IIF 3.5%) to be check.Dalit (I/13) op. by NOBLE (32.5%, ISRA PTS 28.75%, DELEK DRLG 22.0%, TAMAR 9.25%, DOR EN 4.0%, Harel IIF 3.5%) to be check.

Fortis has transferred its 30% interest in PL 617 and PL 771 to partner MOL with effect from 23 April 2018 (reported by the NPD on 27 April 2018). The licences are located immediately east of Valhall on the Norwegian / Danish border. PL 617 covers 112 sq km over part of block 2/9 and PL 771 covers 260 sq km over parts of blocks 2/8 and 2/9. Valhall was discovered in 1975 by well 2/8-6 drilled by Amoco and first oil was produced in October 1982 from the field’s Upper Cretaceous chalk reservoir (Tor and Hod formations). By January 2017 the field, together with Hod, had produced 1 Bboe, more than three times what was expected in the original PDO. The operator has ambitions to produce at least another 500 MMboe over the field’s lifetime. Following completion of the deal, MOL Norge AS is the sole participant (100% + operator) in PL 617. Interest in PL 771 is split between MOL Norge AS (70% + operator) and DEA Norge AS (30%).

Norway (Lindesness Ridge (Central Graben)) Valhall

Repsol continued offering a farm-in opportunity in the Andaman III PSC, located in offshore North Sumatra Basin, in late October 2018. The company is offering up to 49% interest to participate to a planned high-impact exploration drilling campaign in late 2019. A data room was opened in September 2018 and the process is expected to be finalized in early 2019. The planned well, Rencong 1, will likely target Upper Eocene-Lower Oligocene carbonates of the Tampur Formation. The operator commenced the search for a deepwater rig in early September 2018. It is understood that the necessary permits for the drilling campaign are in place. Rencong 1 will fulfill the exploration commitments for the PSC. In late November 2017, the company completed the seismic commitment with a 3D seismic survey covering over 3,000 sq km in the block. The survey, acquired using Elnusa’s “Elsa Regent” vessel, was reported as the largest 3D seismic survey acquired in Indonesia at the time. The block is operated by Repsol’s fully owned subsidiary Talisman (Andaman) BV, with 100% interest. Prior to the acquisition by Repsol, Talisman had offered a farm-in opportunity in the block in 2014. At the time, several companies reportedly expressed interest in the highly prospective block. The Andaman III PSC, awarded in 2009, covers approximately 8,500 sq km and lies between shelf and over 1,300 m water depth. The block was offered during Phase II 2008 Tender Round under the regular tender mechanism and was officially awarded to Talisman (100%, operator) on 30 November 2009. The company paid a signature bonus of USD 7.5 million for the block. Firm commitments include G&G studies worth USD 2 million, acquisition of 2,500 sq km 3D seismic (USD 15 million) and drilling one well (USD 30 million). The seismic acquisition commitment was initially planned in 2010 but has been pushed back to a later date. The well commitment likewise has not been fulfilled. This deep water area in the southern Andaman Sea is vastly under-explored. Three exploration wells have been previously drilled within the current block boundaries. All are situated in the southern of the block, on the North Sumatran shelf. Samalanga 1 (P&A/dry - 1986) and Glumpang Minyeuk 1 (P&A/dry, 1987) were both drilled by Inpex, under the North Aceh Offshore PSC. EAO-B-1, which lies at the edge of the block, was also a dry hole. This well was drilled by Mobil in 1982 under the NSO PSC. Background Information Multiple play types exist in the area, including carbonate build-up on a basement high or on an anticline, syn-rift clastics with combined stratigraphic-structural trap component, inverted syn-rift clastics close to the Mergui Ridge, carbonate build-ups on flanks of the Mergui Ridge and Barisan fold-belt anticlines. Potential source rocks in the area in include the shales of the Eocene Parapat (lacustrine syn-rift), Oligocene Bampo, Lower Miocene Peutu/Belumai and Middle Miocene Baong formations. Potential reservoirs which could have commercial accumulations in this deepwater area are the Belumai carbonates and Parapat syn-rift sandstones. Shales of the Bampo and Baong formations would be the likely seals. Second exploration phase commitments (Year 4 to 6) include G&G studies (USD 0.6 million), acquisition of 500 sq km 3D seismic data (USD 3 million) and drilling one exploration well (USD 30 million). Directly east of the Andaman III block are Eni's Krueng Mane block, where two out of the planned three exploration wells were drilled in 2008/2009, and Zaratex's Lhokseumawe PSC. The 1985-1997 North Aceh Offshore PSC, operated by Inpex, previously covered a portion of this new block. This contract was held under moratorium for several years while Inpex attempted to re-negotiate the terms of the PSC to take into account the deep water nature of the area. Failure to settle the terms and the subsequent unjustifiable economics of exploration led to Inpex prematurely relinquishing the block. Vintage 2D seismic does exist, after Geco Prakla shot several 100 km lines over the area (North Sumatra Basin - Mergui Ridge) in 1995.

Indonesia, Andaman III PSC

Northern Oil and Gas has agreed to acquire ca. 43 sq km net in the Williston Basin from W Energy Partners. The assets account for around 6,750 boe/d of production. Total consideration at closing will consist of USD 100 million in cash and 56.37 million shares of Northern common stock. The deal will have an effective date of 1 Jul ’18.

Northern O&G has agreed to acquire ca. 43km² net from W Energy Partners for US$156 MM. The assets account for around 6 750 boe/d of production.

It was reported in November 2017 that Oil and Gas Development Company Ltd (OGDCL) has assigned 2.5% working interest in Khanpur 2870-7 EL (Indus Basin) onshore concession to Government Holdings (Pvt) Ltd (GHPL) with effect from 30 October 2017. As a result the revised equity split is as follows: OGDCL 97.5% (operator) and GHPL 2.5%. Khanpur EL covers an area of 2,497 sq km and is located in the Rahimyar Khan district of Punjab province. OGDCL was exclusively awarded the exploration licence, with the Petroleum Concession Agreement (PCA) having been signed on 21 February 2014.  

Pakistan (Jacobabad High (Indus B.)) Khanpur

On 1 October 2018 OMV Petrom reported having reached an agreement with Mazarine Energy Romania for the transfer of licences for nine oil and gas fields. This deal follows the first one completed in 2017 where Mazarine bought 19 fields from OMV Petrom. The agreement includes the transfer of wells and infrastructure as well as approximately 100 staff to Mazarine. The deal is now subject to approval by the relevant authorities. The nine fields are situated about 30 km west of the city of Bacau in the Carpathian Flysch Zone. The cumulated oil and gas production from the nine fields amount to some 1,000 boe/d. Mazarine’s goal is to extend the life cycle of these fields and to maintain the production activities in the field.   Mazarine Energy Romania SRL is a subsidiary of Netherlands-based Mazarine Energy BV.

Romania, Bacau

GHP is looking to farmout a 50% interest in its so far wholly-owned West Gebel El Zeit block, 214 sq km on/offshore in the Gulf of Suez Basin.

GHP is looking to farmout a 50% interest in its so far wholly-owned West Gebel El Zeit block, 214 sq km on/offshore in the Gulf of Suez Basin.

Petrobras President, Roberto Castello Branco, in early July said the company plans to sell all its onshore and shelf fields to concentrate activities on deepwater assets. New larger and more attractive packages for onshore assets will be launched. The current divestment list may include the Canto do Amaro and Carmopolis fields, both onshore with currently active production. In 2019, Petrobras divested 65 mature fields. Petrobras is specializing in the deepwater fields because this is where we can extract the greatest possible return and where Petrobras is unbeatable. He characterized the onshore and shelf fields as very small for Petrobras with low productivity. Castello Branco highlighted that for Petrobras to face the opening of markets and be competitive, the company has been focusing on cost reduction.Meanwhile, Petrobras and other rightholders received various contract extensions on blocks where they held interests such as FZA-M-59, SEAL-T-118, SEAL-T-143, SEAL-T-154, SEAL-T-155, ES-T-506, ES-T-516, PN-T-103, PN-T-69, PN-T-87. Two other Petrobras blocks (PAR-T-198 and PAR-T-218) in the Parana Basin returned to active status after lengthy periods of force majeure and the first period of exploration has now been extended to 3 November 2021. Regarding divestment in the downstream, the Petrobras CEO anticipated that the next refinery to receive a binding proposal will be Repar, in Paraná, in August. Castello Branco also said that most of the contracts to sell the refineries could be signed by the end of 2020 with formal closing of deals in 2021. He also believes that the sale of Gaspetro can be completed by year end. Mitsui, a Petrobras partner in the company, has the right of first refusal, but thus far has not shown interest. Regarding divestment in BR Distribuidora and Braskem, Castello Branco said that those divestments would depend on improvements to the economic scenario and capital markets. He again expressed satisfaction with the binding offers received for the RLAM refinery further noting it was the first major asset offered for sale in 2020 and that given the complex scenario for the global economy and the oil industry, it was a very good result,” he said.

Brazil, Petrobras President, Roberto Castello Branco, in early July said the company plans to sell all its onshore and shelf fields to concentrate activities on deepwater assets. New larger and more attractive packages for onshore assets will be launched. The current divestment list may include the Canto do Amaro and Carmopolis fields, both onshore with currently active production.

Korea National Oil Corp. (KNOC) continued offering a farm-in opportunity in Block 6-1C and 6-1E, in the offshore Ulleung Basin, as of June 2020. KNOC owns 100% working interests in the both blocks and has extended its exploration rights in the both blocks for another 10-year exploration period since February 2020. One prospect named as Yellow Tai structure with an estimation of 3.5 Tcf of gas resources, is the drilling target for the company in 1H 2021. KNOC announced in earlier February that the structure 'Bangeo' (name in Korean) located in the deep-water area with an average water depth of 1,000 m, about 40 km east of Donghae field, the only gas field in Korea, is expected to have resource reserves more than 10 times that of the Donghae field. (It is possibly talking about the same structure which is estimated to locate within the Block 6-1E). In addition, the new structure is considered to have the same strata type as that is distributed in the Block 8/6-1N where KNOC with its partner Woodside Australia made a non-commercial discovery in 2015. In order to confirm the possibility, a large-scale 3D seismic survey was planned to be conducted initially in the first half of 2020, but has been deferred to 2021   Background Information Block 6-1C and 6-1E are the only exploration blocks in the vicinity of the Donghae Gas field, the only producing gas field in South Korea. The fields and discoveries in the blocks had reservoirs in the Miocene section, with traps related to anticlines, unconformity and stratigraphic variation. Older and deeper traps related to rifting, including normal faults and tilted basement fault-blocks, have not been tested. Block 6-1C (6-1 Central), covering more than 2,000 sq km, contains the only two producing gas fields in South Korea, Donghae 1 and Donghae 2 (in the past was referred to as Gorae-8). Donghae-1, with recoverable reserves of around 190 Bcf and 3 MMbc, was brought into commercial production in November 2004. Donghae 1 field reached peak annual production of around 19 Bcf in 2010. In 2018, annual production was around 3Bcf, with daily average output of 10 MMcf/d. Production life is expected to be until 2021, with the field planned to be converted afterwards into an offshore storage facility. Donghae 2 gas field is located 5.4 km southwest from the Donghae 1 gas field. Donghae 2 has estimated recoverable reserves of about 22 Bcf and it was brought onstream in July 2016. It was jointly developed by KNOC (operator, 70% interest) and Daewoo International (30% interest). The field reached a daily production of 22 MMcf/d in 2018. Block 6-1E, covering about 1,300 sq km, contains two gas discoveries Dolgorae 2 and 3. Dolgorae 2 was discovered in January 1989, discovery well Dolgorae 2 was drilled by Korea Petroleum Dev. Corp, one outpost well Dolgorae (Dolphin) 2A-1X was drilled in the same year. The discovery was estimated to have 75 Bcf of gas in-place. Dolgorae 3 was discovered in 1987, discovery well Dolgorae 3 was also drilled by Korea Petroleum Dev. Corp, two outpost wells were drilled in 1988 as dry hole or oil/gas shows. The discovery was estimated to have 140 Bcf of gas in-place.

Korea National Oil Corp. (KNOC) continued offering a farm-in opportunity in Block 6-1C and 6-1E, in the offshore Ulleung Basin, as of June 2020. KNOC owns 100% working interests in the both blocks and has extended its exploration rights in the both blocks for another 10-year exploration period since February 2020.

In late May 2020, ALNAFT director Noureddine Bedoui said that the agency planned to launch a bid round in the medium term. He expressed hope that the new hydrocarbon law under which the offering will be organized, will spur the interest of E&P companies. Bedoui recalled that the new law improves fiscal terms for operators and provides more flexibility in contract terms. He also mentioned that direct negotiations were possible for E&P companies wanting to enter into a partnership to explore or develop hydrocarbon resources. This refers to the numerous permits held 100% by Sonatrach. The state company has not enough resources to work on all this acreage and is keen to partner with IOC's. The last bid round was held in Algeria in 2014. Since then, a new round has been considered several times but did never materialize. On 15 March 2017, the then ALNAFT Director Sid Ali Betata said that Algeria will wait until the crude oil market improves before launching its next licensing round. In December 2016, Betata said that his agency intends to launch its fifth bid round for hydrocarbon rights in 2017. In May 2015, it was reported that ALNAFT has started talks with oil companies in preparation for the next bid round. Around 50 oil companies were pre-qualified to take part in the bid round. In early December 2014 it was reported that ALNAFT intends to launch its next bid round, the fifth, in the third quarter of 2015. In late October 2014 Betata said at the closing of the fourth round that the new acreage offer will be launched “within weeks”.

n late May 2020, ALNAFT director Noureddine Bedoui said that the agency planned to launch a bid round in the medium term. He expressed hope that the new hydrocarbon law under which the offering will be organized, will spur the interest of E&P companies.

On 12 March 2020, Sonatrach signed a memorandum of understanding with Chevron to start discussions on the partnership opportunities in the hydrocarbon industry. Both companies will discuss opportunities in exploration, development and production of hydrocarbons in the light of the new hydrocarbon law which became effective in December 2019. A future partnership would allow a transfer of technology and know-how which would benefit the various segments of the Algerian oil and gas industry. In August 2019 it was reported that any new venture projects in discussion between Sonatrach and IOC’s are frozen until the political transition in Algeria is completed. Sonatrach at the time was dealing only with day-to-day tasks to keep existing production going. The political transition was completed with the December 2019 presidential elections. In April 2019 it was reported that a delegation of Chevron was to visit Algeria in the coming days. Chevron and the authorities were probably to discuss shale oil and gas production opportunities in the country as Chevron’s attempt to take over Anadarko failed. In March 2019 it was reported that Sonatrach is holding talks with Chevron. Sonatrach SEO Abdelmoumen Ould Kaddour met three high ranking officials from Chevron in charge of overseas E&P development. Chevron is interested un upstream conventional and unconventional hydrocarbon projects. The company’s move is motivated by fellow U.S. player Anadarko who has been operating in Algeria for several years. A Chevron delegation was to go to Algiers in April to further discuss potential opportunities. Chevron is not yet present in Algeria’s E&P sector.

Algeria, not found

Bight Petroleum Corp is seeking a strategic partner to join exploration activities in the exploration permits EPP 41 and EPP 42, located in the Eastern Bight Basin. Bight Petroleum is offering significant equity and strategic entry into these permits, which have planned 3D seismic acquisition and future drilling, in return for a carry of the future activity.  The potential partner would assist with funding the 3D seismic, planned for Q4 2019. PGS will conduct the Duntroon 3D survey to de-risk the prospectivity and mature drill ready prospects. Bight opened a dataroom for the farm-out in Q2 2019, with hopes to finalise an agreement in 2H 2019.  The farminee would carry Bight Petroleum on the planned seismic with a follow up well option. The Duntroon seismic is planned to be carried out across both permits, with 2,820 sq km to be acquired.  It would be designed to acquire more data over the Price Prospect as well as define drillable targets.  Mapping and derisking of the prospects is then planned for late 2020. The Price Main Prospect is the largest prospect within EPP 41 and is estimated to contain potential in-place resources of 8 Bb, with significant multi-million barrel recoverable resource potential, across a 74 sq km closure.  It is a three-way closed trap against a bounding fault with potentially five sandstone units within the intra-Waigunda section.  The Upper Tiger and Hammerhead deltaic sequences have been outlined as primary targets, which are reported to be similar to those at Stromlo, a well being drilled to the west, within the Bight Basin. There is also the potential for stratigraphic trapping. The prospect is located in water depths of 1,900 m. Remapping conducted by Bight Petroleum, using depth conversion, 3D seismic interpretation and reprocessing has resulted in 14 explorations targets being identified on 2D seismic data, with Price the largest. It is estimated that there are around 43 Bb in place, with an estimated potential recovery of around 9 Bb of oil. Bight has reported that the 3D seismic would be aimed to de-risk the play and define drillable targets within the permits. Bight reports that the current 2D seismic data available provides poor resolution for mapping the reservoir sequences but they do appear thickly developed with minimal faulting. The permits cover a total area of around 8,500 sq km, located around 50 km south of the Eyre Peninsula in around 1,100 to 2,200 m water depth. Both permits were awarded in July 2011, for an initial period of six years. After work suspensions relating to the first terms, the permits will now expire on, or be eligible for renewal by, 7 July 2024. Bight Petroleum has contracted RISC as its executive advisor in the farm-out. Companies interested in pursuing this opportunity should contact: Jens Biertumpel, CEO Tel: +41 78 810 4323 Email: [email protected]  Lawrence Bernstein, Exploration VP, COO Tel: +1 403 354 2492 Email: [email protected] Bight Petroleum has also contracted RISC Advisory to assist in the farm-out process, so additional contact can be made via: Robbie Harrison, Director A&D Email: [email protected]         Tel: +61 8 9420 6648 Dan Calder, Director A&D Email: [email protected]                Tel: +61 8 9420 666

Bight Petroleum Corp is seeking a strategic partner to join exploration activities in the exploration permits EPP 41 and EPP 42, located in the Eastern Bight Basin.

As of April 2020, China National Offshore Oil Corp (CNOOC) is seeking partners in its BC9 and BCD10 contracts in the Gabon Coastal Basin offshore Gabon. The company operates the contracts BC9 and BCD10 with a 100% interest since Shell exited the licences in November 2019. The company attempts to farm out up to 50% stake prior to drill two high impact wells between late 2020 and 2021, one in each block. According to CNOOC all commitments have been met in both contracts. The company is to enter, in September 2020, in the 2-year fourth exploration period of the BC9 contract with the possibility to be extended up to three years. The BCD10 licence holds the multi Tcf Leopard gas discovery (2014) and is in a gas holding period until 2026 with minimal work commitments. CNOOC identified, both in post-salt and in pre-salt sequences, some 25 leads and/or prospects of which two are drill-ready. The "Tigre" prospect is to be drilled in about 2,000 m of water depth in the BC9 block targeting an approx. 100 sq km area in the pre-salt Gamba sandstones of Aptian age. The "Seal" prospect is to be drilled in approx. 400 m of water depth in the southeastern corner of the BCD10 block targeting the carbonate of the Albian Madiela Group formation in a large 3-way structure with mean recoverable resources estimated at 356 MMbo. CNOOC is also working on the Leopard gas discovery studying for a further appraisal program to determine the feasibility of a standalone development. CNOOC has open a data room since March 2020 with an anticipated bid deadline in mid-2020. Contact details:         Lucas Ong Business Development Advisor                          E-mail: [email protected]               Tel: +44 1895-555319 Ben Kilner Team Lead, Global Exploration                          E-mail: [email protected]               Tel: +44 1895-555310   Background information The blocks BC9 and BCD10 were initially granted to Shell on September 2007. BC9 and BCD10 blocks are mainly in deep waters, covering a total of some 13,400 sq km of which about 530 sq km are in shallow waters. CGG acquired a 6,000 sqkm 3D seismic program between 2010 and 2011. CNOOC farmed in both blocks in 2012. The partners drilled a first wildcat N'Komi Marin 1 in 2014, the well intersected a 200 m paleo-oil column in the pre-salt Gamba formation. It was followed by a success with the Leopard gas and condensate discovery made in October 2014. The latter drilled to TD of 5,063 m intersected a substantial gas column of 200 m of net gas pay in the Gamba formation. The discovery was confirmed by the appraisal Leopard 2 suspended in January 2016. CGG completed in March 2016 the acquisition of a 3D seismic program in the BCD10 block. Six exploration wells were drilled before 2007, in the areas covered by the actual BC9 and BCD10 blocks, targeting post-salt objectives such as the Cenomanian Cap Lopez formation and the Albian Madiela Group formation. All were dry except the Grand Large N'Kendji Marine 1 wildcat, which encountered non-commercial oil in February 1985. The well, drilled by Elf Gabon, is located 85 km west of Sette Cama in 163 m of water. It bottomed in the Albian Madiela Group at a depth of 3,893m.

China National Offshore Oil Corp (CNOOC) is seeking partners in its BC9 and BCD10 contracts in the Gabon Coastal Basin offshore Gabon.

As of 17 April 2020, Petroperu as future operator of Block 192 continues to seek a partner to take a 60% working interest in block located onshore in the Maranon Basin. Fontera Energy currently operates the block and has been in discussions with Petroperu to become the partner however a decision has not been made by the state company who may be talking to other interested companies. Fontera continues to operate the block under a temporary agreement. In November 2018, Peru’s congress approved a bill which gives Petroperu the right through direct negotiations to sign a hydrocarbon production contract for onshore Block 192 in the Maranon Basin of the Loreto area. The bill also gives Petroperu the option to allow a NOC to participate as a partner or operate the contract. Fontera Energy is currently the operator of the block under a temporary contract which expired on 10 June 2019 but has been extended multiple time since. The 5,126 sq km block was awarded to Pacific Stratus International Energy Ltd on 30 August 2015 and was originally set to expire on 31 August 2017.The company was required to drill 6 production wells over the two-year contract, and must maintain a number of producing wells greater than or equal to the average number of producing wells registered in the 12 months prior to the contract effective date. The block was suspended under force major from March 2016, the suspension was lifted in September 2018.

Perupetro SA seeking partner for Block 192 in Maranon Basin

Mirpur Khas 2568-7 EL, Lower Indus onshore, Sindh, tested and ops terminated late Nov ’18 at TD 4,040m, target Lower Goru assumed productive, no details, HL-5 rig.  UE (op), partners Bow Energy, SRL, Zaver + Govt Holdings.

Moroja 1 (UEPL 65% op. Bow Energy 30%, GHPL 5%) in Mirpur Khas 2568-7 EL, gas discovery, during a successful test programme in the Lwr and U. sst of the Cretaceous Lwr Goru Fm, the well have flowed 31 MMscfg/d.

As announced on 24 July 2018 by Rio Negro provincial Energy Secretary, Sebastian Caldiero, launched a six block bid round including the Catriel Oeste, Catriel Viejo, Loma Guadalosa, Tres Nidos, Las Bases and Puesto Prado blocks. The due date for bids is 31 August at 11 AM local time at the secretary offices in Espana 336, Cipolletti city. Opening of A envelopes will take place the same day at 12 PM. The province requires a minimum investment of US$ 60 million for the next 5 years. Caldiero also said that 45.23 sq km Catriel Oeste and 43.28 sq km Puesto Prado were already producing. These areas were already offered in February, apparently with no response. Central Resources Inc, through its subsidiary in Argentina, CRI Holding Inc Suc Arg was the operator of these blocks, but they were relinquished in 2017. Catriel Oeste was Central Resources' most important concession in the Rio Negro province. It also held interests in the Las Bases and Puesto Prado blocks. For more information please click on www.energia.rionegro.gov.ar/licitacion, contact [email protected] or call to +54 299 4773371.<P />

As announced on 24 July 2018 by Rio Negro provincial Energy Secretary, Sebastian Caldiero, launched a six block bid round including the Catriel Oeste, Catriel Viejo, Loma Guadalosa, Tres Nidos, Las Bases and Puesto Prado blocks.

On 23 July 2020, the Georgian Government (the Government) and Frontera Resources (Frontera) settled their dispute regarding Block XII, in eastern Georgia (South Caspian Basin). Frontera agreed to relinquish more than 99% of the 5,060 sq km Block XII, while the Government allowed Frontera to maintain contract areas encompassing its fields. Frontera's new contract areas: Mirzaani (17.2 km2), Taribani (17.66 km2), Patara-Shiraki (1.96 km2), Bayda (3.71 km), Nazarlebi (0.49 km2) and Mtsarekhevi (1.59 km2), totaling 42.61 sq km.

Georgia (South Caspian B.) ? op. by FRONTERA (100%) in Block XII

Eni has signed with Sonatrach to acquire a 49% stake in 3 onshore blocks in the North Berkine Basin, namely Sif Fatima II, Zemlet El Arbi and Ourhoud II, total 8,500 sq km. Sonatrach retains 51%. Exploration is planned with a view to lead to some production in late 2020 - reserves of the 3 blocks estimated at 145 MMboe.  The farmin is yet to be approved by the authorities.   The map below illustrates Sif Fatima II (3,132 sq km) + Zemlet El Arbi (2,742 sq km), but please note Ourhoud has yet to be confirmed – below only shows the Ourhoud field block.

Algeria, Sif Fatima II (Dev)

On 1 July 2020, the Agencia Nacional de Hidrocarburos (ANH) announced it received five expressions of interest from two companies to incorporate areas to the 2020 bidding round referred as the 3rd cycle of the Proceso Permanente de Asignacion de Areas or PPAA. The ANH also indicated that the 4th cycle of the PPAA to be held in 2021 is being revised. On 12 June 2020, the ANH published a modified schedule for the 2020 PPAA: The deadline to present the expression of interest was extended to 30 June. The Land Map with the areas offered in the 3rd cycle of the PPAA will be published on 18 August. The rest of the dates continues as previously published: The list of qualified investors will be published on 25 September. The offer hearing will be on 30 October. The areas will be awarded on 27 November 2020, unless there is a counteroffer, in which case they will be awarded on 14 December 2020. Contracts will be signed from 30 November 2020. For areas with counteroffers, they will be signed from 15 December 2020. Despite the difficult circumstances this year with the pandemic and the low oil prices, it is good that the ANH continues with the process to assign areas in Colombia as the country needs to increase reserves and there are still good opportunities in the country. Background Information On 20 May 2020, the ANH published several modifications to the 3rd cycle of the PPAA: It introduced the expression of interest, which is a communication where companies indicate their interest in an area. The ANH will study those areas and will determine if they became areas to be offered in the bid round. Companies must present a proposal or be fined by the ANH USD 100,000. The ANH indicated that this year during the 3rd cycle, the agency will not offer areas determined and delimited by the ANH. It will not be mandatory to buy data packages to participate in the PPAA. Areas classified as frontier or immature will only be assigned as Technical Evaluation Agreements (TEA). The schedule was modified as followed: Companies have until 31 August to update their qualification documents. The ANH will publish the preliminary list of qualified companies on 21 September and the final list on 25 September. The expression of interest deadline was set as 17 June. On 28 April 2020, the ANH published a modified schedule for the 3rd cycle of the PPAA. The due date to request areas to be incorporated into the process was set to 4 May 2020. On 3 August 2020 the agency was going to publish the areas for the 3rd cycle. The areas will be awarded on 27 November 2020, unless there is a counteroffer, in which case they will be awarded on 14 December 2020. Contracts will be signed from 30 November 2020. For areas with counteroffers, they will be signed from 15 December 2020. On 17 April 2020, the ANH published a list of companies qualified to participate in the 2020 PPAA. The list included 29 companies and only one company, Emerald Energy PLC, did not qualify. From the pre-qualified companies, most (17) were eligible to do exploration or exploitation of offshore areas, and 12 were not. Pre-qualified companies PPAA Colombia 2020   Company Qualified offshore CNE Oil and Gas S.A.S. No Frontera Energy Colombia Corp. Yes Ecopetrol S.A. Yes Parex Resources (Colombia) Ltd. Yes Geoproduction Oil and Gas GMBH No Occidental Andina LLC Yes Occidental de Colombia LLC No Gran Tierra Energy Colombia LLC Yes Cepsa Colombia S.A. No Geopark Colombia S.A.S. Yes Occidental Condor LLC Yes Aspect Holdings LLC No Hunt Overseas Oil Company Yes Ecopetrol Costa Afuera S.A.S. Yes Hocol S.A. Yes Amerisur Exploracion Colombia Limited No Mansarovar Energy Colombia Ltd. Yes Union Temporal La Lula Captiva No Noble Energy Limited Yes Hupecol Oriente Colombian Holdings LLC No ONGC Videsh Limited Yes Colombia Energy Development Co. No Interoil Colombia Exploration and Production INC No Vetra Exploracion y Produccion Colombia S.A.S. Yes Petroleos Sud Americanos SA No CNOOC Petroleum Colombia Limited Yes Lewis Colombia INC Yes Ismocol S.A. No Pluspetrol Colombia Corporation Yes Source: IHS Markit © 2020 IHS Markit

Colombia, On 1 July 2020, the Agencia Nacional de Hidrocarburos (ANH) announced it received five expressions of interest from two companies to incorporate areas to the 2020 bidding round referred as the 3rd cycle of the Proceso Permanente de Asignacion de Areas or PPAA.

Statoil has reportedly elected to hand back its AD-10 block, acquired in 2014 off the Takhine coast, following an assessment of the area’s prospectivity and a high tax régime, inter alia. The wholly-owned, 9,015-sq km block lies in the Bengal Deep Sea Fan.

Myanmar, not found

13 November 2018, Uzbekneftegaz (UNG) and the Abu Dhabi National Oil Company (ADNOC) signed a Framework Agreement under which ADNOC will provide strategic advice in relation to Upstream and Downstream operations.The agreement was signed by Mr. Ashrafkhanov, Chairman of the Board, Uzbekneftegaz and Mr. Alsuwaidi, the Executive Office Director of ADNOC at the Abu Dhabi International Petroleum Exhibition and Conference (ADIPEC).

13 November 2018, Uzbekneftegaz (UNG) and the Abu Dhabi National Oil Company (ADNOC) signed a Framework Agreement under which ADNOC will provide strategic advice in relation to Upstream and Downstream operations.The agreement was signed by Mr. Ashrafkhanov, Chairman of the Board, Uzbekneftegaz and Mr. Alsuwaidi, the Executive Office Director of ADNOC at the Abu Dhabi International Petroleum Exhibition and Conference (ADIPEC).

Block 6 off SW Cyprus, Cyprus’ Energy Minister has announced that the results of the well (spudded last month) are encouraging, with reservoir geology at the gas find similar to Zohr in nearby Egyptian waters, more details to follow, Saipem 12000 DS. Eni (op), partner Total.

Cyprus (Herodotus B.) Calypso 1 op. by ENI SPA (50.0%, TOTAL 50.0%) in Block 06

In conjunction with the release of its Q3 results on 22 October 2019, Oil Search Ltd, announced it has retained an investment bank to manage the sale of a 15% equity stake in the company's core Alaskan leases. This would reduce Oil Search's interest from 51% to 36%. The process is set to kick off in November and the timing of the sale is targeted for mid-2020, after the 2019/2020 drilling season but before a Final Investment Decision (FID) is made on the Pikka Unit development. Oil Search has previously stated it plans on initial production of 30,000 bo/d in 2022, increasing to 120,000 bo/d in 2024. Potential debottlenecking opportunities could increase that figure to 150,000 bo/d. Pikka is estimated to hold up to 750 MMbo recoverable resource. A Final Investment Decision on the Pikka Unit Development is currently scheduled for mid-2020. Oil Search farmed in to and became operator of the North Slope properties (Pikka Unit and adjacent exploration acreage, Horseshoe block and Hue Shale area) in early 2018 through an agreement with Armstrong Energy and GMT Exploration for USD 400 million, and subsequently exercised an option to take Armstrong's and GMT's remaining interest in June 2019 for USD 450 million. In August 2019, the company reached an agreement to align its interests with Repsol, resulting in a payment to Oil Search of USD 64.4 million. In the aligned areas, the working interest split 51% for Oil Search and 49% for Repsol. Source: Oil Search

Oil Search Ltd, announced it has retained an investment bank to manage the sale of a 15% equity stake in the company's core Alaskan leases. This would reduce Oil Search's interest from 51% to 36%.

S-C part of AE-0047-3M-Agua Dulce-06 block, onshore Sureste Basin, suspended at TMD 4,199m (3,773m TVD) mid-Jan '20. Target Cretaceous.

Vinik 1EXP nfw. (Pemex 100%), S-C part of AE-0047-3M-Agua Dulce-06 onshore block, suspended at TMD=4199m (3773m TVD) mid-Jan '20. Target Cretaceous. Results are not available.

W. Bohai Gulf Basin, WD 20m, ops terminated 10 May ’19, no results, HYSY 921 JU. Target Tertiary sands.

Caofeidian 18-1E-1 (CFD 18-1E-1) nfw W. Bohai Gulf Basin, WD 20m, ops terminated 10 May ’19, no results, Target Tertiary sands.

On 9 October 2018, the Federal Agency for Subsoil Use held an auction for three blocks in Dagestan Republic (North Caucasus). Two companies submitted applications and local DagestanBureniyeServis offered highest bids for all blocks. The winner of the auction will obtain 20-year E&P licenses. Details of the offer are as follows: The Kapiyevskiy block covers 10.1 sq km in the Terek-Caspian Basin and encompasses the developed Kapiyevskoye oil field with remaining recoverable 3P reserves estimated at 0.5 MMbbl. Three oil accumulations in the Lower Cretaceous and Middle Jurassic sections have been identified at Kapiyevskoye discovered in 1969. Cumulative oil production amounts to 3.4 MMbbl. The starting price amounted to RUB 9.48 million (USD 0.14 million). The winning bid was RUB 10.428 million (USD 0.16 million). The Oktyabrskiy block covers 2.9 sq km in the Terek-Caspian Basin and encompasses the almost depleted Oktyabrskoye oil field. One oil accumulation in the Lower Triassic section has been identified at Oktyabrskoye discovered in 1985. Cumulative oil production amounts to 0.044 MMbbl. The starting price amounted to RUB 0.772 million (USD 0.01 million). The winning bid was RUB 0.849 million (USD 0.01 million). The Nakazukhskiy block covers 3.6 sq km in the Terek-Caspian Basin and encompasses the almost depleted Nakazukhskoye oil field discovered in 1988. Cumulative oil production amounts to 0.38 MMbbl. The starting price amounted to RUB 0.752 million (USD 0.01 million). The winning bid was RUB 0.827 million (USD 0.01 million).

Russia Government of Russia awards three licenses in Dagestan - Kapiyevskiy, Oktyabrskiy & Nakazukhskiy block

United Oil & Gas announced on 17 July 2019 that it had signed a non-binding Heads of Terms agreement to sell its interest in licence P2366 (blocks 15/18d and 15/19b) to Anasuria Hibiscus UK Limited. In an update on 7 October 2019 it was confirmed that the Sale and Purchase Agreement (SPA) had been signed. United Oil and Gas was awarded the licence in the 30th Offshore Licensing Round. The acreage contains the Crown discovery. The signing of the SPA triggered a payment of USD 100,000 from Hibiscus to United Oil and Gas. Following the approval from the OGA which was confirmed on 12 December 2019 a further payment of USD 900,000 will follow. USD 50,000 of this total is payable to Swift Exploration which held a 5% interest in the licence. Subject to further milestones being agreed an additional sum of USD 3 million will be paid before the end of 2020 and then a further USD 1 million paid once the field is on production. Crown was discovered by ConocoPhillips by exploration well 15/19-9 in 1998. The well was drilled to test a four-way dip closed structure and encountered oil and gas in the Balmoral Sandstone Member. The sands were good quality with a net to gross in the region of 35-90%. United Oil and Gas published the results of a Competent Persons Report on 1 February 2019 which estimated the Crown discovery to hold 2C gross unrisked contingent resources of 6.35 MMbbl STOIIP. The work programme involved rock physics modelling and seismic reprocessing. Interest and operatorship in P2366 is now held by Anasuria Hibiscus UK Limited (100%).

United Kingdom, P2366

Jinzhou 9 block, W. Liaodong Bay, Bohai Gulf Basin, WD 26m, ops terminated 20 Mar '20, results n/a, Zhongyouhai 5 JU. Target Dongying fm + Pre-Tertiary basement.

SZ 34-1-1 nfw Jinzhou 9 block, W. Liaodong Bay, Bohai Gulf Basin, WD 26m, ops terminated 20 Mar '20, results n/a, Zhongyouhai 5 JU. Target Dongying fm + Pre-Tertiary basement.

Ref. DEA 23 Jul '19, Hunt's awards of the Degueche/Hezoua (8,679 sq km) and Elwaha (6,657 sq km) blocks were gazetted on 24 Dec '19, thus effective. Both lie in the Ghadams Basin, west of Sabria oilfield and El Franig gasfield:

Hunt's awards of the Degueche/Hezoua (8,679 sq km) and Elwaha (6,657 sq km) blocks were gazetted on 24 Dec '19, thus effective. Both lie in the Ghadams Basin, west of Sabria oilfield and El Franig gasfield:

Coro's 2018 conditional agreement to acquire a 42.5% stake in the Bulu PSC off East Java has been called off as a result of successful drilling in the Duying block. One of the 698-sq km Buru units contain the Lengo gasfield, for which an FDP has been approved. KrisEnergy (op), partners Satria, HyOil + Gwinet.

Coro's 2018 conditional agreement to acquire a 42.5% stake in the Bulu PSC off East Java has been called off as a result of successful drilling in the Duying block. One of the 698-sq km Buru units contain the Lengo gasfield, for which an FDP has been approved. KrisEnergy (op), partners Satria, HyOil + Gwinet.

The latest news on the new-field wildcat Steig 1 drilled by Rhein Petroleum GmbH in the Graben Neudorf tract in western Germany states that the well is a significant oil discovery for the company. As stated on 20 January 2020 by Tulip Oil Holding B.V., the majority owner of Rhein Petroleum, the discovered pool holds in excess of 115 MMBbl oil in place. The company intends to appraise the discovery and produce the find with horizontal wells. Rhein Petroleum is the sole operator of the well. Steig 1, drilled as directional well, was started on 26 May 2019. The well is located approximately 1 km north of the city of Weingarten (10 km northeast of Karlsruhe), within the northern sector of the Upper Rhine Valley (Oberrheingraben). Steig 1 was targeting the sandstone series of the late Eocene-early Oligocene Pechelbronn Beds, expected to be encountered at a depth of approximately 900 m. The well had a planned final depth of 1,033 m. The information from mid-2018 suggested that Rhein Petroleum started constructing a road leading to the future drillsite and the pad was (likely) completed in August. The operator was expecting to commence the drilling in late September/early October 2018. The Steig 1 well is understood to be a field reactivation well (the wells drilled in the 1950s recognized an oil pool that was never produced). News from early 2019 stated new-field wildcat Steig 1 was expected to spud during spring of 2019 (May/June?). The company had secured all the necessary drilling permit and is believed to have already constructed the drilling pad. On 20 May 2019, Rhein Petroleum disclosed it was erecting a drilling unit - the onset of the drilling was set for 27 May 2019. The well was expected to take four to six weeks to drill. By the end of May, the well reached a depth of 517 m. The well reached the final depth of 1,020 m on 6 June – 503 m had been drilled during the month. On 8 July 2019, Tulip Oil Holding B.V., 90%-owner of Rhein Petroleum GmbH, disclosed that Steig 1 encountered oil column of 150 meters (did not reach a water contact in the oil-bearing sands). The well was tested and has been completed for production after producing 4,000 b of oil, which demonstrated economic viability of the discovery. Tulip advised that the well is believed to be a significant oil discovery and the tests, continued until mid-August 2019, were assessing the size and value of the discovered pool. Planning for the development of the discovery had commenced. encountered an oil. Rhein Petroleum, the sole operator of the well, has commenced field development planning and is preparing an application for a mining plot. Background Information Rhein Petroleum was awarded the 326 sq km Graben-Neudorf permit 27 July 2011 (effective 1 August 2011). The tract had a three-year validity term, until 31 July 2014, and was extended thereafter until 31 May 2018. The well Steig 1 is located near the vintage Weingarten oil field, producing oil since mid-1930 until 1964.

Steig 1 (Rhein Petroleum 100%) in Graben Neudorf block, NE of Karlsruhe, reportedly significant oil find, compl. oil after testing, 4000 bo produced from a 150m column, target Pechelbronn beds at 900m. Appraisal is planned prior to devt, mining plot required. The discovered pool holds in excess of 115 MMBbl oil in place.

BP Exploration & Production was awarded Green Canyon Block GC 584 (G36297) on 1 June 2018. The block, which was originally offered as part of OCS Lease Sale 250, lies 4km northwest of the Constellation oilfield. Constellation (formerly known as Hopkins) is a Pliocene discovery located in central Green Canyon. Production from Constellation will be tied-back to Anadarko's Constitution spar in ~1,524m of water. Recoverable reserves at Constellation are said to be an estimated 160 MMbo. First production is anticipated to occur during 2018. Following official award, BP Exploration & Production is now the operator and sole interest-holder (100% WI + Op) in GC 584.

BP Exploration & Production was awarded Green Canyon Block GC 584 (G36297) on 1 June 2018. The block, which was originally offered as part of OCS Lease Sale 250, lies 4km northwest of the Constellation oilfield. Constellation (formerly known as Hopkins) is a Pliocene discovery located in central Green Canyon. Production from Constellation will be tied-back to Anadarko's Constitution spar in ~1,524m of water. Recoverable reserves at Constellation are said to be an estimated 160 MMbo. First production is anticipated to occur during 2018. Following official award, BP Exploration & Production is now the operator and sole interest-holder (100% WI + Op) in GC 584.

On 25 February 2020, Maurel & Prom SA announced that it has abandoned the NFW Kama 1 with oil shows in the Kari permit. The well was drilled to TD of 2,701 m MD in the Neocomian Kissenda formation. The operator encountered several levels between 1,865 m MD and 2,701 m MD containing oil shows of 35° API. The oil-saturated sandstones were of so poor quality that Maurel & Prom did not even test the well. At least the well proved that a petroleum system is working in the Kissenda formation. Earlier Maurel & Prom informed in the first days of February 2020 that the drilling in the NFW Kama 1 was approaching the targets. The company spudded Kama 1 in late December 2019, with the rig "Caroil-7" mounted on a barge in the swamp area of the southern part of the permit. The main objectives of Kama 1 were the early-rift sandstones of the Kissenda formation of Neocomian age. Maurel & Prom discovered the Kissenda play a decade ago further north in Gabon within the Ezanga permit. On 23 October 2019, Maurel & Prom announced in its Q3 2019 results that all preparatory works for the drilling of Kama 1 have been completed. As of early August 2019, Maurel & Prom completed half of the access channel from the Nyanga river to the drilling area. Early 2019, Maurel & Prom communicated its plans to begin exploratory drilling within its Nyanga Mayombe and Kari exploration permits in late 2019: two commitment wells were planned, one in each contract. The company identified several prospects from the 2D seismic lines acquired in 2012 and 2014 and an FTG program acquired in 2018 in the northern part of Nyanga Mayombe permit. The Kari permit covers some 2,000 sq km primarily within the South Gabon Sub-basin (Gabon Coastal Basin). It adjoins Perenco’s producing Echira and Atora Centre areas and Assala Energy’s Producing Gamba-Ivinga-Totou areas to the west and the onshore Nyanga Mayombe permit (Maurel & Prom) to the south. The Kari permit contains the Moula sub-commercial gas field discovered by Shell in 1990. Background Information On 14 July 2004, Rockover Oil & Gas signed a Technical Evaluation Agreement (TEA) for the Kari block. According to the Gabonese legislation a TEA could be valid for 6-12 months. On 27 December 2004, Maurel & Prom announced that it had signed an agreement to acquire the Rockover Oil and Gas Ltd, including its Gabonese assets estimated at 27 MMbo (P+P reserves), for US$ 72 million. Maurel & Prom will hold 100% interests in the following permits: Kari, M'Bindji, Nyanga-Mayombe and Ofoubou-Ankani. On 4 October 2007, Maurel & Prom converted the TEA into a Production Sharing Contract (PSC). During 2009, Maurel & Prom asked to add the relinquished part of Etekamba to Kari. On 1 February 2017, Pertamina Internasional Eksplorasi dan Produksi (PIEP) settled an offer to acquire all of Maurel & Prom SA’s securities, hence Maurel & Prom Gabon. Maurel & Prom holds a 100% interest in the permit.

Kama 1 nfw. (Maurel & Prom 100%) in Kari block, swamp area, onshore South Gabon sub-basin, P&A, oil shows (35° API in poor-quality sst) at TMD=2701m (Kissenda Fm).

In August 2020, the Agencia Nacional de Hidrocarburos (ANH) published the status of Exploration and Production (E&P) contracts and Technical Exploration Agreements (TEAs) valid as of 30 June 2020, and indicated that the LLA 5 Block in the Llanos Basin, is now 100% owned and operated by Gran Tierra Energy (GTE). On 20 February 2019 Gran Tierra Energy (GTE) announced an agreement with Vetra Energia for 100% interest in the LLA-5 Block of the Llanos Basin. The acreage is contiguous with the GTE’s LLA 1, LLA 10 and LLA 70 blocks which represent a new core area for the company. This company deal will expand GTE’s Llanos Basin holdings that are located near the prolific Cano Limon production area and the Capachos Block. Vetra Energia was the 100% owner and operator of the 756.83 sq km LLA 5 Block since July 2010 when it was preliminary awarded during the Ronda Colombia 2010. The official award was granted in March 2011.

(Llanos-Barinas B.) LLA 5 block, the Agencia Nacional de Hidrocarburos (ANH) indicated that the LLA 5 Block is now 100% owned and operated by Gran Tierra Energy (GTE).

Eni has withdrawn from the offshore North Coast Marine Area 1 Block (NCMA 1) and Block 9 (part of the NCMA 1 unitised area), according to industry sources in mid-November 2018. It is not wholly understood if this deal is subject to government approval. Eni's departure leaves Shell as the main stakeholder. Eni's 17.31% interest gives the Royal Dutch supermajor's total WI of 80.5%. National Oil Company, Petrotrin holds the remaining 19.5%. As part of the state-mandated process to replace debt-laden Petrotrin, Heritage Petroleum is stated to replace Petrotrin as the new state E&P company once it is fully operational by 1 December 2018. Previously in May 2017, Shell had also acquired 17.31% WI from Centrica, in a transaction involving a number of blocks including NCMA 1, Block 9, Block 22 and NCMA 4. This deal involved Centrica's disposal of it's remaining gas assets in Trinidad and Tobago to Shell for US$ 36 million, Shell has been improving its strategic position in gas in Trinidad in recent years, through its purchase of BG in 2016, its stake in LNG plants in Trinidad, its purchase of remaining Centrica interest in 2017, acquisition of Chevron's offshore gas assets in late May 2017, and now capitalising on Eni's withdrawal from NCMA 1.The NCMA 1 Block, contains the Hibiscus, Poinsettia and Chaconia gas fields. The President of Venezuela, Nicolas Maduro, and the Prime Minister of Trinidad and Tobago (T&T), Keith Rowley signed a joint declaration on 25 August 2018, for the execution of the Dragon Field interconnection project. The delayed project will transport gas from the Dragon Field via a planned 30km subsea pipeline to Shell's Hibiscus platform in Trinidad and Tobago territorial water, before entering Trinidad's gas grid.

NCMA 1

Hitherto unreported, On 29 November 2019, exploration rights for the Deep Offshore West Orange Basin were awarded to Total. Total is understood to have signed a deal with Sezigyn (in May 2018) in which Total would take operatorship and an 80% interest in the block once exploration rights were awarded. Sezigyn was awarded a TCP for the block immediately after Shell relinquished it. The ultra-deepwater block, was held Shell until October 2016. It covers 37,400 sq km and lies in water ranging in depth between 500 m and 4,000 m. It is bound to the north by the maritime boundary with Namibia and to the east by two permits, Block 2C and Block 3B/4B. Total operates the block with an 80% interest, Sezigyn holds the remaining 20% stake. Exploration to date within the block: No wells have been drilled in the ultra-deepwater block however, In October 2015, Shell received approval for drilling within the area. The company identified a 900 sq km area towards the north western margin of the block in which the well would have been located (at the time Shell estimated a well would cost USD 150 and 200 million). In late February 2013, Shell completed major 3D seismic survey over the block. The survey was conducted by the “Polar Duchess” which towed eight-streamers, 8 km in length, 200 m apart giving a total area under tow of 11.2 sq km. The 7,900 sq km survey started in early November 2012.

Exploration rights for the Deep Offshore West Orange Basin were awarded to Total. Total is understood to have signed a deal with Sezigyn (in May 2018) in which Total would take operatorship and an 80% interest in the block once exploration rights were awarded. Sezigyn was awarded a TCP for the block immediately after Shell relinquished it. T

Sidetrack of Samurai-2 in SE part of Green Canyon block 432, deviated into 476, target Miocene oil zone penetrated in block 432, cleared to plug (results n/a) on 25 Oct ’18. Samurai-2 TD’d at 9,778m with 46m total oil pay. Deepwater Asgard DS. Murphy (op), partner BHP Billiton.

United States, not found

On 20 December 2017, the Federal Agency for Subsoil Use held an auction for the Khadytayakhskiy block in Yamalo-Nenets Autonomous Okrug (West Siberia). Rosneft-subsidiary Sibneftegaz won the contest with the offer of RUB 786.372 million (USD 13.3 million). The winner of the auction will obtain a 25-year E&P license with a seven-year exploratory stage. The Khadytayakhskiy block covers 1,036 sq km in the central part of the Nadym-Taz Basin and encompasses the Khadytayakhinskiy prospect with hydrocarbon resources estimated at 139 MMbbl of oil, 10,154 Bcf of gas and 245 MMbbl of condensate. Seismic coverage amounts to 1,266 km of 2D data. One exploratory well has been drilled in the area. Hydrocarbon resources (categories D1+D2) of the block are estimated at 91 MMbbl of oil, 1,610 Bcf of gas and 38 MMbbl of condensate. The starting price amounted to RUB 655.31 million (USD 11.1 million).  

Russia, not found

Skye Energy Ventures Pty Ltd, through its subsidiary company Skye Petroleum Pty Ltd, is offering a farm-in opportunity to exploration permit EP 497, located in the Peedamullah Shelf/Barrow Sub-basin, North Carnarvon Basin. Skye is likely offering a low-cost entry with no drill commitments and is seeking a partner to assist in Early Cretaceous oil play exploration. Commercial discoveries could potentially be developed alongside Skye Energy Venture operated oil assets located to the north in adjacent permits. The central area of the permit, within the Barrow Sub-basin, is covered by the Flinders 3D survey which was acquired by TGS in 2001. The survey extends north over the Cyrano, Chervil, Herald North and Pepper South oil discoveries which offer structural plays in the Upper Jurassic to Lower Cretaceous. The play extends to the 1993 Santa Cruz oil/gas discovery with EP 497. Santa Cruz 1 was drilled on vintage 2D seismic data and is not covered by the Flinders 3D seismic survey. Thus, the areal coverage of the structure is currently unknown. Low quality structure maps from the vintage data indicate that the well clipped a structure of around 50 sq km with the possibility of additional stratigraphic elements analogous to the Stag oil field. The well encountered a biodegraded gas cap with a 10 m oil leg below in the Birdrong Sandstone at a depth of around 430 m. Although the sandstone was found to be of poor quality at location, the permit could also offer prospectivity in the Mardie Greensand and Barrow Group, all of which overlain by the regional, and proven, Muderong Shale seal. In the nearby Herald North field, oil derived from pre-Jurassic calcareous source rocks appears to have migrated and filled the reservoir. The migration path is not clear. This oil is thought to have biodegraded in situ by the influx of meteoric waters. Two wells are also located within the permit area: Bricklanding 1 and Dill 1. Bricklanding 1 was designed to test the low side fault closure against the Flinders Fault in 2006. The well was plugged and abandoned with minor gas shows in the Calypso Formation. EP 497 is now in term three of a six year work programme after being awarded on 16 November 2017 to Carnarvon Petroleum. Skye Petroleum (previously Skye Alba) acquired 100% interest in July 2018. The permit offers an exploration upside to the oil and gas assets held by Skye in the adjacent permits. In the remaining three year work programme, commitment spend totals around AUD 6.9 million dollars through geochemical studies and 100 sq km of new 3D seismic data acquisition in the final term. In the first two years, it is thought that Carnarvon focused on building a well and seismic database of the block through data collection, mapping and geotechnical work. Across 11 discoveries and abandoned fields held by Skye Energy Ventures, recoverable resources totaled around 40 MMb oil and 90 Bcf gas. It is thought, that before further appraisal, development and advance production techniques, around 10-15 MMbo and 50 Bcf gas could remain. Skye is specifically targeting advanced oil recovery to maximise production from the existing assets. Infrastructure within the permits includes Chervil, South Pepper and Herald North pipelines and the Port Airlie Island terminal. EP 497 covers an area of 478 sq km and is 100% owned and operated by Skye Petroleum Pty Ltd. The company is seeking a farm-in partner to assist with the exploration work programme over the next three years, until the permit is scheduled to expire on, or be renewed by, 15 November 2023. Companies interested in pursuing this opportunity are to contact: Joseph Graham – Skye Energy Ventures CEO Phone: +61 (0) 417 592 555 E-mail: [email protected]

Skye Energy Ventures Pty Ltd, through its subsidiary company Skye Petroleum Pty Ltd, is offering a farm-in opportunity to exploration permit EP 497, located in the Peedamullah Shelf/Barrow Sub-basin, North Carnarvon Basin.

Committed well in Tuban block, East Java, P&A believed dry early Feb '20. PTD was 2,414m, targets Kujung + Tuban reef fm’s.

West Musi A-1 nfw. committed well in Tuban block, P&A believed dry, PTD was 2,414m, targets Kujung + Tuban reef fm’s.

In October 2017, the Government of South Sudan confirmed that it was offering 12 exploration blocks to international companies. The blocks are located in both Muglad and Melut basins, over remote as well as slightly explored areas. Offered Blocks       Block Name Basin Area (~sq km) Possible Reservoir Targets Block A1 Muglad/Melut 23,300 Cretaceous, Galhak and Melut Fms (Maastrichtian), Jimidi Fm (Miocene), Yabus Fm (Eocene) Block A2 Melut 18,400 Galhak and Melut Fms (Maastrichtian), Jimidi Fm (Miocene), Yabus Fm (Eocene) Block A3 Muglad 11,450 Cretaceous: Aradeiba, Bentiu and Zarqa Fms Block A4 (*) Muglad 3,000 Cretaceous: Aradeiba, Bentiu and Zarqa Fms Block A5 Muglad 4,200 Cretaceous: Aradeiba, Bentiu and Zarqa Fms Block A6 Muglad 4,000 Cretaceous: Aradeiba, Bentiu and Zarqa Fms Block B1 (*) Melut 44,200 Galhak and Melut Fms (Maastrichtian), Jimidi Fm (Miocene), Yabus Fm (Eocene) Block B2 (*) Muglad/Melut 47,700 Cretaceous: Aradeiba, Bentiu and Zarqa Fms Block E1 (*) Muglad 21,450 Cretaceous: Aradeiba, Bentiu and Zarqa Fms Block E2 (*) Muglad 22, 300 Cretaceous: Aradeiba, Bentiu and Zarqa Fms Block DC (*) Melut   Galhak and Melut Fms (Maastrichtian), Jimidi Fm (Miocene), Yabus Fm (Eocene) Block S7 Melut   Galhak and Melut Fms (Maastrichtian), Jimidi Fm (Miocene), Yabus Fm (Eocene)          (*) Blocks “under negotiation” according to Nilepet, (October 2017)   For more information contact to: Eng. Mohamed Lino Benjamin, Undersecretary, Ministry of Petroleum Phone: +211 956 666 935 / +211 912 366 661 Email:  [email protected] Mr.Steven Puoch Riek Deng, Executive Director, Office of the Minister, Ministry of Petroleum Phone: +211 950 800 039 / +211 922 555 344 Email: [email protected]    

South Sudan, not found

Europa Oil and Gas reported on 11 June 2020 that it was acquiring, subject to regulatory approval, 100% interest in Frontier Exploration Licence (FEL) 3/19 from DNO. The acquisition requires Europa to pay an upfront nominal fee and grant DNO a 5% Net Profits Interest for any future hydrocarbon production from accumulations within the licence. These include the Edge Prospect, with estimated un-risked prospective resources of 1.2 Tcfg. Prior to this transaction, the Department of Communications, Climate Action and Environment (DCCAE) had reported on 31 March 2020 that FEL 3/19 was held by CNOOC (80% + operator) and DNO (20%). Therefore, during Q2 2020 and prior to the deal with Europa, DNO acquired CNOOC's operated interest (the terms of which have not been reported). FEL 3/19 spans the Slyne and Erris sub-basins, 18 km east of the producing Corrib gas field and around 24 km east of Europa's drill-ready Inishkea prospect in FEL 4/19. The Edge prospect and leads such as Clayton, Downey, Lynott and McGowan were identified in the licence and reported by Faroe Petroleum in 2016. Edge was described by Faroe Petroleum as a Triassic Sherwood Sandstone reservoir, with a reported chance of success of around 15%. The Corrib reservoir consists of the same formation at 3,300 m depth, whereas the Edge prospect is reportedly much shallower. Europa intend to re-launch the farmout of FEL 3/19 alongside its FEL 4/19 (Inishkea) farmout which, due to the proximity to the Corrib field, provide infrastructure-led exploration opportunities. Following regulatory approval, FEL 3/19 will be wholly owned by Europa Oil and Gas (Holdings) plc.

Europa announces the conditional acquisition of FEL03/19, off NW Ireland, from DNO. The 956-sq km permit contains the 1.2 Tcf Edge prospect, adding onto Europa's other regional assets.

Nitherto-unreported, on 21 May '19 newcomer Tnf was awarded sole rights to PPL 624, 17,000 sq km undrilled in E. PNG, east of the Bismark Volcanic Arc. The contract runs 6 years:

Newcomer Tnf Holdings Ltd was awarded exploration licence PPL 624

Equinor used the “Transocean Spitsbergen” S/S to drill exploration well 16/5-7 on the Klaff prospect which was spudded 12 June 2019 (delayed from 2018). The well is located in PL 502, immediately southwest of Johan Sverdrup. It had objectives in the Jurassic, Triassic and Permian and partner Aker BP reported prospective, pre-drill, resources of 50-372 MMboe. 16/5-7 was drilled to TD at 2,028 m in Basement and on 12 July 2019 it was abandoned. No reservoir intervals were encountered at any level, although oil shows were observed in the upper 19 m of the weathered and fractured Basement (possibly residual). The well is classified as a dry hole. The first phase of Johan Sverdrup is due onstream in November 2019. Development will concentrate on the Field Centre (in the north-west area of the field, PL 265) and will consist of four bridge-linked fixed platforms (WHP plus drilling, processing, riser/utility and accommodation) plus three subsea water injection templates. A total of 35 wells are planned for Phase I. The PDO for Phase II was submitted in August 2018 with a planned onstream date of Q4 2022. Phase II will include a new processing platform added to the Field Centre facilities, increasing processing capacity to 660,000 boe/d. There will be five subsea templates hosting 28 new wells and the establishment of the power-from-shore solution for the whole Utsira High area by 2022. In August 2018 recoverable reserves for Johan Sverdrup were increased to 2.2 - 3.2 Bboe. Equinor Energy AS operates PL 502 with a 44.44% interest. Petoro AS holds 33.33% and Aker BP ASA holds the remaining 22.22%.

016/05-07 (Klaff) nfw (Equinor 44,44% op, Petoro 33,33%, Aker BP 22,22%) in PL 502, SW of Johan Sverdrup, P&A, dry, intersected about 110m of basement rock. It noted that roughly 77m of this was weathered and fractured basement rock with poor to moderate reservoir properties. While the well did encounter traces of oil in a 19m zone in the upper part of the basement, it was impossible to determine whether the oil was producible or simply residual. Along with the basement rock, the well was also drilled to investigate potential reservoir rocks in several other levels including the Upper Jurassic intra Draupne formation sst, Upper Triassic Skagerrak Fm. and Upper Permian Zechstein group. TD=2028m.

Spirit Energy Norway, operator of production licence PL 780, is in the process of concluding the drilling of wildcat well 16/1-33 S. The well was drilled about 5 kms north of the Ivar Aasen field in the central part of the North Sea, and about 200 km west of Stavanger. The objective of the well was to prove petroleum in reservoir rocks in the Middle Jurassic (Sleipner Formation) and the Upper Triassic (Skagerrak Formation). The well encountered the Sleipner Formation with a thickness of about 205 meters, with 85 metres of aquiferous sandstone layers of moderate to very good reservoir quality. The Skagerrak Formation came in at a thickness of about 75 meters, with a total of 15 metres of aquiferous sandstone layers with moderate to good reservoir properties. The well is dry. The well was not formation-tested, but data acquisition was carried out. This is the first exploration well in production licence PL 780. The licence was awarded in APA 2014. Well 16/1-33 S was drilled to respective vertical and measured depths of 3042 and 3158 metres below sea level, and was terminated in the Skagerrak Formation in the Upper Triassic. Water depth at the site is 116 metres. The well will now be permanently plugged and abandoned. Well 16/1-33 S was drilled by the Leiv Eiriksson drilling facility, which will now proceed to drill wildcat well 6507/4-1 in production licence PL 1009 in the southern part of the Norwegian Sea, where ConocoPhillips Skandinavia is the operator. Original article link Source: NPD

(Viking Graben Province) 16/1-33 S (Sorvesten) nfw in PL 780 contract, operated by Spirit Energy (60%) and partner AKER BP (40%), is dry. The well encountered the Sleipner Formation with a thickness of about 205 meters, with 85 metres of aquiferous sandstone layers of moderate to very good reservoir quality. The Skagerrak Formation came in at a thickness of about 75 meters, with a total of 15 metres of aquiferous sandstone layers with moderate to good reservoir properties.

Saka Energi was officially awarded the West Yamdena block, located in onshore/offshore Tanimbar Islands, on 31 January 2018. The block was offered as part of the Conventional Oil and Gas Bidding First Round 2017 under the Direct Offer mechanism. The block will be operated under the new Gross Split fiscal terms. The base government/contractor split under Gross Split terms is 57%/43% for oil and 52%/48% for gas, subject to modifiers depending on the specific situation of the block. Signature bonus for the block was USD 500,000. The minimum exploration commitments for the first three-year exploration period include three G&G studies and 1,000 sq km of 3D seismic acquisition, for a total value of USD 2.1 million. The West Yamdena block covers an area of approximately 8,200 sq km. The block is located between the Tanimbar Island Basin and the Banda Forearc Basin, with a small extension into the Bonaparte Basin to the south. There is no well drilled to date in the West Yamdena block. South-west of the block is Inpex’s giant Abadi gas field which has proven hydrocarbons in Jurassic sandstones of the Plover Formation. The regional geology suggests primarily Mesozoic targets for this block. The Plover Formation (Lower-Middle Jurassic) has been proven as a major gas reservoir in Australian Northwest Shelf, in addition to the Abadi field. Other potential reservoirs in the block could be turbidite sandstones of the Maru (Triassic) and Ungar (Upper Jurassic-Lower Cretaceous) formations.

Indonesia (Calder Graben (Bonaparte B.)) Abadi

Pandion has agreed to acquire a 10% stake from Wintershall in the MOL-operated PL 820S / blocks 25/7 + 8, Balder field area in the NNS. Partners-to-be MOL (op), Lundin, Wintershall + Pandion. The deal will be effective 1 Jan ’18 subject to usual consents.

Pandion will acquire a 10% interest in PL 820S from Wintershall (->20%, MOL 40% op. Lundin 30%).

It is understood that Turkiye Petrolleri A.O. (TPAO) has completed the drilling activity in Alanya 1 deep water new field wildcat (NFW) well in the Block 4319 offshore licence (Antalya Basin) in the Mediterranean Sea during early May 2019 and the Fatih drillship has been moved to a different block. The results are currently not available but it is understood that the well was drilled to a TD of around 5,500 m. It was drilling at 4,200 m depth during mid-February 2019. Alanya 1, located at 2,600m water depth, was spudded on 1 November 2018 using the Fatih drillship with a PTD of approximately 5,500 m. It is situated around 65km from the coastline and approximately 112km southeast from the city of Antalya. This was the company’s first well in the licence area and another exploration well, Finike 1, is planned in late 2019. TPAO had purchased the deep water drillship “Deepsea Metro 2” in 2016 which was later renamed to “Fatih”. TPAO completed an offshore 3D seismic acquisition programme in the Mediterranean Sea in 2017. The survey utilised TPAO’s “Barbaros Hayreddin Pasa” 3D seismic vessel. Block 4319, located at the eastern part of the Gulf of Antalya in the Mediterranean Sea, covers an area of 10,170 sq km with TPAO holding 100% equity. It was exclusively awarded to TPAO on 6 October 2007.    Background Information Polarcus Ltd finalised a long-term collaboration agreement with TPAO in early January 2013. The agreement included the sale of the “Polarcus Samur” (subsequently renamed “Barbaros Hayreddin Pasa”) 3D seismic vessel to TPAO and also included the provision by Polarcus of seismic acquisition and management services for the vessel over a three-year period. TPAO have used the vessel to acquire 3D seismic data in both the Black Sea and the Mediterranean Sea. The sale and delivery of the “Polarcus Samur” was completed on 11 February 2013 following the satisfactory conclusion of negotiations and the subsequent execution of contracts.

Turkiye Petrolleri A.O.(TPAO) completes drilling Alanya 1 deep water exploratory well in Block 4319 in Mediterranean Sea results n/a.

N-C part of CNH-R02-L01-A7.CS/2017 contract, A7.CS, Area 7 block, offshore Sureste Basin, WD 426m, P&A dry at TD 4,451m, Valaris 8505 SS. Eni (op), partners Capricorn + Citla. Target L. Miocene.

Ehecatl 1 expl. (Eni 45% op. Cairn 30%, Citla Egy. 25%) on Block 7 disappoints, P&A failed to find hc’s. WD=426 m TD=4451m, was looking to prove hc’s in the Lower Miocene.

AIM-listed Baron Oil has announced that the conditions precedent to the Option Agreement entered into with Corfe Energy to be assigned part of its rights to farm in to an interest held by Corallian Energy in UK North Sea Licence P2235 (UKCS Block 11/24b), which contains the Wick Prospect, have now been satisfied and Baron has committed to farm in to the licence. Baron will now enter into a fully-termed farmout agreement under which, subject to necessary regulatory consents, it will pay 20% of the costs of the Wick well (currently estimated at £840,000), plus £6,500 in back costs, to earn a 15% interest in the licence. Bill Colvin, Chairman of Baron commented: 'As noted when we announced the Option Agreement, the Wick Prospect offers a rare opportunity to drill a low cost and relatively low-risk well in the near term. Our share in the Prospect has significant potential at current oil prices for Baron shareholders and it provides the possibility of an early, low cost, development opportunity.  Success in this well will provide shareholders with a meaningful uplift in the asset value of the Company.' Original article link Source: Baron Oil

United Kingdom, not found

UKOG confirms it has accepted the award of licence P2366 / blocks 15/18d + 15/19b (Crown oil discovery), total 13.6 sq km near the Piper, MacCulloch and Dumbarton/Donan fiels in the NS. Discussions with potential farmin partners are now cleared to roll. The licence term starts 1 Oct ’18. www.uogplc.com.

United O&G (100%) has been awarded Licence P2366

On 27 January 2020, Rosneft announced that fully-owned subsidiary Orenburgneft discovered the Dolgovskoye Zapadnoye oil field in Orenburg (Volga-Urals), within the Buzulukskiy block. Recoverable reserves of the field are estimated at 7 MMt (51 MMbbl) of oil. Rosneft was awarded exploration and production license ORB03180NR for the Buzulukskiy block in 2005. The company identified the Dolgovskaya Zapadnaya structure through an 1,800 sq km 3D seismic survey acquired in the area. Rosneft plans to drill two appraisal wells at the field, 25 development wells and to use the infrastructures of the Bobrivskoye and Dolgovskoye fields to develop the field.

Rosneft has reported an oil discovery at the Buzulukskiy block in Russia's Orenburg region. The company's regional subsidiary Orenburgneft has confirmed recoverable reserves of more than 51 MMbo at the West Dolgovskoye field following the completion of exploration drilling.

On 16 July 2020, Hocol Petroleum, a 100% subsidiary of Ecopetrol, announced that the Merecumbe 1 new-field wildcat (NFW), in the SSJN 1 Block, in the Lower Magdalena Basin, found gas in Eocene conglomeratic sandstones and some limestone layers of the Chengue Formation. The NFW spudded on 5 November 2019, it was completed in December 2019 and reached a total vertical depth (TVD) of 7,235 ft (2,205 m). The well lies in the northern part of the SSJN 1 Block, about 14 km north of the Bullerengue gas discovery. The Agencia Nacional de Hidrocarburos (ANH) reported that the Merecumbe 1 produced 2.38 MMcfg in December 2019, 0.47 MMcfg in January 2020, and 35.11 MMcfg in March 2020. Lewis Energy is the operator of the 920.11 sq km SSJN 1 Block with 50% working interest and lone partner is Hocol with the remaining 50% since December 2009 when Hocol farmed in. The original 1,672.7 sq km SSJN 1 Block was officially awarded to Lewis Energy in December 2008, and in July 2019, 752.28 sq km were relinquished. Background Information On 5 May 2020, Hocol Petroleum, announced that the Bullerengue 3 shallower-pool wildcat (SPW) discovered gas in several sand intervals in a shallower reservoir than the Bullerengue 1 discovery, which produces from Eocene sandstones of the Chengue Formation. It is speculated that the Bullerengue 3 discovered gas in the Miocene-Oligocene sandstones of the Cienaga de Oro Formation. The company indicated that they are doing several production tests since 17 November 2019. The Bullerengue gas/condensate field was discovered in October 2015 by the Bullerengue 1 new-field wildcat (NFW). The NFW was drilled to a TD of 7,500 ft (2,286 m) where it tested 2.5 MMcfg/d and 50 barrels of condensate in an unreported reservoir. 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.

(Lower Magdalena b.), Merembé-1 nfw operated by LEWIS EN (50%), ECOPETROL (50%) in SSJN 1 block, drilled 5-27 Nov '19, gas discovery in the Eocene Chengue fm, tested during 1H '20, results n/a.

Hoang Long Joint Operating Co (HLJOC) has completed the appraisal well Te Giac Trang 15X (16-1-TGT-15X) at Te Giac Trang (White Rhinoceros) field in Block 16-1, Cuu Long Basin, around early April 2020. The well, spudded around mid January 2020, was drilled to a TD of 4,906 m using the Borr Drilling "Idun" J/U. It targeted the Lower Miocene Bach Ho clastic and Lower to Upper Oligocene 'D and E' sequence at H 1.2 fault block. The main reservoir intervals were fracked and completed as dual producers. Operations are expected to be completed in Q2 2020. Production performance test at the deeper Oligocene 'D and E' sequences to access its recovery factor and the commerciality of the new play for the field. Test result has not been released. An injector well, 16-1-TGT-H5-32I was drilled from H5-WHP by Borr Drilling "Idun" J/U between November and December 2019. It was completed as a producer well but will be converted to a water injector at later date. The last development drilling campaign at Te Giac Trang was in 2018 and it consisted of three wells (two infill and one re-entry), drilled using two separate rigs, “PV Drilling I” J/U (16-1-TGT-H1-16AP) and Japan Drilling’s “Hakuryu-11” J/U (16-1-TGT-H5-31P and 16-1-TGT-14XST3). All wells were completed and put on production. The Te Giac Trang field produced approximately 16,000 bo/d and 12 MMscf/d from 28 producers in 2019. The Te Giac Trang field was first discovered in 2003. First oil production from the field commenced on 22 August 2011. Block 16-1 is operated by Hoang Long Joint Operating Company (HLJOC). Interest in the block is held by PetroVietnam Exploration Production Corp (41%), PTTEP Hoang Long Co Ltd (28.5%), SOCO Vietnam Ltd (28.5%) and OPECO Vietnam Ltd (2%). Background Information As of end November 2019, a total of 53 wells were drilled in Te Giac Trang field: 1 new-field wildcat, 18 outpost wells, 28 producer wells and 1 injector wells. The 2018 development drilling campaign was carried out between late August 2018 and February 2019. The campaign consisted of three wells (two infill and one re-entry) drilled using two separate rigs, PV Drilling I” J/U (16-1-TGT-H1-16AP) and Japan Drilling’s “Hakuryu-11” J/U (16-1-TGT-H5 31P and 16-1-TGT-14XST3). All wells were completed and put on production. The 2016/2017 development drilling campaign was completed on or around 10 July 2017 with a total of five wells drilled (16-1-TGT-H4 27P, 16-1-TGT-H4 28P, 16-1-TGT-H5 29P, 16-1-TGT-H1 30P and 16-1-TGT 14X/XST1/XST2). 16-1-TGT-14X was initially planned for 2014/2015 drilling campaign but was postponed due to time limitation. The remaining four wells were completed as producer wells and have commenced production. The Te Giac Trang Full Development Plan (FFDP) was submitted to relevant authorities in Q4 2016 and was formally approved by the Government of Vietnam on 9 February 2017. The FFDP includes up to 18 additional wells and a new processing equipment (water handling) to be installed on the H1-WHP. The processing equipment is designed to handle 90,000 bo/d with specific handling capacity of up to 65,000 bw/d. The installation of new processing equipment was completed in mid Q4 2017. A three-wells appraisal campaign was plan for 2014/2015 drilling campaign. Due to limited time, only two wells were drilled 16-1-TGT 9X/ST1 and 16-1-TGT 12/ST1). The wells were drilled using the Ensco “Ensco 109” J/U (16-1-TGT 9X/ST1) and UMW “Naga 2” J/U (16-1-TGT 12/ST1) to appraise the Miocene and Oligocene sandstone C and D sequences in different fault blocks. 16-1-TGT 14X was carried forward to the next drilling campaign. The H5-WHP topside was loaded out on 10 July 2015 for installation. First production commenced on 10 August 2015. The development plan for the H5 fault block was approved on 20 September 2014. The jacket of H5-WHP was installed in early September, followed by the topside and associated pipelines in Q3 2015. Development drilling from H5-WHP commenced on 1 October 2014 in parallel with infill wells drilling from the H4-WHP. A total of 18 wells have been drilled in the field which includes development, infills, injectors and outpost well between 2013-2015. Following the discovery of 16-1-TGT-10X ST1 (2013), located in the southernmost of H5 fault block, HLJOC planned to install a new wellhead platform in the H5 fault block with production tied-in to the FPSO via H1-WHP (wellhead platform). Phase 2 development drilling commenced in early October 2011 with 5 wells drilled from H4-WHP and early July 2012 with 4 wells from H1-WHP. Production from H4 platform commenced on 6 July 2012. Production from the Te Giac Trang field commenced on 22 August 2011 from the H1 wellhead platform at an initial rate of 15,000 bo/d. The field was expected to plateau at 55,000 bo/d and 30 MMscfg/d from eight wells for the first phase of development. Crude oil is sent via a subsea pipeline to the “Armada TGT 1” FPSO and from there exported via tankers to local refineries. Gas is piped to the nearby Bach Ho facilities and then transported onshore for the domestic market through the existing pipeline system. The Phase 1 development drilling campaign (8 wells) in the field was completed in March 2011, with the successful completion of the TGT H1-8P well. All wells from the first phase of development drilling were suspended until commencement of Phase 1 production. The Field Development Plan (FDP) was approved in September 2009. The development plan comprised of a Floating, Production, Storage and Offloading vessel (FPSO), two well head platforms (H1 and H4 WHP) and a subsea pipeline system to transport hydrocarbons, gas export, gas lift and water for injection. The FPSO was scheduled for operation and deliver its 1st oil by June 2011, and was expected to store up to 1 million barrels of crude and process 45,000 bo/d. In 2006-2007, appraisal wells, 16-1-TGT 2X, 16-1-TGT 3X and 16-1-TGT 4X were drilled to aid the determination of the best location for the initial development and to assess the extent of the TGT Field and the flow patterns and recovery characteristics of the Lower Miocene Bach Ho formations from the different fault blocks. The remaining appraisal wells, 16-1-TGT 5X, 16-1-TGT 6X and 16-1-TGT 7X was suspended as oil and gas producers. The Te Giac Trang (TGT) field was discovered by HLJOC with 16-1-TGT 1X (Te Giac Trang / White Rhinoceros) (2005), which was spudded on 2 June 2005 using “Atwood Beacon" J/U and was drilled to TD 4,478m MD. The objective of the well was to investigate a subtle three-way dip closure Lower Bach Ho Formation play and an Oligocene D play and targeted a rollover anticline against a fault. The well has flowed 8,566 bo/d of 37 degrees API oil plus 4.86 MMcfg/d on a 80/64" choke, from the section 2,701-2,760m in the Lower Miocene Bach Ho Formation clastics. The deeper Oligocene interval was also tested having exhibited significant oil shows during drilling, but only non-commercial flows were achieved due to formation tightness In late April 2004, 462 sq km 3D and 82 km 2D tie lines in the survey were acquired using WesternGeco's "Emerald" S/V. 16-1-VV 1X (Voi Trang / Golden Elephant) wildcat was plugged and abandoned on or around 9 May 2003. The well, spudded on 29 March using the "Trident 12" J/U in 35m of water, was drilled to a TD of 3,755m and tested over a Basement interval. This flowed only approximately 10 bbls of oil however and the decision to abandon the well was taken. Oil shows were encountered in the Oligocene, over the sections 2,886-3,363m and 3,404-3,442m, but these were not tested. The well had a PTD of 3,745m to test the fractured Basement play. Vertical wildcat, 16-1-VT 1X (Voi Trang / White Elephant) (oil discovery) was spudded on 12 October 2002 using the "Trident 12" J/U and was drilled to a TD of 2,490m MD. The well was reported to have tested a maximum sustained rate of 3,500 b/d of 42 API oil from the open hole interval 2,086-2,490m, over both E-sequence Oligocene and Basement sections. The flows are believed however to have come mainly from the Oligocene section with up to 40% water cut. 16-1-VT 2X appraisal well was spudded in 2003. Partner Soco reported that the well was drilled to a TD of 2,530m, including a 268m section in Basement, but failed to encounter commercial quantities of oil. Oil shows were also observed in the Oligocene section (which was thought to have produced most of the flows in discovery well 16-1-VT 1X), but the section was not considered to be well enough developed in the appraisal. In 2002, the rightholding in Block 16-1 was revised with Amerada Hess exiting the country. The revised holdings in HJLOC are now PetroVietnam 41%, SOCO 28.5%, PTTEP 28.5% and Opeco 2% HLJOC’s first well, 16-1-NO 1X (Ngua O / Black Horse) wildcat, was spudded on 23 May 2002 using the "Trident 12" J/U, was drilled to a TD of 3,684m including approximately 520m of Basement section. Shows were encountered in the overlying Miocene sandstone objective, but the reservoir characteristics of the interval precluded testing. A single DST was undertaken in the multiply-fractured Basement section over the interval 3,174-3,563m, flowing 250 bo/d during an 18 hour testing interval. The acquisition of a 640 sq km 3D seismic survey over the BaVi prospect was completed in early October 2000. The survey commenced on 24 July 2000 using Geco Prakla as seismic contractor. The survey was being carried out jointly with adjoining Conoco Block 16-2 under a joint acquisition programme between HLJOC and Conoco using the seismic vessel “Geco Resolution”. About 3,400 km of 1978 and 1984 vintage seismic was also being reprocessed. In 1997, Block 16 was split into Blocks 16-1 and 16-2. 16-BV 1X (Ba Vi 1X), the first well, then Block 16 was drilled by Vietsovpetro in June 1981. The well, located 85km south-east of Vung Tau in 50m water depth was plugged and abandoned as an oil discovery at a TD of 3,463m after having tested 400 bo/d in the Lower Miocene Bach Ho Sandstone Member at a depth between 2,593m and 2,638m. Another test in the Upper Oligocene Tra Tan Formation flowed 120 bo/d. The granite basement was reached at 3,364m with 66m penetrated. Tests in Paleogene and Miocene yielded water with oil and gas shows.

Hoang Long Joint Operating Co (HLJOC) Block 16-1: Te Giac Trang 15X, completed Results Unknown

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

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

ENEVA SA was drilling with gas shows the 4-ENV-SWPGN1-MA (4-ENV-006-MA) new-pool wildcat (NPW) in the PN-T-048 block during mid-August 2019. The operator filed a gas show report for the well with the ANP on 9 August 2019. The NPW was spudded on 21 July 2019.     The NPW has a proposed total depth (PTD) of 2,215 m. The Devonian Cabecas Formation and the Mississippian Poti Formation are the primary targets.      The NPW is located in the north-central area of the block approximately 4.4 km south south-west of the 1-PGN-FAZTIANGUAR-MA (1-PGN-001-MA) new-field wildcat (NFW) suspended with gas shows in April 2014. ENEVA SA has 100% working interest in the BT-PN-004 contract, PN-T-048 block. On 11 July 2019, the ANP approved a 4th modification to the discovery evaluation plan (PAD), modified from the 3rd modification on 19 June 2019, for the discovery evaluation plan (PAD) for the 1-PGN-FAZTIANGUAR-MA (1-PGN-001-MA) new-field wildcat gas discovery of the Eneva operated BT-PN-004 contract, PN-T-048 block.  The ANP granted the operator an extension from 25 June 2019 to 4 September 2019 to drill a contingent well and stimulate the zone contingent on results or relinquish the PAD.  If all commitments are completed, then the final expiry date will be 4 November 2019 extended from 4 October 2019.   In mid-March 2019, ENEVA SA made a part relinquishment of the remaining valid exploration area of the BT-PN-004 contract, PN-T-048 block retroactive to 14 November 2018.   The BT-PN-004 contract covered a total area of 1,455.2 sq km in two separate blocks, Block 1 of 1,057.18 sq km and Block 2 of 398.02 sq km.    PGN relinquished all of the 398.02 sq km BT-PN-004 contract, Block 2 associated with the 1-OGX-FAZENDAHAVANA-MA (1-OGX-115-MA) gas discovery completed in 2013 but apparently non-commercial after plugging the 4-PGN-FAZHAVANA-002D-MA (4-PGN-026D-MA) new-pool wildcat (NPW) in early-August 2018.    The remaining valid exploration area includes the entire 1,057.18 sq km Block 1 associated with the 1-PGN-FAZTIANGUAR-MA (1-PGN-001-MA) new-field wildcat gas discovery from April 2014.  That discovery is yet to be appraised. On 24 May 2018, the ANP approved a 2nd modification to the discovery evaluation plan (PAD) for two evaluation areas of the Parnaiba Gas Natural (PGN) operated BT-PN-004 contract, PN-T-048 block.  The ANP granted the operator an extension from 10 July 2018 to 25 June 2019 to drill a contingent well or relinquish the PAD.  If all contingent commitments are completed, then the final expiry date will be 4 October 2019 extended from 29 November 2018.  PGN is the operator of the contract with a 100% working interest. On 9 December 2016, the ANP approved a modification to the Parnaiba Gas Natural (PGN) operated BT-PN-004 contract, PN-T-048 block.   On 10 September 2014, the ANP approved the discovery evaluation plan (PAD) for two evaluation areas of the Parnaiba Gas Natural (PGN) operated BT-PN-004 contract, PN-T-048 block.   On 9 April 2014, PGN suspended with gas shows 1-PGN-FAZTIANGUAR-MA (1-PGN-001-MA) new-field wildcat (NFW) at a final total depth (TD) of 2,545 m.   Parnaiba Gas Natural (PGN) filed a second gas show report with the ANP on 8 April 2014 after filing the first show report on 26 March 2014 for the well drilled in the PN-T-048 block.   The NFW was spudded on 10 March 2014 within the BT-PN-004 contract, PN-T-048 block. The well had a proposed total depth (PTD) of 2,188 m with the Devonian Cabecas Formation as the primary objective and the Mississippian Poti Formation as a secondary objective. PGN utilized the BCH Energy 5 land rig to drill the well, located in the northwestern area of the block about 39 km west-southwest of the nearest well, the 1-OGX-FAZENDAHAVANA-MA (1-OGX-115-MA) suspended with gas shows in August 2013. This was the first well drilled by the operator where the ANP is utilizing the new company name, or acronym PGN, for Parnaiba Gas Natural.

Brazil, BT-PN-004

E-C part of AE-0073-M-Puchut-01 block, onshore Tampico-Misantla Basin in Puebla, horiz well from Llano Lindo-1 drillpad, compl o&g at TMD 4,940m (3,269m TVD) in mid-May ’19, tested ab. 800 bo/d. Target Pimienta fm.

Kaneni 1 unconventional well (Pemex 100%) in E-C part of AE-0073-M-Puchut-01 block, onshore horiz well from Llano Lindo-1 drillpad, compl o&g at TMD=4940m (3269m TVD) in mid-May ’19, tested ab. 800 bo/d. Target Pimienta fm.

January 2020 gas well in S. part of ATP-2021-P, Surat Basin, TMD 3,217m, gas in the main target Patchawarra, Tirrawarra + Nappameri, shows in the Toolachee (gas) and Birkhead + Westbourne (oil), 6-stage frac job starting 12 Jul '20 in the Patchawarra + Tirrawarra sst, testing to follow. Vintage (op), partners Metgasco (carried) + Bridgeport.

Australia (Eromanga B.) Vali 1ST1 op. by VINTAGE EN (50%), BRIDGEPORT (25%), METGASCO (25%) in ATP 2021-P block, TD = 3217 m, gas in the main target Patchawarra, Tirrawarra + Nappameri, shows in the Toolachee (gas) and Birkhead + Westbourne (oil), 6-stage frac job starting 12 Jul '20 in the Patchawarra + Tirrawarra sst, testing to follow. Vintage (op), partners Metgasco (carried) + Bridgeport.

On 6 February 2019, the ANP officially approved of Neptune Energy Brasil Participacoes Ltda divesting its 35% non-operated working interest to Oak Petroleo e Gas SA in the Reconcavo Basin REC-T-057 block awarded through the ANP Round 13.  Alvopetro is the operator of the contract with a 65% working interest and Oak Petroleo e Gas holds a 35% working interest.

Neptune Energy Brasil Participacoes divesting its 35% non-operated working interest to Oak Petroleo e Gas (Alvopetro op.65%) in the REC-T-057 block.

On 13 January 2019, the National Oil and Gas Authority (NOGA) and Eni SpA signed a Memorandum of Understanding (MoU) enabling the detailed study and potential future pursuit of petroleum exploration within the extensive 2,800 sq km offshore Block 1 concession. It is an area located in the territorial waters of Bahrain with depths up to 70m that both parties believe remains largely unexplored. The MoU was signed in Manama by Oil Minister and NOGA Chairman H.E. Sheikh Mohammed bin Khalifa bin Ahmed Al Khalifa and Eni CEO Claudio Descalzi. In clarifying the intent of the agreement, Sheikh Mohammed stated that “This strategic partnership with Eni is a major step towards utilizing the Kingdom’s offshore natural resources. With this signing, we aim to hold various discussions to review all relevant aspects of the technical and commercial terms of the potential exploration and development within a reduced timeframe”. Claudio Descalzi confirmed that “We are delighted with the signing of this agreement and the opportunity to explore the potential of Block 1. This MoU and the exploration in Block 1 will allow Eni to start cooperating and investing in a country that was one of the first in the Gulf to produce oil and which now aims at unveiling its offshore potential. Entering in Bahrain will enable our company to expand its presence in a key region of the Middle East, in line with our strategy aimed at diversifying our exploration portfolio across basins with liquid hydrocarbon potential while keeping high quality stakes throughout the exploration phase”. ChevronTexaco had been the last company to hold an operating interest in Block 1. Its broad ranging EPSA had been awarded to Chevron (operator, 100% interest) by the Ministry of Oil and Industry on 24 February 1998 but the merged company relinquished its EPSA for offshore Blocks 1, 2 and 3 at the end of the agreement's first exploration period in February 2002. Thailand's PTT Exploration and Production Public Company Limited (PTTEP) signed a one-year Technical Evaluation Agreement (TEA) for the offshore Block 1 and Block 2 in May 2005, but it was cancelled in 2006 following the establishment of NOGA. The acreage was subsequently incorporated into acreage allocated to a Bid Round announced in March 2007. It is understood that PTTEP had intended to sign an EPSA for the acreage during 2H 2006 and has established a local subsidiary for that purpose. Block 1, which lies to the north-east of Bahrain Island, has been explored unsuccessfully by several additional companies including Harken Energy, Kufpec, Superior Oil and Union Texas.

Bahrain, not found

SONAHYDROC has farmed out part of its 58% in the Yema and Matamba-Makanzi licences (total 400 sq km in the onshore L. Congo Basin) to Société de Génie et d’Exploitation Minière et Petrolière (SOGEMIP) and Log Sàrl. Presidential approval is required for the move to proceed after which partners will be SONAHYDROC (op,  25%), Surestream (35%), SOGEMIP (20%), Log 20%.

Democratic Republic of Congo, Matamba-Makanzi

According to reports in late-November 2017, Oilstone Energia has signed an agreement to purchase the Cerro Bandera exploitation concession situated in the Neuquen Province from state company YPF for USD 14 million. The 249.70 sq km Cerro Bandera block is located on the Huincul Uplift area of the Neuquen Basin. Once the agreement is approved by the Neuquen Province government, YPF will assign 100% of the concession to Oilstone, who has been operating the block since May 2011 under a service contract for the state company. However, YPF will maintain its rights in the Vaca Muerta and Los Molles formations, as well as an option to perform exploration project in the northern region of the block. Expected completion date is 22 May 2018.

Argentina (Neuquen B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: Cerro Bandera op. by OILSTONE E (0.0%, YPF 100.0%) to be check.

Further to the cash-bid offer concluded last week (see DEA 7 Feb ’19), Beach Energy came out on top in the auction for V18-3 in the Otway Basin with a AUD 4 million bid. The block encompasses the 180-Bcf La Bella discovery. Beach has until 21 Feb ’19 to accept the award.

Beach confirmed it had successfully bid US$2,8 MM for Block V18-3, which contains the La Bella discovery.

Delek Drilling has exercised an option under which it will acquire a 24.99% stake from Ratio in the latter’s Royee (399) offshore block, 399 sq km in the Levantine Basin. The Royee contract has been extended to Apr ‘20 provided that explo drilling starts by 30 Sep ’19 – the Ensco DS-7 is believed to be lined-up. Following necessary approvals, partnership to be Ratio (op), partners Delek, Edison Intl + Israel Opportunity O&G.

Israel, Royee (399)

Further to DEA 28 Dec ’18, the Ministry of Energy and Mineral Resources (MEMR) has officially signed 3 Gross Split contracts with the winners of the 3rd Conventional O&G Round 2018. Mubadala-owned PearlOil was awarded South Andaman, a consortium of Repsol and Mitsui received South Sakakemang, while state company Pertamina was awarded the Maratua block. Commitments include G&G studies and 3D surveys. Total signature bonuses USD 6 million, work commitments USD 10.95 million. More from GEPS.

The Ministry of Energy and Mineral Resources (MEMR) has officially signed 3 Gross Split contracts with the winners of the 3rd Conventional O&G Round 2018. Mubadala-owned PearlOil was awarded South Andaman, a consortium of Repsol and Mitsui received South Sakakemang, while state company Pertamina was awarded the Maratua block. Commitments include G&G studies and 3D surveys. Total signature bonuses USD 6 million, work commitments USD 10.95 million.

DEA has signed an agreement to acquire Sierra O&G, holder of 6 blocks totalling ab. 9,400 sq km in the Sureste Basin, including a 40% stake in the Talos-operated Zama discovery in block 7, currently being appraised. The deal will bring DEA’s block inventory to 11 (1 onshore), map below: DEA. Deal completion is pending usual official clearances.

Mexico, not found

According to local reports in May 2018, the subsidiary company of CAPSA, Capex, has completed the Agua del Cajon 1034 outpost well with gas in March 2018 after it tested 2.49 MMscf/d and 50.3 bc/d between the interval of 2,374 to 2,422 m (7,787 to 7,946 ft) in the tight reservoir of Lower Bajocian to Upper Callovian Lajas Formation. The well is situated on the company’s 100%-held Agua del Cajon block, with total depth (TD) of 2,500 m (8,202 ft) reached in February 2018 after it was spudded in late-January 2018. Agua del Cajon block covers 353 sq km of land in the Huincul Uplift area of the Neuquen Basin. The outpost well was drilled to appraise the Agua del Cajon field which has produced over 21 Bscfg and 8 MMbo since 1971, predominantly from the Lotena Formation sandstone. The field also produces from several unconventional reservoirs including Vaca Muerta and Quintuco shales and tight reservoirs of Los Molles and Lajas formations. The Neuquen Province government granted a 35 year concession for unconventional hydrocarbons in the block to Capex in April 2017. The company reportedly plans to invest over USD 126 million in conducting a pilot project targeting gas from the Vaca Muerta Formation shale through 2021. The pilot project will include the drilling of 35 wells over four years, which can expand to 240 wells with total investment of over USD 1.5 billion, if results are positive. Background Information Capex has been the 100% operator on the Agua del Cajon block since January 1991, with the producing Agua del Cajon field on improved recovery since early-1999.

According to local reports in May 2018, the subsidiary company of CAPSA, Capex, has completed the Agua del Cajon 1034 outpost well with gas in March 2018 after it tested 2.49 MMscf/d and 50.3 bc/d between the interval of 2,374 to 2,422 m (7,787 to 7,946 ft) in the tight reservoir of Lower Bajocian to Upper Callovian Lajas Formation.

NW part of AE-0110-Cinturón Plegado Perdido-09 block, DW GoM Basin, WD 3,015m, P&A mid-Mar ’19, results n/a, La Muralla IV SS. PTD was 6,200m, target Wilcox.

Nobilis-1DEL appr NW part of AE-0110-Cinturón Plegado Perdido-09 block, DW GoM Basin, WD 3,015m, P&A mid-Mar ’19, results n/a, PTD was 6,200m, target Wilcox.

NW Shanwan Sag of the Junggar Basin, in April tested 847 Mcfg/d from 5,490-5,589m in the Permian Fencheng fm. Shatan-1 (2018) tested 190 bo/d from the Permian Wuerhe fm + oil shows in the Triassic Baikouquan + Karamay fm's.

China (Junggar B.) Shatan (Ju) 1 op. by PETROCHINA (100%) in Shamenzi block, total depth 5566 m tested 847 Mcfg/d from 5,490-5,589m in the Permian Fencheng fm. Shatan-1 (2018) tested 190 bo/d from the Permian Wuerhe fm + oil shows in the Triassic Baikouquan + Karamay fm's.

OMV New Zealand Ltd, a wholly owned subsidiary of OMV AG, spudded the Toutouwai 1 exploration well in PEP 60093, located in the Taranaki Basin, on 8 March 2020. The well was drilled by the COSL Drilling Europe AS owned "COSL Prospector" rig which was released from the well location on 13 April 2020. The Petroleum Exploration and Production Association of New Zealand (PEPANZ) reported on 14 April 2020 that preliminary results indicate the well successfully encountered oil and gas. The implications of coronavirus disease 2019 (COVID-19) and restrictions imposed by New Zealand's transition to "Alert Level 4" have limited the testing phase, with the well subsequently plugged and abandoned following positive indications from multiple intervals. With reference to Toutouwai 1, John Carnegie, PEPANZ CE, stated "the potential benefits to Taranaki and all New Zealand are substantial" and that the find could "help New Zealand's long-term energy security" Toutouwai 1 is the first discovery to be made in New Zealand since 2014 and had pre-drill estimated recoverable resources of 90 MMboe. The well was drilled in a water depth of 131 m and had a target depth of 4,361 m, with the last casing point at 1,520 m. Targets included the Cretaceous North Cape Formation and Paleogene sandstones. The contingent well was the third of a multi-well exploration campaign being undertaken by OMV in the Taranaki and Great South basins. The "COSL Prospector" rig was contracted to undertake the campaign and arrived at the Toutouwai location in early March 2020 after drilling the unsuccessful Tawhaki 1 well in the Great South Basin. The Maui 8 new-pool wildcat (PML 381012, Taranaki Basin) was due to follow Toutouwai 1 in Q2 2020, however the implications of coronavirus disease 2019 (COVID-19) mean the programme is now indefinitely suspended. On 3 March 2020, climate activists boarded the COSL Prospector rig as it was moving to the Toutouwai 1 location. It is not clear if this resulted in a delay to the spud date. PEP 60093 covers an area of 2,137 sq km was awarded on 16 December 2015. Interests in the permit are OMV New Zealand Ltd (40% plus operatorship), SapuraOMV Upstream (NZ) Sdn Bhd Ltd (30%) and Mitsui E&P Australia Pty Ltd (30%).

Toutouwai 1 nfw. (OMV % op, Mitsui E&P, Sapura Energy ) in PEP 60093, offshore block, several hydrocarbon-charged layers encountered while drilling, well now assumed P&A but considered a discovery, Target North Cape fm + Paleogene sst. WD=131m, TD=4317m.

In late 2018, Burrulus Gas Co. (Burrulus) completed the exploratory well Swan East 1 in the WDDM Area 2 development lease, offshore Nile Coastal/Deep Water Sub-basin as a gas discovery in the Messinian layer. Burrulus Gas Co. is a JV between EGPC and Shell and Petronas. Background Information Swan 1ST1 exploratory well in the WDDM Block, offshore Nile Coastal/Deep Water Sub-basin was completed in October 2011 as a gas discovery. The original hole, Swan 1, was spudded on 1 August 2011 with objectives in Kafr El Sheikh Formation and particularly to cross a paleo-channel sand. The well was drilled to a TD of 3,350m (3,280m TVD) before being suspended. Then the hole was sidetracked from a KOP of 2,440 m and drilled to TD at 3,283m (3,256m TVD). The second sidetracked Swan ST2 development well was completed in March 2012 as a gas well. The West Delta Deep Marine (WDDM) concession comprises 8 producing gas fields: Scarab, Saffron, Simian (including Swan and satellite SimSat-P2), Sienna, Sapphire (including satellites Sapsat-1, Sapsat-2), Serpent, Saurus, Sequoia. A total of 5 fields are thought to be developed later: Mina, Silva, Sienna Up, Solar, Sama Offshore. The fields are located at water depths ranging from 250 -1,200 m (800 - 3900 ft) and approximately 90 km to 120km from the shore and are thought to contain reserves in the amount of 4 Tcf.

Egypt, Mina (Dev)

In May 2020 Island Gas (subsidiary of IGas Energy Plc) acquired Total E&P UK Ltd's 20% interest in three onshore licences PEDL 273 (194 sq km), PEDL 305 (142 sq km) and PEDL 316 (111 sq km). IGas is the operator of the three licences that cover a total area of 447 sq km across blocks: SE/41e, SE/31c, SK/49, SK/59b, SK/87c SK/88b and SK/89e. Total hold no further interest in the licences and the deal marks Total's exit from the UK onshore. All three licences are located in the East Midlands and Yorkshire. IGas is already operator of the three licences, therefore the deal has increased its interest from 35% to 55%. In 2017 Total started to reduce its stake in the three licences when INEOS acquired 30% interest from Total. Interest in the three licences PEDL 273, PEDL 305 and PEDL 316 is held by IGas subsidiary Island Gas Ltd (55% + operator), INEOS Upstream Ltd (30%) and Egdon Resources UK Ltd (15%).

Total (20%) has exited onshore licences PEDL273, PEDL305 and PEDL316, with its 20% stake assigned to operator IGas,

South Pacific (PNG) Investments Ltd (SPI), an Inergy International Co Ltd subsidiary company, is seeking to farm-down interest in exploration licence PPL 565, located in the Gulf of Papua within the Fly Platform. Farm-in terms remain negotiable with the company looking to retain around 20% non-operated interest.  It is likely that farm-in agreements will include minimal back payments for work already completed in the licence area by SPI but could include submissions to alter the committed work programme. SPI was awarded PPL 565, with 100% interest, in 2015 for a period of six years. PPL 565 stretches from the west Pasca field area to the Pandora field over an area of 3,970 sq km. Both the Pasca and Pandora fields contain Miocene reefal carbonate plays and reservoir potential occurs in Late Jurassic, Early and Late Cretaceous sandstones through a series of titled fault blocks, draped anticlines, carbonate pinnacles and reefs and possible turbidite fan deposits. Nearby liquids and gas sources are proven by the neighbouring discoveries, but subsurface risks remain in understanding migration pathways and the presence of suitable traps. To minimise exploration risk, SPI plans to conduct seismic reprocessing of select 2D lines to tie in 3D data with control points at the Pasca field to the Solwara 3D survey data to the west and data control points within PPL 578 including the Goaribari 1 well. Two reservoir horizons are of interest to SPI – an Eocene basal sand and Mid Jurassic submarine fan sands, possibly derived from erosion of the Pasca Ridge. Pasca A field was discovered in 1968. A significant blowout at Pasca A3 well in 1983 put developments in doubt. However, Twinza took over operatorship in 2013 and began reviewing the potential of remaining hydrocarbons. A two-phase development programme has been submitted by Twinza to the government for consideration to produce LPG, condensate and gas. Phase I would consist of the initial production of natural gas liquids, including condensate and LPG with reinjection of dry gas, ahead of Phase II. Phase II would see the dry gas exported. Pandora was discovered in 1998 and holds estimate reserves of 900 Bcf. Gas production could support the Pasca Phase II development or work as a standalone project. PPL 565, which covers an area of 3,970 sq km, was awarded on 24 December 2015 and is scheduled to expire or be renewed by 23 December 2021. The initial two-year work programme includes geological and geophysical reviews of existing data, maturing into 2D seismic acquisition by December 2019. The first exploration well is also scheduled by December 2019 but could be subject to a work programme variation upon review of data by SPI. South Pacific (PNG) Investments Ltd is looking to farm-down interest in its 100% owned and operated exploration licence PPL 565, which is located in the offshore Fly Platform.

Guinea South Pacific (PNG) Investments Ltd looking to farm-down interest in PPL 565, offshore Fly Platform

In early March 2019, Qarun Petroleum Co (Qarun) completed the Bolt 113-1 exploration well in the East Bahariya Ext.III (Bolt) concession, Abu Ghardiq basin as an oil well. The well was spudded on 11 February 2019 using the “EDC-47” land rig and drilled to a TD of 3,353m in the Albian part of the Kharita Member. It has a planned TD of 3,277 m and the Uper Cenomanian Bahariya formation as the primary objective and the Lower Cenomanian Kharita Member as the secondary objective. Qarun Petroleum Co is a JV between the EGPC, Apache Oil Egypt, Dana Petroleum and Sinopec IP Corp. Background Information Qarun was awarded the East Bahariya Ext.III (Bolt) concession in the Abu Ghardiq Basin, Western Desert in August 2018.

Qarun Petroleum Co completed the Bolt 113-1 exploration well in the East Bahariya Ext.III (Bolt) concession,

Latif 2669- EL, Lower Indus onshore, TD 3,613m, MDT yielded 28.6 MMcfg/d, WHP 3,116 psi, from the Lower Goru, SLR-215 rig. UE (op), partners Eni + PPL.

Pakistan (Indus B.) Latif

BP + Eni signed an LoI leading to the latter acquiring 42.5% and operatorship from BP in the 29,956-sq km Sirte Offshore Area C permit (Areas 37, 38 + 39), Gulf of Sirte, the 17,612-sq km Ghadames North (Area A) as well as the 5,700-sq km Ghadames South (Area B) permits, Ghadames Basin. Exploration, suspended since 2014, is hoped to resume in 2019. Partnership to become Eni (op) 42.5%, BP 42.5%, Libyan Investment Authority 15%.

Libya, Area C

On 15 May 2018 Union Jack Oil Plc announced that it, along its partner Humber Oil and Gas, had each agreed to acquire a 16.25% interest in PEDL 201 and a 12.5% interest in PEDL 181 from Celtique Energie for a payment of GBP 7,500 for each consideration. The companies are investigating the potential for shale gas in the acreage. The deals received regulatory approval in July 2018. PEDL 201 is located on the edge of the Widmerpool trough sub-basin within the onshore section of the Anglo-Dutch basin within the counties of Nottinghamshire and Leicestershire In October 2014 Egdon spudded an exploration well in the licence targeting the Burton-on-the-Wolds prospect. The well had a planned vertical depth of 1,000 m and was designed to intersect two Carboniferous targets. Egdon announced that the well had reached a TD of 1,086 m and had intersected thin sands in the primary target of the Rempstone Sandstone Group while the reservoir rocks of the secondary deeper target were absent. Weak hydrocarbon shows were observed however interpretation of the log data showed the sands to be water bearing. In an update in November 2014 it was confirmed that the well had been abandoned. PEDL181 is located in East Lincolnshire. It was awarded to Europa in the 13th Onshore Licensing Round in 2008. In 2015 the company drilled the Kiln Lane-1 well. The well encountered the Westphalian and Namurian sand intervals which were water wet. Following completion of the deal interest in PEDL 201 is held by Egdon Resources U.K. Limited (45% + operator), Union Jack Oil Plc (26.25%), Humber Oil and Gas Limited (16.25%) and Terrain Energy Limited (12.5%) and interest in PEDL 181 is held by Europa Oil and Gas Limited (50% + operator), Egdon Resources U.K. Limited (25%), Union Jack Oli Plc (12.5%) and Humber Oil and Gas Limited (12.5%).

On 15 May 2018 Union Jack Oil Plc announced that it, along its partner Humber Oil and Gas, had each agreed to acquire a 16.25% interest in PEDL 201 and a 12.5% interest in PEDL 181 from Celtique Energie for a payment of GBP 7,500 for each consideration. T

On 1 July 2018, the government of La Pampa Province will have provincial company Pampetrol will take over the Medanito Sur block from its current operating group headed by Tecpetrol. After the transfer, the government will reportedly set up a data room before putting out the block for offer after the transfer. The Medanito Sur covers 106 sq km of land in the Northeast Platform area of Neuquen Basin. Tecpetrol has been the operator of the block after it completed the purchase of Americas Petrogas subsidiary, Americas Petrogas Argentina, in August 2015. The company holds 60%, with partner Raiser 20% and state company Integracion Energetica Argentina SA (previously known as ENARSA) with the remaining 20%. Background Information The Medanito Sur block was producing at approximately 442 bo/d and 230 Mscfg/d at the end of April 2018, with El Jabali as the largest field in the block. The field was discovered in 2008 and put on stream in 2010 before it was put on recovery in 2013 and 2014. It has produced a total of 1.8 MMbo and 2.8 Bscfg from the Tordillo Formation.

On 1 July 2018, the government of La Pampa Province will have provincial company Pampetrol will take over the Medanito Sur block from its current operating group headed by Tecpetrol.

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). The exchange concerning the two licences was complete on 23 June 2020. In the UK, Cairn operates through its wholly owned subsidiary - Nautical Petroleum. Shell has acquired a 50% interest in licence P2379 which contains the Diadem prospect, the licence has a firm well commitment that is expected to be drilled in 2022. In exchange for the P2379 interest, Cairn has acquired a 50% interest in licence P2380 from Shell. The P2380 licence has a firm well commitment well on the Jaws prospect, which is expected to be drilled in 2H 2021. The Jurassic Fulmar sandstone play is prolific in the area and if the wells are successful then they could be tied into the Nelson facilities. The commitment well for Jaws is required to be drilled to a depth of 3,730 m or the base of the Upper Jurassic. P2380 was awarded in the 30th Offshore licensing round which focussed on ‘mature’ areas of the North Sea and comprises of just one block – 22/12d. Any potential discoveries could be used to extend the field life at Nelson. Shell also picked up licence P2377 in the 30th Round which also contains a firm commitment well on a prospect known as Orlov and is within reach of a tie-back to Nelson. In September 2019 Zennor Petroleum and ONE-Dyas pulled out of licence P2379 leaving Cairn as the sole participant. The licence comprises of four blocks – 22/11b, 22/12b, 22/16b and 22/17c and contains three discoveries 22/11b-3 (Lima), 22/12a-10 (Phoenix) and 22/16-6 (Dalziel). The first of the three discoveries was 22/12a-10 (Phoenix) back in 2004. The discovery was made by Shell as a near field exploration project for the Nelson facilities. The discovery was appraised in 2010 with well 22/12a-12 which confirmed oil bearing sands within the Forties Sandstone Member within a relatively simple and low risk 4-way dip closed structure. A sidetrack of the appraisal well 22/12a-12Y was kicked-off and penetrated the reservoir outside of the structure and did not encounter any hydrocarbons. 22/11b-13 (Lima) was discovered in 2008. The well targeted three Jurassic pods. Of the three pods, only one (Fulmar 1) contained oil which is stratigraphically trapped within thin sandstones pinching out before the pod. The most recent discovery was 22/16-6 (Dalziel) in 2015. This was drilled by ENGIE targeting the Upper Jurassic Fulmar prospect. It encountered oil and tested in excess of 8,000 boe/d. Following completion of the deals interest in the licences will be held by 50% each between Cairn and Shell.

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).

On 23 July 2018, Shell reported that it was awarded two offshore blocks in Mauritania: C-10 and C-19. The acreage is located in shallow to deep waters of the MSGBC basin. Shell will operate the blocks with a 90% interest and state company Société Mauritanienne des Hydrocarbures et du Patrimoine Minier (SMHPM) will hold the remaining 10%. Once the awards are ratified by the government, Shell will open an office in Mauritania for its local subsidiary Shell Exploration and Production Mauritania who will start exploration activities. Block C-10 covers around 12,500 sq km it covers the area which was intensely explored by Woodside in the early 2 000’s. The company made the Chinguetti, Tiof, Tevet and Banda discoveries on the acreage. Later, the block was operated by Tullow who relinquished it in late 2017. The Chinguetti field which was last operated by Petronas ceased production in late 2017 and is currently being decommissioned. The new C-10 block, as awarded to Shell includes also the area relinquished in 2016 from block C-12 by Kosmos. Block C-19 covers around 12,175 sq km, it was previously operated by Chariot Oil who relinquished the acreage in mid-2016 before it could carry out planned drilling. Chariot had identified and matured to drilling stage four prospects in the south-west corner of the block. The block also contains two historical wells: Ras Al Baida A-1 with gas shows by Hispanoil in 1980 and Al Kinz 1A, dry, by Amoco in 1969. Under the current C-19 contract, Shell has agreed a back-in right for Chariot of between 10 and 20% subject to government approval.

Shell (90% op. SMHPM 10%) has signed up to explore 2 blocks C-10 and C-19. The blocks are located in WDs 20 – 2000m and cover a joint area of 23675km². C-10 is composed of former blocks C-10 (relinquished by Tullow in early 2018), C-28 and C-29. Chariot O&G relinquished C-19 in 2016 and has a back in right for a 10-20% working interest.

OMV confirmed on 14 January 2019 that the estimated recoverable volumes at Wisting in PL 537 have increased from 350 MMbo (reported in 2017) to 440 MMbo. The increase follows the results from the latest appraisal well, 7324/8-3, drilled in 2017 coupled with an increased understanding of the subsurface following the utilisation of Controlled Source Electro Magnetic (CSEM) with traditional seismic techniques. The company plans to develop the field using an FPSO with a subsea production system consisting of 34 wells in total (19 producers and 15 water injectors). The company is currently maturing two FPSO concepts – a circular and a ship-shaped hull. Final concept selection is expected in 2020. The Wisting Central discovery was made in 2013 by 7324/8-1 which proved a 50 - 60 m oil column in the Jurassic Realgrunnen Group. This was the first oil discovery in the Hoop area of the Barents Sea and confirmed a new play. Appraisal well 7324/8-3 was spudded on 16 August 2017. The well encountered a 55 m oil column in the Middle Jurassic to Upper Triassic Sto and Fruholmen formations. A water injection test was performed in the Sto Formation, indicating good water injection properties. Interest in PL 537 is divided between OMV (Norge) AS (25% + operator), Equinor Energy AS (35%), Idemitsu Petroleum Norge AS (20%) and Petoro AS (20%).

OMV (25% op, Equinor 35%, Petoro 20%, Idemitsu 20%) confirmed that the estimated recoverable volumes at Wisting in PL 537 have increased from 350 MMbo (reported in 2017) to 440 MMbo. The increase follows the results from the latest appraisal well, 7324/08-03, drilled in 2017 coupled with an increased understanding of the subsurface following the utilisation of Controlled Source Electro Magnetic (CSEM) with traditional seismic techniques.

PEMEX plugged and abandoned the Teca 1DEL outpost in the AE-0009 block in the Sureste Basin during late-September 2018.  The well reached a final total depth (TD) of 3,730 m.  The outpost was spudded on 14 July 2018.  This is the first outpost of the June 2016 Teca 1 oil and gas discovery. The outpost had a proposed total depth (PTD) of 3,710 m and the primary target was the Upper Miocene Formation. It is located approximately 3.1 km east south-east of the Teca 1 discovery well in a water depth of 43 m. The drilling cost estimate was reported to be USD 17.51 million at an exchange rate of 1USD = 18.5 MXN and the completion cost is USD 7.95 million. The Teca 1DEL had an estimated 73 MMboe reserves to incorporate into the field area. PEMEX suspended as an oil and gas discovery the Teca 1 new-field wildcat (NFW) in the AE-0009 block in the Sureste Basin on 3 June 2016.  The operator published information on 28 July 2016 with its 2nd quarter results that the NFW was a discovery.  The operator reported that the well tested 3,186 bo/d and 7.3 MMcfg/d from the Upper Miocene Formation and it estimates 3P reserves of 50-60 MMboe.  The CNH reported that the zone was perforated from 3,162 m to 3,170 m.  The NFW reached a final total depth (TD) of 3,569 m. The NFW was spudded on 11 March 2016.  The well had a proposed total depth (PTD) of 3,730 m.  The middle Pliocene formation was the primary objective and the Miocene Formation was a secondary objective. The “Fortius” J/U drilled the well in a water depth of 44 m.  The well is located in the northeastern area of the block. The nearest well is the Marbella 1 located in the same block about 8.9 km southwest. The trap is reported to be an east west trending salt induced anticlinal nose. The prospect size is reported to be 64 MMboe. The water depth is 44 m.  On 26 November 2015, the CNH approved plans by PEMEX to drill the Teca 1. SENER awarded the AE-0009-2M-Tucoo-Xaxamani-01 entitlement to Pemex 100% through Ronda 0 on 27 August 2014. The block covers an approximate area of 977.8 sq km.

Teca 1DEL (Pemex 100%) in AE-0009-Tucoo-Xaxamani-01 contract, P&A, results n/a. the primary target was the Upper Miocene Fm. TD=3730m.

Dráva 2 block, NE Croatia, Somogy-Dráva sub-basin, drilled 14-30 Nov '19, TMD 1,635m (1,598m TVD, Mesozoic), w.o. results, Nat 402 rig.

Jankovac 1 nfw. (INA 100%) in the Drava 2 permit in NE of the country, completed. The well was drilled to the final depth of TD=1635m in an undisclosed Mesozoic succession. The results of the well, have yet to be disclosed.

Umuseti East prospect, also appraisal to Umuseti field in Umuseti/Igbuku block, onshore Niger Delta, 3 hc intvs encountered (2 oil, 1 gas), compl. 28 Nov ‘17, Cardinal Drilling Services rig. Tests confirmed communication with the nearby Umuseti field. Pillar (op) 60%, well funding partner Newton Energy.

Nigeria (Niger Delta) Anagba 1 op. by PILLAR OIL (60.0%, NEWTON EN 40.0%) in Umuseti/Igbuku block

WD and NOC signed EPSAs for Area 91 (ex-concession 96) and 107 (ex-concession 97) onshore in the Sirte Basin. The EPSAs have already been ratified, allowing for immediate action. Through the conversions, Area 91 will run to 2036 and Area 107 to 2037 under a new joint optg co designated Sarir Oil Operations (NOC-WD 51:49).

WD and NOC signed EPSAs for Area 91 (ex-concession 96) and 107 (ex-concession 97) onshore in the Sirte Basin. The EPSAs have already been ratified, allowing for immediate action. Through the conversions, Area 91 will run to 2036 and Area 107 to 2037 under a new joint optg co designated Sarir Oil Operations (NOC-WD 51:49).

Tarba Energia will acquire the 100% interest held by Petroleum Oil & Gas Espana (POGESA) in the El Romeral-1, El Romeral-2 and El Romeral-3 production concessions located to the east of Sevilla in the Guadalquivir Basin. The deal, which was signed in December 2019 with an economic date starting in July 2019, will be effective upon approval of the license transfer by the authorities. The deal involved an initial consideration of EUR 750,000 (USD 837,000) plus further deferred considerations of EUR 250,00 (USD 279,000) for each of the next three wells to be drilled in the concessions. Warrego Energy, which currently holds 85% of Tarba Energia, funded the initial consideration and Prospex Oil and Gas – the other shareholder in Tarba Energia – acquired 49.9% in the project by funding Warrego Energy accordingly (through the issue of a second class of Tarba shares). The three blocks, covering a total area of 310 sq km, encompass five one-well Miocene gas fields out of which three - Ciervo 1, Santa Clara 1 and Sevilla 1- are currently in production and two - Rio Corbones 1 and Sevilla 3 - are shut-in with a low-cost workover potential. The gas is converted in electricity by an 8.1 MW power station owned the operator of the license. As per a 2019 independent reserves and resources assessment, the three producing fields hold remaining reserves of 0.3 Bcf. In addition to the five fields, the tracts cover two undeveloped discoveries with 2C contingent resources estimated at 5 Bcf and 13 nearfield prospects identified on 2D seismic and supported by AVO analysis with unrisked prospective resources (2U) estimated at 90 Bcf. The El Romeral contracts were awarded to group led by Repsol on 28 July 1994. After numerous interest change, Petroleum Oil & Gas Espana became the sole rightholder of the tract in December 2017. The contracts are valid until 2024 and can be renewed twice for a ten-year term. The ultimate expiry date is 28 July 2044. Subject to regulatory approval, Tarba Energia will hold a 100% interest in the El Romeral-1, El Romeral-2 and El Romeral-3 production concessions.

Tarba (owned by Warrego Egy + Prospex O&G) has agreed to acquire Petroleum Oil & Gas España's 100% in the El Romeral-1, -2 & -3 prod. leases totalling 310 sq km in Andalucía.

BP has announced two new exploration discoveries in the North Sea. The discoveries are Capercaillie, in Block 29/4e in the Central North Sea, and Achmelvich, in Block 206/9b west of Shetland. BP is 100% owner of Capercaillie and the Achmelvich well partnership comprises BP (operator, 52.6%), Shell (28%) and Chevron (19.4%).BP announces two new exploration discoveries in the UK North Sea Both wells were drilled by the Paul B Loyd Junior rig in Summer 2017. The Capercaillie well was drilled to a total depth of 3,750 metres and encountered light oil and gas-condensate in Paleocene and Cretaceous-age reservoirs. The well data is currently under evaluation. Options are expected to be considered for a possible tie-back development to existing infrastructure. The Achmelvich well was drilled to a total depth of 2,395 metres and encountered oil in Mesozoic-age reservoirs. Evaluation and interpretation of the well results is ongoing to assess future options. Mark Thomas, BP North Sea Regional President said: 'These are exciting times for BP in the North Sea as we lay the foundations of a refreshed and revitalised business that we expect to double production to 200,000 barrels a day by 2020 and keep producing beyond 2050. 'We are hopeful that Capercaillie and Achmelvich may lead to further additions to our North Sea business, sitting alongside major developments like Quad 204, which came onstream in 2017, Clair Ridge, due to come into production this year, and the non-operated Culzean field, expected to start-up in 2019.' Original article link Source: BP

United Kingdom, not found

The government of the United Arab Emirates’ Ras Al Khaimah launched its first petroleum licensing round on Monday. The licensing round offers seven areas, including four shallow water offshore blocks and three onshore blocks, covering almost the entire emirate, the Ras Al Khaimah (RAK) government said in a statement.Ras Al Khaimah Offshore and Onshore Acreage are currently unlicensed. Building on legacy work and studies, RAK Gas reviewed the offshore and onshore subsurface potential, using Play Based Exploration (PBE), to build a rejuvenated Exploration Portfolio. RAK Gas has committed to organise a License Round for its entire offshore and onshore concessions in 2018, to allow companies bid for acreage.The following blocks are on offer:Data Rooms will be open in Ras Al Khaimah and London.Click here for further informationOriginal article linkSource: Reuters

The government of the United Arab Emirates’ Ras Al Khaimah launched its first petroleum licensing round on Monday. The licensing round offers seven areas, including four shallow water offshore blocks and three onshore blocks, covering almost the entire emirate,

IHS Markit understands that PT Sele Raya has likely plugged and abandoned wildcat Belato 2 in the Merangin II PSC, located onshore in the South Sumatra Basin, around late December 2019, as an oil discovery. The well was spudded on 12 November 2019, using land rig "Bohai #25", and was likely targeting the Middle-Upper Miocene Air Benakat Formation. The last exploration well drilled in the block was Lumbian 2 which was completed in early May 2016 as an oil and gas well, after confirmation from DST. The well may have targeted shallow sandstone reservoirs of the Air Benakat Formation which flowed oil and gas from the Lumbian 1 discovery well in 2011. Lumbian 2 was spudded around mid-March 2016. According to former partner Tata Petrodyne, several other prospects have been identified in the block, with total risked recoverable resources estimated at around 72 MMbo and 467 Bcfg. PT Sele Raya is operator of the Merangin II PSC with 44.6% interest. The remaining interests are held by Merangin BV (wholly owned subsidiary of Invenire Energy, which acquired Tata Petrodyne in 2019) (35.4%) and Sinochem (20%). The first well drilled on the Belato structure was Belato 1 in 2006. The well was P&A with gas shows after testing Air Benakat Formation sandstones. The block also contains two producing fields, Belani West and Siera Southeast (also known as Tampi Fields). The operator drilled two development wells, Belani West 11 and Belani West 13 in the Belani West field in early 2019, for the purpose of increase production from this block. Other drilling activities reported as part of the 2019 work programme also include workover of two existing development wells and drilling of one exploration well. Background Information The block is located in the South Sumatra Basin at the junction of the north-west to south-east trending Central Palembang Depression and the north-east to south-west trending Jambi Trough. Exploration of the area has focused on the Air Benakat Formation sandstones and the deeper Talang Akar Formation sandstones, along with fractured, weathered pre-Tertiary igneous basement and granite wash sediments. Good reservoir quality has been observed in the sands locally but their areal extent is limited. Structural plays sealed intra-formationally seems the most common play, with carbonate build-ups and stratigraphic traps seen as minor. Previously covered by Gulf's Merangin PSC (which encompassed both "Third Round" Merangin I & II blocks), the area has been relatively under explored but activity has been ongoing since the early 20th Century. Early explorers BPM and NKPM had no commercial success within the area encompassed by the new block. In the modern era, Huffco held the 5,160 sq km Mangunjaya Kapahiang PSC over the region between 1968-1982, drilling 16 wells and shooting over 3,800km of 2D seismic. Oil was discovered at Meruap and Huffco planned its development. However, the high exploration expenses incurred by Huffco led to commerciality not being granted. The area was then awarded to BP under the 5,905 sq km Merangin PSC between 1984-1987. BP shot about 845km of 2D and drilled delineations of Meruap. The global drop in oil prices in 1986-1987 prevented the field's further development until it was awarded as a TAC to BWP Meruap in 1994. From December 1993 to December 2000, Gulf Resources (earlier as Asamera) explored the area under a later version (4,000 sq km) of the Merangin PSC. In 1994, Asamera shot a 2D survey across the Telisa Anticline, located in the north-eastern corner of the PSC. A second survey between February-October 1996 recorded 682km of 2D data. Wildcat Halilintar 1 was spudded in October 1997 at a location in the northern part of the contract area. Halilintar 1 was designed as a deep well to test for gas to add to the feedstock supply for the Duri steamflood generators in Caltex's Rokan PSC in Central Sumatra. It was designed to test Talang Akar Formation sandstones and also the potential of the pre-Tertiary section at the location. Halilintar 1 was plugged and abandoned as an unsuccessful test in March 1998, despite having intersected fractured gas bearing granodiorite overlain by a sequence of thick granite wash sediments. PT Sele Raya was originally awarded the PSC on 14 October 2003, the company having submitted the successful bid for the block under the "Third Round" of Migas acreage releases which closed on 31 July 2003. The block was offered under standard PSC terms. The production split for the block was set at 75/25 for oil and 60/40 for gas in favour of the government. Signature bonus amounted to USD 678,000 and the PSC carried financial commitments of USD 4,522,500 for the first three years and USD 13.36 million for six years. After the block award, Sele Raya drilled seven exploration wells: Belato 1 (October 2006, P&A gas shows), Southeast Siera 1 (November 2007, oil discovery, 700 bo/d), West Belani 1 (July 2008, oil discovery, 750 bo/d), Southeast Siera 2 appraisal (September 2008, suspended oil), Gasop A-1 (September 2009, P&A dry), West Belani Extension 1 (April 2010, suspended oil shows) and Kemang Utara 1 (June 2010, suspended, result unreported). The eighth exploration well drilled in the block was wildcat Lumbian 1. The well, located about 27 km north-west of the South East Siera 1 and West Belani 1 discoveries, was spudded in mid-February 2011 and was drilled to a TD of 1,067m. Possible primary targets are sandstones of the Middle to Upper Miocene Air Benakat Formation. In mid/late May 2011, the operator suspended Lumbian 1 as an oil and gas discovery. Well testing operations yielded 760 bo/d plus 47 Mcfg/d. In early August 2015, PT Sele Raya plugged and abandoned the North Tampi 1 wildcat as a dry well. The well was spudded on 31 May 2015 using a 750 HP land rig owned by PT Daqing Jaya Petroleum Engineering. The objective target of the well is in the Middle to Upper Miocene Air Benakat Formation and Lower to Middle Miocene Gumai Formation, with PTD around 1,075 m. Reportedly by local press, estimated drilling cost for the well was between USD 4 million to USD 5 million.

Belato 2 expl. in Merangin II PSC P&A, oil discovery, Target assumed Air Benakat Fm. Sele Raya (op), partners Tata Petrodyne + Sinochem.

On 1 February 2020 the Greenland Government launched the Open Door Procedure for the onshore areas of the Nuussuaq Basin and Disko West area. The Open Door Procedure will remain open until the Greenland Government decides to close the procedure with an expected notice of 90 days. The acreage on offer has been divided in to three separate blocks covering a total area of 13,073 sq km. The exploration period for any licences is 10 years divided into three or four sub-periods. Applicants are allowed to apply for an extension of the exploration period up to a maximum of three years. These areas were last opened up in 2016 but no applications were made.

On 1 February 2020 the Greenland Government launched the Open Door Procedure for the onshore areas of the Nuussuaq Basin and Disko West area. The Open Door Procedure will remain open until the Greenland Government decides to close

On 14 January 2019, Eni SpA announced that it has entered into a Head of Agreement (HoA) with BP plc and the Ministry of Oil and Gas (MOG) for the acquisition of exploration and production rights for a newly created Block 77 (precise details yet to be announced by the MOG), a 3,100 sq km area, 30 km to the east of Block 61 (Khazzan-Makarem Gas Field). Eni Oman (a wholly owned subsidiary of Eni SpA) will act as operator during the exploration phase and both companies will take a 50% share. According to Eni, the agreement along with the signing for Block 47 “represents a further step in Eni’s strategy to reinforce its presence in the Sultanate of Oman and strengthen the collaboration with OOCEP, which is Eni’s partner in Block 52”.

Eni (50% acting as operator during the exploration phase) and BP (50%) signed with Oman’s Ministry of Oil & Gas an agreement that sets up the principles for the acquisition of the exploration and production rights of Block 77 onshore (3100km²) (precise details yet to be announced by the MOG), 30 km to the east of Block 61 (Khazzan-Makarem Gas Field).

Equinor spudded an exploration well on its Skruis prospect in PL 532 on 27 September 2018 using the “Songa Enabler” S/S. 7220/5-3 is located east of Kramsno and north of Nunatak. The well was drilled to TD at 1,782 m in the Upper Triassic Fruholmen Formation and has made a new oil discovery with estimated recoverable reserves of 12-25 MMbo. A 35 m oil column (30 m sandstone) was proven in the Jurassic Sto Formation with an OWC at 1,415 m subsea. There was a further 30 m of water-wet sandstone in the Sto Formation and a 110 m water-wet sandstone in the Lower Jurassic Nordmela Formation. It is likely that the find will be developed as a tie-in to Johan Castberg. On 29 October 2018 the well was being abandoned. Kramsno well 7220/4-1 (also in PL 532) proved a 130 m gross gas column in the Jurassic Sto and Nordmela formations (with poorer than expected reservoir quality) and a 45 m gross gas column was present in the Snadd Formation. Initial recoverable reserve estimates for the discovery ranged from 70 to 140 Bcf. The well was drilled between December 2013 and February 2014. Nunatak was also drilled in 2013 in PL 532 (as part of the same drilling campaign as Kramsno). The Cretaceous Knurr Formation target was gas-bearing but the reservoir is of poor quality and the discovery was deemed non-commercial. The PDO for Johan Castberg (in PL 532) was approved on 28 June 2018. The development contains recoverable reserves of 450-650 MMboe and first oil is expected in Q4 2022. The three fields involved in the project – Skrugard, Havis and Drivis – will be developed using an FPSO, 10 subsea templates, two satellite structures and 30 wells, with oil exported by shuttle tanker (Equinor, together with other companies operating in the area, is still investigating the future profitability of an oil terminal at Veidnes). CAPEX is estimated at NOK 47.2 billion (USD 5.79 billion) and the break-even price is around USD 31 per barrel. Johan Castberg is forecast to produce for at least 30 years.   Interest in PL 532 is held by Equinor Energy AS (50% + operator), Eni Norge AS (30%) and Petoro AS (20%).

Norway (Bjornoyrenna Fault Complex (Barents Sea Platform)) Johan Castberg

Add. DEA 18 Dec '19: Tangram is offering equity in P2421 (block 211/23c) SW of Dunlin and containing the 211/23b-12 (Skye) discovery (Hess, 1994) and Skylark prospect, target Tarbert sst. Contact: [email protected].

United Kingdom (East Shetland B. (Viking Graben Province)) 211/23b-12 (Skye)

On 12 September 2018 Sapura Energy Bhd announced that it had signed a heads of agreement with OMV AG to form a strategic partnership, to create “sustainable long-term growth [and] expand(ed) portfolios”.  The transaction is thought to be worth around USD 1.6 billion. Under the terms of the agreement OMV is to acquire a 50% interest in Sapura’s wholly owned subsidiary Sapura Upstream Sdn Bhd. The companies reported that it allows them to expand their acreage positions and better opportunities within the upstream energy sector. Within Australasia, OMV holds interest in two Australian permits, in the North Carnarvon Basin, and ten New Zealand permits across the Taranaki, East Coast and Great South basins.  Sapura has interest in three Australian permits, also within the North Carnarvon Basin, and in five of OMV’s Taranaki Basin permits.

Australia, not found

W-C part of CPO 11, Llanos Basin, drilled and P&A 1Q '20, no results. Hupecol carried thru drilling, ops under Parex management as part of a 2018 50% farmin agreement which also requires 108km of 2D seismic. Target assumed Carbonera.

Montuno 1 (Hupecol 100%) in CPO 11 block, P&A, no further results were available.

Wellesley Petroleum has acquired Equinor's 45% operated stake in recently awarded PL090 JS, effective 30 November 2018. Equinor, Idemitsu and Neptune were awarded PL090 JS for stratigraphies below Base Cretaceous over 4.06 sq km in North Sea part block 35/11, covering the SW portion of the Grosbeak discovery on 9 October 2018. The licence is in the Production phase valid until 9 March 2024 and was split out of Equinor-operated PL090 F. Grosbeak is mostly licensed under Wellesley Petroleum-operated PL248 I and PL925, immediately to the E. It was discovered by 35/12-2 (2009, Wintershall, 2,541m) and appraised during July-October 2018 by 35/11-21 S & 21 A (Wellesley Op) which confirmed recoverable resources of 50-128 MMbo and 0.6-1.3 Tcfg in Jurassic Ness, Etive, Sognefjord and Fensfjord formations. Revised PL090 JS equity partners are Wellesley Petroleum AS (45% + Op), Idemitsu Petroleum Norge AS (40%) and Neptune Energy Norge AS (15%).

Wellesley Petroleum has acquired Equinor's 45% operated stake in recently awarded PL090 JS, effective 30 November 2018. Equinor, Idemitsu and Neptune were awarded PL090 JS for stratigraphies below Base Cretaceous over 4.06 sq km in North Sea part block 35/11, covering the SW portion of the Grosbeak discovery on 9 October 2018.